Softly, softly in the western US

Wary Californian power traders have reverted to tried-and-tested trading strategies. But, asks Catherine Lacoursière, will the new, apparently stable market hold up to another long hot summer?

By all accounts, the new price mitigation rules for power trading in the western US have succeeded in keeping power prices in check. The true test came on the heels of the July 4 holiday, when the western US faced its first heat wave since the former power trading regime collapsed during 2000 and 2001. This time, when temperatures – and therefore demand – spiked, the price of power was capped at $92 a megawatt hour (MWh).

Nevertheless, the ultimate vote of market confidence – portfolios of long-term contracts and a vibrant forward market – has not been achieved, with the majority of power trading still done in the short-term markets. While the industry is taking measured steps towards the development of a competitive electricity market, temporary market rules and debate over future market design are creating uncertainty.

And the current market stability may only be partly due to the Federal Energy Regulatory Commission’s (Ferc’s) price mitigation measures, says Keith Casey, manager of market analysis and mitigation at the California independent system operator (Cal Iso). “You might want to view the improvement we have seen in the markets with a bit of caution,” he says. “We have had favourable supply conditions that to a large extent have been responsible for improvements in market conditions.”

The western US states have benefited from new generating capacity and a healthy supply of hydroelectricity this year. In a drought year, however, Casey warns that the supply-and-demand crisis could resurface.

Certainly, the high-volume, halcyon days of 2000 and 2001, characterised by gaming strategies ranging from ‘fat boy’ trades to ‘megawatt laundering’ are gone. Fat boy trades involve artificially increasing the load by scheduling excess generation and receiving payment from the Cal Iso for that excess generation. Megawatt laundering refers to trading power in and out of the state to avoid price caps, thereby inflating prices

Much of the action in the western market today follows a tried-and-tested strategy: trading basis risk between the hydro-abundant Pacific Northwest and California, where prices are considerably higher, even with the price caps.

But due to evolving trading rules, a credit crisis and the closing of three major energy exchanges – California Power Exchange (Cal PX), EnronOnline and Dynegy Direct – the bulk of trading activity is centred in the near-term markets, as the details of the future market are worked out.

One unknown is the likely regulatory environment after September 30, when Ferc’s price mitigation plan is set to expire. The cornerstones of the mitigation rules involve:

• region-wide price caps in spot electricity markets; and
  
• when reserves drop below 7% in the Cal Iso spot markets:
  
• a requirement that generation loads must be offered into the Cal Iso. This is intended to prevent generators from physically withholding power; and
  
• bidding requirements linked to the marginal cost of generation during reserve deficiencies. This requirement was triggered on July 9 and again on July 10, when reserve margins fell below 7%. The price cap was reset to $57.14 and $55.26/MWh respectively on the two days, based on the cost of generation of the highest-priced unit in operation in the last full hour in which prices dipped below 7%.

Some argue the plan is discouraging the very market conditions it was devised to encourage – that is, a competitive market that supports long-term energy contracts.

Eric Saltmarsh, general counsel of regulatory body the California Electricity Oversight Board, says the market is not yet fixed. Given different supply-and-demand dynamics, generators still have leverage to let prices run away, says Saltmarsh. That leverage – or market power – was visible during the week of July 8. According to Ferc’s price mitigation rules, spot market prices were adjusted to reflect the marginal cost of generation – in this case, prices moved as low as $55.26/MWh. And generators, of course, are mandated under the must-offer rules not to withhold power.

Nevertheless, fearing that generators might be reluctant to sell at the lower prices, Ferc reset prices on July 11 to the upper limit of the cap of $91.87/MWh. The regulators said they did not want to chance power disruptions.

The must-offer rule is flawed, adds Saltmarsh. “There is nothing to stop a generator pretending a generator is broken and re-entering the market when market prices are more favourable,” he says.

Many have described the interplay between the generators and the regulators as a game of chicken. California state governor Gray Davis had stronger words, accusing the federal regulators of protecting the generators.

Others argue that the price caps are a deterrent to the development of long-term contracts. “Price caps are a huge negative for forward sales,” says Mark Davis, market development director for APX, the biggest scheduler of power in the US. “If you were investing your money, would you invest in something with downside and a capped upside? Probably not.”

But APX is seeing its core scheduling business boom. The closure of three major electricity exchanges has left a big void in the market. With Cal PX closed and both Enron and Dynegy having shuttered their online exchanges, much electronic trading has been replaced by old-fashioned telephone trading. And APX’s scheduling business is picking up some of the slack. Where APX scheduled 125 MWh last year – with no ‘wash trades’, quips Davis – it has scheduled 130 MWh in the first half of 2002. Much of the new business comes from both small and large generators who prefer to have the APX deal with the real-time Cal Iso on their behalf.

However, another major market concern is that the energy exchange closures have meant the loss of the western US power markets’ most liquid forward markets and pricing benchmarks.

Market players migrating to longer-term contracts face two major obstacles – lack of forward pricing indexes and of creditworthy counterparties. As the three biggest power exchanges fell like dominoes, the market entered into fewer long-term deals and more shorter-term trades.

Dominated by the state’s two largest electricity buyers, Pacific Gas & Electric (PG&E) and Southern California Edison, Cal PX’s day-ahead market provided a highly liquid index and good price discovery, says APX’s Davis. When Cal PX closed, EnronOnline became the benchmark. Left standing now is the Iso’s spot market. “So if you want to know what prices will be tomorrow or in August, you’re out of luck,” says Davis. “When Cal PX went away, the term was trading blind.”

Longer-term contracts
Nevertheless, major market participants, such as the state-operated Department of Water Resources (DWR) and the big investor-owned utilities, have shifted the majority of their transactions away from the spot market and into longer-term bilateral trades. Gradually, the market is following them there.

The Bonneville Power Administration (BPA) – the federal marketer of wholesale electricity and transmission to the Pacific Northwest, which typically does its trading in the bilateral markets – has long-term contracts with both the DWR and various investor-owned utilities. Two years ago, the BPA had dealt primarily through the Cal PX and Cal Iso. When the California utilities were mandated to buy all their supplies on the Cal PX, Bonneville – like others – was forced to do business in the short-term markets. With Cal PX gone, that requirement no longer exists.

Hence, the challenge in the bilateral market today is to find creditworthy counterparties. Many power traders are selling assets to bolster their balance sheets in light of a spate of downgrades by credit rating agencies. Entering into agreements with counterparties requires greater vigilance, says Stephen Oliver, vice-president, bulk power marketing and transmissions services at BPA.

“We may be asking for additional credit lines. We are continuing to apply our credit policy,” he says. “But people are realising what their credit limits are on those policies more frequently.” The BPA is also avoiding spot market trades on the Cal Iso, due to the $60 million the Iso owes it. The money is tied up in refund negotiations and PG&E’s bankruptcy proceedings.

The Cal Iso is awaiting its own settlements from the energy crisis. It is a creditor in PG&E’s bankruptcy reorganisation, the terms of which are still being debated. In addition, the Cal Iso has requested that Ferc grant it refunds from various utilities accused of price gouging during the energy crisis.

Generators
Not surprisingly, generators have been some of the most vociferous opponents of the price caps. And how and when the caps should be put into effect is in question. Not all agree that Ferc should have raised the cap to $92 in July, implementing and then withdrawing the marginal cost pricing rules when reserve margins fell below 7%.

Curbing the market power of generators has been a recurrent theme in a number of stakeholder proposals submitted to Ferc as part of its California market redesign efforts.

In the nearer term, extension of the Ferc price mitigation measures beyond next month will probably offset some of the risk associated with regulatory uncertainty in the market. And the measures seem likely to be extended. However, the mitigation plan – with as many supporters as detractors – remains the subject of an ongoing consultation, revision and refining process among market participants.

One of the price mitigation proposals, supported by the Cal Iso, is the call for capacity obligations. “Obligations on load-serving entities on a more forward basis to ensure projected load requirements ought to be part of a longer-term market design to help prevent another crisis,” contends the Iso’s Casey.

The absence of such forward obligations in 2000 and 2001 provided generators with virtually unfettered power in the spot market. Similar obligations are in place or have been called for in other US markets, and proposals have ranged from 5% to 110% of the load sold forward.

Reining in the trading practices that contributed to price manipulation and inflation will also help instill faith in the market. Congestion management schemes or the trading practices that affected electricity sales – thereby volumetrically distorting prices – were the most harmful, says the Oversight Board’s Saltmarsh.

Such practices often involved generators withholding power and notifying the market through bids that the power would not be available at prices at which it was economically competitive to run generators. Instead, it was not unknown for a generator to signal its willingness to enter the market at $400/MWh when bids were at the $60 level. Other strategies – such as scheduling against false load – resulted in payments to the perpetrators, but did not affect market clearing prices.

While Ferc has undertaken a wide-ranging investigation – which may result in punitive action – into ‘Enron-type’ trading schemes, some market stakeholders feel Ferc needs to widen its enforcement net. For instance, the megawatt laundering targeted by Ferc only covers 10–15% of such trades in the market, says Saltmarsh. By Ferc’s definition, megawatt laundering involves buying on the power exchange in the day-ahead market and scheduling it out through the exchange’s export schedule.

The power marketers then imported the power back into California at higher prices, having circumvented the state’s price caps. Generators with uncommitted capacity, however, would not buy the power on the exchange – rather, they would schedule their own power out of California via the Iso.

“The questions Ferc has asked so far in its requests for certification ignore the elephant in the room,” says Saltmarsh. “These are essentially creative trading schemes that can be used by someone who trades in a market but doesn’t have the ability to control or manipulate trading capacity. Ferc is not addressing questions about the exercise of market power to the people who had market power.”

The value of megawatt laundering by generators runs into billions of dollars, says Saltmarsh, while that for power marketers without generating capacity stands in the millions of dollars. Ferc is right to pursue the Enron schemes, he says, but broaden the definition and they will get more answers.