California: Crisis Over? As summer turns to autumn, the electricity and gas markets in California are more or less back to “normal”

California: Crisis Over? As summer turns to autumn, the electricity and gas markets in California are more or less back to “normal”

October 01, 2001

As summer turns to autumn, the electricity and gas markets in California are more or less back to “normal.”

By late September, electricity spot market prices were around $30 a mWh, well below the federal price caps of $90 a mWh. The last electric system emergency alert occurred on July 3.The state emerged from the summer without suffering a single additional rolling blackout. Daily reserve margins occasionally reached as high as 20%.

The independent system operator, or “ISO,” reports a peak load hovering around 35,000 megawatts while available generation is around 42,000 megawatts.

The state Department of Water Resources, or “DWR,” which is responsible for procuring power for the financially-crippled electric utilities in California, has so much power locked up under high-priced short- and long-term bilateral contracts that — at times — it has had to dump power at prices as low as $1 a mWh.

Gas prices at the California border have plummeted from their winter highs of more than $10 an mmBtu to much less than $3 an mmBtu. Gas storage levels are on target both to meet supply needs and to provide a hedge against supply shortages.

What happened? Have the electric and gas markets in fact returned to normal or is the current situation just a lull in the storm?

Why Did Prices Fall?

A combination of factors — often alluded to as the “perfect storm”— led to the California power crisis. (For background on the crisis, see “California at Sea: The Perfect Political Storm” in the NewsWire for December 2000.) The apparent return of the market to normalcy is the result of a similar convergence of factors.

Conservation Helped

The state recognized it could not rely solely on “building” out of the electricity shortage. Demand reduction measures helped bring supply and demand back into balance. First, the California Public Utilities Commission, or “CPUC,” authorized record rate increases for electric customers and these brought about price-induced conservation. Second, almost as an act of faith, the state initiated a set of very aggressive conservation programs at a cost of more than $1 billion. These programs ran the gamut from a statewide public information blitz — including placemats in fast food restaurants with energy saving tips printed on them — to complex, market-driven peak demand reduction schemes. This two-pronged approach appears to have contributed measurably to lower peak demands for electricity.

The electricity rate increases this year were the first statewide since 1996. Retail rates for the heaviest residential users increased about 37%. Rates for small businesses increased an average of 38 to 45%, while industrial customers saw a nearly 50% increase. Agricultural customers flexed some of their political muscle and ended up with rate increases of only 15 to 20%. The new rates had an “inverted block” structure, meaning that rates increased as consumption increased. For example, residential customers who consumed less than a pre-specified baseline level did not see any meaningful rate increase but customers who consumed more saw rate increases of between 13 and 100%. High prices cause consumers to consume less.

In addition, customers who managed to reduce monthly usage by 20% compared to the year before were paid a 20% rebate on their electricity bills by the state. This program was surprisingly successful. Three million customers qualified for the rebates in June and 4.3 million qualified in July, which was three to four times the expected participation rate. Total rebates during June and July were $155 million.

Traditional utility demand-side management, or “DSM,” programs played a significant role as well. Over the past few years, California’s utility conservation programs were not aimed at immediate demand reductions but, instead, attempted to bring about long-term changes in customers’ energy usage habits as well as to develop markets for energy-efficient devices. As a result, the utilities would under-spend DSM budgets and achieve little in the way of near-term energy conservation or peak demand reductions. This all changed in 2001, when “savings now” became the mantra. Rebates and direct subsidies for the purchase and installation of energy-efficient appliances and equipment again became the norm. The CPUC set very high peak demand and energy conservation reduction targets for the utilities while giving the utilities a freer hand as to which DSM programs to pursue.

Customers swarmed to the utility rebate programs. Through the second quarter of 2001, the three major electric utilities spent or committed almost $200 million of their annual budgets of $259 million. The programs were so successful that all three utilities have had temporarily to shut them down due to lack of funds. This is all the more impressive considering the programs did not become available until late February 2001.

The three utilities have achieved combined annual savings of about 800 million kWh and a peak demand reduction of 200 megawatts. This is collectively about 80% of the savings targets set by the CPUC, which, at the time the targets were set in January, seemed ridiculously aggressive. All three utilities are on track to achieve their targets well before the end of the year. Southern California Edison has had the best results to date, achieving over 114% of its peak demand reduction target and over 90% of its energy savings target by July 1.

How did these conservation efforts affect electricity consumption and peak demand this summer? The results are startling.

Both peak demand and overall consumption were about 5.5% lower in 2001 than in 2000. Adjusting for weather and the downturn in the economy, the California Energy Commission estimated that conservation saved closer to 9%. It is difficult to determine exactly how much of the decline is attributable to what factors. However, it is clear that a concerted program of consumer education, carrots (rebates) and sticks (steeply increasing prices) can, in a very short time, have a substantial impact on electricity use.

Gas Prices Fell

The California power system relies on natural gas as its marginal fuel. Thus, soaring gas prices last year contributed to higher power prices. Conversely, the falling gas prices of the past few months have helped to bring down spot and forward power prices.

Several factors are responsible for the decline in gas prices. Mild weather, a slowing economy, and electricity conservation resulted in lower demand for natural gas and more opportunities to inject natural gas for storage than the previous summer. The other important factor was Pacific Gas & Electric’s solution to the credit concerns of gas suppliers, which prevented any disruption to gas supplies to PG&E and the utility’s customers. (See box on page 18 called “Overview of California Gas Infrastructure.”)

The original run-up in gas prices was stunning. Demand for natural gas increased by 8% in 2000 as compared to 1999, largely due to increased in-state gas-fired electric generation. The demand for greater quantities of in-state gas-fired generation resulted from dry hydro conditions in the Pacific Northwest, low availability of power imports, and increased electricity demand in many sectors due to a thriving economy.

Injections of gas into storage effectively ceased in July 2000, with significant storage withdrawals occurring in August. Reduced levels of gas in storage led to less gas inventory available to serve winter peak demand and to provide protection against price spikes.

PG&E’s credit problems also contributed to the gas price run-up last winter. Gas suppliers became concerned that PG&E would be unable to pay for gas and would only sell to the utility for cash, with reasonable assurance of payment, or under Presidential decree. PG&E was forced by its deteriorating financial condition to withdraw gas from storage to meet its winter core loads. PG&E warned that it was facing a situation where it would have to cut off customers. Last January, the CPUC granted a request by PG&E to allow the utility to pledge its gas customers’ accounts receivable for the purpose of procuring gas supplies for its customers. Core gas in storage was pledged as collateral in case the core customers’ receivables were insufficient for suppliers’ concerns. Through this pledge and the nearing end of the winter season, PG&E was able to purchase sufficient gas supplies to serve all of its customer loads — despite filing for bankruptcy on April 6.

The California Public Utility Commission asked the federal government to investigate whether the consistently higher Topock price premiums were the result of market abuses by El Paso Natural Gas Company and El Paso Merchant Energy. The Federal Energy Regulatory Commission launched a formal hearing into these allegations in May.

In February 2000, El Paso Natural Gas Company awarded 1,220 mmcf a day of firm capacity to its affiliate, El Paso Merchant Energy. The CPUC and Southern California Edison claimed that El Paso Merchant Energy used market power to manipulate natural gas prices in California, which contributed in turn to higher electricity prices. Southern California Edison presented as evidence a report by The Brattle Group that El Paso Merchant Energy had manipulated natural gas prices by withholding 35% of the available capacity on the El Paso and Transwestern pipelines, resulting in $3.6 to $3.8 billion in higher natural gas costs for Californians. El Paso Merchant Energy countered with reports by Economists, Inc. and Lexecon, Inc. that said El Paso had neither the opportunity, means nor motive to control pipeline capacity in order to raise California’s gas costs. In June 2001, El Paso Natural Gas split the disputed capacity among 30 different natural gas shippers when its affiliate’s capacity contract expired. While this nullified future concerns about market manipulation, El Paso’s past actions remain hotly debated. The FERC judge has yet to issue a decision.

California natural gas prices spiked to record levels in late 2000 and early 2001, but have now returned to pre-2000 levels. Bidweek prices at the California delivery points of Malin and Topock broke through the $3 threshold in June 2000 and did not drop back below this threshold until July 2001. Prices at these delivery points rose far above other regional markets, such as Chicago.

At Topock, bidweek prices peaked at $16.41 an mmBtu in January 2001. At Malin, bidweek prices peaked at $14.42 in December 2000. The national average price of gas was $6.88 an mmBtu.

Daily gas prices were even more volatile. For example, in response to a cold front, Topock daily prices peaked between $54 and $59 an mmBtu during December 9 to 11, 2000, while falling as low as $13.20 an mmBtu during the same month.

Gas prices began to fall in January and February, bumped back up in May, and then resumed falling.

The expectation that the high summer 2000 gas demands would reappear in 2001 were reflected in the premiums paid for June bid-week prices in California as compared to the Henry Hub. The Topock-Henry Hub differential was $7.99 an mmBtu and the Malin-Henry Hub differential was $2.25 an mmBtu. However, bid-week prices at Topock dropped throughout the summer months: July, August and September bid-week prices fell to $4.75, $3.76 and $2.65 an mmBtu, respectively. At Malin, July, August and September bid-week prices dropped to $3.24, $3.14 and $2.34 an mmBtu, respectively. By September, the differentials between Henry Hub and the California delivery points fell to $.29 an mmBtu at Topock and $.10 an mmBtu at Malin.

By mid-September 2001, the American Gas Association reported that US storage fields were 81% full as compared to 68% full last year. Storage fields in the western consuming region were 85% full in mid-September 2001 as compared to 72% full at that time last year.

Gas pipeline companies are working to address the longer-term gas transportation shortage that exists in California. Currently, interstate capacity to California exceeds intrastate receipt capacity by 345 mmcf per day. Approximately 6,480 million cubic feet per day of interstate natural gas pipeline capacity to California has been proposed, along with 645 mmcf per day of California intrastate natural gas pipeline capacity. If all of these pipeline expansions were built, there would be a shortage of takeaway capacity at the California border — only 300 mmcf per day of the 6,480 mmcf per day of deliveries could be delivered to the local distribution companies. How many of these expansions are actually built will depend on responses from open seasons, utility plans and regulatory policies. With such a number of potential interstate pipeline expansions being proposed, it seems likely that the natural gas supply situation in California will change in the next few years, possibly to one of excess capacity.

New Power Plants Came On Line

California has among the most stringent air quality rules in the nation, and many power plants can only operate a limited number of hours per year as a result of emission caps in their air permits. In 2000, many power plants produced much more power than the plants had generated in the past decade. In fact, some plants generated 50% or more power compared to the plants’ recent history. However, since emissions caps were often instituted based on historic emission (and generation) patterns, some plant operators either violated their emissions caps or had to buy emissions credits to allow them to continue running during the power emergency. As a result of increased demand, the price of emissions credits soared to record levels, resulting in increased power costs.

Operators of gas-fired generating facilities with high capacity factors rushed to install pollution control measures, such as selective catalytic reduction, or “SCR,” to avoid the need either to buy emissions credits in the future or to violate emissions caps. SCR has now been installed in plants representing about 2,400 megawatts, with retrofits at 4,600 megawatts of additional generators planning or pending. These actions will reduce the demand for emissions credits. In addition, the South Coast air quality management district also reformed its emissions credit trading program for power plants to reduce the impact of offset trading on power prices throughout the rest of California.

Other actions have been taken to reduce the impact of air pollution regulations on generation from existing plants. Governor Davis used his emergency powers to direct air districts to issue variances to power plants in return for substantial mitigation payments. The governor issued another emergency order to allow the use of backup generators as a means of preventing blackouts, but this provision so far has not had to be activated. These measures are temporary: all of the governor’s emergency orders will expire on December 31, 2001.

California also took steps to increase the number of power plants. In the past three years, the California Electricity Commission has approved more power facilities than it had on a cumulative basis in the prior 20 years. Some of these approved projects are under construction and two Calpine projects are now operating. The governor issued an executive order to expedite CEC permitting and established a goal of having an additional 5,000 megawatts on line by the end of September. While not meeting this ambitious goal, approximately 2,279 megawatts of new generation capacity will become operational in California by the end of September, with another 1,000 megawatts expected to become operational by the end of the year.

Over the next few years, the new supply situation looks healthy. Another 3,500 megawatts is expected to come on line by next summer.

As of August 1, the DWR had executed about 40 contracts and reached an agreement in principle on another 18. Moreover, many of these contracts are the credit support for projects that are under construction or in planning or permitting. Also, the state legislature this year established the California Consumer Power and Conservation Financing Authority, which has adopted a goal of adding up to 3,000 megawatts of additional resources by next summer. This new agency wants to develop a portfolio that contains about 1,000 megawatts of renewables and an additional 2,000 megawatts of gas fired peaking plants as insurance against price spikes in California. These peaking plants would be owned and operated by the state government.

There has been less progress on transmission upgrades. The CPUC has approved and expedited the construction of at least 31 transmission upgrade projects at a cost of more than $120 million. However, major transmission upgrade projects such as Path 15 between northern and southern California, Rainbow-Valley into San Diego, additional transmission capacity into the San Francisco area peninsula, and upgrades into the rapid load growth areas of San Jose and Tri Valley have been controversial and are proceeding much more slowly through the CPUC’s certificate of public convenience and necessity and environmental review processes.

The reliability of new generation facilities will also require the expansion of gas pipeline capacity discussed earlier.

Regulatory Actions Helped

Two important federal regulatory actions provided much needed price stability in western wholesale electricity markets. First, FERC directed California last December to shift from its reliance on the Power Exchange, a spot market, to long-term bilateral contracts. DWR’s power purchase contracts accomplished this. Moreover, these contracts addressed credit issues for the suppliers, which has further stabilized the market.

Second, FERC imposed price caps in an 11-state area in the West. Although there have been a number of challenges to this sweeping order, and there are also numerous implementation issues, the price caps have played a significant role in stabilizing western electricity markets. The unresolved implementation issues include the application of the must-offer requirement to “slow start” units, reliance on the price of California marginal units when the Pacific Northwest has its peak this winter, and the demise of ISO ancillary service markets for replacement reserves given the “free call option” required by the must-offer requirement.

Who Will Pay the Bill?

Even with the return to normalcy, there is still a very significant issue associated with recovery of past power costs. PG&E and Southern California Edison ran up bills of $14 billion before the DWR stepped in to buy electricity for them. The DWR has paid about another $10 billion to buy electricity. Generators have unpaid claims for billions of dollars.

As the NewsWire goes to press, at least three generators are talking about forcing Southern California Edison into bankruptcy.

PG&E announced a reorganization plan in mid-September to emerge from bankruptcy. The plan claims to repay fully all creditors and, at the same time, not to increase electric rates for PG&E’s retail customers. The cornerstone of PG&E’s proposal is a shift of assets from the CPUC-regulated distribution company to three new FERC-regulated companies. One of the newly created entities would own and operate about 7,100 megawatts of nuclear and hydroelectric generating units and control some low-cost power contracts with northern California irrigation districts. Another entity would own and operate PG&E’s electric transmission system as part of a FERC-approved western regional transmission organization. A third entity would own and operate PG&E’s backbone gas system as an interstate pipeline. PG&E believes that this transfer of assets can occur as part of the bankruptcy reorganization plan without CPUC approval but with approval by the appropriate federal agencies. The new PG&E generating company would commit to sell all of its power to the distribution company for 12 years at long-term market-based rates. Generators and some other creditors would receive 60% of their receivables in cash and 40% in long-term notes from the three new companies. The distribution utility would not return to the procurement business unless it is guaranteed a passthrough of these expenses, and it would not be assigned any of DWR’s contracts.

Meanwhile, Governor Davis claims that California is owed $8.9 billion for overcharges by power sellers. The governor hopes to use any refunds to cover some of the outstanding power procurement costs. FERC established a settlement conference to consider these claims, but the judge ultimately concluded that California would be unlikely to demonstrate that there were more than $1 billion in overcharges, which is far less than the amount of the unpaid bills. FERC then took the extraordinary step of expanding the amount of the potential refunds by including extra-jurisdictional entities. Hearings are set for this fall on these issues. Any and all FERC decisions on the issue of power refunds will be challenged in the courts by both California buyers and also power suppliers.

Aside from hoping for a big refund from power suppliers, California is preparing for “the mother of all bond issues”— a $13.5 billion offering. Legal challenges are likely to delay this bond issuance at least until early next year. California’s state budget has gone from ever-expanding surpluses for the past several years to a spiraling deficit. All of these issues will provide a difficult backdrop for the 2002 state budget debate and also next year’s election for governor. The political blame game is likely to intensify as the state draws nearer the elections.

Is the Crisis Over?

At a minimum, there is an enormous amount of clean up to be done.

Credit issues continue to cast a long shadow over the electricity market. PG&E is in bankruptcy proceedings. Southern California Edison may soon also be. The California utilities were the credit support behind the Power Exchange and the ISO. The Power Exchange filed for bankruptcy on January 28.

Many market participants are concerned that the ISO market is beginning to unravel. The ISO operates a real time market to ensure balanced supply and demand for electricity. In April, the federal government ordered the ISO to find a creditworthy entity to stand behind its supply orders. The ISO had to turn to the DWR as such an entity. The DWR insisted in return on access to the ISO trading room floor, which is a violation of the ISO’s tariffs. In response to bad publicity, the ISO ended this practice in late August.

Power suppliers, the DWR, the ISO, PG&E and Southern California Edison are embroiled in a dispute over who is responsible for paying for the electricity sold through the ISO since last January. The utilities claim that the DWR has assumed this responsibility to the extent of the “net short” of the utilities last January. The DWR admits to being responsible for these costs, but only from an unspecified later date. However, the DWR claims either that it has never received an invoice for these costs from the ISO or that the ISO settlement process is too opaque to allow it to pay the bills. Before it will pay these invoices, the DWR wants access to confidential information from the ISO settlement records. In late September, the DWR and the ISO proposed a complex and cumbersome process to redo the settlement process at the ISO, to negotiate additional agreements between DWR and the California utilities, and potentially to get the CPUC or FERC approval. At this time, the ISO owes more than $1.2 billion to electricity suppliers, and the tab grows each month.

In reaction to the nonpayment of these invoices, suppliers are either netting their claims against preliminary invoices from the ISO or attempting to avoid providing services to the ISO. Such behavior is in violation of tariffs, but so are the actions of the ISO and DWR. Such netting is becoming so endemic that the ISO only paid about 8¢ on the dollar for its June 2001 invoices. The ISO has complained to FERC that generators are increasingly ignoring its dispatch requests. Generators charge that the ISO is implementing its tariffs in a manner that minimizes DWR costs.

Underlying these market issues is a conflict between the state and federal governments. In January, Governor Davis appointed a new board to run the ISO in violation of the FERC-approved ISO bylaws. This new board is not only closely aligned to the governor, but is also prone to blame FERC and the generators for any and all problems.

Similar jurisdictional disputes and finger-pointing may paralyze efforts to upgrade California’s gas delivery system.

There is substantial political instability in California. The governor’s effort to help Southern California Edison avoid bankruptcy dissolved in a blaze of acrimony in the state legislature. Consumer groups are threatening some form of ballot initiative. DWR’s power sales contracts have become a new lightning rod for political activists. The legislature passed a bill intended to force generators to renegotiate the contracts with DWR. Little political consensus has developed for solutions aside from a desire to rely more upon state government and less on markets.

In addition to these regulatory and political issues, there are other issues of concern for the coming year. The Pacific Northwest is low on water to run its hydroelectric plants. A return to expected or average hydro conditions in California and the Pacific Northwest could substantially depress power and gas loads next summer. On the other hand, a continuation of dry hydro conditions for another year could have adverse consequences on both reliability and prices.