Natural gas from the Deep Panuke field off the coast of Nova Scotia could have gained a strong foothold in New England during the past few years—if the gas had started flowing in 2010, as had been the plan. New England, with its shift to gas-fired power generation and its wintertime heating needs, surely has needed the gas; it still does. Today, with the first Deep Panuke gas finally expected to come ashore in the next few weeks, we ask, can the new gas from Nova Scotia push its way into New England, or will the coming influx of Marcellus gas into the six-state region push Deep Panuke gas back across the border?
In this Part 1 of our two-part series, we examine how the Deep Panuke discovery once was viewed as the next big thing for New England gas supply, and as a follow-up to the Sable Island Offshore Project (SIOP)—also off Nova Scotia—which was the first to utilize the Maritimes & Northeast pipeline into New England. We also look at why it has taken so long to get Deep Panuke gas flowing, and how gas-market dynamics in New England have changed during that years-long delay. In Part 2, we will consider what might happen as the new southward flow of Deep Panuke gas collides with the opposing flows of Marcellus gas—through beefed-up Algonquin Gas Transmission (AGT) and Tennessee Gas Pipeline (TGP) networks—to New England.
The development of the Deep Panuke gas field has been in the works for a long time—many years before it became apparent that new techniques for economically extracting shale gas from the Marcellus, Utica and other plays would transform the North American gas supply situation, particularly in the northeastern U.S. (see The Marcellus Changes Everything). Shell was the first to explore the Deep Panuke region, starting in the late 1980s. PanCanadian followed in the 1990s, and in 1998 its PP-P3 discovery well made it clear Deep Panuke was worth developing. PanCanadian merged with Alberta Energy to form EnCana in 2002, and that same year EnCana got the regulatory go-ahead for a $1 billion project that would deliver up to 400 MMcf/d from Deep Panuke reserves estimated at about 900 Bcf. In 2003, however, EnCana asked for and received a regulatory time-out, and for the next three years it reevaluated—and ultimately scaled down—the project. The new $700 million plan, which received regulatory approval in 2007, called for delivering up to 300 MMcf/d, probably for a period of about 13 years. The first gas, as we said, was supposed to start flowing more than three years ago, but one setback after another pushed that start date back again and again, most recently to sometime this quarter. (The delay also has pushed up the project’s price tag, to $1 billion.) As EnCana put it in a July 24, 2013 statement, the project is now “in the final steps to achieving first gas. Final commissioning is taking place offshore. Gas will be introduced from the wells to the platform following final commissioning.
Deep Panuke is a gas-supply follow-up to SIOP, whose production started in 1999, peaked only nine years later, and is now in decline. But the two are step-sisters, chemically speaking. SIOP gas, whose production started in 1999 but has ramped down dramatically in recent years, is sweet and wet--rich with natural gas liquids--and is processed onshore at Goldboro, Nova Scotia. Deep Panuke gas, meanwhile, is sour and dry, and will be processed on the platform; when the gas makes landfall it will be good-to-go for marketing. Repsol--the Spanish oil and gas company, eager to expand into the northeastern U.S.--in 2009 contracted to buy all of EnCana’s Deep Panuke gas: up to 300 MMbcf/d for the life of the project. Repsol also owns 75% of Canaport, the LNG import terminal in Saint John, New Brunswick, which has the capacity to produce up to 1.2 Bcf/d from LNG but which has been operating at much lower levels because gas prices in North America are much lower than in Asia and Europe, discouraging imports. (Irving Oil owns the other 25% of Canaport.) SIOP gas and gas converted from LNG at Canaport flows through the Canadian portion of the Maritimes & Northeast Pipeline to help to meet the needs of gas consumers in Nova Scotia and New Brunswick. Some gas also flows south in the 800 MMcf/d U.S. portion of Maritimes & Northeast, which runs from the Canadian border at Calais, Maine, to Wells, Maine, where the pipeline merges with the Portland Natural Gas Transmission System (PNGTS) pipeline to form a joint, 100-mile, 600 MMcf/d pipeline through southern New Hampshire to Dracut, in northeastern Massachusetts (see Figure 1). (An aside of sorts: In 2003, the PNGTS pipeline, which runs from northern New Hampshire to Wells and was originally intended to bring gas south from Quebec, was reworked to provide bidirectional service—the idea being to enable SIOP gas to make its way to Quebec as well as to Boston, the largest city in New England.)