page4

Pioneer marks milestone year inAlaska; Oooguruk at the forefront

Vol. 13, No. 38 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of September 21, 2008 • $1.50

● E X P L O R A T I O N & P R O D U C T I O N

● L A N D & L E A S I N G

B R E A K I N G N E W S

● L A N D & L E A S I N G

6 Taking stock after Ike: Hurricane destroys at least 28 plat-

forms in Gulf, others severely damaged; more devastation expected

10 Devon feeds B.C. gas frenzy: Adds up to 8 Tcf to poten-tial gas resources at Horn River; joins others in warning of cost issues

18 FERC OKs Oregon LNG terminal: Facility would deliver1.3 Bcf per day, opponents say regional demand won’t suffice

Kodiak Electric Association poured foundations this summer forthree 1.5-megawatt wind turbines on Pillar Mountain. The windfarm will produce about 10 percent of the area's electricity needsand is expected to go online next summer or fall.

Busy winter aheadCompanies pursue multiyear oil, gas exploration programs across North Slope

By ERIC LIDJIPetroleum News

his could be one of the busiest winters on the North Slope inrecent memory, as some companies follow promising findsand others work to bring fields online.

Anadarko Petroleum Corp. appears to be expanding itssearch for gas into the National Petroleum Reserve-Alaska, andBrooks Range Petroleum Corp. plans to focus on Gwydyr Bay,while Chevron plans to return to the White Hills. Eni Petroleum isgearing up to drill its first wells at the Nikaitchuq unit, whileExxonMobil proceeds with drilling plans for the Point Thomsonunit despite legal challenges.

Other majors such as BP and ConocoPhillips could have explo-

T

Exxon spending includes $20 million inupgrades to Nabors Rig 27E to drill thehigh-pressure reservoir at Point Thomson.

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Are the revenues right?GAO report urges assessment of royalties, taxes from federal oil and gas leases

By ALAN BAILEYPetroleum News

ith the run-up of oil and gas prices during thepast couple of years, the federal governmentmay be falling short in the revenues that itcollects from U.S. oil and gas leases?

The U.S. Government Accountability Office, in areport issued Sept. 3, said instability in the nation’sfiscal system for oil and gas leasing and the lack of anup-to-date assessment of that system have created arisk that the United States may not be collecting asmuch oil and gas revenue as it might, and that anindependent review of the fiscal parameters of feder-al oil and gas leasing is warranted.

The U.S. Department of the Interior, which over-sees federal leasing onshore through the Bureau of

Land Management and offshore through the U.S.Minerals Management Service, has challenged sever-al of the GAO findings.

The GAO report is the result of a follow-up to a2007 report by the agency, which concluded that U.S.federal revenues from oil and gas are low comparedwith those collected by other resource owners.

“In May 2007 we reported that, based on studiesby industry experts, the amount of money that theU.S. government receives from the production of oiland gas on federal lands and waters … was among thelowest in the world,” Frank Rusco, GAO acting direc-tor, natural resources and environment, said in the let-ter to Congress that constitutes the body of the GAOreport. “The government take that accrues to any gov-

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see REVENUES page 21

MGM to test four plays Drilling could tap 400 Bcf of potential gas reserves in NW Mackenzie region

By GARY PARKFor Petroleum News

rctic explorer MGM Energy said it plans to testfour distinct play types for natural gas during theupcoming winter drilling program in the north-western region of the Mackenzie Delta. The

plan is subject to the approval of MGM’s partners andregulators.

Four wells will be drilled to depths of about 5,000-6,600 feet and are projected to cost a total of C$74million. Each prospect has un-risked potential of 80-100 billion cubic feet.

The program is part of a farm-in agreement withChevron Canada and BP Canada Energy, an 11-wellprogram which requires a minimum three wells thiswinter for MGM to earn a 50 percent working interest

in existing discoveries and three more wells in the2009-2010 winter season.

The first 2008-09 well, which MGM presidentHenry Sykes said could spud before the end ofDecember, will be on Ellice Island, testing prospec-tive zones within the Taglu formation.

The second, identified with three-dimensional seis-mic acquired by MGM in the 2007-08 season, willtest the footwall of the Ellice Island anticline in the

A

see MGM page 18

Four wells will be drilled to depths ofabout 5,000-6,600 feet and are projected

to cost a total of C$74 million. Eachprospect has un-risked potential of 80-100

billion cubic feet.

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Rural energy meeting focuses on renewables

GIRDWOOD – More than 450 agency and utility officials,researchers, and local leaders gathered in Girdwood this week toshare their experiences and brainstorm solutions to the cripplingcost of energy in rural Alaska.

“We have to solve this energy-cost issue for the long-term suc-cess of Alaska,” Alaska Energy Authority executive directorSteven Haagenson told attendees of the Alaska Rural EnergyConference Sept. 16.

The focus of the conference, which was sponsored by AEA, theU.S. Department of Energy, the University of Alaska Fairbanks,and the Denali Commission, was developing “local and renew-able” energy sources.

Haagenson said the focus reflected the economic benefits ofgetting communities off expensive fossil fuels.

Greenpeace, investors targetAlberta oil sands developers

GREENPEACE IS BACK ON one of its favorite hobby-horses – whipping the Alberta oil sands, with the backing ofsome British investment firms.

The environmental group’s latestreport, apparently endorsed by Holdenand Partners, Innovest and Co-operativeAsset Management, warns BP and RoyalDutch Shell that they risk a backlash frominvestors by pursuing oil sands develop-ment.

Co-operative Asset manages invest-ments of about $5.6 billion and ownsshares worth about $150 million in BPand Shell, or less than 2 percent of eachcompany.

It is trying to convince other institutional investors to

see INSIDER page 18

see RENEWABLES page 19

contents Petroleum News A weekly oil & gas newspaper based in Anchorage, Alaska

2 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

17 Senate panel OKs coal-to-gas funds

Stevens pushes for federal backing of Fairbanks synthetic fuels project to cut reliance of Interior military bases on foreign oil

10 Devon feeds British Columbia gas frenzy

Independent adds up to 8 Tcf to potential gas resourcesat Horn River; joins others in warning of cost,infrastructure problems

11 Russian firm seeks stake in Total project

Kharyaga in Nenets Autonomous Okrug third production-sharing project to come under government pressure after Sakhalin I and II

18 FERC approves LNG terminal in Oregon

Facility would deliver 1.3 Bcf per day, opponents say regional demand won’t suffice, terminal could create market for Alaska

LAND & LEASING

OUR ARCTIC NEIGHBORS1 Greenpeace, investors target oil sands developers

9 Russia stakes claims to Arctic resource base

6 Alliance elects directors at annual meeting

9 Operator to replace Kuparuk pipeline

9 Marathon requests rate increase for KNPL

NATURAL GAS

OIL PATCH BITS

INTERNATIONAL

EXPLORATION & PRODUCTION

ALTERNATIVE ENERGY

OIL PATCH INSIDER

PIPELINES & DOWNSTREAM

5 Hunt for Labrador natural gas revived

Newfoundland royalty regime, technology advancesattract C$186 million in exploration bids; gas discoveries to date total 4.2 Tcf

4 Pioneer marks milestone year in Alaska

Oooguruk comes on line as drilling continues in North Slope field; Cook Inlet’s Cosmopolitan advances toward development decision

6 MMS, operators take stock after Ike

Hurricane destroys at least 28 platforms in Gulf, othersseverely damaged; more reports of devastation expected

8 Minnows battle upstream

Canadian juniors favor oil over gas, B.C. over Alberta as they increase capital budgets; reposition operations to avoid royalty hikes

Rural energy meeting focuses on renewables

12 Russia may designate offshore oil off-limits

12 Norwegian firm leases BOS 3-D seismic vessel

12 Russia’s Rosneft gets first ice-class tanker

12 Dutch select Norwegian base for Russian project

16 Licensees seek more time for Nenana

17 Potential Alaska state, federal oil and gas lease sales

ON THE COVERBusy winter ahead

Companies pursue multiyear oil, gas exploration programs across North Slope

MGM to test four plays

Drilling could tap 400 Bcf of potential gas reserves in NW Mackenzie region

Are the revenues right?

GAO report urges assessment of royalties, taxes from federal oil and gas leases

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PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 3

Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay 18-05A BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 3K-108 ConocoPhillipsDreco 1000 UE 16 (SCR/TD) Prudhoe Bay B-36 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD2-466 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk annual maintenance ConocoPhillipsTSM 7000 Arctic Fox #1 Stacked in Yard Pioneer Natural Resources

Arctic Wolf #2 Stacked in yard FEX

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES Prudhoe Bay J-08A BPMid-Continental U36A 3-S Milne Point MPJ-06 BPOilwell 700 E 4-ES (SCR) Prudhoe Bay GPB F-38 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay W-31 BPDreco 1000 UE 9-ES (SCR/TD) Orion V-207 BPOilwell 2000 Hercules 14-E (SCR) Stacked AvailableOilwell 2000 Hercules 16-E (SCR/TD) Being fitted out for drilling

this winter Brooks Range PetroleumOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Oliktok Point OPi2 AnadarkoEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Stacked Brooks Range PetroleumAcademy AC electric Canrig 105-E (SCR-TD) Stacked on ice pad at Chandler #1 AnadarkoAcademy AC electric Canrig 106-E (SCR/TD) Stacked Chevron

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site 6-23 BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay well N-14 BPIdeco 900 3 (SCR/TD) Kuparuk well 1J-101 ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOIME 1000 19-E (SCR) Oooguruk ODSN-45i Pioneer Natural ResourcesOilwell 2000 33-E Stacked BP

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Moving to Moquawkie No. 4 Aurora Gas

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 KDU 9 Marathon

Nabors Alaska DrillingContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Beluga River Unit 211-26 ConocoPhillips

Rowan CompaniesAC Electric 68AC (SCR/TD) On site at Cosmopolitan Pioneer Natural Resources

Cook Inlet Basin – Offshore

Chevron (Nabors Alaska Drilling labor contract)428 AN-32 Anna platform Chevron

XTO EnergyNational 1320 A Platform A no drilling or workovers at present XTONational 110 C (TD) Idle XTO

Kuukpik 5 Well A-15 Tyonek platform ConocoPhillips

Mackenzie Rig StatusCanadian Beaufort Sea

SDC Drilling Inc.SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available

Mackenzie Delta-Onshore

AKITA EqutakDreco 1250 UE 62 (SCR/TD) Rig Racked in Inuvik, NT AvailableModified National 370 64 (TD) Rig racked in Inuvik, NT Available

Central Mackenzie Valley

Akita/SAHTUOilwell 500 51 Rigging up on Goose Island, Norman Imperial oil

Wells NT

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of September 18, 2008.

Active drilling companies only listed.

TD = rigs equipped with top drive units WO = workover operations CT = coiled tubing operation SCR = electric rig

This rig report was prepared by Alan Bailey

Baker Hughes North America rotary rig counts*September 11 September 5 Year Ago

US 2,031 2,013 1,787Canada 433 418 364Gulf 65 63 73

Highest/LowestUS/Highest 4530 December 1981US/Lowest 488 April 1999Canada/Highest 558 January 2000Canada/Lowest 29 April 1992

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

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● E X P L O R A T I O N & P R O D U C T I O N

Pioneer marks milestone year in AlaskaOooguruk comes on line as drilling continues in North Slope field; Cook Inlet’s Cosmopolitan advances toward development decision

By ALAN BAILEYPetroleum News

n the year or so since Dallas-basedPioneer Natural Resources announcedthat it was throttling back on its Alaskaexploration program to focus on its

Oooguruk and Cosmopolitan projects, thecompany has made some significantprogress. First oil flowed from the compa-ny’s Beaufort Sea Oooguruk field at thebeginning of June. And at the end ofDecember, the company successfully tested

its first Cosmopolitan appraisal well.The Oooguruk startup marked the first

North Slope oil production operated by anindependent oil company. Pioneer owns a70 percent working interest in the field, withItalian major Eni Petroleum owning theremaining 30 percent.

“2008 was really a milestone year forPioneer in Alaska,” Tadd Owens, Pioneer’sdirector of government and public affairs,told Petroleum News Sept. 12. “We kickedoff production at Oooguruk in June and thatwas the culmination of a couple of years of

pretty significant con-struction activity.”

Owens said Pioneeris now in the earlystages of a two tothree-year, 40-welldrilling program atOooguruk. So far thecompany has complet-ed two productionwells and a well fordisposing well cuttings. And in the transitionfrom field construction into field operation,the company is still finishing up “a few oddsand ends on the construction side,” Owenssaid.

Harrison BayOooguruk lies under the waters of

Harrison Bay northwest of the KuparukRiver unit, with the wellheads and produc-tion facilities located on an artificial gravelisland that Pioneer had to construct as partof field development. Nabors Rig 19-AChas been installed on the island for develop-ment drilling.

Oooguruk production is carried onshorethrough a 12-inch subsea pipeline to theKuparuk River unit well pad 3H, for pro-cessing in the Kuparuk field’s CentralProcessing Facility 3. The 12-inchOooguruk flowline runs inside a 16-inchpipeline that would provide secondary con-tainment were oil to leak from the innerpipe. The Alaska Oil and Gas ConservationCommission is allowing Pioneer to use arelatively new type of multiphase meteringto measure the quantity of co-mingled oil,gas and water that is passing fromOooguruk into the Kuparuk system.

There are two distinct oil pools in theOooguruk field — the Kuparuk pool and thedeeper and larger Nuiqsut pool. One of theproduction wells that Pioneer has now com-pleted penetrates the Kuparuk pool whilethe other well penetrates the Nuiqsut pool,Owens said. The company is in the processof drilling the first Oooguruk injection well— the plan is to use water-alternating-gasenhanced oil recovery to maximize produc-tion, with about half of the eventual wells inthe field being injectors, he said.

Under its permit conditions, Pioneer hashad to limit the drilling of some wells tointermediate depths initially, schedulingthem for completion at later dates.

“We have some seasonal drilling restric-tions, so we’ve had to juggle our schedule abit,” Owens said.

Initial shutdownPioneer had to stop the initial Oooguruk

production just a few weeks after startupbecause of a planned maintenance shut-down at the Kuparuk processing facility.The Kuparuk facility is scheduled for restartin September, Owens said.

The production in June came through theinitial well in the Kuparuk pool and that wellperformed up to par. However, it is too earlyto say how closely field performance willmatch pre-development estimates —

Pioneer anticipates peak gross production of15,000 to 20,000 barrels of oil per day in2010, with production of as much as 90 mil-lion barrels of oil over the 25- to 30-year lifeof the field.

“Certainly the first Kuparuk well that wedrilled was very successful and … we’rejust at the beginning stages,” Owens said.“… It’s going to be a learning process for usas we complete wells and gather more infor-mation, and get a sense of how the reser-voirs perform.”

Meanwhile, Pioneer is investigating thepotential for extending the field, usingopportunities that the company has identi-fied in locations positioned both verticallyand horizontally relative to the existing oilpools. The company may opt to go afterthese opportunities once the initial 40-welldrilling program has been completed,Owens said.

CosmopolitanPioneer’s other major Alaska venture,

the 25,000-acre state and federalCosmopolitan unit, lies around 800 milessouth of Oooguruk, about two miles off-shore from Anchor Point in the southernKenai Peninsula.

Pennzoil discovered an oil pool atCosmopolitan in 1967 in the StarichkofState No. 1 well, drilled offshore with ajack-up rig.

In 2003 ConocoPhillips, by that time theCosmopolitan operator, drilled a long-reachwell and sidetrack called Hansen No. 1 andHansen No. 1-A from an onshore well pad.Those wells “tested at a stabilized rate of600 to 800 barrels a day over different inter-vals that lasted three to four months,”according to statements made back in 2005by Tim Dove, president and chief operatingofficer for Pioneer.

Pioneer has put the recoverable resourcepotential of the area at between 30 millionand 50 million barrels of oil.

Pioneer gradually bought out all theworking interest owners of Cosmopolitanincluding, in 2006, ConocoPhillips’status asoperator. And in September 2007 Pioneerstarted drilling the Hansen 1A 1L sidetrackfrom the same onshore pad used byConocoPhillips, with Rowan rig 68. Thatwell was completed in late 2007 and a sub-sequent extended test produced 400 to 500barrels of oil per day from the Starichkofzone.

Encouraging resultsCombined with the results of the tests in

the original Hansen well, there is a flow rateof about 1,000 barrels per day, a numberright in the middle of the hoped-for range,Owens said.

“The results were encouraging,” he said.“… Good news, but there’s a lot of work todo before we can kick off full developmentat Cosmo.”

Owens said Pioneer is evaluating boththe effectiveness of the drilling and the sig-nificance of the test results.

4 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

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OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 13, No. 38 • Week of September 21, 2008

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ITADD OWENS

see PIONEER page 13

By GARY PARKFor Petroleum News

ust as it happened in Western Canada,the search for oil occurred long beforeanyone began looking for natural gas onCanada’s East Coast. But the potential

resource of 61 trillion cubic feet offshore ofNewfoundland has always been a dream ofgovernments and industry.

Other than the Sable project offshore ofNova Scotia and the nearby Deep Panukefield, part of the estimated 18 Tcf on theScotian Shelf, the odds have been againstturning Atlantic Canada into a major gas-producing region.

The stormy, icy seas of the North Atlantic,the technological challenge of getting gas toshore and the absence of a royalty regimehave always blocked the path to progress ofNewfoundland.

As well, the province’s grand gas prizehas been overshadowed by its hydroelectricprospects.

But that hasn’t stopped proponents fromquietly evaluating ways to commercializethe resources.

They’ve talked about building a concrete-encased pipeline to withstand icebergs thatcarve huge trenches into the seabed, deploy-ing tankers to ship compressed natural gas,using gas transport modules on barges, anddeveloping compressed gas coselles (coiledpipe in a carousel-shaped container thatcould store 330 million cubic feet in oneship).

It’s all been in the name of tapping thevast quantities of natural gas stranded off-shore of Newfoundland and opening up mar-kets in the northeastern United States.

Suddenly, long after exploration effortsfrom 1971 to 1983 yielded five significantgas discoveries totaling 4.2 Tcf on theLabrador Shelf, there is a fresh awakening ofinterest.

Interest robust in exploration rightsChevron Canada, Husky Energy, Suncor

Energy and two small Newfoundland firms(Vulcan Minerals and Investcan Energy)have made successful bids of C$186.4 mil-lion for rights to explore four contiguousblocks in an area 30 miles off the Labradorcoast, the Canada-Newfoundland andLabrador Offshore Petroleum Board report-ed September 11.

Husky led the way investing C$10.2 mil-lion for 100 percent of one block covering585,580 acres and paying 75 percent of aC$120.2 million bid for 577,502 acres, withSuncor taking the remaining 25 percent.

Chevron invested C$46.5 million for out-right control of a third parcel, while Vulcanand Investcan committed C$9.6 million forthe final block.

The dollar figures represent what eachcompany, partnership or joint venture com-mits to spend during the first six years of a

nine-year exploration license.Husky chief executive officer John Lau

said it has been a priority for his company,which already holds major stakes in the TerraNova and White Rose oil projects, to expandits presence in Newfoundland and Labrador.

To date, Labrador has recorded 26 explo-ration wells and two delineation holes, whichcompanies drilled at a time when they werelooking for oil.

Four years ago, the Hong Kong-con-trolled company got responses from morethan 40 groups interested in helping it devel-op 2.3 trillion cubic feet of gas associatedwith the White Rose oil field, placing itself inthe forefront of efforts to commercialize thegas resource by tackling the gargantuanobstacles posed by the region. These include500 icebergs that cut a path across the GrandBanks each year and scour the seafloor, andthe costs of exploratory wells, which are nowcommonly around C$70 million.

In addition, there has been a joint studyby various companies looking for ways tomove the region ahead.

But, given the time needed to evaluatedevelopment and transportation options,Husky’s Lau has doubted that commercialproduction will take place before 2016.

Over decades, various Newfoundlandgovernments have prodded the industry tofind ways to develop the province’s gasresource, with some leaders even hinting thata failure to move ahead could lead to forfei-ture of exploration rights.

Breakthroughs for gasThe most positive recent development

was the release a year ago of a comprehen-sive Newfoundland energy plan that includ-ed the first gas royalty regime covering basicand net royalties.

The basic royalty provides a revenuestream to the government at all stages of aproject. It is linked to realized prices, ratherthan volumes or project economics thatapply under existing oil royalty terms, mean-ing the province’s percentage share of grossrevenue from each project would largely bedriven by price.

That approach ensures greater transparen-cy and that the interests of government andindustry are “well-aligned,” according to theenergy plan.

The net royalty is based on project prof-itability and reflects the revenue and costsassociated with a particular project. Whereprofitability of a project is higher, theprovince will share in that profitability;

where it is less or declining, the net royaltywill be lower and the province’s take willdecline.

A formula for both royalty rates willenable a quick response to falling or risingprices, “sending a positive message toinvestors and demonstrating that theprovince is prepared to share in price risk.”

“It is a challenge to develop a uniformregime to meet the needs of all parties as wehave diverse regions like the active Jeanned’Arc Basin, deepwater regions like theOrphan and Laurentian basins and remoteregions like the Labrador Shelf,” the govern-ment said.

“We have designed an offshore naturalgas royalty that recognizes the cost andshares the risk associated with various gasdevelopments.”

That was an important breakthrough forthe gas sector. The second breakthroughoccurred last month with a developmentagreement between the Newfoundland gov-ernment and the ExxonMobil-operatedHebron oil project, ending two years of ten-sion between industry and government.

Paul Barnes, Atlantic manager for theCanadian Association of PetroleumProducers, said the Hebron pact allows theindustry to understand exactly what equitypositions the government wants in new proj-ects and that it is willing to pay its full shareof those stakes.

He said technological improvementssince drillers pulled out of Labrador in 1983open the way to more cost-efficient opera-tions in the icy waters.

There are also fresh alternatives, such as

large liquefied natural gas technology, orLLNG, for shipping the gas to market.

Early days yet for industryAs a result, the industry has returned to

Labrador to conduct seismic that, along withthe initial discoveries, points to considerablepotential, he said.

Companies with major interests in one ormore of Labrador’s significant discoverylicenses include Chevron, Husky, Petro-Canada and ConocoPhillips Canada.

For now, the rights-holders are sidestep-ping any questions on their exploration plansor the likelihood of commercial gas produc-tion.

Husky spokesman Graham White toldPetroleum News his company is only in theearly stages of planning an assessment of theresources it may hold.

But he said it is motivated by its experi-ence operating in “rough conditions” atWhite Rose and Terra Nova.

Chevron spokesman Tim Murphy agreedthat developing an exploration plan, led byseismic work, will “take a little period oftime.”

While there is no questioning the techni-cal challenges, Chevron, already a partnerin the Hebron and Hibernia projects,believes it has the “wherewithal” from itsglobal activities to tackle such a frontieropportunity, he said.

Suncor said it has an eye on developinglong-term gas prospects as a hedge againstthe gas it needs to fuel its oil sands opera-tions in Alberta. ●

PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 5

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Hunt for Labrador natural gas revivedNewfoundland royalty regime, technology advances attract C$186 million in exploration bids; gas discoveries to date total 4.2 Tcf

JCompanies with major interests in

one or more of Labrador’ssignificant discovery licenses

include Chevron, Husky, Petro-Canada and ConocoPhillips

Canada.

By RAY TYSONFor Petroleum News

eported damage to Gulf of Mexicooil and gas facilities is mounting inthe wake of Hurricane Ike, whilegovernment authorities try to figure

out how long before the region’s produc-tion can be restored to pre-hurricane lev-els.

“We expect additional reports of dam-age as weather allows more flights out tothese areas and the operators are able toboard the platforms to begin inspection,”Lars Herbst, Gulf regional director for theU.S. Minerals Management Service(MMS), told reporters in a Sept. 16 tele-conference.

At midweek, 28 production platformswere reported destroyed and several othersseverely damaged, including the BP-oper-ated Mad Dog production spar whichreportedly lost its drilling rig. “We arecounting Mad Dog as a platform rigdestroyed,” Herbst said.

Chevron said reconnaissance flightsindicated that some of its platforms wereaffected by the storm, “with several report-ed as toppled in the eastern and westernshelf areas.”

Herbst said most of the facilities report-ed destroyed by Ike were older, lower-pro-ducing platforms located in deeper por-tions of the relatively shallow waters of the

U.S. Gulf’s continental shelf. “This isindicative of waves 40 to 50 feet hittingthe production decks,” he noted.

Additional damage reported includedthree jack-up drilling rigs destroyed andone jack-up drilling rig with extensivedamage. In a separate matter, two drillingrigs that had been reported drifting onSept. 3 had been secured by tugs, MMSsaid, adding that early reports also indicat-ed some pipeline damage. “For pipelines,those always take longer to assess thedamage,” Herbst said.

Platforms reported destroyed by Ikeproduced a total of 11,000 barrels of oilper day and 82 million cubic feet of gasper day. The U.S. Gulf normally producesaround 1.3 million barrels of oil per dayand about 7 billion cubic feet of gas perday.

Still, as of Sept. 18, MMS reported that93 percent of the total oil and about 78 per-cent of the total natural gas produced in theU.S. Gulf remained shut-in. However, theone-two punch of Ike and earlier Gustavhas kept on average roughly 80 percent ofthe oil and 65 percent of the gas out of cir-culation for the past three weeks.

The Gulf of Mexico provides 25 per-cent of America’s oil production and 15percent of its natural gas production.

“It’s probably a little too early to makethat assessment, as far as the total length oftime to get all or essentially all of the pro-

duction back online,” Herbst said.

Damage may be widespreadIt took months to restore production

after hurricanes Katrina and Rita, bothdevastating Category 5 storms when theypassed through producing areas of theU.S. Gulf in 2005.

“Hurricane Ike, while a Category 2hurricane, was a large storm,” Herbstsaid, noting that of the 3,800 oil and gasfacilities in the U.S. Gulf, 1,450 wereexposed to hurricane winds greater than74 miles per hour. An estimated 12,200miles of pipeline also were in Ike’s path,he added.

The 28 platforms thus far reporteddestroyed by Ike compare to 44 destroyedby Katrina and 64 by Rita. However, themain difference is that the storms of twoyears ago appear to have taken a heaviertoll on deepwater facilities, whichaccount for 70 percent of all oil producedin the U.S. Gulf.

However, Herbst cautioned that pre-liminary inspections had not yet beenconducted on the more westerly portionof the U.S Gulf, including offshore Texas.For one, he said helicopter flyovers hadbeen limited due to fuel shortages createdby Ike.

“We just do not have confirmation atthis time, either from our aircraft that arein the area, or from operator over-flights,” Herbst said.

He said once most of the damageassessments are in, MMS would then

begin “transitioning” to the next phase –looking for ways to resume production,including barging oil ashore and re-rout-ing stranded product through undamagedpipeline systems.

Operators resume productionMeanwhile, operators began returning

to offshore platforms to assess hurricanedamage or to restart production.

Anadarko Petroleum said it wasrepairing minor surface damage on itsdeepwater Constitution, Marco Polo,Gunnison, Nansen, and Boomvang plat-forms and that it had resumed productionfrom its “ultra-deepwater” IndependenceHub platform, the largest single source ofnatural gas in the U.S. Gulf, and addedthat its Neptune platform was ready toresume production as pipelines allowed.

Shell Oil, the U.S. Gulf’s largest pro-ducer with over 130,000 barrels per dayof capacity, said it restarted some 26,000barrels of oil equivalent per day and thatit expected the bulk of its remaining pro-duction in the East Gulf to start up latethis weekend and into mid-next week.

In another sign of recovery, theLouisiana Offshore Oil Port, the onlyU.S. deepwater crude oil port, said it wasrunning at full rates and meeting all cus-tomer requests for crude while offloadingtankers. Waterways to refineries fromNew Orleans to Houston were reopening,though some with restrictions, while nav-igational aids were being restored anddebris cleared. ●

6 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

● P I P E L I N E S & D O W N S T R E A M

MMS, operators take stock after IkeHurricane destroys at least 28 platforms in Gulf of Mexico, others severely damaged; more reports of devastation expected

R

OIL PATCH BITSAlliance elects directors at annual meeting

The Alaska Support Industry Alliance saw some new and returning directorselected at its annual meeting Sept. 11.

Kevin Dorling of Petroleum Equipment and Services is new to the Allianceboard, while veterans Richard Faulkner of Steelfab and Buzz Otis of ForbesStorage, Fairbanks, returned to director seats. Incumbent board members JohnDittrich of Bethel Services, Mark Hylen of Beacon Occupational Health & SafetyServices, Patrick Walsh of Peak Oilfield Services, Tom Walsh of PetrotechnicalResources of Alaska and Lon Wilson of the Wilson agency were re-elected.

David Lawer of First National Bank and Bill Barron of CH2M Hill left theboard after their two-year terms expired.

Paul Laird, general manager of the Alliance said about 460 people attended themeeting, making it one of the best-attended general meetings in the organization’s29-year history.

—ALAN BAILEY

PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 7

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By GARY PARKFor Petroleum News

ramatic shifts from natural gas tooil and from Alberta to BritishColumbia have become two of themost common prescriptions for the

ills plaguing Canada’s junior and inter-mediate sectors.

Caught in the vise of plunging oil andgas prices, many – especially those with afoothold in the resource plays of BritishColumbia – are trying to lower risk byhiking their capital spending in 2008.

For those with restricted options, thelikely outcome is being swallowed duringa wave of consolidation that is predictedonce commodity prices stabilize.

In a word, “not all producers are creat-ed equal,” said Chris Theal, managingdirector of research at Tristone Capital.

But, of those who are more equal thanothers, B.C. is opening up to companiesthat are able to turn vertical wells intohorizontal wells, using multi-stage frac-turing completion technologies.

Theal said that approach is lower risk,developmental and repeatable … a tem-plate for success.

In addition, hiking cap-ex over thesecond half of the year is essential to cur-tail taxes among companies that are flushwith cash from robust commodity pricesin the first half.

“That’s the driving force,” said CIBCWorld Markets analyst William Lee.” Butwith the pullback in commodities, I don’tthink a lot of companies are in that posi-tion anymore.”

Birchcliff Energy, which posted sec-ond-quarter production of 9,583 barrelsof oil equivalent per day, is a frontrunner,increasing its cap-ex by 47 percent toC$220 million because of its drilling suc-cess in the Peace River Arch of north-western Alberta, where it concentrates onMontney-Doig gas and Worsley lightcrude.

It now forecasts 2008 production at13,500-14,000 boepd, 1,000 boepd high-er than its original forecast.

Bucking the trends, Birchcliff is alsoscooping up land in Alberta where pricesare considerably lower than in BritishColumbia, said company chief financialofficer Bruno Geremia.

Reacting to falling pricesProEx Energy, which operates exclu-

sively in British Columbia, has pumpedanother 15 percent into its 2008 capitalprogram, raising the total to C$190 mil-lion.

Chief executive officer Dave Johnsonsaid ProEx can succeed at lower com-modity prices because it controls risk.

In the resource sector, once land hasbeen secured and technology has beenproven, the emphasis is more on execu-tion and cost control than exploration, hesaid.

That theory is already paying off on avertical well drilled in 1999 that hasgrown from minimal gas flows to 2.2 mil-lion cubic feet per day after getting a2,500-foot horizontal extension with sixseparate fracture stimulations, ProExsaid.

The company has drilled 170 wellsover the past four years since being spunoff by predecessor Progress Energy andhas acquired 86,000 acres this year on topof the 425,000 acres it already owned.

Others on the move in various waysinclude NAL Oil & Gas Trust, BreakerEnergy and Storm Exploration.

NAL has boosted spending on oil tobetween 70 percent and 85 percent, saidCEO Andrew Wisell. “We’re focusing onour oil opportunities for the rest of theyear” to a greater extent than NAL hasdone before, he added.

Breaker chief financial officer MaxLof said his company, which had second-quarter volumes of 5,922 boepd, hasdirected an increasing chunk of its cap-exto oil from 30 percent in the openingquarter of 2006 to 53 percent in the latestquarter, when oil accounted for 70 per-cent of cash flow.

“We can direct capital where we wantit,” he said. “That shift has really paid bigdividends.”

Rush from royalty hikesStorm, which had output of 6,130

boepd in the second quarter, will shrinkspending in Alberta as much as possiblebecause of the province’s royalty hikes

in 2009.CEO Brian Lavergne said Storm is

resolved to have 80 percent of its produc-tion coming from British Columbia bythe end of 2008.

Iteration Energy CEO Brian Illingechoes that sentiment, saying his compa-ny (which pumped 18,152 boepd in theApril-June period) will increase spendingin the westernmost province during thebalance of 2008 at the expense of Alberta.

As well, he said a number of projectsplanned for the final quarter are notattractive at today’s prices and will be“put off to another time.”

Rocky road in marketsInvestor relations firm, Bryan Mills

Iradesso – whose latest quarterly reportcovers 63 juniors (producing 500 to10,000 boepd) and 24 intermediates(10,000-100,000 boepd) – said the juniorstraded at a discount to their larger peersdespite greater production growth, higheroperating margins and lower debt ratios.

The firm’s president Peter Knapp saidthe market premium becomes even moreintriguing given that juniors raised theaverage production growth in the quarterby 4 percent, while the intermediateswere frozen.

In addition, juniors had median net-backs of C$38.08 per barrel of oil equiv-alent compared with C$37.43 boe forintermediates and had a net debt of 0.7times cash flow against 1.3 times forintermediates.

Based on August 29 share prices, theaverage second-quarter enterprise valuefor juniors was four times annualizedcash flow, compared with 5.8 times forintermediates. By dividing the share priceby the cash flow per share, juniors tradedat 3.2 times annualized cash flow pershare and intermediates at 4.2 times.

Though TSX Venture Exchange (thespringboard for emerging companies) hasdropped about 45 percent this year, oiland gas juniors generated total returns of37 percent in the second quarter.

But Knapp conceded that based onmarket performance “it pays to be anintermediate,” and he expects that tobecome even more apparent in a calmercommodity price world.

Mostly the tide moves because ofcommodity prices,” he said.

Knapp said price stability will be a sig-nal for buyers and sellers to reach consen-sus on the value of assets.

If and when the wave of corporate andasset deal-making occurs, he suggested thattoday’s market may, on reflection, seemlike a time to buy low and sell high. ●

8 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

● E X P L O R A T I O N & P R O D U C T I O N

Minnows battle upstreamCanadian juniors favor oil over gas, B.C. over Alberta as they increase capital budgets; reposition operations to avoid royalty hikes

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PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 9

● P I P E L I N E S & D O W N S T R E A M

Operator to replaceKuparuk pipelineConocoPhillips says work also will enable line to accept smartpigs for corrosion monitoring; project expected to take two years

By ERIC LIDJIPetroleum News

onocoPhillips plans to replace morethan four miles of pipe in theKuparuk River unit early next year toallow for better corrosion monitoring.

The replacement will allow unit operatorConocoPhillips to run smart pigs and main-tenance pigs through the Kuparuk PipelineExtension. Pigs are mechanical devices fedthrough a pipeline for different purposes.Smart pigs measure damage along the wallsof a pipeline, while maintenance pigs cleanout deposits that could lead to corrosion.

The shortest of the major pipelines onthe North Slope, the Kuparuk PipelineExtension runs about nine miles fromCentral Processing Facility-2 to CentralProcessing Facility-1, both in the easternhalf of the Kuparuk River unit.

Originally, the westernmost piece ofNorth Slope transportation infrastructurewhen it came online in 1981, the extensionnow connects the Alpine Oil Pipeline andfields to the west with the Kuparuk OilPipeline, which feeds into the trans-Alaskaoil pipeline.

During its first 25 years in operation, theKuparuk Pipeline Extension moved morethan 73 million barrels of sale-quality oilinto the gathering facilities at Prudhoe Bay.And although the small pipeline has been aworkhorse, that much oil naturally takes itstoll.

But monitoring the Kuparuk PipelineExtension is cumbersome.

Currently, ConocoPhillips can’t pig theabove-ground pipeline because of its odddesign: About half of the line is 12 inches in

diameter, while the rest is 18 inches indiameter. As a result, the field operator canonly monitor the line externally, using ultra-sound equipment.

The upgrades will enlarge the narrowersection, making the entire pipeline 18 inch-es in diameter. It also will use existing ver-tical support members and pipeline racks.The old pipe will be cleaned and recycled.

Along with the replacement effort,ConocoPhillips plans to build pig launchingand receiving terminals at either end of thepipeline. The terminals will be built inbasins used for collecting snow during win-ter cleanups and melt-water during springbreakup.

The company said it expects to finish theentire project by the fall of 2010.

Corrosion a focus since 2006Corrosion became a public issue in

March 2006, after sediment build-up inpipelines at the BP-operated Prudhoe Bayfield caused the largest oil spill in NorthSlope history.

Following the spill, ConocoPhillips vol-untarily evaluated its pipelines at Kuparukunder a program devised by the U.S.Department of Transportation. The federalagency came to Alaska in November 2006to inspect ConocoPhillips’ North Slopepipelines.

But the program requiresConocoPhillips to conduct further inspec-tions. The smart pigs will allow the compa-ny to inspect the pipeline to DOT standardsby the agency’s deadline in May 2011. ●

C

PIPELINES & DOWNSTREAMMarathon requests rate increase for KNPL

For the second time this year, Marathon Oil is asking state regulators to increaseshipping rates on a small Cook Inlet gas pipeline because of declining throughput vol-umes.

Should Regulatory Commission of Alaska approve the increase for the KenaiNikiski Pipeline, or KNPL, the firm transportation rate for reserved space on the linewould jump nearly 40 cents, or 19.3 percent, to $2.472 per thousand cubic feet of dailycapacity per month, while the interruptible rate would increase by about one cent to$0.0681 per Mcf.

The pipeline does not currently have any firm shippers.The 20-inch KNPL runs 17.5 miles from the gas fields around Kenai to a pipeline

hub north of Nikiski. It can transport around 167 million cubic feet of gas at maximumcapacity. Under a settlement agreement reached in late 2006, Marathon is required toadjust the KNPL tariff when throughput on the line changes more than 10 percent over12 months. Currently, Marathon, Union Oil Co. of California, ConocoPhillips andAurora Power ship gas on the pipeline, mostly for sales to a liquefied natural gas plantin Nikiski. The pipeline also once supplied the now mothballed Agrium fertilizer plant.

Marathon most recently raised rates on the line April 1. The new rates, if approved,would go into effect on Oct. 1. RCA is accepting comments on the proposal throughSept. 26.

— ERIC LIDJI

Contact Eric Lidji at 907-770-3505or elidji@petroleumnews.com

INTERNATIONALRussia stakes claims to Arctic resource base

The Russian bear is starting to throw its weight around in more than Georgia thesedays, making it clear the use of a mini-submarine to plant a flag under the North Polelast year was more than just an empty gesture.

At the same time Canadian Prime Minister Stephen Harper took senior cabinet min-isters to Inuvik, Northwest Territories, last month to bolster his claims to Arctic sover-eignty, there was an unparalleled gathering of Russia’s national security council to drivehome Security Secretary Nikolai Patrushev’sassertion that the Arctic will become its “majorstrategic resource base.”

The council, comprising defense and interiorministers and speakers of Russia’s legislativehouses, met at the Nagurskaya military base on aHigh Arctic island.

Harper, in his pre-election campaign polar trek,said the discovery so far of oil, natural gas, miner-als and diamonds in the Beaufort, Eastern Arctic,Nunavut, NWT and Yukon is “merely the tip of theproverbial iceberg.”

Certain of Canada’s territorial claims to a large chunk of the Arctic, he said its shareof “this incredible endowment will fuel the prosperity of our country for generations.”

The Russians are just as confident they have rights, prompting Canada’s DefenseMinister Peter MacKay to acknowledge that “we’re obviously very much concernedabout much of what Russia has been doing lately.”

He said Canada has been on the alert lately for Arctic patrol flights by Russianbombers, intercepting those planes with F0-18s.

“We remind them that this is sovereign Canadian airspace and they turn back,”MacKay said. “And we’re going to continue to do that.”

But turning back doesn’t mean a retreat by Russia whose President DmitryMedvedev said Sept. 17 his country should legislate its claims to disputed Arctic terri-tory.

“We must finalize and adopt a federal law on the southern border of Russia’s Arcticzone,” he told Russia’s Security Council.

“We have to ensure the long-term national interests of Russia in the Arctic,”Medvedev said.

Russia, the United States, Canada, Norway and Denmark have until May 2009 tofile new ownership claims with a United Nations commission.

That’s where Russia is expected to insist it has jurisdiction over much of the Arcticbecause of an underwater ridge linking Siberia to the seabed that extends under theNorth Pole.

—GARY PARK

Russia, the United States,Canada, Norway and

Denmark have until May2009 to file new

ownership claims with aUnited Nations

commission.

10 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

By GARY PARKFor Petroleum News

he Horn River Basin in far-flung northeasternBritish Columbia is now more than two-thirds of theway to its estimated potential shale gas resources of50 trillion cubic feet after less than two years of

exploration effort.The scramble to secure rights in that area, along with

Montney to the south, continued apace at the latest gov-ernment land auction, which pulled in C$220 million –once a staggering single-sale result, but now falling intothe “ordinary” category after the benchmark returns ofC$610 million in July and C$501 million in August.

Devon Energy has joined the list of companies offer-ing details of the potential size of the emerging shale gasplay.

Chris Seasons, president of Devon’s Canadian unit,said the Oklahoma City-based independent may haveuncovered 5 trillion to 8 trillion cubic feet of gas andbelieves its 153,000 acres may be capable of producing700 million cubic feet per day based on test wells lastwinter.

“This is not small by any stretch of the imagination,”he said.

Devon’s numbers add to a growing basket thatincludes 16 Tcf by an EnCana-Apache joint venture, 6Tcf from EOG Resources and 3 Tcf to 6 Tcf from Nexen.

At the upper end of the forecasts, these companieshave accumulated 36 Tcf, closing in on the 50 Tcf pro-jected for the area by Wood Mackenzie.

Seasons told a North American Oil and GasConference sponsored by investment dealer Peters & Co.that Devon is still in the “very early stages” of commer-cial development and is now grappling with perhaps thetoughest challenge of all – getting the resource on-stream, economically.

While drawing parallels between Horn River and theBarnett Shale in Texas, where Devon is producing 1 bil-lion cubic feet per day, he said northern B.C. is accessi-ble only in winter and does not have the same infra-structure as the Barnett, located around the Fort Worthmetro area, although the B.C. government is helpingfinance roads that will expand the drilling season to 10months.

“We’re not drilling on the outskirts of suburbanDallas, we’re drilling in the bush,” Seasons said, addingthat trying to frac wells in temperatures of minus 50degrees Fahrenheit with the amount of water that isrequired is “a bit of a challenge.”

“It is the logistics of getting up there,” he said.“When you operate in the winter, you burn fuel, so it isjust generally a higher cost.

“I can see a day when there will be a real demand forsand and fresh water for pumping … all things that mayconstrain the overall industry at some juncture,” he said.

In addition, Seasons said he is concerned “there willbe a real shortage of technical staff and skilled trades tomake this all happen.”

But he is confident Devon, based on its experience inthe Barnett, “will lick” the problems.

Controlling costs key to shale gas playOn the matter of potential resources, Seasons was less

forthcoming on Devon’s 150,000 net acres in theMontney play other than saying it has greater variabilitythan Horn River in terms of reservoir quality, but it doeshold great potential.

Apache Canada president John Crum told the confer-ence the industry will seek ways to curb costs.Otherwise, he said Horn River “will have a hard timemaking it, certainly where gas prices are now.

“Bottom line is, if you can’t get your costs down,plays like this don’t make sense,” he said.

Bruce March, CEO of Imperial Oil, told the confer-ence its joint venture with sister company ExxonMobilplans to drill exploratory wells this winter on the JV’s115,000-acre lease, which will help determine resource

quality and productivity.“This is an area that has demonstrated promise for

significant natural gas resources and pilots by others inthe area,” he said.

Chris Feltin, a research analyst at Tristone Capital,cooled some of the over-heated enthusiasm for HornRiver, suggesting the winter freeze-up and lack of waterneeded to extract gas from the tight rock formationsmakes him question whether there will be enough pro-duction to offset recent declines in Western Canadianvolumes.

Peters & Co. and Wood Mackenzie believe many ofBritish Columbia’s unconventional plays can be eco-nomic at gas prices of C$6.50 per thousand cubic feet,but RBC Dominion Securities analyst Gordon Gee hasraised the threshold to C$8.

AJM Petroleum Consultants CEO Robin Mann has

● N A T U R A L G A S

Devon feeds British Columbia gas frenzyIndependent adds up to 8 Tcf to potential gas resources at Horn River; joins others in warning of cost, infrastructure problems

T

see FRENZY page 14

● O U R A R C T I C N E I G H B O R S

Russian company seeks stake in Total projectKharyaga in Nenets Autonomous Okrug third production-sharing project to come under government pressure after Sakhalin I and II

PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 11

By SARAH HURSTFor Petroleum News

nternational oil companies in Russiawere dealt the latest in a long series ofblows in early September with theannouncement that the country’s Energy

Ministry has approved the sale of a 20-percent stake inthe Kharyaga oil field to state-owned Zarubezhneft.Kharyaga is located in the Nenets Autonomous Okrugand has estimated reserves of 55 million metric tons(376.3 million barrels). It is one of three projects inRussia run on the basis of a Production SharingAgreement, with France’s Total holding a 50-percent

stake, Norway’s StatoilHydro 40 percentand the Nenets Oil Co. 10 percent.

Total has been under pressure fromthe Russian government over its stakein Kharyaga for several years. In 2005

Russia’s environmental watchdog initiat-ed license revocation discussions after

alleging that Total had failed to follow field devel-opment recommendations. The Energy Ministry has nowgiven Zarubezhneft the green light to initiate talks withTotal, and the Russian company will have to decide whatit will pay for the 20 percent. Russian newspaperKommersant quotes an analyst as estimating the value ofthe stake at around $300 million.

The 29-year production-sharing contract forKharyaga was signed in 1995 and came into effect inJanuary 1999, according to Total’s Web site. In Octoberof that year the wells worked over by Total began pro-duction and output tripled to more than 7,800 bpd. Phase2 was launched in 2000 and completed in 2003 with thestartup of new installations.

“The extremely hostile conditions include an icylandscape, just five hours of daylight in winter, and tem-peratures that plunge below minus 30 degrees C,” Totalsaid. “Fast reflexes are a necessity in remote Kharyaga,and with 16 nationalities taking part in the project, flex-ibility is also critical. Although the technology is not par-

I

see STAKE page 12

12 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

Russia may designate offshore oil off-limits

Russia’s Ministry of Natural Resources andEnvironment has proposed the creation of anational reserve of valuable mineralresources that would be kept for future gen-erations and would include most offshoreoil resources. Licenses for these fields mightthen be out of reach for state-owned Rosneftand Gazprom, which have been vying forthem, until the government decides it is time todevelop the oil.

In any case, the Russian companies do not havethe technology or financial resources to develop off-shore oil, the Web site b-port.com reported Sept. 5. Italso noted that a federal natural gas reserve alreadyexists, comprising 31 strategic onshore and offshoredeposits. These include far northern deposits in theRepublic of Sakha, the Yamal-Nenets AutonomousOkrug, and in the Barents, Kara and Okhotsk seas.

—SARAH HURST

Norwegian firm leases BOS 3-D seismic vessel

Geophysical company TGS-NOPEC has signed amutually binding letter of intent with Norway’s BergenOilfield Services for use of the three-dimensional seis-mic vessel BOS Arctic, the companies announced Sept.9. The contract begins in November and lasts for a min-imum of 12 months, with an option for TGS to contractone of BOS’ 3-D vessels for another 12-month periodunder the same commercial terms. The BOS Arctic hasalready completed two projects since her launch in

June2008.

“We feel confident that the BOS Arctic will deliverbest-in-class seismic services to TGS,” said Jan Sovik,BOS’ vice president for marketing and sales. “We arefurther excited to expand our 3-D activity to cover

areas outside the North Sea. BOS will continue toexpand its fleet of operated and owned vessels in thecoming months.” Currently, BOS has two other vesselsin its fleet, BOS Atlantic and BOS Angler, which areboth designed for 2-D seismic data acquisition.

TGS has a worldwide collection of more than fourmillion digital well logs. Coverage is available formajor exploration and development plays worldwide,including North America and the Gulf of Mexico,Russia/CIS, Offshore Northwest Europe, West Africaand Madagascar. In the Arctic, TGS already has datasets from Alaska, Greenland, Svalbard, the Russian

Barents Sea and the Chukchi Sea. —SARAH HURST

Russia’s Rosneft gets first ice-class tanker

Spanish shipyard Factorias Vulcano, atthe port of Vigo, has completed construc-tion of the first ice-class tanker commis-sioned by Russian state-owned oil compa-

ny Rosneft. The 30,000-ton vessel, calledthe Arkhangelsk, will ship oil from the Timan

Pechora province to Murmansk. TheArkhangelsk is designed to work in ice that is over

a meter (3.3 feet) thick and has the capacity to ship25,000 tons of oil.

Rosneft anticipates that the Arkhangelsk will ship1.2 million tons (8.2 million boe) of oil annually to theBelokamenka floating oil terminal in Kola Bay. Thecompany plans to add two vessels similar to theArkhangelsk to its fleet by 2009.

—SARAH HURST

Dutch select Norwegian basefor Russian project

Dutch company Fugro has started using theNorwegian port of Kirkenes as a base for a three-monthtest drilling program around Russia’s Shtokman naturalgas field in the Barents Sea. Russia’s state-ownedmajor Gazprom had asked Fugro to use Russian portssuch as Murmansk. Fugro’s technical manager toldNorwegian newspaper Finnmarken that it is more con-venient to transport people in and out of Kirkenes witha two-hour direct flight to Norwegian capital Oslo, andthat customs declaration of equipment is much easier inNorway than in Russia.

Murmansk port is currently undergoing a modern-ization program and Gazprom intends it to be the mainbase for the Shtokman project. Meanwhile, Norwayalso needs to improve its infrastructure in the north, thehead of the Norwegian Barents Secretariat, RuneRafaelsen, has said.

—SARAH HURST

TGS-NOPEC will contract the BOS Arctic for at least 12 months starting in November.

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ticularly remarkable, the climate is taxing, as the con-stant cold saps energy and slows things down, whilethe lack of sunlight eventually makes people more tiredand irritable. Today, Kharyaga is the focus of ourexploration and production operations in Russia.” ●

continued from page 11

STAKE

With the Hansen 1A 1L well targeting arelatively shallow prospect and being thelongest extended reach well ever drilled inthe Cook Inlet basin’s challenging coalseam-laced geology, it is critical to learnfrom the experience of drilling that wellbefore embarking on the next drilling proj-ect, Owens said.

“Cosmopolitan really becomes a sort ofdrilling Rubik’s cube,” Owens said.“You’ve got to be confident that yourdrilling plan is going to be successful andthat you’ve got the best plan to develop thatresource. Successfully drilling that well wasa big step in the right direction for us,because that really proved to us that thoselong horizontals from onshore can effective-ly produce the reservoir.

“Technically they’re very challengingwells. The technology that exists today indrilling allows these wells to even be con-templated. 10 or 15 years ago they probablywould not have been realistic.”

Pioneer also wants to use the well testresults to learn more about theCosmopolitan reservoir.

2009 wellThe company plans to drill another

appraisal well, this time a separate wellrather than a sidetrack, from the same wellpad in late 2009. That, combined with somefront-end engineering development designwork and some permitting, should lead to adevelopment decision.

“At the end of 2009 we’re hoping tohave a good project design, to have permitsin place and to have a second successfulappraisal well drilled,” Owens said. “At thatpoint we think we’ll have everything inplace to … move forward with a full devel-opment.”

And the development design thatPioneer envisages will entail tanker truckingoil from the well pad to the Tesoro refineryat Nikiski. The trucks would use the existingSterling Highway that runs down the westside of the Kenai Peninsula and the opera-tion would only cause a small increase inhighway traffic, Owens said.

“We’d have processing facilities and atruck-loading rack on site adjacent to theexisting drill pad,” he said. “… We’re in themidst of a third-party transportation riskassessment. The feedback we’ve got is thatthe route is considered very good.”

If Cosmopolitan goes on line, the fieldalso will produce modest quantities of natu-ral gas — the field reservoir has a very lowgas-to-oil ratio, Owens said. Pioneer antici-pates the construction of a 16-mile gaspipeline that runs north to connect into thesouthern end of the existing KenaiKachemak pipeline.

No new explorationGiven the size of Pioneer’s organization

in Alaska and the scale of the company’scurrent activities at Oooguruk andCosmopolitan, the company does not antic-ipate any new exploration for the time beingin its 1 million net acres of North Slope leas-es, Owens said.

“We do not have any exploration drillingplanned for 2009, and that is really due tohaving an awful lot on our plate right now,”Owens said. “… We’re really in a develop-ment phase right now in the Alaska divi-sion.”

But Pioneer continues to evaluate explo-ration opportunities and it works withexploration partners ConocoPhillips andAnadarko Petroleum on a significant chunkof its exploration acreage.

And what about the impact of the state’snew Alaska Clear and Equitable Share oiland gas tax on future exploration and pro-

PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 13

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PIONEER

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see PIONEER page 14

estimated the current average cost ofC$10 million for a Horn River well coulddrop to C$6 million-$8 million as opera-tors adapt to the region.

While resource numbers and costs aregetting juggled, there has been no taper-ing off in the industry willingness to digdeep to stake out positions.

Bidders shift focus to Horn RiverThe B.C. government reported that its

September returns of C$220 millionpushed the total at the midway point ofthe 2008-09 fiscal year over C$2 billion,with the major interest concentrated westof Dawson Creek and north of FortNelson in the Western Horn River Basin,where three drilling licenses fetchedC$98 million.

The leading buyers were StandardLand Co. at C$68 million, Meridian Land

Services at C$22 million and CanadianCoastal Resources at C$7.8 million, all ofthem acting as brokers for unidentifiedclients.

Winning bids ranged from C$4,900 toC$14,400 per hectare (C$1,983-$5,828per acre) as industry attention shiftednorth from the more advanced Montneyarea to Horn River.

In the Montney region, two licensescollected C$26 million, with bids ofC$7,200-C$12,400/ hectare. They arelocated 15 miles west of the Groundbirchfield and 10 miles east of Chetwynd.

Five lease bids averagingC$4,711/hectare to C$5,460/hectare gen-erated C$7.4 million for the Kobes field,30 miles north of Hudson’s Hope.

The total sale offered 105 parcels cov-ering 92,973 hectares, with 94 parcelsand 80,401 hectares selling at an averageC$2,745 per hectare. The bids eased backto a more traditional range after averagesof C$4,596/hectare in July andC$4,359/hectare in August.

The drilling licenses carry an exclu-sive right to explore for petroleum andnatural gas, giving the successful biddersthree to five years to drill wells, depend-ing on location.

Leases carry primary terms of five to10 years.

Focus on B.C. as Alberta reserves decline

Collecting just C$74 million from thefirst of its September auctions, Albertanudged its year-to-date total to C$894million at a per-hectare average ofC$394, compared with C$1.03 billionaveraging C$449 per hectare in the sameperiod last year.

B.C. Energy Minister Richard Neufeldsaid his province is gaining industryattention as its gas reserves have climbedfor eight consecutive years to 17.6 Tcf,while Alberta’s known reserves are indecline at about 48 Tcf.

He suggested that exploration successin B.C. has been a larger factor behind thegeographic shift than Alberta’s royaltyincreases, which take effect in 2009.

The next B.C. sale is set for October15, offering 120 parcels covering 75,768hectares. ●

14 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

Region caught in energy squeezeThe sudden emergence of an energy shortage in northeastern British Columbia

could put a crimp on what is rated as North America’s liveliest gas play.Fort Nelson, the major service center for the Horn River Basin, is caught in an

electricity squeeze that could inhibit gas exploration.“New supply is urgently required” to meet customer demand in the area “under

any scenario of future load growth analyzed,” according to a filing with the B.C.Utilities Commission.

It also says not only is there no capacity to meet economic growth, but someexisting customers are facing the prospect of blackouts.

Currently, Fort Nelson – which is outside the B.C. electricity grid — relies onlocal gas-fired generators for its power, with backup from a public utility in north-western Alberta.

The document, attached to B.C. Hydro’s 2008 long-term electricity purchaseplan, said it is likely B.C. will have to rely on Alberta until at least 2013 for anysignificant power additions.

Although a number of gas companies exploring in the region meet their ownpower needs by using diesel fuel to fire generators, those costs are in danger aslimits are imposed on greenhouse gas emissions and carbon taxes are introduced.

In addition, B.C. Hydro estimates another 100 to 250 megawatts of powercould be needed for Horn River exploration and a possible Spectra Energy proj-ect to pump carbon dioxide into underground storage.

A spokeswoman for B.C. Hydro told the Vancouver Sun that the challenge fac-ing the utility is “huge and rapid growth … it can be difficult to predict where thegrowth is going to be and how much energy we will need. But we want to supporteconomic development in the area.”

That could involve connecting the Fort Nelson area to B.C’s mainline gridrather than spending C$400 million on a 180-mile high-voltage line from thePeace River region of Alberta that would take until 2016 to complete.

Meanwhile, partnerships are being formed by large producers to meet some oftheir own needs in the short term and eventually to tie into the Hydro grid.

–GARY PARK

continued from page 10

FRENZY

duction?“We were very clear along with our peers

in the industry that we felt that ACES tookthe tax rates too high,” Owens said.“Obviously the state has taken a calculatedrisk that it can balance those higher tax rateswith significant incentives on the front end.… Time will tell how it plays out.”

Owens also said that because of the com-plexity of the tax and the fact that the state isstill writing the regulations for implementa-tion, Pioneer isn’t yet clear what the eventu-

al impact of the tax will be.“Companies will have to do a lot of work

to build those regulations into their businessmodels,” Owens said.

And with the prospect of a future gas linefrom the North Slope still beyondPioneer’s 10- to 15-year investment hori-zon, the company is taking a wait-and-seeposition on pipeline proposals.

“Like all prospective shippers we’reinterested in access.” Owens said. “…We’re confident that if and when apipeline is built and if Pioneer has gas toship that we’ll be able to get our gas intothe line.” ●

continued from page 13

PIONEER

PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 15

16 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

● E X P L O R A T I O N & P R O D U C T I O N

Licensees seek more time for NenanaJoint holders Doyon, ASRC and Usibelli ask state to extend basin exploration license to full 10-year term to continue work program

By ALAN BAILEYPetroleum News

aced with the prospect of their statelicense to explore the Nenana basin ter-minating in September 2009, jointlicensees Doyon Ltd, Arctic Slope

Regional Corp. and Usibelli Energy haveapplied to the Alaska Department of NaturalResources for an extension from the currentseven years to the maximum permissibleterm of 10 years. The license would not thenexpire until September 2012.

The license extension application is outfor public review, with comments requiredby 5 p.m. Oct. 15.

The geographical area covered by thelicense includes some state land that wasselected for transfer to the University ofAlaska, as part of a 2005 university trust set-tlement.

“The university has concurred with thisproposed action in accordance with the 2005legislation and settlement agreement,” DNRsaid in a public notice for the proposedlicense extension.

Work commitment metDNR also said the work commitment for

the license has been met to date.In fact, the original licensee, Andex

Resources, contracted PGS Onshore to con-duct a two-dimensional seismic survey inthe Nenana basin in the spring of 2005. Butuncertainty regarding changes in Alaska gas

production taxes as the production profitstax and Alaska Clear and Equitable Shareproduction tax legislation moved throughthe state Legislature put the dampers on fur-ther work.

The companies that now hold the licenselost three seasons of field work because ofchanges in tax policy, Jim Mery, senior vicepresident of lands and natural resources forDoyon, told Petroleum News Sept. 16. Butwith the tax situation settled, the licenseesnow want time to continue the explorationprogram in the basin.

“Our intention is to have a bit more timeso we can explore some more,” Mery said.

Gas prospective basinThe 8,500-square-mile Nenana basin lies

in a long, narrow, northeast trending zonejust a few miles northwest of the town ofNenana, on the Parks Highway about 45miles from Fairbanks in Interior Alaska. Thebasin, which may attain a maximum depthof as much as 16,000 feet, exhibits some-what similar geology to the prolific CookInlet basin and is generally consideredprospective for natural gas.

Only two relatively shallow wells haveever been drilled in the basin and both ofthem were located toward the basin’s edge.

Increasingly tight gas supplies in theCook Inlet region and soaring energy pricesin Fairbanks have heightened interest infinding gas at Nenana.

Andex originally purchased the Nenanabasin exploration license in 2002, with awork commitment of $2.5 million. Thelicense included about 500,000 acres of stateland. Andex also negotiated oil and gas leas-es on about 41,000 acres of Native landowned by Doyon and on about 9,500 acresowned by the Alaska Mental Health LandsTrust in the basin.

Partnership survives Andex exitIn 2004 Andex formed a Nenana basin

exploration partnership with Doyon, ASRCand Usibelli Energy, leading to the spring2005 seismic program. Following seismicacquisition Andex proceeded with theanalysis of the new seismic data, to deter-mine a site for a 10,000 to 12,000-foot wild-cat well.

“Our intention is to have that dataprocessed and interpreted such that we’ll beable to define drill sites so that we can bedrilling our first wildcats next drilling sea-son, in early 2006,” said Bob Mason, Andexvice president of exploration for the north-ern region, at the time. “With success, wecould be moving into the developmentphase based on our initial wells, as early aslate 2006, or 2007, and depending on theresults we see from this drilling, we could bein the process of negotiating, and then final-ly building a pipeline into Fairbanks, suchthat we could have first gas sales in 2008.”

But the spring of 2006 brought the longPPT debate in the Alaska Legislature. TomDodds, president of Andex, told the AlaskaHouse Finance Committee on April 3, 2006,that Andex and its partners had put on holdplanning for a Nenana basin gas explorationwell, pending resolution of the proposedPPT.

In late 2007 Andex finally pulled out ofthe Nenana project; Doyon, ASRC andUsibelli Energy took over the explorationlicense.

In December 2007 Mery told PetroleumNews that Doyon wanted to move aheadwith the Nenana exploration and hoped tofind a new partner for the work.

“Now we’re in a process of trying to getthe project moving again. We’ve lost, ineffect, a 50 percent partner,” Mery said. “…Our goal is to get a drilling rig on the groundin the winter of 2009.” ●

FOn the WebSee previous Petroleum News coverage:

“Andex out of Nenana basin,” in Dec.16, 2007, issue atwww.petroleumnews.com/pnads/135883609.shtml

“Dodds: Andex Nenana drilling on holdpending state of Alaska production tax,”in April 9, 2006, issue at www.petrole-umnews.com/pnads/890875365.shtml

“Nenana gas project analyzing seismic,”in Sept. 4, 2005, issue at www.petrole-umnews.com/pnads/707352753.shtml

PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 17

Fire and Life Safety Specialists

Providing design, installation, repair/service& inspections on fire protection systems.

520 W. 58th St, Ste G, Anchorage, AK 99518 | Phone (907) 569-4340 | coscofire.com

LAND & LEASINGPotential Alaska state and federal oil and

gas lease salesAgency Sale and Area Proposed Date

BLM NE NPR-A Sept. 24, 2008BLM NW NPR-A Sept. 24, 2008DNR Beaufort Sea Areawide Oct. 22, 2008DNR North Slope Areawide Oct. 22, 2008DNR Alaska Peninsula Areawide May 2009DNR Cook Inlet Areawide May 2009DNR Beaufort Sea Areawide October 2009DNR North Slope Areawide October 2009DNR North Slope Foothills Areawide October 2009MMS Sale 209 Beaufort Sea 2009MMS Sale 211 Cook Inlet 2009DNR Alaska Peninsula Areawide May 2010DNR Cook Inlet Areawide May 2010DNR Beaufort Sea Areawide October 2010DNR North Slope Areawide October 2010DNR North Slope Foothills Areawide October 2010MMS Sale 212 Chukchi Sea 2010MMS Sale 217 Beaufort Sea 2011MMS Sale 214 North Aleutian basin 2011MMS Sale 219 Cook Inlet 2011MMS Sale 221 Chukchi Sea 2012

Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, man-ages leasing in the National Petroleum Reserve-Alaska; DNR, Alaska Department of

Natural Resources, Division of Oil and Gas, manages state oil and gas lease sales onshoreand in state waters; MHT, Alaska Mental Health Trust Land Office, manages sales on trust

lands; MMS, U.S. Department of the Interior’s Minerals Management Service, Alaskaregion outer continental shelf office, manages sales in federal waters offshore Alaska.

This week’s lease sale chartsponsored by:

PGS Onshore, Inc.

● A L T E R N A T I V E E N E R G Y

Senate panel OKscoal-to-gas fundsStevens pushes for federal backing of Fairbanks synthetic fuelsproject to cut reliance of Interior military bases on foreign oil

By STEFAN MILKOWSKIFor Petroleum News

AIRBANKS – U.S. Sen. Ted Stevenshas won tentative approval for a $10million grant aimed at jumpstarting asynthetic fuels project near Fairbanks.

The money was included in a draft defensespending bill approved Sept. 10 by aSenate Appropriations subcommittee. Themeasure has yet to pass the full committeeand the full Senate and House.

The money would be used to completefeasibility and environmental studies forthe project, which would use the Fischer-Tropsch process to make synthetic jet fueland other liquid fuel substitutes from coal,Stevens said Sept. 15.

So far, the project has been pushedfrom the Alaska side. The Fairbanks NorthStar Borough put $250,000 toward theproject earlier this year, and state lawmak-ers and Gov. Sarah Palin contributed$300,000 in the 2009 capital budget.

An initial feasibility study by theToronto-based engineering firm HatchLtd. is expected out in a few weeks.

Jim Dodson, president of the FairbanksEconomic Development Corp., which isworking to develop the project, said thenew funding would allow the Air Force topick up where the borough and state leftoff.

“The Air Force’s project is our project,”Dodson said. “What we asked them to dois pick this up as a project.”

The Air Force has made no formalagreement to pursue the project and didnot ask for the funding, according toStevens.

But the Air Force is seeking to reduceits reliance on foreign oil by using synthet-

ic fuels, according to Gary Strasburg, chiefof environmental public affairs for the AirForce.

“We are trying to get all our aircraft cer-tified to fly on blended fuel by 2011, andthen we would like to be able to have halfof the fleet be flying on a 50-50 blend by2016, the idea being that it would encour-age the market to produce a coal-to-liquidsfuel for us to fly on,” he said.

Stevens said the project could help pro-tect Eielson Air Force Base and FortWainwright Army Post from base closureinitiatives.

“If there is another base closure round,these bases are going to be challengedunless they can show that they have along-term supply of available fuel,” hesaid. “What we’re trying to do is reducethe cost to these bases.”

Proponents are looking to develop theproject as a publicly supported privateventure. Current plans call for productionof 20,000 to 40,000 barrels per day of liq-uid fuels, electricity production, and thedistribution of waste heat. Cost estimatesfor the project range from $500 million to$2 billion, according to Fairbanks NorthStar Borough Mayor Jim Whitaker.

Whitaker and Dodson have both prom-ised they will not pursue the project unlessit proves capable of reducing greenhousegas emissions, which have been linked toglobal climate change, either throughincreased efficiency or the use of biomassin place of coal.Stevens said his push forthe federal funds reflects the strong supportfor the project at a July energy summit inFairbanks and the Chena Hot SpringsResort. He said he hoped the spending billwould pass before Congress recesses laterthis month. ●

F

impress on their super-majors that theyhave failed to properly weigh the poten-tial dangers to their reputations.

Niall O’Shea, an analyst with Co-operative Asset, said BP and Shell arecounting too heavily on the emergingcarbon capture and storage technology toreduce carbon dioxide emissions fromoil sands plants by storing them under-ground.

He noted that while carbon captureand storage might have an impact, thetechnology is unproven and won’t beavailable on a commercial scale for 15years.

Investors seek dialogueO’Shea said the objective is not to

stop all development.“But it’s not clear how BP and Shell

are going to manage their risks,” he toldthe Globe and Mail. “There (are) somany uncertainties. We’re asking for adialogue and to understand what theirposition is. We want to protect our long-term investment.”

Alberta Energy Minister Mel Knightcountered that his government willachieve its goal of cutting greenhousegas emissions from the oil sands by 14percent by 2050.

Though carbon capture and storage isstill in its infancy, Knight said it is “defi-nitely” the answer to lowering emissions,noting that EnCana’s Weyburn oil field inSaskatchewan, where CO2 is pumpedinto an aging reservoir, has establishedthe viability of the technology.

Knight said Greenpeace and theBritish funds are taking a short-sightedview.

Shell said it is taking independentsteps to halve emissions from its own oilsands operations by 2010, and BP said itis taking a proactive approach to ensurethat the oil sands play an important rolein energy security.

Greenpeace suedMeanwhile, Greenpeace is being sued

for C$120,000 by Syncrude Canada,which said activists from the environ-mental organization trespassed on theSyncrude site in July as part of theircampaign to halt rising crude productionfrom the oil sands.

The Syncrude consortium is seekingan injunction to prevent Greenpeace fromentering the site in the future, saying theactivists are putting themselves and con-sortium employees at risk.

Greenpeace said the lawsuit isdesigned to “financially cripple a non-profit organization and intimidate criticsof the tar sands.”

—GARY PARK

18 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

Tertiary-aged lower Taglu and Aklakreservoirs in the southern portion of theanticline.

The third well is planned for the north-ern portion of the Ellice anticline and willtest Aklak reservoirs in the crest of theNorth Ellice anticline. The company saidthe North Ellice crestal play has addition-al deeper potential that is unlikely to betested this winter.

The final well, also pinpointed from 3-D seismic acquired by MGM, will test astratigraphic play on the west side ofLangley Island.

It is a new play type for this portion ofthe basin and is analogous to the reser-voirs found at MGM’s Umiak discovery,which has gas resources estimated at 265Bcf.

MGM said it expects to test and com-plete each of the four wells before the endof the drilling season in mid-April, but itcautioned that unforeseen weather andoperating conditions could affect the pro-gram.

The company said existing cashresources, comprised chiefly of fundsraised from an MGM equity issue in July,are sufficient to fund anticipated drillingand logistics costs, plus the company’sother costs for the next year. ●

continued from page 1

MGMcontinued from page 1

INSIDER

● P I P E L I N E S & D O W N S T R E A M

FERC approves LNG terminal in OregonFacility would deliver 1.3 Bcf per day, opponents say regional demand won’t suffice, terminal could create market for Alaska

By ERIC LIDJIPetroleum News

fter more than three years of review, federal regula-tors have approved the first new liquefied naturalgas terminal on the West Coast.

The Federal Energy Regulatory Commission onSept. 18 voted 4 to 1 in favor of letting Bradwood LandingLLC and NorthernStar Energy LLC start work on an LNGreceiving terminal located 38 miles up the ColumbiaRiver in northern Oregon.

The proposed project would deliver up to 1.3 billioncubic feet per day of natural gas to mills and plants in thePacific Northwest. The commission also approved con-struction of a 36.3-mile pipeline from the proposed termi-nal to existing natural gas infrastructure.

Depending on the speed and ease of local and state per-mitting, the companies expect to start building the termi-nal next year and bring the facility into operation by 2012.

The recent decision doesn’t guarantee construction ofthe LNG terminal, though.

As a condition of its approval, the FERC set out 109safety, security and environmental measures, most requir-ing the companies to submit new information to the fed-eral regulators before starting construction on the termi-nal.

New market for Alaska LNGA West Coast LNG terminal would create a domestic

market for exports leaving Alaska.The Alaska Gasline Port Authority, a local group pro-

moting an LNG project to market gas from the North

Slope, began discussions with the companies behindBradwood Landing, as well as with other competing LNGprojects, back in 2005.

“We’ve always assumed that there would be WestCoast markets and opportunities,” said Bill Walker, gener-al counsel and project manager for the port authority.“We’ve been watching them and have been in communi-cation with all of them… We would expect to have morecommunication with them.”

Currently, the Port Authority project is in limbo. Thestate rejected a project proposal submitted by the grouplast year, but Gov. Sarah Palin recently signed an execu-tive order directing her administration to continue pursu-ing an LNG project.

TransCanada, one of two companies working on a pos-sible overland gas pipeline, agreed to include an LNGoption for potential shippers bidding in a future open sea-son.

Views differ on demandProponents of the new LNG terminal like FERC

Commissioner Philip Moeller believe it is the best way toaddress the expected energy demands of the PacificNorthwest.

“The economy of the Pacific Northwest will continue to

grow, and it will continue to need the opportunity to grow,”Moeller wrote in a statement of support. “As its populationbase grows so will its energy consumption.”

He said natural gas supplies from Western Canada are onthe decline, while increased production from fields inWyoming and Colorado is headed eastbound through newpipelines like the Rockies Express, rather than west intoOregon and Washington.

Moeller believes LNG is the quickest and most reliableway to meet rising demand, citing local reluctance towardnew nuclear and coal facilities, the lack of untapped hydro-electric opportunities, and long lead time and unpredictabil-ity of solar and wind in the region.

But opponents like FERC Commissioner JonWellinghoff, who provided the lone opposing vote, arguethat the growth in demand expected across the PacificNorthwest isn’t large enough to support a project the sizeof Bradwood Landing.

“Evidence strongly suggests that the primary purposeof the Bradwood Project is not to meet the projected ener-gy needs of the Pacific Northwest, but rather is to serveother markets,” Wellinghoff wrote in his dissenting opin-ion.

Wellinghoff cited filings from 2006 whereNorthernStar listed California, Idaho and Nevada, in addi-tion to Oregon and Washington, as possible markets forthe facility.

Rather than approve a new LNG terminal, he arguedfor expanding domestic natural gas infrastructure, increas-ing renewable resources and distributed generation tomeet expected demand growth in the region.●

“We’ve always assumed that there would beWest Coast markets and opportunities.”

—Bill Walker, general counsel and project managerfor Alaska Gasline Port AuthorityA

PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 19

“We’ve had cheap and convenient oil,”he said. “Today it’s just convenient.”

Dennis Witmer, director of the ArcticEnergy Technology DevelopmentLaboratory at UAF and a conference organ-izer, said the conference has always high-lighted renewables, but added that the inter-est was much greater now because of highdiesel prices.

The first conference was held in 2002and has been convened every 18 monthssince. Conference workshops focused on thestate’s new renewable energy fund, dieselefficiency, energy economics, and wind,hydro, biomass, geothermal and other proj-ects. Conferees also discussed some railbeltenergy issues.

In an address Sept. 16, Haagenson, whois also the state energy coordinator, spelledout his vision for rural Alaska. He describedthe problem as multi-faceted, with rural res-idents often spending a large percentage oftheir income on energy, and with largeamounts of money flowing out of commu-nities through the purchase of fossil fuels.

Haagenson promoted a shift toward sus-tainable, local energy solutions, and hecalled on local leaders to play an active role.

“This is not just about the state comingto rescue you,” he said. “I want Alaskans tobe engaged in the solution.”

Haagenson said he hoped to complete astatewide energy plan by Dec. 1. The planwill include estimates of energy use in indi-vidual communities, lists of potential ener-gy alternatives, and per-unit cost estimatesfor existing and potential energy projects,he said.

He added that if the state energy planworks as envisioned, the state’s Power CostEqualization program, which subsidizesrural electricity, will no longer be needed.

“That would be my goal,” he said.Several major wind power projects are

already in the works across Alaska, with thefirst large-scale turbines set to be commis-sioned next year in Kodiak.Kodiak Electric Association has alreadyordered three 1.5-megawatt GE wind tur-bines and done site work for a 4.5-megawatt wind project on Pillar Mountain.

“Hopefully by about this time next year,we should be into operation,” said utilitypresident Darron Scott.

The largest wind installation to date is inKotzebue and has a nominal capacity ofroughly 1 megawatt.

According to Scott, the Kodiak projectwas developed in response to a board direc-tive calling for 95 percent of the utility’senergy to come from cost-effective renew-ables by 2020. Kodiak already gets about80 percent of its electricity from hydro, hesaid. The three turbines will provide anadditional 9 percent of the community’sneeds and offset about 800,000 gallons ofdiesel fuel per year.

The $23 million project received a $1million state grant and took advantage of a$12 million federal loan. According toScott, the turbines will create local jobs andproduce power at a cost of about 14 to 16cents per kilowatt-hour, compared with 28to 30 cents for diesel.

“It’s half the price of diesel,” he said, “soit’s a win-win all around.”

Developers are also pushing ahead witha 30–megawatt wind project on Fire Islandnear Anchorage. Alaska Native corporationCIRI and wind power developer enXcoDevelopment, Inc. are pursuing the projectthrough a joint venture called Wind EnergyAlaska.

Steve Gilbert, enXco’s Alaska projectsmanager, said the new company is current-ly evaluating design-build bids from threecontractors and hope to pick one by the endof the year. The company also is working

on a power purchase and sale agreementwith Chugach Electric Association,Anchorage Municipal Light and Power,Homer Electric Association, and GoldenValley Electric Association, he said.

Various entities have pursued the projectsince 2000, but the project stalled in 2005after the Federal Aviation Administrationraised concerns about interference withradar and other equipment. Gilbert saiddevelopers got the go-ahead from the FAAin May after reducing the scope of the proj-ect and commissioning new radar softwareto eliminate interference.

Current plans call for 20 wind turbineswith a nominal capacity of 30 megawatts.The project is expected to cost $130 million,including underwater transmission lines toAnchorage. The state provided $25 millionin this year’s budget for the construction oftransmission lines. Gilbert said he was aim-ing for a construction date of 2010.

Golden Valley Electric Association ispursuing its own 24-megawatt project nearHealy.

“Wind at Golden Valley is attractive eco-nomically right now because it will offsetoil-fired power plants,” said Kate Lamal,GVEA’s vice president of power supply.

But Lamal added that the utility wouldneed to back up its wind generation withother generation to ensure an adequatepower supply in times of low wind. Theutility will need financial help to make theproject a money-saver for consumers, shesaid.

A six-year-old energy-related researchcenter at UAF is losing its core funding andbeing absorbed into a new university entitywith an expanded focus.

The Arctic Energy TechnologyDevelopment Laboratory will become partof the Alaska Center for Energy and Power,a university program formed earlier thisyear. AETDL relied on federal fundingreceived through the National EnergyTechnology Laboratory’s Arctic EnergyOffice. That funding will dry up at the end ofthe federal fiscal year on Sept. 30.

While both university entities conduct

energy research and development, AETDLis focused on fossil fuel resources whileACEP also looks at renewable resources,according to AETDL director DennisWitmer.

ACEP is still without steady funding afterGov. Sarah Palin vetoed $1.5 million in stateand federal funds from the budget earlier thisyear. Gwen Holdmann, the group’s organi-zational director, said she has applied for$10 million in state, federal, and privategrant money and has already secured abouthalf that much. Funded projects involvegeothermal, in-stream hydro, waste heatrecovery, biomass, and other energyresources.Holdmann said she is still lookingfor steady funding for research staff.

On Tuesday, University of AlaskaPresident Mark Hamilton told conferenceattendees the university system is ready tohelp develop energy solutions.

“We can do anything that you and thestate want us to do,” he said.

— STEFAN MILKOWSKI

continued from page 1

RENEWABLES

20 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

Companies involved in Alaska and northern Canada’s oil and gas industry

ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS

AACE Air CargoACS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11 Acuren USAAir Liquide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17Air Logistics of AlaskaAirport EquipmentAlaska Air CargoAlaska Analytical Laboratory . . . . . . . . . . . . . . . . . . . . . . . . .8Alaska AnvilAlaska Computer BrokersAlaska CoverallAlaska DreamsAlaska Frontier ConstructorsAlaska Interstate Construction (AIC)Alaska Marine Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24Alaska Railroad Corp.Alaska Regional Council of Carpenters (ARCC)Alaska Rubber & SupplyAlaska Sales & ServiceAlaska Steel Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5Alaska TelecomAlaska Tent & TarpAlaska TextilesAlaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24Alliance, TheAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16American Tire Corp.Ameri-Tech Building SystemsArctic ControlsArctic Foundations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Arctic Slope Telephone Assoc. Co-op. . . . . . . . . . . . . . . . . . .6Arctic StructuresArctic Wire Rope & SupplyASRC Energy ServicesAurora GeosciencesAvalon Development

B-FBadger ProductionsBaker HughesBombay Deluxe RestaurantBP Exploration (Alaska)Brooks Range SupplyCalista Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Canadian Mat Systems (Alaska)Carlile Transportation Services . . . . . . . . . . . . . . . . . . . . . . .5CGGVeritas U.S. LandCH2M HILLChiulista Camp ServicesColville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2CONAM ConstructionConocoPhillips AlaskaConstruction Machinery IndustrialCosco Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17Crowley Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Cruz ConstructionDelta P Pump and Leasing

Dowland-Bach Corp.Doyon DrillingDoyon LTDDoyon Universal ServicesEEIS Consulting EngineersEgli Air HaulEngineered Fire and Safety . . . . . . . . . . . . . . . . . . . . . . . . . .6ENSR Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Epoch Well ServicesEquipment Source Inc.ESS Support Services WorldwideEvergreen Helicopters of Alaska . . . . . . . . . . . . . . . . . . . . .18Fairweather Companies, TheFlowline Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17FoundexFriends of Pets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17Frontier Flying Service

G-MGBR EquipmentGCIGreat Northern EngineeringGPS EnvironmentalHawk Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Heating & Ventilation SalesHoladay-ParksIndustrial Project ServicesInspirationsJackovich Industrial & Construction SupplyJudy Patrick PhotographyKenai Aviation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23Kenworth AlaskaKing Street StorageKuukpik Arctic Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Kuukpik - LCMFLaBodegaLister IndustriesLounsbury & Associates . . . . . . . . . . . . . . . . . . . . . . . . . . . .12Lynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24MACTEC Engineering and ConsultingMapmakers of AlaskaMAPPA TestlabMarathon OilMarketing SolutionsMayflower CateringM-I Swaco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13MRO SalesMWH

N-PNabors Alaska DrillingNANA/Colt Engineering

Natco CanadaNature Conservancy, TheNEI Fluid TechnologyNMS Employee Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Nordic CalistaNorth Slope TelecomNorth Star Equipment Services (NSES) . . . . . . . . . . . . . . . . .9North Star Terminal & Stevedore (NSTS)Northern Air CargoNorthern Transportation Co.Northland Wood ProductsNorthwest Technical ServicesOffshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Oilfield ImprovementsOpti Staffing GroupP.A. LawrencePanalpinaPDC Harris GroupPeak Civil Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Peak Oilfield Service Co.Penco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Petroleum Equipment & ServicesPetrotechnical Resources of AlaskaPGS Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17Price Gregory (formerly HC Price)Prudhoe Bay Shop & StoragePTI Group

Q-ZQUADCORain for RentSalt + Light CreativeSchlumberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21Seekins FordShaw AlaskaSpenard Builders SupplySTEELFAB3M AlaskaTaiga VenturesTire Distribution Systems (TDS)Total Safety U.S. Inc.TOTE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22Totem Equipment & SupplyTTT EnvironmentalTubular Solutions AlaskaTutkaUdelhoven Oilfield Systems ServicesUnique MachineUnivar USAURS AlaskaUsibelliU.S. Bearings and DrivesVictaulicWesternGecoWeston SolutionsXTO Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3

All of the companies listed above advertise on a regular basis with Petroleum News

Business SpotlightOpti Staffing Group

Opti Staffing Group is a full-service employ-ment agency that specializes in placing topcandidates at Alaska’s busiest companies. Thecompany uses the “candidate-centricapproach.” This means that, instead of focusingon getting as many job orders as possible andthen trying to find people to fill them, Opti per-sonnel constantly evaluate and market top tal-ent to contacts with whom they’ve built strongrelationships. Opti believes skill sets and expe-rience are a significant part to any placement,but equally significant are personality factors.Before every placement, Opti meets withclients in their own environment to assure thebest possible match.

Nick DraineNick Draine arrived in Alaska in 2005. Originally from South Dakota, home of the

Nick Draine, Skilled Trades Recruiter

FOR

RES

T C

RA

NE Sturgis Motorcycle Rally, Nick worked at the

Black Hills Harley Davidson shop. In 2007 hecame into Opti's Office to explore other oppor-tunities, and he’s been there ever since as askilled trades recruiter. In August, Nick and hisbusiness partner Kendra White were major con-tributors to breaking the company’s all-timesales record.

Kendra WhiteKendra White has been with Opti since

2006. She was originally hired as an operationsrecruiter and in September 2007 she acceptedthe position of skilled trades recruiter. With herbusiness partner, the skilled trades team hasbecome the entire company’s No. 1 team. Kendraalso has also made the most marketing calls tocompanies for nine consecutive months, another Opti record. This means she has prob-ably talked to many Petroleum News readers.

—PAULA EASLEY

Kendra White, Skilled Trades Recruiter

FOR

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PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 21

ernment resource owner is largely determined by the gov-ernment’s oil and gas fiscal system — the precise mix andtotal amount of payments made to the government for therights to explore, develop and sell oil and gas resources.”

Balance neededA “fair government take” requires the establishment of

a balance between encouraging private companies to investin oil and gas development and the need to maintain thepublic interest in collecting the appropriate level of rev-enue, Rusco said.

In recent years many countries have responded tochanging market conditions such as increased industryprofits by re-evaluating their revenue collection from oiland gas production. Some countries with uncertain oil andgas resources have actually reduced their government oiland gas take, but many countries have significantlyincreased their take, he said.

Rusco cited a Wood Mackenzie report as identifying themost prominent fiscal trend at the moment as the imposi-tion of windfall profits taxes or other mechanisms toincrease the resource owners’ shares of oil and gas rev-enues.

“For example, the State of Alaska recently increased itsgovernment take and changed the terms of contracts togive Alaska larger shares of revenues as oil and gas pricesincrease,” Rusco said.

At the same time countries such as Algeria, Russia andVenezuela also have tightened their controls over their ownresources, he said.

Attractive targetsU.S. regions such as the Gulf of Mexico remain attrac-

tive targets for oil and gas investment because, in additionto a relatively low government take, they have largeremaining resources and because the United States is gen-erally a good place to do business, when compared withmany other countries with comparable oil and gasresources, Rusco said. And, as oil and gas prices haverisen, the number of drilling rigs operating onshore and off-shore in the United States has increased faster than in therest of the world.

But Wood Mackenzie found that periodic changes infiscal terms coupled with inflexibility of those terms rela-tive to market conditions have resulted in the deepwaterGulf of Mexico being ranked as having a particularlyunstable fiscal system, Rusco observed. Fiscal stability isimportant to oil company investment decisions.

Though the Interior Department does not set tax rates,the agency enjoys considerable latitude in setting royaltyterms for federal leases. Royalty rates, however, cannot bechanged once leases are issued; a consequent lack of flex-ibility in fiscal terms has led in the past to ad hoc changesin royalty rates on new leases, Rusco said.

And an inability for royalty rates to track oil price fluc-tuations may result in unduly low government revenues.Royalty reductions at times of low oil prices, for the Gulfof Mexico between 1996 and 2007, for example, could endup costing the federal government billions of dollars whenoil prices are high, he explained.

Need for reviewThere is a need to review the entire oil and gas fiscal

system, including taxation, when determining the levels ofroyalty rates, Rusco said.

“Because Interior has not comprehensively re-evaluatedthe federal oil and gas fiscal systems for over 25 years,such a comprehensive evaluation of the systems, both on-and offshore, is overdue,” Rusco said. “Comparing oil andgas fiscal systems and attractiveness for investment isinherently complex and Interior has not collected informa-tion needed to perform such a comprehensive review.”

The review needs to take into account the views ofindustry experts, as well as using the Interior Deparement’sown expertise, Rusco said.

GAO also recommends that Congress consider direct-ing the Secretary of the Interior to have MMS and otherInterior agencies establish procedures for comparing feder-al oil and gas regimes with those of other resource ownersand report the results of the comparisons to Congress,Rusco added.

In response, Steven Allred, assistant secretary of theinterior, said that a comprehensive evaluation of fiscal sys-tems would be premature because MMS has already com-missioned a study into leasing and revenues in the Gulf ofMexico (GAO responded by commenting that it viewedthe MMS study as too restricted in scope).

Allred further said new procedures for comparing oil

and gas regimes are not appropriate because MMS andBLM already do this, in effect, as part of their existing pro-cedures and because the question of what other resourceowners do is not the most important consideration whendesigning fiscal terms for leases.

MMS evaluates situationMMS evaluates the expected oil and gas resources and

the current market conditions “in light of our organicstatutes and tax laws” when setting fiscal terms for leasesales and analyzing sale results, Allred said. MMS analysisof lease sale results includes a determination of whetherfiscal terms are working as intended.

“Studies and literature are reviewed related to fiscalterms and potential economic, fiscal and geologic out-comes in different countries and regions operating underdifferent fiscal terms,” Allred said.

And GAO has not clarified the link between the level ofgovernment take and the attractiveness of an oil provincefor investors, Allred said.

“It is important to point out that global companies havechoices where they make capital investments,” Allred said.“Their investment choices are affected by many variables,including the fiscal risk of rents, royalties, and bonus bids,as well as the cost of capital, risk and the attractiveness ofalternative investments.”

An increase in government take could result in a loss ofdomestic oil and gas production, he said.

Rather than being inflexible, MMS has shown flexibil-ity in establishing fiscal terms for oil and gas leases in theGulf of Mexico, with the deepwater Gulf of Mexico royal-ty reductions of 1998 and 1999 being “consistent withanticipated technical, as well as market, conditions at thetime of sale,” he said.

MMS and BLM are both investigating the use of slidingroyalty scales in the future, he said.

Interior bureaus have achieved the purposes of theOuter Continental Shelf Lands Act and the Federal LandPolicy and Management Act in achieving goals such as fairmarket value, encouraging competitive oil and gas devel-opment, protecting the environment and achievingresource conservation, Allred said.

“Maximizing federal mineral revenues or achievingsome worldwide ranking of government take are not pur-poses in the existing laws guiding federal oil and gas pro-grams,” Allred added. ●

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REVENUES

ration news in the coming weeks.This winter is the first exploration sea-

son following revisions to the tax code gov-erning oil and gas production in Alaska.The revised code, called Alaska’s Clear andEquitable Share, or ACES, included anexpansion of tax credits designed to pro-mote exploration.

Early reports from the oil patch suggestthis winter could be notable for its lack offirst-year exploration ventures. Last winter,several large and small companies struckout on ambitious multiyear programs withvarying degrees of success.

As a result, some details of the comingseason might not become available untillater in the year, as companies begin apply-ing for drilling permits. However, earlyword suggests some of the more activeplayers last winter plan to return to the fieldin the coming season.

Anadarko stakes three in NPR-AAnadarko looks to be expanding its

search for natural gas in the foothills of theBrooks Range this winter with a move intothe NPR-A.

Earlier this month, the independent with

extensive land holdings in Alaska stakedthree exploration wells around the WolfCreek prospect located 30 miles due westof the historic Umiat field and the ColvilleRiver in the northwest portion of thereserve.

The proposed well locations sit on a sin-gle federal lease — AA-86604.

A notice of staking is generally the firststep toward drilling an exploration well in afrontier area like the NPR-A, but it is noguarantee that a well will ultimately bedrilled.

By detailing the proposed surface loca-tion for a well, literally with a stake driveninto the ground, the notice gives federalland managers a chance to start site inspec-tions, which could uncover possible surfaceissues, like the location of proposed iceroads or ice pads.

Because the notice doesn’t cover issuesunderground, Anadarko will need to applyfor and receive a drilling permit, as well asother permits, before starting any wells.

Anadarko remains cautious about thenotices of staking becoming wells this year.

“We’ve staked some locations to poten-tially drill next winter,” said spokesmanMark Hanley.

If drilled, the three wells, Wolf CreekNo. 4, No. 5 and No. 6, would likely tar-

get gas.The U.S. Navy drilled Wolf Creek No. 1

in the spring of 1951, finding gas in theChandler formation at 1,500 feet. The wellflowed at a rate of 881,000 cubic feet perday of gas, but the Navy never quantifiedthe resource potential of the prospect.

Anadarko picked up the Wolf Creekprospect during a 2006 lease sale in theNPR-A, following several previous acqui-sitions of nearby acreage in the foothills.

Wolf Creek follows Gubik wellAnadarko made history this past winter

with an exploration program deliberatelytargeting natural gas. Previous gas discov-eries in northern Alaska have either beenaccidental, or incidental to more substantialoil finds.

This past winter, Anadarko drilled twowells, Gubik No. 3 and Chandler No. 1, onNative land east of the Colville River nearUmiat, also in the foothills of the BrooksRange.

The Gubik field, like the Wolf Creekprospect, dates back to exploration wellsdrilled across the region in the early 1950sby the Navy and the U.S. GeologicalSurvey. Those wells found gas in the PrinceCreek, Chandler and Ninuluk formations,leading the USGS to estimate total gas

reserves at Gubik at around 600 billioncubic feet.

By the end of the drilling season thispast spring, Anadarko “encountered naturalgas in two zones” with Gubik No. 3, butsuspended drilling at the deeper ChandlerNo. 1 well.

Anadarko left Nabors rig 105-E atChandler for the summer, with the intentionof possibly returning to finish the well thiswinter. The company also secured Naborsrig 245-E, which is currently stacked atOliktok Point.

Plans could play into lease saleAnadarko previously proposed well

locations for five other Gubik wells.The independent could further consoli-

date its holdings in the foothills in the com-ing week.

The large swatch of land between theWolf Creek and Gubik prospects is avail-able as part of the upcoming northeastNPR-A lease sale scheduled for Sept. 24.

Anadarko declined to comment on theupcoming lease sale.

The company is already one of thelargest leaseholders in Alaska, with muchof its acreage spread across the gas-pronefoothills of the Brooks Range. The result ofAnadarko’s drilling on those leases couldhave broad implications for the state in thecoming years.

Though Anadarko hasn’t publicly esti-mated the potential gas reserves in thefoothills recently, Enstar Natural Gasbelieves the Gubik find might justify asmall-diameter pipeline into SouthcentralAlaska to help offset declining gas fields inthe Cook Inlet basin.

But a series of larger gas discoveriesspread across several prospects in theBrooks Range foothills could change thesupply dynamics for a larger pipeline run-ning into Canada and the Lower 48. Twoproposals to build that line depend onknown gas accumulations at legacy oilfields further north on the Slope.

Currently, no major natural gas infra-structure exists in northern Alaska.

Anadarko is partnering with BG Groupand PetroCanada on its exploration pro-gram in the foothills. Anadarko partnerswith ConocoPhillips on other projects inthe state.

BRPC plans Gwydyr Bay wellsA joint venture lead by Brooks Range

Petroleum Corp. is moving forward with adevelopment plan for several prospectsnorth of Prudhoe Bay on Alaska’s NorthSlope.

The four-company partnership plans todrill as many as three wells this winter,exploring two prospects along the GwydyrBay coastline, between the Sakonowyakand Kuparuk rivers.

The goal is to prove up possible reservesenough to justify developing the prospects.

Though no development plans havebeen filed with the state, the joint venture iscurrently running economic models andstarting early engineering work related tofuture facilities, according to HillaryMcIntosh, manager of business develop-ment and external affairs for BRPC. Shesaid the companies expect to apply for adevelopment unit this fall.

The joint venture, which includes part-ners TG World Energy Corp, Bow ValleyAlaska Corp. and Nabors subsidiaryRamshorn Investments Inc., led one of thebusiest exploration programs on the NorthSlope this past winter, drilling two wellsand a pair of sidetracks, as well as acquir-ing a portfolio of 3-D seismic data.

The drilling program this year dividedBRPC’s efforts over two prospects, one atGwydyr Bay and another near the villageof Nuiqsut to the south. This winter the

22 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008

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EXPLORATION

see EXPLORATION page 23

company will focus on Gwydyr Bay,drilling wells at the North Shore and SakRiver prospects.

BRPC drilled the North Shore No. 1exploration well in 2007, and tested thewell this year at a rate of 2,092 barrels perday of oil from the Ivishak formation. Amechanical problem down hole compro-mised a test of the shallower Sag River for-mation, but one partner predicted the wellcould have hit flow rates up to 1,000 bpd ifunencumbered.

This winter, BRPC plans to drill theNorth Shore No. 3 exploration well fromthe same pad used to drill North Shore No.1. The well will require the company tobuild five miles of ice road, connectingexisting gravel roads in Prudhoe Bay to thesouth, according to operations plans filedwith the state in August.

A little more than a mile to the north,BRPC also plans to drill Sak River No. 1A,a sidetrack of a dry hole the companydrilled in 2007. If the well is successful,the company would also drill a secondsidetrack, Sak River No. 1B.

Expanded holdings over summerThe proposed exploration program fol-

lows a summer where the joint ventureexpanded its Gwydyr Bay land holdingsby acquiring 5,120 acres from PioneerNatural Resources. The three state leasesincluded the Pete’s Wicked oil prospectdiscovered by BP in 1997.

After the land acquisition, the fourcompanies met to discuss strategies for“establishing a threshold” at Gwydyr Bay,or finding methods of developing the tightgrouping of fields and satellites in theregion in the most economic manner.

Speaking to investors in June, CliffordJames, TG World Energy president andCEO, mentioned several proposals, whichincluded using the North Shore pad to testtwo satellites and drilling lateral wellsfrom Sak River to test the Kuparuk forma-tion.

James also mentioned lumping the var-ious prospects into two general productionareas, one at North Shore and another atPete’s Wicked and the Arcturus prospect tothe east.

JV returns seismic to front burnerThe joint venture also plans to shoot 3-

D seismic next March or April over itsSlugger prospect south of Point Thomsonon the eastern edge of the central NorthSlope.

The companies had planned to shoot130 square miles of seismic earlier thisyear, but postponed the program becauseof travel restrictions on the North Slope.

“It’s crying for seismic to firm up someof these prospects,” James said in June.

The companies picked up the Sluggerleases in October 2007.

Chevron back to White HillsChevron will return to the White Hills

prospect this coming winter to continue amultiyear and multiwell program startedthis past winter.

In the early months of the year, the com-pany drilled three exploration wells at theprospect in the foothills of the BrooksRange just west of the Dalton Highway.

The seven- or eight-well explorationprogram represented a return to northernAlaska for Chevron after nearly 15 yearsfocused on Cook Inlet.

In paperwork filed with the state beforethe White Hills program began, Chevrondetailed locations for seven wells at theprospect. This past winter, the companydrilled Smilodon 9-4-9, Mastodon 6-3-9and Panthera 28-6-9 using Nabors rig106E.

The company plans to use the rig againfor work at White Hills this winter.

Chevron named the proposed wells atWhite Hills after prehistoric animals,including Stegodon, Gulo, Megatheriumand Titanothere.

Over the summer, Chevron brought onTotal E&P USA Inc., a subsidiary of theFrench major Total S.A., as a 30-percentpartner on the project. Total currently holdsextensive state acreage in the Beaufort Sea,

and once held federal acreage in the NPR-A.

Chevron has declined to identify the tar-get of the White Hills effort, or release anyresults from the first year of the drillingprogram, calling it a “tight” venture.

Eni gets Nikaitchuq permitsEni Petroleum recently secured its first

drilling permits for the Nikaitchuq offshoreunit in the Beaufort Sea. The Alaska Oiland Gas Conservation Commission issuedpermits for a development well and servicewell, both located at Oliktok Point.

The Italian major sanctioned the $1.45billion project this past January, laying outa plan for drilling around 80 wells from acombination of onshore and offshore pads.The company also plans to build independ-ent processing facilities to support the unit.

ExxonMobil moves on Point ThomsonEarlier in the year, ExxonMobil

announced plans to drill exploration wellsin the Point Thomson unit this winter,despite complex geology and even morecomplex legal issues.

The Texas-based major recently bargedequipment and supplies to the easternmoststate unit on the North Slope, just west ofthe Arctic National Wildlife Refuge, in

preparation for a $1.3 billion program todrill up to five wells and bring the unitonline by 2014.

The spending includes $20 million inupgrades to Nabors Rig 27E. Though therig has racked up significant mileageacross the North Slope over the past fiveyears, it is not currently designed to handlethe high-pressure reservoir at PointThomson.

The upgraded rig is expected to arriveon the North Slope by the start of the year.

As ExxonMobil prepares to drill, thecompany remains tied up in legal battleswith the state Department of NaturalResources over the status of the unit.

Earlier this year, the state terminated thePoint Thomson unit and revoked all butone of the leases, saying ExxonMobil has-n’t done enough to develop the unit overthe past 30 years. ExxonMobil still consid-ers itself a leaseholder, though, saying thestate had no legal basis for revoking theleases. The parties remain in court over thematter.

The various parties have until mid-October to update the court on mediationattempts. ●

PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008 23

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EXPLORATION

Contact Eric Lidji at 907-770-3505or elidji@petroleumnews.com

24 PETROLEUM NEWS • WEEK OF SEPTEMBER 21, 2008