Natural Gas Pains
Joseph Hargett, Option Advisor, 02.06.09, 02:20 PM EST
Options players can cash in on the overall weakness in the sector by loading up on some put options.
According to the latest data from the Labor Department, the U.S. economy just experienced its worst month of job losses since 1974. The economic report only underscored the growing problem that energy providers are facing in the current market: falling demand and falling prices.
In fact, natural gas prices have plummeted throughout the recession, plunging more than 66% from a high of $13.69 per million British thermal units (BTU) in July 2008 to approximately $4.60 per million BTU on Friday.
Volatility creates money-making opportunities. Click here for a free trial of Bernie Schaeffer's Option Advisor with daily trading recommendations and intraday updates.
What's more, the AMEX Natural Gas Index (XNG) has paced the decline in natural gas futures, giving back more than 48% since July 2008. During this time frame, the index has fought a losing battle with resistance at its 10-week and 20-week moving averages. Furthermore, the 20-week moving average has descended into the psychologically important 400 region, an area that has held the XNG in check since early December.
Despite this poor price action, options traders are betting heavily that the sector has formed a bottom. Specifically, the composite Schaeffer's put/call open interest ratio (SOIR) for XNG components rests at 0.56, in the 36th percentile of its annual range. Furthermore, only 7% of the 98 analysts covering natural gas stocks rate them a "sell."
Should energy prices continue to deteriorate in the midst of this economic turmoil, we could see this bullish sentiment unwind in the form of added selling pressure for the natural gas sector.
Saturday, February 7, 2009
Friday, February 6, 2009
Natural Gas Inventory Down
NEW YORK -- U.S. natural gas inventories fell by 195 billion cubic feet in the week ended Jan. 30, the Energy Information Administration reported Thursday. Analysts at IHS Global Insight had expected a drawdown of 221 billion cubic feet. At 2,179 billion cubic feet, stocks were 60 billion cubic feet higher than last year at this time and 17 billion cubic feet above the five-year average, the EIA reported. After the data, March natural gas futures rose 1.1% to $4.641 per million British thermal units.
Copyright © 2009 MarketWatch, Inc.
Copyright © 2009 MarketWatch, Inc.
Thursday, February 5, 2009
Corning Natural Gas Coming to Pennsylvania
Corning Natural Gas Corporation has completed a major pipeline project into Pennsylvania that will bring Marcellus Shale gas to its customers.
Corning Natural Gas President Mike German said the project was the company’s largest single expansion in a quarter-century and would bring significant quantities of competitively priced gas to the utility’s customers.
Jerry Sleve, administrative vice president for the utility company, said “the combination of new local supplies and falling wholesale prices should result in much lower gas prices for our customers in the future.”
CNG’s new pipeline interconnects with a producer’s gathering line in Jackson Township, Pennsylvania.
“Given the Marcellus Shale prospects in our New York State service territory, CNG is hopeful of connecting more local production,” Sleve said, “More local production would likely put further downward pressure on gas prices, thereby helping not only core residential and commercial customers, but also providing a competitive advantage to local industries.”
German said that, “connecting local production is becoming a significant business opportunity for the company and we look forward to similar projects in the future.”
Corning Natural Gas President Mike German said the project was the company’s largest single expansion in a quarter-century and would bring significant quantities of competitively priced gas to the utility’s customers.
Jerry Sleve, administrative vice president for the utility company, said “the combination of new local supplies and falling wholesale prices should result in much lower gas prices for our customers in the future.”
CNG’s new pipeline interconnects with a producer’s gathering line in Jackson Township, Pennsylvania.
“Given the Marcellus Shale prospects in our New York State service territory, CNG is hopeful of connecting more local production,” Sleve said, “More local production would likely put further downward pressure on gas prices, thereby helping not only core residential and commercial customers, but also providing a competitive advantage to local industries.”
German said that, “connecting local production is becoming a significant business opportunity for the company and we look forward to similar projects in the future.”
Wednesday, February 4, 2009
El Paso Natural Gas 2.5 Trillion Cubic Feet Equivalent
2.5 trillion cubic feet equivalent (Tcfe) proved
reserves, including the Company's proportionate interest
in Four Star Oil & Gas (Four Star)
-- 595 billion cubic feet equivalent (Bcfe) of reserve
additions prior to revisions
-- 192 percent reserve replacement prior to price-related
revisions
-- $2.87 per million cubic feet equivalent (Mcfe) domestic
reserve replacement costs prior to price-related revisions
-- Increased risked resource potential (which is in addition
to proved reserves) to 3.5 Tcfe
Note: Reserve additions include extensions, discoveries and purchases of reserves in place
El Paso Corporation (NYSE: EP) reported today that its proved natural gas and oil reserves at December 31, 2008 totaled 2.5 Tcfe, including 222 Bcfe related to its 48.8 percent interest in Four Star.
"El Paso had a very good year in terms of reserve additions, percentage of reserves replaced and domestic reserve replacement costs, excluding the effects of significant price-related revisions at year-end," said Doug Foshee, president and chief executive officer of El Paso Corporation. "Extensions and discoveries were up 69 percent over 2007 results, which demonstrate significant improvement in our E&P business. And the $2.87 per Mcfe domestic reserve replacement costs, excluding price-related revisions, is our best performance since I joined El Paso in 2003. While a sharp drop in commodity prices had a significant impact on year-end reserves, it is important to note that the year-end reserve calculation assumed very little reduction in service costs, which have fallen since year end and continue to decline. If we had calculated our year-end reserves assuming a Henry Hub natural gas price of $7.00 per MMBtu, $70.00 per barrel WTI pricing and assuming no further reduction in service costs, El Paso's reserves, including our interest in Four Star, would have been approximately 3.0 Tcfe."
Below is a reconciliation of consolidated proved reserves from December 31, 2007 to December 31, 2008, and a summary of El Paso's proportionate interest in Four Star proved reserves at December 31, 2008.
Consolidated Proved Reserves (Bcfe)*
------------------------------------
Proved Reserves at Dec. 31, 2007 2,853
Production (272)
Sales of Reserves in Place (303)
Extensions and Discoveries** 577
Purchases of Reserves in Place 18
Revisions Due to Price (476)
Revisions Other than Price (72)
Proved Reserves at Dec. 31, 2008 2,325
El Paso's Interest in Four Star Proved Reserves (Bcfe)
-----------------------------------------------------
Four Star at December 31, 2008 222
* Year end reserve estimates are based on $5.71 per MMBtu natural gas
(Henry Hub) and $44.60 per barrel (WTI) oil prices
** 128 Bcfe of reserve extensions and discoveries related to our Altamont
oil properties were based upon a $70 per barrel (WTI) oil prices, but were
ultimately eliminated due to price-related revisions at year end.
Approximately 74 percent of the December 31, 2008, proved reserves are proved developed, and 92 percent are natural gas. Approximately 85 percent of price-related revisions are attributable to the decline in oil and NGL prices. Of the price-related revisions, approximately 300 Bcfe were domestic, the largest portion of which was related to the company's Altamont oil properties. In addition, El Paso did not book any reserves from the Camarupim (Bia) project in Brazil due to the sharp drop in oil prices.
El Paso E&P's oil and gas 2008 capital expenditures were approximately $1.7 billion, which includes approximately $50 million for acquisitions of producing properties and approximately $200 million for international expenditures.
El Paso Corporation expects to take a fourth quarter after-tax full-cost ceiling test charge of $1.9 billion and a $0.1 billion impairment of its investment in Four Star. Approximately $1.4 billion of the full-cost ceiling test charge is attributable to the domestic full-cost pool and $0.5 billion to the Brazilian full-cost pool. The company uses the full-cost method of accounting for its oil and natural gas properties. The carrying value of these assets, net of related deferred income taxes, is evaluated on a quarterly basis and is limited to the present value of estimated net revenues of proved reserves using a 10-percent discount rate based on prices and costs at the end of the quarter plus the cost of unevaluated oil and natural gas properties (i.e. a cost center ceiling). A ceiling test charge occurs when the carrying value of the natural gas and oil assets exceeds the cost center ceiling.
El Paso has derivative positions that are intended to manage the price risk of its natural gas and oil production for 2009 and beyond. They are recorded on a mark-to-market basis and therefore were not included in the ceiling test calculation. These positions had a net asset value of approximately $700 million at December 31, 2008.
The ceiling test and impairment charges are non-cash items that do not impact any of the covenants on the debt obligations of El Paso Corporation or its subsidiaries. Based on current reserves and the expected fourth quarter 2008 ceiling test charge, the company estimates its first quarter 2009 per-unit DD&A rate will decline by approximately $0.90 per Mcfe from the rate used in the fourth quarter of 2008 to approximately $2.30 per Mcfe.
27 Percent Increase in Non-Proved Resources
El Paso also reported today that at December 31, 2008, it had an estimated 3.5 Tcfe of net risked or 6.6 Tcfe of net unrisked non-proved resource potential in addition to its 2.5 Tcfe of proved natural gas and oil reserves. The company's risked non-proved resource potential rose 0.7 Tcfe, or 27 percent, from 2007 levels. The majority of the increase was primarily due to the addition of new opportunities in the Haynesville Shale, infill opportunities in the Altamont Field and the Raton Basin coal bed methane program. Non-proved resources include the company's proportionate share of Four Star.
Foshee added, "One of our key successes in 2008 was the expansion of our future drilling inventory. The 2009 E&P capital program will optimize our current investment opportunities while preserving the drilling inventory that we have worked hard to develop, most of which is operated by El Paso and held by production."
A breakout of non-proved resources (risked/unrisked) is as follows:
Unconventional - 1,080/1,560 Bcfe - Unconventional resources primarily consist of the company's coal bed operations in the Raton, Black Warrior, and Arkoma Basins and its holdings in the New Albany and Haynesville shale plays.
Conventional, low-risk (probability of geologic success greater than or equal to 40 percent) - 1,770/2,300 Bcfe - This consists of conventional resources in the Rockies, south Texas, and Brazil development programs. It also includes tight-sand drilling in the ArkLaTex area.
Conventional, higher-risk (probability of geologic success less than 40 percent) - 700/2,785 Bcfe - This includes higher-risk exploration in the Gulf of Mexico, Texas Gulf Coast, and undrilled international exploration prospects in Brazil and Egypt.
Click here to view a chart showing the change in year end reserves, including the Company's proportionate interest in Four Star.
El Paso Corporation provides natural gas and related energy products in a safe, efficient, and dependable manner. The company owns North America's largest interstate natural gas pipeline system and one of North America's largest independent natural gas producers. For more information, visit www.elpaso.com.
Cautionary Note to U.S. Investors
Note that the SEC permits oil and gas companies, in their filings 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 have used certain terms in this news release, such as risked and unrisked non-proved resource potential, that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Risked and unrisked non-proved resource potential are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Unrisked resource potential is less certain than those for risked resource potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at http://www.elpaso.com, including the inherent uncertainties in estimating quantities of proved reserves and non-proved resource potential.
CAUTIONARY STATEMENT
This release includes certain forward-looking statements and projections. The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this release, including, without limitation, changes in unaudited and/or unreviewed financial information; the uncertainty of estimating proved reserves and non-proved potential, the future level of service costs, the availability and cost of financing to fund our future exploration and production operations; the effects of any changes in accounting rules and guidance; our ability to meet production volume targets in our Exploration and Production segment; changes in commodity prices and basis differentials for oil, natural gas, and power, including the impact upon our hedge positions and our full-cost ceiling test in the future; general economic and weather conditions in geographic regions or markets served by the company and its affiliates, or where operations of the company and its affiliates are located, including the risk of a global recession and negative impact on natural gas demand; political and currency risks associated with international operations of the company and its affiliates; competition; and other factors described in the company's (and its affiliates') Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. The company assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by the company, whether as a result of new information, future events, or otherwise.
Certain of the production information in this press release include the production attributable to El Paso's 49 percent interest in Four Star Oil & Gas Company ("Four Star"). El Paso's Supplemental Oil and Gas disclosures, which are included in its Annual Report on Form 10-K, reflect its proportionate share of the proved reserves of Four Star separate from its consolidated proved reserves. In addition, the proved reserves attributable to its proportionate share of Four Star represent estimates prepared by El Paso and not those of Four Star. The reserve replacement ratio and reserve replacement costs are two metrics we use to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our core asset areas. In this press release, we have excluded price-related revisions from the calculations of these metrics. These revisions are included in the calculations of these metrics as presented in company's Annual Report on Form 10-K. See the company's Annual Report on Form 10-K for further discussions of these metrics.
Contacts:
Investor-Media Relations
Bruce L. Connery
Vice President
Office: (713) 420-5855
Media Relations
Bill Baerg
Manager
Office: (713) 420-2906
reserves, including the Company's proportionate interest
in Four Star Oil & Gas (Four Star)
-- 595 billion cubic feet equivalent (Bcfe) of reserve
additions prior to revisions
-- 192 percent reserve replacement prior to price-related
revisions
-- $2.87 per million cubic feet equivalent (Mcfe) domestic
reserve replacement costs prior to price-related revisions
-- Increased risked resource potential (which is in addition
to proved reserves) to 3.5 Tcfe
Note: Reserve additions include extensions, discoveries and purchases of reserves in place
El Paso Corporation (NYSE: EP) reported today that its proved natural gas and oil reserves at December 31, 2008 totaled 2.5 Tcfe, including 222 Bcfe related to its 48.8 percent interest in Four Star.
"El Paso had a very good year in terms of reserve additions, percentage of reserves replaced and domestic reserve replacement costs, excluding the effects of significant price-related revisions at year-end," said Doug Foshee, president and chief executive officer of El Paso Corporation. "Extensions and discoveries were up 69 percent over 2007 results, which demonstrate significant improvement in our E&P business. And the $2.87 per Mcfe domestic reserve replacement costs, excluding price-related revisions, is our best performance since I joined El Paso in 2003. While a sharp drop in commodity prices had a significant impact on year-end reserves, it is important to note that the year-end reserve calculation assumed very little reduction in service costs, which have fallen since year end and continue to decline. If we had calculated our year-end reserves assuming a Henry Hub natural gas price of $7.00 per MMBtu, $70.00 per barrel WTI pricing and assuming no further reduction in service costs, El Paso's reserves, including our interest in Four Star, would have been approximately 3.0 Tcfe."
Below is a reconciliation of consolidated proved reserves from December 31, 2007 to December 31, 2008, and a summary of El Paso's proportionate interest in Four Star proved reserves at December 31, 2008.
Consolidated Proved Reserves (Bcfe)*
------------------------------------
Proved Reserves at Dec. 31, 2007 2,853
Production (272)
Sales of Reserves in Place (303)
Extensions and Discoveries** 577
Purchases of Reserves in Place 18
Revisions Due to Price (476)
Revisions Other than Price (72)
Proved Reserves at Dec. 31, 2008 2,325
El Paso's Interest in Four Star Proved Reserves (Bcfe)
-----------------------------------------------------
Four Star at December 31, 2008 222
* Year end reserve estimates are based on $5.71 per MMBtu natural gas
(Henry Hub) and $44.60 per barrel (WTI) oil prices
** 128 Bcfe of reserve extensions and discoveries related to our Altamont
oil properties were based upon a $70 per barrel (WTI) oil prices, but were
ultimately eliminated due to price-related revisions at year end.
Approximately 74 percent of the December 31, 2008, proved reserves are proved developed, and 92 percent are natural gas. Approximately 85 percent of price-related revisions are attributable to the decline in oil and NGL prices. Of the price-related revisions, approximately 300 Bcfe were domestic, the largest portion of which was related to the company's Altamont oil properties. In addition, El Paso did not book any reserves from the Camarupim (Bia) project in Brazil due to the sharp drop in oil prices.
El Paso E&P's oil and gas 2008 capital expenditures were approximately $1.7 billion, which includes approximately $50 million for acquisitions of producing properties and approximately $200 million for international expenditures.
El Paso Corporation expects to take a fourth quarter after-tax full-cost ceiling test charge of $1.9 billion and a $0.1 billion impairment of its investment in Four Star. Approximately $1.4 billion of the full-cost ceiling test charge is attributable to the domestic full-cost pool and $0.5 billion to the Brazilian full-cost pool. The company uses the full-cost method of accounting for its oil and natural gas properties. The carrying value of these assets, net of related deferred income taxes, is evaluated on a quarterly basis and is limited to the present value of estimated net revenues of proved reserves using a 10-percent discount rate based on prices and costs at the end of the quarter plus the cost of unevaluated oil and natural gas properties (i.e. a cost center ceiling). A ceiling test charge occurs when the carrying value of the natural gas and oil assets exceeds the cost center ceiling.
El Paso has derivative positions that are intended to manage the price risk of its natural gas and oil production for 2009 and beyond. They are recorded on a mark-to-market basis and therefore were not included in the ceiling test calculation. These positions had a net asset value of approximately $700 million at December 31, 2008.
The ceiling test and impairment charges are non-cash items that do not impact any of the covenants on the debt obligations of El Paso Corporation or its subsidiaries. Based on current reserves and the expected fourth quarter 2008 ceiling test charge, the company estimates its first quarter 2009 per-unit DD&A rate will decline by approximately $0.90 per Mcfe from the rate used in the fourth quarter of 2008 to approximately $2.30 per Mcfe.
27 Percent Increase in Non-Proved Resources
El Paso also reported today that at December 31, 2008, it had an estimated 3.5 Tcfe of net risked or 6.6 Tcfe of net unrisked non-proved resource potential in addition to its 2.5 Tcfe of proved natural gas and oil reserves. The company's risked non-proved resource potential rose 0.7 Tcfe, or 27 percent, from 2007 levels. The majority of the increase was primarily due to the addition of new opportunities in the Haynesville Shale, infill opportunities in the Altamont Field and the Raton Basin coal bed methane program. Non-proved resources include the company's proportionate share of Four Star.
Foshee added, "One of our key successes in 2008 was the expansion of our future drilling inventory. The 2009 E&P capital program will optimize our current investment opportunities while preserving the drilling inventory that we have worked hard to develop, most of which is operated by El Paso and held by production."
A breakout of non-proved resources (risked/unrisked) is as follows:
Unconventional - 1,080/1,560 Bcfe - Unconventional resources primarily consist of the company's coal bed operations in the Raton, Black Warrior, and Arkoma Basins and its holdings in the New Albany and Haynesville shale plays.
Conventional, low-risk (probability of geologic success greater than or equal to 40 percent) - 1,770/2,300 Bcfe - This consists of conventional resources in the Rockies, south Texas, and Brazil development programs. It also includes tight-sand drilling in the ArkLaTex area.
Conventional, higher-risk (probability of geologic success less than 40 percent) - 700/2,785 Bcfe - This includes higher-risk exploration in the Gulf of Mexico, Texas Gulf Coast, and undrilled international exploration prospects in Brazil and Egypt.
Click here to view a chart showing the change in year end reserves, including the Company's proportionate interest in Four Star.
El Paso Corporation provides natural gas and related energy products in a safe, efficient, and dependable manner. The company owns North America's largest interstate natural gas pipeline system and one of North America's largest independent natural gas producers. For more information, visit www.elpaso.com.
Cautionary Note to U.S. Investors
Note that the SEC permits oil and gas companies, in their filings 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 have used certain terms in this news release, such as risked and unrisked non-proved resource potential, that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Risked and unrisked non-proved resource potential are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Unrisked resource potential is less certain than those for risked resource potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at http://www.elpaso.com, including the inherent uncertainties in estimating quantities of proved reserves and non-proved resource potential.
CAUTIONARY STATEMENT
This release includes certain forward-looking statements and projections. The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this release, including, without limitation, changes in unaudited and/or unreviewed financial information; the uncertainty of estimating proved reserves and non-proved potential, the future level of service costs, the availability and cost of financing to fund our future exploration and production operations; the effects of any changes in accounting rules and guidance; our ability to meet production volume targets in our Exploration and Production segment; changes in commodity prices and basis differentials for oil, natural gas, and power, including the impact upon our hedge positions and our full-cost ceiling test in the future; general economic and weather conditions in geographic regions or markets served by the company and its affiliates, or where operations of the company and its affiliates are located, including the risk of a global recession and negative impact on natural gas demand; political and currency risks associated with international operations of the company and its affiliates; competition; and other factors described in the company's (and its affiliates') Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. The company assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by the company, whether as a result of new information, future events, or otherwise.
Certain of the production information in this press release include the production attributable to El Paso's 49 percent interest in Four Star Oil & Gas Company ("Four Star"). El Paso's Supplemental Oil and Gas disclosures, which are included in its Annual Report on Form 10-K, reflect its proportionate share of the proved reserves of Four Star separate from its consolidated proved reserves. In addition, the proved reserves attributable to its proportionate share of Four Star represent estimates prepared by El Paso and not those of Four Star. The reserve replacement ratio and reserve replacement costs are two metrics we use to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our core asset areas. In this press release, we have excluded price-related revisions from the calculations of these metrics. These revisions are included in the calculations of these metrics as presented in company's Annual Report on Form 10-K. See the company's Annual Report on Form 10-K for further discussions of these metrics.
Contacts:
Investor-Media Relations
Bruce L. Connery
Vice President
Office: (713) 420-5855
Media Relations
Bill Baerg
Manager
Office: (713) 420-2906
Tuesday, February 3, 2009
SME Goes Natural Gas
By KARL PUCKETT • Tribune Staff Writer • February 2, 2009
In uncertain regulatory climate has prompted a developer to scrap its plans for a $900 million coal-fired power plant east of Great Falls and turn instead to renewable energy to meet the needs of its 65,000 Montana customers.
Southern Montana Electric Generation and Transmission announced today that it will seek financing to construct a 120-megawatt combined cycle natural gas-fired facility, in addition to six megawatts of wind power.
For the past four years, SME has been working on the 250-megawatt coal-fired Highwood Generating Station, but it faced stiff opposition in the courts and a state environmental appeals board.
SME already was planning to build 6 megawatts of wind power at the coal-fired facility, but CEO Tim Gregori said additional wind megawatts could be added now depending on the outcome of financing.
Repeated appeals of the project made obtaining financing for Highwood Generating Station too uncertain for financing institutions, which prompted the change in direction, Gregori said.
“That cast a stigma not only on our plant, it cast a stigma on any energy development in the state,” he said.
The election of Democrat Barack Obama, who has pushed renewable energy and more emissions controls of greenhouse gases, was a factor in the decision because it created more uncertainty about the future of coal-fired power, Gregori said. But he said the state’s regula-tory system as the main factor in the about-face.
The system was used by opponents to repeatedly appeal the project, Gregori said. But the new plans are another example of how the developer has listened to the public’s concerns and responded, Gregori said.
Bozeman-based Earthjustice attorney Abigail Dillen, which represented opponents in the courts and before the state Board of Environmental Review, said she looked forward to working with SME in its investment in renewable energy.
“We are thrilled they’ve decided to move away from coal,” Dillen said.
Anne Hedges of the Montana Environmental Information Center, calling coal-fired power plants the leading emitter of climate changing pollution, said SME’s decision was an “enormous step forward.”
“We can no longer continue to ignore global warming,” she said.
She added that SME should still move the natural gas fired power plant and the wind generation to a new site, calling it an industrial facility in the middle of farmland.
If opponents oppose Highwood now even after the changes, they are “hypocrites,” Gregori said.
SME broke ground on the coal-fired facility this past fall. Gregori said much of the preparation work will fit well with construction of the natural gas facility.
SME is speaking with the same “entities” about financing as it was when the project involved a coal-fire power plant, Gregori said.
Highwood is proposed by four rural cooperatives and would serve 65,000 Montanans including some customers served by the utility arm for the city of Great Falls.
In uncertain regulatory climate has prompted a developer to scrap its plans for a $900 million coal-fired power plant east of Great Falls and turn instead to renewable energy to meet the needs of its 65,000 Montana customers.
Southern Montana Electric Generation and Transmission announced today that it will seek financing to construct a 120-megawatt combined cycle natural gas-fired facility, in addition to six megawatts of wind power.
For the past four years, SME has been working on the 250-megawatt coal-fired Highwood Generating Station, but it faced stiff opposition in the courts and a state environmental appeals board.
SME already was planning to build 6 megawatts of wind power at the coal-fired facility, but CEO Tim Gregori said additional wind megawatts could be added now depending on the outcome of financing.
Repeated appeals of the project made obtaining financing for Highwood Generating Station too uncertain for financing institutions, which prompted the change in direction, Gregori said.
“That cast a stigma not only on our plant, it cast a stigma on any energy development in the state,” he said.
The election of Democrat Barack Obama, who has pushed renewable energy and more emissions controls of greenhouse gases, was a factor in the decision because it created more uncertainty about the future of coal-fired power, Gregori said. But he said the state’s regula-tory system as the main factor in the about-face.
The system was used by opponents to repeatedly appeal the project, Gregori said. But the new plans are another example of how the developer has listened to the public’s concerns and responded, Gregori said.
Bozeman-based Earthjustice attorney Abigail Dillen, which represented opponents in the courts and before the state Board of Environmental Review, said she looked forward to working with SME in its investment in renewable energy.
“We are thrilled they’ve decided to move away from coal,” Dillen said.
Anne Hedges of the Montana Environmental Information Center, calling coal-fired power plants the leading emitter of climate changing pollution, said SME’s decision was an “enormous step forward.”
“We can no longer continue to ignore global warming,” she said.
She added that SME should still move the natural gas fired power plant and the wind generation to a new site, calling it an industrial facility in the middle of farmland.
If opponents oppose Highwood now even after the changes, they are “hypocrites,” Gregori said.
SME broke ground on the coal-fired facility this past fall. Gregori said much of the preparation work will fit well with construction of the natural gas facility.
SME is speaking with the same “entities” about financing as it was when the project involved a coal-fire power plant, Gregori said.
Highwood is proposed by four rural cooperatives and would serve 65,000 Montanans including some customers served by the utility arm for the city of Great Falls.
Monday, February 2, 2009
Chinese Natural Gas Output Increased in 2008
Chinese natural gas output up by 12.3% in 2008 - steelguru.com
Xinhua quoted an industry association said China's production of natural gas rose 12.3%YoY to 76.1 billion cubic meters in 2008 as the government promoted cleaner energy.
The China Petroleum and Chemical Industry Association said the annual growth rate was down from 23.1% in 2007.
According to statistics from BP China consumed 67.3 billion cubic meters of gas in 2007, an annual increase of 19.9%. This compared to 55.6 billion cubic meters in 2006 up by 21.6% from the previous year. Consumption figures for 2008 are unavailable.
China's production and consumption of natural gas have been rising steadily since the government set a target of raising the proportion of natural gas in total energy consumption to 5.3% by 2010 from 2.8% in 2005. The plan was aimed to shift away from a heavy reliance on coal, which accounts for about 70% of total energy consumption.
The CPCIA said the expansion of the natural gas infrastructure, including pipelines, reflected the rapid increases in output and consumption.
In 2008, China launched construction of the second east-west gas pipeline and the connection of Central Asia gas pipeline. The new pipelines are scheduled to become operational by the end of 2009 and will have an annual capacity of 30 billion cubic meters. They will mainly carry natural gas from Central Asia to the Yangtze and Pearl River deltas, the country's two most developed regions.
Construction of more liquefied natural gas terminals were also launched last year, while LNG purchase agreements were signed between state oil producers and foreign LNG sellers, including Shell, Total and Qatar Gas, despite higher natural gas prices driven by record oil price hikes in 2008. Those agreements would add possible annual imports of more than 8 million tons.
Xinhua quoted an industry association said China's production of natural gas rose 12.3%YoY to 76.1 billion cubic meters in 2008 as the government promoted cleaner energy.
The China Petroleum and Chemical Industry Association said the annual growth rate was down from 23.1% in 2007.
According to statistics from BP China consumed 67.3 billion cubic meters of gas in 2007, an annual increase of 19.9%. This compared to 55.6 billion cubic meters in 2006 up by 21.6% from the previous year. Consumption figures for 2008 are unavailable.
China's production and consumption of natural gas have been rising steadily since the government set a target of raising the proportion of natural gas in total energy consumption to 5.3% by 2010 from 2.8% in 2005. The plan was aimed to shift away from a heavy reliance on coal, which accounts for about 70% of total energy consumption.
The CPCIA said the expansion of the natural gas infrastructure, including pipelines, reflected the rapid increases in output and consumption.
In 2008, China launched construction of the second east-west gas pipeline and the connection of Central Asia gas pipeline. The new pipelines are scheduled to become operational by the end of 2009 and will have an annual capacity of 30 billion cubic meters. They will mainly carry natural gas from Central Asia to the Yangtze and Pearl River deltas, the country's two most developed regions.
Construction of more liquefied natural gas terminals were also launched last year, while LNG purchase agreements were signed between state oil producers and foreign LNG sellers, including Shell, Total and Qatar Gas, despite higher natural gas prices driven by record oil price hikes in 2008. Those agreements would add possible annual imports of more than 8 million tons.
Sunday, February 1, 2009
Natural Gas Price Pressured by LNG
By TOM FOWLER Copyright 2009 Houston Chronicle
Jan. 31, 2009, 1:47AMAs many as seven massive natural gas export terminals are expected to start up overseas this year, expanding worldwide capacity by 20 percent and flooding markets with new supplies of the key power plant and heating fuel. Dozens of new tankers capable of carrying natural gas in a liquefied form are slated to hit the seas.
Just as these new supplies come on line, worldwide demand is expected to drop as the global recession deepens.
Operators of these new facilities are unlikely to cut back production, however, so shipments of liquefied natural gas will most likely head to the deepest markets with the greatest amount of natural gas storage capacity — the United States.
‘Counterintuitive’
“It’s completely counterintuitive,” said Murray Douglas, a global LNG analyst with Wood Mackenzie in Houston, who is predicting U.S. LNG imports will grow 30 percent to 456 billion cubic feet this year and to more than 1.1 trillion cubic feet by 2013.
“We don’t believe Asia and Europe will be in a position to absorb this new production, and the U.S. is the only market that can take it, that has a large amount of storage.”
The wave of imports might even be strong enough to challenge growing domestic natural gas production from various shale formations, including the Barnett Shale near Fort Worth and Fayetteville Shale in Arkansas.
“This can put pressure on U.S. gas prices and could delay the full development of some of the new shale pro-jects,” Douglas said.
Other analysts, including Houston-based Waterborne Energy and Raleigh, N.C.-based Pan Eurasia Enterprises, agree that an American gas import surge may be coming.
Even the Department of Energy updated its LNG import predictions for 2009 recently to include the possibility of such a surge.
Big energy chunk
Natural gas accounts for 23 percent of total energy consumed in the U.S., according to the Department of Energy, much of it used to fuel power plants.
Twelve percent of the gas comes from foreign suppliers, most of it through pipelines from Canada, and about 3 percent comes from overseas aboard LNG tankers.
Changing to liquid
Natural gas turns into liquid at minus 260 degrees Fahrenheit. In that condensed form, it can be transported in specially designed oceangoing tankers. When the tankers reach a gasification terminal, the liquid is heated back into gas for transport by pipeline.
2007 was a record year for LNG imports into the U.S., with some 770 billion cubic feet arriving through five terminals.
Three terminals came on line in 2008, including Houston-based Cheniere Energy’s terminal on the Louisiana side of the Sabine Pass south of Port Arthur and Freeport LNG’s terminal on Quintana Island south of Houston. The third, owned by The Woodlands-based Excelerate Energy, is near Boston.
Timing not ideal
The timing was bad. U.S. imports slowed as tankers were drawn both to Europe — where prices spiked recently because of ongoing supply disputes with Russia — and Asia, where economic growth and the shutdown of a large nuclear power plant in Japan because of earthquake damage led to greater demand for natural gas to run other power plants.
More of the same was expected for this year. Some equity research firms even stopped tracking LNG terminal operators.
Asia-Pacific region
But the coming wave of new export terminals, where the gas is liquefied and loaded on tankers, is centered largely in the Asia-Pacific region, said Steve Johnson, president of Waterborne Energy. That means those markets will be well-served, leaving more tankers available for Atlantic markets — with the U.S. being the deepest and most liquid.
One might expect the new LNG exporters to delay opening, or at least cut back their output given the lower demand.
But the gas liquefaction projects have been planned over many years and cost their host governments many billions of dollars, Johnson said.
“Shutting it down is the last thing they will do,” Johnson said.
Competitive price
LNG can be competitive priced as low as $3 per million British thermal units, said Zach Allen, head of Pan EurAsian Enterprises, a management advisory firm that follows LNG markets. That’s a price the U.S. hasn’t seen since 2002.
While LNG generally is sold in contracts between importers and exporters, its price is influenced by the price of natural gas traded on the New York Mercantile exchange, which closed Friday at $4.42 per million Btu.
“Some cash is better than none, especially for producers who rely heavily on that cash for social and other programs that would be politically explosive to cut off or cut back,” Allen said.
Some of Qatar’s natural gas fields produce other valuable liquids that are stripped out and sold at prices that essentially cover all production costs before the gas even makes it to market, Douglas said.
“They are essentially producing the gas for free,” Douglas said.
The cost of getting the LNG from its foreign origin to other markets can be relatively low, Johnson said.
The 43-day round trip from the huge export terminal in Qatar to the Lake Charles, La., LNG terminal costs $2.09 per million British thermal units.
From Egypt to Lake Charles takes 30 days and $1.29 per million Btu.
tom.fowler@chron.com
Jan. 31, 2009, 1:47AMAs many as seven massive natural gas export terminals are expected to start up overseas this year, expanding worldwide capacity by 20 percent and flooding markets with new supplies of the key power plant and heating fuel. Dozens of new tankers capable of carrying natural gas in a liquefied form are slated to hit the seas.
Just as these new supplies come on line, worldwide demand is expected to drop as the global recession deepens.
Operators of these new facilities are unlikely to cut back production, however, so shipments of liquefied natural gas will most likely head to the deepest markets with the greatest amount of natural gas storage capacity — the United States.
‘Counterintuitive’
“It’s completely counterintuitive,” said Murray Douglas, a global LNG analyst with Wood Mackenzie in Houston, who is predicting U.S. LNG imports will grow 30 percent to 456 billion cubic feet this year and to more than 1.1 trillion cubic feet by 2013.
“We don’t believe Asia and Europe will be in a position to absorb this new production, and the U.S. is the only market that can take it, that has a large amount of storage.”
The wave of imports might even be strong enough to challenge growing domestic natural gas production from various shale formations, including the Barnett Shale near Fort Worth and Fayetteville Shale in Arkansas.
“This can put pressure on U.S. gas prices and could delay the full development of some of the new shale pro-jects,” Douglas said.
Other analysts, including Houston-based Waterborne Energy and Raleigh, N.C.-based Pan Eurasia Enterprises, agree that an American gas import surge may be coming.
Even the Department of Energy updated its LNG import predictions for 2009 recently to include the possibility of such a surge.
Big energy chunk
Natural gas accounts for 23 percent of total energy consumed in the U.S., according to the Department of Energy, much of it used to fuel power plants.
Twelve percent of the gas comes from foreign suppliers, most of it through pipelines from Canada, and about 3 percent comes from overseas aboard LNG tankers.
Changing to liquid
Natural gas turns into liquid at minus 260 degrees Fahrenheit. In that condensed form, it can be transported in specially designed oceangoing tankers. When the tankers reach a gasification terminal, the liquid is heated back into gas for transport by pipeline.
2007 was a record year for LNG imports into the U.S., with some 770 billion cubic feet arriving through five terminals.
Three terminals came on line in 2008, including Houston-based Cheniere Energy’s terminal on the Louisiana side of the Sabine Pass south of Port Arthur and Freeport LNG’s terminal on Quintana Island south of Houston. The third, owned by The Woodlands-based Excelerate Energy, is near Boston.
Timing not ideal
The timing was bad. U.S. imports slowed as tankers were drawn both to Europe — where prices spiked recently because of ongoing supply disputes with Russia — and Asia, where economic growth and the shutdown of a large nuclear power plant in Japan because of earthquake damage led to greater demand for natural gas to run other power plants.
More of the same was expected for this year. Some equity research firms even stopped tracking LNG terminal operators.
Asia-Pacific region
But the coming wave of new export terminals, where the gas is liquefied and loaded on tankers, is centered largely in the Asia-Pacific region, said Steve Johnson, president of Waterborne Energy. That means those markets will be well-served, leaving more tankers available for Atlantic markets — with the U.S. being the deepest and most liquid.
One might expect the new LNG exporters to delay opening, or at least cut back their output given the lower demand.
But the gas liquefaction projects have been planned over many years and cost their host governments many billions of dollars, Johnson said.
“Shutting it down is the last thing they will do,” Johnson said.
Competitive price
LNG can be competitive priced as low as $3 per million British thermal units, said Zach Allen, head of Pan EurAsian Enterprises, a management advisory firm that follows LNG markets. That’s a price the U.S. hasn’t seen since 2002.
While LNG generally is sold in contracts between importers and exporters, its price is influenced by the price of natural gas traded on the New York Mercantile exchange, which closed Friday at $4.42 per million Btu.
“Some cash is better than none, especially for producers who rely heavily on that cash for social and other programs that would be politically explosive to cut off or cut back,” Allen said.
Some of Qatar’s natural gas fields produce other valuable liquids that are stripped out and sold at prices that essentially cover all production costs before the gas even makes it to market, Douglas said.
“They are essentially producing the gas for free,” Douglas said.
The cost of getting the LNG from its foreign origin to other markets can be relatively low, Johnson said.
The 43-day round trip from the huge export terminal in Qatar to the Lake Charles, La., LNG terminal costs $2.09 per million British thermal units.
From Egypt to Lake Charles takes 30 days and $1.29 per million Btu.
tom.fowler@chron.com
Subscribe to:
Posts (Atom)