San Diego Gas & Electric Company, Complainant, v. Sellers of Energy and Ancillary Service Into Markets Operated by the California Independent System Operator Corporation and the California Power Exchange, Respondents.				Docket No. EL00-95-031
Investigation of Practices of the California Independent System Operator and the California Power Exchange				Docket Nos. EL00-98-030, EL00-98-033
California Independent System Operator Corporation				Docket Nos. RT01-85-000, RT01-85-001
Investigation of Wholesale Rates of Public Utility Sellers of Energy and Ancillary Services in the Western Systems Coordinating Council.				Docket Nos. EL01-68-000, EL01-68-001

In its June 19 Order, the Commission specifically solicited comments on its Order to address, among other things, the appropriateness of the measures the Commission adopted, given the differences between California and other Western Systems Coordinating Council markets.

The Northwest Power Planning Council (Council) is a four-state interstate compact agency, authorized by Congress to provide oversight over the resource planning of the Bonneville Power Administration (Bonneville) and to design a regional fish and wildlife program to help restore fish and wildlife affected by the region’s hydroelectric system. The Council members are appointed by the governors of Idaho, Montana, Oregon and Washington.

The Council would like to address the potential unintended effect of the mitigation order on winter reliability in the Northwest. The Northwest is dependent to a large extent on hydroelectric production. The region has just experienced the second lowest January through July run-off volume in the hydrologic record. The region made it through the summer thus far without power supply interruptions through a combination of extreme measures and luck in the form of relatively cool temperatures. Those extreme measures included significantly curtailing spill at hydroelectric dams to the possible detriment of the survival of downstream migrating juvenile salmonids. They also included the installation of significant amounts of emergency generation, including diesel-fueled internal combustion engines, to the detriment of regional air quality. And they also included substantial reductions in loads, achieved at some cost to the regional economy. The load reductions were accomplished by significant buyouts of industrial and irrigation load combined with some plant closures and voluntary curtailment and conservation. In total regional loads are approximately 4000 MW below last years’ levels. This is approximately 18 percent below normal summer loads.

The Northwest is a winter peaking system. Many parts of the region can experience extreme cold winter weather, making the reliability of power supply a potential life and death issue. Under normal circumstances, the Northwest would expect to import power from California and the Desert Southwest to meet load during periods of peak winter demand. For the coming winter, the Council has estimated the probability that it would not be possible to meet regional loads one or more times at 12 percent. This is more than twice the traditional loss of load probability of 5 percent. The problems observed in the analysis are the result of relatively poor hydro conditions combined with periods of severe winter weather. This assumes the current load reductions and emergency generation can be maintained and that at least some imports are available from California and the Desert Southwest, a situation that did not obtain last winter.

We cannot know with any certainty what hydro and weather conditions will be next winter. We do know that following on the heels of a dry summer period, we are more likely to experience a relatively dry fall and winter. We are concerned that should the Northwest experience severe conditions next winter, the mitigated price might preclude operation of needed generation for Northwest load. We are also concerned that the owners of temporary generation installed over the past year in response to short supplies and high prices may choose to remove these plants prior to this coming winter. We have already seen some instances of this happening. Finally, we are concerned that the current price mitigation mechanism is chilling efforts underway on the part of regional suppliers to install needed permanent peaking capability.

To avoid this potential problem next winter, we believe that FERC should prospectively undertake modifications to the mitigation order. We believe that the following are appropriate modifications:

1. Allow inclusion of relevant transmission costs and losses and congestion charges in setting the mitigation level for interstate sales;
2. Expand the "must offer" requirement to ensure that California generators must offer to other markets in the WSCC even if their output is not required by the California ISO or require the California ISO to offer power that it doesn’t need to other control areas in the WSCC
3. Eliminate the California 10 percent credit premium or apply it west wide. The premium distorts the market and could induce deliveries to California when power is needed in the Northwest or elsewhere in the West.
4. Exempt generation of unit sizes of 100 MW capacity or less that was brought on line during the period November 1, 2000 through September 15 of this year. A number of emergency generation projects in the Northwest have already been terminated in response to lower market prices and the price mitigation. However, there are a number of emergency generating units that were either put in service prior the Commissions Order or which were sufficiently far along that they are being completed subsequent to the Order. This provision would allow these to operate during a period of tight supplies.
5. Adjust the cap for sales in the Northwest for the actual gas price in Northwest. Last winter there was an extreme spike in the Pacific Northwest prices for natural gas due to regional pipeline limitations. While we don’t necessarily believe that will be the case this winter, this provision would ensure that high gas prices do not result in needed generation being kept off the market
6. In the event that a Stage 1, 2 or 3 emergency is declared in a control area in the Northwest Power Pool, the price cap should be the higher of (1) the price cap determined using the modifications recommended above or (2) a daily price cap calculated based on:
1. A relevant daily gas hub price published in Gas Daily;
2. A pre-set proxy gas-fired generating plant heat rate;
3. The cost of transporting gas;
4. FERC’s estimate of variable O&M cost of $6/MWh;
5. A mark-up to provide incentives to operators of plants needed at the margin.

The exemption for small generation (Item 4. above) should be maintained.

The Council believes these changes should largely prevent the Commission’s price mitigation order from having the unintended effect of holding off the market generation needed to meet winter loads in the Northwest and elsewhere in the West.

CONTACT INFORMATION

Wallace Gibson
Manager, System Analysis
Northwest Power Planning Council
851 Southwest Sixth Avenue - Suite 1100
Portland, OR 97204-1348
(503) 222-5161

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