Coal demand for electrical generation lowest since 1992

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Latest Oil and Gas News: 
February 21, 2012

(Bloomberg; Feb. 17) - Coal demand in the U.S. is collapsing as power companies switch away from the fossil fuel to take advantage of the cheapest natural gas in 10 years. Use of coal to generate electricity will drop 2 percent this year to the lowest since 1992, while gas-fired consumption will rise 5.6 percent, according to the Energy Department.

Appalachian coal, the U.S. benchmark grade, sank 15 percent in January and is down 26 percent from a 2011 high. "It's very ugly," J. Christopher Haberlin, a Richmond, Virginia-based analyst at Davenport & Co., an investment brokerage, said Feb. 15. "Gas is a major driver and the oversupply there has been well documented, but adding to the pain is the unseasonably mild winter we're having."

Utilities are also switching to gas from coal because of an impending government rule that calls for Texas and 26 eastern states to cap sulfur dioxide to limit acid rain and soot. The rule, combined with low gas prices, may force utilities to close about 12 percent of the nation's coal-fired generating capacity, according to IHS CERA. "Our newest combined-cycle natural gas plants are dispatching before any of our coal plants," Duke Energy CEO Jim Rogers said at a conference in New York on Feb. 15. "We don't see building another coal plant for two to three decades."

Iowa utility conversions will make gas its No. 1 fuel

(Des Moines Register; Feb. 18) - Is the age of coal ending for Iowa's utilities?

Five years ago Alliant Energy wanted to build a $1.8 billion, 600-megawatt coal-fired electricity generator to partner with an existing 134-megawatt, coal-fired unit on the east side of Marshalltown. The new coal unit didn't happen. Alliant overcame considerable vocal opposition from environmentalists and got approval from the Iowa Utilities Board, but the board attached so many conditions that Alliant decided to ditch the project.

Five years later things have changed. Today Alliant is converting the 134-megawatt Marshalltown unit from coal to natural gas, a process it says will be complete by spring. It has done the same thing with an older 82-megawatt coal-fired plant that serves Dubuque. It also plans to add an additional 550 megawatts of natural gas generation, with the site and other details to be determined sometime this spring.

The result would more than double Alliant's natural gas generation capacity to 1,491 megawatts. Meanwhile, coal-fired generation would drop to second place in the Alliant system, with 1,326 megawatts. Patricia Kampling of Alliant said the push for a coal plant in 2007 "was a lifetime ago." Gas is at decade-low prices, and new environmental regulations are forcing utilities to decide if they want to spend a lot of money to retrofit older coal plants to comply with new emission rules or move to more gas generation.

Environmental groups less friendly to natural gas industry

(Washington Post; Feb. 19) - Just four years ago, shale gas king Aubrey McClendon told Chesapeake Energy shareholders, "Finally, we made some new friends this year." The CEO sketched a vision of working with "leading environmental organizations" on issues "where our interests might be aligned." But those friendships grew old, then cold. Environmental groups that once took McClendon's money in a common cause against coal power have stepped back as they weigh the perils of extracting shale gas.

The Sierra Club took $26 million in contributions from McClendon and Chesapeake-affiliated companies between 2007 and 2010. Last year, the group walked away from Chesapeake and an offer of an additional $30 million. The American Lung Association has accepted funds from Chesapeake since 2009 for its "Fighting for Air" campaign. Natural gas entrepreneur T. Boone Pickens gave $453,250 to the liberal think tank Center for American Progress in 2008 and 2009 for its National Clean Energy Project.

It made sense that environmentalists viewed the gas industry as an ally when they were trying to forge a climate deal on Capitol Hill in 2009 and 2010, said Deborah Gordon of the Carnegie Endowment for International Peace energy and climate program. "When cap-and-trade was going through, they needed an alternative. ... They saw it as the savior, and it's anti-coal," Gordon said. But now concerns about the chemicals used in hydraulic fracturing have become more pressing. "It's just exploded," she said.

Companies showing less interest in New York's dry gas

(The Journal News, Westchester, NY; Feb. 18) - Energy companies swept through New York's Southern Tier and into the Catskills in 2008, eager to lease natural gas rights from landowners in the Marcellus Shale region. Close to four years of regulatory review and a de facto moratorium later, New York's portion of the Marcellus remains untapped by hydraulic fracturing and now companies like Chesapeake Energy and Consol Energy are cutting back drilling in other states and focusing on wet gas not found in New York.

It all raises the question: Has New York missed the gas-drilling boom? Most experts say no, but several said low gas prices could have an effect on the pace drillers set in New York should the state allow high-volume fracking. Since the initial rush of leasing activity in 2008, companies have cooled considerably toward New York. Firms like Chesapeake and Schlumberger, an oilfield-services company, have pulled employees from the area in recent years. New lease offers to landowners have been virtually non-existent.

While industry and landowner representatives credit that to the state's extended regulatory uncertainty, the type of gas available in the New York portion of the Marcellus hasn't helped. Parts of the Marcellus formation in Ohio and western Pennsylvania have wet gas, which contains less methane and more other hydrocarbons, such as ethane. Those hydrocarbons can be separated and sold, creating profit. In New York, the Marcellus is believed to contain dry gas, which is almost entirely comprised of methane.

N.Y. to give drillers three options for wastewater disposal

(The Associated Press; Feb. 20) - One of the most contentious issues in the debate over shale gas drilling in New York's share of the Marcellus Shale region - how to handle millions of gallons of contaminated wastewater - remains unsettled. As the state ponders final regulations, environmental advocates say the issue is a glaring gap in preparations. "All of those options have impacts; none of them is particularly benign," said Kate Sinding, a staffer of the Natural Resources Defense Council.

There are three options for waste disposal in the state Department of Environmental Conservation's 1,500-page environmental review and proposed regulations for hydraulic fracturing of horizontal wells for natural gas in the Marcellus Shale: 1) Truck the millions of gallons of wastewater produced per well to a treatment facility and either discharge the treated water into a river or reuse it for another drilling project; 2) Ship it out of state for deep-well injection disposal; or 3) Recycle it on-site for drilling multiple wells.

Environmental Conservation Commissioner Joe Martens says permit applications must include details about how wastewater will be handled. It's up to the drillers to determine what method to use. The proposed treatment requirements would rule out any of the wastewater plants now in existence in New York unless they invest in new equipment.

Encana sells 40% of undeveloped
B.C. gas assets to Mitsubishi

(Wall Street Journal; Feb. 17) - Encana said Feb. 17 that Japan's Mitsubishi Corp. will invest about $2.9 billion to acquire a 40 percent stake in Encana's undeveloped Cutbank Ridge natural gas assets in northeastern British Columbia. The deal comes as Japan scrambles to lock in global gas supplies after last year's devastating earthquake and tsunami forced the country to loosen its reliance on nuclear energy.

The deal marks the latest foray by an Asian firm into western Canada's vast energy resources. Under the agreement, Mitsubishi will own 40 percent of the Cutbank Ridge Partnership, which holds 409,000 net acres of undeveloped Montney lands in B.C., plus additional development potential in the Cadomin and Doig formations. The transaction doesn't include any of Encana's current Cutbank Ridge production of about 600 million cubic feet of gas a day, processing plants, gathering system or its Alberta landholdings.

Encana, which will operate the partnership, said the partners aim to jointly develop production capacity to deliver "abundant natural gas to markets for decades ahead."

Mitsubishi will pay $1.45 billion on closing, expected later this month. It will also invest $1.45 billion of the partnership's future capital investment for a commitment period, expected to be about five years, thereby reducing Encana's own capital funding commitments over that period.

Mitsubishi says it will accelerate
LNG feasibility work in Canada

(Platts; Feb. 20) - Japan's Mitsubishi Corp. intends to accelerate feasibility studies to export Canadian natural gas as LNG, following its latest agreement to take a 40 percent stake in Encana Corp's Cutbank Ridge natural gas play, the company said in a statement Feb. 20. Mitsubishi's announcement follows Encana's statement that the two companies had agreed on a $2.9 billion deal for developing the Cutbank Ridge play in western Canada.

Mitsubishi said the total estimated ultimate recoverable resources from the Cutbank Ridge play are more than 35 trillion cubic feet. The Cutbank Ridge partners plan to invest more than $6 billion over the next five years to drill approximately 600 horizontal production wells to develop the asset, Mitsubishi said.

With its latest acquisition of additional natural gas resources, Mitsubishi will accelerate its ongoing feasibility studies to develop Canadian LNG for export. Currently, Mitsubishi is undertaking natural gas development in the Cordova Embayment in British Columbia with Canadian-based Penn West Exploration, Chubu Electric Power, Tokyo Gas, Osaka Gas and state-owned Japan Oil, Gas and Metals National Corp. and Korea Gas Corp.

Japan imported record amount of LNG in January

(Reuters; Feb. 20) - Japan's imports of LNG soared to a record high in January mainly to fuel electricity generation, helping make up for dwindling use of nuclear power due to the Fukushima radiation crisis. The volume of customs-cleared LNG imports rose 28.2 percent from a year earlier. The LNG imports, mainly from Qatar and Malaysia, totaled about 390 billion cubic feet in January, exceeding the previous record of 362 bcf set last August.

The country's 10 regional electricity utilities consumed a record amount of gas for power generation in January, industry data has shown. By the end of January, only three of Japan's 54 nuclear reactors were in operation amid safety concerns after the March earthquake and tsunami triggered a radiation crisis at Tokyo Electric Power's Fukushima Daiichi nuclear plant, leading to widespread contamination and mass evacuations.

Since then no reactors shut down for regular maintenance have restarted as they need to meet new safety checks and receive clearance from both the central and local governments. Without such approval, all Japan's reactors could be shut by the end of April. The prospect of being without nuclear power has raised fears of forced power rationing and temporary blackouts in the summer, when air conditioning puts extra strains on supply.

Yemen LNG will divert more cargoes to Asia

(Yemen Post; Feb. 19) - Under the sales and purchase agreement signed in 2005 between Yemen LNG and France's Total, the Gulf of Mexico and Western Europe were supposed to be the primary destinations for LNG sales. Yet since the commencement of Yemen LNG production in 2009, up to 15 cargoes a year have been diverted to more rewarding Asian markets.

Responding to the continuing fall of U.S. gas prices, Yemen LNG and Total have agreed to further increase the number of diversions by 20 additional cargoes to South Korea over the years 2012, 2013 and 2014. Under the agreement, the LNG is sold to Kogas at current market prices. Total and Yemen signed the deal Feb. 14.

In 2011 Yemen LNG delivered 60 percent of its production to Asia, 15 percent to Europe and 25 percent to the Americas. "Our reputation as a reliable LNG supplier is appreciated by the premium Asian buyers. Korea now receives half of our LNG production and we also regularly supply China, Japan and India. The fall of the U.S. LNG demand was unforeseen by the markets," said Yemen LNG's General Manager Francois Rafin.

Gazprom says it will sit out shale gas rush

(Wall Street Journal; Feb. 17) - As many of the world's biggest energy companies vie for shale gas assets, a top executive at Russia's Gazprom said it doesn't plan to join the frenzy. "Our traditional reserves are tenfold more efficient (to develop) than shale resources," Gazprom Deputy Chief Executive Alexander Medvedev said Feb. 16. "In Russia, we put [shale] on a long shelf and maybe in 50 to 70 years we will look at it again."

Gazprom has said that shale drilling, which requires hydraulic fracturing to break apart underground rock, poses "significant environmental risks, particularly the hazard of surface and underground water contamination with chemicals applied in the process."

Several European nations sit atop shale deposits, with the U.S. Energy Information Administration estimating that Poland has the continent's largest reserves. Poland has been keen to tap its deposits to end the country's dependence on Russia for energy. U.S. oil companies Chevron, ExxonMobil and ConocoPhillips have begun drilling projects in Poland.

Europe could be stuck with Russian gas

(Wall Street Journal; Feb 19) - A major transformation of the global natural gas market is under way. Fresh supply routes are being drawn, new exporters are emerging and established trade patterns are being turned on their heads. Yet Europe, the world's second-largest gas market behind the U.S., stands apart from much of this change. It looks likely that new sources of internationally traded LNG will be largely gobbled up by Asia, leaving the U.K. and Europe stuck in their codependency with Russia.

This isn't surprising for Australian LNG, which will go to booming Asia economies. However, analysts say Asia's growing appetite may also draw supplies that might have served Europe from Africa, North America and the Mideast. Proposed U.S. Gulf Coast export terminals would appear to be pointing at Europe. However, expansion of the Panama Canal by 2014 could provide "an even shorter shipping route [to Asia] than from the Gulf Coast to the U.K.," said a Brookings Energy Security Initiative report.

This leaves Europe stuck in an awkward embrace with Russia that looks set to get even stronger. Last month, German utility RWE AG said Europe's big plan to counterbalance Russian dominance - the Nabucco pipeline that would directly import Caspian gas - could be scrapped due to financial pressures.  Days later, Russia's gas monopoly, Gazprom, said it will speed up plans for a pipeline into southern Europe that has long been seen as an attempt to thwart Nabucco.

More information later this year on
Papua New Guinea LNG expansion

(Dow Jones; Feb. 21) - A $15.7 billion venture in Papua New Guinea operated by ExxonMobil may know by the end of the year if it has enough natural gas for an expansion that could vastly improve its profitability, project partner Oil Search said Feb. 21. PNG LNG is one of the largest and most complex energy projects under construction in the world. An expansion to three LNG production units from the initial two could give a big boost to Oil Search, for which the project is its flagship investment.

An expansion could also benefit the impoverished nation of Papua New Guinea, whose gross domestic product is already set to more than double with the project's foundation stage. Exxon, Oil Search and other partners including Australia's Santos Ltd. already have enough gas to underpin construction of the foundation stage of PNG LNG, which will ship an average of almost 900 million cubic feet of gas a day starting in 2014 to customers in Japan, China and Taiwan.

As anticipated by some analysts, Oil Search said Feb. 21 that initial exploration drilling to support a possible expansion has been pushed back until mid-2012 from an original timetable of the end of the first quarter. "A preliminary view on whether enough gas is available to underwrite an expansion or whether additional activities are required is likely to be formed in late 2012/early 2013," Oil Search CEO Peter Botten said. 

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