Would Natural Gas Tax on North Slope Push Big Oil?

Anchorage Daily News

Published: November 29th, 2008 04:00 AM
Last Modified: November 29th, 2008 09:01 AM

Backers of a proposed voter initiative to impose a state tax on natural gas reserves got clearance to start collecting signatures to put the idea on the ballot, the lieutenant governor's office said.

The backers hope that by taxing the North Slope's huge gas reserves, the oil companies there will push ahead faster on plans for a multibillion-dollar gas pipeline project. They want the initiative on the 2010 ballot.

The state Department of Law reviewed the initiative proposal and concluded it was in the proper form, although the department said the proposal has numerous ambiguities and could be difficult to implement as a law if voters approve it, the lieutenant governor's office said.

Key backers are Democratic state Reps. Harry Crawford of Anchorage, David Guttenberg of Fairbanks and Beth Kerttula of Juneau. Their proposal calls for a 3-cent tax on every thousand cubic feet of known gas reserves in very large fields in Alaska. The North Slope has about 35 trillion cubic feet of gas reserves -- resulting in a potential tax levy of about $1 billion a year. But the proposed law would exempt from the tax any gas committed for shipment through a pipeline once it's built.

North Slope oil companies produce natural gas with oil now. They use the gas to power the oil fields and coax more oil from the ground. But they are not shipping it out to markets outside the state for lack of a gas pipeline.

With the lieutenant governor's approval in hand, the initiative backers have one year to gather the thousands of signatures from across the state for the initiative to be placed on the ballot.

Argentina Natural Gas Prices to Rise

By Drew Benson

Nov. 28 (Bloomberg) -- Argentine Planning Minister Julio de Vido said the government eliminated natural gas subsidies, which will mean higher well-head prices and rate increases for the biggest residential and industrial consumers.

The move, effective Nov. 1, will save the government 1.4 billion pesos ($420 million) a year, De Vido said during a press conference in Buenos Aires.

“These measures will produce a significant and direct reduction in subsidies for natural gas rates and as such increase production, which means more jobs,” De Vido said.

Consumers that use the most natural gas, 36 percent of residential users and 1.5 percent of industrial clients, will pay higher rates, De Vido said.

The announcement came a day after sporadic power outages for 43,000 consumers amid a heat wave led Argentines in some neighborhoods across Buenos Aires to bang on pots and pans in protest.

To contact the reporter on this story: Drew Benson in Buenos Aires at abenson9@bloomberg.net.

Italian Natural Gas Grid for Sale

Wall Street Journal - Europe

Enel SpA, Italy's biggest utility by revenue, will soon try to sell a controlling stake in its lucrative Italian natural-gas grid, a person familiar with the matter said.

During a Nov. 11 board meeting, Enel's board gave Chief Executive Fulvio Conti a mandate to announce an international auction for the sale of a majority stake in Enel Rete Gas SpA, which it currently owns nearly all of, the person said.

Enel, which also supplies electricity in Italy and other countries, wants to sell some of its assets to slash some of the debt it accumulated after a joint takeover of Spain's Endesa SA last year, in the world's biggest utility acquisition. Enel, whose debt stood at €51.4 billion ($67.2 billion) on Sept. 30, expects to raise some €1.2 billion through the sale, the person said.

Italy's gas regulators valued the Enel Rete Gas grid at €1.6 billion in Jan. 2008, when it set the grid's fees. Enel is Italy's second-largest distributor of natural gas after ENI SpA.

It is unclear who could emerge as a potential bidder. In recent years, Russian gas company OAO Gazprom has pushed to expand its presence in Italy, in particular by signing a deal with ENI to sell directly to Italy's lucrative natural gas market. However, the person familiar with the matter said Enel is likely to seek a nonindustrial buyer that it can form a partnership with.

A spokesman for Gazprom declined to comment.

F2i SGR, an Italian investment fund specializing in infrastructure, could be interested in the grid, because it is in line with the assets the fund typically invests in, an F2i spokesman said. The spokesman added that the fund had not been in talks with Enel about a potential bid, because the grid had not been formally placed on sale.

Enel has appointed Banca IMI SpA, the investment banking arm of Italy's largest bank Intesa Sanpaolo, and Morgan Stanley as financial advisers for the auction, the person familiar with the situation said.
—Liam Moloney contributed to this article.

Write to Stacy Meichtry at stacy.meichtry@wsj.com

Chesapeake Stock Offering for Natural Gas Exploration

By DEBORAH YAO, AP Business Writer
10:09 AM PST, November 27, 2008
Chesapeake Energy Corp., the nation's largest producer of natural gas, seeks to raise up to $1.8 billion through common stock sales in an effort to fund its drilling and exploration activities and mitigate the impact of lower natural gas prices on cash flow.

In two filings with the Securities and Exchange Commission late Wednesday, the company said it will issue shares worth as much as $1 billion before fees and also registered 50 million shares worth at most $791 million for potential sale.

Oklahoma City, Okla.-based Chesapeake said it will use proceeds from the $1 billion offering for general corporate purposes, including fund exploration, development and other capital expenditures.

The move would dilute holdings of shareholders, who already suffered through a substantial decline in Chesapeake's stock price this year. Shares closed at $20.24 on Wednesday, off 73 percent from the stock's $74 52-week high set this summer.

But the company said cash flow, borrowings and cash on hand have not been enough to pay for capital expenditures.

Chesapeake has used up the remaining financing available under its $3.5 billion bank credit facility and only $251 million is left of another $460 million credit line. Credit markets remain tight with financial institutions under duress.

While cash flow from operations had risen in the first nine months of 2008 compared to a year ago, it's heavily dependent on natural gas prices, which have fallen off sharply.

"Changes in market prices for natural gas and oil directly impact the level of our cash flow from operations," the company said in a filing.

Chesapeake has hedged about 73 percent of its remaining natural gas and oil reserves in 2008 and 67 percent of expected production in 2009 at average prices of $9.09 and $8.65 per thousand cubic feet equivalent (Mcfe), respectively. In Nymex trading Thursday, natural gas for January delivery slid 9.7 cents to $6.781 per 1,000 cubic feet.

The company has cut back on its capital expenditure budget through 2010 in light of global economic distress and concerns about oversupply of natural gas in the U.S. market.

Chesapeake said it's negotiating with several "significant" leaseholders to acquire leaseholds at reduced prices. In the filing, it said some leaseholders may agree to accept common stock for all or part of the deal.

The company has struck several multibillion-dollar transactions recently.

In September, BP PLC's U.S. arm said it plans to buy a 25 percent stake in Chesapeake's Fayetteville Shale assets in Arkansas for $1.9 billion. A month earlier, BP said it had bought similar Chesapeake assets in Oklahoma for $1.7 billion.

Earlier this month, Chesapeake sold even more natural gas assets to Norwegian energy company StatoilHydro for $3.38 billion.

U.S. Natural Gas Weekly Inventory Falls This Week

NEW YORK (MarketWatch) -- Natural gas inventories fell by 66 billion cubic feet to stand at 3,422 billion cubic feet in the week ended Nov. 21, the Energy Information Administration reported Wednesday. Analysts surveyed by Platts expected gas in storage to have dropped by between 43 and 48 billion cubic feet last week. After the data, January natural gas futures were up 28 cents, or 4.4%, to $6.67 per million British thermal units.

Chesapeake Closes Natural Gas Deal with Statoil Hydro

OKLAHOMA CITY (AP) — Chesapeake Energy has closed a $3.37 billion sale on rights to the massive Marcellus Shale natural gas deposits in Appalachian region, the company said Tuesday.

The nation's largest natural gas producer announced two weeks ago it would sell a 32.5 percent interest to Norwegian energy company Statoil Hydro, while maintaining a working interest of 67.5 percent.

While Chesapeake has recently been forced to tamp down takeover rumors as energy prices spiral downward, the Statoil deal may pave the way for the company to expand overseas, where the advanced drilling techniques used in the U.S. are not as developed.

Chesapeake Energy Corp. said it will "jointly explore unconventional natural gas opportunities worldwide" with Statoil.

Chesapeake received $1.25 billion in cash at the closing, giving it access to much needed cash amid a severe global credit crisis, and will get a further $2.125 billion between 2009 and 2012 through an expenditure agreement.

"We are honored to partner with one of the leading international oil and gas companies and are excited about the opportunities to jointly export our world class unconventional natural gas technology for further long-term growth," said Chesapeake Chief Executive Aubrey McClendon.

McClendon, listed by Forbes as the 134th richest person in the U.S., was forced last month to sell nearly all of the shares he had amassed in Chesapeake to meet margin loan calls.

The $570 million firesale was described by McClendon as a personal matter and he has vowed to rebuild his stake.

Chesapeake shares have tumble nearly 64 percent since late August have been extraordinarily volatile over the past month.

Shares jumped fell 2 cents to $18.24 Tuesday. Statoil's American depository receipts rose 38 cents to $16.61.

Natural Gas Fields Discovered in Mozambique

MAPUTO, Nov 24 (Reuters) - Mozambique said on Monday it had found two new natural gas fields in the southern Inhambane province which, if commercially viable, would supply domestic and regional markets.

"If it is viable, this discovery will make it possible to respond to domestic demand for natural gas," Mineral Resources Minister Esperanca Bias told reporters.

"We have a list of projects that could possibly be supplied, such as generating electricity, setting up a fertiliser factory and use in vehicles."

Gas exploration at the Njika-1 well in Mozambique began on Oct. 1, 2008. The project is a joint venture between South Africa's Sasol (SOLJ.J: Quote, Profile, Research, Stock Buzz), Malaysia's Petronas [PETR.UL] and the Mozambican government.

Under Mozambican law, the consortium that has discovered the gas reserves has six months to assess its findings and present a report to the government.

Sasol, the world's biggest maker of diesel from coal, owns 50 percent of the project, Petronas owns 35 percent, while the government of Mozambique holds 15 percent through national oil company Empresa Nacional De Hidrocarbonetos De Mozambique (ENH).

The two blocks, 16 and 19, were granted to the consortium in June 2005.

Mozambique currently has available around 140 million gigajoules of gas at the Pande/Temane reserves in the same province, used to supply both the domestic and regional markets.

Sasol has invested $1.2 billion to explore these gas fields, and plans to spend an additional $146.8 million to increase gas exports to South Africa by 20 percent in 2009. (Reporting by Charles Mangwiro, editing by Anthony Barker)

Natural Gas Drilling Cut Backs Coming

By BRETT CLANTON Copyright 2008 Houston Chronicle
Nov. 20, 2008, 11:06PM
Marginal gas wells at risk
In Texas, most rigs are drilling for natural gas and operate on land, with a much smaller number working the Gulf of Mexico. Generally, the biggest clusters of activity are gas fields in East Texas and the Barnett Shale around Dallas-Fort Worth, and oil fields in the Permian Basin of West Texas.

Texas, where roughly half of U.S. rigs are working today, is likely to be hit hard by industry budget cuts that analysts predict will take 300 to 500 drilling rigs out of service nationwide.

Last week, the U.S. rig count fell by 51 to 1,941, according to the Nov. 14 weekly rig data report by Baker Hughes, an oil field services provider in Houston. Texas accounted for 23 of those lost rigs, leaving 899 still working in the state.

Anita Sparks, city secretary in Rankin, an oil town in West Texas with a population of 750, said lights on oil rigs still shine on the horizon at night, rental houses are full of oil workers and the local economy is good.

But she said the recent slide has gotten everyone's attention. "We're used to the ups and downs," she said. "You just hope that people are a little smarter this time around."

Analysts said areas that are the most costly to develop will be most vulnerable to rig losses.

In Texas, those include economically marginal oil properties in West Texas and deep, expensive gas wells in South Texas and offshore, said industry analyst Dan Pickering, of Tudor, Pickering, Holt & Co. Securities, a Houston investment bank. Core areas of the Barnett Shale and the emerging Haynesville Shale play in East Texas and northwestern Louisiana should hold up the best, he said.

Drilling decline likely
Texas Railroad Commissioner Elizabeth Ames Jones said that while the state is on track to issue 25,000 drilling permits — the most since 1985 — a decline in drilling activity is likely next year as producers postpone projects. "Even if it comes down to 19,000, we're still breaking records," she said, but noted that any decline will mean job losses and less revenue to the state.

The state collects what it calls severance taxes from energy companies based on the market price of oil and natural gas. In fiscal 2008, ending in August, those collections were $4.1 billion, up from $2.7 billion in 2007, according to the Texas Comptroller's Office. That total was the highest ever in nominal terms, but on an inflation-adjusted basis, collections were higher from 1981 to 1985.

If collections fall in 2009, which Jones expects, it will mean less money for two of the state's biggest public funds. One quarter of the collections go to a fund supporting Texas public schools, while 75 percent winds up in the state's general fund that supports public transportation, health care services and a host of other programs. There could also be less revenue for public universities, which receive oil and gas royalties from university-owned lands.

Diversification could help
About 226,000 Texans were employed in the state oil and gas industry during September, 8.7 percent more than at the same point in 2007, according to the Texas Workforce Commission.

Employment levels will be "under duress" for a little while until oil and gas companies can reduce costs, but should rebound once energy firms begin investing again, said Bill Herbert, industry analyst with Simmons & Co. International, an investment bank in Houston.

State officials and industry leaders like to say Texas' economy is not as dependent on oil and gas as it was in the 1970s and 1980s — when oil prices soared to highs only recently exceeded when adjusted for inflation, then crashed amid a prolonged energy downturn.

In 2007, the industry accounted for 15.7 percent, or $179 billion, of Texas' gross state product. That's up from 14.8 percent, or $158 billion, the year before. The industry hit a peak of 26 percent of gross state product in 1981.

"Texas has diversified away from oil and gas dependence since the bust of the 1980s," Pickering said, "but it is still meaningful."

Shale Natural Gas Solid for 10 Years

From Herald News Services
Published: Saturday, November 22, 2008

Washington - U. S. natural gas production from shale could double in the next 10 years, a spokesman for the natural gas industry said on Friday.

"What we've seen so far from shale fields is just the tip of the iceberg," terry ruder, vice-chairman of the Natural gas Supply association, said at a conference sponsored by the Federal energy regulatory commission.

Ruder said U. S. shale reserves could provide one-quarter of the nation's natural gas supply in the next decade, up from about 10 to 12 per cent of U. S. gas demand in 2008.
He said U. S. shale production could grow to 15-billion to 20-billion cubic feet per day by 2018, from about 6-8 bcf per day now.

There are about 20 major shale fields in the U. S. that produce or have potential to produce natural gas, including the Bakken field in North and South Dakota and the Haynesville area in east Texas and Louisiana.

Ruder and other industry representatives at the conference expressed concern a potential windfall profits tax could hinder shale output.

"Shale developments are highly capital intensive and a windfall profit tax assessment . . . would directly and immediately reduce investment in U.S. shale developments and adversely affect production," Ruder said.

Pennsylvania Tough Regs for Natural Gas Drillers

By Steve McConnell
Wayne Independent
Fri Nov 21, 2008, 05:34 PM EST
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Wayne County -

As some county landowners await the natural gas boom, executives from major natural gas companies are saying it may be too difficult to drill here because of an over-demanding regulatory system that could put the brakes on the “gold rush.”
At a state senate hearing in Luzerne County on Tuesday, Wendy Straatman, president of Exco-North Coast Energy, which has signed more than 100 land leases in the county, said, in her written testimony, that the company may have to put its investments on hold due to an “uncertain regulatory and legislative environment.”
The company has experienced “permitting delays – unlike anything we have seen in any other state in which we operate,” according to her testimony.
John Baen, professor of real estate at the University of North Texas, said, in his report to the committee, that the commonwealth is a “disjoined jungle of agencies, boards, counsels, and regulatory bodies ... (with) unpredictable permitting success or denial based on any one ‘roadblock ... reducing the chance that the Marcellus Shale as a resource will ever be developed.”
In order to drill and maintain natural gas operations in the Marcellus Shale, drilling companies mainly need permits from the state Department of Environment Protection (DEP), which regulates the drilling process, public health and water quality issues, and the Delaware River Basin Commission (DRBC), which regulates water withdrawal and quality.
Besides the economic consideration that the Marcellus Shale could support U.S. natural gas energy needs for at least 14 years, according to Penn State geoscientist Terry Engelder, and provide well-paying jobs to the region, environmental regulators must walk the fine line of not stymieing the industry while ensuring that the commonwealth’s pristine environment - and public health - is not compromised.
“We have a responsibility here to give the industry thorough and timely (permit) reviews,” said DEP spokesman Tom Rathburn. “We’re not holding anyone up here. We’re getting it done.”
He said this year the department approved 7,700 permits in the traditional oil and gas fields in western Pennsylvania, a four-fold increase from last year, and 300 permits in the Marcellus area.

Regulatory Hurdles

To efficiently drill the Marcellus Shale, natural gas well operators must bust open gas seams, thousands of feet below the surface, through a process called “hydraulic fracturing,” which creates fractures in the rock seams trapping gas.
One well, however, may need more than one-million gallons of water, combined with sand and trade-secret chemicals, for the process.
To obtain the large quantities of water needed to bust a shale, gas operators need Delaware River Basin Commission (DRBC)’s permission to siphon water from the county’s rivers, streams, or ponds.
DRBC is a federal multi-state agency which regulates water resources in the basin, 36 percent of which is underlain by the Marcellus Shale.
“For the first time, this is an area ... the commission has not been involved in,” said Clarke Rupert, a DRBC spokesperson, about the Marcellus phenomenon. With “the large use of water, that’s why the review by the commission has become necessary.”
William Muszynski, water resources manager with DRBC, said, in his presentation at the senate hearing, that drilling operations are expected to have a “substantial effect” on the basin’s water resources.
But industry representatives say there are too many regulatory players and too many different permits, some of which are redundant.
Stephen Rhodes, president of the Pennsylvania Oil and Gas Association, an industry group, said there are also a myriad of other lesser known permits, environmental safety procedures, and regulatory groups like county conservation districts that the industry must satisfy.
“It’s unlike anywhere else in the country,” said Rhodes, of the state’s regulatory climate. “They are treating us like residential subdivisions or Wal-Mart. It’s a complex process (natural gas extraction) and we understand. We just need to find ways to streamline it. ... Nobody in this industry has any intent to operate in a way that is damaging to the environment.”
“The regulations are in place to protect the commonwealth,” said Dave Messersmith, of the Penn State Cooperative Extension Office in Wayne County. “They are there for a reason.”
“The turnaround time on applications is really pretty quick,” he added.
Rhodes said the regulation requirements are much stronger in the Marcellus Shale, in contrast to the long-standing permit requirements in the state’s traditional oil and gas fields.
“The review process is extremely detailed and involved,” said Rhodes. “This could stifle billions of dollars in investment if (the permit process) it is not streamlined.”
According to Muszynski’s testimony, DRBC is working to “streamline permitting requirements” and is expecting “increased (permit) application activity” in Wayne County.
Late October, DRBC received its first water withdrawal application for Marcellus-related operations, a request from Chesapeake Appalachia LLC, a subsidiary of Chesapeake Energy Corp., to draw 30 million gallons of water, in a 30 day period, from the East Branch of the Delaware River.

Pennsylvania Natural Gas Rush is On!

By Steve McConnell
Wayne Independent
Wed Nov 19, 2008, 05:19 PM EST
Wayne County -

They were scouring through land deeds at the county courthouse today as they have been all year, trying to secure natural gas rights for a handful of major companies, who plan to drill here one day - it seems.
These landmen, landwomen, representatives of the natural gas companies, whoever they are, don’t say much or identify who they’re with, but they come and go all day, keeping their business to themselves, said Ginger Golden, of the county deed office.
The Marcellus Shale, a vast geologic area stretching throughout northern Appalachia and loaded with trillions of pounds of natural gas, has become the latest lovechild of the natural gas industry since it could suit the needs of U.S. natural gas consumption for at least 14 years, by itself.
A walk through this deed office, one of hundreds of county deed offices throughout the shale, affirms the fact.
Their not rude, just quiet, especially amongst themselves - a competitor may be nearby - as they sift through county land records, as observed by The Wayne Independent on Wednesday.
There were about 14 together in one room that day, tracing property ownership and plot lines through time.
While only a couple of permits have been issued in the county, all earlier this year, and only one well has been drilled, according to state Department of Environmental Protection figures, there are at least 1,800 leases signed in the county today - with landowners anxiously awaiting the day when royalties literally spew from the shale below.
It is difficult to determine an exact, total number of signed leases. Some leases signed with one company were later sold to a different company. Some of these reassignments are probably occurring now, said Golden.
A review by The Wayne Independent found most leases signed in areas north of Honesdale, covering a wide-swath of the county’s northern half, in the following townships and boroughs: Scott, Starrucca, Preston, Buckingham, Manchester, Mount Pleasant, Damascus, Lebanon, Dyberry, Clinton, Bethany, and Oregon.
There were also leases signed south of Honesdale, although much less, in the following townships and boroughs: Canaan, Cherry Ridge, Texas, Berlin, Palmyra, Hawley and Lake.
Chesapeake Appalachia, a subsidiary of Chesapeake Energy Corp., of Oklahoma, holds the lion’s share - nearly 1,500 leases. (A lease is an intent to drill.)
Exco-North Coast Energy, of Ohio, who has drilled extensively in western Pennsylvania, signed 124 leases here.
Cabot Oil & Gas Corp., of Texas, signed 67; Stone Energy Corp., of Louisiana, signed 74, according to county records.
Of note, Chesapeake, it seems, is holding onto their leases with only three rescinded, in August. The natural gas giant has also recently bought leases from Interstate Gas Marketing, of Indiana, Pennsylvania, and Black Cat Energy, of Texas.


From lease to drill
In a state senate committee hearing on Tuesday in Luzerne County regarding the economic and environmental impact of the Marcellus Shale play, gas company executives stated that they plan to move ahead with drilling, despite what they say is a cumbersome regulatory system, which is stymieing their progress. (The Wayne Independent will follow-up on this in another report.)
State Sen. Lisa Baker’s office provided the executives written testimony to the Wayne Independent.
Wendy Straatman, president of Exco-North Coast Energy, said the company’s focus this year has been land lease transactions.
“To date, we have invested significant sums toward that end, essentially providing us the right to drill on and under someone’s property,” according to her written testimony. “In total, during this calendar year, I believe that Marcellus producers, including Exco, have invested significantly more than $2 billion in land leases alone. ... Please understand that these land leases represent the “tip of the iceberg” in terms of what we as an industry are poised to invest in Pennsylvania.”
Scott Rotruck, vice president of corporate development for Chesapeake Energy, said the company will ramp up drilling operations next year.
“We currently have two drilling rigs operating in the Marcellus Shale, one of which is in Pennsylvania. Depending on the rate of permitting, we could drill 50-75 wells ... next year,” according to his written testimony.
Chesapeake is one of the largest leaseholders in the Marcellus Shale with approximately 1.8 million acres leased.
Testimony from the hearing will soon be available on the senator’s state website, said Brian Grove, chief of staff.

Toyota Camry Compressed Natural Gas Hybrid Unveiled in Los Angeles

Autoweek

There are fuel sippers, and then there are fuel shunners. The Toyota Camry hybrid concept unveiled Wednesday at the Los Angeles auto show that runs on compressed natural gas falls into the second category.

The car is powered by a 2.4-liter, four-cylinder engine with Toyota’s Hybrid Synergy Drive technology. But the conventional gasoline engine is replaced with the CNG (compressed natural gas) system. Working together, the unit is rated at 170 hp.

The combined fuel-economy rating is 33 mpg--close the conventional hybrid’s 34 mpg--and it doesn’t use a drop of gasoline. The two CNG tanks are installed in the well for the spare tire, and they have the equivalent of eight gallons of gasoline and a range of at least 250 miles.

Toyota had a natural-gas program in 1999 in California, but canceled it after a year because of the lack of a refueling infrastructure. There are less than 1,000 natural-gasoline stations today, and less than half are open to the public, Toyota said.

For the L.A. show, Toyota gussied up the Camry with some concept touches, including custom fascias in the front and rear, 19-by-7.5-inch alloy wheels and run-flat tires. The ride height is lowered and the body gets side skirts and graphics.

We first saw this car at the company’s Sustainable Mobility Seminar in Portland, Ore., this fall.

Honda Natural Gas Car is a Civic

Business First - Columbus Ohio
In dedicating its new Indiana plant this week, Honda Motor Co. Ltd. officials also announced the facility will begin producing a compressed natural gas-powered car next year.

The automaker said its Greensburg-based Honda Manufacturing of Indiana LLC arm, which began production in October, will turn out a natural-gas powered vehicle dubbed the Honda Civic GX next year. Honda didn’t disclose how many of the vehicles the plant will be producing or when production will start.

The company said the vehicle will be the world’s only compressed natural-gas powered passenger car.

At the Greensburg plant, about 1,000 employees working on one shift produce Honda Civic sedans with four-cylinder engines. Engines for the plant are made at Honda’s plant in Anna, northwest of Honda of America Manufacturing Inc.’s Marysville headquarters. The Anna plant serves as the North American hub of the company’s engine operations.

A second shift is expected to begin next year and eventually employ 2,000, allowing the plant to produce 200,000 vehicles a year. The Greensburg plant also will be taking on Civic production previously housed at Honda’s East Liberty plant early next year as part of a number of changes to the automaker’s production operations.

Shale Natural Gas is a kin to Cattle v Farmer

ALBANY, New York: Advanced drilling techniques that blast millions of gallons (liters) of water into 400-million-year-old shale formations a mile (1.6 kilometers) underground are opening up "unconventional" gas fields touted as a key to the nation's energy future.

These deposits, where natural gas is so tightly locked in deep rocks that it's costly and complicated to extract, include the Barnett Shale in Texas, the Fayetteville Shale of Arkansas, and the Haynesville Shale of Louisiana. But the mother lode is the Marcellus shale underlying the Appalachians.

Geologists call the Marcellus a "super giant" gas field. Penn State geoscientist Terry Engelder believes it could supply the natural gas needs of the United States for 14 years.

But as word spread over the past year that a 54,000-square-mile (139,860-square-. kilometer) shale field from southern New York to West Virginia promised to yield a trillion dollars worth of gas, making millionaires of local landowners, environmental alarms were sounded.

Would gas wells damage water wells? Would chemicals poison groundwater? Would fabled trout streams be sucked dry? Would the pristine upstate reservoirs that supply drinking water to New York City be befouled?

"This gas well drilling could transform the heavily forested upper Delaware watershed from a wild and scenic natural habitat into an ugly industrial landscape that is forever changed," said Tracy Carluccio of Delaware Riverkeeper. She'd like a moratorium on drilling to allow an inventory of natural areas to be done first.

So loud were the protests in New York that Gov. David Paterson directed the Department of Environmental Conservation to update its oil and gas drilling regulations to reflect the advanced drilling technology, which uses millions of gallons of water and poses waste-disposal challenges.

Now, while new drilling rigs sprout in Pennsylvania and West Virginia, development of the Marcellus in New York is on hold until next year, while the DEC holds hearings and drafts regulations.

Gas developers say environmental alarms are exaggerated and New York could miss out on much-needed capital investment and jobs if it takes a heavy-handed regulatory approach.

"These are surgical operations utilizing the most advanced drilling technology known to man," Tom Price Jr., senior vice president of Chesapeake Energy, told state lawmakers in Albany at a recent hearing.

The technology that has raised concern involves horizontal drilling and hydraulic fracturing, also known as fracking. Thousands of wells have been drilled and fracked in New York in the past 50 years, New York DEC Commissioner Pete Grannis said. But refinement of the technology makes it feasible to extract gas from deeper, denser shales.

The latest technology, known as "slick water fracturing," uses far more water than earlier methods — 1 to 5 million gallons (3.9 million to 18.9 million liters) for each fracking operation, Grannis said. That fact, and the proximity of the Marcellus to New York City's watershed, prompted the regulatory review.

New York and Pennsylvania regulators promise full disclosure of all chemicals used in fracking, which industry insiders say are not hazardous. John Pinkerton, chairman and CEO of Range Resources, said used fracking fluid is no more toxic than what goes down the drain at a hair salon.

Roger Willis, who owns a hydraulic fracturing company in Meadville, Pennsylvania, said thousands of frack jobs have been done in rock formations above and below the Marcellus shale in New York state with no damage to aquifers.

Willis said frack fluids are isolated from groundwater by steel and concrete well casings. The well bore goes thousands of feet deeper than potable water supplies, through multiple layers of rock, until it reaches the gas-rich shale. Then it turns sideways and continues horizontally for several thousand feet.

The fracking fluid is blasted into the shale, opening cracks that let trapped gas escape. The fractures are held open with sand mixed with the fluid.

Flowback pipes collect the gas and used fracking fluid, which now has a high concentration of salt from the ancient sea where the shale sediments formed.

The well casings that are meant to protect groundwater have occasionally failed.

"There are going to be some problems, although they're not commonplace," said Bryan Swistock, a water resources expert from Penn State. "Laws on the books are adequate to take care of that."

Disposal of salty fracking water is problematic because of limited capacity in existing treatment plants, which can't remove salt but can only dilute it to an acceptable level for discharge into rivers. Alternatives include new recycling technologies and injection well disposal, where water is blasted back into the earth for permanent disposal.

While New York and Pennsylvania require that waste water be stored in a holding pond with an impervious liner until it's disposed of, critics fear such ponds could leak, or overflow in a rainstorm.

Mountain Natural Gas to Midwest

Pipelines carrying Rocky Mountain natural gas to markets across the United States are virtually full, and prices in the region are dropping as a result of supply overwhelming both local demand and export capacity.

But three companies are offering competing proposals to build a big, new, straight-shot pipeline from Wyoming to Chicago, and that city’s millions of people who use natural gas to heat their homes during the teeth-chattering winters along Lake Michigan.

On an average day, Chicago and surrounding areas use nearly 4 billion cubic feet of natural gas. On a cold day, demand can hit more than 10 billion cubic feet, according to Kinder Morgan Energy Partners LP, based in Houston, the backer of one Rockies-Chicago pipeline proposal.

“There’s a couple of smaller projects [offering new capacity by adding more compression or an extra line], but there’s not another big pipe on the near-term horizon,” said Joe Magner, a Denver oil and gas analyst with Tristone Capital Inc., a Calgary, Alberta, Canada-based energy investment banking firm. “We need another big pipe.”

Natural Gas Money for New York Staten Island

Natural gas boom could edge into NYC watershed
11/15/2008, 1:40 p.m. EST
By MICHAEL HILL
The Associated Press

TOMPKINS, N.Y. (AP) — Gary Galley talks about scratching out a living on his farm west of the Catskills Mountains as he feeds his cattle. The big money from this valley land, he believes, could come from a massive natural gas reserve thousands of feet below where he stands.

"Go ahead and drill!" Galley said with a laugh as his cows grazed.

Galley is among dozens of landowners in this rural region 120 miles northwest of New York City who signed lease deals with energy companies that could open their land to drilling. This part of Delaware County sits on the edge of a multistate natural gas reserve called the Marcellus shale formation, and hopes are high here that wells could bring a bonanza of royalty checks and tax revenue.

But there could be a big problem — potentially a $10 billion problem. New York City draws most of its water from in and around the Catskills and city officials are worried about the expected natural gas boom edging into their watershed. Before a single company has applied to drill here, there are rumblings of a high-stakes conflict between watershed residents and the protectors of a water supply for 9 million people.

"This is a particularly extreme example of something that absolutely, positively cannot take place within the confines of the watershed," said New York City Councilman James Gennaro, chairman of the Environmental Protection Committee. "It's laughable, the whole notion that this could take place on any scale."

Marcellus is a deep formation covering parts of West Virginia, Ohio, Pennsylvania and all of New York's Southern Tier. Proponents describe it as an energy game changer, a reserve that will bring Texas oil-like revenues to the East. It has been estimated that the entire formation holds enough natural gas to satisfy the nation's demand for 14 years.

The Catskill Mountains are near the northeast edge of the formation and represent a fraction of Marcellus in New York. Still, land agents have signed lease deals in parts of Sullivan and Delaware counties, suggesting potential.

Drillers largely ignored Marcellus for many years because it was too deep and too expensive to tap. That changed as energy prices skyrocketed and geologists refined a horizontal drilling process to tap deep reserves. Sand and chemically treated water is blasted down the right-angled holes to fracture rocks and release trapped gas.

The process, called "hydrofracking," requires millions of gallons of water, a portion of which comes back up and is stored temporarily on site before being treated. Environmentalists opposed to drilling in the watershed are particularly concerned about water storage.

Paul Rush, a deputy commissioner with the city's Department of Environmental Protection, told lawmakers in Albany at a recent hearing that hazardous compounds used in hydrofracking could pose a "grave threat" to New York City's water. The city is one of the rare municipalities in the nation with a waiver from federal environmental officials that allows it to avoid filtration.

Natural Gas Company Stock Trading Again

TULSA, Okla., Nov. 14, 2008 (Canada NewsWire via COMTEX) ----American Natural Energy Corporation (the "Company") (TSX Venture: ANR.U) is pleased to announce that, effective at the opening day, November 17, 2008, the common shares of the Company are scheduled to be reinstated to trading on the TSX Venture Exchange (the "Exchange"). The Company's common shares were suspended from trading on the Exchange on July 25, 2007 as a result of a cease trade order issued by the British Columbia Securities Commission, and subsequent cease trade orders issued in Alberta, Manitoba, Ontario and Quebec, for failure to timely file financial statements for the fiscal year ended December 31, 2006.

As announced in the Company's news release of October 30, 2008, the cease trade orders were revoked on October 29, 2008. The Company has filed all annual and interim financial statements and related management's discussion and analysis, and its continuous disclosure filings are up-to-date. As part of seeking revocation of the cease trade orders, the Company filed an amended Form 51-101F1 and amended Form 51-101F3, pursuant to National Instrument 51-101 Standards of Disclosure for Oil And Gas Activities, under the Company's profile on SEDAR at http://www.sedar.com.

<< Recent Business of
the Company >>

The Company's exploration and development of its Bayou Couba oil and gas leases in St. Charles Parish, Louisiana have continued to move forward and were unaffected by the cease trade orders.

On October 19, 2005, the Company executed an exploration and development agreement (the "Agreement") with Dune Energy, Inc., which provided for the creation of an area of mutual interest in St. Charles Parish, Louisiana, covering an area of approximately 31,367 acres. On June 26, 2007, Dune Energy paid the Company the sum of $3 million to increase its participation to 75% of the Company's interest under the Agreement, excluding the area of the Company's Bayou Couba lease in which the Company retains a 50% interest. On September 1, 2007, Dune Energy was elected successor operator under the Agreement and paid the Company an additional $500,000, which was used by reduce existing obligations of the Company.

During 2007 and to date in 2008, the Company has participated in an expanded 255 square mile 3D seismic survey and evaluation with ExxonMobil of which the Company received an exclusive license covering 60 square miles which includes its Bayou Couba joint development area. The interpretation of the seismic survey has been ongoing and has produced numerous exploration and development prospects.

The Company plans to seek industry participation in the development of its interests in its oil and natural gas properties, and debt or equity financing to reduce its current liabilities. Additional information about the Company can be found under its profile on SEDAR at http://www.sedar.com.

<< Board of Directors >>

There has been no change in the board of directors of the Company since the cease trade orders were issued.

The board of directors consists of Michael K. Paulk, the President and Chief Executive Officer, Steven P. Ensz, the Vice-President, Finance, Chief Financial Officer and Secretary, and two independent directors, Brian E. Bayley and John K. Campbell. In connection with the Company's debenture financing in 2003, the holders of such debentures are entitled to designate two additional persons to serve as directors. At present, such director positions remain vacant.

Michael Paulk was elected as a director, and appointed the President and Chief Executive Officer of the Company in July of 2001. From October 1994 to January 2001, when it was sold to Chesapeake Energy Corporation, Mr. Paulk was the President and a director of Gothic Energy Corporation, which during his tenure was engaged in the acquisition, development, exploration and production of natural gas and oil. Mr. Paulk has been involved in the oil and gas industry for more than thirty years.

Steven Ensz has been Vice-President, Finance, Chief Financial Officer and Secretary of the Company since July of 2001. He is a certified public accountant and is responsible for all of the Company's financial disclosure and reporting. From March of 1998 to January of 2001, he held a similar position with Gothic Energy Corporation, and from July 1991 to February 1998, he was Vice-President, Finance of Anglo-Suisse, Inc., an oil and natural gas exploration and producing company. Mr. Ensz has held various positions within the energy industry, including President of Waterford Energy, an independent oil and gas producer, for more than 25 years.

Brian E. Bayley was elected a director of the Company on June 1, 2001. Mr. Bayley has been the co-chair of Quest Capital Corp. since January 1, 2008, prior to which he was the President and Chief Executive Officer from June 2003 to January 1, 2008 and the Chief Executive Officer from June, 2003 to March 17, 2008. Quest Capital Corp. is a mortgage investment corporation whose shares are listed on the Toronto Stock Exchange, and provides financial services to small and mid-cap companies operating primarily in North America. Mr. Bayley currently serves as a director or officer of numerous other public companies, none of which is a reporting issuer under U.S. securities laws, including Esperanza Silver Corp. and PetroFalcon Corporation. Mr. Bayley is also a director of TransAtlantic Petroleum (USA) Corp., which also provided financing to the Company, and purchased $3.0 million principal amount of the Company's 8% convertible secured debentures, in 2003.

John K. Campbell has been a director of the Company since April of 2000, and was the President of Gothic Energy Corporation from April 2000 to July 2001. Mr. Campbell recently retired as the President of TransAmerica Industries Ltd., a position he had held since 1986.

Natural Gas Expansion in USA

Los Angeles Times
By Cynthia Dizikes
November 13, 2008
Reporting from Washington -- The federal government announced Wednesday that it would be taking the first major step to expand offshore oil drilling after a long-standing ban on new energy exploration off much of the U.S. coast expired last month.

Officials with the U.S. Minerals Management Service, which oversees oil and gas development in federal waters, said that starting today it would begin the process that could lead to leases at a potential site at least 50 miles off the coast of Virginia, an area that has not had offshore drilling.

Although the move involves only one coastal area, it represents the first turn of the crank in a much larger offshore drilling campaign that rose to a fury this summer amid a tumultuous election season and soaring gas prices -- and now stands to increase energy exploration in federal waters around the country, including off the coasts of California, Alaska and Florida.

"We've had some discussion, but now we're getting serious about it," said Randall Luthi, director of the Minerals Management Service. "This is actually an important step in our nation's energy security picture."

It could, however, be only a temporary step.

Democratic lawmakers and President-elect Barack Obama have said they would consider offshore drilling as a compromise in a comprehensive energy policy and as a way to wean the U.S. off foreign oil.

But whatever the new administration and Congress decide is likely to be more restrictive than current rules under the lapsed ban, which technically allow oil companies to drill as close as three miles offshore with federal approval.

"The issue of offshore drilling will be addressed by the next president and the next Congress," said Drew Hammill, spokesman for House Speaker Nancy Pelosi (D-San Francisco), who recently supported letting states decide whether to permit energy exploration 50 miles to 100 miles off their coasts.

Since 1981, a congressional moratorium on new offshore drilling has prevented the Interior Department from establishing leases in virtually all coastal waters outside of the western Gulf of Mexico and some areas of Alaska. The ban was enacted after a massive oil spill devastated the Santa Barbara coast in 1969.

Last month, however, the Democratic-controlled Congress allowed the moratorium to lapse amid pressure from the White House, Republican lawmakers and even members of the Democratic caucus who had come under attack for not doing more to bolster domestic energy supplies with gas prices topping $4 a gallon over the summer.

The process in Virginia will begin with a 45-day public comment period starting today and ending Dec. 29. The Interior Department does not expect to start leasing the area until at least 2011, after an environmental impact analysis is performed.

Virginia Gov. Tim Kaine, a Democrat, and the Legislature have supported offshore gas exploration.

According to rough estimates, the Interior Department believes there could be 130 million barrels of oil and 1.14 trillion cubic feet of natural gas in the area they expect to begin leasing off Virginia's coast.

In total, the Interior Department has estimated that there could be 18 billion barrels of oil and 77 trillion cubic feet of natural gas beneath 574 million acres of federal coastal waters that were off-limits before the ban lapsed.

But environmental groups and some Democrats have argued that the resulting gasoline could be years away and would do little or nothing to substantially reduce prices any time soon.

The Department of Energy has estimated that crude oil and gas production and prices would not be substantially effected until 2030.

"It is not going to make a meaningful difference in terms of gas at the pump," said Daniel Hinerfeld, spokesman for the Natural Resources Defense Council. "It is just a distraction from our need to cut off our dependence on oil."

In addition to Virginia, the Interior Department has announced a new five-year plan that could lead to opening formerly prohibited waters off California and Florida -- two states that have shown greater opposition than Virginia to new drilling.

The Minerals Management Service expects to come out with a list of specific locations by the beginning of next year. The move has been seen by some as a last attempt by the Bush administration to expand drilling before Obama becomes president in January.

"President Bush's 11th-hour effort to open sensitive coastal areas to new offshore drilling is nothing more than a desperate attempt to give one more parting gift to his friends in the oil and gas industry," Rep. Lois Capps (D-Santa Barbara) said after the announcement.

Dizikes is a Times staff writer.

Alaskan Natural Gas via Hydrates

By Daniel Whitten

Nov. 12 (Bloomberg) -- Alaska has enough natural gas trapped in ice formations beneath permanently frozen subsoil and offshore to heat more than 100 million homes for a decade, a U.S. report estimated.

Hydrates, crystalline structures consisting of gas and water locked below the permafrost, contain 85.4 trillion cubic feet of natural gas, the Interior Department's U.S. Geological Survey said in a report released today.

``The hydrates have more potential for energy than all other fossil fuels combined,'' Interior Secretary Dirk Kempthorne said in a news conference. ``This is a huge resource for energy and one cannot overstate that.''

Natural gas is considered a bridge fuel to cleaner energy because it produces fewer emissions of greenhouse gases, which are blamed for global warming, than coal and involves fewer hazards than nuclear reactors. Coal generates half of the U.S.'s power.

Some environmentalists say hydrate production causes the release of methane, which is a greenhouse gas.

The world currently consumes about 104 trillion cubic feet of natural gas annually and the U.S. uses about 23 trillion cubic feet gas per year, according to the Energy Information Administration.

Hydrates gas could be produced and sold at under $10 per million British thermal unit, and less than that with advancements, said U.S. Geological Survey Director Mark Myers. Natural gas for December delivery cost $6.413 per million Btu at 12:20 p.m. on the New York Mercantile Exchange.

ANWR Drilling

About 4 percent of the estimated gas hydrates lies below the Arctic National Wildlife Refuge, which Congress has placed off limits to drilling.

While Interior Department officials wouldn't estimate when full scale gas-hydrate production would begin, they said it could be within the next decade if it was proven to be profitable.

Researchers must perform long-term production tests to demonstrate gas hydrates as an economically producible resource, Myers said. ``Hydrate accumulation in conventional hydrate reservoirs can be produced with existing technology,'' he said.

Much of the promise of Alaskan hydrates depends on whether a pipeline advocated by Alaska Governor Sarah Palin, the former Republican vice presidential candidate, can be built, Myers said. The $27 billion conduit would carry natural gas from Alaska to U.S. markets.

Extraction Methods

Several methods for extracting gas hydrates are under development. One method, depressurization, separates gas and water from the hydrate structure. A second involves injecting carbon dioxide below the permafrost, which releases methane molecules in production.

The Energy Department is spending $12 million on a 27-month study with ConocoPhillips to test the carbon-dioxide injection method. BP Plc also is researching a process using $4.6 million in federal funding. Chevron Corp. is researching in the Gulf of Mexico.

Chesapeake & Statoil Ink Natural Gas Deal

By Vibeke Laroi and Marianne Stigset

Nov. 11 (Bloomberg) -- StatoilHydro ASA agreed to pay $3.38 billion to Chesapeake Energy Corp. for shale assets and to finance drilling as Norway's largest oil and gas producer taps unconventional sources to increase reserves.

StatoilHydro will buy a 32.5 percent stake in Chesapeake's Marcellus Shale gas acreage in the U.S. northeast for $1.25 billion, the Stavanger-based company said today. It will pay $2.13 billion to fund 75 percent of drilling and completion costs from 2009 to 2012, which will require ``a significant level of drilling activity.''

``It's positive that they add to their reserves, because that has been a problem for them,'' said Christian Nagstrup, an analyst at Jyske Bank A/S, who has an ``accumulate'' on the stock. ``They have a strategy of international expansion and this is a relatively fast way to do that.''

Oil producers are tapping unconventional sources, such as oil sands in Canada and shale assets, to stem a decline in production from fields in the North Sea and other maturing areas. StatoilHydro last year bought an oil sands company in Canada for $2.1 billion, while BP this year has bought shale assets from Chesapeake Energy for $3.7 billion.

Production

StatoilHydro shares fell 7.5 kroner, or 5.6 percent, to 126 kroner as of 5:30 p.m. in Oslo. Chesapeake slipped $1.19, or 5 percent, to $22.49 as of 11:30 a.m. in New York.

StatoilHydro expects equity production from Marcellus of at least 50,000 barrels of oil equivalent a day in 2012 and a peak of at least 200,000 barrels after 2020. By contrast, the company forecast earlier this month it expects total equity production of 2.2 million barrels of oil a day in 2012.

``It's a good price if you compare it to the price per acre BP paid in their deals,'' said Trond Omdal, an analyst at Arctic Securities in Oslo, who has a ``buy'' on the shares. ``They're increasing their production at a low price.''

The company will pay about $5,800 a net acre, said StatoilHydro Executive Vice President Peter Mellbye at a press conference in Oslo. That's almost half of the $14,074 a net acre BP paid in September for shale assets from Chesapeake.

17,000 Wells

``BP paid an awful lot more for the rights they acquired,'' Mellbye said. ``But they bought in an area that's much more mature where you find much more experience so the risk is less but so is the upside potential.''

The field is now producing 3,000 barrels of oil equivalent a day from six wells, he said. The companies expect as many as 17,000 wells.

The credit crisis and a 50 percent slump in U.S. gas prices since July have pared asset prices. Chesapeake in July said it was looking for buyers for part of its Marcellus assets.

Unconventional gas sources, such as shale deposits, are more expensive to develop and need a greater number of wells than conventional reserves. They became economic to develop because of high oil and gas prices and less so when prices fall.

``It's the most cost effective option in the U.S. today'' to produce energy, Mellbye said, adding that exploration would still be profitable if gas prices fell ``on the lower end of the $5-10 million Btus scale.''

U.S. natural gas for December delivery traded at about $7.25 per million British thermal units yesterday.

China

Chesapeake in September sold a 25 percent stake in the Fayetteville Shale project to BP Plc for $1.9 billion, following a July sale of 20 percent in the Haynesville Shale project to Plains Exploration & Production Co. for $3.3 billion. BP also paid $1.75 billion for Chesapeake's assets in the Woodford Shale formation in Oklahoma in July.

Royal Dutch Shell Plc, Europe's biggest oil producer, is also developing shale projects in the U.S.

Chesapeake and StatoilHydro also agreed to jointly develop unconventional natural gas assets in China, Ukraine and Romania, Mellbye said today on a conference call with investors.

StatoilHydro, the second-largest gas supplier to Europe, is increasingly looking to gas as large oil discoveries become a thing of the past and companies seek stable gas supplies. StatoilHydro expects half of its production to come from natural gas in 2012, spokeswoman Rannveig Stangeland said by phone today. The U.S. is the world's largest gas market.

The company's average daily gas production rose to 619,000 barrels of oil equivalents in the first nine months of 2008, from 581,000 barrels a year earlier.

Strategic

``Strategically this move is absolutely right for the company, notably in comparison to their involvement in Shtokman, which carries sky-high risk,'' said Gudmund Halle Isfeldt, an analyst at DnB NOR ASA, who has a ``buy'' recommendation. ``Gas is more environmentally friendly than oil and this is in a more politically stable environment, close to major U.S. cities.''

StatoilHydro is one of the partners in OAO Gazprom's Arctic Shtokman natural-gas project.

Oneok Profits Up with Natural Gas

DOW JONES NEWSWIRES

Oneok Inc.'s (OKE) third-quarter net income more than quadrupled on continued strength of its 48%-owned Oneok Partners LP (OKS) unit, which benefited from increased volumes and higher pricing.

Oil and gas company Oneok reported net income of $58 million, or 55 cents a share, up from $13.9 million, or 13 cents a share, a year earlier.

Revenue rose 51% to $4.24 billion.

On average, analysts polled by Thomson Reuters were looking for per-share earnings of 24 cents on revenue of $2.82 billion.

Gross margin fell to 10.7% from 12.1% as the cost of sales and fuel products rose.

The distribution segment for Oneok reported its operating loss widened to $2.9 million from $1.6 million a year earlier. The energy-services segment also posted a wider loss of $3.5 million from a loss of $0.7 million.

Looking ahead, Oneok narrowed its 2008 earnings view to a range of $2.95 to $ 3.05 a share, compared with its August expectation of $2.90 to $3.10 a share.

Oneok Partners, Oneok's gas-gathering and transportation unit, reported net income of $203.9 million, or $1.97 a unit, up from $95.9 million, or 98 cents a unit, a year earlier.

Revenue jumped 59% to $2.24 billion.

Analysts were looking for earnings of $1.23 a unit on revenue of $1.94 billion.

Gross margin declined to 14.5% from 15.2%.

Oneok Partners also raised its 2008 full-year forecast to reflect the strong performance of natural gas liquids gathering and price fluctuations. It now expects earnings of $5.95 to $6.15 a unit, up from its August view of $5.20 to $ 5.60 a unit.

In 2006, Oneok sold its businesses in gathering and processing, natural gas liquids, pipelines and storage to Northern Border Partners for $3 billion and became that company's general partner and 48% owner. Northern Border was renamed Oneok Partners.

Oneok distributes natural gas through its regulated utilities in Oklahoma, Kansas and Texas. Through Oneok Partners, it operates 14,300 miles of gas- gathering pipeline and 6,920 miles of transportation pipeline as well as gas- processing plants and storage facilities.

Oneok's shares were unmoved in after-hours trading after closing $31 on Wednesday, while Oneok Partners shares rose 3.4% to $56.25.

-By John Kell, Dow Jones Newswires; 201-938-5285; John.Kell@dowjones.com;

Western Australia Natural Gas Bullish for Next 7 Years

DEMAND for natural gas in Western Australia will double in the next six years notwithstanding the collapse of resources projects, as the fallout from the global financial crisis continues.

A DomGas Alliance report says more than 1100 terajoules of extra natural gas will be required each day to meet new and replacement demand by 2014-15.

The forecast appetite for extra natural gas from new projects and to cover contracts expiring in the intervening years is the equivalent of the existing market, the report by Economics Consulting Services says.

"The new projects included in this study are generally in feasibility study stages and are reasonable prospects to proceed subject to acceptable market conditions and regulatory approvals," it says.

"The actual level of demand will depend on gas availability and price. The forecast assumes gas at similar prices to current levels."

Gas prices in WA, which are higher than on the eastern seaboard, are also on the rise.

DomGas Alliance chairman Stuart Hohnen says the Varanus Island explosion -- which wiped out 30 per cent of the state's gas supply -- reinforced WA's dependence on natural gas to generate electricity, fuel industry and supply households and businesses.

"The West Australian market provides the advantages of low sovereign risk, no currency risk, geographic proximity and access to secure long-term contracts.

"The investment and technology thresholds for domestic gas developments are also considerably lower than for liquefied natural gas."

The report says 274 terajoules a day of replacement gas will be required by 2015 to meet current demand for electricity generation, industrial processing and manufacturing as contracts expire. Alumina production is the largest user of natural gas in WA, followed by electricity generation.

The report forecasts demand of 818TJ daily from new mineral and petroleum projects in WA, including expansions of three large iron ore producers and six new mining projects in the Pilbara, coupled with at least five iron ore projects under consideration in the Mid West region, the expansion of two gold mines and the possible development of eight more in the Goldfield region, as well as four nickel projects.

The release of the report follows the opening last Friday of a 320MW gas-fired power station at Kwinana on Perth's southern outskirts.

The NewGen Kwinana power station, a joint venture between ERM Power and Babcock and Brown Power, will deliver wholesale electricity to retailer Synergy and to the South West Interconnected System for the next 25 years.

Liquid Natural Gas Cars Not Coming to California - For Now

LNG Proposition Goes Down In Clean-Burning Flames
11/08/2008

Despite heavy financial backing from the alternative fuels industry, Proposition 10, the California bond measure that would have created rebate incentives for the purchase of cars and trucks running on natural gas or other alternative fuels, was soundly defeated on election day.

Nearly 60 percent of voters on Nov. 4 cast ballots against the initiative, which was backed by billionaire ex-oilman T. Boone Pickens, the founder of Seal Beach-based Clean Energy Fuels, a supplier of compressed and liquefied natural gas for vehicles.

The failed bill would have provided $2.8 billion for rebates to promote the purchase of clean cars and trucks. Funding would have come from general obligation bonds sold by the state. Repaying those bonds would have cost Californians $333 million a year for three decades, a total of almost $10 billion.

Clean Energy pumped nearly $19 million into the campaign to pass Prop. 10 and natural gas producer Chesapeake Energy and its owner, Aubrey McClendon, donated $3.5 million to the Yes on 10 campaign. Another supporter was Long Beach-based Westport Fuel Systems, which has been developing LNG fuel systems for trucks in the harbor.

But despite all the big money behind Yes on Prop 10, the measure also had strong opposition, including Gov. Schwarzenegger, the state Democratic and Republican parties, and the chair of the California Air Resources Board.

Natural Gas 2009 - Drill What You've Got

By JIM FUQUAY
jfuquay@star-telegram.com
Fort Worth Star Telegram

Less can be more, at least in the view of independent petroleum producers grappling with how to adjust their operations to plunging natural gas and crude-oil prices.

In the past two weeks, energy producers have issued a near-uninterrupted string of improved third-quarter earnings announcements. But often as not, Wall Street was more interested in what the companies had planned for 2009 and how it would square with an environment of lower prices.

The answer was commonly along the lines of "drill what you’ve got," which likely comes as no surprise to Tarrant-area residents who witnessed the recent collapse in new leasing activity in the Barnett Shale.

For example, XTO Energy Chairman Bob Simpson said that 2009 will be "the year of the drill bit" for the Fort Worth-based producer.

The company closed $4.8 billion in acquisitions during the quarter, bringing its total for the year to $7.5 billion.

"We’re going to turn to drill that area, having wrapped up a very successful acquisition effort that gave the company, in my opinion, the best set of assets it’s ever had," Simpson said during a conference call with financial analysts.

Simpson also voiced a common theme when he said that "cash flow, at the moment, is king."

Just about every independent producer swore in the coming year to live within available cash from operations, rather than drawing down lines of credit or issuing debt.

"We will not outspend our cash resources in 2009 and 2010," Aubrey McClendon, Chesapeake Energy chairman, said during his third-quarter conference call with analysts.

That’s a sharp contrast to the previous three years, when the 80 largest exploration-and-production companies spent 147 percent of their cash flow, said Michael Bodino, director of research for SMH Capital.

He said the industry was generally operating at a consensus price level of $80 a barrel for oil and $8 for gas, but that’s come down to $70 and $7.

"We’ve seen such a big change in spending habits" in response to the plunge in natural gas and crude oil prices, Bodino said.

Or, as financial analyst David Tameron of Wachovia Capital put it: "The chorus of 'We got Shale’ during the summer has quickly turned to 'We will live within cash flow.’ "

But Tameron, in a research note to clients, said he believes that there is more political correctness than change of heart in those pledges.

"If prices turn around, we think the same management teams, facing a declining production profile, will quickly ramp back up," he said.

The issue of declining production represents another trend of the third-quarter reports. Most producers, while cutting their capital spending budgets, also forecast higher production in 2009.

It sounds counterintuitive, but it’s probably right, Bodino and others said.

"When you retrench, the first thing that gets cut is money for new acreage or exploration," he said. "What does get spent is money for production projects," which offer the fastest return of capital and best chance to pad cash flow.

XTO President Keith Hutton said the company might not run as many drilling rigs as it might have next year, but it also likely will remain at its current level of 93 active rigs and perhaps slightly more.

"We’ve got a couple more [rigs] coming, so we maybe go to 95, but that’s really it," Hutton said during last week’s conference call.

Previously, the company had estimated that it might go as high as 100 rigs, he said.

"What we did was basically say, look, there’s some rigs that are drilling in areas where we can’t bring the wells on for three or four or five months. So we just dropped out there."

Range Resources Chairman John Pinkerton has been making a similar case.

After spending about $200 million in 2008 on acquiring new acreage, he said, the company will redirect that money to drilling, which will produce cash flow faster.

Quicksilver Resources President Glenn Darden joined the chorus of getting more from less.

The company was running 14 rigs in the Barnett Shale as of Sept. 30 but has already dropped that to 10 and expects to reduce it to nine by year’s end. And it will run nine rigs in 2009.

The result?

"We will grow production, at a minimum, to 25 percent" companywide, Darden said during the company’s earnings call last week.

And Quicksilver closed its $1.3 billion purchase of properties in the Alliance Airport area during the quarter and is quickly bringing production online from the 13,000 acres that came with that purchase.

The company has 300 sites it expects to drill on that property, Darden said.

There is also widespread sentiment that the cost of drilling each of those wells is coming down and could come down further. For example, Darden said he expects service costs to decline at least 10 percent and as much as 20 percent next year.

"All of this pullback in activity leads inevitably to a better price environment for us," he said. "We are aggressively pursuing better prices on all of our services."

XTO’s Hutton said that, given the softening market, "we might as well wait" on drilling.

"You should hold off on picking up any rigs for three months and pick them up later, because you’re going to catch them at 15 percent less," Hutton said.

Chesapeake’s McClendon agreed, speculating that costs could decline "as much as 15 to 20 percent, and we think it’s already happening today."

Myanmar's Natural Gas Posturing for Trouble

China and India should have restrained Myanmar from sending naval and prospecting vessels this week to a natural-gas-rich patch of the Bay of Bengal that is also claimed by Bangladesh. The tense maritime standoff brought a risk of war between two failed states.

The two Asian powers are the principal export markets for Myanmar's ample natural resources. Like much of sub-Saharan Africa, Myanmar is a focus of intense Chinese efforts to lock up supplies of oil, gas and other commodities. Myanmar's resources can be easily transported to China's burgeoning southwest.

Beijing-backed companies pay their bills on time and don't ask questions about human rights, which is very convenient to one of the world's most repressive regimes.

For its part, India has provided Myanmar with considerable military aid, and Indian companies are racing to match their Chinese counterparts' deals there.

Resource revenues are one of the regime's few sources of income, and help pay the soldiers on whom it relies to put down periodic pro-democracy protests. Last year's demonstrations, which nearly toppled the regime, made the military rulers even more interested in those earnings.

Their decision to provoke Bangladesh, which has no cozy relationship with China or India, shows how far they will go to keep the commodities flowing.

New Delhi and Beijing should not be comfortable with this odious regime. Propping up such a government is a crime against Myanmar's citizens, and in the long run unlikely to benefit either of the great powers of the region.

Myanmar's patrons, which are eager to be seen as responsible international actors, should not have allowed such destabilizing behaviour, China's pious urging of caution on both sides this week notwithstanding.

Adding a conflict with Myanmar to Bangladesh's long list of problems will only further weaken a country that has already begun to produce Islamic militants in worrying quantities, and sits perpetually on the brink of humanitarian catastrophe.

For now, reining Myanmar in from starting a war would be a small but important sign that the two powers will not always accept resources obtained at an immorally high cost.

Pickens Still Pitching Natural Gas & Alternative Energy

It’s the end of a long day and T. Boone Pickens is in the Nashville studio of the RFD Network, surrounded by young members of 4-H clubs and Future Farmers of America.

It seems the 80-year-old billionaire has struck a chord with the young people. “Boone. Boone. Boone,” they chanted.

Maybe he has found recruits for the Pickens Plan Army he’s assembled to back his proposal to start weaning the nation off foreign oil. Pickens and his army want wind farms across the Great Plains to generate electricity, and natural gas to be used as a transportation fuel, reducing the need for oil imports.

But even at a triumphant moment as the recent evening in Tennessee offered, Pickens has far to go. He wants his plan adopted in the first 100 days of the new White House administration. He’s campaigning for it as hard as if he were running for office.

Ruby Natural Gas Pipeline from Colorado to California

LOS ANGELES, Nov 6 (Reuters) - The California Public Utilities Commission on Thursday approved plans by PG&E Corp's (PCG.N: Quote, Profile, Research, Stock Buzz) Pacific Gas & Electric unit to bring Rockies natural gas to California on the $3 billion Ruby Pipeline planned by El Paso Corp (EP.N: Quote, Profile, Research, Stock Buzz).

The 670-mile, 42-inch-diameter Ruby pipeline will run from the Opal hub in Wyoming to the Malin, Oregon, hub near the California-Oregon border. The Ruby line would connect with the PG&E natural gas pipeline system at Malin.

The 15-year agreement calls for PG&E as anchor shipper to get 375 million cubic feet per day of the Ruby's capacity to deliver 1.3 billion to 1.5 billion cubic feet (bcf) per day at Malin. The commission also let the utility recover its costs from retail customers to ship gas on Ruby, as well as its Redwood Path line.

The 15-year pact starts in 2011 or when the proposed Ruby line is ready for operation.

El Paso spokesman Bill Connery said the Ruby is on schedule to open in March 2011. The PG&E share will be about a quarter of the line's capacity. Connery said El Paso is talking with about a dozen independent producers of Rockies gas to fill the line.

The Cal PUC action "is a major milestone for the Ruby project," said Connery, who added that El Paso has companies lined up for almost 1.2 bcf per day on Ruby.

Ruby's construction is not expected to be affected by the current credit crunch because construction is to begin in 2010, when, he said, El Paso hopes availability to credit is not as tight.

"Ultimately, the natural gas pipelines, because they have long-term commitments from shippers, tend to be very attractive from the financing standpoint," Connery said.

El Paso plans to file in January for Federal Energy Regulatory Commission permitting for the Ruby line.

Commissioner Timothy Simon said the Ruby Pipeline-PG&E deal is "in the public interest" and will help keep natural gas and electric rates lower and allow California to diversify its gas supply. The state is heavily reliant on Canadian natural gas, which is declining, Simon said.

In approving PG&E's agreement with El Paso Corp and Ruby Pipeline LLC, the California PUC dismissed an alternate proposal for PG&E to get supply from another proposed project, the Sunstone Pipeline backed by Williams Companies Inc (WMB.N: Quote, Profile, Research, Stock Buzz) and TransCanada Corp (TRP.TO: Quote, Profile, Research, Stock Buzz) and its Gas Transmission Northwest Corp (GTN).

The Sunstone line would be 230 miles longer than the Ruby line and would also bring gas from the Opal hub in Wyoming. (Editing by Christian Wiessner)

CenterPoint Natural Gas Profit

CenterPoint Energy Inc., Houston’s power distributor, said third-quarter profit rose 49 percent after contracts locking in prices in the company’s natural gas business increased in value.

Net income climbed to $136 million, or 39 cents a share, from $91 million, or 27 cents, a year earlier, Houston-based CenterPoint said today in a statement. The company recorded a one-time gain of $46 million to reflect an increase in the valuation of gas contracts.

CenterPoint had profit of $35 million before interest and taxes from gas sales in competitive markets, up from $4 million in 2007’s third quarter. Earnings from gathering and processing gas rose 69 percent to $44 million, and gas utilities had a loss of $6 million, compared with an $8 million loss a year earlier. Interstate pipelines earned $55 million before interest and taxes, down 21 percent.

“They had very strong performance in a couple of the gas units,” said Debra Bromberg, an analyst at Jefferies & Co. in New York who has a “buy” rating on CenterPoint shares and doesn’t own any. She said profit exceeded her estimate.

CenterPoint didn’t provide a figure for earnings excluding one-time costs and gains. Items such as a $46 million gain on gas contracts and a $24 million drop in the value of fuel inventories were quantified before taxes.

The company raised its 2008 earnings forecast to $1.25 to $1.35 a share. The company said previously that per-share profit would be in the upper half of its estimate of $1.15 to $1.25. Third-quarter revenue rose 34 percent to $2.52 billion.

CenterPoint rose 25 cents, or 2.1 percent, to $11.92 at 9:33 a.m. in New York Stock Exchange composite trading. The stock has five buy and three hold ratings from analysts.

Profit from power transmission and distribution rose 3.1 percent to $202 million as the addition of more than 42,000 metered customers made up for the loss of sales caused by Hurricane Ike, which knocked out electricity service to more than 2 million homes and businesses in the Houston area when it struck Texas on Sept. 13.

Devon & Chevron Natural Gas for Stock Swap

Oklahoma City, OK (AHN) - Devon Energy Corporation and Chevron reached an agreement to swap 14.2 million shares of Chevron common stock Devon owned for an interest in a coalbed natural gas field and $280 million in cash.

The transaction gave Devon Energy Corp. (DVN) Chevron's 44 percent interest in the Drunkard's Wash coalbed 51,000 acre natural gas field in east-central Utah.

It produces the equivalent of 40 million cubic feet of natural gas daily.

Oklahoma City-based Devon Energy Corp. is listed in the S&P 500 index and it is the largest U.S.-based independent oil and gas producer.

Appalachian Marcellus Shale Natural Gas Estimates Growing

ALBANY, N.Y. - A geologist says the Marcellus shale region of the Appalachians could yield seven times as much natural gas as he earlier estimated, meaning it could meet the entire nation's natural gas needs for at least 14 years.

Penn State University geoscientist Terry Engelder said in a phone interview Monday that he now estimates 363 trillion cubic feet of natural gas could be recovered over the next few decades from the 31-million-acre core area of the Marcellus region, which includes southern New York, Pennsylvania, West Virginia and eastern Ohio.

Engelder and geologist Gary Lash of the State University of New York at Fredonia touched off a gas rush in the region last January with their study estimating that the Marcellus could yield as much as 50 trillion cubic feet of natural gas.

Geologists have long known about the existence of the Marcellus shale, but exploration there accelerated only recently when the price of natural gas rose high enough to make it economically feasible to use the advanced drilling techniques necessary to produce gas from the hard rock thousands of feet underground.

Production on the Marcellus gas field, or "play," is considered to be in the early stages, but the sheer size of it is drawing heavy interest from the exploration industry.

"It has the potential to be the biggest gas field in the United States," John Pinkerton, chairman and chief executive of Range Resources Corp., said last week in an interview at the Fort Worth, Texas-based company's office in western Pennsylvania.

Engelder first presented his new numbers in Pittsburgh last week at a conference on Appalachian gas sponsored by the energy information firm Platts. He said he based his revised estimate on new figures from Chesapeake Energy Corp., the nation's largest natural gas producer.

Oklahoma-based Chesapeake recently told investors and analysts that each square mile in the Marcellus could contain 30 billion to 150 billion cubic feet of gas. Engelder and Lash initially estimated 9 billion cubic feet per square mile.

Chesapeake also said the thickness of the gas-containing shale ranged from 50 to 300 feet, while Engelder and Lash assumed a thickness of 50 feet.

Applying his own calculations to numbers presented by Chesapeake, Engelder came up with his new estimate of how much gas the region might be able to produce over the next few decades, given enough time and money.

"Geologists are still trying to size this play," Engelder said. "We don't really know how much gas is there and how much can be recovered."

More Kazakh Natural Gas Going to China

BEIJING (XFN-ASIA) - China National Petroleum Corp (CNPC), parent of listed Petrochina Co Ltd (SHA 601857; HK 0857), said it has signed a framework agreement with Kazakhstan's national oil and gas company KazMunaiGaz to expand cooperation in natural gas.

KazMunaiGaz has agreed to ensure the transport of natural gas produced by CNPC from the Aktobe field via phase II of the Kazakhstan-China Gas Pipeline, in addition to supplying five bln cubic meters of natural gas to the pipeline as contracted earlier.

Meanwhile, the two sides will jointly develop the Urikhtau gas condensate field and export 5-10 bln cubic meters of natural gas to China. The exports are subject to the fulfilment of gas demand in southern Kazakhstan, according to a statement published on CNPC's website.

The Beineu-Bozoy-Kyzylorda-Shymkent section of the Kazakhstan-China Gas Pipeline will be constructed and operated jointly by the two companies. The pipeline has natural gas transport capacity of 10 bln cubic meters per year.

In addition, the two companies also agreed to expand phase I of the Kazakhstan-China Gas Pipeline subject to an assessment of incremental natural gas resources.

In a separate statement, the CNPC said it signed an in-principle agreement with Russia's Transneft to build and operate a crude pipeline.

With the establishment of phase I of Russia's Far East pipeline, the two companies will jointly build and operate the Sino-Russia Crude Pipeline which runs from the Siberian city of Skovorodino to Daqing in China, via China's border city of Mohe.

The pipeline is about 70 kilometers long in Russia and 960 kilometers in China.

Rosneft and CNPC will sign a new long-term oil purchase and sale contract after the completion of the pipeline.

China and Russia will formally sign a contract within the year detailing the timetable for pipeline construction. The agreement also provides for long term cooperation in the trading of crude and the integration of upstream and downstream businesses, CNPC said.

The two sides will also further promote joint exploration and development in Russia, as well as the establishment of a joint venture refinery in China, it added, without providing details.

Egyptian Natural Gas to Lebanon

BEIRUT, Nov. 1 (Xinhua) -- Lebanese Energy and Water Minister Alan Tabourian said natural gas shipments to be used for electricity production, will begin to arrive from Egypt to Lebanon at the beginning of 2009, local Daily Star reported Saturday.

"Egypt assured us that Lebanon will receive natural gas at the beginning of 2009 and would supply it until 2013," he said on Friday.

Importing electricity from Egypt was too expensive, and "simply too high for Lebanon," said Tabourian.

The Lebanese government hopes to reduce the national energy bill by 30 percent by switching from oil to natural gas.

Successive governments in the past have failed to deal with the power sector's problems despite studies by international agencies, the report said.

The International Monetary Fund and donor countries are pressing the Lebanese government to find a radical solution for the electricity crisis, linking any future funds to reforms in this sector.

New York Natural Gas Ends Week on High Note

Natural gas in New York rose for the third time in four days as lower temperatures next week may boost demand for the heating fuel. Prices surged in the final 30 minutes of trading as heating oil, a competing fuel, jumped with the contract’s expiration.

Fuel use may increase as overnight temperatures in Chicago next week dip to 24 degrees, about 13 degrees below normal, AccuWeather.com of State College, Penn., predicted today. About 72 percent of homes in the Midwest rely on gas for heat.

“It’s hard for people to take a bearish attitude in a market where it’s half the price it was in July,” said Peter Beutel, president of energy consultant Cameron Hanover Inc. in New Canaan, Connecticut. “We’re coming into the peak demand season.”

Natural gas for December delivery rose 35.2 cents, or 5.5 percent, to settle at $6.783 per million British thermal units at 3:18 p.m. on the New York Mercantile Exchange. Prices reached their high for the year of $13.694 per million Btu on July 2. The futures dropped 8.8 percent this month and are down 19 percent from a year ago.

The expiration of the October heating oil and gasoline futures contracts at the close of floor trading today prompted buying in other energy markets, said John Kilduff, senior vice president of risk management at MF Global Inc. in New York.

“Ten cents is a pretty big move for expiring contracts; we saw similar with crude mid-month,” he said. “It’s got people short covering on all fronts. It has been so bearish that there was a bit of a scare put in the market and people cycled out of short positions.”

A speculative short is a bet that prices will decline. Crude oil, gasoline, natural gas and heating oil all began rising at about 2 p.m. New York time.

Below-normal temperatures are probable in the Chicago area starting Nov. 5, according to the Climate Prediction Center in Camp Springs, Md.

U.S. gas inventory gains in a government report next week may be limited to 30 billion to 40 billion cubic feet, said Martin King, an analyst at FirstEnergy Capital Corp. in Calgary. King said he had expected an increase of between 40 billion and 50 billion cubic feet before colder weather was predicted.

“Weather forecasts have shifted to be a little more bullish,” King said. “As far as I can tell from the pipeline data being posted, we could be looking at a fairly small build.”

The Energy Department said Thursday that U.S. inventories totaled 3.393 trillion cubic feet in the week ended Oct. 24, higher than the five-year average at the start of the cold- weather season.

Supplies typically rise until early November, when demand increases with colder weather.

“It’s a little dangerous to take a short position in here, given the illiquidity of the market,” said Tom Orr, research director at Weeden & Co. in Greenwich, Conn. “You could get a cold shot at any time and be back above $7.”

Hedge funds and other large speculators have sold positions as the financial crisis prompted investors to reduce their risk and move into cash holdings, said Orr.

“Everybody I talk to at the hedge funds says they’re all in cash,” Orr said. “Everyone is in a holding pattern. No one is trading.”