.
.--.
Print this
:.--:
-
|select-------
-------------
-
Price Spike

By Roxane Richter

Participants in the electricity markets have been badly shaken by huge price spikes, trading losses and defaulted delivery contracts. Is better risk management just around the corner?

What a difference a price spike makes. Not simply an ordinary summertime blip of volatility—this one was a no-holds-barred wallop of spot daily and hourly electricity prices that soared to never-before-seen heights.

For the electricity markets, it felt something like the 1987 stock market crash. On June 25 and 26, prices per megawatt hour (MWh), which typically range during summertime from $38 to $150, levitated eerily into the $4,900–$7,500 range and at one point even hit $10,000. The result: tremors of disbelief and aftershocks as marketers, traders, utilities, risk managers, regulators and electricity end-users sorted through the market wreckage.

“I’ve never seen anything like this—from $30 to $5,000, $6,000 dollars!” says Shannon Burchett, president of Ameren Energy, a newly created independent energy marketing and trading affiliate in St. Louis. “It’s off the scale. There’s no market I’m familiar with that has this volatility. When I worked with cobalt it would go from $13 to $60 and $80 in a few weeks, and I thought that was dramatic volatility. If you’re on the right side of the power market, it’s an exhilarating ride; otherwise, it’s not a pleasant experience.”

Fingers were pointed at a number of factors. An earlier-than-expected heat wave didn’t help things. Neither did about 20 generating-unit outages, mostly a result of repairs and storm damage. But the situation was exacerbated by transmission constrictions and breaches of contracts to deliver electricity. Others pointed to larger issues such as demand inelasticity in an immature market, varying levels of trader sophistication and what some were calling a textbook example of a market squeeze. When added together, says Paul Messerschmidt, manager of power markets services at Energy Security Analysis, all these factors created a recipe for power prices to trade at levels “that transcend cost-based physical markets and enter price-squeezing realms, where financially oriented traders attempt to extract value from assets they control.”

“The market saw electricity prices that transcended cost-based physical markets and entered price-squeezing realms.”
Paul Messerschmidt
manager of power markets services,
Energy Security Analysis

The market spike caused liquidity briefly to drop off by some 50 percent and sent traders and marketers running to their risk management departments. Unable to pay exorbitant fees or procure power at any price, the Midwest power crunch forced many Ohio manufacturers to shut down and send workers home. Electric system emergencies were declared in Illinois, Ohio and Minnesota. Every utility in Wisconsin and Illinois pulled the plug on interruptible service customers (companies that agree to put up with power outages for reduced rates), and in Chicago a utility appealed to its businesses and residential users to shut off their air conditioning. Another major utility was rumored to be spending $100 million a day to meet the demand for power—with costs to be paid in the end by shareholders, not utility customers.

A buyer’s nightmare

A number of firms experienced serious power trading losses and defaulted contracts, which led to more losses and defaulted contracts in a complicated daisy chain (see box). “The cascading effect sucked other people into that vortex—a very expensive vortex,” notes Messerschmidt, who says that other electric utilities and customers have yet to come forward on breach-of-contract damages and trading losses.

Before the dust had settled, some utilities had begun complaining to regulators about price squeezes. Decatur, Ill.-based Illinois Power petitioned the Federal Energy Regulatory Commission to implement an emergency order capping the price of electricity at $200/ MWh. Illinois Power, already suffering under new state deregulatory laws and some $864 million in nuclear power plant debt, could ill afford to purchase high-priced electricity on the open market during the late-June price spike. The utility claims it “experienced market power abuse” when it was forced to pay as much as $4,000/MWh—more than 35 times what it is allowed to charge its customers—to meet its obligation to serve native load.

Illinois Power wasn’t alone. On June 29, Cincinnati Gas and Electric Co. and Western Resources asked FERC to hold an emergency conference to investigate the run-up in Midwestern power prices in late June. Since then, several other companies have come forward to add their names to the FERC request. Some of the companies complained about poor credit, financial capabilities and access to transmission issues.

The transmission problems—or, more specifically, access-to-transmission problems—have long been a headache for some industry participants. For about two years, power marketers have complained about open access, which was promised by FERC in Order 888. Ownership of transmission networks by private power companies has proven to be the proverbial fly in the ointment of open, nondiscriminatory transmission access. The limited availability of transmission paths for power flow reportedly served to exacerbate the Midwest shortages. Tired of adopting a wait-and-see attitude, about 70 marketers filed a petition with FERC in March, which sought relief from transmission owner discrimination.

Another important factor that contributed to the financial chaos was a trading practice called “sleeving.” “Sleeve” trading (apparently a practice undertaken by both Federal Energy Sales and the Power Company of America) transpires when two parties agree to a deal without the appropriate credit arrangements. To circumnavigate the problem, a third party steps in to provide creditworthiness and performance obligations. Although more of a hush-hush maneuver than an openly accepted one, traders claim sleeving is a fairly common move used by market participants for price discovery or to pump up volume sales.

Others, however, believe many of the market-related problems can be traced to an important human factor that’s often overlooked: the sheer inexperience of power traders when confronted by a volatile new market that’s still suffering from low-liquidity pangs and deregulatory growing pains. As with other energy commodity markets, like natural gas and oil, it can take anywhere from five years to a decade to reach full maturity—that is, the maturity of the market itself, its trading mechanisms and its trading personnel.

“Quite frankly, there are wide variations in the level of trader sophistication among energy traders in the industry today, and at least some of the price escalation can be traced to inappropriate reaction to market signals by less experienced traders,” says Richard Green Jr., chairman and CEO of UtiliCorp United, about the late-June incident.

Markets don’t kill companies—traders do, notes Randy Brown, a partner at Frontier Commodities, a Spring, Texas-based hedging and trading educational services firm. Because energy companies promote a no-loss, rather than small-loss, trading atmosphere, he says, many inexperienced power traders probably tried to wait out a market spike that turned out to be a freight train.

The Default Daisy Chain
June’s price spike showed how a default by one company can have multiple effects on the larger market. FirstEnergy Trading and Power Marketing, a subsidiary of Akron, Ohio-based FirstEnergy Corp., reported an estimated $25 million in economic damages during the late-June heat wave, because Federal Energy Sales, a small Rocky River, Ohio-based power marketer, breached on a contract to deliver electricity. In FirstEnergy’s lawsuit, filed June 24 against Federal Energy, the company stated that Federal Energy called FirstEnergy to break its contract to sell electricity from June 1 to December 30, the day before the peak of the power supply shortage.

As a result of the default, FirstEnergy was forced to purchase power at elevated prices on the secondary market—prices that had already shot upwards of 100 times summer-1997 levels. On July 8, a national wire service reported that FirstEnergy Corp. would take charges totaling $111 million, or 50 cents a share, in the second quarter, in part a result of June’s heat wave.

To be fair, Federal Energy was not the only power marketer that apparently backed out of contracts, and FirstEnergy was not the only active customer of Federal Energy or the sole party affected in the transaction (or daisy) chain. Also directly affected by the Federal Energy fiasco was the municipality of Springfield, Ill. (which, in turn, defaulted on some power deliveries); Greenwich, Conn.-based power marketer Power Company of America, and several parties with either direct or indirect exposure to Federal Energy. On July 8, The Wall Street Journal reported that El Paso Energy Corp. was seeking $7.4 million in damages from the city of Springfield, because the municipality defaulted on a contract, forcing El Paso to purchase sky-high-priced spot power. Springfield, facing some $20 million in potential claims, confirmed that it broke contracts with El Paso, Southern Co. (a $10 million contract), LG&E Energy and PECO Energy after Federal Energy initially breached its contract.

“The biggest contributing factor [to the price spike] was a lack of contract performance,” concludes Gelber. “You’ve got poorly capitalized, nameless entities leveraging their positions. If it had been, say, Exxon, and not Federal, Exxon would have performed no matter the price. Federal took on more risk than it could manage.”

—A.W.

“These guys were blinded like deer in headlights. There are six kinds of risk: fixed price, floating price, basis price, index price, trader and credit risk. Trader risk is the one that no one wants to talk about,” Brown says. “The biggest difference between Wall Street and the oil patch is that Wall Street defeats the risk of traders, has trader backstops and properly trains them. What’s just happened will affect the market for two yearsor more. They’ll be overly cautious now and less bearish than they’ve ever been. You know that meteor that took out the dinosaurs? This meteor wipe-out will get rid of all of the oil-patch dinosaurs.”

A seller’s dream

One of the handful of marketers to reap the hefty rewards of the late-June price run-up was Aquila Energy, the power marketing arm of Missouri-based UtiliCorp United. Aquila was long on power volume and, in its largest megawatt-per-hour deal, sold at $5,000/MWh to a major Midwest utility on June 25.

“We did extremely well,” says Kevin Fox, Aquila’s general manager of power trading. “We were long. Our general strategy for the July–August time frame was long gamma, long delta in our books—long on volume and consistent performance. The only thing that really changed that week was our ability to negotiate. On a normal day, you could improve the bid or improve the offer, but some people found themselves forced to buy at whatever price was out there, and that helped run the market up and contributed to the frenzy. The bid-offer spread grew quite wide on Wednesday and Thursday [June 24 and 25], as wide as $500. So $500 times, say, 800 megawatts is $400,000 on a daily trade.”

“People in the past have said to me that the real market players will never trust a bunch of fly-by-night traders with a roll of quarters and a telephone booth.”
Rusty Braziel
chairman of the board,
Altra Energy Technologies

Ameren Energy had only been actively trading power for three weeks when the June market meltdown occurred. Company president Shannon Burchett, who says the company was also long on volume, says he’s pleased with his firm’s initiation into power’s volatile ride: “We did well. We’d estimated $1,000 per megawatt-hour for July. I don’t think anyone estimated $6,000, but we were ready for it. We did deals in the thousands-per-megawatt range.”

Post-meltdown control

Now that the fallout has shaken up energy trading rooms and board rooms, many players are reassessing and regrouping their trading-room staffing, business processes, risk management programs, and counterparty credit and performance exposure. They’re also taking a long, hard look at all of the inherent risks involved in playing the power market.

An Energy Risk Checklist
KPMG’s Houston-based Energy Risk Management Practice offers the following tips to power market participants. Make sure you have:
  • A thorough understanding of the risks—by everyone affected by those risks.
  • An effective separation of duties (not just a paper one) between trading, risk management and back-office staffs.
  • An experienced and empowered risk staff, compensated on the execution of sound risk management, not revenue or goals.
  • A detailed product identification and development process, outlining risk, trading parameters and pricing applicable to intercompany transfers of products or components of products.
  • Clear and regularly reviewed risk and dollar-stop limits.
  • Management reporting of mark-to-market valuations and VAR calculations (daily or real-time) and regular stress testing.
  • Market development, credit monitoring, trade confirmation, transmission scheduling, contract administration, transaction accounting, margin compliance and regulatory reporting processes that are fully integrated with trading and risk management processes.

“When markets spike like that, there’s little anyone can do,” says Mark Walker, president of Primo Systems. “If it were one month down the road, you could use futures or swaps, but not when prices exceed $10,000 for spot on hourly shortfalls. You just have to recognize that in peak demand times, you’ll get a few hours when those kinds of spikes are going to occur.” Walker adds, however, that proper credit management could have prevented some of the damage. “There was too much business done with companies whose balance sheets were too small to suffer a market disruption.”

“It’s way beyond what anybody expected in terms of historical multiple standard deviations,” adds Scott Olle, president of Objective Resources Group Corp. “No model would adequately capture that kind of move. If it did, it would prevent you from trading. Sensitivity analysis for extreme conditions is really what we endorse.” Still, Olle notes that when firms contract for scheduling, they are required to enter details on the custody chain associated with the transaction. “If your system can capture that information, you can search through your custody chain—even for counterparties you thought you had nothing to do with—to see how a particular default would affect you. You may still have the problem on the delivered quantities, but you may ask not to be matched up in the future with the problem counterparty or other parties related to the counterparty.”

Hindsight, as they say, is always 20/20. Many participants willing to enter the fray of the power market often look past the do-or-die risks involved in power marketing (for the seller and the buyer) and focus solely on the lure of the oh-so-attractive $210 billion in annual deregulated power sales at stake. If nothing else, the meltdown has served as a wake-up call for the increased need for greater diligence in risk management, counterparty credit and performance exposure evaluations.

“Most companies use a scoring system that assigns a credit limit, usually done on the originating deal, and volatility is rarely factored in,” says Peter Weigand, president of Skipping Stones, a Philadelphia-based energy consulting firm. “You need to figure out where your exposure is now, but also where your exposure will be later, using a combination of credit limit guidelines, value-at-risk calculations and stress testing. It’s especially critical on spot deals.”

Building a fully competitive foundation

Without a doubt, the lion’s share of the blame for June’s sky-high market spike can be traced to the power market’s regulatory woes. Companies are forced to keep one foot in an unregulated environment and the other in the regulated arena—a precarious balancing act between open competition and federally mandated safety nets.

“I don’t think it was as traumatic as everyone makes it out to be,” says Art Gelber, president of Gelber & Associates, a Houston-based energy consulting firm. “It’s certainly not an excuse to slow down regulation. In fact, it’s a good reason to speed it up. The market is half-regulated. If the entire market were deregulated, this never would have happened—there would have been better liquidity and a more evenhanded dispatch of power.”

But there are those who don’t believe an unregulated spot market can be trusted to balance supply and demand in energy. And while most people in the energy business now actively support an unregulated power market, there are and have been others who distrust the reliability of power marketers and open competition.

“People in the past have said to me that the real market players will never trust a bunch of fly-by-night traders with a roll of quarters and a telephone booth,” says Rusty Braziel, chairman of the board at Altra Energy Technologies. “In crude oil, natural gas and now power, the entrenched naysayers have been proven wrong. An unregulated spot market is the only viable mechanism that can be trusted to balance supply and demand.”

Julie Simon, policy director at the Electric Power Supply Association (EPSA), agrees. Simon says the key lesson to be drawn from the price spikes in the Midwest power markets is that fully competitive markets are needed to align the forces of supply and demand. Policy-makers should take steps to clear out the structural shortcomings that exacerbated the problem, rather than target the market forces that helped mitigate them. Price caps and other knee-jerk regulatory actions, because they mask demand, tend to undermine the market’s evolution and promote less efficient solutions to capacity shortfalls over time. “Competition is the answer, not the problem,” she concludes.

Was this information valuable?
Subscribe to Derivatives Strategy by clicking here!

--