By Gaurav Singh
June 30 (Bloomberg) -- Coal India Ltd. short-listed ArcelorMittal, the world’s biggest steelmaker, and nine other companies to develop its abandoned mines to help ease a shortage of the fuel in the country.
State-owned Coal India is offering 18 of its abandoned mines for development, Chairman Partha S. Bhattacharyya said by telephone, confirming a report in the Business Standard newspaper today. The offered mines hold combined reserves of 1.6 billion metric tons, Bhattacharyya said.
Finding partners for the mines may help Coal India, the country’s monopoly miner, raise production by 29 percent within three years and allow the nation to avoid costly imports to meet the fuel needs of power plants. India aims to add 13,000 megawatts of new capacity every year, President Pratibha Patil told parliament June 4.
“Our portion of the equity will largely be the mines,” Bhattacharyya said. “The partners can have 50 percent of the coal provided they have customers in the country.”
Rio Tinto Group, JSW Steel Ltd., GVK Power & Infrastructure Ltd. and Essar Mineral Resources Ltd. were also short-listed, according to the Business Standard report. Ian Head, a spokesman for Rio Tinto, wasn’t immediately available when contacted by Bloomberg at his Melbourne office.
Coal India aims to complete the bidding process by the year-end and will offer as much as half of the equity in the ventures to its partners, Bhattacharyya said. The company invited separate bids for the mines, owned by three of its units, he said.
Coal Shortages
India’s coal shortage will be about 228 million tons by the year ending March 2012, J. Goel, chief general manager of sales and marketing at Coal India, said on Feb. 24. Demand is estimated to reach 731 million tons a year by then, according to government estimates.
Coal India produced 403.7 million tons of the fuel in the year that ended March, data on the company’s Web site show. The company signed a 20-year agreement on May 29 to supply fuel to the coal-fired plants of NTPC Ltd., India’s biggest power producer.
To contact the reporter on this story: Gaurav Singh in New Delhi at gsingh31@bloomberg.net
Tuesday, June 30, 2009
Natural Gas Pipeline Control Switches Owners
June 30, 2009 - 7:11AM
Enterprise Products Partners LP will acquire Teppco Partners LP in a sweetened all-stock deal worth about $US3.3 billion ($4.09 billion), forming what the two pipeline operators say will be the nation's largest publicly traded energy partnership.
The new partnership, announced on Monday and expected to close by year's end, will have operations throughout the US, on the east, west and gulf coasts.
Keeping the name Enterprise Products Partners, it will own nearly 77,000km of crude and natural gas pipelines; 200 million barrels of storage capacity for natural gas liquids, crude and refined products; and 27 billion cubic feet of natural gas storage capacity.
It also will control one of the largest US terminals for natural gas liquids in the Houston Ship Channel.
In a conference call on Monday to discuss the deal, Randy Fowler, chief financial officer for Enterprise, said the combined entity will have an equity market capitalisation of about $US14 billion ($17.36 billion). He said the combination creates a portfolio of largely fee-based operations with a broad geographic footprint.
"The larger scale translates into more sources of cash flow," Fowler said.
Teppco, which had seen its stock value tumble along with the price of oil and natural gas, had rejected a bid for $US2.8 billion ($3.47 billion) earlier this year. The new offer represents a 9.3 per cent premium to Teppco's closing price on Friday.
The combined company will provide some stability in what has become an extraordinarily volatile oil and gas market.
"We're largely a fee-based company," said Rick Rainey, a spokesman for both Enterprise and Teppco. "Whether the price of gasoline is $US2 (a gallon) at pump, or $US4 a pump, we get the same amount of money to ship it."
The deal creates an enormous transportation and storage network and will lead to $US20 million ($24.8 million) in savings, the companies said. Enterprise will bring together the oil and gas operations of Texas billionaire Dan Duncan, whose Enterprise GP Holdings LP owns the general partners that control both Enterprise and Teppco.
Enterprise and Teppco are both master limited partnerships, or MLPs, which trade publicly but don't pay corporate income taxes. They rely on assets that generate cash flow - in this case pipelines and storage facilities - and distribute profits to shareholders.
Teppco shareholders will receive 1.24 Enterprise common shares for each Teppco share, a 14.5 per cent premium to the initial offer made by Enterprise on March 9.
Teppco Partners LP and its general partner, Texas Eastern Products Pipeline Co. LLC, will become wholly owned subsidiaries of Enterprise. Teppco said its shareholders should benefit from the combination through a lower cost of capital and improved access to capital markets.
http://business.smh.com.au/business/enterprise-to-buy-teppco-in-us33b-allstock-deal-20090630-d2rr.html
Enterprise Products Partners LP will acquire Teppco Partners LP in a sweetened all-stock deal worth about $US3.3 billion ($4.09 billion), forming what the two pipeline operators say will be the nation's largest publicly traded energy partnership.
The new partnership, announced on Monday and expected to close by year's end, will have operations throughout the US, on the east, west and gulf coasts.
Keeping the name Enterprise Products Partners, it will own nearly 77,000km of crude and natural gas pipelines; 200 million barrels of storage capacity for natural gas liquids, crude and refined products; and 27 billion cubic feet of natural gas storage capacity.
It also will control one of the largest US terminals for natural gas liquids in the Houston Ship Channel.
In a conference call on Monday to discuss the deal, Randy Fowler, chief financial officer for Enterprise, said the combined entity will have an equity market capitalisation of about $US14 billion ($17.36 billion). He said the combination creates a portfolio of largely fee-based operations with a broad geographic footprint.
"The larger scale translates into more sources of cash flow," Fowler said.
Teppco, which had seen its stock value tumble along with the price of oil and natural gas, had rejected a bid for $US2.8 billion ($3.47 billion) earlier this year. The new offer represents a 9.3 per cent premium to Teppco's closing price on Friday.
The combined company will provide some stability in what has become an extraordinarily volatile oil and gas market.
"We're largely a fee-based company," said Rick Rainey, a spokesman for both Enterprise and Teppco. "Whether the price of gasoline is $US2 (a gallon) at pump, or $US4 a pump, we get the same amount of money to ship it."
The deal creates an enormous transportation and storage network and will lead to $US20 million ($24.8 million) in savings, the companies said. Enterprise will bring together the oil and gas operations of Texas billionaire Dan Duncan, whose Enterprise GP Holdings LP owns the general partners that control both Enterprise and Teppco.
Enterprise and Teppco are both master limited partnerships, or MLPs, which trade publicly but don't pay corporate income taxes. They rely on assets that generate cash flow - in this case pipelines and storage facilities - and distribute profits to shareholders.
Teppco shareholders will receive 1.24 Enterprise common shares for each Teppco share, a 14.5 per cent premium to the initial offer made by Enterprise on March 9.
Teppco Partners LP and its general partner, Texas Eastern Products Pipeline Co. LLC, will become wholly owned subsidiaries of Enterprise. Teppco said its shareholders should benefit from the combination through a lower cost of capital and improved access to capital markets.
http://business.smh.com.au/business/enterprise-to-buy-teppco-in-us33b-allstock-deal-20090630-d2rr.html
Monday, June 29, 2009
Natural Gas Business for Honeywell
(RTTNews) - Diversified manufacturer Honeywell International Inc. (HON: News ) said Thursday that it has agreed to buy the Germany-based RMG Group, comprising of RMG Regel + Messtechnik GmbH and all of its subsidiaries, in a deal valued at about US$400 million.
RMG, which specializes in the design and manufacture of natural gas control, measurement and analysis equipment including flow metering technology, regulating products and safety devices for oil and gas companies, has estimated 2009 sales to be US$290 million.
Morristown, New Jersey-based Honeywell said the acquisition will build its presence particularly in the areas of natural gas transportation, storage, distribution and industrial consumption.
RMG aligns strongly with Honeywell's field instrumentation and control solutions. RMG's gas flow meters and regulating devices complement Honeywell's pressure and temperature transmitters as well as liquid natural gas level gauges.
RMG, which specializes in the design and manufacture of natural gas control, measurement and analysis equipment including flow metering technology, regulating products and safety devices for oil and gas companies, has estimated 2009 sales to be US$290 million.
Morristown, New Jersey-based Honeywell said the acquisition will build its presence particularly in the areas of natural gas transportation, storage, distribution and industrial consumption.
RMG aligns strongly with Honeywell's field instrumentation and control solutions. RMG's gas flow meters and regulating devices complement Honeywell's pressure and temperature transmitters as well as liquid natural gas level gauges.
Sunday, June 28, 2009
Russia Invites Shell for Sak3 and Sak4 Natural Gas
NOVO-OGARYOVO, Russia : Russian Prime Minister Vladimir Putin on Saturday invited Shell to participate in two new natural gas projects during a meeting with the Anglo-Dutch company's chief executive.
"I think it is fully possible to pursue cooperation further with Shell in other projects, such as Sakhalin-3 and Sakhalin-4," Putin said.
"Your work is successful and I thank you for that," the premier added. "It is not only successful but also ahead of schedule."
Shell's Jeroen van der Veer welcomed Putin's offer, calling it an "ideal time" to consider future energy projects in Russia.
"We are ready to move quickly," he told Putin.
Shell partnered with Russian gas giant Gazprom to launch Russia's first liquefied natural gas plant in February on the Pacific island in Russia's Far East.
In late 2006, Shell was essentially sidelined from the 22-billion-dollar (16-billion-euro) Sakahlin-2 plant, forced to sell its controlling stake in the project under Russian state pressure.
But Putin played down the troubled history of Shell's upstream investment in Russia on Saturday.
"Shell has been working in Russian for over 100 years," he said. "Today, Shell is present in many sectors... The most important contract being Sakhalin in which you have almost a 30 percent stake."
He said contracts handed out by Shell to Russian companies had amounted to 12 billion dollars, aiding development in the regions.
Shell signed an array of accords to partner with Sovcomflot, which owns Russia's largest shipping fleet, for the future construction of an LNG plant on the Yamal peninsula in northwest Siberia and transport of oil and gas from Russia's Arctic fields.
The Yamal peninsula in northern Russia is estimated to hold gas reserves of 5.9 trillion cubic metres, and Gazprom has set development of the region as a top priority as production at its current Soviet-era fields begins to decline.
Russia has said it wants to develop its LNG capacity to diversify away from pipeline-reliant exports to Europe and place more emphasis on new Asian and US markets.
"These are very serious documents. It allows not only to put use to Sovcomflot's vessels, but to think on the development of our competencies in the construction of tankers, which will be needed in the near future," Putin said.
Shell has owned a 27.5 percent stake in the Sakhalin Energy project since its sale to Gazprom in 2006 gave the state monopoly a 51 percent share in the project.
The Gazprom takeover was widely seen as a Kremlin-orchestrated move to regain control over the exploitation of the country's energy resources.
Sakhalin Island, on Russia's pacific border near Japan, sits atop a massive 45 million barrels in oil and gas reserves, according to estimates.
http://www.channelnewsasia.com/stories/afp_world_business/view/438942/1/.html
- AFP /ls
"I think it is fully possible to pursue cooperation further with Shell in other projects, such as Sakhalin-3 and Sakhalin-4," Putin said.
"Your work is successful and I thank you for that," the premier added. "It is not only successful but also ahead of schedule."
Shell's Jeroen van der Veer welcomed Putin's offer, calling it an "ideal time" to consider future energy projects in Russia.
"We are ready to move quickly," he told Putin.
Shell partnered with Russian gas giant Gazprom to launch Russia's first liquefied natural gas plant in February on the Pacific island in Russia's Far East.
In late 2006, Shell was essentially sidelined from the 22-billion-dollar (16-billion-euro) Sakahlin-2 plant, forced to sell its controlling stake in the project under Russian state pressure.
But Putin played down the troubled history of Shell's upstream investment in Russia on Saturday.
"Shell has been working in Russian for over 100 years," he said. "Today, Shell is present in many sectors... The most important contract being Sakhalin in which you have almost a 30 percent stake."
He said contracts handed out by Shell to Russian companies had amounted to 12 billion dollars, aiding development in the regions.
Shell signed an array of accords to partner with Sovcomflot, which owns Russia's largest shipping fleet, for the future construction of an LNG plant on the Yamal peninsula in northwest Siberia and transport of oil and gas from Russia's Arctic fields.
The Yamal peninsula in northern Russia is estimated to hold gas reserves of 5.9 trillion cubic metres, and Gazprom has set development of the region as a top priority as production at its current Soviet-era fields begins to decline.
Russia has said it wants to develop its LNG capacity to diversify away from pipeline-reliant exports to Europe and place more emphasis on new Asian and US markets.
"These are very serious documents. It allows not only to put use to Sovcomflot's vessels, but to think on the development of our competencies in the construction of tankers, which will be needed in the near future," Putin said.
Shell has owned a 27.5 percent stake in the Sakhalin Energy project since its sale to Gazprom in 2006 gave the state monopoly a 51 percent share in the project.
The Gazprom takeover was widely seen as a Kremlin-orchestrated move to regain control over the exploitation of the country's energy resources.
Sakhalin Island, on Russia's pacific border near Japan, sits atop a massive 45 million barrels in oil and gas reserves, according to estimates.
http://www.channelnewsasia.com/stories/afp_world_business/view/438942/1/.html
- AFP /ls
Saturday, June 27, 2009
Rig Count at 843 for Natural Gas
NEW YORK, June 26 (Reuters) - The number of rigs drilling for natural gas in the United States resumed its downward track, falling 5 to 687 this week, according to a report on Friday by oil services firm Baker Hughes in Houston.
U.S. natural gas drilling rigs have been in a mostly steady decline since peaking above 1,600 in September, but last week the count unexpectedly rose by 7 to 692, the first gain since November 2008.
Sources said new rigs in some prolific shale plays, such as Haynesville in Louisiana or Marcellus in Appalachia, may have been the reason for the unexpected gain.
The number of operating gas rigs now stands at 843 rigs, or 55 percent, below the same week last year, when there were some 1,530 active rigs looking for gas.
Near record-high gas production last year and a deep recession that sharply cut demand led to a severe oversupply that pressured gas prices this spring below the $4 per mmBtu level from their peak above $13 last July.
The 75 percent slide in natural gas prices over the past 11 months and tighter access to credit have forced many producers to scale back drilling operations.
With the natural gas drilling rig count still below 700, most analysts expect to see year-on-year output declines soon, probably early this summer, which should help tighten the overall supply-demand balance. (Reporting by Joe Silha; Editing by Walter Bagley)
U.S. natural gas drilling rigs have been in a mostly steady decline since peaking above 1,600 in September, but last week the count unexpectedly rose by 7 to 692, the first gain since November 2008.
Sources said new rigs in some prolific shale plays, such as Haynesville in Louisiana or Marcellus in Appalachia, may have been the reason for the unexpected gain.
The number of operating gas rigs now stands at 843 rigs, or 55 percent, below the same week last year, when there were some 1,530 active rigs looking for gas.
Near record-high gas production last year and a deep recession that sharply cut demand led to a severe oversupply that pressured gas prices this spring below the $4 per mmBtu level from their peak above $13 last July.
The 75 percent slide in natural gas prices over the past 11 months and tighter access to credit have forced many producers to scale back drilling operations.
With the natural gas drilling rig count still below 700, most analysts expect to see year-on-year output declines soon, probably early this summer, which should help tighten the overall supply-demand balance. (Reporting by Joe Silha; Editing by Walter Bagley)
Friday, June 26, 2009
Natural Gas Speculation in British Columia, Canada
Alberta is lagging behind British Columbia in terms of oil and gas land sales for the year, as companies in search of the next big play flock to that province.
One week ago, British Columbia had the ninth biggest oil and gas land rights sale in its history, amassing more than $178 million in bonus bids in the monthly auction – triple the combined total for the last five sales.
Eight of the bids in the June 17 sale were on parcels of land in the Horn River Basin, north of Fort Nelson, for a total of $173 million.
Comparatively, in Alberta’s June 10 land rights sale, 66 parcels of land were bid on in northern Alberta, including the Peace Country, for a total of more than $5.6 million.
So far in 2009, bids were made on 1,057 parcels of land in northern Alberta, netting more than $66 million, less than half of last week’s B.C. sale alone.
The next provincial land rights sale takes place today.
In the B.C. sale, companies paid between $2,100 and $11,765 per hectare; in Alberta the average price this year per hectare is $144.27.
But regardless of the numbers, the province says it remains confident in the future of its petroleum industry.
“There’s certainly an interest in the play that’s going on in northeastern B.C. and whenever something like this occurs – when there’s a big play – there’s a rush to the epicentre,” Alberta Energy department spokesman Bob McManus said from Edmonton.
“But that play will extend to Alberta in time. We’re confident that there will be activity in Alberta as a result of that play, portions of it do extend across the border into Alberta.”
But Kevin Rathburn, vice-president of the Grande Prairie Petroleum Association, said that in addition to the popularity of the Horn River natural gas play, the new provincial royalty framework implemented on Jan. 1 is discouraging companies from the province.
“I would say it’s probably the royalty scheme. It’s cheaper in B.C. to drill, you get more money back, our royalties are higher so there’s less (activity here),” Rathburn said.
“It’s just cheaper for them. They get a better return on the dollar with the lower royalties.”
Low natural gas prices, currently at less than $4 a gigajoule, are also affecting where companies decide to set up shop, he said.
“We (Grande Prairie) are in a mature field, so there’s going to be a rush for a new, hot play,” he said. “And there’s still going to be lots more infield drilling in the Grande Prairie area, but not at $3.90 per gigajoule. At that price they can’t make any money out of it.”
However, McManus said incentives introduced by Energy Minister Mel Knight in March are attractive for companies. The province is offering a $200-per-metre royalty credit to companies that drill new wells between April 1 and March 31, 2010.
In addition, a five per cent royalty rate will also be levied on the first year of production from wells drilled during that time period – a substantial amount less than the royalty regime that came into effect on Jan. 1.
“We have royalty schemes in place here in Alberta which are very attractive, certainly especially in terms of deep wells, so we feel that we are very competitive from that point of view,” McManus said.
“Right now especially, many wells which are operating in Alberta are paying lower royalties than they would in British Columbia or in Saskatchewan.”
For his part, B.C. Energy Minister Blair Lekstrom said last week’s land rights sale demonstrated that oil and gas companies are confident in the province’s future.
“I think it shows investor confidence in our province and in what we’ve been able to accomplish here through our regulatory regime, through the royalty incentive programs we’ve set,” Lekstrom said from Victoria.
Asked if B.C. has been actively courting companies leery of Alberta’s new royalty framework, Lekstrom said the province has been focusing on what it can do from within its own borders.
“We’re focused on what we have to offer, not on what others have done or haven’t done,” he said. “We’ve made it very clear at the beginning we have some ideas on what we’d like to do to attract investors and their capital to come to our province.”
rzaccagna@bowesnet.com
One week ago, British Columbia had the ninth biggest oil and gas land rights sale in its history, amassing more than $178 million in bonus bids in the monthly auction – triple the combined total for the last five sales.
Eight of the bids in the June 17 sale were on parcels of land in the Horn River Basin, north of Fort Nelson, for a total of $173 million.
Comparatively, in Alberta’s June 10 land rights sale, 66 parcels of land were bid on in northern Alberta, including the Peace Country, for a total of more than $5.6 million.
So far in 2009, bids were made on 1,057 parcels of land in northern Alberta, netting more than $66 million, less than half of last week’s B.C. sale alone.
The next provincial land rights sale takes place today.
In the B.C. sale, companies paid between $2,100 and $11,765 per hectare; in Alberta the average price this year per hectare is $144.27.
But regardless of the numbers, the province says it remains confident in the future of its petroleum industry.
“There’s certainly an interest in the play that’s going on in northeastern B.C. and whenever something like this occurs – when there’s a big play – there’s a rush to the epicentre,” Alberta Energy department spokesman Bob McManus said from Edmonton.
“But that play will extend to Alberta in time. We’re confident that there will be activity in Alberta as a result of that play, portions of it do extend across the border into Alberta.”
But Kevin Rathburn, vice-president of the Grande Prairie Petroleum Association, said that in addition to the popularity of the Horn River natural gas play, the new provincial royalty framework implemented on Jan. 1 is discouraging companies from the province.
“I would say it’s probably the royalty scheme. It’s cheaper in B.C. to drill, you get more money back, our royalties are higher so there’s less (activity here),” Rathburn said.
“It’s just cheaper for them. They get a better return on the dollar with the lower royalties.”
Low natural gas prices, currently at less than $4 a gigajoule, are also affecting where companies decide to set up shop, he said.
“We (Grande Prairie) are in a mature field, so there’s going to be a rush for a new, hot play,” he said. “And there’s still going to be lots more infield drilling in the Grande Prairie area, but not at $3.90 per gigajoule. At that price they can’t make any money out of it.”
However, McManus said incentives introduced by Energy Minister Mel Knight in March are attractive for companies. The province is offering a $200-per-metre royalty credit to companies that drill new wells between April 1 and March 31, 2010.
In addition, a five per cent royalty rate will also be levied on the first year of production from wells drilled during that time period – a substantial amount less than the royalty regime that came into effect on Jan. 1.
“We have royalty schemes in place here in Alberta which are very attractive, certainly especially in terms of deep wells, so we feel that we are very competitive from that point of view,” McManus said.
“Right now especially, many wells which are operating in Alberta are paying lower royalties than they would in British Columbia or in Saskatchewan.”
For his part, B.C. Energy Minister Blair Lekstrom said last week’s land rights sale demonstrated that oil and gas companies are confident in the province’s future.
“I think it shows investor confidence in our province and in what we’ve been able to accomplish here through our regulatory regime, through the royalty incentive programs we’ve set,” Lekstrom said from Victoria.
Asked if B.C. has been actively courting companies leery of Alberta’s new royalty framework, Lekstrom said the province has been focusing on what it can do from within its own borders.
“We’re focused on what we have to offer, not on what others have done or haven’t done,” he said. “We’ve made it very clear at the beginning we have some ideas on what we’d like to do to attract investors and their capital to come to our province.”
rzaccagna@bowesnet.com
Thursday, June 25, 2009
U.S. Natural Gas Supplies are Ample
NEW YORK (Dow Jones)--Natural-gas futures fell Wednesday along with other energy commodities amid a glut of natural gas and predictions for another large storage injection.
Natural gas for July delivery on the New York Mercantile Exchange was trading 8.9 cents lower, or 2.29%, at $3.79 a million British thermal units. The contract fell as low as $3.759/MMBtu in earlier trading.
Ample stocks of natural gas were helping mitigate forecasts for hot weather and an expected increase in demand for natural gas-fired power to cool homes and businesses.
"The heat is being somewhat ignored," said Lisa Zembrodt, commodity analyst of Louisville, Ky.,-based Summit Energy. "No matter how you look at it, there's gas out there to meet demand."
Zembrodt added the market is likely to track crude oil and related energy products until the gas market gets some "solid direction" from the storage report on Thursday.
The amount of gas in storage as of June 12 totaled 2.557 trillion cubic feet - about a third higher than last year and 22.6% above the five-year average. Traders are expecting another large injection on Thursday, providing yet another bearish consideration for the market.
The Energy Information Administration is due to release its weekly natural gas storage report at 10:30 a.m. E.T. on Thursday.
Jim Ritterbusch, president of the energy advisory firm Ritterbusch and Associates, is expecting a 100 bcf storage injection. "Although such a build would be downsized considerably from the prior week, we also feel that the psychological impact of a sixth consecutive triple digit storage increase would be considerable," he wrote in a note.
Ritterbusch said that slowing the mounting storage surplus this summer will require some supply disruptions as a result of hurricane activity.
The National Weather Service forecast forecast for June 29 to July 3 calls for warmer-than-normal temperatures across Texas, the Midwest and the Great Plains. Below-normal temperatures are expected in parts of the Northeast.
-By Veronica Dagher and Jason Womack, Dow Jones Newswires; 212-416-2143; veronica. dagher@dowjones.com
Natural gas for July delivery on the New York Mercantile Exchange was trading 8.9 cents lower, or 2.29%, at $3.79 a million British thermal units. The contract fell as low as $3.759/MMBtu in earlier trading.
Ample stocks of natural gas were helping mitigate forecasts for hot weather and an expected increase in demand for natural gas-fired power to cool homes and businesses.
"The heat is being somewhat ignored," said Lisa Zembrodt, commodity analyst of Louisville, Ky.,-based Summit Energy. "No matter how you look at it, there's gas out there to meet demand."
Zembrodt added the market is likely to track crude oil and related energy products until the gas market gets some "solid direction" from the storage report on Thursday.
The amount of gas in storage as of June 12 totaled 2.557 trillion cubic feet - about a third higher than last year and 22.6% above the five-year average. Traders are expecting another large injection on Thursday, providing yet another bearish consideration for the market.
The Energy Information Administration is due to release its weekly natural gas storage report at 10:30 a.m. E.T. on Thursday.
Jim Ritterbusch, president of the energy advisory firm Ritterbusch and Associates, is expecting a 100 bcf storage injection. "Although such a build would be downsized considerably from the prior week, we also feel that the psychological impact of a sixth consecutive triple digit storage increase would be considerable," he wrote in a note.
Ritterbusch said that slowing the mounting storage surplus this summer will require some supply disruptions as a result of hurricane activity.
The National Weather Service forecast forecast for June 29 to July 3 calls for warmer-than-normal temperatures across Texas, the Midwest and the Great Plains. Below-normal temperatures are expected in parts of the Northeast.
-By Veronica Dagher and Jason Womack, Dow Jones Newswires; 212-416-2143; veronica. dagher@dowjones.com
Wednesday, June 24, 2009
Natural Gas Pipeline for Wyoming-Oregon FER Approved
Wyoming-Oregon Gas Pipeline Clears Regulatory Hurdle
BY ETHAN LINDSEY
Bend, OR June 23, 2009 2:47 p.m.
http://news.opb.org/article/5282-wyoming-oregon-gas-pipeline-clears-regulatory-hurdle/
A 680-mile natural gas pipeline between Wyoming and Oregon cleared a major governmental hurdle this week.
The Federal Energy Regulatory Commission signed off on a preliminary environmental report for the Ruby Pipeline.
Central Oregon correspondent Ethan Lindsey reports.
The proposed pipeline would run from southwest Wyoming, through Utah and Nevada, and then cross into Oregon near Lakeview.
Houston’s El Paso Corp. says the project is key to expanding natural gas exports to California and the west.
Brent Fenty is with the Oregon Natural Desert Association. He says, originally, environmentalists objected to the pipeline crossing through the Sheldon National Wildlife Refuge in Nevada.
Brent Fenty: “You know, my understanding is that they have adjusted the pipeline route to avoid impacts on the refuge.”
Fenty says he remains concerned about sage grouse habitat and pronghorn migration.
The federal energy draft report found the project would have adverse environmental impacts but most could be mitigated by the company.
Developers say they want to have the pipeline flowing by March of 2011.
BY ETHAN LINDSEY
Bend, OR June 23, 2009 2:47 p.m.
http://news.opb.org/article/5282-wyoming-oregon-gas-pipeline-clears-regulatory-hurdle/
A 680-mile natural gas pipeline between Wyoming and Oregon cleared a major governmental hurdle this week.
The Federal Energy Regulatory Commission signed off on a preliminary environmental report for the Ruby Pipeline.
Central Oregon correspondent Ethan Lindsey reports.
The proposed pipeline would run from southwest Wyoming, through Utah and Nevada, and then cross into Oregon near Lakeview.
Houston’s El Paso Corp. says the project is key to expanding natural gas exports to California and the west.
Brent Fenty is with the Oregon Natural Desert Association. He says, originally, environmentalists objected to the pipeline crossing through the Sheldon National Wildlife Refuge in Nevada.
Brent Fenty: “You know, my understanding is that they have adjusted the pipeline route to avoid impacts on the refuge.”
Fenty says he remains concerned about sage grouse habitat and pronghorn migration.
The federal energy draft report found the project would have adverse environmental impacts but most could be mitigated by the company.
Developers say they want to have the pipeline flowing by March of 2011.
Tuesday, June 23, 2009
Marcellus Natural Gas Play for Williams
STATE COLLEGE, Pa. -- Natural gas company Williams said Monday that it will pay $33 million for half of Rex Energy's interest in three Pennsylvania counties to develop natural gas wells in the Marcellus Shale.
Tulsa, Okla.-based Williams will earn its 50 percent interest by incurring 90 percent of the costs associated with drilling and completing wells until it has invested $33 million on behalf of Rex and $41 million in its own costs and expenses. Williams has until the end of 2011 to fulfill its funding obligations.After that investment, the companies will share the costs.
State College-based Rex has leases on 44,000 acres in Westmoreland, Clearfield and Centre counties.
The deal is Williams' second recent transaction in the Marcellus Shale, a massive area that spans from northern West Virginia, much of Pennsylvania and into New York. On June 1, Williams entered a midstream joint venture that owns 1,800 miles of intrastate natural gas gathering lines servicing 6,900 Appalachian Basin wells.Rex also announced that it has closed the deal to acquire the 50 percent stake owned by its joint venture partner of property in Butler County, Pa., for $4.2 million.
Tulsa, Okla.-based Williams will earn its 50 percent interest by incurring 90 percent of the costs associated with drilling and completing wells until it has invested $33 million on behalf of Rex and $41 million in its own costs and expenses. Williams has until the end of 2011 to fulfill its funding obligations.After that investment, the companies will share the costs.
State College-based Rex has leases on 44,000 acres in Westmoreland, Clearfield and Centre counties.
The deal is Williams' second recent transaction in the Marcellus Shale, a massive area that spans from northern West Virginia, much of Pennsylvania and into New York. On June 1, Williams entered a midstream joint venture that owns 1,800 miles of intrastate natural gas gathering lines servicing 6,900 Appalachian Basin wells.Rex also announced that it has closed the deal to acquire the 50 percent stake owned by its joint venture partner of property in Butler County, Pa., for $4.2 million.
Monday, June 22, 2009
Natural Gas Doesn't Water Hurt Marcellus Shale Area
RUSS WEGE
http://www.dailygazette.com/news/2009/jun/21/0621_wege/
My career aspirations led me to study petroleum engineering in the 1950s. Upon graduation, I was employed by an energy company in the Southwest. It took years to develop an understanding of the problems concerning oil and gas production. Eventually, I became fairly proficient, and was involved in designing and performing fracture treatments of oil and gas reservoirs in order to increase production.
A Viewpoint column by Patricia O’Reilly Rush, on June 14, suggests that hydrofracturing of the Marcellus Shale for development of natural gas resources would endanger water supply resources.
This simply would not occur.
Need for facts
Since very few people in the Northeast have had experience with well stimulation, I believe your readers should have a better understanding of the facts before forming an opinion on this aspect of energy development.
Although oil production was first developed in Titusville, Pa., in 1859, the national search for oil energy began after the Spindletop discovery in East Texas during 1901.
Oil and gas reservoirs deplete over time. Often, a well can be stimulated to produce at a greater rate. Initially, well stimulation was achieved by the very dangerous procedure of placing several gallons of nitroglycerine opposite the oil-bearing formation. Upon detonation, the well bore would be increased from perhaps seven inches to two to three feet. The greater exposed surface area would allow increased flow into the well bore, which produced well stimulation.
The introduction of breaking oil and gas reservoirs using hydraulic pressure began in the 1940s. Initially, only a few hundred gallons of oil was used to crack the reservoir rock and stimulate the well. This technique was better than using nitroglycerine, and certainly was safer, but the procedure left something to be desired.
The thinking was that the crack that was propagated by hydraulic pressure immediately “healed” after the pressure was released. This problem was solved by adding sand to the hydraulic fluid. The sand would flow into the cracked reservoir rock, propping the crack open, in effect, greatly increasing the diameter of the well bore and stimulating oil or gas production.
The “frac” treatment technology is very successful and has been used countless times over the past 60 years to stimulate oil and gas reservoirs around the world.
During the early days of the oil industry, natural gas was considered a waste product and was often flared. Eventually, inexpensive natural gas began to displace manufactured gas in our cities. The demand for natural gas rapidly grew, and is still growing. Energy companies soon began to develop natural gas reserves.
The energy industry has long known there were vast quantities of oil and gas reserves in very low permeability or “tight” rock formations. Such deposits are in the oil shales of the Rocky Mountains, the tar sands in Canada, and natural gas in the Marcellus Shale in the Northeast.
The days of cheap energy are over. Domestic oil production peaked in the 1970s. Imported oil to meet our national needs now approaches 75 percent.
Congress should not have allowed this to happen, but it did. The good news is that the United States has massive coal reserves. The bad news is that coal does not burn as cleanly as natural gas and the Obama administration is making moves to diminish — if not shut down, this needed source of energy.
Natural gas burns very cleanly and we are producing about 87 percent of our needs, with the remainder coming from Canada. We must continue to develop additional gas reserves. Therefore, the vast gas reserves locked into the “tight” Marcellus Shale must be developed. Directional drilling into this massive shale formation exposes additional length of this gas-bearing reservoir to production and improved fracturing techniques opens up this valuable resource for decades of reliable production.
Rush’s recent Viewpoint column suggests fracture treatments of this resource will threaten water supplies, and she urges that development of this needed resource be terminated. The possibility of “frac” fluids contaminating water supplies is simply zero. I have never heard of a “frac” treatment ever adversely affecting another formation — let alone reaching the surface to pollute a stream!
What happens after a huge injection of water into a well is a backflow of water following the treatment. The backflow may last for weeks but it will end. The chemicals that concern Rush reduce pipe friction and carry the propping agent, such as sand, that keeps the fracture open.
No reason to stop
Treatment of the backflow should be a permit condition and not a reason to condemn the effort to develop this resource.
Finally, well treatments that involve the use of millions of gallons of water may be a concern to regulators and riparian interests, but can be addressed through the well permit system issued by the state Department of Environmental Conservation.
It is good to develop wind, solar, geothermal and other alternative energy sources but they will never replace oil, gas, coal and nuclear energy sources in the foreseeable decades of time. We must recognize the energy realities and not jeopardize our safety and well-being by eliminating sources of energy, thinking that some energy alternative or small-car mandate will solve our energy needs.
Russ Wege lives in Glenville. The Gazette encourages readers to submit material on local issues for the Sunday Opinion section.
http://www.dailygazette.com/news/2009/jun/21/0621_wege/
My career aspirations led me to study petroleum engineering in the 1950s. Upon graduation, I was employed by an energy company in the Southwest. It took years to develop an understanding of the problems concerning oil and gas production. Eventually, I became fairly proficient, and was involved in designing and performing fracture treatments of oil and gas reservoirs in order to increase production.
A Viewpoint column by Patricia O’Reilly Rush, on June 14, suggests that hydrofracturing of the Marcellus Shale for development of natural gas resources would endanger water supply resources.
This simply would not occur.
Need for facts
Since very few people in the Northeast have had experience with well stimulation, I believe your readers should have a better understanding of the facts before forming an opinion on this aspect of energy development.
Although oil production was first developed in Titusville, Pa., in 1859, the national search for oil energy began after the Spindletop discovery in East Texas during 1901.
Oil and gas reservoirs deplete over time. Often, a well can be stimulated to produce at a greater rate. Initially, well stimulation was achieved by the very dangerous procedure of placing several gallons of nitroglycerine opposite the oil-bearing formation. Upon detonation, the well bore would be increased from perhaps seven inches to two to three feet. The greater exposed surface area would allow increased flow into the well bore, which produced well stimulation.
The introduction of breaking oil and gas reservoirs using hydraulic pressure began in the 1940s. Initially, only a few hundred gallons of oil was used to crack the reservoir rock and stimulate the well. This technique was better than using nitroglycerine, and certainly was safer, but the procedure left something to be desired.
The thinking was that the crack that was propagated by hydraulic pressure immediately “healed” after the pressure was released. This problem was solved by adding sand to the hydraulic fluid. The sand would flow into the cracked reservoir rock, propping the crack open, in effect, greatly increasing the diameter of the well bore and stimulating oil or gas production.
The “frac” treatment technology is very successful and has been used countless times over the past 60 years to stimulate oil and gas reservoirs around the world.
During the early days of the oil industry, natural gas was considered a waste product and was often flared. Eventually, inexpensive natural gas began to displace manufactured gas in our cities. The demand for natural gas rapidly grew, and is still growing. Energy companies soon began to develop natural gas reserves.
The energy industry has long known there were vast quantities of oil and gas reserves in very low permeability or “tight” rock formations. Such deposits are in the oil shales of the Rocky Mountains, the tar sands in Canada, and natural gas in the Marcellus Shale in the Northeast.
The days of cheap energy are over. Domestic oil production peaked in the 1970s. Imported oil to meet our national needs now approaches 75 percent.
Congress should not have allowed this to happen, but it did. The good news is that the United States has massive coal reserves. The bad news is that coal does not burn as cleanly as natural gas and the Obama administration is making moves to diminish — if not shut down, this needed source of energy.
Natural gas burns very cleanly and we are producing about 87 percent of our needs, with the remainder coming from Canada. We must continue to develop additional gas reserves. Therefore, the vast gas reserves locked into the “tight” Marcellus Shale must be developed. Directional drilling into this massive shale formation exposes additional length of this gas-bearing reservoir to production and improved fracturing techniques opens up this valuable resource for decades of reliable production.
Rush’s recent Viewpoint column suggests fracture treatments of this resource will threaten water supplies, and she urges that development of this needed resource be terminated. The possibility of “frac” fluids contaminating water supplies is simply zero. I have never heard of a “frac” treatment ever adversely affecting another formation — let alone reaching the surface to pollute a stream!
What happens after a huge injection of water into a well is a backflow of water following the treatment. The backflow may last for weeks but it will end. The chemicals that concern Rush reduce pipe friction and carry the propping agent, such as sand, that keeps the fracture open.
No reason to stop
Treatment of the backflow should be a permit condition and not a reason to condemn the effort to develop this resource.
Finally, well treatments that involve the use of millions of gallons of water may be a concern to regulators and riparian interests, but can be addressed through the well permit system issued by the state Department of Environmental Conservation.
It is good to develop wind, solar, geothermal and other alternative energy sources but they will never replace oil, gas, coal and nuclear energy sources in the foreseeable decades of time. We must recognize the energy realities and not jeopardize our safety and well-being by eliminating sources of energy, thinking that some energy alternative or small-car mandate will solve our energy needs.
Russ Wege lives in Glenville. The Gazette encourages readers to submit material on local issues for the Sunday Opinion section.
Sunday, June 21, 2009
Natural Gas Plentiful in Barnett Shale
http://www.star-telegram.com/dallas_news/story/1444043.html
Chesapeake Energy Chairman and CEO Aubrey McClendon said Friday that the Barnett Shale has surpassed the venerable San Juan Basin as the biggest natural gas producer in the United States.
He also said the Barnett, which has speckled North Texas with roughly 10,000 natural gas wells, "will be producing at least 50 years" and "probably" for a century.
McClendon made the comments in a speech to the Rotary Club of Fort Worth and in a brief telephone interview with the Star-Telegram.
He said Chesapeake officials estimate Barnett production at 5.5 billion cubic feet a day but acknowledged that no one knows precisely. The San Juan is in the Four Corners region of the Southwest, with production concentrated in northwestern New Mexico and Colorado.
Gene Powell, publisher of the Barnett Shale Newsletter, has estimated Barnett production at 4.9 billion cubic feet per day, but that was as of Jan. 1. Barnett drilling activity has been centered most heavily in Tarrant and Johnson counties but also extends into Hood, Palo Pinto, Parker, Somervell, Denton, Jack, Montague and Wise counties.
Not what it was
Steve Grape, an official with the Dallas office of the U.S. Department of Energy, said the Barnett and San Juan are "probably running neck and neck nowadays" in gas production. The San Juan led the nation in production in 2007, Energy Department figures show, but no comparison of production for specific fields has been released for 2008.
There is still substantial drilling in the Barnett, with 74 rigs active Friday, according to RigData. But that’s only slightly more than one-third the peak rig count of 214 for the Barnett, a gas-rich geological zone about 6,500 to 8,500 feet below the surface. Drilling has declined sharply as a result of a steep decline in natural gas prices in the wake of a severe recession that has weakened energy demand.
Texas Railroad Commission spokeswoman Stacie Fowler said that 10,539 wells had been drilled in the Barnett through March and that there are 9,732 producing wells.
Reaping benefits
McClendon, who has come under fire recently for the $112.5 million compensation package he received in 2008, told Rotarians that Fort Worth and North Texas are "fortunate to overlay one of the largest energy deposits" in the nation, with residents to reap benefits for many decades to come from lease bonuses, royalties and jobs.
Since entering the Barnett, in 2004, Chesapeake has made 225,000 lease agreements in the area, McClendon said. The company, which is based in Oklahoma City and has a large regional office in Fort Worth, directly employs 700 people in the area; 5,000 others have worked with Chesapeake as contractors in activities such as leasing and drilling, he said.
McClendon urged that the U.S. embrace natural gas as a transportation fuel to reduce reliance on foreign oil and coal. He said he drives a "dual-fuel" Chevrolet Tahoe that can run on gasoline or compressed natural gas. The natural gas has cost him only 95 cents a gallon for the past two months, he said.
He acknowledged, however, that America lacks the kind of well-developed infrastructure for refueling natural gas-powered vehicles that has been available for gasoline-powered vehicles for many decades.
JACK Z. SMITH, 817-390-7724
Chesapeake Energy Chairman and CEO Aubrey McClendon said Friday that the Barnett Shale has surpassed the venerable San Juan Basin as the biggest natural gas producer in the United States.
He also said the Barnett, which has speckled North Texas with roughly 10,000 natural gas wells, "will be producing at least 50 years" and "probably" for a century.
McClendon made the comments in a speech to the Rotary Club of Fort Worth and in a brief telephone interview with the Star-Telegram.
He said Chesapeake officials estimate Barnett production at 5.5 billion cubic feet a day but acknowledged that no one knows precisely. The San Juan is in the Four Corners region of the Southwest, with production concentrated in northwestern New Mexico and Colorado.
Gene Powell, publisher of the Barnett Shale Newsletter, has estimated Barnett production at 4.9 billion cubic feet per day, but that was as of Jan. 1. Barnett drilling activity has been centered most heavily in Tarrant and Johnson counties but also extends into Hood, Palo Pinto, Parker, Somervell, Denton, Jack, Montague and Wise counties.
Not what it was
Steve Grape, an official with the Dallas office of the U.S. Department of Energy, said the Barnett and San Juan are "probably running neck and neck nowadays" in gas production. The San Juan led the nation in production in 2007, Energy Department figures show, but no comparison of production for specific fields has been released for 2008.
There is still substantial drilling in the Barnett, with 74 rigs active Friday, according to RigData. But that’s only slightly more than one-third the peak rig count of 214 for the Barnett, a gas-rich geological zone about 6,500 to 8,500 feet below the surface. Drilling has declined sharply as a result of a steep decline in natural gas prices in the wake of a severe recession that has weakened energy demand.
Texas Railroad Commission spokeswoman Stacie Fowler said that 10,539 wells had been drilled in the Barnett through March and that there are 9,732 producing wells.
Reaping benefits
McClendon, who has come under fire recently for the $112.5 million compensation package he received in 2008, told Rotarians that Fort Worth and North Texas are "fortunate to overlay one of the largest energy deposits" in the nation, with residents to reap benefits for many decades to come from lease bonuses, royalties and jobs.
Since entering the Barnett, in 2004, Chesapeake has made 225,000 lease agreements in the area, McClendon said. The company, which is based in Oklahoma City and has a large regional office in Fort Worth, directly employs 700 people in the area; 5,000 others have worked with Chesapeake as contractors in activities such as leasing and drilling, he said.
McClendon urged that the U.S. embrace natural gas as a transportation fuel to reduce reliance on foreign oil and coal. He said he drives a "dual-fuel" Chevrolet Tahoe that can run on gasoline or compressed natural gas. The natural gas has cost him only 95 cents a gallon for the past two months, he said.
He acknowledged, however, that America lacks the kind of well-developed infrastructure for refueling natural gas-powered vehicles that has been available for gasoline-powered vehicles for many decades.
JACK Z. SMITH, 817-390-7724
Saturday, June 20, 2009
Natural Gas Rig Count Up June 19, 2009
NEW YORK, June 19 (Reuters) - The number of rigs drilling for natural gas in the United States unexpectedly rose by seven to 692 this week, the first gain in the rig count in seven months, according to a report on Friday by oil services firm Baker Hughes in Houston.
U.S. natural gas drilling rigs have been in a mostly steady decline since peaking above 1,600 in September.
Despite the modest gain, the total still stands at about 822 rigs, or 54 percent below the same week last year.
Near record-high gas production last year and a deep recession that sharply cut demand led to a severe oversupply that pressured gas prices this spring below the $4 per mmBtu level from their peak above $13 last July.
The 75 percent slide in natural gas prices during the last 11 months and tighter access to credit have forced many producers to scale back drilling operations.
But sources said new rigs in some prolific shale plays such as Haynesville in Louisiana or Marcellus in Appalachia may have been the reason for the unexpected gain.
The last time the gas drilling rig count rose was on Nov. 21, when the number climbed by 13 to 1,511.
With the natural gas drilling rig count still below the 700 mark, most analysts expect to see year-on-year output declines soon, probably by early summer, which should help tighten the overall supply-demand balance. (Reporting by Joe Silha
U.S. natural gas drilling rigs have been in a mostly steady decline since peaking above 1,600 in September.
Despite the modest gain, the total still stands at about 822 rigs, or 54 percent below the same week last year.
Near record-high gas production last year and a deep recession that sharply cut demand led to a severe oversupply that pressured gas prices this spring below the $4 per mmBtu level from their peak above $13 last July.
The 75 percent slide in natural gas prices during the last 11 months and tighter access to credit have forced many producers to scale back drilling operations.
But sources said new rigs in some prolific shale plays such as Haynesville in Louisiana or Marcellus in Appalachia may have been the reason for the unexpected gain.
The last time the gas drilling rig count rose was on Nov. 21, when the number climbed by 13 to 1,511.
With the natural gas drilling rig count still below the 700 mark, most analysts expect to see year-on-year output declines soon, probably by early summer, which should help tighten the overall supply-demand balance. (Reporting by Joe Silha
Friday, June 19, 2009
Natural Gas Talk Heats Up as Supply Rises
By CHRISTINE BUURMA and VERONICA DAGHER
NEW YORK -- Natural-gas futures finished lower Thursday after U.S. government data showed a bigger-than-expected build in gas inventories last week, adding to already-ample supplies as weak demand and mild weather continue to pressure prices.
Natural gas for July delivery on the New York Mercantile Exchange settled 16 cents lower, or 3.8%, at $4.093 a million British thermal units. The contract fell as low as $4.065 a million BTUs earlier in the day.
The U.S. Energy Information Administration reported Thursday an injection into storage of 114 billion cubic feet of gas for the week ended June 12, outpacing the 104 billion-cubic-foot build that analysts and traders had forecast in a Dow Jones Newswires survey.
The latest build brings the total amount of gas in storage to 2.557 trillion cubic feet, about 23% above the five-year average and 32% above last year's level as of June 12.
Supplies of gas have ballooned as U.S. onshore production, particularly from tight rock formations called shales, has boomed. This supply glut has developed just as the economic downturn has suppressed gas demand as large industrial consumers cut spending, driving gas futures prices down 70% from last July.
"Demand is still weak," said Larry Young of Infinity Futures in Chicago. "That's why we still have a bias to downside."
Producers have reined in drilling activity as prices have fallen, with the number of rigs drilling for gas in the U.S. falling by more than half since September, according to oil-field-services company Baker Hughes. Signs of a significant drop in output have yet to emerge, however.
Gas futures prices are getting little support from weather forecasts.
Hot weather in the Midwest over the next two weeks could be offset by cooler-than-normal temperatures in the Northeast over the same period, limiting the demand for additional gas-fired power for cooling, meteorologists said.
"Warm weather for the Northeast is not likely" for the next 10 to 15 days, Joe Bastardi, a meteorologist with AccuWeather.com, said in a note to clients Thursday.
The National Weather Service was predicting warmer-than-normal temperatures across the Midwest from June 23 to June 27, with below-normal temperatures along the East Coast.
NEW YORK -- Natural-gas futures finished lower Thursday after U.S. government data showed a bigger-than-expected build in gas inventories last week, adding to already-ample supplies as weak demand and mild weather continue to pressure prices.
Natural gas for July delivery on the New York Mercantile Exchange settled 16 cents lower, or 3.8%, at $4.093 a million British thermal units. The contract fell as low as $4.065 a million BTUs earlier in the day.
The U.S. Energy Information Administration reported Thursday an injection into storage of 114 billion cubic feet of gas for the week ended June 12, outpacing the 104 billion-cubic-foot build that analysts and traders had forecast in a Dow Jones Newswires survey.
The latest build brings the total amount of gas in storage to 2.557 trillion cubic feet, about 23% above the five-year average and 32% above last year's level as of June 12.
Supplies of gas have ballooned as U.S. onshore production, particularly from tight rock formations called shales, has boomed. This supply glut has developed just as the economic downturn has suppressed gas demand as large industrial consumers cut spending, driving gas futures prices down 70% from last July.
"Demand is still weak," said Larry Young of Infinity Futures in Chicago. "That's why we still have a bias to downside."
Producers have reined in drilling activity as prices have fallen, with the number of rigs drilling for gas in the U.S. falling by more than half since September, according to oil-field-services company Baker Hughes. Signs of a significant drop in output have yet to emerge, however.
Gas futures prices are getting little support from weather forecasts.
Hot weather in the Midwest over the next two weeks could be offset by cooler-than-normal temperatures in the Northeast over the same period, limiting the demand for additional gas-fired power for cooling, meteorologists said.
"Warm weather for the Northeast is not likely" for the next 10 to 15 days, Joe Bastardi, a meteorologist with AccuWeather.com, said in a note to clients Thursday.
The National Weather Service was predicting warmer-than-normal temperatures across the Midwest from June 23 to June 27, with below-normal temperatures along the East Coast.
By BEN GEMAN AND KATHERINE LING, Greenwire
Published: June 18, 2009
The release of a major new study today that boosts estimates of U.S. natural gas resources is shaking debates over the use and regulation of a fuel that could help slow global warming but could create other environmental concerns.
The report by the Potential Gas Committee, a nonprofit group that provides closely watched analyses of U.S. resources, shows a 35 percent jump in domestic gas estimates.
The United States has a total resource base of 1,836 trillion cubic feet (tcf) worth of likely and potential resources, the report says, a sharp jump from the last estimate two years ago of 1,321 tcf, and the highest in the group's 44-year history.
With the addition of Energy Department estimates of proved reserves, the total U.S. future supply is 2,074 tcf, a rise of more than 35 percent from the committee's last biennial estimate.
The increase is largely due to the viability of tapping gas from shale formations, such as the Barnett in Texas, the Marcellus in Appalachia, the Haynesville in Louisiana and the Rocky Mountains.
"New and advanced exploration, well drilling and completion technologies are allowing us increasingly better access to domestic gas resources -- especially 'unconventional' gas -- which, not all that long ago, were considered impractical or uneconomical to pursue," said John Curtis, professor of geology and geological engineering at the Colorado School of Mines, which supports the committee's work.
But the increasing use of a technique called hydraulic fracturing to access these shale plays has sparked a Capitol Hill battle over regulating the extraction method. Several Democrats have introduced legislation that would bring the technique under Safe Drinking Water Act regulation -- reversing an exemption in a 2005 energy law -- and require disclosure of chemicals used in the process.
The industry and allied groups are fighting the effort. They say it would slow access to what the new report demonstrates is an abundant domestic energy source.
"Hydraulic fracturing is the Rosetta Stone of natural gas development. With it, otherwordly amounts of shale and tight-pocket gas can be found, produced and delivered to Americans who need it. Without it, those resources remain trapped underground," said Chris Tucker, a spokesman for Energy In Depth, an industry-backed group that recently launched an effort to fight the legislation.
A spokesman for Rep. Diana DeGette (D-Colo.), the sponsor of the fracturing legislation, said her bill is not about preventing gas production, which she supports, but that the extraction technique must have more oversight and disclosure.
"I would definitely say that she believes it is a necessary technology for the energy market. She also believes we need to ensure the health of the public as these processes are taking place," said DeGette spokesman Kristofer Eisenla.
Report sparks climate debate
Meanwhile, the report is also significant in light of pending congressional efforts to enact a sweeping bill to place mandatory limits on U.S. greenhouse gas emissions.
House Democratic leaders plan to bring a sweeping climate bill to the floor in the coming weeks that is sponsored by Energy and Commerce Chairman Henry Waxman (D-Calif.) and Rep. Ed Markey (D-Mass.). The greenhouse gas caps in the Waxman-Markey bill would curb U.S. emissions by 17 percent by 2020 from 2005 levels, with an 83 percent cut by 2050.
Burning natural gas currently provides about a fifth of U.S. electric power, and gas produces half the greenhouse gas emissions of coal. However, switching to gas creates concerns about the costs that could accompany increased demand if supplies were tight.
Joe Romm of the Center for American Progress, a liberal think tank, has called attention in recent weeks to the higher U.S. supply estimates driven by shale gas plays. He calls increased estimates a "game changer" and very good news.
Romm said the new report underscores that the 2020 emissions reduction targets in the Waxman-Markey bill are certainly achievable and may even be too weak. That is because with ample supply, gas will remain at a moderate price -- around $5 to $6 per million British thermal units -- and will keep compliance costs down, he said.
He noted that a key factor behind the cost of capping carbon is the cost to replace existing coal plants. With cheaper natural gas, that can more easily be done with idle natural gas plants built during a overbuild in the 1990s that are connected to the grid system, but the fuel has been too costly to use until now, said Romm, a former DOE official.
"I think this is a big deal," Romm said of the higher estimates. Additional gas will also encourage more utilities to build wind generation, as natural gas is currently the best backup power for the intermittent energy, he said.
Pickens plan
But others have their eye on these U.S. supplies as a way to power vehicles.
Famed Texas oilman T. Boone Pickens is spending aggressively to promote his plan to transition vehicles such as heavy-duty trucks and city fleets to natural gas in order to curb demands for oil imports. Pickens also supports a major build-out of wind for electricity, which would help free up natural gas for vehicles.
He quickly seized on the new report.
"Obviously, this underscores what Boone has spoken about for well over a year and gives further credibility to a key aspect of the Pickens plan, and that is using natural gas as a transportation fuel alternative to foreign oil, diesel and gasoline," said Jay Rosser, a spokesman for Pickens.
"This should quiet any skeptic who is concerned about using our abundant supplies of natural gas as an important transitional fuel," he added.
Copyright 2009 E&E Publishing. All Rights Reserved.
For more news on energy and the environment, visit www.greenwire.com.
Published: June 18, 2009
The release of a major new study today that boosts estimates of U.S. natural gas resources is shaking debates over the use and regulation of a fuel that could help slow global warming but could create other environmental concerns.
The report by the Potential Gas Committee, a nonprofit group that provides closely watched analyses of U.S. resources, shows a 35 percent jump in domestic gas estimates.
The United States has a total resource base of 1,836 trillion cubic feet (tcf) worth of likely and potential resources, the report says, a sharp jump from the last estimate two years ago of 1,321 tcf, and the highest in the group's 44-year history.
With the addition of Energy Department estimates of proved reserves, the total U.S. future supply is 2,074 tcf, a rise of more than 35 percent from the committee's last biennial estimate.
The increase is largely due to the viability of tapping gas from shale formations, such as the Barnett in Texas, the Marcellus in Appalachia, the Haynesville in Louisiana and the Rocky Mountains.
"New and advanced exploration, well drilling and completion technologies are allowing us increasingly better access to domestic gas resources -- especially 'unconventional' gas -- which, not all that long ago, were considered impractical or uneconomical to pursue," said John Curtis, professor of geology and geological engineering at the Colorado School of Mines, which supports the committee's work.
But the increasing use of a technique called hydraulic fracturing to access these shale plays has sparked a Capitol Hill battle over regulating the extraction method. Several Democrats have introduced legislation that would bring the technique under Safe Drinking Water Act regulation -- reversing an exemption in a 2005 energy law -- and require disclosure of chemicals used in the process.
The industry and allied groups are fighting the effort. They say it would slow access to what the new report demonstrates is an abundant domestic energy source.
"Hydraulic fracturing is the Rosetta Stone of natural gas development. With it, otherwordly amounts of shale and tight-pocket gas can be found, produced and delivered to Americans who need it. Without it, those resources remain trapped underground," said Chris Tucker, a spokesman for Energy In Depth, an industry-backed group that recently launched an effort to fight the legislation.
A spokesman for Rep. Diana DeGette (D-Colo.), the sponsor of the fracturing legislation, said her bill is not about preventing gas production, which she supports, but that the extraction technique must have more oversight and disclosure.
"I would definitely say that she believes it is a necessary technology for the energy market. She also believes we need to ensure the health of the public as these processes are taking place," said DeGette spokesman Kristofer Eisenla.
Report sparks climate debate
Meanwhile, the report is also significant in light of pending congressional efforts to enact a sweeping bill to place mandatory limits on U.S. greenhouse gas emissions.
House Democratic leaders plan to bring a sweeping climate bill to the floor in the coming weeks that is sponsored by Energy and Commerce Chairman Henry Waxman (D-Calif.) and Rep. Ed Markey (D-Mass.). The greenhouse gas caps in the Waxman-Markey bill would curb U.S. emissions by 17 percent by 2020 from 2005 levels, with an 83 percent cut by 2050.
Burning natural gas currently provides about a fifth of U.S. electric power, and gas produces half the greenhouse gas emissions of coal. However, switching to gas creates concerns about the costs that could accompany increased demand if supplies were tight.
Joe Romm of the Center for American Progress, a liberal think tank, has called attention in recent weeks to the higher U.S. supply estimates driven by shale gas plays. He calls increased estimates a "game changer" and very good news.
Romm said the new report underscores that the 2020 emissions reduction targets in the Waxman-Markey bill are certainly achievable and may even be too weak. That is because with ample supply, gas will remain at a moderate price -- around $5 to $6 per million British thermal units -- and will keep compliance costs down, he said.
He noted that a key factor behind the cost of capping carbon is the cost to replace existing coal plants. With cheaper natural gas, that can more easily be done with idle natural gas plants built during a overbuild in the 1990s that are connected to the grid system, but the fuel has been too costly to use until now, said Romm, a former DOE official.
"I think this is a big deal," Romm said of the higher estimates. Additional gas will also encourage more utilities to build wind generation, as natural gas is currently the best backup power for the intermittent energy, he said.
Pickens plan
But others have their eye on these U.S. supplies as a way to power vehicles.
Famed Texas oilman T. Boone Pickens is spending aggressively to promote his plan to transition vehicles such as heavy-duty trucks and city fleets to natural gas in order to curb demands for oil imports. Pickens also supports a major build-out of wind for electricity, which would help free up natural gas for vehicles.
He quickly seized on the new report.
"Obviously, this underscores what Boone has spoken about for well over a year and gives further credibility to a key aspect of the Pickens plan, and that is using natural gas as a transportation fuel alternative to foreign oil, diesel and gasoline," said Jay Rosser, a spokesman for Pickens.
"This should quiet any skeptic who is concerned about using our abundant supplies of natural gas as an important transitional fuel," he added.
Copyright 2009 E&E Publishing. All Rights Reserved.
For more news on energy and the environment, visit www.greenwire.com.
Thursday, June 18, 2009
Natural Gas Exploration for Florida Coming
By H. JOSEF HEBERT – 3 hours ago
WASHINGTON (AP) — Legislation that would require greater use of renewable energy, make it easier to build power lines and allow oil and gas drilling near the Florida coastline advanced Wednesday in the Senate.
The Energy and Natural Resources Committee approved the bill by a 15-8 bipartisan vote. But both Democrats and Republicans expressed concerns about the bill and hoped to make major changes when it reaches the Senate floor, probably in the fall.
The measure's primary thrust is to expand the use of renewable sources of energy such as wind, solar and geothermal sources as well as deal with growing worries about the inadequacies of the nation's high-voltage power grid.
But the bill also would remove the last congressional barrier to offshore oil and gas development, lifting a ban on drilling across a vast area in the eastern Gulf of Mexico that Congress put off limits three years ago. Drilling would be allowed within 45 miles of most of Florida's coast and as close as 10 miles off the state's Panhandle area.
The Senate bill for the first time would establish a national requirement for utilities to produce 15 percent of their electricity from renewable sources, a contentious issue that is likely to attract heated debate.
Twenty-eight states currently have some renewable energy requirement for utilities, but supporters of the measure argue a national mandate is needed to spur such energy development.
The legislation also would give much wider authority to federal regulators over the nation's electricity grid.
The Federal Energy Regulatory Commission would be given authority to approve the siting of high voltage power lines if states fail to act and would be given additional powers over cyber security on the grid.
Senate Majority Leader Harry Reid, D-Nev., has said he hopes to take up energy legislation after the August recess, although it's uncertain whether it will be merged with separate legislation addressing climate change. The House is working on a climate bill that includes many of the same energy issues addressed by the Senate bill.
While the bill was approved by a safe margin in the committee its prospects in the full Senate are anything but certain. Several senators called it too weak in its support of renewable energy development, while others said it ignored nuclear energy and greater domestic oil and gas production.
"None of us got all we wanted," said Sen. Jeff Bingaman, D-N.M., the committee's chairman, who was forced to agree to a variety of compromises to give the bill a chance of advancing. Nevertheless, he said the bill would help shift to cleaner, more secure sources of energy.
Bingaman and many of the panel's other Democrats had wanted at least a 20 percent renewable energy requirement. The bill requires 15 percent renewable use by 2021, but also would allow utilities to avoid a fourth of that mandate by showing improvements in efficiency. Renewable energy use could be cut further for utilities that increase their use of nuclear energy either from a new reactor or increased reactor output.
"This is an extraordinary weak bill," said Sen. Bernie Sanders, I-Vt.
But Sanders voted to advance the bill, as did Sen. Bob Corker, R-Tenn. Both senators said they hoped the bill will be strengthened.
"I suspect their definition of strengthening might be somewhat different," quipped Sen. Evan Bayh, D-Ind., whose own support of the bill came despite strong opposition to the federal renewable energy requirements on utilities.
Sanders wants the renewable energy requirement to be much higher, at 25 percent. Corker said the bill needs more to promote nuclear energy and domestic oil and gas production.
"We simply must do more to increase our domestic (oil and gas) production and use of nuclear energy," said Sen. Lisa Murkowski of Alaska, the committee's ranking Republican. Still, she voted for the bill which includes a commitment to increase loan guarantees for a natural gas pipeline in her state from $18 billion to $30 billion.
The bill also calls for establishing a new office to steer grants and loan guarantees to clean energy projects, including nuclear and those using technology to capture carbon dioxide; creating an oil products reserve to be used if there are supply problems; and creating federal standards for efficiency standards for new building.
The Chamber of Commerce said the bill shows progress toward crafting a comprehensive energy policy, but some environmentalists said it falls short of shifting the country away from fossil fuels. With its new offshore drilling, support for coal and nuclear energy "this bill fails to live up to the vision of a clean energy future," complained Brent Blackwelder, president of Friends of the Earth.
Copyright © 2009 The Associated Press. All rights reserved.
WASHINGTON (AP) — Legislation that would require greater use of renewable energy, make it easier to build power lines and allow oil and gas drilling near the Florida coastline advanced Wednesday in the Senate.
The Energy and Natural Resources Committee approved the bill by a 15-8 bipartisan vote. But both Democrats and Republicans expressed concerns about the bill and hoped to make major changes when it reaches the Senate floor, probably in the fall.
The measure's primary thrust is to expand the use of renewable sources of energy such as wind, solar and geothermal sources as well as deal with growing worries about the inadequacies of the nation's high-voltage power grid.
But the bill also would remove the last congressional barrier to offshore oil and gas development, lifting a ban on drilling across a vast area in the eastern Gulf of Mexico that Congress put off limits three years ago. Drilling would be allowed within 45 miles of most of Florida's coast and as close as 10 miles off the state's Panhandle area.
The Senate bill for the first time would establish a national requirement for utilities to produce 15 percent of their electricity from renewable sources, a contentious issue that is likely to attract heated debate.
Twenty-eight states currently have some renewable energy requirement for utilities, but supporters of the measure argue a national mandate is needed to spur such energy development.
The legislation also would give much wider authority to federal regulators over the nation's electricity grid.
The Federal Energy Regulatory Commission would be given authority to approve the siting of high voltage power lines if states fail to act and would be given additional powers over cyber security on the grid.
Senate Majority Leader Harry Reid, D-Nev., has said he hopes to take up energy legislation after the August recess, although it's uncertain whether it will be merged with separate legislation addressing climate change. The House is working on a climate bill that includes many of the same energy issues addressed by the Senate bill.
While the bill was approved by a safe margin in the committee its prospects in the full Senate are anything but certain. Several senators called it too weak in its support of renewable energy development, while others said it ignored nuclear energy and greater domestic oil and gas production.
"None of us got all we wanted," said Sen. Jeff Bingaman, D-N.M., the committee's chairman, who was forced to agree to a variety of compromises to give the bill a chance of advancing. Nevertheless, he said the bill would help shift to cleaner, more secure sources of energy.
Bingaman and many of the panel's other Democrats had wanted at least a 20 percent renewable energy requirement. The bill requires 15 percent renewable use by 2021, but also would allow utilities to avoid a fourth of that mandate by showing improvements in efficiency. Renewable energy use could be cut further for utilities that increase their use of nuclear energy either from a new reactor or increased reactor output.
"This is an extraordinary weak bill," said Sen. Bernie Sanders, I-Vt.
But Sanders voted to advance the bill, as did Sen. Bob Corker, R-Tenn. Both senators said they hoped the bill will be strengthened.
"I suspect their definition of strengthening might be somewhat different," quipped Sen. Evan Bayh, D-Ind., whose own support of the bill came despite strong opposition to the federal renewable energy requirements on utilities.
Sanders wants the renewable energy requirement to be much higher, at 25 percent. Corker said the bill needs more to promote nuclear energy and domestic oil and gas production.
"We simply must do more to increase our domestic (oil and gas) production and use of nuclear energy," said Sen. Lisa Murkowski of Alaska, the committee's ranking Republican. Still, she voted for the bill which includes a commitment to increase loan guarantees for a natural gas pipeline in her state from $18 billion to $30 billion.
The bill also calls for establishing a new office to steer grants and loan guarantees to clean energy projects, including nuclear and those using technology to capture carbon dioxide; creating an oil products reserve to be used if there are supply problems; and creating federal standards for efficiency standards for new building.
The Chamber of Commerce said the bill shows progress toward crafting a comprehensive energy policy, but some environmentalists said it falls short of shifting the country away from fossil fuels. With its new offshore drilling, support for coal and nuclear energy "this bill fails to live up to the vision of a clean energy future," complained Brent Blackwelder, president of Friends of the Earth.
Copyright © 2009 The Associated Press. All rights reserved.
Wednesday, June 17, 2009
Natural Gas Decision in India at $2.34/mmBTU
The Bombay High Court ruling on natural gas supply from the Krishna-Godavari basin appears to have upheld contractual obligations on the part of
Reliance Industries Ltd (RIL) to Reliance Natural Resources Ltd (RNRL), now de-merged corporate entities. The court order calls on RIL to supply 28 mmscmd of gas at $2.34 per mmBtu over a 17-year period.
Yet the ruling hinges on a mere technicality. As per para 317 of the order, the ‘agreed price’ is governed by another contested contract, that between RIL and NTPC, the power major. The court has held that it ‘would not like to impinge on the merits of the suit pending between NTPC and RIL...’ and the former’s right to 12 mmscmd of gas at a price of $2.34 per unit. Note also that the contention of RNRL in the ‘marathon hearing’ has been that the NTPC price, which was supposed to have been arrived at on the basis of competitive bidding, can be deemed reasonable.
But then, according to the production sharing contract (PSC), when it comes to valuation of gas, just about two clauses seem to contain the mechanics of determining the price. As per article 21.6.2 (b) of the PSC, gas which is sold to the government or its nominee “shall be valued on the terms and conditions actually obtained including pricing formula and delivery”. And clause (c) adds that gas which is sold or disposed of otherwise...”shall be valued on the basis of competitive arms-length sales in the region for similar sales under similar conditions”. And the fact of the matter is that the admissibility of the NTPC contract price and its validity for supply to RNRL remains to be tested in a court of law.
Meanwhile, the Centre — the sovereign is the licenser and owner of all natural resources — has of late worked out the price of K-G basin gas at $4.20 per mmBtu. Now para 320 of the ruling does suggest that “even at” $2.34 per mmBtu price, “RIL makes a profit”. But should the profitability criteria be used to judge price? What’s clearly required is better scope for price discovery in the rather fledgling national market for gas. A stand-alone gas Act is required as well. There’s also an immediate policy issue involved. A clutch of fertiliser producers now have agreements with RIL to source gas at $4.2/unit and these new contracts ought surely to be honoured.
Reliance Industries Ltd (RIL) to Reliance Natural Resources Ltd (RNRL), now de-merged corporate entities. The court order calls on RIL to supply 28 mmscmd of gas at $2.34 per mmBtu over a 17-year period.
Yet the ruling hinges on a mere technicality. As per para 317 of the order, the ‘agreed price’ is governed by another contested contract, that between RIL and NTPC, the power major. The court has held that it ‘would not like to impinge on the merits of the suit pending between NTPC and RIL...’ and the former’s right to 12 mmscmd of gas at a price of $2.34 per unit. Note also that the contention of RNRL in the ‘marathon hearing’ has been that the NTPC price, which was supposed to have been arrived at on the basis of competitive bidding, can be deemed reasonable.
But then, according to the production sharing contract (PSC), when it comes to valuation of gas, just about two clauses seem to contain the mechanics of determining the price. As per article 21.6.2 (b) of the PSC, gas which is sold to the government or its nominee “shall be valued on the terms and conditions actually obtained including pricing formula and delivery”. And clause (c) adds that gas which is sold or disposed of otherwise...”shall be valued on the basis of competitive arms-length sales in the region for similar sales under similar conditions”. And the fact of the matter is that the admissibility of the NTPC contract price and its validity for supply to RNRL remains to be tested in a court of law.
Meanwhile, the Centre — the sovereign is the licenser and owner of all natural resources — has of late worked out the price of K-G basin gas at $4.20 per mmBtu. Now para 320 of the ruling does suggest that “even at” $2.34 per mmBtu price, “RIL makes a profit”. But should the profitability criteria be used to judge price? What’s clearly required is better scope for price discovery in the rather fledgling national market for gas. A stand-alone gas Act is required as well. There’s also an immediate policy issue involved. A clutch of fertiliser producers now have agreements with RIL to source gas at $4.2/unit and these new contracts ought surely to be honoured.
Tuesday, June 16, 2009
Natural Gas Futures Hedged by Encana
http://blogs.reuters.com/james-pethokoukis/
* Says hedged production of about 1.39 bln cubic feet/day
* Says hedged at average price of $6.21/Mcf
* Hedging expected to increase certainty in cash flow
June 15 (Reuters) - EnCana Corp (ECA.TO), Canada's biggest energy company, established fixed price hedges on about 35 percent of its expected natural gas production as part of its extended risk management program for 2010.
EnCana said it had hedged about 1.4 billion cubic feet of natural gas per day at an average price of $6.21 per thousand cubic feet (Mcf) for the 2010 gas year, which runs from Nov. 1, 2009 to Oct. 31, 2010.
"Our hedging program increases certainty in cash flow and helps ensure that we meet our capital investment and dividend requirements. It also brings greater certainty to the economics of our projects," Chief Executive Officer Randy Eresman said in a statement.
At an average price of $6/Mcf, the company expects to earn an after-tax rate of return on gas projects in excess of 20 percent, Eresman added.
Shares of the Alberta-based company closed at C$61.99 Friday on the Toronto Stock Exchange. (Reporting by Isheeta Sanghi in Bangalore; Editing by Himani Sarkar)
* Says hedged production of about 1.39 bln cubic feet/day
* Says hedged at average price of $6.21/Mcf
* Hedging expected to increase certainty in cash flow
June 15 (Reuters) - EnCana Corp (ECA.TO), Canada's biggest energy company, established fixed price hedges on about 35 percent of its expected natural gas production as part of its extended risk management program for 2010.
EnCana said it had hedged about 1.4 billion cubic feet of natural gas per day at an average price of $6.21 per thousand cubic feet (Mcf) for the 2010 gas year, which runs from Nov. 1, 2009 to Oct. 31, 2010.
"Our hedging program increases certainty in cash flow and helps ensure that we meet our capital investment and dividend requirements. It also brings greater certainty to the economics of our projects," Chief Executive Officer Randy Eresman said in a statement.
At an average price of $6/Mcf, the company expects to earn an after-tax rate of return on gas projects in excess of 20 percent, Eresman added.
Shares of the Alberta-based company closed at C$61.99 Friday on the Toronto Stock Exchange. (Reporting by Isheeta Sanghi in Bangalore; Editing by Himani Sarkar)
Monday, June 15, 2009
Natural Gas Drillers to Leave it in the Ground
http://www.chron.com/disp/story.mpl/headline/biz/6476969.html
By KRISTEN HAYS Copyright 2009 Houston Chronicle
June 13, 2009, 3:08AM
Natural gas producers have been idling rigs for six months, trying to reduce output and boost prices that fell sharply amid bloated inventories and recession-shrunken demand.
That sweet spot remains elusive, despite a 56 percent reduction in the number of rigs drilling for natural gas, to 700 from the September peak of more than 1,600.
“It’s a self-correcting mechanism,” said David Pursell, an analyst with Tudor, Pickering, Holt & Co. Securities in Houston. “Prices go low, the rig count follows, and voila, production falls and the market fixes itself.”
But natural gas prices have largely lingered below $4 per million British thermal units since March after falling 78 percent from a high of more than $13 last summer.
Pursell said this down cycle has been more severe than is typical because the recession-fueled fall in demand followed rapid supply growth last year thanks to a boom in producing gas from thick shale rock. And inventories keep rising as producers have yet to dial down production enough to decrease underground stockpiles. Natural gas in storage reached 2.443 trillion cubic feet for the week ending June 5, the U.S. Energy Information Administration reported Thursday, up from 2.337 trillion a week earlier and 1.875 trillion in early June last year.
The agency, an arm of the Department of Energy, also projected in its monthly short-term outlook that total natural gas consumption is projected to fall by 2.2 percent this year and then increase slightly in 2010.
Headed for a record
By October, the EIA expects gas in storage to reach 3.659 trillion cubic feet — 94 billion cubic feet above the previous record of 3.565 trillion cubic feet in October 2007. The nation’s total storage capacity is about 3.8 trillion cubic feet.
“We’re producing a ton of gas. It’s dropped off some, but we’re producing from wells already drilled,” said James Williams, head of WTRG Economics, an Arkansas-based energy consulting firm.
“Clearly, we have more supply than demand,” Williams said.
Likely won’t follow oil
The Energy Information Administration doesn’t expect natural gas prices to mimic crude’s recent uptick. Instead, the agency projects that natural gas prices will average $4.13 per million Btu this year and creep up to an average of $5.49 in 2010.Natural gas for July delivery closed at $3.86 per million Btu Friday on the New York Mercantile Exchange.
“There certainly has been no indication on the price side that the market thinks we’re digging out of that supply situation,” said Karr Ingham, head of Ingham Economic Reporting in Amarillo. “We’re relatively early into this contractionary period.”
Pursell said the shrunken rig count will result in less production, but not as quickly as the industry would like. Weak demand will linger as long as industrial usage falls, as it will when GM shutters factories for nine weeks this summer. Car manufacturing requires lots of natural gas to produce steel, rubber and plastic, he noted.
The Energy Information Administration expects industrial consumption to fall by 8 percent this year.
New factors
And the storage side of the issue has some new factors that didn’t exist in previous times of oversupply, Pursell said.
First, increased liquefied natural gas imports could add more to storage and keep prices low. LNG is natural gas chilled to liquid form so it can be shipped via tanker or truck when pipelines aren’t available.
More LNG has been expected to arrive in the U.S. this year because of weak demand elsewhere and increased capacity to liquefy natural gas at plants in other parts of the world, including Qatar, Algeria and Russia.
“There’s lots of LNG out there and uncertain global demand,” Pursell said.
Second, technological advances in shale gas production have created more prolific wells. A tried-and-true vertical well is drilled straight down. Now producers also drill horizontal wells, where the bit dives vertically and then turns to drill sideways through a formation, gaining access to more gas than a vertical well. More access means more production per well.
Best wells drilled first
And while the overall natural gas rig count has plummeted, producers are ditching more rigs that drill vertically than ones drilling horizontally. Pursell said the horizontal rig count is down 40 percent, while the vertical rig count is down 64 percent.
“When times are tough, cash matters, and you’re trying to survive, you tend to keep drilling your best wells and you tend to try not to drill your worst wells. In simple terms, you drill your best stuff first,” he said.
Ingham said the pullback in drilling lays the foundation for prices to spike when demand recovers with the economy, storage thins out and production is slow to restart.
“We go through these very defined cycles and over the course of the contraction, we sideline so much production capacity that we generally get caught a little flat-footed. There’s an ugly intersection between strengthening demand and falling supply,” he said.
kristen.hays@chron.com
By KRISTEN HAYS Copyright 2009 Houston Chronicle
June 13, 2009, 3:08AM
Natural gas producers have been idling rigs for six months, trying to reduce output and boost prices that fell sharply amid bloated inventories and recession-shrunken demand.
That sweet spot remains elusive, despite a 56 percent reduction in the number of rigs drilling for natural gas, to 700 from the September peak of more than 1,600.
“It’s a self-correcting mechanism,” said David Pursell, an analyst with Tudor, Pickering, Holt & Co. Securities in Houston. “Prices go low, the rig count follows, and voila, production falls and the market fixes itself.”
But natural gas prices have largely lingered below $4 per million British thermal units since March after falling 78 percent from a high of more than $13 last summer.
Pursell said this down cycle has been more severe than is typical because the recession-fueled fall in demand followed rapid supply growth last year thanks to a boom in producing gas from thick shale rock. And inventories keep rising as producers have yet to dial down production enough to decrease underground stockpiles. Natural gas in storage reached 2.443 trillion cubic feet for the week ending June 5, the U.S. Energy Information Administration reported Thursday, up from 2.337 trillion a week earlier and 1.875 trillion in early June last year.
The agency, an arm of the Department of Energy, also projected in its monthly short-term outlook that total natural gas consumption is projected to fall by 2.2 percent this year and then increase slightly in 2010.
Headed for a record
By October, the EIA expects gas in storage to reach 3.659 trillion cubic feet — 94 billion cubic feet above the previous record of 3.565 trillion cubic feet in October 2007. The nation’s total storage capacity is about 3.8 trillion cubic feet.
“We’re producing a ton of gas. It’s dropped off some, but we’re producing from wells already drilled,” said James Williams, head of WTRG Economics, an Arkansas-based energy consulting firm.
“Clearly, we have more supply than demand,” Williams said.
Likely won’t follow oil
The Energy Information Administration doesn’t expect natural gas prices to mimic crude’s recent uptick. Instead, the agency projects that natural gas prices will average $4.13 per million Btu this year and creep up to an average of $5.49 in 2010.Natural gas for July delivery closed at $3.86 per million Btu Friday on the New York Mercantile Exchange.
“There certainly has been no indication on the price side that the market thinks we’re digging out of that supply situation,” said Karr Ingham, head of Ingham Economic Reporting in Amarillo. “We’re relatively early into this contractionary period.”
Pursell said the shrunken rig count will result in less production, but not as quickly as the industry would like. Weak demand will linger as long as industrial usage falls, as it will when GM shutters factories for nine weeks this summer. Car manufacturing requires lots of natural gas to produce steel, rubber and plastic, he noted.
The Energy Information Administration expects industrial consumption to fall by 8 percent this year.
New factors
And the storage side of the issue has some new factors that didn’t exist in previous times of oversupply, Pursell said.
First, increased liquefied natural gas imports could add more to storage and keep prices low. LNG is natural gas chilled to liquid form so it can be shipped via tanker or truck when pipelines aren’t available.
More LNG has been expected to arrive in the U.S. this year because of weak demand elsewhere and increased capacity to liquefy natural gas at plants in other parts of the world, including Qatar, Algeria and Russia.
“There’s lots of LNG out there and uncertain global demand,” Pursell said.
Second, technological advances in shale gas production have created more prolific wells. A tried-and-true vertical well is drilled straight down. Now producers also drill horizontal wells, where the bit dives vertically and then turns to drill sideways through a formation, gaining access to more gas than a vertical well. More access means more production per well.
Best wells drilled first
And while the overall natural gas rig count has plummeted, producers are ditching more rigs that drill vertically than ones drilling horizontally. Pursell said the horizontal rig count is down 40 percent, while the vertical rig count is down 64 percent.
“When times are tough, cash matters, and you’re trying to survive, you tend to keep drilling your best wells and you tend to try not to drill your worst wells. In simple terms, you drill your best stuff first,” he said.
Ingham said the pullback in drilling lays the foundation for prices to spike when demand recovers with the economy, storage thins out and production is slow to restart.
“We go through these very defined cycles and over the course of the contraction, we sideline so much production capacity that we generally get caught a little flat-footed. There’s an ugly intersection between strengthening demand and falling supply,” he said.
kristen.hays@chron.com
Sunday, June 14, 2009
Exxon Natural Gas Project in Alaska?
By Kirsten Korosec
http://industry.bnet.com/energy/10001438/exxon-joins-transcanada-pipeline-worries-abound-for-mackenzie-gas-project/
ExxonMobil’s reversal from foe to friend of an Alaskan natural gas pipeline proposed by TransCanada has given the state-sponsored project some much-need momentum. And while many are cheering Exxon’s announcement, some folks are worried it will derail another pipeline project in northern Canada. Not to mention a rival Alaska gas project from BP and ConocoPhliips.
Exxon has been viewed as a crucial player for the success of the TransCanada pipeline. So Exxon’s decision to help finance and build the $26 billion project was met with a sigh of relief and ethusiasm from government officials including Gov. Sarah Palin.
The 1,700-mile pipeline would carry natural gas from Alaska’s North Slope, where Exxon holds the largest natural gas reserves. Natural gas from the Point Thomson field, where Alaska state officials recently scrapped efforts to evict Exxon and partners BP and Conoco for decades of inaction, is expected to begin production in 2014, according to a Bloomberg article.
Exxon’s decision to join TransCanada poses a problem for two separate pipeline projects.
One is the rival Alaska gas project proposed by BP and Conoco. BP and Conoco decided to build its own pipeline after TransCanada won an exclusive state license under the Alaska Gasline Inducement Act, legislation backed by Palin. The companies said their project, dubbed Denali, will move forward, but added they were open to alternative plans.
The other pipeline considered at risk is the Mackenzie Gas Project in northern Canada. TransCanada and Exxon are both financially involved in the project. TransCanada invested $500 million in the Aboriginal Pipeline Group, which owns a third of the Mackenzie pipeline. Exxon owns a majority of Imperial Oil, the lead partner on the project.
The Alaska pipeline would carry more natural gas — four billion compared to one billion cubic feet — making it cheaper. In addition, there’s concern TransCanada’s pipeline will come online first because of a provision included in a broad U.S. energy bill that would bring costs down. The provision would increase federal loan guarantees for the Alaska gas pipeline from $18 billion to $30 billion. Meanwhile, the Mackenzie project has suffered from delays and cost overruns, which is only adding to fears for its chance of survival.
http://industry.bnet.com/energy/10001438/exxon-joins-transcanada-pipeline-worries-abound-for-mackenzie-gas-project/
ExxonMobil’s reversal from foe to friend of an Alaskan natural gas pipeline proposed by TransCanada has given the state-sponsored project some much-need momentum. And while many are cheering Exxon’s announcement, some folks are worried it will derail another pipeline project in northern Canada. Not to mention a rival Alaska gas project from BP and ConocoPhliips.
Exxon has been viewed as a crucial player for the success of the TransCanada pipeline. So Exxon’s decision to help finance and build the $26 billion project was met with a sigh of relief and ethusiasm from government officials including Gov. Sarah Palin.
The 1,700-mile pipeline would carry natural gas from Alaska’s North Slope, where Exxon holds the largest natural gas reserves. Natural gas from the Point Thomson field, where Alaska state officials recently scrapped efforts to evict Exxon and partners BP and Conoco for decades of inaction, is expected to begin production in 2014, according to a Bloomberg article.
Exxon’s decision to join TransCanada poses a problem for two separate pipeline projects.
One is the rival Alaska gas project proposed by BP and Conoco. BP and Conoco decided to build its own pipeline after TransCanada won an exclusive state license under the Alaska Gasline Inducement Act, legislation backed by Palin. The companies said their project, dubbed Denali, will move forward, but added they were open to alternative plans.
The other pipeline considered at risk is the Mackenzie Gas Project in northern Canada. TransCanada and Exxon are both financially involved in the project. TransCanada invested $500 million in the Aboriginal Pipeline Group, which owns a third of the Mackenzie pipeline. Exxon owns a majority of Imperial Oil, the lead partner on the project.
The Alaska pipeline would carry more natural gas — four billion compared to one billion cubic feet — making it cheaper. In addition, there’s concern TransCanada’s pipeline will come online first because of a provision included in a broad U.S. energy bill that would bring costs down. The provision would increase federal loan guarantees for the Alaska gas pipeline from $18 billion to $30 billion. Meanwhile, the Mackenzie project has suffered from delays and cost overruns, which is only adding to fears for its chance of survival.
Saturday, June 13, 2009
Natral Gas Rigs Down Again This Week
NEW YORK (Dow Jones)--The number of rigs drilling for oil and natural gas in the U.S. fell this week as producers continued to rein in drilling activity amid slumping energy prices.
The number of oil and gas rigs fell to 876, down 11 from the previous week, according to rig data from oil-field services company Baker Hughes Inc (BHI). The number of gas rigs was 685, a drop of 15 rigs from last week, while the oil rig count rose to 183, an increase of four rigs. The number of miscellaneous rigs was unchanged at eight rigs.
The number of gas rigs in use peaked at 1,606 in September.
Natural gas prices have tumbled about 70% from summer highs amid robust production from U.S. onshore natural gas fields and weak demand. Large industrial consumers have curbed gas use to cut costs during the recession. In response to falling gas prices, producers such as Chesapeake Energy Corp. (CHK) and Devon Energy Corp. (DVN) have slashed their spending plans and rig counts to reduce the flow of new gas supplies into the market.
Analysts anticipate that the sharp decline in natural gas drilling activity will eventually bring supply back in line with demand and help bolster gas prices.
Gas for July delivery on the New York Mercantile Exchange was recently down 7.3 cents, or 1.86%, at $3.86 a million British thermal units.
-By Christine Buurma, Dow Jones Newswires; 201-938-2061; christine.buurma@dowjones.com
The number of oil and gas rigs fell to 876, down 11 from the previous week, according to rig data from oil-field services company Baker Hughes Inc (BHI). The number of gas rigs was 685, a drop of 15 rigs from last week, while the oil rig count rose to 183, an increase of four rigs. The number of miscellaneous rigs was unchanged at eight rigs.
The number of gas rigs in use peaked at 1,606 in September.
Natural gas prices have tumbled about 70% from summer highs amid robust production from U.S. onshore natural gas fields and weak demand. Large industrial consumers have curbed gas use to cut costs during the recession. In response to falling gas prices, producers such as Chesapeake Energy Corp. (CHK) and Devon Energy Corp. (DVN) have slashed their spending plans and rig counts to reduce the flow of new gas supplies into the market.
Analysts anticipate that the sharp decline in natural gas drilling activity will eventually bring supply back in line with demand and help bolster gas prices.
Gas for July delivery on the New York Mercantile Exchange was recently down 7.3 cents, or 1.86%, at $3.86 a million British thermal units.
-By Christine Buurma, Dow Jones Newswires; 201-938-2061; christine.buurma@dowjones.com
Friday, June 12, 2009
ONGC is a Natural Gas Player
By Rakteem Katakey
June 11 (Bloomberg) -- Oil & Natural Gas Corp., India’s biggest energy explorer, may have lost 30 billion rupees ($630 million) selling natural gas at below production costs in the year ended March 31, Chairman and Managing Director R.S. Sharma said in New Delhi today.
ONGC sells natural gas to power and fertilizer companies, from fields allotted to it before India started auctioning oil blocks in 1999, below cost as the nation attempts to keep electricity and food prices in check and meet demand in the world’s second-fastest growing major economy. Inflation in India slowed to a three-decade low as the weakest economic growth in seven years sapped domestic demand.
The government has yet to implement an increase in the price of gas that was approved in May 2005, Sharma said May 18.
The explorer has asked the government to increase the price of gas produced at fields allocated to it to $4 per million British thermal units from $2.1 per million British thermal units, the Hindu Business Line reported March 17.
ONGC produced 22.5 billion cubic meters, or 60 percent of India’s output of gas, in the year ended March 31, according to the Oil Ministry’s Web site.
ONGC is attempting to start producing gas from new fields off India’s east coast by 2012, director of exploration D.K. Pande said Feb 23. The KG-DWN-98/2 field lies adjacent to Reliance Industries Ltd.’s KG-D6 field which began producing gas on April 2.
Reliance aims to supply more than 40 percent of the country’s oil and gas needs by March 2010.
ONGC plans to borrow 270 billion rupees for projects of units in the next three to four years, he said. These include a chemical plant in Gujarat and a power plant in Tripura, he said.
The company may borrow 50 billion rupees by January to redeem commercial paper that was used to fund the purchase of Imperial Energy Plc, he said.
The rise in oil prices was “worrisome” for the Indian economy, he said.
To contact the reporter on this story: Rakteem Katakey in New Delhi at rkatakey@bloomberg.net.
Last Updated: June 11, 2009 10:41 EDT
June 11 (Bloomberg) -- Oil & Natural Gas Corp., India’s biggest energy explorer, may have lost 30 billion rupees ($630 million) selling natural gas at below production costs in the year ended March 31, Chairman and Managing Director R.S. Sharma said in New Delhi today.
ONGC sells natural gas to power and fertilizer companies, from fields allotted to it before India started auctioning oil blocks in 1999, below cost as the nation attempts to keep electricity and food prices in check and meet demand in the world’s second-fastest growing major economy. Inflation in India slowed to a three-decade low as the weakest economic growth in seven years sapped domestic demand.
The government has yet to implement an increase in the price of gas that was approved in May 2005, Sharma said May 18.
The explorer has asked the government to increase the price of gas produced at fields allocated to it to $4 per million British thermal units from $2.1 per million British thermal units, the Hindu Business Line reported March 17.
ONGC produced 22.5 billion cubic meters, or 60 percent of India’s output of gas, in the year ended March 31, according to the Oil Ministry’s Web site.
ONGC is attempting to start producing gas from new fields off India’s east coast by 2012, director of exploration D.K. Pande said Feb 23. The KG-DWN-98/2 field lies adjacent to Reliance Industries Ltd.’s KG-D6 field which began producing gas on April 2.
Reliance aims to supply more than 40 percent of the country’s oil and gas needs by March 2010.
ONGC plans to borrow 270 billion rupees for projects of units in the next three to four years, he said. These include a chemical plant in Gujarat and a power plant in Tripura, he said.
The company may borrow 50 billion rupees by January to redeem commercial paper that was used to fund the purchase of Imperial Energy Plc, he said.
The rise in oil prices was “worrisome” for the Indian economy, he said.
To contact the reporter on this story: Rakteem Katakey in New Delhi at rkatakey@bloomberg.net.
Last Updated: June 11, 2009 10:41 EDT
Thursday, June 11, 2009
T. Boone Talking Again About Natural Gas
By Michael Newsom / The Sun Herald, Biloxi, Miss.
Wednesday, June 10, 2009 - Added 4h ago
BILOXI -- The creator and namesake of the "Pickens Plan" for more renewable energy and less foreign oil said Tuesday he expects significant energy legislation by year’s end. He also called for pressure on Washington to produce solutions.
T. Boone Pickens -- well-known for the $58 million advertising campaign for his energy plan -- addressed the Southern Growth Policies Board, which Gov. Haley Barbour chairs, on the last day of the group’s conference here. The summit was sponsored by Chevron and Southern Company, which owns Mississippi Power Company, among others.
Pickens, founder and chairman of BP Capital Management and author of the New York Times [NYT] Bestseller "The First Billion is the Hardest," said his ideas are attainable and there are examples of successes, particularly with natural gas, wind and solar technology. He lamented the U.S. has gone the last 40 years without developing an energy plan, but said it’s imperative to develop one now.
He said for years politicians agreed with him on foreign oil, but many kept getting elected and nothing ever happened.
"Now we are 68 percent imports, and over half of that comes from Venezuela, the Middle East and Africa, which are all unstable areas," Pickens said. "The biggest fear I have is the security issue. As long as we import the oil from where it is coming from, our security is in jeopardy."
According to Pickens, the United States presently uses about 25 percent of the world’s oil, but only represents 4 percent of the global population. He said there’s hope for alternatives to gasoline and diesel fuel, particularly natural gas, which is abundant in the United States.
Currently only one natural gas-powered car model, a Honda Civic, which he owns, is for sale in the United States, he said. But General Motors makes nearly 20 different natural gas vehicles, none of which are sold in the United States.
The substance is also powerful enough to propel an 18-wheeler, but there is about a $65,000 difference in the price of a natural gas truck and a diesel model. He favors incentives to encourage natural gas.
Other countries, particularly Iran, are moving toward natural gas engines. About 10 million vehicles run on natural gas worldwide, but only about 142,000 of them are in the United States, Pickens said. Los Angeles, Denver and Seattle operate buses on natural gas, and San Francisco is studying it, Pickens said. Barbour also noted some buses in Jackson currently run on it.
"It’s cleaner and it’s cheaper," Pickens said.
Pickens is also noted for being in the wind energy business. He said the U.S. is the world’s number one wind producer, having overtaken Germany. Wind and solar technology can work well, Pickens said, although some critics say it isn’t always sunny or windy. Pickens said wind sometimes works better at night and solar works better in daylight.
He said that he talked with then Republican presidential hopeful Sen. John McCain and then Democratic presidential hopeful Sen. Barack Obama about energy before the November elections last year. If both, who supported energy independence, were given an energy quiz then, they’d fail, he said.
"They did not know energy," Pickens said. "Look at their backgrounds. They never worked in energy."
McCain wanted more battery-powered cars, but didn’t realize there was no battery capable of moving an 18-wheeler. Obama talked with Pickens about a goal of having 1 million hybrid U.S. cars in 10 years, but finally agreed with Pickens that was too low a goal, given there are about 250 million cars in the United States now, Pickens said.
Congress is currently talking about two major energy-related bills. One, the Waxman-Markey bill, is designed to promote clean energy and reduce greenhouse gases, and another, known as the NAT GAS Act of 2009, promotes natural gas technologies. Pickens believes there is a "50-50" percent chance an energy bill will pass this year, possibly near the August recess. The climate change legislation, which many conference panelists expressed concern over how it would affect energy costs, might not make the final version, he believes.
He encouraged the audience, which included several state governors and many from the business and nonprofit sectors, to get involved in the fight.
Wednesday, June 10, 2009 - Added 4h ago
BILOXI -- The creator and namesake of the "Pickens Plan" for more renewable energy and less foreign oil said Tuesday he expects significant energy legislation by year’s end. He also called for pressure on Washington to produce solutions.
T. Boone Pickens -- well-known for the $58 million advertising campaign for his energy plan -- addressed the Southern Growth Policies Board, which Gov. Haley Barbour chairs, on the last day of the group’s conference here. The summit was sponsored by Chevron and Southern Company, which owns Mississippi Power Company, among others.
Pickens, founder and chairman of BP Capital Management and author of the New York Times [NYT] Bestseller "The First Billion is the Hardest," said his ideas are attainable and there are examples of successes, particularly with natural gas, wind and solar technology. He lamented the U.S. has gone the last 40 years without developing an energy plan, but said it’s imperative to develop one now.
He said for years politicians agreed with him on foreign oil, but many kept getting elected and nothing ever happened.
"Now we are 68 percent imports, and over half of that comes from Venezuela, the Middle East and Africa, which are all unstable areas," Pickens said. "The biggest fear I have is the security issue. As long as we import the oil from where it is coming from, our security is in jeopardy."
According to Pickens, the United States presently uses about 25 percent of the world’s oil, but only represents 4 percent of the global population. He said there’s hope for alternatives to gasoline and diesel fuel, particularly natural gas, which is abundant in the United States.
Currently only one natural gas-powered car model, a Honda Civic, which he owns, is for sale in the United States, he said. But General Motors makes nearly 20 different natural gas vehicles, none of which are sold in the United States.
The substance is also powerful enough to propel an 18-wheeler, but there is about a $65,000 difference in the price of a natural gas truck and a diesel model. He favors incentives to encourage natural gas.
Other countries, particularly Iran, are moving toward natural gas engines. About 10 million vehicles run on natural gas worldwide, but only about 142,000 of them are in the United States, Pickens said. Los Angeles, Denver and Seattle operate buses on natural gas, and San Francisco is studying it, Pickens said. Barbour also noted some buses in Jackson currently run on it.
"It’s cleaner and it’s cheaper," Pickens said.
Pickens is also noted for being in the wind energy business. He said the U.S. is the world’s number one wind producer, having overtaken Germany. Wind and solar technology can work well, Pickens said, although some critics say it isn’t always sunny or windy. Pickens said wind sometimes works better at night and solar works better in daylight.
He said that he talked with then Republican presidential hopeful Sen. John McCain and then Democratic presidential hopeful Sen. Barack Obama about energy before the November elections last year. If both, who supported energy independence, were given an energy quiz then, they’d fail, he said.
"They did not know energy," Pickens said. "Look at their backgrounds. They never worked in energy."
McCain wanted more battery-powered cars, but didn’t realize there was no battery capable of moving an 18-wheeler. Obama talked with Pickens about a goal of having 1 million hybrid U.S. cars in 10 years, but finally agreed with Pickens that was too low a goal, given there are about 250 million cars in the United States now, Pickens said.
Congress is currently talking about two major energy-related bills. One, the Waxman-Markey bill, is designed to promote clean energy and reduce greenhouse gases, and another, known as the NAT GAS Act of 2009, promotes natural gas technologies. Pickens believes there is a "50-50" percent chance an energy bill will pass this year, possibly near the August recess. The climate change legislation, which many conference panelists expressed concern over how it would affect energy costs, might not make the final version, he believes.
He encouraged the audience, which included several state governors and many from the business and nonprofit sectors, to get involved in the fight.
Wednesday, June 10, 2009
Natural Gas Leases Approved Closer to Shore
By BEN GEMAN, Greenwire
Published: June 9, 2009
The Senate Energy and Natural Resources Committee approved expanded oil and gas leasing today in the eastern Gulf of Mexico in a bipartisan vote that would upend a 2006 compromise with Florida senators that provided their state at least a 125-mile buffer in most areas until mid-2022.
The committee voted 13-10 in favor of Sen. Byron Dorgan's (D-N.D.) plan to allow leasing as close as 45 miles from Florida's coast. It also allows leasing in a gas-rich region called the Destin Dome off the Florida Panhandle that is even closer to shore.
The drilling amendment vote was part of the committee's ongoing markup of a broad energy bill.
Dorgan said the measure should be part of a bill that also addresses alternative energy and efficiency. "I am interested in doing this to increase production," Dorgan said.
But Sen. Robert Menendez (D-N.J.) said wider drilling in the eastern gulf would endanger Florida's environment and tourist economy while failing to reduce gasoline prices. "This continues our dependency and at the end of the day just helps the oil industry," he said.
Florida Democratic Sen. Bill Nelson slammed the plan in a prepared statement, arguing it could hamper military training, while blaming prices at the pump on financial speculators.
"Congress ought to be looking at that and at a real alternative energy program, instead of trying to put oil rigs off the world-class tourist spots all along Florida's coast," Nelson said.
Nelson vowed to block the effort in remarks to reporters after the vote. "We will have a bunch of senators filibuster this if we have to protect the interests of the United States military," he said.
Environmentalists oppose Dorgan's effort. "The Dorgan amendment would threaten Florida's coasts with oil spills and pollution while increasing our dependence on oil and increasing global warming pollution," said Anna Aurilio, director of the Washington office of the group Environment America, this morning.
But American Petroleum Institute President Jack Gerard praised the action after the vote. "By allowing greater access to oil and natural gas leasing in promising areas of the eastern Gulf of Mexico, Senator Dorgan's amendment stands to help the American people by creating new jobs, adding new energy resources and providing new revenues to federal, state and local governments," he said in a prepared statement.
After a long debate, the committee rejected, 10-13, an amendment by Sen. Mary Landrieu (D-La.) to provide states with offshore production in adjacent federal waters with a 37.5 percent share of revenues, while steering 50 percent of their revenues to federal deficit reduction and 12.5 percent to the Land and Water Conservation Fund.
A 2006 gulf leasing law created a revenue-sharing program for Louisiana, Texas, Mississippi and Alabama. Landrieu's plan would have provided this share to Alaska and to states that might have offshore leasing in the future, which she calls a critical state incentive for allowing oil and gas drilling in the outer continental shelf.
Landrieu also argued that revenue-sharing compensates for the impact of infrastructure for offshore development on coastal states, and she also cited the conservation funding in an effort to corral support.
But revenue-sharing opponents said the OCS is a national resource and cited future losses to the Treasury if a large share of leasing and royalty payments is directed to coastal states.
Chairman Jeff Bingaman (D-N.M.) said the Interior Department has estimated that total future federal losses from revenue sharing could be between $653 billion and $790 billion dollars. "We are not in a position as a country today where we can give away $653-$790 billion in future revenue," Bingaman said.
Several lawmakers said they will look to revisit the revenue-sharing issue to seek a compromise as the bill proceeds toward the Senate floor.
Copyright 2009 E&E Publishing. All Rights Reserved.
Published: June 9, 2009
The Senate Energy and Natural Resources Committee approved expanded oil and gas leasing today in the eastern Gulf of Mexico in a bipartisan vote that would upend a 2006 compromise with Florida senators that provided their state at least a 125-mile buffer in most areas until mid-2022.
The committee voted 13-10 in favor of Sen. Byron Dorgan's (D-N.D.) plan to allow leasing as close as 45 miles from Florida's coast. It also allows leasing in a gas-rich region called the Destin Dome off the Florida Panhandle that is even closer to shore.
The drilling amendment vote was part of the committee's ongoing markup of a broad energy bill.
Dorgan said the measure should be part of a bill that also addresses alternative energy and efficiency. "I am interested in doing this to increase production," Dorgan said.
But Sen. Robert Menendez (D-N.J.) said wider drilling in the eastern gulf would endanger Florida's environment and tourist economy while failing to reduce gasoline prices. "This continues our dependency and at the end of the day just helps the oil industry," he said.
Florida Democratic Sen. Bill Nelson slammed the plan in a prepared statement, arguing it could hamper military training, while blaming prices at the pump on financial speculators.
"Congress ought to be looking at that and at a real alternative energy program, instead of trying to put oil rigs off the world-class tourist spots all along Florida's coast," Nelson said.
Nelson vowed to block the effort in remarks to reporters after the vote. "We will have a bunch of senators filibuster this if we have to protect the interests of the United States military," he said.
Environmentalists oppose Dorgan's effort. "The Dorgan amendment would threaten Florida's coasts with oil spills and pollution while increasing our dependence on oil and increasing global warming pollution," said Anna Aurilio, director of the Washington office of the group Environment America, this morning.
But American Petroleum Institute President Jack Gerard praised the action after the vote. "By allowing greater access to oil and natural gas leasing in promising areas of the eastern Gulf of Mexico, Senator Dorgan's amendment stands to help the American people by creating new jobs, adding new energy resources and providing new revenues to federal, state and local governments," he said in a prepared statement.
After a long debate, the committee rejected, 10-13, an amendment by Sen. Mary Landrieu (D-La.) to provide states with offshore production in adjacent federal waters with a 37.5 percent share of revenues, while steering 50 percent of their revenues to federal deficit reduction and 12.5 percent to the Land and Water Conservation Fund.
A 2006 gulf leasing law created a revenue-sharing program for Louisiana, Texas, Mississippi and Alabama. Landrieu's plan would have provided this share to Alaska and to states that might have offshore leasing in the future, which she calls a critical state incentive for allowing oil and gas drilling in the outer continental shelf.
Landrieu also argued that revenue-sharing compensates for the impact of infrastructure for offshore development on coastal states, and she also cited the conservation funding in an effort to corral support.
But revenue-sharing opponents said the OCS is a national resource and cited future losses to the Treasury if a large share of leasing and royalty payments is directed to coastal states.
Chairman Jeff Bingaman (D-N.M.) said the Interior Department has estimated that total future federal losses from revenue sharing could be between $653 billion and $790 billion dollars. "We are not in a position as a country today where we can give away $653-$790 billion in future revenue," Bingaman said.
Several lawmakers said they will look to revisit the revenue-sharing issue to seek a compromise as the bill proceeds toward the Senate floor.
Copyright 2009 E&E Publishing. All Rights Reserved.
Tuesday, June 9, 2009
Alaska Pipeline Debate on Natural Gas Loan Guarantees
WASHINGTON, June 8 (Reuters) - Key U.S. lawmakers have reached a deal on legislation that would boost the federal government's loan guarantee for building a massive pipeline that would transport Alaska's huge natural gas reserves to the lower 48 States.
Senate Energy and Natural Resources Committee Democratic chairman Jeff Bingaman and top panel Republican Lisa Murkowski have agreed to a measure that would raise the 2004 loan guarantee program for the pipeline project to $30 billion from $18 billion.
TransCanada Corp (TRP.TO) received a state license in December to build a $26 billion pipeline from Alaska to a pipeline hub in Alberta. North Slope Gas producers BP Plc (BP.L) and ConocoPhillips (COP.N) have also proposed an Alaskan gas line project, however.
Either project would be eligible for the Senate measure, which also clarifies that the federal government will step in and repay loans for up to 80 percent of the cost of the total project if the pipeline's owners default on the financing.
"Hopefully these changes will speed the pace of efforts to get a gas line built and offset the financial challenges caused by lower natural gas prices and tighter financial markets," Murkowski said in a statement.
Since the 1970s government officials and industry groups have sought to construct a pipeline that would be used to ship the North Slope's known natural gas reserves of 35 trillion cubic feet.
If approved, the pipeline measure will be folded into a larger energy package that tackles a variety of issues including establishing a renewable electricity standard and increasing appliance efficiency standards. The Senate panel is set to vote on the entire energy bill as early as Tuesday. (Reporting by Ayesha Rascoe; editing by Jim Marshall)
Senate Energy and Natural Resources Committee Democratic chairman Jeff Bingaman and top panel Republican Lisa Murkowski have agreed to a measure that would raise the 2004 loan guarantee program for the pipeline project to $30 billion from $18 billion.
TransCanada Corp (TRP.TO) received a state license in December to build a $26 billion pipeline from Alaska to a pipeline hub in Alberta. North Slope Gas producers BP Plc (BP.L) and ConocoPhillips (COP.N) have also proposed an Alaskan gas line project, however.
Either project would be eligible for the Senate measure, which also clarifies that the federal government will step in and repay loans for up to 80 percent of the cost of the total project if the pipeline's owners default on the financing.
"Hopefully these changes will speed the pace of efforts to get a gas line built and offset the financial challenges caused by lower natural gas prices and tighter financial markets," Murkowski said in a statement.
Since the 1970s government officials and industry groups have sought to construct a pipeline that would be used to ship the North Slope's known natural gas reserves of 35 trillion cubic feet.
If approved, the pipeline measure will be folded into a larger energy package that tackles a variety of issues including establishing a renewable electricity standard and increasing appliance efficiency standards. The Senate panel is set to vote on the entire energy bill as early as Tuesday. (Reporting by Ayesha Rascoe; editing by Jim Marshall)
Monday, June 8, 2009
Natural Gas Laws in Colorado Painful for Some
By DENNIS WEBB/The Grand Junction Daily Sentinel
Sunday, June 07, 2009
PARACHUTE — Mineral owners Saturday assailed a Democratic lawmaker over the state’s new oil and gas rules, while Republican gubernatorial candidate Scott McInnis said new natural gas discoveries across the country are playing the primary role in Colorado’s drilling slowdown.
“The new regulations basically took away my minerals rights,” Tom Rutledge told state Rep. Kathleen Curry, D-Gunnison, at a meeting of the National Association of Royalty Owners in Parachute.
The Grand Junction resident said his land in North Park was declared off-limits to drilling under new rules designed to protect wildlife.
“I didn’t donate my land to become wildlife habitat,” he said.
“I don’t appreciate the tone of this entire discussion,” Curry said after also hearing criticism from other mineral owners, including one who said “Demoncrats” are responsible for taking people’s property rights.
The new rules were pushed by Democratic Gov. Bill Ritter and approved this year by a Democrat-controlled Legislature.
“This is your fight; this isn’t my fight,” McInnis joked to Curry when she asked the Grand Junction resident whether he wanted to jump into Saturday’s debate over the new rules.
McInnis instead gave a speech focusing on the numerous new natural gas plays in other parts of the country that have left the United States awash in natural gas and helped lower prices and reduce local drilling.
McInnis is a former western Colorado congressman who recently filed paperwork to run for governor in 2010. In an interview after his speech, he said the state’s new rules aren’t the central cause of Colorado’s drilling slowdown, although they may be a contributing factor.
He said it’s too early to judge the new rules, and the state has a right to be demanding in its regulation of energy companies.
“I just want it to be balanced. I don’t want it to be punitive. I just want it to be fair,” he said.
Curry, chairwoman of the House Agriculture, Livestock and Natural Resources Committee, said the Colorado Oil and Gas Conservation Commission did its best to create rules that balance competing interests.
Oil and gas commission member Tresi Houpt also defended the rules, speaking to mineral owners and in an interview. She said the state hasn’t taken away people’s opportunity to develop their minerals in areas falling under new restricted-surface-occupancy rules. It only requires that they work with the Division of Wildlife to find a way to put in habitat protections, she said.
Diane Roth, a lobbyist for mineral owners, spoke in defense of Curry, saying she has been “one of the best legislative champions on royalty issues.”
Sunday, June 07, 2009
PARACHUTE — Mineral owners Saturday assailed a Democratic lawmaker over the state’s new oil and gas rules, while Republican gubernatorial candidate Scott McInnis said new natural gas discoveries across the country are playing the primary role in Colorado’s drilling slowdown.
“The new regulations basically took away my minerals rights,” Tom Rutledge told state Rep. Kathleen Curry, D-Gunnison, at a meeting of the National Association of Royalty Owners in Parachute.
The Grand Junction resident said his land in North Park was declared off-limits to drilling under new rules designed to protect wildlife.
“I didn’t donate my land to become wildlife habitat,” he said.
“I don’t appreciate the tone of this entire discussion,” Curry said after also hearing criticism from other mineral owners, including one who said “Demoncrats” are responsible for taking people’s property rights.
The new rules were pushed by Democratic Gov. Bill Ritter and approved this year by a Democrat-controlled Legislature.
“This is your fight; this isn’t my fight,” McInnis joked to Curry when she asked the Grand Junction resident whether he wanted to jump into Saturday’s debate over the new rules.
McInnis instead gave a speech focusing on the numerous new natural gas plays in other parts of the country that have left the United States awash in natural gas and helped lower prices and reduce local drilling.
McInnis is a former western Colorado congressman who recently filed paperwork to run for governor in 2010. In an interview after his speech, he said the state’s new rules aren’t the central cause of Colorado’s drilling slowdown, although they may be a contributing factor.
He said it’s too early to judge the new rules, and the state has a right to be demanding in its regulation of energy companies.
“I just want it to be balanced. I don’t want it to be punitive. I just want it to be fair,” he said.
Curry, chairwoman of the House Agriculture, Livestock and Natural Resources Committee, said the Colorado Oil and Gas Conservation Commission did its best to create rules that balance competing interests.
Oil and gas commission member Tresi Houpt also defended the rules, speaking to mineral owners and in an interview. She said the state hasn’t taken away people’s opportunity to develop their minerals in areas falling under new restricted-surface-occupancy rules. It only requires that they work with the Division of Wildlife to find a way to put in habitat protections, she said.
Diane Roth, a lobbyist for mineral owners, spoke in defense of Curry, saying she has been “one of the best legislative champions on royalty issues.”
Saturday, June 6, 2009
Natural Gas Rig Count is Down Again
NEW YORK, June 5 (Reuters) - The number of rigs drilling for natural gas in the United States fell 3 to 700 this week, a fresh 6-1/2-year low, according to a report issued Friday by oil services firm Baker Hughes in Houston.
U.S. natural gas drilling rigs have been in a steady decline since peaking above 1,600 in September, and now stand at about 793 below the same week last year, the lowest level since late November 2002 when there were 695 gas rigs operating.
Tight credit and a 75 percent slide in natural gas prices over the last 11 months have forced many producers to scale back drilling operations.
Near record-high gas production last year and a deep recession that sharply cut demand led to a severe oversupply that has kept gas prices this spring below the $4 per mmBtu level from their peak above $13 last July.
With the natural gas drilling rig count likely to continue to fall in coming weeks, most analysts expect to see year-on-year output declines soon, probably by early summer, which should tighten the overall supply-demand balance. (Reporting by Joe Silha, editing by John Picinich)
© Thomson Reuters 2009 All rights reserved
U.S. natural gas drilling rigs have been in a steady decline since peaking above 1,600 in September, and now stand at about 793 below the same week last year, the lowest level since late November 2002 when there were 695 gas rigs operating.
Tight credit and a 75 percent slide in natural gas prices over the last 11 months have forced many producers to scale back drilling operations.
Near record-high gas production last year and a deep recession that sharply cut demand led to a severe oversupply that has kept gas prices this spring below the $4 per mmBtu level from their peak above $13 last July.
With the natural gas drilling rig count likely to continue to fall in coming weeks, most analysts expect to see year-on-year output declines soon, probably by early summer, which should tighten the overall supply-demand balance. (Reporting by Joe Silha, editing by John Picinich)
© Thomson Reuters 2009 All rights reserved
Friday, June 5, 2009
Natural Gas Inventory is UP
NEW YORK (AP) — Natural gas stockpiles rose more than analysts expected last week, the government said Thursday, as demand continues to lag.
The Energy Department's Energy Information Administration said in its weekly report that natural gas inventories held in underground storage in the lower 48 states rose by 124 billion cubic feet to about 2.34 trillion cubic feet for the week ended May 29.
Analysts expected an increase of 115 billion to 120 billion cubic feet, according to a survey by Platts, the energy information arm of McGraw-Hill Cos.
The inventory level was 22 percent above the five-year average of about 1.91 trillion cubic feet, and 31 percent above last year's storage level of about 1.79 trillion cubic feet.
Natural gas lost 1.57 cents at $3.609 per 1,000 cubic feet in morning trading on the New York Mercantile Exchange.
Copyright © 2009 The Associated Press. All rights reserved.
The Energy Department's Energy Information Administration said in its weekly report that natural gas inventories held in underground storage in the lower 48 states rose by 124 billion cubic feet to about 2.34 trillion cubic feet for the week ended May 29.
Analysts expected an increase of 115 billion to 120 billion cubic feet, according to a survey by Platts, the energy information arm of McGraw-Hill Cos.
The inventory level was 22 percent above the five-year average of about 1.91 trillion cubic feet, and 31 percent above last year's storage level of about 1.79 trillion cubic feet.
Natural gas lost 1.57 cents at $3.609 per 1,000 cubic feet in morning trading on the New York Mercantile Exchange.
Copyright © 2009 The Associated Press. All rights reserved.
Wednesday, June 3, 2009
Natural Gas in Shale is a Good Thing
NEW YORK, June 2 (Reuters) - Rich Kinder, chairman and CEO of pipeline and storage company Kinder Morgan Energy Partners LP (KMP.N) said Tuesday huge untapped reserves of shale gas are actually bullish for the natural gas industry, a contrarian view for most in the energy business.
"I would look at the overall shale situation as very bullish for the industry, very bullish for a midstream company like Kinder Morgan," Kinder told the Reuters Energy Summit in Houston.
"Upstream folks will tell you we have '100 years of natural gas supply' that we know we can access in the lower 48 without importing any LNG. When you look at a way to solve the CO2 problem, natural gas has got to be an enormous part of that solution and now we know we have the supply to do that," Kinder said.
He added, "We are going to have a lot of supply and more need for natural gas transportation in this country," the place where Kinder Morgan steps in as the second largest gas pipeline system in the nation.
Kinder said there was no question shale gas is having a "severe impact on prices" and he expects that to continue until drilling rates cut back and demand improves as the economy picks up.
"What the upstream sector has done in the natural gas field, strictly with the shale plays is just a dramatic improvement. The common accepted knowledge just a couple of years ago was, 'we're depleting our resources in the lower 48, the imports from Canada are not what they used to be and we need all the LNG we can get,'" he said.
Kinder said shale plays and vast improvements in horizontal drilling techniques have led to much more access to natural gas production and a much greater impact on prices.
Kinder also said gas storage has been pushed to near record highs this year but cautioned the summer and hurricane season are still ahead.
"We don't know what the electric demand is going to be during the summer. We don't know how hot it's going to be, whether we're going to have any hurricane disruptions," but Kinder said storage will affect the price.
PIPELINE OUTLOOK
Kinder Morgan is also joint developer of the huge Rockies Express natural pipeline with Sempra Energy (SRE.N) unit Sempra Pipelines and Storage, and ConocoPhillips (COP.N).
When complete, the 1,679-mile pipeline will be one of the largest gas pipelines in North America, delivering about 1.8 billion cubic feet per day of gas from Rio Blanco County in Colorado to Monroe County in Ohio.
Adverse weather delayed the eastern advance of the pipeline several times in the past few months, but Kinder said the project is "weeks away" from reaching Lebanon, Ohio and affirmed the projected in service date to Clarington, Ohio, for Nov. 1.
Drilling activities were suspended due to flooding on both the Illinois and Wabash rivers.
In November, Sempra said project costs had ballooned to $6 billion from earlier estimates of $4.4 billion, due to rising labor and permitting costs on the eastern leg of the line. Continued...
"I would look at the overall shale situation as very bullish for the industry, very bullish for a midstream company like Kinder Morgan," Kinder told the Reuters Energy Summit in Houston.
"Upstream folks will tell you we have '100 years of natural gas supply' that we know we can access in the lower 48 without importing any LNG. When you look at a way to solve the CO2 problem, natural gas has got to be an enormous part of that solution and now we know we have the supply to do that," Kinder said.
He added, "We are going to have a lot of supply and more need for natural gas transportation in this country," the place where Kinder Morgan steps in as the second largest gas pipeline system in the nation.
Kinder said there was no question shale gas is having a "severe impact on prices" and he expects that to continue until drilling rates cut back and demand improves as the economy picks up.
"What the upstream sector has done in the natural gas field, strictly with the shale plays is just a dramatic improvement. The common accepted knowledge just a couple of years ago was, 'we're depleting our resources in the lower 48, the imports from Canada are not what they used to be and we need all the LNG we can get,'" he said.
Kinder said shale plays and vast improvements in horizontal drilling techniques have led to much more access to natural gas production and a much greater impact on prices.
Kinder also said gas storage has been pushed to near record highs this year but cautioned the summer and hurricane season are still ahead.
"We don't know what the electric demand is going to be during the summer. We don't know how hot it's going to be, whether we're going to have any hurricane disruptions," but Kinder said storage will affect the price.
PIPELINE OUTLOOK
Kinder Morgan is also joint developer of the huge Rockies Express natural pipeline with Sempra Energy (SRE.N) unit Sempra Pipelines and Storage, and ConocoPhillips (COP.N).
When complete, the 1,679-mile pipeline will be one of the largest gas pipelines in North America, delivering about 1.8 billion cubic feet per day of gas from Rio Blanco County in Colorado to Monroe County in Ohio.
Adverse weather delayed the eastern advance of the pipeline several times in the past few months, but Kinder said the project is "weeks away" from reaching Lebanon, Ohio and affirmed the projected in service date to Clarington, Ohio, for Nov. 1.
Drilling activities were suspended due to flooding on both the Illinois and Wabash rivers.
In November, Sempra said project costs had ballooned to $6 billion from earlier estimates of $4.4 billion, due to rising labor and permitting costs on the eastern leg of the line. Continued...
Tuesday, June 2, 2009
Champaign Natural Gas Tax No Sip of Wine
By Mike Monson
Monday, June 1, 2009 8:03 AM CDT
E-mail Story Printer-friendly
CHAMPAIGN – Implementing a new natural-gas use tax on bulk purchases of out-of-state natural gas could wind up becoming a big income generator for the city of Champaign.
But there are still a number of questions about the proposed tax, including whether it would be applied to the University of Illinois and Unit 4 schools.
The city council will consider a number of proposed tax and fee increases at a 7 p.m. study session Tuesday. The meeting will be in council chambers at the City Building, 102 N. Neil St.
In the case of the natural-gas use tax, City Finance Director Richard Schnuer is asking the city council for authorization to further investigate imposing a 2.75 percent tax on entities purchasing natural gas out of state.
The city currently charges a 2.75 percent utility tax on users of natural gas and electricity bought through AmerenIP as well as on water purchases.
But larger natural-gas customers, such as the UI, the Unit 4 school district and some local businesses, don't pay the city tax. Those entities buy natural gas out of state, known as "from the wellhead," and then have it shipped here. State law exempts such purchases from the city's utility tax, which is based on the cost of gas sold.
But, under state law, the city can charge a natural-gas use tax that charges on a per-therm or volume basis for those out-of-state purchases, according to Schnuer. The city doesn't currently levy such a tax.
Schnuer said he talked with an AmerenIP official and that, based on the number of natural-gas therms that were transported to Champaign by AmerenIP that were bought out of state, the city could earn as much as $1.4 million from the new tax. That's substantially above the $150,000 that Schnuer originally estimated.
Schnuer said the current situation – with large users paying no tax while smaller users do pay a city tax – is inequitable.
"I think people would agree that, in general, when two parties are doing something similar, you want to treat them similarly," he said.
In a memo to the city council, Schnuer wrote that the proposed tax would apply to public entities such as Unit 4 schools. He also wrote that the city has not discussed the issue with UI officials and that the such discussions would take place if the city council gives the go-ahead.
The UI has long taken the position that it is not subject to taxes assessed by units of local government. But, in some cases, the university does make payments in lieu of taxes, such as in lieu of paying the city's food and beverage tax, Schnuer wrote.
Terry Ruprecht, the UI's director of energy conservation, confirmed that the UI does not believe it is subject to local taxation.
"The state does not get taxed by a city," he said. "That position has been consistent in the 21 years I've been here."
Ruprecht said a 2.75 percent tax would cost the UI a substantial sum, likely about $1 million, if it were imposed. The UI bought $35 million worth of natural gas in the fiscal year that ended June 30, 2008.
In his memo, Schnuer noted that the town of Normal levies a 5 percent natural-gas use tax and that Illinois State University pays the tax.
Unit 4 Chief Financial Officer Gene Logas said the school district bought about $800,000 in natural gas last year and that about 80 percent of that was bought out of state. He estimated such a tax would cost the school district $20,000 annually.
"Obviously, we'd rather work with the city to avoid that," he said. "We're facing the same budgetary constraints that they are."
Schnuer added that it is "not the intent" of city staff to raise $1.4 million from the tax, and that the city council could consider a number of different options. For example, the city council could generate an additional $150,000, as originally projected, by lowering the gas utility tax charged small users to 1.5 percent and imposing a gas-use tax of 1.4 percent on out-of-state purchases. Or the city could impose a smaller use tax on big customers to raise the $150,000.
The city could also opt to exempt the UI and Unit 4 from such a tax.
Monday, June 1, 2009 8:03 AM CDT
E-mail Story Printer-friendly
CHAMPAIGN – Implementing a new natural-gas use tax on bulk purchases of out-of-state natural gas could wind up becoming a big income generator for the city of Champaign.
But there are still a number of questions about the proposed tax, including whether it would be applied to the University of Illinois and Unit 4 schools.
The city council will consider a number of proposed tax and fee increases at a 7 p.m. study session Tuesday. The meeting will be in council chambers at the City Building, 102 N. Neil St.
In the case of the natural-gas use tax, City Finance Director Richard Schnuer is asking the city council for authorization to further investigate imposing a 2.75 percent tax on entities purchasing natural gas out of state.
The city currently charges a 2.75 percent utility tax on users of natural gas and electricity bought through AmerenIP as well as on water purchases.
But larger natural-gas customers, such as the UI, the Unit 4 school district and some local businesses, don't pay the city tax. Those entities buy natural gas out of state, known as "from the wellhead," and then have it shipped here. State law exempts such purchases from the city's utility tax, which is based on the cost of gas sold.
But, under state law, the city can charge a natural-gas use tax that charges on a per-therm or volume basis for those out-of-state purchases, according to Schnuer. The city doesn't currently levy such a tax.
Schnuer said he talked with an AmerenIP official and that, based on the number of natural-gas therms that were transported to Champaign by AmerenIP that were bought out of state, the city could earn as much as $1.4 million from the new tax. That's substantially above the $150,000 that Schnuer originally estimated.
Schnuer said the current situation – with large users paying no tax while smaller users do pay a city tax – is inequitable.
"I think people would agree that, in general, when two parties are doing something similar, you want to treat them similarly," he said.
In a memo to the city council, Schnuer wrote that the proposed tax would apply to public entities such as Unit 4 schools. He also wrote that the city has not discussed the issue with UI officials and that the such discussions would take place if the city council gives the go-ahead.
The UI has long taken the position that it is not subject to taxes assessed by units of local government. But, in some cases, the university does make payments in lieu of taxes, such as in lieu of paying the city's food and beverage tax, Schnuer wrote.
Terry Ruprecht, the UI's director of energy conservation, confirmed that the UI does not believe it is subject to local taxation.
"The state does not get taxed by a city," he said. "That position has been consistent in the 21 years I've been here."
Ruprecht said a 2.75 percent tax would cost the UI a substantial sum, likely about $1 million, if it were imposed. The UI bought $35 million worth of natural gas in the fiscal year that ended June 30, 2008.
In his memo, Schnuer noted that the town of Normal levies a 5 percent natural-gas use tax and that Illinois State University pays the tax.
Unit 4 Chief Financial Officer Gene Logas said the school district bought about $800,000 in natural gas last year and that about 80 percent of that was bought out of state. He estimated such a tax would cost the school district $20,000 annually.
"Obviously, we'd rather work with the city to avoid that," he said. "We're facing the same budgetary constraints that they are."
Schnuer added that it is "not the intent" of city staff to raise $1.4 million from the tax, and that the city council could consider a number of different options. For example, the city council could generate an additional $150,000, as originally projected, by lowering the gas utility tax charged small users to 1.5 percent and imposing a gas-use tax of 1.4 percent on out-of-state purchases. Or the city could impose a smaller use tax on big customers to raise the $150,000.
The city could also opt to exempt the UI and Unit 4 from such a tax.
Monday, June 1, 2009
Russian Natural Gas Player is Novatek
By LIAM DENNING
Competing with Gazprom on its home turf is no mean feat. But independent Russian natural-gas producer Novatek hasn't done badly. Since its global depositary receipts debuted in London in 2005, they have risen 175%, valuing Novatek at almost $16 billion.
But the stock now commands a giddy 25 times 2009 earnings, and cracks are showing in the investment case.
Novatek agreed last week to pay $650 million for 51% of an undeveloped natural-gas field from companies linked to Gennady Timchenko's Volga Resources fund. The same week, Volga raised its stake in Novatek to 18.2% and Mr. Timchenko joined its board.
Analysts say production from the field is more than a decade away. The large upfront investment needed risks eroding free cash flow, a major element of Novatek's appeal.
The other element is high growth. Before the financial crisis, this looked secure. Gazprom, apparently struggling to produce enough natural gas to export to Europe, was happy for others to take share in the domestic market.
Suddenly, Gazprom's exports have slumped. Europe faces a slow recovery and wants to diversify its energy supplies. Prospects have dimmed at home. Thane Gustafson at IHS Cambridge Energy Research Associates reckons Russian natural-gas demand could peak in 2015.
Novatek, which can't export, risks being crowded out. Gazprom aside, its other competitors are mostly oil companies producing natural gas as a side product, making it hard to fit output to lower demand.
Novatek's largest shareholder, with a 20% stake, is Gazprom itself. How much protection that offers in a slowing market, however, is far from certain.
Write to Liam Denning at liam.denning@wsj.com
Competing with Gazprom on its home turf is no mean feat. But independent Russian natural-gas producer Novatek hasn't done badly. Since its global depositary receipts debuted in London in 2005, they have risen 175%, valuing Novatek at almost $16 billion.
But the stock now commands a giddy 25 times 2009 earnings, and cracks are showing in the investment case.
Novatek agreed last week to pay $650 million for 51% of an undeveloped natural-gas field from companies linked to Gennady Timchenko's Volga Resources fund. The same week, Volga raised its stake in Novatek to 18.2% and Mr. Timchenko joined its board.
Analysts say production from the field is more than a decade away. The large upfront investment needed risks eroding free cash flow, a major element of Novatek's appeal.
The other element is high growth. Before the financial crisis, this looked secure. Gazprom, apparently struggling to produce enough natural gas to export to Europe, was happy for others to take share in the domestic market.
Suddenly, Gazprom's exports have slumped. Europe faces a slow recovery and wants to diversify its energy supplies. Prospects have dimmed at home. Thane Gustafson at IHS Cambridge Energy Research Associates reckons Russian natural-gas demand could peak in 2015.
Novatek, which can't export, risks being crowded out. Gazprom aside, its other competitors are mostly oil companies producing natural gas as a side product, making it hard to fit output to lower demand.
Novatek's largest shareholder, with a 20% stake, is Gazprom itself. How much protection that offers in a slowing market, however, is far from certain.
Write to Liam Denning at liam.denning@wsj.com
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