UNITED STATES OF AMERICA
BEFORE THE
ENVIRONMENTAL PROTECTION AGENCY
Carbon Pollution Emission Guidelines
for Existing Stationary Sources:
Electric Utility Generating Units
)
)
)
Docket No. EPA-HQ-OAR-2013-0602
COMMENTS OF
THE LOUISIANA PUBLIC SERVICE COMMISSION
On June 18, 2014, as part of President Obama’s Climate Action Plan, the U. S.
Environmental Protection Agency (“EPA”) proposed sweeping carbon dioxide (“CO2”)
regulations governing the power sector1. The proposal, referred to as the Clean Power Plan
(“CPP”), requires widely disparate reductions in state-by-state emissions of CO2.
These
reductions range from approximately 11% in North Dakota to 72% in Washington. Louisiana
has an interim goal of 38% in 2020 and a final goal of 42% in 2030. The proposed reductions
are purportedly justified on the basis of the State’s ability to improve the heat rate efficiency of
coal units, an assumption with no basis in fact as further discussed herein, and by relying on
drastic changes to the State’s generation portfolio. As discussed in more detail throughout these
comments, the EPA has overstepped the bounds of its authority in attempting to regulate state-by
-state electricity generation portfolios. Even assuming Congress has given EPA such grant of
authority, however, the assumptions relied on by EPA in developing the CPP were erroneous and
technically flawed.
Comments are currently due on or before December 1, 2014. As the regulatory agency
with jurisdiction over public utilities in the State of Louisiana, the Louisiana Public Service
Commission (“LPSC” or “Commission”), has a substantial interest in this proceeding and
1
79 Fed. Reg. 34830 (2014).
.
through undersigned counsel submits the following comments. The LPSC worked diligently
with the Louisiana Department of Environmental Quality (“LDEQ”), the Louisiana Attorney
General, the Louisiana Department of Natural Resources and other state officials in analyzing the
CPP. We adopt the comments of those agencies to the extent they are not inconsistent with the
specific comments included herein. We also support the legal challenge previously made by the
Louisiana Attorney General in State of West Virginia, et al., v. EPA2 and the § 307(d) challenge
submitted in this rulemaking August 25, 2014 by several States’ Attorneys General, including
Louisiana’s.
Further, we have solicited input from LPSC stakeholders, including utilities,
consumer groups, and regional transmission organizations in developing these comments. 3 It is
our hope that EPA will take all of these comments into consideration and withdraw the proposed
rule in its entirety. Alternatively, the LPSC respectfully requests that the EPA make significant
modifications to the rule consistent with the recommendations set forth in § IV, infra, and as
explained more fully herein.
I.
INTRODUCTION
The LPSC is the constitutionally-created agency tasked with regulating public utilities in
the State of Louisiana. Louisiana Constitution Article IV, Section 21, provides as follows:
The commission shall regulate all common carriers and public
utilities and have such other regulatory authority as provided by
law. It shall adopt and enforce reasonable rules, regulations, and
procedures necessary for the discharge of its duties, and shall have
other powers and perform other duties as provided by law. 4
In addition, La. R.S. 45:1163(A)(1) provides as follows:
The commission shall exercise all necessary power and authority
over any street, railway, gas, electric light, heat, power,
2
D.C. Cir. 14-1146 (pending).
LPSC Docket R-33253.
4
LA Const. art. IV, § 21.
3
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waterworks, or other local public utility for the purpose of fixing
and regulating the rates charged or to be charged by and service
furnished by such public utility.5
In accordance with its constitutional and legislative mandates related to electric utilities, the
LPSC regulates electric utilities within its jurisdiction in a manner that provides adequate and
reliable electric service at a fair and reasonable rate to all Louisiana ratepayers. The LPSC
regulates four large investor-owned utilities (“IOUs”) and thirteen smaller electric cooperatives
in the State. The four IOUs are Cleco Power, LLC (“Cleco”), Entergy Gulf States, Louisiana,
L.L.C. (“EGSL”), Entergy Louisiana, LLC (“ELL”), and Southwestern Electric Power Company
(“SWEPCO”, a division of American Electric Power “AEP”).
The Commission does not
regulate municipal electric utilities or Entergy New Orleans. 6
The LPSC has previously provided comments in EPA rulemakings that were anticipated
to have an impact on LPSC ratemaking authority and the services provided by utilities regulated
by the LPSC. The LPSC provides these comments on the proposed CPP to express deep
concerns about the EPA’s legal authority to implement this rule, the practical implications of the
proposed rule, technical flaws in the EPA’s models and assumptions, and the extreme negative
impacts that the proposed rule will have on the citizens of Louisiana - some of the country’s
poorest citizens.7
As will be explained in § III.G., infra, the potential economic impacts of this rule in
Louisiana range from $3.9 billion to $5.6 billion. Given the Commission’s objective of ensuring
safe, reliable electric service at reasonable prices, the Commission has worked tirelessly to
maintain affordable electricity rates for the citizens of Louisiana. The LPSC is in the best
5
La. R.S. 45:1163(A)(1).
La. R.S. 45:1164.
7
According to the United States Census Bureau, 18.7% of Louisiana citizens lived below the poverty level from
2008-2012. United States Census Bureau State and County Quickfacts.
http://quickfacts.census.gov/qfd/states/22000.html
6
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position to determine, within the police power of the state, which regulatory policies are most
closely aligned with the public interest of its citizens. The LPSC respectfully submits that the
CPP will create undue hardships on Louisiana families through unwarranted electricity bill
increases and potential service interruptions.
As explained in more detail below, the LPSC believes there are significant legal and
technical defects associated with the CPP and respectfully requests that the EPA withdraw the
proposed rule in its entirety. In the alternative, the LPSC requests that the EPA, at a minimum,
modify the rule in accordance with the specific enumerated recommendations below, all other
comments herein, and those of other Louisiana agencies and planning authorities, giving due
consideration to the following statement made by Supreme Court Justice Ruth Bader Ginsburg in
deciding whether or not to uphold CAA regulations:
“…as with other questions of national or international policy, informed
assessment of competing interests is required. Along with the environmental
benefit potentially achievable, our Nation's energy needs and the possibility
of economic disruption must weigh in the balance.”8
II.
LEGAL BASIS FOR THE RULE IS FLAWED
While the LPSC appreciates the difficult position in which the EPA finds itself given the
politics of climate change regulations, the LPSC respectfully submits that the proposed CPP
exceeds the congressional grant of authority provided in the CAA and must be withdrawn or
drastically modified in order to withstand a legal challenge.
8
American Electric Power Co., Inc. v. Connecticut, 131 S Ct. 2527, 2539 (2011).
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A. EPA’s attempt to coerce states to enact laws and regulations under threat of penalty
is unlawful.
The CPP goes beyond EPA’s grant of authority in the CAA by imposing requirements
on states to develop a state implementation plan (“SIP”) under threat of a federal
implementation plan (“FIP”) by requiring states to :
“…measures, along with implementing and enforcing measures, that will
achieve a level of emission performance that is equal to or better than the level
specified in the state plan. The state must then adopt the state plan through
certain procedures, which include a state hearing. Within the time period specified
in the emission guidelines (from as early as June 30, 2016 to as late as June 30,
2018, depending on the state's circumstances), the state must submit its complete
state plan to the EPA. The EPA then must determine whether to approve or
disapprove the plan. If a state does not submit a plan, or if the EPA does not
approve a state's plan, then the EPA must establish a plan for the state.”9
Unlike historical regulation of National Ambient Air Quality Standards (“NAAQS”)
pursuant §110 and mercury pursuant to § 111, this regulation does not merely set a currently
achievable emissions standard. Rather, this regulation effectively mandates that states enact laws
and regulations allowing them to enforce resource planning decisions over and above those
already adopted pursuant to state resource planning authority, by imposing drastic emissions
reductions incapable of being achieved otherwise. This type of regulation would set shaky legal
precedent and fundamentally change the cooperative federalism approach currently imposed by
the CAA.
i. States have police power over resource planning
decisions.
The CPP is a thinly veiled attempt to assume powers not previously granted to or
historically exercised by the EPA, without the benefit of any clear Congressional authorization to
invade this area of regulatory expertise reserved to the States under the Tenth amendment to the
9
Clean Power Plan, VIII.A.
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U.S. Constitution.10 Individual states have traditionally exercised jurisdiction over resource
planning decisions.11 The LPSC has jurisdiction over electric utility resource matters pursuant to
its constitutional authority found in Article IV Section 21 of the Louisiana Constitution of 1974.
Pursuant to that authority, the LPSC has extensively investigated and provided rules and
programs in attempts to diversify Louisiana’s fuel mix including its new nuclear incentive rule,
integrated resource planning (“IRP”), renewable energy (“RE”), and energy efficiency (“EE”) as
discussed in greater detail below. Despite these and other efforts involving multi-year studies
and numerous stakeholders, the CPP disregards the findings and recommendations of the LPSC’s
technical experts and attempts to replace sound rules and regulations with those of its own.
The LPSC recently approved participation by three of its four investor-owned
jurisdictional electric utilities in Louisiana in the Midcontinent Independent System Operator
(“MISO”) Regional Transmission Organization (“RTO”) and along with the other MISO states
has incurred extensive costs to “provide independent transmission system access, deliver
improved reliability coordination, perform efficient market operations, coordinate regional
planning, and foster a platform for wholesale energy markets.12 The proposed rule threatens to
disrupt the voluntary participation and collaboration in MISO and other RTOs. EPA presumes
that it can usurp state regulatory functions by merely referring to the resource planning mandates
as Building Blocks or guidelines. Calling them flexible does not make them so. Below are some
of the Commission rules and policies that would potentially be disrupted by this regulation.
Certification of the Public Convenience and Necessity
Since 1983, the LPSC has required jurisdictional electric utilities to seek a determination
from the Commission, prior to “commenc[ing] any on site construction activity or enter into any
10
See generally US Const. amend. X.
Federal Power Act (FPA) § 16 U.S. Code § 201.
12
MISO Workshop Presentation (November 12, 2014).
11
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contract for construction or conversion of electric generating facilities or contract for the
purchase of capacity or electric power, other than emergency or economy powered purchases”,
that such project or purchase of capacity or electric power (other than emergencies or other
stated exceptions).13 The LPSC routinely reviews utility requests for certification pursuant to its
constitutional authority.
Integrated Resource Planning
Approximately 27 states, including Louisiana have enacted rules on IRP.14 When the
LPSC adopted its rules in 2012, the stated objective was for electric utilities to pursue a resource
plan that offers the most economic and reliable combination of resources satisfying the
forecasted load requirements, including evaluation of supply-side, demand-side, and economic
transmission resource options. The LPSC’s IRP rules were adopted as part of a lengthy
rulemaking process with input from many stakeholders. It is uncertain how the CPP would
impact the LPSC’s ability to continue to effectively guide this process when resource planning
decisions may be made on the front end, as part of an environmental rulemaking, as oppose to
the stakeholder process contemplated by the IRP.
New Nuclear Incentive Rule
The Energy Policy Act of 2005 created incentives for the development of nuclear energy.
In order for Louisiana utilities to avail themselves of these incentives, the Commission directed
its Staff to develop an incentive rule to promote nuclear power plant development in Louisiana.
The Commission thereafter, in 2007, after an extensive rulemaking process, enacted a general
order establishing guidelines for the development of nuclear power by utilities in Louisiana, and
13
LPSC General Order dated May 29, 2009, modifying the LPSC General Order dated September 20, 1983, Docket
R-30517).
14
LPSC General Order dated April 18, 2012 (Docket R-30021), Pg. 8, Para. 2, Synapse Energy Economics, Inc.,
Best Practices in Electric Utility Integrated Resource Planning, June 2013.
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to “create a high degree of regulatory certainty for utilities considering developing nuclear power
plants in Louisiana.” 15 The rule remains in place today.
Energy Efficiency
In conjunction with its IRP rules the LPSC implemented a “Quick Start” EE program to
develop, in the short term, a set of EE programs that could be implemented quickly and
economically, in order to begin developing the infrastructure necessary to support the successful
implementation of energy efficiency programs in Phase II and over the long-term.16
Renewable Energy
Congress has not successfully passed legislation mandating a renewable portfolio
standard, despite attempts to do so. Nor has it delegated to any agency that which it was unable
to do itself. Certainly there is no unambiguous expression of Congressional intent to empower
EPA to adopt such policies under § 111 of the CAA, which pre-dated the failed WaxmanMarkey legislation of 2009.17 Nevertheless, many states have passed renewable legislation in the
form of goals and mandatory RPS.
As discussed more fully under Section III.E., infra,
Louisiana has investigated the feasibility of an RPS on multiple occasions, finding that an RPS
did not make economic sense for Louisiana at the current time but that Louisiana utilities should
continue to monitor and report on RE developments.18
Rather than implement an RPS, which is essentially what the EPA suggests Louisiana
should do in its § 111(d) SIP, the LPSC undertook a pilot program pursuant to which mandatory
requests for proposal for RE were issued. As a direct result of the RFPs issued by 3 of
15
LPSC General Order dated May 18, 2007 (Docket R-29712)
LPSC General Order dated September 20, 2013 (Docket R-31106).
17
H.R. 2454, 111th Cong.(American Clean Energy and Security Act of 2009).
18
LPSC Dockets R-28271 In Re Re-study of the feasibility of a renewable portfolio standard for the State of
Louisiana and R-28271 Subdocket B, In Re Re-study of the feasibility of a renewable portfolio standard for the
State of Louisiana.
16
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Louisiana’s investor-owned electric utilities, approximately 80 (“MW”) of RE was acquired.19
As an indirect result, an additional 356 MW of wind energy were purchased.20 Unfortunately, all
except about forty MW of the RE is sited outside of the state of Louisiana.21 The Commission
considered limiting the RE pilot to in-state resources, but ultimately expanded it due to concerns
over potential Commerce Clause challenges and the delay that may be caused by litigation. The
fact that out-of-state resources were ultimately chosen over in-state resources is further evidence
of the limited availability of RE resources in Louisiana.
ii. Wholesale dispatch of power plants in FERC
regulated under FPA.
The Federal Power Act (“FPA”) did not displace the previously discussed state regulation
of intrastate sales of electricity. It did, however, close the gap in regulation across state lines left
by the Supreme Court’s decision in Public Utilities Comm’n of Rhode Island v. Attleboro Steam
and Electric Co., 273 U.S. 83, 89 (1927). The FPA empowered the Federal Power Commission
(“FPC”, and its successor, the Federal Energy Regulatory Commission, or “FERC”) to regulate
wholesale electricity rates but limited the power “to those matters which are not subject to
regulation by the States.” 22,23 Specifically, the FPA grants FERC authority over all facilities for
interstate transmission or sale of electric energy.24
Congress expressly reserved for state
regulation (a) any aspect of the delivery of electricity from a generator to a retail consumer in the
same state, or (b) the use of local distribution facilities.25
19
LPSC Order Nos. U-32814, U-32557, U-32981.
LPSC Docket No. U-32814.
21
Id.
22
FPA § 201, Federal Power Commission v. Southern California Edison Co., 376 U.S. 205, 214 (1964).
23
Id.
24
FPA § 201.
25
Id.
20
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Pursuant to the Energy Policy Act of 2005, FERC has approved mandatory and
enforceable reliability standards promulgated by the North American Electric Reliability
Corporation (“NERC”) with which the electric industry must comply. Contained in these
standards are key requirements necessary to ensure the bulk electric system meets an adequate
level of reliability. Failure to comply with these standards affects the ability of the power grid to
operate reliably and subjects registered entities and its member utilities to civil monetary
penalties. Yet, reliability concerns seem to have been a non-factor in EPA’s analysis.
The LPSC urges EPA to consider the comments of reliability planning organizations on
this issue.
For example, MISO filed comments in this docket on November 25, 2014,
requesting that the EPA eliminate the interim deadline of 2020, finding the deadline unfeasible
and stating that the EPA’s “timeline will force decisions that pit environmental compliance
against electric reliability."26 Similarly, the Southwest Power Pool ("SPP"), the RTO in which
LPSC-regulated SWEPCO is a member, has provided comments stating that the EPA's proposal
will impact reliability and will have material impacts on the market based dispatch of electric
generating units within the region and that the timing proposed for compliance is "infeasible."27
2. Louisiana has
regulations.
legislation
governing
carbon
emissions
EPA’s proposed rule is inconsistent with Louisiana Revised Statute Title 30 § 2060.1,
which requires the LDEQ, “in collaboration with and input from the Commission” to set fossilfueled electric generating unit performance standards, not the EPA.28 These agencies are to set
the standard based on inside-the-fence measures, and allow for a more lenient standard based on
such factors as cost and impacts on the ratepayers and the economy. EPA’s proposed rule is in
26
MISO comments dated November 25, 2014.
SPP comments dated October 14, 2014.
28
La. R.S. 30:2061.1 (2014).
27
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direct conflict with the interests of Louisiana citizens, as expressed through their elected
representatives, by refusing to allow Louisiana a sufficient role in setting the standard, or any
flexibility or exceptions based on cost, engineering or economic factors.
In pertinent part, the statute provides:
In developing a plan for the implementation of any guidelines for
greenhouse gas emissions that the United States Environmental Protection
Agency may issue under Section 111 (d) of the Clean Air Act, the Department of
Environmental Quality, in collaboration with and input from the Public Service
Commission, may establish standards of performance for carbon dioxide
emissions from existing fossil fuel-fired electric generating units…
[T]he standard of performance… shall be based on:
(1) The best system of emission reduction, taking into account the cost of
achieving such reduction…;
(2) Reductions…that can reasonably be achieved through measures undertaken at
each fossil fuel-fired electric generating unit; …
(3) Efficiency improvements … that can be undertaken … without switching to
other fuels, co-firing with other fuels, or limiting the utilization of the unit.”
Even more importantly, the statute goes on to provide that the Department may adopt “less
stringent standards or longer compliance schedules” than those provided in federal rules based
on:
(1) Consumer impacts, including any disproportionate impacts of energy price
increases on lower income populations;
(2) Unreasonable cost due to plant age, location, or basic process design;
(3) Physical difficulties or impossibility of implementing emission reduction
measures;
(4) Absolute cost of applying the performance standard to the unit;
(5) Expected remaining useful life of the unit;
(6) Economic impacts of closing the unit;
(7) Need to maintain reliability on electric grid; and,
(8) [A]ny other factors specific to the unit.”29
29
Id. These criteria for setting a more lenient standard and longer compliance schedule are based on the federal
implementing regulations promulgated by EPA, at 40 C.F.R. § 60.24 (f).
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B. Section 111(d) of the CAA does not provide a legal basis for the proposed rule.
i. Section 111(d) does not provide give EPA
authority to regulate “outside the fence”.
When looking at the Building Blocks and “outside the fence” regulations contained
therein, one cannot help but ask how this type of regulation purportedly emanates from the
specific grant of authority found in § 111(d) of the CAA. EPA has effectively commandeered
resource planning authority as a mechanism for reducing CO2 emissions through § 111(d) and
implement an emission reduction plan at a federal level. While EPA goes to great lengths to
suggest that the states have flexibility in developing their plans, it has provided no viable
alternative to the resource planning options contained in the CPP. Even if states could come up
with alternatives, there is significant uncertainty regarding the circumstances under which a SIP
will ultimately be approved. The LPSC does not believe it was the intent of Congress to give
EPA this much authority through § 111(d) and create this much uncertainty surrounding
regulation traditionally left to states.
Section 111(d) is a rarely used provision of the CAA found under a section entitled “new
or modified sources”. In contrast to the national ambient air quality standards (NAAQS) found
in §§ 108-110, which were a central part of the CAA prior to the 1970 amendments, § 111 was
implemented to establish nationwide uniform emissions standards for new or modified stationary
sources to prevent new pollution problems rather than address existing ambient air quality. 30 The
standards were meant to control emissions through the introduction of the best system of
emission reduction (“BSER”) when units were being built, and therefore easier and more
efficient to control. Yet, this proposed rule goes even further than the NAAQS, which have
always been a central part of the Act.
30
Domiki and Zacaroli, The Clean Air Handbook, Ch. 9 (2011).
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ii. The CPP is inconsistent with the statutory text of
Section 111(d)
EPA cannot overlook the fact that Section 111(d) actually provides a very specific and
unambiguous grant of authority to EPA, as follows:
42 USC § 7411 - Standards of performance for new stationary sources
…
(d) Standards of performance for existing sources; remaining useful life of source
(1) The Administrator shall prescribe regulations which shall establish a
procedure similar to that provided by section 7410 of this title under which
each State shall submit to the Administrator a plan which
(A) establishes standards of performance for any existing source for
any air pollutant
(i) for which air quality criteria have not been issued or which is
not included on a list published under section 7408 (a) of this title
or emitted from a source category which is regulated under
section 7412 of this title but
(ii) to which a standard of performance under this section would
apply if such existing source were a new source, and
(B) provides for the implementation and enforcement of such
standards of performance. Regulations of the Administrator under this
paragraph shall permit the State in applying a standard of performance
to any particular source under a plan submitted under this paragraph to
take into consideration, among other factors, the remaining useful life
of the existing source to which such standard applies.
(emphasis added)
EPA’s reliance on this provision for implementing CO2 emissions from power plants is
problematic for a few reasons. First, § 111(d)(1)(A) requires that the use of the language “any
air pollutant” was intended to encompass carbon dioxide. In Massachusetts v. EPA, the United
States Supreme Court held that greenhouse gas (“GHG”) emissions from motor vehicles are “air
pollutants” under § 202(g) of the Clean Air Act, going so far as to say that “air pollutant”
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included “all airborne compounds of whatever stripe.”31 Massachusetts triggered a heightened
desire for EPA regulation of CO2 emissions from the power sector and breathed new life into
efforts to require EPA to undertake such regulation. Previously, this agency has declined to
regulate GHG emissions, finding that none of the approaches to reducing CO2 were well-suited
to regulation by the EPA specifically acknowledging as early as 2003 that the Department of
Energy was better equipped to set efficiency standards for products such as air conditioners and
appliances and that “Any widespread effort to switch away from fossil fuels in either sector
would likewise require a wholesale transformation of our methods for producing power and
transporting goods and people” and it is “hard to overstate the economic significance of making
these kinds of fundamental and widespread changes in basic methods of producing and using
energy.“32
The Supreme Court’s decision in Massachusetts and the subsequent “Endangerment
Finding”33 cannot stand for the proposition that the reduction of CO2 emissions is necessary at all
costs. What Massachusetts did stand for was the proposition that EPA could not simply decide
not to act for policy reasons but “must ground its reasons for action or inaction in the statute.”34
In Massachusetts, the question was one of whether the EPA was fulfilling its duty under CAA §
202. By contrast, the pendulum has now swung in the other direction and EPA is attempting to
enact rules that far exceed the statutory text or any statutory duty.
Relying on the expansive definition of air pollutant found in § 202(g) (“all airborne
compounds of whatever stripe”), the EPA attempted to require best available control technology
(“BACT”) and “major source” permits on the basis of CO2 emissions pursuant to several
31
549 U.S. 497 (2007).
68 Fed. Reg. 52,922.
33
74 Fed. Reg. 66,496 (2009).
34
Id. at 535.
32
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enforcement provisions that referenced “any air pollutant”. In Utility Air Regulatory Group v.
EPA35 the Court upheld the EPA’s authority to require “anyway sources” to obtain PSD and Title
V permits but declined to give EPA the wide latitude it had assumed in “tailoring” those
statutory provisions to suit its policy objectives. In light of UARG, EPA is required to give a
“reasonable, context-appropriate meaning” to the regulation it wishes to enforce.36
It is worthy of note that similar to its BSER analysis conducted by EPA in the proposed
CPP, the UARG Court acknowledged EPA’s intention that improvements in EE would be the
foundation of GHG BACT pursuant to § 7602. The Court acknowledged this but did not decide
whether BACT could be used to force improvements in EE, stating only that BACT was already
limited to control technology that “did not require a fundamental redesign of the facility” and
that the record did not reflect that EPA’s demands would be of a significantly different character
than those traditionally associated with PSD review or that BACT is “incapable of being sensibly
applied to greenhouse gases.37 LPSC submits that this is indication that EPA’s deference is not
unlimited on these issues and BSER in § 111(d), likewise, cannot force the type of fundamental
changes proposed herein.
Assuming for arguments sake that CO2 meets the definition of any air pollutant for the
purposes of § 111(d), EPA still has to overcome a number of statutory hurdles to make the CPP
fit within the plain text of the statute. Specifically, § 111(d)(1)(A)(i) explicitly prohibits the
regulation of source category[ies] regulated under § 112. The Supreme Court in Am. Elec.
Power, Inc. v. Connecticut, 131 S. Ct. 2527, 2537 n.7 (2011), stated “EPA may not employ [§
111(d)] if existing stationary sources of the pollutant in question are regulated under . . . the
‘hazardous air pollutants’ program, [§ 112]. Nevertheless, on February 16, 2012, EPA finalized
35
573 U.S.____ (2014).
Id.
37
Id.
36
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§ 112 regulations on “stationary sources” that included coal-fired power plants. See 77 Fed. Reg.
9,304 (Feb. 16, 2012). Those very same plants are included in the CPP despite their being
explicitly prohibited and that such explicit prohibition has been acknowledged by the United
States Supreme Court.
Even if EPA could overcome the aforementioned statutory prohibition, which we do not
think it can, there is yet another requirement: that the source category is one regulated under the
new source performance standards found in § 111(b).
iv. Section 111(d) envisions a state-directed approach with guidelines by EPA.
Despite the promise of flexibility, EPA has provided no opportunity for states to have a
meaningful role in this process, as the proposed rule requires SIPS to meet draconian standards
of “emission performance equivalent to the goals established by the EPA, on a timeline
equivalent to that” in the rule. EPA’s proposed rule is inconsistent with § 111(d) because while it
purports to allow flexibility, in fact, it provides only one way of accomplishing the standards –
EPA’s way. Given the severity of the emissions reductions, there is no meaningful way for
States to develop an autonomous plan for compliance, despite the United States Supreme Court’s
acknowledgment that this state authority is necessary given that § 111 allows “each State to take
the first cut at determining how best to achieve EPA emissions standards within its domain.”38
Section 101(a)(3) of the CAA provides a clear definition of the role of States in
regulating pollutants, namely that “the prevention and control of air pollution at its source is the
primary responsibility of States and local governments….”.39 As the D.C. Court has recognized
in multiple cases, Congress has clearly recognized that states are in a superior position compared
to the EPA to make a determination regarding the exact method and process that the individual
38
39
AEP v. Connecticut, 131 S. Ct. 2527, 2539 (2011).
42 U.S.C. Section 1857(c)(4).
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[electric generating units] within its borders will follow to meet the applicable standards.40 One
obvious reason for this deference required by Congress is the state’s familiarity with the
problems and issues confronting the industry within the state and the status and cost of various
emission controls that are required to meet the standards. The EPA is clearly attempting to usurp
the authority granted to the States in the CAA as well as the police power of the states by taking
away any meaningful opportunity for states to determine how they will meet required emissions
reductions within their own borders.
v. EPA fails to consider efficiency implications of its other rules and
regulations.
The U.S. power industry has already been subjected to a number of other state and
federal environmental regulations that require the installation of pollution-cutting and control
technologies. As explained further in § III.B.4, infra, the recent Mercury and Air Toxics Rule
(“MATS”) required the installation of pollution control technologies that will reduce most coalfired units’ thermal efficiencies by as much as one to four percent.41 The installation of the
controls necessary to achieve and maintain compliance with MATS is still underway at many
units and may further degrade unit efficiency making the emissions reductions required by the
CPP even more difficult to achieve. Further, many of the heat rate improvement projects
involve equipment replacements or upgrades that will trigger the new source review (“NSR”)
provisions of the Clean Air Act. EPA offers no relief from NSR enforcement for operators who
seek to comply with § 111(d) by improving unit efficiency, and without such relief, many
40
See e.g., Train v. Natural Res. Defense Council, Inc., 421 U.S. 60, 86-87 (1975); Union Elec. Co. v. EPA, 427
U.S. 246, 269 (1976).
41
Cleco comments, LPSC Docket R-33253, In Re: The United States Environmental Protection Agency’s proposed
rule on carbon dioxide emissions from existing fossil-fuel fired electric generating units under Section 111(d) of the
Clean Air Act.
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operators will be reluctant to engage in more expensive efficiency improvements like turbine
replacements and other equipment upgrades that offer the most cost-efficient improvements.
Adding to the confusion, EPA’s proposal for modified and reconstructed units42, issued
the same day as its existing source plan, establishes a much less ambitious target rate for heat
rate improvements for these units, offering alternatives based on a two percent improvement
over a unit’s best historic heat rate, or another value based on a unit-specific evaluation
conducted by the states. EPA’s proposal assumes that heat rate improvements can be measured
and verified for compliance purposes through existing monitoring and reporting conventions
developed for the Acid Rain Program and used in other allowance trading programs, as set forth
in 40 CFR Part 75. However, EPA now proposes to augment this reporting regime by requiring
new methods to be employed for reporting net generation, in order to calculate CO2 emission
rates in terms of pounds per megawatt-hour of electricity.
III.
TECHNICAL BASIS FOR THE RULE IS FLAWED
The LPSC found numerous instances of incorrect data and assumptions, as further
detailed below. The LPSC submits that the errors in EPA’s modeling and analysis are further
proof that states are in the best position to oversee utility resource planning. The LPSC has
worked closely with LDEQ, in addition to other Louisiana stakeholders, in reviewing the
baseline information included in the EPA technical support documents. This collective review
has identified several data deficiencies that were identified by LDEQ in their initial comments.
The LPSC does not envy the position of trying to understand the resource availability and
requirements of all fifty states. To the extent that EPA attempts to redeem this rule, the LPSC
requests the following technical flaws be remedied in the final rule.
42
Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units;
Proposed Rules, 79 Fed. Reg. 34959 (June 18, 2014).
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A. EPA’s Proposed BSER for Louisiana is Discriminatory.
The EPA sets 2 target CO2 emission rates for Louisiana as shown in Figure 1. The 2020
Interim Goal will require Louisiana to reduce its CO2 emissions by 38 percent from a baseline
level of 1,533 lbs/MWh to 948 lbs/MWh. The EPA’s 2030 Final Goal of 883 lbs/MWh is a 42
percent reduction relative to EPA’s 2012 baseline.
Overall, the Interim Goal will require
Louisiana to reduce its power sector CO2 emission by as much as 17.8 million metric tons, and
19.7 million metric tons by 2030.43 The EPA’s proposed final CO2 emissions reductions is
comparable, in level terms (or mass balance terms) to the carbon emissions of three of
Louisiana’s four major coal facilities (Brame Energy Center, Dolet Hills, and RS Nelson).
1,800
1,600
lbs CO2/MWh
1,400
2020 Interim Goal: 948
lbs/MWh; a reduction of
585 lbs/MWh, or 38
percent.
1,200
1,000
2030 Final Goal: 883
lbs/MWh; a reduction of
650 lbs/MWh, or 42
percent.
800
600
400
200
0
2012 Baseline
2020 Interim Goal
2030 Final Goal
Figure 1. Proposed Louisiana CO2 State-wide Emission Rate Reduction
Source: EPA Technical Support Documents.
Louisiana will be required to reduce its CO2 emissions at a level comparable to the
national average reduction under the proposed CPP. Figure 2 highlights Louisiana’s required
43
EPAs Rate to Mass Technical Support Document and Data File, issued November 2014.
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emissions reductions relative to other states despite the fact that Louisiana uses about 27 percent
more natural gas to generate electricity than the overall U.S. average.
Louisiana gets effectively no credit, under the proposed CPP, for having spent decades
concentrating its power generation resources into cleaner burned fuel sources: Louisiana will be
required to reduce its CO2 emissions by 650 lbs/MWh, an amount virtually equal to the national
average of 649 lbs/MWh.
1,600
1,400
lbs CO2/MWh
1,200
Louisiana’s emission
rate reduction: 650
lbs/MWh
US average emission
rate reduction:
649 lbs/MWh
1,000
800
600
400
0
AL
AK
AZ
AR
CA
CO
CT
DE
FL
GA
HI
ID
IL
IN
IA
KS
KY
LA
ME
MD
MA
MI
MN
MS
MO
MT
NE
NV
NH
NJ
NM
NY
NC
ND
OH
OK
OR
PA
RI
SC
SD
TN
TX
UT
VA
WA
WV
WI
WY
200
Figure 2. State Comparison of Emission Rate Reductions
Source: EPA Technical Support Documents.
Figure 3 highlights the inequity of the proposed EPA CPP in greater detail. The figure
charts the percent emissions reductions (star symbols) required under the proposed CPP against
each state’s share of coal generation. In 2012, 16 states reported that they generate 80 percent or
more of their electricity from coal. Of those 16 states, only one (South Dakota) has a proposed
CPP carbon emissions reduction that is greater than the national average (67 percent reduction).
Another four states have reductions that are comparable to the national average, while the
balance are below, and in some instances, well below the national average and the required
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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reductions EPA is imposing on Louisiana. Consider that four states (Kentucky, North Dakota,
Wyoming, and West Virginia) all report 100 percent of their power being generated from coal,
and yet all four have emissions reductions less than 30 percent.
100%
90%
80%
Percent
70%
60%
50%
40%
30%
20%
0%
KY
ND
WY
WV
SD
MT
NE
IA
KS
MO
IL
IN
TN
UT
MD
OH
CO
MN
NC
WI
SC
MI
AR
PA
NM
GA
AZ
AL
OK
TX
LA
VA
WA
HI
FL
OR
DE
MS
NH
NV
NJ
MA
AK
NY
CA
CT
ID
ME
RI
10%
Coal Generation as Percent of Total
Emissions Reduction
U.S. Average Emissions Reduction
Figure 3. Myth: Louisiana Will Not be Impacted Much Since it is a Natural Gas State
Source: EPA Technical Support Documents.
Even more imposing is the impact that the proposed CPP will have on Louisiana
ratepayers.
Louisiana’s required emissions reductions, as a share of state Gross Domestic
Product (or “GDP”) is considerable. Figure 4 shows that Louisiana will be one of the hardest
impacted states on an emissions reduction per GDP basis of any state in the country. Louisiana,
for instance, ranks 8th in the required reductions per unit of state GDP under the proposed CPP.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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New Natural Gas End Uses & Fuel Diversity Concerns
`
Greater than 100 M short tons per million $
50M-100M short tons per million $
Less than 50M short tons per million $
No Requirement
Figure 4. Emissions Reductions per State GDP
Source: EPA Technical Support Documents.
Figure 5 outlines the various components of EPA’s estimated BSER for Louisiana.
Building Block 1, which estimates the percent reductions available from improved coal plant
thermal efficiencies, accounts for 8 percent of Louisiana’s required CO2 reductions under the
proposed CPP.
Building Block 2, which estimates the CO2 reductions that would arise if
Louisiana required its natural gas combined cycle (“NGCC”) units to increase their operating
utilization rates to 70 percent on an annual average basis, accounts for the overwhelming share
(58 percent) of the reduction under the EPA’s BSER estimates for Louisiana. Building Block 3a,
representing the emissions reductions associated with preserving “at-risk” nuclear generation,
accounts for three percent of Louisiana’s BSER.
Building Block 3b, estimated to be the
potential emission reductions available from the utilization of greater levels of renewable energy,
would account for 16 percent of Louisiana’s BSER. Lastly, Building Block 4, estimated by EPA
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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as the potential CO2 reductions that could arise from greater levels of energy efficiency, are
estimated to account for 15 percent of Louisiana’s BSER.
Building Block 1: EPA reviewed the
opportunity for coal-fired plants to
improve their heat rates. BSER
assumes all coal plants can increase
their efficiency by 6 percent.
Building Block 2: EPA found
an average availability of 70
percent for natural gas CCs to
be technically feasible.
8%
Building Block 4: EPA estimated energy
efficiency deployment in 12 leading
states and assumes all states can increase
their current annual savings rate to reach
annual savings of 1.5 percent by 2030.
15%
Each building
block accounts for
a portion of the
total goal.
16%
3%
58%
Building Block 3b: EPA
developed targets for renewable
energy penetration in six regions
and calculated regional growth
factors to achieve each target by
2030.
Building Block 3a: EPA identified
five nuclear units currently under
construction and assumes that 5.8
percent of existing nuclear capacity
is ‘at-risk” but can be retained.
6
Figure 5. EPA’s Proposed CPP, Louisiana BSER Targets
Source: EPA Technical Support Documents.
As will be discussed in greater detail herein, the LPSC takes serious issue with the
development of EPA’s BSER, in general, and the methods by which each of the building blocks
associated with the BSER are calculated. The LPSC believes there are errors associated with
each of the analyses that leads to significant overestimates of the potential emissions reductions
available in each of the building blocks. Further, the LPSC believes EPA has failed to consider
other critical policy issues in estimating Louisiana’s BSER such as cost and power system
reliability.
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B. Building Block 1 is flawed.
EPA’s heat rate analysis uses data for 884 coal- and petroleum coke-fired electric
generating units (EGUs) for an 11-year period to examine the potential for gross heat rate
efficiencies.44,45 EPA performed a statistical analysis of hourly heat rates to evaluate variations
in efficiency and derive a potential for heat rate improvement. EPA concluded that the heat rate
of U.S. coal-fired EGUs could be improved by an average of four percent by adopting ‘best
practices’ that have the potential to improve heat rate. In addition, EPA relied upon a 2009
engineering study46 to conclude that another two percent of heat rate improvement was possible
throughout the U.S. fleet through equipment upgrades. EPA added together these two average
improvement percentages and concluded that the entire U.S. fleet of coal-fired EGUs could
increase heat rate efficiency by six percent.
i.
Heat rate assumptions are incorrect.
An EGU’s heat rate is traditionally defined as the amount of fuel energy input needed to
produce one unit of electric energy output. Thus, the more efficient the unit is, the lower its heat
rate. The heat rate of an EGU can be expressed as a gross heat rate or a net heat rate. A gross
heat rate is the total energy input from the fuel divided by the total electrical energy generated.
A net heat rate still uses the total energy input from fuel, but subtracts from the denominator the
generated electricity used by the facility to power the unit itself.47
44
The study population included units that reported both heat input and electrical output to the EPA’s Clean Air
Markets Division in 2012.
45
EPA Technical Support Document: GHG Abatement Measures, p. 2-18.
46
Sargent & Lundy 2009, Coal-Fired Power Plant Heat Rate Reductions, SL-009597, Final Report, January 2009,
available at http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.
47
The electricity used by the facility is termed auxiliary load and can include the energy used to run pumps, fans,
pulverizers, emissions controls, lighting and various other components.
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Typical industry practice is to report a unit’s net heat rate. 48 The EPA’s use of gross heat
rate is contrary to industry practice and EPA’s own analysis. Most studies examining thermal
efficiency opportunities (heat rate improvements or “HRI”) at power generation facilities utilize
net heat rate measurements, not gross heat rate. In fact, the Sargent & Lundy report frequently
cited and relied upon by the EPA in developing Building Block 1, defines an EGU’s heat rate as:
…the amount of fuel energy input needed (Btu, higher heating value basis) to
produce 1 kWh of net electrical energy output. It is the metric most often used in
the electric power generation industry to track and report the performance of
thermal power plants.49,50
Moreover, EPA’s analysis was inconsistent. While EPA’s statistical analysis uses gross
heat rate as the measure of operating efficiency, its Building Block 1 recommendations are based
upon on a net heat rate. EPA attempts to explain this inconsistency by saying that any HRI
method that reduces gross heat rate will also reduce net heat rate, and that some HRI methods
reduce net heat rate without reducing gross heat rate. Similarly, the EPA “expect(s) the HRI
potential on a net output basis is somewhat greater than on a gross output basis, primarily
through upgrades that result in reductions in auxiliary loads”.51 While the assumptions made by
the EPA to extrapolate a net heat rate value based on a gross heat rate estimate may be valid on
average, there is not a relationship between net and gross heat rate that is applicable to all types
of plants, and thus, these assumptions are likely problematic at the state and regional level. 52
The North American Electric Reliability Corporation (“NERC”) recently released a
review of the “reliability implications and potential consequences from the implementation of the
48
See U.S. Department of Energy, Energy Information Administration, Glossary.
Available at:
http://www.eia.gov/tools/glossary/index.cfm?id=H.
49
Sargent & Lundy 2009, Coal-Fired Power Plant Heat Rate Reductions, SL-009597, Final Report, January 2009,
available at http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf, (emphasis added).
50
The U.S. Department of Energy’s Energy Information Administration also expresses heat rates in terms of net
generation. See EIA’s website, “What is the efficiency of different types of power plants,” available at:
http://www.eia.gov/tools/faqs/faq.cfm?id=107&t=3.
51
EPA Technical Support Document: GHG Abatement Measures, p. 2-37.
52
EPA Technical Support Document: GHG Abatement Measures, p. 2-37.
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proposed CPP and its underlying assumptions.” In its review, NERC also highlights the error in
EPA’s Building Block 1 methodology:
The EPA calculated unit-specific heat rates using gross generation data … With
this approach, the EPA excluded generation-reducing effects from postcombustion environmental controls, such as selective catalytic reduction and fluegas desulfurization controls. The EPA then used net generation data, without
consideration for these retrofits, for coal-fired EGUs when calculating the state
CO2 emission rate goals. These retrofits will reduce the net output of these units,
as well as their associated net heat rate efficiency. Not considering these
reductions creates an inconsistent approach, especially considering that most coalfired EGUs will require control retrofits to comply with environmental
regulations, such as the Mercury Air Toxic Standards (MATS) and Section 316(b)
of the Clean Water Act.53
ii.
Not all EGUs are created equally
The heat rate of an EGU is not a constant value and, as the EPA points out, a number of
factors can affect an EGU’s efficiency that include its: thermodynamic cycle; coal rank and
quality; facility size; pollution control systems; operating/maintenance practices; type of cooling
system; geographic location and ambient conditions; load generation flexibility requirement
(baseload vs. load following); and plant components.54 In addition, not all EGUs are designed to
be operated at the same exact heat rate. Coal-fired EGUs throughout the U.S. differ in age; burn
differing types of coal; and have been designed and constructed by different manufacturers. For
instance, an EGUs “design heat rate,” and its actual average heat rate, are likely to differ
significantly since the design heat rate is a “theoretical target that represents an optimal, fullload, steady-state condition and is considered the best a unit could potentially achieve under its
original design conditions.”55 The age of a coal generation unit, its historic operations and
53
North American Electric Reliability Corporation. 2014. Potential reliability impacts of EPA’s Proposed Clean
Power Plan, p. 8.
54
EPA Technical Support Document: GHG Abatement Measures, p. 2-4.
55
Southwestern Electric Power Company’s (SWEPCO) Comments dated July 25, 2014, LPSC Docket No. R-33253,
In re: The United States Environmental Protection Agency’s proposed rule on carbon dioxide emissions from
existing fossil-fuel fired electric generating units under Section 111(d) of the Clean Air Act.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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maintenance, and the retrofit of any auxiliary equipment like emissions controls will
significantly impact the coal unit’s heat rate. In other words, unit HRIs are unit-specific and it is
unreasonable to assume that all EGUs could incorporate all heat rate improvement methods and
that each method would impact each and every EGUs in the same manner.
For instance, in Louisiana, Cleco recently noted in formal comments before the
Commission that its Madison 3 unit is a “new generation sub-critical circulating fluidized bed
boiler with state-of-the-art technologies to achieve low heat rate and low emissions that has very
limited opportunities (“marginal opportunities”) for any thermal efficiency gains.”56 Cleco also
noted that an additional 6 percent thermal efficiency improvement at its other 2 coal generation
facilities would also be equally unlikely since the utility (and its partners) have already installed
HRI measures at these plants.
The Sargent & Lundy report, upon which much of the EPA’s HRI assumptions are based,
identified a series of HRI measures and their potential effectiveness. The Sargent & Lundy
report offers guidelines to be used to evaluate individual facilities, on a case-by-case basis and
applies its findings to two case studies to calculate potential improvements. The EPA, however,
erroneously assumes that these potential improvements and case study results are applicable and
achievable to all coal fired EGUs in the U.S.
Further Sargent & Lundy has noted that many of the assumptions EPA utilized in its
proposed rule take conclusions from their study out of context noting that:

The results in the 2009 Report were mostly based on publicly available
data, data from original equipment manufacturers, and Sargent & Lundy's
power plant experience. Furthermore, the case studies showed that not all of
56
In re: The United States Environmental Protection Agency’s proposed rule on carbon dioxide emissions from
existing fossil-fuel fired electric generating units under Section 111(d) of the Clean Air Act. Louisiana Public
Service Commission, Docket No. R-33253, Cleco Power LLC’s Responses to LPSC Staff’s Notice of Request for
Specific Comments dated July 25, 2014.
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the examined alternatives were feasible to apply to an individual generating
unit due to a number of factors, including plant design, previous equipment
upgrades, and each plant's operational restrictions.

Various limitations exist for applying each heat rate improvement strategy,
and these limitations depend on the unit type, fuel type, and many other
site-specific conditions. Therefore, the ability to apply each strategy and the
amount of heat rate reduction that can be achieved by each strategy is sitespecific and must be evaluated on a case-by-case basis.

It appears as though the EPA assumed that heat rate improvements cited in
our 2009 Report were additive and applicable to all coal-fired units. Heat
rate improvement ranges described in the 2009 Report case studies were
estimated at a conceptual level, and were not based on detailed site-specific
analyses. Verification of actual heat rate improvements was not made
determine whether any of the strategies were implemented and what actual
heat rate improvements were realized based on site-specific design.

Combinations of strategies to achieve heat rate improvements do not always
provide heat rate improvement reductions equal to the sum of each
individual strategy's heat rate improvement because many of the
technologies affect, or are dependent upon, plant operating variables that are
inter-related. Therefore, case-by-case analyses should be conducted to
determine whether the incremental heat rate improvement through the
application of multiple strategies is economically justified.

The performance of some of the evaluated heat rate improvement strategies
degrades over time, even with best maintenance practices. Therefore,
depending on the strategy employed or the technology installed to reduce
heat rate at an existing coal-fired EGU, the unit heat rate initially obtained
may increase over time.57
iii.
Lower loads equal higher heat rates
The EPA’s proposed rule also fails to consider the impact of its Building Blocks upon
one another. For instance, the aim of Building Block 2 is to increase the dispatch of NGCCs,
thereby decreasing the base-load usage of coal-fired units. What the EPA does not consider in
its analysis is that this change in dispatch of coal-fired EGUs is likely to have a negative effect
on the efficiency of coal-fired EGUs. Coal-fired units are designed to operate as base-load units,
57
Sargent & Lundy. Letter to National Rural Electric Cooperative Association, re: Coal Fired Power Plant Heat
Reduction, dated October 15, 2014.
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running continuously at a steady load. Changing the dispatch of these units to cycle up and
down, or run at minimum loads will reduce its thermal efficiencies (i.e., increase the unit’s heat
rate) thereby requiring more, not less thermal input per unit of generation. The relationship of
unit load to heat rate is shown in Figure 6 below.
Figure 6. Heat Rate Change (Relative to Full Load) vs. Load
Source: In re: Swepco Comments dated July 25, 2014, LPSC Docket R-33253.
Sargent & Lundy identified this problem in their summary of study conclusions upon
which EPA purports to base its proposed thermal efficiency improvement building block:
Heat rate is increased when plants operate at lower loads, and the benefit of a heat
rate improvement strategy is reduced at lower loads. Therefore, if an existing
EGU is currently base-loaded and shifts to a load-cycling operating profile in the
future, that unit's annual average heat rate will increase, and the heat rate
reduction strategy (or strategies ) implemented will not lower the annual average
heat rate as much as compared to base-load operation. In some cases any HRI
improvements achieved by undertaking the relevant options described in S&L's
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2009 Report could, in some cases, be negated by HRI losses associated with loadcycling.58
A recent NERC review of the EPA’s Proposed CPP Rule also reaches a similar
conclusion regarding coal-fired capacity factors and increased heat rates:
Lower-capacity factors will cause an increase in heat rates, particularly if the
lower-capacity factors are due to the cycling of the coal units. As a result of
Building Block 2, coal units will cycle more often; therefore, assumed heat rate
improvements across the entire coal fleet are unlikely. While recognizing capacity
effects in the regression analysis, the EPA did not evaluate the effects of lowercapacity factors resulting from the dispatching of natural gas generation before
coal generation.59
iv.
MATS-related improvements raise net heat rates.
EPA’s MATS rule will require some facilities to add pollution controls that could raise
net heat rates by 1 to 4 percent.60 Both Cleco and SWEPCO have undertaken improvements of
emissions control systems that will impose increase the facilities’ net heat rates.61 Cleco has an
application currently pending before the LPSC in which it is seeking to recover $114 million in
MATS retrofits at three facilities the effect of which could be to raise net heat rates.62 This
problem is also highlighted by Sargent & Lundy, again, in response to the EPA’s use of its prior
work in developing the first building block of the Proposed CPP:
The installation of additional pollution controls such as that required by
regulations including BART, MATS, etc. will decrease the heat rate efficiency of
any unit as compared to its heat rate efficiency before the installation.63
58
Sargent & Lundy. Letter to National Rural Electric Cooperative Association, re: Coal Fired Power Plant Heat
Reduction, dated October 15, 2014.
59
North American Electric Reliability Corporation. 2014. Potential reliability impacts of EPA’s Proposed Clean
Power Plan, p. 8.
60
Cleco comments dated July 25, 2014, LPSC Docket R-33253.
61
SWEPCO Comments dated July 25, 2014, LPSC Docket R-33253.
62
LPSC Docket U-32507.
63
Sargent & Lundy. Letter to National Rural Electric Cooperative Association, re: Coal Fired Power Plant Heat
Reduction, dated October 15, 2014.
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v.
Improvements may
(“NSR”) process.
trigger
New
Source
Review
The EPA also fails to consider the relationship between its Proposed CPP Rule and prior
standards it has imposed on EGUs under NSR. The EPA regulates emissions from new, large
stationary sources through the NSR process. If a new emissions source will produce emissions
above a certain threshold, it must acquire a permit. This permit requires that the emissions
source employ the BACT to ensure it will take all feasible steps available to limit emissions.
BACT is set on a source-specific basis, and it is quite possible that capital investments and
upgrades to EGU efficiency would trigger NSR and even higher capital investments in
retrofitting additional environmental controls. This is an issue also highlighted by Sargent &
Lundy in its reply to the EPA’s use of its study results for the development of Building Block 1:
“many of the options for HRI listed in our 2009 Report have triggered New Source Review
actions by EPA and others.”64
vi.
Empirical modeling used in heat rate analysis is flawed.
In an effort to estimate the potential emissions reductions from heat rate improvements,
the EPA performed three analyses:
1) A regression analysis to understand the impact of capacity factor and ambient
temperature;
2) A bin model to determine the potential from best practices; and
3) An evaluation of available data and information to assess the potential from equipment
upgrades.65
64
65
Id.
EPA Technical Support Document: GHG Abatement Measures, p. 2-22.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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The EPA performed 3 regression analyses: (1) heat rate onto capacity factor; (2) heat rate
onto ambient temperature; and (3) heat rate onto capacity factor and ambient temperature. 66 The
EPA explains that because it is evaluating heat rate under normal operating conditions, it
eliminated records with hourly heat rate values outside of +/- 2.6 standard deviations.67 While
this may be an acceptable practice for the EPA, it is contrary to standard statistical and economic
practice for empirical work. As explained in Chambers (1986), if the outliers in question are
“elements with values that have been correctly recorded and that cannot be assumed…[that]
there are no more similar outliers in the non-sampled part of the target population,” then they
should not simply be dropped from a regression.68 The EPA states that these outliers occur for
plants utilizing partial operating hours and low load conditions and are not due to incorrect data
or other problems.69 This type of outlier should not be ignored, since it is still representative of
some portion of the population.70 There is simply no statistical rationale for the EPA’s selective
exclusion of this data.
The EPA’s regression results are expressed as the “R-squared” of the regression, which is
one measure of the goodness of fit. However, the EPA’s model omits a number of important
variables,71 and thus it cannot be said with certainty that the R-squared is attributable to capacity
factor and ambient temperature alone. When variables are omitted, the estimated coefficients
may be biased in the amount that they are correlated with the included variables.
66
EPA Technical Support Document: GHG Abatement Measures, p. 2-24.
EPA Technical Support Document: GHG Abatement Measures, p. 2-24.
68
Chambers, Raymond, 1986. Outlier Robust Finite Population Estimation Journal of the American Statistical
Association, p. 1063. Available: http://0-www.jstor.org.iii-server.ualr.edu/stable/2289084
69
EPA Technical Support Document: GHG Abatement Measures, p. 2-24.
70
The proper weighting to be used has been addressed theoretically as well as empirically, for instance, Chambers,
Raymond, 1986. Outlier Robust Finite Population Estimation Journal of the American Statistical Association, p.
1063. Available: http://0-www.jstor.org.iii-server.ualr.edu/stable/2289084.
71
As noted by the EPA in its TSD, variables such as thermodynamic cycle, coal rank and quality, facility size,
pollution control systems, operating/maintenance practices, type of cooling system, geographic location and ambient
conditions, load generation flexibility requirement (baseload vs. load following), and plant components are relevant
in determining heat rate, but were omitted from the regression analysis. GHG Abatement Measures, p.2-24.
67
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One example of an omitted variable is one representing the degree to which the unit is
load-following. The EPA recognizes that load-following is vitally important in determining heat
rate.72 If a load-following plant has a large capacity, then the estimate for the impact of capacity
on heat rate will be higher since it is also capturing the impact of load-following on heat rate.
Thus, the capacity impact will be overestimated. Similarly, plants that have many starts, will
have higher heat rates since it takes more fuel to produce less energy. However, the EPA’s
analysis removes observations with higher heat rates even if those higher rates were due to
higher number of starts.
The second portion of the EPA statistical analysis, which utilizes a bin model to
determine the potential improvement from using best practices, groups plants into bins based
only on temperature and capacity.73 This analysis raises similar concerns with reliability and
comparability as noted earlier in the criticisms of the initial regression analysis. For instance, if
plants with similar temperature and/or capacity are different in other important yet unconsidered
ways, then the EPA’s statistical bin analysis will not be appropriate. This is of particular
importance since the EPA’s proposed HRI is based on “comparable” plants within the same bin,
that very well could be unreliable if plants differ based on unconsidered factors.
EPA also cites Fredricks and Todd (2009) as proponents for the widely applicable
reduction in heat rate in power plants by better data monitoring: statistical process control
(“SPC”).74 Fredricks and Todd discuss the use of what is today more frequently referred to as
the use of “big data” in improving the identification of problem areas in electricity generation.
While these methods can be informative in the use of better statistical methods and data
72
EPA Technical Support Document: GHG Abatement Measures, p. 2-24.
EPA Technical Support Document: GHG Abatement Measures, p.2-30.
74
Fredrick & Todd, 1993. Statistical Process Control Methods in Performance Monitoring. Available at
http://famos.scientech.us/Papers/1993/1993section11.PDF.
73
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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.
collection processes, Fredrick and Todd warn that their findings cannot be generally applied,
which is what EPA appears to be doing in its third methodology. Fredrick and Todd, for
instance, only consider the impact of SPC in 2 plants, where the costs and improvements found
are in no way representative of the population of power plants in operation. The authors stress
(much like Sargent and Lundy) the importance of plant-by-plant analysis to provide true cost and
potential heat rate reduction estimates. The cost estimates provided by the EPA are too general,
and contradict suggested methodology by existing literature.
The EPA concludes that the results of its analysis display a wide range of heat rate
variability thus indicating the potential for heat rate improvement. The generation-weighted
mean RSD for the study population is 5.4 percent: a value weighted more heavily for large units,
which also likely have larger potential improvement on average. This methodology will provide
a disproportionate estimate which does not directly correspond for smaller units. Similarly, the
EPA admits that there has been a large change in quality of reporting for a number of plants over
the 11 year sample, the implications of which are not fully considered in the development of the
Building Block 1 recommendations. For example, EPA does not indicate how Table 2-8 (in its
GHG Abatement Measures TSD) will change if instead of using data from the previous 11 years,
only the previous five years’ data are included, where the data reporting changes have already
occurred.
The reporting methods for heat rate are noisy: the level of accuracy for heat rate
measurement varies by EGU, which causes statistical noise in any analysis using this measure.
Statistical noise is a common concern in empirical research, but nonetheless needs to be
addressed in a straightforward and open manner. The EPA states, “approximately two-thirds of
the large decreases in heat rate can be associated with changes in reporting method implemented
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 34
.
to provide more accurate heat input data.”75 If the heat rate measures remained noisy throughout
the sample period, this would just create attenuation bias in any regression estimates for heat
rate. However, in this case, the heat rate measures for some EGUs become less noisy over time.
This means that if the “noisiness” of a plant’s heat rate reporting is related to one of the variables
in the estimated regressions, the error term will be heterogeneous and dependent on time.
Heterogeneous errors violate the assumptions of OLS regression, but the full extent of the impact
cannot be determined without further analysis.
vii.
EPA fails to consider the potential stranded costs and
rate impacts associated with its recommendations.
While the EPA calculates costs associated with its proposal based on the cost of
compliance, it does not consider the potential for significant stranded costs associated with the
reduced production, or premature retirement of coal-fired EGUs.76 A utility’s investment in an
EGU is recovered through depreciation over the life of the facility. “Stranded costs” are incurred
when the undepreciated value of that facility is no longer recoverable. Many coal plants facing
potential shut down from the Proposed CPP Rule (and the cumulative impact of other EPA
regulations) are older with most of their original investment being recovered through utility rates
over an extended period of time. These plants, however, are not completely depreciated, since
many require ongoing capital in order to continue to run, and remain compliant with ongoing
changes in EPA regulations.
For Louisiana, the EPA’s target for reduced coal generation is about 48 percent of the
reported 2012 coal-fired generation (from 24.3 million MWh in 2012 to a target of 11.5 million
MWh). Table 1 presents the cost estimate for coal plant capital investments and associated
75
EPA Technical Support Document: GHG Abatement Measures, p. 2-34.
The investment of an EGU is recovered through depreciation expense over the life of the plant. Stranded costs are
the undepreciated value of a facility that ceases to be “used and useful”.
76
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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.
stranded costs. Assuming a capital cost of $150/kW (mid-range estimate for thermal upgrades),
capital upgrades in Louisiana required by Building Block 1 of the EPA’s proposal would total
over $638 million. Compounded with this costs, are the stranded costs associated with having to
make these new HRI investments, and recover these new costs, in addition to each EGU’s
remaining plant in service, over a lower generation amount (i.e. stranded facilities costs). The
LPSC estimates these potential coal facility compliance and stranded costs to total $1.5 billion in
net present value terms.77 Louisiana ratepayers will likely be required to foot this bill.
Preliminary Cost Estimates
Low
Mid
High
Range
Range
Range
Cost
Cost
Cost
------ ($ Millions, NPV) ------
Building Block
Strategy
Building Block 1
Increase Coal Plant Thermal Efficiency
Coal plant capital investment costs:
Stranded coal plant capital cost:
Building Block 2
$
$
425.5
842.6
$
$
638.3
842.6
$
$
851.0
842.6
Increase Natural Gas Generation Capacity Factor
New transmission capital investments:
Stranded oil/gas steam plant capital cost:
Building Block 3a At Risk Nuclear Generation
Building Block 3b Increased Renewable Generation
Increased capital cost margin:
Utility lost revenue recovery:
Building Block 4
Increased Energy Efficency
Increased energy efficiency program expenditures:
Utility lost revenue recovery:
Total Louisiana Cost Impact:
$ 1,268.1
$ 1,480.8
$ 1,693.6
Table 1. Estimated Cost of Building Block 1
Note: Coal plant capital investment costs are assumed to be: $100/kW (low); $150/kW (mid); and $200/kW (high)
for all Louisiana coal units.
Stranded cost estimates are only included for utility-owned units with publicly available data.
77
The reported 2012 plant in service figures for Louisiana coal-fired units total $1.7 billion. If one were to assume
that the 48 percent decrease in Louisiana’s coal-fired generation were applied to these facilities uniformly, this
would result in a potential stranded cost of over $842 million.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 36
C. Building Block 2 is Flawed
i.
Incorrect data
The LPSC supports the initial comments filed by LDEQ on September 12, 2014 focusing
on several data errors and omissions that would significantly alter the EPA’s calculations in
“Building Block 2” and impact the final goal for Louisiana. For instance, the EPA calculations
inadvertently exclude two NGCC units that are “under construction,” as defined by the Proposed
CPP. First, Entergy Louisiana is constructing 2 new NGCC units at its Ninemile Point Electric
Generating Plant in Westwego, Louisiana. As noted by the LDEQ, permits for this facility were
issued in August 2011, and, according to the Entergy website, these units are expected to come
online in mid-2015.78 A recent report from Entergy indicates that Ninemile 6 may come online
before the end of 2014. The new units will have a nameplate capacity of 640 MW and a
projected net summer capacity of 559 MW.
Also, a new NGCC is being constructed by Louisiana Energy and Power Authority
(“LEPA”) in Morgan City Louisiana (at the current Morgan City Power Plant location). This
new NGCC unit is expected to come online in late 2015 and will have a nameplate capacity of 84
MW and a net summer capacity of 64.5 MW.79 The impact of these omitted NGCC units totals
724 MW of nameplate capacity, or 624.5 MW of net summer capacity that should be added to
the EPA calculations for “Under Construction NGCC Capacity.”
78
See “Entergy Louisiana to Build State-of-the-art Generation Unit at Ninemile Point Plant.”
http://www.entergy.com/news_room/newsrelease.aspx?NR_ID=2178.
79
See “PA breaks ground on $120 million power plant.” Available at:
http://www.postsouth.com/article/20140425/News/140429706.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 37
Available at:
Conversely, in its Block 2A calculations, the EPA includes 655 MW of capacity for a
NGCC unit as being under-construction. This facility, however, has been technically listed as
being “under-construction” for an extended period of time, and is not likely to reach commercial
operation in the time period envisioned in the Proposed CPP. The Washington Parish Energy
Center was originally permitted by the LDEQ in June 2000, however, it was never completed
and to date, no longer has an active air permit. As a result, this EGU should be removed from
the Louisiana baseline calculation reducing the state’s existing NGCC capacity from 6,508 MW
to 5,853 MW.
The LPSC and LDEQ have also identified a number of other units that should not be
included in the EPA’s baseline NGCC calculations. First, the EPA’s calculations include 5 units
at Entergy Gulf States Louisiana’s Louisiana Station No. 1 as NGCCs. These units total 406
MW of nameplate capacity. As noted by LDEQ, three of these units are actually boilers and not
turbines and the relevant pages from the Permit for these units were included in the LDEQ’s
comments. In addition, Louisiana Station No. 1 is located adjacent to an ExxonMobil refinery
and chemical facility. The majority of power generated at Louisiana Station No. 1 is dedicated
to this facility and thus does not meet the requirement of an “affected electric generating unit.”80
Removing these facilities from the EPA’s calculations further reduces Louisiana’s total NGCC
nameplate capacity to 5,447 MW.
As also noted by the LDEQ, all 3 units at Entergy Louisiana’s Perryville Power Station
are classified by the EPA as NGCC units. However, one of these units (Unit 2-1) is actually a
simple cycle and should not be included as an NGCC. The removal of this Perryville unit
80
Publicly available data from the EIA’s Form 923 for 2012 show that Louisiana Station 1’s sales for resale were
just 27.3 percent of the facility’s total disposition.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 38
represents a further decrease of 186 MW in NGCC capacity, resulting in a total NGCC
nameplate capacity of 5,261 MW.
Table 2 uses the EPA’s spreadsheet to show the impact of these corrections and resulting
baseline emissions rate. The addition of 724 MW of Under Construction NGCC capacity, along
with the reduction of 1,248 MW of current NGCC capacity results in an increase of Louisiana’s
baseline emissions rate from 883 lbs/MWh to 981 lbs/MWh.
Coal
NGCC
O/G
Steam
(lb/MWh)
Step 2
(HRI)
Step 1 (2012 Data for Fossil Sources)
2012 Generation
Emissions Rate
Other
Emissions
Coal
(lbs)
NGCC
O/G Steam
Other
Under
Construction
NGCC
NGCC
Capacity Capacity
Adj. Coal
Rate
(MW)
(lbs/MWh)
(MWh)
Step 3a & 3b (Redispatch)
Resdispatched Generation
Coal
O/G Steam
(MWh)
Other
Emissions
Final Goal
(2030 and
Other Gen. thereafter)
(lbs/MWh)
(lbs)
(MWh)
40,018,850
3,267,065,650
5,223,728
883
6,456,931
6,727,786
6,984,289
6,707,787
6,662,950
8,257,755
40,862,114
40,129,528
38,873,943
39,105,753
38,433,689
35,991,386
5,636,440,288
3,578,046,071
3,267,065,650
2,353,497,076
1,681,085,998
3,267,065,650
8,315,696
5,629,549
5,223,728
3,699,551
2,577,715
5,223,728
866
881
891
898
910
944
7,953,968
33,302,164
3,671,015,973
4,551,327
981
EPA Proposal
Louisiana
2,323
766
1,581
3,267,065,650
24,300,393
19,771,182
14,254,748
5,223,728
6,508
-
2,184
11,538,767
6,768,706
Corrections
1. Add Ninemile 6
2. Add Morgan City 14-01
3. Remove Perryville 2-CT
4. Remove Louisiana St, 1A, 2A, 3A
5. Remove Louisiana St, 4A, 5A
6. Remove Washington Parish
2,323
2,323
2,323
2,323
2,323
2,323
766
766
763
786
803
766
1,581
1,581
1,581
1,581
1,581
1,581
3,267,065,650
3,267,065,650
3,267,065,650
2,353,497,076
1,681,085,998
3,267,065,650
24,300,393
24,300,393
24,300,393
24,300,393
24,300,393
24,300,393
19,771,182
19,771,182
19,209,368
18,693,317
17,899,980
19,771,182
14,254,748
14,254,748
14,254,748
14,254,748
14,254,748
14,254,748
5,223,728
5,223,728
5,223,728
3,699,551
2,577,715
5,223,728
6,508
6,508
6,322
6,360
6,251
5,853
640
84
-
2,184
2,184
2,184
2,184
2,184
2,184
11,007,278
11,469,009
11,906,277
11,434,918
11,358,482
14,077,182
2,323
830
1,581
767,517,423
24,300,393
16,260,301
14,254,748
1,053,538
5,261
724
2,184
13,559,310
Cumulative (Corrections 1 through 6)
NGCC
Table 2. Corrections to EPA’s Calculations for Louisiana NGCCs.
ii.
Incorrect use of capacity
The LPSC supports the LDEQ’s assertion that the capacity used to calculate NGCC
availability and resulting output should be based on a generating unit’s net summer dependable
capacity, not its nameplate capacity.
The EPA employed its Integrated Planning Model (“IPM”) to estimate the economic and
emissions implications of its proposed rule. As described in the GHG Abatement TSD the IPM
is:
a multi-regional, dynamic, deterministic linear programming model of the U.S.
electric power sector that the EPA has used for over two decades to evaluate the
economic and emission impacts of prospective environmental policies. IPM
provides a wide array of projections related to the electric power sector and its
related markets (including least cost capacity expansion and electricity dispatch
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 39
projections) while meeting fuel supply, transmission, dispatch, and reliability
constraints.81
It is clear that the EPA has used this IPM model extensively to conduct various analyses
of regulations and legislative proposals. The EPA believes that the “IPM represents a powerful
tool to evaluate the technical feasibility of requiring increasing levels of re-dispatch from higher
to lower-emitting EGUs.”82 The inputs to the IPM for existing and under construction EGUs
however, are based on data from the National Electric Energy Data System (“NEEDS”). This
database “contains the generation unit records used to construct the "model" plants that represent
existing and planned/committed units in EPA modeling applications of IPM.”83 And the NEEDS
database uses capacity values that reflect an EGU’s net summer capacity. This is explained in
the EPA’s documentation for IPM and NEEDS:
The NEEDS unit capacity values implemented in EPA Base Case v.5.13 reflect
net summer dependable capacity18, to the extent possible. Table 4-4 summarizes
the hierarchy of primary data sources used in compiling capacity data for NEEDS
v.5.13; in other words, data sources are evaluated in this order, and capacity
values are taken from a particular source only if the sources listed above it do not
provide adequate data for the unit in question.84
81
GHG Abatement TSD, 3-20.
GHG Abatement TSD, 3-21.
83
EPA’s Power Sector Modeling Platform v.5.13. Available at:
http://www.epa.gov/powersectormodeling/BaseCasev513.html#needs.
84
Id. See documentation for v.5.13, Chapter 4: Generating Resources.
82
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 40
If the EPA’s underlying model that instructs the development of its proposal relies upon
net summer capacity, why then does EPA’s proposal and calculations of target emission rates use
nameplate capacity? Table 3 includes the corrections made in Table 2, and also adjusts for the
change from nameplate capacity to net summer dependable capacity listed in the NEEDS
database. This correction results in a further increase to Louisiana’s baseline emissions rate, to
1,078 lbs/MWh.
Coal
NGCC
O/G
Steam
(lb/MWh)
Step 2
(HRI)
Step 1 (2012 Data for Fossil Sources)
2012 Generation
Emissions Rate
Other
Emissions
Coal
(lbs)
NGCC
O/G Steam
Other
Under
Construction
NGCC
NGCC
Capacity Capacity
Adj. Coal
Rate
(MW)
(lbs/MWh)
(MWh)
Step 3a & 3b (Redispatch)
Resdispatched Generation
Coal
O/G Steam
NGCC
(MWh)
Other
Emissions
Final Goal
(2030 and
Other Gen. thereafter)
(lbs/MWh)
(lbs)
(MWh)
40,018,850
3,267,065,650
5,223,728
883
6,456,931
6,727,786
6,984,289
6,707,787
6,662,950
8,257,755
40,862,114
40,129,528
38,873,943
39,105,753
38,433,689
35,991,386
5,636,440,288
3,578,046,071
3,267,065,650
2,353,497,076
1,681,085,998
3,267,065,650
8,315,696
5,629,549
5,223,728
3,699,551
2,577,715
5,223,728
866
881
891
898
910
944
13,559,310
7,953,968
33,302,164
3,671,015,973
4,551,327
981
2,184
20,267,815
11,889,215
26,169,293
3,267,065,650
5,223,728
1,092
2,184
17,537,203
10,287,423
26,990,816
3,267,975,083
4,065,791
1,078
EPA Proposal
Louisiana
2,323
766
1,581
3,267,065,650
24,300,393
19,771,182
14,254,748
5,223,728
6,508
-
2,184
11,538,767
6,768,706
Corrections
1. Add Ninemile 6
2. Add Morgan City 14-01
3. Remove Perryville 2-CT
4. Remove Louisiana St, 1A, 2A, 3A
5. Remove Louisiana St, 4A, 5A
6. Remove Washington Parish
2,323
2,323
2,323
2,323
2,323
2,323
766
766
763
786
803
766
1,581
1,581
1,581
1,581
1,581
1,581
3,267,065,650
3,267,065,650
3,267,065,650
2,353,497,076
1,681,085,998
3,267,065,650
24,300,393
24,300,393
24,300,393
24,300,393
24,300,393
24,300,393
19,771,182
19,771,182
19,209,368
18,693,317
17,899,980
19,771,182
14,254,748
14,254,748
14,254,748
14,254,748
14,254,748
14,254,748
5,223,728
5,223,728
5,223,728
3,699,551
2,577,715
5,223,728
6,508
6,508
6,322
6,360
6,251
5,853
640
84
-
2,184
2,184
2,184
2,184
2,184
2,184
11,007,278
11,469,009
11,906,277
11,434,918
11,358,482
14,077,182
Cumulative (Corrections 1 through 6)
2,323
830
1,581
767,517,423
24,300,393
16,260,301
14,254,748
1,053,538
5,261
724
2,184
7. Change NGCC Capacity
to Summer MW
2,323
766
1,581
3,267,065,650
24,300,393
19,771,182
14,254,748
5,223,728
4,256
-
Cumulative (Corrections 1 through 7)
2,323
830
1,581
767,517,423
24,300,393
16,260,301
14,254,748
1,053,538
4,256
624
Table 3. Corrections to EPA’s Calculations Adjusting for Net Summer Capacity.
iii.
The CPP fails to recognize the significant carbon
emissions reductions already made by Louisiana
through an increase in NGCC dispatch
The CPP also fails to recognize the significant strides Louisiana’s regulators have taken
over the past several years to maximize the use of new generation technologies and efficiencies
to reduce costs and emissions while also evaluating the impact these changes may have on rates.
Figure 7 for instance, shows that Louisiana’s natural gas heat rates have fallen 9.7 percent in the
last 10 years, at an average annual rate of one percent. Similarly, natural gas-fired emissions
have fallen 11.2 percent, at an average annual rate of 1.2 percent. This result was achieved
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 41
through considerable, concerted, and coordinated statewide regulatory actions that balance costs
12,000
1,400
11,500
1,350
11,000
1,300
10,500
1,250
10,000
1,200
9,500
2004
2005
2006
2007
2008
Natural Gas Heat Rate
2009
2010
2011
2012
2013
CO 2 Emissions (lbs/MWh)
Heat Rate (Btu/kWh)
and benefits to all Louisiana power market stakeholders.
1,150
Natural Gas Emissions
Figure 7. Recent Trends in Louisiana Gas-Fired Generation
Source: EPA Clean Air Markets database.
Figure 8 highlights the efficiency of Louisiana’s NGCC units. On average, Louisiana’s
NGCC units operate at heat rates that are 29 percent lower than Louisiana’s steam units and emit
30 percent less emissions.
[Space intentionally left blank.]
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 42
14,000
1,800
1,600
Heat Rate (Btu/kWh)
1,400
10,000
1,200
8,000
1,000
6,000
800
600
4,000
400
2,000
0
200
2004
2005
2006
NGCC Heat Rate
2007
2008
Steam Heat Rate
2009
2010
2011
NGCC Emissions
2012
2013
0
Steam Emissions
Figure 8. Louisiana NGCC Efficiency and Emissions
Source: EPA Clean Air Markets database.
iv.
The proposed rule does not appreciate the significance
of the required dispatch modification
The EPA’s estimated CO2 emissions reduction associated with Building Block 2 is the
largest share of proposed reductions (58 percent) of any building block included in the CPP’s
proposed BSER. The EPA estimates, if utilized for SIP purposes, would entirely reconfigure
Louisiana’s economic dispatch from one that currently relies on a modest level of baseload coal
generation, to one almost exclusively reliant upon natural gas generation. Figure 9 compares
Louisiana’s current generation fuel mix to the one likely to arise under the EPA’s proposed plan.
EPA’s analysis suggests that Louisiana should shift its current 31 percent reliance on natural gasfired generation to one that would be forced to rely on natural gas for 63 percent of its power
generation: a level that is more than double the national average for natural gas-fired generation
as forecast by the Energy Information Administration in its most recent Annual Energy Outlook
(“AEO”). This represents a considerable change in Louisiana’s power generation configuration
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 43
CO 2 Emissions (lbs/MWh)
12,000
that may very well lead to a significant increase in ratepayer costs as well as potential service
interruptions.
CPP Proposed
Generation Mix
2012 Generation Mix
Coal, 38%
NGCC, 31%
Coal, 18%
NGCC, 63%
Oil/Gas Steam, 23%
Other, 8%
Oil/Gas Steam, 11%
Other, 8%
Figure 9. Louisiana’s 2012 Generation Fuel Mix and EPA’s Proposed CPP Fuel Mix.
Source: EPA Technical Support Document, Goal Computation.
This change in fuel mix is highlighted by NERC in its reliability assessment. NERC
explains that:
the power industry relies upon diversification of fuel sources as a mechanism to
offset unforeseen events (e.g., abnormal weather, regional transfers, labor strikes,
unplanned outages); ensure reliability; and minimize cost impacts. Fuel
diversification is also a component of an “all-hazards” approach to system
planning, which inherently provides resilience to the BPS.”85
85
North American Electric Reliability Corporation. 2014. Potential reliability impacts of EPA’s Proposed Clean
Power Plan, p. 9.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 44
There is currently 60 GW of nameplate coal-fired capacity in the U.S. that is expected to
retire by 2020.86 This, plus the additional 49 GW estimated to retire as a result of the EPA’s
proposal87 means the U.S. electric power industry will need to compensate for over 100 GW of
retired coal-fired capacity. EPA’s proposal threatens to exacerbate this shift in the resource mix
further threatening fuel diversity.
Table 4 lists the NGCC units included in EPA’s CPP baseline calculations. Base year
(2012) generation is provided along with the estimated generation level arising from EPA’s
Building Block 2 analysis, and the percent increase this generation represents relative to base
year 2012 levels. A number of anomalies are apparent from this table. First, under the EPA’s
estimates, Louisiana Station No. 1 would actually need to ramp-down to meet the arbitrary 70
percent utilization level upon which EPA’s second building block is based. Thus, based upon
EPA’s own analysis, Louisiana should adopt policies that promote (or incent) one of its more
efficient CHP units to operate at a lower, rather than higher operating efficiency.
[Space intentionally left blank.]
86
The EIA AEO for 2014 estimates 60 GW of retirements by 2014. This assumes implementation of the MATS
standard as well as other existing laws and regulations. See “Planned coal-fired power plant retirements continue to
increase.” Available at: http://www.eia.gov/todayinenergy/detail.cfm?id=15491.
87
EPA Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and
Emission Standards for Modified and Reconstructed Power Plants, p. 3-32.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 45
Nameplate
Capacity
(MW)
Louisiana Station No. 1
Coughlin Power Station
Sterlington
Acadia Energy Center
Carville Energy LLC
Ouachita
Washington Parish Energy Center
Perryville Power Station
J Lamar Stall Unit
Total
EPA
2012
Estimated
Generation
Generation
------ (MWh) ------
Capacity Factor
EPA
Highest Highest
Assumed
in Last
in Last
Increase
10 Years 5 Years
(%)
406.3
922.8
226.3
1,376.0
570.0
903.9
655.0
824.1
624.0
2,949,067
1,434,842
4,610
4,785,503
2,899,630
1,658,025
2,486,523
3,552,982
2,498,257
5,674,113
1,391,473
8,460,749
3,504,816
5,557,900
4,027,464
5,067,226
3,836,851
-12.6%
52.3%
69.8%
30.4%
12.1%
49.1%
70.0%
35.7%
5.2%
99.5%
26.9%
15.6%
40.8%
62.6%
20.8%
0.0%
29.4%
43.0%
99.3%
26.3%
1.4%
40.8%
62.6%
20.8%
0.0%
29.4%
43.0%
6,508
19,771,182
40,018,850
34.7%
29.9%
28.0%
Table 4. Building Block 2, Louisiana NGCC Units
The final averages in last two columns reflecting maximum capacity factors in the last ten and five years do not
include Louisiana Station No. 1. Source: EPA Technical Support Document, Goal Computation.
What is more dramatic is the substantially increased utilization from the remaining units
that would be required under EPA’s proposed rule. The Coughlin Power Station will be required
to increase it generation utilization by 52 percent over 2012 levels, the Sterlington unit will be
required to increase its power generation utilization by close to 70 percent, and the Ouachita unit
would be required to increase its power generation utilization by close to 50 percent. These are
considerable increases that are simply unrealistic for the implementation time afforded by EPA
for CPP compliance.
The last two columns of Table 4 underscore the implausibility of EPA’s Building Block 2
calculations. These two columns present the highest generation utilization levels for each NGCC
unit over the past 10 years and 5 years, respectively. At no point over the past decade has any
CPP-eligible EGU reached a 70 percent utilization level. Only the Carville Energy LLC unit has
reached a level close (63 percent) to that assumed in EPA’s second building block. In fact, even
this utilization level is exceptional and has only arisen in the 2012 base year. Over the past 10
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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years, Carville has operated, on average around 50 percent and has operated at an average
utilization of 57 percent over the past five years.
On average, most Louisiana EGUs (excluding Louisiana Station No. 1) report 10 year
average generation utilization levels of 20 percent and five year average utilization levels of 32
percent: both of which are significantly lower than the EPA’s target of 70 percent.
v.
EPA modeling does not properly account
transmission-related constraints and costs.
for
The conclusions reached in the EPA’s Building Block 2 analysis suggests that Louisiana
could, and should, improve its generator efficiency performance, and that the IPM assumptions
and results simply reflect these efficiency opportunities.
These conclusions are naïve and
inconsonant with conclusions reached in prior LPSC investigations. The LPSC has spent a
considerable amount of time and resources over the past decade investigating the opportunities
for better utilizing NGCC generation that includes leveraging a considerable amount of CHPbased generation at many of the state’s large industrial facilities. The LPSC has consistently
reached the conclusion in most of these investigations that the costs of expanding newer NGCC
generation, and ramping down older, less efficient natural gas-fired steam generation, is costly.88
In theory, as the EPA correctly notes, the efficiency opportunities, and opportunities for
reduced emissions across a range of pollutants (not just CO2), through the increased utilization,
and “re-dispatch” of NGCC generation are considerable. Just as important to the Commission,
however, are the possibilities for lowering overall generation costs for Louisiana ratepayers by
utilizing more efficient and lower-cost natural gas based generation. The EPA should rest
assured that the LPSC, like many state utility regulators, is vigilant in assessing these types of
efficiency opportunities. The EPA can also rest assured that the LPSC’s past investigations were
88
LPSC Docket U-27136, Subdocket A,
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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based upon very detailed multi-area electric generation dispatch modeling with utility-specific
data and operational input that go well beyond any generalized model like the IPM used in the
development of the CPP.
However, the LPSC has determined through these analyses that in-state improvements
arising from increased NGCC utilization comes at a cost: billions in transmission-related and
other bulk-power sector investments. The EPA building block analyses simply fails to consider
the rather expansive and expensive transmission costs that will need to be incurred to
accommodate dispatching regional NGCC units to an average 70 percent utilization rate. The
Proposed Rule, as will be discussed in greater detail later in our comments, also fail to appreciate
the substantial time investment needed to facilitate the types of changes envisioned in EPA’s
BSER analysis.
vi.
Reliability
The CPP could very likely result in serious adverse reliability-related impacts.
Louisiana’s electric utilities, as well as several RTOs, have clearly indicated that future
compliance could hinge on the use of systematic curtailment of service through “brown-outs”
and rolling black-outs.
The EPA has not provided any information, nor conducted any
independent reliability analyses to contradict this assertion.
The SPP, for instance, recently express three primary concerns in comments filed before
the LPSC as well as the EPA.89 The SPP notes that the Proposed CPP will likely negatively
impact bulk power system reliability, has a challenged compliance timeline, and will have a
material impact on regional economic dispatch.90 The SPP conducted two different analyses:
89
See Comments of the Southwest Power Pool filed before the EPA on October 9, 2014 (hereafter “SPP
Comments”). These comments were also formally filed before the LPSC on October 14, 2014.
90
SPP Comments, p. 1.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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one on the impacts the Proposed CPP would have on transmission system reliability and a
second analysis on the impact of the Proposed CPP on regional reserve margins and generation
adequacy.
The SPP’s transmission system reliability analysis considered two potential bulk power
system scenarios that included: one where unused/underutilized (existing) generation is
dispatched to offset generation anticipated to be retired by the CPP; and a second that assumes
new generation will be developed, to supplement existing generation, to meet regional power
generation requirements (and offset generation retired due to CPP implementation). The SPP
transmission system reliability analysis found, under both scenarios, that the Proposed Rule
would result in “extreme reactive power deficiencies” that would expose the system, including
areas in northwestern Louisiana, to widespread reliability risks and violations of NERC
standards.
The SPP also conducted a generation adequacy analysis finding that the proposed CPP
would result in as much as 6,000 MWs of retirements: an amount that is some 200 percent above
current SPP unit retirement projections. The SPP notes that the Proposed CPP will have “serious
detrimental impacts on the reliable operation of the bulk power system” that will likely introduce
“the real possibility of rolling blackouts or cascading outages.” The SPP notes that it currently
utilizes a 13.6 percent minimum planning reserve margin and, based upon its estimates, the CPP
could drive actual reserve margins to 4.7 percent for the overall region, by 2020 and into a
negative level by 2024. Some localized areas are anticipated to see reserve margins fall to levels
even lower than the 4.7 percent. For instance, parts of northwest Louisiana are estimated to see
their reserve margins fall to -10.0 percent by 2020 and by -25.0 percent by 2024. These potential
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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resource adequacy outcomes are simply unacceptable from the LPSC’s perspective and represent
a very important and fundamental flaw in the CPP proposal.
Further, while Louisiana has considerable natural gas infrastructure, it is not clear that
many other places of the country do, and the power sector ramifications of this gas infrastructure
inadequacy can ripple backwards into Louisiana through power and/or gas service interruptions,
cascading brown-outs, power and gas commodity price spikes, as well as a variety of other
unanticipated market and policy outcomes.
vii.
The CPP’s proposed compliance timeline is
unreasonable and likely to lead to unnecessary costs.
The short time frame for compliance with this rule creates a number of resource planning
uncertainties for utilities and the LPSC. As noted earlier, the LPSC has solicited information
from its utilities and other stakeholders, through a written comment process and is not likely to
understand the full impact that the Proposed CPP will have on its regulated utilities given the
continued uncertainties associated with this new regulation.
Most utilities, to date, have
indicated that a number of difficult decisions will have to be made, and are currently being
investigated, should the CPP continue along its currently-proposed framework.
Major electric reliability organizations such as the regional reliability coordinating
councils (MISO, SPP, as well as NERC), and reliability regulators, like the FERC, are also in the
process of evaluating the CPP’s potential impacts. To date, these analyses are ongoing and
preliminary. Most important is the fact that all Louisiana regulated investor-owned utilities have
advised the LPSC that they will have difficulty complying with the rule and that it will likely
result in considerable cost increases to their respective ratepayers.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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The EPA proposes interim reductions of 38 percent by 2020 with the total 42 percent
reduction to occur by 2030. Thus, 90 percent of the overall proposed reductions for Louisiana
are expected to occur by the interim goals period. It will be difficult to meet such requirements
within the given time period given the national scope of this rule, and the near-term transmission
constraints noted earlier. While the EPA hails the Proposed Rule’s “flexibility,” the LPSC finds
the proposals anything but flexible, representing a return to the command-and-control regulation
of the 1970s.
The currently proposed CPP timeline envisions a final rule being developed by June
2015. States will be given 12 months to develop initial State Implementation Plans (“SIPs”)
(June 30, 2016) and 24 months for final SIPs (June 30, 2017). States developing a regional
response are given until June 30, 2018. Thus, states are likely to have approved SIPs in place
sometime in the 2017-2018 time period. Interim reductions, however, begin in 2020: some two
to three years after compliance plans are approved. This is simply not enough time given the
Rule’s potential compliance requirements.
For instance, it takes at least 3 years to plan, permit, and develop a new NGCC unit,
assuming no development congestion and a relatively normal business-as-usual development
environment that will likely not be the case given the broad, far-reaching national nature of the
proposed CPP.
It takes, on average, some 8 years to plan, permit, and develop a new
transmission project. New generation and transmission will likely be necessary to maintain
resource adequacy requirements if Building Block 2 is chosen as a compliance option using
EPA’s estimates.
Louisiana will also be required to increase its renewable power generation by 103 percent
by 2020 to meet the CPP’s proposed interim emissions reduction goals. This is equivalent to a
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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495 MW increase in renewable generation capacity that will have to be developed in a post-SIP
approved 24 to 36 month compliance window. Consider that it has taken some states, such as
New Jersey, Maryland, and Colorado, at least 5 to 6 years to increase their in-state renewable
generation shares to six percent of total generation.
Likewise, Louisiana will be required to increase its commitments to energy efficiency
from 0 to 1.14 percent in 2020 and 9.33 percent in 2030. Between 2020 and 2030 represents an
increase of 720 percent. This new requirement is comparable to 1.4 GW of avoided generation
capacity that, again, will have to be developed within a two to three year period: a time period
far more escalated that the time it took EPA’ best practices states to reach what EPA believes to
be an optimal level of energy efficiency adoption.
What this all adds up to is offering Louisiana, and other states, a choice between three
bad state implementation options. First, Louisiana can choose speed over cost-effectiveness by
adopting a set of poorly-examined emissions reductions strategies included in EPA’s deficient
building block analysis in order to meet the unnecessarily expedited interim goals deadline.
Second, Louisiana, by adopting EPA’s proposed building blocks on an expedited basis, can run
the risk of compromising system reliability since the ability of the bulk power system to
accommodate these EPA strategies, as discussed earlier, is questionable. Third, Louisiana can
try to develop a more cost-effective set of strategies, on a more reasonable pace, and run the risk
of paying considerable penalties and potential fines for non-compliance. The LPSC finds all of
these potential outcomes (or any combination of them) simply unreasonable and inconsistent
with its charge to provide safe, economic and reliability electricity service to Louisiana
ratepayers.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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The comments offered by MISO support the LPSC’s conclusions that EPA’s expedited
time frame will be expensive and could very well challenge system reliability. In in comments
before the LPSC, MISO noted that the compliance timeline included in the proposed rule
significantly challenges its ability to sustain adequate reserve margins91. MISO also noted that
CPP compliance costs would be “non-trivial” and heavily dependent on timing factors. MISO
developed a number of compliance cost estimates, for instance, and found that regional
approaches would save MISO states, collectively around $3 billion in implementation costs over
a state level approach.92 MISO also noted that the expedited timing of the CPP would likely
discourage regional-based solutions, thereby leaving these opportunities for reducing overall
compliance costs on the table.93
viii.
PA did not account for the potential rate impacts of the
CPP.
While the EPA calculates costs associated with its proposal based on the cost of
compliance, it does not consider the upgrades in transmission required for the increase in NGCC
dispatch. Nor does the EPA consider the potential for significant stranded costs associated with
the reduced production, or premature retirement of Louisiana’s existing oil and gas-fired steam
EGUs.94 For Louisiana, the EPA’s target for reduced oil/gas steam generation is about 48
percent of the reported 2012 oil/gas steam generation (from 14.3 million MWh in 2012 to a
target of 6.8 million MWh).
Table 5 presents the cost estimate for new and upgraded transmission investments and
associated stranded costs. Transmission related costs are simply illustrative and are based upon
91
LPSC Docket R-33253.
Id.
93
Id.
94
The investment of an EGU is recovered through depreciation expense over the life of the plant. Stranded costs are
the undepreciated value of a facility that ceases to be “used and useful”.
92
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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the additional of several new transmission projects at a typical per-project costs of around $500
million.
The midrange estimate for new transmission is $1.0 billion.
The stranded costs
associated increased NGCC dispatch and decreased oil/gas steam generation (i.e. stranded
facilities costs) results in a potential mid-range estimate of $986.4 million. When these costs are
added to the costs calculated for Building Block 1, the total potential costs eligible for recovery
from Louisiana ratepayers increases to almost $3.5 billion.
Preliminary Cost Estimates
Low
Mid
High
Range
Range
Range
Cost
Cost
Cost
------ ($ Millions, NPV) ------
Building Block
Strategy
Building Block 1
Increase Coal Plant Thermal Efficiency
Coal plant capital investment costs:
Stranded coal plant capital cost:
Building Block 2
$
$
425.5
842.6
$
$
638.3
842.6
$
$
851.0
842.6
$
$
500.0
986.4
$ 1,000.0
$
986.4
$ 1,500.0
$
986.4
$ 2,754.5
$ 3,467.3
$ 4,180.0
Increase Natural Gas Generation Capacity Factor
New transmission capital investments:
Stranded oil/gas steam plant capital cost:
Building Block 3a At Risk Nuclear Generation
Building Block 3b Increased Renewable Generation
Increased capital cost margin:
Utility lost revenue recovery:
Building Block 4
Increased Energy Efficency
Increased energy efficiency program expenditures:
Utility lost revenue recovery:
Total Louisiana Cost Impact:
Table 5. Estimated Cost of Building Block 2
Note: Coal plant capital investment costs are assumed to be $100/kW (low); $150/kW (mid); and $200/kW (high)
for all Louisiana coal units.
Stranded cost estimates are only included for utility-owned units with publicly available data.
Typical transmission investment resulting from increased NGCC dispatch assumed to be $500 million: low estimate
assumes one project; mid-range estimate assumes two projects; high assumes three projects.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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D. Building Block 3(a) is Flawed
The EPA uses its Building Block 3(a) to include a factor for “preserved” nuclear
generation that might otherwise be retired. The EPA identifies a number of factors that could put
nuclear EGU’s at risk: facility age; increased fixed O&M costs; low wholesale electricity prices;
and additional capital investment associated with ensuring plant security and emergency
preparedness.95 Using an estimate published in the EIA’s Annual Energy Outlook for 2014, the
EPA assumes that six percent of each state’s nuclear generating capacity is “at-risk.”96
Louisiana has two nuclear facilities in operation with a combined capacity of 2,134 MW (net
summer capacity).97 EPA included 985 GWh of generation from these facilities in its target
emission rate calculation for Louisiana.98
a. EPA’s allowance for “at risk” nuclear capacity
effectively subsidizes unprofitable generation
The EPA’s proposal effectively penalizes states with operable nuclear facilities by adding
nuclear generation to the denominator of its equation thereby lowering a state’s emission rate.
The EPA’s proposed formula is basically a ratio of carbon emissions-to-generation. Thus adding
to the equation a zero-carbon emissions generation value increases the denominator while
holding the numerator constant. The result is a reduced target emission rate, requiring greater
carbon emission reductions. Penalizing a state for zero-carbon generation seems contradictory to
the EPA’s goals. The rule should be designed to reward a state for utilizing zero-carbon emitting
generation, not penalize it.
95
EPA Technical Support Document: GHG Abatement Measures, 4-33.
EPA Technical Support Document: GHG Abatement Measures, 4-33.
97
U.S Department of Energy, Energy Information Administration, Annual Electric Generator Data, 2012. Available
at: http://www.eia.gov/electricity/data/eia860/.
98
This assumes 5.86 percent of capacity at a 90 percent capacity factor.
96
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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This issue is highlighted by NERC in its reliability assessment:
“The nuclear retirement assumptions add pressure to states that will need to retire
nuclear units. For these states, more CO2 reductions from other measures than
originally estimated by the EPA may be required.”99
Because neither of Louisiana’s existing nuclear facilities are “at-risk” an no new nuclear
is under construction, this component should not be included in the denominator of the
equation.100
b. The basis for EPA’s “at risk” nuclear capacity estimates
is weak and not well supported
The EPA based its assumption of “at-risk” nuclear capacity on an estimate published in
the EIA’s Annual Energy Outlook for 2014. The EIA however, does not provide any detailed
calculations, nor does it identify specific plants, timeline or rationale for this estimate other than
“continued economic challenges.”101 The simply states:
Additionally, the AEO2014 nuclear projection assumes a decrease of 5.7 GW by
2020 in several regions where existing nuclear units appear at risk of early closure
due to a combination of high operating costs and low electricity prices. 102
The Entergy Companies also noted this in comments filed with the LPSC on the proposed
rule:
While the Companies do not know which units the EIA had in mind, the
Companies do not consider any of their nuclear units in Louisiana to be
99
North American Electric Reliability Corporation. 2014. Potential reliability impacts of EPA’s Proposed Clean
Power Plan, p. 8
100
Pg. 6, Joint Comments of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, L.L.C., LPSC Docket R33253.
101
Jones, J. and M. Leff. 2014. Implications of accelerated power plant retirements. Energy Information
Administration, U.S. Department of Energy. April 2014.
102
Energy Information Administration, U.S. Department of Energy. 2014. Annual Energy Outlook, Electric Market
Module. Available at: http://www.eia.gov/forecasts/aeo/.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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vulnerable to the type of economically-forced closure described by the EPA in
this proposed rule.103
The EPA also notes the lack of specific retirement assumptions, but yet determines that
the 5.7 GW retirement projection “is a reasonable proxy” and applies it to all states with nuclear
generation regardless of region or fleet characteristics (e.g., age of facility, historic capacity
factor, economic dispatch, regulatory environment).
c. EPA’s “at risk” nuclear proposals are ambiguous on
how nuclear generation will be treated for compliance
purposes
The EPA’s “at-risk” nuclear component is not a compliance requirement and no specific
monitoring or verification is required. This portion of the EPA’s BSER seems only to serve as a
method for reducing a state’s target emission rate. It is unclear how actual net generation values
will be accounted. For example, if the two units in Louisiana operate below a 90 percent
capacity factor in one year (as a result of refueling or outage), it is unclear if Louisiana would
still be able to claim “credit” for the entire 985 GWh used in calculating the state goal, or if some
adjustment would be applied.
d. At-Risk nuclear is not anticipated to impose additional
costs upon Louisiana ratepayers at the current time.
The nuclear component of EPA’s proposed rule is not expected to impose a cost to
Louisiana ratepayers. If the EPA allows a state to use the same 6 percent of nuclear generation
for compliance of the target emissions rate, and nuclear generation remains constant, then it
should impose no cost. This could change, however, over time, if the costs associated with
operating nuclear power exceed wholesale market rates.
At that time, Louisiana could be
compelled to assume an “above-market” cost in order to remain compliant with CPP provisions.
103
Joint Comments of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, L.L.C. p. 6, LPSC Docket R33253.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Preliminary Cost Estimates
Low
Mid
High
Range
Range
Range
Cost
Cost
Cost
------ ($ Millions, NPV) ------
Building Block
Strategy
Building Block 1
Increase Coal Plant Thermal Efficiency
Coal plant capital investment costs:
Stranded coal plant capital cost:
Building Block 2
$
$
425.5
842.6
$
$
638.3
842.6
$
$
851.0
842.6
$
$
500.0
986.4
$
$
1,000.0
986.4
$
$
1,500.0
986.4
$
-
$
-
$
-
Increase Natural Gas Generation Capacity Factor
New transmission capital investments:
Stranded oil/gas steam plant capital cost:
Building Block 3a At Risk Nuclear Generation
Building Block 3b Increased Renewable Generation
Increased capital cost margin:
Utility lost revenue recovery:
Building Block 4
Increased Energy Efficency
Increased energy efficiency program expenditures:
Utility lost revenue recovery:
Total Louisiana Cost Impact:
$ 2,754.5
Table 6. Estimated Cost of Building Block 3a
$ 3,467.3
$ 4,180.0
Note: Coal plant capital investment costs are assumed to be $100/kW (low); $150/kW (mid); and $200/kW (high)
for all Louisiana coal units.
Stranded cost estimates are only included for utility-owned units with publicly available data.
Typical transmission investment resulting from increased NGCC dispatch assumed to be $500 million: low estimate
assumes one project; mid-range estimate assumes two projects; high assumes three projects.
Nuclear assumed to have no additional cost.
[Space intentionally left blank.]
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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E. Building Block 3(b) is Flawed
i.
Based on erroneous method of averaging.
Section 4.2 of EPA’s GHG Abatement Measures TSD details how annual renewable
energy (“RE”) generation goals are calculated. First, the EPA starts with a regional approach, by
assigning each state to 1 of 6 regions.104 An RE generation target is calculated for each region
based on an average of the 2020 RPS requirements for states within that region. Then, a regional
annual growth factor is developed to allow the region as a whole to reach the regional RE target
by 2029. This annual growth factor is applied to each state’s reported 2012 non-hydro RE
generation for the years 2017 through 2029.
For Louisiana, the EPA methodology results in a 2020 non-hydro RE generation target of
3.3 million MWh for Louisiana, which is a 38 percent increase over Louisiana’s 2012 non-hydro
RE generation. This target increases to 6.9 million MWh by 2030, which is 184 percent greater
than Louisiana’s 2012 non-hydro RE generation.
[Space intentionally left blank.]
104
Alaska and Hawaii are assigned to their own separate regions.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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8
7
Million MWh
6
5
4
3
2
1
0
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
Figure 10 EPA Estimated Louisiana Non-Hydro RE Generation Targets
Source: EPA Technical Support Document: GHG Abatement Measures, Data File: Proposed Renewable Energy
(RE) Approach (XLS).
The regional growth factors calculated by EPA are defined by the assignment of states to
a region and the states’ mandates regarding RE generation. For the South Central region, to
which Louisiana is assigned, EPA calculated an average annual growth factor of 8.35 percent.
This percentage is applied to Louisiana even though non-hydro RE generation in Louisiana has
actually been falling over the past decade.
The LPSC is concerned about the EPA’s non-hydro RE targets for Louisiana since RE
resources are some of the most expensive to deploy, and will have a considerable impact on the
cost of complying with the proposed rule.
While considerable strides have been made in
reducing costs and increasing efficiencies of RE technologies, the costs of RE technologies are
still considered “above market” by most measures as seen in Figure 11.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Conventional
Conventional Coal
$96
IGCC
$116
Natural Gas CC
$66
Natural Gas Advanced CC
$64
Natural Gas CT
$128
Natural Gas Advanced CT
$104
Advanced Nuclear
$96
Renewable
Geothermal
$48
Biomass
$103
Wind
$80
Offshore Wind
$204
Solar PV
$130
Solar Thermal
$243
0
50
100
150
200
250
Levelized Cost of Electricity ($/MWh)
Figure 11 Comparison of Fossil Fuel and Renewable Energy Resource Costs ($/kW)
Source: Energy Information Administration, U.S. Department of Energy. 105
The EPA’s method for estimating RE targets is unreasonable in general and unrealistic as
it applies specifically to Louisiana. First, the use of a regional average is highly subjective and
assumes that the states in a region are similar in terms of their specific policies and incentives
regarding RE development. It also assumes that all states included in a region are comparable in
terms of their technical potential for RE generation. This is clearly not the case for Louisiana
and the region in which it was assigned.
Applying an RE generation target to Louisiana that is derived from other states’ RPS
policies is unreasonable since it suggests a capability and public interest finding consistent with
adopting similar RE goals. As will be discussed later, the LPSC has twice examined the merits
of adopting an RPS in Louisiana. The EPA’s average regional approach effectively sweeps
105
The cost provided here is for traditional geothermal applications. This differs from the geo-pressure/geothermal
applications that may have limited applicability in Louisiana and would have a significantly higher cost.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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under the rug over 10 years of Louisiana-specific analysis in favor of its own generalized
approach. The LPSC believes this is highly unreasonable and inconsistent with the basic tenets
of the CAA.
The use of a regional average determined by the policies of other states is also
inconsistent with traditional utility resource planning practices in Louisiana that seek to acquire
supply and demand side resource on a least-cost basis. There is no way an approach that
averages projected RE generation additions over a geographic region that spans from the plains
of Nebraska to the Gulf of Mexico can be consistent with these least cost resource procurement
practices.
ii.
EPA’s RE target calculations for Louisiana are in error.
State RPS polices have been developed and deployed by individual states based the
state’s own assessment of its ability to implement a reasonable, achievable and cost-effective
renewable requirement.
The EPA’s GHG Abatement TSD explains that it relied on these
individual state RPS requirements to develop the regional RE targets. 106 The EPA also notes that
it “did not include targets that were capacity-based.”107,108 The EPA’s method calculates an RE
generation target for each region based on an average of the 2020 RPS requirements for each
state in that region. An annual growth factor is then applied to each state within a region so that
the region as a whole will reach the regional target by 2029.
The EPA assigns Louisiana to what it refers to as the South Central region. Figure 12
highlights the states included in the South Central region, which also includes Arkansas, Kansas,
106
GHG Abatement TSD, p. 4-9, fn 108.
GHG Abatement TSD, p. 4-9, fn 108.
108
While most state RPS requirements are based on a percentage of total electric generation or retail sales, there are
some that are capacity based.
107
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Nebraska, Oklahoma and Texas.109 Only 2 of the 6 states in the South Central region have
implemented a mandatory RPS.110 And, both of those RPS goals are based upon total capacity
rather than a share of retail sales (or generation).111 The RPS in Kansas requires each investorowned utility and electric cooperative to generate or purchase 20 percent of its peak demand
from renewable resources for each year beginning in 2020. This is the sole basis for the EPA’s
South Central target of 20 percent by 2020.112
Texas also has a mandatory RPS.
Like Kansas, the Texas Renewable Generation
Requirement is not based on percentages, but rather a fixed capacity amount that is irrespective
of statewide generation or capacity totals.113 Texas has a fixed RE capacity requirement of 5,800
MW by 2015, and a voluntary target of 10,000 MW by 2025.
[Space intentionally left blank.]
109
The U.S. Department of Energy’s Energy Information Administration uses a somewhat different regional
definition. The EIA’s Southwest region includes Arkansas, Louisiana, New Mexico, Oklahoma and Texas. So, the
EIA Southwest region includes New Mexico, but does not include Kansas and Nebraska. The U.S. Census Bureau
also has its own definition, defining the West South Central as Arkansas, Louisiana, Oklahoma and Texas (no
Kansas or Nebraska).
110
Oklahoma has a voluntary Renewable Energy Goal for its electric utilities that calls for 15 percent of total
installed capacity to be derived from renewable sources by 2015. Available at:
http://webserver1.lsb.state.ok.us/2009-10bills/HB/hb3028_enr.rtf.
111
See Kansas Corporation Commission, Kansas Renewable Energy Standard, at: http://kcc.ks.gov/energy/res.htm;
and Public Utility Commission of Texas, Goal for Renewable Energy at:
http://www.puc.state.tx.us/agency/rulesnlaws/subrules/electric/25.173/25.173.pdf.
112
EPA Technical Support Document: GHG Abatement Measures, Data File: Proposed Renewable Energy (RE)
Approach (XLS).
113
Public Utility Commission of Texas, Goal for Renewable Energy at:
http://www.puc.state.tx.us/agency/rulesnlaws/subrules/electric/25.173/25.173.pdf.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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KS: 20% of
capacity by
2020
TX: 5,800 MW
by 2015
Figure 13 South Central Region States
Source: EPA GHG Abatement Measures TSD, p. 4-14.
The EPA does not consider that the other states in the South Central region have chosen
not to implement an RPS. Nor does the EPA identify how a 20 percent capacity standard
translates to a comparable generation (MWh) standard. Correcting for these errors substantially
changes the estimated EPA target for Louisiana RE generation as shown in Figure 14. For
instance, converting the Kansas RPS standard from a capacity based target to a generation based
target, results in a reduction of the target RE generation for Louisiana by an average of 14
percent.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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8
7
Million MWh
6
5
4
3
2
1
0
2017
2018
2019
2020
2021
2022
2023
EPA Target RE Generation
2024
2025
2026
2027
2028
2029
Corrected RE Target Generation
Figure 14 Corrected RE Target Generation for Louisiana.
Note: Assumes a 38 percent capacity factor for Kansas renewable generation.
Source: Kansas Corporation Commission, 2014 Report on Electric Supply and Demand; and Energy Information
Administration, U.S. Department of Energy.
NERC addresses this issue in its reliance review:
The EPA method of assigning renewable regions is questionable. Of the six
renewable regions created in the lower 48 states, targets for two regions (South
Central and Southeast) were set based upon a single-state RPS. For example, the
South Central state region (AR, KS, LA, NE, OK and TX) was set based upon
only the Kansas RPS. Kansas accounts for only 6 percent of this region’s retail
power sales and has the third-best wind resources in the country. Given the
combination of a low population, large land area, and very high wind resource
availability, Kansas has relatively low costs to meet its RPS. However, Louisiana
(ranked #48 in wind resources and double the retail sales) is assigned the same
non-hydro renewable target. To put these two states in the same region sets
unattainable targets for Louisiana.114
It should also be noted that the EPA fails to consider the consumer protection
components of many state RPS mandates. The EPA assumes that because other states in the
region have set renewable energy goals to a certain level, that these goals are directly applicable
114
North American Electric Reliability Corporation. 2014. Potential reliability impacts of EPA’s Proposed Clean
Power Plan, p. 12.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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to the surrounding states. However, many states have carefully crafted rate caps and other
protection mechanisms to safeguard ratepayers against large increases in their bills.
For
instance, in Kansas the Renewable Energy Standard has a one percent cap on the rate impact of
compliance. The Kansas Corporation Commission may exempt any utility that can demonstrate
that compliance with the RPS would cause retail rates to increase by one percent or more. Other
states with rate impact or revenue requirement caps include: Colorado, Delaware, Illinois,
Maryland, Michigan, Missouri, New Mexico, North Carolina Ohio, Oregon and Washington.115
In its reliability review, NERC highlights a number of other issues with the EPA’s
reliance on state RPS standards:116
A. States RPS qualifications vary and may or may not include hydroelectric generation,
municipal solid waste (MSW), combined heat and power (CHP), clean coal, carbon
capture and sequestration, and energy efficiency measures. Using New York as an
example, NERC points out that the state’s hydroelectric generation accounts for 18.25
percent of total generation and is included as a baseline renewable for RPS purposes.
This is different from what the EPA assumes in its methodology.
B. Energy efficiency also plays differing roles in state RPS standards. For instance, the
RPS in North Carolina allows up to 25 percent of the target to be met by energy
efficiency gains. NERC explains that if this had been excluded from the EPA’s
calculations, the targets for all of the states in the Southeast region would decrease.
C. EPA did not consider multipliers given to certain resources. For example, Nevada
gives 2.4 credits for every one kWh of energy produced by solar photovoltaics.
115
Database of State Incentives for Renewables and Efficiency, U.S. Department of Energy. Available at:
http://www.dsireusa.org/summarytables/rrpre.cfm.
116
North American Electric Reliability Corporation. 2014. Potential reliability impacts of EPA’s Proposed Clean
Power Plan, pgs. 12-13.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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NERC identifies six states that have multipliers. Excluding these suggests a target
that is higher than actual.
D. The determination of state goals does not fully reflect the economic aspects and
resource limitations due to “permitting, market saturation, transmission access, and
project financing issues.” For instance, wind projects may have difficulty getting
necessary permits and may be objected to at the local level. And, many high-grade
wind sites are located in remote areas that would require large capital investments to
move the energy to consuming areas.
E. The EPA also neglected to consider the expiration or reduction of federal tax credits
in upcoming years and the impact that will have on investment decisions. Those
uncertainties “will directly impact the electric industry’s plan to quickly adapt to the
CPP requirements.
iii.
EPA lumps Louisiana into a region that has nothing to
do with this RE capabilities.
EPA’s regional approach imposes the same target percentage to all states in a given
region regardless of their RE technical capabilities. The regional definition for EPA’s South
Central region is dominated by states that have considerable opportunities for onshore wind
development and are already some of the larger wind developers in the country. Table 7
highlights each of these South Central States, their 2012 wind generation capacity and their share
of total U.S. wind generation capacity.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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State
Capacity
(MW)
Percent
of Total
(% )
Texas
California
Iowa
Illinois
Oregon
Oklahoma
Minnesota
Washington
Kansas
Colorado
North Dakota
New York
Indiana
Wyoming
Pennsylvania
Idaho
Michigan
South Dakota
New Mexico
Montana
12,178.9
5,506.3
5,005.0
3,520.1
3,151.9
3,132.9
2,842.3
2,806.2
2,719.1
2,271.1
1,759.2
1,636.4
1,539.7
1,407.3
1,343.9
962.7
874.8
790.5
777.5
627.8
20.6%
9.3%
8.5%
6.0%
5.3%
5.3%
4.8%
4.8%
4.6%
3.8%
3.0%
2.8%
2.6%
2.4%
2.3%
1.6%
1.5%
1.3%
1.3%
1.1%
State
West Virginia
Ohio
Missouri
Nebraska
Maine
Wisconsin
Utah
Arizona
Hawaii
New Hampshire
Nevada
Vermont
Maryland
Massachusetts
Alaska
Tennessee
New Jersey
Delaware
Rhode Island
Capacity
(MW)
Percent
of Total
(% )
583.3
461.7
458.5
455.4
427.6
369.6
324.4
237.3
205.6
171.0
150.0
120.2
120.0
63.8
32.7
29.1
7.5
2.0
1.5
1.0%
0.8%
0.8%
0.8%
0.7%
0.6%
0.5%
0.4%
0.3%
0.3%
0.3%
0.2%
0.2%
0.1%
0.1%
0.0%
0.0%
0.0%
0.0%
Table 7 South Central States Wind Capacity and Relative Share of Total U.S. Wind
Capacity (2012)
Source: Energy Information Administration, U.S. Department of Energy.
As highlighted in the table, four of the South Central states account for over 30 percent of
total U.S. wind generating capacity. What is also important about Table 7 is that Louisiana is not
included in the table. As will be discussed in greater detail later, Louisiana does not have, and
very likely never will have, any wind generation. Louisiana simply does not have the technical
capabilities for any meaningful grid-scale wind generation. Thus, placing Louisiana in a set of
states with such tremendous wind development opportunities is unreasonable for at least two
reasons.
First, wind energy tends to be the lower cost of all commercially-available RE
technologies. Figure 15 shows the total system levelized costs of commercially-available RE
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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technologies.
At an average of $80/MWh, onshore wind can currently be developed and
installed for 22 percent less than the next closest (non-hydro) RE option which is biomass. If
Louisiana were to attempt to develop wind energy, it is likely that the resource would be need to
be developed offshore rather than onshore, requiring Louisiana to pay a 154 percent RE
development premium relative to other states with abundant wind resources.
Average Levelized Cost (2012 $/MWh)
300
$243
250
$204
200
150
100
$130
$103
$85
$80
50
0
Wind
Biomass
Solar PV
Offshore Wind
Solar Thermal
Hydro
Figure 15 RE Generation Levelized Costs ($/MWh)
Source: Energy Information Administration, U.S. Department of Energy. 117
Wind energy is not only one of the lower cost RE resources, but is also one of the few RE
resources that can be considered grid-scaled, bringing a meaningful level of capacity that could
be used to displace fossil-fueled generation. Table 8 shows the average installation size for
active 2012 RE projects across the U.S.
117
Biomass estimates are based on the overnight capital cost of biomass and do not include potential transportation
costs that would be incurred.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Capacity
(MW)
Agricuture Crop Byproducts
Black Liquor
Geothermal
Landfill Gas
Municipal Solid Waste
Biomass Gases
1
Biomass Liquids
2
3
Biomass Solids
Solar (Photovoltaic, Thermal)
Tires
Wood Waste Liquids
Wood Waste Solids
Wind
4
5
Number of
Installations
Average
Capacity
(MW)
351
4,029
2,592
1,895
2,203
22
163
197
1,501
96
16.0
24.7
13.2
1.3
22.9
207
143
1.5
115
2
57.4
40
3,170
26
2
553
1
20.0
5.7
26.0
89
5
17.8
3,390
59,075
183
947
18.5
62.4
Table 8. Average RE Installation Size (kW)
Note: 1Biomass Gases include digester gas, methane, and other biomass gases; 2Biomass Liquids include fish oil,
liquid acetonitrile waste, medical waste, tall oil, ethanol, waste alcohol, and other Biomass Liquids not specified;
3
Biomass Solids include animal manure and waste, solid byproducts, and other solid biomass not specified; 4Wood
Waste Liquids include red liquor, sludge wood, spent sulfite liquor, and other wood related liquids not specified; and
5
Wood Waste Solids include paper pellets, railroad ties, utility poles, wood chips, and other wood solids.
Source: Energy Information Administration, U.S. Department of Energy.
Wind projects have an average nameplate capacity of 62 MW relative to the next best
alternative, which is biomass liquids at 57 MW. After that, all other renewable installations have
an average capacity of 26 MW percent or less. There is no way Louisiana can cost-effectively
scale a set of RE projects that are comparable to the size of the wind facilities located in Texas or
the Midwest, and even if possible, they would likely be located in such remote (offshore) areas
requiring additional, and likely cost-prohibitive, interconnection and integration investments.
iv.
The paucity of RE resources in Louisiana is wellrecognized.
As part of its Alternative RE Approach the EPA compared each state’s existing RE
generation to an estimate of its RE technical potential. To do so, EPA used measurements of
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 70
technical potential estimated by the National Renewable Energy Laboratory (“NREL”).118 The
EPA’s Alternative RE Approach TSD states that “[t]he comparison of RE technical potential to
existing RE net generation yields – for each state and for each selected RE technology – a
proportion of achieved renewable generation from technical potential.”119
However, the Alternative RE Approach shows that Louisiana has very little RE technical
capabilities. In fact, the EPA’s estimate of “State-Level Target Generation Levels Under the
Alternative RE Approach” for Louisiana is actually 607 GWh less than Louisiana’s reported
2012 RE generation.120
The EPA sets a target that suggests considerable RE growth for
Louisiana (184 percent), while the EPA’s own alternative analysis shows that this is almost
impossible.
The NREL document EPA relied upon includes a number of tables reflecting each state’s
RE technical potential.
Each of these charts, with the exception of biomass, shows that
Louisiana is technically challenged in the area of RE development. For instance, Figure 16
provides a summary map using NREL’s measurements of technical potential for onshore wind
by state: the darker the color, the greater the achievable energy generation from wind. The map
shows that the Upper Plains region, the Midwest and Texas have considerable wind resources. A
state or region’s wind resource (defined in part by its average annual wind speeds) should be an
important input into any RE target or goal. The estimated technical potential for Louisiana is at
the lowest end of the spectrum. Yet, it has been lumped into a region with considerable wind
energy resources and technical potential.
118
See Lopez, et al., NREL, “U.S. Renewable Energy Technical Potentials: A GIS-Based Analysis,” July, 2012.
Alternative RE Approach Technical Support Document, p. 1.
120
Table 1.1 in the EPA’s Alternative RE Approach Technical Support Document shows a RE Target Generation
value of 2,503 GWh, while Louisiana’s 2012 RE Generation is 3,110 GWh.
119
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Thousand GWh
< 50
50 – 100
100 – 500
500 – 1,000
> 1,000
Figure 16. NREL Estimated Technical Potential for Onshore Wind Power by State
Source: National Renewable Energy Laboratory, U.S. Department of Energy.
Likewise, a state’s solar exposure provides considerable inference into its ability to
support solar energy investments. Figure 17 shows that Louisiana is not well endowed with solar
energy resources, particularly relative to other South Central states. While solar can be installed
in areas with lower solar exposure, the effectiveness is significantly reduced, thereby raising the
cost of using this resource as a carbon emissions mitigation strategy.
[Space intentionally left blank.]
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Thousand GWh
< 10
10 – 50
50 – 75
75 – 100
> 100
Figure 17. NREL Estimated Technical Potential for Urban Utility-Scale Photovoltaics by
State
Source: National Renewable Energy Laboratory, U.S. Department of Energy.
v.
The use of biomass is ambiguous and raises additional
unaddressed concerns.
Louisiana does not have a significant potential for large wind and solar installations,
however, it does have some biomass opportunities. Figure 18 presents a comparable map
reflecting NREL’s measurements of technical potential for biomass.
The map shows that
Louisiana has potential for biomass, but is still second to states with greater potential like
California, Texas, Illinois, Iowa and Nebraska.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Thousand GWh
<1
1–5
5 – 10
10 – 15
> 15
Figure 18. NREL Estimated Technical Potential for Biopower by State
Source: National Renewable Energy Laboratory, U.S. Department of Energy.
Most of Louisiana’s current and likely future biomass capabilities are restricted to a few
agricultural sectors that include:
(1) forestry harvesting and paper processing, (2) rice
production, and (3) sugar production. Louisiana could, in theory, use some of this biomass
capability to meet EPA’s target RE goals but the ability to do so is entirely dependent upon
EPA’s willingness to accept and support extensive biomass development. Figure 19 for instance,
estimates the biomass capacity requirements that would be needed to meet EPA’s annual RE
generation targets assuming that the current biomass composition is increased proportionately.
Louisiana’s 2012 non-hydro RE generation translates to an implied capacity value of 334
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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MW.121 Using EPA’s proposed non-hydro RE generation targets, Louisiana would have to add
614 MW of biomass capacity to reach an implied target of 948 MW by 2030.
1,000
900
800
Capacity (MW)
700
600
500
400
300
200
100
0
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Agricultural Byproduct
Wood/Waste Wood
Black Liquor
2012 Implied Capacity
Figure 19. Estimated Louisiana Biomass Capacity Under Proposed EPA RE Targets
Note: Assumes an 83 percent capacity factor to convert target generation (MWh) to capacity
(MW).
EPA’s proposed rule may allow for increased use of biomass to meet the non-hydro RE
generation targets. However, while burning biomass may be technically renewable, it is not
necessarily clean. In fact, the EPA’s own data shows that solid biomass fuels such as wood
waste and agricultural byproducts can emit as much, if not more CO2 than coal, and significantly
higher quantities of NOx.122 And, in July 2013, the U.S. Court of Appeals vacated the EPA’s
“biogenic carbon deferral” in which the EPA had exempted CO2 emissions from biomass plants
121
This assumes a capacity factor of 83 percent.
See “Emission Factors for Greenhouse Gas Inventories,” Available at:
http://www.epa.gov/climateleaders/documents/emission-factors.pdf.
122
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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for purposes of CAA permitting for a period of 3 years pending further study.123 Thus it is
unclear how increased biomass generation will be subjected to, or impacted by other EPA rules
such as the Cross State Air Pollution Rule (“CSAPR”).
Large scale biomass generation applications, particularly more economical co-firing
applications, could lead to a number of environmental compliance issues not addressed in EPA’s
Proposed Rule. For instance, larger biomass co-firing applications designed to displace existing
fossil generation will likely be grid connected and as such, will likely be CSAPR-eligible. While
Louisiana has a number of biomass co-firing applications today, these biomass generators are not
CSAPR-eligible since the power generated is used almost exclusively on-site. Future gridconnected biomass applications would put a considerable amount of pressure on Louisiana in
meeting its already stringent CSAPR NOX emission requirements. Further, emissions associated
with the transportation of biomass could negate emissions reductions and increase costs.
vi.
EPA fails to appreciate the age of Louisiana’s existing
RE generation fleet.
Figure 20 compares the 2012 base level of non-hydro RE generation for Louisiana
against the annual target amounts included in the EPA TSDs. The line running across the chart
shows the current 2012 baseline level, whereas the bars show the total levels of RE generation
that arise through the use of EPA’s regional average growth factors. The difference between the
line and the bars is the growth needed to reach the annual targets.
123
Center for Biological Diversity v. EPA, 749 F.3d 1079 (D.C. Cir. 2014).
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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8
7
Million MWh
6
5
4
3
2
1
0
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Target
Baseline
Figure 20. EPA Projections of Louisiana Baseline and RE Generation Targets
Source: EPA Technical Support Document: GHG Abatement Measures, Data File: Proposed Renewable Energy
(RE) Approach (XLS).
What is potentially lost in the analysis included in Figure 20 is that the baseline level of
current Louisiana RE generation is almost exclusively associated with biomass co-firing
applications. And, most of these biomass were developed in the late 1970s and early 1980s as a
means of reducing on-site agricultural processing costs through on-site generations. In fact, prior
to 2005, Louisiana’s share non-hydro RE generation as a percent of total was higher than that of
the U.S. average. However, Louisiana’s non-hydro RE generating fleet has aged over time. Few
upgrades have been made to this fleet since the 1970s making the RE generation baseline upon
which EPA assumes Louisiana will be able to build is faulty: Louisiana, in fact, will be lucky to
just maintain its exiting share of RE generation over the next several years, much less add to it at
levels envisioned by the EPA.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Company Name
Over 40 Years Old
KPAQ Industries LLC
Boise Packaging & Newsprint LLC
Over 30 Years Old
Temple-Inland Corp
Temple-Inland Corp
IPC-Mansfield Mill
IPC-Mansfield Mill
IPC-Mansfield Mill
M A Patout & Sons Ltd
M A Patout & Sons Ltd
Agrilectric Power Partners Ltd
Over 20 Years Old
Georgia-Pacific - Port Hudson
Under 20 Years Old
Temple-Inland Corp
Red River Mill Intl Paper Company
Capacity
(MW)
Percent
of Total
Capacity
(% )
48
45
12.5
61.5
2.8%
13.8%
Black Liquor
Wood/Waste Wood
1979
1981
1981
1981
1981
1981
1981
1984
35
33
33
33
33
33
33
30
37.5
25.0
40.0
40.0
30.0
1.0
2.0
12.1
8.4%
5.6%
9.0%
9.0%
6.7%
0.2%
0.4%
2.7%
Wood/Waste Wood
Wood/Waste Wood
Black Liquor
Black Liquor
Black Liquor
Agricultural Byproduct
Agricultural Byproduct
Agricultural Byproduct
GEN1
1986
28
67.7
15.2%
Black Liquor
NO10
3 T-G
1999
2008
15
6
37.0
78.8
8.3%
17.7%
Wood/Waste Wood
Black Liquor
445.1
100.0%
Generator Id
Online
Date
Facility
Age
(years)
GEN2
TG
1966
1969
NO9
NO8
GEN1
GEN2
GEN3
1000
2000
GEN1
Total
Fuel
Table 9. Louisiana 2012 RE Generation by Age Category
Source: Energy Information Administration, U.S. Department of Energy.
Table 9 provides a list of operable RE generating units in Louisiana by age category. The
majority of Louisiana’s operable non-hydro RE capacity is over 30 years old (almost 60 percent),
and over 16 percent is more than 40 years old. Just 26 percent, or one-quarter of the operable
non-hydro RE capacity in Louisiana is less than 20 years old.
Not only does EPA fail to consider the age of Louisiana’s non-hydro RE fleet, but it also
fails to conduct any analysis of the economic viability of this type of generation. The majority of
generation produced by Louisiana’s biomass fleet comes from the burning of black liquor, a
byproduct of pulp and paper mills. In fact, over 60 percent of Louisiana’s biomass capacity is
fueled by black liquor. Another 36 percent is wood and waste wood and less than four percent
comes from agricultural byproduct (such as bagasse from sugar cane production and rice hulls).
Continued generation at these types biomass facilities is not a function of an RPS, but rather the
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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economic viability of these industries. Moreover, as with other limited resources, increased
generation will increase costs of the commodity in manufacturing and other processes. For this
reason, the LPSC limited the use of biomass in its RE pilot program. 124
Even if Louisiana adopted an RPS, it is highly unlikely that these existing non-hydro RE
generation facilities would see “new life” through re-powering or other marginal investments
given their age, and the nature of the industries to which they are tied. For instance, the paper
mill industry across the U.S. has been in steady decline. And, the sugar and rice industries are
facing challenges to remain competitive in a global market.125
Louisiana will be challenged to maintain its existing share of RE generation, relative to
total, much less growing this generation by a 184 percent as suggested in the EPA RE targets.
Any RE target developed for Louisiana needs to factor these unique agricultural sector factors, as
well as the age of the existing base of RE generation in the state. EPA proposed RE targets,
however, do neither.
vii.
EPA’s recommendations are inconsistent with prior
LPSC findings.
The LPSC takes an active regulatory role in the oversight of its utilities’ resource
planning decisions. Louisiana was one of the early adopters of the use of competitive bidding
rules and requirements to take advantage of environmentally-friendly, and highly efficient
natural gas-fired combined cycle generation in the early part of the last decade. Louisiana was
124
LPSC General Order dated December 9, 2010 (Docket R-28271 Subdocket B).
The sugar industry in the U.S. faces increasing competition as the Mexican-subsidized industry has been
exporting increasing amounts of low-priced sugar into U.S. markets. In recent years Mexico’s surpluses have
caused U.S. sugar prices to fall to unsustainably low levels. See: American Sugar Alliance, “U.S. Sugar Producers
File Antidumping, Subsidy Cases Against Mexico”, March 28, 2014. Available at: http://www.sugaralliance.org/us-sugar-producers-file-antidumping-subsidy-cases-against-mexico-4732/.
Also, the U.S. rice industry faces
increased competition from alternative crops and the supply of farmland in rice growing regions is diminishing.
See: Rice farming.com, Hybrid-Rice Update. Available at: http://www.ricefarming.com/home/issues/201312/Hybrid-Rice-Update.html.
125
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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also one of a few states to adopt cost-recovery rules and guidelines in creating a stable regulatory
environment and reduce the risks of zero-emissions nuclear power. Similarly, this Commission
has also examined, in significant detail, the opportunities for Louisiana RE generation: not once,
but on two separate occasions.
First, in October 2004, the LPSC published a notice of a proceeding to examine the
feasibility of renewable energy development and the various policy merits of adopting an RPS.126
This initiative examined how RE generation would fit into Louisiana utility resource plans and
was designed to assess cost-effective RE potential and public interest in adopting RPS policies.
The proceeding continued for over two years and included numerous intervernors and
stakeholder groups.127
The LPSC solicited a wide range of Louisiana-specific RE generation and technological
information during the course of its first RE proceeding. While the LPSC Staff and independent
consultants conducted their own analysis of RE potential, utilities and other stakeholders were
encouraged to submit their data and analysis on the costs and benefits of RE development. A
wide range of information was analyzed including: the technological status of various RE
technologies; the efficiencies of these technologies; trends in current and emerging RE
technologies; and the costs of employing these technologies.
Most importantly, the LPSC
examined in detail the Louisiana-specific costs and rate impacts associated with various RE
technology development scenarios.
This investigation was a comprehensive “bottoms-up”
analysis, not a highly generalized “top-down” analysis like the one upon which the EPA’s
proposed RE generation targets is based.
126
127
LPSC Docket R-28271.
Id.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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The Commission issued an Order in its first comprehensive RE investigation in January
2007 finding that the “availability of acceptable renewable resources, the willingness of
customers to enroll and the relationship between the participation levels and pricing” were
uncertain and it declined to adopt and RPS.128 It was also noted that while Louisiana has the
potential for “developing renewable resources such as biomass, landfill gas and offshore wind, it
does not have the same opportunities as some other states for building on-shore wind,
geothermal, hydro and solar generation resources.”129
The LPSC re-opened its RE proceeding in January 2009 to again evaluate the feasibility
of an RPS for Louisiana. This second investigation was conducted in response to a new focus on
renewable standards at the Federal level and the increasing adoption of RPS policies in other
states.130
Similar to the first proceeding, this second investigation included an exhaustive
examination of the potential for RE in Louisiana. The LPSC considered the interests of 50
intervenors, held multiple technical conferences and meetings and solicited several rounds of
comments. The LPSC concluded that additional analysis was needed to provide “Louisianaspecific, actual cost data and enable a long-term decision tailored to meet Louisiana’s needs.”131
It was determined that there that a Renewable Energy Pilot Program (“REPP”) would be the best
solution for the State of Louisiana. The pilot would:
meet the Commission’s objective of developing real cost data to assist the
Commission in making a decision with regard to a long-term ROS and at the same
time provide developers with an incentive to market their resources to Louisiana
utilities and take advantage of federal and state subsidies that may expire in the
near term.132
128
Id.
Id.
130
Notice of Final Task Force Report and Strawman Policy Proposal dated February 5, 2010, LPSC Docket R28271 Subdocket B.
131
LPSC Staff’s Final Recommendation dated June 15, 2010, Docket R-28271 Subdocket B.
132
Id.
129
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An implementation plan for a 3-year pilot program was subsequently developed and
adopted. Over the course of the pilot, LA utilities acquired approximately 80 MW of RE133.
Nearly 400 additional MWs were acquired later and alleged to have been available because of
the pilot program.134 Unfortunately, all except approximately 40 MW of the acquired RE is sited
outside of Louisiana. In August 2013, the LPSC Staff presented its final annual report on the
REPP. The LPSC Staff concluded that the investor-owned electric utilities had complied with
the requirements of the REPP and that the REPP enabled the LPSC and its Staff to “evaluate the
availability, costs, and potential benefits of renewable generation resources for Louisiana.” 135 In
addition, the utilities provided significant analysis and data on the potential for RE development
in Louisiana. It was concluded that:
the Commission's REPP was a valuable learning experience for the Commission,
Staff, and participating utilities. Staff also concluded that based on the
information filed by the utilities, as well as Staffs participation throughout the
process, a mandatory RPS is not warranted at this time. The data provided by
the utilities indicated that the levelized cost of renewable technologies exceeds the
costs of conventional resources. For example, the levelized cost of a combined
cycle gas turbine is below the cost of any of the major renewable technologies.
Current prices for natural gas have put renewable technologies at a cost
disadvantage. Finally, interest at the federal level for a mandatory renewable
energy policy currently appears to be limited.136
viii.
EPA fails to appropriately account for the full costs and
rate impacts of its RE proposals.
The EPA failed to appropriately account for the rate impacts associated with the RE
portion of its proposed rule. The costs of increased renewable energy go beyond the cost of RE
technologies and must include lost revenues incurred by Louisiana’s utilities. Table 10 provides
an estimate of the potential cost of the EPA’s proposal to Louisiana ratepayers.
133
LPSC Dockets U-32785, U-32557, U-32981.
LPSC Docket U-32814.
135
LPSC General Order dated September 20, 2013 (Docket R-28271 Subdocket B).
136
Id. (emphasis added)
134
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 82
Preliminary Cost Estimates
Low
Mid
High
Range
Range
Range
Cost
Cost
Cost
------ ($ Millions, NPV) ------
Building Block
Strategy
Building Block 1
Increase Coal Plant Thermal Efficiency
Coal plant capital investment costs:
Stranded coal plant capital cost:
Building Block 2
$
$
425.5
842.6
$
$
638.3
842.6
$
$
851.0
842.6
$
$
500.0
986.4
$
$
1,000.0
986.4
$
$
1,500.0
986.4
$
-
$
-
$
-
$
$
388.8
248.8
$
$
432.0
276.4
$
$
475.3
304.0
Increase Natural Gas Generation Capacity Factor
New transmission capital investments:
Stranded oil/gas steam plant capital cost:
Building Block 3a At Risk Nuclear Generation
Building Block 3b Increased Renewable Generation
Increased capital cost margin:
Utility lost revenue recovery:
Building Block 4
Increased Energy Efficency
Increased energy efficiency program expenditures:
Utility lost revenue recovery:
Total Louisiana Cost Impact:
$ 3,392.1
$ 4,175.7
$ 4,959.3
Table 10. Estimated Cost of Building Block 3b
Note: Coal plant capital investment costs are assumed to be $100/kW (low); $150/kW (mid); and $200/kW (high)
for all Louisiana coal units.
Stranded cost estimates are only included for utility-owned units with publicly available data.
Typical transmission investment resulting from increased NGCC dispatch assumed to be $500 million: low estimate
assumes one project; mid-range estimate assumes two projects; high assumes three projects.
Nuclear assumed to have no additional cost.
Renewable energy assumes generation portfolio of 75 percent biomass; 15 percent wind and 10 percent solar. This
results in a levelized cost differential of $37.60/MWh (when compared to a new NGCC).
Lost base revenues estimated at $24.05 per MWh for both renewable energy and energy efficiency.
Assumes 10.915 percent discount rate (based on typical utility allowed rate of return).
Assuming a cost differential of $37.60/MWh, the increased capital cost of the EPA’s RE
targets are estimated to be $432.0 million (mid-range). This, coupled with likely lost revenues of
$276.4 million will result in an increased cost of $708.4 for Building Block 3b. This brings the
potential costs associated with Building Blocks 1, 2 and 3 to almost $4.2 billion (mid-range
estimate).
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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F. Building Block 4 is Flawed
i.
Building Block 4 is based on inappropriate method of
determining technical potentials.
Chapter 5 of the EPA’s GHG Abatement Measures TSD provides information regarding
the EPA’s determination of appropriate levels of demand-side EE as a component abatement
measure within its BSER.137 Section 5.3 details the EPA’s development of annual EE goals.138
The EPA first determined what it refers to as a “best practices” scenario for each state, which
was used to estimate the potential for states to implement policies that increase investment in
what the EPA believes are cost-effective demand-side energy efficiency technologies and
practices. The EPA created this scenario using a level of EE performance demonstrated or
required by policies in leading states, while considering each state’s existing level of EE
performance and allowing “appropriate time” for states to increase from current EE levels of
performance to the identified best practices level.139
The EPA determined that all states should be able to reach an annual incremental EE of
1.5 percent of annual retail sales. Furthermore, EPA has determined a best practices rate of
improvement of 0.2 percent of annual retail sales starting in 2017.140 Since within EPA’s data
Louisiana had no reported savings from EE in 2012,141 the EPA’s proposed methodology would
require Louisiana to continually increase incremental annual EE saving from 2017 through 2025,
and furthermore continue this level of annual savings through 2030.
The LPSC is concerned that EPA’s proposed methodology may be inappropriate for
individual states, including Louisiana. EPA’s proposed methodology by definition applies a
137
EPA Technical Support Document: GHG Abatement Measures, pp. 5-1 to 5-77.
EPA Technical Support Document: GHG Abatement Measures, pp. 5-30 to 5-59.
139
EPA Technical Support Document: GHG Abatement Measures, p. 5-33.
140
EPA Technical Support Document: GHG Abatement Measures, p. 5-33.
141
EPA Technical Support Document: GHG Abatement Measures, p. 5-17.
138
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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national goal for EE potential to all states, regardless of “on-the-ground” realities. Within
Louisiana, the Entergy Companies (Entergy Louisiana and Entergy Gulf States) serve
approximately 63 percent of all Louisiana retail electric customers, and is by far the largest
electric utility in the State.142 Entergy included in its 2012 IRP a Demand-Side Management
(“DSM”) potential study for its Louisiana operating companies.143 This study, conducted by ICF
International for Entergy, evaluated EE potential for years 2013 through 2028 across three
scenarios: Low, Reference, and High.
Entergy DSM Potential
EPA
Low
Reference
High
Proposed
Year
Case
Case
Case
Target
2020
2.56%
4.31%
5.95%
1.14%
2021
2.94%
4.96%
6.85%
1.85%
2022
3.31%
5.59%
7.73%
2.71%
2023
3.63%
6.13%
8.49%
3.69%
2024
3.88%
6.56%
9.10%
4.78%
2025
4.08%
6.88%
9.55%
5.88%
2026
4.21%
7.09%
9.86%
6.88%
2027
4.30%
7.24%
10.09%
7.78%
2028
4.37%
7.35%
10.25%
8.60%
2029
4.43%
7.44%
10.39%
9.33%
Table 11. Entergy 2012 IRP DSM Potential Study: Cumulative Savings as Percentage of
Total Projected Sales.
Source: In re: The United States Environmental Protection Agency’s proposed rule on carbon
dioxide emissions from existing fossil-fuel fired electric generating units under Section 111(d) of
the Clean Air Act. Louisiana Public Service Commission, Docket No. R-33253, Joint comments
of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC in response to the
Commission Staff’s notice of request for specific comments.
142
See, http://www.entergy-louisiana.com/about_entergy/default.aspx; Entergy Louisiana and Entergy Gulf States
Louisiana server approximately 1.07 million electric customers in Louisiana.
See also,
http://quickfacts.census.gov/qfd/states/22000.html; the U.S. Census Bureau estimates there are slightly less than
1.70 million households in Louisiana.
143
Strategic Resource Plan: An Integrated Resource Plan for the Entergy Utility System and the Entergy Operating
Companies 2009-2028 (August 21, 2009), LPSC Docket No. R-30021.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 85
Table 11 above shows the cumulative EE savings expressed as a percentage reduction of
annual energy sales determined by the Entergy DSM potential study, as well as the target levels
for cumulative EE savings included in EPA’s proposed rule. Entergy’s DSM potential study
shows that while EPA’s near-term EE savings targets are arguably conservative, the EPA’s
proposed methodology overstates the ultimate potential for EE savings within Louisiana in all
but the most optimistic scenarios. Only under the study’s high scenario did Entergy’s 2012 study
find EE potential sufficient to meet EPA’s proposed EE goal for Louisiana. Entergy recently
released a new long-term DSM potential study supporting its current IRP analysis. This study’s
findings are lower than Entergy’s earlier study, now finding that Entergy only has the technical
potential to achieve 6.1 percent cumulative energy savings under the reference scenario
compared to estimated sales by 2034. Even under the high scenario, it finds the utility only has
the technical potential to achieve 9.6 percent cumulative energy savings by 2034, just slightly
greater than EPA’s proposed target for 2030.144
Louisiana major electric and natural gas utilities are in the early stages of implementing
EE programs pursuant to the LPSC EE rules finalized August 21, 2013.145 This situation
explains the finding of cumulative EE savings greater than EPA’s near-term cumulative EE
savings targets. However, it is clear that Entergy’s DSM potential study examining only EE
potential in Louisiana does not support the EPA’s proposal of a 1.5 percent annual savings target
relative to annual retail sales as an appropriate target for EE in Louisiana.
144
Long-Term Demand Side Management Potential in the Entergy Louisiana and Entergy Gulf States Louisiana
Service Areas (November 3, 2014), LPSC Docket No. I-33014, p. iv.
145
LPSC Docket R-31106.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 86
ii.
EPA fails to examine cost-effectiveness.
As mentioned previously, the EPA created its “best practice” scenario by examining the
level of EE performance demonstrated or required by policies in leading states. EPA’s proposed
methodology by definition applies a national goal for EE potential to all states, and nowhere in
its analysis did the EPA examine or recognize important differences between individual states.
This leads to many mitigating factors omitted from the EPA’s analysis the LPSC believes needs
to be considered. First among these is the large variance in electric rates themselves throughout
the country.
Greater than 15¢ per kWh
12.5¢ -- 15¢ per kWh
10.5¢ -- 12.5¢ per kWh
Less than 10.5¢ per kWh
Figure 21. Average Retail Price of Electric to Residential Customers (August 2014)
Source: Energy Information Administration, U.S. Department of Energy
Figure 21 presents the average residential electric price per kWh by state for August
2014.
Even ignoring Alaska and Hawaii, which due to geographic remoteness see higher
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 87
electricity prices than the contiguous US, electric rates vary considerably throughout the country.
The most expensive state, Connecticut, reported electric prices in August 2014 equal to 19.67
cents per kWh, while the least expenses state, Washington, had electric prices less than half this
amount at only 8.93 cents per kWh.146 This regional variation is due to many factors, but
regional resource availability accounts for a significant portion. For instance, electric prices in
the Pacific Northwest have historically been less than the rest of the country due to the
abundance of local hydropower. Likewise, New England has historically seen higher electric
prices due to the need to import fuel stocks a significant distance. Louisiana is located within a
prolific natural gas producing region, and thus has the third lowest residential electric rates in the
country, behind only Washington and West Virginia.147
Rarely, if ever, has EE been viewed as a goal in-and-of-itself, but as a means to meet
multiple policy objectives, such as reducing the escalation of energy prices through reduction of
consumption or demand. Thus, consideration of the cost-effectiveness of potential EE programs
has always been central to examination of the appropriate level of EE investment. The EPA’s
GHG Abatement Measures TSD restates this role of EE,148 and further acknowledges that
“(m)ost states evaluate their EE policy options through the application of cost tests, weighing the
projected benefits with the costs of energy efficiency technologies and practices.” 149 EPA’s
decision of a national “best practices” standard however does not recognize the costeffectiveness of potential levels of EE investments. Put simply, it is cost-effective to have higher
levels of EE investment in states with high energy costs due to the benefits of displacing these
146
Electric Power Monthly: Table 5.6.A. Average Retail Price of Electric to Ultimate Customers by End-Use Sector
(October 27, 2014), U.S. Energy Information Administration.
147
Electric Power Monthly: Table 5.6.A. Average Retail Price of Electric to Ultimate Customers by End-Use Sector
(October 27, 2014), U.S. Energy Information Administration.
148
EPA Technical Support Document: GHG Abatement Measures, pp. 5-24 to 5-26.
149
EPA Technical Support Document: GHG Abatement Measures, p. 5-25.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 88
costs. However, these levels of EE investment may not be appropriate in low energy costs states,
such as Louisiana, since the benefits of avoiding energy costs are much lower.
Indeed, the EPA’s discussion of states which have either achieved or have policies
requiring EPA’s chosen “best practices” levels of percent incremental annual savings
demonstrate the relationship between EE and high retail electric prices.150 Of the twelve states
that have either achieved or are required to achieve an incremental savings through EE of 1.5
percent per year, eight states are among the top 20 states in terms of residential retail electric
prices. Likewise, of the 20 states that have either achieved or are required to achieve an
incremental savings through EE of 1.0 percent per year, six (CT, NY, RI, CA, VT, MA)
comprise the 6 states in the continental U.S. with the most expensive residential retail electric
rates. Fourteen of these states are among the top 20 states in terms of residential retail electric
prices.151
iii.
Fails to recognize that prior technical potentials arose in
high-cost energy environment
In addition to the EPA’s omission of accounting for the cost-effectiveness of EE, and the
inherent differing economics seen throughout the country, EPA also fails to recognize structural
changes occurring in energy markets in the past few years. In most states, natural gas-fueled
power plants operate as the “marginal” unit in most hours throughout the year (i.e. natural gas
fueled power plants are the most expensive per kWh unit typically dispatched to serve
customers). Therefore, the costs to operate these natural gas fueled-plants typically set the
overall wholesale electricity rate before transmission and local distribution costs to end
150
EPA Technical Support Document: GHG Abatement Measures, p. 5-33.
EPA Technical Support Document: GHG Abatement Measures, p. 5-33; and Electric Power Monthly: Table
5.6.A. Average Retail Price of Electric to Ultimate Customers by End-Use Sector (October 27, 2014), U.S. Energy
Information Administration.
151
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 89
consumers. It follows that this operating cost would follow natural gas prices, as has been noted
by many market analysts.
Figure 22 presents historic and projected natural gas production in the U.S. as projected
in the EIA’s most recent Annual Energy Outlook.152
From 1990 through the late 2000’s,
domestic production of natural gas was essentially flat, remaining under 20 Tcf per year.
However, the emergence of shale gas extracted through hydraulic fracturing significantly
increased domestic production, more than displacing declining production in traditional onshore
and offshore production. In 2014, natural gas from shale deposits is estimated to account for
nearly 40 percent of all natural gas produced. By 2030, the production of natural gas from shale
deposits is estimated to increase to account for over 49 percent of all domestic production.
Likewise, total production of natural gas is expected to increase by nearly 42 percent. Whereas
historically the natural gas market represented a market that was supply constrained, forecasts
now show production to keep pace with all projected growth in consumption.
[Space intentionally left blank.]
152
Annual Energy Outlook 2014: Figure MT-44. U.S. Natural Gas Production by Source in the Reference Case,
1900-2040 (May 7, 2014), U.S. Energy Information Administration.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 90
40
Historic
Projected
35
Trillion Cubic Feet
30
25
20
15
10
5
0
1990
1995
2000
2005
2010
Alaska
Lower 48 offshore
Tight gas
2015
2020
2025
2030
2035
2040
Coalbed methane
Lower 48 onshore conventional
Shale Gas
Figure 22. Natural Gas Production by Source
Source: Energy Information Administration, U.S. Department of Energy
This new reality is highlighted in a review of wholesale natural gas prices as shown in
Figure 23. From 1997 through 2000, wholesale natural gas prices averaged just $2.79 per Mcf,
and were relatively stable, as shown by a relatively low standard deviation. This changed
dramatically in late-2000 through 2008, when natural gas prices increased sharply, averaging
$6.24 per Mcf through the period. Wholesale natural gas prices were also much more volatile
than seen previously, with a standard deviation of $2.39. With the emergence of large-scale
hydraulic fracking in 2009, wholesale natural gas prices have dropped just as dynamically,
averaging $3.86 per Mcf. Likewise, volatility in natural gas markets has also fallen, being even
more stable than prices were in the late 1990s.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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average for period
2000-2001 heating season
through 2008: $6.24
$20
$18
(standard deviation: $2.39)
$16
$14
$/Mcf
$12
average 1997
through 2000: $2.79
(standard deviation: $1.28)
since 2009: $3.86
(standard deviation: $0.84)
$10
$8
$6
$4
$2
$0
Jan-97
Jan-99
Jan-01
Jan-03
Jan-05
Jan-07
Jan-09
Jan-11
Jan-13
Figure 23. Historic Daily Henry Hub Spot Prices
Source: Energy Information Administration, U.S. Department of Energy
Figure 24 shows the effect that changing natural gas markets have had on forecasts of
future natural gas prices. In its 2009 AEO the EIA projected that wholesale natural gas prices
would increase from then current levels in real terms to a high of $9.91 per MMBtu by 2030.
With the significant change in natural gas markets, the EIA has revised these estimates in
subsequent AEO publications. In the 2013 AEO, the EIA projected that wholesale natural gas
prices would only reach $5.29 per MMBtu in real terms by 2030, a nearly 47 percent reduction
from 2009 estimates.
[Space intentionally left blank.]
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Figure 24. Historic and Projected Henry Hub Spot Prices from EIA AEO
Source: Energy Information Administration, U.S. Department of Energy
The adoption of energy efficiency resource standards (“EERS”) by various states mirrors
this changing outlook on the future prices of energy. Of the 26 states that have adopted EERS,
only 3 states (Arkansas, Oregon, and Wisconsin) have adopted such measures since 2010.153
Indeed, 15 states adopted EERS in the years 2007 through 2009, when projections of future
natural gas prices were at their highest.154 Since 2011, not a single state has adopted an energy
efficiency resource standard.155
LPSC is concerned with the EPA’s proposed methodology of relying on “best practices”
in general, as laid out previously. However, the LPSC is also concerned with the EPA’s reliance
on requirements of individual states’ EERS to inform what a national “best practice” amount of
incremental savings through EE would be. The majority of these EERS were passed during a
153
EPA Technical Support Document: GHG Abatement Measures, p. 5-15.
EPA Technical Support Document: GHG Abatement Measures, p. 5-15.
155
EPA Technical Support Document: GHG Abatement Measures, p. 5-15.
154
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 93
period when the consensus view was rapidly raising natural gas and electricity costs. Since the
cost-effectiveness of a proposed energy efficiency program is estimated over the useful life of
the program, this pessimistic outlook resulted in higher benefits for proposed energy efficiency
investments than would have been estimated if natural gas prices were assumed to be stable, as it
is now viewed. By its very nature, the EPA’s proposed methodology overstates the potential for
cost-effective energy efficiency nation-wide and then it overstates the potential statewide by
using a one-size-fits-all approach.
iv.
Fails to consider rate impacts and lost utility base
revenues
Pages 5-27 through 5-29 of the EPA’s GHG Abatement Measures TSD discuss
comparative cost statistics of EE resources to alternative electricity resource options utilizing a
levelized cost of energy (“LCOE”) or levelized cost of saved energy (“LCSE”) in the case of
EE.156 Within this analysis, the EPA finds that a review of studies examining only utility costs
find an average LCSE in the range of 1 to 6 cents per kWh. The EPA further references a recent
review conducted by the American Council for an Energy Efficient Economy (“ACEEE”) which
examined studies across 20 states performed between 2009 and 2012 which found the LCSE for
electric energy efficiency programs in the range of 1.3 to 5.6 cents per kWh, with a mean value
of 2.8 cents per kWh.157
However, examining cost-effectiveness of EE resources by only
examining utility costs is fundamentally flawed.
Unlike traditional supply resources, use of demand-side resources affects a utility’s
financial position by reducing the utility’s earnings through a reduction in sales. A non-trivial
portion of a typical electric utility’s costs arise from fixed costs not directly related to the
156
157
EPA Technical Support Document: GHG Abatement Measures, pp. 5-27 to 5-29.
EPA Technical Support Document: GHG Abatement Measures, p. 5-27.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 94
production of electricity, but to the generation, transmission, and distribution infrastructure
required to efficiently produce and transport electricity to end-use customers. These fixed costs
therefore will not be reduced by increased efficiency of end-use customers, and will still have to
be recovered through other means without negatively affecting a utility’s financials. This is
sometimes referred to as the lost contributions to fixed costs, lost revenue recovery or lost
margin recovery, and has been discussed exhaustively in technical literature, including within an
EPA-affiliated November 2007 white paper158 where it was noted that “(f)ew energy efficiency
policy issues have generated as much debate as the issue of the impact of energy efficiency
programs on utility margins.”159
The LPSC is concerned the EPA is not valuing EE resources and their potential on a
correct comparable basis to traditional resources. Recovery of utility lost margins resulting from
EE require rate increases in the form of either (1) subsequent base rate cases, (2) lost revenue
adjustment mechanisms (“LRAMs”), or (3) decoupling mechanisms.
Rate increases to
customers are costs directly related to investment in EE and should be included when comparing
resource potentials of EE to supply side alternatives. Other issues include the efficiency of
demand-side resources from free ridership and endogeneity issues. As noted by the EPA in its
GHG Abatement Measures TSD, empirical analyses including these factors “present a wider
range of estimates of cost of saved energy.”160 One study referenced in the GHG Abatement
Measures TSD estimated the average utility cost of saved energy in the range of 5.1 to 14.6 cents
158
Aligning Utility Incentives with Investment in Energy Efficiency: A Resource of the National Action Plan for
Energy Efficiency (November 2007), National Action Plan for Energy Efficiency.
159
Aligning Utility Incentives with Investment in Energy Efficiency: A Resource of the National Action Plan for
Energy Efficiency (November 2007), National Action Plan for Energy Efficiency, p. ES-3.
160
EPA Technical Support Document: GHG Abatement Measures, p. 5-28.
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
Page 95
per kWh.161 As noted earlier, Louisiana had the third lowest residential electric rates in the
country in August 2014 at 9.77 cent per kWh.162 It is doubtful that extensive EE investments
with an average utility cost of saved energy of 14.6 cents per kWh would be cost-effective in low
energy cost states such as Louisiana.
v.
Technical Analysis fails to examine total rate and
ratepayer impacts adequately
Lastly, the LPSC is concerned that the EPA’s analysis assesses EE potential on an
inherently incorrect basis. For best practices, the EPA determined that all states should be able
to reach an annual incremental savings through EE equal to 1.5 percent of annual retail sales.163
The finding of an EE potential goal based on annual incremental savings assumes that savings
through EE exists no matter how saturated the market may become. In other words, the EPA
incorrectly forces states to view EE as the proverbial “gift that keeps on giving,” rather than a
demand-side resource comparable to traditional supply resources. For instance, such a goal in
terms of renewable energy would require states to increase each year their renewable energy
generation, rather than achieve a particular amount of renewable generation capacity or energy,
regardless of the need for such generation.
The LPSC suggests a more appropriate and
theoretically sound goal would be based on cumulative energy savings.
Table 12 provides the cost estimate to Louisiana ratepayers given the EPA’s target levels
of EE. Like the RE component, the cost to ratepayers is not simply the cost of EE programs, but
also the lost revenues incurred. Assuming a mid-range cost estimate of $106/MWh, EE program
161
EPA Technical Support Document: GHG Abatement Measures, p. 5-28.
Electric Power Monthly: Table 5.6.A. Average Retail Price of Electric to Ultimate Customers by End-Use Sector
(October 27, 2014), U.S. Energy Information Administration.
163
EPA Technical Support Document: GHG Abatement Measures, p. 5-33.
162
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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expenditures would total $538.9 million. This, in addition to $122.3 million of lost revenues to
utilities, results in a total Building Block 4 cost of $661.2 million.
Preliminary Cost Estimates
Low
Mid
High
Range
Range
Range
Cost
Cost
Cost
------ ($ Millions, NPV) ------
Building Block
Strategy
Building Block 1
Increase Coal Plant Thermal Efficiency
Coal plant capital investment costs:
Stranded coal plant capital cost:
Building Block 2
$
$
425.5
842.6
$
$
638.3
842.6
$
$
851.0
842.6
$
$
500.0
986.4
$
$
1,000.0
986.4
$
$
1,500.0
986.4
$
-
$
-
$
-
$
$
388.8
248.8
$
$
432.0
276.4
$
$
475.3
304.0
$
$
462.6
110.1
$
$
538.9
122.3
$
$
615.2
134.5
Increase Natural Gas Generation Capacity Factor
New transmission capital investments:
Stranded oil/gas steam plant capital cost:
Building Block 3a At Risk Nuclear Generation
Building Block 3b Increased Renewable Generation
Increased capital cost margin:
Utility lost revenue recovery:
Building Block 4
Increased Energy Efficency
Increased energy efficiency program expenditures:
Utility lost revenue recovery:
Total Louisiana Cost Impact:
$ 3,964.8
Table 12. Estimated Cost of Building Block 4
$ 4,836.9
$ 5,709.0
Note: Coal plant capital investment costs are assumed to be $100/kW (low); $150/kW (mid); and $200/kW (high)
for all Louisiana coal units.
Stranded cost estimates are only included for utility-owned units with publicly available data.
Typical transmission investment resulting from increased NGCC dispatch assumed to be $500 million: low estimate
assumes one project; mid-range estimate assumes two projects; high assumes three projects.
Nuclear assumed to have no additional cost.
Renewable energy assumes generation portfolio of 75 percent biomass; 15 percent wind and 10 percent solar. This
results in a levelized cost differential of $37.60/MWh (when compared to a new NGCC).
Energy efficiency costs are assumed to be $91/MWh (low); $106/MWh (mid); and $121/MWh (high).
Lost base revenues estimated at $24.05 per MWh for both renewable energy and energy efficiency.
Assumes 10.915 percent discount rate (based on typical utility allowed rate of return).
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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G. Total Impacts
Table 13 provides a complete summary of the LPSC’s preliminary estimates of the
potential compliance costs associated with EPA’s proposed CPP. These compliance costs are
based upon the emissions reduction targets estimated by the EPA for each of the building blocks
included in the BSER. In total, the LPSC estimates that CPP compliance will cost Louisiana
ratepayers somewhere between $3.9 billion and $5.7 billion, in NPV terms. Stranded utility
costs, a cost estimate excluded in the EPA’s analysis, are estimated at $1.8 billion (NPV). Lost
utility base revenues associated with increased renewable energy and energy efficiency
programs, represent another cost excluded from the EPA’s analysis. These costs are estimated to
range from $360 million to $439 million (NPV).
[Space intentionally left blank.]
LPSC Comments – Docket EPA-HQ-OAR-2013-0602
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Preliminary Cost Estimates
Low
Mid
High
Range
Range
Range
Cost
Cost
Cost
------ ($ Millions, NPV) ------
Building Block
Strategy
Building Block 1
Increase Coal Plant Thermal Efficiency
Coal plant capital investment costs:
Stranded coal plant capital cost:
Building Block 2
$
$
425.5
842.6
$
$
638.3
842.6
$
$
851.0
842.6
$
$
500.0
986.4
$
$
1,000.0
986.4
$
$
1,500.0
986.4
$
-
$
-
$
-
$
$
388.8
248.8
$
$
432.0
276.4
$
$
475.3
304.0
$
$
462.6
110.1
$
$
538.9
122.3
$
$
615.2
134.5
Increase Natural Gas Generation Capacity Factor
New transmission capital investments:
Stranded oil/gas steam plant capital cost:
Building Block 3a At Risk Nuclear Generation
Building Block 3b Increased Renewable Generation
Increased capital cost margin:
Utility lost revenue recovery:
Building Block 4
Increased Energy Efficency
Increased energy efficiency program expenditures:
Utility lost revenue recovery:
Total Louisiana Cost Impact:
$ 3,964.8
$ 4,836.9
$ 5,709.0
Table 13. Cost Estimates of EPA's Clean Power Plan for Louisiana
Note: Coal plant capital investment costs are assumed to be $100/kW (low); $150/kW (mid); and $200/kW (high)
for all Louisiana coal units.
Stranded cost estimates are only included for utility-owned units with publicly available data.
Typical transmission investment resulting from increased NGCC dispatch assumed to be $500 million: low estimate
assumes one project; mid-range estimate assumes two projects; high assumes three projects.
Nuclear assumed to have no additional cost.
Renewable energy assumes generation portfolio of 75 percent biomass; 15 percent wind and 10 percent solar. This
results in a levelized cost differential of $37.60/MWh (when compared to a new NGCC).
Energy efficiency costs are assumed to be $91/MWh (low); $106/MWh (mid); and $121/MWh (high).
Lost base revenues estimated at $24.05 per MWh for both renewable energy and energy efficiency.
Assumes 10.915 percent discount rate (based on typical utility allowed rate of return).
Table 14 provides these total compliance cost estimates on a cost per ton of avoided
emissions basis. Compliance costs associated with just the capital investments and program
expenditures for each of the EPA’s proposed building blocks are estimated to cost Louisiana
ratepayers from $90 per ton to $174 per ton. The inclusion of stranded utility costs increases
estimated Louisiana ratepayer costs by about $92 per ton. The addition of lost utility revenues
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increases unit-based compliance costs even further by $18 per ton to $22 per ton. In total, the
actual estimated cost to Louisiana ratepayers is $200 to $289 per ton. These estimates are far
higher than the EPA estimated (national average) compliance costs of $60 per ton.
Preliminary Cost Estimates
Low
Mid
High
Range
Range
Range
Cost
Cost
Cost
------ ($ Millions, NPV) ------
Preliminary Cost Estimates ($/ton)
Low
Mid
High
Range
Range
Range
Cost
Cost
Cost
------ ($/ton, NPV) ------
Total Capital Cost and Program Expenditures
$ 1,777.0 $ 2,609.2 $ 3,441.4
$
90.01 $ 132.17 $ 174.32
Total Stranded Costs
$ 1,829.0 $ 1,829.0 $ 1,829.0
$
92.65 $
92.65 $
92.65
Total Utility Lost Revenue
$
$
18.18 $
20.20 $
22.21
Total Louisiana Cost Impact
$ 3,964.8
358.8 $
398.7 $
$ 4,836.9
438.6
$ 5,709.0
$ 200.84
$ 245.01
$ 289.19
Table 14. Cost Estimates of EPA's Clean Power Plan for Louisiana, $/ton
IV.
CONCLUSIONS AND RECOMMENDATIONS
The LPSC believes the CPP is legally flawed and should be withdrawn in its entirety. In
the alternative, however, and in the event the EPA issues a final rule, the LPSC offers six
specific recommendations consistent with its comments herein.
1. Address reliability-related issues associated with the proposed
rule in a diligent fashion through the development of a
reliability-based study process that would include a number of
regional technical conferences, conducted jointly between the
EPA, the FERC, state regulatory commissions, and regional
transmission organizations/reliability organizations.
The LPSC, as noted earlier, is very concerned about the reliability and generation
resource adequacy implications of the Proposed Rule. The Commission’s regulated utilities, as
well as many RTOs governing transmission operations across Louisiana, have raised serious
questions about the region’s ability to meet current reliability requirements in the face of the
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EPA’s proposed CPP implementation timeline. Even with an extension, the LPSC believes that
the issue of bulk power system reliability has not been explored adequately in the development
of this Proposed Rule. The LPSC recommends the EPA initiate a study process with the FERC,
as well as state regulators and RTOs, to understand the full reliability ramifications of not only
the proposed CPP, but many other recently-promulgated EPA rules that, cumulatively, are
anticipated to have considerable implications for bulk-power system reliability. The LPSC
believes that a meaningful, but expedited, reliability study process could be conducted within a
12 month period and that it would be in all stakeholders’ interest to initiate such a process before
finalizing the Proposed Rule.
2. Adopt a reliability “safety-valve.”
The Proposed Rule would benefit from the inclusion of a reliability “safety valve” that
exempts states from CPP implementation, or certain provisions of CPP implementation, if
compliance can be reasonably shown to lead to a reliability or generation adequacy challenge.
RTOs are likely in the best position to make such findings with potential oversight from both the
FERC and the EPA.
3. Accept the proposed data revisions offered in the Louisiana
Department of Environmental Quality’s Original Comments.
The LPSC has worked closely with, and agrees with the initial comments of the LDEQ
filed before the EPA in this matter.
The LPSC believes that the LDEQ’s proposed
recommendations are reasonable and better reflect the “on-the-ground” view of the state’s
electric generation resources and their operations than those included in the EPA’s baseline
calculations.
4. Extend the existing schedule to allow states the opportunity to
develop the adequate physical and institutional infrastructure
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necessary to implement the Proposed Rule as well as to explore
regional solutions.
The currently-proposed EPA timeline is too aggressive and will likely lead to reliabilityrelated challenges in the very near future. The bulk power system infrastructure is currently
insufficient to meet the current EPA CPP timeline. Further, the Proposed Rule provides little
insight into whether or not there is enough natural gas infrastructure to support some of the
dramatic wholesale power generation market changes anticipated by the CPP. Additional time
for implementation would assist in minimizing these potential negative market outcomes.
Lastly, the EPA takes for granted the institutional infrastructure that is lacking in certain
parts of the country for initiating many of the policies included in its BSER approach. Rather
than implement an RPS and EE targets or goals, Louisiana has taken a more measured approach
to alternative energy in an effort to avoid the imposition of unduly burdensome energy costs on
its ratepayers.
The State is lacking in a broad number of potential market suppliers and
alternatives (primarily in RE and EE) and does not have the historical institutional background in
the development of regional clean power, clean air, and efficiency markets that exists in places
like the Northeastern U.S. The EPA implementation period should be extended to give states
like Louisiana the opportunity to develop these additional institutional resources to avoid the rate
shock and economic harm that will otherwise result.
5. Allow the use of industrial CHP as an efficiency resource
under Building Block 4.
The EPA’s current energy efficiency building block creates a considerable degree of
emphasis on the utilization of “traditional” energy efficiency resources coming from the
residential and commercial sectors. The Proposed Rule, and the BSER for Louisiana, is silent on
the potential use of industrial CHP as a potential efficiency resource. The LPSC recommends
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that the EPA include industrial CHP as a resource in any Final Rule on this matter. Louisiana is
in the middle of an “industrial renaissance” that could see, in a matter of just a few years, the
development of over $100 billion in new capital investment. Few industrial projects to date,
however, have indicated a willingness to adopt CHP measures. Including CHP in the Final Rule
could give Louisiana a meaningful way of meeting its rather stringent CO2 emission reduction
requirements, and at the same time, offer increased efficiency opportunities for these new
industrial facilities. The LPSC, therefore, encourages EPA to include the thermal efficiencies
from new, incremental CHP applications as a compliance measure under the Louisiana BSER.
6. Allow the use of biomass as a renewable energy resource under
building Block 3(b).
The Commission noted earlier in its comments that biomass is its primary opportunity for
adding renewable-based resources. The EPA, however, has not been clear in the degree to which
biomass will be allowed as a compliance measure under the CPP. The LPSC recommends that
biomass be explicitly included as a compliance option for Building Block 3(b).
The LPSC respectfully requests that the EPA give due consideration to all of the
foregoing comments, including the specifically enumerated recommendations listed above.
Respectfully Submitted,
__________________________________
Melanie A. Verzwyvelt (Bar Roll No. 28252)
Rusten A. May (Bar Roll No. 34841)
Staff Attorneys
Louisiana Public Service Commission
P.O. Box 91154
Baton Rouge, Louisiana 70821-9154
Ph. (225) 342-9888
Email: melanie.v@la.gov
rusten.may@la.gov
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