Vol. 6, No. 21 $1 • www.PetroleumNewsAlaska.com Alaska’s source for oil and gas news Week of December 16, 2001

I N S I D E

BP talks to state about Badami 8

AOGCC denies Danco petition 11

Cross-border legislators promote gasline 9

State approves AEC as McCovey operator 7

Prince William Sound might get Waterkeepers 3

Alberta warns against ratifying Kyoto Protocol 13

“Americans stand united with those wholove democracy, justice and individual liberty.We are committed to upholding these princi-ples, embodied in our Constitution's Bill ofRights, that have safeguarded us throughoutour history and that continue to provide thefoundation of our strength and prosperity.”

—PRESIDENT GEORGE W. BUSH DEC. 9, 2001

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

■ A R C T I C G A S

’Tis the seasonJu

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ors

Ala

ska Unocal, Marathon going forward with

Kenai Kachemak pipeline project Companies form new company to lead pipeline development; first phasebetween Ninilchik and the Kenai gas fields planned to be operational in 2004

By Petroleum News • Alaska

Unocal Alaska and Marathon Oil Co. said Dec.11 that they have formed the Kenai KachemakPipeline LLC, which will be the primarydeveloper of a new natural

gas pipeline system on the southernKenai Peninsula. The newly formedcompany will provide natural gassupplies to industrial customers andto utilities for distribution to resi-dential and commercial usersthroughout Southcentral Alaska,the companies said in a statement.

A conceptual study that alsoinvolved Enstar and the HomerElectric Association was begun ayear ago. The first phase of thepipeline — between the Ninilchikand Kenai gas fields — is planned to be operationalby the beginning of 2004.

“Our study shows that a pipeline system in theregion in feasible; therefore Unocal and Marathonwill move forward with detailed engineering andpermitting,” said Charles Pierce, vice president forUnocal Alaska.

John Barnes, manager of Marathon’s Alaskabusiness unit, said his company is pleased with theprogress of the study group and looks forward toworking with Unocal to prove up necessary natural

gas on the companies respective prospects and bringthe gas to market.

“A significant portion of Marathon’s capitalspending next year in Alaska will be directed towardincreasing natural gas resources that can be producedthrough the new pipeline,” Barnes said.

Pipeline will follow highway

The companies said that the ultimate capacity androute of the pipeline system is dependent on futureresults of gas exploration drilling on the KenaiPeninsula.

The current plan calls for the pipeline to beinstalled in phases between existing pipelines in theKenai gas field and the Anchor Point area. A possi-ble pipeline segment between Anchor Point andHomer has been proposed as a distribution line to be

North Slope gas producers teamchallenges governments to get onboardRisk and reward different for pipeline than for overall gas commercializationproject, BP’s Konrad tells Resource Development Council’s annual conference

By Kristen Nelson PNA Editor-in-Chief

The Alaska North Slope gas producers’ team isclose to completing the work it set out to do in2001, but needs cooperation of governmentsto move the work forward, the team’s leaders

told the ResourceDevelopment Council forAlaska’s annual conferencein Anchorage Nov. 29.

Robbie Schilhab, businessdevelopment manager forExxonMobil, said the team iscompleting the conceptualdesign work, and by the endof the fourth quarter, canstart working on the econom-ic analysis and puttingtogether draft environmentalreports.

In the key technical area, Schilhab said the teamhas done conceptual design for a world-class gastreating plant for CO2 removal and chilling andcompressing the gas; for a natural gas liquidsextraction plant; for more than 5,000 miles of 52-

inch pipeline and some 25 compressor stations;and has looked at more than 1,200 stream cross-ings and more than 1,500 road crossings along theroute.

A significant thing that came out of the workdone so far “is the challenges that surfaced. Thereare several things that we really, really need to go

back and do some more extensive engineeringwork on.” Schilhab didn’t specify areas needingmore work, but did say: “We’ve obviously identi-fied more work that we’ll want to continue to do todrive down the overall project cost.”

What’s next? Schilhab said that as the costwork is completed, those estimates will be condi-tioned and put into an economic model and “eachof the companies will be able to put their analysison this.”

The 2001 work programs will probably be com-

John Barnes,Marathon

Tony Izzo, Enstar Charles Pierce,Unocal

see PIPELINE page 4

British Columbia aims for C$24billion in new energy investment

With its traditional economic underpinnings weakened andcrumbling, British Columbia is turning to oil and gas for salva-tion — aiming for C$24 billion in new investment over the next

five years, a doubling of producing wellsand 8,000 additional jobs.

Current revenues of C$4.6 billion a yearrepresent 8 percent of government rev-enues while activity generates 32,000direct jobs.

Premier Gordon Campbell, in his firstmajor speech on energy since sweeping topower last spring, set ambitious goals forthe energy sector and hinted that there mayeven be ways to open up the offshore.

The message was also taken to Houstonand Dallas by British Columbia EnergyMinister Richard Neufeld, who met withexecutives from many leading Americanenergy companies to impress on them that

British Columbia has a new government that “believes free enter-prise creates the jobs and the wealth.”

“We want an energized economy, we want an economy thatworks for everyone here,” Campbell told oil and gas executives

Ken Konrad, perfor-mance unit leader ofBP’s Alaska gas group

see CHALLENGE page 15

see INVESTMENT page 15

“We need to encour-age oil and gas sec-tor growth and Iwant the industry todouble the number ofwells.” —BritishColumbia PremierGordon Campbell

“Massive pre-investment, absent a clearpath toward success, is a fool’s game.”

—Ken Konrad, BP

ON DEADLINE2 Petroleum News • Alaska Week of December 16, 2001

The Alaska Rig Report as of 12/13/01, active drilling companies only listed.

Contractor/ Rig Type Rig No. Field/Platform Field Operator

North SlopeDoyon Drilling Inc.Dreco 1250 UE D14 (SCR/TD) Prudhoe Bay BPSky Top Brewster NE-12 15 (SCR/TD) Stacked/Endicott Is. AvailableDreco 1000 UE 16 (SCR) Prudhoe Bay BPDreco D2000 UEDB 19 (SCR/TD) Alpine PhillipsOIME 2000 141 (SCR/TD) Meltwater PhillipsNabors Alaska DrillingTrans-ocean rig CDR-1(CT) Stacked/Prudhoe Bay AvailableDreco 1000UE 2-ES(SCR) Prudhoe Bay BPMid-Continent U36A 3-S(CT) Prudhoe Bay BPOilwell 700-E 4-ES(SCR) Milne Point BPDreco 1000UE 9-ES(SCR/TD) Prudhoe Bay BPOilwell 2000 Hercules 14E (SCR) Prudhoe Bay Pending/AnadarkoOilwell 2000 Hercules 16E (SCR/TD) Kuparuk PhillipsOilwell 2000 17E (SCR/TD) Stacked/Pt. McIntyre AvailableEmsco Electro-hoist-2 18-E(SCR) Stacked/Deadhorse Pending/PhillipsOIME 1000 19E (SCR) Idle/Prudhoe Bay Pending/PhillipsEmsco Electro-hoist Varco TDS3 22-E(SCR/TD) Stacked/Milne Point AvailableEmsco Electro-hoist-2 Canrig 1050E 27-E(SCR/TD) Milne Point BPEmsco Electro-hoist-2 28-E(SCR) Stacked/Deadhorse AvailableOilwell 2000 33-E(SCR/TD) Northstar Island BPOIME 2000 245E (SCR/TD) Kuparuk PhillipsNordic/Calista ServicesSuperior 700UE 1 (SCR/CT) Prudhoe Bay BPSuperior 700UE 2 (SCR) Stacked/Kuparuk AvailableIdeco 900 3 (SCR/TD) Kuparuk Phillips

Cook Inlet Basin-Onshore

Kuukpik / H & R DrillingRigmasters 850 9 Ninilchik, NNA #1 Unocal

Inlet Drilling AlaskaTaylor Rig Glacier Rig 1 Kenai Gas Field 24-5 MarathonInlet Drilling Alaska/Cooper ConstructionKremco 750 CC-1 Stacked/Tyonek AvailableNabors Alaska DrillingNational 154 Stacked/Kenai AvailableWilson 120 158 Stacked/Beluga AvailableNational 110-UE 160 (SCR) Stacked/Kenai AvailableContinental Emsco E3000 273 Anchor Pt. Phil l ips

Cook Inlet Basin-Offshore

XTO Energy (Inlet Drilling Alaska Labor Contractor)NA CT-A Idle/Mid. Grd. Shoal XTO EnergyNA CT-C Idle/Mid. Grd. Shoal XTO EnergyNabors Alaska DrillingIDECO 2100E 429 (SCR) Osprey Platform Forest OilUnocal (Nabors Alaska Drilling Labor Contractor)Oilwell 2000E 51 Idle/Steelhead Platform UnocalNational 1320UE 54 Idle/Grayling Platform UnocalNational 1320UE 55 Idle/Grayling Platform UnocalOilwell 860 56 Monopod Platform UnocalDrawworks Removed 57 Idle/Granite Pt. Platform UnocalNational 1320UE 58A Idle/King Salmon Platform UnocalDrawworks Removed 58B Idle/Granite Pt. Plat. UnocalOIME SD8M 60 Idle/Bruce Platform UnocalNational 1320UE 76 Idle/Dolly Varden Plat. UnocalNational 1320UE 77 Idle/Dolly Varden Plat. UnocalIdeco 2100E 428 Stacked/Baker Platform Available

Bering Sea-Port ClarenceFairweatherDreco 147 SDC-1 Stacked/Port Clarence Available

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

The Rig Report was prepared by Dan Wilcox

Rig startups expected in the next 6 months:

Akita EqutakRig 63 startup expected Dec. 20 on Mackenzie Delta-Onshore

XTO Energy (Inlet Drilling Alaska Labor Contractor)Rig CT-C expected to resume December 2001 at Mid. Ground Shoal

UnocalRig 54 startup expected February 2002 on Grayling Platform Rig 58A startup expected January 2002 on King Salmon Platform

Photo of XTO Energy Platform in Cook Inlet courtesy of Judy Patrick

XTO Energy, Inc.

ON DEADLINEPetroleum News • Alaska 3Week of December 16, 2001

Kay Cashman, PUBLISHER

Dan Wilcox CHIEF EXECUTIVE OFFICER

Kay Cashman PUBLISHER

Kristen Nelson EDITOR-IN-CHIEF

Steve Sutherlin MANAGING EDITOR

Gary Park CANADIAN CORRESPONDENT

Alan Bailey CONTRIBUTING WRITER

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Judy Patrick Photography CONTRACT PHOTOGRAPHER

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Petroleum News • Alaska and its supplement, Petroleum Directory, are owned byPetroleum Newspapers of Alaska LLC. The newspaper is published at weekly. Several of theindividuals listed above work for independent companies that contract services to PetroleumNewspapers of Alaska LLC or are freelance writers.

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Petroleum News Alaska, ISSN 10936297, Week of December 16, 2001 Vol. 6, No. 21

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ON DEADLINE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2FINANCE & ECONOMY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5EXPLORATION & PRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . .7ARCTIC GAS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9PIPELINES & DOWNSTREAM . . . . . . . . . . . . . . . . . . . . . . . . . . . .10COOK INLET . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11WORLD OIL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13

Index

Call Rhody or Mike

(907) 279-2401Fax: (907) 278-71 74

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SAFETY & ENVIRONMENTWaterkeeper program proposed forPrince William Sound

A Waterkeeper program is needed for Prince William Sound, musician and formerfisherman David Grimes told the Prince William Sound Regional Citizens’ AdvisoryCouncil at its quarterly board meeting in Anchorage Dec. 7.

Grimes is working at organizing a Prince William Sound Keeper, which he sayswould be a clearinghouse for scouting reports from fishermen, villagers and othersregarding the health of the sound’s ecosystem.

“Prince William Sound is a global treasure, not just for the people who live here,”Grimes said. “How the richest nation on the earth treats its richest places says a lotabout the future of the earth.”

The Waterkeeper Alliance is the umbrella organization for 70 Keeper programslocated throughout North and Central America, including Cook Inlet, the organizationsaid. The Keeper concept started on New York’s Hudson River where a coalition ofcommercial and recreational fishermen mobilized in 1966 to reclaim the Hudson fromits polluters. Grimes said the program was modeled after the riverkeepers of the BritishIsles who looked after private trout and salmon streams. Keeper programs employ avariety of strategies to enforce environmental laws including conducting water qualitymonitoring, participating in coastal planning, attending board meetings, educating thepublic and devising solutions to water quality problems, and if necessary pursuing lit-igation as a final step to enforcement.

The Keeper program, he said, has a broad mission that deals with everything thatgoes on in the watershed, even events like the trans-Alaska pipeline reauthorization,which affects almost all watersheds in Alaska, Grimes said. A PWS Keeper wouldmonitor the rockfish population for over fishing, the herring population, sea lions,whales, seals, and other animals. The Keeper would also document “ongoing prob-lems” from the 1989 oil spill, he said.

Editor’s note: The “What’s New” section of the Cook Inlet Keeper’s Web page(http://www.inletkeeper.org/) contains reviews on various oil and gas projects.

Cook Inlet Keeper, which recently partnered with the Alaska Center for theEnvironment on Environmental Defense Fund’s ActionNetwork, is headed by attorneyBob Shavelson.

—Steve Sutherlin

constructed and owned by Enstar. Thepipeline route will essentially follow theAlaska Department of Transportation rightof way easements along the SterlingHighway, the companies said. Initialpipeline surveying of the route has begun.

Enstar also participating

Tony Izzo, president of Enstar, said hiscompany is a strong supporter of the pro-ject. “It will provide additional gas sup-plies for our customers throughoutSouthcentral Alaska. The new pipelinesystem will also encourage gas explorationand development, as well as bring the ben-efits of clean and efficient natural gas tohomeowners and businesses in the area.”

The companies said Enstar will providesupport for the engineering, design andconstruction of the pipeline system andwill likely play a role in the system’s oper-ation. Enstar is also expected to providelocal gas distribution services in the ser-vice area.

Homer Electric Association and its gen-eral manager, Norm Story, were involvedin developing the project.

“HEA has been a strong proponent ofthe pipeline,” said Unocal’s Pierce.“Homer Electric will continue to workclosely with Unocal and Marathon to helpensure that the project reaches a successfulcompletion.”

“Homer Electric remains excited abouthelping to move the project forwardbecause it is very important to our mem-bers and the Southern Kenai community asa whole,” said Story.

A public meeting was scheduled inAnchor Point Dec. 13 to provide addition-al information and solicit public feed-back.◆

ON DEADLINE4 Petroleum News • Alaska Week of December 16, 2001

continued from page 1

PIPELINE Our study shows that a pipelinesystem in the region in feasible;

therefore Unocal and Marathon willmove forward with detailed

engineering and permitting.” —Charles Pierce, Unocal Alaska

FINANCE & ECONOMYOPEC secretary-general says heexpects production pact

The secretary-general of the Organization of Petroleum Exporting Countriessaid Dec. 11 he expects to reach a deal this week with non-OPEC nations to cutproduction by 500,000 barrels a day to help curtail sliding oil prices.

“They will just have to get to 500,000 barrels per day. ... Every nation has todecide on their own reduction,” AliRodriguez said told reporters inVenezuela’s Margarita Island before asummit of the Association of CaribbeanStates.

OPEC is seeking a deal in which 2million barrels of crude per day areremoved from the market beginning Jan.1 to stabilize prices. Rodriguez, a former Venezuelan oil minister, said he expect-ed a final deal with non-OPEC nations by the end of the week — but added thatOPEC would reconsider its strategy if a deal falls through. He didn’t elaborate.

OPEC hopes to cut production by 1.5 million barrels per day on Jan. 1 if non-OPEC nations contribute a 500,000 barrels-per-day cut.

Rodriguez said he didn’t plan to meet with Mexican Oil Minister ErnestoMartens during the Margarita summit to encourage Mexico to make a bigger pro-duction cut. Martens has said Mexico, which doesn’t belong to OPEC, is stickingto plans to cut exports by 100,000 barrels a day in January.

Besides Mexico’s 100,000-barrel offer, Russia has offered a 150,000-barreldaily cut and Oman a 25,000-barrel cut. Norway has said it will reduce productionby 100,000 to 200,000 barrels per day but has yet to release an official figure.

Oil prices have fallen more than 30 percent in recent months, hurt by a declinein demand. In trading Dec. 11, January crude oil futures were off 20 cents to$18.37 a barrel.

—The Associated Press

OPEC is seeking a deal in which 2million barrels of crude per dayare removed from the marketbeginning Jan. 1 to stabilize

prices.

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

Knowles calls for improvedmonitoring of oil and gas industry Governor says $4.8 million initiative would add 30 positions,increase environmental and safety monitoring, speed permitting

By Steve Sutherlin PNA Managing Editor

Gov. Tony Knowles proposed a $4.8 mil-lion initiative Dec. 12 to hire more per-sonnel for state oil and gas permittingand regulation agencies for increased

environmental monitoring and faster permit-ting. The plan seeks $3.7 million from theLegislature to add 30 staff positions to sixstate agencies. Another $1.1 million wouldbe raised from existing fees paid by oil andgas companies. No new industry fees wereproposed.

Knowles said the proposal would benefitindustry through faster lease processing, per-mitting and more collaborative decision-making.

“One of the goals of this initiative is to getpeople out of the office and into the field,where the hands-on work needs to be done,”Knowles said. “This will require some reor-ganization of responsibilities ... but we arecommitted to raise the standard for environ-mental responsibility and maintaining a pos-itive, 'open for business' attitude.”

Knowles said his plan would reduce thetime for processing air and water quality per-mits and oil spill contingency plans to keep

pace with drilling permit applications thathave increased 35 percent over the last 10-year average. It would also expedite process-ing of title and lease applications by theDepartment of Natural Resources to keeppace with increased private sector activity.

Monitoring by the state would alsoincrease under the initiative, Knowles said. Itwould increase well inspections, testing, andfollow-up by the Alaska Oil and GasConservation Commission and air and waterquality monitoring and inspections and oilspill preparedness drills by establishing afull-time North Slope office of theDepartment of Environmental Conservation.

Enforcement of electrical and occupa-tional safety and health codes by theDepartment of Labor and WorkforceDevelopment will be stepped up, as will fireand life safety inspections by the fireDepartment of Public Safety.

The plan would add support to ensurehabitat restoration and protection of fish andwildlife by the Department of Fish andGame, Knowles said, working with industryon how best to undertake exploration, devel-opment, field closures, and remediation.

—The Associated Presscontributed to this story

Petroleum News • Alaska 5Week of December 16, 2001

FINANCE & ECONOMY■ W A S H I N G T O N , D . C .

Some oil price recovery expected byspring, EIA short-term forecast saysNatural gas near-term spot prices ‘significantly weakened’ by warmweather and weakness in U.S. industrial production; new gas supplydemand expected to remain flat or fall in 2002

By Petroleum News • Alaska

The U.S. Department of Energy’s EnergyInformation Administration said in its Decembershort-term forecast that while “world oil priceshave languished below” the range of $22-$28 a

barrel preferred by the Organization of PetroleumExporting Countries, and world market conditionshave produced increasing inventories in industrial-ized countries, the agency still expects to see “somerecovery in prices” of crude oil by spring.

“Nevertheless, unless world demand growthrecovers more quickly than we now have reason toexpect, prices that are comfortably within the OPECband may be hard to come by over the next year,” theEIA said Dec. 6.

As producing countries “jockeyed over the issueof production cutbacks,” the agency said, OPEC has

reported that their basket price averaged about $17.60per barrel in November, following a $19.60 averagein October and $24.30 in September.

Natural gas spot prices weak

In natural gas, warm weather and weakness inU.S. industrial production have “significantly weak-ened” near-term spot prices, the EIA said, with spotprices at the Henry Hub near or below $2 per thou-sand cubic feet from mid-November through the firstweek of December compared to $3 at the end ofOctober.

There was an untypical build in natural gas stor-age levels in November, reflecting “the continuingexcess supply situation… It is becoming far less like-ly now that average spot gas prices will move signif-icantly above $2.00 per thousand cubic feet in 2002

ADVICEPortfolio strategy update

Slow recovery at best?By David Gottstein

Editor’s note: The following column was compiled in earlyDecember. David Gottstein is with Dynamic Research Group inAnchorage.

We are not in the camp of those who believe the U.S. econo-my is going to bounce back anytime soon. At best we believe theeconomy is hitting a bottom, and could very well take another legdown, but that any signif-icant recovery will nottake place in the year2002.

By a significant recov-ery we mean a sustainedperiod of increasingemployment.

The American econo-my has been on a high for a very long time. The longest in record-ed history. With all the excesses that have been built into theeconomy, it will be difficult for our current state of affairs to actas a launching pad for more success.

Excessive prosperity will more likely be followed by a down-turn as opposed to another immediate upturn. Eventually, therewill be a recovery because of the inherent power of our funda-mental approach to capitalism and market mechanisms; howeverit isn’t likely to happen anytime soon.

It is true that the Federal Reserve has lowered interest ratesdramatically and that Congress is preparing to pass a so-calledstimulus package, but these actions won’t be enough.

Japan has had almost zero interest rates for some time, andthat hasn’t helped, and the likely stimulus package will not takehold.

And remember, lower interest rates lowers income for thoseinvesting in fixed income investments.

Tax cuts that put money in the hands of people who will spendit will help, but most of the envisioned cuts are not of that bent.

We can’t increase demand by simply increasing capacity.Only after demand starts to outstrip capacity will manufacturersbegin to build again.

Problems are worldwide

The problem is that there are problems all over.

■ L O N D O N

OPEC delays cuts in oil production untilNorway specifies reduction in its outputRussia’s pledge to cut output ended a showdown with OPEC that threatenedto unleash a price war for crude; cartel expects Norway to match Russia’s cut

By Bruce Stanley Associated Press Business Writer

OPEC has delayed a long-planned 6 percentreduction in oil output because it has yet to learnhow big a production cut Norway is ready tomake, a cartel official said Dec. 6.

Although Russia agreed Dec. 5 to cut its output by150,000 barrels a day, Norway has became the focusof attention as the Organization of PetroleumExporting Countries tries to coordinate a cutback inglobal crude supplies in the hope of shoring up sag-ging prices. Oil prices have fallen by a third since theSeptember 11 terrorist attacks on the United States.

OPEC expects Norway, the world’s third-largestcrude exporter, to match Russia’s cut, said the OPECofficial, speaking on condition of anonymity from thegroup’s headquarters in Vienna, Austria.

If it does, then OPEC will have a big enough com-

mitment from independent crude suppliers outsidethe cartel to justify triggering the 1.5 million barrel-a-day cut its 11 members agreed on last month, the offi-cial said. Mexico and Oman have promised to curtailtheir production, and Angola has said it wants tocooperate.

“As long as we don’t have the exact figure fromNorway, we cannot go ahead and implement the cut,”the OPEC official said. Norway was expected toannounce its decision within a few days.

Norway initially pledged 150,000 barrel cut

Norway has so far offered broadly to cut output by100,000-200,000 barrels a day. However, it madethat pledge at a time when OPEC was expectingRussia to cut much more than 150,000 barrels.

Russia’s decision to cooperate, to this extent atleast, ended a showdown with OPEC that threatened

We are not suggesting adepression, or even a severe

recession. We are justsuggesting that the economy

will take longer to recover thanmost expect.

OUR CURRENT RECOMMENDATIONS■ IMS Healthcare (RX)

■ PPI Corporation (PPL)

■ Mirant Corporation (MIR)

see GOTTSTEIN page 6

see FORECAST page 6

see OPEC page 6

FINANCE & ECONOMY6 Petroleum News • Alaska Week of December 16, 2001

unless some very cold weather intervenes inthe near term,” the agency said.

A 5 percent decline in demand for natur-al gas is projected over the heating seasonof October to March. Last winter demandgrew by 6.7 percent during the heating sea-son. Spot wellhead prices, which averaged$6.49 an Mcf last winter, are expected to betwo-thirds lower this winter, about $2.15 anMcf.

New gas supply requirements in theUnited States — domestic production andimports — are expected to remain flat orfall in 2002.

Natural gas supply high, prices low

The EIA said that underground storagelevels for natural gas set a record inNovember, with net injections into storage

continuing through the last week of themonth — normally a time when with-drawals exceed injections.

For the end of November the agencysaid the storage level is estimated to havebeen about 29 percent above last year’slevel.

Increased gas production combined withdecreased gas demand over the summerbecause of mild summer weather. The highprice of gas earlier in the year reduceddemand, as has the slowing of the economy,particularly in natural gas intensive industri-al sectors such as chemicals and primarymetals. While gas-directed drilling rates aredown sharply since July, this will probablynot reduce production enough to preventrelatively low prices this winter and throughmost of 2002.

The EIA said “pressure on domesticwellhead prices to remain near (and at timesbelow) $2 per thousand cubic feet will bestrong through much of 2002.” ◆

to unleash a potentially devastating pricewar for crude.

The Russian pledge was “a welcomedevelopment,” OPEC secretary-general AliRodriguez told the official OPEC newsagency.

“We remain optimistic that other pro-ducers will follow suit to give strength andpurpose to our market stability goals,” hesaid.

In an unusual act of diplomatic brinks-manship, OPEC insisted last month thatnon-OPEC producers promise to trim theiroutput by a total of 500,000 barrels a daybefore it would put its own cuts into effectJan. 1.

OPEC wants cuts on secondquarter, too

OPEC is weary of cutting production —by a total of 3.5 million barrels so far thisyear — only to see outsiders maintain oreven boost their output.

Russia’s turnaround appeared to vindi-cate OPEC’s tough stance. Russia, theworld’s No. 2 oil producer, had said forweeks it would cut its daily output of 7.2million barrels by just 50,000 barrels.

Peter Gignoux, head of the petroleumdesk at Salomon Smith Barney in London,suggested that Russia might simply be mak-ing a virtue out of necessity.

“Russian exports always decrease at thistime of year, as seasonal demand increasesfor their internal market,” he said.

Russia pointedly did not say how long itsproduction cut would last, and that has fedthe suspicions of some analysts and OPECdelegates.

OPEC wants independent producers tocut output through the second quarter ofnext year, when seasonal demand for oiltends to dip as weather warms in the UnitedStates and other major import markets.Some countries, Russia in particular, mightnot want to make such a commitment.

“Any production cuts must be extendedfor as long as takes, if we are going to besuccessful in establishing a concrete floorunder prices,” Rodriguez warned. ◆

continued from page 5

OPEC

continued from page 5

FORECAST

Japan is still in trouble, and things mayeven be getting worse. Germany is headinginto a recession. China’s growth has beenalmost eliminated due to lack of increasedglobal demand for its products.

It is true our military spending will help,but it won’t do it all, at best adding one totwo hundred thousand workers in defenserelated fields. However we have alreadylost multiples of that so far, with unemploy-

ment levels having not even peaked. We think we are headed at least to 7 per-

cent from the recently reported 5.4 percentlevel.

Falling oil prices will help, but againwon’t do it all.

We are not suggesting a depression, oreven a severe recession. We are just sug-gesting that the economy will take longer torecover than most expect, and that theimprovement won’t be as strong.

At least for the foreseeable future. We will at least need to see an end to lay-

offs before a recovery can commence.

STATEWIDEState headed back toward deficits

After a year of high oil prices and a small budget surplus in fiscal year 2001, “thestate is headed back toward growing budget deficits as oil prices move into their his-toric range of $17 to $19 per barrel for Alaska North Slope crude,” RevenueCommissioner Wilson Condon said in a Dec. 7 letter conveying Revenue’s fall rev-enue forecast to Gov. Tony Knowles.

Condon said the department is forecasting a $906 million deficit for fiscal 2002(ending June 30), “based on oil averaging $20.55 for the year.” High prices in the firstsix months of the year help keep the average from looking worse.

“Alaska North Slope crude was selling for around $17 a barrel last week and weexpect it to hang around that price range for the rest of the year,” Condon said.

If the nation’s economy starts to recover next year and if worldwide oil demandpicks up a bit, the department sees ANS crude averaging $18.81 a barrel in fiscal 2003(beginning July 1) and $19.72 in fiscal 2004 (beginning July 1, 2003).

Prices also depend upon the ability of the Organization of Petroleum ExportingCountries to manage world oil supply. Revenue is forecasting that the state’s budgetgap will continue to grow, with a budget gap of $1.13 billion in fiscal 2003 and $1.07billion in fiscal 2004. Production, which averaged 991,000 barrels a day in fiscal2001, is expected to average 1.012 million barrels a day in 2002 and to remain abovethe million-barrel-a-day mark through fiscal 2010. But, Condon said, because of theway oil production is taxed, declining barrels of Prudhoe are being replaced by bar-rels from newer fields which bring less revenue to the state.

Revenue is forecasting that the Constitutional Budget Reserve will be empty bysummer 2004.

—Kristen Nelson

■ T U L S A

Oklahoma governor urgesConoco to return to stateOklahoma officials look at tax incentives to lure theConocoPhillips headquarters to state; Keating meets withMulva, plans meeting with Dunham in Houston

By The Associated Press

Oklahoma Gov. Frank Keating plans totravel to Houston to try to convinceofficials of Conoco Inc., formerlybased in Ponca City, to return to the

Sooner State. Conoco and Bartlesville-based Phillips

Petroleum Co. announced Nov. 18 a pro-posed $15.4 billion merger of the two com-panies, with headquarters in Texas.

Keating met Dec. 7 with Jim Mulva,Phillips’ chief executive officer, to “talkabout the value of staying in Oklahoma,”Keating press secretary John Cox said Dec.10.

In Houston, Keating is expected to meetwith former Oklahoman Archie Dunham,Conoco’s chief executive officer, who isslated to head the merged company.

“So much of the media focus has been onkeeping Phillips in Oklahoma, but they arealready here,” Cox said. “It’s really moreabout getting Conoco to move to Oklahoma.That’s why the meeting with Mr. Dunham isso important.”

Conoco officials have shown support forheadquartering in Houston and haveremained vague about Oklahoma job cuts inU.S. Securities and Exchange Commission

documents filed this month.

Incentive to stay

Oklahoma legislators from theBartlesville area indicated that the meetingbetween Keating and Mulva lent more sup-port for the idea of a tax reform packageworking as an incentive to place companyheadquarters in Oklahoma.

Proposals discussed have called for elim-inating all or part of the state income tax,which wealthier executives must pay inOklahoma, unlike Texas.

Bartlesville-area lawmakers — Reps.Mike Wilt and Gary Taylor, along with Sen.Jim Dunlap — are hoping for a special ses-sion vote on tax reform that would allowOklahomans to vote on the matter byAugust.

While state officials look at tax proposalsas a way to lure the ConocoPhillips head-quarters to Oklahoma, Dunham and Mulvahave said they want top offices in Houstonbecause of Wall Street perceptions, better airtravel and increased educational and enter-tainment options.

The merger’s impact on the 2,400Phillips jobs in Bartlesville and 1,900 atConoco in Ponca City still is undecided,company officials say.◆

continued from page 5

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Petroleum News • Alaska 7Week of December 16, 2001

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CENTRAL NORTH SLOPEState approves AEC Oil andGas (USA) as McCoveyoperator, update of plan

The Alaska Department of Natural Resources Division of Oiland Gas has approved an update to the initial plan for theMcCovey unit and a change of operator from Phillips AlaskaInc. to AEC Oil and Gas (USA) Inc.

The division said Dec. 6 that the McCovey unit agreement,approved by the division andthe U.S. Department of theInterior’s MineralsManagement Service for atwo-year term expiring Aug.31, 2002, has been extendedthrough June 30, 2003, sub-ject to concurrence by MMS.MMS spokeswoman Robin Cacy told PNA Dec. 10 that MMSis reviewing the application.

The McCovey update proposes using the steel drilling cais-son, rather than an ice island, to drill the McCovey well. Thedivision said that AEC plans to obtain the necessary permits touse the SDC to drill exploratory wells in the McCovey unit,refurbish the SDC between May 1 and July 15, 2002, and moveit to the McCovey unit location by Aug. 10.

The rig would be unoccupied in quiet mode between Sept. 1and Oct. 15, 2002, to limit affecting the whale migration.

The proposed schedule includes drilling from the SDC dur-ing the 2002-2003 winter season.

The division said the McCovey update is approved throughJune 30, 2003, conditioned upon: beginning of drilling by June30, 2003; the working interest owners drilling the well from abottom-founded mobile offshore drilling unit; drilling the well toa depth sufficient to penetrate the Basal Brookian Interval or13,000 feet subsea, whichever is lesser; termination of the unit ifthe working interest owners do not meet obligations for the unit.

■ A N C H O R A G E

Phillips Petroleum capital budget up2 percent; Alaska share down Alaska capital projects include 10 exploration wells; millennium class tankers;facility expansion at Alpine; Kuparuk and Prudhoe Bay satellite development

By Petroleum News • Alaska

The board of directors ofPhillips Petroleum Co. hasapproved $3.5 billion for cap-ital projects in 2002, up from

$3.1 billion for 2001. Alaska's exploration and pro-

duction capital budget did not seean increase. Instead, it hasdropped more than 14 percent, to$807 million from $942 million in2001.

Overall, the company's explo-ration and production budgets,$2.6 billion for 2002 and $2.55billion for 2001, rose 2 percent.Where the money is goingchanged, with exploration dollarsdropping 47 percent to $238 mil-lion (from $446 million in 2001)and production gaining 12 percentto $2.6 billion (from $2.55 billionin 2001), with foreign productiongaining the most, up 49 percent to$2.4 billion from $2.1 billion in2001.

International competition

Phillips said Dec. 11 when itreleased the capital budget that thelarger capital program reflectsincreased spending on develop-ment of legacy exploration andproduction assets in Venezuela,China and the Timor Sea and afull year of funding for down-stream projects acquired in theSeptember 2001 acquisition ofTosco Corp.

“The Alaska projects have tomeasure up against Phillips’worldwide projects. Wheremoney will be spent comes downto economics,” Phillips AlaskaInc. spokeswoman Dawn Patiencetold PNA.

The capital budget is split 74percent to exploration and produc-

tion, 24 percent to refining, mar-keting and transportation and 2percent for general corporate pur-poses.

Fewer wells

The Alaska exploration budgetis down almost 40 percent to $41million, from the $68 million bud-geted in 2001. The production cap-ital budget for Alaska, $766 mil-lion, is down more than 12 percentfrom $874 million in 2001.

Phillips officials have said thatfewer exploration wells areplanned in Alaska in 2002: 10compared to 15 in 2001, nine in2000 and six in 1999.

“This past year was an excep-tional year for exploration,”Patience said.

Phillips said that Alaska wellsin 2002 will be in the NationalPetroleum Reserve-Alaska and onthe North Slope.

Phillips Petroleum spokes-woman Kristi DesJarlais told PNAthe difference in 2001 and 2002production capital spending islargely due to the investmentsPhillips made this past year indeveloping the Alpine andMeltwater fields.

“Another difference betweenlast year and this year is the acqui-

sition of addition interest in TAPSthat is reflected in 2001,” she said.

Of the capital production bud-get, Patience told PNA, the com-pany will spend about $200 mil-lion in 2002 on its millenniumclass tankers (four are under con-struction, one is already in ser-vice), and about $47 million onAlpine capacity expansion.Production at Alpine, where thefacilities are rated for 80,000 bar-rels per day, reached a one-dayhigh in November of 108,000 bpd,Patience said. A lot of tweakinghas been done with the Alpinefacilities already, she said, and thecapacity expansion will be a wayto look at expansion for Alpinesatellites and other developments.

The rest of the capital produc-tion budget is primarily for satel-lite work, Patience said:Meltwater, Palm and West Sak atKuparuk and Borealis at PrudhoeBay.

Alaska capital projects accountfor 23 percent of Phillips' world-wide investment for next year,Patience said, with about 50 per-cent of the company's actual pro-duction worldwide coming fromAlaska — a year-to-date averagefor 2001 of 392,000 barrels perday. ◆

Sag Delta No. 1 rehabilitationplanned for this winter

BP Exploration (Alaska) Inc. is permitting remediation workat the Sag Delta No. 1 exploratory well site in the SagavanirktokRiver delta, a special condition of its U.S. Army Corps ofEngineering permit for expansion of Milne Point G, H and Ipads.

The corps said the work will rehabilitate the well site to tidalflats at an elevation similar to surrounding tidal flats and with nohydrocarbon contamination.

The Sag Delta No. 1 well was drilled in 1975. A breachoccurred in the reserve pit in 2001 and was repaired April 26,

see SAG DELTA page 9

The McCovey updateproposes using the steel

drilling caisson, rather thanan ice island, to drill the

McCovey well.

Phillips’ capital production budget includes about $47 million for Alpinecapacity expansion.

Judy

Pat

rick

By Kristen NelsonPNA Editor-in-Chief

BP Exploration (Alaska) Inc. has toldthe state in an annual progress reportthat Badami unit production remainsat about 2,000 barrels of oil per day

and that no further development drilling isplanned at the field — the farthest east pro-ducing field on the North Slope.

But the company said facilities atBadami could be used for other develop-ment.

BP has stopped importing gas fromEndicott to Badami and has no plans toresume importing gas under the current planof development.

Production continued through last winterwithout a pipeline shutdown and evacuationto avoid the line freezing. There were nosignificant changes in surface facilities andinfrastructure at the field.

Well work was limited to minor non-riginterventions, and that is expected to con-tinue for this plan of development. The fieldis being operated with limited manpower,with approximately 15 people on site.

Badami satellite evaluationcontinues

Last February, BP constructed an iceroad and removed the Badami and PointThomson drilling rigs. BP said it has noplans for further development drilling atBadami.

But satellite evaluation continues, andBadami facilities could be used forSlugger, an exploration unit which lies afew miles to the south (see adjacent map).

“Further evaluation of satellite potential

within the unit was undertaken and discus-sions with third parties interested in partici-pating in exploration of this potential havetaken place,” BP said.

“Discussions have also taken place withthe Slugger exploration unit partnersregarding use of the Badami facilities fornon-unit activity and development.”

BP is also the unit operator at Slugger.BP and the other Slugger unit workinginterest owners, Chevron and Phillips, allsubmitted letters to the Department ofNatural Resources in July, committing todrill the Slugger No. 1. The companies hadpreviously presented reprocessed Sluggerunit seismic data to the Division of Oil andGas.

The well requirement at Slugger requiresdrilling through the Kemik interval by May15, 2003, subject to termination of the unitand payment of a $430,000 penalty, whichwill be paid by BP and Chevron should thewell not be drilled by the state’s deadline.

As reported by PNA in August, BPfarmed out all — and Chevron and Phillipsfarmed out part — of their working interestin the Slugger unit to independents ForestOil Corp. and Andex Resources LLC inexchange for a disproportionate share of thecosts of the first Slugger well. Andex andForest will each receive approximately a 20percent working interest in the easternNorth Slope unit.

On Aug. 21, a Chevron representativetold PNA, “One of the reasons we likeSlugger is it should ring the cash registerfaster than our other North Slope explo-ration prospects since, if successful, the pro-duction will likely be processed at the exist-ing Badami facilities.”◆

EXPLORATION & PRODUCTION8 Petroleum News • Alaska Week of December 16, 2001

■ E A S T E R N N O R T H S L O P E

Badami facilities could beused for Slugger developmentNo further development drilling is planned for Badami; unitproduction remains at 2,000 barrels of oil per day

Oil & Gas Units, Eastern North Slope

EXPLORATION & PRODUCTION/ARCTIC GASPetroleum News • Alaska 9Week of December 16, 2001

2001, with 14 loads of gravel from agravel stockpile on site.

The site covers approximately nineacres and includes a gravel pad, tworeserve pits and two smaller pits withinthe pad, and an adjacent bermed flarepit.

Preliminary results of a survey of thepad done earlier this year indicated thatapproximately 10 percent of the gravelmay be contaminated with hydrocar-bons.

Gravel removal at Sag Delta No. 1 isscheduled for this winter using an iceroad which will run offshore from EastDock to the Sag Delta No. 1 site. Alldrilling wastes, reserve pit water andhydrocarbon-contaminated gravel will

be removed for off-site disposal. The gravel pad and berms will be

removed completely so that the site isleft at an elevation similar to the sur-rounding tidal flat. Contaminated grav-el will be hauled off-site for disposaland any clean gravel not used to fill thereserve pits removed for off-site reuse.

The site will not be seeded or fertil-ized as it will be below tidal level and isintended to become visually integratedwith the natural tidal flats, which is amostly un-vegetated, irregularly flood-ed tidal flat of the Sagavanirktok River.

continued from page 7

SAG DELTA The site covers approximatelynine acres and includes a gravelpad, two reserve pits and two

smaller pits within the pad, andan adjacent bermed flare pit.

■ C A N A D A

Cross-border legislators launchpromotion of highway pipelineInternational committee to pursue “timely” construction,but Torgerson cautions that growing gas reserves andeconomic slowdown make start-up unlikely before 2011

By Gary Park PNA Canadian Correspondent

Abilateral committee of legislatorsfrom Alaska and three Canadianjurisdictions has pledged itself toachieving a “timely” delivery of

gas through an Alaska Highwaypipeline, while being cautioned to lowerits sights on a start-up date.

The committee, holding its first meet-ing in Whitehorse Dec. 8, set its missionas expediting gas shipments in a waythat will maximize benefits for Alaska,the Yukon, British Columbia andAlberta.

Yukon Economic DevelopmentMinister Scott Kent said one of the pri-mary goals will beto encourage deci-sion-makers in allfour legislatures tobegin work on thehighway project.

But Alaska Sen.John Torgerson, inan interview withthe Whitehorse Starprior to the meeting,said he doubts apipeline will beoperational before2011 — three tofour years behindthe usual forecasts— and could evenbe delayed until2013.

He said the cur-rent economicslowdown hasallowed a build upof gas reserves because of conservationand the decline in demand, especially forgas-fired electrical generation by indus-trial users.

Torgerson pointed out that gas pro-ducers who normally like to have sevento eight years of supply, now havereserves stretching out over 11 years.

In addition, the volumes from 17,000gas wells drilled in the past year haveyet to be factored in, further reducingthe urgency of an Alaska Highwaypipeline.

However, Torgerson said there is noreason to expect a repetition of the late1970s when the original highway pro-ject was shelved.

He predicted in the interview that theAlaska producers, who are expected torelease the findings of their feasibilitystudy in the first quarter of 2002, willreport that a pipeline is not economicalwithout tax and other revenue support

from the federal, state and territorialgovernments.

Energy bill would removecommitments

Torgerson said a new Democrat-spon-sored energy bill before the U.S. Senateproposes to take away significant com-mitments made to the state of Alaska andFoothills Pipe Lines Ltd. when the high-way corridor was entrenched in interna-tional agreements in the 1970s.

Under the proposed bill, Alaska’scommunities could lose the guarantees ofcommunity access to the gas line thatthey currently have if the producers weregiven the right to build their ownpipeline.

The implications for Foothills alonecould result in years of legal action,which would be the last thing the projectneeded, Torgerson said.

Along with Torgerson and Kent, theinternational committee includes MarkHlady, a member of the Alberta legisla-ture and chair of the Alberta legislature’sstanding policy committee on energy andsustainable development. BritishColumbia has yet to appoint a represen-tative.

Torgerson told the inaugural meetingthat the committee must strive to coordi-nate measures to maximize jobs andbusiness opportunities along the pipelineroute.

Hlady, echoing the Alberta govern-ment’s insistence of making gas liquidsavailable to the province’s petrochemicalindustry, said that ensuring access toboth the gas and the liquids by all com-munities, industries and hubs could be animportant function of the committee.

The committee will finalize its goalsafter discussions with British Columbiaand the Northwest Territories, agreeingthat two pipelines — the highway projectand a stand-alone Mackenzie Valley pro-ject — will eventually be constructed.

The committee said it will explore thepossibility of hosting a conference andtrade show in Calgary next year, with afocus on regulatory matters and businessopportunities.

The next meeting will be held inBritish Columbia in January. ◆

Yukon EconomicDevelopmentMinister Scott Kent

The committee, holding its firstmeeting in Whitehorse Dec. 8, set

its mission as expediting gasshipments in a way that will

maximize benefits for Alaska, theYukon, British Columbia and

Alberta.

Alaska Sen. JohnTorgerson

ARCTIC GAS/PIPELINES & DOWNSTREAM10 Petroleum News • Alaska Week of December 16, 2001

DRIFT RIVERCook Inlet Pipe Line applies toremove old pipeline at Drift River

Cook Inlet Pipe Line Co. is permitting the removal of approximately 2,000 feetof 20-inch pipeline from beneath the channel of the Drift River on the west side ofCook Inlet.

The company recently replaced the pipeline crossing at Drift River using hori-zontal drilling techniques and is applying to remove the old pipeline, no longer inuse.

Cook Inlet Pipe Line said pipeline will be drained prior to removal. Thepipeline will be excavated to near the top of the pipe and lifted from one end usingan excavator or crane. Excavated materials will be placed on the upstream side ofthe excavation and dozed back into the excavation once the pipeline has beenremoved.

The work area in the channel is approximately 50 feet wide by 2,000 feet long.The trench will be approximately 10 feet wide and up to 10 feet deep; some 7,500cubic yards of sand and gravel would be excavated and side cast.

The work is proposed for March or October of 2002 to avoid major impacts toanadromous fish and waterfowl.

■ C A N A D A

Record drilling not enough tostop decline in gas reserves Canadian Association of Petroleum Producers reportssupplies fell in 2000 for fifth straight year; crude oil andequivalent gains 400 million barrels

By Gary Park PNA Canadian Correspondent

Canada’s record-breaking explo-ration efforts to build its natural gassupplies are going backwards, withreserves falling in 2000 for the fifth

straight year. In its 50th annual reserves report, the

Canadian Association of PetroleumProducers reported that despite theunprecedented completion of 8,929 gaswells in 2000, reserves across Canadaslipped by 2.1 percent from 1999 to exitthe year at 59.7 trillion cubic feet, down12 trillion cubic feet since 1990.

In the Western Canada SedimentaryBasin, there was a similar decline to 56.9trillion cubic feet, but the East Coast off-shore showed a net gain of 300 billioncubic feet to 2.7 trillion cubic feet.

Crude oil and equivalent reservesgrew by almost 400 million barrels in2000 to 12.3 billion barrels, largely dueto discoveries in Saskatchewan, wherereserves increased by 7.7 percent to 1.15billion barrels.

Booked reserves at oil sands projectswere basically unchanged at 5 billionbarrels, although the Alberta Energy andUtilities Board estimates the provincehas 315 billion barrels of ultimatelyrecoverable reserves.

Industry invested almost C$23billion

CAPP said the industry investedalmost C$23 billion in capital programsduring 2000, up C$6 billion from 1999,making the oil and gas sector the largestprivate-sector investor in Canada for theyear.

But, faced with forecasts of a possible20 percent decline in spending in 2002,CAPP fiscal policy chairman JohnRichels said the industry “has to reinvestjust to sustain the current production lev-els.”

The major immediate concern is theerosion of gas reserves at a time whenCanada is being counted on to provide 70percent of North America’s incrementalgrowth demand over the next eight years.

Greg Stringham, CAPP vice-presidentof markets and policy, said member com-panies are agreed the focus must shift to

gas, with greater emphasis on explorato-ry drilling instead of development work.

Drilling likely to shift to deeperplays

The decline rates of wells drilled inwell-defined areas, combined with posi-tive results from areas such as BritishColumbia’s :Ladyfern region, are likelyto see drilling shift to deeper plays inAlberta and British Columbia and north-ward to the Yukon and NorthwestTerritories, CAPP said.

According to CAPP, the industryreplaced only 79 percent of productionfrom the Western Canada SedimentaryBasin in 2000 compared with 83 percentin 1999.

In Alberta, 65 percent of gas produc-tion in 2000 was replaced, leavingreserves at 44.8 trillion cubic feet and150 percent of British Columbia’s pro-duction was replaced, building reservesto 8.9 trillion cubic feet although theLadyfern discoveries have yet to be cal-culated.

The report attributed Alberta’s resultslargely to a continued shallow-gasdrilling trend in southeastern Alberta,which accounted for 50 percent of all gaswells in the province.

More than 10,000 gas wells thisyear

CAPP said gas drilling in all ofCanada should surpass 10,000 wells thisyear — based on a total 9,102 gas com-pletions to the end of October — beforedeclining in 2002 in response to weakercommodity prices and reduced cashflows. Other industry organizations andanalysts are widely agreed in their 2002forecasts that the number of gas wellswill drop by as much as 25 percent nextyear.

Conventional light and heavy reservesin Western Canada rose to 3.5 billionbarrels, replacing 104 percent of produc-tion, due largely to Saskatchewan’sheavy-oil dominated industry replacing154 percent of production Alberta’sreplacement rate of 74 percent left theprovince with 2.08 billion barrels, whileBritish Columbia was unchanged at 174million barrels.

CAPP said new drilling in the EastCoast’s offshore Hibernia and TerraNova fields added 136 million barrelsafter production and raised reserves toabout 1 billion barrels. So far, there hasbeen no attempt to estimate reserves forthe White Rose, Hebron/Ben Nevis,which are due to come on stream in thenext three or four years, or other fields inNewfoundland’s Grand Banks. ◆

The major immediate concern is theerosion of gas reserves at a time

when Canada is being counted on toprovide 70 percent of North

America’s incremental growthdemand over the next eight years.

Williams executive dies at 58 Cuba Wadlington Jr., president and chief executive officer of Williams’ gas

pipeline division and executive vice president of Williams, died Dec. 9 of compli-cations related to cancer. He was 58.

From 1995-99, he served as senior vice president and general manager ofWilliams’ Transco natural gas pipeline system. From 1988 to 1995, he served assenior vice president and general manager of Williams Western Pipeline Co., exec-utive vice president of Kern River Gas Transmission Co. and director of NorthwestPipeline Corp. and Williams Western Pipeline, all affiliates or subsidiaries ofWilliams.

He was vice president of planning and corporate development for NorthwestPipeline from 1984-88. The Kern River pipeline was conceived and planned whilehe served in this position.

From 1979 to 1984, he served as director of regulatory affairs for NorthwestAlaskan Pipeline Co., a wholly owned subsidiary of Northwest Energy Co.

TULSA

By Kristen Nelson PNA Editor-in-Chief

After months of written and oral presen-tations, examination and cross exami-nation, the Alaska Oil and GasConservation Commission has found

no merit in a petition from Danco Inc. andMonte Allen to forcibly unitize two leasesinto the North Cook Inlet unit and hasdenied the petition.

The commission first denied the petitionin 1997, saying then that because the leasesin question expired shortly after petitionersfiled for forced unitization in August 1996,any decision it rendered would be moot.

That decision was appealed. The superi-or court affirmed the commission’s deci-sion, but the Alaska Supreme Court ruled inMay 2000 that the commission could orderunitization retroactive to the date of the peti-tion and remanded the case for a hearing onthe merits.

In a Dec. 3 decision, the commissionitemized evidence by experts for the peti-tioners that the unit should be expanded andsaid it found that evidence neither crediblenor persuasive.

The commission said it found evidenceby witnesses for North Cook Inlet unit oper-ator Phillips (Phillips Petroleum Co. andPhillips Alaska Inc.) that the existing unitencompasses the productive reservoir to beboth credible and persuasive.

Issue of standing not addressed

Jurisdiction over the case was returnedto the commission effective August 2000and in September 2000 the commissionissued a procedural order stating it wouldfirst determine if the leases should beordered unitized, and then decide the detailsof a plan of unitization, noting that that itwould determine at that time whether itmight be appropriate to defer to theDepartment of Natural Resources on someor all of the details of a plan of unitization.

DNR approved the existing voluntaryNorth Cook Inlet unit.

In 1997 the commission said it haddecided not to reject the petition on theground that petitioners owned no workinginterest in the leases (Danco and Allen wereoverriding royalty interest owners, notworking interest owners), but noted thatdecision “was made without notice to otherinterested parties and is subject to beingrevisited at the request of an interested

party.” Phillips argued in

the present hearingthat petitioners do nothave standing to peti-tion for involuntaryunitization becausethey do not own anyworking interest inthe leases.

The commissionsaid in this decisionthat because the Supreme Court directed itto hold a hearing on the merits, it did notrevisit the earlier decision. The commissionalso said Phillips had urged it to “decide thecase on the facts so that the matter is finallyresolved on the merits.”

The commission said it “decides thispetition on its merits and does not addressthe standing issue. We observe, however,that the issue is open to further Commissionconsideration in any future petition forinvoluntary unitization brought by a personother than a working interest owner.”

Theory that unit “may” be drainingleases

The commission said it agrees withPhillips that petitioners have the burdenproof “and believes that the involuntaryunitization statute contemplates that a peti-tioner must show that the conditions forexercise of the involuntary unitizationpower have been met in order for thatpower to be exercised.”

The commission said that petitionersargued that because the hearing was bifur-cated — with details of a unit to be deter-mined after an expansion decision — that itwas sufficient to show at this stage that theNorth Cook Inlet unit “may” be draining theadjacent leases.

“There is no merit to this notion, whichwould render futile and superfluous theconsiderable expenditure of time, effort andmoney in connection with the hearing thatcommenced last March and with severalinterruptions, ended in June. It is complete-ly clear,” the commission said, “that it iswas the purpose of that hearing, and notsome future hearing, to present whateverevidence the parties wished to be consid-ered on the question of whether the statuto-ry conditions for involuntary unit expansionwere met in this case.”

The commission said that even if thepetitioners “may” be draining argument hadmerit, the evidence fails to show any rea-sonable possibility that the North CookInlet unit is draining gas from the Dancoleases.

Petitioners’ evidence “not credibleor persuasive”

Petitioners’ presented three primary wit-nesses: Dr. James Givens, a petroleum engi-

neer; David Lappi, a geologist and geo-physicist; and Monte Allen, one of the peti-tioners.

Givens’ “various, and conflicting, pro-

posed reservoir limits extending into theDanco leases are inconsistent with wellcontrol. Notably, at least one dry hole ispresent within each of the proposed reser-voir limits,” the commission said, and fur-ther said that it found Givens’ testimony“inconsistent and self-contradictory andthat his analysis as described in his testimo-ny does not conform to generally accepted

professional methods for petroleum engi-neering and is not credible or persuasive.”

The commission noted that it did notqualify Monte Allen as an expert, and said“his testimony on technical issues is notbased on and does not reflect the applica-tion of generally accepted geological, geo-physical, or engineering principles or tech-niques, and it is not credible or persuasive.”

“Mr. Allen also made a number of asser-tions concerning the alleged misconduct ofunit or lease operators or state officials,” thecommission said, and it said that it found“those assertions to be erroneous or irrele-vant to the issues in this case or both.”

Lappi’s testimony focused on interpret-ing Phillips’ seismic data and the commis-sion said that seismic and well control datashow that areas Lappi “characterized as con-sistent with gas are likely to represent coaldeposits and that, in any event, those areasare not continuous with the gas reservoirs inthe NCIU.

“Hence,” the commission said, “if anygas exists under the Danco leases, it is not inreservoirs that extend from the NCIU.”

Of Lappi’s testimony on a gas-water con-tact, the commission said Lappi “misreadand misinterpreted or selectively ignored therelevant well data.”

The commission said it “also finds thatMr. Lappi’s analysis as described in his tes-timony does not conform to generallyaccepted professional methods for petrole-um geology or geophysics and is not credi-ble or persuasive.”

COOK INLETPetroleum News • Alaska 11Week of December 16, 2001

■ N O R T H C O O K I N L E T

Alaska Oil and Gas Conservation Commission denies Dancopetition for forced unitization of leases into North Cook Inlet unitCommission hears case remanded from Alaska Supreme Court on the merits; issue of standing not addressed, but commissionsays that issue is open to consideration in any future petition brought by a person other than a working interest owner

see PETITION page 12

“… if any gas exists under theDanco leases, it is not in reservoirs

that extend from the NCIU.” —Alaska Oil and Gas Conservation

Commission

The commission said it “decidesthis petition on its merits and doesnot address the standing issue. Weobserve, however, that the issue is

open to further Commissionconsideration in any future petition

for involuntary unitization brought bya person other than a working

interest owner.”

AOGCC commisioners, from left to right, are Cammy Oechsli Taylor(chair), Dan Seamount and Julie Heusser.

Phillips’ witnesses “credible andpersuasive”

The commission also reviewed testi-mony of the five witnesses presented byPhillips and found testimony from eachto be “credible and persuasive.”

John Horn, a retired Phillips manager,provided written testimony on the histo-ry of the North Cook Inlet unit. Thecommission said Horn “stated that it wasthe intention of Phillips to include with-in the NCIU all of the commercially pro-ductive gas regions in the area and thatPhillips had no reason to exclude fromthe unit productive lands already leasedby Phillips, including the lands withinwhat later became the Danco leases.”

Area first leased in 1961, 1962

The area was first leased in 1961 and1962. DNR approved the North CookInlet unit in 1967 — including leasesthat subsequently became the Dancoleases at issue here. In 1972, the com-mission said, DNR required contractionof the unit “to conform to the presenceof productive gas reservoir.” Acreage

excluded from the unit eventuallylapsed; subsequent leases composed ofportions of the land excluded wereallowed by their owners to expire with-out drilling.

Danco acquired its leases (ADL369100 and ADL 369101) north of theunit in 1986. In 1988, Danco assigned allworking interest ownership in the leasesto Amoco Production Co., reserving anoverriding royalty interest, fractions ofwhich were assigned to others includingMonte Allen.

ARCO acquired 100 percent of theworking interest in the Danco leases in1992 through drilling an exploratorywell on an adjacent lease. In 1992,ARCO and Phillips cross-assigned inter-

est in a number of leases, including theDanco leases. The primary terms of theDanco leases expired Aug. 31, 1996.

In April 1999 and August 2000, por-tions of lands comprising the formerDanco leases were re-offered by DNRbut received no bids.

Estimated recoverable gas an issue

The commission said Givens said“estimates of recoverable gas in theNCIU have essentially doubled since thepool was discovered in 1965 and thatthis doubling indicates that the poolextends under the Danco leases.”

Givens compared “an early deliver-ability projection that was based on verylittle data to later material balance analy-ses” to show doubled reserves, the com-mission said, but the deliverability pro-jection was done in 1967 based on onlythe Sterling formation and at a timewhen seven wells had been drilled andthere was no significant production.

“To derive material balance reservesfrom a deliverability estimate, as Dr.Givens did, is a fundamental misapplica-tion of this data,” the commission said,noting that neither Phillips nor its part-ners made any claims of gas in place atthe 1967 hearing.

The commission said Givens referredto material balance analyses from a 1996report by Geoquest on Cook Inlet provenreserves.

“Contrary to the suggestion thatreserves estimates were recently dou-bled,” the commission said, “theGeoquest Report indicates that data fromas early as 1975 … established a materi-al balance trend that projects recoverablereserves of 2.36 TSCF, with GIP of 2.72TSCF. The report found that 1.049TSCF of gas remained in the Sterlingand Beluga Formations in communica-tion with the wells based on materialbalance calculations. …

“Utilizing the same Geoquest dataand extrapolating back to day one ofproduction,” the commission said, “areservoir pressure very close to thatactually measured can be demonstrated.This technique indicates that NCIUreserves have not changed significantlysince the beginning of production. Anystatement referring to a doubling ofreserves is incorrect and ignores actualdata.”

Area not larger

The commission also said that Givens“mistakenly assumes that more gasreserves means a greater areal extent ofthe reservoir.” Volume of gas containedin a reservoir depends on several factors,the commission said, including: lengthand width; thickness; gas saturation; netto gross sand ratio; porosity.

“Evidence submitted at the hearingshows that the thickness of the produc-tive intervals in both the Sterling andBeluga formations is now known to besubstantially thicker than was apparentor counted at the time of initial fielddevelopment,” the commission said, andintervals counted as productive haveproduced more gas than expected.

The commission said that 3-D seismicsurveys acquired by Phillips and ARCOover the North Cook Inlet unit providemuch better quality and precision thatthe 2-D seismic available when the unitwas formed and “subsurface interpreta-tions presented by Phillips included rig-orous calibration of 3-D seismic with allrelevant well data, including NCIUdevelopment wells and Tyonek Deepexploratory wells drilled in the unit.”

This data demonstrates, the commis-sion said, “that the areal extent of theCook Inlet No. 1 Sand gas accumulationis marginally less extensive than esti-mated at the time of the 1967Conservation Order No. 40 hearing. …

“The seismic data, as calibrated bywell and production data, demonstratepersuasively that the Danco leases arestructurally lower than 4260 feet subsea,the depth of the gas water contact in themost areally extensive NCIU gas reser-voir. The Danco leases do not containany portion of any productive gas reser-voir within the NCIU.” ◆

COOK INLET12 Petroleum News • Alaska Week of December 16, 2001

Anchorage Daily News

Petroleum News • Alaska

Alaska Business

Monthly

Alaska Journal

of Commerce

Fairbanks Daily

News-Miner

Juneau Empire

continued from page 11

PETITION “Utilizing the same Geoquest dataand extrapolating back to day one

of production … indicates that NCIUreserves have not changed

significantly since the beginning ofproduction. Any statement referringto a doubling of reserves is incorrectand ignores actual data.” —Alaska

Oil and Gas ConservationCommission

    

WORLD OILPetroleum News • Alaska 13Week of December 16, 2001

■ C A N A D A

Alberta warns Kyoto could drive capital,companies from Canada Preliminary findings project loss of 70,000 energy industry jobs, extra C$3 a barrel on oilsands operating costs and C$6 billion in annual losses for Alberta

By Gary Park PNA Canadian Correspondent

Canada’s role as the largest exporter ofoil and gas to the United States hangsin the balance as the federal andAlberta governments clash over

whether Canada should formally ratify theKyoto Protocol on reducing greenhouse gasemissions.

A preliminary report by the Alberta gov-ernment, obtained by Petroleum NewsAlaska the last week in November, warns oiland gas companies will flee Canada, 70,000industry-related jobs will be lost and thecosts of oil sands production will climb ifthe terms of Kyoto are implemented.

Alberta, which is due to release a detailedeconomic assessment by mid-December,estimates the cost of meeting the greenhousegas emission targets would be C$6 billion ayear for the petroleum-driven Alberta econ-omy.

The government report calculates oilsands operating costs would rise by aboutC$3 a barrel, at a time when advances intechnology, including lower emissions ofcarbon dioxide, have allowed SuncorEnergy Inc. and Syncrude Canada Ltd. to settheir sights on C$15 a barrel and less andhelped to attract more than C$50 billion ofpotential new investment.

Investment would flee south

The preliminary findings, presented toAlberta cabinet ministers, also warn of aflight of investment capital to Mexico,Venezuela and Saudi Arabia, Canada’smajor competitors for a share of the U.S.energy market, which are exempt fromKyoto.

“We don’t believe Canada should ratifyKyoto” unless it can obtain credit for export-ing “clean” energy such as natural gas andhydroelectric power, Alberta EnvironmentMinister Lorne Taylor said.

“How suicidal does the federal govern-ment want to be in the destruction of theCanadian economy?” he asked.

“Mexico is our competitor for natural gasand Venezuela is our competitor for heavyoil, so if it is too expensive to develop those

resources here, companies will simply movethere,” said Taylor. “What will happen iscarbon dioxide production will also move ...and that’s what is so ridiculous” about thefederal government’s insistence that it willratify Kyoto, he said.

Industry concerned

Pierre Alvarez, president of the CanadianAssociation of Petroleum Producers, carriedthe industry’s concerns to the federal gov-ernment the last week in November.

He told reporters the industry does notwant to see foreign firms, especially thosefrom the United States, pull back fromplanned multi-billion-dollar investments inCanada, or have Canadian companies movetheir capital to other countries.

Alvarez noted that Canadian-based com-panies have boosted their overseas invest-ment to C$3 billion this year from C$500million in 1994.

“We now have large Canadian indepen-dents who are capable of playing on an inter-national field and Canada has got to be com-petitive,” he said.

Calgary-based Nexen Inc. (formerlyCanadian Occidental Petroleum Ltd.),which produces 118,000 barrels a day inYemen (more than half its total output), isready to reallocate its investment to otherparts of the world if Canada becomesuncompetitive, said president and chiefexecutive officer Charlie Fischer.

He said the industry in Canada can’tafford to lose its competitive edge against

the United States, which has refused to signon to Kyoto.

Nexen, which is a 7 percent partner in theSyncrude Canada consortium and has justannounced its participation in a new C$2billion oil sands project, will do a “lot ofrethinking” if it is faced with an extra C$3 abarrel on its operating costs, said companysenior vice-president Roger Thomas.

Signs of political divisions

While Prime Minister Jean Chretien sayshe is confident Parliament will formally rat-ify Canada’s participation in Kyoto by nextJune, there are growing signs of a rift with-in the federal cabinet.

In late November, Natural ResourcesMinister Ralph Goodale and IndustryMinister Brian Tobin said in public speech-es that the overall costs of reducing green-house gas emissions will be a key ingredi-ent in deciding whether or not Canada willsign on.

A study in October by Tobin’s depart-ment estimated the cost of compliance forCanada at about 1.5 percent of nationalgross domestic product, or about C$15 bil-lion a year.

Goodale told a news conference Nov. 30that the concerns of Alberta and the petrole-um industry merit serious attention ifCanada is to have both a healthier environ-ment and solid economy.

He said oil sands production is“extremely valuable” to Canada and a keysource of security of supply for the UnitedStates. “We need to make sure that thestrong level of activity in the oil sands con-tinues,” he said.

The depth of the political divisions sur-faced in late November when Chretien andAlberta Premier Ralph Klein shared thesame microphone as part of a Canadiantrade mission to Texas and California.

“We cannot agree to the Kyoto Protocolas it now stands,” said Klein, arguing theemissions reductions would hit Alberta dis-proportionately.

“We have the intention of ratifying,”Chretien responded. “We have to talk withthe provinces before we ratify it, but ourgoal is to ratify.” ◆

“How suicidal doesthe federal govern-ment want to be inthe destruction ofthe Canadian econo-my?” —AlbertaEnvironmentalMinister Lorne Taylor

“We have the inten-tion of ratifying. Wehave to talk with theprovinces before weratify it, but our goalis to ratify.” —Canadian PrimeMinister Jean Chretien

GULF OF MEXICOAnadarkoapparent winnerin GOM sale

Anadarko Petroleum Corp. saidDec. 5 that it is was the apparent highbidder on 26 tracts in the eastern Gulfof Mexico lease sale 181.

The company submitted winningbids representing a total investment ofabout $136 million. The 26 tracts covernearly 150,000 acres in water depthsranging from 7,000 to 9,500 feet. TheU.S. Department of the MineralsManagement Service said the area ofsale 181 is in deepwater off Alabamaand Louisiana.

Robert J. Allison Jr., Anadarkochairman and chief executive officer,commended MMS for their dedicatedeffort to move forward with the EasternGulf of Mexico sale. “These tracts havenot been available for exploration since1988, well before major advancementsin deep water exploration and produc-tion technology. The opportunity toexplore this acreage, and the significantresources that lie beneath, is a positivemove for this Administration and forenergy consumers,” he said.

Prior to this sale, Anadarko held atotal of 351 leases in the Gulf, of which109 are located in deep water.Additionally, the company has a part-nership with BP to explore 95 deepwater blocks held by BP in the GardenBanks and Keathley Canyon areas ofthe Central Gulf of Mexico.

ADVERTISER INDEX14 Petroleum News • Alaska Week of December 16, 2001

THE REST OF THE STORYPetroleum News • Alaska 15Week of December 16, 2001

pleted in December and January, withsome report out on the results in the firstquarter next year.

And work will continue inWashington, D.C., on enabling legisla-tion.

The pace of the 2002 work program,Schilhab said, “will be dictated by whatwe find from these economic results andalso dictated by the political climate,”including the federal government’s activ-ity on enabling legislation and the state’swillingness to provide fiscal certainty.

Enabling legislation essential

“The project is a huge commercial andtechnical challenge and is going to remainthat way,” Joe Marushack, PhillipsAlaska Inc.’s ANS gas vice president toldthe RDC conference, citing project cost,political challenges, technical aspects andvolatility of the gas market.

“We’re truly disappointed” thatenabling legislation the team proposedthis summer has not moved forward, hesaid. Securing enabling legislation “forcompeting projects — not only the pro-ducers, but available to any group — isextremely important.”

“We believe it’s in the best interest ofAlaskans that a low-cost project isallowed to move forward with a rapidpermitting process and we ask you tosupport this in the future.”

In addition to the enabling legislation,the team also supports accelerated depre-ciation. Phillips, not the team, has alsoasked for fiscal tax incentives whichwould come into play in a low-price envi-ronment, Marushack said.

“Within the state,” he said, “we need astable fiscal environment and that is beingaddressed. Current law allows the state tounilaterally change both the economicsand relative competitiveness of the pro-ject that has already been built. This cre-ates unacceptable exposure for such alarge and risky project. There’s nothingnew here and a lot of people understandit. The state recognized this when theypassed the Stranded Gas DevelopmentAct, but it was limited to LNG… Whatwe’re really trying to do is find a set ofrules that we all understand that we agreeto live by for this project.”

In 2002, Marushack said, we will“work to achieve the required federal leg-islation — the enabling legislation, thefiscal legislation” and to advance statefiscal certainty.

Project probably not commerciallyviable

Ken Konrad, performance unit leaderof BP’s Alaska gas group, told the RDCconference that progress with govern-ments is one area where “we’ll need tomatch forward spend with overallprogress.” More than $100 million hasbeen invested this year, he said, and we“simply cannot continue to invest at thispace absent more clarity on key issues.”

The oil and gasbusiness is fiercelycompetitive, he said,and companies needto focus scarcehuman and financialresources wherethey can best be putto use.

“Massive pre-investment, absent aclear path towardsuccess, is a fool’sgame,” he said.

Governments said at the beginning ofthe year that they wanted to help, Konradsaid, and were asked for help in threeareas — U.S. federal regulatory legisla-tion; fiscal predictability in Alaska; andefficient regulatory processes in Canada.

The producers’ regulatory legislation,he said, would provide clear and timelyregulatory process, meet all modern-dayenvironmental regulations and leaveintact the historic Alaska Natural GasTransportation Act.

“We remain hopeful we’ll see successon this bill sometime next year, but in themeantime we’ll need to pace our invest-ment activity accordingly.”

Alaska fiscal certainty, he said, is not arequest “for any reduced taxes or subsi-dies: just clear, simple, predictable rules.”

In Canada, he said, the companies are“discussing with regulators and FirstNations how to develop a thorough butefficient regulatory process that meets theneeds of all groups, while avoidingunnecessary duplication of efforts anddelays.”

“So, three important areas where gov-ernment can help — and three importantareas where we have not yet been able toachieve success,” Konrad said.

Different levels of risk

Konrad said that while he hadn’t yetseen results of this year’s study, he thinksit “will show a project with lower unitcosts to market and lower fuel uses tomarket than any other major ANS gasstudy to date, including pipeline studies

and LNG studies.” Unit costs will be “notquite competitive, but close to it” andthose costs will be based, he said, “onthorough engineering analysis, not wishesand assertions.”

“Unfortunately,” Konrad said, “Iexpect our analysis will also indicate theproject is not at this point in time com-mercially viable. The risk and reward bal-ance is simply not sufficient to attract therequired multi-billion dollar investment.”

What does being commercial mean?There has been some confusion, Konradsaid, about economics for the project.There are two different kinds:

There are pipeline investors — whocould include producers, financialinvestors, pipeline companies — who“generally earn what is known as a utilityrate of return, reflecting the generally lowrisk, stable nature of their investment,” hesaid.

“Effectively, pipeline investors enterinto long-term binding contractual com-mitments with customers — in this caseproducers.” The producers would agree,he said, “to pay capital costs, financingcosts, operating costs and reimburse anyapplicable taxes to the pipeline investors— whether gas is transported or not.”

The main risk to pipeline investors isthe creditworthiness of its customers.“With companies like BP andExxonMobil as key customers,” Konradsaid, “I think it’s probably a pretty safebet.”

Pipeline investors also look at life ofreserves, “which in the case of Alaska isquite high” with additional potential fromyet-to-find resources.

The pipeline investors also, he said,assume a portion of construction cost risk.

With financially strong customers likethe ANS producers and “an unrivaledresource base, we would expect no short-age of prospective pipeline investors

seeking a relatively secure return. Andindeed, we have seen this to be the casewhen we’ve talked to all the pipelinecompanies across North America,”Konrad said.

There’s more than just thepipeline

“Overall project economics encom-pass a much wider realm than just thelower risk utility portion of the project,”Konrad said. “It is this wider view of theproject that will ultimately drive invest-ment decisions.”

“Producers — and the state — willshoulder most project risk by guarantee-ing pipeline investors will be paidregardless,” Konrad said.

“In addition to paying for a pipeline— either directly through ownership orindirectly via firm transportation com-mitments — producers must also consid-er things like gas production costs, theimpacts on oil production from gas sales,price risk in the market, … the risk ofhigher than anticipated tariffs fromshared-cost overruns, pipeline operatingcosts, risks associated with project delaysand the risks of changing taxation.”

Producers are not afraid of these risks,Konrad said: “These are risks we livewith and manage on a regular basis.”

But the producers need to understandthe risks, seek to minimize them whenpossible and balance them against poten-tial rewards in assessing commercial via-bility, he said.

“While we absolutely, positively wantto monetize our very sizeable gasreserves on the North Slope — becausethat is the business we’re in, that is whatwe do for a living — we simply cannotinvest in projects where risks outweighrewards.

“If we did, it wouldn’t be long beforewe were out of business.” ◆

continued from page 1

CHALLENGE

Joe Marushack,Phillips Alaska Inc.’sANS gas vice president

the British Columbia Oil and GasConference in Vancouver conference Dec.7.

Tax incentives in the works

“We need to encourage oil and gas sec-tor growth and I want the industry to dou-ble the number of wells.”

Campbell said a new draft energy poli-cy will be released in January that willcoordinate regulation and development ofall forms of energy, from hydroelectricpower to oil and gas, and alternativesources such as wind and solar power gen-eration.

As well, corporate tax incentives willhelp strengthen investment, including aphase-out of corporate capital taxes.

His declaration came amidst mountingeconomic woes, with the fisheries and min-ing sector in the doldrums, the forestrystruggling under the weight of U.S.imposed duties on softwood experts and

tourism reeling from the aftermath of Sept.11.

Elected on promises to improve BritishColumbia’s business environment,Campbell has been sideswiped by a reces-sion that is expected to result in the layoffof one-third of all government employeesas part of a massive reorganization.

Viewing the oil and gas industry as oneof the few bright spots, Campbell told thecompany executives he is even ready tograpple with the contentious issue of open-ing up the offshore by seeking answers toenvironmental and aboriginal opposition.

SUBHEAD: Queen Charlotte Basinreport due in January

He said a scientific report, due to bereleased by Jan. 15, may suggest thatdevelopment of the Queen Charlotte Basincan occur without excessive ecologicalrisk.

If that is the case, Campbell said, theprovince will quickly begin the process ofnegotiation with industry, local govern-ment and Native groups to open the region,

continued from page 1

INVESTMENT

see INVESTMENT page 16

even though leaseholders Shell CanadaLtd., Petro-Canada and Chevron CanadaResources Ltd. have said they are in nohurry to start exploration.

Lifting the government moratorium onexploration of the basin would allow accessto reserves tentatively estimated by theGeological Survey of Canada at 9.8 billionbarrels of oil and 43 trillion cubic feet ofgas.

Neufeld said he heard a lot of interest inthe offshore from the executives of El PasoCorp., Anadarko Petroleum Corp.,Burlington Resources Inc., Apache Corp.Marathon Oil Co., Conoco Inc. and DukeEnergy Corp.

He said the companies indicated theyare ready to explore the offshore “as longas the price is competitive and there is theneed for the product.”

Neufeld also said the federal govern-ment, realizing it allows exploration ofCanada’s East Coast, is no longer asopposed to opening up British Columbia’scoast.

“We know we’ll have to work with

them on royalties, who owns the seabed,who owns the resources ... so we have aregulatory system in place before industrygoes out there,” he said.

More Ladyferns out there

Campbell said the Ladyfern region ofnortheastern British Columbia, which herated as the “largest single natural gas dis-covery in Canada in the last 15 years,” isfurther proof of the province’s potential.

“There are more Ladyferns out thereand what we have to do is to create anenvironment that encourages explo-ration,” he said.

Alberta Energy Co. alone estimates itsLadyfern production will eventually pro-duce C$1 billion a year in royalties.

To speed approvals, Campbellpromised a single authority permittingagency that will allow the industry to fast-track development.

But he cautioned that developmentmust be environmentally sustainable andthat aboriginal communities must have achance to share in the wealth.

He said a five-year draft agreement toimprove communications with Nativegroups has been signed with three FirstNations in the Ladyfern area, where

blockades have stalled exploration andpipeline construction. The government’sobjective is to involve other First Nationsin that agreement.

Opposition strong to offshoredrilling

The depth of opposition to removingthe offshore ban was captured in a reportreleased Dec. 4 by the left-wing CanadianCenter for Policy Alternatives, which saidBritish Columbia could fall into the sametrap as Newfoundland, 5,000 miles to theeast.

It said billions of dollars of publicmoney could be invested to develop off-shore oil and natural gas without generat-ing hoped-for wealth or equivalent valuein jobs.

“Even if you look at this strictly froman economic point of view, offshore oildoes not make sense for B.C.,” said DaleMarshall, a resource policy analyst withthe center and author of the report.

The report tabulates the billions of dol-lars the federal and Newfoundland gov-ernment poured into the offshore Hiberniafield, which came on stream four yearsago and has been producing about140,000 barrels per day, although it has

permission to pump up to 180,000 barrelsper day.

The trouble-plagued project was madepossible with about C$3.4 billion in feder-al money and more than C$1 billion fromthe Newfoundland government.

“Those governments spent billions ingrants and a billion in investment capital,on top of billions in tax exemptions, inter-est-free loans and loan guarantees,” saidMarshall.

“Based on the royalties agreementstruck (with the operating company) thereis no guarantee the governments will recu-perate all their money through royaltiesand tax revenues.”

Marshall estimated Hibernia has creat-ed only 7.5 jobs for every C$1 millioninvested, even when including multiplierefforts.

Legislature looks for feedback

The center’s study comes just asBritish Columbia members of the legisla-ture are visiting northern communities toget feedback on offshore developmentwhile the government ponders whether tolift a 1981 provincial moratorium onexploration and development. The federalgovernment has had its own freeze ondevelopment since 1971.

Marshall said “going with offshore oilis a lost opportunity. Investments inrenewable energy create 60 percent morejobs than offshore oil and conservationprojects create five times more jobs. Weshould be shifting our attention to thesetechnologies.

“They are not part of sunset industries.They promise tremendous growth in thefuture and they provide a greater numberof more stable jobs.”

“The reason for the large job creationpotential of conservation is two-fold:Retrofitting buildings so that they needless energy is highly labor-intensive; anddecreased energy use means people havemore money to spend in the local econo-my, which creates jobs.”

It estimated the North American mar-ket for wind, solar, tidal, biomass andgeothermal technologies is projected togrow from US$7 billion this year toUS$82 billion in 2010.

The study noted that because AtlanticCanada is a less developed region, theCanadian government granted bothNewfoundland and Nova Scotia some reg-ulatory authority and, more importantly,allowed those two provinces to collectsome of the royalties from offshore devel-opment.

Given the fact that British Columbia isseen as a more economically prosperousregion “the odds of Canada extending thesame courtesy to B.C. seems less promis-ing.”

First Nations claim title offshore

In addition, the study noted, there is theobstacle posed by unresolved aboriginalland claims, with at least four FirstNations claiming rights and title overmarine resources in Hecate Strait orQueen Charlotte Sound, where the oil andgas reserves lie.

Thus the province must resolve whoowns the offshore resources, which meanscomplicated multilateral negotiationsbetween the federal and British Columbiagovernments and First Nations.

On Dec. 5, the Tsimishian First Nationand the Haida announced they had joinedto oppose any lifting of the moratorium.

Tsimishian leader Deborah Jeffrey saidNatives have complete jurisdiction overHecate Strait and insist that any explo-ration must be blocked until an indepen-dent environmental assessment is com-pleted.

—Gary Park

THE REST OF THE STORY16 Petroleum News • Alaska Week of December 16, 2001

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INVESTMENT