FERC Filings
MOTION OF THE ELECTRIC POWER SUPPLY ASSOCIATION-Docket No. EL01-1-000
C. Wholesale and Retail Market Revisions, Not Cost-Based Rates, Are Needed
EPSA does not mean to suggest that markets are working perfectly in California or that the Commission need not be concerned about prices this summer. There are two fundamental problems with the wholesale market in California:
(1) a structure that puts undue pressure on the more volatile short-term markets and (2) the imposition of price caps on purchases of wholesale energy and ancillary services. Both need to be fixed. These fundamental flaws need to be corrected, not through a change in rate structure, which will do nothing to alleviate the problems, but by a change in the California rules that mandate use of the California Power Exchange and elimination of price caps.
The California wholesale market has been designed to incent load participants to move much of their buying and selling activity into the day-ahead, day-of and real-time markets, particularly in the California Power Exchange (CalPX). In any commodity market, it is natural that shorter-term markets will be the most volatile. Many market participants, both buyers and sellers, prefer to manage risk through a strategy that combines longer-term and shorter-term purchases.
In fact, many of the companies that acquired utility assets in California assets prefer a strategy that permits most, if not all, of their risks to be hedged in forward markets.
Thus, many generators sold power ahead of the summer. A recent article from Dow Jones, Winners in $4 Billion California Sweepstakes, attached hereto, documents this situation.
Current market rules, however, limit the ability of California’s utilities to access the hedging tools normally available to load serving entities. Utilities are permitted to buy only a limited portion of their load in the CalPX’s block forwards market, which mitigates some risk, but until recently were not permitted to engage in forward bilateral contracts, options or other risk mitigation tools otherwise in use in the wholesale market.
With strict limitations on their use of forward markets and other risk management tools, the utilities have been forced to purchase significant portions of their supply in the spot market. This situation is compounded by California Public Utility Commission rules that make forward market purchases subject to after-the-fact reasonableness reviews by state regulators, while spot market purchases are deemed per se reasonable. This approach to rate regulation has no place in a competitive markets.
Additionally, price caps have created a problem in the Cal ISO’s real-time balancing market, driving the load serving entities in California to under-schedule their power needs in the day-ahead markets as a means of achieving a lower overall energy rate.
The balancing market price caps provide a free hedging product, allowing utilities to transfer purchases to the real-time market when the price in the day-ahead market exceeds the cap set by the Cal ISO. The Cal ISO has determined that underscheduling has significant operational and reliability impacts; in some hours, the Cal ISO has met as much as 25 percent of the system needs in the real-time market.
During summer 2000, the Cal ISO went out of market to purchase 159,098 megawatt hours, spending $101 million.
Price caps have also discouraged demand-side responses and load reduction programs. For example, under its Demand Relief Program the California ISO paid an average capacity price of $1,207 (at a time when energy prices were capped at $750) to incent load reduction. Why should load be paid a price for curtailing far in excess of what supply is paid for producing? With or without price caps, load reduction programs will face a greater challenge in 2001, when the supply and demand balance will be even tighter than it has been in 2000.