Scientech IssueAlert for June 19, 2001
California Update: Expanded Price "Mitigation" Plan and a Transmission Deal for
San Diego's Transmission Assets
by Will McNamara
Director, Electric Industry Analysis
Wholesale power prices will be limited around the clock in California and 10 other Western
states following a 5-0 vote by the Federal Energy Regulatory Commission (FERC) on June 18.
The order, which lasts through September of next year, limits the prices power generators can
charge to utilities under a complex formula based on the costs of the least-efficient producer
during any given hour. It expands on an April 29 FERC order restraining wholesale prices in
California during power emergencies.
Analysis: FERC has bowed to the pressure from California officials and the ongoing volatility of
Western markets and expanded a previously adopted price screen policy that it believes has
already been successful in curbing wholesale power prices. While the federal government has
maintained its public opposition to any long-term form of price controls, FERC has apparently
found some wiggle room to create a “price mitigation plan” designed primarily to reduce price
spikes in California and other Western states. The commission offers that it has not imposed
cost-based price caps in the West, as demanded by California officials, but rather has
established a price-mitigation plan, based on market principles, that will be applied to all of the
Western spot markets. Meanwhile, the California government has reached another milestone in
its attempt to gain control of the state's electric market by striking a deal with Sempra Energy,
parent company of San Diego Gas & Electric (SDG&E) for the utility's transmission assets.
There are some key elements of FERC's order that are important to understand. First, the order is
a significant expansion of the commission's previously established policy for Western price caps
that was formulated in late April of this year. Previously, FERC applied price controls only in
California and only during times of a Stage 3 power alert (signaling that power reserves had
fallen to dangerously low levels). Varying from month to month, the price screen previously put
into place was based on what it cost to produce power at the least efficient (and therefore most
costly) plant running at the time. Under the expanded order, price controls now will also be used
during non-emergency periods throughout the entire Western region (11 states). The other states
included in the Western Systems Coordinating Council (WSCC) are Washington, Oregon,
Montana, Idaho, Wyoming, Utah, Arizona, Nevada, New Mexico, and Colorado.
The expanded order retains the use of a single-price auction and must-offer and marginal-cost
bidding requirements when reserves are below 7 percent in California. What is different is that
now the California ISO market clearing price will also serve to constrain prices in all other spot
markets in the Western states, and will also be adapted for use even during times when reserves
are above 7 percent. Until September 2002, during non-emergency periods the price for
wholesale power in all 11 Western states cannot exceed 85 percent of the cost of electricity sold
during a Stage 1 (or lowest level) power emergency. The new rule sets an initial price ceiling of
$107.9/MWh for wholesale power sales, which is considerably lower than the average price
screen put into place by FERC's original order. Power generators will not be permitted to sell
above the mitigated prices in the Western markets.
In addition, all public utilities that own or control generation in California must offer power into
the California ISO's spot markets. This rule also applies to non-public utilities selling into the
markets run by the California ISO or using FERC-jurisdictional transmission facilities. Other power
sellers operating in the WSCC must also offer power into spot markets in the region, but have
more flexibility in choosing among the spot markets among the 11 states.
FERC Chairman Curt Hèbert offered that the plan relies on “market-oriented principles” that will
restrain prices rather than set them by “bureaucratic fiat.” Hèbert also said that the tying of price
structure to the efficiency of production will encourage power generators to invest in new
facilities. As the order stops short of imposing strict price limits based on the cost of an individual
generator's production, the commission has argued that the policy does not represent price
controls in its strictest definition.
The most surprising element of FERC's expansion of price controls for the West is the length of
time that the price caps will be kept in place. The commission has appeared to go from one
extreme to the other, moving from strong resistance to any form of long-term or permanent price
controls to an order that mitigates prices for more than a year (14 months to be exact). Although
FERC attempted to find a balance among the polarized positions in the price cap debate, its
order has not quelled the ongoing disagreements related to this issue, with the Bush
administration, California officials and power generators weighing in with disagreement.
As noted, the commission's order attempted to reach a middle ground by striving to give
something to all of the various stakeholders. To some extent, FERC succeeded in reaching this
objective. In general, Democrats (most clearly represented by Calif. Senator Dianne Feinstein)
had called for price caps based on each generator's cost of production. Republicans generally
have resisted any form of price controls, preferring instead to let the market run itself. With the
commission's new ruling, Democrats have gained a limited form of the price controls that they
sought. Feinstein responded that the order was “not perfect” but did represent “a giant step
forward.” In turn, Republicans say that market forces will still play a lead role in determining
electricity prices.
However, it would be inaccurate to say that the commission's order has been met with
overwhelming enthusiasm. Houston-based Reliant Energy, which has been singled out by
California Governor Gray Davis as one of the companies that has unjustly profited from the state's
energy market, responded that FERC's expanded price controls were more of a “political
response to the California crisis than an acknowledgement of the market realities in California.”
Further, the company said that the commission had ignored the basic principles of supply and
demand and reiterated its position that any form of price controls would decrease available
supply and discourage conservation on the part of Californians. The commission's order will only
serve to further destabilize the California market, Reliant said. To solve the problem, Reliant
believes that California needs a long-term plan that will address increasing the state's generation
supply and providing incentives for reduced demand.
Interestingly, President Bush said on June 18 (in advance of the FERC's unanimous vote) that
the expected order did not constitute price controls by the term's strict definition. Rather than
putting firm price controls into place, Bush implied that FERC's order to establish an expanded
mechanism to mitigate any severe price spikes that might occur offered something that is
“completely different” from price controls.
Gov. Davis, while generally pleased that FERC has taken action to control prices in California
and the West, also raised concern that the expanded order does not address previous power sales
that have led to significant debt on the part of the California utilities. In fact, FERC's expanded
order does not take effect until today (June 19) and does not apply to any power sales that took
place prior to that date. The commission has indicated that it will address refunds for past
periods in future orders.
Meanwhile, Gov. Davis announced on June 18 a deal for the state to purchase SDG&E's
transmission assets for 2.3 times book value, which equates to just under $1 billion. The utility's
transmission network includes 170 electric lines exceeding 69 kilovolts in capacity and spanning
about 1,800 circuit miles from southern Orange County to the Mexican border. In addition, the
assets include about 135 electric substations and transmission interties with SCE's system at the
San Onofre Nuclear Generating Station.
Under the pending deal, the state would free SDG&E from the burden of approximately $750
million in uncollected debts that the utility has accumulated due to purchases for power on the
wholesale spot market. Davis already has announced that the pending deal represents a
“massive” benefit to San Diego ratepayers because it averts any further rate increases (“balloon
payments”) that would be necessary for SDG&E to put into place to recoup its debt. In return, the
state would acquire the company's 1,800 miles of power lines for just under $1 billion plus the
retirement of related debt of about $180 million. The deal is subject to the approval of state
regulators and lawmakers and has a deadline of Aug. 15.
Davis has encountered difficulty in striking similar deals with the two other California utilities,
Pacific Gas & Electric (PG&E) and Southern California Edison (SCE). PG&E has expressed no
interest in selling its transmission assets to the state of California, and the pending deal with
SCE, in which the state has offered $2.76 billion (or 2.3 times the system's book value) has faced
obstacles. In essence, California legislators, who must approve the sale of SCE's transmission
assets to the state, have said “not so fast” and begun to question what value there would be for
the state in owning utility transmission assets. Clearly, SCE (and SDG&E, for that matter) would
benefit from the sale in that it would avert lengthy and costly bankruptcy proceedings and clear
huge debt loads. However, California legislators have raised concerns that California customers
ultimately would be forced to pay for the transmission lines through rate increases. This concern
will also apply to the state's offer for the SDG&E transmission assets, and could cause
complications for this pending deal. |
