The most important things an energy company has to understand before taking the plunge into power trading.

By Emily Eisenlohr

The Big Bang of deregulation in the energy business has sent most diversified energy companies scrambling for new and innovative ways to maximize profits and return on equity, deliver new services to their customers, and, increasingly, capitalize on the convergence between the natural gas and electric utility industries. Out of the rubble, energy trading has emerged as the most powerful tool to accomplish these ambitious goals.

But, as the mountainous price spike of 1998 proved, energy trading also injects significant price risk into a corporate balance sheet. If this risk isn’t managed adequately, the results can be disastrous—huge trading losses for the trading facility and, by association, degraded credit quality for other members of its corporate family.

To complicate matters, energy trading affects the risk profile of the trading entity, as well as the overall corporate credit risk, in a stunning variety of ways. Any commodity product, of course, brings with it substantial price volatility that’s not reflected in traditional financial statements. Since trading is contractual in nature, commodity contracts appear on the balance sheet only at settlement. It’s essential that trading firms balance the risk of potential losses resulting from price fluctuations with greater capital and liquidity resources.

Moreover, the slim margins earned from trading commodity products provide little means to offset potential losses. As a result, the policies, procedures, systems and people dedicated to risk management are the most important influences on an energy company’s credit profile.

	The trading-marketing arm is not a generator of earnings growth on its own, but a creator of business opportunities for other segments and a profitability enhancer.

Counterparty risk—the risk of loss from the failure of a party to a contract to meet its obligations under the contract—is another major consideration for a trading operation. Effective counterparty risk management requires credit expertise, substantial due diligence and Aristotelian trading discipline to prevent losses. In addition, an experienced legal team is critical in minimizing counterparty risk. After all, the content of the initial master agreement governing the trading relationship between two parties and the subsequent confirmations that capture the details of their individual trades could be hotly contested in court should disagreements arise—as was seen after the bankruptcies of three power marketers in the summer of 1998.

Because of these risk management bugaboos, it’s critically important for energy trading firms to understand not only the conventional wisdom of the financial markets but also the nuances of the energy business.

The energy company

All diversified energy companies do or will engage in some level of BTU trading as an essential component of total corporate strategy. For the major BTU traders, the trading function is critical. Many of these large-volume traders are part of vertically integrated organizations engaged in all levels of the energy business: upstream (electric generation, gas exploration and production), midstream (electric and gas transmission), and downstream (electric and gas distribution). Trading is crucial to such organizations because it helps sell the energy supply generated by the upstream segment, ensures volumes for the midstream and ensures reliable supply for downstream. The importance of the trading–marketing arm is not so much as a generator of earnings growth on its own, but rather as a creator of business opportunities for other segments, and a profitability enhancer for each of those segments.

Utility companies have engaged in marketing production from the assets they own—“trading around assets,” as it is called—for a long time. The marketing function is the grease that helps “optimize the value of hard assets”—the current catch phrase for maximizing these assets’ profitability, whether they are oil and gas reserves in the ground, generating plants, transmission lines, pipelines or storage facilities.

Marketing can be beneficial in a number of ways. In operations, production of certain threshold volumes of electricity or natural gas is necessary for the optimum functioning of a production plant. On the financial side, marketing can improve the return on assets. And in the increasingly important area of customer service—including the regulated distribution arm of a corporation—utilities can provide value-added services and earn incremental, unregulated margins above the regulated margin they earn by delivering electricity and natural gas. Such value-added services may involve customizing fuels; delivery based on seasonal and peak needs, storage needs, and fuel-switching capability; or procuring fuels economically and arranging for their most efficient and economical transport.

The convergence of the formerly separate natural gas and electric industry is a trend resulting not only from the shift from regulated to competitive supply markets in natural gas and electricity, but also from the related shift in the market’s focus from the regulators to the customer. In anticipation of a deregulated, more competitive world, both gas and electric utilities are seeking to differentiate themselves by offering major customers an array of value-added services that could yield better-than-regulated margins.

Wholesale trading operations of utility companies are at the center of their strategy of offering the entire value chain of energy, because trading allows them to provide multiple fuels and related services to major customers that have fuel-switching capabilities. Industrial customers, in particular, have such fuel-switching capabilities. An industrial firm doing business in a process industry, such as paper or oil refining, wants the lowest-cost, most reliable supply of energy available, regardless of the type.

A trading operation can also provide a company with a competitive edge by furnishing market intelligence—giving the company firsthand information about energy prices. Such information can be used to make arbitrage profits or to take a view on the market through proprietary trading—which, if done successfully, can increase a BTU trader’s profit margins. Market intelligence can also provide useful information about the energy consumption patterns of large-volume customers, which gives a BTU trader not only an outlook for local energy prices, but also the competitive edge of knowing what value-added energy services to market to those major customers.

Market intelligence also provides useful information with which to monitor counterparty credit. Traders gain tremendous amounts of market information and may receive valuable early signals about difficulties being experienced by other trading firms. This information is one of the many sources used by the credit function to manage counterparty risk in the best-managed firms.

Thin margins

Many companies still developing BTU trading operations have either minimal earnings or losses from the startup costs of hiring personnel and installing information technology to track and monitor risk. Getting into the business isn’t for the timid—it usually involves a capital investment of between $30 million and $60 million. Moreover, most energy trading volume is plain vanilla commodity trading—a low-margin business. In fact, since most trading operations do not engage in substantial speculative trading, uncharacteristically wide margins could suggest undue risk-taking. Also, the market is fiercely competitive, since numerous large-volume BTU traders pursue the same customers and opportunities, further shrinking margins.

	BTU traders have long been trying to boost their volumes in order to make up for thin spreads. But these long-term contracts also entail higher risk.

Margins in the gas segment of the market are tiny—less than 2 cents per MCF. Although markets for power are less mature, their margins are not much better—only a fraction of a cent per kilowatt-hour. Most market participants expect electricity-trading margins to shrink further as the power market develops and becomes more efficient. The lower level of profitability may cause some participants to exit if returns are not commensurate with risks.

So why get into the business at all? Most trading operations exist expressly to enhance the profitability of other segments of the corporation. Some of the benefits provided by trading—whether it is incremental profits from additional volumes on a company’s pipeline or new business derived from market intelligence—could be buried in the earnings of other business segments. Nevertheless, it is important for a trading operation to be consistently profitable on its own—via proprietary trading, customer trading or both.

BTU traders have long been trying to boost their volumes in order to make up for thin spreads. The widest margins, of course, are found in longer-term structured deals with major industrial customers and other utilities. But these long-term contracts also entail more risk. In addition to the base margin of providing the commodity over the long-term, the trader adds incremental margins for the price risk expected to be incurred over this period, for the costs of hedging that risk and for ancillary energy management services.

Wider margins can also be earned in niche businesses. For example, certain regions have market inefficiencies or limited competition that result in wider margins. Providing energy for peak periods (when demand is at its seasonally highest levels, with unanticipated swings) commands wider margins than providing energy for normal levels of demand.

The risks

Simply put, trading is trading. Firms that trade financial instruments, precious metals, energy, agricultural products or foreign currencies share many of the same risks, including the risk of changes in the balance of supply and demand and resultant price fluctuations, and the risk that counterparties will be unable to meet their obligations.

Regardless of the commodity traded, firms need to address these risks with well-defined risk management policies and procedures, including a clear chain of management responsibility for each type and level of risk. They also need to pay up for experienced traders, systems that effectively measure and communicate risk, and models that can be relied on to provide timely and accurate risk assessments. Moreover, they must demonstrate a commitment to trading that is visible in the marketplace; secure broad access to supply sources to meet contractual demands; implement sound counterparty risk management policies, procedures, and systems with managers experienced in credit to oversee the function; and provide enough capital and liquidity to meet daily obligations and support market confidence.

This is no easy task, of course. Energy commodities are among the most volatile of the widely traded asset classes. Volatility levels also change over long periods of time, adding to the difficulties in managing trading risk. Electricity is generally recognized as the most volatile of the energy commodities. Caution is the name of the game, thanks to the effects of regional weather patterns, transmission constraints and the shift from regulation to competition on the generation side. Useful price signals and hedging tools are growing in number and improving in quality, but are still not especially developed.

Natural gas is another highly volatile commodity—a significant factor for the electric industry, which is growing more and more dependent on natural gas as a fuel. Natural gas will be the fuel for most new generating plant additions. Table 1 (next page) shows how several commonly traded commodities and financial instruments differ in their levels of volatility. The following graph of the volatilities makes the comparison even more dramatic. Models can measure and help manage risks resulting from volatility, but sophisticated knowledge of modeling is critical to prevent surprises. Many models are based on historical volatility levels, but those levels can change rather dramatically during paradigm shifts in markets or unexpected events.

The risk-tolerance hierarchy

Trading, as opposed to brokering, can be categorized into three broad levels of risk. The lowest level is assumed by firms that simply trade around their assets. Their trading desks are used primarily to sell their output. This type of trading is the reason so many firms have obtained power-marketing licenses from the Federal Energy Regulatory Commission, whereas a much smaller number actively trade.

Trading around assets involves only modest amounts of risk. A contract to sell is simultaneously matched with the physical output of the assets or a contract to buy on similar terms. There is little exposure to price risk because the price is set, the transaction is promptly closed and the firm has assets to back its commitment. When these companies use financial derivatives, it is generally on a limited basis and only to lock in prices. Also, these firms’ trading activities are generally short-term—usually 30 days for gas, a time period that holds more price certainty than longer tenors.

	Many companies still developing BTU trading operations have either minimal earnings or losses from the startup costs of hiring personnel and installing information technology to track and monitor risk.

The risks that are involved in trading around assets—weather risk (warm winters equal low gas demand), “cyclicality” (market diversification mitigates this risk), credit risk (customer diversity and thorough knowledge of customers mitigate this risk) and supply risk (also helped by diversity of reserve supply for gas marketers or multiple power plants in case of power marketers)—are easily managed.

The firms that also trade to provide resources to meet client needs assume the next level of risk. If their customers need structured, long-term energy contracts, the trading operation provides the information and resources to offer the best solution and to offset the risks being assumed by the firm in any of its subsidiaries when it enters into the contract with the customer. If the contract is a long-term sale to the customer, the trading operation must buy the same quantity in the long term to meet the firm’s obligation.

The highest level of trading risk is assumed by market-makers, who stand willing to trade at competitive prices and buy and sell over a variety of tenors. Although the biggest volumes for the most part are in plain-vanilla contracts, large-volume traders are more likely than their smaller-volume counterparts to engage in transactions with terms longer than a month (the longer the time, the greater the exposure to price changes). They are also more likely to trade in less liquid commodities, such as power and exotic derivatives, for which price discovery may be difficult and the market may not always be available. With large volumes, they are less likely to trade back-to-back, because hedging each trade becomes costly and unwieldy to execute. They are more likely to hedge an aggregate of trades, which is more efficient and profitable, but which may result in an imperfect hedge. With more access to market intelligence and more financial resources than smaller-volume traders, BTU traders are more likely to engage in proprietary trading based on expected price moves that may not materialize.

Know who you’re dealing with

After price risk, counterparty risk is the next most significant risk to a trading operation. Counterparty risk is the risk that the counterparty to the trading firm’s contract will not perform as promised. Two forms of losses can arise from a counterparty’s failure to perform. The most easily understood is the settlement risk—the trading firm delivers on its side of the contract (commodity or money in payment), but does not receive the other side (money in payment or commodity).

Presettlement risk is more complex to measure and manage. Consider an example: Party A, which needs to deliver power in a region over an entire summer, contracts the previous fall to purchase power from Party B for delivery during the summer. When summer arrives, however, Party B is in dire straits and does not meet its obligation. Party A’s obligation to provide power has not gone away, and it must now buy that power on the open market. If prices have risen since the fall, Party A faces a loss in meeting its obligation. The amount of presettlement risk assumed depends on the volatility of the commodity’s price and the tenor of the contracts with the counterparty.

The legal nature of BTU trading activity is one of the most critical issues in analyzing counterparty risk. Some energy marketers are independent firms of modest size. Other trading operations are carried on within a corporation. The trading entity may be a subsidiary of the corporation or a division of one of its major operating subsidiaries. Each legal form entails unique counterparty risks. Independent firms can be viable counterparties, but must be especially careful about risk management, since no parent is present to help bail them out of mistakes. They may have more modest amounts of capital invested and are usually regarded as riskier counterparties. All three failures of the summer of 1998 were independent trading firms.

The easiest counterparty credit risk to assess is a situation in which the trading activity is a division of an operating subsidiary. The trading risk is blended with corporate credit risk. These operating subsidiaries usually have rated debt.

Table 1

Comparison of Volatility Levels for Several Commodities and Financial Futures Contracts (annualized standard deviation of monthly returns over 15 years)
Commodity/Financial Instrument	Annualized Standard Deviation of Return
Natural Gas	76%
Amex Oil	41
S&P 500	16
Gold	14
Yen	11
Bond Index	9
Source: RemotePlus

Table 2

The Top 10 Gas Marketers in 1998 (full-year sales volume)
Rank	Gas Marketer	Sales Volume (bcf/d)	Market Share
1	Enron	11.13	9.5%
2	Aquila Energy	9.60	8.2
3	PG&E Energy	9.37	8.0
4	Duke Energy	8.40	7.2
5	Dynegy	8.20	7.0
6	Coral Energy	8.10	6.9
7	Engage Energy	7.00	6.0
8	TransCanada	5.56	4.7
9	Southern Company	5.30	4.5
10	Koch Energy	5.15	4.4
Total Sales 117.32
Source: Intelligence Press Inc.

Table 3

The Top 10 Power Marketers in 1998
Rank	Power Marketer	Sales Volume	Market Share
1	Enron Power Marketing	399.1	17.6%
2	Southern Company Energy Marketing	184.6	8.1
3	Electric Clearinghouse	121.0	5.3
4	Aquila Power Corp.	120.4	5.3
5	Entergy Power Marketing	98.0	4.3
6	Duke Energy Trading & Marketing	97.0	4.3
7	LG&E Energy Marketing	94.0	4.1
8	PG&E Energy Trading	82.3	3.6
9	PacifiCorp Power Marketing	79.9	3.5
10	Citizens Power Sales	76.9	3.4
Total Sales 2,268.4
Source: Edison Electric Institute

Trading divisions have become more rare as trading activities have grown, however, and most diversified energy companies now engage in trading through a separate subsidiary, and possibly more than one. No public information is available to assess the level of risk being assumed in the trading operation, the amount of counterparty risk assumed or how well risk in general is being managed. Since June 1998, nonpublic financials for these companies have become more readily available—a marked improvement.

Ratings implications

Even with sound risk management policies in place, BTU trading holds potential for significant losses. From a broad perspective, engaging in BTU trading, which will be necessary to some degree for most market participants, leads to increased business risk across the whole corporation. This is especially true given the recent trend toward explicit, formal support by the parent for the trading subsidiary’s activities. Ratings agencies may weigh the amount of support provided as part of their assessment of the parent’s credit profile.

Many energy trading and marketing operations are only a few years old, and, as they have grown, a good number of them have had changes in management and policies along the way that have had an impact on earnings. Many companies are still learning the trading business—which requires different competencies from those required in their core utility business—while they are making large investments. Risk management is something that is still evolving. This is particularly true for electric power, since the market is still developing. In the meantime, gas and electricity volumes are rising rapidly, perhaps outpacing the installation of appropriate risk management systems and procedures to manage and monitor the growth.

There is concern that increasing competition and consolidation in wholesale BTU trading raise the risk of significant loss for those who participate. Second-tier traders may face charges to earnings as they unwind large or long-term contracts.

When the risks of energy trading firms are evaluated, we need to examine risk management policies and oversight; the experience of traders and managers; corporate strategy regarding the trading function; management of the credit function; the firm’s value-at-risk and other risk management models; back-office operations; access to supply to meet obligations; the formal parent support of the trading entity; and the capital and liquidity of the trading entity relative to the business risks.

An exhaustive list indeed. Companies thinking of joining the energy trading business have a lot to think about before making the leap.

The Energy Trading Timeline Although utilities have been “trading around their assets” for many years—originally marketing their excess capacity themselves at regulated rates—wholesale power trading in significant volumes at market-based prices is a relatively recent phenomenon. Wholesale and retail energy marketing first developed as a result of gas deregulation, which began in the 1980s. Wholesale gas marketing began with the Federal Energy Regulatory Commission (FERC) allowing open access on pipelines (that is, pipelines opening up their transportation service to wholesale customers) in 1985. Capacity release (the ability of pipelines to auction-off unused pipeline capacity) and the unbundling of interstate pipeline services (major wholesale customers became responsible for buying gas for themselves and for transporting it to their facilities) were enacted in 1992. These regulatory actions gave rise to the development of energy marketers that traded gas and pipeline capacity. Enron, then a diversified gas transmission company, began building its wholesale trading business as part of its strategy to become the “first gas major.” Then, in 1984, Natural Gas Clearinghouse, now named Dynegy Inc., was formed. Other gas companies followed suit in the 1990s by establishing energy marketing affiliates of their own. In 1990, the Henry Hub futures contract was established. This improved the liquidity of the market by providing a trading instrument and the additional market confidence that comes with better availability of price information, also enhancing the ability to hedge. Not only were Enron and Dynegy among the first natural gas marketers, they also anticipated the convergence of gas and electricity—with the expectation that a growing portion of power generation would be fired by gas. In the mid-1980s, Enron began building gas-fired electric power plants in the United States, as part of its strategy to sell gas worldwide. By 1992, it was building gas-fired power plants in other parts of the world, and broke out power as a separate segment and core competency. Dynegy, for its part, formed Electric Clearinghouse in 1994, adding another product to its “energy store” concept. By 1996, natural gas companies dominated the top 10 power marketers (see Table 1). Virtually no traditional investor-owned utility names appeared among the majors at that time. (The names are those that these firms used at the end of 1996. Many energy marketers have changed their names for purposes of corporate image or after an acquisition or merger.) FERC awarded the first power marketer licenses in 1986 (Citizens), while wholesale power marketing got a big boost in the mid-1990s. The U.S. Congress passed the Energy Policy Act in 1992, which created a new, unregulated generating entity (the exempt wholesale generator) and gave FERC authority to develop wholesale electric competition. After soliciting input from the industry, FERC issued its Order 888 in 1996, which enabled wholesale competition in the electric industry by forcing transmission owners (mostly those vertically integrated investor-owned utilities that are subject to FERC’s jurisdiction) to provide equal access at comparable terms to their transmission systems for the movement of wholesale power. Suppliers could no longer be economically prohibited by high transmission rates from reaching wholesale customers, who theoretically had the ability to choose suppliers before that year. The deregulation of the electric industry has also caused electric utility companies to increase their investments in new businesses, including energy trading. Two notable examples are Houston Industries and Duke, both of which in 1997 acquired gas companies with well-developed energy trading infrastructures and expertise. These acquisitions catapulted them into the ranks of major BTU traders. The top 10 gas and power marketers in 1998 are shown in Tables 2 and 3. The presence of many of the large trading firms on both lists, such as Enron, Aquila, Southern, Duke, PG&E Energy Trading, and Dynegy/Electric Clearinghouse shows the extent of development of the BTU trading market and the convergence of the electric and gas markets. The presence in Table 3 of several companies from the electric utility sector among the top 10 is also notable. The delay in these utilities’ standing among the top 10 power marketers reflects the challenges they had to overcome in shifting their trading from that of a regulated utility into that of a power marketing entity. These challenges included satisfying regulators’ concerns about the separation of a regulated utility’s activities, including its transmission grid controls, from the nonregulated marketing activities of the trading affiliate. American Electric Power, an electric utility holding company, is a significant trader of energy, particularly electric power, but because it trades through its utilities, it does not report these trades to FERC for FERC’s tracking of power marketer trading. The top 10 power marketers still dominate approximately 60 percent of the market, down from 73 percent in 1996. FERC does not require licenses to trade at unregulated prices in the natural gas sector. By the end of 1998, 560 power marketers were licensed to trade, although only 150 actually traded and reported those trades to FERC as required. —E.E.

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