With new futures contracts, the wide-open spaces of financial risk management and derivatives hold promise for the electricity industry.

By James Lacey

Utilities were once the sacred cows of the investment world. Protected by federal and state regulations, utilities could do as they pleased, passing on all cost increases to customers and ensuring that profits were robust. Each utility was its own little monopoly.

But it's been a few years since utilities first felt the icy winds of competition. And now the utility industry has reached another milestone. On March 29 a new era officially dawned for the nation's electrical industry when the New York Mercantile Exchange began trading energy futures contracts. The two contracts are based on the two most active delivery points in the cash electricity markets today, the California­Oregon border and the Palo Verde high-voltage switchyard.

The advent of futures trading heralds a more fundamental change in the electricity business. "Utilities are facing price risk for the first time," says John Woodley, a commodities trader at Morgan Stanley. "It is a radically different mindset from the cost-based pricing they are used to. Many have not learned yet how to cope with this environment." Peter Fusaro, president of Global Change Associates, an energy consulting company, puts the problem more succinctly. "Utilities will have to start thinking of electrons as money," he says. Coping means facing the daunting task of learning about the power of financial derivatives while also building new marketing and distribution skills. Utilities that don't master the paradigm shift could find themselves takeover targets.

Aggressive marketing

A few utilities are in the forefront of the radical restructuring. Duke Power, UtiliCorp and Niagara Mohawk Power are already expanding into other markets, selling long-term contracts and options on their capacity and adding the risk management structures needed for future success. Often they have set up their own power marketing divisions or formed alliances with already established brokers or power marketers. These companies have decided on a two-pronged approach that combines tight internal financial management and an aggressive stance in marketing and distribution, which in some cases involves entering markets where they have no generation assets.

Of course it isn't just the $200 billion electricity industry that is facing change. All power marketers have been forced to confront the future. Some gas companies, for instance, have seized the opportunities presented by competition and have applauded the advances in risk management and derivatives development. And the electricity industry is five times the size of the natural gas market. In fact, Enron has grown from a small, sleepy gas provider to a dominant force in the gas industry by relying on its marketing skills and ability to manage the physical and financial risk of its substantial positions. It has already begun to leverage this knowledge in the electricity industry, where it has become one of the major forces in the market.

The restructuring of the electricity industry is still in the nascent stages. And because electricity cannot be stored, while natural gas can, electric utilities will not develop into risk managers in the same fashion. In fact, Morgan Stanley's Woodley says that almost all of the deals that are being done are still for the physical product. Financial transactions based entirely on paper and cash are very limited. But pure financial deals are on the increase at an ever-accelerating pace. Rob Fischetti, an assistant vice president of Prebon Energy, the energy broker subsidiary of Prebon Yamane, says that of the deals negotiated in the quarter ended March 31, 1996, only 70 percent were for physical product, down from 99 percent in the previous quarter.

Most electrical utilities can't decide whether to take an aggressive or defensive posture in response to the industry restructuring. A survey conducted by Derivatives Strategy of 30 of the largest utilities in the country quickly established that only a small number have created risk management organizations (beyond those developed for insurance purposes) or independent power marketing arms. "Some utilities can not seem to decide what they want to do," says Shannon Burchett, senior vice president of Duke/Louis Dreyfus, the power marketing joint venture between the utility Duke Power and the broker Louis Dreyfus. "They are sitting back collecting their monopolistic rents for as long as they can, counting on their state regulators to protect them."

Many of these companies are counting on the close relations they have built up with their customers over the years, as well as services such as on-site power equipment management, to keep their competitors at bay.

Others are retooling. Allegheny Power Systems, for example, is reorganizing to slim down and pare costs to meet the expected assault on its markets. Other giant utilities, such as Consolidated Edison in New York, have held meetings about the new paradigm, but as of yet have not established any new risk management functions or independent marketing arms.

Don't do anything hasty

It makes sense for utilities to consider their options before committing to a certain course. First of all, electricity prices are very volatile. Price fluctuations for non-firm energy, as tracked by the Dow Jones COB Index since its inception on June 21, 1995, demonstrate that daily price swings of 20­25 percent are not uncommon and often approach 50 percent. Annualized price volatility for the period surveyed was over 220 percent.

Price volatility has historically inhibited the expansion of utilities, which for the most part have proven a bit shy of entering into markets where they have no generating capacity. The financial risks inherent with promising delivery in a market where the utility has no control of the physical supply is not something that many utilities wish to undertake.

The lack of pricing transparency also makes the electricity market a difficult place to apply traditional financial risk management techniques.

The first and probably the most important problem is the lack of a forward pricing curve for each region. Some of this can be attributed to the short existence of the wholesale markets. Without a long series of historical data, it has been difficult to build a reliable curve. As of last month there are four indices listed in The Wall Street Journal. These indices track the price level at the California­Oregon Border and Palo Verde switchyard (the same as the NYME contracts listed above) for both interruptible and non-interruptible power.

Slow development

As of yet there is no index with the same authority in the central or eastern region. A number of deals are being done at the Pennsylvania­New Jersey­Maryland (PJM) border by all of the major power marketers, though to date the major eastern utilities have not come to the table in a significant way. There is wide speculation that these PJM deals may soon form the basis of a new index. Though NYME recently offered traders an option on the two contracts already trading, Beth Desmond, a trader with Bankers Trust, says, "We need an option like a hole in the head."

There is no real discussion yet in the central region, managed by ECAR, [the East Central Area Reliability Agreement) or the southern states (SERC, the Southern Electric Reliability Council) because neither of these regions boasts a central delivery point. Instead, power is delivered to the border of each utility's region through bilateral pricing agreements. Because of the lack of pricing transparency most of the deals done away from the major transfer hubs also tend to be very costly.

Large power brokers such as Prebon Yamane and Duke/Louis Dreyfus have enough experience and a large enough presence in the market to do deals even in the absence of published index prices. Their OTC contracts are based on in-house pricing models and usually hedged through the firm's own portfolio. The same is true for the OTC deals being signed by banks. Using their own models and price curves the banks, for a price, will set up almost any type of deal imaginable. Morgan Stanley's Woodley boasts, "If a client wants it, we can build a synthetic transmission grid across the Atlantic."

Watch the curve

Backwardation (when forward prices are less then spot prices) can happen in almost any market, and if prolonged can lead to a serious lack of liquidity. Robert Maxant, a partner at Deloitte & Touche, says: "The inability to store the product will do some interesting things to the price curve and may make efficient arbitrage impossible. Speculators will not participate in such a market and without them liquidity is drained from the long-term futures markets." Backwardation is a very real concern among many of the more active market players who list current overcapacity, and the increased efficiency of new generation assets, as key factors in lowering forward prices. Tony D'Agostino, a trader at Cinergy, one of the forward-thinking utilities, says: "Backwardation is a very likely happenstance in this market. Right now there is a tremendous uncertainty premium that is keeping the market in contango [where futures prices are higher than near-term prices on the yield curve], but that will disappear as transparency increases." When asked how a utility will hedge long term contracts in such a market he replies, tongue in cheek, "Be a seller."

Even D'Agostino agrees that factors such as increased usage, uncertainty of supply and regulatory uncertainty will help to keep the curve contango. Others such as Duke/Louis Dreyfus's Burchett say: "There is a lot of overcapacity so prices may decline a bit going forward, but there is also a lot of volatility so even when the market is slipping towards backwardation, there will always be someone who wants to fix his prices. This action alone will fix forward prices and keep the market contango." Prebon Yamane's Fischetti discounts the problem altogether: "It may happen from time to time as it does in the natural gas and crude markets, but it will be short-lived and go back contango as soon as enough firms try to lock in prices or the weather turns."

It is said that swap deals are being done against various indices, but outside of Prebon Yamane, none of the marketers surveyed for this article admitted to doing any. The most common reason given was that they were not comfortable with the structures they had seen or the reliability of the indices being used. While the indices reflected in the NYME contracts were given high marks, most players commented that there was only a very slight correlation between those regions and the rest of the country. In fact, hedging in general is a large concern in the futures and swaps market. Robert Mango, a power broker at Niagara Mohawk Power, says: "No one in the East is using West Coast contracts to hedge. In the East the only effective way to hedge exposures is in areas where gas is the dominant fuel, and to a limited degree, where gas is the fuel at the margin. You can buy a gas contact to reduce the exposure of a gas-fired plant on the system."

Here come the power marketers

In spite of the hesitation in the market over non-physical deals, some utilities are setting up new power marketing arms to take advantage of the changes that are coming. It is in these organizations that most of the cutting-edge deals and structures are being done. One of the more aggressive firms in this arena is PacifiCorp, a Portland, Oregon­based utility. It has recently announced the intention to move outside of its own region and expand its presence into the eastern states. The first step was to spend $31 million to purchase the excess power of financially troubled Big Rivers Power in Kentucky. This access to power in the Eastern region, says PacifCorp's CEO Frederick W. Buckman, will give the company the credibility it needs to become a financial player in the East. At the same time PacifiCorp announced the formation of a power marketing arm that will be based in White Plains, New York.

The new utility players are split between the independent power brokers and the utility-affiliated power marketers. Who has the leg up in this new arena? For the time being it is easily the independent power brokers. Many of them are drawing on the experience they have already developed in oil, natural gas and other markets. They have the systems and personnel in place to accurately price and make deals today. Many utilities find themselves well behind the power curve in this area.

In this case the power marketer which actually owns or has come to an agreement with a power generator has a distinct advantage in the market. As D'Agostino of Cinergy says: "We already have clients asking us to write puts on electricity. In the event that we have one of those contracts put to us we can always cut back on our own production. In this case the ownership of the production assets is a big advantage. It allows us to do to deals that other marketers without such assets could not do without accepting substantial downside risk." The ownership of power generation allows for many types of deals that under other circumstances would be considered too risky.

Sue Becht, risk manager at Duke Power in North Carolina, explains the competitive advantage utilities have over new entrants: "We own the physical assets so we can hedge our exposure relatively easily. In fact we have trading operations only because we have product to lay off, not the other way around. Additionally, this is something we have been doing for years on a voluntary basis. In the past a utility that needed power would call and if we had excess we would sell it to them. This has given us a tremendous knowledge base. We know everything about everyone: generation capability, peak needs, etc. All that is changed now is that we are selling contractual options on our excess power to those who we know will need it."

Fast-growing segment

In fact, D'Agostino says that options on power are one of the fastest-growing products on the market. A typical structure would have one utility that is worried about meeting demand for power in August. That utility would buy what is referred to as a 5/16 call, which allows them to call five days of power for sixteen hours a day. This power can usually be called on a day-before basis on any business day of the month. So for a 22-day work month the utility would theoretically purchase 22 daily calls and pay accordingly. An independent marketer would hedge this type of deal with a back-to-back contract or by going forward in the market and buying the power for August. On the other hand, a firm that owns the excess capacity would sell the option against the plant that has the capacity to spare and hedge with the physical product itself.

Just exactly how the electricity industry will change in the future is still a matter of debate. Fusaro of Global Change Associates predicts that the new futures contracts will lead to an explosion of derivative products in the electricity markets. He also believes that the volatilities eventually will fall to mirror those of natural gas, hovering around 30­40 percent on an annualized basis. Burchett at Duke/Louis Dreyfus agrees. "I don't know if electricity will ever become a ten-year market, but there is no reason to believe that it will not match the duration and volatility of other commodities, and this should happen fairly quickly."

D'Agostino at Cinergy thinks that electricity volatility will never be as low as that of natural gas. "Because electricity is an instantaneous product there will always be hourly volatility. Intraday volatility," he adds, "will always be high, and though annual volatility may eventually drop towards that of natural gas, it will be a long time in coming and may always be a bit higher."

Hampered by credit quality

One inhibiting factor in the growth of the electricity-related derivatives markets is low credit quality. Deloitte & Touche's Maxant points out that in the financial industry, many firms will not deal in derivatives with any firm rated less then triple-A. Few players in the electricity industry even come close to that level of creditworthiness. Enron, one of the largest market participants, is in fact rated triple-B. In the future these low-rated parties may have trouble finding counterparties to deal with them, especially in long-dated contracts. They will be forced to forgo some lucrative deals, set up better capitalized subsidiaries or pay exorbitant premiums based on their lower credit standing.

Radical change may not be so quick in coming, says Morgan Stanley's Woodley. "Utilities are very competent when it comes to delivery and no financial player is going to tamper with that. What pricing transparency will do along with an accurate forward curve is allow utilities to plan. For instance, if transaction-based curves had been available years ago probably no money-draining nuclear plants would have been built."

One large positive effect that can be expected from the newly competitive electrical markets is greatly reduced prices for electricity. In the 22 months after the COB index was introduced prices fell dramatically. During that time the amount of energy traded at the border eventually totaled over 30 billion megawatts, up from several hundred million. Prices during this period dropped from $20­25 per megawatt hour to $15­20 by early 1995. By the beginning of the year prices had dropped as low as $12 per megawatt hour.

Whatever the new electricity industry looks like, those utilities that haven't yet decided what tack to take still have a bit of time to make up their minds-but not much.

According to Deloitte & Touche's Maxant, electric utilities must take certain steps. They must decide on a basic strategy for the new markets, but this cannot be done in a void; at the same time the utility is deciding on a strategy it must also decide on its appetite for risk. Hopefully, when this is done the utility will take the time to develop a proper risk management structure and obtain the systems and expert personnel required to make it work.

The Morning After

NYME electricity futures have started trading. Finally. So what's next?

It was a bit anticlimactic, the day that electricity futures finally hit the boards at NYME late in March. But after the three-year struggle to get them launched, Beth Desmond, a trader on Bankers Trust's electricity desk and one of the prime movers in the battle for electricity futures, says: "The first day of trading was very encouraging. We saw a lot of industry business, including some utilities and power marketers, rather than just a lot of local interest." However, now that the contracts have finally begun trading, concluding a rollercoaster-like voyage to Commodity Futures Trading Commission (CFTC) approval, what's next? For now, says Desmond, "The market will enter into a period of slow growth."

A brief scare

Indeed, utilities may be getting off to a particularly slow start because of a regulatory snafu that was only resolved one week before the contracts' release date. The key questions: were electricity futures securities, and were utilities even allowed to hold them? The Federal Electricity Regulatory Commission (FERC) and the Securities and Exchange Commission (SEC) eventually ruled that electricity contracts were not, in fact, securities, but, as Desmond says, "This did create some last-minute panic and confusion."

For traders and brokers the most immediate consequence of the NYME contracts is a number of new hedging and arbitrage strategies. In particular, Desmond cites new basis markets. For example, it is possible to arbitrage the pricing difference between NYME California­Oregon Border (COB) options, which refer to contracts covering that area, and OTC options linked to the Dow Jones COB Index, which have different pricing conventions (one is a futures price and one is an OTC price). She also explains that location basis (that is, the difference in price between electricity originating in different locations) is another area in which the NYME contracts will play an active role. Of course, she notes, some market participants may try to "stretch it a bit by attempting to hedge PMJ [Pennsylvania­Maryland­New Jersey] electricity with NYME futures." Adds Desmond, "I am skeptical that any correlation exists between PMJ and COB."

Future developments...

Over the long haul, only one West Coast futures contract may survive trial-by-trading. Desmond, who has been trading electricity derivatives since their inception, feels that the forces of natural selection will tend to "kill off" one of the two fledgling NYME contracts. "It has always been my opinion that one of the two contracts would be much stronger than the other, and right now it looks like the COB index will become the standard, rather than Palo Verde, which is already showing less trading volume than the COB." And further down the road? "The next step is a NYME contract based on an East Coast delivery point," says Desmond.