Maine ratepayers won’t necessarily benefit by paying up to $75 million per year to buy capacity in yet-to-be-built pipelines as a way to spur their construction.
That’s the conclusion of the staff of the Maine Public Utilities Commission, which just finished a review of Maine’s energy cost-cutting options under a 2013 law that allows the PUC to commit up to $75 million annually in ratepayer money to buy pipeline capacity in order to spark new pipeline construction serving the New England region. There are no compelling reasons to risk ratepayer dollars to secure pipeline capacity when other projects in New England are underway that make buying pipeline capacity a less critical option, the PUC staff concluded in a June 8 report.
The commission staff concluded that long-term, natural gas pipeline capacity commitments aren’t necessary “to address high winter price levels and volatility” — the thinking behind the 2013 state law that gave the PUC the ability to use ratepayer money to buy pipeline capacity. That’s because a shortage of gas pipelines in New England isn’t the only factor driving recent electricity price fluctuations. Low oil prices, increases in liquefied natural gas supplies and warm winter weather conditions have led prices to drop since 2013, when high prices spurred lawmakers to give the PUC additional authority.
In addition, the staff wrote, there is excess capacity available at most times. Buying capacity year-round just to protect against winter price spikes is not in the ratepayers’ interest.
The challenge for the three commissioners of the PUC, who will decide whether to endorse the staff recommendations in coming weeks, is to find a way to encourage pipeline capacity in New England and Maine without exposing the state’s residents to unnecessary risk.
This proposal to buy pipeline capacity is reminiscent of PURPA contracts that grew out of the energy crisis of the 1970s. Congress, trying to encourage the development of domestic alternative energy sources, passed the Public Utility Regulatory Policy Act, which led to long-term contracts designed to spark the development of biomass, waste-to-energy and, especially, natural gas cogeneration as a hedge against price uncertainty. But utilities and generators signed these contracts when electricity prices were high. Since then, electricity prices have generally dropped, leaving consumers paying hundreds of millions of dollars in above-market rates.
History risks repeating itself with pipeline capacity purchases.
The concerns raised by the PUC staff are valid, but there is still a need to increase the supply of natural gas in New England and especially in Maine. By increasing the flow of natural gas from places such as New York and Pennsylvania to exceed demand, electricity prices could decrease further, as natural gas is the preferred fuel for generating electricity in the Northeast.
To expand pipeline capacity, however, developers need financing. To secure financing, they need long-term commitments. The utilities that burn the gas to create electricity have been unwilling to make these commitments, which is reason for caution but not inaction.
The challenge for Maine utility regulators is to find a way for the state, which consumes just 9 percent of New England’s electricity, to contribute to — and spur others to contribute to — a meaningful expansion of natural gas infrastructure to serve electricity generators. Maine and other states have substantially increased natural gas infrastructure, but it’s to serve homeowners, who increasingly are heating with natural gas. This competition for gas contributes to winter price spikes.
Maine does not have a strong record of predicting energy futures, and no other Northeastern state has committed itself to a similar arrangement, though Massachusetts and Connecticut are looking into it.
The Legislature gave the PUC the authority to solve a vexing problem — Maine’s increasing reliance on natural gas for electricity generation without access to a growing supply of natural gas. To solve the problem, the PUC must balance the benefits and risks of any solution. In this case, a regional plan must be part of the solution.
