Analysts to FERC: US gas market in good shape

Nov. 1, 2010
The US natural gas market is in good shape, with production at levels not seen in more than 35 years, moderate prices, and storage about 90% full with about 3 weeks left in the usual injection period, US Federal Energy Regulatory Commission staff analysts told the commission on Oct. 21.

Nick Snow
Washington Editor

The US natural gas market is in good shape, with production at levels not seen in more than 35 years, moderate prices, and storage about 90% full with about 3 weeks left in the usual injection period, US Federal Energy Regulatory Commission staff analysts told the commission on Oct. 21.

"The abundance of domestic gas has resulted in moderate prices," said Christopher Ellsworth, chief of the fuels market analysis branch in FERC's enforcement office. "These prices, low compared to other fuels, contributed to record demand by power generators this summer."

New supplies and infrastructure suggest that the industry is better prepared than ever to meet winter gas needs, Ellsworth said, adding, "Forecasts for a mild winter compared to last year, coupled with abundant supplies, should help keep prices moderate." Two transparency orders—Nos. 704 and 720—are beginning to provide more market information, he said.

Record-high demand for power generation this past summer in response to hotter weather and higher industrial demand as the general economy improves have increased prices year-to-year, he told the commission. Prices nevertheless are lower than in recent years and are well below the 2005 price spike resulting from Hurricanes Katrina and Rita and the 2008 increase which occurred just before the financial crisis, Ellsworth said.

"Low gas prices are largely the result of the influx of new, low-cost shale gas, which has revolutionized the natural gas industry," he report indicated.

Production up 23%

US gas production has increased 23% in the last 5 years to more than 58 bcfd from 48 bcfd in 2005, Ellsworth said. Most of that growth comes from shale gas, which now accounts for 20% of US gas production, he noted.

"Shale gas development has turned the economics for drilling for gas on its head," he said. "The cost of developing shale gas has declined and well productivity has increased as drillers gain experience with the new technology. In some instances, the time needed to drill a shale gas well has plunged from weeks to just days. This has driven down break-even costs for most gas shales to less than $4/MMbtu and even lower when natural gas liquids such as propane, ethane, and butane are present."

Ellsworth said that the presence of NGLs increases well profitability considerably although new infrastructure in some instance will be needed to get these products to markets. "There is a possibility that the need to find a ready market for [NGLs] could slow down shale gas development in some areas," he said. "Possible regulations in response to concerns about the impact of [hydraulic fracturing] fluids on the environment could affect future drilling plans. However, if current trends in technology continue, the cost of developing shale gas is likely to continue to fall, which should moderate long-term gas prices."

The US is relying less on other source as shale gas production increases, he told the commission. Gulf of Mexico gas production has declined to 7 bcfd from more than 11 bcfd in 2006, which has reduced market apprehension over potential offshore production disruptions from hurricanes and little impact on total gulf production from the deepwater drilling moratorium, Ellsworth said.

He said a geographical shift in gas production is changing how the nation's pipelines are used, particularly in the Northeast, where Canadian gas imports have dropped by 50% since October 2009 to less than 1 bcfd. "Western Canadian gas is being replaced by cheaper sources, including 1.7 bcfd via the new Rockies Express Pipeline and Northeast production [is being] led by growth in the Marcellus shale" where production has doubled in the last 12 months to around 700 MMcfd, he said. "Together, Marcellus production and Rockies supplies are beginning to compete against traditional Gulf Coast supplies," he observed.

Western trends

While less Canadian gas has flowed to the US Northeast, it maintained its market share in the West and helped, along with mild weather, to keep gas prices moderate in California and the Pacific Northeast this past summer, according to Ellsworth. "And next spring, the 1.5 bcfd Ruby Pipeline is targeted to become operational, offering more Rockies production to Northern California and the Pacific Northwest as an alternative to Canadian gas," he said.

LNG imports, meanwhile, through eight US, one Canadian, and one Mexican terminal have dropped to less than 1 bcfd after peaking at a record 5 bcfd in January, he said. Ellsworth cited two reasons for the decline: Shale gas production growth has helped reduce US prices to well below international prices (with prices at the UK's National Balancing Point averaging $1.30/MMbtu higher than at the Henry Hub, while some Asian prices have been almost $8/MMbtu higher). And while global liquefaction capacity increased 30% last year, global demand is up too (by 21% in Asia and 41% in Europe).

"Today, two US terminals—Everett in Boston and Elba Island in Georgia—are responsible for most of the LNG imports," the FERC analyst said. "Both terminals' supplies are supported by long-term contracts. The Canadian terminal—Canaport, near St. John, NB—has steadily sent regasified LNG to New England and will become more important as production from Sable Island in Nova Scotia begins an expected rapid decline in the next year."

He said LNG can still play a significant role in the Northeast, where prices can be significantly higher than on the Gulf Coast and therefore more attractive to international suppliers. "New England has access to more than 3.2 bcfd of LNG terminal capacity, including two new offshore terminals in Massachusetts Bay and the Canadian Canaport terminal," he pointed out. LNG supplied 56% of peak New England gas demand this past January and could do so again this winter, Ellsworth said.

At the same time, storage is again robust, he continued. "While overall injections were slow during the summer—due to record gas consumption for power generation—injections began to pick up in September, and stocks for winter should end up close to last year's record 3.8 tcf," he said. The US Energy Information also has reported that the nation's peak working storage capacity grew by 130 tcf between April 2009 and April 2010, Ellsworth said. Inventories of other fuels also are high as winter approaches, with distillate fuel oil stocks at a record 172 million bbl at the beginning of October and heating oil demand expected to be lower due to the economic recession, he said.

New pipelines

Ellsworth also noted that much new pipeline capacity has been added in the Northeast, with 500 MMcfd completed since spring on top of the 5.6 bcfd added in 2008 and 2009. "New pipelines and capacity completed by January should add an additional 725 MMcfd, making a grand total of 1.2 bcfd added in the Northeast since last winter," he said. "Much of the new pipeline capacity is targeted at improving the access of shale gas to markets."

Another 325 MMcfd of new pipeline capacity has been added in the West since spring, along with 2.5 bcfd along the Gulf Coast and in the Southeast, he indicated. "We expect another 3.5 bcfd in the West and 5.3 bcfd in the gulf and the Southeast to be added before the end of winter," Ellsworth said.

He added that a much anticipated western pipeline is TransCanada's 477 MMcfd Bison system, which will transport gas from the Rockies to the Midwest through an interconnection with the Northern Border Pipeline. Bison should begin service in mid-November, he said.

Prices for gas in the Northeast have narrowed relative to the Henry Hub, he continued. Prices in New York on Oct. 1 were $2.03/MMbtu higher than those at the Henry Hub for January 2011, substantially less than comparable price differences of $4.03 in 2010 and $5.51 in 2009. "The decline in these projected October-to-January differentials reflects market expectations about the change in winter price volatility due to added pipeline, LNG, and storage capacity in the region, as well as new supplies coming from the Marcellus shale formation and the Rocky Mountains via the Rockies Express pipeline expansion," Ellsworth said. "It also reflects lower gas prices in general."

Development of new gas supplies and transmission capacity also has pushed basis prices lower nationwide, he continued. Compared with the same period last year, winter basis swaps have declined by 46% in Chicago, 55% in the Pacific Northwest, and 32% in Appalachia, he said.

More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on