Report 2002-009 Summary - April 2003
California Energy Markets:
The State's Position Has Improved, Due to Efforts by the Department of Water Resources and Other Factors, but Cost Issues and Legal Challenges Continue
The Department of Water Resources (department) has renegotiated 23 power contracts with 14 suppliers to improve the energy delivery, financial, and legal aspects of these contracts. In addition, the investor-owned utilities are once again responsible for purchasing the net short.
- The portfolio better fits California's power needs by converting nondispatchable power to dispatchable power, but much of the improved fit is due to a reduction of forecasted demand, not the renegotiated contracts.
- Reported contract cost reductions were estimated at $5.5 billion on a nominal basis and based on assumptions at the time of the renegotiations.
- The terms and conditions of the restructured contracts have significantly improved reliability, but the department remains restricted in its ability to assign contracts to other parties and thus remains legally and financially responsible.
- Based on March 2003 market assumptions, replacement power costs, and discounting to present value, the department consultant currently estimates ratepayer savings as $580 million.
- During 2002 the department was not able to coordinate its power supplies with the utilities' generating facilities so as to minimize ratepayers' costs.
Even though the investor-owned utilities have resumed purchasing the net short, the department retains substantial responsibilities, including:
- Stewardship of the Electric Power Fund.
- Vigilance to mitigate the potential high costs of its contracts.
- Management of operating and service agreements with the investor-owned utilities.
- Administration of the bonds issued to finance the power-purchasing program.
RESULTS IN BRIEF
Forced to act quickly to restore stability to the State's electrical power system during the California energy crisis of 2000 and 2001, the Department of Water Resources (department) entered into a number of long-term contracts for electricity, many of which later proved to be unfavorable to the State. This report follows up on a previous audit report issued in December 2001 that examined those contracts and the department's power-purchasing role and called for a strategic framework for California's electricity industry. The department has had some success in renegotiating the contracts to fit the power supply more closely to consumer demand and to improve the terms and conditions of some contracts. In addition, the responsibility for purchasing the net short (any electricity that the utilities themselves cannot supply) has reverted back to the three largest investor-owned utilities (Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric). However, significant future challenges in energy issues remain for the department, the California Public Utilities Commission, and the investor-owned utilities, particularly with respect to management of the contract portfolio.
During the height of the energy crisis, extreme shortages of electricity caused numerous warnings of blackouts and in some cases led to rolling blackouts. At the same time, electricity prices in the State rose to all-time highs, causing credit problems for the State's three largest investor-owned utilities and leading to a reluctance on the part of generators of electricity to sell power to the utilities. In response to this crisis, the governor declared a state of emergency and the Legislature gave the department the authority to purchase the net-short energy required by the three utilities. The department was given this responsibility by Assembly Bill 1 of the 2001-02 First Extraordinary Session (AB 1X). On January 1, 2003, after nearly two years of purchasing the net-short energy for the investor-owned utilities, the department's power-purchasing responsibility ended and the utilities themselves became responsible for purchasing the energy needed to cover their net-short requirements.
Our December 2001 report observed that the responsibility assigned to the department by AB 1X was an immense challenge, given the crisis situation, the short time to prepare for this new role, and the department's limited power-purchasing experience and lack of infrastructure relative to the scale of this effort. Despite these impediments, the department did step in and buy the power needed to keep the lights on in California. In fulfilling its new role, the department entered into 52 long-term contracts with a face value (nominal value) of $42.9 billion to deliver power in California, and it spent approximately $10.7 billion to purchase power to meet the State's daily power needs through the first nine months of 2001. However, our report concluded that the department needed to make improvements in several areas, including improving the terms and conditions of the power contracts it had entered into, managing the future cost and legal risks of these long-term contracts, and developing the infrastructure to support its power-purchasing role. In addition, in the wake of California's failed deregulation plan, we recommended that the governor and Legislature develop a strategic framework for California's electricity industry.
Since our December 2001 report, the department has made progress in implementing our recommendations, but much remains to be done to manage the continuing financial and legal risks that face the State. The department has renegotiated the terms and conditions of 23 long-term power contracts with 14 suppliers, representing over one-half of the total value of the portfolio. These renegotiated contracts contribute to the improved fit of the portfolio to the State's forecasted demand for power by converting significant amounts of nondispatchable or must-take power—power that the department was obligated to purchase regardless of the need—to power deliveries the department can use when needed. In addition, the renegotiated portfolio increases power deliveries in Northern California in 2002 and 2003 to meet demand. Further, the department was able to shift some deliveries of power from Southern to Northern California, which reduced the amount of surplus power projected in Southern California. The department also renegotiated for more capacity tied to tolling agreements—cost-management arrangements that allow the department either to purchase the fuel needed for the power facilities under contract or to tie the fuel cost to the current cost of natural gas.
However, most of the improvement in the fit of the power supply to the demand has resulted from significant changes in the demand forecast rather than from significant improvements in the power contracts. These changes in the forecast include reductions in the demand for power from the investor-owned utilities for a variety of reasons, including the ability of certain electricity customers to buy electricity from alternate suppliers.
The contract renegotiation efforts have reduced the costs of the department's contract portfolio. The savings resulting from the renegotiated contracts can be calculated in a variety of ways, each with some merits and each with some limitations. Throughout the energy crisis, the department and the governor's office reported both the contract costs and the savings in terms of the contract payments to suppliers. Thus, they reported that the estimated reductions in contract costs from the restructuring of the contracts totaled approximately $5.5 billion, which represents approximately 13 percent of the total original contract costs of $42.9 billion. These contract cost reductions were based on information available at the time of the renegotiations and were calculated using a negotiation model that the department used when evaluating the effect of different renegotiation options on the reduction in contract costs.
While this savings estimate reasonably reflects reductions in the nominal cost of the contract portfolio to the department, an alternative analysis would estimate the savings to the utilities' customers. With consideration of the replacement power costs and using a revenue requirement model, a department consultant currently estimates that the net savings to ratepayers in nominal terms is $1.5 billion. Also, because these savings will occur over the next 20 years, the department consultant currently estimates that the net present value of the future stream of savings to ratepayers is $580 million. These March 2003 estimates of customer savings are a function of economic, market, and dispatch assumptions used by the department consultant in its modeling and would change if those assumptions changed. Also, the department indicates that its revenue requirement model is not designed to value nonprice benefits resulting from the renegotiation efforts, such as the improved availability and reliability provisions in the contracts. Further, most of these contract cost reductions will result not from reducing the price per megawatt-hour of the power purchased but rather from shortening the length of the contracts or reducing the amount of power to be delivered. However, this reduction of contract length contributed to a department objective to shorten the time that it would have financial or legal responsibility for the contracts and, in the process, permit the utilities to procure energy themselves to meet the additional uncovered net short.
According to the department, the March 2003 estimate of savings to the consumer from the renegotiated contracts as of December 31, 2002, using the revenue requirement model, was made only at our request, and the department would not otherwise have made this calculation. In addition, the amounts are from its consultant's draft report, and as of March 17, 2003, the amounts had not gone through the department's ordinary standards of review for reports of this nature. However, this is the only estimate the department provided to us of the savings to the consumer from the renegotiated portfolio as of December 31, 2002. Further, we observed that these forecasts are consistent with the forecasts prepared by the department consultant in establishing the department's revenue requirements and were also used in support of the revenue bonds that the department issued in October and November 2002.
Our review of the legal terms and conditions of the restructured contracts indicates that although the economic benefits to individual consumers are likely to be modest, the renegotiations have generally resulted in improved terms over those in the original contracts, as shown in our updated report card evaluation of certain contracts. For example, we found that the restructured contracts have much stronger guarantees that the sellers will deliver the power promised under the contracts and build the new generation facilities promised in the contracts. As a result, the renegotiated contracts better meet the reliable energy goals of AB 1X and thus better ensure the availability of electricity to satisfy consumer demand. These improvements are accomplished through stronger terms and conditions, such as termination rights for the State and penalty provisions when sellers fail to deliver energy or construct new generation facilities as promised under the contract. Changes in the type of energy products purchased under the contracts also increase the reliability of the department's long-term contract portfolio. Both the stronger terms and conditions, and the product changes are likely to provide economic benefits to ratepayers.
Another benefit from the renegotiations is that the State has entered into settlement agreements with suppliers, in some cases substantial ones. In most of these settlements, the suppliers agreed to cooperate with the attorney general's energy investigation and to make financial settlements to the State.
While the restructured contracts are better from a legal standpoint, significant risks remain for the department, particularly in the contracts that the State has not renegotiated. An area of continuing concern is the restrictions on the department's ability to assign the contracts to other parties, particularly to the investor-owned utilities. Now that the department's power-purchasing authority under AB 1X has expired, the investor-owned utilities have resumed purchasing the net short and have also assumed the day-to-day management and operation of the contract portfolio. Nonetheless, the department remains legally and financially responsible for the contracts, until either the investor-owned utilities meet certain credit standards or suppliers decide to release the department from this obligation. As a result, the department continues to have significant ongoing legal and technical responsibilities for the management of the long-term contracts and could retain those responsibilities for the remaining life of the contracts.
In our December 2001 audit, we indicated that in future years the department would have significant amounts of surplus power that it would need to sell. In 2002 the department did sell surplus power, but these sales were not significant in proportion to the department's total purchases. Our consultant advises us that the costs reported from the department's surplus power sales do not appear unreasonable. Although the department's renegotiation efforts have reduced the potential for surplus power sales in future years, it is still likely that significant sales will occur, particularly in the years 2003 through 2005. However, because providers of the net short must ensure that they have sufficient power to meet demand, some sales of surplus power are inevitable to ensure a sufficient supply of power.
The department was not able to achieve a coordinated dispatch of power supplies between the contract portfolio and the investor-owned utilities' generating facilities so as to minimize costs to ratepayers. The electric power that the retail customers of the investor-owned utilities purchase is obtained from a variety of sources—hydroelectric dams, nuclear, and fossil fuel-fired power plants that the utilities own, as well as a variety of contracts with suppliers entered into by the department and the investor-owned utilities—each with a different cost per unit of power delivered during different times of the day and week. As such, there is an opportunity each day to optimize this mix of sources to provide power at the lowest possible cost. In our December 2001 audit, we cite a specific example in which small savings in daily power costs could result in annualized savings to the ratepayers of tens of millions of dollars. However, the department has been unable to implement a coordinated dispatch of power sources with the investor-owned utilities. It attributes this inability, to some degree, to the investor-owned utilities' failure to share with the department information about the availability of their generating facilities and the terms of their third-party contracts, as well as to fluctuations in demand forecasts by the investor-owned utilities that make minimizing purchase costs more difficult.
Finally, substantial work remains to be done by others to restore California's electric markets to full health and to manage the power portfolio assembled by the department during its two-year tenure as power buyer for the State. Issues involving the creditworthiness of the investor-owned utilities must be resolved, plans must be made for the long-term governance of the utilities' power-procurement practices, and changes are needed in the power market structure to assure that the markets are effective and well monitored. Although California's power supply situation has improved over the past two years, accounting and credit issues have affected many companies in the power supply industry, raising questions regarding the further development of new supplies. Furthermore, substantial outstanding investigations and litigation associated with the power crisis are still unresolved. As this range of issues makes clear, much remains to be done to stabilize the State's power markets.
In addition to marketwide issues, the department's ongoing stewardship of the Electric Power Fund and the contract portfolio will be an important component of the State's power supply for years to come. The contract portfolio is likely to remain under department management for much of the next decade and will require continued vigilance to mitigate the potentially high costs of those contracts. Attendant upon those responsibilities will be the need for the department to manage its operating partnerships with the utilities to schedule and deliver the power and to procure fuel. In addition, the department will continue to be responsible for managing the Electric Power Fund and for the administration of the bonds issued to finance the cost of the AB 1X power program. These remaining responsibilities carry substantial ongoing obligations to manage costs and risks and will require a sustained professional organization at the department to properly protect the State's interests.
The department's future activities can be described as falling into four broad categories, each defined by basic contractual responsibilities that it will carry into the future. Our recommendations are that the department continue to (1) meet its legal and technical responsibilities regarding the contract portfolio, (2) manage the operating agreements that set forth how the investor-owned utilities are to operate the contracts, (3) manage the servicing agreements with the investor-owned utilities under which the department collects revenues from the utilities to pay for power and debt service, and (4) service the revenue bonds that were issued to finance the power-purchasing program.
The department indicates that it appreciates our efforts along with those of our consultant in preparing this report.