United States v. Missouri (229 F. Supp. 3d 906, 2017)

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

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

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 Protection 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 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 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.

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” 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 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 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 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 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 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 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 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; Presentation 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. 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:

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.

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).

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 reports that load was limited by the plug-gage that is at issue in this case.

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 producti