California: The Financial Effects of the Crisis
By Robert B. Weisenmiller, Steven C. McClary, William Monsen & Heather Vierbicher
Californians received an early warning in May of what is expected to be a long summer of blackouts. Hot weather pushed up air conditioning loads and plant outages limited supply, forcing the California independent system operator to implement rolling blackouts. More than 225,000 Californians had their electricity cut off on May 7 and 8. The blackouts were a reminder of the four days of blackouts — and numerous “stage 1” and “stage 2” alerts — earlier this year. They are a harbinger of things to come.
Unprecedented levels of outages are expected to hammer California this summer.
Low water levels throughout California and the Pacific Northwest will significantly reduce hydroelectric generation. Fewer customers are available for voluntary interruption than in 2000. Available generation will be limited by concerns about creditworthy buyers, permit limitations, potential gas curtailments and high gas prices, the operational limitations of aging power plants and — possibly — market manipulation. Regulatory and political efforts in California to promote conservation and add peaking plants have been too little and too late. The California supply system has little or no cushion.
The North American Electric Reliability Council predicts California will be forced to curtail customers for up to 260 hours. Other estimates put the number of blackout hours as high as 1,000 if the summer is warmer than normal.
Rotating blackouts are the most obvious sign that California has failed to tame the power crisis that erupted last fall. However, once the blackouts are over, the citizens and businesses in California will continue to suffer from the after effects of the crisis.
This article focuses on the longer-term financial impact of the electricity crisis for the state, its citizens and some key players in the market.
Roots of a Financial Meltdown
Pacific Gas & Electric Company, or PG&E, and Southern California Edison, or Edison, were trapped until recently between runaway wholesale market prices and frozen retail rates. The two utilities ran up deficits at a rate of about $1 million an hour in order to buy electricity for their customers. Although both utilities borrowed money to keep up with their mounting losses, the creditworthiness of both evaporated as these deficits climbed. The financial hemorrhaging ultimately led both utilities in January 2001 to default on payments to the California power exchange — or CalPX — and California independent system operator — or Cal ISO — which, in turn, could not make payments to generators and power markets who had sold through them. The utilities also stopped payments to qualifying facility projects — or QFs — gas suppliers and lenders. Eventually, this led to the CalPX filing for bankruptcy.
Electricity suppliers refused to sell to PG&E, Southern California Edison and the Cal ISO due to credit concerns. The state then stepped in to fill the gap.
California’s Department of Water Resources, or DWR, is now the single largest power buyer in California. California Governor Gray Davis signed legislation in February authorizing DWR to enter into contracts for the purchase of electricity and to provide power not only to PG&E and Edison, but also to local publicly owned electric utilities. To date, DWR has negotiated about 25 long-term contracts with terms of up to 20 years; the agency has nearly 10,000 megawatts under contract for the period 2001 to 2010. Few details of these contracts are public.
DWR is covering most of the utilities’ “net short” position — the power needed to meet electricity demand after accounting for purchases from QFs and generation still owned by the utilities. DWR’s purchases, combined with an average 7% demand reduction due to conservation by consumers, are expected to cover about 70% of that net short position in June and July and 60% in August. In other words, DWR will be forced to buy over 10% of California’s power needs in the spot markets this summer. DWR already has spent well over $5 billion for power purchases.
The governor plans to reimburse the general fund and finance power purchases for the remainder of 2001 from the sale of $13.4 billion in revenue bonds. This will be the largest municipal bond issue in US history, dwarfing a 1998 Long Island Power Authority issue. The governor signed legislation authorizing the bond sale in May.
Governor Davis claims the revenue earned from the sale of bonds will be sufficient to replenish state coffers. However, those projections are based on the state paying an average price of $195 an mWh during the hot summer months ahead. Power at that price may be hard to find. Futures prices for power are closer to $300 an mWh for the summer months. This spring, the state paid on average $346 an mWh for power. Thus, there is uncertainty about the ultimate size of the bond issue and whether it will be enough to cover the state’s purchases in the months ahead. In addition to these uncertainties, other factors could undermine the state’s ability to issue the bonds.
The PG&E bankruptcy is complicating the bond issue. PG&E filed for reorganization under Chapter 11 in federal bankruptcy court on April 6. The utility said it had run up debt of more than $9 billion by the time of the filing. Its principal creditors are independent generators and power marketers, natural gas suppliers and banks. This is the largest investor-owned utility bankruptcy and the third largest corporate bankruptcy in US history. Robert Glynn, Jr., chairman of Pacific Gas and Electric Company, said of the bankruptcy filing, “We chose to file for Chapter 11 reorganization affirmatively because we expect the court will provide the venue needed to reach a solution, which thus far the state and the state’s regulators have been unable to achieve. The regulatory and political processes have failed us, and now we are turning to the court.”
The threat of a potential ballot initiative to overturn the revenue bond legislation could also slow or halt the bond sale.
Effect on QFs
One group hit hard by the utilities’ financial meltdown is California QFs. More than 600 QF projects provide 20% to 30% of California’s power under long-term contracts, with prices below current market prices. The utilities owe these QFs approximately $2.3 billion. Edison stopped making payments to QFs in November 2000. PG&E paid QFs for purchases in November but, starting in December, paid for at most 15% of power deliveries through the end of March 2001. Many of these QFs were project financed. The utility defaults forced many of them to default on payments to their suppliers and lenders.
Not surprisingly, increasing numbers of QFs have had to shut down. Natural gas suppliers demanded cash payments for fuel deliveries and refused to extend credit to QFs. Without fuel deliveries, some QFs were forced to stop generating. As much as 3,000 megawatts of QF capacity went offline. On March 19 and 20, California was hit with rotating blackouts, affecting as many as 450,000 customers.
Some QFs took their cases to the courts and the Federal Energy Regulatory Commission. Caithness filed suit in a Nevada federal court for authority to place a lien on Edison’s share of the Mohave generating station. The Nevada court sided with Caithness, allowing the lien to be put in place until Edison made good on past payments to Caithness. CalEnergy filed suit against Edison for the right to sell power to other purchasers without terminating its power purchase agreements. A California court ruled in CalEnergy’s favor, granting it the right temporarily to suspend deliveries of capacity and energy to Edison and to sell to other purchasers. Ridgewood Power and several other QFs asked FERC for permission to sell power in the wholesale market.
QF problems caused by the utility defaults are intertwined with a controversial regulatory proceeding. In August 2000, Edison disputed the use of Topock — a major California gas delivery point — gas prices in a formula used to determine short-run avoided cost, or “SRAC,” payments to certain QFs. Edison claimed that use of the formula to determine the avoided cost price results in a price that exceeds Edison’s true avoided costs because natural gas market prices were distorted by market power problems in the gas market. While California regulators considered changing the formula, Edison began to withhold payments from QFs.
After the March blackouts, California regulators directed the utilities to resume paying QFs for future deliveries but at the same time approved Edison’s request to change the formula underlying the SRAC prices. The new formula lowers the prices the utilities must pay to QFs for their power. California regulators replaced the southern California Topock index with one based at Malin, Oregon — the delivery point for gas to northern California — plus the intra-state transportation tariff rate for delivery within the state. In May, the price paid to QFs was 20% lower than what QFs would have earned for their power under the previous SRAC pricing formula. While California regulators ordered the utilities to pay QFs for power purchases on a going-forward basis, past payments owed to QFs remain in limbo.
The decision by the California Public Utilities Commission to revise the formula underlying payments to QFs brought an avalanche of formal protests and lawsuits. QFs argued that the regulators overstepped their bounds, violated PURPA, violated CPUC statutory authority and due process, and made a decision not supported by evidence. Many QFs did not resume full operation after the CPUC decision.
In response to these protests, the CPUC launched an investigation into whether QFs were meeting contractual performance obligations, pointedly noting that QFs that were not generating power were affecting the state’s energy crisis and questioning actions QFs had taken in courts and at FERC to sell power outside of their contracts. A press release issued by the CPUC said, “The QFs are seeking to divert electricity they supply under contractual arrangements with the utilities and instead sell that electricity to third parties at higher ‘market’ rates.” The CPUC directed the utilities to file a report with the CPUC outlining the status of energy deliveries over the past 12 months for each QF supplier and to notify the CPUC of any QFs that have made declarations of intent to withhold future deliveries.
Effect on Ratepayers
California ratepayers will face sticker shock when they open their electric bills in June. The state’s utilities are just now implementing a new rate increase approved in late March by the CPUC. The impact of the increase may show up in June bills. The rate increase is supposed to finance the state’s power purchases.
In January, the CPUC raised all customers’ retail electric rates by 1¢ a kWh. The rate increase, called an “energy procurement surcharge,” was allocated to customers on an equal cents per kWh basis. The increase was intended to be a temporary measure, giving the CPUC time to investigate the utilities’ financial situation in more depth.
However, time and events did not stand still for the regulators. The utilities’ financial condition deteriorated and the state’s power purchase bills mounted. In late March, the CPUC approved an additional 3¢ increase and made the January 1¢ increase permanent. The combined increase – equivalent to about a 40% rate hike – was the largest rate increase in California history. The increase has not affected all customer classes equally. Residential and small business customers that are heavy users of electricity and medium-and large-size customers will bear the brunt of the rate increase. Residential users who conserve energy and keep use below certain thresholds will see little or no increase.
The CPUC has still not addressed completely the priority among the state government, the QFs and utilities for laying claim to the additional revenue brought in by the rate increase. The state cannot sell bonds unless the bondholders are guaranteed an acceptable claim on a share of the revenue. It is not yet clear whether — even with the rate increases — there will be enough money not only to cover the costs of buying power on a going-forward basis, but also to repay the billions of dollars the state has already spent this year.
Appeals are likely to any CPUC decision on the waterfall for these revenues among competing claims.
The utilities have still not been reimbursed for shortfalls run up last year. Several plans are being pursued to address these shortfalls. California officials and utilities are seeking a FERC decision to require both public and private generation owners and power marketers to refund “overpayments” caused by the high prices paid in 2000. This would reduce the shortfall between utility revenues and costs. However, FERC has found only limited potential “overpayments” to date. Even if FERC ordered refunds of all the charges identified as potentially subject to refund, the amounts identified thus far would make no appreciable dent in the utilities’ shortfall.
It is not clear that the $13.4 billion the state plans to borrow this summer will be enough to cover what it will have to pay to buy electricity or that it will even be able to sell its bonds. California could easily find itself having to increase rates further or to dip further into the budget surplus.
In addition, under a recently-executed “memorandum of understanding” between the DWR and Edison, Edison would sell its transmission assets to the state at a price above book value and apply the extra revenue against past undercollections, in an attempt to avoid bankruptcy. The memorandum authorizes Edison to issue bonds for the remaining revenue shortfall to be paid by customers in the future. Edison’s remaining shortfall is estimated to be $2 billion.
The proposed deal between Edison and the state has little support in the California legislature. The deal is opposed by consumer groups and the left wing of the democratic party as a bailout for Edison and by most republicans as a plan to put the state in the power transmission business. The plan addresses electricity problems at most only in southern California. There is nothing to recommend the plan to legislators from the northern part of the state.
At the end of the day, California’s ratepayers may already have been hit with record rate increases, but they should expect more increases. Higher rates will eventually dampen electricity demand, thereby reducing future generating capacity shortfalls.
Effect on State Government
The golden state’s finances are not looking very golden. The dot-com economy bubble burst. An overall economic slowdown appears likely. Tax revenues are expected to decline. Pending rate increases will disproportionately hit California industry.
Credit rating agencies placed the state on credit watch in January. In April, Standard and Poor’s lowered the state’s rating on general obligation bonds from “AA” to “A+”. It similarly revised other lease ratings and ratings for the California health facilities construction loan insurance fund, known as Cal Mortgage. Only the state’s cash reserves, diverse economy, and the planned sale of revenue bonds saved California from a more drastic rating downgrade. Other ratings agencies followed suit with their own credit downgrades.
In May, Governor Davis revised his budget proposal for the upcoming fiscal year. The revisions lowered previous projections by $5.7 billion. The governor proposed cutting spending for transportation, housing, and the environment by $2.5 billion as a result. California’s budget surplus is now expected to dwindle to only $1 billion next year, down from over $5 billion this year. Some political observers believe the governor proposed insufficient reductions and an inadequate reserve, leaving the legislature to assume responsibility for another $2 to $3 billion in budget cuts.
According to the state controller, California has paid $5.1 billion through early May to buy electricity. Nearly all was to cover purchases made in the spot market. DWR paid only $36 million for power under long-term contracts. The rest was short-term spot market power. In January, the governor projected the state would only spend $1 billion to address the electricity crisis. In fact, the state is now spending about $70 million a day and $1 billion a month.
The key question is how long California can maintain such spending. The answer may be until November 15, 2001. After that, general fund expenditures for short-term purchases of electricity cannot exceed $500 million in the aggregate. This legal restriction, codified recently by the legislature, is intended to protect the general fund from future energy purchases.
The scenario could hardly be more bleak. Current monthly spending is twice this amount, almost all of which is spent on spot market purchases, but the state will be restricted to spending only $500 million. It is far from obvious that either PG&E or Edison will be financially capable of reassuming the responsibility for power procurement if the state is forced to exit the business.
Effect on PG&E Creditors
The full financial impact of PG&E’s bankruptcy filing cannot be known at this point, but it will undoubtedly be far-reaching. There are approximately 100,000 claims against the utility in addition to the top 20 creditors (see table). In addition, consumer advocacy groups and nonprofit groups are seeking their place at the negotiating table.
One important issue in the early stages of the bankruptcy proceedings is the jurisdictional clash between the CPUC and the court. PG&E is seeking an injunction from the bankruptcy court against part of a March CPUC order. In that order, the CPUC required PG&E to recalculate various transition cost balancing accounts back to 1998. The effect of the order was to reduce PG&E’s net undercollections. If upheld, the effect would be to shift billions of dollars of liability from PG&E’s ratepayers to shareholders. The CPUC is claiming that it has sovereign immunity from bankruptcy court jurisdiction, and this overrides the PG&E reorganization effort.
The fiscal impact of PG&E’s bankruptcy filing on those QFs holding PG&E receivables is another unknown. PG&E wants to delay its decision on whether to assume or reject the QF contracts until it finishes working out a reorganization plan. QFs have filed a variety of petitions with the bankruptcy court including ones asking for the suspension of their obligations under the contracts with PG&E.
Meaningful solutions to California’s electricity crisis have been hard to achieve. Although all parties have solutions, partisan bickering, longstanding animosities, and real conflicting interests hamper the search for a consensus.
The political agenda is dominated by attempts to shift blame to someone else. California officials claim the problem is that the federal government has refused to implement regional price caps while Texas-based generators manipulate energy markets and Federal regulators. Federal officials point to California’s decision to implement a flawed restructuring program, hinder the development of an effective regional power market, attempt to repeal the laws of economics and hamper the development of new supplies by a cumbersome siting process.
Governor Davis recently declared “war” on the generators and power marketers and has signed legislation to set up a state power authority.
The state attorney general, Bill Lockyer, who has been investigating the practices of power generators and marketers for almost a year, said recently, “I would love to personally escort [Enron Corp. Chairman Kenneth] Lay to an 8 x 10 cell that he could share with a tattooed dude who says, ‘Hi, my name is Spike, honey.’”
The politicians also continue to rail against the state’s utilities. Perhaps in response, PG&E appeared to time its bankruptcy announcement so that it was made the morning after the governor went on state television to unveil his plan to tackle the electricity shortage.
Among the few areas of consensus are the need for new supplies and additional conservation.
The California Energy Commission has expedited the applications for several peaking plants. Governor Davis issued an executive order directing the commission to permit new peaking and renewable power plants on an expedited schedule. Power plants that are permitted under this emergency process are exempt from the requirements of the California Environmental Quality Act. California has also relaxed its stringent air emissions limitations for this summer.
Governor Davis also issued an executive order to encourage greater energy conservation. The order directs the CPUC to create financial incentives for conservation by residential, commercial and industrial customers. Under this program, the utilities will provide rate reductions of up to 20% to consumers who reduce their electricity consumption by at least 20% during June to September 2001. The program will be financed through a reduction in the utilities’ payments to the Department of Water Resources in subsequent months.
These efforts may provide some help to California this summer, and will certainly bring more relief in 2002.
The California Energy Commission has permitted 24 power plants in recent years, of which nine plants representing over 6,000 megawatts are under construction. The first 3,000 megawatts should be on line by the end of this year.
In the end, the market may be a powerful enough force that it overcomes the political muddle. Californians are just starting — half a year into the crisis — to see meaningful price signals, which should dampen demand. Normal rainfall should eventually return to the West and further increase supplies. Increased gas drilling and expansions of the gas system should dampen the Western gas basis differential. In the longer term, the market will adjust. The forecast in the shorter term is for an intemperate summer.