Deregulation or, as it should be more properly called, restructuring of U.S. power
markets was supposed to induce greater efficiencies and reduce prices to consumers.
Restructuring should also foster greater innovation and investor confidence for
much-needed new infrastructure development.
Yet the U.S. transition to competitive wholesale power markets has stalled
(see Figures 1 and 2). Indeed, many states are retreating from restructuring,
and the Federal Energy Regulatory Commission (FERC), the Securities and Exchange
Commission, and politicians continue their vigorous investigations into trading
and accounting practices.
To some, the goals of restructuring probably remain frustratingly elusive,
and their concern may be justified. This paper will explore why credit risks
are likely to remain high in the power markets long after the current set of
concerns are resolved. We also believe raising capital will remain difficult
for the long-term.
Already, widening credit spreads and equity prices that have fallen to multi-year
lows have sent investors fleeing from the sector. And credit risk is continuing
to intensify in the face of continuing regulatory and political uncertainty
and declining market fundamentals.
Investors may find that generation assets, particularly new construction, are
at risk of becoming partially stranded investments if they cannot access their
intended markets or simply cannot transact as intended because of inadequate
Partial restructuring has created dysfunctional wholesale electricity markets.
This situation is largely attributable to two problems. One, the United States
has a transmission system that largely isn’t designed to operate in competitive
markets. Many markets allocate transmission usage using non-market-based means
while generation tries to operate competitively. In such a market, the premise
of investments may prove wrong and investors may find themselves at risk of
a credit surprise.
Second, only about one-third of the U.S. generation fleet operates in a competitive
environment; the rest still operates within the complacency of cost-of-service,
rate-of-return environments. That means where merchant power plants operate
along side of utility-owned generation, an uneven playing field exits.
The industry of competitive generation has suffered an unprecedented downward
credit spiral this year with very few investment-grade players remaining and
some on the verge of bankruptcy. The power industry’s recent boom, which inflated
asset price values beyond which normal markets could hope to sustain, led many
lenders to overvalue the collateral upon which they loaned capital.
The resulting cheap credit led energy merchant companies to aggressive borrowing
and high leverage. Most borrowing and lending relied upon two key assumptions
that didn’t materialize: first, competition and deregulation would spread quickly
and widely; and second, older coal-fired and nuclear power plants would permanently
Now, amidst the industry’s poor fundamentals, weak power prices and surplus
generation capacity, expectations are growing for a record number of defaults.
Already lenders have suffered defaults of bank loans and capital markets bonds.
Still, billions more in loans have become problem loans a signal that
likely portends more defaults to come and threatens the entire business model
of competitive power.
Despite transitional problems, expect restructuring to forge ahead. As some
unknown cowboy philosopher said, “It is easier to let the cat out of the bag
than to put it back in.” So it goes for deregulation and restructuring.
Major markets, mainly New England, New York, Pennsylvania-New Jersey-Maryland
(PJM), and Texas, are well into restructuring and aren’t turning back. Moreover,
the industry’s turmoil has neither completely consumed nor paralyzed FERC. FERC
is moving forward with restructuring as evidenced by the tremendous scope of
its standardized wholesale market design (SMD) proposal.
According to FERC Commissioner Nora Brownell, who spoke at a Standard & Poor’s
co-sponsored conference in New York, “The cost of doing nothing is greater than
the cost of doing something.” Brownell also stated that the vulnerability of
the entire market terrifies FERC and that the reality is that the current electricity
infrastructure will not support economic growth in the United States.
As FERC presses ahead with electricity reform, we’ve cautioned investors that
deregulation will not follow the paths of other restructured industries either
in the United States or abroad. Electricity is a unique commodity, if indeed
it can be called a commodity, and because of its differences, credit surprises
could be in the making, particularly if restructuring does not progress beyond
its stalled state. Certainly against the wave of defaults, eminent defaults,
and regulatory and political uncertainty, the industry may be hard-pressed to
raise capital for new investment that may be needed in a few years.
What Distinguishes Electricity
It would surprise few that restructuring the U.S. electricity market and introducing
competition has been difficult. For one, electricity is like no other commodity,
including traded financial securities or oil and gas. That means attempts to
draw analogies to the economic and physical behavior of common commodities,
such as oil and gas, metals, agricultural products, and financial products,
may come up short. Many rules that apply in these markets break down in electricity
markets, making the analysis of competitive electricity investment and credit
a thorny task. Consider the following:
Electricity is extremely capital-intensive. The generation of the first
electron from a power plant can cost hundreds of millions of dollars.
Electricity cannot be stored in any meaningful amounts. As a result,
some power plants rarely operate, while some run continuously.
Electricity has a unique nondirectional aspect of transport. Somewhat
like air pollution, it follows the rules of physics and not those of various
jurisdictions or marketers.
A powerful inelastic demand quality of electricity governs consumer behavior.
There just are not viable substitutes for it.
The current industry structure largely provides no real-time means to
adjust consumer demand based on price.
Weather heavily influences day-to-day and hour-by-hour demand and, in
some markets, notably the hydro-rich Pacific Northwest, available supply.
Electricity prices can exhibit extreme volatility at times because of
the above qualities, because its value to consumers changes hourly, and because
transmission availability can restrict power flows.
Few commodities can incite the heated national, regional, and local debates
that electricity restructuring seems to inspire.
The marginal cost of production drives the price of power down, except
during shortages, to levels that often fall short of capital recovery needs.
Such characteristics, particularly volatility, potentially turn what might
be a small credit concern in a functional market into a much bigger credit problem
in a partially deregulated environment. For example, a generator with an all-requirements
contract that cannot access transmission during a congestion period may find
itself paying a fortune in replacement power to satisfy contractual obligations
to its seller.
Figure 1: Status of Electricity Restructuring February 2001 Source:
Coordination and Reliability
Electricity has another unique characteristic that complicates restructuring:
coordination. At all times, aggregate supply and demand must operate in equilibrium;
a system cannot generate more or less electricity than demand or else the system
shorts out. But the coordination function is not something left to the markets.
Utilities once closely coordinated their own generation and transmission investment
and operations through central dispatch and planning processes. In a competitive
market, utilities don’t necessarily own all, or any, of the generation and transmission
assets that service their franchise areas.
Now, according to the North American Electric Reliability Council, that coordination
and reliability task, which once provided the most reliable system in the world,
is being done by various means and numerous market participants, including energy
marketing and trading companies.
Reliability is a catchall term that the industry uses to measure the performance
of the bulk power system that delivers electricity to consumers when they want
it and in the amounts they need. It considers the performance of generation,
transmission, and distribution systems by measuring the frequency, magnitude,
and duration of adverse effects of the system, such as blackouts. A key component
of reliability is transmission.
An “incomplete transition to fair and efficient competitive wholesale markets”
has exacerbated transmission problems, according to the Department of Energy
in its May 2002 National Transmission Grid Study. The evidence is compelling.
Transmission loading relief actions (TLRs) are up incidents where transmission
congestion prevents market-based transactions from occurring.
Frequent TLRs indicate that efficient generation may be curtailed and that
load-serving entities (distribution companies) have to pay more than is necessary
for electricity. FERC has observed instances where congestion causes the price
of power in one region to be higher than surrounding regions at the same time.
In two relatively well-functioning markets, New York and PJM, FERC estimates
that transmission-related congestion problems cost consumers about $2 billion
in 2000. In New York alone during the summer of 2000, the estimated cost was
about $700 million. Blackouts in California during 2000 and 2001 and unprecedented
high electricity prices throughout the western states also evidence an incomplete
During the first half of the 1900s, power engineers designed the current transmission
hub-and-spoke systems for vertically integrated utilities that serviced their
own franchise territories. Central coordination of generation and transmission
worked well in that environment where ratepayers could absorb the costs of inefficient,
albeit effective, operations.
However, competitive trading and marketing of power requires transmission to
move power in varying amounts and in different directions throughout the day.
These patterns significantly differ from patterns contemplated when transmission
was built. Without that capability, it is difficult to see how deep and liquid
power markets will develop, regionally or nationally.
That suggests that trading and marketing companies may be riskier than measures
of value-at-risk suggest. Moreover, calculations of mark-to-market would be
suspect if transmission were not “competitive-capable” (could wash trades be
an unintended consequence of partial restructuring?). Consider the folly of
building a just-in-time manufacturing plant with no ability to store production
and which could not rely on trucks and highways to move goods.
Figure 2: Status of Electricity Restructuring March 2002 Source:
What FERC Is Doing
The California debacle and the Enron bankruptcy have strengthened FERC’s restructuring
resolve. FERC and others have acknowledged that a lack of a standardized wholesale
market design is impeding development of a well-functioning wholesale market.
FERC wants a wholesale market that recognizes real physical differences in regional
markets, but with a single tariff design.
The commission opened the way for competitive wholesale power through FERC
Orders 888 and 889. FERC Order 2000 continued restructuring by encouraging the
transition from more than 140 control areas to the development of four to five
regional transmission organizations. The United States Supreme Court recently
strengthened prior FERC orders by affirming open access for independent power
and traders to utilities’ transmission lines. FERC’s proposed standardized wholesale
market design is the next step.
FERC stated that it wants to establish a common market framework within which
all customers can benefit from an efficient and well-operating competitive wholesale
market, regardless of the state of retail access. FERC seeks to develop standard
rules and a uniform tariff and require that transmission systems operate independently
of the market participants they serve.
A standard market design would provide a system that generates price signals
that reflect the temporal and locational value of electricity transmission
congestion pricing. And finally, the SMD would reflect regional characteristics,
such as the generation and fuel mix and use patterns.
Gaining consensus among industry participants and stakeholders will be a major
challenge for FERC. In fact, since issuing the SMD Notice of Proposed Rulemaking
(NOPR), FERC has had to acknowledge that there will have to be regional differences
in how markets are designed. That said, many states and their regulators are
firmly opposed to the SMD NOPR.
Unlike electricity industries in other countries, the U.S. electricity industry
operates in a complicated regulatory setting, which is frustrating FERC’s efforts.
In addition to FERC at the national level, 50 states and many municipalities
also regulate the industry. Nonprofit entities alone own about 30 percent of
the industry, while the investor-owned utilities, independent power companies,
and energy merchants own the remaining 70 percent. About 25 percent of the industry
sits outside of FERC’s authority.
Transmission-Related Credit Risks
According to FERC and others, a transmission system that cannot meet competitive
wholesale electricity market needs could be causing any one of a number of problems:
In markets with bilateral contracts between sellers and buyers (which
includes most markets), a non-price allocation of capacity creates congestion
during peak times, which means that some sellers and buyers are curtailed and
prevented from transacting in the market.
Systems that manage congestion based upon non-economic systems hide price
signals that tell investors where to build generation and transmission assets.
Therefore, a risk exists that either investments get built in the wrong locations
or they do not get built at all.
Market congestion is likely contributing to illiquid markets, which hinders
the development of efficient (and perhaps profitable) trading and marketing.
In some markets where they own both generation and transmission, utilities
have incentives to discriminate against merchant generators in providing transmission
Adjoining regions with different regulations, computer systems, market
rules, software, and reliability objectives will impede trade and introduce
economic inefficiencies in a way not dissimilar to international trade barriers
(referred to as a seams problem). In extreme cases they may give rise to gaming
incentives with names such as Fat Boy, Ricochet, and the like, which were popularized
by Enron traders.
FERC’s implementation of a standard market design could drag on for years.
Utilities with low-cost operations will be challenged to find an upside in embracing
competition and connecting with larger markets that could raise costs to their
customers. Their regulators may see little benefit to the local markets in participating
in regional transmission projects where multiple jurisdictions are involved.
Although some “low cost” utilities may find that their low costs are transitory
if environmental compliance raises their cost of generation, politicians will
be quick to resist any restructuring that carries a risk of increased retail
rates for their constituents.
The Dual-Universe of Generation
Except for certain pockets, such as in the New York City area, Boston, San
Francisco, Wisconsin, and Southwest Connecticut, many of the nation’s power
markets have too much capacity, and that will generally pressure credit. Power
prices have largely been driven down to the marginal cost of production. That
means that power plants selling into depressed markets are likely earning little
or nothing toward their fixed costs.
Such a situation should force unprofitable plants into retirement, and that
would be the case in a truly competitive, restructured power market. However,
about two-thirds of U.S. generation still operates in a cost-of-service, rate-of-return
environment, which means that ratepayers carry the fixed costs of generation
owned by vertically integrated utilities.
A recent trend away from deregulation in some states is allowing utilities
to reintegrate vertically. That could exacerbate credit pressures for some merchant
generators, such as in Arizona and New Mexico. Potentially worse is the possibility
that announcements of retirements, to the extent there any material ones, may
actually be plants going into a mothballed state, standing by in case power
Merchant power plants, even those with efficient heat rates, will find competing
in markets where regulated utility generation operates alongside them difficult
unless demand begins to rise or power plants permanently retire. Utility-owned
generation need only bid their marginal production costs in the market.
Such a bid strategy will tend to drive down energy prices in a way that will
hurt unregulated, independent merchant generation. In markets that have forced
utilities to completely divest, such as New England, this dual universe of generation
ownership should be less of a problem.
As a point aside, one of the intended benefits of deregulation has been the
introduction of competition among wholesale generators. Without the complacency
of cost-of-service operating environments, the new owners of older utility generation
have focused on improving operations. A visible sign has been the improvement
in generation availability and load factors for base load plants, particularly
nuclear and coal.
While many independent market studies that accompanied the new gas-fired merchant
power plant construction assumed that older plants would retire, just the opposite
has happened. Many have extended their lives and now produce more low-cost power
than before a situation that has also contributed to excess generation
and credit pressures in some markets.
Outlook for Credit
What does the restructuring of the U.S. power sector hold for credit? At a
minimum, restructuring is a lengthy work-in-progress that could take many turns
along the way. The U.K.’s electricity regulator, for instance, has made numerous
changes since deregulation began in 1991 to its industry structure that affected,
and continues to affect, the credit of most participants. But the effects were
not uniform; Standard & Poor’s expects that U.S. restructuring also will affect
credit differently for industry participants, as it already has. Much of the
effects will rest with how participants themselves choose to capitalize their
firms, as well as in what parts of the industry they chose to enter and in what
markets they elect to compete.
Nonetheless, the interim state of U.S. restructuring has left a cloud of uncertainty
over investors and lenders. That in and of itself raises credit risk. The absence
of a standardized wholesale market design, which includes an efficiently operating
transmission system, and an uneven playing field in wholesale generation raises
credit concerns because of unintentional results, which include:
Some buyers and sellers of power cannot enter into some transactions
when power is most expensive because transmission is allocated using non-market
Lack of a standardized wholesale market design is masking price signals
that either lead to infrastructure investments in the wrong locations
or of the wrong type or investments not being made.
The effective subsidization of utility-owned generation that creates
an uneven playing field for merchant generation in the wholesale generation
Look for FERC and many states to press ahead with restructuring, but expect
a slow timeframe. In particular for FERC, restructuring will be a major initiative
even after the current turmoil and collapse in power prices subside. In the
meantime, however, credit risk will not likely abate, and raising new capital
will be a challenge.