United States of America v. Ameren Missouri

Filing 852

MEMORANDUM OPINION AND ORDER: IT IS HEREBY ORDERED that Defendant Ameren Missouri is found liable under the Clean Air Act, 42 U.S.C. § 7401 et seq. IT IS FURTHER ORDERED that a status conference to address remedies is set for Wednesday, Februa ry 15, 2017 at 11:00 a.m. in courtroom 16-South. IT IS FURTHER ORDERED that the United States' Motion in Limine to Curtail Ameren's Re-Litigation of the Law of the Case # 757 is DENIED per my rulings above. IT IS FURTHER ORDERED that Amere n's Motion to Treat Certain KDHE Produced Documents as Highly Confidential During Trial # 778 is DENIED as moot. IT IS FURTHER ORDERED that Ameren's Motion to Bar Robert Koppe's New Causation Opinions # 787 is DENIED as moot. IT IS F URTHER ORDERED that Ameren's Motion to Bar Dr. Ranajit Sahu's New Opinions # 793 is DENIED as moot. IT IS FURTHER ORDERED that Ameren's Motion to Strike EPAs New Expert Opinion Evidence and Related Trial Exhibits # 832 is DENIED per my rulings above. IT IS FURTHER ORDERED that the Parties Joint Motion to Correct Clerks Exhibit List # 829 is GRANTED. Signed by District Judge Rodney W. Sippel on 1/23/17. (ARL)

UNITED STATES DISTRICT COURT
EASTERN DISTRICT OF MISSOURI
EASTERN DIVISION

UNITED STATES OF AMERICA,
Plaintiff,
vs.
AMEREN MISSOURI,
Defendant.

)
)
)
)
)
)
)
)
)

Case No. 4:11 CV 77 RWS

MEMORANDUM OPINION AND ORDER

“‘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 ...........................................................................................................................1
FINDINGS OF FACT......................................................................................................................6
I. BACKGROUND CONCERNING THE DEFENDANT, THE RUSH ISLAND PLANT,
AND THE APPLICABLE REGULATIONS ............................................................................. 6
A. The Defendant .................................................................................................................. 6
B. The Rush Island Coal-Fired Power Plant ......................................................................... 6
C. Facts Concerning General Applicability of the Prevention of Significant Deterioration
Program ................................................................................................................................... 7
D. Notice of the Violations Alleged in the Complaint .......................................................... 9
II. FACTS CONCERNING THE 2007 AND 2010 BOILER UPGRADES AT RUSH
ISLAND UNITS 1 AND 2 ........................................................................................................ 10
A. The Boiler Components at Issue and Their Role in Burning Coal to Generate
Electricity............................................................................................................................... 10
B. Operational Problems Leading up to the 2007 and 2010 Boiler Upgrades .................... 16
1.

Boiler tube leaks ......................................................................................................... 19

2.

Slagging and fouling ................................................................................................... 20

3.

Pluggage ..................................................................................................................... 22

4. Availability losses caused by the replaced components prior to the 2007 and 2010
outages as reported to the Generating Availability Data System ...................................... 32
5.

Reduction in the maximum capability of Unit 2 prior to the 2010 outage ................. 38

C. The Approval and Engineering Process for the 2007 and 2010 Major Modifications .. 41
D. Ameren Justified Replacing the Economizers, Reheaters, Lower Slopes, and Air
Preheaters Because They Would Improve Operations and Allow the Units to Generate
More......................................................................................................... …………………..45
E. Implementation of the 2007 and 2010 Major Modifications ......................................... 52
ii

F.

The Cost of the 2007 and 2010 Major Modifications .................................................... 57

III. THE 2007 AND 2010 BOILER UPGRADES EACH RESULTED IN A SIGNIFICANT
NET EMISSIONS INCREASE OF SO2 WITHIN THE MEANING OF THE PSD
REGULATIONS ....................................................................................................................... 58
A. Overview ........................................................................................................................ 59
B. GADS-Based Emissions Calculations for Rush Island Units 1 and 2 ........................... 61
1. Results of projected emissions increase calculations based on the GADS data at Rush
Island Unit 1 ....................................................................................................................... 71
2.

Rush Island Unit 1 actual emission increases ............................................................. 75

3. Results of projected emissions increase calculations based on the GADS data at Rush
Island Unit 2 ....................................................................................................................... 78
4.

Rush Island Unit 2 actual emission increases based on availability........................... 82

C. Emissions Increases Based on Unit 2 Capability Analyses ........................................... 84
1.

The expected capability and efficiency impact of the Unit 2 boiler upgrade ............. 85

2.

Actual increases in Unit 2’s capability ....................................................................... 89

3.

Dr. Sahu’s emission calculations based on Unit 2’s capacity increase ...................... 95

4. Nothing in Mr. Caudill’s opinions negates Mr. Koppe’s calculations of capability
increases ............................................................................................................................. 95
D. PROSYM-BASED EMISSIONS CALCULATIONS ................................................... 98
1.

Production cost modeling at Ameren ......................................................................... 98

2.

Dr. Hausman’s sensitivity analyses .......................................................................... 101
a.

Unit 1 sensitivity analysis ..................................................................................... 102

b.

Unit 2 sensitivity analysis ..................................................................................... 103
Dr. Hausman’s “with and without” analyses ............................................................ 103

3.
a.

Unit 1 analysis....................................................................................................... 105

b.

Unit 2 analysis....................................................................................................... 106

iii

IV. AMEREN HAS FAILED TO MEET ITS BURDEN TO ESTABLISH THE
APPLICABILITY OF THE DEMAND GROWTH EXCLUSION ....................................... 107
A. Background about the Market for Rush Island’s Generation ....................................... 107
B. Ameren’s Failure of Proof Regarding Demand Growth as a Cause of Increased
Emissions ............................................................................................................................. 111
V. AMEREN’S NSR EMISSION ANALYSES .................................................................. 114
A. Ameren Performed No Pre-Project NSR Analysis for Either Project .......................... 116
1.

Rush Island Unit 1 .................................................................................................... 116

2.

Rush Island Unit 2 .................................................................................................... 117

B. Ameren’s Post Hoc Reasonable Possibility Analysis is Substantively Flawed ........... 121
1. Ameren’s calculations fail to model all of the performance improvements expected
from the boiler upgrades .................................................................................................. 121
2.

Ameren’s capable of accommodating approach ....................................................... 122

3.

No analysis of relatedness ........................................................................................ 124

C. Nothing in Ms. Ringelstetter’s Analyses Excuses Ameren’s Failure to Perform
Appropriate NSR Projections .............................................................................................. 126
1.

Ms. Ringelstetter failed to address relatedness for either unit .................................. 126

2.

Ms. Ringelstetter’s Unit 1 analysis relies on faulty assumptions ............................. 128
a.

Background regarding ancillary services .............................................................. 128

b.

Ms. Ringelstetter’s modeling choice..................................................................... 131

VI. THE 2007 AND 2010 BOILER UPGRADES TRIGGERED TITLE V
REQUIREMENTS. ................................................................................................................. 132
CONCLUSIONS OF LAW .........................................................................................................132
I.

OVERVIEW .................................................................................................................... 132

II. THE UNITED STATES PROVED THAT AMEREN VIOLATED THE PREVENTION
OF SIGNIFICANT DETERIORATION AND TITLE V PROVISIONS OF THE CLEAN AIR
ACT ......................................................................................................................................... 133
iv

A. Undisputed Elements of Proof ..................................................................................... 133
B. The Projects Should Have Been Expected to Cause—and Did Cause—Emissions
Increases .............................................................................................................................. 134
1.

Legal standard........................................................................................................... 134

2. The evidence shows that Ameren should have expected an emissions increase related
to each project, and such an emissions increase occurred ............................................... 137
a. The Koppe-Sahu emissions calculations show a predicted increase at Unit 1 and
were confirmed by an actual increase .......................................................................... 138
b. The Koppe-Sahu emissions calculations show a predicted increase at Unit 2 and
were confirmed by an actual increase .......................................................................... 143
3. Dr. Hausman used Ameren’s modeling to quantify the emissions impact from the
projects ............................................................................................................................. 148
4. The evidence shows that efficiency improvements would not prevent emissions from
increasing as a result of the projects ................................................................................ 151
5. Conclusion: The emissions evidence shows an increase related to the projects should
have been expected and actually occurred ....................................................................... 154
C. Ameren Also Violated Title V ..................................................................................... 155
III. AMEREN’S DEFENSES AND CRITIQUES OF THE UNITED STATES’ EVIDENCE
FAIL ........................................................................................................................................ 156
A. The Projects were not Routine Maintenance................................................................ 156
1.

Legal standard........................................................................................................... 157

2. The boiler refurbishments at each Rush Island unit constitute one project for routine
maintenance purposes ...................................................................................................... 158
3.

The projects do not qualify for the routine maintenance exemption ........................ 160
a.
b.

Purpose.................................................................................................................. 161

c.

Frequency.............................................................................................................. 162

d.
4.

Nature and extent .................................................................................................. 160

Cost ....................................................................................................................... 163
Conclusion: the projects cannot be considered routine ............................................ 163
v

B. The Emissions Increases Cannot Be Set Aside Based on the Demand Growth
Exclusion. ............................................................................................................................ 164
1. Ameren’s experts confirm that demand was not projected to—and did not—cause the
pollution increases at Rush Island.................................................................................... 165
2. Ameren’s evidence does not address what portion of the units’ projected or actual
emissions increases were “unrelated” to the projects ...................................................... 166
3.

Ameren’s other demand growth arguments fail ....................................................... 169

4. Emissions resulting from operations that would not have been possible but for the
boiler upgrades cannot be considered “unrelated” to those boiler upgrades ................... 172
C. Ameren’s New Source Review Analyses Are Fatally Flawed and Cannot Provide Safe
Harbor from Liability .......................................................................................................... 176
1.

Ameren does not have a legitimate process for assessing PSD applicability ........... 176

2.

Unit 1 ........................................................................................................................ 179

3.

Unit 2 ........................................................................................................................ 181

EVIDENTIARY ISSUES FROM TRIAL ...................................................................................184
I.

AMEREN’S MOTIONS TO STRIKE TESTIMONY AND EVIDENCE ...................... 184
A. Ameren’s Motions to Strike Mr. Koppe and Dr. Sahu’s Testimony and Evidence
Concerning the Causation of Actual Emissions Increases .................................................. 184
B. Ameren’s Motion to Strike Dr. Hausman’s Testimony Criticizing Ms. Ringelstetter’s
Opinions............................................................................................................................... 187

II. THE UNITED STATES’ MOTION TO CURTAIL RE-LITIGATION OF THE LAW OF
THE CASE .............................................................................................................................. 187
CONCLUSION ............................................................................................................................188

vi

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 (“Ameren”) 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 (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).
1

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 (“SO2”), 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:
[O]ld plants [are treated] more leniently than new ones because of the expense of
retrofitting pollution-control equipment. But there is an expectation that old plants
will wear out and be replaced by new ones that will be subject to the more
stringent pollution controls that the Clean Air Act imposes on new plants. One
thing that stimulates replacement of an old plant is that aging produces more
frequent breakdowns and so reduces a plant's hours of operation and hence its
output.
2

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 SO2. The Rush Island plant currently
emits about 18,000 tons of SO2 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 SO2. 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 SO2.
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.
3

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 SO2
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 SO2 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
4

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 V provisions of the Clean Air Act.

5

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

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 (Pl. Ex. 297), at AUE00022523, 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 (“SO2”). The SO2 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 SO2.
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 SO2. 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, SO2 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
7

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 SO2. 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 SO2. 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 SO2. 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. § 7602(j). 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,

8

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)(i).
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 SO2 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

9

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, reheaters, lower slope panels, and air preheaters 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
10

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
superheating 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
11

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 (ECF. 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 has 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 reheaters’ 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 (Pl. 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, reheaters, 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
12

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 precipitator and then being sucked out by induced draft (“ID”) fans and sent up
the stack. During this process, the air preheater 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 preheater 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 preheaters were Ljungstrom regenerative air

preheaters. Specification No. EC-5491 (Pl. 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.
13

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-to-day 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; Vasel 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 83:515. 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.

14

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

15

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 (Pl. 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. Pl. 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 (Pl. 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 (Pl. 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
16

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 (Pl. Ex. 10), at AM-00080275; Project
Approval Package (Pl. 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 (Pl. 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 SO2 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
17

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. 237:9238:1; 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 (Pl. Ex. 798), at AUE00020397.
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 Ameren 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 preheaters. 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,
18

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, 7:168:20, 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 pluggage” and
noting boiler tube leaks at Unit 1), 590 (describing need for Unit 1 replacements following
switch to PRB coal); Project Approval Form (Pl. Ex. 2), at AM-00072829 (noting “tube leaks”
and “load reductions due to flyash pluggage” at Unit 2); Project Approval Package (Pl. Ex. 3), at
AM-00072831 & 837 (same statements for Unit 2); Project Approval Package (Pl. 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 (Pl. Ex. 45) at AM-0266037, 38 (noting derates due to “permanently plugged” air
preheaters); September 18, 2009 Memo (Pl. Ex. 26), at AM-00954160 (Unit 2 air preheaters
“have continued to foul”); October 15, 2009 Memo (Pl. Ex. 23), at AM-00926322-323
(describing problems in Unit 2 reheater and economizer following switch to PRB coal);
Specification No. EC-5491 (Pl. Ex. 10), at AM-00080276-279 (describing problems in Unit 1
and 2 boiler components); Presentation re: Justification for Projects (Pl. Ex. 28), at AM00966724-725, 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.

19

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 (Pl. Ex. 3), at AM-00072837; see also id. at AM00072831 (noting problems that were “causing tube leaks” in the lower slopes and that “[t]here
have been tube leaks in the economizer sections and reheater pendants”); Project Approval
Package (Pl. 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 megawatthours 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
20

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 (Pl. 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. Pl.
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; Pl. Ex. 28, at
AM-00966745; Project Approval Package (Pl. 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.
21

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. 1B, 103:24 - 104:4, 104:16 - 104:22. Ash also accumulates on the air preheater surfaces,
restricting flue gas flow through the air preheaters and reducing the unit’s output. Stevens Test.,
Tr. Vol. 2-A 59:7 - 60:22; July 15, 2005 Email (Pl. Ex. 45), at AM-0266037, 38; September 18,
2009 Memo (Pl. Ex. 26), at AM-000954160; Koppe Test., Tr. Vol. 3-A, 14:11-14:15, 17:517:11.
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 AM00072585 (“The switch to 100% PRB coals has caused flyash pluggage in the reheater and
economizer. The pluggage in the existing staggered economizer has caused load reductions.”);
Rush Island Resurfacing Study (Pl. 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 (Pl. 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 pluggage 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 preheaters,

22

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 reheater 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 reheaters 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 pluggage occurred in certain areas of the reheater 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 Dep., Nov. 5, 2013, Tr. 162:7-19, 174:923

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 preheaters. 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 AM000954160 (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 pluggage 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.

24

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,
25

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, Pl. 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 (Pl. 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 Ameren executives). For instance, the 2008 State of
the System report included a graphical representation of the high differential pressure problems
caused by pluggage, 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 Pl. Ex. 15, at AM-00196909-10:

26

27

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. Pl. Ex. 15, at AM00196909. 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. Pl. Ex. 15, at AM-00196910. Koppe Test., Tr. Vol. 3-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. 3-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
throughout 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. 3-A 25:22-27:17 (discussing Koppe
demonstrative 6).

28

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 (Pl. 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.

Plaintiff’s 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 Pl. 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
29

way to indicate in the narrative description of the load test reports that load was limited by the
pluggage 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 (Pl. Ex. 15), at AM-00196900.
82.

Ameren trial witness David Strubberg conceded that the reported Unit 1 losses

were smaller due to the replacement of the air preheaters. Strubberg Test., Tr. Vol. 8-A, 80:1281:22 (discussing excerpt of presentation in Pl. 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, 90:1191:10.
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
1

See Pl. Ex. 928, at Cell O.2 (“FD Fan Capacity”), W.2 (“ID FAN SUCT PS”),
Y.2 (“ID Fan suction press”); AJ.2 (“ECON PLUGGAGE ID FAN SUCT). AK.2 (“Due to
pluggage in boiler, it limits ID fan suction pressure”); AL.2 (“limited by the ID fan suction
pressure…Boiler is plugged”); AO.2 (“ID suction Supht [sic] plugged Econ plugged”); AP.2
(“ID Fan Suction (Plugged Boiler)”); AQ.2 (“ID Fan Suction (Plugged Boiler)”), BD.2 (“02 blr
pluggage”), BF.2 (“FD FANS”); BV.2 (“APH Pluggage”), BW.2 (“APH Pluggage”), BX.2
(“APH Pluggage”), BY.2 (“APH Pluggage”), BZ.2 (“ID Fan Suction Pressure”), CA.2 (“ID FAC
SUCTION PRESS.”), CC.2 (“ID Fan Suction”); CE.2 (“Blr Pluggage”), CH.2 (“APH Pluggage),
CI.2 (“Suction Press.”), CJ.2 (“APH Pluggage”), CK.2 (“APH Pluggage”), CN.2 (“ID Fan
Suction Pressure”), CO.2 (“APH Pluggage”), CP.2 (“ID suc press Blr & APH’s plugged”), CQ.2
(“APH Pluggage”), CR.2 (“ID FAN SUCT”), CS.2 (“APH Pluggage”), CT.2 (“Aph Pluggage”),
CU.2 (“APH Pluggage”), CV.2 (“ID fan suction pressure”).
30

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 preheater
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
preheater 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 bypass 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 (Pl. Ex. 934), at AM-00015890-MDNR. When shown the document at trial, Ameren
31

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 (Pl. 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 (Pl. 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.
32

90.

Plaintiff’s 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 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

33

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. 7A 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 (ECF No. 823); Moore Rule 30(b)(6) Dep., Sept. 16, 2014, 123:12-124:15;
February 6, 2007 Email (Pl. 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 (Pl. Ex. 930), at AM-02583221.

34

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 figures are compiled and
easily accessible in the NERC/GADS reporting program.” June 25, 2002 Email (Pl. 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, (Pl. Ex.
331), at AM-00491836. The company’s financial model for justifying projects based on their
35

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 (Pl. 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 Ameren 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
36

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 78:20-79:13.
109.

The deratings experienced at Units 1 and 2 were not short-term or one-time

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 derates 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; 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
(Pl. 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.

37

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 (Pl. 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 (Pl. 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 (Pl.
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, 84:2385:2. The magnitude of a reported derating is affected by the reported capability. Id. 85:3-10;
see December 2010 Capability Table (Pl. Ex. 257), at AM-00067232.

38

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 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 pluggage.

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 Ameren 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.
39

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, Ameren 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 AM00196628.
122.

Ameren assigned 22.5 megawatts to the reheater, economizer, and air preheater 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. 340

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 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 (Pl. 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
41

more than $25 million. Stevens Test., Tr. Vol. 2-A 5:2-7; December 20, 2004 Generating
Engineering Budget Project Proposal (Pl. 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, reheater, lower
slope tubes and air preheaters were coordinated by Alstom Power and generally treated together
within the Project Book. Rush Island Unit 1 Project Book (Pl. 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 preheaters

were all approved under Ameren’s Work Order Procedures. Stevens Test., Tr. Vol. 1-B 72:1521, 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
42

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 preheater.”).
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 (Pl.
Ex. 1), at AM-00072590; Project Approval Package (Pl. 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. EC5491 (Pl. 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, 45:1446:25, 55:9-56:4, 66:5-67:9; October 15, 2009 Memo (Pl. 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
43

10 layers of approval review. Stevens Test., Tr. Vol. 2-A 7:5-15, 13:15-22; Project Approval
Package (Pl. Ex. 1), at AM-00072580; Project Approval Form (Pl. Ex. 2), at AM-00072829;
Project Approval Package (Pl. Ex. 4), at AM-00072850; Project Approval (Pl. Ex. 5), at AM00072906.
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 (Pl. Ex. 1), at AM00072580. 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 (Pl. Ex. 4), at AM-00072850;
Project Approval (Pl. 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, 46:647:11; May 16, 2009 Email (Pl. Ex. 347), at AM-02637756. On August 14, 2009, Mr. Baxter
reported that the outage had been approved. August 14, 2009 Email (Pl. Ex. 553), at AM02480812.

44

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 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. Vol. 2-A, 8:21- 9:6; Project Approval
Package (Pl. Ex. 1), at AM-00072580; Project Approval Package (Pl. 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. 73:1274:11.
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 (Pl. 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.

45

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 (Pl. Ex. 10), at AM-00080325329; Presentation re: Justification for Projects (Pl. 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 reheaters without plugging or
fouling. Stevens Test., Tr. Vol. 2-A 45:14 - 46:25; October 15, 2009 Memo (Pl. Ex. 23), at AM00926322; Specification No. EC-5491 (Pl. 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 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
46

the lower slope tubes stiffer, 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 preheaters 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 AM00080279, 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, 27:1323, 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
47

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 AM0954160 (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 derates and outages due to boiler tube leaks); see also
Vasel 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 (Pl. Ex.
895), at AM-02632840; Meiners Test., Tr. Vol. 7B, 34:9-35:25.
48

149.

Further evidence of Ameren’s expectation of availability improvements is found

in Plaintiff’s 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 reheaters, 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, “[b]asically that’s what Ameren expected” based on
a review of Ameren’s project justifications. Caudill Test., Tr. Vol. 10-B, 36:10-37:2, 37:1738:10.

49

153.

Mr. Caudill also agreed that pluggage 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, 34:1735:1, 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. Caudill conceded
that Ameren did not justify the replacement of the economizers, reheaters, and air preheaters
based on any expectation that they would result in an improvement in gross unit efficiency.
Caudill 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 pluggage 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 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.
50

October 15, 2009 Memo (Pl. 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 preheater.”); 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 (Pl. 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 (Pl. 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; Pl. Ex. 48, at “Data Entry” Sheet; July 2009 ELT
Progress Report (Pl. 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
51

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
(Pl. 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 economic 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 (Pl. 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 (Pl. Ex. 63), at AUE-00156343; Overhead Photo of Laydown Areas (Pl. 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.

52

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 (Pl. Ex. 10), at AM-00080233; Rush Island Project Book (Pl. Ex.
63), at AUE-00156362. Ameren’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 (Pl. 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

53

own staff. Stevens Test., Tr. Vol. 2-A, 21:18 – 22: 18; 2007 Post Outage Report (Pl. Ex. 34), at
AM-02252259, 260; 2010 Post Outage Report (Pl. 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 Manitowoc
222 and 2250 cranes. Stevens Test., Tr. Vol. 2-A, 18:14-19:19; 48:12-20; 2007 Post Outage
Report (Pl. Ex. 34), at AM-0225210; 2010 Post Outage Report (Pl. 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
54

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 (Pl. 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 (Pl. 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 (Pl. Ex. 6), at AM-00072912; Project
Approval Package (Pl. Ex. 1), at AM-00072591; Project Approval Package (Pl. Ex. 3), at AM00072838; 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 (Pl. 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
55

outage was similarly referred to as “among the most significant in [company] history.” Jerry
Odehnal Report (Pl. Ex. 40); see Vasel Dep., Aug. 15, 2013, Tr. 272:2-23 (describing exhibit
40); see also 2010 State of the System presentation , Pl. Ex. 41, at AM-02493747 (distinguishing
the air preheater, reheater and economizer replacements from the “routine maintenance” done
during the 2010 outage).
173.

By the time of their replacements in 2007 and 2010, the reheaters, economizers,

and air preheaters were more than 30 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 (Pl. Ex. 6), at AM-00072912 (“units have operated for nearly 30 years without replacing
any of the major components”); Unit 2 ELT Progress Report (Pl. 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 (Pl. Ex. 456), at AM00953927.
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. Ameren’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.

56

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 coalfired 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.

57

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, 89:2390:3.
180.

A capital project is one that would improve the value of the asset. Stevens Test.,

Tr. Vol. 1-B, 91:1-10.
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 SO2 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) SO2 increase; or (2) a
40 tons-per-year SO2 increase related to the boiler upgrades actually occurred. Ameren SJ
Decision; see also 40 C.F.R. § 52.21(a)(2)(iv)(b), (c).
185.

As described further below, Ameren should have expected the 2007 and 2010

boiler upgrades to increase the availability of the units, thereby resulting in more than 40 tons per
58

year of increased SO2 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. Hausman,
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 SO2. After a brief overview, the specific evidence supporting a finding that the
2007 and 2010 boiler upgrades resulted in significant SO2 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 costeffective units in a large and interconnected electricity supply system that is vastly larger than
59

any individual unit, it was not a lack of demand that was holding the units back prior to the 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 SO2 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 SO2 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 SO2. Sahu Test., Vol. 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 SO2. 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 SO2 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 SO2 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 SO2).
60

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.

Plaintiff’s 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.”)
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, reheaters, 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
61

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; 75:311. “[P]roblems 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
62

Test., Vol. 3-A, 34:13-21, 51:20-57:17; see also GADS Events Data (Pl. Ex. 925), 2007 and
2010 Outage Reports (Pl. Ex. 34 and 46), Condition Assessments (Pl. 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. 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
63

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. 4B, 39:16–40:4; see also id. at 36:12–21. Dr. Hausman 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.

64

203.

The data also shows a relationship between unit availability and SO2 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 36:2237:1.

65

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, 50:313 (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 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, 51:553:16, 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

66

57:15-58:21; September 9, 2006 Email and attached critical review spreadsheet (Pl. 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
Ringelstetter’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
67

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 (Pl. Ex. 250), at Spreadsheet
Tab “Instructions.” The 1985 EPRI study provides a similar formula. See Economic Evaluation
of Plant-upgrading Investments (Pl. 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 (Pl. Ex. 250), at Spreadsheet Tab “Instructions.”
211.

Dr. Sahu’s emission calculations also used the same SO2 emission factor 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
(Pl. 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. Caudill Test., Tr. Vol. Vol. 10-B, 44:2445:12; 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
68

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 SO2 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 SO2 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 149152, col. D (and comment box) (showing that Ameren did not include efficiency benefit inputs
for “decrease in fuel usage”)), Pl. Ex. 110, at AM-02465690; Koppe Test., Vol. 3-B, at 29:932:9. 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
69

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.
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 SO2 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 SO2 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 SO2 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.

70

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 “wellknown 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, Ameren should have expected an increase of at least

600 tons per year of SO2 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 SO2. 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,
71

which is roughly equivalent to 14 days of operation per year. Koppe Test., Tr. Vol. 3-A, 45:1546:24. 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 reheater,

economizer, air preheater, and lower slopes caused about 50% of all the availability 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 1’s availability during the baseline period by 3.8

percentage points. Sahu Test., Tr. Vol. 5, 63:11-64:5. Unit 1’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 upgrade 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.

72

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 1’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 1’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 (Pl. Ex. 214);
September 28, 2005 Email attaching Availability Worksheet (Pl. Ex. 215), at Rush tab.
229.

Ameren’s 2006 Fuel Budget forecast showed a 4.2 percentage point improvement

in Unit 1’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
73

Dep. Dec. 12, 2013, Tr. 122:13-123:2; Aug. 17, 2007 Email and Attached Spreadsheet (Pl. Ex.
523), AM-02264672.
230.

Similarly, Rush Island Plant Manager Robert Meiners gave a presentation 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 longterm 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 (Pl. 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 SO2 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 SO2 over the PSD baseline emissions as a result
of the replacement of the economizer, reheater, 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.
74

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 tonper-year increase in emissions of SO2. 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 1’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, 56:2258:2; 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 Run” (Pl. Ex. 105), at AM-02276058; Strubberg Test., Tr. Vol. 8-A,
75

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 1’s
record availability to Ameren’s CEO Warner Baxter. April 7, 2009 Email re: “Rush Island Unit
1 Record Run” (Pl. 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 further show that Unit 1’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 1’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
76

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 (“CEMS”) 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 CEMS data show that Unit 1’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 SO2 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 CEMS data also show that in 2008, the first calendar year after the

2007 boiler upgrade, Rush Island Unit 1 emitted more SO2 than it had in any year since 1995.
Knodel Test., Tr. Vol. 1-A 82:9-19. During the relevant post-project period, Unit 1 emitted
15,539 tons per year of SO2, 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 SO2 emissions of more than 400 tons per year. Sahu Test.,
77

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, Ameren should have expected an increase of

approximately 400 tons per year of SO2 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 SO2. 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
78

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 preproject 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 preheaters

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 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.
79

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 1’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 (Pl. Ex. 48), at “Data Entry” tab (row
155, col. F (and hidden comment: “4.3% gain related to outage work (u2 vs. u1)”). 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 (Pl. Ex. 347), at AM-02637756 (“I do believe the
model is now a much more accurate representation of the economic benefits.”).
254.

Unit 1’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 Meiners Test., Tr. Vol. 7-B, at 57:11-16 (none of the availability improvement would have
2

As discussed above, the final EAF input was adjusted downward by 0.1%, from 4.3% to
4.2%, as result of eliminating the lower slope replacement from the final scope of the project.
FOF 148.
80

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%. 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 (Pl. 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
SO2 increase from such operations was far more than 40 tons per year. Sahu Test., Tr. Vol. 5,
81

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
SO2 due solely to the improvements in equivalent availability that Ameren should have expected
from the replacement of the economizer, reheater, and air preheater. Sahu Test., Tr. Vol. 5, 73:674:14, 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, 80:1381:1, 82:13-83:5; see also Pl. Ex. 746 (work paper showing no GADS events for reheater,
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 postproject 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
82

problems that it had. I mean, it’s night and day.”). Ameren 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, 66:1367:3; 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 hours per year in the baseline period caused by problems associated with
the reheater, economizer, and air preheater. Sahu Test., Vol. 5, 83:8-22, 112:6-11, 158:3-8;
Koppe Test., Vol. 3-A, 83:20-84:3; see also Koppe Test., Tr. Vol. 4-A, 115:18-25 (If “half of all
the outage time that’s occurring is eliminated by the projects and the effect of all the other
equipment in the unit stays the same, … then the availability of the unit as a whole increases, and
it increases specifically because the projects have eliminated boiler tube leaks in these sections
and have eliminated the effects of pluggage.”).
264.

There is no question that these increased hours of operation were accompanied by

more heat input. Annual heat input increased from 42,326,578 MMBtu per year in the baseline
period to 47,660,058 MMBtu per year in the post-project period. Sahu Test., Tr. Vol. 5, 112:1720.
265.

Similar increases are shown in Ameren’s certified CEMS data, which show that

Unit 2 operated more hours and emitted more pollution per hour during the relevant post-project
period as compared to the baseline period. The CEMS data show that Unit 2’s operating time
83

increased by 123 hours per year, from 8,478 hours per year in the baseline to 8,601 hours per
year in the applicable post-project period. Furthermore, when it was operating, Unit 2 emitted
456 more pounds per hour of SO2 than it had in the baseline (increasing from 3,371 pounds per
hour in the baseline to 3,827 pounds per hour in the post-project period). Knodel Test., Tr. Vol.
1-A, 109:7-16, 111:8-20, 112:3-10, 113:1-21.
266.

Ameren’s CEMS data also show that in 2011, the first calendar year after the

2010 boiler upgrade, Rush Island Unit 2 emitted more SO2 than it had in any year since 1995.
Knodel Test., Tr. Vol. I-A 82:9-19. During the applicable period of highest post-project
emissions, Unit 2 emitted 16,458.1 tons per year of SO2, which is 2,171 tons per year more than
Unit 2 actually emitted during the baseline period. Sahu Test., Tr. Vol. 5, 74:15-18, 78:9-12,
112:25-113:3; Knodel Test., Tr. Vol. 1-A, 97:11-98:5.
267.

Because all of the availability losses and outage hours caused by the reheater,

economizer, and air preheater in the baseline were eliminated (243 EFPH and 146 outage hours),
and it only takes an additional 21 hours of operation for Rush Island Unit 2 to emit 40 tons of
SO2, at least 40 tons of the overall increase in emissions at Unit 2 are related to the increased
equivalent availability and operating hours enabled by the replacement of these components.
Sahu Test., Tr. Vol. 5, 80:13-84:4, 115:10-116:4, 165:15-25.
C. Emissions Increases Based on Unit 2 Capability Analyses
268.

In addition to improving the availability of both units, the 2010 boiler upgrade

should have been expected to increase the capability of Rush Island Unit 2. As described further
below, because Unit 1 experienced a capability increase after the 2007 boiler upgrade, Ameren
should have expected – and did expect – a similar increase to occur after the 2010 boiler upgrade
at Unit 2. Koppe Test., Tr. Vol. 3-B, 19:20-25.
84

1.

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

269.

In October 2007, Ameren engineers noted that Unit 1 had experienced an increase

in capability due to the boiler component replacements, and Rush Island Supervising Engineer
Gregory Vasel asked the Plant’s Performance Engineer James Bosch to quantify that increase: “I
looked at the 2006 [project justification] for the U2 economizer, reheater, and lower slope, and it
projects no increase in capacity. I asked Mr. Bosch to quantify the capacity increase we’ve
realized on U1, as well as the aux power reduction we’re seeing with running one of our ID fans
in low speed. … I communicated this to Leo Reid, who is working on the [project justification]
for Bob Schweppe.” Vasel Email (Pl. Ex. 130), at AM-02635983 (emphasis in original); Koppe
Test., Tr. Vol. 3-B, 12:17-13:4.
270.

Mr. Bosch reviewed full load tests from before and after the Unit 1 outage and

determined that there had been a 19 MW increase in Unit 1’s gross capability (from 611 MW to
630 MW). Pl. Ex. 130, at AM-02635983. Ameren project engineer Leo Reid incorporated a
“16MW increase in generating capacity” into an updated financial analysis for the Unit 2 project.
Id. at AM-02635982. In assessing what caused the capacity increase, Mr. Vasel instructed Mr.
Bosch to look at the “delta P reductions of the [air preheater] vs. ([reheater] + economizer) …”
Id. at AM-02635981. The updated financial analysis was provided by Mr. Vasel to Ameren’s
Director of Power Operations Robert Meiners, and was described as the “best information” that
the plant had at the time. Id.
271.

Mr. Koppe reviewed Ameren’s full load tests and Plant Information data (“PI

data”) for Unit 1 and confirmed Mr. Bosch’s analysis showing a 19 megawatt increase in
capability had occurred at Unit 1. Mr. Koppe also reviewed the Plant Information data and other
company documents and confirmed that there was a “dramatic drop” in the differential pressures
85

in the air preheater and economizer after the Unit 1 boiler upgrade. For example, a graph
presented in Ameren’s 2008 State of the System meeting indicates a “tremendous reduction” in
the air preheater delta P from 14 to 5 inches of water. An air preheater delta P of 14 inches is
“extremely high,” and a reduction to 5 inches shows that Unit 1’s capability was no longer
limited by the effects of pluggage. Koppe Test., Vol. 3-A, 22:13-25:4; Vol. 3-B, 13:5-23; 2008
State of the System, Pl. Ex. 15, at AM-00196909; see also Sind Test., Vol. 9-B, 26:16-18 (air
preheater differential pressures above 11 inches are “extremely high”); Cardinale Dep., July 31,
2014, Tr. 84:3-21; see FOF 75, 76 (showing graphs).
272.

Ameren subsequently increased Unit 1’s capability rating to 630 MW gross. Mr.

Bosch reported the results of his quantification of a 19 MW increase in an email dated November
1, 2007. Vasel Email (Plaintiff’s Exhibit 130), at AM-02635983. The document officially
revising the 2008 capability stated that the increase was based on plant staff’s request to reflect
performance improvements following the spring 2007 outage during which the reheater,
economizer, and air preheaters were replaced. Shelton Test., Tr. Vol. 10-A, 89:10-23.
273.

In February 2008, Rush Island Plant Manager David Strubberg gave a

presentation at a State of the System meeting in which he discussed the “Future Priorities” for
Rush Island. Among the priorities discussed by Mr. Strubberg was a “25-30 MW” capability
increase expected as a result of the boiler component and air preheater replacements and a
separate 13 MW capability increase expected due to the replacement of the LP turbine. 2008
State of the System (Pl. Ex. 15), at AM-00196628; Koppe Test., Vol. 3-B, at 24:2-25:2.
274.

A few months later, in June 2008, Rush Island Superintendent of Operations

Andrew Williamson was asked by Ameren’s Dispatch Coordinator Steve Schoolcraft to estimate
the predicted capability of Unit 2 following the outage. Mr. Williamson noted: “We did
86

experience a substantial increase on Rush 1 due to increased boiler performance with the new
RH/Econ/APHs and should reasonably expect the same for Rush 2.” June 2008 Email (Pl. Ex.
267), at AM-02660313. Mr. Williamson predicted that Unit 2’s capability would be 625 MW
(net), which is about 655 MW (gross), after the outage. Of this, Mr. Williamson predicted that
the boiler component replacements at issue, alone, would increase Unit 2’s capability to 615 MW
(net), or roughly 645 MW (gross), and replacement of the low pressure turbine would add
another 12-15 MW. Id. at AM-02660307-08; Koppe Test., Tr. Vol. 3-B, 25:3-26:11; Williamson
Test., Tr. Vol. 9-B, 40:10-41:2, 41:7-42:1.
275.

Later in 2008, Mr. Williamson’s prediction that Unit 2 would be able to achieve

625 MW (net) after the work was incorporated into Ameren’s 10-Year System Plan, and
represented an increase of 44 MW over the capability of Unit 2 at the time. This was the only
increase in capability across the entire Ameren system noted in the 10-Year Plan. 10 Year Plan
Spreadsheet (Pl. Ex. 251), at “UE” tab (hidden comment to row 20, col. F: “Rush Island unit 2
net output is increased from 581 to 625 (44 MW increase) provided by Steve Schoolcraft”), and
“UE Changes” tab (row 54: “Rush Island 2’s net output were changed to 625 MW per the plant’s
request …”); Koppe Test., Tr. Vol. 3-B, 26:16-27:6.
276.

As described above, in 2009, Ameren completed an updated financial analysis for

the Unit 2 outage. In addition to improvements in equivalent availability, Ameren’s updated
analysis included a 22.5 MW “projected annual increase … in plant capacity” as a result of the
replacement of the reheater, economizer, and air preheater. Financial Analysis for Unit 2 (Pl. Ex.
48), at “Data Entry” Sheet, row 147, col. B & E; Koppe Test., Tr. Vol. 3-B, 28:2-12, 30:4-32:23.
277.

The capacity increase input in the financial analysis was based on Ameren’s

estimate that replacing the economizer, reheater, and air preheater would allow Unit 2 to produce
87

30 more MW of capacity during the summer and 20 more MW for the rest of the year. The
capability benefits were based on the combined effect of all three component replacements, and
represented an increase over what Unit 2 was able to achieve during the pre-project period.
Koppe Test., Tr. Vol. 3-B, at 27:7-32:23; Pl. Ex. 48, at “Data Entry” Sheet, row 147, col. B & E
(formula bar: 0.25*30 + 0.75*20); July 2009 ELT Progress Report (Pl. Ex. 110), at AM02465690 (“30MW gain in summer (3 mos), 20MW gain balance of year from Reheater,
Economizer and APH investment”), Pl. Ex. 347, at AM-02637758 (same), June 15, 2009 CPOC
Email (Pl. Ex. 895), at AM-02632842 (same).
278.

In the Fall of 2009, Ameren also completed updated Full Work Order

Authorizations for the replacement of the reheater, economizer, and air preheater. Consistent
with previous projections, Ameren engineers described that 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.” October 15, 2009 Memo (Pl. Ex. 23), at AM-00926323; September 18, 2009
Memo (Pl. Ex. 26), at AM-00954160. Similar statements were made in other Ameren
documents. See, e.g., Pl. Ex. 893, at AM-02229417 (“Approximately 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.”).
279.

Based on his review of Ameren’s documents and data, Mr. Koppe confirmed that

Ameren should have expected, and did expect, an increase in Unit 2’s capability of at least 22
MW (gross) as a result of replacing the economizer, reheater, and air preheater. That additional
capability would result from eliminating the effects of pluggage and allow Unit 2 to burn more
coal per hour. Koppe Test., Vol. 3-B, 33:14-34:1; see also Vol. 3-A, 27:18-25, 29:2-8, Vol. 4-A,
46:23-47:18.
88

280.

Ameren should not have expected any sustainable change in gross efficiency as a

result of the reheater, economizer, and air preheater replacements. There was no expected
efficiency benefits used as an input in the original Unit 2 project justification. The updated
project justification included a 0.5% reduction in auxiliary load for the economizer and air
preheater replacements, which equates to about 3 MW of net capability. The 3 MW reduction in
auxiliary load would improve net efficiency, not gross efficiency, and would not be expected to
change the full load heat input of Unit 2. FOF 117. Ameren did not project any decrease in fuel
usage as a result of any efficiency changes associated with the component replacements. Koppe
Test., Vol. 3-A, 5:13-20, Vol. 3-B, 28:13-29:8, Ex. 110, at AM-02465690 Pl. Ex. 48, at “Data
Entry” sheet, at rows 149-152 (no decrease in fuel usage input for auxiliary load reductions).
281.

Ameren’s best expectation for the effect of the LP turbine on unit efficiency is

that it would increase Unit 2’s capability by 12 MW, which is the amount that was guaranteed by
the vendor. Sind Test., Vol. 9-B, 20:3-12, 26:23-28:3. Ameren’s updated financial analysis for
the Unit 2 outage estimated that the efficiency improvements associated with the LP turbine
would allow Unit 2 to produce 15 more MW of capability. The 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 less coal. Pl. Ex. 48, at “Data Entry” sheet,
rows 149-152 (no “decrease in fuel usage” input for turbine replacement) Pl. Ex. 110, at AM02465690; Koppe Test., Vol. 3-B, at 29:9-32:9.
2.

Actual increases in Unit 2’s capability

282.

Consistent with the results achieved after the Unit 1 project, there was a big

improvement in Unit 2 in the air preheater differential as a result of the air preheater
replacements, where the differential pressure went from about 15 inches of water to about 5
89

inches. Koppe Test., Tr. Vol. 3-A, 25:22-27:17; Sind Test., Tr. Vol. 9-B, 25:6-26:2 (Mr. Sind’s
capacity analysis showed a big decrease in air preheater differential pressure from 13-14 inches
to less than 6 inches); Williamson Test., Tr. Vol. 9-B, 44:7-14 (differential pressure of 15 inches
indicates “high pluggage”).
283.

The improvement in the air preheater differential pressure, along with

improvements in the other limitations (economizer differential pressure and ID fan suction
pressure), meant that Unit 2’s capability and ability to burn coal was no longer limited by
pluggage after the Unit 2 boiler upgrade. Koppe Test., Tr. Vol. 3-A, 27:18-25, 28:7-14, 29:2-8.
During the PSD baseline period, when the unit was experiencing extensive pluggage, the average
full load capability of Rush Island Unit 2 was only 620 gross megawatts. FOF 120; Koppe Test.,
Tr. Vol. 3-B, 35:17-36:4, 45:12-46:5; PX 928 (Rule 1006 summary of full load tests for Unit 2).
284.

The increase in capability at Unit 2 was evident as soon as the unit returned to

service after the 2010 outage. For example, on May 29, 2010, Ameren conducted a Full Load
Test in which Unit 2’s gross capability was measured to be 655 MW, exactly as Mr. Williamson
had predicted in 2008. Compare May 29, 2010 Full Load Test (Pl. Ex. 236) (655.13 gross
megawatts), with June 2008 Email (Pl. Ex. 267), at AM-02660307-08 (predicting 625 net
megawatt); Williamson Test., Tr. Vol. 9-B 41:14-16 (confirming that 625 net megawatts equates
to 655 gross megawatts); see also Sind Test., Tr. Vol. 9-B, 29:19-30:16. A full load test
conducted in October 2010, after the unit had been in service for several months following the
boiler upgrade, showed even higher capability. The gross capability measured during that test
was 664 MW. October 19, 2020 Full Load Test (Pl. Ex. 913). No capability limitations were
noted by plant engineers in either test report.

90

285.

Similarly, in October 2010, Ameren performed a test to verify that the new

reheater, economizer, and air preheater had satisfied their performance guarantees. Unit 2’s
capability during the performance test was recorded as about 659 MW (gross). Boiler
Performance Test Report (Pl. Ex. 81), at AM-00482381.
286.

Ever greater capability was noted among the “Bottom-Line Results” of the Unit 2

outage during the 2010 State of the System Meeting: “679 Gross MWs!” 2010 State of the
System (Pl. Ex. 41), at AM-02493751.
287.

After the 2010 outage, Ameren also reported a substantial increase in Unit 2’s

capability to its system operator, MISO, to NERC, and to the Missouri Public Service
Commission. Specifically, in September 2010, Ameren reported to NERC that Unit 2’s
summertime peak capability had increased to 648 MW (gross), 617 MW (net), “due to work
completed in the 2010 major boiler outage (replacement low pressure turbines and numerous
boiler modifications).” October 27, 2010 MISO Verification Test Data (Pl. Ex. 139), at AM02663830 (emphasis added). Ameren provided the same information to NERC in September
2010. September 15, 2010 Capability Validation (Pl. Ex. 133), at AM-02645178; see also
Koppe Test., Tr. Vol. 3-B, 46:6-47:22.
288.

Later in December 2010, Ameren responded to a request from the Missouri Public

Service Commission to identify any plant upgrades that it expected to result in an increase in the
amount of electricity the plant would produce in the future. MPSC Data Request 0257 (Pl. Ex.
222); Koppe Test., Vol. 3-B, 50:22-51:11.
289.

Ameren told the Missouri Public Service Commission that the 2010 outage,

including the component replacements at issue, would result in a 34 MW increase in Unit 2’s
capability, which it characterized as having been based on a “significant capacity restoration[]”
91

of 22 MW and a “true capacity increase[]” of 12 MW. Ameren Resp. to DR 0257 (Pl. Ex. 223);
Koppe Test., Vol. 3-B, 51:12-52:22. Joe Sind, the Ameren engineer who performed the analysis
supporting Ameren’s statements to the Missouri Public Service Commission, confirmed that the
reported 12 MW “true capacity increase” was based on the company’s best expectation of the
impact of the LP turbine replacement on the capability of the unit. Sind Test., Tr. Vol. 9-B,
20:3-12, 27:12-28:3. Mr. Sind’s work papers show that his capacity analysis only looked at
changes in unit capability and air preheater differential pressures and that he reported increases
in capability for other Ameren units where work had been done on air preheaters but no turbine
work had occurred. Sind Test., Tr. Vol. 9-B, 22:3-23:17, 25:6-26:2.
290.

Mr. Koppe confirmed the increase in capability reported by Ameren to the Public

Service Commission was consistent with his review of “thousands of hours of operation at full
power.” Koppe Test, Tr. Vol. 4-A, at 49:16-23.
291.

In its response to the Missouri Public Service Commission, Ameren also reported

that a 2.4% efficiency improvement had occurred as a result of the 2010 overhaul, of which 1.9%
was due to the LP turbine replacement and 0.5% was due to the reduction in auxiliary load
caused by the air preheater and economizer replacements. Dec. 6, 2010 Email re: “Updated DR
0257 Spreadsheet” (Pl. Ex. 216), AM-02757946; Ameren Resp. to DR 0257 (Pl. Ex. 223), at
AM-02762954; Sind Test., Tr. Vol. 9-B 26:23-28:3; Finnel Test., Tr. Vol. 10-A, 12:16-13:18.
As a result, the increase in capability Ameren reported to the Missouri Public Service
Commission was greater than the reported efficiency improvement, which means that Unit 2
would be capable of burning more coal as a result of the 2010 work. Sind Test., Vol. 9-B, 28:618; Koppe Test., Vol. 3-B, 52:3-22.

92

292.

Ameren takes its obligation to provide truthful information to the Missouri Public

Service Commission seriously. Meiners Rule 30(b)(6) Dep., Oct. 15, 2014, Tr. 19:5-13.
293.

Outside of this litigation, Ameren has attributed only 12 MW of the megawatt

capacity increase at Unit 2 to the replacement of the LP turbine. Even as recently as a January
2011 email, Mr. Shelton reconfirmed that the 1.9% improvement in efficiency that Ameren
reported to the Missouri Public Service Commission equated to 12 MW. Mr. Shelton further
stated that while there might be a little more increase, he could not quantify or estimate any such
benefit because it would be too uncertain. Shelton Test., Tr. Vol. 10-A, 100:13-101:1, 102:11103:20; January 21, 2011 Email (Pl. Ex. 935), at AM-02248224.
294.

Ameren further raised the capability of Unit 2 after the 2010 boiler upgrade. In

December 2010, the gross capacity of Rush Island Unit 2 was further increased to “better reflect
the increase in output following the spring 2010 outage in which two new LP turbines were
installed and several boiler components were replaced.” The July 2011 gross capacity was listed
as 641 MW, which was 26 MW greater than the July 2008 capacity, while the December 2011
gross capacity was listed as 653 MW. December 14, 2010 Capability Table (Pl. Ex. 257), at
AM-00067232, 67235; Shelton Test., Tr. Vol. 10-A, 92:22-93:15.
295.

Mr. Koppe also conducted an analysis of the company’s operating data and found

a very substantial increase in Unit 2’s capability after the 2010 boiler upgrade. Koppe Test., Tr.
Vol. 3-B, 5:25-6:3; id. at 19:14-19 (“comparing the baseline period to the post-project period, the
capability of Unit 2 increased by a large amount”). Mr. Koppe’s findings are consistent with
Ameren’s documents.
296.

Mr. Koppe’s analysis of the Plant Information (“PI”) data focused on those hours

in which Unit 2 was operated at “full load,” as indicated by the fact that the turbine valves were
93

wide open, and accepting as much steam as the boiler could produce. Mr. Koppe’s approach is
consistent with the approach Ameren uses for its full load tests, which are weekly tests done by
plant engineers to determine the capability of the units. Koppe Test., Tr. Vol. 3-B, 6:9-7:16,
8:20-9:8; Sind Test., Vol. 9-B, 30:1-7 (during a full load test, the plant is trying to generate as
much output as it can).
297.

The pre-project period in Mr. Koppe’s analysis of the PI data was January 2006

through December 2007, which is the period of time closest to the PSD baseline for which
Ameren produced a complete set of data. The capability of Unit 2 during that time was 615
MW. Koppe Test., Tr. Vol. 3-B, 34:2-35:13.
298.

The post-project period in Mr. Koppe’s analysis of the PI data was October 2010

to August 2011, because that period provided the “best measure … of how much the unit’s actual
capability had increased” as a result of the project. The post-project capability of Unit 2 was 653
MW (gross). Koppe Test., Tr. Vol. 3-B, 34:16-35:8.
299.

Based on the Plant Information data, the overall increase in capability was 38

MW. This is a 6.2% increase in Unit 2’s capability. Koppe Test., Vol. 3-B, 49:9-15.
300.

Based on his analysis of the PI data, Mr. Koppe determined that 23.3 MW (3.8%)

of the increase were related to the component replacements at issue, and 14.7 MW (2.4%) were
related to efficiency improvements. The 23.3 MW related to the project at issue resulted in Unit
2 being able to burn more coal per hour. Koppe Test., Vol. 3-B, 34:2-35:13, 49:1-50:18.
301.

A similar increase in capability is shown by looking at all of Ameren’s full load

tests conducted during the PSD baseline period and comparing them to the post-project period.
Based on the full load tests, the average capability of Rush Island Unit 2 increased from 620 MW
(gross) during the baseline period to 657 MW (gross) during the post-project period, for an
94

overall increase of 37 MW. Koppe Test., Tr. Vol. 3-B, 35:17-36:4, 45:12-46:5; see also Pl. Ex.
928 (1006 summary of full load tests for Unit 2).
3.

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

302.

As noted above, Dr. Sahu determined that a capability increase of only 1.7 MW at

Rush Island Unit 2 will cause a 40 ton per year increase in SO2 emissions. Sahu Test., Vol. 5,
41:11-14, 46:5-11.
303.

Dr. Sahu calculated the emissions associated with an 18-MW increase in

capability and determined that Ameren should have expected such an increase to result in an
emissions increase of 416.8 tons per year of SO2. Sahu Test., Vol. 5, 84:5-87:25.
304.

The company’s project justification documents indicate that it expected Unit 2’s

capability to increase as a result of the project by more than ten times the amount that would
result in 40 additional tons of SO2 per year. Because the actual and expected increase in
capability far exceeded 1.7 MW, and exceeded the 18 MW used in Dr. Sahu’s calculations, at
least 40 tons of the overall increase in SO2 emissions are related to the capability increase caused
by the replacement of the economizer, reheater, and air preheater at Unit 2. Sahu Test., Tr. Vol.
5, 87:22-25, 97:3-98:16.
4.

Nothing in Mr. Caudill’s opinions negates Mr. Koppe’s calculations of
capability increases

305.

In contrast with Mr. Koppe, Ameren’s capability expert, Mr. Caudill, ignored

Ameren’s full load tests. He failed to even analyze the performance test that specifically
assessed the post-project performance of the boiler upgrades. Although Mr. Caudill reviewed
many Ameren performance test reports for turbines, including turbines at plants that are not at
issue in this case, he did not review the performance test report for the new reheater, economizer,
95

and air preheaters that are actually at issue in this case. Caudill Test., Tr. Vol. 10-B, 53:7-54:6;
Boiler Performance Test Report (Pl. Ex. 81).
306.

Instead, Mr. Caudill simply applied “filters” to the pre- and post-project data that

excluded more than 99% of the data in the periods he chose. For instance, the pre-project period
he chose included 7,473 hours of data, but he filtered out all but 28 of those hours. Similarly, the
post-project period he chose included 14,304 hours, but he filtered out all but 111 hours. Caudill
Test., Tr. Vol. 10-B, 67:11-22. The effect of Mr. Caudill’s decision to filter out 99% of the
operating data was that he only included hours in his capability analysis when the unit was not
load limited. Caudill Test., Tr. Vol. 11-A, 4:16-6:4. Rather than assess the actual capability of
the Unit 2 boiler, Mr. Caudill excluded all of the effects of pluggage on the boiler’s actual
capability, including the thousands of hours of data that demonstrated the actual effects of
pluggage when the boiler could not produce enough. Koppe Test., Vol. 3-B, 7:17-8:19.
307.

Removing Mr. Caudill’s filters drastically changes the results of his pre-and post-

project comparisons. For instance, at Unit 2, the unfiltered data show that average hourly gross
heat input actually increased by over 300 mmBTU per hour and that the maximum hourly gross
heat input similarly increased by more than 300 mmBTU per hour. Caudill Test., Tr. Vol. 11-A,
7:10-8:2. Similarly, Mr. Caudill’s unfiltered data show that average hourly MW increased by
approximately 50 MW and that the maximum hourly megawatts increased by 29 MW. Caudill
Test., Tr. Vol. 11-A, 8:3-15 (Caudill Cross Test.).
308.

In addition to confirming that Unit 2 was actually operating at higher average

hourly heat inputs after the 2010 outage, Mr. Caudill’s unfiltered data also confirm that Unit 2
spent significantly more time operating at higher loads following the 2010 outage. For instance,
during the pre-project period when Unit 2 was experiencing load limitations due to pluggage, it
96

spent only 10% of its operating hours at the highest load range identified by Mr. Caudill, with
the largest fraction of the operating hours (40%) spent at the second highest load range. By
contrast, after the 2010 outage the load range at which Unit 2 operated the most had shifted up to
the highest load range identified by Mr. Caudill, with Unit 2 spending 40% of its operating hours
at the highest load range after the 2010 outage as compared to 10% before the outage. Caudill
Test., Tr. Vol. 11-A, 11:8-13:16. This is exactly what would be expected when a plugged boiler
is no longer load limited following an upgrade.
309.

Mr. Caudill also expressed an opinion on efficiency. However, his efficiency

analysis suffered from at least two fundamental flaws that render it of little to no relevance here.
First, Mr. Caudill conceded that his opinions do not address whether the projects were expected
to, or did, cause increases in the total annual amount of generation or fuel burned at Rush Island.
By analogy, Mr. Caudill explained that his analysis looked at the equivalent of miles-per-gallon
rather than looking at the total gallons of fuel used in a year. Caudill Test., Tr. Vol 10-B, 11:2012:12.
310.

Second, Mr. Caudill did not analyze the required NSR pre-and post-project

periods. Ameren itself has chosen specific two-year pre-project baseline periods to present in
this case for purposes of determining whether its projects violated New Source Review. Vol. 10B, 30:19-31:12 (Caudill Cross Test.). Yet Mr. Caudill only used approximately one year of preproject data. And at Unit 2 there was not a single month in the pre-project period that Mr.
Caudill used that actually overlapped with the two-year NSR baseline period that is at issue in
this case. Caudill Test., Tr. Vol. 10-B, 32:4-33:17.
311.

In addition, the time periods Mr. Caudill examined skew his results. For instance,

he relied on pre-project periods when efficiency was significantly worse than it was during the
97

applicable NSR baseline period, effectively making the unit less efficient for purposes of his
comparison. Ameren’s Exhibit TW demonstrates that during the pre-project period selected by
Mr. Caudill, Rush Island Unit 2 had the worst efficiency (i.e., the highest heat rate) in any of the
five years leading up to the 2010 outage. Yet Mr. Caudill did not even look at data from those
other years. Exhibit TW; Caudill Test., Tr. Vol. 10-B, 42:25-43:19.
D. PROSYM-BASED EMISSIONS CALCULATIONS
312.

In addition to Dr. Sahu’s translation of the performance improvements calculated

by Mr. Koppe into calculations of emissions increases, the United States also presented
emissions analyses performed by Dr. Ezra Hausman using Ameren’s production cost modeling
program.
313.

Ameren’s experts agree that using results from a production cost modeling run is

an appropriate way to forecast future emissions for a New Source Review analysis. King Test.,
Tr. Vol. 6-B, 66:3-15; Chupka Test., Tr. Vol. 8-B, 80:14-17. In fact, Ameren expert Michael
King admitted that he used production cost modeling runs in his New Source Review analyses in
prior enforcement cases. King Test., Tr. Vol. 6-B, 66:16-19.
1.

Production cost modeling at Ameren

314.

“A production cost model is a computer application used to simulate an electric

utility’s generation system and load obligations.” Finnell MPSC Test. (Pl. Ex. 439), at 3:10–11.
315.

Ameren regularly uses a production cost model called ProSym to forecast its unit

operations for a variety of business purposes, including fuel budgeting and rate case justifications
before the Missouri Public Service Commission. Finnell MPSC Test. (Pl. Ex. 439), at 3:11–14;
Ringelstetter Test., Vol. 11-B, 12:15–17.

98

316.

Ameren’s ProSym model is calibrated with actual load information to check its

accuracy as a forecasting tool. Finnell Rule 30(b)(6) Dep., Nov. 22, 2013, Tr. 28:6-20. The
calibration shows that the projection runs “come within a fairly high degree of accuracy.” Finnell
Rule 30(b)(6) Dep., Nov. 22, 2013, Tr. 28:6-29:13. According to Ameren, ProSym “does a good
job of modeling the electric system and how it’s operated.” Finnell Rule 30(b)(6) Dep., Nov. 22,
2013, Tr. 29:2-13.
317.

This computer simulation software uses a complex algorithm, but is basically a

“supply and demand” model that predicts how the system operator, MISO, will dispatch
Ameren’s units hour-by-hour for a given period after taking into account various inputs like unit
performance projections and load forecasts that Ameren develops as inputs into the program.
Finnell Test., Tr. Vol. 9-B, 67:10–11; Hausman Test., Tr. Vol. 4-B, 41:17–23, 44:7–15.
318.

As Ameren’s witness Mr. Finnell explained, at Ameren, “[t]he fuel budget

process involves collecting information from various work groups or [expert] areas in the
company for items that are used in the ProSym model. The ProSym model is then executed, and
the results are prepared and issued to various groups within the company.” Finnell Test., Tr.
Vol. 9-B, 66:22–67:1.
319.

The fuel budgeting process typically involves forecasting unit operations for five

years. Finnell Test., Tr. Vol. 9-B, 70:20- 21.
320.

Ameren’s modeling runs show how unit performance improvements interact with

rising system loads or other market factors to affect unit operations. Hausman Test., Tr. Vol. 4B, 40:7–12; Ringelstetter Test., Tr. Vol. 11-B, 56:10-21.
321.

Jaime Haro, Ameren’s manager in charge of load forecasting and risk

management, testified at trial he had worked with the company’s modeling department, and
99

confirmed that Ameren’s modeling resources could be used to perform sensitivity analyses and
investigate how different scenarios might impact operations at Ameren’s units. Haro Test., Tr.
Vol. 9-A, 133:1–14.
322.

The inputs used by ProSym in simulating dispatch and operations can be divided

into two types: market factors and unit characteristics. Hausman Test., Tr. Vol. 4-B, 42:13–17.
323.

Market considerations that are input into ProSym include things like hourly load

data—e.g., load forecasts for the market Ameren serves—as well as fuel costs, off-system
market data, and system requirements. Finnell MPSC Test. (Pl. Ex. 439), at 3:3–5; Hausman
Test., Tr. Vol. 4-B, 42:21–43:15.
324.

Unit characteristics that are supplied for the model include measures of the unit’s

efficiency (also called its “heat rate” as it describes how much heat or fuel it takes for the unit to
produce each unit of electricity), the unit’s maximum capacity, the unit’s projected availability,
and other physical constraints such as how long it takes the unit to ramp up to full load if it is
taken offline for any reason (its “ramping constraints”). Hausman Test., Tr. Vol. 4-B, 43:21–
44:3.
325.

As used by Ameren, the model takes into account two measures of unit

availability when it projects unit operations: a unit’s “forced outage rate,” and its “partial outage
rate.” Hausman Test., Tr. Vol. 4-B, 52:25–53:20.
326.

The forced outage rate is a measure of time that the unit was able to run at any

level. So, in a non-leap year, it would be the number of hours the unit could run divided by
8,760, the number of hours in a year. Hausman Test., Tr. Vol. 4-B, 53:2–6.
327.

The partial outage rate is the model’s input for deratings. It is the percentage of

actual available generation divided by the total available generation from the unit assuming
100

every available hour could have been loaded at full power. Hausman Test., Tr. Vol. 4-B, 53:9–
15.
328.

Adding the forced and partial outage rates of a unit together gives you the

“effective unit outage rate.” To determine a unit’s equivalent availability factor, one subtracts
the effective unit outage rate from 1. Hausman Test., Tr. Vol. 4-B, 53:16–54:9.
2.

Dr. Hausman’s sensitivity analyses

329.

After investigating Ameren’s modeling files, Dr. Hausman identified several

performance improvements that Ameren modeled at its Rush Island plants concurrent with the
boiler upgrade work at issue in this case. Hausman Test., Tr. Vol. 4-B, 47:19–48:2.
330.

Dr. Hausman executed “sensitivity analyses” using Ameren’s production cost

modeling files to determine how the performance improvements at the Rush Island Units were
impacting the modeling projections for those units’ operations. Hausman Test., Tr. Vol. 4-B,
47:19–48:2.
331.

A sensitivity test is a standard modeling technique whereby a modeler runs a

computer simulation multiple times, varying only one input or parameter a little bit each time in
order to investigate how that single element interacts with the rest of the system being modeled.
Hausman Test., Tr. Vol. 4-B 46:24–47:8.
332.

Dr. Hausman’s sensitivity analyses revealed straightforward, linear relationships

between unit capacity or unit availability and the unit’s projected fuel use—and, accordingly,
pollution levels. Hausman Test., Tr. Vol. 4-B, 55:20-56:19, 63:20-64:20, 65:22-66:7, 71:7-25,
72:12-21.
333.

As shown below, any one of the performance improvements that Ameren

modeled at the Rush Island units following the boiler upgrades would result in a concomitant
101

increase in fuel use that would translate into a pollution increase well above the 40 tons-per-year
threshold for SO2 to trigger New Source Review. Hausman Test., Tr. Vol. 4-B, 73:11–21.
a.
334.

Unit 1 sensitivity analysis

For Unit 1, Dr. Hausman reviewed a credible fuel budgeting modeling run

performed in 2006 in order to evaluate how performance improvements following the 2007
projects at Unit 1 would be projected to affect operations and pollution. The model run he used
was contemporaneously performed by the company when Ameren was planning the Unit 1 work,
the modeling files were complete (allowing for replication and verification of the results), and
the inputs presented credible, long-term forecasts without “red flags” such as artificial
constraints or other indications that would suggest the model run was used for a different
purpose or did not reasonably reflect company expectations. Hausman Test., Tr. Vol. 4-B, 68:416 & 97:15–98:1; see also Finnell Test., Tr. Vol. 10-A, 5:23–8:23 (discussing Plaintiff’s Exhibit
892 and updates to Ameren’s 2006 fuel budget modeling).
335.

Comparing the year before the work was performed to the year after it was

completed, Ameren modeled a 4% increase in equivalent availability following the boiler
upgrades—a 2.2% improvement in the unit’s forced outage rate and a 1.8% improvement in the
unit’s partial outage rate. Hausman Test., Tr. Vol. 4-B, 69:16–22.
336.

Dr. Hausman determined that a one percentage point improvement in Unit 1’s

forced outage rate would translate into an additional 481 billion BTUs of fuel consumption per
year and an additional 162 tons of SO2 per year. Hausman Test., Tr. Vol. 4-B, 71:19-23.
337.

Dr. Hausman also found that reducing Unit 1’s partial outage rate (deratings) by

one percentage point would result in an additional 408 billion BTUs of fuel consumption per
year and an additional 138 tons of SO2 per year. Hausman Test., Tr. Vol. 4-B, 72:12–21.
102

b.
338.

Unit 2 sensitivity analysis

For Unit 2, Dr. Hausman reviewed Ameren’s “Original” 2010 Fuel Budget

modeling run performed in early 2010 in order to evaluate how performance improvements
following the 2010 projects at Unit 2 would be projected to affect operations and pollution
following that work. That model run was used by Ameren’s environmental services department
to perform its “reasonable possibility analysis” for that work. Hausman Test., Tr. Vol. 4B, 49:6–
10; Hutcheson Test., Vol. 11-A, 38:22-39:1.
339.

Dr. Hausman determined that each additional megawatt of increased unit capacity

at Unit 2 will result in that unit burning an additional 69 billion BTUs per year and an additional
23 tons of SO2 per year. Hausman Test., Tr. Vol. 4-B, 59:24–60:2.
340.

Dr. Hausman also found that a one percentage point improvement in the unit’s

forced outage rate would translate into an additional 566 billion BTUs per year and, as a result,
an additional 189 tons of SO2 per year. Hausman Test., Tr. Vol. 4-B, 64:15–20.
341.

A one percentage point improvement in Unit 2’s partial outage rate would

translate into an additional 466 billion BTUs per year and, as a result, an additional 156 tons of
SO2 per year. Hausman Test., Tr. Vol. 4-B, 64:15–20.
3.

Dr. Hausman’s “with and without” analyses

342.

In addition to his sensitivity analyses, Dr. Hausman also performed a “with and

without” analysis using Ameren’s ProSym model. A “with and without” analysis is a standard
modeling technique used throughout the industry and in many fields that employ computer
modeling. It compares two scenarios—one in which the performance improvements Ameren
expected were realized (the scenario Ameren itself modeled), and another scenario in which the

103

units simply continued operating as they had in the past, without realizing any performance
improvements as a result of the modifications. Hausman Test., Tr. Vol. 4-B, 25:12–18, 74:5–7.
343.

This technique allows the modeler to look at the impact of one change (or set of

changes) in the system while holding all else constant. Hausman Test., Tr. Vol. 4-B, 25:16–19 &
74:7–12.
344.

Ameren’s experts conceded that utilities often run a production cost model twice,

changing just one variable, in order to see how changing that variable would impact the output of
the model. King Test., Tr. Vol. 6-B, 67:14-19; Chupka Test., Vol. 8-B, 79:18-81:2. As Ameren
expert Marc Chupka testified, the type of with-and-without modeling analysis that Dr. Hausman
did in this case is a “standard tool” in utility modeling practice. Chupka Test., Tr. Vol. 8-B,
80:18-22.
345.

Ameren expert Michael King agreed that the difference between two estimates of

future emissions – one of which accounted for the project and one of which did not – would
show the impact of the project. King Test. Tr. Vol. 6-B 69:7-71:23.
346.

In his testimony in a prior NSR enforcement case, Ameren expert Michael King

performed two modeling runs to identify the emissions that he testified were unrelated to the
project and should be excluded from an NSR calculation under the demand growth exclusion.
King Test. Tr. Vol. 6-B 65:17-21. In other words, Mr. King used the same technique in that case
that Dr. Hausman did here (except Mr. King set out to identify the emissions that were unrelated
to the project, while Dr. Hausman identified the emissions related to the project).
347.

Similarly, Ameren expert Marc Chupka testified that one way to perform an NSR

emissions analysis would be to (1) start with a contemporaneous emissions projection that

104

incorporates the effect of the project; (2) compare that projection to the baseline period; and then
(3) address any unrelated factors. Chupka Test., Tr. Vol. 8-B, 81:3-24.
a.
348.

Unit 1 analysis

For Unit 1, Dr. Hausman’s with-and-without analysis compared the ProSym

modeling forecasts performed by Ameren in 2006 to another version in which the unit did not
increase its availability by 4% following the work.
349.

The comparison revealed that, but for the performance improvements modeled at

the unit, Rush Island Unit 1 would have operated 192 fewer hours, the unit would have burned
over 1,600 billion BTUs less coal, and it would have emitted 562 fewer tons in the year he
examined. Hausman Test., Tr. Vol. 4-B, 79:23–80:7.
350.

Based on Ameren’s updated 2006 fuel budget modeling, the company projected

that it would emit as much as 15,561 tons per year of SO2 in the five years after the project, a
687-ton increase above baseline levels. Of that projected increase in emissions, 562 tons would
not have been projected were it not for the availability improvements modeled at Unit 1.
Hausman Test., Tr. Vol. 4-B, 80:10–21.
351.

Dr. Hausman also used Ameren’s Plant Information data to develop inputs based

on the putative performance improvements in the company’s Plant Information data. Dr.
Hausman accepted the data at face value and gave Ameren credit for a 3.0% efficiency
improvement (more than Ameren reasonably should have or did expect) and also incorporated a
20-MW increase in Unit 1’s capacity. Hausman Test., Tr. Vol. 4-B, 81:1–3.
352.

Using these inputs from the company’s Plant Information data and re-running his

with-and-without analysis, Dr. Hausman found that Ameren would have projected a 716-ton

105

increase above baseline pollution levels, of which 591 tons would not have been projected but
for the performance improvements at the unit. Hausman Test., Tr. Vol. 4-B, 81:3–6.
b.
353.

Unit 2 analysis

For Unit 2, Dr. Hausman compared the ProSym modeling forecasts performed by

Ameren to another version in which the unit did not increase its capacity by 18 MW and improve
its availability by 2% following the work. The performance improvements represented by
Ameren in this model are consistent with the performance improvements that Mr. Koppe
independently determined the company should have expected to result from the boiler work.
Hausman Test., Tr. Vol. 4-B, 82:21–24. The comparison revealed that, without the performance
improvements modeled at the unit, Rush Island Unit 2 would have operated 96 fewer hours, the
unit would have burned nearly 1,600 billion BTUs less in coal, and it would have emitted 746
fewer tons of SO2 in the year he examined. Hausman Test., Tr. Vol. 4-B, 75:18–76:5.
354.

Based on Ameren’s “original” 2010 fuel budget modeling, the company projected

as much as 16,816 tons per year of SO2 in the five years after the project, a 2,528-ton increase
above baseline levels. Of that projected increase in emissions, 746 tons would not have been
projected were it not for the performance enhancements modeled at Unit 2. Hausman Test., Tr.
Vol. 4-B, 76:22–77:6.
355.

As with Unit 1, Dr. Hausman reviewed Ameren’s Plant Information data to

develop inputs based on the putative performance improvements contained in the company’s
data. Once again, Dr. Hausman accepted the Plant Information data at face value. Thus, Dr.
Hausman gave Ameren credit for an efficiency improvement (4.2%) that exceeded what it
reasonably should have or did expect, and also incorporated a 34 MW increase in capacity (a
5.75% increase). Hausman Test., Vol. 4-B, 79:6–8.
106

356.

Using these PI-inputs and re-running his with-and-without analysis, Dr. Hausman

concluded that Ameren still would have projected a 1,905-ton per year increase above baseline
pollution levels, of which 696 tons would not have been projected but for the performance
improvements at the unit. Hausman Test., Tr. Vol. 4-B, 78:21–79:2.
IV.

AMEREN HAS FAILED TO MEET ITS BURDEN TO ESTABLISH THE
APPLICABILITY OF THE DEMAND GROWTH EXCLUSION
357.

Ameren pled as its Twenty-Sixth Affirmative Defense that any emissions

increases following the 2007 and 2010 outages at Rush Island Unit 1 or Unit 2 were the result of
increased demand and not the projects at issue. Answer (ECF No. 250), at 31.
A. Background about the Market for Rush Island’s Generation
358.

The Midcontinent Independent System Operator (“MISO”) serves as the dispatch

operator for Ameren’s Rush Island units. Hausman Test., Tr. Vol. 4-B, 33:24–34:1.
359.

As a dispatch operator, MISO aims to meet system demand with the lowest-

cost—though still reliable—portfolio of electricity generation it can. “[G]eneration owners tell
the dispatch operator what’s available and at what price. And then the dispatch operator uses a
computer algorithm to find the lowest cost way of meeting load.” Hausman Test., Tr. Vol. 4-B,
33:19–23, 34:2–9.
360.

“MISO’s job is to find the lowest cost way of meeting that demand. And the way

they do that is they start by turning on the lowest cost sources of energy first. Those are often
nuclear or coal units like the Rush Island units. And then they progressively turn on more and
more costly generators to run until at every moment the energy being generated is balanced with
the load required by the system.” Hausman Test., Tr. Vol. 4-B, 31:14–21.

107

361.

As a general matter, electricity cannot be stored, so—at least when considering

the system as a whole—electricity production and demand must be constantly balanced. Hamal
Test., Tr. Vol. 9-A, 98:11–13. That does not mean, though, that electricity production and
demand are the same thing. As with every market, the electricity market has a demand side and
a supply side—and just because demand for electricity may be rising does not mean that any
specific generating unit will be used to serve that rising demand. Hamal Test., Tr. Vol. 9-A
41:24–42:8.
362.

The Rush Island units cannot generate—and so cannot serve demand—if they are

unavailable. And Ameren cannot offer generation it does not have to the market: if a Rush
Island unit was forced offline because of some mechanical failure, Ameren would not be able to
offer Rush Island generation into the MISO market. Similarly, when Rush Island units are load
limited or derated for some reason, Ameren cannot offer the unavailable portion of its generating
capacity to the MISO market. Hamal Test., Tr. Vol. 9-A, 40:21–41:7; Naslund Test., Tr. Vol. 6B, 13:24-14:5; King Test., Tr. Vol. 6-B, 52:24-53:6 (demand and availability are both necessary
in order for a unit to operate).
363.

Furthermore, in general, MISO cannot call on Ameren’s units to provide more

electricity than Ameren has offered into the market. Hamal Test., Tr. Vol. 9-A, 41:10–14;
Hausman Test., Tr. Vol. 4-B, 35:6–9.
364.

Ameren does not need MISO’s permission to bring a unit offline if it has

experienced a tube leak or other failure at the unit. Hamal Test., Tr. Vol. 9-A, 41:17–20;
Hausman Test., Tr. Vol. 4-B, 35:10–12.
365.

MISO does not tell generation owners like Ameren how to spend their capital

improvement budgets or how to improve their generation services. Hamal Test., Tr. Vol. 9-A,
108

41:21–23; Hausman, Tr. Vol. 4-B, 35:13–19; Meiners Test., Tr. Vol. 7-B, 57:17-58:13. Ameren
controls the engineering of its units and decides what maintenance work needs to be performed
and when to perform that work. Hausman Test., Tr. Vol. 4-B, 36:3–6; Meiners Test., Tr. Vol. 7B, 57:17-58:13. By controlling the maintenance of and investment in the Rush Island generating
units, Ameren manages those supply assets to ensure that they can serve as much market demand
as they can. Hausman Test., Vol. 4-B, 35:23–36:21.
366.

MISO does not pay bonuses to generation owners when their units perform well

or reliably. Hausman Test., Tr. Vol. 4-B, 35:20–22.
367.

“Rush Island has low operating cost[s]. MISO’s job is to run the system as

efficiently as possible, and that translates into MISO doing what it can to get Rush Island to run
more.” Hamal Test., Tr. Vol. 9-A, 37:20–23. As a natural corollary, if Ameren is able to make
the Rush Island units able to operate more hours or at higher loads, then MISO would call on
them to make use of that new-found capability. Hamal Test., Tr. Vol. 9-A, 51:22–52:17.
368.

Jaime Haro, Senior Director of the Ameren’s Enterprise and Commodity Risk

Management Department, described how the Rush Island units compare to other units in
Ameren’s generating portfolio by providing a generalized schematic of the “merit order” or
“dispatch order” of its various plants. Haro Test., Tr. Vol. 9-A, 130:14 – 132:9; Hausman Test.,
Tr. Vol. 4-B, 31:14–32:22. At the bottom of the schematic are units that cannot shut down and
are the cheapest to run, such as Ameren’s Callaway nuclear plant. Next up to be dispatched are
other baseload coal units such as the Rush Island generating units that run basically whenever
they are available. Haro Test, Vol. 9-A, 65:1–66:1; Tr. Vol. 6-A, 55:4-7.

109

[Ameren Demonstrative WC_2]
369.

Coal units like Rush Island are expensive to shut down, and it takes hours—

sometimes as much as a day—to start them back up. Hamal Test., Tr. Vol. 9-A, 45:10–15. As
such, the Rush Island units may ramp down their generation through the night or during other
periods of low system load, but they generally do not turn off. Hamal Test., Tr. Vol. 9-A, 46:7–
23; Haro Test., Tr. Vol. 9-A, 131:7–12.
370.

As illustrated by Ameren’s schematic, the general impact of an increase in system

demand is that the Rush Island units might ramp down a little later at night than they otherwise
would, or ramp up to high loads a little earlier in the mornings than they otherwise would. Haro
Test., Tr. Vol. 132:2–9.
371.

As Mr. Haro testified, though, when load is up, as it often is during the “on peak”

hours shown with relatively high prices at the left and right hand side of the graphic, the Rush
Island units are typically generating as much as they can. Haro Test., Tr. Vol. 9-A, 131:1–15.

110

Obviously, if the unit is already fully loaded, it cannot increase its output in order to serve more
of the market’s demand for electricity. Hamal Test., Vol. 9-A, 58:16–17.
372.

In general, the Rush Island units are more likely to be running fully-loaded during

“on peak” hours than “off peak” hours. Hamal Test., Tr. Vol. 9-A, 59:3–5, 59:17–19. Even
according to Ameren’s expert’s analysis, only a third of the hours the Rush Island Unit 2
operated with some available capacity to spare were “on peak” hours. Thus, according to
Ameren’s expert, Unit 2 was at maximum capacity for more than half of all hours in the baseline
period—and more than two-thirds of all “on peak” hours in the baseline period. Ringelstetter
Test., Vol. 11-B, 40:10 – 15; Def. Demonstrative TK-15.3
373.

This relationship is borne out in Ameren’s modeling files. For example, as is

evident in Ameren’s modeling efforts performed in 2006, even when the company forecast
system load to increase each year, the Rush Island units were projected to generate at essentially
flat levels throughout the forecast period. As Dr. Hausman explained, this clearly indicates the
Rush Island Units are baseload units, and they are more or less insensitive to variations in system
load. Hausman Test., Tr. Vol. 4-B, 45:20–22.
B. Ameren’s Failure of Proof Regarding Demand Growth as a Cause of Increased
Emissions
374.

In the company’s 2011 Corporate Social Responsibility Report, Ameren

characterized the projects at issue in this case as “necessary to respond” to increased demand.
Naslund Test., Tr. Vol. 6-B, 16:12-15, 18:3-5; Corporate Social Responsibility Report (Pl. Ex.
3

Even this number appears to understate how often the units were run at their “available
capacity.” Ms. Ringelstetter’s analysis does not accurately reflect those hours when the unit was
ramping up after coming offline. She counted those hours as having “available capacity” even
though the units would have been physically incapable of generating more during that time.
Ringelstetter Test., Vol. 11-B, 69:3–70:15.
111

431) at AM-00510618. In other words, Rush Island could not have served at least some of the
increasing system demand without the Rush Island upgrade projects.
375.

To the extent that system demand was growing, as of 2008, Ameren expected that

its purchase of three combustion turbines (natural gas units), would satisfy that demand growth
until at least 2018. Naslund Test., Tr. Vol. 6-B, 15:14-16:11.
376.

To the extent that system demand was growing, Ameren did not offer any

evidence at trial to show how changes in system demand, if any, would or did specifically impact
the operation of and emissions from the Rush Island units. For example, Ameren utility market
expert Cliff Hamal admitted that he did not quantify “how demand would change Rush Island’s
operations in any way.” Hamal Test., Tr. Vol. 9-A, 39:23–40:5.
377.

The industry does have a standard measure that isolates demand for the output of

individual generating units. That metric is known as the “utilization factor,” and Ameren itself
uses it during the course of its business. Sahu Test., Tr. Vol. 5, 56:18-57:3, 76:15-22;
Ringelstetter Test., Tr. Vol. 11-B, 80:18-81:6; Economic Evaluation of Plant-upgrading
Investments (Pl. Ex. 241), at AME_RHK000011-12 (“loading order [is] reflected in the
utilization factor”) (EPRI Report, Vol. 1); Availability Worksheet (Pl. Ex. 250), at Spreadsheet
Tab “Instructions” (utilization factor is the “percent of mwhrs used after outages and derates”).
378.

Ameren expert Michael King testified that demand for the generation of coal units

had been decreasing since 2007 due to falling natural gas prices. King Test., Tr. Vol. 6-B,
34:20-35:3, 35:8-16. Mr. King also testified that the utilization factors for the Rush Island units
have been declining since around 2007. King Test., Tr. Vol. 6-B, 87:13-24. Mr. King further
explained that if the utilization factor is decreasing, any emissions increases during that time
period cannot be the result of increased demand. King Test., Tr. Vol. 6-B, 88:3-6, 89:9-12.
112

379.

Ameren expert Sandra Ringelstetter calculated utilization factors in this case and

found that the utilization factor for Unit 1 was projected to remain basically constant and in fact
decreased from 91.18% in the baseline period to 89.66% in the applicable post-project period.
Ringelstetter Test., Tr. Vol. 11-B, 83:4–15; Def. Ex. NE, at “RI U1 2007 Summary” tab. As a
result, any increase in generation that was projected to occur and was in fact realized at Unit 1
following the 2007 outage cannot be attributed to increased demand.
380.

For Unit 2, Ms. Ringelstetter calculated that Unit 2’s utilization was projected to

increase slightly (about 2%), but that it in fact decreased from 91.45 in the baseline period to
89.37 in the relevant post-project period. Ringelstetter Test., Tr. Vol. 11-B 81:7-83:3; Def. Ex.
NE, at “RI U2 2010 Summary” tab. As a result, the more than 15% increase in emissions that
was projected to occur and that was in fact realized at Unit 2 following the 2010 boiler upgrades
cannot be attributed to increased demand.
381.

At Rush Island, emissions of SO2 track availability of the units more closely than

demand. Sahu Test., Tr. Vol. 5, 103:5-107:19; see also King Test., Tr. Vol. 6-B, 86:2-23
(Ameren expert conceding the relationship between availability and SO2 pollution at Rush
Island).

113

Unit 1 SO2 Pollution Tracks Availability, Not Demand on the Unit
100

16000

80

12000

60

8000

40

4000

20

%

SO2 Pollution (tons per year)

20000

0

0
2000

2001

2002

2003

2004

SO2 Pollution (tons per year)

2005

2006

Availability (%)

2007

2008

Utilization Factor (%)

Unit 2 SO2 Pollution Tracks Availability, Not Demand on the Unit
100

16000

80

12000

60

8000

40

4000

20

%

SO2 Pollution (tons per year)

20000

0

0
2000

2001

2002

2003

2004

2005

SO2 Pollution (tons per year)

382.

2006

2007

Availability (%)

2008

2009

2010

2011

Utilization Factor (%)

Ameren did not offer any evidence to explain how an increase in emissions

associated with an increase in capacity at Rush Island can be caused by demand growth.
V.

AMEREN’S NSR EMISSION ANALYSES
383.

Ameren called two witnesses at trial from its Environmental Services Department:

Steven Whitworth and Michael Hutcheson. Mr. Whitworth was the Supervisor of the Air
114

Quality section within Ameren’s Environmental Services Department from 2002 to 2007. In
2007, Mr. Whitworth became Department manager, which meant that he has ultimate
responsibility over the entire Environmental Services group. Whitworth Test., Tr. Vol. 11-A,
90:4-9. Mr. Hutcheson works for Mr. Whitworth and was the Ameren employee responsible for
performing the NSR emissions calculations that Ameren presented at trial. Hutcheson Test., Tr.
Vol. 11-A, 34:2-35:2, 54:20-55:11, 63:9-15.
384.

Ameren does not have any internal guidelines for performing a New Source

Review analysis. Hutcheson Test, Tr. Vol. 11-A, 65:21-24.
385.

The Environmental Services Department at Ameren is responsible for

determining New Source Review applicability. Environmental Services does not have any role
in Ameren’s capital project justification process. Naslund Test., Tr. Vol. 6-B, 19:20-23, 20:7-18.
386.

Project justification packages include a document called the Project Risk

Management Plan. Schweppe Dep., May 20, 2014, Tr. 112:2-7.
387.

Robert Schweppe was Director and later Managing Supervisor of the Project

Engineering group at Ameren. Prefatory Statement to Depo Designation, Vol. 6-A, 19:9-11;
Project Approval Package (Pl. Ex. 1), at AM-0072586. Mr. Schweppe signed off on the Project
Risk Management Plan for the major component replacements at issue for both Unit 1 and Unit
2. Project Approval Package (Pl. Ex. 1), at AM-00072606 (Unit 1 boiler components); Project
Approval Package (Pl. Ex. 3), at AM-00072841 (Unit 2 boiler components); Project Approval
Package (Pl. Ex. 4), at AM-00072864 (Unit 1 air preheater); Project Approval Package (Pl. Ex.
6), at AM-00072923 (Unit 2 air preheater).
388.

Each Project Risk Management Plan lists whether certain risk factors have been

addressed, followed by a series of check boxes. One of the check boxes is for
115

“Legal/Environmental.” For each of the projects at issue, the Legal/Environmental box was not
checked. Pl. Ex. 1 at AM-00072606; Pl. Ex. 3 at AM-00072841; Pl. Ex. 4 at AM-00072864; Pl.
Ex. 6 at AM-00072923.
389.

Mr. Schweppe testified that he did not know why the Legal/Environmental box

was not checked, and that he did not “recall that box ever being checked” for “any project risk
plan.” Mr. Schweppe continued that he did not know what the box meant and that he had never
asked anyone to understand what it meant. Schweppe Dep., May 20, 2014 Tr., 112:14-114:5.
A. Ameren Performed No Pre-Project NSR Analysis for Either Project
1.

Rush Island Unit 1

390.

Ameren has admitted that it performed no emission calculations for purposes of

determining PSD applicability prior to undertaking the 2007 project at Unit 1. Whitworth Test.,
Tr. Vol. 11-A, 94:23-25; Boll Test., Tr. Vol. 8-B, 38:3-5; Birk Dep., Sept. 24, 2013, Tr. 220:1421; see also Knodel Test., Tr. Vol. 1-A, 88:10-12; Ameren Closing Arg., Vol. 12, 51:18-20.
391.

Mr. Whitworth, the Head of Ameren’s Environmental Services department,

testified at trial that the only pre-project emission evaluation he did for Unit 1 was a nonnumerical analysis that considered only whether the Unit 1 project would increase the unit’s
potential to emit. Mr. Whitworth also admitted that he relied on an inapplicable provision of the
Missouri regulations. Whitworth Test., Tr. Vol. 11-A, 88:16-25, 90:12-15, 90:20-92:19; see also
Boll Test., Tr. Vol. 8-B, 9:7-13:25 (company relied on non-numerical evaluation of whether
project would have an impact on maximum continuous rating), 38:3-14.
392.

Ameren’s Environmental Services Department did not communicate with project

engineer David Boll at any time prior to the Unit 1 project completion in 2007. Boll Test., Vol.
8-B, 39:17-21, 40:6-9.
116

393.

The Rush Island Plant Manager at the time of the 2007 outage was Robert

Meiners. As plant manager, he was accountable for making sure the plant complied with
environmental regulations. Meiners Test., Tr. Vol. 7-B, 64:2-5. However, Mr. Meiners had no
communications with anyone about whether to seek a New Source Review permit for the Unit 1
project. When asked whether he understands that PSD requires utilit[ies] to make a prediction of
future emissions in order to do [] emissions analys[es], Mr. Meiners replied “That’s not – not my
responsibility. I’m not involved with it.” Meiners Dep., April 8, 2014, Tr. 342:11-17. In fact,
Mr. Meiners testified that throughout his more than 40-year career at Ameren, he never had a
single discussion with anyone about whether or not to seek an NSR permit for any capital project
at all. Meiners Test., Tr. Vol. 7-A, 68:2-18 and Vol. 7-B, 64:2-20. Similarly, Mr. Strubberg
testified that he was not involved in any assessment of whether the projects triggered PSD.
Strubberg Test., Tr. Vol. 8-A, 73:17-74:5.
394.

Prior to undertaking the Unit 1 project, Ameren did not communicate with

permitting authorities about whether a New Source Review permit would be required. Whitworth
Test., Tr. Vol. 11-A, 106:3-7.
2.

Rush Island Unit 2

395.

The Head of Ameren’s Environmental Services department, Mr. Whitworth,

testified at trial that the only pre-project emission evaluation he did for Unit 2 was a nonnumerical analysis that considered only whether the Unit 2 project would increase the unit’s
potential to emit. Mr. Whitworth also admitted that he relied on an inapplicable provision of the
Missouri regulations. Whitworth Test., Tr. Vol. 11-A, 88:16-25, 90:12-15, 90:20-92:19.
396.

The Ameren employee who was responsible for doing NSR calculations for

Unit 2 was Michael Hutcheson. Mr. Hutcheson testified that he did not review any EPA or
117

Missouri Department of Natural Resources guidance specifically as part of his work for the
project at issue. Hutcheson Test., Tr. Vol. 11-A, 65:25-66:2.
397.

Mr. Hutcheson admitted he had no personal knowledge of the project or whether

the effects of the project were included in the projections he relied upon.
a. Mr. Hutcheson testified that in performing the company’s NSR analysis, he did
not speak to any of the engineers who planned and developed the project. He
received information from his superiors in the Environmental Services
Department, but he did not know the source of that information. Hutcheson Test.,
Tr. Vol. 11-A, 63:5-19.
b. Mr. Hutcheson also testified that he did not review any of the project justification
documents for the work. Hutcheson Test., Tr. Vol. 11-A 63:20-25.
c. Mr. Hutcheson did not know whether the modeling runs that he relied on for his
analysis included any projected improvements in capacity or availability. Mr.
Hutcheson did nothing to check the validity of the modeling runs he received, but
simply “took them on their face.” Hutcheson Test., Tr. Vol. 11-A, 65:4-20;
Hutcheson Dep., April 24, 2014, Tr. 118:20-119:5.
d. Mr. Hutcheson testified that he did not consider whether availability was expected
to improve as a result of the projects because he did not think that information
was “relevant” or “necessary.” Hutcheson Test., Tr. Vol. 11-A, 82:16-25.
398.

Mr. Hutcheson performed two purported NSR analyses for the Rush Island Unit 2

project – the “Original” Reasonable Possibility Analysis and the “Amended” Reasonable
Possibility Analysis. Neither analysis was completed before the project work started. Knodel
Test., Tr. Vol. 1-A, 88:13-18; Whitworth Test., Tr. Vol. 11-A, 96:12-23, 97:2-15; Hutcheson
118

Test., Tr. Vol. 11-A, 84:15-17, 85:3-8. Mr. Hutcheson’s analysis relied on a ProSym model run
the company performed that had been completed in January 2010, after the outage had begun.
Hutcheson Test., Vol. 11-A, 38:22-24. The Original Reasonable Possibility analysis was not
completed until after the project had begun. Mr. Hutcheson admitted that the analysis should be
completed before beginning construction. Hutcheson Test., Tr. Vol. 11-A, 56:1-7; 84:15-85:2;
see also Knodel Test., Tr. Vol. 1-A, 88:24-89:3.
399.

Mr. Hutcheson began working on the Original Reasonable Possibility Analysis

only after Ameren’s legal department requested analyses of about 20 projects, including the Rush
Island Unit 2 project. Some of the projects he was asked to analyze had already occurred and
some were planned for the future. Hutcheson Test., Tr. Vol. 11-A, 34:2-23.
400.

Although the Unit 2 project was originally approved in 2005 and re-approved by

Ameren’s Board of Directors and CEO on August 14, 2009 (FOF 136, 137), Mr. Hutcheson did
not even begin collecting information relevant to his NSR analysis until November or December
2009. Hutcheson Test., Tr. Vol. 11-A, 84:11-14.
401.

Ameren’s “Original” ProSym modeling run was not completed until January

2010, after the 2010 outage had begun. The original case was used to develop the corporate
budget for 2010. Finnell Dep., Nov. 22, 2013, Tr. 79:2-8. After the 2010 outage was complete,
Ameren ran two other modeling cases, including the “EDF” case. Finnell Test., Tr. Vol. 10-A,
9:25-10:5. The EDF case was completed in early 2011. Finnell Test., Tr. Vol. 10-A, 10:3-5.
The EDF case was the same as the “Original” case, but was modified to include efficiency
improvements. Finnell Dep., Nov. 22, 2013, Tr. 77:12-20. The EDF case was used by
environmental services to perform the Amended Reasonable Possibility Analysis. Finnell Dep.,
Nov. 22, 2013, Tr. 76:4-79:8; Hausman Test., Tr. Vol. 4-B, 87:11-14.
119

402.

Ameren’s Original Reasonable Possibility analysis “projected” that Unit 2’s

emissions of SO2 would increase by 2,531.15 tons per year, from 14,287.73 in the baseline
period to 16,818.88 tons per year in the highest projected post-project period. Hutcheson Test.,
Tr. Vol. 11-A, 40:22-41:2; Knodel Test., Tr. Vol. 1-A, 91:10-17; Def. Ex. C at Tab Net
Emissions Change; see also Pl. Ex. 493, at AM-02231873, at “projected Emissions” tab
(showing even higher projected SO2 emissions of 17,018 for Unit 2 in 2012).
403.

Ameren excluded every ton of the projected emissions increase on the basis that

Unit 2 was capable of accommodating all of the increases in the baseline. Ameren provided no
other reason for excluding the projected emissions increases in its Original Reasonable
Possibility Analysis. Knodel Test., Tr. Vol. 1-A, 91:10-17. Mr. Hutcheson stated that there was
no mechanism in his spreadsheet (Def. Ex. C and D) to account for whether the projected
increase was related to the project. He testified that the relatedness question was a “qualitative”
one not a “quantitative” one. Hutcheson Test., Tr. Vol. 11-A, 80:22-81:3.
404.

Ameren did not rely on any guidance or applicability determinations in making

their capable of accommodating determination. Whitworth Test., Tr. Vol. 11-A, 102:3-8,
103:24-104:3.
405.

In late 2010, well after Ameren had completed the Unit 2 boiler upgrade, Mr.

Hutcheson was asked by Ameren’s in-house counsel, Susan Knowles, to revise his analysis.
Hutcheson Test., Tr. Vol. 11-A, 85:3-11; Naslund Test., Tr. Vol. 6-B, 18:14-19; Hutcheson Dep.,
April 24, 2014, Tr. 115:2-12. Mr. Hutcheson used the EDF case to perform the Amended
Reasonable Possibility Analysis. Hutcheson Dep., April 24, 2014, Tr. 117:10-20; Hausman
Test., Tr. Vol. 4-B, 87:11-14.

120

406.

Mr. Hutcheson completed the Amended Reasonable Possibility Analysis in early

2011, almost a year after the Unit 2 project had begun, and then only after EPA had issued a
Notice of Violation to Ameren and after this lawsuit had been filed. Knodel Test., Tr. Vol. 1-A,
92:14-24, 93:15-19; Hutcheson Test., Tr. Vol. 11-A, 55:2-56:9, Def. Ex. D; RFA No. 7.
407.

Mr. Hutcheson was asked to perform the Amended Reasonable Possibility

analysis in order to incorporate a 2.4% efficiency improvement expected from the 2010 outage.
No efficiency improvement had been incorporated into the Original Analysis. Mr. Hutcheson
was not asked to make any other changes to the inputs into the analysis, such as changes that
reflected the full extent of the capacity or availability improvements at Unit 2. Hutcheson Dep.,
April 24, 2014, Tr. 115:13-23; 117:10-20.
408.

Ameren’s expert, Mr. King, testified that he would not perform an NSR analysis

based on a modeling run that was created just for NSR purposes. Mr. King agreed that in using
such a run, a source runs the risk of looking like it is “cooking the forecast” to project no
emissions increase. King Test., Tr. Vol. 6-B, 67:20-68:13.
409.

Even with the changes made to the efficiency input, Ameren’s Amended

Reasonable Possibility Analysis still “projected” an increase of SO2 emissions of 2,059.30 tons
per year. Knodel Test., Tr. Vol. 1-A, 93:3-5; Def. Ex. D. As with its original analysis, Ameren
excluded every ton of the projected emissions increase on the basis that the unit was capable of
accommodating those emissions in the baseline period. Ameren provided no other basis for
excluding those emissions increases. Knodel Test., Tr. Vol. 1-A, 93:6-14.
B. Ameren’s Post Hoc Reasonable Possibility Analysis is Substantively Flawed
1.

Ameren’s calculations fail to model all of the performance improvements
expected from the boiler upgrades
121

410.

Ameren’s Reasonable Possibility Analysis was based on its computer simulations

performed for fuel budgeting purposes in January 2010. Those simulations include an 18 MW
increase in Unit 2 capacity and a 2% improvement in unit availability—resulting in a 95%
EAF—for the unit following the boiler work at issue in this case. See FOF 338, 353.
411.

But project justification documents developed in 2009 projected significantly

better performance at Unit 2 following the work. The CPOC report relied on a 22.5 MW
increase in unit capacity as a result of the boiler work, as well as a 4.2% improvement in
availability—resulting in a nearly 97% EAF—for the unit following the upgrades. See FOF 157,
158, 253.
2.

Ameren’s capable of accommodating approach

412.

Ameren calculated the emissions the unit was capable of accommodating before

the project by using the amount of time the unit was available to operate and multiplying that by
the 95th percentile emissions rate (in pounds per hour). Hutcheson Test., Tr. Vol. 11-A, 41:3-17,
47:20-48:6, 68:16-24. Mr. Hutcheson calculated the 95th percentile emissions rate in Def. Ex. C,
Tab Sheet1 and the results are shown in columns X and Y of the tab. Hutcheson Test., Vol. 11A, 46:18-47:1.
413.

Mr. Hutcheson’s use of the 95 percentile emissions rate was not based on

anything in the New Source Review rules. Hutcheson Test., Tr. Vol. 11-A, 69:13-70:5. Nor was
it a standardized practice within Ameren. In fact, he used a 97th percentile emissions rate for
nitrogen oxides for the same project. Hutcheson Test., Tr. Vol. 11-A, 78:3-22; Def. Ex. C at Tab
RI U2 W2010 Detail.
414.

In selecting the emissions rate for the capable of accommodating analysis, Mr.

Hutcheson wanted to pick a rate that was “representative of what the unit could accommodate in
122

the baseline.” The value he picked was in the top five percent of emissions rates that the unit
achieved during the baseline period and that the median value would have been the 50th
percentile. He also testified that he “would have no doubt” that there could be a big difference
between the 95th percentile value and the 50th percentile value. Hutcheson Test., Tr. Vol. 11-A,
70:12-71:11.
415.

Mr. Hutcheson did not look to see whether Unit 2 actually ran at the 95th

percentile value for even 24 hours. Hutcheson Test., Tr. Vol. 11-A, 73:8-11.
416.

The 95th percentile calculation that Mr. Hutcheson said was a representative

emissions rate for Unit 2 actually included several hours in which Unit 2 was emitting at a rate
well over what is allowed by its permit. Def. Ex. C at Tab Sheet1 (Column L, Rows 4563-4574
and 4590-4591); Hutcheson Test., Tr. Vol. 11-A, 73:12-21.
417.

By using the 95th percentile emissions rate, Ameren calculated it would have

accommodated about 17,550 tons of SO2. Hutcheson Test., Tr. Vol. 11-A, 67:5-16. That much
annual pollution would be more than Unit 2 had emitted since 1995, when the units were
required to make reductions under the Acid Rain program. Declaration of Steven Whitworth (Pl.
Ex. 926), at p. 10; Hutcheson Test., Tr. Vol. 11-A, 67:20-68:6; Knodel Test., Tr. Vol. 1-A, 56:14.
418.

Mr. Hutcheson testified that had he used an average SO2 emissions rate rather

than the 95th percentile rate, it would “essentially be recalculating the baseline.” Hutcheson
Test., Vol. 11-A, 47:12-14. This is incorrect. Ameren’s capable-of-accommodating calculation
is based on the unit’s availability, not on the actual operation. It calculates the additional
emissions impact from running every hour the unit was available.

123

419.

Had Mr. Hutcheson used the 50th percentile value for the SO2 rate, even Ameren’s

flawed analysis would show the project triggered New Source Review. This can be seen from
Def. Ex. C. Column Y on Sheet1, which has the results of the 95th percentile calculation. The
calculation is linked to the ultimate emissions calculation set forth in Tab Net Emissions Change.
Hutcheson Test., Vol. 11-A, 76:8-24; Def. Ex. C.
420.

When clicking on the interactive formula bar for Cell Y8 in Tab Sheet1, the user

can change .95 to .5 and thus run the calculation using the 50th percentile. After doing so, the
Net Emissions Change tab automatically changes: the capable-of-accommodating number
becomes 197 tons, the net change (the emissions increase) becomes 2,334 tons, and the
spreadsheet indicates that the project triggers New Source Review. Def. Ex. C at Tab Net
Emissions Change (Columns E, G, and I).

3.
421.

No analysis of relatedness

Mr. Hutcheson testified that to assess whether the increase was related to the

project he talked to several people including his boss, Ken Anderson, and Steven Whitworth, the

124

head of the Environmental Services Department. None of the engineers who planned the outage
were involved. Hutcheson Test., Tr. Vol. 11-A, 81:4-16.
422.

Mr. Hutcheson testified that they discussed the heat rate, maximum design rate of

the boiler, and SO2 emissions rate. They concluded that those characteristics would not change
due to the projects and thus any increase was not related to the projects. Hutcheson Test., Vol.
11-A, 49:17-50:21.
423.

In performing the New Source Review analysis for Unit 2, Mr. Hutcheson did not

look at whether availability was expected to increase as a result of the project. He testified that if
the unit was capable of accommodating additional demand, “the availability is not necessarily
relevant” and that it “wasn’t necessary” to look at availability for his analysis. Hutcheson Test.,
Vol. 11-A, 82:16-25.
424.

In contrast to Mr. Hutcheon’s trial testimony, Ameren in fact uses availability

predictions as part of its process to determine how much coal to buy. The company does so
because the more available a unit like Rush Island is, the more it will generate and the more coal
it will need. Naslund Test., Tr. Vol. 6-B, 11:6-16.
425.

Ameren also used availability in the baseline as the basis for its capable of

accommodating calculations. As Mr. Hutcheson explained, the company looked to availability
to determine what the unit was capable of generating before the project. Hutcheson Test., Tr.
Vol. 11-A, 44:9-14, 87:4-12.
426.

In Rule 30(b)(6) testimony, Steven Whitworth, the head of Ameren’s

Environmental Services Department, testified as Ameren’s corporate representative. Mr.
Whitworth testified that he believed emissions that a unit was capable of accommodating are per
se unrelated. In the Rule 30(b)(6) deposition, Whitworth testified that, “The emissions that the
125

unit was capable of accommodating prior to the outage would be totally unrelated to . . . any
activities that occurred on the outage. So just by the nature of the scope, the emissions are
unrelated.” Whitworth Rule 30(b)(6) Dep., Dec. 4, 2013, Tr. 38:4-12; Whitworth Test., Tr. Vol.
11-A, 101:19 – 102:2.
C. Nothing in Ms. Ringelstetter’s Analyses Excuses Ameren’s Failure to Perform
Appropriate NSR Projections
1.

Ms. Ringelstetter failed to address relatedness for either unit

427.

Changes in availability would affect how much the unit was projected to generate.

Ringelstetter Test., Tr. Vol. 11-B, 78:3–9.
428.

Changes in unit capacity would affect how much the unit was projected to

generate. Finnell Test., Tr. Vol. 10-A, 9:7–10.
429.

Ms. Ringelstetter examined selected ProSym modeling files and observed that

Ameren projected changes in the Rush Island units’ availability and capacity following the boiler
work at issue in this case, but testified that those changes had nothing to do with the boiler work.
See, e.g., Ringelstetter Test., Vol. 11-B, 56:10–15.
430.

Ms. Ringelstetter noted that the maximum capacity at Rush Island Unit 2 was

projected to be 11 MW above baseline levels following the boiler upgrades, but she attributes the
capacity increase entirely to the LP turbine work performed in 2010. Ringelstetter, Vol. 11-B,
17:20–24 & Ameren’s Summary Exhibit XF_2 (indicating 11 megawatt increase).
431.

However, her baseline capacity number is not a measure of the unit’s actual

performance based on operating data; rather it is a reported number that tracks Ameren’s
Capability Tables. Ringelstetter Test., Tr. Vol. 11-B, 73:12–74:9.

126

432.

Ameren’s documents and witnesses stated that the company’s 2005 Capability

Tables were “unrealistically high” and were later adjusted downward significantly in February,
2006. Finnell Test., Tr. Vol. 10-A, 5:23–8:23 (discussing Plaintiff’s Exhibit 892 and updates to
Ameren’s 2006 fuel budget modeling which show adjustments from the “unrealistically high”
610 MW to values between 581-596 MW). Since Ameren’s selected baselines for both units
include substantial amounts of 2005, Ms. Ringelstetter’s 11 MW number significantly
understates the projected capacity increase at Unit 2 compared to Ameren’s documents and data.
FOF 157, 289, 299, 300, 301.
433.

Ms. Ringelstetter further testified that Ameren’s ProSym models projected an

increase in availability at each unit following the boiler upgrades, but stated that the increase is
not substantial enough to appear to be a meaningful difference, and so discounts it entirely for
her emissions assessment. Ringelstetter Test., TR. Vol. 11-B, 17:4–12.
434.

Ms. Ringelstetter discounted these increases even though the availability forecast

for Ameren’s economic justification of the work at Unit 2 was fine-tuned to the tenth of a
percent, and even that tiny variation meant hundreds of thousands of dollars dropped out of the
analysis. June 15, 2009 Email (Pl. Ex. 895), Meiners Test., Tr. Vol. 7-B, 34:9-35:25.
435.

Ms. Ringelstetter offered no opinion on how—if at all—the projects at issue in

this case would have been expected to change the operations of the Rush Island units.
Ringelstetter Test., Tr. Vol. 11-B, 59:23–60:3.
436.

Nor did Ms. Ringelstetter offer any independent opinion on whether or to what

extent the low pressure turbine replacement that occurred at Rush Island Unit 2 alongside the
boiler modifications had any impact on unit operations or performance. Ringelstetter Test., Tr.
Vol. 11-B, 60:4–9.
127

437.

As such, all of her emissions analyses—and all of the emissions she concludes

should be excluded from the emissions projection—rest on the assumption that none of the
projected emissions increases were caused or enabled by the projects at issue in this case.
Ringelstetter, Tr. Vol. 11-B, 18:9–11 & 22:2–9.
438.

When she developed her calculations for her expert report, Ms. Ringelstetter

believed it was irrelevant whether the projects at issue in this case resulted in performance
improvements. Rather, by her calculations, the only thing that mattered for the demand growth
exclusion was whether the unit “could have accommodated” the projected emissions levels
during the baseline. Ringelstetter Test., Tr. Vol. 11-B, 77:2–17.
2.

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

439.

Background regarding ancillary services

Ancillary services are things other than simple electric generation that utilities

provide to keep the electric grid operating reliably. Generally they involve promises that certain
amounts of generation will be held in reserve or would be dedicated to real-time adjustments in
response to market fluctuations. When a unit was providing some ancillary services, it would
typically not be operating at its full capabilities. Hamal Test., Tr. Vol. 9-A, 23:4–6; Haro Test.,
Tr. Vol. 9-A, 99:21–100:13.
440.

On January 1, 2007, Ameren Missouri entered into a short term contract to

provide ancillary services to its Illinois affiliates. Def. Ex. HX. That contract was to last “from
January 1, 2007 until the earlier of (i) December 31, 2007, or (ii) the date during calendar year
2007 on which the Midwest Independent Transmission System Operator, Inc. (“Midwest ISO”)
ancillary services market for Ancillary Services is operational.” Def. Ex. HX at 1.

128

441.

The short-term contract was later renewed when the launch of MISO’s ancillary

service market was further delayed. Haro Test., Tr. Vol. 9-A, 133:24–134:7.
442.

The contract did not specify how much of the ancillary services described in the

contract would be provided by Rush Island units or how often the units would be assigned to
provide those services. Def. Ex. HX at Article 3, § 3.1.1 and Schedule A.
443.

As of January 2009, ancillary services such as regulation hours and spinning

reserves were offered into—and cleared through—MISO’s ancillary services market. Hamal
Test., Tr. Vol. 9-A, 43:10–12; Ringelstetter Test., Tr. Vol. 11-B, 95:10–14.
444.

As Mr. Hamal explained: “In order to provide [ancillary services], you can’t be at

full load. You have to back off. You have to be at partial load. And so when prices are really
high, I’d rather have a high-cost unit at partial load than a low-cost unit.” Hamal Test., Vol. 9-A,
24:11–15.
445.

The Rush Island units would not be expected to provide ancillary services once

MISO’s ancillary service market was implemented. Ameren’s contract for ancillary services was
never intended to extend beyond when MISO’s ancillary services market started up in 2009.
Haro Test., Vol. 9-A, 102:1-14, 134:4-7.
446.

The MISO ancillary services market helped optimize the provision of ancillary

services like regulation and spinning reserves: “it allow[ed] MISO to look at the fact that not
only is that unit providing regulations, but it’s not providing energy. So if that’s a low-cost unit
providing regulation, there may be a high-cost unit that could provide that regulation and save
the system money overall.” Hamal Test., Tr. Vol. 9-A, 24:5–10.
447.

Since the Rush Island units are relatively-low cost units that run all the time,

(Hamal, Tr. Vol. 9-A, 26:16–17), the implementation of the MISO ancillary services market
129

meant they would be “held back” little if any to provide ancillary services once those services
were cleared through the market system. Hamal Test., Tr. Vol. 9-A, 24:20–24.
448.

Ameren’s chief modeler, Mr. Timothy Finnell, explained that in order to model

ancillary services like regulation hours or spinning reserves in ProSym, Ameren would inflate a
unit’s partial outage rate, thereby depressing the unit’s availability in the model. That would, in
effect, lower the output of the units that were assigned to regulation in the model. Finnell Test.,
Tr. Vol. 9-B, 99:3–7; see also Ringelstetter Test., Tr. Vol. 11-B, 62:4–63:17.
449.

Mr. Finnell admitted that assigning units regulation hours or ancillary services in

the model would affect how much generation they were expected to produce and how much coal
they were expected to burn in the forecast years. Ameren modeled ancillary services by
increasing a unit’s partial forced outage rate. Increasing the forced outage rate results in reduced
generation and coal burned in the model. Finnell Test., Tr. Vol. 9-B, 99:3–100:19.
450.

In 2008, Mr. Finnell, then head of Operations Analysis in Ameren’s Corporate

Planning Department and in charge of the company’s ProSym modeling, testified before the
Missouri Public Service Commission about how the sale of ancillary services impacted the
company’s business forecasts:
Q.
Is AmerenUE selling ancillary services to the utility operating
subsidiaries owned by Ameren Corporation in Illinois?
A.
Yes, for 2008, AmerenUE is selling 39 MW of spinning reserves
and 68 MW of supplemental reserves to Illinois affiliates.
Q.
Does the PROSYM model include the sales of ancillary services to
these Illinois utilities?
A.
No. The sales of these ancillary services were not included
because they are based on a short-term contract that will end when the MISO
ancillary service market begins.
130

Finnell MPSC Test. (Pl. Ex. 439), at 12:16–23.
451.

Neither of Ameren’s two experts hired to discuss dispatch and market issues

quantified how the provision of ancillary services influenced Rush Island operations before the
projects were performed or once the modifications were completed. Mr. Hamal “didn’t get into
the details and quantify how much regulation Rush Island did,” focusing instead on the general
market structure. Hamal Test., Tr. Vol. 9-A, 44:3-5. Ms. Ringelstetter, despite offering an
opinion that Ameren’s modeling of ancillary services was “entirely appropriate,” (Ringelstetter
Test., Tr. Vol. 11-B, 66:4–6), did not mention ancillary services, regulation hours, or spinning
reserves in her expert report, nor was she aware of any “specifics” regarding Ameren’s shortterm ancillary service agreements. Ringelstetter Test., Tr. Vol. 11-B, 66:10–67:10.
b.
452.

Ms. Ringelstetter’s modeling choice

For the analysis in which she concludes that projected emissions would not

increase following the Unit 1 modification work, Ms. Ringelstetter uses a ProSym modeling
effort that includes two artificial adjustments.
453.

First, the ProSym modeling run that Ms. Ringelstetter used when assessing the

2007 project at Rush Island 1 included an input for that unit which was intended to reflect its
provision of ancillary services. Despite the short-term nature of the services as described above,
she used a run where Unit 1 was modeled as holding back 15 MW for regulation hours for every
year of the model forecast, 2007 through 2012. Ringelstetter Test., Tr. Vol. 11-B, 63:18–64:2;
see Hausman Test., Tr. Vol 4-B, 97:3-9.
454.

Second, Ms. Ringelstetter claims the modeling effort suffered from what she calls

a bias in the inputs which requires a downward adjustment to the model’s projections. However,

131

Ameren never performed such an adjustment when it did its own analyses, and in fact other
modeling efforts did not suffer from this bias. Hausman Test., Tr. Vol. 4-B, 98:9–99:12.
455.

Without either of these adjustments, Ms. Ringelstetter’s analysis would show a

significant projected increase in Rush Island 1 operations and pollution above baseline levels.
Hausman Test., Tr. Vol. 4-B, 99:13–23.
VI.

THE 2007 AND 2010 BOILER UPGRADES TRIGGERED TITLE V
REQUIREMENTS
456.

The Clean Air Act Title V permit for the Rush Island Plant contains a condition

restating the requirement that Ameren was prohibited from performing any unpermitted major
modifications of Rush Island Units 1 or 2. Declaration of Steven Whitworth (Pl. Ex. 926), at
attached Title V Permit, AM-02511339-2511393, at 2511362.
457.

Ameren has not obtained a permit for its major modifications, and the Rush Island

Title V permit does not incorporate PSD requirements for its major modifications. Pl. Ex. 926,
at attached Title V Permit, AM-02511339-2511393, at 2511348-350 (Listing no Unit Specific
Emission Limitations for SO2).
CONCLUSIONS OF LAW
I.

OVERVIEW
Under the Clean Air Act’s PSD program, an existing source of pollution must obtain a

permit and install state-of-the-art emissions controls when the source makes a “major
modification.” Ameren SJ Decision, 2016 WL 728234, at *4. The United States claims Ameren
violated the PSD program’s requirements by making major modifications to Units 1 and 2 at
Rush Island without obtaining applicable permits or installing required emissions controls. The
only disputed element of proof is whether the projects performed on Units 1 and 2 were “major
132

modifications” under the law. See Subsection II.A (other elements of proof undisputed). To
prove a major modification, the United States must show the work at issue was (1) “a physical
change or change in method of operation that (2) would result in a significant net emissions
increase.” Ameren SJ Decision, 2016 WL 728234, at *2 (citing 40 C.F.R. §52.21(b)(2)).
For the purposes of the first prong of the test, the term “physical change” is extremely
broad, and there is no dispute that the projects were physical changes. Id. at *4. But not all
physical changes trigger PSD permitting requirements. Routine maintenance, repair, and
replacement projects are excluded from the definition of “major modification.” Id. Ameren
argues the challenged Rush Island projects were routine maintenance projects and as a result
exempt from being considered “physical changes.” Subsection III.A below explains why the
challenged projects are not routine maintenance.
For the purposes of analyzing the second prong of the test, Subsection II.B below
explains that the projects would be expected to result in—and did result in—a significant net
emissions increase. Because the projects were physical changes that would result and did result
in a significant net emissions increase, they were major modifications under PSD.
Because the United States has proved the Rush Island projects were major modifications,
Ameren violated the PSD provisions of the Clean Air Act because it did not obtain the required
permits or meet other PSD requirements before beginning construction. In addition, as explained
in Subsection II.C below, Ameren also violated the Title V provisions of the Clean Air Act.
II.

THE UNITED STATES PROVED THAT AMEREN VIOLATED THE
PREVENTION OF SIGNIFICANT DETERIORATION AND TITLE V
PROVISIONS OF THE CLEAN AIR ACT
A. Undisputed Elements of Proof

133

The only disputed element of proof is whether the projects were major modifications
under the law.
There is no dispute that:


Ameren is a “person” under the applicable law and the owner and operator of the
Rush Island facility. 42 U.S.C. 7602(e) and 10 C.S.R. 10-6.020(2); FOF 2.



Rush Island Units 1 and 2 are each a “major emitting facility,” a “major stationary
source,” and an “electric steam generating unit” under the applicable PSD and Title V
provisions. 42 U.S.C. § 7479(1), 40 C.F.R. § 52.21(b)(1) and (b)(31); FOF 13.



EPA provided sufficient pre-filing notice of the violations to Ameren and the State of
Missouri and provided notice of the filing of this case to the State. 42 U.S.C. §
7413(a), (b); FOF 18-21.



At the time of the projects, Rush Island was in an area designated as attainment for
SO2. 42 U.S.C. § 7471; FOF 11. Therefore the PSD program applies.

B. The Projects Should Have Been Expected to Cause—and Did Cause—Emissions
Increases
1.

Legal standard

There are two ways to establish PSD liability. The United States can satisfy its burden by
proving either that: (1) the source should have expected an emissions increase related to the
project (the expectations approach); or (2) an emissions increase related to the project actually
occurred (the actual emissions approach). Ameren SJ Decision, 2016 WL 728234, at *16; see
also 40 C.F.R. § 52.21(a)(2)(iv)(b), (c).
Regulations establish how to compare pre- and post-project emissions. The pre-project
“baseline” is any 24 consecutive months in the 5 years before the project. 40 C.F.R.
§52.21(b)(48)(i). The post-project period is the maximum annual emissions in any one of the
five years after the project. 40 C.F.R. §52.21(b)(41)(i). The difference between the baseline and
post-project high emissions year is the emissions increase for PSD purposes. An increase of 40
134

tons or more of SO2 per year is “significant” under the regulations. 40 C.F.R. §52.21(b)(23)(i).
In this case, there is no evidence of any creditable emissions decreases, so any emissions
increase proven is the same as the net emissions increase. See 40 C.F.R. § 52.21(b)(3).
Under the expectations approach, courts must determine what a source should have
expected at the time of the project. To prevail, the United States “must show that at the time of
the projects [defendant] expected, or should have expected, that its modifications would result in
a significant net emissions increase.” Ameren SJ Decision, 2016 WL 728234, at *13 (citing
cases and quoting United States v. Ala. Power Co., 730 F.3d 1278, 1282 (11th Cir. 2013)
(internal quotations omitted)).
Ameren’s internal documents are relevant to what the company expected or should have
expected. See, e.g., Ala. Power, 730 F.3d. at 1286-87; United States v. La. Generating LLC, 929
F. Supp. 2d 591, 593-594 (M.D. La. 2012) (“The documents clearly show outages were a
problem and the company planned to work on the reheaters in order to fix those problems.”);
Ohio Edison, 276 F. Supp. 2d at 834 (“The documents prepared to justify the expenditures
described the various purposes of the projects to include replacement of major components to
increase the life and the reliability of the units.”).
Under the actual emissions approach, the question is simply whether SO2 emissions
actually increased by more than 40 tons per year as a result of the project.
Under either approach, additional operations made possible by a project must be
attributed to that project. As EPA has explained, “where the proposed change will increase
reliability, lower operating costs, or improve other operational characteristics of the unit,
increases in utilization that are projected to follow can and should be attributable to the change.”
61 Fed. Reg. 38,250, 38,268 (1996). A series of court decisions have echoed this requirement.
135

“If an increase in hours of operation is caused or enabled by a physical change, the increased
hours must be included” in the projection. Duke Energy 2010, 2010 WL 3023517, at *5; see
also Duke Energy 2007, 549 U.S. at 577-78 (noting regulatory provision that requires assessing
number of hours the unit is or probably will be running); Ala. Power, 730 F.3d at 1281; United
States v. Cinergy Corp., 458 F.3d 705, 710 (7th Cir. 2006) (revitalizing a plant to operate more
hours may trigger PSD obligations); Ohio Edison, 276 F. Supp. 2d at 834-35 (finding PSD
liability for projects that were “intended to result in increased hours of operation as a result of a
reduction in . . . forced outages”).
Even when there is evidence that emissions will or did increase after a project, a source
may demonstrate that the increased emissions should be excluded from PSD review under the
“demand growth exclusion.” Under the demand growth exclusion, a source must exclude from
its calculations:
any emissions increases that “an existing unit could have accommodated during
the consecutive 24–month period used to establish the baseline actual emissions . .
. and that are also unrelated to the particular project, including any increased
utilization due to product demand growth.” 67 Fed.Reg. at 80,277 (codified at 40
C.F.R. § 52.21(b)(41)(ii)(c)).
New York v. U.S. E.P.A., 413 F.3d 3, 31 (D.C. Cir. 2005) (“New York I”). After substantial
argument about the application of the demand growth exclusion at summary judgment, I
explained its application as follows:
if emissions increase because a project enables the unit to meet previously unmet
demand during peak hours, for example, those emissions increases are likely
related to the project and therefore do not qualify for the demand growth
exemption. . . if the unit undergoes modifications that allow it to run more during
the daytime hours tha[n] it could before, it cannot be said that the increased
emissions were merely a coincidence or unrelated to the modification.
Ameren SJ Decision, 2016 WL 728234, at *10.
136

Finally, Congress intended for the PSD rules to “have broad application.” Id. (citing Ala.
Power Co. v. Costle, 636 F.2d 323, 399-400 (D.C. Cir. 1979)).
2. The evidence shows that Ameren should have expected an emissions increase related
to each project, and such an emissions increase occurred
The core facts of this case show that before Ameren performed the challenged projects,
problems with the components at issue were limiting the units’ performance. Replacing those
components would improve performance and result in additional use and pollution. That was
what Ameren should have expected before the work began. The evidence shows that is what
Ameren did expect. The evidence also shows that is exactly what happened.
Two key—and undisputed—characteristics of the Rush Island units underlie the entire
discussion of emissions increases. First, the Rush Island units are big sources of pollution. That
means even small performance improvements can enable a 40-ton increase in SO2. For example,
there is no dispute that it only takes an additional 21 hours of operations at full power for a Rush
Island unit to emit more than 40 tons of SO2. FOF 190.
Second, the Rush Island units are “baseload” units. FOF 6. They are relatively cheap
sources of electricity. FOF 50. The market for electricity, which puts a premium on price,
drives these baseload units to operate as much as they can. Id. That means the Rush Island units
run every hour they are available—and at high or even maximum levels during hours of “peak”
demand. FOF 6, 371-372. Moreover, Rush Island’s baseload status means that if the units
improve their performance in any way that allows them to generate more electricity, the market
will call on the units to generate more electricity. FOF 50, 215. As Ameren’s retired executive
Charles Naslund explained at trial, Ameren plans its coal purchases based in part on availability
projections because the company knows that the more available the Rush Island units are, the
137

more they will run. FOF 424. That additional generation requires additional coal—and means
additional pollution. FOF 205.
These two facts lead to a logical conclusion: if the Rush Island units are upgraded so they
can generate more electricity, they will. Performance improvements have a direct impact on
annual generation and pollution levels. Ameren’s witnesses and documents recognize this
simple relationship. FOF 424, 427-428, 448. And using Ameren’s computer modeling software,
United States’ expert Ezra Hausman illustrated that a mere one-megawatt improvement in unit
capacity would lead to an additional 23 tons per year of SO2 pollution and that a one percent
improvement in unit availability would result in about 150 extra tons of SO2 per year. FOF 336337, 339-41. Ameren should have expected the Rush Island boiler upgrades to result in at least
an additional 40 tons of SO2 pollution—and that is exactly what happened.
a.

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

Before the projects, the components at issue were causing outages and deratings at
Unit 1. FOF 47-88. Ameren’s availability data showed that the economizer, reheater, lower
slope tubes, and air preheater were the predominant cause of availability losses at the unit, so
Ameren decided to replace them with redesigned components. FOF 136, 138-139, 222-223. The
decision to replace these components was the result of a lengthy and deliberate process and was
ultimately approved by a series of managers and executives, culminating with the Ameren parent
company CEO. FOF 136, 177. One of the bases of that approval was the expectation that the
replaced components would cause no outage time for 20 years following the projects. FOF 38,
145-149. Looking at the unit as a whole, Ameren expected that Unit 1’s long-term availability

138

would increase to 95% after the work was done, about a 3% increase compared to the PSD
baseline. FOF 228.
The United States’ expert Robert Koppe did his own analysis of how the project would
affect Unit 1’s performance. Mr. Koppe is a power plant engineer who has spent much of his
career analyzing the performance of generating units on behalf of utilities and public service
commissions using methodologies that courts have consistently found to be reliable. FOF 90-91;
see, e.g., United States v. Cinergy Corp., 623 F.3d 455, 459 (7th Cir. 2010); United States v.
Ohio Edison Co., 276 F. Supp. 2d 829, 877 (S.D. Ohio 2003). Mr. Koppe analyzed the problems
affecting Rush Island during the baseline period and determined what Ameren should have
expected to result from the work it did in the 2007 and 2010 outages. FOF 195.
Mr. Koppe started by identifying all the outage hours and deratings attributed to the
components at issue during the baseline. He found that the equivalent availability losses due to
the four components at issue totaled 336 hours in the baseline period, about half the unit’s total
outage time.4 FOF 197, 222. Importantly, Mr. Koppe also looked at the condition of the unit as
a whole and the other work performed during the 2007 outage. FOF 197-198. As Mr. Naslund
explained at trial, Ameren was working hard to address any potential future problems during the
outage. FOF 199. Mr. Koppe concluded that the other work performed during the 2007 outage
would prevent availability from declining due to other potential issues. FOF 255. He also
4

Ameren claims that Mr. Koppe and Dr. Sahu should have accounted for derates
differently. This portion of Ameren’s criticism has to do with what is known in the industry as a
“utilization factor” and whether Mr. Koppe and Dr. Sahu should have used a different utilization
factor for deratings than they did for outages, as Ameren’s expert Marc Chupka testified he
would have done. But Mr. Chupka is an economist, not a power plant engineer, and Dr. Sahu’s
use of a single utilization factor for both outages and deratings is exactly what the Electric Power
Research Institute (“EPRI”) has recommended since the 1980s. FOF 210. In fact, except for the
purposes of this litigation, Ameren instructs its engineers to do the very same thing. FOF 210.
139

concluded that the project would completely eliminate availability losses from the components at
issue and result in an availability improvement of 3.8% from the baseline, bringing Unit 1’s
availability to about 96% post-project.5 FOF 224-225, 227. Mr. Koppe concluded—and
Ameren witnesses and documents confirm—that availability would not have increased at all if
these problematic components had not been replaced. Rather, it would have gotten worse. FOF
227, 231, 239, 255.
Dr. Ranajit Sahu, a permitting engineer and expert for the United States, took Mr.
Koppe’s findings on expected improved availability and used them to calculate the expected
additional pollution that would result from the improvements, using a methodology that has been
recognized as industry-standard by several courts. See, e.g., Ala. Power, 730 F.3d at 1284-85;
La. Generating, 929 F. Supp. 2d at 596. Dr. Sahu concluded, as Ameren did, that the company
would utilize the regained hours at the same proportion as it had in the past. FOF 206, 208.
Based on his and Mr. Koppe’s analyses, Dr. Sahu calculated an expected increase in emissions of
608 tons of SO2 post-project for Unit 1. FOF 232. Because Dr. Sahu’s calculation was based on

5

Ameren argues in its post-trial brief that Mr. Koppe testified that it would not be
reasonable to expect the units could achieve over 95% availability post-project because “things
happen” and “other components can fail.” Ameren then argues that an increase to 95% at Unit 1
is no significant increase at all because Unit 1 had a baseline availability of 94.7%. There are
two major flaws with this argument. First, Mr. Koppe did not testify that the units would not be
expected to achieve over 95% availability; in fact, he testified that Ameren should have expected
“the fairly long-term average equivalent availability” to reach about 95%, but “the best
performance post-project” (which is the relevant measure) “would be more like 97 or 98
percent.” Koppe Test., Tr. Vol. 3-A, 79:7-14. Second, Ameren’s argument that there was no
expected significant availability increase only works if its suggested baseline availability figure
of 94.7% is accepted. That figure is at odds with Mr. Koppe’s well-supported calculation that
Unit 1’s baseline availability was actually 92.1%. Ameren’s calculations appear to be based on
the exclusion of certain GADS events from its performance data, but Ameren offered no
testimony at trial to support that approach.
140

the additional operation allowed by the project, the entire predicted increase is related to the
work. Id.
Post-project results confirm Mr. Koppe and Dr. Sahu’s calculations. In 2008, Unit 1 set
its record availability with the best availability in the entire Ameren system. FOF 234; see also
FOF 236. As Mr. Koppe and Ameren both expected, all the outages and deratings due to the
replaced components were eliminated. FOF 237. Availability during the highest post-project
emissions year reached 96.4%, which is 4.3% higher than the baseline. FOF 238. The entire
expected improvement related to the project (3.8%) was realized. That improvement was an
order of magnitude more than the 0.3% increase needed to result in 40 additional tons of SO2.
FOF 191. The chart below shows the baseline availability losses caused by the components at
issue (orange) and caused by all other factors (blue). After the work was completed, Unit 1’s
actual availability climbed to 96.4% and it did not experience any losses due to the new

Equivalent Full Power Hours Lost

components and actual availability. FOF 237–38.

700

Rush Island Unit 1

600
500

Other Losses
Modified Component Losses

3.8% EAF
Availability

[VALUE]

400
300
200

354.9

314.5

Baseline

Post-Project

100
0

EAF:

92.1%

96.4% (+ 4.3%)

141

With the availability improvement came an actual increase in emissions of 665 tons of
SO2. FOF 664. Those additional tons were made possible by the availability improvement and
are related to the project. FOF 239.
At trial, Ameren sought to exclude any testimony from Mr. Koppe and Dr. Sahu on the
cause of the actual increase. As discussed below (see Subsection I.A on Evidentiary Issues), I
am denying Ameren’s motions to strike this testimony because I find that the challenged
opinions were properly disclosed. But even without the challenged testimony, the evidence
shows an actual and significant net increase of emissions related to the project for both units.
Ameren has not challenged the admissibility of the testimony by Mr. Koppe and Dr. Sahu that:


An availability improvement of just 0.3% or an additional 21 hours of operation
would cause a more than 40 ton-increase in pollution.



The work would eliminate all availability losses due to the components, increase
overall availability by far more than 0.3%, and increase pollution.6



Post-project data shows those predictions came true: there were no component losses
of any kind in the post-project year, availability improved by much more than 0.3%,
the unit operated hundreds of hours more, and pollution increased.

FOF 267. Mr. Koppe and Dr. Sahu made a prediction based on improved unit performance, and
the actual data confirmed those predictions. As Mr. Koppe explained at trial:
[If] half of all the outage time that’s occurring is eliminated by the projects and
the effect of all the other equipment in the unit stays the same . . . then the
availability of the unit as a whole increases, and it increases specifically because
the projects have eliminated boiler tube leaks in these sections and have
eliminated the effects of pluggage.
***
The causation of what actually happened is obvious from the—from the data.
Koppe Test., Tr. Vol. 4-A, 115:18-25, 4-B, 18:1-4.
6

Ameren concedes that Unit 1 availability was projected to increase by 1.3%. Ameren
Br. at 5 (Doc. 835).
142

Here, based on the substantial and credible evidence presented showing how the project
would cause improvements in availability and, as a result, increase emissions, I am able to find,
even without explicit expert testimony, that the predicted cause of the increase was the cause of
the actual emissions increases. See, e.g., United States v. Crenshaw, 359 F.3d 977, 988 (8th Cir.
2004) (citing Jackson v. Virginia, 443 U.S. 307, 319 (1979) (noting court authority “to draw
reasonable inferences from basic facts to ultimate facts”).
b.

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

The background story of Unit 2 is the same as Unit 1. Unit 2 had the same problems with
the components at issue limiting the unit’s availability in the time leading up to the outage. As
with Unit 1, Mr. Koppe analyzed the expected impact of the 2010 project on Unit 2’s
availability. FOF 47–88, 145–47, 197–98. Mr. Koppe found that the outages and deratings at
Unit 2 caused by the economizer, reheater, and air preheater resulted in about 245 equivalent lost
hours during the baseline, slightly more than half the total lost operating time. FOF 247. As
with Unit 1, Mr. Koppe examined the overall condition of Unit 2 and found that other work
performed during the outage would prevent availability from getting worse and that the
component replacements would result in an availability improvement. FOF 251. For Unit 2, he
predicted that the project would completely eliminate all of the losses due to the three
components at issue and, by itself, would improve Unit 2’s availability by 2.8%. FOF 248, 251.
None of these improvements would be possible if Ameren had not replaced the reheater,
economizer, and air preheater. Rather, without the project, availability at Unit 2 would have
decreased, not increased. FOF 255.

143

Ameren argued at trial that availability could never increase beyond 95%. But former
plant manager Robert Meiners agreed with Mr. Koppe and Dr. Hausman that the long-term
availability forecast of 95% meant individual years would be as high as 97% or 98%. FOF 257.
As noted above, the relevant PSD inquiry compares the baseline emissions to the year with the
highest amount of projected emissions in the five-year post-project period. Tellingly, Ameren
already knew that Unit 1 set an availability record after the 2007 project of nearly 97% in 2008.
FOF 254. When seeking re-approval of the Unit 2 project in 2009, Ameren’s engineers
explicitly stated they expected Unit 2 to perform “at least equal to, if not better than,” Unit 1 and
expected a 3‒4% availability improvement. FOF 256. Mr. Meiners confirmed this at trial,
testifying that the availability input used in financially justifying the Unit 2 outage to senior
company executives was almost 97%. FOF 253.
The post-project data shows that Unit 2’s availability actually reached 97.4% in the
highest year after the project. FOF 260. As Ameren’s trial witness Scott Anderson testified after
reviewing Unit 2’s historic availability statistics, the difference between the pre- and post-project
performance was “night and day.” FOF 261. Comparing the baseline to the post-project year,
Mr. Koppe predicted an availability improvement of 2.8% due to the project alone, and Ameren
actually got an improvement of 2.9%. FOF 259. The components at issue caused no availability
losses after the project, as Mr. Koppe predicted. Id. As with Unit 1, the availability
improvements far exceeded the small changes that would cause Unit 2 to emit 40 additional tons
of SO2.
The chart below shows the baseline availability losses caused by the components at issue
(orange) and caused by all other factors (blue). After the work, there were no losses due to the
new components and actual availability climbed to 97.4%. FOF 259–60.
144

Equivalent Full Power Hours Lost

500

Rush Island Unit 2

400

243.2

Other Losses
Modified Component Losses

2.8% EAF

300
200

236.0

227.5

Baseline

100

Post-Project

0

EAF:

94.5%

97.4% (+ 2.9%)

Based on Mr. Koppe’s prediction of regained availability, and using the method
described above, Dr. Sahu calculated an expected increase of 415 tons per year of SO2 in Unit 2
that would result from the availability improvement alone. FOF 258.
Separate from the expected increase in emissions based on availability improvements,
Ameren also should have expected an emissions increase at Unit 2 based on capacity
improvements. After the Unit 1 outage, Ameren saw a significant capacity gain as a result of the
project. FOF 269. Ameren and Mr. Koppe both analyzed how a similar capacity gain would
affect Unit 2’s post-project operation.7 8
There is no dispute that Ameren realized a gain in capacity, measured in megawatts
(“MW”), at Unit 1. FOF 269–70, 274. Ameren expected similar improvement at Unit 2. Id. In

7

In addition, Ameren replaced the low pressure turbine during the 2010 outage, which
would also be expected to affect performance.
8

Ameren argues that Mr. Koppe and Dr. Sahu’s analyses double count the effect of
deratings already accounted for in its availability analysis in its capacity analysis, but Dr. Sahu
clearly presented separate emissions calculations for the availability and capacity increases. FOF
258, 302-303. See also US Br. at 26 n.16 (Doc. 838).
145

a series of company documents from Fall 2007 until the time of the overhaul, Ameren engineers
repeatedly stated that significant capacity increases (of up to 30 MW) would result from the
boiler work. FOF 269–78. That expectation was included in the documents presented to
corporate executives seeking approval of the Unit 2 project. That expectation was even used to
calculate how the project would impact Ameren’s shareholders and ratepayers. FOF 158, 276.
For instance, in the justification for the outage work that was presented to Ameren’s executives,
the company’s engineers explained exactly what benefits they assessed in determining the
projected value of the project. The first benefit listed is “30 MW gain in summer (3 mos), 20
MW gain balance of year from reheater, economizer and APH [air preheater] investment.” Pl.
Ex. 110 at AM-02465690 (emphasis added); FOF 277.
As he did for availability, Mr. Koppe independently studied the data and information
produced by Ameren and reached a conclusion similar to what Ameren’s engineers found before
the Unit 2 outage. Mr. Koppe confirmed that pluggage had limited Unit 2’s capability during the
pre-project period and that Ameren should have expected at least 22 MW of increased capability
due to the boiler work. FOF 279. Another 12-15 MW of capability would result from the new
LP turbine. FOF 280. Dr. Sahu calculated that an 18 MW capacity increase due to the boiler
project alone would increase emissions by 417 tons of SO2. FOF 303.
The post-project data confirmed the results of Mr. Koppe’s analysis. In fact, Ameren
reported its improved capacity to MISO, the North American Electric Reliability Council, and
the Missouri Public Service Commission, among other outside entities, each time attributing a
major portion of the unit’s capacity increase to the boiler work at issue. For example, Ameren
responded to an inquiry from the Missouri Public Service Commission in a rate case related to
the Unit 2 2010 outage. In defending its requested rate increase, Ameren stated that unit
146

capability improved by 34 MW, of which 22 MW were restored capacity. FOF 288–89.
Similarly, Ameren reported that Unit 2’s summertime peak capability had increased to nearly 650
MW gross “due to work completed during the 2010 major outage (replacement of lower pressure
turbines and numerous boiler modifications).” FOF 287 (emphasis added).
Ameren’s post-project reports are quite similar to what Mr. Koppe found in reviewing the
post-project data. Mr. Koppe first analyzed Ameren’s “Plant Information” database and
determined that Unit 2’s capability had increased by 38 MW, from 615 MW during the preproject period9 to 653 MW afterwards. FOF 296–99. An almost identical increase is observed
by comparing Ameren’s “full load” test reports. The average capability reported by Ameren in
those reports increased by 37 MW, when comparing baseline (620 MW) and post-project (657
MW) periods. FOF 295, 301.
Of the overall increase in capability, Mr. Koppe determined that about 23 MW of the
increase were due solely to the component replacements and would require more coal to be
burned. FOF 300. Ameren’s documents show that it had reached the same conclusion. The
predicted and actual capability increases Mr. Koppe reports are right in line with what Ameren
used in its financial justification for Unit 2 (22.5 MW) and far more than the 1.7 MW that would
result in 40 additional tons of SO2.
Based on the performance improvements predicted by Mr. Koppe, Dr. Sahu calculated
increases of more than 400 tons of SO2 due to either the availability increase or the capacity
increase alone. FOF 258, 303. Both the availability and capacity improvements Mr. Koppe
predicted were borne out by actual data. FOF 237–38, 259–60. After the 2010 project, overall
9

Because Ameren did not produce complete Plant Information data from before 2006,
Mr. Koppe used January 2006-December 2007 for the pre-project period, since that was closest
in time to Ameren’s baseline.
147

emissions of SO2 from Unit 2 increased by 2,171 tons per year. FOF 266. As a result, the actual
emissions increase includes increases resulting from the availability increase and the capacity
increase. Each is an order of magnitude larger than the PSD significance threshold.10
3.

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

The conclusions of Mr. Koppe and Dr. Sahu are further supported by Dr. Hausman’s
analysis of Ameren’s computer modeling efforts. Dr. Hausman is a modeler and market
consultant with nearly 20 years of experience focused on the electric industry.
Ameren uses a sophisticated computer modeling program called ProSym to predict the
operations of its generating fleet—including the Rush Island units—so it can plan accordingly.
FOF 314–15. Ameren uses ProSym modeling for a number of things, including rate recovery
proceedings before the Missouri Public Service Commission, fuel purchasing and planning, and
informing capital investment decisions. FOF 315. Ameren has testified to the public service
commission that its use of ProSym is “very well calibrated” and gives reliable projections of
future unit performance. Plaintiff’s Exhibit 439.
In the lead-up to the Rush Island overhaul projects—and in the normal course of its
business—Ameren used ProSym to model and predict the Rush Island units’ fuel needs (“heat
input” in the industry parlance) for the years after the 2007 and 2010 major boiler outages. FOF
318–19, 329. Dr. Hausman performed two types of analysis based on Ameren’s modeling. First,
Dr. Hausman examined how varying specific inputs, such as the units’ availability parameters or

10

As noted in the discussion of Unit 1, even if I were to exclude testimony on actual
emissions causation from Mr. Koppe and Dr. Sahu, which I will not, I can connect the dots
myself to find the predicted—and realized—improvements caused the predicted—and realized—
emissions increase.
148

maximum capacity values, would affect the model’s projections for that unit’s future
performance. FOF 330–31. In effect, he investigated whether, and to what extent, the Rush
Island units would actually use extra operating hours or extra capacity if the units were
improved. The model that Ameren used routinely to simulate its units’ operations showed that if
Ameren increased the number of hours its Rush Island units were able to run, or if the company
enabled the units to operate at higher output levels during those hours, then the units would take
advantage of those performance enhancements, burning more coal and, as a result, emitting more
pollution. FOF 332. In fact, the models showed that both a unit’s capacity level and its
availability are linearly related to the unit’s projected coal consumption. Id.
The results of the ProSym runs confirm the admissions by Ameren’s witnesses:
performance improvements like capacity increases or availability gains would lead to additional
operations and additional pollution. FOF 427–28. Dr. Hausman’s sensitivity analyses quantify
those relationships.
The following chart provides the results of Dr. Hausman’s sensitivity analyses. Dr.
Hausman ran several iterations of Ameren’s ProSym model to identify what changes in forced
outage rates, partial outage rates, and capacity would mean for coal consumption and pollution.
FOF 334–41.
∆ Coal Consumption
(Billion BTU)

∆ SO2 Pollution
(tons per year)

Forced Outage Rate (per 1%)

481

162

Partial Outage Rate (per 1%)

408

138

Maximum Capacity (per 1 MW)

69

23

Forced Outage Rate (per 1%)

566

189

Partial Outage Rate (per 1%)

466

156

Performance Measure
Rush 1

Rush 2

149

The demonstrated relationship between availability and capacity and emissions mean that
a mere 0.3% improvement in availability11 or a 1.7 MW increase in capacity is enough to cause
the Rush Island units—modeled by Ameren in its regular business—to emit 40 additional tons of
SO2 pollution. FOF 333.
Dr. Hausman’s second set of analyses compared the results of Ameren’s modeling
efforts, which included assumptions about improved unit availability and capacity beginning the
year after the projects were performed, to model runs in which the Rush Island Units were not
improved—that is, a scenario in which the outages that included the projects at issue in this case
were never undertaken. FOF 342. These “with and without” analyses served to isolate the
amount of the projected increase in unit operations and air pollution that was caused or enabled
by Ameren’s 2007 and 2010 outage work. FOF 343, 345. In other words, even though other
factors contributed to unit operations and pollution, the comparison reveals how much of those
emissions would not have been emitted “but for” the Rush Island performance improvements.
Ameren—not Dr. Hausman—performed the engineering assessments of their outage work and
folded those expected operational benefits into the company’s modeling.12 Dr. Hausman simply
examined the result of those operational benefits on the units’ projected operations. The
11

These figures were based on Unit 1’s partial outage rate results. Looking at Unit 2 or
the forced outage rates would yield a smaller percentage triggering 40 tons of S02.
12

Ameren argues that Dr. Hausman’s with-and-without analyses are irrelevant because
they do not compare baseline performance to projected performance. Rather, his analyses
compare two future scenarios: the projected performance with the project to projected
performance without the project. Although the comparison Dr. Hausman did is not the same as
what is required of sources doing PSD calculations, Dr. Hausman’s comparisons are relevant to
this case, which requires a determination about causation. The purpose of Dr. Hausman’s
analysis was to examine the relationship between capacity and availability and that of generation
and emissions. Conducting a with-and-without analysis provides useful causation information
and is a standard industry method.
150

performance improvements Dr. Hausman identified in Ameren’s ProSym input files are
consistent with the performance improvements Mr. Koppe expected the Rush Island units would
see over baseline levels based on his engineering analysis. The results of Dr. Hausman’s
analyses are summarized in the table below:
Baseline
Emissions

Modeled
Performance
Improvements

Projected
Emissions

Total
Increase

Result of
Improvements

Rush 1

14,874 tpy

4.0% EAF

15,561 tpy

687 tons

562 tons

Rush 2

14,288 tpy

18 MW and
2.0% EAF

16,816 tpy

2,528 tons

746 tons

FOF 348–50, 353–54. These results show that Ameren’s modeling would predict significant
emissions increases at the Rush Island units as a result of the projects.
Ameren’s expert witnesses confirmed at trial that the technique Dr. Hausman used is
commonly used in the industry. FOF 344. Ameren’s experts Michael King and Marc Chupka
testified that they had done or recommended similar analyses in prior PSD enforcement cases—
but did not do them here. Id.
4.

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

Ameren argued that it expected unit efficiency to improve at Unit 213 and that this
efficiency improvement would offset any overall increase in emissions. Before this litigation,
however, Ameren made clear that it expected the improved efficiency to result in more
13

Ameren has also argued that efficiency was expected to prevent an emissions increase
at Unit 1. However, the project was not justified based on any efficiency improvements. It was
justified based on outages and load limitations. FOF 145–47, 212. Moreover, while Ameren has
now claimed some improvements in the unit’s net efficiency, such an improvement means more
of the unit’s generation can be sent to the grid (as opposed to be used to run the plant itself) but
does not reduce the amount of coal burned. FOF 117, 213, 351.
151

generation (greater total capacity) rather than less coal burned. In justifying the projects to
management, Ameren’s engineers predicted a small improvement (0.5%) in auxiliary load due to
the boiler component replacements and a 15 MW increase in capacity due to the low pressure
turbine. FOF 280. The 15 MW Ameren attributed to the turbine was separate from the 22.5
MW improvement attributed to the boiler components. Pl. Ex. 110; FOF 281. Similar
improvements were reported by Ameren to the Missouri Public Service Commission—a 0.5%
improvement due to the boiler component replacements and a 1.9% (12 MW) improvement due
to the turbine replacement. FOF 291. Both types of improvements would result in producing
more generation, but not in burning less coal. FOF 117, 213, 214, 280. Consistent with these
reported expectations, Ameren did not incorporate any efficiency change in the 2010 fuel budget
model run that it used as the projection for its NSR emissions calculation. FOF 401, 407. While
Ameren later revised that run to reflect changed efficiency at Unit 2, it only did so after the
project was long complete and the United States had filed this lawsuit. FOF 401. These
revisions, which were made after the completion of the project and even after this lawsuit was
filed, lack credibility. And even the revised projection showed an emissions increase that would
trigger NSR after the analysis is adjusted to disregard Ameren’s inappropriate application of the
demand growth exclusion. See Subsection III.C.
The United States’ experts took these potential efficiency improvements into
consideration in performing their analyses. FOF 213–15, 279, 280, 300. Mr. Koppe explained
that auxiliary load reductions would not impact gross efficiency, which is what matters for
purposes of determining how much sulfur dioxide a unit will emit. FOF 117, 213. In his
analysis of the turbine replacement at Unit 2, Mr. Koppe concluded that because the capacity
increase at Unit 2 exceeded the efficiency improvement, the unit would ultimately still burn
152

more coal even with the turbine replacement. FOF 214, 215, 280, 281, 300. Separately, Dr.
Hausman did a variant of his with-and-without analysis that incorporated an efficiency increase
that was even greater than the 2.4% improvement Ameren reported to the Missouri Public
Service Commission. Dr. Hausman’s analysis found improving efficiency had only a small
effect on the projected increase related to the project, which was 696 tons of SO2—still more
than 15 times the threshold requirement. FOF 356.
Ameren concedes that efficiency actually got worse after the project compared to the
baseline. Ameren blames a portion of the actual increase in pollution on the realized decrease in
efficiency. Regardless of the cause for the unit’s decline in efficiency, each hour of operations or
each extra MW that is generated at the plant requires that much more coal—and results in that
much more pollution. Ameren’s argument has no impact on the United States’ actual emissions
theory because blaming increased emissions on unexpectedly declining unit efficiency does not
change the fact that the units burned more coal and emitted more pollution than they otherwise
would have without the boiler upgrades—and some of the emissions increase would never have
occurred had Ameren decided not to perform those overhauls. Ameren did not claim that the
efficiency decrease accounts for the entire post-project emissions increase. So even if some of
the post-project actual increase was due to worsening efficiency, there was still an increase of
emissions due to the projects.
Ameren argues that efficiency was expected to improve, so it was reasonable to expect
less pollution, and then it argues that efficiency actually got worse, so the increase in pollution is
unrelated to the projects. The evidence shows that the efficiency increase that Ameren claims to
have expected would result in more MW, not less fuel burned. FOF 214, 215, 280, 281, 291,
300. And while the efficiency decrease that came after the project could explain part of the
153

actual increase, it does not alter the fact that a substantial portion of the increase (far more than
40 tons) was related to the increased availability and capacity caused by the project. FOF 216.
5.

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

Ameren expected the projects to cause its highest period of post-project availability to
rise well above the baseline availability for both units. The projects caused substantial
availability increases. Ameren also expected and realized a post-project increase in capacity at
Unit 2 from the challenged boiler work. Those expected and actual performance improvements
were significantly larger than the small changes (an additional 21 full power hours or 1.7 MW)
needed to cause a 40-ton increase in emissions.
The United States’ experts approached the question of estimating the projected increases
from different perspectives. Mr. Koppe and Dr. Sahu first focused on the expected incremental
availability (and, for Unit 2, capacity) improvement, determined whether those improvements
would be realized for the unit as a whole, and then directly calculated the tons of emissions
associated just with those project-related improvements. Dr. Hausman took another approach.
Using Ameren’s modeling, he began with a projection that accounted for everything that Ameren
expected at the units in the future, and then he isolated the amount of generation and pollution
related to the project. Ameren criticized both approaches but never did its own calculation to
show which of the additional tons of emissions were related to the projects.
Using these different approaches, Mr. Koppe and Dr. Sahu reached very similar
conclusions to Dr. Hausman. Additionally, these experts’ calculations were confirmed by the
actual results, as shown in the two charts below:

154

UNIT 1

Koppe/Sahu

Hausman

Ameren’s
Documents

Actual Emissions

∆ EAF

3.8%

4.0%

4.0%

4.3%

∆ SO2

608 tons

562 tons

[No PSD Analysis]

665 tons

227, 232

348 – 350

228 – 231

238, 243

FOF

UNIT 2
∆ EAF

Koppe/Sahu

Hausman

Ameren’s
Documents

Actual Emissions

2.8%

2.0%

3-4%

2.9%

∆ Capacity

18.1 MW

18 MW

22.5 MW

23 MW

∆ SO2

415 (EAF)
417 (MW)

746 tons

2,531

2,170 tons

251, 258, 303

353, 354

256, 276, 277, 402

260, 266, 300

FOFs

The Koppe-Sahu results, Dr. Hausman’s analyses, and the actual post-project data all
establish that there is a significant net SO2 increase of more than 40 tons that was caused by the
projects. Based on the known facts that the Rush Island units are low-cost, baseload units,
common sense compels the same conclusion: improving availability or capacity at baseload units
like Rush Island will result in additional operations and pollution. Ameren’s model confirms
that relationship, as Dr. Hausman showed and Ameren’s chief modeler confirmed in his
testimony. FOF 329–41, 448. Other courts have recognized this relationship. See Subsection
II.B.1 above (citing cases). Ameren should have expected a significant net emissions increase
and should have obtained a permit before beginning work.
C. Ameren Also Violated Title V
Because I conclude the projects were major modifications, I also find that Ameren has
violated Title V of the Clean Air Act.

155

Title V creates an operating permit program designed to collect all of a source’s
applicable requirements under the Clean Air Act in a single place. 42 U.S.C. § 7661c(a);
Ameren SJ Decision, 2016 WL 728234, at *3 (quoting Sierra Club v. Otter Tail Power Co., 615
F.3d. 1008, 1012 (8th Cir. 2010)).
Missouri’s Title V program requires sources to obtain a permit with “all applicable
requirements.” 10 C.S.R. § 10-6.065(6)(C)1.A; see also 42 U.S.C. §§ 7661 - 7661c(a). By
definition, applicable requirements include requirements under the New Source Review program.
10 C.S.R. § 10-6.020(2)(A)23; see also Ameren SJ Decision, 2016 WL 728234, at *24. In
addition, Ameren’s Title V permit prohibits major modifications without Ameren first obtaining
a permit. FOF 456.
By performing major modifications without obtaining an NSR permit (and satisfying the
associated requirements, including the requirement to operate best availability control
technology to reduce emissions), Ameren violated both the requirement to obtain a permit with
all applicable requirements and the permit prohibition against unpermitted major modifications.
III.

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

A. The Projects were not Routine Maintenance
Ameren has asserted the routine maintenance, repair, and replacement defense. The
routine maintenance exemption provides that projects do not constitute “major modifications” if
they merely consist of routine maintenance, repair, or replacement activities. See 40 C.F.R. §
52.21(b)(2)(iii)(a); 10 C.S.R. 10-6.060(8).
Based on the evidence presented at trial, I conclude that the projects cannot be considered
routine maintenance under the law. The Rush Island boiler refurbishments at issue were the
156

most expensive boiler projects ever performed on an Ameren boiler. FOF 182, 183. They
involved the redesign and replacement of major boiler components that were intended to
improve the performance of the units and enable them to burn coal they were not originally
intended to burn. FOF 47, 53, 62, 134, 138–47. They were the first such replacements in the
history of each unit, are rarely done at any unit in the industry, and the combination of boiler
replacements has rarely, if ever, been done in the industry. FOF 172, 174–76. Under the
appropriate legal standards, every factor of the routine maintenance test weighs heavily against
classifying the work as routine maintenance, repair, and replacement. Even Ameren’s
designated expert on routine maintenance, Jerry Golden, acknowledged at trial that these projects
were not de minimis. FOF 164.
1.

Legal standard

The standard for the routine maintenance, repair and replacement exemption in the NSR
rules “is a narrow one and is generally limited to de minimis circumstances.” Ameren SJ
Decision, 2016 WL 728234, at *5. Ameren has the burden of proving the routine maintenance
exemption applies. Id.
As I explained at summary judgment, to determine whether a defendant has met its
burden of proving the routine maintenance exemption, courts examine the projects, taking into
account the 1) nature and extent, 2) purpose, 3) frequency, and 4) cost of the activity to arrive at
a common-sense finding. Id. at *4, *5 (citing Wisconsin Elec. Power Co. v. Reilly, 893 F.2d 901,
910-11 (7th Cir. 1990)). “Frequency [is] evaluated by considering the work conducted at the
particular unit, work conducted by others in the industry, and work conducted at other individual
units within the industry. In evaluating frequency, the most relevant inquiry is how often similar

157

projects have been undertaken at particular units in the industry, not how many similar projects
have been implemented industry wide.” Id. at *5.
EPA has consistently interpreted the routine maintenance exemption as requiring review
based on the “principle that a non-routine collection of activities, considered ‘as a whole,’ is not
exempt under routine exclusion, even if individual activities could be characterized as routine.”
Id. at *8. For these reasons, as I stated at summary judgment:
separate equipment or component replacements should be taken as a whole, i.e.,
multiple component replacements may constitute one ‘project,’ for purposes of
the RMRR analysis, if . . . it appears that the work was done as part of one
project. Under this common sense framework, I agree with EPA that whether the
challenged work was planned for together, budgeted together, performed together,
and undertaken for the same purpose are relevant to the inquiry.
Id.
2.

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

All of the boiler component replacements were related in that they were planned together,
budgeted together as capital projects, performed at the same time, and undertaken for the same
purpose. As a result, I find that the work should be viewed together in determining whether it
qualifies for the routine maintenance exemption.14
The work was planned together. There is no question that Ameren planned the
component replacements together. When Ameren issued the contract documents to qualified
bidders for the project, it consolidated all of the work in its contract specifications. FOF 133,
134. Ameren noted that the projects were combined to “gain efficiencies in procurement, design
and installation” and described the air preheater replacement as “part of a Major Mechanical

14

Even if I were to consider each major component replacement separately, I would still
conclude that the projects were not routine maintenance under the weight of the evidence.
158

Work Package to include the Economizer, Reheater and Lower Slope portion of the boiler.”
FOF 132. Ameren described the “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.
P. Ex. 6; FOF 139.
The work was budgeted together. As of December 2004, Ameren had created a
preliminary capital budget for the replacement of the Unit 1 economizer, reheater, lower slopes,
and air preheater as part of a single project. FOF 126. Even though Ameren prepared separate
work orders for the two air preheater replacements, all the work was from Ameren’s capital
budget—not the operations and maintenance budget—and was budgeted for the same outage to
be performed at the same time. FOF 130, 131, 181. Likewise, at Unit 2, Ameren consolidated
the replacement of the challenged components when it sought bids from outside engineering
firms to design, fabricate, and install those components. FOF 133.
The work was performed at the same time. It is undisputed that the components at issue
were performed together during the same outages at Unit 1 and Unit 2. FOF 25, 169, 170.
The work was undertaken for the same purpose. Ameren’s routine maintenance expert,
Mr. Golden, agreed that the purpose of the work at each unit was the same. FOF 150–51. Mr.
Golden confirmed Mr. Stevens’ testimony that the purpose of the work at each unit was to
eliminate pluggage and fouling of the economizers and reheaters and to eliminate future forced
159

and maintenance outages caused by tube leaks.15 FOF 56–69, 145–47, 149. The United States’
expert Mr. Koppe also explained that Ameren could completely resolve the capability restraints
caused by pluggage only by replacing each of the components at issue during the same outage.
FOF 53, 63, 196. Ameren’s Jeff Shelton agreed. FOF 64.
3. The projects do not qualify for the routine maintenance exemption
a.

Nature and extent

The 2007 and 2010 projects involved the replacement of major boiler components that
are integral to the operation of the Rush Island Unit 1 and 2 boilers. The 2007 and 2010 projects
took years to design and plan and required the special fabrication of components that were not
otherwise available at the Rush Island plant. FOF 139, 164. The projects were far more
extensive than the type of maintenance, repair, and replacement routinely performed at Rush
Island and other coal-fired power plants. FOF 165–72. And it is clear from Ameren’s
documents that the company itself never considered these projects to be just “routine
maintenance,” as that term is understood in the industry; it considered them to be “major boiler
modifications” or “major boiler refurbishments.” FOF 50, 130, 139, 171.
Each of the boiler components was redesigned to eliminate the recurring problems
associated with Ameren’s switch to PRB coal. FOF 53, 134, 138–49. These design changes
were intended to upgrade and improve the performance of the boilers. FOF 145–60.
Given the complexity of the replacements, the components were designed, engineered,
and constructed by outside contractors, such as Alstom Power, the original manufacturer of the
boilers. The work was well beyond the capacity of Ameren’s own staff. FOF 128, 166.

15

On Unit 1, the lower slopes were replaced to eliminate tube leaks and repair damage
resulting from slag falls and erosion following the switch to PRB coal. FOF 52, 53, 56–59.
160

In contrast with routine maintenance, repairs, and replacements undertaken at utility
plants, the projects required approvals of executives at the very highest level of the company,
including Ameren’s CEO. FOF 135–37.
The economizers, reheaters, and air preheaters each weigh hundreds of thousands of
pounds and required construction of heavy equipment such as monorails and cranes. FOF 162,
167–68.
The 2007 outage for 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. FOF 169.
Ninety-one percent of the work done during the Unit 1 outage was performed by contractors. Id.
The 2010 outage at Unit 2 lasted approximately 100 days and required more than 350,000
hours of labor, of which 290,953 hours were performed by contractors. FOF 170. An average of
360 contractor staff worked two 10-hour shifts six days a week during the outage. Id.
The 2007 and 2010 overhauls were considered capital projects and were funded out of
Ameren’s capital budget rather than the operations and maintenance budget. FOF 181. As
capital projects, these component replacements improved the value of the generating unit. FOF
180.
As a result, the nature and extent of these projects weighs heavily against a finding that
these projects qualify for the narrow routine maintenance exemption.
b.

Purpose

As noted above, the consistent purpose of the projects was to eliminate pluggage, fouling,
and tube leaks. Ameren expected that tube leaks in the economizers and reheaters would be
eliminated for at least 20 years. FOF 38, 145–47. By contrast, routine maintenance, repair, and
replacement is performed to allow a unit or plant to continue to operate in its present condition.
161

See Doc. 227-2, Memorandum from Don Clay, Acting EPA Ass’t Admin. (Sept. 9, 1988), at 3-4;
Doc. 227-3, 2000 DTE Applicability Determination Detailed Analysis, at 11.
The replacement of these major boiler components allowed the units to operate hundreds
more hours than they could in the baseline period at a higher capacity by eliminating tube leaks,
load limitations, and operational constraints. The purpose of these projects indicates that the
work was far from routine.
c.

Frequency

Even though the most relevant inquiry is how often similar projects have been undertaken
at particular units in the industry, for each of the three inquiries under the frequency factor, the
inquiry weighs heavily against a finding of routineness.
Frequency at the unit. None of the components at issue had been replaced at these units
before. FOF 173. The components were replaced after 31 years of service at Unit 1 and 33
years of service at Unit 2. FOF 4, 174.
Frequency at individual units within the industry. The components at issue are very
rarely replaced at any plant. FOF 174–76. Ameren’s expert confirmed this point. 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 the lower furnace is about 40 years. FOF
174. 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. Id. This
evidence, coming from Ameren’s expert, demonstrates that replacing the components at issue is
rarely done at individual units within the industry.
Work conducted by others in the industry. Mr. Golden testified about a list he has
complied of 18,300 projects undertaken at coal-fired power plants. The list includes projects that
162

Mr. Golden identifies as capital projects costing more than $100,000. Id. As an initial matter,
the relevance of Mr. Golden’s list to this case is weak because Mr. Golden has been unable 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. Id. Boiler refurbishments like the ones
at Rush Island are not common in the industry.
Regarding air preheater replacements, Mr. Golden identified 35 replacements of
regenerative air preheaters going back to the 1970s. 16 FOF 176. By his count, that is less than 2
percent of the coal-fired units in the country. However, Mr. Golden was unable to say whether
those 35 instances were complete replacements or similar to those at Rush Island. Id. Even if
they were, a replacement that takes place at less than 2 percent of the units going back to the
1970s is not common in the industry.
As a result, the frequency factor weighs heavily against these projects being routine.
d.

Cost

The projects at issue were the most expensive capital projects ever done at Rush Island.
Each project cost substantially more than the entire operations and maintenance budget for the
plant for an entire year. FOF 177, 178, 182. Grouping the replacements at each unit together,
the two projects were among the most expensive boiler projects ever undertaken at any of
Ameren’s plants. FOF 183.
Based on the undisputed facts regarding the costs of these projects, the cost factor also
weighs heavily against these projects being routine.
4.
16

Conclusion: the projects cannot be considered routine

Even for the claimed 35 air preheater replacements, Mr. Golden was unable to testify
that all were complete replacements or that all the replacements were comparable to the air
preheater replacements at Rush Island. FOF 177.
163

Ameren has not satisfied its burden of proving that the Rush Island projects fall within
the narrow routine maintenance exemption. The 2007 and 2010 major boiler outages were
unprecedented events for Rush Island Units 1 and 2—they were the centerpieces of the “most
significant” outages in plant history. FOF 172. A common sense finding weighing the nature
and extent, purpose, frequency and cost of the projects reveal them to be far from de minimis
activities contemplated by the exemption. Ameren’s expert agreed and testified at trial that these
projects were not de minimis activities. As a result, Ameren’s routine maintenance defense fails.
B. The Emissions Increases Cannot Be Set Aside Based on the Demand Growth
Exclusion
Ameren also asserts the “demand growth exclusion,” set forth at 40 C.F.R. §
52.21(b)(41)(ii)(c), as a defense to liability. As the United States Court of Appeals for the
District of Columbia explained in New York v. EPA, “the regulation establishes two criteria a
source must meet before excluding emissions from its projection: (1) the unit could have
achieved the necessary level of utilization during the [baseline period]; and (2) the increase is not
related to the physical or operational change(s) made to the unit.” 413 F.3d at 33 (quotations
omitted). “The two prongs are distinct. Satisfying the ‘could have accommodated’ prong is
necessary but not sufficient to justify application of the exclusion, and emissions that ‘could have
been accommodated’ at baseline are not per se ‘unrelated.’” Ameren SJ Decision, 2016 WL
728234, at *21.
Additionally, as stated at summary judgment, “the burden is Ameren’s to prove that the
demand growth exclusion applies.” Id.

164

1.

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

Fundamental to an invocation of the demand growth exemption is that demand on the
unit increases. But in this case just the opposite happened, as the data shows—and Ameren’s
expert witnesses conceded.
A unit’s “utilization” is a measure of how much of its available capacity the unit is called
on to use. The measure serves to reflect market demand on a specific unit. FOF 377. As Mr.
King explained, a declining utilization factor means demand on the unit is decreasing. FOF 378.
As a result, when the utilization factor is declining, an increase in pollution cannot be the result
of demand. Id.
As far as the actual emissions case is concerned, Mr. King and Ms. Ringelstetter both
testified that the utilization factor for the Rush Island units actually decreased after the projects.
FOF 378–80. The declining demand that the units actually experienced after the projects
prevents Ameren from asserting a successful demand growth argument for the actual emissions
increase shown in the data.
Ameren’s application of the demand growth exclusion also fails for the expectations case.
Ameren’s testifying expert Marc Chupka looked at the utilization factor data leading up to each
project and concluded that “[i]t would be reasonable to assume a constant utilization factor for
projecting future emissions” following the boiler upgrades at issue in this case. FOF 208. Ms.
Ringelstetter agreed. She testified that the utilization of Unit 1 was projected to remain basically
constant, and, though utilization of Unit 2 was projected to increase somewhat (about 2%), the
increase paled in comparison to the projected increase in emissions (over 15%). FOF 380. A
constant utilization factor means static demand on the units. If that demand is constant, it cannot
165

be the cause of an emissions increase. Regardless, even the marginal projected increase in Unit
2’s utilization factor cannot account for the substantial emissions increase that Ameren’s
modeling and calculations projected. Id.

2.

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

The evidence Ameren presented in support of the demand growth defense generally falls
into two categories: (1) evidence that regional demand for electricity was generally going up
during the years surrounding the Rush Island projects, and (2) calculations regarding how much
generation (and pollution) the units “could have accommodated” during the baseline periods.
The central problem for Ameren’s defense is that these showings, while necessary to the
company’s proof, are insufficient to establish that the demand growth exclusion applies to any
specific “portion” of its projected emissions increases, as required by the rule. Cf. 40 C.F.R.
§ 52.21(b)(41)(ii)(c); see also 40 C.F.R. § 52.21(r)(6)(i)(c) (requiring operators to document and
describe certain PSD analyses, including “the amount of emissions excluded under [the demand
growth exclusion] and an explanation for why such amount was excluded”). Ameren has failed
to establish a correlation between rising regional demand and any specific impact on unit
performance in order to show what portion of its projected emissions increases are “unrelated” to
the projects at issue in this case.17

17

Ameren’s theory on demand growth appears to be that, if it can prove emissions were
related to demand, then the emissions cannot be related to the projects. This rests on the false
assumption that an effect can only have one cause. Because pollution, like any effect, can have
more than one “but for” cause, it is not enough for Ameren to simply point out that some of its
projected and actual increases in emissions are related to the presence of sufficient market
demand for Rush Island power. Ameren disputes the relevance of the restaurant analogy argued
by the United States and used by the Court at summary judgment. See Ameren SJ Decision,
2016 WL 728234 at *10 n.17. But the restaurant analogy remains useful. To be sure, a meal
166

The first category of Ameren’s evidence—its various system load forecasts—fails to
connect meaningfully to projections of unit operations because increases in system demand do
not necessarily translate into increases in unit operations. As Ameren’s witnesses testified,
during the baseline period, the units operated as baseload units and operated whenever they were
available. As a result, they were usually fully-loaded during “on peak” hours when system
demand was at its highest. FOF 371–72. If the units were generally maxed out anyway,
increases in system demand would have little effect on unit operations.18 That is reflected in
Ameren’s expert testimony on unit utilization, discussed above. Moreover, as Dr. Hausman
testified, Ameren’s ProSym modeling efforts showed just how disconnected unit operations were
from system level demand. Ameren’s load forecasts were inputs into its modeling runs, and they
reflected the company’s expectation that system load was growing on the order of 1% a year.
But the output files from those very same runs reveal Ameren’s computer simulations projected
that generation from the Rush Island units would increase immediately following the outage and
then remain relatively flat. FOF 373. Ameren seems to suggest that rising regional demand for
electricity—like a rising tide—would lift operating levels at its units. The evidence clearly
establishes otherwise.

served to a restaurant customer is “related” to the customer’s decision to order it (customer
demand); but that does not mean that the meal is “unrelated” to the restaurant having an open
table or the chef's preparation of the food.
18

Ameren witness Jaime Haro noted that, for baseload units like Rush Island, increases in
system demand would mean the units still ran at high levels most of the day, but they might ramp
down a little later each day or turn up to full load a little earlier each morning. FOF 370. The
marginal increases in demand on the “shoulder” hours may have been attributable to system level
demand, but Ameren made no attempt to quantify just what portion of its emissions projections
were made up of these marginal shifts. As a result, Ameren cannot meet its burden of proof on
this defense.
167

Ameren’s second category of evidence, presented through its expert Sandra Ringelstetter,
is a series of calculations describing how much SO2 pollution the Rush Island units “could have
accommodated” during their respective baseline periods. This, too, fails to address how any
specific portion of its projected emissions increases is unrelated to the projects at issue. It does
not address any portion of the units’ projected emissions at all. While varying somewhat in the
details, all of these calculations involve picking a pollution rate the units achieved at some
limited point during the baseline period (sometimes a month, sometimes a week, sometimes a
discontinuous set of hours taken from across the 24-month baseline period), and then multiplying
that emissions rate by the unit’s baseline equivalent availability levels. Since EAF is a measure
of available hours, and since its emissions rate is related to a unit’s load levels,19 these
calculations essentially assume that the unit would run flat out, at some very high level of
operations, through day and night, for nearly two continuous years. Ameren then concludes that,
since demand was going up and its “could have accommodated” calculations result in more
emissions than any projected increase in this case, all projected emissions increases can and
should be excluded from the NSR liability calculation.
Ameren’s “could have accommodated” calculations are fundamentally flawed. For
example, they employ unreasonably-high emissions rates and rely on applicability
determinations divorced from the operational realities of electric utilities. But even if Ameren’s
“could have accommodated” calculations were reliable, the calculations cannot—as a structural
matter—say anything about whether the projected emissions from the units are related to the
projects at hand. Ameren’s “could have accommodated” calculations consider neither the
19

Despite Ms. Ringelstetter’s testimony to the contrary, hourly emissions are directly
related to hourly heat input in her own analysis, Ringelstetter Test., Vol. 11-B, 85:15–86:3, and
the relationship between heat input and unit load level is “more or less linear.” Id. at 85:9 – 11.
168

projects at issue nor the projected emissions in any way. At best, the calculations have
something to say about only one prong of the demand growth exclusion, which is not sufficient
to establish the exclusion applies.

3.

Ameren’s other demand growth arguments fail

Ameren made two additional arguments at trial in support of its demand growth defense.
First, Ameren argued that “unit-level demand” is not the focus of the test, and that instead, the
demand growth exclusion focuses directly on “systemwide demand.” In other words, Ameren
argues that the problem of translating system demand into demand on the unit and changes in
unit operations is not required by the rule itself. For that proposition, Ameren cites the 1992
WEPCO Rule Preamble where the demand growth exclusion was first introduced. The passage
does not support Ameren’s argument; in fact, just the opposite:
[W]here increased operations are in response to independent factors, such as
system-wide demand growth, which would have occurred and affected the unit’s
operations even in the absence of the physical or operational change, such
increases do not result from the change and shall be excluded from the projection
of future actual emissions.
57 Fed Reg. 32,314, 32,326 (1992). As a result, the regulations themselves establish that EPA
has always required an operator to show whether—and to what extent—demand would “affect
the unit’s operations” before the demand growth exclusion could be applied.20

20

Ameren cites various other authorities in its post-trial brief to support its argument that
evidence of increasing systemwide demand is sufficient to establish the demand growth
exclusion. Ameren misreads each of these authorities, ignoring paired language clarifying that
the relevant inquiry requires consideration of how demand affects the units at issue. The demand
growth standard is clear. In situations like these, “where [a] proposed change will increase
reliability, lower operating costs, or improve other operational characteristics of the unit,
increases in utilization that are projected to follow can and should be attributable to the change.”
61 Fed. Reg. 38,250, 38,268 (1996).
169

Ameren’s second argument was presented through the testimony of Ms. Ringelstetter.
Specifically, Ameren argued that any performance changes or any emissions increases following
the Rush Island modifications would be unrelated to those boiler modifications. This conclusion
is unsupported and was offered for the first time at trial.
Until the summary judgment ruling, Ameren and its experts declared that it did not really
matter what the project was so long as the unit, during the baseline, “could have accommodated”
the projected emissions. As the head of Ameren’s Environmental Services Department testified
in Rule 30(b)(6) deposition testimony, “The emissions that the unit was capable of
accommodating prior to the outage would be totally unrelated to . . . any activities that occurred
on the outage. So just by the nature of the scope, the emissions are unrelated.” Whitworth Rule
30(b)(6) Depo. Test. 38:4-12; see also Ameren SJ Decision, 2016 WL 728234, at 9 (describing
Ameren’s argument that “‘unrelated’ means any emissions increases a unit could have
accommodated at baseline”). And when Ms. Ringelstetter originally performed her “could have
accommodated” calculations, she declared that was the only step necessary to establish that the
exclusion applied. She testified at her deposition that even assuming the performance
improvements she recognized in Ameren’s modeling files were the result of the boiler upgrades,
it would not have changed her analysis, her calculations, her considerations, or her conclusions
in any way. FOF 438.
Ameren’s theory is inconsistent with the plain language of the regulations, the case law,
and my summary judgment decision holding that the two prongs of the exclusion are distinct.
See Ameren SJ Decision, 2016 WL 728234, at *11. After my summary judgment ruling,
Ameren adjusted its theory and attempted to show that neither the capacity increase experienced
at Unit 2 nor the availability increase experienced at either unit was related to the boiler upgrade
170

work at issue in this case. Not only is such a conclusion contrary to the Ameren’s internal
engineering and economic documents, the pre- and post-project analyses provided by Ms.
Ringelstetter, on which Ameren bases its relatedness arguments, are flawed.
Ms. Ringelstetter’s capacity analysis begins by relying on inapplicable pre-project values.
Instead of comparing projected future operations to actual, past operations, she looks at modeling
inputs from previous years. Though those earlier modeling efforts might generally be expected
to reflect the unit’s actual operations around that time, the capacity values used here present a
particular problem: Ameren uses its capability tables to develop unit capacity inputs, and for half
of the baseline at each unit, the capacity tables were “unrealistically high.”21 FOF 431–32. That
means the capacity increase Ameren expected to see and did see following the Unit 2 work was
about twice what Ms. Ringelstetter saw. That increase cannot be attributable to turbine work
alone, as Ms. Ringelstetter claims. FOF 431–32; cf., e.g., FOF 304.
Ms. Ringelstetter’s analysis also discounts the observed availability increases post-project
as being too small to be meaningful. Essentially, Ms. Ringelstetter argues that the increases are
“in the noise,” so there is no increase at all. But the evidence shows that just a 0.3% availability
improvement could result in 40 additional tons of SO2 at Rush Island. FOF 191. Ameren’s
21

In January and February of 2006—and in middle of the baseline periods—Ameren
decided to update its capability tables to come up with more accurate predictions. Pl. Ex. 157 at
AM-02743289. For the Rush Island units, that meant substantially reducing the projected unit
capabilities as operating data showed that the units were struggling to perform as expected for
many months of the year. U.S. FOF 119. Recognizing this, and using “historical operating data
along with design criteria,” Ameren updated its capability tables and substantially reduced the
Rush Island numbers in order to “generate more realistic capability ratings for all of [the
company’s] fossil units.” Pl. Ex. 260 at AM-00091465. The new numbers dropped the average
annual capability ratings for the units by about 12 MW. Compare Pl. Ex. 157 with Pl. Ex. 260.
So Ms. Ringelstetter’s baseline capability number is substantially inflated since almost half of
the numbers there were “unrealistically high.” U.S. FOF 432.
171

economic justifications were calculated to a tenth of a percent. FOF 104, 148. Ms.
Ringelstetter’s opinion also disregards the fact that Ameren projected long-term averages in its
computer modeling and that specific years, as is relevant under the PSD analysis, might be as
much as 2% or 3% higher than the inputs presented in the ProSym inputs. FOF 257. The
important inquiry here is the size of the availability gain, which the evidence noted in Subsection
II.B has shown to be about 3‒4%. As Dr. Hausman testified, that kind of gain would lead to
additional operations and pollution. To the extent Ms. Ringelstetter’s testimony disregards these
gains, her testimony is simply not credible.
4.

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

Ameren’s demand growth defense fails to address whether projected emission increases
are related to the projects at issue. No matter how Ameren calculates the quantity of emissions it
could have emitted had demand for electricity stayed high through the night, it does not address
the reality that the units’ real opportunities to sell more (and emit more) came by expanding their
ability to operate when the demand is high—and when their units are generally maxed out—
during the day. FOF 370–71. If there were baseline hours where the unit could not operate
because of outages caused by the components at issue, any post-project recovery of those hours
would be related to the project. Mr. Koppe found there were 246 outage hours for Unit 1 and
146 outage hours for Unit 2 caused by the projects in the baseline. FOF 240, 263. As described
in Subsection II.B of my Conclusions of Law, both Mr. Koppe and Ameren concluded that those
hours would be recovered and used in the post-project period. For those hours, the units went
from unable to operate to able to operate. Demand did not cause that change; the units already
operated every hour they could. That change resulted from $70 million of capital work. As I
172

explained at summary judgment, when a unit “undergoes modifications that allow it to run more
during the daytime hours tha[n] it could before, it cannot be said that the increased emissions
were merely a coincidence or unrelated to the modification.” Ameren SJ Decision, 2016 WL
728234, at *10.
Ameren’s witness admitted that changes in unit capacity or availability would lead to
changes in operations and pollution, FOF 427–28, and the company justified the cost of the
projects on precisely those kinds of performance improvements. FOF 146, 277. Dr. Hausman
specifically examined how performance improvements at the units translate into coal
consumption and pollution, and the result is predictable: when the units are better able to supply
electricity, they do so, and they burn more coal in the process, emitting more pollution. See
Subsection II.B.2.c.
Moreover, the company’s data reflects the straightforward relationship between the Rush
Island units’ performance abilities and their pollution levels. As discussed earlier, “[u]tilization
is a variable that describes how much of the [unit’s] available capacity the unit utilizes,” and that
in turn reflects the influence of all of the “market considerations” like system demand and
market price that can impact unit operations. FOF 377. A unit’s equivalent availability factor,
on the other hand, reflects the engineering condition of the unit—how well it has been
maintained and whether it stands ready to generate whenever needed. FOF 94. The graphs
below show that Ameren’s historical emissions data reflects the reality that Rush Island
operations were driven by its engineering condition (measured by its availability) more than any
market fluctuations (measured in its utilization). These graphs show SO2 emissions, availability,

173

and utilization factor at Units 1 and 2, respectively. They were the subject of testimony by Dr.
Sahu and Mr. King and are based on data compiled by Dr. Sahu and Ms. Ringelstetter.22

Unit 1 SO2 Pollution Tracks Availability, Not Demand on the Unit
100

16000

80

12000

60

8000

40

4000

20

%

SO2 Pollution (tons per year)

20000

0

0
2000

2001

2002

2003

2004

SO2 Pollution (tons per year)

2005

2006

Availability (%)

2007

2008

Utilization Factor (%)

Unit 2 SO2 Pollution Tracks Availability, Not Demand on the Unit
100

16000

80

12000

60

8000

40

4000

20

%

SO2 Pollution (tons per year)

20000

0

0
2000

2001

2002

2003

2004

SO2 Pollution (tons per year)

2005

2006

2007

Availability (%)

22

2008

2009

2010

2011

Utilization Factor (%)

Ameren moved to exclude the graphs as not properly disclosed. For reasons I discuss
below (see Section on Evidentiary Issues), I will deny Ameren’s motion as it relates to these
graphs. Notably, the charts were also used in the United States’ summary judgment briefing,
Doc. 609 at p. 20, and Ameren’s David Strubberg presented a similar chart, comparing
availability and generation, at the 2008 State of the System Meeting. FOF 202.
174

Reviewing these charts at trial, Ameren’s testifying expert Michael King conceded that there was
a relationship between availability and pollution. FOF 381.
Ameren argued that being forced to translate system level demand into an effect on unit
operations would turn the analysis from an annual emissions focus to an hour-by-hour
assessment, which is not contemplated by the regulations. That argument fails for two reasons.
First, just as a restaurant owner knows the ebb and flow of customers throughout the
lunch and dinner rushes, Ameren knew that Rush Island generally ran hard throughout the day
and ramped down somewhat at night. In this context, Ameren’s employees noted that derates
resulting from pluggage in the units’ boiler components were costing the company as much as
$25,000 a day. FOF 112. A company does not lose earnings when it has available capacity that
it could dip into at a moment’s notice; it loses earnings when it cannot provide the generation it
would otherwise be able to sell for a profit. See, e.g., FOF 112, 274 (Williamson email). And
when Ameren justified the substantial expense of the boiler overhauls at the Rush Island units,
the company quantified the benefit of recovering availability and capacity. Again, those benefits
can only be considered “benefits” of the projects if the units would not have otherwise been able
to operate that often or at those levels. See, e.g., FOF 146. Documents like these reflect the
general truth—without necessitating an hour-by-hour data review—that the units were limited,
the problems were expected to be fixed, and the units would operate more as a result.
Ameren’s argument that NSR cannot require sources to perform an hour-by-hour look at
operations is disingenuous when its own ProSym software—which it uses regularly in the course
of its business and runs hundreds if not thousands of times each year—solves the dispatch
problem on an hour-by-hour basis for every year it is told to do so. FOF 317. That model makes
175

it easy to isolate how performance improvements would interact with other market constraints to
determine unit operations on an hour-by-hour basis and further determine how those hourly
operations translate into annual generation and pollution numbers. Dr. Hausman did just that,
and the results showed a straightforward relationship: more capacity or more availability led to
more generation and more pollution. PSD requires sources to consider “all relevant information”
in analyzing whether emissions will increase; it does not contemplate sources ignoring known,
relevant information just because it might be unfavorable. Section 52.21(b)(41)(ii)(a). Ameren
had the relevant information, and that information showed that the Rush Island units’
performance would improve, resulting in increased generation and emissions.
As I have previously ruled, increases made possible by performance improvements must
be attributed to the project and cannot be covered by the demand growth exclusion. See
Subsection II.B.1.
C. Ameren’s New Source Review Analyses Are Fatally Flawed and Cannot Provide
Safe Harbor from Liability
Ameren’s emissions calculations are not reasonable analyses under the PSD rules and
therefore do not show that Ameren should not have expected an emissions increase.

1.

Ameren does not have a legitimate process for assessing PSD applicability

First, Ameren’s position relies on a fundamental misunderstanding of the PSD program.
Ameren offered the testimony of Mr. Boll and Mr. Whitworth at trial to describe how Ameren
determined whether a project might cause an emissions increase. Both witnesses testified that
the company looked to whether the unit’s potential emissions were expected to increase.23 FOF
391. The company employee actually charged with performing the PSD analysis for Unit 2
23

Mr. Boll used the term maximum continuous rating. FOF 391. As Ameren explained in
its earlier briefing, that term is a measure of a unit’s potential emissions. Doc. 542 at 5-6.
176

confirmed Ameren’s reliance on the wrong metrics when he testified that any improvements in
availability were “irrelevant.” FOF 396, 397(d).
Ameren’s method of assessing PSD does not comply with the rules, EPA’s instructions,
or case law. The rules explicitly direct a source to compare projected emissions to baseline
emissions, both measured in tons per year. 40 C.F.R. § 52.21(b)(41), (48). As noted above, both
EPA and the courts that have interpreted the PSD program have explained that “[i]f an increase
in hours of operation is caused or enabled by a physical change, the increased hours must be
included” in the projection. Duke Energy 2010, 2010 WL 3023517, at *5. EPA has brought
enforcement actions since 1999 based on improvements in availability that lead to increases in
annual pollution. Ameren’s testifying expert conceded that EPA’s enforcement approach has
been “well-known in the industry” since 1999. FOF 219.
By focusing on potential emissions, Ameren ignores my ruling on Ameren’s first motion
for summary judgment. In motions practice, Ameren argued that the United States had to show a
“modification” under the Missouri SIP before turning to the issue of whether the projects were
“major modifications.” Doc. 542 at 1-2. Ameren argued that modification status was controlled
by potential emissions. Id. I rejected that argument. Doc. 711. As Ameren argued at summary
judgment, “‘modification’ and ‘major modification’ are distinct terms with separate
characteristics under the SIP.” Doc. 542 at 5. At trial, however, Ameren described its internal
analysis as focused solely on the first test, not the major modification test actually before the
Court.
For the reasons described in Subsection II.B.2 of my Conclusions of Law, if Ameren had
considered how the actual performance changes would affect generation, it would have expected
and found emissions increases related to the project.
177

Second, Ameren failed to coordinate between the engineers who planned and performed
the projects and the environmental services employees charged with assessing NSR applicability.
Michael Hutcheson, who performed the NSR analysis for the Unit 2 project, reported that he
learned about the project from his boss and his boss’s boss but never talked to the engineers
working on the project. FOF 397(a).
On the other side of this divide, engineering leaders at Ameren like Robert Meiners and
David Strubberg testified that they had no involvement in assessing whether the projects
triggered PSD. FOF 393. Mr. Meiners testified that as plant manager, he was “accountable” for
ensuring that Rush Island complied with environmental regulations. Id. Despite that
accountability, Mr. Meiners testified that he had never been involved in a single discussion about
whether to seek a New Source Review permit for any project:
Q. Even though you were plant manager, though, you had no involvement at all in
the decision of whether to seek a New Source Review permit for either of the
projects at issue in this case, right?
A. I was not involved with that. We had an environmental department that took
care of those kind of items. I was not involved.
Q. And by "not involved," I mean, you didn't have a single discussion with
anyone about the decision of whether to seek a New Source Review permit?
A. No, I did not.
Q. And, in fact, throughout your career at Ameren you've never had a single
discussion with anybody about whether to seek a New Source Review permit for
any project, right?
A. No, I have not.
Tr. Vol. 7-B, 64:6-20.
The project justification packages that Ameren regularly put together as part of the work
approval process included a checkbox asking whether the proponent had assessed
178

“Legal/Environmental” risks. FOF 388. But as one engineering manager testified, he could not
“recall that box ever being checked” and had no idea what it meant. FOF 389. Each project had
to be approved by a series of managers and executives, even the company CEO and board of
directors. FOF 135–37. But the Environmental Services Department, charged with assessing
NSR applicability, was not asked to approve the projects.
As a result, Ameren’s PSD process suffered from two major flaws: the employees
charged with assessing applicability started with an incorrect understanding of the law and
lacked a meaningful understanding of the facts of the projects. In addition to these procedural
flaws, for the reasons that follow, the actual analyses Ameren did “conduct” (for Unit 2 only)
provide no basis for finding that Ameren could have reasonably expected the project would not
significantly increase net emissions.

2.

Unit 1

Ameren concedes that it performed no numerical calculation for the Unit 1 project.24
FOF 391. Whatever qualitative analysis may have been done at the time cannot shield Ameren
from liability now. Nor can the post-hoc analysis offered at trial by testifying expert Sandra

24

Ameren argued for the first time in its post-trial brief that it was not required to
perform a numerical calculation at Unit 1 because the provision of the 2002 Reform Rules
requiring such calculations be performed was on remand at the relevant time. Ameren’s
argument fails. Even though a portion of the rule was on remand at the time, the Missouri SIP
and EPA still required sources to maintain these records. See 71 Fed. Reg. 36,486, 36,487-88
(June 27, 2006); see also US Resp. Br. (Doc. 838) at 47-48. Moreover, as Ameren itself points
out, the United States has not brought a record-keeping case and is not seeking judgment that
Ameren failed to maintain the necessary records. Rather, the relevant issue is whether Ameren
reasonably should have expected emissions to increase because of the projects. Whether Ameren
performed a numerical calculation at all is certainly relevant to that inquiry and will, accordingly,
be considered.
179

Ringelstetter, who used an inapt modeling run and incorrect application of the demand growth
exclusion.
As an initial matter, there is no contemporaneous evidence that Ameren performed any
assessment of the Unit 1 project. Mr. Boll testified that Ameren performed a qualitative
emissions analysis for the projects in 2005. FOF 390, 391. But this analysis did not even rise to
the back-of-an-envelope level—there is no written record of any such analysis. Moreover,
because Mr. Boll and Mr. Whitworth made clear they only considered the maximum continuous
rating of the unit, any qualitative analysis they did “conduct” did not comply with NSR
requirements and therefore was not reasonable under the law. Id.
The post-hoc analysis performed by Ms. Ringelstetter does nothing to support Ameren’s
belief that emissions would not increase at Unit 1. Despite presumably having access to scores
of ProSym modeling runs that projected Unit 1’s post-project operations, Ms. Ringelstetter
selected a run with two key flaws. First, according to her trial testimony, the run actually
overstated emissions, so she adjusted it downward. FOF 454. Notably, other runs had no such
issue, and Ameren itself never saw the need to adjust the run. FOF 454. Second, the run
intentionally depressed output from Unit 1 for the full five years following the project based on
the potential for the unit to provide ancillary services.25 FOF 448, 449, 453. Ameren did not
provide any evidence to support this assumption other than the testimony of Ms. Ringelstetter
herself. Ms. Ringelstetter testified the modeling assumption was “entirely appropriate” and yet
did not offer any document or specific fact to support that conclusion. She never even

25

Ancillary services are services other than simple electric generation that utilities
provide to keep the electric grid operating reliability. FOF 439.
180

mentioned ancillary services, spinning reserves, or regulation hours in her expert report. FOF
451. Moreover, the limited evidence in the record contradicts her opinion:
1. The only evidence that Ameren may have expected to provide some ancillary services
with the Rush Island units around the time the boiler upgrades were performed is a
short-term contract between Ameren Missouri and its Illinois affiliates. But that
contract does not require anything specific of the Rush Island units in particular; in
fact, it gave Ameren Missouri flexibility to provide the services from a number of
different units. FOF 442.
2. Whatever effect the contract may have had on operations of the Rush Island units, the
effect was never expected to last. The contract was never intended to extend beyond
the inauguration of MISO’s regional ancillary services market (originally scheduled
in 2008 and then delayed to January 2009). FOF 440. Ameren’s witnesses all agreed
that once MISO implemented its ancillary services market the Rush Island units
would not be providing such services at it does not make economic sense to hold back
such cheap, reliable sources of generation. In fact, Ameren’s head modeler told the
Missouri Public Service Commission in that it did not make sense to model those
services because they were based on a “short-term contract that will end when the
MISO ancillary service market begins.” FOF 445.
Selecting a run which depressed output for five years by modeling ancillary services at the Rush
Island Unit 1 that—if ever they had an impact on operations—would last no more than two years
after the project runs afoul of the regulations’ requirement to “consider all relevant information”
and use the highest year of post-project emissions. 40 C.F.R. § 52.21(b)(41)(ii)(a).26
3.

Unit 2

While Ameren did at least perform numerical analyses for Unit 2, these analyses are no
more compelling than its qualitative analysis for Unit 1.
As an initial matter, even though PSD analyses should be completed before beginning
construction, Ameren did not complete any numerical analysis for Unit 2 until after the project
work started. FOF 398-401. Ameren began its “Original” analysis at the end of 2009, which
26

After using an inappropriate modeling run to obtain projected emissions, Ms.
Ringelstetter misapplied the demand growth exclusion, as described in Subsection III.B of my
Conclusions of Law.
181

relied on a January 2010 modeling run. By the time that analysis was done, the project was
underway and it was too late for Ameren to comply with the law if a permit was required.
Moreover, the work had been approved for four years at that point. The work was first approved
in 2005 and then reassessed in a process that culminated with the final approval from the Board
of Directors in August 2009. FOF 400.
Mr. Hutcheson testified at trial that the Original Unit 2 emissions calculation was one of
about two dozen requested at the same time by Ameren’s legal department. FOF 399. The
projects to be assessed were a mix of past and future projects. Id. For Unit 2, the request came
well after the project had been fully approved. FOF 400. This type of afterthought analysis
(even if it had been finished just before the start of construction instead of just after) does not
serve as a reasonable emissions calculation or prevent a finding of liability, particularly where
the analysis fails to account for the company’s actual expectations of performance
improvements, as discussed below.
Ameren’s “Amended” Unit 2 analysis is not helpful because it was not performed until
even later and was only performed well after the project was completed, after Ameren received
the Notice of Violation from EPA, after this lawsuit was filed, and only upon the request of
Ameren’s in-house counsel. FOF 401, 405-406. Ameren’s in-house counsel asked the
Environmental Services Department to perform this post-project amended “expectations”
analysis to include the results of the amended EDF case that counsel had previously asked Mr.
Hutcheson to run. That case was modeled to include additional efficiency improvements that
had been left off from the Original run. FOF 401-407. Because the Amended analysis was
performed under these circumstances and presumably for the purpose of this litigation, any
credibility the analysis might otherwise have is severely diminished. Ameren’s expert, Mr.
182

King, testified that he would not perform an NSR analysis based on a modeling run that was
created just for NSR purposes, agreeing that in using such a run, a source runs the risk of looking
like it was “cooking the forecast” to project no emissions increase. FOF 408.
In addition to these procedural flaws, the analyses Ameren actually did conduct suffered
from considerable substantive flaws. Ameren’s Original analysis failed to fully incorporate the
improved availability the company expected after the project. The modeling run used for the
projection assumed 95% availability for Unit 2 after the project. FOF 257, 410. But, as
discussed in Subsection II.B.2 above, Ameren expected that the best years after the project
would be 2‒3% higher than that, based on its experience with Unit 1’s record availability in
2008. The justification seeking ultimate approval for the project was based on an availability of
nearly 97%. The regulations require Ameren to consider the highest year of emissions. 40
C.F.R. § 52.21(b)(41)(i). By limiting availability to 95%, Ameren failed to perform a reasonable
analysis under the PSD rules.
Even without fully accounting for the project’s effects, Ameren’s analysis would have
shown an NSR-triggering increase except for what Ameren excluded based on its capable of
accommodating analysis. In calculating the capable of accommodating number, however,
Ameren posited that the unit could have run all available hours and that it could have polluted at
its 95th percentile emissions rate. FOF 412. The effect was that the total capable of
accommodating number was more SO2 per year than Ameren had emitted since 1995 (when
Acid Rain rules were taking effect). FOF 417. Had Ameren used a more realistic emissions rate,
its own analysis would have shown that it was not capable of accommodating the projected
increase. FOF 413–16, 419, 420.

183

The post-hoc analysis by Ms. Ringelstetter begins with the same flaw as Mr. Hutcheson’s
calculation. Ms. Ringelstetter also failed to properly account for the project. She used the same
modeling run as Mr. Hutcheson and as a result did not account for Ameren’s actual, expected
highest year of availability and “business activity.” In addition, she attributed the entire capacity
gain modeled in that run to the turbine, despite the fact that Ameren expected increased capacity
resulting from the boiler work as well, as described in Subsection II.B.2 above. FOF 430.
Finally, Ms. Ringelstetter did not do her own analysis of whether the increased emissions
projected by the model were related to the project.27 FOF 437. She simply assumed they were
not. FOF 437–38. Because her assumptions are incorrect, Ms. Ringelstetter’s analysis is not
persuasive.
EVIDENTIARY ISSUES FROM TRIAL
At trial and in post-trial briefing, both parties moved to exclude, strike, or deem irrelevant
certain testimony or exhibits. For the reasons stated below, to the extent I have relied on
evidence and testimony challenged by either party in my findings of fact and conclusions of law
set out above, the parties’ motions are denied. To the extent I have not relied on the challenged
evidence and testimony, the parties’ motions are denied as moot.
AMEREN’S MOTIONS TO STRIKE TESTIMONY AND EVIDENCE

I.

A. Ameren’s Motions to Strike Mr. Koppe and Dr. Sahu’s Testimony and Evidence
Concerning the Causation of Actual Emissions Increases
In two motions filed during trial (Doc. 787 and 793), and in a motion filed along with its
post-trial briefs (Doc. 832), Ameren moved to exclude certain testimony of Mr. Koppe and Dr.
Sahu, along with related exhibits that were admitted into evidence during trial concerning
27

Ms. Ringelstetter’s analysis of the emissions that unit was capable of accommodating
is also flawed, for the reasons described in Subsection III.B of my Conclusions of Law.
184

causation of the actual emissions increases. Ameren argues the testimony concerning the
causation of the actual emissions increases are new, undisclosed opinions.
While Ameren argues that Mr. Koppe and Dr. Sahu’s opinions are new, there is no
dispute that both Mr. Koppe and Dr. Sahu (1) analyzed the actual post-project data in their
reports, the attachments, and their work papers, and (2) stated that the projected increases
actually materialized. Both Mr. Koppe and Dr. Sahu disclosed in their reports that they analyzed
post-project actual data. Likewise, their opinions about how the projects enable increased
availability and contribute to increases in emissions were discussed in their reports and at their
depositions. Ameren argues that because neither expert’s report states their opinions in the
precise words that Ameren thinks they should have used, the reports did not give notice that the
projects at issue actually caused increases in emissions. But the notice required of expert
opinions is not so formulaic. While undisclosed expert opinions are inadmissible, Rule
26(a)(2)(B) “contemplates that the expert will supplement, elaborate upon, explain and subject
himself to cross-examination upon his report.” Thompson v. Doane Pet Care Co., 470 F.3d
1201, 1202-1203 (6th Cir. 2006) (holding the district court erred in excluding the testimony of an
expert accounting witness because he failed to recite in his report that his opinion was based on
“generally accepted accounting principles,” the phrase used in the contract at issue in the case;
further holding there was no authority for the “mechanical and formalistic ruling” that an
expert’s opinion must state such “magic words”); see also Wood v. Robert Bosch Tool Corp.,
No. 4:13 CV 01888 TCM, 2015 WL 5638040, at *8 (E.D. Mo. 2015) (denying in part a motion
to strike new expert opinion statements because the offered statement “clarifies [the expert
witness’s] earlier information, does not contradict it, and should not be surprising to Defendant
or its experts”). For these reasons, and those set out in the United States’ post-trial brief (see
185

Doc. 831 at 50-56) and its opposition to Ameren’s motion to strike (see Doc. 836), Mr. Koppe
and Dr. Sahu’s challenged opinions are not “new opinions.” Ameren had sufficient notice of
both the United States’ actual emissions case and of Mr. Koppe and Dr. Sahu’s opinions.
Moreover, Ameren cannot show that it was prejudiced by the challenged testimony or the
admission of the exhibits. The evidence the United States presented to show that the actual
emissions increases were caused by the projects was also presented in the context of its
expectations case regarding the expected causes of projected emissions increases, so the
challenged testimony is in part cumulative evidence. Additionally, Ameren had the opportunity
both during pre-trial discovery and during cross-examination at trial to test those opinions. See
Doc. 831 at 50-56. Finally, Mr. Koppe’s testimony regarding Ameren’s full load tests and
related exhibit 928 do not prejudice Ameren. Exhibit 928 is merely a summary exhibit of
Ameren’s own capability data. Ameren itself argued at summary judgment that such summary
evidence containing simple mathematic calculations (averaging pre-project and post-project data
and comparing them) is admissible. Moreover, Mr. Koppe considered the full load tests along
with numerous other materials to reach his conclusion that the capacity increase was due to the
projects, making the exhibit cumulative evidence.
Accordingly, I find that the opinions were sufficiently disclosed and that Ameren has not
suffered any prejudice from the admission of that testimony because it had notice and
opportunity to test it and because it is in part cumulative evidence. As a result, I will not strike
Mr. Koppe and Dr. Sahu’s testimony on the causation of the actual emissions, Mr. Koppe’s
testimony concerning the increased MW capability at Unit 2, or the related challenged exhibits.

186

B. Ameren’s Motion to Strike Dr. Hausman’s Testimony Criticizing Ms.
Ringelstetter’s Opinions
Ameren has also moved to strike certain testimony of Dr. Hausman, arguing that he
offered new opinion testimony at trial when he criticized Ms. Ringelstetter’s analysis. Ameren
asks me to strike Dr. Hausman’s testimony from the record per Fed. R. Civ. P. 26. In the
challenged testimony, Dr. Hausman testified about the different ProSym runs he and Ms.
Ringelstetter analyzed, which included a discussion of why he chose the particular run selected.
This testimony is not a new opinion that should be stricken under Rule 26. Rather, as Rule 26
contemplates, Dr. Hausman’s testimony merely clarified his previously disclosed opinion,
explaining why he chose the ProSym run he used and how the different runs he and Ms.
Ringelstetter used factored into the different conclusions each expert drew. Thompson, 470 F.3d
at 1202-1203. Moreover, Ameren has not shown it was prejudiced by this testimony, as it had
always had the opportunity to test the basis of Dr. Hausman’s analysis. See also Doc. 836 at 17
(discussing the lack of prejudice to Ameren).
As a result, I will not strike Dr. Hausman’s testimony concerning the differences between
his and Ms. Ringelstetter’s analyses because it is not undisclosed testimony and Ameren cannot
show it was prejudiced by the testimony.
II.

THE UNITED STATES’ MOTION TO CURTAIL RE-LITIGATION OF THE
LAW OF THE CASE
In its post-trial brief, the United States also raised an evidentiary issue, renewing its

motion in limine to curtail Ameren’s re-litigation of the law of the case. See Doc. 757; Doc. 758
at Section IV.B. The United States argues that three categories of evidence Ameren presented at

187

trial are irrelevant and should be excluded:28 (1) applicability analyses or permitting documents
that were generated after the projects at issue in this case and involving different facilities
operating under separate state implementation plans at different types of sources, (2) testimony
from EPA or state agency staff regarding the operation and application of regulatory provisions,
and (3) PowerPoint presentations and other pamphlets discussing NSR regulations.
Ameren argues that these categories of evidence are relevant, not to establish the
reasonableness of any legal interpretation, but to establish the reasonableness of its engineering
judgments, emissions analyses, and predictions of the future.
To the extent I rely on the challenged evidence in my findings and conclusions above, I
will deny the United States’ motion. To the extent I have not relied on the challenged evidence,
the motion is denied is moot.
CONCLUSION
For the reasons set out above, I find that the United States has established by a
preponderance of the evidence that Ameren violated the PSD and Title V provisions of the Clean
Air Act. The 2007 project at Rush Island Unit 1 and the 2010 project at Rush Island Unit 2 were
each major modifications under the PSD provisions of the Clean Air Act. Ameren violated the
requirements of the PSD program by failing to obtain a preconstruction permit and install best
available pollution control technology, among other requirements. Ameren also violated Title V
of the Clean Air Act and its operating permit by performing a major modification without
obtaining the required permit and by not including applicable requirements in its operating
28

The United States seeks to exclude the following exhibits and testimony: Ameren
exhibits BQ, PQ, PV, QJ, QS, RB, RC, RD, RE, RG, RH, RN, OY, OZ, PA, PF, and deposition
testimony from David Campbell, Trial Tr. Vol. 12, 9:10-11:8; Gregg Worley, Trial Tr. Vol. 12,
4:2-5:22; and James Stewart, Trial Tr. Vol. 12, 11:4-13:2.
188

permit applications. As a result, I will enter a finding of liability against Ameren. A status
conference will be set to address remedies.
Accordingly,
IT IS HEREBY ORDERED that Defendant Ameren Missouri is found liable under the
Clean Air Act, 42 U.S.C. § 7401 et seq.
IT IS FURTHER ORDERED that a status conference to address remedies is set for
Wednesday, February 15, 2017 at 11:00 a.m. in courtroom 16-South.
IT IS FURTHER ORDERED that the United States’ Motion in Limine to Curtail
Ameren’s Re-Litigation of the Law of the Case #[757] is DENIED per my rulings above.
IT IS FURTHER ORDERED that Ameren’s Motion to Treat Certain KDHE Produced
Documents as Highly Confidential During Trial #[778] is DENIED as moot.
IT IS FURTHER ORDERED that Ameren’s Motion to Bar Robert Koppe’s New
Causation Opinions #[787] is DENIED as moot.
IT IS FURTHER ORDERED that Ameren’s Motion to Bar Dr. Ranajit Sahu’s New
Opinions #[793] is DENIED as moot.
IT IS FURTHER ORDERED that Ameren’s Motion to Strike EPA’s New Expert
Opinion Evidence and Related Trial Exhibits #[832] is DENIED per my rulings above.
IT IS FURTHER ORDERED that the Parties’ Joint Motion to Correct Clerk’s Exhibit
List #[829] is GRANTED.
_________________________________
RODNEY W. SIPPEL
UNITED STATES DISTRICT JUDGE
Dated this 23rd day of January, 2017.

189