Goodrich Petroleum Corporation shifting towards Oil and Liquids development from Natural Gas; Allocated 70% of its 2011 Capital Program to Oil Exposure (62% Eagle Ford Shale Trend)!!

Goodrich Petroleum increased 2011 capital program to develop the company's new acreage in the Eagle Ford Shale, as the company joins the shift towards oil and liquids development. Goodrich Petroleum increased its total 2011 capital budget by $10 million, from $225 million to $235 million.  The company increased the allocation to the Eagle Ford Shale formation by $45 million, from $100 million to $145 million.

Eagle Ford Shale

Goodrich Petroleum has been focusing its attention and capital over the last few years for developing the company's natural gas assets, including the Haynesville Shale and Cotton Valley formations in East Texas and North Louisiana.

In April 2010, faced with low prices and weak fundamentals for natural gas, the company decided to diversify away from this commodity, and purchased 35,000 net acres in the Eagle Ford Shale in Texas. The acreage is located in La Salle and Frio County, which is considered the oil window of the play. During the fourth quarter of 2010, the company drilled 4 gross or 3 net wells into the Eagle Ford Shale. Goodrich Petroleum is operating two rigs on its Eagle Ford Shale acreage and expects to drill from 22 to 26 wells on its 40,000 net acres.

Recent M&A Deals in Eagle Ford Shale:

Source: Derrick Petroleum E&P Transactions Database

Haynesville Shale

Although Goodrich has been focusing in the Haynesville Shale, the company is deemphasizing development here in 2011 in favor of more oil focused properties in its portfolio. In 2010, the company spent approximately 56% of its total drilling budget, or $156 million, to drill 18 net wells into the Haynesville Shale. In 2011, the company plans to spend only $90 million to drill nine net wells on its Haynesville Shale properties. One area of focus for Goodrich Petroleum in 2011 will be in the Shelby Trough area of East Texas, where the company has 28,000 net acres under lease. The company drilled its first Haynesville Shale well here, and also plans development of the Bossier Shale in 2011. This formation lies just above the Haynesville Shale and produces natural gas.

Recent M&A Deals in Haynesville Shale:

Source: Derrick Petroleum E&P Transactions Database

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EnCana seeks JV partner for development of unconventional gas in British Columbia

Encana Corporation has engaged RBC Capital Markets and Jefferies & Company Inc as its exclusive agents in connection with the proposed sale and/or joint venture of selected interests of the company in Northeast British Columbia. The company’s Greater Sierra area has been divided into two areas of opportunity - an asset sale and a joint venture. A portion of the company’s holdings are also being offered for joint venture.

Greater Sierra: The acquisition area for sale includes all lands, production and related infrastructure. The joint venture area is available for partnering with Encana on its existing production and infrastructure and future development plans.

Acquisition area:
-- Jean Marie: 1,500 net sections of land (95% WI)
-- 73 MMcfe/d (97% gas) - sales October 2010
-- 593 undrilled booked locations
-- Shale Gas: 35 net sections of land (93% WI)
-- 36 Horizontal locations in Muskwa, Otter Park and Evie.

Joint venture area:
-- Jean Marie: 1,281 net sections of land (90% WI)
-- 129 MMcfe/d (96% gas) - sales October 2010
-- 856 undrilled locations (575 booked + 281 unbooked).

Horn River: Offered for joint venture
-- 52 net sections of land (100% WI)
-- 120 Horizontal locations in Muskwa, Otter Park and Evie.

Earlier on 9-Feb-2011, PetroChina and Encana have signed a Co-operation agreement, that PetroChina would acquire a 50% interest in Encana’s Cutbank Ridge business assets in British Columbia and Alberta at a consideration of C$5.4 billion (US$5.451 billion). Under the Co-operation agreement, the two companies would establish a 50/50 Joint Venture (JV) that would ambitiously grow natural gas production from the Cutbank Ridge lands for years ahead.

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Encana acquires liquids-rich Duvernay Shale acreage for C$1,600/acre.. Encana turns focus to gas liquids as low natural gas prices persist.

In recent months, Encana has assembled about 190,000 net acres in the Simonette and Kaybob areas of the Duvernay shale in Alberta, which it acquired for about $300 million or an average cost of about C$1,600 per acre. This exciting new play has the potential to add significant liquids production to the Canadian division and is a promising complement to the company’s liquids rich acreage in the Montney where it has 495,000 acres of land with liquids potential on it, in addition to 380,000 net acres in the Alberta Deep Basin area.

Michael Graham from Encana said, “The Duvernay play seems similar to the Eagle Ford and that there we could go from sort of a dry gas window into a liquids-rich window. Bulk of our acreage, probably 2/3 of our acreage, we think certainly will be in the liquids-rich area.” Encana plans to drill 3 or 4 horizontal wells into it and then the company may consider joint venture partners for Duvernay Shale. Recently, Encana struck a C$5.4 million JV with PetroChina on its Cutbank Ridge project. The snapshot of this deal is as follows:

Source: Derrick Petroleum E&P Transactions Database


Encana shifts focus to gas liquids!!
Encana delivered solid cash flow and grew natural gas production by 4% per share in the first quarter of 2011. Cash flow was US$955 million, or $1.29 per share – down 17% largely due to lower natural gas prices compared to the first quarter of 2010.


It’s part of a strategic shift that will see Encana focus on gas deposits with a higher proportion of condensates and light oil. Because natural gas liquids receive premium prices compared to crude, companies like Encana are using the dollars to offset the lower gas price and continue with ambitious unconventional gas drilling.


“By bringing on more oil and NGL production and stripping out more NGLs from our natural gas stream, we expect to significantly increase the weighting of liquids in our portfolio, capturing more value and enhancing returns,” CEO Randy Eresman said on a conference call.

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Global E&P transactions 2010 Review is available for free.. Last 7 days to avail it. If interested, do write to anitha.bharathi@derrickpetroleum.com

Abraxas Petroleum Built Around Solid Conventional Assets; Expanded Capital Program of $60 million for 2011; Most of its capex is going to producing more oil!!

Abraxas reported 2010 year-end reserves totaled 26.6 mmboe up 7% over 2009 despite selling 9% of proved reserves in our divesture program. The company operates wells in the Bakken, West Texas, South Texas, and Canada. Abraxas has outside operated wells in the Bakken. Most of its capex is going to producing more oil. Its goal this year 2011 is to try to get to a 50% oil/gas mix. In the Eagle Ford, it would like to accelerate its partnership with the JV. Last year it had asset sales of $34 million (non-core and non-operated). The money is used for this year's capex and to pay down debt. It would like to eventually get 90% of its assets operating.

Source: Derrick Petroleum E&P Transactions Database

Currently, Abraxas has south and West Texas conventional assets, Eagle Ford and northern Rockies and Canada conventional resource plays, including the Bakken and the Niobrara.

Abraxas has 8,333 acres in Eagle Ford. This location, part of a $25 million equity investment, is 43% oil, 35% gas/condensate, and 22% gas window. The company also has approximately 14,000 acres in the Niobrara shale, with 3,800 gross acres leased and 11 producing wells. Its holdings are in the same area with Chesapeake (CHK) and EOG Resources. In the Southern Alberta Bakken it has approximately 10,000 acres leased. Abraxas also has a small holding in the Pekisko Fairway in Canada.

Abraxas' Rocky Mountain assets has 7.2 MMBoe in proven reserves; 63% of this is proved developed, 82% is crude oil, with 1063 Boepd of production, 900 gross producing wells, and 90,362 gross acres. Primary locations here are the Willston Basin, Powder River Basin, Green River Basin, and Unita Basin.

The Permian Basin has 5.6 MMBoe of proved reserves; 66% proved developed; 70% is natural gas. There is also 1254 Boepd of production; 237 gross producing wells; 36,064 acres, The primary producing sub-basins are the Delaware Basin and Eastern Shelf.

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The Gulf Coast has 9 MMBoe of proved reserves; 38% is proved developed; 91% is natural gas; 1044 Boepd of production. This area has 74 gross producing wells, and Abraxas has 11,414 acres in the area. The primary sub-producing basin is the Onshore Gulf Coast.

This company looks to be another oil and gas exploration and production company with great assets that, in time, could turn into something great if everything works out. It is well positioned, especially if oil gets up to around a $100 a barrel and stays there for a while.

Rosneft and Lukoil team up to jointly explore Arctic shelf

Rosneft will open its licencing zones to Lukoil off of Russia's oil-and-gas-rich Arctic Yamal peninsula.

Given the successful development of their mutual cooperation, and with the goal of raising the profitibility of existing projects, Rosneft and Lukoil have agreed to join forces in the following areas:

• Oil exploration & development, development and transportation of hydrocarbons in the license areas of the Nenets Autonomous District;
• Exploration in the areas licensed to Rosneft on Russia’s Arctic shelf and development of fields that are already open, within the framework of current Russian legislation;
• Development of the market for domestic petroleum products, petrochemicals, gas processing and base oils;
• Joint marketing of associated and natural gas from fields in the Bolshekhetskaya and Vankor zones;
• Joint deliveries of petroleum products, liquefied gas and petrochemical products to the distribution and production facilities of both companies;
• Development of solutions for improving production efficiency for petrochemical products, oil and gas, in Russia and abroad;
• Use of existing logistics infrastructure, including transshipping facilities for crude oil, refined pretroleum products and petrochemical products that are for export; and development and execution of transportation infrastructure projects for petroleum products, including the construction of a product pipeline interconnecting with the "Moscow product ring," and the "South” project.

This marks Lukoil's first offshore deal in Russia since launching the Korchagin oil field in the Caspian Sea last year, Lukoil is also venturing out of Russia, actively seeking US shale gas opportunities (Lukoil planning shale JVs in 2011). Rosneft has been aggressively partnering with foreign majors including BP, Chevron and ExxonMobil for developing its offshore fields.

Key projects of Rosneft and Lukoil:

1. Joint transportation of gas from the Vankor field and the Bolshekhetskaya Depression.
On 12 April 2011, Lukoil and Rosneft signed an agreement, under which Rosneft will independently transport gas from the Vankor field and adjoining license areas to Lukoil’s infrastructure. In turn, LUKOIL will transport gas through its facilities to Gazprom’s gas transportation system. At present, Lukoil and Rosneft are building their own gas pipeline sections and infrastructures.

2. Priazovneft
Rosneft and Lukoil each own a 42.5-percent stake in Priazoneft.  The Administration of the Krasnodar Territory owns the remaining 15 percent. Priazovneft is developing the Temryuksko-Akhtarsk license area on the shelf of the Azov Sea. In 2008, the “New” oil field was opened. The field’s recoverable reserves are: Oil: C1 - 0.87 million tonnes; C2 – 2.25 million tonnes; Gas: C1 – 319 million m3; C2 - 820 million m3. Seismic work is currently underway.

3. Caspian Oil Company
Rosneft and Lukoil each own 49.9 percent of the Caspian Oil Company; Gazprom owns the remaining 0.2 percent. In 2008, the West-Rakushechnaya field in the north-Caspian area was opened. In 2010, an assessment well was drilled at the Ukatnaya structure. Open non-industrial deposit.http://docsearch.derrickpetroleum.com/research/q/Rosneft.htmlhttp://docsearch.derrickpetroleum.com/research/q/Rosneft.htmlhttp://docsearch.derrickpetroleum.com/research/q/Lukoil.html

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

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

Operational update during the Quarter:

GLNG 

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

Carnarvon Basin

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

Bayu-Undan / Darwin LNG

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

Indonesia

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

Key Exploration Activities:

Source: Derrick Petroleum Planned Exploration Wells Database

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Canadian assets worth $7 billion on the market, contributes 15% to global deals in play

Source:Global E&P Transactions 2010 Review

Canadian oil sands reported $12.8bn in asset sales, corporate acquisitions and joint ventures for 2010. The Montney (BC & Alberta)  recorded $2.3bn in trades or 5x times 2009 total and twice 2008 deals less Shell-Duverney. The number of oil sands deals went up, but the average deal value decreased significantly due to the 2009 Petro-Canada Suncor $18bn merger. Bakken & Saskatchewan plays totalled $2.6bn. The Montney and Bakken unconventional plays made up ~10% of the Canadian transactional market place.

Canadian assets worth $7billion on the market in Q1 2011

Source: Derrick Petroleum E&P Transactions Database

$7bn of assets on the market, corporate acquisitions and development assets worth $5.46 bn in Q1 2011. 


Key assets on the market

Source: Derrick Petroleum E&P Transactions Database