Wednesday, May 18, 2011

BP sells Wytch Farm oil assets to Perenco for $610 million. BP’s Southern North Sea gas assets worth $750-$900 million are up for grab..

BP agreed to sell its interests in the Wytch Farm, Wareham, Beacon and Kimmeridge fields to Perenco UK Ltd for up to $610 million in cash. The sale of these interests is part of BP's plan, announced in July 2010, to divest up to $30 billion of assets by the end of 2011. Before today's agreement, BP had already announced sales agreements totalling around $25 billion.

An immediate payment of $500 million has been made, a further $55 million will be paid on completion which is expected at the end of 2011 with the remaining $55 million contingent on Perenco's future development of the Beacon field and on oil prices in 2011-13.

Equity interests being sold
  • Wytch Farm: BP (Operator) 67.81%, Premier 12.38%, Maersk 7.43%, Summit Petroleum Dorset Ltd 7.43%, Talisman 4.95%
  • Wareham and Beacon: BP (Operator) 67.5%, Premier 12.5%, Maersk 7.5%, Summit 7.5%, Talisman 5%.
  • Kimmeridge: BP 100%.

Production associated with the sale:
Earlier in February 2011, BP initiated a sale which included the Wytch Farm onshore oilfield and all of BP’s operated gas fields in the Southern North Sea, including associated pipeline infrastructure and the Dimlington terminal. The company had reported net production from these assets to be around 40,000 BOE/d (75%- Gas). Thus, the remaining oil production of 10,000 BOE/d of the total package was from Wytch farm oil field.

BP’s Southern North Sea gas assets up for sale.
The production associated with BP’s Southern North Sea gas assets is approximately 30,000 boe/d. These assets could be valued between $750-$900 million (based on $25,000-$30,000/BOE). This sale is part of their $30 billion divestiture program.

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.

List of West African Oil Discoveries in 2010 - 2011.

Ok.., here it is.. One of the most definitive lists of discoveries in West Africa for 2010-2011 so far. There is increasing excitement about the vast potential in West Africa's offshore basins and I thought it would be worthwhile to list them out. The material has been sourced from Derrick Petroleum's exhaustive data on exploration and deals. For the record, I consider Angola part of West Africa here, although to be more precise, it is located in South-West-Central Africa. 

For more information of discoveries and exploration plans for the following West African countries in 2011, click on the following links. Cote D’ivoireGhana discoveriesGhana Exploration in 2011Exploration in Mauritania, Benin & TogoAngolaSierra LeoneSengalLiberia; Cameroon.

Table 1: List of Discoveries in 2010 - 2011. Source Derrick Petroleum Services

Map of West Africa - Source: USGS

Sierra Leone
The Mercury-1 well was announced as a discovery in Nov 2010 with approximately 135 net feet of oil pay in two Cretaceous-age fan systems. Anadarko operates block SL-07B-10 with a 65-percent working interest. Co-owners in the block include Repsol (25%) and Tullow (10%). This was the second well drilled on the block, the first being the Venus-B well on the Venus prospect drilled in August 2009 which encountered 14 m of hydrocarbons.

Source: Anadarko Corp

The Dzata - 1 well was drilled in May 2009 in the Cape Three Points Deep Water Block by the Aban Abraham drillship and struck hydrocarbons over 94 m, including a 25-m net section of layered oil and gas pay. The well is temporarily plugged and abandoned for future appraisal activities. Vanco Energy (28.34%) is operator of the block and other partners are Lukoil (56.66%) and Ghana National Petroleum Corporation (15%). 

Source: Hess Corp

In March 2009, Kosmos announced that the Tweneboa-1 well drilled in the Deep Water Tano Licence discovered a light hydrocarbon accumulation with 21 m net pay in a single, good-quality sandstone reservoir similar in age to those found in the Jubilee Field. The Tweneboa-1 well was the seventh consecutive successful well Kosmos and its partners drilled on the West Cape Three Points and Deepwater Tano blocks, including three previous exploration wells that found oil on the West Cape Three Points Block since mid-2007. The Mahogany-1 exploration well discovered the Jubilee Field, which was announced in June 2007; the Odum-1 exploration well discovered the Odum Field, which was announced in February 2008; and the Mahogany-3 well discovered the Mahogany Deep Field which was announced in January 2009.

The Owo prospect in the Deep Water Tano Licence was drilled in early June 2010 and encountered a significant light oil accumulation . The Enyenra-2A appraisal well on this discovery intersected 32 m in 2 channels. Tullow operates the block, holding a 49.95% interest; Kosmos Energy holds 18%; Anadarko Petroleum holds 18%; Sabre Oil and Gas holds 4.05%; and the Ghana National Petroleum Corporation holds a 10% carried interest.  

The Teak-1 exploration well in the West Cape Three Points Block was spud in Q4 2010 and discovered oil. On Mar 28, 2011, the Teak-2 exploration well encountered approximately 90 net feet of high-quality oil, condensate and natural gas pay in stacked Campanian- and Turonian-age reservoirs. Kosmos Energy (30.875%) is the operator of the Block. Other partners are Anadarko (30.875%) Tullow Oil (22.896%), KG Group (3.5%), Sabre Oil and Gas ( 1.854%) and Ghana National Petroleum Corporation (GNPC) which has a 10% carried interest.

To find out which companies are drilling in Ghana in 2011, click here

On June 24, 2010, Total announced that the Agge-3B.T1 well in the OML 136 licence in water depths of 140 m discovered several gas bearing reservoirs totalling a gross thickness in excess of 150 m. A production test performed over the lower intervals yielded a production of 21 million cubic feet of gas per day on a 36/64’’ choke. Conoil Producing Limited (60%) is the operator of the licence and Total (40%) is partner.

Source: Total

On 12 July 2010, Sinopec announced that the UDELE-3 well in Block 137, in the Niger Delta, struck an oil layer of 45.9 m and test yields showed an oil flow of 3,365 barrels of oil and 28,300 cubic metres of gas a day. Sinopec is the owner and operator of the licence after acquiring the Swiss firm Addax Petroleum.

The Pegi-1 discovery well encountered 165 net feet (50.3 m) of rich gas condensate. The well was drilled in 315 ft (96 m water depth to a total depth of 11,407 feet (3,477 m) beneath the Awawa field. Analysis of recovered samples indicated an API gravity of ~41 degrees. ExxonMobil is the operator of the block with a 40 percent working interest, with the NNPC holding the remaining 60 percent. 

Bowleven, the West Africa focused oil and gas exploration group traded on AIM, announced that the Sapele-1 exploration well drilling in the Douala Basin, offshore Cameroon was drilled to a total depth (TD) of 4,733 m. Based on an analysis of a major steep change in pressure encountered and the interpretation of the seismic, Bowleven interpreted that the well may have encountered a significant hydrocarbon column in the Cretaceous. Further studies are ongoing. The well was drilled on the MHLP-5 block on Sept 14 2010. The MHLP-5, MLHP-6 and MLHP-7 blocks are located in the Etinde Permit Area and the blocks are operated by Bowleven (75%) and the partner is Vitol Group (25%).

Source: Bowleven

Drilling in the Onal licence area yielded the Maroc Nord OMOC-N-1 discovery which identified a 111-metre column of oil. Pump tests established a flow of 1,700 bpd of oil (flow limited by the pump’s maximum capacity) with an API of 33.4. Maurel &  Prom (85%) operates the Onal production licence and is partnered by Tullow (7.5%) and AIC-Petrofi (7.5%).

The Southeast Etame No. 1 (“ETSEM-1”) exploration well completed drilling to a total depth of 9,045 feet (2,757 m) offshore Gabon and encountered approximately sixteen feet (five m) of oil saturated Gamba sandstone. Valco Energy (28.07%) operates the Etame Marin Permit in which this discovery was made with the other partners being Addax Petroleum (31.36%), Sasol Petroleum (27.75%), Sojitz Etame Limited (2.98%), PetroEnergy Resources Corp. (2.34%) and Tullow Oil Gabon SA (7.5%).

The Castanha-1 well was spud in Nov 2009 and struck 15 m of hydrocarbons in pre-salt sediments at a depth between 2,214 and 2,229 m. The Castanha-4 appraisal well encountered a gross hydrocarbon column of approx. 15 m in the Chela Formation. Production testing of the Castanha-2, Castanha-3 and Castanha-4 appraisal wells is planned to commence following which the consortium will take a decision as to its commerciality. Participating Interests in the Cabinda Onshore South Block in which the discovery was made are: Pluspetrol Angola Corporation (Operator) 45%; Force Petroleum de Angola 20%; Sonangol P&P 20%; Lacula Oil Company (ROC) 10%; Cuba Petroleo 5%.

Source: Roc Oil

The Nzanza-1 and Cinguvu-1 wells, both located in Block 15/06 some 350 km North-West of Luanda, were drilled in a water depth of 1,400 m and reached a total depth of respectively 3,008 m and 3,023 m in April 2010. Both wells encountered oil pay in sands of Lower Miocene age with good reservoir characteristics. During production tests, Nzanza-1 well produced an 18° API oil at rates above 1,600 barrels per day (b/d). Total, one of the partners in the block, indicates that a potential for future production wells in excess of 5,000 b/d per well, when associated to artificial lift, exists. At the Cinguvu-1 well, the production test, limited by surface facilities, reached a flow of 6,400 b/d of a 23° API oil. Eni (35%) is the operator of the block, and the other partners are Sonangol (20%), Sinopec Corp (15%), Total (15%), Falcon Oil SA (5%), Petrobras (5%) and Statoil (5%).

Source: ENI

Drilled in waters measuring 453 m deep, the Begonia-1 discovery well is located on the northeastern section of Angola's Block 17/06. This was the second discovery on the block; the first was the Gardenia-1 well.  Production tests of the discovery well, Begonia-1, flowed high-quality, 36-degree API oil at a rate of more than 6,000 barrels per day from the Miocene formation. Sonangol is the concessionaire of the block, and Total serves as the operator of Block 17/06 with 30 percent interest. Partners on the block include Sonangol Pesquisa e Producao with 30%, Sonangol Sinopec International Seventeen Limited with 27.5%, ACREP Bloco 17 with 5%, Falcon Oil Holding Angola with 5%, and PARTEX Oil and Gas with the remaining 2.5%.

On the same Block 17/06, the Canna-1 well, drilled in a water depth of 445 m, in the north-eastern area of the deep offshore block 17/06, discovered hydrocarbons in a reservoir of Miocene age and produced more than 5,000 barrels per day of high quality oil (33° API) during a production test.

An exploration well on the Cabaca South East prospect in Block 15/06 was drilled in 2010 and discovered oil in it. The Cabaca South East-1 well, located at a depth of 470 m, at a distance of 100 km from the coast, successfully reached its multi-target objective in the deepest levels of Miocene age, where oil bearing reservoirs, with a total of 450 m of gross thickness, was proven. During production tests, the well flowed high quality 34° API degrees oil at rates of about 7,000 barrels/day. The rates were constrained by the limited capacity of the surface facilities. Eni has a 35% working interest and is the Operator in Block 15/06, while Sonangol E&P is the Concessionaire. The other partners in the JV  are Sonangol Pesquisa e Produção (15%), SSI Fifteen Limited (20%), Total (15%), Falcon Oil Holding Angola SA (5%), Petrobras International Braspetro B.V. (5%) and Statoil Angola Block 15/06 Award AS (5%).

On the same block (15/06), the Mpungi-1 well, 120 km from the Angolan shoreline in 1,050 m of water, was drilled to a total depth of 2,300 m and encountered oil pay in both the Upper and the Middle Miocene sand reservoirs. During the production test of the main pool, the well flowed light oil at rates in excess of 6,000 barrels per day.

Denbury Resources 2011 May Corporate Presentation

- Oil and Natural gas production averaged 63,604 BOEpd compared to 53,125 BOEpd during the first quarter of 2010.
This 10,479 BOE/d of additional production is primarily attributable to:
 (1) incremental average production of 14,400 BOE/d from properties acquired and retained in the Encore merger, which is impacted by the fact that 2010 production only reflected a partial period in the first quarter of 2010
(2) increased tertiary production of 3,802 barrels per day ("Bbls/d") between the two quarters, offset by 
(3) a decrease of 6,750 BOE/d due to the sales of non-strategic Encore properties and our interests in Encore Energy Partners LP ("ENP") after the first quarter of 2010

Edison - First Quarterly Report at 31 March 2011

Canadian Oil Sands 2011 Raymond James Canadian Energy Conference

•100% of production is fully upgraded light sweet synthetic crude oil
•Furthermore all of production is unhedged, providing providing full exposure to crude oil prices;
•As a result, we are one of the most highly correlated investments toWTI crude oil.

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:

HIGHLIGHTS of the Quarter:
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.
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.
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.
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.
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.
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


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