Futures Trading for Utilities Maybe, Just Maybe, Will Happen

William H. Smith, Jr.

nless utility regulators learned commod- U ity futures trading in a former life, they do not have any innate savvy on hedging strategies or forward transactions. But it is time to get up to speed. Utilities are starting to look seriously at this market as a tool for their gas supply strategies.

Utilities are starting to look seriously at this market a s a tool for their gas

supply strategies.

Regulators do not need to learn how to conduct futures transactions, any more than they need to know how to conduct seismic interpretation, weather forecasting, labor ne- gotiations, price bond issues, or remediation of toxic waste sites. Utilities may have reason to do any or all these activities. The regulator’s job is to be able to evaluate whether the utilities have made reasonable decisions in performing their public service functions.

FERC’s initiatives are giving gas distribu- tors and end users a widening range of choices to meet their supply needs. In this kind of a competitive market, it is not unusual to see the emergence of a futures trading market.

Who’s Playing? Not Utilities Producers, marketers, local distribution

companies, end users, and anyone else can participate in this market for gas futures. State regulators do not participate in this market,

William H. Smith, Jr., is chief of the Bureau of Rate and Safety Evaluation for the Iowa Utilities Board and directs the Board‘s FERC participation. He participated in the Regulatory and Policy Issues Task Force for the NPC study.

at least not on a profess- ional basis. Despite the g rowth of t rading in natural gas

contracts, little of it seems to be coming from distribution utilities. Why are they holding back? Are regulators to blame?

Utilities cite several persuasive nonregulatory reasons for their reluctance to become active futures traders. They believe the market is unsettled and volatile. Partly they attribute this to the extensive use of NYMEX prices for contract price setting. To the extent a utility’s suppliers have hedged their risk through futures contracts in order to give the utility a fixed-price contract, the utility is actually participating indirectly. Utilities also note that the highest price differen- tials have been in the winter months, when the impact on customers would be greatest. Utilities correctly note that they lack the sophistication to build and conduct successful trading strate- gies. And these companies are cautious about the cost of staffing a knowledgeable trading group.

Regulators do not need to learn how to conduct futures transactions, any more than they need to know how to

conduct seismic interpretation, weather forecasting, labor

negotiations, price bond issues, or remediation of toxic

waste sites.

Utilities feel a working futures market gives them benefits even without participation. Letting sellers to these utilities hedge facilitates fiied- price supply contracts. Such hedging gives the utilities price discovery. It can be used as a pricing mechanism in purchase contmcts.

To these reasons for nonparticipation, the regulatory system adds just one more, although it is an important one: fear that a cost will not be recovered.

12 NATURAL G A S JUNE 1993 Copyright 0 1993 by Executive Enterprises

Nothing to Fear but Disallowance Most retail gas customers still want to buy a

bundled, delivered, no-notice gas service. Regu- lators still believe one of their main functions is to verlfy that the utility’s gas purchases on behalf of those bundled, delivered service cus- tomers are made at the best prices consistent with the reliability inherent in a firm, no-notice service. In most states, regulators now expect to see diversity in the gas supply arrangements: several suppliers, different geographic sources, transportation over multiple pipelines if pos- sible, and a variety of contract terms and expi- ration dates. Futures contracts could add an- other dimension of diversity to this stew.

Futures contracts couid add another dimension of diversity. . .

The key question is whether futures contracts can improve either the cost or the reliability of the utility‘s gas supply. A commission could find that a utility could have lowered its gas costs through futures contract trading. Then the commission could disallow the difference between the lower cost and the amount actually paid.

The coin, however, flips both ways. Futures trading could lead to a higher gas cost. Then the commission could disallow the cost in excess of the more conventional lower-cost strategy. Some observers believe the fear of this possibility is the real reason utilities are avoiding the futures market.

Thus far, no one has persuaded regulators that direct participation in the NYMEX market is the preferred way of meeting customers’ gas needs. Indeed it would be surprising if any- one had: With utilities defending their nonparticipation, who is there to make a well- informed argument to a state commission that the utilities are missing an opportunity on the NYMEX? Neither consumer advocates, other intervenors, nor the regulators themselves are likely to have the information or the analytic skill to make such a case.

Utilities have a real concern that the pru- dence review process will be asymmetrical. There is a small but real risk of disallowance of some gas cost, and there is no countervailing opportunity to profit by superior performance.

8egulatory Action To Reduce :he Barrier Regulators need to be satisfied with four

points before they will be able to reduce utilities’ fear of adverse regulatory consequences of futures trading. Either regulators and utilities need to understand these points better so they can live with them, or the market must mature in a way that makes these points obsolete.

1. Hedging versus Speculation Hedging requires the presence of specula-

tors in the market who trade to profit from price changes in the futures market. Hedgers shift price risk to these speculators. Most regulators think utilities should avoid nonproductive risk. Thus, regulators believe that utilities should not undertake speculative trading.

Successful speculation requires different skills than marketing and distributing natural gas. Utilities could hire or develop this skill, but only at a cost. It has also been suggested that the risk-return relationship for gas distribution is incompatible with market speculation. This is because losses from speculation would be likely to occur at the same time as rate payers are experiencing higher natural gas prices. Allowing gas speculation could open the door to utility speculation in other energy commodi- ties or even in commodities less directly related to the utility’s business, perhaps Canadian cur- rency. Perhaps most bluntly, regulators recog- nize a poIitical reality: The pubIic views com- modity speculation as gambling and would protest such a use of ratepayer money.

The public views commodity speculation as gambling azd Would protest Such Ei US2 Gd

ratepayer money.

If a PGA shifts the risk of gas cost to ratepayers, it is appropriate to question a utility’s incentive to hedge carefully. A regulator look- ing to give a utility more incentive to lower gas cost might consider eliminating the PGA, in whole or in part, in favor of a fixed gas cost. Other incentive plans can also be devised. The issue of symmetry between risks and rewards needs to be considered in an incentive plan.

Regulators are feeling their way towards distinctions between speculation and hedging in another emerging market: emissions allow- ances. Electric utilities have been issued allow- ances to emit sulfur dioxide into the atmo- sphere based on their generating plants, and

JUNE 1993 PiATi;?AL GAS Copyright 0 1993 by Executive Enterprises

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must develop strategies for holding, selling, and buying these allowances. State and federal regulators expect to review these plans for ratemaking effects much as gas purchasing plans are reviewed.

On March 31, 1993, FERC issued a final accounting rule (Order No. 552, Docket No. RM92-1) for allowances and allowance trading that requires distinct treatment for hedging and speculative transactions. Contemporaneous records are to identlfy the purpose for which allowances were purchased. Hedging treat- ment is limited to exchange-traded allowance futures contracts “used to protect the utility from the risk of unfavorable price changes.” The costs and benefits of these transactions are held in deferred accounts until the contracts are closed. The rule shouId stimulate ex- change-trading of allowance contracts. Re- ported exchange transactions will facilitate fact-based regulatory review of hedging trans- actions.

One analyst has suggested three tests for acceptable levels of natural gas futures trading that would be presumed to be for hedging:

Futures contract volume should be lim- ited to the utility’s physical purchase volumes. The utility has no need to hedge volumes larger than it uses. “Account churning” should be limited. Excessive turnover suggests specula- tion rather than risk minimization. Logic behind a transaction should be documented and defensible.

2. Understanding Volatility in the Market The natural gas contract has been well-

received in the commodities markets. The contract reached the WaIIStreetJournal’s

reporting requirement faster than the crude oil contract. Within a year, open interest was greater than for gasoline and heating oil. During 1’992, a natural gas contract ranked among the five widest swings in commodity trades during each quarter. During the third quarter, the October gas contract produced the biggest gain of any traded commodity. That kind of volatility makes for great speculation, but is hard on hedgers and spot buyers.

It is a matter of some concern to regulators if these volatile prices, driven to some extent by speculative interest, are used as the basis for

pricing long-term supply contracts. Payments could be too high or too low because of short-term market activity. Thus, both buyers and sellers could be pushed into uneconomic decisions concerning fuel choice or production levels.

The degree to which the futures market sets the price outside its proper domain is a point for further study.

3. Convergence Theory of commodities markets says that as

the time of delivery approaches, differences between the futures prices and the cash (or spot) price for the commodity should disappear. This convergence has not happened with the gas contract as consistently as was expected. Lack of convergence detracts from the confidence LDCs and regulators want to have if the market is to be useful for hedging and price discovery purposes. [For more details about convetgence in natural gas futures contracts, see Schneier’s December 1990 column in this publication, “Making Fu- tures Work through Convergence.’3

It has been suggested that the convergence problem is really one of timing. The futures contract closes seven days before the delivery month. Spot gas is typically priced on a monthly basis, with large volume trades made in the final days of the prior month, but with price changes occurring well into the month.

As the market matures, the importance of bid week is diminishing. If the convergence problem is just a timing matter, trading patterns may smooth out enough to eliminate the problem.

4. Basis Risk Futures contracts have to use a specific time

and place for delivery. Assuming that is not the place buyers actually want to receive gas, they accept the risk of deviations in price pat- terns between the two points. This risk is called basis risk.

An extreme example occurred when Hurri- cane Andrew closed the Henry Hub (the basis of the NYMEX natural gas contract) at the time of August delivery. That closing caused a price surge there that did not occur elsewhere in the gas system. Instead of hedging a risk, market participants found themselves exposed to a risk because of their participation.

Although this hurricane was an admittedly unusual event, regulators would gain confidence in the gas futures market if it can find ways to reduce or eliminate basis risk. a

14 NATURAL GAS JUNE 1993 Copyright 0 1993 by Executive Enterprises