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Noble enters Marcellus shale in a $3.4 billion JV with Consol Energy.

Consol Energy has agreed with Noble Energy for the joint development of Consol's 663,350 Marcellus Shale acres in Pennsylvania and West Virginia for aggregate payments to Consol of approximately $3.4 billion.

Noble Energy will acquire 50% of Consol's undivided interest in the Marcellus Shale acres held by Consol in exchange for $1.07 billion, payable in three equal installments. Noble will also pay $2.13 billion in the form of a 1/3 drilling carry of certain Consol working interests obligations as the acreage is developed. Also, Noble Energy will pay $160 million at closing for Consol's existing Marcellus Shale wells, which have proved developed producing reserves of 89 Bcf and production of 35 MMcfe/d, net to Noble. Finally, Noble Energy will pay $59 million to acquire a 50% interest in Marcellus gathering assets.

Key operational aspects of the joint venture include:

• Acreage estimated to contain 7.4 Tcfe risked resources net to Noble Energy's interest, of which 400 Bcfe were proven reserves at year-end 2010
• More than a decade of development activity anticipated, which includes the drilling of approximately 4,400 gross well locations
• Net production to Noble Energy's interest has the potential to reach 600 MMcfe/d in 2015 and is expected to continue growing into the next decade
• Leasehold position is over 85% held by production, almost entirely operated with close to 100% working and 88% net revenue interests
• A pre-defined long-term development plan forecasts drilling activity to increase from 4 rigs to 16 rigs in 2015 
• Operations to be shared between the partners with Noble Energy's initial focus on the wet gas portion of the acreage
• Sharing of midstream infrastructure and access to water handling capabilities.

Accelerated Development Plan:

The joint development plan calls for the rig count to increase from four rigs currently drilling in the Marcellus to 8 rigs in 2012 and 12 rigs in 2013, eventually reaching a plateau of 16 horizontal rigs in 2015. In terms of operating areas, Consol will operate the dry gas areas of 570,000 acres and 3,700 locations in a stretch from Jefferson and Clearfield counties through Westmoreland, Fayette and Greene counties and into West Virginia. Noble will operate 95,000 acres and 630 locations of wet gas regions that include the western half of Washington County into Marshall County, West Virginia, and elsewhere in West Virginia.

Noble Energy- Expands international operations and plans to divest non core assets

Noble Energy, with its core operations in Africa and East Mediterranean, has started expanding its international operations in US. In the last two years, Noble Energy accumulated approximately 430,000 net acres in the Niobrara shale at a low entry cost of $480/acre. Noble Energy has allocated $875 million to develop its properties in the Denver Julesburg basin, where the company is working on the Niobrara formation. The company plans to drill 70 horizontal wells in 2011 targeting this formation.

Now, Noble Energy has targeted another unconventional play- Marcellus Shale. The $3.4 billion deal marks Noble's entry into the Marcellus Shale development. What's next in Noble Energy’s target list???

Noble Energy had been hesitant to move the company into the Marcellus. However, the area has become a hub of natural gas production as advanced methods, including hydraulic fracturing and horizontal drilling, have allowed energy producers to extract oil and gas from dense shale rock. Now, Noble has entered Marcellus area and considers this $3.4 billion JV opportunity beneficial due to its enormous resource potential, its proximity and access to premium markets, and its competitive cost structure.

In a conference call, Noble executives said the company would consider selling some of its North American assets to focus its drilling program on the Marcellus, the Gulf of Mexico and the DJ Basin in the western United States.

A fair deal by Consol Energy:

In April 2010, Consol paid $1.88 billion for Dominion’s Marcellus acres, or $3,827 per acre. Now the same acreage is being sold by Consol to Noble for ~9,650/acre. Over the past 15 months, Consol has largely de-risked these acres which made the $/acre increase by $5,823.

Source: Consol Energy

The following table summarizes the metrics of the recent major Marcellus deals. The adjusted $/acre denotes the value of the acreage after allocating some value to the reserves, production or midstream assets.

Announcement Date	Heading	Deal Value ($MM)	Quick $/Acre	Adjusted $/Acre
6/2/2011	Exxon acquires Marcellus Shale assets for $1.7B	1,690	5,331	4,280
5/16/2011	Enerplus sells certain Marcellus assets for $575M	575	6,319	5,982
12/21/2010	EXCO and BG acquire Marcellus assets from Chief Oil & Gas and partners for $459M	459.4	9,188	7,055
11/9/2010	Chevron acquires Atlas Energy for $4.3B	4,300	8,848	2,836
5/28/2010	Shell acquires Marcellus acreage from East Resources for $4.7B	4,700	7,231	6,462
5/25/2010	Williams acquires Marcellus acreage from Alta Resources for $501M	501	11,929	11,929
5/10/2010	BG forms $950M JV with EXCO to develop Marcellus Shale	950	10,215	7,809
4/9/2010	Atlas Energy forms $1.7B JV with Reliance to develop Marcellus Shale	1,699	14,158	14,158

Mako Energy and Partners Considering Potential Sale and/or Farmout Options for their Rock Creek Project and Duvernay Shale Acreage

Mako Energy Limited has announced that it, and its joint venture partners, Transerv Energy Limited and Kilgore Oil & Gas Ltd, are planning a potential farmout or other disposition of all or a portion of their Duvernay and Rock Creek mineral rights in West Central Alberta. They have engaged Macquarie Capital as advisor.

The land holding of the joint venture within the Duvernay and Rock Creek fairway totals 261.08 gross sections (167,040 gross acres). Mako holds 50% interest in both the resource plays, and the remaining is held by Transerv (34%) and Kilgore (16%).

Rock Creek Project

  • The total land holdings of the joint venture within the Rock Creek project is 132.28 gross sections (84,659 gross acres). The land position extends across Niton, Pembina, Willesdon Green and Rimbey fields.

  • Highly analogous to the Bakken and Cardium unconventional light oil plays.

  • Proven Production reservoir-20 MMbbls of liquids and 1 Tcf of gas.

  • The project has estimated recoverable resources of 30 MMBOE, gross P90 resources of 189.78 MMBOE (80% Oil) and gross P10 resources of 286.58 MMBOE (Source: Sproule and Associates).

  • The average Estimated Ultimate Recovery per well is 168,000 BOE.

  • Plan to commence a 3-well drilling program in September 2011 comprising horizontal wells with multi-stage fracs. Kilgore anticipates drilling and completion cost of approximately C$4.5 million per well.

  • Transerv reviewing options for select farmout to fund initial 3 well program.

  • Horizontal wells have been used to exploit the Rock Creek gas play for the last five years with approximately 30 wells. However, there have been only 5 applications of horizontal wells to the Rock Creek oil play, of which two are still confidential.

Duvernay Shale Acreage

  • The total land holdings of the joint ventures within the liquids rich Duvernay Shale is 128.28 gross sections (82,099 gross acres).

  • The Duvernay formation has been the focus of recent industry attention which generated a one day record land sale of C$750 million for 497 sections (318,080 acres) of land surrounding, or contiguous, with the joint venture’s lands with an average metric of about $2,000/acre ($5,000/hectare).

Comparable Deals

   • In April, 2011, Encana acquired about 190,000 net acres in the Simonette and Kaybob areas of the Duvernay shale in Alberta for approximately US$300 million or an average cost of about C$1,600 per acre (US$1,579 per acre). The company believed that the bulk of the acreage (~2/3 of total acreage) was located in the liquids rich window and planned to drill 3 to 4 horizontal wells in the year 2011, starting in around August. As no Proved Reserves were booked at the time, Derrick ascribed the entire deal value ($300 million) to Undeveloped Acreage ($1,579/ Acre).

  • In June, 2011, Talisman acquired a 100% WI in approximately 255,000 net acres in the Duvernay Shale play in Alberta through land sales for $510 million or $2,000/Acre. Talisman believes this to be a liquids rich shale play.

Duvernay Shale vs Other shales

Derrick Comments

Derrick values this package between $80-$100 million for

1. The value of the Rock Creek farmout option (~7.5 million): This farm out option was disclosed by Transerv (partner), where they are looking for a partner to fund a 3 well drilling program to begin in Sep, 2011. The drilling and completion cost of each well is estimated to be ~C$4.5 million (~US$4.6 million). Hence, the total cost for 3 wells is estimated to be ~$15 million. Assuming a 50% carry for the JV, the value is estimated to be ~$7.5 million.


2. Disposition of 50% of the  Duvernay Shale acreage (~82 million): The value of the JV’s acreage is estimated to be $164 million ($2,000/Acre). Assuming 50% to be sold, the value is estimated to be $82 million. The $/Acre metric is based on the recent June 2011 Alberta land sales where Talisman acquired Duvernay lands for $2,000/Acre ($5,000/Hectare).

The Mako JV Duvernay lands are adjacent to the land where Talisman paid a whopping $5,000/ Ha ($2,000/ acre) for 255,000 acres for a total consideration of $510 million in the 1 June, 2011 Alberta Crown Land Sale. The Mako JV lands were acquired previously for about $200/ Ha, as reported by Transerv. This is a substantial increase in the value of the shale acreage and the Mako JV is looking to capitalize on appreciation in their Duvernay shale property.

No Significant Change in Number of 'Deals in Play' So Far In 2011 In North America

There are no big changes in the numbers of 'deals in play' as measured on 1 Jan, 2011 & 1 Aug, 2011. Apart from an increase by 10 in Aug 1, 2011, the number of opportunities and their spread between country, sub-region/ plays, shales, and conventionals/ unconventionals remains largely the same. This analysis is based on opportunities recorded in Derrick’s “Deals in Play’ database as on 2 different dates: 1 Jan, 2011 and 1 Aug, 2011. Only opportunities where deal values are equal to or greater than $100 million have been considered for this analysis. The following charts show the split up of the number of opportunities vs Sub Region/ Play Type. Additional insights gleaned from this information are presented below.

Chart 1: Number of opportunities Vs Sub Region/ Play Type on 1 Jan, 2011. Source: DPS

Chart 1: Number of opportunities Vs Sub Region/ Play Type on 1 Aug, 2011. Source: DPS


On  Aug 1, 2011, there were 78 assets for sale in North America (US and Canada) with asset/ project values greater than $100 million. This is an increase by 10 in the number of deals in the market in this region as compared to Jan 1, 2011.

On Aug 1, 2011, the most number of deals in play were from Alberta, Canada at 14 (17.94%), for conventional assets/ projects. Deals in play from Alberta were also on top on Jan 1, 2011 at 11 or 16.17% of all opportunities.

Marcellus Shale related packages hold 2nd and 3rd place, in terms of number of packages for sale, as of Jan 1, 2011 & Aug 1, 2011, at 10 & 8 respectively. These numbers have remained constant for both these periods.

On Jan 1, 2011, there were 45 opportunities in the US (66%) and 23 in Canada (34%) as compared to 47 in the US (60%) and 31 in Canada (40%) on Aug 1, 2011.

On Jan 1, 2011, there were 28 (41%) shale opportunities as compared to 34 (44%) on Aug 1, 2011.

On Jan 1, 2011, there were 34 (50%) opportunities related to conventional hydrocarbons compared to 38 (49%) on Aug 1, 2011. On Jan 1, 2011, 34 (50%) opportunities were for unconventional hydrocarbons and on Aug 1, 2011, 40 (51%) were for conventionals.

Shale Assets Dominate North American Opportunities

Analysis of all opportunities for sale (Assets, JV, Corporate M&A, etc) in North America with deal values above $100 million gives the following results seen in Chart 1. Opportunities related to the Marcellus Shale lead the pack at $7.5 billion worth of assets for sale in the US. Oil sands related projects in Canada come second with $4.5 billion worth of assets for sale.  

Figure 1: Chart of total deal value vs play type/ sub-region. Only deals in the market with deal values above $100 million have been considered for this analysis. Source: Derrick Petroleum ‘Deals in Play’ database.

Clearly, there are a lot of shale related opportunities in North America. Shale related opportunities represent ~52% of all opportunities in North America with the rest split between the conventionals (34.8%) and oil sands (12.5%). Marcellus shale related opportunities dominate at ~23% of all opportunities.

Shales are the hottest play in North America at the moment, and deal activity involving them looks set to dominate the oil and gas industry in North America for some time to come. 

CIC acquires 30% stake in GDF’s E&P unit for $3.3 billion. Chinese companies on acquisition spree again.

China Investment Cop (CIC) has inked Memorandum of Understanding to acquire a 30% stake in GDF Suez's gas exploration and production unit. It is believed that CIC will acquire the stake for as much as €2.3 billion ($3.27 billion) and finance GDF to expand power projects in Asia-Pacific.

Facts of GDF

GDF deploys its exploration and production activities in the Netherlands, Germany, the United Kingdom, Norway, Algeria, Egypt, and, in a more limited way, in Mauritania, the Ivory Coast, the USA, Indonesia, Denmark and France. The Group is also present in Azerbaijan, Libya, Australia and Greenland. The key figures concerning the exploration-production sector are as follows:

• 51.2 MMBOE (Gas- 74% and Oil- 26%) produced in 2010
• 815 MMBOE (Gas- 74% and Oil- 26%) in 2P reserves at year end 2010.

Source: GDF SUEZ

Comments on this Chinese Alliance

• There are some uncertainties about this MoU getting finalised. On the other hand if it is finalised, it will be beneficial to GDF to reduce its liabilities by €10 billion to €4 - €5 billion, and to meet the rapidly growing power demand in Asia-Pacific.
• GDF Suez has plans to put the exploration and production business into a separate unit ahead of the capital increase by the end of the year. As part of this, are there any chances for other potential candidates to acquire a strategic stake in GDF following the dilution of 30% stake?
• In 2009, China Investment made significant investments in Russia (Nobel Holdings) and Kazakhstan (KazMunaiGas EP). Last year, CIC formed an oilsands JV with Penn West Energy and committed to invest approximately $800 million in Penn West’s assets. Now, CIC has taken an initiative to venture into Europe. CIC- Quite active in overseas investment and posted 11.7% return on its overseas investments last year.
• Since January 2011, when CNOOC struck a Niobrara JV, there were no acquisitions by the Chinese companies. This $4.28 billion alliance and the recent CNOOC-OPTI oilsands (~$2.1 billion) deal have ended the long break the Chinese companies had taken from acquisition mode. Looks like the acquisition spree has again started!

SandRidge ropes in Korean partner, Atinum, to exploit Mississippian Play in a $500 Million JV. Chesapeake offers $1.5 Bn-Mississippian parcel for sale.

Slow M&A activity in the first week of August has ended with SandRidge Energy's $500 million JV with Atinum.
SandRidge Energy has entered into a joint venture with an affiliate of Atinum Partners Co Ltd, a leading investment firm located in South Korea. The JV area of mutual interest (AMI) covers, substantially, all of SandRidge's original Mississippian Play area, located in Northern Oklahoma and Southern Kansas, other than wells and acreage within the associated spacing units spudded prior to the effective date and all wells and acreage associated with SandRidge Mississippian Trust I.

As per the terms of the agreement, SandRidge will transfer an undivided 13.2% non-operated working interest in approximately 860,000 acres, or approximately 113,000 net acres to Atinum for a total transaction value of $500 million. Atinum will pay $250 million in cash at closing. Atinum has also committed to a drilling carry obligation to pay 13.2% of SandRidge's share of drilling and completion cost for wells drilled in the AMI up to a total amount of $250 million, which is anticipated to occur over a three year period.

Mississippian Oil Play- A new comer to the Unconventional Sector

The Mississippian Oil Play is an emerging horizontal play that has the potential to become one of the most profitable domestic onshore oil plays. This play is led by Chesapeake Energy, SandRidge Energy, Range Resources, Devon Energy and Eagle Energy of Oklahoma LLC. SandRidge Energy is the most active driller in this play with 3,400 drilling locations and 12 horizontal rigs.

The interesting fact about the Mississippi horizontal wells is the rate of return, when compared to other areas being drilled in the industry. The IRR for a Mississippi horizontal well is 120% and better than the average Bakken Shale well at 92%.

Economics of Mississippian Oil Play

• The Mississippian play exists in the shallow depths of less than 6000 feet.
• The cost to drill and complete a well is $3 million.
• The EUR for a well in this play ranges between 300 and 500 Mboe (52% crude oil).
• Low horsepower rigs (< 1,000 hp) and low pressure pumping (~12,500 hp).
• With the availability of extensive existing infrastructure and high IRR, as compared to the Bakken and Eagle Ford oil plays, the exploitation and development of Mississippian play is feasible and profitable.

The following table illustrates the comparison of single well economics of the unconventional oil plays-

SandRidge has made a good deal with Atinum. Chesapeake to follow.

SandRidge had accumulated the Mississippian acreage over a period of 3 years at an average cost of ~$200/acre or ~$170 million. However, the current transaction returns a value of $4,425/acre to SandRidge Energy and $/acre is increased by more than 20 times. This value of the acreage should also be attractive for Chesapeake who holds approximately 1.1 million net acres in this play. Chesapeake, in May 2011, had initiated a joint venture process for the same play. The highlights of Chesapeake holdings in the play are as follows- 

Chesapeake’s Mississippian play:
-- ~1.1 million net acres.
-- As of May 2011, Anadarko Basin had total of 1,990,000 net acres; Proved reserves of 2,184 Bcfe; Unrisked unproved resources of 33,500 Bcfe; April 2011 daily net production of 510 MMcfe.
-- As of October 2010, Mississippian play completions: ~230,000 net acres; 21 MMBOE of Proved reserves; ~145 MMBOE of risked unproved resources; ~385 MMBOE unrisked unproved resources; Net production in October 2010 was 3 MBOE/d.
-- To date, Chesapeake has drilled 53 operated Mississippian horizontal wells and has participated in the drilling of 36 non-operated Mississippian horizontal wells.
-- Currently drilling with five operated rigs.
-- Plans to increase its operated drilling activity in the Mississippian to seven rigs by the end of Q4-2011.

Source: Derrick Petroleum "Deals in Play" Database

Husky Seeks JV Partner for Accelerated Development of its Ansell, Liquids Rich, Gas Assets

Husky’s chief executive, Amit Ghosh, said in its 2nd quarter conference call, that the company is seeking a joint-venture partner to accelerate development of an emerging liquids-rich natural gas play in western Alberta.

Husky has created a preliminary development plan which could potentially see up to 2,600 Cardium and deeper Manville formation wells drilled in its Ansell assets, most of which would be horizontal. In the first two quarters of 2011, Husky drilled 21 Cardium Formation wells at Ansell. A further 12 Cardium and nine deeper multi-zone wells are planned to be drilled in the second half of 2011. The company is currently constructing additional offload capacity on its own, which will increase total production capacity at Ansell to 56 MMcf/d and over 2,000 Bbls/d liquids.

As prices for natural gas continue to remain low, North American natural gas producers have shifted focus towards fields rich in natural gas liquids, which trade at prices close to crude oil, and the Ansell property is one such liquids rich gas field, which could benefit from further development. 

Analyst Comment

Assuming a 50% JV for the undeveloped acreage of 150,000 acres, we value the 50% JV to be between $60 - $80 million. This valuation is based on similar recent deals in the vicinity involving the Cardium Formation acreage where the acreage metric was between $1,200/acre - $1,800/acre. 

Derrick 'Deals in Play'

Derrick has aggregated all publicly announced properties for sale. Derrick’ Deals in Play is the most comprehensive data set of its kind in the industry. This special feature includes every deal ranging from the large packages being brokered through investment banks to the much smaller, non-brokered prospects. For more information click here. 

Petrobras to sell $13.6 billion worth of assets in 2011 - 2015

Petrobras, Brazil's largest company, came out with its 2011 -2015 business plan last week. For the first time, Petrobras said in its business plan, it is looking to divest $13.6 billion worth of assets over the 2011 - 2015 period.

Reuters quoted its chief executive, Jose Sergio Gabrielli,  as having said on Monday, that as part of its divestment plan, Petrobras will look at selling stakes in some of its offshore oil blocks. Also, the company would sell stakes in some of its oil exploration and production projects, and partners in those projects would also be allowed to buy stakes. However, sale of its production assets would reportedly not involve its pre-salt  blocks.

Petrobras’ exploration is primarily focused in three major offshore basins in southeastern Brazil: Campos, Espirito Santo and the Santos basins. As of December 31, 2010, the company held exploration rights in 21 blocks comprising 6,374 sq km in the Campos Basin, 19 blocks (16 offshore blocks) comprising 8,086 sq km in the Espirito Santo Basin and 47 blocks comprising 29,302 sq kms in the Santos Basin. Petrobras also produces hydrocarbons and holds exploration acreage in 19 other basins in Brazil. Of these, the most significant are the shallow offshore Camamu basin and the onshore Potiguar, Reconcavo, Sergipe, Alagoas and Solimoes basins. In 2010, the company’s average daily production from its Brazilian assets was 2,165.5 MBOE/d.

Figure 1: Petrobras concession areas, Brazil. Source: Petrobras

Outside Brazil, Petrobras has significant operations in Argentina, Venezuela, Colombia, Peru, Ecuador, Bolivia, Gulf of Mexico, offshore Nigeria, Angola, Portugal, Turkey, Senegal, Libya, Tanzania, Mozambique, Iran, Pakistan and India. In 2010, the company’s average daily production from the International assets was 2,405.4 MBOE/d.

Petrobras is planning to divest $13.6 billion worth of assets over five years, which equates to approximately $2.5 billion worth of assets to be sold every year.

Derrick 'Deals in Play'

Derrick has aggregated all publicly announced properties for sale. Derrick’ Deals in Play is the most comprehensive data set of its kind in the industry. This special feature includes every deal ranging from the large packages being brokered through investment banks to the much smaller, non-brokered prospects. For more information click here. 

67 Unconventional Assets for Sale as of July 2011

There are many unconventional packages put up for sale, with most in the US or Canada. Given the flurry of unconventional deal activity recently, it wouldn’t be surprising if unconventional deal volumes and values reach record highs this year.

Jack Williams, president of the Irving, Texas-based ExxonMobil's XTO unit, which was acquired by ExxonMobil in June 2010, says that Exxon is looking to expand its shale gas holdings in more than a dozen gas-rich shale-rock formations worldwide. Exxon is also getting active internationally, starting hydraulic fracturing on formations in Poland this year and last week agreeing with China Petrochemical Corp. to jointly assess the resource’s potential in China. Although gas prices have been relatively low, Exxon is reportedly pleased with the returns they’re seeing with production from their unconventional assets, and particularly XTO’s assets.

This announcement by Exxon comes on the back of a series of multi-billion dollar deals involving unconventional (shale) transactions. Last week, BHP Billiton agreed to acquire Petrohawk Energy for $12.1 billion to expand its shale gas holdings in the US. Since June 1, companies including Exxon, Marathon Oil Corp. and Malaysia’s Petroliam Nasional Bhd have announced at least $7 billion worth of North American shale-gas deals.

The following table shows unconventional opportunities for sale recorded in Derrick’s “Deals in Play’ database, part of Derrick’s ‘E&P transactions’ database

Table 1: Unconventional opportunities available in US and Canada as of July 2011. Click on squares to get to the detailed deal sheet. Source: Derrick Petroleum Services. *HRB = Horn River Basin.
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There are currently 67 unconventional oil and gas packages for sale in the market. The majority of these packages are located in the USA (46) and most of them are either for unconventional oil (21) or unconventional gas (21). A large number of packages are for investments in undeveloped discoveries (30) and for investments in fields under development (20). Eagle Ford Shale has the most number of opportunities at 12 followed by the Marcellus Shale at 7. Most packages are related to selling undeveloped acreage (36), followed by Joint Venture related opportunities (17)

      

E&P Opportunities in Asia in 2011

There are 33 opportunities recorded and analysed in Derrick’s ‘Deals in Play’ database for the 2 previous years till date (July 2011). A sample of these opportunities is shown in the chart below.

Indonesia has the highest number of opportunities at 9 followed by the Philippines at 5, India and Myanmar at 4 each and Vietnam at 3. Pakistan has 2 opportunities and Bangladesh, Brunei, China, Lebanon, Malaysia and Sri Lanka have 1 each.

There is 1 corporate M&A and 18 exploration/ developing undeveloped discoveries opportunities. 1 opportunity is related to producing fields and 3 are related to fields under development. 9 opportunities are for new exploration awards by governments/ NOC’s and 1 opportunity involves a mix of asset types.

Table 1: Sample of E&P Opportunities available in Asia with sellers, country and year of announcement shown. Hover over squares for additional information. Click on squares to go to the deal sheet in the ‘Deals in Play’ database (Pop ups need to be allowed).

Derrick has valued 5 deals where valuation was possible (e.g., asset sales). The sellers here are
a.GeoGlobal Resources
b.Union Fenosa Gas
c.Hycarbex-American Energy
d.Inpex
e.ConocoPhillips
For further information click on the companies above.

For information about Derrick Petroleum Services ‘Deals in Play’ database write to sanjay.samuel@derrickpetroleum.com or sales@derrickpetroleum.com.

Shell opts out of Mackenzie Gas Project in Canada

Shell is looking to divest its interest in the Mackenzie Gas Project which consists of
      a. Development of one of 3 natural gas fields in the Mackenzie Delta region, and its production facilities, that is planned to be tied into the Mackenzie pipeline; Taglu (Imperial Resources Canada 100%), Parsons Lake (ConocoPhillips 75% and ExxonMobil 25%) and Niglintgak (Shell Canada 100%). Approximately 6 Tcf of natural gas has already been discovered in the three fields.
     b. A gathering pipeline system
     c. A gas processing facility near Inuvik (the Inuvik area facility)
     d. A natural gas liquids pipeline from the Inuvik area facility to Norman Wells
     e. A 11.4% stake in the long delayed, 1,196-kilometre natural gas pipeline from the Inuvik area facility to        northwestern Alberta.

The Niglintgak natural gas reservoir is located at the southern end of the Niglintgak Island in the Mackenzie Delta, about 120 km northwest of Inuvik and about 85 km west of Tuktoyaktuk. Niglintgak is held 100% by Shell Canada. The field holds 1 Tcf of gas, and according to regulatory filings, its development would cost C$800 million. Subject to regulatory approval, drilling activities could begin in the winter of 2011. Drilling is expected to take three winters. Based on this schedule, production of natural gas would begin in 2014. The estimated operational life of the Niglintgak field is estimated to be about 25 years.

Derrick values the upstream portion of the deal to be between $300 - $350 million. The 1 Tcf of recoverable reserves is valued at $1.8 - $2 /BOE. This metric is based on a similar deal in the region involving MGM Energy and KOGAS in Dec 2010, where the contingent resources of the Umiak SDL 131 field was valued @ $2/BOE. The gas from the Umiak field is also to be tied up with the Mackenzie Valley Pipeline.

The Mackenzie pipeline has hit many delays and questions are being raised about its economic viability, given the abundance of shale gas that is being developed in North America, high construction costs and low gas prices. However, the chief executive of Imperial Oil, the lead partner in the project, has affirmed that they are still committed to going forward with the pipeline project. It is planned that the pipeline will carry 1.2 bcf of gas daily. Shell says it wants to focus on other opportunities.

Buyers have until August 31 to make their bids.

Shell Canada also recently announced they are looking for a JV partner to develop its Nikanassin Play in its Chinook Asset in Canada’s Deep Basin.

CNOOC to acquire OPTI Canada for $2.1 billion. Nexen gets a healthier and wealthier partner.

CNOOC has agreed to acquire OPTI Canada, for a consideration of approximately US$2.1 billion, subject to regulatory and shareholders approvals. Through this acquisition, CNOOC will own a 35% working interest, with Nexen holding the balance 65% in the four oil sands projects- Long Lake, Kinosis, Leismer, and Cottonwood, located in Alberta.

Source: CNOOC


Acquisition Highlights (OPTI’s interest):

• 195 million barrels of proved reserves
• 534 million barrels of probable reserves
• 1,100 million barrels of contingent resources
• 335 million barrels of prospective resources
• ~10,000 bbl/d bitumen production at Long Lake
• 90,944 net acres owned by OPTI
• Existing Upgrader built and operating at the Long Lake site
• Increases CNOOC’s reserves and production by 5.3% and 1%, respectively

Source: CNOOC

Deal Valuation
It is estimated that the value of Contingent Resources for Long Lake and Kinosis projects to be $415.20 million (at $0.60/BOE). The remaining deal value of $1,660.30 million is ascribed to Proved plus Probable Reserves of Long Lake project ($4.90/BOE or $158,124/Daily BOE).

Note: Although OPTI has reported probable reserves for Kinosis project, it is believed that as the project is not yet developed, the probable reserves are counted under the contingent resources. The contingent resources associated with Leismer and Cottonwood projects are not included for valuation as they are not planned to be developed in the medium term.

CNOOC- the healthier partner for Nexen

Last week, Opti Canada had filed for bankruptcy protection in Alberta as the company ran out of cash to fund its oil sands operations. In this regard, CNOOC’s proposal to acquire OPTI rescues not only OPTI but also Nexen as it has got a wealthier partner for its oil sands assets. Nexen has revealed that it will ramp up the drilling at its Long Lake oil sands project to use the processing plant more effectively.

Source: OPTI Canada

Canadian Oil Sands - resources and related deal activity

Alberta’s oil reserves are located in three main areas: Peace River, Cold Lake, and Athabasca. The Athabasca oil sands area, where OPTI and Nexen own substantial resources, is the richest of the three and has the most concentrated oil sands development.

Canada's oil sands are estimated to hold as much as 175 billion barrels of bitumen (Source: Energy Resources Conservation Board (ERCB)). ERCB reports that oil sands bitumen production is currently around 1.5 million barrels per day and expects the oil sands production to reach 2.7 million barrels per day by 2015. The oil sands projects are believed to have a steady production profile of up to 50 years with no decline.

Eighty percent of all bitumen resources in the Athabasca oil sands region are too deep to mine and hence these bitumen resources have to be recovered using in-situ techniques, such as SAGD. It is estimated that Canadian oil sands resources represent 13% of the world’s total crude oil reserves, ranking second only after Saudi Arabia (Source: Energy Information Administration).

Source: CNOOC

The deal activity with respect to oil sands was completely down since the beginning of 2011. The last major acquisition by the Chinese companies in the oil sands was in April 2010, when Sinopec acquired Syncrude project from ConocoPhillips for $4.65 billion.

The following table shows the oil sands deals since 2005.

Source: CNOOC

The Chinese companies were active in acquiring oil and gas assets past one year. The significant (greater than $1 billion) acquisitions include:

• Sinopec acquiring 40% interest in Repsol's Brazilian business for $7.1 billion
• Sinopec acquiring Syncrude project from ConocoPhillips for $4.65 billion
• CNOOC and Bridas acquiring Pan American Energy from BP for $3.5 billion
• CNOOC acquiring Niobrara shale assets from Chesapeake for $3.5 billion
• Sinopec acquiring Argentina unit of Oxy for $2.45 billion

Petrochina failed to acquire Encana's Montney assets in a $5.4 billion bid made in February 2011. Notably, there were no acquisitions made by the Chinese companies since then.

Prior to this $2.1 billion oil sands deal, CNOOC clinched a back to back Niobrara JV with Chesapeake. The acquisition trend of CNOOC in North America discloses an interesting fact that, CNOOC is interested in acquiring oil assets unlike other Chinese or Asian companies who were/are interested in unconventional gas assets.

Mozambique: Oil & Gas Exploration in 2011 – 2012

Mozambique is a country in East Africa present between Tanzania on the north and South Africa in the south. A string of significant gas discoveries in the off shore north-east has substantially increased the prospectivity in the country and exploration activity looks set to pick up.

The country has two main sedimentary basins; the Rovuma Basin in the north east, where most of the discoveries have occurred, and the Mozambique basin further south. The Rovuma Basin is located close to the border between Tanzania and Mozambique, at the Rovuma delta, and measures 400 km in length and about 160 km in breadth. The area towards the south follows the Ibo horst trend and towards the north, it is featured as a tertiary Rovuma delta.

The Pande gas field, discovered by Gulf Oil, was the first field to be discovered in Mozambique, in 1961. This was followed by the Búzi (1962) and Temane (1967) gas fields. Exploration activity on the Pande/ Temane block by Sasol later led to the discovery of the Inhassoro gas field.

The consortium exploring the Offshore Area 1, led by Anadarko, has been the most successful so far with 4 significant gas discoveries. These are listed below:

Discovery Name	Net Pay (ft)	Gross Pay (ft)	Oil/ Gas	Total Depth	Date	Reservoir rock	Future Work
Windjammer	555	> 1200	Gas	16,930	Mar-2010	Oligocene + Paleocene	Coring program completed (part of appraisal work)
Collier		-	-	10,500	Apr-2010	-	Plugged and suspended following pore pressure issues. Did not evaluate the desired section.
Ironclad	124		Oil	17,402	Aug-2010	Cretaceous	Plugged and abandoned as sands had low porosity and permeability
Barquentine	416		Gas	16,880	Oct-2010	Oligocene + Paleocene	Appraisal
Lagosta	550		Gas	16,307	Nov-2010	Oligocene + Eocene	Coring program completed (part of appraisal work)
Tubarao	110		Gas	13,900	Feb-2011	Eocene	Appraisal

Table 1: Windjammer, Barquentine, Lagosta and Tubarao encountered substantial gas. The Ironclad well is significant because it encountered an oil column (although non-commercial), which was the first time oil was discovered in offshore Mozambique or in the deep offshore off East Africa.Source, Derrick Petroleum Services.

Source: Wentworth Resources

An overview of exploration activity planned in the country is provided in the table below, along with an account of recent exploration from Derrick Petroleum’s “Exploration Database” is provided below.

Block/ License Name	Operator	Onshore/Offshore	Hydrocarbon	Wells planned in 2011	Wells planned in 2012+
Offshore Area 1	Anadarko	Deep Offshore	Gas	1	6
Onshore Rovuma Block	Anadarko	Onshore	Not mentioned		1
Buzi Block	Energi Mega Persada	Onshore	Gas	1
Inhaminga	DNO International ASA (DNO)	Onshore	Not mentioned	1
Blocks 2 & 5	StatoilHydro	Deep Offshore	Not mentioned
Area 4	ENI	Deep Offshore		1

Table 1: Operators planning to drill exploration wells in Mozambique in 2011 and 2012+. Source, Derrick Petroleum ‘Planned Wells Exploration Database’

Offshore Area 1:
Anadarko is the operator of the 2.6-million-acre Offshore Area 1 with a 36.5% working interest. Co-owners in the area are Mitsui E&P (20 %), BPRL (10 %), Videocon Mozambique Rovuma 1 (10 %) and Cove Energy Mozambique Rovuma Offshore (8.5 %). Empresa Nacional de Hidrocarbonetos, E.P.'s 15- interest is carried through the exploration phase. An overview of the recent exploration activity in this area is given in Table 1, and the 4 discoveries can be seen in Map 1.

The consortium is planning to acquire 3D seismic over the Black Pearl prospect in Q1-Q2 2011, following which exploratory drilling would occur. In 2012, the consortium plans to drill the Atum-1, Golfinho-1, Linguado, Badejo-1, Camarao and Black Pearl prospects.

Onshore Rovuma Block:
Anadarko (37.5%) operates this block and the partners are Maurel & Prom (24%), Wentworth Resources Ltd (15.3%), Cove Energy Plc (10%) and ENH (15%). On October 11, 2009 the first exploration well on the block, Mecupa-1,was spudded. It had minor gas shows and was plugged and abandoned.

At present (July 2011), the partners have agreed to enter a 2nd exploration phase beginning in 2011. The work programme is expected to include additional seismic acquisition and at least one exploration well.

Buzi Block:
This onshore block is operated by Energi Mega Persada (75% WI) and partner is ENH (25%). The Buzi block is located onshore within the central part of the Mozambique Basin and covers approximately 10,300 km2 and lies immediately to the North of the Pande, Temane and Inhassoro Gas fields. The undeveloped Buzi gas discovery within the block, is only 27 km to the southwest of Beira. Initial plans included two exploration wells and possibly two appraisal probes, should gas be discovered. This is yet to be done.

The consortium was planning to spud its first well on the block in 2011 as announced in 2009. However, as on 30 June, 2011, no information about drilling has been released by either of the partners.

Inhaminga Block:
The Inhaminga Block lies onshore Mozambique. DNO International (34% WI) operates the block and partners are New Age Ltd (41%), Harmattan Uruguay S.A., and the Mozambique government (20%). DNO International has planned to carry out 2D seismic program on the block in H2 2009. The first prospect Chite was drilled on 19 November, 2010. However, the well was dry and was plugged and abandoned. The second well Inhaminga High-1 well was spudded in Feb 2011, and was also dry.

DNO says in its 2010 annual report that it plans to drill a well here in 2011. However, media reports mention that DNO will close down its operations in Mozambique after drilling unsuccessful wells.

Blocks 2&5:
Blocks 2 & 5 are located in the Rovuma basin offshore northern Mozambique, and operated by Statoil (90% WI) with partner ENH (10%). A 1,300 sq km 3D seismic survey was carried out between March & June 2010 and interpretation is ongoing as of March 2011. The decision to extend the license and commit to drilling an exploration well was supposed to have been made by 1 June 2011, but as on 1 July, this decision is still forthcoming. 

Area 4:
ENI operates the block with a 70% WI. Other partners are Galp Energia (10%), ENH (10%) and KOGAS (10%). Area 4 is located in deep water up to a depth of 2,600 metres in the Rovuma Basin and covers an area of 17,646 sq kms in a previously unexplored geological basin, and this operation is part of Eni's strategy to identify new areas with a high exploration potential.

The consortium is planning to drill a well in September 2011.