Gould: Oilfield Services Spending Likely to Increase

- Gould: Oilfield Services Spending Likely to Increase

Thursday, September 08, 2011
Rigzone Staff
by Karen Boman

Schlumberger CEO Andrew Gould said he believes that integrated oilfield service companies will play an even more important role in extracting the full potential of existing and new hydrocarbon resources, and that the share of future spending on oilfield services will likely increase.

Oilfield services companies that best help their customers to de-risk and drive project financial performance will ultimately be the most successful, Gould said, adding that the company's approach of applying its unique scientific platform and technical abilities to all parts of its business – supported by its research by development investment of over one billion dollars per year.

Speaking at the Barclays Capital CEO Energy-Power Conference in New York on Sept. 7, Gould said his company has not seen its customers' activity plans impacted by the significant downward revisions of 2011 and 2012 growth forecasts for the major OECD countries, as well as inflation pressure in some key non-OECD countries that is causing concern. However, the company is monitoring the situation closely and is ready to adjust its plans if needed.

"In the past two years, our industry has seen significant volatility, with the largest year-on-year fall in global energy demand in two decades followed by the largest recovery ever seen," Gould said, noting that the world and the energy industry have faced major natural disasters and political unrest and the financial markets have been significantly impacted by both the sovereign debt crisis in parts of the Eurozone as well as the U.S.

The importance of higher exploration activity is best illustrated by the growing supply challenge the industry is facing with the International Energy Agency estimating that around 40 percent of the oil production needed by the end of this decade has yet to be found or developed, Gould said. By 2030, this figure will likely be about 60 percent; natural gas resources show similar trends.

"Adding future reserves is becoming more complex and technologically intense, and is associated with additional cost and risk. With more than half of reserves discovered worldwide offshore and new reserves often located in deepwater and hidden below complex salt structures, the ability to de-risk exploration prospects prior to drilling becomes more and more important," Gould said.

However, statistics show that, on average, two out of three frontier exploration wells today are unsuccessful, indicating that, in spite of advances in seismic technology, the industry still fails to properly manage exploration risk, Gould said. "While seismic technology advances have made significant contributions to better evaluate trap and reservoir risks, almost three-quarters of dry exploration wells are due to inadequate understanding of seal and charge risk."

The last decade has seen a doubling of the number of land and offshore rigs operating worldwide in more difficult, complex and expensive situations, but the general approach to drilling optimization has changed little since the 1980s. "Over the past decades, we have seen excellent examples of advances in individual drilling technologies such as top drives, rotary steerable systems and PDC cutters," Gould noted. "We believe that in order to create the next step change in drilling performance, we need to take a systems approach and move the entire drilling process from being partly an art form to becoming a full-fledged science."

While conventional gas will continue to play a central role in the global supply picture in the next five years, making up more than 85 percent of total gas supply, shale gas development activity continues to grow in the U.S. and worldwide. The U.S. Energy Information Administration estimates that international shale resources are six times higher than those of the U.S. At this time, international shale gas activity remains focused on exploration and pilot projects, but Gould said activity will increase in the coming years and shale gas will begin to have an impact on international supply towards the end of this decade.

Schlumberger's CEO said that the current industry approach to shale development in North America is sub-optimal, as it involves significant cost and resource waste. Thought the energy industry drills horizontal wells spread evenly over acreage, with the entire horizontal section completed and fractured with massive amounts of water proppant and hydraulic horsepower, shale reservoir quality varies both vertically and laterally. "And the standard logging measurements interpretation techniques and modeling workflows used in sandstones and carbonates cannot be directly applied."

Gould noted that the company is seeing signs that the scientific approach to shale developments is gaining momentum and as the international oil companies continues to build their positions in the shale basins both in the U.S., and overseas this trend will only strengthen. "The scientific approach will also be critical overseas as the industry faces more public pressure to minimize the operational footprint and adapt to less available infrastructure compared to North America," said Gould.

Besides investing heavily in the development of new individual drilling technologies that combine the capabilities of its various drilling product lines and creating a powerful technical community by co-locating its GeoMarket drilling experts into drilling support centers, Schlumberger has some of its brightest minds working on creating numerical models able to predict the behavior of the entire drill string as a function of changing surface and downhole parameters, Gould said. The company will have 10 drilling support centers established by year-end; that number will increase to 30 by the end of 2012.

To meet the challenges of more complex, more expensive and more difficult projects, Gould told attendees at the SPE Offshore Europe conference in Aberdeen, Scotland earlier this week that project management skills need to dramatically improve. "Great project managers cannot be created overnight as it's a combination of leadership and technical skills, with the ability to constantly evaluate options. The need to train rand season project managers is becoming acute."

The talent war within the oil and gas industry will be "inflationary and disruptive" as the industry is chasing the same workers and not necessarily adding to the same population at the same rate. Engineers in the U.S. and western Europe can be recruited based on the industry's technology, but only after defending company ethics, proving that the energy industry is not a sunset industry a clear position on climate change. "In the rest of the world, this is unnecessary as oil and gas companies get the pick of students because an oil and gas career is coveted," Gould said.

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IHS: Consolidation of Small E&P Cos Could Increase

- IHS: Consolidation of Small E&P Cos Could Increase

Monday, August 29, 2011
IHS CERA

The uncertainty of future oil prices, combined with falling share prices on both London's Alternative Investment Market (AIM) Index and the Standard and Poor's (S&P) Index in the U.S., has made close to 100 small exploration and production (E&P) companies in the U.K. and two dozen large U.S. producers, prime targets for consolidation in order to achieve future funding, reports IHS in its IHS Herold Oil and Gas Perspectives Report.

"There are nearly 100 E&P companies listed on London's AIM, and while a number of these are small companies, numerous others have participated in apparently significant discoveries around the world that may turn into important oil and gas fields," said Robert Gillon, director of energy company research at IHS, and author of the weekly IHS Herold Oil and Gas Perspectives. "However, almost none of these AIM-listed E&Ps have reached the production stage, which means they are not yet generating revenue. Without revenue, they are dependent on future funding to continue operations. That funding can be accomplished either through additional share sales or a farm-out of an interest in their exploration licenses."

In addition to the AIM-listed companies, Gillon said there are about two dozen large (market cap $0.5 billion to $3.0 billion) U.S. oil and gas producers that could be ripe for consolidation as well. "Some of these U.S. companies are also reliant on external financing to fund their capital budgets, but all of them have developed reserves that could be sold in the very liquid transaction market."

Gillon said it is probably "not a coincidence" that the AIM-listed stocks peaked at about the same time as the Greek financial crisis, while the U.S. companies started to slide after oil prices topped out in April. On August 4, both indices took a serious hit, with the London group down 9.6 percent, while the S&P index shed 7.8 percent, and both have suffered further losses since then.

The AIM index is now down by 40 percent from its recent peak, which means the average company would need to sell almost 70 percent more new shares to raise the same amount of money as it did a few months ago. Meanwhile, optimism about future oil prices is more subdued, and the potential farm-in partners recognize that. As a result, they will demand more favorable terms on the deal. But commitments to the host government must be honored to hold the license.

"We believe there could be a wave of consolidation in the exploration sector," said Gillon. "Selling out will become the most attractive alternative."

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Sevan Marine: Cost Increase for FPSO Sevan Voyageur

- Sevan Marine: Cost Increase for FPSO Sevan Voyageur

Friday, August 26, 2011
Sevan Marine ASA

Sevan Marine informed that the results for the second quarter of 2011 will be postponed until August 31, 2011. There will be no public presentation for 2Q-2011.

Following detailed project reviews and assessments on the FPSO Sevan Voyageur upgrade project, there has been identified additional costs to be incurred by the Company, resulting in a current cost estimate for the project in the range of USD 170-190 million. The increase from the previously announced cost estimate of USD 160-170 million is mainly a result of time related costs due to additional delays, in part as a result of the Company's challenging liquidity situation, as well as certain increased procurement costs for equipment and yard services. First oil is currently expected to take place during the second quarter of 2012. FPSO Sevan Voyageur is contracted to E.ON Ruhrgas UK E&P for the Huntington field in the UK North Sea. Estimated contract value is USD 535 million for the fixed term of five years. The contract has extension options.

The Board of Directors continues to hold constructive dialogue with bondholders and other relevant parties regarding a global restructuring of the Company's balance sheet.

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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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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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EOG 2Q Earnings Climb on Production Increase

- EOG 2Q Earnings Climb on Production Increase

Friday, August 05, 2011
EOG Resources Inc.

EOG Resources reported second quarter 2011 net income of $295.6 million, or $1.10 per share. This compares to second quarter 2010 net income of $59.9 million, or $0.24 per share.

Consistent with some analysts' practice of matching cash flow realizations to settlement months, and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the second quarter 2011 was $299.2 million, or $1.11 per share. Adjusted non-GAAP net income for the second quarter 2010 was $44.9 million, or $0.18 per share. The results for the second quarter 2011 included a $226.2 million, net of tax ($0.84 per share) impairment of certain non-core North American natural gas assets, gains on property dispositions, net of tax, of $105.2 million ($0.39 per share) and a previously disclosed non-cash net gain of $189.6 million ($121.4 million after tax, or $0.45 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $6.3 million ($4.0 million after tax, or $0.01 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

Operational Highlights

Total company production increased 13 percent in the first half of 2011 compared to the same period in 2010. Driven by a 60 percent rise in United States crude oil and condensate production during the second quarter, EOG delivered 46 percent total company crude oil, condensate and natural gas liquids production growth versus the second quarter 2010. Leading the crude oil production growth was the South Texas Eagle Ford followed by the Fort Worth Barnett Shale Combo. Also contributing to the increase were newer crude oil and liquids-rich plays such as the Colorado Niobrara, Oklahoma Marmaton, West Texas Wolfcamp and New Mexico Leonard.

"Demonstrating the depth and quality of our portfolio, EOG's crude oil and liquids-rich plays delivered strong, consistent second quarter production results, driving our overall first half 2011 production growth," said Mark G. Papa, Chairman and Chief Executive Officer. "Just as we had forecast, EOG's natural gas production is decreasing due to asset sales and the priority we have placed on developing our outstanding crude oil and liquids investment opportunities."

EOG is on track to achieve its targeted 9.5 percent total company organic production growth for 2011. Total company 2011 crude oil and condensate production is projected to increase by 52 percent, while total company crude oil, condensate and natural gas liquids production is forecast to rise 47 percent over 2010.

Crude Oil and Liquids Activity

Early in its transition to a liquids-focused company, EOG identified the rich oil potential of the South Texas Eagle Ford Shale and amassed a large acreage position in the sweet spot of the crude oil window.

"We are finding that well results across our 535,000 net acre position in the Eagle Ford oil window are remarkably similar. The wealth of drilling, completion and production data at our fingertips is reflected in the steadily rising momentum of our operations and success in achieving more predictable results," Papa said.

As EOG further defines geologic sub-trends and refines completion techniques, the majority of its Eagle Ford wells are being completed to sales at initial production rates in excess of 1,000 barrels of crude oil per day (Bopd). Leveraging this consistency, EOG ramped up its drilling activity from 10 rigs at the beginning of 2011 to its current intensive program of 22 rigs.

In Gonzales County where EOG is actively drilling, the King Fehner Unit #2H, #4H, #5H and #6H wells began initial production at maximum rates ranging from 1,238 to 1,487 Bopd with 1.2 to 1.6 million cubic feet per day (MMcfd) of rich natural gas.

"These are the first Eagle Ford wells that EOG has tested with a tighter spacing pattern. If downspacing proves economically viable, we have the potential to significantly increase our reserves in the Eagle Ford," Papa said.

EOG reported production rates from other successful wells in Gonzales County. The Merritt #4H had a peak initial production rate of 1,361 Bopd with 0.6 MMcfd of rich natural gas. The Steen Unit #1H, #2H, #4H and #6H came online with production rates ranging from 663 to 1,269 Bopd with 0.7 to 1.4 MMcfd of rich natural gas. In its far northeastern acreage where EOG announced success from a fault block earlier this year, the Hill Unit #1H and #3H were completed. They flowed to sales at peak rates of 1,461 and 1,734 Bopd with 1.0 and 1.3 MMcfd of rich natural gas, respectively.

In LaSalle County, the Naylor Jones A #2H, 99 #1H and 96 #1H provided additional confirmation of the consistent quality of EOG's 120-mile acreage trend. The wells, located in the southwestern part of EOG's block, had strong production rates ranging from 997 to 1,153 Bopd with 1.0 to 2.3 MMcfd of rich natural gas. In Karnes County, the heart of EOG's extensive acreage, the Max Unit #1H had a peak initial production rate of 1,591 Bopd with 1.5 MMcfd of rich natural gas. Also in Karnes County, the Braune Unit #1H was turned to sales at an initial rate of 1,611 Bopd with 1.0 MMcfd of rich natural gas. EOG has 100 percent working interest in all 16 of these Eagle Ford wells.

"With the 77 percent crude oil mix of our Eagle Ford acreage position, this large, highly rated resource play has become a significant contributor to fueling EOG's transition to an oil company in a short period of time," Papa said.

EOG announced positive drilling results from a new horizontal crude oil play, the Marmaton sandstone in the Oklahoma Panhandle. In Ellis County where EOG has drilled a series of wells, the Brown 18 #1VH and Opal 31 #1H were completed to sales at production rates of 620 and 1,312 Bopd with 0.7 and 2.6 MMcfd of natural gas, respectively. EOG has 58 and 49 percent working interest in the wells, respectively. EOG has 88 percent working interest in the Fischer 12 #1VH, which began initial production at 508 Bopd, with strong natural gas production. Encouraging well results provide the potential for additional development drilling locations on its 34,000 net acre position. To identify further exploration opportunities, EOG plans to acquire 3D seismic over this acreage.

EOG continues to post excellent drilling results from its 131,400 net acre position in the West Texas Wolfcamp and its 108,000 net acre position in the New Mexico Leonard Shale and Bone Spring Sands plays. The current moderate level of drilling activity is expected to ramp up in 2012 and beyond. Following refinements in completion techniques, recent well results show improvement in crude oil production flow rates.

Drilled and completed in the West Texas Wolfcamp, the University 40-A #0401H began flowing to sales at a maximum oil rate of 935 Bopd with 838 thousand cubic feet per day (Mcfd) of rich natural gas. EOG has 85 percent working interest in this Irion County well. Also in Irion County, the Linthicum M #1H and I #5H had production rates of 809 and 664 Bopd with 892 and 1,178 Mcfd of rich natural gas, respectively. EOG has 75 and 85 percent working interest in the wells, respectively. EOG has 100 percent working interest in the University 9 #2802H, drilled in Reagan County, northwest of its Irion County and Crockett County activity. The well had a peak production rate of 583 Bopd with 254 Mcfd of rich natural gas.

In Lea County, New Mexico where EOG is developing its Leonard Shale acreage, the Caballo 23 #1H was completed at a production rate of 665 Bopd with 1.2 MMcfd of rich natural gas. EOG has 86 percent working interest in the well. In Eddy County, the Elk Wallow 11 St. #4 had a maximum production rate of 735 Bopd with 2.0 MMcfd of rich natural gas. EOG has 75 percent working interest in this Leonard Shale well. Also in Eddy County, EOG drilled the Parkway 23 State #3H in the Bone Spring Sands, which is producing 511 Bopd with 726 Mcfd of natural gas. EOG holds 81 percent working interest in the well.

Since mid-2009, EOG's Denver-Julesburg Basin drilling activity has been concentrated on its 80,000 net acre Hereford Ranch Field in Weld County, Colorado. The Jake 2-01H discovery, which was drilled as a horizontal well targeting the Niobrara formation, began initial production in late 2009 at a first month average rate of 645 Bopd. Since the first quarter 2011, it has been producing at a relatively stable rate of 250 to 300 Bopd. Following the Jake well, the Elmer 8-31H, which was drilled in March 2010 with a short lateral, had an initial average 30-day production rate of 283 Bopd and is currently producing approximately 225 Bopd. Encouraging data from long-term stabilized crude oil production rates indicate that the Niobrara wells will be characterized by lower initial flow rates, but flatter decline curves than other crude oil resource plays.

Acreage outside EOG's Hereford Ranch Field was also proven productive during the quarter. Southeast of the Hereford Ranch Field, the Fiscus Mesa 9-10H was drilled and completed to sales at an initial controlled rate of 335 Bopd with 174 Mcfd of natural gas. EOG has 86 percent working interest in the well. West of the Fiscus Mesa well, EOG has 75 percent working interest in the Gravel Draw 9-09H that began production at an initial controlled rate of 277 Bopd with 146 Mcfd of natural gas. Based on long-term well production results from its Hereford Ranch Field and new drilling results and production data, EOG has established the economic potential for crude oil development on 169,000 of its 220,000 net acre Niobrara position.

In the Texas Fort Worth Barnett Combo, EOG's program in Montague County and western Cooke County continues to deliver successful production results with efficiency gains in both drilling and completion operations. In western Cooke County, the Gaedke A Unit #3H and #4H and B Unit #5H, #6H and #7H wells were brought to sales at rates ranging from 338 to 696 Bopd with 807 to 2,152 Mcfd of rich natural gas. EOG has 99 percent working interest in the wells. In Montague County, EOG has 100 percent working interest in the Stoddard A Unit #1H, B Unit #2H, C Unit #3H and D Unit #4H that came online at rates ranging from 777 to 918 Bopd with 1,262 to 2,677 Mcfd of rich natural gas. While EOG's efforts have focused on testing new completion techniques in the sweet spot of its core acreage, an inventory of several years of drilling locations has been identified in the play.

Despite weather challenges in the North Dakota Williston Basin over the last eight to nine months, EOG continued its drilling and production activities, as well as operating its proprietary crude-by-rail transportation system. Although EOG minimized the adverse impact of abnormally wet weather on production goals during the second quarter, completion operations were impacted and area flooding remains an issue.

Drilled with a 9,968 foot long-reach lateral, the Liberty LR #21-36H was completed to sales at a maximum rate of 1,201 Bopd with 1,147 Mcfd of natural gas. EOG has 95 percent working interest in the well. The Fertile #19-29H and #45-29H were both completed in the Bakken formation in Mountrail County. The wells, in which EOG has 38 and 75 percent working interest, respectively, came online at maximum rates of 1,008 and 1,223 Bopd, respectively. In Williams County, EOG has 67 percent working interest in the Hardscrabble 13-3526H, which began flowing to sales at 1,474 Bopd. EOG holds 85 percent working interest in the Clarks Creek 3-0805H, which was completed in the Three Forks formation in McKenzie County at a maximum production rate of 1,384 Bopd.

"EOG's early innovative crude-by-rail midstream investments in the Bakken and Eagle Ford have proven valuable in delivering our crude oil directly to major market hubs given the current lack of available pipeline capacity in these two prolific plays," Papa said. "Our Bakken crude oil rail transportation system was particularly beneficial during the recent North Dakota flooding because it enabled EOG to continue to make crude oil deliveries."

Natural Gas Activity

In North America, EOG's natural gas production decreased 1.6 percent in the second quarter compared to the same prior year period due to reduced drilling activity and natural gas asset sales. In the United States where EOG is employing drilling capital to maintain core leasehold positions, it posted strong operational results from its Marcellus Shale and Haynesville/Bossier Shale natural gas horizontal resource plays. In Canada, EOG's natural gas production decreased due to asset divestitures and the reallocation of capital toward liquids-rich reinvestment opportunities.

Capital Structure

During the second quarter, total cash proceeds from sales of acreage, producing natural gas properties and midstream assets were approximately $684 million. Through the first half of 2011, total cash proceeds from assets sales were $944 million. Based on negotiated purchase and sale agreements and other pending transactions, EOG anticipates property sales for the full year of approximately $1.6 billion, or $600 million higher than the original $1 billion target for 2011. Estimated exploration and production expenditures will range from $6.8 billion to $7.0 billion, including exploration, development and production facilities and midstream expenditures, an increase of approximately $400 million from EOG's previously stated targets.

At June 30, 2011, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 30 percent. Taking into account $1.6 billion of cash on the balance sheet at the end of the quarter, EOG's net debt was $3.6 billion for a net debt-to-total capitalization ratio of 23 percent. EOG is targeting a net debt-to-total capitalization ratio of 30 percent or less at both year-end 2011 and 2012. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

"Our well-timed efforts to recreate EOG as a high margin, crude oil-focused company are paying off," Papa said. "On the basis of both per share earnings and cash flow growth, EOG is positioned to be an industry leader for years to come."

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Oil Demand to Increase; Supply Less Certain -Study

- Oil Demand to Increase; Supply Less Certain -Study

Thursday, August 04, 2011
Ernst & Young LLP

Oil demand and prices should continue to rise in the third quarter of 2011 according to indicators, even with ongoing uncertainty with respect to the economic recovery, deficit reduction initiatives in the US and the debt crisis in Europe.

In the first quarter of this year, with expectations for continued economic improvement and as a result of the supply disruptions from the Middle East, oil prices rose to over $100/barrel. But after peaking in the second quarter, crude prices fell back slightly, in spite of the announced stock release by the International Energy Agency (IEA), as the economic recovery lost some steam.

Oil

The bright spot in the oil outlook is the increasing activity in the Gulf of Mexico since the oil spill last year, with the first new production out of the Gulf coming in the second quarter. While overall production remains below pre-2010 levels, the application and permitting process is substantially improved, and increasing production will create jobs and increase domestic energy supplies at a time of expected strong demand growth. Oil production elsewhere in the Americas continued to increase as well, notably from the Bakken formation in the Upper Midwest, as well as from the Canadian oil sands and Brazil.

The big unknowns for oil producers are the short-term effects of the IEA's release of 60 million barrels from emergency supplies and OPEC members' disagreement over supply increases. The IEA's release announcement brought prices down temporarily and is expected to fill the void of Libyan supplies. However, as the market moves into the high-demand season, the IEA release will not meet that increased demand, and the market will need more supply from OPEC at a time when its spare capacity is at its lowest level in more than 20 years. Beyond the short-term, over the next three to five years, pressures on OPEC to increase capacity and production are expected to increase substantially.

"Oil prices are dictated by supply and demand, and all signs point to modest oil demand growth and uncertain supply," said Marcela Donadio, Americas Oil and Gas Leader, Ernst & Young LLP. "Barring a strong economic shock, continued strong oil prices seem to be in order over the next three to five years."

Gas

US natural gas production continues to grow, with the latest production figures reaching the highest point in almost 40 years. Shale gas is driving the growth and is now approaching about 30% of US total gas production, even as gas-directed drilling has slowed and issues surrounding the economic feasibility and potential environmental impacts of the resource are raised.

"We maintain that natural gas is a sound solution to the nation's need for domestic, cleaner-burning fuel," said Donadio. "We have the resource in abundance and we know how to produce it safely. We need to put any questions around that to rest and focus on creating more opportunities to increase natural gas demand."

Oilfield services

Oilfield service activity is dictated by upstream spending. Spending is expected to continue to grow by about 15 to 20% in 2011, returning close to the peak 2008 levels. Service capacity is being strained by the unconventionals boom. Cost increases and staffing shortages are appearing. This resurgence of the oilfield service segment is being driven by fit-for-purposes technology such as rotary steerable rigs and directional/horizontal drilling; strong oil prices; and the efficient application of shale gas technologies including multi-stage fracking and horizontal drilling.

Transactions

The second quarter was another fairly strong quarter for oil and gas transaction activity, marking seven consecutive quarters of deal growth. Deal activity in Americas continues to dominate the global transactions landscape.

Looking into the second half of year, transaction activity should stay fairly strong, boosted by the expected continued high oil prices and the ever-high geopolitical risk, tempered only by the still reasonably high levels of economic uncertainty, particularly in the US and Europe.

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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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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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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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Far East Energy Notes 66% Increase in Shouyang Block

- Far East Energy Notes 66% Increase in Shouyang Block

Friday, July 22, 2011
Far East Energy Corp.

Far East Energy announced the results of an independent report prepared by Netherland, Sewell & Associates, Inc. ("NSAI") evaluating, as of June 30, 2011, the net contingent gas resources and Net Present Value at 10% Discount ("NPV10") of the net contingent cash flow for the three target coal seams in Far East Energy's 485,000 acre (1960 square kilometers) Shouyang Block, situated in Shanxi Province, China.

The report, which is subject to certain limitations and assumptions described therein, gives a Best Estimate of NPV10 of $1.23 billion, which reflects a 66% increase over the previously prepared NSAI report as of December 2010; a High Estimate of $2.11 billion, which reflects a 44% increase; and a Low Estimate of $319.30 million, which reflects a 143% increase.

"Obviously, this is an exhilarating report. It reflects the great potential of the Shouyang Block project," said Michael R. McElwrath, CEO and President of Far East. "These estimates not only reinforce the belief we have had in this project since the beginning, but it also better defines the economic potential of the Shouyang Block. As you may recall when we released the December 2010 NSAI report we stated that it was our hope and belief that the numbers then reported by NSAI, were just the beginning indicators of the Shouyang Block's vast resource potential. Now, with the receipt of the latest NSAI report, a mere six months later, this is being borne out. As the Company continues its development of the Shouyang Block project, with operations now under the oversight of David Minor, Executive Director of Operations, we believe we are well positioned to enter the next development phase and expect to see increased well-by-well gas rates coupled with sustainability."

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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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