Encana/Petrochina Montney JV collapses. Encana in the hunt for new JV partners

Encana is looking for new partners to develop its Cutbank Ridge assets following the collapse of its C$5.4 billion deal with PetroChina. The companies were unable to achieve substantial alignment with respect to key elements of the proposed transaction, including the joint operating agreement.

The assets in the terminated JV included the majority of Encana’s Montney, Cadomin and other natural gas assets, on a portion of the company’s British Columbia and Alberta lands. According to Encana, the Cutbank Ridge assets hold reserves of: Proved-1.8 Tcfe, Probable-0.6 Tcfe and Possible- 0.4 Tcfe; and Contingent resources of 3.1 Tcfe, on a best estimate case.

Foreigners’ invasion into Montney Shale:

The Encana-PetroChina JV was the largest amongst several recent deals in the Canadian Shales. Following are the few snippets of the other significant Montney deals:

• In early June 2011, Petronas agreed to form a Montney JV with Progress Energy Resources, to develop the Altares, Lily and Kahta shale gas assets in north-eastern British Columbia and acquire 50% of Progress’ interest in the three areas, for a total consideration of C$1,070 million.
• Recently, Talisman clinched back-to-back Montney JVs with Sasol. In December 2010, Sasol agreed with Talisman to acquire a 50% interest in the Farrell Creek assets located in the Montney basin for C$1,050 million. In March 2011, Sasol agreed with Talisman to acquire a 50% interest in Cypress A acreage, located in the Montney basin for C$1,050 million.
• In early 2010, Kogas agreed with Encana to spend C$565 million over three years to explore new shale gas reservoirs in largely undeveloped areas of Encana's land, in the Horn River and Montney formations.

This is an interactive chart to compare the Montney deals since 2007.

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Other divestiture/JV plans from Encana

In April 2011, Encana announced plans seeking investors in two joint ventures on Encana assets outside Cutbank Ridge in northeast British Columbia – one on undeveloped Horn River shale lands and the other in the company’s Greater Sierra resource play. Discussions are well underway on these potential transactions, as well as on a potential divestiture of producing assets in the northern portion of Greater Sierra. Encana expects that these transactions, plus other divestitures and joint venture pursuits that the company has initiated, will generate proceeds and joint venture investments in 2011, of between $1 billion and $2 billion, a level that exceeds Encana’s net divestiture target of $500 million to $1 billion for 2011.

Potential buyers of Encana’s assets

The termination of this Encana-Petrochina JV opens doors for other companies who are interested in shale gas. These companies could be ExxonMobil, ConocoPhillips and other Asian investors like Kogas, Mitsui, Mitsubishi, CNPC, CNOOC, etc.

Source Documents

Encana may 2011 corp presentation

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Rbc capital markets marketing flyer

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Statoil Eyes $32 Billion Investment over the next two years; Plans to increase production to above 2.5 mmboepd over the next 10 years

Norwegian oil giant Statoil ASA will spend $32 billion on exploration and production over the next two years as it aims to ramp up production to above 2.5 mmboepd over the next decade. Statoil, which produces about 80 percent of Norway’s oil and gas, is expanding abroad to maintain output and boost reserves amid dwindling production from aging North Sea fields. The company plans to double oil output in Brazil in less than a decade, and is seeking to add to its portfolio.

In addition to continued focus on production from operations on the Norwegian Continental Shelf (NCF), Statoil said the increased output will come through strengthened positions in the Gulf of Mexico, Brazil, Angola, the Caspian region and Arctic Sea, while also stepping up production of shale gas and liquids. "The NCF remains a very attractive and globally competitive province for future oil and gas activities," said, Statoil Chief Executive, Helge Lund.

As well as conventional oil and gas operations, Statoil is developing the Eagle Ford shale field in southwestern Texas through a joint venture with Talisman Energy Inc. and the Marcellus shale region together with Chesapeake, which includes northern West Virginia across Pennsylvania and parts of New York.

View the Eagle Ford Shale deal snapshot here:

Source: The Derrick E&P Transactions Database
Growing Market:
Statoil will “benefit from our strong gas position in a growing gas market,” said Lund. Oil and gas from sites along the Norwegian coast will account for about 1.4 million barrels of oil equivalent a day in 2020, the company estimated. The international portfolio, which will also include non-Norwegian Arctic sites and the Caspian region, is forecast to produce about 1.1 million barrels of oil a day, Statoil said.

The company will spend $16 billion on exploration, drilling and production in 2012, on par with what it will spent in 2011. Statoil expects to drill 20 to 25 high-impact wells in the years 2011 to 2013.

The company in February 2011 forecast output will grow on average 3 percent in each of the next two years, to about 2 million barrels of oil equivalent a day, below a former target of 2.06 million to 2.16 million barrels. "The positive is that they are announcing growth internationally to 1.1 million barrels in 2020, and they are quite specific about that, given that they haven't quite delivered recently," said Trond Omdal, an analyst at Arctic Securities.

Exploration would be about $3 billion this year, up from about $2.5 billion in 2010 when the company trimmed spending in the wake of the global financial crisis, Tim Dodson, head of the company's exploration arm, told Reuters.

Reserves have been in decline, with a replacement ratio of just 87 percent in 2010 and 73 percent in 2009. Oil and gas production in Norway, which accounts for about half of the company's total output, is expected to be above 1.4 million boed in 2020, the level it produced in 2010.

Statoil's Exploration Portfolio for 2011 and 2012:

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Source Documents:

Statoil 2011 positioned for long term growth

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Hupecol to divest La Cuerva interest

Scotia Waterous (USA) Inc has been retained as exclusive financial advisor by Hupecol to explore alternatives to optimize the company’s portfolio, including the divestment of Hupecol’s interest in the La Cuerva block in Colombia’s Llanos Basin.  

Highlights of the Offering:

1) La Cuerva block in the Eastern portion of the Llanos Basin consisting of ~47,950 gross acres

• 100% WI, and operated by Hupecol
• Contract consists of an 8% royalty
• Contract does not contain over-rides or preferential rights; all obligations have been met

2) Opportunity to acquire current production with significant exploration and development upside

• Production of approximately 2,900 bbl/day (June 2011)
• Targeted reservoirs, typically in the Carbonera C3/C5/C7 reservoirs found between 3,500 and 4,500 ft TVD, have excellent production characteristics

3) Net 2P reserves of more than 16.3 MMboe certified by third-party reserve engineers Petrotech with a PV-10% of  approximately US$435 million based on a 3/31/2011 effective date 

• Proved: 6.1 MMbbl oil (47% proved developed); probable and possible: 13.8 MMbbl; 3.7 MMbbl of prospective resources identified
• Widespread 3-D seismic coverage over reservoirs of excellent quality

PROPOSALS DUE: August 11, 2011

Recent deals in Colombia and valuation of La Cuerva block

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The value of the La Cuerva block is estimated to be $200-$430 million, based on

• $18-$22/2P BOE, a close comparable to the Hupecol-Sinopec deal where the 2P metric was $25/BOE. The Hupecol-Sinopec metric is discounted to account for the difference in RLI of  La Cuerva block (15 years) and Hupecol-Sinopec assets (6 years). With $18-$22/2P BOE, the value of the asset is $290-$360 million.
• $70,000/Daily BOE for the current production of 2,900 bbl/day and thereby the value of the asset to be $200 million.
• 2P-NPV10 of $435 million, as reported in Scotia's marketing flyer.

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Other opportunities available in Colombia

There are currently three other asset packages in Colombia that are available for sale. The packages are offered by InterOil and Alange Energy. The snapshots of the packages are as follows- 

Source: Derrick Petroleum E&P Transactions Database

Source Documents:

La cuerva map

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Scotia waterous marketing flyer

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Cameroon: Oil and Gas Exploration in 2011 and 2012

Cameroon is a country on the West Coast of Africa.  It is bordered by Nigeria to the west; Chad to the northeast; the Central African Republic to the east; and Equatorial Guinea, Gabon, and the Republic of the Congo to the south. Cameroon has relatively modest oil and gas reserves, although it accounts for about half of the country’s exports. Oil production has also been declining in recent years due to maturing of existing fields. Here is a list of operators with plans to drill exploration wells in the near future. Also listed are operators that had plans to drill in the next 2 years, but who have since not made any announcements.  Information has been sourced from Derrick Petroleum's exploration and deals databases.

Block	Operator	Wells planned in 2011	Wells planned in 2012+
Bomono	Bowleven plc		2
Kombe-N’sepe	Perenco
Ndian River	Kosmos Energy (Africa)
MHLP-5	Bowleven plc
Tilapia	Noble Energy Inc	1

 Exploratory wells planned to be drilled/being drilled in Cameroon in 2011 and 2012. Source: Derrick Petroleum Planned Wells Exploration Database. The number of columns has been minimized to fit the table on the page. The actual database has many more parameters listed and recorded. 

1.             Bomono: The Bomono permit is located onshore Cameroon near Mt. Cameroon. It consists of 2 parts, OLHP 1 and 2, covering an area of 2328 sq kms. In February 2009 work commenced on the airborne gravity and magnetic survey. A 500 km 2D seismic survey was obtained by Jan 2011. Bowleven is planning to drill upto two wells on the permit in H1 2012. Bowleven has a 100% interest in the permit.

Map of Bowleven’s permits in Cameroon. Source: Bowleven.

2.             MLHP-5, MLHP-6 and MLHP-7: Bowleven operates these three shallow blocks in the Etinde Permit area with a 75% interest. The Blocks are located across the Rio del Rey basin (part of the southern margin of the Niger Delta oilfield basin) and the Douala Basin (which contains large undrilled seismically identified structures), together referred to as the Etinde Permit. The Etinde Permit covers approximately 2,314 km2. The water depths are shallow, from the shoreline up to approximately 70 meters maximum depth.

The Company drilled a high impact exploration well Sapele-1 on MLHP-5 on September 14, 2010. The well was to target a series of stacked reservior objectives, from the proven Miocene fairway down to the deeper Cretaceous fairway. The Sapele-1 well encountered a significant layer of hydrocarbons. Wireline log evaluation indicated all of the five objectives to be hydrocarbon-bearing with net pay confirmed in three, based on fluid samples. Bowleven has a 75% interest while Vitol E&P has 25% interest.

3.             Kombe-N’sepe: Kombe-N’sepe Block has an area of 3026 sq kms. The Kombe-N’sepe Block is located at the northern end of the late Cretaceous turbidite play fairway that extends from northern Gabon through Equatorial Guinea into southern Cameroon. More than two billion barrels of oil have been discovered in the region. Operators have made several small oil and gas discoveries in and around the Kombe-N’sepe Block. A two-well exploration campaign was planned to begin in either 2009 or early 2010. However, pending further announcements by the consortium, it is unlikely that an exploration well will be drilled in 2011. Perenco (40%) operates the block and the partners are Kosmos Energy (35%) and Société Nationale des Hydrocarbures (25%)

Source: Kosmos Energy

4.             Ndian River: Ndian River Block is located in Coastal strip of Rio del Rey Basin bordering Gulf of Guinea and abutting Cameroon/Nigeria border (predominantly onshore). Société Nationale des Hydrocarbures will be carried through exploration and appraisal phases and has an option to back in to the project with an interest of up to 15% upon approval of a development plan. Kosmos initially is focusing on the Ndian River Block’s under-explored northern extension of the late Cretaceous/lower Tertiary turbidite play. Since 2007 exploration activities have included a gravimetric and magnetic survey of the block, field studies, reprocessing of existing data and a 2D survey over an area with the highest potential. It is unlikely a well will be drilled in 2011, as the partners are not talking about it so far.

 5.             Tilapia: Tilapia block is located in the Douala/Kribi-Campo basin offshore Cameroon and covers a total area of 3,874.9 sq km. A 3D seismic survey was acquired in 2010 and an exploration drilling program was to commence in 2011. However, pending further company announcements, it is likely that exploratory drilling will only occur in 2012. Noble Energy (50% interest) is the operator along with partner Petronas (50% interest). 

Source: Noble Energy

For more information of discoveries and exploration plans for the following West African countries, click on the following links. Cote D’ivoire; Ghana discoveries; Ghana Exploration in 2011, Exploration in Mauritania, Benin & Togo; Angola; Sierra Leone; Sengal; Liberia; List of West African discoveries in 2010 – 2011.

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BG and ENI eyeing for stake in ONGC’s KG – DWN - 98/2; Plans to spend around INR 36,000 crore (US$ 7,898 million) along with its partners on developing the block

In 2010, India’s state run Oil & Natural Gas Corporation (ONGC) has made significant finds in the Krishna Godavari (KG) basin, which is right next to the KG-D6 block of RIL in the K-G basin, off the east coast. ONGC is aiming to develop the KG basin assets through four different projects. The G-1 and GS-15 integrated development followed by the S-1 and Vasistha deep-water development, exploitation of discoveries in the KG-DWN-98/2 block and Project Manik, involving the oil finds.

The blocks are divided into two discovery areas - the Northern Discovery Area (NDA) consisting of the Padmawati, Kanakadurga, Annapurna, N-1, D/KT, U, A, W and E gas finds in water depths ranging from 594m to 1,283m and the Southern Discovery Area (SDA) consisting of the UD-1 discovery falls in ultra-deepwater with a depth of 2,841m.

KG-DWN-98/2, which has 10 gas discoveries, was awarded under the New Exploration Licensing Policy, which allows ONGC to farm out a participating interest to foreign firms. In 2010, ONGC had asked foreign firms to submit proposals to buy a stake in the block. Cairn India is already a 10 per cent partner in the block.

“Giving away more will result in losing control and, in turn, our decision-making ability. We want an international partner who can get us the technology for deep-sea exploration. Both BG and ENI have it. These players are experts in deep water and know exactly how to go about the routine of the block,” said, one of the board members, ONGC. He added the discoveries in KG-DWN-98/2 and three in adjacent blocks together hold 6.37 trillion cubic feet (tcf) of in-place reserves. RIL’s KG block holds in place reserves of 11.3 tcf.

In February 2011, BP agreed to buy a 30-percent stake in 23 oil and gas blocks owned by Reliance Industries for $7.2 billion, as part of a long-term deal that involves a total investment of $20 billion. Nearly four months after RIL signed a deal with BP for getting BP’s technology for deep-sea exploration.

To know more about Reliance-BP's $7.2 billion deal, CLICK HERE 

Block 1G was given to ONGC on nomination basis. It cannot sell stake to any firm and can at best involve a foreign firm as a service contractor. ONGC has partnership with BG India in three blocks in KG offshore, two operated by ONGC and one operated by BG. Petrobras and ENI have also partnership in one block each.

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ONGC has entered into a period of exploration for appraisal after completing the exploration MWP commitments in block KG-DWN-98/2. The company plans to start producing 25-30 mscmpd of gas from the block in 2016-17.

Source Documents:

ONGC to sell 30 percent stake in KG block

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Laredo Petroleum grabs Permian focused Broad Oak Energy for $1 billion

Laredo Petroleum LLC has agreed to acquire Broad Oak Energy Inc, whereby Broad Oak will become a wholly-owned subsidiary of Laredo in exchange for aggregate consideration of approximately $1 billion. This is the biggest deal in the Permian Basin so far in 2011. This merger will make the combined company a leading player in the Permian Wolfberry oil play alongside Laredo's well established presence in the liquids-rich Granite Wash play.
Is the combined company planning for an IPO?
Both Laredo and Broad Oak are privately held companies formed in partnership with their management teams by affiliates of Warburg Pincus LLC. Through this merger, is there an IPO coming up from Laredo's side??

Broad Oak Energy Inc is a privately held oil and gas exploration and production company with a particular focus on the Permian Basin of West Texas. Broad Oak has assembled approximately 65,000 acres in the Wolfberry play of the Midland Basin. Assets include both infill and extension drilling prospects targeting a 3000 ft. proven producing interval that comprise Upper and Lower Spraberry, Dean and Wolfcamp reservoirs. Broad Oak has drilled over 200 wells and plans to drill 120 wells during the second half of 2010. The following map shows the operated producing assets of Broad Oak and Laredo Petroleum.

The following is the gross production profile of  Broad Oak operated assets.

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Summary of Permian Basin deal activity in the last 5 years

Deals by key operators in the Permian Basin

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Here are the significant Permian Basin deals of 2010 where the $/flowing barrel equivalent was around $100,000.

-- Apache acquires BP assets in Permian Basin for $3.1B

-- Concho Resources and Apache acquire assets of Marbob Energy for $1.65B

-- SandRidge Energy acquires Arena Resources for $1.3B

-- Oxy acquires Yates Drilling Co for $1.1B


Comparison of the deal activity by US sub-regions 
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The Permian Basin received the highest production multiples, $80,000-$110,000 per flowing barrel equivalent. The metrics reflect the premium buyers are willing to pay for oil reserves; future drilling opportunities, behind pipe potential and reserve quality.

The first 5-month results of 2011 show the total value of Permian Basin deals to be $2.3 billion with an average production metrics of ~90,000/daily BOE. There are a few Permian Basin packages put up for sale by Element Petroleum (brokered by BMO Capital), Piedra Resources (brokered by RBC Capital) and Parallel Petroleum (brokered by Scotia Waterous). These packages, being mandated by major advisors, are to make huge money to the Permian Basin for this year.

Source Documents

Permian basin overview

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USGS Assessment on Permian Basin Reservess

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Broad oak & laredo offset leases

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Apache announces 5 new discoveries in Egypt Concessions! Multi Play potential opens up!

Apache today announced five new discoveries in its Faghur Basin play in the far southwest of Egypt's Western Desert Oil and Gas province (See Map).

The Faghur discoveries include West Kalabsha-I-4, which logged 79 feet of net pay and test flowed 7150 bpd of oil and 11.4 MMcfd of gas; Faghur North-1X which logged 25 feet of net pay and test flowed 1444 bpd of oil and 3.9 MMcfd gas; Faghur South-1X which logged 38 feet of net pay and tested 2768 bpd of oil and 4 MMcfd of gas; Huni-1X which logged 27 feet of net pay and tested 970 bpd of oil and the Neith North-1X which logged 77 feet of net pay.

"The Faghur Basin continues to be a successful focus area for Apache, with AEB, Safa, and now Paleozoic reservoirs that have proven to be prolific oil and gas producers. These recent discoveries support the multi-pay potential of this oil-prone area of the Western Desert," said Tom Voytovich, vice president of Apache's Egypt Region.

Apache also said that the AG-96 development well in the Abu Gharadig Concession acquired from BP in late 2010 tested 3,347 barrels of oil and 1 million cubic feet (MMcf) of natural gas per day from the Lower Bahariya formation.

Apache paid $650 million to BP in Nov 2010 to acquire four development leases and one exploration concession across 394,300 acres. The assets have estimated proved reserves of 20 million barrels of oil equivalent (59 percent liquids), and first-half 2010 net production of 6,016 barrels of oil and 11 million cubic feet of natural gas per day.  The BP assets also included strategically positioned infrastructure- a natural gas processing plant, a liquefied petroleum gas plant and oil and gas export lines – that will enable Apache to increase production from its existing fields in the Western Desert.

Thus far in 2011, Apache has drilled eight new discoveries in 10 attempts in the Faghur Basin, and drilling is under way on three additional wells —Mandulis-1X, Neilos-1X and Faghur North-2X. Eight additional exploration wells are planned for the area this year. Apache had earlier stated in its 2010 annual report that it plans to drill 65 exploration wells in Egypt in 2011, 50% more than in 2010 (See Table 1 for Apache's exploration wells in 2011). 

Exploratory wells being drilled by Apache as operator globally in 2011. Source: Derrick Petroleum Planned Wells Exploration Database. The table does not include exploration wells where Apache is partner but non-operator. 

Apache had earlier in 2011 redeployed all non-essential expatriate personnel and all expatriate dependents from Egypt. However, key expatriate personnel remained in-country to work alongside Egyptian national personnel to manage ongoing production operations. Apache's production, located in remote locations in the Western Desert continued uninterrupted. 

Earlier in 2011, the Siwa-D-1X well drilled in the Siwa Concession pushed Jurassic and Cretaceous plays farther south and westward and will lead to follow-up exploration prospects. Apache expects to commence production from the well upon approval of a development plan later in 2011.

Apache also said that the the Tayim West-1X discovery in the West Kalabsha Concession represented the first Paleozoic success found in a reservoir separate from the younger proven Jurassic and Cretaceous sands and opens up the area to further deep tests in upcoming wells. The discovery is currently on production.

Apache's current gross operated production in Egypt totals approx. 215,000 barrels of oil and 900 MMcf of gas per day, including 40,000 barrels of oil per day from the Faghur Basin.

Click here for Apache's press release on the 5 discoveries.

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