ESAI: Shale development to boost US ethylene exports
August 6th, 2012 | OGJ editors
A natural gas liquids boom stemming from development of US shale plays will spur investments in export-related petrochemical plans targeting Latin American market, Energy Security Analysis Inc. (ESAI) said in a recent report.

With US demand for ethylene derivatives growing modestly, expanding petrochemical capacity will be export-oriented. ESAI expects the US surplus of ethylene derivatives to expand to over 4 million tonnes/year (tpy) by 2016, a 40% increase from 2011.

The US is seeing considerable activity, almost all of which is based on the frenetic pace of shale gas exploration and production and the prospects for cheap, large volumes of natural gas as potential feedstock (OGJ, May 7, 2010, p. 88).

Consequently, US ethylene is becoming more competitive in global markets given its feedstock price advantage over naphtha, ESAI reported Aug. 2 in its 5-year Global Industrial Fuels Outlook. ESAI is based in Boston.

Two proposed crackers tentatively are scheduled to come on stream during 2012-16, and several existing plants are undergoing upgrades to absorb more ethane. The last time a cracker was built in the US was 2000.

In response to increased liquids production from Marcellus and Utica shales in Pennsylvania and Ohio, Royal Dutch Shell selected a site near Pittsburgh for the potential construction of a petrochemical complex (OGJ Online, Mar. 15, 2012).

Dow Chemical Co. plans to invest $1.7 billion to build a 1.5-million-tpy cracker at its Freeport, Tex., center (OGJ Online, Apr. 30, 2012).

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Sumitomo, Tokyo Gas Secure U.S. LNG From Dominion for Japan
April 27, 2012 | by Yuriy Humber | Bloomberg News
Sumitomo Corp. (8053), Japan’s third- largest trading house, and Tokyo Gas Co. (9531) secured a supply contract from the U.S., where natural gas trades for a fraction of the price in Asia.

Sumitomo and Tokyo Gas agreed to buy 2.3 million metric tons of liquefied natural gas annually for 20 years from Dominion Resources Inc. (D) (D)’s Cove Point project, the trading house said today in a statement. Dominion, which needs U.S. approval to sell to Japan, plans to build and start operating the Cove Point plant in 2017. Dominion, based in Richmond, Virginia, will liquefy the gas from Sumitomo’s assets in the northeast of the U.S.

“If the project is finally agreed, Sumitomo will be able to establish a natural gas and LNG value chain in the U.S.” stretching from extraction to export, Sumitomo said.

Japanese traders, led by Mitsubishi Corp. (8058)’s $6 billion outlay on an Encana Corp. (ECA) shale project announced in February, are stepping up purchases of U.S. and Canadian natural gas assets as they seek to export the fuel in the form of LNG to Asia. The 40-year-old oil-linked price mechanism for Asian LNG means buyers in the region, which accounts for more than 60 percent of global demand, are paying nine times more for gas than U.S. domestic users.

Nuclear Meltdown

U.S. Henry Hub futures rose 4.8 percent to $2.134 per million British thermal units as of 12:29 a.m. in New York. Japan, which has just one of its 54 nuclear reactors in operation since a March 2011 meltdown at its Fukushima Dai-Ichi plant, paid about $18.85 per million Btu in the first 11 months of last year, according to finance ministry data.

At current U.S. prices, the Japanese partners will be able to sell their contracted LNG in the domestic market at less than $10 per million Btu, Kunio Nohata, senior general manager at Tokyo Gas, told reporters in Tokyo today.

Sumitomo was among the first Japanese traders to invest in U.S. shale with the 2009 purchase of a 12.5 percent stake in the Barnett Shale Gas project in Texas from Carrizo Oil & Gas Inc. (CRZO) (CRZO) Together with its stake in Rex Energy Corp. (REXX) (REXX)’s Marcellus shale area, the trader has a 140 million cubic feet per day supply of gas, JPMorgan Securities Japan Co. said in a March 19 report.

“For the trading companies the areas for new acquisitions are food, base metals like copper, and especially shale gas and oil,” JPMorgan analyst Akira Kishimoto said yesterday in Tokyo, before the Sumitomo announcement. LNG exports from North America may become one of the main businesses of Japanese trading companies in about five years, he said. Import Terminal

Sumitomo, which also owns U.S. gas trader Pacific Summit Energy LLC, said the Cove Point LNG will be destined for Japan. Cove Point currently acts as an LNG import terminal, operated by Dominion.

The feed for Dominion’s Cove Point LNG, also in the northeast of the U.S., will come from the Marcellus shale project, Sumitomo said. The LNG plant Dominion plans to build will have an annual 5-million-ton capacity, it said.

Japan’s imports of spot LNG surged 20 percent to a record in February, with supplies from Nigeria providing more than half of the total as the country seeks fuels to replace power from nuclear plants that have been shut, customs data showed. Imports under immediate and short-term contracts rose to 1.18 million tons, according to data from the finance ministry.

Japan’s total LNG imports, which include long-term contracted shipments, rose 22.5 percent in February from a year earlier to 7.67 million tons, according to the finance ministry.

To contact the reporter on this

story: Yuriy Humber in Tokyo at yhumber@bloomberg.net To contact the editor responsible for this story: Rebecca Keenan at rkeenan5@bloomberg.net

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Natural Gas Is on a Roll, Executive Declares
April 26, 2012 | by EriC Lipton | The New York Times
A “perfect storm” of economic and regulatory factors is driving major United States utilities to rapidly switch from coal to natural gas as an electric power source, the top executive of one of the nation’s largest utilities said on Thursday.

Nicholas K. Akins, chief executive of Ohio-based AEP, said the company plans to retire 5 of its 25 coal-burning plants and shut down coal-powered units at other plants it owns in a shift that collectively means the elimination of about 5,000 megawatts of capacity. The result will be that by 2020, only about half of the power AEP produces will come from coal, down from about 67 percent last year.

The surge in domestic production of cheap natural gas, largely yielded by the rise of the controversial technique of forcing gas out of shale through hydraulic fracturing, has been a big factor in this shift. A series of new environmental regulations and pressure from environmentalists are also leading major utilities to either shut down older plants or spend billions of dollars to upgrade them.

Mr. Akins estimated that the industry would have to spend about $300 billion through the end of the decade to expand natural gas power generation capacity or retrofit older coal-fueled plants so they can meet new environmental standards — investments that it is asking regulators to allow it to pass on to its customers, at least in part, which total five million accounts in 11 states.

Renewable energy is expected to contribute a larger share of power to AEP’s mix by 2025, Mr. Akins said, but perhaps not as much as expected because of a decline in federal subsidies and continuing repercussions from the bankruptcy of Solyndra, the California solar manufacturer that collapsed last year despite receiving a $535 million federal loan guarantee.

And the once-anticipated nuclear power renaissance will probably not materialize, he added, in view of the Fukushima disaster in Japan last year.

Domestically, coal mining will be the hardest hit by this historic shift, he said. Last year alone, the amount of electricity produced by AEP’s gas-powered plants jumped 24 percent, with most of that resulting from a drop in production at coal plants.

“Our industry is in the midst of an extraordinary period of transformation and investment which will affect how we produce and delivery electricity — and what you pay for it — for decades to come,” Mr. Akins said in his remarks before the United States Chamber of Commerce,

At the Southern Company, another major coal-burning utility, natural gas is now responsible for 46 percent of its electricity, up from 16 percent four years ago. That translates into about 45 million tons of coal slated to be burned this year by Southern, down from 80 million tons in 2007, Southern’s chief executive, Tom Fanning, said in his own remarks on the topic on Wednesday.

Mr. Akins said he was somewhat concerned that the nation may end up too reliant on natural gas, particularly given the history of price volatility of natural gas. The price has dropped from $10.8 per thousand cubic feet at the wellhead as of July 2008 to $2.89 as of January.

An earlier version of this post misidentified the entity that, according to Nicholas K. Akins, will have to either spend about $300 billion through the end of the decade to expand natural gas power generation capacity or retrofit coal-fueled plants to meet new environmental standards. Mr Akins said the industry would have to spend that much, not AEP alone.

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NAT GAS Act Runs Out Of Momentum
March 13, 2012 | by Michael Bates | NGT News

The U.S. Senate voted today 51 to 47 in the affirmative to amend the behemoth transportation bill to include the NAT GAS Act, but that majority fell short of the 60 affirmative votes necessary to add the amendment to the bill. The overall transportation bill will proceed to a full vote in the Senate without the amendment, leaving the future of the NAT GAS Act uncertain. The legislation is not necessarily dead, but there are few options to reintroduce the bill before the November elections. Sen. Robert Menendez, D-N.J., submitted the NAT GAS Act as a possible amendment to the transportation bill on March 5, with Sens. Richard Burr, R-N.C., and Harry Reid, D-Nev., as co-sponsors. The Senate approved Menendez's measure - along with 29 others, out of more than 300 proposals - for consideration last Wednesday. The NAT GAS Act is a policy mechanism aimed at increasing the use of natural gas as a transportation fuel and boosting domestic production of natural gas vehicles. The bill seeks to reinstate tax credits for NGV purchases and conversions that expired at the end of 2010, as well as to extend credits for fueling infrastructure that expired at the end of December 2011. Other measures include the creation of a production tax credit for NGV manufacturers. Sens. Menendez, Burr, Reid, and colleague Saxby Chambliss, R-Ga., put the act into the Senate's queue in November 2011 with pay-for measures included. But as today's vote suggests, that carrot did not entice a sufficient number of naysayers to cross the aisle. "Congress wants to do something, but you have people who say you shouldn't be picking winners and losers," Richard Kolodziej, president of trade group NGVAmerica, told NGT News. "Of course we should be. The loser is foreign oil; the winner is domestic fuel." A companion bill to the NAT GAS Act, H.R.1380, is still alive in the House.

EAGLE FORD OIL ACQUIRES WORKING INTEREST IN BAYOU CHOCTAW
AUGUST 16, 2011 | Eagle Ford Oil & Gas

Eagle Ford Oil & Gas Corp. (ECCE.OB) (the “Company”), Houston, Texas, August 16, 2011 announced that today acquired 1.5% Working Interest in the Bayou Choctaw Project. The Bayou Choctaw Project (“Bayou Choctaw”) involves working interests in approximately 1,500 acres of leases in the Bayou Choctaw Field (“Bayou Choctaw”), located 13 miles southwest of Baton Rouge, Louisiana in West Baton Rouge and Iberville Parishes, Louisiana. The field is a salt dome structure that has radial trapping faults. The field was discovered by Exxon in 1931 and, to date, a total of 373 wells have produced over 30 million barrels of oil and 30 Bcf of natural gas. The majority of oil production was from sands that range in depth from 2,000 to 9,000 ft. and are located near the flanks of the dome. The age of these sands is Miocene to Oligocene. The majority of production to date has come from the Cib Haz formation. Bayou Choctaw is believed to be an example of the additional development opportunities remaining in a number of salt dome structures onshore Louisiana. The vast majority of the drilling in the Bayou Choctaw Field and surrounding domes occurred during the time period from the 1930s through the 1980s. The prevalent seismic data gathering technologies during this time frame was single fold data acquisition which upgraded to multifold data acquisition in the 1970s. The use of 3D seismic data did not become prevalent in the onshore Gulf Coast area until the mid-1990s with transition zone shoots in Louisiana beginning in the second half of the 1990s. Re-processing of high-quality 3D seismic data with the latest generation of algorithms and the following geophysical analysis of the reprocessed seismic data and correlation to other available geological and analogous well production has resulted in an improved sub-surface view of the configuration and size of the salt formation. On the basis of extensive geological, geophysical and engineering evaluations of these leases, including review of reprocessed 3-D seismic data, an initial six (6) well bores of currently shut-in oil wells, suitable for immediate workover and recompletion operations, were identified for workover / recompletion operations with an additional 18 shut-in wells identified for further engineering potential workover / recompletion operations. To date, the initial six (6) wells have been reworked / recompleted with production restored on four (4) wells with two (2) wells in the final stage of workover and testing procedures. Another well has been converted to a salt water disposal well to optimize field operating cost efficiencies. Ongoing engineering and geological / geophysical study is underway to prioritize additional well workovers in the field. In addition, the Bayou Choctaw development program provides for the drilling of four (4) wells to approximately 9,500 feet, with the primary objective of completion in the Upper Bol Mex geological formation and secondary objectives of the Lower Bol Mex, Marg Tex, C-29 and Cib Haz formations. One (1) well has been drilled, logged and is awaiting completion in the Cib Haz formation for initial production operations. A second well was begun as a side-track from an existing well bore with operations currently suspended pending additional engineering assessment of further drilling expected to be carried out by year end, 2011. A third well was spud August 3, 2011 with formation objectives of the Cib Haz, Upper Bol Mex and Lower Bol Mex. Drilling operations are currently on schedule. The fourth well is expected to be drilled during the fourth calendar quarter, 2011. Up to three (3) additional wells may be drilled in the future in order to produce concurrently from multiple zones and accelerate cash flow. The oil we produce is light sweet Louisiana crude which is currently being sold at a premium to published WTI pricing. Northwind Oil & Gas, LLC, a wholly-owned subsidiary of Houston, Texas based Northwind Energy Partners, LLC (“Northwind”), is the operator of Bayou Choctaw. Management Comments Mr. Paul Williams, the Chief Executive Officer of Eagle Ford Oil and Gas said, “The acquisition of the working interest and strategic alliance with Northwind Energy and the subsequent ability to develop the field will provide Eagle Ford the ability to grow our company and achieve sustainable profitability. The properties, as well as the prospects, will provide our company with much of the needed cash flow to achieve our goals.” Mr. Williams went on to say; “This acquisition provides a solid foundation to grow the Company and build shareholder value through both drilling and additional acquisitions.” Forward Looking Statements The information may include forward-looking statements, which are subject to known and unknown risks and uncertainties that could cause actual results to differ materially. We refer you to the discussion of risk factors that could affect future operating or financial performance in our most recent prospectus and Form 10-K at December 31, 2010, 10-Q at March 31, 2011 and other SEC Filings. In addition, the Company intends to file reports on Form 8-k as to the acquisition and Sandstone’s financial information in accordance with SEC requirements. Investor Contact: Brad Holmes (713)304-6962 b_holmes@att.net