Goldman Sees US As Top Oil Producer In 2017 - Report

- Goldman Sees US As Top Oil Producer In 2017 - Report

Monday, September 12, 2011
Dow Jones Newswires
LONDON
by London Bureau

The U.S. will soon become the world's top oil producer, The Sunday Times reported Goldman Sachs as forecasting.

U.S. oil production should reach 10.9 million barrels a day by 2017, a third higher than 8.3 million barrels currently, the newspaper reported the investment bank as saying.

Russia, now the top oil producer, should see production increase only 100,000 barrels in the same period, for an output of 10.7 million barrels a day, the report said.

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

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BP Sees Russian Office Raids As 'Pressure' - Interfax

- BP Sees Russian Office Raids As 'Pressure' - Interfax

Wednesday, August 31, 2011
Dow Jones Newswires
MOSCOW
by Ira Iosebashvili

Russian raids on BP's Moscow offices are a means of pressuring the company's business activities within the country, BP Russia head Jeremy Huck said Wednesday, Interfax reported.

The court decree to raid BP's office "has no legal basis," Huck said.

"The work of our office is paralyzed. We see these actions as an element of pressure on BP's business in Russia."

Earlier, Russian bailiffs entered a BP Moscow office to examine documents requested in a $3 billion lawsuit filed by Siberia-based minority shareholders in BP's Russian joint venture, TNK-BP Holding (TNBP.RS).

Huck said he expected the raids to continue until the end of the week.

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

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Premier Oil Sees 60,000 Boepd Production in Second Half

- Premier Oil Sees 60,000 Boepd Production in Second Half

Thursday, August 25, 2011
Dow Jones Newswires
LONDON
by Iain Packham

Independent oil and gas company Premier Oil expects production to increase to around 60,000 barrels of oil equivalent a day in the second half of the year as its Chim Sao and Gajah Baru projects come on line in the next few weeks, Chief Executive Simon Lockett told Dow Jones Newswires Thursday.

First-half production averaged 36,900 barrels of oil equivalent a day, down from 46,600 in the first half of 2010 as unplanned maintenance work sapped production. Full-year production is estimated to be between 40,000 and 45,000, similar to levels in 2010.

Premier has put in place a $40 million investment program to minimize future disruptions and some of the work undertaken will actually boost production, Lockett said.

Premier said it expects second-half production to be higher than the first half as the Chim Sao project in Vietnam, which it operates, starts oil production in the next few weeks. This will be supplemented by the start of gas production at the Premier-operated Gajah Baru project in Indonesia.

Lockett said he expects production from Gajah Baru and Chim Sao will "push our production numbers up from the low end that we had in the first half of this year up to 60,0000 barrels [of oil equivalent] a day towards the back end of this year."

"That will keep us on track to deliver 75,000 barrels [of oil equivalent] a day back-end of next year and on to 100,000 barrels a day in the medium term, which is the stated target."

The company is also stepping up its exploration activities and estimates up to 20 exploration and appraisal wells will be drilled in the next 12 months, targeting around 300 million barrels of oil equivalent. It expects to drill 10 exploration wells in the second half of 2011 in Indonesia, Vietnam, Norway and the U.K.

Finance Director Tony Durrant told Dow Jones Newswires that Premier's exploration activities will cost around $250 million over 2011 and estimated that $150 million of that will be spent in the second half.

Premier said it has set itself an exploration target of achieving 200 million barrels of oil equivalent of reserve additions by 2015, of which around 75 million barrels have already been achieved.


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

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CNOOC Sees 51% Increase in YOY Profit

- CNOOC Sees 51% Increase in YOY Profit

Wednesday, August 24, 2011
CNOOC Ltd.

CNOOC announced its interim results as of June 30, 2011.

The Company's total net oil and gas production amounted to 168.7 million barrels of oil equivalent (BOE), representing an increase of 12.9% year-on-year (YOY). This is mainly attributed to: firstly, the new oilfields and development wells which continued to introduce new momentum to the Company's production; secondly, production contributions from newly acquired projects since 2010; and thirdly, the composite decline rate of producing oil and gas fields which has remained low through comprehensive adjustment measures.

Meanwhile, international oil prices fluctuated sharply, although generally, it sustained at a high level. Having benefited from this, the Company's realized oil price reached US $108.16/barrel, 40.8% higher than that of the same period last year. The Company's realized gas price was US $4.92/mcf, increasing 15.5% YOY.

Due to stable oil and gas production growth, as well as higher realized prices, the Company's oil and gas sales revenue for the first half of the year surged 45.0% YOY to RMB97.03 billion. Despite escalating prices of oilfield services and raw materials, the Company's production cost has remained at a low level mainly due to cost savings and efficiency enhancement. The seasonality factor has also lowered the production cost. During the first half of 2011, our operating cost was down 3.8% from 2010 average of US $7.28 to US $7.00 per barrel. The Company recorded net profit of RMB39.34 billion ($5.06B), representing a significant increase of 51.4% YOY.

In the area of exploration, the Company made 6 new discoveries and 18 successful appraisal wells. The first commercial discovery of Wushi 17-2 was made in Wushi Sag in the Western South China Sea. In terms of rolling exploration, two new discoveries Qinhuangdao 33-2 and Qinhuangdao 33-3 were made following the discovery of Qinhuangdao 33-1 South last year in the Shijiutuo uplift area.

Since the beginning of the year, the Company has further expanded its investments in shale oil and gas play and oil sands of North America, through the acquisition of a 33.3% interest in Chesapeake's Niobrara project and the acquisition of OPTI Canada Inc. In addition, we successfully acquired a one-third interest held by Tullow Oil in each of Exploration Areas 1, 2 and 3A in Uganda.

The Company has kept a good track record on health, safety and environmental protection (HSE) since established more than a decade ago. However, the oil spill incident of Penglai 19-3, an oilfield operated under production sharing contract in Bohai Bay, posed HSE challenges to the Company. This incident has made certain impact on the marine environment. Being a responsible energy company, we will continue to urge and assist ConocoPhillips China Inc., the operator of the Penglai 19-3 oilfield, to complete the cleanup work in a timely manner and to minimize the impact on the marine environment.

In addition, due to the combination of the progress of acquisition project and the impact from the oil spill incident, we reset the Company's annual production target at 331-341 million BOE.

Mr. Wang Yilin, Chairman of the Company said, "The outstanding results for the first half of 2011 demonstrated our operating and management capabilities. At the same time, we faced a challenge posed by the oil spill incident occurred at Penglai 19-3 oilfield and we felt deeply sorry about it. The Company has already started performing inspection on the major facilities, equipments and production operations of all our oilfields, and reinforcing our risk management measures, to avoid similar incidents happening in the future."

Mr. Yang Hua, Chief Executive Officer of the Company commented, "Since the beginning of the year, the Company has increased its investments in unconventional energy through the acquisition of shale oil and gas and oil sands projects, building an important resource base for the future. Year 2011 is a year of steady growth for the Company. In the second half of the year, the Company will continue to progress steadily to lay a solid foundation for the Company's long term development."

In the first half of the year, the Company's basic earnings per share reached RMB0.88. In order to share our outstanding results with shareholders, the board has declared an interim dividend of HK $ 0.25 per share (tax inclusive).

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Petro Matad Sees 'Live Oil Shows' at DT-9 Well

- Petro Matad Sees 'Live Oil Shows' at DT-9 Well

Monday, August 22, 2011
Petro Matad Ltd.

Petro Matad announced that the Company's Davsan Tolgoi-9 well ("DT-9") has reached a total depth of 1,766m in metamorphic rocks below the Lower Tsagaantsav objective.

The well penetrated the top of the Lower Tsagaantsav at 1,596m where it encountered sandstone with live oil shows consisting of fast bluish white fluorescent cut. The shows were preceded by elevated gas in the overlying Lower Zuunbayan seal. The well drilled a 132m gross thickness of Lower Tsagaantsav, with 8 meters of net pay averaging 23% porosity within a single principal zone between 1,639 and 1,651m depth

DT-9 was designed to test a Lower Tsagaantsav structural closure within Petro Matad's Shoroo prospect. The Company is preparing future drilling locations in a contiguous part of Shoroo Prospect, where the Lower Tsagaantsav reservoir is 100m higher than at DT-9. The location of this prospect is shown on the map in the website version of the Company's news release of 14 July 2011. The high porosity sandstone with high calculated hydrocarbon saturation in DT-9 provides a well-defined test interval for Petro Matad's on-going testing program.

The exploration drilling rig has now been relocated from DT-9 to the DT-10 location. DT-10 will target a Lower Tsagaantsav primary objective 4.3 km south of DT-9, within a separate structural closure that is 450m higher than DT-9. The structure lies between the Company's Shoroo and Gal prospects in an area that was enhanced by recent reprocessing of the Davsan Tolgoi 3D seismic survey. The DT-10 structure is analogous to producing structures at the Tolson Uul field in Block XIX north of Davsan Tolgoi, and the DT10 closure is situated along the interpreted migration path between DT-9 and the Lower Tsagaantsav oil encountered in the Company's DT-3 well drilled in 2010. DT-10 continues the Company's evaluation of its Lower Tsagaantsav prospect inventory in the western part of the Davsan Tolgoi area of Block XX. DT-10 was spudded at 1300hrs (Mongolian time) on August 21.

Commenting on the results from DT-9, Petro Matad CEO Doug McGay stated "DT-9 is the latest successful well in the Company's Davsan Tolgoi exploration program and we are pleased to note such a good, solid interval of hydrocarbons. The Davsan Tolgoi Shoroo Prospect is now starting to develop very satisfactorily, considering the success of DT-9 and the previously drilled DT-4, together with the recently completed re-mapping of the reprocessed 3D seismic data in this area.

"The Company is now building an appreciable database of new and reprocessed data on Davsan Tolgoi and nearby environs. The mapping and integration of the merged seismic data (reprocessed 3D and 2D, and the 2011 2D) will be combined with this year's drilling and testing results and add knowledge and confidence to the Company's understanding of its assets."

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Melrose Sees 23% Increase in 1H11 Production

- Melrose Sees 23% Increase in 1H11 Production

Wednesday, August 17, 2011
Melrose Resources plc

Melrose announced its interim results for the six month period ended 30 June 2011.

Operational highlights

• average production increased by 23 percent to 20.2 Mboepd on a net entitlement basis (equivalent to 38.0 Mboepd on a working interest basis)
• 3D seismic interpretation completed on the South East Mansoura concession (Egypt) confirming Cretaceous oil play potential
• 2D seismic acquisition completed on the Mesaha (Egypt) and Rhône Maritime (France) frontier exploration concessions
• operations on the South West Kanun (Turkey) exploration well are nearing completion with no oil shows yet encountered
• Concession Agreements signed for the Muridava and Est Cobalcescu licenses (Romania)
• entered into a two year extension on the Galata Block exploration concession (Bulgaria)

Financial highlights

• revenue increased to $155.8 million (H1 2010: $110.0 million)
• EBITDAX increased to $134.4 million (H1 2010: $86.3 million)
• profit after tax increased to $33.2 million (H1 2010: $4.1 million)
• net debt reduced to $367.3 million (H1 2010: $459.6 million)
• financial gearing of 107 percent (H1 2010: 140 percent)

Robert Adair, Executive Chairman commented, "The first half of 2011 represented an important turning point for the Company, with the production revenues from our two core areas in Egypt and Bulgaria allowing us to progress a number of high potential exploration initiatives.

"The Company has delivered a strong financial performance and our underlying profitability has continued to improve while we have made a major step towards reducing financial gearing.

"We look forward to making further progress in continuing to grow as a diversified, well balanced exploration and production company."

CHAIRMAN'S STATEMENT

The first half of 2011 has been a period of strong financial performance for the Company as we began to see the benefits from our new Bulgarian gas field developments which came on stream late last year. Coupled with production from our existing Egyptian assets, the new fields have helped generate significant post tax profits and operating cash flow of $33.2 million and $104.9 million, respectively, and we are on track to reduce our financial gearing towards 100 percent by year end.

The Company achieved an average production rate of 20.2 Mboepd on a net entitlement basis (equivalent to 38.0 Mboepd on a working interest basis) during the first half of 2011. This was somewhat below forecast due to a number of operational factors in Egypt which we are addressing through a remedial drilling and work-over program. While these considerations should have a minimal impact on reserves, we feel it prudent to reduce our full year production guidance to 36.0 Mboepd on a working interest basis pending completion of the rig activities.

During the period we made good progress on a number of exploration initiatives as we strengthen the Company's focus on high growth opportunities. We completed the interpretation of the 3D seismic data which we acquired over the South East Mansoura concession in Egypt last year and were pleased to confirm significant oil potential in the Cretaceous exploration play. We plan to drill our first test well on this play later this year on a prospect called Al Hajarisah. We also completed the acquisition of key 2D seismic surveys over our high potential frontier exploration blocks in Egypt (Mesaha) and offshore France (Rhône Maritime). Detailed interpretation of these surveys is still ongoing but the preliminary analysis indicates that both blocks contain numerous large structures which could form the basis for hydrocarbon traps. We plan to drill our first well on Mesaha next year and envisage 3D seismic acquisition or drilling on the Rhône Maritime block within the same timeframe.

During the period, the Company announced the Concession Agreements for the Muridava and Est Cobalcescu concessions offshore Romania had been signed and we are looking forward to acquiring seismic surveys over these blocks in 2012 with a view to starting a drilling campaign in 2013. In addition, the Company has exercised its option to enter a two year extension of the Galata exploration permit in Bulgaria. Both these shallow water western Black Sea areas are highly prospective, containing a number of plays and have the potential to make a significant contribution to the Company's growth plans.

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ATP Sees Revenue Increase in 2Q 2011

- ATP Sees Revenue Increase in 2Q 2011

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

ATP announced second quarter 2011 results.

Results of Operations

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

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

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

Capital Resources and Liquidity

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

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

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

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

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

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OPEC Shaves Oil Demand Outlook, Sees 'Dark Clouds' over Econ

- OPEC Shaves Oil Demand Outlook, Sees 'Dark Clouds' over Econ

Tuesday, August 09, 2011
Dow Jones Newswires
LONDON
by Benoit Faucon

OPEC Tuesday trimmed its global oil demand growth forecast for 2011 and warned it could cut the outlook further, signaling that mounting economic woes are biting into the world's crude consumption.

In its monthly report, the Organization of Petroleum Exporting Countries reduced the global demand growth forecast for this year by 150,000 barrels of oil a day--the deepest such cut this year--on a downgrade in its U.S. economic growth outlook and weakening Chinese prospects.

"Dark clouds over the economy are already impacting the market's direction," OPEC said. "The potential for consequent deterioration in market stability requires higher vigilance and close monitoring of developments over the coming months."

Global oil demand will still rise by 1.2 million barrels a day, and the downgrade represents only a fraction of the 88.14 million barrels a day OPEC expects to be consumed this year worldwide.

OPEC warned that were higher oil prices to persist or the most industrialized economies to suffer further setbacks, it might trim the forecast by another 200,000 barrels a day. OPEC produces more than one in three barrels consumed worldwide each day.

Coming hard on the heels of a drop in oil prices by over 10% since early August, the downgrade could give ammunition to an Iran-led group that has fought higher oil output. A June OPEC meeting in Vienna ended in acrimony after a Saudi Arabia-led group failed to persuade OPEC that an anticipated surge in oil demand this year merited an output increase.

OPEC Tuesday cut its U.S. economic growth forecast to 1.8% in 2011 from 2.5% previously. U.S. oil consumption data for May showed the largest decline observed since January 2010 and demand contraction in industrialized countries was expected to continue.

OPEC also said demand in China--the engine of oil consumption growth in recent years-has been losing steam. The country's factory sector grew in June at its slowest pace in 28 months, OPEC said.

OPEC estimated demand for its own crude remained unchanged for 2011 and is still up 200,000 barrels compared to last year, as the global demand downgrade is offset by lower-than-expected non-OPEC supply. The OPEC oil demand outlook, however, was cut by 100,000 barrels a day for next year.

But the group's data also still points to a supply gap of 811,000 barrels a day in the second half of this year, according to a Dow Jones calculation of the difference between current oil output and OPEC's demand forecast for the coming period.

But the crystal ball will roll into the consumers' camp with the U.S. Energy Information Administration expected to release its own report later Tuesday, followed by the International Energy Agency Wednesday.

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

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PXP Sees Increase in 2Q Revenue

- PXP Sees Increase in 2Q Revenue

Thursday, August 04, 2011
Plains Exploration & Production Co.

Plains Exploration & Production (PXP) announced 2011 second-quarter financial and operating results.

• Revenues of $514.8 million and net income of $124.9 million, or $0.87 per diluted share.
• Adjusted net income of $77.1 million, or $0.54 per diluted share (a non-GAAP measure).
• Income from operations of $186.1 million.
• Net cash provided by operating activities of $287.5 million.
• Operating cash flow of $299.6 million (a non-GAAP measure).
• Average daily sales volumes of approximately 97.7 thousand barrels of oil equivalent (BOE), a 15% increase compared to second-quarter 2010 or 27% increase pro-forma for the 2010 asset sale.
• Average daily liquids sales volumes increased 7% compared to second-quarter 2010 or 12% pro-forma for the 2010 asset sale and are expected to increase ratably throughout the rest of the year.
• Crude oil price realization of 88%.
• Executed crude oil contracts significantly improving differentials.
• Total production costs per BOE of $16.09.
• Gross margin per BOE was $25.31 and cash margin per BOE was $39.92 (a non-GAAP measure).

FINANCIAL SUMMARY

PXP reports second-quarter revenues of $514.8 million and net income of $124.9 million, or $0.87 per diluted share, compared to revenues of $364.6 million and net income of $45.4 million, or $0.32 per diluted share, for the second-quarter 2010. These results include certain items affecting comparability of operating results. These items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts, an unrealized gain on investment, and other items. When considering these items, net income for the second-quarter 2011 was $77.1 million, or $0.54 per diluted share (a non-GAAP measure), compared to $36.9 million, or $0.26 per diluted share, for the second-quarter 2010.

For the first six months of 2011, PXP reports revenues of $945.1 million and net income of $195.9 million, or $1.37 per diluted share, compared to revenues of $748.6 million and net income of $103.9 million, or $0.73 per diluted share, for the same period in 2010. These results include certain items affecting comparability of operating results. These items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts, an unrealized gain on investment, and other items. When considering these items, net income for the first six months of 2011 was $129.6 million, or $0.90 per diluted share (a non-GAAP measure), compared to $80.5 million, or $0.57 per diluted share, for the same period in 2010.

A reconciliation of non-GAAP financial measures used in this release to comparable GAAP financial measures is included with the financial tables.

CRUDE OIL MARKETING UPDATE

In August, PXP executed a new marketing contract for its California crude production with ConocoPhillips (NYSE:COP - News). Currently PXP sells approximately 65% of its California crude oil to ConocoPhillips. The new contract covers approximately 90% of PXP's California production, extends the dedication from January 1, 2015 to January 1, 2023 and replaces the percent of NYMEX index pricing mechanism with a market-based pricing approach beginning in 2012.

Separately, PXP executed an agreement with a third party purchaser to sell a large portion of its Eagle Ford crude oil using a Light Louisiana Sweet (LLS) based pricing mechanism.

In 2012, using the current market price outlook and the new marketing contracts, PXP currently expects full-year oil price realization to be between 101% - 103% of NYMEX. PXP expects 2012 total company liquids price realization, which includes crude oil and natural gas liquids, to be between 93% - 95% of NYMEX compared to full-year 2011 total company liquids price realization guidance range of 84% - 86%.

MANAGEMENT COMMENT

James C. Flores, Chairman, President and CEO of PXP commented, "Today's announcement underscores the strength of our asset base and the skill of our dedicated employees as we continue to execute our plan to manage volume growth and strong margins. Compared to the second-quarter 2010 our total Company sales volumes increased 15% and liquids sales volumes increased 12%, pro-forma for the 2010 asset sale. In our Eagle Ford area, daily sales volumes are expected to more than double by year-end 2011 as operational momentum builds during the second half of the year. In each of our core asset areas, we remain focused on the execution of the onshore oil drilling and expansion plan and results continue to be positive. With higher crude volumes and stronger crude pricing, the business generated a 41% increase in operating cash flow and a 20% increase in cash margin per BOE over the second-quarter 2010. We expect these trends to continue supported by the accelerated Eagle Ford activity and the recently executed crude oil marketing contracts reflecting premium pricing to NYMEX."

GUIDANCE UPDATE

Due primarily to our accelerated drilling activity in the Eagle Ford and a higher than originally planned rig count in the Haynesville, PXP's Board of Directors approved an increase in 2011 capital spending which is estimated to be approximately $1.5 billion, excluding deepwater spending, up from $1.2 billion.

For the first six months, average daily sales volumes were 92.9 thousand BOE. With higher drilling activity year-to-date than originally planned in the Haynesville and the Eagle Ford, full-year 2011 average daily sales volumes are now expected to be near the upper end of a new guidance range of 97 – 100 thousand BOE per day.

PXP expects its oil price realization for the full-year 2011 to be above the guidance range due to continued strength of California crude oil pricing relative to NYMEX West Texas Intermediate.

PXP expects lease operating expense per BOE, a component of total production cost per BOE, to be at the high end of the $7.90 - $8.30 per BOE full-year 2011 guidance range due to the increased activity in the Eagle Ford.

OPERATIONAL UPDATE

In the Texas Panhandle asset area, PXP has 5 drilling rigs operating in the Granite Wash trend and expects to continue this level of activity through 2011. Second-quarter daily sales volumes averaged approximately 13,620 BOE per day net to PXP, or 52% higher than first-quarter 2011 and 139% higher than the second-quarter 2010. Average daily sales volumes are expected to increase to approximately 17,000 BOE net per day by year-end 2011. During 2010 and early 2011, PXP built 15 production handling facilities and related infrastructure in order to support the rapid growth in sales volumes that PXP is now reporting.

In the Eagle Ford asset area, PXP has 5.5 net drilling rigs operating, up from the 3 net rig program originally planned for 2011. Second-quarter daily sales volumes averaged approximately 2,330 BOE per day net to PXP, an increase of approximately 4% to first-quarter 2011 average daily sales volumes. For the month of July, daily sales volumes averaged approximately 4,400 BOE per day net to PXP; and PXP expects to exit the year above 10,000 BOE net per day for this asset area.

The two most recent initial production test rates are as follows: The Carmody Trust 1H and the Carmody Trust 2H, both located in Karnes County, Texas, achieved an initial production rate of approximately 1,745 gross and 1,396 net BOE per day and 1,904 gross and 1,523 net BOE per day, respectively.

During the first half of this year, PXP built 4 production handling facilities and related infrastructure out of the 12 facilities currently planned through 2012 to support future sales volume growth. Each facility has the capability of supporting multiple wells and construction continues on future production facilities. Timing of right-of-way approvals temporarily slowed construction during the second quarter which slowed the process of connecting completed wells to pipelines. With many of the initial logistics resolved, PXP anticipates a ramp up in sales volumes during the second half of 2011.

In the California asset area, PXP has 3 drilling rigs operating onshore where PXP continues its active development program in the Los Angeles and San Joaquin Basins. Daily sales volumes onshore and offshore averaged 40,500 BOE per day net to PXP, or 7% higher than first-quarter 2011 and slightly higher than the second-quarter 2010. Average daily sales volumes are expected to be above 41,000 BOE net per day by year-end 2011.

In the Haynesville Shale asset area, PXP's primary operator is currently operating 31 rigs and expects to reduce the rig count during the quarter. In addition, PXP expects 15 or more rigs run by other operators on its acreage. Second-quarter daily sales volumes averaged approximately 181.7 million cubic feet equivalent (MMcfe) per day net to PXP, or 12% higher than first-quarter 2011 and 71% higher than second-quarter 2010. The rate of increase in sales volumes is anticipated to slow as the rig count decreases later this year.

In the Wyoming Mowry Shale, PXP drilled and completed its first well in June 2011 and produced high-quality oil in small quantities. PXP drilled its second well and is in the process of completing this well. We will study the results of these initial wells and drill two additional wells in 2012 to further evaluate the project.

In the Gulf of Mexico asset area, the operator of the Lucius discovery, Anadarko Petroleum Corporation (NYSE:APC - News), recently announced the finalization of a unitization agreement with Exxon Mobil Corporation and co-owners to develop the Lucius field. Anadarko will operate the unit which includes portions of Keathley Canyon blocks 874, 875, 918 and 919 in the deepwater Gulf of Mexico. Following the unitization agreement, the Lucius interest owners entered into an agreement with the Hadrian South co-venturers whereby natural gas produced from the Hadrian South field will be processed through the Lucius facility in return for a production-handling fee and reimbursement for any required facility upgrades.

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CGGVeritas Sees 16% Increase in YOY Revenue

- CGGVeritas Sees 16% Increase in YOY Revenue

Friday, July 29, 2011
CGGVeritas

CGGVeritas announced its non-audited second quarter 2011 consolidated results. All comparisons are made on a year-on-year basis unless stated otherwise. All second half 2010 results are reported before restructuring and impairment.

• Group Revenue was $750MM, up 16% year-on-year and 3% sequentially.
• Group Operating Income was $16MM:
• Sercel continued to deliver strong performance with Operating Income at $76MM, a margin of 29%.
• Services Operating Income was a loss of $29MM mainly related to North American seasonality in Land, operational interruptions and continued overcapacity in the marine market.
• Multi-client marine and Processing & Imaging contributions were particularly strong.
• Net Income was negative at $38MM, including one-off $17m refinancing costs.
• Net Free Cash Flow was negative at $7MM this quarter and positive at $58MM for the first half of the year.
• Net Debt to Equity ratio was 40%.
• Debt maturity was extended to 2021 and Term Loan B was fully repaid with the issuance of our $650 million Senior Note.
• As planned in our Performance Program, following their upgrades, the Oceanic Phoenix and Oceanic Endeavour returned to operations. Our ship management partnership with Eidesvik was established and a support vessel charter agreement with Bourbon was signed. The Commander was decommissioned at the end of May.
• BroadSeisTM, our advanced marine solution continued to see growing acceptance, and we further developed our newly established commercial joint ventures.
• Our cost reduction program is progressing well in the context of rising fuel cost and the weakening US dollar.

Backlog as of July 1st sequentially strengthened, up 7% to $1.31 billion.

Post Closing Events

Strategic agreement signed with Spectrum, a Norwegian multi-client company, for the contribution by CGGVeritas of our 2D Multi-client marine library for a consideration in cash and a 25% equity position in Spectrum.

CGGVeritas CEO, Jean-Georges Malcor commented, "During the quarter, Sercel delivered excellent performance and Services, despite the impact of Land seasonality, continued to see the signs of a progressively strengthening second half of the year.

"North American Land activity was seasonally low as we repositioned our crews from Canada and the Arctic to the lower 48 for an expected robust summer campaign. Increasing demand for our marine multi-client data in advance of the announced Gulf of Mexico and Brazil lease sales was confirmed, a promising trend for both future multi-client sales and the progressive balancing of over-capacity in marine.

"Our performance plan is progressing well in a context that remains impacted by rising fuel cost and a weakening US dollar. We continued to manage our balance sheet proactively with the significant extension of debt maturity, and in the first half of the year generated positive net free cash flow.

"Looking forward, we expect Sercel to continue to deliver strong financial performance and, while difficult conditions remain in the marine market, Services should benefit from our performance program and from the increasing demand for multi-client data in the second half of the year and particularly near year-end."

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Noble Energy Sees 44% Increase in 2Q Profits

- Noble Energy Sees 44% Increase in 2Q Profits

Thursday, July 28, 2011
Noble Energy Inc.

Noble Energy reported second quarter 2011 net income of $294 million, or $1.61 per share diluted, on revenues of $954 million. The Company's second quarter 2010 net income was $204 million, or $1.10 per share diluted, on revenues of $751 million. Net income for the second quarter 2011 includes unrealized commodity derivative gains, a gain on asset divestiture, as well as certain asset impairments. Excluding these items, second quarter 2011 adjusted net income was $263 million, or $1.44 per share diluted. Adjusted net income for the second quarter of 2010 was $198 million, or $1.07 per share diluted.

Discretionary cash flow for the second quarter 2011 was $659 million, compared to $496 million for the similar quarter in 2010. Net cash provided by operating activities was $745 million, and capital expenditures were $702 million.

Key highlights for the second quarter 2011 include:

• Sold 174 million cubic feet per day (MMcf/d) of natural gas in Israel, up 44 percent from the second quarter last year
• Produced a record 59 thousand barrels of oil equivalent per day (MBoe/d) in the DJ basin
• Drilled longest-ever horizontal Niobrara well in the DJ basin with a 9,100 foot lateral in the Wattenberg field
• Announced a discovery at Santiago in the deepwater Gulf of Mexico and increased Galapagos net production impact to over 10 thousand barrels of oil per day
• Accelerated startup of Aseng, offshore Equatorial Guinea, with first oil production now expected by year-end 2011
• Completed transfer of assets and exit from Ecuador
• Increased liquidity to over $3.6 billion, with $1.5 billion in cash at the end of the period

Charles D. Davidson, Noble Energy's Chairman and CEO, commented, "The second quarter was another strong quarter for Noble Energy. With our performance to date, we now expect sales volumes for the year will fall in the top end of our original guidance range. The second half of the year will be very active for our Company with further expansion of the DJ basin horizontal Niobrara play and active rig programs in all of our key offshore regions. We continue to make excellent progress on our major development projects with Aseng in Equatorial Guinea now well ahead of schedule and our exploration success at Santiago being integrated into the Galapagos project plans. In addition, we anticipate testing multiple exploration opportunities in West Africa, the Eastern Mediterranean, and the deepwater Gulf of Mexico before the end of the year."

The Company's total sales volumes for the second quarter 2011 averaged 215 MBoe/d. Production volumes were 216 MBoe/d, with the difference attributable to crude oil and condensate underliftings in Equatorial Guinea. Excluding the 2010 sale of certain onshore U.S. assets, as well as the impact of the Company's exit from Ecuador, sales volumes were up 3 percent from the second quarter 2010. Growth in the DJ basin and Israel more than offset timing differences in Equatorial Guinea liftings, as well as natural decline in the Company's various other onshore U.S. and deepwater Gulf of Mexico assets.

International sales volumes were 100 MBoe/d, up slightly from the second quarter last year despite lower liquid liftings in Equatorial Guinea and the termination of the Company's activities in Ecuador. Strong power generation demand and lower competing imports led Noble Energy's natural gas sales in Israel to be up substantially from the prior year. In the North Sea, field performance at Dumbarton and Lochranza accounted for increased oil volumes. The Company's 2010 volumes included 27 MMcf/d of natural gas in Ecuador, where its production sharing contract was terminated in late 2010.

Noble Energy's U.S. volumes were 115 MBoe/d for the second quarter of 2011, down versus the prior year period as a result of the 2010 sale of approximately 6 MBoe/d of Mid-continent and Illinois basin oil assets. In the DJ basin, second quarter 2011 volumes averaged over 59 MBoe/d, up 8 percent from the same period in 2010. The increase is attributed to the continued acceleration of the Company's vertical and horizontal drilling programs in Wattenberg. A third-party processing facility expansion came online in June 2011, which is allowing for further field production growth.

The Company's barrel of oil equivalent (Boe) realizations were up significantly for the second quarter 2011 versus 2010. International natural gas as a percentage of total Company volumes grew to 32 percent for the second quarter 2011, with global liquids representing 39 percent, and U.S. natural gas the remaining 29 percent.

Total production costs per Boe, including lease operating expenses, production and ad valorem taxes, and transportation were $7.92 per Boe, up approximately 5 percent from the second quarter 2010. The increase was largely attributable to higher production and ad valorem taxes caused by stronger commodity pricing. Lease operating expense was $5.06 per Boe and depreciation, depletion, and amortization was $12.01 per Boe for the second quarter 2011. Exploration expense for the quarter included recognition of dry hole cost on the Kora well, offshore Senegal and Guinea-Bissau. General and administrative expenses were up primarily related to increased staffing for the development of the Company's major development projects. Noble Energy's adjusted effective tax rate was 33 percent, with 52 percent deferred. Deferred taxes for the second quarter 2011 were impacted by the resolution of prior year tax reviews.

The Company recorded asset impairments totaling $131 million in the second quarter 2011, resulting from field performance at Oliver Creek in East Texas and Iron Horse in Wyoming, combined with a low natural gas price environment. Other operating income/expense includes a $26 million gain on the divestiture of assets, primarily a result of the Company's transfer of assets and exit from Ecuador. The gain and asset impairments are excluded from net income in determining adjusted net income. Also included in other income/expense is a $7 million deferred compensation income item relating to the quarterly value change of Noble Energy stock held in a benefit program.

UPDATED GUIDANCE

Noble Energy has raised its full year 2011 sales volume guidance to range from 215 to 218 MBoe/d, with the primary driver being higher natural gas volumes in Israel. For the third quarter 2011, the Company expects volumes to average 215 to 220 MBoe/d. Onshore U.S. volumes should be up versus the second quarter, with crude oil and natural gas growth from the DJ basin offsetting natural declines in other onshore natural gas areas. The deepwater Gulf of Mexico is expected to have lower sales volumes as result of natural decline and the impact of a Swordfish gas well that recently watered out. Higher volumes in Equatorial Guinea and strong demand for natural gas in Israel should contribute to increased international volumes.

The Company also adjusted its 2011 total capital program to approximately $3.0 billion. Over a third of the $300 million increase is related to new high-impact international exploration opportunities, with the remainder supporting the expansion of the Wattenberg horizontal Niobrara program, the acceleration of major projects in Equatorial Guinea, and the addition of a new near-term gas development project in Israel.

The addition of the offshore Senegal and Guinea-Bissau opportunity, as well as the updated timing of a Cyprus exploration well (now planned to spud in the fourth quarter) comprises the majority of the higher exploration capital for 2011.

The Company continues to expand its Niobrara drilling program at Wattenberg, with plans to bring a fifth horizontal rig into the field in the middle part of the third quarter. As a result of the additional rig and continued efficiencies, the Company anticipates drilling around 85 horizontal Niobrara wells in the DJ basin in 2011, up approximately 20 percent from original estimates. Offshore Israel, the Company is proceeding with development of the Noa field in the third quarter of 2011 (first production is expected in the second half of 2012).

In Equatorial Guinea, the Company is continuing to progress its liquid developments at Aseng and Alen. First production at Aseng is now expected by year-end 2011.

Noble Energy has modified its full year exploration expense guidance to range from $380 to $440 million as a result of the new exploration opportunities in West Africa (Senegal and Guinea-Bissau) and Cyprus. In addition, income from equity method investees has been increased to between $165 to $185 million, up from original guidance as a result of strong global liquid prices.

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FMC Technologies Sees 21% Increase in 2Q Earnings

- FMC Technologies Sees 21% Increase in 2Q Earnings

Monday, July 25, 2011
FMC Technologies Inc.

FMC Technologies reported second quarter 2011 revenue of $1.2 billion, up 21 percent from the prior-year quarter. Diluted earnings per share were $0.39, equal to the prior-year quarter.

Total inbound orders of $1.5 billion were up 18 percent from the second quarter of 2010 and included $939 million in subsea systems orders. Backlog for the Company reached a record $5.0 billion including record subsea systems backlog of $4.2 billion. Subsea systems recorded its sixth consecutive quarterly backlog increase.

"We have booked almost $1.9 billion in subsea orders during the first half of 2011, and continue to believe $4.0 billion in orders for the year is possible," said John Gremp, President and Chief Executive Officer. "Our subsea revenue of nearly $800 million during the second quarter has kept us on track to reach $3.3 billion revenue for the year. Our fluid control business is continuing to produce at record levels and as our capacity expansion comes online, we will be able to meet our customers' growing demands."

Review of Operations – Second Quarter 2011

Energy Production Systems

Energy Production Systems' second quarter revenue was $967.6 million, including subsea systems revenue of $795 million. Surface wellhead revenue was up 13 percent from the second quarter of 2010 with stronger North American activity partially offset by market timing and execution issues in our international operations.

Energy Production Systems' operating profit of $97.3 million decreased 25 percent from the prior-year quarter, due to lower margins in subsea systems combined with increased costs and less favorable mix in surface wellhead.

Energy Production Systems' inbound orders for the second quarter were $1.2 billion, including subsea systems orders of $939 million. Backlog for Energy Production Systems was $4.5 billion, including $4.2 billion in subsea systems at the end of the second quarter.

Energy Processing Systems

Energy Processing Systems' second quarter revenue of $262.9 million was 37 percent higher than the prior-year quarter. The increase came mainly from fluid control, with record revenue in the quarter.

Energy Processing Systems had record operating profit of $53.9 million in the second quarter, up 62 percent from the prior-year quarter. The increase was driven by higher volume in fluid control resulting from strong North American pressure pumping activity.

Energy Processing Systems' inbound orders were a record $339.8 million in the second quarter led by strong orders in fluid control. Backlog for the segment finished the quarter at $421.3 million.

Corporate Items

Corporate expense in the second quarter was $10.6 million, an increase of $0.5 million from the prior-year quarter. Other expense, net, was $2.0 million, a decrease of $7.9 million from the prior-year quarter due largely to $4.0 million in foreign exchange gains in 2011 compared to a $2.7 million loss in 2010.

The Company ended the quarter with net debt of $44.8 million. Net interest expense was $2.1 million in the quarter.

The Company repurchased 149,000 shares of common stock in the quarter, at an average cost of $40.87 per share.

Depreciation and amortization for the second quarter was $26.3 million, up $0.9 million from the previous quarter. Capital expenditures for the second quarter totaled $61.8 million.

The Company recorded an effective tax rate of 30.9 percent for the second quarter.

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Magnum Hunter Sees 133% Increase in Reserves

- Magnum Hunter Sees 133% Increase in Reserves

Thursday, July 14, 2011
Magnum Hunter Resources Corp.

Magnum Hunter announced a 133% increase in the quantity of the Company's estimated total proved reserves at June 30, 2011 as compared to December 31, 2010. The present value of estimated future cash flows, before income taxes, of the Company's estimated total proved reserves as of mid-year 2011, discounted at 10% ("PV-10"), also increased 141% as compared to six months ago at year-end 2010.

Magnum Hunter's total proved reserves increased by 17.8 million barrels of oil equivalent (Boe) to 31.2 million Boe (55% crude oil & ngl; 50% proved developed producing) as of June 30, 2011 as compared to 13.4 million Boe (51% crude oil & ngl; 44% proved developed producing) at December 31, 2010. The Company's reserve life (R/P ratio) was approximately 17.3 years as of June 30, 2011.

The Company's PV-10 at June 30, 2011 increased by $250 million or 141% to $428 million from $178 million at December 31, 2010. Under new SEC guidelines, the commodity prices used in the December 31, 2010 and June 30, 2011 PV-10 estimates were based on the 12-month unweighted arithmetic average of the first day of the month price for the periods January 1, 2010 through December 31, 2010, and July 1, 2010 through June 30, 2011, respectively, adjusted by lease for transportation fees and regional price differentials. For crude oil and ngl volumes, the average West Texas Intermediate posted price of $89.96 per barrel at June 30, 2011, was up 13% from the average price of $79.43 per barrel at December 31, 2010. For natural gas volumes, the average price of the Henry Hub spot price of $4.20 per million British thermal units ("MMBTU") at June 30, 2011 was down (4%) from the $4.37 per MMBTU at December 31, 2010. All prices were held constant throughout the estimated economic life of the properties.

Note: PV-10 is a non-GAAP financial measure and should not be considered as an alternative to the standardized measure of discounted future net cash flows as defined under GAAP; see "Non-GAAP Measures: Reconciliation to Standardized Measure" below for the Company's definition of PV-10 and a reconciliation to the standardized measure.

The Company's June 30, 2011 total proved reserves of 31.2 million Boe reflect an organic growth of 6% from the Company's pro forma proved reserves of 29.4 million Boe as of December 31, 2010, when including the proved reserves related to the Company's acquisition of the assets of NGAS Resources, Inc. and NuLoch Resources, Inc., which occurred on April 13, 2011 and May 3, 2011, respectively. Magnum Hunter's first half of fiscal year 2011 organic extensions and discoveries from drilling activities replaced the Company's estimated production through June 30, 2011 by a factor of four times. When including the first six months of fiscal year 2011's property acquisition activities, the replacement of production factor for the first six months of fiscal year 2011 increased by approximately 20 times.

The estimates of Magnum Hunter's total proved reserves as of December 31, 2010 and June 30, 2011 were prepared by the Company's third-party engineering consultants.

Resource Potential

The Company's internal engineering team has evaluated the resource potential of Magnum Hunter's existing undeveloped lease acreage position in our three unconventional shale plays. The undeveloped acreage evaluated includes 652,419 gross acres and 347,547 net acres to Magnum Hunter's ownership interest.

The current number of total new drilling locations in Magnum Hunter's inventory today is approximately 4,000 of which 1,350 are identified drilling locations in these three unconventional resource plays, net to the Company's interest. The net unrisked resource potential of 462 million barrels of oil equivalent is approximately 48% crude oil and natural gas liquids

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Chevron Sees Increase in 2Q Earnings on Higher Oil Prices

- Chevron Sees Increase in 2Q Earnings on Higher Oil Prices

Tuesday, July 12, 2011
Chevron Corp.

Chevron reported in its interim update that earnings for the second quarter 2011 are expected to be higher than in the first quarter 2011. Upstream results are projected to improve between sequential quarters, benefiting from higher crude oil prices.

Basis for Comparison in Interim Update

The interim update contains certain industry and company operating data for the second quarter 2011. The production volumes, realizations, margins and certain other items in the report are based on a portion of the quarter and are not necessarily indicative of Chevron's full quarterly results to be reported on July 29, 2011.

Unless noted otherwise, all commentary is based on two months of the second quarter 2011 versus full first quarter 2011 results.

UPSTREAM

U.S. net oil-equivalent production during the first two months of the second quarter was in line with the first quarter 2011. International net oil-equivalent production declined 76,000 barrels per day, largely reflecting maintenance activity in Kazakhstan.

U.S. crude-oil realizations for the first two months of the second quarter increased about $18 per barrel to $111.11, and International liquids realizations improved approximately $13 to $108.46 per barrel. U.S. natural gas realizations increased $0.28 to $4.32 per thousand cubic feet, and international natural gas realizations increased $0.41 to $5.44 per thousand cubic feet.

International Upstream earnings in the second quarter are expected to reflect higher exploration expenses.

The company's general guidance for the quarterly net after-tax charges related to corporate and other activities is between $250 million and $350 million. Due to foreign currency effects and the potential for irregularly occurring accruals related to income taxes and other matters, actual results may significantly differ from the guidance range.

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Rex Sees 9% Increase in 2Q Production Guidance

- Rex Sees 9% Increase in 2Q Production Guidance

Monday, July 11, 2011
Rex Energy Corp.

Rex announced second quarter production results. The company also adjusted operating expense guidance for the full year.
Second Quarter 2011 Unaudited Production

Rex Energy exceeded its previously announced second quarter guidance by 9% with an average production rate of 35.2 MMcfe/d. This is an 87% increase over second quarter 2010 and a 28% increase over first quarter 2011. Oil and natural gas liquids accounted for 41% of the total equivalent net production for the quarter. Natural gas production increased 184% over second quarter 2010 and 48% over first quarter 2011. Natural gas accounted for 59% of total equivalent net production for the quarter.
Full Year Lease Operating and G&A Expense Guidance

Rex Energy is decreasing its previously given lease operating expense (LOE) guidance from $32.0 million -- $37.0 million down to $31.0 million - $34.0 million. The decrease in LOE guidance is the result of lower operating cost assumptions.

Rex Energy is increasing its 2011 general and administrative (G&A) guidance range from $20.0 million - $21.0 million to $24.0 million - $25.0 million. The increase in G&A primarily results from one-time legal fees and costs related to the previously announced settlement in Westmoreland County and costs associated with the departure of the company's former CEO.

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Namibia Sees 11 Billion Barrels In Offshore Oil Reserves

- Namibia Sees 11 Billion Barrels In Offshore Oil Reserves

Wednesday, July 06, 2011
Dow Jones Newswires
WINDHOEK

An estimated 11 billion barrels in oil reserves have been found off Namibia's coast, with the first production planned within four years, mines and energy minister Isak Katali announced Wednesday.

The finding could put Namibia on par with neighboring Angola, whose reserves are estimated at around 13 billion barrels and whose production rivals Africa's top producer, Nigeria.

Katali said that Enigma Oil & Gas, owned by London-listed Chariot Oil & Gas, has identified 11 prospects along the southern coast.

"The largest of these, the Nimrod Prospect in 350 meters (1,150 feet) depth, and most likely reserves in the event of success are estimated to be greater than four billion barrels," he told parliament.

"Enigma expects to find oil rather than gas," Katali said, adding that first production could begin as early as 2015.

Enigma holds a 50% equity in the offshore Southern Block together with Brazil's Petrobras.

According to Katali, another Brazilian company, HRT Oil & Gas Ltd, has raised $1.3 billion on the Brazilian stock market, with $300 million earmarked for oil and gas exploration in Namibia.

He said that HRT has certified about 5.2 billion barrels of potential reserves.

"This finding could turn offshore Namibia into a great producer of oil and gas in a short time," Katali said.

In his statement to Parliament, Katali added that HRT would drill three to four wells in that area as early as next year.

Another find off Namibia's central coast called Delta Prospect contained recoverable resources of up to two billion barrels of oil, by Arcadia Expro Namibia and British firm Tower Resources, he said.

"We expect that six to eight wells to be drilled in Namibia's waters in the next 18 months, the highest number in Namibia's exploration history," he said.

Namibia has long been seen as a potential new source of oil, hampered by a lack of exploration to determine the extent of its reserves. Its offshore geology is similar to Brazil, which is seeing a boom in oil.

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S&P Lifts BP Outlook To Stable; Sees Less Downside Risk

- S&P Lifts BP Outlook To Stable; Sees Less Downside Risk

Wednesday, July 06, 2011
Dow Jones Newswires
by Melodie Warner

Standard & Poor's Ratings Services revised its credit outlook on BP to stable from negative, saying it sees less downside risk to the oil company's credit quality and little evidence of further erosion to its business standing.

The ratings company also affirmed BP's long-term corporate credit rating of A, which is five steps below the coveted AAA.

"The stable outlook reflects our view that BP is well positioned to meet potentially substantial additional fines and other payments related to the Gulf of Mexico disaster," the firm said. For its analysis, S&P assumes that all Gulf of Mexico-related payments will total less than $55 billion and will be spread over several years.

The ratings firm noted BP's first-quarter average realized oil price was 19.2% higher than the fourth quarter, and rose 31% from a year earlier. BP's refining margins also expanded in 2011, while its underlying downstream operating profit increased to $2.1 billion in the first quarter, from a quarterly average of $1.2 billion in 2010, despite a 6% decline in refining throughput, S&P said.

But, a sustained decline in oil prices below $70 a barrel alongside underlying operating cash flow of less than $25 billion could put downward pressure on the ratings, S&P said. Any upside rating potential is limited until there is more clarity on the penalties BP could face in the U.S. for the Gulf of Mexico oil spill.

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Chesapeake Energy Boosts Payout; Sees Regular Increases

- Chesapeake Energy Boosts Payout; Sees Regular Increases

Monday, June 13, 2011
Dow Jones Newswires

Chesapeake said Monday it raised its common-stock dividend by 17%, marking the natural-gas company's first increase since June 2008.

"It is our goal to be able to increase our common-stock dividend regularly in the years ahead," said Chief Executive Aubrey K. McClendon.

The company raised its quarterly dividend to 8.75 cents a share from 7.5 cents; the increased payout will cost the company an additional $32.9 million a year.

"From a value perspective, this announcement is negligible though it does paint a positive picture from an optical standpoint," analysts with Canaccord Genuity wrote in a note to clients.

Chesapeake Energy, the second-largest U.S. natural-gas producer after Exxon Mobil Corp. (XOM), joins a long list of companies that have increased payouts to shareholders in recent months using stockpiled cash. Last month, Chesapeake Energy reported that it swung to a first-quarter loss on steep derivatives losses and a 42% drop in revenue as energy prices declined, while production increased from a year ago.

On Friday, shareholders demonstrated dissatisfaction with the company's board and pay practices as about 22% of votes were withheld in McClendon's re-election as chairman, up from only 4% that opposed his election in 2008. In an advisory say-on-pay vote, only 58% said they approved of Chesapeake's executive-compensation plan.

Chesapeake spokesman Jim Gipson said Monday that the dividend hike had "been planned for many months" and wasn't made in response to Friday's shareholder votes.

Shares, which have risen 19% in the last year, recently traded down 77 cents, or 2.63%, at $28.47.

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Circle Oil Sees Increase in 2011 Recoverable Resources

- Circle Oil Sees Increase in 2011 Recoverable Resources

Wednesday, June 08, 2011
Circle Oil plc

Circle Oil announced the 2011 update to Ultimate Recoverable Resources ("URR")1 for the NW Gemsa Concession, Egypt, and the Sebou Permit, Morocco, which indicates a significant increase over the 2010 URR estimates for both permits. The updated gross estimates were compiled by RPS Energy ("RPS"),an independent consultancy specializing in petroleum and gas reservoir evaluation. The estimates use the 2007 Petroleum Resources Management System ("PRMS") produced by SPE/WPC/AAPG/SPEE and are set out in the tables below together with further explanation of the results.

Egypt

The new resource estimates take account of the results of the drilling and development activity up to but not including Geyad-3.

The RPS report2 states that the most likely (P50) URR for the discoveries in NW Gemsa in Al Amir SE, Geyad plus South Gharib in Al Amir are 30.0MMBO and 34.2 bcf of gas, which together equates to 35.9MMBOE gross (14.4MMBOE net).3 This constitutes a 49% increase over the 2010 figure of 24.1MMBOE gross (9.6MMBOE net). The most likely unrisked URR in the Kareem reservoir in the Al Amir prospect is 3.9 MMBOE gross with a geological probability of success of 84%, as assigned by RPS. The Al Amir Kareem area volume was included in the Al Amir SE URR in the 2010 report, as at that time it was considered as an adjoining portion to Al Amir SE which had and has still not been drilled, but could be reasonably judged to be economically productive on the basis of geological, geophysical and engineering data. The 2011 total most likely (P50) recoverable resources estimate, to compare like with like areas (including Al Amir Kareem) with the 2010 report, is 33.2MMBO and 38.1 bcf of gas, which together equates to 39.8MMBOE gross (15.9MMBOE net). This constitutes a 65.1% increase over the 2010 figure of 24.1MMBOE gross (9.6MMBOE net).

The upside estimate (P10) for the discovered fields increases to 54.5MMBOE gross (21.8MMBOE net) which represents a 33% increase over the 2010 figure of 41.0MMBOE (16.4MMBOE net). The unrisked upside estimate of URR in the Kareem reservoir in the Al Amir prospect is 9.3MMBOE gross (3.7MMBOE net). The 2011 total upside (P10) recoverable resources estimate, to compare like with like areas, is 63.8MMBOE gross (25.5MMBOE net), which constitutes a 55.6% increase over the 2010 figure of 41.0MMBOE gross (16.4MMBOE net).

The increase in URR is due to a large increase in the estimated recovery factor from the Kareem reservoir which results from observation of well production performance data and the positive effect of the planned installation of gas production and water injection facilities, which are expected to be completed by the end of 2011.

The NW Gemsa Concession partners include: Vegas Oil and Gas (50% interest and operator); Circle Oil Plc (40% interest); and Sea Dragon Energy (10% interest).

The NW Gemsa Concession, containing the Al Amir and Geyad Development Leases, covering an area of over 260 square kilometres, lies about 300 kilometres southeast of Cairo in a partially unexplored area of the Gulf of Suez Basin. The concession agreement includes the right of conversion to a production licence of 20 years, plus extensions, in the event of commercial discoveries.

Morocco

The new resource estimates take account of the results of the drilling up to and including KSR-11.

The RPS estimate of most likely (P50) URR of gas is 30.6 bcf gross (23.0 bcf net).This, together with our own internal estimate of gas production and resources remaining to be produced in areas not included in the report of 1.5 bcf gross, gives a total of 32.1 bcf gross (23.9 bcf net) URR for the Sebou block. This represents a significant increase in gas resources of 83.4% over the 2010 figure of 17.5 bcf gross (13.0 bcf net).

The RPS estimate of upside (P10) URR is 41.7 bcf gross (31.3 bcf net) which together with our own internal estimate of resources in areas not included in the report of 1.5 bcf gross, gives a total of 43.2 bcf gross (32.2 bcf net) for 2011, which represents a 66% increase over the 2010 figure of 26.0 bcf gross (19.3 bcf net).

In the Sebou concession, Circle has a 75% share and ONHYM, the Moroccan State oil company, has a 25% share. In the Oulad N'zala concession, Circle has a 60% share and ONHYM has a 40% share. Both concessions include the right of conversion to a production licence of 25 years, plus extensions in the event of commercial discoveries.

The Sebou permit lies to the north-east of Rabat in the Rharb Basin in Morocco. The Rharb Basin is a foredeep basin located in the external zone of the Rif Folded belt.

Prof Chris Green, CEO, said, "I am very pleased to report this significant uplift in resource numbers for the oil and gas discoveries on our NW Gemsa and Sebou blocks. This is testimony to both the continuing advancement of the partnership's development and appraisal programme in Egypt and the success of our exploration drilling in Morocco. It also highlights the way in which the Company has been utilizing the funds raised from the placing in 2010 to create value for our shareholders. Our drilling success rate over the past three years has been excellent. We continue with our task of increasing both our production capability and resource base."

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IEA Sees Larger Role for Natural Gas

- IEA Sees Larger Role for Natural Gas

Monday, June 06, 2011
Dow Jones Newswires
by John Biers

Natural gas could be entering a "golden age" and represent a much larger portion of the global energy mix, but the fuel is still a fossil fuel and doesn't represent a panacea for climate change, the International Energy Agency said Monday.

The IEA, which represents the governments of consuming countries, said natural gas could rise by more than 50% from 2010 levels and account for more than a quarter of global energy demand by 2035. The estimates follow a recent surge of shale gas production in the U.S., which has significantly altered the energy picture in recent years in the U.S.

But the IEA cautioned that while an increased use of natural gas could boost energy security, it shouldn't overwhelm other energy forms that could be better in addressing climate change. IEA Executive Director Nobuo Tanaka expressed concern that governments over react against nuclear energy following the recent Japan crisis.

"While natural gas is the 'cleanest' fossil fuel, it is still a fossil fuel," Tanaka said. "Its increased use could muscle out low-carbon fuels, such as renewables and nuclear - particularly in the wake of the incident at Fukushima and the likelihood of a reduced role for nuclear in some countries. An expansion of gas use alone is no panacea for climate change," he said.

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