A Perfect Storm: Rethinking Electricity Restructuring
Prepared by Hannah S. Flint
Student
Georgetown University School of Law
Published by the Electric Markets Research Foundation
November 10, 2014
I.
Introduction
Addressing the U.S. House Energy and Power Subcommittee, Commissioner John Norris
of the Federal Energy Regulatory Commission (FERC) acknowledged that although “the energy
sector and the electric sector experienced only modest, incremental change for much of the last
century . . . that time of incremental change is clearly over.”1 Stagnant demand growth, the shale
revolution and a multitude of federal and state policies have resulted in a rapidly changing
energy landscape. Although the entire industry is facing these new challenges, restructured
electricity markets that rely solely on market forces have made these changing dynamics even
more prominent, and many parts of the country are now facing concerns of near- and long-term
capacity shortfalls.2
Due in part to an abundant supply of low-cost natural gas, various environmental
regulations, and government subsidies for renewable projects, coal-fired and nuclear base load
generation have had difficulty remaining economic to operate in today’s restructured markets.
Some nuclear and coal plants have already retired, and many more are scheduled to shut down.3
1
Evaluating the Role of FERC in a Changing Energy Landscape: Hearing Before the Subcomm. on
Energy and Power, 113th Cong. (2013) (testimony of John Norris, Comm’r, FERC).
2
See Joe Chesto, Here’s why it’s good a New Englander leads the Federal Energy Regulatory
Commission, BOS. BUS. J. (Dec. 13, 2013); see also Evaluating the Role of FERC in a Changing Energy
Landscape: Hearing Before the Subcomm. on Energy and Power, 113th Cong. (2013) (press release,
Subcomm. on Energy and Power).
3
See, e.g., Evaluating the Role of FERC in a Changing Energy Landscape: Hearing Before the Subcomm.
on Energy and Power, 113th Cong. (2013) (testimony of Tony Clark, Comm’r, FERC) (“This flood of
domestic gas and oil, combined with new EPA rules, has upended utility planning models and market
1
The Clean Power Plan proposal issued by EPA in June 2014 to regulate carbon emissions from
existing power plants will only further exacerbate the retirement situation. Despite FERC’s
efforts to “refine market rules to ensure that all resources are participating in markets on a level
playing field,”4 market structures, subsidies and environmental regulations quickly made natural
gas and renewables the clear market “winners.”5 This heavy reliance on a less diverse fuel mix in
the restructured markets has in turn led to additional challenges, including a need for new
infrastructure in order to integrate greater amounts of renewable generation onto the grid6 and
new natural gas pipeline infrastructure to ensure adequate supplies of gas in regions with tight
pipeline capacity.7
At the same time that new generation is needed to replace retiring base load generation,
generators facing unstable market designs8 and “rock-bottom power prices” have found “little
incentive to invest in [base load] generation” in restructured markets.9 Not only is new base load
generation not being built, but many market participants are exiting markets for less risky
investments. Aggressive market oversight and enforcement, along with unclear rules, have
increased trading costs and noncompliance risk, which has led market participants, particularly
fundamentals.”); David Dittman, The Pedal’s to the Metal for the US Electric Power Industry, INVESTING
DAILY (Dec. 12, 2013); Corina Rivera-Linares, DATC: Tenor of conversation around transmission must
be changed, TRANSMISSION HUB (Nov. 4, 2013).
4
See Comm’r Norris’ testimony supra note 1, at 7.
5
See Chesto supra note 2.
6
Evan Halper, Power struggle: Green energy versus a grid that’s not ready, L.A. TIMES (Dec. 3, 2013)
(“The problem is that renewable energy adds unprecedented level of stress to a grid designed for the
previous century.”).
7
Rod Kuckro, Who benefits when gas prices spike during a New England freeze?, ENERGY WIRE (Jan. 6,
2014) (“The reliance on spot gas purchases is a significant factor behind EIA data showing New England
states ranking among the top 10 in the United States for average retail electricity rates.”).
8
Eileen O’Grady & Scott DiSavino, U.S. power companies struggle to profit: executive, REUTERS (Nov.
10, 2013) (Calling for competitive market rules to evolve, GDF Suez Energy Marketing NA stated that
“in Texas, ‘we are developing [projects], but we are not going to pull any triggers until we see a more
structurally sound design.’”).
9
See Comm’r Norris’ testimony supra note 1, at 4; see also Jeff Beattie, Amid dismal generation outlook,
utilities seek growth in wires and pipes, ENERGY DAILY (Nov. 13, 2013).
2
banks, to exit power markets, leading to concerns regarding the liquidity of these markets.10 In
addition, several utilities are seeking growth in more stable investments, namely their regulated
businesses and transmission and pipeline infrastructure.11 FirstEnergy, for example, announced
its intention to remake itself “from a champion of competition to a more old-fashioned looking
power company”12 to reduce their “exposure and risk to power markets.”13 The electric utility
committed to “downsizing its unregulated companies” to focus on “becom[ing] more of a
regulated company . . . grow[ing] predictable cash flow” from its regulated subsidiaries, which
are expected to provide about 80 percent of the company’s revenues.14 The company also has
plans to invest billions of dollars in transmission infrastructure projects, investments that are
guaranteed a reasonable rate of return set by FERC.15
These challenges have sparked substantial debate as to whether competitive market rules
provide the adequate incentives to “achieve efficient market-based outcomes, or whether rule
changes are necessary.”16 Market participants have opined that “the industry is falling apart” as a
result of “market protocols ill-suited to address fundamental market changes brought about by
lower natural gas prices, stricter environmental regulations and financial compliance
10
Hannah Northey, Frustrated Senators ask if Wall Street is friend or foe, E&E DAILY (Jan. 16, 2014).
See, e.g., Comm’r Norris’ testimony supra note 1, at 6 (“As a result of the current uncertainty around
investment in generation, a large portion of current and planned utility capital expenditures is in
transmission and distribution.”); John Funk, FirstEnergy confirms rate increases with transmission
improvements, CLEVELAND PLAIN DEALER (Nov. 12, 2013) (FirstEnergy, for example, expects its
transmission investments will increase its regulated net profits by about 20% per year.); see Beattie supra
note 9 (DTE announced plans to spend $1 billion to $1.4 billion on its gas pipeline and storage business
over the next five years.); Electric power sector making record investments in transmission and
distribution, ELECTRIC LIGHT & POWER (Dec. 19, 2013) (An EEI survey indicates that investor-owned
utilities and stand-alone transmission companies invested a record $34.9 billion in transmission and
distribution infrastructure in 2012.).
12
See Funk supra note 11.
13
John Funk, FirstEnergy is planning to spend billions to upgrade power lines, increase reliability and
profits, CLEVELAND PLAIN DEALER (Nov. 5, 2013).
14
Id.
15
Id.
16
See Comm’r Norris’ testimony supra note 1, at 7.
11
3
regulation.”17 A study was recently published by the American Public Power Association
(APPA) that looked specifically at generating capacity additions in 2013. The APPA study found
that almost all new capacity in 2013 was constructed under a long-term contract or ownership.
Just 2.4 percent of the new capacity was built for sale into a market, a number that includes new
facilities for which no information could be found about the contracts. Moreover, when broken
down geographically, only 6 percent of all capacity constructed in 2013 was built within the
footprint of restructured markets with mandatory capacity markets.18 But both restructured
markets and FERC appear once again eager to layer on additional market rules in an effort to
resolve these issues rather than to evaluate the whole model.19 During a time of tight supply and
already low margins, the critical question is how the restructured markets and FERC plan to
incentivize additional supply in the market to solve anticipated capacity shortfalls without further
depressing market prices and thus devaluing current generators?
Electricity is undoubtedly critical to the U.S. economy and national security, and in light
of these challenging circumstances that have significant implications for current electricity rates
and reliability, it is time for electricity market restructuring to be reconsidered. This paper takes
the position that electricity regulation offers the financial stability and comprehensive planning
necessary to provide reliable and affordable electricity to American consumers, and is therefore,
a superior model to restructured markets as they exist today in the United States.
II.
Electricity Regulation and the Push Towards Industry Reform
Electricity regulation began its evolution in the late nineteenth century and was
“developed around the concept of a central source of power supplied by efficient, low-cost utility
See O’Grady supra note 8.
AM. PUB. POWER ASS’N, POWER PLANTS ARE NOT BUILT ON SPEC: 2014 UPDATE 1 (Oct. 2014),
available at http://www.publicpower.org/files/PDFs/94_2014_Power_Plant_Study.pdf.
19
“The commission [FERC] is heavily engaged in the work of assessing and responding to these fuel mix
changes.” See Comm’r Clark’s testimony supra note 3, at 1.
17
18
4
generation, transmission, and distribution.”20 The move from municipal to state regulation in the
early twentieth century was based in part on the view that regulation was in the public interest
because the electric industry exhibited characteristics of a natural monopoly, where “one firm
can serve the market more cheaply than two or more firms and can keep out rival firms by
expanding output and lowering price when threatened.”21 This was particularly true for
transmission and distribution systems, where it would be “too costly to permit multiple lines” to
the same destination.22 Accordingly, states granted monopoly franchises with the exclusive right
to serve a particular territory to vertically integrated utilities in exchange for an obligation to
serve all customers within that territory.23 To avoid monopoly pricing, utilities and regulators
entered into the “regulatory compact,” where regulators “set the price and quantity of service at
hypothesized competitive levels”24 and ensured that utilities operated efficiently without excess
costs.25 The regulatory compact is mutually beneficial to the regulated utility and its ratepayers:
“utility investors are provided a level of stability in earnings . . . [and] in turn, ratepayers are
afforded universal, non-discriminatory service and protection from monopolistic profits.”26
A.
Push Towards Industry Restructuring
The industry flourished for many years under the vertically-integrated model with state
supervision. Regulation allowed the rapid expansion of the electric industry, and increased
demand growth allowed utilities to capture economies of scale by building large generating units,
20
NAVIGANT CONSULTING, EVOLUTION OF THE ELECTRIC INDUSTRY STRUCTURE IN THE U.S. AND
RESULTING ISSUES (Prepared for Electric Mkts. Research Found., Oct. 2013).
21
R. Richard Geddes, A Historical Perspective on Electric Utility Regulation, REGULATION 75, 76 (Jan.
1992), available at http://object.cato.org/sites/cato.org/files/serials/files/regulation/1992/1/v15n1-8.pdf.
22
Lester B. Lave et al., Rethinking Electricity Deregulation, 17 ELEC. JOURNAL 11, 13 (Oct. 2004).
23
See Navigant supra note 20, at 3.
24
JOSEPH P. TOMAIN & RICHARD D. CUDAHY, ENERGY LAW IN A NUTSHELL 171 (West Publ’g Co., 2d
ed. 1992).
25
See Lave supra note 22, at 13-14.
26
See Tomain supra note 24, at 171-72.
5
driving down costs and electricity rates.27 Regulation also provided utilities a fair return on their
investment that attracted capital and allowed them to expand into new regions that previously did
not have access to electricity.28 In the 1960’s, utilities invested heavily in new generation,
particularly nuclear power, projecting continued demand growth in the decades to follow.
Beginning in the 1970’s, however, a number of events caused demand to decline and
electricity prices to rise significantly, ultimately leading to a push for industry reform.29 The
Arab oil embargo of 1970 caused fuel prices to skyrocket and contributed to inflation, in turn
causing interest rates to more than triple.30 The rate of electricity demand growth decreased as
consumers began conserving energy in response to these rising costs, revealing that electricity
demand was more elastic than previously anticipated.31 At the same time as declining demand,
electricity prices spiked as higher-than-expected generation costs went into customer rate-base.
Utilities experienced these higher costs for a number of reasons. In particular, power
plants under construction experienced significant material and labor cost overruns due to high
inflation and interest rates, causing construction delays and forcing some plants to entirely cancel
construction plans prior to completion.32 Additional safety requirements and a concerned public
following the nuclear accident at Three Mile Island also raised costs for nuclear plants.33
Burdened by high electricity rates, consumers objected to paying for costly excess generation,
arguing that customers should not be responsible for poor investment decisions made by utility
27
See Suedeen G. Kelly, The New Electric Powerhouse: Will They Transform Your Life?, 29 ENVTL. L.
285 (1999); see also Navigant supra note 20, at 3.
28
See Navigant supra note 20, at 3, 6.
29
See Lave supra note 22, at 13.
30
See Navigant supra note 20, at 7.
31
See Kelly supra note 27, at 3; see also Tomain supra note 24, at 379.
32
See Navigant supra note 20, at 8.
33
Id.
6
monopolies.34 And perhaps most importantly, the incremental costs for new generation, partly
due to declining gas costs, became less than retail rates paid by large industrial consumers in
many regions of the country, and they saw competition as a means of lowering their costs. Other
consumers also raised concerns about regulators’ abilities to choose the best investments for
utilities and to determine when company operations were efficient.35 As a result, consumers in
many states began advocating for industry reform.
Subsequently, Congress took a number of actions that facilitated the move towards
deregulation and industry restructuring. In response to the Arab oil embargo, the nation’s fuel
shortages and rising fuel prices, Congress enacted the Public Utility Regulatory Policies Act
(PURPA) in 1978.36 Congress sought to promote energy efficiency to conserve energy resources
and promote alternative fuel sources in order to “reduce the need to consume traditional fossil
fuels” for power generation.37 PURPA encouraged the development of non-traditional entities,
namely cogeneration and small power production facilities, and required utilities to purchase
energy from these “qualifying facilities” (QFs) at the utilities’ “avoided cost.”38 PURPA was the
first introduction of competition into the electric industry, and while the QF industry quickly
developed, concerns arose about their ability to access the utility’s transmission systems, and a
concern that utilities could charge QFs discriminatory rates to wheel power.39 Some also argued
that not only QFs, but other non-utilities, should be able to compete in generation markets. The
Energy Policy Act of 1992 (EPAct 1992) and FERC Order 888 addressed these issues and
further enabled competition. EPAct 1992 provided market development incentives, created a
34
See Lave supra note 22, at 13.
Id. at 15-16.
36
S. Cal. Edison Co. v. FERC, 193 F.3d 17, 19 (D.C. Cir. 1999).
37
Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the
Public Utility Regulatory Policies Act of 1978, 45 Fed. Reg. 38,12214, 38,12215 (Feb. 25, 1980).
38
FERC v. Mississippi, 456 U.S. 742, 750 (1982).
39
See Tomain supra note 24, at 383.
35
7
new class of “independent” generators that were exempt from certain federal laws, and gave
FERC broad authority to order utilities to wheel power for wholesale transactions. Consequently,
FERC implemented EPAct 1992 in its landmark Order 888, which required utilities to
“unbundle” (i.e., financially separate) their generation and transmission functions for wholesale
transactions and to provide open access to transmission on a non-discriminatory basis.40 In 1999,
FERC further enabled industry restructuring by adopting Order 2000, which formally created (on
a voluntary basis) independent transmission system operators, known as Regional Transmission
Organizations (RTOs), and sometimes referred to as Independent System Operators (ISOs), to
facilitate greater coordination and access to transmission.41 These statutory and regulatory
actions further facilitated the push for competition within the electric industry.
At a time when other industries, such as the airline, natural gas and telecommunications
industries, were experiencing what appeared to be great success after deregulation, electricity
restructuring appeared to be the common-sense solution to the problems facing the industry and
consumers. Perhaps even more influential, Great Britain, among other countries, privatized its
electric industry in the early 1990’s, introducing competition into generation and later into the
retail side.42 After a visit to Great Britain, Elizabeth Moler, FERC Chair at the time, stated that
“the Brits’ enthusiasm about the early successes of their restructuring definitely emboldened us
to embark upon restructuring.”43 By the 1990’s, electricity restructuring “took on an appearance
of inevitability, an over-whelming force that could not be resisted – a juggernaut.”44
B.
Halt in Restructuring
40
Id. at 388-390.
Id. at 390.
42
DANIEL YERGIN, THE QUEST: ENERGY, SECURITY, AND THE REMAKING OF THE MODERN WORLD 38586 (Penguin Books 2012).
43
Id.
44
Gerald A. Norlander, Disconnected Policymakers, 14 ELEC. JOURNAL 22, 23 (Aug. 2001).
41
8
In general, states with the highest retail rates advocated most aggressively for
deregulation; although, between 1996 and 2000, almost all states were at least investigating
deregulating retail competition, and 25 states had adopted legislation or enacted regulations at
the state level approving retail competition.45 The introduction of retail competition in these
states called for a restructuring of how the market and transmission access in particular operated,
and as a result, most states adopting retail competition also formed or joined RTOs. Thus, 23
states began restructuring their electricity markets by the late 1990’s.46 This all changed in 2000,
however, with the collapse of California’s electricity restructuring.47
In the late 1990’s, California’s electricity demand began growing faster than supply, due
in part to economic growth, weather conditions, a slower pace of generation construction
completion, and a reduction in reserve margins.48 Rising natural gas prices, market manipulation,
reduced electricity imports, and increased environmental costs further exacerbated the
situation.49 A drought in the Pacific Northwest reduced significantly the regular imports that
California relied on, and some observers believe that the market rules in California allowed
significant market manipulation that also increased prices. By the summer of 2000, all of these
factors converged, and the market was left with severe supply shortages, causing market prices to
skyrocket, and because retail rates were fixed, utilities were left paying much more for wholesale
electricity than they were able to sell it at retail.50 By the middle of 2001, “in the wake of one
See Steven Ferrey, Deregulation of Power: Deregulation and unbundling services – New market forces,
2 L. INDEP. POWER § 10.1 (2013).
46
Id.
47
See generally Paul L. Joskow, California’s Electricity Crisis, 17 OXFORD REVIEW OF ECON. POLICY
365 (2001); CONG. BUDGET OFFICE, CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS
(Sept. 2001) (providing detailed analyses of the California electricity crisis).
48
See Joskow supra note 47.
49
Id.
50
See Cong. Budget Office supra note 47.
45
9
bankrupt utility [and the near bankruptcy of others], even higher wholesale prices, and rolling
black-outs – skeptics blamed deregulation for putting California in a perilous position.”51
Following the California electricity crisis, several states began to rethink restructuring
and retail competition, and several states that had already passed restructuring legislation began
to delay implementation, modify programs, and even reverse retail competition and
restructuring.52
C.
Electricity Restructuring Today
The experiment of restructuring in the late 1990’s resulted in a fragmented electric
industry, with parts of the country restructuring and other parts remaining regulated. FERC
expressed its goal to establish a standardized national electricity market and introduced the
Standard Market Design Notice of Proposed Rulemaking (NOPR) in 2002.53 Due to political
pushback, particularly from regions that had not restructured, FERC withdrew its Standard
Market Design NOPR in “connection with efforts to secure the passage of the 2005 Energy
Policy Act.”54
Today, the country continues to be greatly divided on the electric industry restructuring
question, and states retain the decision-making authority regarding the structure in their states.55
Several states, mostly in the Southeast, Southwest and Northwest, chose to remain traditionally
regulated, with vertically integrated utilities providing end-user customers “bundled” services
(i.e., generation, transmission and distribution services).56 Other parts of the country, including
51
Id.
See Ferrey § 10.1 supra note 45.
53
See Tomain supra note 24, at 399.
54
Id.
55
EPSA, ELECTRICITY PRIMER: ELECTRICITY 101 (last visited Feb. 2, 2014), available at
http://www.epsa.org/industry/primer/.
56
See Retail Electricity Markets, COMPETE COAL. (last visited Feb. 2, 2014), available at
http://www.competecoalition.com/files/Retail%20Electricity%20Markets.pdf.
52
10
the Northeast, mid-Atlantic, much of the Midwest, Texas and California, however, chose to offer
some form of competition into their electricity markets, although market structures differ by
state.57 For example, some states allow full retail competition, allowing customers to choose
between the incumbent utility or competitive suppliers.58 Other states have only introduced
competition into generation, and the incumbent utility still provides supply services to end-user
customers.59
III.
The Reality of Restructuring in the Electricity Industry
“The concept [of deregulation] seemed straightforward: Opening the monopoly electric
generation market to competition would usher in a new era of lower prices and innovation the
same way it did with airlines and long-distance telephone service.”60 In theory, electricity
deregulation should make sense. At the macro-level, the invisible hand of the market, rather than
regulators, “assure[s] that supply always exceeds demand” through market price signals, which
indicate how much generation is needed and ensure that the least costly generators are selected to
operate.61 Removing the “conscious setting of just and reasonable wholesale rates by fallible
mortals” encourages competition, driving down prices and fostering innovation.62 Deregulation
offers an idyllic promise: “large and small consumers alike will see lower rates, more choices,
improved services, all with no impact on reliability.”63
A.
Electricity’s Unique Characteristics
57
See EPSA Primer supra note 55.
Id.
59
Id.
60
Jeffrey Tomich, 2 states feel the market heat as their deregulated neighbors reap rewards, ENERGY
WIRE (Jan. 29, 2014).
61
See Norlander supra note 44, at 22; see also COMPETE COAL., PRINCIPLES FOR WELL-FUNCTIONING
COMPETITIVE ELECTRICITY MARKETS (2013), available at
http://www.competecoalition.com/files/COMPETE%20Market%20Principles.pdf.
62
See Norlander supra note 44, at 22.
63
Id. at 23.
58
11
But in reality, “circumstances do not always fit the vision.”64 While the restructuring of
the airline, telecommunications and natural gas industries have been cited as evidence of the
benefits that competition can provide, such as lower costs and innovation, electricity has unique
characteristics that prevent the industry from reaping the same benefits. Natural gas, for example,
is controllable, meaning the gas is pumped through pipelines at roughly 25 miles per hour to a
specific recipient, and gas is capable of being stored.65 Electricity, in contrast, travels at the
speed of light, flows to the path of least resistance, and has limited storage capability, which
means that adequate supply must be available at the exact time that it is needed to meet demand.
As a result of electricity’s short-run characteristics, the power grid requires constant balancing in
order to maintain reliability, and even small changes in supply or demand can have a significant
impact.66 Adding to this challenge, electricity, unlike many other commodities, requires capitalintensive infrastructure to move it to market, and this infrastructure takes time to build.67
Generation is also capital-intensive and takes years to build. These factors highlight the extensive
coordination required in planning and operating generation and transmission systems in order to
maintain reliability that is critical to the U.S. economy and national security.
Unlike other commodities, when demand exceeds supply and prices rise significantly,
electricity consumers have no alternative product. For example, when the supply of corn is
limited and prices rise, customers may choose to purchase beets instead of paying the higher
price for corn, causing supply and demand to balance out. The corn market can also react quickly
to rising prices and reallocate farmland around the world to growing more corn. When the supply
64
Id.
See Steven Ferrey, Deregulation of Power: Natural gas and telecommunications deregulation
comparisons, 2 L. INDEP. POWER § 10.4 (2013).
66
See Steven Ferrey, Deregulation of Power: Deregulation and unbundling services – Spark spread and
arbitrage, 2 L. INDEP. POWER § 10.2 (2013).
67
See Steven Ferrey, Deregulation of Power: Reliability and Blackouts, 2 L. INDEP. POWER § 10.5 (2013).
65
12
of electricity is tight and prices rise, however, customers are forced to pay astronomical prices or
curtail electricity service, and new generating capacity takes years to build. Electricity regulation
provides customers with the substantial assurance that electricity supply will always be available
without exposing them to price volatility, as utilities are required to plan years in advance to
meet forecasted demand.
Because of electricity’s unique characteristics, even the most zealous restructuring
advocates recognize the need for market rules and oversight in restructured markets, and many
have stressed that “if deregulation is to bring benefits to consumers, the markets it creates must
be competitive.”68 Accordingly, restructured markets have been structured to “introduce as much
competition as possible among generators while maintaining strict regulation over the
transmission and distribution systems.”69
B.
Externalities Distort Competitive Markets
The biggest flaw behind electricity restructuring was likely the belief that electricity
markets can function competitively and efficiently to meet consumer needs in the short- and
long-term without taking into consideration changes in market conditions and inevitable
government intervention. Mixing competitive markets with regulatory fiats has lead to many of
the problems with restructuring. This section identifies a number of externalities that have
distorted electricity wholesale markets, sending inaccurate price signals and leading to concerns
of near- and long-term capacity shortfalls.
1. Stagnant Demand Growth
68
See Lave supra note 22, at 16.
Electricity Market FAQ, COMPETE COAL. (last visited Feb. 2, 2014),
http://www.competecoalition.com/press_kit/faq.
69
13
While electric utilities in both regulated and restructured markets are struggling with
declining electricity demand,70 commentators note that “one of the underlying initiatives in any
effort to restructure an industry is to grow consumption as a means of delivering value to
customers and investors,” and the electric industry has no such potential for growth.71 In fact,
FERC Commissioner Philip Moeller stated that “demand in 2020 might actually be negative
compared to today.”72 In addition to a recovering economy, the electric industry has a number of
policies that encourage customers to reduce demand. End-use energy efficiency programs,
demand response programs, and demand side management are often subsidized by government
fiat and have common goals: reduce consumer demand, lower electricity prices during peak
times and enhance reliability.73 Although many states have adopted these types of programs,
FERC has taken certain regulatory actions to further incentivize these programs in restructured
markets. For example, FERC adopted Order 745, which required demand response providers to
be paid the full locational marginal price (LMP) to “remove the barriers to the participation of
demand response providers.”74 Although the U.S. Court of Appeals for the District of Columbia
vacated Order 745 in its entirety on May 23, 2014, the Court has delayed action while FERC
considers whether to seek Supreme Court review.
70
Kristi E. Swartz & Rod Kuckro, Declining demand dogs investor-owned utilities, ENERGY WIRE (Jan.
30, 2014).
71
Bernard M. Fox, Investor Beware: Don’t Overestimate Financial Returns in a Restructured Electric
Industry, 136 (11) FORT. 64 (June 1, 1998).
72
Philip Moeller, Comm’r, FERC, Remarks at the Energy Wire Roundtable: Leaders weigh in on electric
power’s transformation (Jan. 27, 2014), http://www.eenews.net/energywire/stories/1059993460.
73
Demand Response, FERC (last updated Oct. 18, 2013), https://www.ferc.gov/industries/electric/indusact/demand-response.asp.
74
FERC Order No. 745, 18 C.F.R. 35 (March 15, 2011), available at
http://www.ferc.gov/EventCalendar/Files/20110315105757-RM10-17-000.pdf.
14
Incentivizing customers to reduce demand below efficient market levels, however,
distorts wholesale markets and artificially lowers market prices.75 In addition, stagnant demand is
particularly bad news in wholesale markets, where generators are already struggling with low
market prices.76
2. Regulator-Imposed Price Caps
In restructured markets, all generators are paid the marginal cost at each location in the
system, meaning the highest priced bid made by a generator that is needed to meet demand in
any hour.77 During high demand or peak periods, prices rise substantially as higher cost
generators are needed to meet load. Because these peak generators may only be needed a few
peak hours each year, prices must be high enough to incent them to stay in business.78
Regulators, concerned with price spikes during peak hours, however, have imposed uniform
price caps on restructured markets.79 These price caps have the effect of distorting market forces
by constraining “prices from rising to their competitive levels under peak demand
contingencies,”80 providing insufficient revenues to keep peak generators operating. Price caps
also hide price signals that would otherwise tell the market that capacity is short and that new
generation investment would be profitable. Nonetheless, regulators consider price caps a vital
consumer protection device. As discussed below, restructured markets are now considering
mechanisms to incent new capacity, such as through capacity markets.
3. Federal Subsidies
75
Brief for Petitioners at 31, EPSA v. FERC, No. 11-1486 (D.C. Cir. Oct. 11, 2013).
Scott DiSavino, New England power grid sees no demand growth over next 10 years, REUTERS (Nov.
8, 2013).
77
ROSS BALDICK, SINGLE CLEARING PRICE IN ELECTRICITY MARKETS 1 (U. Tex. Austin, Feb. 18, 2009).
78
Paul L. Joskow, Capacity payments in imperfect electricity markets: Need and design, 16 UTIL. POL’Y
159, 160 (2008).
79
Id. at 166.
80
Id. at 162.
76
15
Many restructuring advocates argue that “subsidized resources distort the market and
harm customers, and should not be allowed to interfere in competitive markets.”81 Congress,
however, has for many years chosen to incentivize the development of certain resources by
providing subsidies for these resources. In particular, wind production tax credits (PTCs) and
solar investment tax credits (ITCs) have significantly altered the fuel mix within restructured
markets. Wind PTCs and solar ITCs allow these resources to bid into the wholesale markets at
low and sometimes negative prices, “masking the true price of power,”82 and thus artificially
suppressing wholesale prices.83 Otherwise economic resources, such as nuclear power plants,
may prove uneconomic in these distorted wholesale markets, and as a result, may be required to
shut down, as many have already done.84
These subsidized resources are also renewable resources that are variable in nature as
opposed to base load generation, such as natural gas, coal and nuclear generation, which can be
scheduled to run as needed. This situation undoubtedly leads to reliability concerns because
“when the sun is not shining and the wind is not blowing, electricity must still be produced.”85
European countries have faced similar capacity challenges, and the European Union Commission
issued new guidelines that signal an end to subsidies for renewable resources to “meet a demand
by some members states, including France, for extra capacity to be provided by ‘coal and gas
power plants which are flexible enough to be turned on and off whenever needed.’”86
4. Federal Environmental Regulations
81
See Market Principles supra note 61, at 6.
See Rivera-Linares supra note 3.
83
See Comm’r Norris’ testimony supra note 1, at 3-4.
84
Id.
85
EU signals end to high subsidies for renewable energy, EUBUSINESS (Nov. 7, 2013),
http://www.eubusiness.com/news-eu/energy-competition.rap.
86
Id.
82
16
Many recent final and proposed environmental regulations promulgated by the
Environmental Protection Agency (EPA) have caused utilities in both regulated and restructured
states to experience increasing costs, triggering the retirement of many coal-fired power plants.
In particular, the Mercury and Air Toxics Standards (MATS), EPA’s rule regulating mercury and
other air toxics from coal- and oil-fired power plants, and the Clean Power Plan,87 EPA’s
recently proposed rule regulating greenhouse gas emissions in the electric utility industry, have
caused considerable reliability concerns.
EPA estimates that 49 GW of coal generation could retire nationally as a result of its
proposed greenhouse gas rule,88 and in total, EPA’s final and proposed environmental rules
could result in nearly 110 GW of coal generation retirement by 2020, representing nearly 33
percent of existing coal generation and nearly 10 percent of all existing electric generating
capacity.89 FERC Commissioner Philip Moeller, who has been outspoken about the reliability
implications of the MATS rule, recently commented during a House Energy & Power
Subcommittee hearing that “adding new carbon dioxide compliance obligations on top of MATS
creates a complex regulatory environment, the implications of which are not yet understood.”90
Reliability concerns have become particularly significant in restructured markets. Despite
the low cost of natural gas causing coal-fired generation to operate less often, recent final rules
87
Issued under Section 111(d) of the Clean Air Act, the Clean Power Plan establishes state-specific
carbon emissions reduction goals and includes guidelines to direct states in developing implementation
plans. Chris Holly, Interstate power flows raise issue for EPA carbon rule—state officials, The ENERGY
DAILY (Sept. 15, 2014).
88
Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants
and Emission Standards for Modified and Reconstructed Power Plants, EPA (June 2014),
http://www2.epa.gov/sites/production/files/2014-06/documents/20140602ria-clean-power-plan.pdf.
89
Id.; AEO2014 Early Release Overview, EIA (Feb. 2014), available at
http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2014).pdf.
90
FERC Perspectives: Questions Concerning EPA’s Proposed Clean Power Plan and other Grid
Reliability Challenges: Hearing Before the Subcomm. on Energy and Power, 113th Cong. 9 (2014)
(testimony of Philip Moeller, Comm’r, FERC), available at
http://docs.house.gov/meetings/IF/IF03/20140729/102558/HHRG-113-IF03-Wstate-MoellerP20140729.pdf.
17
and additional impending rules “change the economics of placing a power plant in reserve for
emergencies, as compared to removing it entirely from the system.”91 Due to existing flaws in
market price formation, market prices have made it “uneconomic to upgrade older, less efficient
plants to meet increasingly strict federal and state environmental rules,”92 generation that is
essential to maintaining reliability. For example, one of New England’s few remaining coal-fired
power plants, and the only coal-fired power plant left in Connecticut, is on “shaky ground
financially,” according to a report predicting its “inevitable” retirement.93 Oil- and coal-fired
generation produced as much as 35 percent of New England’s electricity during last winter’s
extreme weather, compared to less than four percent normally, highlighting the significant
reliability implications facing the region once these plants retire and can no longer provide backup generation.94 This winter may be no better, as National Grid has said that because of higher
gas prices and pipeline constraints, customers in Massachusetts are likely to see a 37 percent
increase in electric bills this winter.95
Many stakeholders anticipate that these environmental rules will require “a complete
redesign of markets” in order to accommodate switching electric markets to dispatch generation
based on environmental considerations instead of the current system based on price
considerations.96 This move will also significantly increase reliance on natural gas generation,
which could lead to additional reliability implications due to current challenges with expanding
91
Evaluating the Role of FERC in a Changing Energy Landscape: Hearing Before the Subcomm. on
Energy and Power, 113th Cong. 4 (2013) (testimony of Philip Moeller, Comm’r, FERC), available at
http://www.ferc.gov/CalendarFiles/20131205094226-Moeller-12-05-2013.pdf.
92
See DiSavino supra note 76.
93
Manuel Quinones, Report questions economic health of Conn.’s last coal-fired power plant, E&E
NEWS PM (Jan. 23, 2014).
94
Daniel Acker, New England’s governors push for electricity tariff for construction of natural gas lines,
BLOOMBERG (Jan. 24, 2014).
95
Jack Newsham, Electric bills heading up this winter, THE BOSTON GLOBE (Sept. 25, 2014).
96
Katherine Ling, Grid reliability is among many FERC concerns about EPA carbon proposal –
testimony, E&E DAILY (July 29, 2014).
18
natural gas pipeline infrastructure in restructured markets. In addition, since electricity markets
are interstate in nature, the Clean Power Plan’s “state-by-state approach results in an
enforcement regime that would be awkward at best, and potentially very inefficient and
expensive.”97
The Midcontinent Independent System Operator (MISO), a region heavily reliant on
coal-fired generation, previously projected that its region will be short of capacity by 2016, with
a planning reserve margin of only seven percent by 2016, compared to the 14.8 percent that
MISO considers a minimum reserve margin in order to maintain system reliability. 98 A 2013
survey of MISO market participants “confirmed previous studies showing how retirements of
coal-fired plants resulting from implementation of the Mercury and Air Toxics Standards would
affect resource adequacy in the upper Midwest.”99 MISO recently released a report that showed
that EPA’s carbon emissions proposal could put an additional 14,000 MW of coal capacity at
risk of retirement.100 Clair Moeller, MISO’s transmission and technology supervisor, recently
stated that MISO is “concerned as we move through the next tranche of environmental
regulations [and] expect this tight capacity situation to persist for a long time . . . causing us to
relook at some of our rules.”101 As reserve margins have tightened, generators have pushed
FERC and MISO to encourage new generation by enacting mandatory capacity auctions,
allowing additional payments to generators to secure supply commitments sufficient to meet
future demand.102
See Comm’r Moeller testimony supra note 90, at 2.
Mark Watson, MISO’s existing footprint to be short of power by 2016: survey, PLATTS (Dec. 5, 2013).
99
Id.
100
Hannah Northey, EPA rules for coal-fired power threaten Midwest reliability – grid operator,
GREENWIRE (Sept. 19, 2014).
101
Id.
102
Jeff Beattie, MISO reserve margin to plummet by 2016 – Midwest officials, THE ENERGY DAILY (Sept.
19, 2014).
97
98
19
5. State Environmental Policies
Similarly, many states have implemented environmental policies that have furthered the
demise of important base load generation. Over 35 states have adopted renewable
portfolio/energy standards, which require a certain percentage of electricity generation to come
from renewable sources.103 California, for example, adopted a rigorous renewable portfolio
standard that requires 33 percent of electricity to come from renewable sources by 2020.104 In
addition, over 20 states have adopted greenhouse gas targets.105 These environmental policies
essentially require utilities to rely more heavily on lower- or zero-carbon-emitting fuels, such as
renewables, and cause base load generation, such as coal-fired power plants, to become obsolete.
6. Disconnect Between Wholesale and Retail Prices
While wholesale prices in restructured markets are set by market forces, retail prices
faced by electric consumers may or may not reflect these market prices. This disconnect between
wholesale and retail prices creates a problem for the power seller in that it faces very volatile
prices that the consumer may not respond to. Again, the result is market distortion. While
customers in regulated markets may face this same disconnect, regulators work to align rates
with the cost of service as much as possible.
While competitive markets require all resources to be able to compete on a level playing
field, these externalities distort markets and essentially choose “winners” and “losers.”106 Natural
gas and renewables have proven to be the clear market winners, exposing customers to the
103
Overview Presentation: Clean Air Act and Upcoming Carbon Pollution Guidelines for Existing
Sources, EPA, http://www2.epa.gov/carbon-pollution-standards/what-epa-doing#overview (last updated
Sept. 23, 2013).
104
California Commission Docket No. 11-12-020 (Dec. 1, 2011).
105
See EPA Overview Presentation supra note 103.
106
See Market Principles supra note 61.
20
increased risks of relying on a less diverse fuel mix.107 Moreover, the fact that new base load
generation is not being built to replace retiring base load generation leads to additional reliability
concerns.108
C.
Can Restructured Markets Be Fixed?
The problems of matching future (long-term) supply with demand in restructured markets
are well-known, both to the restructured markets and to FERC, and numerous attempts are being
made to correct these problems in piecemeal fashion. One approach is the development of
capacity markets, used by PJM, New York ISO and ISO New England, in which the RTO/ISO
conducts capacity auctions each year to ensure adequate supply for three years in the future.109
The RTO/ISO determines the lowest cost set of resources needed for the target year, and each
accepted bid receives the highest accepted offer, the single capacity market price. Capacity
market generators receive periodic payments for providing “reliable capacity” to the system.110
Other RTOs/ISOs, such as MISO, are energy-only markets, relying solely on energy market
prices to attract new investment.111 This limited focus on the short-term and cost in both
approaches ignores considerations important to reliability, such as resource dispatchability and
fuel diversity, which are becoming increasingly important concerns. Many proposals have been
made to fix RTOs to ensure resources adequacy, and FERC is currently conducting a proceeding
to examine the issue. FERC Commissioner Moeller recently commented that the “flaws in
existing price formation were greatly exposed during last winter’s Polar Vortex events . . . [and]
107
See Chesto supra note 2.
See Luther Turmelle, Report: Power plant retirements in New England may create problems, NEW
HAVEN REGISTER (Dec. 4, 2013).
109
See Navigant supra note 20, at 37.
110
Id. at 36. See generally Timothy Mount, Problems with Capacity Markets: Why are Customers Paying
so Much and Getting so Little in Return? (Am. Pub. Power Assoc. 2007) (identifying challenges in
capacity markets).
111
See Navigant supra note 20, at 36.
108
21
the Commission has begun an overdue and extensive project to examine ways to improve price
formation at the wholesale level.”112 In its study of 2013 capacity additions, APPA points to the
central flaw of mandatory capacity markets as their inability to support long-term financial
arrangements needed to construct power plants.113 However, it is at best unclear whether any of
the current efforts will be sufficient to correct the fundamental problems of electric markets: that
electricity is not a commodity; it has important social and environmental dimensions associated
with it; and it will continue to be the focus of government oversight and interference. The
question becomes whether the alternative, fully regulated markets, provides a better model.
IV.
Regulation Provides a Superior Business Model to Restructuring
In light of the inadequacies of wholesale electricity markets, restructured markets lack the
proper incentives to achieve efficient market-based outcomes and fail to provide a sustainable
business model. Electricity regulation, however, offers the comprehensive approach to
generation planning and financial stability necessary to sustainably provide reliable and
affordable electricity to American consumers.
A.
Comprehensive Generation Planning
Recent changes in the energy landscape “underscore the speed with which a seemingly
oversupplied market can become short of capacity” and highlight the critical importance of
taking a comprehensive approach to generation planning to ensure that sufficient capacity will be
available to meet future demand.114 Therefore, a central benefit of electricity regulation is the
utility’s ability to take a comprehensive approach to generation planning, ensuring a diverse
generation portfolio that mitigates the risks of relying on a less diverse fleet.
See Comm’r Moeller testimony supra note 90, at 7.
See APPA supra note 18, at 6.
114
See Turmelle supra note 108.
112
113
22
Regulators created Integrated Resource Planning (IRP) processes in the 1980’s in an
attempt to avoid the mistakes made in the 1970’s.115 IRPs are “comprehensive planning
process[es] designed to provide insight into how a utility may best meet its resource needs over a
long-term (10-20 year) planning horizon while considering all resource options and a range of
risks and uncertainties that are inherent in the utility industry.”116 These processes consider
multiple factors, including resource dispatchability and the optimal mix of resources taking into
account transmission and other costs.117 Periodic reviews, typically every two to five years, also
provide for updates that reflect changing conditions.118 Moreover, the IRP process typically
involves public and other stakeholder involvement.119 IRPs provide incredible benefits to
customers because state regulators are able to take into account all factors, short- and long-term,
affecting reliability and affordability.
Although states differ, many restructured states either repealed their IRP processes or
began to ignore them during restructuring.120 RTOs and ISOs rely solely on competitive energy
(and sometimes capacity) markets for attracting sufficient generation to meet future demand.
While competition generally has many good virtues, it typically results (without regulatory
intervention) in cost and pricing considerations alone. It does not, for example, value diversity in
its energy mix.
“Having a diverse energy mix is key to a society surviving changes in demographics,
government, geologic processes and natural disasters, supply disruption during war and extreme
115
See Navigant supra note 20, at 9.
Id. at note 222.
117
Id. at 26, 61 (identifying six variables considered when making generation decisions).
118
Id.
119
Id. at note 222.
120
Id. at 61.
116
23
weather conditions.”121 During last winter’s polar vortex, for example, nuclear and wind
generation “stepped up to the plate to relieve natural gas and coal when they failed to deliver on
demand.”122 Maintaining a diverse generation portfolio also mitigates the risk of volatile fuel
prices. The IRP process in regulated states recognizes the importance of maintaining a diverse
mix of generation in order to spread risk among multiple resources.123
As previously discussed, numerous externalities in the market have caused some coalfired and nuclear base load generation to be uneconomic in wholesale markets, causing these
markets to become increasingly reliant on natural gas and renewable resources, and many parts
of the country are now beginning to see the risks of becoming too dependent on limited
resources. New York, New England and the mid-Atlantic, for example, are increasingly reliant
on natural gas; however, the “region is at the end of major interstate natural gas pipelines, which
makes it vulnerable to price spikes when gas supplies are strained.”124 Pipeline customers that
contract for firm capacity receive it first, release capacity if they do not need it, and power
generators are then able to buy spare capacity at a discount.125 Therefore, on “cold days, the
natural gas pipelines are filled to capacity, but power plants [that do not hold contracts for firm
capacity] that normally rely on that gas get bypassed . . . [and] to keep the lights on, more
expensive gas is imported from Canada, and rarely used oil and coal turbines are fired up.”126
James Conca, Polar Vortex – Nuclear Saves the Day, FORBES (Jan. 12, 2014),
http://www.forbes.com/sites/jamesconca/2014/01/12/polar-vortex-nuclear-saves-the-day/.
122
Id.
123
See Chesto supra note 2.
124
Hannah Northey, FERC eases price cap in PJM amid unprecedented gas price spikes, GREENWIRE
(Jan. 27, 2014).
125
See Kuckro supra note 7.
126
See Acker supra note 94.
121
24
When “natural gas prices spike, so does the cost of making electricity,” leading to higher
electricity rates for customers.127 In fact, FERC granted PJM Interconnection’s request to waive
the $1,000-per-megawatt-hour (MWh) price cap on power from gas-fired generation due to the
“unprecedented spikes in fuel costs caused by recurring extreme cold weather events.”128 As gas
prices skyrocketed, the cost to produce electricity soared to around $1,200 per MWh, and
generators were unable to cover the difference between the cost of generating power and the
market price.129 As a result, customers were exposed to “stiff increases in their electrical
bills.”130
B.
Adequate Investment in Generation
In a capital-intensive industry, such as the electric industry, in which capital represents
roughly two-thirds of the cost of generation and nearly all of the cost of transmission, providing
electric producers with financial stability is critical for ensuring that investment in generation is
not neglected.131 Electricity regulation guarantees this necessary stability by providing regulated
utilities with a means of recovering their investments plus a fair return through retail rates,
ensuring that sufficient generation will be built to meet future demand.
Restructuring advocates argue that customers should not bear the risk of poor investments
through retail rates;132 however, the ultimate risk to customers is that sufficient generation will
not be available to provide reliable electricity without exposing them to highly volatile rates. In
127
Larry Rulison, National Grid customers getting a break on bills, ALBANY TIMES UNION (Jan. 30,
2014), http://www.timesunion.com/business/article/National-Grid-customers-getting-a-break-on-bills5187704.php.
128
See Northey supra note 124.
129
Id.
130
See Rulison supra note 127.
131
SETH B. BLUMSACK ET AL., LESSONS FROM THE FAILURE OF U.S. ELECTRICITY RESTRUCTURING 10
(Carnegie Mellon U. 2006).
132
About COMPETE: Competition in Competitive Markets, COMPETE COAL. (last visited Feb 2, 2014),
http://www.competecoalition.com/about.
25
fact, investors in restructured markets, subject to market uncertainties and already low revenue
margins, have been hesitant to invest in base load generation in wholesale markets, exposing
customers to the risk of short- and long-term capacity shortfalls and highly volatile prices when
supply is tight.133 Further, when they do invest in restructured markets, investors must seek
higher returns to reflect the higher risk, ultimately increasing costs to consumers. Despite the
need for new base load generation in many restructured markets, FERC Commissioner John
Norris recognized that “with the exception of building [generation] in a vertically integrated state
where state regulation of generation provides a reasonable assurance of cost recovery, it seems
unlikely that new coal or nuclear facilities will be constructed in the foreseeable future.”134
Facing similar “growing worries about its future power supplies, with supply falling and
prices rising . . . thanks to years of neglect and underinvestment,” Great Britain announced a $26
billion deal to build a new nuclear power plant with two state-backed Chinese companies
“reduc[ing] the investment risk.”135 Many commentators view this action as a “move that reaches
[back] . . . to an earlier time when Britain and many other Western countries did not assume that
their national energy needs would be served by market forces,” a signal that “the free market no
longer served the national interest.”136 As Great Britain’s electricity market structure served as
the global model for electricity restructuring, particularly in the United States, Great Britain’s
recent actions provide a warning to U.S. regulators of the serious shortcoming of restructured
electricity markets.137
1. Low-Risk Investments
133
See Beattie supra note 9.
See Comm’r Norris’ testimony supra note 1, at 6.
135
Stanley Reed & Stephen Castle, Deal to Build a British Nuclear Plant Assumes a Role for
Government, N.Y. TIMES (Oct. 21, 2013).
136
Id.
137
See Yergin supra note 42, at 386.
134
26
In a capital-intensive industry, providing regulated utilities with a means of recovering
their investments through retail rates is essential for attracting low-cost capital.138 Because these
investments are considered low risk, regulated utilities have greater access to low-cost capital
compared to investments in restructured markets, allowing regulated utilities to build cheaper
generation and passing these cost savings on to consumers.139 Restructuring advocates argue that
regulated utilities, however, have no incentive to prevent cost overruns and project delays
because costs are ultimately passed through to customers;140 however, any excess costs must be
approved by state regulators in order to be added to rate-base, and state “rate regulators do not
like to raise rates, particularly residential rates, because of the political fallout that always
occurs.”141 Moreover, if excess costs are not added to rate-base, these costs directly impact the
company’s bottom-line, which could affect the company’s credit rating and access to low-cost
capital in the future.142 Regulators in many states have also designed new ways to provide proper
incentives to utilities, such as incentive rates or cost caps. Regulated utilities, therefore, have
great incentives to meet project budgets and schedules.
Conversely, investors are more hesitant to invest in high-risk projects with little certainty
of recovering investment costs.143 Generation investments in restructured markets are now
viewed as project-finance investments, “meaning that the revenues from the investment are the
sole source of capital-cost recovery.”144 These investments are financed primarily on debt, and
are thus significantly more risky than “system financing” in regulated markets, and lenders,
138
See Blumsack supra note 131.
Id.
140
See About COMPETE supra note 132.
141
See Kelly supra note 27.
142
Scott DiSavino, Southern boosts cost, delays Mississippi Kemper coal plant start, REUTERS (Oct. 30,
2013).
143
See Lave supra note 22, at 19.
144
See Blumsack supra note 131.
139
27
therefore, require much higher interest rates for these investments.145 Project-finance, in addition,
takes considerably more time due to the complexities of securing the financing and negotiating
contracts with the various parties involved.146 As a result, generators in restructured markets do
not have access to the same low-cost capital available to regulated utilities, making new plant
and equipment more expensive and raising total costs significantly.147
In addition, federal oversight and enforcement of competitive markets have raised
operating costs and risks of noncompliance for market participants.148 FERC has issued more
than $1 billion in fines for alleged market manipulation, and this “increased enforcement activity
has pushed some big players out of the power markets, especially banks that provided much
needed liquidity.”149 One merchant generator opined that as a result of increased risk, “‘we really
need to start seeing some structural improvement’ before the company will consider further
investment.”150
2. Adequate Returns on Investments
Regulated utilities are allowed to earn a fair rate of return to incentivize adequate
investment. In restructured wholesale markets, on the other hand, market participants stress that
“this is an industry that is not making money . . . [and] if your returns are less than your average
weighted cost of capital, you are in trouble. And that’s where the industry – overall – is.”151 A
number of factors, such as abundant natural gas that has lowered fuel prices, subsidies for
145
Id.
E.R. YESCOMBE, PRINCIPLES OF PROJECT FINANCE 33 (Academic Press, 2d ed. 2014).
147
See Lave supra note 22, at 19.
148
See O’Grady supra note 8.
149
Id.
150
Id.
151
Id.
146
28
renewables, and “outdated market rules, have squeezed profits for merchant power generators –
all but eliminating prospects for new investment.”152
On top of already suppressed market prices, the heavy reliance on natural gas in
restructured markets has reduced revenue margins. In restructured markets, generators bid into
the market at their marginal cost, and all accepted bids receive the “market-clearing price,” the
“offer price of the highest accepted offer in the market.”153 The market-clearing price provides
incentives for efficient dispatch and optimal investment, meaning “demand is served by
resources whose total fuel bill is the lowest possible . . . [and] the right technologies are built in
the right places at the right time.”154 As a result, generators have an incentive to provide the
least-costly electricity to obtain greater revenue margins between the market-clearing price and
the generator’s bid. With a diverse fuel mix, the market-clearing price provides these greater
revenue margins because generators’ bids vary depending on resource; however, in markets that
rely primarily on natural gas, the majority of accepted bids are natural gas generators that have
bid into the market at similar prices, and thus, the revenue margin for these generators is greatly
reduced.
Investors have been hesitant to invest in high-risk, low-return projects in restructured
markets, raising concerns that markets fail to provide adequate incentives for generation
development, and particularly for development of base load generation. U.S. restructured
markets appear to be quickly following in Great Britain’s footsteps, facing a “looming energy
crisis in this decade thanks to years of neglect and underinvestment.”155
C.
Adequate Investment in Pipeline Infrastructure
152
Id.
See Baldick supra note 77.
154
Id.
155
See Reed supra note 135.
153
29
The vulnerability of natural gas price volatility because of inadequate pipeline capacity
raises an additional long-term concern in restructured markets: who pays for the additional gas
pipeline infrastructure that is needed to secure supply to generators in areas with tight
capacity?156 Natural gas pipelines “build new capacity for the express needs of their shippers . . .
so it is up to the customers to decide how much reliability and flexibility they want.”157
The “vertically integrated model allows for a very orderly process of addressing and
funding these needs” through a long-term planning process and permitting utilities to recover the
cost of firm service.158 For example, Florida regulators approved plans for a new two-section,
591-mile pipeline in the Southeast, from Southwest Alabama through Georgia to Central Florida,
with Florida Power & Light contracting to buy almost half of the firm capacity.159 In response to
the proposal, one Florida state regulator “praised the project as helping the state’s fuel diversity
by reducing the chance of supply interruptions . . . and achiev[ing] that mitigation against price
fluctuations.”160
Similar project proposals in restructured markets, however, have not been as successful.
The proposed expansion of Spectra Energy’s Algonquin pipeline into the Northeast provides one
such example. Spectra Energy cited a “lack of incentives in the electric market design for the
generators to procure firm pipeline capacity that supports infrastructure development in the first
place.”161 Currently, 80 to 90 percent of gas-fired power plants in PJM, for example, rely on
156
Teresa Hanse, Transmission Grows Despite Hurdles, ELECTRIC LIGHT & POWER (Nov. 14, 2013).
NAVIGANT CONSULTING, NG MARKET NOTES - LOW PRICES, CSPAR REJECTION, RELIABILITY
DIALOGUES: WHERE DOES GAS-FIRED GENERATION GO FROM HERE? 4 (2012), available at
http://www.navigant.com/insights/library/energy/2012/natural_gas/ng-market-notes-sep2012/.
158
Id.
159
Jim Turner, FPL pipeline: Florida Power & Light to invest in new 600-mile natural gas pipeline,
WPTV (Oct. 25, 2013) (purchasing 400 million cubic feet of the total 1 billion cubic feet).
160
Id.
161
Letter from William T. Yardley, Algonquin Gas Transmission, to Gordon van Welie, President &
CEO, ISO New England Inc. (Sept. 18, 2012), available at http://www.iso157
30
“non-firm” spot market gas.162 It is unlikely that generators will contract for long-term firm
capacity (10-, 12-, 15-, 20-year firm transportation contracts) because generators do not have a
means to recover the cost of firm capacity and do not even know if they will be in operation a
few years into the future.163 In response to the challenges of constructing pipeline infrastructure
in the Northeast, New England’s governors requested that ISO-New England impose a market
tariff that would get passed down to ratepayers to help finance new pipeline infrastructure,164 a
proposal closely resembling the ratemaking process in regulated markets. FERC Commissioner
Moeller recently opined that he is “concern[ed] that this challenge of financing adequate pipeline
infrastructure in New England will be replicated in other markets . . . [and] we haven’t yet found
solutions to the New England situation.”165
D.
Stable Retail Rates
Unlike typical commodities, electricity customers do not have a substitute they can buy
when supply is tight; they are forced to pay astronomical prices or curtail electricity service.
Thus, customers have limited means to handle electricity price volatility. Under electricity
regulation, customers typically pay a price for electricity that is averaged over a certain time
period, “ignoring the low generation and transmission costs when demand is low as well as the
high costs when demand is high.”166 These stable rates provide reliable electricity without
exposing customers to the risks of volatile prices.
ne.com/committees/comm_wkgrps/strategic_planning_discussion/materials/agt_and_spctr_comm_on_iso
_ne_addrs_gas_dep_drft_paper.pdf.
162
See Northey supra note 124.
163
See Kuckro supra note 7 (ISO’s forward capacity market, for example, is only a three-year
commitment.).
164
See Acker supra note 94.
165
See Comm’r Moeller testimony supra note 90, at 4.
166
See Lave supra note 22, at 22.
31
In restructured markets, consumers may have the ability to contract for service at a fixed
price, or they may choose to be exposed to market prices. In theory, higher retail rates would
cause consumers to use less electricity, flattening the “load-duration curve to the point where
there would be substantially less demand for peak generating units and the wholesale price of
power would be constrained to much lower levels than we have seen in the past.”167
However, consumer price volatility and even price volatility to suppliers who offer fixed
prices to customers have recently come under the spotlight. Politicians all across the Northeast
have raised complaints and requested investigations over the price spikes that occurred due to the
polar vortex. In light of these challenges, federal and state regulators have begun proposing
solutions that will defer or postpone these additional costs to customers, solutions
acknowledging consumers’ inability to handle the price volatility of these markets and closely
resembling regulatory actions in regulated markets. For example, National Grid of New York,
“fearing that customers wouldn’t be able to handle another month of stiff increases in their
electrical bills,” plans to offer customers $32 million in bill credits to offset the expected $30 bill
increase for February.168 In an unusual decision by state regulators, National Grid was granted
special permission to recover the money from ratepayers over time.169 Similarly, a number of
factors have caused retail rates in New Jersey to increase significantly, and the state has tried to
contain these increasing rates “by blending power costs over three years, a system that has
lowered utility bills when energy bills are rising, but has failed to deliver savings when fuel costs
are dropping.”170
V.
Conclusion
167
Id.
See Rulison supra note 127.
169
Id.
170
Tom Johnson, The Explainer: Factors Driving Electricity Prices in New Jersey, N.J. SPOTLIGHT (Dec.
3, 2013).
168
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“In short, this appears to be no ordinary time in the world of energy and its regulation.”171
Although the entire industry is facing new challenges as a result of a rapidly changing energy
landscape, competitive market structures have made these changing dynamics even more
prominent. Inevitable government intervention has distorted restructured markets, causing these
markets to provide inadequate incentives to achieve efficient market-based outcomes. Otherwise
economic resources, such as coal-fired and nuclear power plants, prove uneconomic in these
distorted restructured markets, and as a result of this and other factors, many are now scheduled
to retire. At the same time that new base load generation is needed to replace retiring generation,
new investment in generation is unlikely due to unstable market conditions and already low
profit margins. As a result, many parts of the country are now facing short- and long-term
capacity shortfalls.
Market structures and environmental regulations have also resulted in a less diverse
generation mix in competitive markets, exposing customers to highly volatile fuel costs, and
customers, particularly in the Northeast, have recently seen their retail rates skyrocket in tandem
with the price of natural gas. Moreover, customers in restructured markets are facing rising retail
rates as huge transmission and pipeline infrastructure investments are being made to integrate
greater amounts of renewable generation onto the grid and to secure adequate and firm supplies
of low-cost gas in regions with tight capacity.
To resolve these issues of tight supply, low margins and rising retail rates, FERC appears
eager to layer on additional market rules, but it remains unclear how FERC will actually
accomplish these goals without further distorting the market. In light of these challenging
circumstances that have significant implications for current electricity rates and reliability,
171
See Comm’r Clark’s testimony supra note 3, at 6.
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regulators should acknowledge the shortcomings of restructured electricity markets and seriously
reconsider the benefits that electricity regulation provides.
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