Statutory
Interpretation Exercise
NOTE: Assume that all of the following facts are
true, though many are not. Specifically,
all four of the disputed transactions below are hypothetical, though they may
resemble actual transactions from the
SCE v. Dynegy
Before the Federal Energy Regulatory Commission, and
the
This is a dispute between Southern California Edison Corp. (“SCE”) and Dynegy Corp. over the reasonableness of rates charged by Dynegy for wholesale sales of electric power to SCE during the period running from December 2000 through May 2001. SCE seeks a FERC order requiring Dynegy to refund $4 million in “excess charges” associated with those sales.
Historical
Context of Regulation
During the late 19th and early 20th century, a great deal of government attention was devoted to the problem of curbing the influence (political as well as economic) of large business associations. Policymakers concluded that: (1) if the market was left completely alone, unbridled competition in some industries tended to lead toward market failure and the accumulation of monopoly power by a very few firms; and (2) monopolies tended to harm consumers by producing less and charging more for their product.
The governmental response was twofold. First, between 1890 and 1914, the government created a system of antitrust laws, which defined certain forms of competition as unfair and illegal. These laws outlawed harmful business practices, including cooperative arrangements designed to give members of the cooperative greater market power (i.e., power to influence market prices) and misuse of so-called “monopoly power” (the unilateral ability of powerful oligopolists or monopolists to influence market price).
Second, in industries that tended toward monopoly because a single seller was most efficient, governments began to charter (i.e., license) private monopoly sellers within designated geographic areas, but limited the price those sellers could charge (to their costs plus a “reasonable” rate of return on prudently incurred investments). This system of “public utility regulation” began in the late 1800s with the creation of the Interstate Commerce Commission to regulate railroad rates and comparable state agencies. It now comprises federal agencies, like the Federal Energy Regulatory Commission (“FERC”), and state public utility commissions, like the California PUC. Traditionally, these agencies set the rates charged by regulated public utilities through so-called “rate cases.”
The
Federal Power Act and Wholesale Electric Rates
The Federal Power Act of 1935 (“FPA”) requires that wholesale electricity sales be made at rates that are “just and reasonable.” Throughout most of the FPA’s life, the FERC used rate cases to approve and limit wholesale rates. Wholesale sellers would submit information about their costs and investments to FERC, requesting authority to charge particular rates and earn a particular rate of return for their shareholders. A single FERC-approved rate would cover both the cost of the electricity sold at wholesale and the cost of transmitting it over the utility’s transmission lines, in one “bundled” rate. FERC’s professional staff and other interested parties scrutinized the requested rates, sometimes arguing that the requested rates were too high. The FERC Commissioners (political appointees who run the agency) then decided what rates would be “just and reasonable.” Analogous rate proceedings took place at the state level, reviewing the reasonableness of retail electric rates, and still do today in most states.
In traditional rate cases, the regulatory agency bases its decision on (a) the value of prudent capital investments on which the utility will be permitted to earn a return, (b) the value of operating expenses, and (c) the rate of return on investment that is “reasonable” under the circumstances. While regulators have mostly eschewed fixed formulae for selecting rates of return, in more than 100 years of state and federal ratemaking they have rarely exceeded 20 percent or dipped below mid single digit returns.
Electricity
Restructuring
In recent decades, more and more economists and public policy analysts have extolled the advantages of competition over regulation, and have promoted the idea that free markets can drive down costs and prices by reducing inefficiencies. These ideas motivated restructuring of traditionally regulated industries like banking, airline, and telecommunications, before electricity restructuring took hold in the 1990s. A series of actions by Congress, the FERC, and states has led to an increasing “unbundling” of power generation, power sales, and power transmission and distribution services, such that only the latter component of electric service is now considered a natural monopoly requiring government rate regulation.
Consequently, the FERC and some states set about trying to promote competition in power sales markets, permitting buyers to choose the company from which they would buy power, rather than requiring service by only the government-chartered monopoly provider. To facilitate the development of wholesale markets, FERC began by requiring owners of transmission lines to transmit power for third parties at regulated rates. FERC then authorized wholesale buyers (usually, public utilities and municipal utilities serving retail customers) to negotiate their own rates with individual power suppliers (owners of generating plants) of their choice. Some state Public Utility Commissions (“PUCs”) initiated similar restructurings in retail electricity markets, authorizing individual buyers to choose their power suppliers and simultaneously loosening regulatory restrictions on prices to promote price competition among sellers. In this way, the FERC and some state agencies allowed the market, rather than regulators, to set rates with the hope that long term costs would decrease.
In a series of orders issued during 1996 and 1997, the
FERC approved the restructuring proposals, which called for the three major
public utilities in California (Pacific Gas and Electric Company (PG&E),
Southern California Edison Company (SCE), and San Diego Gas & Electric
Company (San Diego) to (1) transfer operational control of their respective
transmission systems to the Cal ISO, and (2) purchase all of the energy needed
to serve their retail customers through wholesale spot markets (day-ahead or
day-of markets administered by the California Power Exchange Corporation (“Cal
PX”). The three public utilities were
precluded by
The
The Cal PX short term and spot markets worked like a clearinghouse system, with a day-ahead market and a real time market. For example, in the day-ahead market, sellers would submit bids indicating how much power they’d be willing to sell into the system the next day, and at what prices. Similarly, buyers submitted bids indicating how much power they would be willing to buy, and at what prices. The Cal PX matched up these sell and buy bids to “clear” the market, while the Cal ISO and PX worked together to ensure that the transmission system could accomplish the delivery of power from sellers to buyers. Information from the day ahead market was also used to arrange for the availability of power generation reserves, to ensure that there would be enough power available each day to serve sudden increases in demand.
Early market operations proceeded relatively smoothly, with average wholesale energy prices at levels below those previously experienced in a cost-based regulatory regime, averaging about $33/megawatt-hour (“MWh”)* for the first two years, compared with about $50/MWh before then. But the Cal ISO eventually experienced problems, leading to the imposition of a $750/MWh purchase price cap (that is, the Cal ISO would reject offers to sell power to it at prices above this level). In May 2000, however, real-time prices in the Cal PX market reached the Cal ISO's $750 cap for the first time, and the Cal PX average price in its day-ahead market for the month topped $316/MWh. In June 2000, prices reached levels that exceeded by three or four times those seen at comparable demand conditions in prior years. Thus began what has been termed the California Energy Crisis.
Figures 1 and 2 trace the behavior of electricity prices
on the
FIGURE 1
FIGURE 2
As wholesale prices increased, some of the wholesale buyers (specifically, SCE and PG&E) remained subject to rules prohibiting them from increasing retail prices above a statutory maximum. This meant that for some time periods, they purchased power at rates exceeding the rates at which they could sell it. This damaged their credit ratings and ultimately led PG&E to file for Chapter 11 bankruptcy.
Analysis of these price fluctuations by regulators, academics, and market participants point to a variety of factors, some combination of which caused these price spikes. All agree that for good reasons or bad, the supply of power available through the Cal PX markets was insufficient to meet demand, which not only drove prices up, but also created shortages. Figure 3 summarizes the history of partial and full blackouts before and during the crisis.
FIGURE
3: Power Outages (Declared Power
Emergencies), 1998 to May, 2001
The list of possible (and alleged) causes of the crisis include the following:
- The growth
in electricity demand in
- The lack of a connection between wholesale power costs and retail costs. As the wholesale price spiked, retail prices remained low (by law). Consequently, retail demand remained strong, despite high wholesale prices.
- A
drought in the
- A
spike in the market price of natural gas, which is the fuel source for
more than 40 percent of
- Interruptions
in gas and electric transmission, which exacerbated scarcity
problems. For example, the major
pipeline supplying natural gas to southern
- The
high price of pollution emissions allowances (needed to run fossil-fueled
plants) in the southern
- Manipulation of the market by sellers, including price fixing.
FIGURE 4:
Historic Precipitation and Generation at
The Dispute Between Dynegy
and SCE
The Underlying Issue
This case involves four disputed charges, all for wholesale sales of power by Dynegy to SCE in the winter and spring of 2000-2001. In each case, SCE is alleging that the rates charged are not “just and reasonable” under the Federal Power Act. Sections 205 of the FPA states as follows:
Section 205(a) Just and reasonable rates
“All rates and charges
made, demanded, or received by any public utility for or in connection with the
transmission or sale of electric energy subject to the jurisdiction of the
Commission, and all rules and regulations affecting or pertaining to such rates
or charges shall be just and reasonable, and any such rate or charge that is
not just and reasonable is hereby declared to be unlawful.”
Section 206 of the FPA goes on to authorize those harmed by rates that are “unjust and unreasonable” to petition the Commission for a refund. This case was initiated by one such petition. There are four payments, or “charges,” in dispute. We have been asked to determine whether the four disputed charges, all of which were established through the California PX bidding system, are just and reasonable under the FPA.
Hearing Panels and Procedures
Each disputed charge will be decided by multiple hearing panels working independently – some hearing panels will represent the FERC commissioners, who must make the initial decision; other panels will represent the D.C. Circuit Court of Appeals, who will either affirm or deny the appeal of the FERC decision on each issue. Each panel will serve as FERC Commissioners for one issue, and as the D.C. Circuit panel on another issue. Initial Panel group assignments are as follows (however, we may move you to another panel to even out the size of the panels during the exercise):
Panels will be assigned to issues as follows:
|
ISSUE |
FERC PANELS |
D.C. CIR. PANEL |
|
|
A à |
B |
|
|
Cà |
D |
|
|
Eà |
F |
|
|
Gà |
H |
|
|
Ià |
J |
|
|
Bà |
C |
|
|
Dà |
E |
|
|
Fà |
G |
|
|
Hà |
I |
|
|
Jà |
A |
During the first 20 minutes of the exercise, each FERC panel will convene separately to discuss the issue before them. By the end of the 20 minutes, the group must decide whether to grant SCE’s petition for a refund on that issue. In each case, the panels have complete discretion to decide whether Dynegy’s sale of power to SCE was at a “just and reasonable” rate. Panels may order full refunds, partial refunds, or no refunds at all, based upon their conclusions as to whether the initial sales rates were “just and reasonable” under the FPA. Panel decisions need not be unanimous. Where decisions are not unanimous, panelists should report to the D.C. Circuit the vote of the panel (2-1, 2-2 or 3-1).
The Four Disputed Charges
A FERC hearing officer has previously taken testimony and other evidence on each of these four disputed charges. The record showed that on each of the days involved, the charges in question were among the highest rates charged for sales of power into the Cal PX market. The hearing officer also certified the following statements of fact for each charge:
1. The
2. The
FIGURE 5
The following email exchange between Dynegy traders+, concerning the May 3rd market, was entered into evidence at the hearing:
TRADER 1: “We decided prices were too low … so we shut down.“
TRADER 2: “Excellent. Excellent.”
TRADER 1: “We pulled about 1000 megs off the market.”
TRADER 2: “That’s sweet.”
TRADER 1: “Everybody thought it was really exciting that we were gonna play some market power.”
TRADER 2: “That was fun!”
SCE contends that this use of market power by Dynegy led to exhorbitantly high prices which were not just and reasonable, and seeks a refund of $750,000, which represents the difference between the price Dynegy charged and the recent historical “fair” price of $40/MWh. Dynegy contends that it is free to sell power or not to sell it into the Cal PX system, and that its charges were therefore just and reasonable.
3. The
· Approximately $50/MWh represented Dynegy’s usual costs (fuel, delivery costs, etc.) of providing the power.
· Another $200/MWh represented the cost of buying air pollution allowances to enable the plant to run that day.
· The remaining $250/MWh represented the risk premium Dynegy charged to cover the risk of nonpayment by SCE.
SCE claims that these prices are not just and reasonable. They contend that price gouging in the air pollution credit market created unjust prices, and that they should not have to bear the portion of the price which represents a risk premium. SCE seeks a refund of the entire $2.3 million, which represents the difference between the price Dynegy charged and the recent historical “fair” price of $40/MWh. Dynegy contends that all three of these components of the May 29th price are just and reasonable under the FPA.
4. The