On Monday, EIA published its base case version of its 2014 Annual Energy Outlook (AEO2014). EIA predicted that natural gas production will rise steadily throughout the forecast period, reaching 37.5 trillion cubic feet (Tcf) per year by 2040, an increase of 56% over 2012 levels. This projected increase in production is notably higher than the outlook a year ago in AEO2013, largely the result of higher shale gas production growth. The increase in supply will satisfy higher growth in both domestic consumption and exports.

EIA projects robust growth in natural gas production, trade

Shale gas production is expected to double, reaching 53% of all produced volumes by 2040, up from 40% in 2012. As with overall gas production, production from shale plays is higher than in AEO2013 because of an updated, more localized assessment of well recovery and decline rates. Natural gas from tight formations continues to be an important source of supply, as well.

Total domestic natural gas consumption is projected to grow by 6.0 Tcf from 2012 to 2040, when it would equal 44% of the 13.5 Tcf increase in U.S. production. Other highlights:


  • All consumption sectors except residential grow significantly through 2040.
  • The greatest increase occurs in industrial gas consumption, including lease and plant fuel, which will rise by 2.5 Tcf. This is 59% higher than projected in AEO2013, the result of increased manufacturing shipments, particularly for chemicals, as well as generally higher levels of energy intensity.
  • The electric generation sector is projected to increase its gas consumption by 2.0 Tcf from 2012 to 2040 in AEO2014, up significantly from its projected 0.2-Tcf increase over this period in AEO2013. Natural gas satisfies the majority of growth in U.S. electric generation.
  • The use of natural gas in the transportation sector also shows strong growth.

According to the AEO2014, the United States will become a net exporter of natural gas by 2017, two years earlier than seen in AEO2013. Net natural gas exports will reach 5.8 Tcf by 2040, versus net imports in 2012 of 1.5 Tcf. The growth in net exports accounts for 54% of projected production growth through 2040, and is 39% higher than projected in AEO2013. Other AEO2014 trade highlights:


  • Net LNG exports will rise by 3.5 Tcf over the AEO2014 projection period. This increase is attributable to a more optimistic assessment of the number of liquefaction trains that can simulataneously be constructed in North America, as well as the increased capacity to produce natural gas domestically.
  • By 2040, net pipeline exports to Mexico will grow to 3.1 Tcf, from 0.6 Tcf in 2012. This growth is 32% higher than seen in AEO2013, as the AEO2014 factors in the effect of additional pipeline infrastructure built for the Mexican market to receive more gas from the United States via pipeline, and less gas from LNG imports.
  • While the United States is projected to continue to be a net importer of natural gas from Canada, the volume decreases to 0.7 Tcf by 2040, versus 2.0 Tcf in 2012. Pipeline imports from Canada are largely projected to occur in the western United States, with exports to Canada from the eastern United States projected to increase significantly.


(For the Week Ending Wednesday, December 18, 2013)

  • Following three weeks of weather-driven increases, natural gas spot prices decreased slightly at most trading locations in the country. However, the Henry Hub spot price increased slightly, from $4.24/MMBtu last Wednesday, December 11, to $4.26/MMBtu yesterday.
  • At the New York Mercantile Exchange, the January 2014 contract declined from $4.337/MMBtu last Wednesday to $4.251/MMBtu yesterday, ending five consecutive weeks of increases in the front-month contract price.
  • Working natural gas in storage decreased to 3,248 Bcf as of Friday, December 13, according to the EIA Weekly Natural Gas Storage Report (WNGSR). Stocks declined by a record 285 Bcf for the week. This is the largest withdrawal since EIA started publishing weekly storage data in 1994. Storage levels are 13.1% below year-ago levels and 7.4% below the 5-year average.
  • The natural gas rotary rig count totaled 369 this week, a decrease of 6 from the previous week, according to data released December 13 by Baker Hughes Inc. The oil rig count rose by 14 to 1,411 active units. The total rig count is 1,782, up 7 rigs from the previous week, but down 17 from a year ago.
  • The weekly average natural gas plant liquids composite price rose 1.2% this week (covering December 9 through December 13) compared to the previous week, and is now at $11.00/MMBtu. Propane and ethane drove the increase in the composite price, rising by 5.0% and 7.2%, respectively, over this period. Isobutane decreased by 5.3%, while butane decreased by 3.8%, and natural gasoline decreased by 2.4%.

EIA projects robust growth in natural gas production, trade

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    Prices decrease in most of the country. Natural gas prices decreased in most of the United States, with weather warming from the cold temperatures at the beginning of the report week. The average temperature in the Lower 48 states rose from 32 degrees Fahrenheit on Thursday, December 12, to 40 degrees yesterday, with demand for electric consumption (power burn) and residential and commercial heating both decreasing as a result. As this occurred, supply recovered partially from the reduced production levels last week caused by well freeze-offs. As demand declined and supply partially recovered, the Henry Hub spot price in Erath, Louisiana, went from $4.40/MMBtu on Thursday, December 12, to $4.26/MMBtu yesterday, but was still up slightly by 2 cents MMBtu over the $4.24/MMBtu price on Wednesday, December 11.

    The largest price decline took place in New York City as the Transco Zone 6-NY spot price fell from $16.54/MMBtu on Wednesday, December 11, to $4.39/MMBtu yesterday. New York prices spiked last week as cold temperatures drove up demand. This was compounded by reduced deliveries into the area on the Texas Eastern Transmission Company (Tetco) pipeline, following two interruptions to service in the southwestern portion of the Appalachian Basin’s Marcellus Shale play. Both interruptions took place in southwest Pennsylvania, which forms part of an integrated production region with West Virginia. The first of the two interruptions was an unplanned outage at a Tetco compressor station on December 10, followed by reduced deliveries onto Tetco from the Dominion Transmission (DTI) pipeline on December 11 because of unplanned maintenance at the Oakford Appalachian Gateway metering station. Prices also fell at Boston’s Algonquin Citygate hub, which began the report week on December 11 at $20.40/MMBtu and decreased to $12.59/MMBtu yesterday, although this was still significantly higher than at any other major hub. The Algonquin spot price spiked at $33.14/MMBtu on Friday, December 13, its highest level since January 2013. While new pipeline infrastructure has primarily alleviated the impact of pipeline constraints on New York area markets, the impact of New England constraints remains a significant factor in keeping prices high there.

    Natural gas futures price declines 8.6 cents/MMBtu over the week. The near-month (January 2014) futures price began the report week at $4.337/MMBtu and ended at $4.251/MMBtu, its first weekly decline since the beginning of November. The 12-month strip (the average of the 12 contracts between January 2014 and December 2014) decreased by 5.4 cents to $4.192/MMBtu yesterday.

    Natural gas liquids prices are up week-on-week based on rising propane and ethane prices. The weekly average natural gas plant liquids composite price rose 1.2% this week to $11.00/MMBtu. Propane spot prices were the largest contributor to the composite increase, rising by 5.0% because of elevated demand, while ethane prices rose by 7.2%.

    Gas consumption declines as weather warms. Total natural gas consumption for the report week declined by 8.8% compared with last week, as temperatures recovered from lows reached during last week’s cold snap. Residential/commercial sector and electric sector consumption decreased by 8.9% and 15.5%, respectively. The largest percentage decreases in electric-sector consumption of natural gas came from the Midcontinent and Texas, which declined week-on-week by 34% and 58%, respectively. In the Midwest, power sector consumption declined by only 0.3%, after increasing by 183% the previous report week, with temperatures there staying 43% below levels from two weeks ago. Net pipeline exports to Mexico rose 5.7%, due to higher exports from the Southwest, while exports from Texas remained relatively flat.

    Total supply recovers over the week. Total natural gas supply rose by 1.2% for the report period. Domestic dry gas production increased by 1.6% above week-ago levels, after declining by 3.4% last week following widespread well freeze-offs concentrated largely in the southwestern United States. Net imports from Canada declined by 3.9%, driven by a 31% decline in Canadian gas imported into the Midwest. LNG imports, a minor part of supply, were up 42%, with a large part of the increased sendout coming from the Distrigas LNG terminal in Everett, Massachusetts.

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    Gas storage sees record high net withdrawal. The net withdrawal reported this week was 285 Bcf. The previous record withdrawal was 274 Bcf in January 2008. The previously largest recorded December withdrawal was 208 Bcf, in December 2000. December withdrawals have averaged 109 Bcf per week since 2008. This week’s withdrawal is 215 Bcf larger than last year’s withdrawal of 70 Bcf and 152 Bcf larger than the 5-year average withdrawal of 133 Bcf. Current inventories totaling 3,248 Bcf are 488 Bcf (13.1%) less than last year at this time, and 261 Bcf (7.4%) below the 5-year (2008-12) average.

    Net withdrawal is significantly larger than market expectations of 264 Bcf. At 10:30 a.m., when the EIA storage report was released, prices for natural gas futures on the Nymex increased by 7 cents/MMBtu. In the hour following the release, prices climbed an additional 6 cents/MMBtu, to just under $4.44/MMBtu.

    Only the West region posted a record withdrawal. Although the largest withdrawals occurred in the East and Producing regions, which had net withdrawals of 132 Bcf and 99 Bcf, respectively, only the West region posted a record withdrawal. This week’s withdrawal of -54 Bcf in the West was higher than the previous record withdrawal, which was 43 Bcf in January 2007. The previous December record withdrawal was 39 Bcf in December 2009. This week’s withdrawal of 132 Bcf in the East was substantially lower than the previous record, which was 179 Bcf in February 2007. In the East, the December record withdrawal was 142 Bcf, in December 2000. In the Producing region, this week’s withdrawal of 99 Bcf was slightly lower than the previous record of 100 Bcf in January 2010, but it broke the previous December record withdrawal of 75 Bcf from December 2009. Storage capacity, particularly in high deliverability salt facilities located predominately in the Producing region, has grown over time, making larger withdrawals possible.

    Cold weather during the storage report week prompted the large withdrawal. Temperatures in the Lower 48 states averaged 29.3 degrees for the week, 9.1 degrees cooler than the 30-year normal temperature and 15.1 degrees cooler than the same period last year. Parts of the Midwest experienced below-freezing weather for the entire week, with temperatures as much as 20 degrees below the seasonal norm. Natural gas production was also down, as many locations experienced well freeze-offs in the first half of the storage week. Storage operators met this elevated heating demand by executing large net withdrawals on behalf of their customers.

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