# Amicus Curiae Brief — Environmental Defense v. Duke Energy Corporation

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385016_0237%3A23

## Record

- **Collection:** Supreme Court brief
- **Document type:** Amicus Curiae Brief
- **Published:** January 1, 2007
- **Citation:** 549 U.S. 561

## Text

28 FILED

SEP 15 2006
No. 05-848
“OPPICEOPTHE CLERK
SUPREME COURT, U.S.
IN THE

Supreme Court of the Anited States

ENVIRONMENTAL DEFENSE, ET AL.,

Petitioners,
V.

DUKE ENERGY CORPORATION,
Respondent.

' On Writ of Certiorari to the United States Court of Appeals
for the Fourth Circuit

BRIEF AMICI CURIAE OF
THE AMERICAN PUBLIC POWER ASSOCIATION
AND THE NATIONAL RURAL ELECTRIC
COOPERATIVE ASSOCIATION
IN SUPPORT OF RESPONDENT DUKE ENERGY

JANET PITTERLE HOLT*
738 West Glebe Road
Alexandria, VA 22305
(703) 684-6102

RAE E. CRONMILLER
RICHARD H. ROBINSON
NRECA

4301 Wilson Boulevard
Arlington. VA 22203
(703) 907-5791

* Counsel of Record Counsel for Amici Curiae
WILSON-EPES PRINTING CO., INC. ~ (202) 789-0096 — WASHINGTON, D.C. 20001

Maks 4
01 oe
ae | 7
al .*
Ps ee

; ae ents

aa 7 =; -
Mw a 2a, iu yr

oye > al x > A
A 7 A ae se ie re

ri

<
=“

fees

ry

rs i

TABLE OF CONTENTS

eRe er FTE vecesescsncrssscanesnsenintncenenavininemenniin ili
STATEMENT OF INTEREST OF AMICI CURIAE .........0.0000000+ l
SUMMARY OF ARGUMENT ..0.0cccccscceccccsccscssssevsesesssosesessesesscrees 4

I. REQUIRING NSR PERMITTING, A LENGTHY
AND COSTLY PROCESS, FOR REPAIRS THAT
DO NOT INCREASE A FACILITY’S
ACHIEVABLE HOURLY EMISSIONS RATE
WOULD SERIOUSLY IMPEDE THE ABILITY
OF PUBLIC AND RURAL COOPERATIVE
GENERATING SYSTEMS TO SUPPLY
RELIABLE AND AFFORDABLE ELECTRIC
PTT 00: wicermnestinasantennentnandapenagnemapnicnnieesaectimtasenenmectad 5

A. Public Power and the Nation’s Electric
Cooperatives Have a Duty to Provide
Reliable and Affordable Electric Service................... 5

B. Small Electric Generating Systems Often
Rely On Just a Few Units and Must Be Able
to Make Repairs to a Unit Without Taking
that Unit Offline For an Extended Period of

C. Requiring NSR Permitting For Repairs That
Do Not Increase Achievable Hourly
Emission Rates Would Present Small
Utilities With a Hobson’s Choice....................0.ccc00000 7

1. The NSR_ Permitting Process is
Expensive, Time-consuming and Often Not
RET Ise es a Oe eee eS RT 9

2. Obtaining a Synthetic Minor Permit is
Not a Rational, Economically Feasible or
Financially Prudent Alternative......................:.000000 11

il
TABLE OF CONTENTS—Continued
Page
3. For Even a Short Period, the Cost of
Replacement Power During NSR Permitting
Could Be Crippling For Many Public Power
and Rural Cooperative Systems...... ..............scee+esee+ 14

4. Requinng NSR Permitting For Repairs
That Do Not Increase a Unit’s Achievable
Hourly Emissions Rate Would Subject
Small Utilities to Constant NSR Permitting
or Compromise of Capacity. .............ccccsecsceeeseeeeeeees 16

5. The Potential Liability For Public Power
and Cooperatives is Great..................:cccccesseseseeeeeeees 18

Il. USE OF THE NSPS DEFINITION OF
"MODIFICATION" WILL NOT CIRCUMVENT
CONGRESS' INTENT TO REQUIRE
EMISSIONS REDUCTIONS NECESSARY TO
MEET CAA HEALTH, WELFARE AND
ENVIRONMENTAL GOAL G..........cccccessssesesssesseserensees 19

SPD cccepenencesmraptantuinianicceneetnensasettttinneseieimanemiacnengsnes 21

iil
TABLE OF AUTHORITIES

CASES:

Alabama Power v. Costle, 636 F.2d 323 (D.C.
IT: IIIT iiscalielceniacanihiiicdenleahiaenaheninpsendesdatoniaiiiician

Alaska Department of Environmental
Conservation v. EPA, 540 U.S. 461 (2004) .........

New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005)..........

United States v. Duke Energy Corp., 411 F.3d
EEE: CIEE écincncacscotnisessenintbeccyseseenscsnencentn

Wisconsin Elec. Power Co. v. Reilly, 893 F.2d
ge | Eero ENE

STATUTES:
Clean Air Act, 42 U.S.C. 7401 ........cccceccececesssecsseseeeees

Small Business Regulatory Enforcement
Fairness Act of 1996, 5 U.S.C. 801......................

es Se seo cicctcrnicstintedictncnainiiianenioaninnindessinn
Conn. Gen. Stat. Ann. §29-20-108 .0..........ecceecceeeeees
Ga. Code Ann. §46-3-125 ..........cceccecessessseesscsseseeceeenes
La. Rev. Stat. Ann. §33-4545-2 oo...cccceeccecceeeeeeneeenes
Mass. Gen. Laws ch. 164, §47C..0.0.......ccccceceseceeeeeeees
Miss. Code Ann. §77-5-703(C).........cscccssceseeeeeeeeeeeeees
Pe DRT. GREE, CEFR IIID crccsececescosccseteseresecsoctenennesooves

RULES:
LE EE ae ae oem

Page

oe en |

iv

TABLE OF AUTHORITIES—Continued

Page
REGULATIONS:
BOC Be GIS RO certeeetenmennenintenminisiitin 1]
FEDERAL REGISTER:
45 Fed. Reg. 52,676 (Aug. 7, 1980) ).........cccceceseesees 16
63 Fed. Reg. 57356 (Oct. 27, 1998). ........cecscceeceeeeeees 20
OTHER AUTHORITIES:

EPA New Source Review: Report to the
TENNENT NTE Nes Ce 9

IN THE
Supreme Court of the Gnited States

No. 05-848

ENVIRONMENTAL DEFENSE, ET AL.,

Petitioners,
Vv.

DUKE ENERGY CORPORATION,
Respondent.

On Writ of Certiorari to the United States Court of Appeals
for the Fourth Circuit

BRIEF AMICI CURIAE OF
THE AMERICAN PUBLIC POWER ASSOCIATION
AND THE NATIONAL RURAL ELECTRIC
COOPERATIVE ASSOCIATION

All parties consent to the filing of this brief. !

STATEMENT OF INTEREST
Ne OF AMICI CURIAE
Created in 1940 as a non-profit, non-partisan organization,
amicus curiae the American Public Power Association
(APPA) is the service organization for the nation's more than

' No party or its counsel authored this brief in whole or in part nor
made a monetary contribution to amici for the preparation or
submission of it. This brief is filed with the written consent of all
parties pursuant to Rule 37.3(a). Copies of the requisite consent
letters have been filed with the Clerk.

2

2,000 community-owned and community-operated electric
utilities that serve more than 43 million Americans in 49
states or approximately 14 percent of the nation’s electricity
customers. 1,400 of the 2,011 public power systems in the
United States serve communities with populations of 10,000
or fewer. Thirty percent or 29,175 MW2 of APPA’s
members’ power generating capacity is coal-fired.

Although the vast majority of the public power systems is
owned by cities and towns, a number of counties, public
utility districts and even a handful of states have public
power systems. Most public power systems, especially the
smaller ones, are governed by a city council, while others are
overseen by an independently elected or appointed board.

Public power has a strong environmental protection record
and a reputation for reliable and affordable power service.
APPA’s mission is to assist its members in ensuring that
ae-quate, reliable electricity is available to their customers at
a reasonable price while protecting the environment.

Amicus curiae the National Rural Electric Cooperative
Association (NRECA) was formed in 1942 by the nation’s
rural electric cooperative leaders dedicated to electrifying
vast regions of the country and providing reliable and
affordable electric power through electric cooperative entities.
Today, NRECA serves as the national service organization
for 930 not-for-profit rural electric cooperatives that provide
electric service to 39 million Americans in 47 states. Each
electric cooperative is incorporated as a private entity in the
state in which it resides and has a lega! obligation to provide

2 “Megawatt” or “MW” is used to describe the electric generating
(output) capacity of a facility. Another measure of capacity used
by utility engineers describes the capability of a unit to burn fuel
(i.e., its heat input capacity) and is expressed in terms of million
British Thermal Units (mmBtu) per hour. Because unit emissions
are directly related to the amount and type of fuel burned in that
unit, a unit’s capacity to emit is directly related to the unit’s heat

input capacity.

3

reliable electric service to its customer-members.
Collectively, cooperatives serve all or portions of 2,500 of
the nation’s 3,128 counties and their service areas cover 75
percent of the U.S. landmass.

The scarcity of reliable and affordable clectric power in
many regions of the United States in the late 1960’s created a
need for cooperative self-generation of electric power.
Today, sixty-five rural electric generating and transmission
cooperatives (G&Ts), which are owned by the distribution
cooperatives they serve, generate and transmit power to 670
of the 865 distribution cooperatives. Overall, cooperative
G&T generation produces 41 percent of all distribution
cooperative needs. The need to provide reliable, primary
(baseload) and affordable electric power effectively dictated
coal as the fuel of necessity rather than natural gas and
nuclear power. Presently, 80 percent of NRECA’s members’
cooperative generation or 23,000 MW is coal-fired. The
remaining distribution cooperatives receive power directly
from other generation sources within the electric utility sector,
a significant portion of which also originates from coal-fired
generation.

NRECA’s cooperative members are dedicated to offering
their member-consumers a broad array of electric generation
choices including “green power.” Today, about two-thirds of
the cooperatives offer a green or renewable power option.
The majority of this generation is by wind or biomass.

Amici curiae, who are owned by their communities or
customers, represent smaller electric generating entities.
Collectively, amici curiae comprise a significant portion of
the electric generation and distribution industry which, in
turn, serves over 25 percent of electricity customers and over
80 percent of the landmass in the United States. For this

3 Over 95 percent of the members of APPA and NRECA are
considered “small entities” under the Small Business Regulatory
Enforcement Fairness Act of 1996, 5 U.S.C. 801 ef seg.

4

reason, amici curiae provide a unique and invaluable
perspective on the effect that the Environmental Protection
Agency’s (EPA’s) enforcement interpretation of New Source
Review (NSR) can have on the ability to supply reliable and
affordable electric service throughout the United States.

SUMMARY OF ARGUMENT

Requiring NSR permitting under EPA’s NSR enforcement
interpretation when a small electric utility merely takes a
boiler offline to undertake the repair or replacement of a
broken component without increasing the unit’s permitted
capacity to emit (i.e., its emissions rate, unaffected by hours
of operation, or its hourly maximum achievable emissions
rate) is inconsistent with the Clean Air Act, 42 U.S.C. 7401
et seg. (CAA).* It also would be costly, potentially
financially crippling and environmentally unnecessary for
anall public and rural electric generating systems that service
a significant portion of the U. S. population and landmass.
Accordingly, to ensure that these smaller utilities can
continue to meet their duty to provide reliable and affordable
electric service, this Court should affirm the decision of the
United States Court of Appeals for the Fourth Circuit in
United States v. Duke Energy Corp., 411 F.3d 539 (4th
Cir. 2005).

4 Amici curiae’s primary purpose in filing this brief is not to repeat
the reasons why EPA’s position is inconsistent with the letter and
the spirit of the CAA. Instead, amici curiae can provide the Court
with insight into the practical effect of the position advocated by
Petitioners and EPA.

5

ARGUMENT

I. REQUIRING NSR PERMITTING, A LENGTHY
AND COSTLY PROCESS, FOR REPAIRS THAT
DO NOT INCREASE A_ FACILITY’S
ACHIEVABLE HOURLY EMISSIONS RATE
WOULD SERIOUSLY IMPEDE THE ABILITY OF
PUBLIC AND RURAL COOPERATIVE
GENERATING SYSTEMS TO SUPPLY
RELIABLE AND AFFORDABLE ELECTRIC
POWER.

A. Public Power and the Nation’s Electric
Cooperatives Have a Duty to Provide Reliable
and Affordable Elec ric Service.

Public power and electric cooperatives have a duty to
provide reliable and affordable electric service to their
customers. That duty to serve their constituents comes from
state statutes and common law that require the public power
systems > and cooperatives © to provide an adequate,
dependable and economical supply of electric power.’

5 See, e.g., Ga. Code Ann. §46-3-125 (public power authority is
charged with taking all “necessary or desirable action in order to
provide or make available an adequate, dependable, and
economical supply of electric power and energy and related
services”), Miss. Code Ann. §77-5-703(c)\ municipalities owning
electric generation and/or distribution systems have obligation to
provide most adequate, reliable and economical source of electric
power), Neb. Rev. Stat. §70-1403 (public power has obligation to
provide adequate, reliable and economical source of electric

power).

© See, e.g., Conn. Gen. Stat. Ann. §29-20-108 (municipal electric
utilities can form cooperative public corporations to provide
efficient, low cost and reliable electric power), La. Rev. Stat. Ann.
§33-4545-2 (power authority authorized to cooperate with electric
power cooperative associations to ensure an adequate, reliable and
economical supply of electric power), Mass. Gen. Laws ch. 164,

B. Small Electric Generating Systems Often Rely
On Just a Few Units and Must Be Able to Make
Repairs to a Unit Without Taking that Unit
Offline For an Extended Period of Time.

Many factors affect the amount of actual electric generation
produced by steam from a boiler or “emissions unit” of a
coal-fired electric generator — seasonal fluctuations in electric
demand, the availability of other units in the system, the cost
of one unit’s generation relative to other units, the cost of
electricity from other producers and even the annual rainfall,
which affects the availability of electricity from hydroelectric
power plants, which, in turn, affects the demand for
electricity from fossil fuel electric generating units. A
planned or forced® outage at one unit in the system will
paquire immediate increased production at another unit
within the system or region.

From time to time, public power and the electric
cooperatives must take a unit offline to make a repair. Such
a repair characteristically involves replacing a failed or worn
component with a new or refurbished one. Typical examples
of repair work to a coal-fired electric generating boiler are
replacing steam tubing, water pumps and valves. These
types of repairs allow the generating unit to maintain its full,
legal, operational capabilities. EPA’s position in the case
before this Court is that many common (and often minor)

§47C (municipal plant may form cooperative to provide efficient,
low cost and reliable electric power).

7 The cooperatives also have additional duties to serve originating
from service agreements with consumers, corporate bylaws and
articles of incorporation and, for those who acquire financing from
the federal government, provisions in associated loan agreements.

8 Forced outages are unanticipated and/or unplanned periods when
a boiler is brought offline to perform necessary repairs.

7

repairs to units trigger NSR because they are physical
changes that allow the facility to increase its hours of
operation to levels that the unit was capable of achieving or
had achieved in the past.

Although the larger electric generating systems have
dozens of units that are subject to the CAA’s NSR program,
public power and rural electric cooperative power systems
frequently have only a single commercial-sized coal-fired
unit that serves thirty to fifty percent (or in some instances
100 percent) of the system’s electric load. For example, 75
percent of all cooperative generators have a single coal unit
that represents over twenty percent of all the electricity sold.
Twenty-five percent of all cooperative generators have a
single unit that represents thirty-three percent of all
electricity sold. These small systems cannot take a unit
offline a moment longer than necessary to make a repair
without incurring potentially huge financial impacts if
substitute power must be purchased on the wholesale market.

C. Requiring NSR Permitting For Repairs That Do
Not Increase Achievable Hourly Emission Rates
Would Present Small Utilities With a Hobson’s
Choice.

A forced outage in an electric generating system requires
fast and deliberate action. The stakes are particularly high
for smaller systems because, as noted above, a major portion
of the system’s ability to provide electric power to its
consumers is no longer available. Unfortunately, under the
position advocated by Petitioners, when a small system
makes a repair that does not increase the unit’s achievable
hourly emissions rate but may allow the unit to increase
utilization of existing capacity within permit limits, it will be
faced with three equally untenable choices: (1) Obtain an
NSR permit which takes on average 18 months, which would
not be a feasible response to an immediate forced outage;

8

(2) Go through a CAA permitting process and obtain a
“synthetic minor” permit? that effectively imposes permanent
legal limits on the unit’s operations, which process also
cannot be completed expeditiously;!° or (3) Conclude that
no NSR permit is required (for example through a
complicated and uncertain ‘“actual-to-projected actual”
emissions increase analysis) and risk enforcement action
including massive civil liability to the utility and potential
personal criminal liability to the responsible owner and/or
operator if, after retrospective review, the regulatory agency
believes that NSR was applicable.

Under EPA’s enforcement interpretation, during any
planned or forced outage, an operator must determine if a
repair will trigger NSR applicability. In many cases, even
with a planned outage, the actual physical repairs required
are not ascertainable until the unit is actually offline and the
yeernal parts exposed and examined by utility personnel.
This NSR applicability determination can be extremely time-
consuming, complex and uncertain, given varying
interpretations posited by EPA over the years as well as in
this case.

9 A CAA permitting process in which a utility obtains a synthetic
minor permit is a process in which the unit’s operator voluntarily
imposes new lower legal limits on the unit’s allowable emissions,
which in most cases results in limiting the total number of hours
the unit is allowed to operate in a year.

10 A unit may be forced to accept a permit limit on its hours of
operation because the approval and installation of Best Available
Control Technology (BACT) emission controls is not a feasible
response to a forced outage that needs immediate repair. Although
usually shorter than the 18 or more months required to obtain an
NSR BACT permit, depending on the jurisdiction, such a synthetic
minor permit still requires a minimum 30 — 180 day public review
period.

9

1. The NSR Permitting Process is Expensive,
Time-consuming and Often Not Feasible.

The NSR review process consists of the preparation and
submission of a permit application by the owner/operator of
the unit, followed by an extensive review of the application
by the state and/or federal permitting authority. The
application includes an assessment of the air quality impact
of the proposed major modification, an assessment of its
potential effect on national parks or wilderness areas and an
assessment of retrofitted pollution controls called the best
available control technology (BACT) analysis. This review
can take up to two years or more. Many states, in
implementing Federal Clean Air Act requirements,'! provide
for a 30-day application completeness review, a 60-day
agency technical review, a 30-day public comment period
and a 30-day period for a public hearing. In some instances,
the 30-day completeness review re-starts if application
deficiencies are later identified. The BACT determination is
one of the most complex portions of the NSR process
involving a technical feasibility evaluation of alternative
emissions control technologies, cost evaluations of each
technology alternative and an assessment of the
environmental and energy impacts of each alternative. Thus,
the time period from submission of the application to
approval of the permit is typically 18 to 22 months. See, e.g.,
Alaska Department of Environmental Conservation v. EPA,
540 U.S. 461, 515 (2004)(process took 18 months). Even
EPA in its report to President Bush on NSR admitted that the
entire NSR permit process typically lasts between 7 to 22
months. EPA New Source Review. Report to the President
(2002).

'! These requirements are implemented through CAA State
Implementation Plans (SIPs).

10

This period does not include the time necessary to prepare
the application (which can take six months or more) or to
install any resulting controls, which could take years. Even a
NSR_ non-applicability determination typically takes 18
months. If, in order to undertake common repair and
replacement projects, a small utility is faced with the time it
takes to prepare an NSR application, complete the permitting
process, defend legal challenges to the permit and retrofit any
required controls, that small utility may be unable to serve its
customers and, accordingly, may have to forgo such projects.

The NSR permitting process is not only expensive'? and
time-consuming, but the resulting controls can add tens of
millions of dollars in capital installation and annual operating
costs to a system. Moreover, during NSR applicability
determinations and permitting review, a public or cooperative
utility may not be able to provide electricity to its consumers
wth existing generating capacity within its system, and thus
may be forced to buy substitute power from others at
uncertain and usually high wholesale market rates.

For all of these reasons, amici curiae are extremely
concerned because repairs that only maintain a unit’s full
operational capabilities, but do not increase a_ unit’s
maximum hourly achievable emission rate would require
NSR permitting under the position now advocated by EPA
and Petitioners. It is difficult to believe that, by means of a
technical amendment in 1977, Congress intended to expand
the NSR program so radically and to create such a regulatory
obstacle to the supply of reliable and affordable electricity to
millions of households across the nation. Indeed, EPA’s own
interpretation and implementation of the program for nearly
two decades never suggested that NSR could be triggered by
common repairs that merely maintained a facility’s operating

\2 The air permitting application can cost as much as $500,000,
in-luding an assessment of BACT that can cost between $15,000
and $50,000.

11

capabilities without ‘ncreasing the facility’s maximum hourly
emissions rate.

2. Obtaining a Synthetic Minor Permit is Not a
Rational, Economically Feasible or Financially
Prudent Alternative.

Petitioners suggest that one viable option to avoid the full
NSR permitting process is to limit future potential annual
emissions to significant emissions increase levels '? above
representative past emissions by obtaining a synthetic minor
permit. This approach is not at all viable. Avoiding the
lengthy NSR permitting process by artificially limiting unit
utilization would be an enormously expensive and unwise
alternative and is not contemplated by EPA’s regulations.
See Wisconsin Elec. Power Co. v. Reilly, 893 F.2d 901, 917
n.13 (7" Cir. 1990).

Generating units are utilized or “dispatched” in order of
lowest to highest unit operating costs. Even “baseload” coal-
fired utility units rarely operate at more than 80% of annual
capacity factor.'* Lesser utilized or “intermediate load” units
operate at lower annual capacity factors but must be available
to meet increasing electric demand during times of peak
usage within the year or long-term outages of baseload units.
In addition, many electric generating units are designed to
meet both current and future customer electricity demands on
utility systems and thus may not be operated at full
operational capacity for a number of years until electricity
demand grows. In such cases, these intermediate load units

'3 The NSR definition of a significant increase for SO2, NO, and
volatile organic compounds (VOC) is 40 tons but other
significance levels vary. 40 C.F.R. §52.21(b)(23).

'4 “Capacity factor” is the ratio of actual MWH generated in a year
by the unit to the MWH that would be generated if the unit
operated continuously at maximum output.

12

will be ramping up to baseload use. Likewise, some units
may go for years with very minimal operation in areas of the
county where hydro-electric power is the baseload economic
choice and rainfall is adequate for years or even decades.

Under Petitioners’ formulation, each time an operator
makes a repair and accepts a synthetic minor NSR permit
limit, it would have to restrict annual future usage based on
its recent historic levels of operations to avoid the full NSR
permitting process. Under the most recent NSR permitting
process, typically a unit’s future operation under a synthetic
minor permit would be limited to an annual avera~ - emission
based on the 24 consecutive months of highest 0; -ration over
the previous five years. Thus, a small system with a unit
under a synthetic minor permit limit loses its ability to use its
needed and otherwise available and already permitted excess
capability, and faces financially difficult choices in replacing
that ‘ost generation.

Taking a synthetic minor permit in response to a physical
change in lieu of full NSR permitting may appear to be the
most expedient option. This alternative, however, is
typically very expensive. To demonstrate, NRECA
aggregated for all cooperative coal-fired generating units the
difference between their presently permitted electric
generation (including annual emissions) and their generation
(including annual emissions) if each unit were limited to its
annual generation average of the highest 24 consecutive
months within the five years from 2000 to 2004 using U.S.
Department of Energy, Energy Information Administration
(EIA) official data (Form 767). Summing this information
for all cooperative units results in a combined generation loss
of 18.28 percent. Stated differently, of the 23,089 MW of
NECRA member cooperative coal-fired capacity legally
available, the synthetic minor limitations would result in the

13

equivalent of over a 4,220 MW loss,'> which equates to
effectively eliminating over seven large commercial
generating units, representing over $7 billion in replacement
coal-fired generation.'® This lost generation capacity would
be enough to provide electricity to over 3.3 million
residential homes. !’

This loss of over 18 percent of cooperative generation
capacity that would result if Petitioners’ view of NSR were
the law simply is not a viable option for small electric
systems and cannot be justified to the customers of a public
power system or to the members of a not-for-profit
cooperative. The diminished unit availability would impact
capital cost recovery, negatively affect financial credit ratings,
and increase rates as additional generation facilities or the
purchase of substitute power would be needed to make up for
the lost generation capacities. Thus, synthetic minor
permitting is not a rational, economically feasible or
financially prudent alternative for the communities that own
public power and for the consumers that own cooperative
systems. This result certainly could not have been what
Congress intended.

'5 Technically, the loss is not one of capacity (MW), but one of
generation output, best expressed in a megawatt-hour (MWh)
metric. The MW capacity loss cited here is derived by dividing
the MWh loss by 8,760, the total number of hours in a year.

16 The replacement generation cost estimate of $1,700/KW
(kilowatt) installed capacity is based on Department of Energy,
Energy Information Administration (EIA) estimated “overnight
cost” of new coal-fired generating adjusted to include a 10 percent
contingency factor reflecting change orders in contracts during
construction, a 4 percent real dollar increase in materials and labor,
and a 7 percent cost of financing during five years of construction.

'7 This calculation is based on average sales to residential
consumers based on EIA Electric Sales Revenue and Price, 2004
publication.

14

3. For Even a Short Period, the Cost of
Replacement Power During NSR Permitting
Could Be Crippling For Many Public Power
and Rural Cooperative Systems.

The cost of replacement power purchased on the spot
wholesale electricity market can be considerably more
expensive than the power produced by a utility’s own
generating facilities because the price of substitute generation
is market-based. The difference between the small utility’s
own generation cost and the price of substitute generation
purchased on the wholesale market is especially exacerbated
ai times of peak demand such as during summer or winter
because the wholesale market price of electricity is based on
the cost of the last and most expensive generation, i.e., the
last to dispatch in the region. One large APPA member in
the West has seen the market price of wholesale electricity
range from $50 to $400 per MWH during summer hours or
other high load periods — a 700% price differential.

To illustrate the financial impact of the high cost of
replacement power, for every twenty-four hour day a
baseload commercially sized 600 MW unit is offline, the
difference between the cost of replacement power and the
cost of power generated by the unit can easily amount to
$576,000 per day, over a 330% increase.'* Taking a

'8 This result comes from standard engineering calculations
assuming 80% annual capacity usage of the 600 MW unit and
8,760 hours in a year. Baseload generation costs of $15/Mwh, a
realistic conservative average, and replacement power costs of
$65/MWh were used. The replacement power cost is also a
conservative estimate based on the average future prices derived
from the five regional electricity trading hubs of PJM, Cinergy,
Entergy, ERCOT, and Palo Verde over the twenty-month forward
period beginning on August 2006. This information is provided by
the energy brokers Amerax, Preban and TFS; and pricing reports
in Platt’s Megawatt Daily and NYMEX. Transmission costs,
which can be very substantial, were excluded from this calculation.

15

synthetic minor permit for the unit assuming an 18% loss of
capacity, a likely reduction discussed earlier, would cost the
small utility over $70 million for the first 18 months for
substitute power. This last figure, however, ignores the costs
of supplying power after the initial 18-month period. To
replace the 18% loss of capacity quickly, in 18 months, gas
generation would likely be constructed or purchased,
resulting in an additional cost of almost $69 million, '°
making the combined costs of supplying substitute
generation while other generation is built plus the new
generation total $139 million. Thus, in taking a commercial
unit offline in a public power or cooperative system for even
a few months while that system seeks an NSR permit, an
NSR applicability determination or even a synthetic minor
permit, the system would have to purchase replacement
power at significantly higher prices and, ultimately, a
significant rate increase could be necessary to cover the
higher cost of purchased power and potentially building new
power. Depending on the relative financial impact, credit
ratings and potentially even the financial stability of these
small systems could be very negatively affected.

Thus, during the 18-month NSR permitting process (or
even in the synthetic minor permitting process), the small
system would be forced to purchase replacement power in
the wholesale market, which, depending on the prevailing
rates, could spell severe economic problems for the system.
Moreover, accepting an artificial cap on operations by means
of a synthetic minor permit and operating well below

'9 This calculation assumes combined cycle gas generation capital
costs of $625/K W based on the EIA 2006 Annual Energy Outlook.
The unit could be permitted in an expedited process as a Clean Air
Act minor source and built in only 18 months. The calculation
does not reflect the actual cost of power generation from this type
of gas unit; it reflects only construction cost. Considering
historically high natural gas prices, the overall cost of generating
power from this unit operation would be considerably higher than
the coal-fired generation it would replace.

16

capacity - - which systems might be forced to do - - would
significantly impair the capital of the system.

Faced with these obstacles, under Petitioners’ view, small
generating systems would find it difficult, if not impossible,
to meet their obligation to provide reliable and affordable
electric service. Congress hardly could have intended to
require small systems to undergo the lengthy and costly NSR
permitting process every time they made a repair to a unit
that did not increase its maximum achievable hourly
emissions rate, and EPA could not have done so in its
regulations without disclosing the extraordinary expansion of
the NSR program it was contemplating and assessing the
equally extraordinary economic impact of such an expansion.
Yet, when it promulgated the 1980 NSR Rules, EPA’s
economic assessment showed no such expansion. See 45 Fed.
Reg. 52,676, 52,729 (Aug. 7, 1980).

4. Requiring NSR Permitting For Repairs That
Do Not Increase a Unit’s Achievable Hourly
Emissions Rate Would Subject Small Utilities
to Constant NSR Permitting or Compromise of
Capacity.

The problems generated by subjecting units to the NSR
permitting process for repairs that do not increase the unit’s
maximum achievable hourly emissions rate are multiplied by
the frequent shifts in generation loads or hours of operation
of a unit within a small system. As set forth above,
numerous planned and unplanned factors, including seasonal
demand, forced outages and rainfall, affect the usage of a unit.
If small utilities are required to go through the NSR review
process for common repairs, such as those targeted by EPA
in the NSR enforcement initiative, small utilities will be in a
constant NSR permitting cycle.

Under EPA’s enforcement interpretation, every repair or
replacement of a component such as a tube assembly, pump

17

or valve - - which occurs frequently over the life of a
generation unit - - would put the operator in the same
predicament — undergo a lengthy NSR permitting process and
install controls or limit capacity. If the utility chooses the
more expedient option of a synthetic minor permit, it will
find itself in a downward spiral, successively limiting its
operations further and further below its permitted, full
operational capabilities.

The dilemma faced by a small electric system
contemplating repairs to a unit is exacerbated by the
methodology for determining whether an annual emissions
increase would occur if that methodology requires a
“projection” of likely future utilization within permitted
capacity. Such a projection is, at best, fraught with
complexity, subjectivity and uncertainty.?°

In the enforcement cases, EPA posited an outcome-
determinative methodology that assumes that whenever a
component that caused forced outages in the past is repaired,
the repair will inexorably lead to “recovered” utilization and
thus an increase in hours of operation and, therefore,
emissions. This approach is in contrast to the NSPS
maximum hourly emissions test, which is purely an
engineering evaluation of the fuel burning (and therefore
emitting) capacity of the unit in question.

20 Any emissions increase test that is based on projected utilization
requires seer-like knowledge because it must be applied at the time
of the proposed project and prior to post-project operation, when it
is impossible to predict all future unit operational parameters that
may affect emissions. For example, fuel characteristics such as
inherent sulfur concentrations can vary unpredictably over time,
resulting in annual unit emissions increases unrelated to any

physical change; and seasonal generation demands on the unit due
to weather or unit outages can force a greater operational burden
on the unit than predicted. Additionally, many other unforeseeable
factors can cause subtle unit emission increases unrelated to any
physical change.

18

Thus, small utilities in particular will face significant
uncertainty and expense because an NSR applicability
determination implicates systems having only several units
whose annual production and operating hours vary
considerably as these units experience differing maintenance
Outage times and production rates to meet dispatch
obligations on a year-to-year basis. The position advocated
by EPA and Petitioners, which is not consistent with the
requirement for a “modification” as determined under the
New Source Performance Standards (NSPS), will make it
impossible for small electric utilities to maintain their units
as required or make desirable efficiency improvements.
Operators will hesitate to take units offline to replace
components to maintain unit performance because of the
complicated analysis that would have to be performed to
make an educated guess as to the risk that the repair will
trigeer NSR review - - a complicated analysis that is always
subject to second-guessing because no one can accurately
predict how the myriad of factors that affect the utilization of
one unit within the system will change in the future.

Certainly, Congress could not have intended to subject
small electric systems to such expense and uncertainty every
time a unit undertakes the type of projects targeted in EPA’s
enforcement initiative. Yet, this will be precisely the result
so long as the test required for NSR applicability is not keyed
to a repair that actually increases a unit’s maximum
achievable hourly emissions rate.

5. The Potential Liability For Public Power and
Cooperatives is Great.

If an operator errs in forgoing NSR permitting, the
potential CAA liability is $32,500 per day per occurrence
(i.e., per pollutant). If sulfur dioxide (SO2) and nitrogen
oxides (NOx) triggered NSR review bu: the utility failed to

19

realize it for a year 27! , the potential liability for
noncompliance is $23,725,000 (365 x 2 x $32,500). 42
U.S.C. §7413(b). The utility could also face injunctive relief,
including the cost of BACT, as well as potential personal
liability.

Subjecting small utilities to the NSR applicability process
for a mere increase in hours of operation after a common
repair creates uncertainty over whether NSR permitting is
required. Cooperatives and public power systems selecting
any one of the Hobson’s alternatives would face significant
financial burdens because of loss of ability to utilize full
generation capabilities of units that have required very
significant capital investments, as well as additional costs to
provide substitute generation to avoid abrogating their duty
to their customers to provide reliable and affordable electric
service.

Il. USE OF THE NSPS’ DEFINITION OF
"MODIFICATION" WILL NOT CIRCUMVENT
CONGRESS' INTENT TO REQUIRE EMISSIONS
REDUCTIONS NECESSARY TO MEET CAA
aa. WELFARE AND ENVIRONMENTAL

Contrary to Petitioners’ claims, rejection of EPA’s
enforcement interpretation will not circumvent Congress’
intent to require emissions reductions necessary to meet CAA
health, welfare and environmental goals. A significant
portion of public power and cooperative coal-fired generation
already meets NSPS requirements and/or has been through

2! As discussed in Alabama Power v. Costle, 636 F.2d 323, 401
(D.C. Cir. 1979), a facility’s “net” emissions across all the units at
a facility over a five-year contemporaneous period are considered.
See also, New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005).

pan 20
New Source Review, and is equipped with modern pollution
controls.

Over 60 percent of public power’s coal-fired generation
already meets applicable NSPS requirements under the CAA.
Likewise, over 50 percent of cooperative coal-fired
generation already meets applicable NSPS requirements
under the CAA. Additionally, 20 percent of all cooperative
generation has gone through NSR.

Moreover, even those units that have not been through any
form of new source review are well-regulated and will
continue to be subject to other, increasingly stringent CAA
programs that ensure that these facilities are well-controlled
without interfering with their duty to serve. For example,
due to subsequent CAA regulatory mandates effectively
forcing pollution control retrofits on the remaining and older
cooperative units, 90% percent of cooperative generation
usir~ high sulfur coal is equipped with flue gas
desulfurization (FGD) units to control sulfur dioxide (SO)
emissions, the primary pollutant associated with coal-fired
generation.”? In addition, virtually all cooperative generating
capacity in the Eastern United States, equaling about 6,000
MW, is also retrofitted with state-of-the-art nitrogen oxides
(NO,) controls, Selective Catalytic Reduction (SCRs),
because of EPA’s NO, SIP Call requirements promulgated
in 199823, to control Eastern ozone. Almost all cooperative
coal-fired generation is also equipped with low-NO, burner
technology regardless of where the units are located.

Thus, even though much of cooperative and public power
coal-fired generation is newer and/or equipped with state-of-
the-art pollution controls, electric cooperative generation and
public power units would still be subject to the lengthy and
costly NSR applicability process under EPA’s NSR

22This number includes one commercially sized unit where the
FGD retrofit is ongoing.

23 See 63 Fed. Reg. 57356 (Oct. 27, 1998).

21

enforcement interpretation, which would jeopardize their
ability to provide reliable and affordable electric service.

CONCLUSION

Under Petitioners’ view of NSR, the operator of a small
electric utility who merely needs to replace a broken part
would be forced to endure a lengthy NSR process and to
navigate through a test that is so complex, confusing and
fraught with subjectivity that it has gone through years of
EPA iterations, interpretations and court battles. For the
foregoing reasons, the judgment below should be affirmed.

Respectfully submitted,

JANET PITTERLE HOLT*
738 West Glebe Road
Alexandria, VA 22305
(703) 684-6102

RAE E. CRONMILLER
RICHARD H. ROBINSON
NRECA

4301 Wilson Boulevard
Arlington, VA 22203
(703) 907-5791

* Counsel of Record Counsel for Amici Curiae

September 15, 2006

---

Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385016_0237%3A23. Public record. Not legal advice.