A new natural gas platform will be built off the north-west coast of Western Australia.
The North Rankin B platform will recover remaining low pressure gas from the North Rankin A and Perseus gas fields.
Natural gas will be pumped from the facility to be processed onshore 145 kilometres away at Karratha.
BHP Billiton, one of six participants in the project, has approved US$850 million in funding for the new platform.
Monday, March 31, 2008
Sunday, March 30, 2008
Gazprom Leveraging Europe
Due to increasing oil prices caused by global conflicts and growing demand, Europe, together with the most important importers regard as important that their energy policy be reviewed and the reliability of their suppliers be re-examined. For several decades, Gazprom has been an organic part of European energy security; it provided stable natural gas supplies under all circumstances.
Hungary is an important partner of Gazprom, with its share of 7.5bn cubic metres it was the fifth largest buyer in 2007. In addition to outstanding business relations, Hungary also serves as a gas distribution centre of strategic significance for Gazprom. Not too long ago we started a joint venture with MOL (Hungarian Oil Company) to construct an underground gas storage tank, large enough to store no less than 1bn cubic metres of natural gas. To satisfy Europe's growing natural gas needs we secure several sources for the exploration of new gas fields, for the construction of new transportation routes and for the establishment of new, underground gas storage tanks on the Continent. By exploiting the Shtokman gas field in cooperation with our European partners, we are opening the world's largest natural gas reserve in the sea, thus further increasing Europe's gas supply security.
The two basic pillars of energy security for areas in need to import natural gas - including Europe - are reliable supplies provided at economically still rational prices. The term energy security means to us reliable profit acquired by way of predictable demand based on long-term contracts and mutual participation in pipeline construction. This enables us to take part in several billion euros worth of investments through which European consumers can access reserves from natural gas fields in the most remote corners of the world. For this reason we are somewhat concerned about recommendations made by the European Commission for reforming the EU energy market, because these raise questions about investments needed for the development of the European energy infrastructure as well as common energy security goals. This is one of the reasons why we initiated constructive dialogue with EU institutions.
Gazprom is fully aware of, and many from Brussels to Budapest are concerned about the fact that disputes that erupted between Gazprom and the transit countries about the price of gas could unfavourably influence the EU's energy security. Recent negotiations with the Ukrainians and the Belarusians prove that it is possible to reach agreements and that nothing threatens deliveries to Europe. Our commitment to greater transparency is also indicated by the fact that we have informed our European partners of these throughout the negotiations.
The two gas pipelines - the Northern Stream and the Southern Stream - that significantly increase the quantity of gas that can be transported to Europe are the most visible and most promising indications of increased cooperation and mutual dependence between Europe and Russia. During the past several months Gazprom conducted countless negotiations with governments and other interested parties affected by these projects. A few weeks ago the Russian and the Hungarian delegations have conducted rather successful negotiations about extending the Southern Stream pipeline into Hungary. I believe that the Southern Stream - whose supplies are already guaranteed - could be an important step towards establishing energy security in the area.
The key to Gazprom's long-term profitable and reliable functioning is mostly based on the well-considered selection of our business partners. The booming and stable European economy with its 500 million consumers and with an easily predictable energy need, already linked to us also with a huge network of existing pipelines, as well as successful economic relations make Europe one of our most important business partners. But could this judgment change? It is the common goal of both Europe and Gazprom that energy security could only be realized if the seller and the buyer develop relations based on mutual confidence and on rational economic decisions. Gazprom has committed itself to transparency and is prepared to conduct open dialogue with Hungary, with the EU, with any member state of the EU and with their European business partners to ensure energy security, our common goal for decades ahead.
Hungary is an important partner of Gazprom, with its share of 7.5bn cubic metres it was the fifth largest buyer in 2007. In addition to outstanding business relations, Hungary also serves as a gas distribution centre of strategic significance for Gazprom. Not too long ago we started a joint venture with MOL (Hungarian Oil Company) to construct an underground gas storage tank, large enough to store no less than 1bn cubic metres of natural gas. To satisfy Europe's growing natural gas needs we secure several sources for the exploration of new gas fields, for the construction of new transportation routes and for the establishment of new, underground gas storage tanks on the Continent. By exploiting the Shtokman gas field in cooperation with our European partners, we are opening the world's largest natural gas reserve in the sea, thus further increasing Europe's gas supply security.
The two basic pillars of energy security for areas in need to import natural gas - including Europe - are reliable supplies provided at economically still rational prices. The term energy security means to us reliable profit acquired by way of predictable demand based on long-term contracts and mutual participation in pipeline construction. This enables us to take part in several billion euros worth of investments through which European consumers can access reserves from natural gas fields in the most remote corners of the world. For this reason we are somewhat concerned about recommendations made by the European Commission for reforming the EU energy market, because these raise questions about investments needed for the development of the European energy infrastructure as well as common energy security goals. This is one of the reasons why we initiated constructive dialogue with EU institutions.
Gazprom is fully aware of, and many from Brussels to Budapest are concerned about the fact that disputes that erupted between Gazprom and the transit countries about the price of gas could unfavourably influence the EU's energy security. Recent negotiations with the Ukrainians and the Belarusians prove that it is possible to reach agreements and that nothing threatens deliveries to Europe. Our commitment to greater transparency is also indicated by the fact that we have informed our European partners of these throughout the negotiations.
The two gas pipelines - the Northern Stream and the Southern Stream - that significantly increase the quantity of gas that can be transported to Europe are the most visible and most promising indications of increased cooperation and mutual dependence between Europe and Russia. During the past several months Gazprom conducted countless negotiations with governments and other interested parties affected by these projects. A few weeks ago the Russian and the Hungarian delegations have conducted rather successful negotiations about extending the Southern Stream pipeline into Hungary. I believe that the Southern Stream - whose supplies are already guaranteed - could be an important step towards establishing energy security in the area.
The key to Gazprom's long-term profitable and reliable functioning is mostly based on the well-considered selection of our business partners. The booming and stable European economy with its 500 million consumers and with an easily predictable energy need, already linked to us also with a huge network of existing pipelines, as well as successful economic relations make Europe one of our most important business partners. But could this judgment change? It is the common goal of both Europe and Gazprom that energy security could only be realized if the seller and the buyer develop relations based on mutual confidence and on rational economic decisions. Gazprom has committed itself to transparency and is prepared to conduct open dialogue with Hungary, with the EU, with any member state of the EU and with their European business partners to ensure energy security, our common goal for decades ahead.
Saturday, March 29, 2008
British Columbia - Natural Gas Big Time Player
British Columbia, long an also-ran in Canada's energy boom, is emerging as one of North America's hottest areas for natural-gas exploration.
One factor: An accommodating government in a time when other countries and regions are angling for a bigger slice of energy-production profits.
Thursday, British Columbia said it reaped 152 million Canadian dollars (US$149.2 million) on the sale of drilling rights on 81 parcels of land covering more than 220,000 acres. It was the latest in a series of major sales, which already had brought in more than C$1 billion in the fiscal year ending Monday, outpacing the previous annual high of C$625.7 million.
One factor: An accommodating government in a time when other countries and regions are angling for a bigger slice of energy-production profits.
Thursday, British Columbia said it reaped 152 million Canadian dollars (US$149.2 million) on the sale of drilling rights on 81 parcels of land covering more than 220,000 acres. It was the latest in a series of major sales, which already had brought in more than C$1 billion in the fiscal year ending Monday, outpacing the previous annual high of C$625.7 million.
Friday, March 28, 2008
Long Island Natural Gas via Canada
A little-noticed action by federal energy regulators will increase natural gas supplies for Long Island and parts of New York City by about 10 percent in the next 19 months -- helping to meet growing demand and, in the view of some, reducing the need for gas from the proposed Broadwater barge in the Long Island Sound.
The increased supply -- 200 million cubic feet a day phased in by November of next year -- will come from $118.4 million in improvements to the Iroquois Gas Transmission System pipeline that brings Canadian gas through upstate New York and Connecticut to a National Grid/KeySpan station in South Commack.
Improvement of the Iroquois pipeline is one of several measures that Broadwater opponents, including local environmentalists and Connecticut Attorney General Richard Blumenthal, favor as alternatives to the Broadwater liquefied natural gas processing plant proposed for a site midway to Connecticut.
National Grid KeySpan senior vice president for energy portfolio management Richard Rapp said the added gas increases the supply at South Commack by a third to 40 percent and adds about 10 percent to the total supply available for National Grid's downstate area, which includes Long Island, most of Queens, Brooklyn and Staten Island. "It's entirely for KeySpan's needs, for our firm customers -- commercial and residential," he said. Customers are guaranteed an uninterrupted supply; some commercial customers can be temporarily asked to switch to other fuels if gas supplies are tight.
The increased supply -- 200 million cubic feet a day phased in by November of next year -- will come from $118.4 million in improvements to the Iroquois Gas Transmission System pipeline that brings Canadian gas through upstate New York and Connecticut to a National Grid/KeySpan station in South Commack.
Improvement of the Iroquois pipeline is one of several measures that Broadwater opponents, including local environmentalists and Connecticut Attorney General Richard Blumenthal, favor as alternatives to the Broadwater liquefied natural gas processing plant proposed for a site midway to Connecticut.
National Grid KeySpan senior vice president for energy portfolio management Richard Rapp said the added gas increases the supply at South Commack by a third to 40 percent and adds about 10 percent to the total supply available for National Grid's downstate area, which includes Long Island, most of Queens, Brooklyn and Staten Island. "It's entirely for KeySpan's needs, for our firm customers -- commercial and residential," he said. Customers are guaranteed an uninterrupted supply; some commercial customers can be temporarily asked to switch to other fuels if gas supplies are tight.
Thursday, March 27, 2008
Petrobras Inks Large Natural Gas Contract
March 26 (Bloomberg) -- Gas Natural SDG SA, Spain's largest natural-gas supplier, agreed to buy fuel from Petroleo Brasileiro SA until 2012 to supply its customers in Brazil.
The Barcelona-based company will buy 9.5 million cubic meters a day of gas, Gas Natural said in an e-mailed statement late yesterday.
Gas Natural is expanding outside Spain to make up for a falling market share since the market was opened to competition. In Brazil, where demand for the fuel grew twice as fast as Spain in 2006, it's supplying gas to 739,000 clients.
The Barcelona-based company will buy 9.5 million cubic meters a day of gas, Gas Natural said in an e-mailed statement late yesterday.
Gas Natural is expanding outside Spain to make up for a falling market share since the market was opened to competition. In Brazil, where demand for the fuel grew twice as fast as Spain in 2006, it's supplying gas to 739,000 clients.
Wednesday, March 26, 2008
Natural Gas Projects Hughe in East Texas
A huge shift in natural gas flows is expected as more than 40 infrastructure projects go online in the Southeast/Gulf region beginning in 2008, according to a report released Tuesday.
The study, released by Golden, Colo.-based Bentek Energy LLC, said 25 natural gas pipeline projects, 11 natural gas storage projects and four liquefied natural gas terminals are expected to shift gas flow patterns, disrupt regional pricing relationships and realign the value of transportation capacity across the most complex pipeline grid in North America between early 2008 and mid-year 2009.
Many of the projects under construction are by companies either based in Houston or with a large presence here, including Owensboro, Ky.-based Boardwalk Pipeline Partners LP (NYSE: BWP), CenterPoint Energy Inc. (NYSE: CNP), Enterprise Products Partners LP (NYSE: EPD), Kinder Morgan Energy Partners LP (NYSE: KMP), Plains All American Pipeline LP (NYSE: PAA) and Spectra Energy Corp. (NYSE: SE).
Many of the projects are tapping into areas in East Texas and will be moving gas into southeast and northeast markets.
The energy markets information company said the current level of industry infrastructure expansion has not been seen since the interstate construction boom of the late 1940s and early 1950s.
"The pipeline and LNG projects represent a total of more than 25.4 billion cubic feet per day of additional capacity serving the Southeast Gulf region, with an additional 6.3 Bcf/d of new storage deliverability as well," said Russell Braziel, managing director of Bentek. "But there's a catch: In the short term there will not be enough incremental supplies to fill the new pipeline and LNG terminal capacity."
Bentek expects the initial shortfall to affect regional flows and pricing from projects that will displace or "steal" gas from traditional pipelines; increased demand and supplies; and LNG supplies competing for the same markets.
The study, released by Golden, Colo.-based Bentek Energy LLC, said 25 natural gas pipeline projects, 11 natural gas storage projects and four liquefied natural gas terminals are expected to shift gas flow patterns, disrupt regional pricing relationships and realign the value of transportation capacity across the most complex pipeline grid in North America between early 2008 and mid-year 2009.
Many of the projects under construction are by companies either based in Houston or with a large presence here, including Owensboro, Ky.-based Boardwalk Pipeline Partners LP (NYSE: BWP), CenterPoint Energy Inc. (NYSE: CNP), Enterprise Products Partners LP (NYSE: EPD), Kinder Morgan Energy Partners LP (NYSE: KMP), Plains All American Pipeline LP (NYSE: PAA) and Spectra Energy Corp. (NYSE: SE).
Many of the projects are tapping into areas in East Texas and will be moving gas into southeast and northeast markets.
The energy markets information company said the current level of industry infrastructure expansion has not been seen since the interstate construction boom of the late 1940s and early 1950s.
"The pipeline and LNG projects represent a total of more than 25.4 billion cubic feet per day of additional capacity serving the Southeast Gulf region, with an additional 6.3 Bcf/d of new storage deliverability as well," said Russell Braziel, managing director of Bentek. "But there's a catch: In the short term there will not be enough incremental supplies to fill the new pipeline and LNG terminal capacity."
Bentek expects the initial shortfall to affect regional flows and pricing from projects that will displace or "steal" gas from traditional pipelines; increased demand and supplies; and LNG supplies competing for the same markets.
Tuesday, March 25, 2008
Chesapeake Finds Natural Gas in Louisiana
Chesapeake Energy Corporation (NYSE:CHK) today announced a new natural gas discovery in the Haynesville Shale in Louisiana. In addition, the company announced two other new unconventional natural gas discoveries and five new unconventional oil projects. The company believes these discoveries and projects are significant and has decided to increase its capital expenditure budget for 2008 and 2009 in order to increase drilling and leasing activity on these new plays as well as its three most important existing unconventional shale plays: the Barnett Shale, the Fayetteville Shale and the Marcellus and Lower Huron Shales in Appalachia. Chesapeake Provides Information on the Haynesville Shale Discovery and Seven Other New Discoveries and Projects As a result of recent drilling results, Chesapeake is announcing eight new unconventional natural gas discoveries and unconventional oil projects described below. Haynesville Shale: Based on its geoscientific, petrophysical and engineering research during the past two years and the results of three horizontal and four vertical wells it has drilled, Chesapeake believes the Haynesville Shale play could potentially have a larger impact on the company than any other play in which it has participated to date. Chesapeake is currently utilizing four rigs to drill Haynesville Shale wells and plans to increase its drilling activity level to approximately 10 rigs by year-end 2008 and potentially more in 2009. The company currently owns or has commitments for more than 200,000 net acres of leasehold in the Haynesville Shale and has a leasehold acquisition effort underway with the goal of owning up to 500,000 net acres in the play. Colony Granite Wash (Anadarko Basin of western Oklahoma): Chesapeake is also announcing the discovery of the Colony Granite Wash play in Washita and Custer Counties, Oklahoma. Developed internally two years ago, the Colony Granite Wash play is now producing 40 million cubic feet of natural gas equivalent (mmcfe) per day net to the company from 12 net horizontal wells. Chesapeake is currently utilizing four rigs to further develop its leasehold of approximately 60,000 net acres in the Colony Granite Wash play that the company believes will accommodate the drilling of approximately 250 additional net horizontal wells over time. Mountain Front Granite Wash (Anadarko Basin of southwestern Oklahoma and Texas Panhandle): During the past few months, Chesapeake has drilled three horizontal Granite Wash wells along the 150 mile Mountain Front area of the Anadarko Basin. The company believes its current leasehold of approximately 75,000 net acres will accommodate the drilling of approximately 400 additional net horizontal wells over time. Five New Unconventional Oil Projects: Chesapeake is also announcing today that it has identified five new unconventional oil projects, four of which have been developed on a proprietary basis. The projects range in size from approximately 100,000 to 1,000,000 acres and are located in four different states in the U.S. Chesapeake has commenced oil production in two of the projects and initial drilling in the other projects is scheduled during the next 12 months. Chesapeake Increases Drilling and Leasehold Acquisition Activities in the Fort Worth Barnett Shale, Fayetteville Shale, Marcellus Shale and Lower Huron Shale Plays In addition to the increased drilling and leasing activity on the new discoveries and projects described above, Chesapeake plans to increase drilling and leasing activities in several of its existing shale plays discussed below. Fort Worth Barnett Shale (Greater Fort Worth Area): Chesapeake is continuing its drilling and leasing program in the Barnett Shale, particularly in the Core and Tier 1 sweet spot of Tarrant, Johnson and western Dallas counties. The company’s net natural gas production in the Barnett Shale is now approximately 450 mmcfe per day. Chesapeake plans to increase its Barnett Shale drilling activity by five rigs, from 40 to 45 rigs by year-end 2008. Fayetteville Shale (Arkansas): In the Fayetteville Shale, Chesapeake’s net natural gas production is now approximately 130 mmcfe per day. The company plans to increase its Fayetteville Shale drilling activity from 12 rigs currently to approximately 25 rigs by early 2009 in response to the company’s recent 10% increase in expected estimated ultimate per well recoveries for horizontal Fayetteville Shale wells. Marcellus and Lower Huron Shales (Kentucky, West Virginia, Pennsylvania and New York): Chesapeake owns a leasehold position of 1.6 million net acres in the Marcellus and Lower Huron Shale plays. The company has drilled 26 vertical and horizontal Marcellus and Lower Huron Shale wells to date and plans to drill approximately 165 vertical and horizontal Marcellus and Lower Huron Shale wells in 2008 and 2009. Company Raises Capital Spending Plans for Increased Drilling Activity and Leasehold Expenditures To capitalize on the new discoveries, projects and existing plays described above, Chesapeake is increasing its capital expenditure plans for 2008 and 2009. In light of higher per well reserve recovery expectations and decreasing per well costs in key shale plays, the company plans to increase its drilling activity levels in each of 2008 and 2009. Specifically, Chesapeake plans to increase its current drilling activity levels in the Fort Worth Barnett Shale, Fayetteville Shale and Haynesville Shale plays by 24 operated rigs by year-end 2008. As a result of the Haynesville Shale discovery and other new discoveries and projects, the company also plans to increase its leasehold expenditures to more fully capture the value of the plays and projects recently identified by Chesapeake. Chesapeake currently plans to spend an additional $275 million and $675 million for drilling and leasehold in 2008 and 2009, respectively, as compared to its previously announced spending plans. Chesapeake Raises 2008 and 2009 Production Forecasts and Increases Natural Gas Hedging Positions Due to higher recovery expectations in various plays and increased drilling activity levels, the company has raised its 2008 and 2009 production forecasts by 30 and 100 mmcfe per day, respectively. Accordingly, Chesapeake now expects its average daily production rate to increase in 2008 by approximately 21% over its 2007 average rate to 2,370 mmcfe per day and in 2009 by approximately 16% to 2,740 mmcfe per day. These are increases of 5% and 33%, respectively, over 2008 and 2009 production growth levels of 20% and 12% projected by the company last month. In response to the strength of natural gas prices experienced during early March, the company added to its 2008 and 2009 natural gas hedging position and began to hedge a portion of its expected production in 2010. Chesapeake currently has hedged, using swaps, approximately 71%, 40% and 12% of its expected 2008, 2009 and 2010 natural gas production at average NYMEX prices of $8.77, $9.13 and $9.34 per mcf, respectively. Additionally, the company has hedged, using collars, approximately 6% of its expected 2008 and 2009 natural gas production at an average NYMEX floor price of $7.88 per mcf and an average NYMEX ceiling price of $9.64 per mcf in 2008 and an average NYMEX floor price of $8.22 per mcf and an average NYMEX ceiling price of $10.70 per mcf in 2009. Depending on changes in oil and natural gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice. Company Revises Capital Funding Plans Due to New Discoveries and Increased Capital Expenditure Budgets Chesapeake believes the combination of developing the new discoveries and projects announced today, increasing drilling activity levels to accelerate the development of existing plays, and the higher cost of acquiring leasehold in some of the company's most important plays creates the need for an increase in the company's capital expenditures. The company had planned to fund its 2008 and 2009 capital expenditures through cash flow from operations, borrowings under its revolving credit facility, and from previously announced producing property monetizations and the sale of a minority interest in a private partnership for the company’s midstream assets. These initiatives remain on track for completion in the second quarter of 2008, although it is possible that current uncertainty in the financial markets could impact this timing. Considering that uncertainty and the increasing number of upside growth opportunities available, the company now expects to fund some or all of these additional expenditures through the public capital markets. Although a departure from its previously announced plans, Chesapeake believes that the potential incremental financial returns available from its increased capital spending will far exceed the expected capital costs. Management Comments Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, "We are very excited to announce our Haynesville Shale discovery and our seven other new unconventional gas discoveries and oil projects. We are proud of our collection of high-quality, growth-oriented onshore U.S. assets and as competitive conditions allow, we will provide investors with more information about our existing, emerging and new plays. "We believe we must invest the necessary capital to more fully capture the upside of our new opportunities. We remain focused on per-share value creation and we believe our shareholders will benefit from our increased investments in these new discoveries and projects and in our most important existing plays.” Conference Call Information A conference call to discuss this release has been scheduled for Tuesday, March 25, 2008 at 9:00 a.m. EDT. The telephone number to access the conference call is 913-981-5557 or toll-free 888-677-8775. The passcode for the call is 2609304. We encourage those who would like to participate in the call to dial the access number between 8:50 and 8:55 a.m. EDT. For those unable to participate in the conference call, a replay will be available for audio playback from noon EDT on March 25, 2008, and will run through midnight EDT on Tuesday, April 8, 2008. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 2609304. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake’s website at www.chk.com and selecting the "News & Events” section. The webcast of the conference call will be available on our website for one year. This press release includes "forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of oil and natural gas reserves, expected oil and natural gas production and future expenses, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information. Factors that could cause actual results to differ materially from expected results are described in "Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the U.S. Securities and Exchange Commission on February 29, 2008. These risk factors include the volatility of oil and natural gas prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent oil and natural gas companies and majors; the availability of capital on an economic basis to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and the amount and timing of development expenditures; uncertainties in evaluating oil and natural gas reserves of acquired properties and associated potential liabilities; unsuccessful exploration and development drilling; declines in the values of our oil and natural gas properties resulting in ceiling test write-downs; lower prices realized on oil and natural gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower oil and natural gas prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; production interruptions that could adversely affect our cash flow; and pending or future litigation. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. The SEC has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third-party engineers or appraisers. Chesapeake Energy Corporation is the largest independent and third-largest overall producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and corporate and property acquisitions in the Mid-Continent, Fort Worth Barnett Shale, Fayetteville Shale, Haynesville Shale, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast, Ark-La-Tex and Appalachian Basin
Monday, March 24, 2008
Bolivia Natural Gas Desired by Argentina & Brazil
The two countries depend on their poorer neighbor for gas to power homes, businesses and cars. But Bolivia's gas industry, stagnating after a decade of falling foreign investment, can no longer keep up with demand from the continent's two largest economies.
Last year, a frigid winter burned up Argentina's tight gas supply, causing a shortfall that idled factories and gas-powered taxis. And as the Southern Hemisphere heads for winter again, experts predict the situation could be worse.
Home to South America's second-largest natural-gas reserves, Bolivia produces some 1.4 billion cubic feet of it a day -- enough to feed domestic demand and a long-standing contract with Brazil, but not an ambitious 2006 export deal with Argentina.
Bolivia had gambled that the tight energy market would draw foreign investment needed to fulfill the new contract. But international companies have been wary of the nation's gas fields after President Evo Morales placed them under state control in 2006. Pledged support from Venezuela and Iran also has yet to materialize.
As investment finally begins to pick up, Bolivia expects to boost production by 5 percent this year, and another 11 percent in 2009, Vice President Alvaro Garcia said in February.
Meanwhile, energy-starved Brazil and Argentina are scrambling over the short supply.
At an energy summit last month, Argentina sought to increase its Bolivian gas imports by a third to roughly 140 million cubic feet a day for the coming winter. Morales asked Brazil, whose older gas contracts take precedence, to share with its southern neighbor.
But Brazil, which buys 1.1 billion cubic feet a day from Bolivia -- half the natural gas consumed by its 190 million residents -- could not spare "a single molecule," said Sergio Gabrielli, head of state energy company Petroleo Brasileiro S.A.
"We have to produce more gas," Bolivian Hydrocarbons Minister Carlos Villegas said after the summit.
Landlocked Bolivia is cut off from most international markets. It pipes gas only to its neighbors -- except for Chile, which Bolivians still resent for seizing their coastline in an 1879 war. Chile instead imports what little gas Argentina can spare.
That isolation has fostered a joint dependency with Brazil, which all but built Bolivia's hydrocarbons industry while using the cheap gas to fuel its own rapid economic growth.
But Bolivia's poor grew weary of watching their underground treasure feeding a neighbor's wealth, and elected Morales in 2005 on a pledge to reclaim state control of the energy industry.
His takeover of the sector the next year at first spooked the few foreign investors who hadn't already fled the politically unstable country.
Natural gas production has since flatlined, while Bolivia's government tripled its share of revenues and pumped the funds toward popular social programs.
The energy shortage has helped persuade private companies to open their wallets for now. Foreign investment more than quadrupled from less than $200 million in 2006 to $876 million promised so far for this year, though most is dedicated to pumping existing fields rather than developing new ones.
Bolivia's 2006 deal with Argentina would quadruple its export commitment to 978 million cubic feet a day by 2010, shipping the gas through a new $1.5 billion pipeline. But the hike in deliveries will now be pushed back until "2011, maybe 2012, or the middle of 2013," Garcia said last month. The pipeline's construction is on hold.The delays led some analysts to question Bolivia's grasp of the industry's calculated risks and long lead times.
"They seem to think you can put natural gas in a potato sack and load it on a truck and off it goes," said independent Bolivia-based energy consultant Andres Stepkowski.
Last year, a frigid winter burned up Argentina's tight gas supply, causing a shortfall that idled factories and gas-powered taxis. And as the Southern Hemisphere heads for winter again, experts predict the situation could be worse.
Home to South America's second-largest natural-gas reserves, Bolivia produces some 1.4 billion cubic feet of it a day -- enough to feed domestic demand and a long-standing contract with Brazil, but not an ambitious 2006 export deal with Argentina.
Bolivia had gambled that the tight energy market would draw foreign investment needed to fulfill the new contract. But international companies have been wary of the nation's gas fields after President Evo Morales placed them under state control in 2006. Pledged support from Venezuela and Iran also has yet to materialize.
As investment finally begins to pick up, Bolivia expects to boost production by 5 percent this year, and another 11 percent in 2009, Vice President Alvaro Garcia said in February.
Meanwhile, energy-starved Brazil and Argentina are scrambling over the short supply.
At an energy summit last month, Argentina sought to increase its Bolivian gas imports by a third to roughly 140 million cubic feet a day for the coming winter. Morales asked Brazil, whose older gas contracts take precedence, to share with its southern neighbor.
But Brazil, which buys 1.1 billion cubic feet a day from Bolivia -- half the natural gas consumed by its 190 million residents -- could not spare "a single molecule," said Sergio Gabrielli, head of state energy company Petroleo Brasileiro S.A.
"We have to produce more gas," Bolivian Hydrocarbons Minister Carlos Villegas said after the summit.
Landlocked Bolivia is cut off from most international markets. It pipes gas only to its neighbors -- except for Chile, which Bolivians still resent for seizing their coastline in an 1879 war. Chile instead imports what little gas Argentina can spare.
That isolation has fostered a joint dependency with Brazil, which all but built Bolivia's hydrocarbons industry while using the cheap gas to fuel its own rapid economic growth.
But Bolivia's poor grew weary of watching their underground treasure feeding a neighbor's wealth, and elected Morales in 2005 on a pledge to reclaim state control of the energy industry.
His takeover of the sector the next year at first spooked the few foreign investors who hadn't already fled the politically unstable country.
Natural gas production has since flatlined, while Bolivia's government tripled its share of revenues and pumped the funds toward popular social programs.
The energy shortage has helped persuade private companies to open their wallets for now. Foreign investment more than quadrupled from less than $200 million in 2006 to $876 million promised so far for this year, though most is dedicated to pumping existing fields rather than developing new ones.
Bolivia's 2006 deal with Argentina would quadruple its export commitment to 978 million cubic feet a day by 2010, shipping the gas through a new $1.5 billion pipeline. But the hike in deliveries will now be pushed back until "2011, maybe 2012, or the middle of 2013," Garcia said last month. The pipeline's construction is on hold.The delays led some analysts to question Bolivia's grasp of the industry's calculated risks and long lead times.
"They seem to think you can put natural gas in a potato sack and load it on a truck and off it goes," said independent Bolivia-based energy consultant Andres Stepkowski.
Sunday, March 23, 2008
Gazprom to Become Coal Giant for Natural Gas
March 21 (Bloomberg) -- OAO Gazprom, Russia's largest energy company, said methane captured from underground coal mines may provide a ``serious'' addition to resources as producing natural- gas fields in Siberia decline.
The state-run gas exporter plans to take the first steps toward producing methane from coal seams this year or next, the Moscow-based company said in an e-mailed statement today after Deputy Chief Executive Alexander Ananenkov met with the governor of the coal-rich Kemerovo region.
The gas reserves held in Russia's coal seams may stand at 49 trillion cubic meters, equal to about a fifth of the country's reserves in conventional fields, Gazprom said. The gas producer, which also owns oil and electricity assets, is seeking to become Russia's largest coal miner after pooling assets with OAO Siberian Coal Energy Co., also known as SUEK.
The state-run gas exporter plans to take the first steps toward producing methane from coal seams this year or next, the Moscow-based company said in an e-mailed statement today after Deputy Chief Executive Alexander Ananenkov met with the governor of the coal-rich Kemerovo region.
The gas reserves held in Russia's coal seams may stand at 49 trillion cubic meters, equal to about a fifth of the country's reserves in conventional fields, Gazprom said. The gas producer, which also owns oil and electricity assets, is seeking to become Russia's largest coal miner after pooling assets with OAO Siberian Coal Energy Co., also known as SUEK.
India Negotiating Natural Gas Pipeline with Iran
Mumbai, March 21 India will soon start negotiations with Iran and Pakistan on the Iran-India gas pipeline. The negotiations will resume after the formation of the new government in Pakistan, said Mr Murli Deora, Union Minister for Petroleum and Natural Gas, speaking to reporters on the sidelines of the PetroFed award function on Friday.
The focal point of the negotiations would be the ‘carrying cess on gas’, which would be levied while gas is transported from Iran to the India-Pakistan border, he said.
“We expect to settle this issue (carrying cess) in the two rounds of negotiations. We are hopeful of reaching an agreement with the Pakistan government,” Mr Deora said.
NELP regime
The Minister said that the response to the seventh round of NELP (New Exploration Licensing Policy) was “excellent”. Road shows would be soon held in Australia, Singapore and Venezuela, he added. Almost all the global oil majors, including Chevron and British Gas, have assured their participation, he said.
The Union Government’s initiatives under the new exploration licensing policy have started bearing fruit, according to the Minister.
Before implementation of NELP, only 11 per cent of the Indian sedimentary basins were under exploration. So far under the NELP regime, 49 oil and gas discoveries have been made in 15 blocks, which have added more than 600 million tonnes of oil equivalent hydrocarbon reserves.
During the XI Plan the area under exploration has been targeted at 80 per cent of the Indian sedimentary basin area. By 2015, the ministry proposes to have 100 per cent of the Indian sedimentary basin area under exploration. The Government is in the process of framing parameters for an open acreage policy, he said.
Oil prices, exports
“The country is also in the process of adding substantial refining capacity to become a refining hub. Even today, the refining capacity is more than the consumption of petroleum products and our exports of oil products constitute the single largest export item from the country,” he said.
On the issue of oil price hike, Mr Deora said that in spite major of crude price escalation, the country is prepared to take the price hike. The foreign exchange and foreign remittances levels are high, which is a good indicator, he said.
The focal point of the negotiations would be the ‘carrying cess on gas’, which would be levied while gas is transported from Iran to the India-Pakistan border, he said.
“We expect to settle this issue (carrying cess) in the two rounds of negotiations. We are hopeful of reaching an agreement with the Pakistan government,” Mr Deora said.
NELP regime
The Minister said that the response to the seventh round of NELP (New Exploration Licensing Policy) was “excellent”. Road shows would be soon held in Australia, Singapore and Venezuela, he added. Almost all the global oil majors, including Chevron and British Gas, have assured their participation, he said.
The Union Government’s initiatives under the new exploration licensing policy have started bearing fruit, according to the Minister.
Before implementation of NELP, only 11 per cent of the Indian sedimentary basins were under exploration. So far under the NELP regime, 49 oil and gas discoveries have been made in 15 blocks, which have added more than 600 million tonnes of oil equivalent hydrocarbon reserves.
During the XI Plan the area under exploration has been targeted at 80 per cent of the Indian sedimentary basin area. By 2015, the ministry proposes to have 100 per cent of the Indian sedimentary basin area under exploration. The Government is in the process of framing parameters for an open acreage policy, he said.
Oil prices, exports
“The country is also in the process of adding substantial refining capacity to become a refining hub. Even today, the refining capacity is more than the consumption of petroleum products and our exports of oil products constitute the single largest export item from the country,” he said.
On the issue of oil price hike, Mr Deora said that in spite major of crude price escalation, the country is prepared to take the price hike. The foreign exchange and foreign remittances levels are high, which is a good indicator, he said.
Saturday, March 22, 2008
Arkansas to Raise Severance Tax on Natural Gas
The House and Senate leaders said Thursday that Gov. Mike Beebe likely has the three-fourths majority votes he needs in both chambers to raise the state severance tax on natural gas.
Beebe should know by today whether he will call the Legislature into special session to enact the tax hike he negotiated with the gas companies operating in the state, his spokesman Matt DeCample said.
"It's looking like a decision will be made (Friday)," DeCample said after legislators got their first look at draft legislation Thursday afternoon during a joint meeting of the House and Senate Revenue and Taxation committees.
At least 75 of the 100 House members and 27 of the 35 state senators must vote for the proposal to reach the three-fourths majority required to raise the severance for the first time since 1957.
Beebe should know by today whether he will call the Legislature into special session to enact the tax hike he negotiated with the gas companies operating in the state, his spokesman Matt DeCample said.
"It's looking like a decision will be made (Friday)," DeCample said after legislators got their first look at draft legislation Thursday afternoon during a joint meeting of the House and Senate Revenue and Taxation committees.
At least 75 of the 100 House members and 27 of the 35 state senators must vote for the proposal to reach the three-fourths majority required to raise the severance for the first time since 1957.
Friday, March 21, 2008
Liquid Natural Gas Plant Approved for Long Island, New York
The Federal Energy Regulatory Commission approved a $700 million liquefied natural gas terminal on Thursday for Long Island Sound, but the project faces opposition on environmental grounds and the possibility of a catastrophe should the terminal become the target of a terrorist attack.
New York officials have yet to decide whether to issue permits for the project, and Connecticut officials have warned that they will fight it to the United States Supreme Court.
Broadwater Energy, a consortium of Shell Oil and TransCanada Pipelines, wants to build the terminal, which would sit 9 miles from Long Island and 10 miles from Connecticut. Plans call for construction to begin in October 2009 and for the terminal to be operating by December 2010.
The commission, which voted 5 to 0 to approve the project, says it will be the first floating terminal in the United States for storage and delivery of natural gas.
“It’s a reasonable and sensible decision,” said Gary Hale, a Broadwater spokesman. “They have input from thousands of hours of efforts from the best scientific minds in the nation, environmentalists, and from the Coast Guard.”
Mr. Hale said the terminal was needed to meet the region’s growing energy needs. The New York State Energy Plan projects a 37 percent growth in statewide natural gas use by 2021.
About half of the gas from the terminal would go to New York City. Twenty-five percent to 30 percent would go to Long Island, and the rest would go to Connecticut.
Former Gov. Eliot Spitzer had planned to decide next month whether the state should issue permits for the project. Gov. David A. Paterson has said he may postpone that decision.
Mr. Hale said he expected delays but was confident that the terminal would be built.
“Some officials have talked about using Connecticut resources to go to court to appeal this, which I feel would be a waste of time and money, but I suspect that will happen,” he said.
Attorney General Richard Blumenthal of Connecticut said he planned to ask for an immediate rehearing and would take the state’s arguments to the Supreme Court if necessary.
New York officials have yet to decide whether to issue permits for the project, and Connecticut officials have warned that they will fight it to the United States Supreme Court.
Broadwater Energy, a consortium of Shell Oil and TransCanada Pipelines, wants to build the terminal, which would sit 9 miles from Long Island and 10 miles from Connecticut. Plans call for construction to begin in October 2009 and for the terminal to be operating by December 2010.
The commission, which voted 5 to 0 to approve the project, says it will be the first floating terminal in the United States for storage and delivery of natural gas.
“It’s a reasonable and sensible decision,” said Gary Hale, a Broadwater spokesman. “They have input from thousands of hours of efforts from the best scientific minds in the nation, environmentalists, and from the Coast Guard.”
Mr. Hale said the terminal was needed to meet the region’s growing energy needs. The New York State Energy Plan projects a 37 percent growth in statewide natural gas use by 2021.
About half of the gas from the terminal would go to New York City. Twenty-five percent to 30 percent would go to Long Island, and the rest would go to Connecticut.
Former Gov. Eliot Spitzer had planned to decide next month whether the state should issue permits for the project. Gov. David A. Paterson has said he may postpone that decision.
Mr. Hale said he expected delays but was confident that the terminal would be built.
“Some officials have talked about using Connecticut resources to go to court to appeal this, which I feel would be a waste of time and money, but I suspect that will happen,” he said.
Attorney General Richard Blumenthal of Connecticut said he planned to ask for an immediate rehearing and would take the state’s arguments to the Supreme Court if necessary.
Thursday, March 20, 2008
Switzerland & Iran Inked 25 Year Natural Gas Deal!
Iran signed a natural gas export contract with a Swiss energy group on Monday, the Iranian foreign minister said.
The 25-year gas deal between the National Iranian Gas Export Company (NIGEC) and Switzerland's Elektrizitaetsgesellschaft Laufenburg (EGL) was finalized in September last year. Under the deal, Iran has to deliver 5.5 billion cubic meters of gas per year to Europe via a pipeline scheduled to be complete in 2010.
"Today, we have witnessed the signing of an important gas agreement between companies of the two countries," Manouchehr Mottaki said at a joint news conference with his Swiss counterpart Micheline Calmy-Rey, who is currently on a visit to Iran.
The Swiss minister said the bilateral deal did not violate United Nations sanctions imposed on Iran over its controversial nuclear program and served only to secure uninterrupted energy supplies to her country.
"We have a strategic interest to secure our gas supplies and diversify our gas suppliers," Calmy-Rey said.
She also said the current deal may reduce Europe's dependency on energy supplies from Russia.
"We are decreasing our dependence, and the dependence of Europe, on Russian gas," she said.
Russia's energy giant Gazprom announced last week that the average price for natural gas for Europe in 2008 could reach $400 per 1,000 cubic meters, 13% more than previously expected.
The 25-year gas deal between the National Iranian Gas Export Company (NIGEC) and Switzerland's Elektrizitaetsgesellschaft Laufenburg (EGL) was finalized in September last year. Under the deal, Iran has to deliver 5.5 billion cubic meters of gas per year to Europe via a pipeline scheduled to be complete in 2010.
"Today, we have witnessed the signing of an important gas agreement between companies of the two countries," Manouchehr Mottaki said at a joint news conference with his Swiss counterpart Micheline Calmy-Rey, who is currently on a visit to Iran.
The Swiss minister said the bilateral deal did not violate United Nations sanctions imposed on Iran over its controversial nuclear program and served only to secure uninterrupted energy supplies to her country.
"We have a strategic interest to secure our gas supplies and diversify our gas suppliers," Calmy-Rey said.
She also said the current deal may reduce Europe's dependency on energy supplies from Russia.
"We are decreasing our dependence, and the dependence of Europe, on Russian gas," she said.
Russia's energy giant Gazprom announced last week that the average price for natural gas for Europe in 2008 could reach $400 per 1,000 cubic meters, 13% more than previously expected.
Wednesday, March 19, 2008
Raymond James - Natural Gas Prices to Fall this Summer
Shares in onshore drilling contractors have rallied alongside natural gas prices, but some say it's too early to call a recovery in the market that has been dogged by overcapacity.
Land-based drilling companies have outperformed most oilfield service companies this year, as cold winter weather and smaller-then-expected imports of liquefied natural gas have pushed gas futures prices up nearly 40 percent.
But so far, there are only small signs of life in the U.S. onshore markets, suggesting that the stocks may have gotten ahead of themselves.
"While we can't blame most for jumping on the bullish bandwagon, our view is that natural gas prices still fall this summer," Raymond James wrote in a note to clients last week. "This should drive activity lower and leave the market oversupplied and overly optimistic."
As a result, Wall Street earnings estimates are too high and need to be lowered, the firm said.
Raymond James sees higher imports of LNG and increased production weighing on natural gas prices in coming months, although the research firm has become less bearish in its outlook due to the winter's colder than expected weather.
Still, shares of Nabors Industries Ltd are up 15 percent this year, Grey Wolf Inc has risen 15 percent, Patterson-UTI Energy Inc is up 16 percent and Pioneer Drilling Co has climbed 25 percent.
By comparison, an index of drilling companies which includes offshore drillers .15GSPOILD is up about 1 percent on the year.
In January, analysts had forecast gas prices would average $7.30 per thousand BTU, up from $6.95 in 2007, although many experts have raised their expectations by about $1 in recent weeks because of strong demand.
Land-based drilling companies have outperformed most oilfield service companies this year, as cold winter weather and smaller-then-expected imports of liquefied natural gas have pushed gas futures prices up nearly 40 percent.
But so far, there are only small signs of life in the U.S. onshore markets, suggesting that the stocks may have gotten ahead of themselves.
"While we can't blame most for jumping on the bullish bandwagon, our view is that natural gas prices still fall this summer," Raymond James wrote in a note to clients last week. "This should drive activity lower and leave the market oversupplied and overly optimistic."
As a result, Wall Street earnings estimates are too high and need to be lowered, the firm said.
Raymond James sees higher imports of LNG and increased production weighing on natural gas prices in coming months, although the research firm has become less bearish in its outlook due to the winter's colder than expected weather.
Still, shares of Nabors Industries Ltd are up 15 percent this year, Grey Wolf Inc has risen 15 percent, Patterson-UTI Energy Inc is up 16 percent and Pioneer Drilling Co has climbed 25 percent.
By comparison, an index of drilling companies which includes offshore drillers .15GSPOILD is up about 1 percent on the year.
In January, analysts had forecast gas prices would average $7.30 per thousand BTU, up from $6.95 in 2007, although many experts have raised their expectations by about $1 in recent weeks because of strong demand.
Tuesday, March 18, 2008
Natural Gas Found in Egypt by BP & ENI
CAIRO, March 18 (Reuters) - A natural gas find in an area controlled by BP (BP.L: Quote, Profile, Research) and a subsidiary of Italian firm ENI (ENI.MI: Quote, Profile, Research) could hold one trillion square feet of reserves, the Egyptian state news agency MENA said.
BP and ENI subsidiary IEOC had bought rights to the eastern Mediterranean area where the gas was found 22,000 feet below sea level, Mahmoud Latif, chairman of state-owned Egyptian Natural Gas Holding Company, was quoted by MENA on Monday.
BP and ENI subsidiary IEOC had bought rights to the eastern Mediterranean area where the gas was found 22,000 feet below sea level, Mahmoud Latif, chairman of state-owned Egyptian Natural Gas Holding Company, was quoted by MENA on Monday.
Monday, March 17, 2008
Feds to Rule - LNG in New York
This week, the federal government will weigh a controversial energy decision for the Northeast—whether to allow a floating liquefied natural gas terminal to be moored 10 miles off the shore of New York in the middle of Long Island Sound. The 1,200-foot barge would accept supercooled fuel from Africa and the Middle East, process it back into a gas, and send it by pipeline to New York and Connecticut.
I wrote this story explaining LNG and the environmental and security concerns. Such issues are very much alive in this Broadwater project, a joint venture of Shell and TransCanada Pipeline. Connecticut Gov. Jodi Rell leads the opposition on environmental grounds.
In the New York governor's office, which changes hands today, Eliot Spitzer was going to make his position known by April 12, but David Paterson, who succeeds Spitzer as governor this afternoon, says that timeline will probably be delayed. The Connecticut Post editorializes: "The dramatic downfall of New York Gov. Eliot Spitzer will have impacts far beyond the Empire State, and one of them might be in the middle of Long Island Sound."
Coast Guard Commandant Thad Allen said at a congressional hearing earlier this month that his forces do not have the resources to protect the LNG tankers from terrorist threats in Long Island Sound and that there needs to be a national discussion of security demands on hazardous freight.
Yet the federal siting decision isn't in the hands of the Coast Guard but the Federal Energy Regulatory Commission, which is slated to consider Broadwater at a hearing on Thursday. After that, the project still must obtain state approvals to proceed.
Just last week, there was a relevant discussion at the National Academy of Sciences energy summit—not about Broadwater but about the United States's evolution into a country that acquired all of its natural gas from North America (80 percent domestically) to a country that relies on natural gas imports through LNG.
Steven Specker, president and chief executive officer of the electric industry's Electric Power Research Institute, said that the price of LNG appears to be linked to the price of that other vital energy commodity we import, oil. That's the commodity that broke $110 a barrel last week, while natural gas prices recently have been relatively moderate. Natural gas fires a significant portion of the nation's electricity. So what happens with LNG will show up in consumer power bills.
"We are on a path for linking the price of electricity to the price of oil by 2012 to 2015," Specker said. "That is only going to get more so if we have limited options. Gas is the default option [for electricity] that we are going to use for the next few years. It's wonderful—it's much lower in [carbon dioxide emissions]. And we're going to have a good bit of LNG coming on the market between now and 2010. So we may have a situation where the price goes down and is delinked from oil for a few years. That will just be a head fake because, by 2012 and 2015, we may find ourselves in a real difficult situation."
So those who fear damage to Long Island Sound, or adding another terrorist target near New York, should add to their worries the possibility that we are carving out an energy future even more reliant on imports, where power for our homes is just as volatile in price as the fuel for our cars. But the reason we are vulnerable to any of these threats is because we haven't found a way to cut our insatiable demand for energy. The Big Oil/Big Natural Gas companies have done the calculations; they're betting they'll find buyers for what they're selling in the Northeast—even if it's at a newly global price.
I wrote this story explaining LNG and the environmental and security concerns. Such issues are very much alive in this Broadwater project, a joint venture of Shell and TransCanada Pipeline. Connecticut Gov. Jodi Rell leads the opposition on environmental grounds.
In the New York governor's office, which changes hands today, Eliot Spitzer was going to make his position known by April 12, but David Paterson, who succeeds Spitzer as governor this afternoon, says that timeline will probably be delayed. The Connecticut Post editorializes: "The dramatic downfall of New York Gov. Eliot Spitzer will have impacts far beyond the Empire State, and one of them might be in the middle of Long Island Sound."
Coast Guard Commandant Thad Allen said at a congressional hearing earlier this month that his forces do not have the resources to protect the LNG tankers from terrorist threats in Long Island Sound and that there needs to be a national discussion of security demands on hazardous freight.
Yet the federal siting decision isn't in the hands of the Coast Guard but the Federal Energy Regulatory Commission, which is slated to consider Broadwater at a hearing on Thursday. After that, the project still must obtain state approvals to proceed.
Just last week, there was a relevant discussion at the National Academy of Sciences energy summit—not about Broadwater but about the United States's evolution into a country that acquired all of its natural gas from North America (80 percent domestically) to a country that relies on natural gas imports through LNG.
Steven Specker, president and chief executive officer of the electric industry's Electric Power Research Institute, said that the price of LNG appears to be linked to the price of that other vital energy commodity we import, oil. That's the commodity that broke $110 a barrel last week, while natural gas prices recently have been relatively moderate. Natural gas fires a significant portion of the nation's electricity. So what happens with LNG will show up in consumer power bills.
"We are on a path for linking the price of electricity to the price of oil by 2012 to 2015," Specker said. "That is only going to get more so if we have limited options. Gas is the default option [for electricity] that we are going to use for the next few years. It's wonderful—it's much lower in [carbon dioxide emissions]. And we're going to have a good bit of LNG coming on the market between now and 2010. So we may have a situation where the price goes down and is delinked from oil for a few years. That will just be a head fake because, by 2012 and 2015, we may find ourselves in a real difficult situation."
So those who fear damage to Long Island Sound, or adding another terrorist target near New York, should add to their worries the possibility that we are carving out an energy future even more reliant on imports, where power for our homes is just as volatile in price as the fuel for our cars. But the reason we are vulnerable to any of these threats is because we haven't found a way to cut our insatiable demand for energy. The Big Oil/Big Natural Gas companies have done the calculations; they're betting they'll find buyers for what they're selling in the Northeast—even if it's at a newly global price.
Sunday, March 16, 2008
Arkansas Natural Gas Big State Revenue Issue
LITTLE ROCK - The Fayetteville Shale play, a rock formation encompassing multiple counties in North-Central Arkansas and holding vast reservoirs of natural gas, is at the center of the state's political, economical and environmental discussions. A 2008 study by the University of Arkansas estimated the shale play would generate $17.9 billion and more than 11,000 jobs for the state's economy through 2012. This weekly report notes highlights from activities in, and matters concerning, the Fayetteville Shale play.
Beebe, industry agree to severance tax increase, legislators question proposal
LITTLE ROCK - Gov. Mike Beebe said Tuesday he did not budge in five months of negotiations with natural gas industry officials that resulted in a tentative agreement to raise the state severance tax for the first time in more than 50 years.
The pact would generate about $57 million next year if the Legislature approved it in a special session the governor said he wants to call by the end of the month if lawmakers appear inclined to provide the supermajority votes in both chambers needed for approval.
The proposal would raise the severance tax, at three-tenths of 1 cent per 1,000 cubic feet of gas among the lowest in the nation, to 5 percent of market value at the time of extraction.
Gas from "high cost" wells would be taxed at 1.5 percent for the first three years of production to allow producers to recover their costs, Beebe said. Well owners who did not recover their costs within that time frame could apply for a 12-month extension.
*
High cost wells incapable of producing more than 100 million cubic feet (mcf) of gas per day would be classified as "marginal gas wells" and be taxed at a rate of 1.25 percent, as would non-high cost wells incapable of producing more than 250 mcf per day.
All other wells producing commercial quantities would be taxed at a 1.5 percent rate for the first two years of production, Beebe said.
The tax increase would go into effect Jan. 1, 2009, and would raise $57.1 million in 2009, based on conservative estimates of gas price and production levels from both industry and government officials, Beebe said. The 2009 figure is based upon an $8 gas price assumption, although the current market value of gas is nearer to $9 "and appears to be going up all the time," Beebe said.
Projections show tax proceeds peaking at $101.6 million in 2015, Beebe said.
Of the revenue generated, 95 percent would go to road improvements. Of that, 70 percent would go for state highways, and counties and cities would receive 15 percent each, Beebe said.
Updated study: Fayetteville Shale's economic impact $17.9 billion through '12
LITTLE ROCK - Natural gas drilling in the eight-county Fayetteville Shale play will produce a $17.9 billion economic benefit to the state through 2012, an updated University of Arkansas study released Thursday projects.
The study by the UA Center for Business and Economic Research also concluded that a severance tax rate of 5 percent of market value without reductions or exemptions would negatively affect the projection by 13 percent.
Calculations show economic output in 2007 alone was $2.6 billion, 62.5 percent higher than the $1.6 billion estimated for last year in the first study. The study also found that drilling and related activities accounted for 9,533 jobs in 2007, 43.1 percent more than originally anticipated and close to the 10,000 jobs the original study projected would be created through 2008.
More than 11,000 jobs will be tied to the industry every year through 2012, the new study found.
More than 80 companies with activities in the shale play provided information for the $28,000 study, paid for by Arkansas Land and Exploration LLC, Chesapeake Energy Corp., Petrohawk Energy Corp. and Southwestern Energy Co. The first study was paid for by Southwestern.
According to survey respondents, an average price of $6.21 per million British thermal units (MMBTU) is necessary for the forecasted investments to be made, Deck said.
Beebe, industry agree to severance tax increase, legislators question proposal
LITTLE ROCK - Gov. Mike Beebe said Tuesday he did not budge in five months of negotiations with natural gas industry officials that resulted in a tentative agreement to raise the state severance tax for the first time in more than 50 years.
The pact would generate about $57 million next year if the Legislature approved it in a special session the governor said he wants to call by the end of the month if lawmakers appear inclined to provide the supermajority votes in both chambers needed for approval.
The proposal would raise the severance tax, at three-tenths of 1 cent per 1,000 cubic feet of gas among the lowest in the nation, to 5 percent of market value at the time of extraction.
Gas from "high cost" wells would be taxed at 1.5 percent for the first three years of production to allow producers to recover their costs, Beebe said. Well owners who did not recover their costs within that time frame could apply for a 12-month extension.
*
High cost wells incapable of producing more than 100 million cubic feet (mcf) of gas per day would be classified as "marginal gas wells" and be taxed at a rate of 1.25 percent, as would non-high cost wells incapable of producing more than 250 mcf per day.
All other wells producing commercial quantities would be taxed at a 1.5 percent rate for the first two years of production, Beebe said.
The tax increase would go into effect Jan. 1, 2009, and would raise $57.1 million in 2009, based on conservative estimates of gas price and production levels from both industry and government officials, Beebe said. The 2009 figure is based upon an $8 gas price assumption, although the current market value of gas is nearer to $9 "and appears to be going up all the time," Beebe said.
Projections show tax proceeds peaking at $101.6 million in 2015, Beebe said.
Of the revenue generated, 95 percent would go to road improvements. Of that, 70 percent would go for state highways, and counties and cities would receive 15 percent each, Beebe said.
Updated study: Fayetteville Shale's economic impact $17.9 billion through '12
LITTLE ROCK - Natural gas drilling in the eight-county Fayetteville Shale play will produce a $17.9 billion economic benefit to the state through 2012, an updated University of Arkansas study released Thursday projects.
The study by the UA Center for Business and Economic Research also concluded that a severance tax rate of 5 percent of market value without reductions or exemptions would negatively affect the projection by 13 percent.
Calculations show economic output in 2007 alone was $2.6 billion, 62.5 percent higher than the $1.6 billion estimated for last year in the first study. The study also found that drilling and related activities accounted for 9,533 jobs in 2007, 43.1 percent more than originally anticipated and close to the 10,000 jobs the original study projected would be created through 2008.
More than 11,000 jobs will be tied to the industry every year through 2012, the new study found.
More than 80 companies with activities in the shale play provided information for the $28,000 study, paid for by Arkansas Land and Exploration LLC, Chesapeake Energy Corp., Petrohawk Energy Corp. and Southwestern Energy Co. The first study was paid for by Southwestern.
According to survey respondents, an average price of $6.21 per million British thermal units (MMBTU) is necessary for the forecasted investments to be made, Deck said.
Saturday, March 15, 2008
Mountain Natural Gas Pipeline to Equal Market Price
In the Rocky Mountains, the energy crisis has mostly been a crisis for natural gas producers and a boon for consumers.
Last fall, gas suppliers competing to stuff excess production into constrained pipeline systems drove spot prices to a laughably low 5 cents for 1,000 cubic feet of gas. That's the equivalent of a nickel to heat a typical house for two winter days.
"A lot of producers didn't think it was funny," said Porter Bennett, president and chief executive for energy analysts Bentek Energy LLC. "They were actually paying somebody to take it." Storing gas or turning off wells isn't always practical.
Yet for consumers across much of the West, where natural gas historically has been cheap and plentiful, the party is almost over, and it may have ended with that final discount splurge. The first of a handful of major new pipelines originating in the Rocky Mountains is starting to siphon away the bounty, promising lower prices for other regions.
"If you don't care about the rest of the country, it's not such a good thing," Bennett said in Golden, Colo. "We kind of get screwed in the deal."
Gas suppliers say this equation works both ways — if they can't maximize profits, fewer companies would bother drilling for natural gas in the West, which could lead to shortages and higher prices. They say gas production will continue to soar, keeping prices around here under control.
The new pipelines will take the Rockies' landlocked supply to major markets in California, the Phoenix area and flood the Midwest, where it can free up other supplies for the gas-starved Northeast.
The so-called big dog of these new pipelines — the 1,678-mile Rockies Express from Meeker, Colo., to Clarington, Ohio, — is largely built and partly operational. It's the biggest pipeline project in the continental U.S. in the past quarter-century, said Joe Hollier, a spokesman for builder Kinder Morgan Energy Partners.
Nearing full capacity, the Rockies Express will move 1.6 billion cubic feet of natural gas a day — a third more gas than the daily consumption of Denver and other cities along Colorado's Rocky Mountain Front.
Besides making more money for gas suppliers here, analysts say the new pipelines will even out national supplies and lop off price spikes in other regions, especially the East, but at the expense of Rocky Mountain states.
"We have felt the impact," said Mark Stutz, a spokesman for Colorado's Xcel Energy, which has been forced to raise rates by 36 percent this heating season and blames the new Rockies Express pipeline for the competition.
"The concern is that we are going to be paying prices that are more analogous to what we're seeing in the Midwest or California," he said. That could mean a doubling of rates, though analysts see more moderate, gradual increases.
Even now, relatively low prices persist in the Rocky Mountains because gas production is soaring with the price of oil, and new pipelines can quickly get leased to capacity, leaving some competition among producers.
A survey by The Associated Press found that households across the Rocky Mountains buying natural gas from major utilities pay as little as $6.36 a decatherm, a heat value roughly equal to 1,000 cubic feet of gas, depending on the quality.
In other parts of the continent, notably Georgia and South Carolina, natural gas can top $25 a decatherm. Hawaii has the country's highest average prices at more than $34, according to the U.S. Energy Information Administration.
Arizona has some of the West's highest prices for natural gas, but the doubling up of a pipeline from northwestern New Mexico will moderate higher-cost gas from Texas, said Libby Howell, a spokeswoman for Arizona's major supplier, Southwest Gas. It charges winter rates of $15.15 a decatherm.
As long as gas production continues to ramp up in the Rocky Mountains, producers argue, local prices should stay under control.
And the outlook for gas production is strong, says Keith Rattie, chairman and chief executive of Salt Lake City-based Questar Corp., a gas driller and utility that has been beefing up its own pipeline systems in parts of Colorado, Utah and Wyoming and has huge reserves of gas.
"The producers are drilling away," he said.
Texas is the country's biggest producer of gas, but there's no shortage in the West. Beside working gas fields and known supplies, the Rocky Mountains alone contain more than 200 trillion cubic feet of probable natural gas reserves — a 10-year supply for whole nation, said John Curtis, a geologist who runs the Potential Gas Agency at the Colorado School of Mines.
For decades that gas sold for cheap. Now, suppliers are giddy at the prospects of higher profits.
Largely because of the new pipelines, Questar, among other Rocky Mountain producers, is planning to hold back no gas in storage this year. Questar hooked up to the Rockies Express in December.
"We're off to a good start," Rattie told investors in a conference call Feb. 13 on the company's performance. "Rockies prices should be much higher this year."
Not every gas driller is convinced.
"I'm personally very skeptical about getting in the Rockies for gas production, because the market is so volatile and weak at times," said Sidney J. Jansma Jr., president and chief executive of Grand Rapids, Mich.-based Wolverine Gas & Oil Corp., which is producing 10 percent of Utah's crude oil after making a wildcat discovery in 2004.
"I'd rather work somewhere else. I've got a big project I'm working in Ohio where I'm going to get the return I need producing natural gas," said Jansma. He started drilling in Ohio on Feb. 21.
Consumers generally are buffered from the highs and lows of market prices for natural gas, but their regulated rates follow general trends.
In Utah, which has the lowest average natural gas prices outside Alaska, the major utility Questar Corp. delivers gas for $8.17 a decatherm, plus taxes.
Questar's Utah customers have special protection from price hikes. Under a court ruling 32 years ago, Questar was forced to sell gas from its Wyoming fields at no more than the cost of production to its Utah ratepayers, who helped pay for the drilling. Utah consumers get 40 percent of their heating gas through this arrangement, which will continue to buffer them from market upswings.
"The ratepayers totally won," said Daniel Berman, a Salt Lake City attorney who handled the case.
Last fall, gas suppliers competing to stuff excess production into constrained pipeline systems drove spot prices to a laughably low 5 cents for 1,000 cubic feet of gas. That's the equivalent of a nickel to heat a typical house for two winter days.
"A lot of producers didn't think it was funny," said Porter Bennett, president and chief executive for energy analysts Bentek Energy LLC. "They were actually paying somebody to take it." Storing gas or turning off wells isn't always practical.
Yet for consumers across much of the West, where natural gas historically has been cheap and plentiful, the party is almost over, and it may have ended with that final discount splurge. The first of a handful of major new pipelines originating in the Rocky Mountains is starting to siphon away the bounty, promising lower prices for other regions.
"If you don't care about the rest of the country, it's not such a good thing," Bennett said in Golden, Colo. "We kind of get screwed in the deal."
Gas suppliers say this equation works both ways — if they can't maximize profits, fewer companies would bother drilling for natural gas in the West, which could lead to shortages and higher prices. They say gas production will continue to soar, keeping prices around here under control.
The new pipelines will take the Rockies' landlocked supply to major markets in California, the Phoenix area and flood the Midwest, where it can free up other supplies for the gas-starved Northeast.
The so-called big dog of these new pipelines — the 1,678-mile Rockies Express from Meeker, Colo., to Clarington, Ohio, — is largely built and partly operational. It's the biggest pipeline project in the continental U.S. in the past quarter-century, said Joe Hollier, a spokesman for builder Kinder Morgan Energy Partners.
Nearing full capacity, the Rockies Express will move 1.6 billion cubic feet of natural gas a day — a third more gas than the daily consumption of Denver and other cities along Colorado's Rocky Mountain Front.
Besides making more money for gas suppliers here, analysts say the new pipelines will even out national supplies and lop off price spikes in other regions, especially the East, but at the expense of Rocky Mountain states.
"We have felt the impact," said Mark Stutz, a spokesman for Colorado's Xcel Energy, which has been forced to raise rates by 36 percent this heating season and blames the new Rockies Express pipeline for the competition.
"The concern is that we are going to be paying prices that are more analogous to what we're seeing in the Midwest or California," he said. That could mean a doubling of rates, though analysts see more moderate, gradual increases.
Even now, relatively low prices persist in the Rocky Mountains because gas production is soaring with the price of oil, and new pipelines can quickly get leased to capacity, leaving some competition among producers.
A survey by The Associated Press found that households across the Rocky Mountains buying natural gas from major utilities pay as little as $6.36 a decatherm, a heat value roughly equal to 1,000 cubic feet of gas, depending on the quality.
In other parts of the continent, notably Georgia and South Carolina, natural gas can top $25 a decatherm. Hawaii has the country's highest average prices at more than $34, according to the U.S. Energy Information Administration.
Arizona has some of the West's highest prices for natural gas, but the doubling up of a pipeline from northwestern New Mexico will moderate higher-cost gas from Texas, said Libby Howell, a spokeswoman for Arizona's major supplier, Southwest Gas. It charges winter rates of $15.15 a decatherm.
As long as gas production continues to ramp up in the Rocky Mountains, producers argue, local prices should stay under control.
And the outlook for gas production is strong, says Keith Rattie, chairman and chief executive of Salt Lake City-based Questar Corp., a gas driller and utility that has been beefing up its own pipeline systems in parts of Colorado, Utah and Wyoming and has huge reserves of gas.
"The producers are drilling away," he said.
Texas is the country's biggest producer of gas, but there's no shortage in the West. Beside working gas fields and known supplies, the Rocky Mountains alone contain more than 200 trillion cubic feet of probable natural gas reserves — a 10-year supply for whole nation, said John Curtis, a geologist who runs the Potential Gas Agency at the Colorado School of Mines.
For decades that gas sold for cheap. Now, suppliers are giddy at the prospects of higher profits.
Largely because of the new pipelines, Questar, among other Rocky Mountain producers, is planning to hold back no gas in storage this year. Questar hooked up to the Rockies Express in December.
"We're off to a good start," Rattie told investors in a conference call Feb. 13 on the company's performance. "Rockies prices should be much higher this year."
Not every gas driller is convinced.
"I'm personally very skeptical about getting in the Rockies for gas production, because the market is so volatile and weak at times," said Sidney J. Jansma Jr., president and chief executive of Grand Rapids, Mich.-based Wolverine Gas & Oil Corp., which is producing 10 percent of Utah's crude oil after making a wildcat discovery in 2004.
"I'd rather work somewhere else. I've got a big project I'm working in Ohio where I'm going to get the return I need producing natural gas," said Jansma. He started drilling in Ohio on Feb. 21.
Consumers generally are buffered from the highs and lows of market prices for natural gas, but their regulated rates follow general trends.
In Utah, which has the lowest average natural gas prices outside Alaska, the major utility Questar Corp. delivers gas for $8.17 a decatherm, plus taxes.
Questar's Utah customers have special protection from price hikes. Under a court ruling 32 years ago, Questar was forced to sell gas from its Wyoming fields at no more than the cost of production to its Utah ratepayers, who helped pay for the drilling. Utah consumers get 40 percent of their heating gas through this arrangement, which will continue to buffer them from market upswings.
"The ratepayers totally won," said Daniel Berman, a Salt Lake City attorney who handled the case.
Friday, March 14, 2008
Williams & TransCanada Want Natural Gas Pipeline for the West
TransCanada Corp. (TSX:TRP) and U.S.-based natural gas company Williams (NYSE:WMB) are proposing to jointly develop the Sunstone Pipeline to take gas to markets in the western United States.
The two companies said Thursday they are evaluating the construction of a 995-kilometre, one-metre-diameter pipeline with capacity of up to 1.2 billion cubic feet per day to enter service in 2011.
The new line would be built alongside the existing Williams Northwest Pipeline between the Opal Hub in Wyoming and Stanfield, Ore., where it connects to TransCanada's Gas Transmission Northwest (GTN) system.
"Sunstone offers customers in the West excellent access to markets and supply," TransCanada president and CEO Hal Kvisle said in a statement.
"Sunstone and GTN provide efficient, continued access to Western Canada Sedimentary Basin gas supply in addition to new access to growing Rocky Mountain production."
The two companies did say how much they expected such a system will cost to build.
The two companies said Thursday they are evaluating the construction of a 995-kilometre, one-metre-diameter pipeline with capacity of up to 1.2 billion cubic feet per day to enter service in 2011.
The new line would be built alongside the existing Williams Northwest Pipeline between the Opal Hub in Wyoming and Stanfield, Ore., where it connects to TransCanada's Gas Transmission Northwest (GTN) system.
"Sunstone offers customers in the West excellent access to markets and supply," TransCanada president and CEO Hal Kvisle said in a statement.
"Sunstone and GTN provide efficient, continued access to Western Canada Sedimentary Basin gas supply in addition to new access to growing Rocky Mountain production."
The two companies did say how much they expected such a system will cost to build.
Thursday, March 13, 2008
Argentina Guarantees Natural Gas to Chile
SANTIAGO, March 11 (Reuters) - Chile's government said on Tuesday it secured more natural gas from neighboring Argentina until colder weather sets in starting in May, at which time flows will only cover residential and commercial use.
Argentina cut its natural gas exports to Chile to a minimum last year, prioritizing its domestic market instead as sizzling economic growth spurred greater energy demand.
"The (Argentine) government ratified its commitment to providing sufficient natural gas so that residential and commercial supplies are uninterrupted, particularly during the winter months," Chile's National Energy Commission said in a statement.
Up until May, Buenos Aires will send bigger volumes of natural gas to Chile through the GasAndes pipeline and to northern and southern regions. These flows will resume after the cold months have passed, the commission said.
Demand for heating surges in both countries during the Southern Hemisphere's winter, and last year Argentina was forced to limit natural gas and power supplies for industrial and other large users to avoid residential shortages.
Chile depends exclusively on Argentina for natural gas and has suffered from frequent restrictions on flows since 2004.
Argentina's government announced late on Monday that it will raise taxes on its natural gas exports to help ensure domestic supplies, and it will also allow market prices to reign for new natural gas projects to stimulate more investment in the tightly regulated energy sector.
Argentina cut its natural gas exports to Chile to a minimum last year, prioritizing its domestic market instead as sizzling economic growth spurred greater energy demand.
"The (Argentine) government ratified its commitment to providing sufficient natural gas so that residential and commercial supplies are uninterrupted, particularly during the winter months," Chile's National Energy Commission said in a statement.
Up until May, Buenos Aires will send bigger volumes of natural gas to Chile through the GasAndes pipeline and to northern and southern regions. These flows will resume after the cold months have passed, the commission said.
Demand for heating surges in both countries during the Southern Hemisphere's winter, and last year Argentina was forced to limit natural gas and power supplies for industrial and other large users to avoid residential shortages.
Chile depends exclusively on Argentina for natural gas and has suffered from frequent restrictions on flows since 2004.
Argentina's government announced late on Monday that it will raise taxes on its natural gas exports to help ensure domestic supplies, and it will also allow market prices to reign for new natural gas projects to stimulate more investment in the tightly regulated energy sector.
Wednesday, March 12, 2008
Enbridge Buys Natural Gas from Swift
A subsidiary of Enbridge Energy Partners LP has agreed to buy up to 15 million cubic feet per day of natural gas from Swift Energy Co.
Financial terms of the agreement were not disclosed.
The Houston oil and gas company will be purchasing the natural gas from Houston-based Swift's Bay de Chene Field.
Enbridge (NYSE: EEP) also has an option of raising the capacity to 25MMcf per day.
The 15 MMcf capacity is expected to be available by the end of the second quarter 2008, according to Swift (NYSE: SFY).
Financial terms of the agreement were not disclosed.
The Houston oil and gas company will be purchasing the natural gas from Houston-based Swift's Bay de Chene Field.
Enbridge (NYSE: EEP) also has an option of raising the capacity to 25MMcf per day.
The 15 MMcf capacity is expected to be available by the end of the second quarter 2008, according to Swift (NYSE: SFY).
Tuesday, March 11, 2008
Chevron LNG Plant for Western Australia
Oil and gas giant Chevron Australia will build a new liquid natural gas plant off Western Australia's Pilbara coast.
The company is yet to finalise any international sales contracts but will commit to quarantining a certain percentage for domestic use in WA.
Chevron Australia chief, Roy Kryzwosinski, says the facility will initially process five million tonnes of gas a year.
He says Chevron is yet to finalise international buyers for the LNG, but is negotiating domestic contracts with the State Government.
"Wheatstone will provide a strategic hub for us for future LNG expansion", he says.
"It will likely provide for a gas to liquids project.
"Initially, it will provide one train, but we are yet to determine where the facility will be".
The Wheatstone gas field is about 85 kilometres north-west of Barrow Island.
The company is yet to finalise any international sales contracts but will commit to quarantining a certain percentage for domestic use in WA.
Chevron Australia chief, Roy Kryzwosinski, says the facility will initially process five million tonnes of gas a year.
He says Chevron is yet to finalise international buyers for the LNG, but is negotiating domestic contracts with the State Government.
"Wheatstone will provide a strategic hub for us for future LNG expansion", he says.
"It will likely provide for a gas to liquids project.
"Initially, it will provide one train, but we are yet to determine where the facility will be".
The Wheatstone gas field is about 85 kilometres north-west of Barrow Island.
Monday, March 10, 2008
Thailand Natural Gas Project OK by Chevron
Chevron Corporation (NYSE:CVX) today announced that the company and its partners have given the green light to construct the Platong Gas II natural gas project in the Gulf of Thailand. Total development cost of the field is approximately $3.1 billion with startup scheduled for first quarter 2011. The Platong Gas II development, located in shallow water, 120 miles (200 km) offshore, is designed to add 420 million cubic feet of natural gas per day processing capacity. The project feeds the growing demand for gas in the domestic market. Chevron is operator and holds a 69.8 percent participating interest with Mitsui Oil Exploration Co. Ltd. (27.4 percent) and PTT Exploration and Production Public Co. Ltd. (2.8 percent). "The Asia-Pacific region is poised to become the world’s most significant oil and gas consumer, with demand forecasted to grow by about 90 percent by 2030,” said Jim Blackwell, president of Chevron Asia Pacific Exploration and Production Co. "Chevron is well positioned with a robust queue of major projects across the region to help satisfy future demand. "The Platong Gas II project alone has the potential to satisfy 14 percent of the natural gas used for power generation in the Kingdom. Platong Gas II is a milestone that builds on the 45-year relationship between Chevron and the Kingdom of Thailand,” said Blackwell. Tara Tiradnakorn, president of Chevron Thailand Exploration and Production, added, "Platong Gas II is a world-class natural gas project that will generate new jobs and revenue for the Kingdom, as well as provide a future source of energy for the Thai people and industry for decades to come.” Chevron recently signed an agreement with the Ministry of Energy of Thailand to increase its daily contract quantity of natural gas by 500 million cubic feet to 1.2 billion by 2012 from company-operated offshore blocks 10, 11, 12 and 13. Platong Gas II is expected to be the major source of this increase in production. In October 2007, the company received ten-year lease extensions until 2022 for blocks 10 through 13. Chevron has ownership interests in these blocks ranging from 60 percent to 80 percent. Chevron operates more than 195 platforms in the Gulf of Thailand with 2007 total average daily production of 138,000 barrels of oil and condensate (71,000 net) and 1.7 billion gross cubic feet of gas (916 million net). Chevron Corporation is one of the world’s leading integrated energy companies with subsidiaries that conduct business across the globe. The company’s success is driven by the ingenuity and commitment of approximately 59,000 employees who operate across the energy spectrum. Chevron explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and other energy products and services; manufactures and sells petrochemical products; generates power and produces geothermal energy; and develops and commercializes the energy resources of the future, including biofuels and other renewables. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com. Cautionary Statement Relevant to Forward-Looking Information for the Purpose of "Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995. Some of the items discussed in this press release are forward-looking statements about Chevron’s activities in Thailand. Words such as "anticipates,” "expects,” "intends,” "plans,” "targets,” "projects,” "believes,” "seeks,” "estimates,” "budgets” and similar expressions are intended to identify such forward-looking statements. The statements are based upon management’s current expectations, estimates and projections; are not guarantees of future performance; and are subject to certain risks, uncertainties and other factors, some of which are beyond the company’s control and are difficult to predict. Among the factors that could cause actual results to differ materially are changes in prices of, demand for and supply of crude oil and natural gas; actions of competitors; the potential disruption or interruption of production and development activities due to war, accidents, political events, civil unrest, or severe weather; government-mandated sales, divestitures, recapitalizations and changes in fiscal terms or restrictions on scope of company operations; and general economic and political conditions. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Sunday, March 9, 2008
Northern Indiana Natural Gas Prices Up
Another hike in the cost of natural gas is in store for customers of Northern Indiana Public Service Company, NIPSCO, according to an announcement this week that said an increase of 4.14 percent will appear on March billing statements.
That's compared to last month when residential customers experienced a 7.52 percent increase over January.
February's increase, based on a customer's usage of 200 therms of natural gas, translated to approximately $15.42 more for the month.
In March, based on 150 therms, means customers will pay about $6.91 more to keep warm.
The increases, and at times decreases, in the cost of gas, dubbed a GCA or gas cost adjustment, are approved by the Indiana Regulatory Commission, and reflect the fluctuations in the price NIPSCO pays in the marketplace.
The company passes on the costs of the natural gas directly to customers without any markup under its traditional, regulated GCA service option.
Aside from the gas supply charge, the other components of NIPSCO's monthly gas statements include service costs for gas delivery, and state and local taxes. These service costs, which are also regulated by the IURC, vary with monthly natural gas use.
That's compared to last month when residential customers experienced a 7.52 percent increase over January.
February's increase, based on a customer's usage of 200 therms of natural gas, translated to approximately $15.42 more for the month.
In March, based on 150 therms, means customers will pay about $6.91 more to keep warm.
The increases, and at times decreases, in the cost of gas, dubbed a GCA or gas cost adjustment, are approved by the Indiana Regulatory Commission, and reflect the fluctuations in the price NIPSCO pays in the marketplace.
The company passes on the costs of the natural gas directly to customers without any markup under its traditional, regulated GCA service option.
Aside from the gas supply charge, the other components of NIPSCO's monthly gas statements include service costs for gas delivery, and state and local taxes. These service costs, which are also regulated by the IURC, vary with monthly natural gas use.
Saturday, March 8, 2008
New York City Gate Natural Gas $10.99/mBTU
ARLINGTON, Va., March 7 /PRNewswire-USNewswire/ -- This week U.S. natural gas prices neared $10 per MMBtu -- more than quadruple the 1999 price of $2.38 -- as oil prices hovered just over $100 per barrel. http://www.bloomberg.com/markets/commodities/energyprices.html
American Chemistry Council (ACC) President & CEO Jack N. Gerard issued the following statement:
"This week's sky-high energy prices signal that Congress has much energy work left to do. We welcome lawmakers' attention to energy diversity and efficiency -- policies we have long-supported. But domestic energy supply is a vital missing piece Congress ignores at America's cost. Congress can help prevent further damage by looking again at moratoria on domestic energy development. We strongly urge lawmakers to support legislation such as the National Environment and Energy Development (NEED) Act.
http://thomas.loc.gov/cgi-bin/bdquery/z?d110:h.r.02784: It will not be a moment too soon.
"U.S. households, manufacturers, farmers and other natural gas consumers pay dramatically more for natural gas when federal energy policy keeps restrictions on our own domestic supplies -- the only industrialized nation in the world to do so. Since 1999, the cumulative increase in the nation's natural gas bill is more than $522 billion -- that's $4,568 per taxpayer. America's chemistry sector has lost more than 118,000 jobs, and the manufacturing sector as a whole has lost three million jobs. If milk prices had increased at the same rate as U.S. natural gas prices, a gallon of milk would cost $11 today. Gasoline would cost $5.37 a gallon.
"Natural gas will have a prominent role in Congress's attempts to reduce greenhouse gas emissions. It's used for cleaner electricity generation, cleaner transportation fuels, hydrogen for fuel cells and as a key feedstock for chemistry used in products to improve energy efficiency -- from wind power blades and solar panels to energy-efficient appliances, compact fluorescent light bulbs, coatings, lubricants, low-rolling resistance tires and many others. Increased access to domestic natural gas supply should be a key feature of any climate policy that Congress considers."
http://www.americanchemistry.com/newsroom
The American Chemistry Council (ACC) represents the leading companies engaged in the business of chemistry. ACC members apply the science of chemistry to make innovative products and services that make people's lives better, healthier and safer. ACC is committed to improved environmental, health and safety performance through Responsible Care(R), common sense advocacy designed to address major public policy issues, and health and environmental research and product testing. The business of chemistry is a $635 billion enterprise and a key element of the nation's economy. It is one of the nation's largest exporters, accounting for ten cents out of every dollar in U.S. exports. Chemistry companies are among the largest investors in research and development. Safety and security have always been primary concerns of ACC members, and they have intensified their efforts, working closely with government agencies to improve security and to defend against any threat to the nation's critical infrastructure.
American Chemistry Council (ACC) President & CEO Jack N. Gerard issued the following statement:
"This week's sky-high energy prices signal that Congress has much energy work left to do. We welcome lawmakers' attention to energy diversity and efficiency -- policies we have long-supported. But domestic energy supply is a vital missing piece Congress ignores at America's cost. Congress can help prevent further damage by looking again at moratoria on domestic energy development. We strongly urge lawmakers to support legislation such as the National Environment and Energy Development (NEED) Act.
http://thomas.loc.gov/cgi-bin/bdquery/z?d110:h.r.02784: It will not be a moment too soon.
"U.S. households, manufacturers, farmers and other natural gas consumers pay dramatically more for natural gas when federal energy policy keeps restrictions on our own domestic supplies -- the only industrialized nation in the world to do so. Since 1999, the cumulative increase in the nation's natural gas bill is more than $522 billion -- that's $4,568 per taxpayer. America's chemistry sector has lost more than 118,000 jobs, and the manufacturing sector as a whole has lost three million jobs. If milk prices had increased at the same rate as U.S. natural gas prices, a gallon of milk would cost $11 today. Gasoline would cost $5.37 a gallon.
"Natural gas will have a prominent role in Congress's attempts to reduce greenhouse gas emissions. It's used for cleaner electricity generation, cleaner transportation fuels, hydrogen for fuel cells and as a key feedstock for chemistry used in products to improve energy efficiency -- from wind power blades and solar panels to energy-efficient appliances, compact fluorescent light bulbs, coatings, lubricants, low-rolling resistance tires and many others. Increased access to domestic natural gas supply should be a key feature of any climate policy that Congress considers."
http://www.americanchemistry.com/newsroom
The American Chemistry Council (ACC) represents the leading companies engaged in the business of chemistry. ACC members apply the science of chemistry to make innovative products and services that make people's lives better, healthier and safer. ACC is committed to improved environmental, health and safety performance through Responsible Care(R), common sense advocacy designed to address major public policy issues, and health and environmental research and product testing. The business of chemistry is a $635 billion enterprise and a key element of the nation's economy. It is one of the nation's largest exporters, accounting for ten cents out of every dollar in U.S. exports. Chemistry companies are among the largest investors in research and development. Safety and security have always been primary concerns of ACC members, and they have intensified their efforts, working closely with government agencies to improve security and to defend against any threat to the nation's critical infrastructure.
Friday, March 7, 2008
German Natural Gas Suppliers Under Probe
Germany's Federal Cartel Office has launched a probe of 35 natural gas suppliers suspected of charging excessively high prices.
German authorities had noted price differences that ranged from 25 percent to 45 percent, the office said in a statement on Wednesday, March 5.
The cartel office would therefore check whether recent German gas price hikes were justified, it added.
"Horribly weak" competition
Office head Bernhard Heitzer said preliminary results of the probe suggested that competition was "still horribly weak" in the gas sector.
"From what we know now, an entire series of companies have raised gas prices to a level that they could never demand in a functioning, competitive economy," he said.
A gas compressor station of the Yamal-Europe pipeline near Nesvizh, some 130 km southwest of the capital Minsk, Belarus, Wednesday, Dec. 27, 2006. Bildunterschrift: Großansicht des Bildes mit der Bildunterschrift: As much as 20 percent of the German market stands to be affected by the probe
The price increases concerned four million clients and around 20 percent of the market, the office said.
A spokesman contacted by the AFP news service declined to provide the names of companies under investigation, saying only that national and regional firms were concerned.
In all, 770 companies supply gas to households and companies in Germany, of which around 30 are active throughout the country.
Some don't pass on savings
Regional anti-cartel offices had also launched their own investigations into gas price increases.
Heitzer said a number of companies were raising gas prices in a way that would be impossible to do in a normal competitive situation.
"Even in places where the network fees are low, that price advantage isn't necessarily passed on to clients; the savings appear to be used to boost the company's value in another area," Heitzer added.
German authorities had noted price differences that ranged from 25 percent to 45 percent, the office said in a statement on Wednesday, March 5.
The cartel office would therefore check whether recent German gas price hikes were justified, it added.
"Horribly weak" competition
Office head Bernhard Heitzer said preliminary results of the probe suggested that competition was "still horribly weak" in the gas sector.
"From what we know now, an entire series of companies have raised gas prices to a level that they could never demand in a functioning, competitive economy," he said.
A gas compressor station of the Yamal-Europe pipeline near Nesvizh, some 130 km southwest of the capital Minsk, Belarus, Wednesday, Dec. 27, 2006. Bildunterschrift: Großansicht des Bildes mit der Bildunterschrift: As much as 20 percent of the German market stands to be affected by the probe
The price increases concerned four million clients and around 20 percent of the market, the office said.
A spokesman contacted by the AFP news service declined to provide the names of companies under investigation, saying only that national and regional firms were concerned.
In all, 770 companies supply gas to households and companies in Germany, of which around 30 are active throughout the country.
Some don't pass on savings
Regional anti-cartel offices had also launched their own investigations into gas price increases.
Heitzer said a number of companies were raising gas prices in a way that would be impossible to do in a normal competitive situation.
"Even in places where the network fees are low, that price advantage isn't necessarily passed on to clients; the savings appear to be used to boost the company's value in another area," Heitzer added.
Thursday, March 6, 2008
Gazprom & Ukraine Fighting Natural Gas with Europe in the Middle?
Western Europe is watching warily as Russia and Ukraine are locked in a natural gas dispute that has reduced the supply to Ukraine by at least half since the beginning of the week.
After Russia’s statecontrolled natural gas monopoly announced the second supply cut in two days on March 4, Ukraine’s natural gas company said there are no immediate plans to divert Europebound gas to Ukrainian customers, but held out the possibility it could do so if reserves run low.
Much of the Russian gas consumed in Europe comes in pipelines crossing Ukraine.
The Russian monopoly, OAO Gazprom, is demanding Ukraine sign documents resolving a $600 million debt dispute and enabling further gas deliveries. On March 3, it cut shipments by 25 percent.
Gazprom spokesman Sergei Kupriyanov announced another 25 percent cut in the evening on March 4 and held out the possibility of more.
The European Union “looks to the parties to make every effort to find a rapid and durable solution to their disagreement.
In addition, we look to both parties to ensure that gas supplies to the EU remain unaffected,” EU Energy Commissioner Andris Piebalgs said in a statement.
After Russia’s statecontrolled natural gas monopoly announced the second supply cut in two days on March 4, Ukraine’s natural gas company said there are no immediate plans to divert Europebound gas to Ukrainian customers, but held out the possibility it could do so if reserves run low.
Much of the Russian gas consumed in Europe comes in pipelines crossing Ukraine.
The Russian monopoly, OAO Gazprom, is demanding Ukraine sign documents resolving a $600 million debt dispute and enabling further gas deliveries. On March 3, it cut shipments by 25 percent.
Gazprom spokesman Sergei Kupriyanov announced another 25 percent cut in the evening on March 4 and held out the possibility of more.
The European Union “looks to the parties to make every effort to find a rapid and durable solution to their disagreement.
In addition, we look to both parties to ensure that gas supplies to the EU remain unaffected,” EU Energy Commissioner Andris Piebalgs said in a statement.
Wednesday, March 5, 2008
PetroChina Projects Natural Gas Double Production by 2118
China's natural gas output would at least double the present volume in the coming decade to reach 150 billion to 200 billion cubic meters, PetroChina Vice President Jia Chengzao said on Tuesday.
PetroChina, the country's leading natural gas producer, alone has reported an annual output rise of 10 billion cubic meters for two consecutive years, he said.
"We will strive to keep the same growth rate this year," said Jia, a member of the 11th National Committee of the Chinese People's Political Consultative Conference, who is attending the annual political advisory session.
His company produces about 75 percent of China's total natural gas output.
Recent discoveries of new gas fields, including Jidong Nanpu Oil Field in north China's Bohai Bay, which contains 1.18 billion tons of oil and gas reserves, would boost China's natural gas sector and optimize its energy structure, said Jia.
PetroChina, the country's leading natural gas producer, alone has reported an annual output rise of 10 billion cubic meters for two consecutive years, he said.
"We will strive to keep the same growth rate this year," said Jia, a member of the 11th National Committee of the Chinese People's Political Consultative Conference, who is attending the annual political advisory session.
His company produces about 75 percent of China's total natural gas output.
Recent discoveries of new gas fields, including Jidong Nanpu Oil Field in north China's Bohai Bay, which contains 1.18 billion tons of oil and gas reserves, would boost China's natural gas sector and optimize its energy structure, said Jia.
Tuesday, March 4, 2008
$4 Billion USD Investment for Oil and Natural Gas
Natural Gas Partners said it has closed on a $4 billion fund to invest in the oil and gas industry.
Since its founding in 1988, the private equity company has managed more than $7 billion of cumulative capital and made investments in over 130 companies in the oil and gas production, oilfield service, mid-stream and related energy sectors.
Natural Gas Partners said the new fund will engage in the same size and type of deals the company has made in the past.
"The fund has made ten investments to date, many of which are managed by experienced management teams from prior NGP portfolio companies, said William Quinn, the company's managing partner, in a statement. "Given our current investment pace and strong deal flow, we are glad to have raised a fund that is of sufficient size to allow us to continue to do this over the next several years."
The Natural Gas Partners funds are managed by Irving-based NGP Energy Capital Management. NGP Energy Capital Management's $9 billion in investments also includes NGP Capital Resources Co. (Nasdaq: NGPC), a publicly traded business development company with more than $400 million in capital; NGP Energy Technology Partners L.P. a $148 million fund investing in companies that provide technology-related products and services to the oil and gas, power and alternative energy sectors; and NGP Midstream and Resources L.P., a $1.4 billion fund that invests in selected areas of the energy infrastructure and mineral businesses.
Since its founding in 1988, the private equity company has managed more than $7 billion of cumulative capital and made investments in over 130 companies in the oil and gas production, oilfield service, mid-stream and related energy sectors.
Natural Gas Partners said the new fund will engage in the same size and type of deals the company has made in the past.
"The fund has made ten investments to date, many of which are managed by experienced management teams from prior NGP portfolio companies, said William Quinn, the company's managing partner, in a statement. "Given our current investment pace and strong deal flow, we are glad to have raised a fund that is of sufficient size to allow us to continue to do this over the next several years."
The Natural Gas Partners funds are managed by Irving-based NGP Energy Capital Management. NGP Energy Capital Management's $9 billion in investments also includes NGP Capital Resources Co. (Nasdaq: NGPC), a publicly traded business development company with more than $400 million in capital; NGP Energy Technology Partners L.P. a $148 million fund investing in companies that provide technology-related products and services to the oil and gas, power and alternative energy sectors; and NGP Midstream and Resources L.P., a $1.4 billion fund that invests in selected areas of the energy infrastructure and mineral businesses.
Monday, March 3, 2008
Alaska Natural Gas Pipeline Construction Still Only An Idea
David M. Reaume is a Washington state-based economist who was based for many years in Juneau, Alaska and is very up on the possibility of building a natural gas pipeline from Alaska to the Mid-west USA.
In November the average U.S. city gate price for natural gas stood at $8.05 per thousand cubic feet, or mcf. Some divining that I have done suggests that an average real -- inflation-adjusted, 2007 dollars -- U.S. city gate price of about $9 per mcf qualifies as a minimum "Go Price," where by the Go Price I mean one just high enough to give a positive incentive for producers to get the gas to the pipeline, assuming that the state and the federal government also pitch in.
Accepting that an average real city gate price of $9 per mcf is only a rough estimate of the critical Go Price, how likely is it that we will hit that price in a few years, and how likely is it that it will stay at or above that price for the long term? The answer depends on how one models future natural gas prices.
If, for example, we look at a simple time trend in real natural gas prices over the past 20 years we find that recent peaks are likely to be transitory. But this ignores the fact that the world might have changed greatly over the past five or 10 years. Given the heavy concentration of natural gas reserves outside the United States and Canada, there is some reason to suspect that natural gas prices might eventually return to something like their historical relationship to crude oil prices. After all, about 43 percent of the world's natural gas reserves are located in Iran (16 percent) and Russia (27 percent), two countries that have strong incentives to price their natural gas in step with OPEC's pricing of crude oil.
So what would happen if we abandon simple time trends and look at natural gas prices in relationship to crude oil prices? In particular, what would happen if the average real U.S. city gate price of natural gas found its way back to its historical relationship with the average real U.S. price of crude oil? Good things for pipeline construction. If the price of crude oil were to average $80 per barrel -- in inflation-adjusted 2007 dollars -- the corresponding average U.S. city gate price for natural gas would eventually rise to $9.50 per mcf.
But that might be asking too much given that there is no shortage of analysts who think that crude oil prices are due to drop sharply as the world economy slows down. A more reasonable target may be the $9 per mcf number that my divining suggests may represent a critical value for the proposed pipeline. To reach $9, the average U.S. price of crude oil would only need to stay above about $60 per barrel, both again in inflation-adjusted dollars. That is no sure thing but does not seem too far out of reach even though the December "Energy Outlook" from the U.S. Department of Energy forecasts zero gain in real natural gas prices for the next five years.
Would I bet on pipeline construction getting the go-ahead in the next three or four years? No, but I would not bet against it either. Gov. Sarah Palin is on the right track. Line up a contractor. Then if prices do respond favorably the stage is set. Is $500 million in pre-construction incentives a waste of money? I don't think so, given the stakes and the potential benefits to Alaskans. But then I don't live in Alaska anymore. Only Alaskans can decide.
In November the average U.S. city gate price for natural gas stood at $8.05 per thousand cubic feet, or mcf. Some divining that I have done suggests that an average real -- inflation-adjusted, 2007 dollars -- U.S. city gate price of about $9 per mcf qualifies as a minimum "Go Price," where by the Go Price I mean one just high enough to give a positive incentive for producers to get the gas to the pipeline, assuming that the state and the federal government also pitch in.
Accepting that an average real city gate price of $9 per mcf is only a rough estimate of the critical Go Price, how likely is it that we will hit that price in a few years, and how likely is it that it will stay at or above that price for the long term? The answer depends on how one models future natural gas prices.
If, for example, we look at a simple time trend in real natural gas prices over the past 20 years we find that recent peaks are likely to be transitory. But this ignores the fact that the world might have changed greatly over the past five or 10 years. Given the heavy concentration of natural gas reserves outside the United States and Canada, there is some reason to suspect that natural gas prices might eventually return to something like their historical relationship to crude oil prices. After all, about 43 percent of the world's natural gas reserves are located in Iran (16 percent) and Russia (27 percent), two countries that have strong incentives to price their natural gas in step with OPEC's pricing of crude oil.
So what would happen if we abandon simple time trends and look at natural gas prices in relationship to crude oil prices? In particular, what would happen if the average real U.S. city gate price of natural gas found its way back to its historical relationship with the average real U.S. price of crude oil? Good things for pipeline construction. If the price of crude oil were to average $80 per barrel -- in inflation-adjusted 2007 dollars -- the corresponding average U.S. city gate price for natural gas would eventually rise to $9.50 per mcf.
But that might be asking too much given that there is no shortage of analysts who think that crude oil prices are due to drop sharply as the world economy slows down. A more reasonable target may be the $9 per mcf number that my divining suggests may represent a critical value for the proposed pipeline. To reach $9, the average U.S. price of crude oil would only need to stay above about $60 per barrel, both again in inflation-adjusted dollars. That is no sure thing but does not seem too far out of reach even though the December "Energy Outlook" from the U.S. Department of Energy forecasts zero gain in real natural gas prices for the next five years.
Would I bet on pipeline construction getting the go-ahead in the next three or four years? No, but I would not bet against it either. Gov. Sarah Palin is on the right track. Line up a contractor. Then if prices do respond favorably the stage is set. Is $500 million in pre-construction incentives a waste of money? I don't think so, given the stakes and the potential benefits to Alaskans. But then I don't live in Alaska anymore. Only Alaskans can decide.
Sunday, March 2, 2008
Tennessee Natural Gas Exploration - Success!
AMESTOWN, Tenn. - They call him the boom maker.
Known for hitting substantial oil wells on and around the Cumberland Plateau, Young Oil Corp. owner and CEO Anthony Young has made a name for himself. Tales of his oil exploration in Tennessee have reached the Los Angeles Times, and the entrepreneur is enjoying success, with fancy cars and private jets.
Young's company is among dozens of oil and natural-gas businesses that have made millions in Tennessee during the past 150 years, and their finds have spurred jobs in many rural East and Middle Tennessee counties. But just as many others have struck out. The state has battled images of rough terrain and overall small production numbers that have kept major oil companies away.
But with record crude oil prices and an increase in demand for domestic exploration, could Tennessee's role in the oil industry be changing?
Big plays for a small player
As far as total oil production, Tennessee is still a relatively small player on a national scale. The state ranks 28th, but only 31 or 32 states produce any oil at all, according to Jeff Bailey, CEO and director of Tengasco Inc., a Knoxville-based oil and natural-gas exploration and production company.
Tengasco produces only a small amount of oil, mostly in the Swan Creek area of Hancock County, but at one time was the largest natural-gas producer in the state.
"We produce about 10,000 barrels of oil a year out of Tennessee, and all of that was found accidentally while we were drilling for gas," Bailey said. "Tennessee has a very small amount of oil and is pretty far down on the list."
All-time production for the state since the 1860s is 20.8 million barrels for an estimated total value of $428 million, according to a state geology report.
To compare, Alaska's production is about 30 times that in a given year. And the United States uses more than 20 million barrels of oil a day.
Because of that, Bailey said, exploration in East and Middle Tennessee and largely across the country is focused mostly on natural gas. For oil, the company relies more on its leases in Kansas and along the Gulf Coast.
But just because Tennessee ranks relatively low in nationwide production doesn't mean oil wells discovered here aren't big in their own right. Several companies, including Kentucky's Basin Oil & Gas Corp. and Huntsville, Tenn.'s Miller Petroleum, have hit record-setting wells. In its lifetime, the Days Chapel Field in Campbell County has produced 3 million barrels for Miller Petroleum, and the company claims to have drilled or serviced 65 percent of the wells in the state.
Basin Oil & Gas also claimed one of Tennessee's biggest wells in 1999, when a find in Overton County initially produced 2,400 barrels a day.
"There have been some pretty amazing fields in Tennessee," Bailey said. "A few of the finds over there (on the plateau) are kind of unique. So there's kind of a little new niche going on over there. Those guys may have stumbled onto something."
More recently, in March 2007, Young Oil Corp. hit one of those million-dollar wells. Located on leased property in eastern Overton County and assigned the name Norrod No. 1, the well came in free-flowing at more than 1,900 barrels a day. The landowners, who make about one-eighth of the profits, were pocketing $9,000 daily.
Leaseholders and landowners aren't the only ones making money from the exploration. A 3 percent tax is levied on all oil discovered in Tennessee, according to the Tennessee Department of Environment and Conservation. Of that 3 percent, that state receives two-thirds and the county of origin receives one-third.
In 2006, the most recent year for information, Tennessee realized $448,000 in severance tax revenue from petroleum exploration, TDEC reported.
Young reports that Norrod is still producing at a controlled rate of 100 barrels a day, meaning production was cut to sustain the well for a longer period of time. The well has produced 40,000 barrels of oil in less than a year.
Known for hitting substantial oil wells on and around the Cumberland Plateau, Young Oil Corp. owner and CEO Anthony Young has made a name for himself. Tales of his oil exploration in Tennessee have reached the Los Angeles Times, and the entrepreneur is enjoying success, with fancy cars and private jets.
Young's company is among dozens of oil and natural-gas businesses that have made millions in Tennessee during the past 150 years, and their finds have spurred jobs in many rural East and Middle Tennessee counties. But just as many others have struck out. The state has battled images of rough terrain and overall small production numbers that have kept major oil companies away.
But with record crude oil prices and an increase in demand for domestic exploration, could Tennessee's role in the oil industry be changing?
Big plays for a small player
As far as total oil production, Tennessee is still a relatively small player on a national scale. The state ranks 28th, but only 31 or 32 states produce any oil at all, according to Jeff Bailey, CEO and director of Tengasco Inc., a Knoxville-based oil and natural-gas exploration and production company.
Tengasco produces only a small amount of oil, mostly in the Swan Creek area of Hancock County, but at one time was the largest natural-gas producer in the state.
"We produce about 10,000 barrels of oil a year out of Tennessee, and all of that was found accidentally while we were drilling for gas," Bailey said. "Tennessee has a very small amount of oil and is pretty far down on the list."
All-time production for the state since the 1860s is 20.8 million barrels for an estimated total value of $428 million, according to a state geology report.
To compare, Alaska's production is about 30 times that in a given year. And the United States uses more than 20 million barrels of oil a day.
Because of that, Bailey said, exploration in East and Middle Tennessee and largely across the country is focused mostly on natural gas. For oil, the company relies more on its leases in Kansas and along the Gulf Coast.
But just because Tennessee ranks relatively low in nationwide production doesn't mean oil wells discovered here aren't big in their own right. Several companies, including Kentucky's Basin Oil & Gas Corp. and Huntsville, Tenn.'s Miller Petroleum, have hit record-setting wells. In its lifetime, the Days Chapel Field in Campbell County has produced 3 million barrels for Miller Petroleum, and the company claims to have drilled or serviced 65 percent of the wells in the state.
Basin Oil & Gas also claimed one of Tennessee's biggest wells in 1999, when a find in Overton County initially produced 2,400 barrels a day.
"There have been some pretty amazing fields in Tennessee," Bailey said. "A few of the finds over there (on the plateau) are kind of unique. So there's kind of a little new niche going on over there. Those guys may have stumbled onto something."
More recently, in March 2007, Young Oil Corp. hit one of those million-dollar wells. Located on leased property in eastern Overton County and assigned the name Norrod No. 1, the well came in free-flowing at more than 1,900 barrels a day. The landowners, who make about one-eighth of the profits, were pocketing $9,000 daily.
Leaseholders and landowners aren't the only ones making money from the exploration. A 3 percent tax is levied on all oil discovered in Tennessee, according to the Tennessee Department of Environment and Conservation. Of that 3 percent, that state receives two-thirds and the county of origin receives one-third.
In 2006, the most recent year for information, Tennessee realized $448,000 in severance tax revenue from petroleum exploration, TDEC reported.
Young reports that Norrod is still producing at a controlled rate of 100 barrels a day, meaning production was cut to sustain the well for a longer period of time. The well has produced 40,000 barrels of oil in less than a year.
Saturday, March 1, 2008
Natural Gas Public Company Stock - UP UP Up Today
NEW YORK (Associated Press) - Major exploration finds, higher production and climbing prices have pushed the natural gas sector back into investors' favor this year.
The Amex Natural Gas Index, which tracks the share performance of 15 companies, has climbed more than 25 percent since the start of 2008. Several individual companies have posted double-digit percentage gains as well.
Some analysts, though, are now trying to tame expectations that stocks and commodity prices will keep surging.
Commodity prices in general have been boosted by a weaker dollar, which has been falling amid concerns about the U.S. economy. Natural gas prices have marched upward along with those for oil, rising by more than 25 percent this year.
Shares in natural gas producers have also been supported by falling inventories, which are down 7.6 percent from year-ago levels, according to the Department of Energy. Colder weather than last winter has boosted the use of natural gas for heating.
In addition, exploration and production companies like Houston's EOG Resources Inc. and Southwestern Energy Co. have reported surging production, billions of cubic feet worth of new finds and positive outlooks.
EOG shares reached a new high Thursday after the company said it found crude oil at operations in Texas and Colorado. It also expects to begin producing gas at sites in Canada's Horn River Basin, with significant output beginning in 2010.
The company raised its 2009 and 2010 annual production growth forecast to 13 percent to 15 percent, compared with a previous average target of 10 percent.
Southwestern's stock has climbed more than 20 percent this year as investors became exuberant about its profit potential. The company said Thursday that its fourth-quarter earnings more than doubled on higher production and pricing. It also added 1 billion cubic feet of oil equivalent to its first-quarter production outlook.
"The positive news flow will continue," said FBR Research analyst Amir Arif. He rates the stock as "outperform," saying he expects Southwestern to boost production through better techniques.
Other stocks have seen similar gains. Fort Worth, Texas-based XTO Energy Inc. has risen almost 20 percent this year. It posted a sharply higher fourth-quarter profit and issued a better 2008 production outlook due to its previous and planned acquisitions.
Devon Energy Corp. shares have gained about 17 percent since the start of the year. The Oklahoma City producer said earlier this month that its fourth-quarter earnings more than doubled, on one-time gains from asset sales as well as higher production.
Though expectations for the natural gas industry have improved, it was not long ago that analysts were forecasting higher inventories and weak natural gas prices.
Citi Investment Research analyst Gil Yang says he is "bullish" on the natural gas sector, but believes some share prices have flown too high, too fast.
"Investors should take a more cautious view on the sector in the near term following strong performance of natural gas and natural gas equities in recent weeks," Yang said.
He downgraded four stocks on Thursday, cutting EOG, Southwestern, Chesapeake Energy Corp. and Quicksilver Resources Inc. to "hold" from "buy."
Banc of America analyst Michael Schmitz said that although prices may edge higher with oil, expectations "need to be reined in." That the natural gas sector's performance will likely be "quite volatile," he said, and investors should buy on price declines while remaining selective. Top of page
The Amex Natural Gas Index, which tracks the share performance of 15 companies, has climbed more than 25 percent since the start of 2008. Several individual companies have posted double-digit percentage gains as well.
Some analysts, though, are now trying to tame expectations that stocks and commodity prices will keep surging.
Commodity prices in general have been boosted by a weaker dollar, which has been falling amid concerns about the U.S. economy. Natural gas prices have marched upward along with those for oil, rising by more than 25 percent this year.
Shares in natural gas producers have also been supported by falling inventories, which are down 7.6 percent from year-ago levels, according to the Department of Energy. Colder weather than last winter has boosted the use of natural gas for heating.
In addition, exploration and production companies like Houston's EOG Resources Inc. and Southwestern Energy Co. have reported surging production, billions of cubic feet worth of new finds and positive outlooks.
EOG shares reached a new high Thursday after the company said it found crude oil at operations in Texas and Colorado. It also expects to begin producing gas at sites in Canada's Horn River Basin, with significant output beginning in 2010.
The company raised its 2009 and 2010 annual production growth forecast to 13 percent to 15 percent, compared with a previous average target of 10 percent.
Southwestern's stock has climbed more than 20 percent this year as investors became exuberant about its profit potential. The company said Thursday that its fourth-quarter earnings more than doubled on higher production and pricing. It also added 1 billion cubic feet of oil equivalent to its first-quarter production outlook.
"The positive news flow will continue," said FBR Research analyst Amir Arif. He rates the stock as "outperform," saying he expects Southwestern to boost production through better techniques.
Other stocks have seen similar gains. Fort Worth, Texas-based XTO Energy Inc. has risen almost 20 percent this year. It posted a sharply higher fourth-quarter profit and issued a better 2008 production outlook due to its previous and planned acquisitions.
Devon Energy Corp. shares have gained about 17 percent since the start of the year. The Oklahoma City producer said earlier this month that its fourth-quarter earnings more than doubled, on one-time gains from asset sales as well as higher production.
Though expectations for the natural gas industry have improved, it was not long ago that analysts were forecasting higher inventories and weak natural gas prices.
Citi Investment Research analyst Gil Yang says he is "bullish" on the natural gas sector, but believes some share prices have flown too high, too fast.
"Investors should take a more cautious view on the sector in the near term following strong performance of natural gas and natural gas equities in recent weeks," Yang said.
He downgraded four stocks on Thursday, cutting EOG, Southwestern, Chesapeake Energy Corp. and Quicksilver Resources Inc. to "hold" from "buy."
Banc of America analyst Michael Schmitz said that although prices may edge higher with oil, expectations "need to be reined in." That the natural gas sector's performance will likely be "quite volatile," he said, and investors should buy on price declines while remaining selective. Top of page
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