EnQuest Lowers Production Target for 2011

- EnQuest Lowers Production Target for 2011

Friday, September 02, 2011
EnQuest plc

EnQuest updated its production targets for the full year 2011. The S7 production well in the Conrie field, discovered earlier this year, and the S8Z well in area 6 of the Don Southwest field both started production during August 2011. The S7 Conrie well came on production at lower than expected rates. The S8Z well started production at the expected initial rate, but has declined more quickly than anticipated. EnQuest is in the process of testing and assessing the well results. EnQuest does not expect a material change in ultimate recovery of reserves in the Don Southwest field and is studying whether a further well or sidetrack is needed.

As a result of the production uncertainty on both wells, EnQuest expects average production for the full year 2011 in a range between 23,000 Boepd to 24,500 Boepd.

Alma Development Project

EnQuest has submitted the first draft of the proposed Field Development Plan ('FDP') for the Alma (formerly Ardmore) Development in the Central North Sea. This first draft FDP has been submitted to DECC specifically for the Alma field, with a separate FDP to follow shortly for the Galia (formerly Duncan) field; final approval of these FDP's is anticipated in time for full project sanction before year end. If approved, the project is scheduled to start production in the second half of 2013; peak production is expected to be in excess of 20,000 Boepd. EnQuest is looking forward to being in a position to provide full details on the Alma and Galia development project following full project sanction.

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Halliburton Planning To Hire 11,000 In 2011

- Halliburton Planning To Hire 11,000 In 2011



Aug 25, 2011

Halliburton (NYSE:HAL) plans to hire 11,000 workers in North America in 2011, according to a top executive who told Jim Cramer on CNBC's Mad Money on Wednesday.

The president of the Western Hemisphere, Jim Brown said many of the new hires will be sent to North Dakota's oil-rich Bakken shale, which is one of the largest oil finds in the U.S.

Brown commented, "If you have a willingness to work and an aptitude to learn with a high school education, within a year-and-a-half to two years, you can become a front-line supervisor. That job will pay $125,000 to $130,000 a year. It's a tremendous opportunity. You gotta come to North Dakota, but what we're doing here, we're replicating across the nation."

Halliburton (NYSE:HAL) has a potential upside of 79.6% based on a current price of $40.27 and an average consensus analyst price target of $72.31.

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Statoil Unlocks Third Gullfaks Discovery in 2011

- Statoil Unlocks Third Gullfaks Discovery in 2011

Wednesday, August 24, 2011
Statoil
by SubseaIQ

An exploration well and a sidetrack currently being completed by Statoil near Gullfaks South have yielded the third discovery made in the Gullfaks license so far this year.

"This confirms yet again that infrastructure-led exploration is important and yields highly commercial finds which can be brought on stream quickly," said Tom Dreyer, exploration head for the northern North Sea.

"We regard the area around Gullfaks South as prospective and the find confirms our faith in the area. Even though the volumes are modest compared with the large finds made off Norway earlier, this type of discovery is important for maximizing the potential on the Norwegian continental shelf, and contributes to extending the production life of installations."

The wells were intended to prove petroleum in Middle Jurassic reservoir rocks of the Brent group, and whether communication exists with the producing structures in Gullfaks South. Wells 34/10-52 A and B were drilled by Deepsea Atlantic, which will proceed to shore for modification work after completing this operation

Oil- and gas-bearing intervals were observed in the upper part of the Brent group along both well paths, and a column about 120 meters thick with good reservoir quality was proven.

No hydrocarbons were found in the lower Brent group. The wells have not been formation tested, but data were collected and cores taken to determine the hydrocarbon system and contacts.

Preliminary calculations indicate that 3 to 9.5 million barrels of recoverable oil equivalent are present, which are planned to be tied back to existing infrastructure in the Gullfaks area.

The two other discoveries made so far this year in the Gullfaks license are Rutil and Opal.

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Exoma Starts Drilling 5th Well in 2011 Exploration Campaign

- Exoma Starts Drilling 5th Well in 2011 Exploration Campaign

Monday, August 22, 2011
Exoma Energy Ltd.

Exoma announced that the fifth well of its 2011 exploration campaign, Katherine-1, has spudded. The primary target of this well will be Shale Gas in the Toolebuc Formation of the Eromanga Basin in Central Queensland.

After coring the shale, this well will be deepened to test a potential conventional oil play in the underlying Hutton sandstone. The Katherine-1 oil test is a follow up to Toobrac-1, a well drilled in 1985 that discovered oil shows in a thin sand onlapping a basement high. The well is located down-dip on the structure and tests a potential thickening of the reservoir sand observed in the seismic data.

• Well Name: Katherine-1
• Permit: ATP 999P
• Location: Eromanga Basin, approx. 60km SSW of Longreach, Queensland.
• Target:
  • Primary Target: shale gas in the Toolebuc Formation. The carbonaceous Toolebuc Shale will be cored and the well logged. The shale core will be subject to laboratory analysis to identify source maturity, hydrocarbon type and content, detailed mineralogy, rock properties and permeability.
  • Secondary Target: conventional oil in the Hutton sandstone. The Hutton sandstone section will be rotary drilled and logged. If any hydrocarbons are present, the reservoir will be drill stem tested.
• Planned Depth: Toolebuc Formation 590 meters; Hutton Sandstone 1189 meters

Exoma has a 50% beneficial interest in both ATP 999P and the Katherine-1 well. CNOOC Galilee Gas is earning its participating interest by a farmin whereby CNOOC will provide the initial $50 million of joint venture expenditures on Exoma's five Gaililee Basin ATP's.

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Abraxas Looks Ahead to 'Active' 2011 Drilling Program

- Abraxas Looks Ahead to 'Active' 2011 Drilling Program

Tuesday, August 09, 2011
Abraxas Petroleum Corp.

Abraxas provided an operational update and issued production guidance for 2011.

Rocky Mountain – North Dakota / Montana

In McKenzie County, North Dakota, Abraxas drilled the Stenehjem 27-34 1H to a total measured depth of 16,504 feet, including a 5,965 foot lateral in the middle Bakken formation, and completed the well with a 17-stage fracture stimulation. The well was placed on production in late June and in 44 days the well has produced (on a restricted choke) 20,000 barrels of oil, 32.2 MMcf of wellhead gas which yields 2,700 barrels of natural gas liquids and 23.3 MMcf of residue gas for a total of 26,500 barrels of oil equivalent, or an average of 600 barrels of oil equivalent per day. For the past three days, the well averaged 615 barrels of oil equivalent per day on a 21/64-inch choke with 750 psi of flowing pressure. Abraxas owns a 79% working interest in this well.

In various counties in North Dakota and Montana, fourteen non-operated horizontal wells, targeting the Bakken or Three Forks formation, in which Abraxas owns a working interest are currently in progress or recently placed on-line. Seven gross (0.35 net) wells went on production in June or July, three gross (0.08 net) wells have been fracture stimulated and are currently cleaning up, one gross (0.36 net) well is waiting on completion, one gross (0.01 net) well is currently drilling and two gross (0.05 net) wells are waiting on a drilling rig. Since January 2010, Abraxas has elected to participate in 19 gross (1.00 net) non-operated wells in the Bakken / Three Forks play.

In McKenzie County, North Dakota, two gross (0.11 net) non-operated horizontal wells targeting the Mission Canyon have been drilled, completed and are currently waiting on production facilities. Early production testing of these wells has yielded flow rates in excess of 1,000 barrels of oil per day each.

In early July, Abraxas announced the purchase of a drilling rig that is in the process of being refurbished. After completion, the rig will be mobilized to McKenzie County, North Dakota and it is anticipated that the rig will begin drilling on the first pad site in October.

Rocky Mountain - Wyoming

In Campbell and Niobrara Counties, Wyoming, a two well oil development program is scheduled to begin this fall. One of these horizontal wells will target the Niobrara formation and one will target the Turner formation. Abraxas owns a 100% working interest in each of these wells.

South Texas – Eagle Ford

Abraxas currently owns a 41% equity interest in Blue Eagle, a joint venture between Abraxas and Rock Oil Company, LLC. On June 29, 2011, Rock Oil contributed an additional $11 million to the joint venture and Blue Eagle purchased approximately 2,487 net acres in McMullen County, Texas in the oil window of the play.

In DeWitt County, Texas, Blue Eagle's first well, the T-Bird 1H, continues to outperform expectations and is currently producing 930 barrels of oil equivalent per day, which is comprised of 185 barrels of condensate, 300 barrels of natural gas liquids and 2.7 MMcf of residue gas. The well has produced approximately 230,000 barrels of oil equivalent during its first 180 days on production. Blue Eagle owns a 100% working interest in this well.

In DeWitt County, Texas, Blue Eagle participated in a non-operated horizontal well with its 43.9% working interest. The Matejek Gas Unit 1 was drilled to a total measured depth of 17,865 feet, including a 3,600 foot lateral, and completed with a 14-stage fracture stimulation. The well is currently shut-in waiting on pipeline hookup which is expected to be completed later this month.

In Atascosa County, Texas, the Grass Farms 1H is currently drilling the lateral at a total measured depth of 13,150 feet towards a total measured depth of 13,380 feet, including a 6,000 foot lateral. A fracture stimulation date has been secured for this well in September, a month later than originally anticipated. Blue Eagle owns a 100% working interest in this well.

West Texas

In Nolan County, Texas, the Spires 126 2H was drilled to a total measured depth of 9,000 feet, including a 2,000 foot lateral, and completed open hole and un-stimulated. The well was recently placed on-line and during the first 20 days of production, the well averaged 125 barrels of oil equivalent per day, which was comprised of 47 barrels of oil, 46 barrels of natural gas liquids and 210 Mcf of residue gas. Abraxas owns a 100% working interest in this well.

In Coke County, Texas, the Sadie #2A was drilled to a total vertical depth of 6,425 feet and is waiting on completion and the Sadie #1B is currently drilling below 4,600 feet towards a total vertical depth of 6,500 feet. These two delineation wells are targeting the Canyon Sands. Abraxas owns a 100% working interest in these wells.

In Reeves County, Texas, Abraxas previously announced that it acquired an additional 640 net acres, for a total of approximately 3,000 net acres, in the emerging Wolfbone play. Two wells directly adjacent to our acreage are currently being drilled by the industry.

Canada - Pekisko

In Alberta, Canada, the Twining 6-11 was drilled to a total measured depth of 8,900 feet, including a 3,025 foot lateral, and is waiting on completion and the Twining 6-12 recently reached total measured depth of 9,150 feet, including a 3,380 foot lateral. These two wells are targeting the Pekisko formation. Canadian Abraxas owns a 100% working interest in each of these wells.

Guidance

For July, Abraxas produced approximately 4,160 barrels of oil equivalent per day up from an average of 3,845 barrels of oil equivalent per day for the second quarter. Abraxas expects production for 2011 to average 4,000 – 4,200 barrels of oil equivalent per day, including its equity interest share of Blue Eagle's production, which would generate an exit rate for 2011 between 4,700 and 4,900 barrels of oil equivalent per day.

Comments

"We've been busy! It is a refreshing change to get back to a very active drilling program. So far, we are quite pleased with the results of our operated (and non-operated) wells and we hope to continue this success throughout the year. The purchase of the drilling rig will enable us to be quite active in the Williston Basin on an operated basis and in an efficient manner for years to come," commented Bob Watson, Abraxas' President and CEO.

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ATP Sees Revenue Increase in 2Q 2011

- ATP Sees Revenue Increase in 2Q 2011

Tuesday, August 09, 2011
ATP O&G Corp.

ATP announced second quarter 2011 results.

Results of Operations

Revenues from oil and gas production were $172.9 million for the second quarter 2011, compared to $101.1 million for the second quarter 2010. Increased revenues from production were attributable to higher production volumes and higher oil prices. Oil and gas production for the second quarter 2011 was 2.1 MMBoe (23.6 MBoe/d) compared to 1.9 MMBoe (21.3 MBoe/d) for the second quarter 2010, an 11% increase. Average prices were up 68% over the same period a year ago. Oil represented 68% of total production for the second quarter 2011, compared to 48% of total production for the second quarter 2010.

ATP recorded a net loss attributable to common shareholders of $56.9 million or $(1.11) per basic and diluted share for the second quarter 2011, compared to $82.9 million or $(1.63) per basic and diluted share for the same 2010 period. The net loss attributable to common shareholders for the second quarter of 2011 was impacted by several items analysts often exclude from their published estimates. Those items include impairment expense of $45.7 million, workover expenses of $17.3 million and $1.2 million of drilling interruption costs associated with the Gulf of Mexico moratorium. Also, the items include $45.1 million related to the unrealized derivative income for the quarter. As a result of production increases and higher oil prices, ATP reduced its estimate of the time required to repay a dollar-denominated Override at Gomez. This change in estimate resulted in our recognizing $21.9 million in incremental interest expense related to this Override in the second quarter of 2011 compared to the first quarter of 2011.

The impairment expense of $45.7 million during the second quarter of 2011 related primarily to South Timbalier (“ST”) Block 77 (acquired in 2005), due to ATP's decision not to move forward with a capital expenditure on this property in the second half of 2011. The workover expense is related to the Gomez MC 711 #5 well, which was placed back on production late in the second quarter.

Capital Resources and Liquidity

In the second quarter 2011, ATP conveyed dollar-denominated Overrides and NPI's in the Gomez Hub and the Telemark Hub for net proceeds of $70.3 million. These Overrides and NPI's obligate ATP to deliver a percentage of the proceeds from the future sale of hydrocarbons in the specified proved properties until the purchasers achieve a specified return.

In June 2011 ATP closed a perpetual preferred equity offering that provided net proceeds of $123.3 million, net of discount, related option contract costs and issuance costs. Shares of the preferred are convertible into common shares at $22.20 per share.

During July 2011, ATP entered into a crude oil prepaid swap transaction for 274,500 barrels at a net price of $111.84 per barrel. ATP received $30.7 million at closing. A schedule summarizing ATP's outstanding oil and gas derivatives can be found near the end of this press release.

ATP incurred $220.5 million of capital expenditures ($209 million, excluding capitalized interest) on oil and gas properties during the first half of 2011, of which $34.8 million was funded through vendor deferral and net profit interest programs. These capital expenditures were predominantly related to the Gomez and Telemark Hubs, and the Octabuoy production platform. In the remainder of 2011, ATP anticipates incurring $250 million to $300 million in total capital expenditures, excluding capitalized interest, of which $150 million to $200 million will be contributed by vendors through existing NPI programs or deferral programs.

ATP had unrestricted cash of $185.9 million and restricted cash of $47.4 million at June 30, 2011.

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Abraxas Petroleum Announces Production And 2011 Estimates

- Abraxas Petroleum Announces Production And 2011 Estimates



Aug 9, 2011

During the month of July, Abraxas (NASDAQ:AXAS) produced 4,160 barrels of oil equivalent per day up from an average of 3,845 barrels of oil equivalent per day for the Q2.

Abraxas expects production for 2011 to average 4,000 to 4,200 barrels of oil equivalent per day, including its equity interest share of Blue Eagle's production that would generate an exit rate for 2011 between 4,700 and 4,900 barrels of oil equivalent per day.

Abraxas Petroleum (NASDAQ:AXAS) has a potential upside of 97.6% based on a current price of $3.09 and an average consensus analyst price target of $6.11.

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Double Eagle Petroleum Briefs 2011 Exploration, Development Plans

- Double Eagle Petroleum Briefs 2011 Exploration, Development Plans

Wednesday, August 03, 2011
Double Eagle Petroleum Co.

Double Eagle Petroleum announced an update to its 2011 drilling program and is providing guidance on its 2012 expected drilling programs. The Company's development program will be focusing on its two major development fields, the Atlantic Rim CBM and the Pinedale Anticline. The major exploration projects are the Niobrara oil shale target in the Atlantic Rim and the Main Fork Unit in north east Utah. Total estimated capital spending for 2011 projects will be approximately $30 million.

2011 Field Development

In 2011, the Company will be increasing its total net well count in the Catalina CBM Unit 25% by drilling approximately 14 gross (13 net) coal bed methane (CBM) wells in this unit to add to the existing 70 gross (51 net) CBM producing wells. Twelve of these wells are in an exploratory area and the Company will have a 100% working interest in these wells. The Company will have a 73% working interest in the two development wells in the existing unit participating area.

Anadarko will be drilling 25 exploration wells in the newly formed Spy Glass Unit which includes the Sun Dog and Doty Mountain participation areas. The exploration wells for 2011 were required by the Spy Glass Unit agreement. The Company will have no interest or costs associated with these wells, but the data obtained will be valuable in determining the nature and extent of the CBM field, which will aid future field development.

The approved Atlantic Rim Environmental Impact Study allows for a total 1,800 CBM wells and 200 conventional (non-coal bed methane) wells. Double Eagle, together with Anadarko Petroleum, are the operators of various units in the Atlantic Rim and as of June 30, 2011 a total of 400 CBM wells have been drilled (no conventional wells). Currently, the Company has 123 approved CBM drilling permits and Anadarko has approximately 30 approved CBM drilling permits for future drilling in the Atlantic Rim.

Also, Double Eagle will participate in the drilling of 16 (gross) new production wells in the Mesa Unit on the Pinedale Anticline, which is an increase of 10 (gross) wells from the initial estimate provided by the operator of the Mesa Units, QEP. The Company has an estimated 8.5% working interest in these planned wells.

2011 Exploration Projects

The Company also plans to drill one Niobrara Oil Shale well in which Double Eagle will have an estimated working interest of 93%. The Company initially planned two Niobrara exploratory wells but due to certain lease holders in the area not cooperating in drilling plans, the Company determined that the best location and opportunity to gain formation knowledge was to drill in a section which the Company controlled. The Company is awaiting final permit approval for this well.

The Company also is evaluating further development of the Main Fork Unit Project (formerly known as Christmas Meadows/Table Top Unit). The Company previously drilled the Table Top Unit #1 well in 2007. The Company is working with a major integrated oil and gas company that has option farm-in rights to advance further unit delineation, assist with costs related to seismic, environmental analysis and, if necessary, an exploratory well. Assuming the farm-in right is exercised; Double Eagle will have a 12%-16% working interest after payout.

Prior seismic data has been reprocessed and a LIDAR (Light Detection and Ranging) survey has been conducted. Preliminary development well locations, pipelines and roads have been identified as part of a full field development environmental impact study being conducted by the USFS. In 2011, surveying and associated archeological and biological studies are being conducted along with a source test in preparation for a potential 2D seismic acquisition program in 2012.

2012 Development Projects

Looking ahead into 2012, the Company's initial plans are to continue development in our two main fields. In the Atlantic Rim, the Company plans to drill 14 new CBM production wells in the Catalina unit, 25 new CBM wells in the Anadarko operated Doty Mountain Unit and, depending upon the results of the initial test well, several Niobrara wells. In the Pinedale Anticline, the Company anticipates 16 new wells to be drilled in 2012. The Main Fork Project is expected to proceed as mentioned above.

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Report: E&P Capital Spending to Rise 12% in 2011

- Report: E&P Capital Spending to Rise 12% in 2011

Tuesday, August 02, 2011
Rigzone Staff
by Karen Boman

Capital spending on exploration and production (E&P) by 139 publicly traded oil and gas companies is expected to rise by 12 percent to $406 billion in 2011. Spending growth this year is largely fueled by strong oil prices and builds on gains of 19 percent in 2010, according to a new report by IHS.

While the increase is less than the 19 percent increase seen last year, oil and gas companies, which spent considerably less during the economic downturn of two years ago, are continuing to increase their upstream portfolio investments, particularly for oil-weighted projects, said Aliza Fan Dutt, senior analyst at IHS and author of the IHS Herold Global E&P CAPEX Review.

"Despite recent volatility and a wobbly economy recovery, oil prices remain relatively strong, which supports higher capital spending. In addition, investments in oil and unconventionals continue at a rapid clip, which conventional gas outlays remain relatively depressed."

The shift to drilling on oil and liquids-rich properties that began in 2010 accelerated through the year and continues today, according to the report. According to Fan Dutt, "those companies that shifted their portfolios earlier will benefit more than those that moved more slowly." Fan Dutt cited EOG Resources as an example of such a company. EOG, a natural gas producer, shifted to the oil side much earlier than most of its peers. AS a result, oil now contributes 60 percent of the company's revenues; EOG is posting strong earnings growth."

"Cost inflation will continue to be a key issue, with more companies competing for oil services and equipment during a time of elevated oil prices," said Fan Dutt. "Cost containment will be particularly important for natural gas-weighted producers as they struggle to achieve strong margins amid weak natural gas prices."

Mid-size U.S. E&P companies should increase spending by 25 percent, while U.S. integrated oil companies are expected to reduce their spending rate to 14 percent this year. However, as a group, integrated oils are planning to continue their massive investments in oil and gas projects worldwide.

Marathon Oil Corp., the most aggressive of the integrated U.S. companies, is ramping up spending by 37 percent as it drills on expanded U.S. acreage in the Anadarko Woodford play, the Niobrara play in the Denver-Julesberg Basin in Colorado and Wyoming and in its Bakken shale position.

The largest North American E&Ps will increase capital outlays by only three percent, which will be buttressed by spending on unconventional resources in shale basins, according to the report. "For example, Pioneer is increasing its spending by 53 percent, with its expansive holdings in the Spraberry field and Eagle Ford shale play, where it was an early entrant."

Global integrated oil companies will continue to make massive investments in oil and gas projects worldwide with a "muted" nine percent spending increase, down slightly from last year. Canadian integrated oil companies are slightly more eager to spend with a planned increase of 13 percent. Husky Energy leads this group with a 44 percent increase on operations mainly in Western Canada and offshore Canada's east coast.

Spending by integrated oil companies outside North America is expected to rise by 13 percent in 2011, the same growth rate seen last year. IHS attributed the increase to strong spending in Latin America and Russia. Colombia's state-owned oil company Colombia will spend 56 percent more this year on top of a 34 percent increase last year. Brazil's state energy company Petrobras also continues to invest heavily on its upstream portfolio with an estimated 24 percent increase. Additionally, Russia's Lukoil is expected to spend 55 percent more this year.

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Whiting Boosts 2Q Production in 2011, Ups Capex to $1.6B

- Whiting Boosts 2Q Production in 2011, Ups Capex to $1.6B

Thursday, July 28, 2011
Whiting Petroleum Corp.

Whiting's production in the second quarter of 2011 totaled 5.84 million barrels of oil equivalent (MMBOE), of which 4.79 million barrels were crude oil/natural gas liquids (82%) and 1.05 MMBOE was natural gas (18%). This second quarter 2011 production total equates to a daily average production rate of 64,120 barrels of oil equivalent (BOE), which compared to the 64,600 BOE average daily rate in the second quarter of 2010.

After three weeks of mostly dry weather, we are making good progress fracing new wells and returning wells to production. In the Williston Basin, we reached a new production record of 58,105 BOE per day gross (31,161 net) on July 19, 2011. Our Sanish field is also coming back strong after first half 2011 inclement weather, reaching 44,102 BOE per day gross (22,817 net) on July 19, 2011.

We currently have two full-time dedicated frac crews and one half-time frac crew working in the Williston Basin and believe they are capable of fracing approximately 18 to 20 wells per month between now and year-end 2011. Therefore, we expect to reduce our current 44-well inventory of operated wells waiting on completion to below 25 by November 30, 2011. Based on our current drilling rig count of 17 rigs working in the Williston Basin, 20 to 25 wells being prepared for completion represents a typical inventory.

We have 11 service units running in the Sanish field and are making good progress in placing back into production wells that were shut-in during the inclement weather due to muddy roads. As of July 15, 2011, we had 27 wells waiting for a service unit. We expect this inventory to be eliminated by September 30, 2011

We reported in our news release of June 8, 2011, that our Seep Ridge Gas Pipeline in Uintah County, Utah was shut-in for repairs on April 16, 2011. The pipeline was back on stream June 14, 2011 and is currently at full capacity. We are transporting 21.9 million cubic feet (MMcf) of gas per day net to Whiting's interests from the Flat Rock and Chimney Rock fields.

In addition on June 8, 2011, we reported that we were experiencing under-deliveries of CO2 contract quantities from our North Ward Estes field CO2 supplier. The shortfall was approximately 25 MMcf per day below our contracted delivery volume of 134 MMcf per day. Currently, we are receiving 122 MMcf per day and expect to resume delivery of full contract quantities by September 30, 2011. Further, we have recently signed two new CO2 supply contracts for additional quantities of CO2 that we expect to be sufficient to fully execute our development plans at North Ward Estes for several years. More details are included later in this news release.

Second Quarter 2011 Financial Results

Discretionary cash flow in the second quarter of 2011 totaled a record $313.3 million, representing an increase of 37% over the $228.2 million reported for the same period in 2010. The increase in discretionary cash flow in the second quarter of 2011 versus the comparable 2010 period was primarily the result of a 29% increase in the Company's realized oil price (net of hedging), including the price of natural gas liquids (NGLs). A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.

In the second quarter of 2011, Whiting reported net income available to common shareholders of $202.9 million, or $1.73 per basic share and $1.71 per diluted share, on total revenues of $481.2 million. This compared to net income available to common shareholders of $119.9 million, or $1.18 per basic share and $1.06 per diluted share, on total revenues of $377.6 million in the second quarter of 2010.

The Company's second quarter 2011 results include after-tax unrealized derivative gains of $84.5 million, or $0.71 per diluted share. Excluding this gain and certain other items, Whiting reported second quarter 2011 adjusted net income available to common shareholders of $120.3 million, or $1.02 per basic and diluted share. This compared to second quarter 2010 adjusted net income available to common shareholders of $72.2 million, or $0.71 per basic share and $0.66 per diluted share. A reconciliation of adjusted net income available to common shareholders versus net income available to common shareholders is included later in this news release.

First Six Months 2011 Financial Results

Discretionary cash flow in the first six months of 2011 totaled $597.4 million, representing an increase of 35% over the $442.7 million reported for the same period in 2010. The increase in discretionary cash flow in the first half of 2011 versus the comparable 2010 period was primarily the result of a 23% increase in the Company's realized oil price (net of hedging), including the price of NGLs. A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.

In the first six months of 2011, Whiting reported net income available to common shareholders of $222.0 million, or $1.89 per basic share and $1.87 per diluted share, on total revenues of $913.4 million. This compared to net income available to common shareholders of $201.1 million, or $1.97 per basic share and $1.79 per diluted share, on total revenues of $728.9 million in the first six months of 2010.

Excluding after-tax unrealized derivative gains and losses and certain other items, Whiting reported first half 2011 adjusted net income available to common shareholders of $221.2 million, or $1.89 per basic share and $1.87 per diluted share. This compared to first half 2010 adjusted net income available to common shareholders of $134.7 million, or $1.32 per basic share and $1.23 per diluted share. A reconciliation of adjusted net income available to common shareholders versus net income available to common shareholders is included later in this news release.

James J. Volker, Whiting's Chairman and CEO, commented, "Our two recent discoveries at Redtail and Hidden Bench, our new wells at Sanish and Lewis & Clark and our encouraging results at Big Tex demonstrate our strategy and ability to develop new oil play areas for future multi-rig development while successfully executing on our existing large scale resource plays. This course of action resulted in our decision to increase our capital budget to $1.60 billion from $1.35 billion."

Mr. Volker continued, "We hold more than 680,000 net acres in the Bakken/Three Forks Hydrocarbon System that we believe will provide increased production and reserve additions. We added 76,000 net acres in the Williston Basin during the second quarter. With our planned development in these new areas and our existing core properties, we expect a strong second half in 2011."

2011 Capital Budget Increased to $1.6 Billion from $1.3 Billion

Whiting has increased its 2011 capital budget to $1,600.0 million from $1,350.0 million. Of this $250.0 million increase, we expect to invest approximately $90.0 million in additional land acquisitions. We have increased our acreage acquisition budget to $200.0 million from $110.0 million. We expect to invest the remaining $160.0 million in drilling. New plays receiving a portion of this funding in 2011 include the Hidden Bench prospect in McKenzie County, North Dakota (18 additional wells), the Cassandra prospect in Williams County, North Dakota (6 additional wells), the Starbuck prospect in Richland County, Montana (5 additional wells), and our Redtail Niobrara prospect in Weld County, Colorado (4 additional wells). The increased budget is expected to be funded through internal cash flow and bank borrowings from our line of credit.

Hidden Bench Prospect. Whiting completed the Arnegard 21-26H discovery well at its Hidden Bench prospect flowing 2,423 barrels of oil and 4,012 thousand cubic feet (Mcf) of gas or 3,092 BOE per day from an 8,913-foot lateral in the Bakken formation on June 23, 2011. The flow rate was gauged on a 48/64-inch choke with a flowing casing pressure of 900 psi. The well, which was drilled to a vertical depth of approximately 11,490 feet, was fracture stimulated in a total of 30 stages, all using sliding sleeves. Whiting owns 59,170 gross (30,905 net) acres in the Hidden Bench prospect, located in McKenzie County, North Dakota. The Company plans to drill a total of 11 operated wells in the prospect in 2011.

Also at Hidden Bench, Whiting completed the Rovelstad 21-13H flowing 1,880 barrels of oil and 3,419 Mcf of gas (2,450 BOE) per day on June 15, 2011. The well was tested on a 48/64-inch choke with a flowing casing pressure of 700 psi and was fracture stimulated in a total of 30 stages, all using sliding sleeves. The Rovelstad well is located approximately two miles northeast of the Arnegard well.

Redtail Prospect. Whiting completed the Wild Horse 16-13H discovery well at its Redtail prospect flowing 1,061 barrels of oil and 1,561 Mcf of gas (1,321 BOE) per day from the Niobrara formation at a vertical depth of 6,762 feet. The flow rate, which was taken on June 16, 2011, was gauged on a one-inch choke with a flowing casing pressure of 270 psi. The Wild Horse 16-13H was fracture stimulated in 21 stages, all using sliding sleeve technology. The well's lateral length was 4,113 feet. The Wild Horse 16-13H produced at an average rate of 454 BOE per day during its first 30 days of production. Based on the results of this well, Whiting added four wells to its 2011 drilling program at Redtail. As of July 15, 2011, Whiting had acquired 103,880 gross (75,701 net) acres in the Redtail prospect in the Denver Julesburg Basin. Our average acreage cost to date is $462 per net acre, and we have an average working interest of 73% and an average net revenue interest of 61%.

Our first three horizontal wells at Redtail, the Pawnee 16-13H, the Terrace 36-11H and the Chalk Bluffs 36-13H, were completed with initial flow rates of 141 BOE per day, 105 BOE per day and 99 BOE per day. We believe that the higher production rates exhibited at the Wild Horse well were primarily the result of changing the well orientation to a northeast azimuth from an east to west orientation and modifying our frac design, including our frac fluid. We expect our next well at Redtail, the Two Mile Creek 22-13H, to be completed by the end of July 2011.

Big Tex Prospect. Whiting fraced its first horizontal well at the Big Tex prospect the first week of July 2011. The Bissett 9701, located in the Delaware Basin in Pecos County, Texas, produced 788 BOE per day (92% oil) from the Wolfbone on July 25, 2011. The well is still cleaning up after frac. The well's 3,610-foot lateral was fracture stimulated in a total of 16 stages, all using sliding sleeves.

As of July 15, 2011, Whiting had accumulated 116,494 gross (88,062 net) acres in our Big Tex prospect area in Pecos, Reeves and Ward Counties, Texas in the Delaware Basin. Our average acreage cost to date is $540 per net acre, and we have an average working interest of 76% and an average net revenue interest of 57%.

Big Island Prospect. At our Big Island prospect in Golden Valley County, North Dakota, we completed the Maus 23-22 pumping 282 barrels of oil per day from the Red River formation at a depth of approximately 12,450 feet. This is a conventional vertical well that we believe sets up four more tests of adjacent Red River prospects. We estimate EURs in this area at 400,000 BOE for a completed well cost of only approximately $3.8 million.

Operations Update - Core Development Areas

Bakken and Three Forks Development

Lewis & Clark Prospect. Whiting completed the Clemens 34-9TFH in the Three Forks formation flowing 1,919 barrels of oil and 1,137 Mcf of gas (2,108 BOE) per day on June 29, 2011. The well was tested on a 48/64-inch choke with a flowing casing pressure of 544 psi. The Clemens well, which was drilled on the north-central portion of the Lewis & Clark prospect in Billings County, North Dakota, was fracture stimulated in a total of 30 stages. The new producer was drilled approximately five miles east of the Federal 32-4TFH discovery well, which was completed in the Three Forks formation flowing 1,970 BOE per day on November 25, 2009.

Also at Lewis & Clark, Whiting completed the Richard 21-15TFH in the Sanish Sand flowing 865 barrels of oil and 977 Mcf of gas (1,028 BOE) per day on May 22, 2011. The well was tested on a 20/64-inch choke with a flowing casing pressure of 483 psi. The Richard well, which was drilled on the southeast side of the prospect in Stark County, North Dakota, was fracture stimulated in a total of 30 stages.

We own 387,351 gross (254,818 net) acres in the Lewis & Clark prospect, which is more than three and a half times larger than our Sanish field. At Lewis & Clark, Whiting has a controlling interest in 164 1,280-acre spacing units with an average working interest of 64%. Based on production to date at Lewis & Clark, it appears that these wells have a relatively shallow decline rate. Therefore, we continue to believe that our wells at Lewis & Clark will have Estimated Ultimate Recoveries (EURs) in the 300,000 to 500,000 BOE range.

Whiting's net production from the Lewis & Clark prospect averaged 2,640 BOE per day in the second quarter of 2011, up 93% from the 1,370 BOE per day average in the first quarter of 2011. From April 15 through July 15, 2011, Whiting completed 10 new wells at Lewis & Clark, bringing the total number of producing operated wells to 26. The average initial production rate for the 10 new wells came to 647 BOE per day. As of July 15, 2011, there were nine wells being completed or awaiting completion and six wells were being drilled. We currently have six drilling rigs operating in this project, and we expect to average eight rigs working from September through December. Based on well results to date, we plan to step up activity in the Stark County and Billings County portions of the prospect in the second half of 2011.

New Pronghorn Gas Plant. In early April 2011, Whiting broke ground on the construction of a gas processing plant at Lewis & Clark. The Pronghorn Gas Plant, formally named the Belfield Gas Plant, is located near Belfield, North Dakota. The Pronghorn Gas Plant will have an initial inlet capacity of 30 MMcf of gas per day and is expected to be completed by November 2011.

Whiting's net production from the Middle Bakken and Three Forks formations in the Sanish and Parshall fields of Mountrail County, North Dakota averaged 24,350 BOE per day in the second quarter of 2011 in the face of extreme weather, a decrease of 6% from the 26,010 BOE average daily rate in the first quarter of 2011.

In the Sanish field, we completed the Nesheim 11-24XH flowing 3,502 barrels of oil and 1,500 Mcf of gas (3,752 BOE) per day on July 14, 2011. The cross-unit well flowed on a 48/64-inch choke with a flowing casing pressure of 720 psi. The well was fracture stimulated in a total of 30 stages, all using sliding sleeve technology. The new producer was drilled on the east-central side of the Sanish field.

Also in the Sanish field, Whiting completed the Brookbank State 41-16XH flowing 2,503 barrels of oil and 1,990 Mcf of gas (2,835 BOE) per day on June 10, 2011. This cross-unit well flowed on a 52/64-inch choke with a flowing casing pressure of 700 psi. The well was fracture stimulated in a total of 21 stages, all using the plug & perf method.

Whiting recently completed its second wing well in the Sanish field. The Oppeboen 14-5WH was completed flowing 2,198 barrels of oil and 581 Mcf of gas (2,294 BOE) per day on July 15, 2011. The well's flow rate was gauged on a 20/64-inch choke with a flowing casing pressure of 1,233 psi. The well's 6,176-foot lateral was fracture stimulated in a total of 22 stages, all using sliding sleeves. Whiting has a total of up to 81 potential wing well locations in Sanish field. A wing well is normally a well drilled within a typical east-west trending 1,280-acre unit near the north or south lease line with an approximate 7,000-foot lateral.

Whiting also saw strong results from a Three Forks well in the Sanish field. The Vangen 11-3TFH was tested flowing 1,200 barrels of oil and 830 Mcf of gas (1,338 BOE) from the Three Forks formation on June 25, 2011. The flow rate was gauged on a 40/64-inch choke with a flowing casing pressure of 409 psi. The well was drilled on the south-central side of the Sanish field.

Whiting owns 106,898 gross (65,056 net) acres in the Sanish field, located in Mountrail County, North Dakota. Whiting's net production from the Sanish field in the second quarter of 2011 averaged 20,515 BOE per day, a decrease of 5% from the first quarter 2011 average rate of 21,685 BOE per day. The decrease was due to well completion delays and downtime resulting from inclement weather in North Dakota. Compared to the second quarter 2010 average rate of 20,045 BOE per day, production in the second quarter of 2011 was up 2%.

From April 15 through July 15, 2011, Whiting completed five operated Bakken wells and three operated Three Forks wells in the Sanish field. The average initial production rate for the five Bakken wells came to 2,614 BOE per day, while the initial production rates for the three Three Forks wells averaged 811 BOE per day. The eight new completions bring to 171 the number of Whiting-operated wells in the Sanish field as of July 15, 2011. Including non-operated wells, there were 243 producing wells in the Sanish field as of July 15, 2011. The Company plans to continue with its current nine operated drilling rig count in the Sanish field through 2013. In 2011, Whiting intends to drill 95 operated wells (52.7 net wells) in the field, of which 70 are planned Three Forks wells, 15 are cross-unit Bakken wells, seven are Bakken infill wells and three are wing wells. Whiting has contracted two full-time dedicated frac crews and a half-time crew that started the last week of June 2011 working in the Williston Basin that we believe are capable of fracture stimulating 18 to 20 wells per month. As of July 15, 2011, 29 operated wells and six non-operated wells were being completed or awaiting completion and eight operated wells and two non-operated wells were being drilled in the Sanish field.

The 17-mile oil line connecting the Sanish field to the Enbridge pipeline in Stanley, North Dakota is currently transporting approximately 33,000 barrels per day, which represents approximately 85% of Whiting's gross operated Sanish production. This 8-inch diameter line has a capacity of approximately 65,000 barrels of oil per day. The Company is currently saving between $1.00 and $2.00 per barrel in transportation costs for each barrel that is transported through the pipeline rather than being transported by truck.

Robinson Lake Gas Plant. During the second quarter of 2011, a fractionation facility and a second NGL train were brought online at the Robinson Lake Gas Plant. As of July 8, 2011 the plant is processing 39.6 MMcf of gas per day (gross). The plant has a processing capacity of 90 MMcf of gas per day. Currently, there is inlet compression in place to process 70 MMcf per day, and compression will be added as the processing demand increases. Whiting owns a 50% interest in the plant. The plant receives 25% of the net proceeds from natural gas and NGLs processed at the plant. As of July 8, 2011, sales from the plant were 30.9 MMcf of gas and 4,372 barrels of NGLs per day, from which Whiting was netting 3.9 MMcf of gas and 546 barrels of NGLs per day due to its 50% plant ownership.

Williston Basin Land Position. Whiting increased its acreage position in the Bakken / Three Forks Hydrocarbon System of the Williston Basin to 1,102,302 gross acres from 999,972 gross acres and to 680,137 net acres from 603,702 net acres. This includes 62,180 gross (41,332 net) acres in Richland County, Montana acreage, referred to as the Missouri Breaks prospect, which is prospective in both the Bakken and Three Forks formations. The Company expects to drill at least one well at Missouri Breaks in the second half of 2011. Whiting's average cost for its entire Williston Basin acreage is currently $419 per net acre.

In-House Core Analysis. In April 2011, Whiting installed two scanning electron microscope workstations in its Denver office. These machines enable us to perform core analyses in weeks rather than months. We believe that we are one of the few companies in the US to have this in-house capability.

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Statoil's 2Q Earnings Soar in 2011

- Statoil's 2Q Earnings Soar in 2011

Thursday, July 28, 2011
Statoil

Statoil's second quarter 2011 net operating income was NOK 61.0 billion, a 129% increase compared to NOK 26.6 billion in the second quarter of 2010. The quarterly result was mainly affected by a 32% increase in the average prices for liquids measured in NOK, a 28% increase in average gas prices, a NOK 8.8 billion gain related to the 40% Peregrino divestment and an 18% decrease in lifted volumes, when compared to the same period last year.

"Statoil delivered record net income in the second quarter of 2011, reflecting an operational performance in line with expectations, the value-creating Peregrino transaction and strong oil and gas prices throughout the period. Production was mainly impacted by previously announced extensive maintenance activities and seasonal variability in gas off-take. We continued to make progress within exploration and project developments in the quarter, staying on track to deliver future growth," says Helge Lund, Statoil's chief executive officer.

Net income in the second quarter of 2011 was NOK 27.1 billion ($5.01B) compared to NOK 3.1 billion in the same period last year. This result reflected higher prices for both liquids and gas, a gain on sale of asset of NOK 7.5 billion net of tax, reduced exploration expenses and higher net financial income, partly offset by reduced liftings. The tax rate for the quarter was 56%.

Adjusted earnings in the second quarter of 2011 were NOK 43.6 billion, compared to NOK 36.5 billion in the second quarter of 2010.

Adjusted earnings after tax were NOK 12.8 billion in the second quarter of 2011. Adjusted earnings after tax exclude the effect of tax on net financial items, and represent an effective adjusted tax rate of 71% in the second quarter of 2011.

Total equity production was 1,692 mboe per day in the second quarter of 2011 compared to 1,957 mboe per day in the second quarter of 2010.

Highlights since first quarter 2011:

• The sale of 40% of the Peregrino offshore field in Brazil was completed and a gain of NOK 8.8 billion before tax is recorded.
• Successful exploration drilling activities in Norway and internationally.
• The approval of the Plan for development and operation (PDO) for the Hyme field (formerly Gygrid) on the NCS.
• The approval of the Plan for development and operation of the Valemon gas and condensate field on the NCS.
• The announcement of the divestment of a 24.1% interest in the Gassled joint venture to Solveig Gas Norway AS.
• The approval of the Plan for development and operation for Visund South fast track on the NCS.
• Statoil awarded the contract for construction of two new specially designed category D drilling rigs.
• First shipment of Peregrino crude.
• Strengthened position in Eagle Ford through acquiring new leases.

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Rocksource Makes Headway in 2011 Drilling Program

- Rocksource Makes Headway in 2011 Drilling Program

Wednesday, July 27, 2011
Rocksource ASA

Rocksource has now announced the drilling results from three of its five, 2011 exploration wells. Initial results show one discovery (Norvarg) and two dry holes at wells drilled to test unproven petroleum systems (Breiflabb and Kora). Wells four and five in the 2011 program are expected to spud in September.

Norvarg

In June Rocksource announced a gas discovery in the Norvarg prospect in the Barents Sea license PL 535, operated by Total E&P Norge AS. On Norvarg Rocksource's Electromagnetic (EM) technology successfully identified the stacked hydrocarbon reservoirs present within the structure. It is too early to conclude on flow rate characteristics; hence the partnership has decided to perform a production test to gather information about reservoir production properties. Well operations are still ongoing with the planned well test to commence shortly.The test results are expected in early August.

Breiflabb

Earlier in July Rocksource announced a dry well on the Breiflabb prospect in license PL 416 in the Norwegian part of the North Sea. The Breiflabb prospect was characterized by a weak EM anomaly and was estimated to have a pre drill chance of success of 44 percent. The false positive response (EM anomaly not associated with hydrocarbon) is believed to have come from deeper levels that were not penetrated by the well.

Kora

The Kora-1 well in offshore Senegal and Guinea Bissau was on July 27 announced as unsuccessful. The Kora prospect had an EM anomaly interpreted by Rocksource to be associated with hydrocarbons with an approximate 50 percent chance of success. The prospect was found dry and the strong EM anomaly is believed to have been caused by a combination of lithologies (rock types) which have combined to produce unusually high resistivity. Although these lithologies were not specifically predicted pre-drill, given the lack of well control in this frontier area it was accounted for in Rocksource's prospect risking. Rocksource recently farmed down half of its interest in AGC Profond receiving as an initial consideration, USD 28 million in promoted contribution towards past expenditure and the costs of the Kora-1 well.

Commenting on the drilling results so far Chief Technology Officer John Howell said, "The average chance of success in our 2011 drilling campaign is approximately 50 percent. When you drill five wells with 50 percent chance of success, you should expect two to three discoveries and two to three dry holes. Although we would have liked more discoveries early, we believe we can still deliver a successful drilling campaign and we are looking forward to the results from the two remaining wells this year, and to test the further potential in our extensive exploration portfolio in 2012 and beyond."



The final two wells in 2011, will test the Heilo (PL 530) and Phoenix (PL559) prospects on the NCS. Both are expected to spud in September. Both wells are within proven petroleum systems and are on trend with earlier oil discoveries.

Heilo

PL 530 which includes the Heilo prospect is located in the Barents Sea on trend with the Goliat discovery to the west and the Nucula discovery to the southeast. The license which is operated by GDF Suez was reported to be the most sought after block in the Norwegian 20th Licensing Round. Rocksource carries a mean volume estimate of 200 mill boe and a chance of success of approximately 50% for the Heilo prospect. A success in the initial target will trigger a sidetrack to allow further efficient appraisal of the structure.

Phoenix

PL 559 which includes the Phoenix prospect was Rocksource's highest priority application in the Norwegian APA 2009 license round and is located on the Nordland Ridge, immediately to the east of the Norne, Urd, Falk and Linerle fields. Prospectivity within the license consists of three main prospects and several leads. All three prospects have encouraging EM responses. Rocksource carries a mean volume estimate of 160 mill boe for the Phoenix prospect and a chance of success of approximately 50%.

In parallel with the ongoing drilling operations Rocksource is continuing to mature EM positive prospects towards drilling decisions, and expect to firm up wells for drilling in 2012 and beyond throughout the remainder of the year.

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TNK-BP Touts Financial Results for 1H 2011

- TNK-BP Touts Financial Results for 1H 2011

Tuesday, July 26, 2011
TNK-BP

TNK-BP reported its results for the first half of 2011.

Commenting on the results, Mikhail Fridman, Executive Chairman of TNK-BP Ltd., said, "This was an exceptional first half performance for TNK-BP. Thanks to management's continuous efforts to enhance operational efficiency and further develop our key business streams, the Company was able to deliver robust results. We have increased production, significantly expanded our resource base and nearly doubled net profit for the period. Growing our international business is a key priority for TNK-BP and we've made great progress thus far in 2011 by closing the deal to acquire BP's upstream assets in Venezuela and identifying several additional acquisition targets abroad."

1H11 OPERATIONAL HIGHLIGHTS

• In 1H11, oil and gas production (excluding JVs) continued to grow and reached 1,765 mboe/d, up 1.2% on 1H10. This growth was primarily driven by further production increases at our producing greenfields, Uvat and Verkhnechonskoye, and also by continued success in developing our Orenburg fields as well as increasing gas production at Rospan. We have developed and started implementation of a long-term West Siberia efficiency improvement program targeting a decrease in the annual production decline rate from the current 7% to approximately 2-3% per year.
• We have made good progress in our exploration and appraisal program aimed at growing the company’s resource base. Over 200 million boe of resources were added in 1H11 through exploration and appraisal. We have also demonstrated our ability to obtain new acreage by successfully acquiring 3 licenses through the federal auctions in the Orenburg region with estimated resources of 149 million boe.
• On the international front, we have closed the acquisition of upstream assets from BP in Venezuela in June, while the Vietnam deal close is expected in 3Q pending approval by the Vietnamese Ministry of Industry and Trade. We will now focus on the integration of these assets into our portfolio and ensuring their operational and financial efficiency. We have also just announced the signing of a Farm-out Agreement with Brazilian Petra Energia for the acquisition of a 45% stake in 21 blocks in the Brazilian Solimoes Basin. We hope to have the necessary agreements finalized before the end of August.
• Refining throughput was at 761 mb/d, increasing 11% y-o-y as a result of continuing debottlenecking efforts.
• We have progressed with expansion of our retail chain by opening the first two new-format highway service stations under the BP brand in Tver region within the framework of our long-term retail business development strategy. Opening these new service stations is the first step in implementing a strategy to develop highway retail sites in the European part of Russia. The operations of the sites have been very successful with initial fuel sale volumes exceeding the plan by 2-3 times.
• We also continued to reinforce our position in B2B by signing a long-term formula-based jet fuel supply agreement signed with Transaero Airlines, in line with the company’s strategy to strengthen its presence in Russia’s jet fuel market and increase transparency of fuel sales.
• Finally on the corporate side, we have embarked on an important initiative of improving the organizational structure of our business, led by Deputy Chairman of the Management Board, Maxim Barskiy. This involves switching from an asset-based management system, where local management has both wide functional and operational responsibility, to a functional governance model (or matrix model), with clear segregation of functions and more streamlined decision making. The first practical steps of this transition were the integration of Technology and Supply Chain Management streams into Upstream, as well as development and enactment of the new Delegation of Authority Matrix. The new organizational structure will improve decision-making, focus local management on its area of expertise, and improve our competitive advantage, as we continue our transformation into a global oil and gas player.

Commenting on the financial results, Jonathan Muir, Chief Financial Officer of TNK-BP Ltd., said, "In the first half 2011, TNK-BP continued to demonstrate strong financial results, supported by a favorable market environment, sustainable production growth and refinery throughput improvement. EBITDA increased by 59% y-o-y to USD 7.4 bn, underpinned by a 42% rise in the oil price, partially offset by cost increases due to higher excise rates, rising electricity and transportation tariffs, and continuing rouble appreciation. Our net income increased by 87% y-o-y to USD 4.5 bn on the back of EBITDA growth. Healthy cash flows from operations allowed us to raise organic capital expenditure by 33% y-o-y to USD 2.2 bn with particular focus on our key growth assets: Uvat, Verkhnechonskoye and Orenburg. Our financial discipline remained strong with good cash flow and successful debt portfolio management giving us the flexibility to pursue strategic inorganic opportunities."

1H11 FINANCIAL HIGHLIGHTS

• Revenues for 1H11 increased by 41% relative to 1H10 reflecting a 42% higher Urals price and 21 mboe/d (1.2%) production growth partly offset by a decrease of export sales in favor of the domestic market to avail of higher netbacks.
• Export duties and taxes other than income tax increased by 38% for 1H11 relative to 1H10 as a result of the impact of higher Urals prices on export duty and mineral extraction tax rates as well as the growth in excise rates in Russia partly offset by a significant duty lag benefit.
• Underlying materials, service and payroll inflation on cash costs amounted to only 4% year-on-year. However, electricity and transport tariff growth inflated cash costs by 8%. Rouble appreciation added 4% year-on-year. In addition, a one-off increase on an environmental provision in 2Q11 related to reassessment of some legacy issues increased costs by 3%.
• EBITDA for 1H11 amounted to USD 7.4 bn which is 59% higher compared to 1H10 largely due to the higher prices and duty lag benefit supported on the operations side by higher production and sales volumes. These positive factors were partly offset by a negative exchange rate impact as well as tariff and excise rates growth.
• 1H11 Net income amounted to USD 4.5 bn which is 87% up on the same period of 2010. This increase outpaced the EBITDA growth primarily due to relatively flat DD&A.
• Operating cash flow for 1H11 totaled USD 5.9 bn, up 51% compared to 1H10. This is a reflection of the higher EBITDA (adjusted for non-cash provisions), partly offset by a USD 0.5 bn increase in working capital primarily due to a price-driven growth in inventory and accounts receivable balances.
• Net debt increased by USD 0.6 bn compared to year end 2010 resulting in gearing growing to 22%.
• Organic capital investment in 1H11 amounted to USD 2.2 bn, 33% above 1H10, largely associated with increased investments in our growth greenfields (VCNG, Uvat) and Orenburg.

2Q11 RESULTS

• Revenues for 2Q11 increased by 11% relative to 1Q, reflecting primarily the increase in Urals price.
• Export duties and other taxes increased 20% q-o-q driven by a 12% increase from the price effect on export duties and MET and a decrease in duty lag benefit in 2Q, partly offset by the effect of lower export sales volumes.
• Cash costs (operating expenses, transportation and SG&A) increased by 15% largely due to rouble appreciation, increase in wellwork, contracting and other activities compared to a seasonally slower 1Q as well as increased environmental provisions.
• EBITDA for 2Q11 was 12% lower compared to 1Q. The most significant reason is the decrease of duty lag benefit further exacerbated by price-driven growth in duties, taxes and costs of purchases that effectively eliminated all q-o-q benefit of higher prices on revenues. Other factors include a comparative negative impact of one-offs - disposal gains in 1Q and higher provisions in 2Q, as well as rouble appreciation and increased spending on well-work together with annual wages and salary indexation and Moscow offices relocation cost.
• 2Q11 Net Income decreased by 14%, generally following the EBITDA trend.
• Operating cash flow in 2Q increased by 55% compared to 1Q attributed primarily to lower working capital. This is mainly due to a comparative USD 1.3 bn reduction in accounts receivable balances driven by a general decrease of trade accounts receivable due to lower crude export sales in June as well as shorter receivables collection terms.
• Organic capital investments were $0.4bn higher than in 1Q11, representing primarily a seasonally higher activity level.
• Compared to the 2Q 2010 results, 2Q 2011 EBITDA and net income increased by 45% and 81%, respectively. This reflects a stronger external environment with the Urals price increasing by 48% and a higher duty lag benefit supported by an increase in trading volumes and an improvement in trading mix, including in particular a 6% higher share of refined products. These positive factors were partly offset by the effect of a stronger rouble and inflationary pressure on costs and a USD 0.1 bn comparative net loss related to one-off impacts.

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Crimson Updates Production Activity, Ups 2011 Capital Plans

- Crimson Updates Production Activity, Ups 2011 Capital Plans

Monday, July 18, 2011
Crimson Exploration Inc.

Crimson Exploration Inc. on Monday provided an operational update and announced an increase in its 2011 capital program.

In Liberty County, TX, the Catherine Henderson #B-4 (64.0% WI) commenced production at a gross daily rate of 1,379 Boepd, or 721 barrels of condensate, 208 barrels of natural gas liquids and 3.2 Mmcf of natural gas on a 13/64th choke and 7,000 psi of flowing tubing pressure. This well was drilled to a total measured depth of 15,338 feet in the Lower Cook Mountain formation. Approximately one mile to the northwest, Crimson has drilled the Catherine Henderson A-10 (66.0% WI), targeting the Cook Mountain formation, to a total measured depth of 13,742 feet. Completion operations are scheduled to begin by the end of July with first production in early August.

In Zavala County, TX, Crimson completed the KM Ranch #1H (50.0% WI), targeting the Eagle Ford Shale, and has commenced flow-back operations with results expected in mid-August. The well was drilled to a total measured depth of 12,627 feet, including a 5,800 foot lateral and 20 stages of fracture stimulation. The KM Ranch #1H represents Crimson’s first well in Zavala County where Crimson has an estimated 147 drilling locations and approximately 2,300 net acres held by production. Crimson anticipates spudding the KM Ranch #2H (50.0% WI) in the beginning of November subsequent to spudding its first well in the Booth-Tortuga Area, approximately 13 miles to the southwest of the KM #1H, in the beginning of October.

In Karnes County, Texas, Crimson spud the Littlepage McBride #2H (53.0% WI), targeting the Eagle Ford Shale formation, which is drilling at 8,480 feet toward an estimated total measured depth of 15,850 feet. Completion operations are expected to begin mid-third quarter with initial production to follow in September. The Littlepage McBride #2H is located approximately 0.6 miles to the east of the Littlepage McBride #1H well (53.0% WI) which is currently producing 525 Boepd and has produced a cumulative 53,000 Boe since coming online in early April. Due to the success experienced in Karnes County, we have planned a continuous drilling program for the remainder of the year, commencing a well per month beginning in August.

Updated 2011 Capital Program

Crimson’s Board of Directors recently approved increasing its 2011 capital budget to $78 million, a 30% increase, to accelerate oil weighted drilling activities in Zavala, Dimmit and Karnes Counties. This decision was made based on Crimson’s extensive portfolio of drill ready oil opportunities and recent success. The increase in capital expenditures marks the beginning of an Eagle Ford development program that represents a strategic shift to oil and liquids rich projects in proven areas. As a result, preliminary internal forecasts indicate Crimson’s production mix will be over 40% crude oil and natural gas liquids by January 2012 and over 50% crude oil and natural gas liquids by the second quarter of 2012.

Second Quarter 2011 Production

Crimson produced approximately 4.4 Bcfe of natural gas equivalents, or an estimated 48,740 Mcfe per day, during the second quarter 2011, compared with 2.7 Bcfe, or 30,084 Mcfe per day, produced during the second quarter of 2010, a 62% increase period over period. The second quarter production results were in line with management’s guidance.

Crimson Exploration is a Houston, TX-based independent energy company engaged in the acquisition, development, exploitation and production of crude oil and natural gas, primarily in the onshore Gulf Coast regions of the United States. The Company owns and operates conventional properties in Texas, Louisiana, Colorado and Mississippi, approximately 12,000 net acres in the Haynesville Shale, Mid-Bossier, and James Lime plays in San Augustine and Sabine counties in East Texas, approximately 6,700 net acres in the Eagle Ford play in South Texas and approximately 11,000 net acres in the Denver Julesburg Basin of Colorado.

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EIA: Higher US Gas Production Expected for 2011

- EIA: Higher US Gas Production Expected for 2011

Tuesday, July 12, 2011
Dow Jones Newswires
NEW YORK
by Amy D'Onofrio

The U.S. Energy Information Administration raised its forecast for natural-gas production for 2011, and said inventories are expected to come close to last year's record levels this fall.

The EIA also expects demand for gas to be slightly stronger than previously expected.

U.S. gas production is expected to average 65.4 billion cubic feet a day in 2011, up 5.8% from last year. The forecast was up from last month's prediction of 4.5% growth in output, according to the agency's monthly Short Term Energy Outlook released Tuesday.

"Growing domestic natural gas production has reduced reliance on natural gas imports and contributed to increased exports," the EIA said.

That increase in production is partly due to drilling to access gas in shale rock formations, where output has shot up in recent years.

Pipeline gross exports to Mexico and Canada are expected to average 4.2 Bcf/d in 2011, up from 3.1 Bcf/d in 2010, while liquefied natural gas imports are seen falling to 1 Bcf/d, from 1.2 Bcf/d in 2010, the agency said.

Production continues to grow faster than consumption. Total gas consumption is forecast to increase by 2% in 2011 to 67.4 billion cubic feet a day, on higher demand from industrial and electric power consumers.

Consumption is expected to drop slightly in 2012 to 67.3 billion cubic feet a day. The EIA expects residential and commercial consumption to decline because cooler weather is expected in the Midwest and West, the EIA said.

Natural-gas prices at the benchmark Henry Hub should average $4.26 per million British thermal units over the second half of 2011, "as the inventory deficit relative to last year narrows," the EIA said. In June, prices averaged $4.54, or 34 cents higher than the forecast last month.

Uncertainty over natural gas prices is still lower this year compared with the same time last year, the statistical arm of the Department of Energy said.

Gas prices will likely come under downward pressure as inventories rise during the summer months, but prices are expected to average $4.54 in 2012 as production growth slows.

This year, inventories should remain high, however.

Inventories are forecast to surpass 3.8 trillion cubic feet at the end of October "because of current high production rates and a milder summer relative to last year," according to the report.

Copyright (c) 2011 Dow Jones & Company, Inc.

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NY Official: Highly Unlikely to Issue Fracking Permits in 2011

- NY Official: Highly Unlikely to Issue Fracking Permits in 2011

Friday, July 01, 2011
Dow Jones Newswires
NEW YORK
by Matt Day & Angel Gonzalez

New York State environmental authorities have determined that hydraulic fracturing can be safe, but the first permits to apply the controversial drilling technique won't likely be issued this year, the state's top environmental official said Friday.

Joe Martens, commissioner for the state's Department of Environmental Conservation, said that with strict regulation, "we believe high-volume fracturing can be done safely in New York."

Hydraulic fracturing, also known as fracking, involves injecting high volumes of water mixed with chemicals into tight rock formations, in order to crack them and release the oil and gas trapped within.

Martens was presenting a study of the environmental impact for high-volume fracturing commissioned by the state government that recommends that fracking be allowed on private lands, but not near public aquifers nor the New York City and Syracuse watersheds.

DEC, however, won't issue permits until the report, unveiled Friday, goes through its comment period and is finalized. "It's impossible to predict" when first permits will be issued," Martens said. "It is highly unlikely that it would be this year." DEC will issue regulations codifying the recommendations of the report once the review process is over, Martens said.

New York state's embrace of fracking comes amid national controversy over the issue. Proponents say the technique, perfected in the last decade by independent U.S. oil companies, is an economic boon for state coffers and local populations, and has unleashed an unprecedented supply of natural gas. Opponents say fracking can pollute aquifers and surface waters, constituting a serious danger to public health, allegations the oil industry denies.

New York, which straddles the giant Marcellus Shale natural gas field, has huge gas potential, but fierce opposition to the practice and the uncertainty caused by the controversy has kept it off limits to oil producers. Opposition hasn't been limited to New York. The New Jersey legislature voted on Wednesday to ban fracking in its state, though it isn't a key drilling area. Even in places traditionally comfortable with the tradeoffs associated with energy production, such as Texas, oversight has increased. The U.S. Environmental Protection Agency is currently doing its own study, primarily on the potential effects of fracking on drinking water and groundwater.

Catskills Citizens For Safe Energy, an advocacy organization that opposes fracking, said in a statement on its website that "no one" can say with certainty that chemicals injected into the ground "won't present a threat to our drinking supplies in the years and decades to come." The state's recommendations will protect some drinking water supplies, but not others, the organization said.

With the recommendations issued by DEC, more than 80% of the Marcellus Shale resources present in the state will be within the reach of energy companies, Martens said.

Martens said after a close examination of contamination incidents in neighboring Pennsylvania, which also sits atop the Marcellus Shale, New York environmental authorities "have been able to isolate what the problems were."

New York state officials will require that oil companies put a long piece of pipe--known as "intermediate casing"--separating the drill pipe from the surrounding rock formation in order to keep shallow natural gas found during the drilling process from migrating into nearby aquifers or drinking wells. Authorities will also seek to ensure that wells are properly cemented, as poor cementing jobs were implicated in a number of cases where "people ended up with gas in their wells," Martens said.

The state will also require rigorous equipment tests and better storm-water controls, and will seek to have its staff conduct diligent oversight, Martens said.

Martens acknowledged, however, that the state has "limited staff right now" to enforce the strict regime it envisions. That could create a backlog in permitting. "We will only review those applications that we have the staff capacity to handle," he said.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Barclays: Worldwide Spending to Pass Half Trillion Mark in 2011

- Barclays: Worldwide Spending to Pass Half Trillion Mark in 2011

Monday, June 13, 2011
Rigzone Staff
by Karen Boman

Worldwide exploration and production (E&P) spending in 2011 is expected to rise to 16 percent to $529 billion, compared with $458 billion in 2010, with strong year-over-year improvement in spending driven by large increases inside and outside North America, Barclays Capital today reported in its global E&P capital spending update.

E&P spending in North America is now forecast to be up 16.2 percent in North America and 15.5 percent outside of North America, compared with forecast increases in December 2010 of 11 percent globally, including seven percent in North America and 12 percent outside of North America. Barclays reports budgets have been revised dramatically higher in the U.S. and internationally for U.S. and European based independents, Southeast Asian companies and companies focused on the Middle East.

Spending increases this year will be led by North America, where high oil prices and the continued shift towards drilling in oil and liquids rich plays have resulted in solid growth. E&P capital spending for North America is expected to increase by 16.2 percent from $127.6 billion in 2010 to $148.3 billion in 2011.

Latin America, Europe and the Middle East are expected to be the strongest regions internationally for E&P spending. Petrobras' multi-year pre-salt development offshore Brazil and ambitious plans by Colombian state energy company Ecopetrol are driving the forecast increase in capital spending by Latin American companies, with spending in the region expected to be up 26 percent in 2011 to $65.5 billion from $52.1 billion in 2010, Barclays reported.

Spending increases of roughly 23 percent are anticipated both in Europe and the Middle East, with spending estimated at $39.9 billion this year in Europe and $22.1 billion in spending in the Middle East. India, Asia and Australia spending will be up 15 percent this year to $79.3 billion. Russian spending is expected to rise by three percent to $36.1 billion this year from 2010.

Capital expenditures for North Africa, where the "Arab Spring" of political demonstrations and civil war across the region has affected government and the economy, are anticipated to be down by over 16 percent to $25.2 billion this year due to sizable spending reductions by Egyptian General Petroleum Corp. and National Oil Corporation, as well as a reduction by Sonangol and lower spending for Nigeria National Petroleum Corp. as an election cycle concludes in Nigeria.

The U.S. continues to attract the majority of worldwide E&P spending at 21 percent; however, this percentage has continued to fall each cycle. Internationally, the India, Asia and Australia region absorbs the largest share of spending, which is being driven by large investments by Chinese national oil companies and Southeast Asian companies such as Malaysia's Petronas and Indonesia's Pertamina. In India, ONGC and Reliance are making significant investments in the region.


U.S. and European independents are stepping up spending internationally, with U.S.-based independents now forecasting international spending increases of 23 percent, up from four percent in December, while the European independents are anticipating spending growth of 23 percent versus 12 percent at the end of 2010. "We believe this is in part due to higher oil prices, higher cash flows, new exploration programs, and recent exploration success," Barclays said.

Spending among supermajors is expected to rise by 16 percent this year, led by Total, BP and Shell, compared with average spending growth of eight percent over the past five years. This increase is due to engineering and construction-related spending for several large liquefied natural gas projects, increasing Iraq spending, and increased deepwater drilling, especially in West Africa and Brazil.

While ExxonMobil remains the largest capital spender worldwide for oil and gas this year, Petrobras is quickly catching up; Petrobras and PetroChina may overtake ExxonMobil in spending in the next few years. Ninety percent of the top 20 spenders are expected to increase capital expenditures this year, with the exception of Russia-based Gazprom, which Barclays believes is primarily currency-related due to currency fluctuations in 2012, and Sonangol in Angola.

Barclays noted that the correlation between increased E&P spending and inflation-adjusted oil prices is significant, and expects a higher oil price environment to persist over the next several years driven by accelerating decline curves, continued difficulty finding and developing large reserves, increased demand in emerging markets, and tight spare capacity.

"Based on our view of a continued high oil price environment, we expect 2011 to mark the first year of multi-year double-digit spending growth internationally," Barclays said.

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