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Nizhnekamsk TPP-2, which joined Tatneft Group of Companies in 2010, will provide in full volume heat power for the first stage of TANEKO Refinery and Petrochemical Plants Complex scheduled for commissioning on October 10, 2010.

With the launch of TANEKO Refinery and Petrochemical Plants Complex the significance of Nizhnekamsk TPP will increase many times. Currently, mounting of steam system lines is in the process at the thermal power plant with hydraulic tests planned for September. The steam line is being installed at present. Later steam pipelines will be laid through the technological overpass 2.6 km long to connect subsequent stages of the complex.

Calculations show that the existing equipment of Nizhnekamsk thermal power plant could yield a good profit without significant renovation and modernization, but subject to full loading of all its facilities.

Turbines of the station are designed for cogeneration of heat and power. Supply of steam to TANECO complex will cause growth of electric power generation. Completion of the complex construction will cause multi-fold increase of the capacity of Nizhnekamsk TPP. In turn, this will allow TANECO to significantly reduce energy costs and increase competitiveness.

The plans envisage concluding an agreement on elaborating a feasibility study in 2010 for reconstruction of the station. It is expected to expand the main building, introduce new gas turbine technologies allowing to make a qualitative step forward in the development of the thermal power station. Having fulfilled the action plan on reconstruction of the station it will be possible not only to provide for the energy needs of TATNEFT's companies in Nizhnekamsk area, but also use cheap electric power for the oil production process.

As a result, TATNEFT will stop being a consumer of electricity only, but it will become a meaningful generating company - participant of the wholesale electricity market.

Reference Information. Nizhnekamsk TPP was put into operation in 1979 and it is considered to be the youngest one among all the generating facilities of the Republic. The main fuel for Nizhnekamsk TPP is natural gas of Urengoy field. Reserve fuel is mazut M-100. Its installed capacity is 380 megawatts of electric power and 1,940 Gcal / hour of heat. The thermal power plant supplies electric power to the wholesale market and generates steam for OAO Nizhnekamskneftechim, OAO Nizhnekamskshina and hot water to supply the city of Nizhnekamsk.

Transfer of ownership of the thermal power plant from OAO Generating Company to OOO Nizhnekamsk TPP was registered on June 1, 2010.

Nabors Industries Ltd. (Nabors) (NYSE: NBR) and Superior Well Services, Inc. (Superior Well Services) (Nasdaq: SWSI) today announced that they have entered into a definitive merger agreement whereby Nabors will acquire Superior Well Services. The agreement contemplates that Nabors will commence a tender offer for all outstanding shares of Superior Well Services common stock at a price of $22.12 per share in cash in accordance with the merger agreement. The transaction is valued at approximately $900 million.

Gene Isenberg, Nabors' Chairman and CEO, commented: "For some time now, we have evaluated integrating more service offerings into our business, particularly internationally. Although we expect this acquisition by itself to be significantly accretive to 2011 results, our major motivator was the opportunity to leverage this well respected franchise into a global force utilizing our extensive international footprint and resources.

"In addition to the upside associated with expanding internationally, we expect to derive significant synergies in North America by integrating pumping services with our drilling and workover offerings. The most readily identifiable economies will be derived from our own Oil and Gas entities, with further benefits dependent upon how quickly we can increase activity across more of our fleet. Superior Well Services' broad U.S. presence complements that of both our U.S. Land Drilling and Well-servicing operations and augments our expansion into areas such as the Marcellus shale region.

"Superior Well Services possesses one of the newest fleets in the industry with over 430,000 hydraulic fracturing horsepower. This high quality fleet is operated by a very capable, well managed organization that can quickly become a substantial unit of Nabors. This transaction also provides good value to the Superior Well Services stockholders as the offer price represents an attractive premium to the 30-day average closing stock price."

Superior Well Services' Chairman and CEO David Wallace said: "We are very pleased to be joining forces with Nabors. This complementary combination of the largest land drilling contractor in the world with a leader in technical pumping will make both organizations stronger and better able to meet our customers' needs not only in the U.S., but around the world. We believe this transaction will deliver an immediate and significant premium for our shareholders."

Holders of approximately 34% of Superior Well Services' outstanding shares of common stock have entered into agreements agreeing to tender their shares. Nabors expects to commence the tender offer promptly and expects the offer to close by the end of the third quarter. Following completion of the tender offer, Nabors will acquire any remaining shares of Superior Well Services through a second-step merger at the same price paid in the tender offer.

Under the terms of the agreement approved by the boards of directors of both companies, the tender offer is conditioned on the tender of at least a majority of Superior Well Services' shares calculated on a fully diluted basis and other customary closing conditions, including the receipt of regulatory approvals. In addition, the merger agreement requires Superior Well Services to pay Nabors a termination fee of approximately $22.5 million and reimbursable expenses of up to $5 million in the event that the agreement is terminated for certain reasons.

Noble Energy, Inc. (NYSE: NBL) announced today that it has closed the previously announced sale of certain Mid-Continent and Illinois basin assets to an affiliate of Citation Oil & Gas. Proceeds from the transaction were $552 million and included final closing adjustments from the effective date of April 1.

Noble Energy is a leading independent energy company engaged in worldwide oil and gas exploration and production. The Company operates primarily in the Rocky Mountains, Mid-Continent, and deepwater Gulf of Mexico areas in the United States, with significant international operations offshore Israel and West Africa. Noble Energy is listed on the New York Stock Exchange and is traded under the ticker symbol NBL. Visit Noble Energy online at www.nobleenergyinc.com.

Nabors Industries Ltd. (Nabors) (NYSE: NBR) and Superior Well Services, Inc. (Superior Well Services) (Nasdaq: SWSI) today announced that they have entered into a definitive merger agreement whereby Nabors will acquire Superior Well Services. The agreement contemplates that Nabors will commence a tender offer for all outstanding shares of Superior Well Services common stock at a price of $22.12 per share in cash in accordance with the merger agreement. The transaction is valued at approximately $900 million.

Gene Isenberg, Nabors' Chairman and CEO, commented: "For some time now, we have evaluated integrating more service offerings into our business, particularly internationally. Although we expect this acquisition by itself to be significantly accretive to 2011 results, our major motivator was the opportunity to leverage this well respected franchise into a global force utilizing our extensive international footprint and resources.

"In addition to the upside associated with expanding internationally, we expect to derive significant synergies in North America by integrating pumping services with our drilling and workover offerings. The most readily identifiable economies will be derived from our own Oil and Gas entities, with further benefits dependent upon how quickly we can increase activity across more of our fleet. Superior Well Services' broad U.S. presence complements that of both our U.S. Land Drilling and Well-servicing operations and augments our expansion into areas such as the Marcellus shale region.

"Superior Well Services possesses one of the newest fleets in the industry with over 430,000 hydraulic fracturing horsepower. This high quality fleet is operated by a very capable, well managed organization that can quickly become a substantial unit of Nabors. This transaction also provides good value to the Superior Well Services stockholders as the offer price represents an attractive premium to the 30-day average closing stock price."

Superior Well Services' Chairman and CEO David Wallace said: "We are very pleased to be joining forces with Nabors. This complementary combination of the largest land drilling contractor in the world with a leader in technical pumping will make both organizations stronger and better able to meet our customers' needs not only in the U.S., but around the world. We believe this transaction will deliver an immediate and significant premium for our shareholders."

Holders of approximately 34% of Superior Well Services' outstanding shares of common stock have entered into agreements agreeing to tender their shares. Nabors expects to commence the tender offer promptly and expects the offer to close by the end of the third quarter. Following completion of the tender offer, Nabors will acquire any remaining shares of Superior Well Services through a second-step merger at the same price paid in the tender offer.

Under the terms of the agreement approved by the boards of directors of both companies, the tender offer is conditioned on the tender of at least a majority of Superior Well Services' shares calculated on a fully diluted basis and other customary closing conditions, including the receipt of regulatory approvals. In addition, the merger agreement requires Superior Well Services to pay Nabors a termination fee of approximately $22.5 million and reimbursable expenses of up to $5 million in the event that the agreement is terminated for certain reasons.

Nabors will hold a conference call to discuss the proposed transaction at 4:00 p.m. Eastern / 3:00 p.m. Central Time on Monday, August 9, 2010. Slides will be posted on the Nabors website shortly before the call and can be accessed at www.nabors.com, under Investor Relations - Events Calendar. Please use the following dial-in information:

Talisman Energy Inc. and Ecopetrol S.A. have agreed to acquire BP Exploration Company (Colombia) Limited. Talisman will complete its transaction through an indirect wholly owned subsidiary.

Talisman and Ecopetrol have reached an agreement to acquire all of the outstanding shares of BP Exploration Company (Colombia) Limited (BPXC), an indirect wholly owned subsidiary of BP plc, for total cash consideration of US$1.9 billion, which includes a working capital adjustment, estimated at approximately US$145 million. Under the terms of the transaction, Talisman will acquire a 49% interest in BPXC for US$858 million (excluding its share of working capital), while Ecopetrol will take the remaining 51% interest. The transaction is expected to close by the end of 2010, subject to Colombian and US regulatory approval and other customary conditions.

"This is an exciting opportunity and an excellent fit with Talisman's strategy of long-term profitable growth," said John A. Manzoni, President & CEO. "These are tremendous assets that our team knows well. They are attractively priced, with excellent running room and we are partnering with the pre-eminent oil and gas company in Colombia.

"Talisman and Ecopetrol are currently partners in several blocks in Colombia and Peru. This acquisition of BPXC by Talisman and Ecopetrol is the most significant business transaction that the two companies have undertaken jointly to date. Talisman is looking forward to building on this strategic relationship between our two companies.

"Completion of this transaction will accelerate our objective of building a material core area in Latin America, with target production of at least 50,000 boe/d. This will add another oil weighted producing area to our asset mix. The acquisition provides over 12,000 boe/d of production net to Talisman, plus immediate cash flow which will fund the expected short-term exploration and development opportunities we see on this acreage.

"This acquisition builds on Talisman's large acreage position in Colombia, in close proximity to our Niscota Block, where we have announced a significant discovery with the Huron well. The acquisition also adds an ownership position in strategic infrastructure which provides a key competitive advantage. The size of the deal is very manageable for Talisman and allows us to preserve a strong balance sheet and maintain spending flexibility."

The Acquisition

These are high quality assets, with exploration and development upside. Most of the acreage is in close proximity to existing Talisman blocks. Talisman will now have a position along most of the under-explored foothills trend.

The transaction includes BPXC's interests in the Tauramena (31%), Rio Chitamena (31%), Recetor (50%) and Piedemonte (50%) association contracts. BPXC also holds a 40.56% interest in the RC4 and RC5 exploration blocks offshore Cartagena. The transaction also includes BPXC's interests in the Cusiana gas processing facility and interests in four pipelines, totaling some 1,600 kilometres of crude and 400 kilometres of gas pipelines, including a 24.8% interest in the OCENSA crude oil pipeline. Talisman will hold a 49% indirect interest.

Producing fields on the licenses include the Cusiana oil and gas field, and the Pauto and Floreña fields. Short-term activity is expected on the under-developed Pauto gas condensate field, and the Floreña oil field on the Piedemonte block. BPXC's interest in the Pauto field may extend onto Talisman's Niscota block, which contains the Huron gas condensate discovery. Ecopetrol have an existing interest in these two blocks and have completed the majority of development planning.

BPXC currently have 470 employees, and it is expected that the majority of these will transfer with BPXC to the new owners. Talisman and Ecopetrol are pleased to welcome these experienced staff members.

The transaction adds immediate production and cash flow to Talisman's Latin American asset base. Current BPXC production is approximately 25,000 boe/d, of which 65% is liquids production. Liquids production is exported or sold to domestic refineries and the natural gas production is sold domestically.

Talisman estimates 2P reserves for BPXC, before royalties, of 123 mmboe, with proved reserves of 95 mmboe (~60% oil and liquids). Net of royalties, these numbers are 98 mmboe (2P reserves) and 75 mmboe (proved reserves). Talisman's indirect interest will be 49%.

The acquisition includes an interest in strategic infrastructure, providing access to export markets. The transaction includes an interest in the OCENSA pipeline, which is critical to moving production from the Llanos basin to the Coveñas Terminal on the coast. Current capacity on the pipeline is approximately 450,000 bbls/d.

The pipeline is currently running at capacity and an ownership position will provide strategic egress, with liquids volumes in Colombia expected to rise. Transport via pipeline offers significant cost savings compared to trucking.

The transaction metrics are attractive. After deducting the value of non-reserve assets, the BPXC transaction implies metrics of approximately US$40,000/boe/d and less than US$9.00/boe 2P reserves before royalties.

Colombia has significant exploration potential, a rapidly growing hydrocarbon sector, and an attractive fiscal regime. This is an under-explored world-class basin with significant yet-to-find oil potential.

Oil production in Colombia averaged 680,000 bbls/d in 2009, an increase of 13% over the previous year, and is expected to exceed 800,000 bbls/d in 2011 (EIA estimates). In the recent 2010 open bid round, over 200 bids were submitted on 80 blocks, with more than 30 successful bidders.

The fiscal terms are attractive, particularly given the resource potential in the country. Royalties are approximately 20%, with an income tax rate of 33%.

Talisman in Colombia

Talisman has been in Colombia for a decade, although the company has significantly expanded its exploration footprint in the country over the past two years, adding substantial amounts of acreage and drilling a number of successful exploration wells. The company opened an office in Bogota in late 2008 and currently has over 30 employees in Colombia. Talisman will continue to maintain a separate office in Bogota to run its ongoing activities.

Talisman currently holds interests in 14 blocks (prior to this transaction) totaling 5.2 million net acres. The acquisition of BPXC adds an additional 330,000 net acres adjacent to Talisman's foothills acreage.

Talisman's other interests in Colombia include:

Interests in three blocks (290,000 net acres) in the Foothills trend which contains the announced Huron discovery.
Five blocks (450,000 net acres) in the Foreland basin, where the recent Chiriguaro discovery was made.
Three blocks (3.9 million net acres) in the heavy oil trend, where a recent stratigraphic test at Guairuro-1 confirmed oil.
Recent award of three blocks (500,000 net acres) in the Putumayo basin.
Goldman, Sachs & Co. advised on the transaction.

Hess Corporation (NYSE: HES) and American Oil & Gas Inc. (NYSE-AMEX: AEZ) jointly announced today that Hess has agreed to acquire American Oil & Gas pursuant to a merger agreement approved by the Boards of Directors of both companies in an all-stock transaction. The acquisition will increase Hess' strategic acreage position in the Bakken oil play in North Dakota by approximately 85,000 net acres.

Under terms of the agreement, Hess has agreed to issue 0.1373 shares of its common stock in exchange for each outstanding share of American Oil & Gas' common stock. This represents a 9.4 percent premium to American Oil & Gas stockholders based on the closing stock prices of Hess' and American Oil & Gas' shares on July 27, 2010. It is expected that Hess would issue approximately 8.6 million shares for all outstanding American Oil & Gas shares and options on a net settlement basis. The merger agreement provides for a possible cash dividend to American Oil & Gas' stockholders to the extent of American Oil & Gas' positive working capital as of the closing date (subject to certain adjustments that are described in the merger agreement) and subject to available cash. Hess has committed (subject to the terms and conditions of a customary commitment letter) to provide American Oil & Gas with a $30 million working capital credit facility to help finance American Oil & Gas' planned exploration and production activities and other working capital needs prior to the closing of the transaction.

"This acquisition builds upon our strong land position in the Bakken, leverages our nearby infrastructure and offers operational synergies," said Greg Hill, President of Worldwide Exploration and Production at Hess.

"We believe this transaction captures the value that we have been able to create since our initial entry in the North Dakota Bakken play four years ago," said Pat O'Brien, CEO of American Oil & Gas. "We are excited about the leverage our stockholders will gain not only to Hess' compelling Bakken position and developmental activities, but also to Hess' large and diverse global project portfolio."

The transaction is subject to customary closing conditions, including approval of American Oil & Gas' shareholders. Holders of approximately 20.5 percent of American Oil & Gas common stock have agreed to vote their shares in favor of the merger. Completion of the transaction is expected in the fourth quarter of 2010. In connection with the transaction, Goldman, Sachs & Co. is acting as financial advisor to Hess, and Tudor, Pickering, Holt & Co. Securities Inc. is acting as financial advisor and provided a Fairness Opinion to American Oil & Gas. Legal counsel is being provided by White & Case LLP for Hess, and Patton Boggs LLP for American Oil & Gas.

BP announced today that it has entered into several agreements to sell upstream assets in the United States, Canada and Egypt to Apache Corporation. The deals, together worth a total of $7 billion, comprise BP’s Permian Basin assets in Texas and south-east New Mexico, US; its Western Canadian upstream gas assets; and the Western Desert business concessions and East Badr El-din exploration concession in Egypt.

The decision to make these divestments follows the announcement made by BP last month that it was increasing its target for divestments to $10 billion. The proceeds of the sales will be used by BP to increase the cash available to the group.

BP Chairman, Carl-Henric Svanberg, said: “Over the last two months the Board has considered BP’s options for generating the cash necessary to meet the obligations likely to arise from the Gulf of Mexico oil spill. BP has an extremely strong asset base which is diversified geographically as well as by asset class. The Board believes that there are opportunities to divest assets which are strategically more valuable to other parties than they are to BP. Today’s announcement is the first such transaction and meets the value and strategic criteria of both parties.”

BP group chief executive Tony Hayward said: “We have achieved an excellent price for a set of properties that are worth more to others than to BP. This is a good first step which underlines our ability and determination to get maximum value for everything we sell.”
“This transaction provides a sustainable growth platform for Apache’s onshore North America operations as well as strategic infrastructure and exploration potential in Egypt,” said G. Steven Farris, Apache’s chairman and chief executive officer. “We appreciate the opportunity and the professional manner in which BP employees conducted themselves. Their cooperation was a key ingredient for this transaction to come together.”

The aggregate proceeds for the deals is $7 billion, subject to customary post-completion price adjustments, such proceeds to be paid in cash. Each sale will take place through a separate agreement between BP and Apache, and none of the sales will be conditional on completion of any of the other sales occurring. Although each of the transactions is subject to certain regulatory approvals (as described in more detail below), it is expected that they will all be completed during the third quarter of 2010.

Apache is due to pay BP a cash deposit of $5 billion in aggregate on 30 July 2010. The deposit is split $3.25bn for Canada, $1.5bn for Permian and $0.25bn for Egypt. For the sale of the Western Canadian upstream gas assets, the relevant BP selling entity shall issue a convertible debenture in favour of Apache in an amount equivalent to the sale price for such assets. The debenture will automatically exchange for the assets that are sold to Apache on closing of the transaction.

For each sale, in the event that any third party exercises any pre-emption rights over any asset being sold, the relevant price payable by Apache will be correspondingly reduced to take into account that it will not acquire such asset and the proceeds for the sale of such asset will instead be received by BP from the third party. For the sale of the Western Canadian gas assets, any such pre-emption exercise will adjust the amount of the convertible debenture accordingly and require a corresponding portion of the $3.25bn deposit to be repaid to Apache.

For each sale, in the event that the necessary regulatory approvals are not obtained by a certain date (for the Permian Basin assets sale this is 29 October 2010; for the Western Canadian gas asset sale this is 31 January 2011; and for the Egyptian asset sale this is 19 July 2011), BP will be required to repay the relevant deposit to Apache or, in the case of the Western Canadian gas asset sale, the convertible debenture. BP plc. has guaranteed such repayment obligations.

The aggregate replacement cost profit (before interest and taxation) attributable to the assets to be sold in these deals for the year ended 31 December 2009 was US$166 million. The aggregate value of the gross assets (net of accumulated depreciation) to be sold in these deals as at 30 June 2010 was US $3,085 million (with a net book value of tangible and intangible assets included in this number as of this date of US$ 2,998 million).

Sale of Permian Basin assets in Texas and south-east New Mexico

The total consideration payable for the Permian basin assets is US$3.10 billion, subject to customary post-completion price adjustments.

The ten Permian Basin fields are: Block 31, Empire/Yeso, SELea, Brown Bassett, Block16/Coy Waha, Spraberry, Wilshire, North Misc, Pegasus, Delaware Penn in Texas and south-east New Mexico. Included in the sale of such interests are the two BP-operated gas processing plants at Block 31 and Crane and non-operated interests in the Terrell gas processing facility. Net production from these assets are approximately 15,100 barrels of liquids per day and 80 million cubic feet of gas per day. Approximately 126 million barrels of oil equivalent of net proved reserves and 148 million barrels of oil equivalent of net resources are associated with these assets.

Sale of Western Canadian upstream gas assets

The total consideration payable for the Western Canadian gas assets is US$3.25 billion, subject to customary post-completion price adjustments. Approximately 214 million barrels oil equivalent of net proved reserves and 1,368 million barrels oil equivalent of net resources are associated with these assets.
The upstream Western Canadian gas business has net production of 240 million cu ft of gas per day and 6,500 barrels of liquids per day. The producing assets that are included, both operated and non operated, are managed by the following Operating Areas: Noel, Ojay, Chinchaga, Wapiti, Fox Creek, Edson, Marten Hills, South West and St. Lina. Also included is the proposed Mist Mountain coal bed methane project.

Sale of Western Desert business concessions and East Badr El-din exploration concession in Egypt

The total consideration payable for the Western Desert business concessions and East Badr El-din exploration concession is US$0.65 billion, subject to customary post-completion price adjustments.

In Egypt, the net production of the assets being sold is approximately 6,016 barrels of oil per day and 11 million cubic feet of gas per day. Approximately 20 million barrels of oil equivalent of net proved reserves and 55 million barrels of oil equivalent of net resources are associated with these assets. The sale includes the East Badr El-din concession where BP has an exploration licence with a 100 per cent interest and BP’s interests in the Western Desert business concessions.

The effective date for each of the transactions is 1 July 2010. Various governmental and regulatory consents are required for each of the transactions to complete. The sale of the Permian Basin assets in Texas and south-east New Mexico will require antitrust clearance under the Hart-Scott-Rodino Act. The consents required for the sale of the Western Canadian gas assets include Canadian antitrust approval as well as consent under the Investment Canada Act and National Energy Board approval. The sale of the Western Desert business concessions and East Badr El-din exploration concession are subject to approvals from the Egyptian General Petroleum Corporation and Egypt’s Ministry of Petroleum.
Completion of each of the sales is also subject to customary closing conditions, including that there have been no breaches of the representations and warranties given by BP for such sale that would at closing of such sale constitute a material adverse effect on the ownership, operations or value of the relevant assets.

Financing for the project comes from Nord Stream’s shareholders who are providing investment totaling 30 percent of the total project cost pro rata to their holding in the company (Gazprom 51 percent, BASF/Wintershall GmbH, 20 percent, E.ON Ruhrgas AG 20 percent and N.V. Nederlandse Gasunie 9 percent) with 70 percent project financing from the bank market . Twenty-six banks are participating in the deal underlining the attractiveness of the project during difficult market conditions. The ECAs providing cover for the deal are HERMES and SACE with support also coming from Germany’s untied loan guarantee scheme: the amount covered by such agencies totals approximately 3.1 billion euros. Nord Stream will be approaching the financial markets for the financing of Phase II in 2010.

The positive response from lenders has meant that Nord Stream was approximately 60 percent oversubscribed for the 3.9 billion euros funding. Nord Stream has RBS, Commerzbank and Société Générale acting as financial advisers. Unicredit have a limited advisory role in connection to the untied loan programme of the German government. White & Case are acting as legal advisers to Nord Stream while Clifford Chance acts for the lenders.

According to Matthias Warnig, Managing Director of Nord Stream: “It is clear from Phase I financing that investors see Nord Stream as an excellent investment opportunity. We sincerely thank them for their constructive support which brings us another step closer to realising this important project. The successful conclusion of the Phase I financing demonstrates that there is genuine enthusiasm for a project that will provide Europe with another major supply route for natural gas. With construction of the first pipeline to begin in April, Nord Stream is on track to deliver gas to Europe from 2011.”

Alexey Miller, Management Committee Chairman of Gazprom said: “The completion of Phase I financing is a landmark event in the development of Nord Stream and helps take the project from concept to reality. Nord Stream solidifies the long-standing energy relationship between Russia and Europe, a relationship that has lasted nearly forty years. Gazprom is delighted to be part of a venture that will provide reliable supplies of Russian energy to Europe for many decades to come.”

Dr. Bernhard Reutersberg, Chairman of E.ON Ruhrgas, stated: “The successful completion of Phase I financing demonstrates that E.ON Ruhrgas and the members of the Nord Stream consortium continue to be seen as reliable partners, especially in difficult economic times. By attracting 70 percent of the project’s costs through external financing, Nord Stream has demonstrated that it meets the high requirements of banks for stable commercial projects.”

According to Dr. Rainer Seele, Chairman of Wintershall/BASF: “Nord Stream is the best anti-freeze agent for Europe. It will secure substantial energy supply to Europe for a significant period of time. With its excellent CO2 values and its ability to be stored, gas is the only fossil fuel with a climate-friendly future and a natural partner of renewable energies with fluctuating production like wind and sun.”

Marcel Kramer, Chairman and CEO of Gasunie said: “Gasunie welcomes the completion of Phase I financing. Nord Stream is a vital additional route for the delivery of substantial quantities of natural gas. The project will enable consumers in many parts of Europe to continue to benefit from natural gas, the cleanest fossil fuel. Nord Stream really contributes to a sustainable future.”

The pipelaying of the first line of Nord Stream will start in April 2010 with the Castoro Sei pipelay vessel operating from this date. The Solitaire pipelay vessel will begin to lay pipe on the same line in September 2010. It is planned that construction of the first line will be completed in 2011 with construction on the second parallel line scheduled to begin in 2011 and finishing in 2012.

The twenty-six banks participating in the deal are:

• Banco Bilbao Vizcaya Argentaria S.A. (BBVA)
• The Bank of Tokyo-Mitsubishi UFJ, Ltd.
• BayernLB, London Branch
• BNP Paribas SA
• Caja Madrid
• Commerzbank AG
• Crédit Agricole CIB
• Credit Suisse AG
• Deutsche Bank AG
• Dexia Credit Local
• DZ BANK AG Deutsche Zentral-Genossenschaftsbank, Frankfurt am Main
• Espirito Santo Investment
• Fortis Bank Nederland
• ING Bank N.V.
• Intesa SanPaolo
• KfW IPEX-Bank
• Mediobanca
• Natixis
• Nordea Bank
• Raiffeisen Zentralbank Oesterreich AG
• The Royal Bank of Scotland
• Société Générale
• Standard Bank Plc
• SMBC Europe Ltd.
• UniCredit Group
• WestLB AG

Original Story

The project is planned to increase oil production and recovery from the ACG field through a new offshore facility between the existing Deepwater Gunashli (DWG) and Chirag-1 platforms. First oil from the Chirag Oil Project, the latest stage in ACG’s development stretching back more than 15 years, is expected in late 2013, and the COP development will allow recovery of an additional 360 million barrels of oil in total.

Original Story

Original Story

ConocoPhillips [NYSE:COP] today announced 2009 preliminary net proved reserve additions of approximately 1.216 billion barrels of oil equivalent (BOE), including equity affiliates. The company’s reserve replacement ratio was 141 percent, based on 865 million BOE of production, including fuel gas. ConocoPhillips’ total proved reserves at year-end 2009 were 10.326 billion BOE.

“Our strong reserve replacement ratio was achieved by progressing major projects during 2009,” said John Carrig, president and chief operating officer. “Our reserve replacement ratio also benefited from the addition of Syncrude oil sands mining operations and net reserve additions from our LUKOIL Investment segment.”

Year-end proved reserves include 248 million barrels associated with the company’s Canadian Syncrude operations, now required under recent changes in the U.S. Securities and Exchange Commission (SEC) regulations. The company’s organic reserve replacement ratio, excluding Syncrude as well as sales and acquisitions, was 110 percent.

Costs incurred for 2009 are $10.936 billion, resulting in finding and development costs for the year of $8.94 per BOE. The company’s five-year average reserve replacement was 145 percent and its five-year average finding and development cost per BOE was $13.57. The company will provide additional details on its 2009 proved reserves in its Annual Report on Form 10-K, expected to be filed with the SEC in late February.

IRVING, Texas(BUSINESS WIRE1)Exxon Mobil Corporation (NYSE:XOM) and Petrobras announced today that an ExxonMobil affiliate signed an agreement with a Petrobras affiliate and the Turkish National Oil Company (TPAO) to explore for hydrocarbons in the deepwater Black Sea offshore Turkey.

“We are pleased to add this prospective acreage to our global portfolio and expand our presence in the deepwater Black Sea”
Under the terms of the farm-in agreement, ExxonMobil Exploration and Production Turkey B.V. will acquire a 25 percent interest in the Sinop, Ayancik and Çarşamba sub-blocks of the AR/TPO/3922 exploration license. Petrobras will retain a 25 percent equity interest in the block and will remain the operator. TPAO holds the remaining 50 percent interest.

"We look forward to utilizing the technologies and expertise of all three companies as we explore for potential commercial resources in the Black Sea," said Mehmet Uysal, CEO of TPAO.

"We are pleased to add this prospective acreage to our global portfolio and expand our presence in the deepwater Black Sea,” said Russ Bellis, exploration director, ExxonMobil International Limited.

This agreement covers approximately 7.4 million acres and is subject to approval by the Turkish Government.

The announcement builds on an agreement2 signed between ExxonMobil and TPAO in November 2008 to jointly explore deepwater prospects in the Samsun block of AR/TPO/3922 exploration license and the eastern portion of AR/TPO/3921 exploration license in the Black Sea.

Original Story

McMoRan’s Co-Chairman, James R. Moffett, said: “Davy Jones log results confirm our
geologic model and indicate that the previously identified sands in the Wilcox section on this
large ultra-deep structure encompassing four OCS lease blocks (20,000 acres) provides
significant additional development potential which, upon confirmation development drilling,
could make Davy Jones one of the largest discoveries on the Shelf of the Gulf of Mexico in
decades. The geologic results from this well are important and are redefining the subsurface
geologic landscape below 20,000 feet on the Shelf of the Gulf of Mexico. The results from this
well will be incorporated into our models as we continue to define the potential of this
promising new exploration frontier.”

McMoRan plans to deepen the well to 29,000 feet to test additional objectives.

McMoRan is one of the largest acreage holders on the Shelf of the Gulf of Mexico and onshore in the Gulf Coast area with rights to approximately one million gross acres including 150,000 gross acres associated with the ultra-deep gas play below the salt weld. Prospects on this acreage have multi-Tcfe gross unrisked potentials and target objective sections on the Shelf in the Miocene and older age sections that have been correlated to those productive sections seen in deepwater discoveries by other industry participants.

McMoRan operates the Davy Jones prospect and is funding 25.7 percent of the exploratory costs and holds a 32.7 percent working interest and 25.9 percent net revenue interest. Other working interests owners in Davy Jones include: Plains Exploration & Production Company (NYSE: PXP) (27.7%), Energy XXI (NASDAQ: EXXI) (15.8%), Nippon Oil Exploration USA Limited (12%), W.A. "Tex" Moncrief, Jr. (8.8%) and a private investor (3%).

Original Story pdf

- Capital spending of $5.2 billion, an increase of greater than 10% over 2009, funded by operating cash flow, expected asset sales and Talisman's balance sheet strength. Approximately $300 million of the capital budget consists of non-cash items.

- Expected production relatively unchanged from 2009, excluding 2010 asset sales. The company is improving the quality of its portfolio as it cycles capital into assets with the potential for higher returns and higher growth.

- Spending $1.6 billion on North American shale properties. Within the Pennsylvania Marcellus and Montney shale plays, development drilling is expected to more than double. Talisman will also spend $270 million on conventional properties.

- Examining the sale of a significant amount of non-core conventional assets in North America, depending on market conditions. These assets are currently producing approximately 40,000 boe/d.

- Development spending of $800 million in the UK, including the Auk North, Auk South and Burghley development projects. The company plans to spend $550 million cash (plus an additional $300 million in non-cash spending) on development projects in Norway with the Yme field redevelopment and infill drilling at Varg, Gyda and Brage.

- $780 million of development spending in Southeast Asia with new oil field developments in Vietnam and Australia, as well as development drilling and platform upgrades in Malaysia.

- $700 million of international exploration spending, with key wells in South America, the Middle East and Southeast Asia. We expect to drill four onshore wells in Papua New Guinea (PNG) this year, including a development well.

- An additional $190 million for development in the rest of world and for other projects.

The company expects that finding and development (F&D) costs will fall in 2009 and again in 2010. Talisman plans to issue its year end 2009 results on February 10, 2010.

"Our main priority in 2010 will be continuing the portfolio transition, in particular ramping up development of the Marcellus and Montney shale plays," said John A. Manzoni, President and CEO. "We will also be examining for sale additional non-core conventional assets in North America and continue to enhance our international exploration portfolio and capabilities as we build on last year's success.

"The second priority will be to continue the focus on returns and profitability. We expect returns to increase as we successfully cycle capital into higher value investments, which should also lead to continued improvement in our F&D costs. We have put processes in place to manage our capital programs more efficiently; we are reviewing costs across the organization, and implementing performance management tools throughout the business.

"Third, we will continue to build our organizational capability. Our executive team was strengthened last year with the addition of Paul Smith, Richard Herbert and Nick Walker at the executive level, as well as significant new talent across the organization, including new country managers for Malaysia and PNG. We will continue to upgrade our capabilities and processes, and develop our talent across the organization in 2010.

"There are a number of key outcomes from our 2010 plan.

"We will maintain balance sheet strength and flexibility. The $4.9 billion in cash spending will be funded from operating cash flow, non-core asset sales and balance sheet strength. We have designed the program to be robust at US$60/bbl oil prices and US$3.50/mmbtu natural gas prices, with considerable flexibility to adjust the capital program up or down in light of conditions throughout the year. We will also remain vigilant for strategic acquisition opportunities.

"The capital program has a strong development bias, with approximately 85% directed towards development programs and 15% towards international exploration. Within the development portfolio, 36% has been allocated towards shale programs in North America, 19% for Norway, 18% for the UK, 18% for Southeast Asia, 6% for North American conventional gas and 3% for the rest of world.

"North American shale emerges as the main near term production growth engine. Talisman expects to spend $1.6 billion on shale programs this year, similar to last year, although 2009 included substantial amounts for strategic land acquisitions. This year, spending on land will be significantly less.

"Having built an inventory of 10 years worth of shale gas drilling locations, this year the focus will shift to commercial development and drilling. Drilling in the Marcellus and Montney shale plays is expected to more than double, from roughly 70 development and pilot wells in 2009 to over 200 this year.

"In the Marcellus, we will gradually increase from the current six rigs, up to 10 by year end. We expect to exit 2010 producing between 250-300 mmcf/d, up from 65 mmcf/d at the end of 2009. In the Montney, we expect to drill 35-40 horizontal wells, starting commercial development in the Greater Cypress and Farrell areas. In Quebec, we will test our first horizontal pilot well, which was drilled in 2009, with plans for two additional horizontal wells this year.

"We expect to spend $270 million on core conventional properties in Canada. However, we are also examining for sale, additional non-core pieces of our conventional business in 2010 in order to provide funds for reinvestment and shift our North American base towards the shale business, which within our portfolio, generates higher returns.

"The plan for the North Sea is to establish the region as a stable, cash generating business through the medium-term. Almost half of the $800 million in UK development spending in 2010 is slated for the Auk North and Auk South field developments. There are also significant expenditures planned for Claymore, Blake and Burghley. In addition, we are evaluating development options for the Godwin, Cayley and Shaw discoveries.

"In Norway, the majority of the $550 million cash development budget is directed at bringing the Yme field onstream, with first oil expected in the second half of 2010. Talisman also plans to drill additional infill wells at Brage, Gyda and Varg.

"Southeast Asia will continue as a growth area with significant upside from exploration. The $780 million development program includes HSD/HST field development in Vietnam, ongoing development drilling and platform upgrades in Malaysia and the Kitan oil field development in Australia.

"Exploration activity in 2010 includes potential high-impact wells in Colombia, Peru, the Kurdistan region of northern Iraq, Indonesia and PNG. In addition, we are drilling exploration wells in Malaysia and the North Sea, including a well to appraise last year's Grevling discovery in Norway.

"Production in 2010 is expected to be broadly the same as 2009 at around 425,000 boe/d, excluding any sales in North America during the year. Gains in shale volumes and from Southeast Asia offset declines in North American conventional production and the UK. However, actual 2010 production volumes will depend on the outcome of our divestment program in North America.

"While the underlying production volumes will be flat again in 2010, the quality of the portfolio will be improving as we cycle capital into higher return, higher growth parts of the portfolio.

"The new portfolio direction is clear. New investment patterns have been established for North America shale, strategic exploration and the North Sea. We will continue to upgrade the quality of our portfolio and build our organizational capability. Underpinning it all, of course, is high quality execution and delivering on our promises, which is imperative. With successful asset sales, we expect to have rebased the company by the end of this year, set to drive sustainable and visible growth from that point forward."

North America

In North America, Talisman's objective is to become a leading, returns based, shale gas producer. The company plans to spend $1.9 billion in 2010, of which, approximately $1.6 billion (85%) has been allocated toward shale programs, primarily in the Pennsylvania Marcellus and Montney.

This is roughly comparable to the amount Talisman spent on shale plays last year; however, the total in 2009 included significant spending on shale land acquisitions. As a result of these purchases, Talisman has a 10 year drilling inventory (4,800 net drilling locations) on Tier 1 acreage within its Pennsylvania Marcellus and Montney shale plays. The amount of anticipated spending budgeted for land is significantly lower this year as the focus shifts to drilling.

In the Pennsylvania Marcellus play, we have budgeted close to $1 billion, ramping up to 10 rigs (currently six) over the course of 2010. The plan is to drill 170 net wells in the Marcellus this year (up from 53 in 2009), with about 145 wells completed and tied-in. We expect to exit 2010 at between 250-300 mmcf/d, up from 65 mmcf/d at the end of 2009. Plans are built on an expected ultimate recovery per well of 3.5 bcf, with 30 day initial production rates of 3 mmcf/d. The majority of Marcellus wells have been permitted and the company has secured sufficient egress capacity, water access and disposal for its 2010 plans.

In the Montney shale, Talisman is moving the Farrell Creek and Greater Cypress areas into commercial development with approximately 25 horizontal development wells expected in 2010 (with plans to complete 17 of these during the year). In addition, we expect to drill 10-15 Montney shale pilot wells, including our first multi-lateral, as we continue to delineate this large play. The company will expand from three rigs to as many as nine by the end of the year, spending approximately $550 million.

We expect to exit the Montney shale in 2010 at between 40-60 mmcf/d, based on expected ultimate recoveries of around 5 bcf per well and 30 day initial production rates of 4.5 mmcf/d.

In Quebec, Talisman will complete the horizontal well started in 2009, with an additional two horizontal wells planned for this year, to further de-risk the play.

The company also plans to spend approximately $270 million on conventional programs in 2010. A significant portion of this will be focused on Chauvin oil development, with much of the remainder spent on high return, tight gas drilling in the Ojay and Wild River areas.

The company is examining the sale of a number of gas-weighted properties, which currently produce approximately 40,000 boe/d. Although these are high quality assets, they cannot effectively compete for capital within Talisman's portfolio.

North Sea

Capital spending in the North Sea is budgeted at $1.8 billion in 2010. Of the total, $160 million (9%) is being directed towards exploration. The plan also includes $300 million of non-cash capital spending (capitalized leases) in Norway.

Major projects in the UK include the Auk North project (first production 2011), the Auk South project (first production 2012) and the Burghley development (first production late 2010). We are completing a well north of Tweedsmuir to test a northern extension of the field. We also have a full year of mobile exploration and development drilling planned. The company also expects to restart development drilling in Claymore and begin the first phase of an upgrade project to the Claymore compressors, which should improve field reliability.

Development planning will commence for the recent Cayley, Shaw and Godwin discoveries, which will be linked to an upgrade of the Montrose/Arbroath facilities.

In Norway, activities will focus on bringing the Yme redevelopment project onstream, with first oil expected in the second half of 2010. There is also a 10 well development program planned for the Varg, Gyda and Brage areas.

Southeast Asia

Talisman plans to spend $1.1 billion in Southeast Asia in 2010, with exploration spending accounting for $280 million, or 26% of the total.

Major activities include a 16 well infill drilling program at PM-3 CAA in Malaysia/Vietnam, platform upgrades and planning for the phase 2 incremental oil recovery project.

The company is also anticipating approval for its offshore HSD/HST oilfield developments in Vietnam, with significant capital spending this year. Similarly, development of the Kitan discovery offshore Australia is also expected to start this year. The company expects to start development drilling in PNG, with an early condensate recovery scheme in one of the blocks acquired last year.

International Exploration

The international exploration budget for 2010 is $700 million, with two-thirds allocated to build new core areas and one-third to support existing core areas. The goal of the program is to add 600-650 million boe of prospective resource additions over the next five years at a finding cost of less than $5/boe.

In Southeast Asia, Talisman will commence the Makassar Strait drilling program in Indonesia with two wells in the Pasangkayu block and will acquire seismic in the Andaman III block. In Malaysia, we will drill a deep exploration well in the PM-3 block and reprocess seismic over the two Sabah exploration blocks awarded in late 2009. In PNG, the company plans to acquire 1,000 kilometres of 2D seismic and drill four onshore wells.

Following the successful Situche appraisal well in Block 64 in Peru, the company plans to drill the Runtasapa exploration well in adjacent Block 101. In Colombia, Talisman is currently drilling one exploration well, with another planned for later in the year. The company plans to commence appraisal drilling on the Huron discovery in the Niscota Block late in 2010. A number of seismic programs will also be acquired in the exploration blocks awarded in the Colombia 2008 bid rounds.

In the Kurdistan region of northern Iraq, we will finish drilling our second exploration well, Kurdamir, in Block K44 and acquire seismic data in Block 9.

In the North Sea, Talisman plans to drill one exploration well in the UK and two exploration wells in Norway. The 2009 Grevling discovery in Norway will be appraised.

Original Story

A consortium agreement concluded by OMV’s two core shareholders Österreichische Industrieholding AG (ÖIAG) representing the Austrian state and IPIC provides for their coordinated behavior and for restrictions on shareholdings.

ÖIAG and IPIC now hold 154,550,263 shares (51.5% of the registered capital). The registered capital of OMV consists of 300,000,000 shares whereof 1,219,695 treasury shares held by OMV are not entitled to vote thus resulting in a total of 298,780,305 voting rights. Other than treasury shares one share equals one voting right. Therefore 154,550,263 shares/voting rights represent 51.7% of all voting rights.

Link

Calgary, Alberta - Shell Canada Products (Shell) announced today that a decision was made to undertake steps towards the conversion of its 130,000 barrels per day Montreal East Refinery to a terminal to receive gasoline, diesel and aviation fuels, which will continue to be distributed via Shell’s nearby Montreal terminal.
After reviewing a number of options for the Montreal East Refinery, Shell concluded the facility, founded 75 years ago, no longer fits with Shell’s long-term strategy.
“This difficult decision was made after extensive deliberation. We appreciate the decision impacts employees and their families and we certainly intend to support them throughout the process,” said Christian Houle, General Manager for Shell’s Montreal East Refinery
As more becomes known in the coming months about the overall plans for conversion to a terminal, employees, media, government officials and other stakeholders will be kept informed throughout the process. For the time being, it remains business as usual for our refinery operations.
“During the process, we will continue to provide our customers with our usual high level of service and quality products. Safety of our employees and regulatory compliance in our operations remains our number one priority,” said Lorraine Mitchelmore, Shell Canada President and Country Chair.

Original Story

"We are pleased to have Nippon Oil as a customer of the Gorgon Project. The agreement is another step towards commercializing our equity natural gas in Australia."

John Gass, president, Chevron Global Gas, said "We have a long history of working with Nippon Oil and, with this agreement, are proud to add a new dimension to that relationship."

Gass added that, "Our agreements with Nippon Oil and other leading Japanese and Korean energy companies demonstrate that Chevron is strongly positioned to meet long-term demand growth in Asia-Pacific."

Chevron is the operator of the Gorgon Project and holds an approximate 47 percent interest.

The initial Gorgon Project development, in northwestern Australia, will include a three-train, 15 million-metric-tons-per-year liquefied natural gas facility and a domestic gas plant.

Chevron Corporation is one of the world's leading integrated energy companies, with subsidiaries that conduct business worldwide. The company's success is driven by the ingenuity and commitment of approximately 62,000 employees who operate across the energy spectrum. Chevron explores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and other energy products; manufactures and sells petrochemical products; generates power and produces geothermal energy; provides energy efficiency solutions; and develops the energy resources of the future, including biofuels and other renewables. Chevron is based in San Ramon, Calif. More information about Chevron is available at www.chevron.com.

Average drilling rigs operating reported in the Company's monthly announcements represent the average number of the Company's drilling rigs that were operating under a drilling contract. The Company cautioned that numerous factors in addition to average drilling rigs operating can impact the Company's operating results and that a particular trend in the number of drilling rigs operating may or may not indicate a trend in or be indicative of the Company's financial performance. The Company intends to continue providing monthly updates on drilling rigs operating shortly after the end of each month.

The Russian-British company TNK-BP is going to increase its oil production in the framework of the Uvat project in 2010 by 37%, compared to 2008, up to 4 mln tons, the press service of the company quoted the words of Andrei Rublev, General Director of TNK-Uvat. Mr. Rublev said that commercial development of two new fields of the Uvat group – the Urnenskoe and Ust-Tegusskoe fields was started in early February 2009.“Thus, we added two more fields to the Kalchinskoe field, which so far was the only producing field in the Tyumen Region, and produced 2 mln tons of oil in these new fields.

For those worried about the current slow down in investment, this is a reminder of the reality.

The company's increases are based on investments already done. The dearth of investment will cause problems in the future, not today.