Should Maine be in the natural gas business?

Matthew Stone, Andrew Catalina | BDN
Natural gas has accounted for a growing portion of the electricity generated in New England since 2000, essentially replacing oil and coal. Power plants that can run on oil or gas have increasingly turned to less expensive natural gas in recent years.
Posted May 31, 2013, at 1:35 p.m.
Irving Oil delivered its first truckload of compressed natural gas, or CNG, to the McCain Foods plant in Easton, Maine, on May 10. Truck-delivered CNG is “at the leading-edge of natural gas technology,” said Paul Browning, Irving Oil’s president and CEO.
Irving Oil delivered its first truckload of compressed natural gas, or CNG, to the McCain Foods plant in Easton, Maine, on May 10. Truck-delivered CNG is “at the leading-edge of natural gas technology,” said Paul Browning, Irving Oil’s president and CEO.

Maine’s electric ratepayers could be called on to partially finance the construction of natural gas pipeline in southern New England under a bill that received broad support last week in the Legislature’s Energy Committee.

The bill is a multipronged effort to lower electricity prices in Maine which combines elements from at least nine separate proposals. Other parts of the legislation would boost funding for energy efficiency, directly lower businesses’ electricity costs and make it more affordable for residents to abandon oil heat.

But how the bill proposes to expand limited natural gas pipeline infrastructure in Maine and New England — by allowing the state to purchase pipeline capacity, a commodity most often purchased by gas traders and distribution companies — has garnered the most attention.

Proponents of the legislation — including lawmakers from both parties, the head of the Maine Public Utilities Commission and the lobbying group for many of the state’s paper mills — say a “market failure” has kept private investors from financing the development of gas pipelines in New England. As a result, the region’s ability to bring in gas from emerging gas resources such as the Marcellus and Utica shales in Pennsylvania and New York is limited, particularly on days when electricity demand is high.

Opponents — who include some environmental groups, the state’s power companies and local natural gas distributors — acknowledge Maine faces a natural gas infrastructure problem. But they say it’s unwise to put Maine ratepayers on the line for an investment that might not pan out if natural gas prices don’t remain low or if Maine is able to access natural gas supplies from other regions, such as New Brunswick, in the future.

While the legislation is designed to compensate for a market slow to invest in the region’s pipeline infrastructure, there are still privately financed developments in the works to expand the region’s pipe capacity. And the operator of the region’s electrical grid, ISO New England, is considering changes to how it pays for electricity which could make it more appealing for the region’s gas-fired power plants to invest in new pipeline.

Natural gas and New England

For much of the past year, New England has paid the highest daily price for natural gas in the country, a reflection of high demand in the region and limited infrastructure for transporting gas.

According to the U.S. Energy Information Administration, gas prices at New England’s main trading hub, Algonquin Citygate near Boston, were nearly 87 percent higher on average in November and December 2012 than they were at the nation’s primary trading spot, Henry Hub in Louisiana.

That daily price is generally paid by those without long-term contracts for gas, such as gas-fired power plants. The price swings according to demand and weather conditions, sending it up during high-demand days in the summer and winter.

“A well-known issue in New England is that there is not enough gas getting in during peak times,” said Amy Sweeney, a statistician with the Energy Information Administration. “New England can end up with really high natural gas prices, so that will affect anyone who uses natural gas, whether it’s a residential structure or a power plant.”

While natural gas is more expensive in New England than elsewhere, it’s still among the cheapest energy sources available. Since 2000, natural gas has essentially replaced oil and coal as the primary component in the region’s electricity mix.

In 2012, natural gas accounted for 52 percent of electricity generated in New England, up from 15 percent in 2000, according to ISO New England. During the same period, oil dropped to 1 percent from 22 percent, and coal dropped to 3 percent from 18 percent.

ISO New England turns to more expensive oil and coal during peak-demand periods when natural gas is scarce and more expensive, said Marcia Blomberg, an ISO New England spokeswoman.

Abundant supply, limited transportation

New England’s difficulty in securing low-cost natural gas has been exacerbated recently as gas production has declined off the coast of Nova Scotia and the region has received fewer liquefied natural gas shipments as gas dealers fetch higher prices in Europe.

At the same time, limited infrastructure makes it difficult for New England to take full advantage of growing natural gas resources in nearby New York and Pennsylvania.

New England has five pipelines that bring natural gas into the region, according to the Maine Public Utilities Commission, and natural gas sources in the Upper Midwest are far away.

In addition, the structure of the region’s electricity market has created a limited pool of investors willing to sign long-term contracts for pipeline capacity, according to a 2012 report by Jason Rauch, an analyst at the Maine Public Utilities Commission.

A pipeline developer needs to sign long-term contracts with investors who want to buy pipeline capacity before it can secure federal approval to build a pipeline. In New England, it’s most often local natural gas utilities and gas traders that sign long-term contracts for pipeline capacity.

For gas utilities, it assures a steady supply of gas for home heating. Traders can purchase pipeline capacity at a price regulated by the federal government, then turn around and sell gas or sell their rights to pipeline capacity to gas distributors and make a hefty profit, according to Matthew Oliver, who researched natural gas pricing and pipeline congestion for his doctoral dissertation at the University of Wyoming.

“If the available capacity coming into Maine is very scarce, and its market value is very high, then the price that I can get for use of that capacity is very high,” he said.

That means gas traders who already own pipeline capacity have little incentive to invest in more pipeline capacity that could lower natural gas spot prices, Oliver said. The region’s power generators similarly have little incentive to invest in more pipeline, according to Rauch. They generally buy natural gas in real time to respond to demand for electricity; they’re largely paid by ISO New England to respond to real-time demand.

Maine as pipeline investor

The bill pending before the Legislature would allow Maine to buy pipeline capacity, with the hope that state government’s buying power could spur new pipeline construction. It’s a rare, though not unprecedented, move in the nation’s privately owned pipeline network. Alaska has invested in natural gas pipelines, and its legislature recently approved spending $400 million more to spur pipeline construction in the Anchorage area.

Under Maine’s legislation, if the state purchases capacity in a pipeline that’s ultimately built, the state could enter into energy cost-reduction contracts with natural gas generators by selling capacity in exchange for rates that reduce electricity costs.

The bill would put a limit on the amount of pipeline capacity the state could buy.

The Maine Public Utilities Commission would be responsible for approving a cost reduction contract, though it would be required to hire a consultant to negotiate the contract and work with the state’s public advocate and the governor’s energy office. The governor would have ultimate authority over whether Maine enters into such a contract.

The state’s authority to negotiate a contract would lapse in 2018.

Pipeline construction underway

While the market for pipeline capacity in New England is limited, privately funded expansion plans for some of the region’s primary pipelines are in the works.

Spectra Energy expects to complete an expansion of its Algonquin Gas Transmission pipeline by 2016 that will add 500 million cubic feet of transmission capacity per day; the pipeline’s capacity is currently 2.44 billion cubic feet per day. The Algonquin Incremental Market project will largely expand the capacity of the existing Algonquin pipeline, which runs more than 1,100 miles between New Jersey and Massachusetts.

Under the energy bill pending before the Maine Legislature, Maine would be limited to buying 200 million cubic feet per day of capacity.

Spectra has secured long-term contracts for pipeline capacity from the private market and is filing for approval from the Federal Energy Regulatory Commission, said company spokeswoman Marylee Hanley.

Another New England pipeline, the Portland Natural Gas Transmission System, is also planning a pipeline expansion and is seeking capacity investors. So is the Tennessee Gas Pipeline, another of the region’s transmission routes, according to the Northeast Gas Association.

ISO New England is also looking to change the way it pays for electricity so it can provide incentives to gas-fired power generators to buy pipeline capacity and spur more pipeline construction. The organization is considering a model under which it rewards power generators for supplying power during high-demand periods.

“We’re thinking these incentives within the market could help spur that kind of investment to assure they can get gas when they need it,” said Blomberg, the ISO New England spokeswoman.

While additional pipeline would help transport more gas to Maine, added pipeline is no guarantee of lower natural gas prices, especially as demand continues to grow, said Oliver.

“Whatever new capacity gets built needs to be sufficiently above existing demand to where it’s not still congested after you build the pipeline,” he said. “If it’s still congested even after you build the pipeline, [the price differential is] still not going to go away.”

Matthew Stone is a reporter in the BDN’s State House bureau.

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