They got it! · 11 Sticky time for Alberta oil sands: ... 15 Agrium names new Kenai Nitrogen team ... Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status Alaska Rig

page6

Alaska lawmakers look atalternatives to 20/20 oil tax

Vol. 11, No. 29 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of July 16, 2006 • $1.50

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4Mackenzie hearings insult aboriginals: An overlooked

pipeline link in gas project is front-and-center as group vents

11 Sticky time for Alberta oil sands: Bodman visits amidgrowing debate over frantic pace of expansion; reality check needed?

16 Alaska loses out to other investments: XTO defersMiddle Ground Shoal drilling this year, will probably do it in ’07

Buyers can’t be choosers

When the Tai an kou heavy lift vessel arrived in the Gulf of Mexico inearly June to pick up the Tellus jack-up rig for its trip north to Alaska’sCook Inlet, its captain was in for a surprise. The kind of surprise some-body’s got to pay for. See full story on page 8 and related story on thispage. In the photo above, a worker repairs the hull plate.

MO

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Direct from Alberta to TexasEnbridge seeks support for new bullet pipeline to Houston refineries

By GARY PARKFor Petroleum News

he jostling to build more oil pipeline capacity outof Alberta has turned from push to shove, withEnbridge quietly unveiling plans for a possible400,000 barrel-per-day direct link to Texas.

The 36-inch, C$3.6 billion system would coverabout 2,000 miles from the Hardisty Hub in Alberta tothe Houston refinery region and could be in service by2011, said Richard Bird, Enbridge’s executive vicepresident of liquids.

It also raises to six the number of ventures com-peting to access United States markets, offering 2.1million bpd of new export capacity on top of the 1.7million bpd of conventional and heavy crude Canadacurrently delivers to the U.S.

Bird said shippers have already shown interest in

the possibility of a bullet line, but it will be up to themto make the commitments that will see the project goahead.

Otherwise, Enbridge could offer a more expensivelink from either Chicago or Cushing, Okla., to Texas,but that longer route would require higher tolls.

Bird told a Calgary conference that contracted vol-umes of 400,000 bpd are required to make the newproposal economic.

The proposal sees Enbridge lock horns with pri-

In addition to the race to line up shippersthere is the challenge of developing newmarkets by matching various crude typeswith U.S. refineries which are reluctant to

sign long-term supply contracts.T

see ENBRIDGE page 14

Explorers lose Mackenzie testcase; Petro-Canada hikes Arcticoffer — again

Faced with increasingly bleak natural gas explorationprospects, Canada’s Mackenzie Delta and Beaufort Sea has seenits troubles compounded by a National Energy Board ruling thatcould give independent E&Ps second thoughts about embarkingon new wells.

Canada’s energyregulator sided withImperial Oil in its dis-agreement with sixexplorers who wantedthe proposed gas gath-ering pipelines andmain line down theMackenzie Valleydeclared a “singlepipeline” falling underNEB jurisdiction.

Instead the boardupheld the status quo,which puts the gather-ing network and a pro-cessing plant at Inuvik, Northwest Territories, under the CanadaOil and Gas Operations Act and the Mackenzie Valley line underits own control.

Anadarko, BP, Chevron Canada, Devon Energy, EnCana andNytis Exploration, all members of the Mackenzie ExplorersGroup, wanted the gathering operations to be overseen by theNEB, arguing that was necessary to achieve just and reasonabletolls, non-discriminatory service and fair access to transmissionsystems.

Anadarko, BP, ChevronCanada, Devon Energy,

EnCana and Nytis Exploration,all members of the MackenzieExplorers Group, wanted the

gathering operations to beoverseen by Canada’s National

Energy Board, arguing thatwas necessary to achieve just

and reasonable tolls, non-discriminatory service and fairaccess to transmission systems.

see EXPLORERS page 16

They got it!Stevens: Escopeta has its Jones Act waiver to bring jack-up rig to Alaska

By KAY CASHMANPetroleum News

scopeta Oil has receivedits Jones Act waiver tobring a jack-up drillingrig into Cook Inlet.

U.S. Sen. Ted Stevens, R-Alaska, made the announce-ment in Anchorage on July 7.

Escopeta Oil PresidentDanny Davis confirmed he had the waiver inhand. Homeland Security issued it June 27, hetold Petroleum News, and granted it in the interestof national security.

“Pretty soon Cook Inlet will be out of gas (see

chart, page 9). The two mili-tary bases near Anchorageneed it, and the people inSouthcentral Alaska need it.And we’re hoping to find it— plus a lot of oil,” Davissaid.

“The Maritime adminis-tration, the Department ofHomeland Security, theDepartment of Defense and

the Department of Energy all signed off on this,”he said. “And we had excellent support from ourCongressional delegation in Washington, D.C.,the governor, and the mayor of the Kenai

DANNY DAVIS BOB WARTHEN

Admin working contractIn-state gas sales, in-state open season, marketing all being addressed

By KRISTEN NELSONPetroleum News

roundtable discussion ofthe draft gas pipeline fis-cal contract will continueafter the Legislature

begins its second special ses-sion.

Sen. Ralph Seekins, chair-man of the Senate SpecialCommittee on Natural Gas Development, said thecommittee would continue the roundtable in the spe-cial session, in addition to working on legislation.The committee started work July 13 on the adminis-tration’s production profits tax and on a bill amend-ing the Stranded Gas Development Act.

Gov. Frank Murkowski’sadministration has said it isworking on concerns about thefiscal contract raised in publiccomments, including thingsthat need better explanationsand others that may result inchanges in the contract.

The roundtables were heldJuly 6 in Fairbanks and July 7in Anchorage, with participa-

tion by representatives of the administration and BP,ConocoPhillips and Exxon, as well as legislative con-sultants.

Roger Marks, a petroleum economist with theDepartment of Revenue, reviewed the proposal that

see WAIVER page 9

see CONTRACT page 15

AROGER MARKS JIM CLARK

E

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

2 PETROLEUM NEWS • WEEK OF JULY 16, 2006

NATURAL GAS

GOVERNMENT

PIPELINES & DOWNSTREAM

ON THE COVERThey got it!

Escopeta has its Jones Act waiver tobring jack-up rig to Alaska

Admin working contract

In-state gas sales, in-state open season, marketing all being addressed

Direct from Alberta to Texas

Enbridge seeks support for new bulletpipeline to Houston refineries

FINANCE & ECONOMY

EXPLORATION & PRODUCTION

6 Lawmakers look at alternatives to 20/20

Hawker, Samuels propose levy based on capital investment; Wagoner wants tax on gross; administration will reintroduce 20/20

5 ANGDA proposes in-state changes

CEO Harold Heinze: Alaska Natural Gas DevelopmentAuthority premised on having big project from which to build spur

7 White House delivers 1-2-3 verbal punch

Bush administration officials urge Alaska Legislatureto enact laws to speed gas pipeline construction

11 A sticky time for Alberta oil sands

Bodman visits Alberta amid growing debate over frantic pace of expansion; two former political leaders call for reality check

13 Anadarko continues Canada pullout

Bear Head LNG project to be sold to U.S. Venture Energy for $125 million; Anadarko has 18-month option on throughput

8 Songa needs more time to finish Tellus jack-up

4 Mackenzie hearings “insult” aboriginals

4 TransCanada urges Alaska gas contract completion

5 Does Alaska spur line qualify for federal loan guarantee?

6 Third phase of Alaska gas pipeline public process to begin

16 XTO defers Middle Ground Shoal drilling

15 Stevens, Murkowski urge state to move

15 Agrium names new Kenai Nitrogen team

16 Petro-Canada hikes Arctic offer — again

14 Oil sands: China feels Canadian cold shoulder

11 Oil sands shares dip as costs escalate

Explorers lose Mackenzie test case

PETROLEUM NEWS • WEEK OF JULY 16, 2006 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Workovers DS18-01 BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 1J-109 ConocoPhillipsDreco 1000 UE 16 (SCR) Workover D-15a BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD4-320 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk 1J-156 ConocoPhillipsTSM 7000 Arctic Fox #1 Stacked in Yard Pioneer Natural Resources

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES Workover DS 04-31 BPMid-Continental U36A 3-S Milne Point MPF-29 BPOilwell 700 E 4-ES (SCR) GPB J-28 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay Z-18 BPDreco 1000 UE 9-ES (SCR/TD) L-217i BPOilwell 2000 Hercules 14-E (SCR) Stacked at Cape Simpson AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked, Prudhoe Bay AvailableOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableOIME 1000 19-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Stacked, Kuparuk AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) DS 15-36B BP

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay K-2D BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay L5-28a BPIdeco 900 3 (SCR/TD) Kuparuk 3M-23a ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E Moving BP

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Drilling Long Lake #2 Aurora Gas

Kuukpik 5 Drilling Swanson River SCU 42-05X Unocal

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Rig move Marathon

Nabors Alaska DrillingNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Stacked in Kenai Available

Cook Inlet Basin – Offshore

Unocal (Nabors Alaska Drilling labor contractor)Not Available

XTO EnergyNational 1320 A Platform A C21A-23 XTONational 110 C (TD) Idle XTO

Mackenzie Rig StatusCanadian Beaufort Sea

Seatankers (AKITA Equtak labor contract)SSDC CANMAR Island Rig #2 SDC In cold shutdown at Paktoa Devon ARL Corp.

Mackenzie Delta-OnshoreAKITA EqutakDreco 1250 UE 62 (SCR/TD) Stacked in Tuktoyaktuk, NT Available

Yukon Territories Rig StatusNorthwest Territories

Ensign Resources Svc. Grp.Jackknife Double 55 Racked in Ft. Nelson

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of July 12, 2006.

Active drilling companies only listed.

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

This rig report was prepared by Alan Bailey

Baker Hughes North America rotary rig counts*July 7 June 30 Year Ago

US 1,659 1,66 1,394Canada 560 473 367Gulf 91 87 96

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUD

Y P

ATR

ICK

4 PETROLEUM NEWS • WEEK OF JULY 16, 2006

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NATURAL GASTransCanada urges contract completion

Hal Kvisle, president and chief executive of TransCanada, dropped in on theAlaska Legislature July 13 by letter, urging the state to complete its contract nego-tiations with the North Slope producers.

In the letter, which Gov. Frank Murkowski read parts ofduring his address to a jointHouse-Senate session of theLegislature, Kvisle saidTransCanada recognizes the

importance of the agreement the state has reached withNorth Slope producers. He said it is difficult to see how aNorth Slope gas pipeline project could proceed without theproducers, and reminded the administration that it hasadvised it to be wary of independent pipeline proposalswhich did not include the producers.

TransCanada has declined to join various consortiums to develop the pipelinewithout producer support, Kvisle said. He mentioned rights which TransCanadaholds in Alaska and said TransCanada continues to be willing to make those avail-able to an Alaska project as long as TransCanada builds the Canadian side of theline.

Kvisle said that with the resolution of some matters in the contract,TransCanada is generally supportive and urged the state to settle the contract andmove forward with the project.

—KRISTEN NELSON

HAL KVISLE

NEWS FLASH

Mackenzie hearings ‘insult’ aboriginalsAn overlooked pipeline link in the Mackenzie Gas Project is now front-and-

center as a northern aboriginal group gives vent to feelings that it has beenignored in the process.

Chief James Ahnassay of the Dene Tha’ seized his chance during a two-dayregulatory hearing to question the legitimacy of the regulatory phase that he saidhad become “deeply hurtful and insulting” to his community of 2,500 residentswhose lands embrace the southernend of the Northwest Territories,northeastern British Columbia andnorthwestern Alberta.

He told a session of the envi-ronmental Joint Review Panel thatthe Dene Tha’ were participating“under protest” because multi-mil-lion dollar access and benefitsagreements signed with theMackenzie proponents stop at theNorthwest Territories border.

The Canadian government haspromised to spend C$500 millionover 10 years to help aboriginalsalong the Mackenzie Valleypipeline route in the Northwest Territories handle the project impact, but allocat-ed only C$600,000 to the Dene Tha’ which took its objections to Federal Court ofCanada, arguing hearings should be postponed until the concerns had beenresolved.

Alberta leg will create no new jobsThe Alberta leg is expected to cost about C$212 million and involve 400 work-

ers during a single construction season, after which the connection will be operatedby remote control from Calgary, creating no new jobs for the Dene Tha’ in Alberta.

Ahnassay told the panel the Dene Tha’ should receive benefits to tackle thesocio-economic impact of the pipeline in a region where the project threatens thehunting lifestyle of the people.

“We should have been fully consulted from Day 1, just like everybody else. Butthat’s not the avenue they have taken,” he said.

Instead, the Dene Tha’ have been limited to making only a presentation to thehearings, although TransCanada, which will operate the main line, said it is work-ing with the Dene Tha’ under a “community cooperation protocol.”

But separate hearings to be conducted by the Alberta Energy and Utilities Boardoffer no assurances that recommendations by the Joint Review Panel will be hon-ored in the province, which reinforces Ahnassay’s view that the Dene Tha’ are beingdiscriminated against.

Without issuing any specific threats he told the Edmonton Journal “there comesa breaking point. ... We have reached that” because of past experience that showsnew pipelines always generate additional resource activity to the detriment of theaboriginal lifestyle.

—GARY PARK

Chief James Ahnassay of the DeneTha’ seized his chance during a two-day regulatory hearing to question

the legitimacy of the regulatoryphase that he said had become

“deeply hurtful and insulting” to hiscommunity of 2,500 residents whoselands embrace the southern end of

the Northwest Territories,northeastern British Columbia and

northwestern Alberta.

PETROLEUM NEWS • WEEK OF JULY 16, 2006 5

● N A T U R A L G A S

ANGDA proposes in-state changesCEO Harold Heinze: Alaska Natural Gas Development Authority premised on having big project from which to build spur

By KRISTEN NELSONPetroleum News

laska Natural Gas Development Authority plans arepremised on having the big North Slope gaspipeline project go forward, and “if that requires thecontract we need to help make that happen,” Harold

Heinze, ANGDA’s chief executive officer, said at a June12 board meeting.

Heinze got board approval for comments on the draftfiscal contract Gov. Frank Murkowski’s administrationhas negotiated with BP,ConocoPhillips and ExxonMobilfocused on in-state use of naturalgas.

He said in response to a questionfrom ANGDA Vice-Chair ScottHeyworth, that if there is no big gasline, then none of ANGDA’s work isa throwaway. In addition to a spurline, ANGDA has looked at what itcalls a bullet line, a pipeline fromthe North Slope to SouthcentralAlaska that would be a much smaller diameter than theproposed 48-inch to 52-inch mainline pipe to the Lower48.

Board Member John Kelsey noted that there is “aground swell” of people trying to kill the contract andHeinze said he’s well aware there are forces pulling lotsof different ways. He told the board his objective is tooffer commentary on the contract to make its provisionsworkable for in-state gas.

The administration has asked for constructive sugges-tions, he said, and what he’s proposing are negotiatingpositions. None of these proposed changes should be dealkillers, Heinze said.

ANGDA’s suggestions include:

ANGDA not named, but included under stateANGDA is not named in the contract, Heinze said, but

is part of the fiscal contract because it is not excluded. The contract defines state as “the Alaska government,

but excluding its judiciary and any independent or quasi-judicial regulatory agency, such as the RegulatoryCommission of Alaska or the Alaska Oil and GasConservation Commission.”

Assistant Attorney General Ken Diemer told the boardit appeared to him that Heinze was correct, since ANGDAis a non-judicial type of agency.

The contract modifications ANGDA recommendedunder Article 7, state ownership, include: defining a coor-dinated state approach where ANGDA handles the in-state activities and Alaska Pipe (the limited liability com-

pany that would be formed to handle the state’s equityinterest in the mainline pipe) handles interstate export;involving ANGDA in the development of the LLC forpipeline ownership; having the lateral line delivering gasto Cook Inlet be another element in the mainline gas proj-ect to allow use of the federal loan guarantees; providing

the same tax credit to in-state gas transmission pipelineinvestors as given to North Slope gas gathering pipelinesto encourage in-state infrastructure development; andremoving ANGDA from the contract’s definition of stateso there are no unintended consequences.

Heinze said the tax credit, 35 percent, would reducethe tariff for the spur line by taking one-third of the costoff the top.

Potential role in marketingIn Article 9, in-state markets, ANGDA proposed that

parties to the contract provide a free option on up to 5 per-cent of throughput capacity, similar to a pledgeConocoPhillips made for an Alabama liquefied naturalgas terminal, described in media coverage as a “no-cost”option to buy up to 200 million cubic feet of gas per dayat market rates, the average spot market price. It suggest-ed the state make a statutory commitment of a portion ofits state gas to in-state consumers to allow certainty of gasavailability for Alaska utilities and manufacturers as theyobtain financing to back their open season commitmentsand also recommended assigning ANGDA the commer-cial buy-sell role in Alaska, and requiring a study ofANGDA as an aggregator of in-state demand and royaltygas for in-state use as a potential way to facilitate the par-ticipation of smaller in-state gas utilities.

FERC and state regulatory agenciesArticle 8 of the draft contract, “Regulation of and

access to project facilities and disposal services,” saysregulation is expected to be exclusively under the NaturalGas Act, the Alaska Natural Gas Act of 2004, other appli-cable federal law and the contract and if federal law doesnot apply, regulation will be by commercial agreements.The Federal Energy Regulatory Commission andCanada’s National Energy Board shall have exclusivejurisdiction and if the Regulatory Commission of Alaskaimposes regulations which cause a loss to a participant inthe project, the state will reimburse the participant for theloss.

As with Article 7, ANGDA is requesting that it — andRegulatory Affairs and Public Advocacy within theDepartment of Law — be excluded from the definition ofstate. In addition it is requesting that appropriate actionsfor the RCA in the in-state open season process be speci-fied; that FERC provisions governing conduct of openseasons, mileage-based tariff calculations, capacityexpansions and non-discrimination be incorporated in thecontract; that the contract preserve the right of anyagency of the state to appeal to FERC; acknowledgeRCA jurisdiction over Alaska utilities; and reaffirm theAOGCC’s preeminence on producing-field conserva-tion issues. ●

Does spur line qualify forfederal loan guarantee?

Assistant Attorney General Ken Diemer told theAlaska Natural Gas Development Authority June12 that a contract with Preston, Gates & Ellis willget the authority an opinion on whether or not aspur line qualifies for federal loan guarantees underthe Alaska Natural Gas Pipeline Act.

Harold Heinze, the authority’s chief executiveofficer, said if a spur line qualifies for the federalloan guarantees it would lower the cost of interest,which would reduce the tariff. Heinze said it’s notobvious that the authority qualifies, but if it does,that could halve the tariff for a spur line from themainline to bring gas to Southcentral.

Board members were interested in why a limitedliability company was proposed under the fiscalcontract to manage the state’s interest in the main-line project when ANGDA already exists.

Board Member Dan Sullivan, also a member ofthe Anchorage Assembly, said he mentionedANGDA’s ability to manage the state’s equity in themainline project when Gov. Frank Murkowskibriefed the assembly, but said he didn’t get muchcomment back. Sullivan said he doesn’t see “own”in the ANGDA language, while it does occur in theAlaska Pipe LLC language.

Diemer and Heinze walked the board through acomparison of ANGDA’s statutes and those pro-posed for Alaska Pipe, which would manage thestate’s ownership interest in a North Slope gaspipeline under the proposed fiscal contract.

The purposes are similar, although that of AlaskaPipe is more specific; both are public corporationsand instrumentalities of the Department of Revenuebut with legal existence independent of and sepa-rate and apart from the state; their powers are virtu-ally identical; and both have authority to issuebonds and/or securities to finance projects.

Heinze said both the authority and Alaska Pipehave the same ability to act as businesses and thereisn’t much in a business sense that either can’t do.

—KRISTEN NELSON

A

HAROLD HEINZE

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By MATT VOLZThe Associated Press

wo Anchorage lawmakers aim tobreak a stalemate over the rewrite ofAlaska’s oil production taxes with analternative version of a proposal to

tax oil companies’ profits.Republican Reps. Mike Hawker and

Ralph Samuels have come up with a con-cept they hope other legislators will seeas a compromise to the tax bill that hasalready been rejected twice this year.

The plan would still replace Alaska’sproduction tax with one based on oilcompanies’ Alaska profits, with thepotential of increasing revenue to thestate by hundreds of millions, if not bil-lions, of dollars at high oil prices.

But Hawker and Samuels’ proposaldeparts from the original in its approachto the most disputed part of the bill: therate at which company profits would betaxed.

State lawmakers have twice failed tonegotiate that base tax rate. First, theSenate rejected the House’s rate of 21.5percent at the close of the regular session.Then, the House rejected a conferencecommittee’s negotiated 22.8 percent ratein the first special session.

Both chambers dismissedMurkowski’s 20 percent tax rate propos-al, which was agreed upon by the three oilcompanies with whom the governor

negotiated tax androyalty terms for anatural gas pipeline.

Tax rate based oninvestment

Hawker andSamuels decided totake a differentapproach for theyear’s second spe-cial session, which begins July 12. Theiridea is to base each oil company’s tax rateon the level of capital investment thatcompany makes in the state. If a compa-ny put more money into the state, itwould be taxed at a lower rate. If a com-pany did not meet acertain level, itwould be taxed at ahigher rate.

The concept ismeant to bringtogether those whowant a 20 percenttax rate and thosewho want a 25 per-cent tax rate as wellas encourage oilcompanies to spend more money on cap-ital projects in Alaska and slow the rate atwhich oil production is drying.

“The driving issue is the decline in oilproduction,” Hawker said. “As in allthese proposals, the devil is in the details.

We’ve got to recog-nize the differentcircumstance of thesmall producers andexplorers. But we’renot going to get any-where if we don’tget to the table.”

Samuels said theplan is still a conceptat this point — “We

haven’t fleshed out where the numberswould be” — and he and Hawker firstwanted to see if it was practical enough towork. After conversations withDepartment of Revenue officials,Samuels said, he thinks it could be done.

He said the nextstep will be for thepair to brief theirfellow legislatorsand the industry onthe proposal, andfrom there it willtake shape.

Theirs will beone of possiblythree productiontax proposals law-makers may have

before them this special session.Murkowski plans to reintroduce a ver-

sion of his 20 percent profits tax billtoday, according to spokesman JohnManly.

The governor will address a joint ses-sion of the House and Senate onThursday, July 14, as Petroleum Newsgoes to press, about the two issues of thespecial session: the production taxchanges and a bill giving Murkowski theauthority to negotiate the gas deal withBP, ExxonMobil and ConocoPhillips.

Also bill based on grossAlso, Senate Resources Chairman

Tom Wagoner, R-Kenai, said he has a billready that would tax companies based ontheir gross production of oil and gasinstead of their profits.

Wagoner firstannounced that planearlier in July at anappearance support-ing Republicangubernatorial candi-date John Binkley,who has attackedMurkowski’s oil taxplan and his gas dealwith the three oilcompanies.

A tax on gross production would beless of an overhaul and more of an adjust-ment to the current tax system. That sys-tem is seen as being flawed because of acomplex formula called the EconomicLimit Factor that has allowed several oilfields to pay minimal or no productiontaxes.

Wagoner said he is willing to look atthe proposal by Hawker and Samuels.

“I’m not going to tell you right nowthat mine is better than theirs,” Wagonersaid. “It’s a new concept, and I’m notgoing to dismiss it out of hand. But I’vegot to look at what it does to the littleguy.”

Democrats favor tax on grossLegislative Democrats, the minority

in the House and Senate, have been call-ing for a gross production tax for sometime. They say it would be easier toimplement and would make it harder foroil companies to cook the books, where-as they believe the companies couldmanipulate a net-profit tax.

“I’ve always preferred gross,” saidSen. Kim Elton, a member of the SenateResources Committee. “You can’t gameit. It’s a tax we’ve had for many, manyyears. We understand it, the producersunderstand it.”

Elton had not seen Hawker andSamuels’ proposal but said he was gladlawmakers were talking about alterna-tives instead of repeating the samedebate that has twice failed to result in apassed bill.

Senate PresidentBen Stevens, R-Anchorage, said theSenate will likelylet the House takeaction on the taxbill first.

“I think theSenate is probablyin a position to waitto see what theHouse does,” Stevens said. “The Senatehas been consistent in what it’s donethroughout this entire debate. The Househas had a lot of deliberations and gyra-tions about what they’re going to try todo.”

Stevens announced earlier in July thathe won’t run for re-election, but hislame-duck status won’t change the taxdebate, he said. Stevens supportsMurkowski’s original tax plan.

“It’s going to take more than an influ-ential leader in the Legislature to changeminds. The issues have been before usfor so long,” he said.

The governor still supports his 20percent profit-tax plan. Murkowski con-sultant Dan Dickinson said he hashelped Hawker and Samuels to someextent as they shaped their idea, butthere is nothing to it yet.

“I have not taken that concept and runit up the administration’s flagpole to seeif anyone salutes,” Dickinson said.

However, Dickinson acknowledgesthat some changes will be necessary forthere to be a breakthrough this specialsession.

“I don’t think people are very opti-mistic to just reintroducing the bill andhoping for a different result. Can wechange parts of it, and what’s necessaryto get the reforms?” he said. ●

6 PETROLEUM NEWS • WEEK OF JULY 16, 2006

NATURAL GASThird phase of public process to begin

Alaska Gov. Frank Murkowski said July 7 that a series of meetings will be heldJuly 17-July 24 to provide more explanation and answers to questions raised bythe public about the draft fiscal contract the administration has negotiated withBP, ConocoPhillips and ExxonMobil.

“Many members of the public throughout the state had questions and concernsregarding the proposed gas pipeline contract,” Murkowski said. “It is our obliga-tion to provide Alaskans with the best business deal possible, and we feel the con-tract we have negotiated with the three producers is just that. But it is evident fromthe public that we need to answer their questions and give better explanations ofwhat is in the contract.”

The Department of Revenue hosted public forums run July 17-July 24: Juneau, July 17, 12 p.m.-3 p.m., Centennial Hall; Kenai, July 18, 2 p.m.-5 p.m., Challenger Learning Center; Fairbanks, July 19, 2 p.m.-5 p.m., UAF Downtown Center; Anchorage, July 20, 2 p.m.-5 p.m., UAA Consortium Library; Mat-Su, July 21, 2 p.m.-5 p.m., Palmer Depot; Eagle River, July 21, 7 p.m.-9 p.m., Eagle River Parks/Rec Office; and Barrow, July 24, 1 p.m.-5 p.m., North Slope Borough Assembly Room.

—PETROLEUM NEWS

● G O V E R N M E N T

Lawmakers look at alternatives to 20/20Hawker, Samuels propose levy based on capital investment; Wagoner wants tax on gross; administration will reintroduce 20/20

TRep. Mike Hawker

Sen. Ben Stevens

Sen. Kim Elton

Rep. Ralph Samuels

Hawker and Samuels decided totake a different approach. Their

idea is to base each oil company’stax rate on the level of capital

investment that company makes inthe state. If a company put moremoney into the state, it would be

taxed at a lower rate.

PETROLEUM NEWS • WEEK OF JULY 16, 2006 7

● N A T U R A L G A S

White House delivers1-2-3 verbal punchTop Bush administration officials urge Alaska Legislature to enactlaws to speed construction of North Slope to Lower 48 gas line

By ROSE RAGSDALEFor Petroleum News

pparently losing patience with foot-dragging in Juneau, the WhiteHouse is urging the AlaskaLegislature to get on with the busi-

ness of developing an Alaska gas pipelinein three separate messages from top Bushadministration officials in recent weeks.

The missives came during the twoweeks leading up to a second special ses-sion of the Legislature scheduled to beginJuly 12. State lawmakers were to againconsider the controversial gas line con-tract the Murkowskiadministration inkedthis spring with thethree North Slopegas producers, BP,ConocoPhillips andExxonMobil. TheLegislature failed toratify the contract inthe regular legisla-tive session thatadjourned in May orin an initial special session in June.

Delivering sequential verbal punches,Joseph T. Kelliher, chairman of theFederal Energy Regulatory Commission,U.S. Energy Secretary Samuel Bodman,and Vice President Dick Cheney made itknown that Alaska could soon be on theropes in its fight to deliver much-needednatural gas to the Lower 48.

Kelliher outlined dangers of waitingtoo long to set in motion licensing andconstruction of the proposed 4.5-billion-cubic-feet-a-day gas line from the NorthSlope to the Lower 48.

Writing to Gov. Frank H. Murkowski,Kelliher reiterated his belief that Alaskanatural gas would be an important addi-tion to future supplies needed by Lower48 markets. He also summarized the find-ings of a report FERC submitted toCongress July 10 on the status of theAlaska gas pipeline. It is the second in aseries of reports FERC’s staff must pre-pare for Congress every six months undersection 1810 of the Energy Policy Act of2005.

Because the state Legislature did notapprove the gas line contract developedunder the Alaska Stranded GasDevelopment Act this spring, “the oppor-tunity for beginning meaningful develop-ment of an application in 2006 has beenmissed,” Kelliher said.

But “if a project sponsor is ready tobegin developing its application and con-ducting necessary field surveys in thespring of 2007, it is possible that an appli-cation could be filed at the Commissionbefore the end of 2008,” he added.

‘Window’ may be closing“The report states, however, that

whether the project sponsor begins devel-oping an application and conducting fieldsurveys in the spring of 2007 dependslargely on the Alaska state Legislatureacting this summer. If not, the Alaska gaspipeline will be further delayed,” Kelliherwrote.

Why the hurry? Kelliher said a window of opportunity

for Alaska gas may be rapidly closing.

While Alaska North Slope gas oncewould have competed only with otherNorth American gas production, the U.S.natural gas market is turning increasinglyto imported liquefied natural gas to meetincremental growth, he explained. FERChas approved LNG import facilities in thepast year with the capacity to delivernearly 45 bcf per day of gas to the U.S.market.

Kelliher also noted that while the 35trillion cubic feet of proved North Slopegas reserves represents about 13 percentof 263 tcf in proved gas reserves in NorthAmerica, it is less than 1 percent of 6,044tcf in proved reserves worldwide.

The report further predicts that giventhe large capital investment in LNG facil-ities, LNG exporters will prefer to estab-lish long-term relationships and that ifthere is no substantial progress on build-ing an Alaska pipeline, gas buyers in theLower 48 will be more likely to enter intolong-term LNG contracts.

Construction of the gas line was onceprojected to cost $18 billion to $20 bil-lion, but the estimate already has climbedto about $25 billion and will likely con-tinue to rise with further delays, FERCsaid.

Thus, Alaska’s pipeline project may beat risk of being marginalized in the searchfor new natural gas supplies for U.S. con-sumption, Kelliher said.

Feds doing their partThe report indicated that work on the

gas pipeline at the federal level is movingapace with significant activity, includingnomination of a federal coordinator, DruePearce, in June; completion of an intera-gency memorandum of understanding inMay among 15 federal agencies pledgingcooperation on pipeline matters; comple-tion of an in-state demand/needs study bythe U.S. Department of Energy in June;and the commencement of alternativemeans of pipeline construction study byDOE in April.

The FERC chairman also observedthat the McKenzie Gas Pipeline Project inCanada and unconventional sources ofgas in the Lower 48 no longer pose sig-nificant competition to the Alaska gasline.

Bodman urged the Legislature to takeaction this summer in a two-page letterdated July 6. The secretary urged the leg-islators to consider the best interests ofthe nation as well as Alaska in their delib-erations.

“Wellhead gas prices in the lower 48states more than doubled from 2002 to2005; that price increase has greatlyincreased consumer natural gas pricesand has adversely affected gas intensiveindustries such as fertilizer productionand petrochemicals, resulting in plant clo-sures and job losses,” Bodman said.

Cheney, who wrote to the LegislatureJune 27, reminded the lawmakers thatPresident Bush said America needs theenergy Alaska natural gas can provide,and urged them to enact legislation thissummer to facilitate construction of theAlaska gas pipeline.

“Your early action is necessary tomove the process forward,” Cheneyadded. ●

A

FERC ChairmanJoseph Kelliher

8 PETROLEUM NEWS • WEEK OF JULY 16, 2006M

OD

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Engine room inspection

Starboard deck

Repairs above and in the photo to the right

Songa needs more time to finish TellusWhen the Tai an kou heavy lift vessel arrived in the Gulf of Mexico in June to

pick up the Tellus jack-up rig for its trip north to Alaska’s Cook Inlet, its captain wasin for a surprise. The kind of surprise somebody’s got to pay for.

The Tellus, an independent-leg cantilever jack-up, was at a shipyard in PortArthur, Texas, undergoing an extensive retrofit and refurbishment by its owner,Songa Offshore, before being deployed to upper Cook Inlet to drill three wells forEscopeta Oil. It was supposed to be ready in late May or early June for the trip north.

So when representatives of Moduspec USA went to check on the status of thejack-up to commission it for its trip north, they told Escopeta the refurbishment wasrunning four to five months behind schedule because of difficulties in getting work-ers and equipment and supplies.

But buyers (in this case lessees) — even unpleasantly surprised ones — can’t befussy in today’s jack-up market; especially those who locked in their day rate sever-al months ago.

So, Escopeta President Danny Davis renegotiated his contract with Tai an kou’sowner, Coscol (HK) Investment & Development Co. of Hong Kong.

The vessel, he said, will be back in December to pick up the Tellus for the jour-ney to Alaska.

But the news wasn’t all bad. The new schedule works for Escopeta and its part-ner Centurion Gold Holdings.

“The timing works because it takes about 60 days to get up there, and leaving in,say, mid-to-late December puts us there at the end of February. If everything worksout we could be drilling the first or second week of March,” Davis said.

“That gives us just enough time to drill our three wells before the end of the sea-son,” he said.

The primary objective of its visual inspection, Moduspec said in its report toEscopeta, was “to assess the status of the rig, its equipment, and all of the rig systemswith respect to their operational readiness and capability to work safely and effi-ciently.” (See adjacent photos from Moduspec’s report.)

Several sections of the hull were being replaced at the time of the inspection, soModuspec was not allowed to inspect the underside of the vessel, but the report didnote that “several barges and scaffolding were being used to facilitate the work.”

“Based upon the existing condition of the rig and the activities that were observedon the day of the inspection, it is Moduspec’s professional opinion that if all activi-ties progress efficiently and without interruption, the rig may be ready to drill inapproximately 90 days from the date of this report. However, this assumes that all ofthe newly installed equipment is functioning properly as a system. This estimated 90-day period does not include the period of time normally reserved for SystemIntegration Tests (SITs),” Moduspec said in its report.

Davis said based on the fact there is still major reconstruction work to be done onthe derrick and rig floor, he decided to go with a December load date for the Tellus.

—KAY CASHMAN

Peninsula Borough and his liaison, BillPopp.”

The Jones Act waiver is “a one-timewaiver, to bring the jack-up to Alaskaonly. When it leaves, Songa is taking theTellus to the Middle East,” he said so theJones Act won’t be a factor.

The Jones Act requires U.S. flaggedvessels be used between U.S. ports.Escopeta and its partner in its Cook Inletacreage, Centurion Gold Holdings, haveto use a foreign-flagged vessel to trans-port the Songa Offshore Tellus jack-upfrom the Gulf of Mexico to Alaskabecause there are no American-flaggedvessels “capable of moving a rig likethis,” Davis said.

Hong Kong-based Coscol (HK)Investment & Development Co.’s 520-foot-long Tai an kou heavy lift vessel willbe doing the job. It will take 60 days toreach Alaska from Port Arthur, Texaswhere the Tellus is currently being refur-bished.

Initially Escopeta, operator of the130,000 acres it and partner Centurionown in the Cook Inlet Basin, was expect-ing the Tellus to be ready to load in June,but Moduspec USA did a rig inspectionon June 23 and told Escopeta that Songaneeded more time to complete the refur-bishment. Consequently, the jack-up willhead to Alaska in December instead ofJune (see adjacent sidebar).

Escopeta plans to spud the first ofthree 2007 inlet wells using the jack-upin March at its East Kitchen prospect.

“Then we’ll move it to our Kitchenprospect, and then do a delineation wellat East Kitchen or Kitchen depending onwhat we’ve found,” Davis said.

Entrix, the company handling the per-mitting for Escopeta, is “finishing thepermitting as we speak,” Davis said.

Bob Warthen, general manager ofEscopeta’s new Alaska affiliate, EscopetaEnergy Co., is working with the state tounitize the two prospects into a singleKitchen unit.

Estimate 1.7 billion barrels of oil, 7.5 tcf of gas

How much oil and gas do Escopeta

and Centurion hope to find? “In our Kitchen prospects alone we

think we have 1.7 billion barrels of oiland 7.5 tcf of gas in un-risked, in-housereserves — 450 million barrels and 2.5tcf at East Kitchen and 1.3 billion barrelsand 5 tcf at Kitchen,” Davis said.

The Kitchen prospects are offshore theKenai Peninsula in 70 feet of water closeto the Kenai industrial complex north ofNikiski. Escopeta has almost 12 years ofwork in the prospects, including thereprocessing of seismic by Houston-based Apex Metalink with its proprietarytechnology.

Kitchen and East Kitchen are east ofthe Middle Ground Shoal field whereXTO Energy is doing additional develop-ment work to improve on the 12 millionbarrels of reserves it bought from ShellOil in 1998. Shell developed the eastflank of the Middle Ground Shoal struc-ture in the 1960s and it moved on to thewest flank in the late 1980s.

If Escopeta’s theories on oil migrationin the inlet are correct, the oil in theMiddle Ground Shoal structure migratedfrom east to west, filling Escopeta’sKitchen prospect traps first before mov-ing on to Middle Ground Shoal and thenon to subsequent traps. “The theory on

migration of oil is that the migrating oilfinds a path, and then travels along thatpath, not deviating from it,” Warthensaid. “When it leaves the source area, itmigrates up dip and fills the deepest trapsfirst. As these are filled the oil continuesto migrate updip filling the shallowesttraps in turn.”

He said Middle Ground Shoal is about80 to 85 percent filled while structuresfarther along the migration path are lessfilled, supporting the idea that theKitchen structures were filled beforeMiddle Ground Shoal.

If that is true, the Kitchen structureswould likely contain a great deal of oiland gas, a state geologist told PetroleumNews.

Warthen has worked Cook Inlet since1967, first for Union Oil (Unocal, now

Chevron) where he was a regional geolo-gist for 26 years, and then as a consultant.

After he took an early retirement fromUnocal in 1992, he began working all theavailable data on the inlet, developing abasin map that identified acreage lateracquired by Escopeta as having high oiland gas potential. Escopeta now ownssome 130,000 acres of oil and gas leasesin the Cook Inlet basin and Warthen hasgone from consultant to part owner andexecutive.

Current Cook Inlet production is fromTertiary formations: dry gas fromSterling, Beluga and upper Tyonek; oilfrom the lower Tyonek and Hemlock.There is no production from the olderCretaceous and Jurassic in the upperCook Inlet basin, although surface oil

PETROLEUM NEWS • WEEK OF JULY 16, 2006 9

Cook Inlet Hiistoric and Projected Natural Gas Production1958 - 2025

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Beluga River

North Cook Inlet

continued from page 1

WAIVER

see WAIVER page 10

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seeps are known from the JurassicTuxedni formation.

The Tuxedni, said Warthen, has beenidentified by the USGS as the sourcerock for all of the oil present in theHemlock.

Davis said potential deep gas belowthe Tertiary is a separate prospect. Theobjectives at Kitchen and East Kitchenare the major producing Cook Inlet for-mations, the Sterling, Beluga, Tyonekand Hemlock. Escopeta does not attrib-ute any reserves to pre-Tertiary, he said,but considers them a very viable futuretarget.

USGS theories hold that only 4 per-cent of the volume of oil that theoretical-ly generated from Cook Inlet source rockhas been identified. If Escopeta’sapproach bears fruit, it will fill in manyof the blanks in Cook Inlet knowledge,with a payoff for the company.

“We believe that these prospects areamong the missing giants postulated bythe U.S. Department of Energy in itsrecent report on Cook Inlet,” Warthensaid.

Bill Rutter Jr. of Rutter and Wilbanks,another Cook Inlet player, said most ofthe inlet wells “have only been drilledinto the top of the structure. … But youdon’t know how much oil and gas is in astructure until you drill down the sides ofit, drill deeper.” Escopeta’s Kitchenwells will be drilled to 16,000-17,000feet as compared to an average verticaldepth of approximately 12,000 feet forthe deepest inlet wells.

ASRC Energy Services will be themain contractor on the Kitchenprospects. It will oversee Inlet Drillingcrews that were trained for the Tellus bySonga.

A fourth well onshore in JanuaryASRC Energy will also oversee a

fourth well for Escopeta in 2007, whichwill be drilled first, in January, at theHouston independent’s North Alexanderprospect.

The natural gas prospect lies onshoreon the northwestern edge of the CookInlet basin along the western margin ofthe Susitna River drainage. The prospectis six to 10 miles north of the StumpLake gas field; and six to nine miles eastof the Lewis River gas field, both ofwhich have established gas production.

North Alexander will be drilled usingeither a Nabors rig or one Escopetabrings in from Canada. “It all depends onwhat kind of price I can get fromNabors,” Davis said.

Escopeta estimates the three objec-tives at North Alexander — the Belugaand Tyonek formations (sandstones, silt-stones and pebble conglomerates) andthe shallower Sterling sandstones —hold almost 400 billion cubic feet of gas.

Well depth will be approximately9,500 feet. ●

10 PETROLEUM NEWS • WEEK OF JULY 16, 2006

continued from page 9

WAIVER

Bill Rutter Jr. of Rutter andWilbanks, another Cook Inlet

player, said most of the inlet wells“have only been drilled into the topof the structure. … But you don’t

know how much oil and gas is in astructure until you drill down thesides of it, drill deeper.” Escopeta’s

Kitchen wells will be drilled to16,000-17,000 feet as compared to

an average vertical depth ofapproximately 12,000 feet for the

deepest inlet wells.

By GARY PARKFor Petroleum News

hen former Alberta Premier PeterLougheed speaks, he is guaranteedan audience.

When former U.S. VicePresident Al Gore speaks, the same applies.

When the two of them, coming as theydo from opposite ends of the political spec-trum, raised qualms earlier in July aboutthe pace of development in the Alberta oilsands they rattledthose who believeoutput from the sec-tor will triple to 3million barrels perday by 2015 andcould reach 4.7 mil-lion bpd in 2020.

And among thosepaying attention willalmost certainly beU.S. EnergySecretary SamuelBodman who made aJuly 12-14 visit toAlberta to learn first-hand the scope of oilsands expansion andthe role the vastresource might playin helping PresidentGeorge W. Bushachieve his goal ofdrastically reducing oil imports from theMiddle East.

Bodman was due for a lively sales pitchfrom Alberta government and industryleaders about the unlimited potential of theoil sands to provide the U.S. with a secure,long-term source of energy.

The ground work was laid earlier in Julywhen Alberta Premier Ralph Klein toldVice President Dick Cheney in the WestWing of the White House that he couldexploit the oil sands in the November mid-term congressional elections.

Canada’s Prime Minister StephenHarper, in his first official visit toWashington on July 6, added to the full-court press by discussing with Bush thecritical role the oil sands could play in U.S.energy security.

The two leaders agreed to explore regu-latory cooperation to increase productionwhile placing an emphasis on the “environ-ment, climate change and air quality.”

Lougheed calls for moratoriumBut Bodman also arrived in the thick of

a heated debate erupting in Alberta as crit-ics of the economic and environmentalimpacts of converting sticky bitumen intosynthetic crude start to gain attention.

Their cause has received momentumfrom an unlikely quarter.

Lougheed, who was premier from 1971to 1979 and was a driving force in ensuringthe provincial government facilitated thepioneering oil sands ventures by SuncorEnergy and Syncrude Canada, is every-thing an elder statesman should be — intel-ligent, measured in what he says andrespected.

Thus he has shaken Alberta to the coreof its economic future by giving interviewsand speeches that call for a moratorium onnew projects (excluding those that havereceived regulatory approvals), giving citi-zens time to rethink where the frenzieddevelopment is headed and the governmenta chance to establish criteria to determinewhich projects can meet the new standards.

Those standards would likely includepreferential treatment of operations that useless or no natural gas to generate power forthe extraction and processing of bitumen,along with methods for capturing and stor-ing carbon, which is a byproduct of oilsands operations and a major contributor togreenhouse gases.

Lougheed’s concerns have been fueledby a recent trip he made to northernAlberta, where the regional governmentargues it is unable to pay for the infrastruc-ture needed to meet the demands of exist-ing oil sands ventures, let alone more thanC$100 billion that are scheduled over thenext decade.

The oil sands capital of Fort McMurrayhas seen its population more than double to75,000 over the last nine years and alreadyfaces a shortage of 3,000 homes as its num-bers grow by 10 percent a year.

PETROLEUM NEWS • WEEK OF JULY 16, 2006 11

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

A sticky time for Alberta oil sandsBodman visits Alberta amid growing debate over frantic pace of expansion; two former political leaders call for reality check

W

Alberta PremierRalph Klein

Former U.S. VicePresident Al Gore

Shares dip as costs escalateShares of leading oil sands players have taken a hit in the latest shake-up resulting

from capital cost overruns.Amir Arif, an analyst with Friedman Billings Ramsey, triggered a 2 percent drop

in Suncor Energy shares July 10 by suggesting that investors “should be taking prof-its” because the risk of falling short-term oil prices along with cost inflation “mutesour near-term enthusiasm” for the oil sands.

Shares of Shell Canada and Western Oil Sands, partners in the Athabasca project,were trimmed a few days earlier when they disclosed that pressures on labor, equip-ment and materials could delay their expansions plans.

Western, a 20 percent partner, set off alarm bells when it estimated the first expan-sion phase, to boost production by 100,000 barrels per day to 255,000 bpd, couldclimb by 50 percent to C$11 billion, setting the stage for the full three-stage ventureto rise from C$13.5 billion to above C$20 billion.

Shell has ordered project reviewsShell, the 60 percent operator, although not ready to confirm that prediction, said

it has ordered internal and external project reviews that would lead to a more detailed

see OIL SANDS page 13see SHARES page 13

12 PETROLEUM NEWS • WEEK OF JULY 16, 2006

Companies involved in Alaska and northernCanada’s oil and gas industry

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AAce TransportAcuren USA (formerly Canspec Group)AeromedAES Lynx EnterprisesAgriumAir LiquideAir Logistics of AlaskaAlaska Airlines Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Alaska AnvilAlaska CoverallAlaska DreamsAlaska Frontier ConstructorsAlaska Interstate ConstructionAlaska Marine Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Alaska Railroad Corp.Alaska Rubber & SupplyAlaska Steel Co.Alaska TelecomAlaska Tent & TarpAlaska TextilesAlaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Alliance, TheAlpine-MeadowAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Arctic ControlsArctic FoundationsArctic Slope Telephone Assoc. Co-op. . . . . . . . . . . . . . . . . . . . 4Arctic StructuresArctic Wire Rope & SupplyASRC Energy Services

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Scott Graika, Sales and Service

Alaska Rubber & Supply Inc.

Alaska Rubber & Supply is aworldwide industrial supply firm spe-cializing in hoses, fittings, accessoriesand rubber products. The company’sexpertise in hydrostatic testing andhose assembly certification, belt slit-ting, metal hose fabrication, pressuretesting, engineering design and repairof fuel and lubrication equipment, isunrivaled in this region. With itsAnchorage staff of 20, ARS puts cus-tomer service first.

Scott Graika has been with thecompany since 1983, minus a three-year stint at the Red Dog Mine. A life-long Alaskan and the youngest offour brothers, he was raised with astrong work ethic. He says that trans-lated into good customer serviceskills. Scott and wife Pat have a son,Justin, age 17. Golf, fishing, snowma-chining and traveling are favorite per-sonal and family activities.

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

FOR

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Lougheed startled many long-timeobservers by suggesting the oil companies,enriched by profits from the oil sands,should pay for some of the upgrading theybenefit from.

Whether by accident or design, he haschosen a pivotal moment in Alberta’s histo-ry to take his stand, with Klein steppingdown later this year after 14 years as leader,putting the heat on the candidates for pre-mier to answer their predecessor’s con-cerns.

Gore film critical of oil sandsGore entered the picture with his film

about climate change, “An InconvenientTruth,” which has stirred passions inAlberta by characterizing oil sands produc-tion as a huge waste of natural gas and amajor environmental culprit.

He plunged deeper into the controversyby telling Rolling Stone magazine that fourmetric tons of landscape is torn up forevery barrel of oil squeezed out of the oilsands.

“It is truly nuts,” Gore said. “But, youknow, junkies find veins in their toes. Itseems reasonable to them, because theyhave lost sight of the rest of their lives.”

Klein, known for his short fuse, brushedGore off as someone from the “far left.”

“I don’t know what he proposes theworld run on ... maybe hot air,” he said.

But Klein is no longer assured of unwa-vering support for his government’s oilsands objectives.

Brian Mason, leader of the oppositionNew Democratic Party, wants a commis-sion established to lay the groundwork fora “long-term development strategy” thatputs an equal emphasis on prosperity andthe environment.

Even some of Klein’s cabinet ministersare quietly acknowledging the need toreview aspects of oil sands operations,

notably the consumption of fresh water.One cubic meter (6.29 barrels) mined

from the sands requires 2 to 4.5 cubicmeters of water in a province with a longhistory of drought.

If all of the approved oil sands projectsproceed they will need twice as much wateras the City of Calgary with 1 million peo-ple.

University of Alberta ecologist DavidSchindler has argued that “water is usedlavishly in the extraction and refining ofboth conventional oil and synthetic crude.There are compelling reasons why thismust cease.”

But so far the government has confinedits water conservation measures toenhanced recovery schemes. ●

PETROLEUM NEWS • WEEK OF JULY 16, 2006 13

update by the end of July.Brian Straub, Shell’s senior vice president for oil

sands, said the company wants to assure itself that “wecan execute successfully ... right now our focus is on mit-igating the costs and risks.”

Suncor has just embarked on regulatory hearingsaimed at increasing production from 260,000 bpd to350,000 bpd by 2008 as part of an overall goal of reach-ing 500,000-550,000 bpd by 2010-12.

It was not overly troubled by the Friedman BillingsRamsey downgrade to “market perform” from “outper-form,” describing the move as only modest and insisting

it has learned enough from previous cost overruns to haveconfidence in its plan and its ability to deliver.

Front-end engineering continuesShell and Western said the front-end engineering work

for their expansion will continue, but a final decision toproceed with construction will not be made until thefourth quarter.

Western, which said it wanted to make the marketaware of the potential for a cost overrun, said a year-longreview of the 100,000 bpd expansion showed “very sig-nificant upward pressures on capital costs.”

Based on that it now anticipates capital spending willrun to C$300 per annual barrel of production, up from theprevious C$200.

Will Roach, chief executive officer at UTS Energy, a

partner with Petro-Canada and Teck Cominco in the FortHills project, agreed that the whole industry is facing costpressures, but the projects are “so long and with such largeresources they can withstand fairly substantial capitalintensity at the beginning.”

However, some analysts believe producers will have toeither defer work or take a chance that oil prices willremain high, justifying higher capital costs in the oilsands.

Some are also urging companies to pool their efforts ina bid to curb overruns, following the lead of CanadianNatural Resources, which negotiated fixed price dealswith contractors covering C$5.6 billion of the C$6.8 bil-lion budgeted for the initial 110,000 bpd phase of theHorizon project.

—GARY PARK

continued from page 11

OIL SANDS

continued from page 11

SHARES

● F I N A N C E & E C O N O M Y

Anadarko moves ahead with Canada pulloutBear Head LNG project to be sold to U.S. Venture Energy for $125 million; Anadarko has 18-month option on throughput

By RAY TYSONFor Petroleum News

.S.-based Anadarko Petroleum has found a buyer forits Bear Head liquefied natural gas subsidiary, repre-senting the last of the company’s Canadian proper-ties. Anadarko earlier put its Canadian exploration

and production assets up for sale.Anadarko said it intends to use proceeds from the

Canadian sales to help pay down more than $20 billion ofdebt it would incur with the planned acquisitions of E&Pindependents Kerr-McGee and Western Gas Resources.

The divestiture program likely will include non-coreKerr-McGee and Western Gas assets. But Anadarko saidthese sales would not be announced until after the Kerr-McGee and Western Gas deals close, probably during thisyear’s third quarter.

Western Gas owns Canadian properties through itsWestern Gas Resources Canada subsidiary but it isunknown whether Anadarko plans to sell or retain WesternGas’ Canadian assets. Kerr-McGee has no Canadian prop-erties.

Anadarko agreed to sell its Bear Head LNG subsidiaryto privately owned U.S. Venture Energy for $125 million,Anadarko said July 10. As part of the deal, Anadarko

would have an 18-month option to secure up to 350 millioncubic feet per day of throughput capacity. The optionwould begin when the transaction closes, hopefully “with-in a few weeks,” Anadarko said.

The sale to U.S. Venture Energy includes all assets,rights and obligations associated with the Bear Head LNGproject, excluding long-term pipeline transportation agree-ments, Anadarko said.

Anadarko retaining ability to supply LNG“With the sale, we are recovering our investment and a

reasonable premium, while retaining the ability to supplyLNG to the Canadian Maritimes and U.S. Northeast con-suming regions,” said Anadarko Senior Vice PresidentKarl Kurz.

Anadarko had big plans for the Bear Head project in2004 when it acquired the property from Access NortheastEnergy, a private Canadian company whose sole projectwas a proposed LNG receiving terminal on the coast ofNova Scotia.

When Anadarko bought the Bear Head, front-end engi-neering and design had been completed for a terminalcapable of processing up to 1 billion cubic feet a day ofLNG. The terminal site, which was expected to begin com-mercial operations in late 2007, is at Bear Head, Point

Tupper on Cape Breton Island, along the Strait of Canso. Anadarko said in 2004 it wanted to secure processing

capacity for natural gas it produced in Algeria and Qatar,two of the world’s top LNG exporting countries.

Bob Daniels, Anadarko’s senior vice president of explo-ration and production, said then the Bear Head projectwould give Anadarko a competitive advantage in interna-tional natural gas development by providing the companywith a low-cost, low-risk entry into the LNG business.

“Participating in the commercialization of internationalnatural gas resources is becoming more necessary in theupstream industry and is consistent with Anadarko’sgrowth strategy going forward,” he explained.

He added: “Using the planned Bear Head terminal as afoothold, we expect to partner with other major entitiessuch as national oil companies to facilitate the broadervalue chain of investment, with the primary purpose ofusing re-gasification as a leveraging vehicle into newupstream natural gas opportunities and profitability.”

Anadarko’s Kurz said the company told investors in2004 Anadarko would either secure an upstream supplysource or would explore other options with its terminalwithin a two-year period. “With this agreement, we retain

U

see ANADARKO page 14

vately held Altex Energy, which is also tryingto line up support for a 250,000 bpd directroute from Alberta to the U.S. Gulf Coast,which is targeted for a 2010 in-service date.

Altex: proprietary diluentAltex Chief Executive Officer Jack

Crawford said his company’s plans won’t bealtered in response to Enbridge, claimingAltex has the edge because of its plans to usea proprietary diluent to facilitate the ship-ment of heavy crude by eliminating the needfor conventional diluent that is rising in costas domestic supplies shrink.

He said that by combining technologyand its own diluent Altex can take away thepenalty of paying a premium for diluent inAlberta and taking a write down at the deliv-ery end where the diluent is worth less.

Crawford estimated the cost of shippingon the Altex pipeline could be about half thetolls paid on a competing system.

He had previously estimated that shippersrelying on conventional diluent would paytolls of $8-$10 per barrel for bitumen, mak-ing the Altex pipeline economical at 250,000bpd. Bird said that if oil sands productionrises by 2 million bpd by 2015 Enbridgethinks only 750,000 bpd of that increase willfind markets in the U.S. Midwest.

It has calculated that the Gulf Coast couldhandle 200,000-400,000 bpd of oil sandscrude, with 750,000 bpd going to east ofChicago, 100,000 bpd to the Midwest,50,000 bpd to the Rockies, 10,000 bpd toCalifornia and 300,000-500,000 bpd to Asia.

Enbridge: increasing pipe sizesTo accommodate those demands,

Enbridge has increased the planned size ofseveral pipelines including Waupisoo fromthe Athabasca oil sands to Edmonton to 30

inches from 24 inches; Gateway, fromEdmonton to Kitimat, British Columbia, fortanker shipment to California and Asia to 36inches from 30 inches; its Southern Accessline in Wisconsin to 42 inches from 30 inch-es; and the Southern Access extension fromWisconsin to Chicago to 36 inches from 30inches.

In addition, Enbridge is working on its$1.8 billion Alberta Clipper project to carry400,000 bpd from Edmonton throughWisconsin to Chicago, paralleling its exist-ing mainline.

That puts it head-to-head withTransCanada’s Keystone project, which isdesigned to transport 400,000 bpd fromAlberta to Illinois and has put the applica-tion before regulators, while Enbridge antic-ipates filing an application for Clipper latethis year.

TransCanada believes it is ahead of thepack having signed 300,000 bpd of shippingcontracts with ConocoPhillips.

In addition to the race to line up shippersthere is the challenge of developing newmarkets by matching various crude typeswith U.S. refineries which are reluctant tosign long-term supply contracts.

That also leads to the debate overwhether it is better to deliver raw bitumen tothe U.S. or gain control of the value-addedend product by building new upgradingcapacity in Alberta. ●

14 PETROLEUM NEWS • WEEK OF JULY 16, 2006

the upstream opportunity in the near termwithout owning and operating the LNG ter-minal,” Kurz said.

Less than two weeks before the BearHead LNG announcement, Anadarko saidit would sell its wholly owned CanadianE&P subsidiary, Anadarko Canada, as partof its “portfolio refocusing efforts” relatedto the Kerr-McGee and Western Gas acqui-sitions.

“Properties like ours are in high demandin Canada right now, attracting valuationssignificantly above those reflected in ourstock price,” Anadarko chief executive JimHackett said. “This arbitrage opportunitymotivates us to essentially trade out of the

Canadian operations and into the Kerr-McGee and Western properties.”

Anadarko Canada produces about 340million cubic feet of equivalent per day,about 85 percent of which is natural gas.Year-end 2005 proved reserves in Canadatotaled nearly 1.6 trillion cubic feet equiva-lent, of which almost 85 percent were nat-ural gas and 76 percent were proved devel-oped.

Anadarko agreed to acquire Kerr-McGee for $16.4 billion in cash or $70.50per Kerr-McGee share, plus the assumptionof net debt and other liabilities estimated at$1.6 billion. In a separate deal, Anadarkoagreed to buy Western Gas for $4.7 billion,or $61 per Western share, plus the assump-tion of debt and other liabilities estimatedat $600 million. ●

continued from page 13

ANADARKO

China feels Canadian cold shoulder China feels snubbed in its efforts to stake out a leading production role in the

Alberta oil sands. It has failed over the past two years to form a long-term alliancewith the two major players, Suncor Energy and Syncrude Canada, and beenunable to form partnerships with smaller producers, a top official with one ofChina’s state-owned oil companies said.

His blunt message went some way towards explaining why China has beenstalled since striking two small equity positions a year ago, one each by Sinopecand offshore producer CNOOC, despite its professed desire to diversify its glob-al crude oil supplies.

Song Yiwu, vice president of CNPC International, a unit of China NationalPetroleum Corp., told a Calgary conference that CNPC’s efforts to establish sig-nificant partnerships have met with a chilly reception and feedback that is “not sopositive.”

“We want to do something in Canada,” he declared. “The bigger the better.“We want to diversify our import channels and oil from Canada is an option

for us. We think you need a market andwe are a big emerging market,” Songsaid.

But China’s offer of preferentialaccess to its markets for raw bitumenhas met with resistance from companiessuch as EnCana, Canadian NaturalResources and Husky Energy.

“We want to work together,” Songsaid. “To us, it looks like you’re notinterested.”

He said Canadian companies just want to focus on domestic and U.S. markets,while China needs stable, long-term supply sources by negotiating deals withwhat he described as “local super players.”

“We don’t like to talk with some small-size company because their purpose isto just package something and sell to someone. ... We are looking for a long-termpartner,” Song said.

Doubting that the U.S. can absorb all of the planned increase in oil sands out-put, he said the product is exactly what China wants, given its appetite for diesel.

CNPC: interested in alliancesDespite rumors that circulated earlier this year that CNPC was poised to

embark on a $20 billion-plus takeover, Song insisted his company was more inter-ested in alliances than acquisitions.

Canada’s National Energy Board echoed some of those sentiments in Junewhen it said producers believe that “filling up existing markets in the U.S. in theshort term makes sense and that the Far East has potential in the longer term.”

Richard Bird, Enbridge’s vice president of liquids pipelines, said his compa-ny’s planned Gateway pipeline, which could send 300,000 bpd to Asian markets,is an opportunity for CNPC to source Canadian oil, but he believes the Chinesecompany would sooner take a direct role in production.

Wenran Jiang, acting director of the China Institute at the University ofAlberta, told the conference it is possible China has found access to other oil sup-plies around the world that are cheaper than the price of admission to the oilsands.

Although the Alberta government is eager to have Chinese participation, hesaid the Canadian government has yet to remove trade barriers, while businessexecutives often have to wait eight months to get a Canadian working visa.

In addition, negative speculation about China’s pending takeover of Canadiancompanies has created a disincentive, Jiang said.

—GARY PARK

continued from page 1

ENBRIDGE

Despite rumors that circulatedearlier this year that CNPC was

poised to embark on a $20billion-plus takeover, Song

insisted his company was moreinterested in alliances than

acquisitions.

Altex Chief Executive Officer JackCrawford said his company’s plans

won’t be altered in response toEnbridge, claiming Altex has theedge because of its plans to use a

proprietary diluent to facilitate theshipment of heavy crude by

eliminating the need forconventional diluent that is rising

in cost as domestic supplies shrink.

the state take its royalty and tax gas in-kind(a total of 20 percent of the gas) along witha matching 20 percent equity interest in theproject.

The high cost of the project, long con-struction period and long distance to marketmean this project has a low rate of returncompared to other projects around theworld. The project’s most prominent featureis its size, he said, with cost overrun risksmagnified because of the size. Another riskis the future price of natural gas, somethingMarks called “utterly unknowable.”

What the contract doesThe contract creates fiscal stability for

the gas pipeline project and increases therate of return. Marks said the state believesthat because of the risks, the project willneed a high rate of return to be feasible.

Under the status quo the state could takeits gas in-value (producers sell the gas andthe state receives a check) or in-kind. Within-value gas the producers pay for 100 per-cent of the pipeline but only own 80 percentof the gas. The state pays its share throughtariff deductions, but the time value ofmoney reduces the rate of return to the pro-ducers because they have to account for 100percent of the project costs upfront, againstonly 80 percent of the gas.

If the state owned 20 percent of thepipeline but took its gas in-value it wouldinsist on a firm transportation commitmentfrom the producers for shipping the state’sin-value gas, Marks said. Because that com-mitment is a long-term liability the produc-ers would have to capitalize it upfront — itwould be no different for them than payingfor 100 percent of the line.

If the state takes its gas in-kind and theproducers own 100 percent of the project,the producers get a firm transportation com-mitment from the state and that offsets 20percent of the cost. From a firm transporta-tion commitment, it’s a small step for thestate to ownership, Marks said.

With state ownership of 20 percent andgas in-kind, the state gets a seat at the tableand there is a 2-2.5 percent improvement inthe rate of return. State ownership and tak-ing its gas in-kind has the same economicsignificance as if the state took no royalty ortaxes under the status quo, but by taking anequity position and its gas in-kind, “the stategives up no revenues,” Marks said.

Jim Clark, the governor’s chief of staffand the state’s lead negotiator on the con-tract, said the reverse is not true: the statecan’t negotiate owning pipe but not take gasin-kind. It was taking gas in-kind that led toownership, he said.

A third alternativeBill McMahon of ExxonMobil told the

committee that as the companies negotiatedwith the state sometimes both sides wereable to move a bit on an issue and some-times groups of items were traded.

In the area of in-kind state gas owner-ship, he said, the problem was solved in athird way, without taking either the state’s

or the producers’ original positions but bycoming up with a third alternative.

The producers, he said, were looking forlower state take to make the project eco-nomic and were also looking for a way tovalue gas for royalty and production tax toreduce disputes.

When the state proposed taking its gasin-kind, that allowed the producers to droptheir request for lower state take because itimproved the economics, McMahon said. Italso solved the valuation issue because thestate would sell its own gas.

In-state gas useMarks said there are risks associated

with the state’s position: completion,reserves, force majeure and marketing, butsaid the state does not believe those risks areincredibly large — and in exchange it gets agas pipeline and can sell gas in-state.

There has been criticism of the contractfor no guarantee of in-state gas sales, hesaid, but the state would be financiallyindifferent between selling gas in-state andselling it in Chicago. With the short distanceto Fairbanks — and a correspondingly lowmileage-sensitive tariff — Fairbanks wouldhave the lowest priced gas in the country, hesaid.

Bob Loeffler, a partner in Morrison andFoerster, and counsel to the state, said theadministration has been “listening carefullyabout serving in-state needs” and is lookingat policies for pricing that gas. The thinking,he said, is that there would be a pricing for-mula where the state would be economical-ly indifferent between in-state and long-haul sales. He also noted that the Alaska

constitution requires that such a sale be inthe best interest of all Alaskans.

Clark said this is a more complicatedissue than it would appear, but it is not acontract issue: It’s a policy issue that theadministration is looking at discussing inthe fiscal interest finding. Policy, he said,would be developed by the administrationand the Legislature after the contract, butbefore the open season.

Clark said pricing choices for in-statesales include: netback plus transportation;netback plus transportation plus a biddingrate (the state would put the gas out for bid);and a Henry Hub price such as is being usedin Southcentral Alaska.

Loeffler said he thinks some existing in-state users of natural gas, such as Enstar,could probably be ready for an in-state openseason. He said while you have to committo take capacity in an open season anddemonstrate creditworthiness, it would be anumber of years before gas would flow,providing time to build out infrastructure.The open season is probably a year and ahalf to two and a half years out, and pay-ments wouldn’t start until gas is flowing, hesaid.

Another concern about in-kind gas is themarketing issue.

Clark said the Minerals ManagementService is taking gas in kind and finding thatthey make money on the upside, a 1-2 per-cent increase over taking gas in-value.

Deputy Commissioner of NaturalResources Ken Griffin said based on arecent MMS report on its in-kind programthe costs the state attributed to marketing inits model were “probably quite conserva-tive.” MMS benefits from marketing a rela-tively small amount of gas, Griffin said,larger volumes are more meaningful to themarket and the state will have some 800million cubic feet per day going into a mar-keting center. If the state took its gas in-value, he said, it would be dependent on thecompanies to market that gas and their mar-keting strategies, organizations and activi-ties are very different, and the state wouldbe captive to a very aggressive or a veryconservative risk-taking strategy. By takinggas in-kind, he said, the state will developits own risk profile.

In-kind also eliminates valuation dis-putes. Over the years those have been hard-fought and have created frictions that makeit difficult to function effectively as part-ners, Griffin said, and make it difficult forthe state to encourage developments on theNorth Slope.

Clark said the state is looking at devel-oping an in-state team with expertise simi-lar to that of the permanent fund, and to usethem to manage a group of outside mar-keters. The state would keep those that hadthe best results and replace others.

Griffin said DNR is studying ways tomanage the marketing and making con-tacts. ●

PETROLEUM NEWS • WEEK OF JULY 16, 2006 15

PIPELINES & DOWNSTREAMAgrium names new Kenai Nitrogen team

Chris Sonnichsen has been named plant manager at Agrium’s Kenai NitrogenOperations. Sonnichsen, who has a bachelor’s degree in chemical engineering, hasextensive experience in the fertilizer industry and has worked at the Kenai facility fornine years, most recently as Kenai production manager.

Other new members of the Kenai plant leadership team are: Bruce Jackman, tech-nical services superintendent; Jeff Turkington, operations superintendent; Rick Main,maintenance superintendent and John Averill, safety, security and emergency responsesupervisor. They join Jim Senn, business support superintendent and Don Zacharias,human resources superintendent.

—PETROLEUM NEWS

continued from page 1

CONTRACT Stevens, Murkowski urge state to moveAlaska’s U.S. senators, Lisa Murkowski and Ted Stevens, urged Alaska legislators

to move on a natural gas pipeline before the state loses the window it now has to mar-ket its energy.

Murkowski joined a July 6 meeting of the Senate Special Committee on NaturalGas Development by phone; Stevens attended the July 7 meeting in person.

Murkowski said Alaskans tend to think “there will always be a market for Alaskagas,” but she said that may not be the case.

Liquefied natural gas imports are growing fast, from current imports of some 4 bil-lion cubic feet a day, she said, to an expected 12 bcf a day by 2010 and 18 bcf a dayby 2020. She said FERC Chairman Joseph Kelliher told her in a recent meeting thaton June 15 FERC approved expansions and new receiving terminals that will handle8.2 bcf a day and grow to 9.7 bcf a day. In one day’s action, she said, FERC approvedcapacity nearly twice what the Alaska gas pipeline will handle and 18 applications arepending.

If the Alaska project is delayed even a year or two “it could drastically affectAlaska’s chance to sell our gas,” she said. With projects under way between now and2010 to produce between 150 tcf and 250 tcf of gas, if a contract isn’t approved quick-ly, the “chances are Alaska will be left out in the cold.”

“I think we’re racing the clock. I think the clock that we’re racing is LNG termi-nals and long-term contracts; once those are in place Alaska’s gas doesn’t look near-ly so necessary or competitive,” she said.

Stevens told the committee that if legislators don’t act in this Legislature, “we’ll beat a table like this in two years trying to make the same decisions.”

If Alaska gas doesn’t get long-term contracts, he said, those contracts will go toLNG. Stevens said he thinks Alaska’s energy future is the next 50 years. He told leg-islators he was pleading with them to put aside politics and do what’s best for the state.He said he knows the Legislature is in a fight with Frank Murkowski. Stevens said hefought with him for years but always managed to work with him, and urged legisla-tors to find a way do that and move the project ahead.

He said if the Legislature can’t get this job done before November he thinks a lotof people will pull back from investments in the state. If what you do cools offinvestors, he said, “you’re not going to see that development in your lifetime.”

—KRISTEN NELSON

Imperial, lead partner in the MackenzieGas Project, with Shell Canada,ConocoPhillips Canada and ExxonMobilCanada as its partners, flatly rejected thatidea, insisting that the gathering lines in theMackenzie Delta and a natural-gas-liquidsline from Inuvik to Norman Wells should besubject to the COGO Act.

The NEB endorsed that argument, rulingthat COGO is designed to regulate oil andgas exploration and development in theNorthwest Territories in a safety and envi-ronmentally friendly way, whereas theNEB’s role is to protect the public interestwhere oil and gas are transported acrossjurisdictional boundaries by regulating traf-fic, tolls and tariffs.

Explorers group disappointedDevon Canada Vice President Michel

Scott told Petroleum News that the explorersgroup was “disappointed ... no doubt”because it viewed the Mackenzie project asa “basin-opening” pipeline that should beexploration friendly by ensuring there wassome form of economic recourse to a highertribunal for explorers who were unhappywith the terms being offered.

He said the choices now are for explorersto “accept the deal that is put in front of themor build their own facilities.”

“We’d like to see the whole set of facili-ties be as exploration friendly as possible,”Scott said.

The NEB decision has created “uncer-tainty and will have an impact on the pace ofexploration,” he said, suggesting third-partycompanies face an added challenge to fundtheir programs.

An Imperial spokesman told reportersthat his company was pleased to now haveclarity on how to proceed with theMackenzie project.

Winter outlook already shakyThe outlook for the 2006-07 winter was

already shaky. Devon has put drilling onhold while it evaluates results from a C$60million well in the Beaufort Sea.

On top of that it has relinquished morethan 400,000 acres of rights and has said it

would be open to taking on a partner.A partnership of Chevron and BP has

indicated its waning optimism by invitingexpressions of interest on an areawide farm-in opportunity for about 1 million acres ofexploration acreage near the Mackenziepipeline corridor, where 3-D seismic hasidentified prospects over about 308 square

miles.Anadarko will provide a reading on the

level of enthusiasm when it seeks buyers forits Arctic holdings as it unloads all of itsCanadian assets.

They include a 25 percent stake in theUmiak N-16 discovery well and N-5 delin-eation well on Richard’s Island and 140,000acres of Delta leases that it acquired in part-nership with EnCana and ConocoPhillipsearlier this year for C$40.3 million.

Appeal under consideration Scott said lawyers for the explorers group

are still considering the decision to decide ifan appeal is possible.

However, he conceded that the group’spriority is still to get the main line built with-out which there is “no hope of getting anygas out of the region.”

The NEB left one shred of hope for theexplorers by saying it “remains concerned”about appropriate tolls and access to thegathering pipelines and “the methods forresolving disputes on these matters.”

It has indicated that proposed mecha-nisms to satisfy those issues will be dis-cussed during the current round of NEBhearings on the project and could be part ofthe board’s final ruling in 2007.

For now, the proposed gathering systemis intended to have initial capacity of 1.075billion cubic feet per day when it comes onstream in 2011. Of that total 830 millioncubic feet will come from the anchor fieldsat Taglu, Niglintgak and Parsons Lake, leav-ing 245 million cubic feet available for third-party shippers holding discoveries north ofInuvik.

But the explorers group has estimatedthat initial gas volumes take up almost all ofthe planned gathering pipelines, leaving lit-tle scope for any new discoveries in theMackenzie Delta and Beaufort, suggestingthat another pipeline might have to be builtto connect with the main line.

—GARY PARK

16 PETROLEUM NEWS • WEEK OF JULY 16, 2006

New round in Canada Southern bidding For a company holding assets that remain unproven and are at least a decade and

likely longer away from development, Canada Southern Petroleum has caused one ofthe liveliest takeover contests in Canadian oil patch history.

Petro-Canada put its third offer on the table July 11, dangling an all-cash bid ofUS$13 per share, having started out at $9.75 and climbed to $11, only to be toppedagain on July 12 by Canadian Oil Sands Trust, which raised its friendly bid to $13.10.

Petro-Canada’s offer expires July 27 while the trust bid is open until Aug. 1.Once more, the board of Canada Southern has unanimously recommended that

shareholders go with the trust, while the company’s shares have almost tripled in valuesince Petro-Canada initiated a hostile bid of $7.50 on May 11 that it hiked to $11 onJune 29. The trust entered the picture on June 19 at $9.75.

Canada Southern estimates it has 927 billion cubic feet of gas reserves in Canada’sArctic Islands, but it is prevented by Canadian and U.S. regulators from claiming thosereserves because there is no way to bring the gas to market.

Trust Chief Executive Officer Marcel Coutu said the trust’s interest is unchanged.The Arctic gas resources provides a “hedging strategy with unparalleled duration”

to cover the trust’s gas needs to fuel its one-third stake in the Syncrude Canada oilsands consortium, he said.

Kathy Sendall, Petro-Canada’s vice president for North American natural gas, saidher company believes “these Arctic assets will play an important role in the futuredevelopment of northern Canadian natural gas.”

Exactly what role Petro-Canada isn’t saying because it has no current developmentplan. Sendall emphasized that before gas in the remote Arctic Islands can be exploit-ed, the holdings must be consolidated.

“Acquiring this piece and removing the burden of (Canada Southern’s) carriedinterest is an important step in that consolidation,” she said.

“As we’ve said before, as the controlling interest holder and as an established oper-ator it just makes sense that Petro-Canada would be in the best position to consolidateand develop these future resources,” Sendall said.

Although Petro-Canada won’t comment, observers hold the theory that CanadaSouthern’s gas could serve as a back up for the joint Petro-Canada-TransCanada liq-uefied natural gas terminal at Gros Cacouna, Quebec.

Petro-Canada’s primary hope is that it will form a partnership with Russia’sGazprom to provide LNG for the facility.

—GARY PARK

continued from page 1

EXPLORERS

EXPLORATIONXTO defersMiddle GroundShoal drilling

Kyle Hammond, vice president ofoperations for XTO’s Permian divisionin Alaska, characterized the situation inhis company’s Cook Inlet MiddleGround Shoal field as “business asusual.”

XTO bought two Middle GroundShoal state leases and the field’s A and Cplatforms from Shell. Since then thecompany has increased reserves andmaintained production rates at the fieldthrough continued drilling and develop-ment. By late 2005 XTO had drilled 11sidetrack wells, with average reserves of750,000 barrels per well.

But Hammond said July 6 that XTOhas deferred drilling of further sidetrackwells into 2007. The company hadplanned to drill those wells in 2006.

“We’ve definitely decided not to dothose this year,” Hammond said, com-menting that the deferral stems from adecision to invest in other areas at themoment. There is, however, a high prob-ability of drilling the wells next year, hesaid. Meantime XTO has completed aremodel of the crew quarters on the Cplatform, Hammond said. An upgradeof the fire and gas detection systems onboth Middle Ground Shoal platformscontinues. The upgrade is 90 percentcomplete on C platform and still inprogress on A platform, Hammond said.

—ALAN BAILEY