Tuesday, February 22, 2011

BP intends to sell Southern North Sea assets to fuel growth

After tying up a $7.2 billion alliance with Reliance, BP announced today the intention of selling its interests in a number of operated oil and gas fields in the UK. The assets involved are the Wytch Farm onshore oilfield in Dorset and all of BP’s operated gas fields in the Southern North Sea, including associated pipeline infrastructure and the Dimlington terminal.

These divestments will allow BP to focus resources and investment on its diverse central North Sea, northern North Sea, West of Shetland and Norway assets and on successful delivery of its new major projects.

Trevor Garlick, Regional President, BP North Sea said: “The North Sea is a significant business for BP and we are currently investing here at the highest level for more than ten years, with four major new field development projects underway in the UK and two in Norway. The assets we intend to divest are of high value but find it difficult to compete for capital and resource within our North Sea portfolio. We believe they will attract earlier investment and be of greater value to a new buyer.

BP aims to complete the divestments around the end of 2011, subject to receipt of suitable offers and regulatory and third party approvals.




The equity being offered for sale by BP is as follows: 

Wytch Farm
All of BP’s equity which is:
  • 67.81% operated interest in the Wytch Farm oil field (covering the Frome, Bridport and Sherwood reservoirs)
  • 67.5% operated interest in the Beacon discovery
  • 67.5% operated interest in the Wareham oil field
  • 100% operated interest in the Kimmeridge oil field Southern North Sea 
  • BP’s interest in the Cleeton stream fields
  • BP’s interest in the West Sole stream fields
  • BP’s interest in the Amethyst field and
  • BP’s interest in the related infrastructure, including the Cleeton Field, the Southern North Sea Pipeline System (SNSPS) and the Dimlington terminal



BG and Ophir to drill ahead in Tanzania deepwaters after their third victory at Chaza-1

BG group and Ophir Energy are planning to continue with their exploration activities off Tanzania after their third consecutive success with Chaza-1 in Block 1. The earlier two wells, Pweza-1 and Chewa-1, both in Block 4, discovered significant quantities of gas in them.


Background: 

  • The JV comprising of Ophir Energy and BG Group are carrying out Tanzania’s first deepwater drilling campaign consisting of Blocks 1, 3 and 4. 
  • The blocks cover an area of about 28,050km2 area of the Mafia Deep Offshore Basin and northern portion of the Ruvuma Basin.



Exploration History:

  • Infill 2D seismic surveys were acquired in Block 1 in 2005 and Blocks 3 and 4 in 2006.  Further 2D and 3,500km2 of 3D seismic data across all three blocks were acquired in 2008 to mature a number of prospects to a drillable status.

  • First well, Pweza-1 on Block 4 discovered gas in 60m Eocene section
  • The next well Chewa-1 hit gas in a Palaeocene reservoir
  • Chaza-1 drilled on Block 1 hit gas in a secondary objective

Forward Plan:


  • The Joint Venture has contracted the semi-submersible rig Deepsea Stavanger to drill two to three wells during 2H 2010.  Following completion of the first drilling campaign a further 4,000km2 of 3D seismic data will be acquired during 1H 2011.
  • There are tentative plans to drill a second well in Block 1 targeting the Jodari prospect later this year.


Montenegro plans to explore the Adriatc Sea – 15 international companies express interest


On December 24, 2010 Montenegro invited international oil and gas companies to take part in its oil and gas exploration activity. About 15 international companies have expressed interest in searching for hydrocarbons offshore Montenegro where it hopes to cover its oil and gas needs from its own resources.

Highlights:
  •  Montenegro currently has no oil production
  • A two-year exploration concession is offered along with a 30-year license that would cover research as well as possible production from several locations thought to hold commercial deposits off its southern Adriatic coast.
  • The area to be included in the first exploration phase covers 4000 square kilometers.
  • The concession deal would include all phases of exploration, verification, development and exploitation of the deposits with a possibility to extend the concession duration.
  • The 15 international companies which have expressed interest are as follows: Novatek-Russia; NIS- Gazprom NEFT – Serbia, HESS Corporation –USA; Trajan Oil&Gas-Energian Oil&Gas Great Britain – Greece; Edison SpA – Itally; Geopartners Limited – Great Britain; TDE Services – Hungary; HELLENIC Petroleum – Greece Sterlin Energy PLC – Great Britain; ENI – Italy; Northern Petroleum PLC – Great Britain; Total – France; INA – Croatia; Statoil ASA – Norway I Premieroil – Great Britain.




  • The existence of basic preconditions for oil and gas in the Adriatic geological basin has been proven.






PA Resources reported 2010 results – production down 4.5%; 2010 Capex in-line with five-year forecast

PA Resources reported a production of 10,700 boepd in 2010, 4.5% lower to 2009. This is due to lower production recorded in company’s main producing Azurite field. The company did not reach the 2010 production target of 15,000 – 20,000 boepd as per the five-year plan. Revenue in 2010 up 5.4% from 2009.


Summary:


































Production down 4.5%


-          Total revenue for the Group during the fourth quarter amounted to SEK 697.7 million ($108.66 million). EBITDA for the quarter totalled SEK 437.7 million ($68.2 million).


































2010 Capex in-line with forecast, five year plans entails investments of approx. $1,000 million

Development Capex:
-          Azurite completion in Q2 2011
-          Didon North tie-back
-          Aseng field development
-          Progress Zarat field
Exploration Capex:
-          Drilling onshore Jelma in Tunisia and offshore Denmark on licence 12/06
-          Seismic study evaluation in the United Kingdom and the Netherlands.

-Net entitlement reflects West Africa production sharing contract and the impact of tax and royalty in Tunisia.



Marcellus, Eagle Ford and Permian Basin - The top three regions for Oil and Gas M&A in US

The top three regions - Marcellus, Permian and Eagle Ford, accounted for $37.5bn in transactions or 50% of the total reported for US in 2010. The year included significant conventional transactions along with higher profile unconventional sales. Strong crude prices, new reservoir plays and technological applications stimulated Permian Basin deal flow.The Barnett and Haynesville shale areas saw reduced acreage transactions. The Barnett numbers included Chesapeake’s VPP and EnerVest’s surprising acquisition of Talon. Overall, shale plays generally see more deal flow as plays advance (Eagle Ford & Marcellus) and less deal flow (Haynesville & Barnett) as plays mature.

New plays like the Niobrara and Avalon Shale should see additional deal flow in 2011.

BHP debuts in US shale business by purchasing Chesapeake's Fayetteville assets for $4.8 billion


BHP Billiton has made its first move into the US shale gas business with the acquisition of Fayetteville shale assets from Chesapeake for $US4.75 billion cash. Chesapeake's Fayetteville shale assets include approximately 487,000 acres of leasehold and producing natural gas properties located in Arkansas. This is the second largest position in one of the largest gas fields in the world. This acquisition will increase BHP Billiton's net reserve and resource base by 45%. These assets currently produce approximately 415 MMcf/d and include development options that will support substantially higher production over a 40 year operating life. The assets include 2.4 Tcf of proved reserves and 10 Tcf of total risked resource potential. The transaction also includes midstream assets with approximately 420 miles of pipeline.


It’s a material asset with room to grow:
The acquisition is consistent with BHP Billiton's strategy of investing in large, long-life, low cost assets with significant volume growth from future development. BHP said it is paying $1.77/Mcf of proved reserves which is consistent with the recent ExxonMobil’s acquisition of Petrohawk’s Fayetteville assets for $1.92/Mcf. BHP aims to triple daily production from the new asset as the field is developed, and plans to spend $800 million to $1 billion a year over 10 years to develop the field, BHP chief Michael Yeager said.


Unconventional gas to quench the thirst of US gas demand:



Chesapeake says, “Enormous value created through JV transactions – More to come in 2011”
This Fayetteville transaction is in line with Chesapeake’s 2011-12’s “25/25” plan, ie., reducing debt by 25% by selling assets, while increasing production by 25%. Chesapeake’s drilling capital to be invested in liquid plays will move from 10% in 2009 to 70% in 2012. In 2010, Chesapeake invested ~$5.0 billion of leasehold in liquids-rich plays which will be largely recovered from JV partners in next few years. In the past two years, Chesapeake has created enormous value through JV transactions and more to come in 2011…

After Encana's JV for shale gas, now Cenovus looks for JV partners to develop its oil sands resources


Cenovus, which was split from Encana in December 2009, would be following its predecessor that has formed joint ventures with Petro-China, CNPC and Korea Gas to develop unconventional resources. 
Cenovus Energy Inc is currently seeking a joint-venture partner to speed development of its Alberta oil sands holdings and boost the value of its reserves.


Cenovus’ oilsands projects overview:
-- Core oilsands projects: Foster Creek, Christina Lake and Pelican Lake; Cenovus holds approximately 800,000 net acres of existing bitumen leases within the Athabasca and Cold Lake areas and has additional 652,000 net acres on the Cold Lake Air Weapons Range.
-- Combined production of Foster Creek, Christina Lake and Pelican Lake was 82,527 BO/d net to Cenovus in Q4-2010.
-- Foster Creek in 2011F: $350 - 400 million of capital; 2.1-2.3 SOR; $11.10-11.85/bbl operating cost; 110-120 gross strat wells; Phases F, G and H construction ramp up; Expects production of 56,000 BO/d in later 2011.
-- Christina Lake in 2011F: $350-400 million of capital; 2.4-2.7 SOR; $18.65-19.40/bbl operating costs; 50-60 strat wells; Continue construction on Phase C and D; Expects net production of 16,000 BO/d in later 2011.

-- Pelican Lake: $175-200 million of capital; $14-15/bbl operating cost; 40-45 gross strat wells; Start drilling infill patterns; Potentially accelerate drilling program.
-- As of December 31, 2010, Proved bitumen reserves - 1,154 MMBO; Proved plus Probable bitumen reserves - 1,677 MMBO.
-- The increase in reserves is mainly attributed to the approved expansion of the Foster Creek development area and increased recovery due to advancements in technology, such as wedge wells, and improved reservoir performance.
-- In addition to the expanded reserves numbers, there was a significant increase to the company’s bitumen economic contingent resources in 2010, mainly attributed to the assessment data collected from stratigraphic (strat) wells. Best estimate bitumen economic contingent resources at year-end 2010 were 6.1 billion bbls, a 13% increase over 2009.
-- 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.

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