“The transaction reduces Statoil’s non-operated holdings at an attractive price, demonstrating the value of the Marcellus assets” said Torstein Hole, Statoil senior vice president and US onshore head.

“Our new partnership with Southwestern Energy provides us with an opportunity to maximise the value of an important growth asset in our US onshore portfolio. Southwestern is a very dynamic operator that will maximise the value and return.”

The transaction covers 515,000 acres in the southern part of the Marcellus, in which Statoil today holds an average working interest of 29%.

The divested share of the Southern Marcellus represents approximately 30,000 acres. Statoil’s 2014 third quarter production from the Marcellus play amounted to 130,500 barrels of oil equivalent per day, of which approximately 4,000 barrels came from the assets included in the transaction.

Southwestern is an experienced operator in the development and production of US onshore unconventionals. It announced the acquisition of Chesapeake Energy’s holdings in the Southern Marcellus asset on 16 October 2014.

Statoil have agreed to give Chesapeake consent for their transaction with Southwestern. Statoil and Southwestern have now agreed to the partial sell-down of Statoil’s interest at an equivalent price to that agreed between Chesapeake and Southwestern.

Statoil and Southwestern have put in place a new joint development agreement. Following the transaction, Statoil will hold around 23% of the underlying non-operated Southern Marcellus assets. The transaction is expected to close in Q1 2015.

"I am delighted that we have concluded this important transaction with Southwestern despite the turbulence in today's energy markets," said John Knight, executive vice president for Global Strategy and Business Development at Statoil.

The transaction confirms the attractiveness of US unconventionals and the significant value created in developing the assets.

Statoil has established a strong acreage foothold in US unconventionals since entering the Marcellus in a joint venture with Chesapeake in 2008.

After initial entry into the Marcellus in 2008, Statoil entered into the Eagle Ford in 2010, acquired Brigham Exploration in Bakken in 2011 and the Marcellus-operated acreage acquisition in 2012.

Since 2011, Statoil have been transitioning from a non-operator to an established unconventional operator and today its portfolio includes operated positions in each of these assets.

• Statoil optimises portfolio – realising USD 394 million from Marcellus asset

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The Gee and Neal discovery wells extend the sweet spot of the Utica formation beyond Southeast Ohio and Western Pennsylvania, where previous discoveries have been located, and into an area where Shell holds a major leasehold position of approximately 430,000 acres. The Gee well was drilled over 100 miles to the northeast of the nearest horizontal Utica producer, and had an initial flowback rate of 11.2 million cubic feet of natural gas per day. Gee has been on production for nearly one year. Shell began production of the Neal well in February, with observed peak flowback rates of 26.5 million cubic feet of natural gas per day.

“This successful discovery is the result of solid technical work in our onshore business” said Marvin Odum, Shell’s Upstream Americas Director. “Last year, we refocused our resources plays strategy to select fewer plays with specific scale and economic characteristics to best suit our portfolio. The Appalachian basin is one of those areas, and these two high-pressure wells both exhibit exceptional reservoir quality.”

Shell is currently awaiting results from four additional Utica wells drilled in Tioga County, and anticipates those wells will produce later this year.

• Shell announces Utica gas discovery in Pennsylvania

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In one agreement with Ultra Petroleum, Shell will acquire 155,000 net acres in the Marcellus and Utica Shale areas in Pennsylvania and receive a cash payment of $0.925 billion from Ultra in exchange for 100 percent of Shell’s Pinedale asset in Wyoming, including associated gathering and processing contracts, subject to closing.

In a separate agreement with Vine Oil & Gas LP and its partner Blackstone, Shell has agreed to sell 100 percent of its Haynesville asset in Louisiana, including associated field facilities and infrastructure for $1.2 billion in cash, subject to closing.

“We continue to restructure and focus our North America shale oil and gas portfolio to deliver the most value in the longer term. With this announcement we are adding highly attractive exploration acreage, where we have impressive well results in the Utica, and divesting our more mature, Pinedale and Haynesville dry gas positions,” said Marvin Odum, Shell’s Upstream Americas Director.

The Shell net production from Pinedale in the second quarter 2014 was 190 million standard cubic feet per day (mmscf/d) of dry gas (32 thousand barrels of oil equivalent per day (kboe/d)). During the first half of 2014, Ultra’s net production from the assets Shell is acquiring in Pennsylvania averaged 109 mmscf/d (19 kboe/d).

“We first entered the Pinedale Anticline in 2001, and I am proud of our operational excellence, community engagement, and leadership in responsible energy development over that time,” said Odum.

Shell’s Pinedale asset (which includes 19,000 net acres of leasehold interest, 1,108 gross wells and associated facilities, and an average of 0.7 percent overriding royalty interest in 11,500 acres) will be exchanged for cash and Ultra’s 100 percent interest in the Marshlands area (63,000 net acres) as well as its entire interest (92,000 net acres) in the Tioga Area of Mutual Interest (AMI), an unincorporated joint venture with Shell. After completion of this transaction, Shell will have a 100 percent interest in the Tioga AMI. The agreement is effective 1 April 2014, and is expected to close this year.

Shell’s Haynesville asset includes 107,000 net acres in in north Louisiana. The transaction includes 418 producing wells, 193 of them operated by Shell. As of 1 July 2014, the gross production from the Haynesville asset was approximately 700 mmscf/d of dry gas, with Shell’s net working interest share at approximately 250 mmscf/d (43 kboe/d). The agreement is effective 1 July 2014, and is expected to close in the fourth quarter of this year.

“We very much appreciate the support we have had in north Louisiana, and we will continue to operate in the state, as we have for decades, through our downstream, retail, midstream, and New Orleans-based deep-water operations,” said Odum.

• Shell divests U.S. onshore gas assets in Pinedale and Haynesville, adds acreage in Marcellus and Utica

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“Consistent with our philosophy to add scale and scope to our operations, this acquisition significantly bolsters our position in one of our liquids-rich core development areas,” said Dave Hager, Devon’s chief operating officer. “These assets directly overlap our existing core Cana position and expand our exposure to other western Oklahoma oil and gas plays.”

Devon plans to discuss the transaction in more detail on its upcoming conference call following the release of first-quarter earnings on May 7, 2014. The transaction is expected to close by the end of the second quarter, subject to customary purchase price adjustments, terms and conditions.

• Devon Energy Announces Acquisition of Cana-Woodford Shale Acreage

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"Gaining a position in a world class, oil-rich resource play like the Eagle Ford accelerates the transition of our portfolio and underscores our investment focus on high margin assets," says Doug Suttles, Encana President & CEO. "With this transaction, combined with our announced divestments of Jonah and properties in East Texas, we're replacing natural gas production with high margin oil and liquids production."

This transaction directly aligns with Encana's strategy by adding a sixth core growth asset in an established oil production basin that provides immediate impact on company-wide returns. The Eagle Ford is recognized as being among the most prolific and profitable resource plays in North America. In the first quarter of 2014 production from the acreage to be acquired by Encana included approximately 46,000 barrels per day (bbls/d) of total liquids production and 44 million cubic feet per day (MMcf/d) of natural gas, generating operating cash flow of US$327 million, with about 75 percent of the total production volumes for the period being oil.

The Eagle Ford assets offer a large contiguous land position in the core of the play, fitting well with Encana's technical expertise in developing resource plays. The Company expects the assets to be free cash flow positive in 2014, allowing Encana to execute its existing capital plan for 2014 without redirecting capital from its other five core growth plays. Through the second half of this year, Encana plans to start ramping up its activity in the play and exit 2014 with at least four drilling rigs running.

"In addition to the near term growth potential of this asset, we believe there are many opportunities to enhance the value of this world class position by applying our proven resource play expertise." adds Suttles. "Overall, this acquisition fully aligns with our strategy announced last November; it will significantly boost our oil and liquids output, improve our ability to generate cash flow and enhance our portfolio of world class resource plays."

With cash on hand combined with anticipated proceeds from previously announced transactions, Encana is well positioned to fund this acquisition.

The transaction is subject to satisfaction of normal closing conditions, as well as regulatory approvals, and is expected to close by the end of the second quarter 2014 with an effective date of April 1, 2014. Scotia Waterous advised Encana on this transaction.

• Encana Continues Bold Change With US$3.1 Billion Oil-Rich Eagle Ford Acquisition

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“This is a significant step in our subsidiaries’ joint efforts with YPF to develop one of the most exciting shale plays in the world today,” said George Kirkland, vice chairman of Chevron Corporation. “Vaca Muerta could become an important contributor to Chevron’s long term production growth.”

The agreements build off the progress made with the drilling program begun in 2013 and call for continued investment toward large-scale drilling and production in the 96,000-acre (388-sq. km) Loma Campana concession. The agreements also call for exploration of shale oil and gas resources in the 49,400-acre (200-sq. km) Narambuena area located about 70 miles (100 kilometers) north of Loma Campana in the Chihuido de la Sierra Negra concession, one of the main producing areas in the Neuquén Basin of west-central Argentina.

“YPF is a reliable partner and operator that is advancing the project in the right direction,” said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production Company. “We are pleased with the progress achieved so far and look forward to continuing to provide our technical expertise and investment to help Argentina achieve its goal of energy self-sufficiency.”

• Chevron, YPF Continue Development of Vaca Muerta Shale in Argentina

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Recent advances in technology, such as multi-stage hydraulic fracturing, have made it possible to economically develop unconventional gas and oil in the Montney Formation over the past several years, but little had been known about its total potential. The report estimates that there is approximately:

• 12,719 billion m3 (449 Tcf) of marketable natural gas;
• 2,308 million m3 (14,521 million barrels) of marketable natural gas liquids (NGLs); and
• 179 million m3 (1,125 million barrels) of marketable oil.

Although the findings for marketable NGLs and oil are notable, the estimated quantity of natural gas is extensive.

"At current consumption rates the Montney gas resource would meet Canadian needs for 145 years," said Gaétan Caron, the NEB's Chair and CEO. "The report clearly shows that Canadian energy markets will be well supplied with natural gas far into the future."

By combining the Montney's marketable gas estimate with prior assessments, the total ultimate potential remaining in Western Canada is 17,898 billion m3 (632 Tcf). This estimate is likely to increase as additional unconventional potential from other formations is estimated.

Overall, Canada has a very large remaining natural gas resource base in Western Canada to serve its markets into the future.

The Montney Formation is roughly located in northeast British Columbia, south of Fort Nelson and spread into northwest Alberta past Grande Prairie (Figure 1).

• Montney Formation one of the Largest Gas Resources in the World, report shows

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Chevron Canada Limited successfully concluded the initial twelve well exploration drilling program in the liquids-rich portion of the Duvernay shale play. Five wells have been completed and are tied into production facilities, and an additional four wells are waiting on completion and tie-in. The company's acreage is well positioned in the condensate-rich and volatile-oil portion of the play. Liquids yield for the completed wells range from 30 to 70 percent with initial production rates up to 7.5 million cubic feet of natural gas per day and 1,300 barrels of condensate per day.

"Early results of our Duvernay exploration program are encouraging," said George Kirkland, vice chairman of Chevron Corporation. "This discovery creates a foundation for future growth in Canada."

"Well performance and condensate yields exceeded our expectation and strengthen our plans going forward. Near term plans include transitioning to a two-rig drilling program to optimize well and completion design, and full field spacing requirements," said Jeff Shellebarger, president of Chevron North America Exploration and Production Company.

With the acquisition of Alta Energy Luxembourg S.à.r.l. and affiliates' acreage announced earlier this year, Chevron now has approximately 325,000 net acres in the Kaybob area of the Duvernay play.

• Chevron Establishes Recoverable Resource in the Duvernay Shale Play

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The transaction is expected to close during the second quarter of 2013, subject to customary governmental approvals. Under the agreement, Sinochem will acquire approximately 82,800 net acres of leasehold held by Pioneer for all Wolfcamp depths and deeper horizons. Pioneer retains 60% of its interest in the Wolfcamp depths and deeper horizons, with Sinochem receiving 40% of Pioneer’s interest. Pioneer will continue as operator and will conduct all leasing, drilling, completion, operations and marketing activities in the joint interest area. The joint interest area covers defined portions of Upton, Reagan, Irion, Crockett and Tom Green Counties in Texas. Pioneer retains its current working interests in all horizons shallower than the Wolfcamp horizon.

In addition to funding its own drilling obligations for the horizontal Wolfcamp Shale, Sinochem has agreed to fund 75% of Pioneer’s portion of drilling and facilities costs after closing until the $1.2 billion of drilling carry is fully utilized. Pioneer has six years to utilize the drilling carry, subject to extension under certain circumstances. At closing, Sinochem will pay its 40% share of net expenditures in the joint interest area from the December 1, 2012 effective date of the transaction to the closing date. Pioneer and Sinochem have agreed to a development plan which forecasts the drilling of 86 horizontal Wolfcamp Shale wells during 2013, increasing to 120 wells in 2014 and 165 wells in 2015.

To the extent Sinochem elects to participate in any vertical wells that are drilled in the joint interest area after the effective date, Sinochem will receive its share of production and costs from the Wolfcamp and deeper horizons based on the anticipated reserve contribution from the Wolfcamp and deeper intervals relative to anticipated reserves from all completed intervals. Pioneer’s and Sinochem’s participation in vertical wells will be based on each party’s interest without any drilling carry being applied. Pioneer will retain 100% of its existing vertical production in the joint interest area.

Pioneer has successfully drilled and completed 39 horizontal wells in the Wolfcamp Shale joint interest area through December 31, 2012. Of these 39 wells, 22 wells were on production and 4 additional wells were flowing back. Of the 22 wells on production, 20 wells were completed in the B interval and 2 wells were completed in the A interval. Pioneer’s net horizontal Wolfcamp Shale production in the joint interest area averaged approximately 2,000 barrels oil equivalent per day (BOEPD) in 2012, with a year-end exit rate of approximately 5,000 BOEPD.

Scott Sheffield, Chairman and CEO, stated, “We are very excited to work with Sinochem, a global energy and chemicals leader, in the southern horizontal Wolfcamp Shale area, and are pleased that they share our confidence in accelerating the development of this large, oil-rich acreage position. This accelerated development will add significant production and reserves for Pioneer while enhancing shareholder value. It will also reduce our country’s dependence on foreign oil imports, create thousands of new U.S. jobs, further stimulate the Permian Basin economy and add significant tax revenues for use by local communities, schools, the state and the nation.”

Consistent with the announced transaction with Sinochem, the responsibilities for certain Executive Vice Presidents (EVPs) who are members of Pioneer’s Management Committee will be rebalanced. These changes are effective immediately.

William F. Hannes, formerly EVP South Texas Operations, will become EVP of the newly formed Southern Wolfcamp Asset Team. This asset team will focus on executing the drilling program in the horizontal Wolfcamp Shale joint interest area.

Danny L. Kellum, EVP Permian Operations, will focus his attention on Pioneer’s remaining Permian activities, with executive responsibility for the Permian Asset Team and Permian integrated services. This asset team will focus on executing the horizontal and vertical drilling programs over the remainder of Pioneer’s Permian acreage.

Jay P. Still, EVP Domestic Operations, will add executive responsibility for Pioneer’s South Texas operations to his current responsibilities for the Company’s Mid-Continent, Rockies, Alaska and Barnett Shale assets.

BofA Merrill Lynch served as financial advisor and Vinson & Elkins LLP served as legal advisor to Pioneer on the transaction.

• Pioneer Natural Resources Announces $1.7 Billion Horizontal Wolfcamp Shale Transaction with Sinochem

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Mr Davey said:
“Shale gas represents a promising new potential energy resource for the UK. It could contribute significantly to our energy security, reducing our reliance on imported gas, as we move to a low carbon economy.
“My decision is based on the evidence. It comes after detailed study of the latest scientific research available and advice from leading experts in the field.
“We are still in the very early stages of shale gas exploration in the UK and it is likely to develop slowly. It is essential that its development should not come at the expense of local communities or the environment. Fracking must be safe and the public must be confident that it is safe.
“We are strengthening the stringent regime already in place with new controls around seismic risks. And as the industry develops we will remain vigilant to all emerging evidence to ensure fracking is safe and the local environment is protected.
“The new Office of Unconventional Gas and Oil, led by DECC, will be able to focus regulatory effort where necessary to meet the needs of future production.
“Emissions of methane – which is a potent greenhouse gas - are already subject to control, but I am today commissioning a study of the possible impacts of shale gas development on greenhouse gas emissions and climate change.”
To date there has been no commercial shale gas production in the UK. Exploratory fracking has been suspended since May 2011 after two small seismic tremors were detected near the country’s only fracking operations in Lancashire.
Following a detailed study and further analysis by an independent panel of experts commissioned by the Department of Energy and Climate Change, with feedback from a wide public consultation, and the benefit of the report by the Royal Society and Royal Academy of Engineering, the Government has concluded that the seismic risks associated with fracking can be managed effectively with controls.
New controls to mitigate seismic risks announced today include:
A prior review before fracking begins must be carried out to assess seismic risk and the existence of faults;
A fracking plan must be submitted to DECC showing how seismic risks will be addressed;
Seismic monitoring must be carried out before, during and after fracking;
A new traffic light system to categorise seismic activity and direct appropriate responses. A trigger mechanism will stop fracking operations in certain conditions.
These controls, along with the rest of recommendations in the independent report into seismic activity and fracking commissioned by the Government and published in March this year, have been accepted by the Secretary of State.
The Secretary of State has also accepted all the recommendations of the Royal Society report which are relevant to Government. (One further recommendation is being considered by the Research Councils.)
The study of the possible impacts of shale gas development on greenhouse gas emissions and climate change will consider the available evidence on the lifecycle of greenhouse gas emissions from shale gas exploitation and the need for further research.

Tony Grayling, Head of Climate Change and Communities at the Environment Agency, said:
“The Environment Agency takes the potential risks arising from fracking for shale gas extraction very seriously and has undertaken a thorough assessment of them.
“We are satisfied that existing regulations are sufficient to protect people and the environment in the current exploratory phase. We have also established a Shale Gas Unit to act as a single point of contact for industry to ensure there is an effective, streamlined approach for the regulations that fall within our responsibility.”
Steve Walker, the Health and Safety Executive's Head of Offshore Oil and Gas Safety, said:
"HSE will be working closely alongside our partners on fracking, building on expertise gained from regulating other forms of oil and gas extraction.
"Over the past 16 years HSE has worked very closely with the Environment Agency on regulating a range of high hazard industries in England and Wales and we are developing our joint approach to the regulation of unconventional gas.
"We will play our full part in taking forward any proposals for the regulatory regime, working with the new Office for Unconventional Gas and Oil."

NOTES FOR EDITORS

Read the Written Ministerial Statement on the DECC website.
Two small seismic tremors were experienced while Cuadrilla Resources was fracking for shale gas at their Preese Hall site in Lancashire in April and May 2011. Operations were suspended, and Cuadrilla submitted a geotechnical report, which concluded that the tremors were caused by fracking, and recommended how these risks could be mitigated in future operations. DECC conducted a public consultation in April and May 2012 on a review of Cuadrilla’s geotechnical report and recommendations by a panel of independent experts. That report can be found on the Oil and Gas website.
Before an operator can begin hydraulic fracturing they must obtain landowner permission (if necessary), local authority planning permission and other regulatory consents including environmental permits from the Environment Agency or the Scottish Environment Protection agency and scrutiny from the Health and Safety Executive before DECC considers consent to individual operations. For more details of regulations and procedure for shale gas visit the shale gas pages of the DECC website.
Further fracking operations by Cuadrilla are dependent upon them obtaining new planning permissions, Environment Agency permits and consent from DECC.
An independent review of the health, safety and environmental risks associated with hydraulic fracturing for shale gas was carried out by the leading engineering and science bodies in the UK, the Royal Academy of Engineering and the Royal Society. The report published in June 2012 is available on their website [External link]. Their central conclusion is that the risks can be managed effectively in the UK so long as operational best practices are implemented, and enforced through regulation.
As announced in the Gas Generation Strategy on 5 December, an Office of Unconventional Gas and Oil will be created as a single point of contact for investors and to streamline the regulatory process to make it simple and safe. Further details of the make-up and operation of the new office will be made in due course.
For more information about the Environment Agency’s role in regulating unconventional gas visit their website [External link].

• New Controls Announced For Shale Gas Exploration

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The Moomba-191 shale well is flowing natural gas at a stabilised rate of 2.7 mmscf/d from the Roseneath, Epsilon and Murteree shale targets. Santos initially announced success at Moomba-191 in its interim report in August.

Santos Vice President Eastern Australia, James Baulderstone, said the Moomba-191 shale well was another milestone for Santos’ Cooper Basin unconventional gas program, which began in 2004.

“The connection of the Moomba-191 well is a significant step forward as we work to unlock the vast unconventional potential of the Cooper Basin,” Mr Baulderstone said.

“While this is the first commercial shale well, and more work will be required to unlock the area’s full potential, this is clearly a landmark for Australia’s natural gas industry. Producing commercial quantities of natural gas from the Cooper's shale rock formations would provide the potential for ongoing energy security for South Australia and our eastern states, plus valuable export revenue.

“The well was only 350 metres from the existing pipeline network and eight kilometres from Moomba's gas processing plant, which enabled it to be brought on line quickly, illustrating the importance of Santos' existing infrastructure position in commercialising the region’s significant resource potential.”

Further drilling is planned for the area, including an ongoing vertical well appraisal program and Santos’ first horizontal shale well planned for early 2013.

Santos was joined by the Premier of South Australia, the Hon Jay Weatherill MP, and the Minister for Mineral Resources and Energy, the Hon Tom Koutsantonis MP, to officially open the Moomba-191 well at an on-site ceremony north-east of the Moomba processing plant.

Mr Weatherill said: “Natural gas from unconventional sources has been regarded as something that would happen in the future but today's opening demonstrates that the future is happening today.”

"This is the first step in the next wave of Cooper Basin development that will lead to natural gas from unconventional sources being increasingly used in households across SA and Eastern Australia more generally.”

Santos has a 66.6% interest in the South Australian Cooper Basin Joint Venture. The other participants are Beach Energy (20.21%) and Origin Energy (13.19%).

• Santos announces start of Australia’s first commercial shale gas production

by abarrelfull

This announcement supports Shell’s strategy of further building an industry-leading liquids-rich shale resource. The acquisition provides both existing production and near-term growth potential from a proven resource, as well as promising opportunities for expansion.

The acquisition covers 618,000 net acres in the Permian Basin in West Texas that currently produces some 26,000 barrels of oil equivalent per day and has significant growth potential.

• Royal Dutch Shell acquires liquids-rich shale acreage in Texas

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KMP will invest approximately $90 million in the project, which also involves adding associated receipt facilities by constructing a five-bay truck offloading facility and three new storage tanks with approximately 360,000 barrels of crude/condensate capacity at Kinder Morgan’s DeWitt Station in DeWitt County, Texas, and Wharton Pump Station in Wharton County, Texas. Pending receipt of environmental and regulatory approvals, construction is scheduled to begin in the fourth quarter of 2012.

“This pipeline lateral will provide yet another attractive delivery point for customers of our KMCC pipeline while providing Phillips 66 with enhanced access to price-advantaged Eagle Ford crude and condensate,” said KMP Products Pipelines President Tom Bannigan. The project is expected to be immediately accretive to cash available to KMP unitholders upon completion in the first quarter of 2014.

Kinder Morgan’s crude/condensate pipeline, which was ready for service in June 2012, transports crude/condensate from the Eagle Ford shale to the Houston Ship Channel through 65 miles of new-build construction and 113 miles of converted natural gas pipeline.

“This agreement aligns with a fundamental part of the Phillips 66 business strategy to get advantaged crude to our refineries,” said Glenn Simpson, general manager, Phillips 66 Crude & International Supply.

• Kinder Morgan Energy Partners and Phillips 66 Agree to Deliver Eagle Ford Shale Crude to Coastal Refinery

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This loan will finance capital investments required of CDGR in connection with its subscription of 40% interest in a partnership which owns the shale gas assets in the Montney land in British Columbia, plus additional potential lands tapping the Cadomin and Doig geological formations. Encana Corporation, Canada's largest natural gas producer, is the operator and managing partner of this partnership.

Canada is endowed with vast shale gas reserves and has great potential as a new natural gas supplier for the markets in the Asia-Pacific region. The participation of MC in this project to secure gas interests in North America will contribute to Japan's energy security by diversifying the natural gas supply sources and easing the demand-supply balance in the Asian liquefied natural gas (LNG) markets.

MC is also planning to produce LNG in its production facilities that are going to be built on the western coast of British Columbia by using the natural gas produced from this shale gas project and the shale gas project in the Cordova Embayment*1, and to export the output to Japan and the Asian region. This project is expected to make Canada, which is politically stable and a relatively short distance from Japan, a new LNG supply source, thereby contributing to the diversification of Japan's LNG supply sources.

JBIC will continue to actively support Japanese businesses that promote the development and acquisition of energy resources by drawing on its various financial facilities and schemes for structuring projects, and by performing its risk-assuming functions.

• Energy and Natural Resources Financing for the Shale Gas Project in Canada

by abarrelfull

This is an early entry at scale into over 13 million acres of immature, but potentially highly prospective play at low cost, with high risk but also with significant upsides.

Through a step-wise exploration programme the partners will potentially drill 10-20 wells by 2017 in three phases to demonstrate prospectivity.

Petrofrontier will operate the first phase of the programme while Statoil has secured options to operate from the second exploration phase in addition to increase ownership interests from 25 to 65% of Petrofrontier's interests.

Statoil has committed to contribute USD 25 million for the first phase of the exploration programme. This figure could escalate to USD 200 million through a phase two and three depending on exploration results.

"These exploration activities are in line with our objective to access shale plays at an early exploration stage, at low cost and develop them into potentially high value assets. We are looking forward to explore it together with our partner Petrofrontier – a small but highly competent company", says senior vice president for New Ventures in Statoil, Atle Rettedal.

"We are very excited to announce this farm-in agreement with Statoil. Statoil is a highly regarded international exploration company, actively involved in major unconventional plays and brings exceptional financial resources and technical capabilities to our new relationship" says Paul Bennett, President and CEO of PetroFrontier. "We believe that partnering with a global leader like Statoil validates the potential of our assets and the exploration work we have completed to date."

Petrofrontier is anexploration company listed on the Toronto Stock Exchange and holds a 75-100% interest in the four Georgina exploration permits EP 103,104,127 and 128, in addition to pending exploration permits.

• Statoil enters shale exploration in Australia

by abarrelfull

LLC WESTGASINVEST currently holds subsoil rights to nine unconventional (shale) gas license areas in the Lviv Basin of Ukraine, totalling approximately 3,800 square kilometres of acreage.
This Agreement was developed within the frameworks of the Memorandum of Understanding between Eni and Nadra Ukrayny, and the Cooperation Agreement with Cadogan Petroleum, both signed in 2011.

The Lviv Basin is considered to be one of the most prospective basins in Europe for the exploration of unconventional gas, being also the prosecution of the Lublin Basin in Poland which has already attracted substantial interest from the hydrocarbon industry.

Eni has been present in Ukraine since 2011 in the Zagoryanska and Pokroskoe licenses located in the Dniepr-Donetz Basin and operates with Cadogan.
This transaction, which strengthens the company's presence in Ukaraine, represents a major step forward for the development of Eni's global unconventional portfolio. It will allow Eni to establish the foundation from which to build a robust future in that country.

Eni made its entry in the European unconventional gas landscape in 2010 through the acquisition of 3 licenses in the Polish Baltic Basin on which it is currently operating, leveraging the extensive knowledge and expertise acquired through its JV in the Barnett Shale in Texas, the first shale gas basin in the world to be developed on a large-scale.

• Eni signs a Share Purchase Agreement with Nadra Ukrayny and Cadogan Petroleum for the development of Unconventional Gas in Ukraine

by abarrelfull

As the President has made clear, domestic natural gas and oil resources will continue to play a key role in America’s energy future. Already, technological advancements like hydraulic fracturing – innovation supported by public research – have allowed development of previously uneconomic natural gas and oil deposits. In fact, since 2008, U.S. oil and natural gas production has increased each year. In 2011, U.S. crude oil production reached its highest level in 8 years, increasing by an estimated 110,000 barrels per day over 2010 levels to 5.59 million barrels per day. And U.S. natural gas production grew in 2011 as well – the largest year-over-year volumetric increase in history – easily eclipsing the previous all-time production record set in 1973. Overall, oil imports have been falling since 2005, and oil import dependence declined from 57 percent in 2008 to 45 percent in 2011 – the lowest level since 1995.

As the United States continues to expand domestic natural gas and oil production, it is critical that the public have full confidence that the right safety and environmental protections are in place – guided by the best available science. Leveraging each agency’s core competencies and strengths will enhance efforts to explore the significant new resource development opportunities made possible in recent years by hydraulic fracturing and other new technologies, and meet high-priority challenges in a coordinated and common-sense way.

"Science, research and innovation continue to play a vital role in our efforts to further expand oil and gas production in the United States and make sure it’s done safely and responsibly," said Department of the Interior Deputy Secretary David J. Hayes. "Improvements in technologies like hydraulic fracturing are responsible for greatly increasing our capacity to develop America’s abundant unconventional resources in recent years. Through a close collaboration across the government that reduces redundancy and streamlines our research, we are positioning the Obama administration to best meet the critical need of increasing public understanding and public confidence of these critical technologies so that we can continue safe and responsible exploration and production for many decades to come."

"The development of American shale gas resources is having a transformative impact on the U.S. energy landscape, helping to improve our energy security while spurring economic development and job creation around the country," said Acting Under Secretary of Energy Arun Majumdar. "The Energy Department remains committed to the safe and responsible development of this American resource, and continued cooperation between government and private industry partners under President Obama’s all-of-the-above approach to American energy."

"We are moving into a new era of American energy, one that has the potential to create jobs, strengthen our energy independence and security, and cut pollution. President Obama has created this interagency working group to ensure that these energy innovations happen safely and responsibly, without compromising the environment or the health of the American people," said EPA Deputy Administrator Bob Perciasepe. "We will continue to rely on the best available science to oversee the responsible development of these energy sources."

A primary goal of this effort will be to identify research topics where collaboration among the three agencies can be most effectively and efficiently conducted to provide results and technologies that support sound policy decisions by the agencies responsible for ensuring the prudent development of energy sources while promoting safe practices and human health. The new research partnership is an example of the Obama Administration’s effort to coordinate activities across the federal government　to support development of our abundant domestic natural gas resources in a safe and responsible way.　Today the Administration announced　that a broader set of activities will be coordinated under an Executive Order issued by President Obama to create a new Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources.　

• Obama Administration Announces New Partnership on Unconventional Natural Gas and Oil Research

by abarrelfull

Chesapeake has completed the sale of preferred shares of a newly formed unrestricted, non-guarantor consolidated subsidiary, CHK Cleveland Tonkawa, L.L.C. (CHK C-T), and a 3.75% overriding royalty interest in the first 1,000 new net wells to be drilled on CHK C-T leasehold and certain wells contributed at closing for proceeds of $1.25 billion. The purchasing investment group was led by GSO Capital Partners LP, an affiliate of the Blackstone Group (NYSE:BX), and included TPG Capital, Magnetar Capital and EIG Global Energy Partners. CHK C-T owns approximately 245,000 net leasehold acres in the Cleveland and Tonkawa unconventional liquids-rich tight sand plays in Roger Mills and Ellis counties, Oklahoma. Chesapeake has retained all the common equity interests in CHK C-T.

The holders of CHK C-T preferred shares are entitled to receive an initial annual distribution of 6%, payable quarterly. Chesapeake has retained an option exercisable prior to March 31, 2019 to repurchase the preferred shares for cash in whole or in part at any time, at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x.

Chesapeake has also completed the sale of a 10-year volumetric production payment (VPP) to an affiliate of Morgan Stanley (NYSE:MS) for proceeds of approximately $745 million, or approximately $4.68 per thousand cubic feet of natural gas equivalent (mcfe), for certain producing assets in its Anadarko Basin Granite Wash play. The transaction included approximately 160 billion cubic feet of natural gas equivalent (bcfe) of proved reserves and current net production of an estimated 125 million cubic feet of natural gas equivalent (mmcfe) per day. Chesapeake has retained drilling rights on the properties above and below currently producing intervals and outside of existing producing wellbores. Including this transaction, the company has completed 10 VPP transactions since December 2007 and, in doing so, has sold approximately 1.37 trillion cubic feet of natural gas equivalent (tcfe) of proved reserves for combined proceeds of approximately $6.4 billion, or approximately $4.65 per mcfe, which is approximately 300% more than the company’s current drilling and completion cost per mcfe.

Finally, Chesapeake recently signed a purchase and sale agreement covering approximately 58,400 net acres of leasehold in the Texoma Woodford play in Bryan, Carter, Johnston and Marshall counties in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for approximately $590 million in cash before certain deduction and standard closing adjustments. The properties include approximately 25 mmcfe per day of current net production. The transaction is expected to close on April 30, 2012.

• Chesapeake Energy Corporation Announces Three Oil and Gas Asset Monetization Transactions for Proceeds of $2.6 Billion

by abarrelfull

Charle Gamba, President and CEO of the Corporation, commented, “As the world's largest publicly-owned integrated oil and gas company, ExxonMobil brings significant experience, technology, research and financial resources to this shale oil joint venture with Canacol. We look forward to working with their team to explore the substantial shale oil potential on the VMM 2 contract. At the same time, Canacol has chosen to retain its 100% interest in the adjacent Santa Isabel E&P contract in order to capture all of the upside on the block should the play prove commercial on the adjacent VMM 2 and VMM 3 blocks.”

Key terms and conditions
Pursuant to the terms of the FOA, ExxonMobil will carry the cost of the drilling and testing of up to three wells to test conventional and unconventional targets in the La Luna and Rosablanca formations, both proven oil source rocks in the area. The first two wells will be vertical wells, while the third well will possibly be a horizontal multistage fractured well. It is anticipated that prospective intervals of the La Luna and Rosablanca will be cored and logged within the first well, and stimulated and flow tested within the second well. Should ExxonMobil choose to proceed with a third well, it will possibly be a horizontal multi-stage fractured well. Under the terms of the agreement, ExxonMobil will pay 100% of the cost of the three wells, up to a cap of gross US$15 million for each of the first 2 wells, and a cap of gross US$ 17.5 million for the third well should it be a horizontal lateral well exceeding 4,000 feet in lateral length, and US$ 15 million should it be another vertical well. ExxonMobil will also pay Canacol US$ 2.2 million upon execution of the FOA for back-costs related to the acquisition of 3D seismic on the block in 2011. The total potential investment on the block is approximately US$ 50 million. In return, ExxonMobil shall earn 50% of Canacol’s 40% interest in the contract. Vetra will remain as operator of VMM 2 during the exploration period and expects to spud the first exploration well in late 2012. The formal assignment of working interests as contemplated by the transaction, including Canacol’s 20% interest, remain subject to the approval of the Agencia Nacional de Hidrocarburos (ANH) of Colombia.

Canacol’s unconventional shale oil play

• VMM 2 (20% interest, 7,561 net acres)
• VMM 3 (20% interest, 16,622 net acres) (1)
• Santa Isabel (100% interest, 101,542 net acres)

Located in the Middle Magdalena basin, the VMM 2 E&P contract is one of three adjacent contracts that expose Canacol to a potentially large, unconventional shale oil fairway in the thick Cretaceous La Luna and Rosablanca formations analogous to the Eagle Ford formation. Ranked as one of the most productive source rocks in the world, the La Luna is also the primary source rock in Venezuela’s Maracaibo basin, which contains over 250 billion barrels of recoverable oil.

Historical vertical wells drilled into the La Luna source rock in the nearby Totumal and Butarama fields in the Middle Magdalena Basin have tested rates of up to 900 barrels of light oil per day natural flow from fractured shales within the La Luna, such as the Buturama 2 well tested in 1953 by Intercol. In the last year, this unconventional play type has received considerable attention from world-class, international resource play operators and is an area of emphasis in the upcoming 2012 Colombia Bid Round.

According to the ANH, approximately 30% of the 109 new E&P contracts planned for the 2012 Colombia Bid Round have exposure to some form of unconventional resource potential. Additionally, Ecopetrol is targeting over 25,000 barrels of production per day from the Middle Magdalena unconventional shale fairway by 2015.

Charle Gamba, President and CEO of the Corporation, commented, “Land values in the Middle Magdalena basin that feature prospective unconventional resources have increased 7-fold from approximately $125/acre to over $700/acre in less than a year.”

VMM 3 E&P contract
Effective January 2012, Shell-Colombia acquired 100% participating interest in the VMM 3 E&P contract. ShellColombia has assumed approximately US $50 million in work commitments, which consist of all costs for seismic acquisition and the drilling of three exploratory wells. Effective 2014, Canacol has the option to exercise a 20% participating interest in the VMM 3 E&P contract for no additional cost.

Canacol’s zero cost option to exercise a 20% participating interest in the VMM 3 E&P contract allows the Corporation to not only retain a significant interest in VMM 3’s deep cretaceous potential, but also benefit from having a world-class operator such as Shell-Colombia exploring the area. In addition, Canacol aims to capture valuable information from Shell-Colombia’s activities to de-risk the exploration and development of the Corporation’s 100%-operated interest in the adjacent Santa Isabel E&P contract.

Santa Isabel E&P contract
Canacol retains 100% interest in the Santa Isabel E&P contract, and plans to drill one exploration well in the second half of 2012. Should the Cretaceous shale exploration wells in the adjacent VMM 2 and VMM 3 prove successful, Canacol will have retained significant exposure and upside to the play on its 100% owned contract.

Independent Evaluation by GLJ Petroleum Consultants Ltd. (“GLJ”)
The Corporation engaged GLJ Petroleum Consultants Ltd. “GLJ” to conduct an independent evaluation of the undiscovered petroleum initially-in-place (“UPIIP”) for Canacol’s interests in the Middle Magdalena VMM 2 and Santa Isabel E&P contracts effective December 31, 2011. The Corporation owns 20% interest in VMM 2 and 100% interest in Santa Isabel.

GLJ prepared the evaluation in accordance with resource and reserves definitions, standards, and procedures in the Canadian Oil and Gas Evaluation (“COGE”) Handbook. COGE Handbook defines UPIIP as:
“Undiscovered Petroleum Initially-In-Place (equivalent to undiscovered resources) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of Undiscovered Petroleum Initially-In-Place is referred to as Prospective Resources; the remainder as Unrecoverable.”

GLJ has provided low, best, high, and mean estimates* of UPIIP for the La Luna and Rosa Blanca shale formations:

Santa Isabel E&P contract 100% Canacol interest UPIIP (MMbbl)

VMM 2 E&P contract 20% Canacol interest UPIIP (MMbbl)

Santa Isabel and VMM 2 contracts Total Canacol interest UPIIP (MMbbl)

Estimates of UPIIP were generally prepared using land and technical information including well information, engineering, geological, and geophysical data available from Canacol to December 31, 2011. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.

*Low estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

*Best estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

*High estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

• Canacol Energy Ltd. and ExxonMobil Sign Agreement for Shale Oil Exploration Project in Colombia

by abarrelfull

In this regard, reported that within our annual exploration program exploratory wells have made The Set X-1 (YPF.Md.NLaFi.x-1) and Middle Malal - 94 (YPF.Md.NMDM-94), whose locations are in West Payún blocks and Rio Grande Valley, respectively, in the province of Mendoza.

The objective of the well The Set X-1 was to assess the presence and productivity of hydrocarbons in the Vaca Muerta formation and confirm the model Prospective proposed. Well Said started production with an initial flow daily average of 427 barrels of oil equivalent of 36 ° API quality after 2 fractures have performed in a section of 138 meters of formation. Thus, the the same positive result allowed us to confirm the prospective model in the Province Mendoza.

In turn, the well Malal Environment - 94 was aimed at evaluating the presence and productivity Vaca Muerta formation hydrocarbons in the northern basin. The results of that well yielded a daily average initial production approximately 55 barrels of 27 ° API quality, following a fracture in a section of 120 meters of formation.

The positive result allows us to extend the estimate of the area prospects for such training at 2,000 km2 with an expectation of resources 1,000 million barrels of oil equivalent for this site in the Province Mendoza.

It is noteworthy that these 2 wells are drilled in Mendoza producing the Vaca Muerta formation at depths of between 2,200 and 2,400 meters in vicinity of structures associated with the Andes.

Finally, given the results obtained, we will expand our plan exploratory drilling in the coming months three exploratory wells targeting the Vaca Muerta formation in the Province of Mendoza to delineate the potential in the southern of the Province.

• YPF - Preliminary results exploratory wells formations unconventional oil (shale oil) in the province of Mendoza

by abarrelfull