EL NIÑO HAS STRUCK, WITH NO END IN SIGHT.

Consider that Aquila Energy, the marketing arm of UtiliCorp United, has announced a new financial derivative, known as GuaranteedForecast,sm to hedge the weather against forecasts by the National Weather Service. The new product will pay holders a guaranteed amount if the mercury strays, and Aquila touts its thermometer hedge for any of 170 U.S. cities (em be it Spokane, El Paso, Chicago or New York. Why talk about the weather when you can invest in it, in true '90s fashion?

For this heating season, however, it may be too late.

The American Gas Association released figures recently indicating that this year's winter so far (weeks ending Oct. 4, 1997, through Feb. 7) has been about 6.8 percent warmer than normal and 5.1 percent warmer than 1996-97. The warmer trend appeared most pronounced in January 1998, which came in nearly 20 percent warmer than normal and 18.3 percent warmer than 1996-97, according to the A.G.A.

Meanwhile, in the Feb. 17 issue of its Natural Gas Weekly Market Update, the U.S. Energy Information Administration said most forecasters were calling for more of the same, with implications for gas prices: "The lack of any substantial weather-related demand for natural gas so far this winter has resulted in a more than 33-percent drop in gas prices on both the spot and futures markets since mid-November."

Prior EIA research indicates that if average heating season temperatures rise 1.43 degrees Fahrenheit above normal, the drop in demand for natural gas will outweigh the increase that occurs each year to supply economic growth, thus forcing prices down. %n1%n In its Feb. 17 update, the EIA predicted gas storage levels "well ahead of last year," if the mild temperatures continue.

El Niño, it appears, has spared no one. Out west, Southern California Gas Co. lowered its procurement charge for retail core subscription to $2.0658 per MMBtu, effective Feb. 6, down from $2.3036 for January, $2.4684 in December, and $3.3872 for November 1997.

Nevertheless, while gas prices may be down, gas price volatility remains high.

On Feb. 9, for example, just a week before it was reporting that 33-percent price drop, the EIA notes an unexpected rally in gas futures prices:"[M]ost industry observers were surprised by the upward trend in both spot and March futures contract prices. The Henry Hub average spot price gained about 25 cents over the week ending Friday, Feb. 6, while the March futures contract gained almost 30 cents from the closing price on its first day of trading as the near-month contract expired on Jan. 29." %n2%n

John Herbert, previously on staff at the EIA and an expert on gas storage, pricing and risk management (email: jhhl@email.msn.com), explains the paradox: "Gas volatility doesn't go away, despite these new markets and transparent pricing.

"A key factor is storage relative to demand. In general, this winter's gas market has proven to be much different than a year ago, especially at the beginning of the season. That had a lot to do with the weather, and the industry appeared to be factoring in El Niño. At the start of last winter (1996-97), storage was down, for practically all energy, including propane and oil.

"But at the start of this winter," explains Herbert, "propane and oil were much higher. By November, gas storage was soon found to be above the prior year's level. Storage was growing, relative to expected demand. Prices going into December and January were lower."

Price volatility can occur between regions as well, marked by wide fluctuations in basis (the difference in spot prices between pairs of market hubs), as explained by consultant Benjamin Schlesinger, president of Benjamin Schlesinger and Associates, of Bethesda, Md. "This past winter (1997-98), we're seeing the fairly classic pattern of western gas stuck at fairly low prices, and by that I mean the Rockies and Canada, as a result of inadequate gas transmission capacity from West to East."

In a recent study he published on the Internet, %n3%n Schlesinger describes the phenomenon of basis "brick walls," wherein a stark line will develop across a map of North America, dividing regions into areas of positive and negative basis, in which citygate prices lie above or below prices in the South Central producing area. He shows how a brick wall developed in April 1996 running roughly north-south along the Mississippi River valley. But that configuration had changed by December, after the brick wall evaporated and then reappeared along the U.S.-Canada border.

"There haven't been any basis blowouts this past winter, as we saw during the last two years. In 1996-97, for instance, we saw the "brick wall" shift and re-emerge along the northern-tier states. That reveals how you cannot predict with certainty where the next 'wall' will develop."

Herbert seconds the motion: "Energy tends to show greater volatility than other commodities and natural gas is about twice as volatile as other commodities, generally. And that volatility is more than just day-to-day, week-to-week or month-to-month. Volatility can be seen from year to year as well."

If gas price volatility is the enemy, what's the remedy? Will a solution come from more regulation to dampen price risk for consumers even though it may shut them out from potential price savings? Or, will the answer come from greater price transparency, supplied by new spot and futures markets, including even perhaps coal or electricity futures, which could allow cross-hedging between different energy inputs?

The Past Winter:

What Happened and Why

Much has been written about the price spikes that plagued natural gas markets during the 1996-97 winter heating season.

In a study released last summer, %n4%n the A.G.A. notes the irony of high prices coupled with higher-than-normal overall

temperatures: "The 1996-97 winter heating season, on a national basis, was 3.5 percent warmer than normal and 6.1 percent warmer than the preceding winter." The A.G.A. also explains how the gas industry had drawn down storage inventories the year before to the lowest level in a decade, spawning higher-than-normal demand to refill storage throughout the summer of 1996. Then, when cold weather hit in November and December, many LDCs proved reluctant to withdraw significant gas volumes from storage "so early in the season." The A.G.A. ascribes that reluctance in part to "the role storage played in sustaining demand during the extended cold that [had] occurred" throughout the prior winter of 1995-96. It also cites index pricing practices as a cause for high prices in 1996-97. It notes that pricing for "substantial volumes of LDC gas supply" traditionally are based on first-of-the-month indices, despite bargains that may arise later in the month in the "aftermarket," and questioned whether the indices were set entirely at arm's length, or were supported by sufficient volume.

Were LDCs at fault? On one hand, the evidence discounts the idea that unregulated gas marketers manipulated the market. Schlesinger notes in his study that gas market concentration as measured by the Herfindahl-Hirschman Index fell each year from 1992 through 1996. He adds that 303 gas marketing companies were operating in unregulated North American gas markets by May 1997. The EIA puts the HHI for gas marketing firms at 243 for 1996, %n5%n far below the figure of 1,800 suggested in the Justice Department's Merger Guidelines as a sign of a highly concentrated market.

Nevertheless, while the EIA won't say that LDCs messed up, a study it released in August %n6%n seemed to offer no other reasonable conclusion for the 1996-97 winter heating season.

EIA agrees that at the start, after inventories had shrunk in the winter before (keeping prices high during the 1996 summer injection season); LDCs may have feared they would be caught short of storage toward the end of the coming winter. The EIA adds, however, that disruptions in railroad dispatch related to the merger between Southern Pacific and Union Pacific, appeared to have delayed coal shipments to power producers in Texas, adding to the pressure on gas prices. %n7%n Overall, the EIA finds that LDCs shunned withdrawals from downstream storage in the East Consuming Region (much of that storage is owned by the LDCs themselves). Instead, the LDCs turned to the spot market for supply in December, despite the high cost, rather than draw down storage volumes so early in the heating season, and even though storage was cheaper than spot prices. With the significant drop in December 1996 storage withdrawals, relative to the prior year, storage levels in the East Consuming Region equaled, and in some weeks actually exceeded, year-earlier values when prices were lower. The spot price for the Henry Hub in December 1996 averaged $3.78.

The EIA adds that "institutional factors" played a role: "Effective price signals to residential consumers are masked by specialized residential billing procedures, such as levelized billings, that are designed to avoid unexpected large increases in the monthly cost when possible." Why, for instance, should LDCs feel concern over high spot prices if they can pass along the expenses through gas cost recovery rates or a purchased gas adjustment clause?

Overall, according to the EIA, residential consumers paid $23.2 billion for natural gas during the 1996-97 heating season (em up from $21.2 billion the year before, representing an increase of more than 10 percent.

In fact, gas price fluctuations during the winter of 1996-97 prompted customers to ask for fixed-price options, even as pilot programs emerged for retail choice. Some regulators answered that wish, sometimes despite objections from the industry.

In New York, for example, Consolidated Edison Co. joined with Enron to oppose mandated fixed-price offerings. The utility predicted "confusion," while Enron claimed that a fixed-price option "distorts price signals" and would prove to be "a major hindrance" to competition. Regulators in New Jersey encouraged more conservative procurement practices, though it forces customers at risk to miss out on gas price savings. (See sidebar, "Low Price vs. Fixed Price.")

Electricity Futures:

Primed for Cross Hedging?

Last month, the New York Mercantile Exchange submitted two new electricity futures contracts (and two options contracts) for approval by the Commodity Futures Trading Commission. %n8%n One futures contract would be delivered at the Cinergy Control Area; the other at Entergy. (See sidebar, "NYMEX to the Rescue?")

These two proposals follow on the heels of the Minneapolis Grain Exchange, which earlier submitted electricity futures and options contracts to the CFTC, with a delivery point within a 30-mile radius of the Twin Cities, or the "TC GEN," to hedge against a cash market into the Mid-Continent Area Power Pool. %n9%n Terri Huffaker, vice president of marketing and public relations for the MGE, says the MAPP contract will offer NYMEX futures contracts at COB, Palo Verde, Cinergy and Entergy, by allowing delivery both on- and off-peak. (See sidebar.)

"Some commercial participants in the MAPP region approached us, including utilities and power marketers, asking for a risk-management vehicle. A marketer in the MAPP region really can't use the Palo Verde contract to hedge. We [MAPP] have different peaking seasons than Palo Verde."

Huffaker adds that the MGE worked with Northern States Power Co. and various MAPP-region power marketers to develop the contract. "MAPP did not work with us directly on contract design. We cannot claim we have a blanket endorsement from MAPP as an institution."

If all these new markets weren't enough to expand energy hedging opportunities, the NYMEX board of directors in January announced approval of a coal futures contract, to be launched later this year, with a trading unit of 37,200 MMBtu (heat content minimum of 12,000 Btu per pound), and a delivery point on the Ohio River between Milepost 206 and 317, or on the Big Sandy River.

Meanwhile, NYMEX had delayed filing yet another electricity futures

contract, deliverable at the PJM Interconnection. As explained by public relations officer Nachamah Jacobovits, NYMEX is waiting for the PJM companies to sort out all the trading rules for their new power pool, including the new locational marginal pricing scheme for electric transmission service approved for PJM in November by the Federal Energy Regulatory Commission, before launching a futures contract. "We're waiting to make sure that our contract reflects the cash market."

Cynthia Taylor, PJM's manager of customer relations and training, confirms the delay: "We will be implementing locational marginal pricing. There is no history for this type of market. I believe that is what has stalled the opening of the NYMEX contract."

Steven L. Brash, a spokesman for Cinergy, attributes the NYMEX decision to fix a contract at the Cinergy interconnection to his company's "very active and longer-time support for open transmission access" (hinting at the efforts of former PSI CEO James Rogers), and to the fact that the company maintains its own trading floor, 24 hours a day, seven days a week, operated through Cinergy's energy commodities business unit (not a separate subsidiary).

The Entergy contract, on the other hand, located near the Henry Hub, site of a premier gas spot market and a highly successful NYMEX futures contract for gas, offers the tantalizing prospect of cross-hedging between electricity and gas.

Entergy claims that its control area is well-equipped and positioned to handle physical delivery over its backbone of 500-kilovolt transmission lines and interconnections with 12 surrounding utilities. Shahid Malik, senior vice president and COO of Entergy Power Marketing Corp. (the utility's marketing and trading subsidiary), anticipates "a very good arbitrage opportunity" with the Henry Hub.

"A fairly large proportion of gas-fired generation is located in the South Central states," notes Malik. "This fact will allow us to hedge our trading of electricity with gas. You don't necessarily need to have a lot of nearby gas generation, but it does help."

When asked about the proposed NYMEX coal futures contract, and whether its location at a coal loading facility in Kentucky, close to the new electricity contract at the Cinergy control area, could possibly allow for power/coal cross-hedging, an EIA source declined comment, and Malik questioned whether the power contract would feature enough liquidity. He did volunteer, however, that the Cinergy contract could act as a proxy for New York and northeastern power markets in the event of a delay in starting up the PJM futures contract.

"They [NYMEX] have some real problems at PJM," Malik added.

Ben Schlesinger and John Herbert both remain cautious. "NYMEX is forging ahead," says Schlesinger, "but volumes will have to pick up through spark spread trading and arbitrage, before we get any real change."

Herbert acknowledges that Cinergy and Entergy are "very active wholesale markets for power, in terms of volume," but questions the market links between electricity and gas.

"Right now there's not much of a connection because of institutional constraints. That's why utilities are looking for assets.

"It's hard to cut deals, because nominations and contracts are not in synch. But if a company has both types of assets it can cut that knot." F

Bruce W. Radford is editor of Public Utilities Fortnightly.

Low Price vs. Fixed Price

Which Do Customers Want? Which Will Regulators Allow?

CONCERNED over gas price spikes during the winter of 1996-97, state regulators have called for more fixed-price

arrangements (em both in setting regulated retail gas rates and for portfolio supply contracting by gas utilities:

INDIANA. After hearing complaints about gas price volatility, state commission allows Indiana Gas Co. to back away from practice of buying all baseload gas supply at market-index prices, and instead buy a portion of gas supply under collars or fixed-price contracts. Case No. 37394-GCA54, 177 PUR4th 587, May 28, 1997 (Ind.U.R.C.).

IOWA. Utilities board allows MidAmerican Energy Co. to offer optional fixed-price sales service in a two-year pilot if the utility will absorb any gains and losses. Docket No. RPU-97-C (TF-97-201), 181 PUR4th 395, Dec. 10, 1997 (Iowa U.B.).

MICHIGAN. Regulators allow Michigan Consolidated Gas Co. to increase reliance on fixed-price gas supplies, but reject proposal to include a "volatility adjustment" in the gas cost recovery factor. Case No. U-11145, 179 PUR4th 333, Aug. 13, 1997 (Mich.P.S.C.).

NEW JERSEY. Stipulation says that, assuming normal weather, Public Service Electric & Gas Co. will acquire up to 50 percent of residential gas supply through fixed-price contracts or financial derivatives to hedge or lock in price, such as floors, swaps, caps, collars, puts and calls. Board acknowledges that customers could miss out on some price savings. Docket No. GR96070554, 179 PUR4th 326, July 30, 1997 (N.J.B.P.U.).

NEW MEXICO. PUC fines Public Service Co. of New Mexico for understating gas supply costs. Finds that near-total reliance on spot market purchases led to a price spike in retail gas rates. Case No. 2752, 175 PUR4th 393 (N.M.P.U.C.).

NEW YORK. Rule requires gas utilities to review procurement practices and submit plans for fixed-price service, but allows LDCs to limit fixed prices to 10 percent of customers and to exclude non-core and low-volume (cooking only) customers, who would not likely benefit. Case 97-G-0600, 180 PUR4th 553, Oct. 7, 1997 (N.Y.P.S.C.).

VIRGINIA. Pilot program allows Roanoke Gas Co. to use financial instruments to hedge against prices for up to 25 percent of normal wintertime gas demand, excluding demand supplied from storage withdrawals. Case No. PUE970420, July 24, 1997, 179 PUR4th 364 (Va.S.C.C.).

NYMEX to the Rescue?

New Contracts Could Hedge Against Gas

PROPOSED contracts:

•  Cinergy Control Area (NYMEX). 736 MWh, Peak hours (delivery 7A.M. to 11P.M., Eastern time).

•  Entergy Control Area (NYMEX). 736 MWh, peak hours (delivery 6 A.M. to 10 P.M., Central time).

•  PJM Interconnection (NYMEX). On hold, pending implementation in April 1998 of locational marginal pricing for transmission and development of experience in cash market.

•  Twin Cities (Minneapolis Grain Exchange). 736 MWh, peak hours (delivery 6 A.M. to 10 P.M., Central time); 368 MWh, off-peak hours (delivery 10 P.M., to 6 A.M., Central time).

1 John Herbert, James Thompson, and James Todaro, "Recent Trends in Natural Gas Spot Prices," Natural Gas Monthly, December 1997, p. vii (U.S.E.I.A.).

2 Natural Gas Weekly Market Update, Feb. 9, 1998 (U.S.E.I.A.).

3 Benjamin Schlesinger, "Natural Gas Industry Trends: Commoditizing Everything in Sight," posted by New York Mercantile Exchange, see www.nymex.com/ein/ein.html.

4 LDC System Operations and Supply Portfolio Management During the 1996-97 Winter Heating Season, A.G.A. Issue Brief 1997-06, June 10, 1997.

5 William Trapmann and James Todaro, "Natural Gas Residential Pricing Developments During the 1996-97 Winter," Natural Gas Monthly, Aug. 1997, p. l (U.S.E.I.A.).

6 Ibid.

7 Herbert, et al., see note 1.

8 63 Fed.Reg. 7406, Feb. 13, 1998.

9 63 Fed. Reg. 3543, Jan. 23, 1998.

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