Energy price volatility is the bane of gas and electric utilities.
Price spikes will trigger howls of outrage from customers, often with the attendant political fallout. If there is one thing that customers and regulators do not like, it is nasty surprises on the gas or electric bill.
To keep those surprises to a minimum, utilities have available a wide range of hedging instruments and strategies – either on established commodity exchanges or through over-the-counter markets – to assist with their management of physical supply.
“Most of our companies do some sort of hedging of fuel, in particular gas. In some cases, they’ll hedge purchases of wholesale power or, if they have generation, sales of electricity,” said Richard McMahon, Vice President for Finance and Energy Supply at Edison Electric Institute, which represents investor-owned utilities. Gas utilities also employ hedging strategies to smooth out their exposure to changing prices.
Hedging is a means of price protection. A utility that needs to buy natural gas or coal, for example, can essentially “lock in” a price using a financial instrument such as a commodity futures contract. When the time comes to take delivery of the fuel, the utility liquidates the futures contract and buys the gas or coal from its usual suppliers. Any gain, or loss, on the financial side resulting from the closing of the futures position is offset by the difference in the price for the physical fuel. The point of the exercise is to avoid potential price volatility in favor of price stability. Sometimes this means that the fuel might be purchased at a price higher than the prevailing market – or on the sell side, electricity might be sold for less than the going price. Hedging is intended to reduce price risk, not necessarily make money on the transaction.
“Regulators should expect utilities to realize small losses from hedging in most years because hedging is, after all, an insurance policy against severe price spikes, and insurance is not costless,” said Ken Costello, Natural Gas Principal with the National Regulatory Research Institute, an arm of the National Association of Regulatory Utility Commissioners. “Almost all regulatory commissions allow gas utilities to hedge with financial instruments. A much smaller number require them to do so,” he said.
Since the early 2000s, state regulatory commissions have told gas utilities that buying at the market or spot prices may no longer be acceptable – that is, it may be imprudent. It is also the nature of hedging that a utility and its customers could pay above-market prices if the market for the physical commodity falls below the price that is hedged, he said.
The Need for Utilities to Hedge
Natural gas and electricity futures contracts were introduced in the early and mid-1990s. Today, there are approximately 250 electricity and 300 natural gas futures, options and cleared swaps contracts available to market participants from both the New York Mercantile Exchange and the Intercontinental Exchange. These cover various delivery points, quantities and time spans.
Regulators began taking a serious look at utility hedging after a series of particularly severe natural gas price spikes. Prices went to a then-record of $10 per million British thermal units (MMBtu) in late 2000 and again in 2003, then ran up to an all-time high of $15/MMBtu in 2005 after Hurricane Katrina, and spiked again at more than $13 in 2008.
Colorado Public Utilities Commissioner Matt Baker said the agency looks at risk aversion starting with the planning process. “We’re trying to get utilities to create enough fuel diversity between coal, gas, wind, and energy efficiency and demand response, so that consumers have protection if one commodity gets out of line. On the gas side, we’ve encouraged our utilities to enter into long-term, fixed-price physical contracts.”
He noted that one utility recently signed a 10-year contract pegged at $5.15/MMBtu. “We looked at how much we were spending on hedges and what the value of that was. What we’re trying to do is purchase some stability. There’s probably a little bit of a premium on it, but over the 10-year life span, we think this will be in the best interest of the ratepayers, even though gas is $2.50 now.”
The local distribution gas utilities are also encouraged to use financial instruments to hedge their supplies, he said.
Baker said the commission encourages gas and electric providers to look at all available tools. “We need to make sure that we have stable prices.”
Unbundled Markets
In Texas, the power markets were unbundled – that is, the generation and distribution functions were separated into distinct businesses – about 10 years ago. This has resulted in very robust wholesale and retail markets with about 50 or 60 retail electric providers, said Texas Public Utilities Commissioner Ken Anderson.
“The design of the market is such that it strongly encourages generators and load-serving entities to hedge their risk,” Anderson said. “If a market participant goes unhedged in some way, they’re taking a big, big risk.”
More than 90 percent of the power in the Electric Reliability Council of Texas (ERCOT) is sold in one-on-one cash market transactions between a generator and a retail provider, supported by over-the-counter contracts for hedging purposes. For example, Anderson said, a generator will enter into a one-year contract to sell power to a retailer. That contract sets the price. The retail provider then will enter into a contract as a hedge against volatile pricing in the real-time or day-ahead market, since many retail customers will sign up for fixed-rate contracts, he said.
“The only way that the retail provider can offer that fixed price is to enter into a contract with a generator,” Anderson said. “If the retailer runs the risk of just buying in the real-time market, the company can get upside down real quick.”
He pointed out that late in the winter of 2011-2012, electricity prices ranged from around $19 to $29/megawatt hour. “Over the summer, there were prolonged hours where prices were $3,000/MWh. It doesn’t take very many hours at $3,000 to put a retail provider out of business,” Anderson said.
