page

9Geologist Dave LePain says it’stime to drill the Holitna basin

Vol. 8, No. 44 • www.PetroleumNews.com North America’s source for oil and gas news Week of November 2, 2003 • $1

● A N C H O R A G E , A L A S K A

● C A N A D A

● H O U S T O N , T E X A S

Squeezing last drop from Cook Inlet

8 Husky ready to open wallet: The once scrawny after-

thought among Canada’s five majors ready to spend up to C$2 billion

4Three bite at Bristol Bay licenses: Three companies are

interested in exploration licenses in Alaska’s Bristol Bay region

17 Unocal scores at Harvest Deep: The Harvest 2 appraisalwell in the Gulf of Mexico will likely produce more than the discovery well

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

On Oct. 27 Unocal Alaska spokeswoman Roxanne Sinz said Unocal hadstarted workover operations on the Steelhead platform in Cook Inletthe weekend of Oct. 25-26. “We will be doing three workovers andone redrill for gas deliverability.” Unocal’s 39th plan of developmentfor the Trading Bay unit said Unocal was considering rig projects on theSteelhead and Grayling platforms to improve deliverability and recov-ery of gas reserves from the Grayling participating area and will “con-tinue to evaluate the possibility that oil reservoirs exist within theJurassic section within” the unit. But Sinz said, “At this time no Jurassicprojects are envisioned.”

Pioneer steals show Last winter’s successful explorer takes big block south of Prudhoe Bay

By KRISTEN NELSON Petroleum News Editor-in-Chief

allas-based Pioneer Natural Resources came toAlaska a year ago when it acquired 70 percentinterest in 10 Armstrong Resources’ BeaufortSea leases and took over as operator at the

Northwest Kuparuk prospect (now Oooguruk unit)between the Kuparuk River unit and Thetis Island. Itdrilled three exploration wells last winter and discov-ered oil.

Pioneer made another big move this month at thestate’s areawide North Slope and Beaufort Sea leasesales where it was high bidder on a huge block ofacreage south of Prudhoe and Kuparuk and on somevery pricey Beaufort Sea tracts north of Prudhoe.

In its first appearance at Alaska lease sales, Pioneerdominated both the North Slope and Beaufort Seasales held Oct. 29 in Anchorage, with its high bids

totaling almost $3.9 million, or two-thirds of the total$5.8 million in high bids at the sales.

It’s no wonder that Jim Hansen, the Division of Oil

Province plans direct offshoreinvestment via creation of Petro-Newfoundland

Asweeping change of government in Newfoundland, which sawthe Liberal party defeated after 14 years in power, could lead to thecreation of a new provincially owned corporation to invest in oil andnatural gas.

The Conservative party, led by former cable TV tycoon DannyWilliams, promised during the campaign to create Petro-Newfoundland, which it hopes will acquire the Canadian govern-ment’s indirectly held stake in the offshore Hibernia oilfield.

The federal government still owns 19 percent of Petro-Canada,which in turn owns 20 percent of Hibernia, which is authorized toproduce 220,000 barrels per day.

But Newfoundland has been increasingly unhappy over its shareof taxes and royalties from Hibernia since the field came on streamsix years ago.

What role Petro-Newfoundland would play in raising thosereturns or participating in other industry projects is not clear.

The Canadian Association of Petroleum Producers is anxious tohave an early meeting with Williams to explore those plans, and toraise its own concern about the long wait to get projects approvedin the region.

see NEWFOUNDLAND page 23

Apache piles up the cashAcquisitions, drillbit successes drive production, cash flow to record heights

PETROLEUM NEWS ig independent Apache Corp., which hasdone about $6.5 billion in acquisitions duringthe past decade, is now reaping the benefitsof this year’s $1.5 billion in deals with huge

production gains and mounting cash reserves thathave left industry observers wondering about thecompany’s next move.

Houston-based Apache surprised no one butperhaps Wall Street when it checked in Oct. 23with 2003 third-quarter net income, excluding anon-cash charge, of $276 million or $1.81 pershare, beating analysts’ earnings consensus of$1.77 per share by 4 cents. Apache’s net was up 90percent from $145 million or 95 cents per share in

the year-ago quarter.Since the first of the year, Apache’s overall pro-

duction has increased a third to 449,034 barrels perday of oil equivalent, largely on the strength ofShell acquisitions in the Gulf of Mexico and BPacquisitions in the gulf and North Sea.

Canada set totop 20,000 wellsIndustry expects to log its twobusiest drilling years on record

By GARY PARK Petroleum News Calgary Correspondent

wo industry organizations are counting onCanada logging its two busiest drilling years onrecord in 2003 and 2004, with the prospect ofbreaking the 20,000-well barrier this year.

The Petroleum Services Association of Canadahas raised the bar for 2003 to 20,400 wells, close to1,000 wells above the earlier forecast by the Canadian

Apache surprised no one but perhaps WallStreet when it checked in Oct. 23 with

2003 third-quarter net income, excluding anon-cash charge, of $276 million or $1.81

per share, beating analysts’ earningsconsensus of $1.77 per share by 4 cents.

B

see APACHE page 23

T

see WELLS page 23

see PIONEER page 21

Northeast British Columbia — Andarko Canada preci-sion drilling rig

AN

AD

AR

KO C

AN

AD

A

D

CO

URT

ESY

UN

OC

AL

Victors after the sale: from left, Chris Cheatwood andDavid Braddock of Pioneer Resources; Diane Kerr,Anadarko Petroleum; Ken Sheffield, Pioneer; and JohnBridges, Anadarko.

JUD

Y P

ATR

ICK

2 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003RIG REPORT

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point, drilling MPK-21 BPSky Top Brewster NE-12 15 (SCR/TD) Stacked, Endicott Island AvailableDreco 1000 UE 16 (SCR) Stacked, Deadhorse AvailableDreco D2000 UEBD 19 (SCR/TD) Alpine, drilling CD2-30 ConocoPhillipsOIME 2000 141 (SCR/TD) Prudhoe Bay, drilling W-400 BP

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES (SCR) Prudhoe Bay, Y-23B BPMid-Continent U36A 3-S Prudhoe Bay, 1D-110A AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay, summer maintenance BPDreco 1000 UE 7-ES (SCR/TD) Stacked, Kuparuk ConocoPhillipsDreco 1000 UE 9-ES (SCR/TD) Prudhoe Bay, V-114 BPOilwell 2000 Hercules 14-E (SCR) Stacked, Prudhoe Bay AnadarkoOilwell 2000 Hercules 16-E (SCR/TD) Stacked, Camp Lonely 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 ConocoPhillipsEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR/TD) Stacked, Deadhorse AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Stacked, Kuparuk ConocoPhillips

Nordic Calista ServicesSuperior 700 UE 1 (SCR/TD) Pad S-102 BPSuperior 700 UE 2 (SCR) Drill site 7 well 33 BPIdeco 900 3 (SCR/TD) Stacked, Kuparuk 1Q pad Available

North Slope - Offshore

Nabors Alaska DrillingOilwell 2000 33-E (SCR/TD) NS29 RWO BP

Cook Inlet Basin – Onshore

Marathon Oil Co.(Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Cannery Loop, #1 Marathon

Inlet Drilling Alaska/Cooper ConstructionKremco 750 CC-1 Stacked, Kenai Forest Oil

Nabors Alaska DrillingRigmasters 850 129 Stacked UnocalNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 KS1 ConocoPhillips

Aurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Demobilization, from Mobil Moquawkie 1 Aurora Gas

Evergreen Resources AlaskaWilson Super 38 96-19 Stacked in yard Evergreen Resources

Alaska CorporationEngersol Rand 1 Stacked in yard Evergreen Resources

Alaska Corporation

Cook Inlet Basin – Offshore

XTO Energy (Inlet Drilling Alaska labor contract)National 1320 A Idle IdleNational 110 C (TD) Moved to C22-23 for a workover XTO

Nabors Alaska DrillingIDECO 2100 E 429E (SCR) Osprey, Redoubt Shoal RU #7 Forest Oil

Unocal (Nabors Alaska Drilling labor contractor)Not Available

Kuukpik 5 Well B-3, Tyonek platform ConocoPhillips

Mackenzie Rig StatusMackenzie Delta-Onshore

Akita EqutakOilwell 500 62 Stacked, Tuktoyaktuk, NT EnCanaDreco 1250 UE 63 (SCR/TD) Stacked, Swimming Point, NT Chevron Canada

64 Stacked, Inuvik, NT Available

Central Mackenzie ValleyAkita/SAHTUOilwell 500 51 Stacked, Norman Wells Apache Canada

Nabors Canada62 Stacked, Norman Wells Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of October 29, 2003.

Active drilling companies only listed.

Rig start-ups expected in next 6 monthsNabors7ES Moving to Prudhoe Bay the end of November or first of December.

Pelican HillH35 Barged to the west side of Cook Inlet, on location getting read to

spud.

Akita Equtak40 Drilling for Northrock Resources near Tulita, NT.

December 2003 start-up.

51 Drilling for Apache Canada in the Colville lake area.December 2003 start-up.

55 Drilling for EnCana near Tulita, NT. January 2004 start-up.

62 Drilling for EnCana this winter in the Mackenzie Delta.January 2004 start-up.

63 Drilling for Chevron Canada this winter in the Mackenzie Delta.December 2003 start-up.

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

This rig report was prepared by Wadeen Hepworth

Baker Hughes North America rotary rig counts*

October 24 October 17 Year AgoUS 1,090 1,115 856Canada 389 391 235Gulf 101 102 106

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:

Courtesy Offshore DiversChristy loading platform in Cook Inlet

Petroleum News (ISSN 1544-3612) Week of November 2, 2003Vol. 8, No. 44

Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518(Please mail ALL correspondence to:

P.O. Box 231651, Anchorage, AK 99523-1651)Subscription prices in U.S. — $52.00 for 1 year, $96.00 for 2 years, $140.00 for 3 years. Canada / Mexico

— $165.95 for 1 year, $323.95 for 2 years, $465.95 for 3 years.Overseas (sent air mail) — $200.00 for 1 year, $380.00 for 2 years, $545.95 for 3 years.

“Periodicals postage paid at Anchorage, AK 99502-9986.”POSTMASTER: Send address changes to Petroleum News, P.O. Box 231651 • Anchorage, AK 99523-1651.

NOTICE: Prior to April 6, 2003, Petroleum News was formerly known as Petroleum News Alaska.

KAY CASHMAN, PUBLISHER & MANAGING EDITOR

Dan Wilcox CHIEF EXECUTIVE OFFICER

Kristen Nelson EDITOR-IN-CHIEF

Steve Sutherlin ASSOCIATE EDITOR

Gary Park CALGARY CORRESPONDENT

Larry Persily JUNEAU CORRESPONDENT

Wadeen Hepworth ASSISTANT TO THE PUBLISHER

Alan Bailey CONTRIBUTING WRITER

Allen Baker CONTRIBUTING WRITER

Paula Easley COLUMNIST

Patricia Jones CONTRIBUTING WRITER

Judy Patrick Photography CONTRACT PHOTOGRAPHER

Firestar Media Services DIRECTORY PROFILES

Mapmakers Alaska CARTOGRAPHY

Mary Craig CHIEF FINANCIAL OFFICER

Susan Crane ADVERTISING DIRECTOR

Forrest Crane CONTRACT PHOTOGRAPHER

Steven Merritt PRODUCTION DIRECTOR

Tom Kearney ADVERTISING DESIGN MANAGER

Heather Yates CLASSIFIEDS MANAGER

Randy Brutsche RESEARCH EDITOR

Tim Kikta CIRCULATION REPRESENTATIVE

Dee Cashman CIRCULATION REPRESENTATIVE

Petroleum News and its supplement, Petroleum Directory, are owned byPetroleum Newspapers of Alaska LLC. The newspaper is published weekly. Several

of the individuals listed above work for independent companies that contractservices to Petroleum Newspapers of Alaska LLC or are freelance writers.

ADDRESSP.O. Box 231651Anchorage, AK 99523-1651

EDITORIAL Anchorage907.522.9469

Juneau907.586.8026

EDITORIAL EMAILpublisher@petroleumnews.com

BOOKKEEPING& CIRCULATION 907.522.9469 Circulation Emailcirculation@petroleumnews.com

ADVERTISING 907.770.5592Advertising Emailscrane@petroleumnews.com

CLASSIFIEDS907.644.4444Classifieds Emailclassifieds@petroleumnews.com

FAX FOR ALL DEPARTMENTS907.522.9583

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003 3ON DEADLINE

EXPLORATION & PRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16FINANCE & ECONOMY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7GOVERNMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9LAND & LEASING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13NATURAL GAS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9NORTH OF 60 MINING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19PIPELINES & DOWNSTREAM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14

Issue Index

GULF OF MEXICOUnocal makes strike at St. Malo withover 450 feet of net oil pay

Operator Unocal and its partners have turned up an oil discovery at their St.Malo prospect that appears to rival some of the largest finds in deepwater Gulf ofMexico.

The discovery well, located on Walker Ridge Block 678, is said to haveencountered more than 450 feet of net oil pay over a gross hydrocarbon columnof 1,400 feet, “indicating that St. Malo is a major hydrocarbon accumulation,”Unocal partner Devon Energy said Oct. 29.

Reserve estimates were not provided by the St. Malo partners. Unocal said anappraisal well is planned next year to further evaluate and gauge the discovery’ssize.

“The potential volumes at St. Malo give us the confidence to call this discov-ery a significant milestone in our Gulf of Mexico deepwater program,” said MikeBell, vice president of Unocal’s Deepwater USA unit.

Similar to Cascade discoveryBoth the net pay and gross hydrocarbon column encountered by the St. Malo

discovery well are comparable in size to such big deepwater gulf finds as Tahiti,Atlantis, Mad Dog, Neptune and Cascade. Tahiti alone contains an estimated 400to 500 million barrels of equivalent reserves.

In fact, Michael Lacey, Devon’s senior vice president of exploration and pro-duction, said that “St. Malo is in the same area and a similar play concept to our2002 Cascade discovery” on Walker Ridge Block 206.

Cascade is thought to contain more than 300 million barrels of oil equivalent.Cascade also is said to be important because it penetrated the deep Eocene sec-tion, where it encountered a hydrocarbon column that one of the partners charac-

see UNOCAL page 6

WASHINGTON, D.C.Natural gas, crude oil reserves up

The federal government said Oct. 27 that proved reserves of natural gas and crudeoil in the United States “have increased for the fourth year in a row.”

That information came from an advance summary of the 2002 crude oil, natural gasand natural gas liquids reserves report from the U.S. Department of Energy’s EnergyInformation Administration.

The agency said natural gas proved reserves have increased in eight of the past nineyears.

The 2002 increase in U.S. natural gas reserves was 2 percent, with reserve additions118 percent of production. Gas production, however, declined 2 percent in 2002, withsharp declines in the Gulf of Mexico only partially offset by large production increas-es in the Rocky Mountains.

Large 2002 gas reserves additions in the Rocky Mountains and Texas “highlight ashift from conventional gas fields to unconventional gas fields,” the agency said.

Eleven of the top 20 natural gas fields of 2002 are in the Rocky Mountains. Significant reserves were added to the Powder River basin coalbed methane fields,

the Pinedale field in Wyoming and the Wattenberg field and coalbed methane fields inColorado. In Texas, significant reserves were added in the Newark East field, thenation’s 10th largest natural gas field.

Coalbed methane reserves increased 5 percent from 2001 and accounted for 10 per-cent of U.S. dry gas proved reserves. Coalbed methane production increased 3 percentfrom 2001 and accounted for 8 percent of U.S. dry gas production.

The agency said the majority of natural gas total discoveries in 2002 were fromextensions of existing conventional and unconventional gas fields.

Crude reserves up 1 percent U.S. crude oil proved reserves increased by 1 percent in 2002, the agency said, and

reserves additions were 112 percent of production, with 97 percent of all new field dis-coveries of crude oil reported in 2002 in federal waters in the Gulf of Mexico. Themajority of 2002 crude oil discoveries were extensions of existing fields, particularlyin Texas, California and federal Gulf of Mexico waters.

An editing error in the Oct. 26 issue of Petroleum News garbled the last sen-tence of an item on page 16 on Canadian gas export revenues.

The sentence should have read: The heaviest nine-month declines occurred in the Rocky Mountain region at

97.5 percent to 11.1 bcf and 20.6 percent to 293.5 bcf in the Pacific Northwest.

CORRECTION

4 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003ON DEADLINE

BRISTOL BAYThree companies interested in BristolBay oil and gas exploration licenses

Three companies are interested in exploring for oil and gas in theBristol Bay region, where the state of Alaska is offering 3 millionacres of land for exploration licensing.

The Alaska Department of Natural Resources, Division of Oiland Gas, received one exploration license proposal Sept. 23. It thensolicited competing proposals, and Jim Hansen, the division’s leas-ing manager, told Petroleum News Oct. 28 that the division received

two letters of intent to submitcompeting proposals by theOct. 27 deadline. The pro-posals are due Nov. 25.

The division began theprocess in July when itsolicited exploration license proposals for anarea of approximately 3 million acres of state-owned and state-selected or top filed lands in theBristol Bay region, north of the village ofNaknek and east of Dillingham. Proposals mustbe for between 10,000 and 500,000 acres, andmust include specific items: lands proposed forlicensing, specific work commitment expressed

in dollars, terms of the license and amount and form of security to be posted. Companies had until Aug. 25 to notify the state that they intended to submit pro-

posals; those proposals were due Sept. 23. The division received two expressions ofinterest by the August deadline, and one proposal by the September deadline. Becausethe process is competitive, the division is not releasing the names of the companieswhich submitted letters of intent, or the name of the company which submitted a pro-posal.

Comments from the public and agencies on whether a license in this area is in thestate’s best interest are due Nov. 25.

The state is also proposing an areawide Alaska Peninsula oil and gas lease sale. Thecompetitive lease sale area is south of the area proposed for exploration licensing, andincludes offshore state land and onshore acres on the Alaska Peninsula from south ofNaknek to north of Cold Bay. Comments on the proposed areawide sale are due Oct.31. A preliminary best interest finding is scheduled for August 2004 and a final bestinterest finding for July 2005. The proposed sale would be in October 2005.

—KRISTEN NELSON, Petroleum News editor-in-chief

Jim Hansen, leas-ing manager,Alaska Division ofOil & Gas

● A N C H O R A G E , A L A S K A

Alaska gas authoritygets federal fundingLegislators OK $200,000; work to include in-state benefits study

By LARRY PERSILYPetroleum News Juneau Correspondent

egislators have approved a governor’soffice request to use $200,000 in one-time federal funding for the AlaskaNatural Gas Development Authority

to hire consultants as it tries to answerwhether the state should build and own anestimated $12 billion liquefied natural gasproject.

The Legislative Budget and AuditCommittee approved the spending requestOct. 29, along with six other items totalingalmost $7 million of federal funding underthe Jobs and Growth Tax ReliefReconciliation Act of 2003.

“These are monies that Congress intend-ed to be fiscal relieffor the states,”explained CherylFrasca, director of thegovernor’s budgetoffice. “They areunrestricted. We havewide latitude in termsof the public purposethey are used for.”

Alaska received$50 million in twoinstallments under thefederal aid-to-statesprogram, with about $18 million still undes-ignated, Frasca said. The Legislative Budgetand Audit Committee, comprised of fivemembers each from the House and Senate,has authority to spend such unanticipatedfederal money when the full Legislature isnot in session.

Natural Resources Department will help

The committee approved $200,000 forthe state gas authority without objection,plus an additional $50,000 from the samefederal pot for the Alaska Department ofNatural Resources so that it could assist theauthority in its work.

The authority is operating under a$150,000 budget this fiscal year and hasbeen telling legislators and the governor’soffice the past three months that it needsmore money if it is to answer all of the ques-tions assigned to it by voters last year.

Senate President Gene Therriault, R-North Pole and vice chairman of the legisla-tive committee, encouraged his colleaguesto approve the $200,000 request.

In-state benefits analysis on work listThe authority intends to use some of the

money to contract for an analysis of the in-state benefits of an LNG project, andTherriault said he believes the informationwould be especially useful to legislators asthey evaluate the potential state-owned proj-ect or if they are later asked to consider tax

breaks for the major North Slope producersif they decide to build their own pipeline.

Separate from the state’s possible LNGproject, the producers are looking at build-ing a pipeline from the North Slope throughAlaska and into Canada to connect with theNorth America natural gas distribution grid.The future of that project depends in greatpart on the federal energy bill under debatein Congress, which could include significantfederal tax incentives to encourage privateconstruction of the $20 billion line.

Alaskans approved creation of the stategas authority by a better than 2-to-1 marginin the November 2002 general election. Theauthority is to present to the Legislature bynext summer a project development plan,including construction cost estimates, staterevenue estimates, cost of buying natural gasfrom the North Slope producers and a mar-keting plan to sell the gas as LNG, and aplan for delivering gas along the pipelineroute and also a spur line to feedSouthcentral Alaska’s energy needs.

$200,000 is enough to startAlthough the authority had asked for up

to $2.5 million for consultant studies, the$200,000 appropriation will let it start workon the most important business questions,said Harold Heinze, the authority’s chiefexecutive officer and only full-time staffer.

Those include researching whether theauthority would be exempt from federal cor-porate income taxes on any profit it mightmake, whether the authority could issue tax-exempt bonds to finance the project, howmuch cash the state might need to put up andhow much it could borrow, and whether theauthority would be required under federallaw to use U.S.-built and U.S.-crewed LNGtankers to ship gas to the California market.

The seven-member board of directors isscheduled to meet Nov. 17 in Anchorage,and Heinze said he expects to present rec-ommendations for which contracts to fundwith the money and a plan to solicit propos-als and award the contracts as quickly aspossible.

Authority will need more money next year

Much of the other work on the authori-ty’s task list will have to wait for additionalfunding when lawmakers reconvene inJanuary, he said. “Come January, from theauthority’s point of view, we’re still lookingat a big number.”

The $50,000 to the Department ofNatural Resources will allow the agency tohelp the gas authority answer “the where,when, why and how of getting the gas,”Heinze said. The state would need to reach adeal with North Slope producers to buyenough gas to supply its LNG project. Theavailability and cost of that gas is a key issuein the authority’s business plan. ●

L

Harold Heinze, CEO,Alaska Natural GasDevelopmentAuthority

The division began theprocess in July when it

solicited exploration licenseproposals for an area of

approximately 3 million acresof state-owned and state-

selected or top filed lands inthe Bristol Bay region, northof the village of Naknek and

east of Dillingham.

FOR

RES

T C

RA

NE

By LARRY PERSILYPetroleum News Juneau Correspondent

t’s been almost three months since muchof the nation saw just how dark life canbe without electricity, and the presidentand the nation’s utilities chose

Halloween week to start pushing hard oncongressional Republicans to stop fightingamong themselves and pass a comprehen-sive national energypolicy bill.

The Augustblackout that hit theEast Coast andMidwest was sup-posed to be the pub-lic-pressure catalystfor quick congres-sional action on anenergy bill. But it’sbeen regional politics— especially taxbreaks for corn-based ethanol fuel —that have stalled thebill.

Caught in theHouse and Senatecrossfire and appar-ently dropped fromthe bill as negotiatorsgive up demandsfrom each side toreach a consensus isone Alaska’s mostvisible issues in the energy bill — federal taxcredits to protect North Slope producersfrom low prices if they build a $20 billionAlaska natural gas pipeline. The WhiteHouse and several House GOP leadersopposed the price-support provision, whichalso has been called the commodity risk pro-vision.

Bill includes other gas line tax incentives

While acknowledging the price-supportprovision may be lost this year, Alaska Sen.Lisa Murkowski pointed to other gas line taxincentives likely to stay in the final bill: taxcredits for the gas treatment plant at PrudhoeBay, accelerated depreciation for thepipeline project, and a federal loan guaran-tee of up to 80 percent of $18 billion. Themeasure also will include provisions to

speed up the permitting and regulatoryreview process for the project, the freshmanRepublican said.

“Whether it’s four provisions that weneed to make the gas line a reality or 14 pro-visions, we need to figure out what we needto make this happen,” Murkowski said.

ConocoPhillips and BP Exploration(Alaska) have said they need the price-sup-port provision before deciding to go aheadwith the project.

If the provision is not forthcoming in theenergy bill, Murkowski said, everyoneinvolved needs to get together, including thestate, and figure out what final piece orpieces may be needed. “I don’t want anymore excuses for us not to go forward.”

Alaska’s other high-profile wish for theenergy bill — congressional approval toopen the Arctic National Wildlife Refuge tooil and gas drilling — also looks like it willbe left on the negotiating room floor as sup-porters do not have enough votes to stop athreatened Senate filibuster by opponents todrilling in ANWR.

Energy tax breaks the biggest battleThe bill’s big battles all along have been

tax credits. House and Senate Republicannegotiators have been meeting in private foralmost two months to carve up billions ofdollars in energy industry tax breaks. Self-imposed deadlines came and went, withwatchers now hoping Congress can reach adeal before its members adjourn to carve uptheir own Thanksgiving turkeys.

The president sent the vice president toCapitol Hill on Oct. 29 to push Republicansto settle their ethanol-tax-break feud andadopt a compromise energy bill. That cametwo days after 20 executives from thebiggest U.S. utilities told an administrationofficial the White House needed to step in

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003 5ON DEADLINE

NORTH AMERICANorth American rig count down 27

The North American rotary rig count fell for a second week in a row, droppingby 27 to 1,479 during the week ending Oct. 24, according to rig monitor BakerHughes. The count declined by 21 rigs during the previous week.

Canada’s rig count in the recent week declined by two to 389 rigs, comparedto 235 for the same weekly period last year.

The United States accounted for most of the loss in the recent week, falling bya net 25 to 1,090 rigs, but was still well ahead of 856 rigs working in the countrya year earlier. The land rig count alone dropped by 25, while offshore Gulf ofMexico lost one rig. Inland waters of the gulf gained one rig.

Of all the rigs at work in the United States, 930 were drilling for natural gasand 158 for oil, while two were being used for miscellaneous purposes. Of thetotal, 744 were drilling vertical wells, 253 directional wells and 93 horizontalwells.

Among the leading producing state in the United States, Texas’ rig count tookthe single largest hit in the recent week, falling by 13 to 462 rigs. New Mexicowas down six to 63 rigs. And Wyoming fell by two to 68 rigs. California increasedby one rig to 26. Louisiana remained unchanged at 158 rigs, as well as Alaska at10 rigs.

● W A S H I N G T O N , D . C .

Pressure on topass energy billAlaska’s gas pipeline price support and language to openANWR likely out of bill, heavy oil credit still possible

I

see PRESSURE page 21

While acknowledg-ing the price-sup-port provision maybe lost this year,Alaska Sen. LisaMurkowski pointedto other gas line taxincentives likely tostay in the final bill,iincluding tax cred-its for the gas treat-ment plant atPrudhoe Bay, accel-erated depreciationfor the pipelineproject, and provi-sions to speed up itspermitting and reg-ulatory review.

Crude futures fall on milder weather Crude oil futures fell Oct. 27 in New York to settle at $29.92 a barrel — the

same level as Oct. 22 — as traders and analysts found little reason to supportprices.

Analysts cited mild weather in the Northeast, sufficient current levels of sup-ply and indications of growing crude oilsupply as reasons for the price weak-ness.

“It’s weather-related, definitely,”said Ed Silliere, a trader with EnergyMerchant in New York. “And, in general, there’s a bearish technical picture.”

Light, sweet December crude oil futures settled down 24 cents at $29.92 a bar-rel after touching a low of $29.70.

On London’s International Petroleum Exchange, December Brent blend crudeoil futures settled down 19 cents at $28.39 a barrel after touching a low of $28.20.

The market drifted cautiously lower after early reports of refinery problems inTexas City, Texas, later turned out to not be as severe as feared, Silliere said.

Funds’ selling also has pressured the market lower, he added. Analysts andtraders warned that Oct. 24’s commitments of traders report indicated funds werevulnerable to selling pressure.

The Commodity Futures Trading Commission said Oct. 24 that as of Oct. 21,the large, noncommercial investors were net long 21,027 crude contracts, up from19,442 the previous week on the New York Mercantile Exchange.

Braced for OPEC cutWith the effects of a planned cut in output by the Organization of Petroleum

Exporting Countries set to begin Nov. 1, analysts and traders are likely to remaincautious through the expiration Oct. 31 of November heating oil and gasolinecontracts, said Mike Fitzpatrick, an analyst with Fimat USA Inc.

—THE ASSOCIATED PRESS

NEW YORK

“It’s weather-related, definitely,” —Ed Silliere, Energy Merchant

6 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003ON DEADLINE● O K L A H O M A C I T Y - H O U S T O N

Kerr-McGee, Noble post third quarter profitsIndependents climb out ofhole after losing financialperformances a year ago

PETROLEUM NEWSxploration and production independ-ents Kerr-McGee and Noble Energy,which reported losing financial per-formances a year ago, turned it

around in the 2003 third-quarter, the com-panies said Oct. 29.

Oklahoma-based Kerr-McGee postednet income of $28.8 million or 29 cents pershare in the third quarter, compared to a lossfrom continuing operations of $86.8 millionor 86 cents per share for the year-ago quar-ter. The company reported cash flow fromoperations totaling $1.2 billion for the firstthree quarters of 2003, up 14 percent fromlast year. It achieved results even with thesale of non-core assets representing about15 percent of last year’s oil and gas produc-tion volumes.

“We will continue to focus on cost con-tainment in all of our operations as we con-centrate on value-adding exploration, acqui-sition and divestiture opportunities,” saidLuke Corbett, Kerr-McGee’s chief execu-tive officer.

Sale of non-core assets has impactKerr-McGee’s daily oil production for

the 2003 third quarter averaged 141,000barrels, versus 192,900 barrels for the prior-year period. The decrease was attributed tothe sale of nearly $1 billion of non-coreproducing properties.

The average sales price for oil, includingeffects of the company’s hedging program,was $25.76 per barrel, up from $23.38 perbarrel for the same third quarter period lastyear, the company said.

Daily volumes of natural gas averaged699 million cubic feet in the 2003 thirdquarter, compared with 789 million cubicfeet for the same 2002 quarter.

The average sales price for the 2003third quarter, including the effects of thecompany’s hedging program, was $4.20 perthousand cubic feet, a 51 percent increasefrom the 2002 third quarter.

Sales from continuing operations totaled$1 billion for the 2003 third quarter, com-pared with $965 million for the 2002 thirdquarter. Capital expenditures were $267.6million versus $293.7 million for the sameperiod last year.

Noble’s cash flow up 33%Houston-based Noble Energy reported

2003 third-quarter net income of $35.1 mil-

lion, or 62 cents per share, compared to anet loss of $1.2 million, or 2 cents per share,for the same period last year. Discretionarycash flow increased 33 percent to $153.2million compared to $115.2 million for theyear-ago period.

Excluding the effect of the after-tax gainon disposition of assets and the write downof assets held for sale, Noble’s net incomewould have been $40.6 million, or 72 centsper share, the company said Oct. 29.

Lower exploration costs a factorNoble attributed the increase in net

income and discretionary cash flow mainlyto higher commodity prices and lowerexploration expense during the third quar-ter.

Increased production also contributed tostrong year-on-year financial and operatingimprovements, the company said.

“The continuing strong commodity priceenvironment has significantly enhanced ourfinancial results,” said Charles Davidson,Noble’s chief executive officer.

The company’s realized natural gasprices for the third quarter 2003 were $4.10per thousand cubic feet, 50 percent abovelast year’s $2.73. Realized oil prices were$27.49 per barrel, an increase of 5 percentcompared to $26.19 per barrel for the thirdquarter 2002.

Reported production — net of adjust-ments for discontinued operations — was90,236 barrels of oil equivalent per day, anincrease of 4 percent compared to 86,807barrels per day of equivalent for the sameperiod last year.

Increase comes from China, EcuadorThe increase in volumes was attributed

to the start-up of production in China and asubstantial increase in production volumesin Ecuador, partially offset by lower domes-tic and North Sea volumes.

As a result of property sales, overall pro-duction declined by about 950 barrels perday of equivalent compared to the 2003 sec-ond quarter, Noble said. ●

Noble Energy’s increase involumes was attributed to the

start-up of production in Chinaand a substantial increase in

production volumes in Ecuador,partially offset by lower domestic

and North Sea volumes. E

terized as a “potentially significant” dis-covery.

The St. Malo well spud on July 6 andwas drilled to a total depth of 29,066 feetin 100 days at an estimated total cost of$62 million, Unocal said. The well islocated in 6,900 feet of water about 250miles southwest of New Orleans. It wasdrilled from the Discoverer Spirit drill-ship.

Upon completion of the St. Malo well,the Discoverer Spirit will be released tomove on to the ExxonMobil Hawkesappraisal well in Mississippi Canyon508, Unocal said.

“St. Malo represents a valuable addi-tion to our portfolio of discoveries, andwe have excellent leverage in this emerg-ing play with a robust portfolio of proj-ects and leads in the Keathley Canyon,Green Canyon and Walker Ridge areas,”Unocal’s Bell said.

Unocal holds a 28.75 percent interestin St. Malo. Petrobras has a 25 percentstake, followed by Devon with a 22.5percent interest, ChevronTexaco with a12.5 percent interest, EnCana with a 6.25percent interest, ExxonMobil with a 3.75percent interest, and Eni Petroleum witha 1.25 stake.

—PETROLEUM NEWS

continued from page 3

UNOCAL

PETROLEUM NEWS 7WEEK OF NOVEMBER 2, 2003

finance&economywww.PetroleumNews.com

HOUSTON, TEXAS● B E R M U D A

Oil, gas adviser to the worldToo much reliance on oil revenues can lead to trouble, says Pedro van Meurs

By LARRY PERSILYPetroleum News Juneau Correspondent

laska has the same problems as many otheroil- and gas-rich nations around the world,says international consultant Pedro vanMeurs. Other than the fact that Alaska is a

state, not a country, it has the same overdepen-dence on resource revenues, the same competitivequest for the industry’slimited investment dol-lars, and the same trou-bling reluctance of its cit-izens to pay for govern-ment services.

“Alaska is the onlystate that has world-classproblems that requireinternational expertise,”said van Meurs, whoanswered the phone morethan seven years ago when the state Department ofRevenue called in search of advice on Alaska’scompetitive position in world markets for liquefiednatural gas.

The state has called on van Meurs several timessince that first consulting contract in 1996.

“Alaska is a very informed democracy … avery participatory democracy,” he said, adding thatthe state’s near-total reliance on oil and gas rev-enues, mixed in with its participatory democracyof vocal citizens, can add a formidable element tothe task of finding long-term answers to the state’sfiscal future.

Budget problems worry industry“The oil industry is worried in every nation

where government depends excessively on oil forbalancing its budget,” van Meurs said. That’s truein Venezuela, Kuwait, Saudi Arabia and Alaska.Industry’s fears of a government relying too muchon one revenue source “colors their investmentdecisions.”

Alaska is benefiting fromtoday’s high oil prices, butvan Meurs said he does notimagine they will last, andsaid $20 to $25 per barrel is areasonable price expectationfor the next decade. “It wouldbe very wise if Alaska bal-anced its budget in that pricerange.” A stable, diversifiedbudget is more attractive toinvestors, he said.

And it’s not only Alaska that has budget prob-lems. Kuwait and Saudi Arabia run a deficit evenat high oil prices, van Meurs said. “Oil is notalways a blessing. A dependency philosophy isbeing created among the people.

“People think oil has to pay for everything.”

Citizens lose connectionToo much reliance on oil revenues means citi-

zens can lose the connection between governmentservices and their own contributions toward thoseservices, he said, adding that he has seen it inVenezuela, Kuwait, Mexico and Alaska. “In allthese there is a sense in the public that they don’thave to pay taxes, they don’t have to contributebecause there is oil.

“Every time you come to Alaska you detect the

This is the last in athree-part series onPedro van Meurs,who has advised thestate of Alaska onoil and gas tax poli-cy since 1996.

A

● H O U S T O N , T E X A S

WesternGeco troubles parentsSeismic joint venture between Baker, Schlumberger drags both into red

PETROLEUM NEWS he world’s largest seismic company, a jointventure between oilfield service titans BakerHughes and Schlumberger, continues to strug-gle with minority partner Baker Hughes

apparently looking for a way out of its30 percent share of WesternGeco.

Formed in June 2000 betweenSchlumberger’s Geco-Prakla andBaker Hughes’ Western Geophysical,WesternGeco was largely responsiblefor dragging both service companiesinto the financial red during the 2003third quarter.

Schlumberger took an after-taxcharge of $205 million and BakerHughes an after-tax charge of $151.2million on WesternGeco, the compa-nies reported during the week of Oct.24. They amounted to non-cashcharges or write downs on the value of the jointventure company, reflecting the sorry state of aseismic industry with excessive capacity.

“We certainly have been concerned about ero-sion of the (seismic) market,” Michael Wiley,Baker Hughes’ chief executive officer, said in aconference call with analysts. “The competitivelandscape is such that there’s really a lot of pres-sure on pricing.”

Wiley, a former ARCO Alaska president, saidthat while Baker Hughes has no immediate plans

to divest its share in WesternGeco, the companywould be looking to “exit” the joint venture in thefuture, presumably when market conditionsimprove.

Of the $151.2 million in Baker Hughes impair-ments taken on WesternGeco, $105.9million was for the multi-client seis-mic library and $45.3 million for theoverall carrying value of the joint ven-ture. The company incurred another$39.3 million charge for discontinuedoperations on the sale of BirdMachine, Baker Hughes’ non-oilfieldoperation, to Austria’s Andritz.

Including charges, Baker Hughesweighed in with a 2003 third-quarternet loss of $98.8 million or 29 cents ashare, compared to net income of$81.6 million or 24 cents in the priorquarter and $64.7 million or 19 centsin the year-ago third quarter.

Earnings estimates for fourth quarter down On sluggish Gulf of Mexico activity and soft

U.S. service pricing, investment banks RBCCapital Markets, Lehman Brothers and DeutscheBank all lowered Baker Hughes earnings estimatesfor the 2003 fourth quarter to 28 cents per sharefrom a previous 29 to 32 cents a share.

Lehman reported to its investors that while

“We certainly havebeen concerned

about erosion of the(seismic) market.The competitive

landscape is suchthat there’s really alot of pressure on

pricing.” —Michael Wiley,

Baker Hughes

T

PEDRO VAN MEURS

JUD

Y P

ATR

ICK

see ADVISER page 8

see PARENTS page 8

Offshore driller Transoceanlooking to spin off barge unitby year-end

Deepwater driller Transocean said it hopes before year-end tolaunch an initial public offering of its TODCO Gulf of Mexicoshallow water and inland barge subsidiary.

Lifted by increasing day rates and strong commodity prices,“we’re hopeful the time may be right for the IPO going into thefourth quarter,” Robert Long, Transocean’s chief executive offi-cer, said in an Oct. 28 conference call with analysts.

$8 million in costs due to delaysTransocean, during the 2003 third quarter, said it incurred $8

million in costs related to the planned IPO because of delays.Excluding the impact of the IPO costs, net income for the quar-ter was $19.0 million or 6 cents per share. That compared to netincome of $255.2 million or 79 cents per share for last year’sthird quarter.

Excluding the impact of a $176.2 million tax benefit and anon-cash loss due to the impairment of assets, Transocean’s netincome for the 2003 third quarter was $105.6 million or 33 centsper share, the company said.

Fleet utilization was 71%Overall fleet utilization was 71 percent during the 2003 third

quarter, compared to 68 percent in the previous quarter and 79percent for the same period last year. Quarter-over-quarter resultswere attributed primarily to improved utilization in the compa-ny’s fleet of deepwater rigs.

Transocean noted that revenues from its TODCO barge unitwere $58.5 million for the third quarter versus $55.4 million dur-ing the previous quarter and $54.0 million for the year-ago peri-od. The 6 percent revenue increase from the 2003 second quarterwas attributed to improvements in both average fleet utilizationand day rates among the segment’s jack-up rigs, the companysaid.

—PETROLEUM NEWS

Bad news: North Slope spendingdown. Good news: Third rotarydrill rig going to Prudhoe Bay

Although the three major North Slope producers are workingtoward reducing operating costs, they still spend far in excess of$1.5 billion a year on goods and services purchased from Alaskabusinesses.

ConocoPhillips, which operates the Kuparuk River unit, spentmore than $600 million with Alaska businesses in 2002. BP,which operates the older and much larger Prudhoe Bay unit,reported more than $900 million spent on goods and servicespurchased from in-state vendors in 2002.

ExxonMobil does not break down its operating and capitalspending between in-state and out-of-state businesses. (Althoughnot an operator of a producing field, ExxonMobil contributes itsshare of unit costs.)

ConocoPhillips and BP both report that about 85 percent oftheir third-party spending for Alaska operations goes to in-statebusinesses. The numbers include operating, maintenance andcapital spending.

Spending on downward trendBoth companies reported a drop in total contractor and sup-

plier spending from 2001 to 2002, with the decline expected tocontinue when 2003 spending is totaled after the end of the year.

BP’s spending on goods and services in 2000 totaled $720million, with 83 percent of the money paid to Alaska businesses,according to the company’s annual Alaska Hire and Purchasingreport issued recently. Total spending jumped more than 60 per-cent to almost $1.2 billion in 2001 as BP completed constructionon its Northstar oil field, adding an average of 60,000 barrels perday to North Slope production.

The company reported its spending with in-state businesses

NORTH SLOPE

see NEWS page 8

Baker Hughes “has done a good jobimproving profitability and loweringdebt,” the company’s revenue and earn-ings growth would “lag” its competitors.

In addition to its $205 million impair-ment on WesternGeco, Schlumbergerrecorded an $86 million charge related tothe early retirement of European debt.The company reported a 2003 third-quar-ter net loss of $55.3 million or 9 cents pershare, compared to a profit of $172.8 mil-lion or 30 cents per share for the sameperiod last year.

Andrew Gould, Schlumberger’s chiefexecutive officer, said in a prepared state-ment that the overall oilfield servicesmarket in North America “is still in a stateof overcapacity, and pricing pressure islikely to remain despite some regionalbright spots.”

In forming WesternGeco three yearsago, Schlumberger gave then financiallytroubled Baker Hughes $500 million in

cash for a 70 percent share of the jointventure. Baker Hughes used the cash topay down debt. The deal also freed upabout $100 million a year in working cap-ital for Baker Hughes and allowed thecompany to focus on its remaining busi-ness units.

Western Geophysical, Baker Hughes’contribution to the joint venture, had beena thorn in the side of Baker Hughes sincethe company had acquired parent WesternAtlas in a $4.5 billion stock swap twoyears earlier. In the fourth quarter of1999, Baker Hughes took a $130 millionrestructuring charge on WesternGeophysical, which at the time had fallenvictim to a price downturn and resultingslowdown in seismic activity. ●

same unwillingness on the part of citizensto contribute to the services governmentis providing,” van Meurs said.

Kuwait and Venezuela face similarproblems. Kuwait’s government wouldnot survive if it even thought out loudabout imposing a personal income tax,said van Meurs, who has done a lot ofwork for the country. And Venezuela hasimploded because its citizens can’t dealwith paying for services.

Fiscal stability is the key to attractinginvestment dollars and to assuring oil andgas companies that your country — orstate — is a good place to do business, hesaid. That’s why Alaska’s Stranded GasDevelopment Act makes so much sense.

Stranded Gas Act a good moveThe act, adopted by the Legislature in

1998 and amended this past session,allows the administration to negotiate acontract with companies for payments inlieu of state and local taxes on a proposednatural gas pipeline from Alaska’s NorthSlope. The fiscal certainty of a scheduleof contractual payments would be a bene-fit to the state and to the companies thatwant to build the project, he said.

The state anticipates receiving a proj-ect application from the North Slope pro-ducers sometime this fall, and has signedon van Meurs to advise Alaska on theeventual negotiations. Although hedeclined to discuss any specifics of hiswork for the state, he was quick to offerhis opinion that Alaska needs to act quick-ly to grab a piece of the North Americagas market.

“The window on selling Alaska gas tothe Lower 48 is coming down,” vanMeurs said.

Alaska Gov. Frank Murkowski and thestate’s congressional delegation are push-ing hard to win congressional support forfederal tax incentives to encourage con-struction of a $20 billion gas pipelinefrom the North Slope to the North

America distribution grid in Alberta. It’s asmart move, said van Meurs.

Answer needed to price riskThe North America gas market is fick-

le. “Rather quickly you get upturns andrather quickly you will get downturns.”Although he sees long-term gas priceshanging around $4 to $4.50 per thousandcubic feet — sufficient to cover expectedcosts of the Alaska project — the risk ofinevitable low prices worries the produc-ers, he said.

“This is a market with an almost dailyattitude.” And that is why the producersand the state are working for federal taxsupports. “The governor has madeabsolutely the right decision to push thisvery hard at this time,” van Meurs said.

And while it may seem as if Alaska hasthe option of turning its gas into LNG andshipping it overseas, so do many othersuppliers around the Pacific Rim and inthe Middle East, he said. And all ofAlaska’s competitors will benefit fromfalling LNG liquefaction plant construc-tion costs and larger and more cost effi-cient tankers.

As Alaska LNG proponents see theircost estimates drop, so too do the com-petitors, none of which need an 800-milepipeline through the arctic to bring naturalgas to tidewater.

Highway line Alaska’s best betThe state’s best bet at the moment to

get its natural gas to market is to look toNorth America, van Meurs said. It’s sim-ply a matter of price stability, he said.“The problem with the North Americamarket is that the price movement is soextreme that investors can’t deal with it.”In the past three years, gas has run up toalmost $10 an mcf and back down to $2 insome U.S. markets.

The United States needs to find a wayto overcome market instability, he said,adding that federal tax credits to helpNorth Slope producers is one option.“What is happening in Washington is emi-nently logical.” ●

8 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003FINANCE & ECONOMYcontinued from page 7

ADVISER

continued from page 7

PARENTSIn forming WesternGeco threeyears ago, Schlumberger gavethen financially troubled Baker

Hughes $500 million in cash for a70 percent share of the joint

venture.

CANADAHusky ready to open acquisition wallet

Watch out for Husky Energy, once a scrawny after-thought among Canada’sfive integrated oil companies and now ready to spend up to C$2 billion bulk-ing its portfolio.

Chief Executive Officer John Lau told a conference call Oct. 23 that hiscompany “already has the finances in place to meet any commitment up to (thelevel of C$1 billion-$2 billion) without resorting to the bank.”

Following its US$588 million acquisition of Marathon Oil’s upstream inter-ests in Western Canada — and subsequent spin off of some of those propertiesto EOG Resources for $320 million — Husky is now “looking at ways toincrease our production ... and we are looking at opportunities,” said Lau, with-out offering further details.

The Marathon deal pumped an additional 20,000 barrels of oil equivalentper day into Husky’s holdings, including what Lau described as a significantboost to gas output in northeastern British Columbia and Alberta.

Despite slight production declines in the third quarter, Husky reported a 40percent jump in profits over a year earlier to C$243 million. Its shares havemade solid gains over the past 52 weeks, climbing to C$23.30 from C$15.43.

—GARY PARK, Petroleum News Calgary correspondent

increased to 86 percent of BP’s goods andservices total in 2001.

BP’s total third-party spending slippedto $1.08 billion in 2002, with the in-statepurchases holding at around 86 percent,or more than $900 million.

“In 2002, BP had no significant newdevelopment projects under way,” thecompany’s report stated. Since complet-ing Northstar, “the company has concen-trated on smaller-scale projects aimed atadding new reserves to existing fields.”

The company’s 2003 spending likelywill total just under $1 billion as BP con-tinues to look for cost savings, saidspokesman Daren Beaudo.

About 80 percent of BP’s spending ison services, including drilling, catering,security, engineering and construction.The rest of the money goes toward sup-plies and equipment.

BP to add third drill rig at Prudhoe Bay

Beaudo said the company plans to puta third conventional rotary rig into serv-ice at Prudhoe Bay in November. Thereare currently two conventional rigs atPrudhoe doing in-field drilling as BP con-tinues to look toward adding productionfrom existing fields.

The new rig’s work could also includein-field drilling, Beaudo said.

The addition of a third rig will bringPrudhoe Bay’s conventional rig countback up to 2001’s three to four rig level.

(In 2002 and 2003 to date only two con-ventional drilling rigs have been workingat Prudhoe Bay.)

ConocoPhillips spent $756 million ongoods and services with Alaska compa-nies in 2001, about 85 percent of its totalNorth Slope vendor spending, said com-pany spokeswoman Dawn Patience. Thecompany in 2001 was completing work tobring its new field at Alpine to full pro-duction. Alpine production averaged40,000 barrels per day in its first partialyear, and then climbed to almost 100,000barrels a day by 2002.

ConocoPhillips’ in-state purchasesdropped to $618 million in 2002 and like-ly will total somewhat more than $500million in 2003, Patience said.

Included in ConocoPhillips’ NorthSlope spending the past several years hasbeen its exploratory drilling in theNational Petroleum Reserve-Alaska,where the company has been working itsleases since 2000.

Conoco’s 2004 spending decisions pending

The company will announce its 2004capital budget in late December, after theboard of directors takes action on spend-ing requests, she said.

ConocoPhillips’ spending totals do notinclude the company’s $1 billion invest-ment in five double-hull oil tankers for itsAlaska trade, the first of which was deliv-ered in 2001 and the last scheduled tostart work in late 2005.

—LARRY PERSILY, Petroleum NewsJuneau correspondent

continued from page 7

NEWS

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003 9NATURAL GAS/GOVERNMENT

● S O U T H W E S T A L A S K A

DGGS geologistadvocates drillingHolitna basin

By PATRICIA JONESPetroleum News Contributing Writer

former Alaska state geologist whohas studied carbonaceous mud-stones, shales and coals taken fromfault outcrops near the Holitna basin

advocates drilling to determine gas andhydrocarbon potential of the remoteregion. (See related story in this week’sNorth of 60 Mining section.)

Plans by Holitna Energy to punch oneor two drill holes in the southwest Alaskabasin this winter are “right on track,” saidDave LePain, who is in the process of pro-ducing a third report on the Holitna basinfor the Alaska Division of Geological &Geophysical Surveys.

Existing state-dis-tributed aeromagnet-ic and gravity data,combined withanalysis of carbona-ceous samples gath-ered in recent yearssuggests the basincontains potentialtargets for gas accu-mulations, both con-ventional andcoalbed methane.

“There are a couple bull’s eyes that cor-respond with gravity lows,” LePain toldPetroleum News in an Oct. 23 phone inter-view from Wisconsin. “Until you provethe stratigraphy … it’s pretty speculative.”

LePain left state employment this sum-mer and has yet to complete a final geo-chemistry analysis report on 50 to 60 sam-ples taken in the Holitna basin in the sum-mer of 2002. An initial review of the sam-ples indicates high levels of total organiccarbons, LePain said.

Follow-up samples gatheredThe samples were gathered in an effort

to follow up on two of about a dozen sam-ples gathered during the 2000 field season,which surprisingly showed potential forhydrocarbon accumulations.

Sampling carbonaceous rocks from theHolitna basin, which is a teardrop shapedformation that starts south of Sleetmute onthe Kuskokwim River and stretches forabout 70 miles along the Farewell fault,isn’t possible because of extensive groundcover.

Instead, LePain’s field crews have gath-ered rocks from outcrops along the fault,several miles to the northeast of the poten-

tial gas basin.Those samples show organic-rich mud-

stones and shales, in thick layers that are“good news for a gas point of view,”LePain said.

The question is, he added, are thosesimilar layers of organic material con-tained within the Holitna basin, and if so,“…is it deep enough to generate the hydro-carbon conversion?”

Past work discounted regionIndustry exploration geologists work-

ing for ARCO, Unocal and Sohio (nowBP) independently considered and rejectedthe Holitna basin during the 1980s.

Older rocks did not show potential forhydrocarbon or gas source rocks, LePainsaid, although the younger, Tertiary stratadid.

“All three acknowledged the potentialsource in the younger rocks, but how areyou going to get it to market, even if youhave a significant volume,” LePain said.“Back in the 1980s, it was not economic…. all three independently walked awayfrom the region.”

Another consideration was the potentialresource size. The Holitna basin, specula-tive as it is, could contain from 50 to 100billion cubic feet of gas, LePain said,which compares to Alaska’s North Slopefields known to contain amounts of gasmeasuring in the trillion cubic feet accu-mulations.

“That (smaller size) is just not attractiveto commercial operators,” he said.

The Holitna basin scenario dramatical-ly changes, though, with a local demandfor energy, which could be provided bydevelopment of the Donlin Creek goldmine.

Some negative characteristicsLePain’s past work and reports on the

Holitna basin do contain some negativetraits, including layers of sandstone inbetween the organic rich shales.

“Those sandstones don’t appear to havea lot of porosity in the outcrops,” LePainsaid. The trap potential of the upper layersis also poor, based on outcrops, creating apotentially leaky reservoir, he said.

The organic rich shales could possiblybe both source rock and reservoir rock,LePain added. “Depending on the fractureand volume, there could be gas storagewithin the matrix,” he said. “Until you puta hole in the ground, you just don’t know.”●

A

Dave LePain, DGGSgeologist

EASTERN BEAUFORT SEAASRC Energy Services gets ANWRtest well planning contract

The Alaska Division of Oil and Gas has selected ASRC Energy Services as itsfirst choice to assist it in drawing up preliminary plans for a stratigraphic test welloffshore the Arctic National Wildlife Refuge 1002 area. Anchorage-based ASRCEnergy Services was one of two companies that responded to a Sept. 26 RFP fromthe state of Alaska for planning the well and putting a consortium together to drillit. (See related story on the cover of last week’s Petroleum News atwww.PetroleumNews.com)

“We have recommended our contractingoffice enter into negotiations with ASRCEnergy Services to negotiate a contract,”division geologist Jim Cowan told PetroleumNews Oct. 24.

If a satisfactory agreement is reached, theArctic Slope Regional Corp. subsidiary willhelp the division put together a plan for theANWR test well, including a cost estimate.ASRC Energy Services will solicit commit-ments and technical input from individuals or organizations willing to participatein a consortium to drill the eastern Beaufort Sea well in the winter of 2004-2005.

The state said the planning project is expected to cost $50,000.According to the RFP, the division is looking at well locations on unleased

state submerged lands approximately 30 miles southeast of Kaktovik, Alaska,“between the state’s three-mile limit and the coastal boundary of the ArcticNational Wildlife Refuge. The area of interest is offshore of the Angun oil seepnear Angun Point.”

The RFP asked for work to be completed by Jan.5, but Cowan said that datewill likely be renegotiated for a later date “sometime in the first quarter of nextyear.”

—KAY CASHMAN, Petroleum News publisher & managing editor

If a satisfactory agreementis reached, the Arctic SlopeRegional Corp. subsidiarywill help the division puttogether a plan for the

ANWR test well, includinga cost estimate.

Tax last-ditch strategy, butAlaskans frustrated with lackof a natural gas project

By LARRY PERSILYPetroleum News Juneau Correspondent

laska legislators are unlikely toadopt a natural gas reserves tax topunish North Slope producers fortheir hesitancy to build a gas

pipeline across the state, but that doesn’tmean lawmakers — and the public —aren’t frustrated with the lack of a project.

Neither Sen. Scott Ogan, R-Palmer, astrong supporter ofthe oil and gasindustry, nor Rep.Eric Croft, D-Anchorage, a vocalcritic of the indus-try’s reluctance tobuild an Alaska nat-ural gas project,expect legislatorswill go along with acitizens group pro-posal for a reserves tax.

“A gas reserves tax is probably a last-ditch strategy,” said Ogan, chair of theSenate Resources Committee. “You haveto be mindful of the law of unintendedconsequences.”

Such a punitive tax would be viewedby the industry as adversarial, especiallyat a time when Alaska wants to attractmore oil and gas investment to the state,he said.

Governor says tax a bad ideaThe governor also sees a reserves tax

as the wrong way to get the multibillion-dollar project built, said his spokesmanJohn Manly. People need to understandthe long and costly legal battle that wouldensue, Manly said, adding that the com-panies’ response likely would be, “We’llsee you in court and for many years tocome.”

But Alaskans are growing tired afterwaiting 25 years for a gas pipeline, Croftsaid. If a project makes economic sense,and if the three major North Slope pro-ducers decline to move ahead, the publicshould be and would be furious, he said.

The unanswered question, the legisla-tors said, is whether a gas pipeline is asmart financial investment. And separatefrom the private-sector project — butwith the same financial question — is theproposed state-owned project to pipe nat-ural gas to Valdez, where it would be liq-uefied and shipped out on tankers toCalifornia or the Far East.

Tax proposal supports LNG projectBackbone II, a successor to the citi-

zens group Backbone that battled againstBP’s takeover of ARCO Alaska’s assetsin 1999-2000, believes the companies arechoosing to develop other gas resources

around the world instead of bringing theirAlaska gas to market. The group’s full-page proposal says the companies couldescape the reserves tax if they agreed tosell at least 1 billion cubic feet of gas perday to an Alaska LNG project, such as thestate-owned project.

Anchorage attorney Bill Walker, whosigned the late-September Backbone IIads in the Anchorage Daily News andFairbanks Daily News-Miner, said thegroup has met three times since then buthas no more campaign plans to report atthis time.

Walker, a member of the originalBackbone group, serves under contract ascity attorney to Valdez, which has longpushed for an LNG project and terminalin the community. He said the city is notpart of the reserves tax campaign.

Conoco writes to all 60 legislatorsThe industry’s strongest opposition

against Backbone II’s newspaper adscame from Kevin Meyers, president ofConocoPhillips Alaska Inc., who sent aletter to all 60 legislators criticizing theproposed tax.

“The state cannot tax this or any otherproject into economic existence,” Meyerssaid. “We urge you to reject any effort totax a project into existence.”

ConocoPhillips and others have spentmillions of dollars studying the econom-ics of an Alaska LNG project, and con-cluded a pipeline from the North Slope tothe Lower 48 is a far better option, hesaid. The biggest strike against an LNGproject is that it cannot compete againstthe oversupply of less expensive projectsthroughout the world, Meyers said in hisletter.

Those other projects do not need an800-mile pipeline through the arctic toget gas to tidewater, nor do they needexpensive U.S.-built and U.S.-crewedLNG tankers, he said.

State gas authority also sends letterMeyers’ letter prompted a response

from the Alaska Natural GasDevelopment Authority, which is work-ing toward its own project for a state-owned pipeline to bring North Slope gasto tidewater. The authority’s plan is to liq-uefy the gas and ship it aboard tankers toCalifornia or the Far East.

The authority said in its letter to alllegislators that a reserves tax would hurtits effort to build a “commercial relation-ship” with the major North Slope produc-ers. The state project would need to buy

gas from the producers and also wouldlike to share the costs of a gas treatmentplant on the slope and the pipeline as faras it goes before the LNG project andLower 48 line split off in their separatedirections.

Harold Heinze, the authority’s chiefexecutive officer, signed the letter.

“The authority feels we have to dobusiness with the companies,” Heinzesaid Oct. 27, two weeks after sending theletter. Heinze said he didn’t want the pro-ducers to get the wrong idea that theauthority is involved in the gas reservestax.

State authority believesit has the answer

In fact, Heinze said in his letter, theauthority’s own analysis confirms “anAlaska LNG project would not be com-petitive for ConocoPhillips.” However,he said, the authority believes its tax-exempt benefits as a public corporationreduce the costs and make the project agood investment for the state.

Heinze said he took Meyers’ letter asan opportunity to tell legislators “there isan honest difference of opinion” as towhat the state authority can do. Theauthority believes a producer-sponsoredpipeline through Alaska and Canada anda state-owned line and LNG project atValdez “are compatible and complimen-tary.”

ConocoPhillips said in its letter it wor-ries that talk of a gas reserves tax andaccusations in the Backbone II newspaperad could hurt the producers’ effort inCongress to obtain federal tax credits fortheir $20 billion pipeline project to theLower 48.

Alaska waits on CongressOgan believes the companies will lose

credibility with the public if Congressapproves the tax incentives as part of theenergy bill but the producers later balk ata fast decision to go ahead with the proj-ect. Although he is hesitant to start spend-ing serious state money on the gas author-ity’s LNG proposal, he acknowledged theidea of a state-owned project “is lookingbetter and better.”

That’s okay with Heinze, whoobserved that the voters’ wide margin ofapproval in the November 2002 statewideelection to set up the authority “reflects alot of Alaskans’ frustration in theprocess.” The state-owned project, hesaid, “may be the best solution to thatfrustration.” ●

10 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003NATURAL GAS● A L A S K A

Gas reserves tax unlikely from legislators“A gas reserves tax is probably alast-ditch strategy. You have to bemindful of the law of unintended

consequences.” —Sen. Scott Ogan, R-Palmer

A

Sen. Scott Ogan, R-Palmer

Calista continues with plansfor B.C. coal-fired plant,while TKC backs shallow gas

By PATRICIA JONESPetroleum News Contributing Writer

power struggle appears to be simmer-ing between Alaska Native corpora-tions planning to build and operate —in remote southwest Alaska — a large

electric generation plant, capable of provid-ing power needed to develop one of theworld’s largest untapped gold deposits.

One plan calls for construction of a large,coal-fired power plant on a barge at Bethel,using Canada coal shipped to Alaska, andrunning a large transmission line almost 200miles northeast to the upper KuskokwimRiver area.

The second Native-backed proposalinvolves tapping coalbed methane and freegas from an unexplored shallow gas field inthe upper Kuskokwim region.

At stake is control and operation of apower plant that could provide up to 80megawatts of power to the remote DonlinCreek deposit, estimated to contain almost28 million ounces of gold. Donlin Creekdevelopers Placer Dome and NovaGoldResources, in the process of completing afeasibility study, need to identify an afford-able supply of power used in the chemicalprocess of separating microscopic gold fromits host rock. (See related story on page 19.)

Among a host of ideas floated for anindustrial source of power generation in theregion, far from Alaska’s existing electricgrid, are two proposals backed by Nativecorporations with ties to the land.

Calista backs coal plantCalista, the regional Native corporation

and subsurface land owner in southwestAlaska, is leaning towards a coal-firedpower plant in Bethel, based on a powerstudy completed in 2002.

A final report with a detailed analysis isexpected before the end of the year from thecorporation’s Nuvista Light & Power Co.,Bob Charles, Calista’s vice president of gov-ernment and corporate relations, toldPetroleum News Oct. 13. A 96-megawattpower plant mounted on a barge, poweredby coal shipped to Bethel from BritishColumbia, appears to be “the lowest costoption,” he said.

The coal plant would provide electricityto Donlin Creek and local villages via a 191-mile, 138-kilovolt power line from Bethel.Costs are estimated at $372 million,although Charles said Calista is “looking atways to reduce those capital costs.”

While Calista is looking at a number ofdifferent options for producing power forDonlin Creek, Charles said local shallowgas development, proposed by anotherNative corporation, is not among those alter-natives: “We are looking at what we know iscurrent and available right now for develop-ment,” he said. “Until it presents itself, noone can say whether it even has potential.”

Calista’s past research of potential gassupplies in the region were not encouraging,Charles added. “We couldn’t get other estab-lished oil and gas companies interested —

it’s a remote region with high developmentcosts and a limited market … (and) all indi-cations from other people is that theybelieve it’s too small.”

Shallow gas ‘perfect solution’But the potential of shallow gas develop-

ment in the region is viewed by the localNative corporation as “the perfect solution,”according to Trevor Smee, president andCEO of The Kuskokwim Corp.

Called TKC, the corporation representsNatives in 10 villages in the upperKuskokwim River area, where the proposedgold mine is located. In addition, TKC ownssurface rights to land neighboring four shal-low gas leases sought by Holitna Energy,state ground some 50 miles southeast of theDonlin Creek deposit.

TKC has partnered with Holitna Energyto develop gas and related power infrastruc-ture from those gas leases, forming a com-pany called Naniq Energy Co. LLC.

“Once you determine the gas field’scapacity — the quantity, pressure and poten-tial volume, then you know how feasible thefield is to build an 80-megawatt powerplant,” Smee said. “We can save about fiveyears off of any other plan suggested to fireup the mine, and we can get the villages inthe upper Kusko power as well.”

Holitna Energy’s early estimates fordeveloping shallow gas, building a powerplant and running electric lines to DonlinCreek and nearby villages is about $90 mil-lion.

A coal-fired power plant is “a waste offederal money,” Smee said. “It goes againsteverything Congress is trying to do, to getoff obligations on international fuels.”

Shallow gas is less costly, it would use alocal source of energy and it would producefewer emissions than the coal-fired plantproposed by Calista, he added.

“At this point, there seems to be a littlebit of resistance at looking at a non-Calistarun solution,” Smee said. “We’re trying toget them to team with us. … We both win ifwe work together.”

Smee and Holitna Energy president PhilSt. George are seeking funds for a detailedgravity survey and gas drilling in the region,planned for this winter. (See story in Oct. 19Petroleum News.)

Included in their queries are federalorganizations, such as the Department ofEnergy and Alaska’s congressional delega-tion. Smee said he’s spent time inWashington, D.C., to “make sure everyoneon the Senate energy committee understandsthere are multiple solutions on the table.”

U.S. Sen. Lisa Murkowski, R-Alaska,introduced legislation earlier this year,

which would authorize up to $100 million ingrants and $50 million in loan guarantees toCalista for development of a power plant.Coal and wind turbines were cited in thefunding request.

Murkowski’s staff said the federal fundscould be used for either coal or gas, and thatpeople in Calista will make the decision. ●

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003 11NATURAL GAS

● S O U T H W E S T A L A S K A

Struggle simmers over power source

A

At stake is control and operationof a power plant that could provide. . . power to the . . . Donlin Creek

deposit, estimated to containalmost 28 million ounces of gold.

But no idea how much of 500trillion cubic feet is recoverable

By GARY PARK Petroleum News Calgary Correspondent

oalbed methane proponents have anew number in their sights ascoalbed methane struggles to gainrecognition among Canada’s energy

resources. Two scientific reports by the Alberta

Geological Survey, a division of theprovince’s Energy and Utilities Board,have estimated the maximum coalbedmethane in-place for the Alberta plains andfoothills at 500 trillion cubic feet, about 12times Alberta’s established remaining mar-ketable conventional gas reserves of 42 tcf,although the ultimate recoverable is listedat 200 tcf.

Until now, the estimates have variedfrom 100 tcf to 1,000 tcf.

The studies are described as the mostcomprehensive scientific data available inAlberta about coalbed methane and aredesigned to encourage development of anuntapped resource at a time when the con-ventional storehouse is in a troublingdecline.

The Energy and Utilities Board saidthere is growing recognition that coalbedmethane is “poised to play a bigger role inmeeting the demand for natural gas ...”

But it acknowledges that the amount ofcoalbed methane that can actually berecovered with current technology andbased on economic conditions is unknown.

Andrew Beaton, a geologist with theAlberta Geological Survey, said the stud-ies, compiled from proprietary researchand with industry help, will correct the“lack of basic data” available in the publicdomain.

He said the hope now is that there willbe further defining and refining of thenumbers to speed up development of theresource.

For now, despite the participation ofmost leading E&P companies in variousprograms, coalbed methane production inCanada is estimated at no more than 25million cubic feet per day, although theNational Energy Board has projected thatwill grow to 1 billion cubic feet per day by2010 and 2 bcf per day by 2020.

Even so, companies are cautious about

releasing their plans and engaging in pre-diction on the ultimate potential of coalbedmethane.

MGV Energy has pioneered production The pioneering producer is MGV

Energy, the Canadian subsidiary ofQuicksilver Resources, of Fort Worth,Texas.

It is targeting output of 15 millioncubic feet per day by the end of 2003 as itcontinues exploration and pilot programsin its six joint ventures covering 450,000acres.

Others in the field include EnCana,which expects to spend about C$200 mil-lion over 12 months drilling 150 wells insoutheastern Alberta. Current productionis about 3 million cubic feet per day.

Nexen, in partnership with TridentExploration and Red Willow Corp., hasplanned to sink up to C$25 million intocoalbed methane this year, includingC$13.4 million to acquire coalbedmethane-prospective land. It has 14 pro-ducing pilot wells, but won’t disclose vol-umes.

Devon Canada has tagged C$10 mil-lion for coalbed methane spending as itcontinues work on a 10-well program;Talisman Energy is operating a joint ven-ture with CDX Canada; and ConnaughtEnergy is operating a five-well pilot proj-ect with Petrobank Energy & Resourcesand Birchill Resources and has a secondjoint venture with Calver Resources.

Government changes introduced Over recent months, both the Alberta

and British Columbia governments haveintroduced changes to promote coalbedmethane development.

Although British Columbia has offeredincentives and legislative changes to stim-ulate the extraction of coalbed methanefrom coal reserves, it is lagging behindAlberta, with only about four E&P com-panies active in the province, comparedwith 25-30 in Alberta, partly because ofunresolved land issues.

Alberta is moving cautiously on theregulatory front, appointing a cross-min-istry steering committee to develop a pub-lic consultation process that the Energyand Utilities Board says “may influencefuture CBM regulations.”

Barbara Thomas, a senior policy advis-er with British Columbia Energy &Mines, told a conference in October that adeal being negotiated with BritishColumbia coal companies will resolve adrawn-out dispute by recognizing coalbedmethane ownership in favor of petroleumand natural gas rather than coal.

That should “facilitate” coalbedmethane development in 308,000 acres offreehold coal lands, about 70 percent ofwhich is held by five coal companies.

Mike Gatens, chairman of theCanadian Unconventional GasAssociation, told a September meetingthat Canada has little hope of closing thegap on the U.S. production of unconven-tional gas until governments offer fiscalincentives to boost coalbed methane andother sources.

He said the United States showed theway in the 1980s when it provided tempo-rary tax incentives to counter dwindlingconventional gas supplies. As a result,130,000 wells yield a total of 18 bcf perday of unconventional gas in the UnitedStates, almost matching Canada’s total gasproduction, with coalbed methaneaccounting for about 25 percent. ●

12 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003NATURAL GAS● C A N A D A

Alberta gets a fix on CBM potential

C

Coal cleat from the Coalspur Coal Zone in the Alberta Foothills (Ardley equivalent).

For now … coalbed methaneproduction in Canada is estimatedat no more than 25 million cubic

feet per day, although theNational Energy Board has

projected that will grow to 1billion cubic feet per day by 2010

and 2 bcf per day by 2020.

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003 13LAND & LEASING

SANTA FE, N.M.Bureau of Land Management leases21 parcels in western New Mexico

Energy companies won 10-year leases on 21 of the 70 parcels in Cibola andCatron counties that were auctioned by the U.S. Bureau of Land Management inwestern New Mexico Oct. 22.

The parcels are east of a site on the Cibola-Catron county line where Salt RiverProject, an Arizona utility company, had proposed to develop a coal strip mine.The company abandoned its plan this summer after years of opposition from ZuniPueblo and others.

The pueblo argued that pumpingwater for the planned mine threat-ened to harm the nearby Zuni SaltLake, which is sacred to many south-western Indian tribes.

Hans Stuart, spokesman for theBLM office in Santa Fe, said hebelieves that the bidding on theparcels shows companies are inter-ested in gas and oil exploration in thearea.

61 parcels auctioned statewide Statewide, the BLM auctioned 61 parcels totaling 77,730 acres, said Theresa

Herrera, spokeswoman for the agency. The parcels vary in size. Stuart said all the bids in the Catron and Cibola county leases were the mini-

mum bid of $2 an acre, which would cover just over 35,000 acres at the bid price.Of the 21 parcels that the BLM auctioned off in Cibola and Catron counties, KHLInc. of Albuquerque won 17, while Tacheene Resources LLC of Denver won four,Herrera said.

The state Land Office leased parcels in the same area at its monthly auctionslast month and again this week. Both KHL and Tacheene Resources won bids forstate land at those auctions as well.

Stuart said the closest federal parcel to be leased out was 17 miles from ZuniSalt Lake.

Officials at the State Land Office said the closest parcel their office has leasedis about 15 miles from the lake.

Zuni Gov. Arlen Quetawki Sr. said Oct. 22 the pueblo won’t protest the oil andgas leases unless it decides they pose a threat to the lake or other tribal interests.

—THE ASSOCIATED PRESS

The parcels are east of a site onthe Cibola-Catron county linewhere Salt River Project, anArizona utility company, had

proposed to develop a coal stripmine. The company abandoned its

plan this summer after years ofopposition from Zuni Pueblo and

others.

14 PETROLEUM NEWS WEEK OF NOVEMBER 2, 2003

pipelines&downstreamwww.PetroleumNews.com

NEW ENGLANDTransCanada locks up moreU.S. Northeast capacity

TransCanada is on its way to owning close to three-quarters ofthe Portland Natural Gas Transmission System in the NewEngland area.

It will buy El Paso’s 29.64 percent stake for about $137.2 mil-lion, including assumed debt of $80.7 million, and if other part-ners in Portland Natural exercise their rights, TransCanada willsee its stake expand to 73.06 percent.

“Increasing our interest in PNGTS bolsters TransCanada’srole as an energy supplier in the U.S. Northeast,” said ChiefExecutive Officer Hal Kvisle. “PNGTS is a strategic link in theNortheast, providing market access to current and future suppliesof natural gas.”

The 285-mile interstate line carries 220 million cubic feet perday of gas, connecting the Trans Quebec & Maritimes Pipelinenear Pittsburg, N.H., and serves delivery points in NewHampshire and Massachusetts.

—GARY PARK, Petroleum News Calgary correspondent

● A N C H O R A G E , A L A S K A

Alyeska savings cuttransportation costsTariff down 30 cents a barrel as company chops $100M in operating costs

By KRISTEN NELSON Petroleum News Editor-in-Chief

lyeska Pipeline Service Co. has cut some $100million a year from its annual operating costsin the last two and a half years, and is lookingat cutting an equal amount in the next three to

five years. Those savings have already reduced the tariff on

oil moved in the trans-Alaska pipeline by some 30cents a barrel, David Wight, Alyeska president andchief executive officer, told the Alaska SupportIndustry Alliance in Anchorage Oct. 23, and the totalsavings, when the additional reductions are made,could total 60 cents a barrel.

Those reductions, combined with savings as theshippers bring their new double hulled tankers online, are expected to take more than one-third of thetransportation cost out of the system over the nextfive to eight years, he said.

What do those savings mean? The 30 cent a barrelsavings already achieved “could add somewherebetween 10 and 15 million dollars per year grosswellhead value to a project” like Point Thomson,Wight said, and “could easily add more than $100million in gross value to a project over the project’slife, even for some of these smaller fields.”

Costs that come out of transportation make Alaskamore competitive, he said, because “the cost chal-lenges are very significant” for the producers on theNorth Slope. Savings in transportation costs, Wightsaid, would be “no small and insignificant compo-nent in making the additional fields that we need tokeep production up more of a reality.”

Taking complexity out of the business How has Alyeska removed $100 million a year in

operating costs? The company “started by looking athow we run our business,” Wight said.

The business is complex and the company hadmore than 400 manuals that told it how to run the sys-tem. Alyeska wrote most of those manuals, he said,and kept adding to them. When a better way to dosomething was found, or when there was a difficulty,“we would sit down and write a new procedure.”

Until, for some procedures, you had to look at 20different manuals to make sure you did the process

right. Alyeska set out to simplify the manuals, and has

eliminated or consolidated them, so that “in someplaces we have 20 or 30 pages where we used to havehundreds.”

It allows Alyeska to understand its business better. “And it gives the regulators a very clear and sig-

nificant look into how we’re going to run the business— and a way to check up.

“And it really takes the complexity out of the busi-ness and allow us to do the business more efficient-ly,” he said. That has allowed Alyeska to reduce theworkload — and the number of people required to dothe work.

The hundred million in savings came from a lot ofthings, Wight said, some of it from things like con-solidating offices, moving its Anchorage staff intoleased space at BP and sharing building security costswith BP.

ALBERTATerasen close to decision onwestern pipeline expansions

Terasen Pipelines is stepping up its race with Enbridge to carrymore heavy oil from the Alberta oil sands.

The Calgary-based company (formerly BC Gas) expects to fileapplications with the National Energy Board before year’s end toboost capacity of its Express and Trans Mountain systems.

A C$70 million addition to Express would increase deliveriesfrom Hardisty, Alberta, to Casper, Wyo., by 40,000-45,000 barrelsper day to the current capacity of 172,000 bpd.

The Trans Mountain line from Edmonton to the BritishColumbia coast and the United States would get a C$15 millioninfusion to raise its capacity by 15,000 bpd from current ship-ments of 200,000 bpd of light and heavy crude.

The current plan is to work on the additions within a year foran in-service date of mid-2005.

Terasen is also working on a 300-mile Bison pipeline from thenortheastern Alberta oil sands to the Edmonton refinery area. That100,000 bpd project has been delayed by at least one year from theprojected mid-2005 start up because oil sands projects were eitherslowed or put on hold.

On a much grander scale, Terasen is exploring a possible C$1.6billion twinning of the Trans Mountain link, allowing it to ship400,000 bpd of heavy heated crude.

That idea has put it in direct competition with Enbridge, whichis eying a possible C$2.5 billion pipeline from northern Alberta toeither Kitimat or Prince Rupert on the British Columbia coast fortanker shipment to California and Asia.

—GARY PARK, Petroleum News Calgary correspondent

A

see ALYESKA page 15

The next step is the Valdez Marine Terminal. Wightsaid that preliminary engineering work has started atthe terminal, which covers almost 1,000 acres.

JUD

Y P

ATR

ICK

Next $100 millionfrom physical changes

The next $100 million is going to comefrom changes in the pipeline itself — and inthe Valdez Marine Terminal.

Plans to change how the pipeline oper-ates are under way. By the end of the yearAlyeska expects to have preliminary engi-neering done and be recommending to itsowners — the major oil shippers — that itelectrify the pump stations and automatethem. (See stories in July 6 and July 13issues of Petroleum News.)

And if the company gets authorization togo ahead early next spring, it expects tohave some of the automated pump stationsup and running by the end of 2005, withcompletion of the work in early 2006.

A pump station looks like a small city,Wight said, and because the pump stationsare remote and manned, more than two-thirds of the buildings are there to housepeople and support the operations.Supporting the people also accounts forabout 40 percent of the cost at a pump sta-tion.

By electrifying pump stations, andautomating them, support for the crew is nolonger needed. “Quite frankly,” Wight said,“this is very similar to what most of theLower 48 pipelines look like today.”

Why wasn’t the pipeline built this way?Some of the communication and controltechnology wasn’t available 30 years ago. A“big, significant upgrade in terms of digitalcommunication and microwave technologyallows you to carefully oversee and monitoran operation of this nature, where youcouldn’t have done that 30 years ago.”

Living quarters and support facilitieswould be removed, Wight said, significant-ly reducing the footprint of a pump station.This reduces air emissions, he said, andremoves “a large source of the small spillsthat we have on the pipeline,” which come,not from the pipeline, but from “fluids asso-

ciated with operations, with people.”

Valdez Marine Terminal next on list The next step is the Valdez Marine

Terminal. Wight said that preliminary engineering

work has started at the terminal, which is “abig piece of our operation.” It covers almost1,000 acres, can store 9 million barrels ofoil, treats ballast water, handles vapors com-ing off tanks and ships, generates power andsupports the Ship Escort and ResponseVessels System.

All the systems at the terminal are nowbeing reviewed, and Wight said he believesthe kind of innovative ideas that came upwhen the pipeline was evaluated “will allowus to change the operations” and probablyalso “the footprint of what Valdez will looklike in the future.”

System designed for present volume of oil

The existing system — with pump sta-tions and pumping capacity, operating oridle — can handle more than 1.4 millionbarrels of oil a day. Alyeska is only shippingabout 1 million bpd, but, Wight said, withall the pump stations operating, the systemcould move “right at 2 million barrels aday.”

The state is forecasting production ofright at 1 million barrels a day over the next10 years, and then a decline.

So the new system that Alyeska is

designing is for around 1 million bpd,expandable up to about 1.14 million bpdwith drag reducing agent, which reducesfriction. “We continuously monitor the costof generating power … to pump oil throughthe pipeline versus putting friction reducerin the pipeline that therefore takes lesshorsepower to move oil,” Wight said.

But what if more oil is found? Theplanned system could handle as much as 10to 14 percent above the 1 million, the 1.14

million bpd, and would also be scalable tohandle lower volumes, “or we could addadditional pumps if necessary, which wouldbe our fondest dream, that it (production)would go up substantially.”

How long would it take to scale up? Ittook the companies about six and a halfyears to take Alpine to production, Wightsaid, and it would take Alyeska only 18 to24 months to expand to handle additionalvolumes. ●

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003 15PIPELINES & DOWNSTREAM

● S O U T H E A S T A L A S K A

Anchorage firm pushes propane-air projectCompany wants to bring natural gasto Southeast Alaska communities

By LARRY PERSILYPetroleum News Juneau Correspondent

n Anchorage company that has looked since 1986 atbringing natural gas to Alaska coastal communitieshas contracted with a North Dakota utility to conducta marketing study and engineering review for bring-

ing propane to Juneau, Ketchikan and Sitka, mixing it withair and then piping it to customers.

Depending on the survey results, the company nextwould solicit investor and bond financing. Assuming it canarrange tens of millions of dollars in financing, the compa-ny says it could start construction in 2004, according to apress release.

Alaska Intrastate Gas Company, however, faces a Dec.31, 2003, deadline to show proof of financial fitness andfinancing to the Regulatory Commission of Alaska in orderto maintain its unused 1998 certificate to operate a gas util-ity. The commission’s latest order in the case, issued June17, 2002, also gives Alaska Intrastate until Dec. 31, 2004,to begin service, though the company could ask for anotherextension.

Company started in real estate“We have really been through the mill,” said Frank

Avezac of Alaska Intrastate Gas. Avezac said he is anaccountant by trade and in 1986 transformed his Anchoragereal estate company into the envisioned gas distribution

company. He believes he can bring propane to the three Southeast

Alaska communities and pipe it around town at a lower costthan diesel fuel or electricity, though he acknowledgesfinancing has always been a problem.

Alaska Intrastate applied to the state utility regulationcommission in the mid-1990s to barge liquefied natural gasto as many as 17 coastal communities, then later amendedits application to serve the cities with a mixture calledpropane-air, or utility gas.

Project has changed over the yearsIts first application to what was then called the Alaska

Public Utilities Commission sought approval in 1995 toserve Homer and Seward on the Kenai Peninsula. The com-pany later withdrew that application and in 1997 filed toserve most every city in Southeast Alaska, Cordova andValdez in Prince William Sound, and Kodiak.

A February 2002 assessment prepared by engineeringfirm CH2M Hill for Alaska Intrastate looked at the eco-nomics of barging propane to just Juneau, Ketchikan andSitka in Southeast Alaska. October’s on-site feasibilityreview by Montana-Dakota Utilities was limited to justthose three communities, with a combined population ofabout 54,000.

The propane would be brought to town by barge —either in railcars or large tanks — then gasified and mixedwith air before it is fed into an underground pipe distribu-tion system to fuel furnaces, hot water heaters and otherappliances much the same as methane, the conventionalnatural gas used in cities with pipeline connections to gaswells.

Utility sends two staff members to AlaskaA project manager and a marketing representative for

Montana-Dakota Utilities visited Southeast Alaska inOctober, working under contract to Alaska Intrastate to helpdetermine the feasibility of the gas distribution business,said Dan Sharp, spokesman for the Bismarck, N.D., oil, gas,electricity and construction materials company. The twoworkers will prepare a report this fall on potential cus-tomers, the volume of gas they might purchase, and the fea-sibility of storing propane before mixing it and sending itout as a gas.

Montana-Dakota is not new to Alaska. It owns AlaskaBasic Industries, which owns Anchorage Sand and GravelCo., one of the largest aggregate suppliers in the state, Sharpsaid.

The North Dakota company operates natural gas utilitiesin Minnesota, Montana, Wyoming and North and SouthDakota, and operates a propane-air system similar to whatis envisioned for Southeast Alaska in a North Dakota townof 1,500 people, Sharp said. The utility used to have a fewmore propane-air operations but converted them to conven-tional natural gas piped into the communities.

The liquid propane used in such operations also hassome butane and methane mixed in, Sharp said, with about11 gallons of the propane mixture producing 1 million Btu.

“Our end of it is the feasibility study,” Sharp said, andperhaps engineering work if Alaska Intrastate Gas goesahead with the project.

In addition to contracting with Montana-DakotaUtilities, Avezac said he is working with Foster Energy as

A

continued from page 14

ALYESKA

see PROJECT page 16

16 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003EXPLORATION & PRODUCTION

one of several potential propane suppliers.The 71-year-old company has an office inCalgary, Alberta, and markets about500,000 gallons a day of heating oil, gaso-line, diesel and propane in western Canadaand Michigan.

Study assumptionsThe CH2M Hill study looked at several

factors in serving the coastal communitieswith gas, using the following assumptions:

• The propane could come from gas pro-duction facilities in Alberta or British

Columbia via railcar to Prince Rupert, B.C.,where barges would take the propane toAlaska.

• The estimated cost of the dock and stor-age facilities, vaporization or “send-out”facilities, and underground pipe throughoutmuch of Juneau would total $37.2 million,with a $13.4 million estimate for Sitka and$20 million for Ketchikan. Directional, hor-izontal drilling could help reduce the cost ofrunning pipe beneath city streets, perhapsplacing 500 feet of pipe from a single drillhole, according to the Montana-Dakotateam.

• Additional start-up costs for AlaskaIntrastate are estimated at $7.2 million, not

counting fuel inventory and the cost of pos-sibly purchasing railcars to move thepropane.

• The study assumes the gas utilitywould achieve 60 percent market penetra-tion of residential and small commercialcustomers after five years.

• Alaska Intrastate would capture 100percent of the fuel market for seafoodprocessors in the communities.

Possible cost savingsThe consultants determined residential

consumers would see a small savings afterfactoring in the cost and possible efficiencyloss of converting home heating systems

from oil to gas, but consumers could realizea substantial savings if costs were measuredon new, high-efficiency gas furnaces.

Avezac said his company would helpfinance boiler and hot water heater conver-sions to attract customers, noting that con-version costs for a residential furnace couldrun as high as $1,600.

The company’s original plan almost adecade ago was to get state royalty gas at adiscount for its operations, which wouldhave required legislative action. ThoughAvezac has moved away from that idea forstart-up, he said he would like to someday“buy royalty gas and bring it to the residentsof Southeast Alaska.” ●

continued from page 15

PROJECT

● A L B E R T A

Alberta government offers royalty breaksGas producers forced to shut-in wellsdue to oil sands get C$25 million

By GARY PARKPetroleum News Calgary Correspondent

he gas-over-bitumen dispute in Alberta has movedcloser to a settlement, with the provincial govern-ment offering C$25 million in interim compensa-tion to natural gas producers forced to close 338

wells and 95 million cubic feet per day of output. Energy Minister Murray Smith announced that affect-

ed producers can apply for a royalty deferral equal to 60cents per thousand cubic feet of production.

He said the temporary scheme has been put in placeto reduce potential “financial hardship” while his depart-ment works with the industry to develop a long-termanswer.

Susan Riddell Rose, president of Paramount EnergyTrust, the hardest hit by the shut-in order, said the pro-

gram is a “good first step,” but fallswell short of covering Paramount’sestimated losses of C$8 million ayear along with the “loss of oppor-tunities we’ve suffered in the lastthree months.”

Alberta’s Energy and UtilitiesBoard originally ordered the shut-inof 938 wells to protect reservoirpressures and safeguard 100 billionbarrels of bitumen reserves, whichthe board rated as 600 times theenergy equivalent of the gas reserves.

For now the other 600 wells have temporary exemp-tions from the shut-in because of evidence that the gasextraction does not affect the potential extraction of bitu-men.

Pressure surveys being conductedThe energy board is also working with 15 geologists

from 11 energy companies to conduct pressure surveys

in the area. It has set a tentative deadline of April 1,2004, to decide on the fate of the shut-in wells.

Meanwhile, five of the gas producers — Paramount,Devon Canada, BP Canada Energy, Canadian NaturalResources and ProGas — are taking court action toeither quash the shut-in or appeal the regulator’s deci-sion.

Paramount and Devon argue the Energy and UtilitiesBoard has failed to abide by the legislation under whichit operates and has thus lost its jurisdiction in the issue.

Following an earlier shut-in affecting seven producersand 146 wells with 20 million cubic feet per day of pro-duction, the government paid C$85 million in compen-sation.

In the current case, the producers have claimed theyshould be entitled to compensation of C$600 million-C$800 million.

Oil sands producers such as Petro-Canada haverejected any form of compensation, partly because theyfear some of the costs could land on them. ●

T Energy MinisterMurray Smith

PETROLEUM NEWS 17WEEK OF NOVEMBER 2, 2003

exploration&productionwww.PetroleumNews.com

NORTH SLOPEConocoPhillips proposes 37 newwells at West Sak pilot pad

ConocoPhillips has filed a development plan with the state ofAlaska to develop West Sak heavy oil from the 1J drill site in theKuparuk River unit, formerly known as the West Sak pilot pad,southeast of Kuparuk central processing plant No. 1.

The development includes new pipelines for water injection, mis-cible injectant and crude oil; a cross-country power line; and on-padwell connections and facilities for heating the produced crude oil.

The company is proposing 37 new wells, 20 producers and 17injectors for the West Sak reservoir, and three tie-ins of existing pro-duction wells. West Sak and Kuparuk wells would share truck andlateral lines and common facilities.

No enlargement of the existing drill site 1J gravel pad is planned. Pipeline and power line construction would be done from ice

roads, which would be put in when tundra travel opens in January,with construction planned for completion by May. On-pad construc-tion would begin by April and be complete by the end of the year.ConocoPhillips said a possible variation would have on-pad con-struction beginning this spring, but pipeline and power line con-struction delayed until 2005.

Access will be by existing roads within the Kuparuk River unit,so no new roads will be necessary.

Drilling from the 1J drill site would begin in March or April, andbe complete by 2007. One rig would drill at the pad fulltime and asecond rig would be on site approximately six months per year.

● A N C H O R A G E , A L A S K A

Bristol Bay project drivenby jobs, local energySamuelson said governor wasted no time in responding to region’s needs

By KRISTEN NELSON Petroleum News Editor-in-Chief

ommercial fishing, the economic foundationof the Bristol Bay region, has been bad inrecent years, and the region turned to thestate, asking Alaska Gov. Frank Murkowski

to assist with oil and gas development, both forjobs to supplement fishing and for less expensiveenergy.

As a result, the state has offered explorationlicensing for the area (see story on page XX thisissue), and is preparing a best interest finding for acompetitive oil and gas lease sale.

The state is working on oil and gas develop-ment with the Bristol Bay Native Corp. and withthe local boroughs. There was a meeting inAnchorage Oct. 22 during the Alaska Federation ofNatives annual convention to provide an updateand a chance for Bristol Bay area representativesto talk to the governor about the proposal.

Robin Samuelson of the Bristol Bay EconomicDevelopment Corp. chaired the meeting.

He said the development proposal was suggest-ed right after Murkowski was elected governor,when a few people in the region, among them hisfather, Harvey Samuelson, Bristol Bay NativeCorp. land chair, and Nels Anderson, a former statesenator, said the region needed to write to the gov-ernor and ask for help.

“We’ve been faced with five, six years of fish-

GULF OF MEXICOUnocal scores on HarvestDeep appraisal well in GOM

The Harvest 2 appraisal well, drilled more than one-half milefrom the Gulf of Mexico’s Harvest 1 discovery well, likely willproduce a higher rate than Harvest 1’s current 35 to 40 millioncubic feet of natural gas per day, operator Unocal said Oct. 28.

Located on West Cameron Block 44, the Harvest 2 well wasdrilled to a total depth of 14,322 feet and encountered more than140 feet of net natural gas pay, including 110 continuous feet ofpay in one high-quality interval, Unocal said. Harvest 1 hadencountered 70 feet of net gas pay.

The Harvest 2 well is expected to begin production in mid-December, Unocal said, adding that the company is formulatinga plan for a second appraisal well on West Cameron Block 44and evaluating follow-up drilling opportunities on nearby WestCameron blocks 22 and 57.

Unocal holds a 41 percent working interest in West CameronBlock 44. Marlin Energy Offshore holds a 37 percent interest,followed by the William G. Helis Co. with a 20 percent interestand Houston Energy with a 2 percent interest.

Unocal said it also made a discovery at its deep shelf explo-ration well on the Red Pepper prospect at High Island Block 37.

● A L B E R T A

Natives inherit oil richesLand claim opens way to project run by Fort McKay First Nation

By GARY PARK Petroleum News Calgary Correspondent

tiny aboriginal community in northeasternAlberta suddenly finds itself in control of up to400 million barrels of heavy oil reserves, whichit hopes to turn into the first Native-owned oil

sands project.Following 17 years of negotiations and a 92 per-

cent ratification vote Oct. 23-24, the 550 members ofthe Fort McKay First Nation have accepted a landclaim covering 24 square miles.

The land is about 30 miles north of the oil sandscapital of Fort McMurray and close to the three multi-billion-dollar operations run by Syncrude Canada,Suncor Energy and Shell Canada.

As well, the community will receive a C$41 mil-lion cash payout over three years, with C$10,000 dis-tributed to each member and the remaining C$33 mil-lion locked into a trust fund that will be used for futureinvestment.

Chief Jim Boucher said the deal opens the way to“economic development and employment on thereserve.”

Oil sands project would tap reserves Underpinning that goal is a loosely developed plan

for a 25,000 barrel per day oil sands project to tap alease estimated to hold 200 million to 400 million bar-rels of recoverable bitumen.

“We’re pretty confident we will be able to over-come the risks with getting the project under way,”Boucher said.

But he has cautioned it could take four years toassemble management teams, secure funding and gainregulatory approvals.

Initially, a federal regulatory body will determine ifa project is environmentally and technically feasible.

Fort McKay leaders are also exploring the possi-bility of engaging partners to mine the raw bitumen

C

A

see BRISTOL BAY page 18

see RICHES page 18see UNOCAL page 18

“We didn’t want the industry to arrive onour doorstep with a bunch of Texans as

their workers. We wanted Alaskans, fromthe Alaska Peninsula and Bristol Bay,

trained … to be the workers on oilexploration, seismic work, etc.”

—Robin Samuelson

ing disasters, communities were closing,schools were shutting down, city govern-ments, borough governments, were look-ing in their little jars, and they were see-ing the bottom,” he related.

The governor “wasted no time inresponding” to Bristol Bay’s request,Samuelson said, and put Jim Clark, hischief of staff, as well as commissioners“on notice that our regions were a top pri-ority of his administration ...”

Are there resources? Commissioner of Natural Resources

Tom Irwin said the process started inJanuary and February with informationcoming into the governor’s office and thedepartment from indi-viduals and local gov-ernments in theBristol Bay region.

The departmentdetermined that therewas a resource worthpursuing and in Julythe department signeda memorandum of understanding with theBristol Bay Native Corp., Irwin said,stressing cooperation, mutual interestsand communications.

The department solicited and receivedinterest in an exploration license in theBristol Bay area, and is preparing a bestinterest finding, including input fromlocal communities.

Information from communities isbeing gathered in October and Novemberfor the best interest finding, Irwin said,and in January, when the preliminary bestinterest finding is out, “We’ll go throughthe same process. That will be issued andthen we’ll come back out to the commu-nities for the input.”

Onshore drilling, local participation, jobs

Local participation was one of thethings Bristol Bay insisted on, Samuelsonsaid.

The region wants a stronger economyand saw oil and gas as a way to broadenits economic base, but with some caveats:development would be onshore, withdirectional drilling.

“We didn’t want to go offshore,”Samuelson said, “because of the sensitiv-ity to the commercial fishing fleet, thesubsistence and the resources of theregion.”

Bristol Bay also insisted on participa-tion at all levels and on “a responsivepublic process that was very transparent.We wanted everybody to be on ground

level and sharing the information. Nocommunity should be left out of theprocess,” he said.

Then there were jobs, and training forjobs.

“We didn’t want the industry to arriveon our doorstep with a bunch of Texans astheir workers. We wanted Alaskans, fromthe Alaska Peninsula and Bristol Bay,trained at SAVEC (the Southwest AlaskaVocational and Education Center in KingSalmon) to be the workers on oil explo-ration, seismic work, etc.”

That concern was echoed by audienceparticipants, and Commissioner of Laborand Workforce Development GregO’Claray said the state was working toidentify skills already there and supple-ment where additional training is needed.But, he said, the state needs the commit-ment of residents of that area “that they’rewilling to go into different occupations tosupplement the low income they’re get-ting from fishing. You don’t have to quitfishing,” he said, pointing out that both heand Lt. Gov. Loren Leman are fishermen.These are just our day jobs, he said.

Pioneering roads would be necessaryto support oil and gas exploration anddevelopment activities, Samuelson said,and those roads could “eventually evolveinto a network of surface transportationwithin the region.” (See sidebar on accessissues.)

Improved airports are also an issue,both for fish marketing and health. Manyregion residents have noted that the air-ports were “built for 206s, not DC-6s, totake off loaded with fish.”

“Fisheries has been, and always willbe, our main industry in our region,”Samuelson said. “It’s sustainable and it’srenewable,” he said.

Benefit also for fishing Nels Anderson said Murkowski “has

done more for oil and gas explorationactivities in the state of Alaska in fourmonths than any other previous gover-nor.”

Low-cost fuel, Anderson said, wouldhelp revitalize Bristol Bay’s fishery. Itcosts about $200 to make a ton of ice in

Bristol Bay, he said, compared to about$50 in Cook Inlet.

“Failure to find low-cost energy is notan option,” he said.

Gov. Murkowski told the audience thatit didn’t require any urging to get himinvolved, “because this is what my con-tribution is all about … creating a soundeconomy for the state of Alaska…”

As for the oil and gas potential,Murkowski said 25 years ago, “from thestandpoint of geology, for oil and gasprospects, it was the North Slope, it wasCook Inlet, and it was Bristol Bay.”

Harvey Samuelson agreed. BillBishop, who discovered oil on the KenaiPeninsula at the Swanson River field inthe late 1950s, later worked for theBristol Bay Native Corp., Samuelsonsaid. Bishop died a couple of years ago,“but he told me, ‘we got oil down thereHarvey, be sure and don’t give up, justkeep going after it, eventually you willget it, because I know there’s oil there.’”

An area for independentsMurkowski said the administration

believes an oil and gas industry in theBristol Bay area could supply “numerousjobs, and potentially a petrochemicalindustry, as well as providing low-costenergy for your traditional fish industryas well.” And, unlike the North Slope,Bristol Bay is at tidewater. If commercialquantities of gas are found, it won’trequire an 800-mile pipeline, he said.

Commercial quantities of gas in theBristol Bay region, the governor said,could be “a source of energy to power theregion, instead of your current depend-ence on diesel.”

The governor said he would be in NewOrleans Oct. 26 to speak to theIndependent Petroleum Association ofAmerica, and predicted that independentswill find Bristol Bay attractive.

It’s different than the North Slope, hesaid, where most of the natural gas is con-trolled by three companies. In the BristolBay area, the gas prospects are controlledby the state, Native regional corporationsor the federal government. ●

18 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003EXPLORATION & PRODUCTION

The well found 55 feet of net natural gaspay and is currently flowing at a rate of25 million cubic feet per day. Unocal hasa 36 percent interest in Red Pepper, fol-lowed by Seneca Resources with a 25percent interest, Fidelity Exploration &Production with a 25 percent interest, andthe William G. Helis Co. with a 14 per-cent stake.

Unocal said an exploratory well on theComanchero prospect on Eugene Island37 was a dry hole and that the companywould take a pre-tax $2.4 million chargeagainst 2003 third-quarter earnings.

and assume the financial obligations ofa project that could have an operatinglife of 25 to 30 years.

The first nation, once among thepoorest Native communities inCanada, has already established agroup of companies employing 275people and supporting the entire oilsands industry with contracting, envi-ronmental, trucking and other servic-es. ●

Bristol Bay part of ‘access to the future’ Commissioner of Community and Economic Development Edgar Blatchford

says Alaska Gov. Frank Murkowski’s ‘access to the future’ team is looking at how“to best utilize state and federal agency resources to enhance Alaska’s economy.”

The Bristol Bay-Alaska Peninsula oil and gas development project is one ofthree examples in a status report issued by the access team inmid-September.

Other projects are the Nelson Island road and port project(a 29-mile road system connecting communities on NelsonIsland on the Bering Sea coast west of Bethel, and a deepwa-ter port to reduce shipping costs) and Delta area development(projects in the region southeast of Fairbanks near the junc-tion of the Richardson and Alaska highways include the Pogomine, a missile defense facility and other economic opportu-nities in the upper Tanana basin).

Blatchford said Oct. 22 at a meeting to discuss the BristolBay oil and gas development project that access includes:“legal access, physical access, and access to capital, access to markets, access totechnology, and most importantly, access to jobs.” In addition to the governor’soffice and his department, Blatchford said, the team includes representatives fromthe departments of Transportation and Public Facilities, Natural Resources, Laborand Workforce Development and Environmental Conservation.

The access team status report says the primary benefit of onshore oil and gasdevelopment in the Bristol Bay-Alaska Peninsula area “is to provide local residentswith employment, a natural gas supply to heat homes and businesses, less expen-sive electrical power, and lower costs to the fishing industry (ice production andprocessor facilities).”

Less expensive ice would improve the quality of fish delivered to market andthat, “combined with lower cost in the processing sector due to less expensivepower,” would increase the competitive position of the region’s commercial fish-ing industry.

Road access between communities on the Alaska Peninsula would be a “criticalsecondary long-term benefit, the report said.” Roads would access state and Nativelands for exploration and development. A 282-mile road between King Salmon andthe deepwater port of Chignik “is supported by local and regional organizations.”

EDGAR BLATCHFORD

continued from page 17

BRISTOL BAY

“Failure tofind low-costenergy is notan option.”

—Nels Anderson

continued from page 17

UNOCAL

continued from page 17

RICHES

PETROLEUM NEWS 19WEEK OF NOVEMBER 2, 2003

northof60 miningwww.PetroleumNews.com

SOUTHWEST ALASKAPlacer Dome says infrastructureis its focus at Donlin Creek

Mining giant Placer Dome remains focused on resolving infra-structure hurdles to developing the remote Donlin Creek golddeposit in southwest Alaska.

Finding affordable and significant sources of power and lime-stone, needed in the hardrock extraction process, are two keyissues that the company has been working this summer, projectmanager Gregg Bush told Petroleum News Oct. 21.

Transportation to the remote site, 14 miles north of the upperKuskokwim River at Crooked Creek, is another logistical hurdleto be overcome, he said.

“Transportation is something much more in our control, butwe’re sort of at the mercy of the environment, the circumstances”for electric demand in the undeveloped area, he said. “If we can’tsolve the power problem, we have a serious dilemma.”

Current plans call for a mill with 80 megawatts of powercapacity installed. Peak loads would range from 70 to 75megawatts, with the average load in the low 60s, he said.

Hires Swiss Energy Placer Dome has hired Swiss Energy as its consultant on the

power issue, Bush said. The company is considering a whole hostof power generation ideas and hopes to develop a short list ofpossibilities by the end of the year. (See related story on page 11.)

A final decision on a power source is needed by the end of thesecond quarter of 2004, when the company’s pre-feasibility studyshould be complete, Bush said.

Placer Dome has also been researching options for limestonesources in the region. Current plans call for an average consump-tion of 60,000 tons of limestone per year, although the amountwill vary from year to year, depending on the type of oreprocessed.

The company is also working with the Alaska Department ofTransportation and Public Facilities to identify a road route fromthe Kuskokwim River to the mine site. A winter trail now runsalong Crooked Creek to the mining community of Flat. “Thatestablished winter trail is not necessarily the best place to build aroad,” Bush said.

Winter drilling plannedAfter freeze up, Placer Dome plans to drill some additional

ground water monitoring wells and conduct some condemnationdrilling.

Bush said the company hopes to start a substantial infilldrilling program on the deposit next summer, after completingthe pre-feasibility study and successful resolution of infrastruc-ture hurdles.

A feasibility study could begin late next year, provided allprior steps pan out. “Typically, Placer does a feasibility studywhen they’re pretty sure they are going to build a mine,” he said.

The company would also initiate permitting at the start of the

● N O M E , A L A S K A

Alaska’s next hardrock mine?NovaGold starts final feasibility study for Rock Creek, coarse goldfrom being tested; “aggressively advancing” to June 2004 target date

By PATRICIA JONESPetroleum News Contributing Writer

ineral exploration rigs at the Rock Creekdeposit near Nome, Alaska, completed a10,000-meter in-fill program in earlyOctober designed to prove up the 1 million

ounce gold resource being developed by NovaGoldResources.

Now a reverse circulation drill rig is on site, com-pleting about 2,200 meters of condemnation drillingthat will help locate building sites for mine infra-structure, said DougNicholson, senior projectsengineer at NovaGold.

The condemnation drillingis part of a final feasibilitystudy initiated earlier inOctober. Other feasibilitystudy work includes lettingcontracts for detailed geotech-nical, hydrologic and metallur-gical studies.

“It’s starting to become more of a reality. Westaked out the pit and plant sites, so visually it’s excit-ing,” Nicholson told Petroleum News Oct. 28.“We’re aggressively advancing this to the June 2004target date.”

That’s when the feasibility study should be com-plete, with permitting work planned to start later in2004. “Based on consultation with the permit agen-cies, NovaGold anticipates permit approval in thesummer of 2005 with construction to begin immedi-ately thereafter,” the company said in an Oct. 9 pressrelease.

With a simple milling process and a shallowdeposit to tap, Rock Creek could be producing goldin early 2006, putting it near or at the top of the listfor Alaska’s next producing hardrock gold mine.

“I like its chances very much,” Nicholson said. “Idon’t know when Pogo will start, but we’ll certainlybe before Donlin Creek.”

Assay method alteredNo new numbers are available yet for the geolog-

ical estimate of gold contained in the shallow deposit,located seven miles from the historical mining com-munity of Nome. The company is still receiving andevaluating assays from summer drilling.

Included in the new resource calculation will bedata from a revised assay method, which essentially

quadruples the amount of drill sample that geo-chemists process and evaluate, Nicholson said.

“It’s a much larger volume of sample, so it takes along time to process,” he said. “We like to think thatin the nuggety type of deposit like this, it gives a bet-ter chance to capture any volume of mineralization inthe selected core drill.”

According to Nicholson and a company pressrelease, initial results from the new testing methodsuggest the deposit may contain an overall highergrade of gold than previously estimated.

That’s because conventional assay methods mayunder report grades due to the coarse gold compo-nent.

The company’s scoping study completed earlierthis year was based on a 2.03 gram per ton goldgrade, a “fairly conservative” estimate, he said.“What we are seeing from the drilling and the assayprocedure, we hope to upgrade the deposit.”

Profitable economics on projectCurrent gold prices in the $380 per ounce range

also help out Rock Creek. A financial analysis froman independent economic assessment study complet-ed in August showed a pre-tax return ranging from 19to 25 percent, and an after tax return from 16 toalmost 22 percent, with gold selling at $325 perounce.

Norwest Corp. evaluated capital costs, operatingand processing costs, taxes and royalties for RockCreek and outlined a scenario of a mine that wouldproduce about 110,000 ounces of gold per year, withtotal cash costs less than $200 per ounce.

Economic evaluations were also developed forhigher gold prices, ranging from $350 to $400 perounce. At $375 per ounce gold prices, pre-tax returnsrange from 33 to 38 percent, and after-tax returnsranged from 28 to 32.6 percent.

“For every 10 percent increase in the price of gold,we get an 8 percent kick in the (rate of return),”Nicholson said.

The economic analysis also calculated return rateswith an increase in gold grade.

“We think we’re going to get a double whammy”with potential increases in gold grades and highergold prices, Nicholson said.

NovaGold, a junior exploration company with anumber of gold properties in Alaska, is the sole oper-ator of the Rock Creek deposit. The Bering StraitsNative Corp. has a one-third share of the property,part of an exploration agreement for area lands. ●

M

DOUG NICHOLSON

PATR

ICIA

JO

NES

see DONLIN CREEK page 20

By PATRICIA JONESPetroleum News Contributing Writer

ederal and state regulators missedtheir Oct. 17 deadline for release ofthe final environmental impact state-ment and accompanying record of

decision for a tailings storage expansionproject proposed at the Greens CreekMine in southeast Alaska.

To lengthen the life of the under-ground mine, 18 miles southwest ofJuneau on Admiralty Island, operatorKennecott Greens Creek Mining Co.wants to expand the facility’s storage areafor tailings, ground rock that mineralshave been extracted from in the millingprocess.

The agencies’ preferred alternativeoutlined in the draft EIS would increasethe tailings footprint from the 29 acresallowed under existing permits to 62.2acres, allowing an additional 20 years ofmine life for the 265 employees whowork at Greens Creek.

Part of the proposed expanded area is

on land included in the Admiralty IslandNational Monument, established in 1978by a presidential proclamation issued bythen President Jimmy Carter. Languageallowing development of mining claimswithin that monument was included in theAlaska National Interest LandsConservation Act.

Final editing of errors in the EIS doc-ument submitted by contractors andupdating of drawings caused the delayfrom Oct. 17, said Jeff DeFreest, Juneaudistrict ranger for the U.S. Forest Service,the lead agency overseeing the permitprocess.

Early November deadline setNow, regulators are shooting for an

early November release, he said. “Thedate we first proposed, Nov. 28, was notwell received.”

That could be due to a history ofdelays for this permitting process. Thefinal EIS and decision making processwas previously scheduled for late August.

“There’s a number of contributing fac-tors leading to that delay,” DeFreest said,including comments submitted by otheragencies “at the 11th hour.”

Kennecott first submitted plans for theexpansion project in January 2001,expecting the regulatory review to becompleted before the 2003 constructionseason, Bill Oelklaus, the mine’s environ-mental manager, told Petroleum NewsOct. 21.

“We originally scheduled this for twoyears sooner, so we would have two con-struction seasons,” he said. “Now if wehave a significant weather problem, thatputs things in a precarious position forus.”

At current processing rates, GreensCreek will run out of room for tailings inFebruary 2005. The mine will be forcedto shut down without an expanded tailingdisposal area, Oelklaus said.

That would cause a “significantimpact to the economy of the city andborough of Juneau,” said Stan Foo, min-ing section chief for the AlaskaDepartment of Natural Resources.“Greens Creek is one of the largestemployers in the area, and they providesome of the highest-paying jobs. Theycertainly contribute to the tax base.”

Appeals period adds to lengthEven if the Forest Service and other

agencies are able to publish the EIS anddecision in the Federal Register on Nov.7, as discussed during a teleconferencecall Oct. 20, Kennecott likely won’t

receive permits and the go-ahead for con-struction until next February.

A 45-day appeals period must pass,and DeFreest said he “wouldn’t be sur-prised by an appeal on the project … theForest Service usually sees appeals onmost of its decisions.”

That leaves the mine with a short win-dow to secure construction contracts forthe work to begin in April, the plannedstarting date for the project, Oelklaussaid.

Fine sand must be shipped in and thesite must be prepared for a geosyntheticliner to be placed at the bottom of the newtailings disposal area.

The construction project “will stretchthrough the summer,” he said, adding thatcrews should be able to complete the“critical construction items that requiregood weather.”

Three years too longBoth state and federal regulators

admitted that three years to complete anEIS for an existing operation was exces-sive.

“It usually doesn’t take this long. Itshouldn’t,” DeFreest said.

Foo said the state was working withfederal agencies to “try to improve thatturn-around time.”

“Especially for the operator, itbecomes a moving target when you can’twork on something and bank on it beingcompleted,” he added. “If it’s on stateland, we have more control over it, butwhen it’s federal ground involved, wework as closely as we can to maintain arealistic schedule.”

The Greens Creek mine, which pro-duces silver, gold, zinc and lead, was firstdeveloped in 1987. Mine operations shutdown between 1993 and 1996, due todepressed metal market prices. ●

20 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003NORTH OF 60 MINING

feasibility study, he said. “Our timelinetarget is to have all permits in place by theend of 2006.”

In its agreement with joint venturepartner NovaGold Resources Inc., PlacerDome has a little more than four years tobring Donlin Creek to a mine construc-tion decision. Placer Dome’s earn-in

requirements include spending $30 mil-lion on the property, to include a feasibil-ity plan and acquiring permits.

Bush declined to reveal how much thecompany has spent since assuming oper-atorship of Donlin Creek in mid-February. Total spending on the golddeposit, estimated to contain about 28million ounces of gold, from 1992through the end of 2002 is $45 million.

—PATRICIA JONES, Petroleum News contributing writer

continued from page 19

DONLIN CREEK

● J U N E A U , A L A S K A

Regulators delay Greens Creek expansion projectFinal EIS and decision delayed from Oct. 17 release to early November; mine will run out of space for tailings in February 2005

“There’s a number of contributingfactors leading to that delay,”

DeFreest said, including commentssubmitted by other agencies “at

the 11th hour.”F

and Gas leasing manager, concluded the salewith: “I’d like to thank you for your interestin the leasing program and participating heretoday — especially Pioneer NaturalResources.”

Bids took a big jump over 2002This year’s sales took a big jump over

2002. In last year’s Beaufort Sea sale the state

sold 15 tracts for $506,404.80, an averagebid of $26.34 an acre for 19,226 acres,compared to almost $2 million this yearand almost 50,000 acres — and an aver-age per acre bid of more than $40.

Last year’s North Slope sale wasreported by bid type — sliding scale roy-alty versus fixed roy-alty. The state sold 12North Slope leasesfor a combined valueof $579,727.75, withthe fixed royalty bidsaveraging $11.32 anacre for 29,451 acres,and the sliding scaleroyalty bids averag-ing $86.06 an acrefor 2,864 acres. Thatcompares to almost$4 million this yearand some 220,000acres and an averageper acre bid of morethan $17.

Pioneer has highestper-acre bid

Pioneer was highbidder on 12 of 20tracts sold in theBeaufort Sea sale, and on 41 of 75 tractssold in the North Slope sale.

The state received 26 bids on 20 tractsin the Beaufort Sea sale, 48,640 acres.High bonus bids totaled $1,975,883.60,with an average high bonus bid of $40.62an acre. Pioneer had the highest bid,$87.71 an acre, for tracts 260, 276 and 293in the Beaufort sale.

Its 12 leases from that sale are in twoblocks, one north of Prudhoe Bay and eastof Northstar and the other north ofPrudhoe Bay and south of Northstar.These tracts appear to be acreage former-ly held by BP Exploration (Alaska), whichsold or dropped its exploration acreageearlier in the year.

Bill Van Dyke, petroleum manager atthe Division of Oil and Gas, said after thesale that some of this interest got startedwhen BP put its exploration acreage up forsale when it decided to focus on in-fielddevelopment drilling.

“BP certainly facilitated some of thisactivity, made it happen sooner rather thanlater,” Van Dyke said, because of theexploration acreage the company offeredfor sale and the data the company offeredon that acreage.

Companies interested in BP’s prospectslooked at its data, Van Dyke said, “andthen BP offered to sell seismic packagesthat it controlled … for really goodprices.”

AVCG also takes Beaufort blockIn addition to Pioneer, the Beaufort Sea

sale drew another substantial set of bidsfrom a smaller independent, AVCG, whichtook six leases, spending $241,920.

Van Dyke said AVCG “had that playbefore” in the Gwydyr Bay area and neverwas able to drill a well, “so they cameback and picked up a lot of acreage in thatsame play.”

Ultrastar Exploration took one lease (at

$44.88 an acre) on which Pioneer andAVCG also bid, on the edge of the Pioneerblock south of Northstar.

Armstrong took a lease (at $57.35 anacre), offshore north of Kuparuk.

Pioneer takes 41 North Slope tracts The state received 79 bids on 75 tracts

in the North Slope sale, 220,800 acres,with total high bonus bids of$3,832,793.60 and an average high bid peracre of $17.36.

Pioneer took 41 tracts, all of those itbid on in the onshore sale, paying$2,335,385.60. In addition to the largeblock of tracts south of Kuparuk andPrudhoe, Pioneer also took three tracts onthe western edge of Kuparuk

Anadarko Petroleum took 16 tracts, allit bid on, paying $856,665.60.

AVCG took nine onshore tracts, bid-ding on 11, and paying $325,120, for areasfrom south of Badami in the east to adja-cent to the Colville River unit in the west.

ConocoPhillips took four of the fivetracts on which it bid, paying$160,102.40. These tracts are adjacent tothe Kuparuk River unit on the west andsouth.

Keith Forsgren took the four tracts hebid on just west of Kuparuk for$116,428.80.

Armstrong Alaska bid on two tractsand took one, for $39,091.20.

Establishing a land position Chris Cheatwood, Pioneer’s executive

vice president for worldwide exploration,told Petroleum News after the sale that thecompany bid on some 167,000 acres, andexpects to come away from the sale withabout 155,000 acres. In addition to the onetract it bid on but didn’t get, acreage totalswill drop once the state finalizes the titlework and provides exact acreage for eachtract.

The large onshore block Pioneer tookis between Prudhoe and Kuparuk, justsouth of established field infrastructureand just west of the trans-Alaska pipelineand the Dalton Highway.

Cheatwood said Pioneer had no imme-diate plans for the acreage.

“You’ve got to get established first,” hetold Petroleum News after the sale, “so wejust needed to look at a variety of differentopportunities up here and establish a landposition.”

Acquiring more seismic is the next stephe said, before the company and “putsome plans together and see what we cando on those lands.”

“Our company is working to build aportfolio of opportunities in Alaska,” saidKen Sheffield, head of Pioneer’s Canadaand Alaska operations, who was also inAnchorage for the sale.

Van Dyke said the large onshore blockis likely an oil play in shallower, youngersands. There are “stratigraphic-type playsdown through that area,” he said, andTexaco and Conoco drilled in the area inthe past.

As for the size of the block Pioneerpicked up, Van Dyke said that when

you’re looking “at some of those shallow-er sands and they’re stratigraphic plays …you have to pick up a big block ofacreage” to be sure “you can eventuallycover the whole prospect. … seismicallythey’re kind of difficult to map.”

Anadarko looking for partner “We’re basically completing our

acreage block,” Diane Kerr, AnadarkoPetroleum’s Alaska/Canada frontierexploration manager said after the sale.

Van Dyke said Anadarko has been col-

lecting acreage, “so they’re filling inaround the edges.” Anadarko took leaseson both the eastern and western edges of alarge block running east-southeast fromthe southern edge of the Prudhoe Bay unit.

John Bridges, Anadarko’s land supervi-sor, said the company has “consolidatedour acreage position on a prospect andwe’re currently looking for a partner orpartners.”

The company is interested in drillingon the prospect, he said, and could drill asearly as 2005. ●

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003 21THE REST OF THE STORY

continued from page 1

PIONEER

and force House and Senate negotiators tostrike a deal.

And while Republicans fight amongthemselves, Democrats continue to com-plain they are shut out of the private negoti-ations. “I’ve got to have a bill that can passthe Senate,” said Senate Finance ChairCharles Grassley, R-Iowa, and the chiefproponent of keeping the federal tax breakfor corn-based ethanol. “The Democrats areticked off that they’re not in conference.”

Farm-state senators in agreement Although Democrats are not at the table,

Senate Democratic Minority Leader TomDaschle, D-S.D., is right next to his agricul-tural-state brethren Grassley in spirit andhas said over and over that the bill mustinclude the ethanol tax break or he wouldoppose the entire measure.

Other contentious issues include tradabletax credits for rural electric cooperativesand municipalities, conservation issues,Clean Air Act amendments, liabilitywaivers for gasoline fuel additive produc-ers, tax credits for coal and oil and gas pro-duction, nuclear power, and even a landfillgas tax credit.

Grassley’s big push for ethanol produc-ers has been to insist on continuing the fed-eral tax break of knocking off 5.2 cents fromthe 18.3-cent-per-gallon federal highway

tax for fuel blended with ethanol. Butinstead of continuing to short the FederalHighway Trust Fund to cover the tax break,he wants to change the law to have the costcome out of general tax revenues in thetreasury. Sparing the trust fund the pain ofcovering the tax credit would mean morefederal money for highway constructionnationwide.

California Republican Bill Thomas,chair of the House tax-writing Ways andMeans Committee, opposes shifting theburden for the ethanol tax break.

A lot of speculation,heavy oil part of itMany of the reports about what’s in or

out of the work-in-progress legislation aresomewhat speculative since negotiatorshave not released a new draft bill in morethan a month.

Among the other Alaska issues waitingfor final action is the state’s push to expandthe federal $3-per-barrel tax credit programfor heavy oil to include the North Slope.“Heavy oil is definitely still in play,” saidJohn Katz, head of the state of Alaska’sWashington, D.C., office.

Expanding the tax incentives to includethe slope could lead to a significant boost inproduction from the area’s massive heavyoil deposits.

“Nobody has seen new language in along time,” Katz said. “It’s pretty clearCongress is not adjourning Nov. 7,” its the-oretical pre-Thanksgiving deadline, Katzsaid. ●

continued from page 5

PRESSURE

Bill Van Dyke, petro-leum manager atthe Division of Oiland Gas, said “BPcertainly facilitatedsome of this activi-ty, made it happensooner rather thanlater.” Companiesinterested in BP’sprospects looked atits data “and thenBP offered to sellseismic packagesthat it controlled …for really goodprices.”

22 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003ADVERTISER INDEX

Companies involved in NorthAmerica’s oil and gas industry

ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS

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

Business Spotlight

AAgriumAir Logistics of Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Alaska Airlines CargoAlaska Anvil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Alaska CoverallAlaska Dreams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Alaska Interstate ConstructionAlaska Marine Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Alaska Railroad Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Alaska Rubber & SupplyAlaska TelecomAlaska Tent & TarpAlaska Textiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Alaska Valve & FittingAlaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Alaska’s PeopleAlliance, TheAlpine-MeadowAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Anchorage HiltonArctic Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Arctic Pacific EnterprisesArctic Slope Telephone Assoc. Co-op . . . . . . . . . . . . . . . . . . 21ArrowHealthASRC Energy Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Avalon Development. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

B-FBadger ProductionsBrooks Range SupplyCameronCapital Office Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Carlile Transportation Services. . . . . . . . . . . . . . . . . . . . . . . . . 3Chiulista Camp Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15CN AquatrainColvilleConam ConstructionConocoPhillips Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Cook Inlet Tug & BargeCrowley AlaskaCruz ConstructionDowland - Bach Corp.Doyon DrillingDynamic Capital Management . . . . . . . . . . . . . . . . . . . . . . . 20Engineered Fire and SafetyENSR AlaskaEpoch Well ServicesEra Aviation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12ESS Support Services Worldwide. . . . . . . . . . . . . . . . . . . . . . . 8Evergreen Helicopters of AlaskaEvergreen Resources Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . 5F.A.T.S.Fairweather Companies, TheFMC Energy SystemsForest OilFrontier Flying ServiceF.S. Air

G-MGolder Associates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Great Northern EngineeringGreat NorthwestH.C. PriceIndustrial Project ServicesInspirationsIntegrated Systems GroupIRF GroupJackovich Industrial & Construction SupplyJudy Patrick Photography. . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Jungle Jim’s FloorcoveringKenai AviationKenworth AlaskaKPMG LLPKuukpik Arctic Catering Kuukpik/VeritasKuukpik - LCMFLounsbury & Associates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Lynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Lynx Enterprises . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Machinery Technical SupportMapmakers of AlaskaMarathon OilMaritime HelicoptersMEDC InternationalMI SwacoMichael Baker Jr.Midtown Auto Parts & MachineMillennium HotelMWHMRO Sales

N-PNabors Alaska Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6NANA/Colt EngineeringNatco CanadaNEI Fluid TechnologyNIED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Nordic CalistaNorthern Air CargoNorthern LightsNorthern Transportation Co.Offshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oil and Gas Supply Co.Oilfield TransportPanalpinaPDC/Harris Group. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Peak Oilfield Service Co.Penco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Perkins Coie. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Petroleum Equipment & ServicesPetrotechnical Resources of AlaskaPGS Onshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13ProComm AlaskaPrudhoe Bay Shop & StoragePSI Environmental & Instrumentation

Q-ZQUADCOR & R Scaffold ErectorsSalt + Light CreativeScan HomeSchlumberger Oilfield ServicesSecurity AviationSeekins FordShred AlaskaSnowbird ManagementSOLOCO (Dura-Base)Sourdough ExpressSpan-Alaska ConsolidatorsSTEELFABStorm ChasersTaiga VenturesThrifty Car RentalTOTETotem Equipment & SupplyTravco Industrial Housing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Tucker Sno-CatUBS Financial Services Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Udelhoven Oilfield Systems Services . . . . . . . . . . . . . . . . . . . 4Umiat CommercialUnique MachineUnitech of AlaskaUnivar USA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8URSU.S. Bearings and DrivesVeco AlaskaWell Safe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Wood Group (Alaska)XTO EnergyZY-TECH Global Industries

Ron Schlappy, qualityassurance/process manager

Unique MachineUnique Machine specializes in oil-

field manufacturing and threadingsupport and is Alaska’s largestmachine shop. This 28-year old com-pany offers pipe threading and repair,valve repair and general machineshop and welding services. UniqueMachine’s dedicated employees bringyears of welding and processingexperience to their clientele.

Ron Schlappy started machiningin 1971 and later became manufac-turing manager of an aircraftmachine shop in Wichita, Kan. (wherethey call mountains grain elevators).Ron came north from Kansas fiveyears ago, leaving Dorothy and Totobehind. He promptly gave up scubadiving but enjoys hunting, fishing andflying remote control airplanes. ThisJuly Ron and the love of his life,Patricia, were married atop ChugachState Park’s Rendezvous Peak.

HEA

THER

YA

TES

Michael Hart, president

Lynden Air Cargo LLCMail delivery comprises some 40

percent of Lynden Air Cargo’s Alaskabusiness; the rest is cargo and char-ters. Lynden is the oil spill responsecarrier for Alyeska Pipeline Service Co.Based in Anchorage, Lynden providesscheduled services to Nome, Kotzebue,Bethel and Dillingham. It also main-tains operations for scheduled militaryairlifts in Yokota, Japan and Ramstein,Germany.

Michael Hart joined Lynden AirFreight in 1984 as Alaska regionalsales manager. In 1995 he led thestartup of Lynden Air Cargo. Earlier,with Airborne Freight, Mike managedthe firm’s pipeline construction activi-ties. He spends “way too much timeplaying golf, at the expense of fishing,skiing and other enjoyable pastimes.”The Harts’ two sons and daughterhave families of their own — fivegrandchildren to adore.

FOR

RES

T C

RA

NE

By PAULA EASLEY

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003 23THE REST OF THE STORY

Because of a tangle of federal and provin-cial regulations, the producers’ associationhas estimated it takes twice as long to getapprovals for Canada’s East Coast as it doesfor the British North Sea.

Also on the agenda for Williams is thefuture of the Chevron Canada Resources-operated Hebron-Ben Nevis project that wasshelved 18 months ago because of poor eco-nomics. But Chevron, with its partnersExxonMobil, Petro-Canada and NorskHydro Canada, has reportedly restarted talkswith Newfoundland on the C$3 billion proj-ect, seeking more favorable terms for devel-oping the 400 million-600 million reservoir,of which 75 percent is heavy oil.

A report by RBC Financial Group saidthe prospects of accelerating hydrocarbondevelopment in offshore Newfoundlandhinges on the future of Hebron-Ben Nevisand whether a boundary dispute can beresolved to allow exploration of the OldHarry natural gas prospect in the Gulf of St.Lawrence.

—GARY PARK, Petroleum News Calgary correspondent

continued from page 1

NEWFOUNDLAND

Association of Oilwell Drilling Contractors.Both are also counting on 18,000-19,000

well completions in 2004, giving Canadasuccessive years above the 2001 record of17,945 wells.

The services association, noting that arecord 7,000 wells were drilled in the thirdquarter, said average prices of C$6.50 perthousand cubic feet for gas and US$30.50per barrel of oil have kept producers “verymotivated” to drill throughout the year.

“By working to level out their annualdrilling cycle, companies have been able toattract and retain employees, which setsthem up well for the next phase of drillingactivity,” said Petroleum ServicesAssociation of Canada President RogerSoucy.

While slightly less ambitious in its out-look, the drilling contractors association ispredicting 18,023 wells in 2004 comparedwith the services association’s 18,965.

Martin Molyneaux, an analyst withFirstEnergy Capital, told a PetroleumServices Association of Canada conferencethat that oil will likely average US$27 perbarrel in 2004, with gas fetching US$4.75per million British thermal units through the

year.

Alberta drilling will be down The services association breakdown

includes 13,835 wells in Alberta, down 8percent from this year’s expected tally;Saskatchewan 3,800, down 5 percent; andBritish Columbia 1,100, up 9 percent as thatprovince pulls out the stops to acceleratedevelopment of its northeastern gasprospects.

In addition to northeast BritishColumbia, Soucy said next year’s strengthwill be concentrated in the shallow gasareas of southeastern Alberta and south-western Saskatchewan.

With more rigs expected to be runningthis winter than ever before, following newbenchmarks through the past summer, thedrillers’ association raised its forecast for2003 well completions to 19,423, easilysurpassing its original target of 17,532.

But if the expected 86 percent utilizationrate for the fleet of 681 rigs is to be achievedin next year’s first quarter, CanadianAssociation of Oilwell Drilling ContractorsPresident Don Herring said another 3,000rig hands will be needed, pushing totalemployment for the three months to 15,000.

However, the drillers’ association pre-dicts the number of rig operating days in2004 will drop to 120,6000 from the

128,159 total expected in 2003, whichshould help contractors avoid last winter’smanpower squeeze when some rigs wereforced to shut down temporarily to givecrews time off.

Rig utilization expected at 63 percent The rig utilization rate for all of this year

will be about 63 percent, compared with lastyear’s 46 percent, and is forecast to reach 58percent in 2004, assuming average com-modity prices of $27 a barrel for West TexasIntermediate crude and $4.75 per thousandcubic feet on the New York MercantileExchange.

The robust state of the industry isspilling over in other sectors, includingsteelmaking, Illinois-based IPSCO report-ed.

President and Chief Executive OfficerDavid Sutherland said the pipe-makingbusiness is on track for record sales this yearand a new order for 150,000 tons of large-diameter pipe ensures production atIPSCO’s spiral mill through the first half of2004.

He said sales to Canada rose toUS$127.4 million in the third quarter fromUS$83.14 million a year earlier, whileCanadian sales for the first nine monthswere C$346 million up from C$249 mil-lion. ●

continued from page 1

WELLS

Those acquisitions also helped boostApache production 34 percent above lastyear’s third quarter and 5 percent abovethis year’s second quarter. Oil volumesalone rose 51 percent to 228,698 barrelsper day, while natural gas volumesincreased 19 percent to 1.26 billion cubicfeet per day and natural gas liquids 20percent to 9,686 barrels per day.

Apache also got a boost from the thirdquarter startup of the Zhao Dong oil fieldin China, currently yielding 16,000 bar-rels per day, 60 percent net to Apacheuntil capital and carried funds are recov-ered. Apache actually holds a 24.5 per-cent stake in the field. Moreover, discov-eries during the quarter in WesternAustralia’s offshore Exmouth sub-basin,coupled with more drilling successes inEgypt, have added future productionpotential in both of those Apache coreareas, the company noted.

More than $2 billionin cash from operations

Increased production and strong com-modity prices during the first nine months ofthis year have propelled Apache’s cash fromoperations to over $2 billion, more than theprevious full-year record of $1.9 billion in2001, the company said. Cash from opera-tions during the 2003 third quarter alone was$730 million, up 14 percent from the priorquarter and up 81 percent versus the sameperiod last year.

Apache said all of this activity is expect-ed to land the company about $1 billion indiscretionary cash by year-end, and the deal-minded independent indicated last monththat it could do yet another big acquisitionthis year. But in a recent conference call withanalysts, company officers kept their plansto themselves.

However, Steve Farris, Apache’s chiefexecutive officer, made it clear the companyfinds international properties today moreappealing than North American natural gasproperties, presumably because of the stiff

competition and related high cost associatedwith quality properties. “International is bet-ter because it’s not as frothy as NorthAmerica,” he said.

Despite Apache’s strong balance sheetand rapid production growth this year, thecompany has received mixed reviews fromthe analysts.

In a report to investors, Prudential analystJason Gammel said his firm expects Apacheto increase production 22 percent this yearand 17 percent in 2004. Apache already gen-erates the highest free cash flow per share inthe exploration and production sector, hesaid, adding that Prudential believes Apache“has the strongest balance sheet of the (sec-tor) under our coverage.”

Lehman Brothers analyst Tom Driscoll isforecasting 23 percent production growthfor Apache in 2003 but only a 9 to 10 per-cent increase in 2004, about 8 percent lowerthan Prudential’s estimate. However,Lehman’s model “does not assume anyacquisitions that (Apache) may make overthis time period,” a doubtful scenario givenApache’s track record on deals. ●

continued from page 1

APACHE

24 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2003ADVERTISEMENT