Several of the industry’s top-performing companies have been guided by CFOs with an expansive sense of what the finance office should offer to the business. Increasingly CFOs are developing the...
Natural Gas Hedging: A Primer for Utilities and Regulators
What LDCs should already know.
not enough disparate points to totally upset the underlying relationship.
During periods when markets are under stress and expected price relationships between markets break down, a utility might be expected to practice some discretionary behavior in the management of its risk management transactions. It is observed in the figure that there were two instances when the change in the Henry Hub price was greater than $4.00, and that this change was much greater than the change in the Chicago price on the same day. This is important information. It suggests that the utility might have been able to close out its position on the futures market by, in effect, selling the natural gas at a much higher price than the natural gas purchase price in the local wholesale Chicago market.
Thus, the company might consider closing out its derivative position on a day different from the day initially set in the risk management plan. For example, the risk management program may have specified that both contracts were to be completed during bid week. A deviation from a plan may be acceptable as long as an arbitrage or risk free return is realized and documented.
Such arbitrage opportunities are likely to be discovered if the utility is continually monitoring the cash and futures market. They are an expected benefit from an active price risk management program. 10
Storage: A Good Hedge?
Although natural gas storage offers an effective way to hedge volume risk and fix price, much utility storage has significant costs and risks associated with it. There are also usually huge opportunity costs associated with conventional storage owned or leased by utilities.
Many utilities husband their stored gas in November through mid-January even when the cash price on the wholesale market is significantly greater than the average cost of the gas they have in storage. They could experience a return by withdrawing relatively more natural gas from storage and purchasing relatively less gas on the cash market. They often don't do this because they sometimes need a large amount of natural gas in storage to maintain deliverability.
At the same time, they often withdraw large amounts of gas from storage from mid January until early April in order to reach targeted levels for storage in early April. They do this to satisfy contractual requirements even when the cost of gas on the cash market is much less than the average cost of natural gas in storage. In fact, this behavior contributes to a reduction in the price on the cash wholesale market and, in effect, a reduction in the value of the remaining natural gas in storage.
Almost every year one sees examples where a utility uses gas from storage when it could just as well have purchased gas on the wholesale market at a reduced overall cost without any change in risk exposure. The initial commodity cost of the natural gas plus the cost of storage and withdrawal can often be 30 percent more than purchasing the gas on a nearby wholesale cash market.
In short, since much of the gas