Tullow Reports French Guiana Discovery

- Tullow Reports French Guiana Discovery

Friday, September 09, 2011
Tullow Oil plc

Tullow Oil plc announced Friday that the Zaedyus exploration well (GM-ES-1), offshore French Guiana, has made an oil discovery having encountered 72 meters of net oil pay in two turbidite fans. Results of drilling, wireline logs and samples of reservoir fluids show that the well has encountered good quality reservoir sands on prognosis.

The objective of the Zaedyus well was to test whether the Jubilee-play, successfully established in West Africa, was mirrored on the other side of the Atlantic. This discovery therefore opens a new hydrocarbon basin within which several neighboring prospects have been mapped. This result also reduces the exploration risk associated with Tullow's prospect inventory offshore French Guiana, Suriname and Guyana. An appraisal program and extensive follow-up exploration activities will now be considered.

The Zaedyus well is being drilled in the Guyane Maritime license using the ENSCO 8503 deepwater semi submersible. The well was drilled in water depths of 2,048 meters and has been drilled to a depth of 5,711 meters. Drilling operations will now continue and the well will be deepened to over 6,000 meters to calibrate the deeper geology. The well will then likely be sidetracked to enable cores to be obtained over the reservoir sections.

Tullow (27.5%) operates the Guyane Maritime license and is partnered by Shell (45%), Total (25%) and Northpet (2.5%), a company owned 50% by Northern Petroleum plc and 50% by Wessex Exploration plc.

Angus McCoss, Tullow's Exploration Director, commented Friday:

"The discovery at Zaedyus has proved the extension of the Jubilee-play across the Atlantic and made an important new discovery in French Guiana. Tullow has built a commanding and unique acreage position in South America and this result marks the start of a significant and potentially transformational long-term exploration and appraisal campaign in the region."

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Jubilant Reports Testing Results for Kharsang Field in India

- Jubilant Reports Testing Results for Kharsang Field in India

Monday, September 05, 2011
Jubilant Energy N.V.

Jubilant announced the testing results of the first development well KSG-57 (earlier referred to as "KPL-A") drilled under the Phase-III development drilling campaign in the Kharsang field. The well was spudded on July 28, 2011 and was successfully drilled to 875 meters measured depth (800 meter true vertical depth) on 15th August 2011, on time and within budget. The well was tested with a smaller capacity work-over rig, which was deployed at the site on August 21, 2011.

Based on wireline log interpretation results, formation pressure data from Sequential Formation Testing and Side Wall Core results, the consortium identified four separate intervals, totaling 20 meters of net sand, for testing of shallow C-50 and D-00 Girujan targeted reservoirs.

Upon testing the D-00 sands interval between 786-793 meters and activation through swabbing, the well started self-flowing. The well is presently flowing through 5.56 millimeter choke at a rate of around 170-180 barrels of oil per day (bopd), with Gas-Oil-Ratio of 30 volume by volume and maximum flowing tubing head pressure of 11 Kg/cm2. The initial results are as expected and encouraging. The production from the well is being sent to the Oil Collecting Station (OCS) for further processing.

The KSG-57 well will continue to remain under extended production testing to carry out a multi choke study till production is optimized. The testing of the remaining 11 meters of the two shallower sands will be completed at a later date.

GeoEnpro Petroleum Ltd., a joint venture of GeoPetrol and Jubilant Enpro (a member of the wider Jubilant Bhartia Group), is the operator of the Kharsang Field. Jubilant holds a 25% interest in the block through its subsidiary, Jubilant Energy (Kharsang) Pvt Ltd. The other members of the consortium are Oil India Ltd and GeoPetrol.

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Gulf Shores Reports Bakken Oil Discovery in Saskatchewan

- Gulf Shores Reports Bakken Oil Discovery in Saskatchewan

Thursday, September 01, 2011
Gulf Shores Resources Ltd.

Gulf Shores reported that the 3-34-14-33W1 well in the Coothill area of Southeast Saskatchewan has been drilled and is being cased as a new Bakken oil discovery.

Gulf Shores Resources Ltd. is paying 60% of the cost of the well to earn a 39% working interest in 160 acres with an option on an additional contiguous 320 acres under the same terms.

The rig will now move to the 9-16-15-32W1 location in the Welwyn area west of the Rocanville Field in Southeast Saskatchewan.

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GM Reports Sales In August Were Up

 - GM Reports Sales In August Were Up



Sep 1, 2011

General Motors (NYSE:GM) reported that U.S. August sales were up to 18% to 218,479 units.

The company also said that the month-end dealer inventory in the United States was 556,884 units, including 212,520 full-size pick up trucks and it's on track to meet its target of ending 2011 with a full-size pick up inventory of 200,000 units.

General Motors (NYSE:GM) has a potential upside of 75.6% based on a current price of $23.41 and an average consensus analyst price target of $41.12.

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Lukoil Reports $3.25B in 2Q Earnings, Up 67%

- Lukoil Reports $3.25B in 2Q Earnings, Up 67%

Wednesday, August 31, 2011
OAO Lukoil Holdings

LUKOIL has published consolidated US GAAP financial statements for the second quarter and first half of 2011.

The Company's net income was $6.768 billion in the first half of 2011, which is 69.1% higher y-o-y, including $3.251 billion in the second quarter. EBITDA in the first half of 2011 was $10.688 billion, which is 43.8% higher y-o-y. Sales revenues were $64.538 billion (+29.7% y-o-y). Positive dynamics of our financial results was mainly due to increase in hydrocarbon prices and refining margin in the first half of 2011 compared to the respective period of 2010.

Capital expenditures including non-cash transactions in the first half of 2011 were $3.6 billion, which is 13.3% higher y-o-y. The Company's strict financial discipline helped to generate high free cash flow which reached $4,714 million in the first half of 2011 compared to $3,127 million in the first half of 2010.

In the first half of 2011, lifting costs per boe of production were $4.72, which is 17.4% higher y-o-y. The growth was mainly due to the real ruble appreciation, which was 15.0% in the first half of 2011.

In the first half of 2011, LUKOIL Group total hydrocarbon production available for sale reached 2,162 th. boe per day, which is a 4.4% decrease y-o-y.

In the first half of 2011 throughputs at the Company's refineries (including its share in crude oil and petroleum product throughput at the ISAB and TRN refining complexes) decreased by 1.2% y-o-y and reached 32.03 MM tonnes. Throughputs at the Company's refineries in Russia increased by 1.5% y-o-y, throughputs at the Company's international refineries decreased by 6.9% y-o-y due to shutdown of the Odessa Refinery because of unfavorable economic conditions in the first half of 2011.

Measures aimed at higher efficiency and cost control allowed the Company to generate strong free cash flow and increase net income.

Also, an extended meeting of the OAO LUKOIL Board of Directors was held on Wednesday. The meeting considered the Company's production and financial performance and the investment program implementation results in the first half of 2011.

In his address to the meeting, LUKOIL President Vagit Alekperov specified the need to develop a Hydrocarbon Production Stabilization Program and to rigorously implement it.

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AWE Reports Net Loss

- AWE Reports Net Loss

Monday, August 29, 2011
AWE Ltd.

AWE Limited has announced a statutory net loss of $117.6 million for the 12 months to June 2011. After adjustment for significant one-off, the underlying loss was $16.1 million.

The Company's production assets performed strongly with production of 6.1 million BOE. This delivered a 61% increase in after tax net cash flow from operating activities of $140 million, which included exploration expense of $21 million.

Investment in growth activities continued during the year, with $32 million invested in the completion of the Adelphi takeover, $69 million in exploration activities and a further $80 million in project developments (primarily BassGas MLE and Sugarloaf drilling).

The Adelphi Energy takeover, completed during the year, provides AWE with access to an exciting gas and liquids development project in the US, which is delivering strong initial production performance. Reserve reporting to date at Sugarloaf has highlighted the growth potential of the asset, with 2P reserves increasing to 8.5 million BOE at June, 2011.

The Company reported a cash position of $117 million, at June 30, 2011 with an undrawn $150 million loan facility.

Commenting on the result, AWE's Managing Director Bruce Clement said, "The Company's core business continues to perform well as evidenced by the increased operating cashflow of $140 million for the year, reflecting the strength and diversity of AWE's portfolio of production assets.

"The statutory loss of $118 million was impacted by a number of significant one-off factors, primarily asset impairments and the derecognition of previously booked tax losses.

"The second half of 2010/11 has been a period of consolidation for AWE following an extended period of major exploration activity.

"The Company's focus has been on delivering its core production operations, exploiting its existing asset base and establishing its tight gas and shale gas business through the Sugarloaf acquisition and the Perth Basin exploration initiatives. The Company has also completed a comprehensive review of its core assets.

"Looking forward, AWE has a strong balance sheet, robust future cash flow from its 66 million BOE 2P reserve base and significant potential in its Perth Basin gas exploration assets with access to premium domestic markets.

"The Company's near term plans will focus on continuing the strong performance of the base business, exploiting its tight gas and shale gas projects and pursuing selective growth opportunities.

"The Board and Management of AWE are confident about the Company's future. AWE is well positioned to build on its existing assets and to take advantage of opportunities in the current volatile business environment."

Finance

Operating cashflow was strong for the year, rising 61% to $140 million. The reported cashflow included exploration expense of $21 million and significant Tui and Cliff Head workover costs of $29 million.

The year-end financial position of the Company was strong, with cash of $117 million and no debt (and with a $150 million undrawn corporate debt facility available if required).

AWE's sales revenue fell 14% to $305 million for the year, with net field contributions also lower at $172 million. Total oil and gas sales volumes were in line with the prior year, although oil production was down by 36%, offset by increased gas and associated gas liquids sales over the period. Average received oil prices improved to approximately $91 per barrel, as a result in the stronger international prices partially offset by the stronger A$.

In accordance with AWE's successful efforts accounting policy, $63 million of exploration costs were expensed during the year. These costs were largely related to unsuccessful drilling activity in New Zealand, Yemen and Australia.

A net exploration impairment charge of $61 million (post tax) impacted the statutory results. This impairment included the write down of the Yemen and Bass Basin exploration assets acquired as part of the ARC Energy merger in 2008. In addition, a post-tax net oil and gas asset impairment of $15 million was also recorded (largely related to the Cliff Head project).

Subsequent to the end of the year, AWE sold its shareholding in Buru Energy Limited for a cash consideration of $17 million. These funds were received after year end and are not included in the reported results.

Exploration

Exploration expenditure for the year was primarily incurred on the conventional oil and gas exploration opportunities in Australia, New Zealand and Yemen.

In the latter part of year, AWE accelerated activities in tight gas and shale gas exploration in the onshore Perth Basin, where drilling of the Arrowsmith-2 well has been completed and hydraulic stimulations are being planned. Timing of the hydraulic stimulation activity is subject to the receipt of all regulatory approvals.

AWE continues to pursue further conventional and unconventional exploration opportunities, applying an added degree of financial and technical discipline.

Development

The Adelphi takeover was completed during the year, and development drilling activity in its USA operations has accelerated since the acquisition was finalised. An independent reserve statement was released in March 2011, which reported a 37% improvement (to 8.6 million BOE net to AWE) in existing 2P reserves in the Sugarloaf AMI. Further drilling activity is expected to see added conversion of possible reserves into the 2P reserves category during 2011/12.

The $346 million gross budget for first phase of the Yolla MLE project was approved during the year and significant progress has been made with the onshore fabrication of gas compression and accommodation modules and preparations for offshore installation at the end of 2011. An extended production shutdown is planned during the offshore installation activities (December to April).

The second phase of the development will incorporate the drilling of at least two additional development wells on the Yolla field and remains on schedule for late 2012/early 2013. Engineering planning, including the evaluation of additional upside potential in the field, is continuing with budget commitment expected by end 2011. Total expenditure to June 30, 2011 on the MLE project was $107 million.

Production well workovers were successfully completed on the Pateke and Cliff Head projects, with the Cliff Head-12 well workover increasing production from the Cliff Head field by over 1,500 bopd after coming on stream in August 2011.

2011-2012 guidance

Production guidance for the current financial year has been set at 5.0 to 5.5 million BOE, substantially impacted by the planned extended shutdown of the Yolla field for the offshore installation activities associated with the MLE project. Based on a A$100 per
barrel Brent oil price for the year, AWE expects oil and gas sales revenue to reach a range of $270 to $300 million. Planned exploration expenditure for the year is estimated at $50 million, with development expenditure planned to reach $150 million, the majority of which will be incurred on the BassGas MLE project.

With a net cash position of $117 million AWE is well positioned to further exploit those assets within the Company's existing portfolio and take advantage of opportunities to add to its asset base.

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Northern Offshore Reports 2Q Earnings

- Northern Offshore Reports 2Q Earnings

Thursday, August 18, 2011
Northern Offshore Ltd.

Northern Offshore reported net income for the three months ended June 30, 2011 of US $4.6 million, or US $0.03 per diluted share. This compares to a net loss of US $0.5 million, or US $0.0 per diluted share for the second quarter of 2010. Revenues for the second quarter of 2011 were US $49.9 million compared to US $48.9 million for the second quarter of 2010.

For the six months ended June 30, 2011, net income was US $7.0 million or US $0.05 per diluted share. For the same period in the prior year, net income was US $22.7 million or US $0.15 per diluted share. Revenues for the first six months of 2011 were US $90.4 million compared to US $116.9 million for the same period in 2010.

The company's directors have declared a dividend of US $0.03 per share, or approximately US $5.0 million. Shareholders of record with the VPS on August 31, 2011 will be entitled to receive the dividend, which will be paid on or around September 15, 2011. The shares of the company will be trading ex-dividend from August 29, 2011.

Second Quarter Analysis

Revenues for the three months ended June 30, 2011 were slightly higher when compared to the same period of 2010, primarily due to higher utilization of the jackup fleet, partially offset by lower utilization of the drillship Energy Searcher.

Drilling and production expenses for the three months ended June 30, 2011 were US $2.8 million lower than the same period last year primarily due to lower operating expenses for the drillship Energy Searcher and reduced idle costs for the jackup Energy Exerter. This decrease was partially offset by higher operating expenses related to the contract start-up of the jackups Energy Enhancer and Energy Endeavour. Depreciation expense for the three months ended June 30, 2011 was US $6.5 million lower than the same period in 2010 due to the decrease in depreciable basis of the jackup fleet attributable to the asset impairment charge taken in December 2010. General and administrative expenses were lower than the same period in 2010 due to lower compensation costs.

Interest expense was US $1.3 million lower than in the second quarter of 2010 primarily due to lower outstanding loan balance. Amortization of deferred financing fees was higher than the same period last year primarily due to the acceleration of the amortization of the deferred financing fees relating to the early repayment and cancellation of the US $120 million Revolving Credit Facility on May 31, 2011. Income tax expense was US $6.4 million higher than the same period last year primarily due to a higher annualized effective tax rate, partially offset by a reduction in the accrued withholding tax rate for operations in India.

At June 30, 2011, the Revolving Credit Facility balance was US $32.0 million and the cash balance was US $35.6 million, of which approximately US $28.2 million is unrestricted, leaving the company a net cash position at the end of the period of US $3.6 million.

Updates

The company is pleased to report that the semisubmersible Energy Driller was recently both technically and commercially qualified in a tender process requesting three one-thousand foot depth rated floating drilling rigs for a program offshore India. Although an award has yet to be made, the company is optimistic that the rig should receive a three-year contract due to the qualifying bid and anticipates receiving a letter of award in the next four to six weeks.

The floating production facility Northern Producer remains under contract with EnQuest. The unit continues producing in the North Sea with further field development and tie-back ongoing. The tariff from the facility for the second quarter 2011 averaged US $134 thousand per day on average per-day production of 22.4 thousand barrels.

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Woodside Reports Strong Performance for 1H11

- Woodside Reports Strong Performance for 1H11

Wednesday, August 17, 2011
Woodside Petroleum Ltd.

Woodside reported a first-half profit after tax of US $828 million, underpinned by continued strong performance of the North West Shelf and higher revenues. The underlying net profit after tax of US $842 million was up 3.6%.

Woodside Chief Executive Officer Peter Coleman said, "Our focus on operational excellence continues to deliver outstanding results and today's financial result highlights the ongoing strength of the company's base business.

"Woodside's extensive production facilities are performing well and delivering strong revenues. With around US $2.9 billion in cash and undrawn facilities, together with continued strong cash flows from the underlying business, we enter the second half of 2011 well positioned to fund our growth plans.

"We will continue a disciplined approach to investment to maximise, deliver and capture value from our existing business, our LNG growth options and select opportunities."

Key Points

Reported net profit after tax was $828 million ($901 million 1H 2010), down 8.1%, largely due to last year's first-half being positively impacted by a gain on the sale of Woodside's Otway assets and a lower income tax expense.

• Underlying net profit after tax was $842 million, up 3.6% ($813 million 1H 2010) and represents our second highest first-half profit.
• Strong revenue of $2,253 million up 7.2% ($2,102 million 1H 2010). The recent period of higher commodity prices continues to positively impact profit performance.
• First-half production of 31.9 MMboe (36.7 MMboe 1H 2010), down 13.1% compared to 1H 2010 primarily due to planned maintenance and project outages (-4.3%), cyclone interruptions (-3.6%), average field decline (-3.4%) and divestments (Otway, GOM shelf; -3.4%), partially offset by increased reliability (+1.6%). This was a solid result and keeps us on track for the FY 2011 target of 62 to 64 MMboe.
• Operating cash flow of $1,391 million, up 38.1% ($1,007 million 1H 2010).
• Robust balance sheet to fund growth with $2.9 billion in cash and undrawn debt facilities.
• Capital expenditure# of $1.5 billion, down 6%, as Pluto nears completion.
• Interim dividend of US55 cents per share (cps) fully franked (US50 cps 1H 2010).
• LNG Growth Projects:
  • Pluto LNG Foundation Project – production and cash flow commencing in 2012.
  • Pluto Expansion – Carnarvon Basin drilling and discussions with other resource gas owners continue.
  • Browse – front-end engineering and design (FEED) underway and land access secured.
  • Sunrise – actively re-engaging with government stakeholders.

DIVIDEND PAYMENT

A fully-franked interim dividend of US55 cps (2010: US50 cps) was declared. The record date for determining entitlements to the interim dividend is 26 August 2011 with the ex-dividend date being 22 August 2011. The interim dividend will be paid on 30 September 2011. The dividend reinvestment plan (DRP) will remain activated and will be fully underwritten.

OPERATIONAL OVERVIEW

North West Shelf

The first half of 2011 has seen continued strong performance from the North West Shelf (NWS) facilities. Woodside delivered 132 cargoes of LNG on behalf of the NWS Venture, compared to 127 in the first half of 2010. The increase is primarily attributed to increased production from LNG Train 5 following the completion of remedial work on the main heat exchangers during planned maintenance in May 2010.

Australia Oil

Enfield: Production of 2.1 MMbbls (3.3 MMbbls 1H 2010) benefited from additional volumes from the Horst and Main West infill wells, which were completed during 2H 2010. However production was disrupted at the start of the year as a result of high levels of cyclone activity.

Vincent: Production of 1.5 MMbbls (2.3 MMbbls 1H 2010) was reduced at the start of the year due to cyclone interruption and a scheduled maintenance shutdown of the floating production storage and offloading vessel (FPSO) to reinstate gas compression. The rate of production has increased since gas compression was restored. Two Phase III production wells were spudded during 1H 2011and are expected to contribute to production in 2H 2011.

Stybarrow: Cyclone activity also impacted production but this was more than offset by high production rates from the Stybarrow North production well, which came online at the end of 2010. Production for the half was 1.9 MMbbls (1.2 MMbbls 1H 2010).

DEVELOPMENT ACTIVITIES

Pluto LNG Project

During 1H 2011 the project achieved significant commissioning milestones including the introduction of commissioning gas to the onshore plant. This milestone facilitated start up of the gas turbine generators, which provide electrical power to test all equipment in preparation for a safe start up. Offshore, the Pluto A platform was readied for use with the successful completion of the pressurisation of the trunkline, pipelines and flowlines using commissioning gas. During 2H 2011 onshore and offshore commissioning work will continue.

On 17 June 2011, Woodside revised the expected cost and schedule of the Pluto LNG Project following its regular review of the progress of the project. The first LNG cargo is now estimated for March 2012 and the revised estimate now expected to result in a A $900 million cost increase to a total of A $14.9 billion (100% project). This estimate includes arrangements with customers affected by the delay.

Pluto Expansion

Woodside continues to target expansion at the Pluto LNG Park. It is planned to conduct further exploration and appraisal drilling to prove up additional gas volumes in the Carnarvon Basin. Discussions continue with other resource owners regarding development of additional trains at Pluto.

Browse LNG

During the period, Woodside successfully executed an agreement with the Goolarabooloo Jabirr Jabirr Native Title claimant group and the Western Australian Government, which will enable the establishment of the Browse LNG Precinct.

Environmental studies and approvals progress in line with expectations. Work planned for 2H 2011 includes continuing FEED studies and environmental approvals.

Sunrise LNG

Woodside is actively re-engaging with the Australian and Timor-Leste governments to obtain in-principle approval of the development concept for Greater Sunrise gas.

North Rankin Redevelopment Project

The A $5 billion project (approximately A $840 million Woodside share) will recover remaining low pressure reserves from the North Rankin and Perseus fields and is scheduled for completion in 2013. Commissioning continues on the North Rankin B (NRB) jacket in Indonesia and topsides in Korea. The transport barge, for the NRB jacket delivery to the North West Shelf, has arrived in Indonesia with load out scheduled for 3Q 2011. Modifications to the North Rankin A (NRA) platform continue on schedule, including preparations to
install the bridges linking NRA and NRB.

Greater Western Flank Development (GWF)

The GWF area is located to the south-west of the Goodwyn A platform and contains 14 fields estimated to hold approximately 3 Tcf of recoverable gas and 100 MMbbls of condensate (100% project). The first phase of the GWF Development has progressed to FEED studies as a subsea tieback to the Goodwyn A platform.

North West Shelf Oil Redevelopment Project

The A $1.8 billion project (100%) will extend production from the Cossack, Wanaea, Lambert and Hermes fields beyond 2020. First oil from the Okha FPSO is forecast for early 4Q 2011.

Production outlook

Woodside's 2011 production target is 62-64 MMboe. The company expects continued strong operational performance from the NWS facilities. To ensure ongoing reliability, a significant NWS maintenance shutdown is planned for 3Q 2011. In addition, contribution from two infill wells at Vincent and recommencement of oil production from the NWS Oil Redevelopment Project should provide additional volumes to the base business.

Production volumes are expected to increase strongly following first Pluto LNG cargoes, which are now estimated to commence in March 2012.

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Carrizo Reports Record Production for 2Q11

- Carrizo Reports Record Production for 2Q11

Tuesday, August 09, 2011
Carrizo O&G Inc.

Carrizo announced financial results for the second quarter of 2011, which included the following highlights:

Results for the Second Quarter of 2011

• Record production of 11.2 Bcfe, or 122,788 Mcfe/d
• Revenue of $50.7 million or adjusted revenue, of $54.1 million, including the impact of realized hedges
• Net Income of $7.7 million, or Adjusted Net Income, as defined below, of $9.5 million
• EBITDA, as defined below, of $41.8 million

Production volumes during the three months ended June 30, 2011 were a record 11.2 Bcfe, an increase of 1.9 Bcfe, or 20%, from second quarter 2010 production of 9.3 Bcfe and an increase of 0.5 Bcfe, or 5% from first quarter 2011 production of 10.7 Bcfe. The increase in production from the second quarter of 2010 and the first quarter 2011 to the second quarter of 2011 was primarily due to increased production from new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation, partially offset by normal production decline and the sale of substantially all of our non-core area Barnett Shale properties to KKR Natural Resources ("KKR") in May 2011.

Adjusted revenues were $54.1 million for the second quarter of 2011, which includes oil and gas revenues of $50.7 million and realized hedge gains of $3.4 million, compared to $43.5 million for the second quarter of 2010, which includes oil and gas revenues of $32.9 million and realized hedge gains of $10.6 million. The increase in adjusted revenues was primarily driven by increased production, particularly higher oil and condensate production in the Eagle Ford Shale, and higher oil prices partially offset by lower realized hedge gains. Including the impact of realized hedges, the Company's average realized gas price decreased 13% to $3.83 per Mcfe for the second quarter of 2011 compared to $4.40 per Mcfe for the second quarter of 2010 and the average realized oil price increased 1% to $93.90 per barrel for the second quarter of 2011 compared to $93.30 per barrel for the second quarter of 2010. Revenues excluding the impact of realized hedges are presented in the table below.

Adjusted net income, which excludes certain non-cash items described in the statements of operations included below ("Adjusted Net Income"), was $9.5 million, or $0.25 and $0.24 per basic and diluted share, respectively, during the second quarter of 2011, including a $3.3 million benefit of cash distributions received from a joint venture partner as described below, as compared to $11.3 million, or $0.33 per basic and diluted share, during the second quarter of 2010. The Company reported net income of $7.7 million, or $0.20 per basic and diluted share, for the quarter ended June 30, 2011, as compared to net income of $1.8 million, or $0.05 per basic and diluted share, for the same quarter during 2010.

Earnings before interest, income tax, depreciation, depletion and amortization ("EBITDA") as defined in the Company's new U.S. senior secured revolving credit facility ("Credit Facility") and described in the statements of operations included below was $41.8 million, or $1.07 and $1.06 per basic and diluted share, respectively, during the second quarter of 2011, including the $3.3 million benefit of cash distributions received from a joint venture partner as described below, as compared to $31.6 million, or $0.93 and $0.92 per basic and diluted share, respectively, during the second quarter of 2010. During the second quarter of 2011, the Company received cash distributions of $3.3 million on its B Unit investment in ACP II Marcellus, LLC ("ACP II"), a joint venture partner in the Marcellus Shale that is an affiliate of Avista Capital Partners, LP, a private equity fund, as a result of ACP II's distribution to Avista of remaining proceeds from its sale of oil and gas properties to an affiliate of Reliance Industries Limited ("Reliance"). Although such cash distributions are included in EBITDA and Adjusted Net Income, such cash distributions are recognized as a reduction of oil and gas property costs under the full cost method of accounting and accordingly are not included in net income.

Lease operating expenses (including transportation costs of $1.6 million) were $7.4 million (or $0.66 per Mcfe) for the three months ended June 30, 2011 as compared to lease operating expenses (including transportation costs of $1.5 million) of $6.2 million (or $0.66 per Mcfe) for the second quarter of 2010. Lease operating expenses increased due to increased production primarily attributable to new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation. Although we continued to experience a decrease in the operating cost per Mcfe of our Barnett Shale production, driven by comparatively less salt water disposal costs in the core area of the Barnett Shale as compared to production from other areas of the Barnett Shale, this decrease was offset by increased operating cost per Mcfe associated with higher cost oil production.

Production taxes were $1.5 million (or 2.89% of revenues) for the three months ended June 30, 2011 as compared to $0.9 million (or 2.69% of revenues) for the three months ended June 30, 2010. The increases in production taxes and the percentage of revenues are due to increased oil production, which has a higher effective production tax rate as compared to natural gas.

Ad valorem taxes increased to $1.0 million (or $0.05 per Mcfe) for the three months ended June 30, 2011 from $0.5 million ($0.09 per Mcfe) for the same period in 2010. The increase in ad valorem taxes is due to new oil and gas wells drilled in 2010 as well as a reduction in ad valorem taxes recorded in the second quarter of 2010 reflecting a true up of our first quarter 2010 estimate. The decrease in the per Mcfe amounts is due primarily to this true up of the first quarter 2010 estimate.

General and administrative expense was $5.7 million during the three months ended June 30, 2011 as compared to $4.3 million during the three months ended June 30, 2010. The increase was primarily due to increased compensation costs related to an increase in the number of employees in the second quarter of 2011.

Depreciation, depletion and amortization ("DD&A") expense for the three months ended June 30, 2011 increased to $20.6 million (or $1.84 per Mcfe) from $11.1 million (or $1.19 per Mcfe) for the same period in 2010. The increases in DD&A and the related per Mcfe amounts were primarily due to increased production during the second quarter of 2011 as compared to the same period in 2010 and increased future development costs associated with crude oil and natural gas liquids reserves in the Eagle Ford which were added during the fourth quarter of 2010 and have a higher future development cost per equivalent unit than the Company's proved gas reserves. The increase in the second quarter 2011 forecasted DD&A of $1.58 per Mcfe to the actual DD&A of $1.84 per Mcfe is largely due to increased production in the second quarter of 2011 as compared to the first quarter of 2011 as well as an increase in prior year's estimated future development costs in the Eagle Ford.

Cash interest expense, net of amounts capitalized, increased to $6.1 million for the second quarter of 2011 compared to $2.9 million for the second quarter of 2010. The increase was primarily attributable to interest on the $400 million aggregate principal amount of Senior Notes issued in the fourth quarter of 2010 partially offset by decreased interest attributable to the $300 million aggregate principal amount of Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

An unrealized gain on derivatives of $8.1 million was recorded for the second quarter of 2011 compared to an unrealized loss on derivatives of $7.4 million for the second quarter of 2010 due to the change in fair value of our open derivative positions during those periods.

Non-cash, stock-based compensation expense increased to $6.8 million for the three months ended June 30, 2011 from $3.2 million for the same period in 2010. The increase was largely attributable to additional stock appreciation rights as well as stock appreciation rights that increased in fair value.

Non-cash interest expense, net of amounts capitalized, decreased to $0.7 million for the second quarter of 2011 compared to $1.9 million for the second quarter of 2010, primarily due to decreased amortization of the discount as a result of the $300 million aggregate principal amount of the Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

During the second quarter of 2011, we contributed $1.0 million in common stock to the Carrizo Oil & Gas, Inc. endowed scholarship fund at the University of Texas at Arlington ("UTA") where we are producing natural gas from a number of wells in the Barnett Shale play.

The effective income tax rate was 31.8% for the second quarter of 2011 and 15.0% for the second quarter of 2010. Our estimated annual effective income tax rate for 2011 is approximately 37%, substantially all of which we expect to be deferred. The effective income tax rate for the second quarter of 2011 was lower than 37% primarily due to the true up of prior estimates of the foreign tax benefit associated with the Company's UK Huntington field development. The lower rate in the second quarter of 2010 was due to a true up of prior estimates of state income tax.

Carrizo's President and CEO, S. P. "Chip" Johnson, IV, commented on recent activity, "In late July we initiated sales from a three well pad producing from the Eagle Ford Shale on our Mumme lease in La Salle County, Texas, and from our Orlando Hill well in the Niobrara Formation. These events marked an inflection point in our liquids production growth ramp. We anticipate the oil production from these new wells to be followed by a fairly steady increase for the remainder of the year, with each month's oil production sequentially higher than the last, as a sufficient inventory of drilled wells has been built in the Eagle Ford and Niobrara to allow the execution of a continuous completion program.

"While still flowing back significant quantities of completion fluid, the Mumme 30H, 31H and 32H have each reached rates between 920 BOE per day and 1,184 BOE per day, consisting of 720-984 barrels of oil and approximately 1,200 Mcf of high BTU natural gas which went directly to sales in the existing lease gas gathering system. Following stabilization, we intend to flow these wells at constrained rates to maximize ultimate recoveries. We expect to begin completion of a three well pad on the Glover lease in Atascosa County later this month and anticipate first sales to occur in mid-September. Our recently completed well in the Niobrara Formation, the Orlando Hill 26-44-8-61 in Weld County, Colorado, reached a peak 24 hour production rate of 650 bopd on July 17th and averaged 580 bopd over the following week. The Nelson 17-44-9-60 well has also been completed and is currently flowing back completion fluid with a strong oil cut. An additional Niobrara well, the Wickstrom 7-11-5-60, has been drilled to total depth and is scheduled for completion later this month. We continue to be satisfied with the results of our Niobrara program and expect to be able to average adding a new well to production each month for the rest of 2011.

"The production contribution from our Eagle Ford completion program and our Niobrara activity should allow us to exit the year 2011 at or above our previous guidance of 5,000 net bopd. This growth in liquids production, in addition to the improved well performance from the Barnett Shale, gives us confidence in meeting our 2011 production growth forecast of 32% (after adjustment for the sale of a portion of our Barnett Shale properties to KKR earlier this year)."

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Transocean Reports $2.33B in 2Q Revenue

- Transocean Reports $2.33B in 2Q Revenue

Thursday, August 04, 2011
Transocean Ltd.

Transocean reported net income attributable to controlling interest of $155 million, or $0.48 per diluted share, for the three months ended June 30, 2011. The results compare to net income attributable to controlling interest of $715 million, or $2.22 per diluted share, for the three months ended June 30, 2010.

• Revenues increased nine percent to $2.334 billion compared to $2.144 billion in the first quarter 2011
• Second quarter 2011 net income attributable to controlling interest was $155 million, which included $36 million of certain net unfavorable items, compared to $310 million in the first quarter 2011, which included $139 million of certain net favorable items noted in our first quarter earnings release
• Revenue efficiency improved to 92.1 percent, up from 90.0 percent in the first quarter 2011
• Fleet utilization was 55 percent, unchanged from the first quarter 2011
• Operating and maintenance expenses were $1.492 billion, up from $1.359 billion in the first quarter 2011
• The Annual Effective Tax Rate (4) for 2011 has increased to 22.6 percent from 19.3 percent in the first quarter 2011
• New contracts totaling $1.5 billion were secured in the Fleet Status Report period April 14, 2011 through July 13, 2011
• Non-core assets George H. Galloway and GSF Labrador were classified as assets held for sale, in addition to the previously announced GSF Britannia
• The first quarterly installment of the dividend was paid on June 15, 2011

Second quarter 2011 results included the following items, after tax, that resulted in a net unfavorable impact of approximately $36 million, or $0.11 per diluted share:

$25 million loss on impairment relating to the three Standard Jackups, George H. Galloway, GSF Labrador and GSF Britannia, classified as assets held for sale at June 30, 2011, and
$11 million of net charges related to discrete tax items and the effect of discontinued operations.

Second quarter 2011 results also included expenses associated with the Macondo well incident of approximately $26 million, $19 million after tax, or $0.06 per diluted share. These expenses were primarily related to legal costs and professional service fees.

Operations Quarterly Review

Revenues for the three months ended June 30, 2011 were $2.334 billion, compared to revenues of $2.144 billion during the three months ended March 31, 2011. Second quarter contract drilling revenues, which increased to $2.086 billion from $1.95 billion in the first quarter, were positively impacted by improved activity in the Gulf of Mexico, the commencement of operations of the newbuild Ultra-Deepwater Floater Deepwater Champion, the reactivation of previously idled rigs, and higher revenue efficiency for our Ultra-Deepwater and Deepwater Floaters, partially offset by the stacking of additional Deepwater and Midwater Floaters. Overall utilization was flat during the period compared to the first quarter.

Other revenues increased $54 million to $238 million, primarily due to additional drilling management services activity.

The company reported improved revenue efficiency for our Ultra-Deepwater and Deepwater Floaters compared to the first quarter, as our program to improve efficiency yielded results. Similar to the first quarter, compliance with new well control equipment certification requirements, higher standards for equipment condition and capacity constraints on our vendors continued to adversely impact revenue efficiency and out-of-service time compared to the prior year.

Operating and maintenance expenses totaled $1.492 billion for the second quarter 2011, up from $1.359 billion for the prior quarter. The increase was primarily due to higher maintenance expenses along with increased levels of contract drilling and drilling management services activity.

Net Interest Expense, Capital Expenditures and Cash Flow

Net Interest Expense was $142 million in the period compared to $130 million in the first quarter. The increase is due primarily to interest income associated with a tax refund recognized in the first quarter.

Capital expenditures increased to $293 million for the second quarter compared to $240 million in the first quarter 2011. The higher expenditures were primarily due to our newbuild construction program.

Cash flows from operating activities decreased to $340 million for the second quarter 2011 compared to $390 million for the first quarter 2011. The decrease in cash flows from operations resulted primarily from an increase in working capital.

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Lundin Reports Strong 2Q Results, Boosts Output Forecast

- Lundin Reports Strong 2Q Results, Boosts Output Forecast

Wednesday, August 03, 2011
Lundin Petroleum AB

Lundin reported for the six month period ended June 30, 2011

Six months ended June 30, 2011

• Production of 32,300 boepd up 13% from the first six months 2010
• Profit after tax of MUSD 130.3 up 526% from the first six months 2010
• EBITDA of MUSD 505.3 up 96% from the first six months 2010
• Operating cash flow of MUSD 390.3 up 52% from the first six months 2010
• Net debt down to below MUSD 120 from MUSD 410 at year end
• Five exploration discoveries, four in Norway and one in Malaysia
• Ten Norwegian licenses awarded in the 2010 Norwegian licensing round, six as operator
• Operated license awarded in Barents Sea in the 21st Norwegian licensing round
• Operated Gurita block awarded in the Natuna Sea, offshore Indonesia

Second Quarter ended June 30, 2011

• Production of 31,100 boepd
• Profit after tax of MUSD 76.9
• EBITDA of MUSD 266.9
• Operating cash flow of MUSD 196.7
• Three exploration discoveries – Skalle and Earb South discoveries in Norway and Tarap discovery in Malaysia
• Appraisal well confirmed extension of the Avaldsnes discovery
• New operated block PM307 awarded in Malaysia
• Brynhild field plan of development (formerly called Nemo) submitted

Comments from C. Ashley Heppenstall, President and CEO

Lundin Petroleum achieved excellent results in the second quarter of 2011 with increased profitability and cash flow. What is extremely pleasing however, is the continued exploration success. I have always highlighted that the major valuation creation for our company will be achieved through increasing our oil and gas resources, and the best way to do that is through exploration.

Lundin Petroleum produced a net result for the first six months of MUSD 130.3. The strong production coupled with oil prices achieved of well over USD 100 per barrel resulted in operating cash flow of MUSD 390.3 and EBITDA of MUSD 505.3. Despite our significant exploration and development investment program net debt during the first half of the year has reduced from MUSD 410 to below MUSD 120.

The positive exploration news has continued during the second quarter with further discoveries at Skalle in PL438 in the Barents Sea, Earb South in PL505 in the northern Norwegian north Sea and Tarap in Block SB303 offshore East Malaysia. In addition the results of the first Avaldsnes appraisal well were extremely encouraging confirming the extension of the Avaldsnes field to the south east. We have now achieved five discoveries from our first five exploration wells this year following the Tellus and Caterpillar discoveries during the first quarter.

Our business is continuing to grow and I am confident we will continue to increase shareholder value. We are generating strong cash flow and profitability from our existing production which is outperforming, our development projects are proceeding well and our exploration success continues.

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Marathon Oil Reports $3.87B in 2Q11 Revenue

- Marathon Oil Reports $3.87B in 2Q11 Revenue

Tuesday, August 02, 2011
Marathon Oil Corp.

Marathon Oil reported second quarter 2011 net income of $996 million, or $1.39 per diluted share. Net income in the second quarter of 2010 was $709 million, or $1.00 per diluted share. On June 30, 2011, Marathon Oil completed the spin-off of its Refining, Marketing and Transportation business, now reported as discontinued operations and excluded from segment income; as a result, income from continuing operations will be best suited for comparison. For the second quarter of 2011, adjusted income from continuing operations was $689 million, or $0.96 per diluted share, compared to adjusted income from continuing operations of $440 million, or $0.62 per diluted share, for the second quarter 2010. Second quarter revenue in 2011 was $3.87 billion, compared to $2.9 billion in 2010.

"In the second quarter we successfully completed the spin-off of our downstream business and announced the pending $3.5 billion acquisition of assets in the Eagle Ford shale in Texas," said Clarence P. Cazalot Jr., Marathon Oil's chairman, president and CEO. "Our second quarter financial results, while solid, were negatively impacted by unplanned downtime at key international operations which held our second quarter production to the lower end of guidance. These operations are all back operating at or above expected capacity.

"Importantly, our production forecast and capital expenditure guidance for 2011, excluding acquisitions, remain unchanged. Going forward, we are confident that we have the foundation in place to deliver 5 to 7 percent compound average production growth during the period 2010 - 2016. This strong growth profile is underpinned by our pending top-five acreage position in the core, liquids-rich area of the Eagle Ford, as well as solid positions across the Bakken, Anadarko Woodford and Niobrara liquids-rich resource plays.

"In the Bakken alone we have increased our production growth target and now expect to average 33,000 net barrels of oil equivalent per day (boepd) by 2016. With our plans to significantly increase rig activity to more than 40 rigs over the next 18 months, we see approximately 175,000 boepd of net production across our substantial North America unconventional portfolio by 2016. Additionally, we expect our strong base assets to deliver the cash flow and earnings to fund this growth while we continue to maintain a solid balance sheet and competitive dividend," Cazalot said.

Segment Results

Total segment income was $713 million in the second quarter of 2011, compared to $396 million from continuing operations in the second quarter of 2010.

Exploration and Production

Exploration and Production (E&P) segment income totaled $601 million in the second quarter of 2011, compared to $432 million in the year-ago quarter. The increase was primarily the result of higher liquid hydrocarbon price realizations, partially offset by decreased sales volumes in Libya and Europe and increased depreciation, depletion and amortization (DD&A). Excluding Libya, Marathon Oil was underlifted by 333,000 barrels of oil equivalent (boe) in the second quarter compared to a 1,217,000 boe overlift in the same quarter last year. There was minimal derivatives impact in the second quarter of 2011, while a pre-tax gain of $29 million was included in results for the second quarter of 2010.

E&P production available for sale for the second quarter of 2011 averaged 341,000 boepd, of which 59 percent was liquid hydrocarbons (202,000 barrels per day) and 41 percent was natural gas (833 million cubic feet per day of natural gas). Production was at the low end of guidance largely because of unplanned downtime in Norway, where the Alvheim floating production, storage and offloading (FPSO) vessel was off-line for 13 days to ensure the safe operation of the fire protection system, and to a lesser extent in Equatorial Guinea. Second quarter 2010 production available for sale was 328,000 boepd (excluding 47,000 boepd from Libya).

Marathon Oil estimates third quarter E&P production available for sale will be between 330,000 and 350,000 boepd, which reflects planned maintenance activities in both operated and non-operated assets in the U.K., and includes potential hurricane effects in the Gulf of Mexico. While the mid-point remains unchanged, the range of anticipated full-year E&P production available for sale has been narrowed to between 350,000 and 360,000 boepd, which includes an average 7,000 boepd from Libya. For the E&P segment, Marathon Oil anticipates producing on average 360,000 - 380,000 boepd in 2012, which, due to the uncertain timing of a restart to production from the Company's Libya assets, excludes any Libya production, and excludes the effect of acquisitions or dispositions not previously announced.

E&P sales volumes during the second quarter of 2011 averaged 337,000 boepd, compared to sales volumes of 342,000 boepd (excluding 44,000 boepd from Libya) for the same period in 2010. The slightly lower sales volumes were primarily the result of the timing of liftings from the U.K. and the previously discussed international downtime.

United States E&P reported income of $126 million for the second quarter of 2011, compared to $25 million in the second quarter of 2010. The increase was the result of higher liquid hydrocarbon realizations and sales volumes in the Gulf of Mexico, partly offset by increased DD&A.

International E&P income was $475 million in the second quarter of 2011, compared to $407 million in the second quarter of 2010. The increase reflects the impact of higher liquid hydrocarbon realizations, partially offset by lower sales volumes in Libya, the U.K. and Norway.

Exploration expenses were $145 million for the second quarter of 2011, including $62 million of dry well costs, compared to $125 million in the second quarter of 2010, which included $57 million in dry wells. Dry well costs during the second quarter of 2011 included $38 million related to the Earb exploration well in the Norwegian North Sea, and $22 million incurred subsequent to the first quarter of 2011 related to the Romeo well in the Pasangkayu block offshore Indonesia.

EAGLE FORD: On Marathon Oil's existing acreage, four wells have been drilled and are being tested. During the second quarter, Marathon Oil announced an agreement to acquire Eagle Ford shale assets in south Texas for $3.5 billion, subject to closing adjustments. The transaction is expected to close Nov. 1 with an effective date of May 1. Including this transaction, Marathon Oil's 2011 exit rate from the Eagle Ford is expected to exceed 13,000 net boepd.

BAKKEN: Marathon Oil has seven rigs currently operating in the Bakken in North Dakota, with current production of 16,000 net boepd. Production is expected to increase substantially in the second half of the year as the Company adds a second crew for hydraulic fracturing activities. The Company has 28 gross operated wells awaiting stimulation and plans to fracture stimulate 50 total wells before the end of the year. The Company now expects to exit 2011 with production at approximately 20,000 net boepd, and to reach 33,000 net boepd by 2016.

ANADARKO WOODFORD: Marathon Oil has ramped up to five rigs currently drilling in the Anadarko Woodford in Oklahoma, and expects to have eight rigs operating by the end of the year. The Company is currently producing less than 2,000 net boepd and plans to end the year with production of approximately 5,000 net boepd.

OTHER NORTH AMERICA ONSHORE: In the Niobrara Shale play within the DJ Basin of southeast Wyoming and northern Colorado, results have been positive from two vertical wells drilled. The Company spud its first horizontal exploration well in early July, and expects to add a second rig by September 2011. Marathon Oil continues to acquire seismic data and plans to drill eight to twelve gross wells by year end. The Company also progressed concept selection in its Birchwood in situ project in Alberta, Canada, and anticipates reaching a final investment decision on the first stage of the project in 2012.

GULF OF MEXICO: Marathon Oil has submitted plans to resume drilling on the Innsbruck prospect (Mississippi Canyon Block 993, 85 percent working interest and operator) and is awaiting regulatory approval. In accordance with the federal government's drilling moratorium, drilling on the Innsbruck prospect was suspended in the second quarter of 2010 at a depth of 19,800 feet as compared to a proposed total depth of 29,500 feet. Additionally, due to operator issues at the non-operated host platform, first production from Ozona (Garden Banks block 515) has been delayed until year end. Marathon Oil is completing the well as a single zone oil producer, and expects a 2012 production rate of more than 9,000 net boepd, of which approximately 80 percent is oil. Overall reserve estimates and project costs have remained consistent since project sanctioning. Marathon Oil holds a 68 percent working interest in the Ozona Field, and serves as operator.

POLAND: In late July, Marathon Oil closed a transaction in which Mitsui & Co. acquired a 9 percent working interest in 10 of Marathon Oil's shale gas concessions in Poland. This transaction provides further financial risk mitigation and aligns the Company with another strong partner as Marathon Oil, Mitsui and Nexen prepare to explore and evaluate the full potential of these concessions. Marathon Oil holds a 51 percent working interest in these 10 concessions and serves as operator. The Company plans to spud two wells in the country in 2011.

IRAQI KURDISTAN REGION: Marathon Oil participated in its second discovery in the Iraqi Kurdistan Region during the second quarter. The Swara Tika-1 discovery on the Sarsang block was drilled to a total depth of approximately 12,500 feet and encountered 1,500 feet of gross oil column. Flow rates were established from three zones totaling more than 7,000 barrels of light oil per day (bopd) with associated gas. The flow rates were limited by tubing sizes and testing equipment. Marathon Oil holds a 25 percent working interest in the Sarsang block.

Oil Sands Mining

The Oil Sands Mining (OSM) segment reported income of $69 million for the second quarter of 2011, compared to a loss of $60 million in the second quarter of 2010. A pre-tax gain of $53 million on derivatives was included in results for the second quarter of 2010, but there were no derivative impacts in the second quarter of 2011. The increase in segment income was primarily the result of higher synthetic crude oil sales volumes and higher price realizations as compared to the same quarter last year. Current operating expense per synthetic barrel (before royalties) is $46, compared to $54 in the first quarter of 2011, with the partners continuing to focus on reducing the per barrel cost as production increases for this very long-life asset.

The Jackpine Mine commenced a phased start-up in the third quarter of 2010, and the expanded Scotford upgrader came on line in the second quarter of 2011, increasing overall production. Marathon Oil's second quarter 2011 net synthetic crude production (upgraded bitumen excluding blendstocks) from the Athabasca Oil Sands Project (AOSP) mining operation was 37,000 barrels per day (bpd). This compares to the same period in 2010 when the AOSP produced 15,000 bpd. The Scotford upgrader achieved full capacity in June. Marathon Oil holds a 20 percent working interest in the AOSP.

Marathon Oil expects third quarter net synthetic crude production will be between 40,000 and 45,000 bpd, with anticipated full-year 2011 net synthetic crude production unchanged at between 39,000 and 45,000 bpd. Marathon Oil anticipates producing on average 40,000 to 50,000 bpd of synthetic crude in 2012. Reliable operating performance by the operator is critical to achieving these targets.

In the second quarter of 2011, as a result of life extension for the Greater Jackpine Area, and in accordance with the terms of the original 1999 AOSP Joint Venture Agreement, Shell transferred to Marathon Oil a 20 percent ownership of the portion of Lease 13 known as the Greater Jackpine Area. Marathon Oil has increased net proved developed reserves by approximately 54 million barrels.

Integrated Gas

Integrated Gas segment income was $43 million in the second quarter of 2011, compared to $24 million in the second quarter of 2010. While segment income continued to be affected by weak Henry Hub gas prices, the increase was primarily related to higher volumes. The liquefied natural gas (LNG) facility in Equatorial Guinea had operational availability of 95 percent for the second quarter, which included the impact of a scheduled turnaround.

Special Items/Corporate

During the second quarter of 2011, Marathon Oil assigned an undivided 30 percent working interest in 180,000 acres in the Niobrara Shale play, located in southeast Wyoming and northern Colorado, to another company for $270 million, recording a gain of $24 million net of tax ($39 million pretax).

In May 2011, significant water production increases and reservoir pressure declines occurred at the Droshky development. Plans for a waterflood have been cancelled and the field will be produced to abandonment pressures, expected in the first half of 2012. Consequently, 3.4 million boe of proved reserves were written off and a $178 million net of tax ($273 million pretax) long-lived asset impairment was recorded in the second quarter of 2011.

Marathon Oil's outlook for future U.S. LNG imports makes it unlikely that sufficient U.S. demand for LNG will materialize by 2021, when the rights lapse under arrangements at the Elba Island, Georgia, LNG regasification facility. As a result, Marathon Oil recorded a special item of $17 million net of tax ($25 million pretax) for the full impairment of this intangible asset in the second quarter of 2011.

During the second quarter, the AOSP operator determined the need for and developed preliminary plans to address water flow into a previously mined and contained section of the Muskeg River mine. Estimated costs of $48 million net of tax ($64 million pretax) net to Marathon Oil have been recorded in the second quarter of 2011.

Related to activity of the Company's former downstream business, which is now included in discontinued operations, income tax expense increased due to the impact of state tax law changes and state valuation allowance adjustments. Net of federal tax, $50 million was recorded in the second quarter of 2011.

Related to the tax effect of restructuring international subsidiaries, Marathon Oil recorded a one-time non-cash tax expense of $122 million in the second quarter of 2011.

Marathon Oil's 2011 capital, investment and exploration budget remains unchanged and is expected to be $3.9 billion, excluding discontinued operations, asset acquisitions and associated development capital. This includes approximately $3.4 billion for worldwide E&P, approximately $300 million for Oil Sands Mining, and approximately $200 million for the corporate budget including capitalized interest. Asset acquisitions announced to date, along with associated 2011 development capital, are expected to be approximately $4 billion.

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BOEMRE Reports Final Update on Tropical Storm Don

- BOEMRE Reports Final Update on Tropical Storm Don

Monday, August 01, 2011
BOEMRE

The Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) Hurricane Response Team is concluding its activities related to Tropical Storm Don.

This is the final update of evacuation and shut-in production statistics for Tropical Storm Don.

Based on data from offshore operator reports submitted as of 11:30 a.m. CDT today, none of the 617 manned production platforms in the Gulf of Mexico remain evacuated. Production platforms are the structures located offshore from which oil and natural gas are produced. Unlike drilling rigs, which typically move from location to location, production facilities remain in the same location throughout a project’s duration.

None of the 62 rigs currently operating in the Gulf remain evacuated. Rigs can include several types of self-contained offshore drilling facilities including jackup rigs, submersibles and semisubmersibles.

As part of the evacuation process, personnel activate the applicable shut-in procedure, which can frequently be accomplished from a remote location. This involves closing the sub-surface safety valves located below the surface of the ocean floor to prevent the release of oil or gas. During the recent hurricane seasons, the shut-in valves functioned 100 percent of the time, efficiently shutting in production from wells on the Outer Continental Shelf and protecting the marine and coastal environments. Shutting-in oil and gas production is a standard procedure conducted by industry for safety and environmental reasons.

From operator reports, it is estimated that approximately 2.3 percent of the current oil production in the Gulf of Mexico has been shut-in. It is also estimated that approximately 0.9 percent of the natural gas production in the Gulf of Mexico has been shut-in. The remaining shut-in production is not associated with any reported damage.

The production percentages are calculated using information submitted by offshore operators in daily reports. Shut-in production information included in these reports is based on the amount of oil and gas the operator expected to produce that day. The shut-in production figures therefore are estimates, which BOEMRE compares to historical production reports to ensure the estimates follow a logical pattern.

After the tropical storm passes, facilities are inspected. Once all standard checks have been completed, production from undamaged facilities is brought back on line immediately. Facilities sustaining damage may take longer to bring back on line. BOEMRE will no longer report Tropical Storm Don statistics.

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Chevron Reports $7.7B in 2Q11

- Chevron Reports $7.7B in 2Q11

Friday, July 29, 2011
Chevron Corp.

Chevron reported earnings of $7.7 billion ($3.85 per share - diluted) for the second quarter 2011, compared with $5.4 billion ($2.70 per share - diluted) in the 2010 second quarter.

Sales and other operating revenues in the second quarter 2011 were $67 billion, up from $51 billion in the year-ago period, mainly due to higher prices for crude oil and refined products.

"Our second quarter financial performance was very strong," said Chairman and CEO John Watson. "Earnings gains versus last year's quarter were primarily in our oil and gas exploration and production business, resulting from higher crude oil prices on world markets."

Watson commented, "We continued to advance our major capital projects, resumed important exploration and development drilling activity in the deepwater Gulf of Mexico and acquired new upstream resource opportunities in the second quarter." These achievements include:

• Kazakhstan/Russia - Marked the start of the construction phase for expansion of the Caspian Pipeline Consortium's pipeline, which carries crude oil from western Kazakhstan to a dedicated terminal on the Black Sea. The design capacity of the pipeline will increase to 1.4 million barrels per day from its current capacity of 730,000 barrels per day. The project is planned to be implemented in three phases, with capacity increasing progressively from 2012 to 2015.
• Australia - Received recommendation of conditional environmental approval for the Wheatstone liquefied natural gas (LNG) project from Western Australia's Environmental Protection Authority. The company will continue negotiations to finalize the permit conditions as it works toward a final investment decision on the project in the second half of this year.
• Australia - Signed binding Sales and Purchase Agreements with Tokyo Electric for Wheatstone LNG.
• Bulgaria -Awarded an exploration permit for a prospective shale gas block of more than 1 million acres in northeastern Bulgaria.
• United States - Returned to work in the Gulf of Mexico with three rigs active in the deepwater, drilling the Moccasin exploration well, the Buckskin appraisal well and the Tahiti 2 development program. The company is also drilling on the Gulf of Mexico Shelf to test the ultra-deep gas play.
• United States -Acquired additional acreage in the Marcellus Shale, including from Chief Oil and Gas LLC and Tug Hill, Inc., primarily in Pennsylvania.

"We reached an important milestone in streamlining our downstream asset portfolio with receipt of government approval for the planned sale of our refining and marketing assets in the United Kingdom and Ireland," Watson added. The sale is expected to close in the third quarter. The company also completed the sale of its fuels-marketing and aviation businesses in three Central American countries in the second quarter 2011, as well as other assets in China and North America.

The company purchased $1 billion of its common stock in the second quarter 2011 under its share repurchase program.
UPSTREAM

Worldwide net oil-equivalent production was 2.69 million barrels per day in the second quarter 2011, down from 2.75 million barrels per day in the 2010 second quarter. Production increases from project ramp-ups in Canada and the United States and new volumes stemming from the acquisition of Atlas Energy, Inc. were more than offset by an approximately 40,000 barrels per day negative effect of higher prices on volumes related to cost-recovery and variable-royalty contract terms, and normal field declines.

U.S. upstream earnings of $1.95 billion in the second quarter 2011 were up $860 million from a year earlier. The benefit of higher crude oil realizations was partly offset by higher operating expenses.

The company's average sales price per barrel of crude oil and natural gas liquids was $104 in the second quarter 2011, compared with $71 a year ago. The average sales price of natural gas was $4.35 per thousand cubic feet, up from $4.01 in last year's second quarter.

Net oil-equivalent production of 694,000 barrels per day in the second quarter 2011 was down 2 percent, or 14,000 barrels per day, from a year earlier. The decrease in production was associated with normal field declines and maintenance-related downtime. Partially offsetting this decrease was production from the acquisition of Atlas Energy, Inc. and increases at Perdido in the Gulf of Mexico.The net liquids component of oil-equivalent production decreased 2 percent in the 2011 second quarter to 478,000 barrels per day, while net natural gas production declined 1 percent to 1.30 billion cubic feet per day.

International upstream earnings of $4.92 billion increased $1.47 billion from the second quarter 2010. Higher realizations for crude oil increased earnings between quarters. This benefit was partly offset by higher operating expenses, including fuel, and increased exploration expense. Tax charges were also higher between periods. Foreign currency effects increased earnings by $26 million in the 2011 second quarter, compared with an increase of $107 million a year earlier.

The average sales price for crude oil and natural gas liquids in the 2011 second quarter was $107 per barrel, compared with $71 a year earlier. The average price of natural gas was $5.49 per thousand cubic feet, up from $4.40 in last year's second quarter.

Net oil-equivalent production of 2.00 million barrels per day in the second quarter 2011 was down 38,000 barrels per day from a year ago. Production increases from project ramp-ups in Canada and Brazil were more than offset by an approximately 40,000 barrels per day negative effect of higher prices on volumes related to cost-recovery and variable-royalty contractual terms, and normal field declines. The net liquids component of oil-equivalent production decreased 2 percent to 1.39 million barrels per day, while net natural gas production declined 1 percent to 3.67 billion cubic feet per day.
CAPITAL AND EXPLORATORY EXPENDITURES

Capital and exploratory expenditures in the first six months of 2011 were $13.4 billion, compared with $9.4 billion in the corresponding 2010 period. This represents 52 percent of the company's planned annual capital and exploratory expenditures announced in December 2010. The amounts included $584 million in 2011 and $609 million in 2010 for the company's share of expenditures by affiliates, which did not require cash outlays by the company. Expenditures for upstream represented 91 percent of the companywide total in 2011. These amounts exclude the acquisition of Atlas Energy, Inc., which was accounted for as a business combination.

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ExxonMobil Reports $10.7B in 2Q11, Up 41%

- ExxonMobil Reports $10.7B in 2Q11, Up 41%

Thursday, July 28, 2011
ExxonMobil Corp.

ExxonMobil announced its estimated second quarter 2011 results.

ExxonMobil's Chairman Rex W. Tillerson commented, "ExxonMobil recorded strong results during the second quarter of 2011, while investing at a record level of over $10 billion to develop new supplies of energy to meet growing world demand.

"Second quarter earnings of $10.7 billion were up 41% from the second quarter of 2010, reflecting higher crude oil and natural gas realizations, improved Downstream results and continued strength in Chemicals. First half 2011 earnings of $21.3 billion increased 54% over the first half of 2010.

"In the second quarter, capital and exploration expenditures were a record $10.3 billion, up 58% from the second quarter of 2010.

"Oil-equivalent production increased by 10% over the second quarter of 2010, driven by our world-class assets in Qatar and our growing unconventional gas portfolio.

"The Corporation returned over $7 billion to shareholders in the second quarter through dividends and share purchases to reduce shares outstanding."

SECOND QUARTER HIGHLIGHTS

• Earnings were $10,680 million, an increase of 41% or $3,120 million from the second quarter of 2010.
• Earnings per share were $2.18, an increase of 36%.
• Capital and exploration expenditures were a record $10.3 billion, up 58% from the second quarter of 2010.
• Oil-equivalent production increased 10% from the second quarter of 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up over 12%.
• Cash flow from operations and asset sales was $14.4 billion, including asset sales of $1.5 billion.
• Share purchases to reduce shares outstanding were $5 billion.
• Dividends per share of $0.47 increased by 7% compared to the second quarter of 2010.
• Announced two major oil discoveries and a gas discovery in the deepwater Gulf of Mexico after drilling the company's first post-moratorium deepwater exploration well.
• Concluded the acquisitions of two Phillips companies, nearly doubling our Marcellus acreage footprint to more than 700,000 net acres.

Second Quarter 2011 vs. Second Quarter 2010

Upstream earnings were $8,541 million, up $3,205 million from the second quarter of 2010. Higher liquids and natural gas realizations increased earnings by $3.6 billion. Production mix and volume effects decreased earnings by $480 million.

On an oil-equivalent basis, production increased 10% from the second quarter of 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up over 12%.

Liquids production totaled 2,351 kbd (thousands of barrels per day), up 26 kbd from the second quarter of 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was up 4%, as increased production in Qatar, the U.S. and Iraq more than offset field decline.

Second quarter natural gas production was 12,267 mcfd (millions of cubic feet per day), up 2,242 mcfd from the second quarter of 2010, driven by additional U.S. unconventional gas volumes and project ramp-ups in Qatar.

Earnings from U.S. Upstream operations were $1,449 million, $584 million higher than the second quarter of 2010. Non-U.S. Upstream earnings were $7,092 million, up $2,621 million from last year.

Downstream earnings of $1,356 million were up $136 million from the second quarter of 2010. Margins increased earnings by $60 million. Positive volume and mix effects increased earnings by $150 million, while all other items decreased earnings by $70 million. Petroleum product sales of 6,331 kbd were 27 kbd higher than last year's second quarter.

Earnings from the U.S. Downstream were $734 million, up $294 million from the second quarter of 2010. Non-U.S. Downstream earnings of $622 million were $158 million lower than last year.

Chemical earnings of $1,321 million were $47 million lower than the second quarter of 2010. Improved margins increased earnings by $120 million, while lower sales volumes decreased earnings by $90 million. Other items, mainly unfavorable tax effects, decreased earnings by $80 million. Second quarter prime product sales of 6,181 kt (thousands of metric tons) were 315 kt lower than last year's second quarter.

Corporate and financing expenses were $538 million, up $174 million from the second quarter of 2010 due to the absence of favorable 2010 tax items.

During the second quarter of 2011, Exxon Mobil Corporation purchased 67 million shares of its common stock for the treasury at a gross cost of $5.5 billion. These purchases included $5 billion to reduce the number of shares outstanding, with the balance used to offset shares issued in conjunction with the company's benefit plans and programs. Share purchases to reduce shares outstanding are currently anticipated to equal $5 billion in the third quarter of 2011. Purchases may be made in both the open market and through negotiated transactions, and may be increased, decreased or discontinued at any time without prior notice.

First Half 2011 vs. First Half 2010

Earnings of $21,330 million increased $7,470 million from 2010. Earnings per share increased 47% to $4.32.

FIRST HALF HIGHLIGHTS

• Earnings were $21,330 million, up 54%.
• Earnings per share increased 47% to $4.32.
• Oil-equivalent production was up 10% from 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 12%.
• Cash flow from operations and asset sales was $32.6 billion, including asset sales of $2.8 billion.
• The Corporation distributed over $14 billion to shareholders in the first half of 2011 through dividends and share purchases to reduce shares outstanding.
• Capital and exploration expenditures were a record $18.1 billion, up 35% from the first half of 2010.

Upstream earnings were $17,216 million, up $6,066 million from 2010. Higher crude oil and natural gas realizations increased earnings by $6.2 billion. Production mix and volume effects decreased earnings by $710 million, while all other items, mainly gains from asset sales, increased earnings by $600 million.

On an oil-equivalent basis, production was up 10% compared to the same period in 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 12%.

Liquids production of 2,375 kbd increased 5 kbd compared with 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was up 3%, as higher volumes from Qatar and the U.S. more than offset field decline.

Natural gas production of 13,390 mcfd increased 2,538 mcfd from 2010, driven by additional U.S. unconventional gas volumes and project ramp-ups in Qatar.

Earnings from U.S. Upstream operations for 2011 were $2,728 million, an increase of $772 million. Earnings outside the U.S. were $14,488 million, up $5,294 million.

Downstream earnings of $2,455 million increased $1,198 million from 2010. Margins increased earnings by $510 million. Positive volume and mix effects increased earnings by $520 million, while all other items, mainly favorable foreign exchange effects, increased earnings by $170 million. Petroleum product sales of 6,299 kbd increased 49 kbd from 2010.

U.S. Downstream earnings were $1,428 million, up $1,048 million from 2010. Non-U.S. Downstream earnings were $1,027 million, $150 million higher than last year.

Chemical earnings of $2,837 million were $220 million higher than 2010. Stronger margins increased earnings by $470 million, while lower volumes decreased earnings by $60 million. Other items, including unfavorable tax effects and higher maintenance expenses, decreased earnings by $190 million. Prime product sales of 12,503 kt were down 481 kt from 2010.

Corporate and financing expenses were $1,178 million, up $14 million from 2010.

Gross share purchases through the first half of 2011 were $11.2 billion, reducing shares outstanding by 136 million shares.

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