ConocoPhillips plans to sell Vietnam assets for $2-$2.5 billion.. Lot more parcels available as part of $5-$10 billion divestiture plan.

ConocoPhillips is planning to dispose of its holdings in the projects located in the South China Sea, said John McLemore, a company spokesman.

Conoco- Vietnam operations overview:

• ConocoPhillips has a 23.3% interest in Block 15-1, and its activities are focused around three producing fields: Su Tu Den, Su Tu Den Northeast and Su Tu Vang; and two fields in development: Su Tu Trang and Su Tu Nau. First production on the Su Tu Den Northeast Field occurred in May 2010, averaging a net 4,000 barrels of oil per day and 4 million cubic feet per day of natural gas. Net production from the three producing fields averaged 18,000 barrels of oil per day in 2010.
• ConocoPhillips has a 36% interest in the Rang Dong Field in Block 15-2. Net production in 2010 was 6,000 barrels per day of liquids and 12 million cubic feet per day of natural gas.
• For transportation services, ConocoPhillips has a 16.3% interest in the Nam Con Son natural gas pipeline. This 244-mile transportation system links gas supplies from the Nam Con Son Basin to gas markets in southern Vietnam and has a capacity of 700 MMcf/d.

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A value for the package

The assets put up for sale could be valued between $2-$2.5 billion, while the peers value the assets at about $1.5 billion. Rationale for the valuation is as follows-

• Production of 26,000 boe/d is valued between ~$1.6-$1.8 billion ($60,000-$70,000/boe- based on the recent BP and TNK-BP deal in Vietnam with a premium factor applied);
• A gas pipeline in general has lifetime of about 20 to 25 years. The Nam Con Son pipeline, which was put into service in 2002, is left with 9-16 years of service. Assuming the daily capacity to be approximately consistent at 700 MMcf/d, the 16.3% stake in the Nam Con Son pipeline is valued at ~$400-$700 million (at an average cost of $1,000/Mcf/d of gas pipeline capacity.)

NOTE: Average cost of $1,000/Mcf/d of gas pipeline capacity is sourced from the Midstream Database of Derrick Petroleum.

Source: Derrick Petroleum Midstream Transactions Database

A brief look up at Conoco’s 2011-2012 divestiture program.

ConocoPhillips has planned for $5 billion to $10 billion in asset sales over 2011 and 2012 as it seeks cash to fund share buybacks and growth. ConocoPhillips sold about $7 billion in assets last year through a program announced in 2009 and intended in part to help reduce debt. The following table shows the divestitures of ConocoPhillips since 2010.

Source: Derrick Petroleum E&P Transactions Database

ConocoPhillips has now expanded the total sales target earlier this year to as much as $17 billion. “The company is marketing the assets in Vietnam as part of the divestiture program”, McLemore said in an e-mail yesterday. The following snapshot shows the exhaustive information collected by Derrick Petroleum on Conoco’s $5-$10 billion divestiture plan.

Source: Derrick Petroleum Deals-in-Play

Angola Oil - South West Africa's Next Crown Jewel

INTRODUCTION
Angola is a huge country present on the south-west coast of Africa, bordering the South Atlantic Ocean, between Namibia and the Democratic Republic of the Congo. It was home to a 27 year civil war that is estimated to have cost the lives of up to 1.5 million people, and displaced a further 4 million. The war came to an end following the death of Jonas Savimbi, the leader of the National Union for the Total Independence of Angola (UNITA), in 2002. President Jose Eduardo Dos Santos, the leader of the Popular Movement for the Liberation of Angola (MPLA), the main opponent against Savimbi, consolidated his hold on power and despite promising to hold presidential elections in 2009, has since managed to pass legislation to hold elections in 2012.

Figure 1: Map location of Angola. Modified from Google Earth.

Oil and gas exploration started in the early 1900’s, but it wasn’t till 1955 that the first onshore commercial discovery was made at the Benfica field in the Kwanza basin. In 1966, the first offshore commercial discovery was made at the Limba field in the Lower Congo Basin. There was restricted exploration activity onshore due to the civil war that engulfed the country for a quarter century, and exploration efforts were more focused offshore. Deepwater exploration commenced in 1993, and in 1996 the first deepwater commercial discovery, the Girassol field, was made at the Lower Congo Basin, in Block 17, by a consortium led by Total. In 1999 exploration moved to the ultra deepwater and the first commercial ultra deepwater discovery, the Plutao field, was made in 2002 in the Lower Congo Basin.

GEOLOGICAL BACKGROUND
Angola has three main sedimentary basins; the Kwanza, Namibe and Congo basins. Although all three basins have the pre-requisites for hosting hydrocarbons, only the Congo and Kwanza basins have so far yielded them in commercial quantities. Most of the exploratory success has come from the northern portion of Angola, where it seems the geology has favoured the northern blocks. One noteworthy example is Block 0 that lies offshore the Cabinda province, to the immediate north of the Congo river. Chevron operates Block 0 which provides about 20% of Angola's crude oil production. The mighty Congo river deposited huge amounts of sediment in the area along with vegetative matter that eventually turned into oil over geological time, increasing oil concentrations in this area. The block is divided into Areas A and B and together they contain 21 fields whose total production in 2010 was 365,000 boepd. Exploration in the southern blocks ceased after non discoveries in blocks 9, 21, 22 and 25 located offshore of southern Luanda. However, geologists in Sonangol, the concession holder and national oil company of Angola, are keen to begin comprehensive surveys of blocks in the Namibe Basin, which they believe has untapped resources.

Figure 2: Sedimentary Basins of Angola. Source, Ministry of Petroleum, Angola.

RESERVES AND PRODUCTION
Angola is an oil-dependent state with oil production and its supporting activities contributing about 85% of GDP. Angola has maintained a high growth rate of ~8% over the last 8 years due in large part to oil exports. In 2009 Angola became the leading producer of crude oil in Africa, overtaking Nigeria which experienced extreme sectarian violence and attacks on oil infrastructure. However, at the beginning of 2010, based on EIA data, Nigeria had the highest reserves in Africa, at 37.2 bboe. According to the BP statistical review, Angola’s proved reserves at the end of 2009 were 13.5 bboe and production at the end of the same year was 1.7 mmboe/d. This was up from 0.7 mmboe/d in 1990. The oil minister of Angola has put the reserves as on Dec 2009 at 13.1 billion barrels. Exploration has mainly focused offshore due in a large part to the civil war that divided the country. However, the northern city of Soyo and the disputed Cabinda Province are also host to some proven oil reserves. Angola became a member of OPEC in 2007. According to the EIA, Angola produced 1.82 mmboepd making it the largest crude oil producer in Africa and placing it seventh among OPEC members. Angola has had increasing production capacity from earlier discovered fields coming online but despite this, Angola maintained output at approximately 200,000 bbl/d below capacity, as a response to OPEC’s most recent production allocation. In the first quarter of 2011, EIA estimated Angola supplied 1.7 mmboe/d, which again placed it second behind Nigeria at 2.13 mmboe/d in African crude supply.

Figure 3 – Opec production for Q1 2011. Source: EIA short term outlook, May 10, 2011. Graph, Derrick Petroleum Services.

EXPLORATION
Angola, home to the 3^rd largest proved reserves in Africa after Libya and Nigeria, has had its fair share of exploration, mostly focused offshore and in the deep offshore. The turning-point in the history of oil exploration and production in Angola came about with the commercial discoveries in the deep waters of Block 17 and neighboring Blocks 14, 15 and 16. In 1996 when the reserves of Girassol were discovered in deep water on Block 17, Angola went from being a solid but average oil producing country to a hotspot in the global search for major oil reserves. Oil exploration and production in Angola mainly occurs in the offshore blocks, which are divided into 3 bands; Blocks 0 – 13 are shallow water blocks (Band A); Blocks 14 – 30 are deepwater blocks (Band B); and Blocks 31 – 40 consitute the ultra-deepwater blocks. Angola is also planning to throw up new blocks for exploration in 2011, after deliberation on the terms governing access to its highly prized pre-salt blocks. The pre-salt in Angola is thought widely to be analogues to the pre-salt in Brazils offshore basins which has had many substantial discoveries. Due to the fact that the South American and African continent were joined together in the geological past, many experts now believe that the pre-salt in Angola has potential to host huge reserves of hydrocarbons. In addition, the salt in Angola occurs both onshore and offshore, in contrast to the salt in Brazil which only occurs offshore.

Onshore exploration has been stymied due to the long civil war in the country. The Cabinda province was the site of most onshore exploratory efforts which were halted during the civil war.  At this time the only basin in operation is the Lower Congo, in the onshore area of the Congo River, also known as the Soyo area. However, Angola is now planning new improved policies to tap into its onshore resources and to create a positive atmosphere for drilling onshore.

EXPLORATORY WELLS IN 2011
Unless stated otherwise all data below is from the Derrick Petroleum- Planned Exploration Wells Database. According to this database, updated daily, there are a number of wells planned to be drilled in 2011. 25 wells over 10 blocks are scheduled to be drilled, with most exploratory drilling occurring offshore. 16 of these wells are in the deep offshore with the rest in the shallow offshore. The operators in these blocks are BP, ENI, Sonangol, Vaalco Energy, Petrobras, Maersk Oil, Cobalt International, Chevron, Pluspetrol and Total.

Table 1: Table showing companies planning exploratory drilling in 2011 and beyond. The number of columns has been minimized to fit the table on the page. The actual database has many more parameters listed and recorded. Source, Derrick Petroleum- Planned Exploration Wells Database.

Block 15/06
Eni has a 35% working interest and is the Operator in Block 15/06, while Sonangol E&P is the Concessionaire. The other partners of the Contractor Group 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%). Six discoveries have been made in the block so far; Sangos, N'Goma, Cabaça Norte-1, Nzanza-1,Cinguvu-1 and Cabaça south east. There are no more exploration wells to be drilled as the consortium is now planning development of discoveries.

Angola LNG II Upstream
Angola LNG II is a joint venture composed of Sonagas (22.8%), Chevron (36.4%), Eni (13.6%), Total (13.6%) and BP (13.6%) that will evaluate existing gas discoveries and explore further potential in the Angolan offshore, with the objective of supporting the feasibility of a second LNG train. The consortium plans to carry out a 3D seismic survey and drill 1 exploration well on the Angola LNG II area in 2011.

Block 5
Interoil is a 40% participant in Block 5, where Vaalco Energy Inc. is operator with an equal interest. Sonangol P&P (national oil company of the Republic of Angola) is also a partner with an interest of 20%. Block 5 is 5708 sq kms and is located in the Kwanza basin in the northern waters, offshore Angola. 95% of the block has a water depth of less then 200 mts. Three prospects, Kindele, Loengo and Jack have been mapped on the block. The gross mean unrisked resource potentials for these prospects are estimated to be 41, 93 and 41 mmboe respectively. The operator plans to drill atleast two prospects out of the three in 2011 and the third one in 2012.

Block 6
In Block 6 Interoil is participating with 20%, where Petrobras is operator with an interest of 40% and Sonangol, Initial Oil & Gas and Falcon Oil are partners with a total interest of 40%. Block 6 covers an area of 4930 sq km and is located in the northern area of Kwanza Basin offshore Angola. The water depth ranges from 50 to 500 m. 8 wells were drilled by the previous owners, which resulted in 2 heavy oil discoveries. The largest of these discoveries is the Cegonha heavy oil field. Petrobras is planning to drill 11 wells on its 3 operated blocks in Angola. Assuming 8 wells drilled on the other 2 blocks, 3 wells are expected to be drilled in this block in 2011.

Blocks 18/06 and Block 26.
The consortium plans to drill 8 wells on these blocks in Angola in 2011. The ownership structure of these two blocks is given below.

Figure 4: Ownership Structure for Block 18/06 and Block 26. Source Derrick Petroleum

Block 16
Maersk Oil operates the block with a 65% interest. Sonangol (20%) and Odebrecht (15%) are partners. Block 16 lies 100 km offshore Angola in water depths ranging from 200 m to 1500 m. Wildcat wells targeting the Omba and Caiundo prospects are scheduled to be drilled in 2011.

Blocks 9 & 21
Block 9 (4000 sq km) is located offshore Benguela Basin and in water depths that range between 50 to 1,000 meters. The block has oil potential of 400 MMBO (25-28 degree API). Prospects are scheduled to be drilled in late 2012. Block 21 (4,900 sq km) is located in the deep-water offshore south-central Kwanza Basin, some 200 Km southwest of Luanda. The water depth of the block is 300 to 1,600 m. Two prospects, Bicuar and Cameia, are scheduled to be drilled in 2011.

Block 0
Chevron operates this block with a 39.2% interest. Other partners are Sonangol (41%), Total (10%) and Agip (9.8%). The block is divided into Areas A and B. Together they contain 21 fields whose total production in 2010 was 365,000 barrels of liquids per day. According to Chevron two exploration wells are planned to be drilled on the block in 2011.

Block 8
Maersk Oil is the operator of the block with a 50% interest. The other partners are Svenska Petroleum (30%) and Sonangol (20%). Block 8 is situated along the early Cretaceous pre-salt lacustrine rift trend. It starts at the beach of the Kwanza and extends westwards, with water depth ranging from the very coastline to 600 metres. A well is scheduled to be drilled in 2011.

Block 23
Maersk Oil is the operator of the block with a 50% interest. The other partners are Svenska Petroleum (30%) and Sonangol (20%). Located in the deepwater Aptian salt basin trend, both pre- and post-salt petroleum systems have been identified. A well is planned to be drilled in 2011.

Block 17/06
Deep offshore Block 17, is operated by Total with a 40% interest and is Total’s principal asset in Angola. It is composed of four major zones: Girassol-Rosa and Dalia, which are currently producing. The other partners are Sonangol (30%), Sonangol Sinopec International (SSI) Seventeen Limited (27.5%), ACREP Bloco 17 S.A. (5%), Falcon Oil Holding Angola S.A. (5%) and PARTEX Oil and Gas (Holdings) Corporation (2.5%). The consortium drilled the Canna-1 well in 2011 which 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.

FUTURE
The industry is getting increasingly excited about the prospects in the pre-salt region. So far, all indications are that the pre-salt in Angola is analogous in hydrocarbon bearing potential to the pre-salt regions of Brazil which host substantial reserves. The government of Angola is still mooting production sharing agreements for the pre-salt regions, and once this is done, new pre-salt blocks will be up for grabs. All indications are that exploration activity is bound to increase in Angola. Angola looks set to maintain its high production into the future and, if exploratory success comes from ongoing and future exploration, the country just might topple Nigeria in terms of production and reserves.

For a list of West African oil discoveries in 2010 - 2011 click here

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:




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HIGHLIGHTS of the Quarter:

Brazil

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.

USA

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.

Tanzania

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.

Kenya

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.

India

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.

Norway

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

Source: Derrick E&P Transactions Database

BP looks for acquisition opportunities in Brazil and Russia.. Plans to spend $20 billion in 2011.

“BP is looking to acquire stakes in Brazilian oil fields to increase the production in South America”, said Guillermo Quintero, president of BP's Brazil division, during a press conference. Guillermo added saying, "We can't reveal the names for strategic reasons, but we have two or three farm-in negotiation processes underway. We didn't come to Brazil just to continue what Devon started, Brazil is strategic for us."

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Capital of $20 billion set for 2011

BP plans to spend $20 billion to expand its operations around the world in 2011 and is looking to new areas including Brazil and Russia to increase the oil production. BP's assets in Brazil include 10 blocks. Only one of them is in production phase with output of around 25,000 bpd. Guillermo said BP's production in Brazil could reach 100,000 bpd, but did not offer a clear time frame for this.

Also, BP has plans to participate in Brazil's 11th bidding round to be held in September 2011, which will not include blocks in the coveted deep-water region known as the subsalt that is home to the country's largest oil discoveries.

Status of M&A activity in BRAZIL

Recently, BP received the final approval to complete the purchase of ten exploration and production blocks in Brazil from Devon Energy. In 2010, the Chinese were active acquiring assets in Brazil. In addition, Brazil's Mines and Energy Ministry is planning to include frontier areas in north and northeast Brazil in the highly anticipated round 11 for new oil and natural gas blocks. The round is also expected to include onshore and deepwater areas in mature basins, in addition to equatorial margin basins in the northeastern and northern regions.

The map shows the major 2010 deals in Brazil.

Source: Global E&P Transactions 2010 Review

Opportunities available in Brazil

Derrick Petroleum has aggregated all publicly announced properties for sale. Derrick’ Deals in Play is the most comprehensive data set of its kind in the industry. The following table shows the prolific opportunities available in Brazil.

Source: Derrick Petroleum E&P Transactions Database 

Though 2010 was a disaster for BP due to Macondo oil spill, 2011 seems like a progressive year for BP that has clinched the $7.2 billion alliance with Reliance and announced $20 billion capex for acquisitions in 2011. The following graph shows 2010 production and capex of BP compared with its peers.

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Exploration in the Cook Inlet: A shot in the dark?

INTRODUCTION AND HISTORY

Cook Inlet, the channel that runs from the Anchorage area south to the Gulf of Alaska, is home to Alaska's oldest producing oil and gas basin. Cook Inlet has attracted explorers since at least the last century. From as early as the 1800’s, oil seeps were noted along the Gulf of Alaska, and the search for oil continued into the 1900’s, and does so now into the 21^st century.

Figure 1; Map of the Cook Inlet showing the prominent oil and gas fields. Source, modified from Kenai Burrough.

The first attempts at exploration occurred in the 1900’s when six wells were drilled between 1900 and 1906, although without success. Exploration continued through the 1900’s without much success until the late 1950’s. The first commercial oil discovery was made at the Swanson River Field in 1957. This discovery became a focal point for oil and gas exploration and also helped Alaska achieve statehood by showing that Alaska could support itself through resource development revenues instead of being a drain on the Federal government. The first and largest commercial gas discovery was made at the Kenai Field in 1959. This was followed by the largest oil discovery at the McArthur River Field in 1965. Exploration drilling peaked in 1966 and between 1964 and 1968, 14 offshore platforms were installed. The Steelhead platform was installed in 1986 and the final was Osprey, installed in 2000. Following the discovery of the giant Prudhoe Bay oil field in 1968, the focus of exploration in Alaska shifted to Prudhoe Bay. This discovery was in a sense detrimental to exploration efforts in the Cook Inlet region. The Cannery Loop and Pretty Creek gas fields were discovered in 1979 and were the last commercial gas discoveries. The West McArthur and Tyonek Deep (Sunfish) oil fields, discovered in 1991, were the last major oil discoveries. This area has produced a cumulative total of over 1.3 billion barrels of oil and 7.3 trillion cubic feet of natural gas. However, Cook Inlet natural gas production has been steadily declining with current production at approximately 190 Bcf per year.

Figure 2: Chart showing exploration drilling in the Cook Inlet since 1950, with number of wells. The prominent discoveries are highlighted.

According to the USGS in 2011 "The Cook Inlet Region of Alaska contains an estimated mean of 19 trillion cubic feet of natural gas, about 600 million barrels of oil, and 46 million barrels of natural gas liquids, according to a new assessment by the U.S. Geological Survey (USGS). This estimate is of undiscovered, technically recoverable oil and gas resources, and includes both unconventional and conventional resources.These gas estimates are significantly more than the last USGS assessment of southern Alaska in 1995, in which a mean of 2.14 trillion cubic feet of gas was estimated. This increase in the undiscovered resource is attributed to new geologic information and data."

THE ECONOMICS – HOW GOOD IS GOOD??

Investing in exploration in the Cook Inlet region has become highly attractive after the state passed the House Bill 2001, known as Alaska’s Clear and Equitable Share (ACES) in 2007. ACES was designed to develop and promote drilling activities in many of Alaska’s untapped locations. The program essentially de-risks the process of drilling off shore in Alaska, by providing companies with generous tax incentives to develop existing resources in the area. Production in Alaska has been steadily declining over the last few decades and the State is aiming to ease its increasingly high energy demand. ConocoPhillips and Marathon Oil in February announced that they will close their liquefied natural gas plant in Kenai, which has been the single largest user of Cook Inlet natural gas, due to their inability to renew their contract with Japanese customers. Although there is enough gas in the North Slope of Alaska to meet demand in Cook Inlet, that would entail constructing a massive pipeline over the State, which would cost many billions of dollars. A summary of the incentives offered to explorers is given below.
1. Cash Rebates – Companies get the following rebates
              a. A 65% cash rebate against all exploration, appraisal and development drilling, and seismic expenditures.
              b. A 45% rebate towards all development costs (flow lines, platforms, etc)
Companies can recover upto 65% of these rebates 6 – 12 months after expenditure or well completion.

Special incentives to facilitate the movement of a jack-up rig to the inlet, to hasten gas exploration because of steeply rising demand.

2. Incentives to hasten the movement of a jack-up rig to the inlet
              a. 1^st operator receives 100% (upto 25M) of well cost including mobilization and some jack-up  rig modifications.
              b. 2^st operator receives 90% (upto 22.5M)
              c. 3^rd operator receives 80% (upto 20M)

These credits are only available for the first 3 wells drilled with a Jack-up rig to Pre-Tertiary region and includes rig mobilization costs. Only one credit can be awarded to each company and if hydrocarbons are successfully found, 50% of the tax credit must be paid back from the producer to the States over a period of 10 years; there is no repayment necessary if a dry hole is drilled.

IS GOOD, GOOD ENOUGH?

Some companies are taking full advantage of these tax credits to develop and explore their acreage. Buccaneer Energy, a junior oil and gas company, has been attracted into drilling in the Cook Inlet based on these attractive fiscal policies. The Australian Company, Linc Energy, also drilled the first wildcat gas exploration well in the region in 5 years and drilling operation continue at present. However, it remains to be seen if any of these wells drilled using state sponsored rebates will be commercially successful. If these wells turn out to be commercial finds, it would undoubtedly lead to an increased interest in the Cook Inlet and propel some of these junior exploration companies, exploring in the area, to the big leagues.

Table 1: Table showing the companies planning exploratory drilling in 2010 and 2011. The number of columns have been minimized to fit the table on the page. The actual database has many more parameters listed and recorded. Source, Derrick Petroleum- Planned Exploration Wells Database.

NOTE: Buccaneer Energy was successful with their first well drilled in Q2 2011 in the Cook Inlet; the Kenai Loop-1 well. The Kenai Loop-1 well encountered up to 16 zones  totalling 510 feet of gross pay identified by logs as test candidates in the Beluga and Upper Tyonek Formations. In the initial phase of the testing program, the Kenai Loop # 1 successfully tested gas to the surface at a rate of 10 million cubic feet per day on a 20/64” choke with a FTP (flowing tubing pressure) of 3,495 psi. Buccaneer's expectations have been exceeded!! More to follow as drilling progresses!

Suncor Energy posts 6.5% Increase in Production for Q1 2011; Capital Spending was primarily on Expansion of In Situ Oil Sands Operations; Production In Line with company’s target of one million boepd by 2020

Suncor Energy’s upstream production in first quarter 2011 was 601,300 boepd, up 6.5% over same period last year. Suncor’s Q1 2011 production averaged 601,300 boepd, compared to 564,600 boepd during the first quarter of 2010.  Oil sands production was 322,100 boepd, 59% increase from the first quarter of 2010. Suncor, which is expanding its oil sands production and processing operations as part of a joint venture with Total, said it had seen higher oil sands production volumes and higher realized prices in upstream operations.

In March 2011, the company completed sale of non-core North Sea assets for proceeds of £105 million (US$ 170.44 million), subject to closing adjustments. The company secured two operated exploration licenses and one non-operated exploration license in the Norway portion of the North Sea in April 2011. In addition, the company is evaluating an exploratory well in the Ballicatters field offshore East Coast Canada.

Source: Derrick Planned Exploration Wells Database


Targeting One Million Boepd by 2020

Suncor continues to move forward on its ten-year growth strategy outlined in December 2010. In support of the growth strategy, capital spending in the first quarter was primarily focused on expansion of the company's in situ oil sands operations. In April 2011, Suncor began injecting steam into a Stage 3 well pad and expects to achieve first oil by early July 2011. The expansion is expected to be fully operational in the third quarter of 2011, with production volumes ramping up over approximately 24 months thereafter toward target capacity of 62,500 boepd of bitumen.

With the closing of its strategic partnership agreements with Total E&P Canada Ltd. on March 22, 2011, Suncor expects to progress with engineering and site preparation work for the Fort Hills oil sands mining project and the Voyageur Upgrader. Under the terms of the agreements, Total assumed an interest in both Fort Hills and the Voyageur Upgrader, while Suncor assumed an interest in Total's Joslyn oil sands mining project. Suncor is targeting the completion of the Voyageur Upgrader and the Fort Hills project for 2016.

Source: Derrick E&P Transactions Database

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Quicksilver Resources to sell HRB acreage for $150 million. Another $1.5 billion package in HRB is on the table.

“Quicksilver Resources is considering seeking a partner for its Horn River Basin (HRB) acreage in northeastern British Columbia”, said Glenn Darden, President and CEO of Quicksilver, during the Q1-2011 conference call.

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Source: Quicksilver May 2011- Investor Presentation

Quicksilver’s work program in HRB

Quicksilver completed its 2010/2011 winter drilling program in the Horn River Basin and has now drilled a total of eight horizontal wells into the Muskwa and Klua formations, of which four wells have commenced production (11.1 MMcfe/d for Q1, 2011). Only two additional wells are required to validate all of Quicksilver’s exploratory licenses and convert these licenses, covering approximately 130,000 net acres, into 10-year development leases. In addition, the company has drilled its first horizontal well into the shallower Exshaw oil formation and expects to begin completion activities on this well this summer.  

Status of midstream development in Quicksilver’s HRB asset

Quicksilver has initiated midstream operations associated with its Horn River assets. Construction and compression related to Quicksilver’s own 20-mile, 20-inch gathering line, which will serve as the spine of Quicksilver’s transportation from its Horn River acreage, is now complete. Final tie-in of the line into the Spectra system is anticipated in late May, which will enable the company to flow gas from its four completed gas wells at unrestricted rates of more than 30 MMcf per day.

It’s vital that a company has a strong midstream system in place to ensure it can process and transport its gas at reasonable cost and sell it for acceptable prices. With the midstream facilities in place and considering 25% sale or JV, the acreage to be sold can be valued between $130-$160 million (based on $4,000-$5,000/Acre).

The following table shows the other HRB packages (total worth $1.5 billion) put up for sale.

Source: Derrick Petroleum E&P Transactions Database