East Africa Set for Major Gas, Oil Transformation

By Jacinta Moran in Cape Town; Edited by Jeremy Lovell, Platts, Jul 12, 2012
Oil and gas activity has started rolling in East Africa, as drilling activity ramps up, long-awaited deals are sealed and oil companies scramble to get a slice of what could be an energy goldmine. (see related map: East Africa oil and gas resources) [or right here below

click on map to enlarge -- D.R.]

In Uganda, Tullow Oil has resolved a long-standing dispute with the government for the development of a number of oil-rich blocks, and the UK-listed explorer has also made Kenya's first ever major oil discovery.

Significant gas reserves have been found in Mozambique and Tanzania, where LNG facilities are now been planned. Drilling will kick off in Ethiopia later this year, while Madagascar is believed to hold significant reserves of gas and the Puntland region of Somalia is also showing positive signs. [Read more]

(Also, please see my posts "East African Oil & Gas" and "Third Tanzanian Gas Discovery for Ophir-BG. For gas reserves, please see "Wood Mackenzie: East Africa’s Yet-to-Find Reserves Hold 95 tcf of Gas," OffshoreEnergy Today.com, Aug 22, 2012---Recent discoveries and high profile M&A activity in Mozambique and Tanzania are attracting attention and Martin Kelly, Wood Mackenzie’s Head of Sub-Sahara Upstream Research, says the interest is justified: “100 tcf of gas has been discovered to date in East Africa and we estimate yet-to-find reserves could be as much as 80 tcf in Mozambique and 15 tcf in Tanzania. There is clearly plenty of gas to supply the likely commercialization route of LNG – theoretically enough to support up to 16 LNG trains. “The Rovuma basin is the most prolific in the region, and one of the hottest conventional gas plays in the world, with 85 tcf discovered so far. Globally in 2011, it yielded the third most hydrocarbons, and we expect it to top the list in 2012 if the first half of the year is anything to go by,” Kelly continues. Update:  East Africa may be the new hotspot for explorers but the region will first need to invest in infrastructure to develop and transport the products for domestic and international consumption. The region's regulatory and infrastructure gaps could hinder the transition from gas exploration to production in the medium term, while governments need to be more realistic about timeframes for revenue flows, delegates heard at an industry conference in London on October 2, 2012. [...] Total now expects first commercial oil in Uganda in 2017, a year later than originally expected. The French major entered Uganda's nascent industry early this year after it and China's CNOOC took a third of Tullow's assets for $2.9 billion---please see Jacinta Moran "East Africa Faces Energy Infrastructure Issue," Platts, Oct 4, 2012 -- D.R.)
 

Purvin & Gertz Estimates Future [U.S.] Unconventional Oil Output

by Paula Dittrick, OGJ Senior Staff Writer, OGJ, Jun 24, 2011
Unconventional oil production from the Bakken, Eagle Ford, and Niobrara plays is expected to approach 900,000 b/d in 2015 and exceed 1.3 million b/d by 2020, a consultant forecast.

Purvin & Gertz Inc. estimates current oil production from the Bakken, Eagle Ford, and Niobrara plays at 350,000-400,000 b/d.

The Bakken formation is in North Dakota and Montana, the Eagle Ford is in South Texas, and the Niobrara is in Colorado and Wyoming.

Geoff Houlton, a vice-president with Purvin & Gertz in Houston, told OGJ that shale oil production likely will help offset US oil import volumes in coming years.

Increasing supplies of light, sweet crude from shale oil plays are expected to reduce oil imports of similar quality crude into the Gulf Coast by greater than 500,000 b/d by 2016, he said.

Purvin & Gertz released its base-case forecast in a study entitled “US Midcontinent Crude Oil Market Analysis,” which examined oil logistics and pricing. [Read more]

(Current production from the Eagle Ford is roughly 100,000 barrels per day of crude oil and condensate >> OGJ, May 6, 2011 or EPP press release May 3, 2011. Also, please see my post "BENTEK: Eagle Ford Crude Oil Production Expected to Grow Fivefold in Five Years," here. For maps of the Eagle Ford shale, please see here. For the map of North American shale plays from the U.S. Energy Information Administration/EIA, including the United States, Canada and Mexico, as of May 9, 2011, please see here. Operators increased North Dakota's Bakken production from less than 3,000 barrels per day in 2005 to over 230,000 barrels per day in 2010. The Bakken's share of total North Dakota oil production rose from about 3 percent to about 75 percent over the same period. North Dakota produced an average of 307,000 barrels of crude oil per day in 2010 and comprised about 5.6 percent of the nation's total crude production. The increase in U.S. crude oil production in 2010 was led by escalating horizontal drilling programs in U.S. shale plays---please see my post "United States: Oil Production from Shale Formations, 2005-2010 -- EIA," here. UPDATE: In its Twitter post on June 25th, Platts said, "About 50,000 b/d of Bakken crude oil not being shipped out of N. Dakota due to record flooding in Minot area: state official." -- D.R.)

[...] US Ambassador [to Canada] Backs Increased Canadian Oil-Sands Imports

Petroleum Economist, June 9, 2011
The US government considers Canadian oil supplies an essential ingredient of energy security, even as competition for resources and assets ratchets up with rival China.

Speaking in Calgary, US ambassador to Canada David Jacobson described his country's need for greater imports from stable sources such as Canada to offset dependence on unstable regimes in the Middle East and North Africa. "The US sees Canada as a pillar of our energy security," he said.

It is already the largest energy-trading relationship in history, with Canada accounting for about 22% of US import demand [please see my post "U.S. Crude Oil Imports from Top 15 Countries, Dec 2010 and Full Year 2010," -- Canada supplied about 22% of total US crude oil imports in 2010, i.e., 1.97 million b/d of crude/please also see chart below, out of a total US imports of crude of 9.16 million b/d, as well as about 22% of total US crude oil and products imports in 2010, i.e., 2.532 million barrels per day---1.97 million b/d of crude oil plus 0.56 million b/d of petroleum products---out of a total US imports of crude and products of 11.753 million b/d -- D.R.). Alberta alone pumps about 1.4 million b/d to US refineries or 7% of overall US consumption [U.S. oil consumption increased by some 380,000 b/d or 2.0% to 19.148 million b/d in 2010, compared to the previous year---please see my post "Top 25 World Oil Consumers, 2009-2010." Separately, of the estimated 2.9 million b/d, sic, of crude oil produced in Canada in 2010, 1.5 million b/d of that was derived from the oil sands of Alberta---please see EIA. -- D.R.].

Canada long ago surpassed Saudi Arabia as the top supplier to the world's largest oil consumer and that relationship is poised to grow exponentially as Canadian producers increase production of oil-sands crude.

Canadian exports to the US have more than doubled since 1993 [US imports from Canada of crude oil increased from 900,000 b/d in 1993 to 1,972,000 b/d in 2010, and US imports from Canada of crude oil and petroleum products increased from 1,181,000 b/d in 1993 to 2,532,000 b/d in 2010 -- D.R.] and are set to double and quadruple over the next two decades.

According to IHS Cera, Canadian oil sands could supply 6.3 million b/d by 2035, not including any other conventional and unconventional production that would push the figure past 7 million b/d. Only Russia and Saudi Arabia would have larger output, IHC Cera added, vaulting Canada into the top tier of oil-producing nations. [...]

But that looming reality seems lost on US President Barack Obama, who has seemed to be reluctant to fully embrace the oil sands even as he has talked of the need to reduce imports from unstable and hostile regimes.

A series of nagging doubts have led some Canadian observers to question the president's energy priorities. For instance, the State Department has held up approvals for TransCanada's Keystone XL pipeline to the Gulf coast [where there are more refineries capable of handling the unusually thick crude, i.e. the heavy, high-sulphur bitumen, and please see map below -- D.R.] while it carries out environmental assessments of the carbon intensity of Canadian oil sands and heavy crude in a move seen as bowing to environmental groups. [...]
                  [Click on map to enlarge]

                                                                    Source: PE, here.
Fearing the worst from Obama's climate-change and clean-energy initiatives, the Canadian and Alberta governments have lobbied against the adoption of clean-fuel standards and other environmental policies they claim would discriminate against Canada. [...]

Feeling snubbed by this seeming US indifference, Canada has been courting Asia, and particularly the Chinese, as an alternate buyer of its growing output.

China consumes less than half as much oil as the US [please see my posts "Top 25 World Oil Consumers, 2009-2010 -- EIA." and "Top 21 World Oil Consumers, 2007-2010 -- BP," -- D.R.], but will overtake it in a matter of decades, said Wenran Jiang of the University of Alberta's China Institute [According to the BP Energy Outlook 2030, China is the largest source of oil consumption growth, with consumption forecast to grow by 8 million b/d a day to reach 17.5 million b/d by 2030, overtaking the US to become the world's largest oil consumer -- D.R.]. And like the US, China considers Canadian energy supplies to be vital to its security and economic growth.

About 80% of China's imports must pass through the Malacca Strait and its is keen to diversify supply chains away from vulnerable shipping lanes in Southeast Asia. [Also, please see my post "What is Beijing Willing to Do to Secure Oil and Gas Supplies?" and my post "China: Taking Oil Home," -- D.R.] [...]

While the US dithers over whether to embrace "dirty oil" [please see remarks below -- D.R.] from Canada, Chinese state-owned entities have been on a shopping spree, snapping up C$20 billion ($19.8 billion [sic]) worth of assets in less than two years and forming operating partnerships with Canadian firms for both oil sands and unconventional shale gas.

There is presently no way of shipping that oil to China, but there is a growing call in Canada to do just that.

Enbridge's proposed Northern Gateway pipeline to Canada's west coast is seen as a way of opening up overseas markets and gaining higher world oil prices. [Read more]

Source: U.S. Energy Information Administration (EIA), Today in Energy, Jun 14, 2011, here.

(Canadian oil producers have been clamoring for an outlet for their oil to reach the Gulf Coast, reliving a glut that's accumulated in Cushing, Oklahoma, where several pipeline routes terminate --- the delivery point for the West Texas Intermediate benchmark. The large amount of oil stranded in Cushing has led to a deep discount in crude-oil prices in the region and on the New York Mercantile Exchange. In March, the U.S. State Department delayed approval of the 1.1-million-barrel-a-day TransCanada Corp. Keystone XL pipeline expansion that would bring Canadian oil to the Gulf of Mexico. Environmental groups have raised objections about the possibility of oil spills. Alberta Energy Minister Ron Liepert called for the U.S. State Department to quickly approve the extension of a controversial oil pipeline to the U.S., adding that Canada has other potential customers for its oil. Canada is the biggest supplier of foreign oil to the U.S. but Minister Liepert said Canada is "actively cultivating" relationships with China and other emerging markets, where energy demand is growing rapidly---please see MarketWatch, May 16, 2011. In regard to environmental concerns surrounding oil sands production, Minister Liepert states, “We have been a leader in terms of initiatives around the environment. We have made significant advancement in tailings [Tailings are a mixture of fine clay, silt, sand, water and residual bitumen produced through oil sands extraction -- D.R.] management. Tailings are associated only with the mining operations, which is less than 50 per cent of the oil sands production now and continues to decline as a percentage of production.” He continues, “We have a 15 dollar per ton carbon tax, and most of the large operations in the oil sands fall under that. The tax goes into a clean energy fund. Alberta only has a population of 3.5 million people, but has invested $2 billion—probably the largest of any jurisdiction in the world—into carbon capture and storage.”---please see Energy Digital, Jun 14, 2011. -- D.R.)

Manifa to Yield 500,000 b/d by 2013 and 900,000 b/d by 2014 -- Aramco

by David Rachovich

                                Source: Saudi Aramco via OffshoreEnergyToday.com Feb 23, 2011

                                                       Source: Saudi Aramco website 

                [Click on map to enlarge]

                                                                             Source: Saudi Aramco via EIA, here.

"Significant progress was achieved in 2010 on Manifa, the giant Arabian Gulf offshore field under development [emphasis mine and please see map and images above -- D.R.]," Saudi Aramco said in its 2010 annual review, published on Monday (June 6).

"Project elements completed during the year included all drilling islands, as well as the main and lateral causeways. Construction of the Manifa Central Processing complex has begun, with the main spine and process area pipe rack completed. The Manifa development will accommodate a Central Processing Facility with gas-oil separation, wet crude handling, crude stabilization, gas gathering and compression, produced water disposal, water injection and other related facilities. Field development includes 41 km [25 mi] of causeways and 3 km [1.9 mi] of bridges to support 27 [man-made] drilling islands for the shallow water wells, and 13 offshore platforms for deeper water producing and water injection wells. Onshore facilities include 15 drill sites, a Central Oil and Gas Processing Facility, water supply wells and injection facilities, and multiple gathering, water injection, and product transportation pipelines," it added.

"Manifa is designed to produce in staged increments --- 500,000 [barrels per day] bpd of Arabian Heavy crude oil by 2013 and 900,000 bpd by 2014," the report said. And output "will be used as feedstock for planned refineries in the Kingdom [i.e., for two new deep-conversion refineries at Jubail and Yanbu -- D.R.]."

The Manifa Drilling Team set a new record in December 2010 when it finished drilling the longest well in Saudi Arabia to a total depth of 32,136 ft (± 9.8 km) and completed a horizontal power water injector across the Lower Ratawi reservoir. Calgary Precision Drilling rig did the work on the Manifa well. The same drilling team set an earlier record while working on the 30,850 ft (+9.4 km) Manifa well.

Discovered in 1957, Manifa field is in shallow waters southeast of Tanajib, about 200 km (124 mi) northwest of Dhahran. The oil production started when the C reservoir came on stream in 1964, and the B reservoir was brought on production in 1974. Manifa produced heavy crude oil with about 27° API gravity. The field was shut in during January 1984, due to low demand with less than 1% of the reserves produced (Saudi Aramco Journal of Technology, Summer 2009).

Development strategy of Manifa, the world's fifth-largest oil field, is based on optimum use of onshore drilling. Instead of developing Manifa completely from offshore platforms, it is developed from 27 offshore man-made drilling islands connected by a causeway, in addition to onshore drill sites and offshore platforms. Extended-reach wells such as the two mentioned above are required for optimum field coverage. "Manifa field is located in shallow and environmentally sensitive waters, necessitating maximizing drilling from onshore sites while minimizing offshore platforms," the report argued. Actually, the state-of-the art extended reach drilling (ERD) technology reduces the high capital and operating costs of large offshore structures (jackup rigs or shallow water rigs, with legs that reach the bottom of the sea floor) and at the same time minimizes the environmental impact in this sensitive near-shore area.

"The Kingdom's longer-term concern is over whether it needs to increase oil production capacity to meet likely future demand. The Saudi view on oil markets has altered sharply from where it was a year ago, when a battered global economy was still limping out of recession. Riyadh thinks medium- to long-term oil demand growth may be higher than it had previously anticipated, driven by China, India and also Middle East itself, and discussions are now taking place on whether the Kingdom should raise oil output capacity beyond its current 12.5 million b/d," Petroleum Intelligence Weekly (PIW) said in its article "Saudis Consider Need to Raise Output Capacity." "Now, while no decisions have yet been made and while work is unlikely to start this year, expansions at Shaybah, Manifa and Khurais are back on the table," it maintained. "Aramco has already decided to bring forward the 10 billion- 14 billion bbl Manifa project, and could now expand its capacity from 900,000 b/d to 1.2 million b/d," the article said.

During the May 2010 Offshore Technology Conference, Zuhair Al-Hussain, Aramco vice-president, drilling and workovers, said production from Manifa will start in mid-2013 but will not ramp up quickly to the original target of 900,000 b/d of Arab heavy crude (Oil & Gas Journal via my post).

Saudi Aramco Annual Review 2010 is available for download on the Saudi Aramco website at: http://www.saudiaramco.com/content/www/en/home.html#news%257C%252Fen%252Fhome%252Fnews%252Fpublications-and-reports%252Fcorporate-reports0%252FAnnualreview.baseajax.html

(Update 1: Saudi Oil Minister Ali al-Naimi, chairman of the board of directors at Saudi Aramco toured oil and natural gas installations in the country on October 16, 2012, as part of a review of the country's long-term energy prospects. During the tour with the Board members, HE Naimi launched the Manifa Field’s reservoir water injection operations in preparation for first phase production of Arabian Heavy crude oil at an initial capacity of 500,000 barrels per day (bpd) in the first half of 2013, and which will gradually increase to 900,000 bpd by 2014. The crude oil from Manifa will feed local refineries that are currently under construction, namely the 400,000 b/d SATORP refinery in the easterm Saudi Arabian city of Jubail with France’s Total, and the 400,000 b/d YASREF in Yanbu' on the Red Sea, the joint venture with Sinopec of China (Aramco has said the new Yanbu refinery, which joins two existing refineries at Yanbu, will produce 90,000 b/d of gasoline, 263,000 b/d of ultralow sulfur diesel, and 6,300 tonnes/day (tpd) of petcoke as well as 1,200 tpd of sulfur--see OGJ Online, Dec 3, 2012), and the upcoming Jazan refinery, which has received Board approval for financing, and the project’s contracts are expected to be awarded in the coming weeks---please see Saudi Aramco website/Latest news, Dhahran, Oct 16, 2012 Update 2: Saudi Aramco has let a contract to Houston-based KBR for front-end engineering and design of an integrated gasification combined-cycle power plant in conjunction with a 400,000 bpd refinery under development at Jazan Economic City, Saudi Arabia, according to OGJ Online, Oct. 22, 2012. The IGCC plant, which KBR says will be the world’s largest such facility, will gasify vacuum residue to supply electricity to the refinery and make 2.4 Gw available to Jazan and the surrounding region---please OGJ Online, Nov 13, 2012. Update 3: Production has begun from the first phase of development of Manifa oil field offshore Saudi Arabia and is expected to reach 500,000 bpd by July [2013]. The start-up was 3 months ahead of schedule, according to Saudi Aramco---please see "Manifa oil flow starts offshore Saudi Arabia," OGJ Online, April 15, 2013 -- D.R.)

EPP to Extend Eagle Ford Crude Oil Pipeline

by Christopher E. Smith, OGJ Pipeline Editor, OGJ, May 6, 2011
Enterprise Products Partners LP plans to build an 80-mile extension of its 350,000-b/d Eagle Ford shale crude oil pipeline, allowing it to serve growing production areas in the southwestern portion of the play. The 200,000 b/d Phase II project would originate in Wilson County, Tex., at the terminus of Enterprise's previously announced 140-mile Phase I segment (OGJ Online, Sept. 30, 2010), and extend to a site near Gardendale, Tex., in La Salle County, where a new 500,000 bbl central delivery point is planned.

Phase I is on schedule to begin service by second-quarter 2012, according to EPP, with Phase II set to commence operations in first-quarter 2013. The roughly 220-mile pipeline system will provide Eagle Ford producers with access to the Texas Gulf Coast refining complex through EPP’s Sealy, Tex., delivery point. The Sealy facility interconnects with its Rancho Pipeline and feeds into EPP’s new ECHO crude oil storage terminal being constructed along the Houston Ship Channel in southeast Harris County, Tex. (OGJ Online, Nov. 11, 2010).

The Phase II extension is anchored by a 10-year, 100,000 b/d shipping agreement with Chesapeake Energy Marketing Inc., a subsidiary of Chesapeake Energy Corp. EPP said, including the Chesapeake agreement, it now has producer commitments for 320,000 b/d under 10-year contracts.

About 165 rigs are working in the Eagle Ford shale, having drilled more than 1,200 wells, Enterprise said. Current production from the play is roughly 100,000 b/d [of crude oil and condensate -- D.R.]. With more than 2.5 million acres under lease and potentially 15,000 wells to be drilled over the production life of the Phase II service area (based on EPP’s research and information it obtained from producers), the company expects development activity in this region of the Eagle Ford shale to remain brisk.

Estimates provided by producers also suggest that up to 3 billion bbl of crude oil are recoverable in the southwestern region of the play, EPP said. [Full story]

(Also, Plains All American Pipeline LP/PAA plans to build a 300,000 b/d, 130-mile crude oil and condensate pipeline, a marine terminal facility, and 1.5 million bbl of storage to serve growing Eagle Ford production in South Texas. A long-term throughput agreement with Chesapeake Energy Marketing Inc., a subsidiary of Chesapeake Energy Corp., underpins the construction plans. PAA expects the pipeline to enter service in fourth-quarter 2012 at a cost of about $330 million---please see OGJ, May 18, 2011. Separately, please see my post "BENTEK: Eagle Ford Crude Oil Production Expected to Grow Fivefold in Five Years," here. For maps of the Eagle Ford shale, please see here. For the map of North American shale plays from the U.S. Energy Information Administration/EIA, including the United States, Canada and Mexico, as of May 9, 2011, please see here. -- D.R.)

BENTEK: Eagle Ford Crude Oil Production Expected to Grow Fivefold in Five Years [...]

Business Wire, Apr 18, 2011
Oil, gas and NGL production from the liquids-rich Eagle Ford Shale in South Texas set to boom, due to a highly attractive oil/condensate play, a solid base of midstream infrastructure, extensive planned infrastructure expansions and proximity to some of the largest energy markets in North America. [...]

“Horizontal drilling for oil has been highly successful in the northern part of the play, with production expected to increase [more than] fivefold from current levels of 71,000 barrels of oil per day (B/pd) to an average of 421,000 B/pd by 2015, [almost as much as Australia],” said BENTEK Managing Director E. Russell (Rusty) Braziel. “We are projecting that dry natural gas production, mostly located in the southern portion of the Eagle Ford, will increase [...] [Read more]

(For the current Eagle Ford production of crude oil and condensate, please also see, inter alia, here. Update: for the 2012 figures of crude oil -- here. The increase in U.S. crude oil production in 2010 was led by escalating horizontal drilling programs in U.S. shale plays---please see my post "United States: Oil Production From Shale Formations, 2005-2010 -- EIA," here. For the map of the Eagle Ford shale from the U.S. Energy Information Administration/EIA - map date Oct 6, 2010, please see here. For EIA's map of North American shale plays, including the United States, Canada and Mexico, as of May 9, 2011, please see here. Mexico has begun drilling its northern regions for shale gas which it regards as an extension of the US' frenzied Eagle Ford Shale in South Texas, a bonanza which contains both oil and gas---please see my post, here. Mexico's state-owned oil company Petróleos Mexicanos/Pemex, said in March it had produced its first shale gas from an exploratory well at the Eagle Ford Shale formation in the northeastern state of Coahuila in February. -- D.R.)

OTC: Alaska Would Restore Oil Pipeline Volumes

by OGJ editors, OGJ, Houston, May 4, 2011
The state of Alaska is putting final touches on a plan to attract investment in order to restore trans-Alaska oil pipeline throughput to 1 million b/d within 10 years.

Alaska’s North Slope is still considered sparsely explored, said Daniel S. Sullivan, commissioner of the state Department of Natural Resources. The trans-Alaska oil pipeline has shipped more than 16 billion bbl since 1977, but the ANS and adjacent offshore areas are still lightly drilled.

For example, about 500 exploratory wells have been drilled in an ANS area the size of the state of Wyoming [sic], where more than 19,000 wells have been drilled, Sullivan said May 4 in Houston during the Offshore Technology Conference. Alaska’s other main producing basin, Cook Inlet, is also considered to be underexplored, he said.

The pipeline has a capacity of slightly more than 2 million b/d, which was reached in 1988. But with declines at giant Prudhoe Bay field [please see remarks below -- D.R.], Alaskan oil production had fallen to 628,000 b/d last month (OGJ, May 2, 2011, p. 133).

The state’s five-part plan starts with ensuring that Alaska has a globally competitive investment climate, Sullivan said. The state plans to streamline permitting by enacting statutory and regulatory reforms. Specifics haven’t been released.

The state will enact incentives to facilitate the next phase of ANS development, Sullivan said. That work will involve offshore and onshore heavy and viscous oil development, shale oil, and smaller pools of conventional oil and gas.

Alaska is one of a group of coastal states that seeks to improve liaison with federal agencies, Congress, and the president to promote constructive investment (OGJ Online, May 4, 2011).

Sullivan, who was Alaska’s attorney general until December 2010, noted that Alaska’s constitution provides for the maximization of the state’s natural resources. [Full story]

(Prudhoe Bay field, discovered in 1968, came on stream in 1977, rapidly increasing output until the field's maximum rate was reached in 1979 at 1.5 million barrels a day. This rate was maintained until early 1989. Field's production declined to 1.1 million barrels a day in December 1993 and further to 1 million barrels a day at the beginning of 1995. Prudhoe Bay produced an average of 855,000 barrels a day during the 1996. Production totaled approximately 475,000 barrels a day on January 1, 2004, and continued its decline. Nevertheless, the North Slope’s Prudhoe Bay field today is still the largest oil field in United States, producing nearly 300,000 barrels a day in 2010---please see my post, including remarks and map of Alaska/TAPS, here. Alaska is the second-ranked oil-producing State after Texas, when output from the Federal Outer Continental Shelf/OCS is excluded from the State totals. Alaska produced 599,000 barrels of crude oil per day in 2010, with 97% of this coming from the Alaska's North Slope/ANS. U.S. crude oil production totaled 5.51 million barrels per day in 2010. Thus, Alaska accounted for about 11% of U.S. crude oil production in 2010---please see EIA figures, here. In 1988 it was c. 25% of total U.S. crude oil production. For the latest trends in U.S. oil production, please see my post "Domestic Oil Production Reversed Decades-Long Decline in 2009 and 2010," here. -- D.R.)

Marathon, Nexen to Jointly Explore Shale in Poland

by OGJ editors, OGJ, Houston, Apr 27, 2011
[Calgary-based] Nexen Inc. agreed to acquire a 40% working interest in 10 [please see map below -- D.R.] of [Houston-based] Marathon Oil Corp.’s 11 concessions in Poland's Paleozoic shale gas play.

Marathon will remain operator of its concessions, which cover 2.3 million total acres. Poland has issued drilling licenses for 70 concessions to various oil companies.

During this year’s first half, Marathon plans to shoot 2D seismic surveys. The company tentatively plans to drill one or two wells in the fourth quarter and seven or eight wells during 2012.

Nexen and Marathon are targeting Lower Paleozoic shale at 8,000-13,000 ft. Currently, Nexen is developing shale gas in the Horn River region of British Columbia.

Annell R. Bay, Marathon's senior vice-president, worldwide exploration, said the partnership provides financial risk mitigation and combines the two firm’s extensive unconventional drilling and completion experience. [Full story]
                                      [Click on map to enlarge]

                                                                 Source: Mitsui & Co., Ltd. here

(Marathon is the fourth largest U.S.-based integrated oil company behind ExxonMobil, Chevron Corp., and ConocoPhillips, in the PIW's ranking---please see my post here. Also, it is the fifth largest refiner in the United States---please see my post here. On Jan 13, 2011, Marathon's Board of Directors announced that it approved moving forward with plans to spin off Marathon's downstream business, creating two independent, highly focused energy companies. Marathon Petroleum Corporation, to be headquartered in Findlay, Ohio, is expected to be the fifth largest U.S. refiner with a top-tier downstream portfolio of strategically aligned assets concentrated mainly in the Midwest, Gulf Coast and Southeast regions of the United States. Marathon Oil Corporation, which will remain based in Houston, will be a global exploration and production company with a strong portfolio of assets delivering defined growth leveraged to crude oil production with exploration upside---please see Marathon website. Marathon has operations in the United States, Angola, Canada, Equatorial Guinea, Indonesia, Iraqi Kurdistan Region/IKR, Libya, Norway, Poland and the United Kingdom. It is an integrated international energy company engaged in exploration and production; oil sands mining; integrated gas; and refining, marketing and transportation operations. Nexen Inc. is Canada's sixth largest independent oil and gas producer. Poland's technically recoverable resources of shale gas are estimated to be 187 trillion cubic feet/tcf or c. 5.3 trillion cubic meters/tcm, the highest in Europe---please see my post/table "Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries -- EIA," here. Also, please see my post "World Shale Gas Resources Outside US Assessed," here. UPDATE: For Mitsui's possible participation in Polish shale gas, the first Japanese participation in European shale gas projects!, please see Mitsui's website. -- D.R.)

Continental: Bakken's Giant Scope Underappreciated

by OGJ editors, OGJ, Feb 16, 2011
The Bakken play [please see map below -- D.R.] in the Williston basin could become the world’s largest discovery in the last 30-40 years, a senior manager at Continental Resources Inc. said Feb. 16.

Ultimate recovery from the overall play is now estimated at 24 billion bbl of oil, compared with US reserves of nearly 20 billion bbl, he told the NAPE Expo in Houston.

The 24 billion bbl figure is five times the US Geological Survey’s 2008 estimate and compares with the 151 million bbl the survey put forth as recently as the mid-1990s, said Jack Stark, Continental senior vice-president, exploration (OGJ, Apr. 21, 2008, p. 37).

Close to 2 billion bbl of the 24 billion will come from the underlying Three Forks [region], which Continental helped prove to be a separate reservoir, Stark noted (OGJ Online, July 10, 2008).

The increases resulted as technology evolved over a 20-year span from marginal or uneconomic vertical wells to open hole stimulations in single, dual, and trilaterals to liners with staged fracs that are resulting in 50% rates of return today, Stark said. Industry also began drilling into the Middle Bakken dolomite, which is more porous and permeable than the upper and lower Bakken shale source rocks.

Production exceeds 400,000 b/d including Montana and North Dakota, Stark estimated, and smaller volumes are being produced in Canada. So recovery of that volume of oil will take years.

Industry has completed 2,750 horizontal wells since 2000. It is running 165 rigs that likely will drill 1,800 more wells in 2011, and production could reach as much as 1 million b/d within a few years, Stark said. The Bakken is continuous under nearly 15,000 sq miles.

The play’s numerous operators are drilling 18,000-21,000-ft wellbores that include 9,500-ft laterals and applying 18-30 frac stages/well, said Stark.

In general, higher initial potential producing rates indicate higher estimated ultimate recoveries, but the correlation isn’t 1:1 “due to overriding geological factors,” he said. Operators seem to reach a point of diminishing returns between 18 and 24 frac stages and are still seeking the ideal number of stages, he said. [Full story]

(The Bakken formation was discovered in 1953 and as early as 1974, it was postulated that vast amounts of petroleum were contained in the formation itself but it was not economically viable as the oil was trapped in shale, i.e., fine sedimentary rocks. With the development of new drilling techniques, it became possible to horizontally drill right into the flat shaped deposits and collapse the oil rich rocks by fracking---i.e., pumping sand/proppant and liquids at high pressure into the well bore---in order to allow the oil to flow back up. Applying new drilling techniques alongside higher oil prices made it economically viable to exploit the oil trapped in the Bakken shale as well as other formations such as the Cardium in Alberta and the Viking in Saskatchewan. Armed with the same proven technology, the industry has now set its eyes on the Southern Alberta Basin. With its similarities to the Williston Basin, the companies are excited about the potential of this new emerging light oil play dubbed: The Alberta Bakken, stretching from Southern Alberta into Montana---please see BeatingTheIndex.com blog here. Wood Mackenzie's Upstream M&A Service report "2010 in Review and the Outlook for 2011" shows that US shale gas in particular had an exceptional year in 2010 - continuing a steady increase in deal activity over the last five years - with acquisition spend amounting to US$39 billion, equivalent to 21% of all global merger and acquisition---M&A---activity. Also, "2010 ended with a flurry of shale oil transactions, centered on the Bakken play where we anticipate further activity in the coming year. In the last two months of 2010, there were four US$1 billion plus Bakken deals announced, pushing cumulative M&A spend in North American tight oil beyond US$15 billion," said Luke Parker, manager of WoodMac's M&A research---please see my post here. -- D.R.)

             Map of the Bakken Formation Oil and Gas Play

Source: Geology.com here. Description: The Bakken is below parts of northwestern North Dakota, northeastern Montana, southern Saskatchewan and southwestern Manitoba.

Saudi Arabia Pledges To Fill Oil Supply Gap amid Libyan Unrest

By Takeo Kumagai, Platts blog - The Barrel, Feb 24, 2011
Seeing is believing. That was the first that thought came to my mind when I visited the onshore Khurais oil field in Saudi Arabia's vast desert this week [please see map of oil and gas fields in Saudi Arabia, below -- D.R.].

Located some 150 km (100 miles) [sic] southeast of the capital Riyadh, the Khurais oil field began pumping 1.2 million b/d in 2009 [sic; Khurais reached its maximum sustainable capacity in 2010 -- D.R.], the largest single increment from any single oilfield in the kingdom's history.

As an energy correspondent visiting from Japan, which imports 1.1 million b/d of crude from Saudi Arabia, seeing a production facility that can alone meet 30% of my country's total imports is mind boggling. The Khurais field's production capacity alone is higher than the output capacities of several oil producing countries in Asia and elsewhere.

Saudi Aramco achieved production of 1.2 million b/d at Khurais a month after it was commissioned in May 2009 [sic] and was one of several mega projects designed to take the company's total production capacity to its current 12 million b/d.

The Khurais oil field currently produces around 1 million b/d of Arabian Light crude oil with a gravity of around 32 API, reflecting current demand patterns for lighter grades, Saudi Aramco officials said.

The Khurais field can sustain production at current levels for 30 years, they added.

Output capacity from Khurais could be taken up to between 1.4 million to 1.5 million b/d, should the need arise, by adding another production line to its existing 14 lines, they said, adding that water processing units and other infrastructure can accommodate this increase.

Saudi Arabia, which has total production capacity of 12.5 million b/d if output from the partitioned neutral zone with Kuwait is included, has some 4 million b/d of spare production capacity. Currently [i.e., Jan 2011 data -- please see my post here -- D.R.], Saudi Arabia's crude oil output is 8.4 million b/d. [Also, please see here -- D.R.]

The volume of spare capacity held by Saudi Arabia and a few other members of OPEC was the focus of discussions at an extraordinary meeting of the International Energy Forum held in Riyadh on February 22 amid fears that unrest in Libya might disrupt supply.

Saudi Arabian Oil Minister Ali Naimi told reporters after the oil producers and consumers forum ended that he did not expect the price spike of 2008 to be repeated and that recent market volatility was unlikely to last because current oil markets were well supplied, spare capacity was plentiful and there was no shortage of supply.

Naimi said that, in the event of a supply disruption, Saudi Arabia and OPEC would be ready to step in and use their spare capacity to balance markets. He put global spare capacity at 5 million to 6 million b/d.

"Let me emphasize that this is not 2008...it is an extremely different situation from 2008," Naimi said of the year that saw oil prices soar to a record above $147/barrel, some $38/barrel shy of the current value of Brent crude oil futures.

OPEC insisted at the time that there was no shortage of oil and that the rocketing prices were due less to high demand than to excessive speculative activity.

But it is Saudi Arabia's ability to ramp up production quickly to meet any supply disruption that holds the key to oil market stability [i.e., Saudi Arabia's role as world's unofficial swing producer -- D.R.] and this was reflected in remarks by several officials representing the interests of the world's major oil consuming nations.

The Executive Director of the consumer watchdog the International Energy Agency, Nobuo Tanaka, told Platts in an interview in Riyadh that he had been assured by both the OPEC secretary general and Naimi that any supply gap would be filled.

"There is ample spare capacity. We should not panic," Tanaka said, adding that OPEC members, particularly kingpin Saudi Arabia, were producing "more than they say."

With 260 billion barrels of crude oil reserves lying beneath the sands of this desert kingdom [please see figures here -- D.R.], Khurais is a vital component of the global oil supply chain. [Full story]
                [Click on map to enlarge]

                                                    Source: Saudi Aramco via EIA, here.

Gazprom Ups Italian Gas Supplies 30% Due to Libya Unrest: Source

Platts, Moscow, Feb 28, 2011
Gazprom has increased its daily Russian gas deliveries to Italy by around 30% after unrest in Libya led to the shutdown of the 11 billion cubic meter/year Greenstream pipeline [please see map below -- D.R.] last week, a source close to Gazprom said Monday.

The source told Platts it was unclear how long the gas supplies would remain at an elevated level.

Gazprom's deliveries reached 81.1 million cu m/day on Thursday, up from a daily average of 63 million-65 million cu m on weekdays and 54 million-55 million cu m at weekends, Russian news agency Interfax reported Friday, citing Italy's gas grid operator Snam Rete Gas.

Snam Rete Gas was not available for comment.

Last Tuesday Eni, Italy's main gas supplier and the parent of Snam Rete Gas, announced it had shut down Greenstream.

Greenstream, which is a joint venture between Eni and the National Oil Corporation of Libya, exported around 9.4 billion cu m of gas to Italy in 2010.

It runs from Mellitah in Libya to Gela in Sicily, Italy.

According to the European Commission, 30% of Italy's gas supplies come from Russia, with Libya typically supplying around 11%. Thirty-three percent of the country's gas imports come from Algeria and 9% from Norway.

The increase in Russian supplies to Italy is likely to be temporary, according to a research note by investment company Alfa Bank.

"There could be other positive implications for Russia, as the incident is likely to underscore the country's reputation as a reliable gas supplier and could ease concern over Russia's large share of European gas markets," the note said.

Within Europe, Libya only delivers gas to Italy and Spain [to Spain in the form of LNG -- D.R.]. Libyan gas represents 1.5% of Spanish [gas] imports. [Full story]

(The c. 520-kilometer---323-mile---Greenstream submarine pipeline came online in 2004. For information on Libya's oil and gas profile, please see my post here.)

                                                                       Source: ENI, here

BP and Reliance Industries Announce Transformational Partnership in India

BP website, Feb 21, 2011
BP to take a 30 per cent stake in 23 oil and gas blocks.

Reliance Industries Limited and BP today announced a historic partnership between the two companies. Mr. Mukesh Ambani, Chairman and Managing Director of Reliance Industries Limited, and Mr. Robert Dudley, BP Group Chief Executive, signed the relationship framework and transactional agreements in London.

The partnership across the full value chain comprises BP taking a 30 per cent stake in 23 oil and gas production sharing contracts that Reliance operates in India, including the producing KG D6 block [see map below -- D.R.], and the formation of a 50:50 joint venture between the two companies for the sourcing and marketing of gas in India. The joint venture will also endeavor to accelerate the creation of infrastructure for receiving, transporting and marketing of natural gas in India.


            Map of BP and Reliance Industries Deal Interests

                                                        Source: BP

The partnership will combine BP’s world-class deepwater exploration and development capabilities with Reliance’s project management and operations expertise.

Mukesh Ambani said: “We are delighted to partner with BP, one of the largest energy majors and one of the finest deep water exploration companies in the world. This partnership combines the skills of both companies and will be focused on finding more hydrocarbons in the deep water blocks of India and significantly contribute to India’s energy security.”

For BP, Reliance is a natural partner in India, given its strong position in the Indian market.

“This partnership meets BP’s strategy of forming alliances with strong national partners, taking material positions in significant hydrocarbon basins and increasing our exposure to growing energy markets,” said Mr. Carl-Henric Svanberg, Chairman of BP.

BP will pay Reliance Industries Limited an aggregate consideration of US$7.2 billion, and completion adjustments, for the interests to be acquired in the 23 production sharing contracts. Future performance payments of up to US$1.8 billion could be paid based on exploration success that results in development of commercial discoveries. These payments and combined investment could amount to US$20 billion.

BP’s confidence in India is evident from the fact that the transaction constitutes one of the largest foreign direct investments into India.

The 23 oil and gas blocks together cover approximately 270,000 square kilometers. This will make the partnership India’s largest private sector holder of exploration acreage.

So that the joint venture can capitalize on Reliance’s outstanding project management track record and operations expertise, Reliance will continue to be the operator under the production sharing contracts, whose blocks lie in water depths ranging from 400 to over 3,000 meters. These currently produce about 1.8 billion cubic feet of gas per day (bcf/d), over 30 per cent of India’s total consumption, and over 40 per cent of India’s total production.

“India is one of the fastest growing economies in the world. By allying ourselves with Reliance, we will access the most prolific gas basin in India and secure a place in the fast growing Indian gas markets, creating a genuinely distinctive BP position,” said Bob Dudley. “BP looks forward to a long and successful working partnership with Reliance.”

Completion of the transactions is subject to Indian regulatory approvals and other customary conditions. [Full story]

(BP has been working with Reliance since December 2008 on the D-17 deepwater block in the Krishna Godavari (KG) basin on the east coast of India---see map above. BP, with a 50 per cent interest, operates the block and Reliance holds the remaining interest. BP has a strong presence in India in addition to its interest in block D-17. Castrol India Limited is a market leader in the retail automotive lubricant business, including car engine oils, premium 4-stroke motorcycle oils and multi-grade diesel engine oils. Castrol India also operates in the industrial and marine lubricants markets. Tata BP Solar, a joint venture between BP Solar and the Tata Group, has been operating in India since 1989. It is a leader in the Indian solar energy market, manufacturing solar cells, solar PV modules and systems. Reliance Industries Limited (RIL) is India’s largest private sector company on all major financial parameters. RIL runs the world's largest refining complex at Jamnagar with two plants of combined capacity of 1.24 million barrels per day---please see my post "World's Largest Refineries," including notes, here. It has also been buying up shale gas assets in the United States and has interests in petrochemicals and retail, and is now looking at diversifying. According to BP’s Energy Outlook 2030, energy consumption in India has grown by 190% over the past 20 years and is likely to grow by 115% over the next 20 years, a rate of over 4% per annum. Gas is expected to be the fastest growing fossil fuel, with demand growing at a rate of nearly 5% a year between 2010 and 2030. India’s gas consumption was 5.0 bcf/d in 2009 and is estimated to have been 6.1 bcf/d in 2010 (comprising 4.9 bcf/d production plus 1.2 bcf/d LNG imports). Total Indian gas consumption is projected to grow to 12.5 bcf/d in 2025, and exceed 15 bcf/d in 2030. The Indian deal marks the second major deal under BP's new chief executive Bob Dudley. Last month, on January 14, BP and Rosneft announced a major strategic partnership that would include a share swap and the joint exploration of three blocks in the Russian Arctic---please see my post here. -- D.R.)

Sakhalin-1 Project Drills World's Longest Extended-Reach Well

Scandinavian Oil-Gas Magazine, Jan 31, 2011
Exxon Mobil Corporation says that its subsidiary, Exxon Neftegas Limited, has successfully drilled the world's longest extended-reach well at the Odoptu field, offshore far east Russia. Exxon Neftegas is the operator of the Sakhalin-1 Project on behalf of an international consortium that includes affiliates of the Russian state company Rosneft RN-Astra and Sakhalinmorneftegas-Shelf; the Japanese corporation SODECO; and the Indian state oil company ONGC Videsh Ltd.

The Odoptu OP-11 well reached a total measured depth of 40,502 feet (12,345 meters or 7.67 miles) to set a world record for extended-reach drilling (ERD). The Odoptu OP-11 also set a world record with a horizontal reach of 37,648 feet (11,475 meters or 7.13 miles). Exxon Neftegas completed the record-setting well in only 60 days using ExxonMobil's Fast Drill Process and Integrated Hole Quality technology to maximize performance in every foot of hole drilled at OP-11.

Odoptu, one of three Sakhalin-1 Project fields, is situated 5 to 7 miles (8 to 11 kilometers) offshore northeast Sakhalin Island. [See map below -- D.R.]. The ERD process enables onshore drilling beneath the seafloor to the offshore oil and gas reservoirs to successfully operate in a safe and environmentally responsible manner in one of the most challenging sub-arctic environments in the world. [...]

Since the first Sakhalin-1 well was drilled in 2003, six of the world's 10 record-setting ERD wells have been drilled at the project. The specially designed Yastreb rig [see photo 1 below] has been used throughout, setting multiple industry records for measured depth, rate of penetration and directional drilling.

Since startup, the Sakhalin-1 project has produced approximately 300 million barrels (39 million tons) of oil for export to world markets. It also has been a key supplier of approximately 235 billion cubic feet (6.8 billion cubic meters) of associated natural gas to customers in Khabarovsk Krai, in far eastern Russia, to heat homes and meet growing energy needs. The project will continue to help meet future natural gas demand in this region.

Sakhalin-1 includes the Chayvo, Odoptu, and Arkutun Dagi oil and gas fields located off the northeast coast of Sakhalin Island in the Russian Far East. [See map and photo 2 below -- D.R.]. Potential recoverable resources are 2.3 billion barrels (307 million tons) of oil and 17.1 trillion cubic feet (485 billion cubic meters) of natural gas. Read more
                                      Map: Sakhalin-1

Source: Rigzone Description: Oil from the Chayvo deposit started to run through a pipeline to the De-Kastri terminal in Russia's Khabarovsk Krai in September 2006. An export terminal at De-Kastri began shipments to Japan and South Korea in October 2006. The Sakhalin-1 gas is supplied to local consumers via a pipeline owned by Daltransgaz. Drilling at the Odoptu oil and gas field began in May 2009, and commercial production began in September 2010. The product goes to the Chayvo processing facility and then to the De-Kastri for export. The Arkutun-Dagi field is yet to be developed, but first oil is expected in 2014; it will also go to De-Kastri via Chayvo. -- D.R.

                             Photo 1: Yastreb Land Rig
                                             

Source: offshore-technology.com Description: The Chayvo Yastreb land rig, above, launched in June 2002, was engineered and constructed especially for Sakhalin-1 (Houston-based Parking Drilling Co designed and constructed the "Yastreb"). It is designed to drill extended reach wells to offshore targets from land-based locations. State-of-the-art extended reach drilling (ERD) technology reduced the high capital and operating costs of large offshore structures and at the same time minimized the environmental impact in this sensitive near-shore area. Drilling at Chayvo was completed with a total of 20 ERD wells drilled, setting records in depth, horizontal reach and drilling speed. The Yastreb rig was dismantled, modified and transported to Odoptu field where it has been in operation since the startup of drilling in May 2009. -- D.R.

             Photo 2: Sakhalin-1 - Orlan Offshore Rig (Chayvo)

                                                 Source: Rosneft website

(Sakhalin-1 is the first large-scale shelf development project in Russia being implemented under a production sharing agreement---concluded in 1996. Project participation: Exxon holds an operating 30% stake in the project, Japan's Sodeco holds 30%, with Rosneft---via its affiliates RN-Astra, 8.5%, and Sakhalinmorneftegas-Shelf, 11.5%---and India's ONGC holding 20% each. For cooperation between Rosneft and ExxonMobil, see also my post here. For the longest extended-reach well, i.e. ERD, in Saudi Arabia -- Manifa field, please see my posts here and here. -- D.R.)

World Watch: [Oil/Gas Markets and Egypt]

by Jim Washer, EI
Geopolitics is making a comeback in oil markets. WikiLeaks revelations in December about Arab support for a US nuclear strike against Iran gave a modest boost to crude oil futures, and now civil unrest in Egypt has provided the impetus to push prices above $100/bbl for the first time since September 2008. Egypt is a significant oil and gas producer, but is more important as an energy transit point -- together, the Suez Canal and the Sumed [Suez-Mediterranean] pipeline handle around 2.8 million b/d of crude and products as well as 7% of the world’s LNG trade. [See remarks below -- D.R.]. While Egypt is therefore an important chokepoint, energy markets are in unusually good shape to cope with any disruption. Oil prices may have revisited $100/bbl, but there is plenty of slack in global energy infrastructure -- Opec is sitting on some 6 million b/d of spare upstream capacity, and commercial and strategic inventories remain ample. [Full story]

(Closure of the Suez Canal and the Sumed Pipeline---see map, sorry for the blurriness and the proportion, and photo below---would divert tankers around the southern tip of Africa, the Cape of Good Hope, adding 6,000 miles---or 9,656 kilometers---to transit, according to the Energy Information Administration--EIA, increasing both costs and shipping time. According to a report released by the International Energy Agency (IEA), shipping around Africa would add 15 days of transit to Europe and 8-10 days to the United States. On the other hand, energy analysts believe the real risk is not a closure of the desert conduits---the Suez Canal and the Sumed Pipeline---but that the unrest gripping Cairo will spread to neighboring nations or other Arab countries. Barclays Capital Research report---accessed via Platts, here---noted that around 14% of the world's LNG trade transits the Suez Canal each day with the vast majority of cargoes originating in the Middle East and heading towards Atlantic Basin markets. Also, Egypt exported around 2 Bcf/d of gas in 2009, the majority [some 70%] in LNG form, accounting for around 3.2% of global LNG supply. "In the event of a disruption of LNG exports from Egypt, the greatest implications for gas markets would be for Spain," Barclays Capital said, adding that global LNG markets were well supplied with "ample" production capacity available to meet any potential Egyptian shortfall. The report also noted that Egypt exports gas via the Arab Gas Pipeline, or AGP, and its El Arish-Ashkelon branch, which has the capacity to carry about 1 Bcf/d to Israel, Lebanon, Jordan and Syria. "Most Egyptian [oil] drilling activity has been halted as a result of the political instability, as several international E&P companies have announced staff evacuations," Barclays said. "Gas production, however, has not been affected so far, and there have been no reports of force majeure on LNG deliveries. Egypt's sea ports are officially open, although staff shortages and an absence of customs officials at the Alexandria and Damietta ports are reported to cause traffic disruptions." Egypt has two LNG plants at Idku and Damietta and operations have so far not been affected despite the evacuation of foreign staff. Gas flow to Israel has also not been interrupted. Israel received an estimated 2.1 billion cubic meters, i.e. bcm, in pipeline gas from Egypt in 2010, up from 1.7 bcm a year earlier. -- D.R.)

                                             Source: Oil Capital Ltd. via EIA

                                    Photo: Suez Canal

Source: National Geographic. Description: A tanker carrying liquefied natural gas (LNG) passes through Egypt's Suez Canal in 2007.

Rosneft and BP Form Global and Arctic Strategic Alliance

BP website, Jan 14, 2011
BP and Rosneft announced today [Jan 14] that they have agreed a groundbreaking strategic global alliance.

Rosneft and BP have agreed to explore and develop three license blocks - EPNZ 1,2,3 – on the Russian Arctic continental shelf. [See map below -- D.R.] These licences were awarded to Rosneft in 2010 and cover approximately 125,000 square kilometres in a highly prospective area of the South Kara Sea. This is an area roughly equivalent in size and prospectivity to the UK North Sea.

                  Map: Location and Scale of South Kara Sea Licences

                                                                          Source: BP

This historic agreement creates the first major equity-linked partnership between a national and international oil company. Following completion of this agreement, Rosneft will hold 5 per cent of BP’s ordinary voting shares in exchange for approximately 9.5 per cent of Rosneft’s shares. The share swap component of the alliance creates strategic alignment to pursue joint [oil and gas] projects and demonstrates mutual confidence in the growth potential of both companies.

BP and Rosneft have also agreed to establish an Arctic technology centre in Russia which will work with leading Russian and international research institutes, design bureaus and universities to develop technologies and engineering practices for the safe extraction of hydrocarbon resources from the Arctic shelf. The technology centre will build on BP’s deep offshore experience and learnings with full emphasis on safety, environmental integrity and emergency spill response capability.

Rosneft and BP have agreed to continue their joint technical studies in the Russian Arctic to assess hydrocarbon prospectivity in areas beyond the Kara Sea. The parties will also seek additional opportunities for international collaboration beyond their 50/50 joint venture partnership in Ruhr Oel GmbH, a refining joint venture in Germany (subject to completion of Rosneft’s recent purchase of 50 per cent of Ruhr Oel from PDVSA).

Igor Sechin, Deputy Prime Minister of the Russian Federation, who participated in the signing ceremony, said: “Global capital and Russian companies are clearly ready to invest in world class projects in Russia; and Russian companies are quickly emerging at the forefront of the global energy industry.”

BP’s chief executive, Bob Dudley, said: “This unique agreement underlines our long-term, strategic and deepening links with the world’s largest hydrocarbon-producing nation. We are very pleased to be joining Russia’s leading oil company to jointly explore some of the most promising parts of the Russian Arctic, one of the world’s last remaining unexplored basins. Underpinning this alliance is a new type of relationship based on a significant cross-shareholding, and bringing together technology, exploration and safe and responsible field development skills. We are very pleased to welcome Rosneft as a strategic partner and major shareholder in the BP Group.”

Rosneft’s President, Eduard Khudainatov, said: “I am pleased that in just a few months we’ve significantly moved forward in implementing Russia’s offshore strategy. In its operations, our future joint venture will utilize the experience and expertise of BP, one of the leaders in the global oil and gas industry. This project is unique in its complexity and scale both for Russia and the global oil and gas industry. We see it as the next step in developing our relations with BP.”

BP Chairman, Carl-Henric Svanberg, said: “The world’s need for energy continues to increase. BP is working with national oil companies using its leading exploration skills and expertise to meet this demand. This is a trend which will increase as access to resource becomes scarcer.

This landmark deal creates a deep partnership which represents a new stage in these relationships. The exchange of shares demonstrates our mutual commitment. The BP board believes that the combination of assets and skills will unlock significant value and thus the issue of shares to Rosneft is in the interests of all shareholders.”

The aggregate value of the shares in BP to be issued to Rosneft is approximately $7.8bn (as at close of trading in London on 14 January 2011). The transaction is subject to certain listing approvals and the completion of certain administrative requirements and is expected to complete within a few weeks. BP and Rosneft view their cross-shareholdings as long term and strategic.

Rosneft is Russia’s leading oil producing company. Read More

(BP already has a 1.3% stake in Rosneft and as a result of the announced transaction, BP's stake in Rosneft will increase to 10.8% -- i.e. 9.5% + 1.3%. Also, Russia accounts for around one quarter of the British energy giant's total production -- before the U.S. oil spill. In 1998, BP and Rosneft started an alliance that eventually led to the formation of three joint ventures to conduct exploration on the Russian continental shelf, offshore Sakhalin. BP also owns 50% of Russia's third biggest oil producer, TNK-BP -- see my blog post here. Rosneft's major shareholder (75.16% of shares) is the company Rosneftegaz, 100% state-owned. For the Rosneft's profile, see Platts Top 250 Global Energy Company Rankings -- No. 14, in my blog here. Rosneft has proved reserves of approximately 18.1 billion barrels of oil and 816 billion cubic meters of gas. As of year-end 2009, Rosneft’s total proved oil and gas reserves under PRMS classification were 22.9 billion barrels of oil equivalent, among the highest for a publicly traded petroleum company worldwide, according to Rosneft's website. Also -- according to Platts data, the company operates 1,690 filling stations in 39 regions of the Russia Federation and 7 refineries. It has operations primarily in Western Siberia, Southern and Central Russia, Timan-Pechora, Eastern Siberia, and the Far East, as well as in Kazakhstan and Algeria. -- D.R.)