Tethys Posts Initial Logging Results from Kalypso Well

- Tethys Posts Initial Logging Results from Kalypso Well

Wednesday, September 07, 2011
Tethys Petroleum Ltd.

Tethys announced the initial logging results of its KBD01 (Kalypso) exploration well drilled in the Kul-Bas block some 50 km north west of the Doris oil discovery.

The well has now reached total depth in what is initially interpreted to be rocks of Carboniferous age. Electric logs just run over the deeper section indicate more than 100 meters of gross potential hydrocarbon bearing zones in what is interpreted to be shelf limestones of Carboniferous age. Hydrocarbon shows were also noted whilst drilling. This is in addition to the hydrocarbon indications noted on logs and drill data in the overlying Jurassic section (logged prior to drilling this deeper hole section).

7-inch liner is now about to be run after which a comprehensive testing program on both the Carboniferous and Jurassic intervals is planned following agreement and approvals from the appropriate Kazakh authorities. Obtaining these approvals could take some 2 months (with mobilization of testing equipment to follow thereafter), as this is an exploration well and, unlike appraisal wells, no estimated testing program could be submitted prior to finishing the well.

The nearest field which produces from similar Carboniferous shelf limestones is the Alibekmola field, some 250km to the north in the pre-Caspian Basin Subsalt. It is likely that the limestone interval will require acidisation and possible fracture stimulation to achieve optimal production performance (as do other similar fields). This will be evaluated as part of the test program planning.

Meanwhile, elsewhere in Kazakhstan the AKD06 Doris oil appraisal well is drilling ahead at a depth of 1,755 meters towards the Aptian sandstone target.

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FuelCell Reported Q3 Results, Top Line Up 65% YoY

- FuelCell Reported Q3 Results, Top Line Up 65% YoY



Sep 7, 2011

FuelCell Energy (NASDAQ:FCEL) reported a Q3 loss of $0.07 per share, narrower than consensus estimates for a loss of $0.09 per share. Revenues for the quarter rose 65.1% year-over-year to $31.2 million, topping consensus estimates of $29.0 million.

Chip Bottone, President and CEO of FuelCell Energy, Inc said, "The team at FuelCell Energy achieved an important milestone this quarter by generating a gross margin for the first time since we began the commercialization process of Direct FuelCells. We are executing our revenue growth plan and benefitting from operating leverage that is driving down costs. We have record product and service backlog of $230.6 million and we are producing at a record rate and have substantially increased our production run rate to a level of 56 megawatts annually compared to 22 megawatts of production for fiscal year 2010."

FuelCell Energy has a potential upside of 186.4% based on a current price of $1.03 and an average consensus analyst price target of $2.95.

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FOGL Briefs Interim Results for 1H11

- FOGL Briefs Interim Results for 1H11

Wednesday, September 07, 2011

Falkland O&G Ltd.

FOGL announced its Interim Results for the six months ended June 30, 2011.

Highlights

• Contract signed for the Leiv Eiriksson drilling rig for two firm slots in first half 2012.
• Operatorship and remaining 51% equity in Northern License Area assigned back to FOGL by BHP Billiton together with a significant cash settlement.
• Completed the site survey and 2D seismic program.
• Equity placing raised US $51.8 million before expenses. Cash balance of $110.6 million at period end (2010: $80.4MM).
• Current available funds, including BHPB settlement, of $150.6 million.

Richard Liddell, Chairman of FOGL, said, "We made good progress during the first half of 2011, during which we negotiated the exit of BHPB from our licenses and regained complete control and operatorship of our license areas while also securing a significant cash payment from BHPB. This was an excellent outcome, which has enabled us to drive forward with the most important phase of our exploration program. In addition, we successfully raised $51.8 million through a share placing, which, combined with existing cash resources and BHPB's payment, leaves us in a strong financial position to drill two wells in 2012. We also signed a rig contract and expect drilling to commence with the Loligo well in the first quarter of 2012. In addition, a number of other prospects have been selected and prioritized as possible targets for the second well in the program."

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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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Contango Spotlights Year-End Results

- Contango Spotlights Year-End Results

Monday, August 29, 2011
Contango O&G Corp.

Contango reported natural gas and oil sales from continuing operations for the fiscal year ended June 30, 2011 of approximately $203.8 million, compared to $159.0 million for the same period last year. The Company reported net income attributable to common stock for the year ended June 30, 2011 of approximately $65.0 million, or $4.15 per basic share and $4.14 per diluted share, which included approximately $1.6 million of income from discontinued operations, or $0.10 per basic and diluted share, related to the sale of our Conterra Company assets and the distribution of Contango ORE, Inc. This compares to net income attributable to common stock for the year ended June 30, 2010 of approximately $49.7 million, or $3.14 per basic and $3.08 per diluted share, which included a loss from discontinued operations of approximately $0.5 million, or $(0.03) per basic and diluted share.

For the three months ended June 30, 2011, natural gas and oil sales from continuing operations were approximately $48.9 million, up from $40.1 million for the three months ended June 30, 2010. Contango had net income attributable to common stock of approximately $17.5 million, or $1.12 per basic and diluted share, compared to net income attributable to common stock for the three months ended June 30, 2010 of approximately $15.4 million, or $0.97 per basic and $0.95 per diluted share.

For the remainder of fiscal year 2012, our capital expenditure budget calls for us to invest approximately $81.4 million. Of this, we expect to invest approximately $50 million to drill two wildcat exploration wells in the Gulf of Mexico, at an estimated dry hole cost of approximately $25 million each, net to Contango, subject to permitting approval by the Bureau of Ocean Energy Management, Regulation and Enforcement. We also plan to invest approximately $19.6 million in Alta Energy Partners, LLC, and $11.8 million to complete payment on several capital projects.

Our production is currently 78.1 million cubic feet equivalent per day, net to Contango. As of August 29, 2011, we had no debt and approximately $120 million in net available cash.

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Seadrill Ltd Reported Q2 Results

- Seadrill Ltd Reported Q2 Results



Aug 25, 2011

Seadrill Limited (NASDAQ:SDRL) reported Q2 EPS of $1.34, vs. consensus estimates of $0.69 per share. Revenues for the quarter rose 6.6% year-over-year to $995 million, missing consensus estimates of $1.01 billion.

Seadrill has a potential upside of 23.8% based on a current price of $31.04 and an average consensus analyst price target of $38.42.

Seadrill is currently below its 50-day moving average (MA) of $33.03 and below its 200-day MA of $34.15.

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- Seadrill 2Q Earnings Climb on Demand

Tullow Touts Record Results in 1H11

- Tullow Touts Record Results in 1H11

Wednesday, August 24, 2011
Tullow Oil plc

Tullow announced its half-yearly results for the six months ended 30 June 2011.

2011 Half-yearly results summary

• Record first half revenue and profit
• Interim dividend doubled
• Exploration success continues and developments being progressed

Tullow had a very strong first half. Record results were driven by increased production from the Jubilee field in Ghana and higher commodity prices. Exploration and appraisal success continued and the Group strengthened its portfolio with farm-ins in East Africa and two strategic acquisitions. Further progress was made in Uganda and Tullow now expects completion of its farm-down to CNOOC and Total in September. In July the Group listed Tullow Oil plc shares on the Ghana Stock Exchange.

Key highlights

• Record sales revenue of over $1 billion driven by Jubilee Production; interim dividend doubled.
• 71% exploration and appraisal success year-to-date (17/24); Akasa-1 discovery announced today.
• Completion of farm-in to six blocks in Kenya and Ethiopia; first well to spud in Kenya in Q4 2011.
• Group production expected to average 82-84,000 bopd for 2011 and exceed 100,000 bopd by year-end.
• Jubilee production in Ghana is expected to increase to 105,000 bopd in October; plateau production of 120,000 bopd is now expected before year-end.
• MoU signed with the Government of Uganda; $2.9 billion Sale and Purchase Agreements signed for the farm-down to CNOOC and Total; completion now expected in September.
• Nuon E&P and EO Group acquisitions completed in June and July respectively.
• Secondary listing on the Ghana Stock Exchange completed in July following successful $72.3 million offer.

Commenting, Aidan Heavey, Chief Executive, said, "We have delivered a strong performance and achieved record results in the first half allowing us to double the dividend. We continue to make good progress with production plans in both Ghana and Uganda and while delays to the farm-down to CNOOC and Total have been frustrating, we now expect completion in September. With a strong balance sheet, growing production and a potentially transformational drilling campaign to come, we move into the second half of the year with real confidence."

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Reliable Posts Initial Production Results for Manitoba Well

- Reliable Posts Initial Production Results for Manitoba Well

Tuesday, August 23, 2011
Reliable Energy Ltd.

Reliable provide the following operations update.

Manitoba - Following an extended spring break up, the result of higher than normal rainfall and flooding in southeast Saskatchewan and southwest Manitoba, Reliable commenced drilling operations in early July, 2011 with a rig it has contracted through to March 31, 2012. To date, the Company has successfully drilled three horizontal wells with the fourth currently drilling ahead.

The first well, 04-16-13-28W1 at East Manson, was drilled into the Bakken formation with a horizontal section of 823 meters and included 29 frac intervals. The well has now been on production for 20 days with increasing oil cuts and has averaged 177 bopd gross (133 net) over the last five days, as the well continues to clean up.

The second well, 01-34-12-28W1 at North Elkhorn, was drilled with a horizontal section of 1,280 meters and is currently being completed with 27 frac intervals. The well is expected to be placed on production within seven days.

The third well, 07-09-13-28W1 at East Manson has been drilled with a 580 meter horizontal section and a 19 stage frac program is planned for this well. Completion operations will begin once the 1-34 completion has finished operations.

The fourth well, 15-23-11-29W1 at South Kirkella, is currently drilling and is planned to have a 1,400 meter horizontal section and 44 frac intervals.

The remaining six horizontal wells of our 2011 program in Kirkella include two more horizontals at South Kirkella and four horizontal wells at East Manson. With the success the Company is enjoying at East Manson, the Company's focus will be on developing this field with the aim of increasing production and cashflow.

Montana - In June 2011, Reliable, along with its partners, completed the second vertical well of its Montana program. The White Bear 15-23 well was drilled during the first quarter of 2011 to a total depth of 5,600 feet (1,700 meters) in order to evaluate additional zones below the Bakken. While the original target of reservoir in the Bakken zone was not encountered, this exploration well provided significant data on the Bakken to further the evolution of the geological model of the Bakken in this area of Montana.

Two other potential hydrocarbon-bearing zones were encountered in the wellbore: the Duperow formation and the Bowdoin zone, which produces gas from the Bowdoin Dome field approximately 60 miles to the east. The well was completed and tested in the Duperow formation. High fluid rates were established, but no economic hydrocarbon volumes were produced.

Completion efforts were then directed toward the Bowdoin zone in the original 12B-26 well drilled in 2010. The well was perforated, shut-in for pressure build-up, and once positive pressure information was obtained, the well was placed on flow test. The gas rates for the zone were in line with rates of other unstimulated wells in the Bowdoin Dome field and the well was shut-in and its status with the Montana Board was subsequently changed to "Shut-In Gas Well". Reliable and its partners are currently evaluating the results from the completion and are developing a completion program in the Bowdoin zone of the 15-23 well. The Bowdoin zone appears to be a regional gas resource prospect and we are currently identifying future locations that will evaluate both the Bowdoin and Eagle gas zones.

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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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ReneSola Reported Q2 Results; Issued Guidance

- ReneSola Reported Q2 Results; Issued Guidance



Aug 9, 2011

ReneSola (NYSE:SOL) reported Q2 EPS of $0.02, missing consensus estimates of $0.16 per share. Revenues fell 1.8% year-over-year to $249.3 million, vs. consensus estimates of $147.6 million.

Mr. Xianshou Li, ReneSola's chief executive officer said, "Both wafer and module prices fell faster than expected in the second quarter as European subsidy cuts weakened demand and led to oversupply in the industry. Although this affected both our top and bottom lines, we were able to maintain a gross margin of 18.4% with our industry-low wafer processing costs and growing in-house polysilicon production. Our new Virtus wafer, a multicrystalline wafer that can achieve cell efficiency rates of up to 18.2%, has an even higher profit margin than our existing wafers and has been well-received by clients with its high efficiency-to-price ratio. We expect Virtus wafers to replace all of ReneSola's existing multicrystalline wafers by the end of 2011. As the solar market matures, we will continue to focus on wafer production to capitalize on our brand name, scale of operations and innovative technologies to lead the industry in cost-competitive solar manufacturing."

The company expects Q3 revenues of $220 to $240 million, vs. consensus estimates of $166.63 million.

Renesola has a potential upside of 132.4% based on a current price of $2.77 and an average consensus analyst price target of $6.43.

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Sempra Energy Reported Mixed Q2 Results, Top Line Up 21%

- Sempra Energy Reported Mixed Q2 Results, Top Line Up 21%



Aug 9, 2011

Sempra Energy (NYSE:SRE) reported adjusted Q2 EPS of $0.97, missing consensus estimates of $0.98 per share. Revenues for the quarter rose 21% year-over-year to $2.42 billion, topping consensus estimates of $2.18 billion.

The company sees 2011 EPS of $4.00 to $4.30 per share, vs. consensus estimates of $4.20 per share.

Debra L. Reed, chief executive officer of Sempra Energy said, "Through the first half of the year, we are performing well across the board and are on track to meet our 2011 earnings guidance. Our utility and pipeline acquisitions are providing strong contributions to our earnings. We also are making excellent progress on our major California utility projects and our build-out of contracted renewable energy infrastructure."

Sempra Energy has a potential upside of 24.6% based on a current price of $46.03 and an average consensus analyst price target of $57.36.

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Jubilant Posts Test Results of Appraisal Well DDE-APP-1 in India

- Jubilant Posts Test Results of Appraisal Well DDE-APP-1 in India

Tuesday, August 09, 2011
Jubilant Energy N.V.

Jubilant announced the results of Appraisal Well DDE-APP-1 in the Deen Dayal East Field in the KG Block, which was spudded on the January 1, 2011.

The well was drilled by the operator (GSPC), with the objective of appraising the hydrocarbon bearing sands of the KG-16 discovery well and, in the process, to test the Cretaceous and Jurassic Rift Fill and younger sandstones that were found to be productive in other wells on the Deen Dayal structural complex. The well was drilled to 5,621 meters measured depth and encountered basement at 5,530 meters measured depth.

Two Drill Stem Tests ("DST") were undertaken after electric logging of the lower section of the well. DST-1 was undertaken in the rift fill section with perforation between 4,957 to 4,970 meters measured depth. This test flowed water at an average rate of 1500 bwpd and carbon dioxide ranging 20% to 28% was found in the well stream. DST-2A was undertaken in a shallower section with perforation between 4,774 to 4,786.5 meters measured depth and 4,789-4,799.5 meters measured depth. This flowed gas at 0.73 mmscfd with condensate at 60 bcpd from a 12/64 inch choke; 6% constant carbon dioxide was observed during the test.

The authorized cost to drill and test the well was approximately USD 75 million (USD 7.5 million net to Jubilant), the actual cost to date is approximately USD 69 million (USD 6.9 million net to Jubilant). The rig is currently waiting for a suitable weather window to move to the Well Head Platform.

Jubilant holds a 10% participating interest in this block through its subsidiary Jubilant Offshore Drilling Private Limited in India. Gujarat State Petroleum Corporation Limited, with an 80% participating interest, is the operator for the block. Geo Global Resources holds 10%.

Ajay Khandelwal, CEO of the Company commented, "The results of this well are not as expected and the operator is undertaking a full evaluation of the results. Any impact on 2C resources for DDE will be declared following a detailed evaluation by the operator and independent reserves consultants. Any evaluation will also take into account the possible upside of 2C resources from 20.5 square kilometer development area extension, as previously announced. Furthermore, the ongoing development of DDW (2P reserves area) is currently ahead of schedule with first gas expected in 2013."

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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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Spectra Energy Reported Mixed Q2 Results, Top Line Up Over 11%

- Spectra Energy Reported Mixed Q2 Results, Top Line Up Over 11%



Aug 3, 2011

Spectra Energy (NYSE:SE) reported Q2 EPS of $0.42, ahead of consensus estimates of $0.40 per share. Revenues for the quarter rose 11.8% year-over-year to $1.19 billion, missing consensus estimates of $1.23 billion.

The company expects 2011 EPS to exceed the stated target of $1.65, vs. consensus estimates of $1.76 per share.

Spectra Energy has a potential upside of 13.4% based on a current price of $26.45 and an average consensus analyst price target of $30.

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SM Energy Reported Mixed Q2 Results, Top Line Up Over 78%

- SM Energy Reported Mixed Q2 Results, Top Line Up Over 78%



Aug 2, 2011

SM Energy (NYSE:SM) reported Q2 EPS of $0.91, ahead of consensus estimates of $0.53 per share. Revenues rose 78.5% year-over-year to $377.9 million, topping consensus estimates of $307.5 million.

SM Energy has a potential upside of 13.8% based on a current price of $75.56 and an average consensus analyst price target of $86.

SM Energy is currently above its 50-day moving average (MA) of $70.38 and above its 200-day of $63.32.

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TAG Boasts Production Increase in Year-End Results

- TAG Boasts Production Increase in Year-End Results

Tuesday, August 02, 2011
TAG Oil Ltd.

TAG Oil has filed its audited financial results, Management Discussion and Analysis and Annual Information Form with the Canadian Securities Administrators for the period ended March 31, 2011.

Year-End March 31, 2011 Operating Highlights

• Production revenue for 2011 increased to $13,088,423 compared to $6,527,585 in 2010.
• TAG produced 150,742 net barrels of light oil in fiscal 2011, sold at an average price of $86 per barrel with production costs reduced to less than $20 per barrel.
• Significant gas discovery with the Sidewinder-1 well was followed by three additional Sidewinder discoveries.
• Behind-pipe production capability of more than 5,000 barrels of oil equivalent per day is ready to come on production.
• The Cheal-B4ST well discovered light oil in the Urenui Formation (~1400m), and a second producing formation is now under development at the Cheal field.
• TAG acquired a 100% interest in the Cardiff condensate-rich deep gas discovery.
• Light oil was discovered in three shallow wells during recent drilling in the East Coast Basin, confirming the underlying shale formations as the source of the oil.

Reserves, Production, Drilling — Taranaki Basin

As previously announced, as at March 31, 2011 TAG's independently assessed, proven and probable reserves stood at 1,677,000 barrels of oil equivalent ("BOE"). This assessment accounts for just 475 acres of the 7,487-acre Cheal permit, and only 107 acres of the 7,910-acre Sidewinder permit: The report included an initial reserve estimate from Sidewinder-1 alone, as TAG Oil's five subsequent discovery wells were completed after the fiscal year-end cut-off.

During the 2011 fiscal year TAG's production rate averaged 413 barrels of oil equivalent (BOE) per day. Current production is now at approximately 950 BOE per day with a ramp-up past 5,000 BOE per day as TAG brings "behind-pipe" production online over the coming months.

Production from these new oil and gas wells is awaiting Cheal's minor facility upgrade and the commissioning of the Sidewinder Production Station, both on schedule for completion in coming months. TAG's operations in Taranaki continue to deliver better-than-expected results and have encouraged the Company to accelerate the next phase of exploration drilling, now scheduled to commence in September 2011. This drilling campaign will further target the Mt. Messenger and Urenui Formation prospects as well as potential deeper wildcat targets identified.

During the fiscal year TAG significantly expanded its Taranaki business and prospects with the acquisition of the Cardiff condensate-rich gas discovery. Situated immediately adjacent to New Zealand's landmark Kapuni condensate-rich gas field, the large Cardiff anticline extends across an area some 12 km long by 3 km wide—and the Kapuni Formation can be mapped across the entire structure. In close proximity to TAG-controlled infrastructure and with the strong Taranaki gas market, Cardiff has the potential to become a strategic long-term asset.

Fractured Shale Exploration — East Coast Basin

In 2006, TAG Oil acquired a large land base that covered key acreage potentially prospective for fractured shale exploration in two prospective formations: the Waipawa Black Shale and Whangai Shale.

As part of our scheduled commitments to the New Zealand government, we have voluntarily relinquished some acreage that we've determined to have no exploration potential. As a result of high-grading the acreage, TAG has retained 1.7 million acres (2,656 sections) of what the Company interprets to be the most prospective acreage for both conventional and unconventional exploration.

In November 2008 the Company retained AJM Petroleum Consultants to independently assess the resource potential of the Waipawa Black Shale and Whangai Shale prospects within our permits. The report only considers 200,000 acres of our current 1.7 million acres and concludes a best case estimate of 12.6 billion barrels of oil equivalent of undiscovered Hydrocarbon-In-Place.

Undiscovered Resource Potential on 200,000 Acres of Shale

Billion Barrels of Oil in Place	Low Case	Best Case	High Case
Unconventional Exploration	4,022,263,000	12,654,778,000	39,835,707,000

Since TAG first secured the East Coast Basin shale prospects, the Company has compiled significant critical data including new 2-D seismic data, detailed core and oil-seep analysis, extensive geological surface mapping, and shallow stratigraphic drill testing. As part of the Waitangi Hill area evaluation in Petroleum Exploration Permit 38348, TAG drilled three shallow stratigraphic wells to total depths of 250-300m. All three wells intercepted oil-and-gas-bearing sands under anomalously high pressures, with two of the wells intercepting 11 to 13 meters of gross potential oil pay at approximately 200m depth. All three wells recovered 50-degree API sweet light crude oil, which was lab tested, confirming the source of this high quality oil to be from the underlying Waipawa and Whangai Shale formations.

Liquidity and Financial Summary

TAG ended the year financially very strong and enters fiscal 2012 as a much more substantial corporation with rapidly growing oil and gas production and a relatively undiluted capital structure. Production revenue for 2011 more than doubled over last year to $13,088,423. and generated an operating profit of $6.5 million. TAG remains debt free and our net working capital as at March 31, 2011 was $69.38 million.

During the year TAG completed two equity financings for net proceeds of approximately $75 million. On May 5, 2010, the Company closed an equity offering with a total of 7,700,000 units and 231,000 broker-warrants for net proceeds of $18,534,174. Each unit is comprised of one common share and one-half of one common share purchase warrant. Each whole warrant will be exercisable at $3.60 and will entitle the holder thereof to acquire one common share up until November 5, 2011.

On November 17, 2010, TAG closed a bought deal common share public offering. The Company sold a total of 10,300,000 common shares at a price of $5.20 per share. The Company also granted to the underwriters an over-allotment option to purchase up to an additional 1,250,000 common shares at the same price, which was exercised in full on November 26, 2010. Total net proceeds from the bought deal equity offering including the over-allotment totaled $56,163,805.

The Company currently has 50,069,896 common shares outstanding and 57,566,060 common shares outstanding on a fully diluted basis.

Capital Expenditure

The majority of TAG's capital expenditure items relate to multi-well exploration drilling, optimization work and facility construction. Capitalized oil and gas expenditures during fiscal 2011 totaled $21.8 million as follows:

Cheal Field	$11.40MM
Sidewinder Field	$9.6MM
East Coast Shale	$658,139
Kaheru (offshore JV)	$127,879

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LNG Energy Spotlights Initial Results of Core Analysis, Spudding in Poland

- LNG Energy Spotlights Initial Results of Core Analysis, Spudding in Poland

Friday, July 29, 2011
LNG Energy Ltd.

LNG Energy announced that its third vertical well, the Starogard S-1 well on the Starogard concession in Poland, was spudded on July 16, 2011. LNG has an indirect 20% interest in the well which is currently drilling at a depth of about 1,700 meters and has installed 690 meters of steel casing and cementing it from the bottom to the surface. This depth is below the potential fresh water intervals and was installed to isolate and protect the aquifers. A second string of steel casing will be installed and cemented at an approximate depth of 2,050 meters, prior to drilling ahead to the estimated core point. At the core point, the plan is to core the balance of the well for further analysis of the formations.

LNG has also received an initial portion of the core analysis back from the 3rd party contractors for both the Wytowno S-1 and Lebork S-1 wells, on the adjacent Slawno and Slupsk concessions. The data for the Lebork S-1 well is only from the sidewalls taken in the lower portion of the Ordovician and the Alum shale, as the whole core analysis from above these intervals is not yet completed. The additional core analysis data for the target intervals in the Lebork S-1 well, and the final core analysis reports for both wells are expected to be in by the end of August at which time the log analyses for both wells will be reprocessed with the core data.

• Porosities:
  • Lebork S-1 well: 47 meter thick Ordovician/Cambrian interval has an average porosity of 4.0% and
  • Wytowno S-1 well: 91 meter thick Lower Silurian target interval has porosity ranges of 1.1% to 4%, averaging 3.0% and the 40 meter thick shallower Lower Silurian interval has a porosity of 5.6%.
• Gas filled porosity:
  • Lebork S-1 well: gas filled porosity ranges from 0.8% to 3.9%, averaging 1.8% of bulk volume in the Ordovician/Cambrian and
  • Wytowno S-1 well: the Silurian targets range from 0.3% to 1.6%, averaging 1.1% of bulk volume, with one shallower Silurian interval that has a value of 4.3% of bulk volume.
• Desorption:
  • Lebork S-1 well: average desorption values of 40 Standard Cubic feet of gas per ton of rock, ("SCF/ton") over the Lower Silurian and 268 SCF/ton over the 47 meter Ordovician/Cambrian interval. The Lower Ordovician/Cambrian shale had intervals as high as 451 SCF/ton.
  • Wytowno S-1 well: average desorption values of 124 SCF/ton in the Lower Silurian target interval and 77 SCF/ton in the shallower Lower Silurian interval. For comparative purposes BNK Petroleum Inc.'s Oklahoma Woodford Shale Tishomingo field has average values of 104 SCF/ton.
• Thermal maturity:
  • Wytowno S-1 well: thermal maturity values were estimated from the reflectance of pyrobitumen and the Thermal Alteration Index (TAI) obtained from Palynological (micro-paleo) analysis of the drill cuttings, which both equate to a Ro of 1.8 in the Lower Silurian.
  • Lebork S-1 well: TAI for the cuttings from the Lower Silurian to Ordovician/Cambrian are also equivalent to a Ro of 1.8, which places the thermal maturity for both wells in the dry gas window.
• TOC:
  • Wytowno S-1 well: the total organic carbons ("TOCs") are variable across the Lower Silurian target interval, ranging from 0.1 to 1.3 TOC by percent weight. The TOC data from the Lebork S-1 well is not yet available, however both the log calculated values and SEM image analysis values indicate multiple times higher TOCs across the Ordovician/Cambrian shales.

Incorporating the micro-paleo and high-resolution stratigraphic analysis into the geological model indicates that the Wytowno S-1 well was drilled on a localized paleo-topographic high. What was originally interpreted as Ordovician/Cambrian shales are actually Lower Silurian hot shale intervals. The intervals in the Lebork S-1 well have also been revised on the basis of the micro-paleo and high-resolution stratigraphic analysis, resulting in slightly different thicknesses of the various intervals. In addition to the seismic program, a depth to crystalline basement study will be conducted. The study will cover a large portion of northeast Poland, fully encompassing all three concessions. The interpretation of this study will provide better understanding of general basin geometry, identify sub basins and locate significant basement related faulting. The study is slated for completion in September 2011.

Completion activity for the Lebork S-1 and Wytowno S-1 wells are scheduled to begin in the fourth quarter. The possibility of undertaking the completion of the Starogard S-1 well in conjunction with our two other wells is also under review, with well results and equipment availability to determine the timing. Best North American industry practices are being utilized for drilling and testing the wells, including utilizing bladders to hold the fresh water for fracture stimulating the well, the arrival of these are determining the start of the completion activity. The bladders ensure complete isolation from surface soil and water, reduce truck traffic to and from the site and increase safety. The flowback fluids are flowed directly into self-contained steel tanks on location.

Recently approval has been received from the Polish authorities to acquire approximately 407 km of 2D seismic on the concessions. The seismic program will further define basin structure and burial history as well as aid in individual well location selection. The term of the three Saponis concessions were also extended to provide Saponis enough time to acquire the seismic prior to drilling the second well on each concession. It is anticipated that the acquisition of this seismic will commence in the fourth quarter of this year.

"We are very encouraged by the initial results from the sidewall core tests on the Wytowno well," commented Dave Afseth, President and CEO of LNG. "The results of the core analyses as well as the analyses of the sidewall cores will enable us to design and implement an appropriate stimulation to flow test the wells later this year."

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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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TNK-BP Touts Financial Results for 1H 2011

- TNK-BP Touts Financial Results for 1H 2011

Tuesday, July 26, 2011
TNK-BP

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

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

1H11 OPERATIONAL HIGHLIGHTS

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

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

1H11 FINANCIAL HIGHLIGHTS

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

2Q11 RESULTS

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

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Anadarko Touts 2Q11 Results

- Anadarko Touts 2Q11 Results

Monday, July 25, 2011
Anadarko Petroleum Corp.

Anadarko announced second-quarter 2011 net income attributable to common stockholders of $544 million, or $1.08 per share (diluted). These results include certain items typically excluded by the investment community in published estimates. In total, these items decreased net income by approximately $28 million, or $0.06 per share (diluted) on an after-tax basis. Cash flow from operating activities in the second quarter of 2011 was $1.837 billion, and discretionary cash flow totaled $1.838 billion.

Second-Quarter 2011 Highlights

• Achieved record liquids sales volumes of 297,000 barrels per day
• Finalized Lucius unitization agreement
• Successfully tested three wells at the Caesar/Tonga mega project
• Closed the acquisition of the Wattenberg Processing Plant

"We achieved record liquids sales volumes during the quarter, enhancing margins and generating excellent cash flows," said Anadarko Chairman and CEO Jim Hackett. "Nearly all of the year-over-year volume growth was attributable to a 34,000 barrel-per-day increase in liquids volumes. These results contributed to strong discretionary cash flows of more than $1.8 billion -- approximately $117 million above our capital expenditures, which included a one-time cash investment of $518 million associated with the acquisition of the Wattenberg plant."

During the second quarter of 2011, sales volumes totaled 62 million barrels of oil equivalent (BOE), or 685,000 BOE per day, averaging approximately 2.3 billion cubic feet of natural gas per day, 225,000 barrels of oil per day (BOPD), and 72,000 barrels of natural gas liquids per day.

Operations Summary

The company achieved sales-volumes records during the second quarter of 2011 in Wattenberg, Greater Natural Buttes, Wamsutter (operated), Bone Spring and the Marcellus Shale. In the Eagleford Shale, Anadarko closed its $1.6 billion joint-venture agreement with a subsidiary of Korea National Oil Corporation and exited the quarter with record gross sales volumes of approximately 45,000 BOE per day in the play, an increase of approximately 25 percent from the end of the prior quarter. In Ghana, current gross production from Jubilee is approximately 80,000 BOPD, and production continues to ramp up with further well completions and gas injection.

In the deepwater Gulf of Mexico, Anadarko continued to advance two major projects during the second quarter. The company finalized the Lucius unitization agreement and recently announced plans to develop the field with a truss spar designed for a capacity of 80,000 BOPD and 450 million cubic feet of natural gas per day. Sanctioning is expected to occur later this year, with first production expected in 2014. At the Caesar/Tonga project, Anadarko completed flow and reservoir tests on three wells. Each of the wells tested at flow rates of approximately 15,000 BOPD with high-quality (27º API gravity) oil.

Exploration Summary

Anadarko has mobilized the Discoverer Spirit drillship to begin the company's 2011 exploration program in West Africa, following the drillship's completion of the final test at Caesar/Tonga. This program includes the Montserrado exploration well in Liberia, as well as the Jupiter exploration well and Mercury appraisal well in Sierra Leone. In other deepwater exploration areas, Anadarko continued to delineate its large natural gas discoveries in Mozambique, and to advance appraisal activities in the Tweneboa/Enyenra area offshore Ghana. The company also recently began appraisal drilling in the Campos Basin offshore Brazil.

As previously announced by Diamond Offshore, Anadarko signed long-term contracts in the second quarter for two new-build drillships. The Ocean BlackHawk is expected to be delivered in late 2013, and the Ocean BlackHornet is expected to be delivered in early 2014. These new state-of-the-art rigs are designed to work in up to 12,000 feet of water, and each has been contracted for a term of five years. These new rigs will feature enhanced drilling capabilities and safety equipment designed to meet the highest specifications in the industry.

"We expect the next six to nine months to be the most active period of deepwater exploration and appraisal drilling in our company's history," said Hackett. "Our exploration program is designed to deliver upon our goal of discovering more than 500 million BOE of net risked resources this year. We are continuing to advance our deep inventory of high-impact prospects, and the new rig agreements reinforce our long-term commitment to the safety and success of our global exploration program."

Financial Summary

Anadarko reported total product revenues of approximately $3.5 billion during the second quarter of 2011, a 46-percent increase relative to the second quarter of 2010. The company ended the second quarter of 2011 with approximately $3.4 billion of cash on hand in addition to its five-year, $5 billion undrawn credit facility. As provided in the supplemental information to this release, Anadarko protected an additional 450,000 MMBtu per day of 2013 natural gas production, with three-way collars that have a middle floor of $5.00 per MMBtu and a ceiling of $6.57 per MMBtu.

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