Endeavour International posted 6.6% decline in O&G Production for Q1-2011; Poised for Significant Production Growth in the UK and the US

Endeavour is an independent oil and gas company and has operations in the North Sea and the United States. In May, 2009, the company completed the sale of its Norwegian subsidiary for US$150 million, and those proceeds combined with current cash flow will fund future growth initiatives. Endeavour is currently developing three field discoveries in the United Kingdom sector of the North Sea that will serve as the foundation for production growth over the next two years.

Source: Derrick Petroleum E&P Transactions Database

The company’s first quarter 2011 production was 3,001 boepd, down 6.6% over the same quarter last year. Though the company was not performed for the quarter, the pieces are in place for significant production growth and lower operating costs in the near future; the Bacchus UK oil development is moving forward and appears to be on schedule to start production in Q2-2011, with production expected to ramp-up to 4,000–5,000 bpd net to the company's interest. This more than doubles the company's current production rate. Meanwhile, the company continues to push forward many of its smaller, shorter cycle-time projects.

Source: Endeavour International

Poised for Significant Production Growth in the UK and US

Rapid Growth Expected Over Next Three Years:

Endeavour expanded into the US in 2010 with the purchase of lower-cost, shorter cycle time conventional and unconventional onshore reserves. As it brings its balanced portfolio of oil and gas properties on to full production, management expects to organically double annual production in each of the next three years.  END believes that its existing total reserves can produce 30,000 to 40,000 BOEPD by 2015. During 2011, capital expenditures of about $150 million will target its two key initiatives in the U.K. North Sea – Bacchus and Greater Rochelle and the remainder will be directed toward the Haynesville and Marcellus areas in the U.S. to bring on production.

Source: Derrick Petroleum E&P Transactions Database

Bringing North Sea Assets On-Line

In the Central North Sea, Endeavour has three primary development projects – Bacchus, Columbus and the Greater Rochelle area, which have the potential to significantly expand its production levels and total proved reserves over the next three years. The Company recently increased its working interested in Bacchus from 10% to 30%, giving it an even greater position in this near-term proven oil play.

Source: Derrick Petroleum E&P Transactions Database

Operating the Greater Rochelle Development toward First Production

 In February 2011, the company received final approval of its Field Development Plan for East Rochelle from the Department of Energy and Climate Change (DECC). This is an important next step in moving the field toward first production in late 2012. In the fall of 2010, END also achieved commercial drilling success at West Rochelle confirming a second excellent quality reservoir.

Significant Reserve Growth Driven by the Drill Bit

During 2010, Endeavour grew its 2P oil and gas reserves by 12.3% to 43.7 MMBOE from 38.9 MMBOE, representing a 419% replacement of 2010 production. Production volumes averaged about 4,100 BOEPD during the year. END expects to generate significant production growth from its definable projects in the second half of 2011, with an opportunity to double its production flow rates in each of the next three years from its existing assets.

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Cenovus posted 14% production growth in Foster Creek & Christina Lake for Q1 2011; Plans to invest $1.7 billion - $1.9 billion for the rest of 2011

Cenovus was formed on 2009 from the split of Encana Corporation into two independent publicly traded energy companies: one an integrated oil company (Cenovus), the other a natural gas company (Encana). The company had operations in Athabasca region of Northern Alberta and southern Saskatchewan.

Source: Derrick Petroleum E&P Transactions Database

Cenovus posted increase in oil sands results for the first quarter 2011. The company’s quarterly production was 137,355 boepd, up 5% from the same period last year. Cenovus’s oil sands segment (66,828 bpd) posted 14% production increase over Q1 2010 (58,546 bpd). However the company’s natural gas production was 652 MMcfpd for Q1 2011, down 16% over Q1 2010. The Company’s strategy is to focus on the development of its substantial crude oil resource in Alberta and Saskatchewan. Cenovus is looking primarily in developing the land position in the Athabasca region in northeast Alberta.

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Cenovus reportable E&P segments include Oil Sands and Conventional. Oil Sands, which consists of Cenovus’s producing bitumen assets at Foster Creek and Christina Lake, heavy oil assets at Pelican Lake, new resource play assets such as Narrows Lake, Grand Rapids and Telephone Lake, and the Athabasca natural gas assets. Conventional, which include development and production of conventional crude oil, natural gas and NGLs in Alberta and Saskatchewan.

Expansion phases C and D at Christina Lake continuing to progress on target with expected first production at phase C in the third quarter of 2011 and at phase D in early 2013; and Additional progress on the CORE project at Wood River with coker start up expected in the fourth quarter of 2011.

Cenovus Plans to invest $1.7 billion - $1.9 billion for the rest of 2011

Oil Sands capital investment for Q12011 was primarily focused on facility spending at both Foster Creek and Christina Lake related to the next phases of expansion. The company drilled 440 gross stratigraphic wells during the quarter. Conventional capital investment in the quarter was focused on the continued development of conventional oil properties.

In Feb 2011, Cenovus announced for a venturing partner to develop oil sands holding and boost the value of reserves. The company will get $3 billion, assuming 50-50 JV. On a gross basis, about 260 of the assessment wells were drilled at the company’s oil sands properties in 2010 and an additional 450 strat wells are expected to be completed in 2011. In addition, Cenovus has identified 10 other oilsands projects - Narrows Lake, Grand Rapids in the Greater Pelican region and Telephone Lake project in the Borealis region for future development.

Source: Derrick Petroleum E&P Transactions Database

Canadian Natural Resources posted 2.4% increase in Natural Gas Production for Q1 2011; Provides Development Plan for the rest of 2011

Canadian Natural Resources, which operates in North America, North Sea and Offshore West Africa, reported its Q1 2011 results. Natural gas production for the quarter averaged 1,256 MMcfpd, up 2% from same quarter last year. This is primarily due to new production volumes from the Septimus facility in Northeast British Columbia and from natural gas producing properties acquired during 2010.

North America :

Crude oil and NGLs production in North America was 290,130 boepd for Q1 2011, up 15% from Q1 2010 of 252,450 boepd. This is due to increase in light and medium crude oil and NGLs, Pelican Lake heavy crude oil and primary heavy crude oil offset by a decrease in bitumen (thermal oil) volumes as a result of the timing of steaming cycles.

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International operations:

International operations include North Sea and Offshore Africa.

North Sea:

North Sea production was 34,101 boepd during the quarter, down 8% from Q1 2010 as a result of natural declines. The UK government’s implementation of tax increases in the North Sea resulted in a 24% reduction in the UK. Consequently, Canadian Natural plans to cancel drilling activities in Murchison and accelerate its plans to commence decommissioning of the Murchison platform. The Company will continue to high grade all North Sea prospects for potential future development opportunities. In Q1 2011 the North Sea represented 6% of total Company production.

Offshore Africa

Crude oil production at Offshore Africa was 25,488 boepd for the quarter, a decrease of 15% from Q1/10 as a result of natural declines. Subsequent to quarter end, production at the Olowi Field has been temporarily suspended as a result of a failure of its mid water arch, a support buoy which provides support for production and gas lift flowlines and the main power line.  Current activities are being monitored and a full evaluation is being completed.  As a result, the high end of the production guidance for Offshore Africa has been reduced by 2,000 boepd for 2011.

2011 Development Plan:

The Company forecasts 2011 production levels before royalties to average between 1,203 and 1,270 MMcfpd of natural gas and between 381,000 and 421,000 boepd of crude oil and NGLs. Q2 2011 production guidance before royalties is forecast to average between 1,219 and 1,244 MMcfpd of natural gas and between 345,000 and 375,000 boepd of crude oil and NGLs.

- The natural gas capital expenditure budget for 2011 has been increased by $150 million to reflect increased drilling in the Company’s liquids rich unconventional natural gas plays at Septimus, Edson and Wild Hay and increased related infrastructure projects to reduce operating costs, increase liquids yields and maximize facility utilization.

- The Company targets to drill 827 net primary heavy crude oil wells in 2011 which will drive a targeted 13% production growth in primary heavy crude oil.

- Continue to implement strategies at Pelican Lake to increase production levels from this world class oil pool.

- At Kirby, construction of the 40,000 boepd targeted peak production facility is underway

Construction of the third Ore Preparation Plant looks to be slightly ahead of schedule, which will translate into higher reliability levels upon recommencement of operations.

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Repsol’s Q1 2011 Production down 7.4% over the same period last year; Unrest in Libya and Maintenance work in the Caribbean are the key factors!

Repsol posted O&G production of 324,348 boepd, down 7.4% over Q1 2010 production of 350,000 boepd. This is mainly due to conflicts in Libya, moratorium in GoM production and maintenance turnarounds in Trinidad & Tobago. However, these factors were partially offset by higher output from Peru, driven by demand and the LNG plant, and by the new contract that came into force in Ecuador.

In Libya, Repsol produced 27,000 boepd for Q1 2011, over 43,000 boepd in Q1 2010. Production is completely interrupted from March 2011. Second, the negative impact of production moratorium in GoM. Repsol face a drop of 8,000 boepd versus Q1 2010. Third, maintenance turnarounds in Trinidad & Tobago meant that production was 11,000 barrels per day lower than last year.

Exploration Activities in the Quarter:

Repsol invested €302 million (US$ 426 million) in first quarter 2011. Of this, €252 million (US$ 355.6 million) were spent in Exploration and Production and 85% of this sum was in development projects.

The company currently drilling five exploratory wells; two in the Brazilian Santos 44 block, Itaborai and Tingua; one in Campos 33 block, Gavea; one in Bolivia, Sararenda; and one in the US onshore, Garden Island Bay 1. The company is forging ahead with the appraisal well drilling campaign in Peru with Kinteroni 3 and in Venezuela with Perla 5.

Repsol recently farm-in into 164 blocks at Alaska prolific North Slope. The blocks are close to existing producing fields and cover an area of 2,000 square kilometers.

Source: Derrick Petroleum Planned Exploration Wells Database

PARTIAL DIVESTMENT of YPF:

After the sale of a total 4.2% stake of YPF during the last quarter of 2010, Repsol in March carried out a public offering for 7.7% of that company’s stock and other sales totaling 3.83% of YPF.

In May 2011, Grupo Petersen informed Repsol of its decision to exercise its option to buy 10% of the capital of YPF almost a year in advance of the option’s February 2012 expiration.

Source: Derrick Petroleum E&P Transactions Database
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BG’s Q1 2011 E&P Production hit by civil unrest in North Africa, flooding in Australia, and shutdowns in the North Sea; Will BG ramp up to achieve the Group’s long-term rate of 6-8% to 2020?

Natural Gas giant, BG has challenging first quarter for O&G operations. The group’s production for the period was down 5% from 61.3 mmboe to 58.2 mmboe over the same period last year. This is due to unrest in North Africa, flooding in Australia, an increase in UK tax and a shutdown in the North Sea. The North Sea's effect on the company was exacerbated by the temporary shutdown, largely for maintenance, of the Everest and Lomond platforms. This contributed to a 5% fall in production volumes. In Tunisia, the restart of the Hasdrubal plant was delayed, and in Egypt there was significant disruption to normal patterns of gas demand. In addition, production volumes in the quarter were affected by extreme weather conditions and extensive flooding in Queensland, Australia. However, BG pointed to advances in Brazil and the signing of two sales agreements in Japan as reasons to be optimistic.

BG’s Performance in 2010 compared to Peer Groups:




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HIGHLIGHTS of the Quarter:

Brazil

Production at the first permanent module on Lula Sul increased to some 25 000 boepd, and construction of the next two FPSO modules advanced to around 50% complete, in line with plans.

In April 2011, conclusion of a Drill Stem Test (DST) on the Guará Norte well (3-SPS-69) in Block BM-S-9 in the Santos Basin was done. The DST confirmed high productivity of some 6 000 bopd of light oil (approx 30° API) with flow rates constrained by test facility capacity.

In March 2011, successful completion of drilling on the Iara Horst well in the BM-S-11 concession in the Santos Basin. The well encountered good quality oil (28° API) in a thick reservoir section. Further evaluation activity continues.

In February 2011, a new discovery of oil (approximately 26° API) in Block BM-S-10 in the Santos Basin. The discovery well, known as Macunaíma, is located in a water depth of 2,134m, approximately 244 kms off the coast of Rio de Janeiro state. Further evaluation of the discovery continues.

USA

BG Group's shale gas operations continued to gather momentum, with 46 wells spudded and 22 drilling rigs operating in the Haynesville shale during the quarter. Seven wells were drilled in the Marcellus shale.

Tanzania

In April 2011, the company announced its third Tanzanian gas discovery. The Chaza-1 well is located in Block 1 approximately 18 kms offshore southern Tanzania in a water depth of around 950m. It is intended that a second drilling campaign will commence in late 2011.

Kenya

In March 2011, the company signed a Heads of Agreement with the Kenyan government to acquire a 40% equity interest in the exploration block L10A and a 45% interest in block L10B, subject to negotiation of Production Sharing Contracts. BG Group would operate both blocks.

India

In April 2011, a consortium led by BG Group (50% and operator), was identified as the qualifying bidder for an exploration block (MB-DWN-2010/1) offshore the west coast of India. The block is approximately 350 kms from the coast, covering an area of 7,963 sq kms and in water depths in excess of 2,000m. The award of the contract will be subject to final confirmation from the government of India and regulatory approvals.

Norway

In the 21st licensing round held in April, the Norwegian government awarded BG Group a 40% interest in and operatorship of licence PL599, located in the Norwegian Sea.

"We now expect modest production growth in 2011. The plans for a ramp-up in production in 2012 and 2013, as well as our 2020 goals, are unaffected and are supported by significant progress with our growth projects in Brazil, the US and Australia, as well as further exploration and appraisal success in Brazil and Tanzania.", Mr. Chapman,  BG Group’s Chief Executive added.

BG's Strategic Acquisitions in 2010 and 2011

Source: Derrick E&P Transactions Database

Suncor Energy posts 6.5% Increase in Production for Q1 2011; Capital Spending was primarily on Expansion of In Situ Oil Sands Operations; Production In Line with company’s target of one million boepd by 2020

Suncor Energy’s upstream production in first quarter 2011 was 601,300 boepd, up 6.5% over same period last year. Suncor’s Q1 2011 production averaged 601,300 boepd, compared to 564,600 boepd during the first quarter of 2010.  Oil sands production was 322,100 boepd, 59% increase from the first quarter of 2010. Suncor, which is expanding its oil sands production and processing operations as part of a joint venture with Total, said it had seen higher oil sands production volumes and higher realized prices in upstream operations.

In March 2011, the company completed sale of non-core North Sea assets for proceeds of £105 million (US$ 170.44 million), subject to closing adjustments. The company secured two operated exploration licenses and one non-operated exploration license in the Norway portion of the North Sea in April 2011. In addition, the company is evaluating an exploratory well in the Ballicatters field offshore East Coast Canada.

Source: Derrick Planned Exploration Wells Database


Targeting One Million Boepd by 2020

Suncor continues to move forward on its ten-year growth strategy outlined in December 2010. In support of the growth strategy, capital spending in the first quarter was primarily focused on expansion of the company's in situ oil sands operations. In April 2011, Suncor began injecting steam into a Stage 3 well pad and expects to achieve first oil by early July 2011. The expansion is expected to be fully operational in the third quarter of 2011, with production volumes ramping up over approximately 24 months thereafter toward target capacity of 62,500 boepd of bitumen.

With the closing of its strategic partnership agreements with Total E&P Canada Ltd. on March 22, 2011, Suncor expects to progress with engineering and site preparation work for the Fort Hills oil sands mining project and the Voyageur Upgrader. Under the terms of the agreements, Total assumed an interest in both Fort Hills and the Voyageur Upgrader, while Suncor assumed an interest in Total's Joslyn oil sands mining project. Suncor is targeting the completion of the Voyageur Upgrader and the Fort Hills project for 2016.

Source: Derrick E&P Transactions Database

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Range Resources Q1 output up on Marcellus Shale drilling; Targeting Marcellus to be self-funding 2013 and capture full resource potential

Natural gas company, Range Resources Corp reports increase in its Q1 2011 production as the company focused on drilling the liquids-rich portion of the Marcellus Shale play in Pennsylvania and the Midcontinent regions. The company's production volumes up 17% to 545.5 mmcfepd, and they are on track to produce 400 mmcfe by the end of 2011. Range says by the end of 2012 they will be producing 600 mmcfe. Due to the outstanding performance of its existing wells combined with the initial performance of the newly connected wells, Range's Marcellus production has temporarily outgrown the existing infrastructure.

Range Expects the Marcellus Division to be a Value Driver for the Future
The Marcellus now appears to be the second or third largest natural gas play ever discovered in the world.  With the benefit of a large, liquids-rich window in southwestern Pennsylvania, the Marcellus offers the best economics of any large-scale, repeatable play in the US.  A significant portion of Range's acreage also offers the benefit of natural gas potential from the Upper Devonian and Utica shale formations that lie above and below the Marcellus.  In 2011, Range is directing 86% of its capital budget toward development drilling in the region.

Range has ~550,000 net acres in the SW part of the play. Over 800 wells have significantly de-risked 460,000 of Range’s acres. Assuming 80 acre spacing, and that 80% of this acreage will be drilled, this equates to 4,600 wells. The resource potential is for the Marcellus and does not include any potential from other shale zones. Utica and Upper Devonian shale wells have been completed and are currently waiting on pipeline connection.

Range is giving up 113 mcfe a day of natural gas production capacity with its 52,000 acre Barnett Shale sale. The $900 million Range gets for Barnett, coupled with cash flow and another $200-250 million in expected non-core asset sales this year, not only funds 2011 Marcellus development but also carries $400 million forward for 2012 development. Couple in 2011 and 2012’s development and production growth and Range expects 2013’s capex will be funded solely from its own cash flow.

Key Marcellus Deals in 2010 and 2011

Source: Derrick Petroleum E&P Transactions Database
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Noreco reports first quarter 2011 results

Norwegian Energy Company ASA (Noreco) presents its first quarter 2011 results, with EBITDA of NOK 97 million and a negative net result of NOK 295 million.

Q1 exploration activity
• Svaneøgle exploration well – non-commercial oil discovery
• Ronaldo exploration well – dry 
• Awarded two licenses in 21st NCS licensing round
• Planning for next Noreco operated well – Luna in Denmark

See more from: http://hugin.info/138447/R/1512654/448318.pdf

See more presentations from NORECO: http://docsearch.derrickpetroleum.com/research/q/noreco.html

Marathon Oil reported 11% Growth in Sales Volume Over the Same Period Last Year; Continues its Strategy of Focusing on Unconventional, Liquids-Rich Resource Plays

Marathon reported Q1 2011 sales volumes averaged 400,000 boepd, up 11% over the same period in 2010. This was primarily the result of increased liquid hydrocarbon volumes from the Droshky development in the GoM, which commenced production in mid-2010, and Norway, partially offset by the impact of the suspension of Libyan production. Natural gas sales from Equatorial Guinea were higher in Q1 2011 due to a first quarter 2010 planned turnaround at Marathon's production facilities.


Marathon’s production in Libya is currently suspended as a result of continued political and civil unrest. Marathon had expected to produce approximately 48,000 boepd from the Waha Concession during 2011. In the first quarter of 2011, production available for sale from Libya averaged 28,000 boepd, of which approximately 21,000 boepd was sold. On a cumulative basis, the underlift for Libya at the end of the first quarter was approximately 847,000 boe.

Marathon estimates Q2 2011 production available for sale is projected between 340,000 and 360,000 boepd, excluding the effect of any future acquisitions or dispositions. Anticipated full-year E&P production available for sale is between 345,000 and 365,000 boepd.

Unconventional, Liquid-rich Resource Plays

Source: Derrick Petroleum E&P Transactions Database

During the quarter, Marathon spud its first well targeting the Eagle Ford Shale formation in south Texas. As the Company continues its strategy of focusing on unconventional, liquids-rich resource plays, Marathon has increased its holdings in the Eagle Ford Shale to approximately 29,000 acres, with the rights to acquire an additional 61,000 acres. The Company also has reached agreements on approximately 30,000 additional acres and expects to close those transactions in the second quarter.

 In early April 2011, Marathon signed an agreement to assign a 30 percent undivided working interest in the Company's approximately 180,000 net acres in the Niobrara Shale play. The company is currently acquiring 2-D and 3-D seismic data and expects to participate in eight to 12 gross wells by year end.

Source:Derrick Petroleum E&P Transactions Database
Exploration expenses were $230 million for the first quarter of 2011, compared to $98 million in the first quarter of 2010. Included in exploration expenses for the first quarter of 2011 were dry well expenses of approximately $159 million, primarily related to the Flying Dutchman well located in the Gulf of Mexico and the Romeo well in the Pasangkayu block offshore Indonesia. In March 2011, Marathon completed an evaluation and determined the options to develop Flying Dutchman were not viable. For Romeo, the reservoir's thickness and quality confirmed pre-drill geologic models, but the well was determined to be dry.

Source: Derrick Petroleum Planned Exploration Wells Database

South Western Energy 2011 May Latest Investor Presentation

First Quarter 2011 Highlights:
Production of 115.0 Bcfe, up 28% -  2011 production guidance raised to 483 – 491 Bcf - Acreage in New Ventures outside of New Brunswick at  +620,000 net acres, up 27%
http://docsearch.derrickpetroleum.com/files/12319/SWN%202011%20May%20Latest%20Investor%20Presentation.pdf

Occidental’s Q1 2011 Production Results beat Quarterly Guidance numbers; Announced Second Quarter Operational Guidance

Occidental Petroleum reported Q1 2011 results, daily oil and gas production volumes averaged 730,000 boepd, up 4% over Q1 2010 production of 701,000 boepd. This is primarily due to domestic gas and NGL production and Middle East/North Africa. The domestic gas increase was from the new acquisition in South Texas, which closed in the first quarter of 2011. The Middle East/North Africa increase included new production from Iraq and higher volumes from the Mukhaizna field in Oman.

The company’s sales volume (728,000 boepd), which is higher than initial guidance of 725,000 boepd differ from production volumes due to the timings of liftings principally caused by Iraq where liftings are expected later half of 2011. The company’s Iraq production was lower by about 9,000 boepd due to less than planned spending levels as we are in the startup phases of operations. Inclement weather, mainly in Texas, caused an additional reduction of about 7,000 boepd.

These reductions were offset by less-than-expected production loss from the Elk Hills maintenance shutdown and operational enhancements, providing higher-than-expected production in Colombia, Yemen and Qatar as well as the new assets resulting in production of 730,000 boepd.

The production guidance we gave you in last quarter's conference call of 740,000 to 750,000 BOE a day was at an $85 average price assumption. The actual first-quarter oil price reduced our production volumes by about 10,000 BOE per day including 1000 BOE a day at THUMS and Long Beach in California.

Second Quarter 2011 Outlook

Expected 2Q 2011 exploration expense to be about $85 mm for seismic and drilling operations.

Domestic volumes are expected to increase to about 425 mboepd,  compared with 1Q 2011 production of 404 mboepd

During 2Q11, the company will make a payment of about $500 million in connection with the signing of the Shah Field Development Project

Source: Derrick Petroleum E&P Transactions Database

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Anadarko reported 15-percent quarter-over-quarter increase in daily liquids volumes; On-track with the company’s five-year target of growing sales volumes at a CAGR of 7%- 9%!!

During Q1 2011, Anadarko reported sales volumes totaled 62 mmboe, or 690,000 boepd, averaging approximately 2.4 billion cubic feet of natural gas per day, 212,000 barrels of oil per day, and 76,000 barrels of natural gas liquids per day. This record performance was highlighted by the rapid growth of shale plays and first lifting from the Jubilee field offshore Ghana. Recently, the company closed the $1.6 billion Eagle Ford JV with KNOC.

Source: Derrick Petroleum E&P Transactions Database

Operations Report:

In the company’s shale plays, average sales volumes in the Eagleford and Marcellus areas increased by about 30 percent and 82 percent, respectively, over the fourth quarter of 2010. Production also continued to ramp up at the Jubilee mega project offshore Ghana, which at the end of the 1^st quarter, was producing almost 70,000 boepd gross from five wells.

At the Caesar/Tonga development in the Gulf of Mexico, Anadarko successfully completed and tested two wells at more than 15,000 BOPD and initiated completion activities on the third well. In addition, the development team is simultaneously progressing two riser solutions with first oil expected in 2012.

In Algeria, the El Merk mega project is progressing and is approximately 75% complete and remains on schedule for full facility completion around year-end 2012.


Exploration Report:

Source: Derrick Petroleum Planned Exploration Wells Database

Anadarko announced three deepwater discoveries during the first quarter of 2011. The Teak-1 and Teak-2 discoveries, located in the West Cape Three Points Block offshore Ghana, encountered high-quality oil, condensate and natural gas. In Mozambique, the company announced the Tubarão discovery, marking its fourth operated natural gas discovery in the Offshore Area 1 of the Rovuma Basin. 

In the Deepwater Tano Block offshore Ghana, the company and its partners announced successful appraisal wells at Enyenra-2A, Tweneboa-3 and Tweneboa-3ST. Subsequent to quarter end, the operator also announced the successful Tweneboa-4 appraisal well. Additional appraisal activity is ongoing in the Tweneboa/Enyenra complex as the partnership continues to work toward a declaration of commerciality, which is expected later this year.
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Conocophillips - 1st Quarter 2011 Conference Call

$1.82 adjusted EPS - 1.7 MMBOED production - 89% refining utilization - $4 billion cash from operations excluding working captial
http://docsearch.derrickpetroleum.com/files/12146/Conocophillips%20-%201st%20Quarter%202011%20Conference%20Call.pdf

Helix - First Quarter 2011 Presentation

First quarter average production rate of 160 Mmcfe/d (63% oil) - Q2 production through April 22 averaged approximately 140 Mmcfe/d (~67% oil) - Phoenix production averaged 10.3 MBoe/d for the same period  - Little Burn on track for first production in July (est. 4,500 bpd net)

http://docsearch.derrickpetroleum.com/files/12128/Helix%20-%20First%20Quarter%202011%20Presentation.pdf

Adverse weather conditions affected Santos Q1 2011 Operational results; Revised 2011 Production Guidance to 47-50 mmboe

Santos reports oil and natural gas production of 11 mmboe for first quarter 2011, down 11% than the corresponding period. This is due to adverse weather in Central and Western Australia. Due to this, Santos revised production guidance for the year 2011 from 48-52 mmboe to 47-50 mmboe.

Operational update during the Quarter:

GLNG 

Sales gas production of 2.4 PJ (412.65 kboe)was 50% lower than Q1 2010 due to Santos’ interest in GLNG reducing from 60% in Q1 2010 to 30% in Q1 2011 following the sale of interests in the project to Total and KOGAS.

Carnarvon Basin

Gas production from the John Brookes field of 10.3 PJ (1771 kboe) was 17% lower than Q1 2010 due to cyclone activity and lower customer nominations. Mutineer-Exeter production of 0.05 mmbbl was 67% lower than the previous quarter due to unplanned FPSO repairs in January and February 2011. Stag production of 0.35 mmbbl was 46% higher when compared to Q4 2010 due to the completion of two new development wells following a drilling campaign during Q4 2010.

Bayu-Undan / Darwin LNG

Gross Bayu-Undan gas production of 50.9 PJ (8,752 kboe) was 16% higher than Q1 2010.  Santos’ net entitlement production of 3.7 PJ (636 kboe)was marginally higher than Q1 2010.

Indonesia

Indonesia sales gas production of 10 PJ (1,719 kboe) was 3% higher than Q1 2010 due to temporary high gas demand from Maleo. Crude oil production of 0.11 mmbbl, down 8% lower over  Q4 2010 mainly due to Oyong oil field natural decline.

Key Exploration Activities:

Source: Derrick Petroleum Planned Exploration Wells Database

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