The current disparity between spot gas prices and those on the Nymex strip would appear to make financial hedges a rather unappealing prospect for gas buyers, such as local distribution companies (LDCs). However, hedging isn’t an arbitrage play for LDCs, but rather a means to price risk management. While it might not spare a buck it’s really intended to avoid a surprise.

Despite greater volatility in gas markets, financial hedging has not been universally embraced among LDCs and their regulators. Expertise in evaluating hedging programs varies widely among state regulatory commissions, and LDCs vary widely in their attitudes toward hedging practices, dictated largely by their commission’s open mindedness (or lack thereof) toward gas cost recovery.

For instance, Connecticut’s Department of Public Utility Control (DPUC) had a rulemaking on financial hedging about a dozen years ago. The result proved so onerous to LDCs that it has stifled hedging activity in the state. As the Connecticut rule stands, 80% of savings derived from hedging is returned to ratepayers; however, the same ratepayers are only stuck with 20% of any losses. Joe Rosenthal, principal attorney with the Connecticut Office of Consumer Counsel, told NGI there has been little interest in advancing hedging in the state but perhaps there should be. Two years ago the DPUC looked at hedging again and found little interest among LDCs or consumer advocates, DPUC attorney Wayne Estey said. As things stand, price spikes are mitigated in the true-up of utilities’ purchased gas adjustments (PGAs).

The opposite is true in Oregon. Ken Zimmerman came to the Oregon Public Utility Commission (PUC) from Oklahoma about 18 months ago. The PUC’s senior analyst is now involved in an effort to revamp the way the commission guides the state’s utilities in their risk management practices and oversees their efforts. Oregon has had a gas cost sharing mechanism in place since about 1989, Zimmerman told NGI. “But in 1989 the gas market was a lot more stable and prices were less volatile.”

When Zimmerman came on the scene in Oregon, he found LDCs using financial hedges for a very high percentage of their gas volumes, 90-95%, he said. “That was omitting the other options that might be better for them,” he said, e.g., gas storage and conservation programs. “There’s really no history of in-depth prudence review at the Oregon commission. They [the LDCs] could make the case that this hedging of large volumes was a good idea… The regulatory incentive led to a perverse reality. Let’s focus on getting the right mix of things rather than just trying to hedge everything.”

And so that’s what Zimmerman and his commission colleagues are trying to do, hopefully wrapping it up by the middle of next year.

One place Zimmerman and others might want to look to for guidance on LDC hedging rules and practices is Kansas. With experience in the commodities markets, John Cita holds a doctorate in economics and is the chief economist for the Kansas Corporation Commission (KCC). “When they [LDCs] came in here they ran into a staff that knew a little bit about risk management,” he said.

The first Kansas gas utility to seek approval for a hedging program was Kansas Gas Services Co. (KGS) in about 1997, Cita told NGI. Atmos and Aquila followed shortly thereafter, then cooperative Midwest Energy requested and received approval for a hedging program. Virtually all of the jurisdictional gas utilities have received commission approval to hedge with financial instruments. And within the last year the KCC also has approved financial hedging of gas supply for power generation by electric utility Aquila. Empire District Electric Co. has applied to hedge its gas fuel, too. “That application is sitting on my desk,” Zimmerman said.

The unique thing about what’s going on in Kansas is how the KCC and its regulated gas utilities approached the question of whether to hedge gas supply with financial instruments: they asked customers.

In two rounds of focus groups, initially led by KGS, the utilities queried relatively small samples of customers and asked them what — if anything — they would be willing to pay to have the utility mitigate price volatility on their behalf. The majority of consumers queried were in favor of having the utilities manage at least some of the price risk, Cita told NGI. It was also found that consumers were willing to pay about a dollar per month for the price risk management. From that it was determined the utilities would be allowed to spend the equivalent of one dollar per month for each of their customers on price risk management through financial hedging.

Given increased volatility in gas markets, that one-dollar rule of thumb is now $1.75, but the principle is still the same. “What the KCC approves is the size of the budget, and prior to implementation, utilities come in and tell us about their preferred hedging program,” Cita said. “Through that discussion they tell us which financial derivatives they are interested in using.”

Swaps, calls, collars, any combination, all are on the table, Cita said. What the KCC wants to ensure is that the utilities are hedging and not speculating. The preference is for mechanistic programs with roughly equivalent transactions taking place on a regular schedule, i.e., no market timing. “However, the KCC has granted them discretion to vary from the preferred plan,” Cita said. “We do recognize that they’re the experts.”

The commission tracks the success/failure of the various hedging programs across the board. Overall, the programs are in the black across the board, largely thanks to a particularly good year for KGS. During a price trough KGS hedged virtually all of its supply for 2002-2003 at prices in the $2.00 range.

“We basically did it with swaps to fix the price,” Rick Tangeman, KGS director of FERC, regulatory and strategy, told NGI. Deals were done over about a month’s time so the utility wouldn’t be a market-maker. “It actually ended up being around $3 by the time we got all the swaps,” Tangeman said.

Despite its success in 2002-2003, KGS is more conservative these days. The utility tries to cover about 35% of its supply with financial hedges. Combining that with physical storage locks up about two-thirds of its winter supply, Tangeman explained.

His advice is to be mechanistic about hedging. “If you start putting them [hedges] on and taking them off, then you’re getting into more speculation than you are hedging.” And given where prices are today, even the best of hedging outcomes hardly seems worth a gamble.

“Right now, I don’t care what you do with a hedge,” Tangeman said. “The customers aren’t going to be happy anyway. There’s no amount of money that can buy calls at low enough prices that’s going to make them happy.”

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