DEPARTMENT OF NATURAL RESOURCES AND ENVIRONMENTAL CONTROL

Division of Air and Waste Management

Statutory Authority: 7 Delaware Code, Chapter 60 (7 Del.C., Ch. 60)

7 DE Admin. Code 1146

FINAL

Secretary’s Order No. 2009-A-0032

Amending 7 DE Admin. Code 1146 (Electric Generating Unit (EGU) Multipollutant Regulation Table 5-1)

Date of Issuance: September 1, 2009

Effective Date: October 10, 2009

Under the authority vested in the Secretary of the Department of Natural Resources and Environmental Control (Department), the following findings, reasons and conclusions are entered as an Order of the Secretary in the above-referenced matter.

Procedural History

On February 22, 2009, the Department’s issued Start Action Notice #2009-04, which approved Division of Air and Waste Management, Air Quality Management Section’s (AQMS) request to begin the formal regulatory development process to amend 7 DE Admin. Code Regulation 1146 (Regulation). AQMS prepared a proposed regulation revising Table 5-1 (Annual SO2 Mass Emissions Limits) to increase the mass annual limits for Conectiv Delmarva Generation, Inc.’s (Conectiv) electric generation station’s unit 5 (Facility) located in Edge Moor, New Castle County (Facility). The revision would increase the sulfur dioxide (SO2) annual limit from 2,427 tons to 4,600 tons.

The Department had the proposed regulation published in the May 1, 2009 Delaware Register of Regulations and notice was published in newspapers of general circulation. The Department also provided public notice of a May 26, 2009 public hearing to be held in AQMS’ office in Dover before presiding Hearing Officer Robert P. Haynes.

In a June 29, 2009 technical response memorandum (TRM) to Mr. Haynes, AQMS explained in detail the operational history and basis for the proposed amendment, namely, that the proposed amendment should not result in any actual increase in the Facility’s air emissions of SO2 under normal operating conditions. In the Hearing Officer’s Report, dated August 25, 2009, (Report) and attached hereto as Appendix A, Mr. Haynes recommends the record include AQMS’ TRM, the transcript and the hearing exhibits. Mr. Haynes reviewed the public comments on the proposed amendment, which raised certain questions that were answered by the TRM. Mr. Haynes found ample support in the recommended record for the proposed amendment. He recommends approval of the proposed amendment in Appendix B to the Report, which is the same proposed amendment as published in the May 1, 2009 Delaware Register of Regulations.

Findings

The Report recommends that the proposed regulation be adopted as reasonable and adequately supported on the recommended record developed. I agree with the Report and its recommendations and incorporate it as part of this Order. The reason for the proposed amendment was the resolution of litigation that challenged Regulation 1146, which imposed significant emissions limits on Delaware’s largest sources of stationary air pollutants, namely, large electric generating units. Thus, resolving the challenge to Regulation 1146 is an important benefit to Delaware because when the Department approved Regulation 1146 it cited the substantial pollution reductions, including lowering air emissions of sulfur dioxide by 53%, nitrogen oxides emissions by 24%, and mercury emissions by 82%. Thus, this state-wide significant environment benefit could be threatened if Regulation 1146 was successfully challenged on appeal by Conectiv.

I find that the Department’s experts in AQMS explained in detail the reasons supporting the proposed amendment, which were the settlement of litigation between Conectiv and the Department that resolved Conectiv’s appeal of the Department’s Regulation 1146, as adopted by Secretary’s Order No. 2006-A-0056 (November 15, 2006). Moreover, the Department’s agreed to the settlement because its experts concluded that the proposed amendment would not result in any more emissions being released than under the current SO2 limit that is subject to the amendment. The experts based their opinion on an analysis of the Facility’s operating history and the economics of using low sulfur fuel oil to generate electricity.

I agree with the Department’s experts and find that the proposed regulation is well-supported and reflects the terms of the reasonable settlement to resolve Conectiv’s litigation of Regulation 1146. Regulation 1146 was an important action the Department took to reduce air emissions of harmful pollutants from Delaware’s largest stationary sources of air pollution, namely, large electric generating units. The settlement with Conectiv resolved the uncertainty that the Department face in the appeal that could have resulted in having Regulation 1146 possibly overturned by the court. I also find that the Department’s experts in AQMS have independently determined that the proposed revision under normal operating condition will not result in more SO2 air emissions to occur. This forecast in little actual change in air emissions is reasonably based upon the experts’ analysis of the Facility’s operating history and the economics of burning low sulfur oil to generate electricity. Thus, the Department’s experts conclude that the operating history and economics in the future will keep the Facility from operating a capacity level that will cause it to emit SO2 anywhere near the higher 4,600 tons per year limit.

Regulation 1146 requires the Facility to burn low (.5%) sulfur residual oil, which will further protect the environment and impose operating restrictions on the Facility’s use based upon economics versus other fuels used to generate electricity. The record also has information on the other terms of the settlement that support the amendment as beneficial to the environment, such as advancing the date for lower mercury emissions from the Facility. The Department’s failure to approve of the proposed amendment could constitute possible grounds for Conectiv to claim that the Department was not complying with the terms of the December 2008 settlement. The Department considers that the settlement is reasonable to resolve the litigation on mutually acceptable terms that will result in little risk of SO2 emissions occurring more than in the current levels. Thus, I find that the proposed regulation should be adopted as reasonable and well-supported by the technical analysis in the record.

Conclusions

For the above-stated reasons, I conclude that the Department should approve as a final regulation the proposed amendment to Regulation 1146 to reflect the terms of the settlement of the litigation of Regulation 1146. Consequently, the following is ordered:

1. The Department, acting through this Order of the Secretary, hereby approves as a final regulation the proposed regulation that amends Table 5-1 and the record developed to support it, as described in the Report; and

2. The Department shall have this Order published in the Delaware Register of Regulations and in newspapers in the same manner as the notice of the proposed regulation and serve notice of this action upon those interested person as determined by the Department.

Collin P. O’Mara,

Secretary

12/11/2006

1.0 Preamble

This regulation establishes Nitrogen Oxides (NOx), Sulfur Dioxide (SO2),and mercury emissions limits to achieve reductions of those pollutants from Delaware’s large electric generation units. The reduction in NOX, SO2, and mercury emissions will: 1) reduce the impact of those emissions on public health; 2) aid in Delaware’s attainment of the State and National Ambient Air Quality Standard (NAAQS) for ground level ozone and fine particulate matter; 3) help address local scale fine particulate and mercury problems attributable to coal and residual oil-fired electric generating units, 4) satisfy Delaware’s obligations under the Clean Air Mercury Rule (CAMR), and 5) improve visibility and help satisfy Delaware’s EGU-related regional haze obligations.

While the purpose of this regulation is to reduce air emissions, any emission control equipment installed to meet the requirements of this regulation may impact other media (e.g., water), and any overall environmental impacts must be considered by subject entities when they design their overall compliance strategy. Any emission controls installed to meet the requirements of this regulation will be subject to public review and comment through air permitting requirements of 7 DE Admin. Code 1102 and 1130.

Separate from this regulation the Department will propose regulations to address CO2 emissions from these units, and regulations to satisfy direct fine particulate matter Reasonably Available Control Technology (RACT) and Best Available Retrofit Technology (BART) requirements. Together, these regulations will cover current and foreseeable requirements relative to the subject units.

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2.0 Applicability

This regulation applies to coal-fired and residual oil-fired electric generating units located in Delaware with a nameplate capacity rating of 25 MW or greater that commenced operation on or before the effective date of this regulation.

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3.0 Definitions

The following words and terms, when used in this regulation, shall have the following meanings:

“Administrator” means the Administrator of the United States Environmental Protection Agency or the Administrator’s duly authorized representative.

“Coal” means any solid fuel classified as anthracite, bituminous, sub-bituminous, or lignite.

“Coal-fired” means combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of other fuel, during any year.

“Department” means the State of Delaware Department of Natural Resources and Environmental Control as defined in 29 Del.C., Ch 80, as amended.

“Designated representative” means the natural person who is authorized by the owners and operators of the source and all units at the source to legally bind each owner and operator in matters pertaining to this regulation. If the source subject to this regulation is also subject to the Federal Acid Rain Program, then this natural person shall be the same person as the designated representative under the Acid Rain Program.

“Emissions” means air pollutants exhausted from a unit or source into the atmosphere.

“Generator” means a device that produces electricity.

“Heat input” means the product (in MMBTU/time or TBTU/time) of the gross calorific value of the fuel (in MMBTU/lb or TBTU/lb) and the fuel feed rate (in lb of fuel/time) into a combustion device; or as calculated by any other method approved by the Department and the Administrator, and does not include the heat derived from pre-heated combustion air, recirculated flue gasses, or exhaust from other sources.

“Inlet mercury” means the average concentration of mercury in the flue gas at the inlet to any pollution control device or devices.

“Nameplate capacity” means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other de-ratings) as specified by the manufacturer of the generator or, starting from the completion of any physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other de-ratings), such increased maximum amount as specified by the person conducting the physical change.

“Operator” means any person who operates, controls, or supervises a unit or source subject to this regulation and shall include, but not be limited to, any holding company, utility system, or plant manager of such unit or source.

“Ounce” means 28.4 grams.

“Owner” means: A) any holder of any portion of the legal or equitable title in a unit; B) any purchaser of power from a unit under a life-of-the-unit, firm power contractual arrangement; provided that, unless expressly provided for in a leasehold agreement, owner shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly) on the revenues or income from the unit.

“Residual oil” means No. 5 or No. 6 fuel oil.

“Ton” means 2000 pounds.

“Unit” means, for the purposes of this regulation, a stationary, fossil-fuel-fired boiler supplying all or part of its output to an electric generating device.

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4.0 NOX Emissions Limitations

4.1 From May 1, 2009 through December 31, 2011, no unit subject to this regulation shall emit NOx at a rate exceeding 0.15 lb/MMBTU.

4.1.1 Compliance with the requirements of 4.1 of this regulation shall be demonstrated on a rolling 24-hour average basis.

4.1.2 NOx emissions from multiple units subject to this regulation at a common facility may be averaged on a heat input basis to demonstrate compliance with the requirements of 4.1 of this regulation.

4.2 On and after January 1, 2009, no unit subject to this regulation shall emit annual NOx mass emissions that exceed the values shown in Table 4-1 of this regulation.

4.2.1 From January 1, 2009 through December 31, 2011, compliance with the requirements of 4.2 of this regulation may be achieved by demonstrating that the total number of tons of NOX emitted from a common facility does not exceed the sum of the tonnage limitations for all of the units subject to this regulation at that facility.

4.2.2 Compliance with the requirements of 4.2 of this regulation shall not be achieved by using, tendering, or otherwise acquiring NOx allowances under any state or federal emission trading program.

4.2.3 For the purpose of determining compliance with the requirements of 4.2. of this regulation, the total tons for a specified period shall be calculated as the sum of all recorded hourly emissions, with any remaining fraction of a ton equal to or greater than 0.50 ton deemed to equal one ton and any remaining fraction of a ton less than 0.50 ton deemed equal to zero tons.

4.3 On and after January 1, 2012, no unit subject to this regulation shall emit NOx at a rate exceeding 0.125 lb/MMBTU, demonstrated on a rolling 24-hour average basis.

4.4 Compliance with the requirements of 4.1 through 4.3 of this regulation shall be demonstrated with a continuous emissions monitoring system that is installed, calibrated, operated, and certified in accordance with 40 CFR Part 75 (May 18, 2005 amendment) or other method approved by the Department and the Administrator, and meeting the requirements of 40 CFR Part 96, subpart HH (April 28, 2006 amendment).

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5.0 SO2 Emissions Limitations

5.1 From May 1, 2009 though December 31, 2011, no coal fired unit subject to this regulation shall emit SO2 at a rate exceeding 0.37 lb/MMBTU heat input.

5.1.1 Compliance with the requirements of 5.1 of this regulation shall be demonstrated on a 24-hour rolling average basis.

5.1.2 SO2 emissions from multiple units subject to this regulation at a common facility may be averaged on a heat input basis to demonstrate compliance with the requirements of 5.1 of this regulation.

5.2 On and after January 1, 2012, no coal-fired unit subject to this regulation shall emit SO2 at a rate exceeding 0.26 lb/MMBTU heat input, demonstrated on a rolling 24-hour average basis.

5.3 On and after January 1, 2009, no unit subject to this regulation shall emit annual SO2 mass emissions that exceed the values shown in Table 5-1 of this regulation.

5.3.1 From January 1, 2009 through December 31, 2011, compliance with the requirements of 5.3 of this regulation may be achieved by demonstrating that the total number of tons of SO2 emitted from a common facility does not exceed the sum of the tonnage limitations for all of the units subject to this regulation at that facility.

5.3.2 Compliance with the requirements of 5.3 of this regulation shall not be achieved by using, tendering, or otherwise acquiring SO2 allowances under any state or federal emission trading program.

5.3.3 For the purpose of determining compliance with the requirements of 5.3 of this regulation, the total tons for a specified period shall be calculated as the sum of all recorded hourly emissions, with any remaining fraction of a ton equal to or greater than 0.50 ton deemed to equal one ton and any remaining fraction of a ton less than 0.50 ton deemed equal to zero tons.

5.4 Compliance with the requirements of 5.1 through 5.3 of this regulation shall be demonstrated with a continuous emissions monitoring system that is installed, calibrated, operated and certified in accordance with 40 CFR Part 75 (May 18, 2005 amendment) or other method approved by the Department and the Administrator, and meeting the monitoring and reporting requirements of 40 CFR Part 96, subpart HHH (April 28, 2006 amendment).

5.5 On and after January 1, 2009, no residual oil with a sulfur content in excess of 0.5%, by weight, shall be received for any residual oil-fired unit subject to this regulation.

5.5.1 Compliance with the requirements of 5.5 of this regulation shall be demonstrated by fuel oil sampling and analysis. Samples shall be collected:

5.5.1.1 From the transport vessel for each shipment of residual fuel oil received at the facility for combustion in the subject residual oil-fired unit, or

5.5.1.2 From the supply pipeline each day residual oil is delivered to the facility via pipeline for combustion in a residual oil-fired unit subject to this regulation, after sufficient fuel oil has been drained from the sampling line to remove any fuel oil that may have been standing in the sampling line, or

5.5.1.3 From the supply pipeline at the inlet to the residual oil-fired unit subject to this regulation each day the unit fires any quantity of oil fuel, after sufficient fuel oil has been drained from the sampling line to remove any fuel oil that may have been standing in the sampling line.

5.5.2 Fuel oil samples shall be analyzed in accordance with ASTM D 129-00, ASTM D 1552-03, ASTM D 2622-05, or ASTM D 4294-03.

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6.0 Mercury Emissions Limitations

6.1 From January 1, 2009 through December 31, 2012, any coal-fired unit subject to this regulation shall, on a quarterly average basis:

6.1.1 Emit mercury at a rate that does not exceed 1.0 lb/TBTU heat input, or

6.1.2 Capture and control a minimum 80% of baseline inlet mercury emissions.

6.2 On or after January 1, 2013, any coal-fired unit subject to this regulation shall, on a quarterly average basis:

6.2.1 Emit mercury at a rate that does not exceed 0.6 lb/TBTU heat input, or

6.2.2 Capture and control a minimum 90% of baseline inlet mercury emissions.

6.3 Annual mercury mass emissions from the coal-fired units subject to this regulation shall not exceed the values shown in Table 6-1 of this regulation.

6.3.1 Compliance with the requirements of 6.3 of this regulation shall be demonstrated on an annual basis.

6.3.2 Compliance with the requirements of 6.3 of this regulation shall not be achieved by using, tendering, or otherwise acquiring mercury allowances under any state or federal emissions trading program.

6.4 Compliance with the requirements of 6.1 through 6.3 of this regulation shall be demonstrated as follows:

6.4.1 Compliance with the requirements of 6.1.1, 6.2.1 and 6.3 of this regulation shall be demonstrated with a continuous emissions monitoring system that is installed, calibrated, operated, and certified in accordance with 40 CFR Part 75 (May 18, 2005 amendment) and meeting the monitoring and reporting requirements of 40 CFR Part 60 (June 9, 2006 amendment).

6.4.2 Compliance with the requirements of 6.1.2 and 6.2.2 of this regulation shall be demonstrated as follows:

6.4.2.1 During the period January 1, 2007 through March 31, 2008, the owner or operator shall conduct at least four quarterly stack tests to measure the mercury in the flue gas stream.

6.4.2.1.1 Except as provided for in 6.4.2.1.2 of this regulation, the test sampling location shall be located upstream of any pollution control device.

6.4.2.1.2 The sampling location may be located downstream of any SNCR injection points.

6.4.2.2 There shall be at least three valid stack tests per quarter and at least 45 days between stack tests performed for a given quarter and the stack tests performed for the preceding quarter, unless otherwise approved by the Department.

6.4.2.3 Each stack test shall be conducted in accordance with a testing protocol approved by the Department. Proposed test protocols shall be submitted to the Department no less than 90 days prior to conducting the mercury tests.

6.4.2.4 The baseline inlet mercury emission rate for the affected unit, in lb/TBTU, shall be determined as the arithmetic average of the quarterly stack tests conducted on that unit in accordance with 6.4.2.1 of this regulation.

6.4.2.5 No later than June 1, 2008, the owner or operator shall submit a petition to the Department requesting the establishment of a unit specific mercury emission rate limit. As a minimum, the report shall contain the following information:

6.4.2.5.1 Identification and brief description of the affected unit.

6.4.2.5.2 A list and brief description of all emissions control equipment installed on the affected unit at the time of the stack tests, including operating status at the time of the stack tests.

6.4.2.5.3 An accounting of all fuels and fuel quality being fired during the emissions tests.

6.4.2.5.4 Results of each quarterly mercury emissions tests.

6.4.2.5.5 Proposed mercury emission limits that are no greater than 20% of the baseline uncontrolled mercury emission rate determined in accordance with 6.4.2 of this regulation for the annual periods January 1, 2009 through December 31, 2012, and no greater than 10% of the baseline uncontrolled mercury emission rate determined in accordance with 6.4.2 of this regulation for the annual periods starting January 1, 2013 and beyond.

6.4.2.5.6 Summary description of the actions anticipated by the owner or operator of the affected unit to attain compliance with the proposed mercury emission limits.

6.4.2.6 The owner or operator of the affected unit shall submit to the Department any additional information requested by the Department necessary for review and approval of the petition.

6.4.2.7 The Department shall establish, for the affected unit, a unit specific mercury emission rate no greater than 20% of the unit’s baseline uncontrolled mercury emissions rate for the period January 1, 2009 through December 31, 2012, and no greater than 10% of the unit’s baseline uncontrolled mercury emission rate for the period January 2013 and beyond.

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7.0 Recordkeeping and Reporting

7.1 The owner or operator of a unit subject to this regulation shall comply with all applicable recordkeeping and reporting requirements of 40 CFR Part 75 (May 18, 2005) and this regulation.

7.2 The owner or operator of a unit subject to this regulation shall maintain, for a period of at least five years, copies of all measurements, tests, reports, and other information required by 40 CFR Part 75 (May 18, 2005 amendment) and this regulation. This information shall be provided to the Department upon request at any time.

7.3 After January 1, 2009, the owner or operator of a unit subject to this regulation shall submit to the Department semi-annual reports in conjunction with the reporting requirements of 7 DE Admin. Code 1130. The semi-annual reports shall contain, as a minimum, the following information:

7.3.1 Tabulation of emission monitoring results reduced to one-hour averages, on a clock basis, for the period in units consistent with the applicable emission standard.

7.3.2 In addition to the requirements of 8.3.1 of this regulation, the following calculations shall be made and reported in the semi-annual report:

7.3.2.1 For mass emission standards based on daily limits, the daily mass emission on a calendar day basis for each day in the period, in units consistent with the applicable emission standard.

7.3.2.2 For mass emissions based on an annual limit, the calendar year-to-date summation of mass emissions through the period being reported, in units consistent with the applicable emission standard.

7.3.2.3 For emission rate averaging, identification of the units being averaged, hourly heat input of the respective units, hourly emission rate of the respective units, and the hourly combined heat input weighted emission average for the affected units.

7.3.3 Identification of any period or periods of, and cause for, any invalid data averages.

7.3.4 Records of any repairs, adjustment, or maintenance to the monitoring system.

7.3.5 The results of all fuel oil sulfur analysis.

7.3.6 Identification of any exceedance of any emission standard provided by this regulation, cause of the exceedance, and corrective action taken in response to the exceedance.

7.3.7 Results from all tests, audits, and recalibrations performed during the period.

7.3.8 Any other relevant data requested by the Department.

7.3.9 A statement, “I am authorized to make this submission on behalf of the owners and operators of the affected facility or affected units for which this submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge true, accurate and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”

7.3.10 Signature by the designated representative.

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8.0 Compliance Plan

8.1 The owner or operator of a unit subject to this regulation shall submit a compliance plan to the Department on or before July 1, 2007.

8.2 The compliance plan shall contain, at a minimum, the following information:

8.2.1 Identification of the subject unit.

8.2.2 A description of any existing NOX, SO2, or mercury emissions control technologies installed on the unit, including identification of the initial installation date of the control technologies.

8.2.3 Identification of the requirements of this regulation applicable to the unit.

8.2.4 A description of the plan or methodology that will be utilized to demonstrate compliance with this regulation.

8.2.5 Identification of emission control technologies, or modifications to existing emission control technologies, that will be utilized to comply with the applicable emissions limitations of this regulation. This shall include:

8.2.5.1 A description of the control technology and its applicability to the subject unit.

8.2.5.2 The design control effectiveness or design emission rate following installation of the emission control technology on the subject unit.

8.2.5.3 Estimated dates for start of construction, start-up of the emissions control technology, and estimated project completion date.

8.2.6 A description of the emissions monitoring methodology to be utilized for demonstrating compliance with the emissions limitations of this regulation, including estimated installation dates, start-up dates, and testing dates.

8.2.7 Identification of any planned changes to administrative or operating procedures or practices intended to achieve compliance with applicable emissions limitations of this regulation.

8.2.8 Any other relevant information requested by the Department.

8.2.9 A statement, “I am authorized to make this submission on behalf of the owners and operators of the affected facility or affected units for which this submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge true, accurate and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”

8.2.10 Signature by the designated representative.

8.3 A facility that has submitted a complete compliance plan for its impacted units in accordance with the requirements of 8.0 of this regulation may on one occasion for each unit request an extension of up to one year for any deadline set out in 5.1 and 5.3 of this regulation. The facility shall have the burden of demonstrating that good faith efforts have been made to comply with the original deadline; that the facility is unable to comply because of events or circumstances beyond the control of the facility, including any entity controlled by it; that the delay could not have been prevented by the facility’s exercise of due diligence; and that the facility has taken all reasonable steps or measures to avoid or minimize the delay. The Secretary shall exercise his discretion to grant a request that satisfies all the criteria.

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9.0 Penalties

The Department may enforce all of the provisions of this regulation under 7 Del.C. Ch 60.

Table 4-1

Annual NOX Mass Emissions Limits

 

Control Period NOX

Mass Emissions Limit

Unit

(tons)

Edgemoor 3

773

Edgemoor 4

1339

Edgemoor 5

1348

Indian River 1

601

Indian River 2

628

Indian River 3

977

Indian River 4

2032

McKee Run

244

Table 5-1

Annual SO2 Mass Emissions Limits

 

Control Period SO2

Mass Emissions Limit

Unit

(tons)

Edgemoor 3

1391

Edgemoor 4

2410

Edgemoor 5

2427 4600

Indian River 1

1082

Indian River 2

1130

Indian River 3

1759

Indian River 4

3657

McKee Run

439

Table 6-1

Annual Mercury Mass Emissions Limits

 

Mercury Mass Emissions

2009 - 2012

Mercury Mass Emissions

2013 and Beyond

Unit

(ounces)

(ounces)

Edgemoor 3

266

106

Edgemoor 4

462

183

Indian River 1

207

82

Indian River 2

216

86

Indian River 3

337

134

Indian River 4

700

278

10 DE Reg. 1022 (12/01/06)

12 DE Reg. 347 (09/01/08)

13 DE Reg. 499 (10/01/09) (Final)