CA-ISO REPORT BLAMES CALIFORNIA'S JUNE PRICE SPIKES ON THE LACK OF HEDGING, 
SUGGESTS THAT LOWERED PRICE CAPS HAVE DONE LITTLE TO STOP UNRELENTING, HIGH 
WHOLESALE POWER PRICES
  
09/20/2000 
Foster Electric Report 
Page 3 
(c) Copyright 2000, Foster Associates, Inc. 
The California Independent System Operator, Inc.'s (CA-ISO's) market 
surveillance committee (MSC) has found that utility reluctance to use hedging 
tools and a market design that continues to be faulty despite the 
implementation of reforms were the main reasons for the sustained price 
increases that hit California's wholesale markets in June 2000. 
According to an MSC report -- An Analysis of the June 2000 Price Spikes in 
the California ISO's Energy and Ancillary Services Markets -- the exercise of 
market power in California's wholesale power markets remains rampant. In 
fact, the MSC insisted that market rule changes implemented since last summer 
"have enhanced the ability of market participants to exercise market power in 
the California electricity market." And while the CA-ISO lowered its 
wholesale buyers' price cap from $750 to $250 following California's June 
price spikes, the MSC said the lowered cap has had little impact. Monthly 
average energy prices during June 2000 when the price cap was $750/MWh were 
lower than those during August 2000 when the price cap was $250/MWh although 
roughly the same amount of energy was consumed during these two months, the 
MSC reported. 
The MSC was also critical of existing regulatory constraints on forward 
contracting for energy and ancillary services by California's three utility 
distribution companies (UDCs) --Pacific Gas & Electric, Southern California 
Edison Co., and San Diego Gas & Electric --and the failure of the UDCs to use 
the limited rights they had in this regard. "The June 2000 price spikes can 
be attributed to several factors," the report stated. The primary cause, 
however, "was the lack of sufficient forward energy and ancillary services 
purchases for the month of June 2000 by the UDCs." The failure to enter these 
contracts then enhanced the ability of generators in and outside the ISO 
control area to exercise market power during high-demand conditions. 
"Had California's three utility distribution companies (UDCs) signed forward 
financial contracts equal to their expected net demand for energy and 
ancillary services during each hour of the months of May and June 2000, 
average prices in the PX and ISO markets during these months would have been 
significantly lower," the report stated. "Even if the June 2000 price spikes 
had still occurred, the UDCs would have been largely insulated from this spot 
market price volatility, because of their forward hedges." 
Still, the MSC noted that the UDCs are not solely at fault, having been 
severely limited by the California Public Utilities Commission. Before last 
month, the UDCs could only make limited forward purchases in the CA-PX's 
block forward market, for only certain times of the day and little 
flexibility. "The CPUC restrictions on forward contracting through the CA-PX 
were especially pernicious because the PX was granted a monopoly over forward 
trading by the UDCs," the report declared. And while the CPUC on August 3 
gave SoCal Edison and PG&E more authority to enter long-term bilateral 
contracts, the MSC criticized the move because trading levels are still 
restricted. Similarly, SDG&E has little incentive to enter forward contracts 
because it can pass through its purchased power costs to its customers, no 
matter how high the price. 
Besides forward contracts, the report said other causes of the June price 
spikes were the inability of consumers to adjust their demand in response to 
high prices, and the CA-ISO's new method for allocating replacement reserve 
costs. All the above factors allowed generators to exercise more market power 
in May 2000 than any of the summer months of 1999, the report said, and this 
market manipulation increased even further in June 2000. 
The MSC then took special aim at market rule changes recently adopted (such 
as a new replacement reserve policy ) or under consideration to enhance 
system reliability that can increase the market power exercised in 
California's energy and ancillary services markets. "The CA-ISO operators 
must recognize that they are running markets for energy and ancillary 
services," the report explained. "For that reason, they must carefully 
consider the incentives for market participant behavior created by any market 
rule changes designed to enhance system reliability. Failing to do so can 
result in unnecessarily high prices in the energy and ancillary services 
markets and can exacerbate system reliability problems." 
So what's the solution? While the construction of new generation and 
transmission facilities in California would naturally increase the 
competitiveness of the CA-ISO's energy and ancillary services markets, the 
MSC believes fundamental market reforms are also needed. "The California 
electricity market is not so structurally competitive that market outcomes 
are invariant to market rules," it stated. "The industry is composed of a 
relatively small number of firms, some of which own a sizable fraction of the 
total electricity generating capacity located in the CA-ISO control area. The 
geographic distribution of generation unit ownership can allow some owners to 
exercise locational market power during certain system conditions. In 
addition, the amount of generating capacity owned by some market participants 
allows them to exercise market power during high-load conditions, when there 
is not a physical scarcity of available generating capacity to serve this 
load. Furthermore . . . demand for wholesale electricity in California is 
extremely insensitive to price. Consequently, the structure of the California 
electricity market, at least for the near term, is one where market outcomes 
are very sensitive to market rules." 
As a short-term solution, the MSC support the retail rate freeze (see related 
story, this REPORT) recently signed into law for SDG&E's customers. However, 
it also suggested that the CPUC allow SDG&E broad freedom to engage in 
forward contracting, and that the retail rate ceiling be coupled with a 
requirement that SDG&E "offer rate schedules that encourage retail customers 
to alter their demand in response to hourly wholesale electricity prices." 
Of two possible long-term solutions, the MSC dismissed the reimposition of 
cost-of-service regulation for all but the larger industrial, commercial and 
governmental customers. "This scheme would simply continue the proposed 
short-term solution indefinitely," the report reasoned. Further, the option 
may prove unworkable now that the UDCs own little of their own generation. 
The MSC said, "This solution would continue to leave unanswered the 
fundamental question of cost-of-service regulation: What is the regulated 
firm's minimum-cost mode of production and how should output prices be set to 
provide the strongest possible incentives for the firm to produce in this 
manner? . . . Under this market structure, the CPUC would have to determine 
the prudency of the energy purchasing decisions made by UDCs across the many 
energy and capacity markets and purchasing time horizons available. A 
perceived inability of regulatory processes around the world to cause firms 
to produce in a least-cost manner in the former vertically integrated 
monopoly regime led to the widespread introduction of competition in 
generation and supply. It is difficult to see how regulating the UDCs' retail 
rates under the current regime will be less complex than regulating them 
under the former vertically integrated monopoly regime when the UDCs owned 
significantly more generation and also operated the bulk transmission grid in 
their service territories." 
A second approach that the MSC supports and first outlined last year is to 
separate the distribution side of the UDC's business from the retail supply 
side. Under this arrangement, the price for delivering power anywhere in the 
UDC's service territory would be set by the CPUC. The supply side of the 
UDC's business would be unregulated, except the requirement that it offer a 
fixed default retail rate for each customer class. The report noted that the 
MSC's plan is not new, having been recently put in place in the England and 
Wales electricity market. The major advantage "is that it does not require 
the CPUC to make a determination of the prudency of the wholesale energy 
purchasing decisions of the UDC," the report continued. Further, the supply 
side of the UDC's business can forward contract or purchase on any of the 
CA-PX and CA-ISO markets in any manner they find profitable. 
Finally, among other things, the MSC recommended (1) replacement of the 
current CA-ISO replacement reserve policy with a real-time trading charge, a 
penalty for the oversupply of real-time energy, and the cost of out-of-market 
calls being assigned to the over-consumption of real-time energy; (2) a 
greater emphasis on the market-power implications of proposed market rule 
changes, including reconsideration of the current out-of-market payment 
mechanism, the CA-ISO's 10-minute settlement market, and PG&E hydro 
divestiture agreement with the CA-ISO; and (3) expedited siting and 
construction of new or expanded transmission and generation capacity in 
California.