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5 NEWSLETTER 31 STATISTICS
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www.ogj.com
Mar. 14, 2011
12 LETTERS / CALENDAR
14 JOURNALLY SPEAKING
16 EDITORIAL
34 MARKETPLACE
35 EDITOR’S PERSPECTIVE / MARKET JOURNAL
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Volume 109.11
30 EQUIPMENT 30 ADVERTISERS’ INDEX
GENERAL INTEREST 18 COMMENT— Consultant: US LNG exports likely in near term We are on the brink of a new opening of LNG exports from an unexpected source, according to Fereidun Fesharaki, chairman of FACTS Global Energy, in a recent analysis.
21 CERAWeek topics span deepwater drilling, the economy, oil prices More investments are necessary if oil production is to keep up with spiraling demand worldwide, and industry is increasingly relying on partnerships to spread financial risk and share expertise, oil company executives told the IHS-CERA energy conference last week in Houston.
23 Libya’s oil facilities bombed as sanctions start to bite regime Eric Watkins
24 WATCHING THE WORLD Huhne’s energy plan
25 Release of crude from SPR is an option, White House says Nick Snow
26 WATCHING GOVERNMENT Paying for hazardous duty
26 Bills aim to halt EPA GHG regulation under CAA Nick Snow
27 GAO places high-risk label on DOI’s oil, gas programs Nick Snow
28 Elevated investment might halve UKCS output decline 28 EIA: Finding, lifting costs worldwide declined in 2009 29 EXPLORATION/DEVELOPMENT BRIEFS
The world’s first commercial thermal enhanced oil recovery project that uses solar steam generators went on line Feb. 24 at Berry Petroleum Co.’s heavy oil 21Z lease in McKittrick, Calif. The project incorporates GlassPoint Solar’s single transit trough technology, specifically designed for rugged oil field environments. Photo from GlassPoint Solar.
Innovation Flows From Our Labs To Your Fields, And Now To Your Refineries Chemtech has joined the Champion Technologies portfolio to further optimize our chemicals, engineered programs and downstream capabilities that meet your refinery challenges. Our new, integrated offering delivers cost-effective performance, more reliability and improved throughput with an emphasis on safety. Now offering complete upstream, midstream and downstream solutions.
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LABOR ANALYTICS
OGJ Newsletter
Mar. 14, 2011
®
International News for oil and gas professionals
GENERAL INTEREST Q U IC K TA K E S Talisman, Sasol deepen Montney partnership Talisman Energy Inc. and Sasol Ltd. of South Africa have expanded their strategic relationship in the Montney shale gas play of Northeast British Columbia. Sasol has purchased a 50% net working interest in Talisman’s Cypress A assets northwest of Fort St. John, BC, for $1.05 billion (Can.). Talisman will operate and manage the Cypress A and Farrell Creek areas as an integrated development project. Sasol purchased a 50% net interest in Talisman’s Farrell Creek Montney properties west of Fort St. John in December 2010. That deal, in which Sasol acquired an estimated 4.8 tcf equivalent of net contingent resource, closed Mar. 1. Talisman said the Farrell Creek and Cypress A assets are similar. Sasol Chief Executive Pat Davies said, “This additional acquisition of another high-quality natural gas asset will accelerate our upstream growth while also potentially advancing Sasol’s already strong gas-to-liquids value proposition utilizing our proprietary technology.” Talisman said the Cypress A transaction represents the sale of 14% or 5.6 tcfe of its remaining estimated 39 tcfe of net contingent resource in the play and 17% or 28,600 net acres of its net Tier 1 acres of land in the Montney shale. Sasol will pay $260 million (Can.) or 25% of the consideration in cash at closing and will also provide $790 million to fund 75% of Talisman’s future capital commitments in the integrated joint venture development area. The Cypress A transaction is subject to regulatory approvals and is expected to close by the end of this year’s third quarter. Upon closing, Talisman will hold an estimated 34 tcfe of net contingent resource and 139,000 net acres of Tier 1 acreage in the Montney shale play, including Farrell Creek, Greater Cypress, and the Greater Groundbirch area southwest of Fort St. John.
Total to buy stake in Novatek for $4 billion Total SA announced plans to buy a 12% stake in OAO Novatek, Russia’s largest independent gas producer, for $4 billion with plans to boost Total’s stake to 19.4% in 3 years. Total also plans to acquire 20% interest in Novatek’s northwestern Siberian Yamal LNG project.
Oil & Gas Journal
For up-to-the-minute news, visit www.ogjonline.com
The Total-Novatek transaction comes after BP PLC and OAO Rosneft agreed to form a strategic global alliance that includes a stock swap, an Arctic offshore exploration joint venture and research effort, and a refining partnership (OGJ Online, Jan. 17, 2011). Rosneft and BP plan to form a joint operating company in the next 2 years with a 66.67% and 33.33% participation, respectively. Total expects to close on its 12% stake in Novatek by April and then plans to appoint a representative to Novatek’s board. Through this acquisition, Total will gain access to equity production of 120,000 boe/d and to estimated proved and probable reserves of 1 billion boe. Terms call for Total’s overall holdings in Novatek to increase to 15% within 12 months and to 19.4% within 36 months. Novatek’s 2010 production was 750,000 boe/d, including condensates. Total and Novatek already jointly develop Termokarstovoye field through the Terneftegaz joint venture (OGJ Online, June 25, 2009). Closing on the Yamal LNG partnership is expected by July, Total said. The Yamal LNG project envisions production, treatment, transportation, liquefaction, and shipping of natural gas and NGLs from South Tambey field on the Yamal Peninsula (OGJ, May 10, 2010, Newsletter). Total lists South Tambey resources at 44 tcf of gas, allowing production of more than 15 million tonnes/year of LNG. After Total acquires its 20%, Novatek will hold 51% of the Yamal LNG project. Christophe de Margerie, Total chairman and chief executive officer, said, “This agreement adds to the close cooperation built with Gazprom since 2007 on the Shotkman project.” Last year Gazprom announced it expects a 3-year gas production delay to 2016 from Shtokman (OGJ Online, Feb. 8, 2010). De Margerie met with Russia’s President Dmitry Medvedev in Moscow on Mar. 2. They discussed Total’s activities in Russia. De Margerie signed the Total-Novatek agreement later than same day in the presence of Prime Minister Vladimir Putin. Total expects to become the first international investor to participate in the Yamal LNG project. Total has done business since 1989 in Russia where it operates Kharyaga field with a 40% interest.
5
IPE BRENT / NYMEX LIGHT SWEET CRUDE $/bbl 118.00 115.00 112.00 109.00 106.00 103.00 100.00 97.00
US INDUSTRY SCOREBOARD — 3/14 4 wk. average
Latest week 2/25
Mar. 2
Mar. 3
Mar. 4
Mar.7
Motor gasoline Distillate Jet fuel Residual Other products
YTD avg. year ago1
Change, %
8,808 3,744 1,292 678 4,792 19,314
1.0 0.2 8.3 -2.1 1.6 1.4
8,796 3,727 1,398 580 4,788 19,289
8,726 3,724 1,326 569 4,687 19,032
0.8 0.1 5.4 1.9 2.2 1.4
Crude production NGL production2 Crude imports Product imports Other supply2, 3 TOTAL SUPPLY Refining, 1,000 b/d
5,601 2,068 8,323 2,482 2,032 20,506
5,493 1,956 8,803 2,802 1,772 20,826
2.0 5.7 –5.5 –11.4 14.7 –1.5
5,508 2,063 8,694 2,596 2,069 20,930
5,462 2,098 8,617 2,796 1,657 20,630
0.8 –1.7 0.9 –7.2 24.9 1.5
Crude runs to stills Input to crude stills % utilization
13,885 14,349 81.6
13,104 14,257 81.1
6.0 0.6 ––
14,130 14,558 82.7
14,283 14,593 82.6
–1.1 –0.2 ––
Mar. 8
Mar. 2
Mar. 3
Mar. 4
Supply, 1,000 b/d
Mar.7
Mar. 8
NYMEX NATURAL GAS / SPOT GAS - HENRY HUB
Latest week 2/25
Latest week
Previous week1
346,375 234,708 159,186 40,820 37,075
346,739 238,298 159,937 40,475 37,403
24.9 26.4 42.4 20.8
24.7 27.2 42.1 19.9
Stock cover (days)4 Mar. 2
Mar. 3
Mar. 4
Mar.7
Mar. 8
Same week year ago1 Change
Change
Change, %
Stocks, 1,000 bbl Crude oil Motor gasoline Distillate Jet fuel-kerosine Residual
IPE GAS OIL / NYMEX HEATING OIL ¢/gal 312.00 310.00 308.00 306.00 304.00 302.00 300.00 298.00
YTD average1
8,899 3,753 1,399 664 4,870 19,585
TOTAL PRODUCT SUPPLIED
$/MMbtu 4.00 3.95 3.90 3.85 3.80 3.75 3.70 3.65
Change, %
Product supplied, 1,000 b/d
WTI CUSHING / BRENT SPOT $/bbl 119.00 116.00 113.00 110.00 107.00 104.00 101.00 98.00
4 wk. avg. year ago1
–364 –3,590 –751 345 –328
341,571 231,943 151,821 43,279 40,004
4,804 2,765 7,365 –2,459 –2,929
Change, %
Crude Motor gasoline Distillate Propane Futures prices5 3/4
Change, %
0.8 –2.9 0.7 4.5
24.6 26.3 40.6 18.9
1.2 0.4 4.4 10.1
Change
Light sweet crude ($/bbl) Natural gas, $/MMbtu
101.03 3.86
96.71 3.89
1.4 1.2 4.9 –5.7 –7.3
Change
4.32 –0.03
79.37 4.81
%
21.66 –0.95
27.3 –19.8
1
Based on revised figures. 2OGJ estimates. 3Includes other liquids, refinery processing gain, and unaccounted for crude oil. 4Stocks divided by average daily product supplied for the prior 4 weeks. 5Weekly average of daily closing futures prices. Source: Energy Information Administration, Wall Street Journal
Mar. 2
Mar. 3
Mar. 4
Mar.7
Mar. 8
BAKER HUGHES INTERNATIONAL RIG COUNT: TOTAL WORLD / TOTAL ONSHORE / TOTAL OFFSHORE
PROPANE - MT. BELVIEU / BUTANE - MT. BELVIEU ¢/gal 180.00 175.00 170.00 145.00 140.00 135.00 130.00
Mar. 2
Mar. 3
Mar. 4
Mar.7
Mar. 8
NYMEX GASOLINE (RBOB)1 / NY SPOT GASOLINE2 ¢/gal 300.00 295.00 290.00 285.00 280.00 275.00 270.00 265.00
3,900 3,600 3,300 3,000 2,700 2,400 2,100 1,800 1,500 300 0
3,437 3,100
336
Jan. 10
Feb. 10
Mar. 10
Apr. 10
May 10 Jun. 10
Jul. 10
Aug. 10
Sept. 10
Oct. 10
Nov. 10
Dec. 10
Jan. 11
Note: Monthly average count
BAKER HUGHES RIG COUNT: US / CANADA 1,800
1,707
1,600
1,396
1,400 1,200 1,000 800
625
543
600 400 Mar. 2
1Reformulated
Mar. 3
Mar. 4
Mar.7
gasoline blendstock for oxygen blending 2Nonoxygenated regular unleaded
Mar. 8
200
12/25/09
12/18/09
1/8/10
1/1/10
1/22/10
1/15/10
2/5/10
1/29/10
2/19/10
2/12/10
3/5/10
2/26/10
12/24/10
12/17/10
1/7/11
12/31/10
1/21/11
1/14/11
2/4/11
1/28/11
2/18/11
2/11/11
3/4/11
2/25/11
Note: End of week average count
6
Oil & Gas Journal | Mar. 14, 2011
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Lukoil eyes Siberian Bazhenov, US shale stake OAO Lukoil is experimenting with shale oil recovery in Russia and is interested in participating in a US shale play, the company’s president said at the IHS-CERA energy conference in Houston last week. Vagit Alekperov said Lukoil is experimenting in the Jurassic Bazhenov shale in Western Siberia, one of the world’s most prolific source rocks (OGJ, May 22, 2000, p. 38). Alekperov said Lukoil would like to identify a partner and become involved in shale drilling in the US, where a number of non-US companies have taken positions in recent times, in order to transfer drilling and completion technologies to the Bazhenov.
BOEMRE plans workshop on new offshore rules The US Bureau of Ocean Energy Management, Regulation, and Enforcement will hold a 1-day workshop on Mar. 25 in New Orleans to discuss standards and requirements for exploration and development plans, with an emphasis on new safety requirements which have been implemented in the last 6 months. The workshop at BOEMRE’s Gulf of Mexico regional office will provide information on plan submissions related to E&D plans, worst case discharge calculations, the National Environmental Policy Act, oil spill response plans, and spill response and containment, BOEMRE said. BOEMRE said the workshop will be open to gulf OCS region stakeholders. There is no registration for the meeting, but seating is limited, it said. The workshop will be in addition to one which BOEMRE plans to hold on Mar. 15 to discuss new requirements for offshore oil and gas companies to develop and implement new safety and environmental management systems.
EXPLORATION & DEVELOPMENT Q U IC K TA K E S Pemex tests Eagle Ford shale gas well Pemex Exploracion & Production has tested dry gas at the rate of 3 MMcfd from its first exploratory well in the Eagle Ford shale. The Emergente well, in northern Coahuila state, has 17 frac stages in a 4,500-ft lateral at 2,500 m. Pemex is still evaluating the unconventional gas well, said Pemex E&P Director General Carlos A. Morales Gil. He said the company believes the formation extends to the south and that it should include liquids to the west. The Emergente well is about 5 km west of a gas conditioning station in the Burgos basin, Morales Gil said.
Ghana’s Owo light oil field extended, renamed A Tullow Oil PLC group successfully appraised its Owo light oil field discovery off Ghana, and the field has been renamed Enyenra. The Enyenra-2A appraisal well confirmed a downdip extension of the field discovered by the Owo-1 well in 2010 on the
8
Deepwater Tano block. Enyenra-2A encountered oil and gascondensate in high-quality stacked sandstone reservoirs. Located more than 7 km south of the discovery well, Enyenra-2A was drilled to intersect the upper channel in which oil was discovered by the Owo-1 and Owo-1 sidetrack wells and the lower channel where gas-condensate was found in the Owo-1 sidetrack. Results of drilling, wireline logs, reservoir fluid samples, and pressure data show that Enyenra-2A cut 21 m of oil pay in the upper channel and 11 m of oil pay in the lower channel. Pressure data from the upper channel indicate Enyenra-2A to be in communication with Owo-1. Pressures in the lower channel suggest communication with the deeper pools in the two Owo wells. Enyenra-2A also tested a distal portion of a deeper Turonian-age fan where 5 m of gas-condensate sandstones were intersected. An evaluation of the extent and thickness of this new play continues. The Deepwater Millennium dynamically positioned drillship drilled Enyenra-2A to 13,891 ft total depth in 5,492 ft of water. After logging, the group will suspend the well for future use. The drillship will stay on the block to drill the Tweneboa-4 well.
EPL, Phoenix to explore East Bay moderate depths Energy Partners Ltd., New Orleans, and Phoenix Exploration Co. LP, Houston, will explore moderate depths below production at the giant East Bay area on South Pass blocks 24, 26, and 27 off Louisiana. The East Bay area is nearly all in state waters where the state offers severance tax suspension on wells at 15,000 ft or more of true vertical depth. East Bay, in shallow water 90 miles southeast of New Orleans, is the sixth largest field on the Gulf of Mexico shelf in terms of cumulative production. Technical teams from both firms will use EPL’s 223 sq miles of newly reprocessed seismic data to generate Miocene prospects at 14,000-20,000 ft that can be drilled for $12-20 million. The companies don’t plan to pursue perceived potential in Lower Miocene, Oligocene, and Eocene at costlier ultradeep depths. First drilling could occur in late 2011. The agreement provides for EPL to farm out acreage at East Bay, with a promoted overriding royalty interest in favor of EPL on interest Phoenix earns in successful prospect areas. EPL retained the right to participate up to a 50% working interest in each prospect area. EPL said it chose Phoenix over others because of its “expertise and excellent track record exploring similar plays in this region. By leveraging our respective skill-sets, the agreement allows us to more efficiently generate and drill high-impact prospects below our existing shallow productive horizons.” The moderate depths offer “high-potential resources on the Gulf of Mexico shelf for shallow water costs” at compelling riskreward, EPL said.
Oil & Gas Journal | Mar. 14, 2011
Niobrara oil play fans out near Chugwater, Wyo. The northwest edge of the Denver-Julesburg basin seems in for a round of spirited drilling due to the horizontal Niobrara shale oil play. Various operators have received permits to drill well over 100 wells in a nonproducing area in northwestern Laramie County, Wyo., between Silo oil field and the Chugwater community. Prominent operators EOG Resources Inc., Chesapeake Energy Corp., Noble Energy Inc., and Barrett Resources Corp., are joined by private companies on those permits. Drilling has hardly begun. Recovery Energy Inc., Denver, an independent focused on the Denver basin, will close Mar. 4 on the purchase of 8,060 net acres from Wapiti Oil & Gas LLC for $12.3 million in cash and stock. The deal will give REI 14,400 contiguous gross acres in its Chugwater block. REI will operate its first well in the second quarter of 2011 as soon as a suitable rig is available. It has signed a joint venture agreement with an undisclosed private independent that will pay 100% of the cost of two horizontal Niobrara wells and carry REI for a 40% working interest in each. REI is seeking a total of four drilling permits. REI expects to encounter Niobrara, which it believes will have intense natural fracturing, at 8,300 ft true vertical depth, and then drill a 4,500-ft lateral, said Roger A. Parker, chairman and chief executive officer. The first location is in 19n-67w. REI’s block is about 8 miles south of Chugwater and 10 miles northwest of the northwest edge of Silo field, a vertical 1981 Niobrara discovery redeveloped horizontally in the early 1990s. “There are 122 recently permitted horizontal Niobrara wells within three to four townships around us,” Parker said. REI’s team is interested in conventional and unconventional formations in the basin. The company is drilling J sand development wells in Grover field, Weld County, Colo., where it just closed the acquisition of 1,700 acres from private individuals. That deal also included 6,600 net acres in Goshen County, Wyo. Parker said the company also plans to exploit the Niobrara at Grover, just east of where EOG Resources kicked off the present horizontal Niobrara play with the Jake well in 1-11n-63w (OGJ Online, Apr. 7, 2010). “The acquisition in the Grover field complements our positions throughout the northern half of the DJ basin giving us significant exposure in what we believe will be both the matrix porosity and naturally fractured areas of the Niobrara shale,” Parker said.
DRILLING & PRODUCTION Q U IC K TA K E S DOJ task force consolidates Macondo inquiries The US Department of Justice has formed a task force to maximize resources devoted to the criminal investigation of the Ma-
Oil & Gas Journal | Mar. 14, 2011
condo well accident and subsequent Gulf of Mexico crude oil spill, DOJ officials said on Mar. 7. DOJ’s criminal division, environment and natural resources division, and the US Attorney’s office for eastern Louisiana have been working for several months on separate and simultaneous investigations related to the matter, a spokesman told OGJ. He said that Deputy US Atty. Gen. James Cole decided to establish a single task force after assessing the overlapping cases in an effort to avoid duplication of efforts. John Buretta, a senior counsel in DOJ’s criminal division, will lead the task force under the supervision of Assistant Atty. Gen. Lanny Breuer, who heads that division, the spokesman said.
Seneca sells gulf assets; hits Marcellus output mark An undisclosed purchaser has agreed to buy the Gulf of Mexico oil and gas producing properties of Seneca Resources Corp., Williamsville, NY, for $70 million, leaving Seneca free to increase focus on its Appalachian and California assets. Seneca said it hasn’t made substantial investments in the gulf properties for several years and that it will invest the proceeds in the Marcellus shale. Closing is set for Apr. 30 retroactive to Jan. 1. Meanwhile, Seneca said its Marcellus production reached 120 MMcfd on Mar. 7 from 32 operated and 27 nonoperated wells. The company said longer laterals and more frac stages per well have led to higher anticipated estimated ultimate recoveries that will offset the increased service costs. Seneca said, “We are now anticipating well costs of $5-6.4 million for wells with up to 20 frac stages and lateral lengths reaching over 6,000 ft. Taking these factors into account, we expect to see results continue to improve over time, with some of our best wells achieving EURs of 8 bcf.” This implies 20-65% pretax internal rates of return at $4/MMbtu. With the gulf sale, the exploration and production segment’s fiscal 2011 capital spending is expected to be $600-655 million, up from $485-560 million.
PROCESSING Q U IC K TA K E S Crude unit, hydrocracker due at Sohar Expansion of the Sohar refinery in Oman will include installation of a crude unit and hydrocracker (OGJ Online, Mar. 2, 2011). The refinery, now with a capacity of 116,000 b/d, processes a mixture of Oman Export Blend crude and long resid delivered by pipeline from the 106,000 b/d Mina Al-Fahal refinery near Muscat 266 km to the southeast. Oman Refineries & Petrochemical Co. let a contract to CB&I for front-end engineering and design and project management for a project at Sohar that will include a 71,500 b/d crude distillation unit, 96,800 b/d vacuum distillation unit, 66,400 hydrocracker, and 42,400 b/d deasphalting unit. Other units will be for sulfur recovery, sour water stripping,
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amine regeneration, and isomerization. Existing Sohar facilities in addition to the distillation tower include a 75,260 b/d resid fluid catalytic cracker and propylene recovery and indirect alkylation units. Among goals of the project, according to the Oman Refineries web site, are production of 1.5 million tonnes/year of naphtha to feed the reformer at a nearby Aromatics Oman LLC complex and improvement of RFCC feed quality. Sohar is a port on Oman’s northeast coast.
GHG regulations threaten US refining, EPA told US Environmental Protection Agency regulation of refineries’ greenhouse gas (GHG) emissions could drive many US refiners out of business by placing them at a significant disadvantage to foreign gasoline, diesel fuel, and jet fuel suppliers, National Petrochemical & Refiners Association Pres. Charles T. Drevna said on Mar. 4. “Our nation’s petroleum refineries remain one of the last internationally competitive segments of the American manufacturing base,” he said in a letter to Gina McCarthy, EPA’s assistant administrator for air and radiation, which NPRA submitted to accompany its oral testimony at the agency’s listening session on its effort to implement GHG regulations under the Clean Air Act. EPA has said that it formulated the regulations in response to a 2007 US Supreme Court decision saying that it had the authority and obligation to do so. US refiners process 95% of the gasoline, diesel, jet fuel, heating oil, and lubricants which are used domestically, Drevna continued. “There is no guarantee that the US domestic refining manufacturing base will continue to be in existence two or three decades from now,” he said. “Our members’…plants could well go the way of many domestic auto plants, virtually all of our domestic textile miles, and many domestic steel plants.” In his testimony, Howard J. Feldman, the American Petroleum Institute’s regulatory and scientific affairs director, said API also opposes EPA’s GHG regulatory effort, but backs completion of its new source performance standards under the Subpart Ja rulemaking relative to flares. Refiners already have strong incentives to be more efficient because energy is their second largest cost, less efficient plants have closed as the number of US refineries has dropped by 50% in recent decades, and refiners already have installed cogeneration where appropriate, he noted. “The refining industry already faces a blizzard of EPA regulations that threaten US operations and jobs,” Feldman said. “We’re not sure where this and other regulations fit into [US President Barack Obama’s] regulatory review directive.”
TRANSPORTATION Q U IC K TA K E S Kitimat LNG partners award FEED contract Partners in Canada’s Kitimat LNG project let a contract to KBR for front-end engineering and design of the planned LNG export facility on British Columbia’s west coast.
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Kitimat LNG owners Apache Canada Ltd. and EOG Resources Canada Inc., which let the contract to KBR, plan to build the facility with initial capacity of 5 million tpy on Haisla First Nation land at Bish Cove 400 miles north of Vancouver. Apache Canada is the managing partner of KM LNG Operating General Partnership, which owns 51% of the Kitimat LNG facility and is the facility operator. EOG Canada, through subsidiaries, owns 49%. Kitimat LNG Pres. Janine McArdle said, “This is another important milestone for Kitimat LNG, taking us a significant step closer in being able to export LNG to Asia-Pacific markets as soon as 2015.” Last month, Kitimat LNG Partners agreed to buy the remaining 50% interest in Pacific Trails Pipeline LP, thus securing full ownership of the infrastructure to transport natural gas from production areas to Kitimat LNG (OGJ Online, Feb. 9, 2011). The 36-in., 287-mile buried pipeline will carry natural gas to Kitimat from Summit Lake in Northeast British Columbia. Apache Canada and EOG Canada are in marketing discussions with potential Asia-Pacific LNG customers. The partners expect to have firm sales commitments in place by the time a final investment decision is made near yearend. Kitimat LNG’s application for a 20-year export license is pending with Canada’s National Energy Board. A hearing is set for June 7.
Enterprise to buy Permian carbon dioxide line Enterprise Products Partners LP purchased a 39-mile carbon dioxide pipeline from Trinity Pipeline LP that Enterprise will convert to crude oil service. The 8-in. OD pipeline, extending from Reeves County, Tex., to Lea County, NM, will be capable of shipping an estimated 54,000 b/d to the Basin Pipeline. Converting the pipeline to oil service and linking to Basin will expand takeaway capacity in the Permian basin’s Bone Spring-Avalon play, allowing shippers access to Enterprise’s network, including storage facilities at Midland, Tex., and Cushing, Okla. Enterprise will build a central delivery point and associated infrastructure for receiving truck deliveries of crude oil for loading onto the converted line. Construction of the new facilities and conversion of the pipeline to crude oil service is expected to be completed by yearend. The Bone Spring-Avalon play is characterized by an interval of shale, sandstone, and limestone up to 2,000 ft thick. Prospective production has been identified in multiple horizons on more than 2 million acres throughout Eddy and Lea counties in New Mexico and Reeves, Loving, Ward, and Culberson counties in Texas. Enterprise estimates 120,000 b/d crude oil production and 500 MMcfd gas production as possible from the play by 2018, based on 400 wells drilled/year. There are currently 30 rigs operating in the play, Enterprise said. Energen Resources Corp, Birmingham, Ala., expanded its Bone Spring-Avalon acreage by 17,000 net acres in January and plans to drill at least 14 wells in the play during 2011 (OGJ Online, Jan. 7, 2011).
Oil & Gas Journal | Mar. 14, 2011
MINISTRY of MINES and ENERGY
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G E N E R A L D I R E C T O R AT E f o r H Y D R O C A R B O N S
S O C I E T E N AT I O N A L E D ’ O P E R AT I O N S P E T R O L I E R E S
::
DE LA COTE D’IVOIRE
CALL FOR EXPRESSION OF INTEREST Supply of Liquefied Natural Gas (LNG) On the basis of studies assessing the national Natural Gas supply security, the Government of the Republic of Côte d’Ivoire (“GoCI”) has elected to procure additional supply sources beyond its domestic gas fields. The objective of this call for expression of interest is to identify companies which could provide the GoCI through the stateowned national hydrocarbon company PETROCI Holding, the following energy supply and/or services: With respect to energy supply (the “Supply”) :: Delivery of Liquefied Natural Gas (“LNG”); :: Supply requirement are estimated to amount at a minimum of 100 Billion BCF/Year over a time horizon of 10 years renewable.
With respect to services and infrastructure (the “Services”) :: Transportation, storage and re-gasification of LNG; :: Deliveries into PETROCI pipeline system to be
effected at the Vridi Canal zone – Abidjan.
Submission Process Companies with appropriate experience in these fields are invited to register their interest. NB: The application entitled “Prequalification Document” will be downloaded from PETROCI website: www.petroci.ci The candidate submissions must be labeled: To the Attention of the Managing Director of PETROCI Holding “Expression of Interest for the supply of LNG to Côte d’Ivoire”
Four (4) copies of the submission shall be delivered in a sealed envelope no later than Friday March 19, 2011 at 5:00 pm at the following address: PETROCI HOLDING Mrs. KATIA METAN 14 Boulevard Carde, Abidjan Plateau, Immeuble les Hévéas, 9ème étage, face porte 919 BPV 194 Abidjan, Côte d’Ivoire
Evaluation A short list of candidates offering the best credentials will be established. These pre-selected candidates will then be invited to make both a technical and a financial offer in response to a competitive Request for Proposal (the “RFP”). The winning candidate(s) will be selected based on the selection criteria specified in the RFP.
Expression of Interest Inquiries Candidates should consider the Call for Expression of Interest and request any required clarifications in writing not later than 3 days before the Due Date. All inquiries shall be submitted in writing to: Mister CHARLES ANOH EZOUA, Supervisor of Natural Gas Technical Activities, at the following email address: [email protected] Kassoum FADIKA
The Office of the CEO
2011-2012 EVENTEVENT CALENDAR 2011-2012 CALENDAR Denotes new listing or (0)20 7840 2139, +44 (0)20 7840 2119 (fax), ea change in previously mail: meos@oesallworld. published information. com, website: www. meos2011.com. 20-23.
952-9435 (fax), e-mail: Energy and Infrastructure [email protected], website: Conference, Tbilisi, +44 www.spe.org. 27-29. 207 596 5135, +44 207 596 5106 (fax), e-mail: NPRA International Pet- ilyas.idigov@ite-exhibirochemical Conference, tions.com, website: www. GPA Europe at GasTech San Antonio, (202) 457- giogie.com/2011/. 29-30. MARCH 2011 Conference & Exhibition, 0480, (202) 457-0486 (fax), e-mail: info@npra. Eastern Canada shale NACE Corrosion Confer- Amsterdam, +44 (0) org, website: www.npra. Gas Symposium, Montre1737 855000, +44 (0) ence & Expo, Houston, org. 27-29. 1737 855482 (fax), eal, Que., (877) 927-7936, (800) 797-6223, (281) mail: [email protected], (877) 927-1563 (fax), 228-6329 (fax), website: Howard Weil Annual e-mail: www.gastech. e-mail: customerserwww.events.nace.org/ Energy Conference, New vice@canadianinstitute. co.uk. 21-24. conferences/c2011/inOrleans, (504) 582com, website: www. dex.asp. 13-17. GASTECH International 2500, website: www. canadianinstitute.com/ Conference & Exhibition, howardweil.com/energy- energy_resources/EastAIChE Spring Meeting conference.aspx. 27-30. ernShaleGas.htm. 29-30. Amsterdam, +44 (0) & Global Congress on 1737 855000, +44 (0) Process Safety, Chicago, 1737 855482 (fax), eMiddle East Downstream Offshore Asia Conference (800) 242-4363, (203) mail: [email protected], Week Annual Meeting, & Exhibition, Singapore, 775-5177 (fax), website: e-mail: www.gastech. Abu Dhabi, +44 (0) 1242 (918) 831-9160, (918) www.aiche.org/confer529 090, +44 (0) 1242 co.uk. 21-24. 831-9161 (fax), e-mail: 529 060 (fax), e-mail: ences/springmeeting/ registration@pennwell. wra@theenergyexchange. index.aspx. 13-17. CIPPE China Intercom, website: www. co.uk, website: www. national Petroleum & offshoreasiaevent.com. Offshore West Africa Petrochemical Technol- wraconference.com. 29-31. 27-30. Conference & Exhibition, ogy and Equipment Accra, Ghana, (918) 831- Exhibition, Beijing, +86 IRO On & Offshore ACS National Meeting 10 58236588/6555. 9160, (918) 831-9161 Exhibition, Gorinchem, +86 10 58236567 (fax), & Exposition, Anaheim, (fax), e-mail: registra+31 523 289866, e-mail: Calif., (202) 872-4600, e-mail: cippe@[email protected], antoinettehulst@evene-mail: [email protected], expo.com, website: www. website: www.offshoreementenhal.nl, website: website: www.acs.org. cippe.com.cn/cippeen. westafrica.com. 15-17. www.evenementenhal. 27-31. 22-24. nl/gorinchem/beurzen. World Heavy Oil ConPurvin & Gertz Interna- 29-31. IADC Drilling HSE Asia gress, Edmonton, Alta., tional LPG Seminar, The Pacific Conference & (888) 799-2545, (403) SEG Shale Gas Forum, Woodlands-Houston, Exhibition, Singapore, 245-8649 (fax), website: Chengdu, Sichuan, (713) 331-4000, (713) (713) 292-1945, (713) www.worldheavyoilcon- 292-1946 (fax), e-mail: 236-8490 (fax), e-mail: (918) 497-5500, (918) gress.com. 15-17. 497-5557 (fax), website: [email protected], website: info@purvingertz. com, website: www. www.seg.org. 30-31. www.iadc.org/conferTUROGE Turkish purvingertz.com. 28-31. ences. 23-24. International Oil & Gas Conference & Showcase, OMC Offshore Mediter- SPE European Well APRIL 2011 Ankara, +44 (0) 20 7596 ranean Conference, Abandonment Seminar, Aberdeen, +44 1224 5000, +44 (0) 20 7596 Ravenna, +39 0544 Middle East Downstream 5111 (fax), e-mail: en219418, e-mail: confer- 495051, e-mail: jane. Week Annual Meeting, rodger@hulse-rodger. [email protected], [email protected], website: Abu Dhabi, +44 1242 www.omc.it/2011. 23-25. com, website: www.spe- 529 090, +44 1242 website: www.turoge. uk.org. 29. com. 16-17. 529 060 (fax), e-mail: Marine Technology c.pallen@theenergyexNPRA Annual Meeting, Society Houston Section Woodford Shale Summit, change.co.uk, website: San Antonio, (202) 457- Annual Marine/Offshore Norman, Okla., (405) www.wraconferences. com/2/4/articles/105. 0480, (202) 457-0486 Industry Outlook Confer- 525-3556, ext. 117, (405) 525-3592 (fax), php. 3-6. (fax), e-mail: info@npra. ence, Houston, (512) e-mail: amy.childers@ org, website: www.npra. 301-2744, website: www. iogcc.state.ok.us, webmtshouston.org. 24. GPA Annual Convention, org. 20-22. site: www.woodfordsumSan Antonio, (918) 493mit.com. 29-30. SPE Production and 3872, (918) 493-3875 MEOS/SPE’s Middle East Operations Sympo(fax), e-mail: pmirkin@ Oil & Gas Conference & GIOGIE Georgian sium, Oklahoma City, gpaglobal.org, website: Exhibition, Manama, +44 (800) 456-9393, (972) International Oil & Gas www.GPAglobal.org. 3-6.
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Hannover Messe Pipeline Technology Conference, Hannover, +49 511 90992 22, +49 511 90992 69 (fax), e-mail: [email protected], website: www.pipelineconference.com. 4-5.
AAPG Annual Convention & Exhibition, Houston, (918) 560-2679, (918) 560-2684 (fax), website: www.aapg.org. 10-13.
APPEA. Conference and Exhibition, Perth, +61 (7) 3802 2208, +61 (7) ShaleCon Conference, 3802 2209, website: Montreal, Q.C., (800) www.appeaconferences. 882-8684, e-mail: info@ com.au. 10-13. iapc.com, website: www. shalecon.com/Event. GITA’s Geospatial aspx?id=388398. 4-7. Infrastructure Solutions Conference, Grapevine, Hannover Messe InterTexas, (303) 337-0513, national Trade Show, (303) 337-1001 (fax) Hannover, +49 511 89 0, website: www.gita.org/ +49 511 89 32626 (fax), events/futconf.asp. website: www.hannover- 10-14. messe.de/homepage_e. 4-8. SAGEEP Information Exchange for New-SurSPE/ICoTA CoiledTubface Geophysics Forum, ing & Well Intervention Charleston, (918) 497Conference & Exhibition, 5500, (918) 497-5557 The Woodlands, Texas, (fax), website: www.seg. (800) 456-9393, (972) org. 10-14. 952-9435 (fax), e-mail: [email protected], website: Gas Turbine Users www.spe.org. 5-6. International Annual Conference (GTUI), Dubai, SPE/IADC Managed +971 4 8047883, +971 Pressure Drilling & Un- 4 8873584 (fax), e-mail: derbalanced Operations [email protected], website: Conference, Denver, www.gtui.org. 10-15. (800) 456-9393, (972) 952-9435 (fax), e-mail: The Project Forum, [email protected], website: cow, +44 (0) 20 7357 www.spe.org. 5-6. 8394, +44 (0) 20 7357 8395 (fax), e-mail: enOilTech Atyrau Regional [email protected], Petroleum Technology website: www.europetro. Conference, Atyrau, +44 com. 11-12. (0) 20 7596 5000, +44 (0) 20 7596 5111 (fax), Process Safety Mane-mail: enquiry@iteagement of Chem/ exhibition.com, website: Petrochem & Refineries www.oiltech-atyrau.com/ Conference, Houston, home.html. 5-6. (312) 540-300, ext. 6625, e-mail: MicheAtyrau North Caspian lew@marcusevansch. Regional Oil, Gas and com, website: www. Infrastructure Exhibimarcusevansch.com/ tion, Atyrau, +44 (0) 20 OGJPSM. 11-13. 7596 5000, +44 (0) 20 7596 5111 (fax), e-mail: IPAA OGIS-New York, enquiry@ite-exhibition. NewYorkCity, (202) 857com, website: www. 4722, (202) 857-4799 atyrauoilgas.com2011/. (fax), website: www.ipaa. 5-7. org. 11-13.
Oil & Gas Journal | Mar. 14, 2011
2011-2012 EVENT CALENDAR acooper@hartenergy. MAY 2011 com, website: www.dugconference.com. 18-20. OTC Offshore Technology Conference, Houston, Alliance Expo & Annual (301) 694-5243, or Meeting, Wichita Falls, (866) 229-2386, (972) Texas, (940) 723-4131, 952-9435 (fax), e-mail: (940) 723-4132 (fax), [email protected], ISA Calgary, Calgary, e-mail: texasalliance@ website: www.otcnet. Alta., (403) 209-3555. texasalliance.org, weborg.2011. 2-5. API Pipeline Conference, (403) 245-8649 (fax), site: www.texasalliance. San Antonio, (202) 682 website: www.isacalgary. org/index.php. 26-27. GPA Permian Basin 8000, (202) 682-8222 com. 13-14. Annual Meeting, Odessa, (fax), website: www.api. Oil & Gas Siberia, Novosi- (918) 493-3872, (918) org. 12-13. Middle East Petroleum & birsk, +7 383 2106290, 493-3875 (fax), website: Gas Conference (MPGC), +7 383 2209747 (fax), e- www.gasprocessor.com/ AADE National TechniBahrain, 0065 6338 mail: [email protected], calendar.html. 3. cal Conference and 0064, 0065 6338 4090 website: www.petroleum. Exhibition, Houston, (fax), website: www. sibfair.ru/eng/. 27-29. Antitrust and Consumer (281) 366-8204, e-mail: gulfoilandgas.com. 17-19. Protection Issues in [email protected], GPA Mid-continent An- the Energy Industry website: www.aade.org. DUG Developing Uncon- nual Meeting, Okla. City, Conference, Houston, 12-14. ventional Gas Conference (918) 493-3872, (918) (312) 988-5609, (312) & Exhibition, Fort Worth, 493-3875 (fax), website: 988-5637 (fax), e-mail: Russia & CIS Bottom of (713) 280-6479, (713) www.gpaglobal.org/chap- patricia.harris@americanthe Barrel Technology 583-1353 (fax), e-mail: ters/midcontinent. 28. bar.org. website: http:// Pipe Line Contractors Association of Canada Annual Convention, Maui, (905) 847-9383, (905) 847-7824 (fax), email: [email protected], website: www.pipeline. ca/convention.html. 11-15.
Conference & Exhibition, Moscow, +44 (0) 20 7357 8394, +44 (0) 20 7357 8395 (fax), e-mail: enquiries@europetro. com, website: www.europetro.com. 13-14.
tinyurl.com/energyconfer- International School of ence-program. 5-6. Hydrocarbon Measurement, Oklahoma City, World Renewable Energy (405) 325-1217, (405) 325-1388 (fax), e-mail: Congress, Linkoping, e-mail: info@wrec2011. [email protected], website: www.ishm.info/. 10-12. com, website: www. wrec2011.com. 8-13. IADC Environmental Conference & Exhibition, NPRA National Safety Trinidad & Tobago, (713) Conference & Exhibition, Forth Worth, Texas, 292-1945, (713) 292(202) 457-0480, (202) 1946 (fax), e-mail: info@ 457-0486 (fax), e-mail: iadc.org, website: www. [email protected], website: iadc.org/conferences. 12-13. www.npra.org. 10-11. IADC Critical Issues Middle East Conference & Exhibition, Dubai, (713) 292-1945, (713) 292-1946 (fax), e-mail: [email protected]. website: www.iadc.org/ conferences/Critical_Issues_ME_2011. 10-11.
SPWLA Symposium, Colorado Springs, Colo., (713) 947-8727, (713) 947-7181 (fax), e-mail: www.webmaster@spwla. org, website: www.spwla.2011.com. 14-19.
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JOURNALLY SPEAKING
Europe’s shale revolution
PAULA DITTRICK Senior Staff Writer
Many oil and gas companies eagerly are contemplating shale gas development in Europe and elsewhere, hoping to replicate the US gas model. But simply put, could heavily populated cities such as Paris realistically sustain the activities associated with an equivalent of the North Texas Barnett shale? The French government put its shale oil and gas research permits on hold pending completion in June of a joint study by Energy Minister Eric Besson and Environment Minister Nathalie Kosciusko-Morizet to evaluate the economic, social, and environmental effects of shale exploration (OGJ Online, Feb. 14, 2011). Analysts agree it’s too early to have any idea how many shale plays might develop outside the US and Canada. Paul Stevens, senior research fellow for Chatham House of London, said potential global unconventional gas resources (coalbed methane, tight gas, and shale gas) are estimated at five times conventional gas reserves. But he notes concerns exist about replicating US shale development and production abroad. “The US revolution was triggered by favorable factors such as geology, tax breaks, and a vibrant industry,” Stevens said. Although industry has much interest in Western Europe shale potential, Stevens said, “Geology is less favorable, there are no tax breaks, and the drilling industry is far behind the US. Also in a densely populated Europe…disruptions caused by shale gas developments will struggle to find public acceptance. Unlike the US, benefits from gas production accrue to governments, not local landowners.” In a 2010 report entitled “The Shale Gas Revolution: Hype and Reality,” Stevens discussed prospects outside the US. In Western Europe, the targets primarily are Poland, Germany, Hungary, Romania, Turkey, and northwest England. ExxonMobil Corp., ConocoPhillips, and Chevron Corp. have signed or are negotiating exploration agreements for shale in the Lublin and Podlasic basins in southeast Poland.
Research initiative Industry and the German National Laboratory for Geosciences started the first European interdisciplinary research initiative in 2009 for gas shales
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in Europe. The initiative focuses on potential gas shales, especially Denmark’s Alum shale and Germany’s Posidonia and Carboniferous shales. In Latin America, attention is directed toward Argentina and Chile, Stevens said. China and India have expressed strong interest in CBM. China is assessing its shale gas resources. “However, there are many barriers and constraints to be overcome if the potential is to be converted into energy at the burner tip,” Stevens said. Shale gas deposits in Europe are deeper and smaller than those in the US. European shale plays are fragmented, and the shale is richer in clay, making it less amenable to fracturing. Onshore drilling has been limited in Western Europe, which lacks the history of drill core evidence that exists in the US. “Traditionally, exploration licenses onshore in Western Europe have been granted over relatively small licensing areas, each with its own specific work program as part of the contract,” Stevens said. “The laws and regulations covering oil and gas exploration and development do not even make reference to unconventional gas.” For instance, a gas field normally is defined in terms of the gas-water contact. But there is no such contact point in an unconventional field, and no definable field under current legislation. “However by contrast, the environmental legislation, especially at a local level, is much tougher and more specific than in the United States—at least up until now—and so would present serious challenges for unconventional gas operations in the context of hydraulic fracturing,” Stevens said. Europe lacks the onshore service industry readily available in the US, he said, adding, “The scale of requirement is enormous.” Western Europe had about 100 land rigs available as of April 2010 while 199 rigs were active in the Barnett play at its boom during 2008. Another consideration is that large-scale disruptions caused by drilling and hydraulic fracturing are likely to general local opposition, Stevens said, noting Europe is densely populated and highly urbanized so large-scale unconventional gas operations would impinge on communities. “It is likely to be some time before it will become clear whether or not the shale gas revolution might sweep Europe,” Stevens said.
Oil & Gas Journal | Mar. 14, 2011
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EDITORIAL
A lingering question Disagreement lingers—and always will—over a troubling question raised by the Macondo tragedy of last Apr. 20: Does the fatal blowout condemn all safety habits of an entire industry? During the IHS-CERA Week conference in Houston last week, three interesting views emerged. The oil and gas industry has bristled from sweeping criticism it received in a report delivered in January to President Barack Obama by the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. “The immediate causes of the Macondo well blowout can be traced to a series of identifiable mistakes made by BP, Halliburton, and Transocean that reveal such systematic failures in risk management that they place in doubt the safety culture of an entire industry,” the report said, calling for “no less than a fundamental transformation of its safety culture.”
‘Plenty of evidence’ William Reilly, the former Environmental Protection Agency administrator who co-chaired the commission, said in an IHS-CERA Week panel session that the accident produced “plenty of evidence that it was a systemic problem.” He pointed out that the commission faulted cement-service provider Halliburton and drilling contractor Transocean along with BP, the operator. And offshore operators obviously lacked the ability to respond promptly to a deepwater blowout and spill, yet they claimed otherwise on “pro forma response plans.” They also hadn’t updated spill cleanup equipment installed after the Exxon Valdez tanker spill off Alaska in 1989, Reilly said. These are stinging truths. They make painfully clear the need to redress lapses that Reilly rightly described as inexcusable and to review practices, business relationships, and regulation made obsolete in a rapidly evolving realm of operation. Much less certain is whether they warrant wholesale doubt about the safety culture of an entire, technically complex industry. The oil and gas business will encounter the commission’s extrapolation whenever opposition arises to its work, meaning frequently. Commissioners didn’t have to worry about exploitation of their words the toxic climate of energy
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politics; industry officials do. Industry officials also have reason to defend their safety culture and record, notwithstanding dreadful lapses revealed by Macondo. In its zeal for change, the commission seems dangerously willing to discard what works well. Ali Moshiri, president of Chevron Africa & Latin America E&P Co., thus may have given voice to what other industry executives may be thinking when he said, in the session at which Reilly spoke, that the tragedy “was not a systematic problem; it was an accident that never should have happened.” Moshiri didn’t refute the need for improvement. But his view clearly differed from that of the commission report, which at one point said, “The blowout was not the product of a series of aberrational decisions made by rogue industry or government officials…. Rather, the root causes are systemic and, absent significant reform in both industry practices and government policies, might well recur.” At the IHS-CERA Week session, Moshiri said, “It was an isolated problem.” BP, of course, benefits from any interpretation of Macondo as something beyond a BP problem. In a luncheon speech that began with a personal apology, BP Chief Executive Robert Dudley steered hard toward such a view. He noted the commission finding that the accident had “multiple causes, involving multiple parties.” He pointed to “lessons for the industry as a whole” and the “challenge to work together more effectively.”
Offer to share Dudley also listed some of the many capabilities BP now possesses that no company could claim before the accident. And he made an offer: “We believe we have a responsibility to share our learning with those who can benefit from it, including our competitors, partners, governments, regulators.” Yes, an entire industry can benefit from BP’s lessons learned the hard way. If Macondo makes oil and gas work safer, the question whether pre-Macondo practices deserve wholesale condemnation will not have mattered beyond the extent to which asking it, and arguing over the answer, drove improvement.
Oil & Gas Journal | Mar. 14, 2011
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GENERAL INTEREST
In June 2010, Cheniere Energy announced its intention to export US gas as LNG as it made plans to build liquefaction at its existing— and recently completed—import terminal on the Sabine Pass, Cameron Parrish, La. Photo from Cheniere Energy.
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Oil & Gas Journal | Mar. 14, 2011
COMMENT
Consultant: US LNG exports likely in near term We are on the brink of a new opening of LNG exports from an unexpected source, according to Fereidun Fesharaki, chairman of FACTS Global Energy, in a recent analysis. Only 3-4 years ago, the US was expected to be the second-largest LNG importer in the world. Now, he said, it hopes to export almost 25 million tonnes/year (tpy) from the US Gulf Coast and a yet-to-be-determined quantity from the East Coast. Skeptics of the plans have pointed to the volatility of Henry Hub prices, the rising cost of shale gas, and the potential regulatory challenges on the back of environmental concerns as inhibiting factors. Supporters, on the other hand, say that rising shale gas reserves and production, emerging liquids production from shale, and less-severe environmental impediments than is generally assumed would ensure the success of US shale gas-based LNG export schemes, Fesharaki noted.
Clear facts First and most important, he said, the US may be running out of oil—geologically or geopolitically—but it is not running out of gas. “While nonconventional oil production might reach 10-15% of conventional oil, it is clear that nonconventional gas can approach a third or more of the global gas supply,” he said. Secondly, oil prices and gas prices will not converge in the US for the foreseeable future, “certainly not within the next 20 years or even longer.” A fundamental disconnect between US oil and gas prices persists today, although some indirect linkage will be established as oil prices increase. Gas prices will remain substantially lower than oil prices.
Oil & Gas Journal | Mar. 14, 2011
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GENERAL INTEREST Thirdly, the US Energy Information Administration’s latest estimates pointing to 45% of US gas supply by 2035 coming from shale reinforces the fact that the “huge shale supplies in the US are real and can be counted upon.” While the impact on the water tables and potential problems may lay ahead, he noted, for now, exports from the US are “technically, economically, and legally possible and indeed inevitable.”
Prices Even if Henry Hub prices rise to $8-10/MMbtu while oil prices are in the $120-150/bbl range, “we are talking about Asian prices of some $20/MMbtu.” US exports, therefore, still make sense, even if certain pitfalls remain as far as environmental opposition is concerned. But, in most cases, $1-2/ MMbtu additional costs can fix any problem. “If the gap between [Henry Hub] prices and Asian prices is so wide, these additional costs can easily be accommodated,” he said. Moreover, Fesharaki said there is “almost zero chance” of a big change in the price structure in Asia in the foreseeable future. LNG prices will hover between 80-90% of crude, and larger LNG supplies are unlikely to result in a break in the price due to high costs in construction and delivery of LNG. As such, US LNG exports to Asia will “certainly work under almost any scenario.” For Europe, however, the story is not so simple, he said. While transportation costs are lower, price certainty in terms of oil linkages is not there. The futures of Henry Hub and the UK National Balancing Point price directions are not as clear. Some observers, including Fesharaki, see a closer linkage developing over time. As such, while Europe might be a market for US LNG exports, it cannot compete with Asia, which offers “solid oil price linkages and substantially higher prices than Europe.”
Why attractive? What makes LNG exports from the US attractive to buyers is a combination of lower prices and destination flexibility. For Asian buyers, destination flexibility is just as important as price. Many Asian buyers will view US LNG export projects not only as supply sources, but also as an insurance policy for their portfolios. A price of Henry Hub plus roughly $2/MMbtu fob with full destination flexibility, he said, can be a valuable part of their supply portfolios. There are also options not to take the volume and simply pay the $2/MMbtu fee. How much will be exported from the US? Although future export volumes could be large or small, Fesharaki believes it will take a while before long-term buyers see these exports in the same light as, for example, Qatari or Australian exports. But some volumes—1 bcfd, or 7.5 million tpy at the minimum—will be exported. US LNG exports might well come to market in the next
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3-5 years and the size and direction will depend on several factors, such as consumer comfort levels, as well as on continued confidence in the smooth growth of the US shale gas production. It is not impossible for US LNG exports to grow much larger over time. As of February, no fewer than three companies had announced plans to reconfigure their existing terminals as bidirectional export plants: Dominion (Cove Point, Md.), Freeport LNG (Macquarie Energy and Freeport LNG Expansion LP), and Sabine Pass Liquefaction LLC (Cheniere and Sabine Pass LNG). Of all these schemes, Fesharaki believes Cheniere’s plan to export as much as 16 million tpy of LNG from Sabine Pass, La., has attracted the most interest from prospective tenants. As of early March, Cheniere had accrued provisional commitments for up to 8.3 million tpy of LNG from Sabine Pass. Nonbinding memoranda of understanding for bidirectional throughput rights at Sabine Pass are in place with ENN Energy Trading Co. (1.5 million tpy; PennEnergy, Nov. 11, 2010), Morgan Stanley Capital Group (1.7 million tpy; OGJ, Jan. 17, 2011, Newsletter), Gas Natural Fenosa (up to 1.5 million tpy; OGJ Online, Dec. 1, 2010), EDF Trading (0.7-1.5 million tpy; OGJ Online, Jan. 21, 2011), and Sumitomo (up to 1.5 million tpy; OGJ, Feb. 7, 2011, Newsletter). Cheniere also boasts an MOU for the ex-ship sale of up to 0.6 million tpy of LNG with Best Energy.
Reexports Finally, there is another kind of LNG export from the US. Reexports are volumes that have been unloaded and reloaded for the express purpose of sale to markets abroad. So far, several US terminals have been permitted to export LNG: Cameron LNG, La.; Freeport LNG, Tex.; and Sabine Pass LNG. In 2010, a dozen cargoes were reexported and this number may increase in 2011 to around 20 cargoes. There is little chance of a serious upswing in reexports, however, Fesharaki believes. Clearly, the exporters of LNG to the US will be unhappy to see their LNG exported at three to four times the price they received. This kind of US export activity has limited potential. Next, he said, will be potentially huge exports from Canada, based on shale gas from the Horn River and Montney basins. Exports from Canada’s Pacific Coast, however, are likely to run a few years behind the US.
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Oil & Gas Journal | Mar. 14, 2011
GENERAL INTEREST
CERAWeek topics span deepwater drilling, the economy, oil prices Contributing to this coverage of CERAWeek, the annual energy conference hosted by IHS-CERA in Houston, were Bob Tippee, editor; Alan Petzet, chief editor-exploration; Guntis Moritis, production editor; and Paula Dittrick, senior staff writer.
IHS CERA Chairman Daniel Yergin said he expected the conference to be dominated by questions about the Middle East, uncertainty about oil prices, and what it means for the global economy. “The future of the economic recovery and its vitality are very much front and center,” Yergin said.
The economy, oil prices BP’s deepwater drilling policies More investments are necessary if oil production is to keep up with spiraling demand worldwide, and industry is increasingly relying on partnerships to spread financial risk and share expertise, oil company executives told the IHSCERA energy conference last week in Houston. Total SA Chairman and Chief Executive Officer Christophe de Margerie said sufficient short-term oil supply exists worldwide despite civil unrest in the Middle East. But he said more investments are needed if long-term oil and gas production is to meet forecast demand. Industry is responsible to produce more oil and gas in an acceptable way given rising environmental concerns, De Margerie said. “For the time being, there is no reason to consider a shortage of supply,” he said. Total is relying on numerous partnerships worldwide to grow its oil and gas production, he said. John B. Hess, Hess Corp. chairman and chief executive officer, said he foresees an energy crisis coming as a result of rising oil demand. Current rising oil prices are a warning, he said. “While we are not running out of oil…we are not investing enough to grow production capacity to keep up with demand,” Hess said. “The world’s surplus oil production capacity is currently about 3-4 million b/d. As demand grows in the next decade, we will not have the oil production capacity we will need.”
US drilling regulators need to find a balance between ensuring offshore safety without placing unnecessary constraints on operators, BP PLC Chief Executive Robert Dudley told delegates during CERAWeek. “But ensuring that outcome means the industry has to go further than ever before to ensure safe operations—wider than the upstream, wider than the US,” Dudley said. The April 2010 blowout of the deepwater Macondo well off Louisiana resulted in a massive oil spill. BP operated Macondo. BP is implementing company policies in which it will not drill a deepwater reservoir using a dynamically positioned vessel unless BP already has plans and equipment for shutting in the well and drilling a relief well, Dudley said. The new policy also requires that BP stands ready to launch an emergency response. “If anyone ever has to manage a simultaneous operation involving 50 surface vessels and 16 subsea remotely operated vehicles in a radius of 1 mile, then our experience from last year may be useful,” he said. Since Macondo, Dudley said industry has developed new technologies, systems, and equipment through innovations from both oil companies and contractors. “We believe we have a responsibility to share our learning with those who can benefit from it—including our competitors, partners, governments, regulators,” he said.
Energy policy needed
Enhanced standards
Calling for a US energy policy, Hess advocated energy efficiency, increased oil supply, and he urged government to maintain tax provisions that encourage drilling. “As we moderate demand for oil, we must do all we can to increase supply,” Hess said. “It serves nobody’s purpose for our political leadership to vilify oil producers…. Our country needs to do everything it can to encourage more drilling to strengthen our energy security, including proper regulatory oversight to ensure protection of the environment.” A US energy policy also needs to emphasize natural gas for electricity generation, invest in research for new forms of energy, and set realistic targets for reductions in carbon emissions, Hess said.
BP is enhancing its standards for blowout preventer testing, cementing, well-integrity testing, rig audits, and other well operations, he said. BP is working with industry groups to determine if spill prevention standards can be enhanced industry-wide. “In 10 years’ time, I would expect that there will be a new generation of blowout preventers that represent a major advance on the ones we use today,” Dudley said. BP implemented new standards for its cementing-services oversight including an approval process and stringent contractor lab-quality audits, he said. Regarding its containment efforts, BP is building a next-generation capping stack based on what was learned from the one that shut in the Macondo
Oil & Gas Journal | Mar. 14, 2011
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GENERAL INTEREST well, he said. BP also continues to enhance the real-time ranging technology developed during the drilling of the Macondo relief well. “This cuts the time needed for logging from about 2 days to about 6 hr because the drill bit doesn’t have to be removed,” Dudley said. A ranging tool was field tested on a land rig in Wyoming before using it in the gulf, and more work is needed to improve the tool’s mechanical reliability for future wells, he said. BP also is reviewing the physical cleanup efforts to see what technology needs additional development. One innovation developed during the Macondo spill response was equipment called the sand shark that lifts and sifts beach sand to remove oil.
Views differ over ‘systemic’ problem Differing perspectives on allegations about “systemic” safety problems in offshore oil and gas work emerged during a session panel session on deepwater operations at CERAWeek. William Reilly, co-chairman of the US National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, defended the characterization, which appeared in the commission’s report to President Barack Obama in January an drew criticism from industry groups. The Apr. 20, 2010, accident, which killed 11 workers, showed the industry lacked the ability to contain a deepwater spill, had provided assurance to the contrary in “pro forma response plans,” and hadn’t modernized spill-cleanup equipment, Reilly said. And the commission report found lapses not only by BP, the well operator, but also by Halliburton, which performed the cement job, and Transocean, which owned the rig. “There’s plenty of evidence that it was a systemic problem,” said Reilly, a former administrator of the US Environmental Protection Agency who said he has investments in and sits on the boards of oil and gas companies. Ali Moshiri, president of Chevron Africa & Latin America E&P Co., said the Gulf of Mexico problem “was not a systematic problem. It was an accident that never should have happened.” Reilly applauded the industry’s rapid development of spill-containment capability through the Marine Well Containment Co. and Helix Well Containment Group and said, “Major obstacles to renewing drilling have been removed.” Alluding to a strong message in the commission report, he said, “A renewed culture of safety does seem to be emerging.” Reilly also acknowledged the need for oil and gas from deep water but warned of the consequent “migration toward risk.” Of the need for development of challenging resources, Moshiri said, “We have to be in the deep water because the
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era of easy oil is over, and demand continues to grow.” The Chevron executive said companies apply the best safety and technical standards they can. “Safety and environmental protection is not a cost,” he said. “It’s part of the value that you create.”
Unconventional gas Rapid growth in gas supply from shales and other unconventional reservoirs inverts expectations for North American petrochemicals and underscores the importance of feedstock flexibility in an integrated business strategy, says the leader a major US petrochemical manufacturer. The brightened business outlook shows the importance of integrating petrochemicals not only with refining but also with upstream operations, according to Stephen Pryor, president of ExxonMobil Chemical Co. and vice-president of ExxonMobil Corp. A 20% surge in gas supply from unconventional resources during the past 5 years has boosted ethane production by 25% and lowered the cost of an important feedstock, Pryor told CERAWeek delegates. “We see ethane reemerging as an advantage feedstock in North America, reflecting the growing production of unconventional natural gas and the increasing importance of gas in the world energy mix,” he said. In the US last year, the growing supply of relatively lowcost ethane strengthened margins for ethylene and derivatives, lightened the feed slate, and increased US exports. “The current strength of the US petrochemical market contrasts with conventional wisdom of just a few years ago when it was believed that US petrochemical production would decline, feed slates would get heavier, and the US by 2010 would flip into a net import position,” Pryor said. “Actually, exports grew by about 28% last year.”
Capacity gains? The ExxonMobil Chemical chief doubts that the improved outlook for North American petrochemicals will lead to an early surge in grassroots construction of ethane crackers. At least in the near term, he said, capacity growth will be incremental, resulting from debottlenecking of existing light-feed capacity and limited conversion of heavy-feed crackers. Capacity investment will depend on the pace and pattern of North American ethane supply growth, which in turn will depend on the location and rate of unconventional gas development, liquids content across geologic plays, and construction of equipment able to strip, transport, and store NGLs. “Just as in refining, incremental investment in feed flexibility and capacity creep are the most efficient ways to meeting growing demand in a mature market like North America, major investments at full grassroots costs would be subject to significant risks relative to long-term oil and gas
Oil & Gas Journal | Mar. 14, 2011
GENERAL INTEREST prices, export economics, and gas developments around the world that could provide feedstocks for competitors overseas,” Pryor said.
Integration strategy Feedstock flexibility is central to what Pryor described as the “site-wide optimization” ExxonMobil Chemical applies in its integration strategy. It involves “having the flexibility to process a wide variety of feedstocks and selecting the feed slate that generates the highest value for the integrated complex,” he said. “It entails adjusting the process conditions and product slates in real time so that you extract maximum value from every molecule processed.” Integration is “more than simply collocating refineries with petrochemical plants,” Pryor said. It involves optimization not only of feedstocks but also of products, costs, capital, and people. Pryor said 90% of his company’s petrochemical capacity is integrated with refining or gas processing capacity. The process is continuous and oriented to long-term outcomes. Managing through the “turbulence” of modern markets requires a “disciplined, long-term approach that does not change with short-term changes in commodity prices and profits,” he said.
Plays driving innovation New play types are driving innovations in the oil and gas industry, Jonathan Lewis, Halliburton senior vice-president, drilling and evaluation, said at CERAWeek. Deepwater presalt and shale gas are two examples of the new type of plays that the industry is developing. But with such plays as shale gas, the industry can ill afford the 20-30% nonproductive rig time common in the industry and the industry needs integrated work flows to gain efficiencies in well construction, Lewis said. This cannot be done in laboratories but must be done at the wellsite and operations centers, he added. Operating companies have been driving down costs and gaining efficiencies in tight gas sands and in shale plays. As an example, Charles Stanley, president and chief executive officer of QEP Resources Inc., said QEP in 2010 completed gas wells in the Haynesville shale in 40 days compared with the 66 days/well when the company first started developing the play. For these 12,000-ft wells in the vertical depth and with 5,000-ft horizontal laterals, fraced with 14-16 stages, well completion costs have continued to come down with costs in the later half of 2010 averaging $8.5 million/well compared with $10 million/well in 2009, he said. Another example of efficiency gains is the Pinedale tight gas sands. In 2004, QEP needed 64 days to complete a well compared to 16.8 days/well averaged in 2010, Stanley said. Initially QEP drilled these 14,000-ft wells that contain a
Oil & Gas Journal | Mar. 14, 2011
5,000-ft gross gas column from well sites with single wells. Now QEP has some well pads with up to 50 wells. Costs for completing these wells with about 14 frac stages have dropped to $3.9 million/well from the $8 million/well spent in 2003-04, Stanley said. Stanley attributed much of the gains in efficiency to the people involved, to real-time data that allows speedy improvements in the process, and using the appropriate technology for the economics involved. He noted that the industry has a lot of innovative tools but many are too expensive to deploy.
Libya’s oil facilities bombed as sanctions start to bite regime Eric Watkins Oil Diplomacy Editor
Oil facilities in eastern Libya came under heavy air attack Mar. 9, while the country’s leader Moammar Gadhafi taunted Western powers over their reported plans to establish a no-fly zone over the North African country. “If they take such a decision it will be useful for Libya, because the Libyan people will see the truth, that what they want is to take control of Libya and to steal their oil,” said Gadhafi in an interview by Turkish television channel TRT news. “Then the Libyan people will take up arms against them,” said Gaddafi, who added that the rebels wanted to pave the way for a new colonial era that would allow the US, UK, and France to divide up the country and control its oil wealth. Gadhafi’s defiance toward the Western powers coincided with reports that forces loyal to his rule struck an oil pipeline and oil storage facility as they pounded rebels with artillery and gunfire in at least two major cities. An explosion with a giant yellow fireball rose from the area of the Sidr oil facility, 580 km east of Tripoli, while a rebel spokesman said government air strikes and artillery fire hit an oil storage depot and a pipeline supplying Sidr from oil fields in the desert. For the past week, government forces and rebels have been battling around several key oil ports east—Brega, Ras Lanouf, and Sidr—which together handle 715,000 b/d. A fourth eastern port, Marsa al-Harigah, handled another 220,000 b/d.
Facility damage imminent Oil analyst Samuel Cizsuk of London-based IHS Global Insight said, “It was only a question of time before the escalat-
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WATCHING THE WORLD ERIC
WATKINS
Oil Diplomacy Editor | Blog at www.ogj.com
Huhne’s energy plan Britain should reduce its reliance on oil and move towards renewable energy. That’s the view of Chris Huhne, Britain’s minister of energy and climate change. “I asked economists at [the Department of Energy and Climate Change] to look at how a 1970s style oil price shock would play out today,” Huhne said. “They found that if the oil price doubled, as from $80[/bbl] last year to $160[/bbl] this year, it could lead to a cumulative loss of GDP of around £45 billion over 2 years,” he said. “This is not just far-off speculation,” he claimed, adding, “It is a threat here and now. And the faster we move to a low-carbon economy, the more secure and stable our economy will be.”
Demand not considered Huhne spoke as though high oil prices are a foregone conclusion, having nothing to do with demand. Yet, in his speech, Huhne drew attention to a key fact about demand in Britain. “We have the oldest and leastefficient housing stock in Europe,” Huhne noted. “We use more energy heating our homes than Sweden, which is nearly 5° colder on average.” “Our homes may be our castles, but they shouldn’t cost a king’s ransom to run,” he said, in a neat rhetorical touch. “Across the country, boilers are firing up earlier than they need to, burning more gas than they have to, producing more emissions than they
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should do, and all because our homes leak heat and waste carbon.” He said, “Our housing stock is costing us the earth,” apparently without thinking that such demand boosts prices. Too green behind the ears, perhaps, Huhne says Her Majesty’s government is now developing policies to make the country’s housing more energy efficient.
Nothing up front? “Householders,” Huhne claimed, “will pay nothing up front.” He said, “Businesses will do that for them, getting their money back from the savings on energy bills not just from the present occupier but from the next tenant or owner as well.” He gushed, “It is the most comprehensive energy saving plan in the world,” adding, “There has never been anything quite like it.” Indeed. Yet something does not quite add up in all of this, a point registered by Alistair Lowe of Lloyds Banking Group. “The high oil price, whilst having downsides, should not mean the focus on energy needs to shift exclusively to greener alternatives,” said Lowe. “One should not forget that prices of crude in excess of $100/bbl create a cash cow, and cannot be replaced by manufacturing economics. Huhne’s plan should look to the dwindling North Sea and encourage reinvestment.” Boosting supply! Now that sounds like a plan!
ing violence would damage oil facilities.” According to Cizuk, “Libya has been discounted from the global markets.” In spite of the turmoil in Libya and the evacuation of many expatriate workers, Eni SPA has continued to work with Libya’s National Oil Co. to produce oil and gas, although at considerably reduced levels, according to the company’s Chief Executive Officer Paolo Scaroni. Eni is producing about 100,000 boe/d compared with more than 270,000 b/d before the fighting erupted last month, with natural gas from the Wafa field representing more than 50% of the output. “It is for the Libyan people. My view is that if we can produce gas for the domestic electricity market, this is positive for everyone,” Scaroni told the Financial Times. “If the international community tells us not to produce in Libya, then we won’t produce.” Scaroni also told the paper that he was aware of at least one shipment of oil by the state-owned NOC that had been produced by Eni. “We have a contractual obligation to NOC,” he said. Asked whether the fields were under government or rebel control, he said they were deep in the desert and “under nobody’s control.” US President Barack Obama’s most senior advisers were reported to be meeting today to outline what steps are realistic and possible to pressure the Libyan leader into ending the violence and surrendering power. While Britain and France are pushing for the United Nations to create a no-fly zone over Libya, such a move is considered unlikely to win the backing of veto-wielding Security Council members Russia and China. US Sec. of State Hillary Clinton underlined Washington’s belief that any decision to impose a no-fly zone over Libya is a matter for the UN and should not be a US-led initiative. “We want to see the international community support it (a no-fly zone),”
Oil & Gas Journal | Mar. 14, 2011
GENERAL INTEREST she told the UK’s Sky News. “I think it’s very important that this not be a US-led effort,” she said.
Imposing sactions Still, other efforts do seem to be taking hold against the Libyan regime, with the country’s central bank governor Farhat Bengdara trying to intercede with international financial institutions to soften the effect of any freeze of Libyan assets. Behgdara said he traveled to Istanbul to contact the European Union, IMF, World Bank, and US Treasury and do his best to stop the sanctions that would freeze the central bank’s money, adding that Libya’s revenues have fallen dramatically because of the country’s inability to export oil. Beghdara’s actions confirmed earlier reports that said Libya’s oil trade has been paralyzed as banks decline to clear payments in dollars due to US sanctions. “Banks don’t want to finance the system in Libya, so for
the moment no one is getting money for oil. There are big problems for payments,” said a senior trader with a European oil company. Sources at or close to major European buyers of Libyan crude, including Eni and Saras, told Reuters news agency that the decision by banks to stop export financing of Libyan crude had virtually brought all transactions to a halt. “It’s not a matter of choice, there is an embargo on US dollars coming in and out of Libya,” said a trader with one of the firms, referring to banks’ resistance to clear payments in the US currency. “All US dollar transactions are being blocked,” the trader said, adding it was not clear at this stage if payments were possible in other currencies. Western countries, the EU, and the UN began imposing sanctions on Libya and freezing government assets in response to forces loyal to Gadhafi firing on protesters.
Release of crude from SPR is an option, White House says Nick Snow Washington Editor
The White House confirmed that it is considering the release of crude oil stored in the US Strategic Petroleum Reserve. “But there are a number of factors that go into it, and it is not price-based alone,” Presidential Press Sec. Jay Carney said on Mar. 7. “We’re very cognizant of the fact that Americans are experiencing a sharp rise in prices at the gas pump, and that affects them and their family budgets. And we are monitoring that very closely,” Carney said during the regular daily press briefing. “Meanwhile, we are in discussions with oilproducing countries, as well as the [International Energy Agency], about the various options that are available in the global system to deal with a major disruption, should that occur.” His statement followed White House Chief of Staff Bill Daley’s response on Mar. 6, as he appeared on NBC’s Meet the Press, that “we’re looking at the options.” Daley said, “It is something that only has been done on very rare occasions. There’s a bunch of factors that have to be looked at, and it’s not just the price…. I think there’s no one who doubts that the uncertainty in the Middle East right now has caused this tremendous increase in the last couple of weeks.” The reserve was established in 1975 following the Arab oil embargo and historically has been used only for supply
Oil & Gas Journal | Mar. 14, 2011
interruptions. It was tapped most recently after Hurricane Katrina severely damaged crude oil import infrastructure along the Gulf Coast in 2005. Congressional Democrats have urged its use for the past week as global crude prices have risen in response to political unrest in the Middle East, particularly in Libya where fighting has reached its oil export terminals. “There is reason to be concerned that the situation in Libya and throughout the region could become worse before it improves,” Senate Energy and Natural Resources Committee Chairman Jeff Bingaman (D-NM) said on Mar. 3. “I don’t know that it’s useful to try to predict the most likely outcome, but the reality is that many of the potential scenarios are not good for the stability of world oil flows.” Tapping the SPR would “send a strong signal to oil markets that the US would not allow a physical oil shortage to develop,” Bingaman said. Republicans have responded that encouraging more US crude oil development would be more effective. US House Energy and Natural Resources Committee Chairman Doc Hastings (R-Wash.) announced on Mar. 7 that the committee would hold hearings on Mar. 17 and Mar. 31 to examine the impacts of rising gasoline prices. “Americans know what $4/gal gasoline feels like, and they don’t want to go back to those days. They remember how it strained their monthly budget, increased costs for all types of goods, and forced tough trade-offs on where and how to spend money,” he said. “A return of that scenario would cost jobs and destroy any hope of economic recovery.”
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WATCHING GOVERNMENT NICK
SNOW
Washington Editor | Blog at www.ogj.com
Bills aim to halt EPA GHG regulation under CAA Nick Snow
Paying for hazardous duty The US Bureau of Offshore Energy Management, Regulation, and Enforcement may be considering hazardous duty pay for its offshore oil and gas inspectors in some cases. “Petroleum engineers often operate in environments which would warrant hazardous duty pay,” observed US Department of the Interior’s acting Insp. Gen. Mary L. Kendall during a Mar. 1 House Interior Appropriations Subcommittee hearing on DOI’s management and operations challenges. The higher salaries could help the US Bureau of Land Management, as well as BOEMRE, compete more effectively with the oil and gas industry for qualified employees, “and it’s beginning to be considered,” she said. The idea was one of 60 suggestions Kendall’s office asked BOEMRE officials to consider in a December report, she said. “I’m not certain they like the idea, but they are evaluating it. They have mentioned that their inspectors often face hazardous conditions working offshore,” she told OGJ. The concept is consistent with what US Interior Sec. Ken Salazar and BOEMRE Director Michael R. Bromwich have been saying about DOI’s need to recruit and retain skilled inspectors. Both have described administrative measures to improve the federal government’s management of its offshore resources, ranging from a major restructuring of the former US Minerals Management Service to eliminating potential conflicts of interest to Bromwich’s recent re-
26
cruitment tour of several leading US universities’ petroleum engineering departments.
Necessary ingredient Salazar also has reminded federal lawmakers—as he has testified about DOI’s Fiscal 2012 budget request— that BOEMRE needs to have enough money to complete its overhaul and start doing its job properly. That could be a hard case to make since several newly elected members of Congress apparently came to Washington believing that government employees overall earn good salaries and receive excellent medical and retirement benefits. Salazar and other DOI officials have a readily available response. They simply mention the Macondo well accident, which killed 11 people, and the resulting 5 million bbl of oil that spilled into the gulf. Investigations revealed the need for stronger regulations and enforcement, and that takes money, they maintain. “The budget makes investments to increase capacity for leasing and environmental review, safety and environmental enforcement, and oil spill research,” Salazar said. “This request will enable [DOI] to hire over 100 inspectors, engineers, and other safety and enforcement staff by the end of 2012.” Offering hazardous duty pay to offshore inspectors is only one of many actions BOEMRE is considering, Kendall told OGJ. “They’re already hard at work in several areas,” she said.
Washington Editor
Republican congressional energy leaders introduced bills aimed at stopping the US Environmental Protection Agency’s implementation of greenhouse gas (GHG) regulations under the Clean Air Act. House Energy and Commerce Committee Chairman Fred Upton (Mich.) and Senate Environment and Public Works Committee Ranking Minority Member James M. Inhofe (Okla.) each said his bill was designed to prevent new energy taxes. “Whether at the pump or on their monthly utility bills, American families, farmers, and employers feel the pinch when energy prices go up,” Upton said. “The very last thing the federal government should do is make matters worse by intentionally driving up the cost of energy. Yet that is exactly what’s in store if EPA moves forward with its plans to regulate and penalize carbon emissions under the Clean Air Act.” Inhofe said his bill differs from Sen. John D. Rockefeller’s (D-W.Va.) to delay EPA’s implementation by stopping it completely. “A 2-year delay won’t help our economy grow or help those searching for work,” he declared. “It does nothing to alleviate the uncertainty plaguing businesses all across America. Simply put, EPA’s cap-andtrade regime is bad policy that must be stopped.” EPA began to develop regulations to control GHG emissions under CAA after the US Supreme Court decided in 2007 that the agency had the authority to do so in response to appeals of a Massachusetts lawsuit. The Obama administration and congressional
Oil & Gas Journal | Mar. 14, 2011
GENERAL INTEREST Democrats tried to pressure Congress to act on the matter instead in 2009. The House narrowly passed a global climate change bill that would have established a carbon capand-trade program, but the Senate refused to take it up. EPA moved through the rulemaking process and began to implement its regulations in January. Inhofe said his bill takes this GHG regulatory power from unelected bureaucrats and returns it to Congress where it belongs. His bill has 42 GOP Senate cosponsors. Upton’s has 6 Republicans and 3 Democrats—Reps. Dan Boren (Okla.), Nick J. Rahall (W.Va.), and Collin Peterson (Minn.)—as cosponsors. In response to the bills’ introductions, the American Petroleum Institute said both would stop unelected federal officials from regulating carbon dioxide under CAA without affecting the law’s continuing success. “President Obama’s recent executive order called for a review of regulations that harm job creation,” API Executive Vice-Pres. Marty Durbin said. “EPA’s regulation of GHGs under the CAA is potentially one of the worst offenders and should be at the top of the list.”
GAO places high-risk label on DOI’s oil, gas programs Nick Snow Washington Editor
Problems in the US Department of the Interior’s oil and gas programs are so extensive that the Government Accountability Office has designated their management a high-risk issue, an official of the congressional watchdog service told the US House Interior Appropriations Subcommittee. The primary problems involve collecting revenues, recruiting and managing qualified personnel, recent reorganization of the former US Minerals Management Service, and balancing timely and efficient oil and gas development with environmental stewardship, noted Frank Rusco, a GAO natural resources and environment specialist on energy and science issues who testified at the subcommittee’s hearing on DOI management challenges. DOI’s management of federal resources has been the subject of a large body of GAO’s work and an area where it has found numerous weaknesses and challenges, he said. DOI has taken steps to address material weaknesses, Rusco continued. “In recent years, we’ve seen a kind of sea change on how our oil and gas reports are received and agencies’ willingness
Oil & Gas Journal | Mar. 14, 2011
to listen,” he told the subcommittee. “Five years ago, most of them were automatically challenged. In the last 3 years, most of our recommendations have been endorsed, and we are in the process of closing out many of them. That said, [DOI’s] oil and gas agencies still face significant management challenges.” The reorganization of MMS that US Interior Sec. Ken Salazar launched following the Macondo deepwater well accident in the Gulf of Mexico may eventually lead to more efficient operations, according to Rusco. It also will require such concentrated efforts by leaders and employees that problems could potentially increase in the short term, he said. The reorganization does not address DOI’s onshore oil and gas management through the US Bureau of Land Management, where Rusco said GAO has found several other management issues.
Information systems A second witness, Acting DOI Insp. Gen. Mary L. Kendall, agreed the department’s two oil and gas programs face serious challenges, including US Outer Continental Shelf energy oversight, revenue collection, financial management, and information technology. “The work we did following the Deepwater Horizon accident showed that the industry already has several systems to share information [that DOI] could adopt,” she said. Revenue collections haven’t responded to changing industry practices, Rusco said, citing royalty relief as an example where revenue percentages could have increased automatically as conditions improved. DOI is looking at adopting such an approach, he said. “The industry can account for very small amounts it is producing. So can its customers,” the GAO official said. “When they disagree, they can compare data and quickly resolve the issue. There is nothing comparable in the government to provide verification.” Subcommittee Democrats suggested that improving federal oil and gas revenue collection could help balance the federal budget. “If we’re going to balance the budget, this could be a good place to start,” observed James P. Moran (Va.), the subcommittee’s ranking minority member. “Improving revenue collections and encouraging people working at the agencies to be more conscientious is a good idea. But we also need to give them the tools to do this.” Republicans suggested that DOI study methods producing states use to collect oil and gas revenues. “I think Wyoming does a better job of collecting severance taxes and royalties as well as with its leasing terms,” Cynthia M. Lummis (Wyo.) said. Kendall urged BLM to look more closely at its right-of-way policies “which sometimes are little more than giveaways.” Lummis also said environmental groups were routinely protesting onshore federal oil and gas leases and being reimbursed under the Equal Access to Justice Act, effectively billing taxpayers for preventing development of public re-
27
GENERAL INTEREST sources. Rusco responded that a GAO study found challenges came from a wider range of groups, including sporting and recreation organizations, but added that BLM is missing 90% of its deadlines once it favorably resolves protests.
Elevated investment might halve UKCS output decline Continuation of offshore UK investment at the elevated level foreseen this year could cut the rate of production decline on the UK Continental Shelf (UKCS) by half through 2016, an industry group says. The group, Oil & Gas UK, reports in an activity survey published late last month that investment might reach £8 billion this year, up from less than £5 billion in 2009 and $6 billion in 2010. If companies move forward with all the development plans they’re considering, investment would stay at the higher rage for the next 5 years and might lower the production decline rate of the UKCS to 3%/year, Oil & Gas UK says. For the past 10 years, the decline rate has been 6-7%/year. “The investment could also lead to a further 10,00015,000 jobs in the supply chain across the UK,” the group says. Recent UKCS investment has received a lift from approval of new large-field developments west of the Shetland Islands and in the central North Sea and, to a lesser extent, northern North Sea. Last year, investment began in 13 new oil and gas fields and in four major redevelopment projects. Oil & Gas UK notes 67 potential new-field developments representing an estimated 3.1 billion bbl of recoverable oil. The 10 largest of those projects account for more than 60% of the predicted capital expenditure. Four of them are west of Shetland, three are in the central North Sea, and three are in the northern North Sea.
Output down 5% Average UK production last year was 2.3 million boe/d, down 5% from the 2009 level. Plans, including for additional incremental recovery from existing fields, and development of new fields, target reserves of 11.6 billion boe, 1.3 billion boe more than targeted a year earler. Oil & Gas UK says it believes the UKCS still holds 24 billion boe of recoverable oil and gas. In 2010, the group reports, operators drilled 62 exploration and appraisal wells, two thirds of which were exploratory. The total compares with 65 wells last year. Of the 2010 exploration and appraisal wells, about one
28
third were successful, adding 300-400 million boe to reserves. Oil & Gas UK expects operators to drill a similar number of exploratory and appraisal wells this year, with spending in this category exceeding £1.3 billion. Operating costs last year totaled $6.9 billion, up 5% from 2009. Because of production declines, unit operating costs rose by 10% in 2010. Discoveries “were materially smaller than those found in younger oil and gas provinces elsewhere,” Oil & Gas UK says. UKCS operators face decommissioning costs of £29 billion over the next 30 years, 11% higher than last year’s forecast.
EIA: Finding, lifting costs worldwide declined in 2009 Oil and natural gas finding and lifting costs declined in 2009 for a group of US-based producers, according to a recent report from the US Energy Information Administration. EIA’s report, Performance Profiles of Major Energy Producers 2009, covers 30 oil and gas producers and refiners and finds that the companies’ collective net income declined to the lowest level since 2002. Also, the report finds that capital expenditures in 2009 fell sharply, but upstream capital outlays remained at historically high levels in spite of the decline. Average worldwide finding costs for the sample of companies decreased by $5.79/boe to $18.31/boe of reserves added in 2007-09 compared with the 2006-08 period.
Finding, lifting costs Finding costs declined in all regions except the former Soviet Union, Africa, and the Middle East during 2007-09. Finding costs climbed 32% to $13.92/boe in the FSU, while they increased by 6.7% in Africa to $35.01/boe. Finding costs climbed in the Middle East to $6.99/boe from $5.17/boe. The US offshore, which had the highest finding costs in 2006-08, recorded the largest regional decline in 2007-09, dropping by $23.02/boe to $41.51/boe. Onshore US finding costs were $18.65/boe, down 24% from the previous period. Finding costs in Europe, the region outside the US with the highest costs during 2006-08, also fell sharply in the most recent period to $42.32/boe, down almost 32%. Finding costs in Canada registered a 57% decline to $12.07/boe likely due in part to the inclusion of oil sands in the calculation in 2009, the report said. Worldwide lifting costs for the sampled companies fell by $1.19/boe in 2009 to average $11.51/boe, reversing a nearly
Oil & Gas Journal | Mar. 14, 2011
GENERAL INTEREST decade-long upward trend. Total lifting costs fell in each region except Canada, where they climbed $2.49/boe, again probably reflecting the inclusion of oil sands. EIA said production taxes were the major contributor to the decline in total lifting costs, sliding 84¢/boe in 2009 and accounting for 70% of the decline, as such taxes typically rise and fall along with the prices of oil and gas. Both oil and gas prices fell in 2009. Direct lifting costs fell 14% in the US but increased in every other region during 2007-09, when finding and lifting costs combined fell by almost $5/boe to $29.81/boe.
ducing fault block on the Hilltop structure in Robertson and Leon counties. It confirms the presence of high-quality reservoirs in the downthrown fault block. Gastar, with 67% working interest before payout, plans to complete the well in two initial zones and, depending upon the availability of frac stimulation services, expects the first of these initial completions to be on line by the end of April. Projected completed well cost is $11 million. The company plans to drill the Belin-3 well while continuing to focus on exploitation of the shallower Eaglebine and Glen Rose oil formations on this same acreage.
Cash flow, capital spending
North Breitling Oil & Gas Corp., Irving, Tex., has spudded a development well to Holmes sand and Mississippian Chappel dolomite in Hardeman County, Tex. The company purchased three 2D seismic lines to verify the structural and stratigraphic position of the Holmes sand at the Breitling-Turner-1 drillsite. The well is on a 640-acre closure. Projected depth is 7,600 ft. Breitling said the Holmes is a high-quality sand reservoir encased in the Barnett shale. At least two proved undeveloped locations exist.
Cash flow from operations decreased 41% to $131 billion in 2009 from a year earlier, led by a 66% decline in net income. Meanwhile, capital expenditures for exploration, development, property acquisition, and production decreased 24% to $166 billion in 2009 but remained higher than every year prior to 2006, EIA said. US refining and marketing capital spending declined but remained high in 2009 as capacity increased. US refining and marketing capital expenditures among the surveyed companies decreased 16% from 2008 to $22 billion in 2009, while such expenditures outside the US increased by 2%. Despite the net income loss reported in US refining and marketing, capital expenditures in 2009 remained higher than all but 3 prior years in the survey, according to EIA.
Analyst’s take The calculation that EIA uses is to convert natural gas to equivalent barrels of oil is 0.178 bbl/1 Mcf. Deutsche Bank analyst Adam Sieminski commented in a research report that because natural gas reserve additions were strong in 2009, and natural gas finding costs were low relative to oil, he suspects that the 2009 worldwide finding cost figure of $18.31/boe is skewed to the downside. “Drilling costs are rising again, and correcting for this and the natural gas skew, we would not be surprised to discover that oil finding cost are closer to $25/boe going into 2011-12 and that the current “cost driven” price range for oil is closer to $75-100/bbl,” Sieminski said.
EXPLOR ATION / DEVELOPMENT BRIEFS
Texas East In Gastar Exploration Ltd. said the Belin-2 well in East Texas cut 130 net ft of pay in five sand intervals in Jurassic Lower Bossier. The well went to a total depth of 19,650 ft in a nonpro-
Oil & Gas Journal | Mar. 14, 2011
Utah Newfield Exploration Co. and Harvest Natural Resources Inc. are drilling the last well in the current phase of the Monument Butte field extension project in Utah’s Uinta basin. Thirteen Newfield-operated wells have produced 350,000 bbl of oil and 1.3 bcf of gas since the program began in December 2009, said Harvest. The 13 wells are making a combined 500 b/d of oil and 8 MMcfd of gas. Fourteen wells, including one operated by Harvest, are on production. The program’s most recent well, Meagher 1020-4-2, has made 8,000 bbl of oil and 8 MMcf of gas since going on production in late December 2010. The Newfieldoperated Stewart 1A-29-4-2 well is drilling. Harvest has 40% average working interest in the 13 Newfield-operated wells. The Harvest-operated K Moon 2-13-4-3 well was spud in November 2009 and began production on Feb. 16, 2011. The well has exceeded initial production expectations by making more than 1,500 gross bbl of oil flowing in the first 12 days. A pumping unit will be installed in the next few weeks. The Moon well, in which Harvest’s interest is 60%, is a large step toward confirming the prospectivity of the Harvest-operated acreage in the field extension project. Harvest has identified and prioritized 50 operated locations that will represent the next phase of extension drilling when it is initiated.
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EQUIPMENT | SOFTWARE | LITERATURE EXPANDED ITEMS FOR ELECTRIC WIRELINE IN COILED TUBING Now available is an expanded range of equipment for electric wireline in coiled tubing. The company reports that four new items have been developed to facilitate logging and perforating on coil: • Eight-way collector bulkhead, (10,000 psi)—utilizes a bulkhead with seven-conductor feed-through and boot assembly. • Electrical release for the 27∕8 in. seven conductor cable head—helps ensure reliable and safe termination downhole. • 13∕4 in. single conductor cable head—with electrical and mechanical release options for smaller tubing sizes and restrictions. • A dual polarity electrical release for multiple shot perforating operations that require positive and negative current for firing. The development of two new electrical releases extends the tool’s appli-
cation in perforating where use of a mechanical shear release poses the risk of release upon detonation, the company points out. To be safe, an electrical release should be used when perforating to achieve a controlled release, something that is not possible with a safety joint, the firm says. All components of this wireline CT equipment range, including the four new elements, are compatible with most types of electric wireline in use today. Source: AnTech Ltd., Unit 7, Newbery Centre, Airport Business Park, Exeter, UK EX5 2 UL.
NEW ATOMIC CLOCK AIDS EXPLORATION A new chip scale atomic clock (CSAC) is designed to meet the needs of marinebased oil exploration. The CSAC combines the accuracy and stability of atomic clock technology along with size, weight, and power benefits that help suit it for small-form-factor
uses requiring long battery life. The company notes its use in marine geophysical sensors: When ship crews are seeking places to drill, they send out acoustic pulses that hit and penetrate the ocean floor. Sensors time-stamp when the pulse is received, and postprocessing of sensor data shows likely places to drill. Today, the firm says, most marine sensors have been using ovencontrolled crystal oscillators (OCXOs) as clocks. OCXOs have limited battery life, are subjected to extreme cold water temperatures that can erode performance, and age at a rate that produces an error that varies as a square of time underwater, the company says. This firm’s SA.45s CSAC offers superior battery life, a superior temperature coefficient, and aging advantages that will prolong the life of the sensors and enhance overall monitoring activities. Source: Symmetricom Inc., 2300 Orchard Parkway, San Jose, CA 95131.
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COMPANY NAME
PAGE
Baker Hughes
17
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Champion Technologies
2
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CIT
13
www.cit.com
Deep Offshore Technology
30
www.deepoffshoretechnology.com
Kronos
4
www.kronos.com
Offshore Asia
15
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Oil Sands Heavy Oil Technologies
34
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Petroci
11
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Scott Health & Safety
7
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Presented By:
Supported By:
SPE
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www.spe.org
Deep Offshore Technology ®
30
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This index is provided as a service. The publisher does not assume any liability for errors or omission.
Oil & Gas Journal | Mar. 14, 2011
STATISTICS IMPORTS OF CRUDE AND PRODUCTS — Districts 1-4 — — District 5 — ———— Total US ———— 2-25 2-18 2-25 2-18 2-25 2-18 *2-26 2011 2011 2011 2011 2011 2011 2010 ––––––––––––––––––––––––— 1,000 b/d ––––––––––––––––––––––––— Total motor gasoline ............. Mo. gas. blending comp. ..... Distillate............................... Residual .............................. Jet fuel-kerosine .................. Propane-propylene .............. Other ...................................
773 664 171 268 47 157 8
793 683 152 141 21 86 114
35 35 0 25 4 (85) 115
14 14 19 39 3 (28) 183
808 699 171 293 51 72 123
807 697 171 180 24 58 297
775 586 354 439 61 221 280
Total products ......................
2,088
1,990
129
244
2,217
2,234
2,716
Total crude ...........................
6,939
6,865
1,071
1,240
8,010
8,105
9,236
Total imports ........................
9,027
8,855
1,200
1,484
10,227
10,339
11,952
*Revised. Source: US Energy Information Administration Data available in OGJ Online Research Center.
PURVIN & GERTZ LNG NETBACKS—MAR. 4, 2011 –––––––––––––––––––––––––––– Liquefaction plant –––––––––––––––––––––––––––––––– Algeria Malaysia Nigeria Austr. NW Shelf Qatar Trinidad –––––––––––––––––––––––––––––––– $/MMbtu ––––––––––––––––––––––––––––––––––––
Receiving terminal Barcelona Everett Isle of Grain Lake Charles Sodegaura Zeebrugge
8.46 3.86 7.47 1.64 6.40 7.93
6.41 1.41 4.74 –0.54 8.58 5.49
7.45 3.37 6.55 1.37 6.61 7.29
6.30 1.49 4.64 –0.33 8.22 5.42
7.12 2.04 5.42 –0.06 7.78 6.25
7.36 4.21 6.60 2.40 5.52 7.35
Additional analysis of market trends is available through OGJ Online, Oil & Gas Journal’s electronic information source, at http://www.ogj.com.
OGJ CRACK SPREAD *3-4-11 *3-5-10 Change Change, ———–—$/bbl ——–—— % SPOT PRICES Product value Brent crude Crack spread
122.01 113.77 8.24
FUTURES MARKET PRICES One month Product value 125.56 Light sweet crude 101.03 Crack spread 24.53 Six month Product value 126.61 Light sweet crude 104.11 Crack spread 22.49
88.03 78.05 9.99
33.97 35.72 -1.75
38.6 45.8 -17.5
90.71
34.85
38.4
80.19 10.52
20.84 14.01
26.0 133.2
91.31
35.29
38.7
82.01 9.30
22.10 13.20
27.0 141.9
*Average for week ending. Source: Oil & Gas Journal Data available in OGJ Online Research Center.
Definitions, see OGJ Apr. 9, 2007, p. 57. Source: Purvin & Gertz Inc. Data available in OGJ Online Research Center.
CRUDE AND PRODUCT STOCKS —–– Motor gasoline —–– Blending Jet fuel, ————— Fuel oils ————— PropaneCrude oil Total comp.1 kerosine Distillate Residual propylene ———————————————————————————— 1,000 bbl —————————————————————————
District PADD 1 ..................................... PADD 2 ..................................... PADD 3 ..................................... PADD 4 ..................................... PADD 5 .....................................
12,201 103,045 165,937 16,113 49,079
63,860 54,844 76,707 7,065 32,232
51,228 27,375 52,639 2,316 28,241
10,489 7,228 11,609 718 10,776
58,000 33,067 51,481 3,352 13,285
13,212 1,485 17,619 221 4,537
2,893 9,634 15,042 1 710 --
Feb. 25, 2011 ........................... Feb. 18, 2011............................ Feb. 26, 20102 ...........................
346,375 346,740 341,571
234,708 238,297 231,943
161,799 165,028 147,992
40,820 40,474 43,279
159,185 159,937 151,821
37,074 37,403 40,004
28,279 29,481 26,831
1
Includes PADD 5. 2Revised. Source: US Energy Information Administration Data available in OGJ Online Research Center.
REFINERY REPORT—FEB. 25, 2011 REFINERY –––––– OPERATIONS –––––– Gross Crude oil inputs inputs ––––––– 1,000 b/d ––––––––
District
–––––––––––––––––––––––––––– REFINERY OUTPUT ––––––––––––––––––––––––––– Total motor Jet fuel, ––––––– Fuel oils –––––––– Propanegasoline kerosine Distillate Residual propylene –––––––––––––––––––––––––––––––– 1,000 b/d –––––––––––––––––––––––––––––––
PADD 1 .............................................. PADD 2 .............................................. PADD 3 .............................................. PADD 4 .............................................. PADD 5 ..............................................
912 3,302 6,989 558 2,480
930 3,275 6,770 554 2,269
2,920 2,261 2,049 308 1,565
92 208 607 32 404
322 987 2,084 162 551
45 58 325 9 150
42 248 665 1 57 ––
Feb. 25, 2011 ...................................... Feb. 18, 2011 ...................................... Feb. 26, 20102.....................................
14,241 13,961 14,482
13,798 13,536 14,074
9,103 8,962 8,831
1,343 1,371 1,271
4,106 3,979 3,812
587 560 572
1,012 998 1,063
17,594 Operable capacity 1
80.9% utilization rate
2
Includes PADD 5. Revised. Source: US Energy Information Administration Data available in OGJ Online Research Center.
Oil & Gas Journal | Mar. 14, 2011
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STATISTICS OGJ GASOLINE PRICES
BAKER HUGHES RIG COUNT
Price Pump Pump ex tax price* price 3-2-11 3-2-11 3-3-10 ————— ¢/gal ————— (Approx. prices for self-service unleaded gasoline) Atlanta .......................... 303.0 342.2 Baltimore ...................... 298.6 340.5 Boston ........................... 299.5 341.4 Buffalo .......................... 289.3 352.5 Miami ............................ 302.0 354.4 Newark .......................... 300.3 333.2 New York........................ 288.6 351.8 Norfolk........................... 292.8 330.7 Philadelphia .................. 290.9 341.6 Pittsburgh ..................... 291.9 342.6 Wash., DC...................... 306.5 348.4 PAD I avg .................. 296.7 343.6
260.8 266.2 262.8 277.3 277.9 260.1 276.0 257.3 271.1 270.0 272.0 268.3
Chicago ......................... Cleveland ...................... Des Moines .................... Detroit ........................... Indianapolis .................. Kansas City ................... Louisville ....................... Memphis ....................... Milwaukee ..................... Minn.-St. Paul ............... Oklahoma City ............... Omaha .......................... St. Louis ........................ Tulsa ............................. Wichita .......................... PAD II avg .................
320.7 288.7 298.0 294.2 287.3 290.6 297.4 288.9 287.8 301.1 294.6 295.7 290.7 287.3 280.0 293.5
378.7 335.1 338.4 348.4 340.4 326.3 338.3 328.7 339.1 346.7 330.0 342.1 326.4 322.7 323.4 337.6
301.1 271.8 262.8 277.1 272.8 259.1 271.4 261.9 275.4 271.4 254.4 269.8 259.8 246.4 258.4 267.6
Albuquerque .................. Birmingham .................. Dallas-Fort Worth .......... Houston ......................... Little Rock ..................... New Orleans .................. San Antonio ................... PAD III avg ................
287.8 291.2 294.4 290.4 290.1 291.7 290.9 290.9
325.0 330.5 332.8 328.8 330.3 330.1 329.3 329.5
263.8 262.8 262.1 258.8 258.1 260.8 256.8 260.4
Cheyenne....................... Denver ........................... Salt Lake City ................ PAD IV avg ................
282.0 283.9 279.8 281.9
314.4 324.3 322.7 320.5
252.1 271.7 264.4 262.7
Los Angeles ................... Phoenix.......................... Portland ........................ San Diego ...................... San Francisco................ Seattle........................... PAD V avg ................. Week’s avg. .................. Feb. avg. ....................... Jan. avg......................... 2011 to date ................. 2010 to date .................
310.4 305.1 312.4 317.1 325.0 311.9 313.7 296.0 267.0 261.9 268.0 222.7
377.8 342.5 355.8 384.5 392.4 367.8 370.2 341.3 312.3 307.2 313.2 267.5
303.4 273.1 291.8 308.5 313.1 299.5 298.2 270.6 264.7 269.7 –– ––
*
Includes state and federal motor fuel taxes and state sales tax. Local governments may impose additional taxes. Source: Oil & Gas Journal. Data available in OGJ Online Research Center.
REFINED PRODUCT PRICES 2-25-11 ¢/gal
2-25-11 ¢/gal
Spot market product prices Motor gasoline No. 2 Distillate (Conventional-regular) Low sulfur diesel fuel New York Harbor ......... 291.60 New York Harbor ......... Gulf Coast .................. 273.60 Gulf Coast .................. Los Angeles ................ Motor gasoline Kerosine jet fuel (RBOB-regular) New York Harbor ......... 306.10 Gulf Coast ..................
303.70 296.60 306.90 300.60
Propane No. 2 heating oil New York Harbor ......... 294.90 Mt. Belvieu ................. 153.50
OGJ PRODUCTION REPORT
3-4-11
3-5-10
Alabama............................................ Alaska ............................................... Arkansas ........................................... California .......................................... Land................................................ Offshore .......................................... Colorado ............................................ Florida ............................................... Illinois ............................................... Indiana.............................................. Kansas .............................................. Kentucky............................................ Louisiana .......................................... N. Land ........................................... S. Inland waters .............................. S. Land............................................ Offshore .......................................... Maryland ........................................... Michigan ........................................... Mississippi ........................................ Montana ............................................ Nebraska ........................................... New Mexico........................................ New York............................................ North Dakota ..................................... Ohio................................................... Oklahoma .......................................... Pennsylvania ..................................... South Dakota..................................... Texas ................................................. Offshore .......................................... Inland waters .................................. Dist. 1 ............................................. Dist. 2 ............................................. Dist. 3 ............................................. Dist. 4 ............................................. Dist. 5 ............................................. Dist. 6 ............................................. Dist. 7B ........................................... Dist. 7C ........................................... Dist. 8 ............................................. Dist. 8A ........................................... Dist. 9 ............................................. Dist. 10 ........................................... Utah .................................................. West Virginia ..................................... Wyoming............................................ Others—NV-4 ...................................
6 6 34 40 40 0 67 1 0 0 23 5 172 112 21 16 23 0 2 6 8 1 76 0 154 9 163 99 0 733 2 1 77 52 40 37 70 57 4 56 203 30 33 71 31 21 46 4
5 11 42 25 24 1 51 1 2 0 17 8 199 134 13 15 37 0 0 12 8 2 57 1 86 7 112 68 0 588 4 0 27 22 37 58 78 77 8 55 117 28 35 42 25 24 37 8
Total US ........................................ Total Canada ................................
1,707 625
1,396 543
Grand total ................................... US Oil rigs ......................................... US Gas rigs ....................................... Total US offshore ............................... Total US cum. avg. YTD .....................
2,332 801 899 25 1,714
1,939 456 926 44 1,305
1 2 3-4-11 3-5-10 –—— 1,000 b/d —–—
(Crude oil and lease condensate) Alabama ................................. 17 Alaska .................................... 633 California ............................... 615 Colorado ................................. 72 Florida .................................... 4 Illinois .................................... 26 Kansas ................................... 109 Louisiana ............................... 1,544 Michigan ................................ 13 Mississippi ............................. 60 Montana ................................. 68 New Mexico ............................. 172 North Dakota .......................... 349 Oklahoma ............................... 187 Texas ...................................... 1,457 Utah ....................................... 61 Wyoming ................................. 138 All others ................................ 69 Total .................................. 5,594 1 OGJ estimate. 2Revised. Source: Oil & Gas Journal. Data available in OGJ Online Research Center.
US CRUDE PRICES
*Current major refiner’s posted prices except North Slope lags 2 months. 40° gravity crude unless differing gravity is shown. Source: Oil & Gas Journal.
Data available in OGJ Online Research Center.
WORLD CRUDE PRICES $/bbl1
SMITH RIG COUNT 3-4-11 Percent footage*
0-2,500 2,501-5,000 5,001-7,500 7,501-10,000 10,001-12,500 12,501-15,000 15,001-17,500 17,501-20,000 20,001-over Total
191 60 124 295 394 282 159 145 64 1,714
3.1 50.0 22.5 3.3 8.8 2.4 –– –– –– 6.7
INLAND LAND OFFSHORE
15 1,682 17
3-5-10 Rig Percent count footage* 121 54 125 267 286 211 174 82 48 1,368 15 1,307 46
*Rigs employed under footage contracts. Definitions, see OGJ Sept. 18, 2006, p. 42.
6.6 68.5 24.0 6.7 6.9 1.4 –– –– –– 8.4
2-25-11
United Kingdom-Brent 38° ..................................... Russia-Urals 32° ................................................... Saudi Light 34° ...................................................... Dubai Fateh 32° ..................................................... Algeria Saharan 44°............................................... Nigeria-Bonny Light 37° ........................................ Indonesia-Minas 34°.............................................. Venezuela-Tia Juana Light 31° ............................... Mexico-Isthmus 33° ............................................... OPEC basket........................................................... Total OPEC2 ............................................................ Total non-OPEC2 ..................................................... Total world2 ............................................................ US imports3
Source: Baker Hughes Inc. Data available in OGJ Online Research Center.
Rig count
3-4-11 $/bbl* 87.95 116.50 109.00 117.40 94.42 100.50 96.00 101.00 101.00 94.00 93.00 100.00 91.00
Alaska-North Slope 27° ......................................... South Louisiana Sweet .......................................... California-Midway Sunset 13° .............................. Lost Hills 30° ........................................................ Wyoming Sweet ..................................................... East Texas Sweet ................................................... West Texas Sour 34° .............................................. West Texas Intermediate........................................ Oklahoma Sweet.................................................... Texas Upper Gulf Coast ......................................... Michigan Sour ....................................................... Kansas Common ................................................... North Dakota Sweet ...............................................
Rotary rigs from spudding in to total depth. Definitions, see OGJ Sept. 18, 2006, p. 42.
Proposed depth, ft
17 638 617 69 4 24 114 1,550 18 65 52 165 259 184 1,440 61 139 69 5,485
106.94 104.69 104.55 103.88 108.60 109.60 107.59 99.06 98.95 105.14 104.50 102.12 103.54 97.29 -
-
1
Estimated contract prices. 2Average price (FOB) weighted by estimated export volume. 3Average price (FOB) weighted by estimated import volume. Source: DOE Weekly Petroleum Status Report. Data available in OGJ Online Research Center.
US NATURAL GAS STORAGE1 2-25-11
Producing region ................ Consuming region east ...... Consuming region west ...... Total US ............................. Total US2 ............................
2-18-11
2-25-10
–——––—— bcf —––——– 696 687 584 809 880 872 240 263 298 1,745 1,830 1,754 Change, Dec. 10 Dec. 09 % 3,107
3,130
Change,
% 19.2 –7.2 –19.5 –0.5
–0.7
1
Source: DOE Weekly Petroleum Status Report. Data available in OGJ Online Research Center.
32
Source: Smith International Inc. Data available in OGJ Online Research Center.
Working gas. 2At end of period. Source: Energy Information Administration Data available in OGJ Online Research Center.
Oil & Gas Journal | Mar. 14, 2011
STATISTICS WORLDWIDE CRUDE OIL AND GAS PRODUCTION 12 month average Change vs. Dec. Nov. ––– production ––– –––– previous year ––– 2010 2010 2010 2009 Volume % ––––––––––––––––––– Crude, 1,000 b/d –––––––––––––––––––––––– Argentina ............................ Bolivia................................. Brazil .................................. Canada ............................... Colombia ............................ Ecuador1 ............................. Mexico ................................ Peru ................................... Trinidad .............................. United States ...................... Venezuela1 .......................... Other Latin America ............
520 41 2,180 2,933 781 480 2,574 150 85 5,592 2,200 83
605 44 2,089 2,969 821 470 2,512 150 88 5,595 2,190 82
602 43 2,054 2,748 781 466 2,576 150 98 5,509 2,227 82
599 40 1,950 2,583 670 471 2,602 129 107 5,360 2,163 83
3 3 104 165 111 –5 –26 21 –9 149 63 –1
Dec. Nov. Cum. 2010 2010 2010 –––––––––– Gas, bcf ––––––––––––––
0.5 7.0 5.3 6.4 16.6 –1.1 –1.0 16.4 –8.1 2.8 2.9 –1.6
109.0 41.0 44.0 496.1 30.0 1.0 216.0 31.0 125.0 1,978.0 70.0 5.7
105.0 44.0 42.0 418.1 31.0 1.0 210.0 32.0 120.0 1,907.0 65.0 5.7
1,343.00 486.00 437.50 5,091.00 391.00 12.00 2,557.00 248.50 1,468.17 22,564.00 830.00 65.56
Western Hemisphere ..........
17,619
17,616
17,335
16,756
579
3.5
3,146.8
2,980.8
35,493.73
Austria ................................ Denmark............................. France ................................ Germany ............................. Italy .................................... Netherlands ........................ Norway ............................... Turkey ................................ United Kingdom .................. Other Western Europe .........
18 247 19 51 102 17 1,886 47 1,260 4
18 259 19 49 98 17 1,867 48 1,259 4
18 246 18 51 96 20 1,870 48 1,253 5
18 261 18 55 83 25 2,068 46 1,348 4
–1 –15 –– –4 13 –5 –199 2 –95 1
–3.6 –5.9 –2.1 –7.8 15.7 –21.1 –9.6 4.4 –7.1 28.0
5.0 22.6 2.3 38.6 26.0 400.0 385.0 –– 168.2 2.1
4.9 21.7 2.2 38.1 24.0 320.0 355.4 –– 166.8 1.2
60.63 265.95 24.80 446.79 285.00 2,845.00 3,755.73 –– 2,108.19 13.65
Western Europe .................
3,651
3,638
3,623
3,927
–304
–7.7
1,049.8
934.4
9,805.73
Azerbaijan........................... Croatia ................................ Hungary.............................. Kazakhstan ......................... Romania ............................. Russia ................................ Other FSU........................... Other Eastern Europe ..........
870 13 15 1,650 95 10,240 300 45
1,000 13 15 1,650 95 10,300 400 46
986 13 16 1,593 88 10,200 413 45
1,046 14 14 1,500 90 9,917 433 43
–60 –1 2 93 –2 283 –21 1
–5.7 –6.9 15.9 6.2 –1.9 2.9 –4.8 2.6
60.0 7.0 6.6 120.0 20.0 2,000.0 400.0 21.0
75.0 6.7 6.5 100.0 19.0 1,900.0 450.0 20.8
864.00 72.72 80.69 1,220.00 223.00 22,060.00 4,825.00 237.60
Eastern Europe and FSU .....
13,227
13,519
13,353
13,057
297
2.3
2,634.6
2,578.1
29,583.01
Algeria1 ............................... Angola1 ............................... Cameroon ........................... Congo (former Zaire) ........... Congo (Brazzaville) ............. Egypt .................................. Equatorial Guinea................ Gabon................................. Libya1 ................................. Nigeria1............................... Sudan ................................. Tunisia ................................ Other Africa ........................
1,270 1,620 60 28 280 740 255 250 1,560 2,260 470 65 191
1,270 1,660 60 28 280 740 255 250 1,560 2,180 470 69 191
1,256 1,772 63 28 270 740 255 246 1,550 2,080 475 78 191
1,240 1,789 73 28 240 750 260 229 1,546 1,825 500 81 196
16 –18 –10 –– 30 –10 –5 17 4 255 –25 –3 –5
1.3 –1.0 –13.3 –– 12.5 –1.3 –1.9 7.3 0.3 14.0 –5.0 –4.0 –2.5
250.0 6.5 –– –– –– 120.0 0.1 0.3 46.0 70.0 –– 8.5 9.4
240.0 6.0 –– –– –– 115.0 0.1 0.3 46.0 70.0 –– 8.0 8.7
2,980.00 76.30 –– –– –– 1,404.00 0.72 3.65 552.00 840.00 –– 114.56 109.58
Africa ................................
9,050
9,014
9,004
8,757
246
2.8
510.8
494.0
6,080.81
Bahrain............................... Iran1 ................................... Iraq1 ................................... Kuwait1 2 ............................. Oman ................................. Qatar1 ................................. Saudi Arabia1 2 .................... Syria ................................... United Arab Emirates1 ......... Yemen ................................ Other Middle East ...............
36 3,680 2,410 2,320 885 820 8,600 390 2,320 250 ––
34 3,680 2,350 2,290 881 820 8,500 390 2,290 250 ––
31 3,701 2,364 2,299 864 805 8,329 390 2,306 266 ––
30 3,734 2,399 2,275 814 768 8,183 371 2,271 276 ––
1 –33 –35 24 50 37 146 19 35 –10 ––
4.6 –0.9 –1.5 1.1 6.2 4.8 1.8 5.2 1.5 –3.8 17.4
26.0 415.0 25.0 36.0 90.0 350.0 215.0 18.0 140.0 –– 8.4
25.0 400.0 24.0 33.0 83.0 340.0 200.0 17.0 130.0 –– 9.4
298.28 4,840.00 280.00 418.00 981.00 3,880.00 2,510.00 210.00 1,645.00 –– 120.60
Middle East .......................
21,711
21,485
21,356
21,122
234
1.1
1,323.4
1,261.4
15,182.88
Australia ............................. Brunei ................................ China .................................. India ................................... Indonesia ............................ Japan ................................. Malaysia ............................. New Zealand....................... Pakistan.............................. Papua New Guinea ............. Thailand ............................. Vietnam .............................. Other Asia-Pacific ...............
399 175 4,137 807 915 15 560 52 67 20 222 320 29
414 165 4,274 810 922 15 550 44 66 20 232 320 46
425 160 4,079 745 945 15 572 53 64 22 239 319 46
464 154 3,768 665 953 16 591 51 64 39 240 300 48
–39 6 311 80 –8 –1 –20 3 1 –17 –1 18 –2
–8.3 4.0 8.3 12.1 –0.8 –5.7 –3.3 5.0 1.0 –44.2 –0.2 6.1 –3.2
131.7 40.0 311.6 155.0 238.0 10.5 190.0 12.0 130.4 1.0 88.0 20.0 82.3
133.2 32.0 297.4 150.0 228.0 9.4 180.0 12.0 120.0 0.9 87.0 20.0 79.3
1,596.00 420.00 3,309.30 1,777.48 2,828.00 116.26 2,214.00 146.00 1,496.39 11.70 1,081.00 240.00 952.05
Asia-Pacific .......................
7,718
7,879
7,684
7,351
333
4.5
1,410.5
1,349.2
16,188.18
TOTAL WORLD ....................
72,977
73,151
72,355
70,971
1,384
2.0
10,075.9
9,597.9
112,334.35
OPEC .................................. Offshore Europe ..................
29,540 3,435
29,260 3,419
29,154 3,393
28,665 3,698
489 –305
1.7 –8.2
1,624.5 695.6
1,555.0 639.8
18,863.30 6,980.08
1
OPEC member. 2Kuwait and Saudi Arabia production each include half of Neutral Zone. Totals may not add due to rounding. Source: Oil & Gas Journal. Data available in OGJ Online Research Center.
Oil & Gas Journal | Mar. 14, 2011
33
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Oil & Gas Journal | Mar. 14, 2011
From the Subscribers Only area of
www.ogj.com
THE EDITOR’S PERSPECTIVE
MARKET JOURNAL
Time change offers reminder of flawed approach to energy
MENA strife lifts crude to 2-year high
by Bob Tippee, Editor Punctual Americans have just set timepieces forward by 1 hr in a ritual that reminds thoughtful Americans to wonder how their elected officials might blunder next on energy. On Mar. 13, the US switches to Daylight Savings Time. Until 2007, this would not have happened until Apr. 3. In the Energy Policy Act of 2005, however, Congress extended by a month the period during which sunrise and sunset appear later against the clock. The aim was to conserve energy. The main effect, however, was a palpable yet unimportant alteration of behavior at a time when Congress felt compelled to act. Oil prices in 2005 were rising. Frustrations were high. In their zeal to manipulate things as a demonstration of resolve, lawmakers didn’t stop with watches and clocks. With the 2005 energy bill, they put government strongly in the role of fuel selection—setting, for example, volumetric mandates for ethanol in gasoline. In 2007, as oil prices continued to rise, Congress enacted another comprehensive energy bill, this one stoutly hiking requirements for ethanol and other renewable fuels. Now, with frustration over oil prices rising yet again—this time threatening a slow recovery from deep recession—Congress is talking about another energy bill. Not all the ideas on offer are bad. Republicans want to revive offshore permitting, for example. And Rep. Doc Hastings (R-Wash.), chairman of the House Natural Resources Committee, says he wants to avoid the comprehensive—meaning unmanageable—approach to energy legislation. But Democrats want to act on energy, too. Among other items of lunacy, they seek tax changes that would punish oil and gas companies, large and small. Compromise for the sake of an energy bill would be costly. And no one is talking about trimming ethanol mandates to feasible levels—or, better yet, rescinding them. The country would profit if lawmakers would leave energy alone this time, if they’d let markets run their course, if they’d relax and enjoy their newly sunlit evenings. ONLINE MAR. 4, 2011 | [email protected]
Oil & Gas Journal | Mar. 14, 2011
by Sam Fletcher, Senior Writer Fighting in Libya and general unrest in the Middle East and North Africa sent the price of crude above $102/bbl Mar. 2 in the New York market—“the first time in more than 2 years” the front-month contract closed above $100/bbl, said analysts in the Houston office of Raymond James & Associates Inc. Oil prices pulled back slightly Mar. 3 after New York crude made an unsuccessful run at $103/bbl. However, it surpassed $104/ bbl Mar. 4. Extended conflict in Libya with “commensurately lengthy disruption to oil supply” looks likely, said Raymond James analysts. At Standard New York Securities Inc., the Standard Bank Group, James Zhang said, “If oil prices rise much further, this would pose downside risks to the global economy. Our concerns are based both on the current level of oil prices and the speed with which oil prices rise.” Zhang added, “We view oil at around $130/bbl as a potential inflection point for the global economy. Currently, the global macroeconomy remains supportive of the oil market, in conjunction with strong fund money inflows into the market. However, we expect some demand destruction to be caused by the currently high oil prices.”
$120 crude On the other hand, Olivier Jakob at Petromatrix, Zug, Switzerland, said, “Most policy makers in the US [and] quite a few macro asset managers do not fully realize that the price of oil in the US is at $120/bbl and not at $102/bbl. WTI prices in 2011 cannot be compared to WTI prices in 2008 due to the increase in the spread between WTI and the US Gulf Coast crude oil values.” This year, he said, “WTI has moved to an unusual discount to the rest of the US crude oil markets, and the real price of crude oil in the US, on the basis of Light Louisiana Sweet on the US Gulf Coast, is already close to or above $120/bbl. The fact that WTI is at a deep discount to US Gulf Coast crude oil might not send the average American consumer in panic mode on a news headline basis, but the price of gasoline he buys to fill his car is based on $120/bbl crude oil, not $102/bbl. Based on current prices, we estimate that the average retail US gasoline prices should [soon] be close to $3.60/gal.” Recent data from the Energy Information Administration “imply that 2009 finding costs support an oil price range near $55-75/bbl,” said Adam Sieminski, chief energy economist, Deutsche Bank AG, Washington, DC. However, he explained, “Correcting for rising costs in 2010-12 and strong gas reserves in the ‘barrels of oil equivalent’ figure, we still believe that a range of $75-100/bbl for oil is cost justified. If one adds geopolitical risk into the mix, current prices cannot be considered extreme, in our view.”
Refining margins Sieminski said, “The divergence of US benchmark WTI from the world’s other crude oil benchmarks has played havoc with refining margins. US Gulf Coast WTI margins have benefited sharply from the benchmark’s weakness, while refiners in Europe running Brent have suffered. In Asia, margins have generally held up as strong gains in middle distillates offset weakness in naphtha and gasoline.” Jakob said, “In Europe, the [area] most affected by the loss of Libya crude oil, cash crude oil differentials are globally weakening, and the front Brent futures have moved back to oscillating between a flat and a small contango structure. The loss of Libya crude oil supply is being compensated by a loss of crude oil demand as refineries reduce runs either for planned maintenance or for economical reasons for a lack of processing margins.” He added, “Demand destruction is not an overnight but a lengthy process. Those nations that are subsidizing domestic oil prices will have to run greater budget deficits (Thailand is starting to run out of cash for its oil fund), which then turns into lower ratings, lower gross domestic product growth, etc.” ONLINE MAR. 7, 2011 | [email protected]
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