
    The DETROIT EDISON CO., Plaintiff-Counter-Defendant, v. MICHIGAN DEP’T OF ENVTL. QUALITY and Wayne County Dep’t of Environment, Defendants/Counter-Plaintiffs, and American Lung Ass’n of Michigan, Citizens Environment Alliance of Southwestern Ontario, Creekside Community Dev. Corp., Michigan Envtl. Council, Michigan United Conservation Clubs, Intervenors. United States of America, Plaintiff, v. The Detroit Edison Co., Defendant.
    Nos. 98-CV-74129, 99-CV-70171.
    United States District Court, E.D. Michigan, Southern Division.
    March 12, 1999.
    
      Christopher C. Nern, Peter A. Mar-quardt, Detroit, MI, for plaintiff.
    Joseph M. Polito, Mark A. Goldsmith, Honigman, Miller, et al., Detroit, MI, co-counsel, for plaintiff.
    Todd B. Adams, Asst. Attorney General, Natural Resources Div., Lansing, MI, for defendant Mich. Dept, of Envri. Quality counsel.
    Annette Lange, Asst. Attorney General, U.S. Dept, of Justice, Environment & Natural Resources, Washington, D.C., for United States.
    Hilda V. Gurley, Wayne County Dept, of Environment, Detroit, MI, Beth S. Gott-helf, Tammy L. Brown, Seyburn, Kahn, Ginn, et al., Southfield, MI, for defendant Wayne County.
   INTERIM REMEDIAL ORDER

FEIKENS, District Judge.

1. Introduction

The essential controversy of the above-styled consolidated cases is whether The Detroit Edison Company (“Edison”) violated the federal Clean Air Act (“CAA”), as well as applicable state and county law, when it chose not to obtain environmental permitting before restarting and operating its coal-fired Connors Creek Power Plant (“the Plant”), which is located in Detroit, Michigan and had been unused for almost a decade. Edison temporarily operated the Plant in 1998 in order to meet the greatly increasing energy demand of its Detroit customers during the peak summer months. As the summer of 1999 quickly approaches, Edison now claims it must have the Plant’s power to again avoid electrical “brown-outs” in the Detroit metropolitan area. None of the parties have disputed this urgent need for power.

Rather than to continue to meet this need through coal fuel, Edison has proposed to convert the Plant to a natural gas-fired facility. In order to operate the Plant with natural gas by the summer of 1999, however, Edison must begin renovation and construction now. With the consent of the parties, I have sought to facilitate the conversion solution, which all parties desire, by supervising permit negotiations between the parties’ technical experts over the past month. On Monday, March 8, 1999, these experts agreed on permit conditions for a Plant using natural gas fuel.

Against this background, I make the following findings.

II. Findings

1. I have jurisdiction over this matter pursuant to 28 U.S.C. §§ 1331, 1345, 1355, 1367(a), 1441(a), and 1441(b) and section 113(b) of the CAA, 42 U.S.C. § 7413(b).

2. In order to protect the health, safety, and welfare of the people of the Detroit metropolitan area, the Plant must be operational by or before the early summer of 1999. Therefore, construction necessary to the operation of the Plant as a natural gas-fired facility must begin immediately.

3. The U.S. Environmental Protection Agency (“EPA”) has alleged in its complaint that Edison is in violation of the CAA, its regulations, and Michigan’s State Implementation Plan (“SIP”) because it commenced construction and operations at the Plant in 1998 without having first obtained a Prevention of Significant Deterioration Permit as required by 42 U.S.C. § 7475, 40 C.F.R. § 52.21, and Mich.Rule 201, and also without having obtained a Nonattainment New Source Review Permit as required by 42 U.S.C. § 7503, 40 C.F.R. § 51.165, and Mich.Rules 201 and 221.

4. Upon my review of the pleadings, motions, briefs, and evidence presently before me in the consolidated cases, it is apparent that Edison is in violation of the CAA, its regulations, and Michigan’s SIP because it renovated, restarted, and has since operated, the Plant without having first obtained the necessary permits mentioned above. Edison’s violation grants me the full remedial powers authorized by section 113(b) of the CAA and thus serves as the basis for this Interim Remedial Order.

5. The interim permit agreed to by the parties sets out the conditions under which the Plant can be lawfully operated as a natural gas-fired facility. That permit is in compliance with the CAA, its regulations, and state law. The matter of carbon monoxide emissions offsets has not been addressed in the interim permit.

III. Conclusion

Pursuant to my findings above, it is hereby ORDERED for remedial purposes:

1. may commence and operation activities upon issuance of this Interim Remedial Order.

2. The construction and operation of the Plant must comply with the interim permit.

3. Edison must comply with its obligations to obtain the required carbon monoxide emissions offsets. If and when EPA redesignates the region encompassing Wayne County as an attainment area under the CAA, Edison will not be required to obtain further offsets.

4. The parties will incorporate the terms of the interim permit and the necessary language regarding offsets in a consent agreement. Preparation of the consent agreement should commence immediately.

5. Edison must file a permit application that complies with this Interim Remedial Order no later than March 18, 1999. The parties will comply with any applicable permitting regulations that require notice and public comment on the proposed final permit.

ATTACHMENT

The Detroit Edison Company, Conners Creek Power Plant

PROPOSED SPECIAL CONDITIONS

(Not including the condition for providing offsets)

March 8, 1999

(The precise value of each number representing fuel and emission limits must still be checked for accuracy)

1. For the purposes of this permit, all requirements for notifications or sub-mittal of records to or approval by the District Supervisor, Air Quality Division should be submitted to the Director of Compliance and Enforcement, Air Quality Management Division, Wayne County Department of Environment unless the applicant is otherwise notified in writing by the Air Quality Division. At no time shall notifications or submittals to or approvals by both agencies be required pursuant to this permit. This condition is necessary to ensure compliance with Act 451, 324.5523.

2. The applicant is permitted to convert boilers 15, 16, 17, and 18 at the Con-ners Creek Power Plant (the Plant) to burn natural gas with a design heat input capacity of 840 million BTU per hour per boiler. Each boiler shall be equipped with flue gas recirculation and low NOx burner(s). Once converted, the boilers shall be operated firing natural gas only. Applicant shall not operate the boilers unless the low NOx burner(s) and flue gas recirculation systems are installed and operating properly. This condition is necessary to ensure compliance with the Best Available Control Technology (BACT) determination established pursuant to the federal Prevention of Significant Deterioration regulations (PSD), 40 CFR Part 52.21.

3. Boilers 15, 16, 17, and 18 shall comply with the New Source Performance Standards as set forth at 40 CFR Part 60, Subparts A and Da. The applicant shall comply with all notice requirements, emission standards and continuous emissions monitoring, recordkeeping and reporting requirements as required in 40 CFR Part 60, Subparts A and Da.

4. The applicant shall operate the Plant as a cycling facility. The applicant defines a cycling facility as being operated in the following manner: a) The Plant would typically not be expected to operate on an around-the-clock basis on any given day. b) On an expected typical high demand day, the Plant’s boilers will typically be started early in the day, brought up to operating temperature and pressure and held ready so that steaming rates can be quickly increased to meet system load demand, c) The Plant’s boilers would typically be shut down at night as system demand decreases. d) The Plant is expected to operate most often in the summer months and less in other months when system demand is lower, e) As a cycling facility, the Plant may be dispatched at other appropriate times whenever system demand, capacity/energy availability, market, and/or emergency conditions dictate. This condition is necessary to ensure compliance with the BACT determination established pursuant to the federal PSD regulations, 40 CFR Part 52.21.

5.Applicant shall not fire more than 1512 million cubic feet of sweet natural gas per-boiler per year. This annual limit shall be based upon a 12-month rolling average as determined at the end of each calendar month. Applicant shall monitor and record the hourly natural gas feed rate for each boiler on a continuous basis in a manner and with instrumentation acceptable to the Air Quality Division. These monitors and associated monitoring data shall be used for compliance demonstration purposes. In the event of an unforeseen failure forcing one or more boilers out of service for extended periods, the applicant may request a temporary waiver from the annual natural gas consumption limit and/or ton per year emission limit on one or more of the remaining operational boilers for the period and amount justified by such extended outage, until repairs are completed. Such waiver approval shall not be unreasonably withheld by the Air Quality Division. In no event shall natural gas consumption for the entire Plant be allowed to exceed 6048 million cubic feet of natural gas per year, nor shall the annual emissions of nitrogen oxides (NOx) be allowed to exceed 453.6 tons per year or the annual emissions of carbon monoxide (CO) exceed 332.6 tons per year. These conditions are necessary to ensure compliance with the emission limits established pursuant to the federal PSD regulations, 40 CFR Part 52.21.

6. The NOx emission rates from each boiler when firing natural gas shall not exceed either 0.15 pound per million Btu heat input or 126.0 pounds per hour based on the average of all operating hours in a calendar day with the exception of operation during startup, shutdown, and malfunction. The NOx emission rate from each boiler when firing natural gas shall not exceed 113.4 tons per year. This annual limit shall be based upon a 12-month rolling average as determined at the end of each calendar month. These conditions are necessary to ensure compliance with the emission limits established pursuant to the federal PSD regulations 40 CFR Part 52.21.

7. The CO emission rates from each boiler when firing natural gas shall not exceed either 0.11 pound per million Btu heat input or 92.4 pounds per hour based on the average of all operating hours in a calendar day with the exception of operation during startup, shutdown, and malfunction. The CO emission rate from each boiler when firing natural gas shall not exceed 83.2 tons per year. This annual limit shall be based upon a 12-month rolling average as determined at the end of each calendar month. These conditions are necessary to ensure compliance with the lowest achievable emission rate (LAER) which has been established pursuant to Rule 220.

8. No later than 180 days after initial commencement of operation of each boiler the applicant shall reassess and propose whether lower CO and NOx emission limitations are appropriate based upon all appropriate information including the results of the continuous emission monitoring system (CEMS) data. The applicant shall submit a report of its reassessment to the Air Quality Division within 225 days after commencement of operations. A final decision with regard to whether lower emission limitations are appropriate would occur after review and discussion with the Air Quality Division. Upon determination by the Air Quality Division, and supported by the CEMS data, such limits shall be incorporated as revised permit conditions. These conditions are necessary to ensure compliance with the emission limits established pursuant to the federal PSD regulations, 40 CFR Part 52.21 and LAER which has been established pursuant to Rule 220.

9. Rules 1001,1003 and 1004 — Within 60 days of achieving 80% of the maximum production rate, but not later than 180 days after the initial startup of the Plant, verification of NOx and CO emission rates from each boiler by testing, at owner’s expense, in accordance with Department and Air Quality Management Division, Wayne County Department of Environment requirements, will be required. Verification of emission rates includes the submittal of a complete report of the test results. No less than 30 days prior to testing, a complete stack testing plan must be submitted to the Air Quality Division. The final plan must be approved by the Air Quality Division prior to testing. Stack test results shall be submitted to the Air Quality Division within 30 days of testing.

10. Applicant shall monitor and record the NOx concentration, the percent C02, and natural gas consumption oh a continuous basis in a manner and with instrumentation acceptable to the Air Quality Division and according to the monitoring and reporting principles in Attachment A and the monitoring requirements in 40 CFR Part 75 which also satisfies the monitoring requirements in 40 CFR Part 60, Subparts A and Da. The applicant shall monitor and record the CO concentrations on a continuous basis in a manner and with instrumentation acceptable to the Air Quality Division and according to the Monitoring and Reporting Principles in Attachment A and the monitoring requirements in 40 CFR Part 60, Appendix B, Performance Specification 4A and Appendix F. The continuous emission monitoring system (CEMS) shall be used for compliance demonstration with all permit limitations and the federal New Source Performance Standards requirements The condition is necessary to ensure compliance with the emission limits established pursuant to the federal New Source Performance Standards, Subparts A and Da requirements; the federal PSD regulations, 40 CFR Part 52.21; and the LAER which has been established pursuant to Rule 220.

11.All emissions monitoring and fuel usage data shall be summarized and submitted within 30 days after the end of each month to the Air Quality Division on a monthly basis for the first 12 months of operation and on a quarterly basis thereafter. The emissions and fuel usage report on a per boiler basis shall include, but not be limited to, the calendar daily average NOx and CO emission rates in pounds per million Btu and pounds per hour, 30 day rolling average NOx emission rate in pounds per million Btu, 12 month rolling average NOx and CO emission rates in tons per year, total daily natural gas usage in million cubic feet, and the 12 month rolling average of the natural gas usage in million cubic feet per year. During the Interim Operating Period provided by Attachment A, the stack pounds per million Btu emission rate shall be considered representative of the per boiler pounds per million Btu emission rate. All source emissions data and operating data shall be kept on file for a period of at least five years and made available to the Air Quality Division upon request. This condition is necessary to ensure compliance with the emission limits established pursuant to the federal New Source Performance Standards, 40 CFR Part 60, Subparts A and Da requirements; the federal PSD regulations, 40 CFR Part 52.21; and the LAER which has been established pursuant to Rule 220.

12. The exhaust gases from Boiler Nos. 15 and 16 shall be discharged unobstructed vertically upwards to the ambient air from a stack with a maximum diameter of 120 inches at an exit point not less than 352 feet above ground level. This condition is necessary to ensure compliance with the requirements of the National Ambient Air Quality Standards pursuant to the federal Clean Air Act of 1990 and the PSD increments.

13. The exhaust gases from Boiler Nos. 17 and 18 shall be discharged unobstructed vertically upwards to the ambient air from a stack with a maximum diameter of 120 inches at an exit point no less than 352 feet above ground level. This condition is necessary to ensure compliance with the requirements of the National Ambient Air Quality Standards pursuant to the federal Clean Air Act of 1990 and the PSD increments.

14. At least 14 days prior to commercial operation, applicant shall submit to the Air Quality Division for approval, a malfunction abatement plan and maintenance procedures and schedules plan for the following equipment: boilers, low NOx burners, flue gas recirculation and monitoring equipment. In addition, these plans shall address abnormal conditions, start-up/shutdown/malfunctions, and excess emissions abatement. These plans and procedures must be approved by the Air Quality Division within 12 months of commencement of operation of the Plant. If the Air Quality Division has not approved these plans and procedures within 12 months of commencement of operation of the Plant, the Air Quality Division must notify the applicant and provide a written report of the reasons that the plans and procedures have not been approved. Within 60 days of receipt of the written report, the applicant shall submit revised plans and procedures. Applicant shall implement and maintain the above plans and procedures once they have been approved. This condition is necessary to ensure compliance with the requirements of Rule 911.

Attachment A — Monitoring and Reporting Principles

(Referenced by Special Condition No.10)

March 8, 1999

1. The span value for CO shall be 2.0 times the lowest emission standard. (Rule 1154)

2. A summary report (i.e., excess emissions and monitoring performance report) in accordance with 40 CFR Part 60.7(c) and (d) shall be submitted in a format acceptable to the Air Quality Division within 30 days following the end of each quarter.

3. Emission Monitoring and Emission Limitations:

a.From the time of initial startup of the Plant to the time of final CEMS installation provided by 3(c) below (this time period is known as the
“Interim Operating Period”), the applicant shall monitor each stack serving the Plant’s boilers. During the Interim Operating Period the following shall apply:
i. The NOx emission rate of 0.15 pound per million Btu heat input based on the average of all operating hours in a calendar day with the exception of operation during startup, shutdown, and malfunction shall be applicable on a per stack basis during the Interim Operating Period. Per boiler mass emission rates in Special Condition o No. 6 shall be calculated based on the stack emission rate and natural gas fuel flow and monthly heat content during the Interim Operating Period.
ii. The CO emission rate of 0.11 pound per million Btu heat input based on the average of all operating hours in a calendar day with the exception of operation during startup, shutdown, and malfunction shall be applicable on a per stack basis during the Interim Operating Period. Per boiler mass emission rates in Special Condition No. 7 shall be calculated based on the stack emission rate and natural gas fuel flow and monthly heat content during the Interim Operating Period.
b. Prior to installation, the applicant shall submit to the Air Quality Division a CEMS Monitoring Plan for the Interim Operating Period for review and approval. The Monitoring Plan for the Interim Operating Period shall include drawings showing proposed locations and descriptions of all monitors.
c. No later than April 1, 1999, the applicant shall submit an approvable schedule (“final CEMS Schedule”) to the Air Quality Division identifying the date by which a final CEMS shall be installed and certified to monitor NOx and CO concentrations and the percent C02 on a continuous basis in a manner and with instrumentation acceptable to the Air Quality Division for each boiler. The final CEMS Schedule shall include progress milestones including dates for: completion of boiler duct air flow testing; submission of bids to potential CEMS vendors; purchase/lease of the CEMS; initial CEMS installation; final CEMS Monitoring Plan, final CEMS installation; and CEMS certification test. Applicant shall install final OEMS no later than September 1, 1999.
d. According to the final CEMS Schedule provided in 3(c) above, the applicant shall submit to the Ah- Quality Division a final CEMS Monitoring Plan for review and approval. The final CEMS Monitoring Plan shall include drawings showing proposed locations and descriptions of all monitors. 
      
      . I have attached a copy of the interim permit to this order.
     
      
      . See also the discussion of my jurisdiction over the earlier case. No. 98-74129, in The Detroit Edison Co. v. Michigan Dep’t of Envtl. 
        
        Quality, et al., 29 F.Supp.2d 786 (E.D.Mich.1998).
     