Friday, April 29, 2011

Australian company- Strike Energy acquires Eagle Ford acreage!! May be for $20 million?? Strike increases exposure to OIL

Strike Energy is securing a substantial position in the Eagle Ford shale play. In the last two to three years the Eagle Ford shale play in Texas has emerged as one of the most attractive gas and oil shale plays in North America. Strike has taken a 27.5% position in the Eagle Ford shale play through a joint venture with four Texas-based oil and gas exploration and production companies. This Eagle Ford shale play is located northwest of Strike’s existing production and exploration activities focussed on the gas and condensate rich Wilcox trend.

Leasing activities by the operating partner in the newly formed joint venture have been progressing for some time. The total acreage under lease currently stands at approximately 8,500 acres, with Strike’s net position about 2,300 acres. The leasing is focussed within the interpreted oil fairway where drilling by other operators has resulted in published projected recoveries in the range of 450,000 to 1,000,000 barrels of oil equivalent per well based on 160 acre spacing. Similar recoveries, if extended onto leases secured by the Eagle Ford Joint Venture to date, provide a target potential of 7 to 14 million barrels oil equivalent from Strike’s current net acre position.



Significant Oil Window Transactions in 2010



How much Strike would have shelled out of its pocket for this package??
• The acreage is situated primarily within the oil window of the Eagle Ford.
• Strike’s net acreage position of approximately 2,300 acres, which based upon reported Eagle Ford shale recoveries, has a target potential of 7 to 14 million barrels of oil equivalent.

The 2010 Eagle Ford oil window transactions have set an average acreage metric of ~8,000/acre. Based on this acreage metric of $8,000/acre in oil window, this transaction could be valued at $18 million. In addition, the average resource potential of 10 mmboe associated with this transaction can be valued at $2/boe, which leaves the total value for the resources at $20 million.

Either ways, the value of the acreage been acquired by Strike is around $20 million!!

Thursday, April 28, 2011

Generic Comparison - Reserves/Production


2010 information Coming Soon.....

Conocophillips - 1st Quarter 2011 Conference Call

$1.82 adjusted EPS - 1.7 MMBOED production - 89% refining utilization - $4 billion cash from operations excluding working captial
http://docsearch.derrickpetroleum.com/files/12146/Conocophillips%20-%201st%20Quarter%202011%20Conference%20Call.pdf

Range Resources 2011 April Company Presentation

25% increase in proved developed producing (PDP) reserves - Seven Years of Double-Digit Production Growth - Since 2007, production has increased 54%, while well count has decreased 43%
http://docsearch.derrickpetroleum.com/files/12141/Range%20Resources%202011%20April%20Company%20Presentation.pdf

Helix - First Quarter 2011 Presentation


First quarter average production rate of 160 Mmcfe/d (63% oil) - Q2 production through April 22 averaged approximately 140 Mmcfe/d (~67% oil) - Phoenix production averaged 10.3 MBoe/d for the same period  - Little Burn on track for first production in July (est. 4,500 bpd net)

http://docsearch.derrickpetroleum.com/files/12128/Helix%20-%20First%20Quarter%202011%20Presentation.pdf

KKR acquires Carrizo’s Barnett assets for $104 million. Production is valued at $10,000/mcfe while peers value at $12,500/mcfe- How?

Carrizo Oil & Gas agreed to sell substantially all of its Barnett Shale Tier 1 properties to KKR Natural Resources, the partnership formed between an affiliate of Kohlberg Kravis Roberts & Co LP (KKR) and Premier Natural Resources, for $104 million. The properties that Carrizo are selling are largely in Parker County and represent only a small fraction of the company's Barnett Shale production, which equals about 100 million cubic feet of natural gas per day, said Richard Hunter, Carrizo's director of investor relations. The properties do not include Carrizo's highly productive, 22-well padsite at the University of Texas at Arlington, Hunter said.
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Carrizo President and CEO S. P. "Chip" Johnson, IV commented on the sale, "Our plan to focus our Barnett Shale development drilling on our Core properties in Tarrant County and our success in the initial development of our liquids-rich Eagle Ford Shale and Niobrara resource plays made our Tier 1 Barnett property a candidate for divestiture.

"With their significant proved developed producing reserve component in a reservoir we know well through our current operations in the region, the assets are a great fit for our KKR Natural Resources platform. We are pleased to add these assets to our oil and gas portfolio and remain excited about the opportunity to grow the KNR platform through the acquisition of additional oil and gas properties in North America," said Jonathan Smidt, a Member at KKR and a senior member of KKR's Energy and Infrastructure business.

KKR has been active acquiring conventional and unconventional assets in 2010. The following snapshot shows the deals that KKR clinched in 2010.


Acquisition metrics including probable reserves
The approximately 13,000 acres being sold include 75 gross (58.5 net) wells currently producing at an approximate gross rate of 15.7 MMcfe per day (8.3 MMcfed net). Estimated proved reserves associated with the divested properties amount to 122.4 Bcfe, 55% of which are proved undeveloped, as determined by Carrizo's third party engineers at year-end 2010.


The probable reserves associated with this acquisition are approximately 100 Bcfe. The resource potential for the acquisition based on 58.5 net locations and 1.8 Bcf/well is estimated to be approximately $105 Bcf.

The probable reserves can be valued at $17 million based on $1/boe. The rest of the deal value could be assigned for proved reserves which gives the production metrics to be ~$62,000/flowing barrel (~$10,000/flowing mcfe) whereas peers value the reserves or production at $75,000/flowing barrel (~$12,500/flowing mcfe).

PTTEP to invest $45 billion to boost reserves; Focus to be on S. America and Africa

PTTEP could spend $45 billion to boost petroleum reserves over the next 10 years and may consider a share issue to fund the investment.

PTTEP expects its petroleum reserves to reach 3 billion barrels of oil equivalent (boepd) by 2020. 'In the next 10 years, PTTEP will need up to $45 billion. Company is short of about $11-12 billion, may look at financial options to raise more funds.

PTTEP to focus on South America and Africa

PTTEP has petroleum reserves of just 1.1 billion boepd, Company may buy more assets overseas to boost reserves and meet the country's energy needs. PTTEP is exploring business opportunities in new areas of South America and Africa, with a view to turning the areas into the company's third business pillar, following Thailand plus Burma and Australia plus Canada.

The company's success in collaborating with Norway's national oil company Statoil in the Kai Kos Dehseh (KKD) oil sands project in Canada late last year is the inspiration behind further expansion of oil and gas exploration and production overseas.

PTTEP's existing operations were now very strong and stable. Key oil and gas exploration and production in the Gulf of Thailand and Burma, comprises many fields, such as Thailand's Sirikit, Bongkot and Arthit and Burma's Yadana and Yetagun.

PTTEP is making its presence felt in Australia and Canada. Production at the Montara field off Australia is expected to resume by the end of this year, while Canada commenced production early in the year.

The company is looking to invest in other Canadian exploration and production projects with Statoil, with the two businesses having just inked an agreement to cooperate in this area.

PTTEP has set a target to have a production capacity of 900,000 barrels of oil equivalent per day [boe/d] by 2020. The production sites they have right now will produce half of the target by that year. Therefore, company would look for new projects to help us accomplish the goal.

The company presently aims to produce and sell nearly 300,000boe/d of oil and gas, while the KKD project is expected to have a capacity of 150,000boe/d by 2020. KKD is scheduled to produce 8,000boe/d by the end of this year, rising to 80,000-100,000 within the next five years.

The company president said PTTEP had divided its projects into three groups: those that are already generating revenue; those that are going to generate revenue; and projects in which it has to invest for the exploration stage.

The new projects PTTEP is seeking may be greenfield sites or existing projects. The latter type of deal is more likely to be concluded, as the company needs projects that can generate revenue immediately, Anon (President) said.

"We're looking for many deals in South American countries such as Brazil, and some in Africa. These are unfamiliar areas for PTTEP, so we have to consider everything carefully. We need partners if we want to grow in these regions, compete with existing players and learn new things in which we are not experts," he said.

Wednesday, April 27, 2011

Pioneer investing $1.6 billion for 2011 drilling program (69% for Spraberry); Aims for 18% compounded annual growth for 2011-2013

Pioneer's capital program for 2011 totals $1.8 billion, consisting of $1.6 billion for drilling operations and $0.2 billion for vertical integration and facilities. The 2011 drilling capital of $1.6 billion is focused on oil and liquids-rich drilling, with 75% of the capital allocated to the Spraberry and Eagle Ford Shale plays. The company is projecting 18% compounded annual growth for 2011-2013.
Spraberry

Pioneer estimates that the company will drill approximately 700 wells into the Spraberry formation during 2011. This will increase its net production to between 38,000 boepd and 44,000 boepd by the final quarter of 2011. The company plans to substantially increase the number of rigs drilling the Spraberry formation in West Texas over the course of 2011.

“Our most recent drilling program called for 30 rigs to be operating in the Spraberry during 2011, but we now plan to increase the rig count to 35 rigs by mid-year,” revealed Pioneer Chairman and CEO Scott D. Sheffield.

Other companies working the Spraberry include Cheapeake Energy, which has 680,000 net acres in the Spraberry and three other plays in the Permian Basin.



In 2011, Pioneer Natural Resources will ramp up its development of the Eagle Ford Shale as well. The company will drill 70 gross wells within its joint venture area with Reliance Industries. In 2010, the company drilled 26 wells into the Eagle Ford Shale. The company estimates that this development will increase production from the Eagle Ford Shale to between 10,000 and 13,000 BOEpd in 2011, triple the level of production in 2010.

Pioneer holds 310,000 gross acres in the Eagle Ford Shale, which is growing in popularity among producers because it holds natural gas and oil.

Pioneer Natural Resources plans continued exploitation of its large acreage position in the Spraberry trend in 2011, along with increased development of the Eagle Ford Shale as the company seeks to boost its oil and liquids production. This accelerated drilling program, which is planned to ramp up further in 2012 and 2013, is expected to increase the company’s current compound annual production growth target of more than 15 percent for the 2011 through 2013 period.

RWE to sell 20% interest in Clipper South gas field in UK North Sea


RWE Dea is planning to sell down 20% interest in the Clipper South gas field, UK North Sea. The gas field is located on Blocks 48/19c, 48/19a and 48/20a and straddles Production Licenses P008 and P465.
Highlights
 -- The blocks has reserves of about 180 Bcf.
-- The gas at Clipper South is located in a tight Permian Rotliegend reservoir which contains approximately 500 Bcf of gas in place.
-- The development plan for Clipper South field was approved by the Department of Energy and Climate Change in March 2011.
-- The field will be developed by five horizontal wells, each containing up to six hydraulic fractures, connecting to a wellhead platform and then piped to the Lincolnshire Offshore Gas Gathering system (LOGGS) PR platform.
-- The first gas is expected in the Q1-2012, and the production is anticipated to reach a maximum rate of 100 MMcf/d.
-- Current ownership of the field: RWE (50%, Operator), Bayerngas (25%) and Fairfield Energy (25%).






























Nexen joins Marathon to explore Poland shale gas resources.. Exxon seeks partners for its shale gas licenses in Poland.

Marathon Oil Corporation has signed an agreement with Nexen under which Nexen will acquire a 40% working interest in 10 of Marathon's concessions in Poland's Paleozoic shale play. This partnership provides not only financial risk mitigation but combines the extensive unconventional drilling and completion experience of Marathon and Nexen to fully evaluate the potential of these concessions.

Marathon currently holds an interest in 11 concessions in Poland, encompassing 2.3 million acres. The shales are Lower Paleozoic and located at depths of between 8,000 and 13,000 feet. Marathon plans to acquire 2D seismic during the first half of 2011, potentially followed by the drilling of one to two wells in the fourth quarter of 2011 and seven to eight wells during 2012. Marathon will remain operator of the 11 concessions.

Poland shale gas- A Game Changer??
Poland's Lower Paleozoic shale play may be the largest and most significant opportunity for unconventional gas in central Europe and is evolving rapidly in the wake of successful shale plays in North America. Natural gas demand in the large and growing European market is approximately 50 to 55 billion cubic feet per day, with imports from outside the European Union accounting for approximately 50% of total gas requirements.


In the last three years, Poland had issued more than 70 licenses for shale gas exploration which could make Europe less dependent on supplies from Africa and Russia. However, extraction of resources in Europe is more complex than in the US because of population density. Poland has 5.3 trillion cubic meters of shale natural gas, equal to more than 300 years of the country’s annual gas consumption, the Energy Information Administration of the U.S. Department of Energy said in a report. The companies are now drilling in Poland, but it will take at least a year to determine if shale gas production will be commercially feasible.

Lots more available on Poland table??
Poland’s shale resources are being targeted by Majors like ExxonMobil, Chevron, ENI, ConocoPhillips, Marathon, and Talisman as well as small independents like San Leon Energy, Realm Energy and BNK Petroleum. The following tables show the list of Poland shale gas deals.


As the companies' interest towards shale gas exploitation in Poland is heating up, few companies are calling for partners to give them a helping hand. Below is the list of Poland assets available for sale!!



Tuesday, April 26, 2011

Quicksilver - April 2011 Presentation


Growing production 20% - Maintaining low full cycle unit cost structure to maximize margins - Commercializing Horn River natural gas resource development - Validating Niobrara and Exshaw exploratory opportunities for oil
http://docsearch.derrickpetroleum.com/files/12106/Quicksilver%20-%20April%202011%20Presentation.pdf

W&T Offshore acquires Permian assets for $366 million

W&T Offshore Inc has agreed with private sellers to acquire approximately 21,900 gross leasehold acres (21,500 net acres) in the West Texas Permian Basin for a purchase price of $366 million. The reserves are over 91% oil and natural gas liquids. At January 1, 2011, estimates of proved reserves to be acquired are approximately 27 mmboe; and estimates of proved and probable reserves to be acquired are approximately 53 mmboe. The current wells produce around 2,800 barrel equivalents per day. Since the effective date of Jan 1, 2011, the proposed acquisition, production has increased from about 1,900 barrel equivalents.

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The sellers have three active rigs drilling in the field and ongoing completions are being made on the new wells. There is significant upside potential in the acquisition with hundreds of proved undeveloped and probable well locations. Capital expenditures associated with planned development activities for these properties for the rest of 2011 are currently estimated at $35 to $40 million.

Permian Basin Acquisition Metrics




Source: Derrick Petroleum Global E&P Transactions 2010 Review
(Note: 2010 M&A report is available for free- If interested in getting a copy of the same, please write to anitha.bharathi@derrickpetroleum.com)

In 2010, the Permian Basin received the highest production multiples, $80,000-$110,000 per flowing barrel. The current transaction values the proved reserves at $288 million ($10.67/BOE or ~$103,000 per flowing barrel equivalent) and the probable reserves at $78 million ($3/BOE).

With the reserve life index to be 26 years, the $/proved reserves going at $10.67 is certainly high. The metrics reflect the high oil price and the buyers are willing to pay for oil reserves; future drilling opportunities, behind pipe potential and reserve quality.

Following is the list of significant deals in Permian Basin in the last three quarters.

Source: Derrick Petroleum E&P Transactions Database

Another private company, Element Petroleum LP has put its Wolfberry assets for sale. The following slide shows the overview of the package:



Monday, April 25, 2011

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.
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:

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:








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

Friday, April 22, 2011

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.
















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.
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.


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

Thursday, April 21, 2011

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:

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.
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:

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



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


$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

Parex acquires remaining interests in four Colombian blocks from Remora Energy for $255M

Parex Resources Inc has entered into a definitive agreement to acquire Columbus Energy Sucursal’s (a wholly owned subsidiary of Remora Energy) 50% share in four Llanos Basin blocks for total consideration of $255 million, subject to customary adjustments. Parex already holds the remaining 50% interest in the blocks. The acquisition is effective January 1, 2011 and is expected to close no later than June 29, 2011.



Acquisition Highlights :
-- Increases working interest from 50% to 100% in each of the four Llanos basin blocks namely, LLA-16, LLA-20, LLA-29 and LLA-30.
-- Block LLA-16: This block covers an area of 78,772 net acres and holds Kona multizone light oil discovery (35 degree API oil). In 2011, Parex expects to drill six appraisal/development wells on Block LLA-16 at the Kona discovery, of which two wells have been drilled and cased to date. Effective, March 31, 2011, it holds Proved Reserves of 1.066 MMbbl, 2P Reserves of 5.2 MMbbl and 3P Reserves of 9.6 MMbbl. Current production from the discovery is 1,160 BO/d. The block also holds few exploration prospects - Java, Sulawesi, Moragogi and Merida.
-- Exploartion activities are on going in Block LLA-20, LLA-29 and Block LLA-30.
-- The GLJ Report, effective March 31, 2011, included future development capital of $24.2 million for 2P reserves and $34.6 million for 3P reserves.
-- Acquisition metrics (excluding future development capital): 2P Reserves - $49.42/BOE and 3P Reserves - $26.48/BOE.
-- As of December 31, 2010, NPV-10 of 3P Reserves - $239.105 million and NPV-10 of 2P Reserves - $149.321
million.





















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