20110527Woollums Di.pdf

RECEIVED
2fltHAY27 AHll:OI
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR
APPROVAL OF CHANGES TO ITS
ELECTRIC SERVICE SCHEDULES
AN A PRICE INCREASE OF $32.7
MILLION, OR APPROXITELY
15.0 PERCENT
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) CASE NO. PAC-E-l1-12
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) Direct Testimony of Cathy S. Woollums
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ROCKY MOUNTAIN POWER
CASE NO. PAC-E-l1-12
May 2011
1 Introduction
2 Q.
3 A.
Please state your name and business address and position.
My name is Cathy S. Woollums. My business address is 106 East Second Street,
4 Davenport, Iowa. My position is senior vice president of environmental services
5 and chief environmental counsel for MidAmerican Energy Holdings Company
6 (MEHC). PacifiCorp is a subsidiar ofMEHC.
7 Qualifications
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Please describe your education and business experience.
I received a Bachelor of Ars Degree in Political Science from Winona State
University and a Jurs Doctorate from Drake University Law SchooL. I was
admitted by examination to practice law in Iowa and Ilinois and maintain my
licensure in both states. Following law school, I served a one-year appointment as
a law clerk in the 7th Judicial Distrct in Iowa and then entered the private practice
of law where I was engaged in general and litigation for approximately three
years. I joined Iowa-Ilinois Gas and Electrc Company, a predecessor of
MidAmerican Energy Company and MEHC, in 1991 where I served in the
capacity of an attorney within the general counsel's offce and handled
environmental matters, among others. I became the manager of environmental
services in 1995 and have held increasing positions of responsibilty for
environmental issues within MEHC. In my curent role as the senior vice
president of environmental services, I have responsibilty for the development and
implementation of MEHC's worldwide corporate environmental policy, strategy
and programs, including the development of comments on proposed state and
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federal laws and regulations, integrating environmental assessments of existing
and anticipated environmental regulations into planning and operating decisions
of business units, and advising management of the impact of proposed regulations
and developing potential compliance strategies. In addition, I oversee the
organization's environmental compliance assurance management program,
environmental permitting and reporting, and environmental litigation.
I have served on the Iowa State Bar Association's Environmental and
Natual Resources Section Council, the Edison Electrc Institute's Environment
Executive Advisory Committee, the Iowa Climate Change Advisory Council, the
Midwestern Governors' Association Power Sector Working Group, the
Midwestern Governors' Renewable Electrcity Advanced Coal with Carbon
Captue Advisory Group, and The Climate Registr Advisory Committee. I was
appointed to serve two terms as the Iowa governor's appointee to the Clean Air
Act Compliance Advisory Panel, chaired the Iowa Association of Business and
. Industr's Environmental Committee for four years, and was recently invited to
serve on the GHG Reporting and Mitigation Advisory Committee, a partership
of The Climate Registr and the Greenhouse Gas Management Institute.
Have you previously provided testimony before regulatory bodies?
Yes. While I have not had the opportity to testify before the Idaho Public
Utilties Commission, I am a Company witness on environmental matters pending
before the Wyoming Public Service Commission and I have testified in hearngs
before the Environmental Protection Agency ("EPA") and varous state
environmental proceedings. I have also provided testimony before various
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1 legislative bodies.
2 Purpose of Testimony
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What is the purpose of your testimony?
The purose of my testimony is to provide the Commission and parties with
information supporting the prudence of the Company's pollution control
expenditues for coal-fired power generation plants and the Company's processes
to identify. environmental policy and compliance drvers that influenced the
installation of the emissions controls that are subject to review in this case.
Does your testimony discuss the complexity in balancing stakeholder
interests that the Company faces in making prudent pollution control capital
investment decisions?
Yes. There are many different viewpoints regarding whether the Company should
make investments in its coal-fueled facilities. Some stakeholders take the position
that it is imprudent to make those investments prior to the time they are absolutely
required; some believe that the environmental regulations are too uncertin to
make such investments. Others believe no controls should be installed because the
units should be shut down. Compliance with curent environmental requirements
is necessary to ensure the availability of a reliable source of electricity at a
19 reasonable cost, now and into the futue.
20 Justifcation of Pollution Control Investment
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Why has the Company invested in pollution control equipment?
Because it is legally required to do so. Through the 1977 amendments to the
Clean Air Act, Congress set a national goal for visibility to remedy impairent
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from manmade emissions in designated national parks and wilderness areas; this
goal resulted in development of the Regional Haze Rules, adopted in 2005 by the
EPA. The first phase of these rules trgger Best Available Retrofit Technology
("BART") reviews for all coal-fired generation facilities built between 1962 and
1977 that emit at least 250 tons of visibility-impairg pollution per year.
Visibilty-impairing pollutants include sulfu dioxide SOl, nitrogen oxides NOx
and partculate matter ("PM"). The Company has 14 units that meet the
constrction and emissions threshold criteria and are, therefore, "BART-eligible
units." Pursuant to federal regulations at 40 CFR 51.308(e)(1)(ii), each state is
required to determine which BART-eligible sources are also "subject to BART."
BART-eligible sources are subject to BART if they emit any air pollutant that
may reasonably be anticipated to cause or contrbute to impairment of visibilty in
any designated national park or wilderness area. The investments in pollution
control equipment are at the Company's BART-eligible units that have been
determined by the state environmental regulators to be necessary after considering
available technology; costs of compliance; energy and non-air quality
environmental impacts; existing control equipment and the remaining useful life
of the facility; and the degree of improvement in visibility reasonably anticipated
to result from the use of such technology.
Have the state environmental agencies in Wyoming and Utah completed their
BART determinations?
Yes. After considering these five factors, the respective state deparents of
environmental quality for the units made their BART determinations and
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incorporated the results of the above mentioned BART analyses into the operating
permits, constrction permits and Approval Orders (defined below) for the
pollution control equipment included in this case.
With respect to the Naughton Unit 2 low NOx burers and Wyodak low
NOx burers and bag house projects, the Wyoming Departent of Environmental
Quality ("WY DEQ") issued BART permits for those units on December 31,
2009, incorporating the equipment and installation schedules recommended via
the BART reviews. The conditions of the BART permits have been incorporated
into the Wyoming State Implementation Plan ("SIP") for Regional Haze in
support of its goals to reduce visibilty impairg emissions. The Wyoming SIP is
subject to EPA review and approvaL. The WY DEQ has also issued constrction
permits for the Naughton, Wyodak, and Jim Bridger pollution control projects
included in this case.
With respect to the Hunter Unit 2 and Huntington Unit 1 projects, the Utah
Departent of Environmental Quality ("UT DEQ") has incorporated the results of
BART reviews completed for those facilities into the Utah SIP. The Utah SIP is
also subject to EPA review and approval. The State of Uta has also issued
Approval Orders (i.e., permits to constrct) for each of the Hunter and Huntington
pollution control projects included in this case.
Are the Regional Haze regulations fmal?
Yes. The Regional Haze regulations were initially adopted in 1999 but were
appealed and revised, with amended regulations being issued in 2005. Both Utah
and Wyoming submitted their initial Regional Haze state implementation plans in
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2003, in 2008, and again in 2011, focusing on meeting emission reduction goals
to improve visibility. The attched Exhibit No. 18 demonstrates the EPA's
timeline for states to implement the Regional Haze rule; however, the timeline
does not include the time for EPA to take final action on the proposed regional
haze state implementation plans. The 2011 state implementation plan submittls
are final insofar as state action is considered; these submittals have not yet been
approved by the EPA but, nonetheless, do result in substative requirements being
imposed on the Company's facilities. These requirements are confired in the
WY DEQ's Decision Document on the Company's BART permit applications
dated December 31, 2009, noting:
The entire submittal is curently undergoing EPA review and the
State has no control over how long the EPA takes to review the
SIP. The State, however, does not wait for EPA to complete its
review before implementing a SIP. . .The SOi levels have shown
compliance with the milestones and continue to demonstrate
declining SOl emissions levels.
Do the pollution control investments included in this case also support
compliance with other environmental regulations?
Yes. In addition to the BART requirements under the Regional Haze Rules,
increasingly more strgent National Ambient Air Quality Standards have been
and are being adopted for criteria pollutants, including SOl, NOi, ozone, and PM.
Implementation of the pollution control projects described herein assists in
meeting these more strngent standards, avoiding the negative consequences of an
area being declared to be a nonattainment area. Furher, while the Clean Air
Mercur Rule, which would have required a reduction of mercur emissions of
approximately 70 percent by 2018, was overted by the United States Cour of
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Appeals for the Distrct of Columbia Circuit in February 2008, the EPA has
proposed a new rule that wil require coal-fired generating facilities to reduce
mercury, and other emissions of hazardous air pollutants, through a Maximum
Achievable Control Technology (MACT) stadard. Under a consent decree, the
EPA issued a proposed rule to regulate hazardous air pollutant emissions in
March 2011 and must issue a final rule no later than November 2011. Compliance
with the final stadards is expected to be required by November 2014. The bag
house and scrubber projects described herein wil assist in meeting the
forthcoming MACT requirements.
Utah also has specific state regulations (State Rule 307-424-4) that require
electrc generating units to meet specific mercur emission rates or control
effciencies, notwithstanding any federal rules. The bag house and scrubber
projects at the Hunter and Huntington facilities will assist in meeting the
requirements of that regulation as welL.
In short, the pollution control investments contemplated in this case are
required to maintain compliance with the environmental requirements described
above.
Please clarify the definition of a "presumptive BART emission limit" as it
pertains to established federal pollution control standards.
The use of the term "presumptive BART emission limit" in the instance cited
does not mean that BART emission limits are uncertin futue requirements.
Instead, the use of the term refers to emission rates identified in the Regional
Haze Rule, Code of Federal Regulations (CFR), Title 40, Sections 51.300 through
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1 51.309, and Appendix Y. Electronic copies of the referenced CFRs can be found
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3 http://www.access.gpo.gov/nara/cfr/waisidx 09/40cfr5l 09.html
4 Presumptive BART emission limits come from Appendix Y cited above, and are
5 rates defined by the EPA. States use the rates defined by the EPA to assist in
6 determining whether a BART-eligible facility is presumed to meet the
7 requirement to install best available retrofit technology. For example, if the
8 installation of 10w-NOx burers on a BART-eligible facilty with cell-burers
9 firing sub-bituinous coal achieves an emission rate of 0.28 Ib/MBtu, which is
10 below the EPA presumptive BART rate of 0.45 Ib/mmtu (the presumptive rate
11 for a cell-burer unit buring sub-bituinous coal), it can be presumed that the
12 installation of 10w-NOx burners on this unit meets federal BART requirements
13 with respect to NOx control, and no additional controls would be likely to be
14 required. With respect to SOl control, the states of Utah and Wyoming, along
15 with New Mexico, are participating in a market-trading program identified in the
16 Regional Haze Rule, CFR, Title 40, Section 51.309. Under this program the states
17 have set SOl emission reduction milestones that must be achieved. These
18 milestones have been developed assuming that each coal-fired generating unit
19 meets the lower of its historic emission rate or the presumptive SOl rate. The EPA
20 has defined the presumptive SOl emissions rate as 0.15 Ib/mmBtu or 90 percent
21 removaL. Here again, if the installation of pollution control equipment on a
22 BART-eligible facilty achieves an emission rate less than that presumptive limit
23 and overall emission reduction goals are being met, it can be presumed that the
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installation meets federal BART requirements and no additional controls wil be
required.
Please describe the process the Company engages in to determine whether to
make investments in environmental controls.
First and foremost in the decision to invest in environmental controls are the
Company's compliance obligations. If a permit or regulation requires the
Company's plants to reduce emissions or achieve emission limits that canot be
met with existing equipment, compliance options are examined to ascertin what
equipment can be installed to achieve the emission requirements. The Company
also monitors state and federal rulemakg activities and legislative proposals that
would have an impact on the facilties' operations. Monitorig these futue
requirements allows the Company to ensure it is taking a longer term view of the
potential investments that may be required to lawfully continue operation of the
facilities.
How does the Company plan for existing and future environmental
requirements?
Existing environmental permit and regulatory requirements, such as operatig
within a permitted emission limit or complying with the regulatory requirements
of waste management activities, are implemented through operating practices,
procedures, and plans on a daily basis within the Company's operating facilities.
New compliance obligations may be imposed when operating permits are
renewed or applied for to reflect changes in regulatory requirements. To assess
the potential impacts of new environmental regulatory initiatives, the Company
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employs environmental professionals in the business units who coordiate with
dedicated staff in the environmental policy and strategy group; we review
proposed and final regulatory requirements and are actively engaged in the
regulatory processes at both the state and at the federal leveL. We seek feedback
from our environmental regulators to assess their concerns, read and analyze
legislation and regulations proposed at the state and federal levels, provide
feedback on legislation, and review and comment on proposed reguations. The
Company submits wrtten comments in regulatory proceedings and paricipates in
public heargs on the proposals, ensurg that the Company's concerns or
support, as appropriate, are considered in these public forus. We are both well
informed and engaged on these issues.
In addition, when significant environmental rulemaking or legislative
proposals are released, . we assess those proposals and advise Company
management of the potential impacts of the proposals. If the preliminar or final
form of a proposal would alter the Company's business plan, those plans may be
amended to reflect the likely impact on the Company to achieve compliance with
the requirements within the relevant compliance period after considering our
compliance options.
When you consider the Company's compliance options, what factors are
considered?
There are a multitude of factors, depending on the specific regulation. If a
regulation prescribes a specific emissions limit, the Company reviews what tyes
of controls may be available to achieve the requisite emissions limit, given the
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1 specific characteristics of each unit. System impacts, reliabilty, capital costs,
2 operating and maintenance costs; the life of the controls, the life of the unit itself,
3 cost of replacement generation, and other factors are all considered. If an
4 emissions trading mechanism is available to achieve compliance, the costs of
5 obtaining the emissions allowances is compared to the costs to install and operate
6 controls, considering the factors noted above.
7 Timing of Investments
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How are future environmental requirements factored into the Company's
analysis of its environmental compliance options?
The Company develops a base set of environmental assumptions that reflects the
most likely scenarios to comply with air, water and waste regulations for
inclusion in the development of its annual business planing process. These
environmental assumptions reflect both existing and expected requirements under
the most likely scenario and are utilized as the basis for the Company's integrated
resource planning as well as for the Company's 1O-year business plan. We also
examine the actual and potential compliance time frames and how those
timeframesmay be coordinated with planed plant outage schedules.
Coordinating major environmental control projects with existing outage schedules
allows the Company to avoid additional outage time, reducing the need for
replacement power, minimizes costs, and maintains system reliabilty.
Why is PacifiCorp installng pollution control equipment at this time?
The Company is installng pollution control equipment at this time to comply with
the Regional Haze Rules, as well as in response to more strngent National
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Ambient Air Quality Standards, the impending mercur requirements, and a
number of existing and emerging emission reduction requirements. Final
installation activities and tie-in of the pollution control equipment described
above can only be accomplished when the units are off-line. Meeting the timing
requirements of constrction permits and Approval Orders and reducing plant
outage time necessitated completion of final installation activities and tie-in of the
pollution control equipment durg the scheduled overhauls within this test
period. Installation of the pollution control equipment and associated systems
included in this case represent a significant step for PacifiCorp's coal..fueled
power plant fleet toward meeting the SOl and NOx reductions required by the
Regional Haze Rules and established by the respective states' emissions reduction
milestones.
Has the Company installed the pollution control investments presented in
this case prematurely?
No. The Company has been engaged in Regional Haze Rule compliance planning
with the respective state departents of environmental control since the initial
development of the western states' regional program. Durng the initial 2003 to
2008 planing period, the Company was required by the Wyoming Division of
Air Quality ("WDAQ") to conduct detailed BART reviews. It was the initial
expectation of the western states' regional haze program that individual states
would establish BART emission limits for BART eligible units and would require
installation of appropriate controls by 2013. PacifiCorp originally submitted these
evaluations of its BART eligible facilities in Wyoming in Januar 2007, with
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revisions submitted in October 2007. Addendums to individual facilty BART
reviews were developed in March 2008. WDAQ completed its final reviews of
the BART evaluations and the Company's associated permit applications and
issued Air Quality Permits (constrction permts) for the projects presented in this
case in May 2009. WDAQ followed up by issuing BART permits for the pollution
control projects presented in this case in December 2009. The pollution control
projects presented in this case meet the Company's obligations in this regard.
Did the Company follow a similar process for its Utah coal fueled plants?
Yes. For the Hunter and Huntigton scrubber projects the Company completed
detailed scrubber technology screening studies in 2007 and submitted its Notice
of Intent (constrction permit) applications to the Utah Division of Air Quality
("UDAQ") for the Hunter project in November 2007, with supplements submitted
in December 2007, and its Notice of Intent application for the Huntington project
in April 2008, with a supplement submitted in January 2009. UDAQ completed
its final reviews of the Company's permit applications for the pollution control
projects and issued Approval Orders (constrction permts) in March 2008 for the
Hunter projects and January 2010 for the Huntington projects. UDAQ also
included these projects in its regional haze SIP in 2008. The pollution control
projects presented in this case meet the Company's obligations in this regard.
Do the timelines discussed above provide a reasonable progression of
evaluation, agency coordination, and decision-making for the respective
pollution control projects?
Yes. The pollution control projects presented in this case are extremely complex
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and require a significant amount of evaluation and planning to brig to frition.
The permitting processes described above are required to define the technical
requirements the Company needs to move forward with establishing competitive
pricing for the work and ultimately executing the projects. The time line for
securng contracts for this tye of work through project completion often has a
multi-year duration.
Did other regional emissions control regulations impact planning of the
Company's scrubber projects?
Yes. The states of Utah and Wyoming also participate in a Regional SOl
Milestones and Backstop Trading Program. These pollution control investments
support the milestones established in these states as par of this program.
Did the Company consider future environmental requirements when
undertaking the emission reduction projects proposed for cost recovery in
this case?
Yes. While the projects proposed in this case were implemented as a result of
curent environmental requirements, the Company also considered the need for
the emission reductions and the tye of controls that could be required in the
future when it planed for these projects. There are a multitude of environmental
requirements the electric industry faces over the next several years. Exhibit No.
19, referenced colloquially as the so-called "EPA train wreck" slide, identifies
some of the requirements that are curently underway or in development. There is
a great deal of uncertinly associated with futue environmental requirements;
however, the Company must comply with the requirements that exist today and
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prepare for the regulations that wil be adopted in the futue.
Is there emission reduction equipment that is being installed to comply with
the requirements that exist today that would not be required in the future?
No. The controls are required to comply with existing requirements. Furer, the
addition of scrubbers, 10w-NOx burers and baghouses wil position the Company
well to meet impending environmental requirements, including the Utilty
Hazardous Air Pollutant Maximum Achievable Control Technology standards
that were proposed on March 16,2011, and wil be final in November 2011.
Did the Company need to make the investments included in this case if it
expects to continue operating the plants?
Yes. In order to comply with the requirements that are set forth in the facilties'
air quality permits, it is necessary to install and operate the controls in question.
The Company has an obligation to operate its facilities in compliance with its
permit requirements and the applicable laws and regulations. There have been
many electric utilities around the countr that have made announcements that they
plan to retire plants rather than make investments in emissions control equipment.
These planned retirements are not limited to coal-fueled plants, as evidenced by
Exelon's December 8, 2010, announcement that it would shut its Oyster Creek
nuclear plant ten years early to avoid having to comply with a requirement to
install cooling towers, because doing so would cost more than the value of the
plant.! The Company does not have plans to shut down the facilities in which the
proposed investments have been made.
1 See: htt://ww.nytimes.com/2010/12/09/nyregion/09nuke.html? _r= 1 &parer=s&emc=rss
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Shouldn't the uncertainty associated with future environmental regulations
weigh in favor of waiting unti the regulations are final to install any
controls?
No. The full and final scope of environmental regulations is not easily
determined, paricularly when rulemakings are often lengthy in their own right
and just as often followed by extensive and lengthy litigation before the rule is
finalized. Perfect foresight is not possible; the EPA has recently begu to
acknowledge that its approach to regulation makes it difficult for companies with
compliance obligations to make long-term decisions on compliance. In EPA
Administrator Lisa Jackson's remarks prepared on the release of the Utility
Hazardous Air Pollutants Maximum Achievable Control Technology standards
(HAPs MACT) on March 16,201 i, she stated:
The proposal and implementation of these standards wil also have
benefits for American utilties. For the first time in twenty years,
they wil have certainty about the standads they must meet. And
setting national standards for mercur and air toxics will level the
competitive playing field and close loopholes for big polluters.
Utilities that have already put pollution control technology in place
wil no longer have to compete with those who have delayed those
investments - a group that includes almost half of the nation's
coal-fired plants, which lack advanced pollution control
equipment. In fact, facilities that have already taken responsible
steps to reduce the release of toxins into our air wil be at a
competitive advantage over their heavy-polluting counterpars.
And to ensure cost-effectiveness, we have proposed flexibilty in
meeting the standards. The technologies being required already
exist in abundance, and under the proposal, power providers have
four years to comply.2
The lack of certainty in environmental regulation is well recognized, but
2 Remarks available at:
htt://yosemite.epa.gov /opa/admpress.nsf/12a 7 44 ff56dbff5 85257 590004 7 50b61b 7 e570d651 eade03 85257
8550057011e!OpenDoeument
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does not obviate existing compliance obligations. The uncertinty of futue
environmental regulations is also acknowledged by state utility regulators. On
February 16, 2011, the National Association of Regulatory Utilty Commissioners
Board of Directors adopted a resolution, included as Exhibit No. 20, urging the
EPA to ensure, as the agency develops public health and environmental programs,
that reliability, cost, compounded economic impacts of multiple environmental
rulemakigs, and flexibility of time frames for compliance be considered.
Does the Company believe that any of the emissions control equipment
subject to review in this proceeding will not be necessary as a result of future
environmental requirements?
No. The Company does not anticipate that environmental reguations wil become
less strngent and history demonstrates that regulations become more strngent
over time. The controls subject to review in this proceeding are necessar to allow
the Company to continue operating these facilities given that increasing
strngency. Furher, the Company's analysis suggests that these controls place the
facilities in a position to continue to generate reasonably priced electrcity under
contemplated environmental regulations, even if greenhouse gas legislation is
adopted. The Company's analysis suggests that the cost of carbon under a
regulatory regime for greenhouse gas emissions would have to approach $40 per
ton with gas prices sustained below the $7 - $9/mmBtu range to begin to make
replacement of coal-fueled resources cost effective prior to 2030. Utilizing
greenhouse gas reduction requirements as a basis for curent investment decisions
is highly speculative given that the curent Congressional activity is focused on
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delay or repeal of the EPA's authority to regulate greenhouse gases, and not on a
comprehensive legislative effort to reduce greenhouse gas emissions.
Additionally, in the course of applying environmental requirements to the
Company's facilties, the respective state Departent of Environmental Quality or
the EPA consider what constitutes cost-effective emission reductions, taing the
position that all cost-effective reductions are required. As discussed earlier in my
testimony, in the context of the Regional Haze program's Best Available Retrofit
Technology determinations, the reviewing environmental agency must consider:
(a) the costs of compliance;
(b) the energy and non-air quality environmental impacts of compliance;
(c) any existing pollution control technology in use at the source;
(d) the remaining useful life of the source; and,
(e) the degree of visibility improvement which may reasonably be anticipated
from the use of BART.
Within the foregoing mandatory BART factors are considerations such as
greenhouse gas regulation and other environmental regulatory drivers that may
have an impact on the remaining useful life of the source are considered.
Should the Company wait unti all the regulations are considered, finalized,
and quantified to install controls?
No. Doing so would put the facilties at substantial risk of noncompliance and
does not reflect the reality of the multi state operations and planning process for a
utilty the size of PacifiCorp. Moreover, it would be imprudent for a utility the
size of PacifiCorp to assume it can install all required controls under a "just-in-
Woollums, Di - 18
Rocky Mountain Power
1 time" plan. This approach to compliance poses a significant risk to the Company
2 and its stakeholders; as a practical matter, it cannot be economically achieved on a
3 system the size of the Company's. Emission reduction projects are complex,
4 multi-year projects. Trying to install multiple controls within the same short time
5 frames poses a significant risk of noncompliance with penalties that can be
6 substantiaL. Even if a regulatory agency did not impose penalties for failing to
7 achieve emission reduction deadlines, third parties have not hesitated to bring
8 lawsuits against the operators of those facilities that miss deadlines or are
9 otherwise not in compliance with permit and emission limits. Indeed, the federal
10 clean air act specifically allows for private citizen enforcement of air quality
11 requirements.
12 Considering futue environmental regulatory requirements such as the
13 HAPs MACT when planing compliance projects for existing regulations avoids
14 the concern many companies are expressing about the short three-year compliance
15 period. Because the HAPs MACT had its genesis in the Clean Air Mercur Rule,
16 which was issued by the EPA in 2005 but vacated by the cour in 2008, the
17 Company was able to, and did, consider the potential impacts of a mercur rule on
18 its equipment decisions.
19 If a company waits for a rule to become final to begin to develop its
20 compliance strategy, it may find itself in a situation similar to facilities in
21 Oklahoma where the EPA recently rejected the state's implementation plan for
22 Regional Haze and has required that companies install scrubbers on three plants
23 or switch to natual gas within three years at a cost of approximately $1 bilion.
Woollums, Di - 19
Rocky Mountain Power
1
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4 Q.
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7 A.
8
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20 Q.
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22 A.
23
The permitting, procurement and installation of such equipment in such a short
time frame is challenging, if not impossible, and creates signficant ineffciencies
and cost increases.
Do you believe that the Company may need to change the controls that are
subject to review in this case if the EPA does not approve the State
Implementation Plans?
No. The controls at issue, including scrubbers, low NOx burers, and baghouses
are importt controls to meet both existing and futue environmental regulations.
Emission reduction projects completed under the Regional Haze regulations for
SOl, NOx, and particulate matter wil also serve to reduce mercur and other non-
mercur hazardous air pollutants, consistent with the Utilty HAPs MACT that
wil be finalized later this year. Likewise, these controls wil assist in achieving
attainment with the National Ambient Air Quality Standards, including the fine
particulate standard, and the one-hour SOl standard as well as the impending
revised ozone standad. Even if additional controls for NOx, such as selective
catalytic reduction (SCR) are required, the installation of combustion controls
such as 10w-NOx burers is an importnt step in achieving lower-cost NOx
reductions so that post-combustion controls are more efficient and operating costs
are lower.
Why doesn't the Company wait until it knows the outcome of all air quality,
waste and water rules to implement its environmental projects?
The strcture of the EPA and the natue of its rulemaking process are not
conducive to the agency producing coordinated air quality, waste and water rules
Woollums, Di - 20
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11
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15 Q.
16
17
18 A.
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20
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22
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for the electrcity sector; these media-based rules address different issues through
varying methods with different compliance timeframes. Nonetheless, the
Company undertkes efforts to ensure that the potential compliance requirements
for all these rulemaking activities are understood and reflected in its plans,
making decisions based on the best available information at the time the decisions
are made and updating that information as additional details on requirements
become available.
Environmental regulations and the cost of implementation are only one
factor that influences whether or not to make investments in envionmental
projects; the Company also must consider the cost of alternative generation.
Futue natual gas prices, constrction costs for renewable generation, and
associated transmission availability and costs are also among the factors that are
contemplated in a determination of whether it is economic to install controls at
coal-fueled plants.
Would the Company's decision to make these incremental investments in
environmental controls at these units change if additional limitations were
placed on carbon dioxide emissions?
No. The Company is engaged in assessing its existing generation resources, its
planed supply and demand-side resources and its 10-year capital budget with
respect to the impact of potential carbon dioxide emissions restrctions. While
other planned investments may change, the Company's plans regarding the
emission control investments included in this case would not change.as a result of
carbon-emission restrctions. The curent controls are required under existing
Woollums, Di - 21
Rocky Mountain Power
1
2
3
4
5
6
7 Q.
8
9
10 A.
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18 Q.
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22 A.
23
regulations and the units have depreciation lives for ratemaking puroses that
provide suffcient remaining time to depreciate the investments in the
environmental controls. While carbon restrctions may ultimately affect the cost
of generating electricity at these units, they are stil anticipated to be utilized as
par of the Company's overall generating fleet that wil be necessary to provide
base load electrcity at a reasonable cost to customers.
What efforts are being taken by the Company to understand and evaluate
impacts of potential future environmental regulations on the Company's
business?
PacifiCorp and its parent, MidAerican Energy Holdings Company, are active in
the curent state and federal legislative and agency activities regarding
environmental controls affecting virlly all emissions from coal and natual gas
generating units, and other environmental issues. The Company is cognizant that
some potential restrictions on greenhouse gas emissions ("GHGs") could require
coal (and potentially natual gas) units to adjust the depreciation lives for
ratemaking puroses. The Company considers this possibility when determining
whether to precede with pollution control investments.
Is the Company undertaking reasonable efforts to ensure that environmental
regulators consider the uncertainty created by requiring investments in
certain emissions controls prior to knowing the nature and extent of controls
on other emissions?
Yes. The Company filed an appeal of certain BART permits in Wyoming for this
exact reason. Wyoming was the first state to make the determination that BART
Woollums, Di - 22
Rocky Mountain Power
1
2
3
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6
7
8
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14
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20 Q.
21 A.
22
23
required the installation of SCR controls for nitrogen oxides at Naughton Unit 3,
and also to impose long-term strategy requirements for SCR in a BART permit
for all four units at the Jim Bridger plant. The Company disagreed with the
determination that SCR was BART and asserted that Appendix Y of 40 CFR Par
51 did not contemplate the installation of post-combustion controls. The
Company fuher disagreed that a long-term strategy requirement could be
included in a BART permit. Additionally, the Company was concerned that other
environmental laws and/or regulations could impact the Company's facilities
affected by Wyoming's BART determinations in a way that impacted the
economic analysis associated with the installation of the contemplated controls.
These requirements not only include greenhouse gas reduction requirements, but
also a host of regulatory initiatives underway by the EPA, including the outcome
of pending coal combustion waste disposal regulations and MACT standards for
mercur and non-mercury HAPs. Due to the uncertainty associated with the
potential impact of these rules on the Company's facilities, the Company appealed
the BART permits to ensure that these and other issues were considered in the
agency's decision and, to the extent these issues had an impact on long-term
viability of the facilities, the economic analysis of adding emission reduction
equipment was properly reflected.
Has this appeal been resolved?
Yes. In November 2010, PacifiCorp settled the Wyoming BART appeal to resolve
the matter in a way that did not require more controls and impose additional costs
earlier than originally proposed in the Departent of Environmental Quality's
Woollums, Di - 23
Rocky Mountain Power
1
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6 Q.
7
8 A.
9
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18 Q.
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21 A.
22
23
BART permits. To provide maximum flexibility in the event that other
environmental requirements or uncertinties arose, PacifiCorp and the WY DEQ
included terms in the settlement agreement to address a modification if futue
changes in either federal or state requirements or technology would materially
alter the emissions controls and rates that would otherwise be required.
Has the Company undertaken additional efforts to eliminate some of the
uncertainty associated with future environmental regulations?
Yes. Given the so-called "EPA train wreck" facing the electrc industr, the
Company worked on a comprehensive approach to addressing the ever-changing
and looming environmental requirements. Called REPLACES (The Retirement
Plan Act for Coal-Fueled Electrcity Sources), the Company undertook an effort
to develop a comprehensive plan intended to harmonize environmental
requirements with the nation's desire to shift to cleaner energy sources in a way
that allows for a smoother transition and minimizes costs and risks by clearly
identifying the requirements and timeframes that must be met, rather than being
faced with constantly changing environmental requirements that make long-term
investment decisions diffcult.
Would the proposed MidAmerican Energy Holdings Company REPLACES
program result in the Company requesting accelerated depreciation
treatment of pollution control investments contemplated in this case?
No. The goal of REPLACES (attached as Exhibit No. 21) is to address the curent
patchwork of existing and projected emission reduction requirements and define a
clear long-term regulatory path to allow owners of coal-fueled power plants to
Woollums, Di - 24
Rocky Mountain Power
1
2
3
4
5
6
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12 Q.
13 A.
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economically plan for the viability of electrcal generating units by phasing in unit
retirements begining with older, smaller units to allow for a smoother transition
while replacement generation is brought online and newer technologies are
developed. The REPLACES proposal reflects the Company's view that it does not
make economic sense to install significant emission control on units that are likely
to retire because of the creation of stranded cost for limited environmental benefit.
Under REPLACES, all existing coal-fueled electrc generating units would be
retired, controlled or retrofitted over a period of time and near-term environmental
regulatory relief would be granted for facilties that retire by 2020. Similar
proposals have been advanced by other organizations seeking near-term
regulatory relief but to date none have been adopted.
Please summarize your testimony.
As previously discussed, . the Company has undertaken significant efforts with
permitting agencies to ensure that its environmental control investments are
timely to ensure compliance with existing environmental requirements, that they
proceed in a reasoned fashion, and that they are coordinated with existig outage
schedules to avoid additional outage time associated with equipment tie-in. These
coordinated efforts reduce costs associated with replacement power and maintain
system reliabilty.
Due to the number of PacifiCorp's generating units impacted by
environmental regulation, deferrg installation of compliance-related projects is
often not feasible or cost-effective and places the Company and its customers at
risk of not having access to necessar capital, material, and labor while attempting
Woollums, Di - 25
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
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12 Q.
13 A.
to perform major equipment installations in a compressed time frame concurent
with other utilities. For example, in the eastern United States, utilties are required
to install controls under the Clean Air Transport Rule during the same 2012-2014
time frame within which compliance with the Utility HAPs MACT is required.
We have already seen a rise in project costs in anticipation of the
increased demand for labor and equipment. PacifiCorp's sister company,
MidAmerican Energy Company, has just negotiated a contract for the installation
of scrubbers and baghouses at two of its facilties in 2013 and 2014 and the costs
are approximately 20 percent higher than anticipated. The timing of the
investments is also importnt for ensurg that the Company is in compliance and
is not subject to penalties for noncompliance or third part lawsuits.
Does this conclude your testimony?
Yes.
Woollums, Di - 26
Rocky Mountain Power
20tl HAY 27 AM H: 02 Case No. PAC-E-l1-12
Exhibit No. 18
Witness: Cathy S. Woollums
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony of Cathy S. Woollums
Regional Haze Timeline
May 2011
Mountain PowerRocky 18 Page 1 of 1
Exhibit No. AC-E-11-12
Case No. P S Woollums
Witness: Cathy .
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Exhibit No. 19
Witness: Cathy S. Woollums
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony of Cathy S. Woollums
EPA "Train Wreck"
May 2011
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Case No. PAC-E-11-12
Witness: Cathy S. Woollums
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Exhibit No. 20
Witness: Cathy S. Woollums
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony of Cathy S. Woollums
NARUC Resolution
May 2011
Rocky Mountain Power
Exhibit No. 20 Page 1 of 2
Case No. PAC-E-11-12
Witness: Cathy S. Woollums
Resolution on the Role of State Regulatory Policies in the Development of Federal
Environmental Regulationi
WHREAS, The National Association of Regulatory Utilty Commissioners (NARUC)
recognizes that the U.S. Environmental Protection Agency (EPA) is engaged in the development
of public health and environmental regulations that wil directly affect the electrc power sector;
and
WHEREAS, EPA is expected to promulgate regulations to be implemented by State
environmental reguators concerning the interstate transport of sulfu dioxide and nitrogen
oxides, cooling water intake, emissions of hazardous air pollutants and greenhouse gases, release
of toxic and thermal pollution into waterways, and management of coal combustion solid waste;
and
WHEREAS, NARUC at this time takes no position regarding the merits of these EPA
rulemakings; and
WHEREAS, Such regulations under consideration by EPA could pose significant challenges for
the electrc power sector, with respect to the economic burden, the feasibility of implementation
by the contemplated deadlines and the maintenance of system reliability; and
WHEREAS, EPA is expected to provide opportities for public comment and input with
respect to forthcoming regulations; and
WHEREAS, Compliance with forthcoming environmental regulations wil affect consumers
differently depending upon each State's electrcity market and the natue of the decisions made
by State regulators; and
WHEREAS, Addressing compliance with multiple regulatory requirements at the same time
may help to reduce overall compliance costs and minimize risk assuming reasonable flexibility
with respect to deadlines; and
WHEREAS, State utility regulators are well positioned to evaluate risks and benefits of various
resource options through policies that appropriately account for and mitigate the risks arising
from compliance with pending regulations; and
WHEREAS, Cooperation between utility commissions and environmental regulators can
promote greater policy coordination and integration and improve the quality and effectiveness of
electricity sector regulation; and
WHEREAS, State utility regulators, by working with the power sector and State and federal
environmental regulators, can help to facilitate least-cost compliance with public health and
environmental goals; and
1 Based upon Resolution on Implications of Climate Policy for Ratepayers and Public Utilities, adopted by
NARUC Board of Directors on July 18,2007.
Rocky Mountain Power
Exhibit No. 20 Page 2 of 2
Case No. PAC-E-11-12
Witness: Cathy S. Woollums
WHEREAS, State utility regulators can help to minimize environmental risk as well as
uncertainty regarding reliabilty and customer rate impacts by requesting regulated utilities with
fossil generation to develop plans that evaluate all relevant environmental rulemakings at U.S.
EPA; now, therefore, be it
RESOLVED, That the Board of Directors of the National Association of Regulatory Utilty
Commissioners, convened at its 2011 Winter Committee Meetings in Washington D.C., urges
the EPA to ensure that, as it develops public health and environmental programs, it wil:
. Avoid compromising energy system reliability;
. Seek ways to minimize cost impacts to consumers;
. Ensure that its actions do not impair the availability of adequate electrcity and natual
gas resources;
. Consider cumulative economic and reliabilty impacts in the process of developing
multiple environmental ruemakings that impact the electricity sector;
. Recognize the needs of States and regions to deploy a diverse portfolio of cost-effective
supply-side and demand-side resources based on the unique circumstances of each State
and region;
. Encourage the development of inovative, multi-pollutant solutions to emissions
challenges as well as collaborative research and development efforts in conjunction with
the U.S. Departent of Energy;
. Employ rigorous cost-benefit analyses consistent with federal law, in order to ensure
sound public policy outcomes;
. Provide an appropriate degree of flexibility and timeframes for compliance that
recognizes the highly localized and regional natue of the provision of electrcity services
in the U.S;
. Engage in timely and meaningful dialog with State energy regulators in pursuit of these
objectives; and
. Recognize and account for, where possible, State or regional efforts already undertken
to address environmental challenges; and be it further
RESOLVED, That NARUC urges State utilty regulators to actively engage with State and
federal environmental regulators and to take other appropriate actions in furtherance of the goals
of this resolution.
Sponsored by the Committees on Electricity and Energy Resources and the Environment
Adopted by the NARUC Board of Directors February 16,2011
iu\\ ~Â ~ 21 At" 1: 02 Case No. PAC-E-l1-12
Exhibit No. 21
Witness: Cathy S. Woollums
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Cathy S. Woollums
REPLACES Document
May 2011
.IDAMERICAN
NERGY HOLDI NGSCOMPANY
Rocky Mountain Power
Exhibit No. 21 Page 1 of 12
Case No. PAC-E-11-12
Witness: Cathy S. Woollums
REPLACES: The Retirement Plan Act for Coal-Fueled Electricity Sources
Version 2.0
Overview of a Multimedia Compliance Program for
Coal-Fueled Electricity Sources
The REPLACES program promotes the reduction of traditional pollutants and greenhouse gas
emissions by requirng the retirement, control, or retrofit of all existing coal-fueled electrc
generating units!, as well as the adoption of a new coal unit performance standad that applies on
or after January 1, 2015. It wil provide certainty regarding regulatory requirements for existing
coal-fueled electrc generating units, incentivize earlier retirements and retrofits of existing coal-
fueled electric generating units, allow for continued development and ultimate implementation of
new clean coal technologies and nuclear power, and continue tax credits to support additional
renewable energy development.
The REPLACES program requires the retirement, control, or retrofit of all existig coal-fueled
electrc generating units over a phased-in period, concluding in 2055. It also seeks near-term
regulatory relief for coal-fueled units that cease operation permanently prior by December 31,
2020, as well as harmonization of the U.S. Environmental Protection Agency's regulatory
authority for varous rules including, but not limited to, new source performance standards,
national emissions standads for hazardous air pollutats, national ambient air quality standards,
and new source .review programs for coal-fueled units that wil continue to operate after
December 31,2020.
Applicabilty
For puroses of the REPLACES program;
1. A "covered electric utilty" is defined as an electrc utilty that is an investor-owned
utilty, municipal utility, electrc cooperative or public utilty distrct; is subject to federal
greenhouse gas and traditional emissions restrctions and prohibitions; and is subject to
oversight by a state regulatory authority, governing board, or supervising state or
political subdivision. The REPLACES program would be implemented by the utility
under the supervision of the utilty's state regulatory authority, governing board, or
supervising state or political subdivision in concert with the U.S. Environmental
Protection Agency.
ii. A "merchant coal unit" is defined as a coal-fueled electrc generating unit that 1) is not
owned by a Federal, State, or regional agency or power authority; and 2) generates
1 A "coal-fueled" electrc generating unit is defined as a unit that derives at least 85% of its heat input from coal,
petroleum coke, fuel oil, or any combination of those three fuels.
Version 10-24-10
Rocky Mountain Power
Exhibit No. 21 Page 2 of 12
Case No. PAC-E-11-12
Witness: Cathy S. Woollums
electrcity solely for sale to others, provided that all or a portion of such sales are made
by a separate legal entity that has full or parial ownership or leasehold interest in the
unit; and is not subject to retail rate regulation or setting of retail rates by a State
regulatory authority (or a State or political subdivision thereof), an electric cooperative,
or an Indian trbe pursuant to trbal law. The REPLACES program would be
implemented by the merchant coal unit owner/operator under the supervision of the u.s.
Environmental Protection Agency.
Certification
A covered electrc utilty must certfy that the state regulatory authority, governg board, or
supervising state or political subdivision that oversees the utility has the authority to: (1) consider
the interests of retail electrc consumers served by the utilty, and (2) require the utilty to meet
the program's retirement/retrofit schedule. The owner/operator of a merchant coal unit must
certify that it is subject to the oversight of an appropriate Regional Transmission Organization or
Independent System Operator with the responsibilty to ensure the reliabilty of electrc service
in its terrtory and to protect the interests of electrc markets served by such merchant coal unit.
. Filing of a Compliance Plan. Each certifying covered electrc utility and merchant coal
unit owner/operator shall file with the EPA a compliance plan within 24 months of the
effective date of the legislation. Each certifyig covered electrc utility shall, at the same
time, fie a copy of the plan with its state regulatory authority, governing board, or
supervising state or political subdivision. The plan must identify each coal-fueled electrc
generating unit that is subject to these restrictions and prohibitions; the state in which the
unit is located; the date upon which the unit was placed in service; the greenhouse gas
emissions from the unt in the most recent l2-month period for which data is available;
the date for retirement or retrofit for the unit under the REPLACES schedule; if a unit is
to be retrofitted or controlled, the natue of the retrofit and control equipment and the
expected amount of reduction in emissions; and, for covered utilties, the states in which
any portion of the investment in the unit is included in retail electrc rates, and the plan
for providing electric service after the retirement, control, or retrofit.
. Compliance Plan Updates. Compliance plans must be updated at least every four years.
States and the u.s. Environmental Protection Agency wil develop other procedures as
necessary to ensure compliance with REPLACES.
Specifics
1. Greenhouse Gas Emissions. Section 111 of the Clean Air Act would be amended to use
the following REPLACES retirement/retrofit schedule as the basis for greenhouse gas
new performance standards for existing coal-fueled electrc generating units. To achieve
the greenhouse gas (GHG) emission reductions on a timely basis, any covered electrc
utility or merchant coal unit owner/operator subject to REPLACES must make a legally
binding commitment in wrting to EPA (and, if a covered electrc utility, also to its state
regulatory authority, governing board, or supervising state or political subdivision) to
retire or retrofit all of its existing coal-fueled electrc generating units based on the
following schedule:
2
Version 10-24-10
Rocky Mountain Power
Exhibit No. 21 Page 3 of 12
Case No. PAC-E-11-12
Witness: Cathy S. Woollums
1. A coal-fueled electrc generating unit that began commercial operation on or prior
to December 31, 1959, must be retrofitted or retied by December 31, 2020.
11. A coal-fueled electrc generating unit that began commercial operation after
December 31, 1959, but on or prior to December 31, 1974, must be retrofitted or
retired by December 31, 2035.
11. A coal-fueled electrc generating unt that began commercial operation after
December 31, 1974, but on or prior to December 31, 1999, must be retrofitted or
retired by December 31, 2045.
iv. A coal-fueled electrc generating unit that began commercial operation after
December 31, 1999, or was initially permitted prior to Januar 1,2015, without at
least 50% carbon (COl) captue as measured on an anual basis, must be
retrofitted or retired by December 31, 2055.
Thedates listed above would be binding with the following exception.
a. For a coal-fueled electrc generating unit scheduled for retiement or retrofit in
schedule periods i., ii. or iii. above, a covered electric utility or merchant coal unit
owner/operator may choose to substitute the retirement or retrofit of a coal-fueled
electrc generating unit in a later schedule period, as long as the resultant amount of
greenhouse gas reductions is equal to or greater than the amount of greenhouse gas
reductions that would have been achieved by retirement or retrofit of the scheduled
unit.
The following items would qualify to meet the definition of "retrofit" under this
provision:
a. Conversion of an existing boiler to eliminate the use of coal with the substitution
of natual gas as the primary fuel source.
b. Repowering an existing unit with a combined cycle combustion tubine natual
gas-fueled unit.
c. Replacing a percentage of the coal fuel supply with renewable biomass to meet a
minimum generation performance standard of 1,100 pounds of carbon dioxide
(COl) per gross megawatt-hour, when measured on an anualized basisl. For
clarity, the COl emissions associated with the combustion of renewable biomass
would be excluded for puroses of demonstrating compliance with this generation
performance stadard.
1. Renewable biomass is defined as legally harvested trees, wood, brush,
thinings, chips, and slash; renewable plant material such as feed grains, other
2 The performance stadard of 1,100 pounds of CO2 per gross megawatt-hour is equivalent to approximately a 50%
reduction from the CO2 emissions from an average performng coal-fueled unit. This figue is also consistent with
California's greenhouse gas emission performance stadard under Assembly Bi132.
3
Version 10-24-10
Rocky Mountain Power
Exhibit No. 21 Page 4 of 12
Case No. PAC-E-11-12
Witness: Cathy S. Woollums
agrcultual commodities, plants, and algae; waste material including crop
residue, vegetative waste material, animal waste and byproducts, constrction
waste, food and yard waste, and non-biogenic municipal solid waste and
construction, demolition, and disaster debris; and residues and byproducts
from wood, pulp, or paper products facilties.
d. Installng carbon captue and storage technology to mitigate a minimum of 50%
of the baseline COl emissions emitted by the existing unit, when measured on an
annualized basis.
e. Integrating other non-emitting generation technologies (e.g., solar, nuclear, etc.)
into the existig coal unit steam cycle to meet a minimum generation performance
standad of 1,100 pounds of COl per gross megawatt-hour, when measured on an
anualized basis.
2. Preemption of GHG Regulation. For regulation of GHGs at covered coal units,
preemption of:
1. The Clean Air Act. Specifically EPA would be preempted from establishing
standards of performance for GHGs for existing coal units for other than climate
change, such as ocean acidification; GHGs as a trgger for New Source Review
for major sources; GHGs as an independent basis for requirng a Title V permit if
the GHG in question is only regulated due to its impact on climate change; and
incorporating GHGs into Title V permits for impacts other than climate change,
including ocean acidification.
11. Preemption of Other Federal Laws. Specifically EPA would be preempted from
establishing regulations under other federal environmental laws, such as the Clean
Water Act, the National Environmental Policy Act and the Endangered Species
Act.
11. State Preemption. At a minimum, where inconsistencies exist among state,
regional and federal GHG programs, federal law should prevaiL. States should be
free to pursue the policies they wish, but those policies should not regulate
sources already subject to REPLACES. States would be preempted from taing
any additional actions requirg GHG reductions from covered coal-fueled units,
including, but not limited to, cap-and-trade requirements, taxes, fees, or limits
imposed on these existing coal-fueled units for greenhouse gas emissions.
iv. State and federal common law torts.
3. Effect on Other EPA and State Regulations. The following provisions would apply to
covered electrc utilities and merchant coal unit owners/operators that participate in the
REPLACES program:
1. Pre-202l (Near-Term) Regulatory Relief. Each coal-fueled electric generating
unit must continue to meet all the conditions of its federal, state and locally
enforceable permits in existence at the time the utilty enters into the REPLACES
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program. Notwithstanding any provision of the_Clean Air Act, any. coal-fueled
electrc generating unit subject to REPLACES that commits to ceasing operation
permanently on or before December 31, 2020, shall be exempt from the
following:
a. New source review requirements under the Clean Air Act (42 U.S.C. § 7475)
or state emission reduction requirements under a state implementation plan
addressing new source review requirements.
b. Regulation of hazardous air pollutants under section i 12 of the Clean Air Act
(42 U.S.C. § 7412), including standards promulgated pursuant to
subparagraph (a)(1l) (D).
c. The final rule entitled "Regional Haze Regulations and Guidelines for Best
Available Retrofit Technology (BART) Determinations" (70 Fed. Reg. 39104
(July 6,2005)).
d. New source performance standards for greenhouse gas emissions under
section 111 of the Clean Air Act (42 U.S.c. § 7411).
e. Regulation of coal combustion waste water discharges from thermal
generatig units under title III of the Federal Water Pollution Control Act (17
U.S.C. § 1311 et seq.).
f. Regulation of cooling water intae strctues under section 3l6(b) of the
Federal Water Pollution Control Act (33 U.S.c. §1326(b)), and
g. Effuent guidelines and thermal discharge requirements promulgated under the
Clean Water Act.
11. Regulatory Coordination for Coal Units Operating Post-2020. Coal-fueled units
which continue to operate post-2020 shall be required to meet the criteria as
outlined below.
a. Clean Air Transport Rule. Emission controls, fuel switching, or other
mechanisms shall be employed by January 1, 2021 to meet the following
requirements:
1) Program shall be expanded to affect all 48 continental U.S. states and the
District of Columbia; versus 31 states and the Distrct of Columbia
currently affected.
2) Program shall not seek additional SOz reductions, since the Utilty HAPs
MACT requirements are more restrctive.
3) Utilties shall achieve anual and ozone season NOx emission rates of
0.17 Ib/mmBtu, when measured over the year or ozone season.
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1. A December 31, 2015 compliance date shall be enforced for the 31
curently affected eastern states, plus the Distrct of Columbia.
ii. A December 31, 2020 compliance date shall be enforced for the
remaining 17 western continental U.S. states.
iii. Reductions shall be completed under a cap-and-trade program.
iv. Allowances shall be fully allocated based on an average heat input
from 2008-2010.
v. Each state's actual emissions must be within 110% of its anual
emission allocation.
vi. An additional allowance reserve of 3% shall be set aside for new units.
4) There shall be no additional Regional Haze / Best Available Retrofit
Technology (BART) reductions required for existing coal-fueled units.
5) The combination of emission controls from the Clean Air Transport Rule
and Utilty HAPs MACT rule shall be considered better than BART and
also satisfy all reasonable progress goals established under the visibility
rule.
b. Utilty HAPs MACT Rule. Emission controls, fuel switching, or other
mechanisms shall be employed by January 1, 2021 to meet the following
requirements.
1) 90% reduction in SOi emissions, but not less than 0.15 Ib/mmBtu.
i. No specific reductions for acid gases due to strong correlation with
SOl emissions.
2) 80% reduction in mercur emissions, but not less than 1.7 Ib/TBtu.
i. No specific reductions for non-mercur metallic HA emissions due
to strong correlation with mercur emissions.
c. Coal Ash Management.
1) All coal ash shall continue to be managed as solid waste (subtitle D), and
not hazardous waste (subtitle C).
2) Existing beneficial uses for coal ash shall continue to be eligible.
3) No coal ash shall be deposited into unlined mines, quares, and
sand/gravel pits.
4) New coal ash landfills or landfill expansions shall install liners and
leachate collection systems and be Subtitle D compliant.
5) Wet surace impoundments may continue to operate in their curent form
until January 1, 2025.
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6) No later than January 1,2025, surface impoundments shall be phased out
(traditional cap and close without excavation) and all coal ash shall be
managed dr and disposed in ash mono fills.
7) Individual coal ash damage cases and impoundment strctual integrty
issues shall be addressed on a case-by-case basis.
8) New coal-fueled units shall be designed to manage coal ash dr.
d. Water.
I) No existing coal-fueled units with once-through cooling shall be required
to install closed-loop cooling systems.
2) Each once-through cooled unit which continues to operate post 2020 shall
conduct a fish impingement/entrainent evaluation and implement
reasonable measures to reduce mortality of aquatic life.
1. The evaluations shall be completed by December 31, 2015, and the
most beneficial measures, as determined by the appropriate state
regulatory authority, shall be implemented by December 31,2020.
ii. In no event shall an individual unit be required to expend more than $1
milion per 100 MW of accredited capacity.
3) No existing coal-fueled unit shall be subject to more restrctive thermal
discharge or effuent limits than exist in curent permits.
ii. Preemption of State Regulation of HAPs. Curent and futue state regulations of
hazardous air pollutants, including emissions of mercury, are preempted by the
EPA's Utility HAPs MACT rule.
iv. Clarification of New Source Review Applicabilty. Efficiency and operational
improvements undertaken at a coal-fueled electrc generating unit by a covered
electrc utilty or merchant coal unit owner/operator, regardless of their date,
would not be subject to New Source Review regulations specified within the
federal Clean Air Act.
v. "Safe Harbor" Provision. Each coal-fueled electrc generating unit must continue
to meet all the conditions of its existing federal, state and locally enforceable
permits in existence at the time the units enters into the REPLACES program.
However, except as explicitly outlined above, the existing coal units would not be
subject to any futue rules or changes to regulations under the existing Clean Air
Act, National Ambient Air Quality Standards, Clean Water Act, Safe Driing
Water Act, Resource Conservation and Recovery Act, Comprehensive
Environmental Response, Compensation and Liability Act, and any new state or
local air, water, or other environmental regulations that are more strgent than
curently existing federal, state and local requirements. Compliance with any
additional requirements wil ultimately be achieved by retiring, controllng, or
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retrofitting these coal-fueled electrc generating units on a legally binding
schedule.
VI. Cost Recovery. A covered electrc utility shall be authorized to recover in rates (a)
the prudently incured costs of replacing any coal-fueled electrc generating unit
retired pursuant to the REPLACES compliance plan; and (b) all other reasonable
costs, including but not limited to retrofit costs and accelerated depreciation
expense, associated with the compliance plan.
vll. Joint Ownership. For a coal-fueled electrc generating unit that is owned by more
than one entity, the election to subject the unit to the REPLACES program shall
be made by the operator unless otherwise provided by contract.
vii. Non-Compliance.
a. Retrofits: A covered electrc utilty or merchant coal unit owner/operator
which fails to meet its commitment to retrofit one or more of its existing coal-
fueled electrc generating units based on the REPLACES schedule and its
approved compliance plan wil be subject to an excess emission fee. Such
excess emission fee wil be based on the actual monthly COl emission tons
from the subject untes) multiplied by $50 per ton (in 2010$ escalated with
inflation). Any such excess emission fees shall be paid to the U.S.
Environmental Protection Agency on a monthly basis, no later than 30 days
following the month in which the excess emissions occured.
b. Retirements: A covered electrc utility or merchant coal unit owner/operator
which fails to meet its legally binding commitment to retire one or more of its
existing coal-fueled electrc generating units based on the REPLACES
schedule and its approved compliance plan wil be subject to the same
enforcement actions as a unit which operates without a valid operating permit,
or is otherwise in violation of such permit, in accordance with the provisions
of the Clean Air Act. This shall include, but not be limited to, Section 113
civil and criminal actions, Section 303 emergency powers, and Section 304
citizen suits.
4. New Coal-Fueled Electrc Generating Units. The Clean Air Act (42 U.S.C. 7401 et seq.)
would be amended to establish performance standards for new coal-fueled power plants.
A "covered coal unit" is defined as a unit required to have a Title. V permit under CAA
section 503(a) and is authorized under Federal or State law to derive at least 30 percent of
the annual heat input of the unit from (i) coal; (ii) petroleum coke; or (iii) any
combination of those fuels. The standard applies on or after January 1, 2015 when the
owner or operator of a covered coal unit has received a preconstrction approval or
permit as a new (but not modified) source. A covered coal unit must achieve the
following emissions limits:
1. 0.07 Ib/mmtu anual and ozone season NOx emission rate, when measured on a
30-day rolling average.
ii. 0.10 lb/mmtu SOl emissions rate, when measured on a 30-day rollng average.
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111. 1.5 Ib/TBtu mercur emissions rate, when measured on a 30-day rollng average.
iv. 1,100 pounds of COl per gross megawatt-hour emissions rate, when measured on
an annualized basis.
5. Income Tax Incentives. The following tax-related provisions would apply to covered
electrc utilties and merchant coal unit owners/operators that are p.artcipating in the
REPLACES program:
1. Accelerated Retirement or Retrofit Credit (ARRC). Under new Internal Revenue
Code Section 45R, if a coal-fueled electrc generating unit subject to REPLACES
is retired or retrofitted at an earlier date than required under the REPLACES
schedule (i.e., prior to the respective dates prescribed in Item 2), the covered
electrc utility or merchant coal unit owner/operator shall be eligible to receive
ARRC at a rate equal to one-half of the renewable electricity production tax credit
rate set fort in Internal Revenue Code Section 45(a). For a covered electric
utility, the amount of. credits so generated shall be utilized to benefit retail
customers by reducing the cost of the energy and/or capacity of the supply or
demand resource that replaces the retired or retrofitted coal-fueled electric
generating unit, in the manner determined by the state regulatory authority,
governing board, or supervising state or political. subdivision. The ARRC shall be
calculated by multiplying the average monthly megawatt-hours generated by the
unit being retired or retrofitted durng the 12 calendar months immediately
preceding the retirement/retrofit date by the number of full calendar months the
date of retirement or retrofit precedes the respective scheduled dates prescribed in
Item 2. The ARC may be claimed regardless of whether or not the taxpayer
elects tax incentives under paragraphs 4.iii. and 4.iv., below.
11. Renewable Electrcity Production Tax Credit. The existing renewable electrcity
production tax credit program wil be extended in its curent form through 2055.
11. Election to Expense. Under new Internal Revenue Code Section l79F, a
participant in the REPLACES program, like other taxpayers, may elect to expense
100% of the cost of any qualified emission reduction project to meet these
requirements and reduced C02 propert. A qualified reduced COl propert means
any propert installed as a retrofit of an existing coal-fueled electrc generating
unit or constrcted as a new electrc generating unit, which meets a minimum
generation performance standard of 1,100 pounds of COl per gross megawatt-
hour placed into service after enactment of Section l79F. The election to deduct
costs under this section shall also apply to qualified progress expenditues
incured during the constrction of the qualified equipment/propert, in a manner
similar to the rules of Subsection 48(b).
iv. Dual Alternatives to the Election to Expense. In lieu of enacting a Section l79F
election to expense, mutually exclusive alternatives to elect either a 30% ta
credit or a 30% U.S. Treasur grant would be available to participants in the
REPLACES program. The grant side of this dual approach would permit utilities
without curent federal income tax appetites to timely receive a cash. grant equal
in amount to a correspondig energy investment tax credit. These provisions are
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patterned after similar provisions enacted as part of the American Recovery and
Reinvestment Act of 2009.
a. Investment Tax Credit. Under the REPLACES program, a new Internal
Revenue Code Section 48D would be added to permit a taxpayer to claim
a tax credit equal to 30% of the cost of any qualified emission reduction
project to meet these requirements and reduced COl propert. A qualified
reduced COl propert means any propert installed as a retrofit of an
existing coal-fueled electrc generating unit or constrcted as a new
electrc generating unit that meets a minimum generation performance
standard of 1,100 pounds of COl per gross megawatt-hour placed into
service after enactment of Internal Revenue Code Section 48D. The credit
under this section shall also apply to qualified progress expenditues
incured during the constrction of the qualified emission reduction
project and reduced CO2 propert, in a manner similar to the rules of
Subsection 48(b). This credit would be claimed in lieu of a grant available
under new Internal Revenue Code Section 48E, described below. The
depreciable basis of the propert shall be reduced by the amount of the
credit.
b. Investment Grant. Under new Internal Revenue Code Section 48E, a
taxpayer may apply to the U.S. Treasur for a cash grant equal to 30% of
the cost of any qualified emission reduction project to meet these
requirements and reduced COl propert. A qualified reduced COl propert
means any propert installed as a retrofit of an existing coal-fueled electrc
generating unit or constrcted as a new electric generating unit that meets
a minimum generation performance standard of 1,100 pounds of COl per
gross megawatt-hour placed into service after enactment of Internal
Revenue Code Section 48E. The grant under this section shall be made
available to qualified progress expenditues incured durng the
construction of the qualified emission reduction project to meet these
requirements and reduced COl property, in a maner similar to the rules of
Subsection 48(b). This grant would be claimed in lieu of a tax credit
available under new Internal Revenue Code Section 48D, described
previously, and is payable to the utilty within 60 days after the later of the
expenditue or the date of application. The depreciable basis of the
propert shall be reduced by the amount of the grant.
6. Nuclear Power Development Support. An $8 bilion loan guarantee program wil be
provided to states for distribution to covered electrc utilities parcipatig in the
REPLACES program to develop, own and operate new nuclear power plants. In addition,
covered electrc utilities that develop, own and operate new nuclear power plants wil be
eligible for the tax programs specified above in 4.iii and 4.iv.
7. Emission Reduction Benefits. Retirig, retrofitting, and controlling all of the existing
coal-fueled electric generating units on the predetermined schedule outlined above wil
result in significant emission reduction direct benefits and co-benefits and is estimated to
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result in reductions of sulfu dioxide (SOl), nitrogen oxides (NOx) and mercur (Rg)
emissions, in addition to COl, as compared to baseline emissions in 20083.
1. Retiring all the existing U.S. coal-fueled electrc generating units on the
predetermined schedule outlined above and replacing them with non-carbon
emitting generating units, and controlling the post-2020 coal-fueled fleet to meet
the emission standards outlned above, is estimated to result in the following
emission reductions
Cumulative Reductions from Controls and Retirements
COl SOl NOx Hg"
MTons %MTons %MTons %Tons %
2020 223.3 10.7 6.08 82.1 1.34 47.3 30.08 66.8
2035 958.7 46.1 6.62 89.3 1.94 68.6 36.11 80.3
2045 2,049.3 98.6 7.39 99.8 2.82 99.5 44.89 99.8
2055 2,078.0 100.0 7.41 100.0 2.84 100.0 45.00 100.0
11. Retrofitting all the existing u.s. coal-fueled electrc generating units on the
predetermined schedule outlined above to meet the 1,100 pound of COl per gross
megawatt-hour stadard, and controlling the post-2020 operated coal-fueled fleet
to meet the emission standards outlined above, is estimated to result in. the
following emission reductionss.
Cumulative Reductions from Controls and Retrofits
COl SOl NOx Hg
MTons %MTons %MTons %Tons %
2020 100.5 4.8 5.93 80.1 1.17 41.4 28.39 63.1
2035 431.4 20.8 5.93 80.1 1.17 41.4 28.39 63.1
2045 922.2 44.4 5.93 80.1 1.17 41.4 28.39 63.1
2055 935.1 45.0 5.93 80.1 1.17 41.4 28.39 63.1
3 The total tonnage reductions would be even greater as compared to baseline emissions in 2005. Between 2005 and
2008, emissions from Acid Rain Program units have declined as follows: S02 down by 2.6 milion tons, NOx
down by 0.6 million tons, Hg down by 2 tons, and CO2 down by 22.7 milion tons.4 Mercur emission data were not available on a unit-by-unt basis. Therefore, baseline mercur emissions were
estimated to correlate closely with S02 emissions, since scrubber equipment generally has a mercur co-benefit.5 Since the 1,100 pound CO2 per gross megawatt-hour emission stadad (from a baseline of 2,000 pounds) could
be achieved via a number of alternatives, including CCS, the addition of biomass, or integration of other non-
emittng generation technologies into the steam cycle, it was assumed that CCS would be employed and not affect
emissions of S02, NOx, and Hg above and beyond the direct emission control benefits.
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iii. Converting all the existing U.S. coal-fueled electrc generating units to 100%
natual gas on the predetermined schedule outlined above is estimated to result in
the following emission reductions6.
Cumulative Reductions from Controls and Natural Gas Conversions
CO2 S02 NOx H2
MTons %MTons %MTons %Tons %
2020 103.5 5.0 6.08 82.1 1.22 43.1 30.08 66.8
2035 444.3 21.4 6.62 89.3 1.40 49.4 36.11 80.3
2045 949.7 45.7 7.39 99.8 1.66 58.5 44.89 99.8
2055 963.0 46.3 7.41 100.0 1.66 58.5 45.00 100.0
6 The complete conversion to natual gas of the coal-fueled electrc generating units could occur either as a fuel
switch or a combined cycle repowerig. The table conservatively assumes all units undergo fuel switching, and
NOx is reduced from the controlled average of 0.17 1b/mmtu to 0.12 1b/mmtu. If some of the units were
repowered, additional CO2 and NOx reductions would be expected due to the heat rate improvement.
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