United States v. Missouri

MEMORANDUM OPINION AND ORDER

RODNEY W. SIPPEL, UNITED STATES DISTRICT JUDGE

‘“Why don’t you go up to the Range?’ somebody said to me. ‘The air is pure, and they have the best water on earth.’ ”

- W.P. Kinsella

Shoeless Joe

TABLE OF CONTENTS

INTRODUCTION .. .913

FINDINGS OF FACT .. .916

I. BACKGROUND CONCERNING THE DEFENDANT, THE RUSH ISLAND PLANT, AND THE APPLICABLE REGULATIONS .. .916

A. The Defendant ... 916

B. The Rush Island Coal-Fired Power Plant ...917

C. Facts Concerning General Applicability of the Prevention of Significant Deterioration Program ... 917

D. Notice of the Violations Alleged in the Complaint ... 918

II. FACTS CONCERNING THE 2007 AND 2010 BOILER UPGRADES AT RUSH ISLAND UNITS 1 AND 2 .. .918

A. The Boiler Components at Issue and Their Role in Burning Coal to Generate Electricity ... 919

B. Operational Problems Leading up to the 2007 and 2010 Boiler Upgrades ...922

1.Boiler tube leaks .. .923

2. Slagging and fouling ... 924

3. Pluggage ... 925

4. Availability losses caused by the replaced components prior to the 2007 and 2010 outages as reported to the Generating Availability Data System ...931

5. Reduction in the maximum capability of Unit 2 prior to the 2010 outage ... 934

C. The Approval and Engineering Process for the 2007 and 2010 Major Modifications ...936

D. Ameren Justified Replacing the Economizers, Reheaters, Lower Slopes, and Air Preheaters Because They Would Improve Operations and Allow the Units to Generate More ... 937

E. Implementation of the 2007 and 2010 Major Modifications ... 942

F. The Cost of the 2007 and 2010 Major Modifications ... 944

III.THE 2007 AND 2010 BOILER UPGRADES EACH RESULTED IN A SIGNIFICANT NET EMISSIONS INCREASE OF S02 WITHIN THE MEANING OF THE PSD REGULATIONS ...945

A. Overview .. .945

B. GADS-Based Emissions Calculations for Rush Island Units 1 and 2 ...946

1. Results of projected emissions increase calculations based on the GADS data at Rush Island Unit 1 ...952

2. Rush Island Unit 1 actual emission increases ... 954

3. Results of projected emissions increase calculations based on the GADS data at Rush Island Unit 2 ...956

4. Rush Island Unit 2 actual emission increases based on availability ...958

*912 C. Emissions Increases Based on Unit 2 Capability Analyses ... 959

1. The expected capability and efficiency impact of the Unit 2 boiler upgrade ... 959

2. Actual increases in Unit 2’s capability ...962

3. Dr. Sahu’s emission calculations based on Unit 2’s capacity increase ...965

4. Nqthing in Mr. Caudill’s opinions negates Mr. Koppe’s calculations of capability increases ... 965

' D. PROSYM-BASED EMISSIONS CALCULATIONS .. .966

1. Production cost modeling at Am-eren • ••967

2. Dr. Hausman’s sensitivity analy-ses ... 968

a. Unit 1 sensitivity analysis ...968

b. Unit 2 sensitivity analysis ...969

3. Dr. Hausman’s “with and without” analyses ... 969

a. Unit 1 analysis ... 970

b. Unit 2 analysis ... 971

IV. AMEREN HAS FAILED TO MEET ITS BURDEN TO ESTABLISH THE APPLICABILITY OF THE DEMAND GROWTH EXCLUSION ...971

A. Background about the Market for Rush Island’s Generation ... 971

B. Ameren’s Failure of Proof Regarding Demand Growth as a Cause of Increased Emissions ... 974

V. AMEREN’S NSR EMISSION ANALYSES .. .975

A. Ameren Performed No Pre-Project NSR Analysis for Either Project ... 976

1. Rush Island Unit 1 .. .976

2. Rush Island Unit 2 ... 977

B. Ameren’s Post Hoc Reasonable Possibility Analysis is Substantively Flawed ...979

1. Ameren’s calculations fail to model all of the performance improvements expected from the boiler upgrades ...979

2. Ameren’s capable of accommodating approach ... 979

3. No analysis of relatedness .. .981

C.Nothing in Ms. Ringelstetter’s Analyses Excuses Ameren’s Failure to Perform Appropriate NSR Projections ...982

1. Ms. Ringelstetter failed to address relatedness for either unit ...982

2. Ms. Ringelstetter’s Unit 1 analysis relies on faulty assumptions ... 983

a. Background regarding ancillary services ... 983

b. Ms. Ringelstetter’s modeling choice ... 984

VI.THE 2007 AND 2010 BOILER UPGRADES TRIGGERED TITLE V REQUIREMENTS .. .985

CONCLUSIONS OF LAW .. .985

I. OVERVIEW ...985

II. THE UNITED STATES PROVED THAT AMEREN VIOLATED THE PREVENTION OF SIGNIFICANT DETERIORATION AND TITLE V PROVISIONS OF THE CLEAN AIR ACT ...986

A. Undisputed Elements of Proof ...986

B. The Projects Should Have Been Expected to Cause—and Did Cause— Emissions Increases ... 986

1. Legal standard .. .986

2. The evidence shows that Ameren should have expected an emissions increase related to each project, and such an emissions increase occurred ...988

*913 a. The Koppe-Sahu emissions calculations show a predicted increase at Unit 1 and were confirmed by an actual increase ... 988

b. The Koppe-Sahu emissions calculations show a predicted increase at Unit 2 and were confirmed by an actual increase ... 991

3. Dr. Hausman used Ameren’s modeling to quantify the emissions impact from the projects ... 994

4. The evidence shows that efficiency improvements would not prevent emissions from increasing as a result of the projects ... 996

5. Conclusion: The emissions evidence shows an increase related to the projects should have been expected and actually occurred ... 997

C. Ameren Also Violated Title V ...998

III. AMEREN’S DEFENSES AND CRITIQUES OF THE UNITED STATES’ EVIDENCE FAIL .. .999

A. The Projects were not Routine Maintenance ... 999

1. Legal standard .. .999

2. The boiler refurbishments at each Rush Island unit constitute one project for routine maintenance purposes ...1000

3. The projects do not qualify for the routine maintenance exemption ...1001

a. Nature and extent .. .1001

b. Purpose ... 1002

c. Frequency ... 1002

d. Cost... 1003

4. Conclusion: the projects cannot be considered routine ... 1003

B. The Emissions Increases Cannot Be Set Aside Based on the Demand Growth Exclusion ... 1003

1.Ameren’s experts confirm that demand was not projected to—and did not—cause the pollution increases at Rush Island ... 1003

2. Ameren’s evidence does not address what portion of the units’ projected or actual emissions increases were “unrelated” to the projects ...1004

3. Ameren’s other demand growth arguments fail :.. 1006

4. Emissions resulting from operations that would not have been possible but for the boiler upgrades cannot be considered “unrelated” to those boiler upgrades ... 1008

C.Ameren’s New Source Review Anal-yses Are Fatally Flawed and Cannot Provide Safe Harbor from Liability ...1010

1. Ameren does not have a legitimate process for assessing PSD applicability ...1010

2. Unit 1... 1012

3. Unit 2... 1013

EVIDENTIARY ISSUES FROM TRIAL ...1015

I. AMEREN’S MOTIONS TO STRIKE TESTIMONY AND EVIDENCE ...1015

A. Ameren’s Motions to Strike Mr. Koppe and Dr. Sahu’s Testimony and Evidence Concerning the Causation of Actual Emissions Increases ... 1015

B. Ameren’s Motion to Strike Dr. Hausman’s Testimony Criticizing Ms. Ringelstetter’s Opinions ... 1016

II. THE UNITED STATES’ MOTION TO CURTAIL RE-LITIGATION OF THE LAW OF THE CASE .. .1016 CONCLUSION .. .1017

INTRODUCTION

Plaintiff the United States of America, acting at the request of the Administrator of the United States Environmental Pro *914 tection Agency (“EPA”), filed this suit against defendant Ameren Missouri (“Am-eren”) on January 12, 2011. The United States alleges that Ameren committed various violations of the Clean Air Act, 42 U.S.C. § 7401 et seq., the Missouri State Implementation Plan, and Ameren’s Rush Island Plant Title V Permit when it allegedly undertook major modifications at its Rush Island Plant in Festus, Missouri without obtaining the required permits. For the reasons that follow, I conclude the United States has established that Ameren violated the Clean Air Act and its operating permit by carrying out the Rush Island projects without obtaining the required permits, installing best-available pollution control technology, and otherwise meeting applicable requirements.

The modern Clean Air Act was passed in 1970 in order “ ‘to speed up, expand, and intensify the war against air pollution in the United States with a view to assuring that the air we breathe throughout the nation is wholesome once again.’ ” United States v. Duke Energy Corp. (“Duke Energy 2010 ”), No. 1:00 CV 01262, 2010 WL 3023517 , at *2 (M.D.N.C. July 28, 2010) (quoting H.R. Rep. No. 91-1146, at 1 (1970), reprinted in 1970 U.S.C.C.A.N. 5356). By 1977, Congress had determined that earlier programs “did too little” to achieve air quality goals and added the New Source Review program (“NSR”), including the Prevention of Significant Deterioration (“PSD”) provisions at issue in this case. See Envtl. Def. v. Duke Energy Corp., 549 U.S. 561, 567-68 , 127 S.Ct. 1423 , 167 L.Ed.2d 295 (2007) (“Duke Energy 2007”); New York v. EPA, 413 F.3d 3, 12-13 (D.C. Cir. 2005). The PSD program is designed to prevent significant increases in pollution, an objective built into the very name of the program. United States v. Ameren Missouri (“Ameren SJ Decision”), Case No. 4:11 CV 77 RWS, 2016 WL 728234 , at *13 (E.D. Mo. Feb. 24, 2016). The program is designed to prevent future significant increases in pollution, in part, by requiring major-emitting facilities to employ state-of-the-art pollution controls.

When it enacted the PSD program, Congress required all new major-emitting facilities to comply with PSD requirements by installing state-of-the-art pollution controls at the time of construction. Recognizing the expense and burden of installing such controls, however, Congress did not require facilities then in existence to immediately install pollution controls. Rather, Congress allowed these facilities to continue to operate without installing such controls on the condition that if they ever modified their facilities, they would calculate the impact of those modifications, report the planned modifications to the EPA, obtain the requisite permits, and install the required pollution control technologies at that time. PSD rules apply to “major modifications,” which 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 Ameren SJ Decision, 2016 WL 728234 , at *4. An increase of 40 tons or more per year of sulfur dioxide (“S02”), the pollutant discussed in this case, is “significant” under the regulations. 40 C.F.R. § 52.21 (b)(23)(i).

Congress enacted these modification provisions to ensure that facilities that were grandfathered into the program would not be allowed “perpetual immunity” from PSD’s requirements. Ala. Power Co. v. Costle, 636 F.2d 323, 400 (D.C. Cir. 1979). Under the PSD program:

[Ojld 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 *915 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).

Ameren’s Rush Island plant includes two coal-fired electric generating units, Units 1 and 2. These units went into service in 1976 and 1977 and were grandfathered into the PSD program. Neither unit has air pollution control devices for S02. The Rush Island plant currently emits about 18,000 tons of S02 per year. The Rush Island units are big sources of pollution, so even small performance improvements or increases in unit availability can lead to a 40-ton increase in S02. It only takes an availability improvement of 0.3% or an additional 21 hours of operation at full power for the Rush Island units to emit more than 40 tons of S02.

By 2005, some of the major boiler components in Units 1 and 2 were causing problems that forced Ameren to frequently take the units out of service and made the units underperform, reducing the amount of electricity Ameren could generate and sell from the units. Ameren decided to fix these problems by replacing the problem components with new, redesigned components. Courts in PSD enforcement actions have long recognized that “[i]f 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,” burning more coal and emitting more pollution. United States v. Ala. Power Co., 730 F.3d 1278, 1281 (11th Cir. 2013); see also United States v. Ohio Edison, 276 F.Supp.2d 829, 834-35 (S.D. Ohio 2003). When these conditions occur, as they did here, they trigger a utility’s obligation to conduct PSD review, secure the appropriate permits, and install required pollution controls.

This standard for assessing PSD applicability was well-established when Ameren planned its component replacement projects for Units 1 and 2. Ameren’s testifying expert conceded that the method used by the United States’ experts—which showed that Ameren should have expected the projects to trigger PSD rules—has been “well-known in the industry” since 1999. But Ameren did not do any quantitative PSD review for the project at Unit 1 and performed a late and fundamentally flawed PSD review for Unit 2. And Ameren did not report its planned modifications to the EPA, obtain the requisite permits, or install state-of-the-art pollution controls. Instead, Ameren went ahead with the projects, spending $34 to $38 million on each unit to replace the problem components. It executed these projects as part of “the most significant outage in Rush Island history,” taking each unit completely offline for three to four months. Ameren’s engineers justified the upgrade work to company leadership on the basis that the new components would eliminate outages and the investment would be returned in recovered operations.

The evidence shows that by replacing these failing components with new, redesigned components, Ameren should have expected, and did expect, unit availability to improve by much more than 0.3%, allowing the units to operate hundreds of hours more per year after the project. And Ameren should have expected, and did expect, to use that increased availability (and, for Unit 2, increased capacity) to burn more coal, generate more electricity, and emit more S02 pollution.

Now that the projects have been completed, the evidence shows that Ameren’s expected operational improvements actually occurred. Replacement of the failing *916 components increased availability at both units by eliminating hundreds of outage hours per year. Unit 2 capacity also increased. Ameren’s employees have admitted that those availability increases would not have happened but for the projects. As a result of the operational increases, the units ran more, burned more coal, and emitted hundreds of tons more of S02 per year.

In response to these projects, the United States filed this suit against Ameren, alleging that Ameren violated the Clean Air Act, the Missouri State Implementation Plan, and Ameren’s Rush Island Plant Title V Permit by performing major modifications on Units 1 and 2 without obtaining the required permits, installing state-of-the-art pollution control technology, or otherwise complying with applicable requirements.

Previously, in ruling on the parties’ summary judgment motions, I set out several of the legal standards at issue in this case. See Ameren SJ Decision, 2016 WL 728234 , at *13 (ruling on the parties’ various motions for partial summary judgment and evidentiary motions); United States v. Ameren Missouri, 158 F.Supp.3d 802, 804 (E.D. Mo. 2016) (denying Ameren’s motion for full summary judgment). I held a twelve day non-jury trial beginning on August 22, 2016. The parties filed post-trial briefs and proposed findings of fact and conclusions of law on September 30, 2016 and argued outstanding evidentiary issues that were raised at trial. On October 12, 2016, the parties filed responses to each other’s post-trial briefs.

After consideration of the testimony given at trial, the exhibits introduced into evidence, the parties’ briefs, and the applicable law, I make the following findings of fact and conclusions of law, which largely adopt those proposed by the United States. As discussed below, I conclude the United States has established that Ameren should have expected, and did expect, the projects at Rush Island to increase unit availability (and, for Unit 2, to increase capacity), which enabled Ameren to run its units more, generate more electricity, and emit significantly more pollution. The United States has also established that Ameren actually emitted significantly more pollution as a result of the projects. Ameren has failed to establish that either the routine maintenance or demand growth defenses apply to shield it from liability. As a result, I conclude that the United States has established by a preponderance of the evidence that Ameren violated the PSD and Title Y provisions of the Clean Air Act.

FINDINGS OF FACT

I.BACKGROUND CONCERNING THE DEFENDANT, THE RUSH ISLAND PLANT, AND THE APPLICABLE REGULATIONS

A. The Defendant

1. Defendant Ameren Missouri is a Missouri corporation. Defendant’s incorporated name is Union Electric Company, but Defendant conducts business under the name Ameren Missouri. Answer to Third Amended Complaint (“Answer”), at ¶ 10 (ECF No. 250); Joint Stipulations of Fact (“Joint Stip.”), at ¶ 1 (ECF No. 743).

2. As a corporate entity, Ameren is a “person” within the meaning of the Clean Air Act Section 302(e), 42 U.S.C. 7602(e) and 10 C.S.R. 10-6.020(2). Answer, at ¶ 11; Joint Stip., at ¶ 2.

3. At all times relevant to this case, Ameren has been the owner and/or operator of the Rush Island Plant in Festus, Jefferson County, Missouri. Answer, at ¶¶ 12, 57; Joint Stip., at ¶ 3.

*917 B. The Rush Island Coal-Fired Power Plant

4. The Rush Island coal-fired power plant (“Rush Island Plant”) consists, in part, of Units 1 and 2, which are coal-fired electric generating units. Rush Island Units 1 and 2 went into commercial service in 1976 and 1977, respectively. Answer, at ¶¶ 13, 59; Joint Stip., at ¶ 4.

5. The Rush Island units were originally designed to have an approximately 30-year life. Testimony of U.S. Power Plant Expert Bill Stevens, Trial Transcript Volume (“Tr. Vol.”), 1-B 50:24-51:4, 69:4-11. The components of large units like the Rush Island units typically have a life of between 30 and 40 years. Stevens Test., Tr. Vol. 1-B 81:19-82:1.

6. The Rush Island units were designed as baseload units, meaning they generally operate every hour that they are available to run. Design Data Report (PI. Ex. 297), at AUE-00022523, 22526; Testimony of Retired Ameren Vice President Charles Naslund, Tr. Vol. 6-A, 55:4-7; Anderson Dep., Dec. 4, 2013, Tr., 63:21-64:6; Pope Dep., Sept 20, 2013, Tr. 121:18— 122:11; Testimony of U.S. Utility System Modeling Expert Dr. Ezra Hausman, Tr. Vol. 4-B, 26:15-10; Testimony of EPA Engineer Jon Knodel, Tr. Vol. 1-A, 75:16-75:24; 76:21-76:25.

7. The Rush Island units are among Ameren’s most cost-effective units and carry much of the system load. Retired Ameren executive vice president Charles Naslund described the units as “two workhorses.” Naslund Test., Tr. Vol. 6-A, 50:3-12.

8. Burning coal at Rush Island Units 1 and 2 generates combustion gases containing sulfur dioxide (“SOz”). The S02 gases at Rush Island Units 1 and 2 are passed through a smokestack directly to the atmosphere, as neither unit has air pollution control devices for S02. Testimony of U.S. Emissions Expert Ranajit Sahu, Tr. Vol. 5, 43:9-44:24; Knodel Test., Tr. Vol. 1-A, 73:7-73:9.

9. The Rush Island plant currently emits about 18,000 tons per year of S02. Knodel Testimony, Tr. Vol. 1-A, 73:16-73:18. If Ameren operated scrubbers at Rush Island that achieved emissions reductions comparable to other plants in the region that currently operate scrubbers, S02 emissions would be reduced to several hundred tons per year. Knodel Test., Tr. Vol. 1-A, 108:3-108:5.

C. Facts Concerning General Applicability of the Prevention of Significant Deterioration Program

10. The Clean Air Act’s New Source Review (“NSR”) program consists of a Prevention of Significant Deterioration (“PSD”) program and a Nonattainment New Source Review program. The PSD program applies in areas that are in attainment with the National Ambient Air Quality Standards (“NAAQS”) for a particular pollutant or are unclassifiable. 42 U.S.C. '§§ 7471, 7475. Knodel Test., Tr. Vol. 1-A, 52:11-53:4.

11. The Rush Island Plant is located approximately 50 miles south of St. Louis, Missouri, in the southern tip of Jefferson County, which is currently designated as in nonattainment with the NAAQS for S02. Knodel Test., Tr. Vol. 1-A, 53:8-53:15 At the time of the 2007 and 2010 projects at issue in this case, Jefferson County was classified as in attainment with the NAAQS for S02. Answer, at ¶ 19.

12. At all times relevant to this case, the Rush Island Plant has been a fossil-fuel fired steam electric plant of more than 250 million British thermal units per hour heat input, and has had the potential to emit more than 100 tons per year of S02. The Rush Island Plant is a “major emitting facility” as defined by 42 U.S.C. § 7479 (1), and a “major stationary source” *918 as defined by 40 C.F.R. § 52.21 (b)(1) and 42 U.S.C. § 7602Q). Answer, at ¶¶ 58, 59; Knodel Test., Tr. Vol. 1-A, 53:16-54:1.

13. Rush Island Units 1 and 2 are each a “major emitting facility” as defined by 42 U.S.C. § 7479 (1), a “major stationary source” ■ as defined by 40 C.F.R. § 52.21 (b)(1), and an “electric utility steam generating unit” as defined by 40 C.F.R. § 52.21 (b)(31). Joint Stip., at ¶ 5.

14. At the time of the 2007 and 2010 projects, the applicable EPA-approved Missouri PSD regulations were found in the 2003 version of 40 C.F.R. § 52.21 , as incorporated into Missouri Rule 10 C.S.R. 10-6.060. Before a major source of air pollution located in such an area designated as in attainment with the NAAQS undergoes a “major modification,” the owner or operator of the source must obtain a PSD permit that imposes emission limits. See January 21, 2016 Memorandum and Order (ECF No. 711); 40 C.F.R. § 52.21 (a)(2), (j); 71 Fed. Reg. 36,486 (June 27, 2006).

15. The PSD regulations define “major modification” as “any physical change ... that would result in” a significant net emission increase in actual emissions from a major stationary source. See January 21, 2016 Memorandum and Order (ECF No. 711); 40 C.F.R. § 52.21 (a)(2)®.

16. Under the PSD regulations, a “physical change” does not include “routine maintenance, repair and replacement.” 40 C.F.R. § 52.21 (a)(2)(iii).

17. Under the PSD regulations, a “significant” increase in S02 is 40 tons per year. 40 C.F.R. § 52.21 (b)(23)(i).

D. Notice of the Violations Alleged in the Complaint

18. The EPA issued a Notice of Violation on January 26, 2010, and issued amended Notices of Violation on October 14, 2010 and May 27, 2011. The Notices of Violation identified, inter alia, the alleged violations arising from the 2007 and 2010 major modifications of Rush Island Units 1 and 2 that are at issue in this case. Answer, at ¶ 6; Joint Stip., at ¶ 6.

19. The Notices of Violation were provided to Ameren and the State of Missouri, in accordance with 42 U.S.C. § 7413 (a). Answer, at ¶ 6; Joint Stip., at ¶ 7.

20. The United States filed its original Complaint on January 12, 2011 (ECF No. 1), an Amended Complaint on June 28, 2011 (ECF No. 36), a Second Amended Complaint on October 30, 2013 (ECF No. 165), and a Third Amended Complaint on April 24, 2014 (ECF No. 249). The Amended Complaint, Second Amended Complaint, and Third Amended Complaint alleged, inter alia, violations arising from the 2007 and 2010 major modifications of Rush Island Units 1 and 2 that are at issue in this case, and were filed more than 30 days after notice of the violations was provided as required by 42 U.S.C. § 7413 (a). Joint Stip., at ¶ 8.

21. The United States provided notice of the commencement of this action to the State of Missouri, as required by 42 U.S.C. § 7413 (b). Knodel Test., Tr. Vol. 1-A, 87:4-87:23.

II. FACTS CONCERNING THE 2007 AND 2010 BOILER UPGRADES AT RUSH ISLAND UNITS 1 AND 2

22. The major modifications in this case arise from construction projects undertaken by Ameren in 2007 and 2010 at Rush Island Units 1 and 2. The 2007 major modification occurred at Rush Island Unit 1 during a major boiler outage that began on February 17, 2007 and ended on May 28, 2007. The 2010 major modification occurred at Rush Island Unit 2 during a major boiler outage that began on January 1, 2010 and ended on April 9, 2010. Stevens Test., Tr. Vol. 2-A, 24:9-24:15; 2007 *919 Post Outage Report (Pl. Ex. 34), at AM-02252210; 2010 Post Outage Report (Pl. Ex. 46), at AM-02739973.

A. The Boiler Components at Issue and Their Role in Burning Coal to Generate Electricity

23. Rush Island Units 1 and 2 each include a large boiler where coal is burned to convert water into steam. The boilers are comprised of a number of major components, including the economizers, re-heaters, lower slope panels, and air pre-heaters at issue. The economizer, reheater, and lower slope panels are each comprised of bundles of steel tubes designed to carry high-temperature, high-pressure steam to the turbines. Altogether, the boilers in large coal-fired units like those at Rush Island are constructed of hundreds of miles of tubing. Exposing the steel tube bundles in the major boiler components to the heat from burning coal converts water into steam. The steam is sent to the turbines, including a high pressure turbine, an intermediate pressure turbine, and a low pressure turbine. The turbines spin a generator, which produces electricity. Unlike the tubular boiler components, the air preheater does not consist of steel tube bundles; it consists of metal heat exchanging surfaces that preheat additional air used for combustion of coal in the boiler. Stevens Test., Tr. Vol. 1-B, 55:9-55:13, 57:13-61:6; see also Welcome to Rush Island Plant Presentation (Pl. Ex. 35), at AM-02253169-173.

24. The Rush Island boiler house is approximately 270 feet tall from the ground to the rooftop. Stevens Test., Tr. Vol. 1-B, 95:10-16. Each boiler is approximately 230 feet tall. Stevens Test., Tr. Vol. 1-B, 95: 10-18; Welcome to Rush Island Presentation, (Pl. Ex. 35), at AM-02253171. Each furnace is approximately 60 feet wide and 50 feet deep. Stevens Test., Tr. Vol. 1-B, 96:2-5.

25. The specific boiler components at issue in the major modifications are the economizer, reheater, lower slopes, and air preheaters that were replaced at Rush Island Unit 1 in 2007, and the economizer, reheater, and air preheaters that were replaced at Rush Island Unit 2 in 2010. Knodel Test., Tr. Vol. 1-A, 81:9-82:8; Stevens Test., Tr. Vol. 1-B, 46:2-12.

26. The Rush Island economizers are located in the convection section of each boiler. Stevens Test., Tr. Vol. 2-A, 29:11-24. The purpose of the economizer, which is the first tubular heat exchanging component in the boiler, is to take heat from the hot gases in the boiler and transfer it to high pressure boiler feedwater. When it leaves the economizer, the water is close to turning into steam. It then flows to a steam drum before being circulated through waterwall tubes that form the walls of the boiler furnace, and on to a section of the boiler known as the super-heating section, before being sent as steam to the high pressure turbine. Stevens Test., Tr. Vol. 1-B, 58:12-60:6.

27. Each economizer at Rush Island Unit 1 and 2 weighed approximately 600 tons. Stevens Test., Tr. Vol. 2-A, 34:22-35:7. The original Unit 1 and Unit 2 economizers had identical designs. They each had two banks—an upper and a lower bank—with 276 assemblies per bank, and had a spiral-finned design, with a staggered arrangement. The diameter of each tube was 1.75 inches. Stevens Test., Tr. Vol. 2-A, 29:25-30:18; Specification No. EC-5491 (Pl. Ex. 10), at AM-00080276; Ameren’s Response to Request for Admission (“RFA”) Nos. 362, 364, 365, 367 (EOF. No. 785-1).

28. The Rush Island reheaters are located at the top of each boiler’s furnace. Stevens Test., Tr. Vol 2-A, 41:14-42:13. The purpose of the reheater is to reheat steam after it hás passed through the high *920 pressure turbine, before being sent back to the intermediate and low pressure turbines. Stevens Test., Tr. Vol. 1-B, 60:7-60:17.

29. The original Rush Island reheaters each had a front section and a rear section. The front section had 72 side-by-side assemblies, each of which was over 50 feet tall. The front assemblies were spaced on ten inch centers. The original front section had a sloped bottom, which created a close clearance between the bottom of the re-heaters’ front section and each boiler’s nose. The rear section had 145 assemblies, each of which was around 26 feet tall. Both the front and rear reheater sections were spaced, not platenized, meaning there was no material that connected one tube to the next. Stevens Test., Tr. Vol. 2-A 42:2-43:2; Specification No. EC-5491 (PI. Ex. 10), at AM-00080428; RFA Nos. 386, 387, 389, 390.

30. Rush Island’s lower slope tubes are part of the waterwall tubes and are located in the bottom of the furnace area of the boiler. Stevens Test., Tr. Vol. 1-B, 61:15-24, Tr. Vol. 2-A, 51:2-51:19.

31. In addition to the economizers, re-heaters, and lower slopes, the other primary boiler components at issue in this case are the air preheaters, which help warm combustion air entering the boiler. Forced draft (“FD”) fans are used to push combustion air into the boiler, and before entering the furnace the cold combustion air passes through the lower portion of the air preheater. Once in the furnace, the air mixes with pulverized coal and creates flue gas which heats the water and steam in the boiler tube components. Among other things, the flue gas contains tiny particles of ash known as flyash. Stevens Test., Tr. Vol. 1-B, 57:13-58:11; Tr. Vol. 2-A, 56:21-57:11.

32. The hot flue gas resulting from coal combustion flows up through the furnace and then from the back pass of the boiler down through the top of the air preheater, before going to the electrostatic precip-itator and then being sucked out by induced draft (“ID”) fans and sent up the stack. During this process, the air preheat-er rotates, allowing the hot flue gas exiting the boiler to warm up the forced draft air that is entering the boiler. Stevens Test., Tr. Vol. 2-A 13:10-14, 56:21-58:8; Testimony of U.S. Power Plant Expert Robert Koppe, Tr. Vol. 3-A, at 16:16-17:2.

33. Rush Island Units 1 and 2 each have two air preheaters. Each air preheat-er is approximately 40 feet tall and is located approximately 100 feet from ground level. Stevens Test., Tr. Vol. 2-A 13:10-14, 67:21-68:5. Each air preheater weighed at least a couple hundred tons. Stevens Test., Tr. Vol. 2-A 59:3-6.

34. The original Rush Island air pre-heaters were Ljungstrom regenerative air preheaters. Specification No. EC-5491 (PI. Ex. 10), at AM-00080275. Each original air preheater had three layers: a hot layer, an intermediate layer, and a cold layer. RFA Nos. 329, 332. Each layer was made up of air preheater baskets of various sizes. There were 216 hot end baskets, and each basket was 42 inches thick. There were 216 intermediate end baskets, and each basket was 16 inches thick. RFA No. 333, 334. There were 24 cold end baskets, and each basket was 12 inches thick. Stevens Test., Tr. Vol. 2-A 57:12-58:21; RFA No. 335.

35. Because the tubes that comprise the economizers, reheaters, and lower slopes are in constant contact with flue gas and/or combusting coal, these tubes are subject to deterioration over the life of the boiler and eventually develop leaks, which require repair or replacement. When the tubes degrade and the walls become too weak, the high pressure steam or water can burst through, resulting in a boiler tube leak. Large leaks require a unit to shut down while the portion of the tube *921 that ruptured is repaired, which typically lasts two to three days. Koppe Test., Tr. Vol. 3-A, at 14:16-15:9; Stevens Test., Tr. Vol. 1-B, 65:15-66:7.

36. Typically, the length of tube replaced when fixing a boiler tube leak would be on the order of several feet of tube. Stevens Test., Tr. Vol. 1-B, 79:4-79:19. Such repairs would be part of the day-today responsibility of plant maintenance staff and would involve no design changes to the component. Stevens Test., Tr. Vol. 1-B, 65:15-66:15, 69:4-69:11.

37. Similarly, on occasion some cold end air preheater baskets might need to be replaced due to corrosion. Stevens Test., Tr. Vol. 2-A, 58:14-21.

38. It is well known in the industry that a well-designed section of new boiler tubes should have almost no leaks at all for the first 20 years, before the tubes eventually begin to wear out and start to fail. Koppe Test., Tr. Vol. 3-A 50:11-50:16; Va-sel Dep., Aug. 15, 2013, Tr. 131:11-132:24 (Ameren was not expecting any tube leaks with the new economizer).

39. In light of the harsh conditions in which they operate, boiler components typically have a finite design life of between 20 to 40 years of operation. Stevens Test., Tr. Vol. 1-B 83:5-15. At that point, routine maintenance may no longer be sufficient to maintain desired operations, and an alternate approach may be required to optimize and extend the life of the unit. Vol. 1-B, Stevens Test., 82:2-20.

40. As a result, if a utility like Ameren wants to operate a boiler like the Rush Island boilers beyond 25 to 35 years, one strategy would be to replace the major boiler components, including the reheater. Stevens Test., Tr. Vol. 1-B 83:5-21, 84:5-6. Likewise, an economizer should be expected to last approximately 35 years and lower slope tubes should be expected to last approximately 40 years. Stevens Test., Tr. Vol. 1-B 83:22-84:4, 84:7-8. Ameren’s expert witness, Mr. Jerry Golden, similarly testified that the typical life of a reheater is about 30 years, the typical life of an economizer is about 35 years, and the typical life of a lower furnace is about 40 years. Golden Test., Tr. Vol. 8-A, 18:2-18:11.

41. Life extension activities historically have been considered in the utility industry to be different than typical maintenance activities. The distinction was explained by Mr. Stevens, and is also discussed in an authoritative engineering text published by Babcock and Wilcox known as the “Steam Book.” Stevens Test., Tr. Vol. 1-B 76:7-76:16, 78:4-7, 80:6-17.

42. According to the Steam Book, prior to the 1980s, it was assumed that older plants would be torn down to make room for newer, larger, more efficient units, and it was common to retire plants after 35 to 40 years of service. That assumption changed when utilities began to engage in life extension activities. The concept of “Life Extension and Upgrades” is discussed in a chapter in the Steam book by that name, while routine maintenance is discussed separately. Golden Test., Tr. Vol. 8-A, 32:16-33:8; Stevens Test., Tr. Vol. 1-B, 78:4-79:3.

43. The Steam Book describes a case-study involving the replacement of an economizer as a “life extension” project. In that life extension case study, a staggered economizer at a coal-fired generating unit was experiencing pluggage and gas flow resistance, resulting in erosion and tube failures. It was replaced with a new, redesigned, in-line economizer, which alleviated the operational problems and allowed for higher availability and reliability. Stevens Test., Tr. Vol. 1-B 84:19-87:19.

44. By contrast, typical maintenance activities on coal-fired fired boilers are those done on a day-to-day basis to keep *922 the power plant running in its current condition. Such typical maintenance includes things like replacing small sections of tubing, not replacing entire boiler components. Stevens Test., Tr. Vol. 1-B 64:15-66:15; 77:23-78:3, 78:20-79:19, 80:6-12.

45. Similarly, Ameren’s Work Order Procedure Manual defines routine maintenance activities as those that “relate to work performed regularly by Ameren employees or contractors on an ongoing basis in the customary and normal course of business to operate or maintain facilities and equipment.” Ameren Work Order Procedure (PI. Ex. 7), at AM-00066968; Stevens Test., Tr. Vol. 1-B 71: 15-72:7. Such routine activities are not subject to the requirements of Ameren’s Work Order Procedures. PI. Ex. 7, at AM-00066960, 66968; Stevens Test., Tr. Vol. 1-B 72:9-14; Moore Dep., Sept. 16, 2014, Tr. 22:11-22.

46. Ameren’s Administrative Design Control Manual provides that any activity that changes “any design or operating feature of the plant that is described by drawings or other design documents” is not considered routine maintenance. Ameren Administrative Procedure Design Control Manual (PI. Ex. 495), at AM-0223699; Stevens Test., Tr. Vol. 2-A, 70:24-71:2.

B. Operational Problems Leading up to the 2007 and 2010 Boiler Upgrades

47. The Rush Island Units were originally designed to burn Southern Illinois Bituminous Coal. Rush Island Resurfacing Study (PI. Ex. 20), at AM-00499384; Stevens Test., Tr. Vol. 1-B, 100:24-101:4, Tr. Vol. 2-A, 92:10-92:15. Around 1990, Rush Island began to burn coal from the Powder River Basin in Wyoming, known as PRB coal. Stevens Test., Tr. Vol. 1-B, 101:5-14. By 1995, the Rush Island units were burning 100 percent PRB coal. Stevens Test., Tr. Vol. 1-B, 101:15-20; Meiners Test., Tr. Vol. 7-A, 102:10-12; Meiners Dep., April 8, 2014, Tr. 237:9-238:11; Specification No. EC-5491 (PI. Ex. 10), at AM-00080275; Project Approval Package (PI. Ex. 3), at AM-00072837.

48. Ameren chose to switch to PRB coal, which has less sulfur, in order to comply with the Clean Air Act’s separate “Acid Rain” rules. As Ameren explained in an internal 1992 Acid Rain “Compliance Strategy” document, “a significant advantage of a fuel switch strategy is that it delays an irreversible decision to construct scrubbers.” Report from Union Electric: Compliance Strategy, Clean Air Act Amendments (PI. Ex. 798), at AUE-00020365; Knodel Test., Tr. Vol. 1-A, 102:16-21.

49. The Acid Rain rules are part of a program under Title IV of the 1990 Clean Air Act Amendments designed to reduce by about 50% precursors of acid rain, or acid deposition, from coal-fired power plants. These pollutants include S02 and nitrogen oxides. Knodel Test., Tr. Vol. 1-A, 55:13-19; see 42 U.S.C § 7651 et seq.

50. According to retired Ameren senior vice president Charles Naslund, PRB coal is the cheapest fuel option for the Rush Island plant, and Ameren has the cheapest fuel costs in the regional transmission area, known as the Midcontinent Independent System Operator (“MISO”) area. “So when I bid in my units, basically my units are always picked up pretty much baseload because I’m the cheapest.” Naslund Dep., Sept. 18, 2014, Tr. 144:17-145:7; Knodel Test., Tr. Vol. 1-A, 104:22-105:09. The economic advantage provided by burning cheaper coal than their competitors means Rush Island Units 1 and 2 run a higher percentage of the time. Naslund Test., Tr. Vol. 6-A, 48:7-49:3.

51. Although PRB coal was cheaper and had less sulfur, it differed in other important characteristics, including having a lower heating value and higher moisture *923 content, meaning that more coal needed to be burned to achieve the same output from the units. Stevens Test., Tr. Vol. 1-B, 101:21-102:15; Pope Dep., Sept. 20, 2013, Tr. 71:18-72:9. Because the Rush Island plant was not designed for coal with these characteristics, Ameren knew that switching to PRB would eventually cause operational problems at the units. Meiners Dep., April 8, 2014, Tr. 287:9-238:1; Pope Dep., Sept. 20, 2013, Tr. 73:12-74:12. For instance, Ameren’s Acid Rain Compliance Strategy specifically identified the fact that “the low heat content and the higher moisture of these coals generally result in operational problems that reduce capability.” Report from Union Electric: Compliance Strategy, Clean Air Act Amendments (PI. Ex. 798), at AUE-00020397.

52. The anticipated problems from switching to PRB coal for which the units were not designed were realized, causing related operational problems across the entire boiler. These problems worsened over time, and by the mid-2000’s, these components were also suffering from additional operational problems due to age-related deterioration, including tube leaks in the boiler components. Fred Pope, Rush Island’s former General Manager of Engineering and Technical Services, said Am-eren took interim measures to “defer as long as we could the potential component replacements that ... we anticipated would eventually come as the result of individual components reaching the end of their life, and we recognized that when that occurred, we would. adjust the design of those components ... to accommodate western coal.” Pope Dep., Sept. 20, 2013, Tr. 73:12-74:11.

53. As described further below, these operational problems included boiler tube leaks, slagging, fouling, and plugging, which adversely affected the economizers, reheaters, lower slopes, and air preheat-ers. These problems, which were extensively described in Ameren’s documents, forced each of the units to be completely shut down (in outages) for periods of time, or to have their electricity generation limited to less than full power (derated) for periods of time. Stevens Test., Tr. Vol. 1-B 102:16-102:24, 105:18-105:20, 107:6-109:13; Tr. Vol. 2-A, 7:16-8:20, 59:7-60:22, 63:22-65:7; Koppe Test., Tr. Vol. 3-A, 14:5-15; see Project Approval Package (PL Ex. 1), at AM-0072580 (noting “tube leaks” and “load reductions due to flyash pluggage” at Unit 1), 72585 (recounting that “switch to 100% PRB coals has caused flyash plug-gage” and noting boiler tube leaks at Unit 1), 590 (describing need for Unit 1 replacements following switch to PRB coal); Project Approval Form (PI. Ex. 2), at AM-00072829 (noting “tube leaks” and “load reductions due to flyash pluggage” at Unit 2); Project Approval Package (PI. Ex. 3), at AM-00072831 & 837 (same statements for Unit 2); Project Approval Package (PI. Ex. 6), at AM-00072912 (describing “major boiler modifications” at both units to address components “experiencing an increase in tube leaks” and planned redesigns for PRB coal); July 15, 2005 Email (PI. Ex. 45) at AM-0266037, 38 (noting derates due to “permanently plugged” air preheaters); September 18, 2009 Memo (PI. Ex. 26), at AM-00954160 (Unit 2 air preheaters “have continued to foul”); October 15, 2009 Memo (PI. Ex. 23), at AM-00926322-323 (describing problems in Unit 2 reheater and economizer following switch to PRB coal); Specification No. EC-5491 (PI. Ex. 10), at AM-00080276-279 (describing problems in Unit 1 and 2 boiler components); Presentation re: Justification for Projects (PI. Ex. 28), at AM-00966724-725, 731-736, 740-742, 745, 750-753 (describing problems in components).

1. Boiler tube leaks

54.As discussed above, boiler tube leaks occur in tubular components such as *924 economizers, reheaters, and lower slopes, and large leaks require a unit to shut down for repairs which typically last two to three days. FOF 35.

55. The rates of boiler tube failures are generally unlike the failure rates that may occur in other equipment in a boiler. Other boiler equipment tends to have failure rates that stay constant with time as long as the utility keeps up with its maintenance. But as boiler tube components degrade and reach the end of their useful life, their failure rates increase with time and become repetitive given the miles of deteriorated tubing, any inch of which can fail. As the component reaches the end of life, the failures will keep increasing even though the utility repairs specific leaks. Koppe Test., Tr. Vol. 3-A, 52:8-54:15.

56. The Rush Island Units were experiencing boiler tube leaks in the years leading up to the 2007 and 2010 major boiler outages, particularly in the three boiler tube components at issue in this case. Koppe Test., Tr. Vol. 3-A 14:5-15. As Ameren’s documents described the situation for the Rush Island plant as of 2005, “[t]here were a total of 10 reheat leaks in the reheaters in 2004 alone” along with “a total of 4 economizer tube leaks” and “12 lower slope tube leaks.” Project Approval Package (PI. Ex. 3), at AM-00072837; see also id. at AM-00072831 (noting problems that were “causing tube leaks” in the lower slopes and that “[tjhere have been tube leaks in the economizer sections and re-heater pendants”); Project Approval Package (PI. Ex. 1), at AM-00072585, 72590 (identical document for Unit 1); 2008 State of the System Presentation (PL Ex. 15), at AM-00196730-735 (presentation identifying lost megawatt-hours from boiler tube leaks at both units).

2. Slagging and fouling

57. Slagging is the accumulation of liquid ash on the walls of the furnace and on components that are located at the top of the furnace, including superheaters and reheaters. Slag condenses or solidifies, eventually becoming like rock or concrete. Slag can bridge between tubes causing plugging, which limits flow through the unit. Slag can also fall down through the furnace, causing tube leaks in the lower slope tubes. Stevens Test., Tr. Vol. 1-B, 104:23-105:17; Tr. Vol. 2-A, 51:02-52:25

58. Slag buildup on the reheaters would fall to the bottom of the furnace, causing damage to the lower slope tubes. Stevens Test., Tr. Vol. 2-A 44:1-21; Presentation re: Justification for Projects (Pl.. Ex. 28), at AM-00966735; Specification No. EC-5491 (PI. Ex. 10), at AM-00080278; Boll Dep., Sept. 5, 2014, Tr. 68:11-70:5. The slag falls caused “a vast number of gouges” on the lower slope tubes, which would often require a unit shutdown to repair. PI. Ex. 28, AM-00966722, at 745. The slag falls at the Rush Island units were at times as large as an automobile. Stevens Test., Tr. Vol. 2A, 54:2-14; Boll Dep., Sept. 5, 2015, Tr. 69:22-70:5. In addition, the lower slope tubes were experiencing problems related to 30 years of exposure to liquid ash and molten slag. Stevens Test., Tr. Vol. 2-A 51:20-52:25, 54:2-14; PI. Ex. 28, at AM-00966745; Project Approval Package (PI. Ex. 1), at AM-00072585; Project Approval Package (PL Ex. 3), at AM-00072831.

59. Before the 2007 major boiler outage, Ameren undertook efforts to repair the tube leaks caused by falling slag. For instance, Ameren would pad-weld over areas eroded by flowing slag and would replace leaking sections of tubes. However, because the buildup of slag was a recurring problem that was not being controlled adequately, problems continued. Stevens Test., Tr. Vol. 2-A 54:15-55:8.

60. Fouling is the deposit of solid particles of ash on heat transfer surfaces. When *925 fouling builds up on itself, it can plug the gas flow path between boiler tubing, limiting gas flow across the component, and through the unit. Fouling also leads to higher velocity gas flows through the areas that are not plugged, which causes erosion and tube failures. Stevens Test., Tr. Vol 1-B, 102:16-103:23, Tr. Vol. 2-A, 32:7-32:23.

3. Pluggage

61. Pluggage at Rush Island Units 1 and 2 occurred in the reheaters and economizer boiler tube components and in the air preheaters. Pluggage in boiler tube components occurs when ash material bridges the spaces between tubes, limiting gas flow. Stevens Test., Tr. Vol. 1-B, 103:24-104:4, 104:16-104:22. Ash also accumulates on the air preheater surfaces, restricting flue gas flow through the air pre-heaters and reducing the unit’s output. Stevens Test., Tr. Vol. 2-A 59:7-60:22; July 15, 2005 Email (PI. Ex. 45), at AM-0266037, 38; September 18, 2009 Memo (PI. Ex. 26), at AM-000954160; Koppe Test., Tr. Vol. 3-A, 14:11-14:15,17:5-17:11.

62. Ameren’s documents specifically identified the switch to PRB coal as the reason for increased flyash pluggage and load reductions. Project Approval Package (PL Ex. 1), at AM-00072585 (“The switch to 100% PRB coals has caused flyash plug-gage in the reheater and economizer. The pluggage in the existing staggered economizer has caused load reductions.”); Rush Island Resurfacing Study (PI. Ex. 20) at AM-00499388 (“changing fuels resulted in economizer performance problems ... and maintenance problems ... ”); Bosch Dep., June 12, 2014, Tr. 38:25-39:7; see also July 15, 2005 Email (PI. Ex. 45) at AM-0266037, 38 (noting derates due to “permanently plugged” air preheaters).

63. Mr. Koppe and Mr. Stevens explained that the boiler components were all suffering from the same underlying plug-gage problem that collectively contributed to limiting air and gas flow through the boiler, thus reducing the amount of coal that could be burned. Stevens Test., Tr. Vol. 1-B, 108:13-109:13; Koppe Test., Tr. Vol. 3-A, 28:7-14, 29:2-8; see also Koppe Test., Tr. Vol. 4-A, at 46:23-47:18 (discussing the cumulative effect of the air pre-heaters, reheater, and economizer pressure differentials on overall pressure drop throughout the boiler and its impact on the ID fans).

64. Jeff Shelton, an Ameren trial witness, similarly testified that because they all collectively contribute to the problem, the air preheaters, economizer, and reheat-er have to be looked at together when considering the effects of pluggage on the unit’s ability to generate. Shelton Test., Tr. Vol. 10-A, 106:13-24.

65. Pluggage in the economizer with PRB ash was exacerbated by the original economizer’s staggered alignment design, which created a torturous flow path for the flue gas and ash. Together with the switch to PRB coal, the economizers’ staggered alignment also resulted in erosion, thinning, and tube leaks. Stevens Test., Tr. Vol. 2-A 30:19-32:14, 33:9-22, 40:11-19.

66. Ameren attempted to remedy the problems in the economizer through soot blowing and off-line cleanings, but these efforts did not solve the problem. Pluggage and erosion kept occurring, and the end of the economizers’ lives were approaching. Stevens Test., Tr. Vol. 2-A 32:7-23.

67. The original design of the reheat-ers also exacerbated pluggage due to PRB coal. The spacing of the reheaters, along with the use of PRB coal, led to pluggage of the gas lanes through the reheaters. Contemporaneous documents indicated that “fouling is a daily concern,” that plug-gage occurred in certain areas of the re-heater across the entire boiler width, and that shotguns and dynamite needed to be used to remove the pluggage. Stevens Test., Tr. Vol 2-A, 43:3-45:13; Presenta *926 tion re: Justification for Projects (PL Ex. 28), at AM-00966735.

68. Ameren attempted to address the problems with the reheaters through cleanings, including soot blowing, and even dynamite. Strubberg D.ep., Nov. 5, 2013, Tr. 162:7-19, 174:9-23. However, because of end of life considerations, it became necessary to replace the reheaters. Stevens Test., Tr. Vol. 2-A, 44:22-45:13, 47:20-24.

69. The original air preheaters also consistently experienced pluggage. With the switch to PRB coal, ash accumulated on the air preheater surfaces and built up on itself. Ultimately, the pluggage also led to an end-of-life situation for the air pre-heaters. Stevens Test., Tr. Vol. 2-A 59:7-60:22. As an internal Ameren email stated, “It sounds like we have to live with the load limitations on RI due to fan capacity limits. Is there anything else we should look at, or as Jon suggests, is this beyond recovery due to the permanently plugged air heaters.” July 15, 2005 Email (PL Ex. 45), at AM-0266037; Cardinale Dep., July 31, 2014, Tr. 84:3-21 (air preheater fouling was “permanent”); see also September 18, 2009 Memo (Pl. Ex. 26), at AM-000954160 (noting continued air preheater fouling).

70. The specific mechanisms by which pluggage from PRB coal restricted air and gas flow and limited boiler operation were explained by Mr. Koppe. As noted previously, each boiler’s FD fans push air in through the air preheaters where it is warmed up before it enters the furnace areas of the boiler. Koppe Test., Tr. Vol. 3-A 16:16-20. The very hot gases then flow up through all of the boiler tube components and back through the other side of the air preheaters, through the precipitator, and then are sucked out by ID fans, before going out the stack. Koppe Test., Tr. Vol. 3-A 16:20-17:2. When plug-gage gets bad enough, it is no longer possible to push enough air into the furnace to burn as much coal as could otherwise be burned. That reduces the amount of coal that is burned, which reduces the amount of steam that is generated, which reduces the amount of electricity that is produced. Koppe Test., Tr. Vol. 3-A, 17:3-11.

71. Pluggage limited the amount of coal that could be burned in several ways. First, pluggage impacted the pressure differentials (also known as “delta P”) across the air preheater and economizer, which limited air and gas flow and reduced the amount of coal that could be burned. As discussed above, the hot gases flow through the boiler as air is pushed into the boiler by FD fans and pulled by ID fans. The amount of air pushed into the furnace has to be in balance with the amount of gas that goes out of the furnace. As a component gets plugged, it takes more pressure to push the gas through it. The “delta P” represents the change in pressure from the inlet to the outlet of the various boiler components. When the pressure drop gets too high, the amount of gas flow out of the furnace must be reduced, which requires reducing the amount of air coming into the furnace, which reduces the amount of coal the boiler can burn. Koppe Test., Tr. Vol. 3-A, 17:12-18:21.

72. Second, pluggage also impacted the FD and ID fans. As pluggage got worse, the ID fans, which create a vacuum to suck air out of the boiler, had to work harder and harder to pull air, and eventually got to the point where they were “fan-limited” and could not suck any more without damaging equipment. Cardinale Dep., July 31, 2014, Tr. 103:17-205:17. So the ID fans had to reduce power, which also reduced the amount of coal that could be burned. Koppe Test., Tr. Vol. 3-A, 19:18-20:16.

73. As the air preheaters plugged up more and more, the FD fans also had to work harder and harder to get air into the boiler. Bosch Dep., June 12, 2014, Tr. *927 38:25-40:11. Eventually the FD fans were maxed out and they could not push any more air, which limited the amount of coal that could be burned. Bosch Dep., June 12, 2014, Tr. 39:19-40:11. This typically happened in the summertime. Koppe Test., Tr. Vol. 3-A, at 20:17-21:11; Koppe Test., Tr. Vol. 4-A 44:13-23 (“on the rare occasions when I have before seen units limited by FD fans, it is because the pluggage has gotten so severe in the summer months the FD fans use up all their margin and can’t push any more air”); Birk Dep., Sept. 24, 2013, Tr. 194:7-16; see also July 2005 email, PI. Ex. 45 (discussing “permanently plugged air heaters” and noting that the units “run out of FD fans when ambient temps come up in the summer months”).

74. In the short term, Ameren coped with pluggage by shutting the units down periodically to conduct high-pressure washes to try to clean out some of the pluggage. Koppe Test., Tr. Vol. 3-A 22:3-12; Stevens Test., Tr. Vol. 2-A, 59:7-22; Cardinale Dep., July 31, 2014, Tr. 41:15-43:10. This ameliorated the problem somewhat, but it did not solve it. Koppe Test., Tr. Vol. 3-A 22:3-12. The pressure drop would improve somewhat following a cleaning, but “much of the deposits in the air heater were so hard that they couldn’t be removed even with a high-pressure wash.” Id. at 25:12-21; Stevens Test., Tr. Vol. 2-A, 66:8-23; Cardinale Dep., July 31, 2014, Tr. 84:3-21.

75. Evidence of these problems was specifically discussed in company presentations to Ameren executives and memorialized in documents such as the 2008 “State of the System” report. 2008 State of the System (PI. Ex. 15), AM-00196593, at AM-00196898-923; Meiners Test., Tr. Vol. 7-B, 58:20-59:8 (State of the System presentations were an opportunity to review the performance of plant equipment with Am-eren executives). For instance, the 2008 State of the System report included a graphical representation of the high differential pressure problems caused by plug-gage, showing very high differential pressure ranging from 12 to over 14 inches of water pressure at the beginning of 2007 at both Unit 1 and Unit 2. The two graphs are found in PI. Ex. 15, at AM-00196909-10:

*928 [[Image here]]

76. At Unit 1, the graphs indicate that differential pressure at Unit 1 dramatically dropped from about 14 inches of water pressure in early 2007 down to 4 to 6 inches of water pressure after the Unit 1 air preheaters were replaced in the Spring of 2007. PI. Ex. 15, at AM-00196909. At Unit 2, the graph shows the permanence of the pluggage. As compared to the dramatic improvement achieved at Unit 1 due to the boiler component replacements, the Unit 2 graph shows only a very small improvement in differential pressure (from 14 down to 12 inches) following a washing of Unit 2 in the Spring of 2007, which almost immediately crept back up to 14 inches. PI. Ex. 15, at AM-00196910. Koppe Test., Tr. Vol. 8-A, at 23:15-26:3.

*929 77.The differential pressures described in the 2008 State of the System report before the boiler components were replaced were extremely high and caused load reductions. Koppe Test., Tr. Vol. 8-A, at 24:12-25:4. Ameren’s trial witnesses Joseph Sind and Andrew Williamson referred to such differential pressures as “extremely high” and indicative of “high pluggage.” Sind Test., Tr. Vol. 9-B, at 26:16-18 (air preheater differential pressures above even 11 inches are “extremely high”); Williamson Test. Tr. Vol. 9-B, at 44:4-11 (air heater differential pressure of 15 inches indicates “high pluggage”).

78.Mr. Koppe’s analysis of the company’s operational data showed that the same high differential pressures reported in the 2008 State of the System report plagued Unit 2 thrqughout the years leading up to the 2010 major boiler outage. As Mr. Koppe’s review of Ameren’s data demonstrated, Unit 2’s differential pressure at full load ranged between 10 and 16 inches of water in the years leading up to the projects, before dramatically improving following the 2010 major boiler outage. Koppe Test., Tr. Vol. 8-A 25:22-27:17 (discussing Koppe demonstrative 6).

[[Image here]]

79.Rush Island’s operational data was also compiled in periodic full load tests, which Ameren generally performed on a weekly basis in order to determine the maximum output the unit could achieve at that time. Koppe Test., Tr. Vol. 3-B, 35:17-36:4. During full load tests, the unit tries to generate as much output as it can. Sind Test., Tr. Vol. 9-B, at 30:1-7; Williamson Test., Tr. Vol. 9-B, 42:11-20 (former Rush Island Superintendent of Operations testifying that he reviewed full load tests on a regular basis so he could understand what the capability of the units were); see also November 2007 email (PI. Ex. 130), at AM-02635983 (Rush Island performance engineer James Bosch discussing full load test results after being asked to determine the “capacity” of Unit 1).

80.Plaintiffs Exhibit 928 is a compilation of these full load tests at Unit 2. In addition to reporting actual data such as pressure differentials, each full load test included a row for a possible narrative description of what was limiting load at the time. See PI. Ex. 928, at Spreadsheet Cell B.2 (“Load Limited by”). In addition to the consistently high reported differential pressures, the full load tests performed during the PSD baseline period for Unit 2 (March 2005 to April 2007) are replete with examples where Ameren engineers went out of their way to indicate in the narrative description of the load test re *930 ports that load was limited by the plug-gage that is at issue in this case. 1

81. Ameren also specifically quantified the generation losses due to the boiler components in company presentations. For instance, the 2008 State of the System presentation attributes 185,286 megawatt-hours of lost production at Unit 2 in 2007 to the air preheaters, as compared to only 15,197 megawatt-hours during that same year at Unit 1, which was the year the air preheaters were replaced at Unit 1. 2008 State of the System (PI. Ex. 15), at AM-00196900.

82. Ameren trial witness David Strub-berg conceded that the reported Unit 1 losses were smaller due to the replacement of the air preheaters. Strubberg Test., Tr. Yol. 8-A, 80:12-81:22 (discussing excerpt of presentation in PI. Ex. 14). Similarly, a July 2006 email from Mr. Strubberg concerning the potential risks of postponing the Unit 1 major boiler outage estimated an approximately 35 MW load reduction due to pluggage. Strubberg Test., Tr. Vol. 8-A, 90:11-91:10.

83. The pluggage at Unit 2 continued to get worse in the years leading up to the 2010 major boiler outage. As ash plugged up the economizer or air preheater, some of it could be removed relatively easily. But a hard layer of ash deposit would form on the surfaces that could not be removed “short of going in with a chisel and chiseling it out inch by inch. So as time went on, the thickness of these hard layers increased and that means that even after washing these components, the pressure drops were still very high.” Koppe Test., Tr. Vol. 3-B, 20:1-21:7. This inability to remove the load limitations with high pressure washes was specifically identified in project justification documents for Unit 2. An Ameren memo reported: “A high pressure wash can restore some of the pressure loss, but the gains are dimensioning [sic] with an ever increasing accumulation of hardened fly ash.” September 18, 2009 Memo (PL Ex. 26), at AM-000954160.

84.By 2008, pluggage of the Unit 2 air preheaters had gotten so bad that Ameren had to install a bypass as a temporary measure to allow gas to get around the pluggage. Koppe Test., Tr. Vol. 3-B, 21:8-21:19; Caudill Test., Tr. Vol. 10-B, 40:25-41:7; Cardinale Dep., July 31, 2014, Tr. 103:17-105:17 (“What they did on Unit 2, put in a pipe bypass around the air pre-heater because they really had serious pluggage problems.”). The effect of the bypass would be to increase the electrical output of the unit and decrease its efficiency. Koppe Test., Tr. Vol. 3-B, 21:25-22:10; Cardinale Dep., July 31, 2014, Tr. 43:1-45:10 (“certainly bypassing the air pre-heater is not something you want to do”). Out of all the plants that Mr. Koppe has assessed throughout his career, he has never seen another example of such a by *931 pass being installed. Koppe Test., Tr. Vol. 3-B, 21:20-21:24.

85. The effects of pluggage were also well-documented in other contemporaneous documents. Ameren described the pluggage at Unit 2 in a letter it sent to EPA’s Clean Air Markets Division in 2008, “Unit 2 generation has been limited to approximately 90 percent of normal load since the middle of 2007 due to gas flow restrictions in the air preheater.” April 7, 2008 Letter (PI. Ex. 934), at AM-00015890-MDNR. When shown the document at trial, Ameren capability expert witness Mr. Marcus Caudill referred to that amount as a “huge” load limitation. Caudill Test., Tr. Vol. 10-B, 39:19-41:14.

86. Similarly, in a December 16, 2009 email, which was written after the boiler work had been performed on Unit 1 but before it had been performed on Unit 2, Ameren employee Jeff Shelton wrote that the difference between the Unit 1 and Unit 2 capabilities grew bigger in the summer “due to draft limitations on Unit 2 and that following the boiler work this outage, we expect Unit 2 to not be as limited in the summer due to the draft issues.” December 6, 2009 Email (PI. Ex. 508), at AM-02248370; Shelton Test., Tr. Vol. 10-A, 93:21-94:18.

87. Mr. Shelton recognized that Unit 2 was draft limited in prior years as well. For instance, Mr. Shelton observed in 2008 that Unit 2 “ran into limitations due to gas path pluggage and air heater dps.” December 18, 2008 Email (PI. Ex. 542); at AM-02462552; Shelton Test., Tr. Vol. 10-A, 96:3-97:4.

88. In light of this evidence, Ameren’s expert witness on the capability of the units, Marcus Caudill, agreed ■ that Rush Island Units 1 and 2 were experiencing pluggage that was causing load reductions and derates prior to the 2007 and 2010 outages. Caudill Test., Tr. Vol. 10-B 35:18-22.

4. Availability losses caused by the replaced components prior to the 2007 and 2010 outages as reported to the Generating Availability Data System

89. Ameren uses the Generating Availability Data System (“GADS”) to collect and track operating data for the Rush Island plant, including event data and performance data. The event data tracks causes of lost generation such as derates and full outages, while performance data tracks statistics such as generation, fuel usage, and hours of operation. Anderson Test., Tr. Vol. 7-A, 5:22-6:14.

90. Plaintiffs expert Mr. Robert Koppe, who has been a power plant performance consultant since the 1970s, had a leading role in developing the GADS database, including writing the manual that all utilities use in deciding how to report their data. Koppe Test., Tr. Vol. 3-A 7:18-11:4. Mr. Koppe developed the original list of cause codes that all utilities use to report events in GADS. Id. at 10:17-11:4, 40:9-13.

91. Throughout his career, Mr. Koppe has been hired by dozens of utilities to analyze the performance of their generating units. Koppe Test., Tr. Vol. 3-A 11:5— 20. He has analyzed performance issues relating to hundreds of generating units. Id. at 13:17-25.

92. GADS is an industry-wide database that collects information on the performance of power plants and the effects that various problems have on that performance. Koppe Test., Tr. Vol. 3-A 10:5-11. GADS was developed so that utilities could improve the performance of their generating units. Id. at 10:12-16.

93. Whenever a unit has a problem that limits the amount of electricity it can generate, it is supposed to be reported as an “event” in the GADS data. That could be because the unit was operable but its *932 maximum output was reduced (derated) or because the unit could not operate at all because it was in an outage. Koppe Test., Tr. Vol. 3-A 31:1-9.

94. A statistic known as equivalent availability takes account of the effects of such deratings and outages on the availability of the unit to operate. Koppe Test., Tr. Vol. 3-A at 30:1-19. A derating reflects times when the unit was not capable of operating at its maximum output due to an equipment problem. Id.

95. Staff at the Rush Island plant contemporaneously record event data that identifies the causes of lost availability. These event data are then further reviewed for accuracy on a monthly basis before being uploaded into the company’s GADS system. Anderson Test., Tr. Vol. 7-A, 15:9-18.

96. The Ameren performance engineer at the Rush Island plant who was responsible for ensuring the accuracy of the GADS event data was James Bosch. Anderson Test., Tr. Vol. 7-A 42:9-15; Koppe Test., Tr. Vol. 3-A 32:25-33:3; Meiners Test., Tr. Vol. 7-B, 38:13-24.

97. It is common for utilities to track the causes of their unavailability so that they can quantify the effects that each problem or component is having on availability. In order to improve availability, utilities need to know what the problems are. Koppe Test., Tr. Vol. 3-A at 31:17-24.

98. Ameren is no different. Unit availability, particularly at low-cost units like the Rush Island units, is very important to Ameren. The company tracks availability “quite closely” and awards salary bonuses under its “Key Performance Indicator” program to some employees based in part on meeting availability targets. Naslund Test., Tr. Vol. 6-B, 8:7-16; Response to Interrogatory No. 65 (EOF No. 823); Moore Rule 30(b)(6) Dep., Sept. 16, 2014, 123:12-124:15; February 6, 2007 Email (PI. Ex. 103), at AM-02272420.

99. The Key Performance Indicator bonuses are paid for by Ameren’s customers. Moore Rule 30(b)(6) Dep., Sept. 16, 2014, 124:16-125:9.

100. Improving unit availability was always a goal for Ameren. If a unit is experiencing forced outages, the company would like it to perform better. Naslund Test, Tr. Vol. 6-B, 11:17-24; 13:15-18. Mr. Naslund, vice president of power operations, told the 1500 Ameren employees under his supervision that perfect availability would be 100%. Id.\ Generation Times Article (PI. Ex. 930), at AM-02583221.

101. Staff at the Rush Island plant use GADS data to assess the status of the plant’s equipment, and to adjust their predictions of future availability. Anderson Test., Tr. Vol. 7-A 59:25-60:6; Vasel Dep., Aug. 15, 2013, Tr. 83:22-25.

102. The availability targets set by the company are identified down to the tenth of a percentage point. The company also uses availability predictions to know how much coal to buy. Naslund Test., Tr. Vol 6-B, 10:20-11:9; see also February 6, 2007 Email (PL Ex. 103), at AM-02272420 (discussing proposal to adjust availability KPI bonus target by half a percentage point).

103. Ameren specifically used GADS data to analyze whether to do major capital projects. Koppe Test., Tr. Vol. 3-A at 31:25-34:3. Mr. Bosch, who did not testify at trial, reiterated the importance of such data to the capital project justification process in a 2002 email: “In order to place capital projects in the budget, they must be justified through the EVA program. EVA is a corporate justification software package which incorporates all the required components to derive a recommendation for project approval. The most compelling input in the justification calculation is lost generation. These lost generation ñgures are compiled and easily accessible in the NERC/GADS report *933 ing program.” June 25, 2002 Email (PI. Ex. 99), at AM-02254509 (emphasis added); Bosch Dep., June 12, 2014, Tr. 73:11-74:8; Pope Dep., Sept. 20, 2013, Tr. 25:17-26:4 (management needed to know that there was an economic benefit before approving an investment).

104. Ameren’s EVA Program, or Economic Value Added program, was used to compare two scenarios from a financial point of view in order to justify projects and look at the alternatives. Boll Dep. Tr., Dec. 12, 2013, 126:15-127:11; Generation EVA Instructions, (PI. Ex. 331), at AM-00491836. The company’s financial model for justifying projects based on their availability impacts is capable of determining the effect on anticipated revenue of as little as a 0.1 percentage point change in expected availability. Meiners Test., Tr. Vol. 7-B, 44:23-45:1; June 15, 2009 CPOC Email (PI. Ex. 895), at 02632840.

105. Ameren also uses GADS availability data to report the causes of lost generation at a plant to financial analysts on quarterly conference calls. Anderson Test., Tr. Vol. 7-A, 16:12-16:19.

106. In this case, Mr. Koppe looked at every single event reported in the GADS data for the 60 months prior to the project and determined which ones “would not have occurred but for the problems at issue in the components at issue in this case.” Koppe Test., Tr. Vol. 3-A, 34:7-12. Mr. Koppe reviewed each GADS event and description as reported by Ameren for the relevant time period and then reviewed other sources of information to understand the cause of each event. Koppe Test., Tr. Vol. 3-A, 38:18-39:3.

107. Mr. Koppe specifically included the GADS data for the PSD baseline period for Unit 1 that has been used by Amer-en in this litigation (February 2005 to January 2007). During that baseline period, problems in the economizer, reheater, lower slopes, and air preheaters caused Unit 1 to lose 336.1 equivalent full power hours of generation per year, which is equivalent to roughly 14 days of operation per year. Koppe Test., Tr. Vol. 3-A, 45:15-46:24. The unit was completely shut down in outages for 246.4 hours per year due to problems in the components at issue and lost the equivalent of another 89.7 full power hours of operation due to deratings. Id. These losses were widespread and covered a large fraction of all the months in the baseline. Koppe Test., Tr. Vol. 3-A, 46:25-47:6.

108. Mr. Koppe also specifically reviewed the GADS data for the PSD baseline period for Unit 2 used by Ameren in this litigation (April 2005 to March 2007). During the baseline period, problems in the economizer, reheater, and air preheat-ers caused Unit 2 to lose approximately 245 equivalent full power hours of availability per year. The unit was completely shut down in outages for 145.5 hours per year due to problems in the components at issue and lost the equivalent of another approximately 100 full power hours of operation due to deratings. Koppe Test., Tr. Vol. 3-A, 74:7-75-2; Sahu Test., Tr. Vol. 5, 78:20-79:13.

109. The deratings experienced at Units 1 and 2 were not short-term or onetime events. For instance, Unit 1 was continuously derated for the entire months of June, July, August, September, and October 2006, meaning that the unit was continuously derated every single day of each of those months. Unit 2 similarly experienced continuous derates. Anderson Test., Tr. Vol. 7-A, 50:21-52:16.

110. Mr. Koppe’s compilation of der-ates included certain GADS events identified as “FD fan capacity” limitations because the units would not have been limited by FD fan capacity had it not been for pluggage in the air preheater. Koppe Test., Tr. Vol. 4-A, at 60:9-61:3; *934 see also Koppe Test., Tr. Vol; 3-A, 96:19-97:18.

111. Rush Island Plant staff similarly attributed such fan capacity problems to the boiler components at issue. For instance, a spreadsheet attached to an April 30, 2006 email from Robert Meiners indicates that plant staff determined that Units 1 and 2 were experiencing load limitations during the summer of 2005 that would be eliminated once the reheaters, economizers, and air preheaters were replaced. See April 30, 2006 Email and Attached Condition Assessment (PI. Ex. 106), at Rush Island Spreadsheet Tab, Line 63 (noting that “FD Fans” at Unit 1 and Unit 2 “[c]urrently limit load during summer, but should be eliminated with boiler pressure part and APH”); Anderson Test., Tr. Vol. 7-A, 49:8-25.

112. As described by Ameren’s engineers at the time, the output of the Rush Island units was limited due to “fan capacity limits” resulting from the “permanently plugged air heaters” at the units. July 15, 2005 Email (PI. Ex. 45) at AM-0266037 (also noting that the “Unit 2 Air Pre-heater delta P’s [were] running at 12 inches at full load” and that the “baskets will have to be replaced on the APH’s to make an impact on FD fans”); July 21, 2004 Email (PI. Ex. 555), at AM-02485899; see also FOF 80 & n.2 (summarizing descriptions in weekly full load tests). The limitation on the unit’s ability to operate was estimated to cost Ameren approximately $25,000 per day. July 15, 2005 Email (PL Ex. 45), at AM-02666038.

5. Reduction in the maximum capability of Unit 2 prior to the 2010 outage

113. In addition to lost availability due to outages and derates as reported in GADS, the switch to PRB coal also resulted in a significant reduction in the reported maximum hourly capability of the units prior to the major boiler outages. Koppe Test., Tr. Vol. 3-A 90:11-91:4, Vol. 4-A, 33:10-34:2.

114. The capability of a unit is the maximum electric output that it can produce at that time if asked to do so. Koppe Test., Tr. Vol. 3-A, 84:14-23. The terms “capability” and “capacity” are often used interchangeably. Id. at 85:25-86:5

115. Ameren issued annual capability tables, which “represent the expected average output of each unit based on typical ambient conditions.” See, e.g., 2011 Capability Table (PI. Ex. 257), at AM-00067232. The reported capability of a unit is an estimate of what the utility expects the capability of the unit to be in the following year. Koppe Test., Tr. Vol. 3-A, 84:23-85:2. The magnitude of a reported derating is affected by the reported capability. Id. 85:3-10; see December 2010 Capability Table (PI. Ex. 257), at AM-00067232.

116. Gross capability or gross electrical output is the amount of electricity that the generator produces. Net capability or net electrical output is the amount of electricity that goes out to the grid. The difference between net and gross capability is the electricity the plant itself uses to operate, otherwise referred to as auxiliary load. Koppe Test., Tr. Vol. 3-A, 85:11-17; Koppe Test., Tr. Vol. 3-B, 11:6-15; Shelton Test., Tr. Vol. 10-A, 84:10-15.

117. A reduction in auxiliary load is an improvement in net efficiency, but it does not affect the amount of coal that the unit is capable of burning. It just means that less power is used to run the plant and more power is sent to the grid. Generator output is the same, heat input is the same, but more megawatts can be sent to the grid. Koppe Test., Tr. Vol. 3-B, 11:16-12:4; Shelton Test., Tr. Vol. 10-A, 85:8-10.

118. Ameren lowered the reported capability of Unit 2 substantially from 2005 *935 to 2006. The reduction was about 10 megawatts in the winter and 20 megawatts in the summer. Unit 2’s reported capability-remained essentially the same until 2010 and then increased substantially in 2010 and 2011. Koppe Test., Tr. Vol. 3-A, 88:13— 23.

119. The reduction in reported capability was the result of the effects of plug-gage. Koppe Test., Tr. Vol. 3-A, 90:11-91:4. In 2005, pluggage caused Unit 2 to frequently not be able to meet its reported capability. Koppe Test., Tr. Vol. 4-A, 33:10-34:2. Similarly, Unit 2 was unable to meet its reported capability in the summer of 2005 due to FD fan capacity limitations. January 4, 2006 Email (Pl. Ex. 157), at AM-027432293; Koppe Test., Tr. Vol. 3-A, 91:9-95:11; The reason the fans were running out of capacity in the summer was because of pluggage in the boiler, specifically pluggage in the air preheater. Koppe Test., Tr. Vol. 3-A, 96:19-97:18. As Amer-en documents describe it, the output of the Rush Island units was limited due to “fan capacity limits” resulting from the “permanently plugged air heaters” at the units. July 15, 2005 Email (Pl Ex. 45), at AM-02666037. Such problems with summer capacity were also identified in the project justification documents for Unit 2, where Ameren reiterated that “the current air preheater baskets have continued to foul to the extent that fans are load limited particularly in the summer months.” September 18, 2009 Memo (Pl. Ex. 26), at AM-000954160; see also Cardinale Dep., July 31, 2014, Tr. 84:3-21 (noting that air preheater fouling was “permanent”).

120. The capability of Unit 2 prior to the 2010 major boiler outage was also measured in Ameren’s weekly full load tests. The average capability of Rush Island Unit 2 as measured by Ameren in all of the full load tests that were conducted during the PSD baseline period (March 2005 to April 2007) was only 620 gross megawatts. Koppe Test., Tr. Vol. 3-B, 35:17-36:4, 45:12-46:5; see Pl. Ex. 928 (Rule 1006 summary of full load tests for Unit 2).

121. In the years leading up to the 2010 major boiler outage at Unit 2, Amer-en further quantified the megawatt capability loss that was due to the boiler components at issue. In Ameren’s 2008 annual “State of the System” presentation in 2008, it assigned “25-30 MW” to the Unit 2 “BLR/AHS replacement” in addition to another 13 megawatts that could be gained from replacing the low pressure turbine. 2008 State of the System (Pl. Ex. 15), at AM-00196628.

122. Ameren assigned 22.5 megawatts to the reheater, economizer, and air pre-heater in a financial analysis for the 2010 major boiler outage. Economic Value Added (EVA) Financial Analysis for Unit 2 (Pl. Ex. 48), at “Data Entry” Sheet; Koppe Test., Vol. 3-B, 30:4-32:23. The 22.5 megawatt value was a weighted average based on Ameren’s estimate that the component replacements would allow Unit 2 to produce 30 more megawatts of capacity during the three summer months and 20 more megawatts for the remainder of the year. Koppe Test., Tr. Vol. 3-B, at 27:7-32:23; see Pl. Ex. 48, at “Data Entry” Sheet; July 2009 ELT Progress Report (Pl. Ex. 110), at AM-02465690 (“30 MW gain in summer (3 mos), 20 MW gain balance of year from Reheater, Economizer and APH investment”).

123. Ameren’s final work order authorizations for the reheater, economizer, and air preheater, completed in the fall of 2009, similarly described that the “combined” effect of these component replacements would result in a “gain of 30 MW in the summer and 20 MW in the winter” at Unit 2. October 15, 2009 Memo (Pl. Ex. 23), at AM-00926323; see September 18, 2009 Memo (Pl. Ex. 26), at AM-00954160 (same *936 language in air preheater justification that “gain of 30 MW in the summer and 20 MW in the winter will be obtained with the combined reheater, economizer, and air preheater replacements”).

124. Ameren witness David Boll testified in his deposition that these predicted additional megawatts represented “regained capacity” that had been lost due to the inability to pull gas flow through the plugged air preheaters. Boll Test., Tr. Vol. 8-B, 51:23-52:4, 54:21-25.

125. A summary of the anticipated benefits of the work written in 2010 similarly referred to the fact that “[a]pproximately 30 Megawatts of unit capacity will be recovered during the hottest months because of lower gas flow pressure drops through the new economizer and air preheaters.” March 31, 2010 Email re Newsletter (PI. Ex. 893), at AM-02229417.

C. The Approval and Engineering Process for the 2007 and 2010 Major Modifications

126. The formal approval and engineering process for the 2007 and 2010 major boiler projects began at least three years prior to the first outage. The replacement of all four components was considered together for planning purposes, beginning as early as 2004. For instance, by December 2004, Ameren had created a preliminary budget for replacement of the Unit 1 economizer, reheater, lower slope tubes, and air preheaters, at an estimated capital cost of more than $25 million. Stevens Test., Tr. Vol. 2-A 5:2-7; December 20, 2004 Generating Engineering Budget Project Proposal (PI. Ex. 323); RFA 393.

127. A 500-page Project Book for Unit 1 was compiled as a reference for the work to be completed during the Unit 1 outage. The replacement of the economizer, re-heater, lower slope tubes and air preheat-ers were coordinated by Alstom Power and generally treated together within the Project Book. Rush Island Unit 1 Project Book (PI. Ex. 63), at AUE-00156352 (collectively referring to “Reheater, Economizer, Lower Slope, Air Heater Rotor Replacements” as a single major project); id. at 365 (same), 519 (same), 539 (same); Stevens Test., Tr. Vol. 2-A. 17:1-18:10.

128. The documentation in the Project Book also confirmed that one purchase order for engineering, materials, and construction services was issued to Alstom Power as early as 2005, which included the replacement of the economizer, reheater, lower slope tubes, and air preheaters. PL Ex. 63, at AUE-00156395-398.

129. The replacements of the economizers, reheaters, lower slopes, and air pre-heaters were all approved under Ameren’s Work Order Procedures. Stevens Test., Tr. Vol. 1-B 72:15-21, 91:19-92:3.

130. While the air preheaters were also subject to their own work order justification process, the air preheater justification documents specifically combined the air preheater replacements with the reheater, economizer, and lower slopes as part of a “major refurbishment” at both Unit 1 and Unit 2. October 5, 2005 Memo (PL Ex. 6), at AM-00072912; Stevens Test., Tr. Vol. 2-A 9:24-10:18.

131. Similarly, prior to replacing the Unit 2 air preheaters, Ameren reiterated its reliance on the “combined” effect of the air preheaters, reheater, and economizer for purposes of justifying the replacements. September 18, 2009 Memo (Pl. Ex. 26), at AM-00954160; October 15, 2009 Memo (PL Ex. 23), at AM-00926323 (same); see also id. at AM-00926322 (“Load reductions of 30 MW in the summer and 20 MW for the remainder of the year can be avoided with the new boiler components and the re-designed air pre-heater.”).

*937 132. Ameren’s documents also indicate that the replacement of all the components was combined to “gain efficiencies in procurement, design and installation” and described the air preheater replacements as “part of a Major Mechanical Work Package to include the Economizer, Reheater and Lower Slope portion of the boiler.” Project Approval Package (PI. Ex. 1), at AM-00072590; Project Approval Package (PI. Ex. 4), at AM-00072859; Stevens Test., Tr. Vol. 2-A 10:19-11:18, 13:23-14:7.

133. The engineering specification issued by Ameren called for bids from outside engineering firms for the design, fabrication, and installation of the boiler components at Rush Island Units 1 and 2. Ameren consolidated the replacement of the economizer, reheater, lower slope tubes, and air preheaters for purposes of issuing the specifications. Specification No. EC-5491 (PI. Ex. 10); Stevens Test., Tr. Vol. 2A 15:19-16:13.

134. Ameren provided specific design requirements for the replacement components, including a number of significant design changes that were intended to upgrade and improve the performance of the boiler as a whole. Stevens Test., Tr. Vol. 2-A, 32:24-33:22, 34:8-12, 45:14-46:25, 55:9-56:4, 66:5-67:9; October 15, 2009 Memo (PI. Ex. 23), at AM-00926322 (noting combined project objectives of redesigned economizer and air preheater).

135. In contrast with routine work undertaken at utility plants, the replacement of the economizers, reheaters, lower slopes, and air preheaters required approvals of executives at the highest level of the company, including Ameren’s CEO. The approval process required at least 10 layers of approval review. Stevens Test., Tr. Vol. 2-A 7:5-15, 13:15-22; Project Approval Package (PI. Ex. 1), at AM-00072580; Project Approval Form (PI. Ex. 2), at AM-00072829; Project Approval Package (PI. Ex. 4), at AM-00072850; Project Approval (PI. Ex. 5), at AM-00072906.

136. In August of 2005, Gary Rainwater, then the Ameren CEO, authorized the expenditure of $23,148,000 to replace the economizer, reheater, and lower slope panels at Rush Island Unit 1. Stevens Test., Tr. Vol. 2-A 7:5-15; Project Approval Package (PI. Ex. 1), at AM-00072580. Mr. Rainwater also authorized the expenditure of $24,988,000 for the same work at Unit 2. Project Approval Form (PL Ex. 2), at AM-00072829. Earlier in the spring of 2005, Ameren Missouri Chief Operating Officer Thomas R. Voss authorized the expenditure of approximately $6.9 million for the design, fabrication, and installation of new air preheaters at Unit 1, and, in October of 2005, authorized approximately $7.5 million for similar work at Unit 2. Stevens Test., Tr. Vol- 2-A 13:15-22; Project Approval Package (PI. Ex. 4), at AM-00072850; Project Approval (PI. Ex. 5), at AM-00072906.

137. After the 2007 major boiler outage at Unit 1, Unit 2 went through a second justification process in 2009. The Unit 2 major boiler outage had to be approved by an additional committee known as the Capital Project Oversight Committee (“CPOC”), Ameren’s CEO Warner Baxter, and the full Board of Directors. Meiners Test., Tr. Vol. 7-B, 45:8-25, 46:6-47:11; May 16, 2009 Email (PI. Ex. 347), at AM-02637756. On August 14, 2009, Mr. Baxter reported that the outage had been approved. August 14, 2009 Email (PI. Ex. 553), at AM-02480812.

D. Ameren Justified Replacing the Economizers, Reheaters, Lower Slopes, and Air Preheaters Because They Would Improve Operations and Allow the Units to Generate More

138. Ameren’s contemporaneous project authorization documents identified the *938 new economizers, reheaters, lower slopes, and air preheaters as components that were “improved” and “redesigned” in order to fix the operational problems that had been caused by burning PRB coal and age-related deterioration. Stevens Test., Tr. Yol. 2-A, 8:21-9:6; Project Approval Package (PI. Ex. 1), at AM-00072580; Project Approval Package (PI. Ex. 3), at AM-00072831; Boll. Dep. Tr., Dec. 12, 2013, 164:24-165:26, 168:19-169:6; Birk Dep., Sept. 24, 2013, Tr. 194:1-16; Meiners Dep., April 8, 2014, Tr. 237:18-238:11; Pope Dep., Sept. 20, 2013, Tr. 73:12-74:11.

139. Ameren described the planned “major boiler modifications for Rush Island 1 and 2” as follows:

For several years we have been planning major refurbishment of the Rush Island 1 and 2 boilers, which have operated for nearly 30 years without replacing any of the major components. The major scope elements include the following major components which are experiencing an increase in tube leaks and fatigue issues, and have been redesigned to improve future operation and maintenance:

• Reheater—redesigned for PRB coal

• Economizer—redesigned for PRB coal

• Lower Slope—ruggedized design to better withstand slag falls

• Air Preheater—redesigned for ease of future basket replacement.

Project Approval Package (PI. Ex. 6), at AM-00072912; Stevens Test., Tr. Vol. 2-A 9:24-10:18.

140. Ameren’s expert Jerry Golden agreed that the components replaced at Rush Island were redesigned. Golden Test., Tr. Vol. 8-A, 10:6-10; see also RFA Nos. 377 to 383, 386-387, 389-390, 395-401, 407. Further descriptions of these redesigns are provided below.

141. Economizer Redesign: The design of the new economizers was substantially different from the original design. The redesigned economizers were in-line, rather than the original staggered design, which allowed gas to flow through the boiler more easily. The new economizer design made the economizers less subject to fouling and pluggage. Stevens Test., Tr. Vol. 2-A 32:24-33:22; 34:8-12; Specification No. EC-5491 (PI. Ex. 10), at AM-00080325-329; Presentation re: Justification for Projects (PI. Ex. 28), at AM-00966728-730.

142. Reheater Redesign: The design for the new preheaters was significantly different from the original design. Stevens Test., Tr. Vol., 2-A 45:14-18; Boll Dep. Tr., Sept. 5, 2014, 68:11-70. The spacing between the tubes was increased from 10 to 15 inch centers, and the number of front assemblies was reduced from 72 to 48. The bottom of the reheaters was changed from a sloped bottom that closely tracked the boilers’ nose to a horizontal bottom. The number of rear assemblies was decreased from 145 to 96 assemblies, and their height was increased. Similar to the design change for the front assemblies, the spacing between each tube was increased. Additionally, both the front and rear assemblies were platenized. Together, these changes allowed more space for gas and ash to flow through the reíieaters without plugging or fouling. Stevens Test., Tr. Vol. 2-A 45:14-46:25; October 15, 2009 Memo (PI. Ex. 23), at AM-00926322; Specification No. EC-5491 (PI. Ex. 10), at AM-00080329-332; Presentation re: Justification for Projects (PL Ex. 28), at AM-00966737-738.

143. Lower Slopes Redesign: The design for the new lower slope tubes at Unit 1 was a different design than the original lower slope tubes. Specifically, the new lower slope tubes had a thicker wall to *939 prevent tube leak problems caused by slag falls. The space between each tube was decreased, adding greater strength to assist in slag fall protection. Additionally, the structural support was replaced to provide additional strength. Together, these changes made the lower slope tubes staffer, more rigid, and less likely to be crushed so easily. Stevens Test., Tr. Vol. 2-A 55:9-56:4; Specification No. EC-5491 (Pl. Ex. 10), at AM-00080332-334; Presentation re: Justification for Projects (Pl. Ex. 28), at AM-00966748-749.

144. Air Preheaters Redesign: The new, redesigned air preheaters were changed from the original three-layer Ljungstrom regenerative basket design to a two-layer design. The new two-layer air preheaters had a hot end layer and a cold end layer. In each air preheater, each layer had 24 baskets, each of which was 29 inches deep. While the original air pre-heaters each had 456 baskets, the new air preheaters had only 48 baskets total. The design was changed in order to minimize the outage time required for cleaning the baskets in the future. Stevens Test., Tr. Vol. 2-A 57:12-58:21, 66:5-67:9; Specification No. EC-5491 (Pl. Ex. 10), at AM-00080279, 348-353; RFA Nos. 331, 334.

145. Ameren specifically justified performing these boiler upgrades because they were expected to reduce forced outages due to tube leaks, eliminate load reductions, and increase the capability and availability of the units to operate. One of the specific expectations identified in the project justifications was that the replacements would eliminate outage time due to the components for the next 20 years. Stevens Test., Tr. Vol. 2-A 7:16-8:20, 25:12-26:11, 27:13-23, 59:7-60:22; 63:22-65:7; Golden Test., Tr. Vol. 8-A 12:14-13:8.

146. These expected improvements were explicitly stated in Ameren’s project justification documents. For instance, after describing the “new, improved, redesigned” economizer, reheater, and lower slopes, Ameren’s project authorization for Unit 1 stated that “as a result” of the replacements, “Rush Island will eliminate forced outages due to reheater tube leaks for 20 years, eliminate 30 to 50 MW load reductions due to flyash pluggage of the current economizer, and reduce the number of tube leaks caused by slag falling on the furnace lower slopes.” Project Approval Package (Pl. Ex. 1), at AM-00072580 (emphasis added); see also Project Approval Package (Pl. Ex. 4), at AM-00072858 (noting expected improvement in pressure drop across the air preheater, and two week reduction in future outage costs due to quicker basket replacements); October 15, 2009 Memo (Pl. Ex. 23), at AM-00926322 (project objectives include avoiding “load reductions” and “minimizing future forced boiler outages for the next 20 years”); September 18, 2009 Memo (Pl. Ex. 26), at AM-0954160 (noting that air preheater replacement “will reduce the gas side pressure loss across the air preheaters from 14 to 5 inches” of water pressure, and that project would result in a megawatt “gain”).

147.Ameren expected that the work would reduce the number of forced outages due to these components “to zero.” Project Approval Package (Pl. Ex. 1), at AM-00072585-586 (“Flyash pluggage of the economizer will be eliminated or greatly reduced due to the in-line spiral fin economizer ... Forced outages due to tube leaks in the reheater and economizer will be reduced to zero.”); see also id. at 590 (“completing this project will eliminate all the problems”); Project Approval Form (Pl. Ex. 2), at AM-00072829 (same statements for Unit 2); Project Approval Package (Pl. Ex. 3), at AM-00072831-833, 837 (same statements for Unit 2); Presentation re: Justification for Projects (Pl. Ex. 28), at AM-00966731, 740, 750 (identifying avoided costs associated with avoiding der- *940 ates and outages due to boiler tube leaks); see also Yasel Dep., Aug. 15, 2013, Tr. 131:11-132:24.

148. Ameren ultimately decided not to replace the lower slopes at Unit 2 during the 2010 major boiler outage and therefore adjusted the overall availability improvement expected from the work downwards by 0.1% from 4.3% to 4.2%. June 15, 2009 CPOC Email (PI. Ex. 895), at AM-02632840; Meiners Test., Tr. Yol. 7B, 34:9-35:25.

149. Further evidence of Ameren’s expectation of availability improvements is found in Plaintiffs Exhibit 126, which was a presentation that Mr. Meiners made to senior executives at a business plan meeting. Meiners Test., Tr. Vol. 7-B, 27:21-24, 28:18-20. One of the purposes of the presentation was to discuss component replacements and the condition of the reheater, economizer, air preheater, and lower slopes. Id. 28:10-17. At the end of the presentation, Mr. Meiners presented a graph showing that Rush Island’s availability would increase by almost 5%, from about 90% in 2005-2006 to 95% in the first year after both major boiler outages had been completed. Id. 31:15-21

150. Ameren’s experts agreed that the expressed purpose of the work at each unit was the same: to improve capability and eliminate deratings. For instance, Mr. Golden confirmed that the work at both units was intended to eliminate pluggage and fouling of the economizers and reheat-ers, to eliminate future forced and maintenance outages caused by tube leaks, and to eliminate pluggage problems and deratings from the air preheaters. Golden Test., Tr. Vol. 8-A, 10:11-21,13:16-13:21.

151. Mr. Golden also agreed that the purpose of replacing the lower slopes at Unit 1 was to eliminate tube leaks in the lower slope and damage resulting from slag falls and erosion following the switch to PRB coal. Golden Test., Tr. Vol. 8-A, 10:22-25.

152. Ameren’s expert Mr. Caudill conceded that the expected benefits of replacing the components included reducing forced outages and eliminating or greatly reducing flyash pluggage at the units. As Mr. Caudill put it, “[bjasically that’s what Ameren expected” based on a review of Ameren’s project justifications. Caudill Test., Tr. Vol. 10-B, 36:10-37:2, 37:17-38:10.

153. Mr. Caudill also agreed that plug-gage in the reheater, economizer, and air preheaters contributed to high differential pressure, which Ameren expected to reduce as a result of replacing the reheater, economizer, and air preheaters. Caudill Test., Tr. Vol. 10-B, 34:17-35:1, 35:14-17. In addition to eliminating load reductions, such improvements in differential pressure can result in some increase in net efficiency, but not gross efficiency. Caudill Test., Tr., Vol. 10-B, 35:11-13; Koppe Test., Tr. Vol. 3-B, 11:16-12:4, 28:18-29:4. Mr. Cau-dill conceded 'that Ameren did not justify the replacement of the economizers, re-heaters, and air preheaters based on any expectation that they would result in an improvement in gross unit efficiency. Cau-dill Test., Tr. Vol. Vol. 10-B, 44:24-45:12.

154. Mr. Caudill also conceded that Rush Island Units 1 and 2 were experiencing pluggage that was causing load reductions and derates prior to the 2007 and 2010 outages and that eliminating plug-gage that is causing derates will allow a unit to generate at a higher gross load. Caudill Test., Tr. Vol. 10-B, 35:18-22, 37:3-16.

155. Ameren’s final, updated justification for the 2010 major boiler outage reflected the company’s expectation that the replacements would enable the unit to operate more and to produce more megawatts when operating. The justification *941 identified two types of performance improvements from the boiler work: a capacity increase and an equivalent availability improvement. As described in a 2009 work order authorization request:

A gain of 30 MW in the summer and 20 MW in the winter will be obtained with the combined reheater, economizer and .air preheater replacements. Also included in the justification is an approximate 3-4% improvement in equivalent availability of the unit.

Assumptions: It is assumed that these boiler modifications will result in an improved operation of the unit that is at least equal to, if not better, than that currently experienced with Unit 1 which had similar modifications in 2007. This includes fewer load restrictions, improved equivalent availability and elimination of potential catastrophic failure of the economizer.

October 15, 2009 Memo (PI. Ex. 23), AM-00926323; see also id. at AM-00926322 (“Load reductions of 30 MW in the summer and 20 MW for the remainder of the year can be avoided with the new boiler components and the re-designed air pre-heater.”); Stevens Test., Tr. Vol. 2-A, 25:12-26:11; 27:3-23.

156. The justification of additional generation from the replacements is also found in the financial analysis tool that was used to justify the 2010 outage. The availability gain used in the final financial analysis was the equivalent' of “15 days of generation.” Economic Value Added (EVA) Financial Analysis for Unit 2 (PI. Ex. 48); Meiners Test., Tr. Vol. 7-B, 18:6-11,18:21-19:16.

157. Ameren’s final financial evaluation separately included a 22.5 MW “projected annual increase ... in plant capacity” as a result of the replacement of the reheater, economizer, and air preheater. Economic Value Added (EVA) Financial Analysis for Unit 2 (PI. Ex. 48), at “Data Entry” Sheet; Koppe Test., Tr. Vol. 3-B, 30:4-32:23. This capacity increase was based on Ameren’s estimate that the component replacements would allow Unit 2 to produce 30 more MW of capacity during the three summer months and 20 MW for the remainder of the year. Koppe Test., Tr. Vol. 3-B, at 27:7-32:23; PI. Ex. 48, at “Data Entry” Sheet; July 2009 ELT Progress Report (PI. Ex. 110), at AM-02465690 (“30MW gain in summer (3 mos), 20MW gain balance of year from Reheater, Economizer and APH investment”).

158. The 22.5 MW increase in capacity was separate from the availability input used in the model. July 2009 ELT Progress Report (PL Ex. 110), at AM-02465690 (describing megawatt capability “gain” from boiler upgrade separately from 4.2% equivalent availability impact); Koppe Test., Tr. Vol. 3-B 30:8-31:7. It represented an increase over the capability that Unit 2 was able to achieve during the pre-project period. Koppe Test., Tr. Vol. 3-B, 28:2-12. The financial impact included significant “incremental power sales” that were calculated to have a favorable impact on ratepayers, shareholders, and earnings. July 2009 ELT Progress Report (PI. Ex. 110), at AM-02465691.

159. These boiler capacity and availability gains were also identified separately from an additional 15 megawatt capability gain from replacing the LP turbine with a more efficient design. July 2009 ELT Progress Report (PL Ex. 110), at AM-02465690 (describing gains separately in project economic analysis).

160. During the final 2009 approval process for the Unit 2 outage, Mr. Meiners reiterated the accuracy of these forecasts to Ameren’s CEO, Mr. Baxter. May 16, 2009 Email (Pl. Ex. 347), at AM-02637756 (“I do believe the model is now a much more accurate representation of the eco *942 nomic benefits.”); Meiners Test., Tr. Vol. 7-B, at 46:9-47:11.

E. Implementation of the 2007 and 2010 Major Modifications

161. Ameren installed the new economizer, reheater, two air preheaters, and lower slope panels at Rush Island Unit 1 during an outage that began on February 17, 2007 and ended on May 28, 2007. 2007 Post Outage Report (PI. Ex. 34), at AM-02252210.

162. On January 24, 2007, almost one month before the Unit 1 major boiler outage was to start, there were already 54 contractors on site. The previous week, 17 truckloads of tubing arrived on site and a crane was being constructed for use in replacing the reheater. Rush Island Project Book (PI. Ex. 63), at AUE-00156343; Overhead Photo of Laydown Areas (PI. Ex. 414), AM-00222751. This level of activity on-site, a month before the work had even started, is not typical of routine maintenance at a power plant. Stevens Test., Tr. Vol. 2-A, 18:14-19:19.

163. Ameren installed the new economizer, reheater, and two air preheaters at Rush Island Unit 2 during an outage that began on January 1, 2010 and ended on April 6, 2010. Vol. 2A, Stevens Test., 24:9-15; 2010 Post Outage Report (PL Ex. 46), at AM-02739973.

164. The replacements took years to design and plan and required the special fabrication of components that were not otherwise available at the Rush Island plant. Specification No. EC-5491 (PI. Ex. 10), at AM-00080233; Rush Island Project Book (PI. Ex. 63), at AUE-00156362. Am-eren’s expert, Jerry Golden, acknowledged at trial that these replacements were not de minimis activities. Golden Test., Tr. Vol. 8-A, 33:9-18.

165. The size and extent of the components replaced during the 2007 and 2010 major boiler outages was massive, with the economizers, reheaters, and air preheaters each weighing hundreds of thousands of pounds. Stevens Test., Tr. Vol. 2-A, 13:10-14, 34:22-35:7, 50:11-13, 59:3-6, 67:21-68:5. For example, the new reheaters included two outlet headers that weighed 36,000 pounds each and 144' reheater tube assemblies, including 48 front pendant assemblies that were each approximately 49 feet tall and 96 rear pendant assemblies that were each approximately 35 feet tall. Stevens Test., Tr. Vol 2-A, 45:14-46:25, 50:10-13; Specification No. EC-5491 (PI. Ex. 10), at AM-00080330-332; RFA Nos. 386-387, 390, 395-398. If the Rush Island economizer’s tubing was laid from end-to-end, the length of tubing would stretch around 140 miles. Stevens Test. Tr. Vol. 1-B, 79:20-80:5.

166. Given the complexity of the replacements, the components needed to be designed, engineered, and constructed by outside contractors, such as Alstom Power—the original manufacturer of the boilers, and numerous other contractors. The work involved was substantial, requiring hundreds of thousands of man-hours, and was well beyond the capacity of Ameren’s own staff. Stevens Test., Tr. Vol. 2-A, 21:18-22: 18; 2007 Post Outage Report (PI. Ex. 34), at AM-02252259, 260; 2010 Post Outáge Report (PI. Ex. 46), at AM-02739979.

167. Heavy machinery was required to facilitate the removal of old components and installation of new, redesigned components. Multiple monorails were installed in order to maneuver the components. Stevens Test., Tr. Vol. 2-A, 18:24-19:11; 36:6-18; 38:11-19. Multiple large cranes were constructed to remove and lower the old assemblies to the ground and lift the new assemblies to the necessary height within the boiler. Each outage required the construction of two Manitowoc 888 cranes, as well as several other cranes, including *943 Manitowoc 222 and 2250 cranes. Stevens Test., Tr. Yol. 2-A, 18:14-19:19; 48:12-20; 2007 Post Outage Report (PL Ex. 34), at AM-0225210; 2010 Post Outage Report (PI. Ex. 46), at AM-02739973. The largest Manitowoc crane had to be tall enough to remove 50-foot reheater assemblies through the roof at an approximately 270 foot elevation. Stevens Test., Tr. Vol. 2-A, 48:4-15.

168. The process of removing each old component and installing each new component was highly complex. For the boiler components, each original assembly was cut out and removed one-by-one. Stevens Test., Tr. Vol. 2-A, 36:11-19. Cuts had to be made in the side of the boiler lagging and walls at various elevations, including one at around a 200 foot elevation, as well as in the roof of the boiler house. Stevens Test., Tr. Vol. 2-A, 38:11-19, 47:25-48:3. It would take months to facilitate the removal and re-installation. Stevens Test., Tr. Vol. 2-A, 38:25-39:9; 49:2-7. Many craftsmen were involved in the cutting and welding process. Stevens Test., Tr. Vol. 2-A, 50:20-51:1.

169. The 2007 major boiler outage at Rush Island Unit 1 lasted 100 days and required more than 1,000 workers and 448,539 total hours of labor, of which 402,-109 hours were performed by contractors. Ninety-one percent of the work done during the Unit 1 major boiler outage was performed by contractors. While other work was performed, the replacement of the economizer, reheater, air preheaters, and lower slope panels was the most significant and costly work performed during the outage. Stevens Test., Tr. Vol. 2-A, 21:18-22: 18; 2007 Post Outage Report (PI. Ex. 34), at AM-0225259, 260.

170. The 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. 2010 Post Outage Report (PI. Ex. 46), at AM-02739976.

171. The 2007 and 2010 major boiler outages were significantly different than typical power plant maintenance, repair, and replacement activities undertaken on a day-to-day basis. Ameren itself did not characterize the replacement of major components such as the reheaters, economizers, air preheaters, and lower slopes at issue in this case as “routine.” Instead, Ameren described the work as “major boiler modifications” and identified the work as not recurring and not routine in its project documents. Stevens Test., Tr. Vol. 1-B, 65:24-66:10, 66:8-71:2; Vol. 2-A, 9:24-10:18, 11:19-12:2; October 5, 2005 Memo (PI. Ex. 6), at AM-00072912; Project Approval Package (PI. Ex. 1), at AM-00072591; Project Approval Package (PI. Ex. 3), at AM-00072838; RFA No. 460.

172. The 2007 and 2010 major boiler outages were unprecedented events for Rush Island Units 1 and 2. After the 2007 major boiler outage, Ameren’s Vice President Mark Birk referred to the outage as the “most significant outage in Rush Island history.” May 29, 2007 Email (PI. Ex. 31). Mr. Birk specifically called out the replacement of several components—including the economizer, reheater, lower slope, and air preheaters—as distinct from “the routine maintenance that had to be performed” during the outage. Id. The 2010 major boiler outage was similarly referred to as “among the most significant in [company] history.” Jerry Odehnal Report (PI. Ex. 40); see Vasel Dep., Aug. 15, 2013, Tr. 272:2-23 (describing exhibit 40); see also 2010 State of the System presentation, PI. Ex. 41, at AM-02493747 (distinguishing the air preheater, reheater and economizer replacements from the “routine maintenance” done during the 2010 outage).

*944 173. By the time of their replacements in 2007 and 2010, the reheaters, economizers, and air preheaters were more than 80 years old, nearing the end of their expected lives. These components had never before been replaced at Rush Island Units 1 and 2. Stevens Test. Tr. Vol. 1-B, 50:24-51:4, 81:19-82:1, 84:9-13; 108:13-109:3; Tr. Vol. 2-A, 9:24-10:18, 43:3-25; Golden Test., Tr. Vol. 8-A, 16:7-16; Vasel Dep., Aug. 15, 2013, Tr. 131:11-132:6; October 5, 2005 Memo (PI. Ex. 6), at AM-00072912 (“units have operated for nearly 30 years without replacing any of the major components”); Unit 2 ELT Progress Report (PI. Ex. 110), at AM-02465689 (“The MBO [major boiler outage] is being undertaken to change out 2 major boiler components and the APH that are end of life ... ”); Unit 2 ELT Progress Report (PI. Ex. 456), at AM-00953927.

174. Projects such as the economizer, reheater, air preheater, and lower slope replacements are not performed frequently during the life of a typical utility unit. Stevens Test., Tr. Vol. 1-B, 91:11-18. Am-eren’s expert Mr. Golden agreed that the typical life of a reheater is about 30 years, the typical life of a primary economizer is about 35 years, and the typical life of a lower slope is about 40 years. Golden Test. Tr. Vol. 8-A, 18:2-11. Mr. Golden also testified that complete air heater replacements (including the rotor and all baskets), like the ones done at Rush Island, are not done frequently at any unit. Golden Test., Tr. Vol. Vol. 8-A, 19:9-15.

175. Even looking exclusively to how common work is performed across the utility industry, Mr. Golden was able to identify few, if any, projects that rival the 2007 and 2010 major boiler outages at other Ameren plants or elsewhere in the utility industry. Mr. Golden has worked on 14 NSR cases since 2000 on behalf of electric utilities. Golden Test., Tr. Vol. 8-A, 6:3-16. During that time, he has collected a list of 18,300 projects undertaken at coal-fired power plants that he says are both capital projects and cost more than $100,000. Golden Test., Tr. Vol. 8-A, 25:11-14; 25:24-26:2, 26:13-16. However, Mr. Golden was not able to identify any coal-fired unit in the electric utility industry that has replaced the economizer, the reheater, the lower slopes, and the air preheater together. Golden Test., Tr. Vol. 8-A, 19:3-8; see also Vasel Dep., Aug. 15, 2013, Tr. 154:11-24 (unable to recall any other outage at Ameren when all components were replaced).

176. Similarly, even for the relatively few air preheater replacements that Mr. Golden did identify (35 out of approximately 1,200 coal-fired generating units operating in 2007), Mr. Golden was unable to testify that all were complete replacements or were comparable to those at Rush Island. Golden Test., Tr. Vol. 8-A, 20:2-23, 28:3-12, 28:17-29:5.

F. The Cost of the 2007 and 2010 Major Modifications

177. Replacement of the reheater, economizer, air preheaters, and lower slope at Rush Island Unit 1 ultimately cost approximately $34 million. Stevens Test. Tr. Vol 2A, 22:24-23:3; Golden Test., Tr. Vol. 8-A, 23:7-10.

178. Replacement of the reheater, economizer, and air preheaters at Rush Island Unit 2 ultimately cost more than $38 million. Stevens Test., Tr. Vol 2-A, 28:5-9; Golden Test., Tr. Vol. 8A, 23:7-10.

179. Ameren’s budget for the Rush Island plant is divided into an Operation and Maintenance (“O&M”) component and a Capital component. Stevens Test., Tr. Vol. 1-B, 89:23-90:3.

180. A capital project is one that would improve the value of the asset. Stevens Test., Tr. Vol. 1-B, 91:1-10.

*945 181. The component replacements at issue in this case were capital projects. The projects were actually funded out of Ameren’s capital budget rather than its O&M budget. Stevens Test., Tr. Vol. 1-B, 89:23-90:3, Vol. 2-A 5:12-17; Golden Test., Tr. Vol. 8-A, 23:14-15.

182. Costing $34 to $38 million, the boiler component replacements at Unit 1 and 2 were the costliest capital projects ever done at the Rush Island plant. Golden Test., Tr. Vol. 8-A, 23:7-19. By way of comparison, Rush Island’s entire annual O&M budget for the Rush Island plant was about $25 million. Meiners Test., Tr. Vol. 7-B, 23:24-24:2.

183. The boiler component replacement projects were among the most expensive boiler projects that Ameren identified to EPA as ever having been undertaken at any of its plants. Knodel Test., Tr. Vol. 1-A, 81:9-82:8.

III. THE 2007 AND 2010 BOILER UPGRADES EACH RESULTED IN A SIGNIFICANT NET EMISSIONS INCREASE OF S02 WITHIN THE MEANING OF THE PSD REGULATIONS

184. The 2007 and 2010 boiler upgrades triggered PSD if: (1) Ameren should have expected them to result in a significant (i.e., more than a 40 tons-per-year) S02 increase; or (2) a 40 tons-per-year S02 increase related to the boiler upgrades actually occurred. Ameren SJ Decision; see also 40 C.F.R. § 52.21 (a)(2)(iv)(&), (c).

185. As described further below, Amer-en should have expected the 2007 and 2010 boiler upgrades to increase the availability of the units, thereby resulting in more than 40 tons per year of increased S02 emissions. At both units, these availability improvements resulted from eliminating significant outages and derates that had been plaguing the boilers prior to the upgrades. Removing the problems that had been limiting their pre-project availability should have been expected to increase their post-project operations and emissions. In addition, for at least the 2010 boiler upgrade, Ameren should have expected the new economizer, reheater, and air preheaters to increase the maximum megawatt generating capability of the unit, resulting in increased annual emissions.

186. In addition, availability and hours of operation of Units 1 and 2 actually increased by an amount greater than that required to trigger PSD, just as Ameren expected, as did the megawatt capability of Unit 2.

187. Evidence for these expected and actual increases is found in Ameren’s documents and project justifications, in its GADS and other operational data, and in the results of a computer modeling program called ProSym that Ameren uses to simulate the operations of its generating units. The United States’ emissions experts, Mr. Koppe, Dr. Sahu, and Dr. Haus-man, explained how this evidence demonstrates that the availability and capability improvements at Rush Island Units 1 and 2 would be expected to, and did, far exceed the 40 tons-per-year PSD threshold for S02. After a brief overview, the specific evidence supporting a finding that the 2007 and 2010 boiler upgrades resulted in significant S02 increases is reviewed in further detail below.

A. Overview

188. The Rush Island units are low-cost, baseload units, meaning that they will operate any additional hours that they are made available to operate. FOF 6. As some of the most cost-effective units in a large and interconnected electricity supply system that is vastly larger than any individual unit, it was not a lack of demand that was holding the units back prior to the *946 2007 and 2010 boiler upgrades. These “work horse” units were already made to run every hour they were available to run. What held the units back prior to their upgrades was the forced outages and load ■limitations that were plaguing the boilers as a result of burning a coal for which they were not designed, along with the fact that key boiler components had degraded as they neared the end of their design lives. Fixing those problems was expected to, and did, result in increased operations.

189. Because they lack S02 pollution controls, the Rush Island units are very large sources of air pollution. FOF 8, 9. The large size of the units means that very small changes in performance can result in increased S02 emissions of more than 40 tons per year.

190. For example, it only takes 21 additional hours of full power operation at either unit to produce more than 40 tons of S02. Sahu Test., Yol. 5, 41:3-7, 45:25-46:4. Given that it typically takes two to three days to recover from even a single outage (FOF 35), eliminating just one outage would result in more than 40 additional tons per year of S02. Sahu Test., Vol. 5, 46:17-47:2, 62:2-63:10, 94:5-95:23; August 15, 2005 Presentation (Ex. 332), at AM-00966775, 794 (showing inter alia that one outage due to the economizer lasts three days).

191. Measured in terms of equivalent availability, it takes only about a 0.3 percentage point (i.e., one-third of a percentage point) increase in availability to produce more than 40 additional tons per year of S02 from these units. Hausman Test., Tr. Vol. 4-B, 66:15-25.

192. Similarly, increasing the capability of Rush Island Unit 2 by just 1.7 megawatts would result in an increase in S02 emissions of at least 40 tons per year. Sahu Test., Vol. 5, 41:11-14; 46:5-11; Hausman Test., Tr. Vol. 4-B, 58:4-60:2 (one megawatt increase in capacity produces 23 additional tons of S02).

B. GADS-Based Emissions Calculations for Rush Island Units 1 and 2

193. The United States presented emissions calculations utilizing data generated by Ameren which was transmitted to the North American Electric Reliability Council (“NERC”) and maintained in NERC’s Generating Availability Data System. As explained above in Subsection II. B.4, GADS is an industry-wide database that collects information on the performance of power plants and the effects that various problems have on that performance. Ameren and other utilities use GADS data to track the causes of outages and derates so that they can assess the status of plant equipment and predict future availability. FOF 89, 92. As also described above, Ameren specifically uses GADS data to calculate “lost generation” when performing financial calculations to determine whether to perform capital projects. FOF 103.

194. Plaintiffs expert Mr. Koppe, who has been a power plant performance consultant for four decades and helped develop the GADS database, reviewed Ameren’s GADS data to determine which outages and derates were caused by problems with the boiler components at issue in this case. FOF 90, 91,106.

195. Mr. Koppe then quantified the expected effect of the 2007 and 2010 upgrades on availability. In performing his analyses, Mr. Koppe used the same basic approach that he used to assess expected performance impacts in his work for utilities over the past 40 years. Koppe Test., Vol. 3-A, 35:6-9 (“I’ve seen it used by many different utilities, including Ameren, and I’ve seen it in various industry publications.”)

*947 196. Mr. Koppe concluded that the company should have expected, and did expect, the 2007 and 2010 boiler upgrades to eliminate all of the availability losses that were due to the economizers, reheat-ers, lower slopes, and air preheaters. Koppe Test., Vol. 3-A, 48:24-49:6; see also Sahu Test., Vol. 5, 95:24-97:2. Ameren’s project justifications were based on this very assumption. Koppe Test., Tr. Vol. 3-A, 49:24-51:14. See FOF 145, 146, 147. Similarly, the effects of pluggage on the units were expected to be eliminated for at least decades into the future. Koppe Test., Vol. 3-A, 54:16-55:3.

197. Based on Ameren’s documents and data, and relying on his decades of experience in the industry, Mr. Koppe then made an engineering judgment on the improvements in availability that would be expected to result from the 2007 and 2010 boiler upgrades. In order to determine whether eliminating the causes of unavailability related to the components at issue would result in an overall increase in unit availability, Mr. Koppe assessed the condition of the rest of the equipment at Rush Island Units 1 and 2 in order to ensure that other problems would not be expected to offset the performance improvements expected from the boiler upgrades. As Mr. Koppe explained, the boiler components replaced by Ameren were the “things that were really hurting them” in terms of availability, as they alone were causing roughly half of all the lost productivity at the units during the baseline period. Koppe Test., Vol. 3-A, 47:7-12; 75:3-11. “[Pjroblems with all the rest of the equipment were only half of the losses, and here you had four problems that were half of all the lost productivity.” Id. 48:2-8 . However, he wanted to be sure that “the level of maintenance that was being done” on the remaining parts of the unit that were not being upgraded was sufficient to maintain the overall very good level of performance that those remaining components had experienced. Koppe Test., Vol. 3-A, 56:12-56:25.

198. As part of this review of the entire unit, Mr. Koppe reviewed GADS data and other contemporaneous company data and documents describing the overall condition of the units. Mr. Koppe reviewed, for example, reports identifying all of the maintenance and capital projects done during the outage, unit condition assessments prepared by company engineers, and presentations made by plant engineers to management about the condition of the unit. Koppe Test., Vol. 3-A, 34:13-21, 51:20-57:17; see also GADS Events Data (PI. Ex. 925), 2007 and 2010 Outage Reports (PI. Ex. 34 and 46), Condition Assessments (PI. Ex. 106 and 606), and State of the System Presentations (PL Ex. 15, 41, and 111). Based on his review of this evidence, Mr. Koppe concluded that the overall effect of everything else at the plant on availability would not offset the availability gains from the components at issue. Koppe Test., Vol. 3-A, 51:20-66:5-67:3.

199. Evidence that other problems would not be expected to offset the performance improvements from the 2007 and 2010 boiler upgrades was also provided by Ameren witnesses at trial. As Mr. Naslund testified, as part of the new “super outage” concept that he championed, the company proactively addressed everything that might cause problems in the next six years at a unit to ensure the unit would run as well as possible and “improve unit availability.” Naslund Test., Tr. Vol. 6-B 7:1-8:6. After implementing the super outage process, forced outages in fact went down and availability went up. Naslund Test., Tr. Vol. 6-B, 6:19-25. Mr. Strubberg similarly testified that he was responsible for a condition-based maintenance program called the PRO/PMO program that helped keep the balance of individual components at high availability, and by doing that, it helped keep the units at high availability. *948 Strubberg Test., Tr. Vol. 8-A, 35:21-23, 38:23-24, 39:21-25, 61:5-9, 77:8-12.

200. Once the expected impact on availability is determined for a unit, the next question is to determine whether that increased availability will actually be used to operate more in the future. Whether or not increased availability will result in an additional hour of operation in the future can sometimes be a “tricky question” for some units, “but it’s not for these units, because these units operate for almost every single hour that they are able to operate. So if you increase the number of hours a unit is available to operate, that will result in an increase in the number of hours the unit does operate.” Koppe Test., Vol. 3-A, 35:17-26; see also Naslund Dep., Sept. 18, 2014, at 55:2-55:7.

201. This direct relationship between availability and generation at Rush Island was also confirmed by modeling performed by Dr. Hausman. As Dr. Hausman explained, if availability is improved, it means the unit can run more hours or it can run at a higher level for more hours. Hausman Test., Tr. Vol. 4-B, 39:9-13. For a relatively low-cost baseload unit, if it is able to produce more, it typically will produce more. As Dr. Hausman explained: “I think that’s a fairly fundamental way to look at electricity markets. If I were to run a model and it ran less or used less fuel, there would be something very strange in that.” Hausman Test., Tr. Vol. 4-B, 39:16-40:4; see also id. at 36:12-21 . Dr. Haus-man found exactly such a linear relationship between availability improvements and generation at Rush Island. Hausman Test., Tr. Vol. 4-B, 64:10-64:20, 71:7-25.

202.This direct relationship between availability and generation at baseload units like Rush Island was also obvious from presentations prepared by Ameren itself on the importance of availability, which showed availability tightly tracking plant generation. Strubberg Test., Tr. Vol. 8-A, 100:4-6, 100:15-17; 2008 State of the System (PL Ex. 15), at AM-00196620.

*949 [[Image here]]

203. The data also shows a relationship between unit availability and S02 pollution, as Ameren’s expert Michael King acknowledged at trial. King Test., Tr. Vol. 6-B, 86:2-23.

204. The extraordinarily high use of Rush Island’s availability was also confirmed in the GADS data that Mr. Koppe reviewed, which included data on how often the units were placed in a status known as “reserve shutdown.” When a unit is in reserve shutdown, it is available to operate but does not for economic reasons. Koppe Test., Tr. Vol. 3-A, at 36:22-37:1.

205. The Rush Island units did not spend a single hour in reserve shutdown during the PSD baseline periods. Koppe Test., Tr. Vol. 3-A, 37:2-7; Naslund Dep., Sept. 18, 2014, Tr. 54:21-55:7; RFA Nos. 189, 192, 193, 203. In the five years before the projects, one of the units operated every single hour it was available, and the other operated 99.9% of the time. Koppe Test., Tr. Vol. 3-A, 37:8-18. That means that if a Rush Island unit “is available to operate another hour, it will operate for that hour; and that, of course, requires burning more coal and generating more emissions.” Koppe Test., Tr. Vol. 3-A, 37:19-24; Naslund Test. Vol. 6-A, 50:3-13 (describing Rush Island units as “two workhorses”), 45:3-20 (since 2005, the Rush Island units “were staying up on load at much higher levels around the clock”), 48:7-49:3 (because the Rush Island units are among the cheapest units in MISO, they run a higher percentage of time); Naslund Dep., Sept. 18, 2014, Tr. 55:4-7. 206.Mr. Koppe’s quantification of increased unit availabilities caused by the 2007 and 2010 boiler upgrades was then translated into emissions increases by Dr. Sahu, a combustion engineer and environmental permitting engineer, who has performed PSD calculations hundreds of *950 times. Sahu Test., Vol. 5, 34:24-38:14. Dr. Sahu did not assume that Ameren would generate at full capacity every additional hour that it generated. Instead, he applied the same utilization factor that the units experienced during the PSD baseline period. Sahu Test., Tr. Vol 5, 51:5-53:16, 75:3-77:20.

207. Using the same baseline utilization factor is consistent with the fact that the units are baseload units that are used whenever they are available. In addition, the historic utilization factor of the units remained relatively stable, and Ameren documents indicate that it expected the utilization factor of the units to remain relatively stable going forward. Sahu Test., Tr. Vol. 5, 57:15-58:21; September 9, 2006 Email and attached critical review spreadsheet (PI. Ex. 333), at Rush 1 and Rush 2 tabs.

208. Use of a constant utilization factor was also confirmed by Ameren’s witnesses. Ameren expert Marc Chupka opined in his expert report that it “would be reasonable to assume a constant utilization factor for projecting future emissions at least for some period of time” after the projects at issue in this case. Chupka Test., Tr. Vol. 8-B, 77:3-18. Similarly, Sandra Ringelstet-ter’s work papers identified the baseline utilization factor and the utilization factor projected by Ameren for both Unit 1 and Unit 2. For Unit 1, the utilization factor was projected to stay basically the same (a change of 0.09%), while for Unit 2 it was projected to increase by about 2%. Def. Ex. NE, at “RI U1 2007 Summary” and “RI U1 2010 Summary.”

209. Using the same utilization factor from the baseline period specifically eliminates the impact of other factors that could cause an increase in utilization of a unit when its availability improves, thus isolating just the effect of the boiler upgrades. For instance, whereas Ms. Ringelstetter identified a 2% increase in utilization factor at Unit 2, Dr. Sahu’s use of the baseline utilization factor excludes any effects of increased demand on the units by calculating just the increase that is due to the availability improvements made possible by the upgrades. Sahu Test., Tr. Vol. 5, 75:18-76:5,153:21-25.

210. In addition, as Dr. Sahu described, the general approach of applying a utilization factor to calculate the additional generation from an expected availability improvement is consistent with Ameren’s practices and is well understood in the industry. The same basic formula is found in Ameren’s availability worksheets, which translate availability improvements into generation for fuel budgeting purposes, as well as industry documents such as a 1985 study publication of the Electric Power Research Institute (“EPRI”). Sahu Tr., Vol. 5, 53:17-57:5. For instance, Ameren’s availability worksheets provide the following formula for calculating “expected annual plant generation” from an availability change: “Total Net mwhrs” equals “Plant Equiv. Avail. X Utilization Factor.” Availability Worksheet (PI. Ex. 250), at Spreadsheet Tab “Instructions.” The 1985 EPRI study provides a similar formula. See Economic Evaluation of Plant-upgrading Investments (PI. Ex. 241), at AME_RHK000011. Similarly, although Ameren has criticized Dr. Sahu’s use of utilization factors as applied to both outages and derates in this case, Ameren itself uses utilization factors in a similar way outside of this litigation. For instance, in using a utilization factor to estimate future generation, Ameren’s availability worksheets specifically defines the utilization factor as “the percent of mwhrs used after outages and derates.” Availability Worksheet (PI. Ex. 250), at Spreadsheet Tab “Instructions.”

211. Dr. Sahu’s emission calculations also used the same S02 emission factor *951 from the baseline period. As with holding the utilization factor constant, reasons for using the baseline emission factor in the calculation of post-change emissions include the fact that Ameren documents indicate that the emission factor was expected to remain fairly stable. Sahu Test. Tr. Vol. 58:22-59:24, 89:6-89:13, September 9, 2006 Email and attached critical review spreadsheet (PI. Ex. 333), at Rush 1 and Rush 2 tabs.

212. In addition, the project justification documents for the 2007 and 2010 boiler upgrades made no mention of any expected improvements in the gross efficiency of the units, a point that was conceded by Ameren’s capability expert. Cau-dill Test., Tr. Vol. Vol. 10-B, 44:24-45:12; see also Sahu Test., Tr. Vol. 5, 108:3-21.

213. While Ameren argued that it expected small reductions in auxiliary load as a result of the boiler upgrades, such reductions would result in an improvement in net efficiency, not gross efficiency, and as a result do not affect the amount of coal that the unit is capable of burning. Rather, they just mean that less power is used to run the plant, so more of the gross generation recovered by the boiler upgrades could be sent to the grid. Koppe Test., Tr. Vol. 3-B, 11:16-12:4; Shelton Test., Tr. Vol. 10-A, 85:8-10. As Dr. Sahu explained, all of his calculations are based on gross megawatts because gross is what relates to how much S02 comes out of the boiler. Sahu Test., Tr. Vol. 5, 52:16-24, 84:20-24.

214. Similarly, while Ameren did expect some improvement in efficiency at Unit 2 due to the contemporaneous replacement of the low pressure turbine, Dr. Sahu accounted for that in his calculations by factoring out both the additional megawatt capability of the new turbine and the heat rate of the turbine. Sahu Test. Tr. Vol. 5, 84:9-85:1, 135:23-136:8, 137:9-15; 138:3-10, 181:21-182:4. Dr. Sahu’s treatment of the low pressure turbine on the expected S02 emission rate was consistent with how Ameren itself treated the expected effect of the turbine outside of this litigation. For instance, Ameren’s financial analysis was based on the assumption that the turbine-related efficiency improvements would allow Unit 2 to produce more megawatts, but would not result in the unit burning any less coal. PL Ex. 48, at “Data Entry” sheet (rows 149-152, col. D (and comment box) (showing that Ameren did not include efficiency benefit inputs for “decrease in fuel usage”)), PI. Ex. 110, at AM-02465690; Koppe Test., Vol. 3-B, at 29:9-32:9. As Dr. Sahu noted, Ameren’s financial analysis shows that there was no expected fuel decrease associated with the capacity increase. Sahu Test. Tr. Vol. 5, 97:3-99:4. •

215.Use of a constant emission factor was also corroborated by the United States’ other experts. As Dr. Hausman explained, when a baseload unit like the Rush Island units is modified to become more efficient, it allows the unit to generate more electricity while consuming the same amount of coal. Hausman Test., Tr. Vol. 4-B, 37:6-18. Because a baseload plant has essentially an unlimited market for its very low-cost power, if it becomes more efficient, it will burn the same amount of coal but produce more energy than it can sell into the market. Hausman Test., Tr. Vol. 4-B, 38:7-11. As a result, as Mr. Koppe also explained, the separate efficiency gain from the turbine would result in increased megawatts but would not change the full load heat input to the boiler. Koppe Test., Tr. Vol. 3-B, 29:9-32:9. This was also consistent with Ameren employee Jeff Shelton’s testimony that a more efficient turbine can allow a unit to make more megawatts with the same amount of heat input. Shelton Test., Tr. Vol. 10-A, 85:14-20, 85:5-9.

*952 216. Finally, use of a constant emission rate was also borne out by Ameren’s operating data as reported to EPA, which confirmed that the post-project emission rate at Unit 1 stayed relatively constant, and actually increased somewhat at Unit 2 as compared to the PSD baseline periods. Sahu Test., Tr. Vol. 5, 109:14-22. At Unit 1, reported heat rate deteriorated slightly, from 9,282 Btu/Kwh to 9,447 Btu/Kwh, and the unit emitted approximately 21 more pounds per hour of S02 than it had in the baseline. Sahu Test., Tr. Vol. 5, 110:6-111:6; Knodel Test., Tr. Vol. 1-A, 110:8-24. At Unit 2, reported heat rate deteriorated from 8,800 Btu/Kwh to 9,676 Btu/ Kwh, and the unit emitted approximately 456 more pounds per hour of S02 than it had in the baseline. Knodel Test., Tr. Vol. 1-A, 111:8-20. Sahu Test. Tr. Vol. 5, 112:21-24. As a result, for every additional hour that Rush Island Units 1 and 2 were able to operate in the post project period, they actually emitted more S02 per hour.

217. Because Dr. Sahu’s calculation is based on the incremental impact of the projects on unit performance calculated by Mr. Koppe, his entire predicted increase is related to the project. Sahu Test., Tr. Vol. 5, 49:21-50:3, 60:13-18, 61:15-17, 73:6-74:4, 77:11-20, 84:15-87:10.

218. Ameren presented testifying expert Michael King to critique the approach used by Mr. Koppe and Dr. Sahu. But Mr. King agreed that Mr. Koppe and Dr. Sahu “have the appropriate experience to estimate the effect of modifying a power plant on generation [and] emissions.” King Test., Tr. Vol., 6-B, 65:17-21.

219. Another Ameren testifying expert, Marc Chupka, conceded that the method used by Mr. Koppe and Dr. Sahu for determining PSD emissions increases has at least been “well-known in the industry” since the first enforcement cases were filed in 1999. Mr. Koppe testified that he and Dr. Sahu had used the same basic formula in this case that he and other utilities have used for decades. Koppe Test., Tr. Vol. 3-A, 35:6-9; see also Sahu Test., Tr. Vol. 5, 53:17-57:5 (discussing Ameren and industry documents). Mr. Chupka himself has been asked to analyze utility projects using the same method employed by Mr. Koppe and Dr. Sahu numerous times. Chupka Test., Tr. Vol. 8-B, 74:14-21, 75:5-10.

1. Results of projected emissions increase calculations based on the GADS data at Rush Island Unit 1

220. As described further below, Amer-en should have expected an increase of at least 600 tons per year of S02 emissions over the PSD baseline emissions as a result of the availability improvements caused by the 2007 boiler upgrade.

221. The PSD “baseline” period used by Ameren for Unit 1 in this litigation was the highest 24-month period of emissions in the five years before the 2007 boiler upgrade, which was February 2005 through January 2007. During that period, Unit 1 emitted 14,874 tons per year of S02. Sahu Test., Tr. Vol. 5, 49:8-20; Knodel Test., Tr. Vol. 1-A, 95:6-25.

222. During this baseline period, problems in the economizer, reheater, lower slopes, and air preheaters caused Unit 1 to lose 336.1 equivalent full power hours of generation per year, which is roughly equivalent to 14 days of operation per year. Koppe Test., Tr. Vol. 3-A, 45:15-46:24. The unit was completely shut down in outages for 246.4 hours per year due to problems in the components at issue and lost the equivalent of another 89.7 full power hours of operation due to deratings. Id.

223. As explained by Mr. Koppe, the problems associated with the Unit 1 re-heater, economizer, air preheater, and lower slopes caused about 50% of all the avail *953 ability losses at Unit 1 during the baseline period. Koppe Test., Tr. Vol. 3-A, 47:7-12; 48:2-8.

224. These problems reduced Unit l’s availability during the baseline period by 3.8 percentage points. Sahu Test., Tr. Vol. 5, 63:11-64:5. Unit l’s availability was 92.1% during the baseline. Koppe Test., Tr. Vol. 3-A, 48:9-11. The average annual availability of Unit 1 over the entire five-year pre-project period was 87.5%. Id. 48:15-23

225. Based on his analysis of Ameren’s operating data, including GADS, as well as contemporaneous documents, Mr. Koppe concluded that Ameren should have expected the 2007 boiler upgradé to eliminate all of the availability losses in the baseline period related to problems in the reheater, economizer, lower slopes, and air preheater components. Koppe Test., Tr. Vol. 3-A, 48:24-49:6, 66:5-12; see also Sahu Test., Tr. Vol. 5, 95:24-97:2.

226. Company documents and witnesses confirm that Ameren actually had such an expectation. Ameren expected that as a result of the 2007 boiler upgrade, availability losses attributable to the replaced components would be completely eliminated for years in the future. Meiners Test., Vol. 7-B, 40:1-18 (“Q. Right. If you do the project, in the future you won’t have those causes of unavailability, right? A. Correct.”); Boll. Test., Vol. 8-B, 46:11-47:10 (“that’s probably a good bet”); FOF 145,146,147.

227. Based on his review of company documents and data, as well as his experience in the industry and his assessment of the overall condition of the rest of the unit, Mr. Koppe concluded that Ameren should have expected that the 2007 boiler upgrade would result in a substantial increase in the overall equivalent availability of Rush Island Unit 1. Koppe Test., Tr. Vol. 3-A, 34:13-21, 51:20-55:17, 66:5-12. The impact of the project alone would be to increase the availability of Unit 1 by 3.8 percentage points over baseline availability by eliminating all 336.1 EFPH of availability losses related to the reheater, economizer, lower slopes, and air preheater. Koppe Test., Tr. Vol. 3-A, 48:24-49:6; see also Sahu Test., Tr. Vol. 5, 95:24-97:2. If the four components had not been replaced, the availability of the unit would have been expected to decrease. Koppe Test., Tr. Vol. 3-A, 66:13-67:3.

228. Similar projected increases can be found in Ameren’s availability forecasts. For example, the forecast for the 2006 Fuel Budget projected that Unit l’s long-term average availability would be 95.0% as a result of the “boiler improvements” done during the Unit 1 outage. This represents an increase of 7.5% over Unit l’s five-year pre-project average and about a 3% increase over .Ameren’s high baseline emissions period (a 3 percentage point improvement is the equivalent of about 10 more days of operation). Koppe Test., Tr. Vol. 3-A, 61:20-65:8; Meiners Test., Vol. 7-B, 39:16-25; September 23, 2005 Email (PI. Ex. 214); September 28, 2005 Email attaching Availability Worksheet (PI. Ex. 215), at Rush tab.

229. Ameren’s 2006 Fuel Budget forecast showed a 4.2 percentage point improvement in Unit l’s forced outage rate after the work. Def. Resp. to Interrogatory No. 68; Boll Test., Vol. 8-B, 42:19-44:1. Ameren’s Rule 30(b)(6) witness, David Boll, admitted in deposition testimony that the 4.2% improvement in the outage rate was “most probably due to the major outage” and could provide no other reason for the improvement. Boll Test., Tr. Vol. 8-B, 44:2-45:5; Boll Dep. Dec. 12, 2013, Tr. 122:13-123:2; Aug. 17, 2007 Email and Attached Spreadsheet (PI. Ex. 523), AM-02264672.

230. Similarly, Rush Island Plant Manager Robert Meiners gave a presentation *954 to Ameren senior executives in which he discussed the condition of the reheater, economizer, air preheater, and lower slopes on Rush Island Unit 1 and the efforts to replace those components. At the end of the presentation, Mr. Meiners presented a graph showing that Rush Island’s long-term availability would increase by almost 5 percentage points, from about 90% in 2005-2006 to 95% after both outages had been completed. Mr. Meiners admitted that even a one percent change in availability would be a significant change. Meiners Test., Tr. Vol. 7-A, 68:8-18; Tr. Vol. 7-B, 27:21-24, 28:10-20, 31:15-21, 33:4-6; Rush Island Business Plan Presentation (PI. Ex. 126), at AM-02625397.

231. Before the Unit 1 project had been approved, Ameren was not forecasting an increase in availability; instead its forecasts were that availability would remain flat—91%. That is because all of the other work done during the 2007 outage would maintain availability but would not cause an increase in availability. Koppe Test., Tr. Vol. 3-A, 65:13-66:4, 66:13-67:3.

232. Based on Mr. Koppe’s availability analysis, and consistent with his review of company data and documents, Dr. Sahu translated the increased operations that were expected to result from the 2007 boiler upgrade into emissions and determined that the expected S02 increase from such operations was far more than 40 tons per _ year. Sahu Test., Vol. 5, 39:23-25, 40:21-24, 102:7-10, 113:22-114:1. Specifically, Dr. Sahu calculated that Ameren should have expected a net emissions increase of 607.8 tons per year of S02 over the PSD baseline emissions as a result of the replacement of the economizer, reheat-er, lower slopes, and air preheater. Sahu Test., Tr. Vol. 5, 49:8-50:14, 57:15-59:5, 92:22-93:17; 115:17-20.

233. Even without counting the effects of derates and focusing just on the outages caused by the Components, the 2007 boiler upgrade would allow the unit to operate 246 more hours or about 10 more days per year by eliminating the outages associated with the reheater, economizer, lower slopes, and air preheaters. By itself, this would cause a more than 400 ton-per-year increase in emissions of S02. Koppe Test., Tr. Vol. 3-A, 49:12-23; Sahu Test., Vol. 5, 65:12-66:22.

2. Rush Island Unit 1 actual emission increases

234. Just as Ameren expected, Unit 1 experienced a substantial increase in availability following the 2007 boiler upgrade. In 2008, Rush Island Unit 1 had an equivalent availability of 96.77%. This was the highest equivalent availability of any unit in the entire Ameren system in 2008. Unit l’s equivalent availability in 2008 was higher than any 24-month period of equivalent availability since the Rush Island plant first began tracking availability data in 1982 and higher than any 12-month period since 1990. Anderson Test., Tr. Vol. 7-A 55:8-17, 56:22-58:2; Meiners Test., Tr. Vol. 7-B, 49:9-15, 55:18-23, 56:12-16; Strubberg Test., Tr. Vol. 8-A, 94:3-8, 95:1^4; Def. Resp. to RFA 299; Jan. 9, 2009 Email (PL Ex. 104), at AM-02272427 (“Rush Island 1 had the highest EAF [equivalent availability factor] at 96.77%”); see also Koppe Test., Tr. Vol. 3-A 67:4-69:3.

235. Rush Island Plant management received significant salary bonuses relating the Rush Island’s availability in the year 2008, whereas they had received no such bonuses for the year before. Strubberg Test., Vol. 8-A, 100:23-102:3; Def. Response to Interrogatory No. 65.

236. In April 2009, Rush Island Unit 1 set an “all-time record run for days on line,” breaking the “old plant record of 211 days [that] was set in 1990.” April 7, 2009 Email re: “Rush Island Unit 1 Record *955 Run” (PL Ex. 105), at AM-02276058; Strubberg Test., Tr. Vol. 8-A, 60:7-61:18 (admitting that Unit 1 had an equivalent availability of more than 98% during this period). Ameren Vice President Mark Birk specifically called out the replacement of the “reheater, economizer, and lower slopes” in 2007 as having “paid off’ when he reported Unit l’s record availability to Ameren’s CEO Warner Baxter. April 7, 2009 Email re: “Rush Island Unit 1 Record Run” (PI. Ex. 105), at AM-02276058; see also Koppe Test., Tr. Vol. 3-A 69:12-70:12.

237. The GADS data confirmed that the cause of the improved availability was the improved performance of the components at issue that were replaced as part of the 2007 boiler upgrade. As Ameren should have expected, and did expect, all of the availability losses due to problems in the reheater, economizer, lower slopes, and air preheater were eliminated after the 2007 boiler upgrade. As a result, component-related availability losses were reduced from 336.1 EFPH per year to zero. Availability losses due to everything else also decreased slightly. Koppe Test., Tr. Vol. 3-A, 70:17-71:2, 81:8-17; Sahu Test., Tr. Vol. 5, 64:8-21.

238. Further reflecting the actual performance improvements resulting from the 2007 boiler upgrade, Ameren’s reported GADS data farther show that Unit l’s equivalent availability actually increased over the baseline period by 4.3 percentage points, from 92.1% to 96.4% in the relevant post-project period. Id.; Sahu Test., Vol. 5, 64:24-65:3; Koppe Test., Tr. Vol. 3-A, 71:18-72:14.

239. None of the availability improvements that actually occurred at Unit 1 would have happened if the reheater, economizer, lower slopes, and air preheater had not been replaced. Koppe Test., Tr. Vol. 3-A, 66:13-67:3; Meiners Test., Vol. 7-B, 57:11-16.

240. Similarly, Ameren’s reported GADS data shows that Unit l’s operating time increased from 8,208 hours per year in the baseline to 8,568 hours per year during the highest post-project period of emissions, for an increase of 360 hours. This increase in operating hours included the effect of eliminating the 246 outage hours per year during the baseline period that were caused by problems associated with the reheater, economizer, lower slopes, and air preheater. Koppe Test., Tr. Vol. 3-A, 73:3-15; Sahu Test., Tr. Vol. 5, 65:12-66:22,109:7-13.

241. There is no question that these increased hours of operation were accompanied by more heat input. Annual heat input increased from 43,957,163 MMBtu per year in the baseline period to 45,442,-171 MMBtu per year in the relevant post-project period. Sahu Test., Vol. 5, 109:25-110:5.

242. Similar increases are shown in Ameren’s certified Continuous Emissions Monitoring System (“OEMS”) data, which show that Unit 1 operated more hours and emitted more pollution per hour during the relevant post-project period as compared to the baseline period. The OEMS data show that Unit l’s operating time increased by 320 hours per year, from 8,278 hours per year in the baseline to 8,598 hours per year in the applicable post-project period. Furthermore, when it was operating, Unit 1 emitted 21 more pounds per hour of S02 than it had in the baseline (increasing from 3,593 pounds per hour in the baseline to 3,614 pounds per hour in the post-project period). Knodel Test., Tr. Vol. 1-A, 109:7-16, 110:8-111:7, 112:14-24.

243. Ameren’s OEMS data also show that in 2008, the first calendar year after the 2007 boiler upgrade, Rush Island Unit 1 emitted more S02 than it had in any year since 1995. Knodel Test., .Tr. Vol. 1-A 82:9-19. During the relevant post-project *956 period, Unit 1 emitted 15,539 tons per year of S02, which is 665 tons per year more than Unit 1 actually emitted during the baseline period. Sahu Test., Tr. Vol. 5, 49:8-20, 111:7-16; Knodel Test., Tr. Vol. 1-A, 95:6-25.

244. Eliminating 246 outage hours by replacing the reheater, economizer, lower slopes, and air preheater, by itself, equates to S02 emissions of more than 400 tons per year. Sahu Test., Tr. Vol. 5, 41:3-7, 45:25-46:4, 65:12-66:22. Because all of the availability losses caused by the reheater, economizer, and air preheater in the baseline were eliminated (336 EFPH and 246 outage hours), (Koppe Test., Vol. 3-A, 67:7-73:19), it is clear that at least 40 tons of the overall 665 ton increase in actual emissions is related to the increased equivalent availability and additional operating hours enabled by the replacement of these components. Sahu Test., Tr. Vol. 5, 39:13-17, 64:6-66:22.

3. Results of projected emissions increase calculations based on the GADS data at Rush Island Unit 2

245. As described further below, Amer-en should have expected an increase of approximately 400 tons per year of S02 emissions over the PSD baseline emissions as a result of the availability improvements caused by the 2010 boiler upgrade.

246. The PSD “baseline” period used by Ameren for Unit 2 in this litigation was the highest 24-month period of emissions in the five years before the 2010 boiler upgrade, which was April 2005 through March 2007. During that period, Unit 2 emitted 14,287.7 tons per year of S02. Sahu Test., Tr. Vol. 5, 72:17-73:5; Knodel Test., Tr. Vol. 1-A, 91:4-17.

247. During this baseline period, problems in the economizer, reheater, and air preheaters caused Unit 2 to lose approximately 245 equivalent full power hours of availability per year. The unit was completely shut down in outages for 145.5 hours per year due to problems in the components at issue and lost the equivalent of another approximately 100 full power hours of operation due to deratings. Koppe Test., Tr. Vol. 3-A, 74:7-75-2; Sahu Test., Tr. Vol. 5, 78:20-79:19.

248. These problems reduced Unit 2’s equivalent availability during the baseline period by 2.8 percentage points. Sahu Test., Tr. Vol. 5, 119:6-17; Koppe Test., Tr. Vo. 3-A 76:17-22. According to the company’s GADS events data, Unit 2’s availability was 94.5% during the baseline. The average annual availability of Unit 2 over the entire five-year pre-project period was about 92%. Koppe Test., Vol. 3-A, 75:3-75:23, 76:17-22.

249. The problems associated with the Unit 2 reheater, economizer, and air pre-heaters caused about 50% of all the availability losses at Unit 2 during the baseline period. Koppe Test., Tr. Vol. 3-A, 75:3-11; Sahu Test., Tr. Vol. 5, 79:20-80:12.

250. Based on his analysis of Ameren’s operating data, including GADS, as well as other company documents, Mr. Koppe concluded that, just as at Unit 1, Ameren should have expected the 2010 boiler upgrade to eliminate all of the availability losses in the baseline period related to problems in the reheater, economizer, and air preheaters. Koppe Test., Vol. 3-A, 76:23-77:5.

251. As at Unit 1, based on his review of company documents and data, as well as his experience in the industry and his assessment of the overall condition of the rest of the unit, Mr. Koppe concluded that Ameren should have expected that the 2010 boiler upgrade would result in a substantial increase in the overall equivalent availability of Rush Island Unit 2. Koppe Test., Vol. 3-A, 34:7-21, 55:4-57:22, 73:25-74:2, 77:9-79:14, 84:4-13. The impact of the project alone would be to increase the *957 availability of Unit 2 by 2.8 percentage points over baseline availability by eliminating all 243 EPFH of availability losses related to the reheater, economizer, and air preheaters. Koppe Test., Vol. 3-A, 76:23-77:8.

252. Similar projected increases can be found in Ameren’s project documents and availability forecasts, which indicate that Ameren should have expected and did expect that Unit 2’s equivalent availability would be similar to what Unit 1 achieved after the 2007 boiler upgrade. Koppe Test., Tr. Vol. 3-A, 77:9-20; Meiners Test., Tr. Vol. 7-B, 50:14-51:2.

253. For instance, Ameren updated its financial justification for the Unit 2 outage in 2009, and included in that justification was the expectation that Unit 2’s availability would be as high as Unit l’s availability was in 2008—almost 97%. Koppe Test., Tr. Vol. 3-A, 77:21-78:19; Meiners Test., Tr. Vol. 7-B, 45:8-25, 48:4-49:5, 50:14-51:2; Unit 2 ELT Progress Report, (PL Ex. 110), at AM-02465690; Updated Financial Analysis (PI. Ex. 48), at “Data Entry” tab (row 155, col. F (and hidden comment: “4.3% gain related to outage work (u2 vs. ul)”). That would be a 4.3 percentage point improvement in equivalent availability over what Unit 2 had experienced in 2008, and would represent about 15 additional days of operation for Unit 2. Id.; Meiners Test., Vol. 7-B, 18:22-19:16 (the EAF input in the analysis was the equivalent of “15 days of generation”). 2 Mr. Meiners personally assured Ameren’s CEO Warner Baxter that inputs used in the updated financial analysis for the Unit 2 outage were accurate. Meiners Test., Tr. Vol. 7-B, 46:9-47:11; May 16, 2009 Email (PI. Ex. 347), at AM-02637756 (“I do believe the model is now a much more accurate representation of the economic benefits.”).

254. Unit l’s availability in 2008 was 96.77%. During the same year, Unit 2’s availability was 92.42%. RFAs 299 and 300; Anderson Test., Tr. Vol. 7-A, 55:8-17, 56:22-58:2; Meiners Test., Tr. Vol. 7-B, 49:9-20.

255. All or essentially all of the 4.2 percentage point improvement was related-to the components at issue. All of the other work done during the outage was done to keep the performance of the rest of the unit from getting worse but would not improve availability. Koppe Test., Vol. 3-A, 78:23-79:6; Koppe Test., Tr. Vol. 4-A, 99:22-100:2, 103:14-104:25; see also Mein-ers Test., Tr. Vol. 7-B, at 57:11-16 (none of the availability improvement would have occurred if the components at issue had not been replaced); February 6, 2007 Email (PL Ex. 103) (“In reality, until we have the economizer replacement, Unit 2’s forced outage is going to get worse, not better.”).

256. Ameren’s updated Full Work Order Authorization for the reheater and economizer replacements similarly indicated that Ameren expected the “boiler modifications [to] result in an improved operation of the unit that is at least equal to, if not better, than that currently expected with Unit 2 which had similar modifications in 2007.” The authorization quantified this amount as an expected “3-4% improvement in the equivalent availability of the unit.” October 15, 2009 Memo (Pl. Ex. 23), at AM-00926323; Birk Dep., Sept. 24, 2013, Tr. 194:1-195:13. Mr. Meiners confirmed that the availability input used for the justification was almost 97%. Meiners Test., Tr. Vol. 7-B, 50:14-51:2.

257. Ameren also should have expected Unit 2’s long-term average equivalent availability to increase from 92% to 95%. *958 Because there is a 2-3% variation in long-term forecasts, Ameren understood that Unit 2’s highest annual availability after the 2010 boiler upgrade would be 97-98%. Koppe Test., Tr. Vol. 3-A, 76:17-22, 79:7-14; Meiners Test., Tr. Vol. 7-B, 54:14-55:6; Hausman Test., Tr. Vol. 4-B, 65:9-19. Other forecasts done before the boiler upgrade also predicted greater than 95% as a long term availability after the Unit 2 outage. See Updated 2008 Fuel Budget forecast (PI. Ex. 252) (projecting 97% EAF for Unit 2 after outage); Meiners Test, Vol. 7-B, 51:18-52:7.

258. Based on Mr. Koppe’s availability analysis, and consistent with his review of company data and documents, Dr. Sahu translated the increased operations that were expected to result from the 2010 boiler upgrade into emissions increases, and determined that the expected S02 increase from such operations was far more than 40 tons per year. Sahu Test., Tr. Vol. 5, 39:23-25, 40:21-24, 78:13-19, 99:13-100:11, 102:7-10, 113:22-114:1. Specifically, Dr. Sahu calculated that Ameren should have expected a net emissions increase of 414.5 tons per year of S02 due solely to the improvements in equivalent availability that Ameren should have expected from the replacement of the economizer, reheat-er, and air preheater. Sahu Test., Tr. Vol. 5, 73:6-74:14,115:17-20.

4. Rush Island Unit 2 actual emission increases based on availability

259. Just as Ameren expected, Unit 2 experienced a substantial increase in availability following the 2010 boiler upgrade. During the relevant post-project period, as Ameren should have expected and did expect, there were no availability losses at all due to the reheater, economizer, and air preheater. Availability losses due to all the rest of the equipment at the unit essentially stayed the same. Koppe Test., Tr. Vol. 3-A, 80:7-23; Sahu Test., Tr. Vol. 5, 80:13-81:1, 82:13-83:5; see also PI. Ex. 746 (work paper showing no GADS events for reheat-er, economizer, and air preheater during post-project period).

260. Overall equivalent availability increased by 2.9 percentage points, from 94.5% in the baseline to 97.4% during the first 12 months after the 2010 boiler upgrade, the relevant post-project period in the case. Unit 2’s equivalent availability during this period was higher than any 24-month period in the history of the plant, going back to when Ameren first began tracking availability data in 1982, and higher than any 12-month period since 1987. Koppe Test., Tr. Vol. 3-A, 88:24-89:6; Anderson Test., Tr. Vol. 7-A, 58:3-9, 58:24-59:13; see also Sahu Test., Tr. Vol. 5,81:2-15; PL Ex. 746.

261. Ameren’s witness, Scott Anderson, referred to the increase in Unit 2’s availability before and after the 2010 outage as “night and day.” Anderson Test., Tr. Vol. 7-A, 58:7-9 (It is “obvious that the plant went way too long without a planned outage before correcting the problems that it had. I mean, it’s night and day.”). Amer-en had specifically called Mr. Anderson to discuss what the GADS data showed about the availability of the Rush Island units. Anderson Test., Tr. Vol. 7-A, 31:23-32:19.

262. None of the availability improvements at Unit 2 would have occurred if the reheater, economizer, and air preheater had not been replaced. Koppe Test., Tr. Vol. 3-A, 66:13-67:3; Meiners Dep., Tr. Vol. 7-B, 57:11-16.

263. According to Ameren’s GADS data, Unit 2’s operating time increased from 8,408 hours/year in the baseline period to 8,583 hours/year in the applicable post-project period, for an increase of 175 hours per year. This increase in operating hours included the effect of eliminating 146 outage

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