Thursday, June 30, 2011

Mitsui and SM Energy form Eagle Ford JV. Adjusted $/acre settles at ~11,000/acre

SM Energy Co (SME) entered into an agreement with Mitsui concerning a 12.5% working interest in its non-operated Eagle Ford shale position. The company will be carried on 90% of its drilling and completion costs (excluding costs associated with construction of mid-stream gathering assets) in this acreage until $680 million has been expended for the benefit of SM Energy.

Asset highlights:
  • The project comprises 310,000 gross acres in which Anadarko holds 73% operated WI (~225,000 net acres) and 27% WI is held by SME (~85,000 net acres). Post transaction, SME will have 14.5% WI (~46,000 net acres) in the non-operated portion of its Eagle Ford shale position
  • The acquired acreage includes Eagle Ford (~39,000 acres) and Pearshall acreage (~8,000 acres) and spans across Dimmit, Maverick and Webb counties;
  • Reported average daily production from SME's total non-operated Eagle Ford shale position at the end of the first quarter was 43.5 MMcfe/d / 23.36 MMcfe/d for Mitsui's 12.5% interest (42% oil, 36% natural gas, and 22% NGLs)
  • Proved reserves associated with SME’s total non-operated Eagle Ford shale position as of December 31, 2010 were 52 Bcfe (27.93 Bcfe for Mitsui's 12.5% interest). 48% of these reserves are proved developed.
$/Acre- Valuation Analysis
The value of the reserves is estimated to be $233 million (at $60,000/Daily BOE). In addition, the value of Pearsall acreage is estimated at $16 million (at $2,000/Acre). The remaining deal value of $430 million is ascribed to Eagle Ford acreage ($11,036/Acre). The metrics are calculated without discounting the future carry costs.

To see what other operators are reporting on "Eagle Ford", use our oil and gas document library:

Vigorous growth in Eagle Ford transaction activity:

Activity in the Eagle Ford play has been high in the recent months. In 2010 in the Eagle Ford, 1,018 drilling permits were issued through November, up from 94 the year before, and output of crude oil, condensate and other liquids nearly quadrupled to 3.9 million barrels, according to Texas Railroad Commission data.
In 2010, Eagle Ford Play had generated close to $2.9 billion in revenue and provided nearly $47.6 million in local government revenue. Over the next 10 years, it is expected that more than 5,000 new wells will be drilled and generate more than $21.5 billion in total annual economic output.
Some of the world's biggest oil companies - including Shell, BP, Statoil, Marathon, KNOC and CNOOC - have recently entered the Eagle Ford and taken the acreage metrics to a new bench mark level. Four years back, the acreage cost in the Eagle Ford play was $100-$200/acre which in 2010 was reaching an average price of $10,000/acre. The recent deals by Marathon and KNOC have moved it to another higher level of $20,000-$25,000/acre. The following interactive graph shows the Eagle Ford deals done by these majors.

A good progress in pipeline infrastructure in Eagle Ford play
The Eagle Ford has its high content of valuable crude and natural gas liquids. But along with the optimism, some operators worry that growth could be held back by equipment constraints and a potential lag in building new pipelines, processing plants and other infrastructure. Though the pipeline infrastructure in Texas is very mature, especially for oil and natural gas, the system needs significant investments to process natural gas liquids.
In 2010, investments in midstream development in the Eagle Ford play accounted for an estimated $404.3 million. With more than 130 miles of new pipeline activity, including the continued development of the Chisholm, Dilley, Dos Hermanas, Leona, and Fox Creek pipelines, all indications are that over the next three to five years midstream activities will continue to play a significant role in the development and economic prosperity of the region. The following table shows the midstream deals regarding Eagle Ford play.
Source Documents:

Tuesday, June 28, 2011

Chevron plans on investing $26 billion in 2011, with 87 percent of that amount expected to fund upstream activities

Chevron Corp, the second-largest U.S. oil company plans to take a measured approach to shale gas development despite a flurry of deals in the past year and the industry's huge ambitions for the emerging resource.

View Chevron’s major projects startups:

"You're not going to see Chevron -- I can't speak for others -- just shift the whole business into shale, and let other things go," Bobby Ryan, Chevron's vice president for global exploration, said at the Reuters Global Energy and Climate Summit in Houston on Wednesday. Ryan reiterated that Chevron's focus areas remained the Gulf of Mexico, West Africa and Western Australia, which were all part of a "balanced portfolio" approach to exploration.

Like Exxon and others, Chevron is exploring shale acreage in Eastern Europe, and will drill its first well in Poland this year. In the U.S. Gulf, Chevron recently got clearance for a few wells already under development, and its program includes 10 development and exploration plans and 15 drilling permit applications in various stages of approval or preparation.

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Chevron is set to drill 16 development wells and two exploratory wells at Jalalabad, Moulvibazar and Bibiyana gas fields in Bangladesh for the next one year. According to Petrobangla, Chevron submitted a US$ 350 million capital budget to carry out the plan. "To conduct the drilling operations we need one year as we have to construct concrete drilling pit, mobilize drilling rig and associated equipment, management and treatment of waste and decommissioning of rig and materials", Chevron official said.

Chevron has added 14 million acres to its portfolio, including the acquisition of Atlas Energy in the northeast United States, and deepwater opportunities in Liberia and China. Chevron’s queue of major capital projects, including Gorgon and Wheatstone in Australia. Over the next three years, 25 projects with a Chevron share of more than $250 million each are scheduled to start production, nine of which have a net Chevron share that exceeds $1 billion. Chevron has four major capital projects planned to start up in 2011.

Additionally, over the next three years, the company expects to make final investment decisions on 13 more projects, each with a Chevron share in excess of $1 billion. Construction on the Gorgon project is nearly 25 percent complete, with startup expected in 2014, and Chevron remains on schedule to reach a final investment decision this year on the Wheatstone project, with startup planned for 2016.

Chevron CEO, John Watson told, “Disruption fears are pushing up oil prices and chevron has $26 billion in capital expenditures slated for this year. When it comes to acquisition, it's all about the right opportunity. We are spending almost 90% of our capital dollars on the upstring, exploring and producing oil and gas, where we'll emphasize our growth and we have growth to add over the next five to seven years.”

Check this Video - Chevron CEO John Watson discusses 2011 Capital Expenditure Plan with CNBC:

Monday, June 27, 2011

East Africa's Tanzania - Oil and Gas Exploration in 2011

Tanzania has had sporadic exploratory activity over the last 5 decades. To date, about 40 exploratory wells have been drilled, with only 2 significant gas discoveries at Mnazi Bay and Songo Songo. These discoveries confirm the presence of an active petroleum system. Notable discoveries in 2010, have enhanced the prospectivity of the region and companies are looking to strike it big in 2011. Here are the companies that have been active in Tanzania in the exploration front over the last few years and looking to drill in 2011 and 2012! Shell and Petrobras also have interests in some concessions (see map), but pending further announcements from these companies, it is unlikely any exploratory drilling will occur in 2011. Material has been sourced from Derrick Petroleum's exhaustive data on exploration and deals. The Derrick Petroleum Planned Exploration Wells Database is an extremely useful research tool to keep track of exploratory drilling of companies by region, year, etc. It will also be useful to E&P companies for identifying farm-in opportunities and to oil field services companies for identifying sales opportunities.

Table 1: List of Blocks in Tanzania with operators looking to explore in 2011. Also listed are wells drilled in 2010. 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. For more information on the blocks and their locations and ownership, read below. 

Figure 1: Map of licenced blocks in Tanzania with gas fields shown. Source, Heritage Oil.

1.       Lindi & Mtwara Licences
Tullow operates these two licences in the Tanzanian portion of the Ruvuma Basin. Processing of a 2D seismic dataset over the licenses was completed in 2008. Two prospects, Sudi-1 and Mikindani-1 were identified and Mikindani-1 was planned to be drilled in Q3 2009. However reprocessing of the seismic data by Tullow Oil led to a new drilling location at the Likonde-1 prospect. The Likonde-1 well was spudded on January 09, 2010 and encountered residual oil & gas. The well was plugged and abandoned. The Sudi-1 well in Mtwara licence is scheduled to be drilled in 2H 2011. The Ntorya-1 well is also planned to be drilled in Sept/ Oct 2011, about 14 km to the south of Likonde-1, to a planned total depth of 2020 m, targeting the same high quality Lower Tertiary reservoir sands encountered in the Likonde-1 well. The ownership structure is given below:
Company Share
Tullow Oil*
Aminex plc
Solo Oil Plc

2.       Mandawa
[RELINQUISHED] The Mandawa contract, awarded in 2005, covers 6811 sq kms. It lies just south of Maurel's Bigwa-Rufiji-Mafia Block. The Mihambia prospect, which held pre-drill potential resources of 176 mmboe was spud in early 2009 and the well failed to encounter hydrocarbons. On June 28, 2010 the Company announced that it had commenced drilling the Kianika-1 well which also failed to encounter hydrocarbons. On 23 March 2011, Maurel et Prom (Dominion's joint venture partner) advised the relevant authorities in Tanzania that the partners would be surrendering the Mandawa contract area.

3.       Ruvu
Dodsal Hydrocarbons and Power (Tanzania) Pvt. Ltd., a wholly owned subsidiary of Dodsal Resources signed the Production Sharing Agreement with the Government of Tanzania on October 23, 2007, acquiring possession of an on-shore Oil and Gas Concession called the RUVU block,  30kms West of Dar es Salaam in Tanzania, with an area of more than 15,000 sq. km. Seismic Data Processing and investigative explorations indicates presence of hydrocarbons, with re-interpretation conducted at leading technology centers in Canada, Germany and UK. Based on these positive results, Dodsal is planning for additional 2D seismic acquisition in 2011 and drilling of Exploratory Well in 2012. Dodsal holds 100% interest in the permit.

4.       Kimbiji
Kimbiji Block has a total area of 4298 sq km and lies both onshore and offshore. In 2008, 207 km of 2D seismic was acquired onshore in the Kimbiji licence area. The acquisition of over 300 sq km of fully migrated 3D seismic offshore Tanzania commenced in December 2010 and was completed in January 2011. As of Q1, 2011, the data is currently being processed with a view to establishing a drilling location. The partners are:

Company Share
Heritage Oil Ltd*
Petrodel Resources Ltd

5.       Kisangire
Kisangire Block has a total area of 7280 sq kms and lies onshore. Heritage Oil acquired 198 kms of 2D seismic in the Kisangire licence area in September 2008. The consortium was planning to drill an exploration well in 2009. However, on 17 December 2010, Heritage Oil, Dominion's partner in the Kisangire-Lukuliro contract area, affirmed the proposal that the licence for that area be allowed to lapse.

6.       Block 7
Block 7 has an area of 8492 sq kms and the water depth varies from less than 400 m to more than 2500 m. Dominion has concluded the first phase of interpretation of approximately 4350 kms of 2D seismic lines acquired in late 2007 and early 2008 and identified several prospects. A prospect named Alpha has been identified on the Block by the existing 4,350 kms of 2D seismic coverage. As per the CPR on this prospect, it is estimated to hold mean prospective resource potential of about 1.104Bbbl of oil or 7.069Tcf of gas. Dominion is planning to drill an exploration well on this block in H2 2011. Dominion Petroleum holds 100% interest in the block.

7.       Selous
The Selous PSA in southern Tanzania is a relatively un-explored area dominated by the Permian Selous basin covering an area of 16818 sq kms. A seismic study of the block was planned in H2-2010. As on April 2011, the license has been “frozen” by mutual consent (i.e. no pending commitments). Dominion Petroleum holds 100% interest in the block.

8.       Nyuni
The Nyuni Licence area is located on the eastern costal shelf of Tanzania and covers a total area of 1300 sq kms. The Kiliwani North-1 exploration well, drilled in February 2008, resulted in a gas discovery. The Nyuni PSA contains significant undrilled prospects, notably the Nyuni prospect itself and the Okuza and Fanjove prospects. The Nyuni-2 well was spud on 17 June 2011 and will target the same Neocomian sandstones which form the reservoirs in the nearby Songo-Songo gas field and in Aminex's Kiliwani North gas field reservoir. An additional target is an Aptian/Albian sandstone reservoir which was logged as gas bearing in the Nyuni-1 well, which was drilled but not tested in 2004. It is estimated that drilling to target depth will take 9-10 weeks. Partners are:

Company Share
Aminex plc*
RAK Gas Commission
Key Petroleum Ltd
Bounty Oil & Gas NL

9.       Mafia Bigwa Rufiji
The Mafia Bigwa Rufiji permit is located both onshore and offshore Tanzania. The consortium drilled the Mafia Deep ST-1 well in Q1-2009 which had a pre-drill estimate of 3 Tcf. In August 2009, drilling commenced on a new exploration well Mohoro-1 in the Delta Rufiji. This new prospect, revealed by the seismic survey conducted in 2008 and interpreted in 2009 encountered a column of water impregnated with hydrocarbon gas but in non-commercial quantities. Pending further announcements, no wells are planned to be drilled in 2011 or 2012. Maurel & Prom hold a 40% interest and is operator. Other partners and their stake is not disclosed.

10.   West Songo Songo
The West Songo Songo block (505 sq km) is located immediately west of the producing Songo Songo Gas Field (estimated reserves 1 Tcf). Water depths in the block range from islands (onshore) to shallow water regions of approximately 25m. A 2 well program is planned, with the 2nd well contingent on the success of the first well. New Seismic acquisition is planned in Q3 2009 with drilling of the 1st well in 2010. According to Aminex Plc (partner), no drilling is likely to occur in the next 2 years on this block. Partners in the block are.
Company Share
*Key Petroleum Ltd
Aminex plc

Key Petroleum Ltd is seeking offers, preferably cash offers, to divest all of its interests in both the Nyuni and West Songo Songo PSA areas on the Tanzania Shelf.

11.   Latham
The Latham Area is located offshore, with water depths ranging from near shore to 1,250 m. The area is on trend with, and located approximately 90 km north of the large Songo Songo gas field. Petrodel Resources (operator) plans to carry out a further 3D seismic survey offshore Latham in December 2010. The first exploration well on the block is planned to be drilled in H2 2011. Partners are,
Company Share
Petrodel Resources Ltd*
Heritage Oil Ltd

12.   Blocks 1, 3 and 4
Block 1, 3 & 4, in offshore Tanzania cover an area of 34,760 sq km area in the Mafia Deep Offshore Basin and northern portion of the Ruvuma Basin, and are located in water depths ranging from ~ 100m to greater than 3,000m. 2D and 3D seismic data for Blocks 1, 3 and 4 was acquired in 2008. The first deep water well in Tanzania, Pweza-1 was drilled in Q3 2010 and encountered a thick section of gas bearing sands. The second well, Chewa-1, drilled on Block 4 in Q4 2010, also encountered gas in it. The 3rd well, Chaza-1, in Block 1 at a water depth of ~ 950 m also discovered gas. To date (20 June, 2011), a 3,200 sq km 3D seismic survey has been acquired in Blocks 3 and 4, and a second 3D survey of 1,800 sq km is nearing completion in Block 1. It is intended by the consortium to commence a second drilling campaign in late 2011. Partners are,
Company Share
Ophir Energy plc*

13.   Block 2
The total area of Block 2 is 11,099 sq kms and it lies in water depths of between 400 and 3000 mts. This is a frontier area, as no wells have been drilled this far from the coast. A 6200-km 2D seismic survey was acquired during Q1-2008. Final processed data was delivered in January 2009. According to the latest estimates by the operator, the earliest time for first drilling will be in 2011. Partners are,

Company Share

14.   Discovery Blocks
Orca Exploration Group operates one license in Tanzania which comprises two blocks known as the Discovery Blocks. The license covers an area of about 170 sq km and contains the large Songo Songo gas field which is positioned on and slightly offshore Songo Songo Island (SSI). Orca intends to drill two exploration wells on the Songo Songo West prospect in H2 2011. Orca holds a 100% interest in the licence.

15.   Tanga Block
The Tanga Block lies northernmost coastal Tanzania, directly south of and adjoining Kenyan blocks L17 and L18 in which Afren holds a 100% interest. The licence includes onshore, shallow marine and deep marine areas. The block is covered by 200 km of legacy 2D seismic data, and 1,200 km of good quality new 2D seismic data covering mainly the deeper water area, which was acquired by Petrodel. 900 km of shallow and deeper water 2D seismic acquisition is expected to begin in Q4 2011, based upon which an exploration well might be drilled. Partners are,
Company Share
Afren Plc*
Petrodel Resources Ltd

16.   East Pande Block
The East Pande license lies in the coastal region of southern Tanzania covering an offshore and onshore area in excess of 7,500 sq km. The maximum water depth in the East Pande block is approximately 2,000 m. In late 2010 RAKGas (partner) acquired approximately 1,800 line km of 2D seismic in the offshore section of the block. Ophir intends to acquire a new 3D seismic survey in the offshore section of the block in 2011. Partners are,
Company Share
Ophir Energy plc*
RAK Gas Commission

For more presentations on "Tanzania", use our oil and gas document library:

Friday, June 24, 2011

Malta Farm-In Extends Dominion

Dominion Petroleum Limited has entered into an Execution Agreement to acquire a 75% operated working interest in the production sharing contract for Blocks 4, 5, 6 and 7 of Area 4 Offshore Malta from Phoenicia Energy Company Limited, a wholly owned subsidiary of Mediterranean Oil & Gas plc (MOG), pursuant to a draft farm-in agreement. Closing of the acquisition is conditional upon Maltese government approvals and completion of the Placing of the subscription shares.

Under the terms of the farm-in agreement, Dominion will meet certain exploration costs up to a cap of US$1,260,000, on behalf of MOG in relation to its remaining 15% working interest. Dominion will also compensate MOG for a total amount of US$900,000 in certain historic costs, through the non-refundable sum of US$225,000 and a closing sum of US$675,000 under the farm-in agreement. The exploration costs to be paid by Dominion on behalf of MOG is US$0.189 million. The aggregate deal value including the historic costs is US$1.089 million.

The Maltese PSC is situated to the north of Libya, covering an area of 5,715 sq km in Maltese waters. It includes both the Cretaceous rift potential of the Melita-Median Graben and the confirmed Eocene carbonate play of North Africa. According to RPS Energy's report on Area 4, effective March 2006, there are number of prospects identified within the area, of particular interest is the Tarxien prospect, a lower Eocene carbonate build up. The reporat also estimated the prospect to have a gross recoverable un-risked P50 prospective oil resource of 115 MMbbl with an 18% chance of success.

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The work obligations of the current period of the Maltese PSC comprise the acquisition of 1,000 sq km of 3D seismic data and the drilling of one exploration well. The first exploration period is valid until January 2013 and there is a minimum spend requirement of US$5 million. The company anticipates that the 3D seismic survey will cost between approximately US$8 million and US$10 million gross to undertake, which will satisfy the minimum spend requirement. The results of the seismic survey will enable the JV partners to define and evaluate the Tarxien prospect and other identified opportunities within Area 4, prior to any drilling decision. The long-offset 3D will also allow for a clearer analysis of the pre-tertiary rift-fill below the Eocene carbonates and potential Cretaceous targets.

Post transaction the ownership structure in the blocks will be: Dominion Petroleum (75%, Operator), MOG (15%) and Leni Gas & Oil (10%).


Husky Energy raises $1.2B to fund growth plans; Expects 3 -5% CAGR Production Increase through 2021

Husky Energy Inc, Canada’s No. 3 integrated oil company, said it will raise $1.2-billion though public and private share offerings in order to finance its production growth plans. Husky, said it will sell 36.9 million common shares priced at $27.05 each, to a group of underwriters led by RBC Capital Markets, Goldman Sachs Canada, HSBC Securities (Canada) and J.P. Morgan Securities. The bought deal is expected to raise about $1-billion.
Husky announced a 2011 capital budget of CAD 4.9 billion (US$ 5.02 billion), a 23% increase from 2010. Excluding the acquisition, the bulk of the spending increases will go toward the Sunrise project and Southeast Asia, with reductions in midstream and downstream spending. With the larger capital budget and contributions from the recent acquisitions, Husky expects 2011 total production growth to be slightly above 4%.

Most of the gains will come from an increase in natural gas production of 14%, while expected 5% growth in heavy oil and bitumen volumes should offset a 3% decline in light and medium crude production. To supplement the funding of the capital plan, Husky also announced plans for a CAD 1 billion (US$ 1.02 billion) equity issuance. Current shareholders will have the option of receiving dividend payments in shares instead of cash.

The retention of the Southeast Asian assets is probably a positive step, given the outlook for increased gas demand in the region and the potential for exploration success. Also, moving forward with Sunrise should provide significant growth in oil volumes. However, while the company plans to achieve its previous production growth target of 3%-5% per year, short-term gains rely largely on natural gas acquisitions.

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The move toward natural gas stands in contrast to Husky's peers, which are shifting investment toward oil projects and away from natural gas. Also, the company's natural gas production is coming from Western Canada, a region that falls higher on the cost curve and faces intense competition from U.S. shale plays. As a result, returns may be challenged despite the growth in production.

Husky said the cash will go to boost exploration and development of its properties in Western Canada’s oil sands, offshore Newfoundland and Southeast Asia. It also said that, with the additional capital, it expects production to grow at the high end of its 3-5% annual target though 2015.

Husky Energy’s Exploration Portfolio:

Source Documents:
Corporate Overview June 2011


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