Oklahoma Department of Environmental Quality Air Quality Division

Exhibit 99.01

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION


IN THE MATTER OF:

Oklahoma Gas & Electric Company,
Seminole Generating Station,	CASE NO. 10-024
Sooner Generating Station,
Muskogee Generating Station,

REGIONAL HAZE AGREEMENT

The parties to this Agreement, the Oklahoma Department of Environmental Quality (“DEQ”) and the Oklahoma Gas & Electric Company (“OG&E”) hereby agree to the entry of this Regional Haze Agreement (“Agreement”) in order to satisfy the Best Available Retrofit Technology (“BART”) requirements associated with the Regional Haze Rule, 40 C.F.R. Subpart P, and 40 C.F.R. Part 51, Appendix Y (incorporated by reference at OAC 252:100-8-72).

FINDINGS OF FACT

1. OG&E is an Oklahoma corporation with its principal headquarters in Oklahoma City, Oklahoma.

2. OG&E owns and operates the following three (3) fossil-fuel fired steam electric generating plants:

Seminole Generating Station – This station is located northeast of the City of Konawa, Seminole County, Oklahoma. The station includes three (3) nominal 567 megawatts (“MW”) steam electric generating units designated as Seminole Units 1, 2, and 3. Seminole Units 1 and 2 became operational in 1968, and Unit 3 became operational in 1970. All three (3) units are ▇▇▇▇▇▇▇ & ▇▇▇▇▇▇ wall-fired boilers that fire natural gas as their primary fuel. Each unit is a fossil-fuel fired

boiler with heat inputs greater than 250-mmBtu/hr. Because the units fire natural gas, there are no sulfur dioxide (“SO2”) or particulate matter (“PM”) emission control systems. Seminole Unit 3 was designed with flue gas recirculation (“FGR”) for nitrogen oxide (“NOx”) control. Each unit has the potential to emit 250 tons per year (“TPY”) of NOx. The facility is currently permitted to operate under DEQ Air Quality Permit No. 2003-400-TVR, which was issued on May 8, 2006.

Sooner Generating Station – This station is located in Red Rock, Noble County, Oklahoma. The station includes two (2) 570 MW steam electric generating units designated as Sooner Units 1 and 2. Each unit is a fossil-fuel fired boiler with heat inputs greater than 250-mmBtu/hr. Sooner Units 1 and 2 were in existence prior to August 7, 1977, but not in operation prior to August 7, 1962. Both units fire coal as their primary fuel, and both units have the potential to emit 250 TPY or more of NOx, SO2, and PM. The facility is currently permitted to operate under DEQ Air Quality Permit No. 2003-274-TVR, which was issued on February 11, 2006.

Muskogee Generating Station – This station is located in Muskogee, Muskogee County, Oklahoma. The station includes two (2) 572 MW steam electric generating units designated as Muskogee Units 4 and 5. Each unit is a fossil-fuel fired boiler with heat inputs greater than 250-mmBtu/hr. Both Muskogee Units 4 and 5 were in existence prior to August 7, 1977, but not in operation prior to August 7, 1962. Both units fire coal as their primary fuel, and both units have the potential to emit 250 TPY or more of NOx, SO2, and PM. The facility is currently permitted to operate under DEQ Air Quality Permit No. 2005-271-TVR, which was issued on September 8, 2009.

3. In 1977, the U.S. Congress enacted § 169 of the federal Clean Air Act, 42 U.S.C. § 7491, to protect the visibility of Class I Federal areas (areas determined to be of great scenic importance) from impairment. A particular type of visibility impairment is referred to as “Regional Haze.” See 40 C.F.R. § 51.301 (“Regional Haze means visibility impairment that is caused by the emission of air pollutants from numerous sources located over a wide geographic area. Such sources include, but are not limited to, major and minor stationary sources, mobile sources, and area sources.”). The federal Clean Air Act requires the development of emission limitations for pollutants contributing to Regional Haze which emanate from a variety of sources, including fossil-fuel fired electric generating power plants having a total energy generating capacity in excess of 750

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MW.

4. In 1980, the U.S. Environmental Protection Agency (“EPA”) promulgated regulations addressing Regional Haze reasonably attributable to specific sources or small groups of sources. See 40 Fed.Reg. 80,084. The regulations required States to determine which sources impair visibility and require the installation of BART on certain of those sources.

5. In 1999, EPA amended 40 C.F.R. Part 51, Subpart P, to further define the facilities subject to the Regional Haze requirements. The regulations require States to develop and implement long-term strategies for reducing air pollutants that cause or contribute to visibility impairment in Class I Federal areas.

6. On July 6, 2005, the EPA published the final “Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations” (the “Regional Haze Rule”). See 70 Fed.Reg. 39104. The federal Clean Air Act, 42 U.S.C. §§ 7401 et seq., and the Regional Haze Rule, 40 C.F.R. §§ 51.300 – 51.309, require certain States, including Oklahoma, to make reasonable progress toward the “prevention of any future, and the remedying of any existing, impairment of visibility in mandatory class I Federal areas.” 42 U.S.C. §§ 7491(a)(1), (b)(2) and 40 C.F.R. § 51.300. Moreover, the Regional Haze Rule requires the State of Oklahoma to develop programs to “address regional haze in each mandatory Class I Federal area located within the State and in each mandatory Class I Federal area located outside the State which may be affected by emissions from within the State.” 40 C.F.R. § 51.308(d); see also 40 C.F.R. § 51.300(b).

7. In order to meet the requirements of the Regional Haze Rule, States must submit State Implementation Plans (“SIP”) implementing the requirements of the Regional Haze Rule to EPA for approval. See id. The States were required to submit their SIPs prior to December 17,

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2007. See 40 C.F.R. § 51.308(b). Each Regional Haze SIP must contain “emission limitations representing BART and schedules for compliance with BART for each BART-eligible source that may reasonably be anticipated to cause or contribute to any impairment of visibility in any mandatory Class I Federal area . . . ..” See 40 C.F.R. § 51.308(e).

8. BART-eligible sources include those sources that: (1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant; (2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and (3) whose operations fall within one or more of the specifically listed source categories in 40 CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input). See OAC 252:100-8-71, 40 C.F.R. Part 51, Appendix Y(I)(C)(1), and 42 U.S.C. § 7491(b)(2)(A).

9. “Air pollutants emitted by sources in Oklahoma which may reasonably be anticipated to cause or contribute to visibility impairment in any mandatory Class I federal area are NOx, SO2, PM-10, and PM-2.5.” OAC 252:100-8-73(b).

10. As stated in Paragraph 2 above, Seminole Units 1, 2 and 3, Sooner Units 1 and 2, and Muskogee Units 4 and 5, are all: fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr; units that were in existence prior to August 7, 1977, but not in operation prior to August 7, 1962; and, based on a review of existing emissions data, units that have the potential to emit more than 250 tons per year of a visibility impairing pollutant. Consequently, all seven (7) units meet the definition of a BART-eligible source.

11. ▇▇▇▇ is required for any BART-eligible source that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. See OAC 252:100-8-73(a), 42 U.S.C. § 7491(b)(2)(a), and 40 C.F.R. § 51.308(e).

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EPA has determined that an individual source will be considered to “contribute to visibility impairment” if emissions from the source result in a change in visibility, measured as a change in deciviews (Δ-dv), that is greater than or equal to 0.5 dv in a Class I area. See 40 C.F.R. Part 51, Appendix Y(III)(A)(1); see also 70 Fed.Reg. 39,120; and OAC 252:100-8-73(a). Visibility impact modeling indicates that the maximum predicted visibility impacts from all seven (7) of the OG&E units listed in Paragraph 2 above exceed the 0.5 Δ-dv threshold at the Wichita Mountains Class I Area. See State of Oklahoma Regional Haze SIP, p. 72, table VI-4. Therefore, all seven (7) units are subject to the BART determination requirements.

12. Since the Seminole Generating Station, the Sooner Generating Station, and the Muskogee Generating Station each have a total generating capacity in excess of 750 MW, the Appendix Y guidelines were used to prepare BART determinations for each station. Based on an evaluation of potentially feasible retrofit control technologies, including an assessment of the costs and visibility improvements associated therewith, the following control technologies and emission limits as described in the BART Determinations for each of the three (3) stations (attached as Exhibits A, B, and C; collectively “BART Determinations”) have been determined to be BART and shall be implemented within 5 years of EPA’s approval of Oklahoma’s Regional Haze SIP:

Seminole Generating Station -

Control	Unit 1	Unit 2	Unit 3
NOX Control	Combustion controls including: Low-NOX Burners, Overfire Air, and Flue Gas Recirculation	Combustion controls including: Low-NOX Burners, Overfire Air, and Flue Gas Recirculation	Combustion controls including: Low-NOX Burners, Overfire Air, and Flue Gas Recirculation
NOx Emission Rate (lb/mmBtu)	0.203 lb/mmBtu (30-day average)	0.212 lb/mmBtu (30-day average)	0.164 lb/mmBtu (30-day average)

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Sooner Generating Station -

Control	Unit 1	Unit 2
NOX Control	LNB with OFA	New LNB with OFA
Emission Rate (lb/mmBtu)	0.15 lb/mmBtu (30-day rolling average)	0.15 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	767 lb/hr (30-day rolling average)	767 lb/hr (30-day rolling average)
Emission Rate TPY	3,361 TPY (12-month rolling)	3,361 TPY (12-month rolling)
SO2 Control	Low Sulfur Coal	Low Sulfur Coal
Hourly Emission Rate (lb/mmBtu)	0.65 lb/mmBtu (30-day rolling average)	0.65 lb/mmBtu (30-day rolling average)
Emission Rate (lb/hr)	3,325 lb/hr (30-day rolling average)	3,325 lb/hr (30-day rolling average)
Annual Emission Rate (lb/mmBtu)	0.55 lb/mmBtu (12-month rolling average)	0.55 lb/mmBtu (12-month rolling average)
Combined Annual Emission Rate (TPY)	19,736 TPY
PM10 Control	Existing Electrostatic Precipitator	Existing Electrostatic Precipitator
Emission Rate (lb/mmBtu)	0.10 lb/mmBtu (3-hour rolling average)	0.10 lb/mmBtu (3-hour rolling average)
Emission Rate lb/hr	512 lb/hr (3-hour rolling average)	512 lb/hr (3-hour rolling average)
Emission Rate TPY	2,241 TPY (12-month rolling average)	2,241 TPY (12-month rolling average)

Muskogee Generating Station Units 4 and 5 -

Control	Unit 4	Unit 5
NOX Control	LNB with OFA	New LNB with OFA
Emission Rate (lb/mmBtu)	0.15 lb/mmBtu (30-day rolling average)	0.15 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	822 lb/hr (30-day rolling average)	822 lb/hr (30-day rolling average)
Emission Rate TPY	3,600 TPY (12-month rolling)	3,600 TPY (12-month rolling)
SO2 Control	Low Sulfur Coal	Low Sulfur Coal
Hourly Emission Rate (lb/mmBtu)	0.65 lb/mmBtu (30-day rolling average)	0.65 lb/mmBtu (30-day rolling average)
Emission Rate (lb/hr)	3,562 lb/hr (30-day rolling average)	3,562 lb/hr (30-day rolling average)

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Annual Emission Rate (lb/mmBtu)	0.55 lb/mmBtu (12-month rolling average)	0.55 lb/mmBtu (12-month rolling average)
Combined Annual Emission Rate (TPY)	18,096 TPY
PM10 Control	Electrostatic Precipitator	Electrostatic Precipitator
Emission Rate (lb/mmBtu)	0.10 lb/mmBtu (3-hour rolling average)	0.10 lb/mmBtu (3-hour rolling average)
Emission Rate lb/hr	548 lb/hr (3-hour rolling average)	548 lb/hr (3-hour rolling average)
Emission Rate TPY	2,400 TPY (12-month rolling average)	2,400 TPY (12-month rolling average)

13. In the event that: (i) EPA disapproves the DEQ determination described in the BART Determinations that Dry-Flue Gas Desulfurization with Spray Dryer Absorber (“Dry FGD with SDA”) is not cost-effective for SO2 control and (ii) all administrative and judicial appeals of EPA’s disapproval have been exhausted, then the low-sulfur coal requirement in Paragraph 12 and the BART Determinations for SO2 (and the related electrostatic precipitator requirement for PM) shall be replaced with a requirement that Sooner Units 1 and 2 and Muskogee Units 4 and 5 shall, at the election of the owner and operator of the Unit, either: (i) install Dry FGD with SDA (and install fabric filters for PM control) or meet the corresponding SO2 and PM emission limits listed below (and further described in the Section on Contingent BART Determinations, see § IV(F) of Exhibits B and C, collectively “Contingent BART Determinations”) by January 1, 2018; or (ii) comply with the approved alternative described in Paragraph 14 prior to December 31, 2026:

Sooner Generating Station -

Control	Unit 1	Unit 2
SO2 Control	Dry FGD with SDA	Dry FGD with SDA
Emission Rate (lb/mmBtu)	0.1 lb/mmBtu (30-day rolling average)	0.1 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	512 lb/hr (30-day rolling average)	512 lb/hr (30-day rolling average)
Emission Rate TPY	2,241 TPY (12-month rolling average)	2,241 TPY (12-month rolling average)

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PM10 Control	Fabric Filter	Fabric Filter
Emission Rate (lb/mmBtu)	0.015 lb/mmBtu (3-hour rolling average)	0.015 lb/mmBtu (30-hour rolling average)
Emission Rate lb/hr	77 lb/hr (30-hour rolling average)	77 lb/hr (30-hour rolling average)
Emission Rate TPY	336 TPY (12-month rolling average)	336 TPY (12-month rolling average)

Muskogee Generating Station Units 4 and 5 -

Control	Unit 4	Unit 5
SO2 Control	Dry FGD with SDA	Dry FGD with SDA
Emission Rate (lb/mmBtu)	0.1 lb/mmBtu (30-day rolling average)	0.1 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	548 lb/hr (30-day rolling average)	548 lb/hr (30-day rolling average)
Emission Rate TPY	2,400 TPY (12-month rolling average)	2,400 TPY (12-month rolling average)
PM10 Control	Fabric Filter	Fabric Filter
Emission Rate (lb/mmBtu)	0.015 lb/mmBtu (3-hour rolling average)	0.015 lb/mmBtu (30-hour rolling average)
Emission Rate lb/hr	82 lb/hr (30-hour rolling average)	82 lb/hr (30-hour rolling average)
Emission Rate TPY	360 TPY (12-month rolling average)	360 TPY (12-month rolling average)

14. In lieu of installing and operating BART for SO2 and PM control at the four (4) coal fired units (i.e., Sooner Units 1 and 2 and Muskogee Units 4 and 5), OG&E may elect to implement the fuel switching alternative approved pursuant to 40 C.F.R. § 51.308(e)(2) and as part of the long-term strategy in fulfillment of 40 C.F.R. § 51.308(d)(3). See Sections on Greater Reasonable Progress Alternative Determination, § IV(G) of Exhibits B and C (collectively “Alternative Determination”). As detailed in the Alternative Determination, implementation of this alternative requires OG&E to achieve by December 31, 2026 a combined annual SO2 emission limit that is equivalent to: (i) the SO2 emission limits provided in Paragraph 13 for installing and operating Dry FGD with SDA on two of these coal fired units; and (ii) being at or below the SO2 emissions that

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would result from switching the other two of the coal fired units to natural gas. By adopting the emission limits described in the previous sentence, DEQ and OG&E expect the cumulative SO2 emissions from Sooner Units 1 and 2 and Muskogee Units 4 and 5 to be approximately fifty-seven percent (57%) less than would be achieved through the installation and operation of Dry FGD with SDA at all four (4) units. See Alternative Determination. If OG&E has elected to comply with the emission limits provided in this Paragraph 14 and if, prior to January 1, 2022, any of these units is required by any environmental law other than the Regional Haze Rule to install flue gas desulfurization equipment or achieve an SO2 emissions rate lower than 0.10 lb/mmBtu, and if OG&E proceeds to take all necessary steps to comply with such legal requirement, the enforceable emission limits adopted pursuant to this Paragraph 14 in the operating permits for the affected coal units shall be adjusted, with the reasonable consent of DEQ and OG&E, as appropriate to reflect the installation of that equipment or the emission rates specified under such legal requirement.

15. OG&E and DEQ agree that it is beneficial to resolve this matter promptly and by agreement.

16. OG&E and DEQ waive the filing of a petition or other pleading, and OG&E waives the right to a hearing.

CONCLUSIONS OF LAW

17. DEQ has regulatory jurisdiction and authority in this matter, and OG&E is subject to the jurisdiction and authority of DEQ under Oklahoma law, 27A Okla. Stat. (“O.S.”) §§ 2-5-101 to -118, and the rules promulgated thereunder at Oklahoma Administrative Code (“OAC”), Title 252, Chapter 100, Air Pollution Control. This Order is executed under the authority of, and in conformity with, 27A O.S. § 2-5-110(G).

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18. OG&E and DEQ are authorized by 75 O.S. § 309(E) and 27A O.S. § 2-3-506(B) to resolve this matter by agreement.

19. “Air pollutants emitted by sources in Oklahoma which may reasonably be anticipated to cause or contribute to visibility impairment in any mandatory Class I federal area are NOx, SO2, PM-10, and PM-2.5.” OAC 252:100-8-73(b).

20. DEQ administrative rules provide that BART applicability “shall be determined using the criteria in Section III of Appendix of 40 CFR 51 in effect on July 6, 2005.” OAC 252:100-8-73(a); see also OAC 252:100-8-72 (“Appendix Y, Guidelines for BART Determinations Under the Regional Haze Rule, of 40 CFR 51 is hereby incorporated by reference as it exists July 6, 2005.”). Similarly, the corresponding Federal regulations provide, “[t]he determination of BART for fossil-fuel fired power plants having a total generating capacity greater than 750 megawatts [MW] must be made pursuant to the guidelines in appendix Y of this part (Guidelines for BART Determinations Under the Regional Haze Rule).” See 40 C.F.R. § 51.308(e)(1)(ii)(B); see also 42 U.S.C. § 7491(b)(2)(B). As described in Paragraph 2 of the Statement of Facts, each of the Seminole Generating Station, Sooner Generating Station, and Muskogee Generating Station, has a total generating capacity greater than 750 MW and, therefore, the BART determinations for each of these stations must be made pursuant to the “Guidelines for BART Determinations Under the Regional Haze Rule.” Nothing in this Agreement shall be construed as applying emission limits to any units that are not subject to BART under the Regional Haze Rule, including Muskogee Unit 6.

21. State and Federal rules define BART-eligible sources to include those sources that: (1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant; (2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and (3) whose

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operations fall within one or more of the specifically listed source categories in 40 CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input). See OAC 252:100-8-71, 40 C.F.R. Part 51, Appendix Y(I)(C)(1), and 42 U.S.C. § 7491(b)(2)(A). As stated in Paragraphs 2 and 10 of the Statement of Facts, Seminole Units 1, 2, and 3, Sooner Units 1 and 2, and Muskogee Units 4 and 5 meet all three (3) criteria listed above and, therefore, meet the definition of a BART eligible source.

22. OAC 252:100-8-73(a) provides in part:

Each BART-eligible source that emits any air pollutant which may reasonably be anticipated to cause or contribute to visibility impairment in any mandatory Class I Federal area is subject to BART. This shall be determined using the criteria in Section III of Appendix Y of 40 CFR 51 in effect on July 6, 2005. Thresholds for visibility impairment are set forth in OAC 252:100-8-73(a)(1) and (2).

(1)

A source that is responsible for an impact of 1.0 deciview or more is considered to cause visibility impairment.

(2)

A source that causes an impact greater than 0.5 deciviews contributes to visibility impairment.

As stated in Paragraph 11 of the Statement of Facts, Seminole Units 1, 2, and 3, Sooner Units 1 and 2, and Muskogee Units 4 and 5, each contribute greater than 0.5 deciviews to visibility impairment at the Wichita Mountains Class I Area and, therefore, are considered subject to BART.

23. OAC 252:100-8-75(e) provides that “[t]he owner or operator of each BART-eligible source subject to BART shall install and operate BART no later than five years after EPA approves the Oklahoma Regional Haze SIP.” Similarly, the Federal rule states that each Regional Haze SIP must contain “[a] requirement that each source subject to BART be required to install and operate BART as expeditiously as practicable, but in no event later than 5 years

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after approval of the implementation plan revision.” 40 C.F.R. § 51.308(e)(1)(iv).

24. In lieu of installing and operating BART, the Federal rules provide that States may allow BART subject sources to implement an alternative demonstrated to “achieve greater reasonable progress toward natural visibility conditions.” See 40 C.F.R. § 51.308(e). Any approved Greater Reasonable Progress Alternative shall comply with the requirements of 40 C.F.R. § 51.308(e)(2).

25. In addition to the BART requirements, the Federal rules give States authority to adopt "emissions limitations, compliance schedules, and other measures as necessary to achieve the reasonable progress goals" as part of the long-term strategy that addresses regional haze visibility impairment. See 40 C.F.R. § 51.308(d)(3).

AGREEMENT

26. Based on the above paragraphs, OG&E and the DEQ agree, and it is ordered by the Executive Director as follows:

OG&E, at its election, shall either: (i) install and operate BART and achieve the related emission limits at the Sooner Generating Station, the Seminole Generating Station, and the Muskogee Generating Station as set forth in Paragraph 12 and the corresponding BART Determinations, within 5 years of EPA’s approval of Oklahoma’s Regional Haze SIP; or (ii) implement the approved Greater Reasonable Progress Alternative (i.e., natural gas fuel switching alternative) described in Paragraph 14 and the Alternative Determinations by December 31, 2026.

In the event that EPA disapproves the DEQ determination that Dry FGD with SDA is not cost-effective for SO2 control at Sooner Units 1 and 2 and Muskogee Units 4 and 5 and such disapproval is upheld after all judicial and/or administrative appeals have been exhausted, the SO2 related portions of the BART Determinations and the related SO2 and PM10 emission limits set forth in Paragraph 12 shall not have any further force or effect, and OG&E, at its election, shall either: (i) achieve the SO2 and PM10 emission limits at the Sooner Units 1 and 2 and the Muskogee Units 4 and 5 on or before January 1, 2018 as set forth in Paragraph 13 and the corresponding Contingent BART Determinations; or (ii) implement the approved Greater Reasonable Progress Alternative (i.e., natural gas fuel switching alternative) on or before December 31, 2026 as set forth in Paragraph 14 and the Alternative

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Determinations.

27. Any control equipment required to be installed as BART shall be properly operated and maintained. See 40 C.F.R. § 51.308(e)(v).

28. Nothing in this Agreement shall constitute or be construed as a release for any claim or cause of action related to any NSR or New Source Performance Standard (“NSPS”) liability under the Clean Air Act or the rules promulgated thereunder.

29. The emission limits required by this Agreement shall be incorporated into any otherwise required construction or operating permit issued to OG&E for the affected units.

30. This Agreement shall be incorporated into the Regional Haze State Implementation Plan submitted to EPA for approval by the State of Oklahoma.

GENERAL PROVISIONS

31. OG&E agrees to perform the requirements of this Agreement within the time frames specified unless performance is prevented or delayed by events which are a “force majeure.” For purposes of this Agreement, a force majeure event is defined as any event arising from causes beyond the reasonable control of OG&E or OG&E’s contractors, subcontractors or laboratories which delays or prevents the performance of any obligation under this Agreement. Examples are vandalism; fire; flood; labor disputes or strikes; weather conditions which prevent or seriously impair construction activities; civil disorder or unrest; and “acts of God.” Force majeure events do not include increased costs of performance of the tasks agreed to in this Agreement, or changed economic circumstances. OG&E must notify DEQ in writing within thirty (30) days after OG&E knows or should have known of a force majeure event that is expected to cause a delay in achieving compliance with any requirement of this Agreement. Failure to submit notification within thirty (30) days waives the right to claim force majeure.

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32. No informal advice, guidance, suggestions or comments by employees of DEQ regarding reports, plans, specifications, schedules, and other writings affect OG&E’s obligation to obtain written approval by DEQ, when required by this Agreement.

33. Unless otherwise specified, any report, notice or other communication required under this Agreement must be in writing and must be sent to:

For the Department of Environmental Quality:

▇▇▇▇▇ ▇▇▇▇▇▇▇, Director

Air Quality Division

P.O. Box 1677

Oklahoma City, OK 73101-1677

With copies to:

▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇▇▇

Environmental Attorney Supervisor

Oklahoma Department of Environmental Quality

Office of General Counsel

P.O. Box 1677

Oklahoma City, OK 73101-1677

▇▇▇ ▇▇▇▇▇▇, Environmental Engineering Manager

Air Quality Division

Oklahoma Department of Environmental Quality

P.O. Box 1677

Oklahoma City, OK 73101-1677

For OG&E:

Ford Benham

Supervisor, Air Quality

Oklahoma Gas & Electric Company

321 ▇. ▇▇▇▇▇▇

Oklahoma City, OK 73102

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With copies to:

▇▇▇▇▇▇ ▇▇▇▇▇

Senior Attorney

Oklahoma Gas & Electric Company

321 ▇. ▇▇▇▇▇▇

Oklahoma City, OK 73102

34. This Agreement is enforceable as a final order of the Executive Director of DEQ. DEQ retains jurisdiction of this matter for the purposes of interpreting, implementing and enforcing the terms and conditions of this Agreement and for the purpose of resolving disputes.

35. Nothing in this Agreement limits DEQ’s right to take enforcement action for violations discovered or occurring after the effective date of this Agreement.

36. Nothing in this Agreement excuses OG&E from its obligation to comply with all applicable federal, state and local statutes, rules and ordinances. OG&E and DEQ agree that the provisions of this Agreement are considered severable, and if a court of competent jurisdiction finds any provisions to be unenforceable because they are inconsistent with state or federal law, the remaining provisions will remain in full effect.

37. To ensure continuous and uninterrupted responsibility for the activities required by this Agreement, OG&E agrees to provide a copy of the Agreement to any purchaser of an affected unit prior to sale. OG&E agrees to notify any such purchaser that the obligations under this Agreement are binding on the purchaser and shall notify DEQ of the sale within ten (10) days thereof and provide DEQ with the name of the purchaser.

38. The provisions of this Agreement apply to and bind OG&E and DEQ and their officers, directors, employees, agents, successors and assigns. No change in the ownership or corporate status of OG&E will affect OG&E’s responsibilities under this Agreement.

39. This Agreement is for the purpose of settlement. Neither the fact that OG&E and

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DEQ have agreed to this Agreement, nor the Findings of Fact and Conclusions of Law in it, shall be used for any purpose in any proceeding except the enforcement by OG&E and DEQ of this Agreement and, if applicable, a future determination by DEQ of eligibility for licensing or permitting. As to others who are not parties to this Agreement, nothing contained in this Agreement is an admission by OG&E of the Findings of Fact or Conclusions of Law, and this Agreement is not an admission by OG&E of liability for conditions at or near the facility and is not a waiver of any right, cause of action or defense OG&E otherwise has.

40. OG&E and DEQ agree that the venue of any action in district court for the purposes of interpreting, implementing and enforcing this Agreement will be Oklahoma County, Oklahoma.

41. The requirements of this Agreement will be considered satisfied and this Agreement terminated when OG&E receives written notice from DEQ that OG&E has demonstrated that all the terms of the Agreement have been completed to the satisfaction of DEQ, and that any assessed penalty has been paid.

42. OG&E and DEQ may amend this Agreement by mutual consent. Such amendments must be in writing and the effective date of the amendments will be the date on which they are filed by DEQ.

43. The individuals signing this Agreement certify that they are authorized to sign it and to legally bind the parties they represent.

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44. This Agreement becomes effective on the date of the later of the two signatures below.

Date:

1/18/10

Date:

2/17/10

FOR THE OKLAHOMA GAS & ELECTRIC			FOR THE OKLAHOMA DEPARTMENT
COMPANY:			OF ENVIRONMENTAL QUALITY:



/s/ ▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇			/s/ ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇
▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇			▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇
CHIEF EXECUTIVE OFFICER			EXECUTIVE DIRECTOR

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EXHIBIT A

Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis		September 28, 2009

COMPANY:	Oklahoma Gas and Electric

FACILITY:	Seminole Generating Station

FACILITY LOCATION:	Konawa, Seminole County, Oklahoma

TYPE OF OPERATION:	(3) 567 MW Steam Electric Generating Units

REVIEWER:	▇▇▇▇▇▇▇ ▇▇▇▇▇▇▇, Senior Engineering Manager
	▇▇▇ ▇▇▇▇▇▇, Engineering Manager

I. PURPOSE OF APPLICATION

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final "Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations" (the "Regional Haze Rule" 70 FR 39104). The Regional Haze Rule requires certain States, including Oklahoma, to develop programs to assure reasonable progress toward meeting the national goal of preventing any future, and remedying any existing, impairment of visibility in Class I Areas. The Regional Haze Rule requires states to submit a plan to implement the regional haze requirements (the Regional Haze SIP). The Regional Haze SIP must provide for a Best Available Retrofit Technology (BART) analysis of any existing stationary facility that might cause or contribute to impairment of visibility in a Class I Area.

II. ▇▇▇▇ ELIGIBILITY DETERMINATION

BART-eligible sources include those sources that:

(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant;

(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and

(3) whose operations fall within one or more of the specifically listed source categories in 40 CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input).

Seminole Units 1, 2 and 3 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. All three units were in existence prior to August 7, 1977 but not in operation prior to August 7, 1962. Based on a review of existing emissions data, all three units have the potential to emit more than 250 tons per year of NOx, a visibility impairing pollutant. Therefore, Seminole Units 1, 2 and 3 meet the definition of a BART-eligible source.

▇▇▇▇ is required for any BART-eligible source that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area.

OG&E Seminole Generating Station BART Evaluation September 28, 2009

DEQ has determined that an individual source will be considered to "contribute to visibility impairment" if emissions from the source result in a change in visibility, measured as a change in deciviews (∆-dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling conducted by OG&E determined that the maximum predicted visibility impacts from Seminole Units 1, 2 and 3 exceeded the 0.5 ∆-dv threshold at the Wichita Mountains Class I Area. Therefore, Seminole Units 1, 2 and 3 were determined to be BART applicable sources, subject to the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Seminole Units 1, 2 and 3 were developed based on an evaluation of actual emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling analysis to determine visibility impairment impacts should reflect steady-state operating conditions during periods of high capacity utilization. Therefore, baseline emissions (lb/hr) represent the highest 24-hour block emissions reported during the baseline period. Baseline emission rates (lb/mmBtu) were calculated by dividing the maximum hourly mass emission rates for each boiler by the boiler's full load heat input.

Table 1: Seminole Generating Station – Plant Operating Parameters for BART Evaluation
Parameter	Seminole Unit 1		Seminole Unit 2		Seminole Unit 3
Plant Configuration	Natural Gas-Fired Boiler		Natural Gas-Fired Boiler		Natural Gas-Fired Boiler
Firing Configuration	Wall-fired		Wall-fired		Wall-fired
Gross Output (nominal)	567 MW		567 MW		567 MW
Maximum Input to Boiler	5,480 mmBtu/hr		5,480 mmBtu/hr		5,496 mmBtu/hr
Primary Fuel	Natural gas		Natural gas		Natural gas
Existing NOx Controls	None		None		Flue gas recirculation
Existing PM10 Controls	NA		NA		NA
Existing SO2 Controls	NA		NA		NA
Baseline Emissions Pollutant	Baseline Actual Emissions		Baseline Actual Emissions		Baseline Actual Emissions
	lb/hr	lb/mmBtu	lb/hr	lb/mmBtu	lb/hr	lb/mmBtu
NOx	1,859	0.339	1,940	0.354	1,204	0.219

OG&E Seminole Generating Station BART Evaluation September 28, 2009

IV. BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 (Guidelines for BART Determinations under the Regional Haze Rule). States are required to use the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants having a total generating capacity in excess of 750 MW. The BART determination process described in Appendix Y includes the following steps:

Step l. Identify All Available Retrofit Control Technologies.

Step 2. Eliminate Technically Infeasible Options.

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.

Step 4. Evaluate Impacts and Document the Results.

Step 5. Evaluate Visibility Impacts.

Because the units fire natural gas, emissions of sulfur dioxide (SO2) and particulate matter (PM) are minimal. There are no SO2 or PM post-combustion control technologies with a practical application to natural gas-fired boilers. BART is good combustion practices. A full BART analysis was conducted for NOx.

Table 2: Proposed BART Controls and Limits
Unit	NOx BART Emission Limit	BART Technology
Seminole Unit 1	0.203 lb/mmBtu (30-day average)	Combustion controls including LNB/OFA and FGR
Seminole Unit 2	0.212 lb/mmBtu (30-day average)	Combustion controls including LNB/OFA and FGR
Seminole Unit 3	0.164 lb/mmBtu (30-day average)	Combustion controls including LNB/OFA and FGR

A. NOx

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Potentially available control options were identified based on a comprehensive review of available information. NOx control technologies with potential application to Seminole Units 1, 2 and 3 are listed in Table 3.

	Table 3: List of Potential Control Options
	Control Technology
	Combustion Controls
	Low NOx Burners and Overfire Air (LNB/OFA)
	Flue Gas Recirculation (FGR)
	Post Combustion Controls
	Selective Noncatalytic Reduction (SNCR)
	Selective Catalytic Reduction (SCR)
	Innovative Control Technologies
	Rotating Overfire Air (ROFA)
	ROFA + SNCR (Rotamix)
	▇▇▇▇▇▇▇ Process
	Wet NOx Scrubbing

OG&E Seminole Generating Station BART Evaluation September 28, 2009

In support of the Regional Haze Rule, EPA also prepared a cost-effectiveness analysis for retrofit control technologies on oil- and gas-fired units. EPA's analysis concluded that, although a number of oil- and gas-fired units could make significant cost-effective reductions in NOx emissions using currently available combustion control technologies, for a number of units the use of combustion controls did not appear to be cost effective. As a result, EPA determined that it would be inappropriate to establish a general presumption regarding likely BART limits for oil- and natural gas fired units.

ELIMINATE TECHNICALLY INFEASIBLE OPTIONS (NOx)

Combustion Controls:

Low NOx burners (LNB)/ Over Fire Air (OFA)

Low NOx burners (LNB) limit NOx formation by controlling both the stoichiometric and temperature profiles of the combustion flame in each burner flame envelope. Over Fire Air (OFA) allows for staged combustion. Staging combustion reduces NOx formation with a cooler flame in the initial stage and less oxygen in the second stage.

LNB/OFA emission control systems have been installed as retrofit control technologies on existing natural gas-fired boilers. Boilers of the size and age of the Seminole Units would be expected to achieve an average emission reduction in the range of 25% to 40% from baseline depending on the baseline emission rate and boiler operating conditions. Seminole units 1, 2, and 3 do not operate as base load units. The units have historically operated as "peaking units" responding to increased demand for electricity. While technically feasible, LNB/OFA may not be as effective under all boiler operating conditions, especially during load changes and at low and high operating loads. Based on information available from burner control vendors and engineering judgment, it is expected that LNB/OFA on the wall-fired boilers can be designed to achieve an average efficiency of 25% from baseline emissions under all normal operating conditions.

Flue Gas Recirculation

Flue gas recirculation (FGR) controls NOx by recycling a portion of the flue gas back into the primary combustion zone. The recycled air lowers NOx emissions by two mechanisms: (1) the recycled gas, consisting of products which are inert during combustion, lowers the combustion temperatures; and (2) the recycled gas will reduce the oxygen content in the primary flame zone. The amount of recirculation is based on flame stability. Seminole Unit 3 is currently designed with FGR control.

FGR may be applied in one of two techniques. Both designs are technically feasible retrofit options for gas-boilers. Either system would be expected to achieve an additional 15% reduction above LNB/OFA or approximately 40% overall reduction from baseline.

Post Combustion Controls:

Selective Non-Catalytic Reduction

OG&E Seminole Generating Station BART Evaluation September 28, 2009

NOx resulting in low NOx reduction efficiencies. Mixing of the reactant and flue gas within the reaction zone is also an important factor in SNCR performance. In large boilers, the physical distance over which the reagent must be dispersed increases, and the surface area/volume ratio of the convective pass decreases. Both of these factors make it difficult to achieve good mixing of reagent and flue gas, reducing overall efficiency. Performance is further influenced by residence time, reagent-to-NOx ratio, and fuel sulfur content.

The size of the Seminole Units would represent several design problems making it difficult to ensure that the reagent would be injected at the optimum flue gas temperature, and that there would be adequate mixing and residence time. The physical size of the Seminole boilers makes it technically infeasible to locate and install ammonia injection points capable of achieving adequate mixing within the required temperature zone. Higher reagent injection rates would be required to achieve adequate mixing. This design would tend to result in relatively high levels of ammonia slip. Further, because the Seminole boilers are typically used as peaking units, boiler load is continually changing. Boiler load changes affect flue gas flow rates and temperatures, which would make it particularly difficult to inject the needed quantity of reactant.

Installation of SNCR on large boilers, such as those at Seminole, has not been demonstrated in practice. Assuming that SNCR could be installed on the Seminole Units, given the issues addressed above, control effectiveness would be marginal, and depending on boiler exit temperatures, could actually result in additional NOx formation. SNCR is not a technically feasible retrofit control for the Seminole Boilers.

Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) involves injecting ammonia into boiler flue gas in the presence of a catalyst to reduce NOx to N2 and water. Anhydrous ammonia injection systems may be used, or ammonia may be generated on-site from a urea feedstock.

SCR has been installed as NOx control technology on existing gas-fired boilers. Based on emissions data available from the EPA Electronic Reporting website, large gas-fired boilers (with heat inputs above approximately 1,000 mmBtu/hr) have achieved actual long-term average NOx emission rates in the range of approximately 0.02 to 0.05 lb/mmBtu. Several design and operating variables will influence the performance of the SCR system, including the volume, age and surface area of the catalyst (e.g., catalyst layers), uncontrolled NOx emission rate, flue gas temperature and catalyst activity.

Based on emission rates achieved in practice at existing gas-fired units, and taking into consideration long-term operation of an SCR control system (including catalyst plugging and deactivation) and the fact that the Seminole boilers typically operate as peaking units, it is anticipated that SCR could achieve a controlled NOx emission rate of 0.04 lb/mmBtu (30-day rolling average) on Seminole Units 1, 2 and 3.

Innovative NOX Control Technologies:

Rotating Opposed Fire Air and Rotamix

Rotating opposed fired air (ROFA) is a boosted over fire air system that includes a patented rotation process which includes asymmetrically placed air nozzles. Like other OFA systems,

OG&E Seminole Generating Station BART Evaluation September 28, 2009

ROFA stages the primary combustion zone to burn overall rich, with excess air added higher in the furnace to burn out products of incomplete combustion.

As discussed in for OFA, over fire air control systems are a technically feasible retrofit control technology, and, based on engineering judgment, the ROFA design could also be applied on Seminole Units 1, 2 and 3. However, there is no technical basis to conclude that the ROFA design would provide additional NOx reduction beyond that achieved with other OFA designs. Therefore, ROFA control systems are not evaluated as a specific control system, but are included in the overall evaluation of combustion controls (e.g., LNB/OFA).

ROFA+ SNCR (Rotamix)

The Rotamix system is a SNCR control system (i.e., ammonia injection system) coupled with the ROFA rotating injection nozzle design. The technical limitations discussed in the SNCR section, including the physical size of the boiler, inadequate NH3/NOx contact, and flue gas temperatures, would apply equally to the Rotamix control system. There is no technical basis to conclude that the Rotamix design addresses these unresolved technical difficulties. Therefore, like other SNCR control systems, the Rotamix system is not a technically feasible retrofit control for the Seminole Boilers.

▇▇▇▇▇▇▇ Multi-Pollutant Control Process

The PahlmanTM Process is a patented dry-mode multi-pollutant control system. The process uses a sorbent composed of oxides of manganese (the Pahlmanite™ sorbent) to remove NOx and SO2 from the flue gas.

To date, bench- and pilot-scale testing have been conducted to evaluate the technology on utility-sized boilers. The New & Emerging Environmental Technologies (NEET) Database identifies the development status of the ▇▇▇▇▇▇▇ Process as full-scale development and testing. The process is an emerging multi-pollutant control, and there is limited information available to evaluate its technically feasibility and long-term effectiveness on a large natural gas-fired boiler. It is likely that OG&E would be required to conduct extensive design engineering and testing to evaluate the technical feasibility and long-term effectiveness of the control system on Seminole Units 1, 2 and 3. ▇▇▇▇ does not require applicants to experience extended time delays or resource penalties to allow research to be conducted on an emerging control technique. Therefore, at this time the ▇▇▇▇▇▇▇ Process is not a technically feasible retrofit control for the Seminole Boilers.

Wet NOx Scrubbing Systems

Wet scrubbing systems have been used to remove NOx emissions from fluid catalytic cracking units (FCCUs) at petroleum refineries. An example of a wet scrubbing system is Balco Technologies' LoTOxTM system. The LoTOx system is a patented process, wherein ozone is injected into the flue gas stream to oxidize NO and NO2 to N2O5. This highly oxidized species of NOx is very soluble and rapidly reacts with water to form nitric acid. The conversion of NOx to nitric acid occurs as the N2O5 contacts liquid sprays in the scrubber.

Wet scrubbing systems have been installed at chemical processing plants and smaller coal-fired boilers. The NEET Database classifies wet scrubbing systems as commercially established for

OG&E Seminole Generating Station BART Evaluation September 28, 2009

petroleum refining and oil/natural gas production. However the technology has not been demonstrated on large utility boilers and it is likely that OG&E would incur substantial engineering and testing to evaluate the scale-up potential and long-term effectiveness of the system. Therefore, at this time wet NOx scrubbing systems are not technically feasible retrofit controls for the Seminole Boilers.

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NOx)

Table 4: Technically Feasible NOx Control Technologies – Seminole Station
	Seminole Unit 1	Seminole Unit 2	Seminole Unit 3
Control Technology	Approximate NOx Emission Rate (lb/mmBtu)	Approximate NOx Emission Rate (lb/mmBtu)	Approximate NOx Emission Rate (lb/mmBtu)
LNB/OFA + SCR	0.04	0.04	0.04
LNB/OFA + FGR	0.203	0.212	0.164
LNB/OFA	0.254	0.266	NA
Baseline	0.339	0.354	0.219

EVALUATE IMPACTS AND DOCUMENT RESULTS (NOx)

OG&E evaluated the economic, environmental, and energy impacts associated with the three proposed control options. In general, the cost estimating methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. Major equipment costs were developed based on publicly available cost data and equipment costs recently developed for similar projects, and include the equipment, material, labor, and all other direct costs needed to retrofit Seminole Units 1, 2 and 3 with the control technologies. Fixed and variable O&M costs were developed for each control system. Fixed O&M costs include operating labor, maintenance labor, maintenance material, and administrative labor. Variable O&M costs include the cost of consumables, including reagent (e.g., ammonia), byproduct management, water consumption, and auxiliary power requirements. Auxiliary power requirements reflect the additional power requirements associated with operation of the new control technology, including operation of any new fans as well as the power requirements for pumps, reagent handling, and by-product handling. The capital recovery factor used to estimate the annual cost of control was based on a 7% interest rate and a control life of 25 years. OG&E provided a summary of historical capacity factors which typically ranged between approximately 25% to 30%. Annual operating costs and annual emission reductions were calculated assuming a capacity factor of 50%.

OG&E Seminole Generating Station BART Evaluation September 28, 2009

Table 5: Economic Cost Per Boiler
Cost	Unit	Option 1: LNB/OFA	Option 2: LNB/OFA w/EGR	Option 3: LNB/OFA + SCR
Control Equipment Capital Cost ($)	Unit 1	$9,432,200	$16,977,200	$104,230,200
	Unit 2	$9,432,200	$16,977,200	$104,230,200
	Unit 3	$9,468,600	$9,468,600	$104,834,200
Capital Recover Factor ($/Yr)	Unit 1	$809,300	$1,456,700	$8,943,000
	Unit 2	$809,300	$1,456,700	$8,943,000
	Unit 3	$812,400	$812,400	$8,994,800
Annual O&M Costs ($/Yr)	Unit 1	$588,600	$1,190,900	$8,152,800
	Unit 2	$588,600	$1,190,900	$8,175,600
	Unit 3	$590,800	$590,800	$8,023,800
Annual Cost of Control ($)	Unit 1	$1,397,900	$2,647,600	$17,095,800
	Unit 2	$1,397,900	$2,647,600	$17,118,600
	Unit 3	$1,403,200	$1,403,200	$17,018,600

Table 6: Environmental Costs per Boiler
		Baseline	Option 1: LNB/OFA	Option 2: LNB/OFA w/EGR	Option 3: LNB/OFA + SCR
NOx Emission Rate (lb/mmBtu)	Unit 1	0.339	0.254	0.203	0.04
	Unit 2	0.354	0.266	0.212	0.04
	Unit 3	0.219	0.164	0.164	0.04
Annual NOx Emission (TPY)1	Unit 1	4,068	3,048	2,436	480
	Unit 2	4,248	3,192	2,544	480
	Unit 3	2,636	1,974	1,974	481
Annual NOx Reduction (TPY)	Unit 1	-	1020	1632	3588
	Unit 2		1056	1704	3768
	Unit 3		662	662	2155
Annual Cost of Control2	Unit 1		$1,397,900	$2,647,600	$17,095,800
	Unit 2		$1,397,900	$2,647,600	$17,118,600
	Unit 3		$1,403,200	$1,403,200	$17,018,600
Cost per Ton of Reduction	Unit 1		$1,370	$1,622	$4,765
	Unit 2		$1,324	$1,554	$4,543
	Unit 3		$2,120	$2,120	$7,897
Incremental Cost per Ton of Reduction3	Unit 1	NA	---	$2,042	$7,387
	Unit 2			$1,929	$7,011
	Unit 3			---	$10,459

(1)Emissions for the BART analysis are based on maximum heat inputs of 5,480 mmBtu/hr (Units 1 & 2) and 5,496 mmBtu/hr (Unit 3). Annual emissions were calculated assuming 4,380 hours/year per boiler (50% capacity factor).

(2) Total annual cost for all three units are not additive because Unit 3 is currently equipped with FGR control and Unit 3 has a slightly higher heat input.

(3) Incremental cost effectiveness of the FGR system is compared to costs/emissions associated with LNB/OFA controls. Similarly, incremental cost effectiveness of the SCR system is compared to costs/emissions associated with LNB/OFA+FGR controls.

OG&E Seminole Generating Station BART Evaluation September 28, 2009

B. VISIBILITY IMPROVEMENT DETERMINATION

The fifth of five factors that must be considered for a BART determination analysis, as required by a 40 CFR part 51-Appendix Y, is the degree of Class I area visibility improvement that would result from the installation of the various options for control technology. This factor was evaluated for the Seminole Generating Station by using an EPA-approved dispersion modeling system (CALPUFF) to predict the change in Class I area visibility. The Division had previously determined that the Seminole Generating Station was subject to BART based on the results of initial screening modeling that was conducted using current (baseline) emissions from the facility. The screening modeling, as well as more refined modeling conducted by the applicant, is described in detail below.

Wichita Mountain Wildlife Refuge, Caney Creek, Upper Buffalo and Hercules Glade are the closest Class I areas to the Seminole Generating Station, as shown in Figure 1 below.

Only those Class I areas most likely to be impacted by the Seminole Generating Station were modeled, as determined by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. It can be reasonably assumed that areas at greater distances and in directions of less frequent plume transport will experience lower impacts than those predicted for the four modeled areas.

IMAGE NOT SHOWN

Figure 1: Plot of Facility Location in relation to nearest Class I areas.

OG&E Seminole Generating Station BART Evaluation September 28, 2009

REFINED MODELING:

Because of the results of the applicants screening modeling for the Seminole Generating Station, OG&E was required to conduct a refined BART analysis that included CALPUFF visibility modeling for the facility. The modeling approach followed the requirements described in the Division's BART modeling protocol, CENRAP BART Modeling Guidelines (Alpine Geophysics, December 2005) with refinements detailed the applicants CALMET modeling protocol, CALMET Data Processing Protocol (Trinity Consultants, January 2008)

CALPUFF System

Predicted visibility impacts from the Seminole Generating Station were determined with the EPA CALPUFF modeling system, which is the EPA-preferred modeling system for long-range transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR Part 51), long-range transport is defined as modeling with source-receptor distances greater than 50 km. Because all modeled areas are located more than 50 km from the sources in question, the CALPUFF system was appropriate to use.

The CALPUFF modeling system consists of a meteorological data pre-processor (CALMET), an air dispersion model (CALPUFF), and post-processor programs (POSTUTIL, CALSUM, CALPOST). The CALPUFF model was developed as a non-steady-state air quality modeling system for assessing the effects of time- and space-varying meteorological conditions on pollutant transport, transformation, and removal.

CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a three-dimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and upper-air observations from multiple meteorological monitoring stations. Additionally, the CALMET model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent regional wind flows and complex terrain circulations. Associated two-dimensional fields such as mixing height, land use, and surface roughness are included in the input to the CALMET model. The CALMET model allows the user to "weight" various terrain influences parameters in the vertical and horizontal directions by defining the radius of influence for surface and upper-air stations.

CALPUFF is a multi-layer, Lagrangian puff dispersion model. CALPUFF can be driven by the three-dimensional wind fields developed by the CALMET model (refined mode), or by data from a single surface and upper-air station in a format consistent with the meteorological files used to drive steady-state dispersion models. All far-field modeling assessments described here were completed using the CALPUFF model in a refined mode.

CALPOST is a post-processing program that can read the CALPUFF output files, and calculate the impacts to visibility.

All of the refined CALPUFF modeling was conducted with the version of the CALPUFF system that was recognized as the EPA-approved release at the time of the application submittal. Version designations of the key programs are listed in the table below.

OG&E Seminole Generating Station BART Evaluation September 28, 2009

Table 7: Key Programs in CALPUFF System
Program	Version	Level
CALMET	5.53a	040716
CALPUFF	5.8	070623
CALPOST	5.51	030709

Meteorological Data Processing (CALMET)

As required by the Division's modeling protocol, the CALMET model was used to construct the initial three-dimensional wind field using data from the MM5 model. Surface and upper-air data were also input to CALMET to adjust the initial wind field.

The following table lists the key user-defined CALMET settings that were selected.

Table 8: CALMET Variables
Variable	Description	Value
PMAP	Map projection	LCC (▇▇▇▇▇▇▇ Conformal Conic)
DGRIDKM	Grid spacing (km)	4
NZ	Number of layers	12
ZFACE	Cell face heights (m)	0, 20, 40, 60, 80, 100, 150, 200, 250, 500, 1000, 2000, 3500
RMIN2	Minimum distance for extrapolation	-1
IPROG	Use gridded prognostic model outputs	14 km (MM5 data)
RMAX1	Maximum radius of influence (surface layer, km)	20 km
RMAX2	Maximum radius of influence (layers aloft, km)	50 km
TERRAD	Radius of influence for terrain (km)	10 km
R1	Relative weighting of first guess wind field and observation (km)	10 km
R2	Relative weighting aloft (km)	25 km

The locations of the upper air stations with respect to the modeling domain are shown in Figure 2.

OG&E Seminole Generating Station BART Evaluation September 28, 2009

IMAGE NOT SHOWN

Figure 2: Plot of surface station locations

IMAGE NOT SHOWN

Figure 3: Plot of upper air station locations

OG&E Seminole Generating Station BART Evaluation September 28, 2009

IMAGE NOT SHOWN

Figure 4. Plot of precipitation observation stations

CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry mechanism (MESOPUFF II), the model required input of background ozone and ammonia. CALPUFF can use either a single background value representative of an area or hourly ozone data from one or more ozone monitoring stations. Hourly ozone data files were used in the CALPUFF simulation. As provided by the Oklahoma DEQ, hourly ozone data from the Oklahoma City, Glenpool, and Lawton monitors over the 2001-2003 time frames were used. Background concentrations for ammonia were assumed to be temporally and spatially invariant and were set to 3 ppb.

Latitude and longitude coordinates for Class I area discrete receptors were taken from the National Park Service (NPS) Class I Receptors database and converted to the appropriate LCC coordinates.

CALPUFF Inputs-Baseline and Control Options

The first step in the refined modeling analysis was to perform visibility modeling for current (baseline) operations at the facility. Emissions of NOx for the baseline runs were established based on CEM data and maximum 24-hour emissions averages for years 2001 to 2003. All particulate emissions (PM) were based on emission rates of 0.00186 lb/mmBtu (filterable) and were treated as PM10 (coarse PM) and 0.00559 lb/mmBtu (condensable) and were treated as PM2.5 (fine PM) within CALPUFF and CALPOST. Direct emissions of sulfate were based on the values calculated for the Toxic Release Inventory (TRI) for the years modeled.

Baseline source release parameters and emissions are shown in the table below, followed by tables with data for the various control options. No attempt was made by the applicant to estimate the increase in sulfate emissions that would result from operations of SCR, and as a

OG&E Seminole Generating Station BART Evaluation September 28, 2009

result the visibility improvement for those scenarios may be overestimated by some undetermined amount.

Table 9: Baseline Source Parameters
	Baseline
Parameter	Natural Gas-Fired Unit 1	Natural Gas-Fired Unit 2	Natural Gas-Fired Unit 3 (FGR)
Heat Input (mmBtu/hr)	5,480	5,480	5,496
Base Elevation (m)	290	290	290
Stack Height (m)	54.27	54.27	106.71
Stack Diameter (m)	4.57	4.57	5.49
Stack Temperature (K)	392.44	392.44	411.89
Exit Velocity (m/s)	42.32	42.32	30.95
SO2 Emissions (lb/mmBtu)	0.00055	0.00042	0.00060
SO2 Emissions (TPY)	13.20	10.08	14.44
NOX Emissions1 (lb/mmBtu)	0.339	0.354	0.219
NOX Emissions (TPY)	8136.81	8496.85	5271.87
PM10 Fine Emissions2 (lb/mmBtu)	0.00745	0.00745	0.00745
PM10 Fine Emissions (TPY)	178.82	178.82	179.34

1Baseline NOx emissions were based on the maximum 24-hr average emission rate (lb/hr) reported by each unit during the baseline period 2003-2005. Baseline emissions data were provided by OG&E. Baseline emission rates (lb/mmBtu) were calculated by dividing the maximum 24-hr lb/hr emission rate by the maximum heat input to the boiler.

2PM emissions are based on AP-42 emission factors for natural gas combustion (filterable and condensable).

Table 10: Source Parameters and Emissions for BART Control Options
Scenario		Control	Heat Input (mmBtu/hr)	NOX emissions (lb/mmBtu)	NOX Emissions (TPY)
Control Option 1		LNB/OFA	5,480	0.254	6,097
	Natural Gas- Fired Unit 2	LNB/OFA	5,480	0.266	6,384
	Natural Gas- Fired Unit 3	LNB/OFA FGR	5,496	0.164	3,948
Control Option 2	Natural Gas- Fired Unit 1	LNB/OFA FGR	5,480	0.203	4,872
	Natural Gas- Fired Unit 2	LNB/OFA FGR	5,480	0.212	5,089
	Natural Gas- Fired Unit 3	LNB/OFA FGR	5,496	0.164	3,948

OG&E Seminole Generating Station BART Evaluation September 28, 2009


Scenario		Control	Heat Input (mmBtu/hr)	NOX emissions (lb/mmBtu)	NOX Emissions (TPY)
Control Option 3	Natural Gas- Fired Unit 1	LNB/OFA + SCR	5,480	0.040	960
	Natural Gas- Fired Unit 2	LNB/OFA + SCR	5,480	0.040	960
	Natural Gas- Fired Unit 3	LNB/OFA + SCR	5,496	0.040	963

Visibility Post-Processing (CALPOST) Setup

The changes in visibility were calculated using Method 6 with the CALPOST post-processor. Method 6 requires input of monthly relative humidity factors [f(RH)] for each Class I area that is being modeled. Monthly f(RH) factors that were used for this analysis are shown in the table below.

Table 11: Relative Humidity Factors for CALPOST
Month	Wichita Mountains	Caney Creek	Upper Buffalo	Hercules Glade
January	2.7	3.4	3.3	3.2
February	2.6	3.1	3.0	2.9
March	2.4	2.9	2.7	2.7
April	2.4	3.0	2.8	2.7
May	3.0	3.6	3.4	3.3
June	2.7	3.6	3.4	3.3
July	2.3	3.4	3.4	3.3
August	2.5	3.4	3.4	3.3
September	2.9	3.6	3.6	3.4
October	2.6	3.5	3.3	3.1
November	2.7	3.4	3.2	3.1
December	2.8	3.5	3.3	3.3

EPA’s default average annual aerosol concentrations for the U.S. that are included in Table 2-1 of EPA’s Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program were to develop natural background estimates for each Class I area.

OG&E Seminole Generating Station BART Evaluation September 28, 2009

Visibility Post-Processing Results

Table 12: CALPUFF Visibility Modeling Results for Seminole Units 1, 2 and 3
	2001		2002		2003		3-Year Average
Class I Area	98th Percentile Value ( ∆ dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv
Baseline
Wichita Mountains	1.073	20	0.744	12	1.3	25	1.039	19
Caney Creek	1.173	18	0.455	7	0.443	7	0.69	11
Upper Buffalo	0.635	9	0.24	2	0.302	2	0.39	4
Hercules Glade	0.403	5	0.294	3	0.301	3	0.33	4
Scenario 2 – Combustion Control – LNB/OFA/FGR
Wichita Mountains	0.707	13	0.476	7	0.832	17	0.67	12
Caney Creek	0.754	12	0.284	1	0.284	2	0.44	5
Upper Buffalo	0.411	4	0.157	2	0.191	1	0.25	2
Hercules Glade	0.255	2	0.186	0	0.188	2	0.21	1

Modeling for SCR controls resulted in an approximately 80% reduction in visibility impairment from scenario two.

C. BART DETERMINATION

After considering: (1) the costs of compliance, (2) the energy and non-air quality environmental impacts of compliance, (3) any pollutant equipment in use or in existence at the source, (4) the remaining useful life of the source, and (5) the degree of improvement in visibility (all five statutory factors) from each proposed control technology, the Division determined BART for the three units at the Seminole Generating Station.

New LNB with OFA is determined to be BART for NOX control for Units 1-3 based, in part, on the following conclusions:

1.	Installation of new LNB with OFA and FGR was cost effective, with a capital cost of $16,977,200 per unit for units 1 and 2 and $9,468,600 for unit 3 and an average cost effectiveness of $1,554-$2,120 per ton of NOx removed for each unit over a twenty year operational life.

2.	Combustion control using the LNB/OFA and FGR does not require non-air quality environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is minimal energy impact.

OG&E Seminole Generating Station BART Evaluation September 28, 2009

3.	After careful consideration of the five statutory factors, especially the costs of compliance and existing controls, NOx control levels on 30-day rolling averages of 0.203 lb/mmBtu for Unit 1, 0.212 lb/mmBtu for Unit 2 and 0.164 lb/mmBtu for Unit 3 are justified.

4.	Annual NOx emission reductions from new LNB with OFA and FGR on Units 1, 2, and 3 are 662-1,704 tons for a total annual reduction of 3,998 tons.

LNB with OFA and SCR was not determined to be BART for NOx control for Units 1-3 based, in part, on the following conclusions:

The cost of compliance for installing SCR on each unit is significantly higher than the cost for LNB with OFA and FGR. Additional capital costs for SCR on Units 1-3 are on average $89,957,200 per unit. Based on projected actual emissions, SCR could reduce overall NOx emissions from Seminole Units 1, 2 and 3 by approximately 5,513 tpy (compared to combustion controls and flue gas recirculation); however, the incremental cost associated with this reduction is approximately $44,534,600 per year. or $8,078/ton.

2.	Additional non-air quality environmental mitigation is required for the use of chemical reagents.

3.	Operation of LNB with OFA and SCR is parasitic and requires power from each unit.

4.	SCR control may not be as effective on boilers that operate as peaking units, as NOx reduction in an SCR is a function of flue gas temperature.

5.	The cumulative visibility improvement for SCR, as compared to LNB/OFA and FGR across Wichita Mountains and Caney Creek (based on the 98th percentile modeled results) was 0.56-0.60 ∆dv for all three units.

The Division considers the installation and operation of the BART determined NOx controls, new LNB with OFA and FGR, to meet the statutory requirements of BART.

Unit-by-unit NOx BART determinations:

Seminole Generating Station Unit

1: New LNB with OFA and FGR and meeting NOx emission limit of 0.203 lb/mmBtu (30-day rolling average), 1,112 lb/hr (30-day rolling average), and 4,872 tpy (l2-month rolling) as BART for NOx.

Seminole Generating Station Unit

2: New LNB with OFA and FGR and meeting NOx emission limit of 0.212 lb/mmBtu (30-day rolling average), 1,162 lb/hr (30-day rolling average), and 5,089 tpy (12-month rolling) as BART for NOx.

Seminole Generating Station Unit

3: New LNB with OFA and FGR and meeting NOx emission limit of 0.164 lb/mmBtu (30-day rolling

OG&E Seminole Generating Station BART Evaluation September 28, 2009

average), 901 lb/hr (30-day rolling average), and 3,948 tpy (12-month rolling) as BART for NOx.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD)

Seminole Generating Station is a major source under OAC 252:100-8 Permits for Part 70 Sources. Oklahoma Gas and Electric should comply with the permitting requirements of Subchapter 8 as they apply to the installation of controls determined to meet ▇▇▇▇.

The installation of controls determined to meet ▇▇▇▇ will not change NSPS or NESHAP/MACT applicability for the gas-fired units at the Seminole Station.

VI. OPERATING PERMIT

The Seminole Generating Station is a major source under OAC 252:100-8 and has submitted an application to modify their existing Title V permit to incorporate the requirement to install controls determined to meet ▇▇▇▇. The Permit will contain the following specific conditions:

1. The boilers in EUG 2 are subject to the Best Available Retrofit Technology (BART) requirements of 40 CFR Part 51, Subpart P, and shall comply with all applicable requirements including but not limited to the following: [40 CFR §§ 51.300-309 & Part 51, Appendix Y]

a.	Affected facilities. The following sources are affected facilities and are subject to the requirements of this Specific Condition, the Protection of Visibility and Regional Haze Requirements of 40 CFR Part 51, and all applicable SIP requirements:

EU ID#	Point ID#	EU Name	Heat Capacity (MMBTUH)	Construction Date
2-B	01	Unit 1 Boiler	5,480	1968
2-B	02	Unit 2 Boiler	5,480	1968
2-B	03	Unit 3 Boiler	5,496	5/28/70

b.	Each existing affected facility shall install and operate the SIP approved BART as expeditiously as practicable but in no later than five years after approval of the SIP incorporating the BART requirements.

c.	The permittee shall apply for and obtain a construction permit prior to modification of the boilers. If the modifications will result in a significant emission increase and a significant net emission increase of a regulated NSR pollutant, the applicant shall apply for a PSD construction permit.

d.	The affected facilities shall be equipped with the following current combustion control technology, as determined in the submitted BART analysis, to reduce emissions of NOX to below the emission limits below:

i.	Low-NOX Burners,

ii.	Overfire Air, and

OG&E Seminole Generating Station BART Evaluation September 28, 2009

iii.	Flue Gas Recirculation.

e.	The permittee shall maintain the combustion controls (Low-NOX burners, overfire air, and flue gas recirculation) and establish procedures to ensure the controls are properly operated and maintained.

Within 60 days of achieving maximum power output from each affected facility, after modification or installation of BART, not to exceed 180 days from initial start-up of the affected facility the permittee shall comply with the emission limits established in the construction permit. The emission limits established in the construction permit shall be consistent with manufacturer’s data and an agreed upon safety factor. The emission limits established in the construction permit shall not exceed the following emission limits:

EU ID#	Point ID#	NOX Emission Limit	Averaging Period
2-B	01	0.203 lb/MMBTU	30-day rolling
2-B	02	0.212 lb/MMBTU	30-day rolling
2-B	03	0.164 lb/MMBTU	30-day rolling

g.	Boiler operating day shall have the same meaning as in 40 CFR Part 60, Subpart Da.

h.	After installation of the BART, the affected facilities shall only be fired with natural gas.

Within 60 days of achieving maximum power output from each boiler, after modification of the boilers, not to exceed 180 days from initial start-up, the permittee shall conduct performance testing as follows and furnish a written report to Air Quality. Such report shall document compliance with BART emission limits for the affected facilities. [OAC 252:100-8-6(a)]

i.	The permittee shall conduct NOX, CO, and VOC testing on the boilers at 60% and 100% of the maximum capacity. NOX and CO testing shall also be conducted at least one additional intermediate point in the operating range.

ii.

Performance testing shall be conducted while the units are operating within 10% of the desired testing rates. A testing protocol describing how the testing will be performed shall be provided to the AQD for review and approval at least 30 days prior to the start of such testing. The permittee shall also provide notice of the actual test date to AQD.

iii.	The following USEPA methods shall be used for testing of emissions , unless otherwise approved by Air Quality:

Method 1: Sample and Velocity Traverses for Stationary Sources.

Method 2: Determination of Stack Gas Velocity and Volumetric Flow Rate.

Method 3: Gas Analysis for Carbon Dioxide, Excess Air, and Dry Molecular Weight.

EXHIBIT B

Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis		January 15, 2010

COMPANY:	Oklahoma Gas and Electric

FACILITY:	Sooner Generating Station

FACILITY LOCATION:	Red Rock, Noble County, Oklahoma

TYPE OF OPERATION:	(2) 570 MW Steam Electric Generating Units

REVIEWER:	▇▇▇▇▇▇▇ ▇▇▇▇▇▇▇, Senior Engineering Manager
	▇▇▇ ▇▇▇▇▇▇, Engineering Manager

I. PURPOSE OF APPLICATION

II. ▇▇▇▇ ELIGIBILITY DETERMINATION

BART-eligible sources include those sources that:

(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant;

(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and

Sooner Units 1 and 2 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. Both units were in existence prior to August 7, 1977 but not in operation prior to August 7, 1962. Based on a review of existing emissions data, both units have the potential to emit more than 250 tons per year of NOx, SO2 and PM10, visibility impairing pollutants. Therefore, Sooner Units 1 and 2 meet the definition of a BART-eligible source.

▇▇▇▇ is required for any BART-eligible source that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area.

OG&E Sooner Generating Station BART Review January 15, 2010

DEQ has determined that an individual source will be considered to "contribute to visibility impairment" if emissions from the source result in a change in visibility, measured as a change in deciviews (∆-dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling conducted by OO&E determined that the maximum predicted visibility impacts from Sooner Units 1 and 2 exceeded the 0.5 ∆-dv threshold at the Wichita Mountains Class I Area. Therefore, Sooner Units 1 and 2 were determined to be BART applicable sources, subject to the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Sooner Units 1 and 2 3 were developed based on an evaluation of actual emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling analysis to determine visibility impairment impacts should reflect steady-state operating conditions during periods of high capacity utilization. Therefore, modeled emissions (lb/hr) represent the highest 24-hour block emissions reported during the baseline period. Baseline emission rates (lb/mmBtu) were calculated by dividing the average annual mass emission rates for each boiler by the boiler's average heat input over the years 2004 through 2006.

Table 1: Sooner Generating Station – Plant Operating Parameters for BART Evaluation
Parameter	Sooner Unit 1		Sooner Unit 2
Plant Configuration	Pulverized Coal-Fired Boiler		Pulverized Coal-Fired Boiler
Firing Configuration	Tangentially-fired		Tangentially-fired
Gross Output (nominal)	570 MW		570 MW
Maximum Input to Boiler	5,116 mmBtu/hr		5,116 mmBtu/hr
Primary Fuel	Subbituminous coal		Subbituminous coal
Existing NOx Controls	Combustion Controls		Combustion Controls
Existing PM10 Controls	Electrostatic precipitator		Electrostatic precipitator
Existing SO2 Controls	Low-sulfur coal		Low-sulfur coal
Maximum 24-hour Emissions
Pollutant	lb/hr	lb/mmBtu	lb/hr	lb/mmBtu
NOx	3,075	0.601	2,988	0.584
SO2	4,393	0.86	4,410	0.86
PM10	194	0.038	200	0.039
Baseline Emissions (2004-2006)
Pollutant	lb/hr	lb/mmBtu	lb/hr	lb/mmBtu
NOx	1,834	0.384	1,561	0.337
SO2	2,428	0.509	2,393	0.516

IV. BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

OG&E Sooner Generating Station BART Review January 15, 2010

having a total generating capacity in excess of 750 MW. The BART determination process described in Appendix Y includes the following steps:

Step l. Identify All Available Retrofit Control Technologies.

Step 2. Eliminate Technically Infeasible Options.

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.

Step 4. Evaluate Impacts and Document the Results.

Step 5. Evaluate Visibility Impacts.

In the final Regional Haze Rule U.S. EPA established presumptive BART emission limits for S02 and NOx for certain electric generating units (EGUs) based on fuel type, unit size, cost effectiveness, and the presence or absence of pre-existing controls. The presumptive limits apply to EGUs at power plants with a total generating capacity in excess of 750 MW. For these sources, EPA established presumptive emission limits for coal-fired EGUs greater than 200 MW in size. The presumptive levels are intended to reflect highly cost-effective technologies as well as provide enough flexibility to States to consider source specific characteristics when evaluating BART. The BART S02 presumptive emission limit for coal-fired EGUs greater than 200 MW in size without existing S02 control is either 95% S02 removal, or an emission rate of 0.15 lb/mmBtu, unless a State determines that an alternative control level is justified based on a careful consideration of the statutory factors. For NOx, EPA established a set of BART presumptive emission limits for coal-fired EGUs greater than 200 MW in size based upon boiler size and coal type. The BART NOx presumptive emission limit applicable to Sooner Units 1 & 2 (tangentially fired boilers firing subbituminous coal) is 0.15 lb/mmBtu.

Table 2: Proposed BART Controls and Limits
Unit	NOx BART Emission Limit	BART Technology
Sooner Unit 1	0.15 lb/mmBtu (30-day average)	Combustion controls including LNB/OFA
Sooner Unit 2	0.15 lb/mmBtu (30-day average)	Combustion controls including LNB/OFA
Unit	S02 BART Emission Limit	BART Technology
Sooner Unit 1	0.65 lb/mmBtu (30-day average)	Low Sulfur Coal
Sooner Unit 1	0.55 lb/mmBtu (annual average)	Low Sulfur Coal
Sooner Unit 2	0.65 lb/mmBtu (30-day average)	Low Sulfur Coal
Sooner Unit 2	0.55 lb/mmBtu (annual average)	Low Sulfur Coal

Unit 1 and 2	19,736 TPY	Low Sulfur Coal
Unit	PM10 BART Emission Limit	BART Technology
Sooner Unit 1	0.1 lb/mmBtu (3-hour average)	Electrostatic precipitator
Sooner Unit 2	0.1 lb/mmBtu (3-hour average)	Electrostatic precipitator

A. NOx

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Potentially available control options were identified based on a comprehensive review of available information. NOx control technologies with potential application to Sooner Units 1 and 2 are listed in Table 3.

OG&E Sooner Generating Station BART Review January 15, 2010

	Table 3: List of Potential Control Options
	Control Technology
	Combustion Controls
	Low NOx Burners and Overfire Air (LNB/OFA)
	Flue Gas Recirculation (FGR)
	Post Combustion Controls
	Selective Noncatalytic Reduction (SNCR)
	Selective Catalytic Reduction (SCR)
	Innovative Control Technologies
	Rotating Overfire Air (ROFA)
	ROFA + SNCR (Rotamix)
	▇▇▇▇▇▇▇ Multi-Pollutant Control Process
	Wet NOx Scrubbing

ELIMINATE TECHNICALLY INFEASIBLE OPTIONS (NOx)

Combustion Controls:

Low NOx burners (LNB)/ OverFire Air (OFA)

LNB/OFA emission control systems have been installed as retrofit control technologies on existing coal-fired boilers. Sooner units 1 and 2 operate as base load units. While technically feasible, LNB/OFA may not be as effective under all boiler operating conditions, especially during load changes and at low operating loads. Based on information available from burner control vendors and engineering judgment, it is expected that LNB/OFA on the tangentially-fired boilers can be designed to meet the presumptive NOx BART emission rate of 0.15 lb/mmBtu on a 30-day rolling average and under all normal operating conditions while maintaining acceptable CO and VOC emission rates.

Flue Gas Recirculation

FOR control systems have been used as a retrofit NOx control strategy on natural gas-fired boilers, but have not generally been considered as a retrofit control technology on coal-fired units. Natural gas-fired units tend to have lower O2 concentrations in the flue gas and low particulate loading. In a coal-fired application, the FGR system would have to handle hot particulate-laden flue gas with a relatively high 02 concentration. Although FGR has been used on coal-fired boilers for flue gas temperature control, it would not have application on a coal-fired boiler for NOx control. Because of the flue gas characteristics (e.g., particulate loading and 02 concentration), FGR would not operate effectively as a NOx control system on a coal-fired

OG&E Sooner Generating Station BART Review January 15, 2010

boiler. Therefore, FGR is not considered an applicable retrofit NOx control option for Sooner Units 1 & 2, and will not be considered further in the BART determination.

Post Combustion Controls:

Selective Non-Catalytic Reduction

Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia or urea at high flue gas temperatures. The ammonia or urea reacts with NOx in the flue gas to produce N2 and water. At temperatures below the desired operating range, the NOx reduction reactions diminish and NH3 emissions increase. Above the desired temperature range, NH3 is oxidized to NOx resulting in low NOx reduction efficiencies. Mixing of the reactant and flue gas within the reaction zone is also an important factor in SNCR performance. In large boilers, the physical distance over which the reagent must be dispersed increases, and the surface area/volume ratio of the convective pass decreases. Both of these factors make it difficult to achieve good mixing of reagent and flue gas, reducing overall efficiency. Performance is further influenced by residence time, reagent-to-NOx ratio, and fuel sulfur content.

The size of the Sooner Units would represent several design problems making it difficult to ensure that the reagent would be injected at the optimum flue gas temperature, and that there would be adequate mixing and residence time. The physical size of the Sooner boilers makes it technically infeasible to locate and install ammonia injection points capable of achieving adequate mixing within the required temperature zone. Higher reagent injection rates would be required to achieve adequate mixing. Higher ammonia injection rates would result in relatively high levels of ammonia in the flue gas (ammonia slip), which could lead to plugging of downstream equipment.

Another design factor limiting the applicability of SNCR control systems on large subbituminous coal-fired boilers is related to the reflective nature of subbituminous ash. Subbituminous coals typically contain high levels of calcium oxide and magnesium oxide that can result in reflective ash deposits on the waterwall surfaces. Because most heat transfer in the furnace is radiant, reflective ash can result in less heat removal from the furnace and higher exit gas temperatures. If ammonia is injected above the appropriate temperature window, it can actually lead to additional NOx formation.

Installation of SNCR on large boilers, such as those at Sooner, has not been demonstrated in practice. Assuming that SNCR could be installed on the Sooner Units, given the issues addressed above, control effectiveness would be marginal, and depending on boiler exit temperatures, could actually result in additional NOx formation. SNCR is not a technically feasible retrofit control for the Sooner Boilers.

Selective Catalytic Reduction

OG&E Sooner Generating Station BART Review January 15, 2010

to 0.1 lb/mmBtu. Several design and operating variables will influence the performance of the SCR system, including the volume, age and surface area of the catalyst (e.g., catalyst layers), uncontrolled NOx emission rate, flue gas temperature and catalyst activity.

Based on emission rates achieved in practice at existing coal-fired units, and taking into consideration long-term operation of an SCR control system (including catalyst plugging and deactivation), it is anticipated that SCR could achieve a controlled NOx emission rate of 0.07 lb/mmBtu (30-day rolling average) on Sooner Units 1 and 2.

Innovative NOX Control Technologies:

Rotating Opposed Fire Air and Rotamix

Rotating opposed fired air (ROFA) is a boosted over fire air system that includes a patented rotation process which includes asymmetrically placed air nozzles. Like other OFA systems, ROFA stages the primary combustion zone to bum overall rich, with excess air added higher in the furnace to burn out products of incomplete combustion.

ROFA and Rotamix® systems have been demonstrated on smaller coal-fired boilers but have not been demonstrated in practice on boilers similar in size to Sooner Units 1 & 2. As discussed for OFA, over fire air control systems are a technically feasible retrofit control technology, and, based on engineering judgment, the ROFA design could also be applied on Sooner Units 1 and 2. However, there is no technical basis to conclude that the ROFA design would provide additional NOX reduction beyond that achieved with other OFA designs. Therefore, ROFA control systems are not evaluated as a specific control system, but are included in the overall evaluation of combustion controls (e.g., LNB/OFA).

ROFA+ SNCR (Rotamix)

▇▇▇▇▇▇▇ Multi-Pollutant Control Process

OG&E Sooner Generating Station BART Review January 15, 2010

Units 1 and 2. ▇▇▇▇ does not require applicants to experience extended time delays or resource penalties to allow research to be conducted on an emerging control technique. Therefore, at this time the ▇▇▇▇▇▇▇ Process is not a technically feasible retrofit control for the Sooner Boilers.

Wet NOx Scrubbing Systems

Wet scrubbing systems have been used to remove NOx emissions from fluid catalytic cracking units (FCCUs) at petroleum refineries. An example of a wet scrubbing system is Balco Technologies' LoTOxTM system. The LoTOx system is a patented process, wherein ozone is injected into the flue gas stream to oxidize NO and NO2 to N205. This highly oxidized species of NOx is very soluble and rapidly reacts with water to form nitric acid. The conversion of NOx to nitric acid occurs as the N205 contacts liquid sprays in the scrubber.

Wet scrubbing systems have been installed at chemical processing plants and smaller coal-fired boilers. The NEET Database classifies wet scrubbing systems as commercially established for petroleum refining and oil/natural gas production. However the technology has not been demonstrated on large utility boilers and it is likely that OG&E would incur substantial engineering and testing to evaluate the scale-up potential and long-term effectiveness of the system. Therefore, at this time wet NOx scrubbing systems are not technically feasible retrofit controls for the Sooner Boilers.

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NOx)

Table 4: Technically Feasible NOx Control Technologies – Sooner Station
	Sooner Unit 1	Sooner Unit 2
Control Technology	Approximate NOx Emission Rate (lb/mmBtu)	Approximate NOx Emission Rate (lb/mmBtu)
LNB/OFA + SCR	0.07	0.07
LNB/OFA	0.15	0.15
Baseline	0.384	0.337

EVALUATE IMPACTS AND DOCUMENT RESULTS (NOx)

OG&E evaluated the economic, environmental, and energy impacts associated with the three proposed control options. In general, the cost estimating methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. Major equipment costs were developed based on publicly available cost data and equipment costs recently developed for similar projects, and include the equipment, material, labor, and all other direct costs needed to retrofit Sooner Units 1 and 2 with the control technologies. Fixed and variable O&M costs were developed for each control system. Fixed O&M costs include operating labor, maintenance labor, maintenance material, and administrative labor. Variable O&M costs include the cost of consumables, including reagent (e.g., ammonia), byproduct management, water consumption, and auxiliary power requirements. Auxiliary power requirements reflect the additional power requirements associated with operation of the new control technology, including operation of any new fans as well as the power requirements for pumps, reagent handling, and by-product handling. The capital recovery factor used to estimate the annual cost of control was based on a

OG&E Sooner Generating Station BART Review January 15, 2010

7% interest rate and a control life of 25 years. Annual operating costs and annual emission reductions were calculated assuming a capacity factor of 90%.

OG&E submitted initial cost estimates in 2008 that relied upon a baseline emission rate representative of the maximum actual 24-hour emission rate, which is consistent with the modeling demonstration. However, the calculations overestimate the cost effectiveness by assuming a larger ton per year emissions reduction with the addition of controls than would be realized given actual annual average emissions. Using a representative annual average emission rate (2004-2006), the cost effectiveness ($/ton removed) is much higher, but the result is representative of more reasonably achievable emissions reductions.

Table 5: Economic Cost Per Boiler
Cost	Unit	Option 1: LNB/OFA	Option 2: LNB/OFA + SCR
Control Equipment Capital Cost ($)	Unit 1	$14,055,900	$192,018,500
Annualized Capital Cost ($/Yr)	Unit 1	$1,206,100	$16,477,200
Annual O&M Costs ($/Yr)	Unit 1	$877,100	$14,487,400
Annual Cost of Control ($)	Unit 1	$2,083,200	$30.964,600

Table 6: Environmental Costs per Boiler
		Baseline	Option 1: LNB/OFA	Option 2: LNB/OFA + SCR
NOx Emission Rate (lb/mmBtu)	Unit 1	0.384	0.15	0.07
	Unit 2	0.337	0.15	0.07
Annual NOx Emission (TPY)1	Unit 1	7,266	3,025	1,412
	Unit 2	5,689	3,025	1,412
Annual NOx Reduction (TPY)	Unit 1	-	4,241	5,854
	Unit 2	-	2,664	4,277
Annual Cost of Control	Unit 1	-	$2,091,800	$30,795,600
	Unit 2	-	$2,091,800	$30,795,600
Cost per ton of Reduction	Unit 1	-	$493	$5,260
	Unit 2	-	$785	$7,200
Incremental Cost per Ton of Reduction2	Unit 1	-	-	$17,795
	Unit 2	-	-	$17,795

(1)Emissions for the BART analysis are based on maximum heat inputs of 4,771 mmBtu/hr and 4,634 mmBtu/hr for Units 1 & 2. Annual emissions were calculated assuming 7,738 and 7,164 hours/year for Units 1 and 2 respectively.

(2) Incremental cost effectiveness of the SCR system is compared to costs/emissions associated with LNB/OFA controls.

B. SO2

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES (S02)

Potentially available control options were identified based on a comprehensive review of available information. S02 control technologies with potential application to Sooner Units 1 and 2 are listed in Table 7.

OG&E Sooner Generating Station BART Review January 15, 2010

Table 7: List of Potential Control Options

Control Technology

Pre-Combustion Controls

Fuel Switching

Coal Washing

Coal Processing

Post Combustion Controls

Wet Flue Gas Desulfurization

Wet Lime FGD

Wet Limestone FGD

Wet Magnesium Enhanced Lime FGD

Jet Bubbling Reactor FGD

Dual Alkali Scrubber

Wet FGD with Wet Electrostatic Precipitator

Dry Flue Gas Desulfurization

Spray Dryer Absorber

Dry Sorbent Injection

Circulating Dry Scrubber

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (SO2)

Pre-Combustion Control Strategy:

Fuel Switching

One potential strategy for reducing S02 emissions is reducing the amount of sulfur contained in the coal. Sooner Units 1 & 2 fire subbituminous coal as their primary fuel. Subbituminous coal has a relatively low heating value, low sulfur content, and low uncontrolled S02 emission rate. No environmental benefits accrue from burning an alternative coal; therefore, fuel switching is not considered a feasible option for this retrofit project.

Coal Washing

Coal washing, or beneficiation, is one pre-combustion method that has been used to reduce impurities in the coal such as ash and sulfur. In general, coal washing is accomplished by separating and removing inorganic impurities from organic coal particles. The coal washing process generates a solid waste stream consisting of inorganic materials separated from the coal, and a wastewater stream that must be treated prior to discharge. Solids generated from wastewater processing and coarse material removed in the washing process must be disposed in a properly permitted landfill. Solid wastes from coal washing typically contain pyrites and other dense inorganic impurities including silica and trace metals. The solids are typically dewatered in a mechanical dewatering device and disposed of in a landfill.

Sooner Units 1 & 2 are designed to utilize subbituminous coals. Based on a review of available information, no information was identified regarding the washability or effectiveness of washing subbituminous coals. Therefore, coal washing is not considered an available retrofit control option for Sooner Units 1 & 2.

OG&E Sooner Generating Station BART Review January 15, 2010

Coal Processing

Pre-combustion coal processing techniques have been proposed as one strategy to reduce the sulfur content of coal and help reduce uncontrolled S02 emissions. Coal processing technologies are being developed to remove potential contaminants from the coal prior to use. These processes typically employ both mechanical and thermal means to increase the quality of subbituminous coal and lignite by removing moisture, sulfur, mercury, and heavy metals. To date, the use of processed fuels has only been demonstrated with test bums in a pulverized coal-fired boiler. No coal-fired boilers have utilized processed fuels as their primary fuel source on an on-going, long-term basis. Although burning processed fuels, or a blend of processed fuels, has been tested in a pulverized coal-fired boiler, using processed fuels in Sooner Units 1 & 2 would require significant research, test bums, and extended trials to identify potential impacts on plant systems, including the boiler, material handling, and emission control systems. Therefore, processed fuels are not considered commercially available, and will not be analyzed further in this BART analysis.

Post-Combustion Flue Gas Desulfurization

Wet Scrubbing Systems

Wet FGD technology is an established S02 control technology. Wet scrubbing systems offered by vendors may vary in design; however, all wet scrubbing systems utilize an alkaline scrubber slurry to remove S02 from the flue gas.

Wet Lime Scrubbing

The wet lime scrubbing process uses an alkaline slurry made by adding lime (CaO) to water. The alkaline slurry is sprayed in the absorber and reacts with S02 in the flue gas. Insoluble CaS03 and CaS04 salts are fanned in the chemical reaction that occurs in the scrubber and are removed as a solid waste by-product. The waste by-product is made up of mainly CaS03, which is difficult to ▇▇▇▇▇▇▇. Solid waste by-products from wet lime scrubbing are typically managed in dewatering ponds and landfills.

Wet Limestone Scrubbing

Limestone scrubbers are very similar to lime scrubbers except limestone (CaCO3) is mixed with water to formulate the alkali scrubber slurry. S02 in the flue gas reacts with the limestone slurry to form insoluble CaS03 and CaS04 which is removed as a solid waste by product. The use of limestone instead of lime requires different feed preparation equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas ratio typically requires a larger absorbing unit. The limestone slurry process also requires a ball mill to crush the limestone feed.

Forced oxidation of the scrubber slurry can be used with either the lime or limestone wet FGD system to produce gypsum solids instead of the calcium sulfite by-product. Air blown into the reaction tank provides oxygen to convert most of the calcium sulfite (CaS03) to relatively pure gypsum (calcium sulfate). Forced oxidation of the scrubber slurry provides a more stable by-product and reduces the potential for scaling in the FGD. The gypsum by-product from this process must be dewatered, but may be salable thus reducing the quantity of solid waste that needs to be landfilled.

OG&E Sooner Generating Station BART Review January 15, 2010

Wet lime and wet limestone scrubbing systems will achieve the same S02 control efficiencies; however, the higher cost of lime typically makes wet limestone scrubbing the more attractive option. For this reason, wet lime scrubbing will not be evaluated further in this BART determination.

Wet Magnesium Enhanced Lime Scrubbing

Magnesium Enhanced Lime (▇▇▇) scrubbers are another variation of wet FGD technology. Magnesium enhanced lime typically contains 3% to 7% magnesium oxide (MgO) and 90 -95% calcium oxide (CaO). The presence of magnesium effectively increases the dissolved alkalinity, and consequently makes S02 removal less dependent on the dissolution of the lime/limestone. ▇▇▇ scrubbers have been installed on coal-fired utility boilers located in the Ohio River Valley. Systems to oxidize the ▇▇▇ solids to produce a usable gypsum byproduct consisting of calcium sulfate (gypsum) and magnesium sulfate continue to be developed. Coal-fired units equipped with ▇▇▇ FGD typically fire high-sulfur eastern bituminous coal and use locally available reagent. There are no subbituminous-fired units equipped with a ▇▇▇-FGD system. Because ▇▇▇-FGD systems have not been used on subbituminous-fired boilers, and because of the cost and limited availability of magnesium enhanced reagent (either naturally occurring or blended), and because limestone-based wet FGD control systems can be designed to achieve the same control efficiencies as the magnesium enhanced systems, ▇▇▇-FGD control systems will not be evaluated further as a commercially available retrofitted control system.

Jet Bubbling Reactor

Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike the spray tower wet FGD systems, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower, in the JBR-FGD flue gas is bubbled through a limestone slurry. Spargers are used to create turbulence within the reaction tank and maximize contact between the flue gas bubbles and scrubbing slurry. There is currently a limited number of commercially operating JBR-WFGD control systems installed on coal-fired utility units in the U.S. Although the commercial deployment of the control system continues. there is still a very limited number of operating units in the U.S. Furthermore, coal-fired boilers currently considering the JBR-WFGD control system are all located in the eastern U.S., and all fire eastern bituminous coals. The control system has not been proposed as a retrofit technology on any large subbituminous coal-fired boilers. However, other than scale-up issues, there do not appear to be any overriding technical issues that would exclude application of the control technology on a large subbituminous coal-fired unit. There are no data available to conclude that the JBR-WFGD control system will achieve a higher S02 removal efficiency than a more traditional spray tower WFGD design, especially on units firing low-sulfur subbituminous coal. Furthermore, the costs associated with JBR-WFGD and the control efficiencies achievable with JBR-WFGD are similar to the costs and control efficiencies achievable with spray tower WFGD control systems. Therefore, the JBR-WFGD will not be evaluated as a unique retrofit technology, but will be included in the overall assessment of WFGD controls.

Dual-Alkali Wet Scrubber

OG&E Sooner Generating Station BART Review January 15, 2010

lime or limestone. The reduced liquid-to-gas ratios generally mean smaller reaction units, however additional regeneration and sludge processing equipment is necessary. The sodium-based scrubbing liquor, typically consisting of a mixture of sodium hydroxide, sodium carbonate and sodium sulfite, is an efficient S02 control reagent. However, the high cost of the sodium-based chemicals limits the feasibility of such a unit on a large utility boiler. In addition, the process generates a less stable sludge that can create material handling and disposal problems. It is projected that a dual-alkali system could be designed to achieve S02 control similar to a limestone-based wet FGD. However, because of the limitations discussed above, and because dual-alkali systems are not currently commercially available, dual-alkali scrubbing systems will not be addressed further in this BART determination.

Wet FGD with Wet Electrostatic Precipitator

Wet electrostatic precipitation (▇▇▇▇) has been proposed on other coal-fired projects as one technology to reduce sulfuric acid mist emissions from coal-fired boilers. WESPs have been proposed for boilers firing high-sulfur eastern bituminous coals controlled with wet FGD. ▇▇▇▇ has not been widely used in utility applications, and has only been proposed on boilers firing high sulfur coals and equipped with SCR. Sooner Units 1 & 2 fire low-sulfur subbituminous coal. Based on the fuel characteristics, and assuming 1% S02 to S03 conversion in the boiler, potential uncontrolled H2S04 emissions from Sooner Units 1 & 2 will only be approximately 5ppm. This emission rate does not take into account inherent acid gas removal associated with alkalinity in the subbituminous coal fly ash. Based on engineering judgment, it is unlikely that a ▇▇▇▇ control system would be needed to mitigate visible sulfuric acid mist emissions from Sooner Units 1 & 2, even if WFGD control was installed. WESPs have been proposed to control condensable particulate emissions from boilers firing a high-sulfur bituminous coal and equipped with SCR and wet FGD. The combination of coal and control equipment results in relatively high concentrations of sulfuric acid mist in the flue gas. ▇▇▇▇ control systems have not been proposed on units firing subbituminous coals, and ▇▇▇▇ would have no practical application on a subbituminous-fired units. Therefore, the combination of WFGD+▇▇▇▇ will not be evaluated further in this BART determination.

Dry Flue Gas Desulfurization

Another scrubbing system that has been designed to remove S02 from coal-fired combustion gases is dry scrubbing. Dry scrubbing involves the introduction of dry or hydrated lime slurry into a reaction tower where it reacts with SO2 in the flue gas to form calcium sulfite solids. Unlike wet FGD systems that produce a slurry byproduct that is collected separately from the fly ash, dry FGD systems produce a dry byproduct that must be removed with the fly ash in the particulate control equipment. Therefore, dry FGD systems must be located upstream of the particulate control device to remove the reaction products and excess reactant material.

Spray Dryer Absorber

Spray dryer absorber (SDA) systems have been used in large coal-fired utility applications. SDA systems have demonstrated the ability to effectively reduce uncontrolled S02 emissions from pulverized coal units. The typical spray dryer absorber uses a slurry of lime and water injected into the tower to remove S02 from the combustion gases. The towers must be designed to provide adequate contact and residence time between the exhaust gas and the slurry to produce a relatively dry by-product. SDA control systems are a technically feasible and commercially

OG&E Sooner Generating Station BART Review January 15, 2010

available retrofit technology for Sooner Units 1 & 2. Based on the fuel characteristics and allowing a reasonable margin to account for normal operating conditions (e.g., load changes, changes in fuel characteristics, reactant purity, atomizer change outs, and minor equipment upsets) it is concluded that dry FGD designed as SDA could achieve a controlled S02 emission rate of 0.10 lb/mmBtu (30-day average) on an on-going long-term basis.

Dry Sorbent Injection

Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas exhaust stream. Particulates generated in the reaction are controlled in the system's particulate control device. Typical S02 control efficiencies for a dry sorbent injection system are generally around 50%. OG&E stated that because the control efficiency of the dry sorbent system is lower than the control efficiency of either the wet FGD or SDA, the system will not be evaluated further. As OG&E proposed only the use of low sulfur coal as BART, it is not clear why they did not include this technology in the full evaluation. Lacking any data to justify why this might be a more cost effective option than Dry FGD with SDA, this option is set aside based solely on lower environmental benefit.

Circulating Dry Scrubber

A third type of dry scrubbing system is the circulating dry scrubber (CDS). A CDS system uses a circulating fluidized bed of dry hydrated lime reagent to remove S02. The dry by-product produced by this system is similar to the spray dry absorber by-product, and is routed with the flue gas to the particulate removal system. Operating experience on smaller pulverized coal boilers in the U.S. has shown high lime consumption rates, and significant fluctuations in lime utilization based on inlet S02 loading. Furthermore, CDS systems result in high particulate loading to the unit's particulate control device. Based on the limited application of CDS dry scrubbing systems on large boilers, it is likely that OG&E would be required to conduct extensive design engineering to scale up the technology for boilers the size of Sooner Units 1 & 2, and that OG&E would incur significant time and resource penalties evaluating the technical feasibility and long-term effectiveness of the control system. Because of these limitations, CDS dry scrubbing systems are not currently commercially available as a retrofit control technology for Sooner Units 1 & 2, and will not be evaluated further in this BART determination.

EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (S02)

Table 8: Technically Feasible S02, Control Technologies – Sooner Station
Control Technology	Sooner Unit 1	Sooner Unit 2
Control Technology	Approximate S02 Emission Rate (lb/mmBtu)	Approximate S02 Emission Rate (lb/mmBtu)
Wet FGD	0.08	0.08
Dry FGD – Spray Dryer Absorber	0.10	0.10
Baseline	0.86	0.86
Annual Average Baseline	0.509	0.516

OG&E Sooner Generating Station BART Review January 15, 2010

EVALUATE IMPACTS AND DOCUMENT RESULTS (SO2)

Capital Costs

In 2008 OG&E evaluated the economic, environmental, and energy impacts associated with the two proposed control options. In general, the cost estimating methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. Sixth Edition" EPA-452/B-02-001, January 2002. The cost-effectiveness evaluations were "study" estimates of ±30% accuracy, based on: (I) engineering estimates; (2) vendor quotations provided for similar projects and similar equipment; (2) S&L's internal cost database; and (4) cost estimating guidelines provided in U.S.EPA's, EPA Air Pollution Control Cost Manual. Cost estimates include the equipment. material, labor, and all other direct costs needed to retrofit Sooner Units 1 and 2 with the control technologies.

While generally following the EPA methodology, these cost estimates exploited weaknesses in the estimate assumptions and resulted in highly exaggerated capital and particularly annual costs. In response to the ODEQ draft evaluation and EPA and FLM comments, OG&E submitted revised cost estimates during the public meeting held for the Oklahoma draft SIP. These revised estimates reflect vendor quotes for the Sooner facility. In degree of difficulty, the retrofit at the Sooner facility is described as average. The re-routing of ductwork, storm sewer systems and other equipment relocations were taken into consideration in the conceptual cost estimate.

The new cost estimates use the following methodology:

•

Plant design data were used to develop datasheets to specify the dry FGD, baghouse, and ID booster fan operating conditions. The datasheets were issued to various manufacturers to obtain budgetary quotations. Cost obtained from these quotations were used to derive the pricing used in the capital cost estimate.

•	A general arrangement (GA) drawing was developed using the information received in the budgetary quotations. The GA drawing was used to estimate the major installation quantities for the project including ductwork, structural steel, foundations, relocation cable, and pipelines.

•	A motor list was assembled and used to develop the auxiliary power system sizing and quantities.

•	Mass balances were prepared and used to size the flue gas, material handling, material storage, and piping systems.

•	A schedule was developed to estimate escalation and Allowance for Funds Used During Construction (AFUDC) costs. It was assumed the new DFGDs would come on line at six month intervals with the last unit being completed at Sooner near the end of 2015.

•	Range estimating techniques were used to identify the appropriate amount of contingency to obtain 95% confidence level. The contingency level was approximately 14%.

•	A design and cost basis document was prepared to document the major assumptions and inputs for developing the cost estimate.

•	Labor cost estimates were developed using the Oklahoma area wage rates, installation quantities, and installation rates taken from the ▇▇▇▇▇▇▇ and ▇▇▇▇▇ database.

OG&E Sooner Generating Station BART Review January 15, 2010

The described methodology provides a conceptual capital cost estimate with accuracy in the range of ±20%. This methodology provides a better estimate of the capital costs associated with installing DFGD control systems, and a more accurate estimate of the actual costs that OG&E would incur to install DFGD at the Sooner facility.

The total capital requirement (TCR) is the sum of direct costs, indirect costs, contingency, escalation, and AFUDC. Direct costs include equipment, material, labor, spare parts, special tools, consumables, and freight. Indirect costs include engineering, procurement, construction management, start-up, commissioning. operator training, and owner's costs.

Escalation and AFUDC were calculated from the estimated distribution of cash flows during the construction period and OG&E's before-tax weighted average cost of capital of 8.66%/year. The 37-day tie-in outage for each unit is assumed to be coordinated with the normal 5-week scheduled outage such that incremental replacement cost is negligible.

The capital recovery factor converts the TCR into equal annual costs over the depreciable life of the asset. These are also referred to as levelized capital charges. Property taxes and insurance are sometimes included with the capital charges, but are classified in the OG&E analysis as part of the Indirect Operating Costs to be consistent with the BART reports. The economic parameters used to derive the levelized capital charges are summarized in Table 9.

Table 9: Economic Parameters to Derive Levelized Capital Charges
Commercial Operation Date (Reference Year)	2014
Depreciable Life	20 years
Inflation Rate	2.5%/year
Effective Income Tax Rate-Federal and State	38.12%
Common Equity Fraction	0.557
Debt Fraction	0.443
Return on Common Equity
Nominal	10.75%/year
Real	8.05%/year
Return on Debt
Nominal	6.03%/year
Real	3.44%/year
Discount Rate (after-tax cost of capital)
Nominal	7.64%/year
Real	5.43%/year
Tax Depreciation	20-year straight line
Levelized Capital Charges (real)	10.36%/year

The revised estimates based on vendor quotes results in a TCR of $584,589,400 which is $196,222,600 less than the CUE Cost derived estimates provided in 2008. OG&E has revised the capital recovery factor and reduced the number of years of expected depreciation to 20 from 25 resulting in a levelized capital charge or capital recovery of 30,281,800 per boiler, which is $3,219,100 per boiler per year less than the 2008 estimate. Cost estimates and assumptions are

OG&E Sooner Generating Station BART Review January 15, 2010

reasonable and application of the previously relied upon capital recovery factor does not significantly change the cost per ton of control or the conclusion of this review.

Operating Costs

Annual operating costs for the DFGD system consist of variable operating and maintenance (O&M) costs, fixed O&M costs, and indirect operating costs.

Variable O&M

Variable O&M costs are items that generally vary in proportion to the plant capacity factor. These consist of lime reagent costs, water costs, FGD waste disposal costs, bag and cage replacement costs, ash disposal costs, and auxiliary power costs.

Lime Reagent costs were based on material balances and budgetary lime quotations received for truck delivery, $118.80/ton, which is 59% of the previously assumed cost. Water costs were based on 205,256 lb/hr at full load, a 90% capacity factor and $0.49/1,000 gallons. FGD Waste Disposal was based on material balances for the average fuel composition and a 90% capacity factor. First year cost of on-site disposal is $39.60/ton. Bag and cage replacement costs were based on exhaust gas flow through the baghouse, an air-to-cloth ratio of 3.5 for pulse jet baghouse, 4% contingency for bag cleaning, and 3-year bag life. The first year bag cost (including fabric and hangers) is $3.22/ft2. Ash disposal costs were not assumed to increase from the fabric filter as existing ESP is remaining in service. Auxiliary power costs were based on auxiliary power calculations and a 90% capacity factor. The first year auxiliary power cost is $83.83/MWh, which is 186% of the previously assumed power cost.

Increases in FGD waste disposal, bag and cage replacement, and auxiliary power costs offset decreases in water and lime reagent costs resulting in no appreciable change in expected variable O&M costs from the 2008 estimate.

Fixed O&M

Fixed O&M costs are recurring annual costs that are generally independent of the plant capacity factor. Theses consist of operating labor, supervisor labor, maintenance materials, and maintenance labor.

Operating labor was based on three shifts per day 365 days per year. The first year labor rate (salary plus benefits) is 57.33/hour. Supervisory labor was based on 15% of operating labor in accordance with the EPA Control Cost Manual (page 2-31). Maintenance materials were based on 0.6% of the total plant investment. Previous cost estimates reflecting Cue Cost default assumptions were based on 5% of capital equipment costs and therefore contributed to the exaggeration of annual operating costs. Maintenance labor was again based on 110% of operating labor, which is consistent with the EPA Control Cost Manual (page 2-31).

Due to the difference in cost basis for maintenance materials, the final fixed O&M costs were decreased by approximately $11,456,200 per year per boiler.

OG&E Sooner Generating Station BART Review January 15, 2010

Indirect Operating Costs

Indirect operating costs are recurring annual costs for the FGD system that are not part of the direct O&M. These consist of property taxes, insurance, and administration.

Property taxes were calculated as 0.60% of total capital investment, in accordance with OO&E property tax rates. This rate is significantly lower than the EPA default rate of 1%. Insurance rates were calculated as 0.0105% of total capital investment in accordance with OG&E insurance rates. This rate is significantly lower than the EPA default rate of 1%. Administrative costs were calculated as 20% of the fixed O&M costs rather the EPA Air Pollution Control Cost Manual 6th Ed guidance of 2% of capital investment.

Due to the difference in cost basis for all indirect costs, but most particularly administrative costs, the final indirect operating costs were decreased by approximately $12,636,500 per year per boiler from the previous assessment.

Revised O&M estimates are now consistent with the operating costs documented in the June 2007 report by ▇. ▇▇▇▇▇▇ ▇▇▇▇▇▇▇▇▇▇▇ for the Utility Air Regulatory Group, "Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control Technologies. The ▇▇▇▇▇▇▇▇▇▇▇ report lists a cost range in $/kW of 15 to 38 for O&M costs. OG&E estimates are approximately $29-32/kW.

OG&E submitted initial cost estimates in 2008 that relied upon a baseline emission rate representative of the maximum actual 24-hour emission rate, which is consistent with the modeling demonstration. Following the methodology published in the EPA advanced notice of proposed rulemaking for the Four Corners Power Plant and the Navajo Generating Station, cost effectiveness calculations were revised to reflect average annual emissions from 2004-2006.

Table 10: Economic Cost for Units 1 and 2 – Dry FGD – Spray Dryer Absorber
Cost	Unit 1	Unit 2
Total Capital Investment ($)	$292,294,900	$292,294,900
Total Capital Investment ($/kW)	$514	$514
Capital Recovery Cost ($/Yr)	$30,281,800	$30,281,800
Annual O&M Costs ($/Yr)	$16,550,500	$16,550,500
Total Annual Cost ($)	$46,832,300	$46,832,300

Table 11: Environmental Costs for Units 1 and 2 – Dry FGD – Spray Dryer Absorber
Cost	Unit 1	Unit 2
SO2 Baseline (TPY)1	9,394	8,570
SO2 Controlled (lb/mmBtu)	0.1	0.1
Annual SO2 Controlled (TPY)2	2,017	2,017
Annual SO2 Reduction (TPY)	7,377	6,553
Total Annual Cost ($)	$46,832,300	$46,832,300
Cost per Ton of Reduction	$6,348	$7,147

1Baseline annual emissions are calculated as the average actual S02 emission rate during the baseline years of 2004-2006.

OG&E Sooner Generating Station BART Review January 15, 2010

2Projected annual emissions were calculated based on the controlled SO2 emissions rate, full load heat input of 5,116 mmBtu/hr, and assuming 7,884 hours/year per boiler (90% capacity factor).

OG&E did not submit revised cost estimates for Wet FGD; however, in order to be thorough, some conclusions can be drawn from the estimates provided for Dry FGD. The total capital requirement for wet scrubbers was assumed to be consistent with the previous determination. The capital recovery factor was modified to reflect the current company position of a 20 year depreciation. The annual operating costs were modified to reflect the cost bases for water, labor, auxiliary power, taxes, insurance and administrative costs detailed in the preceding paragraphs.

Table 12: Environmental Costs for Unit 2 – Wet FGD
Cost	OG&E Cost Estimates
Cost	Unit 1	Unit 2
Total Capital Investment ($)	$441,658,000	$441,658,000
Total Capital Investment ($/kW)	$775	$775
Capital Recovery Cost ($/Yr)	$37,898,900	$37,898,900
Annual O&M Costs ($/Yr)	$16,550,500	$16,550,500
Total Annual Cost ($)	$54,449,400	$54,449,400
Control SO2 Emission Rate (lb/mmBtu)	0.08	0.08
Baseline Annual Emissions (TPY)1	9,394	8,570
Controlled Annual SO2 Emission (TPY)2	1,613	1,613
Annual SO2 Reduction (TPY)	7,781	6,957
Cost per Ton of Reduction ($/Ton)	$6,998	$7,827
Incremental Annual Cost ($/Ton)	$18,854	$18,854

1Baseline annual emissions were calculated based on average annual S02 emissions for the years 2004-2006.

2Projected annual emissions were calculated based on the controlled SO2 emissions rate, full load heat input of 5,116 mmBtu/hr, and assuming 7,884 hours/year per boiler (90% capacity factor).

C. PM10

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES (PM10)

There are two generally recognized PM control devices that are used to control PM emission from PC boilers: ESPs and fabric filters (or baghouses). Sooner Units 1 & 2 are currently equipped with ESP control systems.

OG&E Sooner Generating Station BART Review January 15, 2010

Table 12: Summary of Technically Feasible Main Boiler PM10 Control Technologies
Control Technology	PM10 Emissions1 (lb/mmBtu)	% Reduction (from base case)
Fabric Filter Baghouse	0.015	99.7
ESP - Existing	0.039	99.3
Potential PM Emissions	5.65	-

1The PM10 emission rate for the baghouse case is based on filterable PM10 emission limits included in recently issued PSD permits for new coal-fired units. The PM10 emission rate for the ESP case is based on the Units' baseline PM10 emission rates. Potential PM emissions were calculated assuming an average fuel heating value of 8,500 Btu/lb and an ash content of 6.0%, and assuming 80% of the fuel ash will be emitted as fly ash.

EVALUATE IMPACTS AND DOCUMENT RESULTS (PM10)

Costs for Fabric Filter Baghouses were included in the cost estimates provided by OG&E for Dry FGD. Because of the interdependency of the control systems, a determination of baghouse versus existing ESP cannot be made without consideration of the eventual sulfur control. Annual average PM emissions are less than 500 TPY for both boilers. On a PM basis alone and assuming the current 20 year depreciation, no additional operating costs, and 100% emission reduction, a resultant cost effectiveness of $9,324 per ton would support the conclusion that further reductions from the addition of a $45,000,000 fabric filter are not cost effective.

D. VISIBILITY IMPROVEMENT DETERMINATION

The fifth of five factors that must be considered for a BART determination analysis, as required by a 40 CFR part 51-Appendix Y, is the degree of Class I area visibility improvement that would result from the installation of the various options for control technology. This factor was evaluated for the Sooner Generating Station by using an EPA-approved dispersion modeling system (CALPUFF) to predict the change in Class I area visibility. The Division had previously determined that the Sooner Generating Station was subject to BART based on the results of initial screening modeling that was conducted using current (baseline) emissions from the facility. The screening modeling, as well as more refined modeling conducted by the applicant. is described in detail below.

Wichita Mountain Wildlife Refuge, Caney Creek, Upper Buffalo and Hercules Glade are the closest Class I areas to the Sooner Generating Station, as shown in Figure 1 below.

Only those Class I areas most likely to be impacted by the Sooner Generating Station were modeled, as determined by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. It can be reasonably assumed that areas at greater distances and in directions of less frequent plume transport win experience lower impacts than those predicted for the four modeled areas.

OG&E Sooner Generating Station BART Review January 15, 2010

IMAGE NOT SHOWN

Figure 1: Plot of Facility location in relation to nearest Class I areas

REFINED MODELING

Because of the results of the applicants screening modeling for the Sooner Generating Station, OG&E was required to conduct a refined BART analysis that included CALPUFF visibility modeling for the facility. The modeling approach followed the requirements described in the Division's BART modeling protocol, CENRAP BART Modeling Guidelines (Alpine Geophysics, December 2005) with refinements detailed the applicants CALMET modeling protocol, CALMET Data Processing Protocol (Trinity Consultants, January 2008)

CALPUFF System

Predicted visibility impacts from the Sooner Generating Station were determined with the EPA CALPUFF modeling system, which is the EPA-preferred modeling system for long-range transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR Part 51), long-range transport is defined as modeling with source-receptor distances greater than 50 km. Because all modeled areas are located more than 50 km from the sources in question, the CALPUFF system was appropriate to use.

OG&E Sooner Generating Station BART Review January 15, 2010

Additionally, the CALMET model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent regional wind flows and complex terrain circulations. Associated two-dimensional fields such as mixing height, land use, and surface roughness are included in the input to the CALMET model. The CALMET model allows the user to "weight" various terrain influences parameters in the vertical and horizontal directions by defining the radius of influence for surface and upper-air stations.

CALPOST is a post-processing program that can read the CALPUFF output files, and calculate the impacts to visibility.

Table 13: Key Programs in CALPUFF System
Program	Version	Level
CALMET	5.53a	040716
CALPUFF	5.8	070623
CALPOST	5.6394	070622

Meteorological Data Processing (CALMET)

As required by the Division's modeling protocol, the CALMET model was used to construct the initial three-dimensional wind field using data from the MMS model. Surface and upper-air data were also input to CALMET to adjust the initial wind field.

The following table lists the key user-defined CALMET settings that were selected.

Table 14: CALMET Variables
Variable	Description	Value
PMAP	Map projection	LCC (▇▇▇▇▇▇▇ Conformal Conic)
DGRIDKM	Grid spacing (km)	4
NZ	Number of layers	12
ZFACE	Cell face heights (m)	0, 20, 40, 60, 80, 100, 150, 200, 250, 500, 1000, 2000, 3500
RMIN2	Minimum distance for extrapolation	-1
IPROG	Use gridded prognostic model outputs	14 km (MM5 data)
RMAX1	Maximum radius of influence (surface layer, km)	20 km

OG&E Sooner Generating Station BART Review January 15, 2010

Variable	Description	Value
RMAX2	Maximum radius of influence (layers aloft, km)	50 km
TERRAD	Radius of influence for terrain (km)	10 km
R1	Relative weighting of first guess wind field and observation (km)	10 km
R2	Relative weighting aloft (km)	25 km

The locations of the upper air stations with respect to the modeling domain are shown in Figure 2.

IMAGE NOT SHOWN

Figure 2: Plot of surface station locations

OG&E Sooner Generating Station BART Review January 15, 2010

IMAGE NOT SHOWN

Figure 3: Plot of upper air station locations

IMAGE NOT SHOWN

Figure 4. Plot of precipitation observation stations

OG&E Sooner Generating Station BART Review January 15, 2010

CALPUFF Modeling Setup

Latitude and longitude coordinates for Class I area discrete receptors were taken from the National Park Service (NPS) Class I Receptors database and converted to the appropriate ▇▇▇ coordinates.

CALPUFF Inputs-Baseline and Control Options

The first step in the refined modeling analysis was to perform visibility modeling for current (baseline) operations at the facility. Emissions of NOx and S02 for the baseline runs were established based on CEM data and maximum 24-hour emissions averages for years 2001 to 2003.

Baseline source release parameters and emissions are shown in the table below, followed by tables with data for the various control options.

Table 15: Baseline Source Parameters
	Baseline
Parameter	Coal-Fired Unit 1	Coal-Fired Unit 2
Heat Input (mmBtu/hr)	5,116	5,116
Stack Height (m)	152.44	152.44
Stack Diameter (m)	6.10	6.10
Stack Temperature (K)2	430.78	430.78
Exit Velocity (m/s)2	34.12	34.12
Baseline SO2 Emissions (lb/mmBtu)	0.86	0.86
Dry FGD SO2 Emissions (lb/mmBtu)	0.10	0.10
Wet FGD SO2 Emissions (lb/mmBtu)	0.08	0.08
Baseline NOx Emissions (lb/mmBtu)	0.601	0.584
LNB/OFA NOx Emissions (lb/mmBtu)	0.15	0.15
LNB/OFA + SCR NOx Emissions (lb/mmBtu)	0.07	0.07
ESP (Baseline) PM10 Emissions (lb/mmBtu)	0.0379	0.0391
FF PM10 Emissions (lb/mmBtu)	0.012	0.012

1Baseline emissions data were provided by OG&E. Baseline emission rates (lb/mmBtu) were calculated by dividing the maximum 24-hr lb/hr emission rate by the maximum heat input to the boiler.

2Temperature and Velocity were decreased for DFGD and WFGD evaluations. For DFGD, stack temperature was modeled at 359.11K and velocity decreased to 30.61 m/s. For WFGD, stack temperature decreased to 331.89K and velocity decreased to 28.35 m/s.

OG&E Sooner Generating Station BART Review January 15, 2010

Visibility Post-Processing (CALPOST) Setup

Table 16: Relative Humidity Factors for CALPOST
Month	Wichita Mountains	Caney Creek	Upper Buffalo	Hercules Glade
January	2.7	3.4	3.3	3.2
February	2.6	3.1	3.0	2.9
March	2.4	2.9	2.7	2.7
April	2.4	3.0	2.8	2.7
May	3.0	3.6	3.4	3.3
June	2.7	3.6	3.4	3.3
July	2.3	3.4	3.4	3.3
August	2.5	3.4	3.4	3.3
September	2.9	3.6	3.6	3.4
October	2.6	3.5	3.3	3.1
November	2.7	3.4	3.2	3.1
December	2.8	3.5	3.3	3.3

Visibility Post-Processing Results

Table 17: CALPUFF Visibility Modeling Results for Sooner Units 1 and 2 - NOx
	2001		2002		2003		3-Year Average
Class I Area	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. o f Days > 0.5 ∆dv
Baseline
Wichita Mountains	1.244	19	0.901	16	1.199	25	1.115	20
Caney Creek	0.577	10	0.404	5	0.541	10	0.507	8
Upper Buffalo	0.573	8	0.335	4	0.337	3	0.415	5
Hercules Glade	0.440	6	0.274	5	0.388	1	0.367	4
Scenario 1 – Combustion Control – LNB/OFA
Wichita Mountains	0.309	0	0.236	1	0.308	0	0.284	0
Caney Creek	0.147	0	0.103	0	0.14	0	0.13	0
Upper Buffalo	0.139	0	0.085	0	0.084	0	0.103	0
Hercules Glade	0.109	3	0.064	1	0.095	3	0.089	2

OG&E Sooner Generating Station BART Review January 15, 2010

Modeling for SCR controls resulted in an approximately 50% reduction in visibility impairment from scenario one.

Table 18: CALPUFF Visibility Modeling Results for Sooner Units 1 and 2 – SO2
	2001		2002		2003		3-Year Average
Class I Area	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. o f Days > 0.5 ∆dv
Baseline
Wichita Mountains	1.244	24	1.081	24	1.792	33	1.366	27
Caney Creek	0.709	11	0.505	10	0.584	11	0.599	11
Upper Buffalo	0.534	10	0.357	4	0.43	5	0.440	6
Hercules Glade	0.423	5	0.267	2	0.34	3	0.343	3
Scenario 1 – Dry FGD
Wichita Mountains	0.169	3	0.141	0	0.219	3	0.176	2
Caney Creek	0.08	0	0.062	0	0.063	0	0.068	0
Upper Buffalo	0.051	0	0.045	0	0.043	0	0.046	0
Hercules Glade	0.05	0	0.033	0	0.037	0	0.04	0

While mass emissions are decreased marginally with Wet FGD controls modeled impacts increase over modeled concentrations in scenario one. This increased degradation is a result of lower stack temperatures and velocities and higher SO4 emission estimates.

Modeling for existing ESP controls with proposed fabric filters indicate the visibility impairment from direct PM emissions will be improved with the fabric filters but both technologies control visibility impairment well below 0.5dv at all Class I areas.

▇. ▇▇▇▇ DETERMINATION

After considering: (1) the costs of compliance, (2) the energy and non-air quality environmental impacts of compliance; (3) any pollutant equipment in use or in existence at the source, (4) the remaining useful life of the source, and (5) the degree of improvement in visibility (all five statutory factors) from each proposed control technology, the Division determined BART for the two units at the Sooner Generating Station.

NOx

New LNB with OFA is determined to be BART for NOx control for Units 1 and 2based, in part, on the following conclusions:

1.	Installation of new LNB with OFA was cost effective, with a capital cost of $14,055,900 per unit for units 1 and 2 and an average cost effectiveness of $493-785 per ton of NOx removed for each unit over a twenty-five year operational life.

2.	Combustion control using the LNB/OFA does not require non-air quality environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is minimal energy impact.

3.	After careful consideration of the five statutory factors, especially the costs of

OG&E Sooner Generating Station BART Review January 15, 2010

compliance and existing controls, NOx control levels on 30-day rolling averages of 0.15 lb/mmBtu for Unit 1 and 2 are justified meet the presumptive limits prescribed by EPA.

4.	Annual NOx emission reductions from new LNB with OFA on Units 1 and 2 are 2,664- 4,241 tons for a total annual reduction of 6,905 tons based on actual emissions from 2004-2006 and projected emissions at maximum heat input and 90% capacity.

LNB with OFA and SCR was not determined to be BART for NOx control for Units 1 and 2 based, in part, on the following conclusions:

The cost of compliance for installing SCR on each unit is significantly higher than the cost for LNB with OFA. Additional capital costs for SCR on Units 1 and 2 are on average $192,018,500 per unit. Based on projected emissions, SCR could reduce overall NOx emissions from Sooner Units 1 and 2 by approximately 3,226 TPY beyond combustion controls; however, the incremental cost associated with this reduction is approximately $17,795/ton.

2.	Additional non-air quality environmental mitigation is required for the use of chemical reagents.

3.	Operation of LNB with OFA and SCR is parasitic and requires power from each unit.

4.	The cumulative visibility improvement for SCR, as compared to LNB/OFA across Wichita Mountains and Caney Creek (based on the 98th percentile modeled results) was 0.15 ∆dv for both units.

SO2

Continued use of low sulfur coal is determined to be BART for SO2 control for Units 1 and 2 based on the capital cost of add-on controls, the cost effectiveness both in $/ton and $/dv of add-on controls, and the long term viability of coal with respect to other environmental programs, and national commitments.

Installation of DFGD is not cost effective. OG&E's revised cost estimates are based on vendor quotes and go well beyond the default methodology recommended by EPA guidance. The cost estimates are credible, detailed, and specific for the Sooner facility. The final estimate for both boilers at $584,589,800 is $175,329,800 greater than the high end costs assumed by DEQ in the Draft SIP.

These costs put the project well above costs reported for other BART determinations. The federal land managers have informally maintained a spreadsheet of BART costs and determinations for coal-fired facilities. This spreadsheet indicates that the highest reported cost for control was for the Boardman facility in Oregon at a projected cost of $247,300,000. While there is some uncertainty on whether this cost will ultimately be found to be cost effective, it is lower than the cost of controlling a single boiler at the Sooner facility ($292,294,700). Most assessments were based on costs of less than $150,000,000 and related cost effectiveness numbers of $3,053/ton removed for ▇▇▇▇▇▇▇▇ to an average of less than $2,000/ton for the other determinations tracked by the FLMs.

Table 20 provides a summary of the baseline S02 emission rates included in several BART evaluations.

OG&E Sooner Generating Station BART Review January 15, 2010

Table 20: Comparison of Baseline SO2 Emissions at Several BART Units
Station	Baseline SO2 Emission Rate (lb/mmBtu)	Baseline SO2 Emissions (TPY)
Muskogee Unit 4	0.507	9,113
Muskogee Unit 5	0.514	9,006
Sooner Unit 1	0.509	9,394
Sooner Unit 2	0.516	8,570
NPPD ▇▇▇▇▇▇ Gentleman Unit 1	0.749	24,254
NPPD ▇▇▇▇▇▇ Gentleman Unit 2	0.749	25.531
White Bluff Unit 1	0.915	31,806
White Bluff Unit 2	0.854	32,510
▇▇▇▇▇▇▇▇ unit 1	0.614	14,902
Northeastern Unit 3	0.900	16,000
Northeastern Unit 4	0.900	16,000
▇▇▇▇▇▇▇▇ Unit 1	1.180	8,624
▇▇▇▇▇▇▇▇ Unit 2	1.180	11,187
OPPD Nebraska City Unit 1	0.815	24,191

Assuming total annual costs and projected emissions are similar and thereby setting aside the issues related to pre-2008 cost estimates and the ability to compare them to December 2009 estimates, cost effectiveness will be a function of the baseline emissions. This holds true for units firing subbituminous coals with baseline SO2 emissions rates in the range of 0.5 lb/mmBtu to approximately 2.0 lb/mmBtu, because removal efficiencies achievable with DFGD control will vary based on inlet SO2 loading. In general, DFGD control systems are capable of achieving higher removal efficiencies on units with higher inlet SO2 loading. DFGD control systems will be more cost effective on units with higher baseline SO2 emissions because the control systems will be capable of achieving higher removal efficiencies and remove more tons of SO2 per year for similar costs. Conversely, DFGD will be less cost effective, on a $/ton basis, on units with lower SO2 baseline emissions. On the basis of baseline emissions alone, with all other factors being equal, the cost effectiveness of the OG&E units would be about 55 to 185% higher than the other units listed, i.e., less cost effective.

The average cost effectiveness at Sooner for DFGD is $6,348-$7,147 per ton of SO2 removed for each unit over a twenty year operational life. The cost of this control at the Sooner facility is well above the average cost effectiveness reported for similar BART projects, well above costs associated with BACT determinations for SO2, and well above the cost of control originally contemplated in the Regional Haze Rule.

From the FLM BART tracking spreadsheet, the average cost effectiveness in $/dv was $5,700,000/dv. The addition of DFGD at the Sooner Facility was anticipated to reduce impairment by 2.44 dv. Importantly, the cost effectiveness of that improvement is now calculated to be $38,387,000/dv.

OG&E Sooner Generating Station BART Review January 15, 2010

at more Class I areas. For example, the ▇▇▇▇▇▇▇▇ Generating Station located in the north central region approximately 150 miles east of Portland, is located within 300 km of 14 Class I areas. By comparison the Sooner station is located with 300 km of 1 Class I area. Using the sum of modeled visibility improvements at all 14 Class I areas, cost effectiveness of the DFGD control system would be $3,690,510/dv or 10.4 times more cost effective than DFGD controls at the Sooner facility. The federal land managers have indicated that costs effectiveness numbers of less than $10,000,000/dv should be considered cost effective. While this does not prohibit a determination of cost effectiveness at numbers greater than $10,000,000/dv, it does imply that numbers greater than that should receive greater consideration.

An investment of this magnitude to install DFGD on an existing coal-fired power plant effectively guarantees the continued use of coal as the primary fuel source for energy generation in this facility and arguably the state for the next 20 years and beyond. Therefore, a determination in support of DFGD ignores the Obama Administration's stated agenda to control carbon dioxide and other green house gases by restricting the alternatives left open to OG&E and hence the ratepayers of Oklahoma. Substantial uncertainty currently exists about the nature and costs of future federal carbon controls on power plants, including the level of stringency, timing, emissions allowance allocation and prices, and whether and to what degree emissions "offsets" are allowed. Further, new federal MACT mercury control requirements may be imposed on the Sooner facility that would be more stringent than the scrubber can deliver. Fortunately, other technology options now exist that would likely achieve greater mercury reductions at lower cost than the scrubber. If EPA determines that MACT requires greater reductions than those achieved through DFGD, then ratepayers would be at risk to pay for additional required mercury control technology.

The cost for DFGD is too high, the benefit too low and these costs, if borne, further extend the life expectancy of coal as the primary fuel in the Sooner facility for at least 20 years and beyond. BART is the continued use of low sulfur coal.

Wet FGD was not determined to be BART for SO2 control for Units 1 and 2 based, in part, on the following conclusions:

The cost of compliance for installing WFGD on each unit is higher than the cost for DFGD. Based on projected emissions, WFGD could reduce overall SO2 emissions from Sooner Units 1 and 2 by approximately 808 TPY beyond dry scrubbers; however, the incremental cost associated with this reduction is approximately $18,854/ton.

SO3 remaining in the flue gas will react with moisture in the wet FGD to generate sulfuric acid mist. Sulfuric acid is classified as a condensable particulate. Condensable particulates from the wet FGD system can be captured using additional emission controls (e.g., ▇▇▇▇). However, the effectiveness of a ▇▇▇▇ system on a subbituminous fired unit has not been demonstrated and the additional cost of the ▇▇▇▇ system significantly increases the cost of SO2 controls.

Wet FGD systems must be located downstream of the unit's particulate control device; therefore, dissolved solids from the wet FGD system will be emitted with the wet FGD plume. Wet FGD control systems also generate lower stack temperatures that can reduce plume rise and result in a visible moisture plume.

OG&E Sooner Generating Station BART Review January 15, 2010

4.	Wet FGD systems use more reactant (e.g., limestone) than do dry systems, therefore the limestone handling system and storage piles will generate more fugitive dust emissions.

Wet FGD systems require significantly more water than the dry systems and generate a wastewater stream that must be treated and discharged. We FGD wastewater treatment systems typically require calcium sulfate/sulfite desaturation, heavy metals precipitation, coagulation/precipitation, and sludge dewatering. Treated wastewater is typically discharged to surface water pursuant to an NPDES discharge permit, and solids are typically disposed of in a landfill. Dry FGD control systems are designed to evaporate water within the reaction vessel, and therefore do not generate a wastewater stream.

6.	Because of a slower exit velocity, lower stack temperature and higher SO4 emissions associated with Wet FGD, visibility impairment was found to higher under this control strategy than the Dry FGD.

PM10

The existing ESP control is determined to be BART for PM10 controls for Units 1 and 2 based on the determination of low sulfur coal and the high cost of fabric filters relative to the low actual emissions of PM10 from the facility.

Table 21: Unit-by-unit BART determinations
Control	Unit 1	Unit 2
NOx Control	New LNB with OFA	New LNB with OFA
Emission Rate (lb/mmBtu)	0.15 lb/mmBtu (30-day rolling average)	0.15 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	767 lb/hr (30-day rolling average)	767 lb/hr (30-day rolling average)
Emission Rate TPY	3,361 TPY (12-month rolling)	3,361 TPY (12-month rolling)
SO2 Control	Low Sulfur Coal	Low Sulfur Coal
Emission Rate (lb/mmBtu)	0.65 lb/mmBtu (30-day rolling average)	0.65 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	3,325 lb/hr (30-day rolling average)	3,325 lb/hr (30-day rolling average)
Annual Emission Rate (lb/mmBtu)	0.55 lb/mmBtu (annual average)	0.55 lb/mmBtu (annual average)
Emission Rate TPY	19,736 TPY
PM10 Control	Existing ESP	Existing ESP
Emission Rate (lb/mmBtu)	0.1 lb/mmBtu	0.1 lb/mmBtu
Emission Rate lb/hr	512 lb/hr	512 lb/hr
Emission Rate TPY	2,241 TPY (12-month rolling average)	2,241 TPY (12-month rolling average)

OG&E Sooner Generating Station BART Review January 15, 2010

F. CONTINGENT BART DETERMINATION

In the event that EPA disapproves the BART Determination referenced above in regard to the DEQ determination that DFGD with SDA is not cost-effective for SO2 control, the low-sulfur coal requirement in the BART determination for SO2 and the related ESP requirement for PM referenced above shall be replaced with a requirement that Sooner Units 1 and 2 install DFGD with SDA for SO2 control and fabric filters for PM control or meet the corresponding SO2 and PM10 emission limits listed below by December 31, 2018 or comply with the approved alternative described in section G (Greater Reasonable Progress Alternative).

Table 22: Unit-by-unit Contingent BART determinations
Control	Unit 1	Unit 2
SO2 Control	DFGD w/SDA	DFGD w/ SDA
Emission Rate (lb/mmBtu)	0.1 lb/mmBtu (30-day rolling average)	0.1 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	512 lb/hr (30-day rolling average)	512 lb/hr (30-day rolling average)
Emission Rate TPY	2,241 TPY	2,241 TPY
PM10 Control	Fabric Filter	Fabric Filter
Emission Rate (lb/mmBtu)	0.015 lb/mmBtu	0.015 lb/mmBtu
Emission Rate lb/hr	77 lb/hr	77 lb/hr
Emission Rate TPY	336 TPY (12-month rolling average)	336 TPY (12-month rolling average)

The "contingent" ▇▇▇▇ as defined here and in conjunction with the greater reasonable progress alternative recognizes the long term importance of achieving reductions in SO2 while addressing the need for operational flexibility in response to the eventualities of a federal carbon trading program and mercury MACT in the nearer term. It must be understood that DEQ has determined that DFGD is not cost effective. However, if EPA chooses to ignore that element of the BART determination, DEQ does agree that DFGD remains an achievable control option for SO2 reductions.

Switching from coal to natural gas, while physically possible constitutes a significant modification to a facility process not contemplated by the regional haze role. However, exploring some combination of both options, while allowing the uncertainty surrounding other federal environmental programs to settle, is a more equitable alternative for the ratepayers in Oklahoma than requiring an overly costly control merely to achieve limited reductions while simultaneously solidifying the use of a dirty technology from now into the foreseeable future.

G. GREATER REASONABLE PROGRESS ALTERNATIVE DETERMINATION

In lieu of installing and operating BART for SO2 and PM control at Sooner Units 1 and 2 and Muskogee Units 4 and 5. OG&E may elect to implement a fuel switching alternative. The greater reasonable progress alternative requires OG&E to achieve a combined annual SO2 emissions limit (identified in table 23) by installing and operating DFGD with SDA on two of the four boilers and being at or below the SO2 emission that would result from switching the

OG&E Sooner Generating Station BART Review January 15, 2010

remaining two boiler to natural gas. Under this alternative OG&E shall install the controls (i.e., DFGD with SDA or achieve equivalent emissions) by December 31, 2026. By adopting these emission limits, DEQ and OG&E expect the cumulative SO2 emissions from Sooner Units 1 and 2 and Muskogee Units 4 and 5 to be approximately 57% less than would be achieved through the installation and operation of DFGD with SDA at all four units (assuming 90% capacity).

Table 23: SO2 Emissions with Greater Reasonable Progress
	Muskogee	Sooner
Parameter	Unit 4 and Unit 5	Unit 1 and Unit 2
BART (Low Sulfur Coal)	18,096 TPY	19,736 TPY
Contingent BART (DFGD)	4,800 TPY	4,482 TPY
GRP (DFGD/Natural Gas)	3,600 TPY

Under no circumstance will the Greater Reasonable Progress Plan result in less visibility improvement than would be achieved either through the DEQ determined BART or the "contingent" BART. By allowing the installation of SO2 controls to be delayed, current regulatory hurdles to long term natural gas contracts can be addressed and the best interests of the ratepayers and visitors to our Class I areas can be preserved for the long term 2064 goal of natural visibility.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD)

Sooner Generating Station is a major source under OAC 252:100-8 Permits for Part 70 Sources. Oklahoma Gas and Electric should comply with the permitting requirements of Subchapter 8 as they apply to the installation of controls determined to meet ▇▇▇▇.

The installation of controls determined to meet ▇▇▇▇ will not change NSPS or NESHAP/MACT applicability for the gas-fired units at the Sooner Station. The permit application should contain PM10 and PM2.5 emission estimates for filterable and condensable emissions.

VI. OPERATING PERMIT

The Sooner Generating Station is a major source under OAC 252:100-8 and has submitted an application to modify their existing Title V permit to incorporate the requirement to install controls determined to meet ▇▇▇▇. The Permit will contain the following specific conditions:

Affected facilities. The following sources are affected facilities and are subject to the requirements of this Specific Condition, the Protection of Visibility and Regional Haze Requirements of 40 CFR Part 51, and all applicable SIP requirements:

OG&E Sooner Generating Station BART Review January 15, 2010

EU ID#	Point ID#	EU Name	Heat Capacity (MMBTUH)	Construction Date
2-B	01	Unit 1 Boiler	5,116	1974
2-B	02	Unit 2 Boiler	5,116	1974

Each existing affected facility shall install and operate the SIP approved BART as expeditiously as practicable but in no later than five years after approval of the SIP incorporating the BART requirements.

The permittee shall apply for and obtain a construction permit prior to modification of the boilers. If the modifications will result in a significant emission increase and a significant net emission increase of a regulated NSR pollutant, the applicant shall apply for a PSD construction permit.

The affected facilities shall be equipped with the following current combustion control technology, as determined in the submitted BART analysis, to reduce emissions of NOx to below the emission limits below:

i. Low- NOx Burners,

ii. Overfire Air.

The permittee shall maintain the controls (Low-NOX burners, overfire air) and establish procedures to ensure the controls are properly operated and maintained.

EU ID#	Point ID#	NOx Emission Limit	SO2 Emission Limit	Averaging Period
2-B	01	0.15 lb/mmBtu	0.65 lb/mmBtu	30-day rolling
2-B	02	0.15 lb/mmBtu	0.65 lb/mmBtu	30-day rolling

EU ID#	Point ID#	PM10
2-B	01	0.1 lb/mmBtu
2-B	02	0.1 lb/mmBtu

EU ID#	Point ID#	SO2 Emission Limit	SO2 Emission Limit	Averaging Period
2-B	01	19,736	0.55 lb/mmBtu	Annual rolling
2-B	02	19,736	0.55 lb/mmBtu	Annual rolling

Boiler operating day shall have the same meaning as in 40 CFR Part 60, Subpart Da.

Within 60 days of achieving maximum power output from each boiler, after modification of the boilers, not to exceed 180 days from initial start-up, the

OG&E Sooner Generating Station BART Review January 15, 2010

permittee shall conduct performance testing as follows and furnish a written report to Air Quality. Such report shall document compliance with BART emission limits for the affected facilities. [OAC 252:100-8-6(a)]

i.	The permittee shall conduct SO2, NOx, PM10, PM2.5, CO, and VOC testing on the boilers at 60% and 100% of the maximum capacity. NOX and CO testing shall also be conducted at least one additional intermediate point in the operating range.

ii.

Performance testing shall be conducted while the units are operating within 10% of the desired test rates. A testing protocol describing how the testing will be performed shall be provided to the AQD for review and approval at least 30 days prior to the start of such testing. The permittee shall also provide notice of the actual test date to AQD.

EXHIBIT C

Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis		January 15, 2010

COMPANY:	Oklahoma Gas and Electric

FACILITY:	Muskogee Generating Station

FACILITY LOCATION:	Muskogee, Muskogee County, Oklahoma

TYPE OF OPERATION:	(2) 572 MW Steam Electric Generating Units

REVIEWER:	▇▇▇▇▇▇▇ ▇▇▇▇▇▇▇, Senior Engineering Manager
	▇▇▇ ▇▇▇▇▇▇, Engineering Manager

I. PURPOSE OF APPLICATION

II. ▇▇▇▇ ELIGIBILITY DETERMINATION

BART-eligible sources include those sources that:

(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant;

(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and

Muskogee Units 4 and 5 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. Both units were in existence prior to August 7, 1977 but not in operation prior to August 7, 1962. Based on a review of existing emissions data, both units have the potential to emit more than 250 tons per year of NOx, SO2 and PM10, visibility impairing pollutants. Therefore, Muskogee Units 4 and 5 meet the definition of a BART-eligible source.

▇▇▇▇ is required for any BART-eligible source that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area.

OG&E Muskogee Generating Station BART Review January 15, 2010

DEQ has determined that an individual source will be considered to "contribute to visibility impairment" if emissions from the source result in a change in visibility, measured as a change in deciviews (∆-dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling conducted by OG&E determined that the maximum predicted visibility impacts from Muskogee Units 4 and 5 exceeded the 0.5 ∆-dv threshold at the Wichita Mountains, Caney Creek Upper Buffalo, and Hercules Glade Class I Areas. Therefore, Muskogee Units 4 and 5 were determined to be BART applicable sources, subject to the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Muskogee Units 4 and 5 were developed based on an evaluation of actual emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling analysis to determine visibility impairment impacts should reflect steady-state operating conditions during periods of high capacity utilization. Therefore, modeled emissions (lb/hr) represent the highest 24-hour block emissions reported during the baseline period. Baseline emission rates (lb/mmBtu) were calculated by dividing the average annual mass emission rates for each boiler by the boiler's average heat input over the years 2004 through 2006.

Table 1: Muskogee Generating Station – Plant Operating Parameters for BART Evaluation
Parameter	Muskogee Unit 4		Muskogee Unit 5
Plant Configuration	Pulverized Coal-Fired Boiler		Pulverized Coal-Fired Boiler
Firing Configuration	Tangentially-fired		Tangentially-fired
Gross Output (nominal)	572 MW		572 MW
Maximum Input to Boiler	5,480 mmBtu/hr		5,480 mmBtu/hr
2004 – 2006 Average Heat Input to Boiler	4,594 mmBtu/hr		4,739 mmBtu/hr
Primary Fuel	Subbituminous coal		Subbituminous coal
Existing NOx Controls	Combustion Controls		Combustion Controls
Existing PM10 Controls	Electrostatic precipitator		Electrostatic precipitator
Existing SO2 Controls	Low-sulfur coal		Low-sulfur coal
Maximum 24-hour Emissions
Pollutant	lb/hr	lb/mmBtu	lb/hr	lb/mmBtu
NOx	2,710	0.495	2,863	0.522
SO2	4,384	0.800	4,657	0.850
PM10	101	0.018	134	0.024
Baseline Emissions (2004-2006)
Pollutant	lb/hr	lb/mmBtu	lb/hr	lb/mmBtu
NOx	1,342	0.292	1,545	0.326
SO2	2,329	0.507	2,436	0.514

OG&E Muskogee Generating Station BART Review January 15, 2010

IV. BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

Step l. Identify All Available Retrofit Control Technologies.

Step 2. Eliminate Technically Infeasible Options.

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.

Step 4. Evaluate Impacts and Document the Results.

Step 5. Evaluate Visibility Impacts.

In the final Regional Haze Rule U.S. EPA established presumptive BART emission limits for S02 and NOx for certain electric generating units (EGUs) based on fuel type, unit size, cost effectiveness, and the presence or absence of pre-existing controls. The presumptive limits apply to EGUs at power plants with a total generating capacity in excess of 750 MW. For these sources, EPA established presumptive emission limits for coal-fired EGUs greater than 200 MW in size. The presumptive levels are intended to reflect highly cost-effective technologies as well as provide enough flexibility to States to consider source specific characteristics when evaluating BART. The BART S02 presumptive emission limit for coal-fired EGUs greater than 200 MW in size without existing S02 control is either 95% S02 removal, or an emission rate of 0.15 lb/mmBtu, unless a State determines that an alternative control level is justified based on a careful consideration of the statutory factors. For NOx, EPA established a set of BART presumptive emission limits for coal-fired EGUs greater than 200 MW in size based upon boiler size and coal type. The BART NOx presumptive emission limit applicable to Muskogee Units 4 and 5 (tangentially fired boilers firing subbituminous coal) is 0.15 lb/mmBtu.

Table 2: Proposed BART Controls and Limits
Unit	NOx BART Emission Limit	BART Technology
Muskogee Unit 4	0.15 lb/mmBtu (30-day average)	Combustion controls including LNB/OFA
Muskogee Unit 5	0.15 lb/mmBtu (30-day average)	Combustion controls including LNB/OFA
Unit	S02 BART Emission Limit	BART Technology
Muskogee Unit 4	0.65 lb/mmBtu (30-day average)	Low Sulfur Coal
Muskogee Unit 4	0.55 lb/mmBtu (annual average)	Low Sulfur Coal
Muskogee Unit 5	0.65 lb/mmBtu (30-day average)	Low Sulfur Coal
Muskogee Unit 5	0.55 lb/mmBtu (annual average)	Low Sulfur Coal
Units 4 and 5	18,096 TPY	Low Sulfur Coal
Unit	PM10 BART Emission Limit	BART Technology
Muskogee Unit 4	0.1 lb/mmBtu (3-hour average)	Electrostatic precipitator
Muskogee Unit 5	0.1 lb/mmBtu (3-hour average)	Electrostatic precipitator

OG&E Muskogee Generating Station BART Review January 15, 2010

A. NOx

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Potentially available control options were identified based on a comprehensive review of available information. NOx control technologies with potential application to Muskogee Units 4 and 5 are listed in Table 3.

Table 3: List of Potential Control Options

Control Technology

Combustion Controls

Low NOx Burners and Overfire Air (LNB/OFA)

Flue Gas Recirculation (FGR)

Post Combustion Controls

Selective Noncatalytic Reduction (SNCR)

Selective Catalytic Reduction (SCR)

Innovative Control Technologies

Rotating Overfire Air (ROFA)

ROFA + SNCR (Rotamix)

▇▇▇▇▇▇▇ Multi-Pollutant Control Process

Wet NOx Scrubbing

ELIMINATE TECHNICALLY INFEASIBLE OPTIONS (NOx)

Combustion Controls:

Low NOx burners (LNB)/ OverFire Air (OFA)

LNB/OFA emission control systems have been installed as retrofit control technologies on existing coal-fired boilers. Muskogee units 4 and 5 operate as base load units. While technically feasible, LNB/OFA may not be as effective under all boiler operating conditions, especially during load changes and at low operating loads. Based on information available from burner control vendors and engineering judgment, it is expected that LNB/OFA on the tangentially-fired boilers can be designed to meet the presumptive NOx BART emission rate of 0.15 lb/mmBtu on a 30-day rolling average and under all normal operating conditions while maintaining acceptable CO and VOC emission rates.

Flue Gas Recirculation

OG&E Muskogee Generating Station BART Review January 15, 2010

FGR control systems have been used as a retrofit NOx control strategy on natural gas-fired boilers, but have not generally been considered as a retrofit control technology on coal-fired units. Natural gas-fired units tend to have lower O2 concentrations in the flue gas and low particulate loading. In a coal-fired application, the FGR system would have to handle hot particulate-laden flue gas with a relatively high 02 concentration. Although FGR has been used on coal-fired boilers for flue gas temperature control, it would not have application on a coal-fired boiler for NOx control. Because of the flue gas characteristics (e.g., particulate loading and 02 concentration), FGR would not operate effectively as a NOx control system on a coal-fired boiler. Therefore, FGR is not considered an applicable retrofit NOx control option for Muskogee Units 4 and 5, and will not be considered further in the BART determination.

Post Combustion Controls:

Selective Non-Catalytic Reduction

The size of the Muskogee Units would represent several design problems making it difficult to ensure that the reagent would be injected at the optimum flue gas temperature, and that there would be adequate mixing and residence time. The physical size of the Muskogee boilers makes it technically infeasible to locate and install ammonia injection points capable of achieving adequate mixing within the required temperature zone. Higher reagent injection rates would be required to achieve adequate mixing. Higher ammonia injection rates would result in relatively high levels of ammonia in the flue gas (ammonia slip), which could lead to plugging of downstream equipment.

Installation of SNCR on large boilers, such as those at Muskogee, has not been demonstrated in practice. Assuming that SNCR could be installed on the Muskogee Units, given the issues addressed above, control effectiveness would be marginal, and depending on boiler exit temperatures, could actually result in additional NOx formation. SNCR is not a technically feasible retrofit control for the Muskogee Boilers.

OG&E Muskogee Generating Station BART Review January 15, 2010

Selective Catalytic Reduction

SCR has been installed as NOx control technology on existing gas-fired boilers. Based on emissions data available from the EPA Electronic Reporting website, large coal-fired boilers have achieved actual long-term average NOx emission rates in the range of approximately 0.04 to 0.1 lb/mmBtu. Several design and operating variables will influence the performance of the SCR system, including the volume, age and surface area of the catalyst (e.g., catalyst layers), uncontrolled NOx emission rate, flue gas temperature, and catalyst activity.

Based on emission rates achieved in practice at existing subbituminous coal-fired units, and taking into consideration long-term operation of an SCR control system (including catalyst plugging and deactivation) it is anticipated that SCR could achieve a controlled NOx emission rate of 0.07 lb/mmBtu (30-day rolling average) on Muskogee Units 4 and 5.

Innovative NOX Control Technologies:

Rotating Opposed Fire Air and Rotamix

ROFA and Rotamix® systems have been demonstrated on smaller coal-fired boilers but have not been demonstrated in practice on boilers similar in size to Muskogee Units 4 and 5. As discussed for OFA, over fire air control systems are a technically feasible retrofit control technology, and, based on engineering judgment, the ROFA design could also be applied on Muskogee Units 4 and 5. However, there is no technical basis to conclude that the ROFA design would provide additional NOX reduction beyond that achieved with other OFA designs. Therefore, ROFA control systems are not evaluated as a specific control system, but are included in the overall evaluation of combustion controls (e.g., LNB/OFA).

ROFA+ SNCR (Rotamix)

▇▇▇▇▇▇▇ Multi-Pollutant Control Process

OG&E Muskogee Generating Station BART Review January 15, 2010

To date, bench- and pilot-scale testing have been conducted to evaluate the technology on utility-sized boilers. The New & Emerging Environmental Technologies (NEET) Database identifies the development status of the ▇▇▇▇▇▇▇ Process as full-scale development and testing. The process is an emerging multi-pollutant control, and there is limited information available to evaluate its technically feasibility and long-term effectiveness on a large natural gas-fired boiler. It is likely that OG&E would be required to conduct extensive design engineering and testing to evaluate the technical feasibility and long-term effectiveness of the control system on Muskogee Units 4 and 5. ▇▇▇▇ does not require applicants to experience extended time delays or resource penalties to allow research to be conducted on an emerging control technique. Therefore, at this time the ▇▇▇▇▇▇▇ Process is not a technically feasible retrofit control for the Muskogee Boilers.

Wet NOx Scrubbing Systems

Wet scrubbing systems have been used to remove NOx emissions from fluid catalytic cracking units (FCCUs) at petroleum refineries. An example of a wet scrubbing system is Balco Technologies' LoTOxYTM system. The LoTOx system is a patented process, wherein ozone is injected into the flue gas stream to oxidize NO and NO2 to N205. This highly oxidized species of NOx is very soluble and rapidly reacts with water to form nitric acid. The conversion of NOx to nitric acid occurs as the N205 contacts liquid sprays in the scrubber.

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NOx)

Table 4: Technically Feasible NOx Control Technologies – Muskogee Station
	Muskogee Unit 4	Muskogee Unit 5
Control Technology	Approximate NOx Emission Rate (lb/mmBtu)	Approximate NOx Emission Rate (lb/mmBtu)
LNB/OFA + SCR	0.07	0.07
LNB/OFA	0.15	0.15
Baseline	0.292	0.326

EVALUATE IMPACTS AND DOCUMENT RESULTS (NOx)

OG&E evaluated the economic, environmental, and energy impacts associated with the two proposed control options. In general, the cost estimating methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. Major equipment costs were developed based on publicly available cost data and equipment costs recently developed for similar projects, and include the equipment, material, labor, and all other direct costs needed to retrofit

OG&E Muskogee Generating Station BART Review January 15, 2010

Muskogee Units 4 and 5 with the control technologies. Fixed and variable O&M costs were developed for each control system. Fixed O&M costs include operating labor, maintenance labor, maintenance material, and administrative labor. Variable O&M costs include the cost of consumables, including reagent (e.g., ammonia), byproduct management, water consumption, and auxiliary power requirements. Auxiliary power requirements reflect the additional power requirements associated with operation of the new control technology, including operation of any new fans as well as the power requirements for pumps, reagent handling, and by-product handling. The capital recovery factor used to estimate the annual cost of control was based on a 7% interest rate and a control life of 25 years. Annual operating costs and annual emission reductions were calculated assuming a capacity factor of 90%.

Table 5: Economic Cost Per Boiler
Cost	Option 1: LNB/OFA	Option 2: LNB/OFA + SCR
Control Equipment Capital Cost ($)	$14,113,700	$193,077,000
Annualized Capital Costs ($/Yr)	$1,211,100	$16,568,000
Annual O&M Costs ($/Yr)	$880,700	$14,227,600
Annual Cost of Control ($)	$2,091,800	$30,795,600

Table 6: Environmental Costs per Boiler
		Baseline	Option 1: LNB/OFA	Option 2: LNB/OFA + SCR
NOx Emission Rate (lb/mmBtu)	Unit 4	0.292	0.15	0.07
NOx Emission Rate (lb/mmBtu)	Unit 5	0.326	0.15	0.07
Annual NOx Emission (TPY)1	Unit 4	5,258	2,674	1,246
Annual NOx Emission (TPY)1	Unit 5	5,709	2,628	1,227
Annual NOx Reduction (TPY)	Unit 4	-	2,587	4,012
Annual NOx Reduction (TPY)	Unit 5	-	3,081	4,482
Annual Cost of Control	Unit 4	-	$2,091,800	$30,795,600
Annual Cost of Control	Unit 5	-	$2,091,800	$30,795,600
Cost per Ton of Reduction	Unit 4	-	$809	$7,676
Cost per Ton of Reduction	Unit 5	-	$679	$6,871
Incremental Cost per Ton of Reduction2	Unit 4	-	-	$20,143
Incremental Cost per Ton of Reduction2	Unit 5	-	-	$20,488

1Emissions for the BART analysis are based on average heat inputs of 4,594 and 4,739 mmBtu/hr for Units 4 & 5. Annual emissions were calculated assuming 7,829 and 7,395 hours/year for Units 4 and 5 respectively.

2Incremental cost effectiveness of the SCR system is compared to costs/emissions associated with LNB/OFA controls.

OG&E Muskogee Generating Station BART Review January 15, 2010

B. SO2

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES (S02)

Potentially available control options were identified based on a comprehensive review of available information. S02 control technologies with potential application to Muskogee Units 4 and 5 are listed in Table 7.

Table 7: List of Potential Control Options

Control Technology

Pre-Combustion Controls

Fuel Switching

Coal Washing

Coal Processing

Post Combustion Controls

Wet Flue Gas Desulfurization

Wet Lime FGD

Wet Limestone FGD

Wet Magnesium Enhanced Lime FGD

Jet Bubbling Reactor FGD

Dual Alkali Scrubber

Wet FGD with Wet Electrostatic Precipitator

Dry Flue Gas Desulfurization

Spray Dryer Absorber

Dry Sorbent Injection

Circulating Dry Scrubber

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (SO2)

Pre-Combustion Control Strategy:

Fuel Switching

One potential strategy for reducing S02 emissions is reducing the amount of sulfur contained in the coal. Muskogee Units 4 and 5 fire subbituminous coal as their primary fuel. Subbituminous coal has a relatively low heating value, low sulfur content, and low uncontrolled S02 emission rate. No environmental benefits accrue from burning an alternative coal; therefore, fuel switching is not considered a feasible option for this retrofit project.

Coal Washing

OG&E Muskogee Generating Station BART Review January 15, 2010

Muskogee Units 4 and 5 are designed to utilize subbituminous coals. Based on a review of available information, no information was identified regarding the washability or effectiveness of washing subbituminous coals. Therefore, coal washing is not considered an available retrofit control option for Muskogee Units 4 and 5.

Coal Processing

Pre-combustion coal processing techniques have been proposed as one strategy to reduce the sulfur content of coal and help reduce uncontrolled S02 emissions. Coal processing technologies are being developed to remove potential contaminants from the coal prior to use. These processes typically employ both mechanical and thermal means to increase the quality of subbituminous coal and lignite by removing moisture, sulfur, mercury, and heavy metals. To date, the use of processed fuels has only been demonstrated with test bums in a pulverized coal-fired boiler. No coal-fired boilers have utilized processed fuels as their primary fuel source on an on-going, long-term basis. Although burning processed fuels, or a blend of processed fuels, has been tested in a pulverized coal-fired boiler, using processed fuels in Muskogee Units 4 and 5 would require significant research, test bums, and extended trials to identify potential impacts on plant systems, including the boiler, material handling, and emission control systems. Therefore, processed fuels are not considered commercially available, and will not be analyzed further in this BART analysis.

Post-Combustion Flue Gas Desulfurization

Wet Scrubbing Systems

Wet Lime Scrubbing

The wet lime scrubbing process uses an alkaline slurry made by adding lime (CaO) to water. The alkaline slurry is sprayed in the absorber and reacts with S02 in the flue gas. Insoluble CaS03 and CaS04 salts are formed in the chemical reaction that occurs in the scrubber and are removed as a solid waste by-product. The waste by-product is made up of mainly CaS03, which is difficult to ▇▇▇▇▇▇▇. Solid waste by-products from wet lime scrubbing are typically managed in dewatering ponds and landfills.

Wet Limestone Scrubbing

OG&E Muskogee Generating Station BART Review January 15, 2010

product and reduces the potential for scaling in the FGD. The gypsum by-product from this process must be dewatered, but may be salable thus reducing the quantity of solid waste that needs to be landfilled.

Wet Magnesium Enhanced Lime Scrubbing

Magnesium Enhanced Lime (▇▇▇) scrubbers are another variation of wet FGD technology. Magnesium enhanced lime typically contains 3% to 7% magnesium oxide (MgO) and 90 - 95% calcium oxide (CaO). The presence of magnesium effectively increases the dissolved alkalinity, and consequently makes S02 removal less dependent on the dissolution of the lime/limestone. ▇▇▇ scrubbers have been installed on coal-fired utility boilers located in the Ohio River Valley. Systems to oxidize the ▇▇▇ solids to produce a usable gypsum byproduct consisting of calcium sulfate (gypsum) and magnesium sulfate continue to be developed. Coal-fired units equipped with ▇▇▇ FGD typically fire high-sulfur eastern bituminous coal and use locally available reagent. There are no subbituminous-fired units equipped with a ▇▇▇-FGD system. Because ▇▇▇-FGD systems have not been used on subbituminous-fired boilers, and because of the cost and limited availability of magnesium enhanced reagent (either naturally occurring or blended), and because limestone-based wet FGD control systems can be designed to achieve the same control efficiencies as the magnesium enhanced systems, ▇▇▇-FGD control systems will not be evaluated further as a commercially available retrofitted control system.

Jet Bubbling Reactor

Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike the spray tower wet FGD systems, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower, in the JBR-FGD flue gas is bubbled through a limestone slurry. Spargers are used to create turbulence within the reaction tank and maximize contact between the flue gas bubbles and scrubbing slurry. There is currently a limited number of commercially operating JBR-WFGD control systems installed on coal-fired utility units in the U.S. Although the commercial deployment of the control system continues, there is still a very limited number of operating units in the U.S. Furthermore, coal-fired boilers currently considering the JBR-WFGD control system are all located in the eastern U.S., and all fire eastern bituminous coals. The control system has not been proposed as a retrofit technology on any large subbituminous coal-fired boilers. However, other than scale-up issues, there do not appear to be any overriding technical issues that would exclude application of the control technology on a large subbituminous coal-fired unit. There are no data available to conclude that the JBR-WFGD control system will achieve a higher S02 removal efficiency than a more traditional spray tower WFGD design, especially on units firing low-sulfur subbituminous coal. Furthermore, the costs associated with JBR-WFGD and the control efficiencies achievable with JBR-WFGD are similar to the costs and control efficiencies achievable with spray tower WFGD control systems. Therefore, the JBR-WFGD will not be evaluated as a unique retrofit technology, but will be included in the overall assessment of WFGD controls.

OG&E Muskogee Generating Station BART Review January 15, 2010

Dual-Alkali Wet Scrubber

Dual-alkali scrubbing is a desulfurization process that uses a sodium-based alkali solution to remove S02 from combustion exhaust gas. The process uses both sodium-based and calcium-based compounds. The dual-alkali process requires lower liquid-to-gas ratios then scrubbing with lime or limestone. The reduced liquid-to-gas ratios generally mean smaller reaction units, however additional regeneration and sludge processing equipment is necessary. The sodium-based scrubbing liquor, typically consisting of a mixture of sodium hydroxide, sodium carbonate and sodium sulfite, is an efficient S02 control reagent. However, the high cost of the sodium-based chemicals limits the feasibility of such a unit on a large utility boiler. In addition, the process generates a less stable sludge that can create material handling and disposal problems. It is projected that a dual-alkali system could be designed to achieve S02 control similar to a limestone-based wet FGD. However, because of the limitations discussed above, and because dual-alkali systems are not currently commercially available, dual-alkali scrubbing systems will not be addressed further in this BART determination.

Wet FGD with Wet Electrostatic Precipitator

Wet electrostatic precipitation (▇▇▇▇) has been proposed on other coal-fired projects as one technology to reduce sulfuric acid mist emissions from coal-fired boilers. WESPs have been proposed for boilers firing high-sulfur eastern bituminous coals controlled with wet FGD. ▇▇▇▇ has not been widely used in utility applications, and has only been proposed on boilers firing high sulfur coals and equipped with SCR. Muskogee Units 4 and 5 fire low-sulfur subbituminous coal. Based on the fuel characteristics, and assuming 1% S02 to S03 conversion in the boiler, potential uncontrolled H2S04 emissions from Muskogee Units 4 and 5 will only be approximately 5ppm. This emission rate does not take into account inherent acid gas removal associated with alkalinity in the subbituminous coal fly ash. Based on engineering judgment, it is unlikely that a ▇▇▇▇ control system would be needed to mitigate visible sulfuric acid mist emissions from Muskogee Units 4 and 5, even if WFGD control was installed. WESPs have been proposed to control condensable particulate emissions from boilers firing a high-sulfur bituminous coal and equipped with SCR and wet FGD; this combination of coal and control equipment results in relatively high concentrations of sulfuric acid mist in the flue gas. ▇▇▇▇ control systems have not been proposed on units firing subbituminous coals, and ▇▇▇▇ would have no practical application on a subbituminous-fired units. Therefore, the combination of WFGD+▇▇▇▇ will not be evaluated further in this BART determination.

Dry Flue Gas Desulfurization

Another scrubbing system that has been designed to remove S02 from coal-fired combustion gases is dry scrubbing. Dry scrubbing involves the introduction of dry or hydrated lime slurry into a reaction tower where it reacts with S02 in the flue gas to form calcium sulfite solids. Unlike wet FGD systems that produce a slurry byproduct that is collected separately from the fly ash, dry FGD systems produce a dry byproduct that must be removed with the fly ash in the particulate control equipment. Therefore, dry FGD systems must be located upstream of the particulate control device to remove the reaction products and excess reactant material.

Spray Dryer Absorber

Spray dryer absorber (SDA) systems have been used in large coal-fired utility applications. SDA systems have demonstrated the ability to effectively reduce uncontrolled S02 emissions from

OG&E Muskogee Generating Station BART Review January 15, 2010

pulverized coal units. The typical spray dryer absorber uses a slurry of lime and water injected into the tower to remove S02 from the combustion gases. The towers must be designed to provide adequate contact and residence time between the exhaust gas and the slurry to produce a relatively dry by-product. SDA control systems are a technically feasible and commercially available retrofit technology for Muskogee Units 4 and 5. Based on the fuel characteristics and allowing a reasonable margin to account for normal operating conditions (e.g., load changes, changes in fuel characteristics, reactant purity, atomizer change outs, and minor equipment upsets) it is concluded that dry FGD designed as SDA could achieve a controlled S02 emission rate of 0.10 lb/mmBtu (30-day average) on an on-going long-term basis.

Dry Sorbent Injection

Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas exhaust stream. Particulates generated in the reaction are controlled in the system's particulate control device. Typical S02 control efficiencies for a dry sorbent injection system are generally around 50%. OG&E stated that because the control efficiency of the dry sorbent system is lower than the control efficiency of either the wet FGD or SOA, the system will not be evaluated further. As OG&E proposed only the use of low sulfur coal as BART, it is not clear why they did not include this technology in the full evaluation. Lacking any data to justify why this might be a more cost effective option than Dry FGD with SDA, this option is set aside based solely on lower environmental benefit.

Circulating Dry Scrubber

A third type of dry scrubbing system is the circulating dry scrubber (CDS). A CDS system uses a circulating fluidized bed of dry hydrated lime reagent to remove S02. The dry by-product produced by this system is similar to the spray dry absorber by-product, and is routed with the flue gas to the particulate removal system. Operating experience on smaller pulverized coal boilers in the U.S. has shown high lime consumption rates, and significant fluctuations in lime utilization based on inlet S02 loading. Furthermore, CDS systems result in high particulate loading to the unit's particulate control device. Based on the limited application of CDS dry scrubbing systems on large boilers, it is likely that OG&E would be required to conduct extensive design engineering to scale up the technology for boilers the size of Muskogee Units 4 and 5, and that OG&E would incur significant time and resource penalties evaluating the technical feasibility and long-term effectiveness of the control system. Because of these limitations, CDS dry scrubbing systems are not currently commercially available as a retrofit control technology for Muskogee Units 4 and 5, and will not be evaluated further in this BART determination.

OG&E Muskogee Generating Station BART Review January 15, 2010

EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (S02)

Table 8: Technically Feasible S02, Control Technologies – Muskogee Station
Control Technology	Muskogee Unit 4	Muskogee Unit 5
Control Technology	Approximate S02 Emission Rate (lb/mmBtu)	Approximate S02 Emission Rate (lb/mmBtu)
Wet FGD	0.08	0.08
Dry FGD – Spray Dryer Absorber	0.10	0.10
Modeling Baseline	0.80	0.85
Annual Average Baseline	0.507	0.514

EVALUATE IMPACTS AND DOCUMENT RESULTS (S02)

Capital Costs

In 2008 OG&E evaluated the economic, environmental, and energy impacts associated with the two proposed control options. In general, the cost estimating methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. Sixth Edition" EPA-452/B-02-001, January 2002. The cost-effectiveness evaluations were "study" estimates of ±30% accuracy, based on: (I) engineering estimates; (2) vendor quotations provided for similar projects and similar equipment; (2) S&L's internal cost database; and (4) cost estimating guidelines provided in U.S.EPA's, EPA Air Pollution Control Cost Manual. Cost estimates include the equipment, material, labor, and all other direct costs needed to retrofit Muskogee Units 4 and 5 with the control technologies.

While generally following the EPA methodology, these cost estimates exploited weaknesses in the estimate assumptions and resulted in highly exaggerated capital and particularly annual costs. In response to the ODEQ draft evaluation and EPA and FLM comments, OG&E submitted revised cost estimates during the public meeting held for the Oklahoma draft SIP. These revised estimates reflect vendor quotes for the Muskogee facility. In degree of difficulty, the retrofit at the Muskogee facility is described as average. The re-routing of ductwork, storm sewer systems and other equipment relocations were taken into consideration in the conceptual cost estimate.

The new cost estimates use the following methodology:

•

•	A general arrangement (GA) drawing was developed using the information received in the budgetary quotations. The GA drawing was used to estimate the major installation quantities for the project including ductwork, structural steel, foundations, relocation cable, and pipelines.

•	A motor list was assembled and used to develop the auxiliary power system sizing and quantities.

•	Mass balances were prepared and used to size the flue gas, material handling, material storage, and piping systems.

OG&E Muskogee Generating Station BART Review January 15, 2010

•	A schedule was developed to estimate escalation and Allowance for Funds Used During Construction (AFUDC) costs. It was assumed the new DFGDs would come on line at six month intervals with the last unit being completed at Muskogee near the end of 2015.

•	Range estimating techniques were used to identify the appropriate amount of contingency to obtain 95% confidence level. The contingency level was approximately 14%.

•	A design and cost basis document was prepared to document the major assumptions and inputs for developing the cost estimate.

•	Labor cost estimates were developed using the Oklahoma area wage rates, installation quantities, and installation rates taken from the ▇▇▇▇▇▇▇ and ▇▇▇▇▇ database.

Table 9: Economic Parameters to Derive Levelized Capital Charges
Commercial Operation Date (Reference Year)	2015
Depreciable Life	20 years
Inflation Rate	2.5%/year
Effective Income Tax Rate-Federal and State	38.12%
Common Equity Fraction	0.557
Debt Fraction	0.443
Return on Common Equity
Nominal	10.75%/year
Real	8.05%/year
Return on Debt
Nominal	6.03%/year

OG&E Muskogee Generating Station BART Review January 15, 2010

Real	3.44%/year
Discount Rate (after-tax cost of capital)
Nominal	7.64%/year
Real	5.43%/year
Tax Depreciation	20-year straight line
Levelized Capital Charges (real)	10.36%/year

The revised estimates based on vendor quotes results in a TCR of $634,386,800 which is $111,825,200 less than the CUE Cost derived estimates provided in 2008. However, OG&E has revised the capital recovery factor and reduced the number of years of expected depreciation to 20 from 25 resulting in a levelized capital charge or capital recovery of 32,861,300 per boiler, which is $844,900 per boiler per year more than the 2008 estimate. Cost estimates and assumptions are reasonable and application of the previously relied upon capital recovery factor does not significantly change the cost per ton of control or the conclusion of this review.

Operating Costs

Annual operating costs for the DFGD system consist of variable operating and maintenance (O&M) costs, fixed O&M costs, and indirect operating costs.

Variable O&M

Lime Reagent costs were based on material balances and budgetary lime quotations received for truck delivery, $105.53/ton, which is 52% of the previously assumed cost. Water costs were based on 219,839 lb/hr at full load, a 90% capacity factor and $2.57/1000 gallons. FGD Waste Disposal was based on material balances for the average fuel composition and a 90% capacity factor. First year cost of on-site disposal is $40.59/ton. Bag and cage replacement costs were based on exhaust gas flow through the baghouse, an air-to-cloth ratio of 3.5 for pulse jet baghouse, 4% contingency for bag cleaning, and 3-year bag life. The first year bag cost (including fabric and hangers) is $3.31/ft2. Ash disposal costs were not assumed to increase from the fabric filter as existing ESP is remaining in service. Auxiliary power costs were based on auxiliary power calculations and a 90% capacity factor. The first year auxiliary power cost is $85.92/MWh, which is 180% of the previously assumed power cost.

Increases in water, FGD waste disposal, bag and cage replacement, and auxiliary power costs offset decreases in lime reagent costs resulting in an increase in expected variable O&M costs from the 2008 estimate by approximately $1,000,000 per boiler per year.

Fixed O&M

Fixed O&M costs are recurring annual costs that are generally independent of the plant capacity factor. These consist of operating labor, supervisor labor, maintenance materials, and maintenance labor.

OG&E Muskogee Generating Station BART Review January 15, 2010

Operating labor was based on three shifts per day 365 days per year. The first year labor rate (salary plus benefits) is 58.76/hour. Supervisory labor was based on 15% of operating labor in accordance with the EPA Control Cost Manual (page 2-31). Maintenance materials were based on 0.6% of the total plant investment. Previous cost estimates reflecting Cue Cost default assumptions were based on 5% of capital equipment costs and therefore contributed to the exaggeration of annual operating costs. Maintenance labor was again based on 110% of operating labor, which is consistent with the EPA Control Cost Manual (page 2-31).

Due to the difference in cost basis for maintenance materials, the final fixed O&M costs were decreased by approximately $10,300,000 per year per boiler.

Indirect Operating Costs

Indirect operating costs are recurring annual costs for the FGD system that are not part of the direct O&M. These consist of property taxes, insurance, and administration.

Property taxes were calculated as 0.85% of total capital investment, in accordance with OG&E property tax rates. This rate is significantly lower than the EPA default rate of 1%. Insurance rates were calculated as 0.0105% of total capital investment in accordance with OG&E insurance rates. This rate is significantly lower than the EPA default rate of 1%. Administrative costs were calculated as 20% of the fixed O&M costs rather the EPA Air Pollution Control Cost Manual 6th ED guidance of 2% of capital investment.

Due to the difference in cost basis for all indirect costs, but most particularly administrative costs, the final indirect operating costs were decreased by approximately $10,980,000 per year per boiler from the previous assessment.

OG&E submitted initial cost estimates in 2008 that relied upon a baseline emission rate representative of the maximum actual 24-hour emission rate, which is consistent with the modeling demonstration. Following the methodology published in the EPA advanced notice of proposed rulemaking for the Four Corners Power Plant and the Navajo Generating Station, cost effectiveness calculations were revised to reflect average annual emissions from 2004-2006.

Table 10: Economic Cost for Units 4 and 5 – Dry FGD – Spray Dryer Absorber
Cost	Unit 4	Unit 5
Total Capital Investment ($)	$317,193,600	$317,193,600
Total Capital Investment ($/kW)	$555	$555
Capital Recovery Cost ($/Yr)	$32,861,300	$32,861,300
Annual O&M Costs ($/Yr)	$18,438,900	$18,438,900
Total Annual Cost ($)	$51,300,200	$51,300,200

OG&E Muskogee Generating Station BART Review January 15, 2010

Table 11: Environmental Costs for Units 4 and 5 – Dry FGD – Spray Dryer Absorber
	Unit 4	Unit 5
SO2 Baseline (TPY)1	9,113	9,006
SO2 Controlled (lb/mmBtu)	0.1	0.1
Annual SO2 Controlled (TPY)2	2,160	2,160
Annual SO2 Reduction (TPY)	6,953	6,846
Total Annual Cost ($)	$51,300,200	$51,300,200
Cost per Ton of Reduction	$7,378	$7,493

(1)	Baseline annual emissions are calculated as the average actual SO2 emission rate during the baseline years of 2004-2006.

(2)	Projected annual emissions were calculated based on the controlled SO2 emissions rate, full load heat input of 5,480 mmBtu/hr, and assuming 7,884 hours/year per boiler (90% capacity factor).

Table 12: Environmental Costs for Units 4 and 5 – Wet FGD
	OG&E Cost Estimates
Cost	Unit 4	Unit 5
Total Capital Investment ($)	$418,567,000	$418,567,000
Capital Recovery Cost ($/Yr)	$43,363,541	$43,363,541
Annual O&M Costs ($/Yr)	$21,061,140	$21,061,140
Total Annual Cost ($)	$64,424,681	$64,424,681
Control SO2 Emission Rate (lb/mmBtu)	0.08	0.08
Baseline Annual Emissions (TPY)1	9,113	9,006
Controlled Annual SO2 Emission (TPY)2	1,728	1,728
Annual SO2 Reduction (TPY)	7,385	7,278
Cost per Ton of Reduction ($/Ton)	$8,724	$8,852
Incremental Annual Cost ($/Ton)	$30,381	$30,381

(1)	Baseline annual emissions were calculated based on average annual SO2 emissions for the years 2004-2006.

(2)	Projected annual emissions were calculated based on the controlled SO2 emissions rate, full load heat input of 5,480 mmBtu/hr, and assuming 7,884 hours/year per boiler (90% capacity factor).

OG&E Muskogee Generating Station BART Review January 15, 2010

C. PM10

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES (PM1O)

There are two generally recognized PM control devices that are used to control PM emission from PC boilers: ESPs and fabric filters (or baghouses). Muskogee Units 4 and 5 are currently equipped with ESP control systems.

Table 13: Summary of Technically Feasible
Main Boiler PM10 Control Technologies
	PM10 Emissions 1	% Reduction
Control Technology	(b/mmBtu)	(from base case)
Fabric Filter Baghouse	0.015	99.7
ESP - Existing	0.025	99.3
Potential PM Emissions	5.65	-

(1)

The PM10 emission rate for the baghouse case is based on filterable PM10 emission limits included in recently issued PSD permits for new coal-fired units. The PM10 emission rate for ESP case is based on the Units’ baseline PM10 emission rates. Potential PM emissions were calculated assuming an average fuel heating value of 8,500 Btu/lb and an ash content of 6.0%, and assuming 80% of the fuel ash will be emitted as fly ash.

EVALUATE IMPACTS AND DOCUMENT RESULTS (PM10)

D. VISIBILITY IMPROVEMENT DETERMINATION

The fifth of five factors that must be considered for a BART determination analysis, as required by a 40 CFR part 51-Appendix Y, is the degree of Class I area visibility improvement that would result from the installation of the various options for control technology. This factor was evaluated for the Muskogee Generating Station by using an EPA-approved dispersion modeling system (CALPUFF) to predict the change in Class I area visibility. The Division had previously determined that the Muskogee Generating Station was subject to BART based on the results of initial screening modeling that was conducted using current (baseline) emissions from the facility. The screening modeling, as well as more refined modeling conducted by the applicant, is described in detail below.

Wichita Mountain Wildlife Refuge, Caney Creek, Upper Buffalo and Hercules Glade are the closest Class I areas to the Muskogee Generating Station, as shown in Figure 1 below.

Only those Class I areas most likely to be impacted by the Muskogee Generating Station were modeled, as determined by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. It can be reasonably assumed that areas at greater distances and .in directions of less frequent plume transport will

OG&E Muskogee Generating Station BART Review January 15, 2010

experience lower impacts than those predicted for the four modeled areas.

IMAGE NOT SHOWN

Figure 1: Plot of Facility location in relation to nearest Class I areas

REFINED MODELING

Because of the results of the applicants screening modeling for the Muskogee Generating Station, OG&E was required to conduct a refined BART analysis that included CALPUFF visibility modeling for the facility. The modeling approach followed the requirements described in the Division's BART modeling protocol, CENRAP BART Modeling Guidelines (Alpine Geophysics, December 2005) with refinements detailed the applicants CALMET modeling protocol, CALMET Data Processing Protocol (Trinity Consultants, January 2008)

CALPUFF System

Predicted visibility impacts from the Muskogee Generating Station were determined with the EPA CALPUFF modeling system, which is the EPA-preferred modeling system for long-range transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR Part 51), long-range transport is defined as modeling with source-receptor distances greater than 50 km. Because all modeled areas are located more than 50 km from the sources in question, the CALPUFF system was appropriate to use.

OG&E Muskogee Generating Station BART Review January 15, 2010

system for assessing the effects of time- and space-varying meteorological conditions on pollutant transport, transformation, and removal.

CALPUFF is a multi-layer, Lagrangian puff dispersion model. CALPUPF can be driven by the three-dimensional wind fields developed by the CALMET model (refined mode), or by data from a single surface and upper-air station in a format consistent with the meteorological files used to drive steady-state dispersion models. All far-field modeling assessments described here were completed using the CALPUFF model in a refined mode.

CALPOST is a post-processing program that can read the CALPUFF output files, and calculate the impacts to visibility.

Table 14: Key Programs in CALPUFF System
Program	Version	Level
CALMET	5.53a	040716
CALPUFF	5.8	070623
CALPOST	5.6394	070622

Meteorological Data Processing (CALMET)

The following table lists the key user-defined CALMET settings that were selected.

Table 15: CALMET Variables
Variable	Description	Value
PMAP	Map projection	LCC (▇▇▇▇▇▇▇ Conformal Conic)
DGRIDKM	Grid spacing (km)	4
NZ	Number of layers	12
ZFACE	Cell face heights (m)	0,20,40,60,80,100,150,200,250,500

OG&E Muskogee Generating Station BART Review January 15, 2010

Variable	Description	Value
		1000, 2000, 3500
RMIN2	Minimum distance for extrapolation	-1
IPROG	Use gridded prognostic model outputs	14 km (MM5 data)
RMAX1	Maximum radius of influence (surface layer, km)	20 km
RMAX2	Maximum radius of influence (layers aloft, km)	50km
TERRAD	Radius of influence for terrain (km)	10 km
R1	Relative weighting of first guess wind field and observation (km)	10 km
R2	Relative weighting aloft (km)	25 km

The locations of the upper air stations with respect to the modeling domain are shown in Figure 2.

IMAGE NOT SHOWN

Figure 2: Plot of surface station locations

OG&E Muskogee Generating Station BART Review January 15, 2010

IMAGE NOT SHOWN

Figure 3: Plot of upper air station locations

IMAGE NOT SHOWN

Figure 4. Plot of precipitation observation stations

OG&E Muskogee Generating Station BART Review January 15, 2010

CALPUFF Modeling Setup

Latitude and longitude coordinates for Class I area discrete receptors were taken from the National Park Service (NPS) Class I Receptors database and converted to the appropriate LCC coordinates.

CALPUFF Inputs-Baseline and Control Options

The first step in the refined modeling analysis was to perform visibility modeling for current (baseline) operations at the facility. Emissions of NOx and SO2 for the baseline runs were established based on CEM data and maximum 24-hour emissions averages for years 2001 to 2003.

Baseline source release parameters and emissions are shown in the table below, followed by tables with data for the various control options.

Table 16: Source Parameters
	Baseline1
	Coal-Fired	Coal-Fired
Parameter	Unit 4	Unit 5
Heat Input (mmBtu/hr)	5,480	5,480
Stack Height (m)	106.71	106.71
Stack Diameter (m)	7.32	7.32
Stack Temperature (K)2	430.78	430.78
Exit Velocity (m/s)2	25.40	25.40
Baseline SO2 Emissions (lb/mmBtu)	0.80	0.85
Dry FGD SO2 Emissions (lb/mmBtu)	0.10	0.10
Wet FGD SO2 Emissions (lb/mmBtu)	0.08	0.08
Baseline NOx Emissions (lb/mmBtu)	0.495	0.522
LNB/OFA NOx Emissions (lb/mmBtu)	0.15	0.15
LNB/OFA + SCR NOx Emissions (lb/mmBtu)	0.07	0.07
ESP (Baseline) PM10 Emissions (lb/mmBtu)	0.0184	0.0244
FF PM10 Emissions (lb/mmBtu)	0.012	0.012

1Baseline emissions data were provided by OG&E. Baseline emission rates (lb/mmBtu) were calculated by dividing the maximum 24-hr lb/hr emission rate by the maximum heat input to the boiler.

2Temperature and Velocity were decreased for DFGD and WFGD evaluations. For DFGD, stack temperature was modeled at 359.11K and velocity decreased to 22.77 m/s. For WFGD, stack temperature decreased to 331.89K and velocity decreased to 21.10 m/s.

OG&E Muskogee Generating Station BART Review January 15, 2010

Visibility Post-Processing (CALPOST) Setup

Table 17: Relative Humidity Factors for CALPOST
Month	Wichita Mountains	Caney Creek	Upper Buffalo	Hercules Glade
January	2.7	3.4	3.3	3.2
February	2.6	3.1	3.0	2.9
March	2.4	2.9	2.7	2.7
April	2.4	3.0	2.8	2.7
May	3.0	3.6	3.4	3.3
June	2.7	3.6	3.4	3.3
July	2.3	3.4	3.4	3.3
August	2.5	3.4	3.4	3.3
September	2.9	3.6	3.6	3.4
October	2.6	3.5	3.3	3.1
November	2.7	3.4	3.2	3.1
December	2.8	3.5	3.3	3.3

EPA's default average annual aerosol concentrations for the U.S. that are included in Table 2-1 of EPA's Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program were to develop natural background estimates for each Class I area.

Visibility Post-Processing Results

Table 18: CALPUFF Visibility Modeling Results for Muskogee Units 4 and 5 - NOx

	2001		2002		2003		3-Year Average
Class I Area	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. o f Days > 0.5 ∆dv
Baseline
Wichita Mountains	0.511	8	0.613	9	0.744	12	0.623	10
Caney Creek	0.914	37	0.939	31	1.469	33	1.107	34
Upper Buffalo	1.021	21	0.650	11	0.702	13	0.791	15
Hercules Glade	0.574	10	0.431	5	0.407	4	0.471	6
Scenario 1 – Combustion Control – LNB/OFA
Wichita Mountains	0.154	1	0.176	2	0.225	1	0.185	1
Caney Creek	0.280	1	0.283	1	0.444	4	0.336	2
Upper Buffalo	0.312	3	0.192	1	0.211	2	0.238	2
Hercules Glade	0.164	1	0.129	1	0.119	0	0.137	1

OG&E Muskogee Generating Station BART Review January 15, 2010

Modeling for SCR controls resulted in an approximate 50% reduction in visibility impairment from scenario one.

Table 19: CALPUFF Visibility Modeling Results for Muskogee Units 4 and 5 – SO2

	2001		2002		2003		3-Year Average
Class I Area	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. of Days > 0.5 ∆dv	98th Percentile Value (∆dv)	No. o f Days > 0.5 ∆dv
Baseline
Wichita Mountains	0.939	24	1.208	18	1.218	28	1.122	23
Caney Creek	1.081	34	1.287	40	1.724	50	1.364	41
Upper Buffalo	1.342	27	0.974	22	1.286	34	1.200	28
Hercules Glade	1.145	17	0.898	21	0.845	17	0.963	18
Scenario 1 – Dry FGD
Wichita Mountains	0.117	0	0.148	0	0.165	1	0.143	0
Caney Creek	0.140	0	0.171	0	0.234	2	0.182	1
Upper Buffalo	0.160	0	0.114	1	0.167	0	0.147	0
Hercules Glade	0.119	0	0.122	0	0.101	0	0.114	0

While mass emissions are decreased marginally with Wet FGD controls modeled impacts increase over modeled concentrations in scenario one for all Class I areas but the Wichita Mountains. Wet FGD reduced visibility impairment by a further 1% over Dry FGD. This generally increased degradation is a result of lower stack temperatures and velocities and higher SO4 emission estimates.

▇. ▇▇▇▇ DETERMINATION

NOx

New LNB with OFA is determined to be BART for NOx control for Units 4 and 5 based, in part, on the following conclusions:

1.	Installation of new LNB with OFA was cost effective, with a capital cost of $14,113,700 per unit for units 4 and 5 and an average cost effectiveness of $260-$281 per ton of NOx removed for each unit over a twenty-five year operational life.

OG&E Muskogee Generating Station BART Review January 15, 2010

2.	Combustion control using the LNB/OFA does not require non-air quality environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is minimal energy impact.

3.	After careful consideration of the five statutory factors, especially the costs of compliance and existing controls, NOx control levels on 30-day rolling averages of 0.15 lb/mmBtu for Unit 4 and 5 are justified meet the presumptive limits prescribed by EPA.

4.	Annual NOx emission reductions from new LNB with OFA on Units 4 and 5 are 2,018-2,469 tons for a total annual reduction of 4,487 tons based on actual emissions from 2004-2006 and projected emissions at maximum heat input and 90% capacity.

LNB with OFA and SCR was not determined to be BART for NOx control for Units 1 and 2 based, in part, on the following conclusions:

The cost of compliance for installing SCR on each unit is significantly higher than the cost for LNB with OFA. Additional capital costs for SCR on Units I and 2 are on average $193,077,000 per unit. Based on projected emissions, SCR could reduce overall NOx emissions from Muskogee Units 4 and 5 by approximately 3,456 TPY beyond combustion controls; however, the incremental cost associated with this reduction is approximately $16,611/ton.

2.	Additional non-air quality environmental mitigation is required for the use of chemical reagents.

3.	Operation of LNB with OFA and SCR is parasitic and requires power from each unit.

4.	The cumulative visibility improvement for SCR, as compared to LNB/OFA across Wichita Mountains and Caney Creek (based on the 98th percentile modeled results) was 0.10 and 0.18 ∆dv respectively.

SO2

Continued use of low sulfur coal is determined to be BART for SO2 control for Units 4 and 5 based on the capital cost of add-on controls, the cost effectiveness both in $/ton and $/dv of add-on controls, and the long term viability of coal with respect to other environmental programs, and national commitments.

Installation of DFGD is not cost effective. OG&E's revised cost estimates are based on vendor quotes and go well beyond the default methodology recommended by EPA guidance. The cost estimates are credible, detailed, and specific for the Muskogee facility. The final estimate for both boilers at $634,387,200 is $223,691,200 greater than the high end costs assumed by DEQ in the Draft SIP.

These costs put the project well above costs reported for other BART determinations. The federal land managers have informally maintained a spreadsheet of BART costs and determinations for coal-fired facilities. This spreadsheet indicates that the highest reported cost for control was for the Boardman facility in Oregon at a projected cost of $247,300,000. While there is some uncertainty on whether this cost will ultimately be found to be cost effective, it is much lower than the cost of controlling a single boiler at the Muskogee facility ($317,193,600). Most assessments were based on costs of less than $150,000,000 and related cost effectiveness numbers of $3,053/ton removed for ▇▇▇▇▇▇▇▇ to an average of less than $2,000/ton for the other determinations tracked by the FLMs.

OG&E Muskogee Generating Station BART Review January 15, 2010

Table 20 provides a summary of the baseline SO2 emission rates included in several BART evaluations.

Table 20: Comparison of Baseline SO2 Emissions at Several BART Units

Station	Baseline S02 Emission Rate (lb/mmBtu)	Baseline S02 Emissions (TPY)
Muskogee Unit 4	0.507	9,113
Muskogee Unit 5	0.514	9,006
Sooner Unit 1	0.509	9,394
Sooner Unit 2	0.516	8,570
NPPD ▇▇▇▇▇▇ Gentleman Unit 1	0.749	24,254
NPPD ▇▇▇▇▇▇ Gentleman Unit 2	0.749	25,531
White Bluff Unit 1	0.915	31,806
White Bluff Unit 2	0.854	32,510
▇▇▇▇▇▇▇▇ unit 1	0.614	14,902
Northeastern Unit 3	0.900	16,000
Northeastern Unit 4	0.900	16,000
▇▇▇▇▇▇▇▇ Unit 1	1.180	8,624
▇▇▇▇▇▇▇▇ Unit 2	1.180	11,187
OPPD Nebraska City Unit 1	0.815	24,191

Assuming total annual costs and projected emissions are similar and thereby setting aside the issues related to pre-2008 cost estimates and the ability to compare them to December 2009 estimates, cost effectiveness will be a function of the baseline emissions. This holds true for units firing subbituminous coals with baseline SO2 emissions rates in the range of 0.5 lb/mmBtu to approximately 2.0 lb/mmBtu, because removal efficiencies achievable with DFGD control will vary based on inlet SO2 loading. In general, DFGD control systems are capable of achieving higher removal efficiencies on units with higher inlet SO2 loading. DFGD control systems will be more cost effective on units with higher baseline SO2emissions because the control systems will be capable of achieving higher removal efficiencies and remove more tons of SO2 per year for similar costs. Conversely, DFGD will be less cost effective, on a $/ton basis, on units with lower SO2 baseline emissions. On the basis of baseline emissions alone, with all other factors being equal, the cost effectiveness of the OG&E units would be about 55 to 185% higher than the other units listed, i.e., less cost effective.

The average cost effectiveness at Muskogee for DFGD is $7,378-$7,493 per ton of SO2 removed for each unit over a twenty year operational life. The cost of this control at the Muskogee facility is well above the average cost effectiveness reported for similar BART projects, well above costs associated with BACT determinations for SO2, and well above the cost of control originally contemplated in the Regional Haze Rule.

From the FLM BART tracking spreadsheet, the average cost effectiveness in $/dv was $5,700,000/dv. The addition of DFGD at the Muskogee Facility was anticipated to reduce impairment by 4.217 dv. Importantly, the cost effectiveness of that improvement is now calculated to be $24,330,000/dv.

OG&E Muskogee Generating Station BART Review January 15, 2010

A majority of the Class I areas are located in the western part of the U.S. Simply due to the number of Class I areas in the west, it is likely that a BART applicable unit located in the western U.S. will be closer to a Class I area, and that emissions from the unit will affect visibility at more Class I areas. For example, the ▇▇▇▇▇▇▇▇ Generating Station located in the north central region approximately 150 miles east of Portland, is located within 300 km of 14 Class I areas. By comparison the Muskogee station is located with 300 km of 14 Class I areas. Using the sum of modeled visibility improvements at all 14 Class I areas, cost effectiveness of the DFGD control system would be $3,690,510/dv or 6.5 times more cost effective than DFGD controls at the Muskogee facility. The federal land managers have indicated that costs effectiveness numbers of less than $10,000,000/dv should be considered cost effective. While this does not prohibit a determination of cost effectiveness at numbers greater than $10,000,000/dv, it does imply that numbers greater than that should receive greater consideration.

An investment of this magnitude to install DFGD on an existing coal-fired power plant effectively guarantees the continued use of coal as the primary fuel source for energy generation in this facility and arguably the state for the next 20 years and beyond. Therefore, a determination in support of DFGD ignores the Obama Administration's stated agenda to control carbon dioxide and other green house gases by restricting the alternatives left open to OG&E and hence the ratepayers of Oklahoma. Substantial uncertainty currently exists about the nature and costs of future federal carbon controls on power plants, including the level of stringency, timing, emissions allowance allocation and prices, and whether and to what degree emissions "offsets" are allowed. Further, new federal MACT mercury control requirements may be imposed on the Muskogee facility that would be more stringent than the scrubber can deliver. Fortunately, other technology options now exist that would likely achieve greater mercury reductions at lower cost than the scrubber. If EPA determines that MACT requires greater reductions than those achieved through DFGD, then ratepayers would be at risk to pay for additional required mercury control technology.

The cost for DFGD is too high, the benefit too low and these costs, if borne, further extend the life expectancy of coal as the primary fuel in the Muskogee facility for at least 20 years and beyond. BART is the continued use of low sulfur coal.

Wet FGD was not determined to be BART for SO2 control for Units 3 and 4 based, in part, on the following conclusions:

The cost of compliance for installing WFGD on each unit is higher than the cost for DFGD. Based on projected emissions, WFGD could reduce overall SO2 emissions from Muskogee Units 4 and 5 by approximately 864 TPY beyond dry scrubbers; however, the incremental cost associated with this reduction is approximately $30,381/ton.

3.	Wet FGD systems must be located downstream of the unit's particulate control device;

OG&E Muskogee Generating Station BART Review January 15, 2010

therefore, dissolved solids from the wet FGD system will be emitted with the wet FGD plume. Wet FGD control systems also generate lower stack temperatures that can reduce plume rise and result in a visible moisture plume.

4.	Wet FGD systems use more reactant (e.g., limestone) than do dry systems, therefore the limestone handling system and storage piles will generate more fugitive dust emissions.

6.	Because of a slower exit velocity, lower slack temperature and higher S04 emissions associated with Wet FGD, visibility impairment was found to higher under this control strategy than the Dry FGD for three of four Class I areas.

PM10

The existing ESP control is determined to be BART for PM10 controls for Units 4 and 5 based on the determination of low sulfur coal and the high cost of fabric filters relative to the low actual emissions of PM10 from the facility.

Table 21: Unit-by-unit BART determinations

Control	Unit 4	Unit 5
NOx Control	New LNB with OFA	New LNB with OFA
Emission Rate (lb/mmBtu)	0.15 lb/mmBtu (30-day rolling average)	0.15 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	822 lb/hr (30-day rolling average)	822 lb/hr (30-day rolling average)
Emission Rate TPY	3,600 TPY (12-month rolling)	3,600 TPY (12-month rolling)
S02 Control	Low Sulfur Coal	Low Sulfur Coal
Emission Rate (lb/mmBtu)	0.65 lb/mmBtu (30-day rolling average)	0.65 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	3,562 lb/hr (30-day rolling average)	3,562 lb/hr (30-day rolling average)
Annual Emission Rate (lb/mmBtu)	0.55 lb/mmBtu (annual average)	0.55 lb/mmBtu (annual average)
Emission Rate TPY	18,096 TPY
PM10 Control	Existing ESP	Existing ESP
Emission Rate (lb/mmBtu)	0.1 lb/mmBtu	0.1 lb/mmBtu
Emission Rate lb/hr	548 lb/hr	548 lb/hr
Emission Rate TPY	2,400 TPY (12-month rolling average)	2,400 TPY (12-month rolling average)

OG&E Muskogee Generating Station BART Review January 15, 2010

F. CONTINGENT BART DETERMINATION

In the event that EPA disapproves the BART Determination referenced above in regard to the DEQ determination that DFGD with SDA is not cost-effective for S02 control, the low-sulfur coal requirement in the BART determination for S02 and the related ESP requirement for PM referenced above shall be replaced with a requirement that Muskogee Units 4 and 5 install DFGD with SDA for S02 control and fabric filters for PM control or meet the corresponding S02 and PM10 emission limits listed below by December 31, 2018 or comply with the approved alternative described in section G (Greater Reasonable Progress Alternative).

Table 22: Unit-by-unit Contingent BART determinations

Control	Unit 4	Unit 5
S02 Control	DFGD w/SDA	DFGD w/SDA
Emission Rate (lb/mmBtu)	0.1 lb/mmBtu (30-day rolling average)	0.1 lb/mmBtu (30-day rolling average)
Emission Rate lb/hr	548 lb/hr (30-day rolling average)	548 lb/hr (30-day rolling average)
Emission Rate TPY	2,400 TPY	2,400 TPY
PM10 Control	Fabric Filter	Fabric Filter
Emission Rate (lb/mmBtu)	0.015 lb/mmBtu	0.015 lb/mmBtu
Emission Rate lb/hr	82 lb/hr	82 lb/hr
Emission Rate TPY	360 TPY (12-month rolling average)	360 TPY (12-month rolling average)

The "contingent" BART as defined here and in conjunction with the greater reasonable progress alternative recognizes the long term importance of achieving reductions in S02 while addressing the need for operational flexibility in response to the eventualities of a federal carbon trading program and mercury MACT in the nearer term. It must be understood that DEQ has determined that DFGD is not cost effective. However, if EPA chooses to ignore that element of the BART determination, DEQ does agree that DFGD remains a technically feasible control option for S02 reductions.

Switching from coal to natural gas, while physically possible constitutes a significant modification to a facility process not contemplated by the regional haze rule. However, exploring some combination of both options, while allowing the uncertainty surrounding other federal environmental programs to settle, is a more equitable alternative for the ratepayers in Oklahoma than requiring an overly costly control merely to achieve limited reductions while simultaneously solidifying the use of dirty technology from now into the foreseeable future.

G. GREATER REASONABLE PROGRESS ALTERNATIVE DETERMINATION

In lieu of installing and operating BART for S02 and PM control at Sooner Units 1 and 2 and Muskogee Units 4 and 5, OG&E may elect to implement a fuel switching alternative. The greater reasonable progress alternative requires OG&E to achieve a combined annual S02 emissions limit (identified in table 23) by installing and operating DFGD with SDA on two of the four boilers and being at or below the S02 emission that would result from switching the

OG&E Muskogee Generating Station BART Review January 15, 2010

remaining two boiler to natural gas. Under this alternative OG&E shall install the controls (i.e., DFGD with SDA or achieve equivalent emissions) by December 31, 2026. By adopting these emission limits, DEQ and OG&E expect the cumulative S02 emissions from Sooner Units 1 and 2 and Muskogee Units 4 and 5 to be approximately 57% less than would be achieved through the installation and operation of DFGD with SDA at all four units (assuming 90% capacity).

Table 23: S02 Emissions with Greater Reasonable Progress

	Muskogee	Sooner
Parameter	Unit 4 and Unit 5	Unit 1 and Unit 2
BART (Low Sulfur Coal)	18,096 TPY	19,736 TPY
Contingent BART (DFGD)	4,800 TPY	4,482 TPY
GRP (DFGD/Natural Gas)	3,600 TPY

Under no circumstance will the Greater Reasonable Progress Plan result in less visibility improvement than would be achieved either through the DEQ determined BART or the "contingent" BART. By allowing the installation of S02 controls to be delayed, current regulatory hurdles to long term natural gas contracts can be addressed and the best interests of the ratepayers and visitors to our Class I areas can be preserved for the long term 2064 goal of natural visibility.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD)

Muskogee Generating Station is a major source under OAC 252:100-8 Permits for Part 70 Sources. Oklahoma Gas and Electric should comply with the permitting requirements of Subchapter 8 as they apply to the installation of controls determined to meet ▇▇▇▇.

The installation of controls determined to meet ▇▇▇▇ will not change NSPS or NESHAP/MACT applicability for the gas-fired units at the Muskogee Station. The permit application should contain PM10 and PM2.5 emission estimates for filterable and condensable emissions.

VI. OPERATING PERMIT

The Muskogee Generating Station is a major source under OAC 252:100-8 and has submitted an application to modify their existing Title V permit to incorporate the requirement to install controls determined to meet ▇▇▇▇. The Permit will contain the following specific conditions:

1.	The boilers in EUG 3 are subject to the Best Available Retrofit Technology (BART) requirements of 40 CFR Part 51, Subpart P, and shall comply with all applicable requirements including but not limited to the following: [40 CFR §§ 51.300-309 & Part 51, Appendix Y]

a.	Affected facilities. The following sources are affected facilities and are subject to the requirements of this Specific Condition, the Protection of Visibility and Regional Haze Requirements of 40 CFR Part 51, and all applicable SIP requirements:

OG&E Muskogee Generating Station BART Review January 15, 2010

EU ID#	Point ID#	EU Name	Heat Capacity (MMBTUH)	Construction Date
3-B	01	Unit 4 Boiler	5,480	1972
3-B	02	Unit 5 Boiler	5,480	1972

b.	Each existing affected facility shall install and operate the SIP approved BART as expeditiously as practicable but in no later than five years after approval of the SIP incorporating BART requirements.

c.	The permittee shall apply for and obtain a construction permit prior to modification of the boilers. If the modifications will result in a significant emission increase and a significant net emission increase of a regulated NSR pollutant, the applicant shall apply for a PSD construction permit.

d.	The affected facilities shall be equipped with the following current combustion control technology, as determined in the submitted BART analysis, to reduce emissions of NOx to below the emission limits below:

i. Low-NOx Burners,

ii. Overfire Air.

e.	The permittee shall maintain the controls (Low-NOx burners, overfire air, dry) and establish procedures to ensure the controls are properly operated and maintained.

EU ID#	Point ID#	NOx Emission Limit	S02 Emission Limit	Averaging Period
3-B	01	0.15 lb/mmBtu	0.65 lb/mmBtu	30-day rolling
3-B	02	0.15 lb/mmBtu	0.65 lb/mmBtu	30-day rolling

EU ID#	Point ID#	PM10
3-B	01	0.1 lb/mmBtu
3-B	02	0.1 lb/mmBtu

EU ID#	Point ID#	S02 Emission Limit	S02 Emission Limit	Averaging Period
3-B	01	18,096 TPY	0.55 lb/mmBtu	Annual rolling
3-B	02	18,096 TPY	0.55 lb/mmBtu	Annual rolling

g.	Boiler operating day shall have the same meaning as in 40 CFR Part 60, Subpart Da.

h.	Within 60 days of achieving maximum power output from each boiler, after modification of the boilers, not to exceed 180 days from initial start-up, the

OG&E Muskogee Generating Station BART Review January 15, 2010

i.	The permittee shall conduct SO2, NOx, PM10, PM2.5, CO, and VOC testing on the boilers at 60% and 100% of the maximum capacity. NOX and CO testing shall also be conducted at least one additional intermediate point in the operating range.

ii.

Oklahoma Department of Environmental Quality Air Quality Division

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