page6

McGuire proposes geothermal creditfor 400 megawatt plants for 4 years

Vol. 14, No. 2 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of January 11, 2009 • $2

� L A N D & L E A S I N G

� N A T U R A L G A S

� N A T U R A L G A S

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

4 A partner other than Enstar? Governor backed ANGDA-Enstar partnership; ANGDA has RFP out for due diligence on company X

5Shrugging off woes: BC natural gas players geared for active

winter; EnCana-Apache lead drilling; EnCana progresses on major plant

11 Chugach blames price: Electric utility says price main stickingpoint in negotiations; faces natural gas supply shortages in 15 months

Rendition of BP’s new Liberty rig. See story below in Oil PatchInsider.

CO

URT

ESY

BP

Petro-Hunt pulls outDallas-based company drops its bids from the September NPR-A lease sale

By ALAN BAILEYPetroleum News

ust three months after successfully bidding on72 lease tracts in the U.S. Bureau of LandManagement’s September 2008 NationalPetroleum Reserve-Alaska lease sale, Dallas-

based Petro-Hunt LLC has elected to relinquish allof its bids and forfeit its deposit of $2.75 million.Petro-Hunt had been the top bidder in the sale withtotal bonus bids amounting to $13.7 million.

In a Jan. 7 notice announcing receipt of finalpayments on high bids from the lease sale, BLMsaid that Petro-Hunt had notified the agency in lateDecember that “falling oil prices made it uneco-nomical for it to pursue oil production at this timewithin the National Petroleum Reserve-Alaska.”

Alaska North Slope crude oil prices peaked ataround $144 in July but have since dropped pre-cipitously. According to the Alaska Department ofRevenue the West Coast spot price for Alaskacrude was $42.98 on Jan. 6.

Costs too highIn September Herbert Hunt, advisor to Petro-

At current oil prices Petro-Hunt cannotjustify expenditure on NPR-A oil leases,given the Alaska tax structure and thehigh cost of doing business in the state,

Herbert Hunt told Petroleum News Jan. 7.J

see PETRO-HUNT page 19

Heat on Mackenzie panelStrong opposition to delay in release of findings, now set for end of this year

By GARY PARKFor Petroleum News

panel reviewing the proposed MackenzieGas Project pipeline is under pressure torelease its findings within three months andnot at the end of 2009.

According to the Canadian Broadcasting Corp.,the two agencies that founded the Joint ReviewPanel in August 2004 along with then-federalEnvironment Minister Stephane Dion, havedemanded that the panel hasten its work.

CBC said it has obtained a letter to panelChairman Robert Hornal from the chairmen of theMackenzie Valley Environmental Impact ReviewBoard and the Inuvialuit Game Council, which

A

see MAC PANEL page 19

New Enstar gas recordCold snap in Southcentral AK causes highest ever delivery of gas to customers

By ALAN BAILEYPetroleum News

emperatures dipping to minus 16 onJan. 3 in Anchorage may have putsomething of a nip in the air, butthings heated up for Enstar Natural

Gas Co., the main gas utility forSouthcentral Alaska, as customers tookto their gas-heated homes to escape fromthe cold.

At 234 million cubic feet, Jan. 3 saw the largestever daily delivery of gas to Enstar’s customers,Enstar spokesman Curtis Thayer told PetroleumNews.

“The last record was on Jan. 9, 2007,” Thayer

said. That previous record was 227 mil-lion cubic feet, he said.

After factoring in other gas thatEnstar flows through its pipeline net-work for entities such as electric utilitiesand the military, Enstar’s total through-put on Jan. 3 was 314 million cubic feet.That compares with a total throughput of292 million cubic feet on the record set-ting day in 2007.

CEA recordChugach Electric Association, one of the two

electric utilities that supply Anchorage, delivered

TCURTIS THAYER

see RECORD page 18

2009 sealift includes Liberty,Prudhoe rigs, Nikaitchuq equipment; Parker openingAlaska office; Dowland-Bach sold

FIVE BARGES WILL BE PART of a Crowley sealift toAlaska’s North Slope in the summer of 2009. BP’s Libertyrig will be on two of the barges — new 455 series barges —and will depart Washington on July 1. Doyon Drilling’s newworkover rig for Prudhoe Bay will departat the end of July on a 400 series Crowleybarge; and two other barges loaded withequipment for Eni’s Beaufort SeaNikaitchuq oilfield development willdepart in early June from Houma, La.

All five barges are expected to arrivein the Beaufort Sea off Alaska’s NorthSlope at about the same time, in earlyAugust.

The information came from severalPetroleum News sources, but the BPLiberty and Prudhoe information, sans the specific bargeseries data, was confirmed by BP on Jan. 8, and the Eniinformation coincides with the company’s development plansfor its Beaufort Sea Nikaitchuq project, which is expected tocome online at the end of 2009.

see INSIDER page 18

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

2 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

6 McGuire proposes geothermal tax credit

Prefiled bill would credit 35 cents per kilowatt hour for 4 years of geothermal generation of at least 400 kilowatts of electricity

5 Shrugging off woes

BC Natural gas players geared for active winter; EnCana-Apache lead drilling; EnCana launches 1st phase of major processing plant

7 Refinery’s struggles cause for concern

If Flint Hills’ North Pole refinery ceases operations, the Alaska Railroad and the Anchorage airport would both be hit hard

4 Partner other than Enstar for ANGDA?

Governor backed ANGDA-Enstar gas spur line pairing;ANGDA seeks RFP for due diligence on unnamed firm

3 Winning the numbers game

Another year before new SEC rule allowing 12-month average price takes effect

14 Alberta oil sands facing a new enemy

Financial crisis forces a corporate retreat from oil sands;billions of dollars of planned investment now on theshelf; Alberta government urged to rethink royalties

NATURAL GAS

OUR ARCTIC NEIGHBORS

ALTERNATIVE ENERGY

FINANCE & ECONOMY

3 SEC approves new rules for oil reserves

9 One of two unused berths may be removed

8 Russian company to explore in Pechora Sea

8 Safety level high at Norwegian LNG plant

8 Offshore development pushed in Norway

PIPELINES & DOWNSTREAM

SAFETY & ENVIRONMENT

17 Proponent touts coal-to-liquids plant

11 Chevron gets second White Hills permit

12 Evaluating the Foothills natural gas

10 Watching out for the ice in Cook Inlet13 ANS production down on Valdez weather

10 McKay replaces Malone at BP America

10 Don’t get accustomed to cheap oil

13 Fourth explosion targets EnCana in B.C.

11 Chugach blames stalemate on price

15 Western Canada beats 2007 rig count

EXPLORATION & PRODUCTION

1 2009 sealift includes Liberty, Prudhoe rigs, Nikaitchuq equipment

18 Parker to open office in Anchorage; Parker’s Husband, Nabors’ Korach to speak at Meet Alaska

18 Koniag buys Dowland-Bach

18 No news on Exxon invitation to State of Alaska officials

OIL PATCH INSIDER

ON THE COVERPetro-Hunt pulls out

Dallas-based company drops its bids from the September NPR-A lease sale

Heat on Mackenzie panel

Strong opposition to delay in release of findings,now set for end of this year

New Enstar gas record

Cold snap in Southcentral AK causes highest ever delivery of gas to customers

By GARY PARKFor Petroleum News

ithin a year Canadian energy pro-ducers — notably those in the oilsands — should emerge victori-ous from their prolonged battle

with the Securities and ExchangeCommission over U.S. reserves rules.

Effective Jan. 1, 2010, they can applya 12-month average price to estimatetheir reserves, instead of being forced touse the price on Dec. 31.

But the oil sands sector will still haveto endure another year of writedowns thatwill likely wipe hundreds of millions ofbarrels deemed to be uneconomic offtheir books.

A year ago bitumen producers werereveling in the crude price tidal wave thatallowed them to book reserves at US$70per barrel, a figure that climbedtoUS$100 by midyear before starting theprecipitous second-half descent thatdragged heavy crude prices to aboutUS$25 on Dec. 31 — a level that makesmost oil sands projects too costly to beviable and prevents companies frombooking their reserves as proven.

The SEC regulation infuriated leadingproducers, including ExxonMobil,Suncor Energy and Shell Canada, as wellas Cambridge Energy ResearchAssociates, who called for changes torules dating back to 1978.

Criticisms of old systemThe critics said the system was

increasingly at odds with the realities ofthe oil and gas industry of the 21stCentury, arguing it was ironic that com-panies were spending billions of dollarsto develop oil they could not list asreserves, even though the end productwas finding its way into the tanks ofAmerican vehicles.

They also argued it was unfair to use aDec. 31 price in determining reserves,given that bitumen reaches its lowestpoint in winter as demand for the productdrops.

The new rules will also allow compa-nies to claim possible and probablereserves, in addition to the current systemthat limits them to proved developedreserves.

As well, oil sands producers will beable to book their bitumen reserves as oiland gas resources, not just miningreserves.

The SEC itself acknowledged theflaws in the old regulations, saying the“use of the average price will maximizethe comparability of reserves estimatesamong companies and mitigate the distor-tion of the estimates that arises whenusing a single pricing date.”

Final rules not publishedAlthough the SEC has yet to publish

the final rules, despite adopting the newrules on Dec. 29, Canadian producers are

hopeful the change will reduce the impactof price volatility when they estimate thevalue of assets they own.

But they have still to escape the conse-quences of last year’s price nosedive.

“Any oil sands companies filing U.S.-type disclosure for the 2008 year-end mayhave to write off a significant portion oftheir proved bitumen reserves, given thatbitumen prices are extremely low rightnow,” said Phil Welch, president of the

consulting firm of McDaniel &Associates.

Writedowns won’t necessarily affectshare values, assuming producers are ableto re-book that oil at the end of 2009, buta drop in reserve values could make iteven tougher for producers to negotiatedebt given that banks use reserves as a keyindicator of corporate long-term viability,Chris Feltin, an analyst with TristoneCapital, told the Globe and Mail. �

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 3

� F I N A N C E & E C O N O M Y

Winning the numbers gameAnother year before new SEC rule allowing 12-month average price takes effect

“Any oil sands companies filingU.S.-type disclosure for the 2008year-end may have to write off asignificant portion of their proved

bitumen reserves, given thatbitumen prices are extremely low

right now.” —Phil Welch, president, McDaniel & Associates

WSEC approves new rules for oil reserves

The Securities and Exchange Commission on Dec. 29 approved updated rulesfor energy companies that will require them to provide more detailed informationto investors when reporting oil and gas reserves.

Reserves are an oil company’s most valuable asset and a critical indicator of itslong-term financial prospects. Any reduction in their estimated size is a concernfor investors.

The SEC’s reporting rules for oil and natural gas reserves were adopted morethan 25 years ago, and the changes are intended to reflect technological changesin how oil companies determine their proven reserves.

“These updates to the SEC rules will help ensure more meaningful and com-prehensive disclosure of information that, even though it does not appear on acompany’s balance sheet, is of significance to investors in making informedinvestment decisions,” SEC Chairman Christopher Cox said in a statement.

Changes approved unanimouslyThe changes were proposed in June and opened to a 60-day public comment

period. The SEC approved the changes unanimously. The newly adopted revisions: *Allow companies to use new technologies to determine proven oil and gas

reserves provided the technologies have been shown to lead to reliable assess-ments.

*Allow companies to disclose their probable and possible reserves to investors.Until now, SEC rules limited disclosure only to proved reserves.

*Require companies to report oil and gas reserves using an average price basedon the prior 12-month period rather than year-end prices.

*Require companies to certify the independence of petroleum auditors thataudit their assessments of reserves.

The American Petroleum Institute, the industry’s trade association, said it wasreviewing the new rules and had no immediate comment.

In August 2004, the SEC fined Royal Dutch/Shell Group $120 million — oneof the largest penalties against a company in an accounting case — in connectionwith the overstatement of oil and gas reserves. The Anglo-Dutch oil giant’s dis-closure that year of reserve inflation stunned shareholders and the oil industry, andled to the dismissal of several top executives.

The company neither admitted nor denied wrongdoing in agreeing to pay thecivil fine.

—THE ASSOCIATED PRESS

By KRISTEN NELSONPetroleum News

ast summer Alaska Gov. Sarah Palinchallenged the Alaska Natural GasDevelopment Authority to examinethe possibility of a public-private

partnership with Enstar Natural Gas todevelop an in-state gas spur line.

Enstar’s role in the partnership wasdescribed in a statement from the gover-nor’s office “as engineering, construct-ing, operating and maintaining thepipeline.”

ANGDA is beginning evaluation ofanother possible partner.

In a request for proposals issued Jan. 6ANGDA said it wants to know whethercompanies other than Enstar should beconsidered for this partnership and saidits board “has a fiduciary responsibility toseek out other interested companies andseeks a contractor to perform due dili-gence on a publicly traded company,which will be known as COMPANY X.”

ANGDA Chief Executive OfficerHarold Heinze told Petroleum News in aJan. 7 e-mail that “company X is a spe-

cific unidentified publicly traded largepipeline company.” He said the compa-ny’s identity will be revealed to the con-tractor selected in the RFP process “on aconfidential basis.”

Information on the company should beavailable through its U.S. Securities andExchange Commission filings, Heinzesaid.

The report to be prepared under theRFP will be useful to ANGDA’s board ifa deal involving company X comes to theboard, he said, and “will also provide acontrast to the board in its considerationof Enstar” as a potential partner in thespur line project.

The RFP has a budget not to exceed$100,000. A draft report is due March 16and a final report April 20.

The selected contractor will provide areport “specifying the precedent condi-tions for forming a public/private pipelinepartnership under Alaska Natural GasDevelopment Authority’s statutoryauthorities”; a list of desirable financialand operational parameters for the privatepartner in the partnership; an estimate ofcompany X’s conformance to thoseparameters “based on a review of publicinformation filed with the RegulatoryCommission of Alaska and other agen-cies”; and an estimate of company X’sability to satisfy regulatory requirementssuch as “fit, willing and able.”

Governor selected EnstarThe governor “announced the forma-

tion of a public/private partnership” July 7and named ANGDA, Enstar and the Stateof Alaska as the partners, to “build thefirst phase of a bullet line to bring Alaskagas to Alaskans within the next fiveyears.”

Palin said there was synergy: Enstar asa proven operator; ANGDA which canprovide public financing; and the State ofAlaska’s ability to expedite the projectand potentially ensure lower tariff ratesfor an in-state pipeline.

Goals included delivery of natural gasto Southcentral and Interior Alaska withinfive years; spurring exploration and devel-opment of new natural gas resources inthe Cook Inlet and Copper River basins

and providing long-term supplies of natu-ral gas for Southcentral and InteriorAlaska.

Construction of the line would start inthe south and move north, reachingFairbanks and Interior Alaska by 2013. Ifnew sources of natural gas are not devel-oped in Cook Inlet or along the way tofeed the line, construction could then pro-ceed north and access natural gas suppliesin the North Slope Foothills or beyond,making them available to Southcentraland Interior Alaska by 2014. If that phaseis not needed, the in-state line could beconnected to the main North Slope linewhen it is completed in 2018-20.

The governor’s office said in the July 7statement that the development was in ini-tial stages and details would take a fewmonths to develop, with a recommendedstructure and more details targeted forrollout in the fall of 2008 and any neces-sary enabling legislation or appropriationto be sought in the legislative sessionbeginning this January.

Different routesBoth ANGDA and Enstar have been

studying bringing natural gas toSouthcentral, but have been looking atdifferent routes: ANGDA the GlennHighway to Palmer, to connectSouthcentral Alaska with a mainline mov-ing North Slope natural gas to market, andEnstar the Parks Highway throughWasilla. Enstar has been talking withAnadarko Petroleum about moving natu-ral gas from the Gubik field in the NorthSlope Foothills where Anadarko is doingexploration drilling.

The statement released by the gover-nor’s office in July said the state believesthe Richardson Highway route, whichwould then follow the Glenn Highwayinto Southcentral, is “the best for thestate” because of the state’s “interest inreaching the populations, communities,and military and industrial facilities alongthe Richardson Highway.”

The state is also a resource owner inthe Copper River Valley, and “has a sig-nificant interest in promoting the explo-ration and development of natural gas inthat basin,” the governor’s office said. �

� N A T U R A L G A S

Partner other than Enstar for ANGDA?Governor recommended ANGDA-Enstar gas spur line partnership; ANGDA has RFP out for due diligence on unnamed company X

4 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

Kay Cashman PUBLISHER & EXECUTIVE EDITOR

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OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 14, No. 2 • Week of January 11, 2009

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www.PetroleumNews.com

CORRECTIONSara Brown was misquoted in an article, “North in a rage,” in the Dec. 21 issue

of Petroleum News. The article said: The Inuvik Town Council on the Delta demanded that mem-

bers of the JRP (Joint Review Panel) should be fired, with the town’s senioradministrative officer Sara Brown saying she is not aware of anyone who isn’t“frustrated at this point.”

The article went on to say: In one of the strongest condemnations yet of theJRP she said there is “certainly quite a high degree of incompetence” on the panel,echoing the Inuvik council which accused the JRP of “gross incompetence.”

In an e-mail to Petroleum News Brown said: “Although I did make the firststatement regarding frustration, I did not make the other comments attributed tome in the article.”

Petroleum News apologizes for the error.

L

By GARY PARKFor Petroleum News

orget weak natural gas prices and ableak economic outlook, players innortheastern British Columbia’s siz-zling Montney and Horn River plays

are swinging into action, with plans for anactive winter drilling season and infra-structure programs.

Having laid out more than C$3.5 bil-lion over the past two years to secureexploration rights, producers are ready toembark on full-scale drilling efforts toestablish reserves that will allow them tonominate for space on pipelines out of theregion.

Calgary-based investment dealerPeters & Co. forecast in a research notethat drilling, casing and completionspending will reach C$1.38 billion for 250wells in the Montney tight gas play andC$660 million for 60 wells in the HornRiver shales.

The firm suggests that despite a waveof capital spending cuts for 2009, BritishColumbia resource play expendituresshould be better able to withstand troubledtimes, adding that planned spending atMontney and Horn River “remains sub-stantial.”

Bolstering the confidence levels,EnCana — involved in a large-scale joint-venture with Apache in the region — hasrolled out initial plans for what could be amultibillion-dollar gas processing facilityin the Horn River basin.

In a project description for its CabinGas Plant, filed with the British Columbiagovernment, EnCana estimates it couldspend C$400 million on the first phase ofa six-stage development, although futurephases will depend on future production.

The plant, to be located 40 miles north-east of Fort Nelson, is designed to process400 million cubic feet per day when itstarts operation in 2011.

Without any fanfare, EnCana submit-ted the project outline in November underthe province’s environmental assessmentprocess, which is usually the forerunner toa formal regulatory application and publichearings.

EnCana is heading the project onbehalf of the Horn River Basin Shale GasProducers Group, involving seven othercompanies that are poised to spend hun-dreds of millions of dollars tapping tril-

lions of cubic feet of gas reserves.

Technological advancesTrapped in complex rock formations

once thought too costly and challenging todevelop, the Horn River shales — likethose in the Barnett and Haynesville playsof the United States — have seized thespotlight in recent years as a result oftechnological advances, the prospect ofhigher gas prices and shrinking suppliesof conventional gas.

Initial wells in British Columbia costabout C$10 million each to drill and bringon stream, but the use of multiwell padsfor horizontal wells, with as many as 20wells per pad, have dragged costs down toC$7 million per well and reduced theenvironmental impact.

Mike Graham, president of EnCana’sCanadian Foothills division, said his com-pany is determined to “drill a lot of wellsoff a single pad and really try to get ourcosts down.”

So far, he said, the big independent isencouraged by the trends and its produc-tion rates are now “pretty stable,” withone well averaging about 8 million cubicfeet per day over its first month.”

Graham said EnCana and Apacheprobably control about half the HornRiver play and based on data gathered todate, he predicted production will “growvery rapidly” to more than 100 millioncubic feet per day by the end of 2009.

However, he conceded that if commod-ity prices drop sharply it is also one playEnCana is ready to postpone.

Imperial Oil and sister companyExxonMobil Canada have accumulatedabout 115,000 acres in Horn River and arein the preliminary phase of developing aprogram, including modest winter workthat could involve drilling wells to get abetter fix on the resource.

Target 1 bcf per dayEnCana has set an initial target of 1 bil-

lion cubic feet per day for its Horn River

production, based on results from about adozen test wells and, along with Apache,expects to drill about 40 wells this year.

The project description for the gasplant says a single facility to serve all pro-ducers is preferable, for environmentaland economic reasons, to several smallerplants.

As well as processing raw gas for ship-ment to markets, the plant would also beavailable for carbon capture and seques-tration opportunities “assuming appropri-ate fiscal programs can be implemented”— a reference to industry hopes of gov-ernment financing to develop CCS tech-nology.

Richard Neufeld, who has resigned asBritish Columbia’s energy minister to takea seat in the Canadian Senate, toldreporters he has had no indication thatcompanies are planning to scale backspending in Horn River.

Even though the programs have yet toreach the “massive” category, there willbe some “serious” work in Horn River thiswinter as the region develops as a keylong-term source of gas, he said.

Describing the Horn River gas as partof a long-term prospect, he said gas willbe a “transitional fuel” over many decadesand could eventually take a larger role intransportation based on established tech-nology.

John Tasdemir, who heads institutionalresearch at Tristone Capital, said plans forthe current winter exploration season mayhave been trimmed slightly in recentweeks, but expects companies will pushahead in the belief that the economics willimprove as the play is “de-risked.”

Like EnCana, Tristone anticipates full-cycle, all-in costs will decrease overtime,

with Montney costs already easing andHorn River likely to follow, Tasdemirsaid.

Pipelines working on deliveryHeating up the activities, pipeline com-

panies TransCanada and Spectra Energyare working with potential shippers ondelivery systems.

TransCanada said it plans to finalize anapplication with the National EnergyBoard in the current quarter for a new 42-inch line to serve Montney.

The Groundbirch Pipeline would be anextension of its Alberta network, providedthe board approves TransCanada’s appli-cation for its wholly owned NOVA GasTransmissions to move from Alberta tofederal jurisdiction.

That attempted switch was in responseto a binding open season whenTransCanada sought expressions of inter-est from producer in northeastern BritishColumbia to transport about 1 billioncubic feet per day by 2012, with an in-service date of late 2010.

In competition with TransCanada,Spectra has held a binding open season forgas transmission facilities in the region,starting with 260 million cubic feet perday of incremental volumes on the east-bound Alliance pipeline, plus 135 millioncubic feet per day of incremental west-bound shipments expected to be in servicein the final quarter of this year.

Watching these developments is thepartnership of Pacific Northern Gas andKitimat LNG, which is counting on rapidexpansion of British Columbia’s gas pro-duction to support its C$4.2 billion Pacific

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 5

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

Shrugging off woesBC Natural gas players geared for active winter; EnCana-Apache lead drilling; EnCana launches 1st phase of major processing plant

Mike Graham, president ofEnCana’s Canadian Foothillsdivision, said his company is

determined to “drill a lot of wellsoff a single pad and really try to

get our costs down.”

F

see WOES page 6

By KRISTEN NELSONPetroleum News

s Alaska ready for geothermal-generat-ed electricity? Alaska Sen. LesilMcGuire, R-Anchorage, thinks so andhas prefiled legislation proposing a pro-

duction tax credit for geothermal energysystems that generate at least 400 kilowattsof electricity. She said that over time geot-hermal-generated electricity would “signif-icantly cut the cost of energy for Alaskahouseholds, business-es and industry.”

“The time is rightto get serious aboutgeothermal energy asa practical reality,”McGuire said in aJan. 2 statement. “It’sproven and producingin climates and geolo-gy similar to Alaska.”

She led a delegation of western statelawmakers at November conferences inReykjavik, Iceland, reviewing energy andeconomic policy opportunities and issues.

“Iceland is lighting and heating homesand industry and growing fresh fruits andvegetables for 5 cents a kilowatt,” McGuiresaid, calling for that same “vision inAlaska” and “incentives to develop our owngeothermal resources.”

McGuire said her bill would defray aportion of state corporate income tax thatwould be paid by an operating geothermalplant.

Credit for first four yearsThe bill provides that a taxpayer-owned

commercial geothermal electric energy sys-tem which can produce at least 400 kilo-watts of electricity could claim a productiontax credit of 35 cents for each kilowatt hourof geothermal electricity produced or soldduring the first four years of operation if thesystem provides energy for commercialunits owned or used by the taxpayer or ifthe taxpayer sells all or part of the energyproduced by the system.

McGuire said the best known geother-mal development in Alaska is that of BernieKarl at Chena Hot Springs northeast ofFairbanks, “but that should be the begin-ning for many geothermal developments inAlaska.”

While the Alaska Energy Authority lists

a number of possible geothermal areas —Mount Spurr, Mount Makushin, ManleyHot Springs, Pilgrim Hot Springs, Naknek,Tenakee Hot Springs, Pelican, Hoonah,Akutan, Bell Island in addition to ChenaHot Springs — some of those may only bepractical for small-scale geothermal devel-opment, the senator said, while the AlaskaEnergy Authority estimates that MountSpurr and Mount Makushin could supportlarger-scale power production.

Recent state saleThe State of Alaska received some $3.5

million in apparent high bids on 16 tracts atMount Spurr in a September lease sale,with three bidders participating and Reno-based Ormat Nevada picking up 15 of thetracts.

Ormat Nevada had approached theAlaska Department ofNatural Resources tosee if the MountSpurr area, last leasedby the state in the late1980s, could be madeavailable for geother-mal leasing.

Ormat Nevada is asubsidiary of OrmatTechnologies whichspecializes in geothermal power world-wide.

Paul Thomsen, director of policy andbusiness development for OrmatTechnologies told Petroleum News inSeptember that the company has beenlooking at Mount Spurr and Mount

Makushin for some 15 years. He said thecompany has looked at the markets andthinks Alaska “is ripe for developing a baseload geothermal resource.”

There is also activity on federal lands inAlaska.

The U.S. Bureau of Land Managementapproved some 190 million acres of feder-al land for geothermal leasing Dec. 18 in12 western states, including Alaska.

The Ring of Fire resource managementarea in Alaska has 992,785 acres open forgeothermal leasing (with 20 megawatts ofpower possible from geothermal by 2015

and some 150megawatts by 2025)and more than 3 mil-lion acres in theCentral Yukonresource managementarea, although BLMdoes not project anyelectric generationfrom Central Yukongeothermal resources.

There are pending applications for three2,560-acre federal leases at Bell IslandHot Springs in Southeast Alaska for a 20-megawatt power plant to provide powerfor Bell Island Hot Springs and possiblyfor nearby Yes Bay Lodge via an under-water cable. �

6 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

Trail project to ship liquefied naturalgas from the deepwater port at Kitimatto Asian markets.

The partnership expects to knowearly this year whether gas producersendorse its argument that there is a“compelling opportunity … to takeadvantage of the natural gas price gapbetween the lower prices in NorthAmerica and the higher prices in Asia.”

It hopes to complete an environmen-tal assessment by March and is in talkswith 17 First Nations who have tradi-tional land interests along the route.

The plan involves a 280-mile exten-

sion from an existing Pacific NorthernGas pipeline to a liquefaction terminalat Kitimat.

Despite global economic woes, therehas been strong interest in the projectsaid Kitimat LNG Vice President IleneSchmaltz, partly because “the big play-ers in the LNG business tend to be long-term thinkers.”

She said Kitimat LNG dropped itsplans to import LNG because of BritishColumbia’s “plentiful and expandingsupplies of natural gas,” including fore-casts of a three-fold increase in theprovince’s output to 10 billion cubicfeet per day by 2020 — more than 60percent of Canada’s total current vol-umes — and major LNG shortfalls inglobal markets. �

continued from page 5

WOES

� A L T E R N A T I V E E N E R G Y

McGuire proposes geothermal tax creditPrefiled bill would credit 35 cents per kilowatt hour for 4 years of geothermal generation of at least 400 kilowatts of electricity

McGuire said her bill woulddefray a portion of state corporateincome tax that would be paid byan operating geothermal plant. I

On the WebSee previous Petroleum News coverage:

“Feds complete geothermal leasingplan,” in Dec. 28, 2008, issue atwww.petroleumnews.com/pnads/914714756.shtml

“$3.5 million in high bids,” Sept. 14, 2008,issue atwww.petroleumnews.com/pnads/655426834.shtml

“Unalaska seeks drilling company forgeothermal project,” in June 1, 2008,issue atwww.petroleumnews.com/pnads/156568830.shtml

LESIL MCGUIRE The State of Alaska receivedsome $3.5 million in apparent

high bids on 16 tracts at MountSpurr in a September lease sale,with three bidders participatingand Reno-based Ormat Nevada

picking up 15 of the tracts.

By WESLEY LOYAnchorage Daily News

shutdown of the Flint HillsResources refinery at North Polehas potential to rattle theAnchorage economy, and state offi-

cials are working with the company tofind a way to keep the plant going.

Flint Hills, part of Kansas-based KochIndustries Inc., has indicated its agingrefinery is struggling financially becauseof last year’s record high prices for crudeoil used to make such products as jet fuel,heating oil and gasoline.

The company has put the refinery upfor sale, and other options include con-verting it into a receiving station for dis-tributing but not making fuels, said Kochspokeswoman Katie Stavinoha.

Last year, the company also mentionedpossibly upgrading the refinery, but suchan investment has now been deemed “noteconomically justified,” she said.

State and local officials are worriedabout the fate of the refinery, located 360miles north of Anchorage.

Two key enterprises have the mostcause for concern:

*The Alaska Railroad.Nearly every day, a train hauling most-

ly jet fuel makes the run from North Poleto Anchorage. These fuel shipments arevital business for the railroad, generating$41 million, or 36 percent of its combinedfreight and passenger revenue in 2007.

*The Ted Stevens AnchorageInternational Airport.

The Anchorage airport is one of theworld’s busiest pit stops for cargo jets,and they and other aircraft drank down864 million gallons of jet fuel in 2007.The Flint Hills refinery makes roughly 60percent of the jet fuel pumped at the air-port, state officials say.

If the refinery were to cease produc-tion, the Alaska Railroad couldn’t run asmany trains, would have to cut its payrolldramatically, and would need to raiserates for moving passengers and otherfreight such as coal and gravel, said rail-road board chairman John Binkley.

At the airport, fuel sellers likely wouldhave to ship in more fuel from Outsidesuppliers, which could push up prices andmake Anchorage less attractive as a stopfor international air cargo carriers, stateofficials said.

“Flint Hill is one of our star assets,”said Bill Popp, president of theAnchorage Economic DevelopmentCorp. He’s hoping the state will work inearnest to find ways to keep the refinerymaking fuels.

State buyout? On Dec. 10, Gov. Sarah Palin

announced the state had launched a“cooperative effort” to help Flint Hills. Apress release from her office suggestedthe refinery could end up as part of theAlaska Railroad, a state-owned corpora-tion.

But that’s not the ideal outcome,Binkley said later in the month.

“No, the railroad doesn’t want to buy arefinery,” he said. “And the railroad does-n’t want to be in the refinery business.But the railroad wants there to be a refin-ery at North Pole, Alaska.”

The refinery started up in 1977, thesame year the nearby trans-Alaska oilpipeline began carrying Prudhoe Bay

crude oil.The refinery uses a 2½-mile spur line

to tap the big pipe for crude that’s cookedinto finished products. Flint Hills buysthe oil at market rates, plus a premium ofmore than $1 a barrel, from the state,which receives a royalty share of NorthSlope production.

Jet fuel is the refinery’s biggest prod-uct, accounting for about 60 percent of itstotal output. It also makes a lot of heatingoil, plus a dab of gasoline.

In terms of capacity, the North Polerefinery is the state’s largest. Flint Hillshas owned it since July 2004, when itbought the plant from the Williams Cos.

No sweetheart dealKevin Banks, the state’s oil and gas

director, negotiated the 2004 contract tosell state oil to Flint Hills for up to 10years.

In October, two top Flint Hills execu-tives, President Brad Razook and ChiefFinancial Officer Tony Sementelli, cameup from the company’s Wichita head-quarters to meet with Banks and otherstate officials.

They wanted to talk about ways the

state might provide some relief for therefinery, which struggled in 2008 as oilcost in excess of $100 a barrel, Bankssaid.

The executives didn’t provide a wishlist, Banks said, though ideas includechanging the oil supply contract to, forexample, get rid of the premium the statecollects on each barrel.

Flint Hills has agreed to turn overfinancial information to prove it’s beenlosing money, he said.

The state has hired a Dallas energyconsulting firm, Baker & O’Brien, to helpanalyze the Flint Hills data, a process thatcould take three to six months, accordingto the governor’s office.

State officials want to see how theplant fares not only when oil prices arehigh but when prices are much lower, asthey are now, Banks said.

One way the state could help FlintHills would be to lower the sales price ofits royalty oil. But Banks said the courtshave held the state can’t give select com-panies a “sweetheart deal” on stateresources.

Past threatsMight the state simply buy the refin-

ery?“It’s an option that would be consid-

ered,” Banks said.Asked what, exactly, Flint Hills wants

from the state, Stavinoha, the companyspokeswoman, said only: “We’re open to

a broad range of options.” She declined tomake the executives, Razook andSementelli, available for an interview.

Flint Hills has approached the statebefore with threats to shutter the plantunless it received state concessions. Inearly 2006, Sementelli sent a letter seek-ing a change in the state oil supply con-tract.

“We are not asking for a subsidy orhandout,” he wrote, but noted the contin-ued operation of the refinery was in jeop-ardy.

State officials refused Sementelli’srequest.

Aside from Flint Hills, the state’s onlyother major refinery operator is TesoroCorp. of San Antonio, Texas, which runsa plant at Nikiski on the Kenai Peninsula.Tesoro’s top product also is jet fuel for theAnchorage airport, but it also makesmuch of the state’s gasoline.

The high cost of crude oil made lifemiserable last year not only for motoristsfilling up their cars and trucks, but alsofor refiners, said Tesoro spokesman KipKnudson.

“Flint Hills is thought of as a highlycompetent operator,” he said inDecember. “I would assume they’vestruggled for three quarters like we have.”

Koch Industries, which owns FlintHills, is a large but privately held compa-ny. Publicly traded Tesoro has seen itsstock price plunge by more than 70 per-cent last year. �

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 7

DECADES PROUDDECADES AHEAD

Oil & Gas ExplorationALTA/ACSM Surveys3-D Laser Scanning

Planning & PermittingUtility & Drainage Projects

Commercial Site DevelopmentResidential Development

Highway DesignTraffic EngineeringStatewide Service

www.lounsburyinc.com

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

Refinery’s struggles cause for concernIf Flint Hills’ North Pole refinery ceases operations, the Alaska Railroad and the Anchorage airport would both be hit hard

AIn terms of capacity, the North

Pole refinery is the state’s largest.Flint Hills has owned it since July

2004, when it bought the plantfrom the Williams Cos.

By SARAH HURSTFor Petroleum News

pening areas of the Norwegian con-tinental shelf currently closed to oiland gas activities could increaseinvestment by 200-250 billion kro-

ner ($28.8-$35.9 billion) in 2022-40,according to a new report by industryassociation KonKraft. The study alsofound that leaving such acreage closedwould hasten the decline in capital spend-ing on the continental shelf, so that invest-ment could be at 20 percent of today’slevel by 2030.

“This study focuses on measures whichcan combat a future decline in oil and gasoutput,” said Per Terje Vold, chief execu-tive of the Norwegian Oil IndustryAssociation. “It also shows that Norwaystands to lose substantial revenues, expert-ise and investment if today’s politiciansfail to make wise choices over the nextcouple of years. The report identifiesopportunities for limiting the expectedproduction fall,” he added.

KonKraft makes proposals for specificmeasures to help curb a rapid decline inoil and gas production from theNorwegian continental shelf. Theseinclude maximizing recovery from exist-ing fields, maintaining a high level ofexploration and making a continued com-mitment to new technology and modes ofoperation. “The report also points out that

making large discoveries is imperative iflevels of production and investment are tobe maintained,” Vold said. “Opportunitiesfor new finds are greatest in areas current-ly closed to petroleum activities.”

Plateau reachedAfter almost 40 years of virtually unin-

terrupted growth, overall production of oiland gas on the Norwegian continentalshelf has reached a plateau at a daily rateof 4-4.5 million barrels of oil equivalent,the report said. It is expected to remain atthis level for the next seven years, and tostart declining around 2015. Oil outputhas already fallen, but the overall level hasso far been kept high by rising gas pro-duction.

An estimated 25-65 billion barrels ofoil equivalent will remain on the conti-nental shelf in 2015. The range of the esti-mate is wide because 45 percent of theresources are yet to be discovered, accord-ing to KonKraft. In many cases, it willtake up to 15 years between the award ofa license and production starting, thereport said, so decisions taken or avoidedtoday will have major consequences forthe level of production and activity in2020 and beyond.

Areas such as Nordland VI and VII,Troms II, Barents Sea North and the dis-puted zone with Russia are regarded as themost promising places for finding large oiland gas deposits, the report said. TheNordland VI area is currently protectedagainst all petroleum-related activities,and only seismic mapping is allowed inthe Nordland VII and Troms II areas.These blocks are all near the Lofotenregion, home to important fisheries forNorway where possible oil and gas devel-opment is extremely controversial.

Former CEO says no impactOpening the area around Lofoten

would have no negative impact on thefisheries, former Statoil CEO ArveJohnsen told Norwegian newspaperNordlys in December. “Since the verystart, the Norwegian petroleum industryhas been more environmentally friendlyand environmentally oriented than in anyother part of the world. In the course of 40years, we have not had a single blowout,”Johnsen said.

Northern Norway is entering an unusu-ally interesting 50-year period, which isunprecedented in the region, Johnsen toldthe newspaper. The petroleum industrywill raise the knowledge level and indus-trial capacity in the region, he added.Johnsen also expressed dismay that therehas been local opposition to a 100 percentoffshore development of the Goliat oil andgas field in the Barents Sea, which isoperator Eni Norge’s preferred plan. �

8 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

Safety level high at Norwegian LNG plantNorway’s Petroleum Safety Authority has conducted an audit of StatoilHydro

and selected contractors relating to management of working-environment condi-tions at the Melkoya LNG plant, which is part of the offshore Snohvit project inthe Barents Sea. The audit, which took place in mid-November, focused on howStatoilHydro identifies and follows up groups in relation to the risks they areexposed to in the working environ-ment.

“We have observed that systemat-ic work takes place to improve theworking environment on Melkoya,”the authority said in a release Dec.23. “Among other things, anoverview has been established ofrequirements in the working environ-ment area, and StatoilHydro hasemployed an occupational healthtechnician who has conducted verifi-cations and measurements as regards chemicals and noise. We have also seen thatboth StatoilHydro and the main contractors BIS, Aibel and ESS … have proce-dures in place to follow up employees on sick leave.”

The authority identified one nonconformity in relation to the regulatoryrequirements: The systematic mapping and risk assessment of working environ-ment factors on the part of groups employed by contractors is inadequate.Improvements could also be made in the areas of follow-up and facilitation foremployees with reduced ability to work; overview and follow-up of occupationalillness on the part of contractors; training regarding working environment risk forgroups employed by contractors; and assessments of the overall exposure situa-tion and hazards that could cause injuries, the PSA said.

—SARAH HURST

Russian company to explore in Pechora Sea Arctic Marine Engineering Geological Expedition, a Russian company based

in Murmansk, has received government permission to conduct exploration workin two areas at the Dolginskaya field in the Pechora Sea, BarentsObserver report-ed Dec. 22. The work will take place in the vicinity of four exploration wells inthe Dolginskaya-4 and Dolginskaya-5 prospects. Dolginskaya is located near thebetter-known Prirazlomnoye field.

AMIGE specializes in offshore hydrocarbon mapping. The company wasestablished in 1980 and it has four exploration vessels at its disposal.

—SARAH HURST

The authority identified onenonconformity in relation to the

regulatory requirements: thesystematic mapping and risk

assessment of workingenvironment factors on the part ofgroups employed by contractors is

inadequate.

� O U R A R C T I C N E I G H B O R S

Offshore developmentpushed in NorwayOil and gas production will decline if new Arctic areas notopened, report says; fishery, dispute with Russia, both obstacles

O

By KRISTEN NELSONPetroleum News

here are four crude oil loading berthsat the Valdez Marine Terminal butonly two are in use due to reducedthroughput in the trans-Alaska oil

pipeline and modern ship design whichreduces the time a tanker must spend at aberth.

The Trans-Alaska Pipeline System car-riers (BP, ConocoPhillips, ExxonMobil,Koch and Unocal) have applied to theRegulatory Commission of Alaska to per-manently discontinue use for crude oilloading of the two berths no longer usedfor that purpose.

The carriers said in a Dec. 12 filing thatthey are uncertain whether RCA approvalis required and that the filing is done “as aprecautionary matter.”

There are four berths at the terminal,Berths 1, 3, 4 and 5. While there is spacebetween Berths 1 and 3 for Berth 2, thatberth was never built because after thetrans-Alaska oil pipeline became opera-tional it was determined that Berth 2 wasnot needed, the carriers said.

Berth 1 is a floating berth, 390 feet longand 96 feet wide with 13 buoyancy cham-bers, four 12-inch loading arms and a load-ing rate capacity of 80,000 barrels perhour. The berth has been used for crude oiltransfer and as an off-loading point fordiesel fuel consumed at the Valdez MarineTerminal. The berth is capable of beingtransported to a different location by water.

Berth 3 is a fixed platform berth, 122feet long and 46 feet wide with four 16-inch loading arms and a loading ratecapacity of 100,000 barrels per hour.

Berth 3 has been used for crude oiltransfer in the past, but has not been usedfor diesel fuel off-loading. “Berth 3 willcontinue to be used and useful as a layoverberth where tankers and other vessels canbe moored for purposes other than loadingcrude oil,” the carriers said.

No vapor recovery armsBerths 1 and 3 are no longer needed for

crude oil loading. Throughput on the trans-Alaska oil

pipeline peaked at some 2.1 million barrelsa day in the late 1980s, but has sincedeclined to about one-third of that rate,some 700,000 bpd by year-end 2007. Thatdecline in production has resulted in adecline in tanker traffic. When oil through-put was at its peak, the four berths at theterminal “were needed to handle a con-stant stream of tankers. However, today itis not uncommon for several days to elapsebetween tanker callings,” the carriers toldRCA.

The other issue is that while Berths 4and 5 are equipped with vapor recoveryarms to collect vapors released duringtanker loading, Berths 1 and 3 do not havevapor recovery arms. Installation of sucharms costs approximately $20 million perberth, the carriers said and current federalenvironmental regulations require vaporrecovery equipment for berths loadingcrude oil.

The Environmental Protection Agencyallowed loading of crude oil withoutvapor recovery at Berths 1 and 3 until2002. The carriers said EPA recognizedthat Berths 1 and 3 would not need vaporcontrols and allowed for that in its regula-tions.

In addition to reduced throughput inthe pipeline, modern segregated ballastingsystems on tankers that call at the ValdezMarine Terminal have reduced by approx-imately half the time a tanker must remainat a berth.

The carriers said that in the pastbecause of deballasting and loadingrequirements a tanker would remain atberth for some 18 hours, “whereas todaymodern tankers seldom need to deballastat the berth, and crude oil loading requiresan average of approximately nine hoursper vessel.”

Berths no longer neededBecause of these two changes, Berths 1

and 3 are no longer needed. Berth 1 waslast used for crude oil loading in 2001 andBerth 3 in 2002. Berth 1 was last used fordiesel fuel transfer in 2002.

The plan for Berth 1 is to sell it for useor for salvage value, “if either of thoseoptions is determined to be economical.Until then, Berth 1 can be used for pur-poses other than loading crude oil.”

The carriers said they plan to continueto use Berth 3 indefinitely for purposesother than loading crude oil. It is frequent-

ly used as a layover berth whenHinchinbrook Entrance is closed due toadverse weather in the Gulf of Alaska, forcrew member medical evacuations, forvessel repairs or in support of oil spilldrills.

Berth 1 has been used “only very infre-quently since 2002” for non-crude oilloading purposes.

Unused piping associated with crudeoil loading will be removed from Berths 1and 3, the carriers said, including remov-ing all hydrocarbons from the piping atthose berths.

The work is planned for May throughSeptember this year.

The carriers requested that RCA deter-mine whether an application for discontin-uation of use of Berths 1 and 3 for crudeoil loading is required and if so, make afinal finding so that necessary work canbegin by April 15 and so that Berth 1 canbe sold if a buyer can be found. �

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 9

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

One of two unused berths may be removedTwo of four Valdez berths not in use for loading crude; Berth 1 may be sold; Berth 3 will continue in use for other functions

T

10 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

� F I N A N C E & E C O N O M Y

McKay replaces Malone at BP AmericaPETROLEUM NEWS

amar McKay is replacing Bob Malone as chairmanand president of BP America Inc.

Malone is retiring after 34 years with BP, the com-pany said Jan. 6.

“Bob Malone has made anextraordinary difference during histenure at BP America and during hislong career with BP,” BP ChiefExecutive Officer Tony Haywardsaid in a statement. “We are a bettercompany because of his ability toconnect with the men and womenwho operate and maintain our facil-ities and his unflagging commit-ment to safe operations. All of us atBP appreciate what he has done and wish him well in hisnext endeavors.”

Malone spent seven years in Alaska, arriving in 1993

when he was named president of BP PipelinesAlaska. He became president of AlyeskaPipeline Service Co. in 1996 and left the state inJune 2000 when he was named BP Amoco’sregional president, Western United States.

Prior to his appointment as chairman andpresident of BP America in 2006, he was chiefexecutive of BP Shipping Ltd. from 2003-06.

McKay earlier with BP AmericaMcKay, a member of the BP p.l.c. Executive

Management Team, has led the company’s SpecialProjects Team since early 2008. In that capacity, he playeda major role in establishing a new governance model forTNK-BP, BP’s Russian joint venture. Prior to that assign-ment, he served as executive vice president and chiefoperating officer for BP America and brings deep knowl-edge of BP’s US operations to his new position.

McKay joined Amoco Production Co. as a petroleum

engineer in 1980 and later served in a variety ofoperating and commercial roles. During hiscareer he has led upstream production business-es in the Arkoma basin, the Gulf of Mexico andthe North Sea. After working on the BP-Amocomerger, he led BP’s worldwide exploration andproduction strategy efforts followed by a post-ing as chief of staff for the company’s globalexploration and production business. Prior tohis first assignment with BP America, he servedas group vice president for Russia and

Kazakhstan. McKay holds a Bachelor of Science degree in petrole-

um engineering from Mississippi State University. He andhis wife Nancy will be based in Houston, where BP busi-ness units are involved in oil and gas exploration and pro-duction, refining, chemicals, supply and trading, pipelineoperations, shipping, and alternative energy. Houston ishome to nearly 7,000 BP employees. �

L

LAMAR MCKAY

BOB MALONE

� F I N A N C E & E C O N O M Y

Don’t get accustomedto cheap oilCutbacks in exploration now will help fuel price increase whendemand heats up again; some see oil topping $150 per barrel

By JOHN PORRETTOAssociated Press Writer

ll that money you’re saving thesedays at the gas pump? You mightwant to put it in the bank.

The same cheap oil that’s pro-viding relief to drivers and businesses inan awful economy is setting the stage foranother price spike, perhaps as soon asnext year, that will bring back painfulmemories of last summer’s $4-a-gallongas.

The oil industry is scaling back onexploration and production because someprojects don’t make economic sensewhen energy prices are low. And crude isalready harder to find because morenations that own oil companies are block-ing outside access to their oil fields.

When the world emerges from therecession and starts to burn more fuelagain, and higher demand meets lowersupply, prices will almost certainly shoothigher.

Some analysts say oil could eventuallyeclipse $150 a barrel, maybe even on its

way to $200. In such a scenario, gasolinewould easily cost more than the recordhigh of $4.11 a gallon set last summer. Oiltrades at about $50 today.

Spike could be as soon as ‘09No one knows for sure, but some ana-

lysts say the spike could happen as soonas next year, perhaps in 2011 or 2012.

“I think those supply limits will comeback to bite with a vengeance,” said SeanBrodrick, a natural resources analyst atWeiss Research Inc.

High prices at the pump last summer— more than $4 per gallon for gas onaverage — helped slash demand for oil.From November 2007 to October 2008,Americans drove 100 billion fewer milesthan the year before, according to govern-ment figures. The nation’s biggestautomakers lurched toward bankruptcy assales of sport utility vehicles and trucksplummeted.

“We wouldn’t be bailing out the auto-mobile industry today ... had we not had

SAFETY & ENVIRONMENTWatching out for the ice in Cook Inlet

The U.S. Coast Guard and industry are working together to improve safety for CookInlet marine traffic by increasing the observation of ice conditions in the inlet, USCGannounced Jan. 6. The USCG Marine Safety Detachment Kenai and Tesoro Alaska, theoperator of the Nikiski oil refinery, have initiated weekly aerial ice patrols, USCG said.

“The patrols provide an overall pictureas to what ice formations, thicknesses andconcentrations are occurring at variouslocations within the inlet,” said PettyOfficer 3rd Class Mark Worral, MarineSafety Detachment Kenai. “This informa-tion is used to determine the implementa-tion of the winter ice guidelines in the inlet,which affect local mariners and facilities.”

As well as conducting the aerial patrols,the Marine Safety Detachment conductsdaily on-land patrols on foot and by car,generally during the flood tides when icefloes are at their heaviest at the Nikiskidock. Coast Guard personnel conduct spotchecks of vessels moored at Nikiski, to ensure that vessel operators are taking appro-priate measures to mitigate the impacts of sea ice.

The National Oceanic and Atmospheric Administration publishes ice forecasts forCook Inlet three times a week, USCG said. These forecasts use reports on ice condi-tions provided by industrial facilities in the inlet, by vessel operators and by the marinepilots who board vessels in the inlet.

The Coast Guard uses ice condition reports and the NOAA forecasts to determinehow to apply its ice guidelines and additional safety measures, to minimize the risk ofa marine accident in the inlet.

The use of USCG ice guidelines resulted from the occurrence of several marineaccidents in 1999 as a consequence of severe ice conditions. The Coast Guard revisedits guidelines and increased its ice reporting measures after a 2006 incident when seaice plucked the tanker Seabulk Pride from its moorings at the Nikiski dock and causedthe tanker to run aground.

—ALAN BAILEY

The National Oceanic andAtmospheric Administration

publishes ice forecasts for CookInlet three times a week, USCGsaid. These forecasts use reports

on ice conditions provided byindustrial facilities in the inlet,by vessel operators and by the

marine pilots who board vesselsin the inlet.

A

see CHEAP OIL page 17

� N A T U R A L G A S

Chugach blames stalemate on priceElectric utility facing supply shortages in 15 months, says price is the main sticking point in negotiations over new contracts

By ERIC LIDJIPetroleum News

hugach Electric Association doesn’texpect to secure much-needed naturalgas supply contracts any time soon,the electric utility told state regulators

recently, but said the only thing standing inthe way is agreeing on a price with produc-ers in the Cook Inlet basin.

Chugach is searching for new supplies toreplace existing contracts set to expire in2010 and 2011. Explaining its supply prob-lems to state regulators back in February, theutility said it expected to submit new con-tracts for regulatory approval by the end ofthe year.

“Obviously, that has not happened,” theutility wrote to the Regulatory Commissionof Alaska on Dec. 23. “It would be mislead-ing for Chugach to suggest that the filing ofnew Chugach gas supply contracts is immi-nent. No such filing appears imminent.”

Chugach insists the “basic problem” isnot a shortage of natural gas in Cook Inlet,at least not for the next few years, but rathera continuing inability of the utility to reachan agreement with various producers in theregion on how to price existing supplies.

Other than that explanation, Chugachwould not detail the ongoing negotiations itmight have with Chevron, ConocoPhillipsand Marathon, citing confidentiality agree-ments.

Chugach would like to buy at least someof its gas in the future from “smaller, and/orindependent, and/or new Cook Inlet gas pro-ducers,” believing a lack of opportunities tosell Cook Inlet gas is the primary reasonbehind the lack of exploration in recentyears.

Over the longer term, beyond the con-tracts the utility needs to sign soon, Chugachhopes to reduce its overwhelming depend-ence on “geologically produced Cook Inletnatural gas,” by turning to alternative andrenewable fuels, or natural gas from otherbasins.

Contracts based on volumeThe comments come as part of an inves-

tigation by the Regulatory Commission ofAlaska into whether Chugach has enoughnatural gas to meet current and futuredemand.

Chugach is the largest electric utility inAlaska, responsible for generating 55 per-cent of the electricity used in the Railbelt,the population center of the state stretchingfrom Fairbanks to Homer. Chugach usesnatural gas to generate 93 percent of its elec-tricity.

To get that natural gas, around 28 billioncubic feet each year, Chugach has four largesupply contracts, one with Marathon andone each with Chevron, ConocoPhillips andMunicipal Light & Power, the three ownersof the Beluga River gas field on the westernside of Cook Inlet.

Those contracts are based on volume,and expire when Chugach uses a set amountof gas.

At the utility’s current rate of use,Chugach expects the Marathon contract,which accounts for 52 percent of the utility’stotal gas supplies, to run out in “mid-2010.”

Chugach expects its contracts with thethree Beluga River producers to expire inApril 2011. Chugach is unsure whether itwill be able to use those contracts to makeup for the shortfall in the Marathon contract,but even if it can, the utility has no suppliesafter 2011.

May involve state, publicThe debate over pricing Cook Inlet gas

isn’t new and doesn’t seem close to resolu-tion.

With a limited number of buyers andsellers in the region, natural gas in CookInlet is not priced on a spot market, but onlong-term contracts approved by state regu-lators.

For years, the problem has been finding asystem for pricing the gas so that producersearn fair return on investment, new compa-nies have an incentive to explore for gas inthe region and consumers aren’t payingexorbitant rates for natural gas and electrici-ty.

Attempts to strike that balance over thepast decade have involved linking the priceof natural gas in Cook Inlet to the price ofnatural gas in other parts of the country.

In 2001, RCA approved a supply con-tract between Enstar Natural Gas andUnocal that tied Cook Inlet prices to HenryHub spot prices. But in 2006, the RCArejected a different contract between Enstarand Marathon that also used Henry Hub as astarting point.

The pricing dilemma came to a headagain toward the end of 2008, when stateregulators refused to approve two Enstarcontracts with ConocoPhillips andMarathon because the producers wouldn’tagree to a price cap based on productionbasins in the Lower 48.

Chugach shouted from the sidelines inthat case, arguing that any price approvedfor Enstar would set a large precedent for theother major natural gas buyers in the region.

In the four existing Chugach supply con-

tracts, the price of natural gas rises and fallswith oil and natural gas prices in the Lower48, but remains well below the nationalaverage.

Chugach said it has been trying to nego-tiate new contracts since “at least 2004.”

In addition to the problem of price,Chugach said part of the difficulty in secur-ing new supplies is that the utility “does notyet know how public officials in the State ofAlaska will respond to what is obviously amajor public policy issue and potential cri-sis.”

So far, Chugach said it has made “rela-tively little effort” to involve the state or the

public in the stalemate around negotiations,but added, “Obviously, that may have tochange.” �

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 11

EXPLORATION & PRODUCTIONChevron gets second White Hills permit

The Alaska Oil and Gas Conservation Commission has approved a second drillingpermit for Chevron’s exploration venture in the White Hills prospect in the centralNorth Slope.

On Dec. 22, AOGCC approved a permit for Chevron, through its subsidiaryUnocal, to drill the Bluebuck 6-7-9 exploration well on state lease ADL 389182.

Bluebuck 6-7-9 is one of four new exploration well locations Chevron permittedearlier in 2008 in White Hills, after permitting 15 well locations at the prospect in pre-vious years.

The White Hills prospect sits south of the Kuparuk River unit, around 30 mileswest of the trans-Alaska oil pipeline. The prospect stretches around 50 miles north tosouth.

This past winter, Chevron drilled three wells across that area using Nabors rig106E. The company plans to use the rig again this year, but seems to be focusing itsdrilling efforts toward the northern end of the prospect, near the Panthera 28-6-9 welldrilled last year.

Chevron also recently received a permit from the AOGCC to drill the Muskoxen36-7-8 exploration well on state lease ADL 390941, also in the northern end of theprospect.

Chevron has said it is looking for both oil and gas at White Hills. While severalprevious wells drilled by other operators in the region have had oil shows, Chevron isplanning several “relatively shallow” wells, which could signify a natural gas target.

“This is probably mostly gas, but it is an area where they could also find oil,” MartyRutherford, deputy commissioner of the Department of Natural Resources, said at the“Energy in Alaska” conference hosted by Law Seminars International in Anchorage.

Chevron is partnering on the exploration program with the French oil companyTotal. As of Jan. 2, seasonal travel restriction remained in effect on state lands in thefoothills of the Brooks Range, including the primary staging area for the White Hillsventure.

—ERIC LIDJI

On the WebSee previous Petroleum News coverage:

“No to RCA gas price cap,” in Dec. 7,2008, issue atwww.petroleumnews.com/pnads/617505653.shtml

“Gas supplies for CEA?” in Dec. 14, 2008,issue atwww.petroleumnews.com/pnads/297191883.shtml

So far, Chugach said it has made“relatively little effort” to involve

the state or the public in thestalemate around negotiations, butadded, “Obviously, that may have

to change.”

C

By ALAN BAILEYPetroleum News

t’s one thing to know that there are gasfields in the ground but quite anothermatter to determine that those fields canbe viably developed. So, when it comes

to the known gas fields in Alaska’s BrooksRange Foothills, Anadarko Petroleum,together with its partners Petro-Canada andBG, is engaged in a multiyear resourceevaluation, Doug Wilson, Anadarko’sAlaska exploration manager, told theResource Development Council ofAlaska’s annual conference in November.

Anadarko is now working on the secondseason of a Foothills drilling program thatconsists of two phases, Wilson said. Thefirst phase, involving two or possibly threedrilling seasons, is designed to understandthe nature of the gas resource and the reser-voir deliverability. The second phase, con-sisting of field appraisals, will likely takeseveral seasons more, Wilson said.

Delineate gas poolsWilson said that the Foothills gas fields

typically occupy what geologists term“four-way closures,” hydrocarbon trapsformed in situations where the rock stratahave been deformed into dome-like struc-tures. Most of the exploration wells thatdiscovered the fields in the late 1940s andin the 1950s drilled into the tops of thesestructures, Wilson said.

“We really need to understand whetherthe gas is just confined to those traps. Ordoes it go off the structures in betweensome of them? How big is the resource outthere?” Wilson said.

Anadarko also needs to understand thelikely economic performance of produc-tion wells in the fields. Developing thesewell performance forecasts entails anunderstanding of likely production ratesand well spacing, as well as estimates ofhow long production would last and anassessment of possible production prob-lems, Wilson said.

“Those are things we really need tounderstand before we pour billions of dol-lars into a project like this,” Wilson said.

Drilling seasonsThe first drilling season of the first

phase of the Anadarko Foothills explo-ration took place in the winter of 2007-08and saw the completion of the Gubik No. 3well and the partial drilling of the ChandlerNo. 1 well. Both wells lie east of theColville River near Umiat.

The second drilling season, to be con-ducted during the 2008-09 winter, willentail the completion of the Chandler welland the drilling of two new wells, GubikNo. 4 and Wolf Creek No. 4. Wolf Creeklies about 40 miles west of Umiat.

The Nabors rig 105-E that starteddrilling the Chandler No. 1 well last winterspent the summer on an ice pad at theChandler location, ready for a three-tofour-week jump start on continuing to drillthe well this winter.

“We got down to about 1,900 feet lastyear and we want to go back and drill thatwell to about 10,800 feet,” Wilson said.

Anadarko will then move the Nabors rigto drill the Gubik No.4 well, for a down-diptest of the Gubik field. Because of the num-ber of wells that have already been drilledin the Gubik field, Gubik No. 4 is more ofan appraisal well than the other wells thatAnadarko is drilling — Anadarko wants todetermine the extent of the field reservoirand features of the field such as the fluidcontacts, Wilson said. The Gubik No. 4

well will bottom out at around 4,400 feet.

Wolf CreekWhile the Nabors rig is in action at

Chandler and Gubik, the Doyon Arctic Foxrig will deploy to the Wolf Creek field todrill the Wolf Creek No. 4 well to about4,000 feet. The rig will spend the season atWolf Creek, conducting tests to obtaininformation about field deliverability,Wilson said.

And as part of the complex logisticsinvolved in carrying out a drilling programin a remote part of northern Alaska,Anadarko will have to construct 82 milesof ice roads and 80 miles of snow roads thiswinter. Moving equipment to and fromdrilling sites will involve multiple rivercrossings.

“One of the big challenges is going to bemoving all of this equipment on and off thetundra at the same time,” Wilson said.

Anadarko plans to build an insulated icepad at Gubik, to retain the option of stagingequipment on the tundra over the summer.The company also plans to build a conven-tional ice pad at Wolf Creek to support theoperations there.

Field economicsIn addition to understanding the techni-

cal parameters of the gas fields, Anadarkoneeds an understanding of the economicsof developing the fields before the compa-ny can make any development decision —Anadarko has also been using its expertisefrom the Rocky Mountains region to devel-op conceptual designs for Foothills gasfield facilities, Wilson said.

And a pipeline for exporting gas fromnorthern Alaska is obviously critical to thecommerciality of Foothills gas. Two pro-posals for a future North Slope gas exportpipeline are currently in progress, whilethere is also the possibility of a pipeline fordelivering Foothills gas into SouthcentralAlaska.

But Wilson also emphasized that anydevelopment project in the Brooks RangeFoothills needs to compete for capital inAnadarko’s global portfolio of develop-ment opportunities. For example, the com-pany is planning to drill about 20 wells indifferent basins in the Lower 48, Wilsonsaid.

“We have a lot of different opportuni-ties around the world that we’re workingon,” he said. �

12 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

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

Evaluating the Foothills natural gasAnadarko knows the gas is there but needs to assess volumes and production characteristics before making a development decision

I

The Nabors rig 105-E that started drilling the Chandler No. 1well last winter spent the summeron an ice pad at the Chandler location, ready for a three to four-week jump start on continuingto drill the well this winter.

JUD

Y P

ATR

ICK

By KRISTEN NELSONPetroleum News

laska North Slope crude oil produc-tion for December averaged 729,948barrels per day, down 3.7 percentfrom a November average of 758,099

bpd, the drop driven by weather delays inloading crude oil in Valdez at the end ofDecember.

Daily averages dropped beginning Dec.28 (from 382,985 bpd at Prudhoe Bay Dec.27. to 345,157 bpd and from 157,779 bpd atKuparuk Dec. 27 to 128,970 bpd), thendropped substantially Dec. 29 when AlyeskaPipeline Service Co. shut down the trans-Alaska oil pipeline for six hours beginningat about 8 p.m. because storage tanks at theValdez Marine Terminal were nearly full.Tankers couldn’t be loaded because roughwater in Valdez prevented deployment ofboom around the tankers, a requirement forloading. Prudhoe production bottomed at209,189 bpd Dec. 30, Kuparuk at 82,963bpd.

The Alaska Department of Revenuedescribed the production downturn as atrans-Alaska oil pipeline proration due toweather in Valdez from Dec. 27-Dec. 31.

Production was coming back up slowly,with an ANS rate of 598,607 bpd for Jan. 1,up from 413,610 bpd Dec. 30. ANS produc-tion began the month of December at758,096 bpd and peaked at 780,492 bpd forthe month on Dec. 5.

Valdez Marine Terminal inventories,which began the month at 3.7 million bar-rels, peaked at 6.8 million barrels Dec. 29.By Dec. 31 inventory had dropped to 6 mil-lion barrels. The average inventory forDecember was 4.9 million barrels, com-pared to an average of 3.8 million barrels forNovember.

The BP Exploration (Alaska)-operatedPrudhoe Bay field had the largest per-barrelproduction drop from November toDecember, more than 10,000 bpd, averaging361,262 bpd in December, down 2.9 percentfrom a November average of 372,078 bpd.Prudhoe production includes satellite pro-duction from Aurora, Borealis, MidnightSun, Orion and Polaris.

The BP-operated Northstar field had thelargest percentage drop, 10 percent, averag-ing 26,909 bpd in December compared to29,884 bpd in November.

Endicott, also operated by BP, averaged14,287 bpd in December, down 8.9 percentfrom a November average of 15,689 bpd.

Production at BP’s Milne Point fieldaveraged 30,265 bpd in December, down4.8 percent from a November average of31,802 bpd. Milne Point productionincludes Schrader Bluff.

The BP-operated Lisburne field (includ-ing production from Point McIntyre andNiakuk) averaged 36,156 bpd in December,down 4.4 percent from a November averageof 37,829 bpd.

The ConocoPhillips Alaska-operated

Alpine field averaged 109,923 bpd inDecember, down 3.8 percent from aNovember average of 114,255 bpd. Alpineproduction includes satellite productionfrom Fiord, Nanuq and Qannik.

Production at the ConocoPhillips-operat-ed Kuparuk River field averaged 151,146bpd in December, down 3.5 percent from aNovember average of 156,562 bpd.Kuparuk includes satellite production fromTabasco, Tarn, Meltwater and West Sak, aswell as from the Pioneer Natural Resources

Alaska Oooguruk field. The latest produc-tion figures breaking out Oooguruk, fromthe Alaska Oil and Gas ConservationCommission, are for November and showan average of 5,643 bpd from that field.

The temperature for December at PumpStation No. 1 on the North Slope averagedminus 0.05 degrees Fahrenheit, compared to5 degrees F for November.

Cook Inlet crude oil production averaged12,771 bpd in December, down 1 percentfrom a November average of 12,903 bpd. �

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 13

� N A T U R A L G A S

Fourth explosion targets EnCana in B.C.By GARY PARK

For Petroleum News

or the fourth time in three months EnCana’s naturalgas operations in northern British Columbia havebeen the target of what the Royal Canadian MountedPolice believe have been “deliberate” explosions.

On Jan. 4 gas line workers found a partially destroyedmetering shed at a wellhead site southeast of DawsonCreek near the British Columbia-Alberta border.

During October, pipelines were damaged in separateblasts and an explosion at a wellhead caused a leak.

EnCana spokesman Alan Boras told reporters the com-pany is concerned about the safety of its workers and thepeople who live in the area where it operates.

He said EnCana has stepped up its security measuresand is asking the public to help the police determine who

is responsible. To that end it has established a dedicatedtelephone line, allowing those responsible to discuss theirconcerns.

A spokesman for the RCMP said “literally hundreds” ofpeople have been questioned and a door-to-door canvashas been conducted in the area, but “we still don’t have aprime suspect.”

He said the latest explosion was closer to the nearesthouse than any of the previous incidents, adding “webelieve they are becoming increasingly violent.”

Rapid production expansionThe worries are heightened by the rapid expansion of

gas production in northeastern British Columbia, where4,000 wells are on line.

Paul Joosse, an ecoterrorism expert at the University of

Alberta, told the Calgary Herald that the perpetrator isclearly an “amateur,” but shows a level of determinationdespite a lack of technical ability.

He said it was difficult to say whether the attacks are thework of an individual or a “small, tightly knit group.”

Joosse said a blockade against oil and gas vehicles inthe area last summer was a sign of “widespread communi-ty support for civil disobedience and a widespread senti-ment of frustration” by residents upset over the industry’simpact on their land.

In the 1990s, Alberta farmer Weibo Ludwig spentalmost two years in jail on charges related to bombings andvandalism directed at the petroleum industry he accused ofhurting his family, livestock and land.

The RCMP said they have spoken to Ludwig as part oftheir British Columbia investigation, but do not considerhim a suspect. �

F

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

ANS production down on Valdez weatherNorth Slope production drops 3.7% from November due to late-December proration, six-hour closedown of trans-Alaska oil pipeline

A

By GARY PARKFor Petroleum News

hose who trumpeted the virtuallyunlimited commercial potential ofCanada’s oil sands may have finallymet their match after years of fend-

ing off skeptics and critics.Since production of tar-like bitumen

made its debut 40 years ago, the depositsof more than 300 billion barrels thatsprawl across 36,000 square miles ofnorthern Alberta have been the object ofridicule, scorn and even contempt.

Once dismissed as a scientific experi-ment and a pure mining venture of no con-sequence in the global oil equation, the oilsands, through intense lobbying by gov-ernment and industry, are now widely rec-ognized as the world’s second largestproven concentration of oil after SaudiArabia.

More importantly, the industry view ofthe resource changed dramatically whenoperating costs came down from aboutUS$40 per barrel to US$11-$12 aroundthe turn of the century as technology andreliability improved. But the fleetingpromise represented by that trend wasshort-lived, with costs now back at theUS$40 level.

Production from mines and in-situprojects is currently 1.3 million barrelsper day and was on track to reach 4.5 mil-

lion-5 million bpd by 2020 throughplanned investment in mines, upgraders,refineries and pipelines calculated atupwards of C$170 billion.

Dreams evaporatedThen the financial crisis hit and the

dreams evaporated faster than at any timeduring a prolonged period of rapidly ris-ing labor and materials costs, higherAlberta royalties, a phased elimination offederal capital cost allowances for oilsands projects, the uncertain impact of cli-mate change initiatives by Canadian gov-ernments and the incoming Obamaadministration and a losing environmentalbattle for the hearts and minds ofCanadians.

“The economic times have come uponus very, very quickly,” said AlbertaDeputy Premier Ron Stevens. “The priceof oil has dropped by over US$100 perbarrel in a handful of months. The stockmarkets have been cut in half in a matterof months and the credit system hasbecome frozen or near frozen.”

Since markets and oil prices startedtheir spiral from benchmark highs, thecorporate pullback from the oil sands hasanswered those calling for a more man-ageable, measured pace of expansion.

But, the worry now within industry andgovernment circles is that many of theprojects either delayed or shelved over thepast three months — estimated by CIBCWorld Markets to affect more than C$100billion worth of investment and 800,000bpd of the 1.6 million bpd of incremental

production it had expected over the nextfive years — may have been irretrievablylost. Stalled upgraders alone carry a valueof at least C$50 billion.

“These are changed circumstances,”said Bob Skinner, senior vice president ofStatoilHydro Canada. “If oil prices remainlow for a long time, it becomes problem-atic whether you could proceed with oilsands plans that were developed when oilprices were double what they are now.”

Geir Jossang, president ofStatoilHydro’s Canadian division, said hiscompany is maintaining financial flexibil-ity by reducing “short-term investmentsand deferring things we need not neces-sarily go ahead with right now.”

Initial fallout severeWhile the eventual consequences of

slowing or abandoning projects are beingpondered, the initial fallout has beensevere.

The construction industry has slashedits workforce requirements for the heart ofthe oil sands region to 22,000 from 44,000for 2010.

The Canadian Association ofPetroleum Producers has wiped an aver-

14 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

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

Alberta oil sands facing a new enemyFinancial crisis forces a corporate retreat from oil sands; billions of dollars of planned investment now on the shelf; Albertagovernment urged to rethink royalties; long-term impact on planned projects uncertain, but immediate impact is severe

Shifting sandsThe oil sands of Alberta are living

proof of the old adage: The biggerthey are the harder they fall. Evenfaster than they grew from a margin-al resource to a key element in NorthAmerica’s energyfuture, attractingcapital spendingestimates of C$317billion over the next22 years, the oil sands have goneinto a tailspin, induced by the col-lapse of oil prices that did moredamage in a few months than yearsof cost over-runs, shortages of con-struction labor and materials and thethreat of harsh climate-change meas-ures. Petroleum News’ Canadiancorrespondent Gary Park examinesthe fallout from a drastically revisedoil sands agenda and the chances ofa recovery in a two-part series.

T

see NEW ENEMY page 15

Project summary Oil sands projects delayed, deferred or cancelled in the final quarter of 2008:• Shell Canada-operated Athabasca mining project delays 100,000 bpd expansion until costscan be reduced.• Shell Canada withdraws regulatory application for 100,000 bpd Carmon Creek project in thePeace River area of northwestern Alberta.• Petro-Canada and two minority partners delay until at least next year an investment decisionon a mine at their C$24 billion Fort Hills project and put upgrader plans on hold indefinitely.• Suncor Energy delays for one year a planned upgrader for the C$20.6 billion expansion of itsVoyageur project, designed to boost company output to 550,000 bpd from 350,000 bpd. • Nexen and OPTI Canada stall a decision to double capacity at their newly launched Long Lakeproject to 120,000 bpd of synthetic crude. The first phase cost C$6.1 billion.• Canadian Natural Resources slows spending on the second phase of its Horizon project afterfirst phase costs climb 42 percent to C$9.7 billion, scrapping a timeline that would have liftedproduction to 250,000 bpd from 110,000 bpd.• Total Canada delays a 114,500 bpd mine for its Joslyn project and puts an upgrader on hold.• Total Canada-Synenco withdraws a regulatory application for the 115,000 bpd Northern Lightsmine.• StatoilHydro drops a regulatory application for a 20,000 bpd upgrader, part of a C$16 billiondevelopment, after previously extending the timeline by two years to 2016. • North West Upgrading shelves a planned C$4.2 billion upgrader pending financing.• BA Energy abandons a partly built merchant upgrader.

age 60,000-70,000 bpd off forecasts itreleased only six months ago for oil sandsproduction over the 2007-12 period,reduced its 2012-17 forecast by 300,000bpd to 2.83 million bpd in 2017 and low-ered its 2020 target to 3.27 million bpd,off 1.23 million bpd from its low-end out-look in June.

CAPP Vice President Greg Stringhamsaid oil sands developers are now on amoderate-growth path and may even ben-efit from the economic downturn if costsfall enough to restore the economics ofprojects now on the shelf.

But Justin Bouchard, a research analystwith Raymond James, said it remains tobe seen if labor costs will fall as much asthose for materials (steel alone hasdropped by two-thirds from its peak lev-els) to make mega-projects viable again.

“We fully expect costs to come inlower, but the big question is how muchlower?” Bouchard said. “Our concern isthat labor and contractor rates may bestickier in the near term than expected.”

Long-term recovery expectedOver the longer term, interest in the oil

sands is certain to recover, said DonThompson, president of the Oil SandsDevelopers Group, a nonprofit, industryorganization that defines and addressesthe sector’s regional issues.

“The world continues to be hungry forenergy and the oil sands will continue tobe a major source of energy security,” hesaid.

And, regardless of the number ofdeferred or cancelled projects, there willbe considerable investment to keep theexisting facilities operating, Thompsonsaid.

Encouraged by hints from AlbertaEnergy Minister Mel Knight in Decemberthat the government is prepared to do anin-depth analysis if it becomes clear royal-ty increases have blunted Alberta’s com-petitive edge, CAPP President DaveCollyer said the province must show a“sense of urgency” to ensure it remainseconomic against other jurisdictions inconventional and oil sands production.

“That involves the fiscal structure; thatinvolves the regulatory framework; itinvolves greenhouse gas policy. …” hesaid.

Growth will moderatePeter Tertzakian, chief energy econo-

mist at ARC Financial, wrote in theCalgary Herald that oil sands’ growth willmoderate significantly from earlier projec-tions as companies “weigh all the issues,including the cost inflation that arisesfrom aggressive over-investment … in aremote area that has got a lot of environ-mental baggage” and absorb the lessons ofthe oil price crash.

However, he said it is important tounderstand that the current wave of budg-et cuts mostly affect upgrading plants.

“Although cost inflation, regulatoryuncertainties relating to climate-changelegislation and low oil prices havechanged the sentiment on all projects,upgraders are the most capital-intensivecomponent of the multibillion-dollarflow,” Tertzakian said.

”The realization is setting in that it willbecome more economic to pursue build-ing upgrading facilities at existing refiner-ies in the United States, although wherethe money will come from to do that isquestionable, too.”

Tertzakian said that prior to the finan-cial crisis expectations were high thatAlberta upgraders would process 75 per-cent of the province’s oil sands produc-

tion, up from 60 percent today. He nowthinks that share will actually decline to55 percent by 2015.

He told the Financial Post that beforethey embark on a new round of decision-making, companies will pay closer atten-tion to the cost inflation that arose fromaggressive over-spending in Alberta and,based on the lessons of the past fewmonths, will be more sensitive to thepotential for oil price crashes.

They will also be forced to think hard-er about whether they want to be in a busi-ness with such a poor environmentalimage, Tertzakian said, noting that the“environmental lobby has done a mar-velous job of disadvantaging the oilsands.”

“That is the reality. It’s damaged goodsand it is a high-cost producer,” he said.

In a final word for these difficult times,Knight said the Alberta governmentaccepts that the new price range for oil is“not conducive to any new investment.”�

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 15

EXPLORATION & PRODUCTIONWestern Canada beats 2007 rig count

For all the dismal statistics that dominated the final quarter, there was a sur-prise in Canada’s upstream sector in 2008.

The average number of rigs that were kept active in Western Canada throughthe year was up 31 at 402 and the average utilization of the rig fleet rose to 47 per-cent from 42 percent.

Alberta reported 265 active rigs, a drop of one from 2007 and the lowest countsince 2002.The record year was 2005 when an average 396 rigs were at work.

Saskatchewan posted a record average of 67 working rigs, 20 more than 2007and 13 more than the previous high in 2006.

British Columbia logged a 23 percent increase from 2007, with an average rigcount of 64, 10 below the record set in 2005.

Manitoba’s industry kept six rigs at work compared with four in 2007.—GARY PARK

continued from page 14

NEW ENEMYIn a final word for these difficulttimes, Knight said the Alberta

government accepts that the newprice range for oil is “not

conducive to any new investment.”

16 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

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Business SpotlightURS

URS is a publicly held company with morethan 29,000 employees worldwide. In 2006 URSwas named number one on the list of Top 500design firms, first in hazardous waste, and in theTop Ten environmental services andwater/wastewater firms, according toEngineering News Record. URS’ presence inAlaska goes back more than 50 years whenoffices were established in Anchorage to con-duct early geological work in Cook Inlet. URScompleted its first project in Alaska in 1954,opening a permanent Alaska office in 1970. URSAlaska Operations are in Anchorage, withbranch offices in Fairbanks and Homer.

Brian KovolBrian Kovol has worked in the environmental field for more than 18 years, 10 of those

Brian Kovol, Senior Project Manager

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NE with URS Corp. in Alaska. He works with stake-

holders to negotiate the permitting process tosuccessful completion for clients. Brian enjoysbrewing beer, flying — usually to his favorite fish-ing spot — and, when in warmer climates, scubadiving and swimming. Brian and his wife Kimhave three children — Merek, Ayden and Ellen.

Peter CrewsURS civil engineer Peter Crews joined Tryck

Nyman Hayes in 2000. Born in Anchorage, he pre-viously spent 20 years in the survey and construc-tion industry. A key decision was going back tocollege for his civil engineering degree. He, hiswife DaRae, and daughter Katherine enjoy camp-ing and traveling in and outside Alaska. Big planson the drawing board are to visit Europe, Australiaand South America.

Peter Crews, Senior TransportationEngineer

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—PAULA EASLEY

this crazy situation with oil prices,” said Daniel Yergin, chair-man of Cambridge Energy Research Associates, a consultingfirm, and author of “The Prize,” the Pulitzer Prize-winning his-tory of the oil industry.

Oil giants like ExxonMobil, Chevron and ConocoPhillipshave yet to announce their 2009 capital spending plans, butanalysts say even the cash-rich companies are likely to shelvesome projects.

Already, Royal Dutch Shell has postponed a near-doubling ofproduction in Canada’s oil sands — an operation that analystssay only makes economic sense when oil is about $20 a barrelmore expensive than it is now. Marathon Oil says it expects tocut capital spending by 15 percent in 2009.

Production could drop 7%Brodrick said canceled or postponed oil and gas projects

could contribute to a drop of 7 percent or more in global oil pro-duction this year.

Smaller oil producers could cut spending by 30 percent, saidOppenheimer & Co. analyst Fadel Gheit. The majority of U.S.crude and natural gas is supplied by smaller, independent com-panies, not the Exxons and Chevrons, and smaller producershave been forced to pull back because of frozen credit markets.

All this comes as the Organization of Petroleum ExportingCountries, which controls about 40 percent of world crude sup-plies, embarks on its biggest single production cut ever.

It adds up to another round of price shocks for consumersthat’s probably inevitable, said Bruce Vincent, president ofHouston-based Swift Energy Co., an independent producer.

“Demand will start growing, supply will start coming down,and you’ll have that intersect again where prices will take offdramatically,” Vincent said. “(But) it’s not healthy for the econ-omy. It’s not healthy for the industry.”

Already, the futures markets are pricing in more expensiveoil. While a barrel of light, sweet crude for February deliverycosts about $50, the market for September oil is already over$60.

Big Western oil companies like Exxon and ConocoPhillipshave also been cut off from crude reserves under the control ofnationalized oil companies from Saudi Arabia to Venezuela.

Annual investment requirement put at more than $1 trillionLate last year, the International Energy Agency said it will

take more than a trillion dollars in annual investments to findnew fossil fuels over the next two decades in order to avoid short-ages that could choke the global economy.

When the world economy recovers from the current malaise,“Are we going to get another one of these violent cycles whereprices overshoot and you get back in the same spiral?” askedYergin. “Some volatility is inevitable in global commodity mar-kets, but this kind of extreme volatility is bad for everyone. It cre-ates deep wounds.”

Another part of the problem, said Judy Dugan, research direc-tor for the nonprofit Consumer Watchdog, is that oil companiesdidn’t invest enough in new exploration over the past severalyears, as they raked in billions in profits.

“They’re screaming, ‘Drill, baby, drill,’ but they didn’t investanywhere near where they should have been investing whenprices were high,” she said. “Now that prices have crashed, theysay prices are too low, knowing full well prices are going to goback up.” �

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 17

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Oil Patch Bits

Unique Machine putschopper on display

Unique Machine and Orange CountyChoppers had a special chopper built tocelebrate the 50th Anniversary ofStatehood for Alaska. The bike was puton display at the Dena’ina Center inAnchorage in January for the StatehoodCelebration, after which UniqueMachine will display the bike at variousAnchorage locations. A drawing will beheld in March, with 50 percent of theproceeds going to the Children’sHospital at Providence. A subsidiary ofSumitomo Corporation of America,Unique Machine is the largest machineshop in Alaska. For more information onticket sales or where the bike can beviewed, contact Dana Dozark at 907-563-3012 or visit Unique Machine’sWeb site at www.umalaska.com.

NAC has new KingSalmon contract agent

Northern Air Cargo has partneredwith Bristol Bay Contractors to be itscontract agent in King Salmon. BristolBay Contractors, which NAC has long-standing relations with related toseafood, will be responsible for loadingand offloading NAC aircraft, and accept-ing and dispersing freight in KingSalmon. For many years PeninsulaAirways has represented NAC in KingSalmon. The decision to change the rela-tionship was amicable and mutuallydetermined, NAC said in a Decemberpress release. “We have always valuedPenAir as a partner and we wish themgreat success as they turn their focus topassenger transportation,” said NAC’sMargot Wiegele.

Builders Choice tops1,000 modules

In December, Builders Choice hostedan open house to celebrate the produc-tion of its 1,000th module since openingits modular production facility inNovember 2005. The company said thismodule was one of many that havebeen shipped to Alaska’s North Slope tohouse hundreds of employees currentlyworking on some of Alaska’s most sig-nificant oil and gas projects. BuildersChoice is located in a state-of-the-artproduction facility just off Old SewardHighway in Anchorage, Alaska. The mas-sive indoor plant allows crews to workyear round on modules that are pro-duced in an assembly line process.

See full stories in the next PetroleumDirectory magazine, which will carry anew name, Arctic Oil & Gas Directory.

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CHEAP OIL

ALTERNATIVE ENERGYProponent touts coal-to-liquids plant

The multibillion dollar price tag on a coal-to-liquids plant might seem expen-sive but a project proponent says the benefits could outweigh the cost.

Jim Dodson, executive director of the Fairbanks Economic DevelopmentCorp., addressed business people in early January at the Greater FairbanksChamber of Commerce luncheon.

He asked them to look beyond the estimated $2 billion to $6 billion price tag.“It brings tremendous opportunity to Alaska, not just Interior Alaska, but real-

ly, all of Alaska,” Dodson said.The Fairbanks Economic Development Corp. spent $550,000 in 2008 on a fea-

sibility study developed by Toronto-based consultant Hatch. Released inNovember, the study indicated that a coal-to-liquids plant using Fischer-Tropschand gasification technology could be economically feasible in Alaska’s Interior,providing that oil prices remain high and that investors don’t expect a high rate ofreturn.

Fuel at $2 gallonIdeally, a coal-to-liquids plant could supply Fairbanks with fuel on par with $2

per gallon about the same price customers pay when oil is going at $88 per bar-rel, Dodson said. At that level, investors in such a plant could expect a 5-7 per-cent rate of return, not likely high enough to attract big money, he said.

Dodson and others, including borough Mayor Jim Whitaker, have touted theplant as a solution for Fairbanks’ long-term economic viability. Proponents saythe plant could ease the region’s dependence on oil by processing coal into liquidfuels, and help reining in energy costs.

At the same time, the plant could offset some air quality concerns as liquidfuels are generated without the emissions released by oil-fired refineries, propo-nents say.

Most of all, the coal-to-liquids plant could produce synthetic fuels for the U.S.Air Force, which in turn could anchor the military’s future in Interior Alaska,Dodson said.

He said FEDC has discussed terms with and is waiting to start negotiating withthe U.S. Air Force for a contract to study further a coal-to-liquids plant, possiblylocated near Eielson Air Force Base. The air force has $10 million available toadvance those studies, he said.

—THE ASSOCIATED PRESS

Parker to open office in Anchorage; Parker’sHusband, Nabors’ Korachto speak at Meet Alaska

PARKER DRILLING CO. WILL OPENan office in Anchorage in January or earlyFebruary, company officials toldPetroleum News in early January.

The Houston-based firm left Alaska adecade ago during leaner times for the oilindustry.

Parker will “staff up its office” in 2009to support two drilling projects for BP,Parker spokesman Rose Bratton Maltbytold Petroleum News Jan. 7.

One project is two new infield develop-ment drilling rigs for Prudhoe Bay, whichwill kick-off after the rigs arrive in Alaskain 2010; the other is for a rig the companybuilt for BP’s Liberty oil field, currentlybeing developed in the federal waters ofthe Beaufort Sea.

But Parker is also looking for other rigcontracts in Alaska.

Joey Husband, who is moving back toAnchorage from Houston, will overseethat effort as general manager of the com-pany’s Alaska unit.

Husband, who previously spent eightyears in Alaska as a field engineer forSchlumberger, will speak at the Jan. 26Meet Alaska conference in Anchorage.

Also speaking at Meet Alaska is DonKorach, an engineering manager withAlaska’s largest drilling company, NaborsAlaska Drilling.

To register for the conference call TheAlliance at 907-563-2226 in Anchorage orvisit www.alaskaalliance.com online.

Koniag buys Dowland-Bach

KONIAG INC. SAID JAN. 5 that it hasacquired Dowland-Bach, an Alaskan-owned company that designs and fabri-cates control systems and equipment forindustrial and commercial applications.

The purchase was made by KoniagDevelopment Corp., or KDC, a whollyowned subsidiary of Koniag Inc.

Koniag is the Alaska regional Nativecorporation owned by the Alutiiq peoplefrom the Kodiak area.

The purchase of Anchorage-basedDowland-Bach marks Koniag’s first forayinto the Alaska oil industry. Dowland-Bach

was founded in Alaska in 1974 to developfail-safe wellhead and flowline control sys-tems for the Prudhoe Bay oil field. Severalthousand of Dowland-Bach’s wellheadcontrol systems have been installed inextreme locations from the North Slope ofAlaska to South America.

Lynn C. Johnson will remain presidentof Dowland-Bach. The acquisition is notexpected to result in any changes to cur-rent management or the number ofemployees. Dowland-Bach has 27 employ-ees.

“Dowland-Bach is already a successful,highly regarded company, with a demon-strated record of quality service and cus-tomer satisfaction,” KDC President andCEO Tom Panamaroff said. “We’re excit-ed about the possibilities and opportunitiesahead.”

“The new ownership benefits Dowland-Bach, and its customers, as well, by assur-ing long-term continuity,” Johnson said.“With Koniag behind us, Dowland-Bach isbetter positioned to take full advantage ofgrowth opportunities in Alaska, the Lower48, and overseas.”

In addition to the petroleum industry,Dowland-Bach serves clients in wide-rang-ing industries such as utilities, construc-tion, aviation, government, telecommuni-cations, commercial fishing and marine.

KDC oversees a portfolio of diverseenterprises including telecommunications,fluid technology, environmental services,logistics, information technology, physicalsecurity and real estate investments.

While KDC’s past and present assetshave included operations and real estate inAlaska, its purchase of Dowland-Bach isKDC’s first acquisition of an established,successful Alaska company.

No news on Exxon invitation to State of Alaska officials

IN LAST WEEK’S OIL PATCHINSIDER, Petroleum News reported thatState of Alaska officials and the formerleaseholders of the Point Thomson unitended the 2009 portion of their negotia-tions on a positive note, when former PTUoperator ExxonMobil and its majority part-ners in the unit, BP, Chevron andConocoPhillips, reportedly invited AlaskaDepartment of Natural Resources officialsto Exxon headquarters in Texas after thefirst of the year. The purpose of the visitwas to review the technical informationbehind the companies’ proposed develop-ment plan for the defunct eastern NorthSlope unit.

Since that time neither state nor Exxonofficials have made any public commentsregarding the invitation.

Stay tuned. ...

Editor’s note: To submit news for OilPatch Insider, contact Kay Cashman by e-mail at publisher@petroleumnews.com;or by phone at 907-522-9469.

18 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

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power to its customers at a record rateof 485 megawatts on Jan. 4, Chugachspokesman Phil Steyer told PetroleumNews. Chugach’s previous recordpower output of 479 megawattsoccurred in January 2007, at about thesame time that the earlier Enstar recordwas set.

Chugach generates 90 percent of itselectricity using natural gas. But becausethe utility’s largest power plant is atBeluga on the west side of Cook Inlet, alarge proportion of the gas that the utilityuses goes straight to that plant and is,therefore, additional to the gas that Enstarhandles through its pipeline network.

The resulting major total utility gasdemand on exceptionally cold winterdays is referred to as needle-peakingdemand and now exceeds the total gasdeliverability from the Cook Inlet gasfields. Gas producers Marathon Oil Co.and Chevron operate gas storage facili-ties that store excess summer gas for usein the winter. But, even with the storagefacilities contributing to the utility gassupplies, the needle-peaking demandexceeds total deliverability capacity.

LNG curtailmentTo deal with this short-term deliver-

ability problem, the ConocoPhillips andMarathon-owned LNG plant at Nikiskion the Kenai Peninsula reduces LNGproduction, to divert gas for local utilityuse.

ConocoPhillips spokeswoman NatalieLowman confirmed Jan. 7 that the LNGplant has been curtailing production toenable increased gas deliveries to the util-ities.

But with the gas fields also runningflat out, can the gas transmission networkhandle the load?

Enstar’s total transmission capacity isalmost 400 million cubic feet, a numberwell in excess of the record-breakingthroughput, Thayer said. In addition,Enstar has recently fixed some bottle-necks in the pipeline network, to improvethe gas flow from some fields and thusrectify some past gas transportation prob-lems encountered during cold weather,he said.

“Everything was working well,”Thayer said of the record-breaking day.

And Steyer also confirmed that gassupplies have been coming throughsmoothly to Chugach’s power plants,despite the peak demand levels.

Supply contractsThe other issue when it comes to peak

demand is ensuring that there are ade-quate contracted gas supplies for the util-ities — gas deliverability issues havecome to a head in recent years as dwin-dling supplies from the aging Cook Inletgas fields have come into balance withgas demand in the region. Agrium closedits Kenai Peninsula fertilizer plant inDecember 2007 because of a shortage ofgas feedstock and there has been a ragingcontroversy in recent years concerningappropriate pricing for utility gas.

In December the RegulatoryCommission of Alaska rejected newEnstar gas supply contracts withMarathon and ConocoPhillips becausethe two producers would not agree to anRCA-imposed gas price cap. Those con-tracts would have filled a shortfall inEnstar’s contracted supplies, starting onJan. 1, and included provisions for pric-ing gas at different levels for high winterdemand and needle peaking.

Meantime, pending a resolution of thegas pricing issue, RCA is allowing Enstarto plug the gap in its supplies by buyinggas through the new contracts, but at arate below the utility’s average cost ofgas. �

continued from page 1

RECORD

continued from page 1

INSIDER

Hunt management, told Petroleum Newsthat his company was primarily interestedin exploring for oil rather than for naturalgas in NPR-A.

At current oil prices Petro-Hunt cannotjustify expenditure on NPR-A oil leases,given the Alaska tax structure and thehigh cost of doing business in the state,Hunt told Petroleum News Jan. 7. Huntsaid that, in addition to high tax rates,companies operating in northern Alaskahave to deal with a high cost environmentinvolving winter operations and manyenvironmental restrictions.

“It would take much, much higher oilprices to make it worth taking this gam-ble,” Hunt said.

Hunt said that his company thought itunfair to hold onto leases that it was notgoing to use. Instead Petro-Hunt hasrelinquished its bids.

“We still like the acreage but we feltwe shouldn’t warehouse it,” Hunt said.“… We just chose to suffer the loss andhope times will change.”

Hunt said that his company remainsinterested in Alaska and might return tothe state were the economic climate tobecome more favorable.

Ikpikpuk RiverMany of the leases that Petro-Hunt is

giving up would have formed a fairwayaround and to the east of the IkpikpukRiver, which flows south to north up theboundary between Northwest andNortheast NPR-A. The company also bidsuccessfully on a smaller group of tractsin the east-central part of the NPR-Anortheast planning area.

Petro-Hunt LLC is part of the Petro-Hunt Group, “one of the largest privatelyheld energy groups of companies in theworld,” according to the company Website. Petro-Hunt Group companies haveworking interests in and/or operate thou-sands of wells in the United States, main-ly in southern states but also in theWilliston basin of North Dakota andMontana, the Web site says.

The group is associated with the Huntfamily, which has a long association withAlaska. The family already has energyinterest in Alaska in the form of a part-nership involvement in PacRim LP, thecompany that proposes to develop coalmining at Chuitna on the west side of theCook Inlet.

Other companiesOther companies that participated in

the NPR-A lease sale have completedpayments on their bids, BLM said Jan.7.These companies consist ofConocoPhillips Alaska with 33 leases;Petro-Canada (Alaska) with 17 leases;FEX with 11 leases; Anadarko and Petro-Canada with 50 percent each on 13 leas-es; and FEX with 60 percent and Petro-Canada with 40 percent on three leases.For the most part these companies bid ontracts that extend their existing lease posi-tions in and adjacent to NPR-A.

ConocoPhillips extended its explo-ration fairway around the Moose’s Toothunit in northeastern NPR-A, as well asbuying some leases west of Umiat andsome others around the Ikpikpuk River.

“We’re going to be active in the com-ing year, so we’re just putting togetheradditional acreage as we continue toexplore,” ConocoPhillips Land ManagerDavid Brown told Petroleum News inSeptember. “We’re excited about ourposition in Alaska.”

On Jan. 7 ConocoPhillips spokes-woman Natalie Lowman confirmed withPetroleum News that the company is pro-ceeding with plans to drill two wells inthe Moose’s Tooth unit this winter.

Moose’s Tooth sits in an explorationfairway extending southwest from theAlpine field in the Colville River delta —success in the Alpine field has encour-aged ConocoPhillips and its partnerAnadarko to actively explore into north-east NPR-A.

Gas near UmiatAnadarko and Petro-Canada picked up

a swathe of leases extending northwestfrom Umiat on the eastern boundary ofNPR-A, with Petro-Canada by itself pick-ing up some tracts further to the southwest.Anadarko, with its partners Petro-Canadaand BG, is engaged in a multiyear drillingprogram, assessing the developmentpotential of gas pools in the Umiat area.

FEX already had a substantial acreageposition in NPR-A prior to the Septemberlease sale and the leases that the companybid on in September built on that position.In 2007 FEX put its Alaska explorationdrilling on hold for two years. However,the new leases give the company anotherexploration option if the company elects torecommence its NPR-A operations, per-haps in 2010, Richard Garrard, FEX’s geo-science manager in Alaska, told PetroleumNews in September.

Although Anadarko, Petro-Canada andBG are clearly exploring for natural gas inthe Umiat area, Garrard said that FEX isinterested in finding oil as well as gas.ConocoPhillips is presumably looking foroil in the Moose’s Tooth area, althoughsome of that company’s leases elsewherein NPR-A appear to be located in moregas-prone areas. �

PETROLEUM NEWS • WEEK OF JANUARY 11, 2009 19

I want in!

have legislated environmental assessmentresponsibilities along the proposedpipeline route.

The letter dated Dec. 23 and signedby Rick Edjericon and Frank Pokiak saidthe recently announced December 2009completion date for the panel’s work“came as a major surprise when we hadrecently been led to believe that a rea-sonable expectation would be for theEnglish version of the panel’s finalreport to be available by the end ofMarch 2009, with the final publishedreport to be available by the end of June2009.”

“The revised length of the (panel’s)environmental impact review process isnow significantly longer than that origi-nally set out in the (2004) agreement andthe investment of time and resources hasto date been much greater than had beenanticipated as being necessary for thisreview.”

March 31 requested dateThe letter said the panel should

release a “decision document” by March31, followed by “supplementary docu-ments” by Aug. 31. There has been noimmediate response from the panel.

The panel is mandated to deliver rec-ommendations on the MGP’s environ-mental and socioeconomic impacts toresponsible federal cabinet ministers, theNational Energy Board, the MackenzieValley Environmental Impact ReviewBoard, and the Inuvialuit and responsi-ble authorities.

Faced with sifting through a moun-tain of submissions and 11,000 pages of

transcripts from 115 hearing days —amounting to one of the most compre-hensive environmental impact reviewprocesses in Canadian history — theJRP has kept stretching the timetable forcompletion of its report since the hear-ings wrapped up in late 2008.

The MGP co-venturers, led byImperial Oil, had hoped for NEBapproval in 2008 and all regulatoryapprovals in 2009, allowing gas to startflowing from the Mackenzie Delta in2014.

Imperial disappointedA month ago the JRP disclosed it

would not release its report untilDecember 2009.

“We understand that there is tremen-dous interest in the panel’s findings, butwe are required and committed to baseour findings on a full and fair review ofthe evidence,” Hornal said in a state-ment.

That came just days after federalEnvironment Minister Jim Prentice, thecabinet minister responsible for oversee-ing the MGP, said he expected the JRP todeliver its report no later than May 2009.

Word of a further delay prompted asharp reaction from Imperial, whosespokesman Pius Rolheiser said the newtarget date was “well beyond anythingwe had expected … (and was) clearly adisappointment for us and the project.”

Prentice said he, too, was disappoint-ed to hear the revised timeline.

Northwest Territories Premier FloydRoland said that as delays piled up,without any clear answer as to why, theconfidence of the business community inthe NWT was being shaken.

The Inuvik Town Council called forthe dismissal of JRP members.�

continued from page 1

PETRO-HUNTcontinued from page 1

MAC PANELOn the WebSee previous Petroleum News coverage:

“$30.9M for NPR-A,” in Sept. 28, 2008,issue atwww.petroleumnews.com/pnads/489176008.shtml

Many of the leases that Petro-Hunt is giving up would have

formed a fairway around and tothe east of the Ikpikpuk River,

which flows south to north up theboundary between Northwest and

Northeast NPR-A.

20 PETROLEUM NEWS • WEEK OF JANUARY 11, 2009

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