Oil Sands & Gas Shale UPDATE
November 2011
McIlvaine Company
TABLE OF CONTENTS
Analyst Claims Huge Opportunities in European and Asian Shale Gas
National Oilwell and other Oil Field Service Companies Profit from North American Demand
Boardwalk Pipeline, Southwestern Energy Reach 15-Year, $90 Mln Marcellus Gathering Construction Deal
TPG to Expand its 300 Line in PA for Transporting Gas from the Marcellus Shale
Flint Energy Services Wins $430 Mln Oilsands SAGD Construction Contract
Chesapeake and Range Resources among Top Marcellus Producers
TransCanada Boosts Keystone XL Safety Measures to Appease Nebraska Lawmakers
Kinder Morgan to Acquire El Paso in $38 Bln Deal
Drilling Pace Slows in Barnett Shale but is Booming in Permian Basin and Eagle Ford
Consol Energy and Hess Close on Ohio Utica Shale Acreage JV Agreement for $594 Mln
C&J Energy Services Signs Two-Year Contract for Its Sixth Hydraulic Fracturing Fleet
Blacksands Pacific Group Announces Acquisition and JV Partnership in California
Fountain Quail Introduces New Fracking Water System
GAIL Plans to Purchase more U.S. Shale Gas Assets
Study Finds No Major Short Term Impact from Marcellus Shale Drilling on Area Drinking Water
Enbridge Plans $90 Mln Expansion of Bakken Oil Projects
Fluor Wins Alberta’s Redwater Bitumen Refinery FEED Contract
Jacobs Wins $1.4 Bln in Alberta Oil-Sands Contracts
Oilsands Quest to Sell Wallace Creek Property to Further Develop Axe Lake
Spectra, Progress Strike Montney Midstream Deals
Aecon Wins $132 Mln in Contracts at Fort McMurray Oilsands Project
Argentina Poised for Huge Shale Gas Investment with $1 Bln Predicted over the Next Few Years
Santos Says Only Way to Meet Natural Gas Demand Is Allow Unconventional Gas Projects
China Targets Annual Shale Gas Production to 2015 and 2020
With Reserves Larger than U.S. China Plans Subsidies to Tap Shale Gas
EU Split over Oilsands with No Vote until December
PKN Orlen to Invest $158 Mln in Six Shale Gas Test Wells
Drilling Tests and Analysis Indicate Presence of World Class Shale Gas Play in Spain's Basque Area
Massive Shale Gas Potential in UK’s Humber Basin
Jordan Approves Deal with Eesti Energia for Oil Shale Plant
Shale-gas production in Europe could reach 35 billion cubic meters a year (cm/y) by 2020, or 20% of EU member states’ output now, with Poland and the UK the leading producers, says a new report.
Unconventional Gas World Production & Drilling Forecast, a study by Consultants Douglas Westwood, claims shale gas output in Poland and the UK could reach 11 billion cm and 2 billion cm respectively by 2020.
Poland has been aggressively promoting domestic shale gas drilling and last month Cuadrilla Resources claimed to have discovered 5.7 trillion cm in northern England. Prospects for developing shale gas resources beyond North America are “looking good”, said analyst Joseph Dutton, author of the report.
Although North America will dominate the global shale-gas sector – U. S. production totaled 136 billion cm in 2010, according to the Energy Information Administration (EIA) – there will also be “rapid development” of shale gas in Europe, Asia, Australasia and China, the report said. Growth in Asia will “outstrip all other regions”, with production set to rise by 1,000% between now and 2020, to reach 65 billion cm/y.
“China has a very optimistic and forthright attitude to any kind of economic development and it doesn’t have the same issues from a regulatory point of view that Europe does”, Dutton says. “The potential to China is huge.” With shale-gas reserves estimated by the EIA to be 36 trillion cm, China is pushing development of the resources in a bid to avoid a 5 billion cm/y gas-supply shortfall from 2015.
Australia will also see “near-exponential” unconventional gas-growth, with output reaching 69 billion cm/y by 2020. Most of this production will be coal-bed methane (CBM), as production in Queensland ramps up to supply planned natural gas export projects.
In Latin America, unconventional output is set to reach 5 billion cm/y by 2020, Dutton said, as companies such as Repsol explore for and develop shale gas in Argentina’s Neuquén Basin. In Africa, meanwhile shale output is also forecast at 5 billion cm/y by 2020.
The International Energy Agency (IEA) estimates global unconventional-gas reserves – including tight gas, shale gas and CBM – to be around 921 trillion cm in Europe alone. Global unconventional production will make up one-third of gas-supply growth, says the IEA, with shale-gas and CBM from China and Australia important contributors.
But this projected production boom will place “considerable demand” on the global services sector, Dutton said. To achieve shale gas output of 35 billion cm/y in Europe, a huge number of wells must be drilled rapidly and many more rigs will be essential.
“We’d need 4,000 wells to be drilled a year, with around 800 drilling rigs operating, to reach the forecast production”, Dutton said. “The regulatory and environmental frameworks in Europe are an issue, but even if that’s sorted out, a huge investment is required in the drilling sector.” In March, Douglas Westwood said Europe may need to spend $10 billion on its oilfield services sector to see significant unconventional gas production up and running on the continent.
Adding to the financial burden drilling costs in Europe will be significantly higher than in the U.S. because of the depth of the shales and lack of available equipment and infrastructure. Well costs for shale gas in Europe could be as much as $10 million to $15 million each, the consultancy said, while drilling tight-gas wells could cost as much as $18 million to $28 million. By comparison, shale-gas drillers in the U.S. say per well costs are now often beneath $5 million.
While nearly 2,000 rigs are active in the U.S. onshore, in Europe the number is just 75 – and only around 20 of those could be suitable for unconventional gas production. Consequently, new rigs must be built to cope with the deep drilling and multi-stage well stimulation needed for unconventional operations.
There is also an issue with high decline rates from shale-gas wells – which are around 60% in the first year, according to Dutton. To reach output levels estimated in the report, 25, 000 wells will have to be drilled every year to counter act such steep production falls. “With Europe, the energy industry is predominantly developed around the offshore sector,” said Dutton. “The transfer to onshore is possible, but will require a lot of investment.” It offers “huge market opportunities for oilfield services companies, he said.
The report claims countries such as Germany, France and the Netherlands could achieve commercial shale gas production by 2020. But polarized views on hydraulic fracturing (fracking) within the EU could hinder development.
France, which could have the second largest shale gas reserves in Europe, 5.3 trillion cm – assumed the EU Presidency on July 1, it has pushed a pro-fracking agenda and said it will veto any attempts by other EU member states to introduce pan-European gas regulation. With the re-election of Poland’s pro-shale-gas Prime Minister, Donald Tusk, the commitment to developing shale gas looks set to continue.
“The EU needs to tread very carefully”, Dutton said. “Various member states are very keen to develop their own indigenous sources of gas, but it’s about how these are offset from a legal and regulatory standpoint”
Natural gas “ticks the boxes” for the EU’s climate-change targets and is much more commercially viable than renewable energy, which requires such high government subsidies, said Dutton, adding: “Shale-gas development in Europe is something we can’t afford to miss out on. The battleground is going to be around the regulatory issues.”
Demand for equipment and services from North America's oil and natural gas producers generated big third-quarter profits for National Oilwell Varco and Weatherford International, the oil field service companies reported in October.
Profits for Houston-based National Oilwell Varco rose 32 percent to $532 million in the three months ending September 30. Earnings per diluted share grew to $1.25, from 96 cents in the third quarter of 2010.
Revenue grew 24 percent to $3.7 billion year over year.
NOV executives said oil and gas activity in deep waters offshore and in U.S. shale formations propelled profits. The company has benefited from demand for advanced equipment that cuts time and improves the efficiency of producing oil and gas from dense shale, said Chief Financial Officer Clay Williams.
"Shales and deep water continued to shape our industry and drove higher demand for NOV's products and services," Williams said in a conference call with analysts.
"We believe shale drilling will continue to shape National Oilwell Varco's performance for many years to come, owing to our strong position in the supply of key technologies which make shales work."
While low prices have reduced companies' interest in drilling for dry gas, demand is growing for rigs in fields rich in oil and natural gas liquids, which command higher prices, said CEO Pete Miller.
NOV's rig technology division had a record quarter, bringing in nearly $4 billion in new orders, Williams said. The division designs and sells equipment systems used to drill and service wells. The standout quarter included a single $1.5 billion order for seven drillship packages for a Brazilian company, NOV's largest order on record, according to the company.
Weatherford International, a Swiss-based company that has major offices in Houston, doubled its third-quarter profit, bringing in $190 million, compared with $95 million a year earlier. Earnings rose to 25 cents per diluted share, from 13 cents in the third quarter of 2010.
CEO Bernard Duroc-Danner said income surged on booming activity in North America and Latin America, where revenue grew 48 percent and 76 percent respectively.
But profits were moderated by a lackluster quarter in Middle East and North Africa, where revenue fell 5 percent.
Weatherford suffered from higher-than-expected project costs in several Middle Eastern countries, including Iraq. Turmoil in Libya and expired contracts in Algeria also affected the bottom line, Duroc-Danner said.
"The quarter was earned entirely in the Western Hemisphere," he said, while the Middle East and North Africa are in a "transitional period."
"We don't expect these factors to weigh on the region for too long," Duroc-Danner said.
Boardwalk Pipeline Partners, LP and Southwestern Energy Company on October 10 announced that their subsidiaries, Boardwalk Field Services, LLC and Southwestern Energy Production Company, have executed a 15-year definitive gas gathering agreement which will require construction of a natural gas gathering system in Susquehanna and Lackawanna Counties, Pennsylvania. Boardwalk will own and operate the gas gathering system that will support Southwestern's development of Marcellus Shale gas wells in these counties.
The gathering system is expected to cost approximately $90 million and will be comprised of approximately 26 miles of 12" high pressure gas pipeline, a low pressure in-field gathering pipeline, compression and dehydration and will interconnect with Tennessee Gas Pipeline Company in Susquehanna County, Pennsylvania. The system will be built out over several years and is expected to have a delivery capacity of 275,000 Dth/day when fully constructed.
El Paso Corporation on October 7 announced that its wholly owned subsidiary, Tennessee Gas Pipeline Company (TGP), has executed long-term agreements for the MPP project which will expand TGP's 300 Line in Pennsylvania.
The 240,000 dekatherms per day (Dth/d) project includes approximately 8 miles of 30" pipeline looping and modifications to four existing compressor stations in Pennsylvania to provide natural gas transportation from the Marcellus Shale supply area to existing delivery points on the TGP system. All of the capacity is subscribed through agreements with Chesapeake Energy Marketing, Inc., a wholly owned subsidiary of Chesapeake Energy Corporation, for 140,000 Dth/d and Southwestern Energy Services Company, a wholly owned subsidiary of Southwestern Energy Company, for 100,000 Dth/d.
"We are pleased to announce our fourth expansion project in as many years which brings our total investment in Marcellus infrastructure to $1.3 billion and adds nearly 1.5 Bcf/d of capacity," said Norman Holmes, president of Tennessee Gas Pipeline. "This project leverages TGP's strategic location and provides significant new firm transportation capacity for two prominent Marcellus Shale producers."
Capital for the MPP project is expected to be less than $100 million. TGP anticipates filing a certificate application for the project with the Federal Energy Regulatory Commission in late 2011. Pending regulatory approvals, construction would begin in 2013, with a November 1, 2013 in-service date.
Flint Energy Services Ltd. has won a $430 million contract to build a major SAGD oilsands project in the Wood Buffalo Region near Fort McMurray, Alta.
Flint will be responsible for the construction of two major silos of work within the central plant facility. The scope of the project consists of Flint’s traditional mechanical and electrical direct field activities, as well as construction management and support.
Flint’s work will commence in the first quarter of 2012 and will continue until mid-2014. Flint anticipates this project will employ over 1,500 people at peak.
W. J. (Bill) Lingard, President and Chief Executive Officer said they are pleased to have been chosen as the construction partner.
“This is a large construction project and it demonstrates the increasing activity levels in oilsands capital investments.”
With this contract, the backlog of work for Flint’s Facility Infrastructure segment now sits at $740 million. Flint also has others bids in play.
Chesapeake Energy and Range Resources are well known for their Barnett Shale operations in North Texas, but they also are among the top producers in the growing Marcellus Shale natural gas field in Pennsylvania.
The Fort Worth Star-Telegram, citing data compiled by the Fort Worth-based Powell Shale Digest, reported that Chesapeake -- the No. 2 producer in the Barnett Shale, is the top producer in the Marcellus Shale with nearly 163 billion cubic feet of natural gas production in the two-year period that ended on June 30.
Oklahoma City-based Chesapeake has a large operation in Fort Worth.
Range Resources, which is based in Fort Worth, is the No. 4 Marcellus producer at 109.6 billion cubic feet of natural gas production, plus 741,950 barrels of oil and 319,089 barrels of condensate, the Star-Telegram reported.
Other DFW companies also are big in the Marcellus: Fort Worth-based XTO Energy is No. 19. XTO is a subsidiary of Irving-based Exxon Mobil Corp., and Dallas-based Chief Oil & Gas ranked 16th.
TransCanada Corp. has attempted to appease Nebraska lawmakers by adding increased safety measures to a section of the controversial Keystone XL pipeline system that crosses the state's large underground water system.
The Canadian pipeline company made several guarantees to Nebraska lawmakers, including a $100 million bond to ensure adequate funds to clean up after any oil spills, as the state's legislature considered holding a special session to consider legislation to force the company to change Keystone's route.
TransCanada maintains that Keystone's route, which crosses the state's Ogallala Aquifer, causes the least environmental disturbance and that the pipeline is safe. Critics are worried an oil spill could damage the aquifer, which provides water for the state's people and agricultural economy.
In a letter to the Speaker of the Nebraska legislature, Sen. Mike Flood, TransCanada also offered to build a concrete containment ditch around the pipeline where it cross the environmentally sensitive Sand Hills area, to locate a rapid spill-response team in the Sand Hills, to encase the pipeline with an additional protective coating in certain areas, to provide free water testing to nearby land owners and to pay for state regulators to hire a special public liaison officer to handle concerns about the pipeline.
A TransCanada spokesman said company executives offered the concessions to Sen. Flood and other lawmakers in a mid-October meeting. It's still not clear whether the Nebraska legislature intends to hold a special session on the pipeline. Flood's office couldn't immediately be reached for comment.
Kinder Morgan, Inc. and El Paso Corporation on October 16 announced a definitive agreement whereby KMI will acquire all of the outstanding shares of EP in a transaction that will create the largest midstream and the fourth largest energy company in North America with an enterprise value of approximately $94 billion and 80,000 miles of pipelines. The total purchase price, including the assumption of debt outstanding at El Paso Corporation and including the debt outstanding at El Paso Pipeline Partners, L.P. is approximately $38 billion.
The combined enterprise, including the associated master limited partnerships, Kinder Morgan Energy Partners, L.P. and EPB, will represent the largest natural gas pipeline network in the United States, the largest independent transporter of petroleum products in the United States, the largest transporter of CO2 in the United States and the largest independent terminal owner/operator in the United States.
"This once in a lifetime transaction is a win-win opportunity for both companies," said Kinder Morgan Chairman and CEO Richard D. Kinder. "The El Paso assets are primarily regulated interstate natural gas pipelines that produce substantial, stable cash flow and have access to key supply regions and major consuming markets. The natural gas pipeline systems of the two companies are very complementary, as they primarily serve different supply sources and markets in the United States. The transaction is expected to produce immediate shareholder value (upon closing) through strong cash flow accretion and offers significant future growth opportunities."
Doug Foshee, chairman, president and chief executive officer of El Paso Corporation said "We are very pleased to become a significant part of this combined enterprise and offer our shareholders the opportunity to participate in what we believe will be North America's preeminent infrastructure company."
The transaction has been approved by each company's board of directors. KMI has a commitment letter from Barclays Capital underwriting the full amount of cash required for the transaction. Prior to closing, the transaction will require approval of both KMI and EP shareholders. The transaction is expected to close in the second quarter of 2012 and is subject to customary regulatory approvals.
The transaction is expected to be immediately accretive to dividends per share at KMI, distributions per unit at KMP, dividends per share at Kinder Morgan Management and distributions per unit at EPB. Part of these benefits will be driven by cost savings, which are expected to be approximately $350 million per year, or about 5 percent of the combined system's EBITDA. Following is a summary of the plans and benefits for each entity:
Following the closing of the transaction, EP will become a subsidiary of KMI. KMI intends to sell the exploration and production assets of EP. EP's net operating loss carry-forwards will offset taxes associated with this sale and the resulting cash raised will substantially reduce the debt borrowed to fund the cash portion of the transaction. KMI also intends to sell (drop down) all of EP's natural gas pipeline assets to KMP and EPB over the next few years. Each of these transactions will be subject to approval by KMP's or EPB's independent directors, who are expected to obtain independent advisors to assist them in their analysis.
By the end of 2015, KMI expects its assets to consist almost exclusively of its general partner interests in KMP and EPB, and the ownership of KMP units, KMR shares and EPB units. At that point, well over 80 percent of KMI's cash flows is expected to come from the general partner interests and essentially all of the remainder from its limited partner interests. KMI expects to continue to determine dividend payouts based upon this ultimate set of assets and cash flows. In the interim, KMI will be generating more cash flow than necessary to support the expected dividend stream and will use the excess to pay down debt. Incorporating this approach to determining dividends, the transaction is expected to be immediately accretive to KMI's dividend per share.
While KMI will be assuming a significant amount of incremental debt as a result of the transaction, the sale of EP's exploration and production business, dropdown transactions to KMP and EPB, and excess cash flows should allow for a rapid reduction in debt levels. KMI expects its ratio of debt to distributions received will be lower than its current level of about 2.5 times by the end of 2013 and that the ratio of consolidated net debt for the entire enterprise (including debt at KMP and EPB) to consolidated EBITDA will return to a little over 4 times by the end of 2014. "Given the quality of the assets that will be owned by the combined enterprise and the stability of cash flows that these assets generate, we believe that we have a clear path to achieving these expectations and that the resulting debt levels are conservative," said Kinder.
KMP is expected to purchase a significant portion of EP's natural gas pipeline assets over the next few years at attractive prices. These assets will enhance KMP's already very stable cash flow stream and will provide significant additional growth opportunities. For 2012, the KMP distribution per unit and KMR dividend per share are expected to be a little less than $5.00, up from a budgeted $4.60 for 2011. Over the next several years, the average annual growth rate in KMP distributions per unit and KMR dividends per share is expected to be around 7 percent, higher than the prior estimate of 5 percent annually, with the increase driven by the expected dropdowns resulting from this transaction.
KMP expects to fund the asset acquisitions with a combination of equity and debt, consistent with its past practices. The equity will be in the form of both KMP unit and KMR share issuances, with KMI taking a small portion of the issuances. KMP expects it will reduce its debt to EBITDA ratio consistently over this time period down to around 3.3 times, which will continue to represent a very strong balance sheet, especially considering the strength of its assets and the stability of its cash flows.
EPB is also expected to purchase EP pipeline assets from KMI over the next few years at attractive prices. EPB's asset base will continue to consist completely of stable, high quality interstate natural gas pipelines. "We expect EPB to be able to grow its distributions per unit at an average annual growth rate of about 9 percent through 2015 as a result of this transaction," Kinder said. "EPB is also expected to fund its acquisitions with a combination of equity and debt issuance, maintaining its strong balance sheet. We would expect EPB's debt to EBITDA ratio to remain around 4 times, which is appropriate for the strength of the assets that it owns and is expected to acquire."
The combined company will be the largest owner and operator of natural gas pipelines and storage assets in North America with approximately 67,000 miles of natural gas transportation pipelines. Pipelines are connected to many important natural gas shale plays including Eagle Ford, Marcellus, Utica, Haynesville, Fayetteville and Barnett.
"El Paso's assets are a great fit with our long-standing strategy of owning and operating predominantly stable, regulated, fee-based businesses in growing markets," Kinder said. "We have a proven track record of merging companies, operating assets efficiently and growing existing assets through expansions, and we are very excited to add these assets to our portfolio."
Once the transaction is completed, Kinder will remain chairman and CEO of the combined entity. The parent company will be named Kinder Morgan, Inc. and its corporate headquarters will remain in Houston, Texas. Two members of EP's board of directors will join the KMI board of directors. The transaction will require the approval of both KMI and EP shareholders who will vote at special meetings expected to be held by January 2012. Both the boards of directors of KMI and EP are recommending that shareholders vote in favor of the transaction. EP has agreed not to solicit competing transactions and to pay a termination fee of $650 million to KMI under certain circumstances.
Drilling is at a seven- year low in the North Texas natural gas fields. But even as drilling pace slackens in the Barnett Shale, it's booming in other oil and gas fields of Texas such as the Permian Basin of West Texas and the Eagle Ford Shale of South Texas.
The number of active Barnett Shale drilling rigs has fallen to 53, their lowest since June 11, 2004. That's barely more than one-fourth of the peak count of 203 active Barnett rigs on September 5, 2008, the Fort Worth Star-Telegram reported. That falloff comes even as drilling booms in the long-drilled Permian Basin of West Texas and the newly exploited Eagle Ford Shale in South Texas. Those fields offer more liquids such as oil and liquefied gas, drawing higher prices than the drier Barnett Shale natural gas fields. The number of rigs working in the 55-county Permian Basin has nearly tripled in less than two years to 395, with 195 rigs drilling in the Eagle Ford Shale.
Across Texas and the nation, oil production is up. That has diverted attention away from the Barnett Shale, which is a drier field with plenty of low-price natural gas but not as much oil, condensate and other petroleum liquids. "If you look at the drilling rig count for crude oil, compared to natural gas, it gives you a strong visual of what's happening in the industry," Alex Mills, president of the Texas Alliance of Energy Producers, told the Star-Telegram. "There's just an oversupply of natural gas right now, and that has kept gas prices soft. That has made the industry divert the rigs from looking for natural gas to crude oil." Fort Worth-based drilling contractor Union Drilling Co. has moved most of its Texas rigs from the Barnett Shale to the Permian Basin, chief executive Christopher Strong told the newspaper. "We had only one rig out of our Texas fleet that was running in West Texas back in early 2010," he said. "Now we have 16 over there and only four running in the Barnett. It's been a huge shift."
Also, restrictive local regulations has discouraged further drilling in the North Texas field, said Julie Wilson, vice president for urban development for Oklahoma City-based Chesapeake Energy, the Barnett's drilling leader. As a result, Chesapeake has let some of its mineral leases expire in northeastern Tarrant County.
Barnett Shale activity peaked when natural gas sold for $13 per million British thermal units. The price has weakened to $3.50 to $4 per million BTUs, and a sustained price of $4.50 to $5 was needed to support Barnett Shale drilling, Watson said. Should natural gas prices increase again, though, the Barnett rigs could be back, Strong said. "You just need some higher commodity prices," he said.
Consol Energy Inc. announced October 25 that it has closed on its previously announced agreement with Hess Corporation to jointly explore and develop Consol's nearly 200,000 Utica Shale acres in Ohio for aggregate consideration to Consol of approximately $594 million.
In the transaction, Hess Corporation acquired a 50% interest in nearly 200,000 Ohio Utica Shale acres owned by Consol in consideration for $594 million, of which $60 million was paid at closing. Consol and Hess Corporation have entered into a joint development agreement pursuant to which Hess Corporation will pay approximately $534 million in the form of a 1/2 drilling carry of certain Consol working interest obligations as the acreage is developed. Both the acreage and the consideration are subject to customary adjustment for revenues, expenses, and title matters. The effective date of the transaction is August 1, 2011.
C&J Energy Services, Inc. an independent provider of hydraulic fracturing, coiled tubing and pressure pumping services with a focus on complex, technically demanding well completions announced October 24 that it has signed a two-year contract with a large independent E&P company for a 32,000 hp hydraulic fracturing fleet for operations in the Permian Basin on a full month take-or-pay basis. C&J expects to take full delivery of all pumps and initially ordered ancillary equipment in November 2011 and immediately deploy Fleet 6. At the customer's request, and as contracted, C&J has ordered a complete second set of ancillary equipment for delivery in January 2012, which will enable Fleet 6 to be utilized as two independent 16,000 hp fleets for vertical completions, in addition to using the full 32,000 hp fleet to conduct horizontal work. Prior to the delivery of the additional ancillary equipment, C&J anticipates Fleet 6 will be used primarily for vertical completions.
"As a result of providing prior services, we have demonstrated our superior technical abilities and are now pleased to be entering into a long-term relationship with this top-tier E&P Company," commented Josh Comstock, Chairman and Chief Executive Officer. "Due to the expected mix of horizontal and vertical work in the Permian, we were able to contract a second set of ancillary equipment maximizing the efficiency and utilization of our horsepower by dividing Fleet 6 into two separate fleets when completing vertical wells allowing us to perform two vertical completions simultaneously. This contract strengthens our position in the Permian Basin by allowing us to expand our presence in an area that has been in our strategic sight for some time. We plan to continue to focus on basins with long-term development potential and exposure to liquid-rich formations where we can apply the expertise of our design engineers and job supervisors to provide customized solutions through extensive front-end technical analysis and planning.
C&J Energy Services, operates primarily in South Texas, West Texas/East New Mexico, East Texas/North Louisiana and Western Oklahoma.
The Blacksands Pacific Group, Inc, including affiliates and subsidiaries, announces that it has entered into a Joint Venture Agreement with Oil and Gas Technology Fund Inc (“OGTF”) for the development and production from the Torrance Field acreage located in the Los Angeles Basin, California and the exploration and development of other Prospects in Nevada.
Blacksands Pacific extends its partnership by executing an agreement with OGTF to jointly develop and produce from the Torrance Field in Los Angeles Basin, California, as well as explore and develop other prospects in Nevada. Under the terms of the Joint Venture (“Participation”) agreement with OGTF, Blacksands Pacific as Partner and Joint Operator will acquire 50 per cent of the working interest and mineral lease rights of the Torrance field acreage including existing proven reserves from OGTF currently holding 100% working interests subject to 20% royalties in the mineral rights ownership, additional to a 50% assignment of working interest and mineral rights in other Nevada Prospect. Blacksands Pacific has undertaken to fund 100% of the work program for the projects.
The Torrance Field is located in Los Angeles County, about eight miles northwest of the City of Long Beach, adjacent to the Wilmington Field. The entire acre of property is located within the City of Torrance.
The acre of property is located in a structurally high position in the western part of the Torrance Field, which is on the same anticlinal trend as the super giant Wilmington Field. Total production on this trend approaches 3 billion barrels of oil.
Production in the Torrance Field has been from the Pliocene Repetto Ranger Zone and Miocene Puente Main and Del Amo Zones. All of these are oil sands. 61 wells drilled on the property, have produced mostly from the Main Zone. Only one well penetrated the Del Amo Zone, and showed promising sands.
The property is surrounded on all sides by producing wells, including directional wells of the Del Amo unit to the east, and the Redondo unit to the west.
Consulting Geologists have identified a + 300 Million Barrels to 1 Billion Barrels resources prospect in the other Nevada Prospect.
Roanoke-based Fountain Quail Water Management LLC announced October 25 that it has developed a new portable system for treating the wastewater created during the oil and gas drilling process. Fountain Quail manufactures equipment to treat water used in the hydraulic fracturing of the Barnett Shale.
The Rover system can fit on a 30-foot by 55-foot area and runs off generator power if utility access is not available, the company said in a news release.
Fountain Quail is a subsidiary of Aqua-Pure Ventures Inc., a Canadian public company that trades under the symbol AQE on the Canadian TSX Venture Exchange.
“The mobile configuration is suitable for virtually any drilling location,” Aqua Pure Chairman Richard Mangus said in the news release.
Fountain Quail builds and operates machinery that treats wastewater in the hydraulic fracturing method of drilling a natural gas or oil well. It has worked extensively with Devon Energy Corp.
State-run gas utility GAIL India plans to buy stakes in more shale gas assets in the United States, its chairman B.C. Tripathi said on October 24 as the company reported results.
"We are looking for more assets there. We can't fix a timeline but we hope something will come out in six month," Tripathi told reporters at a press conference.
He said GAIL, which will open an office in Houston on November 1, aims to consolidate its presence in shale gas assets in the United States, and use the expertise for exploration in India.
India has pushed back plans to unveil its shale gas exploration policy to next year, Oil Minister S. Jaipal Reddy said recently.
Last month, GAIL agreed to buy a 20 percent stake in one of Carrizo Oil & Gas Inc's shales gas assets in the United States and would invest a total of $300 million over the next five years.
GAIL also on October 24 announced a 19 percent jump in its second quarter net profit to $219 million (10.94 billion Indian rupees).
GAIL, which owns India's biggest gas pipeline network of about 8,700 kilometers, aims to buy four spot liquefied natural gas cargoes in the December quarter, he said.
GAIL aims to increase its pipeline network to 10,000 kms in the current fiscal year to end-March 2012.
Tripathi said GAIL is still in talks to acquire stake in Yamal LNG project in Russian Arctic.
GAIL has stepped up liquefied natural gas imports this fiscal year to make up for a shortfall caused by falling local gas output after Reliance Industries-operated D6 block, off the country's east cost, saw volumes declining.
Tripathi said in July-September GAIL imported 4 spot LNG cargoes and it planned to buy similar volumes in each of next two quarters.
GAIL and top power producer NTPC Ltd hold majority stakes in Ratnagiri Gas and Power Pvt Ltd, which runs the country's biggest gas-based utility popularly known as Dabhol power plant in western Maharashtra state and owns an LNG terminal there.
Tripathi said GAIL would get a cargo in the third week of January to commission the 5-million-tonne-a-year terminal, which will initially run at lower capacity until a breakwater is built.
To meet its growing demand, Tripathi said GAIL will open a trading desk in Singapore on November 1.
Initially the desk will focus on sourcing LNG and not on trading," Tripathi said.
The Center for Rural Pennsylvania on October 25 released the findings of a study it conducted on the impact of Marcellus Shale drilling on drinking water supplies.
The research was sponsored by a grant from the center, which is a legislative agency of the Pennsylvania General Assembly.
The Center for Rural Pennsylvania is a bipartisan, bicameral legislative agency that serves as a resource for rural policy within the Pennsylvania General Assembly.
According to the report, this research studied the water quality in private water wells in rural Pennsylvania before and after the drilling of nearby Marcellus Shale gas wells. It also documented “both the enforcement of existing regulations and the use of voluntary measures by homeowners to protect water supplies.”
In its introduction, the authors said they evaluated water sampled from 233 water wells near Marcellus gas wells in rural regions of Pennsylvania in 2010 and 2011.
“Among these were treatment sites (water wells sampled before and after gas well drilling nearby) and control sites (water wells sampled though no well drilling occurred nearby),” the study indicated. “Phase 1 of the research focused on 48 private water wells located within about 2,500 feet of a nearby Marcellus well pad, and Phase 2 focused on an additional 185 private water wells located within about 5,000 feet of a Marcellus well pad.”
During that phase, the researchers collected both pre- and post-drilling water well samples and analyzed them for water quality at various analytical labs. During Phase 2, the researchers or homeowners collected only post-drilling water well samples, which were then analyzed.
The post-drilling analyses were compared with existing records of pre-drilling water quality, which had been previously analyzed at state-accredited labs, from these wells.
“According to the study results, approximately 40 percent of the water wells failed at least one Safe Drinking Water Act water quality standard, most frequently for coliform bacteria, turbidity and manganese, before gas well drilling occurred,” the report indicated. “This existing pollution rate and the general characteristics of the water wells, such as depth and construction, in this study were similar to past studies of private water wells in Pennsylvania.”
The study’s pre-drilling results for dissolved methane showed its occurrence in about 20 percent of water wells—although levels were generally far below any advisory levels.
“Despite an abundance of water testing, many private water well owners had difficulty identifying pre-existing water quality problems in their water supply,” the report indicted. “The lack of awareness of pre-drilling water quality problems suggests that water well owners would benefit from unbiased and consistent educational programs that explain and answer questions related to complex water test reports.”
In this study, statistical analyses of post-drilling versus pre-drilling water “did not suggest major influences from gas well drilling or hydrofracturing (fracking) on nearby water wells, when considering changes in potential pollutants that are most prominent in drilling waste fluids.”
When comparing dissolved methane concentrations in the 48 water wells that were sampled both before and after drilling, the research found no statistically significant increases in methane levels after drilling—and no significant correlation to distance from drilling.
“However, the researchers suggest that more intensive research on the occurrence and sources of methane in water wells is needed,” the report indicated.
The report then cited the Pennsylvania Oil and Gas Act of 1984, which indicates that gas well operators are “presumed responsible” for pollution of water supplies within 1,000 feet of their gas well for six months after drilling is completed if no pre-drilling water samples were collected from the private water supply.
“This has resulted in extensive industry-sponsored pre-drilling testing of most water supplies within 1,000 feet of Marcellus drilling operations,” the report states. “However, the research found a rapid drop-off in testing beyond this distance, which is driven by both the lack of presumed responsibility of the industry and also the cost of testing for homeowners.”
The authors of the study said their research suggests that a standardized list of minimum required testing parameters should be required across all pre-drilling surveys to eliminate confusion among between water supply owners and water professionals.
The study indicates that this standardized list should include bromide. The research found that bromide levels in some water wells increased after drilling and/or fracking. These increases may suggest more subtle impacts to groundwater and the need for more research.
“Bromide increases appeared to be mostly related to the drilling process,” the study indicated.
Additionally, “a small number of water wells also appeared to be affected by disturbances due to drilling as evidenced by sediment and/or metals increases that were noticeable to the water supply owner and confirmed by water testing results.”
Increased bromide and sediment concentrations in water wells were observed within 3,000 feet of Marcellus gas well sites in this study, suggesting “that a 3,000 foot distance between the location of gas wells and nearby private water wells is a more reasonable distance for both presumed responsibility and certified mail notification related to Marcellus gas well drilling than the 1,000 feet that is currently required.”
On the regulatory side, “the research found that regulations requiring certified mail notification of water supply owners, chain-of-custody water sampling protocols, and the Pennsylvania Department of Environmental Protection’s investigation of water supply complaints were generally followed, with a few exceptions.”
The study also concluded that “since voluntary stipulations were not frequently implemented by private water well owners” that more educational and financial resources should be made available to facilitate testing.
The authors were clear: “This research was limited to the study of relatively short-term changes that might occur in water wells near Marcellus gas well sites. Additional monitoring at these sites or other longer-term studies will be needed to provide a more thorough examination of potential water quality problems related to Marcellus gas well drilling.
Enbridge Energy announced it was planning a $90 million expansion to oil projects in North Dakota that would add 100,000 barrels of oil to the market.
Mark Maki, president of Enbridge Energy Partners, announced his company was working on expanding the gathering capacity of its Bakken program in North Dakota by 100,000 barrels per day.
Maki said this project builds on earlier success stories. Production forecasts for the region, he added, have recently doubled.
The U.S. Geological Survey announced it would review its 2008 estimate of undiscovered, technically recoverable oil and natural gas in the Bakken formation.
The USGS in 2008 estimated there were 3 billion to 4.3 billion barrels of oil in the U.S. part of the formation, making it larger than all other oil assessments in the Lower 48 and the largest continuous oil accumulation ever assessed by the federal government.
The 2008 estimate was 25 times greater than the 1991 estimate. New geological models, drilling and discoveries yielded greater reserve predictions for the formation.
The USGS began an updated Bakken assessment in October.
Fluor Corporation announced October 6 that it was awarded a contract by North West Redwater Partnership to provide front-end engineering and design (FEED) services for a new refinery project in Alberta, Canada. Fluor booked the undisclosed contract value in the third quarter of 2011.
Under the contract, Fluor will be responsible for two sections of the refinery that will upgrade bitumen, separating components and removing impurities, and will also re-evaluate the FEED deliverables based on a revised crude slate.
"The Redwater bitumen refinery will feature state-of-the-art controls to minimize its environmental footprint while providing much needed additional energy resources for North America," said Peter Oosterveer, president of Fluor's Energy & Chemicals Group. "Fluor looks forward to providing FEED services to the North West Redwater Partnership as the important Canadian energy sector continues to expand."
The North West Redwater Partnership is a joint venture between North West Upgrading, Inc. and Canadian Natural Resources Limited.
The Redwater refinery, which will be located north of Edmonton, will use oil sands bitumen to produce diesel, diluent, naphtha and other related products. The refinery will incorporate gasification and carbon capture and storage to reduce its environmental impact.
The engineering project will be executed by Fluor's offices in Calgary, Houston and New Delhi.
Jacobs Engineering Group Inc. (JEC) said it was awarded contracts from seven clients in the Alberta oil sands with a combined value of more than $1.4 billion, expanding its presence in the key energy producing region.
The engineering and construction company said the construction values on the projects range from $15 million to more than $650 million, but didn't disclose further financial details.
Though the company doesn't break out the Alberta operations in its financial reports, Jacobs Group Vice President Chip Mitchell said the Alberta oil sands are a very important component of the business.
Jacobs also said its marine environmental services contract was extended with Horizon Nuclear Power Ltd., a joint venture between E.ON AG and RWE AG, to support the company's new development in the U.K., though terms weren't disclosed.
Jacobs has seen its backlog improved recently and in July President and Chief Executive Craig L. Martin said the company's outlook remained positive as he also noted its solid prospect list and strong fiscal third-quarter performance.
The company in July reported that fiscal third-quarter earnings soared absent a prior-year charge and as revenue rose 9.4%.
Junior oil company Oilsands Quest Inc. has agreed to sell its Wallace Creek property in Alberta for up to $60 million to an unnamed buyer.
Calgary-based Oilsands Quest said it will be paid $40 million cash at closing and an addition $20 million, "subject to certain future events," which the company did not outline.
Proceeds of the sale will be used to develop to move its Axe Lake property in Saskatchewan toward commercial development.
"It will provide us much of the capital we need to complete the Axe Lake pilot and prove the commercial recoverability of our highest priority core asset," CEO Garth Wong said in a statement.
"While Wallace Creek has shown considerable potential, it is not yet as well delineated as Axe Lake and is therefore considerably further away from commercial development."
The sale is expected to close by the end of December.
China Petrochemical Corp. (Sinopec Group), the nation's biggest refiner, agreed to buy Daylight Energy Ltd. for $2.1 billion (C$2.2 billion) in cash, gaining Canadian oil and shale-gas reserves in its largest acquisition this year.
The state-owned company offered C$10.08 a share, Calgary-based Daylight said in a statement October 9. That's 70 percent higher than Daylight's average price during the past 20 trading days and more than double the average 32 percent premium for comparable cash bids for North American energy explorers, data compiled by Bloomberg show.
The takeover would give the Beijing-based company access to more than 300,000 acres of land in areas rich with oil and natural gas, adding to its expansion outside Asia after falling crude prices made valuations attractive. Sinopec Group and Cnooc Ltd. are among Chinese companies that have bought almost $30 billion of Canadian assets in the past five years to meet energy demand in the world's fastest-growing major economy and gain access to drilling methods to help unlock Asian resources.
“Sinopec made a number of oil-sands acquisitions, and this is probably the most gas they've acquired in western Canada,” Neil Beveridge, a Hong Kong-based analyst at Sanford C. Bernstein & Co., said in October.
The oil and gas industry accounts for the second-biggest volume of mergers worldwide this year after telecommunications, with $127 billion in transactions, Bloomberg data show.
Two other energy deals were announced October 10. Superior Energy Services Inc., a U.S.-based oilfield services provider, will pay $2.6 billion in cash and stock for Complete Production Services Inc. In Australia, Everyday Mining Services Ltd. said it will merge with Hughes Drilling Pty Ltd.
Daylight's proven and probable reserves rose 46 percent to the equivalent of 174 million barrels of oil at the end of 2010, the company said March 1. Beveridge values Daylight's reserves at $16.70 per barrel of oil equivalent, saying Sinopec Group is paying a “fair price” for those assets.
Sinopec Group will join rival China National Petroleum Corp. and Cnooc in seeking technology through partnerships as China, estimated to hold more gas trapped in shale rock than the U.S., opens new areas to exploration. The world's biggest energy user, which currently doesn't produce any shale gas commercially, has brought in foreign partners including Exxon Mobil Corp., Royal Dutch Shell Plc and Chevron Corp. to assess its potential.
China has an estimated 1,275 trillion cubic feet of technically recoverable shale gas, more than the estimated reserves in the United States and Canada combined, according to an April report by the U.S. Energy Information Administration.
The U.S. and Canada produced 26.2 trillion cubic feet of gas in 2009 compared with 2.9 trillion cubic feet in China, according to EIA data.
China Petroleum & Chemical Corp., Sinopec Group's Hong Kong-listed unit, fell 4.4 percent to close at HK$7.16. Daylight closed at C$4.59 on Oct. 7 in Toronto. The company's shares have declined 56 percent this year. Canadian markets were closed today because of a national holiday.
Collaboration with overseas companies will help boost the search for shale-gas resources, and “future growth will mainly come from unconventional gas,” Chairman Fu Chengyu said August 30. China Petroleum finished drilling its first shale-gas well in Hubei province July 15, Sinopec Group said July 26.
The company will increase its investments in Canada as part of its global expansion, Sinopec Group said in an e-mailed statement.
Asian buyers may spend $150 billion by 2016 to secure energy resources for their faster-growing economies, according to Sanford C. Bernstein Co. Targets may include Tullow Oil Plc, Canadian Oil Sands Ltd. and Kosmos Energy Ltd., the research firm said.
Sinopec paid $4.65 billion last year to buy a stake in Syncrude Canada Ltd., while Cnooc on July 20 announced it would spend $2.1 billion to acquire Opti Canada Inc.
PetroChina Co. walked away from a $5.25 billion (C$5.4 billion) joint operating agreement with Encana Corp. in June that would have given the Chinese company a 50 percent stake in about 1 trillion cubic feet of Canadian natural gas.
More foreign investment in Canada's resources may involve some risk, such as when the Canadian government blocked BHP Billiton Ltd.'s $40 billion hostile bid for Potash Corp. of Saskatchewan Inc., Phil Flynn, vice president of research at PFGBest in Chicago, said October 10.
Canadian Prime Minister Stephen Harper said last month the nation will “proceed with caution” as it considers opening its doors to more foreign takeovers, making sure they don't lead to a loss of head-office jobs.
Canadian regulators probably won't have issues approving the Daylight takeover, said Robert Mark, an analyst at MacDougall, MacDougall & MacTier Inc. in Toronto.
“This stock has been in free fall for the past few weeks, so shareholders should be firmly behind this bid, which is very good value considering the company's debt and the market uncertainty,” Mark said in an e-mail.
More investment in Canada by international companies such as Cnooc or India's Reliance Industries Ltd. may be imminent due to the relatively low prices of energy stocks, Michael Tims, chairman of investment bank Peters & Co. Ltd. in Calgary, said by telephone.
Spectra Energy Corp on October 19 announced the execution of multi-year agreements between Spectra Energy and Progress Energy Resources Corp. ("Progress") to provide a total 370 MMcf/d of natural gas gathering and processing services to support the development of Montney production in Progress' core development area in northeast British Columbia. The agreements provide for 210 MMcf/d of new service, in addition to the renewal of current contracts, which allows Spectra Energy to continue to provide natural gas gathering and processing to much of Progress' incremental production in the area.
Spectra Energy is the leading provider of natural gas gathering and processing services in the expanding Montney shale play through more than 2,200 kilometers of gathering pipeline and interests in ten processing plants with over 1.5 Bcf/d of gas processing capacity. These gathering and processing services will be provided to Progress at Spectra Energy's Highway, Jedney and McMahon facilities, and, through reactivation of the Aitken Creek Gas Plant.
"We have a strong track record with over 54 years experience in northeast British Columbia in providing our customers with safe, reliable and competitive services," says Doug Bloom, president, Spectra Energy Transmission West. "Our depth and breadth of services in the region position us as a strategic partner in supporting Progress' success in the development of this major unconventional resource play."
The Montney play in northeast British Columbia and northwest Alberta, is estimated to contain approximately 450 Tcf of original gas in place. With over 850 employees across British Columbia, Spectra Energy is well positioned to continue leveraging existing assets and in developing new infrastructure to facilitate supply growth with timely, cost-effective infrastructure solutions for its customers.
Aecon Group Inc. said October 20 it won two fabrication and module assembly contracts worth $132 million at an unspecified oilsands project near Fort McMurray, Alta.
The first of the contracts involves the company fabricating pipe spools and assembling 90 wellpad modules. The second project involves Aecon handling all the off-module fabrication for the project's plant facility.
Fabrication work will take place at Aecon's Sherwood Park facilities in Alberta as well as other undetermined facilities that could include Cambridge, Ont., Brantford, Ont., as well as Dartmouth and Pictou, N.S.
Work will begin next month and extend into the fall of 2013, the company said.
"Aecon's substantial fabrication capacity, including our ability to efficiently utilize a number of facilities across the country, is a significant advantage when undertaking projects like this," said Aecon chief operating officer Teri McKibbon in a release.
"This is a major project in the oilsands, and we are pleased to undertake this work."
Argentina is sitting on top of the third-largest shale gas resources in the world after China and the United States, enough that some energy executives are bullish about the possibilities of exporting surplus output. And so, after eight years of energy shortages, Argentina is poised to turn things around, potentially within the next five years.
The government is starting to promote development with the aim of reversing a shrinking trade surplus as it becomes harder to maintain the exchange rate and social housing and welfare programs that have made Cristina Fernandez de Kirchner one of the most popular presidents in recent times, and propelled her to recent reelection.
The numbers appear to be promising. As the U.S. Energy Information Administration said last April, the country has 774 trillion cubic feet of shale gas resources, those that are technically recoverable. That is far greater than its 13.4 Tcf of proved gas reserves, an amount that has been reduced 50% from 2000 due to limited exploration and aging fields.
Big oil companies like Chevron, ExxonMobil, Petrobras and Total are starting to pour millions of dollars into drilling wells to uncover the potential. Spending is estimated to reach more than $1 billion over the next few years.
"We can replicate what is happening in the United States," said Tomas Garcia Blanco, executive director of exploration and production at YPF, the country's leading oil producer, told MNI on the sidelines of a the Argentina Oil & Gas Expo held recently in Buenos Aires.
The United States is thought to be on track to reduce its reliance on foreign gas by developing its shale formations, even to export supplies as liquefied natural gas.
The same -- or better could hold true for Argentina.
"We are finding a shale in Argentina that has characteristics very superior to what is in production in the U.S.," Garcia Blanco said.
YPF, backed by Spain's Repsol, already has found 4.5 Tcf of shale gas and more than 150 million barrels of shale oil resources within small regions of Neuquen, a southwestern province now at the heart of the hunt for unconventional hydrocarbons and big profits.
This would help rebuild fossil fuel production, which meets 80% of national energy demands, reversing the trend in recent years.
Oil output has dwindled by a third and gas by 13% over the past decade, causing a pullback in energy exports followed by a rise in imports. Argentina is one of the world's fastest growing importers of LNG, bringing in supplies to feed an economy growing by an average of 8% a year since emerging from a 2001-2002 crisis.
The energy deficit is expected to reach $3 billion this year for the first time in 20 years, evaporating a surplus that only five years ago was $6 billion. The deficit could reach $5 billion in 2012, according to private estimates.
This situation has caused the overall trade surplus to narrow to an expected $8.3 billion this year from $11.6 billion in 2010.
And rising energy imports has led to tightening trade barriers, with the government promoting the substitution of imports.
CFK, who has confessed to being "obsessed" with producing all if not most of what the country needs within its borders, has ordered carmakers to export the same value of their imports. Germany's BMW, for example, has responded by exporting auto parts, leather and rice so it can gain authorization to import its high-end vehicles.
The government thinks its shale prospects could change all this.
"In the short and medium term we will return to a complete balance" in energy trade by developing the shale resources and expanding refining capacity, Energy Secretary Daniel Cameron said. "The future is very hopeful."
The question, however, is whether the conditions are in place to develop the resources and build the infrastructure to feed them to the local market and cut imports.
"The resources are there," said Ernesto Lopez Anandon, president of the Argentine Oil and Gas Institute, told MNI. "You have to make it attractive for investment."
With ideal conditions, the widespread development of shale could take three to four years, he said.
Yet there needs to be a price to warrant the spending not only in drilling but in building the infrastructure -- pipelines, processing plants and distribution networks -- to handle the added supplies, he cautioned.
The government has kept controls on gas, oil and refined product prices since after the 2002, crimping profits for the energy sector. This led to an exodus of foreign companies and a pullback in spending, sparking the decline in production and rise in imports.
The government has allowed prices to rise for industrial users, which for gas are paying $4-7 per million British thermal units. Yet residential consumers pay only $0.50/MMBtu, among the cheapest in the world.
With inflation running at an annual 20%, it could prove hard for the government to raise prices on consumers, which burn about a third of the gas production. But in her second term CFK also might start to reverse some policies, like subsidies and price caps, that have left her with difficult fiscal decisions.
Michael Bose, president and country manager of Apache Argentina, said his company will continue to increase spending in Argentina as long as conditions are right.
While he declined to name a price, industry experts say the minimum for shale gas needs to be $6-7/MMBtu. At that, the shale gas would be competitive against imported gas, which costs $10-16/MMBtu.
The question, said Bose, is whether the government will allow a higher price.
Guillermo Giussi, an economist at Economia y Regiones in Buenos Aires, told MNI recently that he expects the government to cut energy and transportation subsidies, which he estimates total $15-20 billion a year, or three-times more than the $6.3 billion in debt payments the government must cover next year.
A reduction will free up funds for other uses, reducing the strain on the central bank to print pesos and the impact on inflation and the exchange rate, he said.
While cutting subsidies also will push up inflation, this could be offset by reducing the pace of monetary expansion, he added.
One indication the government is preparing to reduce subsidies was a move this year to scale back controls on diesel and gasoline prices, which have since gone up 30%.
The only way to meet a tripling in natural gas demand in eastern Australia is by allowing unconventional gas projects, including CSG, Santos says.
The oil and gas company's eastern Australia vice president James Baulderstone told a conference that he expected gas prices to more than double within two decades, driven by demand and linking it to oil prices.
Soaring global demand for liquefied natural gas is expected to contribute to Australia's wealth and make it one of the world's biggest exporters of the commodity.
However the use of fracking to access coal seam gas (CSG) or shale gas is strongly opposed by many Australians and Americans, including farmers, who say it contaminates prime agricultural land.
Santos insists that is false and gas is a safe, low-carbon alternative to coal for providing energy, with eastern Australia potentially having enough gas to supply it for a century.
"The five LNG trains already sanctioned, with more planned, represent a quantum change in eastern Australian natural gas demand,'' Mr Baulderstone told the Opportunities and Challenges for Australian Gas conference on October 31.
"Provided natural gas development activity is allowed to proceed at the right pace, and the market is willing to pay the increased cost of extraction, there is sufficient gas in Eastern Australia to meet this demand.''
But he added that it was not viable to develop much of the gas reserves to meet the new demand at current Australian gas prices of about $4 a gigajoule.
Australian gas prices were some of the cheapest in the developed world, Mr Baulderstone said.
"Comparatively modest price increases driven by this anticipated stronger demand will make the development of extensive additional resources economic for the first time.''
Domestic users would be able to absorb such increases as gas prices had been flat for a decade and a rise was long overdue, he said.
He predicted prices would move to $6 to $9 a gigajoule.
"Industrial customers like Rio Tinto, BHP and Xstrata have benefited greatly over the past decade from basically flat east coast Australian gas prices while their commodity prices (iron ore, copper, silver, coal) have increased in some instances nearly ten fold during the same period,'' Mr Baulderstone said.
Santos is heavily invested in CSG through the US$16 billion (A$15 billion) Gladstone Liquefied Natural Gas (GLNG) project it is leading and is also developing shale gas projects in the Cooper Basin in central Australia.
It is also close to finalizing a $924 million bid for NSW-based Eastern Star Gas, which controls NSW's largest CSG resource.
"Even if the development of Santos' CSG business in NSW was a third of the size of our Queensland project, $2 billion would be added to NSW state revenues and over 1,000 direct jobs would be created,'' he said.
The much awaited spudding of the MacIntyre-2 well oil shale project is underway in the Southern Georgina Basin. Momentum is building as Petrofrontier Corp moves closer toward 500 meters of horizontal drilling into the Shale. Baraka Energy & Resources has reported that joint venture partner Petrofrontier Corp. has spudded the MacIntyre-2 well in the Northern Territory.
PetroFrontier is believed to be the first company to introduce open hole horizontal and multi-stage fracing technologies to unlock unconventional oil potential in Australia.
The drilling of EP127 well has been highly anticipated by investors as well as Baraka, as the company has a 25% undivided working interest.
The objective is to drill the well to 500 meters horizontally into the shale and “hot shale” Basel Arthur Creek Shale, which commences at a depth of approximately 770 meters vertical depth.
Petrofrontier then intends to frac and complete the well using multi-stage open hole techniques.
Baraka also retains an undivided 75% working interest in about 75 square kilometers around the Elkedra-7 well on EP127, where previous drilling has indicated oil shows that could lead to a discovery.
Petrofrontier has also recently completed a well at Baldwin-2 in the Georgina Basin on EP103 only 60 kilometers away.
When final results are released from MacIntyre-2, the completions crew will subsequently return to Baldwin-2 to conduct a similar program there.
It has always been PetroFrontier's strategy to frac MacIntyre-2 and Baldwin-2 back to back in order maximize cost controls.
PetroFrontier intends to use Schlumberger, the Australian representatives of Packers Plus, to run the multistage open hole completion string and conduct the fracture stimulation program.
These technologies have been widely successful in unlocking North American unconventional oil reservoirs such as the Bakken formation, and Baraka and PetroFrontier expect them to assist in establishing commercial production.
Consultants Ryder Scott Company Petroleum have written a report entitled Evaluation of the Hydrocarbon Resource Potential Pertaining to Certain Acreage Interests in the Southern Georgina Basin.
Ryder Scott Petroleum Consultants evaluated Baraka’s concessions in the Georgina Basin and estimated the lands to hold a prospective resource potential of 76.65 billion barrels of oil (unrisked, P50 estimate).
Ryder Scott estimated The Arthur Creek “Hot Shale” potential resource at 7.53 billion barrels and is the primary focus for PetroFrontier and Baraka.
Meanwhile, Baraka has also announced that its application to list on the Frankfurt Exchange (FSE) has been approved and is now trading under the code.
Baraka said that having initially assessed the benefits that could flow to the company and shareholders from a greater exposure to large cash rich Fund Managers and Institutions in Europe, the company carried out serious dialogue and costing to analyze the cost-reward benefits of the listing.
The company believes that it would appeal to the European investors because of the strength of the Australian currency, and the potential success of Baraka’s oil shale project in the Northern Territory, as well as its cash reserves, nil liabilities, strong management and possible acquisition/joint venture of other assets.
Baraka intends to commence a marketing and promotional program throughout Europe to educate the European investors on Baraka’s financial position and project potential, possibly with a follow up road show to selected interested Institutions either this year or in the New Year.
China targets annual shale gas production of 6.5 billion cubic meters by 2015 and 80 billion by 2020 under a government plan to be released soon, reports the China Securities Journal.
China has yet to produce shale gas commercially but aims to triple the use of natural gas to about 10 percent of energy demand by 2020 to cut emissions from coal and oil fired generation.
The country has 36 trillion cubic meters of shale gas, 48 per cent more than the U.S., according to a report by the U.S.’s Energy Information Administration.
Song Xiaodan, a deputy chief economist in the planning department of China National Petroleum Corp (CNPC), was given as a source for the upcoming National Energy Administration plan by the newspaper.
China, estimated to hold more natural gas trapped in shale than the U.S., will offer subsidies and auction new exploration blocks this year to encourage domestic companies to tap the resource.
“The government places high emphasis on developing shale gas and has been actively studying supporting policies,” Zhang Dawei, deputy head of the Strategic Research Center at the Ministry of Land and Resources, said in Shanghai today. A national shale gas plan will be announced soon, he said.
More than 10 shale gas blocks will be offered to Chinese state and private companies in the second round of auctions, Zhang said at a conference. While overseas companies will be barred from the sale to be held this quarter, they can invest in and supply technology to domestic operators, he said.
Cnooc Ltd. and China Petrochemical Corp. are seeking technology through overseas acquisitions. PetroChina Co.’s parent agreed in June to form a venture with Royal Dutch Shell Plc to improve its drilling efficiency after taking 11 months to complete China’s first shale well. China, yet to produce any shale gas commercially, plans 6.5 billion cubic meters of annual output by 2015 and 80 billion cubic meters by 2020, Zhang said.
The subsidy for shale gas will be higher than the 0.2 yuan (3 cents) per cubic meter provided for coal-bed methane, because gas is harder to extract from shale rock, the official said.
Chinese shale may hold 1,275 trillion cubic feet (36 trillion cubic meters of gas), or 12 times the country’s conventional natural gas deposits, the U.S. Energy Information Administration said in April. China’s “technically recoverable” reserves are almost 50 percent more than the 862 trillion cubic feet held by the U.S., the EIA said.
China estimated in 2010 that it had about 31 trillion cubic meters exploitable shale gas reserves, and the figure will be updated by the end of this year as the government has done nationwide onshore appraisal, Zhang said October 20.
Shale gas production in China is expected to increase to about 15 percent of domestic output by 2040, compared with 50 percent by 2030 in the U.S., Steven W. Lewis, a professor at the Baker Institute at Rice University, said at the conference. In Canada, shale may account for a third of overall gas production by mid 2030s, he said.
Sinopec Group, agreed this month to buy Daylight Energy Ltd. for about C$2.2 billion ($2.2 billion) to gain Canadian shale-gas reserves in the company’s largest acquisition this year.
Cnooc agreed in February to buy a 33.3 percent stake in Chesapeake Energy Corp.’s Niobrara shale project in Colorado and Wyoming for $570 million, after paying $1.08 billion last year for one-third of a Chesapeake shale venture in Texas.
In June, PetroChina walked away from a C$5.4 billion bid for Encana Corp.’s Cutbank Ridge gas assets after failing to agree on the price. The acquisition would have been its largest overseas deal.
China Petroleum & Chemical Corp., the listed arm of Sinopec Group, and Henan Provincial Coal Seam Gas Development and Utilization Co. won exploration rights in China’s first auction of shale-gas blocks, the land ministry said in July.
Chevron Corp., BP Plc and Statoil ASA are among international explorers that have entered talks to form joint ventures in China to tap shale gas assets.
China plans to triple the use of natural gas to about 10 percent of energy demand by 2020 to rely less on more polluting coal and oil.
Britain, Estonia and other Eastern European countries joined Canada in its determined opposition to an EU proposal to label tar sands as more highly polluting than other forms of oil, EU sources said on October 25.
"There is some divergence within the EU," one source said. "But the Commission position there is strong backing for this proposal." A meeting of European environment experts on October 25 had at first been expected to vote on a proposed ranking of fuels designed to flag for suppliers the most carbon-intensive options.
Instead, there was only debate and no vote. A vote was now expected to take place in early December, an EU source said.
Several states requested a postponement on the grounds a draft document had only been circulated recently, another source said.
EU member Estonia, which has carbon-intensive oil shale, together with other Eastern Europe states, took an industry perspective that the new ranking would just be an administrative burden, a third source said.
One of Canada's allies in the European Union, Britain was also seeking to modify the EU proposal that tar sands should be ascribed a default greenhouse gas value of 107 grams of carbon per megajoule, source said.
The level would make it clear to buyers it had a greater climate impact that conventional crude oil, whose value is 87.5 grams.
The green fuel ranking also proposes a default value of 131.3 grams per megajoule for shale oil.
In an email seen by Reuters, a British representative said Britain was seeking a compromise that would not "single out oil sand or oil shale.” It said oil sands made "an important contribution to global energy security" and were "a priority for Canada's EU diplomacy." The email also suggested a methodology that would require "a mechanism to track crude from source to supplier." Some analysts said that was a delaying tactic.
European oil companies active in Canada include BP, Total and Royal Dutch Shell
Canada has yet to export crude derived from oil sands to Europe, but government and industry officials worry branding it as much more carbon-intensive than other fuels could set a costly precedent for current or future markets.
The European Commission approved a proposal to include tar sands in the ranking, designed to enable fuel suppliers to identify the most carbon-intensive options, on October 4. That was only one step in the lengthy EU process and it unleashed frantic lobbying.
Canadian Natural Resources Minister Joe Oliver has suggested Ottawa could take the EU to the World Trade Organization if the Europeans adopt the fuel directive. Recently he travelled to Europe to press Canada's case and in an interview with Reuters on October 21 in London said the EU's plans were discriminatory. If agreed, the ranking would complete legislation introduced in 2008, when the EU agreed to reduce the carbon intensity of its transport fuels by 6 percent by 2020 as part of wider goals to cut carbon emissions by 20 percent by 2020.
The 2008 fuel quality directive assigns greenhouse gas emissions values for a range of transport fuels, most of which were dealt with by the end of last year. But a decision on whether to include the tar sands was delayed after Canada said the EU's standards to promote greener fuels would harm the market for its oil sands. Environment groups and scientists have backed the EU stance.
A study by Adam Brandt at Stanford University, California, found there was some uncertainty, but greenhouse gas emissions from oil sands production were "significantly different enough from conventional oil emissions that regulatory frameworks should address this discrepancy."
"The science shows clearly that tar sands are more carbon intensive than other crudes, and that means that any talk of trade discrimination is simply scare-mongering," said Nusa Urbancic, fuels campaigner at green transport lobby group T&E.
In letter seen by Reuters on October 21 the European Commission's Legal Service said the EU proposals could probably be defended if Canada were to take its case to the WTO.
Polish state-controlled oil refiner PKN Orlen SA (PKN.WA) plans to drill six shale gas test wells through 2013 at a cost of $158 million (500 million zlotys) as it looks to build up its upstream operations, a company official told reporters October 24.
Four of the wells will be drilled in 2012, Wieslaw Prugar, Chief Executive of Orlen Upstream, said in Syczyn, eastern Poland, where the company presented its first test well.
Central Europe's largest firm by annual revenue, PKN Orlen owns refineries and filling stations in Poland, the Czech Republic, Germany and Lithuania. It processes mainly Russian crude oil and has for years been planning to reduce that reliance by extracting oil on its own, mostly abroad.
The advent of the shale gas industry in Poland--which has shale gas reserves that could provide for 300 years of consumption, according to U.S. estimates--prompted PKN Orlen to add gas to its upstream plans. This may facilitate asset swaps with firms that have hydrocarbon deposits around the world and may want to enter the Polish shale gas market.
PKN Orlen said earlier this year it was working on an asset swap deal with a North American partner. PKN Orlen's Chief Executive Jacek Krawiec said on October 24 that negotiations continue. Prugar said the deal is "essentially sealed," but he declined to name the partner or say when the agreement would be announced.
Earlier in September, a spokesman for Canada's Encana Corp. (ECA) said the company was in talks with PKN Orlen on a possible deal on shale gas exploration and production, but that no agreement had been reached.
Prugar also said the exploration phase for shale gas at PKN Orlen may "easily" cost a total of PLN1 billion over an unspecified period of time.
Czech firm MND Drilling and Services will drill the first shale gas well for PKN Orlen. At the end of November, after drilling finishes in Syczyn, the team and the drilling equipment will move to a second license in the area.
The Syczyn well is about three kilometers meters deep.
Analysis of drilling and test data from 14 wells drilled since the 1950s has indicated the presence of a world class shale gas play in the Basque Country of northern Spain.
Of 14 wells that penetrated the Cretaceous shale, 10 tested gas and only three penetrated the entire section.
A group led by the Basque National Oil Company will drill its first two appraisal wells in 2012. The 14 earlier penetrations collectively led to an independently estimated midrange resource of about 200 tcf of free gas and adsorbed gas in place.
The Basque Country’s Soc. de Hidrocarburos de Euskadi SA (Shesa) has 44% interest in four blocks 180 miles north of Madrid. Private independents HEYCO Energy Group, Dallas, and Cambria Europe Inc., Casper, Wyo., a True Oil affiliate, have 36% and 20%, respectively.
The firms are talking with other companies about participating in the appraisal program.
Spain, with five liquefied natural gas terminals, is the world’s third largest importer of LNG.
Basque officials, including the country president, toured Barnett shale field sites in the Fort Worth basin earlier this month and visited with Texas regulatory representatives to learn about the operation and regulation of unconventional plays. They have dubbed the Basque Country play as Gran Enara.
The two vertical appraisal wells will go to 15,000-17,000 ft, and as much as two thirds of each wellbore will penetrate the objective formation, said George Yates, president, Heyco Energy.
The over-pressured Cretaceous Valmaseda formation is about 60% shale inter-bedded with 40% tight sands and should be easy to frac, Yates said. The two appraisal wells will be tested into gas pipelines.
The Valmaseda formation has neither been horizontally drilled nor hydraulically fractured, Yates said.
Drilling in Spain averages five wells per year. Rigs capable of drilling the appraisal wells are available in Europe and North Africa. Halliburton and Schlumberger have frac kits elsewhere in Europe capable of the services the group needs in Spain, he said.
The prospective Valmaseda underlies as much as 50-60% of the 700,000 acres covered by the four blocks. The gas is almost pure methane with no liquids and no impurities, Yates said.
The group’s four blocks lie east and northeast of the 150,000-acre Urraca concession held by BNK Petroleum Inc. subsidiary Trofagas Hidrocarburos SL that primarily targets a slightly shallower shale of Jurassic age farther west in the Cantabrian basin.
Realm Energy International Corp., Vancouver, BC, soon to merge with San Leon Energy PLC, has been awarded two shale permits in the basin. Several other concessions are in force in the general area, and still more are pending.
Natural gas prices in Spain are in the neighborhood of $8/Mcf.
The 13 wells on the Shesa group’s acreage are “separated enough to give us an idea of the lateral consistency of this reservoir,” Yates said.
Only a few of the 14 wells were drilled with the Valmaseda sands, and several early wells targeted what the operators thought would be the Ultrillas as primary or secondary targets. None was drilled with the shale as a target.
Of the 10 wells that flowed gas on tests, DSTs averaged less than 1 MMcfd. Seven DSTs exceeded 1 MMcfd, and one test rate reached 9.9 MMcfd. Final shut-in pressure was much lower than initial shut-in pressure, indicating low matrix permeability.
Three of the wells were completed, and two of them were probably commercial, Yates said. Cumulative production is 1.03 bcf at one, Castillo-2, despite a mechanical problem. Another hit a fracture 160 m into the Valmaceda while drilling under-balanced and flowed at an observed rate estimated at 30 MMcfd before being brought under control. It produced 560 MMcf and was abandoned at fairly high pressures, Yates said.
If the play works, it will result in substantial development, employment, and economic advantage to the Basque region.
Huge reserves of a controversial natural resource linked to a possible economic boom in neighboring Lancashire could be located underneath Yorkshire and the Humber.
Chief executive Hugh Mackay told Insider Europa was adopting a "watching brief" to assess the government's appetite for shale gas and how best to exploit the company's license for a giant Humber Basin field.
Europa jointly owns a license with Egdon Resources for a 600 sq km Humber Basin reserve, stretching from Grimsby to north of Scunthorpe, which it holds primarily for its conventional (oil and gas) hydrocarbon potential.
However, the company has noted the basin shares the same geology as the Cuadrilla reserve in Lancashire where the presence of up to 200 trillion cubic feet of shale gas has been identified.
Drilling for the Cuadrilla reserve has been linked to the creation of more than 1,500 jobs and a £6bn economic boom.
"At the moment, it's fair to say, we're just watching what Cuadrilla Resources are doing in Blackpool," said Mackay.
"We're aware it's quite controversial and we are going to watch and see how things develop."
That controversy relates to the "fracking" extraction process which the British Geological Survey (BGS) recently concluded caused earthquake tremors in Lancashire when used by Cuadrilla.
"It's something for the British government and people to decide if they are interested in obtaining gas from shale gas then the license in the Humber area is potentially well located for it," said Mackay.
"The techniques for developing shale gas are quite specific," he added.
"We may want to develop them ourselves, we might wish to consider bringing in a joint venture partner or we might wish to consider selling. At this moment we'd want to keep all options open."
Mackay said the company was aware how "emotive" the extraction of shale gas could be, highlighting that a presidential decree had outlawed the practice in France.
However, he also highlighted the impact shale gas has had on the energy market in the U.S. where use of the resource has risen from 1 per cent of domestic supply to 20 per cent and, he claimed, been credited with both lower natural gas prices and declining dependence on imported natural gas.
Jordanian officials hope the construction of the country's first oil shale power plant would be the key solution to its chronic shortage of energy resources and dependence on influential neighbors for oil and gas.
The government has recently approved a deal wit an Estonian company, Eesti Energia and further talks are expected to conclude the deal before the year end in order to pave the way for the start of the multi-billion dollar project. A deal is expected to be rubber stamped ahead of the planned start of the project as early as 2012, according to Andres Anijalg, project director at Enefit's Jordan Oil Shale program. The plant could help provide the kingdom with electricity from the southern part and also produce amounts of oil for the local market.
Jordan is one of the poorest countries in the region in terms of oil and energy resources, with most of its needs imported from neighboring countries. Saudi Arabia pumps most of the country's fuel needs at a lower price compared to the international market while Egypt pumps gas from the Sinai desert.
Officials have been concerned that the cash-strapped kingdom remains hostage to political relation with the giant neighbors and hope to find a mean of producing energy from local resources. The deal with the Estonian company, as well as an ambitious project to build a peaceful nuclear reactor, could put the kingdom on the right path for energy independence, but not until a decade from now, according to experts.
The revelation of the agreement came during an international conference on energy deficit and challenges facing countries, oil shale, renewable energy and natural gas. The conference is being held in Jordan with participation of dozens of experts from around the world. Goal of the agreement between the government and the Estonian company is to have a power plant able to extract nearly 40,000 barrels of oil per day by 2019. The plant is also expected to generate electricity for industrial and household usage, say experts.
Experts however are concerned with the environmental impact of oil shale as they call for legislations to protect the environment. Jordan Environment Society (JES) Executive Director Ahmad Kofahi warned of grave consequences on the areas where the plant would be constructed as well as the animals and plantations. "We need to have a comprehensive study for the environmental impact such a plant would have. The study should also look into what effects it would have on people concerning their health," he told ANSAmed.
Environmentalists say developing countries could be jumping to such projects without taking into consideration the hazards such projects could have on the eco-system and the populations living within close proximity of them. Jordan said it will look into adopting legislations to guarantee implementation of international standards when operating oil shale power plants.
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