Tethys Highlights 2Q11 Production

- Tethys Highlights 2Q11 Production

Monday, August 15, 2011
Tethys Petroleum Ltd.

Tethys provided an operational update in conjunction with its financial results for the quarter ended June 30, 2011.

Operational Update - Recent Highlights

Kazakhstan

• AKD05 appraisal well flowed at over 1,500 bopd of good quality oil.
• KBD01 (Kalypso) exploration well close to total depth.
• Drilling operations commenced on AKD06, an appraisal well of the Doris oil discovery targeting the Cretaceous sand.
• Stage 2 oil production facilities installed.

Tajikistan

• East Olimtoi exploration well EOL09 has reached total depth and electric logs are currently being run.
• New exploration well "Persea 1" spudded with total depth expected to be 2,700 meters.
• Aero magnetics and gravity gradiometry survey underway.

Uzbekistan

• Initial jet pump trial on the North Urtabulak oilfield successful.
• Negotiations continue on new production and exploration contracts.

Kazakhstan

The appraisal program on the Doris oil discovery and further exploration on the Akkulka and Kul-Bas block is continuing.

The Kalypso (KBD01) wildcat exploration well which, is targeting primarily a large potential structural closure at Permo-Carboniferous level, is currently at a depth of 4,128 meters in what is interpreted to be Carboniferous limestones. Some oil and gas indications have been observed but the significance of these cannot be ascertained until electric logs have been run and further evaluation carried out. The planned total depth of this well is approximately 4,300 meters.

The Doris (AKD06) appraisal well, which is targeting primarily the Cretaceous sandstone interval, which flowed at over 5,400 barrels of oil per day ("bopd") in the AKD01 Doris discovery well, is currently at a depth of 641 meters. This well is located on an amplitude anomaly derived from detailed spectral analysis of the new 3D seismic dataset and is aimed at establishing a stratigraphic component to the Doris oil accumulation. The planned total depth of this well is 2,400 meters and it is estimated to be completed by October 2011.

Tajikistan

The East Olimtoi (EOL09) exploration well has just reached its total depth of 3,765 meters in the Akdzhar formation. Electric logs are currently being run in the Bukhara and Akdzhar sections as well as the lower part of the overlying Alai formation. The initial results from the raw logs indicate some zones of interest in the Bukhara limestone sequence but further data gathering and analysis is required. The Alai formation showed both good oil and gas shows while drilling (with oil and gas to surface) and the electric logs through this interval indicate several hydrocarbon bearing zones with no evidence of any oil-water contact. Following a full analysis of the Bukhara interval, a testing program will commence. The well is exploring an attractive salt induced structure located in the south-east of the PSC area, south of the town of Kulob and only some 10 kilometres north-west of the Afghan border. The nearest oilfield in that region is the Beshtentak field some 75 km to the north-west.

The Persea 1 exploration well is primarily targeting the Bukhara limestone formation in a four-way dip closed structure with the overlying Alai formation forming a potential secondary target. The well is currently at a depth of 606 meters where casing has been run. The planned total depth of this well is 2,700 meters and it is expected that this will be reached by October. The well is located near the town of Kurgon-Teppa in the south-west part of the PSC area with the nearest field in the same Bukhara horizon being Kyzyltumshuk to the immediate south and south-east of the prospect.

The Company has commenced the gravity, gradiometry and magnetic aerial survey. The survey will cover the entire area of the 35,000 km2 Bokhtar Production Sharing Contract Area and will provide additional and more aerially extensive data to complement the existing seismic acquisition. Over 34% of the survey data has now been acquired and the final processed data and results are expected in 4Q 2011. The Company has previously stated that it is seeking a suitable farm-in partner for its exploration program in Tajikistan and these geophysical data are an important part of the information relating to such a potential farm-in. Discussions with several parties are ongoing.

Uzbekistan

The initial results of the recent jet pump trial on the North Urtabulak oilfield appear successful with oil rates on the two test wells increasing by some 20%. Further work is now underway to ascertain the economics of extending the use of jet pumps on the field (and potentially on any new fields the Company is successful in contracting) which, together with the likely effects of the water injection reconfiguration carried out earlier this year, should have a positive impact on oil production levels from the field in the latter half of 2011.

Negotiations continue with the Uzbek authorities on production enhancement contracts for two further oilfields in the Bukhara area, and work continues on the joint exploration study agreement carried out with the Institute of Geology and Prospecting for Oil and Gas Department of the State Holding Company NHC Uzbekneftegas. This study is now almost complete. Tethys hopes this study will lead onto contracts over these exploration areas.

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Caza Spotlights Operational, Financial Results for 2Q11

- Caza Spotlights Operational, Financial Results for 2Q11

Monday, August 15, 2011
Caza O&G Inc.

Caza O&G provided its unaudited financial and operational results for the six months ended June 30, 2011.

Second Quarter Financial Highlights

• Caza's production increased 32% to 18,130 Boe for the three-month period ended June 30, 2011, from 13,712 Boe for the comparative period in 2010. This represents an average daily production rate increase of 48 Boe/d for the three month period ended June 30, 2011, 199 Boe/d as compared to 151 Boe/d for the comparative period. As anticipated, Q2 2011 production was slightly lower than Q1 2011 (which was 23,974 Boe) due to standard production curve declines in certain wells. Recently drilled wells that are in various stages of completion are expected to more than make up for the decline (see "Second Quarter Operational Highlights" below).
• Caza had a cash balance of $24,533,451 as of June 30, 2011, as compared to $9,375,345 at June 30, 2010 and $33,885,900 at December 31, 2010. The increase is attributable to the placing announced on Nov 15 2010. Caza's working capital balance at June 30, 2011, was $20,870,708 as compared to $26,612,514 at March 31, 2011. The decrease in Caza's working capital balance primarily represents the investments made to drill the O.B. Ranch #2 development well in Wharton County, Texas, the Caza Elkins 3401 & 3402 wells in Midland County, Texas, and the Caza 158 #3 in Upton County, Texas.
• Revenues from oil and gas sales increased 112% to $843,836 for the three-month period ended June 30, 2011, up from $398,883 for the comparative period in 2010. The increase in revenues was primarily due to the additional wells brought on since the comparative period. The average combined price received by Caza increased 60% to $46.54 per Boe during the three-month period ended June 30, 2011, from $29.09 per Boe during the comparative period in 2010.
• General and Administrative expenses were $1,435,156 ($1,403,088 net of reimbursements) for the three-month period ended June 30, 2011, as compared to $1,188,962 ($1,078,739 net of reimbursements) for the comparative period in 2010. The change in General and Administrative costs are a result of additional costs incurred and changes in reporting requirements as a result of converting to the International Financial Reporting Standards. During the three month period ended June 30, 2010, the Company received reimbursements that resulted from certain joint venture agreements that provided reductions in overhead costs that expired April 8, 2010.

Second Quarter Operational Highlights

• Drilling commenced on the O.B. Ranch #2 development well in Wharton County, Texas in May 2011. The well reached its target depth of 13,210 feet in June 2011, and electric logs were obtained through the target depth indicating potential pay in the Frio and targeted Cook Mountain formations. The well was fracture stimulated at the end of July 2011, and is currently being flowed back in order to clean up the fracture fluids. The well has been placed on an extended well test, and the market will be updated once stabilized flow rates have been achieved.
• The Caza Elkins 3401 well in Midland County, Texas, reached a total depth of 11,854 feet in June 2011. The rig was immediately moved to the Caza Elkins 3402 location, which reached a total depth of 11,852 feet in July 2011. Log data from both wells indicated multiple potential pay sands for both oil and gas in the Spraberry, Wolfcamp, Strawn, Atoka and Mississippian/Devonian formations. The fracture stimulation program for the Caza Elkins 3401 well began on July 28, 2011. The fracture stimulation program for the Caza Elkins 3402 well began earlier than anticipated on August 12, 2011. Both wells are currently being flowed back in order to clean up the fracture fluids. Caza will update the market once initial flow rates have been established for each well.
• The Caza 158 #3 well on the Windham property reached its target depth of 9,824 feet in June 2011, and Caza elected to participate in the operator's proposal to complete the well. The well has been fracture stimulated across all potentially productive intervals seen on the logs, which include the Spraberry/Wolfcamp, Penn and Strawn formations. The Caza 158 #3 was the fourth well drilled and completed on this property. The Caza 158 #1, 158 #2 and 162 #1 wells are currently at various stages in their respective fracture stimulation programs, but are all producing oil and natural gas.

W. Michael Ford, Chief Executive Officer commented, "I am very pleased with the progress that we have made in 2011, both operationally and from a financial perspective. In the three months to June 30, 2011, Caza has continued to progress a busy work program, which should add further production, reserves and cash flow to the solid platform that we have created through our endeavors to date.

"Revenues have materially risen due to increased oil and gas production levels and a supportive price environment. As we add production through our exploration and development campaign, the Company and the shareholders should continue to benefit.

"I look forward to updating the market on future exploration activities and established flow rates associated with wells that are currently in various stages of completion operations."

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Gran Tierra Reaches 'Significant Milestones' in 2Q11

- Gran Tierra Reaches 'Significant Milestones' in 2Q11

Tuesday, August 09, 2011
Gran Tierra Energy Inc.

Gran Tierra announced its financial and operating results for the quarter ended June 30, 2011. All dollar amounts are in United States dollars unless otherwise indicated.

Highlights for the quarter include:

• Quarterly production of 18,141 barrels of oil equivalent per day ("BOEPD") net after royalty ("NAR"), a 36% increase in average daily production from the same period in 2010 of 13,376 BOEPD due to additional production from existing field developments, new production from recent field discoveries, and production growth from the recently acquired assets of Petrolifera Petroleum Ltd. ("Petrolifera");
• Quarterly oil production of 17,525 barrels of oil per day ("BOPD") NAR, a 32% increase in average daily production from the same period in 2010 of 13,234 BOPD NAR;
• Quarterly gas production of 3.7 million cubic feet per day ("MMCFD") NAR, a 334% increase in average daily production from the same period in 2010 of 0.8 MMCFD NAR;
• Revenue and other income for the quarter of $162.1 million, a 93% increase over the same period in 2010;
• Net income of $31.6 million or $0.11 per share basic and diluted compared to net income of $17.4 million or $0.07 per share basic and diluted in the same period in 2010;
• Funds flow from operations of $88.6 million compared to $44.3 million for the same period in 2010;
• Cash and cash equivalents were $211.4 million at June 30, 2011 compared to $355.4 million at December 31, 2010 and working capital decreased to $215.4 million at June 30, 2011 compared to $265.8 million at December 31, 2010;
• Moqueta-5 delineation well testing was initiated from a single zone at production rates of approximately 730 BOPD over 10 days with a jet pump, with additional testing ongoing;
• Major infrastructure projects were completed including the construction and commissioning of the Moqueta to Costayaco flow-line with first short-term test production commencing in June, and the connection of the Costayaco field into Colombia's national electrical system;
• First production contribution from Gran Tierra Energy's Brazil assets in the Recôncavo Basin was recorded in the quarter;
• Continued to mature plans for robust exploration, delineation and development drilling campaigns in Colombia, Brazil, Peru and Argentina through 2011 and into 2012.

"Several significant milestones were achieved in the second quarter of 2011, positioning the Company to achieve continued growth into the future. The completion of the Moqueta to Costayaco flow-line and initiation of production was a major achievement. This is the first time that an oil field in Colombia has been discovered and test production initiated with operations entirely supported by helicopter and without access by road minimizing the environmental footprint of Gran Tierra Energy's operations at this early stage of development," said Dana Coffield, President and Chief Executive Officer of Gran Tierra Energy. "We achieved record production in the quarter due to effective management of existing producing fields in Colombia and Argentina and new production from recent discoveries in Colombia and Brazil. Record cash flow, and progress in permitting and contracting, are supporting the execution of our planned exploration and drilling program scheduled for the balance of 2011 and into 2012," concluded Coffield.


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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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Delta Ends Strong in 2Q11

- Delta Ends Strong in 2Q11

Thursday, August 04, 2011
Delta Petroleum Corp.

Delta announced its financial and operating results for the second quarter 2011.

Carl Lakey, Delta's CEO and President stated, "We are pleased to provide our shareholders with another solid operating quarter coupled with the accomplishment of some very important strategic steps. We sold our remaining non-core assets, which reduced our leverage and provided sufficient liquidity to continue our deep shale evaluation and development in the Vega Area. While the strategic alternatives process, the 2C well results, and the Netherland Sewell report were all announced subsequent to the end of the quarter, much of the efforts that went into those steps occurred in the second quarter. The 2B and 2C well results and Netherland Sewell's report are very important contributions that support Delta's intrinsic value and aid our strategic alternatives process."

VEGA AREA SHALE EVALUATION UPDATE

As previously announced, the Delta 2C well began producing hydrocarbons on Wednesday, July 20, at a rate of 5.4 million cubic feet of gas per day (MMcf/d), which was choke-restricted with a 7/64 of an inch choke and 8,360 psi of flowing tubing pressure. Gas sales from the well began on Thursday, July 21 from the Niobrara and Frontier formations only. The well is currently producing between 2.5 – 3.5 MMcf/d with 6,100 psi of flowing tubing pressure. The well choke is currently set at 9/64 of an inch. The Mancos shale, Corcoran and Williams Fork formations remain uncompleted.

The Delta 2B well in the Vega Area of the Piceance Basin drilled through a portion of the Mancos formation and reached total depth of 10,700 feet. Below the Williams Fork the well was completed in 1,200 feet of shale in the Corcoran and the upper portion of the Mancos formation. Gas production began on April 24 and sales commenced on April 29. As announced on May 10, the 2B well experienced sustained production of 3.3 MMcf/d from only the Mancos and Corcoran formations. The well is currently producing 0.6 MMcf/d. The information available indicates that the natural fractures in the 2B well may have prematurely closed by the high flow rate (6 MMcf/d) during initial flowback activities, which has subsequently hindered production. The Company is currently evaluating refracturing the well in the Mancos and Corcoran formations to reestablish higher production levels in the well.

The Company is currently drilling the 12B well. The current depth is approximately 8,500 feet with a target depth of 13,000 feet. It is expected that the target depth will reach the Frontier formation. Total depth is expected to be reached during September. Once completed, this well will hold the acreage of the federal Sheep Creek Unit and bring the Company's Vega leasehold up to 95% held by production.

STRATEGIC ALTERNATIVES UPDATE

On July 6, 2011, Delta announced that it had engaged Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors to the Company in conducting a strategic alternatives process aimed at maximizing shareholder value and dealing with the Company's 2012 debt maturities. Through this process, the Board of Directors is evaluating all opportunities available, including a potential sale of the Company. The process is in its early stages and the Company does not expect to make further public comment regarding the process until the Board of Directors has approved a specific transaction or otherwise determines that disclosure of significant developments, if any, is appropriate.

OPERATIONS UPDATE

Current production of the Company approximates 28 million cubic feet equivalent per day (MMcfe/d) net.

2011 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

Delta will focus its current available capital for the remainder of 2011 on drilling and completing the 12B well and completing the remaining two previously drilled Williams Fork wells. The completions of the remaining two previously drilled wells have been postponed to the fourth quarter of 2011; however, these plans could be altered depending on shale well results, with capital potentially being reallocated to additional shale activity. Developments related to the strategic alternatives process may also affect current capital spending plans.

Production for the third quarter 2011 is expected to be between 2.6 Bcfe and 2.7 Bcfe.

RESULTS FOR THE SECOND QUARTER 2011

For the quarter ended June 30, 2011, the Company reported total production of 3.2 Bcfe. Production from continuing operations was 2.8 Bcfe, remaining flat when comparing second quarter 2011 to the prior year period. Revenue from oil and gas sales was $16.9 million, an increase of 14% when compared to the prior year period of $14.8 million. The average natural gas price received during the quarter ended June 30, 2011 increased to $5.31 per thousand cubic feet (Mcf) compared to $4.92 per Mcf for the prior year period. The average oil price received during the quarter ended June 30, 2011 increased to $86.87 per barrel compared to $58.29 per barrel for the prior year period.

The Company reported a second quarter net loss attributable to Delta common stockholders of ($963,000), or ($0.03) per diluted share, compared to a net loss attributable to Delta common stockholders of ($149.8 million), or ($5.43) per diluted share, in the second quarter of 2010. The decrease in net loss is primarily due to a decrease in dry hole costs and impairments and a decrease in operating expenses, as well as discontinued operations.

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Endeavour Makes Headway in US, UK in 2Q11

- Endeavour Makes Headway in US, UK in 2Q11

Wednesday, August 03, 2011
Endeavour International Corp.

Endeavour reported adjusted EBITDA for the second quarter of 2011 was $7.6 million compared to $13.1 million in the second quarter of 2010 and $4.1 million in the first quarter of 2011. On a GAAP basis, net loss was $15.6 million for the second quarter of 2011 as compared to net income of $0.6 million for the same quarter in 2010.

Business Highlights:

• North Sea:
  • Commenced drilling operations at Bacchus
  • Agreement of commercial terms for the processing and transportation of the Greater Rochelle production on the Scott Platform
  • Contracts awarded for the pipeline and umbilical's for the development of Greater Rochelle area
• U.S. Onshore:
  • Announced the acquisition of 50,000 net acres in Marcellus Shale with existing production and pipeline infrastructure
  • 8 gross wells brought on production through July in Louisiana and East Texas
  • 4 additional gross wells completing or drilling in Louisiana
• Financial:
  • Increased available capital in July resulting in cash on hand of approximately $245 million

"During the second quarter financial results were as expected, while we made substantive progress on our U.K. development projects and our U.S. Haynesville unconventional gas play. Adding to this progress, our announced strategic acquisition of acreage and infrastructure gives us exposure to 1.0 to 1.3 trillion cubic feet of gross recoverable natural gas resource potential in the Marcellus area. We are confident that the balanced portfolio can deliver significant growth in both oil and natural gas production in the near-term," said William L. Transier, chairman, chief executive officer and president. "During July, the Company enhanced its flexibility and growth potential by adding approximately $100 million in available liquidity in addition to funding the $110 million needed for the Marcellus acquisition. The additional capital provides the resources to take advantage of opportunities for growth from existing and emerging parts of our portfolios, while also providing liquidity in case of any unforeseen events."

Operational Update

North Sea

The drilling of the three planned development wells is underway in the Bacchus field in Block 22/06a in the Central North Sea. Production from the development is expected to begin in the fourth quarter. The Company has a 30% working interest in the field.

In the Greater Rochelle area, the Company awarded two contracts for the design and fabrication of components for the subsea development that will link production for processing and transport to the nearby Scott platform. The contract for the drilling rig for the development will be finalized during the third quarter. Endeavour is operator and holds a 44% ownership interest in the Greater Rochelle development which is now comprised of Blocks 15/26b, 15/26c and 15/27.

U.S. Onshore

Endeavour will assume operated interests in leasehold, producing wells, pipeline and related facilities held by SM Energy Company and its minority partners in McKean and Potter Counties. The transaction increases Endeavour's leasehold interest in the Marcellus shale to approximately 93,000 gross (68,000 net) acres with more than 300 identified drilling locations in McKean and Cameron counties alone. The purchase will strengthen the Company's position in one of the most active and low-cost U.S. shale plays and provides significant production and reserve potential. The transaction is expected to close in the fourth quarter. In the Company's existing Marcellus acreage in Cameron County, two horizontal wells are waiting on completion, while the existing Daniel Field gathering infrastructure is being expanded.

During the quarter, Endeavour brought six gross wells on production in its Haynesville and Cotton Valley plays in Louisiana and East Texas, respectively. In July, production commenced from two additional gross wells with four other wells currently completing or drilling.

In the Montana Heath shale oil play, the Company and its partners expect to launch drilling operations on four vertical wells in the third quarter. In the Alabama Devonian shale gas play, Endeavour has successfully drilled and cased a horizontal re-entry of a previously drilled vertical pilot well. This well is anticipated to be completed and tested by the fourth quarter.

Financing Update

During the second quarter, the Company completed the redemption of all of its outstanding $81.25 million of 6% Senior Notes due 2012. The Notes were exchanged at 100% of principal amount plus accrued and unpaid interest.

In July, Endeavour closed on its private placement of $135 million aggregate principal amount of 5.5% convertible senior notes due 2016, including the full exercise by the initial purchasers of their option to purchase an additional $15 million principal amount of the offering. The Company intends to use the net proceeds of the offering primarily to fund its announced acquisition of operated interest in the Pennsylvania Marcellus shale play. Endeavour also expanded its credit facility by $75 million under the terms of its Senior Term Loan.

In addition, the Company entered into a letter of credit facility agreement with Commonwealth Bank of Australia in the amount of pounds Sterling 20,600,000 (approximately $33 million). Associated with the letters of credit was the release of the restrictions on approximately $33 million of cash.

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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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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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Talisman Touts 2Q11 Results

- Talisman Touts 2Q11 Results

Thursday, July 28, 2011
Talisman Energy Inc.

Talisman reported its operating and financial results for the second quarter of 2011. The company is reporting under International Financial Reporting Standards (IFRS) and all values in this release are in US$ unless otherwise stated.

• Cash flow was $897 million for the quarter, up 14% compared to $790 million a year ago and $811 million in the first quarter.
• Net income was $698 million versus $572 million in 2010 and a net loss of $326 million in the previous quarter.
• Earnings from operations were $168 million, up 14% from the same period last year and up from $157 million in the prior quarter.
• Production for the quarter averaged 420,000 boe/d, compared to 411,000 boe/d in 2010. Production from ongoing operations was up 13%, compared to 372,000 boe/d a year ago.
• Net debt at June 30, 2011 was $3 billion versus $2.5 billion at March 31, 2011.
• The company closed a second transaction with Sasol, selling a 50% interest in its Cypress A Montney shale properties for C$1.05 billion, including certain future development costs.
• Talisman acquired additional acreage in the Alberta Duvernay shale play, bringing its land position to 360,000 net acres.
• The company continues to deliver strong natural gas volumes in Southeast Asia, with price realizations of $9.78/mcf.
• Talisman plans to drill a number of important exploration wells in the second half of this year.

"Talisman achieved a strong financial performance this quarter" said John A. Manzoni, President & CEO. "We continue to grow and strengthen our shale portfolio in North America, and are looking forward to results from a number of significant exploration wells in the second half of the year.

"Total volumes in the quarter were 2% above the comparable number for 2010, although down from the first quarter, largely due to annual maintenance turnarounds. Excluding volumes from assets which have been sold, underlying growth in production is 13% year over year.

"We continue to see strong growth in North American shale volumes, which averaged approximately 470 mmcfe per day in the quarter, an increase of 178% over the same period last year and up 4% over the previous quarter. Our success in the Marcellus is continuing, with production averaging over 400 mmcf per day during the quarter.

"In the liquids-rich Eagle Ford shale play, we now have six rigs running and are planning to build to 10 by year-end. In the Montney shale, we are operating 10 rigs and closed the second transaction with Sasol during the quarter, for approximately C$1 billion, including certain future development costs.

"We are continuing to build our North American shale portfolio, with a sizeable land acquisition during the quarter, in what we hope will emerge as another successful liquids-rich play. Talisman now holds approximately 360,000 net acres in the Alberta Duvernay shale play, acquired at an average cost of about $2,000 per acre. We will begin drilling into the play in the second half of the year, with two rigs.

"In Southeast Asia, volumes continue to be strong, although down from a year ago, reflecting a one-time upward adjustment in the second quarter of last year and annual maintenance turnarounds. Natural gas prices in the region averaged about $9.80 per mcf during the quarter, reflecting strong regional demand and linkage to oil prices.

"North Sea volumes were down relative to both the previous year and the prior quarter, with annual maintenance turnarounds and natural production declines. Ongoing planned turnarounds will result in slightly lower North Sea production in the third quarter, with a return to higher volumes in the fourth quarter when work is completed. Work on future development projects continues and we have seen encouraging early test results at the Grosbeak discovery in Norway.

"The Yme project in Norway took a significant step forward with offshore installation completed at the end of the quarter; however there is still a significant amount of remaining work to commission the topsides. The amount of rework which is required on the platform has turned out to be substantial, and I believe we are now close to defining the full scope. In light of what we have found we are now moving our expectation for first production to the second quarter of 2012.

"In addition, we have seen a slight delay in the final stages of commissioning the non-operated Kitan project, and our Eagle Ford ramp-up was delayed by about three months.

"This combination of factors has led us to revise our current view of production for this year, including Colombia, to between 430,000 and 440,000 boe per day. Excluding Colombia, this represents only slight absolute growth over last year, although it represents between 7 - 10% organic growth from ongoing operations in 2010. It is, nonetheless, below our minimum expectation of 5% absolute growth for the year and I am very disappointed to miss our own target for the first time since I joined the company.

"The factors which have led to this reduction are specific and identifiable, and we remain confident in the underlying quality of the portfolio. Our growth target of 5 - 10% annually in the medium term remains firmly in place.

"There are continuing signs of success in the early testing phase of our international exploration portfolio, which has been largely focused on Colombia and Papua New Guinea to date. In the second half of the year, we plan to drill significant wells in Indonesia, Peru, Poland and the Kurdistan region of northern Iraq.

"Cash flow was $897 million during the quarter, up 14% year over year, reflecting higher oil prices. Similarly, earnings from operations, which adjust for non-operational impacts, were also up 14% to $168 million.

"Net income was $698 million compared to $572 million a year earlier and a loss of $326 million in the first quarter. This reflects the impact of changing commodity prices on the mark-to-market value of held-for-trading financial instruments and changes in the non-cash value of share based payments.

"We continue to expect that our cash exploration and development capital spending will be between $4 to $4.5 billion. In addition, we have spent $510 million on land purchases in the quarter.

"I am confident in the structure of our portfolio to deliver long-term, profitable growth of 5 - 10%. The project set-backs we have experienced are localized, but nevertheless, reinforce the need to continue the improvements we have begun across our business to address project execution and delivery. We can look forward to getting these issues behind us, and to drilling a number of important exploration wells through the second half. The underlying financial performance was strong this quarter, and we will continue to focus on effectively delivering against our strategy, with our strong portfolio of assets."

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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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Husky Boosts Production, Profit in 2Q11

- Husky Boosts Production, Profit in 2Q11

Wednesday, July 27, 2011
Husky Energy Inc.

Husky continued to execute against its strategic plan in the second quarter of 2011, recording strong growth in earnings, cash flow and production compared to the same period a year earlier. Net earnings grew 274 percent compared to the second quarter of 2010, cash flow increased 104 percent, and production grew 10 percent.

"This marks a second consecutive quarter of strong results across key performance metrics," said Husky CEO Asim Ghosh. "Over the past 12 months we have made significant progress in implementing our strategic plan and executing a financing strategy to carry out our growth initiatives. The momentum we have built in growing production combined with a strong performance from our Midstream and Downstream segments, has enabled us to deliver solid improvements in results."

Production for the quarter averaged 311,600 barrels of oil equivalent per day (boe/day), compared to 283,900 boe/day in the second quarter of 2010. Production gains were achieved despite forest fire and pipeline disruptions in northern Alberta as the Company realizes the benefits from recent acquisitions of oil and gas properties in Western Canada and increased investment in organic growth opportunities.

"In addition, we continue to achieve key milestones in advancing our growth pillars," said Ghosh. "This quarter Husky and its partner in the Liwan Gas Project reached agreements on natural gas prices and have jointly approved the Overall Development Plan (ODP) for the first phase of the development. The submission of the ODP to Chinese government authorities will now take place. This will be a cornerstone development for Husky as we look to build a substantial oil and gas business in the region."

Highlights from the second quarter included the following:

• Net earnings of $669 million, or $0.71 per share (diluted). This compares to net earnings of $179 million or $0.19 per share in the second quarter of 2010.
• Cash flow from operations of $1,511 million, or $1.67 per share (diluted), compared to cash flow of $739 million or $0.87 per share in the second quarter of 2010.
• Drilling was completed on an additional producing well at the North Amethyst field in the Atlantic Region. North Amethyst achieved average gross production of 33,000 bbls/day (23,000 net to Husky) in the quarter.
• Executed an agreement for the sale of gas from the first phase of the Liwan Gas Project The gas price mechanism is in line with the anticipated Guangdong "city gate" market price and provides for an attractive rate of return on the project.
• Phase 1 of the Sunrise Energy Project continued to achieve its milestones, with the first 12 steam-assisted gravity drainage (SAGD) horizontal well pairs completed on schedule.
• Closed a $1.2 billion common share offering, providing the Company with enhanced financial flexibility to accelerate its growth strategy.

Production volumes in the second quarter were in line with annual guidance of 290,000 to 315,000 boe/day. Volumes were impacted by difficult operating conditions in the Slave Lake region where forest fires caused production interruptions, and by the outage of the Rainbow pipeline. The northern portion of the Rainbow pipeline was out of operation through May and June and impacted production by approximately 13,600 boe/day. The northern portion of the pipeline remains shut down, however, Husky has been able to reduce the impact of the outage to approximately 11,000 boe/day through a number of mitigating activities.

"Our thoughts and support are with the people of the Slave Lake region as they look to recover from this devastating event and begin the long process of rebuilding their homes and lives," said COO Rob Peabody. "We are grateful none of our workers were injured and our team in the region deserves a great deal of credit for the work they are doing to mitigate the effects of the disruptions."

Reduced volumes from the Slave Lake region were offset by recent acquisitions and strong performance from the North Amethyst field, which began producing in May 2010. A turnaround of the SeaRose Floating Production, Storage and Offloading (FPSO) vessel, originally scheduled for 16 days, was completed in two days in early July.

Second quarter earnings and cash flow growth were driven by higher production, higher realized crude oil and natural gas prices and strong throughput rates and margins within the Downstream segment. This was partially offset by a stronger Canadian dollar.

Average realized crude oil pricing in the quarter was $86.90 per barrel, compared to $64.75 in the same period of 2010. U.S. refining market crack spreads increased in the quarter, with the average Chicago 3:2:1 crack spread at U.S. $28.90 per barrel, compared to U.S. $11.33 in the same period of 2010.

KEY AREA SUMMARY AND GROWTH UPDATE: THE FOUNDATION BUSINESS

Western Canada - Unconventional and Conventional

The Company continues to maintain production levels in Western Canada and has accelerated development of its emerging oil and gas resource portfolio.

Oil Resource Plays

Husky has an extensive Western Canadian oil resource land base of approximately 500,000 acres and is advancing exploration and development of its highest-potential prospects.

In the second quarter, the Company acquired 11,500 acres in the Bakken formation in south central Saskatchewan, adjacent to its Oungre oil resource lands. Husky now holds 18,700 net acres in this light oil play. Current production from four producing wells is approximately 600 bbls/day and two additional wells have been drilled and will be completed once wet conditions recede. Given the positive results from the first Oungre Bakken wells, Husky has committed additional funds to accelerate the drilling and completion of 10 additional wells in the second half of 2011.

The Company continues to develop its opportunities in the Lower Shaunavon zone in southern Saskatchewan, the Viking zone in southwest Saskatchewan and central Alberta, and in the northern Cardium resource trend at Wapiti and Kakwa in west central Alberta. Spring break-up and extended wet conditions delayed drilling and completion plans in the second quarter, however, the Company expects to accelerate its activities in the second half of the year. The Company drilled two wells at its central Alberta Viking oil resource project in the second quarter, following a six well drilling program in the first quarter. A total of 11 Viking wells have been placed on production from this area along with another three from the southwestern Saskatchewan Viking oil resource project.

Gas Resource Plays

Husky continues to build its gas resource portfolio in Alberta and British Columbia, with approximately 16,000 acres of new land acquired in the quarter, adding to the Company's existing base of approximately 800,000 acres.

A key focus of activity has been the liquids-rich Cardium formation at Ansell in west central Alberta. In the first two quarters, Husky drilled 21 Cardium formation wells at Ansell and a further 12 Cardium and nine deeper multi-zone wells are planned in the second half. The Company is currently constructing additional offload capacity, which will increase total production capacity at Ansell to 56 mmcf/day and over 2,000 bbls/day liquids.

The Company took steps in the quarter to seek a joint venture partner to accelerate development of the Ansell assets. A preliminary development plan has been created which could potentially see up to 2,600 Cardium and deeper Manville formation wells drilled on the play, most of which would be horizontal.

Heavy Oil

To maintain current heavy oil production levels, the Company is accelerating thermal developments. The goal is to achieve an increasingly higher proportion of heavy oil production through thermal at finding and development (F&D) and operating costs comparable to current levels.

Construction of the 8,000 bbls/day South Pikes Peak thermal project was approximately 67 percent complete at the end of the second quarter, and is progressing on schedule and within original cost estimates. First production is expected in mid-2012.

The 3,000 bbls/day Paradise Hill thermal development is progressing on schedule and is approximately 28 percent complete. Paradise Hill will use existing Bolney infrastructure and is planned to become operational in the third quarter of 2012.

Exploration

Husky successfully acquired the exploration rights to two parcels of land in the Northwest Territories in a Call for Bids in the Central Mackenzie Valley. Each block contains approximately 215,000 acres with a five-year primary term and a term extension to nine years when a well is drilled. The lands complement the existing portfolio of resource plays and are close to existing pipeline infrastructure. Development of the properties will be considered in the context of Husky's full suite of opportunities.

The Company is presently evaluating the timing of preliminary work on the new concessions, including conducting 3D seismic and well drilling.

GROWTH PILLARS

Oil Sands

Phase 1 of the Sunrise Energy Project continues to progress on schedule towards planned first production in 2014. In the second quarter, drilling was completed on the first 12 SAGD horizontal well pairs, as part of 49 planned initial well pairs. SAGD drilling costs are trending on budget and on schedule, with the full drilling program forecast to be completed in the third quarter of 2012.

Engineering contractors achieved detailed engineering milestones during the quarter and purchases of major equipment and preparation for surface facility construction remain on schedule for the third quarter.

Conceptual development engineering for subsequent phases of the Sunrise Energy Project has been initiated and a full field development plan is expected to be completed by the end of 2011.

Progress continues at the Tucker Oil Sands Project as the Company enhances its understanding of how to develop the reservoir. Production averaged 6,400 bbls/day during the quarter and Tucker exited the quarter in excess of 7,000 bbls/day.

Atlantic Region

The North Amethyst satellite development continued to perform well through the second quarter, with average gross production of 33,000 bbls/day (23,000 bbls/day net to Husky). Drilling was completed on an additional producing well and a supporting water injection well is scheduled to be completed in the third quarter. The production well came on stream June 23 at a rate of 6,200 bbls/day.

Husky will participate in a partner-operated exploration well at Mizzen in the third quarter. The well will aid in evaluating the 2009 oil discovery on the prospect, located in the Flemish pass. Husky holds a 35 percent working interest in the field. An exploration well is also planned for the fourth quarter to test the partner-operated Fiddlehead prospect, located south of the Terra Nova field. Husky holds a 50 percent working interest in the well.

South East Asia

Development of the Liwan Gas Project offshore southeast China achieved a significant milestone, with the approval of the ODP for the Liwan 3-1 field by Husky and its joint partner, China National Offshore Oil Corporation (CNOOC). Submission of the ODP to Chinese government authorities will now take place.

The companies continue to advance the development towards planned first gas in late 2013 or early 2014.

In support of the ODP submission, a gas sale agreement has been executed with CNOOC Gas and Power Group, Guangdong Trade Branch, for the sale of gas from the Liwan 3-1 field. The gas will supply the Guangdong Province natural gas grid from an onshore gas plant on Gaolan Island, Zhuhai. The gas price mechanism is in line with the anticipated Guangdong "city gate" market price, establishing an attractive rate of return for the project.

The Liwan Gas Project is comprised of three significant gas discoveries the Company has made on Block 29/26: Liwan 3- 1, Liuhua 34-2 and Liuhua 29-1. A gas contract agreement and ODP filing for the Liuhua 34-2 field is expected later this year and similar milestones are anticipated for the Liuhua 29-1 field in 2012.

Production from the Liwan 3-1 field and the Liuhua 34-2 field is expected to ramp up through 2014 towards a rate above 300 mmcf/day (gross). In 2015, the Liuhua 29-1 field is expected to be placed on stream, increasing gross production to approximately 500 mmcf/day. Husky has a 49 percent ownership interest in production.

The Company's share of the estimated total overall integrated project cost of U.S.$6.5 billion will be approximately U.S.$3 billion.

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