Chevron plans on investing $26 billion in 2011, with 87 percent of that amount expected to fund upstream activities

Chevron Corp, the second-largest U.S. oil company plans to take a measured approach to shale gas development despite a flurry of deals in the past year and the industry's huge ambitions for the emerging resource.

View Chevron’s major projects startups:

"You're not going to see Chevron -- I can't speak for others -- just shift the whole business into shale, and let other things go," Bobby Ryan, Chevron's vice president for global exploration, said at the Reuters Global Energy and Climate Summit in Houston on Wednesday. Ryan reiterated that Chevron's focus areas remained the Gulf of Mexico, West Africa and Western Australia, which were all part of a "balanced portfolio" approach to exploration.

Like Exxon and others, Chevron is exploring shale acreage in Eastern Europe, and will drill its first well in Poland this year. In the U.S. Gulf, Chevron recently got clearance for a few wells already under development, and its program includes 10 development and exploration plans and 15 drilling permit applications in various stages of approval or preparation.

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Chevron is set to drill 16 development wells and two exploratory wells at Jalalabad, Moulvibazar and Bibiyana gas fields in Bangladesh for the next one year. According to Petrobangla, Chevron submitted a US$ 350 million capital budget to carry out the plan. "To conduct the drilling operations we need one year as we have to construct concrete drilling pit, mobilize drilling rig and associated equipment, management and treatment of waste and decommissioning of rig and materials", Chevron official said.

Chevron has added 14 million acres to its portfolio, including the acquisition of Atlas Energy in the northeast United States, and deepwater opportunities in Liberia and China. Chevron’s queue of major capital projects, including Gorgon and Wheatstone in Australia. Over the next three years, 25 projects with a Chevron share of more than $250 million each are scheduled to start production, nine of which have a net Chevron share that exceeds $1 billion. Chevron has four major capital projects planned to start up in 2011.

Additionally, over the next three years, the company expects to make final investment decisions on 13 more projects, each with a Chevron share in excess of $1 billion. Construction on the Gorgon project is nearly 25 percent complete, with startup expected in 2014, and Chevron remains on schedule to reach a final investment decision this year on the Wheatstone project, with startup planned for 2016.

Chevron CEO, John Watson told, “Disruption fears are pushing up oil prices and chevron has $26 billion in capital expenditures slated for this year. When it comes to acquisition, it's all about the right opportunity. We are spending almost 90% of our capital dollars on the upstring, exploring and producing oil and gas, where we'll emphasize our growth and we have growth to add over the next five to seven years.”

Check this Video - Chevron CEO John Watson discusses 2011 Capital Expenditure Plan with CNBC:

Husky Energy raises $1.2B to fund growth plans; Expects 3 -5% CAGR Production Increase through 2021

Husky Energy Inc, Canada’s No. 3 integrated oil company, said it will raise $1.2-billion though public and private share offerings in order to finance its production growth plans. Husky, said it will sell 36.9 million common shares priced at $27.05 each, to a group of underwriters led by RBC Capital Markets, Goldman Sachs Canada, HSBC Securities (Canada) and J.P. Morgan Securities. The bought deal is expected to raise about $1-billion.

Husky announced a 2011 capital budget of CAD 4.9 billion (US$ 5.02 billion), a 23% increase from 2010. Excluding the acquisition, the bulk of the spending increases will go toward the Sunrise project and Southeast Asia, with reductions in midstream and downstream spending. With the larger capital budget and contributions from the recent acquisitions, Husky expects 2011 total production growth to be slightly above 4%.

Most of the gains will come from an increase in natural gas production of 14%, while expected 5% growth in heavy oil and bitumen volumes should offset a 3% decline in light and medium crude production. To supplement the funding of the capital plan, Husky also announced plans for a CAD 1 billion (US$ 1.02 billion) equity issuance. Current shareholders will have the option of receiving dividend payments in shares instead of cash.

The retention of the Southeast Asian assets is probably a positive step, given the outlook for increased gas demand in the region and the potential for exploration success. Also, moving forward with Sunrise should provide significant growth in oil volumes. However, while the company plans to achieve its previous production growth target of 3%-5% per year, short-term gains rely largely on natural gas acquisitions.

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The move toward natural gas stands in contrast to Husky's peers, which are shifting investment toward oil projects and away from natural gas. Also, the company's natural gas production is coming from Western Canada, a region that falls higher on the cost curve and faces intense competition from U.S. shale plays. As a result, returns may be challenged despite the growth in production.

Husky said the cash will go to boost exploration and development of its properties in Western Canada’s oil sands, offshore Newfoundland and Southeast Asia. It also said that, with the additional capital, it expects production to grow at the high end of its 3-5% annual target though 2015.

Husky Energy’s Exploration Portfolio:

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Source Documents:
Corporate Overview June 2011

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Statoil Eyes $32 Billion Investment over the next two years; Plans to increase production to above 2.5 mmboepd over the next 10 years

Norwegian oil giant Statoil ASA will spend $32 billion on exploration and production over the next two years as it aims to ramp up production to above 2.5 mmboepd over the next decade. Statoil, which produces about 80 percent of Norway’s oil and gas, is expanding abroad to maintain output and boost reserves amid dwindling production from aging North Sea fields. The company plans to double oil output in Brazil in less than a decade, and is seeking to add to its portfolio.

In addition to continued focus on production from operations on the Norwegian Continental Shelf (NCF), Statoil said the increased output will come through strengthened positions in the Gulf of Mexico, Brazil, Angola, the Caspian region and Arctic Sea, while also stepping up production of shale gas and liquids. "The NCF remains a very attractive and globally competitive province for future oil and gas activities," said, Statoil Chief Executive, Helge Lund.

As well as conventional oil and gas operations, Statoil is developing the Eagle Ford shale field in southwestern Texas through a joint venture with Talisman Energy Inc. and the Marcellus shale region together with Chesapeake, which includes northern West Virginia across Pennsylvania and parts of New York.

View the Eagle Ford Shale deal snapshot here:

Source: The Derrick E&P Transactions Database
Growing Market:
Statoil will “benefit from our strong gas position in a growing gas market,” said Lund. Oil and gas from sites along the Norwegian coast will account for about 1.4 million barrels of oil equivalent a day in 2020, the company estimated. The international portfolio, which will also include non-Norwegian Arctic sites and the Caspian region, is forecast to produce about 1.1 million barrels of oil a day, Statoil said.

The company will spend $16 billion on exploration, drilling and production in 2012, on par with what it will spent in 2011. Statoil expects to drill 20 to 25 high-impact wells in the years 2011 to 2013.

The company in February 2011 forecast output will grow on average 3 percent in each of the next two years, to about 2 million barrels of oil equivalent a day, below a former target of 2.06 million to 2.16 million barrels. "The positive is that they are announcing growth internationally to 1.1 million barrels in 2020, and they are quite specific about that, given that they haven't quite delivered recently," said Trond Omdal, an analyst at Arctic Securities.

Exploration would be about $3 billion this year, up from about $2.5 billion in 2010 when the company trimmed spending in the wake of the global financial crisis, Tim Dodson, head of the company's exploration arm, told Reuters.

Reserves have been in decline, with a replacement ratio of just 87 percent in 2010 and 73 percent in 2009. Oil and gas production in Norway, which accounts for about half of the company's total output, is expected to be above 1.4 million boed in 2020, the level it produced in 2010.

Statoil's Exploration Portfolio for 2011 and 2012:

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Source Documents:

Statoil 2011 positioned for long term growth

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BG and ENI eyeing for stake in ONGC’s KG – DWN - 98/2; Plans to spend around INR 36,000 crore (US$ 7,898 million) along with its partners on developing the block

In 2010, India’s state run Oil & Natural Gas Corporation (ONGC) has made significant finds in the Krishna Godavari (KG) basin, which is right next to the KG-D6 block of RIL in the K-G basin, off the east coast. ONGC is aiming to develop the KG basin assets through four different projects. The G-1 and GS-15 integrated development followed by the S-1 and Vasistha deep-water development, exploitation of discoveries in the KG-DWN-98/2 block and Project Manik, involving the oil finds.

The blocks are divided into two discovery areas - the Northern Discovery Area (NDA) consisting of the Padmawati, Kanakadurga, Annapurna, N-1, D/KT, U, A, W and E gas finds in water depths ranging from 594m to 1,283m and the Southern Discovery Area (SDA) consisting of the UD-1 discovery falls in ultra-deepwater with a depth of 2,841m.

KG-DWN-98/2, which has 10 gas discoveries, was awarded under the New Exploration Licensing Policy, which allows ONGC to farm out a participating interest to foreign firms. In 2010, ONGC had asked foreign firms to submit proposals to buy a stake in the block. Cairn India is already a 10 per cent partner in the block.

“Giving away more will result in losing control and, in turn, our decision-making ability. We want an international partner who can get us the technology for deep-sea exploration. Both BG and ENI have it. These players are experts in deep water and know exactly how to go about the routine of the block,” said, one of the board members, ONGC. He added the discoveries in KG-DWN-98/2 and three in adjacent blocks together hold 6.37 trillion cubic feet (tcf) of in-place reserves. RIL’s KG block holds in place reserves of 11.3 tcf.

In February 2011, BP agreed to buy a 30-percent stake in 23 oil and gas blocks owned by Reliance Industries for $7.2 billion, as part of a long-term deal that involves a total investment of $20 billion. Nearly four months after RIL signed a deal with BP for getting BP’s technology for deep-sea exploration.

To know more about Reliance-BP's $7.2 billion deal, CLICK HERE 

Block 1G was given to ONGC on nomination basis. It cannot sell stake to any firm and can at best involve a foreign firm as a service contractor. ONGC has partnership with BG India in three blocks in KG offshore, two operated by ONGC and one operated by BG. Petrobras and ENI have also partnership in one block each.

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ONGC has entered into a period of exploration for appraisal after completing the exploration MWP commitments in block KG-DWN-98/2. The company plans to start producing 25-30 mscmpd of gas from the block in 2016-17.

Source Documents:

ONGC to sell 30 percent stake in KG block

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Vero Energy reported Operational Update for First quarter 2011; Increased oil production by 120% to 1,051 bpd over the same quarter last year; Disclosed 2011 average production guidance of 10,000 – 10,500 boepd (27-28% liquids)

Vero Energy Inc. (Vero) is a Canadian energy company involved in the exploration, development and production of oil, natural gas and liquids in Alberta.  In third quarter 2010, the company has entered into farm-in agreements to earn up to 19 sections of land in Edson core, Alberta. Vero Energy increased the liquids proportion of total production to 25% in the first quarter of 2011 from 20% in the first quarter of 2010. The company also increased oil production by 120% to 1,051 bpd.

Operational Highlights:

During the quarter, Vero participated in the drilling of 11 (9.2 net) horizontal wells and one vertical deep basin gas well. Horizontal drilling activities achieved success on 10 of 11 wells resulting in five Cardium oil wells, four Notikewin wells, and one Viking well. The drilling program enabled the Company to add significant production since Q4 2010, adding approximately 2,700 boepd and yielding current production field estimates of approximately 11,000 boepd (27-28% liquids). 

"In a challenging operating environment, our team has efficiently and effectively executed an active program that added a significant amount of production in a short period of time on our asset base. Many of the production additions have come from exploratory wells and step out locations.  The results have exceeded our expectations and will be followed up throughout the year and into the future“, said Doug Bartole, President and CEO, Vero Energy.

Plans for the Rest of the Year:

For the remainder of the year Vero plans to drill approximately 25-28 gross (17-19 net) horizontal wells with a focus on Cardium light oil which will comprise approximately 20-23 gross (13-15 net) of the horizontal wells. Gas drilling will continue to be high-graded to target high impact, liquids rich wells that have strong economics.  The Company's gas production is liquids rich and averages ~30 bbls/mmcf.

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Vero reiterates its previously released 2011 average production guidance of between 10,000 - 10,500 boed (27-28% liquids). Upon successful implementation of the Company's 2011 program, the production mix is expected to have changed from approximately 22% oil and liquids in 2010 to an estimated 31 - 35% by year end 2011.


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Cenovus Plans to Accelerate Oil Projects; 500,000 bpd of Net Oil Production Expected by 2021

Cenovus Energy Inc. is planning to accelerate development of its oil sands and conventional oil properties, targeting output of half a million barrels per day within 10 years. The company has approved a 2011 strategic plan that builds upon its original strategy created in 2010 and establishes new timeline and significant oil production increases for the next decade.

The plan targets:

- Total oil production of about 500,000 bpd net by the end of 2021  

- Oil sands production of more than 400,000 bpd net by the end of 2021, about six times greater than current oil sands production

- Conventional oil production of 120,000 bpd to 130,000 bpd by the end of 2016, nearly double current production of about 70,000 bpd 

- A new oil sands project phase expected on stream every 12 to 18 months 

- An increase in total production capacity at Foster Creek to between 270,000 and 290,000 bpd gross, through increased production capacity at phases F, G and H and future phases 

- Drilling about 450 stratigraphic (strat) wells per year for the next five years to prepare for the development of oil sands opportunities

- Doubling of net asset value in the 2010 to 2015 timeframe

"We now have five phases at Foster Creek and three at Christina Lake operating with design capacity of 178,000 barrels per day. We have regulatory approval in place for projects under construction to get to about 440,000 barrels per day of operating capacity on a gross basis" said Brian Ferguson, Cenovus CEO

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Source Documents

Cenovus 10yr-plan-update

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Falkland Oil and Gas Limited Plans to Acquire Extensive License Areas to the South and East of the Falkland Islands

Falkland Oil and Gas Limited (FOGL) is an oil and gas exploration company operating in the South and East Falkland Basins, potentially a new petroleum province in the South Atlantic. Recently, the company secured operatorship and the remaining 51% interest in the Northern license area from BHP Billiton. Currently, FOGL is planning a two well program commencing from Q1 2012, first well on Loligo, identity of 2nd well dependent on results.

FOGL recently confirmed drilling operations on the south of the Falkland Islands will begin in the first quarter of 2012 and revealed it is in early talks with firms interested in taking part in its exploration program. The company however anticipated it did not expect to conclude any farm-out agreement until later this year.

Separately, FOGL said it was planning to acquire some additional focused 2D seismic for its deeper Scotia and Hero prospects so that it can fine-tune the location of an exploration well on either of these two prospects.

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In May 2011, the company revealed it had secured a rig contract for two slots and hopes to begin drilling on its prospects in the first quarter of 2012. The announcement came after it already confirmed it is to test the Loligo prospect - with estimated reserves of 4.7 billion barrels.
The firm added then that it had sufficient funds for a second appraisal well on either Loligo, or on one of the other high ranked prospects such as Nimrod, Vinson or Inflexible and was considering targeting Scotia or Hero but this would involve additional cost due to their greater depth.

“Since becoming operator and 100 percent owner of our licenses on 31 March, we have secured a suitable rig, put in place funding for a 2 well program and have established an experienced drilling management team.”, Tim Bushell, Chief Executive, FOGL.

”We have also accelerated all the other required work streams in preparation for our drilling program which is expected to commence in the first quarter of 2012.”

FOGL is required to make a mandatory relinquishment of 20% of the Northern License area at the end of 2011 as required under the existing license terms. The second phase of the Northern license area does not expire until 15 December 2015 and carries the obligation to drill a single exploration well.

FOGL has already entered Phase 2 of the Southern License area and no further relinquishment is required. FOGL is focused on extensive license areas to the South and East of the Falkland Islands.

Source Documents:

FOGLAGM PPT

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Santos Plans to spend over US$ 100 million for Sangu field in Bangladesh

Santos International is one of Australia’s leading gas producers, supplying Australian and Asian customers. The company is the largest producer of natural gas for the domestic Australian market, and has significant gas and oil operations across Australia and in Indonesia, Papua New Guinea, Vietnam, Bangladesh, India and the Kyrgyz Republic. The company has a strong base in Australia and Indonesia and pursuing focused growth in Asia, of which our activities in Bangladesh are a key part.


Santos in Bangladesh:

Santos acquired 3D seismic in 2010 over the Sangu and Magnama structures. This seismic has revealed some prospects of interest. Santos is planning to spend over $100 million on a three-well program in Block 16 beginning in the fourth quarter of 2011.  All wells are targeting new pools of gas not intersected by the existing Sangu field development. One of the wells, Sangu-11, will be drilled from the Sangu platform and, if successful, will be able to provide some immediate relief to the Chittagong gas situation. The other two wells are targeting prospects approximately five kilometers from the Sangu platform. A further exploration well may also be drilled on the Magnama prospect should time permit in the upcoming drilling season.

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In November 2010, Santos acquired all of the interests of Cairn in Sangu gas field and Block 16 exploration acreage. As a result of this transaction, Santos holds 75% interest (operator) in Block 16 (Sangu) and will have a 100% interest in Block 16 (Exploration). The deal is depicted below:

Source: Derrick Petroleum E&P Transactions Database

Santos exploration portfolio for 2011:

Source: Derrick Petroleum Planned Exploration Wells Database

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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BG plans to invest $500 million in Bolivian Gas fields over the next 5 years

BG in Bolivia:

BG plc demerged from British Gas in 1997 and is in charge of exploration and production and the overseas operations of British Gas. The company entered Bolivia in 1998 and announced the discovery of Margarita field. Currently, BG Group has interests in six exploration and exploitation licenses in Bolivia, including an interest in two gas condensate fields, Margarita and Itau. Gas and liquids are delivered to Yacimientos Petrolíferos Fiscales Bolivianos (YPFB), Bolivian State Energy company to supply Brazilian, Argentine and domestic markets.

Source: BG

Bolivia - Exploration and Production:

Bolivia nationalized its oil and gas industry in 2006 and the country is currently planning to increase its O&G production by allowing international partners to meet export commitments with neighboring Argentina and Brazil.

“Over $1.8 billion will be invested in natural gas exploration this year, more than doubling the amount spent last year. Two-thirds of that will come from YPFB, with private companies putting up the rest”, Villegas, President of YPFB said.

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Bolivia has been successful in bringing a number of multinational partners on board. While there are concerns over the legal protection afforded to foreign investors, BG Group, Total, Gazprom and a number of firms are comfortable with the risk.

Significant Transactions of BG in the year 2010:

Source: Derrick Petroleum E&P Transactions Database

Major E&P companies showing interest in Bolivia:

"Repsol YPF SA, BG Group Plc and Pan American Energy LLC will jointly invest $1.3 billion in the Margarita and Huacaya fields by 2014", YPFB, said in an e-mailed statement. "YPFB, Repsol, Petrobras and Total will invest $750 million dollars in the San Alberto and San Antonio gas fields", according to a separate statement.

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The investments in Margarita and Huacaya will increase the fields’ gas production to 14 million cubic meters in 2014 from a current 2 million. Output at San Alberto and San Antonio will increase by 5 million cubic meters per day, adding to an average 25 million now.

Source Documents:

BG - 2011 Strategy Presentation

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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

Apache Production increased by 25% in Q1 2011; Plans to Raise 2011 Capital Expenditures by 8% to $8.12 billion

Apache Corporation posted Q1 2011 production up 25% to 732,000 boe from 586,000 boe in the first quarter 2010. Liquids production increased 57,000 bpd to 358,000 bpd, which enabled Apache to achieve stand-out earnings and cash flow as a leading beneficiary of rising oil prices. Liquid hydrocarbons represented 49% of quarter production. Approximately 60% of the company’s oil production came from operations outside North America.


Apache’s operational data for year end 2010 comparing to peers:



Last year, Apache grew substantially with three large acquisitions. A $2.7 billion takeover of Houston’s Mariner Energy gave the company its first significant presence in the deep-water Gulf of Mexico. It also paid BP $7 billion for production in Canada, the U. S. Permian Basin, and Egypt; and struck a $1 billion deal with Devon to acquire shallow-water properties in the Gulf of Mexico.

Source: Derrick Petroleum - Global Oil & Gas M&A 2010 Review Report


Milestones during the Quarter:

- Development well in the Forties field (North Sea), which came online at approximately 11,800 boepd.

In the Permian Basin, Apache is operating 24 rigs, up nearly five-fold from a year ago. Targeting primarily oil objectives, Apache drilled 110 wells including 15 horizontals during the first quarter.

- Drilled six wells in Anadarko basin’s Granite Wash formation, every well has tested in excess of 1,000 barrels of oil and 2 mcfpd.

- In Egypt, Apache operated 22 rigs during the quarter, drilling 33 wells, including the company’s first wells in the Tayim development lease in West Kalabsha producing from deeper Paleozoic pay. Apache’s production remained online throughout the quarter, increasing sequentially from the previous three months.

"We continue to strengthen our land position, both in North America and internationally. Our LNG initiatives, Kitimat in Canada and Wheatstone in Australia, are steadily progressing toward project sanction with their respective joint venture partnerships," Farris said.

Plans to raise capital expenditures by 8%

The company now plans to spend $8.12 billion in 2011, up from its forecast for $7.5 billion. “The bulk of the increase will be spent in the second half of the year, so the company's 2011 production outlook for growth of 13% to 17% remains unchanged”, Chambers said.

The company is in the planning stages for the Kitimat liquefied natural gas terminal in northwestern Canada, and expecting a final investment decision on that facility later this year or early next year, with first gas expected in 2015.

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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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