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23Pioneer Natural Resources looksto build Alaska drilling portfolio

Vol. 9, No. 23 • www.PetroleumNews.com North America’s source for oil and gas news Week of June 6, 2004 • $1

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3 Another 165 feet of net oil pay: K2 North satellite discov-

ery in the deepwater Gulf of Mexico produces more for Anadarko

4 One more Alaska gas line plan: Calgary-based pipeline

operator TransCanada submits application, says 2012 start-up possible

11Offer for Healy coal plant rejected: Golden ValleyElectric’s $70 million offer for clean coal plant rejected by AIDEA

Enstar sets record on west side

Enstar installed the longest horizontal directional drilled pipe inAlaska when it replaced a portion of 20-inch transmission line lastwinter on the west side of Cook Inlet. The line was in danger ofbeing washed out after middle channel of the Susitna Rivermoved. See story on page 14.

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Noble Energy to expandGulf deepwater program

By RAY TYSON Petroleum News Houston Correspondent

oble Energy says it intends to accelerateexploration and development activity in thedeepwater Gulf of Mexico, hoping to carveout a third core area in the region, while pur-

suing more geologically deep natural gas plays inshallower waters of the Gulf’s continental shelf.

Over the past few years, the Houston-basedindependent has quietly assembled and evaluatedan impressive acreage position in the deepwaterGulf and appears ready to strike on the explorationfront.

“We haven’t drilled that many wells over thelast few years purposely,” Dick Peneguy, Noble’soffshore manager, said in a May 26 meeting withindustry analysts. “We have been generating moreprospects than we have drilled. We have now puttogether a multi-year prospect portfolio.”

Discovery in first quarter Actually, Noble began putting its foot to the

pedal in the deepwater Gulf during the 2004 firstquarter, announcing a discovery at its Ticonderogaprospect and increasing its working interest in two

Canadian oil sands productionexpected to double by 2015Report says country would move to fourth in ranks of world’s oil producers

By DON WHITELEY Petroleum News Contributing Writer

National Energy Board report says produc-tion from Canada’s oil sands is expected toreach 2.2 million barrels of oil a day by 2015,more than double today’s production.

In a special report entitled Canada’s Oil Sands:Opportunities and Challenges to 2015, theNational Energy Board says the increased produc-tion will move Canada from ninth place to fourthplace in the world’s rankings of oil producers.

But with global demand expected to be about80 million barrels of oil per day in 2015, the oil

sands won’t make a big splash on the world scene.

Reserves estimated at 178 billion barrels Canada’s oil sands deposits, located mostly in

Northern Alberta, are considered to be one of thelargest hydrocarbon deposits in the world, withreserves estimated at 178 billion barrels.

But extracting oil from the sands is an energy-intensive, costly process, and production is eco-nomic only at relatively high prices for both oiland natural gas. For this report, the NationalEnergy Board based its projections on an oil priceof $24 per barrel, and an equivalent natural gas

Talisman high bidderBureau of Land Management’s NW NPR-A sale draws 123 bids for 165 tracts

By KRISTEN NELSONPetroleum News Editor-in-Chief

ive companies, singly and in partnerships, putup $53,904,491 in high bonus bids at theBureau of Land Management’s northwestNational Petroleum Reserve-Alaska sale in

Anchorage June 2. Bidders were: Anadarko Petroleum Corp.,

ConocoPhillips Alaska Inc., Pioneer NaturalResources Alaska Inc., Petro Canada Alaska Inc.and Fortuna Exploration LLC.

The highest bid, $13,745,000, was fromTalisman subsidiary Fortuna for tract D-19, 14,451acres near the Ikpikpuk River, at the junctionbetween the northwest and northeast NPR-A plan-

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see OIL SANDS page 27

see NOBLE page 26

Husky eyes Newfoundland gasfrom White Rose within a decade

Husky Energy is taking one of the boldest steps yet to exploitoffshore Newfoundland’s natural gas potential.

The Canadian integrated, which is operator of the White Roseoil field, is now exploring the viability of producing and trans-porting gas from the same field.

It has invited expressions of interest from contractors and engi-neering firms to weigh the key technical, economic and regulato-

CBM could accountfor 20% of Canada’sgas output by 2020

The long-range importance of coalbedmethane in Canada’s gas supply picture hasbeen emphasized by an executive withNexen, who predicts the resource couldgrow to 1 billion cubic feet per day by 2008and 3 bcf per day by 2024.

Mike Simpson, coalbed methane manager at Nexen, told aCalgary audience May 27 that Canada is following the trend in the

see HUSKY page 27

MIKE SIMPSON

see OUTPUT page 26

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See full map, page 13see LEASE SALE page 12

2 PETROLEUM NEWS • WEEK OF JUNE 6, 2004RIG REPORT

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point, rig workover MPF-18 BPSky Top Brewster NE-12 15 (SCR/TD) Deadhorse yard AvailableDreco 1000 UE 16 (SCR) W pad workover W-20 BPDreco D2000 UEBD 19 (SCR/TD) Alpine, drilling CD2-57 ConocoPhillipsOIME 2000 141 (SCR/TD) Infield Kuparuk, drilling 1E-123 ConocoPhillips

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES (SCR) Prudhoe Bay, 01-04A BPMid-Continent U36A 3-S Prudhoe Bay, 2T-220 ConocoPhillipsOilwell 700 E 4-ES (SCR) Prudhoe Bay, X-16 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay, A-30 BPDreco 1000 UE 9-ES (SCR/TD) Prudhoe Bay, V-02 BPOilwell 2000 Hercules 14-E (SCR) Stacked, Deadhorse AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked, Prudhoe Bay AvailableOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableOIME 1000 19-E (SCR) Stacked, Deadhorse ConocoPhillipsEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Stacked, Kuparuk ConocoPhillips

Nordic Calista ServicesSuperior 700 UE 1 (SCR/TD) Drill site 2 well 24 BPSuperior 700 UE 2 (SCR) Endicott, drill site 14 well 6A BPIdeco 900 3 (SCR/TD) Meltwater, drill site 3N-311 ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E (SCR/TD) Stacked, NorthStar BPEmsco Electro-hoist Canrig 1050E 27-E (SCR/TD) Stacked at 12-acre pad Kerr-McGee

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Nicolai Creek, NCU3 workover Aurora Gas

Evergreen Resources AlaskaWilson Super 38 96-19 Moving into data evaluation from

core drill Evergreen ResourcesAlaska Corporation

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

Kuukpik 5 Swanson River, drilling 241-16 Unocal

Marathon Oil Co.(Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Working on well Beaver Creek #12 Marathon

Nabors Alaska DrillingRigmasters 850 129 Kenai, Red #1 UnocalNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 Stacked, Kenai Available

51 Steelhead platform, done 12-1-03 UnocalIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform Available

Water Resources InternationalIdeco H-35 KD Prep to resume operations Pelican Hill

Cook Inlet Basin – Offshore

Cudd Pressure Control 340K Workover, Osprey Platform Forest Oil

Unocal (Nabors Alaska Drilling labor contractor)Not Available

XTO Energy (Inlet Drilling Alaska labor contract)National 1320 A Idle IdleNational 110 C (TD) Idle XTO

Mackenzie Rig StatusMackenzie Delta-Onshore

AKITA EqutakDreco 1250 UE 62 (SCR/TD) Stacked Tuktoyaktuk, NT EnCanaDreco 1250 UE 63 (SCR/TD) Stacked, Lucas Point, NT Chevron CanadaNational 370 64 Stacked, Inuvik, NT Available

Central Mackenzie ValleyAKITA/SAHTUOilwell 500 51 Stacked in Norman Wells, NT Available

Nabors Canada62 Racked Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of June 3, 2004.

Active drilling companies only listed.

Rig start-ups expected in next 6 monthsRig Owner/No. Rig Location/Activity Operator

Aurora GasAWS1 Will be moving to Kaloa 3 and then to

Long Lake 1 for a re-entry Aurora Gas

XTO EnergyA & C Planning on firing the rigs back up by

the end of summer 2004 XTO

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*

May 28 May 21 Year AgoUS 1,169 1,172 1,059Canada 195 201 258Gulf 93 91 110

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:

Osprey platform JUDY PATRICK

EXPLORATION & PRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22FINANCE & ECONOMY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6LAND & LEASING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12NATURAL GAS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19NORTH OF 60 MINING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10ON DEADLINE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3PIPELINES & DOWNSTREAM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14

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Issue Index

Petroleum News (ISSN 1544-3612) Week of June 6, 2004Vol. 9, No. 23

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GULF OF MEXICODeepwater Gulf’s K2 North producesanother 165 feet of net oil pay for Anadarko

Anadarko Petroleum has found another 165 feet of net oil pay at its 100 percentowned K2 North satellite discovery in the deepwater Gulf of Mexico, greatly expand-ing the field’s size and firmly establishing it as a commercial discovery.

The K2 North field, on Green Canyon block 518, is nowexpected to begin production through the nearby Marco Poloplatform in 2005, Anadarko said June 2, noting that the field’soil-water contact has yet to be established.

“We have yet to determine the field limits, but the delineationwell extends the discovery significantly,” said Jim Hackett,Anadarko’s chief executive officer.

The well’s bottom-hole location is about one mile northwestof Anadarko’s K2 North No. 1 discovery, which was announcedin November 2003.

The K2 North exploration well, including a water depth of4,000 feet, was drilled to a depth of 26,700 feet and was thedeepest offshore well drilled in Anadarko’s history. The subsaltwell encountered 128 feet of net oil pay in the same zone present at Anadarko’s K2 dis-covery.

Reserve estimates for the K2 North field have not been disclosed. But the initialexploration well extended the K2 field two miles north.

The No. 2 well was spud in December 2003 in about 4,000 feet of water and wasdrilled to a total depth of 29,180 feet. The semi-submersible rig remains on location tofurther delineate the field, Anadarko said.

Jim Hackett,Anadarko’s CEO

see ANADARKO page 4

TransCanada submitsapplication to state, says2012 start-up possible

By LARRY PERSILYPetroleum News Government Affairs Editor

ssuming everyone involved in the pro-posed Alaska natural gas line projectcan strike a deal to divvy up the finan-cial risks, and assuming no permitting

delays or other political or regulatory prob-lems, TransCanada Corp. said it believes itcould help build the pipeline and have gasflowing by 2012.

The Calgary-based pipeline operatorsubmitted an application June 1 underAlaska’s Stranded Gas Development Act,the fifth such application the state hasreceived since late January to negotiate along-term fiscal deal for payments in lieu ofall state and municipal taxes on the pro-posed pipeline.

“This project is complex and entails sig-nificant risk. Its success — and similarly the

future well-being of the Alaska economy —will depend upon the goodwill and coopera-tion of many stakeholders,” the companysaid in its application.

TransCanada has said it does not want toown the gas or take the risk of future com-modity prices but it does want to hold aninterest in the pipe and perhaps share theequity with others, including possiblyAlaska Native corporations. “The natureand size of that interest will be determinedlater as the commercial structure of the pro-posed pipeline project becomes betterdefined,” it said.

The company proposes a 48-inch-diame-ter line from the North Slope to BoundaryLake in northern Alberta, carrying 4.5 bil-lion cubic feet per day, feeding into existingpipeline systems for distribution acrossNorth America. That equals almost $6 bil-lion worth of gas a year, at $3.50 per thou-sand cubic feet, with transportation chargesexpected to consume more than half of thatamount.

Construction of the 745 miles of pipe inAlaska is estimated at $6.8 billion in 2004dollars. TransCanada did not provide an

estimate for the almost 1,000 miles of pipein Canada or the extensions required for itsexisting pipeline system. The estimate alsodoes not include the $3 billion or so thatNorth Slope producers would need to spendon a conditioning plant on the slope toremove carbon dioxide, water and otherimpurities before putting the gas into theline.

2012 start-up contingenton shipping contracts

The 2012 start-up date is contingent ongetting contracts with shippers in 2005 andstarting construction in late 2009,TransCanada said. Ship-or-pay contractscould provide the financial security neededto borrow money for construction.

TransCanada believes a 1977 U.S. regu-latory certificate and 1978 Canadian certifi-cate to build an Alaska gas line give it exclu-sive rights to the project, saving two years ofpermitting work that would confront anyother project developer. The company alsoholds right-of-way permits for much of theroute, left over from unsuccessful develop-ment efforts in the 1970s and 1980s.

Other gas line hopefuls, however, dis-pute TransCanada’s exclusive rights to anygas line development, and it’s likely theissue will need to be resolved as the compa-ny, North Slope producers, U.S. andCanadian agencies and others try to puttogether a team to build the line.

The certificates are held byTransCanada’s wholly owned subsidiariesFoothills Pipe Lines Ltd. and AlaskanNorthwest Natural Gas Transportation Co.,which was formed in 1978 to build the linefrom Prudhoe Bay to the Alaska-YukonTerritory border.

Regardless of the regulatory dispute,TransCanada’s far-reaching pipeline net-work offers strong opportunities to moveAlaska gas from the end of any new pipe inAlberta.

TransCanada offers access to several markets

“TransCanada’s network of pipelineassets provides Alaskan gas with unparal-leled access to growing markets across thecontinent,” the application said. “ThePacific Northwest and California; the U.S.Midwest, including the Chicago hub; east-ern Canada; and the U.S. Northeast, includ-ing New England and New York City.”

TransCanada’s proposal is similar to itsCalgary colleague Enbridge Inc., whichsubmitted its application to the state April 30and also touted its ability to use existinglines to move Alaska gas out of Alberta toMidwest markets. Enbridge, however, pro-posed using 36-inch pipe to reduce the risksof construction cost overruns and possiblydelivering too much gas to market tooquickly. If the market could handle moregas, the company would run a second line,with each carrying 2.6 bcf per day.

In addition to Enbridge andTransCanada, the state has received aStranded Gas Act application from the threemajor North Slope producers.

It also received an application in Januaryfrom MidAmerican Energy Holdings Co.,which later withdrew its application afternegotiations with the state broke down, andfrom the municipally owned Alaska GaslinePort Authority, which withdrew its applica-tion last month after electing to sign aninformation-sharing protocol with the stateinstead of negotiating a fiscal contract. �

4 PETROLEUM NEWS • WEEK OF JUNE 6, 2004ON DEADLINE

“This well also has positive implicationsfor the neighboring K2 field,” Hackett said.Anadarko holds a 52.5 percent interest inthat field.

The K2 field also will be tied back to theMarco Polo platform with first productionexpected next year. Anadarko said it is cur-

rently completing the first of six pre-drilleddevelopment wells from its Marco Polofield, which is on schedule for first produc-tion in July 2004.

The Marco Polo platform was designedto handle up to of 120,000 barrels per day ofoil and 300 million cubic feet per day of nat-ural gas. Anadarko made its first deepwaterGulf discovery at Marco Polo in 2000.

—RAY TYSON, Petroleum News Houston correspondent

continued from page 3

ANADARKO

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One more Alaska natural gas line plan

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JUNEAUPersily called back into state service

Larry Persily, Petroleum News’ government affairs editor, isleaving the weekly Anchorage-based newspaper to go back intostate government.

Persily, who had been a Juneau-based journalist for a numberof years prior to going to work for the Knowles administration,was a special assistant to the commissioner of the Department ofRevenue from 1997-99, and then a deputy commissioner from1999-2003.

On August 4 he came to work for Petroleum News as aJuneau correspondent. Persily was promoted to governmentaffairs editor earlier this year.

At the request of the Murkowski administration, Persily is returning to Revenue asa special assistant to Commissioner Bill Corbus, effective June 14. He will be workingon gas line issues, as well as oil and gas fiscal issues.

LARRY PERSILY

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PETROLEUM NEWS • WEEK OF JUNE 6, 2004 5ON DEADLINE

� M A L I B U , C A L I F .

Malibu votes no on LNGCity council opposes two proposed offshore receiving terminals

By LARRY PERSILYPetroleum News Government Affairs Editor

lthough it has no jurisdiction overeither project, the Malibu CityCouncil has voted unanimously tooppose two liquefied natural gas

receiving terminals proposed for watersnorth of the California coastal community.

One of the proposed projects is lookingto become a main receiving terminal forAlaska LNG.

Fear of terrorist attacks and environmen-tal damages from the offshore terminals andthe tankers that would move through thearea motivated the council vote, said MalibuCity Manager Katie Lichtig. “There’s a pos-sibility and a risk that our community couldbe impacted.”

She acknowledged that any worry ofdamage to marine resources primarilyinvolves recreational opportunities for thetown of 13,000 residents. Malibu is about 25miles south of where the gas would comeashore in buried pipe near Oxnard. The ter-minals would be about 15 to 20 miles fromMalibu. The city of Oxnard, which wouldhave to approve the pipelines coming onshore, has questioned both projects in lettersto state and federal officials but has nottaken such a strong step as Malibu’s citycouncil resolution.

“In a day and age when they can flyplanes into the Twin Towers, I see no reasonthey couldn’t do the same thing with liquidgas and obliterate a couple of coastal com-munities,” Malibu Mayor Sharon Barovskytold the Los Angeles Times May 25, the day

after the city council vote.

Developers say risk is overstatedThe projects’ developers — and support-

ers of LNG terminals to meet the nation’sgrowing demand for natural gas — say thesuper-chilled gas is not nearly as volatile ascritics allege, and that double-hull tankers,other safety features and port security wouldminimize the risk to residents.

Developers of the two proposed termi-nals are Crystal Energy LLC, a Houstoncompany that wants to break into the LNGterminal business, and Australian miningand energy giant BHP Billiton. Both havestarted the application process for permits,and both hope to get online in three or fouryears. Crystal Energy has a memorandum ofunderstanding with the Alaska Gasline PortAuthority to work toward converting a 25-year-old former Chevron oil productionplatform in the Santa Barbara Channel intoan LNG receiving terminal.

The port authority, a joint venture of thecity of Valdez and Fairbanks North StarBorough, wants to build a municipallyowned pipeline to move North Slope gas toValdez for liquefaction and shipment toWest Coast and Far East markets.

And in a bid to assist BHP to gain entryto the California natural gas market,Australian Prime Minister John Howardvisited Los Angeles and met withCalifornia Gov. Arnold Schwarzeneggerwhile on a U.S. tour the last week of May.The prime minister was looking to helpbuild support for bringing LNG to WestCoast consumers. �

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HOUSTON, TEXASFront Runner spar installed in Gulf

Project troubled J. Ray McDermott, themarine construction unit of oilfield servicecompany McDermott International, hasfinally completed installation of the FrontRunner production spar in deepwater Gulfof Mexico, the company said June 1.

In March, McDermott projected about$85 million in negative cash flow duringthe first, second and fourth quarters of2004, due to additional costs associatedwith completion of its Front Runner spar,as well as the Carina Aries project inArgentina, and the Belanak FPSO BatamIsland facility.

J. Ray said it installed the 6,220 shortton topsides on the Front Runner spar hulland has commenced hook-up and commis-sioning activities. The spar is moored in3,330 feet of water in the Gulf of MexicoGreen Canyon block 338, about 100 milessouth of Fourchon, La.

The lift was completed using J. Ray’s Derrick Barge 50 and Oceanic 93 “Shear LegCrane.” The Front Runner project is operated by Murphy Exploration & Production.Partners are Dominion Exploration & Production and Spinnaker Exploration Co.

J. Ray also said it was awarded a $47 million contract by Apache Energy, a sub-sidiary of Houston independent Apache Corp., on behalf of the WA-214P joint ventureparticipants, to procure, fabricate, transport and install the John Brookes platform andpipeline system offshore the North West Shelf in Western Australia.

J. Ray said it will fabricate the jacket and piles at its Batam Island, Indonesia, facil-ity beginning in August 2004. Loadout of the substructure is expected to take place inJanuary 2005. The pipeline and platform will be installed using J. Ray’s combinationDerrick Barge DB26 commencing mid-January 2005.

Additionally, J. Ray has been awarded a contract by its Mexican joint venture com-pany Construcciones Maritimas Mexicanas, valued at about $60 million. The contractbetween J. Ray and CMM calls for the charter of J. Ray’s Derrick Barge 101, ShearLeg Crane and Intermac 404, as well as related engineering work.

—RAY TYSON, Petroleum News Houston correspondent

J. Ray McDermott's DB50 and Shear LegCrane perform the dual lift of the 6,220short ton topsides on the Front RunnerSpar hull.

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MAJORVILLE, ALBERTACanadian junior sets major drilling program

Junior E&P company Endev Energy is poised to launch a drilling program in theMajorville area of southeastern Alberta, including 50 wells this spring.

So far, 21 wells have been drilled and cased and are ready for completion and tiein, likely in July. Assuming upbeat results, Endev plans a 90-well program in the samearea, hoping for tie-ins in the final quarter. The company’s production grew by 189percent in the first quarter from a year earlier to 3,428 barrels of oil equivalent per day,stemming from increased gas output from the Majorville area. Gas volumes were upby 82 percent to 14.45 million cubic feet per day, boosted by a C$22 million takeoverin mid-2003 of Moxie Exploration. Endev’s capital budget for 2004 is C$32 million,financed from available bank credit, existing working capital and cash flow, withC$22 million tagged for the core southeastern Alberta area.

—GARY PARK, Petroleum News Calgary correspondent

ATTENTION PETROLEUM NEWS READERSPart 3 of Heinze interview coming next week

Parts 1 and 2 of in interview with Harold Heinze, executive director of the AlaskaNatural Gas Development Authority, appeared in May editions of Petroleum News.Part 3 will appear in the June 13 issue.

For the love of a Golden RetrieverThe Midnight Sun Golden Retriever Club is hosting a Golden Retriever Family Fun

Day on Saturday, June 5, at the Waldron Park Soccer field in Anchorage. Activitiesinclude a silent auction, relay races, agility introduction, best tricks, a talent show and lotsof games. Email info@msgrc.org or call Ken at 907 345-4072 for more information.

6 PETROLEUM NEWS WEEK OF JUNE 6, 2004

finance&economywww.PetroleumNews.com

MOSCOW, RUSSIAU.S. energy secretary: U.S.,Russia should move fromwords to deeds on oil exports

The United States wants to increase imports of natural gas and oilfrom Russia but the two countries must move from words to deeds toget it accomplished, U.S. Energy Secretary Spencer Abraham saidMay 28.

“We want to see Russian oil and gas more available to the U.S.market,” Abraham said at a business round-table in Moscow.

“This could be done via a northern Russian port,” he said, addingthat the Baltic Pipeline System would be a key element in thisprocess.

Abraham said he was satisfied with his discussions on the issuewith Russian authorities on May 27, but said no exact dates had beenset.

“It’s too early to say when it will happen,” he said, warning thatthe projects would demand “substantial investment”.

However, he said it was the time for Russia and the United Statesto “move beyond the talking state” to a more “action-oriented” focus.

He said the fact that Russian President Vladimir Putin had calledfor an increase in Russia’s oil export capacity in his state of the nationaddress was “very positive news for the energy market”.

In order to accelerate an increase in Russian oil exports, the U.S.government will encourage American companies to take part inRussian energy projects, Abraham said.

Abraham traveled to Russia to sign an agreement on removinguranium fuel from dozens of Soviet-built nuclear reactors worldwideto prevent it from falling into terrorists’ hand.

—THE ASSOCIATED PRESS

CANADAE&P companies fight back inCanadian M&A market

After starting to lag behind income trusts in 2003, the traditionalE&P sector made a comeback in the first quarter of 2004, accordingto Calgary-based Sayer Securities, which tracks the M&A market.

The firm said E&P companies spent C$2.8 billion on acquisitionsin the January-to-March period, or about 74 percent of all M&Atransactions, compared with 50 percent for all of last year.

Leading the trend shift were British Gas Group, which acquiredEl Paso Oil and Gas Canada for C$456 million and ThunderEnergy’s C$147 million purchase of Impact Energy.

Sayer said the E&P companies are showing their muscle by com-peting strongly for assets and takeover targets with “upside” such aslarge probable reserves and undeveloped land with drilling potential.

Thunder reflected that approach by paying about C$70,000 perdaily producing barrel of oil equivalent, compared with the medianacquisition price of just under C$27,000 per boe in 2003.

see FIGHT page 7

� H O U S T O N , T E X A S

Panel rejects Leucadia’sbid for Plains ResourcesThe Leucadia group failed to improve its March 19 proposal, Plains’special review committee said; it had expected a ‘superior proposal’

By RAY TYSON Petroleum News Houston Correspondent

special committee formed to review offers forindependent Plains Resources has rejected a bidfrom an investment group led by LeucadiaNational and Pershing Square, appearing to

strengthen the hand of a rival investment group led byMicrosoft co-founder and billionaire Paul Allen.

Plains already has entered into a merger agreementwith the Vulcan Group, a subsidiary of Allen’s VulcanCapital, to acquire Plains for $16.75 per share in cash,or roughly $400 million based on the company’s mar-ket value. Vulcan’s initial bid of $14.25 per share wasrejected by Plains’ board of directors.

In addition to Allen, the Vulcan takeover teamincludes Plains Chairman James Flores and ChiefExecutive Officer John Raymond, the son ofExxonMobil Chairman Lee Raymond. The deal

would require shareholder approval. Leucadia’s offer for Plains, considered after the

board accepted Vulcan’s offer, proposed that Plainsstockholders receive a combination of cash, preferredstock, and debt securities that would be issued byPlains.

According to Securities and ExchangeCommission filings, Pershing Square, which owns5.33 percent of Plains’general partnership, proposed a$75 million cash offer, which would pay Plains share-holders $3 per share, with the balance in new, unreg-istered securities to be issued by a new holding com-pany. Those securities would be valued between $17and $17.60 a share, according to SEC documents.

Committee expected “superior proposal” Nevertheless, the Plains special committee said

A

� C A N A D A

How trusts will surviveExperts count on acquisitions rather than drill bit to fuel sector; expectenergy trusts to tighten screws on cash flow distributions to unit holders

By GARY PARK Petroleum News Calgary Correspondent

anada’s energy trusts will grow through deal-making rather than the drill bit, those involvedin the trust sector told a Conference Board ofCanada seminar at the end of May.

Although the market capitalization of the trustsnow stands at C$26 billion, a 13-fold increase from1998, the trust firms account for only 11 percent ofproduction from the Western Canada Sedimentarybasin, meaning there is ample room for expansion,said Bruce McDonald, an analyst at CanaccordCapital.

He said the trusts, aided by their low capital costs,can outperform the conventional E&P companiesthrough both acquisition and exploration during aperiod of sustained high commodity prices.

Keith McPhail, chief executive officer ofBonavista Energy Trust, said one of the biggestheadaches facing the trusts has been a sharp per-unitdecline in production and reserves.

But he is confident the trusts are now taking meas-ures to more efficiently replace those losses as theyrealize that the cash flow paid out to unit holdersneeds to be trimmed.

To reinforce that trend, trusts must also hire strongtechnical teams and provide them with undevelopedland and strategic, timely acquisitions.

Those who can achieve those ends “with the leastamount of capital” will emerge on top, McPhail said.

On a broad front, he is certain trusts that com-bine a technical focus, low costs and reasonablepayouts will survive, even if some are forced into

C

see BID page 7

see TRUSTS page 7

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 7FINANCE & ECONOMY

To trim that ultimate acquisition priceand boost production from the assets,Thunder will inject the needed capital togrow Impact’s large base of non-producingreserves, Sayer said.

For British Gas, the El Paso packageincluded 630,000 net acres of undevelopedland that the buyer believes holds consider-able exploration potential that will supportits drilling plans for many years.

Another new wrinkle on the M&A frontwas demonstrated by Great NorthernExploration, which paid C$39,000 per boefor assets in the central Alberta area, with

about 40 percent classified as proved non-producing or probable. But the deal was astrategic fit for Great Northern whichincreased its working interest in the area to97 percent from 65 percent.

Bolstering the competitiveness of theE&P companies was the backing of capitalmarkets, Sayer said, noting that for 2003E&P equity financings of C$2.4 billion wereup 118 percent from 2000, the best annualdollar figure for six years.

Sayer said the attractiveness of E&Pequity in the stock market has enabled thosecompanies, in some circumstances, to tradeat high enough values to compete withincome trusts on acquisitions.

—GARY PARK, Petroleum News Calgary correspondent

� A L A S K A

Reserves continue tomake Alaska attractiveCosts high, taxes moderate, for low overall return oninvestment; state now attracting medium-sized, not big players

THE ASSOCIATED PRESS laska remains the most costly placeon the planet to produce oil and gasbut the state could take steps to attractmajor oil company investment,

according to the head of the Alaska Oil andGas Association.

Judy Brady spoke May 25 to the Kenaichapter of The Alliance, a trade organizationrepresenting nearly 400 businesses, organi-zations and individuals that derive theirlivelihood from providing products andservices to oil and other natural resourcecompanies.

Brady based her remarks in part on a2002 study by Wood Mackenzie ofEdinburgh, Scotland, an international ener-gy consulting firm. The firm is working onan update for 2004 that could changeAlaska’s ranking.

Two years ago, Alaska ranked last out of60 oil- and gas-producing regions in 50countries in costs for producing oil and gas.

Alaska’s ranking was based on NorthSlope fields starting up production since1995, although earlier studies found thatproduction costs at Prudhoe Bay and theKuparuk oil fields also are among the high-est in the world.

Despite the expense, Alaska was not theleast profitable region. The state rankedslightly above average in “total governmenttake” of both federal and state royalties,taxes and net profit shares of oil and gas pro-duction. When both costs and “governmenttake” were considered together, Alaskaranked 55th in “post-take value” per barrelof oil.

Alaska ranks low on overall investment return

“Of the places you could go, according tothis study, there are five or six places youwould make less than if you go to Alaskaand there are 55 or 56 places you wouldmake more,” Brady said.

Oil and gas companies are looking toinvest where they can get the best return.

With so many other more profitable placesto go in the world, she said, it’s difficult tomake a boardroom pitch for investing inAlaska.

The state’s saving grace, according toBrady, is that Alaska has relatively highreserves compared to other parts of theworld.

“We’re going to continue to be attractiveif we have those reserves,” she said.

Current high oil prices make productionmore profitable, but do not make Alaskafields more attractive for investment since aproducer will get that same price anywhereon the globe, Brady said.

Medium-sized companiesinterested now

Oil companies remain interested ininvesting in Alaska, she said, but the size ofthe companies has changed.

“We’re not getting the big players weused to get,” said Brady. The companiesinvesting are medium-size regional compa-nies. To continue attracting investment,especially from larger companies, Bradysaid, the state could do a couple of things:create a “steady” tax system and streamlinethe permitting process.

The state and federal “total governmenttake” of 64 percent, with the state account-ing for 47 percent, of oil and gas revenue isnot excessive compared to other areasaround the globe.

“It’s not that our taxes are terribly highhere, they’re in the middle,” said Brady.However, the tax rate combined with thehigh cost of doing business in the state“pushes us over the edge,” she said.

Alaska has attributes that cannot easilybe quantified that the study did not consider,such as political stability, Brady said. Thepressure on oil companies to produce steadyreturns on investments has ratcheted up tothe point that they are willing to commit toregions with questionable stability theywould not have considered exploring fiveyears ago, Brady said. �

A

continued from page 6

FIGHT

May 26 it dismissed Leucadia’s proposaland terminated negotiations. The Leucadiagroup failed to make any improvements onits March 19 proposal, the committee said,adding that it had expected a “superior pro-posal.”

The committee said it was concerned thatthe tax and leverage issues raised in theLeucadia offer would adversely impactPlains’ ability to pay the interest and distri-butions on the proposed debt and preferredstock.

Moreover, the committee expressed con-cern the small amount of cash offered inLeucadia’s proposal would be insufficientfor most Plains shareholders to pay taxes ontheir gains resulting from the transaction and“could create immediate negative sellingpressure on the proposed new debt and pre-ferred securities.”

Also, the deal would create “phantom”taxable income in excess of interest payableto holders of the proposed debt securities,the committee said.

The committee said that despite conced-ing the validity of the tax issues, Leucadiasent a letter to the committee “indicating anunwillingness to improve its offer, and didnot offer any alternative solutions to theissues raised by the special committee.”

Leucadia cancelled proposed meeting Nevertheless, the committee said it invit-

ed Leucadia to meet to discuss its proposal.“After accepting the invitation and

scheduling the meeting, Leucadia cancelledthe proposed meeting, declined to provideall of the requested information, declined toexecute a confidentiality agreement and stat-ed that it would not modify the March 19proposal,” the committee said.

Leucadia did not respond to the commit-tee’s allegations, nor indicate its next moveat Petroleum News’ deadline.

The main objective for both the Vulcanand the Leucadia-Pershing groups appearsto be fast-growing Plains All AmericanPipeline. It so happens that PlainsResources, a small exploration and produc-tion independent, owns 44 percent of thegeneral partnership of Plains All American,a publicly traded master limited partnership,and a 24 percent aggregate ownership inter-est in the pipeline company.

In early April, Plains All Americanannounced the $330-million acquisition ofHouston-based Link Energy, a transactionthat essentially doubled the amount ofpipeline miles held by Plains All Americanin the United States and Canada.

Allen’s Vulcan Capital committed $40million to the Link deal. It marked Allen’sfirst direct venture into the midstream ener-gy sector, preceded by Vulcan’s still pendingtakeover bid for Plains Resources.�

continued from page 6

BID

consolidation.

Buying assets will remain keyRoger Serin, an analyst at TD

Securities, said that buying assets willremain the key to offsetting productiondeclines, given that finding and develop-ment costs will be high due to the shrink-ing productivity and reserves in theWestern Canada Sedimentary basin.

Proven finding, development andacquisition costs for 23 junior E&P com-panies averaged about C$18 per barrel ofoil equivalent in 2003, while for truststhey averaged C$18.50 per boe, Serinsaid.

However, he cautioned that finding,development and acquisition costs are anineffective measure of value creationbecause they don’t reflect differences inasset quality.

The changing complexion of the trustworld was commented on by LeslieLundquist, a portfolio manager at BissettInvestment Management, who notedsome of the shifts taking place.

She said Bonavista has moved to rela-tively low payout ratios, VermilionEnergy Trust has extended its reach toFrance and the Netherlands, ProvidentEnergy Trust has acquired major mid-stream assets and Enerplus ResourcesFund has embarked on a joint venture incoalbed methane with MGV Energythrough the trust’s takeover of Ice Energy.

In addition, Enerplus along withAcclaim Energy Trust were two of thethree buyers of conventional assets

unloaded by Chevron Canada Resources,with Enerplus forking over C$466.3 mil-lion to gain 11,500 boe per day of pro-duction and Acclaim paid C$433.7 mil-lion for 17,000 boe per day.

Lundquist said while there is no cer-tainty that these new strategies will suc-ceed, they are evidence that trusts areflexible.

She said the trusts serve a valuable rolein producing reserves in a cost-effectivemanner, waste less capital on marginalprojects and put their emphasis on results,not promises.

For those reasons, exploration andproduction of the Western Canada basinwill be more disciplined and the distribu-tion of capital between exploration andproduction will become more efficient.

Mark McMurray, an acquisition spe-cialist at Kobayashi Partners, said that astrusts enter their “mid-life crisis” theymust become more involved in portfoliomanagement and ensure that they buyonly high-quality junior E&P companiesto replace reserves and increase output.

He said the competition will intensifyfor companies that have producing prop-erties and a string of moderate-risk invest-ment opportunities.�

continued from page 6

TRUSTSRoger Serin, an analyst at TD

Securities, said that buying assetswill remain the key to offsettingproduction declines, given thatfinding and development costs

will be high due to the shrinkingproductivity and reserves in theWestern Canada Sedimentary

basin.

8 PETROLEUM NEWS • WEEK OF JUNE 6, 2004FINANCE & ECONOMY� G U L F O F M E X I C O

Petsec plans $28Mcapital program,much going into Gulf

By ALLEN BAKERPetroleum News Contributing Writer

etsec Energy Ltd. is planning tospend US$28 million this year oncapital projects, with the bulk of theAustralian firm’s funds being

plowed into the Gulf of Mexico. The company expects natural gas pro-

duction from the Gulf of 6.5 billion cubicfeet this year, up from 4.5 bcf in 2003 andjust 46 million cubic feet in 2002, whenthe company was just getting back on itsfeet. This year’s higher production shouldprovide sufficient cash flow to fund the2004 exploration and development budg-et, Petsec Chairman Terry Fern told thecompany’s annual meeting May 25.

But Fern said three wells drilled offChina this spring produced disappointingresults, with two dry holes and the thirdwell yielding relatively heavy 18-20degree API oil, though in high qualitysands.

The three wells, drilled in April andMay in the Beibu Gulf about 36 miles offthe southern coast of China, cost the com-pany $2 million. Petsec holds a 25 per-cent working interest.

Work in that region with partner RocOil of Australia will continue over thenext three months, Fern said.Concentration will be on the successfulnew 12.8.3 well, which showed 36 feet ofpay, confirming an estimate of oil in placeof 80 million to 90 million barrels, and onthe 12.8.1 field, about a mile to the west,which contains an estimated 10 millionbarrels of recoverable oil.

Four Gulf wells plannedIn the Gulf of Mexico, Petsec is plan-

ning four wells from the Vermilion 258platform, with drilling to start inSeptember. Company engineers thinkthere’s a potential for 20 bcf of recover-able gas there. The first well drilled onthat block this year, the Vermilion 258No. 2, found an estimated 9 bcf of recov-erable gas, with 42 feet of pay. That wellfollowed on Vermilion 258 No. 1,punched in December, which showed 85feet of net gas pay.

Petsec, which has a 100 percent work-ing interest in Vermilion 258, expects theinitial pair of wells to flow 15 million to25 million cubic feet daily when produc-tion starts later this year. The lease isabout 70 miles off the coast of Louisiana.

Overall, Petsec holds five contiguousleases in Vermilion and interests in a totalof 13 leases in the Gulf of Mexico,including productive wells in WestCameron blocks.

The company estimates that its Gulfreserves hold 36 bcf of recoverable gas,and executives see “continuing opportu-nity to acquire additional Gulf of Mexicoleases that will have a further substantialimpact on the company,” according toFern, Petsec’s chairman.�

MERIDIAN, MISS.Business professor says high oil pricescould topple U.S. President George Bush

U.S. President George W. Bush’s success in November is tied to what happensin June when the Iraq government is turned over to local control, a business pro-fessor says.

“The political aspect of Iraq is if we still have the problem we have right nowand oil prices go up to $48 or $50 a barrel, I’m afraid we’regoing to have a new administration,” Habib Bazyari saidMay 25 during a civic club speech in Meridian, Miss.

“Everything depends on the end of June when the newIraqi administration comes into power,” he said. Bazyari isdean of the College of Business at the University of WestAlabama. He moved to the United States from Iran in 1960.

Bazyari said there was a 4 percent growth in the grossdomestic product for the first quarter of 2004. The GDP isthe output of goods and services produced by labor andproperty in the United States.

But the last four of five recessions in the United Statesstarted with an increase in the price of oil, Bazyari said.

“I’m afraid if oil prices stay about $42-$45 (per barrel) we are going to go backinto another recession,” he said.

If that happens, Bazyari said unemployment may increase to close to 6 percent. “The whole thing depends on oil,” Bazyari said. He said the main triggers for higher oil prices are the purchase of gas-guzzling

sport utility vehicles; an increased demand for oil in China and India where man-ufacturing jobs are on the rise; and the need for more oil refineries in the UnitedStates.

He also said the war has affected oil prices because terrorists continually punc-ture pipe lines, wasting millions of barrels of oil in a day.

—THE ASSOCIATED PRESS

INDONESIAIndonesia should quit OPEC if can’tboost output, ex-oil minister says

Indonesia’s status as Asia’s only member of the Organization of PetroleumExporting Countries is under question following reports that it now imports more crudeoil than it exports. A former energy minister, Ginandjar Kartasasmita, said Indonesiamight as well drop out of the cartel “if we can’t boost our crude oil production.”

“There are no advantages for us to stay with OPEC,” said Ginandjar, who wasIndonesia’s mines and energy minister from 1988-1993 under dictator Suharto.Indonesia “will do fine without OPEC,” he told reporters.

Dow Jones Newswires reported in May that Indonesia for the first time became anet crude oil importer in March, undermining its already marginal role in the group.

Mines and Energy Minister Purnomo Yusgiantoro — who is also OPEC’s currentpresident — said in late May that temporary oil field glitches have caused Indonesia’sdecline in crude oil exports. He said Indonesia had 1 billion barrels of reserves it plansto roll out in the next two or three years.

Analysts, however, say unclear investment laws and regulations are discouraginginternational companies from developing the country’s oil and gas reserves.

With crude output of around 980,000 barrels a day in April, Indonesia can’t meet itsdaily OPEC output quota of 1.2 million barrels per day. Some analysts have urged thegovernment to quit OPEC because Indonesia has to pay an annual membership fee, anddoesn’t have much of a say in the group anyway. However, the government insistsIndonesia should stay in OPEC to help influence global oil prices.

—THE ASSOCIATED PRESS

PIn the Gulf of Mexico, Petsec isplanning four wells from theVermilion 258 platform, withdrilling to start in September.

U.S. PresidentGeorge W. Bush

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 9FINANCE & ECONOMY

� O K L A H O M A C I T Y , O K L A .

Kerr-McGee raises productiontarget for 2004 second quarter

BY RAY TYSON Petroleum News Houston Correspondent

err-McGee has raised its oil production range for the 2004second quarter to 130,500-136,500 barrels per day to reflectgreater natural gas liquids output and strong performancesfrom the North Sea and the company’s Nansen and

Boomvang fields in the deepwater Gulf ofMexico.

The Oklahoma-based independent alsohas increased its total production outlook,including natural gas, for full-year 2004 toan average range of 306,000 to 323,000barrels of oil equivalent per day, Kerr-McGee said in a May 26 conference callwith industry analysts.

Guidance for overall production thisyear was raised because of first oil expected from the Red Hawkfield in the Gulf of Mexico this July and from China’s Bohai Bayduring the third quarter, four months ahead of schedule, Kerr-McGee said.

Also, total production for the year will benefit from Kerr-McGee’s $3.4 billion acquisition of Denver-based independentWestport Resources. Kerr-McGee’s total daily production volume isexpected to increase more than 34 percent, 54 percent of which isnatural gas. The deal is expected to close June 25, pending share-holder approval the same day.

For the second quarter of 2004, Kerr-McGee is projecting dailynatural gas production to range between 735 million and 785 millioncubic feet with about 85 percent of the volume coming from theUnited States.

“With these volumes, we believe the range for total productionfor the 2004 second quarter to be about 253,000 to 267,000 barrelsof oil equivalent a day,” said Rick Buterbaugh, Kerr-McGee’s headof investor relations.

Majority of production hedged However, Kerr-McGee has taken hedging positions on a signifi-

cant portion of its oil and gas production at much lower commodityprices than what they are so far averaging during the 2004 secondquarter.

The company locked in 75 percent of its U.S. oil production at$28.23 per barrel and about 85 percent of its North Sea production

at $26.27 per barrel. So far, West TexasIntermediate oil prices are averaging about$38.25 per barrel and North Sea Brent$34.90 per barrel. Second-quarter WTI iscurrently up about $3 per barrel comparedto the first quarter, while Brent is up about$3.60 per barrel.

Kerr-McGee also hedged about 80 per-cent of its U.S. natural gas volumes at a

fixed $4.74 per thousand cubic feet, considerably less than the $6.05average so far in the second quarter. NYMEX gas prices are cur-rently about 30 cents higher than they were in the first quarter.

Meanwhile, Kerr-McGee said it expects to spend about $65 mil-lion on oil and gas exploration in the 2004 second quarter and about$350 million for the year, which includes about $70 million in non-cash charges associated with non-producing leasehold.

“The increase in annual exploration expense results from theaddition of expected Westport activities for the second half of theyear,” Buterbaugh said.

The addition of Westport’s reserves will increase Kerr-McGee’sproved reserves by nearly 30 percent, mainly from North Americannatural gas. At year-end 2003, Westport had 1.8 trillion cubic feet ofgas equivalent proved reserves, consisting of 76 percent natural gasand primarily located in the Rocky Mountain and Texas Gulf Coastareas. Westport also has a reported 1.8 trillion cubic feet of equiva-lent in probable and possible resources, about 50 percent of whichare located in and around the Natural Buttes field, in the Uinta basinof northeast Utah. �

“With these volumes, we believe therange for total production for the 2004second quarter to be about 253,000 to

267,000 barrels of oil equivalent aday.” —Rick Buterbaugh, Kerr-McGee’s head of

investor relations

K

BEIRUT, LEBANONOPEC chief wantsto boost output

OPEC must boost oil output fur-ther to make a “really significantimpact” on surging crude prices, thegroup’s president said June 2, eventhough it is pumping close to capacityalready.

The Organization of PetroleumExporting Countries needs to assessits 11 members’ ability to producemore now that prices for oil futurescontracts have hit new highs after aterror attack in Saudi Arabia at theend of May, OPEC PresidentPurnomo Yusgiantoro told reporters.He spoke upon arrival in Beirut fortalks ahead of a formal OPEC meet-ing on production policy June 3.

The weekend attack on oil-relatedoffices and foreign workers in theeastern Saudi oil hub of Khobarstoked fears the Saudi government,which controls the world’s largestproven crude reserves, cannot protectits vital oil installations.

“We are fully ready to increaseproduction, but there is fear that themarket will be overflooded,” SaudiOil Minister Ali Naimi said. “So,therefore, we should be cautiousabout such action because this is whathappened in 1997-98.”

The Khobar attack caused freshalarm about the reliability of oil sup-plies from key Gulf producers. SaudiArabia is the world’s leading crudeexporter and the only producer with

see OPEC page 10

10 PETROLEUM NEWS • WEEK OF JUNE 6, 2004NORTH OF 60 MINING

SOUTHWEST ALASKAHolitna Energy still working onremote Alaska shallow gas project

Phil St. George still believes in the gas potential for Holitna basin, despite aseries of setbacks since filing in May 2003 for four shallow gas leases in theremote region of southwestern Alaska.

His company, Holitna Energy, and its Native corporation partner, TKC, plan toconvert their shallow gas lease applica-tions covering more than 19,000 acres ofland to exploration licenses under thestate’s conventional gas leasing program.That’s because Alaska’s non-competi-tive, shallow gas leasing program, alsoreferred to as its coalbed methane pro-gram, has been legislated out of exis-tence.

House Bill 531, passed May 11, abol-ished the shallow gas leasing program,leaving a number of pending applica-tions. In addition to Holitna Energy’sfour leases about 50 miles from theDonlin Creek gold mine project, UsibelliCoal Mine at Healy has an application pending for eight shallow gas leases.

And 13 applications are also pending in the Mat-Su Valley, according to JimHansen at the Alaska Division of Oil and Gas. Those applicants can convert theirlease selections into a non-competitive exploration license application, Hansensaid. Before approving an exploration license, the state must issue a best interestfinding, which typically takes about a year to complete, he said.

Companies could do some preliminary fieldwork prior to receiving an explo-ration license, Hansen said. “Any work they do on exploration would counttoward their work commitment,” he said. “But they are at risk whether the licensewill be awarded or not.”

Still positive about Holitna BasinSt. George remains positive about his company’s chances of finding gas to sup-

ply power and heat for Donlin Creek. “We’ve got new information that there’s a good possibility of finding conven-

tional gas, so we think there’s a better chance,” he said, on May 25. “We’ve gotsome more data on the basin and I don’t want to say any more about that.”

Holitna Energy and TKC plan to conduct some exploratory work this winter,pending successful fund-raising for seismic work and initial drilling. (On Jan. 3,Holitna said it plans to drill two exploratory wells this past winter for shallow gasand coalbed methane occurrences had been cancelled because funding had fallenthrough at the last minute.)

St. George said state officials told him they would “try to speed up” the bestinterest finding process, possibly completing it in six months.

Donlin Creek may not be the only potential large mine customer for HolitnaBasin gas. St. George said he was approached by state development employeesinterested in taking Holitna basin gas about 100 miles south to Illiamna Lake,where the Pebble gold-copper-molybdenum project is generating considerableinterest.

—PATRICIA LILES, Petroleum News contributing writer

� S O U T H W E S T A L A S K A

Alaska mine poweroptions down to threePlacer Dome tightens scope of power options for Donlin Creekmine; one on-site and two off-site options being considered

By PATRICIA LILES Petroleum News Contributing Writer

lacer Dome, operator of the remoteDonlin Creek gold deposit in south-west Alaska, has narrowed its consid-eration of electric power options from

11 to three scenarios in its preparation of apre-feasibility study for the large-scalemine project. Two off-site options and oneon-site option to generate up to 70megawatts of electric power needed for alarge hard-rock mine at Donlin Creek arenow being considered in more detail byPlacer Dome, according to the company’sproject manager, Gregg Bush. In a May 24interview with Petroleum News, Bush saidthe company requested “expressions ofinterest” from local and international ener-gy firms for options to provide power tothe remote project. “We received veryenthusiastic responses,” he said.

The on-site generation being consid-ered is either a diesel or LPG-poweredgeneration plant.

One of the off-site generation optionsinvolves building a transmission line con-necting Donlin Creek to Alaska’s existingRailbelt power grid.

The third option being considered isbuilding a coal-fired power plant at Betheland building a transmission line up theKuskokwim River, a scenario advocatedby Calista, the region’s Native corporation.

After narrowing the focus of poweroptions, Placer Dome requested specificcost details and the related scope of workneeded in those top three considerations.Bush said the company requested thatinformation be provided by Sept. 15, so itcan be incorporated in Placer Dome’s pre-feasibility study for the Donlin Creek mineproject. That study should be complete inlate September or early October, Bushsaid.

On-site requires barging, lots of storage

Electric power for the remote gold mineis a key obstacle for its successful devel-opment. Because Donlin Creek ore is asso-ciated with a sulfide material, extractinggold involves an autoclave process, which

requires adding oxygen and heat tocrushed ore. That ups the ante for powerneeds, with estimates of peak needs at 70megawatts of power.

Installing and operating diesel genera-tors to meet that power need would requireabout 30 million gallons of fuel each year,Bush said. That’s in addition to about 15million gallons of diesel that would beused annually by the mine’s dirt movingequipment. The barge shipping season forthe Kuskokwim River is about 122 daysper summer, according to Placer Dome’spartner in the project, NovaGoldResources. In its previous analysis of theDonlin Creek project, NovaGold estimatedthat seven tug and barge deliveries perweek would be required during the ship-ping season.

Bush said Placer Dome is leaningtowards shipping LPG, or propane, toDonlin Creek for fuel to power on-sitegeneration, rather than diesel. Propanerequires lower-pressure storage and han-dling equipment, Bush said, and its cost isusually comparable to diesel. LPG haslower per unit power generation capability,so about 60 million gallons of LPG wouldbe required, he said. “We’re looking atsome underground storage,” Bush added.

Transmission line from RailbeltOne of the off-site generation options

involves tying Donlin Creek into Alaska’sexisting power grid that serves the Railbeltcommunities. “It would not necessarilyhave to connect in Nenana, but that wouldbe the logical place to bring the line acrossthe terrain,” Bush said. That tie-in accesspoint at Nenana could keep the transmis-sion line on the north side of the AlaskaRange, eliminating a crossing point for thestate’s central dividing line of mountains,Bush noted.

But power generation capacity on theRailbelt is already relatively tight, particu-larly in the northern portion of the state. ADecember 2003 report by the AlaskaEnergy Policy Task Force states thatRailbelt energy studies predict electricpower generation needs could grow 39percent from 2008 through 2028.

P

see OPTIONS page 11

significant spare capacity to pump moreoil.

Oil prices eased somewhat early June2, slipping 37 cents to $41.96. That came

a day after a surge on June 1, the first dayof trading on major markets since theKhobar attack. U.S. light crude for Julydelivery climbed $2.45 to $42.33 per bar-rel — the highest settlement price in thecontract’s 21-year history on the NewYork Mercantile Exchange.

—THE ASSOCIATED PRESS

continued from page 9

OPEC

House Bill 531, passed May 11,abolished the shallow gasleasing program, leaving a

number of pendingapplications. In addition toHolitna Energy’s four leases

about 50 miles from the DonlinCreek gold mine project,

Usibelli Coal Mine at Healy hasan application pending for eight

shallow gas leases.

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 11NORTH OF 60 MINING

Deficiencies in generation capacity areprojected in areas of the Railbelt other thanon the Kenai Peninsula, the study said.

Power generation capacity in theFairbanks area currently is 183megawatts, according to the Interior’selectric supplier, Golden Valley ElectricAssociation. Golden Valley plans to buildanother gas-fired power plant in NorthPole, adding another 47 to 120 megawattsof power generation in the Interior byearly 2006. It also produces 25 megawattsof coal-fired power in Healy, fed north bytwo transmission lines that run betweenHealy and Fairbanks.

Nenana is about halfway betweenHealy and Fairbanks. Golden Valleycounts in its generation capacity 20megawatts of power from the hydroelec-tric plant at Bradley Lake. That power issupplied to the Interior by the AlaskaIntertie, which can carry 75 megawatts ofpower north from Willow to Healy, thento Fairbanks via one of the two northerntransmission lines.

Demand growing quicklyGolden Valley set a new record for its

peak demand of electricity this January:192.9 megawatts. Electric demand in theInterior is expected to increase dramati-cally in the near future, even withoutDonlin Creek.

Large new consumers in Fairbankssuch as Wal-Mart, Home Depot, Lowe’sand the expanded Westmark FairbanksHotel will bump the immediate draw ofpower. Another 30 megawatts of demandfor Golden Valley power is expected inthe near future from large-scale industrial

projects and a residential increase inFairbanks-area military personnel.Development of the national missiledefense system at Fort Greeley, construc-tion of the Pogo gold mine northeast ofDelta Junction and electrification of somepump stations on the trans-Alaskapipeline system all are expected toincrease Golden Valley’s demand.

Calista favors coal-fired plant at Bethel

The third power option Placer Dome isconsidering is some version of a coal-fired power plant in Bethel, advocated bythe region’s Native corporation, CalistaCorp. Calista’s non-profit subsidiary,Nuvista Light & Power, released a draftfeasibility study this spring recommend-ing construction of a 100-megawatt-pluspower plant at Bethel, either on two bargestructures or on land south of town.

A connecting 138-kV transmissionline would be built from Bethel to DonlinCreek, an estimated 191 miles, to providethe mine with power. (See story in May 9issue of Mining News.) Timing of thatlarge-scale project, estimated to costabout $370 million, could provide a logis-tical hurdle, according to the Nuvistareport.

“Realistically it will be difficult toconstruct (the coal-fired plant and trans-mission line) prior to 2010,” the tentativedate for Donlin Creek’s mining start.Placer Dome has hired consultants tolook at the Nuvista proposal, from themine developer’s perspective, Bush said.“They are looking at what our cost andconstruction criteria are, separating ourneeds from those of the obvious commu-nity benefits from that study.” �

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OPTIONS

� H E A L Y , A L A S K A

Offer for coal plant rejected by state agencyAIDEA turns down purchase offerfrom Golden Valley Electric forHealy Clean Coal Project

By PATRICIA LILES Petroleum News Contributing Writer

olden Valley Electric Association’s $70 millionoffer to purchase the shuttered, experimentalcoal-fired power plant in Healy, Alaska, has beenturned down by board members of the Alaska

Industrial Development and Export Authority. GVEA’s board members learned of their rejected

offer during a meeting with the state agency’s boardmembers on April 30, according to Kate Lamal, vicepresident of power supply for GVEA.

“They did not like our offer. There was no counter-offer, no alternative offered,” she told Petroleum Newson June 2. “They are continuing to work on permittinga retrofit (of the experimental plant.)”

AIDEA’s Executive Director Ron Miller toldPetroleum News on June 3 that board members did notsee “any substantial benefit to AIDEA” from GVEA’soffer. “There were too many continguencies, and wefeared that AIDEA might have to pay out of pocket forGolden Valley to take over the power plant.”

He also said the annual payments offered by GVEAwould only be paid if the plant was generating elec-tricity, and that AIDEA’s continued warranty and lia-bility of the plant’s operation was not acceptable.

After nearly a year of joint board meetings to dis-cuss the lengthy legal debate about ownership andoperation of the Healy Clean Coal Project, GVEA sub-mitted a purchase offer on March 19 to AIDEA. Thatstate agency owns the $300 million-plus Healy CleanCoal Project, built mostly with federal and state fundsduring the mid-1990s. The 50-megawatt experimentalplant is located outside of Healy, adjacent to a 25-

megawatt coal-fired plant owned and operated byGVEA since 1967.

In its purchase offer, GVEA agreed to pay AIDEA$70 million for the plant over a 40-year period, paying$1,750,000 per year after the plant became opera-tional.

The Healy plant has been shut down since January2000 after conclusion of a 90-day test period, used toevaluate performance, reliability and safety of theexperimental technology.

AIDEA has spent about $9 million a year on theplant since construction was completed in 1997,according to a former project manager. That includesdebt payments on the bonds and about $3 million ayear to keep the plant in standby mode.

GVEA’s purchase offer was contingent on comple-tion of a full retrofit of the plant, which would changeout some of the experimental technology to “environ-mentally equivalent, proven technology,” similar tothat in the smaller, operating Healy coal plant, Lamalsaid. Estimated cost for that work was $65 million.

Collaborative work to obtain an emissions permitfrom the Alaska Department of EnvironmentalConservation for the retrofitted plant is continuing, aneffort that Lamal said began in earnest in Februarywith encouragement from Alaska Gov. FrankMurkowski.

While not designated in the GVEA purchase offer,one potential source for the retrofit funding is a $125

million federal appropriation included in the pendingU.S. energy bill. The remaining amount could be usedto pay off some of the $85 million in bonds issued byAIDEA to raise its share of the initial constructioncosts.

“When you make an offer for something that’s forsale and they say no, what do you do? We’re buildingNorth Pole,” Lamal said. “We have the ability to gotwo-on-one at North Pole.”

GVEA plans North Pole power plantOn May 24, GVEA’s board members gave final

approval for construction of a new, gas-fired powerplant in North Pole.

“We don’t have a signed contract yet, but we’reworking out the details on the equipment,” Lamal said.That decision was not dependent on AIDEA’s rejectionof the HCCP offer, she said on June 3.

“We’ve been working on that project for more thana year.” GVEA’s board decided to spend $75 millionfor the naphtha-fired power plant, selecting a one-on-one configuration, according to GVEA spokeswomanCorinne Bradish.

It will consist of a 47-megawatt simple circuit gen-erator and a 13-megawatt steam turbine. The designallows GVEA to add a second 47-megawatt gas-firedgenerator, which, if combined with the steam turbinein a two-on-one configuration, will produce 120megawatts of electricity.

Construction of that facility should begin in lateJune, and be complete in early 2006. It will be locatedadjacent to GVEA’s existing 120-megawatt heavyatmospheric gas oil fired power plant that operateswithin the security confines of Alaska’s largest oilrefinery, now owned by Flint Hills Resources. NorthSlope crude oil is tapped from the nearby trans-Alaskapipeline system and distilled, providing gasoline, jetfuel, diesel and fuels for electric generation in InteriorAlaska. �

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After nearly a year of joint board meetings todiscuss the lengthy legal debate about

ownership and operation of the Healy CleanCoal Project, GVEA submitted a purchase offer

on March 19 to AIDEA. That state agencyowns the $300 million-plus Healy Clean Coal

Project, built mostly with federal and statefunds during the mid-1990s.

12 PETROLEUM NEWS • WEEK OF JUNE 6, 2004LAND & LEASING� B R I T I S H C O L U M B I A

B.C. closer to call for bids in Muskwa-Kewchika areaNortheast part of province anatural westward extension oftraditional exploration areas

By DON WHITELEY Petroleum News contributing writer

he British Columbia government is one stepcloser to a call for bids on oil and gas leasesin the 64,000 square kilometer Muskwa-Kechika area in northeast British Columbia.

The Ministry of Energy and Mines, in con-junction with the Ministry of SustainableResource Management, has issued new pre-tenure plans that outline environmental require-ments for oil and gas exploration activities.

“This is good news for our oil and gas indus-try that last year increased its investment in theprovince to $3.5 billion from $3 billion the pre-vious year,” Energy Minister Richard Neufeldsaid in a release. “It provides the certainty thatindustry needs to proceed with exploration and

development of the tremendous resource poten-tial in this area.”

Ministry officials have estimated that $16 bil-lion worth of natural gas may lie beneath theeastern parts of this area, which is about the sizeof the Province of Nova Scotia. It is a naturalwestward extension of traditional exploration ter-rain in the northeast part of British Columbia, butto date there has been no drilling activity becauseof environmental issues.

Plans would give assurance of accessThe pre-tenure plans provide potential bidders

for exploration rights with the certainty that theywill be able to get access to this remote explo-ration area. They also give direction for conser-vation of biological diversity, soil and waterresources, as well as targets for minimizing dis-turbance to the general area, and remediationonce exploration and development are complet-ed. The plans become part of any oil and gastenure sold in the area.

Oil and gas activities must comply with the

Muskwa-Kechika Management Act, which wasenacted because of the unique nature of an areathat has often been called the Serengeti of thenorth. Resource activities will be governed by theMuskwa-Kechika Management Plan, which wasdeveloped after consultations with residents,local municipalities, First Nations and tourism,wildlife and resource development interests.

“With clear guidelines in place to protect envi-ronmental values while providing resourceaccess, industry can now acquire the oil and gasrights that form the basis for future develop-ment,” said Sustainable Resource ManagementMinister George Abbott.

“This will ensure new sources of energy andprovide additional jobs and revenue that willbenefit our communities and residents,” addedNeufeld. “B.C. has succeeded in attracting anincreasing share of industry investment, and oiland gas exploration and production activity hassteadily increased in recent years from 821 wellsdrilled in 2002/03 to a forecast of 1,328 wells thisyear.” �

T “This is good newsfor our oil and gasindustry that lastyear increased itsinvestment in theprovince to $3.5 bil-lion from $3 billionthe previous year. Itprovides the certain-ty that industryneeds to proceedwith exploration anddevelopment of thetremendous resourcepotential in thisarea.” —EnergyMinister RichardNeufeld

ning areas. Anadarko took two tracts bidding by

itself for $155,356 and paid out another$2,308,290 as a 30 percent partner withConocoPhillips and Pioneer, for a total of$2,463,646.

ConocoPhillips Alaska bid $1,860,500for eight tracts by itself, $2,871,540 in part-nership with Pioneer and $3,847,150 inpartnership with Anadarko and Pioneer fora total of $8,579,190.

Fortuna, bidding by itself, had$26,480,300 in high bids, 49 percent of thehigh bids at the sale.

Petro Canada, bidding by itself, had$13,614,835 in high bids, 25 percent of thehigh bids at the sale.

Pioneer, bidding in partnership withConocoPhillips and Anadarko, and inanother bidding group with ConocoPhillips,had $2,769,520 in high bids.

No new players None of the bidders are new to Alaska.

ConocoPhillips Alaska is a majorNorth Slope producer and operates boththe Kuparuk River and Alpine fields.Anadarko Petroleum is ConocoPhillips’partner at Alpine and in northeast NPR-Aacreage and also holds substantial North

Slope state, federal and Native corpora-tion acreage.

Pioneer Resources Alaska, a sub-sidiary of Dallas, Texas-based PioneerResources, is a partner, and operator, inthe Oooguruk exploration unit assembledby Denver, Colo.-based Armstrong Oil &Gas in Harrison Bay offshore Kuparukand also has a large acreage position onstate lands south of Prudhoe Bay.

Petro-Canada holds a major acreageposition in the Foothills area north of theBrooks Range, and Fortuna farmed in onTotal’s exploration acreage in the north-east NPR-A and was a partner in theexploration well drilled there last winter.

Dick Garrard, ConocoPhillips Alaskaexploration manager responsible for theNPR-A area, said after the sale thatConocoPhillips expected “some Canadiancompanies would come here, it’s been atrend recently.” And it’s logical, he said,

as “they’re accustomed to working innorthern latitudes” and have experiencein the Arctic.

Petro-Canada is Calgary-based andFortuna is a subsidiary of Calgary-basedTalisman Energy.

A blocky affair Most of the tracts drawing bids were in

good-sized blocks. The only outlier was two tracts

Anadarko bid on by itself, adjacent to thesouthern edge of the northeast NPR-Aplanning area and the most southerly oftracts receiving bids.

In the southwestern portion of the salearea the ConocoPhillips (50 percent)-Anadarko (30 percent)-Pioneer (20 per-cent) partnership took 13 tracts and theConocoPhillips (70 percent)-Pioneer (30percent) partnership took 14 adjacenttracts.

On the northwestern edge of the salearea, southwest of Barrow, Petro-Canadatook a block of 10 leases, and theConocoPhillips-Anadarko-Pioneer bid-ding group took a block of 19 tracts in anarc south of Barrow.

The remaining 65 leases receiving bidsare in a single block beginning at SmithBay in the Beaufort Sea and along theboundary between the northeast andnorthwest NPR-A planning areas, andextending to the southwest.

Thirty-one of the 65 leases in thisblock received multiple bids, the onlytracts in the sale that did, so the pattern oflease holdings does not necessarily reflectthe plans of the companies bidding at thesale. Most of the leases drawing multiplebids are in the center and on the easternedge of this large block.

All of the Fortuna leases are in thisblock: those 22 leases include a band nearthe top of this lease block and leasestrending down to the southern edge of theblock. Petro-Canada took 18 leases in thisblock, three on the eastern edge, eightrunning through the middle of the blockand the remainder on the western edge.

The eight tracts ConocoPhillips bid onby itself are in the upper half of thisblock. Five of the ConocoPhillips-Anadarko-Pioneer tracts are in this block,one to the north, one to the east and threeon the southern edge. Twelve of theConocoPhillips-Pioneer tracts are on thenorthern and southern edges of the block.

continued from page 1

LEASE SALE

see LEASE SALE page 13

BLM legal battle the first hurdle As for future plans in the NPR-A northwest planning area, the first hurdle is a

suit filed by environmental groups. “As everyone here is probably aware, a consortium of environmental groups

sought preliminary injunction against all lease sales associated with the northwestNational Petroleum Reserve-Alaska EIS,” Henri Bisson, BLM Alaska state direc-tor said before bids were opened June 2 at the agency’s northwest NPR-A sale.

“Last Friday, after hearing oral arguments on Thursday, May 27th, the courtruled that the BLM could proceed with today’s scheduled lease sale in the north-west planning area of the petroleum reserve, but cannot permit surface disturbingactivities prior to the final determination on the merits of this case,” he said.

The litigation was filed by the Northern Alaska Environmental Center, NationalAudubon Society, the Wilderness Society, Natural Resources Defense Council,Sierra Club, Alaska Wilderness League and Center for Biological Diversity.

The plaintiffs have challenged BLM’s final integrated activity plan/environ-mental impact statement, arguing that the agency did not give a “hard look” toeach possible lease in its environmental impact statement. U.S. District CourtJudge James Singleton ruled that the Department of the Interior must notify

see LEGAL page 13

What do the companies see? The multiple bids made it evident that

several companies see opportunities in thesame area.

Anchorage geologist David Hite saidafter the sale that the companies are proba-bly looking for stratigraphic, not structuralplays. Stratigraphic plays, like the Alpinetrend, are associated with “ancient shore-lines,” he said. Looking at the big block ofleases he noted it was “running sort ofnortheast-southeast, so I suspect thatthey’re looking at paleo shorelines…”

As for earlier drilling in the area, Hitesaid the Brontosaurus well, which is in thesale area southwest of Barrow, is a case ofcompanies probably looking for structuralfeatures when it was drilled, and nowgoing back to revisit the area as ideas havechanged.

Brontosaurus (see map) appears to beadjacent to tracts taken by ConocoPhillips-Anadarko-Pioneer southwest of Barrow.The well was drilled to a measured depthof 6,660 feet and a true vertical depth of6,635 feet in section 18 township 18 northrange 20 west, Umiat Meridian. It wasplugged and abandoned in February 1985.ConocoPhillips Alaska is the successor toARCO Alaska, the Brontosaurus operator.

Ken Boyd, a geophysicist and formerdirector of the Alaska Division of Oil andGas, said he thought the companies wereprobably looking for an Alpine-type trendin the northern part of the sale area, andnoted that ConocoPhillips Alaska drilledthe Puviaq well on the western edge of thenortheast NPR-A planning area. That well,which ConocoPhillips’ Garrard said is a“very tight hole,” on which the companyhas not released any information, wasdrilled on a tract in the northeast planningarea adjacent to tract D-20, acquired by theConocoPhillips-Anadarko-Pioneer part-nership for $251,600. The tract alsoreceived a $240,835 bid from Petro-Canada.

As for the Brontosaurus well, Boydnoted that “they were chasing somethingelse 20 years ago.”

Garrard said Brontosaurus is the “onlyindustry well ever drilled” in this area,although the government, first the U.S.Navy in the 1940s and 1950s and then theU.S. Geological Survey in the 1970s and1980s, drilled in the area. The Navy dis-covered the Barrow gas field and USGSdiscovered the Walakpa gas field, he said.“But largely, both of those campaigns wereunsuccessful in terms of finding commer-cial volumes of hydrocarbons.”

Distance will be a challenge As for plans for the area,

ConocoPhillips’ Garrard said work in sucha remote area requires a lot of planning —and regulatory and permitting work. Heshould know, as ConocoPhillips is the onlycompany to have drilled even close to thisarea in recent years.

Predecessor ARCO drilled theBrontosaurus well, and ConocoPhillipsdrilled the Puviaq well at the far westernedge of northeast NPR-A leases. “Drillingthe Puviaq well was a two-year process,”he said. The rig was staged on an insulatedice pad, where it over-summered, and thewell was drilled the following season.

And before ConocoPhillips wasallowed to drill, BLM did an environmen-tal assessment of the project.

Bisson said after the sale that the “areais far from the infrastructure developingalong the eastern border of the reserve”and the agency is “gratified to see indus-try’s vote of confidence and willingness toinvest in the future.” �

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 13LAND & LEASING

continued from page 12

LEASE SALE

prospective lessees of the pending litiga-tion, because rights under such leases arecontingent on resolution of the litigation,“and that no right to drill or build roads on

any lease will be permitted until the ter-mination of this litigation.”

Surface occupancy of leases will notbe allowed until the litigation is settled, soBLM will not be allowed to accept appli-cations for permits to drill, geologicalpermits to conduct seismic activities,right of way permits, etc., the judge said.

Bisson said after the sale that theagency would now “do what we have todo to defend the sale, and see where wego from there.”

If the judge makes a decision this fall,he said, then BLM will be able “withsome certainty” to make decisions aboutnext year.

continued from page 12

LEGAL

14 PETROLEUM NEWS WEEK OF JUNE 6, 2004

pipelines&downstreamwww.PetroleumNews.com

CALIFORNIAAttorney general seeking buyerfor Bakersfield oil refinery

California Attorney General Bill Lockyer has hired an oil indus-try consultant to help find a buyer for Shell Oil Co.’s Bakersfieldrefinery, a spokesman for Lockyer said.

“Shell has said the refinery is not a marketable commodity. We’regoing to find out if that’s true,” Lockyer spokesman Tom Dresslarsaid. “The ultimate objective is to try to find a viable buyer.”

Experts believe closing the refinery would force the state’salready record gas prices even higher. Shell has said it would closethe plant in October.

Although the facility is among the state’s smallest and makes only2 percent of California’s gas and 6 percent of its diesel, economistsbelieve the effect of its closure on gas prices could stretch as far asWashington, Arizona and Nevada.

In response to what he believes is a halfhearted attempt to sell thefacility, Lockyer May 26 hired Dallas-based consulting firm TurnerMason & Co. to “locate a buyer with the financial capability, whowill increase production of refined products and implement theclean-products technologies while increasing gasoline output to theCalifornia market,” according to the state’s contract with the firm.

Lockyer will pay consultant Malcolm Turner as much as $35,000through the end of July for the services.

If it is determined that the plant can be sold, the firm will work tofind a buyer, Dresslar said.

“We welcome Malcolm Turner as we would any other inquiringparty, and we would provide him with information once he signs aconfidentiality agreement,” said Shell spokesman Stan Mays.

The company has 21 inquiries in various stages but has notreceived any “credible offers” for the refinery, Mays said.

—THE ASSOCIATED PRESS

ALASKA

Enstar installs longesthorizontal directionaldrilled pipe in AlaskaWork done last winter on west side of Cook Inlet to replace portionof 20-inch transmission line in danger of being washed out

By KRISTEN NELSONPetroleum News Editor-in-Chief

n 1991, Enstar Natural Gas Co. did the first hori-zontal directional drilling in Alaska when itreplaced a section of its Beluga pipeline under themiddle channel of the Susitna River on the west

side of Cook Inlet. Enstar, a subsidiary of SemcoEnergy, is the natural gas transmission company forSouthcentral Alaska. Its Beluga line brings gas from

the west side of Cook Inlet to Anchorage, primarilyfrom the Beluga gas field but also from the Steelheadplatform and smaller fields along the way.

Last winter, Enstar did the longest horizontaldirectional drill in the state to date when — after theriver shifted again — the company relocated thecrossing 2,000 feet to the north, with a 4,305-foothorizontal directional drill under the middle channel.

Horizontal directional drilling was also done when

Trans-Alaska pipeline workersto be polled on satisfaction

The federal and state agencies that oversee the trans-Alaska oilpipeline will survey workers to find out if they still fear reprisalsagainst whistle-blowers.

The Joint-Pipeline Office will send out questionnaires to AlyeskaPipeline Service Co. employees and contractors starting June 1, saidRhea DoBosh, a JPO spokeswoman.

“We definitely want to see if there has been any improvements orchanges since the last survey,” DoBosh said.

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� C O O K I N L E T , A L A S K A

Horizontal directional drilling at the middle channel crossing of the Big Susitna River

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ARCO Alaska (now ConocoPhillipsAlaska) installed the Alpine pipeline underthe Colville River on the North Slope, a dis-tance of 4,279 feet, and more recently aspart of the Kenai Kachemak Pipeline instal-lation on the Kenai Peninsula. It requires aspecial drilling rig that sits at an angle to theground, allowing it to drill shallow horizon-tal holes.

John Lau, Enstar’s director of transmis-sion operations, told Petroleum News thecompany had to wait for a real winter in theCook Inlet area of Southcentral Alaska. Itdidn’t get cold enough in the winter of2002-03 to build the ice road necessary toreach the work site. But, he said, as soon asweather projections for 2003-04 indicatedcold weather, pipe was ordered and prepa-rations begun.

That included bringing in 10,000 feet ofcoated 20-inch pipe and the horizontaldirectional drilling rig needed for the job.

Hole drilled, expanded, pipe pulled through

The horizontal directional drilling wasdone to get the pipe, which carries abouttwo-thirds of the natural gas coming intoAnchorage, 60 feet under the middle chan-nel of the Big Su — far enough beneath thebed of the river that it wouldn’t be washedout as the channel changes.

Lau said in the worst case this crossingshould last 50 years: “But the best case is,it’ll last forever,” depending on what theriver does.

The pictures illustrate part of the proce-dure: The horizontal directional drill wasused to create an initial hole from one sideof the channel to the other; then the holewas reamed out to 30 inches so that the 20-inch transmission pipe could be pulledthrough; the 20-inch pipe was weldedtogether and pulled through; that pipe wasthen welded to conventionally laid pipe andthe whole new section of pipe welded intothe existing line.

Ice road, ice bridges required The work had to be done in the winter

because the site is in the Susitna Flats StateGame Refuge, and could only be donewhen the ground is frozen, Enstar engineerSteve Cooper, the project manager, toldPetroleum News.

Cooper said the work started the secondweek of January with the ice road construc-tion. Fifteen miles of ice road had to be builtfrom the end of the road system off of KnikGoose Bay Road, as well as five ice bridgesacross the Little Susitna River, Fish Creek,a tributary of Fish Creek and the east and

middle channels of the Susitna River. By the end of January, Cooper said, the

ice on the river channels was five feet thick,adequate for the heaviest equipment.

They started stringing pipe at the end ofFebruary, beginning of March.

The horizontal directional drilling por-tion of the project began Feb. 21 and pullingthe 20-inch pipe through was completed

March 26. Before the 4,300-foot sectionwas pulled it was welded, x-rayed andhydro-tested.

Twelve-hour window to connectWhen the new section of pipe was con-

nected, Enstar had to shut down approxi-mately 40 miles of pipeline between twoblock valves. And the window to accom-

plish that work was 12 hours. “In that 12-hour window,” Cooper said,

“the gas supplies from the Beluga field hadto be shut down. The pipeline was shut inand blown down between the block valves,we had to do the cutover, pig the line andpressure it back up.” In that 12-hour win-dow, supply for Anchorage came in onEnstar’s two 12-inch lines from the KenaiPeninsula. “It took cooperation between allthe producers to get gas swapped over,” hesaid.

The tie-in was completed on April 4, andequipment was moved out of the site byApril 7, just as the weather was warming upand the ice road was melting.

Project cost right at $5 million In addition to having to wait for a winter

cold enough for ice roads, the $5 millionproject also faced sea challenges: 54 joints ofpipe were washed overboard in the Gulf ofAlaska on the way to Whittier and 46 addi-tional joints were damaged, so Enstar had tofind about 5,400 feet of replacement pipe andget that coated and barged to Alaska.

Lau said an advantage of the standardpipe Enstar uses is that it was able to replacethe lost and damaged pipe in time to meetproject schedules.

And as for the weather, Lau said “it neverfroze up out there winter before last.” Thiswinter, however, there were “some long coldsnaps and a warmer week here and there —but it didn’t stop us.” �

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 15PIPELINES & DOWNSTREAM

continued from page 14

ENSTAR

Fly-cutter reamer used to enlarge hole for natural gas transmission pipeSections of 20-inch natural gas transmission pipe have been welded together and are beingpulled through the drilled and reamed hole

Pipe exiting after being pulled through horizontal directional drilled crossing under channel

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By KRISTEN NELSON Petroleum News Editor-in-Chief

wners of the trans-Alaska pipelinesystem have authorized AlyeskaPipeline Service Co. to proceedwith preliminary engineering for

reconfiguration of the Valdez MarineTerminal, a step which will providefirmer project sched-ules and costs, neces-sary before the own-ers give finalapproval for thework.

Goals of the reconfiguration are todownsize the terminal to better fit currentand expected throughputs of crude oil —about half of what the terminal handled atits peak in the 1980s — reducing trans-portation costs forAlaska North Slopecrude oil, and mak-ing it more competi-tive with crudeworldwide.

In the preliminaryengineering phaseAlyeska is lookingat costs and schedul-ing for two types ofprojects identified inthe conceptual engi-neering phase, inter-related changes and standalone projects atthe terminal.

The related projects include: a reduc-tion in the amount of tankage in serviceand addition of internal floating lids tothe remaining tanks; handling tankervapors with vapor combustors; and

replacing the existing electric generatingsystem with either new diesel-fired gen-erators or electricity purchased fromCopper Valley with backup diesel powergeneration at the terminal (see part 1 ofthis story in the May 30 issue ofPetroleum News).

More work before sanctioningIn a May 24 interview, Alyeska man-

agers told Petroleum News that work atthe terminal hasn’t been authorized yet.

John Barrett, Alyeska’s strategicreconfiguration program manager, saidthe conceptual engineering work at theterminal generated “a set of ideas thathold a lot of promise, but they have notbeen validated yet.

“Preliminary engineering goes to ahigher level of detail, where you moreaccurately determine the cost and the sav-ings to determine if the project really isviable, and if it is, then it’s sanctioned togo forward and that’s when largeramounts of moneyare spent.”

Both costs andscheduling will belooked at in muchgreater detail overthe course of thisyear.

“We have to getto a point where wesee that this has aneconomic return,and we’re not thereyet,” said ChuckStrub, Alyeska spe-cial projects manager in charge of the ter-minal changes.

Rod Hanson, Alyeska’s Valdez MarineTerminal manager, said the changes in thetanks, vapor control and power genera-tion are the biggest piece of work beinglooked at in the preliminary engineering:“Those all have to happen together or itdoesn’t make sense, so that all has tostand on its own from a business case.”

Detailing the costs and schedule forthe tank and power/vapor work is the firststep in the preliminary engineering, saidStrub. Preliminary engineering for thetank, vapor control and power generation

“requires us to go through and do the tankwork, the internal floating roofs,” he said,along with the vapor combustors for thetanker vapors, and providing powerresources for the facilities.

“And to do that we have to understandall of the cost elements involved in thisand then how we’ll pay back for theinvestment as reduced operations andmaintenance costs over time,” Strub said.

Goal is completion around 2007The goal, said Strub — subject to

approval of the project at the end of thisyear — is to complete the tanks andpower/vapor portions of the project in2007. (See part 1 of story for interrela-tionship of tanks and power/vapor work.)

The retrofit for the internal floatingroofs will take the longest, he said. “Wecalculate we can only do about five tanksa year because of the amount of effortrequired inside each of the tanks” andbecause only that many tanks could betaken out of service at one time.

That time estimate came out of theconceptual study, he said, and “now wehave to go back in and first of all validatewhether we can achieve that schedule andhow much it will cost.”

That work will be the major focusthrough the end of this year: developing

16 PETROLEUM NEWS • WEEK OF JUNE 6, 2004PIPELINES & DOWNSTREAM� V A L D E Z , A L A S K A

Right sizing for Valdez Marine TerminalTank work could start early next year, with tank and power/vapor and firewater work to be completed by 2007;metering and changes to ballast water treatment would be done later

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see SIZING page 17

Rod Hanson,Alyeska’s ValdezMarine Terminalmanager

Chuck Strub,Alyeska special proj-ects manager incharge of the termi-nal changes

The changes in the tanks, vaporcontrol and power generation arethe biggest piece of work being

looked at in the preliminaryengineering: “Those all have to

happen together or it doesn’t makesense, so that all has to stand on

its own from a business case.” —Rod Hanson, Alyeska’s Valdez Marine

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the cost and schedule so economic mod-els can be run to determine if the changeswould be economic. That analysis wouldbe presented to the owners at the end ofthis year or early in the first quarter of2005.

Installing the internal floating lids willtake at least a couple of years of con-struction work, Hanson said.

Strub said the work inside the tanks is“the critical path for this project: It’s thesingle activity that has the longest dura-tion,” and so the plan is to start that workfirst.

In fact, Strub said, they’ll requestfunding in August for the first two tanks,for work to begin in January. That allowslead time for materi-als and contractors,so that — subject tooverall projectapproval at the firstof the year — workcan begin on thefirst two tanks,which will be emp-tied for regularlyscheduled mainte-nance. On thatschedule, majorwork would be com-pleted in 2007.

Work done inside the tank Installation of a floating lid requires

that a hole be cut in the side of the tank,Strub said. First the tanks are emptied andcleaned, and any needed internal repairsare done to the tank.

There are columns inside the tank,supporting the external roof. The internalfloating roof is constructed inside thetank, around the columns and sits on land-ing legs.

“It floats on the surface of the oil,”Hanson said, but has legs so it “can onlycome down to within about six or sevenfeet” of the floor of the tank because thereis equipment in the bottom of the tank.

“And then that allows you later todrain a tank and let it sit on its legs andthen you can get access in to do inspec-tion and repair work, to do maintenancework,” he said.

Firewater system would be changed to freshwater

Preliminary engineering will also lookat the largest of the standalone projects:changing the terminal’s firewater system,currently a pump-driven seawater system,to a freshwater gravity system.

The seawater system accounts for “ahuge amount of cost” at the terminal,Hanson said, more than $30 million injust the last five or six years, “a lot of itdriven by the corrosiveness of saltwater.”The system uses a number of mainpumps, plus smaller pumps, to move sea-water around the terminal in a buriedloop.

There is a rock quarry above the westtank farm, from terminal constructiondays, and Alyeska has done some geo-technical analysis and some engineeringwork and is proposing to create a fresh-water retention basin in the old quarry: “agravity freshwater supply system for ourfirewater system … sized for three timesthe amount of firewater we would need,”Hanson said.

The first advantage, he said, is that it’sno longer saltwater. And because it’sgravity driven you don’t have to rely onpumps, so it’s “even more reliable thanthe current system. And it pulls a lot ofmaintenance costs out of the system.”

The bottom of the reservoir in the pro-posed firewater retention pond is at anelevation of 700 feet, Strub said, com-pared to an elevation of 421 feet at thebottom of the highest tank in the east tankfarm.

Hanson said they’ve been asked if thegravity firewater system would provideenough pressure. Because of the elevationchange there would be “so much pressurethat we’re going to have to put pressure-reducing components in to avoid overpressuring the lower terminal,” he said.While this project is separate from thetank and power/vapor changes, it wouldlikely be implemented around the sametime, Hanson said.

This project is for onshore firewateronly. There are saltwater firewater pumpson the berths in use, berth 4 and berth 5,the only two berths in use at the terminal,“and we haven’t yet decided what theright answer is out there,” he said.

Ballast water changes have own justifications

Alyeska is also looking at changes tothe ballast water system, Hanson said, butthat proposal isn’t as far along as the tank,power/vapor and firewater changes, andwould be done later.

The ballast water plant “is currentlyrunning at about 33 percent capacity,” hesaid. The volume of ballast waterprocessed will continue to decline,Hanson said, and in the next five or sixyears, the current volume of waterprocessed will be cut in half.

Older tankers carry ballast water intheir crude oil tanks, so their ballast water“has remnants of oil from the last cargoload,” he said. When the tankers arrive atthe terminal, they pump the ballast waterthrough buried piping to three ballastwater treatment tanks — the first of threesteps in ballast water treatment. The oilywater sits in the tanks, the oil rises to thetop and is skimmed off and reinjected intothe crude oil system.

“The water is pulled off the bottomand runs through the second state of treat-ment … dissolved air flotation,” Hansonsaid. Air is injected into the water col-umn, creating bubbles which are mixedwith a polymer and rise to the surface,taking more oil out of the water andbringing it to the surface where it can beskimmed off. The water is then routed tobiological treatment tanks wheremicrobes eat the remaining componentsof oil in the water.

The entire process takes a couple ofdays, and at the end the water is dis-charged into the port.

New tankers have segregated ballast tanks

The new double hulled tankers, how-ever, have segregated ballast tanks, so thewater doesn’t come into contact withcrude oil, and doesn’t require treatment,and as more come into service, theamount of ballast water needing treatmentwill continue to decline.

At some point, Hanson said, there is

just a little ballast water which is comingin batches, and “this system is really notdesigned to operate that way. It’sdesigned to operate more in a steady-statemode.”

Of particular concern, he said, is thefinal biological stage, which may not be aviable process for batches.

The conceptual thinking is that the firststage, gravity separation, would remain,although probably with two tanks ratherthan three.

The second stage — dissolved airfloatation — could be replaced withinduced gas floatation, which works onabout the same principle, forcing gasthrough the water instead of air, againwith a polymer that brings oil to the sur-face.

The induced gas floatation system isenclosed in a vessel and any emissionsare contained within the system.

Hanson said it is a simpler processtechnologically, less costly to operate andis more environmentally friendly.

“We’re actually doing some pilot workright now to prove out whether that tech-nology is going to work for us or not,” hesaid.

Alyeska is looking at replacing thethird stage, the biological process, withcarbon absorption, but Hanson said thatchange is far enough out in the future thatthe company is waiting to see what newtechnologies might be developed over the

next several years.

Metering changes could happen by 2008

Another standalone project is chang-ing crude oil metering. Oil is meteredwhen it enters the terminal at the eastmetering facility. Metering performs animportant leak detection function,Hanson said, because a variation betweenoil received between metering stationsindicates a possible leak.

Another metering facility containsseparate meters for oil going to berth 4and berth 5. Keeping track of all of the oilis an important part of the terminal’s busi-ness, Hanson said: “It’s kind of the cashregister side of the business,” so main-taining the metering system is “a prettycritical part of what we do.”

The current meter systems are in-lineturbine meters, with the turbines spun bythe oil as it passes, and “that spinning tur-bine basically tells you … for each spin,how much oil goes by.” It’s very highmaintenance, he said.

There is a new technology that uses“ultrasound, not moving parts, to measurethe flow of oil,” and Hanson said thatwhile this technology is still a few yearsdown the road, it could be in use at theterminal by 2008. The ultrasonic meterswould be placed directly on the crude

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 17PIPELINES & DOWNSTREAM

continued from page 16

SIZING

John Barrett,Alyeska programmanager strategicreconfiguration

see SIZING page 17

JPO’s last surveyed pipeline workersin 2000, finding that employees believedthat Alyeska’s top management retaliatedagainst whistle-blowers. The office alsofound that concerns were never fullyresolved once they were brought up.

The upcoming survey was ordered byfederal regulators when they issued arenewal of Alyeska’s right of way permitsfor the 800-mile trans-Alaska pipeline in2002.

“We view it as a measuring stick,”DoBosh said.

Employees complained to Congress in 1991

JPO took a stronger interest in Alyeskaemployee concerns in 1991 after a groupof pipeline employees took complaints toCongress about worries over safety andenvironmental issues relating to pipelineoperations.

The employees said Alyeska’s man-agement harassed, intimidated and retali-ated against employees who brought upthose types of issues, and Congressionalhearings were held.

In response, JPO established a toll-freehot line for anyone to report concernsdirectly to the consortium. In 1993, theBureau of Land Management hired athird-party contractor to investigate theallegations raised during the congression-al hearings.

That probe confirmed widespreadoperational problems and claims ofemployee harassment.

As result, Alyeska established anemployee concern program in 1996 andhired an independent firm to conduct sev-eral employee surveys.

The surveys also documented employ-ee dissatisfaction, distrust and fears aboutretaliation for reporting problems.

The JPO has conducted more surveys,finding improvement over the long-term

in some areas.

Last survey conducted in 2000 JPO’s last survey, conducted in 2000,

resulted in three recommendations.First, Alyeska should see if claims ofharassment from Alyeska’s top manage-ment were true. If so, Alyeska must takesteps to eliminate the harassment.Second, Alyeska should make sure itscontractors, which employ 68 percent ofthe pipeline work force, comply withestablished employee concerns pro-grams. Third, Alyeska should make sureemployees’ concerns are fully addressedand recommended the company formal-ize a procedure on how to do so.

Alyeska took the recommendationsseriously and has worked on the issuessince then, DoBosh said.

Curtis Thomas, Alyeska’sspokesman, said the company doesn’twait until survey results are revealed tofind out what their workers feel abouttheir work environment.

“Managers and supervisors are con-tinuously receiving training designed tokeep them in tune with employee con-cerns. That will continue,” Thomas said.

Thomas said some employees willlikely voice concerns about upcominglayoffs as the result of the companystreamlining operations by upgradingequipment and converting to electricalenergy to power some pump stationsalong the 800-mile pipeline.

—THE ASSOCIATED PRESS

lines. The metering facility to the berthswouldn’t be needed, and operations andmaintenance work associated with meter-ing would no longer be needed.

“The same thing with the incomingmeter system here that we use for leakdetection — ultrasonics is a potentialreplacement for that,” he said.

Company will rethink how it operates All of the proposed changes, Hanson

said, give the company “an opportunity torethink how we operate, how we main-tain, how we staff the organization forthis.” The terminal has operations, main-tenance and support teams.

Operations are divided into four majorareas: power/vapor; marine; ballastwater; oil move-ments and storage— metering, tankfarms, etc. “In thefuture, with whatwe’re describinghere, we’ll proba-bly just have a sin-gle operationsteam that will have a different set ofresponsibilities from what we currentlyhave laid out.”

“It will still likely be a 24-hour a day,seven-day-a-week operation,” Hansonsaid. Maintenance now works just duringthe day, and there will continue to be amaintenance team, “but as you can imag-ine the amount of maintenance that we’rehaving to do in the future is going to be alot less than what we do now.”

And Alyeska is just starting to look atthe ship escort response vessels system tosee what change could be possible forchanging that cost structure.

Headcount will be affected There are now 300-plus Alyeska

employees at the terminal and the shipescort response vessels system and anequal number of contractor employees,Hanson said, although the contractorcount is a year around average, and thereare more contractors in the summer whenmajor projects and maintenance are done.

Hanson said that while it is too earlyyet to know the impact on employees,“we’ve committed to letting our employ-ees know as soon as we have somethingto share, and then sharing it outside thecompany as well.” He said Alyeska“made a decision early on that we willprovide our employees as much opportu-nity to plan for their future as we can, andso as information is available we’re shar-ing that with employees.”

And, he said, the company is also try-ing to help employees understand that“there’s a lot that’s changing, but there’s alot that stays the same. In the end, we’restill in the same business, we’re still

doing the same thing, we’re still havingthe same level of high standards aroundsafety and environmental performancethat we have now.”

There will be opportunity, he said, and“some kind of neat technology to do ourjobs with in the future. …

“But it’s going to be a smaller organi-zation.”

Organizational changes part of cost Included in the commercial analysis

are the costs of organizational transition,Strub said: You have “to run what you’vegot, build what’s new, start up what’s newand then, finally, ramp down what’s oldand continue to operate on what’s new,and that all becomes part of the commer-cial cost of your investment.”

“We’ve got basically three organiza-tions in place, or being put in place,” saidHanson: “Chuck (Strub) is responsible

for the projectmanagement ofthese changes;I’m responsiblefor the day-to-dayoperations of thecurrent facilityand helpingdesign the organi-

zation to maintain and operate the futureValdez terminal; there’s another team thatwe’re forming up, called a transitionteam, and this team is going to help us getfrom here to there.”

Hanson said planning includes: train-ing employees for the new systems;determining how to staff the organization;outlining benefits for those leaving theorganizations; and making sure that doc-uments in the future match the newequipment and that the old documents areretired. “It’s a large piece of work that hasto be done right,” he said, and so oneteam will focus specifically on the transi-tion.

“We put as much effort into planningthe transition as we do planning the proj-ect — it’s that big,” said Barrett.

Spill preparedness Hanson said that Alyeska has been

asked if there will be enough employeesleft to respond in the event of an emer-gency.

The company is going to review theissue of the resources needed for spillresponse, so that it knows during thepreliminary engineering phase, “howmany people we need for emergencyresponse.”

As for overall changes, “at a mini-mum we’re going to maintain safety andsystems integrity, but in many respects Ithink we’re going to improve.” Forexample, he said, “power/vapor is oneof our most complex facilities in thesystem” and the only facility Alyeskahas governed by process safety manage-ment standards because it handlesvapors, generates power and usessteam-fired turbines and boilers. “Andthat all presents risk and that basicallygoes away — it becomes a much sim-pler operation.”

Operations control central also relocating

Although it isn’t a part of the recon-figuration, Alyeska’s operations controlcenter will be relocating from Valdez toAnchorage in 2006, in the midst of theproposed reconfiguration changes. Thatmove, announced in February, allowscontrol center personnel to work moreclosely with the oil movements andscheduling departments, which are inAnchorage, Alyeska said in a Februarystatement. �

18 PETROLEUM NEWS • WEEK OF JUNE 6, 2004PIPELINES & DOWNSTREAMcontinued from page 17

SIZINGcontinued from page 14

POLL

“We have to get to a point where wesee that this has an economic return,

and we’re not there yet.” —Chuck Strub, Alyeska special projects manager

in charge of the terminal changes

The upcoming survey wasordered by federal regulatorswhen they issued a renewal ofAlyeska’s right of way permitsfor the 800-mile trans-Alaska

pipeline in 2002. “We view it asa measuring stick.”

—Rhea DoBosh, Joint Pipeline Officespokeswoman

PETROLEUM NEWS 19WEEK OF JUNE 6, 2004

natural gaswww.PetroleumNews.com

MACKENZIE VALLEYMackenzie Gas Project to gobefore joint review panel

Canada’s Indian and Northern Affairs Minister Andy Mitchell hasopened the door for a joint review panel to conduct an environmentalimpact review of the C$4 billion Mackenzie Valley natural gaspipeline. He approved a request from the Mackenzie ValleyEnvironmental Impact Review Board to enter into an agreement withfederal Environment Minister David Anderson to set up the panel.

Next, the Canadian Environmental Assessment Agency and theInuvialuit Game Council will settle on the draft terms of reference forthe developer’s environmental impact statement and the draft jointreview panel agreement. The decision to order a panel review flowedfrom concerns raised at public meetings in Norman Wells, Inuvik andFort Simpson along the proposed pipeline route in the NorthwestTerritories. The issues which attracted most concern were: Economicand infrastructure; social and cultural; and cumulative effects.

The environmental review board decided that the review shouldinclude all facilities and activities in the three anchor gas fields on theMackenzie Delta and a central gas processing plant.

It should also cover a 1.9 billion cubic foot per day pipeline andthe extension of the Alberta transmission system to link up with theMackenzie pipeline.

—GARY PARK, Petroleum News Calgary correspondent

RUSSIAPetro-Canada dabbling in LNGfield, looking at plant in Russia

Petro-Canada is going top shelf as its starts to explore the lique-fied natural gas supermarket. The Calgary-based integrated hascozied up to gas giantGazprom as it explores thepossibility of a C$1.8 bil-lion LNG plant in Russia —the first foray by a CanadianE&P company into theLNG world, althoughpipeline companiesTransCanada PipeLines andEnbridge are actively seeking a deal.

Both Petro-Canada and Gazprom, which controls 25 percent ofthe world’s gas reserves, have indicated they are engaged in tenta-tive discussions, although Petro-Canada refuses to characterize thetalks as being at the stage of a full proposal. A spokeswoman forPetro-Canada, reacting to a disclosure by Gazprom deputy chiefexecutive officer Alexander Ryazanov, told the Calgary Herald May26 that the conversations are “very early days ... to say there is a pro-posal on the table would be stronger words than we would use.”

However, she conceded that Petro-Canada is attracted toGazprom because of its size and scope and its array of assets.

Russian news reports say Petro-Canada is weighing an LNGplant at St. Petersburg that is capable of handling 3 million to 5 mil-lion tons a year of gas from Gazprom’s Siberian fields.

An LNG venture would be consistent with Petro-Canada’s glob-al ambitions since its takeover of Germany’s Veba Oil & Gas twoyears ago for C$3.2 billion which has opened up Europe, Africa,Asia and South America to a company that was once Canada’s state-owned oil firm.

—GARY PARK, Petroleum News Calgary correspondent

� T E X A S G U L F C O A S T

Texas LNG project movesahead; first in U.S. since ’82FERC issues EIS for Freeport site;construction to start later this year

By LARRY PERSILYPetroleum News Government Affairs Editor

he Federal Energy Regulatory Commissiondecision to issue a final environmentalimpact statement for the FreeportDevelopment LNG L.P. project on the Texas

Gulf coast is a boost to proponents of building newliquefied natural gas terminals to fulfill domesticenergy needs.

FERC’s May 28 announcement means develop-ers on are target to start construction later this yearand to start taking LNG deliveries during the sec-ond half of 2007, putting Freeport in a good posi-tion to be the first new LNG receiving terminal inthe United States since 1982.

FERC staff concluded the project would have“limited adverse environmental impact,” accord-ing to a press release from Cheniere Energy Inc.,which holds a 30 percent interest in the Freeportventure.

The proposed 233-acre terminal, on QuintanaIsland in front of Freeport, a city of 13,000 resi-dents about 40 miles south of Galveston, isplanned for an initial daily send-out capacity of 1.5billion cubic feet. Dow Chemical Co. andConocoPhillips Co. have contracted for the fullcapacity.

Plans include storage facilities for 6.9 bcf, and

a 9.4-mile pipeline to take the gas to StrattonRidge, Texas, a major connection point for Texasintrastate pipes.

The impact statement is the last step in FERC’senvironmental review of the project, with a finalorder expected soon for construction and opera-tion. Freeport Development filed its FERC appli-cation in March 2003.

ConocoPhillips, Dow take 100% of capacityConocoPhillips in December 2003 signed an

agreement with Freeport Development to take onprimary construction and operation managementof the facility, and to contract for 1 bcf per day ofthe capacity. In exchange, ConocoPhillips agreedto provide construction funding, estimated at about$500 million, and paid Freeport LNG a “nonre-fundable capacity reservation fee of $10 million,”according to Cheniere Energy.

Also as part of the deal, ConocoPhillips is tak-ing a 50 percent interest in the general managingpartner Freeport LNG-GP Inc., which had beenowned 100 percent by Michael Smith, a formerpresident of Basin Exploration Inc., of Denver,Colo. Smith formed the Freeport venture in 2002specifically to build the LNG terminal.

In addition to the managing partnership ofConocoPhillips and Smith, the Freeport projectincludes Cheniere Energy, of Houston, andContango Oil and Gas as limited partners.Contango is a Houston-based independent Gulf

T

� A L A S K A

Alaska looks at gas liquidsConsultant advises state on NGLsfrom proposed North Slope gas project

By LARRY PERSILYPetroleum News Government Affairs Editor

aking money from the ethane, propane andother natural gas liquids that come up withthe methane in North Slope natural gas isn’tas easy as simply building a gas pipeline and

stripping out the liquids somewhere along the way.A consultant advising the state of Alaska said the

challenges include deciding where to strip the liquidsfrom the gas stream; figuring out an affordable wayto get the ethane and other liquids to manufacturers;and finding manufacturing capacity for turning theraw materials into plastics and other products —whether building, expanding or using existing plantcapacity.

“The petrochemical industry is notorious for somepretty horrendous cycles,” said Lesa Adair, a vicepresident at Muse Stancil, a worldwide energy indus-try consulting firm headquartered near Dallas. TheAlaska Department of Revenue signed a $90,000contract with Muse Stancil in March, and companyofficials presented an initial NGL briefing to stateofficials the last week of April.

The state wants to learn more about potential usesfor the liquids produced from a North Slope naturalgas project as it negotiates with producers and othersinterested in building a multibillion-dollar pipeline tomove the gas to market. Muse Stancil’s job is to ana-lyze the economics of possibly creating a petrochem-ical industry in Alaska, including whether the liquids’

volume would be sufficient to supply a new facility.The analysis includes looking at a possible liquid-

stripping plant in Fairbanks or elsewhere, grabbingthe ethane and other liquids from the gas line as ittakes the methane from the North Slope and intoCanada for distribution across North America.

Consultant looks at Alaska economicsMuse Stancil’s contract also calls for a review of

the advantages and disadvantages of stripping theliquids in Alaska and finding a way to ship the prod-ucts to markets vs. sending liquids-rich gas toAlberta for processing and then shipment throughexisting pipe and rail systems to customers.

“It’s one of those balancing acts,” Adair said,measuring the cost of new plants and/or newpipelines vs. using existing or expanded facilities.

Alberta has more natural gas liquids than it needsfor its own petrochemical plants and exports a lot ofWestern Canada’s liquids to U.S. and EasternCanada plants, Adair said. Much of the liquid pro-duction from Canada ends up traveling a long dis-tance to petrochemical plants in Texas. “That’swhere the bulk of the demand is,” Adair said in aninterview last month.

Ethane is used for petrochemical feedstock;propane for industrial, commercial and retail cus-tomers, crop-drying and other farm uses; and butanefor gasoline blending, aerosols and fuels.

Depending on market conditions and Btu require-ments for the end users of Alaska gas, a North Slopegas project supplying 4.5 billion cubic feet per day,as proposed by the major producers, could createNGL volumes of up to 100,000 barrels a day. That’s

M

see TEXAS LNG page 20

see GAS LIQUIDS page 20

CANADACanada promotes natural gasfor vehicle fleets, C$3 carrot

Canada’s government wants fleet owners to switch to natural gasfor their vehicles. And there’s a carrot — well, better yet, 3,000Canadian dollars toward the purchase price.

The idea is to reduce emissions of greenhouse gases. Natural gaspower means a 21 percent cut in those gases.

The government says fleet owners will save on fuel costs as wellas doing their bit for the environment.

The pilot project is targeted at urban areas in Ontario, Albertaand British Columbia.

—ALLEN BAKER, Petroleum News contributing writer

Russian news reports say Petro-Canada is weighing an LNGplant at St. Petersburg that is

capable of handling 3 million to5 million tons a year of gas

from Gazprom’s Siberian fields.

about 5 percent of total U.S. demand.“The natural gas liquid is not the con-

sumable,” Adair said. “It has to have manyother things done to it.”

Ethane, for example, is used to makeethylene, which then can be manufacturedwith other components to make a widerange of products, including polyethyleneplastic for packaging, antifreeze and air-craft de-icer, vinyl siding and even gardenhoses.

Review will consider possible Alaska incentives

Many Alaskans have long dreamed of apetrochemical industry in the state, creatingjobs and diversification in the oil and gasindustry that dominates the state’s econo-my. The Department of Revenue contractwith Muse Stancil pointedly addresses thatvery issue, asking the consultant to look atwhat kind of subsidies might be needed tomake an Alaska petrochemical complexeconomic compared to the alternative ofsending North Slope liquids to Alberta orelsewhere.

Perhaps the state’s tax structure orpipeline tariff may need to include incen-tives or a separate rate to assist in bringingNGLs to market or developing an industryin Alaska, Muse Stancil said in its openingpresentation to the state. That could includeflexibility in valuing the products for royal-ty or tax purposes.

“They’re really just some thoughtpoints,” Adair said in an interview a fewweeks after the presentation.

“This (report) does not attempt to adviseon any course of action, but rather simplydescribes the industry into which Alaskagas and NGLs will compete,” Muse Stancilsaid in its opening presentation.

Utilizing the liquids is a matter of decid-ing where they have the highest value.Taking out the liquids from the gas streamand breaking them apart — fractionation —into ethane, propane, butane and othercomponents is not always so profitable.

That’s a separate operation from the gasconditioning plant that would be needed onthe North Slope to take out the carbon diox-ide, hydrogen sulfide, water and otherimpurities from the gas before putting itinto a pipeline.

Gas liquids business not always profitable

Depending on market conditions, thesecond step, taking out the gas liquids, is atough business. A Muse Stancil chart ofaverage net operating margins for NGLplants from 1990 through March 2004shows U.S. Midcontinent and Gulf Coastplants operated at losses for five periods ofseveral months each over the years — thelongest lasting about a year in 1998-1999.The operating margin for Gulf Coast plants,excluding overhead, capital expendituresand return on capital, was under 20 centsper thousand feet of gas fed into the plantfor all but two brief periods over the past 14years.

“The sale of natural gas liquids is cer-tainly not a slam dunk from a profitabilitystandpoint,” said Dave MacDowell, naturalgas project spokesman for BP Exploration(Alaska) Inc. in Anchorage.

That’s also what the numbers say in theannual reports of Canadian pipeline opera-tor Enbridge Inc., which owns 42.7 percentof the Aux Sable Liquid Products plant inIllinois. Aux Sable strips the NGLs from

the more than 1.5 bcf per day of wet gasdelivered through the Alliance Pipelinefrom Western Canada. Enbridge’s share ofthe loss from Aux Sable was $6.9 million in2003, $3.1 million in 2002 and $6.2 millionin 2001, according to Enbridge’s annualreports.

Regardless of whether North Slope gasline project developers can turn a consis-tent, reasonable profit from the liquids,much of it has to be removed from Alaskagas somewhere before delivery to utilitiesand other customers. Otherwise, the gaswould be too rich — too high of a Btu level— for customers, MacDowell said.

Much of the heavier liquids are alreadypulled from the gas during oil productionfrom North Slope reservoirs and mixed inwith the oil down the trans-Alaska oilpipeline, leaving a higher proportion oflighter ethane and propane for later recov-ery during a gas line project.

The biggest fractionation centers inNorth America, Muse Stancil explained,are in Sarnia, Ontario, just across theMichigan border and fed by a couple oflarge pipeline systems reaching fromWestern Canada, through the Midwest andinto Ontario; Conway, Kan., served by mul-tiple pipelines from north and south; andEdmonton, Alberta. The reference pricepoint for North America NGL is at MountBelvieu, Texas, in the center of the GulfCoast petrochemical industry.

Propane to Midwest, ethane to Gulf Coast

NGL markets tend to be geographicallyisolated, Muse Stancil said, with a lot of thepropane going to the Midwest for crop dry-ing and other agricultural uses. Most of theethane, however, is shipped by pipe or rail tothe Gulf Coast to feed the petrochemicalplants.

“There is no ethane market in Chicago,never has been,” said Ed Small, a consultantand 30-year veteran of the natural gasindustry in Calgary. Depending on marketconditions, he said, much of the ethane canoften earn more staying in the gas streamthan paying its own way from Canada to theGulf Coast for delivery to a plastics plant.

And though ethane usually sells formore than dry gas, a Muse Stancil chart pre-sented to state officials shows ethane sellingat close to natural gas or less in early 1996,1997 and 1998, and pretty consistently thesame or less since natural gas prices startedtheir run-up in early 2001. And while that isgood news for gas producers looking for thebest price for their liquids, it’s been veryhard on U.S. petrochemical plants that needaffordable feedstock. �

20 PETROLEUM NEWS • WEEK OF JUNE 6, 2004NATURAL GAS

Coast oil and gas exploration and produc-tion company.

For its part of the deal, Dow reserved500 million cubic feet per day of capaci-ty for 20 years. The chemical giant’sfacilities in the Gulf Coast region con-sume nearly 700 million cubic feet perday of natural gas. Dow will be able tomarket what it doesn’t need fromFreeport to other industrial consumersand gas distribution hubs in the area.

Neither Dow nor ConocoPhillips haveannounced any LNG supply deals forFreeport, though the oil and gas major hassaid it is looking at possibly bringing ingas from Venezuela, Nigeria or Qatar.

Cheniere also looking at two other LNG projects

Cheniere, looking to become a leaderin the Gulf Coast LNG business, also is

working to develop two other receivingterminals along the Gulf of Mexicocoastline — at Corpus Christi, Texas, andSabine Pass, La. The company submittedits FERC applications for both projectsin December 2003.

The Corpus Christi terminal would beadjacent to the Sherwin Alumina Co.plant on 600 acres along the La QuintaShip Channel. Sherwin Alumina, former-ly the Reynolds Metals Co. Sherwinplant, extracts aluminum oxide frombauxite ore.

The Sabine Pass terminal is proposedfor 570 acres along the Sabine PassChannel in extreme southwest Louisiana,just across the border from Texas.

Each project would include storagefor 10 bcf of gas, and capacity to handleas much as 2.6 bcf per day of LNG deliv-eries, with start-up of operations sched-uled by 2008. Cheniere plans to operateboth terminals as tolling facilities, and islooking to sign up users for long-termdeals. �

continued from page 19

TEXAS LNG

Alaska gas could affect price, consultant saysFinding buyers for all the natural gas coming down the pipe from a large Alaska gas

line project could require some initial price discounting, cutting into profitability in theearly years, says a consultant helping to advise the state.

But the markets would anticipate the delivery of Alaska gas after a decision is madeto build the line and would adjust to the new supply, said Lesa Adair, a vice presidentat Muse Stancil, a worldwide oil and gas consulting firm under contract to the state ofAlaska.

“I agree there is going to be some impact on price,” she said in an interview lastmonth. “But it’s not going to be a situation … (where) the next day it’s going to be mag-ically delivered in Chicago.” The market will have a lot of advance notice to plan forAlaska gas.

“Everyone who is looking at liquefied natural gas projects or Alaska gas … will allbe making decisions,” she said.

Industry observers have said they expect any go-ahead announcement for an Alaskagas line would deter potential LNG developers from building more receiving terminalsthan the market will need in the years ahead when an Alaska line starts competing withperhaps 4.5 billion cubic feet per day of new supply.

The Alaska Department of Revenue has Muse Stancil on contract to advise stateofficials on natural gas and gas liquids issues as the state negotiates with the majorNorth Slope producers and others for possible development of a multibillion-dollarpipeline project. Muse Stancil presented an initial briefing to state officials in late April.

Market penetration a matter of price“Although overall (natural gas) demand growth is expected … penetration of desti-

A rendering of the proposed Freeport, Texas, LNG plant.

continued from page 19

GAS LIQUIDS

see CONSULTANT page 22

Utilities not likely toguarantee take-or-payprice for Alaska gas

By LARRY PERSILYPetroleum News Government Affairs Editor

ooking around for candidates to sharein the financial gamble of a multibil-lion-dollar Alaska natural gas pipeline,it doesn’t appear likely that state regu-

lators would allow gas utilities to take onmuch of the price risk.

Although long-term, take-or-pay con-tracts could protect gas producers andpipeline investors from the financial fear oflow market prices, they also could put utili-ties in the position of paying above-marketprices for Alaska gas in the future. That’ssomething that utility regulators, and con-sumers, don’t like.

But finding a way to spread the riskbetween parties is one of the key unresolvedissues in getting North Slope producers tocommit to the project.

An Alaska gas line moving 4.5 billioncubic feet per day would carry almost $5.8billion worth of gas a year, at $3.50 per thou-sand cubic feet. And with the projectedpipeline tariff possibly eating up two-thirdsof the revenue — if construction cost esti-mates come true — the producers worrywho will help share the risk during periodsof low gas prices.

“You’re probably not going to see LDCs(local distribution companies) take a bigshare of the risk,” said Bill Garner, a manag-ing director of energy investment bankPetrie Parkman & Co., in Houston.“Naturally, LDCs are a little gun-shy aboutsigning these long-term contracts.”

Utilities aren’t necessarily required toobtain regulatory approval of their gas sup-ply contracts but they do need approval oftheir rates, and consumers can protest if theybelieve the utilities are overcharging for gas.

“We know of a number of utilities thatare discouraged (by state regulators) fromsigning long-term contracts,” said MichaelZenker, senior director for CambridgeEnergy Research Associates’ NorthAmerican Natural Gas Service.

Regulators may shift thinking, but it’s too early

Some public utility commissions haveexpressed interest in perhaps moving awayfrom their opposition to long-term gas sup-ply contracts, though it’s still early in theevolution, Zenker said. “We have not seenany material shift away from that.”

Utilities have a responsibility to ensurethat their customers have adequate suppliesof gas, but it’s impossible to know howmuch gas might cost in the future and howmuch utilities should promise to pay for thatsupply. “What always happens to these dealsis the market turns on you,” Garner said.

“Generally, it comes down to the pruden-cy standard. Was it prudent to enter into thecontract at that point in time,” he said. “Theproblem with prudency, it’s always second-guessed.”

Contracts for long-term pipeline shippingcapacity are different than contracts to buygas at a set price, said John Cita, chief econ-omist for the Kansas CorporationCommission, which regulates utilities in thestate. Signing a long-term deal for pipelinetariffs, or even for gas at prices tied to afloating market index, isn’t a problem com-pared to a long-term supply contract at fixedprices, he said.

“Gas LDCs in the Lower 48 have aresponsibility to serve,” Cita said, but takingon the price risk for future gas deliveriescould overstep that responsibility.

Utilities tried long-term contracts in the ’80s

Utilities took such risks in the early1980s, Garner said, when tightening gassupplies and steeply rising prices worried alot of people. The wellhead price for naturalgas in the United States averaged 50 centsper thousand cubic feet in the 1970s, jump-ing to $2 per mcf by the 1980s. The worstyear was 1984, when wellhead prices aver-aged $2.66 — a record that held for 16years.

The problem is utilities signed long-term,take-or-pay contracts during the time of tightsupplies and high prices, only to see pricesslide back to under $2 by 1986 and staythere until 1996.

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 21NATURAL GAS

� A L A S K A

Natural gas price risk sharing an issue

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Enbridge may want 20% stake inpipeline, but not nearly that much gas

Gas pipeline owner and operator Enbridge Inc. is looking to take maybe a 20percent stake in the proposed Alaska gas line project, but isn’t interested in sign-ing up for the market price risk on that much of the gas moving through the line.The 20 percent stake in the pipeline from Alaska’s North Slope to the NorthAmerica distribution system in northern Alberta is not a hard number but is“indicative” of the company’s potential financial interest, said John Carruthers,vice president for upstream development at Enbridge Pipelines Inc. in Calgary.

“We potentially could take some shipping commitments, but not in that range,”Carruthers said May 31. “That’s way more than we could.”

A commitment by its marketing and distribution affiliates to take 20 percent ofthe gas from a project moving 4.5 billion cubic feet per day, as proposed by theNorth Slope producers, would mean signing up for more than $1.1 billion a yearin gas at $3.50 per thousand cubic feet. Enbridge in 2003 generated about $4.8 bil-lion in total operating revenue.

The problems for advocates of an Alaska pipeline has been finding not onlylong-term buyers for that much gas but working out the potentially costly issue ofsharing the price risk.

see SHARING page 22see ENBRIDGE page 22

22 PETROLEUM NEWS • WEEK OF JUNE 6, 2004EXPLORATION & PRODUCTION

The risk of construction cost overruns,permit or regulatory delays, and the fearthat future market prices could fall shortof a profitable return for producers — orperhaps even short of the pipeline tariff ina down market cycle — are all part of theequation, Carruthers said.

Enbridge has announced its willing-ness to work with the state and NorthSlope producers to put together a finan-cially feasible project, and has gone so far

as to apply to the state to negotiate a fis-cal contract governing company pay-ments in lieu of potential taxes on theproject.

In looking to come up with its share ofthe money needed for construction,Carruthers said the company envisionsusing cash to cover 30 percent of its shareand borrowing the rest. Enbridge, just assome of the producers, said the pendingfederal loan guarantee under considera-tion in Congress is key to a go-ahead forthe gas line.

—LARRY PERSILY, Petroleum News government affairs editor

“The price of gas collapsed and they did-n’t want to take the gas anymore,” Garnersaid of utilities’ reaction to the marketchange. Utilities signed contracts stretching10, 15 or even 20 years back in the 1980s,but the norm today is usually just one or twoyears, he said.

A utility could be forced to swallow theloss if state regulators reject its rates based

on above-market gas prices under a long-term contract. “It’s almost a bet-your-com-pany kind of decision,” Garner said.

Without utilities to take on much of thelong-term price risk of an Alaska gas line,the great bulk of the financial hazard is leftto the producers, possibly industrial users ofthe gas, and maybe marketing affiliates ofpipeline companies. Federal law preventsinterstate pipeline companies from owningthe gas moving through their lines, leavingthat role for their affiliated companies,Garner said. �

nation markets may initially require pricediscounting to facilitate displacement ofexisting supply sources,” the consulting firmsaid.

“Initially, displacement of existingsources of supply may be necessary to real-ize full utilization of the available gas linecapacity. Shippers may have to displace notonly the highest-cost sources of existingsupply, but may also have to displace rela-tively inexpensive sources of existing sup-

ply in order to achieve maximum utiliza-tion.”

The consulting firm cautioned the state:“Maximum utilization may not achievemaximum profitability, especially in theearly years of operation.”

And, it warned the state, temporary bot-tlenecks in moving so much gas to where it’sneeded in North America could cause lowershort- or medium-term prices until addition-al pipeline capacity is available to break thejam.

— LARRY PERSILY, Petroleum News government affairs editor

continued from page 21

ENBRIDGE

continued from page 21

SHARING

continued from page 20

CONSULTANT

BRITISH COLUMBIADuvernay Oil makes tight sands gasdiscovery west of Dawson Creek

British Columbia’s tight sands gas plays continue to rack up successes, as juniorexploration company Duvernay Oil Corp. says it has made a significant natural gas dis-covery west of Dawson Creek.

In a press release, the company said a 13-well program has tapped into a gas poolin the company’s Sunset-Groundbirch-Saturn area with potential recoverable reservesof 250 billion cubic feet. The company says the wells are currently producing 10 mil-lion cubic feet of gas per day, and will increase to 30 million cubic feet per day by themiddle of 2005. The gas play, part of the larger Triassic-Doig tight gas sand formation,is estimated to be 80 kilometers long and two kilometers wide. The find is small com-pared to EnCana Corp.’s Greater Sierra (2.5 trillion cubic feet) and Cutbank Ridge tightgas plays, but adds weight to the growing importance of the play.

Tight gas, found in porous rocks such as sandstone, is more costly to produce andoften requires fracturing techniques to get the gas flowing. But with gas prices wellabove $4 per mcf, the economics work.

Duvernay controls another 115 potential drilling locations on the play, but it willtake two to three years of successful exploration and drilling to realize the upper end ofthe reserve potential.

The initial Groundbirch discovery has been delineated by 13 gas wells, along witha series of successful exploration new pool wildcats both north and south ofGroundbirch. Duvernay has a 100 percent working interest in the majority of thesewells. Gilbert Laustsen Jung Associates Ltd. prepared a reserve report for the compa-ny, identifying average proved reserves of 1.7 bcf per well bore and 1.9 bcf proved plusprobable reserves per well bore in the initial Groundbirch pool.

Gas production is being processed at a new sour gas treating facility, constructed byDuvernay in the fourth quarter of 2003.

Duvernay will drill eight to 10 delineation wells along the trend in the next 12months in an effort to further refine reserve and production potential.

—DON WHITELEY, Petroleum News contributing writer

Three North Slopefields show productionincreases in May

By KRISTEN NELSONPetroleum News Editor-in-Chief

verage daily crude oil productionfrom Alaska’s North Slope wasdown almost 1 percent in May com-pared to April, with an average of

966,900 barrels per day in May comparedto 976,428 bpd in April.

Although month-to-month productionaverages were down at several North Slopefields, including the largest — PrudhoeBay and Kuparuk— production was up atNorthstar, Alpine and Milne Point.

BP Exploration (Alaska)-operatedNorthstar had the largest April to Mayincrease, averaging 75,424 bpd in May, up19 percent from an April average of63,351. Production in April was down dueto work on the crude stabilizer at the field.The Alaska Department of Revenue saidNorthstar had output reductions May 11-12and May 23-25 for plant repairs.Production at the field dipped to 29,775barrels May 25, but also got above the80,000 bpd mark on seven days duringMay.

Production from BP’s Milne Point fieldwas up 1.6 percent, averaging 50,492 bpdin May compared to 49,685 bpd in April.

And the ConocoPhillips Alaska-operat-ed Alpine field averaged 106,543 bpd inMay, up 1 percent from an April average of105,454 bpd. Revenue said Alpine lost apower transformer May 17, and had athree-day planned throughput reductionMay 24-26. Production exceeded 100,000bpd on all but four days in May, and

exceeded 110,000 bpd on three days.

Other fields down The BP-operated Endicott field aver-

aged 27,293 bpd in May, down 5.3 percentfrom an April average of 28,817 bpd. TheBP-operated Lisburne field (includingPoint McIntyre and Niakuk) averaged53,571 bpd in May, down 5.1 percent froman April average of 56,449 bpd.

BP-operated Prudhoe Bay (includingMidnight Sun, Aurora, Polaris, Borealisand Orion) averaged 461,562 bpd in May,down 3.5 percent from an April average of478,176 bpd.

Production from the ConocoPhillipsAlaska-operated Kuparuk River field(which includes West Sak, Tabasco, Tarn,Meltwater and Palm) averaged 191,984bpd in May, down 1.3 percent from anApril average of 194,496 bpd.

The North Slope temperature at PumpStation No. 1 averaged 26.3 degreesFahrenheit, compared to 4.6 degrees F inApril, and compared to a three-year aver-age for May of 24.1 degrees.

Crude oil production in the Cook Inletbasin in Southcentral Alaska averaged25,130 bpd, up 2.4 percent from an Aprilaverage of 24,548 bpd. �

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� A L A S K A

Although month-to-month production averages were down at several North Slope fields,including the largest — Prudhoe Bay and Kuparuk— production was up at Northstar, Alpineand Milne Point.

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BP Exploration (Alaska)-operatedNorthstar had the largest April to

May increase, averaging 75,424 bpdin May, up 19 percent from an April

average of 63,351.

By KAY CASHMANPetroleum News Publisher & Managing Editor

laska is one of four key exploration hot spots forPioneer Natural Resources, Ken Sheffield toldmembers of the Alaska Support Industry AllianceMay 27. Sheffield is the president of Pioneer’s

Alaska subsidiary.The Dallas-independent is opening a permanent, 15-

person office in Anchorage and is looking for moreNorth Slope drilling prospects.

Sheffield told Alliance membersthat could all change if the state ofAlaska increases the tax burden onthe oil and gas industry.

“We came to Alaska because ithas a world-class petroleum sys-tem. … It’s a great place to find oil,but sometimes it’s not such a greatplace to make money,” he said.

Sheffield acknowledged thestate has been “improving the reg-ulatory environment in the lastcouple of years.”

Nonetheless, the North Slope is challenging for inde-pendents such as Pioneer, he said.

“It’s the most expensive basin in the world,”Sheffield said, citing the geologic risk common in anyoil province, as well as Alaska’s unique situations thatadd to the risk, including the high cost of transportingcrude oil to West Coast markets; protracted projecttimelines because of limited winter access; and lowactivity levels which reduce the number of oilfield serv-ice and supply contractors in the state and ultimatelydrive up costs because of a lack of competition.

The stability of the state’s fiscal policy is also a con-cern, Sheffield said, and could change his company’s

enthusiasm for Alaska.“I’m concerned about the talk of increasing taxes. It

would be hard for us to move forward if there were anynew taxes. The margins are too thin on the projectswe’re looking at.”

Alaska’s competition for Pioneer’s investment dol-lars — i.e. the company’s other three key explorationhotspots — are the Gulf of Mexico, particularly thedeepwater Gulf, North Africa and West Africa, Sheffieldtold Alliance members.

Portfolio of drilling prospects In Alaska, Pioneer hopes to build a “portfolio” of

drilling prospects: “We’re not just looking to drill one totwo wells per year,” he said, noting the company wouldachieve an “economy of scale” by drilling several wellseach year.

Pioneer currently has four North Slope prospects thatit has either drilled or hopes to drill, including Storms,south of Prudhoe Bay where Pioneer plans to shoot 3-Dseismic next winter; Gwydr Bay, north of theConocoPhillips-operated Kuparuk field; Caribou, whichis “north of Point McIntyre on trend with (BP’s)Northstar” (unit); the new Oooguruk unit, whichPioneer successfully drilled the winter before last and,according to Sheffield, expects to sanction for develop-ment in the fourth quarter of this year.

Goal to achieve step change One of Pioneer’s goals in Alaska is to “achieve a step

change in the North Slope cost structure,” Sheffieldsaid.

“In looking for big reservoirs, you’re going to findsmall reservoirs,” against which Pioneer is applyingwhat he calls the “independent mindset,” whichinvolves “challenging existing methods.”

One thing that needs to be done, Sheffield said, is to

“decrease project cycle times,” from the time of thelease sale until a project is in production. He believesthis can be done without jeopardizing the environment.

Leveraging existing North Slope infrastructure isanother way to bring down costs — something Pioneeris looking at doing in order to bring the Oooguruk unitonline.

The unit is in the shallow waters of Harrison Bay off-shore the North Slope, north and west of, and contigu-ous with, the ConocoPhillips-operated Kuparuk Riverunit. Due to a farm-in executed earlier this year by oper-ator Pioneer and partner Armstrong Oil & Gas’s affiliatein Alaska, ConocoPhillips retains the right to participatein any Oooguruk project sanctioned by Pioneer andArmstrong. Pioneer executives have talked about possi-ble production synergies with the Kuparuk unit’s exist-ing facilities versus a standalone production facility.

Pioneer to open permanent Alaska office

Sheffield lent credence to the speculation that theKuparuk facilities will be tied into the Oooguruk unit’sdevelopment when he told Alliance members May 27that Pioneer has leased half of the sixth floor of theConocoPhillips building in downtown Anchorage.Pioneer, which opened a small, 1,000 square foot officein Anchorage at Pacific Office Center on K Street earli-er this year, was expected to expand its square footagein that building.

Sheffield said the sixth floor space is in the processof being remodeled and by August will have a staff of15, including Sheffield; Pat Foley, manager of land,commercial and regulatory affairs; Mike Dunn, manag-er of engineering and development; Don Bryson, man-ager of exploration; as well as support staff that includestwo engineers and five geoscientists. �

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 23EXPLORATION & PRODUCTION

� A N C H O R A G E , A L A S K A

Pioneer looks to build Alaska drilling portfolioDallas independent opening permanent Alaska office in ConocoPhillips building, has concerns about state increasing oil industry taxes

No plans yet for Evergreen’s Alaskacoalbed methane properties, says Sheffield

The people who came to hear Ken Sheffield speak at a May 27 Alliance breakfastin Anchorage were hoping to hear Pioneer Natural Resources’ plans for the Alaskacoalbed methane properties it will inherit as part of its proposed acquisition ofEvergreen Resources. But Sheffield, president of Pioneer’s Alaska subsidiary, saiduntil the Evergreen deal isapproved by both groups of share-holders, no plans for the coalbedproperties in Southcentral Alaskawill be discussed.

A decision from shareholdersis expected in August orSeptember, he said. Until thattime, Pioneer and Evergreen willcontinue to operate as separatecompanies.

Sheffield reminded attendeesthat the primary reason Dallas-based Pioneer decided to buyDenver-based Evergreen isbecause of Evergreen’s Ratonbasin properties in southeasternColorado and northeastern NewMexico. From March 31, 1995,through Dec. 31, 2003, Evergreengrew its estimated provedreserves in the Raton Basin from58 billion cubic feet of natural gasequivalent to 1,393 bcfe, whichrepresents a compound annualgrowth rate of approximately 44percent. During the same period,the company’s net average dailygas sales from the basin increased from just over 1 million cubic feet of natural gasequivalent to approximately 131 million cfe.

Evergreen’s mineral rights on 300,000-plus acres in Alaska represent only about 2percent of Evergreen’s assets, Sheffield told Petroleum News.

Consequently, Pioneer’s evaluation team is focused first on the natural gas-pro-ducing Raton Basin and will eventually get around to Evergreen’s Alaska acreage,which is still in the exploration and production evaluation stage.

A

Ken Sheffield,Pioneer’s top execu-tive in Alaska

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24 PETROLEUM NEWS • WEEK OF JUNE 6, 2004EXPLORATION & PRODUCTION

APPALACHIATalisman U.S subsidiary Fortunareaches milestone in Appalachians

Fortuna Energy, a subsidiary of Canada’s TalismanEnergy, has surpassed 100 million cubic feet of daily naturalgas production from its Appalachian properties in theCorning area of New York, Talisman said June 1.

The company said it also completed the SRA3 No. 1 gaswell, drilled horizontally to a measured depth of 11,704 feet.The well tested a new structure in the upper Black River for-mation. It flowed tested at 19 million cubic feet of gas perday at a wellhead pressure in excess of 2000 psi, the compa-ny said.

“These are prolific wells and their location close to majorU.S. markets means that they are particularly valuable,” saidJim Buckee, Talisman’s chief executive officer, adding thatproduction in the area has increased from 60 to over 100 mil-lion cubic feet per day in recent months.

The northeastern United States now accounts for morethan 12 percent of Talisman’s consolidated North Americannatural gas production and generates about 18 percent of theoperating cash flow from North American gas operations.

“Fortuna is continuing to build its land base in the areaand is putting together plans for 2005,” Buckee said.

—RAY TYSON, Petroleum News Houston correspondent

“These are prolificwells and their loca-tion close to majorU.S. markets meansthat they are partic-ularly valuable,”said Jim Buckee,Talisman’s chiefexecutive officer,adding that produc-tion in the area hasincreased from 60 toover 100 millioncubic feet per day inrecent months.

OFFSHORE NEWFOUNDLANDNewfoundland’s Terra Nova field dealta setback, reserves slashed by 13%

The Canada-Newfoundland Offshore Petroleum Board has slashed its provenplus probable oil reserves for the offshore Terra Nova field by 13 percent to 354million barrels from its previous 405 million barrels.

Of the revised total, 87 million barrels has already been produced at the Petro-Canada-operated project, which is Newfoundland’s second offshore project afterHibernia.

The updated estimates also slashed total discovered gas resources to 44.9 bil-lion cubic feet from 269 billion cubic feet, although gas production is not on theimmediate horizon for Newfoundland.

The regulator listed Terra Nova’s proven reserves, those given a 90 percentchance of recovery, at 224 million barrels. Probable are given a 50 percent chanceof recovery.

The board said the biggest setback occurred in the so-called Far East region ofthe field, which tumbled to 45 million barrels of proven plus probable from 162million barrels, while the East Flank region lost 4 million barrels to stand at 144million barrels. Offsetting those losses, the Graben region surged to 165 millionbarrels from 95 million barrels.

In a separate assessment, the board said undiscovered hydrocarbon resources inthe newly emerging Flemish Pass basin are rated at 1.7 billion barrels, with a 50percent probability of being recovered, with expected field size ranging from 44million to 528 million barrels.

The basin, comparable in size to the Jeanne d’Arc basin, which holds theHibernia, Terra Nova, White Rose and Hebron-Ben Nevis fields, has barely beenscratched by explorers who have so far drilled only five wells.

Although no commercial accumulations of hydrocarbons have yet been foundin the Flemish Pass basin, hydrocarbon shows have been encountered, raisinghopes along with the Orphan basin that Newfoundland can still become a long-term producing region.

—GARY PARK, Petroleum News Calgary correspondent

NORTH AMERICARig count falls by 9 to 1,364

The number of rotary rigs operating in North America fell by nine to 1,364 dur-ing the week ending May 28, with both Canada and the United States sufferinglosses, according to rig monitor Baker Hughes.

The Canadian rig count fell by six to 195 compared to the previous week, andalso declined by 63 rigs versus the same period last year.

The total number of rigs operating in the United States in the recent weekdecreased by three to 1,169, but was up by three compared to the year-ago peri-od. Land rigs alone actually increased by three to 1,059, while offshore rigsdecreased by two to 93 and inland water rigs dropped by four to 17.

Of the total number of rigs operating in the United States during the recentweek, 1,012 were drilling for natural gas and 156 for oil, while one was beingused for miscellaneous purposes. Of the total, 760 were vertical wells, 284 direc-tional wells, and 125 horizontal wells.

Among the leading producing states in the United States, Oklahoma gainednine rigs in the recent week for a total of 163 rigs. Wyoming’s rig count was upby two to 72, while New Mexico’s was up by two to 66. Alaska picked up one rigfor a total of eight rigs. Louisiana suffered a loss of 11 rigs, dropping its count forthe week to 160 rigs. Texas’ rig count fell by six to 501, while California’sdecreased by two to 21.

—RAY TYSON, Petroleum News Houston correspondent

� N O R T H S L O P E , A L A S K A

Oil officials keep eye on high waterat Alpine field

THE ASSOCIATED PRESSpring thaw in the Colville RiverDelta has surrounded the Alpine oilfield in floodwater, prompting a sus-pension of drilling and other steps to

keep workers and the environment safe. Alpine is the third most prolific field

on the North Slope. Production of about100,000 barrels of oil a day has not beeninterrupted.

Melting and ice jams on the Colvilleand some channels have caused the high-est water levels at Alpine since the fieldstarted producing four years ago.

Floodwaters came within 16 inches ofthe base of the main pipeline at Alpine,according to officials at the AlaskaDivision of Oil and Gas. The pipelinetransports crude oil from Alpine to theKuparuk field about 34 miles away. Wateralso came within 14 inches of the lowestpoint of an access road connecting twodrilling pads. The pads sit on gravel about4 to 6 feet above the ground.

Flooding is a concern at oil fieldsbecause pipeline supports can erode outfrom underneath, destabilizing lines, saidLeslie Pearson, a state spill-responsemanager.

As of the morning of May 28, thewater levels appeared to be receding, butcity officials at nearby Nuiqsut remainedon heightened alert. Mayor Rosemary

Ahtuangaruak asked the North SlopeBorough to provide a staff person to mon-itor water levels in the channel nearesttown. The water was about 6 feet fromtopping its bank the last time shechecked, Ahtuangaruak said.

“I’d rather be proactive than to wakeup and have an ice chunk banging againstthe house,” Ahtuangaruak said.

Hydrologists for ConocoPhillipsAlaska, the company that runs Alpine, arechecking gauges and monitoring riverconditions daily by helicopter.Microwave communications have beenset up in case fiber optics fail due toflooding. A drilling rig was shut downand put in maintenance mode as a precau-tion, according to an e-mail Conoco sentto government agencies alerting them tothe situation.

Conoco spokeswoman Dawn Patiencedownplayed the severity of the risks.

“We haven’t executed anything opera-tionally different. Everything right now isnormal,” Patience said.

The Colville River Delta is a wellknown flood plain. Environmentalists hadopposed the field going forward, in partbecause of the flood risks.

Precisely because of the topographyand conditions, structures at Alpine werebuilt to withstand a 200-year flood,Patience said. �

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PETROLEUM NEWS • WEEK OF JUNE 6, 2004 25ADVERTISER 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

AAeromapAeromedAES Lynx EnterprisesAgriumAir Logistics of AlaskaAlaska Airlines CargoAlaska AnvilAlaska CoverallAlaska DreamsAlaska Interstate Construction. . . . . . . . . . . . . . . . . . . . . . . . 27Alaska Marine Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Alaska Massage & Body WorksAlaska Railroad Corp.Alaska SteelAlaska Tent & TarpAlaska TerminalsAlaska TextilesAlaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Alaska’s PeopleAlliance, TheAlpine-Meadow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7American Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Anchorage HiltonArctic ControlsArctic Fire & SafetyArctic FoundationsArctic Slope Telephone Assoc. Co-opArrowHealthASRC Energy ServicesASRC Energy Services

Engineering & TechnologyASRC Energy Services

Operations & MaintenanceASRC Energy Service

Pipeline Power & CommunicationsAvalon Development. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

B-FBadger ProductionsBaker HughesBrooks Range SupplyCapital Office SystemsCarlile Transportation Services. . . . . . . . . . . . . . . . . . . . . . . . . 5Carolina MatCH2M HillChiulista Camp ServicesCN AquatrainColvilleConam ConstructionConocoPhillips Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Craig Taylor EquipmentCrowley AlaskaCruz ConstructionDowland - Bach Corp.Doyon DrillingDynamic Capital ManagementEngineered Fire and Safety . . . . . . . . . . . . . . . . . . . . . . . . . . 11ENSR AlaskaEpoch Well ServicesEra AviationEvergreen Helicopters of AlaskaEvergreen Resources AlaskaFairweather Companies, TheFMC Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Friends of Pets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Frontier Flying ServiceF.S. Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

G-MGolder AssociatesGreat Northern Engineering. . . . . . . . . . . . . . . . . . . . . . . . . . 12Great Northwest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Hanover CanadaHawk ConsultantsH.C. Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Hunter 3DIndustrial Project ServicesInspirationsJackovich Industrial

& Construction Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Judy Patrick PhotographyKakivik Asset ManagementKenai AviationKenworth Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Kuukpik Arctic Catering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Kuukpik/VeritasKuukpik - LCMFLounsbury & AssociatesLynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Mapmakers of AlaskaMarathon OilMarketing Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23MEDC InternationalMI Swaco. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Michael Baker Jr.Millennium HotelMWH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18MRO Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

N-PNabors Alaska Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21NANA/Colt EngineeringNatco Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Nature Conservancy, TheNEI Fluid TechnologyNordic CalistaNorthern Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Northern Transportation Co. . . . . . . . . . . . . . . . . . . . . . . . . . . 3Northwestern Arctic Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Offshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oilfield ImprovementsOilfield TransportPacific Rim Geological ConsultingPacific Rim Institute

of Safety and Management (PRISM)Panalpina. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12PDC/Harris Group. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Peak Oilfield Service Co.Penco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Perkins CoiePetroleum Equipment & ServicesPetrotechnical Resources of Alaska. . . . . . . . . . . . . . . . . . . . 22PGS OnshoreProComm AlaskaPrudhoe Bay Shop & Storage

Q-ZQUADCORenew Air Taxi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Salt + Light CreativeSchlumbergerSecurity AviationSeekins FordSpan-Alaska ConsolidatorSTEELFABStorm Chasers Marine ServicesTaiga VenturesThrifty Car RentalTOTE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Totem Equipment & SupplyTravco Industrial HousingUBS Financial Services Inc.Udelhoven Oilfield Systems Services . . . . . . . . . . . . . . . . . . . 3Umiat Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Unique MachineUnitech of AlaskaUnivar USAU.S. Bearings and DrivesUsibelli Coal MineVECOWeaver Brothers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26WorksafeWell Safe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13XTO Energy

Rob Halpin, senior account manager

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Allie Huston, co-owner

Totem Equipment & Supply Inc.

Totem Equipment and TotemRentals offer sales, service and rentalsof construction and industrial equip-ment. The manufacturing divisionrecently began designing and buildingcompact, easily transportable heatersystems. A recent market expansioninvolves exports to South Korea. Cliffand Allie Huston started the businessin 1961. Although Cliff is retired, thecompanies are still managed by Allieand their son Michael.

“Jill of all trades” Allie Huston hasworked in every department, includingsales, manufacturing and parts.Interacting with customers makes forsome hilarious moments, especiallybeing a woman in a man’s construc-tion world, says Allie. While theHustons enjoy their active Alaska life,they supplement it with frequentdoses of warm sunshine at their PalmDesert home.

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By PAULA EASLEY

Alaska Railroad Corp.Alaska Railroad Corp.’s interstate

service includes weekly rail-barge tripsbetween Anchorage and Seattle.Intrastate transportation includes pas-senger and full freight services alongAlaska’s railbelt. ARRC works withdomestic railroads, ship and bargelines, and local and interstate truckingcompanies to provide full-service ship-ping.

Rob Halpin has a 30-year historyperforming various management andmarketing functions within Alaska’sfreight transportation sector. He’s beenthe railroad’s senior account managerfor 16 years. Rob is also treasurer forthe National Defense TransportationAssociation. A typical day on the job, hesays, is full of “intrigue, passion, dramaand suspense,” so he is seldom bored.Rob’s two daughters were reared inAlaska and now live in Portland, Ore.Elizabeth is a successful artist and Katieattends college there.

development projects, Lorien andSwordfish.

Noble purchased an additional 50 per-cent stake in Swordfish, pushing its inter-est there to 60 percent. The field, locatedon Viosca Knoll block 917, is expected tocome on stream late in the first quarter of2005, backed with estimated reserves of20 to 25 million barrels of oil equivalent.Two wells have been drilled thus far anda third is planned for this summer.

Noble bought an additional 40 percentstake in Lorien, increasing its interestthere to 60 percent. A 2003 discovery,Lorien is situated on Green Canyon block199. The partners are currently puttingtogether an appraisal program for theprospect, with the hope of launching pro-duction as a tieback in the 2005 fourthquarter. The field contains estimatedreserves of 20 to 30 million barrels of oilequivalent.

Ticonderoga productionplanned for 2006

Fifty-fifty Ticonderoga owners Nobleand Kerr-McGee are hoping to bring theirrecent discovery on stream in the thirdquarter of 2006, Peneguy said, addingthat the discovery well logged “well over230 feet of beautiful oil pay.”

In fact, the only reason Noble gave upoperatorship of Ticonderoga to Kerr-McGee is because production would befunneled through Kerr-McGee’s produc-tion facilities at nearby Constitution, thusreducing overall development costs atTiconderoga.

“The trade off was for us is to haveaccessibility to the spar they are currentlypreparing,” Peneguy said. He saidappraisal work will continue onTiconderoga this year and that a seconddevelopment well likely would be drilledin the first quarter of 2005.

On an oil equivalent basis, he said,Noble would receive 11,000 barrels perday in net production from Swordfish,9,000 barrels per day net from Lorien and15,000 barrels per day net fromTiconderoga.

Deep opportunities maturing Despite working hard to advance the

Swordfish, Lorien and Ticonderogadevelopment projects, Noble’s currentportfolio of deep opportunities is “matur-ing and we now need to start expanding,”Peneguy said.

He added: “So we are moving forwardwith acceleration of our current programand expanding into new areas of thedeepwater.”

Three prospects are under considera-tion for drilling this year, including Sableat Green Canyon block 228, a 10 to 35million barrel of oil equivalent targetPeneguy says “is ready to go.”

Noble owns 100 percent of Sable andis looking to sell down its interest to helpspread financial risk, he said, adding thatinfrastructure in the area would makeSable a candidate for a subsea tieback toan existing platform.

“We have been discussing with a fewoperators, if we are lucky enough here,where we might go,” Peneguy said.

Company now lookingfor larger targets

Noble, which in the past has focusedon smaller deepwater reserves of 20 to 50million barrels to tie back to existinginfrastructure, is now actively looking fortargets “well over” 50 million barrels,Peneguy said.

“Those opportunities, if successful,

will yield standalone opportunities forus,” he said.

In the shallower waters of the Gulf’scontinental shelf, Noble is being far moreselective than in the past when its off-shore acreage domain stretched from thesouthern tip of Texas to southernAlabama.

The company has not given up onmature and largely depleted shelf playsabove 15,000 feet, but is now concentrat-ing on deeper gas plays at 15,000 feet andbelow.

“We have literally reduced ourdependency on the shelf, that is the con-ventional shelf,” Peneguy noted. “Butthere are deep opportunities below that.We have selectively high-graded ourdeep-shelf portfolio.”

Deep gas trend the focus Noble is now focusing its exploration

efforts on the shelf in the West Cameron-South Marsh Island area, in a deep gastrend just east of Louisiana and south ofMississippi-Alabama.

Because of the company’s existinginfrastructure in the area and experiencein the play, “we believe Noble has anenviable geological and geophysicalcompetitive advantage as it relates tofocusing in this trend,” Peneguy asserted.

He noted that because the 15,000-footplay is not as deep as some, it costs just$4 million per well compared to theroughly $1 million per thousand feet itcosts for wells drilled between 17,000and 30,000 feet.

“We believe there are additional shal-low and deep opportunities, yielding sig-nificant resources anywhere from 50 to400 billion cubic feet of gas equivalentper prospect,” Peneguy said.

Despite the shift away from conven-tional plays on the shelf, the area is stillreaping benefits for Noble. The compa-ny’s 17-well recompletion program atcore properties on Main Pass blocks 305and 306 is expected to triple current pro-duction in the field to 6,900 barrels of oilper day from 2,400 barrels last December.

The company also believes there are“deep opportunities” beneath the MainPass acreage.

Deepwater would providebiggest opportunities

However, the numbers show that as faras the offshore Gulf of Mexico goes, it’sthe deepwater that would provide Noblewith its biggest opportunity for futureproduction. The company noted thatwhile the majority of its acreage on thecontinental shelf already is developed,more than 90 percent of its deepwateracreage is undeveloped.

Still, of the 42,100 barrels of oil equiv-alent per day produced by Noble duringthe 2004 first quarter from the Gulf ofMexico, a hefty 80 percent came from theshelf. “But the deepwater is growing andgrowing fast,” Peneguy said.

Noble said it increased its 2004 off-shore capital budget to $325 million, 70percent of which is earmarked for deep-water Gulf of Mexico, primarily becauseof deepwater successes.

“Deepwater has been kind to NobleEnergy over the last few years,” Peneguysaid. “We believe it to be an attractiveplay and a play we have a very strongposition in. We like deepwater because ofthe high-impact resources and moderategeologic and mechanical risks.”

He said Noble also likes the deepwa-ter because of the availability of infra-structure that allows discoveries to betied in to offshore production facilitiesand pipelines in a timely fashion, “yield-ing excellent returns on those invest-ments.” �

26 PETROLEUM NEWS • WEEK OF JUNE 6, 2004THE REST OF THE STORY

United States, where coalbed methane hita “steep growth curve over a 15 year peri-od” and is now contributing 4.4 bcf to 4.6bcf per day to U.S. volumes of 52 bcf perday.

Simpson said that although coalbedmethane output is expected to be a mere100 million cubic feet per day this year,1,000 coalbed methane wells have beendrilled in central Alberta and 100 coalbedmethane wells are being licensed eachmonth.

He said the Canadian Gas PotentialCommittee has projected coalbedmethane reserves of 200 to 600 trillioncubic feet in the Western CanadaSedimentary basin, although the bulk ofexperts believe ultimately recoverable

reserves will be in the range of 20 tcf to100 tcf.

Among the challenges, Simpson saidCanada is discovering that the reservoirsare complex and each requires a distinc-tive approach. “Finding the right technol-ogy is the key challenge,” he said.

George Enyon, a natural gasresearcher with the Canadian EnergyResearch Institute, said coalbed methanedevelopment is a natural extension of theshallow gas industry in Western Canadabecause most of the coalbed methanedeposits are close to the surface.

He said the rig fleet in Western Canadais dominated by shallow equipment,which is suitable for coalbed methane,thus the industry does not have to make aradical departure from its existing devel-opment.

—GARY PARK, Petroleum News Calgary correspondent

continued from page 1

NOBLEcontinued from page 1

OUTPUT

ry issues essential to a safe and reliable gasdevelopment on the Grand Banks, as wellas the capital and operating costs of such adevelopment.

Following a review of the responses,Husky said it may select one or morefirms to participate in a request for pro-posal process. The Canada-Newfoundland Offshore PetroleumBoard has estimated that White Rose hasgas resources of 2.7 trillion cubic feet,while the entire offshore Newfoundlandand Labrador region is rated at 9.6 tcf.

But to date developing the gas hasbeen relegated to second place behind oilbecause of the costs of getting the gas tomarket.

Husky President and Chief ExecutiveOfficer John Lau said in a statement June1 that the Husky evaluation is “the firststep which may help realize gas produc-tion from White Rose within a decade.

“In order to evaluate natural gasdevelopment in the Jeanne d’Arc basin(which contains the Hibernia and TerraNova oil-producing projects as well asWhite Rose, which is due on stream bylate 2005 or early 2006) new technolo-gies will need to be developed and todaywe believe this is possible,” he said.

Husky owns 72.5 percent of the WhiteRose development, with Petro-Canadaholding the remaining 27.5 percent. Theoil venture carries a price tag of C$2.35billion.

Compressed or pressurized natural gas has potential

Husky said its initial assessment indi-cates that a marine transportation systemusing compressed natural gas/pressur-

ized natural gas has potential as a com-mercial venture. But the company wantsto consider other technologies and isinviting proposals that delve into thoseprospects.

The program will include:• A quantified evaluation of viable

alternatives and a methodical selectionprocess to identify a preferred develop-ment option. This will include identifica-tion of potential opportunities for activi-ties that could be carried out inNewfoundland and Labrador and else-where in Canada.

• A capital and operating cost estimatefor each option.

• An evaluation of any unproven tech-nology issues and operating procedures,including proposed work programs, test-ing to address these uncertainties and anestimate of the development time andcosts required.

• An estimate of system operationsbased on simulation modeling includingreliability and weather related factors.

• Identification and quantification ofsafety and environmental related issuesand risk factors.

• An evaluation of regulatory issuesduring all stages of the gas development,including national and international reg-ulations, protocols and codes.

Husky has set a June 30 deadline forexpressions of interest.

—GARY PARK, Petroleum News Calgary correspondent

price of $4 per thousand cubic feet.Oil sands operating costs range from

$4 to $14 for bitumen and $12 to $18 forsynthetic crude oil. The estimated supplycosts ranges from $10 to $19 for bitumenand from $22 to $28 for synthetic crudeoil.

High prices one factor in projection The board bases its projections of

increased oil sands production on severalfactors:

• Global petroleum prices are likely toremain at levels high enough to maintaineconomic viability over the long term.

• Markets will remain strong for oiland natural gas despite a slow, evolution-ary transition to other energy forms overtime.

• Technological advancements, partic-ularly in environmental controls, willcontinue to lower unit costs of oil sandsproduction.

But the national energy body alsooffers some cautionary words, particular-ly on the sensitive topic of natural gassupply and prices.

“Natural gas requirements for the oil

sands industry are projected to increasesubstantially during the projected periodfrom 0.6 billion cubic feet per day in 2003to a range of 1.4 to 1.6 billion cubic feetper day in 2015.

“In response to higher and morevolatile gas prices, producers are seekingways to reduce their dependence on natu-ral gas as the major sources of energy andhydrogen for their operations.”

Natural gas supply and price has beencontroversial, as Alberta shut in some nat-

ural gas production this year to ensure asufficient supply for oil sands production.Along with record high prices for crudeoil recently, natural gas has also remainedat very high levels for this time of year,hovering around $6.70 US per thousandcubic feet.

Canadian gas productionexpected to be flat

Canadian gas production, whichincreased dramatically in the 1990s, isexpected to stay relatively flat, produc-ing about 17 billion cubic feet per dayuntil about 2010. Conventional supplyfrom the Western Canada Sedimentarybasin is expected to decline by 2006-2007.

The board estimates that oil sandsdevelopment and related infrastructurewill require a capital investment inexcess of C$60 billion over the next 10years to achieve the productions levelsprojected in the report. About C$20 bil-lion has already been invested.

“Ongoing volatility in crude oil pricesis expected and suggests that it is unlike-ly that the entire $60 billion in projects

will be constructed within the plannedtime frame,” the report states. “Marketconditions will determine the pace of oilsands development.”

The report also suggests that Alberta’spetrochemical industry, facing tight sup-plies of feedstock gases from conven-tional natural gas production, could usethe ethane and ethylene produced duringthe bitumen upgrading process.

The National Energy Board creditsthe oil industry for making significanttechnological advancements in environ-mental controls that reduce emissions.The industry uses low nitrogen oxidesburners, sour water treaters and flue gasdesulphurization to reduce emissions.

New technology has resulted in sig-nificant reductions in greenhouse gasemissions despite an increase in produc-tion. The board’s report shows a 53 per-cent reduction in carbon dioxide emis-sions per barrel for the period from 1990to 2010 due to investment in new tech-nology. Multi-stakeholder groups havebeen established in recent years to createpolicies and programs to address green-house gas emissions. �

PETROLEUM NEWS • WEEK OF JUNE 6, 2004 27THE REST OF THE STORY

continued from page 1

OIL SANDS

“In order to evaluate natural gasdevelopment in the Jeanne d’Arcbasin new technologies will need

to be developed and today webelieve this is possible.”

—Husky Energy President and CEO John Lau

continued from page 1

HUSKY

28 PETROLEUM NEWS • WEEK OF JUNE 6, 2004ADVERTISEMENT