Last week, the Federal Energy Regulatory Commission (FERC) approved three projects to increase natural gas takeaway capacity from the Marcellus Shale formation. On February 11, FERC approved the TEAM 2014 project expansions on Spectra's Texas Eastern Transmission Co. (Tetco) pipeline. TEAM stands for Texas Eastern Appalachia to Market. The next day, FERC issued an environmental impact statement (EIS) on a new pipeline and related compressor station project—Williams's Constitution Pipeline and the Iroquois Pipeline's Wright Interconnect Project (WIP). The EIS recommended conditional approval for the two projects, pending the adoption of measures to mitigate their environmental impact. WIP has a projected in-service date of March 2015, while the Constitution Pipeline projects the beginning of service in late 2015 or 2016.

The TEAM 2014 project would provide Tetco with capacity to move an additional 0.59 billion cubic feet per day (Bcf/d) out of the Marcellus from interconnects in southwestern Pennsylvania and West Virginia. Expansions would allow for bidirectional flows on portions of Tetco that currently only flow gas from the Gulf and Rockies Express Pipeline into the Northeast. Two shippers—Chevron and EQT Energy—have contracted for the full amount of the capacity expansions. Rockies Express deliveries into the Northeast have declined over the past two years, and in November, FERC upheld a petition from Rockies Express Pipeline LLC allowing for the establishment of firm agreements to reverse direction and move gas east-to-west on the pipeline.

Chevron booked 0.29 Bcf/d of capacity to move gas on the expanded Tetco pipeline from Uniontown, Pennsylvania, to Lambertville, New Jersey, where Tetco connects with Spectra's Algonquin Gas Transmission (AGT) pipeline. EQT Energy booked the remaining 0.29 Bcf/d of firm capacity to move 0.24 Bcf/d of Marcellus gas south to Tetco's AA market zone in the Gulf of Mexico region, and 0.05 Bcf/d west to Lebanon, Ohio, where Tetco connects with the Rockies Express system. Outflows from the Northeast to other parts of the country as a result of these expansions would further decrease net flows of natural gas into the northeastern United States. These decreased flows have largely resulted from increasing Marcellus production, which enabled the Northeast to satisfy a greater portion of its own demand, and increasingly, send gas to other regions. TEAM 2014 would also help alleviate capacity constraints in transporting natural gas to northeastern markets, which contribute to high natural gas and power prices during periods of peak demand.

FERC also issued an EIS that recommended the construction, with modifications to the original plan, of the Constitution Pipeline. This pipeline would deliver up to 0.64 Bcf/d of Marcellus gas from Susquehanna County, in northeastern Pennsylvania, to Wright, New York, where the Wright Compressor Station is currently located. Iroquois would build a new compressor station at an adjacent facility under WIP, and modify the existing compressor station. Cabot Oil & Gas has a binding agreement for 0.49 Bcf/d of firm capacity on the Constitution Pipeline, while Southwestern Energy has an agreement for the remaining 0.15 Bcf/d.

The Iroquois Pipeline currently transports gas south to the Wright Compressor Station from its interconnect with TransCanada's Canadian Mainline in Waddington, New York. At Wright, Iroquois interconnects with Kinder Morgan's Tennessee Gas Pipeline (TGP) northern 200 line, which can flow gas to New England customers via its interconnect with AGT south of Boston, but has delivered increasing amounts of natural gas to the Canadian Mainline via its Niagara Falls interconnect with TransCanada.

The Constitution Pipeline's ability to move Marcellus production to northeastern consumers would significantly benefit from construction of TGP's planned Northeast Expansion Project. This project would take gas from Wright to Dracut, Massachusetts, where it would connect with TGP's existing pipeline as well as a line jointly operated by Spectra's Maritimes & Northeast Pipeline and the Portland Natural Gas Transmission System. Open season for firm capacity agreements on the Northeast Expansion Project began on February 13, and will continue until March 28. Project capacity could range from 0.60 Bcf/d to 2.20 Bcf/d, according to TGP documents.

More summary data


Henry Hub price decline continues. The Henry Hub spot price decreased during most of the report week, before slightly rebounding to close at $5.97/MMBtu on Wednesday, February 19, 18 cents/MMBtu below its closing price on Wednesday, February 12. This marks the second week in a row that the Henry Hub spot price decreased, after reaching its highest level since 2008 on Wednesday, February 5, during a spate of bitterly cold weather throughout the country. Despite the overall decline, the Henry Hub spot price is $2.68/MMBtu above its closing price at this time last year.

Price changes vary nationwide. Prices in the northeastern United States rose significantly on Friday, February 14, as a severe winter storm hit the East Coast. However, prices declined for the remainder of the report week, and were down for the week as a whole. The natural gas spot price at the Algonquin Citygate hub serving Boston area consumers rose from $15.64/MMBtu on Wednesday, February 12, to $23.04/MMBtu on Friday, February 14, but closed yesterday at $13.83/MMBtu as temperatures warmed in the aftermath of the winter storm. Similarly, the spot price at the Transcontinental Pipeline's Zone 6 trading point for delivery into New York City rose from $7.80/MMBtu on February 12 to $8.97/MMBtu on February 14, but then declined to $6.10/MMBtu yesterday.

By contrast, prices in the western and midwestern United States rose over the report week. The Chicago Citygate spot price closed yesterday at $7.89/MMBtu, $1.64/MMBtu above the spot price on Wednesday, February 12. This was likely the result of low storage levels, high weather-driven demand, and a capacity restriction reported yesterday on ANR Pipeline's Muttonville Lateral. This lateral links ANR with the Great Lakes Gas Transmission pipeline. The pipelines transport natural gas imported into Michigan from Canada, as well as gas stored at the Bluewater Gas Storage facility, to the Chicago area and other locations in the Midwest. The Southern California Border Average and PG&E Citygate spot prices also rose by 22 cents/MMBtu and 47cents/MMBtu, respectively, to $5.68/MMBtu and $5.94/MMBtu.

Futures prices surpass $6/MMBtu. Expectations of cold weather, combined with low natural gas storage levels, boosted the near-month contract (for March delivery) past $6/MMBtu for the first time since January 2010. The March 2014 contract rose from $4.822/MMBtu last Wednesday to $6.149/MMBtu yesterday. The price of the 12-month strip (the average of the contracts between March 2014 and February 2015) increased from $4.639/MMBtu to $4.934/MMBtu.

Demand falls in all sectors. Demand for natural gas fell this week across all sectors. Total consumption of natural gas fell to 87.5 Bcf/d, 24% below last week's average of 112.8 Bcf/d, and 3% below the average for the same days in 2013. The decline in demand began last week, after consumption peaked at 125.0 Bcf/d on Thursday, February 6, as the impact of cold weather on that date dissipated. The decline continued through yesterday, when consumption fell to 73.7 Bcf/d.

The largest drop in consumption came from the residential and commercial sector, which fell week-on-week by 18.9 Bcf/d (29.6%), to 44.9 Bcf/d. Natural gas consumption in the power sector (power burn) fell by 6.4 Bcf/d (27.4%) below week-ago levels, to 16.8 Bcf/d. Industrial consumption decreased by 1.0 Bcf/d (4.4%), and natural gas exports to Mexico dipped by 2.9%.

Power burn is down throughout the country. Power burn decreased this week in every region of the Lower 48 states. The largest decreases occurred in the Southeast and Texas, which accounted for 61% of the national decrease from last week's average. Power burn in Texas peaked at the beginning of last week, on February 6, when it reached 7.1 Bcf/d. It then decreased last week, and continued to decrease this week, to 2.6 Bcf/d, 48.3% below week-ago levels. The Midwest, Southwest, Midcontinent, and Pacific Northwest followed a similar pattern as Texas over the past two weeks.

Power burn in the Southeast decreased by 1.5 Bcf/d (23.0%), to an average of 5.0 Bcf/d, versus last week's average of 6.5 Bcf/d. Power burn in the Southeast peaked on February 12, reaching 7.8 Bcf/d, and declined through yesterday. The Northeast followed a similar trend.

Supply declines due to drop in imports. Overall natural gas supply fell by 0.3 Bcf/d below week-ago levels, as a 1.0 Bcf/d drop in natural gas imported from Canada and a 0.1 Bcf/d drop in liquefied natural gas (LNG) sendout offset a 0.9 Bcf/d rise in dry production.

Natural gas entering the United States via pipeline from Canada declined from a 6.5 Bcf/d average last week to 5.4 Bcf/d this week, the result of reduced flow of Canadian gas to the Midwest. Prices and consumption in the Midwest decreased, following last week's spike in demand. At the same time and for similar reasons, LNG sendout from the Elba Island terminal in Georgia, the Cove Point terminal in Maryland, and the Everett terminal in Massachusetts fell. LNG remains a small portion of U.S. natural gas supply.

While imports dropped, dry natural gas production rose by 0.9 Bcf/d (1.4%) to 65.7 Bcf/d, rebounding from last week's decrease. This is a 1.6 Bcf/d (2.4%) increase above year-ago levels. Cold weather reduced production last week, according to reports.

More price data


Withdrawals exceed 230 Bcf for the sixth time this winter. Cooler-than-normal weather drove the fourth straight week of inventory declines greater than or equal to 230 Bcf. It was the sixth weekly decline of 230-plus Bcf this winter. Before this winter, weekly declines greater than 230 Bcf occurred only 12 times since EIA's weekly storage data series began in 1994. The net withdrawal reported for the week ending February 14 was 250 Bcf, 117 Bcf larger than the 5-year average of 133 Bcf and 119 Bcf larger than last year's net withdrawal of 131 Bcf. Working gas inventories totaled 1,443, or 975 Bcf (40.3%) less than last year at this time, 741 Bcf (33.9%) below the 5-year (2009-13) average, and 433 Bcf (23.1%) below the 5-year minimum.

Data revision changes last week's inventory levels. A revision caused by resubmitted data resulted in raising the estimate of working gas stocks in the Producing Nonsalt region by 7 Bcf for the week ending February 7. The reported revision caused the stocks for February 7 to change from 1,686 Bcf to 1,693 Bcf. As a result, the implied net change between the weeks ending January 31 and February 7 changed from -237 Bcf to -230 Bcf. There was a similar revision, also in the Producing region, for the week ending January 24.

Storage draw falls below market expectations of 254 Bcf. When the EIA storage report showing a withdrawal of 250 Bcf was released, the price for the March natural gas futures contract decreased 17 cents on the New York Mercantile Exchange (Nymex). At 10:30 a.m., the price of the near-month (March 2014) contract fell to $5.90/MMBtu. Prices climbed back to $6.04 in the hour following the release.

Net withdrawals in all three regions larger than average. The East, West, and Producing regions had net withdrawals of 129 Bcf, 30 Bcf, and 91 Bcf, respectively.All three gas storage regions remain below their year-ago, 5-year average levels, and 5-year minimums.

Temperatures during the storage report week significantly cooler than normal. Temperatures in the Lower 48 states averaged 27.3 degrees for the week, 8.4 degrees cooler than the 30-year normal temperature and 10.9 degrees cooler than during the same period last year.

More storage data