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Hazy Expectations: Utilities Brace for Troubled Times.

Last year, Dairyland Power Cooperative considered pulling a major generating unit out of service due to some leaking boiler tubes. If it had, the La Crosse, Wisconsin-based power generation and transmission company would have needed to buy replacement power to satisfy long-term contracts with its customers. At the time, replacement power on the spot energy market cost $3,000 per megawatt-hour--more than twenty times what Dairyland charged its 250,000 service end users. "We were potentially exposed to millions of dollars in losses that we could not recoup through charging our customers more for power," says Dan Fruehling, Dairyland's risk manager.

But even if it had not been able to fix those leaking tubes (which it did in one weekend), Dairyland had a backup plan. The power co-op's generator outage insurance policy, sold by Ace Power Products, pays the tab for the extra energy replacement costs after the payment of a deductible. "It's an insurance policy that doesn't keep you out of the hospital, but out of the cemetery," says Larry Thorson, vice president of power marketing at Gen-Sys, Dairyland's marketing affiliate.

Dairyland's experience is not unique in the swiftly deregulating energy industry. The uncertain market price of replacement power and supply and demand fluctuations challenge utilities and their customers to manage energy exposures much like they would other corporate risks, from worker safety to the structural integrity of buildings.

In the days before deregulation, attention to energy costs was minimal, given price stability. Utilities and other energy providers like Dairyland simply went to their Public Utility Commission, provided data regarding their expenses and investments and then requested a 13 percent return on assets, explains William Anderson, director of Swiss Re New Markets and global head of the New York-based alternative risk transfer specialist's power industry practice. "It didn't matter what the price of electricity was, because it was predictable," he says.

The process has changed dramatically in both the competitive power generation and retail power markets. The price of electricity now has a strategic impact on earnings that, if left unheeded, can take a toll on the bottom line. Here is the risk: If the utility experiences a generator outage at a time when demand is enormous (like a hot summer night in July), it must buy power from other providers to fulfill its contractual obligations to users. Sometimes that power is cheap, but more often it carries a shocking price tag.

Ed Zaccaria, senior vice president at Philadelphia-based Ace Power Products, says, "I've seen utilities that were paying one hundred dollars a megawatt-hour have to go into the marketplace and buy power at twenty-five hundred dollars a megawatt-hour--and more. The cost can be tremendous."

Why would a utility need to buy additional power? Besides generator outages, there is the unpredictability of the weather and its effect on consumer and industrial demand for energy. In addition, the weather affects supply--hydroelectric power plants, for example, rely on rainfall to generate power. In the state of Washington, which supplies power to California utilities, drier than normal conditions seriously affected hydroelectric plant output, contributing to California's current energy-deficit crisis.

To help energy generators and retailers mitigate the financial impact of energy price risks, Ace and Swiss Re New Markets are joined by a handful of energy traders, such as Enron Energy Services and Axia Energy, in offering innovative insurance policies and derivative financial instruments. While these proposed solutions are expensive, they provide certainty.

Deregulating Disasters

California's two investor-owned utilities, Southern California Edison and Pacific Gas & Electric (PG&E), forced by deregulation to buy power on the open market and pay market prices, are not allowed to pass on the higher cost to customers in the form of price increases. When demand for power escalated this past winter, the utilities had to buy power on the open market at vastly higher prices than what it could charge. PG&E has filed for bankruptcy, citing a $9 billion debt incurred as a result of higher wholesale power costs.

"An investor-owned utility's shares are based on the price it can sell power for, minus the cost of generating that electricity," Anderson says. "When the latter half of that equation exceeds the former, financial underperformance is the result."

There is a solution offered by some carriers--a dual trigger insurance policy that requires two causal factors to occur simultaneously for the insurance to pay out. The first is an outage in a generating unit, i.e., a physical interruption in the ability of a utility to provide power, forcing it to buy energy on the spot market. The second is the cost of that power on the spot market. The utility and the insurer establish a defined strike price for replacement power, above which the insurer picks up the cost, minus the deductible.

Ace's PowerBacker product, which Dairyland bought, provides up to $150 million in coverage limits if one of the co-op's generating units is forced out of service and it must acquire replacement energy. "If the cost of that power exceeds a specific strike point, which I'll call X, Ace pays the difference between X and the actual market price at that time," Thorson says. The co-op has a substantial deductible it must absorb before the insurance comes into play, but this is a "marginal" financial consideration, he says, given the "sleep-easy" price certainty.

The problem for utilities is that they are required by contracts with end users to provide power at a specified price. If they are forced to buy spot power, there is no recourse to immediately make up for the extra costs from power price hikes.

"Let's assume they have decided to sell power at fifty dollars per megawatt-hour and they're collecting that," says Anderson. "A unit suddenly goes down ... and the cost of replacement power is now forty dollars per megawatt-hour. Well, that's no big deal--they actually make a few bucks. The risk in a competitive marketplace is that in times of high demand, like last summer, market prices reach five hundred dollars a megawatt-hour and more. Then, it's nail-biting time."

Utilities cannot buy a significant volume of power forward--as you can with more liquid commodities. "You can store grain, but you can't store electricity," Anderson says. "Without a doubt, the number one risk facing utilities today is the price of electricity."

It is also fast becoming a major consideration for electricity users--the companies that buy a large volume of power to generate their goods and services. "Industrial customers have tremendous power demands," says Zaccaria. "We estimate that sixty percent of the cost of goods sold in this country is related in some way to energy."

As deregulation takes hold, "companies will have opportunities to buy power in different ways, some may buy short, some long--similar to how companies hedge their positions in foreign exchange or interest rates," Zaccaria says. "Some companies are self-insuring the energy price risk by developing on-site generating facilities. If these were to falter, they'd have to buy replacement power on the spot market--just like utilities. And they would then face the same kinds of challenges."

Weathering Difficulties

More than just power price spikes are puncturing the balance sheet at energy providers. Utilities also are beset by the inconstant supply-demand ratio. "We make our money based on throughput--the volume of natural gas we sell to customers," says Bill Zorr, general manager of gas trading and dispatch at Alliant Energy, a Madison, Wisconsin-based gas and electric utility.

"When it's warmer than normal during the winter, we don't sell much gas and, therefore, don't make as much money," Zorr says. "About three years ago, we decided to do something about this."

Alliant bought a so-called collar derivative. "If the winter turns out to be warmer than expected, our counter-party (in the trade) pays us a certain amount of money," Zorr says. If it's colder than expected, we pay them. Since when it's cold we're selling more gas, the additional revenue makes up for the payment to the counterparty." Since the winter of 1997 was atypically warm, Zorr fared well.

In 1998, Alliant bought another collar, this time through Koch Industries, a Houston-based energy trading concern. Again, the winter was warmer than usual and the company collected on the instrument. This past winter, however, Zorr decided a change was in order. "We'd just had three warm winters in a row so I decided to roll the dice a bit," he says.

"I figured it would be a cold one this time and I didn't want to give away the upside (of having to pay the counterparty) if I was right," Zorr says. "But I still wanted to protect myself just in case I was wrong and we had a very warm winter. So I bought a `floor'--a put option that basically pays me when a certain number of days above a temperature threshold breach the limit in the contract."

Again, Zorr predicted correctly. It was, in fact, one of the coldest winters on record. "Had I bought the collar instead of the floor I would have paid out," he says. Still, he had to pay a hefty premium for a financial hedge that he never used. Did that bother him? "Heck no," he says. "I'm not bummed out when I buy fire insurance and my house doesn't burn down."

The put option was arranged by Axia Energy LLP, the Houston-based energy trading company owned 50 percent by Koch Industries and 50 percent by Entergy Corp., a Houston-based company that owns, manages and invests in power plants. Axia specializes in derivative financial instruments for the power industry.

"Companies are looking to protect their volume exposures, a situation where the weather has an adverse impact on the volume of energy consumed," David Sobotka, Axia president, says. "Less energy translates into less profit. We try to even the score."

Helping him in that regard are the predictable correlations between energy demand curves and the temperature. "Temperature will drive demand at least eighty-five percent of the time, making it pretty easy for companies in the throughput part of the business to project out," he explains. "Since you can postulate what the impact will be on revenues from a certain temperature range during a given period of time, you can fashion a derivative option or swap contract to insulate yourself from the weather's impact on the revenue stream."

Such derivative contracts are based on either heating degree days (HDDs) or cooling degree days (CDDs), depending on the season. An HDD is 65 degrees (defined as the normal temperature) minus the average of the high and low temperatures in a day. Thus, if the high temperature is 40 degrees and the low is 30 degrees, the average for the day is 35 degrees. Subtract 35 from 65 and you get 30 HDDs.

The buyer and the seller base the derivative contract on total HDDs during a multimonth period. If the buyer does not achieve a specified number of HDDs during the period, it receives a specified payback based on the number of degree days short of the prenegotiated target. The same situation applies to CDDs in the summertime.

Permutations

There are other ways to mitigate power price and throughput risks besides insurance and derivatives. There are programs to help a utility offset its power price risks with a call option that caps its exposure to higher replacement power costs.

"You'd have to lay out quite a bit of premium to buy the option, but then at least you'd know that you'd never have to pay more than, say, two hundred dollars per megawatt-hour for replacement power," says Sobotka. Axia also can structure conditional call options, which apply when more than one variable triggers, e.g., a certain number of HDDs and a defined power price in the market. "We can link the option to the need to buy additional power when it is very, very hot and the market price is above, say, two hundred dollars per megawatt-hour," adds Sobotka.

Such novelties intrigue Dairyland's Fruehling and Thorson. "We just modified our PowerBacker contract with Ace to add additional Coverages," says Fruehling. "Previously, we only covered the need to buy replacement power in the event of a big spike in price. We began to think about the impact of slightly higher energy prices over a longer duration."

The co-op operates on razor thin margins that would be cut down to the bone in a long-term outage situation if the PowerBacker contract did not offer recourse because market price never reached the strike point. Thorson explains. "A need to buy replacement power over a protracted period of time, even at marginally higher prices, would have a significant financial impact," he says. "So we amended our contract to mitigate a long-term outage situation, during which the price of power was lower than our previous contract. In effect, we now have two contracts."

In the next year, the Dairyland and Alliant Energy managers plan to watch the insurance and capital markets very closely for new developments. "These risk management concepts are evolving every day," says Zorr. "Next year I may just do another collar--or something completely new and original--based on my sense of where the weather will be."

John Conley ("Utilities Brace for Troubled Times," p. 20) is a New York-based freelance writer who has covered the industry for over twenty years.
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Comment:Hazy Expectations: Utilities Brace for Troubled Times.
Author:Conley, John
Publication:Risk Management
Geographic Code:1USA
Date:Jun 1, 2001
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