State public service commissions are insisting that utilities adopt risk management programs, and are allowing less pass-through for those that don't.

Judging the success of natural gas utility price risk management programs for a heating season is slippery business. Volume risk, the large, unpredictable and, at times, unsettling variability in customer loads during the heating season and a key consideration in a price risk management program for a utility, is of relatively minor importance for most other natural gas businesses that practice price risk management. Accordingly, producers and marketers were once again more successful in 2001/2002 in hedging price risk.

Success in price risk management for producing companies in 2001/2002 often meant locking in a forward price that was large relative to a known forward cost of production.¹ Success in price risk management for marketing companies in 2001/2002 meant doing a lot of deals in which the derivatives market was used to lock in a large number of relatively small returns with a focus on creating a relatively steady cash flow as a base for growth in other areas. Sad to say, the leveraging off of a sound trading operation got out of hand for several companies during the last several years.²

Yet, utilities generally do not have the opportunity to lock in returns on trading positions like marketers, nor do they have a natural yardstick for gauging possible success like producers.³

Moreover, commissions are a major part of the equation for success with utilities. A disallowance because of imprudent price risk management decisions can significantly damage a company's overall net return for an entire year. Yet, sometimes the commission's voice may not be heard for at least a year after the heating season price risk management decisions are made.

Thus, a report for utility price risk management programs for a recent heating season may include information from the current heating season. It might also include information from previous heating seasons about which commissions have recently taken positions. This state of affairs is particularly interesting now, because price risk management programs have been put to the test of two heating seasons that have been completely different in terms of weather and the business environment.

Greater Price Turbulence in 2000-2002: Utility Risk Managers Face Uncertainty

The price of natural gas was near $2/MMBtu in November 1999, but had increased five-fold 13 months later, to $10/MMBtu as of December 2000. Yet, nine months later, in the fall of 2001, the price was back down to $2/MMBtu. ()

Price risk managers had to contend not only with a constantly moving price level⁴ (), but also with changes in price volatility, or the ordinary movement up and down around a price level. Some of the change in price volatility during 2001 was predictable, but some clearly was not.

A useful and simple indicator of price volatility is the variability in percentage changes in price as indicated by the lengths of the lines in Figure 2. The lines indicate that price volatility increased from spring and summer levels in the fall and heating seasons of 1999/2000 and 2001/2002, as expected. But the increase in volatility in the fall and early heating season of 2001/2002 was a surprise.

The large price risk in the fall and early heating season of 2001/2002 can largely be explained by the uncertainty in markets created by the failure of Enron. With traders exiting Enron as a trading partner and seeking new trading partners, there was a reduction in liquidity in the market. Thus, despite robust supplies, each significant movement in temperature between days appeared to be greeted with large up and down movements in price, especially in November when the downward slide of Enron accelerated.

Yet, despite these significant challenges, some utilities and commissions have been successful in steadily addressing utility price risk management practice.

Of course, not too surprisingly, utility price risk management programs vary greatly. In fact, there is an east/west divide, with programs in the east being less ambitious compared to Southern California Gas (SoCal) in the west.

In the West ...

SoCal certainly appears to have continued to have a successful price risk management program during the 2001/2002 heating season. Success for SoCal is measured not only by the ability to effectively hedge or fix its wholesale cost of gas through a derivative instrument, but also by an improved capability to purchase gas.

The hedging program at SoCal is best viewed as a complement to a price incentive program for wholesale gas purchases. Not unsurprisingly, there are risks in this program. Yet, the consumer advocate tracks the incentive program and a report is produced annually. Risks are measured and reported, along with a variety of other information, on a regular basis to commission staff.

SoCal not only uses the New York Mercantile Exchange (NYMEX) futures contract market to hedge price risk, but it also places orders directly onto the exchange floor. The program has been in existence for much of the 1990s, and is manned by professionals who have been engaged in the derivatives market since the inception of the NYMEX natural gas futures market in 1990.

In the East ...

On the other hand, utilities in West Virginia continued with a successful program begun in 1996, several years after the program at SoCal was initiated. The program is a success because the utility, the commission, and the customers generally view it as a success and it is relatively transparent. The approach in West Virginia is much different from the approach in Southern California.

Since 1996, the State Commission and Consumer Advocate staff in West Virginia have tended to set a price target for the utility based on the NYMEX forward strip over several years. The utility then attempts to find a counter-party provider of gas that can at least meet the price. The price is then fixed for all volumes of gas. The utility, in turn, gives up all rights to transportation and storage assets. Thus, utility customers are not faced with any price or volume risk. However, to obtain this, they need to give up any gains associated with having rights to transportation and storage assets, such as gains on the capacity release market.

Utility price risk management in West Virginia had enough of a history by 2001 that a director at the State Commission was able to prepare a report of that experience.

Not only did West Virginia customers experience more stable costs since 1996, but they paid a price that was significantly less than the average cash price during the period.⁵ Naturally, the hedged price in some years was above the cash price and some years it was below. Most importantly, many customers received protection from the high prices in 2000.

When the program was first put in place in 1996, commission staff and the Consumer Advocate proposed as part of a settlement that the utility would lock a price at the average three year NYMEX price. At the time, this was $2/MMBtu. The utility had the option of hedging or not. If it didn't hedge, and if the average spot price paid turned out to be less (more) than the $2/MMBtu, stockholders would receive (incur) the gain (cost).

The report concluded, "when the risk of gas cost increases was transferred to the stockholder, hedging became the strategy of choice." On a policy note, the report concluded, "failure to even consider hedging should be considered as a complete abdication of utility management responsibility."

Utilities in Kentucky-as in California-have also been trying to work out the coordination of utility price risk management with their commission. Especially after the 2000/2001 heating season, Kentucky encouraged utilities to evaluate the use of hedging instruments. Accordingly, companies such as Western Kentucky Gas took positions in the New York Mercantile Exchange natural gas futures contract market for winter 2001/2002.

Yet, Western Kentucky Gas did not place the order directly on the exchange. Like SoCal, it relied on a consultant/broker. The company emphasizes that the hedging program is only part of the overall supply program and its program is manned by supply professionals.

Western Kentucky Gas targets a proportion of its expected requirements to obtain from storage and another smaller proportion to hedge using the NYMEX futures contract. It places the hedges on throughout the non-heating season-the idea is not to put in place all the hedges at one time, and risk the chance of paying a relatively high price. Nonetheless, staff pays much attention to price behavior and market conditions near the time they put the hedges on.

The utility is conservative in its hedging program and hedges a volume of gas purchases for a month that it fully expects to purchase. Thus, it expects to be able to easily match a volume of gas purchased with a futures contract market position. Nonetheless, it plans over time to review its policy as it gains experience using the futures contract market. It views its program as a success in that it is receiving a reduction in price risk exposure for its customers and the cost is viewed as reasonable. The company also worked jointly with the commission to develop the program. The strength of the relationship is also a positive sign.

Unlike SoCal and Western Kentucky Gas, Columbia Gas of Ohio, like many other utilities, relies on its gas suppliers to hedge or fix the cost of gas for forward supplies. The utility has contracts with several marketing companies to lock in a price for a certain volume of gas. Utility staff keeps an eye on the NYMEX futures contract price. When they observe a price that follows some criterion as to reasonableness, they lock in the observed price-or a price near the observed price.

The utility negotiates a forward price with the supplier based upon the NYMEX price plus or minus the difference in gas value, between the wholesale market where the utility intends to take ownership of the gas, and the Henry Hub in Louisiana where the NYMEX contract is traded.

In any case, the utility company seems well aware of the Financial Accounting Standards Board (FASB) Order 133/138. Thus, it believes that were it to engage in the NYMEX market directly, there would be the need to maintain accounting records to document the value of the futures position and the hedged physical position over time (marked to market accounting), and to fulfill other requirements of the Order.

It is also concerned about whether costs associated with running a successful hedging program-such as costs associated with variable margin requirements for a NYMEX futures market position-would necessarily be included in standard gas cost recovery accounting.

Columbia Gas of Ohio, like many other utilities, is somewhat conservative in the amount of gas it hedges. This is, in part, because of a successful customer choice program that has resulted in the number of customers supplied by the utility to vary within a year which, of course, complicates determining the volumes to hedge. It is also conservative because storage capacity is a major component of its portfolio. The utility is somewhat less conservative in terms of how far out the hedge can be placed. The utility is always ahead at least two winters into the future.

Despite these and other issues, Columbia Gas of Ohio continues to consider using futures contracts and other derivatives directly, and is planning to start a detailed review and evaluation of its price risk management program within the context of overall supply management program as soon as the summer of 2002.

And Everywhere Else ...

In a variety of states stretching from Maine to New Jersey and Colorado to Kansas utilities, such as Kansas Gas Service in Kansas, used call options, collars, or fixed price contracts to put a cap on price for a certain volume of gas during heating season 2001/2002.⁶

By the crude measure of price risk management success-whether companies avoided high prices in the heating season-hedging programs of most utilities using such contracts were failures and companies are kicking themselves as a consequence.⁷ Options, for example, increased the cost of gas to consumers without yielding any direct benefit. These instruments are just like insurance. If the accident of high prices occurs, the utility customers are protected. But if the accident of high prices does not occur, they must still pay the premium, as they did.

Figure 3 shows this clearly. Most utilities purchased the hedges over the injection season. It can be observed that the price of natural gas for the heating season months was very high initially in early 2001, but it declined significantly over the injection season and stayed low during the heating season. () Thus, the strike price (cap) for most call options likely exceeded $3.50/ MMBtu, as did the price in most fixed price forward contracts and floor prices in swaps and collars.

Since all bid week prices during the heating were less than $3.50/MMBtu (), options were not executed and utilities with other hedging instruments such as fixed price forward contracts paid a price much greater than the market price.

But this is not a problem. It is just the luck of the draw as long as the volumes hedged were no greater than volumes actually required and volumes determined as part of a plan. In some instances, utilities may have hedged more than actually was required, which could be a problem.

Utility price risk management is first of all about volumes. If enough attention is not paid to the volumes to hedge, the company may find itself in the position of not fixing the cost of the gas-which is the purpose of the hedge in the first place.

For example, a company requires only 20,000 MMBtu to be purchased (after account is taken of normal or planned withdrawals from storage) in a heating season month when the cost of gas is $2/MMBtu. But it has an obligation to pay $4/MMBtu for 30,000 MMBtu under a fixed price forward contract. Under these conditions, the company pays $120,000 for the gas. It then sells the 10,000 MMBtu it didn't need at $2/MMBtu. It receives $20,000 for this gas, which leaves it with a net cost of $100,000 for 20,000 MMBtu, or a unit cost of $5/MMBtu. Thus, it neither fixed the price of gas at $4/MMBtu (the purpose of the hedge), nor did it take advantage of the $2/MMBtu gas.

Available evidence suggests that several companies were in a situation where hedged volumes exceeded required volumes during the heating season of 2001/2002. Yet, whether the avoidable economic costs that occurred as a consequence are considered imprudent or simply oversights by the utility because of its inexperience with hedging will not be known until the next hearing cycles at the commissions.

Progress at State Commissions

Commissions are still sorting out the type of hedging program they are likely to support and what type of hedging decisions are considered prudent. In many states, a commission may encourage a utility to provide a price risk management program. But the utility is allowed discretion in making decisions and on choosing a program. The commission then reviews the price risk management program, the decisions made, and the outcomes from the decisions, just like any other program.

In other states, commissions pre-approve plans. The companies' hope is that if they get approval for the plan, they will be protected from an imprudence disallowance. However, it may not be protected if it is found that in the execution of the plan, consumer price risk protection was not always the focus of the company and price risk protection was compromised as a consequence.⁸

In any case, a plan once proposed by the company and/or approved by the commission should be followed. Plans not followed invariably lead to problems.

Nonetheless, the completion of every case is a mark of success because each ruling establishes business practice in an area of business that is rife with possible conflicts of interest. Toward the end of last year, these conflicts were aired in important hearings in Oklahoma and Rhode Island.

Rhode Island & Oklahoma PSCs: Allowance Rules Vary From State-to-State

In Rhode Island at end of October 2001, the commission stated that it was prescribing a disallowance of hedging for several reasons.⁹ The commission had either approved a utility pilot hedging program to manage the impact of price volatility, or it had instructed the utility to prepare for price spikes through hedging and the utility had done nothing, or not enough.

The company had adequate time to prepare a hedging proposal if they had thought it necessary to get approval, but the company had not acted. Furthermore, the fact that other utilities did not engage in hedging did not shield the company from a finding of imprudence.

The commission ruled that one utility was imprudent because it did not hedge. The other utility was imprudent because it didn't hedge enough.

As a consequence, a disallowance was recommended that amounted to 22 percent of the company's net income. The commission concluded, "The Companies in 2000 acted like the grasshopper in the fable of 'The Grasshopper and the Ant.' Like the grasshopper, the Companies frolicked during the spring and summer and did not prepare or plan ahead for the winter. When the winter came, the grasshopper perished. Unless the company wanted to share the fate of the grasshopper, it should plan ahead and be proactive."

Meanwhile, in November 2001, the Oklahoma commission ruled on an important, contentious, and very controversial case.¹⁰ It found that the company did not have any financial hedges. The company also did not have storage service as a hedge during the heating season of 2000/2001, even though it had access to storage and had used storage services in the past. Instead, it had contracted for a load following service, which effectively provided it with all the gas that it might need, but at a market price. In other words, the customers of the company were completely exposed to price risk.

The company had contracted for the load following service with an affiliate of the parent company. The affiliate had rights to the storage service that the company had previously contracted for. This provided the marketing affiliate with an asset that might be expected to have a very high value during the period, since supplies were recognized as tight and both the price level and price volatility was high as a consequence. This had all the appearance of a conflict of interest-the company appeared to be serving other agents at the expense of the consumer.

Subsequently, the commission found the company's "failure to utilize traditional storage, to develop a diversified gas supply portfolio plan, to implement a price mitigation plan or to take any significant action to mitigate price volatility on behalf of its ratepayers, compels the Commission to find the company imprudent."

The total impact of the program was $46 million. However, the final ruling only disallowed recovery of the $34.6 million remaining balance in gas costs not recovered for the 2000/2001 heating season.

Measuring Achievements

Achievement cannot be completely measured by cataloguing what particular utility commissions and utility companies have been doing. Benefits from price risk management will be well measured, and successful programs identified when utilities follow through on planned programs and adjust programs based on customer requirements being met or not. Moreover, benefits will only grow if going forward utilities and commissions and their staff and consumer advocates are towing the same lines.

Nonetheless, some achievements are worth mentioning:

• More utilities are using the regulated futures options market directly to hedge price risk. They are gaining commercial and other skills from this experience.
• More commissions are ruling on what are prudent price risk management decisions and what are imprudent.
• More commissions are ruling that failure to follow a price risk management plan or failure to make price risk management decisions is imprudent.
• Simply passing all commodity costs onto consumers is no longer considered acceptable as it was in the past. This naturally is good for consumers since it will stabilize their bills over time.¹¹ It is good for stockholders since it will increase or tend to sustain the credit rating of the utility and thus reduce its cost of capital.

Thus, going forward several things may happen from the more active involvement of state commissions. The utility will be better able to satisfy customer needs. Utilities will become better informed, more aggressive buyers of gas. They will be better able to measure the value of their assets, and they will be more likely to capture risk free or arbitrage returns.¹² Finally, as they better understand the gas wholesale market,¹³ with the collapse of Enron, and the increased importance of a credit rating, utilities will be better able to negotiate and purchase gas directly from producers and avoid the problems and costs of dealing with a middleman.

1. The better the producing company is at assessing its expected future production and its expected future marginal cost and the greater the debt on its books the greater the incentive to hedge.
2. This was the great success of Enron. The weakness was that the consistent current cash returns were highly leveraged to investments that didn't yield much of any current income and the marking to market of forward supplies was corrupted to consistently inflate expected paper forward revenues which, in turn, were used to inflate current booked profits. Enron's failure was not about a hedging program but about hedging being used as a term to describe speculative relationships.
3. The trade press, such as Gas Daily, regularly reported throughout much of 2001 on the large number of producing companies using the futures market to lock in large returns. In 2001 up until July/August the average of the forward prices for heating season 2001/2002 was generally above $4.00/MMBtu. If the marginal cost of producing and delivering the gas to the wholesale market is $2.00 for the producer, this represents a 100% return.
4. The decline in the price level for heating season 2001/2002 was largely caused by robustness of supplies as measured by storage in the AGA producing region when compared to year earlier levels, but other factors mattered greatly as well, such as demand. John H. Herbert, "The Gas-Fired Future: Boom or Bust? Last year brought price not seen for decades. So Consumers will buy less gas just as before, and send the forecasts out the window", , p. 20, April 1, 2001, page 20.
5. David J. Ellis, Director of Utilities Division, Public Service Commission of West Virginia, July 11, 2000, available from www.psc.state.wv.us/hedging.pdf.
6. For a clear documentation and review of a hedging program near the beginning of the heating season see "Testimony of Bradley O. Dixon, Case No. 98-KGSC-475-CON, Kansas Gas Service Company", December 21, 2001. It would be a positive sign if more Commissions held such hearings.
7. , Munis credit rules provide risk protection, February 4, 2002, page 6.
8. For example, an approach in some approved plans for options by Commissions is to agree on a lump sum cost of a volume of gas to be hedged, based on the cost of the options at the time of approval. If the utility waits to put on the hedge in the hope that the cost of the option will come down and it will pocket the difference between the approved cost and actual cost, this can create major problems if price risk or price level increases in the interim. If either price risk or the price level increases, the cost of hedging each volume of gas will increase and customers will get much less protection from price risk. Worse than that, the customer may receive no protection if the company fails to put the hedge in place because the 'return' from effecting the program (incentive) was not great enough. In essence the utility is betting that it has a better than a 50/50 chance of obtaining a gain because the cost of an option necessarily declines as the termination date of the option approaches as long as the price level and price volatility do not increase.
9. State of Rhode Island and Providence Plantations, Public Utilities Commission Docket Nos 1673, 1736 & 3347, October 17, 2001.
10. Corporate Commission of the State of Oklahoma, Case No PUD 200100057, November 2001, Order Regarding Prudency.
11. See John H. Herbert, The Gas Merchant Business: Still a Place for LDCs?, , July 1, 1999,
12. John H. Herbert, The ABCs of Trading Btus: A Guide to Convergence of Prices and Services in the North American Natural Gas and Electricity Markets, Energy Intelligence Group, New York, New York, 1998. Martha Amram and Nakin Kulatilaka, Real Options: Managing Strategic Investment in an Uncertain World, Harvard Business School Press, Boston, Massachusetts, 1999.
13. It is also important for utilities to understand better the measurement and interpretation of price risk measurement as described in "Gas Price Volatility-A Practitioner's Perspective", EPRI, Energy Markets and Generation Response, February 2002.

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