Monday, February 28, 2011

Sinopec tastes a slice in Origin's APLNG project.. More slices in APLNG up for grab!!!

Sinopec agreed to acquire a 15% equity stake in Australia Pacific LNG Pty Ltd (APLNG), a 50/50 joint venture created by Origin Energy and ConocoPhillips in 2008. Post transaction, the ownership structure in the joint venture would be- Origin Energy (42.5%), ConocoPhillips (42.5%) and Sinopec (15%). As part of this agreement, APLNG has agreed to supply up to 4.3 million tonnes per annum (MTPA) of LNG to Sinopec for 20 years. 
APLNG Overview
APLNG project includes the development of Australia Pacific LNG’s substantial coal seam gas resources in the Surat and Bowen basins over a 30-year period, a 450 km transmission pipeline, and a multi-train LNG facility on Curtis Island, near Gladstone. Initial plans for the LNG facility are focused on developing two LNG trains, each with a nameplate capacity of approximately 4.5 MTPA of LNG. The project is expected to be sanctioned by mid-year 2011, with the first LNG cargo to be delivered in 2015. The APLNG project’s reserves, as of June 30, 2010 were: Proved plus Probable - 10,143 PJ (1,594.13 MMBOE), Proved plus Probable plus Possible - 14,598 PJ (2,294.29 MMBOE) and Contingent Resources on best estimate case - 4,844 PJ (761.31 MMBOE).


What could be the value of 15% stake in APLNG
The value of the deal was not disclosed. However, the 15% stake in APLNG is estimated to be atleast around $2 billion. Here is a simple valuation method…
ConocoPhillips acquired 50% stake in APLNG for $8 billion when the financial crisis was wide spread in 2008. Of the total $8 billion, $2 billion was marked as performance payments. In comparison with the $6 billion price, the current deal involving 15% stake should be worth atleast around $2 billion.
Largest supply agreement amongst Queensland LNG ventures!!!
This supply agreement would be the largest for any of the Queensland ventures intending to liquefy gas extracted from coal deposits, Grant King, managing director of Origin Energy, told reporters.
Australia was China’s biggest supplier of LNG last year, accounting for 42% of the 9.4 million tons in imports, according to customs data. China paid an average $191 for each ton of Australian term-contract supplies in 2010, compared with an average $323 for all imports, including both term and spot cargoes, customs data show. “The deal will help Sinopec diversify gas supply sources to meet Chinese demand for natural gas," said Sinopec's General Manager Su Shulin in a statement.
More slices of APLNG up for grab!!
Origin and ConocoPhillips will “intensify the dialogue” with other potential customers and may sell more of its interest in the venture, Grant King of Origin Energy said. Will these Chinese, to quench their thirst for natural gas demand, again buy the additional stake?

Origin JV may sell down more of APLNG



Origin Energy may sell down more of its stake in the $35 billion Australia Pacific LNG (APLNG) project after it divested a combined 15% stake to Sinopec with its joint venture partner ConocoPhillips. The current ownership structure of the project - Origin Energy (42.5%), ConocoPhillips (42.5%) and Sinopec (15%).

The $35 billion APLNG project has the following objectives -
-- Development of the Walloons gas fields in the Surat and Bowen basins in south central Queensland with up to 10,000 CSG wells; these gas fields may include Spring Gully, Peat, Denison, Fairview, Arcadia Ridge, Kenya, Kenya East and Angry Jungle;
-- Construction and operation of a 450 km main gas pipeline to connect the Walloons gas fields with the LNG facility near Laird Point;
-- Construction and operation of an LNG facility on Curtis Island near Gladstone for production and export of approximately 18 Mtpa of LNG. The final configuration of the LNG plant is yet to be determined, but may comprise up to four trains, each producing ~4.5 Mtpa of LNG.


APLNG project reserves, as of June 30, 2010 were: Proved plus Probable - 10,143 PJ (1,594.126 MMBOE), Proved plus Probable plus Possible - 14,598 PJ (2,294.293 MMBOE) and Contingent Resources on best estimate case - 4,844 PJ (761.307 MMBOE). ConocoPhillips anticipates peak production of 1.05 net Bcf/d in 2023, excluding effects of possible reversions.

The project has recently won environmental approval from the federal government. The companies aim to make a final investment decision to proceed with the project later this year and expect to rapidly progress the project to sanction, with the first LNG cargo to be delivered in 2015. The project life is approximately 30 years.

Anadarko discloses its 2011 budget plans; exploration to eat up one-fourth of the pie!

Anadarko has disclosed its 2011 outlook and capital program from which it looks forward to generate a significant momentum to continue in 2011 and ahead with its diversified portfolio globally. 

  • Total 2011 capital expenditures are expected to be between $5.6 and $6.0 billion out of which about $1.3-$1.5 billion would be directed towards exploration activities, which is about 25% on the total capex.
  • Exploration capex would be spend company's worldwide offshore and deepwater programs, which include approximately 25 exploration and/or appraisal wells this year.


  • Africa will continue to be a primary focus area with 12 to 15 wells planned in West Africa, and another three to five wells planned in the Rovuma Basin offshore Mozambique.


  • In addition to finding new resources, Anadrako plans to continue advancing existing discoveries to development with very active appraisal programs in Mozambique, Ghana, Brazil, Sierra Leone and the Gulf of Mexico.









Anadarko’s Report Card
  • Anadarko has continued to remain amongst the most active and successful deepwater explorers in the world, and together with its U.S. onshore exploration activities.
  • 19 offshore discoveries in the last three years
  • With Tubarao and Teak discoveries, Anadarko seems to have scored high in the beginning of the year 2011!


Repsol YPF, S.A. (Repsol) reported full year 2010 results; Production up 3.2%; Plan to take decisive steps in the Horizon 2014 Strategy


During 2010, Repsol’s hydrocarbons production was 344 boepd up 3.2% over 2009. This was due to production in Shenzi (USA) an increased share in Libya and the start-up of the Peru LNG project. The company’s increased reserve replacement ratio, of 131%, which endorses the implementation of the company’s successful reserve replacement policy of recent years.

In 2010, YPF's total production was 541 kboepd down 5.4% compared to 2009. Liquids output declined more slowly than gas production as a result of increased investment based on a crude production incentive program. The reserve replacement ratio was 84%, with 100% replacement ratio for liquids.


The company made significant advances in achieving the goals set out in its 2010 Strategic Plan, including the incorporation of Sinopec in Brazil, the placement of 4.2% of YPF and the sale of nonstrategic assets.

Key Achievements in 2010 and Outlook for 2011:



$925 million exploration investments


Intensive exploratory activity


Updates on key projects in upstream




Plan to increase production by 3-4% till 2014 and higher to 2019

2011- A busy year for BHP?? BHP says it sees opportunities in the oil and gas industry.



BHP is still interested in takeovers even after setting aside $80 billion for own projects.
Regulatory concerns are impeding iron-ore acquisitions, though BHP's potash, copper, and oil and gas businesses aren't constrained in the same way,  Marius Kloppers (CEO) said
BHP reported record first-half profit, has committed to spend $80 billion to expand and develop BHP's own mines and oil fields after three investments worth a total of more than $100 billion(Non Oil and Gas ventures- Potash, RioTinto bid and an iron ore venture) were knocked back in the past four years.  Still, acquisitions aren’t off its agenda.
Industry rumours are BHP may decide to pursue energy acquisitions, singling out Anadarko Petroleum Ltd., Woodside Petroleum Ltd. as possible targets.





Internationals and Majors flocked towards US shale gas opportunities




International companies followed up 2009 activities by continuing to enter into US shale gas JVs and providing US operators much needed capital to develop their assets.  The US is attractive to internationals because of its fiscal regime, large shale gas reserve potential and technological opportunities. The international firm’s large balance sheets, low costs of capital and long term view allow them to “pay up for US opportunities”. The same could be said for traditional majors who also made aggressive moves into US shales in 2010 through corporate acquisitions like  East Resources (Shell) and Atlas (Chevron). To fund new shale opportunities the majors also sold non-core assets. 

For more details:

Saturday, February 26, 2011

EnCana and NW Natural form Jonah field JV


Northwest Natural Gas Company (NW Natural) and Encana signed an agreement for NW Natural to invest in a joint venture to develop gas reserves that will provide long-term supplies for NW Natural’s Oregon utility customers over a 30-year period.

During the first 10 years of the joint venture, NW Natural expects the volume of gas produced to provide approximately 8-10 percent of the company’s average annual requirements for its utility customers. These gas reserves come from the Jonah Field in Wyoming, located north of Rock Springs.
Under terms of the agreement, NW Natural will pay approximately $45-55 million a year, for a five-year period, for a total investment of about $250 million, which will cover expected drilling costs in exchange for working interests in certain sections of the Jonah Field. The sections include both future and currently producing wells.
NW Natural estimates the gas reserves will save Oregon customers more than $50 million on a net present value basis over the life of the agreement. The Jonah Gas Field is considered to be one of the 10-largest gas fields in the U.S. with over 2 Trillion cubic feet equivalent (Tcfe) of proved reserves. 

About Jonah


Located south of Pinedale, Wyoming, the Jonah Field is one of our key resource plays. The life of the Jonah Field is estimated to be from 40 to 60 years.



Plains Exploration & Production (PXP) reported 2010 results; Production up 7% over 2009; Plan to invest $1.2 billion in 2011


PXP reported 2010 daily sales volume of 88,500 BOE up 7% over 2009. The company reported full-year revenues of $1.5 billion and net income of $103.3 million, compared to revenues of $1.2 billion and net income of $136.3 million, for the full-year 2009. PXP plan to increase its production and reserves rate from 15% to 20% per year over the next 3 years.

Keypoints:

-- Average daily sales volumes of 88,500 BOE up 7% over 2009. Operating cash flow of $976.7 million up 4% over 2009.

-- Proved reserves of 416.1 million BOE up 16%  over 2009.

--- $1.2 billion capital allocated for 2011.

HRT O&G to sell interest in two oil blocks offshore Namibia

































HRT O&G Exploracao e Producao de Petroleo Ltd (a wholly owned subsidiary of HRT Participacoes em Petroleo SA) has announced that it may sell up to 50% of a pair of oil Blocks 2112A and 2212B in the Walvis Basin, offshore Namibia. HRT holds a 100% participating interest in the two blocks. The blocks are contiguous and span an area of 11,592 sq km (equal to 1,159,200 hectares, or 2,864,446 acres) with water depths ranging between 300 and 1,400 m. In January 2011, HRT has signed 3D seismic contract for 5,278 sq km over the blocks.

Top 20 US deals driven by shales, major oils and dramatic asset moves



  • 14 of the top 20 US deals in 2010 were motivated by shale objectives with some of the largest deals (East, Atlas, Exco, Consol, Reliance) in the Marcellus.
  • Apache’s purchase of BP’ Permian assets and SandRidge’s corporate acquisition of Arena were not driven by unconventional assets. While Concho’s acquisition of Marbob has some Avalon Shale hope.
  • Energy XXI’s and Apache’s purchase of offshore assets from Exxon and Devon were somewhat driven by shales including Devon’s refocus and Exxon’s XTO commitment.
  • Apache’s acquisition of Mariner’s deepwater assets was dramatic.
  • The top 20 deals totaled $44.6bn or 59% of the total market. The 14 clearly shale deals totaled $32.6bn or 43% of the US total.

Friday, February 25, 2011

Namibia – The Next Oil Frontier!! Brazilian HRT snaps up Namibian explorer UNX Energy for C$730 million.


Brazilian company, HRT Participacoes em Petroleo SA agreed to acquire UNX Energy Corp operating in Namibia for approximately C$730 million. In combining the two companies, the resulting entity forms a South Atlantic Margin powerhouse controlling impressive exploration and development concessions in both Namibia and Brazil. BMO Capital Markets and Credit Suisse are acting as exclusive financial advisors to UNX and HRT, respectively.


Asset portfolio of UNX in Namibia
The asset base of UNX consists of approximately 51,000 sq km (approximately 32,000 net) of offshore acreage, strategically located along the prolific South Atlantic Margin, offshore Namibia. Of the four hydrocarbon basins that have been identified offshore Namibia, the Orange Basin provides the greatest exploration potential. UNX’s land holdings in the Orange Basin include 90% working interest in Blocks 2713A, 2713B, 2815, 2816, 2915; and 40% working interest in Blocks 2813A, 2814B and 2914A.


UNX’s PEL 2713 has gross unrisked recoverable prospective resources of 10.5 billion barrels of oil equivalent and gross risked recoverable prospective resources of 3.2 billion barrels of oil equivalent. The resources are comprised of approximately 72% oil, 6% condensate, 3% associated gas and 19% non-associated gas.

West Africa Vs Brazil
Through the deal, HRT wants to expand its exploration and production areas in West Africa, where it sees potential for similar deposits to Brazil's vast, new offshore oil fields. All the wells drilled offshore Namibia had oil shows, confirmed by biomarker and diamondoid studies. The analysis further confirms the identical age and rock type of Brazil.

Recently, the Brazilian giant Petrobras also acquired a stake in Benin block and the company’s geologists disclosed that West Africa holds similarities to Brazil's pre-salt discoveries. Are these West African countries lining up to compete with the Brazilian pre-salt resources?


In addition to this deal, HRT is planning to sell up to 50% of a pair of oil blocks in Namibia’s Walvis Basin.

Click here to see the publications of the companies operating in Namibia: http://docsearch.derrickpetroleum.com/research/q/namibia.html

Centrica plc reported 2010 preliminary results; production up 43% compared to 2009; plan to invest £1.5 billion ($2.42 billion) in 2011

Centrica reported 2010 gas and liquids production volumes increased by 43%, with gas volumes up 48% at 2,520 bcf (2009: 1,699 bcf), and oil and condensate volumes up 26% to 11.1mmboe (2009: 8.8mmboe), reflecting the acquisition of Venture in 2009, good asset performance and higher volumes from Morecambe, which was shut in for parts of 2009.


Delivering value from enlarged upstream business:




- Upstream gas and oil production volume up 43% due to strong Morecambe performance and a full year's contribution from Venture




- 163% production replacement ratio in UK upstream gas and oil 




- Centrica invested £1.7 billion ($2.75 billion) in 2010; £1.5 billion ($2.42 billion) organic investment program for 2011. £450 million ($720.4 million) investment approved to develop York and Ensign gas fields in the UK North Sea

Thursday, February 24, 2011

CNPC and KazMunaiGaz boost strategic partnership. Urikhtau field to provide additional gas supply for Kazakhstan-China pipeline.


CNPC and KazMunaiGaz have signed co-operation agreement to jointly develop the Urikhtau natural gas field located near Kenkiyak in the Aktyubinsk region of western Kazakhstan. CNPC and KazMunaiGaz will hold 50:50 interest in a joint venture to explore and develop the Urikhtau gas field which was tapped during the Soviet era, but has not been developed since Kazakh independence. According to earlier estimates by KazMunaiGaz, Urikhtau's reserves are estimated at ~40 billion cubic meters (1,413 Bcf), and the field has an estimated potential to produce 1.5-2 Bcm/year (52-71 Bcf/year).
The field's gas output is expected to be one of the sources for Kazakhstan's Beineu-Shymkent pipeline, which is a 1,500 km pipeline linking several existing trunk lines in Central Asia, including the Center, Bukhara-Ural, BGR-TBA and Kazakhstan-China pipelines. Construction of the pipeline started in late December and is expected to be completed by 2012.

The 10 Bcm/year pipeline is the second phase of the Kazakhstan-China gas pipeline and will go from near the Caspian Sea to a linkup with the first phase of the pipeline in south-central Kazakhstan. The first phase, which brings gas from Turkmenistan to China via Kazakhstan, was launched in December 2010 with a capacity of 30 Bcm/year and may be increased to 40 Bcm/year.
With the completion of the pipeline construction and development of the Urikhtau gas field, additional gas volumes will be available to export along the Kazakhstan-China gas pipeline. Also, China is seeking greater access to natural resources in Central Asia to fuel its fast-growing economy. This Kazakh co-operation will help China meet the growing demand to an extent.

Democratic fireball goes rolling in Libya; disrupts oil and gas operations

The growing unrest  in Libya since past few weeks has decreased Afica’s oil output by 6% and has sent Brent oil prices skyrocketing above  $105 per barrel. With Muammar Gaddafi’s orders to his security forces to sabotage the country’s oil facilities, many international oil and gas companies have already suspended their operations.

Wintershall turns off the tap…..
  • Wintershall holds eight onshore fields around 1,000 kilometers southeast of Tripoli and 350 kilometers southwest of Benghazi in the Libyan Desert. It also holds  interest in the Al Jurf offshore field in the Mediterranean Sea off the Libyan coast.
  • Following the unrest, Wintershall has shut down its production of much as 100,000 barrels per day.
Repsol follows suit…..
  • Spain's Repsol has halted output in Libya due to unrest. A pipeline bringing Libyan natural gas to Italy was closed.
BP and Shell suspend drilling…..
  • Shell holds five exploration licenses in the Sirte Basin off Libya. It has has temporarily relocated the dependents of expatriate staff outside the country.
  •   BP which does not produce oil or gas in Libya but has been readying an onshore rig to start drilling in the Ghadames basin, has suspended operations.


  • Italian power giant Eni S.p.A (ENI) has a historically large involvement in Libya, which constituted 14% of oil and gas production in 2009. ENI also produces significant natural gas from Libya and pipes over to the continent via the Greenstream pipeline.
  •  It said that its operations and facilities in Libya haven't been affected by the political unrest in the country and production continues as normal. The company is in the process of evacuating non-essential personnel.


Libyan oil and natural gas fields and pipelines


For information about companies with operations in Libya, please click here:

Permian Basin continues to lead the market for mature assets in US

The Permian Basin received the highest production multiples, $80,000-$110,000 per flowing barrel equivalent. The metrics reflect the premium buyers were willing to pay for oil reserves; future drilling opportunities, behind pipe potential and reserve quality.





Deepwater GoM saw the highest reserve metrics as a result of BP’s acquisition of Shell’s mature GOM assets in Dorado and Marlin.

Gassy plays such as the Barnett, Fayetteville and CBM received low metrics due to the low gas price environment.

Oxy paid a premium for Shell’s conventional South Texas gas assets with part of the price driven by liquids content and low operating costs.  


For more details on Permian companieshttp://docsearch.derrickpetroleum.com/research/q/Permian.html

Deepwater GoM a hard sell, but sellers continue to track

As 2011 sets sail, there are at least five sizeable property sale packages being floated in the Gulf of Mexico. One of them, a set of 22 shelf leases with 27 MMcfe/d of production and17 MMboe of reserves offered by EOG Resources, is rumored to have a tentative buyer. Net present value of the EOG properties has been said to be upwards of $200 million, with about $34MM a year in operating cash flow. Unknown is how much of EOG’s half-billion-dollars of plugging and abandonment liabilities is allocated against them.

Deepwater sale properties are facing a rougher market, however. Plains Exploration and Production announced last year it wants to exit its holdings far offshore in the Gulf and opened a data room in December in hopes of finding a buyer. With apparently a dearth of bids, however, CEO James Flores has extended the marketing effort into the first quarter. Said Flores: “The additional time is an important step in securing the optimum value for PXP shareholders.” Other sale packages being marketed include about 7 MMcfe/d of production by Sojitz Energy and others at WC 168, operated by Linder Oil. Also for sale is Leed Petroleum with ~1,200 boe/d of Gulf shelf output and an package of Merit Energy properties producing ~8,400 boe/d. Tristone is handling the Leed and Merit sales. PLS and Burks are offering the Linder package and Randall & Dewey has the PXP deepwater sale. R&D is also agent for ConocoPhillips, which is trying to sell offshore stakes at Green Canyon, Eugene Island and the Europa Field. The major said February 7 it closed the sale of six regional packages for over $1.2 billion but did not mention the offshore assets. Randall & Dewey did not respond to inquiries. Statoil, which took a big plunge into the Gulf in recent years by acquiring stakes in some 400 offshore blocks, now is trying to sell down many of those interests to reduce risk and spread big capital costs.

Major deepwater packages available

Statoil offeringStatoil ASA is planning to sell stakes in GoM exploration licenses where the company has 100% ownership to reduce risk and raise funds for projects.                                                                  

Statoil has interests in more than 400 leases in the Gulf of Mexico. In 2009, Statoil became the operator for an extensive drilling programme with two rigs in the Gulf of Mexico. In March 2010, Statoil was the highest bidder on 21 leases in the Central lease sale 213. These leases are in deepwater and predominantly in high quality Miocene sand.

ConocoPhillips offering                                                                                                 
ConocoPhillips has retained Jefferies & Co Inc to sell certain assets in the Gulf of Mexico. The package includes Green Canyon 563 (K-2 Unit) with 12.4% non-operated interest in 4,000 foot depths. Production is 22,000 BOE/d (2,400 BOE/d net) from eight wells targeting Middle and Lower Miocene turbidites.

Plains E&P offering                                                                                                                               
Plains Exploration & Production Company is in the process of marketing the company’s Gulf of Mexico deepwater assets. Plains has engaged Barclays Capital and Jefferies & Company to assist in executing this sale process.                                                                                                             

The deepwater portfolio is anchored by Friesian and Lucius, two high-quality oil discoveries, and a comprehensive exploration portfolio with interests in 107 blocks, 9 well defined prospects and an additional 22 prospects or leads in Pliocene, Miocene and Lower Tertiary reservoirs. The data room process is underway with final bids expected in late-October to mid-November. PXP expects the transaction to close by year-end 2010.  

On 20-Sep-2010, Plains E&P divested the Gulf of Mexico shallow water properties to McMoRan Exploration for $818 million. Current production from these properties is approximately 45 MMcfe/d of natural gas net to PXP. The properties include estimated Proved (1P) and Proved plus Probable Reserves (2P) of approximately 60 Bcfe (Gas- 85%) and 80 Bcfe, respectively.

Wednesday, February 23, 2011

Woodside Petroleum reported 2010 full year production of 72.7 mmboe, down 10% compared to 2009

Woodside reported a 10% decrease in its 2010 annual production compared to 2009 due to the sale of Otway interests and oil field natural decline. The company recorded 20% growth in its annual revenue due to higher commodity prices and the positive conclusion of LNG price negotiations.
Key Points:


- Production of 72.7 MMboe in line with guidance (2010 target range: 70 – 75 MMboe), but down 10.1% (2009: 80.9 MMboe), largely due to the Otway sale in March 2010 and oil-field natural decline.


- Annual sales revenue of $4,193 million up 20.2% (2009: $3,487 million) despite the lower sales volume of 72.2 million barrels oil equivalent (2009: 80.7 MMboe), largely due to higher commodity prices and the positive conclusion of certain LNG pricing negotiations.


- Reserves replacement ratio remains strong at 148%, up 1.4% (2009: 146%). Proved plus Probable reserves at the end of 2010 were 1,680.1 MMboe, up 1.7% (2009: 1,651.2 MMboe). Proved plus Probable reserve to production ratio has increased to 24 years.


- 2010 Operational highlights

- 2010 Project highlights.

Pemex reduces oil and gas drilling by 42%; planned well count slumps down from 994 to 580; gas ouput to take a dip

Where many oil and gas companies are planning an aggressive drilling programme globally, Mexico’s state oil monopoly, Pemex will drastically cut down the number of wells planned to be drilled this year.
  • A nearly two-thirds drop in planned drilling at the Chicontepec oil project as well as sharply reduced development activities at natural gas fields in the northern Burgos basin near the Texas border account for much of the planned reduction, according to the plan which was released by the National Hydrocarbons Commission on Tuesday.
  • Overall, Pemex will drill 580 wells this year, including 32 exploration probes, compared with 994 wells last year.

  • Many Pemex contractors like Schlumberger Ltd and Halliburton are still reeling from a slowdown in oil and gas activity in Mexico that began in 2010.
  • Chicontepec, a massive, challenging onshore area , on which billions of dollars have been invested till now, has consistently failed to yield as much oil as Pemex has promised.
  • Burgos lies over some of the most bitterly contested drug smuggling territory because of which its activities were hampered by drug gang activity in 2010.               
  • Pemex drilled 816 exploration and development wells in its northern region, which includes Chicontepec, Burgos and several smaller developments, last year.
Oil to rise, Gas to fall!
  • The natural gas output is estimated to  fall from 6.986 billion cubic feet per day to 6.132 billion cubic feet per day by December 2011.
  • The major reduction in wells will come from the Canterall oilfield.


  •  Burgos gas production will decline by 11.5%.
  • Oil will take a jump to 2.626 million barrels per day by December 2011 which is about 2% more than the oil output last year.
  • Chicontepec oil production is forcasted to rise to 70,000 bpd by December 2011 from 59,000 bpd at the end of 2010.

To know more about Pemex, please click here:

Petrobras takes a slice in Benin block and seeks West Africa to be analogous to Brazil's pre-salt discoveries..

Petrobras acquired a 50% interest in Block 4, located off the coast of Benin in West Africa, from Compagnie Beninoise des Hydrocarbures (CBH), a subsidiary of Lusitania Petroleum, which maintains the remaining 50% interest. The block covers an area of approximately 7,400 sq km, at a water depth that varies from 200 to 3,000 meters, at an average distance of 60 km from the coast.


CBH continues to be the operator of the asset; however, Petrobras has the right to take over the operation. The work commitment assumed by the company is to collect and process 2,250 sq km of 3D seismic data by the end of this year. Once the exploratory potential of the area is confirmed, the consortium will undertake to drill three wells.

West Africa is analogous to Brazil's pre-salt province..

Petrobras’ business plan for 2010-2014 includes exploration focus on West coast of Africa. In-line with this plan, the deal represents further expansion of Petrobras' portfolio in the West Coast of Africa, which company geologists say holds similarities to Brazil's pre-salt province. Also, Petrobras aims to find light oil, reproducing the discoveries that took place in the African continent. This is aligned with the company’s strategy to seek for opportunities in deep and ultra deep waters in the region where it  already has operations in countries like Nigeria, Angola, Tanzania, Namibia and Libya. 


To know what other operators are doing in West Africa, please click here: http://docsearch.derrickpetroleum.com/research/q/%22west%20africa%22.html

Chesapeake reported 2010 full year results; Production averages 2.84 bcfe/d, up 14% to 2009, setting record for 21st consecutive year

Chesapeake's average daily production for the 2010 full year of 2.836 bcfe consisted of 2.534 bcf (89% on a natural gas equivalent basis) and 50,397 bbls (11% on a natural gas equivalent basis). Chesapeake anticipates delivering a production growth rate of 25% over the next two years, net of property divestitures pursuant to its 25/25 plan.
Keypoints:

-  2010 average daily production of 2.84 bcfe/d, up 14% after asset sales. Oil and natural gas liquids production of 18.4 mmbbls; up 56% YOY to 11% of total production.
- Acquired $4.7 billion (net of leasehold sales) of primarily liquids-focused leasehold.





















  - 15.2 tcfe of proved reserves. 269 tcfe unrisked unproved resources (~138 tcf from natural gas shale plays, ~15 billion boe from liquids-rich plays, ~38 tcfe from other conventional and unconventional plays)
    
- Aggressively shifting capital to liquid rich plays, as part of 25/25 plan. Production from liquids anticipated to be 20-25% of total in 2012.




















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