Electricity Restructuring in California: History and Current Status

Background:

Following the passage of FERC Order 888, in September 1996, the California legislature passed AB 1890 to deregulate the state’s investor-owned electric utilities and their 42,000 megawatts (MW) of generation capacity. Management of the high-voltage transmission of electricity statewide was taken over by a new quasi-governmental entity called the Independent System Operator (ISO). Management of wholesale electric sales to Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) was handled by a Power Exchange on a spot-market basis 24 hours in advance of when the power was needed. This spot-market price for power only included the energy passing through the lines and did not consider the capacity of power generating facilities.

The transition to a deregulated industry occurred on April 1, 1998. Electricity prices were now set in 10-minute increments, with all suppliers receiving the highest price bid during any particular 10-minute period. Prices fluctuated in accordance with the demand for power, and less efficient facilities came on line only as the demand required. As the reserve margin of available capacity at this time was approximately 25 percent, price fluctuations were not really notable. Furthermore, residential and small commercial retail rates were reduced 10 percent and frozen at that level for a four-year transition period, although customers would pay a sizable surcharge—the Competition Transition Charge—to provide funds for the three investor-owned utilities to pay off their “stranded costs” (remaining debt from previous utility investments and contractual obligations) as well as cover costs associated with a low-income energy program and investments in renewable energy and energy efficiency. The deregulation process allowed no long-term power contracts. The focus of the three utilities was managing their distribution systems and servicing their customers.

AB 1890 also called on the utilities to divest themselves of most of their generation. Thus, more than 27,000 MW of natural gas-fired and 2,500 MW of geothermal generation were sold, mainly to out-of-state corporations, by the end of 1998.

The Developing Crisis:

Fall 2000 arrived, and summer needs for peaking power passed, but the respite from price pressures was brief. The shortage in capacity was attributed to unscheduled shut-downs of generation. This was the case, but many of the shut-downs were for financial, not mechanical, reasons. The prices that PG&E and SCE were being paid by their retail customers no longer covered their wholesale power costs. Wholesale power bids had gone from less than 3¢ per kilowatt-hour (kWh) in the spring of 2000 to between 30¢ and 60¢ per kWh. PG&E and SCE did not have the money to cover these prices. As these two utilities went deeper and deeper into debt, they were not able to pay the independently owned generation facilities for the power. With many smaller generators forced to go off line because they were not being paid, only 33,000 MW were available when the first Stage 3 emergency came in December.

Time for Intervention:

In April, at the urgent request of some Western states, FERC established price caps for wholesale power throughout these states until September 2002. The region-wide cap was set at 10.8¢ per kWh under non-emergency conditions; under emergency conditions the ISO would define a potentially refundable rate. In addition, Governor Davis issued an Executive Order in June that allowed natural gas power plants to exceed current limits on air emissions during the summer months, though with penalties of $7.50 per lb. of NOx and $1.10 per lb. of carbon monoxide when limits were exceeded. Public funds were used to pay for some of the penalties incurred by the oldest power plants which continued to operate after their air pollution credits had been exhausted.

Current Status:

When DWR took over the purchase of electricity for the two financially troubled utilities in January, the decision was made to seek ways to dampen the spot-market price fluctuations by putting in place some long-term (up to 12-year) power contracts. As of mid-October, DWR has committed the state to $43 billion in contracts. The average price of energy to be supplied under those contracts is 6.9¢ per kWh. State law requires that an agreement on the contract rates be in place before the state can issue any bonds to cover the costs.

By the middle of October 2001, $11.3 billion had been spent to buy wholesale power, with the funds coming directly from the General Fund of the state. If the bond issue is not sold before June 2002, the state faces a deficit of $9.3 billion in unreimbursed costs. Governor Davis asked for an issue of $12.5 billion in bonds during the month of September. The legislature contravened the governor’s intent to give payment priority to the generators, with a bill giving payment preference to the bondholders, in order to keep the cost of the bonds as low as possible. The final resolution to repaying the general fund is, at this time, unresolved.

With increased dissension over DWR’s role in managing most of California’s electricity purchases, in September, Governor Davis signed a bill to create the California Power Authority (formally the Consumer Power and Conservation Financing Authority). It is authorized to issue up to $5 billion in bonds to finance power plants, natural gas transmission and storage projects, and energy efficiency programs.

Private Utilities:

In April, PG&E announced that, with $13 billion in outstanding obligations, it would be forced to declare bankruptcy. SCE announced debts of $3.3 billion, but rather than declare bankruptcy, that utility proposed the sale of its high-voltage transmission lines to the state for $5 billion—twice the appraised value. Both utilities have alternative proposals for restructuring. PG&E’s is before the federal bankruptcy court. SCE’s has been approved by the CPUC, and the utility has begun implementation.

PG&E’s plan calls for creation of three new companies under the parent company Pacific Gas and Electric. These would be: 1) a natural gas transmission company, 2) an electric (high-voltage) transmission company, and 3) an electric generation company to provide power from the PG&E hydroelectric facilities and Diablo Canyon Nuclear Power Plant. The generation company would sell energy from its more than 7,000 MW of capacity at 5¢ per kWh for the next 12 years. The three new companies all would be regulated by FERC. The expectation is that PG&E would then be able to borrow against these assets to pay creditors $9.1 billion in cash and $4.1 billion in long-term bonds. The retail power distribution utility, PG&E, would become a separate company with its own stock and with no assets, regulated by the CPUC.

A settlement between SCE and the CPUC was reached on October 2 that would directly restore that utility’s role in purchasing electricity for its customers. Under this agreement SCE would pay off $2 billion in debts through direct rate increases of 40 percent and $1.2 billion from shareholder funds. SCE will suspend dividends to shareholders for at least two years.

Other Issues:

In late September 2001, the CPUC issued an explicit ruling against “direct access,” an option granted to retail customers by the original deregulation legislation to contract with a separate, non-utility, power provider and pay the retail rate charged by that provider. Between July and September, 9 percent more customers sought non-utility providers. Most of these additional contracts involve industrial customers intent upon avoiding the additional costs that will be associated with any state bond issues or utility debt reduction costs. Some pressures are being brought upon the legislature to move back the effective date on which direct access was rescinded, so as to void these recent contracts.

In addition, environmentalists have protested the repeal of direct access because it removes the opportunity of power users in the state to select “green” energy. It is certain that the legislature will take up a green power exemption for direct access customers in 2002. The legislature may also look at the establishment of a renewable energy portfolio requirement for the utilities.

LWVC UPDATE Originally published December 7, 2001