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United States v. Ameren Missouri

United States District Court, E.D. Missouri, Eastern Division

September 30, 2019

UNITED STATES OF AMERICA, Plaintiff,
v.
AMEREN MISSOURI, Defendant. and SIERRA CLUB, Plaintiff-Intervenor,

          MEMORANDUM OPINION & ORDER

          RODNEY W. SIPPEL, UNITED STATES DISTRICT JUDGE.

         TABLE OF CONTENTS

         INTRODUCTION ....................................................................................................................... 1

         I. Summary ........................................................................................................................ 1

         II. Case History .................................................................................................................. 2

         III. Liability Phase Findings of Fact and Conclusions of Law ............................................ 3

         FINDINGS OF FACT ............................................................................................................... 11

         I. BACKGROUND: RUSH ISLAND'S MAJOR MODIFICATIONS .......................... 11

         a. Ameren Redesigned and Rebuilt Units 1 and 2 Near the End of Their Design Life ... 11

         b. Modifications at Rush Island Led to Actual Emissions Increases ............................... 11

         c. Rush Island Is One of a Small Minority of Similar Plants That Continue to Operate Without SO2 Scrubbers ............................................................................................... 12

         i. SO2 Scrubbers Are Widely Used in the Electric Utility Industry ............................ 12

         ii. DSI Controls Are Not Commonly Installed on Units of Rush Island's Size ........... 16

         d. Ameren Evaluated FGD Installation at Rush Island ................................................... 17

         i. Ameren's Studies Recommended Wet FGD at Rush Island .................................... 19

         ii. Ameren's Studies Confirmed the SO2 Emission Rates Achievable at Rush Island 22

         iii. Ameren's Studies Demonstrate How Quickly Wet FGD Can Be Installed ............. 25

         II. RUSH ISLAND'S VIOLATIONS HAVE LED TO MORE THAN 162, 000 TONS OF EXCESS SULFUR DIOXIDE POLLUTION ........................................................................ 27

         a. PSD Requires the Best Available Control Technology ............................................... 28

         i. BACT Determination Is a Five-Step Process .......................................................... 28

         ii. Cost-Effectiveness Does Not Determine BACT ...................................................... 32

         iii. NSPS Do Not Fundamentally Alter the BACT Process .......................................... 33

         b. FGD Scrubbers Constitute BACT for the Vast Majority of Pulverized Coal-Fired Power Plants ................................................................................................................ 34

         i. The Electric Power Utility Industry Recognizes That FGD Constitutes BACT ..... 34

         ii. During The Past Twenty Years, Every BACT SO2 Determination for a Pulverized Coal-Fired Power Plant Has Required FGD ............................................................ 35

         c. The Parties' Competing BACT Analyses .................................................................... 37

         d. Campbell's Testimony Rejecting Wet FGD and Choosing DSI Was Not Credible ... 40

         i. Campbell Overly Relied on Incremental Cost Effectiveness at Rush Island ........... 41

         ii. Campbell's Cost Comparisons Include Cost Categories Not Included in Other Plants' BACT Determinations ................................................................................. 42

         iii. Campbell's Incremental Cost Effectiveness Analysis Was Inconsistent With His Prior Trainings and Advice ...................................................................................... 44

         iv. Campbell's Cost Threshold Opinion Is Unsupported .............................................. 45

         v. Campbell Disregards MDNR Practice Concerning Sources in the Same Category 48

         vi. Campbell Incorrectly Rejects Information From Power Plants Subject to NSPS ... 49

         e. I Reject Campbell's Testimony That DSI Is BACT for Rush Island .......................... 50

         f. Dr. Staudt's Testimony Concerning BACT at Rush Island Was Credible .................. 51

         g. BACT Requirements at Rush Island in 2007 and 2010 ............................................... 53

         h. Rush Island's Excess Emissions Total More Than 162, 000 Tons .............................. 58

         III. CURRENT BACT ANALYSIS .................................................................................. 59

         a. Current BACT Requires Wet FGD ............................................................................. 59

         b. Current BACT Requires an Emissions Limitation of 0.05 lb/mmBTU ...................... 63

         IV. RUSH ISLAND'S EXCESS EMISSIONS CAUSED IRREPARABLE INJURY, INCLUDING INCREASED RISK OF PREMATURE MORTALITY ................................. 64

         a. Rush Island's Excess Pollution Is Substantial ............................................................. 64

         b. Rush Island's Excess SO2 Emissions Created Harmful PM2.5 ..................................... 64

         i. Dr. Schwartz Presented Credible, Well-Supported, Expert Testimony Concerning the Health Impacts of PM2.5 ..................................................................................... 66

         ii. PM2.5 Causes Heart Attacks, Strokes, Asthma Attacks, and Premature Mortality .. 67 iii. Dr. Fraiser's and Dr. Valberg's Testimonies Were Not Credible ............................ 70

         iv. The Evidence Does Not Support Ameren's Argument that Rush Island's Excess Emissions Are Harmless .......................................................................................... 76

         c. Rush Island's Excess Pollution Affects the Entire Eastern Half of the United States 79

         i. Plaintiff's Experts Presented Detailed and Credible Modeling Results .................. 79

         ii. The Model Predicts Rush Island's Excess Emissions Increased PM2.5 Concentrations Across the Entire Eastern Half of the United States ....................... 83

         d. Results of Two Different Models Show Rush Island's Excess Emissions Increased the Risk of Hundreds to Thousands of Premature Deaths ................................................. 87

         i. Dr. Schwartz Published a Peer-Reviewed Quantitative Risk Assessment for Rush Island's SO2 Emissions in 2009 ............................................................................... 87

         ii. Dr. Schwartz Also Quantified Risk Based on Chinkin's CAMx Modeling ............ 88

         iii. Rush Island's Excess Emissions Caused Hundreds to Thousands of Premature Deaths ...................................................................................................................... 89

         e. Ameren's Criticisms of the EPA's Model Are Not Persuasive ................................... 90

         V. RUSH ISLAND'S EXCESS POLLUTION IS BEST REMEDIATED BY DECREASING EMISSIONS AT THE NEARBY LABADIE ENERGY CENTER ............ 95

         a. Reducing Future Pollution from Labadie Will Remediate the Harm from Rush Island for the Same Populations and to the Same Extent ....................................................... 96

         b. Society Will Benefit If Ameren Offsets Its Excess Emissions .................................... 99

         c. Ameren's Surrendering of Pollution Allowances Would Not Remedy Harms to the Populations Affected by Rush Island's Excess Emissions ........................................ 100

         VI. ADDITIONAL EQUITABLE FACTORS SUPPORT THE REQUESTED REMEDIES .......................................................................................................................... 104

         a. Liability Standards Were Well Understood in the Industry ...................................... 104

         b. Ameren Has Benefitted from Delaying Compliance at Rush Island ......................... 108

         c. Ameren Admits It Can Afford to Comply With the Requested Remedies ............... 109

         i. Ameren Has Abundant Financial Resources ......................................................... 109

         ii. Ameren Agrees It Can Finance the Requested Relief ........................................... 112

         iii. The Projected Ratepayer Impact of the Requested Relief Is Less Than Ameren's Yearly Rate Increases ............................................................................................ 113

         iv. Ameren's Average Estimates of Rate Increase Are Misleading ............................ 116

         CONCLUSIONS OF LAW .................................................................................................... 117

         I. THE CLEAN AIR ACT REQUIRES THE BEST AVAILABLE CONTROL TECHNOLOGY FOR MODIFIED POWER PLANTS IN PSD AREAS ........................... 121

         II. THE EBAY STANDARD GOVERNS INJUNCTIVE RELIEF .............................. 122

         III. AMEREN MUST MAKE RUSH ISLAND COMPLIANT BY OBTAINING A PSD PERMIT WITH EMISSIONS LIMITATIONS BASED ON WET FGD ............................ 124

         a. BACT Sets Emissions Limitations Based on the Maximum Degree of Pollution Reduction Achievable ................................................................................................ 125

         b. Industry Experience and Ameren's Own Analyses Show FGD Technology Is Economically and Technically Feasible at Rush Island ............................................ 126

         c. Ameren's Arguments Against PSD Permitting Mischaracterize Case Law, Ameren's Permitting Options, and the Nature of BACT ........................................................... 130

         i. As a Major Stationary Source That Performed Major Modifications, Ameren Must Obtain a PSD Permit, Not a “Minor Permit” ......................................................... 131

         ii. None of Ameren's Arguments or Evidence Prevent Me From Ordering Ameren to Propose Wet FGD as BACT .................................................................................. 133

         iii. Ameren's Arguments for the Least Effective Control Technology, DSI, Contradict the Nature and Definition of BACT ....................................................................... 134

         d. SO2 BACT For Rush Island Was Wet FGD Technology at the Time of the Modifications and Remains So Today ....................................................................... 136

         e. The eBay Factors Require Rush Island to Comply with PSD Permitting and BACT Emissions Limitations ............................................................................................... 137

         i. The Communities Downwind of Rush Island Have Been Irreparably Injured ...... 138

         ii. Legal Remedies Are Inadequate to Remedy the Harm .......................................... 139

         iii. The Balance of Hardships Weighs in Favor of an Injunction Ordering Ameren to Install Wet FGD at Rush Island ............................................................................. 140

         iv. Compliance at Rush Island Serves the Public Interest ........................................... 141

         f. Ameren's Arguments That Rush Island's Excess Pollution Was Not Harmful Are Not Convincing ................................................................................................................. 142

         i. The National Ambient Air Quality Standards (NAAQS) Do Not Establish a Safe Threshold For SO2 Pollution .................................................................................. 142

         ii. The “Significant Impact Levels” Do Not Determine the Meaningfulness of Human Health Impacts ....................................................................................................... 144

         iii. Ameren's Reliance on Scientific Uncertainty Is Misguided and Its Reliance on Fringe Toxicological Evidence Is Unpersuasive ................................................... 145

         IV. LABADIE MUST REDUCE EMISSIONS COMMENSURATE WITH THE EXCESS EMISSIONS RELEASED BY RUSH ISLAND .................................................. 147

         a. The eBay Factors Support the EPA's Requested Injunctive Relief at Labadie ......... 147

         i. The Same Irreparable Injury Analysis of Rush Island's Excess Emissions Applies to Labadie ................................................................................................................... 147

         ii. Legal Remedies Are Inadequate to Remedy the Harm .......................................... 148

         iii. Plaintiffs Suffer the Balance of the Hardships ....................................................... 148

         iv. Pollution Reductions at Labadie Serve the Public Interest .................................... 148

         b. Reducing Pollution from Nearby Labadie Is Relief Narrowly Tailored to Remedy the Harm from Ameren's Violations. . ............................................................................. 149

         c. DSI Installation at Labadie Is Not a Penalty ............................................................. 151

         V. AMEREN'S FAIR NOTICE ARGUMENT FAILS ................................................. 152

         CONCLUSION ........................................................................................................................ 155

         INTRODUCTION

         I. Summary

         In 1970, Congress enacted the modern Clean Air Act to protect the nation's air resources and “promote the public health and welfare and the productive capacity” of the people. 42 U.S.C. § 7401(b)(1). Not satisfied with the results achieved under the 1970 statute, Congress amended the Clean Air Act in 1977 to add protections for areas meeting existing federal air quality standards. The 1977 amendments require newly-constructed power plants to install pollution controls. These pollution controls decreased the pollution coming from new plants. Acknowledging the cost of retrofitting old facilities, the 1977 amendments allowed existing plants to continue operating for their natural lifespan without pollution controls. Existing plants retained this “grandfathered” status until they were modified in any way beyond routine maintenance that increased emissions.

         Ameren Missouri's (Ameren) Rush Island Energy Center (Rush Island) started operating in 1976, one year before the Clean Air Act Amendments. In the mid-2000's, as Rush Island was reaching the end of its natural lifespan, Ameren decided to conduct the most significant outage in Rush Island history to redesign and rebuild essential parts of Rush Island's boilers. To increase Rush Island's capacity and lengthen its life, Ameren reconstructed Rush Island's Unit 1 in 2007 and Unit 2 in 2010. Collectively, these construction outages lasted about 200 days and required more than 1, 360 workers and almost 800, 000 hours of labor. Rush Island's generating capacity and pollution emissions both increased as a result of these major modifications.

         Before making these major modifications, Ameren should have obtained a Clean Air Act permit and installed the best pollution controls available, which were required after 1977 for all new and rebuilt power plants. Ameren did not apply for a permit. Forty-three years after it first came on-line, Rush Island is still operating without any pollution controls. It is now the tenth-highest source of sulfur dioxide pollution in the United States. More than two and a half years ago, I determined that Ameren had violated the Clean Air Act. During the last two and a half years, the parties have prepared and presented evidence to determine how to bring Ameren into compliance with the 1977 Clean Air Act. I held a trial in April 2019 on this issue.

         In this memorandum order and opinion, I provide my findings of fact and conclusions of law from that trial. As a remedy, I will order Rush Island to come into compliance with the Clean Air Act by obtaining a permit under the Prevention of Significant Deterioration (PSD) program. I will also order Ameren to remedy Rush Island's excess pollution with ton-for-ton reductions at its nearby Labadie Energy Center. This remedy will satisfy the purpose of the Clean Air Act to “promote the public health and welfare and the productive capacity” of the people, and it is narrowly tailored to address the harms created by Ameren's violations.

         II. Case History

         In this Clean Air Act case, Plaintiff United States of America claims that Defendant Ameren increased the risk of negative health impacts and premature deaths by releasing excess pollution from Rush Island. Plaintiff is acting at the request of the United States Environmental Protection Agency (EPA). According to the EPA, Rush Island has released more than 162, 000 excess tons of sulfur dioxide into the air because Ameren failed to apply for a permit that would require it to install pollution control technology when it redesigned and rebuilt its boilers at Rush Island. That sulfur dioxide transformed into fine particulate matter (PM2.5) that can cause heart attacks, asthma attacks, strokes, and premature death. Had Ameren installed the required pollution control technology, it would have reduced its Rush Island pollution by 95% or more. To remedy these harms, the EPA seeks an order requiring Ameren to (1) obtain the required Clean Air Act permit (2) install sulfur dioxide “scrubbers” at Rush Island, and (3) install pollution control technology at a second coal-fired power plant to account for the excess emissions Rush Island continues to release while it operates without pollution controls.

         I separated the liability and remedies phases of this case to more orderly conduct discovery and presentation of arguments. In August and September 2016, the liability phase concluded with a 12-day bench trial. On January 23, 2017, I issued my memorandum opinion and order on the liability phase. I found that Ameren violated the Clean Air Act, 42 U.S.C. § 7470 et seq., by overhauling its coal-fired boilers at Rush Island without obtaining the required permits. On February 16, 2017, I granted the Sierra Club's motion to intervene in this suit as a matter of right. [ECF No. 863].[1]

         In April 2019, I held a six-day bench trial to determine the appropriate remedy in this case. In this memorandum order and opinion, I set forth findings of fact and conclusions of law from the remedies phase trial. These findings and conclusions depend in significant part on the evidence presented and conclusions made during the liability phase. Accordingly, I will summarize aspects of the liability phase trial as follows.

         III. Liability Phase Findings of Fact and Conclusions of Law

         Rush Island is a pulverized coal-fired power plant in Jefferson County, Missouri, directly adjacent to the Mississippi River. Rush Island's two units went into service in 1976 and 1977, immediately before the 1977 Clean Air Act Amendments. Because of this timing, Rush Island is one of many power plants that were grandfathered into the Clean Air Act's permitting scheme. The Rush Island plant currently emits about 18, 000 tons of SO2 per year. Neither of Rush Island's units has air pollution control devices for SO2.

         Under the Clean Air Act, every new or modified major pollution source must obtain one of two permits: a Non-Attainment Area permit when they are built in areas more polluted than the National Ambient Air Quality Standards (NAAQS), or a Prevention of Significant Deterioration (PSD) permit when they are built in attainment areas, which are less polluted than the NAAQS. 42 U.S.C. § 7470 et seq. The EPA sets NAAQS for six criteria pollutants at levels “requisite to protect the public health.” 42 U.S.C. § 7409(b). However, NAAQS alone are insufficient to meet the goals of the Clean Air Act: Congress determined that even in attainment areas, air pollution control was necessary “to ensure that the air quality in . . . areas that are already ‘clean' will not degrade.” Alaska Dep't of Envtl. Conservation v. E.P.A., 540 U.S. 461, 470 (2004) (quoting R. Belden, Clean Air Act 6 (2001) at 43).

         Congress has made some exceptions to blunt the impact of the Clean Air Act. Specifically, the Act does not require existing facilities to immediately install pollution controls. Instead, the Act allows these facilities to continue operating through their normal lifespans. This grandfathering only lasts until these plants cease operating or undergo major modifications. Any plant that is retired but reactivated loses its grandfathered status and must obtain a permit. A plant that is rebuilt in any significant way must obtain a permit as well.

         Accordingly, the Clean Air Act represents a compromise: by limiting the duration of grandfathering to facilities' natural life, Congress prevented existing polluters from maintaining in perpetuity their advantage over new plants.

[O]ld plants [are treated] more leniently than new ones because of the expense of retrofitting pollution-control equipment. But there is an expectation that old plants will wear out and be replaced by new ones that will be subject to the more stringent pollution controls that the Clean Air Act imposes on new plants. One thing that stimulates replacement of an old plant is that aging produces more frequent breakdowns and so reduces a plant's hours of operation and hence its output.

United States v. Cinergy Corp., 458 F.3d 705, 709 (7th Cir. 2006). Through the “major modification” exception to grandfathering, Congress memorialized this compromise as a matter of law.

         Major modifications occur when there is a “physical change” or change in the method of operation of a major stationary source that would significantly increase net emissions. See United States v. Ameren Missouri, 2016 WL 728234, at *4 (citing 40 C.F.R. § 52.21(b)(2)(i)). An increase of 40 tons or more per year of sulfur dioxide (“SO2”), the pollutant discussed in this case, is “significant” under the regulations. 40 C.F.R. § 52.21(b)(23)(i).

         Under the Clean Air Act, if a grandfathered polluter ever modifies its facilities, it must do four things: (1) calculate the impact of those modifications, (2) report the planned modifications to the EPA, (3) obtain the requisite permits, and (4) install the required pollution control technologies at that time. This process ensures that any “major modifications” are identified, reported, and permitted. Ameren made major modifications to Rush Island without reporting those modifications and obtaining a permit.

         The natural life of many of Rush Island's component parts is 30 to 40 years. Consistent with those lifespans, by 2005, major boiler components at Rush Island were experiencing performance problems including leaks, slagging, fouling, plugging, gas flow resistance, erosion, and mechanical failure. These problems forced Ameren to take the units offline with increasing frequency so that they could be unplugged, repaired, and otherwise serviced. These aging problems also reduced the capacity of the Rush Island boilers by slowing gas flow and reducing the gas volume moving through each boiler. See United States v. Ameren Missouri, 229 F.Supp.3d 906, 922-936 (E.D. Mo. 2017).

         Ameren sought to increase its plant capacity by redesigning and replacing essential components of both boilers, specifically the economizer, reheater, air preheater, and the “lower slope” panels surrounding the boiler. Ameren overhauled Unit 1 and Unit 2 in this manner in 2007 and 2010, respectively. After Ameren replaced these components at each unit, that unit's electric generating capacity increased immediately to levels that had not been seen in years. To achieve this improved capacity, Ameren employed more than 1, 000 workers over several years. For example, “[t]he 2010 major boiler outage at Rush Island Unit 2 lasted approximately 100 days and required more than 350, 000 hours of labor, of which 290, 953 hours were performed by contractors. An average of 360 contractor staff worked two 10-hour shifts six days a week during the outage.” United States v. Ameren Missouri, 229 F.Supp.3d 906, 943 (E.D. Mo. 2017). The outage at Unit 1 was similar in scope and length, and both units' projects required years of planning.

         Additional evidence presented at trial established that Ameren's work at both units did not constitute “routine maintenance.” The new components in each boiler were designed, engineered, and constructed by outside contractors, and the complexity of the replacements was beyond the capacity of Ameren's in-house staff. Id at 1001. The replaced equipment was so large and heavy that monorails had to be built to transport it at the construction site. Id Ameren budgeted and paid for these projects out of its capital budget instead of its operations and maintenance budget. Id at 1002. The Rush Island modifications required approval from high-level Ameren executives, which is unnecessary for routine maintenance. Id at 1001. Ameren's Vice President called the 2007 modifications the “most significant outage in Rush Island history” and referred to the replacement of the economizer, reheater, air preheater, and lower slopes as distinct from other “routine maintenance that had to be performed” during the outage. Id at 943.

         Ameren's own internal metrics demonstrated an actual increase in emissions at Rush Island. Specifically, Ameren recorded outages and “derate” events, where Rush Island's maximum output was reduced. Ameren recorded these events contemporaneously in its Generating Availability Data System (GADS), and based staff bonuses in part on availability data. Id at 931-933. Between 1997 and 2007, Unit 1's availability fluctuated between 70% and 90%. Id at 949. Following its upgrade, Unit 1's availability increased to 96.77% in 2008. Id at 954. This value was higher than any 12-month period at Unit 1 since 1990. Id Unit 2's availability increased from 94.5% during a five-year baseline to 97.4% after the modifications. Id at 958. This value was higher than any 12-month period at Unit 2 since 1987. Id Ameren's employees have admitted that those availability increases would not have happened but for the projects.

         Courts recognize these availability improvements as leading to emissions increases. “A significant decrease in outages results in a significant increase in both production and emissions.” United States v. Ohio Edison Co., 276 F.Supp.2d 829, 834-35 (S.D. Ohio 2003). “If the repair or replacement of a problematic component renders a plant more reliable and less susceptible to future shut-downs, the plant will be able to run consistently for a longer period of time, ” emitting more pollution as the plant is operated. United States v. Ala. Power Co., 730 F.3d 1278, 1281 (11th Cir. 2013).

         With the facts presented at trial, the preponderance of evidence demonstrated that (1) Ameren conducted a “major modification” when it used more than 1, 000 workers to design and replace essential components of Rush Islands boiler units in 2007 and 2010; (2) Ameren should have expected those modifications to increase emissions by more than forty tons of sulfur dioxide per year; (3) those modifications actually increased emissions by reducing future stoppages, increasing plant capacity, and extending the life of the plant; and (4) those modifications were, in Ameren's expert's words, not de minimis or routine modifications, nor did emissions increase because of demand alone.

         Ameren should have obtained a Clean Air Act permit before beginning its major boiler modification. Ameren did not seek that permit. As a part of the permitting process, major pollution sources like Rush Island are required to have the Best Available Control Technology (BACT) when they undergo major modifications. Rush Island did not have any pollution control technology. Twelve and nine years since Ameren overhauled Unit 1 and Unit 2, respectively, Rush Island still does not have any pollution control technology. Through the end of 2016, Rush Island emitted 162, 000 tons of sulfur dioxide more than it would have had Ameren complied with its obligations under the Clean Air Act.

         Now, in the remedy phase of the trial, Ameren and the EPA dispute whether I should order injunctive relief in this case and what injunctive relief is appropriate. In September 2018, the parties filed five separate motions for summary judgment, three from Ameren, one from the EPA, and one from Plaintiff-Intervenor Sierra Club on the subject of standing. I granted the Sierra Club's motion for summary judgment on standing with respect to relief requested at Rush Island. [ECF No. 1055] There was no dispute of material fact that Sierra Club's members were injured in fact, their injuries were traceable to Ameren's excess emissions, and pollution reductions at Rush Island would redress their injuries.

         I denied the parties' other motions for summary judgment. Neither the EPA nor Ameren demonstrated that there was no dispute of material fact concerning the appropriate remedy. I must evaluate injunctive relief relying on the “well-established principles of equity” the Supreme Court articulated in eBay Inc. v. MercExchange, L.L.C., 547 U.S. 388, 391 (2006).[2] Based on the parties' filings, I could not say as a matter of law what injunctive relief was required pursuant to the eBay factors.

         In April 2019, the EPA and Ameren presented their arguments concerning remedies over six days of trial. The EPA requests an order requiring Ameren to obtain a PSD permit for Rush Island, (2) propose Flue Gas Desulfurization (FGD) scrubbers as the appropriate permit technology, (3) meet an emissions limitation based on FGD scrubbers, and (4) address ton-for-ton excess emissions from Rush Island by installing pollution control technology on Ameren's Labadie Energy Center. Based on the extensive testimony provided by its experts, the EPA argues that the eBay factors support this relief.

         Ameren argues that it did not have fair notice of the EPA's legal interpretations, that there is no evidence of harm created by its SO2 emissions, that Ameren has already decreased its emissions, that it should have had the opportunity to apply for a much less stringent “minor permit, ” and that the expense of installing scrubbers is unduly burdensome.

         In addressing these arguments, I note that by making major modifications without satisfying the requirements of the Clean Air Act, Ameren reaped significant financial benefits. According to Ameren's 2011 estimates, installing wet FGDs at Rush Island would cost between $650 million and $960 million. September 19, 2011 Project Plan (Pl. Ex. 1102), at AM-REM-00294509. Ameren deferred these costs for more than ten years at the expense of downwind communities that it will never have to fully repay. Instead, I may only order remediation enough to account for the total amount of excess emission released by Ameren, a remedy that is more than a decade late, but which is closely tailored to the harm suffered by these communities.

         Accordingly, and based on the evidence presented at trial, I conclude that the following injunctive relief is necessary to remedy the harm created by the more than 162, 000 tons of excess pollution Ameren released from Rush Island: Ameren must (1) apply for and obtain the applicable Clean Air Act permit from the Missouri Department of Natural Resources (MDNR) for its Rush Island Plant, (2) propose wet flue gas desulfurization (FGD) as the required control technology for Rush Island, (3) meet an emissions limitation of 0.05 lb/mmBTU at Rush Island and (4) install and use dry sorbent injection (DSI) technology, or another more effective control technology, at its Labadie Energy Center (Labadie), until it reduces pollution from Labadie in an amount equal to the excess emissions from Rush Island.

         This remedy results from the following findings of fact and conclusions of law. In summary, I find that the EPA's experts convincingly and credibly testified that wet FGD is the most effective control technology that could be used at Rush Island. Additionally, when considering the energy, environmental, and economic impacts, wet FGD is achievable at Rush Island. As a result, wet FGD is the Best Available Control Technology (BACT) for Rush Island. The EPA's experts also convincingly and credibly testified that Ameren's failure to install BACT at Rush Island has led to more than 162, 000 tons of excess SO2 emissions and increased the risk of health problems and premature mortality in the exposed population. Considering this evidence, I conclude that ordering commensurate reductions at Labadie is a remedy that is closely tailored to the harm suffered, addresses irreparable injury that could not be compensated through legal remedies, serves the public interest, and is warranted when considering the balance of hardships in this case.

         FINDINGS OF FACT

         I. BACKGROUND: RUSH ISLAND'S MAJOR MODIFICATIONS

         a. Ameren Redesigned and Rebuilt Units 1 and 2 Near the End of Their Design Life

         1. Rush Island Units 1 and 2 began operating in 1976 and 1977. They were originally grandfathered into compliance with the Clean Air Act without needing to install BACT emission limitations imposed by the Prevention of Significant Deterioration (PSD) program. Ameren Missouri, 229 F.Supp.3d at 915.

         2. Neither Rush Island Unit 1 nor Rush Island Unit 2 has installed any air pollution control devices for SO2 emissions. Id.; see also id. at 917 (Liability Findings ¶ 8).

         3. Rush Island Units 1 and 2 were originally designed to have an approximately 30-year life, with components typically lasting 30 to 40 years. Id. at 917 (Liability Findings ¶ 5). By 2007 and 2010, when Ameren modified Rush Island Units 1 and 2, they had already been operating for 30 years. Ameren has already run the Rush Island plant ten years longer than it expected at the time the plant was constructed.

         4. The 2007 and 2010 modifications ended Rush Island's grandfathered status under the PSD program. The modifications were made during the most significant outage in Rush Island plant history and were justified based on increasing plant operations and revenue. Id. at 915; see also id. at 940 (Liability Findings ¶¶ 155-160), 943 (Liability Findings ¶ 172).

         b. Modifications at Rush Island Led to Actual Emissions Increases

         5. At trial, Ameren argued that it had reduced both its fleetwide SO2 emissions and its emissions from Rush Island. In 2010, Ameren began operating pollution control equipment, specifically Flue Gas Desulfurization (FGD) scrubbers, at its Sioux pulverized coal-fired power plant northeast of Rush Island. Knodel, Tr. Vol. 1-A, 88:16-89:2. Ameren also converted two of its four units at the Meramec Energy Center to natural gas combustion. Michels, Tr. Vol. 5-B at 5:22-6:7. These changes decreased emissions from the Sioux and Meramec plants. (Ex. UU).

         6. Ameren did not install pollution control equipment at Rush Island or its Labadie Energy Center, although it began using lower sulfur coal at these two plants. Michels, Tr. Vol. 5-B, 5:22-6:7.

         7. Ameren has not submitted evidence demonstrating that Rush Island's emissions have decreased or stayed the same after its major modifications. At the remedies phase trial, and in its proposed findings of fact, Ameren did not present any data demonstrating Rush Island's emission rate before 2007. Without that information, Ameren cannot demonstrate that its emissions decreased or stayed the same after its major modifications.

         8. After the liability trial, I found that Ameren's modifications at Rush Island had increased emissions from Unit 1 by about 665 tons per year and from Unit 2 by about 2, 171 tons per year. Ameren Missouri, 229 F.Supp.3d 906, 955, 959.

         c. Rush Island Is One of a Small Minority of Similar Plants That Continue to Operate Without SO2 Scrubbers

         i. SO2 Scrubbers Are Widely Used in the Electric Utility Industry

         9. There are two ways to reduce the amount of SO2 emitted from a pulverized coal-fired electric generating unit: (1) reduce the sulfur content of the source coal, and (2) use a control system to capture SO2 before it is released to the atmosphere. The main types of control technology used to capture SO2 are FGD scrubbers and dry sorbent injection (DSI) technology. Staudt Test., Tr. Vol. 1-B, 12:20-13:14; Callahan Dep., Nov. 8, 2017, Tr. 44:3-10 (testimony of Ameren supervisor of environmental projects).

         10. FGD scrubbers have been widely used to reduce SO2 from coal-fired electricity generating units for decades. Staudt Test., Tr. Vol. 1-B, 15:2-4; Mar. 2009 Rush Island FGD Project Technology Selection Report (Pl. Ex. 1029), at AM-02638262 and AM-02638283; Missouri Department of Natural Resources (MDNR) Rule 30(b)(6) Dep., Aug. 10, 2018, Tr. 141:23-142:3.

         11. Scrubbers can either be “wet” or “dry, ” depending on the amount of moisture introduced into the gas stream. Wet FGD systems introduce more moisture, reducing the temperature of the gas stream and keeping some water in the form of droplets, rather than vapor. Water droplets create a more reactive environment, increasing the amount of SO2 “scrubbed” from the exhaust. Additionally, the lower temperatures in a wet FGD system are compatible with using limestone as the “scrubbing reagent.” Limestone is cheap and readily available in Missouri. Staudt Test, Tr. Vol. 1-B, 13:4-14:12; see also Mar. 2009 Rush Island FGD Project Technology Selection Report (Pl. Ex. 1029), at AM-02638262 and AM-02638283.

         12. Dry FGD systems cool the gas stream less than wet FGD systems do. They use hydrated lime as a reagent, remove less SO2 than dry systems do, and produce a dry waste product that must be disposed of at cost. Staudt Test, Tr. Vol. 1-B, 13:4-14:12; see also Mar. 2009 Rush Island FGD Project Technology Selection Report (Pl. Ex. 1029), at AM-02638262 and AM-02638283.

         13. Wet FGD scrubbers are the most effective SO2 control technology. They can remove more than 99% of a plants SO2 emissions. Dry FGD scrubbers are slightly less effective, but they can still remove more than 95% of a plants SO2 emissions, depending on the type of coal being burned. Staudt Test, Tr. Vol. 1-B, 14:13-15:1; Snell Test, Tr. Vol. 4-B, 50:8-22; Harley Dep., Apr. 11, 2018, Tr. 100:17-101:6 (testimony of Ameren Director of Project Engineering); see also March 2008 EPRI Report: Flue Gas Desulfurization Performance Capability (Pl. Ex. 1045), at AM-02699777 (“plants designed for 99% removal are scheduled to be operating in late 2008 or early 2009”).[3]

         14. As illustrated by Figure 1, scrubbers have been used at pulverized coal-fired power plants dating back to the early 1970s. As of 2016, most of the coal-fired generating capacity operating in the United States was produced by power plants with scrubbers. Specifically, 200, 000 megawatts of capacity was available at scrubbed coal-fired units out of 250, 000 megawatts of capacity at all coal-fired electric generating units. Staudt Test., Tr. Vol. 1-B, 15:2-25; Black & Veatch Rush Island FGD Technology Selection Report (Pl. Ex. 1029), at AM-02638262.

         15. Of that 200, 000 megawatts, wet scrubbers account for about 170, 000 megawatts, while dry scrubbers account for the other 30, 000 megawatts. Staudt Test., Tr. Vol. 1-B, 15:2-25, 19:9-21:15; see also Black & Veatch Rush Island FGD Technology Selection Report (Pl. Ex. 1029), at AM-02638262. Wet scrubbers are by far the dominant SO2 control technology for power plants.

         (Image Omitted)

         16. Scrubbers are currently installed on hundreds of coal-fired electric generating units, including approximately 84% of coal-fired power plants in the United States, weighted by generating capacity. Knodel Test., Tr. Vol. 1-A, 77:6-9; Staudt Test., Tr. Vol. 1-B, 15:17-16:10; see also Stumpf Dep., Mar. 27, 2018, Tr. 48:18-25 (Ameren project manager testifying that FGDs have become prevalent in the utility industry); Harley Dep., 51:1-52:25 (Ameren senior director testifying about scrubber “boom” in the utility industry); Mitchell Dep., May 30, 2018, Tr. 39:14-18 (Ameren project engineer testifying that scrubbers were well-established at the time of the FGD engineering studies for Rush Island).

         17. The vast majority of wet scrubbers operating at power plants today were installed on existing plants, as illustrated by Figure 2. About 120, 000 megawatts of the total 170, 000 megawatts of wet scrubber capacity operating in 2015 was installed on existing plants. Most of that scrubbed capacity was installed between 2005 and 2015. Staudt Test., Tr. Vol. 1-B, 65:13-66:16.

         (Image Omitted)

         18. Rush Island's continued operation without pollution controls has made it one of the largest sources of SO2 pollution in the United States. Between 1997 and 2017, Rush Island moved from being the 154th to the 10th highest man-made source of SO2 emissions in the country. Knodel Test, Tr. Vol. 1-A, 73:6-74:5.[4]

         ii. DSI Controls Are Not Commonly Installed on Units of Rush Island's Size

         19. Unlike FGD control technology, dry sorbent injection does not require a reaction vessel or added moisture. Instead DSI involves blowing reagent directly into the duct work downstream of the coal-fired boiler. A fabric filter or baghouse (hereinafter referred to as DSI-FF) can be added to remove particulate matter and increase overall removal efficiency of sulfate and other pollutants. Without a baghouse, an ordinary DSI system can remove 50% of SO2 emissions. With a baghouse, a DSI-FF can remove 70% SO2 reductions. Staudt Test., Tr. Vol. 1-B, 16:11-17:22; Snell Test, Tr. Vol. 4-B, 10:18-11:9; Harley Dep., Apr. 11, 2018, Tr. 163:2-19 (testifying that DSI typically can achieve 40 to 50% reductions).

         20. There are only a handful of units the size of Rush Island that currently use DSI for SO2 control. None of those systems were in operation prior to 2007 when Ameren undertook the major modifications at issue in this case. Neither party presented testimony identifying the source category to which those large units with DSI belong. Staudt Test., Tr. Vol. 1-B, 52:10-17; Tr. Vol. 2-A, 33:1-11.

         21. Ameren's expert Colin Campbell admitted that Rush Island would be the first power plant to have BACT determined based on the use of DSI, Test., Tr. Vol. 4-A, 98:3-7.

         d. Ameren Evaluated FGD Installation at Rush Island

         22. Although Ameren did not install control technology at Rush Island, Ameren spent about $8 million between 2008 and 2011 evaluating what control technology it should install. Staudt Test, Tr. Vol. 1-B, 17:23-19:7; Campbell Test., Tr. Vol. 4-A, 93:12-17; September 19, 2011 Project Plan (Pl. Ex. 1102), at AM-REM-00294508.

         23. Ameren completed two phases of its evaluation. “[T]he first phase evaluated the various . . . technologies and the second phase utilized the selected technology (Wet FGD system) to develop a design basis, scope and detailed cost estimate.” June 2, 2010 Request for Preliminary Work Order Authorization (Pl. Ex. 1095), at AM-REM-00288486.

         24. The consulting firms Black & Veatch and Shaw prepared independent feasibility studies during these phases. Staudt Test., Tr. Vol. 1-B, 17:23-20:22; AmerenUE Rush Island Power Plant Technology Selection Report (Pl. Ex. 1029); Shaw Technology Evaluation (Pl. Ex. 1069); Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 134:13-135:2, 135:22-136:11, 138:16-138:20, 138:25-139:6 (identifying Pl. Exs. 1029 and 1069 as the final Phase 1 reports, which were the best estimates available at the time concerning the feasibility of using wet scrubbers at Rush Island); Callahan Dep., Nov. 8, 2017, Tr. 119:17-120:9 (supervisor of the Phase 1 and 2 studies testifying Ameren hired multiple independent engineering firms to get a “better handle on potential cost as well as schedule”).

         25. Ameren's internal presentations indicate that these studies were designed to evaluate business planning and compliance options for a number of regulations, including the Cross-State Air Pollution Rule, rules for Hazardous Air Pollutants, and the New Source Review Program, the regulatory program at issue in this case. See June 1, 2010 CPOC Presentation, Scrubber Technology Assessment, Rush Island Plant (Pl. Ex. 1099), at AM-REM-00288980.

         26. In Phase 1, Shaw solicited bids from six vendors with extensive experience installing FGDs. Shaw Technology Evaluation (Pl. Ex. 1069), at AM-REM-00191161; Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 138:25-139:12. After reviewing this and other information, Shaw recommended wet FGD for further review and eventual installation at Rush Island. This decision was “[b]ased on the overall evaluation of experience, performance, arrangement, operating flexibility, constructability, modularization, site impacts, capital costs, operating costs, maintenance and repair costs, and other attributes such as permitting, social-economic costs and public relations.” Shaw Technology Evaluation (Pl. Ex. 1069), at AM-REM-00191196; Staudt Test, Tr. Vol. 1-B, 20:9-22:9.

         27. Black & Veatch also recommended wet FGD for further review in Phase 1.

         28. Ameren accepted the consulting firms' recommendations, selecting wet FGD for further evaluation in Phase 2. In Phase 2, Ameren requested more detailed cost estimates, engineering designs, and project execution plans for Rush Island. The Phase 2 reports were thousands of pages long, included bid information from FGD suppliers, and laid out a detailed schedule for installing FGD at Rush Island. Staudt Test., Tr. Vol. 1-B, 33:17-36:7; Callahan Dep., Nov. 7, 2017, Tr. 165:16-166:20; May 2010 Shaw Final Report (Pl. Ex. 1071); August 2010 Black & Veatch Execution Plan and Report (Pl. Ex. 1115).

         i. Ameren's Studies Recommended Wet FGD at Rush Island

         29. As part of its efforts, Ameren evaluated the technical and economic feasibility of installing FGDs at Rush Island. These evaluations were summarized in several presentations given to Ameren management. February 5, 2010 Project Review Board Presentation-Rush Island FGD (Pl. Ex. 1100), at AM-REM-00288998 to 289000; June 1, 2010 Corporate Project Oversight Committee (CPOC) Presentation, Scrubber Technology Assessment, Rush Island Plant (Pl. Ex. 1099), at AM-REM-00288981 to 288987; March 2, 2009 Economic Value Analysis for Rush Island FGD Project Plan (Pl. Ex. 1023), at AM-02634859 to 2634860.

         30. Based on its evaluations, Ameren's corporate project oversight committee agreed that wet FGD technology (1) was technically and economically feasible at Rush Island, (2) was the right choice for complying with, among other things, New Source Review, and (3) should be pursued further in contract development. Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 58:24-59:12, 59:25-60:22, 82:3-83:17.

         31. Ameren explained in one of its management presentations that wet FGD was its “technology choice for SO2 removal at Rush Island” because of its “advantages in cost, capability and flexibility” over other options. June 1, 2010 CPOC Presentation, Scrubber Technology Assessment, Rush Island Plant (Pl. Ex. 1099), at AM-REM-00288987.

         32. For coal-fired power plants, the emission limitation is typically stated in terms of pounds of pollutant per million BTU of heat input (lb/mmBTU). This unit represents the amount of pollution emitted per unit of fuel put into the boiler. Knodel Test., Tr. Vol. 1-A, 39:1-6. The emission limitation is always accompanied by an averaging time; for coal-fired power plants, typically the averaging time used is a 30-day rolling average to help address variability on a day-to-day basis. Knodel Test., Tr. Vol. 1-A, 39:7-11.

         33. Ameren concluded that the wet FGD systems have the advantage of “[demonstrated performance” to meet an SO2 emission rate guarantee of 0.06 lb/mmBTU. June 1, 2010 CPOC Presentation (Pl. Ex. 1099), at AM-REM-00288984; Callahan Dep., Nov. 8, 2017, Tr. 201:13-21 (agreeing that 0.06 pounds per million BTU was a demonstrated number that could be achieved).

         34. Ameren rejected the less-effective DSI technology because it was “[n]ot commercially demonstrated” and “not proven to meet low emissions requirements.” June 1, 2010 CPOC Presentation (Pl. Ex. 1099), at AM-REM-00288984.

         35. Ameren concluded that wet FGD also had advantages with respect to other environmental impacts, including the removal of Hazardous Air Pollutants (HAPs). Staudt Test., Tr. Vol. 1-B, 40:12-41:7. For example, wet FGD helps remove other acid gases. June 1, 2010 CPOC Presentation, Scrubber Technology Assessment, Rush Island Plant (Pl. Ex. 1099), at AM-REM-00288985. Wet FGD also helps remove organic HAPs, in part due to lower flue gas temperatures. Id Specifically, wet FGD helps remove oxidized mercury, sulfur trioxide, particulate matter, hydrogen chloride, and hydrogen fluoride. Direct Testimony of Mark Birk, Missouri Public Service Commission No. ER-2011-0028 (“Birk PSC Testimony”), Sept. 3, 2010 Tr. 3:20-4:2 (Pl. Ex. 1003); see also Callahan Dep., Nov. 8, 2017, Tr. 25:14-23. Wet FGD also eliminates landfill impacts because the gypsum byproduct can be sold to nearby cement plants. Id at AM-REM-00288986.

         36. Ameren concluded that wet FGD was an economically viable option as well. In Ameren's words “[economic evaluation supported” the use of wet FGD at Rush Island. March 2, 2009 Economic Value Analysis for Rush Island FGD Project Plan (Pl. Ex. 1023), at AM-02634859; February 5, 2010 Project Review Board Presentation-Rush Island FGD (Pl. Ex. 1100), at AM-REM-00288999; June 1, 2010 CPOC Presentation: Scrubber Technology Assessment Rush Island Plant (Pl. Ex. 1099), at AM-REM-00288984 to 288986; August 20, 2010 Rush Island Progress Overview (Pl. Ex. 1101), at AM-REM-00289177; Staudt Test., Tr. Vol. 1-B, 23:2-7; Callahan Dep., Nov. 8, 2017, Tr. 186:7-10.

         37. Wet FGD has a less expensive reagent than dry FGD or DSI. The wet FGD limestone reagent costs $28/ton; the dry FGD lime reagent costs $75/ton; and the DSI trona reagent costs $150/ton. Shaw Technology Evaluation (Pl. Ex. 1069), at AM-REM-00191180.

         38. Ameren also determined that wet FGDs would not require the new induced draft booster fans that dry FGD would require. Instead, the existing fans would only need to be upgraded. Foregoing the new fans would reduce capital costs at Rush island by $37 to $50 million and would result in lower plant energy consumption. An additional $20 million could be saved by using limestone milling equipment at Ameren's Sioux power plant. June 1, 2010 CPOC Presentation, Scrubber Technology Assessment, Rush Island Plant (Pl. Ex. 1099), at AM-REM-00288983; Staudt Test., Tr. Vol. 1-B, 36:20-38:7, 55:5-15.

         39. Wet FGD also provides greater fuel flexibility for Rush Island. Because wet FGD removes more SO2 per ton of coal, Ameren could use higher sulfur coal in some circumstances while still meeting emissions limitations. Staudt Test., Tr. Vol. 1-B, 21:16-22:9; Callahan Dep., Nov. 8, 2017, Tr. 203:13-204:3; see also Birk PSC Testimony (Pl. Ex. 1003) Tr. 4:8-15 (describing fuel flexibility as advantage for wet FGDs in Sioux rate case).

         40. Ameren's final project plan estimated that the total cost of installing wet FGDs at Rush Island would range from $650 million to $960 million, based on estimates provided by multiple engineering firms. September 19, 2011 Project Plan (Pl. Ex. 1102), at AM-REM-00294509; see also February 5, 2010 Project Review Board Presentation-Rush Island FGD (Pl. Ex. 1100), at AM-REM-00289005; Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 87:11-88:1 (identifying these costs as the best estimates available to Ameren at the time of the cost of scrubbing Rush Island).

         41. As part of its economic evaluation, Ameren also compared the estimated costs of installing wet FGDs at Rush Island to the costs incurred by other electric utilities for wet FGD installations. Ameren concluded that the costs of installing FGDs at Rush Island would be consistent with the costs borne by the rest of the industry to install scrubbers. See February 5, 2010 Project Review Board Presentation-Rush Island FGD (Pl. Ex. 1100), at AM-REM-00289006; Staudt Test. Tr. Vol. 1-B, 23:10-25:16, 56:20-57:6; Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 90:6-91:3.

         42. Ameren also told the Missouri Public Service Commission in a formal planning document that it planned to install scrubbers on Rush Island and Labadie. Michels Test., Tr. Vol. 5-B, 17:6-18:19.

         43. Wet FGD is an economically and technically feasible control technology for Rush Island. Staudt Test., Tr. Vol. 1-B, 42:19-24, 48:22-49:11.

         ii. Ameren's Studies Confirmed the SO2 Emission Rates Achievable at Rush Island

         44. To design an FGD system cost estimate, a study must define the emission rate requirements of the proposed system. Staudt Test., Tr. Vol. 1-B, 6:19-7:12, 25:19-26:4; Callahan Dep., Nov. 8, 2017, Tr. 92:12-93:3, 129:8-130:9.

         45. During the first two phases of Ameren's FGD study efforts, Ameren's engineering firms based their design work and cost estimates on an SO2 emission rate target of 0.06 lb/mmBTU. May 2010 Shaw Final Report (Pl. Ex. 1071), at AM-REM-00194954 to 194955; August 2010 Black & Veatch Execution Plan and Report (Pl. Ex. 1115), at AM-REM-00324205 to 324206; Staudt Test., Tr. Vol. 1-B, 26:5-27:4; Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 145:21-146:3, 147:21-147:24, 158:13-21, 161:2-21; Callahan Dep., Nov. 8, 2017, Tr. 51:9-15, 123:8-124:14.

         46. Ameren initially transmitted this 0.06 lb/mmBTU design rate to its outside engineering firms on October 3, 2008. When it did so, Ameren requested that the engineers assess whether FGDs could be designed to achieve even greater SO2 reductions. Oct. 3, 2008 Letter to Black & Veatch (Pl. Ex. 1086) (requesting an assessment of “maximum achievable design basis” for SO2 removal, “even if greater than the design values”); Oct. 3, 2008 Letter to Stone & Webster (Shaw) (Pl. Ex. 1085) (same). Concurrently, Ameren instructed its engineering firms to use a slightly higher “operating” value of 0.08 lb/mmBTU, which would “represent permit requirements” for the FGDs. Id; Callahan Dep., Nov. 8, 2017, Tr. 93:20-94:5, 123:8-124:14.

         47. Depending on the fuel being burned, Ameren estimated that these emission rate targets would reflect removal efficiencies of up to 99%. If Rush Island continued to burn lower sulfur PRB coal, then a design emission rate of 0.06 lb/mmBTU would reflect a 95% SO2 reduction, while an operating rate of 0.08 lb/mmBTU would reflect a 90% reduction. Mar. 2, 2009 Economic Value Analysis for Rush Island FGD Project Plan (Pl. Ex. 1023), at AM-02634848.

         48. As part of its FGD study efforts, Ameren also obtained FGD proposals from all of the major FGD suppliers in the United States, all of whom indicated that they could supply an FGD system capable of meeting Ameren's emission targets. Staudt Test., Tr. Vol. 1-B, 72:19-73:24.

         49. For example, the company Alstom submitted a wet FGD proposal to Ameren in May 2009. May 21, 2009 Alstom WFGD Indicative Submittal (Pl. Ex. 1068). At that time, Alstom had over 50, 000 MW of wet FGD systems either operating or under contract. Id at AM-REM-00191035. Alstom confirmed it could meet Ameren's emission requirements, id, and highlighted its experience with several relevant wet FGD projects for Rush Island:

• A wet FGD installed for a new 750-MW unit at the JK Spruce plant in 2009. The plant burns PRB coal and was provided an emission guarantee of 0.06 lb/mmBTU or 96% removal.
• Wet FGDs contracted to be installed on two existing 450-MW units at the Coronado plant. The plant burns PRB and was provided an emission guarantee of 0.04 lb/mmBTU or 97% removal.
• A wet FGD installed on an existing 720-MW unit at the Iatan plant in 2008. The Iatan plant is located in Missouri, burns PRB coal, and was provided an emission guarantee of 0.021 lb/mmBTU or 98% removal.

Id at AM-REM-00191071-73; see also Staudt Test, Tr. Vol. 1-B, 74:4-76:9.

         50. After the Phase 2 reports were finalized, Ameren began the specification development process for wet FGD at Rush Island. Aug. 5, 2010 Conference Mem. (Pl. Ex. 1088). The final specification was thousands of pages long and extremely detailed. Staudt Test., Tr. Vol. 1-B, 42:25-44:13; Construction Specification Section 1600-Design Basis (Pl. Ex. 1144).

         51. As part of the specification development process, Ameren tasked a team of its engineers to confirm the emission rate targets for the FGDs and prepare the specification in coordination with Ameren's outside engineers. Stumpf Dep., Mar. 27, 2008, Tr. 63:21-64:15, 151:6-153:22, 154:11-17, 158:22-159:20.

         52. As a result of the specification development process, on September 23, 2010, Ameren lowered its SO2 emission rate requirements for the Rush Island FGDs to 0.04 lb/mmBT U.Sept. 23, 2010 Letter to Black & Veatch (Pl. Ex. 1076); Nov. 1, 2010 Conference Mem. (Pl. Ex. 1091), at AM-REM-00286756; Stumpf Dep., Mar. 27, 2008, Tr. 190:12-22, 198:2-8, 218:17-219:9, 238:11-19.

         53. The 0.04 lb/mmBTU SO2 emission rate was the same emission rate guarantee that Ameren obtained for the FGD installed in late 2010 at its Sioux plant. Staudt Test., Tr. Vol. 1-B, 71:13-20; Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 206:10-207:11, 208:6-9.

         54. Based on the coal expected to be used at Rush Island, the 0.04 lb/mmBTU emission rate reflects SO2 removal efficiencies of 95 to 97 percent. Nov. 17, 2010 Letter from BV to Ameren (Pl. Ex. 1174) at BV2_20204414-15; Staudt Test. Tr. Vol. 1-B, 44:14-46:4.

         55. Ultimately, an emission rate of 0.04 lb/mmBTU was used as the design basis in the construction specification. Staudt Test., Tr. Vol. 1-B, 42:25-44:13; Construction Specification Section 1600-Design Basis (Pl. Ex. 1144), at AM-REM-00538825; see also Stumpf Dep., Mar. 27, 2008, Tr. 252:6-253:10, 254:9-23, 286:20-287:5. This rate was retained as the design basis until Ameren suspended the FGD project in September 2011. September 19, 2011 Project Plan (Pl. Ex. 1102), at AM-REM-00294511; Staudt Test, Tr. Vol. 1-B, 44:14-46:4; Stumpf Dep., Mar. 27, 2008, Tr. 286:20-287:5.

         56. The pollution control experts in this case agree that an SO2 emission rate of 0.04 lb/mmBTU would be an achievable design emission rate for a wet FGD at Rush Island. Staudt Test, Tr. Vol. 1-B, 46:5-8; Snell Test, Tr. Vol. 4-B, 51:13-52:16.

         iii. Ameren's Studies Demonstrate How Quickly Wet FGD Can Be Installed

         57. When Ameren suspended the Rush Island FGD project in September 2011, its engineers put into place a “reactivation plan” in case FGDs later became required. September 9, 2011 Project Plan (Pl. Ex. 1102) at AM-REM-00294510 (“The following link is to a document that outlines instructions for reactivating the project including … an estimated schedule . . . [:] WFGD Specification Reactivation.”); see also Staudt Test., Tr. Vol. 1-B, 46:9-47:23; Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 228:6-15.

         58. Ameren's reactivation plan provided that the “Complete WFGD Specification turn-over from Shaw” should be “considered the starting point for picking up where the original [FGD] team left off.” WFGD Specification Reactivation Instructions (Pl. Ex. 1141).

         59. The reactivation plan also included a schedule for completing the project upon reactivation. The plan provided that, upon reactivation, engineers would need two weeks to verify the chosen SO2 technology (wet FGD). If the technology selection changed, engineers would need an additional ten weeks to create a new specification. After management approval, Ameren could send the project to FGD suppliers for bid within six months from re-activation (which was May 2016, under the then-proposed schedule). September 19, 2011 Project Plan (Pl. Ex. 1102), at AM-REM-00294512, AM-REM-00294580. Based on that schedule, the FGD could have been “on-line” by the end of 2020, representing a four and one-half-year process from the time of reactivation. Id.

         60. This reactivation plan allows Ameren to install FGD controls more quickly by taking advantage of all the resources already invested in engineering wet FGDs for Rush Island. Staudt Test., Tr. Vol. 1-B, 46:18-48:6. By the time the project was suspended, Ameren had invested 3 years of engineering work and approximately $8 million on the project. September 19, 2011 Project Plan (Pl. Ex. 1102), at AM-REM-00294508; see also Stumpf Dep., Mar. 27, 2008, Tr. 64:21-65:2, 291:18-292:19.

         61. Company documents refer to the “[e]ngineering activities for Rush Island FGD” as “a significant risk mitigation strategy in terms of cost and schedule.” 2010 Project Review Board Presentation-Rush Island FGD (Pl. Ex. 1100), at AM-REM-00289019; see also, e.g., Ex. 1095, at AM-REM-00288487 (“Continuing with engineering activities for Rush Island FGD is a risk mitigation strategy for both cost and schedule.”). The “risk” was the possibility that FGDs could be required by various drivers. Ameren's “response” was to “[g]et an early start on engineering in order to act as quickly as possible.” Ameren Rule 30(b)(6) Dep., Nov. 7, 2017, Tr. 44:21-45:10, 47:24-48:13, 48:16-49:12, 101:18-103:1.

         62. In light of the extensive amount of engineering work already completed, I find that Ameren would be able to install FGDs at Rush Island within four and one-half years from the date of the requirement to do so. September 19, 2011 Project Plan (Pl. Ex. 1102), at AM- REM-00294512, AM-REM-00294580 (May 2016 reactivation date and December 2020 online date).

         II. RUSH ISLAND'S VIOLATIONS HAVE LED TO MORE THAN 162, 000 TONS OF EXCESS SULFUR DIOXIDE POLLUTION

         63. At the time Rush Island's boilers were modified, the surrounding airshed had attained the NAAQS for fine particulate matter, a key by-product of SO2. Morris Test., Tr. Vol. 4-B, 69:4-24. Although part of Jefferson County is currently a non-attainment area for SO2 itself, at the time of the modifications at Rush Island, it was in attainment of the SO2 NAAQS. Therefore, the requirement to obtain a PSD permit and meet BACT emissions limitations applied to Rush Island. Ameren Missouri, 229 F.Supp.3d at 986; 42 U.S.C. §§ 7471, 7475.

         64. Missouri is the PSD permitting authority for facilities in Missouri, pursuant to an EPA-approved State Implementation Plan, and is subject to EPA oversight. Knodel Test., Tr. Vol. 1-A, 45:2-23, 79:10-17; MDNR Rule 30(b)(6) Dep., Aug, 10, 2018, Tr. 101:13-15.

         a. PSD Requires the Best Available Control Technology

         i. BACT Determination Is a Five-Step Process

         65. Missouri and the EPA use the same definition of BACT, which applies to both new and modified sources. Campbell Test., Tr. Vol. 4-A, 90:24-91:6.

         66. BACT is “an emission limitation based on the maximum degree of reduction of each pollutant subject to regulation . . . which the permitting authority, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such facility . . . .” 42 U.S.C. § 7479(3); Knodel Test., Tr. Vol. 1-A, 38:11-41:13.

         67. An applicant for a PSD permit bears the responsibility when submitting its application of addressing all the steps in the BACT analysis. Knodel Test., Tr. Vol. 1-A, 51:19-23.

         68. The permitting authority reviews each submission and determines if the analysis is correct. If the applicant's BACT analysis is incorrect, the permitting authority modifies the analysis to arrive at the appropriate BACT emissions limitation. In this case, Ameren should have prepared the initial BACT analysis, but the final BACT determination would have been made by MDNR with EPA oversight. Knodel Test, Tr. Vol. 1-A, 44:18-45:23, 53:11-54:18; Dec. 1, 1987 Memo on Improving NSR Implementation (Pl. Ex. 1320) at CampbellEXP0039928.

         69. Because BACT requires “the maximum degree of reduction, ” BACT rates tend to get more stringent over time as pollution control technologies improve. Staudt Test., Tr. Vol. 1-B, 70:10-14, 80:23-81:3.

         70. The EPA's Draft NSR Workshop Manual (“NSR Manual”) outlines the BACT analysis process used by most permitting authorities, including MDNR. Knodel Test., Tr. Vol.

         1-A, 48:12-20, 49:23-26, 50:2-6; MDNR Rule 30(b)(6) Dep., Aug. 10, 2018, Tr. 140:3-21.

         71. The NSR Manual is the most commonly-referenced, commonly used guidance document for BACT analyses in the country. It is the most widely-distributed guidance relating to NSR that is not the regulations themselves. Campbell Test., Tr. Vol. 4-A, 90:4-10; see also Id. at 88:17-89:19 (Ameren expert explaining that he provides a copy of the NSR Manual to participants in his BACT course, which focuses on the top-down method).

         72. MDNR permit engineers rely on the NSR Manual in doing PSD reviews. MDNR Rule 30(b)(6) Dep., Aug. 10, 2018, Tr. 140:3-21.

         73. Determining BACT involves a five-step, top-down process. Knodel Test., Tr. Vol. 1-A, 50:2-6; NSR Manual (Pl. Ex. 1190), at AM-REM-00544123-MDNR; MDNR Rule 30(b)(6) Dep., Aug. 10, 2018, Tr. 101:25-102:24, 106:4-7.

         74. As part of the five-step process, the permit applicant

a. [Step One] Identifies all relevant control technologies for reducing the pollutant at issue, Knodel Test., Tr. Vol. 1-A, 50:7-16; NSR Manual (Pl. Ex. 1190), at AM-REM-00544123-MDNR.
b. [Step Two] Removes any technologies that are not technically feasible for the project in question, Knodel Test., Tr. Vol. 1-A, 50:17-24; NSR Manual (Pl. Ex. 1190), at AM-REM-00544123-MDNR,
c. [Step Three] Ranks the remaining technologies in order of control effectiveness, Knodel Test., Tr. Vol. 1-A, 50:25-51:10; NSR Manual (Pl. Ex. 1190), at AM-REM-00544123-MDNR,
d. [Step Four] Evaluates the technologies in sequence, from most effective to least effective, and selects the most effective technology that is achievable based on energy, environmental, and economic impacts and other costs, Knodel Test., Tr. Vol. 1-A, 51:11-13, 80:8-81:3; NSR Manual (Pl. Ex. 1190), at AM-REM-00544123-MDNR, and
e. [Step Five] Selects an emissions limitation rate based on the design and performance of other pollution sources that have already installed the control technology. Knodel Test., Tr. Vol. 1-A, 51:14-18; NSR Manual (Pl. Ex. 1190), at AM-REM-00544123-MDNR.

         75. Step Four of the method gives the BACT determination a “top-down” character, because it starts with the top control option and moves in sequence to lesser options. If the energy, environmental, and economic impacts of the top option indicate that the technology is “achievable, ” then the analysis stops: the top control is the BACT technology. If the top control is not achievable, the next most-stringent control options are considered in sequence, until an achievable technology is settled on. Staudt Test., Tr. Vol. 1-B, 53:16-54:21; Campbell Test., Tr. Vol. 4-A, 92:20-25; NSR Manual (Pl. Ex. 1190), at AM-REM-00544119-MDNR. Again, as soon as an achievable technology is found in this sequence, the analysis stops, and that technology determines BACT.

         76. The top-down approach applies regardless of whether a plant is new or is undergoing a modification. Knodel Test., Tr. Vol. 1-A, 106:20-25. Under the top-down approach, the burden of proof is on the applicant to justify why the proposed source is unable to apply the best technology available. Dec. 1, 1987 Memo on Improving NSR Implementation (Pl. Ex. 1320) at CampbellEXP0039928; Knodel Test., Tr. Vol. 1-A, 44:5-17.

         77. Almost all Clean Air Act permitting agencies, including the Missouri Department of Natural Resources (MDNR), use the top-down method that is set forth in the EPA's 1990 New Source Review Workshop Manual. Campbell Test., Tr. Vol. 4-A, 48:7-16, 90:20-23; Knodel Test, Tr. Vol. 1-A, 49:21-50:1, 79:22-80:2.

         Cost-Effectiveness Calculations in a Top-Down BACT Analysis

         78. Cost is one of several criteria considered in Step 4 of the BACT process, where applicants determine whether each control technology is achievable. Knodel Test., Tr. Vol. 1-A, 80:8-81:3.

         79. However, step four of the BACT process is not a search for the most cost-effective controls; nor is it a cost-benefit analysis. Id; Staudt Test., Tr. Vol. 1-B, 58:5-16. Rather, cost considerations are measured by what is achievable. 42 U.S.C. § 7479(3). “In the absence of unusual circumstance, the presumption is that sources within the same source category are similar in nature, and that cost and other impacts that have been borne by one source of a given source category may be borne by another source of the same source category.” NSR Manual (Pl. Ex. 1190), at AM-REM-00544146-MDNR; Staudt Test. Vol. 1-B, at 63:14-64:6.

         80. Similar language is found elsewhere in the NSR Manual: “BACT is required by law. Its costs are integral to the overall cost of doing business . . . Thus, where a control technology has been successfully applied to similar sources in a source category, an applicant should concentrate on documenting significant costs differences, if any, between the application of the control technology on those other sources and the particular source under review.” NSR Manual (Pl. Ex. 1190) at AM-REM-00544148-MDNR.

         81. MDNR specifically relies on the NSR Manual's guidance in considering the economic impacts of pollution controls under a BACT analysis. Staudt Test., Tr. Vol. 1-B, 64:7-10; Norborne PSD Permit (Pl. Ex. 1180), at AM-REM-00503313-MDNR (quoting NSR Manual); see also MDNR Rule 30(b)(6) Dep., at 138:20-139:6, 140:22-141:22) (MDNR witness testifying that “when a permit writer looks at a permit application from, for example, a coal-fired utility, [] they would look towards other coal-fired utilities to determine the appropriate controls and what controls are already being used”). The focus is on other sources in the same source category, because they would face similar technical and economic circumstances. Staudt Test., Tr. Vol. 1-B, 64:11-19.

         ii. Cost-Effectiveness Does Not Determine BACT

         82. As one criterion under step four of the top-down method, applicants can also prepare calculations of cost-effectiveness. Average (or total) cost-effectiveness measures the cost of a control option in annualized costs per ton of pollution that it would reduce in a year. Staudt Test., Tr. Vol. 1-B, 57:19-58:4; NSR Manual (Pl. Ex. 1190), at AM-REM-00544153-MDNR to 544154-MDNR.

         83. In contrast, incremental cost-effectiveness compares how much each additional ton of reduction costs as compared to another control option. Campbell Test., Tr. Vol. 4-A, 114:19-115:7. Staudt Test., Tr. Vol. 1-B, 92:1-14; NSR Manual (Pl. Ex. 1190), at AM-REM-00544158. Incremental cost-effectiveness is useful when comparing technologies “next” to each other in the effectiveness rankings, provided those controls result in similar emission rates. Staudt Test., Tr. Vol. 1-B, 92:15-23, NSR Manual (Pl. Ex. 1190), at AM-REM-00544158-MDNR (“The incremental cost effectiveness calculation compares the costs and emissions performance level of a control option to those of the next most stringent control option …”) (emphasis added).

         84. The NSR Manual cautions against over-reliance on incremental cost-effectiveness in eliminating a control under Step Four of the top-down method. Pl. Ex. 1190, at AM-REM-00544163-MDNR (“[U]ndue focus on incremental cost effectiveness can give an impression that the cost of a control alternative is unreasonably high, when, in fact, the cost effectiveness, in terms of dollars per total ton removed, is well within the normal range of acceptable BACT costs.”); see also In re General Motors, Inc., PSD Appeal No. 01-30, 10 E.A.D 360, 371 (E.A.B. Mar. 6, 2002) (the NSR Manual “places primary stress on the average cost measure”).

         iii. NSPS Do Not Fundamentally Alter the BACT Process

         85. Alongside BACT requirements, all new major sources of pollution must meet “New Source Performance Standards” (NSPS). Pursuant to Section 111 of the Clean Air Act, the EPA establishes NSPS for different source categories. See 42 U.S.C. § 7411.

         86. Ameren's expert admitted that the EPA sets the NSPS at rates that can be reasonably met by all new and modified sources in a source category, even though individual sources might be capable of lower emission rates. Campbell Test., Tr. Vol. 4-A, 98:14-18.

         87. An applicable NSPS serves as a “floor” for the emission limit established as BACT. The BACT limit cannot be less stringent than the NSPS. 42 U.S.C. § 7479(3); In re Columbia Gulf Transm'n Co., PSD Appeal No. 88-11, 2 E.A.D. 824, 1989 WL 266361, at *4 (EPA 1989).

         88. As the NSR Manual explains: “[T]he only reason for comparing control options to an NSPS is to determine whether the control option would result in an emission level less stringent than the NSPS. If so, the option is unacceptable.” Ex. 1190, at AM-REM-00544129-MDNR (emphasis added).

         89. “Simply meeting or exceeding the NSPS does not attest to the correctness of a BACT determination.” Columbia Gulf 1989 WL 266361, at *4. That NSPS sets “a ‘floor' on emissions does not fundamentally change the BACT process of determining the ‘best' available technology.” United States v. Ameren Missouri, No. 4:11 CV 77 RWS, 2019 WL 1384631, at *3 (E.D. Mo. Mar. 27, 2019) (citing Columbia Gulf at *4).

         90. The top-down method was originally developed in response to concerns that BACT analyses were inappropriately defaulting to the less-stringent and generally-applicable NSPS standards, without giving enough consideration to more stringent control options required for BACT. Knodel Test., Tr. Vol. 1-A, 47:14-48:9; June 13, 1989 Statement on Top Down BACT (Pl. Ex. 1321), at CampbellEXP0040089.

         b. FGD Scrubbers Constitute BACT for the Vast Majority of Pulverized Coal-Fired Power Plants

         i. The Electric Power Utility Industry Recognizes That FGD Constitutes BACT

         91. BACT for a pulverized coal-fired power plant generally requires either wet or dry FGD scrubbers. Staudt Test., Tr. Vol. 1-B, 95:1-12. This trend results from the top-down process: scrubbers are the most-effective pollution controls. As the industry has progressed, an increasing number of plants have used scrubbers, demonstrating their achievability in different circumstances. See, e.g., supra Figure 1; ¶ 14.

         92. As Ameren's Senior Director of Engineering and Project Management, Duane Harley, explained: “There's lots of different types of scrubbers in the market. Any one of those could be considered BACT. … Could be wet. Could be dry.” According to Harley, dry scrubbers would be preferred in arid locations such as the West and wet scrubbers would typically be installed on plants that are larger than 300 MW. Harley Dep. Tr., Apr. 11, 2018, 97:5-98:8.

         93. The electric power utility industry recognizes that FGD constitutes BACT for coal-fired units. In March 2008, the Electric Power Research Institute published a report on the performance capability of FGD systems. Staudt Test., Tr. Vol. 1-B, 85:7-86:19; see also supra Footnote 3. The report noted: “Many coal-fired units must comply with the Clean Air Act (through New Source Review), consent decrees, or the Clean Air Visibility rules. Operators of these units have or will have to commit to installing FGD systems that meet the regulatory requirements of best available control technology (BACT) … .” 2008 EPRI Report (Pl. Ex. 1045), at AM-02699795.

         94. Ameren itself has acknowledged that BACT may require FGD at Rush Island. Specifically, an Ameren presentation prepared in 2011 for the Missouri Public Service Commission indicates: “New Source Review lawsuit by EPA may require flue gas desulfurization (FGD) systems or scrubbers at Rush Island.” April 2011 Presentation: Ameren Missouri Long Term Low Sulfur Coal Supply (Pl. Ex. 1009), at AM-02225205. It is well-understood that BACT at Rush Island would likely require installing scrubbers.

         ii. During The Past Twenty Years, Every BACT SO2 Determination for a Pulverized Coal-Fired Power Plant Has Required FGD

         95. The prevalence of FGD at other plants is demonstrated by databases maintained by EPA Headquarters and Region 7. EPA Headquarters maintains a RACT BACT LAER Clearinghouse (RBLC) with a searchable database of BACT permit decisions made throughout the United States. The RBLC catalogues permitted technology and emissions limitations for individual facilities. Knodel Test., Tr. Vol. 1-A, 52:5-53:7.

         96. From about 2002 until about 2015, EPA Region 7 also maintained a New Source Review Electricity Generating Unit Coal-Fired Spreadsheet on its website. The spreadsheet was designed to include every NSR application that had been submitted across the United States. It included information such as unit size, type of controls, and BACT limits. Knodel Test., Tr. Vol. 1-A, 34:20-35:8, 52:24-53:10.

         97. Every BACT determination for SO2 emissions from pulverized coal-fired power plants during the past twenty years has required wet or dry FGD as the required pollution control technology. Staudt Test, Tr. Vol. 1-B, 77:20-78:2.

         98. During this period, MDNR determined that BACT at a coal-fired power plant in Southwest Missouri requires the use of FGD controls for SO2. Chipperfield v. Mo. Air Conservation Comm'n, 229 S.W.3d 226, 240 (Mo.Ct.App. 2007). As noted by the Missouri Court of Appeals in a decision upholding MDNR's BACT determination: “In general, pulverized coal-fired boilers burning low-sulfur coal, such as Powder River Basin (‘PRB') coal, may use dry FGD, while boilers burning high-sulfur coals, such as eastern bituminous coal, must use wet FGD.” Id.

         99. EPA expert Jon Knodel is an environmental engineer with EPA Region VII who reviews permits for coal-fired power plants in Missouri. Id at 32:17-20, 54:3-55:3. Based on Knodel's count, between 1999 and 2008, MDNR issued four air permits for coal-fired power plants. Knodel Test., Tr. Vol. 1-A, 54:22-55:3. All of these required either wet or dry FGD as the SO2 control technology. Id at 57:23-58:2, 59:10-15, 59:18-60:21, 60:24-61:3.

         100. In 1999, MDNR issued a PSD permit to Kansas City Power and Light's Hawthorn plant with a 30-day SO2 BACT limit of 0.12 lb/mmBTU, based on the use of a dry FGD. Knodel Test, Tr. Vol. 1-A, 59:10-17.

         101. In 2004, MDNR issued a PSD permit for City Utilities' proposed Southwest power plant with a 30-day SO2 limit of 0.095 lb/mmBTU, based on the use of dry FGD. Knodel Test., Tr. Vol. 1-A, 55:4-58:2; Dec. 15, 2004 Permit to Construct (Pl. Ex. 1004), AM-00134223-EPA, AM-00134224-EPA; see also Chipperfield, 229 S.W.3d at 240 (describing determination of BACT rate). In doing so, MDNR explicitly found that the costs of both wet and dry FGD were reasonable. Staudt Test., Tr. Vol. 1-B, 67:3-68:13; In the Matter of Appeal of City Utilities PSD Permit 10/11/05 Hr'g Tr. (Pl. Ex. 1177) at 16:18-17:16.

         102. In 2006, MDNR issued a permit for Kansas City Power and Light's Iatan power plant with 30-day SO2 limits of 0.1 lb/mmBTU for the existing unit (Unit 1) and 0.09 lb/mmBTU for the new unit (Unit 2), based on the use of wet FGD at both units. Knodel Test., Tr. Vol. 1-A, 59:18-60:9; Jan. 31, 2006 Permit to Construct (Pl. Ex. 1034), at AM-02693650-53. After these permit limits were challenged by a third party, an amended permit was issued in 2007 with lower SO2 limits of 0.07 lb/mmBTU for Unit 1 and 0.06 lb/mmBTU for Unit 2. Knodel Test., Tr. Vol. 1-A, 60:10-21; July 13, 2007 Amendment to Permit (Pl. Ex. 1283), at AMEREMJES0007121-25; Staudt Test., Tr. Vol. 1-B, 81:20-82:13.

         103. In 2008, MDNR issued a PSD permit to Associated Electric Cooperative, Inc. (AECI) for the proposed Norborne plant with 30-day SO2 limits of 0.07 to 0.08 lb/mmBTU, based on the use of dry FGD. Knodel Test., Tr. Vol. 1-A, 60:22-61:3; Feb. 22, 2008 Letter Enclosing Permit to Construct (Pl. Ex. 1180), at AM-REM-00503274-MDNR to 3275-MDNR.

         104. These Missouri permit limits are consistent with those issued by other permitting authorities for coal-fired power plants during the same period, all of which also required the use of wet or dry FGD. Staudt Test., Tr. Vol. 1-B, 77:20-78:2.

         105. For example, Ameren's expert Colin Campbell testified about a PSD permit issued for the following non-Missouri plants: (1) In 2005, Newmont's TS power plant was permitted for an SO2 limit of 0.065 lb/mmBTU; (2) in 2007, LS Power's Longleaf power plant was permitted for the same emission rate (0.065 lb/mmBTU); and (3) also in 2007, Basin Electric's Dry Fork power plant in Wyoming was permitted for an SO2 limit of 0.07 lb/mmBTU. See Campbell Test., Tr. Vol. 4-A, 107:13-108:4, 131:17-132:1.

         c. The Parties' Competing BACT Analyses

         106. During trial, the parties each presented expert testimony concerning what BACT would have been at the time that Ameren modified Rush Island. Based on what BACT would have been, I can determine how much SO2 Ameren would have emitted had it complied with the law. Then, I can subtract that lower pollution amount from the SO2 emissions that were actually released to determine Rush Island's “excess emissions.” For clarity, I refer to this determination as a “historic BACT analysis.” According the correct historic BACT analysis, Ameren's failure to install scrubbers at Rush Island resulted in 162, 000 tons ...


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