US Government Moves To Cap Electricity Prices

US Government Moves To Cap Electricity Prices

August 01, 2001

The US government moved on June 19 to cap electricity prices in an 11-state area, including California.

Meanwhile, California asked the Federal Energy Regulatory Commission to order $9 billion in refunds for the amount it claims electricity generators overcharged for power since May last year.  Utilities in the Pacific Northwest have also demanded refunds.  In late July, the commission said it can only order refunds for California power sales on or after October 2 last year.  The commission announced a methodology it would use in the future to decide when generators are overcharging for power.  It said any refunds ordered could be retroactive only back to December 25 last year for power sales in the Pacific Northwest and back to July 2 this year for power sales in other western states.

Price Caps

The order imposing price caps on June 19 modified a price cap order that had already been in effect for California power sales since April and extended it to an 11-state area in the western United States called the WSCC.  The 11 states are New Mexico, Arizona, Colorado, Utah, Nevada, Oregon, Washington, Idaho, Wyoming and Montana.  The area also includes small portions of Texas, South Dakota and Nebraska.

Last April, FERC set a “soft” price cap for California power sales during reserve deficiency hours.  Reserve deficiency hours are periods when electricity supply falls below a 7% reserve margin.  This was later clarified to mean only during periods when the California independent system operator, or “ISO,” has declared a “stage 1 emergency.” The price cap is a “soft” cap in the sense that sales can still take place at prices above the cap but only if the seller can justify the higher price.

The June order extending the price caps to the rest of the WSCC means that price caps will be in effect throughout the WSCC whenever there is a stage 1 emergency in California.  However, FERC also imposed caps — at 85% of the stage 1 emergency level — during other periods.

The June order also imposed a “must-offer requirement” and said the price caps and must-offer requirement will apply not only to public utilities — defined broadly to include investor-owned utilities, independent generators and power marketers — but also to municipal utilities.

FERC calls the price caps and must-offer requirement a price mitigation plan.

Under this plan, everyone across the WSCC will be subject to the same price caps based on the price at which electricity is being sold in the California ISO.  During stage 1 emergencies, the cap for a particular reserve deficiency hour will be a hypothetical amount, called the “proxy price,” for the last unit of electricity to be bid into the ISO during that hour.  This marginal proxy price will be the cap for that hour for the entire WSCC region.  The cap will apply not only to sales in spot markets, but also to bilateral sales.  Sellers selling outside the ISO will receive the prices they negotiate up to the cap.

Sales during non-reserve deficiency hours will also be subject to a cap.  The maximum price for spot market sales during non-reserve deficiency hours will be no more than 85% of the highest ISO hourly market clearing price established during the hours when the most recent stage 1 emergency was in effect.  Sellers through the ISO will receive the hourly market clearing price up to this maximum price, while for sales outside the ISO — that is, bilateral sales in California and the rest of the WSCC — sellers will receive the prices they negotiate up to the maximum price.

Generators will be divided into two classes.  During reserve deficiency hours, all spare generation capacity in California must be offered to the ISO.  Spare generation capacity in the rest of the WSCC must be offered into a spot market of the generator’s choosing.  This applies only to non-hydroelectric generation.  It applies whether the power plant is owned or is under contract — for example, a tolling agreement — to the extent the output is not scheduled for delivery or committed for minimum operating reserves.  All such must-offer sales of power are subject to the price mitigation detailed above just as with all other sales.

FERC imposed three further restrictions on sellers.  First, power marketers are required to bid as price takers, which means that they cannot bid higher than the market clearing price.  Second, FERC required sellers that own generation to submit bids during reserve deficiencies that are no higher than the marginal cost to replace gas for generation plus variable O&M costs.  Third, FERC instructed bidders to invoice the ISO directly for the costs of complying with emissions requirements and for start-up fuel costs.  In other words, these costs are outside the cap.  Sellers other than power marketers are allowed to justify bids or prices above the maximum prices.

In an earlier order issued April 26, FERC required each gas-fired generator in California to file with the commission and the ISO the heat rate and emission rate for each generating unit.  The ISO would use the heat rates to calculate a marginal cost for each generator by using a proxy for the gas costs, emission cost, and an adder for the variable O&M cost in order to calculate the clearing price during periods of reserve deficiency.  All generators would be paid a single market clearing price reflecting the proxy price for the last unit dispatched during periods of reserve deficiency.

In its June 19 order, FERC determined that the spot gas prices to be used in the formula should be the average of the mid-point of the monthly bid-week prices reported by Gas Daily for three spot market prices reported in California (SoCal Gas large packages, Malin, and PG&E city-gate).  FERC also eliminated NOx costs from the calculation of the mitigated market-clearing price and set the O&M adder at $6 a megawatt hour.  Finally, FERC also instructed the ISO to add 10% to the market clearing price paid to generators to reflect credit uncertainty.

The new price mitigation plan took effect on June 20, 2000 and will remain in effect until September 30, 2002.

FERC applied the plan to municipal utilities as a condition for municipal utilities selling into the spot markets and as a condition of using the interstate transmission grid.

Possible Refunds

On April 26, the FERC launched an investigation into the rates, terms and conditions of sales for resale of electric energy in the WSCC other than sales through the ISO.  This was in addition to the ongoing investigation commenced by FERC the previous year into wholesale sales of electricity in California.

FERC stated in its June 19 order that refunds would not be ordered for California sales before October 2, 2000.  FERC also said in that order that it expected refunds arising from its investigation of rates in the WSCC other than sales through the ISO would be rare because of the market mitigation implemented WSCC-wide in the June 19 order.

On July 25, FERC issued another order explaining the methodology it will use to decide when sellers overcharged for electricity.  The immediate focus of the refund investigation is transactions in the spot markets operated by the ISO and the California Power Exchange and power sales in the Pacific Northwest.  Most interestingly, FERC insisted its refund authority is limited to 60 days after filing of a complaint or institution of a “section 206” investigation.  Also, of interest was the FERC’s determination that it had authority to order refunds from municipal utilities because of its authority over the subject matter of the sales at issue.

FERC said it would calculate overcharges by reference to the price caps, with several slight modifications.  The actual heat rate of the last unit dispatched will be used to calculate the market clearing price.  The June 19 order established a price cap of 85% of the market clearing price established during the most recent stage 1 reserve deficiency for hours in which no reserve deficiency exists.  However, FERC elected not to use this price for such hours in testing for overcharges.

The gas proxy used to determine refunds will be daily spot prices rather than monthly bid week prices.  Further, if the marginal unit was located north of “path 15,” the spot price would be the average of the PG&E city-gate and Malin spot prices, while if the marginal unit was located south of path 15, the spot price would be the SoCal gas-large packages spot price.  Path 15 is the corridor that runs north and south between PG&E and SCE’s territory and is the backbone of California’s transmission system.  In addition, the spot price for gas will be determined by using the simple average of spot prices published in several sources.

The O&M adder of $6 a megawatt hour is the same as that used for the price cap and the 10% adder for creditworthiness issues is to be used for calculating the refund, but only in calculating market clearing prices after January 5, 2001 (the date that the bond ratings of PG&E and SCE were downgraded).  This gives the ISO a baseline against which to calculate whether there were overcharges hour by hour from October 2, 2000 through June 20, 2001.

FERC determined that the most orderly and expeditious method of determining how much in refunds to order is to convene an evidentiary hearing.  Once the ISO calculates the hourly baseline prices using the refund methodology, the ISO and the PX must rerun their settlement and billing processes and penalties.  The ISO has been given 15 days from July 25 to recreate the price caps using the refund methodology.  Within 45 days thereafter, the administrative law judge is to make findings of fact regarding the mitigation price, the amount of refunds owed, and the amount owed to each supplier by the ISO, the investor-owned utilities, and California.

FERC also instituted a conference to be overseen by an administrative law judge to establish the volume of transactions, identification of net sellers and net buyers, price and terms and conditions of the sales contracts, and the extent of potential refunds for the period between December 25, 2000 and June 20, 2001 in the Pacific Northwest.  The refund period for the Pacific Northwest commences December 25, 2000 because Puget Sound Power petitioned FERC for refunds in the Pacific Northwest last October.

The refund methodology for any retrospective refunds in the Pacific Northwest is less clear.  FERC will probably have to reconstruct all spot sales made during the potential refund period.  However, on a going-forward basis, the Pacific Northwest spot market will be subject to the same mitigation as the rest of the WSCC as described in the June 19 order.