AQ-2017-007-R322-REPORTTOTHEBOARDOFSUPERVISORS-2021-06-23.PDF

Executive Summary
of the Report to the Board of Supervisors
Prepared by the Maricopa County Air Quality Department
Board Hearing Date: June 23, 2021
Case Number/Title: AQ-2017-007-Rule 322 (Power Plant Operations)
Agenda Item: (Pending)
Supervisor Districts: All Districts
The Maricopa County Air Quality Department (MCAQD) complied with all statutory and county
policies throughout this rulemaking process. Per the Enhanced Regulatory Outreach Program
(EROP) Policy: “In addition to the required staff report, an executive summary of the report
including an overview of stakeholder input and staff responses will be provided to the Board of
Supervisors at least one week prior to any Board of Supervisors’ public hearing.”
Overview of the Report to the Board of Supervisors:
On May 4, 2016, portions of Maricopa County were designated as a moderate nonattainment area
with respect to the 2008 National Ambient Air Quality Standard for Ozone. Sections 182(b)(2) and
182(f) of the Clean Air Act require jurisdictions that are classified as “moderate” or higher
nonattainment to implement reasonably available control technology (RACT) for all categories of
volatile organic compounds (VOCs) sources covered by a Control Technique Guideline document
as well as for all other major stationary sources of NOx and VOCs that are located within the
nonattainment area. The U.S. Environmental Protection Agency (EPA) defines RACT as “the
lowest emission limitation that a particular source is capable of meeting by the application of control
technology that is reasonably available considering technological and economic feasibility”. The
EPA provides guidance on RACT for sources of NOx through Alternative Control Technology
documents which offer State and local air pollution control authorities information that assists in
determining NOx-RACT for air quality rules. In addition, the EPA reviews state implementation
plan (SIP)-approved air quality rules from other air districts with ozone nonattainment areas to assist
in determining NOx-RACT for air quality rules.
In November 2016, Rule 322 was revised to implement RACT for sources of NOx. The revised rule
was submitted to the EPA in June 2017, as part of the SIP Revision for the Maricopa County Air
Quality Department Ozone Rules contained in the Arizona SIP. The EPA reviewed Rule 322 and
provided the MCAQD with written rule approvability and rule improvement comments for the rule.
EPA staff informed MCAQD staff they would be using a conditional approval process to act on
Rule 322 and the MCAQD would need to draft a commitment letter outlining revisions to Rule 322
to address the rule approvability comments.
On January 28, 2019, the MCAQD submitted a Letter of Commitment for Conditional Approval of
the Maricopa County RACT SIP to the EPA. After the MCAQD submitted the commitment letter,
the EPA informed the MCAQD the commitments were not sufficient to allow the EPA to propose
a conditional approval. Therefore, the EPA proposed full disapproval of Rule 322 in the Federal
Register on December 30, 2019 (Docket ID; EPA-R09-OAR-2019-0321). The proposed disapproval
rulemaking was available for a 30-day comment period, but no comments were received. The
proposed disapproval references a Technical Support Document (TSD) which includes a thorough
1

review of Rule 322. The TSD outlines EPA’s six official rule deficiencies – which prevent approval
of the rule into the SIP – as well as seven rule revision recommendations, which are not currently
the basis for rule disapproval but are recommended for this current proposed rulemaking for Rule
322. Revisions addressing both the EPA’s identified deficiencies and recommendations have been
made to the proposed draft Rule 322 (attached to this report).
On July 20, 2020, the EPA published a final rule disapproving Rule 322 in the Federal Register. The
effective date of final rule disapproval was August 19, 2020. The final rule disapproval requires the
EPA to promulgate a federal implementation plan (FIP) within two years of the effective date of the
final action unless a subsequent SIP revision that corrects the rule deficiencies is submitted and
approved by the EPA. Final rule disapproval also triggers offset sanctions unless the EPA approves
a subsequent SIP revision within 18 months of the effective date of the final action and triggers
highway sanctions unless the EPA approves a subsequent SIP revision within 24 months of the
effective date of the final action.
In addition, RACT analyses submitted by the Arizona Public Service and the Salt River Project for
specific equipment at specific power plants are attached to this report. Section 104.4 of the draft rule
included in this report requires approval from the Control Officer and Administrator to operate
under the 10% exemption detailed in this section. Obtaining approval includes submitting a RACT
analysis to the Control Officer and the Administrator demonstrating conventional commercially
available control technology is not technically and/or economically feasible. The Control Officer has
reviewed these analyses and is proposing to approve the equipment listed in the analyses may
operate under the 10% exemption upon adoption of the rule.
Overview of Stakeholder Input and Staff Responses:
During the rulemaking process, the MCAQD received written comments from three (3)
stakeholders. The stakeholders expressed neither support nor opposition for the rulemaking. The
MCAQD evaluated the comments and drafted responses. The stakeholder comments and the
MCAQD responses to the comments are included in Section 9 of the attached Draft Notice of Final
Rulemaking.
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Report to the Board of Supervisors
Prepared by the Maricopa County Air Quality Department
Board of Health Meeting Date: April 26, 2021
Board Hearing Date: June 23, 2021
Case Number/Title: AQ-2017-007-Rule 322 (Power Plant Operations)
Agenda Item: (Pending)
Supervisor Districts: All Districts
Applicant: Staff
Request: Approve revisions to Rule 322 (Power Plant Operations)
and approve submission of the revised rule as a revision to
the Arizona State Implementation Plan.
On May 4, 2016, portions of Maricopa County were
designated as a moderate nonattainment area with respect to
the 2008 National Ambient Air Quality Standard for Ozone.
Sections 182(b)(2) and 182(f) of the Clean Air Act require
jurisdictions that are classified as “moderate” or higher
nonattainment to implement reasonably available control
technology (RACT) for all categories of volatile organic
compounds (VOCs) sources covered by a Control Technique
Guideline document as well as for all other major stationary
sources of NOx and VOCs that are located within the
nonattainment area. The U.S. Environmental Protection
Agency (EPA) defines RACT as “the lowest emission
limitation that a particular source is capable of meeting by the
application of control technology that is reasonably available
considering technological and economic feasibility”. The
EPA provides guidance on RACT for sources of NOx
through Alternative Control Technology documents which
offer State and local air pollution control authorities
information that assists in determining NOx-RACT for air
quality rules. In addition, the EPA reviews state
implementation plan (SIP)-approved air quality rules from
other air districts with ozone nonattainment areas to assist in
determining NOx-RACT for air quality rules.
In November 2016, Rule 322 was revised to implement
RACT for sources of NOx. The revised rule was submitted
to the EPA in June 2017, as part of the SIP Revision for the
Maricopa County Air Quality Department (MCAQD) Ozone
Rules contained in the Arizona SIP. The EPA reviewed Rule
322 and provided the MCAQD with written rule
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approvability and rule improvement comments for the rule.
EPA staff informed MCAQD staff they would be using a
conditional approval process to act on Rule 322 and the
MCAQD would need to draft a commitment letter outlining
revisions to Rule 322 to address the rule approvability
comments.
On January 28, 2019, the MCAQD submitted a Letter of
Commitment for Conditional Approval of the Maricopa
County RACT SIP to the EPA. After the MCAQD submitted
the commitment letter, the EPA informed the MCAQD the
commitments were not sufficient to allow the EPA to
propose a conditional approval. Therefore, the EPA
proposed full disapproval of Rule 322 in the Federal Register
on December 30, 2019 (Docket ID; EPA-R09-OAR-2019-
0321). The proposed disapproval rulemaking was available
for a 30-day comment period, but no comments were
received. The proposed disapproval references a Technical
Support Document (TSD) which includes a thorough review
of Rule 322. The TSD outlines EPA’s six official rule
deficiencies – which prevent approval of the rule into the SIP
– as well as seven rule revision recommendations, which are
not currently the basis for rule disapproval but are
recommended for this current proposed rulemaking for Rule
322. Revisions addressing both the EPA’s identified
deficiencies and recommendations have been made to the
proposed draft Rule 322 (attached to this report).
On July 20, 2020, the EPA published a final rule disapproving
Rule 322 in the Federal Register. The effective date of final
rule disapproval was August 19, 2020. The final rule
disapproval requires the EPA to promulgate a federal
implementation plan (FIP) within two years of the effective
date of the final action unless a subsequent SIP revision that
corrects the rule deficiencies is submitted and approved by
the EPA. Final rule disapproval also triggers offset sanctions
unless the EPA approves a subsequent SIP revision within 18
months of the effective date of the final action and triggers
highway sanctions unless the EPA approves a subsequent SIP
revision within 24 months of the effective date of the final
action.
In addition, RACT analyses submitted by the Arizona Public
Service and the Salt River Project for specific equipment at
specific power plants are attached to this report. Section
104.4 of the draft rule included in this report requires
approval from the Control Officer and Administrator to
operate under the 10% exemption detailed in this section.
Obtaining approval includes submitting a RACT analysis to
the Control Officer and the Administrator demonstrating
conventional commercially available control technology is not
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technically and/or economically feasible. The Control Officer
has reviewed these analyses and is proposing to approve the
equipment listed in the analyses may operate under the 10%
exemption upon adoption of the rule.
Support/Opposition: During the rulemaking process, the MCAQD has received
written feedback from three (3) stakeholders. The
stakeholders did not express support nor opposition to the
rulemaking.
Staff
Recommendation: Approve
Board of Health
Recommendation: Approve
Additional Comments: This rulemaking is following procedures identified in state
statutes and the Maricopa County Enhanced Regulatory
Outreach Program (EROP) Policy. The County Manager
briefed the Board of Supervisors regarding the rulemaking in
December 2017. The Board of Health Meeting to initiate
regulatory change for Rule 322 occurred on February 25,
2019. Stakeholder workshops for Rule 322 were held on
August 22, 2018 and February 16, 2021. A Notice of
Proposed Rulemaking for the rule was posted on the EROP
website on March 12, 2021. On April 26, 2021, the Board of
Health made a recommendation to the Board of Supervisors
to approve the revisions to Rule 322.
A newspaper notice of the Board of Supervisors public
hearing will be published in the Arizona Business Gazette on
May 20, 2021 and May 27, 2021. This regulatory change will
take effect immediately upon approval by the Board of
Supervisors.
Presented By: Philip A. McNeely, R.G., Director
Prepared By: Planning and Analysis Division
Attachments: Preamble required by Arizona Revised Statutes (A.R.S.) §
49-471.07 (See the Draft Notice of Final Rulemaking)
Summary of the proposed regulatory change (See Item 4 of
the Draft Notice of Final Rulemaking)
Analysis of input received during the process and how that
input was responded to (See Item 9 of the Draft Notice of
Final Rulemaking)
Language of proposed regulatory change or amendment (See
Draft Rule in the Draft Notice of Final Rulemaking)
Strikethrough-underline Version
Clean Version
Minutes from Board of Health meetings
Copies of all written and electronic Stakeholder input
EPA Region IX Air Division Technical Support Document
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RACT Analysis for the control of NOx emissions from APS
Ocotillo and West Phoenix Power Plants
RACT Analysis for the control of NOx emissions from
boilers at SRP Agua Fria Generating Station
RACT Analysis for the control of NOx emissions from
simple-cycle combustion turbine generators at the SRP Agua
Fria and Kyrene Generating Stations
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DRAFT NOTICE OF FINAL RULEMAKING
MARICOPA COUNTY AIR POLLUTION CONTROL REGULATIONS
REGULATION III – CONTROL OF AIR CONTAMINANTS
RULE 322: POWER PLANT OPERATIONS
The Maricopa County Air Quality Department (MCAQD) is proposing to amend Rule 322 (Power
Plant Operations). The Control Officer is posting this Draft Notice of Final Rulemaking on the
Maricopa County Enhanced Regulatory Outreach Program (EROP) website as part of the Report to
the Board of Supervisors, in accordance with the Maricopa County EROP Policy. This notice
includes the preamble, as prescribed in A.R.S. § 49-471.05, and the full text of the rule, including the
intended actions to make new sections or amend, repeal, or renumber the sections of the rule. This
notice also includes a list of all previous notices posted on the Maricopa County EROP website
addressing the proposed rule and the concise explanatory statement prescribed in A.R.S. § 49-471.07
subsection B.
PREAMBLE Return to list of attachments
1. Statutory authority for the rulemaking:
A.R.S. §§ 49-112, 49-474, 49-479 and 49-480
2. Name and address of department personnel with whom persons may communicate
regarding the rulemaking:
Name: Greg Verkamp and Kimberly Butler
Maricopa County Air Quality Department
Planning and Analysis Division
Address: 3800 N Central Avenue, Suite 1400
Phoenix, AZ 85012
Telephone: (602) 506-6010
Fax: (602) 506-6179
Email: AQPlanning@maricopa.gov
Submit Comments At: http://maricopa.gov/FormCenter/Regulatory-Outreach-17/Citizen-
Comments-94
3. Rulemaking process:
This rulemaking (AQ-2017-007-Rule 322) is following procedures identified in state statutes
and the Maricopa County EROP Policy.
County Manager Briefing: December 2017
Stakeholder Workshops: August 22, 2018
February 16, 2021
Board of Health Meeting to Initiate Regulatory
Change: February 25, 2019
Notice of Proposed Rulemaking: March 12, 2021
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Board of Health Meeting to Recommend
Approval to the Board of Supervisors: April 26, 2021
Board of Supervisors Formal Meeting to set the
Public Hearing: May 19, 2021
Board of Supervisors Public Hearing: June 23, 2021
4. Explanation of the rule, including the control officer's reasons for initiating the
rulemaking: Return to list of attachments
Rule 322 (Power Plant Operations) limits emissions of nitrogen oxides (NOx), carbon
monoxide (CO), sulfur oxides (SOx), and particulate matter (PM) from stationary fossil-fuel-
fired electric utility gas turbines, stationary fossil-fuel-fired electric utility steam generating
units or cogeneration steam generating units and limits particulate matter (PM) emissions
from cooling towers associated with this equipment. The MCAQD is proposing to revise
Rule 322 to address rule deficiencies identified by the U.S. Environmental Protection
Agency (EPA) to secure full approval of Rule 322 as a revision to the Arizona State
Implementation Plan (SIP).
On May 4, 2016, portions of Maricopa County were designated as a moderate nonattainment
area with respect to the 2008 National Ambient Air Quality Standard for Ozone. Sections
182(b)(2) and 182(f) of the Clean Air Act require jurisdictions that are classified as
“moderate” or higher nonattainment to implement reasonably available control technology
(RACT) for all categories of volatile organic compounds (VOCs) sources covered by a
Control Technique Guideline document as well as for all other major stationary sources of
NOX and VOCs that are located within the nonattainment area. EPA defines RACT as “the
lowest emission limitation that a particular source is capable of meeting by the application of
control technology that is reasonably available considering technological and economic
feasibility”. The EPA provides guidance on RACT for sources of NOX through Alternative
Control Technology (ACT) documents which offer State and local air pollution control
authorities information that assists in determining NOX-RACT for air quality rules. In
addition, the EPA reviews SIP-approved air quality rules from other air districts with ozone
nonattainment areas to assist in determining NOX-RACT for air quality rules.
In November 2016, Rule 322 was revised to implement RACT for sources of NOX. The
revised rule was submitted to the EPA in June 2017, as part of the SIP Revision for the
Maricopa County Air Quality Department Ozone Rules contained in the Arizona SIP. The
EPA reviewed Rule 322 and provided the MCAQD with written rule approvability and rule
improvement comments for the rule. EPA staff informed MCAQD staff they would be
using a conditional approval process to act on Rule 322 and the MCAQD would need to
draft a commitment letter outlining revisions to Rule 322 to address the rule approvability
comments.
On January 28, 2019, the MCAQD submitted a Letter of Commitment for Conditional
Approval of the Maricopa County RACT SIP to the EPA. After the MCAQD submitted the
commitment letter, the EPA informed the MCAQD the commitments were not sufficient to
allow the EPA to propose a conditional approval. Therefore, the EPA proposed full
disapproval of Rule 322 in the Federal Register on December 30, 2019 (Docket ID; EPA-
R09-OAR-2019-0321). The proposed disapproval rulemaking was available for a 30-day
comment period, but no comments were received. The proposed disapproval references a
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Technical Support Document (TSD) which includes a thorough review of Rule 322. The
TSD outlines EPA’s six official rule deficiencies – which prevent approval of the rule into
the SIP – as well as seven rule revision recommendations, which are not currently the basis
for rule disapproval but are recommended for this current proposed rulemaking for Rule
322. Revisions addressing both the EPA’s identified deficiencies and recommendations have
been made to the proposed draft Rule 322 (included in this notice). A link to EPA’s TSD is
located under Section 5 of this notice.
On July 20, 2020, the EPA published a final rule disapproving Rule 322 in the Federal
Register. The effective date of final rule disapproval was August 19, 2020. The final rule
disapproval requires the EPA to promulgate a federal implementation plan (FIP) within two
years of the effective date of the final action unless a subsequent SIP revision that corrects
the rule deficiencies is submitted and approved by the EPA. Final rule disapproval also
triggers offset sanctions unless the EPA approves a subsequent SIP revision within 18
months of the effective date of the final action and triggers highway sanctions unless the
EPA approves a subsequent SIP revision within 24 months of the effective date of the final
action.
Details about the EPA’s identified deficiencies and the MCAQD’s proposed remedies are
described below, followed by the EPA rule recommendations and the MCAQD’s proposed
revisions to address the recommendations.
Deficiency 1:
Section 104.2 contains overly broad exemptions for units firing on emergency fuel. This is a
RACT approvability issue since other similar rules for this category do not contain the broad
exemptions for unlimited periods of gas curtailment or delivery interruption. To be
consistent with other RACT rules, the District should also limit the total allowable length of
emergency fuel burning to be consistent with other jurisdictions (see, Imperial County
APCD Rule 400.1 Section D.3).
Remedy 1:
The MCAQD is proposing to clarify the exemption in Section 104.2 only applies during
natural gas curtailments and natural gas emergencies and is proposing to limit the amount of
time emergency fuel can be used for a natural gas curtailment or natural gas emergency to
168 hours per calendar year per combustion unit.
Deficiency 2:
Section 104.3 allows units that only fire emergency fuel for 36 hours to be exempted from
certain emission limits. This section needs to be amended to clarify the exemption is only
valid during the 36 hours or less per year when emergency fuel is used.
Remedy 2:
The MCAQD is proposing to clarify that the exemption in Section 104.3 only applies when
a unit is combusting emergency fuel for the purposes of testing, reliability, training, and
maintenance for up to 36 hours per year per combustion unit.
Deficiency 3:
Sections 306.1 and 306.2 allow for an owner or operator to comply with the rule by
submitting a case-by-case RACT analysis that will be incorporated into the permit. This
effectively exempts the source from the rule’s NOx limits, CEMS requirements, and
administrative requirements. This conflicts with the EPA’s current policy on Control Officer
9

discretion. To be approvable for RACT, the option to submit a case-by-case RACT analysis
should be removed, or the case-by-case RACT alternative must be submitted for SIP
approval.
Remedy 3:
The MCAQD is proposing to add a provision stating that any case-by-case RACT alternative
approved by the Control Officer must be submitted for SIP approval and approved by the
Administrator.
Deficiency 4:
The RACT limits provided for NOx-emitting combustion units in sections 306.1 and 306.2
are appropriate for stationary turbines. However, Rule 322 also applies to steam generating
units. RACT limits for these types of units is generally found to be more stringent (for
example, limits in many other jurisdictions are 30 ppmv for gas fuel fired units, and 40 ppmv
for liquid fuel fired units). The County must reduce the overall limit for all applicable units
to be at least as stringent at those demonstrated in EPA guidance or in other SIP approved
regulations or include a separate RACT limit applicable to steam generating units.
Alternatively, the County must provide a demonstration that the existing limits, or other
limits adopted in a modified rule, are appropriate and constitute RACT for Maricopa
County.
Remedy 4:
The MCAQD is proposing to add separate NOx emission limits for new steam generating
units of 30 ppmvd when burning gaseous fossil fuel and 40 ppmvd when burning liquid
fossil fuel to meet RACT.
Deficiency 5:
Section 402 describes the compliance schedules and requirements for NOx in units that are
found to be non-compliant. Owners and operators must comply with section 402.2
Increments of Progress, or section 402.3 Removal From Service. Increments of progress
(i.e., compliance deadlines) may be extended by the Control Officer as needed. This Control
Officer discretion, which conflicts with EPA’s current policy on Control Officer discretion,
should be removed or appropriately constrained. Section 402.3 allows for the removal from
service process to last up to a total of two years, or more time if the County did not act
expeditiously on the permit revision. Units are exempt from NOx limits during this time.
The amount of time that these units are out of compliance should be bounded and
minimized, e.g. by providing a backstop date by which all units must achieve compliance.
Remedy 5:
The MCAQD is proposing to remove the provision in Section 402 that allows the Control
Officer to extend the deadlines for increments of progress. In addition, the MCAQD is
proposing to revise Section 402.3 (new Section 402.2) to state that all combustion units must
comply with Section 306 of the rule or be removed from service within 24 months after the
unit becomes subject to the requirements of Section 306 of the rule.
Deficiency 6:
Rule 323, section 503.2 requires boilers of 100 MMBtu/hr or greater heat input to conduct
triennial stack tests. Rule 322 should require a similar or more stringent requirement for all
EGU boilers and turbines in the same size category.
Remedy 6:
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The MCAQD is proposing to require annual performance tests for any equipment listed in
Section 102.1 or 102.2 that is subject to numeric emission limits in section 306 and 307.
However, if the NOx or CO emission result from any performance test is less than or equal
to 75 percent of the NOx or CO emission limit, the owner or operator may reduce the
frequency of subsequent performance tests to once every 2 years (no more than 26 calendar
months following the previous performance test). If the results of any subsequent
performance test exceed 75 percent of the NOx or CO emission limit, the owner or
operator must resume annual performance tests.
Recommendation 1:
Section 302 describes good combustion practices for turbines and states that any of three
practices listed in 302.1, 302.2, or 302.3 may be chosen. Section 302.3 says that if there is a
pattern of non-compliance with the differential temperature measurement as required in
302.1, the Control Officer may require a Corrective Action Plan (CAP). This appears to
allow a facility to remain out of compliance with the good combustion practice requirement.
We recommend revising this section to indicate that the Control Officer shall require the
operator to submit a CAP.
Revision 1:
The MCAQD is proposing to revise the language in Section 302 including removing Section
302.3.
Recommendation 2:
Section 302 states that if the owner or operator is using a CEMS or “other approved
monitoring method,” then the equipment is otherwise exempt from the requirements of 302.
However, this is problematic, as section 302.3 requires that a CAP must be submitted to the
Control Officer to remedy operation errors. It does not appear that an owner or operator
will need to take corrective action if a CEMS-equipped unit detects operation error. Please
include language that states that a CEMS-equipped unit should take similar corrective action
if an operational error is detected. Section 302 also states that an owner or operator of an
applicable stationary gas turbine “shall” use good operational practices, but then states that
one of the following procedures “may” be used. Please clarify that the second statement
also shall require one of the procedures listed in the subsections of Section 302.
Revision 2:
The MCAQD is proposing to add Section 501.6b which requires an owner or operator using
CEMS to demonstrate good combustion practices to record corrective actions taken each
time the CEMS indicates an exceedance of the applicable emission limits in Section 306 or
307. The MCAQD is also proposing to remove the word “may” from the Section 302
introduction language.
Recommendation 3:
Section 303.2 should be revised to include the units for total dissolved solids (e.g., 20 mg/L).
Revision 3:
The MCAQD is proposing to add “ppm” as the unit measure for total dissolved solids.
Recommendation 4:
Section 306 specifies a 30-day rolling average be used to determine compliance with
applicable NOx limits for units equipped with CEMS. This averaging period is too long
compared to the compliance determination requirements if a facility was using standard
11

source test methods. CEMS determination requirements should at least match the
requirements for source tests (1-hour sample time), and averaging could be conducted over a
24-hour rolling period (see, e.g., SIP-approved Ventura County APCD Rule 59, section B.1.).
Revision 4:
The MCAQD is proposing to replace the 30-day rolling average to determine compliance
with applicable NOx limits with a 24-hour rolling average.
Recommendation 5:
Section 308.1 uses the term “combustion control system” and Section 308.3 uses the term
“emission processing equipment,” neither of which are defined in this rule. We recommend
adding these definitions.
Revision 5:
The MCAQD is proposing to remove references to emission processing equipment in the
rule and add a definition of combustion control system.
Recommendation 6:
Section 308.3 describes Operations and Maintenance (O&M) Plan requirements for an
Emission Control System. Operation & Maintenance plans are required at section 308.2 to
describe the function and maintenance of monitoring equipment. Section 308.3b states that
O&M plans shall be submitted to the Control Officer for approval. Section 308.3e states
that the Control Officer may modify O&M plans. In both of these instances, there is no
discussion as to what criteria these plans or discretionary modifications are intended to meet.
We recommend adding such criteria.
Revision 6:
The MCAQD is proposing to add specific criteria for O&M Plans in new Section 308.2
Recommendation 7:
Section 401 describes the compliance schedule for units that are currently operating and
determined to be compliant with NOx emission limits. NOx facilities must submit a
“Notification of Compliance” which must consist of one of the two following options: a.
Demonstrate there was already a performance test and include the results of said test. This
test must have been conducted within the past five years. Clarify what is intended by
“performance test” in this context (e.g. “performance stack test”). b. Outline the timeline for
a performance test. There are also no constraints on how long an owner or operator might
take to conduct this test after submitting this “Notification of Compliance,” beyond
indicating that a timeline shall be included. Please include a limit for how long a timeline may
extend.
Revision 7:
The MCAQD is proposing to clarify what is intended by “performance test” by referencing
Section 503.4 in Section 401.1 and is proposing to require the Notification of Compliance
include results from a performance test conducted in accordance with Section 503.4 after the
date one year before rule adoption.
Additional revisions were made to address stakeholder and staff comments, which can be
discerned in the “strikeout and underline” version of the rule included in this notice and
described in all Stakeholder Workshop notices and workshop slides/presentations that are
posted on the EROP website.
12

In addition, RACT analyses submitted by the Arizona Public Service and the Salt River
Project for specific equipment at specific power plants are attached to this report. Section
104.4 of the rule included in this notice requires approval from the Control Officer and
Administrator to operate under the 10% exemption detailed in this section. Obtaining
approval includes submitting a RACT analysis to the Control Officer and the Administrator
demonstrating conventional commercially-available control technology is not technically
and/or economically feasible. The Control Officer has reviewed these analyses and is
proposing to approve the equipment listed in the analyses may operate under the 10%
exemption upon adoption of the rule.
5. Studies relied on in the control officer's evaluation of or justification for the rule and
where the public may obtain or review the studies, all data underlying the studies,
any analysis of the studies and other supporting material.
United States Environmental Protection Agency Region IX Air Division (2019), Technical
Support Document for EPA’s Rulemaking for the Arizona State Implementation Plan
Regarding Rule 322, “Power Plant Operations.”
www.regulations.gov/document?D=EPA-R09-OAR-2019-0321-0010
6. An economic, small business and consumer impact statement:
The following discussion addresses each of the elements required for an economic, small
business and consumer impact statement, as prescribed by A.R.S. §§ 41-1055, subsections A,
B and C, and 41-1035:
An identification of the proposed rulemaking, including all of the following:
This rulemaking is proposing to revise Rule 322.
(a) The conduct and its frequency of occurrence that the rule is designed to change.
The MCAQD is proposing to revise Rule 322 to remedy deficiencies identified by the
EPA. This rulemaking is required to secure approval of Rule 322 into the Arizona SIP.
The revisions are explained in more detail in Item #4 of this notice.
(b) The harm resulting from the conduct the rule is designed to change and the
likelihood it will continue to occur if the rule is not changed.
The MCAQD is proposing to revise Rule 322 to remedy deficiencies identified by the
EPA. This rulemaking is required to secure approval of Rule 322 into the Arizona SIP
and avoid sanctions and imposition of a Federal Implementation Plan (FIP) under the
Clean Air Act.
(c) The estimated change in frequency of the targeted conduct expected from the
rule change.
The MCAQD is proposing to revise Rule 322 to remedy deficiencies identified by the
EPA. This rulemaking is required to secure approval of Rule 322 into the Arizona SIP.
As with other rules, the MCAQD will use education, outreach, and other compliance
assurance tools to increase the number of people in compliance with the revised rule.
The MCAQD strives to achieve the highest possible compliance rates.
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A brief summary of the information included in the economic, small business and
consumer impact statement.
The economic, small business and consumer impact statement addresses each of the
elements required for an economic, small business and consumer impact statement, as
prescribed by A.R.S. §§ 41-1055, subsections A, B, and C, and 41-1035.
Name and address of agency employees who may be contacted to submit or request
additional data on the information included in the economic, small business and
consumer impact statement.
Name: Greg Verkamp and Kimberly Butler
Maricopa County Air Quality Department
Planning and Analysis Division
Address: 3800 N Central Avenue, Suite 1400
Phoenix, AZ 85012
Telephone: (602) 506-6010
Fax: (602) 506-6179
Email: AQPlanning@maricopa.gov
Submit Comments At: http://maricopa.gov/FormCenter/Regulatory-Outreach-17/Citizen-
Comments-94
An identification of the persons who will be directly affected by, bear the costs of or
directly benefit from the proposed rulemaking.
This rulemaking will directly affect facilities in Maricopa County that have stationary fossil-
fuel-fired electric utility gas turbines, stationary fossil-fuel-fired electric utility steam
generating units or cogeneration steam generating units.
A cost benefit analysis of the following:
(a) The probable costs and benefits to the implementing agency and other agencies
directly affected by the implementation and enforcement of the proposed
rulemaking.
This rulemaking should not impose any new costs on the MCAQD or on any other
agencies affected by the proposed rulemaking.
(b) The probable costs and benefits to a political subdivision of this state directly
affected by the implementation and enforcement of the proposed rulemaking.
This rulemaking should not impose any new costs on political subdivisions of this state
affected by the proposed rulemaking.
(c) The probable costs and benefits to businesses directly affected by the proposed
rulemaking, including any anticipated effect on the revenues or payroll
expenditures of employers who are subject to the proposed rulemaking.
Probable Costs: The MCAQD does not anticipate the sources directly affected by the
proposed rulemaking will incur significant costs to comply with the proposed rule. The
equipment subject to the proposed rule will continue to operate in a similar manner as it
is operating under the rule currently in force without any major physical modifications
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needed1. Sources that decide to continue to operate equipment under the 10%
exemption in Section 104.4 of the proposed rule will incur costs to conduct a RACT
analysis for each piece of equipment that will operate under the exemption as well as
costs to modify the permit associated with any equipment operated under the
exemption. A minor permit revision application costs $150.00 and permit engineering
hours cost $161.10/hr.
The MCAQD does not anticipate any effect on the revenues or payroll expenditures of
sources who are subject to the proposed rulemaking.
Probable Benefits: The main benefit of adopting the proposed rule is to remedy
deficiencies identified by the EPA and thereby avoid sanctions and the imposition of a
FIP. This includes avoiding offset sanctions which, if imposed, would increase the
current offset ratio in Maricopa County of emission reductions to increased emissions
from 1.15 to 1 to at least 2 to 1. In addition, some of the revisions included in the
proposed rule were proposed by the sources directly affected by the proposed
rulemaking to improve rule clarity. The MCAQD anticipates the increased rule clarity
will provide a benefit to those sources.
A general description of the probable impact on private and public employment in
businesses, agencies and political subdivisions of this state directly affected by the
proposed rulemaking.
This rulemaking should have no impact on private or public employment in businesses,
agencies, and political subdivisions of this state.
A statement of the probable impact of the proposed rulemaking on small businesses.
The statement shall include:
(a) An identification of the small businesses subject to the proposed rulemaking.
There are no small businesses subject to this rulemaking.
(b) The administrative and other costs required for compliance with the proposed
rulemaking.
There are no small businesses subject to this rulemaking.
(c) A description of the methods that the agency may use to reduce the impact on
small businesses.
i. Establish less stringent compliance or reporting requirements in the rule for
small businesses.
There are no small businesses subject to this rulemaking.
ii. Establish less stringent schedules or deadlines in the rule for compliance or
reporting requirements for small businesses.
There are no small businesses subject to this rulemaking.
1 One source that will be subject to the proposed rule upon rule adoption submitted a significant permit application
revision to the MCAQD permitting division for installation of NOx reducing technology on two pieces of equipment.
This application was submitted on January 31, 2019 to comply with the rule currently in force, not the proposed rule
included in this notice.
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iii. Consolidate or simplify the rule's compliance or reporting requirements for
small businesses.
There are no small businesses subject to this rulemaking.
iv. Establish performance standards for small businesses to replace design or
operational standards in the rule.
There are no small businesses subject to this rulemaking.
v. Exempt small businesses from any or all requirements of the rule.
There are no small businesses subject to this rulemaking.
(d) The probable cost and benefit to private persons and consumers who are directly
affected by the proposed rulemaking.
This rulemaking should not result in any significant costs for private persons and
consumers.
A statement of the probable effect on state revenues.
The rulemaking will not impose increased monetary or regulatory costs on other state
agencies, political subdivisions of this state, persons, or individuals so regulated. Without
costs to pass through to customers, there is no projected change in consumer purchase
patterns and, thus, no impact on state revenues from sales taxes.
A description of any less intrusive or less costly alternative methods of achieving the
purpose of the proposed rulemaking, including the monetizing of the costs and
benefits for each option and providing the rationale for not using nonelected
alternatives.
The purpose of this rulemaking is to revise Rule 322 to remedy deficiencies identified by the
EPA. This rule making is required to secure approval of Rule 322 into the State
Implementation Plan (SIP) and avoid sanctions and imposition of a FIP under the Clean Air
Act.
A description of any data on which a rule is based with a detailed explanation of how
the data was obtained and why the data is acceptable data.
Not applicable.
7. The proposed effective date of the rule:
The proposed effective date of this rulemaking is June 23, 2021.
8. Such other matters as are prescribed by statute and that are applicable to the county
or to any specific rule or class of rules:
Under A.R.S. § 49-479(C), a county may not adopt a rule or ordinance that is more stringent
than the rules adopted by the Director of the Arizona Department of Environmental Quality
(ADEQ) for similar sources unless it demonstrates compliance with the applicable
requirements of A.R.S. §49-112.
§ 49-112 County regulation; standards
§ 49-112(A)
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When authorized by law, a county may adopt a rule, ordinance or regulation that is more
stringent than or in addition to a provision of this title or rule adopted by the director or any
board or commission authorized to adopt rules pursuant to this title if all of the following
requirements are met:
1. The rule, ordinance or regulation is necessary to address a peculiar local condition.
2. There is credible evidence that the rule, ordinance or regulation is either;
(a) Necessary to prevent a significant threat to public health or the environment that
results from a peculiar local condition and is technically and economically feasible.
(b) Required under a federal statute or regulation, or authorized pursuant to an
intergovernmental agreement with the federal government to enforce federal statutes
or regulations if the county rule, ordinance or regulation is equivalent to federal
statutes or regulation.
3. Any fee or tax adopted under the rule, ordinance or regulation does not exceed the
reasonable costs of the county to issue and administer the permit or plan approval
program.
§ 49-112(B)
When authorized by law, a county may adopt rules, ordinances or regulations in lieu of a
state program that are as stringent as a provision of this title or rule adopted by the director
or any board or commission authorized to adopt rules pursuant to this title if the county
demonstrates that the cost of obtaining permits or other approvals from the county will
approximately equal or be less than the fee or cost of obtaining similar permits or approvals
under this title or any rule adopted pursuant to this title. If the state has not adopted a fee or
tax for similar permits or approvals, the county may adopt a fee when authorized by law in
the rule, ordinance or regulation that does not exceed the reasonable costs of the county to
issue and administer that permit or plan approval program.
The MCAQD is in compliance with A.R.S. §§ 49-112 (A) and (B). Rule 322 meets A.R.S. §
49-112 (A) (1) by demonstrating that the rule is necessary to address a peculiar local
condition, in that Maricopa County fails to meet the 8-hour NAAQS for ozone. Rule 322
meets the requirements of A.R.S. § 49-112 (A) (2) (b), in that Maricopa County is required by
federal law to revise existing rules to address RACT for the facilities that have stationary
fossil-fuel-fired electric utility stationary gas turbines, stationary fossil-fuel-fired electric
utility steam generating units, stationary fossil-fuel-fired cogeneration steam generating units,
and cooling towers associated with this equipment. As there is no new fee or tax associated
with this proposed rulemaking, the MCAQD also affirms that Rule 322 meets the
requirements of A.R.S. § 49-112 (A) (3) and A.R.S. § 49-112 (B).
9. List of all previous notices posted to the Maricopa County EROP website addressing
the proposed rule and a concise explanatory statement, as prescribed by A.R.S. § 49-
471.07, subsection B:
(a) List of all previous notices posted to the Maricopa County EROP website
addressing the proposed rule:
Notice Date of Posting
Briefing Notification to County Manager: January 26, 2018
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Notice of Stakeholder Workshop: August 03, 2018
February 02, 2021
Notice of Board of Health Meeting to Initiate
Regulatory Change: February 08, 2019
Notice of Proposed Rulemaking: March 12, 2021
Notice of Board of Health Meeting to Make
Recommendations to the Board of Supervisors: April 12, 2021
(b) The following discussion addresses each of the elements required for a concise
explanatory statement, as prescribed by A.R.S. § 49-471.07, subsection B:
i. A description of any change between the proposed rule or ordinance, the final
rule or ordinance or notice of final supplemental rule or ordinance.
The following changes were made after the Notice of Proposed Rulemaking was
published on March 12, 2021.
1. Section 104.4.a.(1) was revised to read as follows:
For equipment for which a RACT analysis was submitted prior to [date of rule
adoption], upon Control Officer approval, equipment may begin to operate
under the exemption until the Administrator approves or denies operation under
the exemption. If the Administrator denies approval to operate under the
exemption, the equipment will become subject to the emission limits in Sections
306 and 307. Return to list of attachments
ii. A summary of the comments and arguments for and against the notice and
the county’s response to the comments and arguments.
The following discussion evaluates the arguments for and against the rule and
includes responses to comments received on the proposed rule or the preamble in
the Notice of Proposed Rulemaking. The MCAQD received written comments from
three (3) stakeholders. All of the comments were reviewed and evaluated by the
MCAQD.
Comment #1: Rule 322, Section 501.1 - This rule now requires records of the type
and amount of fuel used, sulfur content and days and hours of operation. I would
like to remove the requirement to track days and hours of operation and that fuel use
be required to be tracked monthly. Fuel tracking monthly makes the most sense
since invoices are typically sent monthly (in the case of natural gas). I have been
unable to identify a reason to track days and hours of operation. This information
does not appear to be needed to determine compliance.
Response #1: The MCAQD has considered your comment and revised the section
to require fuel use be tracked monthly; however, the MCAQD did not remove the
requirement to track days and hours of operation.
Comment #2: Could you clarify in the proposed language that the 168 hours per
year is per combustion unit for the emergency fuel combustion?
Response #2: The MCAQD clarified the language in Section 104.2 that the 168
hours per year is per combustion unit for the emergency fuel combustion.
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Comment #3: Section 201 – [Our company] requests the following be deleted as it
may be repetitive of the language it preceeds: “The annual capacity factor is
calculated by dividing actual heat input by potential heat input or by dividing actual
electrical output by potential electrical output.”
Response #3: The language has been removed from the definition.
Comment #4: Section 204 – [Our company] requests the following change:
“Equipment or technology, such as including but not limited to water injection …”
Response #4: The requested revision has been made.
Comment #5: Section 302.4 – It is [our company's] experience that Maricopa
County already executes its enforcement authority at the time that an exceedance of
any emission limitation occurs. Typically the County will issue a Notice of Violation,
and, if necessary, an Administrative Order of Abatement on Consent (AOC) to
correct the exceedance. The conditions of both the NOV and the AOC can include
the authority to require injunctive relief which could include the development of a
corrective action plan. Since each exceedance should be reviewed on a case-by-case
basis, and the authority to seek injunctive relief already exists, [our company] does
not believe that this provision of the rule is necessary and recommends the deletion
of this Section.
Response #5: The MCAQD considered your comment and has removed the
provision from the rule.
Comment #6: Section 303.2 – Maricopa County added a requirement to provide in
writing the manufacturer’s affirmation of the % drift rate. For existing cooling
towers, [our company] is concerned that this information may not be available as
there was no requirement to maintain the written affirmation of % drift rate when
the existing cooling towers were permitted and built. [Our company] believes that it
will be difficult to obtain documentation now after a decade or more post
construction. [Our company] proposes that the requirement be amended to require
documentation of % drift rate of any new or reconstructed cooling towers as of the
date of the re-issued rule.
Response #6: The MCAQD considered your comment and has removed the
requirement from the rule; however, it should be noted that Section 503.2 of the
current rule in force and the proposed rule in this notice state the following:
Drift Rate Verification: An owner or operator shall submit design drift rate
verification from the manufacturer of the drift eliminator used in the cooling towers
to the Control Officer if proof of the design drift rate is requested by the Control
Officer.
Comment #7: Section 307 – [Our company] requests the following change: “An
owner or operator of any equipment listed in Section 102 of this rule shall not cause
to be discharged into the atmosphere carbon monoxide (CO) measured in excess of
400 ppmvdc per operating hourat any time.”
Response #7: Section 307 has been revised as follows: An owner or operator of any
equipment listed in Section 102.1 or 102.2 of this rule shall not cause to be
discharged into the atmosphere carbon monoxide (CO) measured in excess of 400
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ppmvd corrected to 15% oxygen for stationary gas turbines, and corrected to 3%
oxygen for steam generating units.
Comment #8: Section 501.7 –[Our company] requests the following correction:
“Equipment Referenced in Sections 104.4, 306.1, and 306.2 Operating Below less
than or equal to 10% of Annual Capacity:”
Response #8: Section 501.7 has been removed from the draft rule.
Comment #9: Section 503.4 – This section should be corrected as follows: “CEMS:
An owner or operator using a CEMS to demonstrate compliance with Section 302,
306, or 307 shall install, operate, calibrate, maintain, and test the CEMS in
accordance with 40 CFR Part 60 or 40 CFR Part 75. Excess emissions for Section
306 are defined as any period during which the 24-hour rolling average emission rate
exceeds the applicable numeric emission limit. Excess emissions for Section 307 are
defined as any period which an operating hour average emission rate exceeds the
applicable numeric emission limit.
Response #9: Section 503.4 has been renumbered to Section 503.6 and revised to
read as follows: CEMS: An owner or operator using a CEMS to demonstrate
compliance with Section 302, 306, or 307 shall install, operate, calibrate, maintain,
and test the CEMS in accordance with 40 CFR Part 60 or 40 CFR Part 75.
a. Excess emissions for Section 306 are defined as any period during which the 24-
hour rolling average emission concentration exceeds the applicable numeric
emission limits.
b. Excess emissions for Section 307 are defined as any period during which the 30-
operating day rolling average emission concentration exceeds the applicable
numeric emission limits.
Comment #10: [Our Company] has reviewed MCAQD's revision to this section
[104.3] and would like to clarify that this exemption applies on a per unit basis and
proposes the following addition as indicated in red font:
104.3 While firing emergency fuel for purposes of testing, reliability, training, and
maintenance, any equipment listed in Section 102 of this rule that is normally fired
with natural gas is exempt from Sections 301, 306, 307, and 503 of this rule. This
exemption shall not exceed 36 hours per calendar year, per unit, excluding hours of
operating during natural gas curtailments and natural gas emergencies
Response #10: Section 104.3 has been revised as follows: While firing emergency
fuel for purposes of testing, reliability, training and maintenance, any equipment
listed in Section 102 of this rule that is normally fired with natural gas is exempt
from Sections 301, 306, 307, 501.4, 503.3, 503.4, 503.5, and 503.6 of this rule. This
exemption shall not exceed 36 hours per calendar year per combustion unit,
excluding hours of operation during natural gas curtailments and natural gas
emergencies.
Comment #11: [Our company] requests that MCAQD revise the definition of
Combustion Control System as follows:
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COMBUSTION CONTROL SYSTEM: Equipment or technology, including but
not limited to, water injection or low-NOx burners that suppress NOx formation
during combustion of fossil fuels.
Response #11: The definition has been revised as follows: Equipment or
technology that suppress NOx formation during combustion of fossil fuels,
including but not limited to, water injection or low-NOx burners.
Comment #12: [Our company] proposes that MCAQD revise Section 302.1 -
Parametric Monitoring to not remove the words "valid maximum" from this
paragraph referencing temperature differentials greater than 100°F. There could be
an instance where there is a system error that shows a false reading where
temperature differential is greater than 100°F, but the condition is not actually
occurring.
Response #12: Section 302 has been significantly revised and now reads as follows:
An owner or operator of any stationary gas turbine listed in Section 102.2 of this rule
shall, regardless of fuel type, use operational practices recommended by the
manufacturer to ensure good combustion control.
302.1 Good combustion practices shall be demonstrated by maintaining the
manufacturer’s recommended maintenance practices onsite and available to
the Control Officer upon request, by maintaining records of all maintenance
activities conducted on the turbines, and by conducting performance tests as
described in Section 503 (unless exempt from Sections 306 and 307 under
the exemption in Section 104.4).
302.2 For stationary gas turbines with a CEMS able to demonstrate compliance
with the applicable emission limits in Sections 306 and 307, good
combustion practices may be demonstrated through continuous compliance
with the applicable emission limits in Sections 306 and 307.
Comment #13: Section 302.3, Corrective Action Plan (CAP) - Parametric
Monitoring and Section 302.4, Corrective Action Plan - CEMS both requires sources
to submit a CAP if conditions in these requirements have been exceeded more than
three times in three months. [Our company] requests that the requirement to submit
a CAP be removed from these provisions.
Response #13: Please see Response #12.
Comment #14: [Our company] proposes to amend Section 501.7 to be consistent
with the exemption listed in Section 104.4 of this Rule:
Equipment Operating less than or equal to 10% of Annual Capacity: At the end of
each month, calculate the annual capacity factor and NOx emissions for the calendar
year to demonstrate that the unit is eligible for the exemption in Section 104.4 of the
rule.
Response #14: Section 501.7 has been removed from the draft rule.
Comment #15: I am attaching our comments on draft rule 322 here. Please let me
know if you have any questions and/or need additional information on anything.
Comments on draft rule 322
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Response #15: Below is a response to each of the comments provided by the
commenter in the attachment above. Each comment is numbered in the right-hand
margin of the attachment and a response to each numbered comment is listed below.
Each response is linked to the comment it corresponds to in the attachment.
15.1 All applicable units will be affected by this rule once it is adopted by either
the new emission limits or alternative RACT requirements. If a permitted
unit is already in compliance with the new emission limits, then no change to
the permit will be necessary. If a permitted unit is not in compliance with the
new emission limits or alternative RACT requirements, then the permit will
need to be revised following the timeframes in Section 402. The draft rule
does reference NSPS and NESHAP standards that facilities may be subject
to as well.
15.2 The MCAQD has revised the definition to more closely match the federal
definition in 40 CFR Part 72 Subpart A. The definition reads as follows: A
clock hour during which a unit combusts any fuel, either for part of the hour
or for the entire hour.
15.3 EPA has indicated that a 30-day rolling average is too long of a time period
for compliance determination (See EPA TSD Recommendation #4).
15.4 Section 302 has been significantly revised. Please see Response #12.
15.5 Section 302 has been significantly revised. Please see Response #12.
15.6 The MCAQD has removed the alternative RACT requirements table and
reinserted the 10% calendar year annual capacity factor exemption.
15.7 Yes unless stated otherwise.
15.8 Section 501.6 has been revised to read as follows:
Good Combustion Practices:
a. Good combustion practices shall be demonstrated by maintaining the
manufacturer’s recommended maintenance practices onsite and available
to the Control Officer upon request, by maintaining records of all
maintenance activities conducted on the turbines, and by maintaining
records of the test results of performance tests conducted under Section
503 (unless exempt from Sections 306 and 307 under the exemption in
Section 104.4).
b. If using CEMS to demonstrate good combustion practices, results of
evaluation and of corrective action shall be recorded each time the CEMS
indicates an exceedance of the applicable emission limits in Section 306 or
307 of this rule.
c. For units equipped with water or steam injection, the owner or operator
shall maintain continuous records of the water to fuel ratio or the steam to
fuel ratio, unless the owner or operator uses CEMS to demonstrate
compliance with the emission limits in Sections 306 and 307, as applicable.
15.9 Per 40 CFR 60.4335 Subpart KKKK, (a) If you are using water or steam
injection to control NOx emissions, you must install, calibrate, maintain and
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operate a continuous monitoring system to monitor and record the fuel
consumption and the ratio of water or steam to fuel being fired in the turbine
when burning a fuel that requires water or steam injection for compliance.
Your company had indicated they wanted to demonstrate compliance with the
emission limits based on their RATA results rather than CEMS.
15.10 Section 503.6 has been revised to read as follows:
CEMS: An owner or operator using a CEMS to demonstrate compliance
with Section 302, 306, or 307 shall install, operate, calibrate, maintain, and
test the CEMS in accordance with 40 CFR Part 60 or 40 CFR Part 75.
a. Excess emissions for Section 306 are defined as any period during which
the 24-hour rolling average emission concentration exceeds the
applicable numeric emission limits.
b. Excess emissions for Section 307 are defined as any period during which
the 30-operating day rolling average emission concentration exceeds the
applicable numeric emission limits.
Comment #16: Although MCAQD’s existing inventory of equipment named in
Section 102.1 and 102.2 may all be located at major sources of NOx, this may not be
the case in the future. To align the applicability of the lower limits in this rule with
MCAQD’s stated intentions for the revised rule, the regulation must be revised to
clarify that the lower limits apply only to units located at stationary sources qualifying
as major sources of NOx. MCAQD can properly qualify the applicability of the
lower NOx emission limitations by adding Section 102.5 to the rule as follows: The
requirements for NOx emissions (NOx RACT) in this rule apply only to equipment
listed in 102.1 and 102.2 if the equipment is located at a major source of NOx.
Response #16: The MCAQD has considered your comment but has determined it is
not necessary to revise the applicability of the rule to clarify the NOx emission
standards in the rule only apply to equipment listed in 102.1 and 102.2 if the
equipment is located at a major source of NOx. Currently, as stated in your comment,
MCAQD’s existing inventory of equipment named in Section 102.1 and 102.2 are all
located at major sources of NOx. As such, all existing equipment is subject to the
NOx RACT emission limits. If a new minor source of NOx to which Rule 322 applies
is built in Maricopa County, that source will be subject to federal new source
performance standards (NSPS). The NSPS for NOx emissions for the equipment
listed in Sections 102.1 and 102.2 are more stringent than the NOx RACT emission
standards in Rule 322 so revising the applicability is not necessary. New minor sources
will meet the standards in the rule because they will have to meet the more stringent
NSPS.
Comment #17: It is our understanding that MCAQD is considering adding a
provision to Rule 322 to require owners and operators to minimize the time spent at
idle or holding at low load levels for any steam generating unit or stationary gas turbine
to which the rule applies. Such a requirement would be inappropriate and, because it
creates an incentive to operate at higher load than necessary, is not environmentally
beneficial. As a result, [our company] recommends that the rule not impose
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operational limits other than the requirements for good combustion practices in
Section 306.
Response #17: The MCAQD is not adding a provision to Rule 322 to require owners
and operators to minimize the time spent at idle or holding at low load levels for any
steam generating unit or stationary gas turbine to which the rule applies.
Comment #18: Sections 306.1 through 306.3 of the current rule establish a
presumptive NOx RACT limit of 42 ppmv, on a dry basis corrected to 3% oxygen,
equivalent to 0.051 lb/MMBtu, for electric utility steam generating units while burning
natural gas and 65 ppmv, on a dry basis corrected to 3% oxygen, equivalent to 0.083
lb/MMBtu, for electric utility steam generating units while burning oil. This
presumptive NOx RACT limit applies to both existing and new steam generating
units, including the existing boilers associated with Units 1 through 3 at Agua Fria
Generating Station. As it pertains to existing units, this limit is unnecessarily stringent
and should be relaxed. A more appropriate presumptive NOx RACT limit for existing
electric utility steam generating units is that in the Texas NOx RACT rule approved by
EPA in April 2019: 0.26 lb/MMBtu (HHV), rolling 24-hour average, and 0.20
lb/MMBtu (HHV), 30-day rolling average, while burning natural gas. 30 TAC §
117.1205(a). 0.30 lb/MMBtu (HHV), rolling 24-hr average, while burning only fuel oil.
30 TAC § 117.1205(c).
Response #18: The MCAQD is proposing to revise the NOx RACT emission limit
for existing steam generating units to 0.1 lb/MMBtu. This limit is consistent with what
has been approved as RACT in other jurisdictions (including Pennsylvania and New
York). In addition, the MCAQD discussed this limit with representatives from EPA
Region 9 and they have indicated the limit is approvable for existing steam generating
units.
Comment #19: Partial Exemption for Low Use EGUs - MCAQD is justified in
retaining the categorical partial exemption [Section 104.4] as currently codified because
control of NOx emissions from electric utility steam generating units and electric
utility stationary gas turbines with calendar year annual capacity factor equal to or less
than 10 percent is not cost effective as shown in Exhibits A and B to these comments.
It is our understanding that MCAQD is considering adding to the rule, in lieu of the
categorical partial exemption, case-by-case RACT requirements for electric utility
steam generating units and electric utility stationary gas turbines with calendar year
annual capacity factor equal to or less than a unit-specific threshold.
Response #19: The MCAQD is proposing to retain the partial exemption for low use
EGUs; however, the MCAQD is proposing to modify the exemption to include a
requirement to obtain approval from the Control Officer and Administrator to operate
under the exemption and a requirement to operate under an annual heat input limit
corresponding to the 10 percent calendar year annual capacity factor. The MCAQD
removed the case-by-case RACT requirements for electric utility steam generating
units and electric utility stationary gas turbines previously listed in the draft rule.
Comment #20: Alternative RACT NOx: [Our company] strongly encourages
MCAQD to retain the categorical partial exemption as currently codified. If MCAQD
proceeds to remove this provision, then a revised rule must include alternative RACT
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requirements for Units 1 through 6 at Agua Fria Generating Station and Units 4
through 6 at Kyrene Generating Station because the emission limitations in Section
306.1 do not represent NOx RACT for these units. For each of these units, in any
calendar year in which the annual capacity factor is equal to or less than 10 percent,
RACT should require [our company] maintain and operate the unit in accordance with
manufacturer’s specifications.
Response #20: As mentioned above, the MCAQD is proposing to retain the partial
exemption for low use EGUs; however, the MCAQD is proposing to modify the
exemption to include a requirement to obtain approval from the Control Officer and
Administrator to operate under the exemption and a requirement to operate under an
annual heat input limit corresponding to the 10 percent calendar year annual capacity
factor.
Comment #21: [Our company] recommends that MCAQD revise the purpose
statement in Section 101 to inform the regulated community that Rule 322 satisfies
NOx RACT requirements under the federal Clean Air Act.
Response #21: The MCAQD does not have the authority to state Rule 322 satisfies
NOx RACT requirements under the federal Clean Air Act. The U.S. Environmental
Protection Agency (EPA) holds this authority.
Comment #22: Section 201 defines the “annual capacity factor” to mean either a heat
input-based ratio or an electric output-based ratio. Section 104.4 establishes a partial
exemption from certain rule requirements for units with calendar year annual capacity
factor equal to or less than 10 percent. For any given unit, in a given calendar year, the
heat input-based capacity factor is different from its electric output-based capacity
factor because efficiency varies with load. These provisions must be revised to clarify
whether the exemption threshold is based on heat input-based capacity factor or
electric output-based capacity factor.
Response #22: The MCAQD is proposing to clarify the exemption threshold is based
on heat-input based capacity factor by revising the definition as follows:
ANNUAL CAPACITY FACTOR: The ratio between the actual heat input to a
stationary gas turbine or steam generating unit from the fuels burned during a calendar
year and the potential heat input to the stationary gas turbine or steam generating unit
had it been operated for 8,760 hours at the maximum rated heat input capacity.
Comment #23: It is our understanding that MCAQD is considering revising the
definition of the term “Continuous Emissions Monitoring System (CEMS”), currently
codified at Section 204, to refer to systems which “continuously sample and analyze.”
This revision would be inappropriate, as CEMS perform periodic, not continuous,
sampling and analysis. (See, for example, 40 CFR § 75.10(d)(1), providing that CEMS
required under the Acid Rain program must be “capable of completing a minimum of
one cycle of operation (sampling, analyzing, and data recording) for each successive
15-min interval.”) SRP suggests adopting the definition at A.A.C. R18-2-101 or the
nearly identical definition in the federal Clean Air Act at § 402(7).
Response #23: The MCAQD is proposing to revise the definition as follows:
CONTINUOUS EMISSION MONITORING SYSTEM (CEMS): The total
equipment required to sample, analyze, measure, and provide a permanent record of
25

emissions by means of readings recorded at least once every 15 minutes (using an
automated data acquisition and handling system (DAHS)).
Comment #24: [Our company] recommends revising the definition of the term
“Electric Utility Steam Generating Unit” to clarify that, for purposes of the NOx
RACT emission limitations, duct burners and heat recovery steam generators which
are components of a combined cycle gas turbine are not considered Electric Utility
Steam Generating Units.
Response #24: The MCAQD has considered your comment and will not be revising
the definition of the term “Electric Utility Steam Generating Unit”; however, the
MCAQD is proposing to revise the term “Combined Cycle Gas Turbine” to
“Combined Cycle Turbine System” and revise the definition as follows:
COMBINED CYCLE TURBINE SYSTEM: A type of stationary gas turbine wherein
heat from the turbine exhaust is recovered by a steam generating unit, with or without
supplemental heat (i.e. duct burner), to make steam for use in a steam-electric turbine.
In addition, the MCAQD is proposing to add the term Combined Cycle Turbine
System to Section 306.1c of the draft rule to clarify which NOx RACT emission limits
a combined cycle turbine system is subject to.
Comment #25: The rule includes numerous references to the term “heat input.” With
the exception of Section 102.2, relating to applicability criteria for stationary gas
turbines, these references are ambiguous as to whether higher heating value (HHV) or
lower heating value (LHV) is intended. In particular, Section 102.1, relating to
applicability criteria for steam generating units, is silent as to whether the threshold is
based on HHV or LHV. Each such reference to the term “heat input” must be revised
to clarify whether the required measurement is based on HHV or LHV.
Response #25: The MCAQD is proposing to clarify the term “heat input” by adding
the phrase “based upon the lower heating value of the fuel” at the end of Section
102.1.
Comment #26: It is our understanding that MCAQCD is considering adding to
Section 309 an additional notification provision requiring an owner or operator to
report the end of emergency fuel use within one business day. The current rule already
requires initial notification within 24 hours after declaration of the emergency that
necessitates use of emergency fuel and a follow-up written report within 48 hours after
commencing use of emergency fuel. These notification requirements are sufficient.
Three reporting requirements for a single, short-term event is overly burdensome and
is unnecessary to enforce the 168 hour/year emergency fuel use restriction. MCAQD
should retain only the 24 hour written report requirement, or the end of emergency
requirement, not both. Requiring end of event reporting is unnecessary because total
hours can be reported with Part 70 semi-annual monitoring and compliance reports.
Response #26: The MCAQD is proposing to add an additional notification provision
requiring an owner or operator to report the end of emergency fuel use within one
business day in Section 309 and is not planning to remove any existing notification
requirements. The MCAQD does not consider the reporting requirements to be overly
burdensome.
26

Comment #27: Section 504 includes numerous citations to EPA test methods
incorporated by reference, in each case referring to “40 CFR 60, Appendix A.” The
test methods in the appendices to part 60 were recodified in 2002. The correct
citations are as follows:
Methods 1 through 2D are in 40 CFR 60, appendix A-1
Methods 3-3C are in 40 CFR 60, appendix A-2
Methods 4-5 are in 40 CFR 60, appendix A-3
Methods 7-10 are in 40 CFR 60, appendix A-4
Method 20 is in 40 CFR 60, appendix A-7.
Response #27: The MCAQD is proposing to revise Section 504 to correct the
citations as indicated by the commenter.
Comment #28: It is our understanding that MCAQCD is considering adding a
provision to Section 503 requiring that a CEMS used to demonstrate compliance with
NOx RACT emission limitations be operated in accordance with either 40 CFR part
60 or 40 CFR part 75. [Our company] recommends that this provision include a
statement to clarify that, if the CEMS is operated in accordance with 40 CFR part 75,
the missing data substitution procedures in part 75 do not apply for purposes of Rule
322.
Response #28: The MCAQD considered your proposed clarification but has
determined it may cause more confusion than clarity and, for this reason, the MCAQD
is not going to include it.
Comment #29: Section 503 - Revise to clarify that, for any unit for which a CEMS is
used to demonstrate compliance with the NOx or CO emission limitation in Section
306 or Section 307, respectively, excess emissions are defined as any period during
which the 24-hour average emission rate as measured using CEMS exceeds the
applicable numeric emission limit. The current (November 2016) rule is ambiguous
regarding averaging time, particularly with respect to Section 307.
Response #29: MCAQD is proposing to add the following subsection to Section 503:
CEMS: An owner or operator using a CEMS to demonstrate compliance with Section
302, 306, or 307 shall install, operate, calibrate, maintain, and test the CEMS in
accordance with 40 CFR Part 60 or 40 CFR Part 75.
a. Excess emissions for Section 306 are defined as any period during which the 24-
hour rolling average emission concentration exceeds the applicable numeric
emission limits.
b. Excess emissions for Section 307 are defined as any period during which the 30-
operating day rolling average emission concentration exceeds the applicable
numeric emission limits.
Comment #30: Section 503 - Revise to clarify that, for any unit for which a CEMS is
used to demonstrate compliance with the NOx or CO emission limitation in Section
306 or Section 307, respectively, annual performance tests are not required.
Response #30: The MCAQD is proposing to add language to Section 503 to clarify
any equipment which uses a CEMS to demonstrate compliance with the NOx and CO
27

emission limitation in Section 306 or Section 307 will not be required to perform an
annual performance test.
Comment #31: Section 503 - Revise to provide for reduced frequency of
performance testing for units for which compliance has been consistently established.
For example, after two consecutive annual performance tests demonstrate that the unit
is complying with the NOx RACT requirement, testing should be required no more
than once every five years. EPA approved a similar RACT requirement into the SIP
for North Carolina.
Response #31: The MCAQD is proposing to add language to Section 503 to provide
for reduced frequency testing for units for which the emission result from the
performance test is less than or equal to 75 percent of the emission limit for the unit.
The language is similar to that in NSPS KKKK. The proposed language reads as
follows:
b. If the NOx emission result from the performance test is less than or equal to 75
percent of the NOx emission limit, you may reduce the frequency of subsequent
performance tests to once every 2 years (no more than 26 calendar months
following the previous performance test). If the results of any subsequent
performance test exceed 75 percent of the NOx emission limit, you must resume
annual performance tests.
The MCAQD is proposing similar language for CO testing requirements as well.
Comment #32: In Section 503 and in any other provision of the rule in which a
reference test method is prescribed, add language allowing for use of the provision in
Section 504 allowing use of an alternative test method upon prior approval from the
Control Officer. For example, if a provision is added to Section 503 prescribing use of
Method 7E, it must allow for use of an alternative test method approved for use in
accordance with Section 504.
Response #32: The MCAQD has considered your comment; however, the EPA will
not approve a rule which contains Control Officer discretion.
Comment #33: [Our company] recommends that MCAQD add transition provisions
to Rule 322 to clarify compliance obligations and effective date in light of the
numerous versions of the rule. Specifically, in order to avoid imposing unnecessary
obligations on [our company] and similarly situated owners and operators of stationary
sources in the event the next version of the rule is disapproved by EPA, [our
company] recommends that the planned revisions to the rule become effective upon
approval by EPA. In addition, [our company] recommends that MCAQCD add a
clarifying statement to the rule indicating that no new compliance demonstration is
required for a unit that demonstrated compliance with the same substantive
requirement in the current (November 2016) version of the rule.
Response #33: Rule 322 will become effective upon adoption by the Maricopa
County Board of Supervisors. The MCAQD anticipates submitting the rule to the
EPA shortly after adoption and anticipates the EPA will act on the rule in a short
timeframe. As this is a new version Rule 322 with new requirements, the MCAQD is
not planning to add language stating no new compliance demonstration is required for
28

a unit that demonstrated compliance with the same substantive requirement in the
current (November 2016) version of the rule.
EXACT WORDING OF THE RULE Return to list of attachments
MARICOPA COUNTY
AIR POLLUTION CONTROL REGULATIONS
REGULATION III - CONTROL OF AIR CONTAMINANTS
RULE 322
POWER PLANT OPERATIONS
INDEX
SECTION 100 – GENERAL
101 PURPOSE
102 APPLICABILITY
103 EXEMPTIONS
104 PARTIAL EXEMPTIONS
SECTION 200 – DEFINITIONS
201 ANNUAL CAPACITY FACTOR
202 COGENERATION STEAM GENERATING UNIT
203 COMBINED CYCLE GAS TURBINE SYSTEM
204 COMBUSTION CONTROL SYSTEM
204 205 CONTINUOUS EMISSION MONITORING SYSTEM (CEMS)
205 206 COOLING TOWERS
206 CORRECTIVE ACTION PLAN (CAP)
207 DISTILLATE OIL
208 207 DRIFT
209 208 DRIFT ELIMINATOR
210 209 DRIFT RATE
211 210 ELECTRIC UTILITY STATIONARY GAS TURBINE
212 211 ELECTRIC UTILITY STEAM GENERATING UNIT
213 212 EMERGENCY FUEL
214 EMERGENCY STANDBY UNIT
215 213 EMISSION CONTROL SYSTEM (ECS)
216 214 FOSSIL FUEL
29

217 215 FUEL SWITCHING STARTUP PROCESS
218 216 HEAT INPUT
219 217 HIGHER HEATING VALUE (HHV) OR GROSS HEATING VALUE
218 LOW SULFUR OIL
220 219 LOWER HEATING VALUE (LHV) OR NET HEATING VALUE
220 NATURAL GAS
221 NATURAL GAS CURTAILMENT
222 OPACITY
223 OPERATING DAY
224 OPERATING HOUR
224 225 PARTICULATE MATTER EMISSIONS
226 PARTS PER MILLION BY VOLUME DRY (PPMVD)
225 227 PEAK LOAD
226 228 POWER PLANT OPERATION
227 229 RATED HEAT INPUT CAPACITY
228 230 REGENERATIVE CYCLE GAS TURBINE
229 RESIDUAL OIL
230 231 SIMPLE CYCLE GAS TURBINE
231 232 STATIONARY GAS TURBINE
232 STEADY STATE
233 SULFUR OXIDES (SOX)
234 THIRTY (30) OPERATING DAY ROLLING AVERAGE
235 THREE (3) HOUR ROLLING AVERAGE
236 235 TOTAL DISSOLVED SOLIDS (TDS)
236 TWENTY-FOUR (24) HOUR ROLLING AVERAGE
237 ULTRA LOW SULFUR OIL DIESEL
238 UNCOMBINED WATER
239 WASTE DERIVED FUEL GAS
SECTION 300 – STANDARDS
301 LIMITATIONS – PARTICULATE MATTER
302 GOOD COMBUSTION PRACTICES FOR TURBINES
303 COOLING TOWERS
304 LIMITATIONS – OPACITY
30

305 LIMITATIONS – SULFUR IN FUEL
306 LIMITATIONS – NITROGEN OXIDES (NOX)
307 LIMITATIONS – CARBON MONOXIDE
308 REQUIREMENTS FOR ECS AND ECS MONITORING EQUIPMENT
309 EMERGENCY FUEL USE NOTIFICATION
SECTION 400 – ADMINISTRATIVE REQUIREMENTS
401 IN EXISTENCE AND IN COMPLIANCE
402 IN EXISTENCE AND NON-COMPLIANT
403 EMERGENCY STANDBY UNITS
SECTION 500 – MONITORING AND RECORDS
501 RECORDKEEPING AND REPORTING
502 RECORDS RETENTION
503 COMPLIANCE DETERMINATION DEMONSTRATION
504 COMPLIANCE DETERMINATION-TEST METHODS INCORPORATED BY
REFERENCE
31

Adopted 07/02/2003; Revised 10/17/2007; Revised 11/02/2016; Revised MM/DD/YYYY
MARICOPA COUNTY
AIR POLLUTION CONTROL REGULATIONS
REGULATION III - CONTROL OF AIR CONTAMINANTS
RULE 322
POWER PLANT OPERATIONS
SECTION 100 – GENERAL
101 PURPOSE: To limit the discharge of nitrogen oxides, sulfur oxides, particulate matter and
carbon monoxide emissions into the atmosphere from stationary fossil-fuel-fired equipment
at electric utility stationary gas turbines, stationary fossil-fuel-fired electric utility steam
generating units, or and stationary fossil-fuel-fired cogeneration steam generating units and
to limit particulate matter emissions from cooling towers associated with this equipment.
102 APPLICABILITY: This rule applies to the following types of equipment that burn fossil
fuel:
102.1 Each electric utility steam generating unit or cogeneration steam generating unit used
to generate electric power that has a rated heat input capacity of equal to or greater
than or equal to 100 million (MM) British thermal units per hour (Btu/hour) (29
megawatts (MW)) based upon the lower heating value of the fuel.
102.2 Each electric utility stationary gas turbine with a rated heat input capacity at peak load
equal to or greater than or equal to 10 MMBtu/hour (2.9 MW) based upon the lower
heating value of the fuel.
102.3 Each cooling tower associated with the type of equipment listed in Sections 102.1 and
102.2 of this rule.
102.4 NSPS & NESHAP: In addition to this rule, facilities may be subject to New Source
Performance Standards (NSPS) in Rule 360 and/or National Emission Standards for
Hazardous Air Pollutants (NESHAP) in Rule 370 of these rules.
103 EXEMPTIONS: This rule shall not apply to the following types of equipment:
103.1 Combustion equipment associated with nuclear power plant operations; or
103.2 Reciprocating internal combustion equipment engines.
104 PARTIAL EXEMPTIONS:
104.1 Stationary gas turbines that meet any of the criteria listed below are exempt from
Sections 301.1, 301.2, 306, 307, 308.4 and 501.4, 503.3, 503.4, 503.5, and 503.6 of
this rule:
a. Used for fire-fighting
b. Used for flood control
c. Engaged by manufacturers in research and development of equipment for either
gas turbine emission control techniques or gas turbine efficiency improvements
32

104.2 Any While firing emergency fuel during a natural gas curtailment or natural gas
emergency, any equipment listed in Section 102 of this rule that is normally fired
with natural gas, as allowed by a permit issued by the Control Officer for that source,
is exempt from Sections 301.1, 301.2, 306, 307, 308.4, 400 and 501.4, 503.3, 503.4,
503.5, and 503.6 of this rule while firing emergency fuel. This exemption shall not
exceed 168 hours per calendar year per combustion unit, excluding hours of
operation for testing, reliability, training and maintenance.
104.3 Any While firing emergency fuel for purposes of testing, reliability, training and
maintenance, any equipment listed in Section 102 of this rule that is normally fired
with natural gas only fires emergency fuel for 36 cumulative hours per year or less,
per unit for testing, reliability, training, and maintenance purposes as allowed by a
permit issued by the Control Officer for that source, is exempt from Sections 301.1,
301.2, 306, 307, 501.4, 308.4, and 400 503.3, 503.4, 503.5, and 503.6 of this rule. This
exemption shall not exceed 36 hours per calendar year per combustion unit,
excluding hours of operation during natural gas curtailments and natural gas
emergencies.
104.4 Any equipment listed in Section 102 of this rule that operates at or below 10 percent
calendar year annual capacity factor, and meets the requirements in 104.4 a, b, and c
is exempt from Sections 306, and 307, 308.4 and 400 of this rule.
a. An owner or operator must submit a RACT analysis to the Control Officer and
the Administrator demonstrating conventional commercially-available control
technology is not technically and/or economically feasible and obtain approval
from the Control Officer and Administrator to operate under the exemption.
(1) For equipment for which a RACT analysis was submitted prior to [date of
rule adoption], upon Control Officer approval, equipment may begin to
operate under the exemption until the Administrator approves or denies
operation under the exemption. If the Administrator denies approval to
operate under the exemption, the equipment will become subject to the
emission limits in Sections 306 and 307.
(2) For equipment for which a RACT analysis is submitted on or after [date of
rule adoption], equipment may begin to operate under the exemption upon
approval from the Control Officer and the Administrator.
b. All equipment operated under this exemption shall have an annual heat input
limit associated with that equipment that corresponds to the 10 percent calendar
year annual capacity factor. The annual heat input limit shall be calculated by
multiplying the equipment’s maximum heat input rate (MMBtu per hour) by 876
hours. An owner or operator with equipment approved to operate under the
exemption shall submit an application to modify the permit associated with the
equipment to include an annual heat input limit within 60 days of the Control
Officer’s approval.
c. To demonstrate compliance with the heat input limit an owner or operator shall
multiply the higher heating value (MMBtu/mass or MMBtu/volume of gas) by
the fuel use (mass or volume of gas).
33

SECTION 200 – DEFINITIONS: For the purpose of this rule, the following definitions shall
apply, in addition to those definitions found in Rule 100 (General Provisions and Definitions) of
these rules. In the event of any inconsistency between any of the Maricopa County air pollution
control rules, the definitions in this rule take precedence.
201 ANNUAL CAPACITY FACTOR: The ratio between the actual heat input to a boiler or
process heater stationary gas turbine or steam generating unit from the fuels burned during a
calendar year and the potential heat input to the boiler or process heater stationary gas
turbine or steam generating unit had it been operated for 8,760 hours during a year at the
maximum steady state design rated heat input capacity or the ratio between the actual
electrical output of a machine or equipment during a calendar year and the potential
electrical output of a machine or equipment had it been operated for 8,760 hours during a
year at full nameplate capacity.
202 COGENERATION STEAM GENERATING UNIT: A steam or hot water generating
unit that simultaneously produces both electrical (or mechanical) and useful thermal energy
(such as heat or steam) from the same primary energy source and supplies more than one-
third of its potential electric output to any utility power distribution system for sale.
203 COMBINED CYCLE GAS TURBINE SYSTEM: A type of stationary gas turbine
wherein heat from the turbine exhaust is recovered by a steam generating unit, with or
without supplemental heat (i.e. duct burner), to make steam for use in a steam-electric
turbine.
204 COMBUSTION CONTROL SYSTEM: Equipment or technology that suppress NOX
formation during combustion of fossil fuels, including but not limited to, water injection or
low-NOX burners.
204 205 CONTINUOUS EMISSION MONITORING SYSTEM (CEMS): The total
equipment required to sample and analyze emissions or process parameters such as opacity,
nitrogen oxide, and oxygen or carbon dioxide, and to provide a permanent data record. The
total equipment required to sample, analyze, measure, and provide a permanent record of
emissions by means of readings recorded at least once every 15 minutes (using an automated
data acquisition and handling system (DAHS)).
205 206 COOLING TOWERS: Open water recirculating devices that use fans or natural draft to
draw or force air through the device to cool water by evaporation and direct contact.
206 CORRECTIVE ACTION PLAN (CAP): A methodical procedure that is used to evaluate
and correct a turbine operational problem and that includes, at a minimum, improved
preventative maintenance procedures, improved ECS operating practices, possible
operational changes, and progress reports.
207 DISTILLATE OIL: A petroleum fraction of fuel oil produced by distillation that complies
with the specifications for fuel oil numbers 1 or 2, as defined by the American Society for
Testing and Materials in ASTM D396-01, “Standard Specification for Fuel Oils.”
208 207 DRIFT: Water droplets, bubbles, and particulate matter that escape from cooling tower
stacks.
34

209 208 DRIFT ELIMINATOR: Device used to remove drift from cooling tower exhaust air, thus
reducing water loss by relying on rapid changes in velocity and direction of air-droplet
mixtures by impaction on eliminator passage surfaces. A drift eliminator is not categorized as
an emission control system but is an inherent part of the cooling tower's design
requirements.
210 209 DRIFT RATE: Percentage (%) of circulating water flow rate that passes through a drift
eliminator on a cooling tower.
211 210 ELECTRIC UTILITY STATIONARY GAS TURBINE: Any stationary gas turbine
that is constructed for the purpose of supplying more than 1/3 of its potential electric
output capacity to any utility power distribution system for sale. Both simple and combined
cycle gas turbines are types of electric utility stationary gas turbines.
212 211 ELECTRIC UTILITY STEAM GENERATING UNIT: Any steam electric generating
unit that uses equipment that combusts fossil fuel to generate steam that is used to drive an
electrical generator and is constructed for the purpose of supplying more than one-third of
its potential electric output capacity and more than 25 MW electric output to any utility
power distribution system for sale.
213 212 EMERGENCY FUEL: Fuel fired only during circumstances such as natural gas
emergency, natural gas curtailment, or breakdown of delivery system such as an unavoidable
interruption of supply that makes it impossible to fire natural gas in the unit. Fuel is not
considered emergency fuel if it is used to avoid either peak demand charges or high gas
prices during on-peak price periods or due to a voluntary reduction in natural gas usage by
the power company. For the purposes of this definition, emergency fuel also includes fuel
used for purposes of testing, reliability, training, and maintenance.
214 EMERGENCY STANDBY UNIT: A stationary gas turbine that is limited by permit
condition to be operated only as a mechanical or electrical power source for a facility when
the primary power source for a facility has been rendered inoperable due to failure beyond
the reasonable control of the operator, except due to power interruption pursuant to an
interruptible power supply agreement. Electricity generated by such a unit cannot be sold.
215 213 EMISSION CONTROL SYSTEM (ECS): A system approved in writing by the Control
Officer, designed and operated in accordance with good engineering practice to reduce
emissions. Post-combustion systems that are designed and operated in accordance with good
engineering practice to reduce emissions from combustion equipment. A combustion
control system is not an emission control system.
216 214 FOSSIL FUEL: Naturally occurring carbonaceous substances from the ground such as
natural gas, petroleum, coal and any form of solid, liquid, or gaseous fuel derived from such
material for the purpose of creating energy.
217 215 FUEL SWITCHING STARTUP PROCESS: The act of changing from one type of fuel
to a different type of fuel.
35

218 216 HEAT INPUT: Heat derived from the combustion of fuel, not including the heat input
from preheated combustion air, recirculated flue gases, or exhaust gases from other sources,
such as gas turbines, internal combustion engines, and kilns.
219 217 HIGHER HEATING VALUE (HHV) OR GROSS HEATING VALUE: The amount
of heat produced by the complete combustion of a unit quantity of fuel determined by a
calorimeter wherein the combustion products are cooled to the temperature existing before
combustion and all of the water vapor is condensed to liquid.
218 LOW SULFUR OIL: Fuel oil containing less than or equal to 0.05% by weight of sulfur.
220 219 LOWER HEATING VALUE (LHV) OR NET HEATING VALUE: The amount of
heat produced by the complete combustion of a unit quantity of fuel determined by a
calorimeter wherein the combustion products are cooled to the temperature existing before
combustion and all of the water vapor remains as vapor and is not condensed to a liquid.
The value is computed from the higher heating value by subtracting the water originally
present as moisture and the water formed by combustion of the fuel.
220 NATURAL GAS: A naturally occurring fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane) produced in geological formations beneath the earth’s surface that
maintains a gaseous state at standard atmospheric temperature and pressure under ordinary
conditions and contains 20 grains or less of total sulfur per 100 standard cubic feet.
221 NATURAL GAS CURTAILMENT: An interruption in natural gas service, such that the
daily fuel needs of a combustion unit cannot be met with natural gas available due to one of
the following reasons, beyond the control of the owner or operator:
221.1 An unforeseeable failure or malfunction, not resulting from an intentional act or
omission that the governing state, federal or local agency finds to be due to an act of
gross negligence on the part of the owner or operator; or
221.2 A natural disaster; or
221.3 The natural gas is curtailed pursuant to governing state, federal or local agency rules
or orders; or
221.4 The serving natural gas supplier provides notice to the owner or operator that, with
forecasted natural gas supplies and demands, natural gas service is expected to be
curtailed pursuant to governing state, federal or local agency rules or orders.
222 OPACITY: A condition of the ambient air, or any part thereof, in which an air contaminant
partially or wholly obscures the view of an observer.
223 OPERATING DAY: A 24-hour period between 0000 and 2359 during which any fuel is
combusted at any time in the unit. It is not necessary for fuel to be combusted continuously
for the entire 24-hour period.
224 OPERATING HOUR: A clock hour during which a unit combusts any fuel, either for part
of the hour or for the entire hour.
36

224 225 PARTICULATE MATTER EMISSIONS: Any and all particulate matter emitted to the
ambient air as measured by applicable state and federal test methods.
226 PARTS PER MILLION BY VOLUME DRY (PPMVD): A unit of proportion used to
express concentration that is corrected to a dry basis.
225 227 PEAK LOAD: 100% of the manufacturer’s design capacity of a gas turbine at 288° Kelvin,
60% relative humidity, and 101.3 kilopascals pressure (ISO standard day conditions).
226 228 POWER PLANT OPERATION: An operation whose purpose is to supply more than
one-third of its potential electric output capacity to any utility power distribution system for
sale.
227 229 RATED HEAT INPUT CAPACITY: The heat input capacity in million Btu/hr. as
specified on the nameplate of the combustion unit. If the combustion unit has been altered
or modified such that its maximum heat input is different than the heat input capacity on the
name plate, the maximum heat input shall be considered the rated heat input capacity.
228 230 REGENERATIVE CYCLE GAS TURBINE: Any stationary gas turbine that recovers
thermal energy from the exhaust gases and utilizes the thermal energy to preheat air prior to
entering the combustion unit.
229 RESIDUAL OIL: The heavier oils that remain after the distillate oils and lighter
hydrocarbons are distilled off in refinery operations. This includes crude oil or fuel oil
numbers 1 and 2 that have a nitrogen content greater than 0.05 % by weight, and all fuel oil
numbers 4, 5, and 6, as defined by the American Society of Testing and Materials in ASTM
D396-01, “Standard Specifications for Fuel Oils.”
230 231 SIMPLE CYCLE GAS TURBINE: Any stationary gas turbine that does not recover heat
from the gas turbine exhaust gases to preheat the inlet combustion air to the gas turbine, or
that and does not recover heat from the gas turbine exhaust gases to heat water or generate
steam.
231 232 STATIONARY GAS TURBINE: Any simple cycle gas turbine, regenerative gas turbine, or
any gas turbine portion of a combined cycle gas turbine system that is not self-propelled or
that is attached to a foundation.
232 STEADY STATE: A safe, stable megawatt load at which a unit with equipment in normal
operating conditions is capable of being held for an extended period of time, without
creating an unsafe or unstable operating condition.
233 SULFUR OXIDES (SOX): The sum of the oxides of sulfur emitted from the flue gas from a
combustion unit that are directly dependent upon the amount of sulfur in the fuel used.
234 THIRTY (30) OPERATING DAY ROLLING AVERAGE: An arithmetic mean or
average of all hourly emission concentrations rates for 30 successive combustion operating
days and calculated by a CEMS at the conclusion of each operating day for the previous 30
operating days.
37

235 THREE (3) HOUR ROLLING AVERAGE: An arithmetic mean or average of the most
recent three one (1) hour tests, or an arithmetic mean or average over a period of three hours
which is newly calculated with each hourly measurement.
236 235 TOTAL DISSOLVED SOLIDS (TDS): The amount of concentrated filterable matter
reported in milligrams/liter (mg/l) or parts per million (ppm), as determined by an applicable
method in the Standard Methods for the Examination of Water and Wastewater, a
conductivity/TDS meter, or ASTM D5907.
236 TWENTY-FOUR (24) HOUR ROLLING AVERAGE: The arithmetic mean of all hourly
emission concentrations measured during the previous 24 operating hours.
237 ULTRA LOW SULFUR OIL DIESEL: Fuel oil containing less than or equal to 0.0015 %
sulfur by weight.
238 UNCOMBINED WATER: Condensed water containing no more than analytical trace
amounts of other chemical elements or compounds vapor or steam.
239 WASTE DERIVED FUEL GAS: A gaseous fuel that is generated from the biodegradation of
solid or liquid waste including, but not limited to, digester gas and landfill gas.
SECTION 300 – STANDARDS
301 LIMITATIONS – PARTICULATE MATTER: An owner or operator of any equipment
listed in Section 102.1 or 102.2 of this rule shall burn only natural gas except when firing
emergency fuel per Sections 104.2 and 104.3 of this rule. An owner or operator may burn a
fuel other than natural gas for non-emergency purposes providing that the fuel shall not
cause to be discharged more than 0.007 lbs. of particulate matter per MMBtu. The use of a
fuel other than natural gas for non-emergency purposes shall be approved by the Control
Officer in an air pollution control permit prior to usage.
301.1 Fuel Type: An owner or operator of any combustion equipment listed in Section 102
shall burn only natural gas except when firing emergency fuel per Sections 104.2 and
104.3 of this rule. An owner or operator may burn a fuel other than natural gas for
non-emergency purposes providing that the fuel shall not cause to be discharged
more than 0.007 lbs. of particulate matter per MMBtu during steady state operations,
demonstrated and documented through performance testing of this alternate fuel
using Test Method 5. This usage of different fuels other than natural gas shall be
approved by the Control Officer prior to usage.
301.2 Particulate Matter Testing A backhalf analysis shall be performed, using Reference
Method 202 referenced in Section 504.6 of this rule, each time a compliance test for
particulate matter emissions to meet the standard in Section 301.1 of this rule is
performed using Test Method 5.
302 GOOD COMBUSTION PRACTICES FOR TURBINES: An owner or operator of any
stationary gas turbine listed in Section 102.2 of this rule shall, regardless of fuel type, use
operational practices recommended by the manufacturer to ensure good combustion
control.
38

302.1 Good combustion practices shall be demonstrated by maintaining the manufacturer’s
recommended maintenance practices onsite and available to the Control Officer
upon request, by maintaining records of all maintenance activities conducted on the
turbines, and by conducting performance tests as described in Section 503 (unless
exempt from Sections 306 and 307 under the exemption in Section 104.4).
302.2 For stationary gas turbines with a CEMS able to demonstrate compliance with the
applicable emission limits in Sections 306 and 307, good combustion practices may
be demonstrated through continuous compliance with the applicable emission limits
in Sections 306 and 307.
During steady state operations, an owner or operator of any stationary gas turbine listed in
Section 102.2 of this rule , regardless of fuel type, shall use operational practices
recommended by the manufacturer and parametric monitoring to ensure good combustion
control as listed below. One of the following procedures may be used. For the purposes of
this rule, if a CEMS or another approved monitoring method is used, then the equipment
would be exempt from the requirements of Section 302 of this rule.
302.1 Monitor the maximum temperature differential across the combustion burners or at
locations around the back end of the turbine, dependent upon the particular unit, to
ensure no more than a 100 F difference using a thermocouple. Differential
temperatures across the burners to demonstrate good combustion practices shall be
measured from at least one minute data point during a complete steady state
operating hour. If a valid maximum temperature differential of greater than 100 F is
observed across the burners, investigation and corrective action shall be taken within
three hours to reduce the temperature difference to 100 F or less; or
302.2 If the manufacturer recommends that the maximum numerical temperature
differential to ensure good combustion is a temperature that is greater than 100°F
then proof of this maximum alternate temperature shall be submitted to the Control
Officer. The procedure to measure the maximum temperature differential listed in
Section 302.1 of this rule shall then be followed using this alternate recommended
maximum temperature differential after approval by the Control Officer.
302.3 If the frequency of failure to meet the proper temperature differential of 100°F or to
meet the alternate temperature differential recommended by the manufacturer
reflects a pattern that the turbine is not being operated in a manner consistent with
good combustion practices, then the Control Officer may require the owner or
operator to submit a Corrective Action Plan (CAP).
303 COOLING TOWERS: An owner or operator of a cooling tower associated with applicable
units listed in Section 102.3 of this rule shall:
303.1 Equip the cooling tower with a drift eliminator. The drift eliminator shall not be
manufactured out of wood.
303.2 The Limit the value obtained by multiplying the concentration of Total Dissolved
Solids (TDS) in the cooling tower water multiplied by the percentage of drift rate
shall for the cooling tower drift eliminator such that the product does not exceed the
maximum numerical limit of 20 ppm.
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303.3 Visually inspect the drift eliminator according to the following schedule, as applicable
depending on the configuration of the drift eliminator on a monthly basis only if the
drift eliminator can be viewed safely and does not require an owner or operator to
walk into the tower. If the drift eliminator cannot be safely inspected monthly then
Section 303.4 of this rule shall apply:
a. Monthly, if the drift eliminator can be viewed safely and if the inspection does
not require a person to walk into the cooling tower; or
303.4 b. Visually inspect the drift eliminator for integrity No less than once per year
during a regularly scheduled outage when the cooling tower is not operating, if it
cannot be inspected on a monthly basis the drift eliminator cannot be safely
inspected while the cooling tower is operating. This visual inspection shall be no
less than once per year.
304 LIMITATIONS – OPACITY:
304.1 An owner or operator shall not discharge into the ambient air from any single source
of emissions any air contaminant, other than uncombined water, in excess of 20%
opacity, for any six (6) minute averaging period, except as provided in Section 304.2
of this rule.
304.2 Opacity may exceed the applicable limits established in Section 304.1 of this rule for
up to one hour during the one hour fuel switching startup process; however, opacity
shall not exceed 40% for any six (6) minute averaging period in this one hour period,
provided that the Control Officer finds that the owner or operator has, to the extent
practicable, maintained and operated the source of emissions in a manner consistent
with good air pollution control practices for minimizing emissions. During the one-
hour fuel switching startup process, an owner or operator shall not discharge into the
ambient air from any single source of emissions any air contaminant, other than
uncombined water, in excess of 40% opacity, for any six (6) minute averaging period.
The one-hour period shall begin when the fuel switching startup process begins.
304.3 Determination of whether good air pollution control practices are being used shall
be based on information provided to the Control Officer upon request, which may
include, but is not limited to, the following:
a. Monitoring results.
b. Opacity observations.
c. Review of operating and maintenance procedures.
d. Inspection of the source.
305 LIMITATIONS – SULFUR IN FUEL: An owner or operator of any applicable
equipment listed in Section 102.1 or 102.2 of this rule that burns fuel oil alone or in
combination with any other fuel as either emergency fuel or non-emergency fuel shall use
only either ultra low sulfur diesel oil or low sulfur oil. An owner or operator using waste
derived fuel gas shall use only waste derived fuel gas that contains no more than 0.08%
sulfur by weight, alone or in combination with other fuels.
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306 LIMITATIONS – NITROGEN OXIDES (NOX): An owner or operator of any
applicable equipment listed in Section 102.1 and 102.2 of this rule shall not cause to be
discharged into the atmosphere nitrogen oxides in excess of the following limits:
306.1 RACT Emission Limits:
a. Existing Steam Generating Units: An owner or operator of any equipment listed
in Section 102.1 of this rule that commenced operation prior to (insert date of
rule adoption) shall not cause to be discharged into the atmosphere nitrogen
oxides in excess of 0.1 lb/MMBtu, calculated as nitrogen dioxide, unless the
equipment is operated in compliance with the case-by-case RACT requirements
established in accordance with Section 306.2 of this rule.
b. New Steam Generating Units: An owner or operator of any equipment listed in
Section 102.1 of this rule that commenced operation on or after (insert date of
rule adoption) shall not cause to be discharged into the atmosphere nitrogen
oxides in excess of the following limits, unless the equipment is operated in
compliance with the case-by-case RACT requirements established in accordance
with Section 306.2 of this rule.
(1) 30 ppmvd corrected to 3% oxygen calculated as nitrogen dioxide when
burning gaseous fossil fuel.
(2) 40 ppmvd corrected to 3% oxygen calculated as nitrogen dioxide when
burning liquid fossil fuel.
c. Stationary Gas Turbines and Combined Cycle Turbine Systems: An owner or
operator of any equipment listed in Section 102.2 of this rule shall not cause to
be discharged into the atmosphere nitrogen oxides in excess of the following
limits, unless the equipment is operated in compliance with the case-by-case
RACT requirements established in accordance with Section 306.2 of this rule.
306.1 (1) 42 ppmdv ppmvd corrected to 15% oxygen calculated as nitrogen dioxide
when burning gaseous fossil fuel. During steady state operations, this test
result using EPA Reference Method(s) 7 or other EPA-approved test method
designated by the Control Officer shall be based upon the arithmetic mean of
the results of three test runs. Each test run shall have a minimum sample time
of one hour. If CEMS is used for the compliance demonstration, the
compliance demonstration shall be based upon a 30-day rolling average. Any
source for which the owner or operator submits to the department a case-by-
case reasonably available control technology analysis that is or will be
incorporated in a permit issued by the Control Officer for that source, is
exempt from Sections 306, 308.4, and 400 of this rule.
306.2 (2) 65 ppmdv ppmvd corrected to 15% oxygen calculated as nitrogen dioxide
when burning liquid fossil fuel. During steady state operations, this test result
using EPA Reference Method(s) 7 or other EPA-approved test method
designated by the Control Officer, shall be based upon the arithmetic mean of
the results of three test runs. Each test run shall have a minimum sample time
of one hour. If a CEMS is used for the compliance demonstration, the
compliance demonstration shall be based upon a 30-day rolling average. Any
source for which the owner or operator submits to the department a case-by-
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case reasonably available control technology analysis that is or will be
incorporated in a permit issued by the Control Officer for that source, is
exempt from Sections 306, 308.4, and 400 of this rule.
306.3 The nitrogen oxides concentration shall be measured dry and corrected to 3% oxygen
for electric utility steam generating units and cogeneration steam generating units. The
nitrogen oxides concentration shall be measured dry and corrected to 15% oxygen for
stationary gas turbines and for combined cycle gas turbines, during steady state
operations.
306.2 Case-by-Case RACT Requirements: Nothing in this rule shall prevent the owner
or operator of any equipment listed in Section 102 of this rule from requesting
alternative RACT requirements on a case-by-case basis. An owner or operator shall
be exempt from Section 306.1 if the owner or operator fully complies with
alternative RACT requirements that are approved by the Control Officer and the
Administrator, incorporated into an Air Pollution Control Permit, and approved into
the Arizona State Implementation Plan.
307 LIMITATIONS – CARBON MONOXIDE: An owner or operator of any equipment
listed in Section 102.1 or 102.2 of this rule shall not cause to be discharged into the
atmosphere carbon monoxide (CO) measured in excess of 400 ppmv ppmvd corrected to 15%
oxygen for stationary gas turbines, and corrected to 3% oxygen for steam generating units. at
any time. During steady state operations, this test result, using EPA Reference Method 10 or
other EPA-approved test method designated by the Control Officer and performed during
steady state compliance source testing, shall be based upon the arithmetic mean of the results
of three test runs. Each test run shall have a minimum sample time of one hour. The CO
concentration shall be measured dry and corrected to 3% oxygen for electric utility steam
generating units and cogeneration steam generating units. The CO concentration shall be
measured dry and corrected to 15% oxygen for stationary gas turbines and for combined cycle
gas turbines, during steady state operations.
308 REQUIREMENTS FOR ECS AND ECS MONITORING EQUIPMENT: An
owner or operator of an emission control system (ECS) shall:
308.1 For affected operations which may exceed any of the applicable standards set forth in
Section 300 of this rule, an owner or operator may comply by installing and operating
an emission control system (ECS) or a combustion control system which reduces
emissions to below the applicable standards in Section 300 of this rule.
308.2 308.1 An owner or operator required to use an approved ECS pursuant to this rule shall not
do so without first properly installing, operating, and maintaining in calibration and in
good working order, Properly install, operate, and maintain in calibration and in good
working order devices for indicating temperatures, pressures, transfer rates, rates of
flow, or other operating conditions necessary to determine if air pollution control
equipment an ECS is functioning properly and is properly maintained as described in
an approved Operation and Maintenance (O&M) Plan.
308.3 Operation and Maintenance (O&M) Plan Required for ECS:
a. 308.2 General Requirements: An owner or operator shall provide and maintain Submit to
the Control Officer for approval an Operation and Maintenance (O&M) Plan for any
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ECS, any other emission processing equipment, and any ECS monitoring devices that
are used pursuant to this rule or to an air pollution permit. The O&M Plan shall
include:
a. The manufacturer name, model designation, and serial number for each ECS and
each ECS monitoring device; and
b. Operating parameters that will be monitored to demonstrate continued operation
of the ECS in the manner the ECS was operated during the most recent
performance test; and
c. The manufacturer’s recommended maintenance procedures and frequencies or, if
the manufacturer’s recommended maintenance procedures are not available, a
maintenance plan based on good engineering practices to reduce emissions.
b. Approval by Control Officer: An owner or operator shall submit to the Control
Officer for approval the O&M Plans of each ECS and each ECS monitoring
device that is used pursuant to this rule.
c. 308.3 Initial Plans: An owner or operator who is required to have an O&M Plan pursuant to
this rule shall Fully comply with all elements of the most recent O&M Plans that the
owner or operator has submitted for approval, but which have not yet been approved
submitted to the Control Officer, unless notified by the Control Officer in writing.
Once the initial plan has been approved in writing by the Control Officer, an owner or
operator shall then comply with the approved plan.
d. 308.4 Revisions to Plan: An owner or operator may revise an initial O&M plan by submitting
written revisions to the Control Officer. The owner or operator shall at all times
comply with the latest version of the O&M Plan submitted to the Control Officer.
Submit a revised O&M Plan within 30 business days following receipt of the Control
Officer’s written notice that an O&M Plan for any ECS or any ECS monitoring device
is deficient or inadequate.
e. 308.5 Control Officer Modifications to Plan: After discussion with the owner or operator,
the Control Officer may modify the plan in writing prior to approval of the initial
O&M plan. An owner or operator shall then comply with the plan that has been
modified by the Control Officer. Maintain on-site, in a readily accessible location, the
most recent O&M Plans for each ECS and each ECS monitoring device.
308.4 Emission Compliance Demonstration:
a. An owner or operator of an electric utility stationary gas turbine, electric utility
steam generating unit or cogeneration steam generating unit used to generate
electric power subject to Section 306 of this rule with a heat input of greater than
250 MMBtu/hr, regardless of fuel type, shall install, calibrate, maintain, and
operate a CEMS or conduct stack tests as approved by the Control Officer for
measuring nitrogen oxides. Where nitrogen oxide emissions are monitored by a
CEMS, then a CEMS shall also be required for the measurement of the oxygen
content of the flue gases. All CEMS shall comply with the provisions in 40 CFR
Part 60.
b. An owner or operator of any affected electric utility stationary gas turbine, electric
utility steam generating unit or cogeneration steam generating unit used to generate
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electric power listed above that requires a CEMS for nitrogen oxides that meets
and is continuing to meet the requirements of 40 CFR Part 75 or Part 60 may use
that CEMS to meet the requirements of Section 308.4(a) of this rule.
309 EMERGENCY FUEL USE NOTIFICATION: An owner or operator of an electric utility
stationary gas turbine, electric utility steam generating unit or cogeneration steam generating
unit used to generate electric power that is fired with emergency fuel but is normally fired with
natural gas shall notify the Control Officer verbally no later than 24 hours after declaration of
the emergency that necessitates its use in compliance with Section 104.2 of this rule. This
verbal report shall be followed by a written report within 48 hours of initial emergency fuel
usage. The written report shall also include identification of the nature of the emergency, initial
dates of usage, and the expected dates of usage. Within 1 business day following the end of an
emergency that necessitates the use of emergency fuel, the owner or operator shall submit a
written report that includes the total number of hours the combustion equipment was
operated with emergency fuel.
SECTION 400 – ADMINISTRATIVE REQUIREMENTS
401 IN EXISTENCE AND IN COMPLIANCE: Except as set forth in Section 104.4 of this
rule and the case-by-case RACT analysis of Section 306.1 of this rule, the The owner or
operator of any electric utility stationary gas turbine, electric utility steam generating unit or
cogeneration steam generating unit used to generate electric power in existence on
November 2, 2016 [insert date of rule adoption] and subject to the emission limits in Section
306 of this rule shall submit a Notification of Compliance within 6 months of becoming
subject to Section 306 of this rule. This Notification shall include one of the following
demonstrations: indicate how compliance with the NOX limit has been determined and if
performance testing is required to demonstrate compliance. If performance testing is
required to demonstrate compliance, the Notification shall include a timeline for the test.
Performance test results from a past test may be used for this determination, as long as the
test was conducted within 5 years before November 2, 2016. If compliance under Section
401 of this rule cannot be demonstrated, an owner or operator of any electric utility
stationary gas turbine, electric utility steam generating unit or cogeneration steam generation
unit used to generate electric power shall comply with Section 402 of this rule.
401.1 Demonstration of Compliance with RACT Emission Limits: For each unit that
is in compliance with the RACT emission limits in Section 306.1 of this rule, the
Notification of Compliance shall include results from a performance test conducted
in accordance with Section 503.4 of this rule, or that a CEMS has been installed (to
demonstrate continuous compliance with the RACT emission limits), after [insert
date – one year before rule adoption].
401.2 Demonstration of Compliance with the exemption in Section 104.4: For each
unit that operates at or below 10 percent calendar year annual capacity factor, the
Notification of Compliance shall include records of the annual capacity factor for the
calendar year previous to the year of rule adoption.
402 IN EXISTENCE AND NON-COMPLIANT:
402.1 Increments of Progress – Installation of Air Pollution Control Equipment:
Except as set forth in Section 104.4 of this rule and the case-by-case RACT analysis
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of Section 306.1 of this rule, when air pollution control equipment is required When
an emission control system or a combustion control system will be installed to
achieve compliance with the emission limits in Section 306.1 of this rule, the owner
or operator shall comply with the following increments of progress and be in
compliance with the emission limits by the date specified: in Section 402.2 of this
rule and be in compliance with the emission limits by the date specified in Section
402.2 of this rule.
402.2 Increments of Progress: The owner or operator of any electric utility stationary gas
turbine, electric utility steam generating unit or cogeneration steam generating unit
used to generate electric power subject to the emission limits in Section 306 of this
rule shall comply with the following increments of progress. The Control Officer,
upon the request of the owner or operator, may extend the increments of progress.
The following compliance schedule does not apply to units already compliant with
this rule as of November 2, 2016:
a. Within 18 months of becoming subject to the emission limits in Section 306.1 of
this rule, submit a compliance schedule and permit application to the Control
Officer.
b. Within 36 months of final permit issuance, be fully compliant with the emission
limits in Section 306.1 of this rule and submit to the Control Officer a complete
source test report indicating compliance.
402.3 402.2 Increments of Progress – Removal From Service: The owner or operator of any
combustion unit in existence on November 2, 2016 [insert date of rule adoption] that
is expected to be removed from service within 24 months of becoming subject to
Section 306.1 of this rule shall be exempt from the emission limits in Section 306.1
of this rule if it complies with the following:
a. Within 6 months of becoming subject to the limits in Section 306.1 of this rule,
submit to the Control Officer a notification of proposed removal from service.
b. Within 14 months of submitting notification under Section 402.3(a) 402.2(a) of
this rule, submit to the Control Officer a decommissioning plan and a permit
revision providing that the units will be decommissioned by a certain date.
c. Within 4 months of decommissioning plan and permit revision approval, or
within 24 months after becoming subject to the emission limits in Section 306.1
of this rule, whichever comes first, discontinue operation of the electric utility
stationary gas turbine, electric utility steam generating unit or cogeneration steam
generating unit used to generate electric power, disconnect the fuel supply line(s),
and notify the Control Officer in writing of the removal from service. Operation
of any electric utility stationary gas turbine, electric utility steam generating unit
or cogeneration steam generating unit used to generate electric power beyond 4
months of decommissioning plan and permit revision approval, shall be
conducted in compliance with the emission limits in Section 306 of this rule.
403 EMERGENCY STANDBY UNITS: The owner or operator of any emergency standby unit
in existence prior to November 2, 2016 shall by January 2, 2017, submit to the Control
Officer a notification requesting an exemption from the requirements of Section 300 of this
rule.
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SECTION 500 – MONITORING AND RECORDS
501 RECORDKEEPING AND REPORTING: Any owner or operator subject to this rule
shall comply with the requirements set forth in this section. Any records and data required
by this section shall be kept on site at all times in a consistent and complete manner and be
made available without delay to the Control Officer or his designee upon request. Records
shall consist of the following information:
501.1 Equipment Listed in Section 102 of this Rule: Days and hours of operation, type(s)
of fuel used, amount of fuel(s) used each month, amount of sulfur in the fuel if using
liquid fuel, and the days and hours of operation and documentation of the sulfur
content of any fuel oil combusted (e.g. fuel receipts, contract specifications, pipeline
meter tickets, fuel supplier information, purchase records, or analytical results).
Records of sulfur content shall provide accurate values for the sulfur content of the
fuel based on enforceable test methods approved by the Administrator.
501.2 Cooling Towers: Monthly gravimetric testing reports for TDS in cooling water in the
cooling tower shall be recorded for six months in succession and thereafter quarterly
reports shall be recorded. Results of the monthly or yearly visual inspection of the drift
eliminator shall also be recorded. If the drift eliminator cannot be visually inspected
monthly, then documentation of the physical configuration of the drift eliminator shall
be submitted to the Control Officer to demonstrate that the drift eliminator cannot be
inspected monthly.
501.3 Emergency Fuel Usage: Type and amount of emergency fuel used, dates and hours
of operation using emergency fuel, nature of the emergency or reason for the use of
emergency fuel as stated in Sections 104.2 and 104.3 of this rule. At the end of each
month, calculate the total hours of operation using emergency fuel during natural gas
curtailments and natural gas emergencies, and total hours of operation using
emergency fuel for purposes of testing, reliability, training, and maintenance.
501.4 Non-Emergency Fuel Switching: Monthly records of fuel switching including stop
and start times, monthly records of hours of operation for testing, reliability and
maintenance purposes per Section 104.3 of this rule, and a yearly log total of these
hours. Dates and times, including start and stop times, when any fuel other than
natural gas is combusted for non-emergency purposes, as allowed by Section 301 of
this rule.
501.5 Continuous Emission Monitoring Systems: All CEMS measurements, results of
CEMS performance evaluations, CEMS calibration checks, and adjustments and
maintenance performed on these systems.
501.6 Good Combustion Practices: Measurements of the temperature differential across
the burners of turbines per Section 302 of this rule, results of evaluation and of
corrective action taken to reduce the temperature differential or a finding that the
temperature differential returned to the range listed in Sections 302.1 or 302.2 of this
rule without any action by the owner or operator. For the purposes of this rule, if a
CEMS or other approved monitoring method is used, then the equipment would be
exempt from the requirements of Section 302 of this rule
a. Good combustion practices shall be demonstrated by maintaining the
manufacturer’s recommended maintenance practices onsite and available to the
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Control Officer upon request, by maintaining records of all maintenance activities
conducted on the turbines, and by maintaining records of the test results of
performance tests conducted under Section 503 (unless exempt from Sections 306
and 307 under the exemption in Section 104.4).
b. If using CEMS to demonstrate good combustion practices, results of evaluation
and of corrective action shall be recorded each time the CEMS indicates an
exceedance of the applicable emission limits in Section 306 or 307 of this rule.
c. For units equipped with water or steam injection, the owner or operator shall
maintain continuous records of the water to fuel ratio or the steam to fuel ratio,
unless the owner or operator uses CEMS to demonstrate compliance with the
emission limits in Sections 306 and 307, as applicable.
501.7 Equipment Referenced in Sections 104.4, 306.1, and 306.2: Maintain records of the
annual capacity factor and NOX emissions to demonstrate compliance with Sections
104.4, 306.1, or 306.2 of this rule, as applicable.
502 RECORDS RETENTION: Copies of reports, logs, and supporting documentation required
by the Control Officer shall be retained for at least 5 years. Records and information required
by this rule shall also be retained for at least 5 years.
503 COMPLIANCE DETERMINATION DEMONSTRATION:
503.1 Ultra Low Sulfur Content of the Diesel Oil Verification: If the Control Officer
requests documentation of the sulfur content of the oil fuel to demonstrate the
0.0015% limit, the owner or operator shall submit one of the following documents
which provides the accurate sulfur content of the fuel based on enforceable test
methods as approved by the Administrator to determine sulfur content:
a. Fuel receipts, or
b. Contract specifications, or
c. Pipeline meter tickets, or
d. Fuel supplier information, or
e. Purchase records, or
f. Test results of the fuel for sulfur content.
The items listed above must provide accurate sulfur content values or be based on
enforceable test methods as approved by the Administrator to determine the sulfur
content.
503.2 Drift Rate Verification: An owner or operator shall submit design drift rate
verification from the manufacturer of the drift eliminator used in the cooling towers
to the Control Officer if proof of the design drift rate is requested by the Control
Officer.
503.3 Performance Test-Particulate Matter: An owner or operator of any combustion
equipment listed in Section 102 of this rule that burns a fuel other than natural gas
for non-emergency purposes shall demonstrate compliance with the emission limit in
Section 301 of this rule by conducting an annual performance test. The performance
47

test shall measure particulate matter emissions, including condensable particulate
matter emissions, using EPA Reference Method 5 and EPA Reference Method 202,
as incorporated by reference in Section 504 of this rule. The result of the
performance test shall be the arithmetic mean of the results of three test runs. Each
test run shall have a minimum sample time of one hour.
503.4 Performance Test-Nitrogen Oxides: An owner or operator of any equipment
listed in Section 102.1 or 102.2 of this rule that is subject to a numeric emission limit
in Section 306 of this rule shall demonstrate compliance with the applicable numeric
emission limits by conducting an annual performance test. The performance tests
shall measure nitrogen oxide emissions using EPA Reference Method 7 or 7E as
incorporated by reference in Section 504 of this rule. The result of the performance
test shall be the arithmetic mean of the results of three test runs. Each test run shall
have a minimum sample time of one hour. The concentration of nitrogen oxides
shall be measured dry and corrected to 3% oxygen for electric utility steam
generating units and cogeneration steam generating units. The concentration of
nitrogen oxides shall be measured dry and corrected to 15% oxygen for stationary
gas turbines and for combined cycle turbine systems. For units that are equipped
with water or steam injection, the ratio of water or steam to fuel shall be measured
during the performance test.
a. For any equipment for which a CEMS is used to demonstrate compliance with
Section 306, an annual performance test is not required.
b. If the NOx emission result from the performance test is less than or equal to 75
percent of the NOx emission limit, the owner or operator may reduce the
frequency of subsequent performance tests to once every 2 years (no more than
26 calendar months following the previous performance test). If the results of
any subsequent performance test exceed 75 percent of the NOx emission limit,
the owner or operator must resume annual performance tests.
503.3 503.5 Waste Derived Fuel Gas – Sulfur Verification: The owner or operator shall submit
documentation of the concentration of the sulfur level of the waste derived fuel gas
to the Control Officer upon request. The sulfur content of gaseous fuels shall be
determined by South Coast Air Quality Management District Method 307-94
Determination of Sulfur in a Gaseous Matrix. Performance Test-Carbon
Monoxide: An owner or operator of any equipment listed in Section 102.1 or 102.2
of this rule that is subject to Section 307 of this rule shall demonstrate compliance
with the emission limit in Section 307 of this rule by conducting an annual
performance test. The performance test shall measure carbon monoxide emissions
using EPA Reference Method 10 as incorporated by reference in Section 504 of this
rule. The result of the performance test shall be the arithmetic mean of the results of
three test runs. Each test run shall have a minimum sample time of one hour. The
carbon monoxide concentration shall be measured dry and corrected to 3% oxygen
for electric utility steam generating units and cogeneration steam generating units.
The carbon monoxide concentration shall be measured dry and corrected to 15%
oxygen for stationary gas turbines and for combined cycle turbine systems.
a. For any equipment for which a CEMS is used to demonstrate compliance with
Section 307, an annual performance test is not required.
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b If the CO emission result from the performance test is less than or equal to 75
percent of the CO emission limit, the owner or operator may reduce the
frequency of subsequent performance tests to once every 2 years (no more than
26 calendar months following the previous performance test). If the results of
any subsequent performance test exceed 75 percent of the emission limit, the
owner or operator must resume annual performance tests.
503.6 CEMS: An owner or operator using a CEMS to demonstrate compliance with
Section 302, 306, or 307 shall install, operate, calibrate, maintain, and test the CEMS
in accordance with 40 CFR Part 60 or 40 CFR Part 75.
a. Excess emissions for Section 306 are defined as any period during which the 24-
hour rolling average emission concentration exceeds the applicable numeric
emission limits.
b. Excess emissions for Section 307 are defined as any period during which the 30-
operating day rolling average emission concentration exceeds the applicable
numeric emission limits.
504 COMPLIANCE DETERMINATION-TEST METHODS INCORPORATED BY
REFERENCE: The following test methods are approved for use for the purpose of
determining compliance with this rule. The test methods are incorporated by reference in
Rule 360 and Appendix G of the Maricopa County Air Pollution Control Regulations.
Alternative test methods as approved by the Administrator or other EPA-approved test
methods may be used upon prior written approval from the Control Officer. When more
than one test method is permitted for the same determination, an exceedance under any
method will constitute a violation. Copies of test methods referenced in this section are
available at the Maricopa County Air Quality Department.
504.1 EPA Reference Methods 1 (“Sample and Velocity Traverses for Stationary
Sources”), and 1A (“Sample and Velocity Traverses for Stationary Sources with
Small Stacks and Ducts”) (40 CFR 60, Appendix A-1).
504.2 EPA Reference Methods 2 (“Determination of Stack Gas Velocity and Volumetric
Flow Rate”), 2A (“Direct Measurement of Gas Volume through Pipes and Small
Ducts”), 2C (“Determination of Stack Gas Velocity and Volumetric Flow Rate in
Small Stacks or Ducts”), and 2D (“Measurement of Gas Volumetric Flow Rates in
Small Pipes and Ducts”) (40 CFR 60, Appendix A-1).
504.3 EPA Reference Methods 3 (“Gas Analysis for the Determination of Dry Molecular
Weight”), 3A (“Determination of Oxygen and Carbon Dioxide Concentrations in
Emissions From Stationary Sources (Instrumental Analyzer Procedure)”), 3B (“Gas
Analysis for the Determination of Emission Rate Correction Factor of or Excess
Air”), and 3C (“Determination of Carbon Dioxide, Methane, Nitrogen and Oxygen
from Stationary Sources”) (40 CFR 60, Appendix A-2).
504.4 EPA Reference Method 4 (“Determination of Moisture Content in Stack Gases”)
(40 CFR 60, Appendix A-3).
504.5 EPA Reference Method 5 (“Determination of Particulate Emissions from Stationary
Sources”) (40 CFR 60, Appendix A-3).
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504.6 EPA Reference Method 202 (“Determination of Dry Impinger Method for
Determining Condensable Particulate Emissions from Stationary Sources”) (40 CFR
51, Appendix M).
504.7 EPA Reference Methods 7 (“Determination of Nitrogen Oxide Emissions from
Stationary Sources”), 7A (“Determination of Nitrogen Oxide Emissions from
Stationary Sources – Ion Chromatographic Method”), 7B (“Determination of
Nitrogen Oxide Emissions from Stationary Sources - Ultraviolet Spectrometry
Spectrophotometry”), 7C (“Determination of Nitrogen Oxide Emissions from
Stationary Sources - Alkaline-Permanganate Ion Colorimetric Method”), 7D
(“Determination of Nitrogen Oxide Emissions from Stationary Sources – Alkaline-
Permanganate Chromatographic Method”), and 7E (“Determination of Nitrogen
Oxide Emissions from Stationary Sources – Instrumental Analyzer Method
Procedure”) (40 CFR 60, Appendix A-4).
504.8 EPA Reference Method 9 (“Visual Determination of the Opacity of Emissions from
Stationary Sources”) (40 CFR 60, Appendix A-4).
504.9 EPA Reference Method 10 (“Determination of Carbon Monoxide Emissions from
Stationary Sources”) (40 CFR 60, Appendix A-4).
504.10 EPA Reference Method 20 (“Determination of Nitrogen Oxides, Sulfur Dioxide and
Diluent Emissions from Stationary Gas Turbines”) (40 CFR 60, Appendix A-7).
504.11 ASTM D2622- 16 05, Standard Test Method for Sulfur in Petroleum Products by
Wavelength Disperse Dispersive X-Ray Fluorescence Spectrometry.
504.12 ASTM D2880- 15, Standard Specification for Gas Turbine Fuel Oils.
504.13 504.12 ASTM D4294- 16e1 03, Standard Test Method for Sulfur in Petroleum and
Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry.
504.14 504.13 Standard Methods for the Examination of Water and Wastewater, Method #2540C
(“Total Dissolved Solids Dried at 180ºC, Method #2540C”), American Public
Health Association, 19th edition, 1995.
504.15 504.14 ASTM D5907-13, Standard Methods for the Examination of Water and Wastewater
for Filterable Matter (Total Dissolved Solids) and Nonfilterable Matter (Total
Suspended Solids) in Water.
504.16 504.15 South Coast Air Quality Management District Method 307-94 307-91
(“Determination of Sulfur in a Gaseous Matrix”), revised 1994.
50

MARICOPA COUNTY
AIR POLLUTION CONTROL REGULATIONS
REGULATION III - CONTROL OF AIR CONTAMINANTS
RULE 322 Return to list of attachments
POWER PLANT OPERATIONS
INDEX
SECTION 100 – GENERAL
101 PURPOSE
102 APPLICABILITY
103 EXEMPTIONS
104 PARTIAL EXEMPTIONS
SECTION 200 – DEFINITIONS
201 ANNUAL CAPACITY FACTOR
202 COGENERATION STEAM GENERATING UNIT
203 COMBINED CYCLE TURBINE SYSTEM
204 COMBUSTION CONTROL SYSTEM
205 CONTINUOUS EMISSION MONITORING SYSTEM (CEMS)
206 COOLING TOWERS
207 DRIFT
208 DRIFT ELIMINATOR
209 DRIFT RATE
210 ELECTRIC UTILITY STATIONARY GAS TURBINE
211 ELECTRIC UTILITY STEAM GENERATING UNIT
212 EMERGENCY FUEL
213 EMISSION CONTROL SYSTEM (ECS)
214 FOSSIL FUEL
215 FUEL SWITCHING STARTUP PROCESS
216 HEAT INPUT
217 HIGHER HEATING VALUE (HHV) OR GROSS HEATING VALUE
218 LOW SULFUR OIL
219 LOWER HEATING VALUE (LHV) OR NET HEATING VALUE
220 NATURAL GAS
221 NATURAL GAS CURTAILMENT
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222 OPACITY
223 OPERATING DAY
224 OPERATING HOUR
225 PARTICULATE MATTER EMISSIONS
226 PARTS PER MILLION BY VOLUME DRY (PPMVD)
227 PEAK LOAD
228 POWER PLANT OPERATION
229 RATED HEAT INPUT CAPACITY
230 REGENERATIVE CYCLE GAS TURBINE
231 SIMPLE CYCLE GAS TURBINE
232 STATIONARY GAS TURBINE
233 SULFUR OXIDES (SOX)
234 THIRTY (30) OPERATING DAY ROLLING AVERAGE
235 TOTAL DISSOLVED SOLIDS (TDS)
236 TWENTY-FOUR (24) HOUR ROLLING AVERAGE
237 ULTRA LOW SULFUR OIL
238 UNCOMBINED WATER
SECTION 300 – STANDARDS
301 LIMITATIONS - PARTICULATE MATTER
302 GOOD COMBUSTION PRACTICES FOR TURBINES
303 COOLING TOWERS
304 LIMITATIONS – OPACITY
305 LIMITATIONS – SULFUR IN FUEL
306 LIMITATIONS – NITROGEN OXIDES (NOX)
307 LIMITATIONS – CARBON MONOXIDE
308 REQUIREMENTS FOR ECS AND ECS MONITORING EQUIPMENT
309 EMERGENCY FUEL USE NOTIFICATION
SECTION 400 – ADMINISTRATIVE REQUIREMENTS
401 IN EXISTENCE AND IN COMPLIANCE
402 IN EXISTENCE AND NON-COMPLIANT
SECTION 500 – MONITORING AND RECORDS
501 RECORDKEEPING AND REPORTING
52

502 RECORDS RETENTION
503 COMPLIANCE DEMONSTRATION
504 COMPLIANCE DETERMINATION-TEST METHODS INCORPORATED BY
REFERENCE
53

Adopted 07/02/2003; Revised 10/17/2007; Revised 11/02/2016; Revised MM/DD/YYYY
MARICOPA COUNTY
AIR POLLUTION CONTROL REGULATIONS
REGULATION III - CONTROL OF AIR CONTAMINANTS
RULE 322
POWER PLANT OPERATIONS
SECTION 100 – GENERAL
101 PURPOSE: To limit the discharge of nitrogen oxides, sulfur oxides, particulate matter and
carbon monoxide emissions into the atmosphere from stationary fossil-fuel-fired electric
utility stationary gas turbines, stationary fossil-fuel-fired electric utility steam generating units,
and stationary fossil-fuel-fired cogeneration steam generating units and to limit particulate
matter emissions from cooling towers associated with this equipment.
102 APPLICABILITY: This rule applies to the following types of equipment that burn fossil
fuel:
102.1 Each electric utility steam generating unit or cogeneration steam generating unit used
to generate electric power that has a rated heat input capacity greater than or equal to
100 million (MM) British thermal units per hour (Btu/hour) based upon the lower
heating value of the fuel.
102.2 Each electric utility stationary gas turbine with a rated heat input capacity at peak load
greater than or equal to 10 MMBtu/hour based upon the lower heating value of the
fuel.
102.3 Each cooling tower associated with the type of equipment listed in Sections 102.1 and
102.2 of this rule.
102.4 NSPS & NESHAP: In addition to this rule, facilities may be subject to New Source
Performance Standards (NSPS) in Rule 360 and/or National Emission Standards for
Hazardous Air Pollutants (NESHAP) in Rule 370 of these rules.
103 EXEMPTIONS: This rule shall not apply to the following types of equipment:
103.1 Combustion equipment associated with nuclear power plant operations; or
103.2 Reciprocating internal combustion engines.
104 PARTIAL EXEMPTIONS:
104.1 Stationary gas turbines that meet any of the criteria listed below are exempt from
Sections 301, 306, 307, 501.4, 503.3, 503.4, 503.5, and 503.6 of this rule:
a. Used for fire-fighting
b. Used for flood control
c. Engaged by manufacturers in research and development of equipment for either
gas turbine emission control techniques or gas turbine efficiency improvements
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104.2 While firing emergency fuel during a natural gas curtailment or natural gas
emergency, any equipment listed in Section 102 of this rule that is normally fired
with natural gas is exempt from Sections 301, 306, 307, 501.4, 503.3, 503.4, 503.5,
and 503.6 of this rule . This exemption shall not exceed 168 hours per calendar year
per combustion unit, excluding hours of operation for testing, reliability, training and
maintenance.
104.3 While firing emergency fuel for purposes of testing, reliability, training and
maintenance, any equipment listed in Section 102 of this rule that is normally fired
with natural gas is exempt from Sections 301, 306, 307, 501.4, 503.3, 503.4, 503.5,
and 503.6 of this rule. This exemption shall not exceed 36 hours per calendar year
per combustion unit, excluding hours of operation during natural gas curtailments
and natural gas emergencies.
104.4 Any equipment listed in Section 102 of this rule that operates at or below 10 percent
calendar year annual capacity factor, and meets the requirements in 104.4 a, b, and c
is exempt from Sections 306 and 307 of this rule.
a. An owner or operator must submit a RACT analysis to the Control Officer and
the Administrator demonstrating conventional commercially-available control
technology is not technically and/or economically feasible and obtain approval
from the Control Officer and Administrator to operate under the exemption.
(1) For equipment for which a RACT analysis was submitted prior to [date of
rule adoption], upon Control Officer approval, equipment may begin to
operate under the exemption until the Administrator approves or denies
operation under the exemption. If the Administrator denies approval to
operate under the exemption, the equipment will become subject to the
emission limits in Sections 306 and 307.
(2) For equipment for which a RACT analysis is submitted on or after [date of
rule adoption], equipment may begin to operate under the exemption upon
approval from the Control Officer and the Administrator.
b. All equipment operated under this exemption shall have an annual heat input
limit associated with that equipment that corresponds to the 10 percent calendar
year annual capacity factor. The annual heat input limit shall be calculated by
multiplying the equipment’s maximum heat input rate (MMBtu per hour) by 876
hours. An owner or operator with equipment approved to operate under the
exemption shall submit an application to modify the permit associated with the
equipment to include an annual heat input limit within 60 days of the Control
Officer’s approval.
c. To demonstrate compliance with the heat input limit an owner or operator shall
multiply the higher heating value (MMBtu/mass or MMBtu/volume of gas) by
the fuel use (mass or volume of gas).
SECTION 200 – DEFINITIONS: For the purpose of this rule, the following definitions shall
apply, in addition to those definitions found in Rule 100 (General Provisions and Definitions) of
these rules. In the event of any inconsistency between any of the Maricopa County air pollution
control rules, the definitions in this rule take precedence.
55

201 ANNUAL CAPACITY FACTOR: The ratio between the actual heat input to a stationary
gas turbine or steam generating unit from the fuels burned during a calendar year and the
potential heat input to the stationary gas turbine or steam generating unit had it been
operated for 8,760 hours at the maximum rated heat input capacity.
202 COGENERATION STEAM GENERATING UNIT: A steam or hot water generating
unit that simultaneously produces both electrical and useful thermal energy (such as heat or
steam) from the same primary energy source and supplies more than one-third of its
potential electric output to any utility power distribution system for sale.
203 COMBINED CYCLE TURBINE SYSTEM: A type of stationary gas turbine wherein
heat from the turbine exhaust is recovered by a steam generating unit, with or without
supplemental heat (i.e. duct burner), to make steam for use in a steam-electric turbine.
204 COMBUSTION CONTROL SYSTEM: Equipment or technology that suppress NOX
formation during combustion of fossil fuels, including but not limited to, water injection or
low-NOX burners.
205 CONTINUOUS EMISSION MONITORING SYSTEM (CEMS): The total
equipment required to sample, analyze, measure, and provide a permanent record of
emissions by means of readings recorded at least once every 15 minutes (using an automated
data acquisition and handling system (DAHS)).
206 COOLING TOWERS: Open water recirculating devices that use fans or natural draft to
draw or force air through the device to cool water by evaporation and direct contact.
207 DRIFT: Water droplets, bubbles, and particulate matter that escape from cooling tower
stacks.
208 DRIFT ELIMINATOR: Device used to remove drift from cooling tower exhaust air, thus
reducing water loss by relying on rapid changes in velocity and direction of air-droplet
mixtures by impaction on eliminator passage surfaces. A drift eliminator is not categorized as
an emission control system but is an inherent part of the cooling tower's design
requirements.
209 DRIFT RATE: Percentage (%) of circulating water flow rate that passes through a drift
eliminator on a cooling tower.
210 ELECTRIC UTILITY STATIONARY GAS TURBINE: Any stationary gas turbine
that is constructed for the purpose of supplying more than 1/3 of its potential electric
output capacity to any utility power distribution system for sale.
211 ELECTRIC UTILITY STEAM GENERATING UNIT: Any equipment that combusts
fossil fuel to generate steam that is used to drive an electrical generator and is constructed
for the purpose of supplying more than one-third of its potential electric output capacity and
more than 25 MW electric output to any utility power distribution system for sale.
212 EMERGENCY FUEL: Fuel fired only during circumstances such as natural gas
emergency, natural gas curtailment, or breakdown of delivery system such as an unavoidable
56

interruption of supply that makes it impossible to fire natural gas in the unit. Fuel is not
considered emergency fuel if it is used to avoid either peak demand charges or high gas
prices during on-peak price periods or due to a voluntary reduction in natural gas usage by
the power company. For the purposes of this definition, emergency fuel also includes fuel
used for purposes of testing, reliability, training, and maintenance.
213 EMISSION CONTROL SYSTEM (ECS): Post-combustion systems that are designed
and operated in accordance with good engineering practice to reduce emissions from
combustion equipment. A combustion control system is not an emission control system.
214 FOSSIL FUEL: Naturally occurring carbonaceous substances from the ground such as
natural gas, petroleum, coal and any form of solid, liquid, or gaseous fuel derived from such
material for the purpose of creating energy.
215 FUEL SWITCHING STARTUP PROCESS: The act of changing from one type of fuel
to a different type of fuel.
216 HEAT INPUT: Heat derived from the combustion of fuel, not including the heat input
from preheated combustion air, recirculated flue gases, or exhaust gases from other sources,
such as gas turbines, internal combustion engines, and kilns.
217 HIGHER HEATING VALUE (HHV) OR GROSS HEATING VALUE: The amount
of heat produced by the complete combustion of a unit quantity of fuel determined by a
calorimeter wherein the combustion products are cooled to the temperature existing before
combustion and all of the water vapor is condensed to liquid.
218 LOW SULFUR OIL: Fuel oil containing less than or equal to 0.05% by weight of sulfur.
219 LOWER HEATING VALUE (LHV) OR NET HEATING VALUE: The amount of
heat produced by the complete combustion of a unit quantity of fuel determined by a
calorimeter wherein the combustion products are cooled to the temperature existing before
combustion and all of the water vapor remains as vapor and is not condensed to a liquid.
The value is computed from the higher heating value by subtracting the water originally
present as moisture and the water formed by combustion of the fuel.
220 NATURAL GAS: A naturally occurring fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane) produced in geological formations beneath the earth’s surface that
maintains a gaseous state at standard atmospheric temperature and pressure under ordinary
conditions and contains 20 grains or less of total sulfur per 100 standard cubic feet.
221 NATURAL GAS CURTAILMENT: An interruption in natural gas service, such that the
daily fuel needs of a combustion unit cannot be met with natural gas available due to one of
the following reasons, beyond the control of the owner or operator:
221.1 An unforeseeable failure or malfunction, not resulting from an intentional act or
omission that the governing state, federal or local agency finds to be due to an act of
gross negligence on the part of the owner or operator; or
221.2 A natural disaster; or
57

221.3 The natural gas is curtailed pursuant to governing state, federal or local agency rules
or orders; or
221.4 The serving natural gas supplier provides notice to the owner or operator that, with
forecasted natural gas supplies and demands, natural gas service is expected to be
curtailed pursuant to governing state, federal or local agency rules or orders.
222 OPACITY: A condition of the ambient air, or any part thereof, in which an air contaminant
partially or wholly obscures the view of an observer.
223 OPERATING DAY: A 24-hour period between 0000 and 2359 during which any fuel is
combusted at any time in the unit. It is not necessary for fuel to be combusted continuously
for the entire 24-hour period.
224 OPERATING HOUR: A clock hour during which a unit combusts any fuel, either for part
of the hour or for the entire hour.
225 PARTICULATE MATTER EMISSIONS: Any and all particulate matter emitted to the
ambient air as measured by applicable state and federal test methods.
226 PARTS PER MILLION BY VOLUME DRY (PPMVD): A unit of proportion used to
express concentration that is corrected to a dry basis.
227 PEAK LOAD: 100% of the manufacturer’s design capacity of a gas turbine at 288° Kelvin,
60% relative humidity, and 101.3 kilopascals pressure (ISO standard day conditions).
228 POWER PLANT OPERATION: An operation whose purpose is to supply more than
one-third of its potential electric output capacity to any utility power distribution system for
sale.
229 RATED HEAT INPUT CAPACITY: The heat input capacity in million Btu/hr. as
specified on the nameplate of the combustion unit. If the combustion unit has been altered
or modified such that its maximum heat input is different than the heat input capacity on the
name plate, the maximum heat input shall be considered the rated heat input capacity.
230 REGENERATIVE CYCLE GAS TURBINE: Any stationary gas turbine that recovers
thermal energy from the exhaust gases and utilizes the thermal energy to preheat air prior to
entering the combustion unit.
231 SIMPLE CYCLE GAS TURBINE: Any stationary gas turbine that does not recover heat
from the gas turbine exhaust gases to preheat the inlet combustion air to the gas turbine and
does not recover heat from the gas turbine exhaust gases to heat water or generate steam.
232 STATIONARY GAS TURBINE: Any simple cycle gas turbine, regenerative gas turbine, or
any gas turbine portion of a combined cycle turbine system that is not self-propelled or that is
attached to a foundation.
233 SULFUR OXIDES (SOX): The sum of the oxides of sulfur emitted from the flue gas from a
combustion unit that are directly dependent upon the amount of sulfur in the fuel used.
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234 THIRTY (30) OPERATING DAY ROLLING AVERAGE: An arithmetic mean or
average of all hourly emission concentrations for 30 successive operating days and calculated
by a CEMS at the conclusion of each operating day for the previous 30 operating days.
235 TOTAL DISSOLVED SOLIDS (TDS): The amount of filterable matter reported in
milligrams/liter (mg/l) or parts per million (ppm), as determined by an applicable method in
the Standard Methods for the Examination of Water and Wastewater, a conductivity/TDS
meter, or ASTM D5907.
236 TWENTY-FOUR (24) HOUR ROLLING AVERAGE: The arithmetic mean of all hourly
emission concentrations measured during the previous 24 operating hours.
237 ULTRA LOW SULFUR OIL: Fuel oil containing less than or equal to 0.0015 % sulfur by
weight.
238 UNCOMBINED WATER: Condensed water vapor or steam.
SECTION 300 – STANDARDS
301 LIMITATIONS – PARTICULATE MATTER: An owner or operator of any equipment
listed in Section 102.1 or 102.2 of this rule shall burn only natural gas except when firing
emergency fuel per Sections 104.2 and 104.3 of this rule. An owner or operator may burn a
fuel other than natural gas for non-emergency purposes providing that the fuel shall not
cause to be discharged more than 0.007 lbs. of particulate matter per MMBtu. The use of a
fuel other than natural gas for non-emergency purposes shall be approved by the Control
Officer in an air pollution control permit prior to usage.
302 GOOD COMBUSTION PRACTICES FOR TURBINES: An owner or operator of any
stationary gas turbine listed in Section 102.2 of this rule shall, regardless of fuel type, use
operational practices recommended by the manufacturer to ensure good combustion
control.
302.1 Good combustion practices shall be demonstrated by maintaining the manufacturer’s
recommended maintenance practices onsite and available to the Control Officer
upon request, by maintaining records of all maintenance activities conducted on the
turbines, and by conducting performance tests as described in Section 503 (unless
exempt from Sections 306 and 307 under the exemption in Section 104.4).
302.2 For stationary gas turbines with a CEMS able to demonstrate compliance with the
applicable emission limits in Sections 306 and 307, good combustion practices may
be demonstrated through continuous compliance with the applicable emission limits
in Sections 306 and 307.
303 COOLING TOWERS: An owner or operator of a cooling tower listed in Section 102.3 of
this rule shall:
303.1 Equip the cooling tower with a drift eliminator. The drift eliminator shall not be
manufactured out of wood.
303.2 Limit the value obtained by multiplying the concentration of Total Dissolved Solids
(TDS) in the cooling tower water by the percentage of drift rate for the cooling
59

tower drift eliminator such that the product does not exceed the maximum
numerical limit of 20 ppm.
303.3 Visually inspect the drift eliminator according to the following schedule, as applicable
depending on the configuration of the drift eliminator:
a. Monthly, if the drift eliminator can be viewed safely and if the inspection does
not require a person to walk into the cooling tower; or
b. No less than once per year during a regularly scheduled outage when the cooling
tower is not operating, if the drift eliminator cannot be safely inspected while the
cooling tower is operating.
304 LIMITATIONS – OPACITY:
304.1 An owner or operator shall not discharge into the ambient air from any single source
of emissions any air contaminant, other than uncombined water, in excess of 20%
opacity, for any six (6) minute averaging period, except as provided in Section 304.2
of this rule.
304.2 Opacity may exceed the applicable limits established in Section 304.1 of this rule
during the one hour fuel switching startup process, provided that the Control Officer
finds that the owner or operator has, to the extent practicable, maintained and
operated the source of emissions in a manner consistent with good air pollution
control practices for minimizing emissions. During the one-hour fuel switching
startup process, an owner or operator shall not discharge into the ambient air from
any single source of emissions any air contaminant, other than uncombined water, in
excess of 40% opacity, for any six (6) minute averaging period. The one-hour period
shall begin when the fuel switching startup process begins.
304.3 Determination of whether good air pollution control practices are being used shall
be based on information provided to the Control Officer upon request, which may
include, but is not limited to, the following:
a. Monitoring results.
b. Opacity observations.
c. Review of operating and maintenance procedures.
d. Inspection of the source.
305 LIMITATIONS – SULFUR IN FUEL: An owner or operator of any equipment listed in
Section 102.1 or 102.2 of this rule that burns fuel oil alone or in combination with any other
fuel as either emergency fuel or non-emergency fuel shall use either ultra low sulfur oil or
low sulfur oil.
306 LIMITATIONS – NITROGEN OXIDES (NOX):
306.1 RACT Emission Limits:
a. Existing Steam Generating Units: An owner or operator of any equipment listed
in Section 102.1 of this rule that commenced operation prior to (insert date of
rule adoption) shall not cause to be discharged into the atmosphere nitrogen
oxides in excess of 0.1 lb/MMBtu, calculated as nitrogen dioxide, unless the
60

equipment is operated in compliance with the case-by-case RACT requirements
established in accordance with Section 306.2 of this rule.
b. New Steam Generating Units: An owner or operator of any equipment listed in
Section 102.1 of this rule that commenced operation on or after (insert date of
rule adoption) shall not cause to be discharged into the atmosphere nitrogen
oxides in excess of the following limits, unless the equipment is operated in
compliance with the case-by-case RACT requirements established in accordance
with Section 306.2 of this rule.
(1) 30 ppmvd corrected to 3% oxygen calculated as nitrogen dioxide when
burning gaseous fossil fuel.
(2) 40 ppmvd corrected to 3% oxygen calculated as nitrogen dioxide when
burning liquid fossil fuel.
c. Stationary Gas Turbines and Combined Cycle Turbine Systems: An owner or
operator of any equipment listed in Section 102.2 of this rule shall not cause to
be discharged into the atmosphere nitrogen oxides in excess of the following
limits, unless the equipment is operated in compliance with the case-by-case
RACT requirements established in accordance with Section 306.2 of this rule.
(1) 42 ppmvd corrected to 15% oxygen calculated as nitrogen dioxide when
burning gaseous fossil fuel.
(2) 65 ppmvd corrected to 15% oxygen calculated as nitrogen dioxide when
burning liquid fossil fuel.
306.2 Case-by-Case RACT Requirements: Nothing in this rule shall prevent the owner
or operator of any equipment listed in Section 102 of this rule from requesting
alternative RACT requirements on a case-by-case basis. An owner or operator shall
be exempt from Section 306.1 if the owner or operator fully complies with
alternative RACT requirements that are approved by the Control Officer and the
Administrator, incorporated into an Air Pollution Control Permit, and approved into
the Arizona State Implementation Plan.
307 LIMITATIONS – CARBON MONOXIDE: An owner or operator of any equipment
listed in Section 102.1 or 102.2 of this rule shall not cause to be discharged into the
atmosphere carbon monoxide (CO) measured in excess of 400 ppmvd corrected to 15%
oxygen for stationary gas turbines, and corrected to 3% oxygen for steam generating units.
308 REQUIREMENTS FOR ECS AND ECS MONITORING EQUIPMENT: An
owner or operator of an emission control system (ECS) shall:
308.1 Properly install, operate, and maintain in calibration and in good working order devices
for indicating temperatures, pressures, transfer rates, rates of flow, or other operating
conditions necessary to determine if an ECS is functioning properly and is properly
maintained.
308.2 Submit to the Control Officer for approval an Operation and Maintenance (O&M)
Plan for any ECS, and any ECS monitoring devices that are used pursuant to this rule
or to an air pollution permit. The O&M Plan shall include:
61

a. The manufacturer name, model designation, and serial number for each ECS and
each ECS monitoring device; and
b. Operating parameters that will be monitored to demonstrate continued operation
of the ECS in the manner the ECS was operated during the most recent
performance test; and
c. The manufacturer’s recommended maintenance procedures and frequencies or, if
the manufacturer’s recommended maintenance procedures are not available, a
maintenance plan based on good engineering practices to reduce emissions.
308.3 Fully comply with all elements of the most recent O&M Plans submitted to the
Control Officer, unless notified by the Control Officer in writing.
308.4 Submit a revised O&M Plan within 30 business days following receipt of the Control
Officer’s written notice that an O&M Plan for any ECS or any ECS monitoring device
is deficient or inadequate.
308.5 Maintain on-site, in a readily accessible location, the most recent O&M Plans for each
ECS and each ECS monitoring device.
309 EMERGENCY FUEL USE NOTIFICATION: An owner or operator of an electric utility
stationary gas turbine, electric utility steam generating unit or cogeneration steam generating
unit used to generate electric power that is fired with emergency fuel but is normally fired with
natural gas shall notify the Control Officer verbally no later than 24 hours after declaration of
the emergency that necessitates its use in compliance with Section 104.2 of this rule. This
verbal report shall be followed by a written report within 48 hours of initial emergency fuel
usage. The written report shall also include identification of the nature of the emergency, initial
dates of usage, and the expected dates of usage. Within 1 business day following the end of an
emergency that necessitates the use of emergency fuel, the owner or operator shall submit a
written report that includes the total number of hours the combustion equipment was
operated with emergency fuel.
SECTION 400 – ADMINISTRATIVE REQUIREMENTS
401 IN EXISTENCE AND IN COMPLIANCE: The owner or operator of any electric
utility stationary gas turbine, electric utility steam generating unit or cogeneration steam
generating unit used to generate electric power in existence on [insert date of rule adoption]
shall submit a Notification of Compliance within 6 months of becoming subject to Section
306 of this rule. This Notification shall include one of the following demonstrations:
401.1 Demonstration of Compliance with RACT Emission Limits: For each unit that
is in compliance with the RACT emission limits in Section 306.1 of this rule, the
Notification of Compliance shall include results from a performance test conducted
in accordance with Section 503.4 of this rule, or that a CEMS has been installed (to
demonstrate continuous compliance with the RACT emission limits), after [insert
date – one year before rule adoption].
401.2 Demonstration of Compliance with the exemption in Section 104.4: For each
unit that operates at or below 10 percent calendar year annual capacity factor, the
Notification of Compliance shall include records of the annual capacity factor for the
calendar year previous to the year of rule adoption.
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402 IN EXISTENCE AND NON-COMPLIANT:
402.1 Increments of Progress – Installation of Air Pollution Control Equipment:
When an emission control system or a combustion control system will be installed to
achieve compliance with the emission limits in Section 306.1 of this rule, the owner
or operator shall comply with the following increments of progress and be in
compliance with the emission limits by the date specified:
a. Within 18 months of becoming subject to the emission limits in Section 306.1 of
this rule, submit a compliance schedule and permit application to the Control
Officer.
b. Within 36 months of final permit issuance, be fully compliant with the emission
limits in Section 306.1 of this rule and submit to the Control Officer a complete
source test report indicating compliance.
402.2 Increments of Progress – Removal from Service: The owner or operator of any
combustion unit in existence on [insert date of rule adoption] that is expected to be
removed from service within 24 months of becoming subject to Section 306.1 of this
rule shall be exempt from the emission limits in Section 306.1 of this rule if it
complies with the following:
a. Within 6 months of becoming subject to the limits in Section 306.1 of this rule,
submit to the Control Officer a notification of proposed removal from service.
b. Within 14 months of submitting notification under Section 402.2(a) of this rule,
submit to the Control Officer a decommissioning plan and a permit revision
providing that the units will be decommissioned by a certain date.
c. Within 4 months of decommissioning plan and permit revision approval, or
within 24 months after becoming subject to the emission limits in Section 306.1
of this rule, whichever comes first, discontinue operation of the electric utility
stationary gas turbine, electric utility steam generating unit or cogeneration steam
generating unit used to generate electric power, disconnect the fuel supply line(s),
and notify the Control Officer in writing of the removal from service.
SECTION 500 – MONITORING AND RECORDS
501 RECORDKEEPING AND REPORTING: Any owner or operator subject to this rule
shall comply with the requirements set forth in this section. Any records and data required
by this section shall be kept on site at all times in a consistent and complete manner and be
made available without delay to the Control Officer upon request. Records shall consist of
the following information:
501.1 Equipment Listed in Section 102 of this Rule: Days and hours of operation, type(s)
of fuel used, amount of fuel(s) used each month, and documentation of the sulfur
content of any fuel oil combusted (e.g. fuel receipts, contract specifications, pipeline
meter tickets, fuel supplier information, purchase records, or analytical results).
Records of sulfur content shall provide accurate values for the sulfur content of the
fuel based on enforceable test methods approved by the Administrator.
501.2 Cooling Towers: Monthly gravimetric testing reports for TDS in cooling water in the
cooling tower shall be recorded for six months in succession and thereafter quarterly
63

reports shall be recorded. Results of the monthly or yearly visual inspection of the drift
eliminator shall also be recorded. If the drift eliminator cannot be visually inspected
monthly, then documentation of the physical configuration of the drift eliminator shall
be submitted to the Control Officer to demonstrate that the drift eliminator cannot be
inspected monthly.
501.3 Emergency Fuel Usage: Type and amount of emergency fuel used, dates and hours
of operation using emergency fuel, nature of the emergency or reason for the use of
emergency fuel as stated in Sections 104.2 and 104.3 of this rule. At the end of each
month, calculate the total hours of operation using emergency fuel during natural gas
curtailments and natural gas emergencies, and total hours of operation using
emergency fuel for purposes of testing, reliability, training, and maintenance.
501.4 Non-Emergency Fuel Switching: Dates and times, including start and stop times,
when any fuel other than natural gas is combusted for non-emergency purposes, as
allowed by Section 301 of this rule.
501.5 Continuous Emission Monitoring Systems: All CEMS measurements, results of
CEMS performance evaluations, CEMS calibration checks, and adjustments and
maintenance performed on these systems.
501.6 Good Combustion Practices:
a. Good combustion practices shall be demonstrated by maintaining the
manufacturer’s recommended maintenance practices onsite and available to the
Control Officer upon request, by maintaining records of all maintenance activities
conducted on the turbines, and by maintaining records of the test results of
performance tests conducted under Section 503 (unless exempt from Sections 306
and 307 under the exemption in Section 104.4).
b. If using CEMS to demonstrate good combustion practices, results of evaluation
and of corrective action shall be recorded each time the CEMS indicates an
exceedance of the applicable emission limits in Section 306 or 307 of this rule.
c. For units equipped with water or steam injection, the owner or operator shall
maintain continuous records of the water to fuel ratio or the steam to fuel ratio,
unless the owner or operator uses CEMS to demonstrate compliance with the
emission limits in Sections 306 and 307, as applicable.
502 RECORDS RETENTION: Copies of reports, logs, and supporting documentation required
by the Control Officer shall be retained for at least 5 years. Records and information required
by this rule shall also be retained for at least 5 years.
503 COMPLIANCE DEMONSTRATION:
503.1 Sulfur Content of the Oil Verification: If the Control Officer requests
documentation of the sulfur content of the oil , the owner or operator shall submit
one of the following documents which provides the accurate sulfur content of the
fuel based on enforceable test methods as approved by the Administrator to
determine sulfur content:
a. Fuel receipts, or
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b. Contract specifications, or
c. Pipeline meter tickets, or
d. Fuel supplier information, or
e. Purchase records, or
f. Test results of the fuel for sulfur content.
503.2 Drift Rate Verification: An owner or operator shall submit design drift rate
verification from the manufacturer of the drift eliminator used in the cooling towers
to the Control Officer if proof of the design drift rate is requested by the Control
Officer.
503.3 Performance Test-Particulate Matter: An owner or operator of any combustion
equipment listed in Section 102 of this rule that burns a fuel other than natural gas
for non-emergency purposes shall demonstrate compliance with the emission limit in
Section 301 of this rule by conducting an annual performance test. The performance
test shall measure particulate matter emissions, including condensable particulate
matter emissions, using EPA Reference Method 5 and EPA Reference Method 202,
as incorporated by reference in Section 504 of this rule. The result of the
performance test shall be the arithmetic mean of the results of three test runs. Each
test run shall have a minimum sample time of one hour.
503.4 Performance Test-Nitrogen Oxides: An owner or operator of any equipment
listed in Section 102.1 or 102.2 of this rule that is subject to a numeric emission limit
in Section 306 of this rule shall demonstrate compliance with the applicable numeric
emission limits by conducting an annual performance test. The performance tests
shall measure nitrogen oxide emissions using EPA Reference Method 7 or 7E as
incorporated by reference in Section 504 of this rule. The result of the performance
test shall be the arithmetic mean of the results of three test runs. Each test run shall
have a minimum sample time of one hour. The concentration of nitrogen oxides
shall be measured dry and corrected to 3% oxygen for electric utility steam
generating units and cogeneration steam generating units. The concentration of
nitrogen oxides shall be measured dry and corrected to 15% oxygen for stationary
gas turbines and for combined cycle turbine systems. For units that are equipped
with water or steam injection, the ratio of water or steam to fuel shall be measured
during the performance test.
a. For any equipment for which a CEMS is used to demonstrate compliance with
Section 306, an annual performance test is not required.
b. If the NOx emission result from the performance test is less than or equal to 75
percent of the NOx emission limit, the owner or operator may reduce the
frequency of subsequent performance tests to once every 2 years (no more than
26 calendar months following the previous performance test). If the results of
any subsequent performance test exceed 75 percent of the NOx emission limit,
the owner or operator must resume annual performance tests.
503.5 Performance Test-Carbon Monoxide: An owner or operator of any equipment
listed in Section 102.1 or 102.2 of this rule that is subject to Section 307 of this rule
shall demonstrate compliance with the emission limit in Section 307 of this rule by
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conducting an annual performance test. The performance test shall measure carbon
monoxide emissions using EPA Reference Method 10 as incorporated by reference
in Section 504 of this rule. The result of the performance test shall be the arithmetic
mean of the results of three test runs. Each test run shall have a minimum sample
time of one hour. The carbon monoxide concentration shall be measured dry and
corrected to 3% oxygen for electric utility steam generating units and cogeneration
steam generating units. The carbon monoxide concentration shall be measured dry
and corrected to 15% oxygen for stationary gas turbines and for combined cycle
turbine systems.
a. For any equipment for which a CEMS is used to demonstrate compliance with
Section 307, an annual performance test is not required.
b If the CO emission result from the performance test is less than or equal to 75
percent of the CO emission limit, the owner or operator may reduce the
frequency of subsequent performance tests to once every 2 years (no more than
26 calendar months following the previous performance test). If the results of
any subsequent performance test exceed 75 percent of the emission limit, the
owner or operator must resume annual performance tests.
503.6 CEMS: An owner or operator using a CEMS to demonstrate compliance with
Section 302, 306, or 307 shall install, operate, calibrate, maintain, and test the CEMS
in accordance with 40 CFR Part 60 or 40 CFR Part 75.
a. Excess emissions for Section 306 are defined as any period during which the 24-
hour rolling average emission concentration exceeds the applicable numeric
emission limits.
b. Excess emissions for Section 307 are defined as any period during which the 30-
operating day rolling average emission concentration exceeds the applicable
numeric emission limits.
504 COMPLIANCE DETERMINATION – TEST METHODS INCORPORATED BY
REFERENCE: The following test methods are approved for use for the purpose of
determining compliance with this rule. The test methods are incorporated by reference in
Rule 360 and Appendix G of the Maricopa County Air Pollution Control Regulations.
Alternative test methods as approved by the Administrator or other EPA-approved test
methods may be used upon prior written approval from the Control Officer. When more
than one test method is permitted for the same determination, an exceedance under any
method will constitute a violation. Copies of test methods referenced in this section are
available at the Maricopa County Air Quality Department.
504.1 EPA Reference Methods 1 (“Sample and Velocity Traverses for Stationary
Sources”), and 1A (“Sample and Velocity Traverses for Stationary Sources with
Small Stacks and Ducts”) (40 CFR 60, Appendix A-1).
504.2 EPA Reference Methods 2 (“Determination of Stack Gas Velocity and Volumetric
Flow Rate”), 2A (“Direct Measurement of Gas Volume through Pipes and Small
Ducts”), 2C (“Determination of Stack Gas Velocity and Volumetric Flow Rate in
Small Stacks or Ducts”), and 2D (“Measurement of Gas Volume Flow Rates in Small
Pipes and Ducts”) (40 CFR 60, Appendix A-1).
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504.3 EPA Reference Methods 3 (“Gas Analysis for the Determination of Dry Molecular
Weight”), 3A (“Determination of Oxygen and Carbon Dioxide Concentrations in
Emissions From Stationary Sources (Instrumental Analyzer Procedure)”), 3B (“Gas
Analysis for the Determination of Emission Rate Correction Factor or Excess Air”),
and 3C (“Determination of Carbon Dioxide, Methane, Nitrogen and Oxygen from
Stationary Sources”) (40 CFR 60, Appendix A-2).
504.4 EPA Reference Method 4 (“Determination of Moisture Content in Stack Gases”)
(40 CFR 60, Appendix A-3).
504.5 EPA Reference Method 5 (“Determination of Particulate Emissions from Stationary
Sources”) (40 CFR 60, Appendix A-3).
504.6 EPA Reference Method 202 (“Dry Impinger Method for Determining Condensable
Particulate Emissions from Stationary Sources”) (40 CFR 51, Appendix M).
504.7 EPA Reference Methods 7 (“Determination of Nitrogen Oxide Emissions from
Stationary Sources”), 7A (“Determination of Nitrogen Oxide Emissions from
Stationary Sources – Ion Chromatographic Method”), 7B (“Determination of
Nitrogen Oxide Emissions from Stationary Sources - Ultraviolet
Spectrophotometry”), 7C (“Determination of Nitrogen Oxide Emissions from
Stationary Sources - Alkaline-Permanganate Ion Colorimetric Method”), 7D
(“Determination of Nitrogen Oxide Emissions from Stationary Sources – Alkaline-
Permanganate Chromatographic Method”), and 7E (“Determination of Nitrogen
Oxide Emissions from Stationary Sources – Instrumental Analyzer Procedure”) (40
CFR 60, Appendix A-4).
504.8 EPA Reference Method 9 (“Visual Determination of the Opacity of Emissions from
Stationary Sources”) (40 CFR 60, Appendix A-4).
504.9 EPA Reference Method 10 (“Determination of Carbon Monoxide Emissions from
Stationary Sources”) (40 CFR 60, Appendix A-4).
504.10 EPA Reference Method 20 (“Determination of Nitrogen Oxides, Sulfur Dioxide and
Diluent Emissions from Stationary Gas Turbines”) (40 CFR 60, Appendix A-7).
504.11 ASTM D2622- 05, Standard Test Method for Sulfur in Petroleum Products by
Wavelength Dispersive X-Ray Fluorescence Spectrometry.
504.12 ASTM D4294- 03, Standard Test Method for Sulfur in Petroleum and Petroleum
Products by Energy-Dispersive X-Ray Fluorescence Spectrometry.
504.13 Standard Methods for the Examination of Water and Wastewater, Method #2540C
(“Total Dissolved Solids Dried at 180ºC”), American Public Health Association, 19th
edition, 1995.
504.14 ASTM D5907-13, Standard Methods for Filterable Matter (Total Dissolved Solids)
and Nonfilterable Matter (Total Suspended Solids) in Water.
504.15 South Coast Air Quality Management District Method 307-91 (“Determination of
Sulfur in a Gaseous Matrix”), revised 1994.
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MARICOPA COUNTY BOARD OF HEALTH MEETING MINUTES
Monday, February 25, 2019 at 1:00 pm
301 W. Jefferson Street, 10th Floor, Phoenix, Arizona 85003
Board of Supervisors Conference Room
President Hughes called the meeting to order at 1:02 p.m. Return to list of attachments
ROLL CALL:
Members Present: Members Not Present:
Don Cassano Kristen Acton
Henri Cournand (via phone)
Robert MacMillan
Andrew Rascón
Nedra Halley
Don Hughes
Debra Baldauff
Bill Gates
Ex-Officio: Max Porter
CALL TO THE PUBLIC:
President Hughes announced that we have speaker slips for anyone wishing to speak on any action items. Speakers will
be called after the item is heard. Each speaker will have 2 minutes to speak.
No speaker slips were received.
President Hughes introduced our newest member to the Board of Health. Mr. Andrew Rascón, District 5 Board of
Supervisor Appointment. Mr. Rascón works for Southwest Center for HIV/AIDS and runs his own non-profit as well.
Welcome and congratulations Mr. Rascón on your appointment as our newest member.
DISCUSSION/ACTION ITEMS
1. Approval of Minutes: President Hughes asked for a motion to approve the BOH finance committee minutes from
the BOH Meeting held on July 23, 2018. Motion was made by Mr. MacMillan to approve the BOH finance committee
minutes as presented. Motion was seconded by Mr. Cassano and all were in favor. The motion passed unanimously.
Approval of Minutes: President Hughes asked for a motion to approve the BOH minutes from the BOH Meeting held
on July 23, 2018. Motion was made by Mr. Cassano to approve the BOH minutes as presented. Motion was seconded
by Ms. Halley and all were in favor. The motion passed unanimously.
2. Approval of FY20 OMB budget request Mr. Scot Pitcairn
Mr. Scot Pitcairn presented Department of Public Health’s budget request for FY2020.
For Fiscal Year 2020 Public Health Department’s total base budget request for this year is $58,150,751, a decrease of 6.2%
from the FY19 Revised budget. This consists of no increase to the General Fund budget, this fund remaining flat and on
target, a 9.8% decrease in the Grant Fund budget, and 1% increase in the Special Revenue Fund budget.
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A summary of our base budget request is as follows:
General Fund $ 12,868,622
Grants Fund 36,271,166
Special Revenue (Fee) Fund 9,010,963
TOTAL $ 58,150,751
Operating Budget
General Fund
The general fund request is shown at target baseline level. No increases are being requested at this time. This is not
intended to imply that all service levels are being adequately met. In order to remain at baseline targets we have budgeted
100% vacancy savings for one division administrator position and our PIO position and have eliminated one program
coordinator position.
Fee Fund
The Fee Fund operating budget is submitted $322,248 below the FY19 Revised budget, reflecting a reduction in the
Childhood Immunization budget that keeps expenditures within anticipated revenues. (This budget will be supplemented
by non-recurring funding).
Grant Fund
The decrease of $4,159,112 in the Grant Fund results from the loss and reduction in several grants, including cuts to WIC,
moving the Ryan White Dental Program to the Ryan White Office, reductions to Healthy Start, and various other grant
losses or reductions.
Non-Recurring Budget
General Fund
The $237,775 in one-time funding in the FY19 budget for the replacement X-Ray equipment at our TB Clinic was removed
from the FY20 budget.
Grant Fund
For FY20 the grant carryover/non-recurring budget is $500,000, an increase of $215,000 over the FY19 budget. This
increase reflects additional carry forward from the Smoke Free Grant and the HPHC (Healthy People Healthy Communities)
integrated IGA grants.
Fee Fund
Following the model used last budget year, we have budgeted funds from our fee fund balance, increasing it from
$593,300 in the current year to $1,000,000 in FY20. Of this amount, $200,000 is budgeted for our policy group. This group
will use these funds for childhood vaccination advocacy and in addressing the opioid epidemic in our county. In addition,
Vital Registration is budgeted $125,000 for expanding the east valley office. The Refugee Medical Assistance Program is
budgeted to use $125,000 since they have run short in funding as a result of the current administration reducing the
number of refugees admitted to the country. The remaining $550,000 is being allocated to address needs in the STD
Control program, Childhood Immunization and other mandated areas.
CSCA and ISF
Last year we requested a review above baseline from the Board of Supervisors due to large deficiencies in our funding.
We are not requesting a review this year but there is a funding gap that the Budget Office and county management are
aware of due to the CSCA and ISF charges placed on the Department. Last year in order to balance our budget, $913,296
was used from our Fee Fund balance and $547,457 was designated from non-departmental funds in the event our indirect
collections were insufficient to cover expenses.
Due to two factors, first the reduction of grant receipts and second the increase over the last several years in CSCA and
Internal Service Charges, our indirect collections are not sufficient to cover our administrative costs, ISF charges and CSCA
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charges combined. Over the past ten years we have internally reduced our administrative staff by 10 positions, saving
over $850,000. However, these reductions have increased the workload on existing staff to the point that we cannot
reduce internally further and still function properly. Our rent is a sizable part of our internal charges but we cannot reduce
that amount unless we are allowed to purchase a facility. Our current lease runs through 2023 and we are not certain
whether we will be able to legally get out of the lease obligation before the lease expires. This shortfall is projected in our
budget at $685,549. The solution to fill this gap is left open for further discussion before our budget recommendation is
finalized.
For this current fiscal year’s budget, the County Budget Office obligated $547,457 for this projected shortfall. We have
held positions and generated vacancy savings with our director’s position to help reduce the use of this commitment, but
those options will probably not exist in the next budget cycle. We also could tap further into our fee fund balance.
Regardless of the solution for this problem, both of these options are only a Band-Aid and will not solve the problem of
uncontrolled escalations of CSCA and ISF charges being pushed into limited grant funds. Further increases in our indirect
rates will only further decrease the delivery of services for mandated and other services that public health is expected to
provide to our community. Therefore, a more viable, longer-term solution needs to be researched.
We should also note with this budget submission that the base-level operating budget is likely unable to handle an
outbreak or emergency should one occur. The two items we see as likely are: 1) measles epidemiology responses and; 2)
the treatment of MDR or XDR Tuberculosis cases.
During this last year our community, along with large parts of the world, have dropped below the required vaccination
rates in our schools to accomplish the herd immunity effect for disease prevention of vaccine preventable diseases. The
most contagious of these is Measles. Measles outbreaks have occurred throughout Europe and other parts of the world
and have occurred in 26 states during 2018. Europe has been fighting this previously contained disease spread for over a
year. During last year, with a 93% vaccination rate (we are just under 95%) European nations had 64,000 cases of the
disease. The main cost of our response will be in the epidemiological tracking of the outbreak; the cost of these can range
from $50,000 to hundreds of thousands of dollars. This is why we have been so active in the work with the state to
decrease the personal exemptions being given out to parents who do not vaccinate their children with the school-required
immunizations. While the financial costs of these outbreaks are staggering, the risk of blindness, hearing impairment,
pneumonia and death (1-2 deaths out of every 1,000 cases) can have drastic consequences for children and families.
The second concern is one that we have seen during the last few budget years but the frequency seems to be escalating.
This is the occurrence of multi-drug resistant (MDR) and extreme drug resistant (XDR) Tuberculosis (TB). This strain of TB
is immune to the normal cost-effective drugs that we use to treat standard cases and requires two other types of drugs
that are extremely expensive. A single case can easily cost between $100,000 and $150,000 over the course of their 18-
month to 24-month treatment, and this does not include any surgically required responses. Non-compliant patients also
incur court costs and isolation costs. We cannot predict the number of cases we will have, but if they do occur we will
need to request additional funds as we have in the past.
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Motion to approve the FY20 OMB budget request for Public Health was made by Ms. Halley, seconded by Mr. Cassano
and all were in favor. The motion passed unanimously
3. Approval of FY20 OMB budget request Mr. Gus Martinez
Mr. Gus Martinez presented Department of Environmental Services’ budget request for FY2020.
FUND 100 (County General Fund)
Requested budget for Fund 100 operating is $247,221 in revenues and $9,459,591 in expenditures.
Revenues
Agency 880 is funded by the County General Fund subsidy. Environmental Services collects enforcement revenue from
non-permitted activities. These fines are associated with violations of the Environmental Health Code by persons and
organizations not subject to obtaining a permit. Requested budgeted revenues remain at $247,221 with no change
between FY2019 adopted and FY2020 requested.
In FY2019 Environmental Services acquired the waste resources department which is tasked with operating the counties
six transfer stations. These transfer stations collects approximately 220K in transfer station fees annually.
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Expenditures
Environmental Services General Fund Agency recommended operating budget expenditures are $9,459,591 or .73%
increase from FY19 adopted.
Requested budget includes a slight increase in the amount of supplies and services by 2% or $103,140 for increased costs
in equipment repairs.
Non-Reoccurring Expenditures
The Departments recommended budget includes non-reoccurring expenses in Fund 100 in the amount of $100,003 for
the following:
 IT Recommendations – $100,003
FUND 505 (County Grant Fund)
Requested budget for Fund 505 operating is $67,198 in revenues and $67,198 in expenditures.
Grant Funds
Agency 881 is a grant from the Food and Drug Administration Department of Health and Human Services. Environmental
Services was awarded the grant on September 10, 2015 in the amount of $67,198 for FY2020. The grant was approved by
the Board of Supervisors on October 21, 2015. The purpose of the grant is to advance conformance with the voluntary
national retail food regulatory program standards. The purpose of the grant is to advance conformance with the voluntary
national retail food regulatory program standards. This grant will serve in assessing foodborne illness risk factors in
Maricopa County and also provide permitted food operations with educational strategies to reduce the occurrence of
foodborne illness risk factors. In Year 2, Environmental Services is providing education to all Environmental Health staff
for implementing Active Managerial Control (AMC) principles during their inspections and train the operators to do the
same (Train the Trainer). This training is based on the results of the survey conducted in Year 1. Also, MCESD will develop
an AMC Toolbox, consisting of guidance documents, templates, logs, videos, and handouts on policies, training, and
verification. These materials will emphasize the shift to a population that learns through the oral and visual delivery of
information. Access to these materials will be streamlined via inspection reports, website design, and other mobile
platforms. AMC will be further incentivized by increasing public awareness of the Department’s voluntary AMC program:
the “Cutting Edge Food Safety Partnership.” Our Department will develop media to showcase Cutting Edge Program
participants.
Revenues
Revenues remain unchanged from FY2019 to FY2020 requested and are mandated by the terms of the grant.
Expenditures
Expenditures remain unchanged from FY2019 to FY2020 recommended and are mandated by the terms of the grant.
FUND 290 (Waste Tire Fund)
Requested budget for Fund 290 operating are $5,825,000 in revenues and $5,825,000 in expenditures.
Revenues
Revenues are received from the State of Arizona to fully cover the expenses to the county. These fees are not directly
collected by the county; they are collected through the purchase of a tire.
Expenditures
The Tire Fund expense budget has increased 14.97% from FY2019 to FY2020 to accommodate the increase tires received
at the tire recycling facility. Year over year, the fund has seen increased costs based on the number of registered vehicles
in Maricopa County.
FUND 506 (Environmental Fee Fund)
Requested budget for Fund 506 operating are $21,012,670 in revenues and $21,001,478 in expenditures.
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Revenues
Requested budgeted revenues for Fund 506 are $21,012,670 or $540,701 (3%) above FY2019 adopted.
Pool, food permitting, and environmental plan review are all experiencing a higher than average permit and plan review
submittals resulting in above budgeted revenue. This is primarily due to an uptick in construction projects as the economy
improves.
As plan review in both the Water and Waste and Environmental Health division’s continue to rise, so do the number of
permits being added. Environmental Services expects these trends to continue through FY2020.
Expenditures
Requested budgeted expenses at $21,001,478 or $599,204 (2.85%) above FY19 adopted. Requested budget includes
overall increase in personnel services by $348,968 or 2% with reductions to personal savings to accommodate the
increased workloads. Supplies and services have been increased by $250,236 due to an increase in central services cost
allocations.
Non-Reoccurring Expenditures
The Departments recommended budget includes non-reoccurring expenses in Fund 506 in the amount of $2,117,426 for
the following:
 Vehicles - $750,000
 Overtime – $125,000
 Rent – $93,954
 Contracting Services - $350,000
 IT Recommendations – $798,472
Motion to approve the FY20 OMB budget request for Environment Health was made by Mr. MacMillan, seconded by
Mr. Cassano and all were in favor. The motion passed unanimously
4. Fee Waiver Applications Ms. Jeannie Taylor
Ms. Jeannie Taylor presented 60 fee waivers for review and consideration of approval. A summary sheet document was
provided.
Motion to approve the 60 fee waivers applications was made by Ms. Halley, seconded by Mr. Cassano and all were in
favor. The motion passed unanimously.
5. Approval of initiation of regulatory change for the following rules: Gregory Verkamp
Kimberly Butler
Gregory Verkamp and Kimberly Butler presented 9 Rules for approval of initiation of regulatory changes. Gregory
explained that all rules are the beginning/initiation process. 8 lf the 9 rules EPA is behind them and will ultimately have
to be approved by the EPA.
A. AQ-2017-002
Rule 321 (Municipal Solid Waste Landfills)
The Maricopa County Air Quality Department (MCAQD) is proposing to revise Rule 321 to reflect the federal municipal
solid waste landfill emission guidelines as promulgated August 29, 2016 and codified at Title 40 (Protection of
Environment) of the Code of Federal Regulations (CFR), Part 60 (Standards of Performance for New Stationary Sources),
Subpart Cf (Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills). In addition, the MCAQD is
proposing to incorporate changes recommended by stakeholders, and to make other changes to improve and clarify the
rule.
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Motion to approve Rule 321 (Municipal Solid Waste Landfills) was made by Ms. Halley, seconded by Mr. MacMillan
and all were in favor. The motion passed unanimously.
B. AQ-2017-007
Rule 322 (Power Plant Operations)
Rule 323 (Fuel Burning Equipment from Industrial/Commercial/Institutional Sources)
Rule 324 (Stationary Reciprocating Internal Combustion Engines)
The MCAQD is proposing to revise Rules 322, 323, and 324 to address rule approvability comments provided by the
Environmental Protection Agency (EPA). These changes are required in order for the EPA to approve these rules as
Reasonably Available Control Technology (RACT) for control of nitrogen oxides, which are precursors to ozone formation.
The MCAQD is also proposing changes to address rule improvement comments provided by the EPA, to incorporate
changes recommended by stakeholders, and to make other changes to improve and clarify the rules.
Motion to approve Rule 322 (Power Plan Operations), Rule 323 (Fuel Burning Equipment from
Industrial/Commercial/Institutional Sources) and Rule 324 (Stationary Reciprocating Internal Combustion Engines) was
made by Mr. Cassano, seconded by Ms. Halley, and all were in favor. The motion passed unanimously.
C. AQ-2017-009
Rule 350 (Storage and Transfer of Organic Liquids (Non-Gasoline) at an Organic Liquid Distribution Facility)
Rule 351 (Storage and Loading of Gasoline at Bulk Gasoline Plants and Bulk Gasoline Terminals)
Rule 353 (Storage and Loading of Gasoline at Gasoline Dispensing Facilities)
MCAQD is proposing to revise Rules 350, 351, and 353 to address rule approvability comments provided by the
Environmental Protection Agency (EPA). These changes are required in order for the EPA to approve these rules as
Reasonably Available Control Technology (RACT) to reduce volatile organic compound (VOC) emissions. The MCAQD is
also proposing changes to address rule improvement comments provided by the EPA, to incorporate changes
recommended by stakeholders, and to make other changes to improve and clarify the rules.
Motion to approve Rule 350 (Storage and Transfer of Organic Liquids (Non-Gasoline) at an Organic Liquid Distribution
Facility), Rule 351 (Storage and Loading of Gasoline at Bulk Gasoline Plants and Bulk Gasoline Terminals) and Rule 353
(Storage and Loading of Gasoline at Gasoline Dispensing Facilities) was made by Mr. MacMillan, seconded by Mr.
Cassano and all were in favor. The motion passed unanimously.
D. AQ-2017-010
Rule 210 (Title V Permit Provisions)
The MCAQD is proposing to revise the MCAQD’s NSR rules in order to secure their approval as part of the State
Implementation Plan (SIP) under the federal Clean Air Act. The MCAQD’s NSR rulemaking is comprised of seven (7) rules,
including Rule 210. All of the NSR rules, with the exception of Rule 210, were approved for the initiation of regulatory
change by the Board of Health at the July 23, 2018 meeting. Rule 210 was not initiated at that time because revisions to
the rule were not anticipated. However, upon review of the U.S. Environmental Protection Agency’s (EPA’s)
recommendations, the MCAQD is requesting approval for the initiation of regulatory change in order to revise Rule 210.
Motion to approve Rule 210 (Title V Permit Provisions) was made by Mr. Cassano, seconded by Dr. Baldauff and all
were in favor. The motion passed unanimously.
E. AQ-2017-011
Rule 204 (Emission Reduction Credits for Use with the Arizona Emissions Bank)
The MCAQD is proposing to revise Rule 204 to add provisions for nontraditional sources of emission reduction credits.
Currently, the rule only allows for the generation, certification and utilization of emission reduction credits from permitted
74

sources. Proposed revisions include new provisions for the generation, certification, and utilization of emission reduction
credits from nontraditional sources that use truck stop electrification, electric standby equipped transport refrigeration
units, and electric onsite equipment. Revising the rule will provide additional sources of emission reduction credits that
will allow Maricopa County to move towards attainment of the National Ambient Air Quality Standards while still allowing
industrial growth.
Motion to approve Rule 204 (Emission Reduction Credits for Use with the Arizona Emissions Bank) was made by Mr.
Cassano, seconded by Dr. Baldauff and all were in favor. The motion passed unanimously.
Discussion Items:
1. Public Health Report Max Porter
I. Human Resources
II. Communication
III. Infrastructure
IV. Strategic Planning
V. Programs
VI. Disease Update
VII. Future Topics
Max Porter presented the Director’s Public Health Report.
The budget isn’t quite as depressing as the picture that was presented to you. Yes we have some concerns when it comes
to our indirect balance, the central service cots, the ISF funds (administrative costs) that we’re hit with. This isn’t just a
concern for us, it’s a concern for all grant funded departments or any department that has a grant. Budget office is looking
into it and is looking for a solution. They understand that it’s not sustainable the way it’s going. We are working with
them. We have sufficient funds for this year to get through. We have a year to work through this and get to a solution.
Our department (Public Health) and Human Services are both heavily, heavily grant funded. We are both under the same
Assistant County Manager Lee Ann Bohn. She is dedicated to working through this year to try to find a solution for that
problem. We will get through this year. We will do what we always do and we will have a successful year. I do want you
to be aware that it’s not quite as bleak as the picture would look on paper. We are a viable department and we are doing
some wonderful things.
We are part of the Big Cities Health Coalition. We’re not a city, we’re a county but we are the 3rd largest Health jurisdiction
in the Country behind New York and LA. Majority of Health departments are run through the City organizations
throughout the Country, your large metropolis areas. Back in the 50’s it was consolidated that all to the Counties because
we could consolidate better across city borders if we did it all in one. We’re the 3rd largest. Part of being a part of this Big
Cities Health Coalition it allowed us to go back to the meetings this year and we meet with the head of the CDC. We
explained to them that part of the problem we are seeing in our Health Departments is that you’re (the CDC) is sending
funding from the federal government, majority of our funding comes from the federal government, to the State. The State
dictates how they will meet deliverables which often don’t work for an urban area like we are and rural areas. So the
funding they are sending down is going through another massaging at the State level. The State is taking out administrative
expenses and then it goes down to the County department level and fewer and fewer services after each one of these
things happen are reaching the people. The CDC heard us. So in three months from that meeting we received our first
notice from the CDC that they are sending out instead of a grant a cooperative agreement. It’s a guaranteed receipt of
funds. We will be getting a new addition of 2.5 million dollars directly from the CDC for OPIOID control. The OPIOID
Cooperative Agreement guaranteed funding will hit us in August. We are hoping that this will be a beginning of the way
grant funding will flow to us. It gives us a lot better ability to change direction when a new problem hits us. Rather than
waiting for the State to determine that it is a problem this will give us the ability to change a grant deliverable directly.
We’re hoping that, that will be a good change for the future of the way our funding comes in.
75

As part of the director’s report here, the big question that if you don’t have you should have is when are we going to get
a new director? We are moving towards that direction. We have some very viable candidates that are in, we have some
good resumes and we’re doing interviews now. So we are hopeful that by your next meeting you will have a real director
that will be giving you this report. We’re hopeful that someone will be here and if they’re not here we will at least have
the name and date of when they will be here.
Childhood Vaccinations
You’re seeing reports almost daily in the news about childhood vaccinations. There is a huge debate with a large amount
of anti-vaxxers, I shouldn’t say large, there is a loud contingency of anti-vaxxers that are in the community. You have to
remember that we lost our herd immunity with our childhood immunizations.
 The majority of the population understand the importance of immunizations. They understand that they have to
participate if we’re going to protect the entire populous.
 There are also 2-3% can’t get vaccinations, they are people that are under treatment for cancer or they are
immune suppressed.
 The anti-vaxxers make up about 3% and they are extremely loud and they’re campaigning against vaccinations.
 6 bills in legislature
o 3 of the bills could really damage our vaccinations
o The anti-vaxxers are pushing harder and harder to give people personal exemptions for whatever reason.
o With legislation we can’t lobby, all we can do is educate.
o The Arizona Partnership for Immunization (TAPI),
Right now should be our peak of flu season
 H1N1 is hitting again
Congenital Syphilis
 Maricopa County Congenital Syphilis rates have doubled in the last 2 years.
 We have been said to be #1 in the nation, we are actually #5
 By statute – 1st trimester tested, 3rd trimester tested
o While it’s horrible the fix is simple
 Tested at delivery
 AHCCCS is on board
 Physicians reminded to test for syphilis in pregnant women
Community Health Survey
 MaricopaHealthMatters.org
 Why the Health Survey Matters
o Every three years, Maricopa County Department of Public Health, in collaboration with health care
and community partners, conducts a Community Health Survey to develop a deeper understanding
from residents about issues that relate to quality of life, availability of services, physical and mental
health, and more.
o The survey is part of a larger review of community health. This goes beyond individual health to look
at what is affecting the community overall, what health issues are affecting some communities more
than others, and what other factors contribute to those issues.
o This research is supported by Synapse, a collaboration of healthcare partners, and the Health
Improvement Partnership of Maricopa County (HIPMC).
o It is part of a broader review of the community’s health conducted in collaboration with seven
healthcare partners and over one hundred community organizations.
o MCDPH needs this to remain an accredited health department.
o Questions come from the National Association of County and City Health Organizations (NACCHO),
the Institute for Healthcare Improvement (IHI) and MCDPH staff, and are finalized for 2019.
o Data from this survey and the countywide health review are used to target programs, funds, and
attention to health needs with the greatest potential for impact and improvement.
76

 How the Survey is Being Conducted
o Goal is 15,000 surveys countywide with representation from all cities and towns
o Responses will be collected from March 1-May 31, 2019
o Robust outreach plan developed with partner organizations assisting in data collection
 What You Get and How You Can Help
 What you can get
o Access to de-identified data
o More responses will allow for more segmentation in data analysis
 How you can help
o Take the survey as a county resident
o Utilize MCDPH outreach toolkit to share the survey with your personal and professional networks
o Possible partnership with MCDPH epidemiologists to clean and analyze data
Community Health Improvement Plan – Grant Opportunity
 Shared Use - https://www.maricopa.gov/4386/Shared-Use
 Opening doors to physical activity and healthy eating.
 Opportunities for physical activity and access to healthy food are essential for health at all ages and stages
of life.
 Many neighborhoods throughout Maricopa County have limited access to spaces for children, youth, adults,
and seniors to easily choose to be active and to eat more nutritious food.
 By opening doors and expanding access to existing facilities, we can improve health and well-being across the
community.
 Maricopa County Department of Public Health (MCDPH) is offering grant funding up to $5000, per site, to
increase the number of spaces in under-served areas, so those community residents can: play exercise and
take part in recreational activities, grow healthy food and participate in nutrition related activities.
 Goal 100 schools opened
 $100,000 ($1500 - $5000 increments)
 School, Church or any public access
 Grant open until June 30th or until funding is gone
 Interested candidates must submit their response either by mail or email no later than May 31, 2019. For full
details, a copy of the request for quote (RFQ), or to submit a response, please visit: bit.ly/opendoorsgrant
ANNOUNCEMENTS AND CURRENT EVENTS
 Next Meeting – April 22, 2019
ADJOURNMENT: There being no further business, motion to adjourn the meeting was made by Ms. Halley, seconded by
Mr. Cassano and motion was passed unanimously. The meeting was adjourned.
77

April 26th 2021
Board of Health Meeting Minutes
Placeholder
78

Copies of All Written and Electronic Stakeholder Input
From: Suzanne Kennedy <suzanne.kennedy@asu.edu> Return to list of attachments
Sent: Wednesday, August 22, 2018 9:28 AM
To: Kristi Beck (AQD)
Subject: Rule Meeting Today and Comments on 322, 323, and 324
Hi Kristi,
I have been called into a meeting today and won’t make it to the rule meetings today. I just have a few comments as
follows:
1. Rule 322, Section 501.1 – This rule now requires records of the type and amount of fuel used, sulfur content
and days and hours of operation. I would like to remove the requirement to track days and hours of operation
and that fuel use be required to be tracked monthly. Fuel tracking monthly makes the most sense since invoices
are typically sent monthly (in the case of natural gas). I have been unable to identify a reason to track days and
hours of operation. This information does not appear to be needed to determine compliance.
2. Rule 323, Section 501.1 – This rule contains similar requirements for tracking fuel use and days/hours of
operation. I would like to request the same change as stated above.
3. Rule 324, Section 502.4.a – The hours of operation for emergencies should be specified in this section and
testing, reliability and maintenance hours should be grouped together as non‐emergency hours. Suggested
language is: “Monthly and rolling twelve month total hours of operation, emergency hours of operation, and
non‐emergency hours of operation (including hours for testing, reliability, and maintenance).”
I am so sorry that I won’t make it. Please call me if you have any questions.
Thanks!
Suzanne
Suzanne Kennedy
Associate Director, Environmental Compliance
Environmental, Health, and Safety
Arizona State University
Cell ‐ 602‐460‐8173
Desk – 480‐965‐1893
79

From: Mcclellan William J (Bill) <Bill.Mcclellan@srpnet.com> Return to list of attachments
Sent: Friday, September 21, 2018 7:54 AM
To: Kristi Beck (AQD)
Cc: Watt Kristin L
Subject: RE: Rule 322 Stakeholder Workshop - August 22, 2018
Kristi,
Could you clarify in the proposed language that the 168 hours per year is per combustion unit for the emergency fuel
combustion?
Thanks,
Bill
From: Kristi Beck (AQD) <Kristi.Beck@Maricopa.gov>
Sent: Friday, August 24, 2018 2:22 PM
To: Michael.Denby@aps.com; 'Ryan.Sweetwood (Ryan.Sweetwood@aps.com)' <Ryan.Sweetwood@aps.com>;
'Charles.Spell (Charles.Spell@aps.com)' <Charles.Spell@aps.com>; Mcclellan William J (Bill)
<Bill.Mcclellan@srpnet.com>; temerson@starwestgen.com
Cc: Kimberly Butler (AQD) <Kimberly.Butler@Maricopa.gov>; Gregory Verkamp (AQD)
<Gregory.Verkamp@Maricopa.gov>
Subject: Rule 322 Stakeholder Workshop ‐ August 22, 2018
*** SRP EXTERNAL EMAIL WARNING: EXERCISE CAUTION WHEN HANDLING
UNEXPECTED EMAILS. REPORT ANYTHING SUSPICIOUS. ***
Good afternoon,
Thank you for attending the Rule 322 stakeholder workshop. We appreciate the feedback that was provided and the
questions that were asked. The PowerPoint slides from the workshop are now available on EROP.
As we discussed during the workshop, I have removed option #3 from the proposed response to rule approvability
issue #3. I have also outlined a new compliance schedule that can be followed if the owner/operator chooses to
replace existing electric utility equipment. The revised draft commitment letter, which includes draft rule language to
address each commitment, is attached to this email. All feedback received before Tuesday, August 28, 2018 will be
reviewed and considered before the next conference call between MCAQD and EPA Region IX.
We also wanted to let stakeholders know that we will be adjusting the rulemaking timeline from what was presented
during the workshop. To ensure that the MCAQD has adequate time to complete the rulemaking process during
the 12-month timeframe stipulated by the Clean Air Act, the MCAQD will be going to the Board of Health in
October 2018 to request approval to initiate regulatory change. Following the Board of Health meeting, the
MCAQD will schedule a second Stakeholder Workshop (in November or December 2018) to discuss the draft rule
with stakeholders.
During the workshop, there was a question about what is required after EPA’s conditional approval. I have attached
EPA’s proposed conditional approval of the Maricopa County 2016 NSR package which explains the following: “If
the ADEQ and MCAQD meet their commitment to submit the required revisions and/or demonstrations within
80

12 months of the EPA’s final action on this SIP submittal, and the EPA approves the submission, then the
deficiencies listed above will be cured. However, if the MCAQD or the ADEQ fails to submit these revisions
and/or demonstrations within the required timeframe, the conditional approval will become a disapproval and the
EPA will issue a finding of disapproval. The EPA is not required to propose the finding of disapproval. Further, a
finding of disapproval would start an 18-month clock to apply sanctions under CAA section 179(b) and a two-year
clock for a federal implementation plan under CAA section 110(c)(1)” (Page 5).
Thank you for participating in the rulemaking process. If you have any questions, please let me know.
Kristi Beck • Senior Planner
Maricopa County Air Quality Department
1001 N. Central Avenue, #125 | Phoenix, AZ 85004
Located at the Central Ave. & Roosevelt METRO stop
Desk: 602.506.6706 | KristiBeck@mail.maricopa.gov
CleanAirMakeMore.com | Maricopa.gov/AQ
Help Reduce Ozone.
Drive Less, Refuel After Dark and Avoid Idling.
81

Return to list of attachments
From: Ryan.Sweetwood@aps.com
Sent: Friday, November 16, 2018 4:06 PM
To: Kristi Beck (AQD)
Cc: Kristin.Watt@srpnet.com; Bill.Mcclellan@srpnet.com; Eric.Massey@aps.com
Subject: DRAFT RULE 322 APS Comments 20181023_FINAL.docx
Attachments: DRAFT RULE 322 APS Comments 20181023_FINAL.docx; APS WP and Ocotillo NOx RACT Analysis
GTs 20181012.pdf
Kristi
The website only allows one document and it won’t show the red color in the Draft Rule Comments, so I am sending it
this way as well. Have a great weekend and holiday.
‐‐‐ NOTICE ‐‐‐
This message is for the designated recipient only and may contain confidential, privileged or proprietary information. If
you have received it in error, please notify the sender immediately and delete the original and any copy or
printout. Unintended recipients are prohibited from making any other use of this e‐mail. Although we have taken
reasonable precautions to ensure no viruses are present in this e‐mail, we accept no liability for any loss or damage
arising from the use of this e‐mail or attachments, or for any delay or errors or omissions in the contents which result
from e‐mail transmission.
82

1. Section 201 ‐ APS requests the following be deleted as it may be repetitive of the language it
preceeds: “The annual capacity factor is calculated by dividing actual heat input by potential
heat input or by dividing actual electrical output by potential electrical output.”
2. Section 204 – APS requests the following change: “Equipment or technology, such as including
but not limited to water injection …”
3. Section 302.4 – It is APS’s experience that Maricopa County already executes its enforcement
authority at the time that an exceedance of any emission limitation occurs. Typically the County
will issue a Notice of Violation, and, if necessary, an Administrative Order of Abatement on
Consent (AOC) to correct the exceedance. The conditions of both the NOV and the AOC can
include the authority to require injunctive relief which could include the development of a
corrective action plan. Since each exceedance should be reviewed on a case‐by‐case basis, and
the authority to seek injunctive relief already exists, APS does not believe that this provision of
the rule is necessary and recommends the deletion of this Section.
4. Section 303.2 – Maricopa County added a requirement to provide in writing the manufacturer’s
affirmation of the % drift rate. For existing cooling towers, APS is concerned that this
information may not be available as there was no requirement to maintain the written
affirmation of % drift rate when the existing cooling towers were permitted and built. APS
believes that it will be difficult to obtain documentation now after a decade or more post
construction. APS proposes that the requirement be amended to require documentation of %
drift rate of any new or reconstructed cooling towers as of the date of the re‐issued rule.
5. Section 307 – APS requests the following change: “An owner or operator of any equipment
listed in Section 102 of this rule shall not cause to be discharged into the atmosphere carbon
monoxide (CO) measured in excess of 400 ppmvdc per operating hourat any time.”
6. Section 501.7 –APS requests the following correction: “Equipment Referenced in Sections 104.4,
306.1, and 306.2 Operating Below less than or equal to 10% of Annual Capacity:”
7. Section 503.4 – This section should be corrected as follows: “CEMS: An owner or operator using
a CEMS to demonstrate compliance with Section 302, 306, or 307 shall install, operate,
calibrate, maintain, and test the CEMS in accordance with 40 CFR Part 60 or 40 CFR Part 75.
Excess emissions for Section 306 are defined as any period during which the 24‐hour rolling
average emission rate exceeds the applicable numeric emission limit. Excess emissions for
Section 307 are defined as any period which an operating hour average emission rate exceeds
the applicable numeric emission limit.
83

Return to list of attachments
Bill McClellan, Manager, Air Quality Services
PAB 359 I P.O. Box 52025
Delivering water and power"' Phoenix, AZ 85072-2025
P: (602) 236-5387 I F: (602) 236-3407
bill. mcclellan@srpnet.com
December 21, 2018
Ms. Kimberly Butler
Maricopa County Air Quality Department
3800 N. Central Ave. Suite 1400
Phoenix, AZ 85012
RE: SRP Comments Regarding Proposed Revisions to MCAQD's Rule 322
Dear Ms. Butler,
Salt River Project Agricultural Improvement and Power District (SRP) appreciates the
opportunity to comment on Maricopa County Air Quality Department's (MCAQD) proposed
revisions to Rule 322: Power Plant Operations and the Environmental Protection Agency's
(EPA) comments on Rule 322 submitted to EPA on December 19, 2016.
SRP is a political subdivision of the State of Arizona that provides retail electric services more
than 1 million residential, commercial, industrial, agricultural, and mining customers in Arizona.
As a vertically integrated utility, SRP provides generation, transmission and distribution
services, as well as metering and billing services. As part of its operations, SRP operates
several power plants located throughout Maricopa County. Accordingly, SRP has a clear and
significant interest in this pending action.
SRP appreciates MCAQD's extensive outreach efforts to stakeholders during the rule making
process for Rule 322. SRP participated in several of the public stakeholder meetings and has
provided both verbal and written comments; MCAQD addressed many of these comments in
subsequent drafts of the proposed rule. Since the most recent public stakeholder meeting,
MCAQD has made additional changes to the proposed revisions to Rule 322 based on an EPA
May 24, 2018 letter entitled "EPA Comments on the Maricopa County Air Quality Department
Rule 322 Power Plant Operations". SRP would like to provide comments on the proposed
changes to the rule and responses to EPA's comment letter.
SRP Comments Regarding EPA Comments on Rule 322
On May 24, 2018, EPA provided comments to MCAQD on the version of the rule dated
December 19, 2016 These comments included four rule approvability comments and eight rule
improvement comments. MCAQD must address the four rule approvability comments in order
for EPA to conditionally approve the rule, and must submit the changes responsive to these
comments to EPA in a "commitment letter".
1
84

In the third rule approvability comment, which focuses on the rule's case-by-case Reasonable
Available Control Technology (RACT) provisions, EPA states:
Section 306. 1 and 306. 2 allow for an owner or operator to comply with this rule by
submitting a case-by-case RACT analysis that will be incorporated into the permit. This
effectively exempts the source from the rule's NOx limits, GEMS requirements, and
administrative requirements. This conflicts with EPA's current policy on Director's
Discretion. To be approvable for RACT, the option to submit a case-by-case RACT
analysis should be removed, or the case-by-case RACT alternative must be submitted
for SIP approval.
SRP recommends that MCAQD state in its commitment letter response to EPA that MCAQD will
submit case-by-case RACT alternatives for SIP approval. However, SRP also recommends that
MCAQD not include an arbitrary cost-effectiveness threshold. SRP believes that any cost-
effectiveness threshold be determined in accordance with EPA costing guidelines and should be
included in the case-by-case RACT alternative. Specifically, the cost-effectiveness threshold
should be determined following EPA's 1994 memorandum1 and adjusted to 2018 using the
consumer price index ("CPI") for all urban consumers published by the Bureau of Labor
Statistics ("BLS")2 without being arbitrarily adjusted upward.
SRP supports MCAQD committing to conducting additional research and analysis to identify
alternative RACT requirements that are technologically and economically feasible and to
provide reasonable documentation to EPA to demonstrate that the requirements meet RACT.
SRP Comments Regarding Additional Rule 322 Changes
As MCAQD has proposed additional changes to Rule 322 addressing EPA's comments, SRP
offers the following comments on the current draft proposal.
I. Partial Exemptions
EPA's second rule approvability comment requests that Section 104.3, Partial Exemptions, be
amended to clarify that the exemption from certain emission limits for units that fire emergency
fuel is only valid during the 36 hours per year when emergency fuel is used. SRP has reviewed
MCAQD's revision to this section and would like to clarify that this exemption applies on a per
unit basis and proposes the following addition as indicated in red font:
104.3 While firing emergency fuel for purposes of testing, reliability, training, and
maintenance, any equipment listed in Section 102 of this rule that is normally
fired with natural gas is exempt from Sections 301, 306, 307, and 503 of this rule.
This exemption shall not exceed 36 hours per calendar year, excluding
hours of operating during natural gas curtailments and natural gas emergencies.
11. Definitions
1 See Memorandum "Cost-Effective Nitrogen Oxides {NOx} Reasonably Available Control Technology (RACT}, D.
Kent Berry, Acting Director, Air Quality Management Division, U.S. EPA, March 16, 1994
2 http://data.bls/gov/cgi-bin/surveymost?cu
2
Delivering water and power 1 "' 85

SRP requests that MCAQD revise the definition of Combustion Control System as follows:
204 COMBUSTION CONTROL SYSTEM: Equipment or technology, ~~:H"Y
water injection or low-NOx burners that suppress
NOx formation during combustion of fossil fuels.
SRP is requesting this proposed language to recognize that combustion control systems are not
limited to water injection or low-NOx burners.
Ill. Good Combustion Practices for Turbines
SRP proposes that MCAQD revise Section 302.1 - Parametric Monitoring to not remove the
words "valid maximum" from this paragraph referencing temperature differentials greater than
100°F. There could be an instance where there is a system error that shows a false reading
where temperature differential is greater than 100°F, but the condition is not actually occurring.
Section 302.3, Corrective Action Plan (CAP) - Parametric Monitoring and Section 302.4,
Corrective Action Plan - CEMS both requires sources to submit a CAP if conditions in these
requirements have been exceeded more than three times in three months.
SRP requests that the requirement to submit a CAP be removed from these provisions. If a
source were to exceed these requirements, it would constitute a permit deviation or excess
emission and MCAQD has enforcement discretion at the time the deviation or excess emission
is reported. In addition, sources subject to this requirement must prepare and submit a semi-
annual compliance report identifying instances of non-compliance.
IV. Monitoring and Records
SRP proposes to amend Section 501. 7 to be consistent with the exemption listed in Section
104.4 of this Rule:
501.7 Equipment Operating or 10% of Annual Capacity: At the end
of each month, calculate the annual capacity factor and NOx emissions for the
calendar year to demonstrate that the unit is eligible for the exemption in Section
104.4 of the rule.
3
Delivering water and power"' 86

SRP greatly appreciates the opportunity to provide comments on MCAQD's proposed revisions
to Rule 322 and the EPA's May 24, 2018 comments on Rule 322. If you have questions or
need additional information regarding these comments, please contact Kristin Watt at
kristin.watt@srpnet.com or 236-5488, or me at bill.mcclellan@srpnet.com or (602) 236-5387.
Sincerely,
Bill McClellan
Manager, Air Quality Services
cc: Kristy Beck, MCAQD
Kristin Watt, SRP
File: ORG 1-1-4
4
Delivering water and power"' 87

Return to list of attachments
From: Marina.Estrella@aps.com
Sent: Monday, April 20, 2020 8:10 AM
To: Gregory Verkamp (AQD)
Cc: Jack McCormack (AQD); Kimberly Butler (AQD); Bill.Mcclellan@srpnet.com; Anne.Carlton@aps.com
Subject: RE: AQ-2017-007-R322-WorkingDraft (1).docx
Attachments: AQ-2017-007-R322-WorkingDraft- APS Comments.docx
Hi Greg,
My apologies, I meant to send this your way last week. I am attaching our comments on draft rule 322 here. Please let
me know if you have any questions and/or need additional information on anything.
Thank you much!
Marina
From: Gregory Verkamp (AQD) <Gregory.Verkamp@Maricopa.gov>
Sent: Monday, April 13, 2020 8:06 AM
To: Estrella, Marina <Marina.Estrella@aps.com>
Cc: Jack McCormack (AQD) <Jack.McCormack@Maricopa.gov>; Kimberly Butler (AQD)
<Kimberly.Butler@Maricopa.gov>; Bill.Mcclellan@srpnet.com; Carlton, Anne B <Anne.Carlton@aps.com>; Hajduk, Mark
B <Mark.Hajduk@aps.com>
Subject: RE: AQ‐2017‐007‐R322‐WorkingDraft (1).docx
***CAUTION*** ***CAUTION*** ***CAUTIO
This e‐mail is from an EXTERNAL address (Gregory.Verkamp@maricopa.gov). DO NOT click on links or open attachments unless y
and know the content is safe. If you suspect this message to be phishing, please report it to the APS Cyber Defense Center at ACD
Great, thanks for the update Marina.
Greg Verkamp • Planning Supervisor
Maricopa County Air Quality Department
Desk: 602‐506‐7141 | CleanAirMakeMore.com
Help Reduce Ozone Pollution. Drive Less, Refuel After Dark and Avoid Idling.
From: Marina.Estrella@aps.com <Marina.Estrella@aps.com>
Sent: Monday, April 13, 2020 7:11 AM
To: Gregory Verkamp (AQD) <Gregory.Verkamp@Maricopa.gov>
Cc: Jack McCormack (AQD) <Jack.McCormack@Maricopa.gov>; Kimberly Butler (AQD)
<Kimberly.Butler@Maricopa.gov>; Bill.Mcclellan@srpnet.com; Anne.Carlton@aps.com; Mark.Hajduk@aps.com
Subject: RE: AQ‐2017‐007‐R322‐WorkingDraft (1).docx
Hi Greg,
Thank you for the reminder and reaching out. I am putting together everyone’s comments at APS and should have
something to you by this Friday the latest.
Thank you much,
Marina Estrella
88

Environmental Consultant, Environmental Support
(c): 480‐309‐8754
From: Gregory Verkamp (AQD) <Gregory.Verkamp@Maricopa.gov>
Sent: Friday, April 10, 2020 12:37 PM
To: Estrella, Marina <Marina.Estrella@aps.com>; Carlton, Anne B <Anne.Carlton@aps.com>; mark.hayduk@aps.com;
Mcclellan William J (Bill) <Bill.Mcclellan@srpnet.com>
Cc: Jack McCormack (AQD) <Jack.McCormack@Maricopa.gov>; Kimberly Butler (AQD) <Kimberly.Butler@Maricopa.gov>
Subject: RE: AQ‐2017‐007‐R322‐WorkingDraft (1).docx
***CAUTION*** ***CAUTION*** ***CAUTIO
This e‐mail is from an EXTERNAL address (Gregory.Verkamp@maricopa.gov). DO NOT click on links or open attachments unless y
and know the content is safe. If you suspect this message to be phishing, please report it to the APS Cyber Defense Center at ACD
Good afternoon Marina, Anne, Mark and Bill,
I am following up on your review of the working draft of Rule 322. Can you please update us on the status of your review
and let us know when you may be submitting comments to us?
Thanks.
Greg Verkamp • Planning Supervisor
Maricopa County Air Quality Department
Desk: 602‐506‐7141 | CleanAirMakeMore.com
Help Reduce Ozone Pollution. Drive Less, Refuel After Dark and Avoid Idling.
From: Gregory Verkamp (AQD)
Sent: Thursday, March 19, 2020 3:35 PM
To: Marina.Estrella@aps.com; Anne.Carlton@aps.com; mark.hayduk@aps.com; bill.mcclellane@srp.com
Cc: Jack McCormack (AQD) <Jack.McCormack@Maricopa.gov>; Kimberly Butler (AQD) <Kimberly.Butler@Maricopa.gov>
Subject: AQ‐2017‐007‐R322‐WorkingDraft (1).docx
Good afternoon Marina, Anne, Mark and Bill,
Attached is a copy of the working draft of Rule 322 for your review and comment. In order to see MCAQD comments
and markup you will have to go to the track changes option and select “All Markup”. If you could please provide us your
comments by April 3rd that would give us time to review and consider your comments, make revisions if necessary, and
then send a draft to the EPA for their review and comment before a potential workshop in May or June. If you need
more time for review and comment please let us know. Also, if you have any questions for us during your review please
let us know.
Sincerely,
89

Greg Verkamp • Planning Supervisor
Maricopa County Air Quality Department
3800 N. Central Avenue, #1400 | Phoenix, AZ 85012
Located near the Central Ave. & Indian School METRO stop
Desk: 602‐506‐7141 | Gregory.Verkamp@maricopa.gov
CleanAirMakeMore.com | Maricopa.gov/AQ
Burn Cleaner, Burn Better.
On No Burn Days, Don’t Burn Wood.
‐‐‐ NOTICE ‐‐‐
This message is for the designated recipient only and may contain confidential, privileged or proprietary information. If
you have received it in error, please notify the sender immediately and delete the original and any copy or
printout. Unintended recipients are prohibited from making any other use of this e‐mail. Although we have taken
reasonable precautions to ensure no viruses are present in this e‐mail, we accept no liability for any loss or damage
arising from the use of this e‐mail or attachments, or for any delay or errors or omissions in the contents which result
from e‐mail transmission.
90

Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
0MARICOPA COUNTY
AIR POLLUTION CONTROL REGULATIONS
REGULATION III - CONTROL OF AIR CONTAMINANTS Return to list of attachments
RULE 322 Commented [KB-A1]: The EPA is proposing that during
POWER PLANT OPERATIONS turbine startup, owners and operators must minimize the
turbine’s time spent at idle or holding at low load levels and
minimize the turbine’s startup time to a period needed for
INDEX
appropriate and safe loading of the turbine, not to exceed 1 hour
for simple cycle stationary combustion turbines and 3 hours for
SECTION 100-GENERAL combined cycle stationary combustion turbines, after which
time the formaldehyde emission limitation of 91 ppbvd or less at
101 PURPOSE 15-percent O2 applies. Minimizing the time spent at idle or low
load operation will minimize the time the turbine’s combustion
102 APPLICABILITY system is not at peak efficiency and the emission controls are
not at minimum operating temperatures.
103 EXEMPTIONS
104 PARTIAL EXEMPTIONS Proposed RTR for Stationary Combustion Turbines
84 FR 15046
SECTION 200-DEFINITIONS
201 ANNUAL CAPACITY FACTOR Commented [CCB2]: APS would like MCAQD to discuss
specifically how these changes will affect units that are already
202 COGENERATION STEAM GENERATING UNIT Comment - 15.1 operating under specific emission limits for NOx, CO and PM10 per
their permit conditions. If it is expected that it will not affect these
203 COMBINED CYCLE GAS TURBINE types of units, then they should be exempted or language inserted to
clarify so that the permitted units are not operated under two
204 COMBUSTION CONTROL SYSTEM different sets of emission limits.
204 205 CONTINUOUS EMISSION MONITORING SYSTEM (CEMS)
205 206 COOLING TOWERS
206 CORRECTIVE ACTION PLAN (CAP)
207 DISTILLATE OIL
208 207 DRIFT
209 208 DRIFT ELIMINATOR
210 209 DRIFT RATE
211 210 ELECTRIC UTILITY STATIONARY GAS TURBINE
212 211 ELECTRIC UTILITY STEAM GENERATING UNIT
213 212 EMERGENCY FUEL
214 EMERGENCY STANDBY UNIT
215 213 EMISSION CONTROL SYSTEM (ECS)
216 214 FOSSIL FUEL
217 215 FUEL SWITCHING STARTUP PROCESS
218 216 HEAT INPUT
219 217 HIGHER HEATING VALUE (HHV) OR GROSS HEATING VALUE
218 LOW SULFUR OIL
220 219 LOWER HEATING VALUE (LHV) OR NET HEATING VALUE
220 NATURAL GAS
221 NATURAL GAS CURTAILMENT
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222 OPACITY
223 OPERATING DAY HOUR
224 PARTICULATE MATTER EMISSIONS
225 PARTS PER MILLION BY VOLUME DRY CORRECTED (PPMVDC)
225 226 PEAK LOAD
226 227 POWER PLANT OPERATION
227 228 RATED HEAT INPUT CAPACITY
228 229 REGENERATIVE CYCLE GAS TURBINE
229 RESIDUAL OIL
230 SIMPLE CYCLE GAS TURBINE
231 STATIONARY GAS TURBINE
232 STEADY STATE
233 232 SULFUR OXIDES (SOX)
234 THIRTY (30) DAY ROLLING AVERAGE
235 THREE (3) HOUR ROLLING AVERAGE
236 233 TOTAL DISSOLVED SOLIDS (TDS)
234 TWENTY-FOUR (24) HOUR ROLLING AVERAGE
237 ULTRA LOW SULFUR DIESEL
238 235 UNCOMBINED WATER
239 WASTE DERIVED FUEL GAS
SECTION 300 – STANDARDS
301 LIMITATIONS - PARTICULATE MATTER
302 GOOD COMBUSTION PRACTICES FOR TURBINES
303 COOLING TOWERS
304 LIMITATIONS – OPACITY
305 LIMITATIONS - SULFUR IN FUEL
306 LIMITATIONS - NITROGEN OXIDES (NOX)
307 LIMITATIONS - CARBON MONOXIDE
308 REQUIREMENTS FOR ECS AND ECS MONITORING EQUIPMENT
309 EMERGENCY FUEL USE NOTIFICATION
SECTION 400 – ADMINISTRATIVE REQUIREMENTS
401 IN EXISTENCE AND IN COMPLIANCE
402 IN EXISTENCE AND NON-COMPLIANT
403 EMERGENCY STANDBY UNITS
SECTION 500 – MONITORING AND RECORDS
501 RECORDKEEPING AND REPORTING
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Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
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502 RECORDS RETENTION
503 COMPLIANCE DETERMINATION DEMONSTRATION
504 COMPLIANCE DETERMINATION-TEST METHODS INCORPORATED BY REFERENCE
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Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
Adopted 07/02/2003; Revised 10/17/2007; Revised 11/02/2016; Revised [Insert Date of Rule Adoption]
MARICOPA COUNTY
AIR POLLUTION CONTROL REGULATIONS
REGULATION III - CONTROL OF AIR CONTAMINANTS
RULE 322
POWER PLANT OPERATIONS
SECTION 100 - GENERAL
101 PURPOSE: To limit the discharge of nitrogen oxides, sulfur oxides, particulate matter and carbon monoxide
emissions into the atmosphere from stationary fossil-fuel-fired equipment at electric utility stationary gas
turbines, stationary fossil-fuel-fired electric utility steam generating units, or and stationary fossil-fuel-fired
cogeneration steam generating units and to limit particulate matter emissions from cooling towers associated
with this equipment.
102 APPLICABILITY: This rule applies to the following types of equipment that burn fossil fuel: Commented [KB-A3]: Megawatts is a unit of power (not a unit
of heat).
102.1 Each electric utility steam generating unit or cogeneration steam generating unit used to generate electric
power that has a heat input of equal to or greater than or equal to 100 million (MM) British thermal units
per hour (Btu/hour) (29 megawatts (MW)).
102.2 Each electric utility stationary gas turbine with a heat input at peak load equal to or greater than or equal
to 10 MMBtu/hour (2.9 MW) based upon the lower heating value of the fuel.
102.3 Each cooling tower associated with the type of equipment listed in Sections 102.1 and 102.2 of this rule.
102.4 NSPS & NESHAP: In addition to this rule, facilities may be subject to New Source Performance
Standards (NSPS) in Rule 360 and/or National Emission Standards for Hazardous Air Pollutants
(NESHAP) in Rule 370 of these rules.
103 EXEMPTIONS: This rule shall not apply to the following types of equipment:
103.1 Combustion equipment associated with nuclear power plant operations; or
103.2 Reciprocating internal combustion equipment engines. Commented [KB-A4]: Permitting Comment – It is possible and
even likely that we will have power plants comprised of IC engines
104 PARTIAL EXEMPTIONS: in the future. Should this happen, would we use Rule 324 or Rule
322 to cover an IC engine power plant. Discuss with Stakeholders.
104.1 Stationary gas turbines that meet any of the criteria listed below are exempt from Sections 301.1,
301.2, 306, 307, 308.4 and 501.4, 503.3, 503.4, 503.5, and 503.6 of this rule:
a. Used for fire-fighting
b. Used for flood control
Commented [KB-A5]: EPA TSD Deficiency #1 (12/11/19) -
Section 104.2 contains overly broad exemptions for units firing on
c. Engaged by manufacturers in research and development of equipment for either gas turbine emergency fuel. This is a RACT approvability issue since other
emission control techniques or gas turbine efficiency improvements similar rules for this category do not contain the broad exemptions
for unlimited periods of gas curtailment or delivery interruption. To
104.2 Any While firing emergency fuel during a natural gas curtailment or natural gas emergency, any be consistent with other RACT rules, the District should also limit
the total allowable length of emergency fuel burning to be consistent
equipment listed in Section 102 of this rule that is normally fired with natural gas, as allowed by a with other jurisdictions (see, Imperial County APCD Rule 400.1
permit issued by the Control Officer for that source, is exempt from Sections 301.1, 301.2, 306, 307, Section D.3).
308.4, 400 and 501.4, 503.3, 503.4, 503.5, and 503.6 of this rule while firing emergency fuel. This Commented [JM(6]: MCAQD Response – Limit set at 168
hours per calendar year per combustion unit.
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Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
exemption shall not exceed 168 hours per calendar year per combustion unit, excluding hours of
operation for testing, reliability, training and maintenance.
104.3 Any While firing emergency fuel for purposes of testing, reliability, training and maintenance, any Commented [KB-A7]: EPA TSD Deficiency #2 (12/11/19) -
equipment listed in Section 102 of this rule that is normally fired with natural gas only fires emergency Section 104.3 allows units that only fire emergency fuel for 36 hours
fuel for 36 cumulative hours per year or less, per unit for testing, reliability, training, and maintenance to be exempted from certain emission limits. This section needs to
purposes as allowed by a permit issued by the Control Officer for that source, is exempt from be amended to clarify the exemption is only valid during the 36
hours or less per year when emergency fuel is used.
Sections 301.1, 301.2, 306, 307, 501.4,308.4, and 400 503.3, 503.4, 503.5, and 503.6 of this rule. This
exemption shall not exceed 36 hours per calendar year per combustion unit, excluding hours of Commented [JM(8]: MCAQD Response – exemption has been
operation during natural gas curtailments and natural gas emergencies. clarified to use emergency fuel for purposes of testing, reliability,
training and maintenance not to exceed 36 hours per calendar year
per combustion unit.
104.4 Any equipment listed in Section 102 of this rule that operates at or below 10 percent calendar year
Commented [KB-A9]: If RACT is limited operating hours, list
annual capacity factor is exempt from Sections 306, 307, 308.4 and 400 of this rule. the unit specific requirements in Section 306.2 (Alternative RACT
requirements).
SECTION 200 - DEFINITIONS: For the purpose of this rule, the following definitions shall apply, in addition to
those definitions found in Rule 100 (General Provisions and Definitions) of these rules. In the event of any
inconsistency between any of the Maricopa County air pollution control rules, the definitions in this rule take
precedence.
201 ANNUAL CAPACITY FACTOR: The ratio between the actual heat input to a boiler or process heater
stationary gas turbine or steam generating unit from the fuels burned during a calendar year and the potential
heat input to the boiler or process heater stationary gas turbine or steam generating unit had it been operated
for 8,760 hours during a year at the maximum steady state design rated heat input capacity; or the ratio between
the actual electrical output of a machine or equipment stationary gas turbine or steam generating unit during a
calendar year and the potential electrical output of a machine or equipment stationary gas turbine or steam
generating unit had it been operated for 8,760 hours during a year at full nameplate capacity.
202 COGENERATION STEAM GENERATING UNIT: A steam or hot water generating unit that Commented [KB-A10]: Should we remove mechanical? A unit
simultaneously produces both electrical (or mechanical) and useful thermal energy (such as heat or steam) from that produces mechanical and thermal energy would not be able to
the same primary energy source and supplies more than one-third of its potential electric output to any utility provide electric output to the grid.
power distribution system for sale.
203 COMBINED CYCLE GAS TURBINE: A type of stationary gas turbine wherein heat from the turbine
exhaust is recovered by a steam generating unit to make steam for use in a steam-electric turbine.
204 COMBUSTION CONTROL SYSTEM: Equipment or technology that suppress NOX formation during Commented [KB-A11]: EPA TSD Recommendation #5
combustion of fossil fuels, including but not limited to, water injection or low-NOX burners. (12/11/19) - Section 308.1 uses the term “combustion control
system” and Section 308.3 uses the term “emission processing
204 205 CONTINUOUS EMISSION MONITORING SYSTEM (CEMS): The total equipment required to equipment,” neither of which are defined in this rule. We
recommend adding these definitions.
continuously sample and analyze emissions or process parameters such as opacity, nitrogen oxide, and oxygen
or carbon dioxide, and to provide a permanent continuous data record. Commented [JM(12]: MCAQD Response – Emission
processing equipment has been removed from this rule and
combustion control system has been defined.
205 206 COOLING TOWERS: Open water recirculating devices that use fans or natural draft to draw or force air
through the device to cool water by evaporation and direct contact.
206 CORRECTIVE ACTION PLAN (CAP): A methodical procedure that is used to evaluate and correct a
turbine operational problem and that includes, at a minimum, improved preventative maintenance procedures,
improved ECS operating practices, possible operational changes, and progress reports.
207 DISTILLATE OIL: A petroleum fraction of fuel oil produced by distillation that complies with the Commented [KB-A13]: “Distillate Oil” is not used in Rule 322.
specifications for fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in
ASTM D396-01, “Standard Specification for Fuel Oils.”
208 207 DRIFT: Water droplets, bubbles, and particulate matter that escape from cooling tower stacks.
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Maricopa County Air Quality Dept.
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Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
209 208 DRIFT ELIMINATOR: Device used to remove drift from cooling tower exhaust air, thus reducing water
loss by relying on rapid changes in velocity and direction of air-droplet mixtures by impaction on eliminator
passage surfaces. A drift eliminator is not categorized as an emission control system but is an inherent part of
the cooling tower's design requirements.
210 209 DRIFT RATE: Percentage (%) of circulating water flow rate that passes through a drift eliminator on a
cooling tower.
211 210 ELECTRIC UTILITY STATIONARY GAS TURBINE: Any stationary gas turbine that is constructed
for the purpose of supplying more than 1/3 of its potential electric output capacity to any utility power
distribution system for sale. Both simple and combined cycle gas turbines are types of electric utility stationary
gas turbines.
212 211 ELECTRIC UTILITY STEAM GENERATING UNIT: Any steam electric generating unit that uses
equipment that combusts fossil fuel to generate steam that is used to drive an electrical generator and is
constructed for the purpose of supplying more than one-third of its potential electric output capacity and more
than 25 MW electric output to any utility power distribution system for sale.
213 212 EMERGENCY FUEL: Fuel fired only during circumstances such as natural gas emergency, natural gas
curtailment, or breakdown of delivery system such as an unavoidable interruption of supply that makes it
impossible to fire natural gas in the unit. Fuel is not considered emergency fuel if it is used to avoid either peak
demand charges or high gas prices during on-peak price periods or due to a voluntary reduction in natural gas
usage by the power company. For the purposes of this definition, emergency fuel also includes fuel used for
purposes of testing, reliability, training, and maintenance.
214 EMERGENCY STANDBY UNIT: A stationary gas turbine that is limited by permit condition to be operated Commented [KB-A14]: “Emergency Standby Unit” is no longer
only as a mechanical or electrical power source for a facility when the primary power source for a facility has used in this rule.
been rendered inoperable due to failure beyond the reasonable control of the operator, except due to power
interruption pursuant to an interruptible power supply agreement. Electricity generated by such a unit cannot
be sold.
215 213 EMISSION CONTROL SYSTEM (ECS): A system approved in writing by the Control Officer, designed
and operated in accordance with good engineering practice to reduce emissions. Post-combustion systems that
are approved in writing by the Control Officer and are designed and operated in accordance with good
engineering practice to reduce emissions from combustion equipment. A combustion control system is not an
emission control system.
216 214 FOSSIL FUEL: Naturally occurring carbonaceous substances from the ground such as natural gas,
petroleum, coal and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of
creating energy.
217 215 FUEL SWITCHING STARTUP PROCESS: The act of changing from one type of fuel to a different type
of fuel.
218 216 HEAT INPUT: Heat derived from the combustion of fuel, not including the heat input from preheated
combustion air, recirculated flue gases, or exhaust gases from other sources, such as gas turbines, internal
combustion engines, and kilns.
219 217 HIGHER HEATING VALUE (HHV) OR GROSS HEATING VALUE: The amount of heat produced
by the complete combustion of a unit quantity of fuel determined by a calorimeter wherein the combustion
products are cooled to the temperature existing before combustion and all of the water vapor is condensed to
liquid.
218 LOW SULFUR OIL: Fuel oil containing less than or equal to 0.05% by weight of sulfur. Commented [KB-A15]: A stakeholder requested that the
existing SIP requirement for low sulfur oil be included in the revised
rule.
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Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
220 219 LOWER HEATING VALUE (LHV) OR NET HEATING VALUE: The amount of heat produced by
the complete combustion of a unit quantity of fuel determined by a calorimeter wherein the combustion
products are cooled to the temperature existing before combustion and all of the water vapor remains as vapor
and is not condensed to a liquid. The value is computed from the higher heating value by subtracting the water
originally present as moisture and the water formed by combustion of the fuel.
220 NATURAL GAS: A naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) Commented [KB-A16]: Source: MCAQD permit issued to a
produced in geological formations beneath the earth’s surface that maintains a gaseous state at standard power plant combusting natural gas.
atmospheric temperature and pressure under ordinary conditions, andconditions and contains 20 grains or less
of total sulfur per 100 standard cubic feet.
221 NATURAL GAS CURTAILMENT: An interruption in natural gas service, such that the daily fuel needs of
a combustion unit cannot be met with natural gas available due to one of the following reasons, beyond the
control of the owner or operator:
221.1 An unforeseeable failure or malfunction, not resulting from an intentional act or omission that the
governing state, federal or local agency finds to be due to an act of gross negligence on the part of the
owner or operator; or
221.2 A natural disaster; or
221.3 The natural gas is curtailed pursuant to governing state, federal or local agency rules or orders; or
221.4 The serving natural gas supplier provides notice to the owner or operator that, with forecasted natural
gas supplies and demands, natural gas service is expected to be curtailed pursuant to governing state,
federal or local agency rules or orders.
222 OPACITY: A condition of the ambient air, or any part thereof, in which an air contaminant partially or
wholly obscures the view of an observer. Return to list of attachments
223 OPERATING DAY HOUR: A 24-hour period between 0000 and 2359 during which any fuel is combusted
at any time in the unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. Commented [EM17]: This definition is different than federal
Any clock hour during which fuel is continuously combusted for 60 minutes. Comment 15.2 rules?
224 PARTICULATE MATTER EMISSIONS: Any and all particulate matter emitted to the ambient air as
measured by applicable state and federal test methods.
225 PARTS PER MILLION BY VOLUME DRY CORRECTED (PPMVDC): A unit of proportion used to Commented [KB-A18]: Definition suggested by a stakeholder.
express concentration that is corrected to a dry basis and to a reference oxygen content of 15% for stationary
gas turbines and 3% for electric utility steam generating units and cogeneration steam generating units.
225 226 PEAK LOAD: 100% of the manufacturer’s design capacity of a gas turbine at 288 Kelvin, 60% relative
humidity, and 101.3 kilopascals pressure (ISO standard day conditions).
226 227 POWER PLANT OPERATION: An operation whose purpose is to supply more than one-third of its
potential electric output capacity to any utility power distribution system for sale.
227 228 RATED HEAT INPUT CAPACITY: The heat input capacity in million Btu/hr. as specified on the
nameplate of the combustion unit. If the combustion unit has been altered or modified such that its maximum
heat input is different than the heat input capacity on the name plate, the maximum heat input shall be
considered the rated heat input capacity.
228 229 REGENERATIVE CYCLE GAS TURBINE: Any stationary gas turbine that recovers thermal energy
from the exhaust gases and utilizes the thermal energy to preheat air prior to entering the combustion unit.
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Maricopa County Air Quality Dept.
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Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
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229 RESIDUAL OIL: The heavier oils that remain after the distillate oils and lighter hydrocarbons are distilled off Commented [KB-A19]: “Residual Oil” is not used in Rule 322.
in refinery operations. This includes crude oil or fuel oil numbers 1 and 2 that have a nitrogen content greater
than 0.05 % by weight, and all fuel oil numbers 4, 5, and 6, as defined by the American Society of Testing and
Materials in ASTM D396-01, “Standard Specifications for Fuel Oils.”
230 SIMPLE CYCLE GAS TURBINE: Any stationary gas turbine that does not recover heat from the gas turbine
exhaust gases to preheat the inlet combustion air to the gas turbine, or that and does not recover heat from the gas
turbine exhaust gases to heat water or generate steam.
231 STATIONARY GAS TURBINE: Any simple cycle gas turbine, regenerative gas turbine, or any gas turbine
portion of a combined cycle gas turbine that is not self-propelled or that is attached to a foundation.
232 STEADY STATE: A safe, stable megawatt load at which a unit with equipment in normal operating Commented [KB-A20]: Removing the term “steady state” from
conditions is capable of being held for an extended period of time, without creating an unsafe or unstable Rule 322. The word was only used to describe conditions for
operating condition. performance tests. Performance test requirements are already
defined in Rule 270.
233 232 SULFUR OXIDES (SOX): The sum of the oxides of sulfur emitted from the flue gas from a combustion unit
that are directly dependent upon the amount of sulfur in the fuel used.
234 THIRTY (30) DAY ROLLING AVERAGE: An arithmetic mean or average of all hourly emission rates for 30 Commented [KB-A21]: EPA has indicated that a 30-day rolling
successive combustion operating days and calculated by a CEMS at the conclusion of each day for the previous average is too long of a time period for compliance determination
30 operating days. (See EPA TSD Recommendation #4 in Section 503).
Comment 15.3
Commented [CAB22R21]: This is the section we need to
235 THREE (3) HOUR ROLLING AVERAGE: An arithmetic mean or average of the most recent three one (1) create a real argument against. This is RACT not NSPS, etc.
hour tests, or an arithmetic mean or average over a period of three hours which is newly calculated with each Commented [JM(23]: MCAQD Response – 30-day rolling
hourly measurement. average removed as a definition.
Commented [KB-A24]: “3-Hour Rolling Average” is not used
236 233 TOTAL DISSOLVED SOLIDS (TDS): The amount of concentrated filterable matter reported in in Rule 322.
milligrams/liter (mg/l) or parts per million (ppm), as determined by an applicable method in the Standard
Commented [KB-A25]: ASTM D5907 and Standard Methods
Methods for the Examination of Water and Wastewater, a conductivity/TDS meter, or ASTM D5907. both refer to total dissolved solids as “filterable” (not concentrated).
234 TWENTY-FOUR (24) HOUR ROLLING AVERAGE: The arithmetic mean of all hourly emission rates
measured during the previous 24 operating hours.
237 ULTRA LOW SULFUR DIESEL: Fuel oil containing less than or equal to 0.0015 % sulfur by weight. Commented [KB-A26]: A stakeholder asked MCAQD to
remove the requirement to use ultra low sulfur diesel from Rule 322.
238 235 UNCOMBINED WATER: Condensed water containing no more than analytical trace amounts of other This requirement was added in 2016 and is not yet SIP approved.
chemical elements or compounds vapor or steam. Commented [KB-A27]: When EPA approved Rule 322 in 2007,
the TSD indicated that “analytical trace amounts” should be defined
239 WASTE DERIVED FUEL GAS: A gaseous fuel that is generated from the biodegradation of solid or liquid the next time the rule is revised.
waste including, but not limited to, digester gas and landfill gas. The term “uncombined water” is only used to describe the opacity
limits in Rule 322. The test method for determining compliance with
SECTION 300 – STANDARDS the opacity limits is EPA Method 9 (Visual Determination of the
Opacity of Emissions from Stationary Sources). It is not possible to
assess the presence or absence of “analytical trace amounts of other
301 LIMITATIONS – PARTICULATE MATTER: An owner or operator of any equipment listed in Section chemical elements or compounds” when conducting a Method 9
102.1 or 102.2 of this rule shall burn only natural gas except when firing emergency fuel per Sections 104.2 and visible emissions evaluation. Furthermore, Method 9 is already clear
104.3 of this rule. An owner or operator may burn a fuel other than natural gas for non-emergency purposes that visible emissions are estimated from the portion of the plume
providing that the fuel shall not cause to be discharged more than 0.007 lbs. of particulate matter per MMBtu. where steam and water vapor are not present (regardless of whether
there are air contaminants present in the steam plume).
The use of a fuel other than natural gas for non-emergency purposes shall be approved by the Control Officer
in an air pollution control permit prior to usage. Commented [KB-A28]: Rule 322 applies to equipment that
combusts fossil fuel. Waste derived fuel gas is not a fossil fuel.
301.1 Fuel Type: An owner or operator of any combustion equipment listed in Section 102 shall burn only Commented [KB-A29]: Moved performance testing
natural gas except when firing emergency fuel per Sections 104.2 and 104.3 of this rule. An owner or requirements to Section 503.
operator may burn a fuel other than natural gas for non-emergency purposes providing that the fuel
shall not cause to be discharged more than 0.007 lbs. of particulate matter per MMBtu during steady
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Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
state operations, demonstrated and documented through performance testing of this alternate fuel
using Test Method 5. This usage of different fuels other than natural gas shall be approved by the Commented [KB-A30]: EPA TSD Recommendation #1
Control Officer prior to usage. (12/11/19) - Section 302 describes good combustion practices for
turbines and states that any of three practices listed in 302.1, 302.2,
or 302.3 may be chosen. Section 302.3 says that if there is a pattern
301.2 Particulate Matter Testing A backhalf analysis shall be performed, using Reference Method 202 of non-compliance with the differential temperature measurement as
referenced in Section 504.6 of this rule, each time a compliance test for particulate matter emissions to required in 302.1, the Control Officer may require a Corrective
meet the standard in Section 301.1 of this rule is performed using Test Method 5. Action Plan (CAP). This appears to allow a facility to remain out of
compliance with the good combustion practice requirement. We
recommend revising this section to indicate that the Control Officer
302 GOOD COMBUSTION PRACTICES FOR TURBINES: During steady state operations, an An owner shall require the operator to submit a CAP.
or operator of any stationary gas turbine listed in Section 102.2 of this rule shall, regardless of fuel type, shall
use operational practices recommended by the manufacturer and parametric monitoring to ensure good Commented [JM(31]: MCAQD Response – Section 302.3 for
CAP removed.
combustion control as listed below. One of the following procedures may be used. For the purposes of this
rule, if a CEMS or another approved monitoring method is used, then the equipment would be exempt from Commented [KB-A32]: Last draft included good combustion
the requirements of Section 302 of this rule. The owner or operator shall demonstrate good combustion practices for steam generating units (to be used as a non-numeric
emission limit during startup and shutdown). That has been removed
control using parametric monitoring or a CEMS. based on EPA’s feedback that the SSM policy may be revised.
Commented [EM33]: If the definition of operating hour differs
302.1 Parametric Monitoring: Monitor the maximum temperature differential across the combustion from federal regulation, we’d like the following added at the end of
burners or at locations around the back end of the turbine, dependent upon the particular unit, to this section: with the exception of SUSD hours, as there are larger
ensure no more than a 100F difference using a thermocouple. Differential temperatures across the temperature differentials during these events. D
burners to demonstrate good combustion practices shall be measured and recorded from at least one Commented [CCB34]: The original purpose of this section was
minute data point during a complete steady state once during each operating houroperating hour. If a to ensure good combustion practices were being practiced to
valid maximum temperature differential of greater than 100F is observed across the burners, minimize particulate emissions (this and cooling towers were
originally created under section 301). The temperature spread was
investigation and corrective action shall be taken within three hours to reduce the temperature created to address units that did not perform PM10 testing at least
difference to 100F or less.; or Comment 15.4 & 15.5 once a permit term and had PM10 emission limits. Here I would like
to introduce that units that perform PM10 testing to meet a PM10
302.2 Alternative Maximum Temperature Differential: If the manufacturer recommends that the a permit limit are exempt from this section.
maximum numerical temperature differential to ensure good combustion is a temperature that is Commented [JM(35]: EPA TSD Recommendation #2
greater than 100°F to ensure good combustion, then proof of this maximum alternate temperature (12/11/19) – Section 302 states that if the owner or operator is using
differential shall be submitted to the Control Officer. The procedure to measure the maximum a CEMS or “other approved monitoring method,” then the
equipment is otherwise exempt from the requirements of 302.
temperature differential listed in Section 302.1 of this rule shall then be followed using this alternate However, this is problematic, as section 302.3 requires that a CAP
recommended maximum temperature differential after approval by the Control Officer. must be submitted to the Control Officer to remedy operation errors.
It does not appear that an owner or operator will need to take
302.3 If the frequency of failure to meet the proper temperature differential of 100°F or to meet the corrective action if a CEMS-equipped unit detects operation error.
Please include language that states that a CEMS-equipped unit
alternate temperature differential recommended by the manufacturer reflects a pattern that the turbine should take similar corrective action if an operational error is
is not being operated in a manner consistent with good combustion practices, then the Control detected. Section 302 also states that an owner or operator of an
Officer may require the owner or operator to submit a Corrective Action Plan (CAP). applicable stationary gas turbine “shall” use good operational
practices, but then states that one of the following procedures “may”
be used. Please clarify that the second statement also shall require
303 COOLING TOWERS: An owner or operator of a cooling tower associated with applicable units listed in one of the procedures listed in the subsections of Section 302.
Section 102.3 of this rule shall:
Commented [JM(36]: MCAQD Response – corrective action
required under 501.6. The reference to “may” has been changed to
303.1 Equip the cooling tower with a drift eliminator. The drift eliminator shall not be manufactured out of shall.
wood.;
Commented [KB-A37]: EPA TSD Recommendation #3
12/11/19 - Section 303.2 should be revised to include the units for
303.2 The Limit the value obtained by multiplying the concentration of Total Dissolved Solids (TDS) in the total dissolved solids (e.g., 20 mg/L).
cooling tower water multiplied by the percentage of drift rate shall for the cooling tower drift
eliminator such that the product does not exceed the maximum numerical limit of 20 ppm. MCAQD Response - Additional Info:
"After a review of the data from the power plants in Maricopa
County, the department required power plant cooling towers to meet
303.3 Visually inspect the drift eliminator according to the following schedule, as applicable depending on a single numerical limit that is the product of two variables. The
the configuration of the drift eliminator on a monthly basis only if the drift eliminator can be viewed limit, expressed as drift x TDS shall not exceed 20. This represents a
safely and does not require an owner or operator to walk into the tower. If the drift eliminator cannot 0.001% drift rate multiplied by a 20,000 ppm. Choosing one
be safely inspected monthly then Section 303.4 of this rule shall apply: numerical value that represents the product of two variables allows
for flexibility over the range of TDS and drift rates thus establishing
BACT for the existing power plants by rule. This standard levels the
a. Monthly, if the drift eliminator can be viewed safely and if the inspection does not require a playing field among the power plants and allows for operational
person to walk into the cooling tower; or flexibility to address the specific factors affecting cooling towers at
the existing power plants."
...
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AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
303.4 b. Visually inspect the drift eliminator for integrity No less than once per year during a regularly
scheduled outage when the cooling tower is not operating, if it cannot be inspected on a monthly
basis the drift eliminator cannot be safely inspected while the cooling tower is operating. This
visual inspection shall be no less than once per year.
304 LIMITATIONS – OPACITY:
304.1 An owner or operator shall not discharge into the ambient air from any single source of emissions any
air contaminant, other than uncombined water, in excess of 20% opacity, except as provided in
Section 304.2 of this rule.
304.2 Opacity may exceed the applicable limits established in Section 304.1 of this rule for up to one hour
during the one hour fuel switching startup process; however, opacity shall not exceed 40% for any six
(6) minute averaging period in this one hour period, provided that the Control Officer finds that the
owner or operator has, to the extent practicable, maintained and operated the source of emissions in a
manner consistent with good air pollution control practices for minimizing emissions. During the one
hour fuel switching startup process, an owner or operator shall not discharge into the ambient air
from any single source of emissions any air contaminant, other than uncombined water, in excess of
40% opacity, for any six (6) minute averaging period. The one hourone-hour period shall begin when
the fuel switching startup process begins.
304.3 Determination of whether good air pollution control practices are being used shall be based on
information provided to the Control Officer upon request, which may include, but is not limited to,
the following:
a. Monitoring results.
b. Opacity observations.
c. Review of operating and maintenance procedures.
d. Inspection of the source.
305 LIMITATIONS - SULFUR IN FUEL: An owner or operator of any applicable equipment listed in Section Commented [KB-A38]: Waste derived fuel gas is not a fossil
102.1 or 102.2 of this rule that burns fuel oil alone or in combination with any other fuel as either emergency fuel. Rule 322 applies to the types of equipment listed in Section 102
fuel or non-emergency fuel shall use only ultra low sulfur diesel oil. An owner or operator using waste derived that combust fossil fuels.
fuel gas shall use only waste derived fuel gas that contains no more than 0.08% sulfur by weight, alone or in
combination with other fuels.
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Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
306 LIMITATIONS – NITROGEN OXIDES (NOX): An owner or operator of any applicable equipment Commented [KB-A39]: EPA TSD Deficiency #3 (12/11/19) -
listed in Section 102.1 and 102.2 of this rule shall not cause to be discharged into the atmosphere nitrogen Sections 306.1 and 306.2 allow for an owner or operator to comply
oxides in excess of the following limits: with the rule by submitting a case-by-case RACT analysis that will
be incorporated into the permit. This effectively exempts the source
from the rule’s NOx limits, CEMS requirements, and administrative
306.1 RACT Emission Limits: requirements. This conflicts with the EPA’s current policy on
Control Officer discretion. To be approvable for RACT, the option
a. Existing Steam Generating Units: An owner or operator of any equipment listed in Section 102.1 to submit a case-by-case RACT analysis should be removed, or the
of this rule that commenced operation prior to (insert date of rule adoption) shall not cause to be case-by-case RACT alternative must be submitted for SIP approval.
discharged into the atmosphere nitrogen oxides in excess of 0.1 lb/MMBtu, calculated as nitrogen Commented [JM(40]: MCAQD Response – case by case
dioxide, unless the equipment is operated in compliance with the applicable alternative RACT RACT analysis must be approved by the Control Officer and the
requirements in Section 306.2 or in compliance with case-by-case RACT requirements Administrator, incorporated into an Air Pollution Control Permit,
and approved into the Arizona State Implementation Plan, see
established in accordance with Section 306.3 of this rule. section 306.3, or listed in Section 306.2 as an alternative RACT
requirement and approved into the SIP as part of Rule 322 SIP
b. New Steam Generating Units: An owner or operator of any equipment listed in Section 102.1 of submittal.
this rule that commenced operation on or after (insert date of rule adoption) shall not cause to be
discharged into the atmosphere nitrogen oxides in excess of the following limits, unless the
equipment is operated in compliance with the applicable alternative RACT requirements in Commented [K(41]: EPA TSD Deficiency #4 (12/11/19) - The
Section 306.2 or in compliance with case-by-case RACT requirements established in accordance RACT limits provided for NOx-emitting combustion units in
sections 306.1 and 306.2 are appropriate for stationary turbines.
with Section 306.3 of this rule. However, Rule 322 also applies to steam generating units. RACT
limits for these types of units is generally found to be more stringent
(1) 30 ppmvdc, calculated as nitrogen dioxide when burning gaseous fossil fuel. (for example, limits in many other jurisdictions are 30 ppmv for gas
fuel fired units, and 40 ppmv for liquid fuel fired units). The County
must reduce the overall limit for all applicable units to be at least as
(2) 40 ppmvdc, calculated as nitrogen dioxide when burning liquid fossil fuel. stringent at those demonstrated in EPA guidance or in other SIP
approved regulations or include a separate RACT limit applicable to
c. Stationary Gas Turbines: An owner or operator of any equipment listed in Section 102.2 of this steam generating units. Alternatively, the County must provide a
demonstration that the existing limits, or other limits adopted in a
rule shall not cause to be discharged into the atmosphere nitrogen oxides in excess of the modified rule, are appropriate and constitute RACT for Maricopa
following limits, unless the equipment is operated in compliance with the applicable alternative County.
RACT requirements in Section 306.2 or in compliance with case-by-case RACT requirements
Commented [JM(42]: MCAQD Response – New steam
established in accordance with Section 306.3 of this rule. generating units shall have a NOx limit of 30 ppmvdc for gas fueled
units and 40 ppmvdc for liquid fueled units unless qualifying for
306.1 (1) 42 ppmdv ppmvdc, calculated as nitrogen dioxide when burning gaseous fossil fuel. During alternative or case-by-case RACT requirements.
steady state operations, this test result using EPA Reference Method(s) 7 or other EPA-
approved test method designated by the Control Officer shall be based upon the arithmetic
mean of the results of three test runs. Each test run shall have a minimum sample time of one
hour. If CEMS is used for the compliance demonstration, the compliance demonstration shall
be based upon a 30-day rolling average. Any source for which the owner or operator submits
to the department a case-by-case reasonably available control technology analysis that is or will
be incorporated in a permit issued by the Control Officer for that source, is exempt from
Sections 306, 308.4, and 400 of this rule.
306.2 (2) 65 ppmdv ppmvdc, calculated as nitrogen dioxide when burning liquid fossil fuel. During
steady state operations, this test result using EPA Reference Method(s) 7 or other EPA-
approved test method designated by the Control Officer, shall be based upon the arithmetic
mean of the results of three test runs. Each test run shall have a minimum sample time of one
hour. If a CEMS is used for the compliance demonstration, the compliance demonstration
shall be based upon a 30-day rolling average. Any source for which the owner or operator
submits to the department a case-by-case reasonably available control technology analysis that
is or will be incorporated in a permit issued by the Control Officer for that source, is exempt
from Sections 306, 308.4, and 400 of this rule.
306.3 The nitrogen oxides concentration shall be measured dry and corrected to 3% oxygen for electric utility
steam generating units and cogeneration steam generating units. The nitrogen oxides concentration shall
be measured dry and corrected to 15% oxygen for stationary gas turbines and for combined cycle gas
turbines, during steady state operations.
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Maricopa County Air Quality Dept. Return to list of attachments
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
306.2 Alternative RACT Requirements: An owner or operator of an affected unit listed in Table 322-1 Commented [EM43]: Please remove the West Phoenix, and the
shall comply with the applicable alternative RACT requirements specified in Table 322-1, unless the Ocotillo Power Plant alternative work requirements from the table
affected unit is operated in compliance with the case-by-case RACT requirements established in below. Rule 322 Section 104.4 submitted to EPA originally
accordance with Section 306.3 of this rule. An owner or operator shall be exempt from Section 306.1 contained an exemption for units operating below 10% calendar year
annual capacity factor. A RACT Analysis was performed and
of this rule if the owner or operator fully complies with the applicable alternative RACT requirements submitted to the County to provide justification for this exemption
in Table 322-1. for West Phoenix units GT1 and GT2 and Ocotillo units GT1 and
Comment 15.6 GT2 since the units were under the 10% annual capacity factor.
Table 322-1 We’d like section 104.4 added to the rule and the specific alternative
RACT requirement removed from the rule since EPA acknowledged
Facility Name Affected Units Alternative RACT Requirements the 10% exemption and did not disapprove as part of their
West Phoenix Simple Cycle 1 – 55 MW Combust no more than 722,700 disapproval of 322.
Power Plant MMBtu of natural gas per calendar Commented [KB-A44]: 137 tons/year
year in the SC1 unit.
Simple Cycle 2 – 55 MW Combust no more than 722,700
MMBtu of natural gas per calendar Commented [KB-A45]: 137 tons/year
year in the SC2 unit.
Ocotillo Power Simple Cycle 1 – 55 MW Combust no more than 722,700
Plant MMBtu of natural gas per calendar Commented [KB-A46]: 137 tons/year
year in the SC1 unit.
Simple Cycle 2 – 55 MW Combust no more than 722,700
MMBtu of natural gas per calendar Commented [KB-A47]: 137 tons/year
year in the SC2 unit.
Agua Fria Steam Boiler 1 – 114 MW To be determined
Generating
Station
Steam Boiler 2 – 114 MW To be determined
Steam Boiler 3 – 163 MW To be determined
Simple Cycle 4 – 90 MW To be determined
Simple Cycle 5 – 90 MW To be determined
Simple Cycle 6 – 90 MW To be determined
Kyrene Steam Boiler 1 – 34.5 MW To be determined
Generating Steam Boiler 2 – 73.5 MW To be determined
Station
Simple Cycle 4 – 53.1 MW To be determined
Simple Cycle 5 – 60 MW To be determined
Simple Cycle 6 – 60 MW To be determined
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Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
306.3 Case-by-Case RACT Requirements: Nothing in this rule shall prevent the owner or operator of
any equipment listed in Section 102 of this rule from requesting alternative RACT requirements on a
case-by-case basis. An owner or operator shall be exempt from Section 306.1 and 306.2 if the owner
or operator fully complies with alternative RACT requirements that are approved by the Control
Officer and the Administrator, incorporated into an Air Pollution Control Permit, and approved into
the Arizona State Implementation Plan.
307 LIMITATIONS - CARBON MONOXIDE: An owner or operator of any equipment listed in Section 102.1 Commented [KB-A48]: Compliance determination procedures
or 102.2 of this rule shall not cause to be discharged into the atmosphere carbon monoxide (CO) measured in moved to Section 503.5.
excess of 400 ppmv ppmvdc at any time. During steady state operations, this test result, using EPA Reference
Method 10 or other EPA-approved test method designated by the Control Officer and performed during steady
state compliance source testing, shall be based upon the arithmetic mean of the results of three test runs. Each test
run shall have a minimum sample time of one hour. The CO concentration shall be measured dry and corrected
to 3% oxygen for electric utility steam generating units and cogeneration steam generating units. The CO
concentration shall be measured dry and corrected to 15% oxygen for stationary gas turbines and for combined
cycle gas turbines, during steady state operations.
308 REQUIREMENTS FOR ECS AND ECS MONITORING EQUIPMENT: An owner or operator of an Commented [KB-A49]: EPA TSD Recommendation #5
emission control system (ECS) shall: (12/11/19) - Section 308.1 uses the term “combustion control
system” and Section 308.3 uses the term “emission processing
308.1 For affected operations which may exceed any of the applicable standards set forth in Section 300 of this equipment,” neither of which are defined in this rule. We
recommend adding these definitions.
rule, an owner or operator may comply by installing and operating an emission control system (ECS) or
a combustion control system which reduces emissions to below the applicable standards in Section EPA TSD Recommendation #6 - Section 308.3 describes Operations
300 of this rule. and Maintenance (O&M) Plan requirements for an Emission Control
System. Operation & Maintenance plans are required at section
308.2 to describe the function and maintenance of monitoring
308.2 308.1 An owner or operator required to use an approved ECS pursuant to this rule shall not do so without equipment. Section 308.3b states that O&M plans shall be submitted
first properly installing, operating, and maintaining in calibration and in good working order, Properly to the Control Officer for approval. Section 308.3e states that the
install, operate, and maintain in calibration and in good working order devices for indicating Control Officer may modify O&M plans. In both of these instances,
temperatures, pressures, transfer rates, rates of flow, or other operating conditions necessary to there is no discussion as to what criteria these plans or discretionary
modifications are intended to meet. We recommend adding such
determine if air pollution control equipment an ECS is functioning properly and is properly maintained criteria.
as described in an approved Operation and Maintenance (O&M) Plan.
Commented [JM(50]: MCAQD Response to #5 - Emission
processing equipment has been removed from this rule and
308.3 Operation and Maintenance (O&M) Plan Required for ECS: combustion control system has been defined.
Commented [JM(51]: MCAQD Response to #6 – Specific
a. 308.2 General Requirements: An owner or operator shall provide and maintain Submit to the Control Officer criteria has been added to the O&M Plan requirements. See section
for approval an Operation and Maintenance (O&M) Plan for any ECS, any other emission processing 308.2.
equipment, and any ECS monitoring devices that are used pursuant to this rule or to an air pollution Must fully comply with all the elements of the O&M plan per
permit. The O&M Plan shall include: section 308.3.
a. The manufacturer name, model designation, and serial number for each ECS and each ECS
monitoring device;
b. Operating parameters that will be monitored to demonstrate continued operation of the ECS in the
manner the ECS was operated during the most recent performance test; and
c. The manufacturer’s recommended maintenance procedures and frequencies or, if the
manufacturer’s recommended maintenance procedures are not available, a maintenance plan based
on good engineering practices to reduce emissions.
b. Approval by Control Officer: An owner or operator shall submit to the Control Officer for approval
the O&M Plans of each ECS and each ECS monitoring device that is used pursuant to this rule.
c. 308.3 Initial Plans: An owner or operator who is required to have an O&M Plan pursuant to this rule shall
Fully comply with all elements of the most recent O&M Plans that the owner or operator has submitted
for approval, but which have not yet been approved submitted to the Control Officer, unless notified by
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Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
the Control Officer in writing. Once the initial plan has been approved in writing by the Control Officer,
an owner or operator shall then comply with the approved plan.
d. 308.4 Revisions to Plan: An owner or operator may revise an initial O&M plan by submitting written revisions
to the Control Officer. The owner or operator shall at all times comply with the latest version of the
O&M Plan submitted to the Control Officer. Submit a revised O&M Plan within 30 business days
following receipt of the Control Officer’s written notice that an O&M Plan for any ECS or any ECS
monitoring device is deficient or inadequate.
e. 308.5 Control Officer Modifications to Plan: After discussion with the owner or operator, the Control Officer
Return to list of attachments
may modify the plan in writing prior to approval of the initial O&M plan. An owner or operator shall
then comply with the plan that has been modified by the Control Officer. Maintain on-site, in a readily
accessible location, the most recent O&M Plans for each ECS and each ECS monitoring device. Commented [EM52]: Does this include electronic copies as
well?
308.4 Emission Compliance Demonstration: Comment 15.7
a. An owner or operator of an electric utility stationary gas turbine, electric utility steam generating
unit or cogeneration steam generating unit used to generate electric power subject to Section 306 of
this rule with a heat input of greater than 250 MMBtu/hr, regardless of fuel type, shall install,
calibrate, maintain, and operate a CEMS or conduct stack tests as approved by the Control Officer
for measuring nitrogen oxides. Where nitrogen oxide emissions are monitored by a CEMS, then a
CEMS shall also be required for the measurement of the oxygen content of the flue gases. All
CEMS shall comply with the provisions in 40 CFR Part 60.
b. An owner or operator of any affected electric utility stationary gas turbine, electric utility steam
generating unit or cogeneration steam generating unit used to generate electric power listed above
that requires a CEMS for nitrogen oxides that meets and is continuing to meet the requirements of
40 CFR Part 75 or Part 60 may use that CEMS to meet the requirements of Section 308.4(a) of this
rule.
309 EMERGENCY FUEL USE NOTIFICATION: An owner or operator of an electric utility stationary gas Commented [KB-A53]: EPA requested notification at the end
turbine, electric utility steam generating unit or cogeneration steam generating unit used to generate electric power of emergency fuel use in 2017 written comments on Rule 322.
that is fired with emergency fuel but is normally fired with natural gas shall notify the Control Officer verbally no
later than 24 hours after declaration of the emergency that necessitates its use in compliance with Section 104.2 of
this rule. This verbal report shall be followed by a written report within 48 hours of initial emergency fuel usage.
The written report shall also include identification of the nature of the emergency, initial dates of usage, and the
expected dates of usage. Within 1 business day following the end of an emergency that necessitates the use of
emergency fuel, the owner or operator shall submit a written report that includes the total number of hours the Commented [KB-A54]: EPA TSD Recommendation #7
combustion equipment was operated with emergency fuel. (12/11/19) - Section 401 describes the compliance schedule for units
that are currently operating and determined to be compliant with
NOx emission limits. NOx facilities must submit a “Notification of
SECTION 400 - ADMINISTRATIVE REQUIREMENTS Compliance” which must consist of one of the two following
options: a. Demonstrate there was already a performance test and
401 IN EXISTENCE AND IN COMPLIANCE: Except as set forth in Section 104.4 of this rule and the case- include the results of said test. This test must have been conducted
by-case RACT analysis of Section 306.1 of this rule, the The owner or operator of any electric utility stationary within the past five years. Clarify what is intended by “performance
test” in this context (e.g. “performance stack test”). b. Outline the
gas turbine, electric utility steam generating unit or cogeneration steam generating unit used to generate electric timeline for a performance test. There are also no constraints on how
power in existence on November 2, 2016 [insert date of rule adoption] and subject to the emission limits in long an owner or operator might take to conduct this test after
Section 306 of this rule shall submit a Notification of Compliance within 6 months of becoming subject to submitting this “Notification of Compliance,” beyond indicating that
Section 306 of this rule. This Notification shall include one of the following demonstrations: indicate how a timeline shall be included. Please include a limit for how long a
compliance with the NOX limit has been determined and if performance testing is required to demonstrate timeline may extend.
compliance. If performance testing is required to demonstrate compliance, the Notification shall include a MCAQD Response - Section 401.1 states that the performance test
timeline for the test. Performance test results from a past test may be used for this determination, as long as the must be conducted in accordance with Rule 270 (Performance Tests)
test was conducted within 5 years before November 2, 2016. If compliance under Section 401 of this rule of these rules.
cannot be demonstrated, an owner or operator of any electric utility stationary gas turbine, electric utility steam
Section 401.1 states that the performance test result indicating
generating unit or cogeneration steam generation unit used to generate electric power shall comply with Section compliance must be included with the Notification of Compliance.
402 of this rule. Demonstrating compliance within 6 months is consistent with what
is required in Rule 270 (source testing within 180 days).
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Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
401.1 Demonstration of Compliance with RACT Emission Limits: For each unit that is in compliance
with the RACT emission limits in Section 306.1 of this rule, the Notification of Compliance shall
include results from a performance test conducted in accordance with Rule 270 of these rules after
[insert date – one year before rule adoption].
401.2 Demonstration of Compliance with Alternative RACT Requirements: To be determined.
402 IN EXISTENCE AND NON-COMPLIANT: Commented [KB-A55]: EPA TSD Deficiency #5 (12/11/19) -
Section 402 describes the compliance schedules and requirements
402.1 Increments of Progress – Installation of Air Pollution Control Equipment: Except as set forth for NOx in units that are found to be non-compliant. Owners and
in Section 104.4 of this rule and the case-by-case RACT analysis of Section 306.1 of this rule, when air operators must comply with section 402.2 Increments of Progress, or
section 402.3 Removal From Service. Increments of progress (i.e.,
pollution control equipment is required When an emission control system or a combustion control compliance deadlines) may be extended by the Control Officer as
system will be installed to achieve compliance with the emission limits in Section 306.1 of this rule, needed. This Control Officer discretion, which conflicts with EPA’s
the owner or operator shall comply with the following increments of progress and be in compliance current policy on Control Officer discretion, should be removed or
with the emission limits by the date specified: in Section 402.2 of this rule and be in compliance with appropriately constrained. Section 402.3 allows for the removal from
service process to last up to a total of two years, or more time if the
the emission limits by the date specified in Section 402.2 of this rule. County did not act expeditiously on the permit revision. Units are
exempt from NOx limits during this time. The amount of time that
402.2 Increments of Progress: The owner or operator of any electric utility stationary gas turbine, electric these units are out of compliance should be bounded and minimized,
utility steam generating unit or cogeneration steam generating unit used to generate electric power e.g. by providing a backstop date by which all units must achieve
compliance.
subject to the emission limits in Section 306 of this rule shall comply with the following increments of
progress. The Control Officer, upon the request of the owner or operator, may extend the increments MCAQD Response - remove the provisions allowing the Control
of progress. The following compliance schedule does not apply to units already compliant with this Officer to extend increments of progress. MCAQD is also proposing
rule as of November 2, 2016: to add a backstop date to Section 402.2.c to require removal from
service within 2 years after a unit becomes subject to the emission
limits in Section 306.1 of this rule.
a. Within 18 months of becoming subject to the emission limits in Section 306.1 of this rule, submit
a compliance schedule and permit application to the Control Officer.
b. Within 36 months of final permit issuance, be fully compliant with the emission limits in Section
306.1 of this rule and submit to the Control Officer a complete source test report indicating
compliance.
402.3 402.2 Increments of Progress – Removal From Service: The owner or operator of any combustion unit
in existence on November 2, 2016 that is expected to be removed from service within 24 months of
becoming subject to Section 306 of this rule shall be exempt from the emission limits in Section 306
of this rule if it complies with the following:
a. Within 6 months of becoming subject to the limits in Section 306 of this rule, submit to the
Control Officer a notification of proposed removal from service.
b. Within 14 months of submitting notification under Section 402.3(a) 402.2(a) of this rule, submit
to the Control Officer a decommissioning plan and a permit revision providing that the units will
be decommissioned by a certain date.
c. Within 4 months of decommissioning plan and permit revision approval, or within 24 months
after becoming subject to the emission limits in Section 306 of this rule, whichever comes first,
discontinue operation of the electric utility stationary gas turbine, electric utility steam generating
unit or cogeneration steam generating unit used to generate electric power, disconnect the fuel
supply line(s), and notify the Control Officer in writing of the removal from service. Operation
of any electric utility stationary gas turbine, electric utility steam generating unit or cogeneration
steam generating unit used to generate electric power beyond 4 months of decommissioning plan
and permit revision approval, shall be conducted in compliance with the emission limits in
Section 306 of this rule.
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Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
403 EMERGENCY STANDBY UNITS: The owner or operator of any emergency standby unit in existence prior
to November 2, 2016 shall by January 2, 2017, submit to the Control Officer a notification requesting an
exemption from the requirements of Section 300 of this rule.
SECTION 500 - MONITORING AND RECORDS
501 RECORDKEEPING AND REPORTING: Any owner or operator subject to this rule shall comply with
the requirements set forth in this section. Any records and data required by this section shall be kept on site at
all times in a consistent and complete manner and be made available without delay to the Control Officer or his
designee upon request. Records shall consist of the following information:
501.1 Equipment Listed in Section 102 of this Rule: Days and hours of operation, type(s) of fuel used,
amount of fuel(s) used each month, amount of sulfur in the fuel if using liquid fuel, and the days and
hours of operation and documentation of the sulfur content of any fuel oil combusted (e.g. fuel receipts,
contract specifications, pipeline meter tickets, fuel supplier information, purchase records, or analytical
results). Records of sulfur content shall provide accurate values for the sulfur content of the fuel based
on enforceable test methods approved by the Administrator.
501.2 Cooling Towers: Monthly gravimetric testing reports for TDS in cooling water in the cooling tower
shall be recorded for six months in succession and thereafter quarterly reports shall be recorded. Results
of the monthly or yearly visual inspection of the drift eliminator shall also be recorded. If the drift
eliminator cannot be visually inspected monthly, then documentation of the physical configuration of
the drift eliminator shall be submitted to the Control Officer to demonstrate that the drift eliminator
cannot be inspected monthly.
501.3 Emergency Fuel Usage: Type and amount of emergency fuel used, dates and hours of operation
using emergency fuel, nature of the emergency or reason for the use of emergency fuel as stated in
Sections 104.2 and 104.3 of this rule. At the end of each month, calculate the total hours of operation
using emergency fuel during natural gas curtailments and natural gas emergencies, and total hours of
operation using emergency fuel for purposes of testing, reliability, training, and maintenance.
501.4 Non-Emergency Fuel Switching: Monthly records of fuel switching including stop and start times, Commented [KB-A56]: Section 501.4 duplicates the
monthly records of hours of operation for testing, reliability and maintenance purposes per Section requirements of Section 501.3. Revised section 501.4 to clarify that
104.3 of this rule, and a yearly log total of these hours. Dates and times, including start and stop times, these requirements apply when a fuel other than natural gas is
when any fuel other than natural gas is combusted for non-emergency purposes, as allowed by Section burned for non-emergency purposes.
301 of this rule.
501.5 Continuous Emission Monitoring Systems: All CEMS measurements, results of CEMS
performance evaluations, CEMS calibration checks, and adjustments and maintenance performed on
these systems. Return to list of attachments
501.6 Good Combustion Practices: Measurements of the temperature differential across the burners of Commented [EM57]: If we are meeting CEMS compliance
turbines per Section 302 of this rule, results of evaluation and of corrective action taken to reduce the requirements is this section required? Please see comment below
temperature differential or a finding that the temperature differential returned to the range listed in too.
Sections 302.1 or 302.2 of this rule without any action by the owner or operator. For the purposes of Commented [CCB58R57]: The original purpose of this section
this rule, if a CEMS or other approved monitoring method is used, then the equipment would be was to ensure good combustion practices were being practiced to
exempt from the requirements of Section 302 of this rule is used to demonstrate good combustion minimize particulate emissions. The temperature spread was created
practices, results of evaluation and of corrective action shall be recorded each time the CEMS indicates to address units that did not perform PM10 testing and/or had PM10
permit limits.
an exceedance of the applicable emission limits in Section 306 of this rule. For units equipped with water Alternatively, the CEMS should be allowed to demonstrate
or steam injection, the owner or operator shall maintain continuous records of the water to fuel ratio or compliance when either 306/306 or the unit CO/NOx permit limits
the steam to fuel ratio, unless the owner or operator uses CEMS to demonstrate compliance with the are being met.
emission limits in Sections 306 and 307, as applicable.
Comment 15.8
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Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
501.7 Records for Alternative RACT Requirements: Equipment Referenced in Sections 104.4, 306.1, and
306.2: Maintain records of the annual capacity factor and NOX emissions to demonstrate compliance
with Sections 104.4, 306.1, or 306.2 of this rule, as applicable. To be determined
502 RECORDS RETENTION: Copies of reports, logs, and supporting documentation required by the Control
Officer shall be retained for at least 5 years. Records and information required by this rule shall also be retained
for at least 5 years.
503 COMPLIANCE DETERMINATION DEMONSTRATION:
503.1 Ultra Low Sulfur Diesel Oil Verification: If the Control Officer requests documentation of the
sulfur content of the oil fuel to demonstrate the 0.0015% limit, the owner or operator shall submit
one of the following documents which provides the accurate sulfur content of the fuel based on
enforceable test methods as approved by the Administrator to determine sulfur content:
a. Fuel receipts, or
b. Contract specifications, or
c. Pipeline meter tickets, or
d. Fuel supplier information, or
e. Purchase records, or
f. Test results of the fuel for sulfur content.
The items listed above must provide accurate sulfur content values or be based on enforceable test
methods as approved by the Administrator to determine the sulfur content.
503.2 Drift Rate Verification: An owner or operator shall submit design drift rate verification from the
manufacturer of the drift eliminator used in the cooling towers to the Control Officer if proof of the
design drift rate is requested by the Control Officer.
503.3 Performance Test-Particulate Matter: An owner or operator of any combustion equipment listed
in Section 102 of this rule that burns a fuel other than natural gas for non-emergency purposes shall
demonstrate compliance with the emission limit in Section 301 of this rule by conducting an annual
performance test in accordance with Rule 270 of these rules. The performance test shall measure
particulate matter emissions, including condensable particulate matter emissions, using EPA
Reference Method 5 and EPA Reference Method 202, as incorporated by reference in Section 504 of
this rule. The result of the performance test shall be the arithmetic mean of the results of three test
runs. Each test run shall have a minimum sample time of one hour.
503.4 Performance Test-Oxides of Nitrogen: An owner or operator of any equipment listed in Section Commented [K(59]: EPA TSD Deficiency #6 (12/11/19) - Rule
102.1 or 102.2 of this rule that is subject to a numeric emission limit in Section 306 of this rule shall 323, section 503.2 requires boilers of 100 MMBtu/hr or greater heat
demonstrate compliance with the applicable numeric emission limits by conducting an annual input to conduct triennial stack tests. Rule 322 should require a
performance test, in accordance with Rule 270 of these rules. The performance tests shall measure similar or more stringent requirement for all EGU boilers and
turbines in the same size category.
nitrogen oxide emissions using EPA Reference Method 7 or 7E as incorporated by reference in
Section 504 of this rule. The result of the performance test shall be the arithmetic mean of the results Commented [JM(60]: MCAQD Response – Annual testing
of three test runs. Each test run shall have a minimum sample time of one hour. The concentration of required for all units subject to a numeric limit in Section 306.
nitrogen oxides shall be measured dry and corrected to 3% oxygen for electric utility steam generating Commented [KB-A61]: EPA has indicated that methods 7 and
units and cogeneration steam generating units. The concentration of oxides of nitrogen shall be 7E are the preferred methods.
measured dry and corrected to 15% oxygen for stationary gas turbines and for combined cycle gas
322-17
107

Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012 Return to list of attachments
turbines. For units that are equipped with water or steam injection, the ratio of water or steam to fuel
shall be measured during the performance test. Commented [EM62]: Can we get clarification on what this
Comment 15.9 means please?
503.3 503.5 Waste Derived Fuel Gas – Sulfur Verification: The owner or operator shall submit documentation of
the concentration of the sulfur level of the waste derived fuel gas to the Control Officer upon request.
The sulfur content of gaseous fuels shall be determined by South Coast Air Quality Management
District Method 307-94 Determination of Sulfur in a Gaseous Matrix. Performance Test-Carbon
Monoxide: An owner or operator of any equipment listed in Section 102.1 or 102.2 of this rule that
is subject to Section 307 of this rule shall demonstrate compliance with the emission limit in Section
307 of this rule by conducting an annual performance test in accordance with Rule 270 of these rules.
The performance test shall measure carbon monoxide emissions using EPA Reference Method 10 as
incorporated by reference in Section 504 of this rule. The result of the performance test shall be the
arithmetic mean of the results of three test runs. Each test run shall have a minimum sample time of
one hour. The carbon monoxide concentration shall be measured dry and corrected to 3% oxygen for
electric utility steam generating units and cogeneration steam generating units. The carbon monoxide
concentration shall be measured dry and corrected to 15% oxygen for stationary gas turbines and for
combined cycle gas turbines.
503.6 CEMS: An owner or operator using a CEMS to demonstrate compliance with Section 302, 306, or Commented [K(63]: EPA TSD Recommendation #4 (12/11/19)
307 shall install, operate, calibrate, maintain, and test the CEMS in accordance with 40 CFR Part 60 or - Section 306 specifies a 30-day rolling average be used to determine
40 CFR Part 75. Excess emissions for Section 306 are defined as any period during which the 24-hour compliance with applicable NOx limits for units equipped with
rolling average emission rate exceeds the applicable numeric emission limit. Excess emissions for CEMS. This averaging period is too long compared to the
compliance determination requirements if a facility was using
Section 307 are defined as any operating hour during which the 1-hour average emission rate standard source test methods. CEMS determination requirements
measured exceeds the applicable numeric emission limit. should at least match the requirements for source tests (1-hour
Comment 15.10 sample time), and averaging could be conducted over a 24-hour
504 COMPLIANCE DETERMINATION-TEST METHODS INCORPORATED BY REFERENCE: rolling period (see, e.g., SIP-approved Ventura County APCD Rule
59, section B.1.).
The following test methods are approved for use for the purpose of determining compliance with this rule. The
test methods are incorporated by reference in Rule 360 and Appendix G of the Maricopa County Air Pollution Commented [JM(64]: MCAQD Response – 30-day rolling
Control Regulations. Alternative test methods as approved by the Administrator or other EPA-approved test average reduced to 24-hour rolling average.
methods may be used upon prior written approval from the Control Officer. When more than one test method Commented [CCB65]: Section 307 should be consistent with
is permitted for the same determination, an exceedance under any method will constitute a violation. Copies of 306 in that it is also a 24 rolling average. Also note here that it is
test methods referenced in this section are available at the Maricopa County Air Quality Department. actually not an “emission rate” but a “emission concentration”
Commented [KB-A66]: This section includes ASTM methods
504.1 EPA Reference Methods 1 (“Sample and Velocity Traverses for Stationary Sources”), and 1A which are not incorporated by reference in Appendix G. When EPA
approves ASTM methods they are incorporated by reference into the
(“Sample and Velocity Traverses for Stationary Sources with Small Stacks and Ducts”) (40 CFR 60, CFR. The ASTM methods listed in this rule are incorporated by
Appendix A). reference into the CFR in Subpart A (General Provisions) of the
New Source Performance Standards. Subpart A (General
504.2 EPA Reference Methods 2 (“Determination of Stack Gas Velocity and Volumetric Flow Rate”), 2A Provisions) of the New Source Performance Standards is
(“Direct Measurement of Gas Volume through Pipes and Small Ducts”), 2C (“Determination of Stack incorporated by reference in Rule 360 of the MCAPCR.
Gas Velocity and Volumetric Flow Rate in Small Stacks or Ducts”), and 2D (“Measurement of Gas The changes in this section align the titles of the methods specified
Volumetric Flow Rates in Small Pipes and Ducts”) (40 CFR 60, Appendix A). in this section with the titles of the methods as listed in 40 CFR 60,
Appendix A.
504.3 EPA Reference Methods 3 (“Gas Analysis for the Determination of Dry Molecular Weight”), 3A
(“Determination of Oxygen and Carbon Dioxide Concentrations in Emissions From Stationary
Sources (Instrumental Analyzer Procedure)”), 3B (“Gas Analysis for the Determination of Emission
Rate Correction Factor of or Excess Air”), and 3C (“Determination of Carbon Dioxide, Methane,
Nitrogen and Oxygen from Stationary Sources”) (40 CFR 60, Appendix A).
504.4 EPA Reference Method 4 (“Determination of Moisture Content in Stack Gases”) (40 CFR 60,
Appendix A).
504.5 EPA Reference Method 5 (“Determination of Particulate Emissions from Stationary Sources”) (40
CFR 60, Appendix A).
322-18
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Maricopa County Air Quality Dept.
AQ-2017-007-Rule 322 Planning & Analysis Division
Draft Rule for Stakeholder Workshop: TBD 3800 N. Central Ave. Ste. 1400
Phoenix, AZ 85012
504.6 EPA Reference Method 202 (“Determination of Dry Impinger Method for Determining Condensable
Particulate Emissions from Stationary Sources”) (40 CFR 51, Appendix M).
504.7 EPA Reference Methods 7 (“Determination of Nitrogen Oxide Emissions from Stationary Sources”),
7A (“Determination of Nitrogen Oxide Emissions from Stationary Sources – Ion Chromatographic
Method”), 7B (“Determination of Nitrogen Oxide Emissions from Stationary Sources - Ultraviolet
Spectrometry Spectrophotometry”), 7C (“Determination of Nitrogen Oxide Emissions from
Stationary Sources - Alkaline-Permanganate Ion Colorimetric Method”), 7D (“Determination of
Nitrogen Oxide Emissions from Stationary Sources – Alkaline-Permanganate Chromatographic
Method”), and 7E (“Determination of Nitrogen Oxide Emissions from Stationary Sources –
Instrumental Analyzer Method Procedure”) (40 CFR 60, Appendix A).
504.8 EPA Reference Method 9 (“Visual Determination of the Opacity of Emissions from Stationary
Sources”) (40 CFR 60, Appendix A).
504.9 EPA Reference Method 10 (“Determination of Carbon Monoxide Emissions from Stationary
Sources”) (40 CFR 60, Appendix A).
504.10 EPA Reference Method 20 (“Determination of Nitrogen Oxides, Sulfur Dioxide and Diluent
Emissions from Stationary Gas Turbines”) (40 CFR 60, Appendix A).
504.11 ASTM D2622- 16 05, Standard Test Method for Sulfur in Petroleum Products by Wavelength Commented [KB-A67]: 40 CFR 60.17(h)(106) – the newest
Disperse Dispersive X-Ray Fluorescence Spectrometry. method incorporated into the CFR is from 2005.
504.12 ASTM D2880- 15, Standard Specification for Gas Turbine Fuel Oils. Commented [KB-A68]: This standard tells turbine owners and
operators what contaminants are acceptable in fuel and at what
504.13 504.12 ASTM D4294- 16e1 03, Standard Test Method for Sulfur in Petroleum and Petroleum concentrations to prevent the fuel from damaging the turbine; this
Products by Energy-Dispersive X-Ray Fluorescence Spectrometry. standard does not specify a method for determining the sulfur
content of a fuel.
504.14 504.13 Standard Methods for the Examination of Water and Wastewater, Method #2540C (“Total Dissolved Commented [KB-A69]: 40 CFR 60.17(h)(156) – the newest
method incorporated into the CFR is from 2003.
Solids Dried at 180ºC, Method #2540C”), American Public Health Association, 19th edition, 1995.
504.15 504.14 ASTM D5907-13, Standard Methods for the Examination of Water and Wastewater for Filterable
Matter (Total Dissolved Solids) and Nonfilterable Matter (Total Suspended Solids) in Water.
504.16 504.15 South Coast Air Quality Management District Method 307-94 307-91 (“Determination of Sulfur in a
Gaseous Matrix”), revised 1994.
322-19
109

Return to list of attachments
Submitted via electronic mail.
Bill McClellan, Manager, Air Quality Services
PAB 359 | P.O. Box 52025
Phoenix, AZ 85072-2025
P: (602) 236-5387 | F: (602) 236-3407
bill.mcclellan@srpnet.com
August 3, 2020
Ms. Kimberly Butler
Planning and Analysis Manager
Maricopa County Air Quality Department
3800 N. Central Ave. Suite 1400
Phoenix, AZ 85012
RE: SRP Comments Regarding Proposed Revisions to MCAQD Rule 322
Dear Ms. Butler,
Salt River Project Agricultural Improvement and Power District (SRP) appreciates the
opportunity to comment on Maricopa County Air Quality Department’s (MCAQD) proposed
revisions to Rule 322: Power Plant Operations.
SRP is a political subdivision of the State of Arizona that provides retail electric services to more
than 1 million residential, commercial, industrial, agricultural, and mining customers in Arizona.
As a vertically integrated utility, SRP provides generation, transmission and distribution
services, as well as metering and billing services. As part of its operations, SRP operates
several power plants located throughout Maricopa County. Accordingly, SRP has a clear and
significant interest in this pending action.
SRP appreciates MCAQD’s extensive outreach efforts to stakeholders during the rulemaking
process for Rule 322. SRP participated in several of the public stakeholder meetings and has
provided both verbal and written comments. MCAQD addressed many of these comments in
subsequent drafts of the proposed rule. On February 25, 2019, MCAQD submitted revisions to
the Maricopa County Board of Health for approval to begin the rulemaking process. MCAQD
intended these revisions to address purported deficiencies identified by U.S. Environmental
110

Protection Agency (EPA) in its disapproval of the rule for purposes of the federally enforceable
State Implementation Plan (SIP) for Arizona.1
As MCAQD has proposed revisions to Rule 322, SRP offers the following comments on the
current draft proposal. Section I contains more substantive comments with respect to the scope
and content of the regulation. Section II contains less substantive comments that SRP offers to
improve rule clarity and implementation.
I. Rule Applicability and Requirements
A. Applicability to Minor Sources
The current (November 2016) rule applies to stationary sources regardless of total annual mass
emissions (tpy). The current, approved State Implementation Plan (SIP) imposes a NOX
emission limitation on equipment listed in Section 102.1 and 102.2 of 155 ppmv NOX when
burning gaseous fossil fuel and 230 ppmv NOX when burning liquid fossil fuel. MCAQD lowered
the limits in revised Rule 322 and intends to submit the rule to EPA for approval into the SIP to
meet NOX RACT requirements. NOx RACT applies only to major sources of NOX, however
MCAQD has not qualified the applicability of the Rule, including lower applicability limits per
Section 306, as applying only to RACT eligible units.
Although MCAQD’s existing inventory of equipment named in Section 102.1 and 102.2 may all
be located at major sources of NOX, this may not be the case in the future. To align the
applicability of the lower limits in this rule with MCAQD’s stated intentions for the revised rule,
the regulation must be revised to clarify that the lower limits apply only to units located at
stationary sources qualifying as major sources of NOX. MCAQD can properly qualify the
applicability of the lower NOX emission limitations by adding Section 102.5 to the rule as follows:
The requirements for NOX emissions (NOX RACT) in this rule apply only to
equipment listed in 102.1 and 102.2 if the equipment is located at a major source of
NOX.
B. Minimization of Startup and Idling Time
It is our understanding that MCAQD is considering adding a provision to Rule 322 to require
owners and operators to minimize the time spent at idle or holding at low load levels for any
steam generating unit or stationary gas turbine to which the rule applies. Such a requirement
would be inappropriate and, because it creates an incentive to operate at higher load than
necessary, is not environmentally beneficial. As a result, SRP recommends that the rule not
impose operational limits other than the requirements for good combustion practices in Section
306. SRP notes that EPA recently proposed to adopt such a requirement in its National
Emission Standards for Hazardous Air Pollutants: Stationary Combustion Turbines Residual
Risk and Technology Review and then, in the final rule, elected not to adopt this requirement
based on concerns regarding necessity of sustained operation at low load.2
1 Air Plan Conditional Approval and Disapproval; Arizona; Maricopa County; Power Plants; Fuel Burning
Equipment, and Internal Combustion Engines at 85 FR 43692-43695.
2 85 Fed. Reg. 13524 (Mar. 9, 2020).
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C. Presumptive NOX RACT for Steam Generating Units
Sections 306.1 through 306.3 of the current rule establish a presumptive NOX RACT limit of 42
ppmv, on a dry basis corrected to 3% oxygen, equivalent to 0.051 lb/MMBtu, for electric utility
steam generating units while burning natural gas and 65 ppmv, on a dry basis corrected to 3%
oxygen, equivalent to 0.083 lb/MMBtu, for electric utility steam generating units while burning
oil. This presumptive NOX RACT limit applies to both existing and new steam generating units,
including the existing boilers associated with Units 1 through 3 at Agua Fria Generating Station.
As it pertains to existing units, this limit is unnecessarily stringent and should be relaxed. A
more appropriate presumptive NOX RACT limit for existing electric utility steam generating units
is that in the Texas NOX RACT rule approved by EPA in April 2019:
• 0.26 lb/MMBtu (HHV), rolling 24-hour average, and 0.20 lb/MMBtu (HHV), 30-day rolling
average, while burning natural gas. 30 TAC § 117.1205(a).
• 0.30 lb/MMBtu (HHV), rolling 24-hr average, while burning only fuel oil. 30 TAC
§ 117.1205(c).3
This limit is appropriate for existing electric utility steam generating units in Maricopa County
both because it is approvable by EPA, as illustrated by the Texas SIP approval rulemaking, and
because the more stringent limit in the current rule is not achievable by the electric utility steam
generating units at Agua Fria Generating Station using combustion controls.
D. Partial Exemption for Low Use EGUs
As provided by Section 104.4 of the current (November 2016) rule, any steam generating unit or
stationary gas turbine to which the rule applies and which has a calendar year annual capacity
factor equal to or less than 10 percent is not subject to the NOX and CO emissions standards or
the associated compliance demonstration requirements. SRP understands that MCAQD intends
to eliminate this categorical partial exemption.
RACT requirements do not apply to CO and other non-NOX requirements in Section 300 of the
current rule. In addition, MCAQD is justified in retaining the categorical partial exemption for
NOX requirements. EPA neither formally disapproved the categorical partial exemption based on
capacity factor in the SIP disapproval rulemaking4 nor expressed any concern with respect to
this provision in the “additional recommendations” conveyed in conjunction with that
rulemaking.5 Rather, EPA has routinely approved NOX RACT SIPs with limited requirements
(i.e., exemptions from otherwise applicable numeric emission standards) for equipment with low
utilization levels. At least two of these SIP approvals occurred in 2019:
3 84 Fed. Reg. 18145 (April 30, 2019).
4 Air Plan Conditional Approval and Disapproval; Arizona; Maricopa County; Power Plants; Fuel Burning
Equipment, and Internal Combustion Engines at 85 FR 43692-43695.
5 U.S. EPA, Technical Support Document for EPA’s Rulemaking for the Arizona State Implementation
Plan Maricopa County Air Quality Department Rule 322 - Power Plant Operations,
www.regulations.gov/contentStreamer?documentId=EPA-R09-OAR-2019-0321-0010&contentType=pdf
(Dec. 11, 2019).
112

• In April 2019, EPA approved the Texas NOX RACT SIP including 30 TAC
§ 117.1203(a)(2), which exempts from all substantive requirements any boiler with actual
heat input ≤ 220,000 MMBtu/yr, and 30 TAC § 117.1203(a)(3), which exempts from all
substantive requirements any CT with operating hours < 850 hr/yr.6
• In May 2019, EPA approved the Pennsylvania NOX RACT SIP including 25 Pa. Code
§ 129.97(c)(7), which exempts from all substantive requirements any fuel burning unit
with an electric output-based capacity factor < 5 percent.7
MCAQD is justified in retaining the categorical partial exemption as currently codified because
control of NOX emissions from electric utility steam generating units and electric utility stationary
gas turbines with calendar year annual capacity factor equal to or less than 10 percent is not
cost effective as shown in Exhibits A and B to these comments. Moreover, given the
dominance of mobile source emissions in the NOX inventory, any emissions reductions that
could be achieved by imposing non-cost effective controls on these units would have minimal
impact on whether Maricopa County achieves attainment with the ozone NAAQS by the
attainment date.8, 9
It is our understanding that MCAQD is considering adding to the rule, in lieu of the categorical
partial exemption, case-by-case RACT requirements for electric utility steam generating units
and electric utility stationary gas turbines with calendar year annual capacity factor equal to or
less than a unit-specific threshold. This rule revision is inappropriate and unnecessary, for the
reasons presented above, and would impose administrative burdens on SRP and similarly
situated owners and operators of stationary sources for no environmental gain. Accordingly,
SRP supports retaining the categorical partial exemption as currently codified.
E. Alternative NOX RACT
SRP strongly encourages MCAQD to retain the categorical partial exemption as currently
codified. If MCAQD proceeds to remove this provision, then a revised rule must include
alternative RACT requirements for Units 1 through 6 at Agua Fria Generating Station and Units
4 through 6 at Kyrene Generating Station because the emission limitations in Section 306.1 do
not represent NOX RACT for these units. For each of these units, in any calendar year in which
the annual capacity factor is equal to or less than 10 percent, RACT should require SRP
maintain and operate the unit in accordance with manufacturer’s specifications.
6 84 Fed. Reg. 18145 (Apr. 30, 2019).
7 84 Fed. Reg. 20274 (May 9, 2019).
8 MAG 2017 Eight-Hour Ozone Moderate Area Plan for the Maricopa Nonattainment Area at p. 6-2.
www.azmag.gov/portals/0/Documents/EP_2016-12-09_MAG-2017-EightHour-Ozone-Moderate-Area-
Plan-for-the-Maricopa-Nonattainment-Area.pdf
9 MAG 2017 Eight-Hour Ozone Moderate Area Plan for the Maricopa Nonattainment Area Appendices
Volume 3 at p. III-1. www.azmag.gov/portals/0/Documents/EP_2016-12-09_MAG-2017-EightHour-
Ozone-Moderate-Area-Plan-Appendices-Volume3.pdf
113

II. Rule Clarity
A. Purpose of Rule
SRP recommends that MCAQD revise the purpose statement in Section 101 to inform the
regulated community that Rule 322 satisfies NOX RACT requirements under the federal Clean
Air Act as follows:
To limit the discharge of nitrogen oxides, sulfur oxides, particulate matter and carbon
monoxide emissions into the atmosphere from stationary fossil-fuel-fired equipment at
electric utility stationary gas turbines, stationary fossil-fuel-fired electric utility steam
generating units, and stationary fossil-fuel-fired cogeneration steam generating units and to
limit particulate matter emissions from cooling towers associated with this equipment. This
rule also satisfies requirements under §§ 182(b)(2) and 182(f) of the federal Clean Air Act for
NOX Reasonably Available Control Technology (“RACT”) for major sources of NOX
emissions.
B. Definition of “Annual Capacity Factor”
Section 201 defines the “annual capacity factor” to mean either a heat input-based ratio or an
electric output-based ratio. Section 104.4 establishes a partial exemption from certain rule
requirements for units with calendar year annual capacity factor equal to or less than 10
percent. For any given unit, in a given calendar year, the heat input-based capacity factor is
different from its electric output-based capacity factor because efficiency varies with load.
These provisions must be revised to clarify whether the exemption threshold is based on heat
input-based capacity factor or electric output-based capacity factor.
C. Definition of “Continuous Emissions Monitoring System”
It is our understanding that MCAQD is considering revising the definition of the term
“Continuous Emissions Monitoring System (CEMS”), currently codified at Section 204, to refer
to systems which “continuously sample and analyze.” This revision would be inappropriate, as
CEMS perform periodic, not continuous, sampling and analysis. (See, for example, 40 CFR
§ 75.10(d)(1), providing that CEMS required under the Acid Rain program must be “capable of
completing a minimum of one cycle of operation (sampling, analyzing, and data recording) for
each successive 15-min interval.”) SRP suggests adopting the definition at A.A.C. R18-2-101 or
the nearly identical definition in the federal Clean Air Act at § 402(7).
D. Definition of “Electric Utility Steam Generating Unit”
The definition of the term “Electric Utility Steam Generating Unit” is ambiguous in that it could be
construed to include the heat recovery steam generator portion of a combined cycle gas turbine.
This would be impractical, as the compliance demonstration requires correction of NOX
concentration to two different oxygen levels for steam generating units and gas turbines, yet the
exhaust gases from the gas turbine and the heat recovery steam generator portions of a
combined cycle gas turbine are commingled. As explained by EPA in adopting New Source
Performance Standards for this category:
Why Are Heat Recovery Steam Generators Included in 40 CFR Part 60, Subpart KKKK?
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For sources that are combined cycle turbine systems using supplemental heat, turbine
NOX emissions would be measured after the duct burner, since emissions and output
associated with duct burners are included in the NOX emission limit. Any combined cycle
units that are subject to the NOX CEMS requirements for 40 CFR part 75 would most
likely have installed the CEMS after the duct burner, on the HRSG stack. Another reason
to require measurement of NOX emissions after the duct burner is that add-on NOX
control systems, such as SCR, are generally located after the duct burner. Turbine NOX
performance testing should be conducted after the NOX control device and would,
therefore, include any emissions from the duct burner.
In addition, all of the data that we have gathered where emissions were tested with and
without duct burner firing show that duct burners have little to no effect on NOX
emissions. Minimal additions and reductions were noted in several recent source tests,
as well as an EPA sponsored test conducted by the EPA's Emissions Measurement
Center. Thus, it is appropriate to include heat recovery sources such as duct burners in
the proposed rule.10
SRP recommends revising the definition of the term “Electric Utility Steam Generating Unit” to
clarify that, for purposes of the NOx RACT emission limitations, duct burners and heat recovery
steam generators which are components of a combined cycle gas turbine are not considered
Electric Utility Steam Generating Units.
E. Definition of “Heat Input”
The rule includes numerous references to the term “heat input.” With the exception of Section
102.2, relating to applicability criteria for stationary gas turbines, these references are
ambiguous as to whether higher heating value (HHV) or lower heating value (LHV) is intended.
In particular, Section 102.1, relating to applicability criteria for steam generating units, is silent
as to whether the threshold is based on HHV or LHV. Each such reference to the term “heat
input” must be revised to clarify whether the required measurement is based on HHV or LHV.
F. Reporting of Emergency Fuel Use
It is our understanding that MCAQCD is considering adding to Section 309 an additional
notification provision requiring an owner or operator to report the end of emergency fuel use
within one business day. The current rule already requires initial notification within 24 hours
after declaration of the emergency that necessitates use of emergency fuel and a follow-up
written report within 48 hours after commencing use of emergency fuel. These notification
requirements are sufficient. Three reporting requirements for a single, short-term event is overly
burdensome and is unnecessary to enforce the 168 hour/year emergency fuel use restriction.
MCAQD should retain only the 24 hour written report requirement, or the end of emergency
requirement, not both. Requiring end of event reporting is unnecessary because total hours can
be reported with Part 70 semi-annual monitoring and compliance reports.
10 70 Fed. Reg. 8314 (Feb. 18, 2005).
115

G. Citations to EPA Reference Methods
Section 504 includes numerous citations to EPA test methods incorporated by reference, in
each case referring to “40 CFR 60, Appendix A.” The test methods in the appendices to part 60
were recodified in 2002. The correct citations are as follows:
Methods 1 through 2D are in 40 CFR 60, appendix A-1
Methods 3-3C are in 40 CFR 60, appendix A-2
Methods 4-5 are in 40 CFR 60, appendix A-3
Methods 7-10 are in 40 CFR 60, appendix A-4
Method 20 is in 40 CFR 60, appendix A-7.
H. Missing Data Substitution
It is our understanding that MCAQCD is considering adding a provision to Section 503 requiring
that a CEMS used to demonstrate compliance with NOx RACT emission limitations be operated
in accordance with either 40 CFR part 60 or 40 CFR part 75. SRP recommends that this
provision include a statement to clarify that, if the CEMS is operated in accordance with 40 CFR
part 75, the missing data substitution procedures in part 75 do not apply for purposes of Rule
322.
I. Compliance Demonstration Provisions
SRP recommends the following revisions to clarify the compliance demonstration provisions in
Section 503.
• Revise to clarify that, for any unit for which a CEMS is used to demonstrate compliance
with the NOX or CO emission limitation in Section 306 or Section 307, respectively,
excess emissions are defined as any period during which the 24-hour average emission
rate as measured using CEMS exceeds the applicable numeric emission limit. The
current (November 2016) rule is ambiguous regarding averaging time, particularly with
respect to Section 307.
• Revise to clarify that, for any unit for which a CEMS is used to demonstrate compliance
with the NOX or CO emission limitation in Section 306 or Section 307, respectively,
annual performance tests are not required.
• Revise to provide for reduced frequency of performance testing for units for which
compliance has been consistently established. For example, after two consecutive
annual performance tests demonstrate that the unit is complying with the NOX RACT
requirement, testing should be required no more than once every five years. EPA
approved a similar RACT requirement into the SIP for North Carolina.11
11 15a NCAC 02D .1407(g); EPA approval: 78 Fed. Reg. 27067 (May 9, 2013).
116

• In Section 503 and in any other provision of the rule in which a reference test method is
prescribed, add language allowing for use of the provision in Section 504 allowing use of
an alternative test method upon prior approval from the Control Officer. For example, if
a provision is added to Section 503 prescribing use of Method 7E, it must allow for use
of an alternative test method approved for use in accordance with Section 504.
J. Effective Date and Transition Provisions
SRP recommends that MCAQD add transition provisions to Rule 322 to clarify compliance
obligations and effective date in light of the numerous versions of the rule. Specifically, in order
to avoid imposing unnecessary obligations on SRP and similarly situated owners and operators
of stationary sources in the event the next version of the rule is disapproved by EPA, SRP
recommends that the planned revisions to the rule become effective upon approval by EPA. In
addition, SRP recommends that MCAQCD add a clarifying statement to the rule indicating that
no new compliance demonstration is required for a unit that demonstrated compliance with the
same substantive requirement in the current (November 2016) version of the rule.
Sincerely,
Bill McClellan
Manager, Air Quality Services
117

Exhibit A
118

Reasonably Available Control Technology
(RACT) Analysis.
RACT Analysis for the control of nitrogen oxides (NOx) emissions from
boilers at Salt River Project Agua Fria Generating Station.
July 2020
Prepared for:
Salt River Project
1500 N. Mill Avenue
Tempe, AZ 85281
www.srpnet.com
Prepared By:
RTP ENVIRONMENTAL ASSOCIATES INC.
304-A West Millbrook Rd.
Raleigh, NC 27609
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Table of Contents
1.0 Introduction. ........................................................................................................ 2
2.0 Reasonably Available Control Technology. ..................................................... 3
2.1 RACT Evaluation. ........................................................................................................................ 3
2.2 Calculation of Cost Effectiveness. ................................................................................................ 4
2.3 Capital Recovery Costs. ............................................................................................................... 4
2.4 RACT Cost Effectiveness Threshold. ........................................................................................... 5
2.5 Conclusion and Proposed RACT Determination. ......................................................................... 6
3.0 NOx Emissions from Combustion Sources. ..................................................... 8
3.1 Thermal NOx. ................................................................................................................................ 8
3.2 Fuel NOx. ...................................................................................................................................... 8
3.3 Prompt NOx. ................................................................................................................................. 8
4.0 Available NOx Control Technologies. ............................................................... 9
4.1 Low NOx Burners. ........................................................................................................................ 9
4.1.1 Low NOx Burners plus Overfire Air. ................................................................................ 10
4.1.2 Low NOx Burners plus Flue Gas Recirculation. ............................................................... 10
4.2 Selective Catalytic Reduction (SCR). ......................................................................................... 10
4.3 Selective Non-Catalytic Reduction (SNCR)............................................................................... 11
4.4 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™). .............................................. 11
5.0 Agua Fria Units 1, 2, and 3 Boilers. ................................................................. 14
5.1 Available NOx Control Technologies. ........................................................................................ 14
5.2 Low NOx Burners. ...................................................................................................................... 15
5.3 Selective Non-Catalytic Reduction (SNCR)............................................................................... 17
5.4 Selective Catalytic Reduction (SCR). ......................................................................................... 18
5.5 Conclusions. ............................................................................................................................... 20
Tables
TABLE ES-1. Cost effectiveness of the NOx control options for the Agua Fria Generating Station Unit 1,
2, and 3 boilers based on a 10% capacity factor for each unit. ............................................................ 1
TABLE 5-1. General specifications for the Agua Fria boilers, Units 1, 2, and 3. ................................. 14
TABLE 5-2. Capital costs, annual costs, and cost effectiveness for low NOx burners for each of the Agua
Fria Unit 1 and 2 boilers based on a 10% capacity factor for each boiler. ......................................... 16
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TABLE 5-3. Capital costs, annual costs, and cost effectiveness for low NOx burners for the Agua Fria Unit
3 boiler based on a 10% capacity factor. ............................................................................................ 16
TABLE 5-4. Capital costs, annual costs, and cost effectiveness for SNCR for the Agua Fria Unit 1, 2, and
3 boilers based on a 10% capacity factor for each boiler. .................................................................. 18
TABLE 5-5. Capital costs, annual costs, and cost effectiveness for SCR for the Agua Fria Unit 1, 2, and 3
boilers based on a 10% capacity factor for each boiler. ..................................................................... 19
TABLE 5-6. NOx control options, emission reductions, and cost effectiveness for each of the Agua Fria
Generating Station Unit 1 and 2 boilers based on a 10% capacity factor. ......................................... 20
TABLE 5-7. NOx control options, emission reductions, and cost effectiveness for the Agua Fria Generating
Station Unit 3 boiler based on a 10% capacity factor. ....................................................................... 20
Attachments
Appendix A. ............................ Riley Power Inc. SRP Agua Fria Power Plant Burner Replacement Design,
Supply and Installation Proposal – Revision 01.
Appendix B. ............................ U.S. EPA’s Air Pollution Control Cost Manual, Air Pollution Control Cost
Estimation Spreadsheet for Selective Non-Catalytic Reduction (SNCR), May 2016
for the Units 1 and 2 and Unit 3 boilers.
Appendix C. ............................ U.S. EPA’s Air Pollution Control Cost Manual, Air Pollution Control Cost
Estimation Spreadsheet for Selective Catalytic Reduction (SCR), May 2016
for the Units 1 and 2 and Unit 3 boilers.
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Executive Summary.
Salt River Project’s (SRP) Agua Fria Generating Station is located in the portion of Maricopa County which
is classified as a moderate nonattainment area for ozone (O3). Maricopa County Air Pollution Control
Regulations (MCAPCR) Rule 322 requires the use of Reasonably Available Control Technology (RACT)
for the control of nitrogen oxides (NOx) emissions from power plants in the county.
For each boiler, Rule 322 currently prescribes a presumptive NOx RACT emission limit of 42 parts per
million by volume, dry basis (ppmdv) (calculated as nitrogen dioxide) corrected to 3% oxygen when
burning gaseous fuel, and 65 ppmdv when burning liquid fossil fuel. For any unit with a calendar year
annual capacity factor equal to or less than 10 percent, NOx RACT requires only work practices; such units
are not subject to numeric emission standards.
This report presents a NOx RACT analysis for three natural gas and fuel oil-fired boilers: Units 1, 2, and 3
at the Agua Fria Generating Station. Each of these boilers has a calendar year annual capacity factor equal
to or less than 10 percent.
The U.S. Environmental Protection Agency has defined RACT as “the lowest emission limitation that a
particular source is capable of meeting by the application of control technology that is reasonably available
considering technological and economic feasibility.” The U.S. EPA’s most current guidance on NOx RACT
cost effectiveness indicates an economically reasonable range up to $2,300 per ton of NOx removed,
expressed in 2020 dollars. Table ES-1 is a summary of the cost effectiveness of the NOx control options for
the Agua Fria Generating Station Unit 1, 2, and 3 natural gas and oil-fired boilers based on an annual
capacity factor of 10%. The costs in Table ES-1 are also substantially higher than the economically feasible
threshold of $2,300 per ton of NOx removed. Accordingly, SRP proposes that MCAQD reaffirm that NOx
RACT for similar natural gas-fired boilers with a calendar year annual capacity factor equal to or less than
10 percent is the use of good combustion practices, and a requirement to operate in accordance with the
manufacturer’s specifications, with no numeric emission standards.
TABLE ES-1. Cost effectiveness of the NOx control options for the Agua Fria Generating
Station Unit 1, 2, and 3 boilers based on a 10% capacity factor for each unit.
Cost Effectiveness, $ per ton of NOx controlled
NOx Control
Option Agua Fria Agua Fria
Units 1 and 2 Unit 3
Low NOx Burners $9,580 $4,320
Selective Non-Catalytic Reduction (SNCR) $10,750 $5,240
Selective Catalytic Reduction (SCR) $13,940 $6,500
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1.0 Introduction.
This document is a Reasonably Available Control Technology (RACT) Analysis for the control of nitrogen
oxides (NOx) emissions from three natural gas and fuel oil-fired boilers at the Agua Fria Generating Station.
This generating station is located in the portion of Maricopa County which is classified as a moderate
nonattainment area under the 2008 ozone National Ambient Air Quality Standard (NAAQS).1 As part of
the moderate classification, Maricopa County Air Quality Department (MCAQD) Maricopa County Air
Pollution Control Regulations (MCAPCR) Rule 322 requires RACT level of control for oxides of nitrogen
(NOx) emissions from power plant operations in the county. Agua Fria Generating Station has specifically
identified emissions units in Rule 322 which are subject to RACT requirements.
The units evaluated in this RACT analysis are the Agua Fria Generating Station Unit 1, 2, and 3 natural gas
and fuel oil-fired boilers.
Chapter 2 of this analysis includes a discussion of RACT, including a discussion of cost effectiveness
thresholds.
Chapter 3 includes a general discussion of NOx emissions from combustion sources, including the reaction
mechanisms responsible for NOx formation.
Chapter 4 includes an evaluation of available NOx control technologies. The available controls are then
reviewed to determine controls which are technically feasible control options. The technical feasibility of
controls is further evaluated for each specific unit.
Chapter 5 includes a detailed RACT analysis for the Agua Fria Generating Station Unit 1, 2, and 3 natural
gas and fuel oil-fired boilers.
1 40 CFR § 81.303. See also 86 Fed. Reg. 26697 (May 4, 2016).
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2.0 Reasonably Available Control Technology.
The Code of Federal Regulations, 40 CFR § 51.908 et seq. specifies the attainment demonstration
requirements pursuant to section 182 of the Clean Air Act (CAA) for areas classified as moderate, serious,
severe, or extreme nonattainment areas. One of the requirements specified in 40 CFR § 51.912 is a RACT
state implementation plan (SIP) submission implementing CAA § 182(b)(2) and (f).
Reasonably available control technology is defined in 40 CFR § 51.100(o) as follows:
(o) Reasonably available control technology (RACT) means devices, systems, process modifications,
or other apparatus or techniques that are reasonably available taking into account:
(1) The necessity of imposing such controls in order to attain and maintain a national ambient air
quality standard;
(2) The social, environmental, and economic impact of such controls; and
(3) Alternative means of providing for attainment and maintenance of such standard. (This
provision defines RACT for the purposes of §51.341(b) only.)
This NOx RACT analysis report for the boilers at Agua Fria Generating Station has been prepared in order
to assist MCAQD in satisfying its obligations relating to a NOx RACT SIP submission. The report focuses
on the environmental and economic impact of potentially available NOx controls for the boilers at the Agua
Fria Generating Station.
2.1 RACT Evaluation.
U.S. Environmental Protection Agency (U.S. EPA) has stated, “RACT for a particular source is determined
on a case-by-case basis, considering the technological and economic circumstances of the individual
source.”2
For purposes of this NOx RACT analysis report for the Agua Fria Generating Station Unit 1, 2, and 3 natural
gas and fuel oil-fired boilers, we have generally followed the approach recommended in applicable U.S.
EPA guidance.3,4 This guidance – particularly the Alternative Control Techniques Document – NOx
Emissions from Utility Boilers (“Utility Boiler ACT Document”) – provides useful information but does
not prescribe a methodological approach and does not establish presumptive RACT either for a category of
sources or for any individual source.5 In addition to the Utility Boiler ACT Document, we used vendor
2 44 Fed. Reg. 53761 at p. 53762 (Sept. 17, 1979).
3 See, for example, U.S. EPA, Alternative Control Techniques Document – NOx Emissions from Utility Boilers, EPA-
453/R-94-023 (Mar. 1994).
4 The cost estimating approach generally recommended by U.S. EPA for RACT and other purposes is set forth in a
series of control cost manuals. The most up-to-date, complete edition of this guidance document is EPA Air Pollution
Control Cost Manual, Sixth Edition (EPA/452/B-02-001) (Jan. 2002) (“Control Cost Manual”).
5 See, for example, 57 Fed. Reg. 55620 at p. 55625 (Nov. 25, 1992) (“Similar to the CTGs issued for VOC source
categories, the ACTs will contain extensive background information on control technologies, costs, availability. etc.,
that can be used by States in making RACT determinations. However, unlike the CTGs, the ACTs will not established
[sic] a presumptive RACT.”)
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information, vendor budgetary quotes, unit performance, other U.S. EPA information, and other technical
sources as discussed in subsequent sections of this report. Historical cost information is adjusted to present
2020 costs using the consumer price index (CPI) published by Bureau of Labor Statistics.
The NOx RACT analysis presented in this report is based on the evaluation of the following criteria for each
emissions unit or for each specific type of emissions unit:
1. A review of available and technically achievable control technologies and the
achievable emissions reduction.
2. The cost effectiveness of the control option expressed in dollars per ton of emission
reduction ($/ton).
3. If applicable, other potential social and environmental impacts of the control option.
2.2 Calculation of Cost Effectiveness.
The RACT evaluation includes an evaluation of environmental, energy, and economic impacts. The most
important issue in a RACT analysis is typically the economic reasonableness of the control option. This
parameter is typically evaluated according to the cost effectiveness of the control option, expressed in
dollars per ton of pollutant reduced. Both average and incremental cost effectiveness may be calculated;
however, for the NOx RACT analysis for the boilers at Agua Fria Station, only average cost effectiveness
is necessary. This parameter represents the overall effect of a particular control technique relative to a
baseline condition and is calculated as follows, using the total annualized cost of the control option under
review:
Average Cost Effectiveness Control option annualized cost
=
($ per ton removed) Baseline emission rate – Control option emissions rate
2.3 Capital Recovery Costs.
Under applicable U.S. EPA guidance, including the Utility Boiler ACT Document, the total annualized cost
of a control option includes the annual cost required to recover the capital investment associated with that
control option. This value is calculated using a Capital Recovery Factor (CRF), which is the ratio of a
constant annual payment or annuity to the present value of receiving that annuity for a given length of time.6
For an interest rate i and n years for the project, the CRF is:
𝑖𝑖(1 + 𝑖𝑖)𝑛𝑛
𝐶𝐶𝐶𝐶𝐶𝐶=
[(1 + 𝑖𝑖)𝑛𝑛−1]
Where, i = Interest rate or cost of capital, fraction
6 See, for example, Utility Boiler ACT Document at p. 6-9 (“To convert total capital cost to an annualized capital
charge, the total capital cost is multiplied by an annual capital recovery factor (CRF).”)
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n = Equipment or Project life, years
In this RACT analysis, the interest rate i is 7.0%, consistent with MCAQD guidance.7 The project life for
all pollution control technology alternatives evaluated in this RACT analysis has been based on an
equipment life of 15 years. Substituting the interest rate of 7.0% and project life of 15 years into the above
equation, the CRF value is:
𝑖𝑖 (1 + 𝑖𝑖 )𝑛𝑛 0.07(1 + 0.07)15
𝐶𝐶𝐶𝐶𝐶𝐶= = = 0.10979
[ (1 + 𝑖𝑖 )𝑛𝑛−1] [ (1 + 0.07 )15 −1]
The annual cost for the capital investment is then calculated as the product of the CRF and the Total Capital
Cost (TCC):
Annual Capital = CRF × TCC
Recovery Cost
2.4 RACT Cost Effectiveness Threshold.
The most current U.S. EPA guidance available regarding cost effectiveness thresholds for NOx RACT
determinations is a 1994 memorandum, Cost-Effective Nitrogen Oxides (NOx) Reasonably Available
Control Technology (RACT). According to this guidance, the high end of the range for cost effective RACT
control options is $1,300 per ton of pollutant controlled.8 The U.S. EPA reaffirmed the relevancy of this
guidance in its final rule to implement the 8-hour ozone NAAQS in 2005.9 Specifically, in the Federal
Register notice for this final rule, U.S. EPA rejected comments suggesting RACT requirements should be
more stringent, characterizing the $1,300 per ton threshold as “our current guidance.”10
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 1994 has the same buying power as $1.75 in March 2020. Therefore, U.S.
EPA’s NOx RACT cost effectiveness threshold of $1,300 per ton in 1994 is equal to $2,300 in 2020.
The cost effectiveness threshold of $2,300 per ton derived above is lower than the threshold of $2,800 per
ton used by the Commonwealth of Pennsylvania in adopting NOx RACT rules that were recently approved
by U.S. EPA. As recognized by U.S. EPA in this SIP rulemaking, States have discretion to apply reasonable
thresholds:
7 MCAQD, Requirements, Procedures and Guidance in Selecting BACT and RACT (revised Jan. 2019). This rate is
conservative; the rate suggested in the Utility Boiler ACT Document is 10%.
8 U.S. EPA, Cost-Effective Nitrogen Oxides (NOx) Reasonably Available Control Technology (RACT), memorandum
from D. Kent Berry, Acting Director Air Quality Management Division (MD-15) (March 16, 1994).
9 70 Fed. Reg. 71612 (Nov. 29, 2005).
10 Ibid at p. 71654.
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EPA is aware that Pennsylvania considered cost-effectiveness levels that are lower than other states
in the OTR when developing the RACT II Rule; however, states have the discretion to determine
what costs are considered reasonable when establishing RACT for its sources. For these reasons,
EPA has not set a single cost, emission reduction, or cost-effectiveness figure to fully define cost-
effectiveness in meeting the NOx RACT requirement. Therefore, each state must make and defend
its own determination on how to weigh these values in establishing RACT. PADEP relied on a cost-
effectiveness of $2,800 per ton of NOx controlled and $5,500 per ton of VOC controlled for the
presumptive limits in the RACT II Rule.11
In addition to the cost effectiveness threshold, the manner in which this threshold is applied in determining
RACT for a category of sources is critically important. The way in which the threshold of $2,800 per ton
was applied in establishing NOx RACT in the Commonwealth of Pennsylvania was summarized by U.S.
EPA as follows:
In determining its presumptive NOx RACT limits under the RACT II Rule, PADEP considered
controls to be economically reasonable when installed and operated under $2,500 per ton of NOx
removed. EPA finds PADEP’s cost effectiveness threshold reasonable. Based on our analysis, EPA
found that cost-effectiveness of SCR in Pennsylvania boilers ranged from $3,651-$25,238 per ton,
while SNCR ranged from $2,217 to $17,594 per ton for conventional boilers (non-CFBs) and $6,076
to $19,732 per ton for CFB boilers. Because cost-effectiveness of these controls exceeded $2,500
per ton of NOx removed for the majority of coal-fired boilers in Pennsylvania without these controls
in place, it is reasonable to conclude that it would be economically infeasible to require the
installation and operation of SCR or SNCR on all coal-fired boilers in Pennsylvania. Based on this
analysis, EPA concludes that PADEP’s RACT II Rule determination for any large coal-fired boilers
without post-combustion controls in place is based on the operation of existing controls, in most
cases LNB and/or OFA. Thus, EPA finds that PADEP’s determination for this subset of coal-fired
boilers is reasonable, considering economic infeasibility of retrofitting these additional controls.12
2.5 Conclusion and Proposed RACT Determination.
The circumstances present in the NOx RACT analysis for coal-fired boilers without add-on NOx controls in
Pennsylvania, as discussed in Section 2.4 above, are representative of those for this RACT analysis: There
are a small number of utility boilers with capacity factors less than 10 percent in Maricopa County and, as
shown in section 5.0 of this report, there are no additional control measures that are economically reasonable
for these units either individually or as a group.
11 84 Fed. Reg. 20274 at 20286 (May 9, 2019).
12 U.S. EPA, Technical Support Document for the Pennsylvania State Implementation Plan Revision for Certain Reasonably
Available Control Technology Requirements under the 1997 and 2008 8-hour Ozone National Ambient Air Quality Standard at
24 (Feb. 22, 2018). Available at www.regulations.gov/contentStreamer?documentId=EPA-R03-OAR-2017-0290-
0017&contentType=pdf. Internal citations omitted; emphasis in original.
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The approach taken by the Commonwealth of Pennsylvania and approved by U.S. EPA should be applied
here: RACT should be established based on the use of work practices and these units should not be subject
to numeric emission standards.
Based on the NOx RACT analysis presented herein, SRP proposes the following as RACT for natural gas
and fuel oil-fired boilers with capacity factor equal to or less than 10%, including Units 1, 2, and 3 at the
Agua Fria Generating Station: Use of good combustion practices, and a requirement to operate in
accordance with the manufacturer’s specifications, with no numeric emission standards.
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3.0 NOx Emissions from Combustion Sources.
Nitrogen oxides (NOx) consist of both nitrogen oxide (NO) and nitrogen dioxide (NO2). During
combustion, NO typically accounts for about 50% to 90% of the total NOx emissions. However, since NO
is converted to NO2 in the atmosphere, the mass emission rate of NOx is usually reported as NO2.
NOx is formed during combustion in natural gas and fuel oil-fired boilers through three mechanisms;
1. Thermal Formation,
2. Fuel Formation, and
3. Prompt Formation.
3.1 Thermal NOx.
Of these three formation mechanisms, thermal formation or thermal NOx is expected to represent at least
70% of the total NOx formation. Thermal NOx results from the high temperature oxidation of nitrogen (N2)
and oxygen (O2). In this mechanism, N2 is supplied from air, which is 78% N2 by volume. The thermal
NOx reactions are described by the Zel’dovich mechanism as follows:
N2 + O ↔ NO + N (1)
N + O2 ↔ NO + O (2)
N2 + O2 ↔ 2NO (1) Overall
The first step is rate limiting due to its high activation energy. As a result, thermal NOx requires high
temperatures to proceed. Thermal NOx formation increases exponentially with temperature, becoming
significant at temperatures above approximately 2,800 °F. Because thermal NOx formation increases
exponentially with temperature and because thermal NOx accounts for a large share of the total NOx
emissions, combustion control systems which reduce peak flame temperatures such as low NOx burners
are effective NOx controls for boilers.
3.2 Fuel NOx.
Fuel NOx results from the oxidation of organic nitrogen compounds in the fuel. Because fuel bound
nitrogen is more easily converted to NOx during combustion, nitrogen levels in fuel can have a significant
impact on NOx formation. However, since both natural gas and distillate fuel oil have only trace organic
nitrogen compounds, fuel NOx formation is expected to be very small for these natural gas and distillate
fuel oil-fired boilers.
3.3 Prompt NOx.
Prompt NOx is formed by the reaction of hydrocarbon radicals with atmospheric nitrogen to produce
hydrogen cyanide (HCN) and ultimately NOx through a complex series of gas phase reactions. Prompt NOx
is expected to account for 20 – 30% of the total NOx emissions. Like thermal NOx, prompt NOx formation
can be reduced through combustion controls which reduce peak flame temperatures.
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4.0 Available NOx Control Technologies.
The RACT evaluation process starts with identifying available control technologies for the source. The
available controls are then reviewed to determine controls which are technically feasible control options.
Note that the following is a general discussion of available controls. However, the applicability of these
controls must be determined for each boiler application.
The following NOx control technologies are available for natural gas and distillate fuel oil-fired boilers:
Combustion Controls 1. Low NOx Burners (LNB)
a. LNB plus Overfire Air (OFA)
b. LNB plus Flue Gas Recirculation (FGR)
Post Combustion Controls 2. Selective Catalytic Reduction (SCR)
3. Selective Non-Catalytic Reduction (SNCR)
4. EMx™ Catalytic Absorption Process (EMx or SCONOx™)
4.1 Low NOx Burners.
For natural gas and fuel oil-fired boilers, Low NOx burners (LNB) are designed to control the mixing of air
and fuel to reduce peak flame temperatures. Low NOx burners reduce NOx emissions by staging the
combustion process. Staging slows down the combustion process, resulting in cooler flame temperatures
which suppresses thermal NOx formation. The Utility Boiler ACT indicates the reduction in NOx emissions
achievable with LNB at wall-fired utility boilers burning natural gas or fuel oil is generally expected to be
30% to 50% from uncontrolled levels.13
Low NOx burners are designed to control fuel and air mixing at the burner in order to create larger flame
patterns. This reduces the peak flame temperature and results in lower thermal NOx formation. The modified
flame structure also reduces the amount of oxygen available in the hottest part of the flame, improving
burner efficiency. Primary combustion, NOx reduction and fuel burnout are accomplished in three stages in
a modern, LNB equipped boiler:
1. The first stage is a fuel rich zone where oxygen levels are maintained below the stoichiometric
requirement to complete combustion. Most NOx is formed in this zone.
2. The second stage is a reducing zone where unburned hydrocarbon radicals reduce the NOx
formed in the first stage.
3. In the third stage, overfire air completes combustion, but produces additional NOx. NOx
formation is minimized by completing combustion in a low excess oxygen environment.
Low NOx burners are an available and effective NOx control technology for natural gas-fired boilers.
13 Utility Boiler ACT Document at p. 2-28.
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4.1.1 Low NOx Burners plus Overfire Air.
Some LNB designs may involve two stage combustion using separate overfire air ports. Combustion air is
directed to the burners at rates less than the stoichiometric requirement to complete combustion, with the
remainder provided in separate overfire air ports. This combustion technique can reduce peak flame
temperatures and reduce NOx emissions. This combustion staging is common in coal-fired boilers.
However, for natural gas and fuel oil combustion, this deep staging of overfire air is not normally required.
Instead, the staging of combustion is typically accomplished within the burner itself. Therefore, separated
overfire air is not a feasible NOx control for these natural gas-fired boilers.
4.1.2 Low NOx Burners plus Flue Gas Recirculation.
Flue gas recirculation (FGR) is another combustion modification often used in conjunction with low NOx
burners. FGR can be used to reduce peak flame temperatures and create an oxygen depleted zone by
reducing the concentration of oxygen near the burner. FGR reduces the oxygen content of the air at the base
of the furnace by diluting the primary air blown into the furnace with recirculated flue gas from the back
pass or economizer section of the boiler. This technique is used to create an oxygen depleted reducing zone
where unburned hydrocarbon species act to reduce the NOx formed near the burner. This oxygen depleted
zone reduces the peak flame temperatures which minimizes NOx formation.
SRP has a vendor quote for low NOx burners without FGR. The addition of FGR to these boilers may result
in NOx emission reductions beyond what can be achieved by low NOx burners alone. However, unlike low
NOx burners which can be installed as replacements to the existing burners, FGR would involve significant
boiler modifications, including new high temperature flue gas ductwork, high temperature fans, dampers,
and control equipment. Because of the large capital costs for the addition of FGR and the incremental
emission reductions which would be achieved with this equipment, FGR is expected to have control costs
at least as high as for low NOx burners. Therefore, FGR is not evaluated further in this RACT analysis.
4.2 Selective Catalytic Reduction (SCR).
Selective Catalytic Reduction (SCR) is a post combustion flue gas treatment for controlling NOx emissions
which uses an ammonia (NH3) or urea (CO(NH2)2) injection system and a catalytic reactor. SCR systems
utilize an injection grid which disperses ammonia in the flue gas upstream of the catalyst. NH3 reacts with
NOx in the presence of the catalyst to form nitrogen (N2) and water according to the following equations:
4NH3 + 4NO + O2 → 4N2 + 6H2O 4NH3 + 2NO2 + O2 → 3N2 + 6H2O
2NH3 + NO2 + NO → 2N2 + 3H2O
Catalysts are substances which evoke chemical reactions that would otherwise not take place by providing
a reaction mechanism that has a lower activation energy than the uncatalyzed mechanism. For SCR, the
catalyst is usually a ceramic noble metal, a base metal (titanium or vanadium) oxide, or a zeolite-based
material. To achieve optimum long-term NOx reductions, SCR systems must be designed for each
application. In addition to critical temperature considerations, the ammonia injection rate must be carefully
controlled to maintain an NH3/NOx molar ratio that effectively reduces NOx. Excessive ammonia injection
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will result in ammonia emissions, called ammonia slip. SCR has the capability to make substantial
reductions in NOx emissions. For these boilers, SCR is expected to reduce NOx emissions by 90%.
4.3 Selective Non-Catalytic Reduction (SNCR).
In a selective non-catalytic reduction (SNCR) control system, urea or ammonia is injected into boilers
where the flue gas temperature is approximately 1,600 °F to 2,100 °F. At these temperatures, urea
[CO(NH2)2] or ammonia reacts with NOx, forming elemental nitrogen and water, without the need for a
catalyst. The overall NOx reduction reactions are similar to those for SCR. Multiple injection points are
required to thoroughly mix the reagent into the boiler furnace. The limiting factor for an SNCR system is
the ability to contact the NOx with the reagent without resulting in excessive ammonia slip and without
excessive ammonia decomposition before the NOx emissions can be reduced. The Utility Boiler ACT
indicates the reduction in NOx emissions achievable with SNCR at wall-fired utility boilers burning natural
gas or fuel oil is generally expected to be 25% to 40% from uncontrolled levels.14
SNCR has been widely used in circulating fluidized bed boilers burning solid fuels such as coal or biomass.
SNCR is not commonly used in other boiler types, although some pulverized coal-fired boilers do utilize
SNCR. Never-the-less, SNCR is generally considered to be a technically feasible NOx control technology
for natural gas and oil-fired utility boilers.
4.4 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™).
The EMx™ system is an add-on control device that catalytically oxidizes NO to NO2 and then adsorbs the
NO2 onto a potassium carbonate-coated catalyst surface. The overall chemical reaction between NO2 and
the potassium carbonate catalyst is as follows:
2 NO2 + K2CO3 → CO2 + KNO2 + KNO3
The EMx™ process does not require injection of a reactant, such as ammonia, into the gas stream being
treated. EMx™ catalyst is reported to perform acceptably in the operating temperature range of 425 °F to
750 °F with the best economy and lowest pressure drop achieved in the temperature range of 550 °F to 650
°F where the catalyst activity is highest and the catalyst volume is minimized.15 Based on this claimed
operating range, the flue gas temperatures from the Agua Fria Unit 1, 2, and 3 boilers would not be in the
optimal range for the EMx™ technology.
The EMx™ catalyst has a finite capacity to react with NO2 because potassium carbonate is “consumed” by
NO2 as shown above. Thus, in order to maintain the required NOx removal rate, the catalyst must be
periodically regenerated. Regeneration is accomplished by passing a reducing gas containing hydrogen in
14 Utility Boiler ACT Document at p. 2-31.
15 See, for example, http://docketpublic.energy.ca.gov/PublicDocuments/Regulatory/Non%20Active%20AFC's/07-
AFC-9%20Canyon/2009/January/TN%2049920%2001-28-09%20ECM%20Technology%20White%20Paper.pdf at
page 38 of the PDF file.
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dilute concentration (i.e., about 2 to 4 percent H2) across the surface of the catalyst in the absence of oxygen.
Hydrogen in the regeneration gas reacts with the nitrites and nitrates to form water and molecular nitrogen.
Carbon dioxide in the regeneration gas reacts with the potassium nitrite and nitrates to regenerate potassium
carbonate, which is the original chemical in the catalyst coating. The overall chemical reaction during
catalyst regeneration is as follows:
KNO2 + KNO3 + 4 H2 + CO2 → K2CO3 + 4 H2O + N2
The regeneration gas is produced in a gas generator using a two-stage process to produce molecular
hydrogen and carbon dioxide. In the first stage, natural gas and air are reacted across a partial oxidation
catalyst to form carbon monoxide and hydrogen. Steam is then added to the mixture and passed across a
low temperature shift catalyst, forming carbon dioxide and more hydrogen. The regeneration gas mixture
is diluted to less than four percent hydrogen using steam.
In order to regenerate its catalyst, the EMx™ system is constructed in parallel modules so that a module
can be isolated from the combustion turbine exhaust gas stream using inlet and outlet dampers. The isolated
module is then regenerated while other modules remain open to flow for treatment of the combustion turbine
exhaust gas stream.
Sulfur compounds (e.g., SO2, SO3) in the gas quickly inactivate the EMx™ catalyst requiring the catalyst
to be removed from the reactor for regeneration. To avoid this problem, EMx™ systems on natural gas
fueled combustion turbines include an upstream ESx™ catalyst module that removes the sulfur before they
reach the EMx™ catalyst beds. The ESx™ catalyst is regenerated at the same time as the EMx™ catalyst
by the same regeneration gas. This releases collected SOx as SO2 into the regeneration off-gas stream.
EMx™ is demonstrated for use on relatively small combined-cycle natural gas fueled combustion turbines.
The largest application is the 50 MW Unit 6 combined cycle combustion turbine at the Redding, California
municipal power plant. EMx™ has not been demonstrated on a large combined cycle combustion turbine
or on any simple-cycle combustion turbine. The La Paloma Generating Project in California initially
proposed to demonstrate EMx™ on a 150 MW turbine, but ultimately an SCR system was installed instead.
This was also the case with the Otay Mesa project located in California.
Some of the issues identified with applying EMx™ are:
• The catalyst is very sensitive to sulfur in the exhaust gas;
• The reliability of the system’s moving parts over time is an operational and maintenance concern;
• The use of hydrogen for regeneration could be a serious safety concern;
• The potential exists for scale-up issues for the larger boilers at the Agua Fria Generating Station;
• An EMx™ system has significant pressure drop – about twice that of a comparable SCR system –
which presents design challenges and would require the replacement of the induced draft fans.
An EMx™ system is expected to achieve controlled NOx emission rates similar to SCR systems, but the
costs are expected to be higher, and EMx™ systems have a limited number of current commercial and
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industrial scale applications on large utility boilers. For these reasons, an EMx™ system is not considered
feasible for this RACT analysis.
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5.0 Agua Fria Units 1, 2, and 3 Boilers.
The Agua Fria Generating Station Units 1, 2, and 3 are natural gas and fuel oil-fired electric utility steam
generating units. The general specifications for these units are summarized in Table 5-1. These units have
very low utilization, with a typical capacity factor of approximately 5 percent, and essentially 100% of the
heat input to all three boilers is typically natural gas.
TABLE 5-1. General specifications for the Agua Fria boilers, Units 1, 2, and 3.
Parameter Unit 1 Unit 2 Unit 3
Fuels Natural Gas / Fuel Oil Natural Gas / Fuel Oil Natural Gas / Fuel Oil
Manufacturer Riley Stoker Riley Stoker Riley Stoker
Boiler Type Wall-Fired Wall-Fired Wall-Fired
No. of Burners 12 12 16
Installation Date 1958 1957 1961
Heat Input Capacity, MMBtu/hr 1,253 1,253 1,956
Electric Capacity, MW 114 114 163
For the 5-year period from 2015 to 2019, the Unit 1 and 2 boilers had NOx emission rates of approximately
0.24 to 0.27 lb/MMBtu on an annual average basis, equal to flue gas NOx concentrations of 200 to 220
ppmdv at 3% excess oxygen. These are annual average rates across all load ranges. It is important to note
that the maximum hourly NOx emission rates are substantially higher than these annual average rates.
The Unit 3 boiler has a higher heat input capacity and higher steam production rate, but is a compact boiler
design with a higher heat release rate, expressed in Btu per hour per cubic foot of furnace volume (Btu/hr-
ft3). As a result, for the 5-year period from 2015 to 2019, the Unit 3 boiler had higher NOx emission rates
of approximately 0.46 to 0.55 lb/MMBtu on an annual average basis, equal to a flue gas NOx concentration
of 375 to 450 ppmdv at 3% excess oxygen. As with the Unit 1 and 2 boilers, the maximum hourly NOx
emission rates are substantially higher than these annual average rates.
5.1 Available NOx Control Technologies.
The available NOx control technologies for the Agua Fria Units 1, 2, and 3 boilers include LNB, SNCR,
and SCR.
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5.2 Low NOx Burners.
LNB are a common method used to control NOx emissions from natural gas-fired boilers. All three of the
Agua Fria Unit 1, 2 and 3 boilers are wall-fired boilers. Units 1 and 2 each have 12 burners, while Unit 3
has 16 burners. A low NOx burner replacement project would involve removing and replacing these
existing burners and making other changes such as upgrades to the boiler control systems.
SRP has received a budgetary quote from Riley Power Inc. to provide the design, material, and fabrication
of new STS® dual fuel LNB to replace the existing burners on the Agua Fria Unit 1, 2 and 3 boilers. The
new burners would be designed to bolt in place with minimal field modifications and have the capability
for 100% firing on either natural gas or distillate fuel oil. A copy of this budgetary quote is provided in
Appendix A of this RACT analysis. These burners would use the existing fans, gas valve train, and control
systems on each boiler. This proposal did not include performance guarantees, unloading, electrical
engineering, installation, startup assistance, or training.
For the Unit 1 and 2 boilers, Riley Power indicated expected performance of 0.16 lb NOx/MMBtu when
firing natural gas and 0.42 lb/MMBtu when firing fuel oil with the LNB. For the Unit 3 boiler, Riley Power
indicated expected controlled NOx emission rates of 0.4 to 0.5 lb/MMBtu with low NOx tips and windbox
partitioning, with emissions as low as 0.3 lb/MMBtu depending on actual unit performance and operating
conditions. From the budgetary quote, Riley Power indicated equipment costs of $2,200,000 for the first
of the Unit 1 and 2 boilers, and $1,850,000 for the second boiler, or an average LNB equipment cost of
$2,025,000 for each of the Unit 1 and 2 boilers. Riley Power also indicated an equipment cost of $2,375,000
for LNB for the Unit 3 boiler.
These quoted prices are for the LNB equipment only. The installation of these burners would include other
indirect costs such as installation, project administration, startup, emissions testing, and training of boiler
operators and plant maintenance staff. For this RACT analysis, consistent with the assumption made in the
Utility Boiler ACT document, the estimated indirect costs are 30% of the total direct costs.16 And because
these boilers are from 59 to 63 years old, there may be significant retrofit contingency costs not initially
anticipated, such as asbestos remediation, control system upgrades, or boiler water wall repairs necessary
for the installation of the burners. For this RACT analysis, the contingency cost is 20% of the sum of the
purchased equipment costs and indirect costs. No retrofit factor is applied.
Total annual costs include capital recovery and general and administrative costs, taxes, and insurance.
Consistent with the Control Cost Manual, the latter cost categories are assumed to be 4% of the total capital
costs.17 Labor, operating & maintenance costs, and overhead are conservatively assumed to be zero.
Tables 5-2 and 5-3 summarize the capital costs, annual costs, and cost effectiveness for low NOx burners
on the Unit 1 and 2 boilers and the Unit 3 boiler, respectively. From Table 5-3, the use of LNB on the Unit
1 and 2 boilers would result in a potential emission reduction of 49.4 tons per year per boiler based on a
16 Utility Boiler ACT Document at p. 6-19.
17 Control Cost Manual, 6th Ed., p. 2-34.
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capacity factor of 10%. LNB would have a total capital requirement of $3,159,000, an annual cost of
$473,200, and a cost effectiveness of $9,580 per ton of NOx controlled.
From Table 5-4, the use of LNB on the Unit 3 boiler would result in a potential emission reduction of 128.5
tons per year based on a unit capacity factor of 10% and an aggressive controlled NOx emission rate of 0.35
lb/MMBtu. LNB would have a capital cost of $3,705,000, an annual cost of $555,000, and a cost
effectiveness of $4,320 per ton of NOx controlled.
Based on these costs, the use of low NOx burners for the control of NOx emissions from the Agua Fria Units
1, 2, and 3 boilers is not a feasible RACT option.
TABLE 5-2. Capital costs, annual costs, and cost effectiveness for low NOx burners for each of the
Agua Fria Unit 1 and 2 boilers based on a 10% capacity factor for each boiler.
Total Capital Requirement with Retrofit (TCR)
Riley Power LNB Equipment Costs $2,025,000 Purchased Equipment Cost (PEC)
Indirect Costs $607,500 30% of the PEC
Contingency Costs $526,500 20% of the PEC and Indirect Costs
Total Capital Requirement $3,159,000
Annual Costs
General & Administrative, Taxes, $126,400 4% of TCR
Insurance
Capital Recovery $346,800 Based on 15-year life and 7% interest rate
Total Annual Cost $473,200
Emission Reduction and Cost Effectiveness
Uncontrolled Emission Rate 0.25 lb/MMBtu
Controlled Emission Rate 0.16 lb/MMBtu
Emission Reduction 49.4 ton/yr
Cost Effectiveness $9,580 $ per ton of NOx Controlled
TABLE 5-3. Capital costs, annual costs, and cost effectiveness for low NOx burners for the Agua
Fria Unit 3 boiler based on a 10% capacity factor.
Total Capital Requirement with Retrofit (TCR)
Riley Power Burner Equipment Costs $2,375,000 Purchased Equipment Cost (PEC)
Indirect Costs $712,500 30% of the PEC
Contingency Costs $617,500 20% of the PEC and Indirect Costs
Total Capital Requirement $3,705,000
Annual Costs
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General & Administrative, Taxes, $148,200 4% of TCR
Insurance
Capital Recovery $406,800 Based on 15-year life and 7% interest rate
Total Annual Cost $555,000
Emission Reduction and Cost Effectiveness
Uncontrolled Emission Rate 0.50 lb/MMBtu
Controlled Emission Rate 0.35 lb/MMBtu
Emission Reduction 128.5 ton/yr
Cost Effectiveness $4,320 $ per ton of NOx Controlled
5.3 Selective Non-Catalytic Reduction (SNCR).
SNCR systems for these boilers would include an ammonia injection grid which would inject urea into the
boiler at locations which would optimize NOx reduction at the given boiler load, as well as aqueous
ammonia or urea storage tanks, and metering equipment and controls. SNCR systems would also require
piping, water treatment for dilution water, ductwork and ductwork modifications, auxiliary power
modifications, and other electrical and site upgrades necessary as part of the SNCR systems.
For purposes of this RACT analysis, the costs of applying SNCR have been conservatively estimated using
the methodology recommended by U.S. EPA in its recently released update to Section 4, Chapter 1 of the
Control Cost Manual.18 Appendix B of this report includes the output of this spreadsheet for the Units 1
and 2 and Unit 3 boilers. Costs estimated using this methodology significantly understate the actual costs
that would be incurred to install SNCR because they do not include annualized sales taxes, property taxes,
insurance costs, or costs for operating and supervisory labor. Inclusion of these costs would be appropriate
and would be consistent with both the Utility Boiler ACT Document and Section 1, Chapter 2 of the Control
Cost Manual.
Table 5-4 summarizes the data from these control cost spreadsheets. The costs in Table 5-4 are based on a
capacity factor of 10% for each boiler and a conservatively assumed SNCR control efficiency of 40% from
the uncontrolled emission rates.
18 Spreadsheet available on the U.S. EPA internet web site at www.epa.gov/sites/production/files/2019-
06/sncrcostmanualspreadsheet_june2019vf.xlsm.
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TABLE 5-4. Capital costs, annual costs, and cost effectiveness for SNCR for the Agua Fria Unit 1,
2, and 3 boilers based on a 10% capacity factor for each boiler.
Units 1 and 2 Unit 3
(each)
Capital Cost, $ $4,233,000 $5,321,000
Capital Cost, $ per kW $37 $33
Direct Annual Costs, $ per year $99,100 $274,900
Indirect Annual Costs (incl. Capital Recovery), $ per year $466,700 $586,600
Total Annual Costs, $ per year $565,800 $861,500
NOx Emission Reduction, tons per year 52.6 164.3
Cost Effectiveness, $ per ton of NOx controlled $10,750 $5,240
From Table 5-4, the use of SNCR on each of the Unit 1 and 2 boilers would result in a potential emission
reduction of 52.6 tons per year. SNCR would have a capital cost of $4,233,000; an annual cost of $565,800;
and a cost effectiveness of $10,750 per ton of NOx controlled. The use of SNCR on the Unit 3 boiler would
result in a potential emission reduction of 164.3 tons per year. SNCR would have a capital cost of
$5,321,000; an annual cost of $861,500; and a cost effectiveness of $5,240 per ton of NOx controlled. Based
on these costs, the use of SNCR for the control of NOx emissions from the Agua Fria Units 1, 2, and 3
boilers is not a feasible RACT option.
5.4 Selective Catalytic Reduction (SCR).
SCR systems for these boilers would include a catalyst reactor housing located upstream of the air heater,
the catalyst and support matrix, an ammonia injection grid, aqueous ammonia storage tanks, and ammonia
metering equipment and controls. SCR systems would also require piping, water treatment for dilution
water, ductwork and ductwork modifications, auxiliary power modifications, and other electrical and site
upgrades necessary as part of the SCR systems.
For purposes of this RACT analysis, the costs of applying SCR have been conservatively estimated using
the methodology recommended by U.S. EPA in its recently released update to Section 4, Chapter 2 of the
Control Cost Manual.19 Appendix C of this report includes the output of this spreadsheet for the Units 1
and 2 and Unit 3 boilers.
19 Spreadsheet available on the U.S. EPA internet web site at www.epa.gov/sites/production/files/2019-
06/scrcostmanualspreadsheet_june-2019vf.xlsm.
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Table 5-5 summarizes the data from these control cost spreadsheets. The costs in Table 3 are based on a
capacity factor of 10% for each boiler and an SCR control efficiency of 90% from the uncontrolled emission
rates.
TABLE 5-5. Capital costs, annual costs, and cost effectiveness for SCR for the Agua Fria Unit 1, 2,
and 3 boilers based on a 10% capacity factor for each boiler.
Units 1 and 2 Unit 3
(each)
Capital Cost, $ $12,634,000 $15,939,000
Capital Cost, $ per kW $111 $98
Direct Annual Costs, $ per year $330,500 $752,700
Indirect Annual Costs (incl. Capital Recovery), $ per year $1,390,400 $1,753,500
Total Annual Costs, $ per year $1,720,900 $2,506,200
NOx Emission Reduction, tons per year 123.5 385.5
Cost Effectiveness, $ per ton of NOx controlled $13,940 $6,500
From Table 5-5, the use of SCR on each of the Unit 1 and 2 boilers would result in a potential emission
reduction of 123.5 tons per year. SCR would have a capital cost of $12,634,000; an annual cost of
$1,720,900; and a cost effectiveness of $13,940 per ton of NOx controlled. The use of SCR on the Unit 3
boiler would result in a potential emission reduction of 385.5 tons per year. SCR would have a capital cost
of $15,939,000; an annual cost of $2,506,200; and a cost effectiveness of $6,500 per ton of NOx controlled.
Based on these costs, the use of SCR for the control of NOx emissions from the Agua Fria Units 1, 2, and
3 boilers is not a feasible RACT option.
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5.5 Conclusions.
Tables 5-6 and 5-7 summarize the available and technically feasible NOx RACT options for the Agua Fria
Generating Station Units 1, 2, and 3 boilers, the potential emission reductions, and the cost effectiveness of
each control option. Note that the potential emission reductions and the resulting cost effectiveness are
based on a on a capacity factor of 10% for each boiler which greatly overstates the actual emissions and the
potential emission reductions. Even with these conservative assumptions, no control options meet the cost
effectiveness threshold of $2,300 per ton discussed in Section 2.4 of this report.
TABLE 5-6. NOx control options, emission reductions, and cost effectiveness for each of the
Agua Fria Generating Station Unit 1 and 2 boilers based on a 10% capacity factor.
Emission Annual Cost
NOx Control Option Rate Emissions Capital Cost Annual Cost Effectiveness
lb/MMBtu ton/yr $ per ton
Current Uncontrolled 0.25 137.2
Boiler
LNB 0.16 87.8 $3,159,000 $473,200 $9,580
SNCR 0.15 84.6 $4,233,000 $565,800 $10,750
SCR 0.025 13.7 $12,634,000 $1,720,900 $13,940
TABLE 5-7. NOx control options, emission reductions, and cost effectiveness for the Agua Fria
Generating Station Unit 3 boiler based on a 10% capacity factor.
Emission Annual Cost
NOx Control Option Rate Emissions Capital Cost Annual Cost Effectiveness
lb/MMBtu ton/yr $ per ton
Current Uncontrolled 0.50 428.4
Boiler
LNB 0.35 299.9 $3,705,000 $555,000 $4,320
SNCR 0.30 264.1 $5,321,000 $861,500 $5,240
SCR 0.050 42.8 $15,939,000 $2,506,200 $6,500
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Appendix A
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Kris Pringle November 22, 2019
Mechanical Engineer Sr.
Salt River Project
P.O. Box 52025
Phoenix, AZ 85072-2025
Re: 503660 SRP Agua Fria Power Plant Burner Replacement
Design, Supply and Installation Proposal – Revision 01
Dear Mr. Pringle,
We appreciate the time extended to Mike Lynch (V.P Projects) and the Riley Power Sales team last week
by Bob Ellis to better understand SRP’s operational goals for Agua Fria Units 1 – 3. From this
information, we are pleased to present you with this more accurate budget estimate including new
gas/oil burners and the ability to light off oil during any interruption of gas supply.
This indicative budget pricing for the scope associated with the design, supply and installation of new
burners to startup on D2 in case of a loss of all Gas supply while meeting current emissions
requirements at Agua Fria Power Plant in Glendale, Maricopa County, Arizona. As the boiler OEM, Riley
Power is uniquely suited to consider both the boiler implications (e.g. performance, temperatures, etc..),
and the burner implications (e.g. flame length, emissions) for this important project.
The basis of this budgetary proposal to provide a Design & Erect (D&E) approach under the Babcock
Power family of companies, with Riley Power Inc (RPI) assuming responsibility for the engineering,
design, procurement, delivery, and TEi Construction (TEIC) will be responsible for the installation of the
equipment.
Riley Power Inc. Experience
With our technical expertise and demonstrated project execution capabilities, RPI provides optimum
technical solutions to the industrial and utility markets. These solutions address boiler technologies, as
well as current and potential future emission regulations. RPI solutions are competitive from both a
capital and operational cost perspective with delivery of these solutions on schedule and with high
quality.
RPI and TEIC have executed numerous burner retrofit / replacement projects over the last few years and
are able to coordinate design with constructability to streamline the overall project success.
The Riley Power Team
Low Evaluated Cost: RPI’s goal is to provide the maximum benefit to SRP while achieving the minimum
total evaluated cost.
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Proven Design: RPI is well experienced in the successful design, supply, start-up, and performance of
fuel burning systems.
Project Management Capability: The RPI team will provide unmatched depth of experience, ability to
execute large projects, and financial strength. Our experience and expertise will provide the best
performing and most reliable technology possible, and a successfully executed project.
Experienced in Fired Equipment Systems Projects: Riley Power’s experience in the design of boiler
systems makes us one of the preeminent suppliers of these systems in the world. We are a major
supplier of engineered products and services to the utility and industrial industries in the areas of fuel
combustion systems, boiler upgrades, fuel switching, and environmental controls. The entire design will
be performed at our headquarters in Marlborough, Massachusetts where engineers and designers work
to provide our clients with state-of-the-art designs using the latest tools such as ProE, STAAD, AutoCAD
and FLUENT CFD Modeling.
Financial Strength: RPI has developed and maintained solid financial strength through its diverse lines
of products and services for the U.S. utility and industrial markets. RPI has more than adequate
resources to complete this project on time and within budget, while meeting all contract requirements.
1.0 Scope of Supply
RPI will provide the following materials and services, as described below.
1.1. Riley STS® Gas Burner
RPI will provide the design, material, and fabrication of new STS® dual fuel burners to replace the
existing burners. The new burners will be designed to bolt in place with minimal field modifications.
The STS® burner will have the capability for 100% firing on either natural gas or number 2 fuel oil.
• Twelve (12) Riley Power Inc. STS® dual fuel burners, each with:
o Dual air zone with stainless steel primary air (PA) barrel
o Stainless steel PA swirler
o 310 stainless steel gas injector nozzles
o Adjustable secondary air (SA) swirl vanes (to be set during commissioning for optimal flame
shape)
o Adjustable burner shroud and PA flow control damper (to bet set during commissioning for
optimal burner air distribution)
o Opening for main flame scanner
o One (1) view port
• Class III Special – Direct Spark igniter (HESI)
• Flame scanner (Dual Channel IR/UV)
• Oil Guns
• Flex hoses for gas and oil
1.2. Engineering Services
• Provide arrangement drawings for RPI supplied equipment
• Provide design documentation, drawings, lists, and manuals for RPI supplied equipment
• Provide installation arrangement drawings of burner equipment and mechanical equipment
supplied in this Proposal
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1.3. Project Management
• Project Manager providing overall project and technical coordination
• Project scheduling and reporting
• Quality Assurance and Control
1.4. Clarifications & Exclusions
• Clarifications:
o Existing fan(s) are to be reused to supply combustion air and cooling air.
o Existing gas valve train is in working condition and can be reused to supply adequate gas flow.
o Existing oil valve train is in working condition and can be reused to supply adequate oil flow.
o Burner front piping to be reused upstream of fuel flex hoses.
o The existing control system(s) will be reused. RPI will provide new air and fuel curves to be
integrated into existing control system by Owner.
o Note that RPI recommends that the existing fuel trains are reviewed for NFPA compliance
• Exclusions:
o Performance Guarantees (if required, to be developed and agreed upon under final contract)
o Unloading of shipped components
o Removal, abatement, and/or disposal of Asbestos and Lead
o Electrical engineering, material supply and installation, if required
o Scaffolding or insulation and lagging
o Refractory repairs or replacement
o Any equipment or services not explicitly stated in this proposal
o Startup Assistance (this can be provided at T&M rates, attached)
o On-site training
o Evaluation of existing equipment not modified by RPI
2.0 Technical Discussion
2.1. STS® Burner System Description
RPI has successfully supplied over 300 STS® burners firing natural gas as a primary and secondary
fuel since 1992. Over 50 have been supplied within last three years. The STS® burner design
excellent flexibility for various fuel sources and across a wide operating load range.
As shown in Figure 1, the combustion air passageway into the furnace is divided into two (2)
streams; primary and secondary air, with independent air flow and swirl control. All adjustments on
the burner are manually set during commissioning for optimal performance and are then left in
place during operation.
Total air flow to the burner is controlled by the burner total air shroud. The primary air (PA) and
secondary air (SA) flow split is controlled through a manually adjusted sleeve damper. The
secondary air register has adjustable axial blades, which provide excellent swirl control and low
pressure drop. The SA swirl is adjustable from the burner front from 0° (no swirl) to 60° (high swirl).
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Separating the swirl control and flow control adjustments gives the STS® burner significantly more
flame shaping control and allows for improved turndown capability. The vanes are used to control
the degree of swirl and subsequent fuel/air mixing and NOX performance. The flame by the STS®
Burner is very symmetrical around the burner throat.
For natural gas firing, a series of gas nozzles are provided on a center gas manifold designed for the
specific application and burner capacity. An air swirler/stabilizer is positioned within the gas nozzles.
The center gas manifold and swirler is located inside the primary air barrel of the burner. Axial and
radial adjustments can be made to the gas tips and swirler to control NOX emissions and flame
shape. These adjustments would be made only if required for fine tuning.
Figure 1: RPI STS burner
2.2. STS® Burner Performance
As seen in Figure 2, the flame produced by the STS® burner is well attached and very uniform to the
burner throat exit. The ignition point is strongly rooted within the burner throat. The flame shape is
narrow close the burner and gradually expands in a conical shape.
Viewing this flame from the observation port mounted on the burner front, one will see a blue-to-
yellow gas flame symmetrically situated around the periphery of the swirler. Flame scannability is
excellent.
a
Figure 2: RPI STS burner flame
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3.0 Commercial
RPI is providing the following indicative non-binding budget pricing for the design, supply and
installation of the replacement STS® burners, as outlined in this proposal:
~ Two Million Two Hundred Thousand Dollars ($2,200,000)
• All materials have been specified and quoted based on RPI standards, and USA codes.
• Pricing does not include sales, use, and other similar taxes
• Pricing does not include spare parts
• Pricing is estimated based on a one (1) year warranty, material only
• Pricing is based current day labor rates and material pricing
• Freight - not include in price, FOB shipping point, prepay and add
• Payment terms – cash neutral milestone payments, net 30 days
For the 2nd duplicate Unit (12 burners), the non-binding budget pricing would be:
~ One Million Eight Hundred Fifty Thousand Dollars ($1,850,000)
For the 3rd Unit (16 burners), the non-binding budget pricing would be:
~ Two Million Three Hundred Seventy-Five Thousand Dollars ($2,375,000)
3.1. Commercial Terms
Commercial terms are to be developed and mutually agreed upon under a final, firm proposal offer.
3.2. Validity
Pricing is indicative non-binding budget pricing and does not represent a firm offer.
3.3. Delivery Schedule
Delivery will be confirmed upon final firm pricing offer. Typically, delivery of this equipment will be
around 26-30 weeks after approved drawings depending on shop loading at time of order.
RPI would like to thank you for this opportunity to work with the Agua Fria on the development of this
project and looks forward to following up this submittal with any additional clarifications necessary.
Should you have any questions please contact Katie Hudon at (508) 854-3996 or Michael Lynch at (508)
854-4001.
Best regards,
Katie Hudon, P.E.
Senior Project Manager
Riley Power, Inc.
Tel: (508) 854-3996, Cell: (774) 239-7669 CC: M. Lynch
R. Ellis
Attachments:
Riley-STS-Overview
147

Appendix B
Salt River Project RTP Environmental Associates, Inc.
NOx RACT Analysis for the Agua Fria Generating Station Unit 1, 2, and 3 Boilers. July 2020
148

Data Inputs
Enter the following data for your combustion unit:
Is the combustion unit a utility or industrial boiler? What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
Please enter a retrofit factor equal to or greater than 0.84 based on the level of
1.00
difficulty. Enter 1 for projects of average retrofit difficulty.
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)? 114 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel? 1,030 Btu/scf Enter the sulfur content (%S) = percent by weight
*HHV value of 1030 Btu/scf is a default value. See below for data source. Enter actual HHV for fuel burned, if known. or
Select the appropriate SO2 emission rate:
What is the estimated actual annual MW output? 99,864 MW/year
Ash content (%Ash): percent by weight
Is the boiler a fluid-bed boiler?
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV, %S, %Ash and cost. Please
Enter the net plant heat input rate (NPHR) 10.99 MMBtu/MW enter the actual values for these parameters in the table below. If the actual value for any
parameter is not known, you may use the default values provided.
Fraction in Fuel Cost
Coal Blend %S %Ash HHV (Btu/lb) ($/MMBtu)
If the NPHR is not known, use the default NPHR value: Fuel Type Default NPHR Bituminous 0 2.35 10.4 11,814 2.79
Coal 10 MMBtu/MW Sub-Bituminous 0 0.31 5.8 8,730 2.04
Fuel Oil 11 MMBtu/MW Lignite 0 0.91 14.3 6,534 1.85
Natural Gas 8.2 MMBtu/MW
Please click the calculate button to calculate weighted
values based on the data in the table above.
Salt River Project RTP Environmental Associates, Inc.
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Enter the following design parameters for the proposed SNCR:
Number of days the SNCR operates (tSNCR) 350 days Plant Elevation 1128 Feet above sea level
Inlet NOx Emissions (NOxin) to SNCR 0.25 lb/MMBtu
NOx Removal Efficiency (EF) provided by vendor (Enter
40 percent
"UNK" if value is not known)
Estimated Normalized Stoichiometric Ratio (NSR) 1.05
*The NSR value of 1.05 is a default value. User should enter actual value, if known.
Concentration of reagent as stored (Cstored) 50 percent* *The reagent concentration of 50% is a default value. User should enter actual value, if known.
Denisty of reagent as stored (ρstored) 71 lb/ft3
Concentration of reagent injected (Cinj) 50 percent Densities of typical SNCR reagents:
Number of days reagent is stored (tstorage) 14 days 50% urea solution 71 lbs/ft3
Estimated equipment life 15 Years 29.4% aqueous NH3 56 lbs/ft3
19% aqueous NH3 58 lbs/ft3
Select the reagent used
Enter the cost data for the proposed SNCR:
Desired dollar-year 2019
CEPCI for 2019 592.1 Enter the CEPCI value for 2019 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index
Annual Interest Rate (i) 7.0 Percent
Fuel (Costfuel) 3.00 $/MMBtu
Reagent (Costreag) 1.62 $/gallon for a 50 percent solution of ammonia*
Water (Costwater) 0.0088 $/gallon*
Electricity (Costelect) 0.0390 $/kWh*
Ash Disposal (for coal-fired boilers only) (Costash) $/ton
* The values marked are default values. See the table below for the default values used
and their references. Enter actual values, if known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet users. Use of other well-known cost indexes (e.g.,
M&S) is acceptable.
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) = 0.015
Administrative Charges Factor (ACF) = 0.03
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Data Sources for Default Values Used in Calculations:
If you used your own site-specific values, please enter
Data Element Default Value Sources for Default Value the the value used and the reference source . . .
Reagent Cost $1.62/gallon of Based on vendor quotes collected in 2014.
50% urea
solution
Water Cost ($/gallon) 0.0088 Average combined water/wastewater rates for industrial facilities in 2013 compiled
by Black & Veatch. (see 2012/2013 "50 Largest Cities Water/Wastewater Rate
Survey." Available at
http://www.saws.org/who_we_are/community/RAC/docs/2014/50-largest-cities-
brochure-water-wastewater-rate-survey.pdf.
Electricity Cost ($/kWh) 0.039 Average annual electricity cost for utilities is based on 2014 electricity production
cost data for fossil-fuel plants compiled by the U.S. Energy Information (EIA).
Available at http://www.eia.gov/tools/faqs/faq.cfm?id=19&t=3.
Fuel Cost ($/MMBtu) 5.14 Weighted average cost based on average 2014 fuel cost data for power plants
compiled by the U.S. Energy Information Administration (EIA) from data reported on
EIA Form EIA-923, "Power Plant Operations Report." Available at
http://www.eia.gov/electricity/data/eia923/.
Ash Disposal Cost ($/ton) Not Applicable Not Applicable Not Applicable
Percent sulfur content for Coal (% weight) Not Applicable Not Applicable Not Applicable
Percent ash content for Coal (% weight) Not Applicable Not Applicable Not Applicable
Higher Heating Value (HHV) (Btu/lb) 1,030 2014 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics,
U.S. Energy Information Administration (EIA) from data reported on EIA Form EIA-
923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Salt River Project RTP Environmental Associates, Inc.
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SNCR Design Parameters
The following design parameters for the SNCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost
Estimate tab.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) = Bmw x NPHR = 1,253 MMBtu/hour
Maximum Annual MW Output (Bmw) = Bmw x 8760 = 998,640 MW/year
Estimated Actual Annual MW Output
99,864 MW/year
(Boutput) =
Heat Rate Factor (HRF) = NPHR/10 = 1.10
Total System Capacity Factor (CFtotal) = (Boutput/Bmw)*(tsncr/365) = 0.10 fraction
Total operating time for the SNCR (top) = CFtotal x 8760 = 840 hours
NOx Removal Efficiency (EF) = (Noxin - NOxout)/Noxin = 40.00 percent
NOx removed per hour = NOxin x EF x QB = 125.29 lb/hour
Total NOx removed per year = (NOxin x EF x QB x top)/2000 = 52.62 tons/year
Coal Factor (CoalF) = 1 for bituminuous; 1.05 for sub-bituminous; 1.07 for Not applicable; factor applies only to coal-
lignite (weighted average is used for coal blends) fired boilers
SO2 Emission rate = (%S/100)x(64/32)*1E6)/HHV = Not applicable; factor applies only to coal-
fired boilers
Elevation Factor (ELEVF) = 14.7 psia/P = 1.04
Atmospheric pressure at 1128 feet above sea 2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)*
14.1 psia
level (P) = =
Retrofit Factor (RF) = Retrofit to existing boiler 1.00
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
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Reagent Data:
Type of reagent used Ammonia Molecular Weight of Reagent (MW) = 17.03 g/mole
Density = 71 lb/gallon
Parameter Equation Calculated Value Units
Reagent consumption rate (mreagent) = (NOxin x QB x NSR x MWR)/(MWNOx x SR) = 122 lb/hour
(whre SR = 1 for NH3; 2 for Urea
Reagent Usage Rate (msol) = mreagent/Csol = 243 lb/hour
(msol x 7.4805)/Reagent Density 26 gal/hour
Estimated tank volume for reagent storage =
8,619 gallons (storage needed to store a 14 day reagent supply)
(msol x 7.4805 x tstorage x 24)/Reagent Density =
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) = i (1+ i)n/(1+ i)n - 1 = 0.1098
Where n = Equipment Life and i= Interest Rate
Parameter Equation Calculated Value Units
Electricity Usage:
Electrcity Consumption (P) = (0.47 x NOxin x NSR x QB)/NPHR = 14.06 kW/hour
Water Usage:
Water consumption (qw) = (msol/Density of water) x ((Cstored/Cinj) - 1) = 0 gallons/hour
Fuel Data:
Additional Fuel required to evaporate water in
Hv x mreagent x ((1/Cinj)-1) = 0.11 MMBtu/hour
injected reagent (ΔFuel) =
Ash Disposal:
Additional ash produced due to increased fuel Not applicable - Ash disposal cost applies only
(Δfuel x %Ash x 1E6)/HHV = 0.00 lb/hour to coal-fired boilers
consumption (Δash) =
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Cost Estimate
Total Capital Investment (TCI)
For Coal-Fired Boilers:
TCI = 1.3 x (SNCRcost + APHcost + BOPcost)
For Fuel Oil and Natural Gas-Fired Boilers:
TCI = 1.3 x (SNCRcost + BOPcost)
Capital costs for the SNCR (SNCRcost) = $1,272,147 in 2019 dollars
Air Pre-Heater Costs (APHcost)* = $0 in 2019 dollars
Balance of Plant Costs (BOPcost) = $1,984,005 in 2019 dollars
Total Capital Investment (TCI) = $4,232,997 in 2019 dollars
* Not applicable - This factor applies only to coal-fired boilers that burn bituminous coal and emits equal to or greater than 0.3lb/MMBtu
of sulfur dioxide.
SNCR Capital Costs (SNCRcost)
For Coal-Fired Utility Boilers:
SNCRcost = 220,000 x (BMW x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
SNCRcost = 147,000 x (BMW x HRF)0.42 x ELEVF x RF
For Coal-Fired Industrial Boilers:
SNCRcost = 220,000 x (0.1 x QB x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
SNCRcost = 147,000 x ((QB/NPHR)x HRF)0.42 x ELEVF x RF
SNCR Capital Costs (SNCRcost) = $1,272,147 in 2019 dollars
Air Pre-Heater Costs (APHcost)*
For Coal-Fired Utility Boilers:
APHcost = 69,000 x (BMW x HRF x CoalF)0.78 x AHF x RF
For Coal-Fired Industrial Boilers:
APHcost = 69,000 x (0.1 x QB x HRF x CoalF)0.78 x AHF x RF
Air Pre-Heater Costs (APHcost) = $0 in 2019 dollars
* Not applicable - This factor applies only to coal-fired boilers that burn bituminous coal and emit equal to or greater than 0.3lb/MMBtu of
sulfur dioxide.
Balance of Plant Costs (BOPcost)
For Coal-Fired Utility Boilers:
BOPcost = 320,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
BOPcost = 213,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x RF
For Coal-Fired Industrial Boilers:
BOPcost = 320,000 x (0.1 x QB)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
BOPcost = 213,000 x (QB/NPHR)0.33 x (NOxRemoved/hr)0.12 x RF
Balance of Plan Costs (BOPcost) = $1,984,005 in 2019 dollars
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Annual Costs
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
Direct Annual Costs (DAC) = $99,139 in 2019 dollars
Indirect Annual Costs (IDAC) = $466,665 in 2019 dollars
Total annual costs (TAC) = DAC + IDAC $565,805 in 2019 dollars
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Water Cost) + (Annual Fuel Cost) +
(Annual Ash Cost)
Annual Maintenance Cost = 0.015 x TCI = $63,495 in 2019 dollars
Annual Reagent Cost = qsol x Costreag x top = $34,908 in 2019 dollars
Annual Electricity Cost = P x Costelect x top = $461 in 2019 dollars
Annual Water Cost = qwater x Costwater x top = $0 in 2019 dollars
Additional Fuel Cost = ΔFuel x Costfuel x top = $276 in 2019 dollars
Additional Ash Cost = ΔAsh x Costash x top x (1/2000) = $0 in 2019 dollars
Direct Annual Cost = $99,139 in 2019 dollars
Indirect Annual Cost (IDAC)
IDAC = Administrative Charges + Capital Recovery Costs
Administrative Charges (AC) = 0.03 x Annual Maintenance Cost = $1,905 in 2019 dollars
Capital Recovery Costs (CR)= CRF x TCI = $464,760 in 2019 dollars
Indirect Annual Cost (IDAC) = AC + CR = $466,665 in 2019 dollars
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Total Annual Cost (TAC) = $565,805 per year in 2019 dollars
NOx Removed = 52.6 tons/year
Cost Effectiveness = $10,753 per ton of NOx removed in 2019 dollars
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Data Inputs
Enter the following data for your combustion unit:
Is the combustion unit a utility or industrial boiler? What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
Please enter a retrofit factor equal to or greater than 0.84 based on the level of
1.00
difficulty. Enter 1 for projects of average retrofit difficulty.
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)? 163 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel? 1,030 Btu/scf Enter the sulfur content (%S) = percent by weight
*HHV value of 1030 Btu/scf is a default value. See below for data source. Enter actual HHV for fuel burned, if known. or
Select the appropriate SO2 emission rate:
What is the estimated actual annual MW output? 142,788 MW/year
Ash content (%Ash): percent by weight
Is the boiler a fluid-bed boiler?
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV, %S, %Ash and cost. Please
Enter the net plant heat input rate (NPHR) 12 MMBtu/MW enter the actual values for these parameters in the table below. If the actual value for any
parameter is not known, you may use the default values provided.
Fraction in Fuel Cost
Coal Blend %S %Ash HHV (Btu/lb) ($/MMBtu)
If the NPHR is not known, use the default NPHR value: Fuel Type Default NPHR Bituminous 0 2.35 10.4 11,814 2.79
Coal 10 MMBtu/MW Sub-Bituminous 0 0.31 5.8 8,730 2.04
Fuel Oil 11 MMBtu/MW Lignite 0 0.91 14.3 6,534 1.85
Natural Gas 8.2 MMBtu/MW
Please click the calculate button to calculate weighted
values based on the data in the table above.
Salt River Project
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May 2020
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Enter the following design parameters for the proposed SNCR:
Number of days the SNCR operates (tSNCR) 350 days Plant Elevation 1128 Feet above sea level
Inlet NOx Emissions (NOxin) to SNCR 0.5 lb/MMBtu
NOx Removal Efficiency (EF) provided by vendor (Enter
40 percent
"UNK" if value is not known)
Estimated Normalized Stoichiometric Ratio (NSR) 1.05
*The NSR value of 1.05 is a default value. User should enter actual value, if known.
Concentration of reagent as stored (Cstored) 50 percent* *The reagent concentration of 50% is a default value. User should enter actual value, if known.
Denisty of reagent as stored (ρstored) 71 lb/ft3
Concentration of reagent injected (Cinj) 50 percent Densities of typical SNCR reagents:
Number of days reagent is stored (tstorage) 14 days 50% urea solution 71 lbs/ft3
Estimated equipment life 15 Years 29.4% aqueous NH3 56 lbs/ft3
19% aqueous NH3 58 lbs/ft3
Select the reagent used
Enter the cost data for the proposed SNCR:
Desired dollar-year 2019
CEPCI for 2019 592.1 Enter the CEPCI value for 2019 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index
Annual Interest Rate (i) 7.0 Percent
Fuel (Costfuel) 3.00 $/MMBtu
Reagent (Costreag) 1.62 $/gallon for a 50 percent solution of urea*
Water (Costwater) 0.0088 $/gallon*
Electricity (Costelect) 0.0390 $/kWh*
Ash Disposal (for coal-fired boilers only) (Costash) $/ton
* The values marked are default values. See the table below for the default values used
and their references. Enter actual values, if known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet users. Use of other well-known cost indexes (e.g.,
M&S) is acceptable.
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) = 0.015
Administrative Charges Factor (ACF) = 0.03
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Data Sources for Default Values Used in Calculations:
If you used your own site-specific values, please enter
Data Element Default Value Sources for Default Value the the value used and the reference source . . .
Reagent Cost $1.62/gallon of Based on vendor quotes collected in 2014.
50% urea
solution
Water Cost ($/gallon) 0.0088 Average combined water/wastewater rates for industrial facilities in 2013 compiled
by Black & Veatch. (see 2012/2013 "50 Largest Cities Water/Wastewater Rate
Survey." Available at
http://www.saws.org/who_we_are/community/RAC/docs/2014/50-largest-cities-
brochure-water-wastewater-rate-survey.pdf.
Electricity Cost ($/kWh) 0.039 Average annual electricity cost for utilities is based on 2014 electricity production
cost data for fossil-fuel plants compiled by the U.S. Energy Information (EIA).
Available at http://www.eia.gov/tools/faqs/faq.cfm?id=19&t=3.
Fuel Cost ($/MMBtu) 5.14 Weighted average cost based on average 2014 fuel cost data for power plants
compiled by the U.S. Energy Information Administration (EIA) from data reported on
EIA Form EIA-923, "Power Plant Operations Report." Available at
http://www.eia.gov/electricity/data/eia923/.
Ash Disposal Cost ($/ton) Not Applicable Not Applicable Not Applicable
Percent sulfur content for Coal (% weight) Not Applicable Not Applicable Not Applicable
Percent ash content for Coal (% weight) Not Applicable Not Applicable Not Applicable
Higher Heating Value (HHV) (Btu/lb) 1,030 2014 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics,
U.S. Energy Information Administration (EIA) from data reported on EIA Form EIA-
923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Salt River Project
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May 2020
158

SNCR Design Parameters
The following design parameters for the SNCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost
Estimate tab.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) = Bmw x NPHR = 1,956 MMBtu/hour
Maximum Annual MW Output (Bmw) = Bmw x 8760 = 1,427,880 MW/year
Estimated Actual Annual MW Output
142,788 MW/year
(Boutput) =
Heat Rate Factor (HRF) = NPHR/10 = 1.20
Total System Capacity Factor (CFtotal) = (Boutput/Bmw)*(tsncr/365) = 0.10 fraction
Total operating time for the SNCR (top) = CFtotal x 8760 = 840 hours
NOx Removal Efficiency (EF) = (Noxin - NOxout)/Noxin = 40.00 percent
NOx removed per hour = NOxin x EF x QB = 391.20 lb/hour
Total NOx removed per year = (NOxin x EF x QB x top)/2000 = 164.30 tons/year
Coal Factor (CoalF) = 1 for bituminuous; 1.05 for sub-bituminous; 1.07 for Not applicable; factor applies only to coal-
lignite (weighted average is used for coal blends) fired boilers
SO2 Emission rate = (%S/100)x(64/32)*1E6)/HHV = Not applicable; factor applies only to coal-
fired boilers
Elevation Factor (ELEVF) = 14.7 psia/P = 1.04
Atmospheric pressure at 1128 feet above sea 2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)*
14.1 psia
level (P) = =
Retrofit Factor (RF) = Retrofit to existing boiler 1.00
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Salt River Project
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Reagent Data:
Type of reagent used Urea Molecular Weight of Reagent (MW) = 60.06 g/mole
Density = 71 lb/gallon
Parameter Equation Calculated Value Units
Reagent consumption rate (mreagent) = (NOxin x QB x NSR x MWR)/(MWNOx x SR) = 670 lb/hour
(whre SR = 1 for NH3; 2 for Urea
Reagent Usage Rate (msol) = mreagent/Csol = 1,340 lb/hour
(msol x 7.4805)/Reagent Density 141 gal/hour
Estimated tank volume for reagent storage =
47,457 gallons (storage needed to store a 14 day reagent supply)
(msol x 7.4805 x tstorage x 24)/Reagent Density =
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) = i (1+ i)n/(1+ i)n - 1 = 0.1098
Where n = Equipment Life and i= Interest Rate
Parameter Equation Calculated Value Units
Electricity Usage:
Electrcity Consumption (P) = (0.47 x NOxin x NSR x QB)/NPHR = 40.22 kW/hour
Water Usage:
Water consumption (qw) = (msol/Density of water) x ((Cstored/Cinj) - 1) = 0 gallons/hour
Fuel Data:
Additional Fuel required to evaporate water in
Hv x mreagent x ((1/Cinj)-1) = 0.60 MMBtu/hour
injected reagent (ΔFuel) =
Ash Disposal:
Additional ash produced due to increased fuel Not applicable - Ash disposal cost applies only
(Δfuel x %Ash x 1E6)/HHV = 0.00 lb/hour to coal-fired boilers
consumption (Δash) =
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Cost Estimate
Total Capital Investment (TCI)
For Coal-Fired Boilers:
TCI = 1.3 x (SNCRcost + APHcost + BOPcost)
For Fuel Oil and Natural Gas-Fired Boilers:
TCI = 1.3 x (SNCRcost + BOPcost)
Capital costs for the SNCR (SNCRcost) = $1,533,886 in 2019 dollars
Air Pre-Heater Costs (APHcost)* = $0 in 2019 dollars
Balance of Plant Costs (BOPcost) = $2,559,326 in 2019 dollars
Total Capital Investment (TCI) = $5,321,176 in 2019 dollars
* Not applicable - This factor applies only to coal-fired boilers that burn bituminous coal and emits equal to or greater than 0.3lb/MMBtu of
sulfur dioxide.
SNCR Capital Costs (SNCRcost)
For Coal-Fired Utility Boilers:
SNCRcost = 220,000 x (BMW x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
SNCRcost = 147,000 x (BMW x HRF)0.42 x ELEVF x RF
For Coal-Fired Industrial Boilers:
SNCRcost = 220,000 x (0.1 x QB x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
SNCRcost = 147,000 x ((QB/NPHR)x HRF)0.42 x ELEVF x RF
SNCR Capital Costs (SNCRcost) = $1,533,886 in 2019 dollars
Air Pre-Heater Costs (APHcost)*
For Coal-Fired Utility Boilers:
APHcost = 69,000 x (BMW x HRF x CoalF)0.78 x AHF x RF
For Coal-Fired Industrial Boilers:
APHcost = 69,000 x (0.1 x QB x HRF x CoalF)0.78 x AHF x RF
Air Pre-Heater Costs (APHcost) = $0 in 2019 dollars
* Not applicable - This factor applies only to coal-fired boilers that burn bituminous coal and emit equal to or greater than 0.3lb/MMBtu of
sulfur dioxide.
Balance of Plant Costs (BOPcost)
For Coal-Fired Utility Boilers:
BOPcost = 320,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
BOPcost = 213,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x RF
For Coal-Fired Industrial Boilers:
BOPcost = 320,000 x (0.1 x QB)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
BOPcost = 213,000 x (QB/NPHR)0.33 x (NOxRemoved/hr)0.12 x RF
Balance of Plan Costs (BOPcost) = $2,559,326 in 2019 dollars
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Annual Costs
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
Direct Annual Costs (DAC) = $274,857 in 2019 dollars
Indirect Annual Costs (IDAC) = $586,631 in 2019 dollars
Total annual costs (TAC) = DAC + IDAC $861,488 in 2019 dollars
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Water Cost) + (Annual Fuel Cost) +
(Annual Ash Cost)
Annual Maintenance Cost = 0.015 x TCI = $79,818 in 2019 dollars
Annual Reagent Cost = qsol x Costreag x top = $192,202 in 2019 dollars
Annual Electricity Cost = P x Costelect x top = $1,318 in 2019 dollars
Annual Water Cost = qwater x Costwater x top = $0 in 2019 dollars
Additional Fuel Cost = ΔFuel x Costfuel x top = $1,520 in 2019 dollars
Additional Ash Cost = ΔAsh x Costash x top x (1/2000) = $0 in 2019 dollars
Direct Annual Cost = $274,857 in 2019 dollars
Indirect Annual Cost (IDAC)
IDAC = Administrative Charges + Capital Recovery Costs
Administrative Charges (AC) = 0.03 x Annual Maintenance Cost = $2,395 in 2019 dollars
Capital Recovery Costs (CR)= CRF x TCI = $584,237 in 2019 dollars
Indirect Annual Cost (IDAC) = AC + CR = $586,631 in 2019 dollars
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Total Annual Cost (TAC) = $861,488 per year in 2019 dollars
NOx Removed = 164.3 tons/year
Cost Effectiveness = $5,243 per ton of NOx removed in 2019 dollars
Salt River Project
SNCR Cost Analysis for the Agua Fria Generating Station Unit 3. RTP Environmental Associates, Inc.
May 2020
162

Appendix C
Salt River Project RTP Environmental Associates, Inc.
NOx RACT Analysis for the Agua Fria Generating Station Unit 1, 2, and 3 Boilers. July 2020
163

Data Inputs
Enter the following data for your combustion unit:
Is the combustion unit a utility or industrial boiler? What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
Please enter a retrofit factor between 0.8 and 1.5 based on the level of difficulty.
1.00
Enter 1 for projects of average retrofit difficulty.
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)? 114 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel? 1,030 Btu/scf Enter the sulfur content (%S) = percent by weight
*HHV value of 1030 Btu/scf is a default value. See below for data source. Enter actual HHV for fuel burned, if known.
What is the estimated actual annual MW output? 99,864 MWh/year
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV and %S. Please enter the
actual values for these parameters in the table below. If the actual value for any parameter is not
known, you may use the default values provided.
Enter the net plant heat input rate (NPHR) 10.99 MMBtu/MW
Fraction in Coal
Blend %S HHV (Btu/lb)
If the NPHR is not known, use the default NPHR value: Fuel Type Default NPHR Bituminous 0 2.35 11,814
Coal 10 MMBtu/MW Sub-Bituminous 0 0.31 8,730
Fuel Oil 11 MMBtu/MW Lignite 0 0.91 6,534
Natural Gas 8.2 MMBtu/MW
Please click the calculate button to calculate weighted
values based on the data in the table above.
Plant Elevation 1128 Feet above sea level
For coal-fired boilers, you may use either Method 1 or Method 2 to
calculate the catalyst replacement cost. The equations for both methods Method 1
are shown on rows 85 and 86 on the Cost Estimate tab. Please select your Method 2
preferred method: Not applicable
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Enter the following design parameters for the proposed SCR:
Number of days the SCR operates (tSCR) Number of SCR reactor chambers (nscr)
350 days 1
Number of days the boiler operates (tplant) Number of catalyst layers (Rlayer)
350 days 3
Inlet NOx Emissions (NOxin) to SCR Number of empty catalyst layers (Rempty) 1
0.25 lb/MMBtu
NOx Removal Efficiency (EF) provided by vendor 90 percent Ammonia Slip (Slip) provided by vendor 2 ppm
Volume of the catalyst layers (Volcatalyst)
Stoichiometric Ratio Factor (SRF)
1.050 (Enter "UNK" if value is not known) UNK Cubic feet
*The SRF value of 1.05 is a default value. User should enter actual value, if known. Flue gas flow rate (Qfluegas)
(Enter "UNK" if value is not known) UNK acfm
Estimated operating life of the catalyst (Hcatalyst)
24,000 hours
Gas temperature at the SCR inlet (T) 650 oF
Estimated SCR equipment life 15 Years*
* For utility boilers, the typical equipment life of an SCR is at least 30 years. Base case fuel gas volumetric flow rate factor
484 ft3/min-MMBtu/hour
(Qfuel)
Concentration of reagent as stored (Cstored) 29 percent*
*The reagent concentration of 29% and density of 56 lbs/cft are
Density of reagent as stored (ρstored) 56 lb/cubic feet* default values for ammonia reagent. User should enter actual values
for reagent, if different from the default values provided.
Number of days reagent is stored (tstorage) 14 days Densities of typical SCR reagents:
50% urea solution 71 lbs/ft3
29.4% aqueous NH3 56 lbs/ft3
19% aqueous NH3 58 lbs/ft3
Select the reagent used
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Enter the cost data for the proposed SCR:
Desired dollar-year 2019
CEPCI for 2019 592.1 Enter the CEPCI value for 201541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index
Annual Interest Rate (i) 7.0 Percent
* $3.56/gallon is a default value for the reagent cost. User should enter actual value, if
Reagent (Costreag) 3.56 $/gallon for a 29 percent solution of ammonia known.
* $0.0390/kWh is a default value for electicity cost. User should enter actual value, if
Electricity (Costelect) 0.0390 $/kWh* known.
$/cubic foot (includes removal and disposal/regeneration of
Catalyst cost (CC replace) 160.00 existing catalyst and installation of new catalyst* * $160/cf is a default value for the catalyst cost. User should enter actual value, if known.
* $60/hour is a default value for the operator labor rate. User should enter actual value, if
Operator Labor Rate 60.00 $/hour (including benefits)* known.
* 4 hours/day is a default value for the operator labor. User should enter actual value, if
Operator Hours/Day 4.00 hours/day* known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost
index to spreadsheet users. Use of other well-known cost indexes (e.g., M&S) is acceptable.
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) = 0.005
Administrative Charges Factor (ACF) = 0.03
Data Sources for Default Values Used in Calculations:
If you used your own site-specific values, please enter
Data Element Default Value Sources for Default Value the value used and the reference source . . .
Reagent Cost ($/gallon) 3.56 Based on the average of vendor quotes from 2011 - 2013.
Electricity Cost ($/kWh) 0.039 Average annual electricity cost for utilities is based on 2014 electricity
production cost data for fossil-fuel plants compiled by the U.S. Energy
Information (EIA). Available at
http://www.eia.gov/tools/faqs/faq.cfm?id=19&t=3.
Percent sulfur content for Coal (% weight) 2.35 Average sulfur content based on U.S. coal data for 2014 compiled by the U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-
923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Higher Heating Value (HHV) (Btu/lb) 1,030 2014 natural gas data compiled by the Office of Oil, Gas, and Coal Supply
Statistics, U.S. Energy Information Administration (EIA) from data reported on
EIA Form EIA-923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Catalyst Cost ($/cubic foot) 160 Cichanowicz, J.E. "Current Capital Cost and Cost-Effectiveness of Power Plant
Emissions Control Technologies", July 2013.
Salt River Project RTP Environmental Associates, Inc.
SCR Cost Analysis for the Agua Fria Generating Station Units 1 and 2. May 2020
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SCR Design Parameters
The following design parameters for the SCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate tab.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) = Bmw x NPHR = 1,253 MMBtu/hour
Maximum Annual MW Output (Bmw) = Bmw x 8760 = 998,640 MWh/year
Estimated Actual Annual MW Output (Boutput) = 99,864 MWh/year
Heat Rate Factor (HRF) = NPHR/10 = 1.10
Total System Capacity Factor (CFtotal) = (Boutput/Bmw)*(tscr/tplant) = 0.10 fraction
Total operating time for the SCR (top) = CFtotal x 8760 = 876 hours
NOx Removal Efficiency (EF) = (NOxin- NOxout)/NOxin = 90.0 percent
NOx removed per hour = NOxin x EF x QB = 281.89 lb/hour
Total NOx removed per year = (NOxin x EF x QB x top)/2000 = 123.47 tons/year
NOx removal factor (NRF) = EF/80 1.13
Volumetric flue gas flow rate (qflue gas) = Qfuel x QB x (460 + T)/(460 + 700)nscr 580,247 acfm
Space velocity (Vspace) = qflue gas/Volcatalyst 110.38 /hour
Residence Time 1/Vspace 0.01 hour
1 for oil and natural gas; 1 for bituminous; 1.05 for
Coal Factor (CoalF) = sub-bituminous; 1.07 for lignite (weighted average is 1.00
used for coal blends)
SO2 Emission rate = (%S/100)x(64/32)*1E6)/HHV = Not applicable; factor applies only to
coal-fired boilers
Elevation Factor (ELEVF) = 14.7 psia/P = 1.04
Atmospheric pressure at sea level (P) = 2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)* 14.1 psia
=
Retrofit Factor (RF) Retrofit to existing boiler 1.00
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Catalyst Data:
Parameter Equation Calculated Value Units
Future worth factor (FWF) = (interest rate)(1/((1+ interest rate)Y -1) , where Y =
Hcatalyts/(tSCR x 24 hours) rounded to the nearest integer 0.311 Fraction
Catalyst volume (Volcatalyst) =
2.81 x QB x EF adj x Slipadj x Noxadj x Sadj x (Tadj/Nscr) 5,256.72 Cubic feet
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Cross sectional area of the catalyst (Acatalyst) = qflue gas /(16ft/sec x 60 sec/min) 604 ft2
Height of each catalyst layer (Hlayer) = (Volcatalyst/(Rlayer x Acatalyst)) + 1 4 feet
SCR Reactor Data:
Parameter Equation Calculated Value Units
Cross sectional area of the reactor (ASCR) = 1.15 x Acatalyst 695 ft2
Reactor length and width dimentions for a square
(ASCR)0.5 26.4 feet
reactor =
Reactor height = (Rlayer + Rempty) x (7ft + hlayer) + 9ft 53 feet
Reagent Data:
Type of reagent used Ammonia Molecular Weight of Reagent (MW) = 17.03 g/mole
Density = 56 lb/ft3
Parameter Equation Calculated Value Units
Reagent consumption rate (mreagent) = (NOxin x QB x EF x SFR x MWR)/MWNOx = 110 lb/hour
Reagent Usage Rate (msol) = mreagent/Csol = 378 lb/hour
(msol x 7.4805)/Reagent Density 50 gal/hour
Estimated tank volume for reagent storage = (msol x 7.4805 x tstorage x 24)/Reagent Density = 16,956 gallons (storage needed to store a 14 day reagent supply)
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) = i (1+ i)n/(1+ i)n - 1 = 0.1098
Where n = Equipment Life and i= Interest Rate
Other parameters Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) = A x 1,000 x 0.0056 x (CoalF x HRF)0.43 = 664.85 kW
where A = Bmw for utility boilers
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Cost Estimate
Total Capital Investment (TCI)
TCI for Oil and Natural Gas Boilers
For Oil and Natural Gas-Fired Utility Boilers between 25MW and 500 MW:
TCI = 80,000 x (200/BMW )0.35 x BMW x ELEVF x RF
For Oil and Natural Gas-Fired Utility Boilers >500 MW:
TCI = 60,670 x BMW x ELEVF x RF
For Oil-Fired Industrial Boilers between 275 and 5,500 MMBTU/hour :
TCI = 7,270 x (2,200/QB )0.35 x QB x ELEVF x RF
For Natural Gas-Fired Industrial Boilers between 205 and 4,100 MMBTU/hour :
TCI = 9,760 x (1,640/QB )0.35 x QB x ELEVF x RF
For Oil-Fired Industrial Boilers >5,500 MMBtu/hour:
TCI = 5,275 x QB x ELEVF x RF
For Natural Gas-Fired Industrial Boilers >4,100 MMBtu/hour:
TCI = 7,082 x QB x ELEVF x RF
Total Capital Investment (TCI) = $12,633,961 in 2019 dollars
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Annual Costs
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
Direct Annual Costs (DAC) = $330,465 in 2019 dollars
Indirect Annual Costs (IDAC) = $1,390,419 in 2019 dollars
Total annual costs (TAC) = DAC + IDAC $1,720,884 in 2019 dollars
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Catalyst Cost)
Annual Maintenance Cost = 0.005 x TCI = $63,170 in 2019 dollars
Annual Reagent Cost = qsol x Costreag x top = $157,375 in 2019 dollars
Annual Electricity Cost = P x Costelect x top = $22,714 in 2019 dollars
Annual Catalyst Replacement Cost = $87,206 in 2019 dollars
nscr x Volcat x (CCreplace/Rlayer) x FWF
Direct Annual Cost = $330,465 in 2019 dollars
Indirect Annual Cost (IDAC)
IDAC = Administrative Charges + Capital Recovery Costs
Administrative Charges (AC) = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost) = $3,278 in 2019 dollars
Capital Recovery Costs (CR)= CRF x TCI = $1,387,141 in 2019 dollars
Indirect Annual Cost (IDAC) = AC + CR = $1,390,419 in 2019 dollars
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Total Annual Cost (TAC) = $1,720,884 per year in 2019 dollars
NOx Removed = 123.5 tons/year
Cost Effectiveness = $13,938 per ton of NOx removed in 2019 dollars
Salt River Project RTP Environmental Associates, Inc.
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Data Inputs
Enter the following data for your combustion unit:
Is the combustion unit a utility or industrial boiler? What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
Please enter a retrofit factor between 0.8 and 1.5 based on the level of difficulty.
1.00
Enter 1 for projects of average retrofit difficulty.
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)? 163 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel? 1,030 Btu/scf Enter the sulfur content (%S) = percent by weight
*HHV value of 1030 Btu/scf is a default value. See below for data source. Enter actual HHV for fuel burned, if known.
What is the estimated actual annual MW output? 142,788 MW/year
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV and %S. Please enter the
actual values for these parameters in the table below. If the actual value for any parameter is not
known, you may use the default values provided.
Enter the net plant heat input rate (NPHR) 12 MMBtu/MW
Fraction in Coal
Blend %S HHV (Btu/lb)
If the NPHR is not known, use the default NPHR value: Fuel Type Default NPHR Bituminous 0 2.35 11,814
Coal 10 MMBtu/MW Sub-Bituminous 0 0.31 8,730
Fuel Oil 11 MMBtu/MW Lignite 0 0.91 6,534
Natural Gas 8.2 MMBtu/MW
Please click the calculate button to calculate weighted
values based on the data in the table above.
Plant Elevation 1128 Feet above sea level
For coal-fired boilers, you may use either Method 1 or Method 2 to
calculate the catalyst replacement cost. The equations for both methods Method 1
are shown on rows 85 and 86 on the Cost Estimate tab. Please select your Method 2
preferred method: Not applicable
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Enter the following design parameters for the proposed SCR:
Number of days the SCR operates (tSCR) Number of SCR reactor chambers (nscr)
350 days 1
Number of days the boiler operates (tplant) Number of catalyst layers (Rlayer)
350 days 3
Inlet NOx Emissions (NOxin) to SCR Number of empty catalyst layers (Rempty) 1
0.5 lb/MMBtu
NOx Removal Efficiency (EF) provided by vendor 90 percent Ammonia Slip (Slip) provided by vendor 2 ppm
Volume of the catalyst layers (Volcatalyst)
Stoichiometric Ratio Factor (SRF)
1.050 (Enter "UNK" if value is not known) UNK Cubic feet
*The SRF value of 1.05 is a default value. User should enter actual value, if known. Flue gas flow rate (Qfluegas)
(Enter "UNK" if value is not known) UNK acfm
Estimated operating life of the catalyst (Hcatalyst)
24,000 hours
Gas temperature at the SCR inlet (T) 650 oF
Estimated SCR equipment life 15 Years*
* For utility boilers, the typical equipment life of an SCR is at least 30 years. Base case fuel gas volumetric flow rate factor
484 ft3/min-MMBtu/hour
(Qfuel)
Concentration of reagent as stored (Cstored) 29 percent*
*The reagent concentration of 29% and density of 56 lbs/cft are
Density of reagent as stored (ρstored) 56 lb/cubic feet* default values for ammonia reagent. User should enter actual values
for reagent, if different from the default values provided.
Number of days reagent is stored (tstorage) 14 days Densities of typical SCR reagents:
50% urea solution 71 lbs/ft3
29.4% aqueous NH3 56 lbs/ft3
19% aqueous NH3 58 lbs/ft3
Select the reagent used
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Enter the cost data for the proposed SCR:
Desired dollar-year 2019
CEPCI for 2019 592.1 Enter the CEPCI value for 201541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index
Annual Interest Rate (i) 7.0 Percent
* $3.56/gallon is a default value for the reagent cost. User should enter actual value, if
Reagent (Costreag) 3.56 $/gallon for a 29 percent solution of ammonia known.
* $0.0390/kWh is a default value for electicity cost. User should enter actual value, if
Electricity (Costelect) 0.0390 $/kWh* known.
$/cubic foot (includes removal and disposal/regeneration of
Catalyst cost (CC replace) 160.00 existing catalyst and installation of new catalyst* * $160/cf is a default value for the catalyst cost. User should enter actual value, if known.
* $60/hour is a default value for the operator labor rate. User should enter actual value, if
Operator Labor Rate 60.00 $/hour (including benefits)* known.
* 4 hours/day is a default value for the operator labor. User should enter actual value, if
Operator Hours/Day 4.00 hours/day* known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost
index to spreadsheet users. Use of other well-known cost indexes (e.g., M&S) is acceptable.
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) = 0.005
Administrative Charges Factor (ACF) = 0.03
Data Sources for Default Values Used in Calculations:
If you used your own site-specific values, please enter
Data Element Default Value Sources for Default Value the value used and the reference source . . .
Reagent Cost ($/gallon) 3.56 Based on the average of vendor quotes from 2011 - 2013.
Electricity Cost ($/kWh) 0.039 Average annual electricity cost for utilities is based on 2014 electricity
production cost data for fossil-fuel plants compiled by the U.S. Energy
Information (EIA). Available at
http://www.eia.gov/tools/faqs/faq.cfm?id=19&t=3.
Percent sulfur content for Coal (% weight) 2.35 Average sulfur content based on U.S. coal data for 2014 compiled by the U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-
923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Higher Heating Value (HHV) (Btu/lb) 1,030 2014 natural gas data compiled by the Office of Oil, Gas, and Coal Supply
Statistics, U.S. Energy Information Administration (EIA) from data reported on
EIA Form EIA-923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Catalyst Cost ($/cubic foot) 160 Cichanowicz, J.E. "Current Capital Cost and Cost-Effectiveness of Power Plant
Emissions Control Technologies", July 2013.
Salt River Project RTP Environmental Associates, Inc.
SCR Cost Analysis for the Agua Fria Generating Station Unit 3. May 2020
173

SCR Design Parameters
The following design parameters for the SCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate tab.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) = Bmw x NPHR = 1,956 MMBtu/hour
Maximum Annual MW Output (Bmw) = Bmw x 8760 = 1,427,880 MW/year
Estimated Actual Annual MW Output (Boutput) = 142,788 MW/year
Heat Rate Factor (HRF) = NPHR/10 = 1.20
Total System Capacity Factor (CFtotal) = (Boutput/Bmw)*(tscr/tplant) = 0.10 fraction
Total operating time for the SCR (top) = CFtotal x 8760 = 876 hours
NOx Removal Efficiency (EF) = (NOxin- NOxout)/NOxin = 90.0 percent
NOx removed per hour = NOxin x EF x QB = 880.20 lb/hour
Total NOx removed per year = (NOxin x EF x QB x top)/2000 = 385.53 tons/year
NOx removal factor (NRF) = EF/80 1.13
Volumetric flue gas flow rate (qflue gas) = Qfuel x QB x (460 + T)/(460 + 700)nscr 905,898 acfm
Space velocity (Vspace) = qflue gas/Volcatalyst 101.64 /hour
Residence Time 1/Vspace 0.01 hour
1 for oil and natural gas; 1 for bituminous; 1.05 for
Coal Factor (CoalF) = sub-bituminous; 1.07 for lignite (weighted average is 1.00
used for coal blends)
SO2 Emission rate = (%S/100)x(64/32)*1E6)/HHV = Not applicable; factor applies only to
coal-fired boilers
Elevation Factor (ELEVF) = 14.7 psia/P = 1.04
Atmospheric pressure at sea level (P) = 2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)* 14.1 psia
=
Retrofit Factor (RF) Retrofit to existing boiler 1.00
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Catalyst Data:
Parameter Equation Calculated Value Units
Future worth factor (FWF) = (interest rate)(1/((1+ interest rate)Y -1) , where Y =
Hcatalyts/(tSCR x 24 hours) rounded to the nearest integer 0.311 Fraction
Catalyst volume (Volcatalyst) =
2.81 x QB x EF adj x Slipadj x Noxadj x Sadj x (Tadj/Nscr) 8,912.71 Cubic feet
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Cross sectional area of the catalyst (Acatalyst) = qflue gas /(16ft/sec x 60 sec/min) 944 ft2
Height of each catalyst layer (Hlayer) = (Volcatalyst/(Rlayer x Acatalyst)) + 1 4 feet
SCR Reactor Data:
Parameter Equation Calculated Value Units
Cross sectional area of the reactor (ASCR) = 1.15 x Acatalyst 1,085 ft2
Reactor length and width dimentions for a square
(ASCR)0.5 32.9 feet
reactor =
Reactor height = (Rlayer + Rempty) x (7ft + hlayer) + 9ft 54 feet
Reagent Data:
Type of reagent used Ammonia Molecular Weight of Reagent (MW) = 17.03 g/mole
Density = 56 lb/ft3
Parameter Equation Calculated Value Units
Reagent consumption rate (mreagent) = (NOxin x QB x EF x SFR x MWR)/MWNOx = 342 lb/hour
Reagent Usage Rate (msol) = mreagent/Csol = 1,180 lb/hour
(msol x 7.4805)/Reagent Density 158 gal/hour
Estimated tank volume for reagent storage = (msol x 7.4805 x tstorage x 24)/Reagent Density = 52,944 gallons (storage needed to store a 14 day reagent supply)
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) = i (1+ i)n/(1+ i)n - 1 = 0.1098
Where n = Equipment Life and i= Interest Rate
Other parameters Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) = A x 1,000 x 0.0056 x (CoalF x HRF)0.43 = 987.24 kW
where A = Bmw for utility boilers
Salt River Project RTP Environmental Associates, Inc.
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Cost Estimate
Total Capital Investment (TCI)
TCI for Oil and Natural Gas Boilers
For Oil and Natural Gas-Fired Utility Boilers between 25MW and 500 MW:
TCI = 80,000 x (200/BMW )0.35 x BMW x ELEVF x RF
For Oil and Natural Gas-Fired Utility Boilers >500 MW:
TCI = 60,670 x BMW x ELEVF x RF
For Oil-Fired Industrial Boilers between 275 and 5,500 MMBTU/hour :
TCI = 7,270 x (2,200/QB )0.35 x QB x ELEVF x RF
For Natural Gas-Fired Industrial Boilers between 205 and 4,100 MMBTU/hour :
TCI = 9,760 x (1,640/QB )0.35 x QB x ELEVF x RF
For Oil-Fired Industrial Boilers >5,500 MMBtu/hour:
TCI = 5,275 x QB x ELEVF x RF
For Natural Gas-Fired Industrial Boilers >4,100 MMBtu/hour:
TCI = 7,082 x QB x ELEVF x RF
Total Capital Investment (TCI) = $15,939,450 in 2019 dollars
Salt River Project RTP Environmental Associates, Inc.
SCR Cost Analysis for the Agua Fria Generating Station Unit 3. May 2020
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Annual Costs
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
Direct Annual Costs (DAC) = $752,678 in 2019 dollars
Indirect Annual Costs (IDAC) = $1,753,542 in 2019 dollars
Total annual costs (TAC) = DAC + IDAC $2,506,221 in 2019 dollars
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Catalyst Cost)
Annual Maintenance Cost = 0.005 x TCI = $79,697 in 2019 dollars
Annual Reagent Cost = qsol x Costreag x top = $491,396 in 2019 dollars
Annual Electricity Cost = P x Costelect x top = $33,728 in 2019 dollars
Annual Catalyst Replacement Cost = $147,857 in 2019 dollars
nscr x Volcat x (CCreplace/Rlayer) x FWF
Direct Annual Cost = $752,678 in 2019 dollars
Indirect Annual Cost (IDAC)
IDAC = Administrative Charges + Capital Recovery Costs
Administrative Charges (AC) = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost) = $3,476 in 2019 dollars
Capital Recovery Costs (CR)= CRF x TCI = $1,750,066 in 2019 dollars
Indirect Annual Cost (IDAC) = AC + CR = $1,753,542 in 2019 dollars
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Total Annual Cost (TAC) = $2,506,221 per year in 2019 dollars
NOx Removed = 385.5 tons/year
Cost Effectiveness = $6,501 per ton of NOx removed in 2019 dollars
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Exhibit B
178

Reasonably Available Control Technology
(RACT) Analysis.
RACT Analysis for the control of nitrogen oxides (NOx) emissions from
simple-cycle simple cycle combustion turbine generators at the Salt River
Project Agua Fria and Kyrene Generating Stations.
July 2020
Prepared for:
Salt River Project
1500 N. Mill Avenue
Tempe, AZ 85281
www.srpnet.com
Prepared By:
RTP ENVIRONMENTAL ASSOCIATES INC.
304-A West Millbrook Rd.
Raleigh, NC 27609
179

Table of Contents
1.0 Introduction. ........................................................................................................ 2
2.0 Reasonably Available Control Technology. ..................................................... 3
2.1 RACT Evaluation. ........................................................................................................................ 3
2.2 Calculation of Cost Effectiveness. ................................................................................................ 4
2.3 Capital Recovery Costs. ............................................................................................................... 4
2.4 Fuel Costs. .................................................................................................................................... 5
2.5 Demineralized Water Costs. ......................................................................................................... 5
2.6 RACT Cost Effectiveness Threshold. ........................................................................................... 6
2.7 Conclusion and Proposed RACT Determination. ......................................................................... 8
3.0 NOx Emissions from Combustion Sources. ..................................................... 9
3.1 Thermal NOx. ................................................................................................................................ 9
3.2 Fuel NOx. ...................................................................................................................................... 9
3.3 Prompt NOx. ................................................................................................................................. 9
4.0 Available NOx Control Technologies. ............................................................. 10
4.1 Diffusion Flame Combustion. .................................................................................................... 10
4.2 Water and Steam Injection.......................................................................................................... 10
4.3 Dry Low NOx (DLN) Combustion. ............................................................................................ 11
4.4 Catalytic Combustion. ................................................................................................................ 11
4.5 Selective Catalytic Reduction (SCR). ......................................................................................... 11
4.6 Selective Non-Catalytic Reduction (SNCR)............................................................................... 12
4.7 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™). .............................................. 12
5.0 Agua Fria Simple Cycle CTG Units 4, 5, and 6. .............................................. 15
5.1 Technically Feasible Control Technologies. .............................................................................. 15
5.2 Water Injection. .......................................................................................................................... 15
5.3 Steam Injection. .......................................................................................................................... 18
5.4 DLN Combustion. ...................................................................................................................... 20
5.5 Selective Catalytic Reduction (SCR). ......................................................................................... 21
5.6 Conclusions. ............................................................................................................................... 23
6.0 Kyrene Simple Cycle CTG Unit 4. .................................................................... 24
6.1 Technically Feasible Control Technologies. .............................................................................. 24
6.2 Water Injection. .......................................................................................................................... 24
6.3 Steam Injection. .......................................................................................................................... 26
6.4 Selective Catalytic Reduction (SCR). ......................................................................................... 28
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6.5 Conclusions. ............................................................................................................................... 29
7.0 Kyrene Simple Cycle CTG Units 5 and 6. ....................................................... 30
7.1 Technically Feasible Control Technologies. .............................................................................. 30
7.2 Water Injection. .......................................................................................................................... 30
7.3 Steam Injection. .......................................................................................................................... 32
7.4 DLN Combustion. ...................................................................................................................... 34
7.5 Selective Catalytic Reduction (SCR). ......................................................................................... 35
7.6 Conclusions. ............................................................................................................................... 36
Tables
TABLE ES-1. Cost effectiveness of the NOx control options for the simple cycle CTGs at the Agua Fria
and Kyrene Generating Stations. .......................................................................................................... 1
TABLE 5-1. Water injection system capital costs for a Westinghouse Model 501-AA CTG and the capital
costs for the Agua Fria Units 4, 5, and 6. ........................................................................................... 16
TABLE 5-2. Annual costs and cost effectiveness for a water injection system for each Westinghouse
Model 501B simple cycle CTG. ......................................................................................................... 17
TABLE 5-3. Steam injection system capital costs for each Westinghouse Model 501B CTG. ............ 18
TABLE 5-4. Annual costs and cost effectiveness for a steam injection system for each Westinghouse
Model 501B simple cycle CTG. ......................................................................................................... 19
TABLE 5-5. Capital costs, annual costs, and cost effectiveness for an SCR system for each Agua Fria
Westinghouse Model 501B simple cycle CTG based on a 10% capacity factor. .............................. 21
TABLE 5-6. NOx control options, emission reductions, and cost effectiveness for each Agua Fria
Westinghouse Model 501B simple cycle CTG based on a 10% capacity factor. .............................. 23
TABLE 6-1. Annual costs and cost effectiveness for a water injection system for the Kyrene Unit 4
Westinghouse Model 501A simple cycle CTG. ................................................................................. 25
TABLE 6-2. Steam injection system capital costs for the Westinghouse Model 501A CTG. .............. 26
TABLE 6-3. Annual costs and cost effectiveness for a steam injection system for the Kyrene Unit 4
Westinghouse Model 501A simple cycle CTG. ................................................................................. 27
TABLE 6-4. Capital costs, annual costs, and cost effectiveness for an SCR system for the Kyrene Unit 4
Westinghouse Model 501A simple cycle CTG based on a 10% capacity factor. .............................. 28
TABLE 6-5. NOx control options, emission reductions, and cost effectiveness for the Kyrene Unit 4
Westinghouse Model 501A simple cycle CTG based on a 10% capacity factor. .............................. 29
TABLE 7-1. Annual costs and cost effectiveness for a water injection system for each General Electric
Model 7B simple cycle CTG. ............................................................................................................. 31
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TABLE 7-2. Steam injection system capital costs for each GE Model 7B CTG. .................................. 32
TABLE 7-3. Annual costs and cost effectiveness for a steam injection system for each GE Model 7B
simple cycle CTG. .............................................................................................................................. 33
TABLE 7-4. Capital costs, annual costs, and cost effectiveness for an SCR system for each Kyrene Unit 5
and 6 simple cycle CTG based on a 10% capacity factor. ................................................................. 35
TABLE 7-5. NOx control options, emission reductions, and cost effectiveness for each Kyrene Unit 5 and
6 simple cycle CTG based on a 10% capacity factor. ........................................................................ 36
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Executive Summary.
Salt River Project’s (SRP) Agua Fria and Kyrene Generating Stations are located in the portion of Maricopa
County which is classified as a moderate nonattainment area for ozone (O3). Maricopa County Air Pollution
Control Regulations (MCAPCR) Rule 322 requires the use of Reasonably Available Control Technology
(RACT) for the control of nitrogen oxides (NOx) emissions from power plants in the county.
For each simple cycle combustion turbine generators (CTG), Rule 322 currently prescribes a presumptive
NOx RACT emission limit of 42 parts per million by volume, dry basis (ppmdv) (calculated as nitrogen
dioxide) corrected to 15% oxygen when burning gaseous fuel, and 65 ppmdv when burning liquid fossil
fuel. For any unit with a calendar year annual capacity factor equal to or less than 10 percent, NOx RACT
requires only work practices; such units are not subject to numeric emission standards.
This report presents a NOx RACT analysis for six simple cycle CTGs: Units 4, 5, 6 at the Agua Fria
Generating Station and Units 4, 5, 6 at the Kyrene Generating Station. Each of these units has a calendar
year annual capacity factor equal to or less than 10 percent.
The U.S. Environmental Protection Agency has defined RACT as “the lowest emission limitation that a
particular source is capable of meeting by the application of control technology that is reasonably available
considering technological and economic feasibility.” The U.S. EPA’s most current guidance on NOx RACT
cost effectiveness indicates an economically reasonable range up to $2,300 per ton of NOx removed,
expressed in 2020 dollars.
Table ES-1 is a summary of the cost effectiveness of the NOx control options for the six affected simple
cycle CTGs based on a conservatively assumed annual capacity factor of 10 percent. The costs in Table
ES-1 are substantially higher than the cost effectiveness threshold of $2,300 per ton of NOx removed.
Accordingly, SRP proposes that Maricopa County Air Quality Department (MCAQD) reaffirm that NOx
RACT for simple cycle CTGs with a calendar year annual capacity factor equal to or less than 10 percent
is the use of diffusion flame combustion and good combustion practices with no numeric emission
standards.
TABLE ES-1. Cost effectiveness of the NOx control options for the simple cycle CTGs at the
Agua Fria and Kyrene Generating Stations.
Cost Effectiveness, $(2020) per ton of NOx controlled
NOx Control
Option Agua Fria Kyrene Kyrene
Units 4, 5, 6 Unit 4 Units 5, 6
Water Injection $3,600 $3,450 $3,770
Steam Injection $3,700 $3,820 $3,870
Advanced DLN Combustion $4,880 Not Technically $3,310
Feasible
Selective Catalytic Reduction (SCR) $6,540 $6,440 $6,530
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1.0 Introduction.
This document is a Reasonably Available Control Technology (RACT) Analysis for the control of nitrogen
oxides (NOx) emissions from simple cycle combustion turbine generators (CTGs) at the Agua Fria and
Kyrene Generating Stations. These generating stations are located in the portion of Maricopa County which
is classified as a moderate nonattainment area under the 2008 ozone National Ambient Air Quality Standard
(NAAQS).1 As part of the moderate classification, Maricopa County Air Quality Department (MCAQD)
Maricopa County Air Pollution Control Regulations (MCAPCR) Rule 322 requires RACT level of control
for oxides of nitrogen (NOx) emissions from power plant operations in the county. Agua Fria and Kyrene
Generating Stations have specifically identified emissions units in Rule 322 which are subject to RACT
requirements.
The units evaluated in this RACT analysis are Agua Fria Units 4, 5, 6 and Kyrene Units 4, 5, and 6.
Chapter 2 of this analysis includes a discussion of RACT, including a discussion of cost effectiveness
thresholds.
Chapter 3 includes a general discussion of NOx emissions from combustion sources, including the reaction
mechanisms responsible for NOx formation.
Chapter 4 includes an evaluation of available NOx control technologies for CTGs. The available controls
are then reviewed to determine controls which are technically feasible control options. The technical
feasibility of controls is further evaluated for each specific unit.
Chapters 5 through 7 include detailed RACT analyses for each specific type of simple cycle CTG at the
Agua Fria and Kyrene Generating Stations.
1 40 CFR § 81.303. See also 86 Fed. Reg. 26697 (May 4, 2016).
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2.0 Reasonably Available Control Technology.
The Code of Federal Regulations, 40 CFR § 51.908 et seq. specifies the attainment demonstration
requirements pursuant to section 182 of the Clean Air Act (CAA) for areas classified as moderate, serious,
severe, or extreme nonattainment areas. One of the requirements specified in 40 CFR § 51.912 is a RACT
state implementation plan (SIP) submission implementing CAA § 182(b)(2) and (f).
Reasonably available control technology is defined in 40 CFR § 51.100(o) as follows:
(o) Reasonably available control technology (RACT) means devices, systems, process modifications,
or other apparatus or techniques that are reasonably available taking into account:
(1) The necessity of imposing such controls in order to attain and maintain a national ambient air
quality standard;
(2) The social, environmental, and economic impact of such controls; and
(3) Alternative means of providing for attainment and maintenance of such standard. (This
provision defines RACT for the purposes of §51.341(b) only.)
This NOx RACT analysis report for the simple cycle CTGs at Agua Fria and Kyrene Generating Stations
has been prepared in order to assist MCAQD in satisfying its obligations relating to a NOx RACT SIP
submission. The report focuses on the environmental and economic impact of potentially available NOx
controls for the simple cycle CTGs at Agua Fria and Kyrene Generating Stations.
2.1 RACT Evaluation.
U.S. Environmental Protection Agency (U.S. EPA) has stated, “RACT for a particular source is determined
on a case-by-case basis, considering the technological and economic circumstances of the individual
source.”2
For purposes of this NOx RACT analysis report for the simple cycle CTGs at Agua Fria and Kyrene
Generating Stations, we have generally followed the approach recommended in applicable U.S. EPA
guidance.3,4 This guidance – particularly the Alternative Control Techniques Document – NOx Emissions
from Stationary Gas Turbines (“Gas Turbine ACT Document”) – provides useful information but does not
prescribe a methodological approach and does not establish presumptive RACT either for a category of
sources or for any individual source.5 In addition to the Gas Turbine ACT Document, we used vendor
2 44 Fed. Reg. 53761 at p. 53762 (Sept. 17, 1979).
3 See, for example, U.S. EPA, Alternative Control Techniques Document – NOx Emissions from Stationary Gas
Turbines, EPA-453/R-93-007 (Jan. 1993).
4 The cost estimating approach generally recommended by U.S. EPA for RACT and other purposes is set forth in a
series of control cost manuals. The most up-to-date, complete edition of this guidance document is EPA Air Pollution
Control Cost Manual, Sixth Edition (EPA/452/B-02-001) (Jan. 2002) (“Control Cost Manual”).
5 See, for example, 57 Fed. Reg. 55620 at p. 55625 (Nov. 25, 1992) (“Similar to the CTGs issued for VOC source
categories, the ACTs will contain extensive background information on control technologies, costs, availability. etc.,
that can be used by States in making RACT determinations. However, unlike the CTGs, the ACTs will not established
[sic] a presumptive RACT.”)
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information, vendor budgetary quotes, unit performance, other U.S. EPA information, and other technical
sources as discussed in subsequent sections of this report. Historical cost information is adjusted to present
2020 costs using the consumer price index (CPI) published by Bureau of Labor Statistics.
The NOx RACT analysis presented in this report is based on the evaluation of the following criteria for each
emissions unit or for each specific type of emissions unit:
1. A review of available and technically achievable control technologies and the
achievable emissions reduction.
2. The cost effectiveness of the control option expressed in dollars per ton of emission
reduction ($/ton).
3. If applicable, other potential social and environmental impacts of the control option.
2.2 Calculation of Cost Effectiveness.
The RACT evaluation includes an evaluation of environmental, energy, and economic impacts. The most
important issue in a RACT analysis is typically the economic reasonableness of the control option. This
parameter is typically evaluated according to the cost effectiveness of the control option, expressed in
dollars per ton of pollutant reduced. Both average and incremental cost effectiveness may be calculated;
however, for the NOx RACT analysis for the simple cycle CTGs at Agua Fria and Kyrene Generating
Stations, only average cost effectiveness is necessary. This parameter represents the overall effect of a
particular control technique relative to a baseline condition and is calculated as follows, using the total
annualized cost of the control option under review:
Average Cost Effectiveness Control option annualized cost
=
($ per ton removed) Baseline emission rate – Control option emissions rate
2.3 Capital Recovery Costs.
Under applicable U.S. EPA guidance, including the Gas Turbine ACT Document, the total annualized cost
of a control option includes the annual cost required to recover the capital investment associated with that
control option. This value is calculated using a Capital Recovery Factor (CRF), which is the ratio of a
constant annual payment or annuity to the present value of receiving that annuity for a given length of time.6
For an interest rate i and n years for the project, the CRF is:
𝑖𝑖(1 + 𝑖𝑖)𝑛𝑛
𝐶𝐶𝐶𝐶𝐶𝐶=
[(1 + 𝑖𝑖)𝑛𝑛−1]
Where, i = Interest rate or cost of capital, fraction
6 See, for example, Gas Turbine ACT Document at p. 2-28 (“Capital costs were annualized using the capital recovery
factor method with an equipment life of 15 years and an annual interest rate of 10 percent.”)
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n = Equipment or Project life, years
In this RACT analysis, the interest rate i is 7.0%, consistent with MCAQD guidance.7
The project life for all pollution control technology alternatives evaluated in this RACT analysis has been
based on an equipment life of 15 years. This equipment life was used for evaluating control technology
costs in the Gas Turbine ACT Document:
The life of the control equipment depends upon many factors, including application,
operating environment, maintenance practices, and materials of construction. For this study, a 15-
year life was chosen.8
This project life in the ACT was used for evaluating water and steam injection, low-NOx combustion, and
selective catalytic reduction control systems.
Substituting the interest rate of 7.0% and project life of 15 years into the above equation, the CRF value is:
𝑖𝑖 (1 + 𝑖𝑖 )𝑛𝑛 0.07(1 + 0.07)15
𝐶𝐶𝐶𝐶𝐶𝐶= = = 0.10979
[ (1 + 𝑖𝑖 )𝑛𝑛−1] [ (1 + 0.07 )15 −1]
The annual cost for the capital investment is then calculated as the product of the CRF and the Total Capital
Cost (TCC):
Annual Capital = CRF × TCC
Recovery Cost
2.4 Fuel Costs.
Some NOx control systems may have an efficiency penalty. That is, the technology may reduce the
efficiency of the CTG. To evaluate efficiency impacts, a uniform natural gas cost of $3.00 per million Btu
has been used in this RACT analysis. This value is representative of the long-term average costs of natural
gas delivered to the affected generating stations.
2.5 Demineralized Water Costs.
Demineralized water costs for pollution control systems like water injection have been estimated using the
methods described in How to Estimate Utility Costs, G. D. Ulrich and T.T. Vasudevan, University of New
7 MCAQD, Requirements, Procedures and Guidance in Selecting BACT and RACT (revised Jan. 2019). This rate is
conservative; the rate suggested in the Gas Turbine ACT Document is 10%.
8 Gas Turbine ACT Document at p. 6-206.
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Hampshire, published in Chemical Engineering, pages 66 – 69, April 2006. Utility costs are given by the
following equation:
𝐶𝐶𝑆𝑆,𝑢𝑢 = 𝑎𝑎 (𝐶𝐶𝐶𝐶 PCI) + 𝑏𝑏൫𝐶𝐶𝑆𝑆,𝑓𝑓൯
Where, CS,u = Price of the Utility
a, b = Utility Coefficients
CE PCI = Chemical Engineering Plant Cost Index
CS,f = Price of Fuel, $/GJ
For demineralized (boiler feed) water costs in $ per cubic meter ($/m3), the coefficients a and b are given
in Table 1 of How to Estimate Utility Costs as:
𝑏𝑏 = 0.04
𝑎𝑎 = 0.005 + 0.0002𝑞𝑞−0.6
q = Demineralizer water capacity, cubic meters per second
For a demineralized water flowrate of 100 gallons per minute (0.0063 m3/sec), the coefficient a is 0.00918.
The December 2019 Chemical Engineering Plant Cost Index is 592.1. For natural gas, the price of fuel,
CS,f , is $3.0/GJ ($3.00/MMBtu). Therefore, the utility cost for demineralized water is:
𝐶𝐶𝑆𝑆,𝐷𝐷𝐷𝐷 = 𝑎𝑎(𝐶𝐶𝐶𝐶 PCI) + 𝑏𝑏൫𝐶𝐶𝑆𝑆,𝑓𝑓൯= 0.00918(592.1) + 0.04(3.0) = 5.42 + 0.12 = $5.555/𝑚𝑚3
For 264.17 gallons per cubic meter, this demineralized water cost is equal to $0.02103 per gallon of
demineralized water produced. This cost is used for all cost evaluations in this RACT analysis.
2.6 RACT Cost Effectiveness Threshold.
The most current U.S. EPA guidance available regarding cost effectiveness thresholds for NOx RACT
determinations is a 1994 memorandum, Cost-Effective Nitrogen Oxides (NOx) Reasonably Available
Control Technology (RACT). According to this guidance, the high end of the range for cost effective RACT
control options is $1,300 per ton of pollutant controlled.9 The U.S. EPA reaffirmed the relevancy of this
guidance in its final rule to implement the 8-hour ozone NAAQS in 2005.10 Specifically, in the Federal
Register notice for this final rule, U.S. EPA rejected comments suggesting RACT requirements should be
more stringent, characterizing the $1,300 per ton threshold as “our current guidance.”11
9 U.S. EPA, Cost-Effective Nitrogen Oxides (NOx) Reasonably Available Control Technology (RACT), memorandum
from D. Kent Berry, Acting Director Air Quality Management Division (MD-15) (March 16, 1994).
10 70 Fed. Reg. 71612 (Nov. 29, 2005).
11 Ibid at p. 71654.
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Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 1994 has the same buying power as $1.75 in March 2020. Therefore, U.S.
EPA’s NOx RACT cost effectiveness threshold of $1,300 per ton in 1994 is equal to $2,300 in 2020.
The cost effectiveness threshold of $2,300 per ton derived above is lower than the threshold of $2,800 per
ton used by the Commonwealth of Pennsylvania in adopting NOx RACT rules that were recently approved
by U.S. EPA. As recognized by U.S. EPA in this SIP rulemaking, States have discretion to apply reasonable
thresholds:
EPA is aware that Pennsylvania considered cost-effectiveness levels that are lower than other states
in the OTR when developing the RACT II Rule; however, states have the discretion to determine
what costs are considered reasonable when establishing RACT for its sources. For these reasons,
EPA has not set a single cost, emission reduction, or cost-effectiveness figure to fully define cost-
effectiveness in meeting the NOx RACT requirement. Therefore, each state must make and defend
its own determination on how to weigh these values in establishing RACT. PADEP relied on a cost-
effectiveness of $2,800 per ton of NOx controlled and $5,500 per ton of VOC controlled for the
presumptive limits in the RACT II Rule.12
In addition to the cost effectiveness threshold, the manner in which this threshold is applied in determining
RACT for a category of sources is critically important. The way in which the threshold of $2,800 per ton
was applied in establishing NOx RACT in the Commonwealth of Pennsylvania was summarized by U.S.
EPA as follows:
In determining its presumptive NOx RACT limits under the RACT II Rule, PADEP considered
controls to be economically reasonable when installed and operated under $2,500 per ton of NOx
removed. EPA finds PADEP’s cost effectiveness threshold reasonable. Based on our analysis, EPA
found that cost-effectiveness of SCR in Pennsylvania boilers ranged from $3,651-$25,238 per ton,
while SNCR ranged from $2,217 to $17,594 per ton for conventional boilers (non-CFBs) and $6,076
to $19,732 per ton for CFB boilers. Because cost-effectiveness of these controls exceeded $2,500
per ton of NOx removed for the majority of coal-fired boilers in Pennsylvania without these controls
in place, it is reasonable to conclude that it would be economically infeasible to require the
installation and operation of SCR or SNCR on all coal-fired boilers in Pennsylvania. Based on this
analysis, EPA concludes that PADEP’s RACT II Rule determination for any large coal-fired boilers
without post-combustion controls in place is based on the operation of existing controls, in most
cases LNB and/or OFA. Thus, EPA finds that PADEP’s determination for this subset of coal-fired
boilers is reasonable, considering economic infeasibility of retrofitting these additional controls.13
12 84 Fed. Reg. 20274 at 20286 (May 9, 2019).
13 U.S. EPA, Technical Support Document for the Pennsylvania State Implementation Plan Revision for Certain Reasonably
Available Control Technology Requirements under the 1997 and 2008 8-hour Ozone National Ambient Air Quality Standard at
24 (Feb. 22, 2018). Available at www.regulations.gov/contentStreamer?documentId=EPA-R03-OAR-2017-0290-
0017&contentType=pdf. Internal citations omitted; emphasis in original.
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2.7 Conclusion and Proposed RACT Determination.
The circumstances present in the NOx RACT analysis for coal-fired boilers without add-on NOx controls in
Pennsylvania, as discussed in Section 2.6 above, are representative of those for this RACT analysis: There
are a small number of simple-cycle CTGs with annual capacity factors14 less than 10 percent in Maricopa
County and, as shown in sections 5.0 through 7.0 of this report, there are no additional control measures
that are economically reasonable for these units either individually or as a group.
The approach taken by the Commonwealth of Pennsylvania and approved by U.S. EPA should be applied
here: RACT should be established based on the use of work practices and these units should not be subject
to numeric emission standards.
Based on the NOx RACT analysis presented herein, SRP proposes the following as RACT for simple cycle
CTGs with capacity factor equal to or less than 10%, including Units 4, 5, and 6 at the Agua Fria Generating
Station and Units 4, 5, and 6 at the Kyrene Generating Station:
1. Nitrogen oxide (NOx) emissions shall be controlled using diffusion flame combustion.
2. The owner or operator shall implement operational practices recommended by the manufacturer
and shall ensure good combustion control through monitoring of temperature differential across
the combustion burners or at locations around the back end of the turbine.
14 All references to “annual capacity factor” in this report are based on the definition in section 201 of Rule 322 as
revised Nov. 2, 2016. This definition uses heat input rather than electric output.
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3.0 NOx Emissions from Combustion Sources.
Nitrogen oxides (NOx) consist of both nitrogen oxide (NO) and nitrogen dioxide (NO2). During
combustion, NO typically accounts for about 50% to 90% of the total NOx emissions. However, since NO
is converted to NO2 in the atmosphere, the mass emission rate of NOx is usually reported as NO2.
NOx is formed during combustion in combustion turbines through three mechanisms;
1. Thermal Formation,
2. Fuel Formation, and
3. Prompt Formation.
3.1 Thermal NOx.
Of these three formation mechanisms, thermal formation or thermal NOx is expected to represent at least
70% of the total NOx formation. Thermal NOx results from the high temperature oxidation of nitrogen (N2)
and oxygen (O2). In this mechanism, N2 is supplied from air, which is 78% N2 by volume. The thermal
NOx reactions are described by the Zel’dovich mechanism as follows:
N2 + O ↔ NO + N (1)
N + O2 ↔ NO + O (2)
N2 + O2 ↔ 2NO (1) Overall
The first step is rate limiting due to its high activation energy. As a result, thermal NOx requires high
temperatures to proceed. Thermal NOx formation increases exponentially with temperature, becoming
significant at temperatures above approximately 2,800 °F. Because thermal NOx formation increases
exponentially with temperature and because thermal NOx accounts for a large share of the total NOx
emissions, combustion control systems which reduce peak flame temperatures are effective NOx controls
for combustion turbines.
3.2 Fuel NOx.
Fuel NOx results from the oxidation of organic nitrogen compounds in the fuel. Because fuel bound
nitrogen is more easily converted to NOx during combustion, nitrogen levels in fuel can have a significant
impact on NOx formation. However, since both natural gas and distillate fuel oil have only trace organic
nitrogen compounds, fuel NOx formation is expected to be very small for these natural gas and fuel oil-
fired CTGs.
3.3 Prompt NOx.
Prompt NOx is formed by the reaction of hydrocarbon radicals with atmospheric nitrogen to produce
hydrogen cyanide (HCN) and ultimately NOx through a complex series of gas phase reactions. Prompt NOx
is expected to account for 20 – 30% of the total NOx emissions. Like thermal NOx, prompt NOx formation
can be reduced through combustion controls which reduce peak flame temperatures.
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4.0 Available NOx Control Technologies.
The RACT evaluation process starts with identifying available control technologies for the source. The
available controls are then reviewed to determine controls which are technically feasible control options.
Note that the following is a general discussion of available controls. However, the applicability of these
controls must be determined for each type of CTG as discussed in sections 5.0 through 7.0 of this report.
Based on a review of recent BACT determinations from the U.S. EPA’s RACT/BACT/LAER
Clearinghouse and a literature review including the U.S. EPA’s Compilation of Air Pollutant Emission
Factors AP-42, Chapter 3.1, Stationary Gas Turbines, April 2000, as well as the Gas Turbine ACT
Document, the following are generally available NOx control technologies for simple cycle CTGs:
Combustion Controls 1. Diffusion Flame Combustion with
a. Water Injection
b. Steam Injection
2. Dry low NOx (DLN) Combustion
3. Catalytic Combustion
Post Combustion Controls 4. Selective Catalytic Reduction (SCR)
5. Selective Non-Catalytic Reduction (SNCR)
6. EMx™ Catalytic Absorption Process (EMx or SCONOx™)
The first three (3) control technologies are combustion control technologies. The last three (3) technologies
are post combustion flue gas treatment technologies.
4.1 Diffusion Flame Combustion.
In a diffusion flame combustor, air from the turbine compressor discharge is mixed with fuel in the flame
zone at a near stoichiometric ratio. The fuel/air mixing and combustion take place simultaneously in the
primary combustion zone. This results in a stable flame but also results in high flame temperatures and high
NOx emission rates. For the most part, diffusion flame combustion will result in the highest levels of NOx
emissions from CTGs.
4.2 Water and Steam Injection.
NOx emissions from diffusion flame combustors can be reduced by injecting water or steam into the
combustion zone. Water is an inert substance in the combustion process which lowers combustion
temperature and therefore reduces thermal NOx formation. Steam or water injected into the combustion
zone acts as a heat sink which lowers peak flame temperatures. Even evaporative cooling, a technique for
increasing turbine output during hot dry conditions, can lower NOx emissions through this mechanism.
Water or steam injection will generally achieve control efficiencies of at least 70% when firing natural gas.
Although water and steam injection cannot be applied to all CTGs, the use of water and steam injection are
generally considered technically feasible control technologies for CTGs with diffusion flame combustors.
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In addition, water and steam injection can increase CTG power output, but water injection is also expected
to result in a heat rate (thermal efficiency) penalty.
4.3 Dry Low NOx (DLN) Combustion.
Dry Low NOx (DLN) combustion for CTGs is a staged combustion system which reduces peak flame
temperatures and reduces thermal and prompt NOx formation. Modern DLN systems lower the combustion
temperature using lean mixtures of air and/or fuel staging. In a typical DLN combustor, air and fuel are
mixed in a premix zone. The premixed air/fuel mixture is then ignited in the flame zone. In DLN
combustors, the excess air acts as a heat sink to lower combustion temperatures.
There are two types of DLN combustors. Two stage lean/lean combustors involve fuel stage and premixed
combustors in which each stage burns lean. These DLN combustors lower NOx emissions by reducing peak
flame temperatures and providing uniform combustion with minimal hot spots. Two stage rich/lean
combustors use air stage and premixed combustors where the primary zone is operated fuel rich and the
secondary zone is operated fuel lean. In the primary zone, the rich mixture produces lower temperatures
and decreases the amount of oxygen available for NOx formation. Exhaust from the primary zone is
quenched with air in the secondary zone. Combustion of the pre-ignited rich mixture is completed in the
secondary fuel lean zone which reduces NOx emissions by reducing combustion temperature.
While DLN combustion is capable of achieving very low NOx emission rates, especially on new CTGs,
because combustion turbines are complex internal combustion engines, DLN combustion is not applicable
to all CTGs.
4.4 Catalytic Combustion.
Catalytic combustion is a NOx control strategy for combustion turbines that reduces the temperature in the
combustor thereby limiting NOx formation. The only identified available catalytic combustion system for
combustion turbines is K-LEAN™ (formerly XONON™). This technology has been demonstrated only
for small CTGs of 1.4 megawatts electric (MWe) output capacity and has not been demonstrated as a retrofit
technology for existing CTGs. Therefore, this technology is not considered to be available or technically
feasible for these CTGs.
4.5 Selective Catalytic Reduction (SCR).
Selective Catalytic Reduction (SCR) is a post combustion flue gas treatment for controlling NOx emissions
which uses an ammonia (NH3) injection system and a catalytic reactor. SCR systems utilize an injection
grid which disperses ammonia in the flue gas upstream of the catalyst. NH3 reacts with NOx in the presence
of the catalyst to form nitrogen (N2) and water according to the following equations:
4NH3 + 4NO + O2 → 4N2 + 6H2O
4NH3 + 2NO2 + O2 → 3N2 + 6H2O
2NH3 + NO2 + NO → 2N2 + 3H2O
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Catalysts are substances which evoke chemical reactions that would otherwise not take place by providing
a reaction mechanism that has a lower activation energy than the uncatalyzed mechanism. For SCR, the
catalyst is usually a ceramic noble metal, a base metal (titanium or vanadium) oxide, or a zeolite-based
material. To achieve optimum long-term NOx reductions, SCR systems must be properly designed for each
application. In addition to critical temperature considerations, the ammonia injection rate must be carefully
controlled to maintain an NH3/NOx molar ratio that effectively reduces NOx. Excessive ammonia injection
will result in ammonia emissions, called ammonia slip.
SCR has the capability to make substantial reductions in NOx emissions. For these CTGs, the use of SCR
is expected to reduce NOx emissions by 90%.
4.6 Selective Non-Catalytic Reduction (SNCR).
In a selective non-catalytic reduction (SNCR) control system, urea or ammonia is injected into boilers
where the flue gas temperature is approximately 1,600 °F to 2,100 °F. At these temperatures, urea
[CO(NH2)2] or ammonia reacts with NOx, forming elemental nitrogen and water, without the need for a
catalyst. The overall NOx reduction reactions are similar to those for SCR. Multiple injection points are
required to thoroughly mix the reagent into the boiler furnace. The limiting factor for a SNCR system is
the ability to contact the NOx with the reagent without resulting in excessive ammonia slip and without
excessive ammonia decomposition before the NOx emissions can be reduced. SNCR may be expected to
reduce NOx emissions from 30% to 50% from the uncontrolled levels depending on the boiler application15.
SNCR has been widely used in circulating fluidized bed boilers burning solid fuels such as coal. However,
the time and temperature range for SNCR is not compatible with gas turbines. We are not aware of the
application of SNCR to any gas turbine either in the U.S. or worldwide. Therefore, SNCR is not a
technically feasible control technology for the affected CTGs.
4.7 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™).
The EMx™ system is an add-on control device that catalytically oxidizes NO to NO2 and then adsorbs the
NO2 onto a potassium carbonate-coated catalyst surface. The overall chemical reaction between NO2 and
the potassium carbonate catalyst is as follows:
2 NO2 + K2CO3 → CO2 + KNO2 + KNO3
The EMx™ process does not require injection of a reactant, such as ammonia, into the gas stream being
treated. EMx™ catalyst is reported to perform acceptably in the operating temperature range of 425 °F to
750 °F with the best economy and lowest pressure drop achieved in the temperature range of 550 °F to 650
15 From the U.S. EPA’S Air Pollution Control Technology Fact Sheet, Selective Non-Catalytic Reduction (SNCR),
EPA-452/F-03-031.
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°F where the catalyst activity is highest and the catalyst volume is minimized.16 Based on this claimed
operating range, it is not feasible to install an EMx™ system on a simple cycle combustion turbine without
a massive dilution air system.17
The EMx™ catalyst has a finite capacity to react with NO2 because potassium carbonate is “consumed” by
NO2 as shown above. Thus, in order to maintain the required NOx removal rate, the catalyst must be
periodically regenerated. Regeneration is accomplished by passing a reducing gas containing hydrogen in
dilute concentration (i.e., about 2 to 4 percent H2) across the surface of the catalyst in the absence of oxygen.
Hydrogen in the regeneration gas reacts with the nitrites and nitrates to form water and molecular nitrogen.
Carbon dioxide in the regeneration gas reacts with the potassium nitrite and nitrates to regenerate potassium
carbonate, which is the original chemical in the catalyst coating. The overall chemical reaction during
catalyst regeneration is as follows:
KNO2 + KNO3 + 4 H2 + CO2 → K2CO3 + 4 H2O + N2
The regeneration gas is produced in a gas generator using a two-stage process to produce molecular
hydrogen and carbon dioxide. In the first stage, natural gas and air are reacted across a partial oxidation
catalyst to form carbon monoxide and hydrogen. Steam is then added to the mixture and passed across a
low temperature shift catalyst, forming carbon dioxide and more hydrogen. The regeneration gas mixture
is diluted to less than four percent hydrogen using steam.
In order to regenerate its catalyst, the EMx™ system is constructed in parallel modules so that a module
can be isolated from the combustion turbine exhaust gas stream using inlet and outlet dampers. The isolated
module is then regenerated while other modules remain open to flow for treatment of the combustion turbine
exhaust gas stream.
Sulfur compounds (e.g., SO2, SO3) in the gas quickly inactivate the EMx™ catalyst requiring the catalyst
to be removed from the reactor for regeneration. To avoid this problem, EMx™ systems on natural gas
fueled combustion turbines include an upstream ESx™ catalyst module that removes the sulfur compounds
before they reach the EMx™ catalyst beds. The ESx™ catalyst is regenerated at the same time as the
EMx™ catalyst by the same regeneration gas. This releases collected SOx as SO2 into the regeneration off-
gas stream.
EMx™ is demonstrated for use on relatively small combined-cycle natural gas fueled combustion turbines.
The largest application is the 50 MW Unit 6 combined cycle combustion turbine at the Redding, California
municipal power plant. EMx™ has not been demonstrated on a large combined cycle combustion turbine
or on any simple-cycle combustion turbine. The La Paloma Generating Project in California initially
16 See, for example, http://docketpublic.energy.ca.gov/PublicDocuments/Regulatory/Non%20Active%20AFC's/07-
AFC-9%20Canyon/2009/January/TN%2049920%2001-28-09%20ECM%20Technology%20White%20Paper.pdf at
page 38 of the PDF file.
17 Depending on CTG load and ambient temperatures, the amount of dilution air needed for EMx™ at 700 °F would
be two to three times the amount of dilution air needed for SCR at 900 °F. Under some operating conditions, dilution
to accommodate EMx™ could nearly double the gas flow through the combustion turbine stack.
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proposed to demonstrate EMx™ on a 150 MW turbine, but ultimately an SCR system was installed instead.
This was also the case with the Otay Mesa project located in California.
Some of the issues identified with applying EMx™ are:
• The catalyst is very sensitive to sulfur in the exhaust gas;
• The reliability of the system’s moving parts over time is an operational and maintenance concern;
• The use of hydrogen for regeneration could be a serious safety concern;
• The potential exists for scale-up issues for larger CTGs such as those at the Agua Fria and Kyrene
Generating Stations;
• An EMx™ system has significant pressure drop – about twice that of a comparable SCR system –
which presents design challenges not currently addressed in the installed simple cycle combustion
turbine population.
EMx™ is infeasible because it has not been demonstrated on any combustion turbine larger than 50 MW.
Size is an important issue for the EMx™ process as it is more suited to small-scale applications and it has
been rejected due to size/scale-up considerations in other situations. More significantly, EMx™ has not
been demonstrated on any simple cycle CTGs such as those at the Agua Fria and Kyrene Generating
Stations. The exhaust temperature from the simple cycle CTGs at the Agua Fria and Kyrene Generating
Stations is too high for application of EMx™ technology.
For these reasons, EMx™ is not considered feasible for this RACT analysis.
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5.0 Agua Fria Simple Cycle CTG Units 4, 5, and 6.
The Agua Fria Units 4, 5, and 6 are natural gas and distillate fuel oil-fired simple cycle CTGs. These units
have very low utilization, with a typical capacity factor less than 1 percent, and essentially 100% of the heat
input to all three boilers is typically natural gas.
Units 4, 5, and 6 are each Westinghouse Model 501B simple cycle CTGs rated at 80 MWe and having a
maximum design heat input capacity of 1,129 MMBtu per hour. These CTGs have no NOx controls.
For this RACT analysis, the uncontrolled NOx emission rate for all control technologies is based on an
uncontrolled NOx emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb NOx/MMBtu.
5.1 Technically Feasible Control Technologies.
For the Agua Fria Units 4 and 5, and 6, the available NOx control technologies are diffusion flame
combustion, with or without water or steam injection; dry low NOx combustion; and SCR.
5.2 Water Injection.
Water injection systems for these CTGs is expected to reduce NOx emissions when firing natural gas from
a worst-case uncontrolled emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb/MMBtu, to 25 ppmdv at
15% O2 and 0.092 lb/MMBtu.
Water injection systems for these Westinghouse 501B CTGs would include water injection nozzles, flow
metering controls, pumps, hardware, and interconnecting piping from a water treatment system to each
CTG. The water treatment system would include reverse osmosis demineralization systems and storage
tanks. Table 5-1 is a summary of the capital costs for a water injection system for Westinghouse Model
501-AA simple cycle CTGs which have a rated capacity of 55 MW(e) from a 2018 vendor quote for
supplying water injection for Westinghouse 501-AA CTGs owned and operated by Arizona Public Service
(APS).
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TABLE 5-1. Water injection system capital costs for a Westinghouse Model 501-AA CTG and the
capital costs for the Agua Fria Units 4, 5, and 6.
Item Cost
Equipment Costs Water Injection (Water pump to unit, no water supply) $1,060,000
(from Supplier Quote) Water Supply (tank, associated piping, valves) $448,000
Shipping $13,000
Tax $69,000
Interface with DCS (APS costs) $60,000
Wiring and Conduit $45,000
Contract Administration (APS costs) $9,000
Project Management (APS costs) $25,000
Engineering Design and Review (contract) $113,000
Foundation, Incidentals, APS Engineering Support $10,000
and Indirect Costs (APS
Engineering Estimate) Inspection and Review $6,000
Construction Management (contract) $27,000
Start-up and Commissioning (B&M) $20,000
I&C Support (APS) $24,000
Performance Testing and Permitting $32,000
Control Integration (APS) $7,000
Operational Spare Parts $91,000
Contingency (based on 20% of total costs) $289,000
TOTAL CAPITAL COST, Westinghouse Model 501-AA CTG $2,348,000
TOTAL CAPITAL COST, Westinghouse Model 501B CTG $2,940,000
The water injection system costs for SRP’s 80 MWe CTGs in 2018 dollars was calculated using the
equipment costs in Table 5-1 and adjusted to the larger Model 501B CTGs using the six-tenth factor rule
which is an empirical relationship between the cost and the size of a manufacturing facility or equipment.18
0.6 0.6
C501B = C501AA ൬S501B ൰ = $2,348,000 ൬80 55൰ = $2,940,000
S501AA
Where C501B = Cost for the SRP Westinghouse Model 501B CTGs
18 See, for example, U.S. EPA, Basis for Denial of Petitions to Reconsider the CAA Section 111(b) Standards of
Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric
Utility Generating Units (April 2016) (“This power law scaling approach is a very common application of what is
referred to as the ‘six-tenths rule’ …. Following the advice of Peters and Timmerhaus, it is common practice for
design engineers to use the 0.6 factor ‘in the absence of other information’ when estimating equipment costs by
scaling.”).
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C501AA = Cost for the APS Westinghouse Model 501AA CTGs
S501B = Size for the SRP Westinghouse Model 501B CTGs = 80 MW
C501AA = Cost for the APS Westinghouse Model 501AA CTGs = 55 MW
As shown above, substituting the total capital cost for the Model 501AA CTGs of $2,348,000 and the sizes
of each CTG into this equation, the resulting cost of water injection for each Model 501B CTG would be
$2,940,000 in 2018 dollars.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 2018 has the same buying power as $1.03 in March 2020. The total capital
cost of water injection systems for Agua Fria Units 4, 5, and 6 in current dollars is $3,028,000.
Table 5-2 is a summary of the annual costs and the cost effectiveness for water injection systems for the
Agua Fria Model 501B CTGs.
The annual capital recovery cost is calculated as the product of the total capital cost of $3,028,000 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 3% loss
in CTG efficiency with water injection and a natural gas cost of $3.00 per MMBtu. The water injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
The emission reduction in Table 5-2 is based on a water injection NOx emission rate when firing natural
gas of 25 ppmdv at 15% O2 equal to 0.092 lb/MMBtu, an uncontrolled emission rate of 135 ppmdv at 15%
O2, equal to 0.50 lb/MMBtu, and a CTG capacity factor of 10%:
1,129 MMBtu 876 hr lb NOx 1.0 ton NOx
Emission Reduction = × × ൬ 0.50 −0.092 MMBtu൰ ×
hr yr 2,000 lb NOx
Emission Reduction = 201.8 ton/year
TABLE 5-2. Annual costs and cost effectiveness for a water injection system for each
Westinghouse Model 501B simple cycle CTG.
Capital Recovery Cost $332,500 $3.028MM × 0.10979
Fuel Cost $89,000 3.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $118,700 1 lb demin water per lb fuel and $0.02103/gal
(see Section 2.5).
Maintenance Cost $49,600 From Table B-2 of the NOx ACT
Plant Overhead Cost $14,900 30% of Annual Maintenance Cost
General & Administrative, Taxes, Insurance $121,100 4% of Total Capital Cost
TOTAL ANNUAL COST $725,800
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Emission Reduction 201.8 ton NOx/year
COST EFFECTIVENESS $3,600 $ per ton of NOx controlled
From Table 5-2, even assuming a potential emission reduction of 201.8 tons per year based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
and a capacity factor of 10%, the use of water injection on each Westinghouse Model 501B simple cycle
CTG would have a cost effectiveness of $3,600 per ton of NOx controlled. This calculation result is
conservative, as it greatly overstates the achievable emission reduction.
In addition, the use of water injection would consume 5.6 million gallons of water per year per unit. This
is a substantial amount of water in an arid region in which water is a valuable natural resource. Based on
these facts, the use of water injection for the control of NOx emissions from the Agua Fria Westinghouse
Model 501B simple cycle CTGs is not a feasible RACT option.
5.3 Steam Injection.
Like water injection, steam injection systems for these CTGs is expected to reduce NOx emissions when
firing natural gas from a worst-case uncontrolled emission rate of 135 ppmdv at 15% O2, equal to 0.50
lb/MMBtu, to 25 ppmdv at 15% O2 and 0.092 lb/MMBtu.
Although steam injection is a technically feasible NOx control option, steam injection is less frequently
used than water injection. Like the water injection systems, steam injection systems would include injection
nozzles, flow metering controls, pumps, hardware, and interconnecting piping from a water treatment
system to each CTG. In addition, a steam injection system would require a boiler to convert the
demineralized water to steam. This boiler may be a natural gas-fired boiler, or it may be placed in the CTG
flue gas outlet plenum to use waste heat from the CTG to create steam.
Table 5-3 is a summary of the capital costs for a steam injection system for each of the Agua Fria Model
501B CTGs. These costs are based on Chapter 6 of the Gas Turbine ACT Document. All costs have been
escalated from 1990 to March 2020 dollars based on the CPI.
TABLE 5-3. Steam injection system capital costs for each Westinghouse Model 501B CTG.
Purchased Equipment Costs (PEC)
Steam Injection System $870,000 Based on $4,200 per gallon per minute (GPM) as steam
Water Treatment System $878,000 WTS = 43,900 x GPM0.5
Taxes and Freight $140,000 8% of the total system costs
Direct Installation Costs
Direct Costs $850,000 45% of Purchased Equipment Costs
Indirect Installation Costs
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Indirect Costs $586,000 33% of the PEC and Direct Costs + $5,000
Contingency Costs $665,000 20% of the Sum of the PEC, Direct and Indirect Costs
TOTAL CAPITAL COST $3,989,000
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
2. Costs are based on the following combustion turbine and water injection system design conditions:
CTG Heat Input Capacity 1,129 MMBtu/hr
Natural Gas Heat Value 21,000 Btu per pound, HHV
Natural Gas Fuel Flow Rate 53,762 lb/hour
Steam-to-Fuel Ratio (Ω) 1.0 lb steam/lb fuel
Water Flowrate 107 gallons per minute (GPM)
Water Flowrate 5,643,600 gallons per year
Cost Escalation (Inflation) Factor 1.93 Escalated from Dec. 1990 to Mar. 2020 based on the CPI.
Table 5-4 is a summary of the annual costs and the cost effectiveness for steam injection systems for the
Agua Fria Model 501B CTGs.
The annual capital recovery cost is calculated as the product of the total capital cost of $4,214,000 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 1% loss
in CTG efficiency with steam injection and a natural gas cost of $3.00 per MMBtu. The steam injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
TABLE 5-4. Annual costs and cost effectiveness for a steam injection system for each
Westinghouse Model 501B simple cycle CTG.
Capital Recovery Cost $438,000 Based on the Total Capital Cost in Table 5-3.
Fuel Penalty Cost $29,700 1.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $118,700 1 lb steam per lb fuel and $0.02103/gal (see
Section 2.5).
Maintenance Cost The NOx ACT indicates no additional turbine
Plant Overhead $0 maintenance cost for steam injection.
General & Adm., Taxes, Insurance (GATI) $159,600 4% of Total Capital Cost
TOTAL ANNUAL COST $746,000
Emission Reduction 201.8 ton NOx/year
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Cost Effectiveness $3,700 $ per ton of NOx controlled
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
From Table 5-4, even assuming a potential emission reduction of 201.8 tons per year based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
and a capacity factor of 10%, the use of steam injection on each Westinghouse Model 501B simple cycle
CTG would have a cost effectiveness of $3,700 per ton of NOx controlled. This calculation result is
conservative, as it greatly overstates the achievable emission reduction.
In addition, the use of steam injection would consume 5.6 million gallons of water per year per unit. This
is a substantial amount of water in an arid region in which water is a valuable natural resource. Based on
these facts, the use of steam injection for the control of NOx emissions from the Agua Fria Westinghouse
Model 501B simple cycle CTGs is not a feasible RACT option.
5.4 DLN Combustion.
SRP obtained from Power Systems Manufacturing (PSM) a budgetary estimate for DLN combustors for
these units, called LEC-III® gas turbine combustion technology. PSM has provided a cost of $8,975,000
(Oct. 2015 dollars) for each CTG, including installation costs.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in October has the same buying power as $1.09 in March 2020. The total capital cost
of water injection systems for Agua Fria Units 4, 5, and 6 in current dollars is $9,783,000 per unit.
This budgetary estimate is based on LEC-III® gas turbine combustion technology designed to meet 15
ppmdv at 15% O2, equal to a NOx emission rate of 0.055 lb/MMBtu. For a maximum design heat input
rate of 1,129 MMBtu per hour for each CTG and a maximum capacity factor of 10%, the potential NOx
emission reduction for the LEC-III® gas turbine combustion technology would be:
0.50 −0.055 lb NOx 1,129 MMBtu 8,760 hr 1.0 ton NOx
Reduction = × × × × 0.1 = 220.1 ton/yr
MMBtu hr yr 2,000 lb NOx
For this analysis, using a capital cost of $9,783,000 per unit and a CRF of 0.10979, the annualized capital
recovery cost would be $1,074,000. For a maximum NOx reduction of 220.1 tons per year, the cost
effectiveness for the LEC-III® gas turbine combustion technology would be $4,880 per ton of NOx
controlled. Based on these costs, the use of the LEC-III® gas turbine DLN combustion technology for the
control of NOx emissions from the Agua Fria Westinghouse Model 501B simple cycle CTGs is not a
feasible RACT option.
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5.5 Selective Catalytic Reduction (SCR).
SCR systems have the capability to make substantial reductions in NOx emissions. For these CTGs, the
use of SCR is expected to reduce NOx emissions by more than 90%, to a long-term emission rate of 9
ppmvd at 15% O2, equal to 0.0331 lb/MMBtu. SCR systems for these simple cycle CTGs would include a
catalyst reactor housing, the catalyst and support matrix, an ammonia injection grid, aqueous ammonia
storage tanks, and ammonia metering equipment and controls. From the U.S. EPA’s 1999 document Air
Pollution Control Technology Fact Sheet for Selective Catalytic Reduction, EPA-452/F-03-032, SCR
capital costs for large gas turbines range from $5,000 to $7,500 per MMBtu per hour of heat input capacity.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in December 1999 has the same buying power as $1.53 in March 2020. The low end
of U.S. EPA’s range of capital cost estimates is $7,650 per MMBtu/hr in March 2020 dollars.
Table 5-5 is a summary of a detailed analysis of the capital costs, annual costs, and cost effectiveness for
SCR systems for each Agua Fria Westinghouse Model 501B simple cycle CTG based on a 93.3% SCR
control efficiency and a 10% capacity factor. The costs in Table 5-5, other than the capital cost, are based
on Table 6-8 of the Gas Turbine ACT Document. Costs have been escalated from 1990 dollars to March
2020 dollars based on the CPI.
TABLE 5-5. Capital costs, annual costs, and cost effectiveness for an SCR system for each Agua
Fria Westinghouse Model 501B simple cycle CTG based on a 10% capacity factor.
A. Total Capital Cost $8,637,000 = Based on the low estimate from EPA-452/F-03-032
B. Direct Annual Costs, $/yr
1. Operating Labor $5,400 = (1.0 hr/8 hr-shift) x ($25.60/hr) x (876 hr/yr)
2. Supervisory Labor $800 = (0.15) x (Operating Labor)
3. Maint. Labor & Materials $24,300 = [(1,250 x TMW) + 25,800] x 0.1
4. Catalyst Replacement $79,700 = [(4,700 x TMW) + 37,200] x 0.1
5. Catalyst Disposal $4,500 = [(V) x ($15/ft3) x (.2638)] x 0.1
6. Ammonia $63,200 = (N) x ($360/ton) (NOx : NH3 ratio = 1:1)
9. Performance Loss $21,000 = (0.005)x(TMW)x($0.06/kWh)x(1,000 kW/MW)x(H)
C. Indirect Annual Costs, $/yr
1. Overhead $18,300 = (0.6) x (all labor and maintenance material costs)
2. Taxes, Insurance, Administra $345,500 = (0.04) x (total capital investment)
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3. Capital Recovery $948,300
TOTAL ANNUAL COST $1,511,000
Emission Reduction 230.9 ton NOx/year
COST EFFECTIVENESS $6,540 $ per ton of NOx controlled
Footnotes
1. Except as noted, costs are based on the Gas Turbine ACT Document, with an escalation factor of 1.93 to
escalate from Dec. 1990 to Mar. 2020 based on the CPI.
2. TMW is turbine output in megawatts, V is catalyst volume in ft3, N is annual ammonia usage in tons
The average cost effectiveness of SCR systems for the Westinghouse Model 501B simple cycle CTGs
would be $6,540 per ton of NOx controlled. Based on these costs, the use of SCR for the control of NOx
emissions from the Agua Fria Westinghouse Model 501B simple cycle CTGs is not a feasible RACT option.
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5.6 Conclusions.
Table 5-6 is a summary of the available and technically feasible NOx RACT options for the Agua Fria
Westinghouse Model 501B simple cycle CTGs, the potential emission reductions, and the average cost
effectiveness of each control option. The potential emission reductions and the resulting cost effectiveness
in Table 5-6 are based on a 10% capacity factor for each CTG. Note that the potential NOx emission
reductions for each option are based on 247.3 tons per year for the uncontrolled CTGs which greatly
overstates the actual emissions and the potential emission reductions. Even with these conservative
assumptions, no control options meet the cost effectiveness threshold of $2,300 per ton discussed in Section
2.6 of this report.
TABLE 5-6. NOx control options, emission reductions, and cost effectiveness for each Agua
Fria Westinghouse Model 501B simple cycle CTG based on a 10% capacity factor.
NOx Control Emission Rate, Potential NOx Capital Annual Cost
Option ppmdv at Emissions, Cost Cost Effectiveness,
15% O2 ton/yr $ per ton
Worst-case 135 247.3
Uncontrolled CTG
Water Injection 25 45.5 $3,028,000 $725,800 $3,600
Steam Injection 25 45.5 $3,989,000 $746,000 $3,700
Dry Low NOx 15 27.2 $9,783,000 $1,074,000 $4,880
Combustion (DLN)
Selective Catalytic 9 16.4 $8,637,000 $1,511,000 $6,540
Reduction (SCR)
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6.0 Kyrene Simple Cycle CTG Unit 4.
The Kyrene Generating Station Unit 4 is a natural gas and distillate fuel oil-fired simple cycle CTG.
However, this unit is permitted to combust fuel oil only as an emergency fuel when natural gas is
unavailable. Unit 4 has very low utilization, with a typical capacity factor less than 0.1 percent.
Unit 4 is a Westinghouse Model 501A simple cycle CTG rated at 53 MWe and having a maximum design
heat input capacity of 969 MMBtu per hour. This CTG has no NOx controls.
For this RACT analysis, the uncontrolled NOx emission rate for all control technologies is conservatively
based on a NOx emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb NOx/MMBtu.
6.1 Technically Feasible Control Technologies.
The available NOx control technologies for this Westinghouse Model 501A simple cycle CTG are diffusion
flame combustion, with or without water or steam injection, and SCR. With respect to DLN combustion,
this CTG has turbine inlet temperatures (TIT) after the compressor stages of less than 1,100 °F. The fuel/air
mixture in the turbine is already too lean to be further reduced using DLN combustion and also maintain a
constant, safe, and stable flame. Therefore, DLN combustion is not a technically feasible control
technology for this Westinghouse Model 501A CTG.
6.2 Water Injection.
A water injection system for this CTG is expected to reduce NOx emissions when firing natural gas from a
worst-case uncontrolled emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb/MMBtu, to 25 ppmdv at
15% O2 and 0.092 lb/MMBtu.
A water injection system would include water injection nozzles, flow metering controls, pumps, hardware,
and interconnecting piping from a water treatment system to the CTG. The water treatment system would
include reverse osmosis demineralization systems and a storage tank. Table 5-1 in the previous chapter of
this report is a summary of the capital costs for a water injection system for a similar Westinghouse Model
501-AA simple cycle CTG totaling $2,348,000 in 2018 dollars.
The water injection system costs for the 53 MWe Unit 4 CTG in 2018 dollars was calculated using the
equipment costs in Table 5-1 and adjusted to the slightly smaller Model 501A CTG using the six-tenth
factor rule.
0.6 0.6
C501A = C501AA ൬S501A ൰ = $2,348,000 ൬53 55൰ = $2,296,400
S501AA
Where C501A = Cost for the SRP Westinghouse Model 501A CTG
C501AA = Cost for the APS Westinghouse Model 501AA CTGs
S501A = Size for the SRP Westinghouse Model 501A CTG = 53 MW
C501AA = Cost for the APS Westinghouse Model 501AA CTGs = 55 MW
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As shown above, substituting the total capital cost for the Model 501AA CTGs of $2,348,000 and the sizes
of each CTG into this equation, the resulting cost of water injection for the Model 501A CTG would be
$2,296,400 in 2018 dollars.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 2018 has the same buying power as $1.03 in March 2020. The total capital
cost of water injection systems for Unit 4 at the Kyrene Generating Station in current dollars is $2,365,300.
Table 6-1 is a summary of the annual costs and the cost effectiveness for a water injection system for the
Kyrene Unit 4 CTG.
The annual capital recovery cost is calculated as the product of the total capital cost of $2,365,300 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 3% loss
in CTG efficiency with water injection and a natural gas cost of $3.00 per MMBtu. The water injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
The emission reduction in Table 6-1 is based on a water injection NOx emission rate when firing natural
gas of 25 ppmdv at 15% O2 equal to 0.092 lb/MMBtu, an uncontrolled emission rate of 135 ppmdv at 15%
O2, equal to 0.50 lb/MMBtu, and a CTG capacity factor of 10%:
969 MMBtu 8,760 hr lb NOx 1.0 ton NOx
Emission Reduction = × × 0.1 × ൬ 0.50 −0.092 MMBtu൰ ×
hr yr 2,000 lb NOx
Emission Reduction = 173.2 ton/year
TABLE 6-1. Annual costs and cost effectiveness for a water injection system for the Kyrene
Unit 4 Westinghouse Model 501A simple cycle CTG.
Capital Recovery Cost $259,700 $2.3653MM × 0.10979
Fuel Cost $76,400 3.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $101,900 1 lb demin water per lb fuel and
$0.02103/gal; (see Section 2.5).
Maintenance Cost $49,600 From Table B-2 of the NOx ACT
Plant Overhead Cost $14,900 30% of Annual Maintenance Cost
General & Administrative, Taxes, Insurance $94,600 4% of Total Capital Cost
TOTAL ANNUAL COST $597,100
Emission Reduction 173.2 ton NOx/year
COST EFFECTIVENESS $3,450 $ per ton of NOx controlled
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From Table 6-1, the use of water injection on this Westinghouse Model 501A simple cycle CTG would
result in a potential emission reduction of 173.2 tons per year. This reduction is based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
and a capacity factor of 10%. The average cost effectiveness is $3,450 per ton of NOx controlled.
In addition, the use of water injection would consume 4.8 million gallons of water per year. This is a
substantial amount of water in an arid region in which water is a valuable natural resource. Based on these
facts, the use of water injection for the control of NOx emissions from the Kyrene Unit 4 simple cycle CTG
is not a feasible RACT option.
6.3 Steam Injection.
Like water injection, steam injection for this CTG is expected to reduce NOx emissions when firing natural
gas from a worst-case emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb/MMBtu, to 25 ppmdv at
15% O2 equal to 0.092 lb/MMBtu.
Although steam injection is a technically feasible NOx control option, steam injection is less frequently
used than water injection. Like the water injection system, a steam injection system would include injection
nozzles, flow metering controls, pumps, hardware, and interconnecting piping from a water treatment
system to the CTG. In addition, a steam injection system would require a boiler to convert the demineralized
water to steam. This boiler may be a natural gas-fired boiler, or it may be placed in the CTG flue gas outlet
plenum to use waste heat from the CTG to create steam.
Table 6-2 is a summary of the capital costs for a steam injection system for Kyrene Unit 4. These costs are
based on Chapter 6 of the Gas Turbine ACT Document. All costs have been escalated from 1990 to March
2020 dollars based on the CPI.
TABLE 6-2. Steam injection system capital costs for the Westinghouse Model 501A CTG.
Purchased Equipment Costs (PEC)
Steam Injection System $747,000 Based on $4,200 per gallon per minute (GPM) as steam
Water Treatment System $813,000 WTS = 43,900 x GPM0.5
Taxes and Freight $125,000 8% of the total system costs
Direct Installation Costs
Direct Costs $758,000 45% of Purchased Equipment Costs
Indirect Installation Costs
Indirect Costs $524,000 33% of the PEC and Direct Costs + $5,000
Contingency Costs $593,000 20% of the Sum of the PEC, Direct and Indirect Costs
TOTAL CAPITAL COST $3,560,000
Footnotes
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1. Costs are based on the Gas Turbine ACT Document.
2. Costs are based on the following combustion turbine and steam injection system design conditions:
CTG Heat Input Capacity 969 MMBtu/hr
Natural Gas Heat Value 21,000 Btu per pound, HHV
Natural Gas Fuel Flow Rate 46,148 lb/hour
Steam-to-Fuel Ratio (Ω) 1.0 lb steam/lb fuel
Water Flowrate 92 gallons per minute (GPM)
Water Flowrate 4,844,300 gallons per year
Cost Escalation (Inflation) Factor 1.93 Escalated from Dec. 1990 to Mar. 2020 based on the CPI.
Table 6-3 is a summary of the annual costs and the cost effectiveness for a steam injection system for the
Kyrene Unit 4 Westinghouse Model 501A simple cycle CTG.
The annual capital recovery cost is calculated as the product of the total capital cost of $3,560,000 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 1% loss
in CTG efficiency with steam injection and a natural gas cost of $3.00 per MMBtu. The steam injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
TABLE 6-3. Annual costs and cost effectiveness for a steam injection system for the Kyrene
Unit 4 Westinghouse Model 501A simple cycle CTG.
Capital Recovery Cost $390,900 Based on the Total Capital Cost in Table 6-2.
Fuel Penalty Cost $25,500 1.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $101,900 1 lb steam per lb fuel and $0.02103/gal (see
Section 2.5).
Maintenance Cost The NOx ACT indicates no additional turbine
Plant Overhead $0 maintenance cost for steam injection.
General & Adm., Taxes, Insurance (GATI) $142,400 4% of Total Capital Cost
TOTAL ANNUAL COST $660,700
Emission Reduction 173.2 ton NOx/year
Cost Effectiveness $3,820 $ per ton of NOx controlled
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
From Table 6-3, even assuming a potential emission reduction of 173.2 tons per year based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
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and a capacity factor of 10%, the use of steam injection on the Westinghouse Model 501A simple cycle
CTG would have a cost effectiveness of $3,820 per ton of NOx controlled. This calculation result is
conservative, as it greatly overstates the achievable emission reduction.
In addition, the use of steam injection would consume 4.8 million gallons of water per year. This is a
substantial amount of water in an arid region in which water is a valuable natural resource. Based on these
facts, the use of steam injection for the control of NOx emissions from the Kyrene Unit 4 Westinghouse
Model 501A simple cycle CTG is not a feasible RACT option.
6.4 Selective Catalytic Reduction (SCR).
SCR systems have the capability to make substantial reductions in NOx emissions. For the Kyrene Unit 4
CTG, the use of SCR is expected to reduce NOx emissions by more than 90%, to a long-term emission rate
of 9 ppmvd at 15% O2, equal to 0.0331 lb/MMBtu. SCR systems for this simple cycle CTG would include
a catalyst reactor housing, the catalyst and support matrix, an ammonia injection grid, aqueous ammonia
storage tanks, and ammonia metering equipment and controls. From the U.S. EPA’s 1999 document Air
Pollution Control Technology Fact Sheet for Selective Catalytic Reduction, EPA-452/F-03-032, SCR
capital costs for large gas turbines range from $5,000 to $7,500 per MMBtu per hour of heat input.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in December 1999 has the same buying power as $1.53 in March 2020. The low end
of U.S. EPA’s range of capital cost estimates is $7,650 per MMBtu/hr in March 2020 dollars.
Table 6-4 is a summary of a detailed analysis of the capital costs, annual costs, and cost effectiveness for
an SCR system for the Kyrene Unit 4 Westinghouse Model 501A simple cycle CTG based on a 93.3% SCR
control efficiency and a 10% capacity factor. The costs in in Table 6-4, other than the capital cost, are
based on Table 6-8 of the Gas Turbine ACT Document. Costs have been escalated from 1990 dollars to
March 2020 dollars based on the CPI.
TABLE 6-4. Capital costs, annual costs, and cost effectiveness for an SCR system for the Kyrene
Unit 4 Westinghouse Model 501A simple cycle CTG based on a 10% capacity factor.
A. Total Capital Cost $7,414,000 = Based on the low estimate from EPA-452/F-03-032
B. Direct Annual Costs, $/yr
1. Operating Labor $5,400 = (1.0 hr/8 hr-shift) x ($25.60/hr) x (876 hr/yr)
2. Supervisory Labor $800 = (0.15) x (Operating Labor)
3. Maint. Labor & Materials $17,800 = [(1,250 x TMW) + 25,800] x 0.1
4. Catalyst Replacement $55,300 = [(4,700 x TMW) + 37,200] x 0.1
5. Catalyst Disposal $3,000 = [(V) x ($15/ft3) x (.2638)] x 0.1
6. Ammonia $54,300 = (N) x ($360/ton) (NOx : NH3 ratio = 1:1)
9. Performance Loss $13,900 = (0.005)x(TMW)x($0.06/kWh)x(1,000 kW/MW)x(H)
C. Indirect Annual Costs, $/yr
1. Overhead $14,400 = (0.6) x (all labor and maintenance material costs)
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2. Taxes, Insurance, Administra $296,600 = (0.04) x (total capital investment)
3. Capital Recovery $814,000
TOTAL ANNUAL COST $1,275,500
Emission Reduction 198.2 ton NOx/year
COST EFFECTIVENESS $6,440 $ per ton of NOx controlled
Footnotes
1. Except as noted, costs are based on the Gas Turbine ACT Document, with an escalation factor of 1.93 to
escalate from Dec. 1990 to Mar. 2020 based on the CPI.
2. TMW is turbine output in megawatts, V is catalyst volume in ft3, N is annual ammonia usage in tons
The average cost effectiveness of SCR systems for the Westinghouse Model 501A simple cycle CTG would
be $6,440 per ton of NOx controlled. Based on these costs, the use of SCR for the control of NOx emissions
from the Kyrene Unit 4 Westinghouse Model 501A simple cycle CTG is not a feasible RACT option.
6.5 Conclusions.
Table 6-5 is a summary of the available and technically feasible NOx RACT options for the Kyrene
Generating Station Unit 4 Westinghouse Model 501A simple cycle CTG, the potential emission reductions,
and the average cost effectiveness of each control option. The potential emission reductions and the
resulting cost effectiveness in Table 6-5 are based on a 10% capacity factor. Note that the potential NOx
emission reductions for each option are based on 212.1 tons per year for the uncontrolled CTG which
greatly overstates the actual emissions and the potential emission reductions. Even with these conservative
assumptions, no control options meet the cost effectiveness threshold of $2,300 per ton discussed in Section
2.6 of this report.
TABLE 6-5. NOx control options, emission reductions, and cost effectiveness for the Kyrene
Unit 4 Westinghouse Model 501A simple cycle CTG based on a 10% capacity factor.
NOx Control Emission Rate, Potential NOx Capital Annual Cost
Option ppmdv at Emissions, Cost Cost Effectiveness,
15% O2 ton/yr $ per ton
Worst-case 135 212.2
Uncontrolled CTG
Water Injection 25 39.1 $2,365,300 $597,100 $3,450
Steam Injection 25 39.1 $3,560,000 $660,700 $3,820
Selective Catalytic 9 14.0 $7,414,000 $1,275,500 $6,440
Reduction (SCR)
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7.0 Kyrene Simple Cycle CTG Units 5 and 6.
The Kyrene Generating Station Units 5 and 6 are natural gas and distillate fuel oil-fired simple cycle CTGs.
However, these units are permitted to combust fuel oil only as an emergency fuel when natural gas is
unavailable. Units 5 and 6 have very low utilization, with a typical capacity factor less than 0.1 percent.
Units 5 and 6 are General Electric (GE) Model 7B simple cycle CTGs rated at 60 MWe, each having a
maximum design heat input capacity of 912 MMBtu per hour. These CTGs have no NOx controls.
For this RACT analysis, the uncontrolled NOx emission rate for all control technologies is conservatively
based on a NOx emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb NOx/MMBtu.
7.1 Technically Feasible Control Technologies.
For the Kyrene Generating Station Units 5 and 6, the available NOx control technologies include diffusion
flame combustion, with or without water or steam injection; DLN combustion; and SCR.
7.2 Water Injection.
Water injection systems for these CTGs are expected to reduce NOx emissions when firing natural gas from
a worst-case uncontrolled emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb/MMBtu, to 25 ppmdv at
15% O2 and 0.092 lb/MMBtu.
Water injection systems would include water injection nozzles, flow metering controls, pumps, hardware,
and interconnecting piping from a water treatment system to each CTG. The water treatment system would
include reverse osmosis demineralization systems and a storage tank. Table 5-1 in Chapter 5.0 of this report
is a summary of the capital costs for a water injection system for a similar Westinghouse Model 501-AA
simple cycle CTG totaling $2,348,000 in 2018 dollars.
The water injection system costs for the 60 MWe Unit 5 and Unit 6 CTGs in 2018 dollars were calculated
using the equipment costs in Table 5-1 and adjusted to the slightly larger GE Model 7B CTGs using the
six-tenth factor rule.
0.6 0.6
C7B = C501AA ൬S7B ൰ = $2,348,000 ൬60 55൰ = $2,474,000
S501AA
Where C7B = Cost for the SRP General Electric Model 7B CTGs
C501AA = Cost for the APS Westinghouse Model 501AA CTG
S7B = Size for the SRP General Electric Model 7B CTGs = 60 MW
S501AA = Size for the APS Westinghouse Model 501AA CTGs = 55 MW
As shown above, substituting the total capital cost for the Model 501AA CTGs of $2,348,000 and the sizes
of each CTG into this equation, the resulting cost of water injection for each GE Model 7B CTG would be
$2,474,000 in 2018 dollars.
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Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 2018 has the same buying power as $1.03 in March 2020. The total capital
cost of water injection systems for Units 5 and 6 at the Kyrene Generating Station in current dollars is
$2,548,100 per unit.
Table 7-1 is a summary of the annual costs and the cost effectiveness for a water injection system for the
Kyrene Unit 5 and Unit 6 CTGs.
The annual capital recovery cost is calculated as the product of the total capital cost of $2,548,100 per unit
and the capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a
3% loss in CTG efficiency with water injection and a natural gas cost of $3.00 per MMBtu. The water
injection system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas
Turbine ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990
dollars to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per
gallon as discussed in Section 2.5.
The emission reduction in Table 7-1 is based on a water injection NOx emission rate when firing natural
gas of 25 ppmdv at 15% O2 equal to 0.092 lb/MMBtu, an uncontrolled emission rate of 135 ppmdv at 15%
O2, equal to 0.50 lb/MMBtu, and a CTG capacity factor of 10%:
912 MMBtu 8,760 hr lb NOx 1.0 ton NOx
Emission Reduction = × × 0.1 × ൬ 0.50 −0.092 MMBtu൰ ×
hr yr 2,000 lb NOx
Emission Reduction = 163.0 ton/year
TABLE 7-1. Annual costs and cost effectiveness for a water injection system for each General
Electric Model 7B simple cycle CTG.
Capital Recovery Cost $279,800 $2.5481MM × 0.10979
Fuel Cost $71,900 3.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $95,900 1 lb demin water per lb fuel and
$0.02103/gal; (see Section 2.5).
Maintenance Cost $49,600 From Table B-2 of the NOx ACT
Plant Overhead Cost $14,900 30% of Annual Maintenance Cost
General & Administrative, Taxes, Insurance $101,900 4% of Total Capital Cost
TOTAL ANNUAL COST $614,000
Emission Reduction 163.0 ton NOx/year
COST EFFECTIVENESS $3,770 $ per ton of NOx controlled
From Table 7-1, the use of water injection on the GE Model 7B simple cycle CTGs would result in a
potential emission reduction of 163.0 tons per year per unit. This reduction is based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
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and a capacity factor of 10%. The average cost effectiveness is $3,770 per ton of NOx controlled. In
addition, the use of water injection would consume 4.6 million gallons of water per unit per year. This is a
substantial amount of water in an arid region in which water is a valuable natural resource. Based on these
facts, the use of water injection for the control of NOx emissions from the Kyrene Unit 5 and Unit 6 simple
cycle CTGs is not a feasible RACT option.
7.3 Steam Injection.
Like water injection, steam injection for these GE Model 7B simple cycle CTGs is expected to reduce NOx
emissions when firing natural gas from a worst-case uncontrolled emission rate of 135 ppmdv at 15% O2,
equal to 0.50 lb/MMBtu, to 25 ppmdv at 15% O2 equal to 0.092 lb/MMBtu.
Although steam injection is a technically feasible NOx control option, steam injection is less frequently
used than water injection. Like the water injection systems, steam injection systems would include injection
nozzles, flow metering controls, pumps, hardware, and interconnecting piping from a water treatment
system to each CTG. In addition, a steam injection system would require a boiler to convert the
demineralized water to steam. This boiler may be a natural gas-fired boiler, or it may be placed in the CTG
flue gas outlet plenum to use waste heat from the CTG to create steam.
Table 7-2 is a summary of the capital costs for a steam injection system for each GE Model 7B simple cycle
CTG. These costs are based on Chapter 6 of the Gas Turbine ACT Document. All costs have been escalated
from 1990 to March 2020 dollars based on the CPI.
TABLE 7-2. Steam injection system capital costs for each GE Model 7B CTG.
Purchased Equipment Costs (PEC)
Steam Injection System $703,000 Based on $4,200 per gallon per minute (GPM) as steam
Water Treatment System $789,000 WTS = 43,900 x GPM0.5
Taxes and Freight $119,000 8% of the total system costs
Direct Installation Costs
Direct Costs $725,000 45% of Purchased Equipment Costs
Indirect Installation Costs
Indirect Costs $502,000 33% of the PEC and Direct Costs + $5,000
Contingency Costs $568,000 10% of the Sum of the PEC, Direct and Indirect Costs
TOTAL CAPITAL COST $3,406,000
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
2. Costs are based on the following combustion turbine and steam injection system design conditions:
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CTG Heat Input Capacity 912 MMBtu/hr
Natural Gas Heat Value 21,000 Btu per pound, HHV
Natural Gas Fuel Flow Rate 43,429 lb/hour
Steam-to-Fuel Ratio (Ω) 1.0 lb steam/lb fuel
Water Flowrate 87 gallons per minute (GPM)
Water Flowrate 4,558,800 gallons per year
Cost Escalation (Inflation) Factor 1.93 Escalated from Dec. 1990 to Mar. 2020 based on the CPI.
Table 7-3 is a summary of the annual costs and the cost effectiveness for a steam injection system for each
GE Model 7B simple cycle CTG.
The annual capital recovery cost is calculated as the product of the total capital cost of $3,406,000 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 1% loss
in CTG efficiency with steam injection and a natural gas cost of $3.00 per MMBtu. The steam injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
TABLE 7-3. Annual costs and cost effectiveness for a steam injection system for each GE
Model 7B simple cycle CTG.
Capital Recovery Cost $374,000 Based on the Total Capital Cost in Table 7-2.
Fuel Penalty Cost $24,000 1.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $95,900 1 lb steam per lb fuel and $0.02103/gal (see
Section 2.5).
Maintenance Cost The NOx ACT indicates no additional turbine
Plant Overhead $0 maintenance cost for steam injection.
General & Adm., Taxes, Insurance (GATI) $136,200 4% of Total Capital Cost
TOTAL ANNUAL COST $630,100
Emission Reduction 163.0 ton NOx/year
Cost Effectiveness $3,870 $ per ton of NOx controlled
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
From Table 7-3, even assuming a potential emission reduction of 163.0 tons per year based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
and a capacity factor of 10%, the use of steam injection on each GE Model 7B simple cycle CTG would
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have a cost effectiveness of $3,870 per ton of NOx controlled. This calculation result is conservative, as it
greatly overstates the achievable emission reduction.
In addition, the use of steam injection would consume 4.6 million gallons of water per year per unit. This
is a substantial amount of water in an arid region in which water is a valuable natural resource. Based on
these facts, the use of steam injection for the control of NOx emissions from the Kyrene Generating Station
Unit 5 and Unit 6 GE Model 7B simple cycle CTGs is not a feasible RACT option.
7.4 DLN Combustion.
SRP obtained from GE a budgetary estimate for proprietary DLN combustors, called DLN1+ technology,
for the GE Model 7001B combined cycle CTGs at SRP’s Santan Generating Station in 2011. Although the
applicability of the DLN1+ technology has not been confirmed for the Kyrene Unit 5 and Unit 6 CTGs, we
have conservatively assumed for purposes of this analysis that this DLN technology would reduce NOx
emissions from the Kyrene Unit 5 and 6 CTGs to less than 9 ppmdv at 15% O2, equal to a NOx emission
rate of 0.0331 lb/MMBtu.
For a maximum design heat input rate of 912 MMBtu per hour for each CTG and a maximum capacity
factor of 10%, the potential NOx emission reduction for the DLN1+ technology for the GE Model 7B simple
cycle CTGs at Kyrene Generating Station would be:
0.50 −0.0331 lb NOx 912 MMBtu 8,760 hr 1.0 ton NOx
Reduction = × × × × 0.1 = 186.5 ton/yr
MMBtu hr yr 2,000 lb NOx
GE provided a cost of $4,800,000 for the first CTG, and $4,000,000 for each additional unit, including
installation. GE has also indicated the need for a hazardous gas protection system at a cost of $325,000.
Therefore, the estimated total capital cost for two of the Santan CTGs would be $9,125,000, or an average
capital cost of $4,562,500 for each unit in 2011 dollars.
The costs for the DLN1+ technology for the slightly larger Kyrene Unit 5 and 6 CTGs were calculated
using the equipment costs for the Santan units adjusted using the six-tenth factor rule.
0.6 0.6
C7B = C7001B ൬S7B ൰ = $4,562,500 ൬912 800൰ = $4,936,000
S7001B
Where C7B = Cost for the Kyrene Unit 5 & 6 GE Model 7B CTGs
C7001B = Cost for the Santan Units 1 – 4 GE Model 7001B CTGs
S7B = Size for the Kyrene Unit 5 & 6 GE Model 7B CTGs = 912 MMBtu/hr
S7001B = Size for the Santan Units 1 – 4 GE Model 7001B CTGs = 800 MMBtu/hr
Substituting the per-unit average total capital cost of $4,562,500 for the Santan CTGs and the sizes of each
CTG into this equation, the resulting cost of the DLN1+ technology for each of the Kyrene Unit 5 and Unit
6 GE Model 7B simple cycle CTGs would be $4,936,000 in 2011 dollars.
Salt River Project RTP Environmental Associates, Inc.
NOx RACT Analysis for the Agua Fria and Kyrene Generating Stations. July 2020
216

Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in June 2011 has the same buying power as $1.14 in March 2020. The total capital
cost of DLN1+ technology for Units 5 and 6 at the Kyrene Generating Station in current dollars is
$5,627,000 per unit.
For this analysis, using a capital cost of $5,627,000 per unit and a CRF of 0.10979, the annualized capital
recovery cost would be $617,800. For a maximum NOx reduction of 186.5 tons per year, the cost
effectiveness for the DLN1+ technology would be $3,310 per ton of NOx controlled. This calculation result
is conservative, as it greatly overstates the achievable emission reduction. Based on these costs, the use of
the DLN1+ technology for the control of NOx emissions from the is not a feasible RACT option.
7.5 Selective Catalytic Reduction (SCR).
SCR systems have the capability to make substantial reductions in NOx emissions. For the Kyrene Unit 5
and Unit 6 CTGs, the use of SCR is expected to reduce NOx emissions by more than 90%, to a long-term
emission rate of 9 ppmvd at 15% O2, equal to 0.0331 lb/MMBtu. SCR systems for these simple cycle CTGs
would include a catalyst reactor housing, the catalyst and support matrix, an ammonia injection grid,
aqueous ammonia storage tanks, and ammonia metering equipment and controls. From the U.S. EPA’s
1999 document Air Pollution Control Technology Fact Sheet for Selective Catalytic Reduction, EPA-
452/F-03-032, SCR capital costs for large gas turbines range from $5,000 to $7,500 per MMBtu per hour
of heat input.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in December 1999 has the same buying power as $1.53 in March 2020. The low end
of U.S. EPA’s range of capital cost estimates is $7,650 per MMBtu/hr in March 2020 dollars.
Table 7-4 is a summary of a detailed analysis of the capital costs, annual costs, and cost effectiveness for
SCR systems for the Kyrene Unit 5 and Unit 6 GE Model 7B simple cycle CTGs based on a 93.3% SCR
control efficiency and a 10% capacity factor. The costs in in Table 7-4, other than the capital cost, are
based on Table 6-8 of the Gas Turbine ACT Document. Costs have been escalated from 1990 dollars to
March 2020 dollars based on the CPI.
TABLE 7-4. Capital costs, annual costs, and cost effectiveness for an SCR system for each
Kyrene Unit 5 and 6 simple cycle CTG based on a 10% capacity factor.
A. Total Capital Cost $6,977,000 = Based on the low estimate from EPA-452/F-03-032
.B. Direct Annual Costs, $/yr
1. Operating Labor $5,400 = (1.0 hr/8 hr-shift) x ($25.60/hr) x (876 hr/yr)
2. Supervisory Labor $800 = (0.15) x (Operating Labor)
3. Maint. Labor & Materials $19,500 = [(1,250 x TMW) + 25,800] x 0.1
4. Catalyst Replacement $61,600 = [(4,700 x TMW) + 37,200] x 0.1
5. Catalyst Disposal $3,400 = [(V) x ($15/ft3) x (.2638)] x 0.1
Salt River Project RTP Environmental Associates, Inc.
NOx RACT Analysis for the Agua Fria and Kyrene Generating Stations. July 2020
217

6. Ammonia $51,100 = (N) x ($360/ton) (NOx : NH3 ratio = 1:1)
9. Performance Loss $15,800 = (0.005)x(TMW)x($0.06/kWh)x(1,000 kW/MW)x(H)
C. Indirect Annual Costs, $/yr
1. Overhead $15,400 = (0.6) x (all labor and maintenance material costs)
2. Taxes, Insurance, Administra $279,100 = (0.04) x (total capital investment)
3. Capital Recovery $766,000
TOTAL ANNUAL COST $1,218,100
Emission Reduction 186.5 ton NOx/year
COST EFFECTIVENESS $6,530 $ per ton of NOx controlled
Footnotes
1. Except as noted, costs are based on the Gas Turbine ACT Document, with an escalation factor of 1.93 to
escalate from Dec. 1990 to Mar. 2020 based on the CPI.
2. TMW is turbine output in megawatts, V is catalyst volume in ft3, N is annual ammonia usage in tons
The average cost effectiveness of SCR systems for the GE Model 7B simple cycle CTGs would be $6,530
per ton of NOx controlled. Based on these costs, the use of SCR for the control of NOx emissions from the
Kyrene Unit 5 and Unit 6 GE Model 7B simple cycle CTGs is not a feasible RACT option.
7.6 Conclusions.
Table 7-5 is a summary of the available and technically feasible NOx RACT options for the Kyrene
Generating Station Unit 5 and Unit 6 GE Model 7B simple cycle CTGs, the potential emission reductions,
and the average cost effectiveness of each control option. The potential emission reductions and the
resulting cost effectiveness in Table 7-5 are based on a 10% capacity factor. Note that the potential NOx
emission reductions for each option are based on 199.7 tons per year for each uncontrolled CTG which
greatly overstates the actual emissions and the potential emission reductions. Even with these conservative
assumptions, no control options meet the cost effectiveness threshold of $2,300 per ton discussed in Section
2.6 of this report.
TABLE 7-5. NOx control options, emission reductions, and cost effectiveness for each Kyrene
Unit 5 and 6 simple cycle CTG based on a 10% capacity factor.
Emission Rate, Potential to Cost
NOx Control ppmdv at Emit Capital Cost Annual Cost Effectiveness,
Option
15% O2 ton/yr $ per ton
Worst-case 135 199.7
Uncontrolled CTG
Water Injection 25 36.7 $2,548,100 $614,000 $3,770
Steam Injection 25 36.7 $3,406,000 $630,100 $3,870
Salt River Project RTP Environmental Associates, Inc.
NOx RACT Analysis for the Agua Fria and Kyrene Generating Stations. July 2020
218

DLN Combustion 9 13.2 $5,627,000 $617,800 $3,310
Selective Catalytic
9 13.2 $7,414,000 $1,218,100 $6,530
Reduction (SCR)
Salt River Project RTP Environmental Associates, Inc.
NOx RACT Analysis for the Agua Fria and Kyrene Generating Stations. July 2020
219

Return to list of attachments
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
REGION IX AIR DIVISION
Technical Support Document
for
EPA’s Rulemaking
for the
Arizona State Implementation Plan
Maricopa County Air Quality Department
Rule 322
Power Plant Operations
Prepared by: Kevin Gong
December 11, 2019
220

RULE IDENTIFICATION
Agency Maricopa County Air Quality Department (MCAQD)
SIP Approved Rule 322 – Power Plant Operations
Rule Revised – October 17, 2007
Submitted - January 9, 2008
EPA Approved – October 14, 2009 (74 FR 52693)
Subject of this Rule 322 – Power Plant Operations
TSD Revised – November 2, 2016
Submitted – June 22, 2017
Completeness Complete by operation of law – December 22, 2017
Finding
BACKGROUND
The Maricopa County Air Quality Department (MCAQD) regulates Maricopa County and
the cities of Phoenix, Mesa, Scottsdale, Tempe, Chandler, Glendale, as well as 17 other
jurisdictions and unincorporated County lands. Part of the area regulated by MCAQD is
included in the Phoenix-Mesa area designated as nonattainment for ozone and classified
as Moderate for the 2008 8-hour National Ambient Air Quality Standard (NAAQS) (see 40
CFR 81.303, 81 FR 26699).
Rule 322, “Power Plant Operations,” regulates electric generating steam units and
turbines. The County identified ten facilities that are major sources of nitrogen oxides
(NOx), and with equipment subject to this rule.
Rule 322 was revised as part of the District’s process to ensure that its rules meet the
reasonably available control technology (RACT) requirements of Section 182(b) of the
Clean Air Act (CAA) for ozone nonattainment areas classified as Moderate. Appendix 1 of
the June 22, 2017 submission, Revisions To The State Implementation Plan Revision For
The Maricopa County Air Quality Department Ozone Rules Contained In The Arizona SIP,
titled Analysis Of Reasonably Available Control Technology For The 2008 8-Hour Ozone
National Ambient Air Quality Standard (NAAQS) State Implementation Plan (RACT SIP)
(“SIP Analysis”) contains the District’s analysis regarding whether Rule 322 implements
RACT levels of control.
RULE SUMMARY
Rule 322 regulates NOx, sulfur oxide, carbon monoxide, and particulate matter emissions
from electric steam generating units, cogeneration steam units, and turbines. It also
describes related recordkeeping, reporting, and monitoring requirements. Changes from
the approved SIP rule include:
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1. Expanded applicability to include units constructed after May 10, 1996, and
eliminated exemptions for units used at military facilities.
2. Added exemptions for units operating at or below 10 percent calendar year
annual capacity factor.
3. New definitions for “Emergency Standby Unit,” “Operating Day,” “Steady
State,” “Ultra Low Sulfur Diesel,” and “Waste Derived Fuel Gas.” Revised
definition for “Total Dissolved Solids.”
4. Clarification in section 302 for measurement periods temperature differential
in turbine units for good combustion practices. These requirements were
renumbered from 301.3 to 302. Requirements for cooling towers were
renumbered from 301.4 to 303.
5. Strengthened RACT emission limits for NOx that now apply to all units
(previously, the limits did not apply to units constructed or modified prior to
May 30, 1979). Gaseous fuel fired operations are limited to 42 ppmv, and
liquid fuel fired operations are limited to 65 ppmv.
6. Provisions for case-by-case RACT determinations by the Control Officer, which
if approved by the County, would exempt the facility from the NOx limits in
section 306, emissions control monitoring requirements in section 308, and
administrative requirements in section 400.
7. New administrative requirements were added to section 400, which had
previously been reserved. The administrative requirements generally consist
of compliance schedules for units to either demonstrate current compliance
with the rule’s requirements, or for non-compliant units to come into
compliance with those limits. This section also includes a schedule for removal
from service if the owner or operator chooses, and a schedule for emergency
standby units to request an exemption from the emission limits.
8. New recordkeeping and monitoring requirements are in sections 501.6 (for
CEMS to meet the good combustion evaluation requirements) and 501.7 (to
require maintaining records for low use units exempt in section 104.4 and for
NOx emission limits compliance for all applicable units).
9. Additional options for ultra low sulfur diesel fuel verification, and for waste
derived fuel gas sulfur verification.
10. An updated list of approved test methods for this rule.
EVALUATION CRITERIA
The following criteria were used to evaluate the submitted rule.
Enforceability
The Bluebook (Issues Relating to VOC Regulation Cutpoints, Deficiencies, and
Deviations, EPA, May 25, 1988) and the Little Bluebook (Guidance Document
for Correcting Common VOC & Other Rule Deficiencies, EPA Region 9, August
21, 2001) were used to help evaluate compliance with the CAA §110(a)(2)(A)
requirement for enforceability.
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Stringency
SIPs must require RACT for each category of sources covered by a Control
Technique Guideline (CTG) document as well as each major source of NOx or
VOC in ozone nonattainment areas classified as Moderate or above (see
sections 182(b)(2) and 182(f)). While there is no CTG for this source category,
the District has identified major sources of NOx covered by this rule within the
nonattainment area. Accordingly, the RACT requirement applies to these
major sources. The EPA has published an Alternative Control Techniques (ACT)
document titled, “NOx Emissions from Stationary Gas Turbines” (EPA 453/R-
93-007, January 1993) which describes available control techniques and their
estimated costs for gas turbine units. The EPA’s ACT document titled, “NOx
Emissions from Industrial, Commercial & Institutional Boilers” (EPA453/R-94-
022, March 1994) describes similar control techniques and cost guidance for
boiler units. These ACTs and other state and local rules for this category were
used to help evaluate Rule 322 against the RACT requirements of CAA
§182(b)(2) and §182(f).
SIP Relaxation
CAA §110(l) prohibits EPA from approving any SIP revision that would
interfere with any applicable requirement concerning attainment and
reasonable further progress (RFP) or any other applicable requirement of the
CAA. In addition, CAA §193 prohibits the modification of any SIP-approved
control requirement in effect before November 15, 1990, in a nonattainment
area, unless the modification insures equivalent or greater emission
reductions.
EPA EVALUATION
A summary of our evaluation of the three criteria follows.
Enforceability
Rule 322 applies to cooling towers, turbines, steam generating units, and
cogeneration units at electric utility facilities. Combustion units at nuclear
power plants and reciprocating internal combustion engines are exempt, while
low-use units operated less than 10% of the calendar year, units firing on
emergency fuel, units testing on emergency fuel, gas turbines used in fire-
fighting, flood control, or in research and development are partially exempt.
The exemptions for firing on emergency fuel are broad, and other similar
regulations provide limits for the length of emergency fuel use. Also, the
exemption for testing on emergency fuel could be interpreted to allow for an
exemption at all times, and not just during the 36 hours used for testing,
reliability, training, and maintenance. Beyond this emergency fuel use issue,
these applicability criteria are clear and establish which units must comply with
this rule. There are also several new definitions and terms in Rule 322 which
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improve clarity. We find these other general provisions to be clear, and do not
interfere with rule enforceability.
Section 300 contains the limits and requirements for controlling emissions
from applicable sources, including PM, CO, and NOx. The NOx limits at Section
306 allow for sources to either comply with the specified emission limits, or to
apply to the Air Quality Department for a case-by-case RACT analysis that
would be incorporated into the facility’s permit. The determination is made by
the Control Officer alone and therefore constitutes unacceptable Control
Officer discretion as outlined in EPA guidance. This is not an approvable
provision from the perspective of SIP enforceability, as the RACT requirement
in question would not be contained in the SIP itself. We discuss this issue
further below in our evaluation for RACT stringency, and in our description of
rule approvability issues.
Section 400 contains administrative requirements and compliance schedules
for units that are in compliance, units that are not in compliance, and for
emergency standby units. The compliance schedule for existing non-compliant
units allows for the Control Officer to extend the compliance schedule upon
request from the owner or operator with no constraints. This also constitutes
unacceptable Control Officer discretion.
Section 500 of the rule contains recordkeeping and reporting requirements for
all equipment subject to this rule, including requirements for units claiming
exemptions. These records include operating hour and days of operation for all
units, fuel use requirements and fuel switching records, CEMS records, records
demonstrating the maintenance of good combustion practices, and records for
annual capacity factor utilization and NOx emissions. All records shall be
retained for at least 5 years. Compliance determination for sulfur content in
fuels and for drift rate verification are adequate. The procedures for
compliance determination for PM, NOx and CO are not contained in this
section. They are established with the emission limits and requirements in
Section 300 “Standards.” We find these monitoring, recordkeeping, and
reporting requirements are adequate in supporting rule enforceability.
Stringency
Rule 322 establishes lower NOx emission limits for applicable units, of 42 ppmv
for gas fired units, and 65 ppmv for liquid fired units. These emission limits are
consistent with limits for stationary turbines (in use at power plants or
otherwise) in other jurisdictions needing to meet RACT, including units of all
sizes in the Imperial County Air Pollution Control District and in the Mojave
Desert Air Quality Management District, and for smaller units in the San
Joaquin Valley Air Pollution Control District, Ventura County Air Pollution
Control District, and the Yolo-Solano Air Quality Management District.
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These emission limits are not demonstrated to be suitable RACT limits for
steam generating electrical units. RACT limits for these units in these other
jurisdictions are commonly lower: at 30 ppmv for gas-fuel fired operations and
40 ppmv for liquid-fuel fired operations. The County has provided additional
information describing these units as operating at very low annual capacity
factors, which would exempt them from compliance with a RACT limit.
However, these units are not required under this rule or another enforceable
SIP-approved provision to continue operating at low capacity factors.
Moreover, this rule would apply to any future boilers that may be constructed
or operated in the County. Therefore, the rule does not ensure that RACT limits
will continue to apply to current or future major sources in the nonattainment
area. A suitable RACT limit for NOx must be included in this rule for these
sources.
Section 306 also allows for owners or operators to request an alternative RACT
determination from the Control Officer for units that they believe cannot meet
the limits set out in the rule. As noted above in our enforceability analysis, this
provision allows for facilities that must implement RACT to request a “case-by-
case reasonably available control technology analysis” to use other control
strategies to meet this rule’s NOx control requirements. There are no
evaluation criteria or provisions for the EPA to assess these case-by-case
determinations in order to assure that the approved limits constitute RACT
levels of control. As a result, this Control Officer discretion interferes with the
requirement to implement RACT for major sources and is an approvability
issue.
Finally, Rule 322 is lacking in any requirement for regular stack testing to
ensure that applicable emission units are complying with these requirements.
This leaves the emission limits in section 300 effectively unenforceable and is
also an approvability issue.
SIP Relaxation
While many of the provisions in this rule are unchanged or more stringent than
the SIP approved rule, the Control Officer discretion in section 306 potentially
would allow for applicable emission units to comply with limits, controls, or
requirements that are not as stringent as the existing limits or requirements
for NOx control. We propose to determine that our approval of the submittal
would not comply with CAA §§110(l) and 193 because (1) the proposed SIP
revision could interfere with the on-going process for ensuring that
requirements for RFP and attainment of the NAAQS are met, and (2) the
emission limits in the submitted rule are not necessarily more stringent than
the existing SIP-approved control requirements that they would replace.
225

RULE DEFICIENCIES
The following are deficiencies that the EPA has identified with Rule 322 that preclude full
approval of the rule into the SIP1:
1. Section 104.2 contains overly broad exemptions for units firing on emergency
fuel. This is a RACT approvability issue since other similar rules for this
category do not contain the broad exemptions for unlimited periods of gas
curtailment or delivery interruption. To be consistent with other RACT rules,
the District should also limit the total allowable length of emergency fuel
burning to be consistent with other jurisdictions (see, Imperial County APCD
Rule 400.1 Section D.3).
2. Section 104.3 allows units that only fire emergency fuel for 36 hours to be
exempted from certain emission limits. This section needs to be amended to
clarify the exemption is only valid during the 36 hours or less per year when
emergency fuel is used.
3. Sections 306.1 and 306.2 allow for an owner or operator to comply with the
rule by submitting a case-by-case RACT analysis that will be incorporated into
the permit. This effectively exempts the source from the rule’s NOx limits,
CEMS requirements, and administrative requirements. This conflicts with the
EPA’s current policy on Control Officer discretion. To be approvable for RACT,
the option to submit a case-by-case RACT analysis should be removed, or the
case-by-case RACT alternative must be submitted for SIP approval.
4. The RACT limits provided for NOx-emitting combustion units in sections 306.1
and 306.2 are appropriate for stationary turbines. However, Rule 322 also
applies to steam generating units. RACT limits for these types of units is
generally found to be more stringent (for example, limits in many other
jurisdictions are 30 ppmv for gas fuel fired units, and 40 ppmv for liquid fuel
fired units). The County must reduce the overall limit for all applicable units to
be at least as stringent at those demonstrated in EPA guidance or in other SIP-
approved regulations, or include a separate RACT limit applicable to steam
generating units. Alternatively, the County must provide a demonstration that
the existing limits, or other limits adopted in a modified rule, are appropriate
and constitute RACT for Maricopa County.
5. Section 402 describes the compliance schedules and requirements for NOx in
units that are found to be non-compliant. Owners and operators must comply
with section 402.2 Increments of Progress, or section 402.3 Removal From
Service. Increments of progress (i.e., compliance deadlines) may be extended
by the Control Officer as needed. This Control Officer discretion, which
conflicts with EPA’s current policy on Control Officer discretion, should be
1 See Letter from Doris Lo, U.S. EPA Region 9 to Philip A. McNeely, Maricopa County Air Quality
Department, “Re: EPA Comments on the Maricopa County Air Quality Department Rule 322 Power Plant
Operations” dated May 24, 2018.
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removed or appropriately constrained. Section 402.3 allows for the removal
from service process to last up to a total of two years, or more time if the
County did not act expeditiously on the permit revision. Units are exempt
from NOx limits during this time. The amount of time that these units are out
of compliance should be bounded and minimized, e.g. by providing a backstop
date by which all units must achieve compliance.
6. Rule 323, section 503.2 requires boilers of 100 MMBtu/hr or greater heat
input to conduct triennial stack tests. Rule 322 should require a similar or
more stringent requirement for all EGU boilers and turbines in the same size
category.
ADDITIONAL RECOMMENDATIONS FOR THE NEXT RULE REVISION
The following revisions were also identified in the May 24, 2018 letter. They are not
currently the basis for rule disapproval, but are recommended for the next time the rule
is amended.
1. Section 302 describes good combustion practices for turbines and states that
any of three practices listed in 302.1, .302.2, or 302.3 may be chosen. Section
302.3 says that if there is a pattern of non-compliance with the differential
temperature measurement as required in 302.1, the Control Officer may
require a Corrective Action Plan (CAP). This appears to allow a facility to
remain out of compliance with the good combustion practice requirement.
We recommend revising this section to indicate that the Control Officer shall
require the operator to submit a CAP.
2. Section 302 states that if the owner or operator is using a continuous
emission monitoring system (CEMS) or “other approved monitoring method,”
then the equipment is otherwise exempt from the requirements of 302.
However, this is problematic, as section 302.3 requires that a CAP must be
submitted to the Control Officer to remedy operation errors. It does not
appear that an owner or operator will need to take corrective action if a
CEMS-equipped unit detects operation error. Please include language that
states that a CEMS-equipped unit should take similar corrective action if an
operational error is detected. Section 302 also states that an owner or
operator of an applicable stationary gas turbine “shall” use good operational
practices, but then states that one of the following procedures “may” be
used. Please clarify that the second statement also shall require one of the
procedures listed in the subsections of Section 302.
3. Section 303.2 should be revised to include the units for total dissolved solids
(e.g., 20 mg/L).
4. Section 306 specifies a 30-day rolling average be used to determine
compliance with applicable NOx limits for units equipped with CEMS. This
averaging period is too long compared to the compliance determination
requirements if a facility was using standard source test methods. CEMS
determination requirements should at least match the requirements for
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source tests (1-hour sample time), and averaging could be conducted over a
24-hour rolling period (see, e.g., SIP-approved Ventura County APCD Rule 59,
section B.1.).
5. Section 308.1 uses the term “combustion control system” and Section 308.3
uses the term “emission processing equipment,” neither of which are defined
in this rule. We recommend adding these definitions.
6. Section 308.3 describes Operations and Maintenance (O&M) Plan
requirements for an Emission Control System. Operation & Maintenance plans
are required at section 308.2 to describe the function and maintenance of
monitoring equipment. Section 308.3b states that O&M plans shall be
submitted to the Control Officer for approval. Section 308.3e states that the
Control Officer may modify O&M plans. In both of these instances, there is no
discussion as to what criteria these plans or discretionary modifications are
intended to meet. We recommend adding such criteria.
7. Section 401 describes the compliance schedule for units that are currently
operating and determined to be compliant with NOx emission limits. NOx
facilities must submit a “Notification of Compliance” which must consist of
one of the two following options:
a. Demonstrate there was already a performance test and include the results
of said test. This test must have been conducted within the past five years.
Clarify what is intended by “performance test” in this context (e.g.
“performance stack test”).
b. Outline the timeline for a performance test. There are also no constraints
on how long an owner or operator might take to conduct this test after
submitting this “Notification of Compliance,” beyond indicating that a
timeline shall be included. Please include a limit for how long a timeline
may extend.
EPA ACTION
The issues described above in the “Rule Deficiencies” section preclude the approval of
this rule into the Arizona SIP. The County and State submitted a commitment letter to
address several of the deficiencies, but these commitments were not sufficient to allow
for the EPA to propose a conditional approval.2 Therefore, we recommend that the EPA
disapprove Rule 322.
This disapproval, if finalized, would trigger highway sanction and FIP clocks because this
rule is required to implement RACT for major sources of NOx under Section 182(f).
2 Letter from Philip A. McNeely, Maricopa County Air Quality Department, to Misael Cabrera, Arizona
Department of Environmental Quality “Re: Request for Submittal of Letter of Commitment for Conditional
Approval of the Maricopa County Reasonably Available Control Technology (RACT) State Implementation
Plan (SIP)” dated January 28, 2019.
228

REFERENCES
1. “Issues Relating to VOC Regulation Cutpoints, Deficiencies, and Deviations,”
(a.k.a., Bluebook) EPA OAQPS, May 25, 1988.
2. “Guidance Document for Correcting Common VOC & Other Rule Deficiencies,”
(a.k.a., Little Bluebook), EPA Region 9, August 21, 2001.
3. “NOx Emissions from Stationary Gas Turbines,” EPA 453/R-93-007, January 1993.
4. “NOx Emissions from Industrial, Commercial & Institutional Boilers,” EPA453/R-
94-022, March 1994.
5. “De Minimis Values for NOx RACT,” Memorandum from G. T. Helms, Group
Leader, Ozone Policy and Strategies Group, U.S. EPA, January 1, 1995.
6. “Cost-Effective Nitrogen Oxides (NOx) Reasonably Available Control Technology
(RACT),” Memorandum from D. Ken Berry, Acting Director, Air Quality
Management Division, US. EPA, March 16, 1994.
7. “Supplemental Table 1. Major Sources of NOx and VOC in Maricopa County,”
attachment to e-mail titled “Maricopa County RACT SIP: EPA Conference Call,”
from Johanna Kuspert, Maricopa County Air Quality Department, dated January 3,
2019.
8. Imperial County Air Pollution Control District Rule 400.1, “Stationary Gas
Turbine(s) – Reasonably Available Control Technology (RACT)”, as amended
February 23, 2010 and submitted to EPA on July 20, 2010.
9. “Imperial County Air Pollution Control District - Appendix A - Rule 400.1
“Stationary Gas Turbines” Cost Effectiveness Analysis,” dated January 26, 2010.
10. Imperial County Air Pollution Control District Rule 400.2, “Boilers, Process Heaters
and Steam Generators”, as amended February 23, 2010 and submitted to the EPA
on July 20, 2010.
11. Mojave Desert Air Quality Management District Rule 1159, “Stationary Gas
Turbines”, as amended September 28, 2009 and submitted to the EPA on May 17,
2010.
12. Mojave Desert Air Quality Management District Rule 1157, “Boilers & Process
Heaters”, as amended May 19, 1997 and submitted to the EPA on August 1, 1997.
13. San Joaquin Valley Air Pollution Control District Rule 4306, “Boilers, Steam
Generators, and Process Heaters – Phase 3,” amended on October 16, 2008 and
submitted to the EPA on March 17, 2009.
14. San Joaquin Valley Air Pollution Control District Rule 4703, “Stationary Gas
Turbines,” amended on September 20, 2007 and submitted to the EPA on March
7, 2008.
15. Ventura County Air Pollution Control District Rule 74.15.1, “Boilers, Steam
Generators, and Process Heaters,” amended on June 23, 2015 and submitted to
the EPA on November 13, 2015.
16. Ventura County Air Pollution Control District Rule 74.23, “Stationary Gas
Turbines,” amended on January 8, 2002 and submitted to the EPA on March 15,
2002.
229

17. Yolo-Solano Air Quality Management District Rule 2.27, “Industrial, Institutional,
and Commercial Boilers, Steam Generators, and Process Heaters,” amended
August 14, 1996 and submitted to the EPA on October 18, 1996.
18. Yolo-Solano Air Quality Management District Rule 2.34, “Stationary Gas
Turbines,” amended November 12, 2014 and submitted to the EPA on June 26,
2015.
230

Return to list of attachments
Reasonably Available Control Technology
(RACT) Analysis.
RACT Analysis for the control of nitrogen oxides (NOx) emissions from the
Arizona Public Service Ocotillo and West Phoenix Power Plants.
October, 2018
Prepared for:
Arizona Public Service
400 North 5th Street
Phoenix, Arizona 85004
www.aps.com
Prepared By:
RTP ENVIRONMENTAL ASSOCIATES INC.
304-A West Millbrook Rd.
Raleigh, NC 27609
231

Table of Contents
1.0 Introduction. ........................................................................................................ 5
2.0 Reasonably Available Control Technology. ..................................................... 6
3.0 RACT Affected Units. ......................................................................................... 8
4.0 NOx Emissions from Combustion Turbines. .................................................. 10
5.0 Available and Technically Feasible Control Technologies. .......................... 11
5.1 Available Control Technologies. ................................................................................................ 11
5.2 Technically Feasible Control Technologies. .............................................................................. 11
5.2.1 Diffusion Flame Combustion. ........................................................................................... 11
5.2.2 Water and Steam Injection. ............................................................................................... 11
5.2.3 Dry Low NOx (DLN) Combustion. .................................................................................. 12
5.2.4 Catalytic Combustion. ...................................................................................................... 12
5.2.5 Selective Catalytic Reduction (SCR). ............................................................................... 13
5.2.6 Selective Non-Catalytic Reduction (SNCR). .................................................................... 14
5.2.7 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™). .................................... 14
5.3 Summary of the Technically Feasible Control Technologies and the Achievable NOx Emission
Rates. .......................................................................................................................................... 15
6.0 Evaluation of the Technically Feasible Controls. .......................................... 16
6.1 Cost Effectiveness. ..................................................................................................................... 16
6.2 Potential Emission Reductions. .................................................................................................. 16
7.0 Westinghouse Model 501-AA Simple Cycle Combustion Turbines. ............ 17
7.1 Water Injection. .......................................................................................................................... 17
7.1.1 Cost, Social, and Environmental Impacts. ........................................................................ 18
7.2 Steam Injection. .......................................................................................................................... 19
7.2.1 Cost, Social, and Environmental Impacts. ........................................................................ 21
7.3 Selective Catalytic Reduction (SCR). ......................................................................................... 22
7.3.1 Cost, Social, and Environmental Impacts. ........................................................................ 22
8.0 RACT Cost Effectiveness................................................................................. 24
9.0 Conclusion. ....................................................................................................... 26
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Tables
TABLE ES-1. NOx control options, emission reductions, and cost effectiveness for each
Westinghouse 501-AA simple cycle CTGs based on a 10% capacity factor. ...................................... 4
TABLE 3-1. General specifications of the affected units in this RACT analysis. ................................... 8
TABLE 3-2. Actual capacity factors and actual NOx emissions for the affected units. .......................... 8
TABLE 3-3. Current baseline NOx emission rates for the Westinghouse Model 501-AA CTGs. .......... 9
TABLE 5-1. Technical feasibility of the available NOx control technologies. ...................................... 15
TABLE 5-2. Achievable NOx emission rates for the available NOx control technologies. ................... 15
TABLE 6-1. Potential NOx emissions for each Westinghouse Model 501-AA simple cycle CTG for the
available control technologies based on an allowable capacity factor of 10%. ................................. 16
TABLE 7-1. Water injection system capital costs for each Westinghouse Model 501-AA CTG. ........ 17
TABLE 7-2. Annual costs and cost effectiveness for a water injection system for each
Westinghouse Model 501-AA simple cycle CTG. ............................................................................. 18
TABLE 7-3. Water injection system capital costs for each Westinghouse Model 501-AA CTG. ........ 20
TABLE 7-4. Annual costs and cost effectiveness for a steam injection system for each
Westinghouse Model 501-AA simple cycle CTG. ............................................................................. 21
TABLE 7-5. Capital costs, annual costs, and cost effectiveness for a selective catalytic reduction
(SCR) system for each Westinghouse Model 501-AA simple cycle CTG......................................... 23
TABLE 8-1. RACT cost effectiveness thresholds for several states and other jurisdictions. ................ 25
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Executive Summary.
The Arizona Public Service (APS) Ocotillo and West Phoenix Power Plants are located in Maricopa
County which is classified as a moderate nonattainment area for ozone. Maricopa County Air Pollution
Control Regulations Rule 322 requires the use of Reasonably Available Control Technology (RACT) for
the control of nitrogen oxides (NOx) emissions from power plants in the county. The units evaluated in
this RACT analysis include the Ocotillo Westinghouse 501-AA simple cycle combustion turbine
generator (CTG) Units GT1 and GT2 and the West Phoenix Westinghouse 501-AA simple cycle Units
GT1 and GT2. Maricopa County Air Quality Department (MCAQD) Maricopa County Air Pollution
Control Regulations (MCAPCR) Rule 322 Section 104.4 presently contains an exemption from NOx
limitations for CTG units that operates at or below 10 percent calendar year annual capacity factor. This
RACT Analysis was performed to provide justification for this exemption for West Phoenix units GT1
and GT2 and Ocotillo units GT1 and GT2.
Table ES-1 is a summary of the available and technically feasible NOx RACT options for the
Westinghouse 501-AA simple cycle CTGs, the potential emission reductions, and the cost effectiveness
of each control option. The potential emission reductions and the resulting cost effectiveness in Table
ES-1 are based on enforceable permit limits which limit the allowable operation of each CTG to a
capacity factor of 10%, equal to operation of each CTG up to 876 hours per year at the maximum heat
input rate of 825 mmBtu per hour. This would limit natural gas consumption for each simple cycle CTG
to 722,700 mmBtu per year.
TABLE ES-1. NOx control options, emission reductions, and cost effectiveness for each
Westinghouse 501-AA simple cycle CTGs based on a 10% capacity factor.
NOx Control Emission Rate, Emission Capital Annual Cost
Option ppmdv at Reduction, Cost Cost Effectiveness,
15% O2 ton/yr $ per ton
Water Injection 25 104 $2,478,000 $1,098,100 $10,570
Steam Injection 25 104 $3,581,000 $1,095,300 $10,540
Selective Catalytic
9 125 $6,002,000 $1,949,400 $15,570
Reduction (SCR)
The U.S. EPA has defined RACT as “the lowest emission limitation that a particular source is capable of
meeting by the application of control technology that is reasonably available considering technological
and economic feasibility.” Based on EPA’s guidance and analysis of the control options contained
herein, none of the NOx control options for the Westinghouse Model 501-AA simple cycle CTGs were
determined to be feasible RACT options.
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1.0 Introduction.
This document is a Reasonably Available Control Technology (RACT) Analysis for the control of
nitrogen oxides (NOx) emissions from the Arizona Public Service (APS) Ocotillo and West Phoenix
Power Plants. The Ocotillo and West Phoenix Power Plants are both located in Maricopa County which
is classified as a moderate nonattainment area under the 2008 and 2015 ozone standards. As part of the
moderate classification, Maricopa County Air Quality Department (MCAQD) Maricopa County Air
Pollution Control Regulations (MCAPCR) Rule 322 requires RACT level of control for oxides of
nitrogen (NOx) emissions from power plant operations in the county. Because the APS Ocotillo and West
Phoenix Power Plants have specifically identified emissions units in Rule 322, the generating units at
these plants are subject to RACT requirements.
The units evaluated in this RACT analysis include the Ocotillo Westinghouse 501-AA simple cycle CTG
Units GT1 and GT2 and the West Phoenix Westinghouse 501-AA simple cycle Units GT1 and GT2. All
four units fire only natural gas. All four units are normally used for intermittent and peak load capacity
during periods of high system load requirements and therefore have low annual utilization or capacity
factors. The low utilization of these units has a significant impact on the feasibility of RACT options.
Note that the new General Electric LMS 100 simple cycle combustion turbine generators (CTGs) at the
Ocotillo Power Plant and West Phoenix Units 3, 4, 5A, and 5B are subject to NOx emission limitations
more stringent than the RACT limit in Rule 322, and therefore, already meet RACT requirements. West
Phoenix Units 1 and 2 require a case-by-case RACT analysis and will be submitted in a separate analysis.
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2.0 Reasonably Available Control Technology.
The Code of Federal Regulations, 40 CFR § 51.908 specifies that the attainment demonstration
requirements of section 182 of the Clean Air Act (CAA) apply to areas classified as moderate, serious,
severe, or extreme nonattainment areas. One of the requirements specified in 40 CFR § 51.912 is a RACT
state implementation plan (SIP) submission implementing CAA § 182 (b)(2) and (f). Reasonably
available control technology is defined in 40 CFR § 51.100(o) as:
(o) Reasonably available control technology (RACT) means devices, systems, process
modifications, or other apparatus or techniques that are reasonably available taking into account:
(1) The necessity of imposing such controls in order to attain and maintain
a national ambient air quality standard;
(2) The social, environmental, and economic impact of such controls; and
(3) Alternative means of providing for attainment and maintenance of such
standard. (This provision defines RACT for the purposes of §51.341(b)
only.)
The U.S. Environmental Protection Agency has defined RACT in the “NOx Supplement” implementing
the 1990 CAA amendments as “the lowest emission limitation that a particular source is capable of
meeting by the application of control technology that is reasonably available considering technological
and economic feasibility” (44 FR 53762; September 17, 1979). The RACT process determines and then
requires the use of reasonable available controls to limit emissions. These requirements identify the
lowest emission limit that a source is capable of meeting after considering technological and economic
feasibility. For existing units, a RACT analysis must consider the site-specific technological and
economic impacts of controls. As the EPA observed in evaluating El Dorado County’s RACT SIP:
“RACT allows for consideration of the economic impact of the controls. Therefore, if a certain
type of emission control or emission limitation is determined to be too costly in light of the
amount of emission reduction it achieves, that control might not be considered RACT. Also, as
economic factors may vary within a State and between different States, a control technology or
emission limitation approved as RACT in one location does not necessarily define RACT for
another location.”1
Thus, a RACT analysis is based on the evaluation of the following criteria for each emissions unit or for
each specific type of emissions unit:
1. A review of available and technically achievable control technologies and the achievable
emissions reduction.
1 Technical Support Document for EPA’s Notice of Proposed Rulemaking for the California State Implementation
Plan, EPA’s Evaluation of El Dorado County Air Quality Management District RACT SIP Update Analysis Staff
Report,” EPA Region 9 Air Division, December 15, 2006.
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2. The cost effectiveness of the control option expressed in dollars per ton ($/ton).
3. If applicable, other potential social and environmental impacts of the control option.
For this analysis, the U.S. EPA’s general approach in the Alternative Control Techniques (ACT)
documents has been used for the combustion turbines evaluated in this analysis.2 The ACT documents
are the primary references used by the state and local agencies in developing NOx RACT requirements.
In addition to the ACT documents, vendor information, unit performance, EPA information, and other
technical sources were reviewed to develop RACT determinations. Historical cost information is adjusted
using the consumer price index (CPI) published by Bureau of Labor Statistics.
2 Available at the EPA’s website: http://www3.epa.gov/ozonepollution/SIPToolkit/ctgs.html.
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3.0 RACT Affected Units.
The units evaluated in this analysis include the Ocotillo simple cycle combustion (or gas) turbine
generators GT1 and GT2 and the West Phoenix simple cycle combustion turbine generators (CTG) Units
GT1 and GT2. All four (4) units fire only natural gas. The new General Electric LMS 100 simple cycle
combustion turbine generators (CTGs) at the Ocotillo Power Plant and West Phoenix Units 3, 4, 5A, and
5B are subject to NOx emission limitations more stringent than the RACT limit in Rule 322, and
therefore, already meet RACT. West Phoenix Units 1 and 2 require a case-by-case RACT analysis and
will be submitted in a separate analysis.
Table 3-1 is a summary of the general specifications for the affected units.
TABLE 3-1. General specifications of the affected units in this RACT analysis.
Installation Capacity,
Unit Type Manufacturer Model
Date MW(e)
Ocotillo GT1 Simple Cycle Westinghouse 501-AA 1972 55
Ocotillo GT2 Simple Cycle Westinghouse 501-AA 1972 55
West Phoenix GT1 Simple Cycle Westinghouse 501-AA 1972 55
West Phoenix GT2 Simple Cycle Westinghouse 501-AA 1972 55
Table 3-2 is a summary of the capacity factor and actual NOx emissions for each affected unit for calendar
years 2015, 2016 and 2017. Note from Table 3-2 that the simple cycle CTGs have had capacity factors
less than 5% in the past three years. The fact that these affected units are low utilization units has a direct
bearing on the feasibility of RACT controls on these units and is an important factor in this RACT
analysis.
TABLE 3-2. Actual capacity factors and actual NOx emissions for the affected units.
Capacity Factor*, % NOx Emissions, ton/year
Unit
2015 2016 2017 2015 2016 2017
Ocotillo GT1 0.1% 0.3% 1.8% 3.1 6.2 33.5
Ocotillo GT2 0.1% 0.3% 2.3% 3.3 7.4 35.5
West Phoenix GT1 0.1% 0.4% 0.5% 2.7 9.7 10.7
West Phoenix GT2 0.2% 0.4% 3.1% 3.4 9.3 52.1
*- Based on total actual electrical output divided by potential electrical output
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Table 3-3 is a summary of the current baseline NOx emission rates for the Westinghouse Model 501-AA
simple cycle CTGs. Note that for the Westinghouse simple cycle CTGs, there are two test conditions:
with and without evaporative cooling. Operation with evaporative cooling can reduce NOx emission rates
by cooling and humidifying the inlet combustion air. Because these simple cycle CTGs are peaking units
that normally operate more during hot summer days when evaporative cooling is effective and needed for
peak power conditions, much of the typical operation of these CTGs is with evaporative cooling.
However, since operation of these CTGs without evaporative cooling typically occurs in cooler months
which would also reduce NOx emissions, these tests are representative of the current emissions from these
units.
TABLE 3-3. Current baseline NOx emission rates for the Westinghouse Model 501-AA CTGs.
Load NOx Emission Rate
Unit Test Date Test Conditions
ppmdv @
MW lb/mmBtu
15% O2
WPPP GT1 8/28/2008 50.0 93 0.34 With Evaporative Cooling
WPPP GT2 8/28/2008 50.0 91 0.34 With Evaporative Cooling
OPP GT1 10/24/2003 55.0 126 0.46 With Evaporative Cooling
Average 103 0.38
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4.0 NOx Emissions from Combustion Turbines.
Nitrogen oxides (NOx) consist of both nitrogen oxide (NO), and nitrogen dioxide (NO2). During
combustion, NO typically accounts for about 50 - 90% of the total NOx emissions. However, since NO is
converted to NO2 in the atmosphere, the mass emission rate of NOx is usually reported as NO2.
NOx is formed during combustion of natural gas in the affected combustion turbines through three
mechanisms;
1. Thermal formation,
2. Fuel formation,
3. Prompt formation.
Of these three formation mechanisms, thermal formation or thermal NOx is expected to represent at least
70% of the total NOx formation. Thermal NOx results from the high temperature oxidation of nitrogen
(N2) and oxygen (O2). In this mechanism, N2 is supplied from air, which is 78% N2 by volume. The
thermal NOx reactions are described by the Zel’dovich mechanism as follows:
N2 + O ↔ NO + N (1)
N + O2 ↔ NO + O (2)
N2 + O2 ↔ 2NO (1) Overall
The first step is rate limiting due to its high activation energy. As a result, thermal NOx requires high
temperatures to proceed. Thermal NOx formation increases exponentially with temperature, becoming
significant at temperatures above approximately 2,800 °F. Because thermal NOx formation increases
exponentially with temperature and because thermal NOx accounts for a large share of the total NOx
emissions, combustion control systems which reduce peak flame temperatures are often effective NOx
controls.
Fuel NOx results from the oxidation of organic nitrogen compounds in the fuel. Because fuel bound
nitrogen is more easily converted to NOx during combustion, nitrogen levels in fuel can have a significant
impact on NOx formation. However, since natural gas has only trace organic nitrogen compounds, fuel
NOx formation is expected to be very small for these natural gas-fired CTGs.
Prompt NOx is formed by the reaction of hydrocarbon radicals with atmospheric nitrogen to produce
hydrogen cyanide (HCN) and ultimately NOx through a complex series of gas phase reactions. Prompt
NOx is expected to account for 20 – 30% of the total NOx emissions. Like thermal NOx emissions,
prompt NOx formation can be reduced through combustion controls which reduce peak flame
temperatures.
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5.0 Available and Technically Feasible Control
Technologies.
The RACT evaluation process starts with identifying available control technologies for the source. The
available controls are then reviewed to determine controls which are technically feasible control options.
5.1 Available Control Technologies.
Based on a review of recent BACT determinations from the U.S. EPA’s RACT/BACT/LAER
Clearinghouse and a literature review including the U.S. EPA’s Alternative Control Techniques
Document - NOx Emissions from Stationary Gas Turbines, January 1993, and the U.S. EPA’s
Compilation of Air Pollutant Emission Factors AP-42, Chapter 3.1, Stationary Gas Turbines, April 2000,
the following are available NOx control technologies:
1. Diffusion Flame Combustion with
a. Water Injection,
b. Steam Injection,
2. Dry low NOx (DLN) Combustion,
3. Catalytic Combustion,
4. Selective Catalytic Reduction (SCR),
5. Selective Non-Catalytic Reduction (SNCR).
6. EMx™ Catalytic Absorption Process (EMx or SCONOx™),
The first three (3) control technologies are combustion control technologies. The last three (3)
technologies are post combustion flue gas treatment technologies.
5.2 Technically Feasible Control Technologies.
5.2.1 Diffusion Flame Combustion.
The Westinghouse Model 501-AA simple cycle CTGs utilize diffusion flame combustion. In a diffusion
flame combustor, air from the turbine compressor discharge is mixed with fuel in the flame zone at a near
stoichiometric ratio. The fuel/air mixing and combustion take place simultaneously in the primary
combustion zone. This results in a stable flame but also results in high flame temperatures and high NOx
emission rates.
5.2.2 Water and Steam Injection.
NOx emissions from diffusion flame combustors can be reduced by injecting water or steam into the
combustion zone. Water is an inert substance in the combustion process which lowers combustion
temperature and therefore reduces thermal NOx formation. Steam or water injected into the combustion
zone acts as a heat sink which lowers peak flame temperatures. Even evaporative cooling, a technique for
increasing turbine output during hot dry conditions, can lower NOx emissions through this mechanism.
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Water or steam injection will generally achieve control efficiencies of at least 70% when firing natural
gas. Although water and steam injection cannot be applied to all CTGs, the use of water and steam
injection is generally considered technically feasible control technologies for the affected CTGs. For all
of the affected units, both water and steam injection are expected to achieve a long term NOx emission
rate of 25 ppmvd at 15% O2, equal to 0.0921 lb/mmBtu. In addition water injection is expected to result
in an 11% increase in power output, but it is also expected to result in a heat rate penalty (a loss of
thermal efficiency) of 3%. The use of steam injection is also expected to result in an 11% increase in
power output, and steam injection would actually improve unit heat rate by 3.3%.
5.2.3 Dry Low NOx (DLN) Combustion.
Dry Low NOx (DLN) combustion for CTGs is a staged combustion system which reduces peak flame
temperatures and reduces thermal and prompt NOx formation. Modern DLN systems lower the
combustion temperature using lean mixtures of air and/or fuel staging. In a typical DLN combustor, air
and fuel are mixed in a premix zone. The premixed air/fuel mixture is then ignited in the flame zone. In
DLN combustors, the excess air acts as a heat sink to lower combustion temperatures.
There are two types of DLN combustors. Two stage lean/lean combustors involve fuel stage and
premixed combustors in which each stage burns lean. These DLN combustors lower NOx emissions by
reducing peak flame temperatures and providing uniform combustion with minimal hot spots. Two stage
rich/lean combustors use air stage and premixed combustors where the primary zone is operated fuel rich
and the secondary zone is operated fuel lean. In the primary zone, the rich mixture produces lower
temperatures and decreases the amount of oxygen available for NOx formation. Exhaust from the primary
zone is quenched with air in the secondary zone. Combustion of the pre-ignited rich mixture is completed
in the secondary fuel lean zone which reduces NOx emissions by reducing combustion temperature.
APS consulted the original equipment manufacturer and received the following analysis. While DLN
combustion is capable of achieving very low NOx emission rates, especially on new CTGs, because
combustion turbines are complex internal combustion engines, DLN combustion is not applicable to all
CTGs. The Westinghouse 501-AA CTGs have turbine inlet temperatures (TIT) after the compressor
stages of less than 1,100 °F. The fuel/air mixture in the turbine is already too lean to be further reduced
using DLN combustion and also maintain a constant, safe, and stable flame. Therefore, DLN combustion
is not a technically feasible control technology for the Westinghouse 501-AA CTGs.
5.2.4 Catalytic Combustion.
Catalytic combustion involves the use of a catalyst to reduce combustion temperatures and NOx
emissions. In a catalytic combustor, fuel and air are premixed and passed through a catalyst bed. In the
bed, the mixture oxidizes at reduced temperatures. The reduced temperatures have the potential to reduce
NOx formation to approximately 3 - 5 ppm. However, the cooler combustion temperatures may decrease
the Carnot efficiency of the CTGs by approximately 15%, since the efficiency for converting heat into
mechanical energy is determined by the temperature difference between heat source and sink.
While catalytic combustion has the potential for application to many combustor types, the catalyst has a
limited operating temperature and pressure range, and the catalyst has the potential to fail when subjected
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to the extreme temperature and pressure cycles that occur in CTGs. Commercial acceptance of catalytic
combustion by gas turbine manufacturers and by power generators has been slowed by the need for
durable substrate materials. Of particular concern is the need for catalyst substrates which are resistant to
thermal gradients and thermal shock.3
Catalytic combustors have not been commercialized for large scale industrial gas turbines. Much of the
development of catalytic combustors has been limited to bench-scale tests of prototype combustors.
Catalytica, Inc., (now owned by Renegy) developed Xenon Cool Combustion, a catalytic technology that
combusts fuel flamelessly. Other company’s such as Precision Combustion Inc. and Catacel™ have
patented technologies for catalytic combustors for gas turbines. However, we are not aware of any
technologies commercially available for large industrial turbines. Therefore, this technology is not
technically feasible for these CTGs.
5.2.5 Selective Catalytic Reduction (SCR).
Selective Catalytic Reduction (SCR) is a post combustion flue gas treatment for controlling NOx
emissions which uses an ammonia (NH3) injection system and a catalytic reactor. SCR systems utilize an
injection grid which disperses ammonia in the flue gas upstream of the catalyst. NH3 reacts with NOx in
the presence of the catalyst to form nitrogen (N2) and water according to the following equations:
4NH3 + 4NO + O2 → 4N2 + 6H2O
4NH3 + 2NO2 + O2 → 3N2 + 6H2O
2NH3 + NO2 + NO → 2N2 + 3H2O
Catalysts are substances which evoke chemical reactions that would otherwise not take place by providing
a reaction mechanism that has a lower activation energy than the uncatalyzed mechanism. For SCR, the
catalyst is usually a ceramic noble metal, a base metal (titanium or vanadium) oxide, or a zeolite-based
material. To achieve optimum long-term NOx reductions, SCR systems must be properly designed for
each application. In addition to critical temperature considerations, the ammonia injection rate must be
carefully controlled to maintain an NH3/NOx molar ratio that effectively reduces NOx. Excessive
ammonia injection will result in ammonia emissions, called ammonia slip.
SCR has the capability to make substantial reductions in NOx emissions. For these CTGs, the use of SCR
is expected to reduce NOx emissions by 90% or even more, to a long-term emission rate of 9 ppmvd at
15% O2, equal to 0.0331 lb/mmBtu. Even lower NOx emission rates could be achieved by combining
SCR with water or steam injection.
3 R.E. Hayes and S.T. Kolaczkowski, Introduction to Catalytic Combustion (Amsterdam: Gordon and Breach
Science Publishers, 1997); E.M. Johansson, D. Papadias, P.O. Thevenin, A.G. Ersson, R. Gabrielsson, P.G. Menon,
P.H. Bjornbom and S.G. Jaras, “Catalytic Combustion for Gas Turbine Applications,” Catalysis 14 (1999): 183-235.
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5.2.6 Selective Non-Catalytic Reduction (SNCR).
In a selective non-catalytic reduction (SNCR) control system, urea or ammonia is injected into boilers
where the flue gas temperature is approximately 1,600 °F to 2,100 °F. At these temperatures, urea
[CO(NH2)2] or ammonia reacts with NOx forming elemental nitrogen and water without the need for a
catalyst. The overall NOx reduction reactions are similar to those for SCR. Multiple injection points are
required to thoroughly mix the reagent into the boiler furnace. The limiting factor for a SNCR system is
the ability to contact the NOx with the reagent without resulting in excessive ammonia slip and without
excessive ammonia decomposition before the NOx emissions can be reduced.
SNCR has been widely used in circulating fluidized bed (CFB) boilers. However, the time and
temperature range for SNCR is not compatible with gas turbines. We are not aware of the application of
SNCR to any gas turbine either in the U.S. or worldwide. Therefore, SNCR is not a technically feasible
control technology for the affected CTGs.
5.2.7 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™).
EMx™ Catalytic Absorption/Oxidation (the second-generation of the SCONOx™ NOx Absorber
technology), available through EmeraChem, is based on a proprietary catalytic oxidation and absorption
technology. EMx™ uses a potassium carbonate (K2CO3) coated catalyst to reduce NOx and CO
emissions from natural gas fired CTGs. The catalyst oxidizes carbon monoxide (CO) to carbon dioxide
(CO2), and nitric oxide (NO) to nitrogen dioxide (NO2). The NO2 absorbs onto the catalyst to form
potassium nitrite (KNO2) and potassium nitrate (KNO3). Dilute hydrogen gas is periodically passed
across the surface of the catalyst to regenerate the K2CO3 catalyst coating. The regeneration cycle
converts KNO2 and KNO3 to K2CO3, water (H2O), and elemental nitrogen (N2). This makes the K2CO3
available for further absorption and the water and nitrogen are exhausted.
ABB Alstom Power purchased a proprietary technology called SCONOx™ from Goal Line
Environmental Technologies. A SCONOx™ system has been in operation since December of 1996 on
the 30 MW Sun Law Energy Federal cogeneration plant in Vernon, California. Since August of 1999,
SCONOx has been in operation on a 5 MW cogeneration plant at Genetics Institute in Andover,
Massachusetts. The Redding Electric Utility in Redding, California installed a SCONOx™ system on a
43 MW combined cycle plant in 2002. ABB Alstom Power subsequently completed design of a scaled-
up SCONOx™ system for 100 MW and greater combined cycle gas turbines.
A significant advantage of SCONOx™ is that it does not require ammonia or urea as a reagent. However,
SCONOx™ is designed for operation at temperatures of 300 °F to 700 °F. Therefore, SCONOx™ has
potential application to combined cycle and cogeneration gas turbines which have lower exhaust gas
temperatures than simple cycle CTs. This operating range is too low for the exhaust gas temperatures
from the simple cycle CTGs. Further, SCONOx™ is expected to achieve controlled NOx emission rates
similar to SCR systems, but the costs are expected to be higher. Finally, SCONOx™ has a limited
number of current commercial and industrial scale applications in the U.S. For these reasons,
SCONOx™ is not considered feasible for this RACT analysis.
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5.3 Summary of the Technically Feasible Control Technologies and
the Achievable NOx Emission Rates.
Table 5-1 is a summary of the technical feasibility of the available NOx control technologies for the
Westinghouse Model 501-AA simple cycle CTGs. Table 5-2 is a summary of the expected achievable
NOx emission rates.
TABLE 5-1. Technical feasibility of the available NOx control technologies.
NOx Control Option Technical Feasibility
Water Injection Feasible
Steam Injection Feasible
Dry low NOx (DLN) Combustion Infeasible
Catalytic Combustion Infeasible
Selective Catalytic Reduction (SCR) Feasible
Selective Non-Catalytic Reduction (SNCR) Infeasible
EMx™ or SCONOx™ Catalytic Absorption Infeasible
TABLE 5-2. Achievable NOx emission rates for the available NOx control technologies.
NOx Emission Rate
NOx Control
Option ppmvd at
lb/mmBtu
15% O2
Water Injection 25 0.0921
Steam Injection 25 0.0921
Selective Catalytic Reduction (SCR) 9 0.0331
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6.0 Evaluation of the Technically Feasible Controls.
6.1 Cost Effectiveness.
The RACT evaluation includes an evaluation of environmental, energy, and economic impacts. The most
important issue of the RACT analysis is typically the economic impact or economic feasibility of the
control option. Economic feasibility is evaluated according to the average cost effectiveness of the
control option, expressed in dollars per ton of pollutant reduced as directed by the U.S. EPA’s Office of
Air Quality Planning and Standards (OAQPS) Cost Control Manual, 5th Edition. The average cost
effectiveness is based on the overall reduction in the air pollutant from the baseline emission rate and is
calculated as:
Average Cost Effectiveness Control option annualized cost
=
($ per ton removed) Baseline emission rate – Control option emissions rate
6.2 Potential Emission Reductions.
In this analysis, potential emission reductions are based on the design emission rates for each unit and
control option and the maximum rated heat input for each unit. For the Westinghouse 501-AA CTGs,
potential emissions are also based on a maximum capacity factor of 10% for each unit.
TABLE 6-1. Potential NOx emissions for each Westinghouse Model 501-AA simple cycle CTG
for the available control technologies based on an allowable capacity factor of 10%.
Control Option Emission Rated Heat Operating Potential to Reduction
Rate Input Capacity Limit Emit from Baseline
lb/mmBtu mmBtu/hr mmBtu/year ton/year ton/year
Uncontrolled (Baseline) 0.38 825 722,700 137.2
Water Injection 0.0921 825 722,700 33.3 103.9
Steam Injection 0.0921 825 722,700 33.3 103.9
Selective Catalytic Reduction 0.0331 825 722,700 12.0 125.2
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7.0 Westinghouse Model 501-AA Simple Cycle
Combustion Turbines.
7.1 Water Injection.
The water injection systems for the Westinghouse 501-AA CTGs would include injection nozzles, flow
metering controls, pumps, hardware, and interconnecting piping from a water treatment system to each
CTG. The water treatment system would include reverse osmosis demineralization systems and storage
tanks. Table 7-1 is a summary of the capital costs for a water injection system for the Model 501-AA
simple cycle CTGs. The equipment costs in Table 7-1 are from a 2018 vendor quote for supplying the
equipment for these Westinghouse 501-AA CTGs. The other costs necessary for installing, starting up,
and operating the water injection systems on these CTGs are as estimated by APS. Note that the costs in
Table 7-1 represent reduced capital costs per CTG based on sharing water supply tanks with two CTGs at
both the Ocotillo and West Phoenix Power Plants. This represents a low estimate of capital costs.
TABLE 7-1. Water injection system capital costs for each Westinghouse Model 501-AA CTG.
Item Cost
Equipment Costs Water Injection (Water pump to unit, no water supply) $1,060,000
(from Supplier Quote) Water Supply (tank, associated piping, valves) $448,000
Shipping $13,000
Tax $69,000
Interface with DCS (APS costs) $60,000
Wiring and Conduit $45,000
Gas Pathing $119,000
Contract Administration (APS costs) $9,000
Project Management (APS costs) $25,000
Foundation, Incidentals, Engineering Design and Review (contract) $113,000
and Indirect Costs (APS APS Engineering Support $10,000
Engineering Estimate) Inspection and Review $6,000
Construction Management (contract) $27,000
Start-up and Commissioning (B&M) $20,000
I&C Support (APS) $24,000
Performance Testing and Permitting $32,000
Control Integration (APS) $7,000
Operational Spare Parts $91,000
Contingency (based on 20% of total costs) $300,000
TOTAL CAPITAL COSTS $2,478,000
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Table 7-2 is a summary of the annual costs for a water injection system for the Model 501-AA CTGs and
the cost effectiveness of the control technology based on limiting the capacity factor of each CTG to 10%,
equal to a natural gas consumption limit of 722,700 mmBtu per year per CTG. The treated water costs
are the current costs for delivering demineralized water to each CTG as estimated by APS. The fuel cost
is based on a 3% loss in CTG efficiency with water injection, the allowable natural gas consumption limit
of 722,700 mmBtu per year per CTG, and a future natural gas cost of $4.50 per mmBtu. The water
injection system maintenance, overhead, and general administrative costs are based on Chapter 6 of the
U.S. EPA’s report Alternative Control Techniques Document – NOx Emissions from Stationary Gas
Turbines, EPA-453/R-93-007, January 1993. The costs from the ACT have been escalated from 1990
dollars to August, 2018 dollars based on the Consumer Price Index (CPI).
TABLE 7-2. Annual costs and cost effectiveness for a water injection system for each
Westinghouse Model 501-AA simple cycle CTG.
Capital Recovery Cost $281,900 Based on the Total Capital Cost in Table 7-1.
Fuel Cost $97,600 3.0% Heat Rate Loss, NG Cost $4.50/mmBtu
Water Treatment Cost $556,700 $0.135 per gallon APS plant estimate.
Maintenance Cost $48,300 From Table B-2 of the NOx ACT
Plant Overhead Cost $14,500 30% of Annual Maintenance Cost
General & Administrative, Taxes, Insurance $99,100 4% of Total Capital Cost
TOTAL ANNUAL COST $1,098,100
Emission Reduction 103.9 ton NOx/year
COST EFFECTIVENESS $10,570 $ per ton of NOx controlled
Footnotes
The cost of capital is based on the APS after tax rate of 7.57% and an expected equipment life of 15 years. The
annual cost is calculated as the product of the total capital cost and the capital recovery factor (CRF):
(1 + )௡ 0.0757(1 + 0.0757)ଵହ
ܥܴܨ = ሾ (1 + )௡−1ሿ= ሾ 0.0757 (1 + 0.0757 )ଵହ−1ሿ= 0.11378
Where, i = Annual interest rate, decimal = 0.0757
n = Control system equipment life, years = 15
7.1.1 Cost, Social, and Environmental Impacts.
From Table 7-2, the use of water injection on each Westinghouse Model 501-AA simple cycle CTG
would result in an emission reduction of 103.9 tons per year. This reduction is based on a current
uncontrolled NOx emission rate of 0.38 lb NOx/mmBtu, a controlled NOx emission rate of 0.0921
lb/mmBtu, and an allowable natural gas use of 722,700 mmBtu per year, equal to a unit capacity factor of
10%. The use of water injection for each unit would have a capital cost of $2,478,000, an annual cost of
$1,098,100, and a cost effectiveness of $10,570 per ton of NOx controlled. In addition, the use of water
injection would consume up to 4,123,900 gallons of water per year per unit. This is a substantial amount
of water in an arid region in which water is a valuable natural resource. West Phoenix and Ocotillo
Power Plants receive their operational water from groundwater wells, a non-renewable and declining
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resource. Arizona is part of the Lower Basin Drought Contingency Plan, which is a result of an 18 year
drought and overly allocated water rights. Arizona is expecting water shortages as soon as 2020. In
addition to the increased strain on a critical environmental and social resource, water treatment adds an
additional energy demand and liquid and solid waste stream.
7.2 Steam Injection.
While steam injection is a technically feasible NOx control option, steam injection is much less frequently
used than water injection. Like the water injection systems, steam injection systems would include
injection nozzles, flow metering controls, pumps, hardware, and interconnecting piping from a water
treatment system to each CTG. In addition, a steam injection system would require a boiler to convert the
demineralized water to steam. This boiler may be a natural gas-fired boiler, or it may be placed in the
CTG flue gas outlet plenum to use waste heat from the CTG to create the steam.
Table 7-3 is a summary of the capital costs for a steam injection system for each Model 501-AA CTG.
These capital costs are based on Chapter 6 of the U.S. EPA report Alternative Control Techniques
Document - NOx Emissions from Stationary Gas Turbines, EPA-453/R-93-007, Jan. 1993, with the
following exceptions:
1. Indirect costs were reduced from 33% of the Purchased Equipment (PEC) and Direct Costs,
to 15% of PEC and Direct Costs, and
2. Project Contingency Costs were reduced from 20% to 10%.
All costs have been escalated from 1990 to August 2018 dollars based on the Consumer Price Index.
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TABLE 7-3. Water injection system capital costs for each Westinghouse Model 501-AA CTG.
Purchased Equipment Costs (PEC)
Steam Injection System $620,000 Based on $4,200 per gallon per minute (GPM) as steam
Water Treatment System $731,000 WTS = 43,900 x GPM0.5
Taxes and Freight $203,000 8% of the total system costs
Direct Installation Costs
Direct Costs $1,315,000 45% of Purchased Equipment Costs
Indirect Installation Costs
Indirect Costs $386,000 15% of the PEC and Direct Costs
Contingency Costs $326,000 10% of the Sum of the PEC, Direct and Indirect Costs
TOTAL CAPITAL COST $3,581,000
Footnotes
1. Costs are based on the U.S. EPA’s report Alternative Control Techniques Document - NOx Emissions from
Stationary Gas Turbines, EPA-453/R-93-007, January 1993.
2. Costs are based on the following combustion turbine and water injection system design conditions:
CTG Heat Input Capacity 825 mmBtu/hr
Natural Gas Heat Value 21,000 Btu per pound, HHV
Natural Gas Fuel Flow Rate 39,286 lb/hour
Steam-to-Fuel Ratio (Ω) 1.0 lb steam/lb fuel
Water Flowrate 78 gallons per minute (GPM)
Water Flowrate 4,123,941 gallons per year
Cost Escalation (Inflation) Factor 1.88 Escalated from Dec. 1990 to August 2018 based on the CPI.
Table 7-4 is a summary of the annual costs for a steam injection system for the Model 501-AA CTGs and
the cost effectiveness of the control technology based on limiting the capacity factor of each CTG to 10%,
equal to a natural gas consumption limit of 722,700 mmBtu per year per CTG. The treated water costs
are the current costs for delivering demineralized water to each CTG as estimated by APS. The fuel cost
is based on a 1% loss in CTG efficiency with steam injection, the allowable natural gas consumption limit
of 722,700 mmBtu per year per CTG, and a future natural gas cost of $4.50 per mmBtu. The water
injection system maintenance, overhead, and general administrative costs are based on Chapter 6 of the
U.S. EPA’s report Alternative Control Techniques Document – NOx Emissions from Stationary Gas
Turbines, EPA-453/R-93-007, January 1993. The costs from the ACT have been escalated from 1990
dollars to August 2018 dollars based on the Consumer Price Index (CPI).
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TABLE 7-4. Annual costs and cost effectiveness for a steam injection system for each
Westinghouse Model 501-AA simple cycle CTG.
Capital Recovery Cost $407,400 Based on the Total Capital Cost in Table 7-3.
Fuel Cost $32,500 1.0% Heat Rate Loss, NG Cost $4.50/mmBtu
Water Treatment Cost $556,700 $0.135 per gallon APS plant estimate.
Maintenance Cost The NOx ACT indicates no additional turbine
Plant Overhead Cost $0 maintenance cost for steam injection.
General & Administrative, Taxes, Insurance $99,100 4% of Total Capital Cost
TOTAL ANNUAL COST $1,095,700
Emission Reduction 103.9 ton NOx/year
COST EFFECTIVENESS $10,540 $ per ton of NOx controlled
Footnotes
1. Costs are based on the U.S. EPA’s report Alternative Control Techniques Document - NOx Emissions from
Stationary Gas Turbines, EPA-453/R-93-007, January 1993.
2. Costs are based on the combustion turbine and water injection system design conditions indicated in Table 7-1.
3. The annual cost of capital is based on the APS after tax rate of 7.57% and an expected equipment life of 15
years. The annual cost is calculated as the product of the total capital cost and the capital recovery factor (CRF):
(1 + )௡ 0.0757(1 + 0.0757)ଵହ
ܥܴܨ = ሾ (1 + )௡−1ሿ= ሾ 0.0757 (1 + 0.0757 )ଵହ−1ሿ= 0.11378
Where, i = Annual interest rate, decimal = 0.0757
n = Control system equipment life, years = 15
7.2.1 Cost, Social, and Environmental Impacts.
From Table 7-4, the use of steam injection systems on each Westinghouse Model 501-AA simple cycle
CTG would result in an emission reduction of 103.9 tons per year. This reduction is based on a current
uncontrolled NOx emission rate of 0.38 lb NOx/mmBtu, a controlled NOx emission rate of 0.0921
lb/mmBtu, and an allowable natural gas use of 722,700 mmBtu per year, equal to a unit capacity factor of
10%. The use of steam injection systems on each unit would have a capital cost of $3,581,000, an annual
cost of $1,095,700, and a cost effectiveness of $10,540 per ton of NOx controlled. In addition, like water
injection, the use of steam injection would also consume up to 4,123,900 gallons of water per year per
unit. This is a substantial amount of water in an arid region in which water is a valuable natural resource.
West Phoenix and Ocotillo Power Plants receive their operational water from groundwater wells, a non-
renewable and declining resource. Arizona is part of the Lower Basin Drought Contingency Plan, which
is a result of an 18 year drought and overly allocated water rights. Arizona is expecting water shortages
as soon as 2020. In addition to the increased strain on a critical environmental and social resource, water
treatment adds an additional energy demand and liquid and solid waste stream.
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7.3 Selective Catalytic Reduction (SCR).
Selective catalytic reduction (SCR) systems for the Westinghouse Model 501-AA simple cycle CTGs
would include a catalyst reactor housing, the catalyst and support matrix, an ammonia injection grid,
aqueous ammonia storage tanks, and ammonia metering equipment and controls. The U.S. EPA’s 1999
document Air Pollution Control Technology Fact Sheet for Selective Catalytic Reduction, EPA-452/F-03-
032, indicates an SCR capital cost for large gas turbines of $5,000 to $7,500 per mmBtu per hour of heat
input. Escalated to 2018 dollars based on the CPI, these costs are equal to $7,650 to $11,500 per
mmBtu/hr. For the Westinghouse Model 501-AA CTGs with a heat input capacity of 825 mmBtu/hr, this
is equal to a capital cost of $6,311,000 to $9,466,000. Based on a 15-year project life, an interest rate of
7.57%, and a capital recovery factor is 0.11378, the annual capital cost would range from $718,000 to
$1,077,000. From Table 6-1, the use of SCR on each CTG would result in an emission reduction of 125.2
tons per year. This reduction is based on a current uncontrolled NOx emission rate of 0.38 lb
NOx/mmBtu, a controlled NOx emission rate of 0.0331 lb/mmBtu, and an allowable natural gas use rate of
722,700 mmBtu per year, equal to a unit capacity factor of 10%.
Table 7-5 is a summary of a detailed analysis of the capital costs, annual costs, and cost effectiveness for
SCR systems for each Westinghouse Model 501-AA simple cycle CTG. The costs in Tables 7-5 are
based on Table 6-8 of the U.S. EPA’s report Alternative Control Techniques Document - NOx Emissions
from Stationary Gas Turbines, EPA-453/R-93-007, January 1993. Costs have been escalated from 1990
dollars to August, 2018 dollars based on the Consumer Price Index (CPI).
7.3.1 Cost, Social, and Environmental Impacts.
From Table 7-5, the use of SCR on each 501-AA CTG would result in an emission reduction of 125.2
tons per year. This reduction is based on a current uncontrolled NOx emission rate of 0.38 lb
NOx/mmBtu, a controlled NOx emission rate of 0.0331 lb/mmBtu, and an allowable natural gas use rate of
722,700 mmBtu per year. From Table 7-5, the use of SCR would have a capital cost of $6,002,000 for
each unit, an annual cost of $1,949,400, and a cost effectiveness of $15,570 per ton of NOx controlled.
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TABLE 7-5. Capital costs, annual costs, and cost effectiveness for a selective catalytic
reduction (SCR) system for each Westinghouse Model 501-AA simple cycle CTG.
A. Total Capital Cost $6,002,000 = (49,700 x TMW) + 459,000
B. Direct Annual Costs, $/yr
1. Operating Labor $5,300 = (1.0 hr/8 hr-shift) x ($25.60/hr) x (H)
2. Supervisory Labor $800 = (0.15) x (Operating Labor)
3. Maint. Labor & Materials $177,800 = (1,250 x TMW) + 25,800
4. Catalyst Replacement $555,900 = (4,700 x TMW) + 37,200
5. Catalyst Disposal $30,500 = (V) x ($15/ft3) x (.2638)
6. Ammonia $34,200 = (N) x ($360/ton) (No escalation to 2018 used)
9. Performance Loss $14,500 = (0.005)x(TMW)x($0.06/kWh)x(1,000 kW/MW)x(H)
C. Indirect Annual Costs, $/yr
1. Overhead $207,400 = (0.6) x (all labor and maintenance material costs)
2. Taxes, Insurance, Administra $240,100 = (0.04) x (total capital investment)
3. Capital Recovery $682,900
TOTAL ANNUAL COST $1,949,400
Emission Reduction 125.2 ton NOx/year
COST EFFECTIVENESS $15,570 $ per ton of NOx controlled
Footnotes
1. Costs are based on the U.S. EPA’s report Alternative Control Techniques Document - NOx Emissions from
Stationary Gas Turbines, EPA-453/R-93-007, January 1993.
2. Costs are based on the following combustion turbine and SCR system design conditions:
Electric Capacity (TMW) 55 MW
Annual Operating Hours (H) 876 hour/year
Ammonia Use (N) 50.5 ton/year, based on uncontrolled NOx emissions of
187.9 ton/yr, and an NH3 to NOx molar ratio of 1.0.
Catalyst Volume (V) 4,095 cubic feet (ft3)
Cost Escalation (Inflation) Factor 1.88
3. The annual cost of capital is based on the APS after tax rate of 7.57% and an expected equipment life of 15
years. The annual cost is calculated as the product of the total capital cost and the capital recovery factor (CRF):
(1 + )௡ 0.0757(1 + 0.0757)ଵହ
ܥܴܨ = ሾ (1 + )௡−1ሿ= ሾ 0.0757 (1 + 0.0757 )ଵହ−1ሿ= 0.11378
Where, i = Annual interest rate, decimal = 0.0757
n = Control system equipment life, years = 15
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8.0 RACT Cost Effectiveness.
According to the U.S. EPA memorandum Cost-Effective Nitrogen Oxides (NOx) Reasonably Available
Control Technology (RACT), from D. Kent Berry, Acting Director Air Quality Management Division
(MD-15), March 16, 1994, the U.S. EPA indicated that cost effective RACT control options should be
within $160 to $1,300 per ton of pollutant controlled. This guidance remains the most current EPA
guidance available. The U.S. EPA reaffirmed the relevancy of this guidance in its final rule to implement
the 8-hour ozone National Ambient Air Quality Standard in 2005 (Federal Register / Vol. 70, No. 228 /
Tuesday, November 29, 2005). In the federal register notice for this final rule, EPA addressed comments
that the cost effectiveness threshold should be higher. In addressing these comments, EPA stated that the
current [1994] guidance may continue to be used by States in making RACT determinations with respect
to the 8-hour ozone standard. In the U.S. EPA’s 2005 NOx SIP Call Rule, EPA stated in the final rule that
the NOx SIP Call controls, at less than $2,000/ton, represented reductions beyond those required by
RACT (70 Fed. Reg. 71654). And while EPA did encourage States to use the latest information available
in making RACT determinations, EPA specifically avoided setting new costing guidelines.
In the U.S. EPA’s Technical Support Document (TSD) for the Cross-State Air Pollution Rule (CSAPR)
for the 2008 Ozone NAAQS, Assessment of Non-EGU NOx Emission Controls, Cost of Controls, and
Time for Compliance, November 2015, the EPA stated:
However, for the purposes of this analysis, the EPA did not further examine control options above
$3,300 per ton. This is consistent with the range we analyzed for EGUs in this proposal, and is
also consistent with what the EPA has identified in previous transport rules as highly cost-
effective, including the NOx SIP call.
In the final Cross State Air Pollution Rule update (81 Fed. Reg. 74504, October 26, 2016), the U.S. EPA
used the $1,400 per ton to establish control requirements for the electric generating units covered under
the rule (page 74581). The U.S. EPA also assessed implementation of one more stringent options at
$3,400 per ton and one less stringent option at $800 per ton. Control strategies that would have cost more
than $3,400 per ton were not included in the final Regulatory Impact Analysis (EPA-452/R-16-004).
Table 8-1 is a summary of RACT cost effectiveness thresholds which have been used by other states and
jurisdictions. Note that with respect to the cost threshold determinations for San Diego and New York,
these areas have cost of living levels which are substantially higher than those for Maricopa County.
Therefore, the high cost thresholds for these jurisdictions may not be comparable to the costs for
Maricopa County. For Pennsylvania, the presumptive RACT benchmark was $2,800 per ton NOx.
However, the RACT II preamble noted that a 25% buffer to the cost-effectiveness will not change the
presumptive RACT determinations. This increased the presumptive RACT benchmark to $3,500 per ton
NOx.
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TABLE 8-1. RACT cost effectiveness thresholds for several states and other jurisdictions.
State/County Nonattainment RACT Threshold, Date of Cost of Living Compared
Designation $ per ton of NOx Determination to Phoenix, AZ4
San Diego, CA Moderate $5,000 2016 150%
Ventura County, CA Serious $1,990 2014 150%
Illinois Moderate $2,500 2012 120%
Maryland Moderate $3,500 2006 120%
New York Moderate $5,000 2016 130%
Pennsylvania Moderate $3,500 2016 120%
Texas Moderate $3,300 2015 100%
Wisconsin Moderate $2,500 2012 100%
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 dollar in March 1994 has the same buying power as $1.71 in August 2018.
Therefore, U.S. EPA’s most current NOx RACT cost effectiveness range of $160 to $1,300 per ton in
1994 is equal to $270 to $2,220 in 2018. Based on this guidance, the maximum cost effectiveness
threshold for RACT would be $2,220 per ton of NOx emissions removed. Note that from Table 8-1,
several agencies have adjusted this value for other considerations. For example, Wisconsin used the same
$1,300 per ton threshold adjusted to 2005 dollars, and then adjusted the threshold upward by 25% for
other considerations.
APS has concluded that a highly conservative cost threshold for RACT in Maricopa County may be based
on increasing the cost effectiveness threshold of $1,300 per ton, adjusted to August 2018 dollars, i.e.,
$2,200, by up to 50%. This would result in a cost effectiveness threshold of $3,300 per ton of NOx
removed. APS has then further rounded this value up to $3,500 per ton to represent a very conservative
cost effectiveness threshold.
4 https://www.bankrate.com/calculators/savings/moving-cost-of-living-calculator.aspx .
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9.0 Conclusion.
The U.S. EPA has defined RACT as “the lowest emission limitation that a particular source is capable of
meeting by the application of control technology that is reasonably available considering technological
and economic feasibility.” As demonstrated above, the Westinghouse Model 501 AA simple cycle CTGs
have low usage and have not exceeded a 5 percent annual capacity factor in the last three years. To ensure
operational flexibility, APS has considered the technological feasibility of the available controls at a 10
percent capacity factor, and has assessed the cost, social, and environmental impacts associated with each
of the technically feasible options. Two of the three options, water injection and steam injection, rely on
the use of a substantial amount of water in an arid region in which water is a valuable, scarce, and non-
renewable natural resource. Arizona is part of the Lower Basin Drought Contingency Plan, which is a
result of an 18 year drought and overly allocated water rights. Arizona is expecting water shortages as
soon as 2020. In addition to the increased strain on a critical environmental and social resource, water
treatment for steam and water injection adds an additional energy demand and liquid and solid waste
stream.
APS has calculated the cost effectiveness threshold to be $3,500 per ton of NOx removed. Water and
steam injection were the two lowest cost options at $10,550 and $10,540, respectively. These costs are
three times this cost effectiveness threshold.
In accordance with EPA’s guidance, and based on the cost, social, and environmental impacts identified
herein, none of the technically feasible NOx control options for the Westinghouse Model 501-AA simple
cycle CTGs are feasible RACT options based on an annual capacity factor of 10 percent (722,700 mmBtu
per year). APS therefore recommends that County Rule 322 be revised to limit the operation of all four
Westinghouse Model 501 AA simple Cycle CTGs to a 10% capacity factor unless APS demonstrates to
the Control Officer that it has already installed, maintained, and operated sufficient air pollution controls
to ensure compliance with the 42 ppmvdc limitation.
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Return to list of attachments
Reasonably Available Control Technology
(RACT) Analysis.
RACT Analysis for the control of nitrogen oxides (NOx) emissions from
boilers at Salt River Project Agua Fria Generating Station.
July 2020
Prepared for:
Salt River Project
1500 N. Mill Avenue
Tempe, AZ 85281
www.srpnet.com
Prepared By:
RTP ENVIRONMENTAL ASSOCIATES INC.
304-A West Millbrook Rd.
Raleigh, NC 27609
257

Table of Contents
1.0 Introduction. ........................................................................................................ 2
2.0 Reasonably Available Control Technology. ..................................................... 3
2.1 RACT Evaluation. ........................................................................................................................ 3
2.2 Calculation of Cost Effectiveness. ................................................................................................ 4
2.3 Capital Recovery Costs. ............................................................................................................... 4
2.4 RACT Cost Effectiveness Threshold. ........................................................................................... 5
2.5 Conclusion and Proposed RACT Determination. ......................................................................... 6
3.0 NOx Emissions from Combustion Sources. ..................................................... 8
3.1 Thermal NOx. ................................................................................................................................ 8
3.2 Fuel NOx. ...................................................................................................................................... 8
3.3 Prompt NOx. ................................................................................................................................. 8
4.0 Available NOx Control Technologies. ............................................................... 9
4.1 Low NOx Burners. ........................................................................................................................ 9
4.1.1 Low NOx Burners plus Overfire Air. ................................................................................ 10
4.1.2 Low NOx Burners plus Flue Gas Recirculation. ............................................................... 10
4.2 Selective Catalytic Reduction (SCR). ......................................................................................... 10
4.3 Selective Non-Catalytic Reduction (SNCR)............................................................................... 11
4.4 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™). .............................................. 11
5.0 Agua Fria Units 1, 2, and 3 Boilers. ................................................................. 14
5.1 Available NOx Control Technologies. ........................................................................................ 14
5.2 Low NOx Burners. ...................................................................................................................... 15
5.3 Selective Non-Catalytic Reduction (SNCR)............................................................................... 17
5.4 Selective Catalytic Reduction (SCR). ......................................................................................... 18
5.5 Conclusions. ............................................................................................................................... 20
Tables
TABLE ES-1. Cost effectiveness of the NOx control options for the Agua Fria Generating Station Unit 1,
2, and 3 boilers based on a 10% capacity factor for each unit. ............................................................ 1
TABLE 5-1. General specifications for the Agua Fria boilers, Units 1, 2, and 3. ................................. 14
TABLE 5-2. Capital costs, annual costs, and cost effectiveness for low NOx burners for each of the Agua
Fria Unit 1 and 2 boilers based on a 10% capacity factor for each boiler. ......................................... 16
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TABLE 5-3. Capital costs, annual costs, and cost effectiveness for low NOx burners for the Agua Fria Unit
3 boiler based on a 10% capacity factor. ............................................................................................ 16
TABLE 5-4. Capital costs, annual costs, and cost effectiveness for SNCR for the Agua Fria Unit 1, 2, and
3 boilers based on a 10% capacity factor for each boiler. .................................................................. 18
TABLE 5-5. Capital costs, annual costs, and cost effectiveness for SCR for the Agua Fria Unit 1, 2, and 3
boilers based on a 10% capacity factor for each boiler. ..................................................................... 19
TABLE 5-6. NOx control options, emission reductions, and cost effectiveness for each of the Agua Fria
Generating Station Unit 1 and 2 boilers based on a 10% capacity factor. ......................................... 20
TABLE 5-7. NOx control options, emission reductions, and cost effectiveness for the Agua Fria Generating
Station Unit 3 boiler based on a 10% capacity factor. ....................................................................... 20
Attachments
Appendix A. ............................ Riley Power Inc. SRP Agua Fria Power Plant Burner Replacement Design,
Supply and Installation Proposal – Revision 01.
Appendix B. ............................ U.S. EPA’s Air Pollution Control Cost Manual, Air Pollution Control Cost
Estimation Spreadsheet for Selective Non-Catalytic Reduction (SNCR), May 2016
for the Units 1 and 2 and Unit 3 boilers.
Appendix C. ............................ U.S. EPA’s Air Pollution Control Cost Manual, Air Pollution Control Cost
Estimation Spreadsheet for Selective Catalytic Reduction (SCR), May 2016
for the Units 1 and 2 and Unit 3 boilers.
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Executive Summary.
Salt River Project’s (SRP) Agua Fria Generating Station is located in the portion of Maricopa County which
is classified as a moderate nonattainment area for ozone (O3). Maricopa County Air Pollution Control
Regulations (MCAPCR) Rule 322 requires the use of Reasonably Available Control Technology (RACT)
for the control of nitrogen oxides (NOx) emissions from power plants in the county.
For each boiler, Rule 322 currently prescribes a presumptive NOx RACT emission limit of 42 parts per
million by volume, dry basis (ppmdv) (calculated as nitrogen dioxide) corrected to 3% oxygen when
burning gaseous fuel, and 65 ppmdv when burning liquid fossil fuel. For any unit with a calendar year
annual capacity factor equal to or less than 10 percent, NOx RACT requires only work practices; such units
are not subject to numeric emission standards.
This report presents a NOx RACT analysis for three natural gas and fuel oil-fired boilers: Units 1, 2, and 3
at the Agua Fria Generating Station. Each of these boilers has a calendar year annual capacity factor equal
to or less than 10 percent.
The U.S. Environmental Protection Agency has defined RACT as “the lowest emission limitation that a
particular source is capable of meeting by the application of control technology that is reasonably available
considering technological and economic feasibility.” The U.S. EPA’s most current guidance on NOx RACT
cost effectiveness indicates an economically reasonable range up to $2,300 per ton of NOx removed,
expressed in 2020 dollars. Table ES-1 is a summary of the cost effectiveness of the NOx control options for
the Agua Fria Generating Station Unit 1, 2, and 3 natural gas and oil-fired boilers based on an annual
capacity factor of 10%. The costs in Table ES-1 are also substantially higher than the economically feasible
threshold of $2,300 per ton of NOx removed. Accordingly, SRP proposes that MCAQD reaffirm that NOx
RACT for similar natural gas-fired boilers with a calendar year annual capacity factor equal to or less than
10 percent is the use of good combustion practices, and a requirement to operate in accordance with the
manufacturer’s specifications, with no numeric emission standards.
TABLE ES-1. Cost effectiveness of the NOx control options for the Agua Fria Generating
Station Unit 1, 2, and 3 boilers based on a 10% capacity factor for each unit.
Cost Effectiveness, $ per ton of NOx controlled
NOx Control
Option Agua Fria Agua Fria
Units 1 and 2 Unit 3
Low NOx Burners $9,580 $4,320
Selective Non-Catalytic Reduction (SNCR) $10,750 $5,240
Selective Catalytic Reduction (SCR) $13,940 $6,500
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1.0 Introduction.
This document is a Reasonably Available Control Technology (RACT) Analysis for the control of nitrogen
oxides (NOx) emissions from three natural gas and fuel oil-fired boilers at the Agua Fria Generating Station.
This generating station is located in the portion of Maricopa County which is classified as a moderate
nonattainment area under the 2008 ozone National Ambient Air Quality Standard (NAAQS).1 As part of
the moderate classification, Maricopa County Air Quality Department (MCAQD) Maricopa County Air
Pollution Control Regulations (MCAPCR) Rule 322 requires RACT level of control for oxides of nitrogen
(NOx) emissions from power plant operations in the county. Agua Fria Generating Station has specifically
identified emissions units in Rule 322 which are subject to RACT requirements.
The units evaluated in this RACT analysis are the Agua Fria Generating Station Unit 1, 2, and 3 natural gas
and fuel oil-fired boilers.
Chapter 2 of this analysis includes a discussion of RACT, including a discussion of cost effectiveness
thresholds.
Chapter 3 includes a general discussion of NOx emissions from combustion sources, including the reaction
mechanisms responsible for NOx formation.
Chapter 4 includes an evaluation of available NOx control technologies. The available controls are then
reviewed to determine controls which are technically feasible control options. The technical feasibility of
controls is further evaluated for each specific unit.
Chapter 5 includes a detailed RACT analysis for the Agua Fria Generating Station Unit 1, 2, and 3 natural
gas and fuel oil-fired boilers.
1 40 CFR § 81.303. See also 86 Fed. Reg. 26697 (May 4, 2016).
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2.0 Reasonably Available Control Technology.
The Code of Federal Regulations, 40 CFR § 51.908 et seq. specifies the attainment demonstration
requirements pursuant to section 182 of the Clean Air Act (CAA) for areas classified as moderate, serious,
severe, or extreme nonattainment areas. One of the requirements specified in 40 CFR § 51.912 is a RACT
state implementation plan (SIP) submission implementing CAA § 182(b)(2) and (f).
Reasonably available control technology is defined in 40 CFR § 51.100(o) as follows:
(o) Reasonably available control technology (RACT) means devices, systems, process modifications,
or other apparatus or techniques that are reasonably available taking into account:
(1) The necessity of imposing such controls in order to attain and maintain a national ambient air
quality standard;
(2) The social, environmental, and economic impact of such controls; and
(3) Alternative means of providing for attainment and maintenance of such standard. (This
provision defines RACT for the purposes of §51.341(b) only.)
This NOx RACT analysis report for the boilers at Agua Fria Generating Station has been prepared in order
to assist MCAQD in satisfying its obligations relating to a NOx RACT SIP submission. The report focuses
on the environmental and economic impact of potentially available NOx controls for the boilers at the Agua
Fria Generating Station.
2.1 RACT Evaluation.
U.S. Environmental Protection Agency (U.S. EPA) has stated, “RACT for a particular source is determined
on a case-by-case basis, considering the technological and economic circumstances of the individual
source.”2
For purposes of this NOx RACT analysis report for the Agua Fria Generating Station Unit 1, 2, and 3 natural
gas and fuel oil-fired boilers, we have generally followed the approach recommended in applicable U.S.
EPA guidance.3,4 This guidance – particularly the Alternative Control Techniques Document – NOx
Emissions from Utility Boilers (“Utility Boiler ACT Document”) – provides useful information but does
not prescribe a methodological approach and does not establish presumptive RACT either for a category of
sources or for any individual source.5 In addition to the Utility Boiler ACT Document, we used vendor
2 44 Fed. Reg. 53761 at p. 53762 (Sept. 17, 1979).
3 See, for example, U.S. EPA, Alternative Control Techniques Document – NOx Emissions from Utility Boilers, EPA-
453/R-94-023 (Mar. 1994).
4 The cost estimating approach generally recommended by U.S. EPA for RACT and other purposes is set forth in a
series of control cost manuals. The most up-to-date, complete edition of this guidance document is EPA Air Pollution
Control Cost Manual, Sixth Edition (EPA/452/B-02-001) (Jan. 2002) (“Control Cost Manual”).
5 See, for example, 57 Fed. Reg. 55620 at p. 55625 (Nov. 25, 1992) (“Similar to the CTGs issued for VOC source
categories, the ACTs will contain extensive background information on control technologies, costs, availability. etc.,
that can be used by States in making RACT determinations. However, unlike the CTGs, the ACTs will not established
[sic] a presumptive RACT.”)
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information, vendor budgetary quotes, unit performance, other U.S. EPA information, and other technical
sources as discussed in subsequent sections of this report. Historical cost information is adjusted to present
2020 costs using the consumer price index (CPI) published by Bureau of Labor Statistics.
The NOx RACT analysis presented in this report is based on the evaluation of the following criteria for each
emissions unit or for each specific type of emissions unit:
1. A review of available and technically achievable control technologies and the
achievable emissions reduction.
2. The cost effectiveness of the control option expressed in dollars per ton of emission
reduction ($/ton).
3. If applicable, other potential social and environmental impacts of the control option.
2.2 Calculation of Cost Effectiveness.
The RACT evaluation includes an evaluation of environmental, energy, and economic impacts. The most
important issue in a RACT analysis is typically the economic reasonableness of the control option. This
parameter is typically evaluated according to the cost effectiveness of the control option, expressed in
dollars per ton of pollutant reduced. Both average and incremental cost effectiveness may be calculated;
however, for the NOx RACT analysis for the boilers at Agua Fria Station, only average cost effectiveness
is necessary. This parameter represents the overall effect of a particular control technique relative to a
baseline condition and is calculated as follows, using the total annualized cost of the control option under
review:
Average Cost Effectiveness Control option annualized cost
=
($ per ton removed) Baseline emission rate – Control option emissions rate
2.3 Capital Recovery Costs.
Under applicable U.S. EPA guidance, including the Utility Boiler ACT Document, the total annualized cost
of a control option includes the annual cost required to recover the capital investment associated with that
control option. This value is calculated using a Capital Recovery Factor (CRF), which is the ratio of a
constant annual payment or annuity to the present value of receiving that annuity for a given length of time.6
For an interest rate i and n years for the project, the CRF is:
𝑖𝑖(1 + 𝑖𝑖)𝑛𝑛
𝐶𝐶𝐶𝐶𝐶𝐶=
[(1 + 𝑖𝑖)𝑛𝑛−1]
Where, i = Interest rate or cost of capital, fraction
6 See, for example, Utility Boiler ACT Document at p. 6-9 (“To convert total capital cost to an annualized capital
charge, the total capital cost is multiplied by an annual capital recovery factor (CRF).”)
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n = Equipment or Project life, years
In this RACT analysis, the interest rate i is 7.0%, consistent with MCAQD guidance.7 The project life for
all pollution control technology alternatives evaluated in this RACT analysis has been based on an
equipment life of 15 years. Substituting the interest rate of 7.0% and project life of 15 years into the above
equation, the CRF value is:
𝑖𝑖 (1 + 𝑖𝑖 )𝑛𝑛 0.07(1 + 0.07)15
𝐶𝐶𝐶𝐶𝐶𝐶= = = 0.10979
[ (1 + 𝑖𝑖 )𝑛𝑛−1] [ (1 + 0.07 )15 −1]
The annual cost for the capital investment is then calculated as the product of the CRF and the Total Capital
Cost (TCC):
Annual Capital = CRF × TCC
Recovery Cost
2.4 RACT Cost Effectiveness Threshold.
The most current U.S. EPA guidance available regarding cost effectiveness thresholds for NOx RACT
determinations is a 1994 memorandum, Cost-Effective Nitrogen Oxides (NOx) Reasonably Available
Control Technology (RACT). According to this guidance, the high end of the range for cost effective RACT
control options is $1,300 per ton of pollutant controlled.8 The U.S. EPA reaffirmed the relevancy of this
guidance in its final rule to implement the 8-hour ozone NAAQS in 2005.9 Specifically, in the Federal
Register notice for this final rule, U.S. EPA rejected comments suggesting RACT requirements should be
more stringent, characterizing the $1,300 per ton threshold as “our current guidance.”10
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 1994 has the same buying power as $1.75 in March 2020. Therefore, U.S.
EPA’s NOx RACT cost effectiveness threshold of $1,300 per ton in 1994 is equal to $2,300 in 2020.
The cost effectiveness threshold of $2,300 per ton derived above is lower than the threshold of $2,800 per
ton used by the Commonwealth of Pennsylvania in adopting NOx RACT rules that were recently approved
by U.S. EPA. As recognized by U.S. EPA in this SIP rulemaking, States have discretion to apply reasonable
thresholds:
7 MCAQD, Requirements, Procedures and Guidance in Selecting BACT and RACT (revised Jan. 2019). This rate is
conservative; the rate suggested in the Utility Boiler ACT Document is 10%.
8 U.S. EPA, Cost-Effective Nitrogen Oxides (NOx) Reasonably Available Control Technology (RACT), memorandum
from D. Kent Berry, Acting Director Air Quality Management Division (MD-15) (March 16, 1994).
9 70 Fed. Reg. 71612 (Nov. 29, 2005).
10 Ibid at p. 71654.
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EPA is aware that Pennsylvania considered cost-effectiveness levels that are lower than other states
in the OTR when developing the RACT II Rule; however, states have the discretion to determine
what costs are considered reasonable when establishing RACT for its sources. For these reasons,
EPA has not set a single cost, emission reduction, or cost-effectiveness figure to fully define cost-
effectiveness in meeting the NOx RACT requirement. Therefore, each state must make and defend
its own determination on how to weigh these values in establishing RACT. PADEP relied on a cost-
effectiveness of $2,800 per ton of NOx controlled and $5,500 per ton of VOC controlled for the
presumptive limits in the RACT II Rule.11
In addition to the cost effectiveness threshold, the manner in which this threshold is applied in determining
RACT for a category of sources is critically important. The way in which the threshold of $2,800 per ton
was applied in establishing NOx RACT in the Commonwealth of Pennsylvania was summarized by U.S.
EPA as follows:
In determining its presumptive NOx RACT limits under the RACT II Rule, PADEP considered
controls to be economically reasonable when installed and operated under $2,500 per ton of NOx
removed. EPA finds PADEP’s cost effectiveness threshold reasonable. Based on our analysis, EPA
found that cost-effectiveness of SCR in Pennsylvania boilers ranged from $3,651-$25,238 per ton,
while SNCR ranged from $2,217 to $17,594 per ton for conventional boilers (non-CFBs) and $6,076
to $19,732 per ton for CFB boilers. Because cost-effectiveness of these controls exceeded $2,500
per ton of NOx removed for the majority of coal-fired boilers in Pennsylvania without these controls
in place, it is reasonable to conclude that it would be economically infeasible to require the
installation and operation of SCR or SNCR on all coal-fired boilers in Pennsylvania. Based on this
analysis, EPA concludes that PADEP’s RACT II Rule determination for any large coal-fired boilers
without post-combustion controls in place is based on the operation of existing controls, in most
cases LNB and/or OFA. Thus, EPA finds that PADEP’s determination for this subset of coal-fired
boilers is reasonable, considering economic infeasibility of retrofitting these additional controls.12
2.5 Conclusion and Proposed RACT Determination.
The circumstances present in the NOx RACT analysis for coal-fired boilers without add-on NOx controls in
Pennsylvania, as discussed in Section 2.4 above, are representative of those for this RACT analysis: There
are a small number of utility boilers with capacity factors less than 10 percent in Maricopa County and, as
shown in section 5.0 of this report, there are no additional control measures that are economically reasonable
for these units either individually or as a group.
11 84 Fed. Reg. 20274 at 20286 (May 9, 2019).
12 U.S. EPA, Technical Support Document for the Pennsylvania State Implementation Plan Revision for Certain Reasonably
Available Control Technology Requirements under the 1997 and 2008 8-hour Ozone National Ambient Air Quality Standard at
24 (Feb. 22, 2018). Available at www.regulations.gov/contentStreamer?documentId=EPA-R03-OAR-2017-0290-
0017&contentType=pdf. Internal citations omitted; emphasis in original.
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The approach taken by the Commonwealth of Pennsylvania and approved by U.S. EPA should be applied
here: RACT should be established based on the use of work practices and these units should not be subject
to numeric emission standards.
Based on the NOx RACT analysis presented herein, SRP proposes the following as RACT for natural gas
and fuel oil-fired boilers with capacity factor equal to or less than 10%, including Units 1, 2, and 3 at the
Agua Fria Generating Station: Use of good combustion practices, and a requirement to operate in
accordance with the manufacturer’s specifications, with no numeric emission standards.
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3.0 NOx Emissions from Combustion Sources.
Nitrogen oxides (NOx) consist of both nitrogen oxide (NO) and nitrogen dioxide (NO2). During
combustion, NO typically accounts for about 50% to 90% of the total NOx emissions. However, since NO
is converted to NO2 in the atmosphere, the mass emission rate of NOx is usually reported as NO2.
NOx is formed during combustion in natural gas and fuel oil-fired boilers through three mechanisms;
1. Thermal Formation,
2. Fuel Formation, and
3. Prompt Formation.
3.1 Thermal NOx.
Of these three formation mechanisms, thermal formation or thermal NOx is expected to represent at least
70% of the total NOx formation. Thermal NOx results from the high temperature oxidation of nitrogen (N2)
and oxygen (O2). In this mechanism, N2 is supplied from air, which is 78% N2 by volume. The thermal
NOx reactions are described by the Zel’dovich mechanism as follows:
N2 + O ↔ NO + N (1)
N + O2 ↔ NO + O (2)
N2 + O2 ↔ 2NO (1) Overall
The first step is rate limiting due to its high activation energy. As a result, thermal NOx requires high
temperatures to proceed. Thermal NOx formation increases exponentially with temperature, becoming
significant at temperatures above approximately 2,800 °F. Because thermal NOx formation increases
exponentially with temperature and because thermal NOx accounts for a large share of the total NOx
emissions, combustion control systems which reduce peak flame temperatures such as low NOx burners
are effective NOx controls for boilers.
3.2 Fuel NOx.
Fuel NOx results from the oxidation of organic nitrogen compounds in the fuel. Because fuel bound
nitrogen is more easily converted to NOx during combustion, nitrogen levels in fuel can have a significant
impact on NOx formation. However, since both natural gas and distillate fuel oil have only trace organic
nitrogen compounds, fuel NOx formation is expected to be very small for these natural gas and distillate
fuel oil-fired boilers.
3.3 Prompt NOx.
Prompt NOx is formed by the reaction of hydrocarbon radicals with atmospheric nitrogen to produce
hydrogen cyanide (HCN) and ultimately NOx through a complex series of gas phase reactions. Prompt NOx
is expected to account for 20 – 30% of the total NOx emissions. Like thermal NOx, prompt NOx formation
can be reduced through combustion controls which reduce peak flame temperatures.
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4.0 Available NOx Control Technologies.
The RACT evaluation process starts with identifying available control technologies for the source. The
available controls are then reviewed to determine controls which are technically feasible control options.
Note that the following is a general discussion of available controls. However, the applicability of these
controls must be determined for each boiler application.
The following NOx control technologies are available for natural gas and distillate fuel oil-fired boilers:
Combustion Controls 1. Low NOx Burners (LNB)
a. LNB plus Overfire Air (OFA)
b. LNB plus Flue Gas Recirculation (FGR)
Post Combustion Controls 2. Selective Catalytic Reduction (SCR)
3. Selective Non-Catalytic Reduction (SNCR)
4. EMx™ Catalytic Absorption Process (EMx or SCONOx™)
4.1 Low NOx Burners.
For natural gas and fuel oil-fired boilers, Low NOx burners (LNB) are designed to control the mixing of air
and fuel to reduce peak flame temperatures. Low NOx burners reduce NOx emissions by staging the
combustion process. Staging slows down the combustion process, resulting in cooler flame temperatures
which suppresses thermal NOx formation. The Utility Boiler ACT indicates the reduction in NOx emissions
achievable with LNB at wall-fired utility boilers burning natural gas or fuel oil is generally expected to be
30% to 50% from uncontrolled levels.13
Low NOx burners are designed to control fuel and air mixing at the burner in order to create larger flame
patterns. This reduces the peak flame temperature and results in lower thermal NOx formation. The modified
flame structure also reduces the amount of oxygen available in the hottest part of the flame, improving
burner efficiency. Primary combustion, NOx reduction and fuel burnout are accomplished in three stages in
a modern, LNB equipped boiler:
1. The first stage is a fuel rich zone where oxygen levels are maintained below the stoichiometric
requirement to complete combustion. Most NOx is formed in this zone.
2. The second stage is a reducing zone where unburned hydrocarbon radicals reduce the NOx
formed in the first stage.
3. In the third stage, overfire air completes combustion, but produces additional NOx. NOx
formation is minimized by completing combustion in a low excess oxygen environment.
Low NOx burners are an available and effective NOx control technology for natural gas-fired boilers.
13 Utility Boiler ACT Document at p. 2-28.
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4.1.1 Low NOx Burners plus Overfire Air.
Some LNB designs may involve two stage combustion using separate overfire air ports. Combustion air is
directed to the burners at rates less than the stoichiometric requirement to complete combustion, with the
remainder provided in separate overfire air ports. This combustion technique can reduce peak flame
temperatures and reduce NOx emissions. This combustion staging is common in coal-fired boilers.
However, for natural gas and fuel oil combustion, this deep staging of overfire air is not normally required.
Instead, the staging of combustion is typically accomplished within the burner itself. Therefore, separated
overfire air is not a feasible NOx control for these natural gas-fired boilers.
4.1.2 Low NOx Burners plus Flue Gas Recirculation.
Flue gas recirculation (FGR) is another combustion modification often used in conjunction with low NOx
burners. FGR can be used to reduce peak flame temperatures and create an oxygen depleted zone by
reducing the concentration of oxygen near the burner. FGR reduces the oxygen content of the air at the base
of the furnace by diluting the primary air blown into the furnace with recirculated flue gas from the back
pass or economizer section of the boiler. This technique is used to create an oxygen depleted reducing zone
where unburned hydrocarbon species act to reduce the NOx formed near the burner. This oxygen depleted
zone reduces the peak flame temperatures which minimizes NOx formation.
SRP has a vendor quote for low NOx burners without FGR. The addition of FGR to these boilers may result
in NOx emission reductions beyond what can be achieved by low NOx burners alone. However, unlike low
NOx burners which can be installed as replacements to the existing burners, FGR would involve significant
boiler modifications, including new high temperature flue gas ductwork, high temperature fans, dampers,
and control equipment. Because of the large capital costs for the addition of FGR and the incremental
emission reductions which would be achieved with this equipment, FGR is expected to have control costs
at least as high as for low NOx burners. Therefore, FGR is not evaluated further in this RACT analysis.
4.2 Selective Catalytic Reduction (SCR).
Selective Catalytic Reduction (SCR) is a post combustion flue gas treatment for controlling NOx emissions
which uses an ammonia (NH3) or urea (CO(NH2)2) injection system and a catalytic reactor. SCR systems
utilize an injection grid which disperses ammonia in the flue gas upstream of the catalyst. NH3 reacts with
NOx in the presence of the catalyst to form nitrogen (N2) and water according to the following equations:
4NH3 + 4NO + O2 → 4N2 + 6H2O 4NH3 + 2NO2 + O2 → 3N2 + 6H2O
2NH3 + NO2 + NO → 2N2 + 3H2O
Catalysts are substances which evoke chemical reactions that would otherwise not take place by providing
a reaction mechanism that has a lower activation energy than the uncatalyzed mechanism. For SCR, the
catalyst is usually a ceramic noble metal, a base metal (titanium or vanadium) oxide, or a zeolite-based
material. To achieve optimum long-term NOx reductions, SCR systems must be designed for each
application. In addition to critical temperature considerations, the ammonia injection rate must be carefully
controlled to maintain an NH3/NOx molar ratio that effectively reduces NOx. Excessive ammonia injection
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will result in ammonia emissions, called ammonia slip. SCR has the capability to make substantial
reductions in NOx emissions. For these boilers, SCR is expected to reduce NOx emissions by 90%.
4.3 Selective Non-Catalytic Reduction (SNCR).
In a selective non-catalytic reduction (SNCR) control system, urea or ammonia is injected into boilers
where the flue gas temperature is approximately 1,600 °F to 2,100 °F. At these temperatures, urea
[CO(NH2)2] or ammonia reacts with NOx, forming elemental nitrogen and water, without the need for a
catalyst. The overall NOx reduction reactions are similar to those for SCR. Multiple injection points are
required to thoroughly mix the reagent into the boiler furnace. The limiting factor for an SNCR system is
the ability to contact the NOx with the reagent without resulting in excessive ammonia slip and without
excessive ammonia decomposition before the NOx emissions can be reduced. The Utility Boiler ACT
indicates the reduction in NOx emissions achievable with SNCR at wall-fired utility boilers burning natural
gas or fuel oil is generally expected to be 25% to 40% from uncontrolled levels.14
SNCR has been widely used in circulating fluidized bed boilers burning solid fuels such as coal or biomass.
SNCR is not commonly used in other boiler types, although some pulverized coal-fired boilers do utilize
SNCR. Never-the-less, SNCR is generally considered to be a technically feasible NOx control technology
for natural gas and oil-fired utility boilers.
4.4 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™).
The EMx™ system is an add-on control device that catalytically oxidizes NO to NO2 and then adsorbs the
NO2 onto a potassium carbonate-coated catalyst surface. The overall chemical reaction between NO2 and
the potassium carbonate catalyst is as follows:
2 NO2 + K2CO3 → CO2 + KNO2 + KNO3
The EMx™ process does not require injection of a reactant, such as ammonia, into the gas stream being
treated. EMx™ catalyst is reported to perform acceptably in the operating temperature range of 425 °F to
750 °F with the best economy and lowest pressure drop achieved in the temperature range of 550 °F to 650
°F where the catalyst activity is highest and the catalyst volume is minimized.15 Based on this claimed
operating range, the flue gas temperatures from the Agua Fria Unit 1, 2, and 3 boilers would not be in the
optimal range for the EMx™ technology.
The EMx™ catalyst has a finite capacity to react with NO2 because potassium carbonate is “consumed” by
NO2 as shown above. Thus, in order to maintain the required NOx removal rate, the catalyst must be
periodically regenerated. Regeneration is accomplished by passing a reducing gas containing hydrogen in
14 Utility Boiler ACT Document at p. 2-31.
15 See, for example, http://docketpublic.energy.ca.gov/PublicDocuments/Regulatory/Non%20Active%20AFC's/07-
AFC-9%20Canyon/2009/January/TN%2049920%2001-28-09%20ECM%20Technology%20White%20Paper.pdf at
page 38 of the PDF file.
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dilute concentration (i.e., about 2 to 4 percent H2) across the surface of the catalyst in the absence of oxygen.
Hydrogen in the regeneration gas reacts with the nitrites and nitrates to form water and molecular nitrogen.
Carbon dioxide in the regeneration gas reacts with the potassium nitrite and nitrates to regenerate potassium
carbonate, which is the original chemical in the catalyst coating. The overall chemical reaction during
catalyst regeneration is as follows:
KNO2 + KNO3 + 4 H2 + CO2 → K2CO3 + 4 H2O + N2
The regeneration gas is produced in a gas generator using a two-stage process to produce molecular
hydrogen and carbon dioxide. In the first stage, natural gas and air are reacted across a partial oxidation
catalyst to form carbon monoxide and hydrogen. Steam is then added to the mixture and passed across a
low temperature shift catalyst, forming carbon dioxide and more hydrogen. The regeneration gas mixture
is diluted to less than four percent hydrogen using steam.
In order to regenerate its catalyst, the EMx™ system is constructed in parallel modules so that a module
can be isolated from the combustion turbine exhaust gas stream using inlet and outlet dampers. The isolated
module is then regenerated while other modules remain open to flow for treatment of the combustion turbine
exhaust gas stream.
Sulfur compounds (e.g., SO2, SO3) in the gas quickly inactivate the EMx™ catalyst requiring the catalyst
to be removed from the reactor for regeneration. To avoid this problem, EMx™ systems on natural gas
fueled combustion turbines include an upstream ESx™ catalyst module that removes the sulfur before they
reach the EMx™ catalyst beds. The ESx™ catalyst is regenerated at the same time as the EMx™ catalyst
by the same regeneration gas. This releases collected SOx as SO2 into the regeneration off-gas stream.
EMx™ is demonstrated for use on relatively small combined-cycle natural gas fueled combustion turbines.
The largest application is the 50 MW Unit 6 combined cycle combustion turbine at the Redding, California
municipal power plant. EMx™ has not been demonstrated on a large combined cycle combustion turbine
or on any simple-cycle combustion turbine. The La Paloma Generating Project in California initially
proposed to demonstrate EMx™ on a 150 MW turbine, but ultimately an SCR system was installed instead.
This was also the case with the Otay Mesa project located in California.
Some of the issues identified with applying EMx™ are:
• The catalyst is very sensitive to sulfur in the exhaust gas;
• The reliability of the system’s moving parts over time is an operational and maintenance concern;
• The use of hydrogen for regeneration could be a serious safety concern;
• The potential exists for scale-up issues for the larger boilers at the Agua Fria Generating Station;
• An EMx™ system has significant pressure drop – about twice that of a comparable SCR system –
which presents design challenges and would require the replacement of the induced draft fans.
An EMx™ system is expected to achieve controlled NOx emission rates similar to SCR systems, but the
costs are expected to be higher, and EMx™ systems have a limited number of current commercial and
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industrial scale applications on large utility boilers. For these reasons, an EMx™ system is not considered
feasible for this RACT analysis.
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5.0 Agua Fria Units 1, 2, and 3 Boilers.
The Agua Fria Generating Station Units 1, 2, and 3 are natural gas and fuel oil-fired electric utility steam
generating units. The general specifications for these units are summarized in Table 5-1. These units have
very low utilization, with a typical capacity factor of approximately 5 percent, and essentially 100% of the
heat input to all three boilers is typically natural gas.
TABLE 5-1. General specifications for the Agua Fria boilers, Units 1, 2, and 3.
Parameter Unit 1 Unit 2 Unit 3
Fuels Natural Gas / Fuel Oil Natural Gas / Fuel Oil Natural Gas / Fuel Oil
Manufacturer Riley Stoker Riley Stoker Riley Stoker
Boiler Type Wall-Fired Wall-Fired Wall-Fired
No. of Burners 12 12 16
Installation Date 1958 1957 1961
Heat Input Capacity, MMBtu/hr 1,253 1,253 1,956
Electric Capacity, MW 114 114 163
For the 5-year period from 2015 to 2019, the Unit 1 and 2 boilers had NOx emission rates of approximately
0.24 to 0.27 lb/MMBtu on an annual average basis, equal to flue gas NOx concentrations of 200 to 220
ppmdv at 3% excess oxygen. These are annual average rates across all load ranges. It is important to note
that the maximum hourly NOx emission rates are substantially higher than these annual average rates.
The Unit 3 boiler has a higher heat input capacity and higher steam production rate, but is a compact boiler
design with a higher heat release rate, expressed in Btu per hour per cubic foot of furnace volume (Btu/hr-
ft3). As a result, for the 5-year period from 2015 to 2019, the Unit 3 boiler had higher NOx emission rates
of approximately 0.46 to 0.55 lb/MMBtu on an annual average basis, equal to a flue gas NOx concentration
of 375 to 450 ppmdv at 3% excess oxygen. As with the Unit 1 and 2 boilers, the maximum hourly NOx
emission rates are substantially higher than these annual average rates.
5.1 Available NOx Control Technologies.
The available NOx control technologies for the Agua Fria Units 1, 2, and 3 boilers include LNB, SNCR,
and SCR.
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5.2 Low NOx Burners.
LNB are a common method used to control NOx emissions from natural gas-fired boilers. All three of the
Agua Fria Unit 1, 2 and 3 boilers are wall-fired boilers. Units 1 and 2 each have 12 burners, while Unit 3
has 16 burners. A low NOx burner replacement project would involve removing and replacing these
existing burners and making other changes such as upgrades to the boiler control systems.
SRP has received a budgetary quote from Riley Power Inc. to provide the design, material, and fabrication
of new STS® dual fuel LNB to replace the existing burners on the Agua Fria Unit 1, 2 and 3 boilers. The
new burners would be designed to bolt in place with minimal field modifications and have the capability
for 100% firing on either natural gas or distillate fuel oil. A copy of this budgetary quote is provided in
Appendix A of this RACT analysis. These burners would use the existing fans, gas valve train, and control
systems on each boiler. This proposal did not include performance guarantees, unloading, electrical
engineering, installation, startup assistance, or training.
For the Unit 1 and 2 boilers, Riley Power indicated expected performance of 0.16 lb NOx/MMBtu when
firing natural gas and 0.42 lb/MMBtu when firing fuel oil with the LNB. For the Unit 3 boiler, Riley Power
indicated expected controlled NOx emission rates of 0.4 to 0.5 lb/MMBtu with low NOx tips and windbox
partitioning, with emissions as low as 0.3 lb/MMBtu depending on actual unit performance and operating
conditions. From the budgetary quote, Riley Power indicated equipment costs of $2,200,000 for the first
of the Unit 1 and 2 boilers, and $1,850,000 for the second boiler, or an average LNB equipment cost of
$2,025,000 for each of the Unit 1 and 2 boilers. Riley Power also indicated an equipment cost of $2,375,000
for LNB for the Unit 3 boiler.
These quoted prices are for the LNB equipment only. The installation of these burners would include other
indirect costs such as installation, project administration, startup, emissions testing, and training of boiler
operators and plant maintenance staff. For this RACT analysis, consistent with the assumption made in the
Utility Boiler ACT document, the estimated indirect costs are 30% of the total direct costs.16 And because
these boilers are from 59 to 63 years old, there may be significant retrofit contingency costs not initially
anticipated, such as asbestos remediation, control system upgrades, or boiler water wall repairs necessary
for the installation of the burners. For this RACT analysis, the contingency cost is 20% of the sum of the
purchased equipment costs and indirect costs. No retrofit factor is applied.
Total annual costs include capital recovery and general and administrative costs, taxes, and insurance.
Consistent with the Control Cost Manual, the latter cost categories are assumed to be 4% of the total capital
costs.17 Labor, operating & maintenance costs, and overhead are conservatively assumed to be zero.
Tables 5-2 and 5-3 summarize the capital costs, annual costs, and cost effectiveness for low NOx burners
on the Unit 1 and 2 boilers and the Unit 3 boiler, respectively. From Table 5-3, the use of LNB on the Unit
1 and 2 boilers would result in a potential emission reduction of 49.4 tons per year per boiler based on a
16 Utility Boiler ACT Document at p. 6-19.
17 Control Cost Manual, 6th Ed., p. 2-34.
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capacity factor of 10%. LNB would have a total capital requirement of $3,159,000, an annual cost of
$473,200, and a cost effectiveness of $9,580 per ton of NOx controlled.
From Table 5-4, the use of LNB on the Unit 3 boiler would result in a potential emission reduction of 128.5
tons per year based on a unit capacity factor of 10% and an aggressive controlled NOx emission rate of 0.35
lb/MMBtu. LNB would have a capital cost of $3,705,000, an annual cost of $555,000, and a cost
effectiveness of $4,320 per ton of NOx controlled.
Based on these costs, the use of low NOx burners for the control of NOx emissions from the Agua Fria Units
1, 2, and 3 boilers is not a feasible RACT option.
TABLE 5-2. Capital costs, annual costs, and cost effectiveness for low NOx burners for each of the
Agua Fria Unit 1 and 2 boilers based on a 10% capacity factor for each boiler.
Total Capital Requirement with Retrofit (TCR)
Riley Power LNB Equipment Costs $2,025,000 Purchased Equipment Cost (PEC)
Indirect Costs $607,500 30% of the PEC
Contingency Costs $526,500 20% of the PEC and Indirect Costs
Total Capital Requirement $3,159,000
Annual Costs
General & Administrative, Taxes, $126,400 4% of TCR
Insurance
Capital Recovery $346,800 Based on 15-year life and 7% interest rate
Total Annual Cost $473,200
Emission Reduction and Cost Effectiveness
Uncontrolled Emission Rate 0.25 lb/MMBtu
Controlled Emission Rate 0.16 lb/MMBtu
Emission Reduction 49.4 ton/yr
Cost Effectiveness $9,580 $ per ton of NOx Controlled
TABLE 5-3. Capital costs, annual costs, and cost effectiveness for low NOx burners for the Agua
Fria Unit 3 boiler based on a 10% capacity factor.
Total Capital Requirement with Retrofit (TCR)
Riley Power Burner Equipment Costs $2,375,000 Purchased Equipment Cost (PEC)
Indirect Costs $712,500 30% of the PEC
Contingency Costs $617,500 20% of the PEC and Indirect Costs
Total Capital Requirement $3,705,000
Annual Costs
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General & Administrative, Taxes, $148,200 4% of TCR
Insurance
Capital Recovery $406,800 Based on 15-year life and 7% interest rate
Total Annual Cost $555,000
Emission Reduction and Cost Effectiveness
Uncontrolled Emission Rate 0.50 lb/MMBtu
Controlled Emission Rate 0.35 lb/MMBtu
Emission Reduction 128.5 ton/yr
Cost Effectiveness $4,320 $ per ton of NOx Controlled
5.3 Selective Non-Catalytic Reduction (SNCR).
SNCR systems for these boilers would include an ammonia injection grid which would inject urea into the
boiler at locations which would optimize NOx reduction at the given boiler load, as well as aqueous
ammonia or urea storage tanks, and metering equipment and controls. SNCR systems would also require
piping, water treatment for dilution water, ductwork and ductwork modifications, auxiliary power
modifications, and other electrical and site upgrades necessary as part of the SNCR systems.
For purposes of this RACT analysis, the costs of applying SNCR have been conservatively estimated using
the methodology recommended by U.S. EPA in its recently released update to Section 4, Chapter 1 of the
Control Cost Manual.18 Appendix B of this report includes the output of this spreadsheet for the Units 1
and 2 and Unit 3 boilers. Costs estimated using this methodology significantly understate the actual costs
that would be incurred to install SNCR because they do not include annualized sales taxes, property taxes,
insurance costs, or costs for operating and supervisory labor. Inclusion of these costs would be appropriate
and would be consistent with both the Utility Boiler ACT Document and Section 1, Chapter 2 of the Control
Cost Manual.
Table 5-4 summarizes the data from these control cost spreadsheets. The costs in Table 5-4 are based on a
capacity factor of 10% for each boiler and a conservatively assumed SNCR control efficiency of 40% from
the uncontrolled emission rates.
18 Spreadsheet available on the U.S. EPA internet web site at www.epa.gov/sites/production/files/2019-
06/sncrcostmanualspreadsheet_june2019vf.xlsm.
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TABLE 5-4. Capital costs, annual costs, and cost effectiveness for SNCR for the Agua Fria Unit 1,
2, and 3 boilers based on a 10% capacity factor for each boiler.
Units 1 and 2 Unit 3
(each)
Capital Cost, $ $4,233,000 $5,321,000
Capital Cost, $ per kW $37 $33
Direct Annual Costs, $ per year $99,100 $274,900
Indirect Annual Costs (incl. Capital Recovery), $ per year $466,700 $586,600
Total Annual Costs, $ per year $565,800 $861,500
NOx Emission Reduction, tons per year 52.6 164.3
Cost Effectiveness, $ per ton of NOx controlled $10,750 $5,240
From Table 5-4, the use of SNCR on each of the Unit 1 and 2 boilers would result in a potential emission
reduction of 52.6 tons per year. SNCR would have a capital cost of $4,233,000; an annual cost of $565,800;
and a cost effectiveness of $10,750 per ton of NOx controlled. The use of SNCR on the Unit 3 boiler would
result in a potential emission reduction of 164.3 tons per year. SNCR would have a capital cost of
$5,321,000; an annual cost of $861,500; and a cost effectiveness of $5,240 per ton of NOx controlled. Based
on these costs, the use of SNCR for the control of NOx emissions from the Agua Fria Units 1, 2, and 3
boilers is not a feasible RACT option.
5.4 Selective Catalytic Reduction (SCR).
SCR systems for these boilers would include a catalyst reactor housing located upstream of the air heater,
the catalyst and support matrix, an ammonia injection grid, aqueous ammonia storage tanks, and ammonia
metering equipment and controls. SCR systems would also require piping, water treatment for dilution
water, ductwork and ductwork modifications, auxiliary power modifications, and other electrical and site
upgrades necessary as part of the SCR systems.
For purposes of this RACT analysis, the costs of applying SCR have been conservatively estimated using
the methodology recommended by U.S. EPA in its recently released update to Section 4, Chapter 2 of the
Control Cost Manual.19 Appendix C of this report includes the output of this spreadsheet for the Units 1
and 2 and Unit 3 boilers.
19 Spreadsheet available on the U.S. EPA internet web site at www.epa.gov/sites/production/files/2019-
06/scrcostmanualspreadsheet_june-2019vf.xlsm.
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Table 5-5 summarizes the data from these control cost spreadsheets. The costs in Table 3 are based on a
capacity factor of 10% for each boiler and an SCR control efficiency of 90% from the uncontrolled emission
rates.
TABLE 5-5. Capital costs, annual costs, and cost effectiveness for SCR for the Agua Fria Unit 1, 2,
and 3 boilers based on a 10% capacity factor for each boiler.
Units 1 and 2 Unit 3
(each)
Capital Cost, $ $12,634,000 $15,939,000
Capital Cost, $ per kW $111 $98
Direct Annual Costs, $ per year $330,500 $752,700
Indirect Annual Costs (incl. Capital Recovery), $ per year $1,390,400 $1,753,500
Total Annual Costs, $ per year $1,720,900 $2,506,200
NOx Emission Reduction, tons per year 123.5 385.5
Cost Effectiveness, $ per ton of NOx controlled $13,940 $6,500
From Table 5-5, the use of SCR on each of the Unit 1 and 2 boilers would result in a potential emission
reduction of 123.5 tons per year. SCR would have a capital cost of $12,634,000; an annual cost of
$1,720,900; and a cost effectiveness of $13,940 per ton of NOx controlled. The use of SCR on the Unit 3
boiler would result in a potential emission reduction of 385.5 tons per year. SCR would have a capital cost
of $15,939,000; an annual cost of $2,506,200; and a cost effectiveness of $6,500 per ton of NOx controlled.
Based on these costs, the use of SCR for the control of NOx emissions from the Agua Fria Units 1, 2, and
3 boilers is not a feasible RACT option.
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5.5 Conclusions.
Tables 5-6 and 5-7 summarize the available and technically feasible NOx RACT options for the Agua Fria
Generating Station Units 1, 2, and 3 boilers, the potential emission reductions, and the cost effectiveness of
each control option. Note that the potential emission reductions and the resulting cost effectiveness are
based on a on a capacity factor of 10% for each boiler which greatly overstates the actual emissions and the
potential emission reductions. Even with these conservative assumptions, no control options meet the cost
effectiveness threshold of $2,300 per ton discussed in Section 2.4 of this report.
TABLE 5-6. NOx control options, emission reductions, and cost effectiveness for each of the
Agua Fria Generating Station Unit 1 and 2 boilers based on a 10% capacity factor.
Emission Annual Cost
NOx Control Option Rate Emissions Capital Cost Annual Cost Effectiveness
lb/MMBtu ton/yr $ per ton
Current Uncontrolled 0.25 137.2
Boiler
LNB 0.16 87.8 $3,159,000 $473,200 $9,580
SNCR 0.15 84.6 $4,233,000 $565,800 $10,750
SCR 0.025 13.7 $12,634,000 $1,720,900 $13,940
TABLE 5-7. NOx control options, emission reductions, and cost effectiveness for the Agua Fria
Generating Station Unit 3 boiler based on a 10% capacity factor.
Emission Annual Cost
NOx Control Option Rate Emissions Capital Cost Annual Cost Effectiveness
lb/MMBtu ton/yr $ per ton
Current Uncontrolled 0.50 428.4
Boiler
LNB 0.35 299.9 $3,705,000 $555,000 $4,320
SNCR 0.30 264.1 $5,321,000 $861,500 $5,240
SCR 0.050 42.8 $15,939,000 $2,506,200 $6,500
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Appendix A
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Kris Pringle November 22, 2019
Mechanical Engineer Sr.
Salt River Project
P.O. Box 52025
Phoenix, AZ 85072-2025
Re: 503660 SRP Agua Fria Power Plant Burner Replacement
Design, Supply and Installation Proposal – Revision 01
Dear Mr. Pringle,
We appreciate the time extended to Mike Lynch (V.P Projects) and the Riley Power Sales team last week
by Bob Ellis to better understand SRP’s operational goals for Agua Fria Units 1 – 3. From this
information, we are pleased to present you with this more accurate budget estimate including new
gas/oil burners and the ability to light off oil during any interruption of gas supply.
This indicative budget pricing for the scope associated with the design, supply and installation of new
burners to startup on D2 in case of a loss of all Gas supply while meeting current emissions
requirements at Agua Fria Power Plant in Glendale, Maricopa County, Arizona. As the boiler OEM, Riley
Power is uniquely suited to consider both the boiler implications (e.g. performance, temperatures, etc..),
and the burner implications (e.g. flame length, emissions) for this important project.
The basis of this budgetary proposal to provide a Design & Erect (D&E) approach under the Babcock
Power family of companies, with Riley Power Inc (RPI) assuming responsibility for the engineering,
design, procurement, delivery, and TEi Construction (TEIC) will be responsible for the installation of the
equipment.
Riley Power Inc. Experience
With our technical expertise and demonstrated project execution capabilities, RPI provides optimum
technical solutions to the industrial and utility markets. These solutions address boiler technologies, as
well as current and potential future emission regulations. RPI solutions are competitive from both a
capital and operational cost perspective with delivery of these solutions on schedule and with high
quality.
RPI and TEIC have executed numerous burner retrofit / replacement projects over the last few years and
are able to coordinate design with constructability to streamline the overall project success.
The Riley Power Team
Low Evaluated Cost: RPI’s goal is to provide the maximum benefit to SRP while achieving the minimum
total evaluated cost.
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Proven Design: RPI is well experienced in the successful design, supply, start-up, and performance of
fuel burning systems.
Project Management Capability: The RPI team will provide unmatched depth of experience, ability to
execute large projects, and financial strength. Our experience and expertise will provide the best
performing and most reliable technology possible, and a successfully executed project.
Experienced in Fired Equipment Systems Projects: Riley Power’s experience in the design of boiler
systems makes us one of the preeminent suppliers of these systems in the world. We are a major
supplier of engineered products and services to the utility and industrial industries in the areas of fuel
combustion systems, boiler upgrades, fuel switching, and environmental controls. The entire design will
be performed at our headquarters in Marlborough, Massachusetts where engineers and designers work
to provide our clients with state-of-the-art designs using the latest tools such as ProE, STAAD, AutoCAD
and FLUENT CFD Modeling.
Financial Strength: RPI has developed and maintained solid financial strength through its diverse lines
of products and services for the U.S. utility and industrial markets. RPI has more than adequate
resources to complete this project on time and within budget, while meeting all contract requirements.
1.0 Scope of Supply
RPI will provide the following materials and services, as described below.
1.1. Riley STS® Gas Burner
RPI will provide the design, material, and fabrication of new STS® dual fuel burners to replace the
existing burners. The new burners will be designed to bolt in place with minimal field modifications.
The STS® burner will have the capability for 100% firing on either natural gas or number 2 fuel oil.
• Twelve (12) Riley Power Inc. STS® dual fuel burners, each with:
o Dual air zone with stainless steel primary air (PA) barrel
o Stainless steel PA swirler
o 310 stainless steel gas injector nozzles
o Adjustable secondary air (SA) swirl vanes (to be set during commissioning for optimal flame
shape)
o Adjustable burner shroud and PA flow control damper (to bet set during commissioning for
optimal burner air distribution)
o Opening for main flame scanner
o One (1) view port
• Class III Special – Direct Spark igniter (HESI)
• Flame scanner (Dual Channel IR/UV)
• Oil Guns
• Flex hoses for gas and oil
1.2. Engineering Services
• Provide arrangement drawings for RPI supplied equipment
• Provide design documentation, drawings, lists, and manuals for RPI supplied equipment
• Provide installation arrangement drawings of burner equipment and mechanical equipment
supplied in this Proposal
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1.3. Project Management
• Project Manager providing overall project and technical coordination
• Project scheduling and reporting
• Quality Assurance and Control
1.4. Clarifications & Exclusions
• Clarifications:
o Existing fan(s) are to be reused to supply combustion air and cooling air.
o Existing gas valve train is in working condition and can be reused to supply adequate gas flow.
o Existing oil valve train is in working condition and can be reused to supply adequate oil flow.
o Burner front piping to be reused upstream of fuel flex hoses.
o The existing control system(s) will be reused. RPI will provide new air and fuel curves to be
integrated into existing control system by Owner.
o Note that RPI recommends that the existing fuel trains are reviewed for NFPA compliance
• Exclusions:
o Performance Guarantees (if required, to be developed and agreed upon under final contract)
o Unloading of shipped components
o Removal, abatement, and/or disposal of Asbestos and Lead
o Electrical engineering, material supply and installation, if required
o Scaffolding or insulation and lagging
o Refractory repairs or replacement
o Any equipment or services not explicitly stated in this proposal
o Startup Assistance (this can be provided at T&M rates, attached)
o On-site training
o Evaluation of existing equipment not modified by RPI
2.0 Technical Discussion
2.1. STS® Burner System Description
RPI has successfully supplied over 300 STS® burners firing natural gas as a primary and secondary
fuel since 1992. Over 50 have been supplied within last three years. The STS® burner design
excellent flexibility for various fuel sources and across a wide operating load range.
As shown in Figure 1, the combustion air passageway into the furnace is divided into two (2)
streams; primary and secondary air, with independent air flow and swirl control. All adjustments on
the burner are manually set during commissioning for optimal performance and are then left in
place during operation.
Total air flow to the burner is controlled by the burner total air shroud. The primary air (PA) and
secondary air (SA) flow split is controlled through a manually adjusted sleeve damper. The
secondary air register has adjustable axial blades, which provide excellent swirl control and low
pressure drop. The SA swirl is adjustable from the burner front from 0° (no swirl) to 60° (high swirl).
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Separating the swirl control and flow control adjustments gives the STS® burner significantly more
flame shaping control and allows for improved turndown capability. The vanes are used to control
the degree of swirl and subsequent fuel/air mixing and NOX performance. The flame by the STS®
Burner is very symmetrical around the burner throat.
For natural gas firing, a series of gas nozzles are provided on a center gas manifold designed for the
specific application and burner capacity. An air swirler/stabilizer is positioned within the gas nozzles.
The center gas manifold and swirler is located inside the primary air barrel of the burner. Axial and
radial adjustments can be made to the gas tips and swirler to control NOX emissions and flame
shape. These adjustments would be made only if required for fine tuning.
Figure 1: RPI STS burner
2.2. STS® Burner Performance
As seen in Figure 2, the flame produced by the STS® burner is well attached and very uniform to the
burner throat exit. The ignition point is strongly rooted within the burner throat. The flame shape is
narrow close the burner and gradually expands in a conical shape.
Viewing this flame from the observation port mounted on the burner front, one will see a blue-to-
yellow gas flame symmetrically situated around the periphery of the swirler. Flame scannability is
excellent.
a
Figure 2: RPI STS burner flame
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3.0 Commercial
RPI is providing the following indicative non-binding budget pricing for the design, supply and
installation of the replacement STS® burners, as outlined in this proposal:
~ Two Million Two Hundred Thousand Dollars ($2,200,000)
• All materials have been specified and quoted based on RPI standards, and USA codes.
• Pricing does not include sales, use, and other similar taxes
• Pricing does not include spare parts
• Pricing is estimated based on a one (1) year warranty, material only
• Pricing is based current day labor rates and material pricing
• Freight - not include in price, FOB shipping point, prepay and add
• Payment terms – cash neutral milestone payments, net 30 days
For the 2nd duplicate Unit (12 burners), the non-binding budget pricing would be:
~ One Million Eight Hundred Fifty Thousand Dollars ($1,850,000)
For the 3rd Unit (16 burners), the non-binding budget pricing would be:
~ Two Million Three Hundred Seventy-Five Thousand Dollars ($2,375,000)
3.1. Commercial Terms
Commercial terms are to be developed and mutually agreed upon under a final, firm proposal offer.
3.2. Validity
Pricing is indicative non-binding budget pricing and does not represent a firm offer.
3.3. Delivery Schedule
Delivery will be confirmed upon final firm pricing offer. Typically, delivery of this equipment will be
around 26-30 weeks after approved drawings depending on shop loading at time of order.
RPI would like to thank you for this opportunity to work with the Agua Fria on the development of this
project and looks forward to following up this submittal with any additional clarifications necessary.
Should you have any questions please contact Katie Hudon at (508) 854-3996 or Michael Lynch at (508)
854-4001.
Best regards,
Katie Hudon, P.E.
Senior Project Manager
Riley Power, Inc.
Tel: (508) 854-3996, Cell: (774) 239-7669 CC: M. Lynch
R. Ellis
Attachments:
Riley-STS-Overview
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Appendix B
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Data Inputs
Enter the following data for your combustion unit:
Is the combustion unit a utility or industrial boiler? What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
Please enter a retrofit factor equal to or greater than 0.84 based on the level of
1.00
difficulty. Enter 1 for projects of average retrofit difficulty.
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)? 114 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel? 1,030 Btu/scf Enter the sulfur content (%S) = percent by weight
*HHV value of 1030 Btu/scf is a default value. See below for data source. Enter actual HHV for fuel burned, if known. or
Select the appropriate SO2 emission rate:
What is the estimated actual annual MW output? 99,864 MW/year
Ash content (%Ash): percent by weight
Is the boiler a fluid-bed boiler?
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV, %S, %Ash and cost. Please
Enter the net plant heat input rate (NPHR) 10.99 MMBtu/MW enter the actual values for these parameters in the table below. If the actual value for any
parameter is not known, you may use the default values provided.
Fraction in Fuel Cost
Coal Blend %S %Ash HHV (Btu/lb) ($/MMBtu)
If the NPHR is not known, use the default NPHR value: Fuel Type Default NPHR Bituminous 0 2.35 10.4 11,814 2.79
Coal 10 MMBtu/MW Sub-Bituminous 0 0.31 5.8 8,730 2.04
Fuel Oil 11 MMBtu/MW Lignite 0 0.91 14.3 6,534 1.85
Natural Gas 8.2 MMBtu/MW
Please click the calculate button to calculate weighted
values based on the data in the table above.
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Enter the following design parameters for the proposed SNCR:
Number of days the SNCR operates (tSNCR) 350 days Plant Elevation 1128 Feet above sea level
Inlet NOx Emissions (NOxin) to SNCR 0.25 lb/MMBtu
NOx Removal Efficiency (EF) provided by vendor (Enter
40 percent
"UNK" if value is not known)
Estimated Normalized Stoichiometric Ratio (NSR) 1.05
*The NSR value of 1.05 is a default value. User should enter actual value, if known.
Concentration of reagent as stored (Cstored) 50 percent* *The reagent concentration of 50% is a default value. User should enter actual value, if known.
Denisty of reagent as stored (ρstored) 71 lb/ft3
Concentration of reagent injected (Cinj) 50 percent Densities of typical SNCR reagents:
Number of days reagent is stored (tstorage) 14 days 50% urea solution 71 lbs/ft3
Estimated equipment life 15 Years 29.4% aqueous NH3 56 lbs/ft3
19% aqueous NH3 58 lbs/ft3
Select the reagent used
Enter the cost data for the proposed SNCR:
Desired dollar-year 2019
CEPCI for 2019 592.1 Enter the CEPCI value for 2019 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index
Annual Interest Rate (i) 7.0 Percent
Fuel (Costfuel) 3.00 $/MMBtu
Reagent (Costreag) 1.62 $/gallon for a 50 percent solution of ammonia*
Water (Costwater) 0.0088 $/gallon*
Electricity (Costelect) 0.0390 $/kWh*
Ash Disposal (for coal-fired boilers only) (Costash) $/ton
* The values marked are default values. See the table below for the default values used
and their references. Enter actual values, if known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet users. Use of other well-known cost indexes (e.g.,
M&S) is acceptable.
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) = 0.015
Administrative Charges Factor (ACF) = 0.03
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Data Sources for Default Values Used in Calculations:
If you used your own site-specific values, please enter
Data Element Default Value Sources for Default Value the the value used and the reference source . . .
Reagent Cost $1.62/gallon of Based on vendor quotes collected in 2014.
50% urea
solution
Water Cost ($/gallon) 0.0088 Average combined water/wastewater rates for industrial facilities in 2013 compiled
by Black & Veatch. (see 2012/2013 "50 Largest Cities Water/Wastewater Rate
Survey." Available at
http://www.saws.org/who_we_are/community/RAC/docs/2014/50-largest-cities-
brochure-water-wastewater-rate-survey.pdf.
Electricity Cost ($/kWh) 0.039 Average annual electricity cost for utilities is based on 2014 electricity production
cost data for fossil-fuel plants compiled by the U.S. Energy Information (EIA).
Available at http://www.eia.gov/tools/faqs/faq.cfm?id=19&t=3.
Fuel Cost ($/MMBtu) 5.14 Weighted average cost based on average 2014 fuel cost data for power plants
compiled by the U.S. Energy Information Administration (EIA) from data reported on
EIA Form EIA-923, "Power Plant Operations Report." Available at
http://www.eia.gov/electricity/data/eia923/.
Ash Disposal Cost ($/ton) Not Applicable Not Applicable Not Applicable
Percent sulfur content for Coal (% weight) Not Applicable Not Applicable Not Applicable
Percent ash content for Coal (% weight) Not Applicable Not Applicable Not Applicable
Higher Heating Value (HHV) (Btu/lb) 1,030 2014 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics,
U.S. Energy Information Administration (EIA) from data reported on EIA Form EIA-
923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Salt River Project RTP Environmental Associates, Inc.
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SNCR Design Parameters
The following design parameters for the SNCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost
Estimate tab.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) = Bmw x NPHR = 1,253 MMBtu/hour
Maximum Annual MW Output (Bmw) = Bmw x 8760 = 998,640 MW/year
Estimated Actual Annual MW Output
99,864 MW/year
(Boutput) =
Heat Rate Factor (HRF) = NPHR/10 = 1.10
Total System Capacity Factor (CFtotal) = (Boutput/Bmw)*(tsncr/365) = 0.10 fraction
Total operating time for the SNCR (top) = CFtotal x 8760 = 840 hours
NOx Removal Efficiency (EF) = (Noxin - NOxout)/Noxin = 40.00 percent
NOx removed per hour = NOxin x EF x QB = 125.29 lb/hour
Total NOx removed per year = (NOxin x EF x QB x top)/2000 = 52.62 tons/year
Coal Factor (CoalF) = 1 for bituminuous; 1.05 for sub-bituminous; 1.07 for Not applicable; factor applies only to coal-
lignite (weighted average is used for coal blends) fired boilers
SO2 Emission rate = (%S/100)x(64/32)*1E6)/HHV = Not applicable; factor applies only to coal-
fired boilers
Elevation Factor (ELEVF) = 14.7 psia/P = 1.04
Atmospheric pressure at 1128 feet above sea 2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)*
14.1 psia
level (P) = =
Retrofit Factor (RF) = Retrofit to existing boiler 1.00
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Salt River Project RTP Environmental Associates, Inc.
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Reagent Data:
Type of reagent used Ammonia Molecular Weight of Reagent (MW) = 17.03 g/mole
Density = 71 lb/gallon
Parameter Equation Calculated Value Units
Reagent consumption rate (mreagent) = (NOxin x QB x NSR x MWR)/(MWNOx x SR) = 122 lb/hour
(whre SR = 1 for NH3; 2 for Urea
Reagent Usage Rate (msol) = mreagent/Csol = 243 lb/hour
(msol x 7.4805)/Reagent Density 26 gal/hour
Estimated tank volume for reagent storage =
8,619 gallons (storage needed to store a 14 day reagent supply)
(msol x 7.4805 x tstorage x 24)/Reagent Density =
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) = i (1+ i)n/(1+ i)n - 1 = 0.1098
Where n = Equipment Life and i= Interest Rate
Parameter Equation Calculated Value Units
Electricity Usage:
Electrcity Consumption (P) = (0.47 x NOxin x NSR x QB)/NPHR = 14.06 kW/hour
Water Usage:
Water consumption (qw) = (msol/Density of water) x ((Cstored/Cinj) - 1) = 0 gallons/hour
Fuel Data:
Additional Fuel required to evaporate water in
Hv x mreagent x ((1/Cinj)-1) = 0.11 MMBtu/hour
injected reagent (ΔFuel) =
Ash Disposal:
Additional ash produced due to increased fuel Not applicable - Ash disposal cost applies only
(Δfuel x %Ash x 1E6)/HHV = 0.00 lb/hour to coal-fired boilers
consumption (Δash) =
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Cost Estimate
Total Capital Investment (TCI)
For Coal-Fired Boilers:
TCI = 1.3 x (SNCRcost + APHcost + BOPcost)
For Fuel Oil and Natural Gas-Fired Boilers:
TCI = 1.3 x (SNCRcost + BOPcost)
Capital costs for the SNCR (SNCRcost) = $1,272,147 in 2019 dollars
Air Pre-Heater Costs (APHcost)* = $0 in 2019 dollars
Balance of Plant Costs (BOPcost) = $1,984,005 in 2019 dollars
Total Capital Investment (TCI) = $4,232,997 in 2019 dollars
* Not applicable - This factor applies only to coal-fired boilers that burn bituminous coal and emits equal to or greater than 0.3lb/MMBtu
of sulfur dioxide.
SNCR Capital Costs (SNCRcost)
For Coal-Fired Utility Boilers:
SNCRcost = 220,000 x (BMW x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
SNCRcost = 147,000 x (BMW x HRF)0.42 x ELEVF x RF
For Coal-Fired Industrial Boilers:
SNCRcost = 220,000 x (0.1 x QB x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
SNCRcost = 147,000 x ((QB/NPHR)x HRF)0.42 x ELEVF x RF
SNCR Capital Costs (SNCRcost) = $1,272,147 in 2019 dollars
Air Pre-Heater Costs (APHcost)*
For Coal-Fired Utility Boilers:
APHcost = 69,000 x (BMW x HRF x CoalF)0.78 x AHF x RF
For Coal-Fired Industrial Boilers:
APHcost = 69,000 x (0.1 x QB x HRF x CoalF)0.78 x AHF x RF
Air Pre-Heater Costs (APHcost) = $0 in 2019 dollars
* Not applicable - This factor applies only to coal-fired boilers that burn bituminous coal and emit equal to or greater than 0.3lb/MMBtu of
sulfur dioxide.
Balance of Plant Costs (BOPcost)
For Coal-Fired Utility Boilers:
BOPcost = 320,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
BOPcost = 213,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x RF
For Coal-Fired Industrial Boilers:
BOPcost = 320,000 x (0.1 x QB)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
BOPcost = 213,000 x (QB/NPHR)0.33 x (NOxRemoved/hr)0.12 x RF
Balance of Plan Costs (BOPcost) = $1,984,005 in 2019 dollars
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Annual Costs
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
Direct Annual Costs (DAC) = $99,139 in 2019 dollars
Indirect Annual Costs (IDAC) = $466,665 in 2019 dollars
Total annual costs (TAC) = DAC + IDAC $565,805 in 2019 dollars
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Water Cost) + (Annual Fuel Cost) +
(Annual Ash Cost)
Annual Maintenance Cost = 0.015 x TCI = $63,495 in 2019 dollars
Annual Reagent Cost = qsol x Costreag x top = $34,908 in 2019 dollars
Annual Electricity Cost = P x Costelect x top = $461 in 2019 dollars
Annual Water Cost = qwater x Costwater x top = $0 in 2019 dollars
Additional Fuel Cost = ΔFuel x Costfuel x top = $276 in 2019 dollars
Additional Ash Cost = ΔAsh x Costash x top x (1/2000) = $0 in 2019 dollars
Direct Annual Cost = $99,139 in 2019 dollars
Indirect Annual Cost (IDAC)
IDAC = Administrative Charges + Capital Recovery Costs
Administrative Charges (AC) = 0.03 x Annual Maintenance Cost = $1,905 in 2019 dollars
Capital Recovery Costs (CR)= CRF x TCI = $464,760 in 2019 dollars
Indirect Annual Cost (IDAC) = AC + CR = $466,665 in 2019 dollars
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Total Annual Cost (TAC) = $565,805 per year in 2019 dollars
NOx Removed = 52.6 tons/year
Cost Effectiveness = $10,753 per ton of NOx removed in 2019 dollars
Salt River Project RTP Environmental Associates, Inc.
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Data Inputs
Enter the following data for your combustion unit:
Is the combustion unit a utility or industrial boiler? What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
Please enter a retrofit factor equal to or greater than 0.84 based on the level of
1.00
difficulty. Enter 1 for projects of average retrofit difficulty.
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)? 163 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel? 1,030 Btu/scf Enter the sulfur content (%S) = percent by weight
*HHV value of 1030 Btu/scf is a default value. See below for data source. Enter actual HHV for fuel burned, if known. or
Select the appropriate SO2 emission rate:
What is the estimated actual annual MW output? 142,788 MW/year
Ash content (%Ash): percent by weight
Is the boiler a fluid-bed boiler?
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV, %S, %Ash and cost. Please
Enter the net plant heat input rate (NPHR) 12 MMBtu/MW enter the actual values for these parameters in the table below. If the actual value for any
parameter is not known, you may use the default values provided.
Fraction in Fuel Cost
Coal Blend %S %Ash HHV (Btu/lb) ($/MMBtu)
If the NPHR is not known, use the default NPHR value: Fuel Type Default NPHR Bituminous 0 2.35 10.4 11,814 2.79
Coal 10 MMBtu/MW Sub-Bituminous 0 0.31 5.8 8,730 2.04
Fuel Oil 11 MMBtu/MW Lignite 0 0.91 14.3 6,534 1.85
Natural Gas 8.2 MMBtu/MW
Please click the calculate button to calculate weighted
values based on the data in the table above.
Salt River Project
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May 2020
294

Enter the following design parameters for the proposed SNCR:
Number of days the SNCR operates (tSNCR) 350 days Plant Elevation 1128 Feet above sea level
Inlet NOx Emissions (NOxin) to SNCR 0.5 lb/MMBtu
NOx Removal Efficiency (EF) provided by vendor (Enter
40 percent
"UNK" if value is not known)
Estimated Normalized Stoichiometric Ratio (NSR) 1.05
*The NSR value of 1.05 is a default value. User should enter actual value, if known.
Concentration of reagent as stored (Cstored) 50 percent* *The reagent concentration of 50% is a default value. User should enter actual value, if known.
Denisty of reagent as stored (ρstored) 71 lb/ft3
Concentration of reagent injected (Cinj) 50 percent Densities of typical SNCR reagents:
Number of days reagent is stored (tstorage) 14 days 50% urea solution 71 lbs/ft3
Estimated equipment life 15 Years 29.4% aqueous NH3 56 lbs/ft3
19% aqueous NH3 58 lbs/ft3
Select the reagent used
Enter the cost data for the proposed SNCR:
Desired dollar-year 2019
CEPCI for 2019 592.1 Enter the CEPCI value for 2019 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index
Annual Interest Rate (i) 7.0 Percent
Fuel (Costfuel) 3.00 $/MMBtu
Reagent (Costreag) 1.62 $/gallon for a 50 percent solution of urea*
Water (Costwater) 0.0088 $/gallon*
Electricity (Costelect) 0.0390 $/kWh*
Ash Disposal (for coal-fired boilers only) (Costash) $/ton
* The values marked are default values. See the table below for the default values used
and their references. Enter actual values, if known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet users. Use of other well-known cost indexes (e.g.,
M&S) is acceptable.
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) = 0.015
Administrative Charges Factor (ACF) = 0.03
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Data Sources for Default Values Used in Calculations:
If you used your own site-specific values, please enter
Data Element Default Value Sources for Default Value the the value used and the reference source . . .
Reagent Cost $1.62/gallon of Based on vendor quotes collected in 2014.
50% urea
solution
Water Cost ($/gallon) 0.0088 Average combined water/wastewater rates for industrial facilities in 2013 compiled
by Black & Veatch. (see 2012/2013 "50 Largest Cities Water/Wastewater Rate
Survey." Available at
http://www.saws.org/who_we_are/community/RAC/docs/2014/50-largest-cities-
brochure-water-wastewater-rate-survey.pdf.
Electricity Cost ($/kWh) 0.039 Average annual electricity cost for utilities is based on 2014 electricity production
cost data for fossil-fuel plants compiled by the U.S. Energy Information (EIA).
Available at http://www.eia.gov/tools/faqs/faq.cfm?id=19&t=3.
Fuel Cost ($/MMBtu) 5.14 Weighted average cost based on average 2014 fuel cost data for power plants
compiled by the U.S. Energy Information Administration (EIA) from data reported on
EIA Form EIA-923, "Power Plant Operations Report." Available at
http://www.eia.gov/electricity/data/eia923/.
Ash Disposal Cost ($/ton) Not Applicable Not Applicable Not Applicable
Percent sulfur content for Coal (% weight) Not Applicable Not Applicable Not Applicable
Percent ash content for Coal (% weight) Not Applicable Not Applicable Not Applicable
Higher Heating Value (HHV) (Btu/lb) 1,030 2014 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics,
U.S. Energy Information Administration (EIA) from data reported on EIA Form EIA-
923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Salt River Project
SNCR Cost Analysis for the Agua Fria Generating Station Unit 3. RTP Environmental Associates, Inc.
May 2020
296

SNCR Design Parameters
The following design parameters for the SNCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost
Estimate tab.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) = Bmw x NPHR = 1,956 MMBtu/hour
Maximum Annual MW Output (Bmw) = Bmw x 8760 = 1,427,880 MW/year
Estimated Actual Annual MW Output
142,788 MW/year
(Boutput) =
Heat Rate Factor (HRF) = NPHR/10 = 1.20
Total System Capacity Factor (CFtotal) = (Boutput/Bmw)*(tsncr/365) = 0.10 fraction
Total operating time for the SNCR (top) = CFtotal x 8760 = 840 hours
NOx Removal Efficiency (EF) = (Noxin - NOxout)/Noxin = 40.00 percent
NOx removed per hour = NOxin x EF x QB = 391.20 lb/hour
Total NOx removed per year = (NOxin x EF x QB x top)/2000 = 164.30 tons/year
Coal Factor (CoalF) = 1 for bituminuous; 1.05 for sub-bituminous; 1.07 for Not applicable; factor applies only to coal-
lignite (weighted average is used for coal blends) fired boilers
SO2 Emission rate = (%S/100)x(64/32)*1E6)/HHV = Not applicable; factor applies only to coal-
fired boilers
Elevation Factor (ELEVF) = 14.7 psia/P = 1.04
Atmospheric pressure at 1128 feet above sea 2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)*
14.1 psia
level (P) = =
Retrofit Factor (RF) = Retrofit to existing boiler 1.00
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
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Reagent Data:
Type of reagent used Urea Molecular Weight of Reagent (MW) = 60.06 g/mole
Density = 71 lb/gallon
Parameter Equation Calculated Value Units
Reagent consumption rate (mreagent) = (NOxin x QB x NSR x MWR)/(MWNOx x SR) = 670 lb/hour
(whre SR = 1 for NH3; 2 for Urea
Reagent Usage Rate (msol) = mreagent/Csol = 1,340 lb/hour
(msol x 7.4805)/Reagent Density 141 gal/hour
Estimated tank volume for reagent storage =
47,457 gallons (storage needed to store a 14 day reagent supply)
(msol x 7.4805 x tstorage x 24)/Reagent Density =
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) = i (1+ i)n/(1+ i)n - 1 = 0.1098
Where n = Equipment Life and i= Interest Rate
Parameter Equation Calculated Value Units
Electricity Usage:
Electrcity Consumption (P) = (0.47 x NOxin x NSR x QB)/NPHR = 40.22 kW/hour
Water Usage:
Water consumption (qw) = (msol/Density of water) x ((Cstored/Cinj) - 1) = 0 gallons/hour
Fuel Data:
Additional Fuel required to evaporate water in
Hv x mreagent x ((1/Cinj)-1) = 0.60 MMBtu/hour
injected reagent (ΔFuel) =
Ash Disposal:
Additional ash produced due to increased fuel Not applicable - Ash disposal cost applies only
(Δfuel x %Ash x 1E6)/HHV = 0.00 lb/hour to coal-fired boilers
consumption (Δash) =
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Cost Estimate
Total Capital Investment (TCI)
For Coal-Fired Boilers:
TCI = 1.3 x (SNCRcost + APHcost + BOPcost)
For Fuel Oil and Natural Gas-Fired Boilers:
TCI = 1.3 x (SNCRcost + BOPcost)
Capital costs for the SNCR (SNCRcost) = $1,533,886 in 2019 dollars
Air Pre-Heater Costs (APHcost)* = $0 in 2019 dollars
Balance of Plant Costs (BOPcost) = $2,559,326 in 2019 dollars
Total Capital Investment (TCI) = $5,321,176 in 2019 dollars
* Not applicable - This factor applies only to coal-fired boilers that burn bituminous coal and emits equal to or greater than 0.3lb/MMBtu of
sulfur dioxide.
SNCR Capital Costs (SNCRcost)
For Coal-Fired Utility Boilers:
SNCRcost = 220,000 x (BMW x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
SNCRcost = 147,000 x (BMW x HRF)0.42 x ELEVF x RF
For Coal-Fired Industrial Boilers:
SNCRcost = 220,000 x (0.1 x QB x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
SNCRcost = 147,000 x ((QB/NPHR)x HRF)0.42 x ELEVF x RF
SNCR Capital Costs (SNCRcost) = $1,533,886 in 2019 dollars
Air Pre-Heater Costs (APHcost)*
For Coal-Fired Utility Boilers:
APHcost = 69,000 x (BMW x HRF x CoalF)0.78 x AHF x RF
For Coal-Fired Industrial Boilers:
APHcost = 69,000 x (0.1 x QB x HRF x CoalF)0.78 x AHF x RF
Air Pre-Heater Costs (APHcost) = $0 in 2019 dollars
* Not applicable - This factor applies only to coal-fired boilers that burn bituminous coal and emit equal to or greater than 0.3lb/MMBtu of
sulfur dioxide.
Balance of Plant Costs (BOPcost)
For Coal-Fired Utility Boilers:
BOPcost = 320,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
BOPcost = 213,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x RF
For Coal-Fired Industrial Boilers:
BOPcost = 320,000 x (0.1 x QB)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
BOPcost = 213,000 x (QB/NPHR)0.33 x (NOxRemoved/hr)0.12 x RF
Balance of Plan Costs (BOPcost) = $2,559,326 in 2019 dollars
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Annual Costs
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
Direct Annual Costs (DAC) = $274,857 in 2019 dollars
Indirect Annual Costs (IDAC) = $586,631 in 2019 dollars
Total annual costs (TAC) = DAC + IDAC $861,488 in 2019 dollars
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Water Cost) + (Annual Fuel Cost) +
(Annual Ash Cost)
Annual Maintenance Cost = 0.015 x TCI = $79,818 in 2019 dollars
Annual Reagent Cost = qsol x Costreag x top = $192,202 in 2019 dollars
Annual Electricity Cost = P x Costelect x top = $1,318 in 2019 dollars
Annual Water Cost = qwater x Costwater x top = $0 in 2019 dollars
Additional Fuel Cost = ΔFuel x Costfuel x top = $1,520 in 2019 dollars
Additional Ash Cost = ΔAsh x Costash x top x (1/2000) = $0 in 2019 dollars
Direct Annual Cost = $274,857 in 2019 dollars
Indirect Annual Cost (IDAC)
IDAC = Administrative Charges + Capital Recovery Costs
Administrative Charges (AC) = 0.03 x Annual Maintenance Cost = $2,395 in 2019 dollars
Capital Recovery Costs (CR)= CRF x TCI = $584,237 in 2019 dollars
Indirect Annual Cost (IDAC) = AC + CR = $586,631 in 2019 dollars
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Total Annual Cost (TAC) = $861,488 per year in 2019 dollars
NOx Removed = 164.3 tons/year
Cost Effectiveness = $5,243 per ton of NOx removed in 2019 dollars
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Appendix C
Salt River Project RTP Environmental Associates, Inc.
NOx RACT Analysis for the Agua Fria Generating Station Unit 1, 2, and 3 Boilers. July 2020
301

Data Inputs
Enter the following data for your combustion unit:
Is the combustion unit a utility or industrial boiler? What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
Please enter a retrofit factor between 0.8 and 1.5 based on the level of difficulty.
1.00
Enter 1 for projects of average retrofit difficulty.
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)? 114 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel? 1,030 Btu/scf Enter the sulfur content (%S) = percent by weight
*HHV value of 1030 Btu/scf is a default value. See below for data source. Enter actual HHV for fuel burned, if known.
What is the estimated actual annual MW output? 99,864 MWh/year
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV and %S. Please enter the
actual values for these parameters in the table below. If the actual value for any parameter is not
known, you may use the default values provided.
Enter the net plant heat input rate (NPHR) 10.99 MMBtu/MW
Fraction in Coal
Blend %S HHV (Btu/lb)
If the NPHR is not known, use the default NPHR value: Fuel Type Default NPHR Bituminous 0 2.35 11,814
Coal 10 MMBtu/MW Sub-Bituminous 0 0.31 8,730
Fuel Oil 11 MMBtu/MW Lignite 0 0.91 6,534
Natural Gas 8.2 MMBtu/MW
Please click the calculate button to calculate weighted
values based on the data in the table above.
Plant Elevation 1128 Feet above sea level
For coal-fired boilers, you may use either Method 1 or Method 2 to
calculate the catalyst replacement cost. The equations for both methods Method 1
are shown on rows 85 and 86 on the Cost Estimate tab. Please select your Method 2
preferred method: Not applicable
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Enter the following design parameters for the proposed SCR:
Number of days the SCR operates (tSCR) Number of SCR reactor chambers (nscr)
350 days 1
Number of days the boiler operates (tplant) Number of catalyst layers (Rlayer)
350 days 3
Inlet NOx Emissions (NOxin) to SCR Number of empty catalyst layers (Rempty) 1
0.25 lb/MMBtu
NOx Removal Efficiency (EF) provided by vendor 90 percent Ammonia Slip (Slip) provided by vendor 2 ppm
Volume of the catalyst layers (Volcatalyst)
Stoichiometric Ratio Factor (SRF)
1.050 (Enter "UNK" if value is not known) UNK Cubic feet
*The SRF value of 1.05 is a default value. User should enter actual value, if known. Flue gas flow rate (Qfluegas)
(Enter "UNK" if value is not known) UNK acfm
Estimated operating life of the catalyst (Hcatalyst)
24,000 hours
Gas temperature at the SCR inlet (T) 650 oF
Estimated SCR equipment life 15 Years*
* For utility boilers, the typical equipment life of an SCR is at least 30 years. Base case fuel gas volumetric flow rate factor
484 ft3/min-MMBtu/hour
(Qfuel)
Concentration of reagent as stored (Cstored) 29 percent*
*The reagent concentration of 29% and density of 56 lbs/cft are
Density of reagent as stored (ρstored) 56 lb/cubic feet* default values for ammonia reagent. User should enter actual values
for reagent, if different from the default values provided.
Number of days reagent is stored (tstorage) 14 days Densities of typical SCR reagents:
50% urea solution 71 lbs/ft3
29.4% aqueous NH3 56 lbs/ft3
19% aqueous NH3 58 lbs/ft3
Select the reagent used
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Enter the cost data for the proposed SCR:
Desired dollar-year 2019
CEPCI for 2019 592.1 Enter the CEPCI value for 201541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index
Annual Interest Rate (i) 7.0 Percent
* $3.56/gallon is a default value for the reagent cost. User should enter actual value, if
Reagent (Costreag) 3.56 $/gallon for a 29 percent solution of ammonia known.
* $0.0390/kWh is a default value for electicity cost. User should enter actual value, if
Electricity (Costelect) 0.0390 $/kWh* known.
$/cubic foot (includes removal and disposal/regeneration of
Catalyst cost (CC replace) 160.00 existing catalyst and installation of new catalyst* * $160/cf is a default value for the catalyst cost. User should enter actual value, if known.
* $60/hour is a default value for the operator labor rate. User should enter actual value, if
Operator Labor Rate 60.00 $/hour (including benefits)* known.
* 4 hours/day is a default value for the operator labor. User should enter actual value, if
Operator Hours/Day 4.00 hours/day* known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost
index to spreadsheet users. Use of other well-known cost indexes (e.g., M&S) is acceptable.
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) = 0.005
Administrative Charges Factor (ACF) = 0.03
Data Sources for Default Values Used in Calculations:
If you used your own site-specific values, please enter
Data Element Default Value Sources for Default Value the value used and the reference source . . .
Reagent Cost ($/gallon) 3.56 Based on the average of vendor quotes from 2011 - 2013.
Electricity Cost ($/kWh) 0.039 Average annual electricity cost for utilities is based on 2014 electricity
production cost data for fossil-fuel plants compiled by the U.S. Energy
Information (EIA). Available at
http://www.eia.gov/tools/faqs/faq.cfm?id=19&t=3.
Percent sulfur content for Coal (% weight) 2.35 Average sulfur content based on U.S. coal data for 2014 compiled by the U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-
923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Higher Heating Value (HHV) (Btu/lb) 1,030 2014 natural gas data compiled by the Office of Oil, Gas, and Coal Supply
Statistics, U.S. Energy Information Administration (EIA) from data reported on
EIA Form EIA-923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Catalyst Cost ($/cubic foot) 160 Cichanowicz, J.E. "Current Capital Cost and Cost-Effectiveness of Power Plant
Emissions Control Technologies", July 2013.
Salt River Project RTP Environmental Associates, Inc.
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SCR Design Parameters
The following design parameters for the SCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate tab.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) = Bmw x NPHR = 1,253 MMBtu/hour
Maximum Annual MW Output (Bmw) = Bmw x 8760 = 998,640 MWh/year
Estimated Actual Annual MW Output (Boutput) = 99,864 MWh/year
Heat Rate Factor (HRF) = NPHR/10 = 1.10
Total System Capacity Factor (CFtotal) = (Boutput/Bmw)*(tscr/tplant) = 0.10 fraction
Total operating time for the SCR (top) = CFtotal x 8760 = 876 hours
NOx Removal Efficiency (EF) = (NOxin- NOxout)/NOxin = 90.0 percent
NOx removed per hour = NOxin x EF x QB = 281.89 lb/hour
Total NOx removed per year = (NOxin x EF x QB x top)/2000 = 123.47 tons/year
NOx removal factor (NRF) = EF/80 1.13
Volumetric flue gas flow rate (qflue gas) = Qfuel x QB x (460 + T)/(460 + 700)nscr 580,247 acfm
Space velocity (Vspace) = qflue gas/Volcatalyst 110.38 /hour
Residence Time 1/Vspace 0.01 hour
1 for oil and natural gas; 1 for bituminous; 1.05 for
Coal Factor (CoalF) = sub-bituminous; 1.07 for lignite (weighted average is 1.00
used for coal blends)
SO2 Emission rate = (%S/100)x(64/32)*1E6)/HHV = Not applicable; factor applies only to
coal-fired boilers
Elevation Factor (ELEVF) = 14.7 psia/P = 1.04
Atmospheric pressure at sea level (P) = 2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)* 14.1 psia
=
Retrofit Factor (RF) Retrofit to existing boiler 1.00
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Catalyst Data:
Parameter Equation Calculated Value Units
Future worth factor (FWF) = (interest rate)(1/((1+ interest rate)Y -1) , where Y =
Hcatalyts/(tSCR x 24 hours) rounded to the nearest integer 0.311 Fraction
Catalyst volume (Volcatalyst) =
2.81 x QB x EF adj x Slipadj x Noxadj x Sadj x (Tadj/Nscr) 5,256.72 Cubic feet
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Cross sectional area of the catalyst (Acatalyst) = qflue gas /(16ft/sec x 60 sec/min) 604 ft2
Height of each catalyst layer (Hlayer) = (Volcatalyst/(Rlayer x Acatalyst)) + 1 4 feet
SCR Reactor Data:
Parameter Equation Calculated Value Units
Cross sectional area of the reactor (ASCR) = 1.15 x Acatalyst 695 ft2
Reactor length and width dimentions for a square
(ASCR)0.5 26.4 feet
reactor =
Reactor height = (Rlayer + Rempty) x (7ft + hlayer) + 9ft 53 feet
Reagent Data:
Type of reagent used Ammonia Molecular Weight of Reagent (MW) = 17.03 g/mole
Density = 56 lb/ft3
Parameter Equation Calculated Value Units
Reagent consumption rate (mreagent) = (NOxin x QB x EF x SFR x MWR)/MWNOx = 110 lb/hour
Reagent Usage Rate (msol) = mreagent/Csol = 378 lb/hour
(msol x 7.4805)/Reagent Density 50 gal/hour
Estimated tank volume for reagent storage = (msol x 7.4805 x tstorage x 24)/Reagent Density = 16,956 gallons (storage needed to store a 14 day reagent supply)
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) = i (1+ i)n/(1+ i)n - 1 = 0.1098
Where n = Equipment Life and i= Interest Rate
Other parameters Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) = A x 1,000 x 0.0056 x (CoalF x HRF)0.43 = 664.85 kW
where A = Bmw for utility boilers
Salt River Project RTP Environmental Associates, Inc.
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Cost Estimate
Total Capital Investment (TCI)
TCI for Oil and Natural Gas Boilers
For Oil and Natural Gas-Fired Utility Boilers between 25MW and 500 MW:
TCI = 80,000 x (200/BMW )0.35 x BMW x ELEVF x RF
For Oil and Natural Gas-Fired Utility Boilers >500 MW:
TCI = 60,670 x BMW x ELEVF x RF
For Oil-Fired Industrial Boilers between 275 and 5,500 MMBTU/hour :
TCI = 7,270 x (2,200/QB )0.35 x QB x ELEVF x RF
For Natural Gas-Fired Industrial Boilers between 205 and 4,100 MMBTU/hour :
TCI = 9,760 x (1,640/QB )0.35 x QB x ELEVF x RF
For Oil-Fired Industrial Boilers >5,500 MMBtu/hour:
TCI = 5,275 x QB x ELEVF x RF
For Natural Gas-Fired Industrial Boilers >4,100 MMBtu/hour:
TCI = 7,082 x QB x ELEVF x RF
Total Capital Investment (TCI) = $12,633,961 in 2019 dollars
Salt River Project RTP Environmental Associates, Inc.
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Annual Costs
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
Direct Annual Costs (DAC) = $330,465 in 2019 dollars
Indirect Annual Costs (IDAC) = $1,390,419 in 2019 dollars
Total annual costs (TAC) = DAC + IDAC $1,720,884 in 2019 dollars
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Catalyst Cost)
Annual Maintenance Cost = 0.005 x TCI = $63,170 in 2019 dollars
Annual Reagent Cost = qsol x Costreag x top = $157,375 in 2019 dollars
Annual Electricity Cost = P x Costelect x top = $22,714 in 2019 dollars
Annual Catalyst Replacement Cost = $87,206 in 2019 dollars
nscr x Volcat x (CCreplace/Rlayer) x FWF
Direct Annual Cost = $330,465 in 2019 dollars
Indirect Annual Cost (IDAC)
IDAC = Administrative Charges + Capital Recovery Costs
Administrative Charges (AC) = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost) = $3,278 in 2019 dollars
Capital Recovery Costs (CR)= CRF x TCI = $1,387,141 in 2019 dollars
Indirect Annual Cost (IDAC) = AC + CR = $1,390,419 in 2019 dollars
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Total Annual Cost (TAC) = $1,720,884 per year in 2019 dollars
NOx Removed = 123.5 tons/year
Cost Effectiveness = $13,938 per ton of NOx removed in 2019 dollars
Salt River Project RTP Environmental Associates, Inc.
SCR Cost Analysis for the Agua Fria Generating Station Units 1 and 2. May 2020
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Data Inputs
Enter the following data for your combustion unit:
Is the combustion unit a utility or industrial boiler? What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
Please enter a retrofit factor between 0.8 and 1.5 based on the level of difficulty.
1.00
Enter 1 for projects of average retrofit difficulty.
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)? 163 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel? 1,030 Btu/scf Enter the sulfur content (%S) = percent by weight
*HHV value of 1030 Btu/scf is a default value. See below for data source. Enter actual HHV for fuel burned, if known.
What is the estimated actual annual MW output? 142,788 MW/year
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV and %S. Please enter the
actual values for these parameters in the table below. If the actual value for any parameter is not
known, you may use the default values provided.
Enter the net plant heat input rate (NPHR) 12 MMBtu/MW
Fraction in Coal
Blend %S HHV (Btu/lb)
If the NPHR is not known, use the default NPHR value: Fuel Type Default NPHR Bituminous 0 2.35 11,814
Coal 10 MMBtu/MW Sub-Bituminous 0 0.31 8,730
Fuel Oil 11 MMBtu/MW Lignite 0 0.91 6,534
Natural Gas 8.2 MMBtu/MW
Please click the calculate button to calculate weighted
values based on the data in the table above.
Plant Elevation 1128 Feet above sea level
For coal-fired boilers, you may use either Method 1 or Method 2 to
calculate the catalyst replacement cost. The equations for both methods Method 1
are shown on rows 85 and 86 on the Cost Estimate tab. Please select your Method 2
preferred method: Not applicable
Salt River Project RTP Environmental Associates, Inc.
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Enter the following design parameters for the proposed SCR:
Number of days the SCR operates (tSCR) Number of SCR reactor chambers (nscr)
350 days 1
Number of days the boiler operates (tplant) Number of catalyst layers (Rlayer)
350 days 3
Inlet NOx Emissions (NOxin) to SCR Number of empty catalyst layers (Rempty) 1
0.5 lb/MMBtu
NOx Removal Efficiency (EF) provided by vendor 90 percent Ammonia Slip (Slip) provided by vendor 2 ppm
Volume of the catalyst layers (Volcatalyst)
Stoichiometric Ratio Factor (SRF)
1.050 (Enter "UNK" if value is not known) UNK Cubic feet
*The SRF value of 1.05 is a default value. User should enter actual value, if known. Flue gas flow rate (Qfluegas)
(Enter "UNK" if value is not known) UNK acfm
Estimated operating life of the catalyst (Hcatalyst)
24,000 hours
Gas temperature at the SCR inlet (T) 650 oF
Estimated SCR equipment life 15 Years*
* For utility boilers, the typical equipment life of an SCR is at least 30 years. Base case fuel gas volumetric flow rate factor
484 ft3/min-MMBtu/hour
(Qfuel)
Concentration of reagent as stored (Cstored) 29 percent*
*The reagent concentration of 29% and density of 56 lbs/cft are
Density of reagent as stored (ρstored) 56 lb/cubic feet* default values for ammonia reagent. User should enter actual values
for reagent, if different from the default values provided.
Number of days reagent is stored (tstorage) 14 days Densities of typical SCR reagents:
50% urea solution 71 lbs/ft3
29.4% aqueous NH3 56 lbs/ft3
19% aqueous NH3 58 lbs/ft3
Select the reagent used
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Enter the cost data for the proposed SCR:
Desired dollar-year 2019
CEPCI for 2019 592.1 Enter the CEPCI value for 201541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index
Annual Interest Rate (i) 7.0 Percent
* $3.56/gallon is a default value for the reagent cost. User should enter actual value, if
Reagent (Costreag) 3.56 $/gallon for a 29 percent solution of ammonia known.
* $0.0390/kWh is a default value for electicity cost. User should enter actual value, if
Electricity (Costelect) 0.0390 $/kWh* known.
$/cubic foot (includes removal and disposal/regeneration of
Catalyst cost (CC replace) 160.00 existing catalyst and installation of new catalyst* * $160/cf is a default value for the catalyst cost. User should enter actual value, if known.
* $60/hour is a default value for the operator labor rate. User should enter actual value, if
Operator Labor Rate 60.00 $/hour (including benefits)* known.
* 4 hours/day is a default value for the operator labor. User should enter actual value, if
Operator Hours/Day 4.00 hours/day* known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost
index to spreadsheet users. Use of other well-known cost indexes (e.g., M&S) is acceptable.
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) = 0.005
Administrative Charges Factor (ACF) = 0.03
Data Sources for Default Values Used in Calculations:
If you used your own site-specific values, please enter
Data Element Default Value Sources for Default Value the value used and the reference source . . .
Reagent Cost ($/gallon) 3.56 Based on the average of vendor quotes from 2011 - 2013.
Electricity Cost ($/kWh) 0.039 Average annual electricity cost for utilities is based on 2014 electricity
production cost data for fossil-fuel plants compiled by the U.S. Energy
Information (EIA). Available at
http://www.eia.gov/tools/faqs/faq.cfm?id=19&t=3.
Percent sulfur content for Coal (% weight) 2.35 Average sulfur content based on U.S. coal data for 2014 compiled by the U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-
923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Higher Heating Value (HHV) (Btu/lb) 1,030 2014 natural gas data compiled by the Office of Oil, Gas, and Coal Supply
Statistics, U.S. Energy Information Administration (EIA) from data reported on
EIA Form EIA-923, Power Plant Operations Report. Available at
http://www.eia.gov/electricity/data/eia923/.
Catalyst Cost ($/cubic foot) 160 Cichanowicz, J.E. "Current Capital Cost and Cost-Effectiveness of Power Plant
Emissions Control Technologies", July 2013.
Salt River Project RTP Environmental Associates, Inc.
SCR Cost Analysis for the Agua Fria Generating Station Unit 3. May 2020
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SCR Design Parameters
The following design parameters for the SCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate tab.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) = Bmw x NPHR = 1,956 MMBtu/hour
Maximum Annual MW Output (Bmw) = Bmw x 8760 = 1,427,880 MW/year
Estimated Actual Annual MW Output (Boutput) = 142,788 MW/year
Heat Rate Factor (HRF) = NPHR/10 = 1.20
Total System Capacity Factor (CFtotal) = (Boutput/Bmw)*(tscr/tplant) = 0.10 fraction
Total operating time for the SCR (top) = CFtotal x 8760 = 876 hours
NOx Removal Efficiency (EF) = (NOxin- NOxout)/NOxin = 90.0 percent
NOx removed per hour = NOxin x EF x QB = 880.20 lb/hour
Total NOx removed per year = (NOxin x EF x QB x top)/2000 = 385.53 tons/year
NOx removal factor (NRF) = EF/80 1.13
Volumetric flue gas flow rate (qflue gas) = Qfuel x QB x (460 + T)/(460 + 700)nscr 905,898 acfm
Space velocity (Vspace) = qflue gas/Volcatalyst 101.64 /hour
Residence Time 1/Vspace 0.01 hour
1 for oil and natural gas; 1 for bituminous; 1.05 for
Coal Factor (CoalF) = sub-bituminous; 1.07 for lignite (weighted average is 1.00
used for coal blends)
SO2 Emission rate = (%S/100)x(64/32)*1E6)/HHV = Not applicable; factor applies only to
coal-fired boilers
Elevation Factor (ELEVF) = 14.7 psia/P = 1.04
Atmospheric pressure at sea level (P) = 2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)* 14.1 psia
=
Retrofit Factor (RF) Retrofit to existing boiler 1.00
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Catalyst Data:
Parameter Equation Calculated Value Units
Future worth factor (FWF) = (interest rate)(1/((1+ interest rate)Y -1) , where Y =
Hcatalyts/(tSCR x 24 hours) rounded to the nearest integer 0.311 Fraction
Catalyst volume (Volcatalyst) =
2.81 x QB x EF adj x Slipadj x Noxadj x Sadj x (Tadj/Nscr) 8,912.71 Cubic feet
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Cross sectional area of the catalyst (Acatalyst) = qflue gas /(16ft/sec x 60 sec/min) 944 ft2
Height of each catalyst layer (Hlayer) = (Volcatalyst/(Rlayer x Acatalyst)) + 1 4 feet
SCR Reactor Data:
Parameter Equation Calculated Value Units
Cross sectional area of the reactor (ASCR) = 1.15 x Acatalyst 1,085 ft2
Reactor length and width dimentions for a square
(ASCR)0.5 32.9 feet
reactor =
Reactor height = (Rlayer + Rempty) x (7ft + hlayer) + 9ft 54 feet
Reagent Data:
Type of reagent used Ammonia Molecular Weight of Reagent (MW) = 17.03 g/mole
Density = 56 lb/ft3
Parameter Equation Calculated Value Units
Reagent consumption rate (mreagent) = (NOxin x QB x EF x SFR x MWR)/MWNOx = 342 lb/hour
Reagent Usage Rate (msol) = mreagent/Csol = 1,180 lb/hour
(msol x 7.4805)/Reagent Density 158 gal/hour
Estimated tank volume for reagent storage = (msol x 7.4805 x tstorage x 24)/Reagent Density = 52,944 gallons (storage needed to store a 14 day reagent supply)
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) = i (1+ i)n/(1+ i)n - 1 = 0.1098
Where n = Equipment Life and i= Interest Rate
Other parameters Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) = A x 1,000 x 0.0056 x (CoalF x HRF)0.43 = 987.24 kW
where A = Bmw for utility boilers
Salt River Project RTP Environmental Associates, Inc.
SCR Cost Analysis for the Agua Fria Generating Station Unit 3. May 2020
313

Cost Estimate
Total Capital Investment (TCI)
TCI for Oil and Natural Gas Boilers
For Oil and Natural Gas-Fired Utility Boilers between 25MW and 500 MW:
TCI = 80,000 x (200/BMW )0.35 x BMW x ELEVF x RF
For Oil and Natural Gas-Fired Utility Boilers >500 MW:
TCI = 60,670 x BMW x ELEVF x RF
For Oil-Fired Industrial Boilers between 275 and 5,500 MMBTU/hour :
TCI = 7,270 x (2,200/QB )0.35 x QB x ELEVF x RF
For Natural Gas-Fired Industrial Boilers between 205 and 4,100 MMBTU/hour :
TCI = 9,760 x (1,640/QB )0.35 x QB x ELEVF x RF
For Oil-Fired Industrial Boilers >5,500 MMBtu/hour:
TCI = 5,275 x QB x ELEVF x RF
For Natural Gas-Fired Industrial Boilers >4,100 MMBtu/hour:
TCI = 7,082 x QB x ELEVF x RF
Total Capital Investment (TCI) = $15,939,450 in 2019 dollars
Salt River Project RTP Environmental Associates, Inc.
SCR Cost Analysis for the Agua Fria Generating Station Unit 3. May 2020
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Annual Costs
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
Direct Annual Costs (DAC) = $752,678 in 2019 dollars
Indirect Annual Costs (IDAC) = $1,753,542 in 2019 dollars
Total annual costs (TAC) = DAC + IDAC $2,506,221 in 2019 dollars
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Catalyst Cost)
Annual Maintenance Cost = 0.005 x TCI = $79,697 in 2019 dollars
Annual Reagent Cost = qsol x Costreag x top = $491,396 in 2019 dollars
Annual Electricity Cost = P x Costelect x top = $33,728 in 2019 dollars
Annual Catalyst Replacement Cost = $147,857 in 2019 dollars
nscr x Volcat x (CCreplace/Rlayer) x FWF
Direct Annual Cost = $752,678 in 2019 dollars
Indirect Annual Cost (IDAC)
IDAC = Administrative Charges + Capital Recovery Costs
Administrative Charges (AC) = 0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost) = $3,476 in 2019 dollars
Capital Recovery Costs (CR)= CRF x TCI = $1,750,066 in 2019 dollars
Indirect Annual Cost (IDAC) = AC + CR = $1,753,542 in 2019 dollars
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Total Annual Cost (TAC) = $2,506,221 per year in 2019 dollars
NOx Removed = 385.5 tons/year
Cost Effectiveness = $6,501 per ton of NOx removed in 2019 dollars
Salt River Project RTP Environmental Associates, Inc.
SCR Cost Analysis for the Agua Fria Generating Station Unit 3. May 2020
315

Return to list of attachments
Reasonably Available Control Technology
(RACT) Analysis.
RACT Analysis for the control of nitrogen oxides (NOx) emissions from
simple-cycle simple cycle combustion turbine generators at the Salt River
Project Agua Fria and Kyrene Generating Stations.
July 2020
Prepared for:
Salt River Project
1500 N. Mill Avenue
Tempe, AZ 85281
www.srpnet.com
Prepared By:
RTP ENVIRONMENTAL ASSOCIATES INC.
304-A West Millbrook Rd.
Raleigh, NC 27609
316

Table of Contents
1.0 Introduction. ........................................................................................................ 2
2.0 Reasonably Available Control Technology. ..................................................... 3
2.1 RACT Evaluation. ........................................................................................................................ 3
2.2 Calculation of Cost Effectiveness. ................................................................................................ 4
2.3 Capital Recovery Costs. ............................................................................................................... 4
2.4 Fuel Costs. .................................................................................................................................... 5
2.5 Demineralized Water Costs. ......................................................................................................... 5
2.6 RACT Cost Effectiveness Threshold. ........................................................................................... 6
2.7 Conclusion and Proposed RACT Determination. ......................................................................... 8
3.0 NOx Emissions from Combustion Sources. ..................................................... 9
3.1 Thermal NOx. ................................................................................................................................ 9
3.2 Fuel NOx. ...................................................................................................................................... 9
3.3 Prompt NOx. ................................................................................................................................. 9
4.0 Available NOx Control Technologies. ............................................................. 10
4.1 Diffusion Flame Combustion. .................................................................................................... 10
4.2 Water and Steam Injection.......................................................................................................... 10
4.3 Dry Low NOx (DLN) Combustion. ............................................................................................ 11
4.4 Catalytic Combustion. ................................................................................................................ 11
4.5 Selective Catalytic Reduction (SCR). ......................................................................................... 11
4.6 Selective Non-Catalytic Reduction (SNCR)............................................................................... 12
4.7 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™). .............................................. 12
5.0 Agua Fria Simple Cycle CTG Units 4, 5, and 6. .............................................. 15
5.1 Technically Feasible Control Technologies. .............................................................................. 15
5.2 Water Injection. .......................................................................................................................... 15
5.3 Steam Injection. .......................................................................................................................... 18
5.4 DLN Combustion. ...................................................................................................................... 20
5.5 Selective Catalytic Reduction (SCR). ......................................................................................... 21
5.6 Conclusions. ............................................................................................................................... 23
6.0 Kyrene Simple Cycle CTG Unit 4. .................................................................... 24
6.1 Technically Feasible Control Technologies. .............................................................................. 24
6.2 Water Injection. .......................................................................................................................... 24
6.3 Steam Injection. .......................................................................................................................... 26
6.4 Selective Catalytic Reduction (SCR). ......................................................................................... 28
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6.5 Conclusions. ............................................................................................................................... 29
7.0 Kyrene Simple Cycle CTG Units 5 and 6. ....................................................... 30
7.1 Technically Feasible Control Technologies. .............................................................................. 30
7.2 Water Injection. .......................................................................................................................... 30
7.3 Steam Injection. .......................................................................................................................... 32
7.4 DLN Combustion. ...................................................................................................................... 34
7.5 Selective Catalytic Reduction (SCR). ......................................................................................... 35
7.6 Conclusions. ............................................................................................................................... 36
Tables
TABLE ES-1. Cost effectiveness of the NOx control options for the simple cycle CTGs at the Agua Fria
and Kyrene Generating Stations. .......................................................................................................... 1
TABLE 5-1. Water injection system capital costs for a Westinghouse Model 501-AA CTG and the capital
costs for the Agua Fria Units 4, 5, and 6. ........................................................................................... 16
TABLE 5-2. Annual costs and cost effectiveness for a water injection system for each Westinghouse
Model 501B simple cycle CTG. ......................................................................................................... 17
TABLE 5-3. Steam injection system capital costs for each Westinghouse Model 501B CTG. ............ 18
TABLE 5-4. Annual costs and cost effectiveness for a steam injection system for each Westinghouse
Model 501B simple cycle CTG. ......................................................................................................... 19
TABLE 5-5. Capital costs, annual costs, and cost effectiveness for an SCR system for each Agua Fria
Westinghouse Model 501B simple cycle CTG based on a 10% capacity factor. .............................. 21
TABLE 5-6. NOx control options, emission reductions, and cost effectiveness for each Agua Fria
Westinghouse Model 501B simple cycle CTG based on a 10% capacity factor. .............................. 23
TABLE 6-1. Annual costs and cost effectiveness for a water injection system for the Kyrene Unit 4
Westinghouse Model 501A simple cycle CTG. ................................................................................. 25
TABLE 6-2. Steam injection system capital costs for the Westinghouse Model 501A CTG. .............. 26
TABLE 6-3. Annual costs and cost effectiveness for a steam injection system for the Kyrene Unit 4
Westinghouse Model 501A simple cycle CTG. ................................................................................. 27
TABLE 6-4. Capital costs, annual costs, and cost effectiveness for an SCR system for the Kyrene Unit 4
Westinghouse Model 501A simple cycle CTG based on a 10% capacity factor. .............................. 28
TABLE 6-5. NOx control options, emission reductions, and cost effectiveness for the Kyrene Unit 4
Westinghouse Model 501A simple cycle CTG based on a 10% capacity factor. .............................. 29
TABLE 7-1. Annual costs and cost effectiveness for a water injection system for each General Electric
Model 7B simple cycle CTG. ............................................................................................................. 31
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TABLE 7-2. Steam injection system capital costs for each GE Model 7B CTG. .................................. 32
TABLE 7-3. Annual costs and cost effectiveness for a steam injection system for each GE Model 7B
simple cycle CTG. .............................................................................................................................. 33
TABLE 7-4. Capital costs, annual costs, and cost effectiveness for an SCR system for each Kyrene Unit 5
and 6 simple cycle CTG based on a 10% capacity factor. ................................................................. 35
TABLE 7-5. NOx control options, emission reductions, and cost effectiveness for each Kyrene Unit 5 and
6 simple cycle CTG based on a 10% capacity factor. ........................................................................ 36
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Executive Summary.
Salt River Project’s (SRP) Agua Fria and Kyrene Generating Stations are located in the portion of Maricopa
County which is classified as a moderate nonattainment area for ozone (O3). Maricopa County Air Pollution
Control Regulations (MCAPCR) Rule 322 requires the use of Reasonably Available Control Technology
(RACT) for the control of nitrogen oxides (NOx) emissions from power plants in the county.
For each simple cycle combustion turbine generators (CTG), Rule 322 currently prescribes a presumptive
NOx RACT emission limit of 42 parts per million by volume, dry basis (ppmdv) (calculated as nitrogen
dioxide) corrected to 15% oxygen when burning gaseous fuel, and 65 ppmdv when burning liquid fossil
fuel. For any unit with a calendar year annual capacity factor equal to or less than 10 percent, NOx RACT
requires only work practices; such units are not subject to numeric emission standards.
This report presents a NOx RACT analysis for six simple cycle CTGs: Units 4, 5, 6 at the Agua Fria
Generating Station and Units 4, 5, 6 at the Kyrene Generating Station. Each of these units has a calendar
year annual capacity factor equal to or less than 10 percent.
The U.S. Environmental Protection Agency has defined RACT as “the lowest emission limitation that a
particular source is capable of meeting by the application of control technology that is reasonably available
considering technological and economic feasibility.” The U.S. EPA’s most current guidance on NOx RACT
cost effectiveness indicates an economically reasonable range up to $2,300 per ton of NOx removed,
expressed in 2020 dollars.
Table ES-1 is a summary of the cost effectiveness of the NOx control options for the six affected simple
cycle CTGs based on a conservatively assumed annual capacity factor of 10 percent. The costs in Table
ES-1 are substantially higher than the cost effectiveness threshold of $2,300 per ton of NOx removed.
Accordingly, SRP proposes that Maricopa County Air Quality Department (MCAQD) reaffirm that NOx
RACT for simple cycle CTGs with a calendar year annual capacity factor equal to or less than 10 percent
is the use of diffusion flame combustion and good combustion practices with no numeric emission
standards.
TABLE ES-1. Cost effectiveness of the NOx control options for the simple cycle CTGs at the
Agua Fria and Kyrene Generating Stations.
Cost Effectiveness, $(2020) per ton of NOx controlled
NOx Control
Option Agua Fria Kyrene Kyrene
Units 4, 5, 6 Unit 4 Units 5, 6
Water Injection $3,600 $3,450 $3,770
Steam Injection $3,700 $3,820 $3,870
Advanced DLN Combustion $4,880 Not Technically $3,310
Feasible
Selective Catalytic Reduction (SCR) $6,540 $6,440 $6,530
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1.0 Introduction.
This document is a Reasonably Available Control Technology (RACT) Analysis for the control of nitrogen
oxides (NOx) emissions from simple cycle combustion turbine generators (CTGs) at the Agua Fria and
Kyrene Generating Stations. These generating stations are located in the portion of Maricopa County which
is classified as a moderate nonattainment area under the 2008 ozone National Ambient Air Quality Standard
(NAAQS).1 As part of the moderate classification, Maricopa County Air Quality Department (MCAQD)
Maricopa County Air Pollution Control Regulations (MCAPCR) Rule 322 requires RACT level of control
for oxides of nitrogen (NOx) emissions from power plant operations in the county. Agua Fria and Kyrene
Generating Stations have specifically identified emissions units in Rule 322 which are subject to RACT
requirements.
The units evaluated in this RACT analysis are Agua Fria Units 4, 5, 6 and Kyrene Units 4, 5, and 6.
Chapter 2 of this analysis includes a discussion of RACT, including a discussion of cost effectiveness
thresholds.
Chapter 3 includes a general discussion of NOx emissions from combustion sources, including the reaction
mechanisms responsible for NOx formation.
Chapter 4 includes an evaluation of available NOx control technologies for CTGs. The available controls
are then reviewed to determine controls which are technically feasible control options. The technical
feasibility of controls is further evaluated for each specific unit.
Chapters 5 through 7 include detailed RACT analyses for each specific type of simple cycle CTG at the
Agua Fria and Kyrene Generating Stations.
1 40 CFR § 81.303. See also 86 Fed. Reg. 26697 (May 4, 2016).
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2.0 Reasonably Available Control Technology.
The Code of Federal Regulations, 40 CFR § 51.908 et seq. specifies the attainment demonstration
requirements pursuant to section 182 of the Clean Air Act (CAA) for areas classified as moderate, serious,
severe, or extreme nonattainment areas. One of the requirements specified in 40 CFR § 51.912 is a RACT
state implementation plan (SIP) submission implementing CAA § 182(b)(2) and (f).
Reasonably available control technology is defined in 40 CFR § 51.100(o) as follows:
(o) Reasonably available control technology (RACT) means devices, systems, process modifications,
or other apparatus or techniques that are reasonably available taking into account:
(1) The necessity of imposing such controls in order to attain and maintain a national ambient air
quality standard;
(2) The social, environmental, and economic impact of such controls; and
(3) Alternative means of providing for attainment and maintenance of such standard. (This
provision defines RACT for the purposes of §51.341(b) only.)
This NOx RACT analysis report for the simple cycle CTGs at Agua Fria and Kyrene Generating Stations
has been prepared in order to assist MCAQD in satisfying its obligations relating to a NOx RACT SIP
submission. The report focuses on the environmental and economic impact of potentially available NOx
controls for the simple cycle CTGs at Agua Fria and Kyrene Generating Stations.
2.1 RACT Evaluation.
U.S. Environmental Protection Agency (U.S. EPA) has stated, “RACT for a particular source is determined
on a case-by-case basis, considering the technological and economic circumstances of the individual
source.”2
For purposes of this NOx RACT analysis report for the simple cycle CTGs at Agua Fria and Kyrene
Generating Stations, we have generally followed the approach recommended in applicable U.S. EPA
guidance.3,4 This guidance – particularly the Alternative Control Techniques Document – NOx Emissions
from Stationary Gas Turbines (“Gas Turbine ACT Document”) – provides useful information but does not
prescribe a methodological approach and does not establish presumptive RACT either for a category of
sources or for any individual source.5 In addition to the Gas Turbine ACT Document, we used vendor
2 44 Fed. Reg. 53761 at p. 53762 (Sept. 17, 1979).
3 See, for example, U.S. EPA, Alternative Control Techniques Document – NOx Emissions from Stationary Gas
Turbines, EPA-453/R-93-007 (Jan. 1993).
4 The cost estimating approach generally recommended by U.S. EPA for RACT and other purposes is set forth in a
series of control cost manuals. The most up-to-date, complete edition of this guidance document is EPA Air Pollution
Control Cost Manual, Sixth Edition (EPA/452/B-02-001) (Jan. 2002) (“Control Cost Manual”).
5 See, for example, 57 Fed. Reg. 55620 at p. 55625 (Nov. 25, 1992) (“Similar to the CTGs issued for VOC source
categories, the ACTs will contain extensive background information on control technologies, costs, availability. etc.,
that can be used by States in making RACT determinations. However, unlike the CTGs, the ACTs will not established
[sic] a presumptive RACT.”)
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information, vendor budgetary quotes, unit performance, other U.S. EPA information, and other technical
sources as discussed in subsequent sections of this report. Historical cost information is adjusted to present
2020 costs using the consumer price index (CPI) published by Bureau of Labor Statistics.
The NOx RACT analysis presented in this report is based on the evaluation of the following criteria for each
emissions unit or for each specific type of emissions unit:
1. A review of available and technically achievable control technologies and the
achievable emissions reduction.
2. The cost effectiveness of the control option expressed in dollars per ton of emission
reduction ($/ton).
3. If applicable, other potential social and environmental impacts of the control option.
2.2 Calculation of Cost Effectiveness.
The RACT evaluation includes an evaluation of environmental, energy, and economic impacts. The most
important issue in a RACT analysis is typically the economic reasonableness of the control option. This
parameter is typically evaluated according to the cost effectiveness of the control option, expressed in
dollars per ton of pollutant reduced. Both average and incremental cost effectiveness may be calculated;
however, for the NOx RACT analysis for the simple cycle CTGs at Agua Fria and Kyrene Generating
Stations, only average cost effectiveness is necessary. This parameter represents the overall effect of a
particular control technique relative to a baseline condition and is calculated as follows, using the total
annualized cost of the control option under review:
Average Cost Effectiveness Control option annualized cost
=
($ per ton removed) Baseline emission rate – Control option emissions rate
2.3 Capital Recovery Costs.
Under applicable U.S. EPA guidance, including the Gas Turbine ACT Document, the total annualized cost
of a control option includes the annual cost required to recover the capital investment associated with that
control option. This value is calculated using a Capital Recovery Factor (CRF), which is the ratio of a
constant annual payment or annuity to the present value of receiving that annuity for a given length of time.6
For an interest rate i and n years for the project, the CRF is:
𝑖𝑖(1 + 𝑖𝑖)𝑛𝑛
𝐶𝐶𝐶𝐶𝐶𝐶=
[(1 + 𝑖𝑖)𝑛𝑛−1]
Where, i = Interest rate or cost of capital, fraction
6 See, for example, Gas Turbine ACT Document at p. 2-28 (“Capital costs were annualized using the capital recovery
factor method with an equipment life of 15 years and an annual interest rate of 10 percent.”)
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n = Equipment or Project life, years
In this RACT analysis, the interest rate i is 7.0%, consistent with MCAQD guidance.7
The project life for all pollution control technology alternatives evaluated in this RACT analysis has been
based on an equipment life of 15 years. This equipment life was used for evaluating control technology
costs in the Gas Turbine ACT Document:
The life of the control equipment depends upon many factors, including application,
operating environment, maintenance practices, and materials of construction. For this study, a 15-
year life was chosen.8
This project life in the ACT was used for evaluating water and steam injection, low-NOx combustion, and
selective catalytic reduction control systems.
Substituting the interest rate of 7.0% and project life of 15 years into the above equation, the CRF value is:
𝑖𝑖 (1 + 𝑖𝑖 )𝑛𝑛 0.07(1 + 0.07)15
𝐶𝐶𝐶𝐶𝐶𝐶= = = 0.10979
[ (1 + 𝑖𝑖 )𝑛𝑛−1] [ (1 + 0.07 )15 −1]
The annual cost for the capital investment is then calculated as the product of the CRF and the Total Capital
Cost (TCC):
Annual Capital = CRF × TCC
Recovery Cost
2.4 Fuel Costs.
Some NOx control systems may have an efficiency penalty. That is, the technology may reduce the
efficiency of the CTG. To evaluate efficiency impacts, a uniform natural gas cost of $3.00 per million Btu
has been used in this RACT analysis. This value is representative of the long-term average costs of natural
gas delivered to the affected generating stations.
2.5 Demineralized Water Costs.
Demineralized water costs for pollution control systems like water injection have been estimated using the
methods described in How to Estimate Utility Costs, G. D. Ulrich and T.T. Vasudevan, University of New
7 MCAQD, Requirements, Procedures and Guidance in Selecting BACT and RACT (revised Jan. 2019). This rate is
conservative; the rate suggested in the Gas Turbine ACT Document is 10%.
8 Gas Turbine ACT Document at p. 6-206.
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Hampshire, published in Chemical Engineering, pages 66 – 69, April 2006. Utility costs are given by the
following equation:
𝐶𝐶𝑆𝑆,𝑢𝑢 = 𝑎𝑎 (𝐶𝐶𝐶𝐶 PCI) + 𝑏𝑏൫𝐶𝐶𝑆𝑆,𝑓𝑓൯
Where, CS,u = Price of the Utility
a, b = Utility Coefficients
CE PCI = Chemical Engineering Plant Cost Index
CS,f = Price of Fuel, $/GJ
For demineralized (boiler feed) water costs in $ per cubic meter ($/m3), the coefficients a and b are given
in Table 1 of How to Estimate Utility Costs as:
𝑏𝑏 = 0.04
𝑎𝑎 = 0.005 + 0.0002𝑞𝑞−0.6
q = Demineralizer water capacity, cubic meters per second
For a demineralized water flowrate of 100 gallons per minute (0.0063 m3/sec), the coefficient a is 0.00918.
The December 2019 Chemical Engineering Plant Cost Index is 592.1. For natural gas, the price of fuel,
CS,f , is $3.0/GJ ($3.00/MMBtu). Therefore, the utility cost for demineralized water is:
𝐶𝐶𝑆𝑆,𝐷𝐷𝐷𝐷 = 𝑎𝑎(𝐶𝐶𝐶𝐶 PCI) + 𝑏𝑏൫𝐶𝐶𝑆𝑆,𝑓𝑓൯= 0.00918(592.1) + 0.04(3.0) = 5.42 + 0.12 = $5.555/𝑚𝑚3
For 264.17 gallons per cubic meter, this demineralized water cost is equal to $0.02103 per gallon of
demineralized water produced. This cost is used for all cost evaluations in this RACT analysis.
2.6 RACT Cost Effectiveness Threshold.
The most current U.S. EPA guidance available regarding cost effectiveness thresholds for NOx RACT
determinations is a 1994 memorandum, Cost-Effective Nitrogen Oxides (NOx) Reasonably Available
Control Technology (RACT). According to this guidance, the high end of the range for cost effective RACT
control options is $1,300 per ton of pollutant controlled.9 The U.S. EPA reaffirmed the relevancy of this
guidance in its final rule to implement the 8-hour ozone NAAQS in 2005.10 Specifically, in the Federal
Register notice for this final rule, U.S. EPA rejected comments suggesting RACT requirements should be
more stringent, characterizing the $1,300 per ton threshold as “our current guidance.”11
9 U.S. EPA, Cost-Effective Nitrogen Oxides (NOx) Reasonably Available Control Technology (RACT), memorandum
from D. Kent Berry, Acting Director Air Quality Management Division (MD-15) (March 16, 1994).
10 70 Fed. Reg. 71612 (Nov. 29, 2005).
11 Ibid at p. 71654.
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Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 1994 has the same buying power as $1.75 in March 2020. Therefore, U.S.
EPA’s NOx RACT cost effectiveness threshold of $1,300 per ton in 1994 is equal to $2,300 in 2020.
The cost effectiveness threshold of $2,300 per ton derived above is lower than the threshold of $2,800 per
ton used by the Commonwealth of Pennsylvania in adopting NOx RACT rules that were recently approved
by U.S. EPA. As recognized by U.S. EPA in this SIP rulemaking, States have discretion to apply reasonable
thresholds:
EPA is aware that Pennsylvania considered cost-effectiveness levels that are lower than other states
in the OTR when developing the RACT II Rule; however, states have the discretion to determine
what costs are considered reasonable when establishing RACT for its sources. For these reasons,
EPA has not set a single cost, emission reduction, or cost-effectiveness figure to fully define cost-
effectiveness in meeting the NOx RACT requirement. Therefore, each state must make and defend
its own determination on how to weigh these values in establishing RACT. PADEP relied on a cost-
effectiveness of $2,800 per ton of NOx controlled and $5,500 per ton of VOC controlled for the
presumptive limits in the RACT II Rule.12
In addition to the cost effectiveness threshold, the manner in which this threshold is applied in determining
RACT for a category of sources is critically important. The way in which the threshold of $2,800 per ton
was applied in establishing NOx RACT in the Commonwealth of Pennsylvania was summarized by U.S.
EPA as follows:
In determining its presumptive NOx RACT limits under the RACT II Rule, PADEP considered
controls to be economically reasonable when installed and operated under $2,500 per ton of NOx
removed. EPA finds PADEP’s cost effectiveness threshold reasonable. Based on our analysis, EPA
found that cost-effectiveness of SCR in Pennsylvania boilers ranged from $3,651-$25,238 per ton,
while SNCR ranged from $2,217 to $17,594 per ton for conventional boilers (non-CFBs) and $6,076
to $19,732 per ton for CFB boilers. Because cost-effectiveness of these controls exceeded $2,500
per ton of NOx removed for the majority of coal-fired boilers in Pennsylvania without these controls
in place, it is reasonable to conclude that it would be economically infeasible to require the
installation and operation of SCR or SNCR on all coal-fired boilers in Pennsylvania. Based on this
analysis, EPA concludes that PADEP’s RACT II Rule determination for any large coal-fired boilers
without post-combustion controls in place is based on the operation of existing controls, in most
cases LNB and/or OFA. Thus, EPA finds that PADEP’s determination for this subset of coal-fired
boilers is reasonable, considering economic infeasibility of retrofitting these additional controls.13
12 84 Fed. Reg. 20274 at 20286 (May 9, 2019).
13 U.S. EPA, Technical Support Document for the Pennsylvania State Implementation Plan Revision for Certain Reasonably
Available Control Technology Requirements under the 1997 and 2008 8-hour Ozone National Ambient Air Quality Standard at
24 (Feb. 22, 2018). Available at www.regulations.gov/contentStreamer?documentId=EPA-R03-OAR-2017-0290-
0017&contentType=pdf. Internal citations omitted; emphasis in original.
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2.7 Conclusion and Proposed RACT Determination.
The circumstances present in the NOx RACT analysis for coal-fired boilers without add-on NOx controls in
Pennsylvania, as discussed in Section 2.6 above, are representative of those for this RACT analysis: There
are a small number of simple-cycle CTGs with annual capacity factors14 less than 10 percent in Maricopa
County and, as shown in sections 5.0 through 7.0 of this report, there are no additional control measures
that are economically reasonable for these units either individually or as a group.
The approach taken by the Commonwealth of Pennsylvania and approved by U.S. EPA should be applied
here: RACT should be established based on the use of work practices and these units should not be subject
to numeric emission standards.
Based on the NOx RACT analysis presented herein, SRP proposes the following as RACT for simple cycle
CTGs with capacity factor equal to or less than 10%, including Units 4, 5, and 6 at the Agua Fria Generating
Station and Units 4, 5, and 6 at the Kyrene Generating Station:
1. Nitrogen oxide (NOx) emissions shall be controlled using diffusion flame combustion.
2. The owner or operator shall implement operational practices recommended by the manufacturer
and shall ensure good combustion control through monitoring of temperature differential across
the combustion burners or at locations around the back end of the turbine.
14 All references to “annual capacity factor” in this report are based on the definition in section 201 of Rule 322 as
revised Nov. 2, 2016. This definition uses heat input rather than electric output.
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3.0 NOx Emissions from Combustion Sources.
Nitrogen oxides (NOx) consist of both nitrogen oxide (NO) and nitrogen dioxide (NO2). During
combustion, NO typically accounts for about 50% to 90% of the total NOx emissions. However, since NO
is converted to NO2 in the atmosphere, the mass emission rate of NOx is usually reported as NO2.
NOx is formed during combustion in combustion turbines through three mechanisms;
1. Thermal Formation,
2. Fuel Formation, and
3. Prompt Formation.
3.1 Thermal NOx.
Of these three formation mechanisms, thermal formation or thermal NOx is expected to represent at least
70% of the total NOx formation. Thermal NOx results from the high temperature oxidation of nitrogen (N2)
and oxygen (O2). In this mechanism, N2 is supplied from air, which is 78% N2 by volume. The thermal
NOx reactions are described by the Zel’dovich mechanism as follows:
N2 + O ↔ NO + N (1)
N + O2 ↔ NO + O (2)
N2 + O2 ↔ 2NO (1) Overall
The first step is rate limiting due to its high activation energy. As a result, thermal NOx requires high
temperatures to proceed. Thermal NOx formation increases exponentially with temperature, becoming
significant at temperatures above approximately 2,800 °F. Because thermal NOx formation increases
exponentially with temperature and because thermal NOx accounts for a large share of the total NOx
emissions, combustion control systems which reduce peak flame temperatures are effective NOx controls
for combustion turbines.
3.2 Fuel NOx.
Fuel NOx results from the oxidation of organic nitrogen compounds in the fuel. Because fuel bound
nitrogen is more easily converted to NOx during combustion, nitrogen levels in fuel can have a significant
impact on NOx formation. However, since both natural gas and distillate fuel oil have only trace organic
nitrogen compounds, fuel NOx formation is expected to be very small for these natural gas and fuel oil-
fired CTGs.
3.3 Prompt NOx.
Prompt NOx is formed by the reaction of hydrocarbon radicals with atmospheric nitrogen to produce
hydrogen cyanide (HCN) and ultimately NOx through a complex series of gas phase reactions. Prompt NOx
is expected to account for 20 – 30% of the total NOx emissions. Like thermal NOx, prompt NOx formation
can be reduced through combustion controls which reduce peak flame temperatures.
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4.0 Available NOx Control Technologies.
The RACT evaluation process starts with identifying available control technologies for the source. The
available controls are then reviewed to determine controls which are technically feasible control options.
Note that the following is a general discussion of available controls. However, the applicability of these
controls must be determined for each type of CTG as discussed in sections 5.0 through 7.0 of this report.
Based on a review of recent BACT determinations from the U.S. EPA’s RACT/BACT/LAER
Clearinghouse and a literature review including the U.S. EPA’s Compilation of Air Pollutant Emission
Factors AP-42, Chapter 3.1, Stationary Gas Turbines, April 2000, as well as the Gas Turbine ACT
Document, the following are generally available NOx control technologies for simple cycle CTGs:
Combustion Controls 1. Diffusion Flame Combustion with
a. Water Injection
b. Steam Injection
2. Dry low NOx (DLN) Combustion
3. Catalytic Combustion
Post Combustion Controls 4. Selective Catalytic Reduction (SCR)
5. Selective Non-Catalytic Reduction (SNCR)
6. EMx™ Catalytic Absorption Process (EMx or SCONOx™)
The first three (3) control technologies are combustion control technologies. The last three (3) technologies
are post combustion flue gas treatment technologies.
4.1 Diffusion Flame Combustion.
In a diffusion flame combustor, air from the turbine compressor discharge is mixed with fuel in the flame
zone at a near stoichiometric ratio. The fuel/air mixing and combustion take place simultaneously in the
primary combustion zone. This results in a stable flame but also results in high flame temperatures and high
NOx emission rates. For the most part, diffusion flame combustion will result in the highest levels of NOx
emissions from CTGs.
4.2 Water and Steam Injection.
NOx emissions from diffusion flame combustors can be reduced by injecting water or steam into the
combustion zone. Water is an inert substance in the combustion process which lowers combustion
temperature and therefore reduces thermal NOx formation. Steam or water injected into the combustion
zone acts as a heat sink which lowers peak flame temperatures. Even evaporative cooling, a technique for
increasing turbine output during hot dry conditions, can lower NOx emissions through this mechanism.
Water or steam injection will generally achieve control efficiencies of at least 70% when firing natural gas.
Although water and steam injection cannot be applied to all CTGs, the use of water and steam injection are
generally considered technically feasible control technologies for CTGs with diffusion flame combustors.
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In addition, water and steam injection can increase CTG power output, but water injection is also expected
to result in a heat rate (thermal efficiency) penalty.
4.3 Dry Low NOx (DLN) Combustion.
Dry Low NOx (DLN) combustion for CTGs is a staged combustion system which reduces peak flame
temperatures and reduces thermal and prompt NOx formation. Modern DLN systems lower the combustion
temperature using lean mixtures of air and/or fuel staging. In a typical DLN combustor, air and fuel are
mixed in a premix zone. The premixed air/fuel mixture is then ignited in the flame zone. In DLN
combustors, the excess air acts as a heat sink to lower combustion temperatures.
There are two types of DLN combustors. Two stage lean/lean combustors involve fuel stage and premixed
combustors in which each stage burns lean. These DLN combustors lower NOx emissions by reducing peak
flame temperatures and providing uniform combustion with minimal hot spots. Two stage rich/lean
combustors use air stage and premixed combustors where the primary zone is operated fuel rich and the
secondary zone is operated fuel lean. In the primary zone, the rich mixture produces lower temperatures
and decreases the amount of oxygen available for NOx formation. Exhaust from the primary zone is
quenched with air in the secondary zone. Combustion of the pre-ignited rich mixture is completed in the
secondary fuel lean zone which reduces NOx emissions by reducing combustion temperature.
While DLN combustion is capable of achieving very low NOx emission rates, especially on new CTGs,
because combustion turbines are complex internal combustion engines, DLN combustion is not applicable
to all CTGs.
4.4 Catalytic Combustion.
Catalytic combustion is a NOx control strategy for combustion turbines that reduces the temperature in the
combustor thereby limiting NOx formation. The only identified available catalytic combustion system for
combustion turbines is K-LEAN™ (formerly XONON™). This technology has been demonstrated only
for small CTGs of 1.4 megawatts electric (MWe) output capacity and has not been demonstrated as a retrofit
technology for existing CTGs. Therefore, this technology is not considered to be available or technically
feasible for these CTGs.
4.5 Selective Catalytic Reduction (SCR).
Selective Catalytic Reduction (SCR) is a post combustion flue gas treatment for controlling NOx emissions
which uses an ammonia (NH3) injection system and a catalytic reactor. SCR systems utilize an injection
grid which disperses ammonia in the flue gas upstream of the catalyst. NH3 reacts with NOx in the presence
of the catalyst to form nitrogen (N2) and water according to the following equations:
4NH3 + 4NO + O2 → 4N2 + 6H2O
4NH3 + 2NO2 + O2 → 3N2 + 6H2O
2NH3 + NO2 + NO → 2N2 + 3H2O
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Catalysts are substances which evoke chemical reactions that would otherwise not take place by providing
a reaction mechanism that has a lower activation energy than the uncatalyzed mechanism. For SCR, the
catalyst is usually a ceramic noble metal, a base metal (titanium or vanadium) oxide, or a zeolite-based
material. To achieve optimum long-term NOx reductions, SCR systems must be properly designed for each
application. In addition to critical temperature considerations, the ammonia injection rate must be carefully
controlled to maintain an NH3/NOx molar ratio that effectively reduces NOx. Excessive ammonia injection
will result in ammonia emissions, called ammonia slip.
SCR has the capability to make substantial reductions in NOx emissions. For these CTGs, the use of SCR
is expected to reduce NOx emissions by 90%.
4.6 Selective Non-Catalytic Reduction (SNCR).
In a selective non-catalytic reduction (SNCR) control system, urea or ammonia is injected into boilers
where the flue gas temperature is approximately 1,600 °F to 2,100 °F. At these temperatures, urea
[CO(NH2)2] or ammonia reacts with NOx, forming elemental nitrogen and water, without the need for a
catalyst. The overall NOx reduction reactions are similar to those for SCR. Multiple injection points are
required to thoroughly mix the reagent into the boiler furnace. The limiting factor for a SNCR system is
the ability to contact the NOx with the reagent without resulting in excessive ammonia slip and without
excessive ammonia decomposition before the NOx emissions can be reduced. SNCR may be expected to
reduce NOx emissions from 30% to 50% from the uncontrolled levels depending on the boiler application15.
SNCR has been widely used in circulating fluidized bed boilers burning solid fuels such as coal. However,
the time and temperature range for SNCR is not compatible with gas turbines. We are not aware of the
application of SNCR to any gas turbine either in the U.S. or worldwide. Therefore, SNCR is not a
technically feasible control technology for the affected CTGs.
4.7 EMx™ Catalytic Absorption/Oxidation (formerly SCONOx™).
The EMx™ system is an add-on control device that catalytically oxidizes NO to NO2 and then adsorbs the
NO2 onto a potassium carbonate-coated catalyst surface. The overall chemical reaction between NO2 and
the potassium carbonate catalyst is as follows:
2 NO2 + K2CO3 → CO2 + KNO2 + KNO3
The EMx™ process does not require injection of a reactant, such as ammonia, into the gas stream being
treated. EMx™ catalyst is reported to perform acceptably in the operating temperature range of 425 °F to
750 °F with the best economy and lowest pressure drop achieved in the temperature range of 550 °F to 650
15 From the U.S. EPA’S Air Pollution Control Technology Fact Sheet, Selective Non-Catalytic Reduction (SNCR),
EPA-452/F-03-031.
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°F where the catalyst activity is highest and the catalyst volume is minimized.16 Based on this claimed
operating range, it is not feasible to install an EMx™ system on a simple cycle combustion turbine without
a massive dilution air system.17
The EMx™ catalyst has a finite capacity to react with NO2 because potassium carbonate is “consumed” by
NO2 as shown above. Thus, in order to maintain the required NOx removal rate, the catalyst must be
periodically regenerated. Regeneration is accomplished by passing a reducing gas containing hydrogen in
dilute concentration (i.e., about 2 to 4 percent H2) across the surface of the catalyst in the absence of oxygen.
Hydrogen in the regeneration gas reacts with the nitrites and nitrates to form water and molecular nitrogen.
Carbon dioxide in the regeneration gas reacts with the potassium nitrite and nitrates to regenerate potassium
carbonate, which is the original chemical in the catalyst coating. The overall chemical reaction during
catalyst regeneration is as follows:
KNO2 + KNO3 + 4 H2 + CO2 → K2CO3 + 4 H2O + N2
The regeneration gas is produced in a gas generator using a two-stage process to produce molecular
hydrogen and carbon dioxide. In the first stage, natural gas and air are reacted across a partial oxidation
catalyst to form carbon monoxide and hydrogen. Steam is then added to the mixture and passed across a
low temperature shift catalyst, forming carbon dioxide and more hydrogen. The regeneration gas mixture
is diluted to less than four percent hydrogen using steam.
In order to regenerate its catalyst, the EMx™ system is constructed in parallel modules so that a module
can be isolated from the combustion turbine exhaust gas stream using inlet and outlet dampers. The isolated
module is then regenerated while other modules remain open to flow for treatment of the combustion turbine
exhaust gas stream.
Sulfur compounds (e.g., SO2, SO3) in the gas quickly inactivate the EMx™ catalyst requiring the catalyst
to be removed from the reactor for regeneration. To avoid this problem, EMx™ systems on natural gas
fueled combustion turbines include an upstream ESx™ catalyst module that removes the sulfur compounds
before they reach the EMx™ catalyst beds. The ESx™ catalyst is regenerated at the same time as the
EMx™ catalyst by the same regeneration gas. This releases collected SOx as SO2 into the regeneration off-
gas stream.
EMx™ is demonstrated for use on relatively small combined-cycle natural gas fueled combustion turbines.
The largest application is the 50 MW Unit 6 combined cycle combustion turbine at the Redding, California
municipal power plant. EMx™ has not been demonstrated on a large combined cycle combustion turbine
or on any simple-cycle combustion turbine. The La Paloma Generating Project in California initially
16 See, for example, http://docketpublic.energy.ca.gov/PublicDocuments/Regulatory/Non%20Active%20AFC's/07-
AFC-9%20Canyon/2009/January/TN%2049920%2001-28-09%20ECM%20Technology%20White%20Paper.pdf at
page 38 of the PDF file.
17 Depending on CTG load and ambient temperatures, the amount of dilution air needed for EMx™ at 700 °F would
be two to three times the amount of dilution air needed for SCR at 900 °F. Under some operating conditions, dilution
to accommodate EMx™ could nearly double the gas flow through the combustion turbine stack.
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proposed to demonstrate EMx™ on a 150 MW turbine, but ultimately an SCR system was installed instead.
This was also the case with the Otay Mesa project located in California.
Some of the issues identified with applying EMx™ are:
• The catalyst is very sensitive to sulfur in the exhaust gas;
• The reliability of the system’s moving parts over time is an operational and maintenance concern;
• The use of hydrogen for regeneration could be a serious safety concern;
• The potential exists for scale-up issues for larger CTGs such as those at the Agua Fria and Kyrene
Generating Stations;
• An EMx™ system has significant pressure drop – about twice that of a comparable SCR system –
which presents design challenges not currently addressed in the installed simple cycle combustion
turbine population.
EMx™ is infeasible because it has not been demonstrated on any combustion turbine larger than 50 MW.
Size is an important issue for the EMx™ process as it is more suited to small-scale applications and it has
been rejected due to size/scale-up considerations in other situations. More significantly, EMx™ has not
been demonstrated on any simple cycle CTGs such as those at the Agua Fria and Kyrene Generating
Stations. The exhaust temperature from the simple cycle CTGs at the Agua Fria and Kyrene Generating
Stations is too high for application of EMx™ technology.
For these reasons, EMx™ is not considered feasible for this RACT analysis.
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5.0 Agua Fria Simple Cycle CTG Units 4, 5, and 6.
The Agua Fria Units 4, 5, and 6 are natural gas and distillate fuel oil-fired simple cycle CTGs. These units
have very low utilization, with a typical capacity factor less than 1 percent, and essentially 100% of the heat
input to all three boilers is typically natural gas.
Units 4, 5, and 6 are each Westinghouse Model 501B simple cycle CTGs rated at 80 MWe and having a
maximum design heat input capacity of 1,129 MMBtu per hour. These CTGs have no NOx controls.
For this RACT analysis, the uncontrolled NOx emission rate for all control technologies is based on an
uncontrolled NOx emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb NOx/MMBtu.
5.1 Technically Feasible Control Technologies.
For the Agua Fria Units 4 and 5, and 6, the available NOx control technologies are diffusion flame
combustion, with or without water or steam injection; dry low NOx combustion; and SCR.
5.2 Water Injection.
Water injection systems for these CTGs is expected to reduce NOx emissions when firing natural gas from
a worst-case uncontrolled emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb/MMBtu, to 25 ppmdv at
15% O2 and 0.092 lb/MMBtu.
Water injection systems for these Westinghouse 501B CTGs would include water injection nozzles, flow
metering controls, pumps, hardware, and interconnecting piping from a water treatment system to each
CTG. The water treatment system would include reverse osmosis demineralization systems and storage
tanks. Table 5-1 is a summary of the capital costs for a water injection system for Westinghouse Model
501-AA simple cycle CTGs which have a rated capacity of 55 MW(e) from a 2018 vendor quote for
supplying water injection for Westinghouse 501-AA CTGs owned and operated by Arizona Public Service
(APS).
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TABLE 5-1. Water injection system capital costs for a Westinghouse Model 501-AA CTG and the
capital costs for the Agua Fria Units 4, 5, and 6.
Item Cost
Equipment Costs Water Injection (Water pump to unit, no water supply) $1,060,000
(from Supplier Quote) Water Supply (tank, associated piping, valves) $448,000
Shipping $13,000
Tax $69,000
Interface with DCS (APS costs) $60,000
Wiring and Conduit $45,000
Contract Administration (APS costs) $9,000
Project Management (APS costs) $25,000
Engineering Design and Review (contract) $113,000
Foundation, Incidentals, APS Engineering Support $10,000
and Indirect Costs (APS
Engineering Estimate) Inspection and Review $6,000
Construction Management (contract) $27,000
Start-up and Commissioning (B&M) $20,000
I&C Support (APS) $24,000
Performance Testing and Permitting $32,000
Control Integration (APS) $7,000
Operational Spare Parts $91,000
Contingency (based on 20% of total costs) $289,000
TOTAL CAPITAL COST, Westinghouse Model 501-AA CTG $2,348,000
TOTAL CAPITAL COST, Westinghouse Model 501B CTG $2,940,000
The water injection system costs for SRP’s 80 MWe CTGs in 2018 dollars was calculated using the
equipment costs in Table 5-1 and adjusted to the larger Model 501B CTGs using the six-tenth factor rule
which is an empirical relationship between the cost and the size of a manufacturing facility or equipment.18
0.6 0.6
C501B = C501AA ൬S501B ൰ = $2,348,000 ൬80 55൰ = $2,940,000
S501AA
Where C501B = Cost for the SRP Westinghouse Model 501B CTGs
18 See, for example, U.S. EPA, Basis for Denial of Petitions to Reconsider the CAA Section 111(b) Standards of
Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric
Utility Generating Units (April 2016) (“This power law scaling approach is a very common application of what is
referred to as the ‘six-tenths rule’ …. Following the advice of Peters and Timmerhaus, it is common practice for
design engineers to use the 0.6 factor ‘in the absence of other information’ when estimating equipment costs by
scaling.”).
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C501AA = Cost for the APS Westinghouse Model 501AA CTGs
S501B = Size for the SRP Westinghouse Model 501B CTGs = 80 MW
C501AA = Cost for the APS Westinghouse Model 501AA CTGs = 55 MW
As shown above, substituting the total capital cost for the Model 501AA CTGs of $2,348,000 and the sizes
of each CTG into this equation, the resulting cost of water injection for each Model 501B CTG would be
$2,940,000 in 2018 dollars.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 2018 has the same buying power as $1.03 in March 2020. The total capital
cost of water injection systems for Agua Fria Units 4, 5, and 6 in current dollars is $3,028,000.
Table 5-2 is a summary of the annual costs and the cost effectiveness for water injection systems for the
Agua Fria Model 501B CTGs.
The annual capital recovery cost is calculated as the product of the total capital cost of $3,028,000 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 3% loss
in CTG efficiency with water injection and a natural gas cost of $3.00 per MMBtu. The water injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
The emission reduction in Table 5-2 is based on a water injection NOx emission rate when firing natural
gas of 25 ppmdv at 15% O2 equal to 0.092 lb/MMBtu, an uncontrolled emission rate of 135 ppmdv at 15%
O2, equal to 0.50 lb/MMBtu, and a CTG capacity factor of 10%:
1,129 MMBtu 876 hr lb NOx 1.0 ton NOx
Emission Reduction = × × ൬ 0.50 −0.092 MMBtu൰ ×
hr yr 2,000 lb NOx
Emission Reduction = 201.8 ton/year
TABLE 5-2. Annual costs and cost effectiveness for a water injection system for each
Westinghouse Model 501B simple cycle CTG.
Capital Recovery Cost $332,500 $3.028MM × 0.10979
Fuel Cost $89,000 3.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $118,700 1 lb demin water per lb fuel and $0.02103/gal
(see Section 2.5).
Maintenance Cost $49,600 From Table B-2 of the NOx ACT
Plant Overhead Cost $14,900 30% of Annual Maintenance Cost
General & Administrative, Taxes, Insurance $121,100 4% of Total Capital Cost
TOTAL ANNUAL COST $725,800
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Emission Reduction 201.8 ton NOx/year
COST EFFECTIVENESS $3,600 $ per ton of NOx controlled
From Table 5-2, even assuming a potential emission reduction of 201.8 tons per year based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
and a capacity factor of 10%, the use of water injection on each Westinghouse Model 501B simple cycle
CTG would have a cost effectiveness of $3,600 per ton of NOx controlled. This calculation result is
conservative, as it greatly overstates the achievable emission reduction.
In addition, the use of water injection would consume 5.6 million gallons of water per year per unit. This
is a substantial amount of water in an arid region in which water is a valuable natural resource. Based on
these facts, the use of water injection for the control of NOx emissions from the Agua Fria Westinghouse
Model 501B simple cycle CTGs is not a feasible RACT option.
5.3 Steam Injection.
Like water injection, steam injection systems for these CTGs is expected to reduce NOx emissions when
firing natural gas from a worst-case uncontrolled emission rate of 135 ppmdv at 15% O2, equal to 0.50
lb/MMBtu, to 25 ppmdv at 15% O2 and 0.092 lb/MMBtu.
Although steam injection is a technically feasible NOx control option, steam injection is less frequently
used than water injection. Like the water injection systems, steam injection systems would include injection
nozzles, flow metering controls, pumps, hardware, and interconnecting piping from a water treatment
system to each CTG. In addition, a steam injection system would require a boiler to convert the
demineralized water to steam. This boiler may be a natural gas-fired boiler, or it may be placed in the CTG
flue gas outlet plenum to use waste heat from the CTG to create steam.
Table 5-3 is a summary of the capital costs for a steam injection system for each of the Agua Fria Model
501B CTGs. These costs are based on Chapter 6 of the Gas Turbine ACT Document. All costs have been
escalated from 1990 to March 2020 dollars based on the CPI.
TABLE 5-3. Steam injection system capital costs for each Westinghouse Model 501B CTG.
Purchased Equipment Costs (PEC)
Steam Injection System $870,000 Based on $4,200 per gallon per minute (GPM) as steam
Water Treatment System $878,000 WTS = 43,900 x GPM0.5
Taxes and Freight $140,000 8% of the total system costs
Direct Installation Costs
Direct Costs $850,000 45% of Purchased Equipment Costs
Indirect Installation Costs
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Indirect Costs $586,000 33% of the PEC and Direct Costs + $5,000
Contingency Costs $665,000 20% of the Sum of the PEC, Direct and Indirect Costs
TOTAL CAPITAL COST $3,989,000
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
2. Costs are based on the following combustion turbine and water injection system design conditions:
CTG Heat Input Capacity 1,129 MMBtu/hr
Natural Gas Heat Value 21,000 Btu per pound, HHV
Natural Gas Fuel Flow Rate 53,762 lb/hour
Steam-to-Fuel Ratio (Ω) 1.0 lb steam/lb fuel
Water Flowrate 107 gallons per minute (GPM)
Water Flowrate 5,643,600 gallons per year
Cost Escalation (Inflation) Factor 1.93 Escalated from Dec. 1990 to Mar. 2020 based on the CPI.
Table 5-4 is a summary of the annual costs and the cost effectiveness for steam injection systems for the
Agua Fria Model 501B CTGs.
The annual capital recovery cost is calculated as the product of the total capital cost of $4,214,000 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 1% loss
in CTG efficiency with steam injection and a natural gas cost of $3.00 per MMBtu. The steam injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
TABLE 5-4. Annual costs and cost effectiveness for a steam injection system for each
Westinghouse Model 501B simple cycle CTG.
Capital Recovery Cost $438,000 Based on the Total Capital Cost in Table 5-3.
Fuel Penalty Cost $29,700 1.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $118,700 1 lb steam per lb fuel and $0.02103/gal (see
Section 2.5).
Maintenance Cost The NOx ACT indicates no additional turbine
Plant Overhead $0 maintenance cost for steam injection.
General & Adm., Taxes, Insurance (GATI) $159,600 4% of Total Capital Cost
TOTAL ANNUAL COST $746,000
Emission Reduction 201.8 ton NOx/year
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Cost Effectiveness $3,700 $ per ton of NOx controlled
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
From Table 5-4, even assuming a potential emission reduction of 201.8 tons per year based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
and a capacity factor of 10%, the use of steam injection on each Westinghouse Model 501B simple cycle
CTG would have a cost effectiveness of $3,700 per ton of NOx controlled. This calculation result is
conservative, as it greatly overstates the achievable emission reduction.
In addition, the use of steam injection would consume 5.6 million gallons of water per year per unit. This
is a substantial amount of water in an arid region in which water is a valuable natural resource. Based on
these facts, the use of steam injection for the control of NOx emissions from the Agua Fria Westinghouse
Model 501B simple cycle CTGs is not a feasible RACT option.
5.4 DLN Combustion.
SRP obtained from Power Systems Manufacturing (PSM) a budgetary estimate for DLN combustors for
these units, called LEC-III® gas turbine combustion technology. PSM has provided a cost of $8,975,000
(Oct. 2015 dollars) for each CTG, including installation costs.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in October has the same buying power as $1.09 in March 2020. The total capital cost
of water injection systems for Agua Fria Units 4, 5, and 6 in current dollars is $9,783,000 per unit.
This budgetary estimate is based on LEC-III® gas turbine combustion technology designed to meet 15
ppmdv at 15% O2, equal to a NOx emission rate of 0.055 lb/MMBtu. For a maximum design heat input
rate of 1,129 MMBtu per hour for each CTG and a maximum capacity factor of 10%, the potential NOx
emission reduction for the LEC-III® gas turbine combustion technology would be:
0.50 −0.055 lb NOx 1,129 MMBtu 8,760 hr 1.0 ton NOx
Reduction = × × × × 0.1 = 220.1 ton/yr
MMBtu hr yr 2,000 lb NOx
For this analysis, using a capital cost of $9,783,000 per unit and a CRF of 0.10979, the annualized capital
recovery cost would be $1,074,000. For a maximum NOx reduction of 220.1 tons per year, the cost
effectiveness for the LEC-III® gas turbine combustion technology would be $4,880 per ton of NOx
controlled. Based on these costs, the use of the LEC-III® gas turbine DLN combustion technology for the
control of NOx emissions from the Agua Fria Westinghouse Model 501B simple cycle CTGs is not a
feasible RACT option.
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5.5 Selective Catalytic Reduction (SCR).
SCR systems have the capability to make substantial reductions in NOx emissions. For these CTGs, the
use of SCR is expected to reduce NOx emissions by more than 90%, to a long-term emission rate of 9
ppmvd at 15% O2, equal to 0.0331 lb/MMBtu. SCR systems for these simple cycle CTGs would include a
catalyst reactor housing, the catalyst and support matrix, an ammonia injection grid, aqueous ammonia
storage tanks, and ammonia metering equipment and controls. From the U.S. EPA’s 1999 document Air
Pollution Control Technology Fact Sheet for Selective Catalytic Reduction, EPA-452/F-03-032, SCR
capital costs for large gas turbines range from $5,000 to $7,500 per MMBtu per hour of heat input capacity.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in December 1999 has the same buying power as $1.53 in March 2020. The low end
of U.S. EPA’s range of capital cost estimates is $7,650 per MMBtu/hr in March 2020 dollars.
Table 5-5 is a summary of a detailed analysis of the capital costs, annual costs, and cost effectiveness for
SCR systems for each Agua Fria Westinghouse Model 501B simple cycle CTG based on a 93.3% SCR
control efficiency and a 10% capacity factor. The costs in Table 5-5, other than the capital cost, are based
on Table 6-8 of the Gas Turbine ACT Document. Costs have been escalated from 1990 dollars to March
2020 dollars based on the CPI.
TABLE 5-5. Capital costs, annual costs, and cost effectiveness for an SCR system for each Agua
Fria Westinghouse Model 501B simple cycle CTG based on a 10% capacity factor.
A. Total Capital Cost $8,637,000 = Based on the low estimate from EPA-452/F-03-032
B. Direct Annual Costs, $/yr
1. Operating Labor $5,400 = (1.0 hr/8 hr-shift) x ($25.60/hr) x (876 hr/yr)
2. Supervisory Labor $800 = (0.15) x (Operating Labor)
3. Maint. Labor & Materials $24,300 = [(1,250 x TMW) + 25,800] x 0.1
4. Catalyst Replacement $79,700 = [(4,700 x TMW) + 37,200] x 0.1
5. Catalyst Disposal $4,500 = [(V) x ($15/ft3) x (.2638)] x 0.1
6. Ammonia $63,200 = (N) x ($360/ton) (NOx : NH3 ratio = 1:1)
9. Performance Loss $21,000 = (0.005)x(TMW)x($0.06/kWh)x(1,000 kW/MW)x(H)
C. Indirect Annual Costs, $/yr
1. Overhead $18,300 = (0.6) x (all labor and maintenance material costs)
2. Taxes, Insurance, Administra $345,500 = (0.04) x (total capital investment)
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3. Capital Recovery $948,300
TOTAL ANNUAL COST $1,511,000
Emission Reduction 230.9 ton NOx/year
COST EFFECTIVENESS $6,540 $ per ton of NOx controlled
Footnotes
1. Except as noted, costs are based on the Gas Turbine ACT Document, with an escalation factor of 1.93 to
escalate from Dec. 1990 to Mar. 2020 based on the CPI.
2. TMW is turbine output in megawatts, V is catalyst volume in ft3, N is annual ammonia usage in tons
The average cost effectiveness of SCR systems for the Westinghouse Model 501B simple cycle CTGs
would be $6,540 per ton of NOx controlled. Based on these costs, the use of SCR for the control of NOx
emissions from the Agua Fria Westinghouse Model 501B simple cycle CTGs is not a feasible RACT option.
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5.6 Conclusions.
Table 5-6 is a summary of the available and technically feasible NOx RACT options for the Agua Fria
Westinghouse Model 501B simple cycle CTGs, the potential emission reductions, and the average cost
effectiveness of each control option. The potential emission reductions and the resulting cost effectiveness
in Table 5-6 are based on a 10% capacity factor for each CTG. Note that the potential NOx emission
reductions for each option are based on 247.3 tons per year for the uncontrolled CTGs which greatly
overstates the actual emissions and the potential emission reductions. Even with these conservative
assumptions, no control options meet the cost effectiveness threshold of $2,300 per ton discussed in Section
2.6 of this report.
TABLE 5-6. NOx control options, emission reductions, and cost effectiveness for each Agua
Fria Westinghouse Model 501B simple cycle CTG based on a 10% capacity factor.
NOx Control Emission Rate, Potential NOx Capital Annual Cost
Option ppmdv at Emissions, Cost Cost Effectiveness,
15% O2 ton/yr $ per ton
Worst-case 135 247.3
Uncontrolled CTG
Water Injection 25 45.5 $3,028,000 $725,800 $3,600
Steam Injection 25 45.5 $3,989,000 $746,000 $3,700
Dry Low NOx 15 27.2 $9,783,000 $1,074,000 $4,880
Combustion (DLN)
Selective Catalytic 9 16.4 $8,637,000 $1,511,000 $6,540
Reduction (SCR)
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6.0 Kyrene Simple Cycle CTG Unit 4.
The Kyrene Generating Station Unit 4 is a natural gas and distillate fuel oil-fired simple cycle CTG.
However, this unit is permitted to combust fuel oil only as an emergency fuel when natural gas is
unavailable. Unit 4 has very low utilization, with a typical capacity factor less than 0.1 percent.
Unit 4 is a Westinghouse Model 501A simple cycle CTG rated at 53 MWe and having a maximum design
heat input capacity of 969 MMBtu per hour. This CTG has no NOx controls.
For this RACT analysis, the uncontrolled NOx emission rate for all control technologies is conservatively
based on a NOx emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb NOx/MMBtu.
6.1 Technically Feasible Control Technologies.
The available NOx control technologies for this Westinghouse Model 501A simple cycle CTG are diffusion
flame combustion, with or without water or steam injection, and SCR. With respect to DLN combustion,
this CTG has turbine inlet temperatures (TIT) after the compressor stages of less than 1,100 °F. The fuel/air
mixture in the turbine is already too lean to be further reduced using DLN combustion and also maintain a
constant, safe, and stable flame. Therefore, DLN combustion is not a technically feasible control
technology for this Westinghouse Model 501A CTG.
6.2 Water Injection.
A water injection system for this CTG is expected to reduce NOx emissions when firing natural gas from a
worst-case uncontrolled emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb/MMBtu, to 25 ppmdv at
15% O2 and 0.092 lb/MMBtu.
A water injection system would include water injection nozzles, flow metering controls, pumps, hardware,
and interconnecting piping from a water treatment system to the CTG. The water treatment system would
include reverse osmosis demineralization systems and a storage tank. Table 5-1 in the previous chapter of
this report is a summary of the capital costs for a water injection system for a similar Westinghouse Model
501-AA simple cycle CTG totaling $2,348,000 in 2018 dollars.
The water injection system costs for the 53 MWe Unit 4 CTG in 2018 dollars was calculated using the
equipment costs in Table 5-1 and adjusted to the slightly smaller Model 501A CTG using the six-tenth
factor rule.
0.6 0.6
C501A = C501AA ൬S501A ൰ = $2,348,000 ൬53 55൰ = $2,296,400
S501AA
Where C501A = Cost for the SRP Westinghouse Model 501A CTG
C501AA = Cost for the APS Westinghouse Model 501AA CTGs
S501A = Size for the SRP Westinghouse Model 501A CTG = 53 MW
C501AA = Cost for the APS Westinghouse Model 501AA CTGs = 55 MW
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As shown above, substituting the total capital cost for the Model 501AA CTGs of $2,348,000 and the sizes
of each CTG into this equation, the resulting cost of water injection for the Model 501A CTG would be
$2,296,400 in 2018 dollars.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 2018 has the same buying power as $1.03 in March 2020. The total capital
cost of water injection systems for Unit 4 at the Kyrene Generating Station in current dollars is $2,365,300.
Table 6-1 is a summary of the annual costs and the cost effectiveness for a water injection system for the
Kyrene Unit 4 CTG.
The annual capital recovery cost is calculated as the product of the total capital cost of $2,365,300 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 3% loss
in CTG efficiency with water injection and a natural gas cost of $3.00 per MMBtu. The water injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
The emission reduction in Table 6-1 is based on a water injection NOx emission rate when firing natural
gas of 25 ppmdv at 15% O2 equal to 0.092 lb/MMBtu, an uncontrolled emission rate of 135 ppmdv at 15%
O2, equal to 0.50 lb/MMBtu, and a CTG capacity factor of 10%:
969 MMBtu 8,760 hr lb NOx 1.0 ton NOx
Emission Reduction = × × 0.1 × ൬ 0.50 −0.092 MMBtu൰ ×
hr yr 2,000 lb NOx
Emission Reduction = 173.2 ton/year
TABLE 6-1. Annual costs and cost effectiveness for a water injection system for the Kyrene
Unit 4 Westinghouse Model 501A simple cycle CTG.
Capital Recovery Cost $259,700 $2.3653MM × 0.10979
Fuel Cost $76,400 3.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $101,900 1 lb demin water per lb fuel and
$0.02103/gal; (see Section 2.5).
Maintenance Cost $49,600 From Table B-2 of the NOx ACT
Plant Overhead Cost $14,900 30% of Annual Maintenance Cost
General & Administrative, Taxes, Insurance $94,600 4% of Total Capital Cost
TOTAL ANNUAL COST $597,100
Emission Reduction 173.2 ton NOx/year
COST EFFECTIVENESS $3,450 $ per ton of NOx controlled
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From Table 6-1, the use of water injection on this Westinghouse Model 501A simple cycle CTG would
result in a potential emission reduction of 173.2 tons per year. This reduction is based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
and a capacity factor of 10%. The average cost effectiveness is $3,450 per ton of NOx controlled.
In addition, the use of water injection would consume 4.8 million gallons of water per year. This is a
substantial amount of water in an arid region in which water is a valuable natural resource. Based on these
facts, the use of water injection for the control of NOx emissions from the Kyrene Unit 4 simple cycle CTG
is not a feasible RACT option.
6.3 Steam Injection.
Like water injection, steam injection for this CTG is expected to reduce NOx emissions when firing natural
gas from a worst-case emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb/MMBtu, to 25 ppmdv at
15% O2 equal to 0.092 lb/MMBtu.
Although steam injection is a technically feasible NOx control option, steam injection is less frequently
used than water injection. Like the water injection system, a steam injection system would include injection
nozzles, flow metering controls, pumps, hardware, and interconnecting piping from a water treatment
system to the CTG. In addition, a steam injection system would require a boiler to convert the demineralized
water to steam. This boiler may be a natural gas-fired boiler, or it may be placed in the CTG flue gas outlet
plenum to use waste heat from the CTG to create steam.
Table 6-2 is a summary of the capital costs for a steam injection system for Kyrene Unit 4. These costs are
based on Chapter 6 of the Gas Turbine ACT Document. All costs have been escalated from 1990 to March
2020 dollars based on the CPI.
TABLE 6-2. Steam injection system capital costs for the Westinghouse Model 501A CTG.
Purchased Equipment Costs (PEC)
Steam Injection System $747,000 Based on $4,200 per gallon per minute (GPM) as steam
Water Treatment System $813,000 WTS = 43,900 x GPM0.5
Taxes and Freight $125,000 8% of the total system costs
Direct Installation Costs
Direct Costs $758,000 45% of Purchased Equipment Costs
Indirect Installation Costs
Indirect Costs $524,000 33% of the PEC and Direct Costs + $5,000
Contingency Costs $593,000 20% of the Sum of the PEC, Direct and Indirect Costs
TOTAL CAPITAL COST $3,560,000
Footnotes
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1. Costs are based on the Gas Turbine ACT Document.
2. Costs are based on the following combustion turbine and steam injection system design conditions:
CTG Heat Input Capacity 969 MMBtu/hr
Natural Gas Heat Value 21,000 Btu per pound, HHV
Natural Gas Fuel Flow Rate 46,148 lb/hour
Steam-to-Fuel Ratio (Ω) 1.0 lb steam/lb fuel
Water Flowrate 92 gallons per minute (GPM)
Water Flowrate 4,844,300 gallons per year
Cost Escalation (Inflation) Factor 1.93 Escalated from Dec. 1990 to Mar. 2020 based on the CPI.
Table 6-3 is a summary of the annual costs and the cost effectiveness for a steam injection system for the
Kyrene Unit 4 Westinghouse Model 501A simple cycle CTG.
The annual capital recovery cost is calculated as the product of the total capital cost of $3,560,000 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 1% loss
in CTG efficiency with steam injection and a natural gas cost of $3.00 per MMBtu. The steam injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
TABLE 6-3. Annual costs and cost effectiveness for a steam injection system for the Kyrene
Unit 4 Westinghouse Model 501A simple cycle CTG.
Capital Recovery Cost $390,900 Based on the Total Capital Cost in Table 6-2.
Fuel Penalty Cost $25,500 1.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $101,900 1 lb steam per lb fuel and $0.02103/gal (see
Section 2.5).
Maintenance Cost The NOx ACT indicates no additional turbine
Plant Overhead $0 maintenance cost for steam injection.
General & Adm., Taxes, Insurance (GATI) $142,400 4% of Total Capital Cost
TOTAL ANNUAL COST $660,700
Emission Reduction 173.2 ton NOx/year
Cost Effectiveness $3,820 $ per ton of NOx controlled
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
From Table 6-3, even assuming a potential emission reduction of 173.2 tons per year based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
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and a capacity factor of 10%, the use of steam injection on the Westinghouse Model 501A simple cycle
CTG would have a cost effectiveness of $3,820 per ton of NOx controlled. This calculation result is
conservative, as it greatly overstates the achievable emission reduction.
In addition, the use of steam injection would consume 4.8 million gallons of water per year. This is a
substantial amount of water in an arid region in which water is a valuable natural resource. Based on these
facts, the use of steam injection for the control of NOx emissions from the Kyrene Unit 4 Westinghouse
Model 501A simple cycle CTG is not a feasible RACT option.
6.4 Selective Catalytic Reduction (SCR).
SCR systems have the capability to make substantial reductions in NOx emissions. For the Kyrene Unit 4
CTG, the use of SCR is expected to reduce NOx emissions by more than 90%, to a long-term emission rate
of 9 ppmvd at 15% O2, equal to 0.0331 lb/MMBtu. SCR systems for this simple cycle CTG would include
a catalyst reactor housing, the catalyst and support matrix, an ammonia injection grid, aqueous ammonia
storage tanks, and ammonia metering equipment and controls. From the U.S. EPA’s 1999 document Air
Pollution Control Technology Fact Sheet for Selective Catalytic Reduction, EPA-452/F-03-032, SCR
capital costs for large gas turbines range from $5,000 to $7,500 per MMBtu per hour of heat input.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in December 1999 has the same buying power as $1.53 in March 2020. The low end
of U.S. EPA’s range of capital cost estimates is $7,650 per MMBtu/hr in March 2020 dollars.
Table 6-4 is a summary of a detailed analysis of the capital costs, annual costs, and cost effectiveness for
an SCR system for the Kyrene Unit 4 Westinghouse Model 501A simple cycle CTG based on a 93.3% SCR
control efficiency and a 10% capacity factor. The costs in in Table 6-4, other than the capital cost, are
based on Table 6-8 of the Gas Turbine ACT Document. Costs have been escalated from 1990 dollars to
March 2020 dollars based on the CPI.
TABLE 6-4. Capital costs, annual costs, and cost effectiveness for an SCR system for the Kyrene
Unit 4 Westinghouse Model 501A simple cycle CTG based on a 10% capacity factor.
A. Total Capital Cost $7,414,000 = Based on the low estimate from EPA-452/F-03-032
B. Direct Annual Costs, $/yr
1. Operating Labor $5,400 = (1.0 hr/8 hr-shift) x ($25.60/hr) x (876 hr/yr)
2. Supervisory Labor $800 = (0.15) x (Operating Labor)
3. Maint. Labor & Materials $17,800 = [(1,250 x TMW) + 25,800] x 0.1
4. Catalyst Replacement $55,300 = [(4,700 x TMW) + 37,200] x 0.1
5. Catalyst Disposal $3,000 = [(V) x ($15/ft3) x (.2638)] x 0.1
6. Ammonia $54,300 = (N) x ($360/ton) (NOx : NH3 ratio = 1:1)
9. Performance Loss $13,900 = (0.005)x(TMW)x($0.06/kWh)x(1,000 kW/MW)x(H)
C. Indirect Annual Costs, $/yr
1. Overhead $14,400 = (0.6) x (all labor and maintenance material costs)
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2. Taxes, Insurance, Administra $296,600 = (0.04) x (total capital investment)
3. Capital Recovery $814,000
TOTAL ANNUAL COST $1,275,500
Emission Reduction 198.2 ton NOx/year
COST EFFECTIVENESS $6,440 $ per ton of NOx controlled
Footnotes
1. Except as noted, costs are based on the Gas Turbine ACT Document, with an escalation factor of 1.93 to
escalate from Dec. 1990 to Mar. 2020 based on the CPI.
2. TMW is turbine output in megawatts, V is catalyst volume in ft3, N is annual ammonia usage in tons
The average cost effectiveness of SCR systems for the Westinghouse Model 501A simple cycle CTG would
be $6,440 per ton of NOx controlled. Based on these costs, the use of SCR for the control of NOx emissions
from the Kyrene Unit 4 Westinghouse Model 501A simple cycle CTG is not a feasible RACT option.
6.5 Conclusions.
Table 6-5 is a summary of the available and technically feasible NOx RACT options for the Kyrene
Generating Station Unit 4 Westinghouse Model 501A simple cycle CTG, the potential emission reductions,
and the average cost effectiveness of each control option. The potential emission reductions and the
resulting cost effectiveness in Table 6-5 are based on a 10% capacity factor. Note that the potential NOx
emission reductions for each option are based on 212.1 tons per year for the uncontrolled CTG which
greatly overstates the actual emissions and the potential emission reductions. Even with these conservative
assumptions, no control options meet the cost effectiveness threshold of $2,300 per ton discussed in Section
2.6 of this report.
TABLE 6-5. NOx control options, emission reductions, and cost effectiveness for the Kyrene
Unit 4 Westinghouse Model 501A simple cycle CTG based on a 10% capacity factor.
NOx Control Emission Rate, Potential NOx Capital Annual Cost
Option ppmdv at Emissions, Cost Cost Effectiveness,
15% O2 ton/yr $ per ton
Worst-case 135 212.2
Uncontrolled CTG
Water Injection 25 39.1 $2,365,300 $597,100 $3,450
Steam Injection 25 39.1 $3,560,000 $660,700 $3,820
Selective Catalytic 9 14.0 $7,414,000 $1,275,500 $6,440
Reduction (SCR)
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7.0 Kyrene Simple Cycle CTG Units 5 and 6.
The Kyrene Generating Station Units 5 and 6 are natural gas and distillate fuel oil-fired simple cycle CTGs.
However, these units are permitted to combust fuel oil only as an emergency fuel when natural gas is
unavailable. Units 5 and 6 have very low utilization, with a typical capacity factor less than 0.1 percent.
Units 5 and 6 are General Electric (GE) Model 7B simple cycle CTGs rated at 60 MWe, each having a
maximum design heat input capacity of 912 MMBtu per hour. These CTGs have no NOx controls.
For this RACT analysis, the uncontrolled NOx emission rate for all control technologies is conservatively
based on a NOx emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb NOx/MMBtu.
7.1 Technically Feasible Control Technologies.
For the Kyrene Generating Station Units 5 and 6, the available NOx control technologies include diffusion
flame combustion, with or without water or steam injection; DLN combustion; and SCR.
7.2 Water Injection.
Water injection systems for these CTGs are expected to reduce NOx emissions when firing natural gas from
a worst-case uncontrolled emission rate of 135 ppmdv at 15% O2, equal to 0.50 lb/MMBtu, to 25 ppmdv at
15% O2 and 0.092 lb/MMBtu.
Water injection systems would include water injection nozzles, flow metering controls, pumps, hardware,
and interconnecting piping from a water treatment system to each CTG. The water treatment system would
include reverse osmosis demineralization systems and a storage tank. Table 5-1 in Chapter 5.0 of this report
is a summary of the capital costs for a water injection system for a similar Westinghouse Model 501-AA
simple cycle CTG totaling $2,348,000 in 2018 dollars.
The water injection system costs for the 60 MWe Unit 5 and Unit 6 CTGs in 2018 dollars were calculated
using the equipment costs in Table 5-1 and adjusted to the slightly larger GE Model 7B CTGs using the
six-tenth factor rule.
0.6 0.6
C7B = C501AA ൬S7B ൰ = $2,348,000 ൬60 55൰ = $2,474,000
S501AA
Where C7B = Cost for the SRP General Electric Model 7B CTGs
C501AA = Cost for the APS Westinghouse Model 501AA CTG
S7B = Size for the SRP General Electric Model 7B CTGs = 60 MW
S501AA = Size for the APS Westinghouse Model 501AA CTGs = 55 MW
As shown above, substituting the total capital cost for the Model 501AA CTGs of $2,348,000 and the sizes
of each CTG into this equation, the resulting cost of water injection for each GE Model 7B CTG would be
$2,474,000 in 2018 dollars.
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Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in March 2018 has the same buying power as $1.03 in March 2020. The total capital
cost of water injection systems for Units 5 and 6 at the Kyrene Generating Station in current dollars is
$2,548,100 per unit.
Table 7-1 is a summary of the annual costs and the cost effectiveness for a water injection system for the
Kyrene Unit 5 and Unit 6 CTGs.
The annual capital recovery cost is calculated as the product of the total capital cost of $2,548,100 per unit
and the capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a
3% loss in CTG efficiency with water injection and a natural gas cost of $3.00 per MMBtu. The water
injection system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas
Turbine ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990
dollars to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per
gallon as discussed in Section 2.5.
The emission reduction in Table 7-1 is based on a water injection NOx emission rate when firing natural
gas of 25 ppmdv at 15% O2 equal to 0.092 lb/MMBtu, an uncontrolled emission rate of 135 ppmdv at 15%
O2, equal to 0.50 lb/MMBtu, and a CTG capacity factor of 10%:
912 MMBtu 8,760 hr lb NOx 1.0 ton NOx
Emission Reduction = × × 0.1 × ൬ 0.50 −0.092 MMBtu൰ ×
hr yr 2,000 lb NOx
Emission Reduction = 163.0 ton/year
TABLE 7-1. Annual costs and cost effectiveness for a water injection system for each General
Electric Model 7B simple cycle CTG.
Capital Recovery Cost $279,800 $2.5481MM × 0.10979
Fuel Cost $71,900 3.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $95,900 1 lb demin water per lb fuel and
$0.02103/gal; (see Section 2.5).
Maintenance Cost $49,600 From Table B-2 of the NOx ACT
Plant Overhead Cost $14,900 30% of Annual Maintenance Cost
General & Administrative, Taxes, Insurance $101,900 4% of Total Capital Cost
TOTAL ANNUAL COST $614,000
Emission Reduction 163.0 ton NOx/year
COST EFFECTIVENESS $3,770 $ per ton of NOx controlled
From Table 7-1, the use of water injection on the GE Model 7B simple cycle CTGs would result in a
potential emission reduction of 163.0 tons per year per unit. This reduction is based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
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and a capacity factor of 10%. The average cost effectiveness is $3,770 per ton of NOx controlled. In
addition, the use of water injection would consume 4.6 million gallons of water per unit per year. This is a
substantial amount of water in an arid region in which water is a valuable natural resource. Based on these
facts, the use of water injection for the control of NOx emissions from the Kyrene Unit 5 and Unit 6 simple
cycle CTGs is not a feasible RACT option.
7.3 Steam Injection.
Like water injection, steam injection for these GE Model 7B simple cycle CTGs is expected to reduce NOx
emissions when firing natural gas from a worst-case uncontrolled emission rate of 135 ppmdv at 15% O2,
equal to 0.50 lb/MMBtu, to 25 ppmdv at 15% O2 equal to 0.092 lb/MMBtu.
Although steam injection is a technically feasible NOx control option, steam injection is less frequently
used than water injection. Like the water injection systems, steam injection systems would include injection
nozzles, flow metering controls, pumps, hardware, and interconnecting piping from a water treatment
system to each CTG. In addition, a steam injection system would require a boiler to convert the
demineralized water to steam. This boiler may be a natural gas-fired boiler, or it may be placed in the CTG
flue gas outlet plenum to use waste heat from the CTG to create steam.
Table 7-2 is a summary of the capital costs for a steam injection system for each GE Model 7B simple cycle
CTG. These costs are based on Chapter 6 of the Gas Turbine ACT Document. All costs have been escalated
from 1990 to March 2020 dollars based on the CPI.
TABLE 7-2. Steam injection system capital costs for each GE Model 7B CTG.
Purchased Equipment Costs (PEC)
Steam Injection System $703,000 Based on $4,200 per gallon per minute (GPM) as steam
Water Treatment System $789,000 WTS = 43,900 x GPM0.5
Taxes and Freight $119,000 8% of the total system costs
Direct Installation Costs
Direct Costs $725,000 45% of Purchased Equipment Costs
Indirect Installation Costs
Indirect Costs $502,000 33% of the PEC and Direct Costs + $5,000
Contingency Costs $568,000 10% of the Sum of the PEC, Direct and Indirect Costs
TOTAL CAPITAL COST $3,406,000
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
2. Costs are based on the following combustion turbine and steam injection system design conditions:
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CTG Heat Input Capacity 912 MMBtu/hr
Natural Gas Heat Value 21,000 Btu per pound, HHV
Natural Gas Fuel Flow Rate 43,429 lb/hour
Steam-to-Fuel Ratio (Ω) 1.0 lb steam/lb fuel
Water Flowrate 87 gallons per minute (GPM)
Water Flowrate 4,558,800 gallons per year
Cost Escalation (Inflation) Factor 1.93 Escalated from Dec. 1990 to Mar. 2020 based on the CPI.
Table 7-3 is a summary of the annual costs and the cost effectiveness for a steam injection system for each
GE Model 7B simple cycle CTG.
The annual capital recovery cost is calculated as the product of the total capital cost of $3,406,000 and the
capital recovery factor (CRF) of 0.10979 as described in section 2.3. The fuel cost is based on a 1% loss
in CTG efficiency with steam injection and a natural gas cost of $3.00 per MMBtu. The steam injection
system maintenance, overhead, and general administrative costs are based on Chapter 6 of the Gas Turbine
ACT Document. The costs from the Gas Turbine ACT Document have been escalated from 1990 dollars
to March 2020 dollars based on the CPI. The demineralized water costs are based on $0.02103 per gallon
as discussed in Section 2.5.
TABLE 7-3. Annual costs and cost effectiveness for a steam injection system for each GE
Model 7B simple cycle CTG.
Capital Recovery Cost $374,000 Based on the Total Capital Cost in Table 7-2.
Fuel Penalty Cost $24,000 1.0% Heat Rate Loss and NG $3.00/MMBtu
(see Section 2.4)
Demineralized Water Cost $95,900 1 lb steam per lb fuel and $0.02103/gal (see
Section 2.5).
Maintenance Cost The NOx ACT indicates no additional turbine
Plant Overhead $0 maintenance cost for steam injection.
General & Adm., Taxes, Insurance (GATI) $136,200 4% of Total Capital Cost
TOTAL ANNUAL COST $630,100
Emission Reduction 163.0 ton NOx/year
Cost Effectiveness $3,870 $ per ton of NOx controlled
Footnotes
1. Costs are based on the Gas Turbine ACT Document.
From Table 7-3, even assuming a potential emission reduction of 163.0 tons per year based on a worst-case
uncontrolled NOx emission rate of 0.50 lb NOx/MMBtu, a controlled NOx emission rate of 0.092 lb/MMBtu,
and a capacity factor of 10%, the use of steam injection on each GE Model 7B simple cycle CTG would
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have a cost effectiveness of $3,870 per ton of NOx controlled. This calculation result is conservative, as it
greatly overstates the achievable emission reduction.
In addition, the use of steam injection would consume 4.6 million gallons of water per year per unit. This
is a substantial amount of water in an arid region in which water is a valuable natural resource. Based on
these facts, the use of steam injection for the control of NOx emissions from the Kyrene Generating Station
Unit 5 and Unit 6 GE Model 7B simple cycle CTGs is not a feasible RACT option.
7.4 DLN Combustion.
SRP obtained from GE a budgetary estimate for proprietary DLN combustors, called DLN1+ technology,
for the GE Model 7001B combined cycle CTGs at SRP’s Santan Generating Station in 2011. Although the
applicability of the DLN1+ technology has not been confirmed for the Kyrene Unit 5 and Unit 6 CTGs, we
have conservatively assumed for purposes of this analysis that this DLN technology would reduce NOx
emissions from the Kyrene Unit 5 and 6 CTGs to less than 9 ppmdv at 15% O2, equal to a NOx emission
rate of 0.0331 lb/MMBtu.
For a maximum design heat input rate of 912 MMBtu per hour for each CTG and a maximum capacity
factor of 10%, the potential NOx emission reduction for the DLN1+ technology for the GE Model 7B simple
cycle CTGs at Kyrene Generating Station would be:
0.50 −0.0331 lb NOx 912 MMBtu 8,760 hr 1.0 ton NOx
Reduction = × × × × 0.1 = 186.5 ton/yr
MMBtu hr yr 2,000 lb NOx
GE provided a cost of $4,800,000 for the first CTG, and $4,000,000 for each additional unit, including
installation. GE has also indicated the need for a hazardous gas protection system at a cost of $325,000.
Therefore, the estimated total capital cost for two of the Santan CTGs would be $9,125,000, or an average
capital cost of $4,562,500 for each unit in 2011 dollars.
The costs for the DLN1+ technology for the slightly larger Kyrene Unit 5 and 6 CTGs were calculated
using the equipment costs for the Santan units adjusted using the six-tenth factor rule.
0.6 0.6
C7B = C7001B ൬S7B ൰ = $4,562,500 ൬912 800൰ = $4,936,000
S7001B
Where C7B = Cost for the Kyrene Unit 5 & 6 GE Model 7B CTGs
C7001B = Cost for the Santan Units 1 – 4 GE Model 7001B CTGs
S7B = Size for the Kyrene Unit 5 & 6 GE Model 7B CTGs = 912 MMBtu/hr
S7001B = Size for the Santan Units 1 – 4 GE Model 7001B CTGs = 800 MMBtu/hr
Substituting the per-unit average total capital cost of $4,562,500 for the Santan CTGs and the sizes of each
CTG into this equation, the resulting cost of the DLN1+ technology for each of the Kyrene Unit 5 and Unit
6 GE Model 7B simple cycle CTGs would be $4,936,000 in 2011 dollars.
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Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in June 2011 has the same buying power as $1.14 in March 2020. The total capital
cost of DLN1+ technology for Units 5 and 6 at the Kyrene Generating Station in current dollars is
$5,627,000 per unit.
For this analysis, using a capital cost of $5,627,000 per unit and a CRF of 0.10979, the annualized capital
recovery cost would be $617,800. For a maximum NOx reduction of 186.5 tons per year, the cost
effectiveness for the DLN1+ technology would be $3,310 per ton of NOx controlled. This calculation result
is conservative, as it greatly overstates the achievable emission reduction. Based on these costs, the use of
the DLN1+ technology for the control of NOx emissions from the is not a feasible RACT option.
7.5 Selective Catalytic Reduction (SCR).
SCR systems have the capability to make substantial reductions in NOx emissions. For the Kyrene Unit 5
and Unit 6 CTGs, the use of SCR is expected to reduce NOx emissions by more than 90%, to a long-term
emission rate of 9 ppmvd at 15% O2, equal to 0.0331 lb/MMBtu. SCR systems for these simple cycle CTGs
would include a catalyst reactor housing, the catalyst and support matrix, an ammonia injection grid,
aqueous ammonia storage tanks, and ammonia metering equipment and controls. From the U.S. EPA’s
1999 document Air Pollution Control Technology Fact Sheet for Selective Catalytic Reduction, EPA-
452/F-03-032, SCR capital costs for large gas turbines range from $5,000 to $7,500 per MMBtu per hour
of heat input.
Based on the CPI Inflation Calculator from the Bureau of Labor Statistics (https://data.bls.gov/cgi-
bin/cpicalc.pl), $1.00 in December 1999 has the same buying power as $1.53 in March 2020. The low end
of U.S. EPA’s range of capital cost estimates is $7,650 per MMBtu/hr in March 2020 dollars.
Table 7-4 is a summary of a detailed analysis of the capital costs, annual costs, and cost effectiveness for
SCR systems for the Kyrene Unit 5 and Unit 6 GE Model 7B simple cycle CTGs based on a 93.3% SCR
control efficiency and a 10% capacity factor. The costs in in Table 7-4, other than the capital cost, are
based on Table 6-8 of the Gas Turbine ACT Document. Costs have been escalated from 1990 dollars to
March 2020 dollars based on the CPI.
TABLE 7-4. Capital costs, annual costs, and cost effectiveness for an SCR system for each
Kyrene Unit 5 and 6 simple cycle CTG based on a 10% capacity factor.
A. Total Capital Cost $6,977,000 = Based on the low estimate from EPA-452/F-03-032
.B. Direct Annual Costs, $/yr
1. Operating Labor $5,400 = (1.0 hr/8 hr-shift) x ($25.60/hr) x (876 hr/yr)
2. Supervisory Labor $800 = (0.15) x (Operating Labor)
3. Maint. Labor & Materials $19,500 = [(1,250 x TMW) + 25,800] x 0.1
4. Catalyst Replacement $61,600 = [(4,700 x TMW) + 37,200] x 0.1
5. Catalyst Disposal $3,400 = [(V) x ($15/ft3) x (.2638)] x 0.1
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6. Ammonia $51,100 = (N) x ($360/ton) (NOx : NH3 ratio = 1:1)
9. Performance Loss $15,800 = (0.005)x(TMW)x($0.06/kWh)x(1,000 kW/MW)x(H)
C. Indirect Annual Costs, $/yr
1. Overhead $15,400 = (0.6) x (all labor and maintenance material costs)
2. Taxes, Insurance, Administra $279,100 = (0.04) x (total capital investment)
3. Capital Recovery $766,000
TOTAL ANNUAL COST $1,218,100
Emission Reduction 186.5 ton NOx/year
COST EFFECTIVENESS $6,530 $ per ton of NOx controlled
Footnotes
1. Except as noted, costs are based on the Gas Turbine ACT Document, with an escalation factor of 1.93 to
escalate from Dec. 1990 to Mar. 2020 based on the CPI.
2. TMW is turbine output in megawatts, V is catalyst volume in ft3, N is annual ammonia usage in tons
The average cost effectiveness of SCR systems for the GE Model 7B simple cycle CTGs would be $6,530
per ton of NOx controlled. Based on these costs, the use of SCR for the control of NOx emissions from the
Kyrene Unit 5 and Unit 6 GE Model 7B simple cycle CTGs is not a feasible RACT option.
7.6 Conclusions.
Table 7-5 is a summary of the available and technically feasible NOx RACT options for the Kyrene
Generating Station Unit 5 and Unit 6 GE Model 7B simple cycle CTGs, the potential emission reductions,
and the average cost effectiveness of each control option. The potential emission reductions and the
resulting cost effectiveness in Table 7-5 are based on a 10% capacity factor. Note that the potential NOx
emission reductions for each option are based on 199.7 tons per year for each uncontrolled CTG which
greatly overstates the actual emissions and the potential emission reductions. Even with these conservative
assumptions, no control options meet the cost effectiveness threshold of $2,300 per ton discussed in Section
2.6 of this report.
TABLE 7-5. NOx control options, emission reductions, and cost effectiveness for each Kyrene
Unit 5 and 6 simple cycle CTG based on a 10% capacity factor.
Emission Rate, Potential to Cost
NOx Control ppmdv at Emit Capital Cost Annual Cost Effectiveness,
Option
15% O2 ton/yr $ per ton
Worst-case 135 199.7
Uncontrolled CTG
Water Injection 25 36.7 $2,548,100 $614,000 $3,770
Steam Injection 25 36.7 $3,406,000 $630,100 $3,870
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DLN Combustion 9 13.2 $5,627,000 $617,800 $3,310
Selective Catalytic
9 13.2 $7,414,000 $1,218,100 $6,530
Reduction (SCR)
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