CUB Opposes Putting All of Natural Gas Purchase Risk onto Customers

The natural gas market has seen some major changes in the past 20 years. From a rapidly awakening generalized concern regarding global warming and the carbon dioxide emissions of fossil fuels, to the more specific and radical price volatility that occurred in the wake of Hurricane Katrina, the price for natural gas has been subject to major changes unknown in previous decades. How utilities purchase natural gas and forecast those costs into customer rates is a matter of (occasionally heated) discussion in a current Public Utility Commission case, UM 1286, the Purchased Gas Adjustment case. The current system was implemented, oh, about 20 years ago, and there are those who say it should be updated for a changing market in a changing world. CUB filed Opening Comments in 1286 this week with our own proposed changes.

Natural gas utilities have traditionally procured their coming year’s supply of gas through one of three ways: outright purchase and storage; contracts for guaranteed future delivery (costing whatever the market charges at that future date); or hedged contracts, wherein a third party takes on the financial risk of a significant increase in the future cost of natural gas, but for a fee. These hedging fees can, for a large gas utility over a number of years, run into the millions of dollars. It is the position of the PUC staff that Oregon utilities have been relying on hedging too much.

In the current system, when costs exceed the amount that was forecast—and charged to customers in rates—customers pay between 67% and 80% (depending on the utility) of the variation in cost, beginning with the first dollar of variation. This sharing of cost between customers and the company (the shareholders , to be exact) is widely held to be an acceptable way to manage the risks of unforeseen changes in cost in the realm of utility regulation. How and when those costs are shared is the crux of the matter, and it is here that CUB parts company not only with the utilities themselves, but also with PUC staff. Staff suggests that customers should pay for 100% of extra costs, above what was forecast, but with increased regulatory oversight of the purchase process (to trim out some of that aforementioned hedging). We respectfully disagree that this is a good idea.

CUB thinks that natural gas utilities should “have some skin in the game.” We want gas utility managers to be worrying about the cost of natural gas; we pay them for their expertise, and we expect them to manage the supply and the cost of that supply more carefully if they know that they will bear a certain percentage of any increased costs. Furthermore, we don’t think the company should be able to hand the unforeseen costs over to customers starting with the first dollar.

So CUB came with a three-step process for sharing that is similar to what we’ve recommended for Oregon’s major electric utilities.

1) We start with a review of the utility company’s earnings to ascertain whether they are within a “reasonable zone” of their expected earnings. Assuming the utility is allowed a 10% Return on Equity (ROE, aka profit margin), and if they are within 1% of that ROE (9-11% ROE), then no cost variations should be passed along to customers.

2) Make sure that a deadband exists around the cost variation, so that the utility is expected to absorb a certain amount of normal changes in cost. This gets rid of the practice of charging customers for the first dollar of unforeseen costs. After all, managing the normal variation of commodity costs is not only an accepted risk of doing business, but is also why we pay the utility an ROE to begin with. The size of the deadband increases with the size of the utility, and is asymmetrical so that the company must absorb twice as much change in additional cost before charging customers as is necessary in decreased costs for a refund to go to customers (after all, it is more likely that costs would go up than down).

3) Finally, where there is extraordinary variation in cost, outside the deadband set for normal variation, customers would share the cost variation at 90%, with the company expected to absorb the other 10%. If costs are down, perhaps due to a warm winter and low demand, then customers would receive 90% of the variation in the form of a refund. Sharing ends when the company has been brought back within its reasonable earnings zone.

CUB feels that this is a good distribution of the risk of volatile gas markets: the company carries the burden of normalized risk, while the broad shoulders of a wide customer base are on hand to share the burden of a truly extraordinary change in gas prices. We certainly hope to see the Commission agree that taking all of the risk away from the utility and placing it on customers is inappropriate; the utility, which has control of gas purchasing, should share the risk of price volatility. ‘Cuz that part of the equation isn’t going away.

GAS FACTS
In developing our analysis, we studied Oregon’s natural gas prices in comparison to the national average and prices in other Western states. Oregon’s commodity gas prices were lower than the national average price for natural gas, and with the exception of an atypical year in 2002, lower than most other Western states’ prices.

Natural gas is going up in price, partially because the demand for it is rising. Some reasons for increasing demand include: it is cleaner-burning than most other heating options (i.e., oil heat, wood heat, coal-generated electricity); is more efficient to burn directly to heat water for your tea or heat a house than to generate electricity and run it through the grid to your house to do the same; and is increasingly being used to generate electricity, which increases demand on a somewhat limited supply.

All fossil fuels, including natural gas, release carbon dioxide when burned; we appreciate the opportunity provided by NW Natural’s Smart Energy program to contribute toward carbon offsets on their customers’ gas bills.

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