page

8Alaska tax chief joins gaspipeline negotiations

Vol. 10, No. 28 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of July 10, 2005 • $1.50

● N O R T H A M E R I C A

● G U L F O F M E X I C O

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

● N O R T H S L O P E

7 Anadarko signs LNG shipping deal: Inked with Maritimes& Northeast Pipeline to deliver gas from Nova Scotia to U.S., Canada

9 Knotty Head well looking good: Gulf discovery wellalready found 300 feet of pay; headed to 32,500 feet to look for more

15Mac plans faulted: Canadian Arctic explorers say Mackenzie

gas pipeline should be larger, able to move more gas

SeaRose ready to set sail

The SeaRose FPSO (floating production, storage and offloading)vessel will depart Marystown, Newfoundland, within the next 30days and, after a series of tests in Mortier Bay, Newfoundland andLabrador, sail to the White Rose oil field. Once on site, the SeaRoseFPSO will connect to a subsea production system consisting of aseries of flexible flowlines, risers and umbilicals totaling 41.1 kilo-meters in length. The installation of the subsea flowlines and ris-ers is under way and will be completed in early August. Hook-upand offshore commissioning will be completed in the fourth quar-ter and first oil production is expected by the end of the year. Seestory on page 10.

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Neptune first for BHPOwners OK $850M Gulf development; Enbridge tapped for $100M pipelines

By RAY TYSON Petroleum News Houston Correspondent

wners of the Neptune discovery have agreed to chip in$850 million to develop their Gulf of Mexico deep-water oil and gas field, situated in the prolific AtwaterFoldbelt play along with several other major discover-

ies on the same geological trend, including Atlantis andMad Dog.

Neptune operator BHP Billiton and partners WoodsidePetroleum, Marathon Oil and Maxus Exploration, sub-sidiary of Repsol YPF, also have tapped Canada’s Enbridgeto build and operate $100 million worth of lateral oil andgas pipelines necessary to transport Neptune’s production tomarket.

Neptune represents several firsts for the U.S. Gulf. Itwould be BHP’s first operated project and Woodside’s first

O

A standalone, tension-leg platform hasbeen selected for the development.see NEPTUNE page 20

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J.C. Anderson on the comebacktrail; Eni under pressure to buy

J.C. ISN’T YET READY TO GO quietly into the night.Even at 74, the “thrill of the chase” hasn’t left him.So he’s returning to the Western Canada Sedimentary

basin as chairman of a junior E&P company, convinced thatthere is still life in the oil and gas business.

Known as a tireless worker and shrewd operator, J.C.Anderson built substantial personalwealth as the founder in 1968 ofAnderson Exploration — a company he

sold in 2001 toDevon Energy forC$5.3 billion whenit was Canada’ssixth largest inde-pendent producer.

Giving himselfno time to slide intoretirement, heformed AndersonEnergy and is going public following a

C$70 million takeover of Aquest Energy to doubleAnderson’s output to 3,600 barrels of oil equivalent per day.

The level of confidence in the Oklahoma-born wildcatteris reflected in the fact that five of his seven managers werepart of his team at Anderson Exploration.

The target for Anderson Energy is to reach 6,400 boe per

J.C. ANDERSON

see INSIDER page 20

Battle continuesAlaska, Point Thomson unit owners still at odds over development drilling at field

By KRISTEN NELSONPetroleum News Editor-in-Chief

he Point Thomson unit owners, nowfocused on gas sales, want develop-ment of the field tied to a natural gaspipeline from the North Slope, not to

deadlines set in a 2001 unit expansionwhich was negotiated when the ownersplanned to begin field development withoil sales.

Point Thomson is a high-pressurereservoir containing both oil condensateand natural gas on the eastern edge of state landson Alaska’s North Slope, adjacent to the ArcticNational Wildlife Refuge. A draft of the Point

Thomson unit’s 22nd plan of develop-ment was submitted to the AlaskaDepartment of Natural ResourcesDivision of Oil and Gas in June by unitoperator ExxonMobil. ExxonMobil, BP,Chevron and ConocoPhillips are themajor working interest owners in PointThomson.

The draft plan does not include devel-opment drilling by June 15, 2006, arequirement under the 2001 unit expan-sion, which also requires completion ofseven development wells within the unit

by June 15, 2008.

TCommissioner ofNatural ResourcesTom Irwin

see POINT THOMSON page 18

Exxon continues salesDevon, XTO cough up $415M as mega-major dumps more North America assets

By RAY TYSON Petroleum News Houston Correspondent

xxonMobil continues to weed its gar-den of unwanted U.S. and Canadianoil and gas properties, selling pack-ages totaling $415 million to big

exploration and production independentsDevon Energy and XTO Energy.

The industry giant also has establishedyet another joint venture with an E&P inde-pendent (XTO), a practice highlighted bylast year’s alliance with Houston-based Apache,among the more successful exploiters of mature prop-erties.

Devon, largest of the U.S.-based independents,said July 5 that it acquired about $200 million worth

of properties from ExxonMobil subsidiaryExxonMobil Canada Energy in the IronRiver area 120 miles northeast ofEdmonton, Alberta.

The acquisition included 208 net sec-tions of heavy oil leases and 51 net sectionsof conventional oil and gas leases, Devonsaid, adding that the deal specifically includ-ed about 165,000 net acres with an averageworking interest of about 96 percent. Theacreage is said to be largely undeveloped.

Iron River is situated northeast of andimmediately adjacent to Devon’s Manatokan field,which produces 7,000 barrels of oil per day fromabout 300 wells.

“We pursued this acquisition because of Iron

Bob Simpson, XTO’schief executive

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see EXXON page 16

2 PETROLEUM NEWS • WEEK OF JULY 10, 2005

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

Exxon continues sales

Devon, XTO cough up $415M forExxonMobil property, as mega-majordumps more NA assets

Neptune first for BHP

Owners give nod to $850M Gulfdevelopment; Canada’s Enbridgetapped for $100M pipelines

EXPLORATION & PRODUCTION

LAND & LEASING

FINANCE & ECONOMY

GOVERNMENT

INTERNATIONAL

NATURAL GAS

4 U.S. attorney ends investigation of Shell

5 Nexen spins off chemicals, sells assets

6 CNOOC chairman says Unocal bid going ahead

6 China tells Congress to stop interfering

7 New M&A firm ready for consolidation

8 Viking makes another raid in Canada

12 Crude futures finish above $61

14 St. Mary to acquire 18.7 bcfe of reserves

16 Calpine selling oil, gas assets for $1.05B

14 Caught between two bidders: Unocal’s options

11 Alaska gets $7M grant for energy training

13 Nuclear answer to U.S. energy needs

4 Mexican Congress lowers Pemex tax rate

6 China to increase imports of Russian oil

6 North Sea platform restarting after gas leak

14 Russia halts pipeline surveying at Baikal

15 Norway, Britain treaty designedto stimulate development

15 Venezuela to begin selling Orinoco tar tracts

15 Explorers: Mac line should be larger

13 Tentatively scheduled Alaska lease sale chart

7 MMS delays Cook Inlet 2006 sale to 2007

12 Canada’s rig count up 91; U.S. unchanged

12 Rowan subsidiary to provide jack-up kits

13 Pioneer has a range of Alaska prospects

8 Petro-Canada putting oil sands pieces in place

10 White Rose oil project on track

ON THE COVERBattle continues

Alaska, Point Thomson unit ownersstill at odds over developmentdrilling at field

5 Alaska oil production drops 6.5 percent

Reduction from May drivenby 36-hour trans-Alaskaoil pipeline planned summershutdown for maintenance

9 Knotty Head discovery well looking good

Gulf of Mexico exploration well has already foundmore than 300 feet of apparent pay; headed to32,500 feet in search of more

7 Anadarko Canada signs LNG shipping deal

Agreement inked with Maritimes & Northeast Pipelineto deliver gas from Nova Scotia to U.S., Canadian markets

8 Alaska tax chief joinsgas line negotiations

Dan Dickinson joins Jim Clark on statenegotiating team, says he won’treturn to state government afternegotiations concluded

4 Russia production hits record

But analyst says it’s a temporary bump after eightstagnant months; oil output in first half the yearlower than expected

9 Experts say bearpopulation will shrink

Melting ice could reduce polarbear population 30percent over next 35-50 years

OIL PATCH INSIDER1 J.C. Anderson on the comeback

trail at 74; Eni under pressure to buy20 Eni chief under pressure to buy;

Italian giant likes high-risk projects

PETROLEUM NEWS • WEEK OF JULY 10, 2005 3

Current Deepwater Activity

Area/ OCS Prospect WaterOperator Block Lease Rig Name Name Depth (ft)

Anadarko Petroleum AT 349 G23473 T.O. DEEPWATER MILLENNIUM Jubilee West 8,774

BHP Billiton Petroleum (GOM) WR 206 G16965 GSF C.R. LUIGS Casade 8,160

Chevron U.S.A. WR 758 G17015 T.O. DISCOVERER DEEP SEAS Jack 6,959

BP E&P GC 826 G09982 DIAMOND OCEAN CONFIDENCE Mad Dog 6,736

BP E&P MC 822 G14658 T.O. DISCOVERER ENTERPRISE Thunder Horse South 6,262

Dominion E&P MC 773 G19996 NABORS POOL 140 Devil's Tower 5,610

Kerr-McGee Oil & Gas GC 768 G21817 DIAMOND OCEAN STAR Deep Blue 5,257

ConocoPhillips GB 783 G11573 NABORS MODS 201 Magnolia 4,674

BP E&P GC 782 G15610 PRIDE MAD DOG SPAR RIG Mad Dog 4,426

BP E&P GC 645 G11080 HOLSTEIN SPAR RIG Holstein 4,344

Anadarko Petroleum GC 652 G21810 ENSCO 7500 Genghis Khan 4,331

Anadarko Petroleum GC 518 G21801 NOBLE PAUL ROMANO K2 North 4,047

BP E&P GC 821 G16806 T.O. MARIANAS Puma 3,944

Eni Petroleum GC 562 G11075 GSF CELTIC SEA K2 3,934

Shell Offshore MC 934 G07976 NOBLE JIM THOMPSON Europa 3,863

Kerr-McGee Oil & Gas EB 602 G14205 DIAMOND OCEAN VALIANT Nansen 3,646

BP E&P AT 398 G16910 T.O. DEEPWATER HORIZON Bonsai 3,610

Union Oil Company of CA GC 512 G26315 T.O. DISCOVERER SPIRIT Knotty Head 3,557

Pioneer Natural Resources USA GC 299 G15571 DIAMOND OCEAN AMERICA Clipper 3,452

Shell Offshore GC 434 G21207 T.O. DEEPWATER NAUTILUS Pathfinder 3,448

Shell Offshore Inc. GB 516 G11528 DIAMOND OCEAN VICTORY Serrano 3,392

Murphy E&P GC 338 G21790 NABORS MODS 200 Front Runner 3,328

Shell Offshore VK 956 G06896 H&P 205 Ram-Powell 3,216

Shell Offshore GC 158 G07995 H&P 202 Brutus 2,985

Shell Offshore MC 807 G07962 H&P 201 Mars 2,945

Walter Oil & Gas MC 161 G21163 DIAMOND OCEAN QUEST 2,924

Shell Offshore GB 426 G08241 AUGER Auger 2,862

LLOG Exploration Offshore GC 157 G24154 DIAMOND OCEAN SARATOGA Citrine 2,614

Kerr-McGee Oil & Gas GC 320 G25139 NOBLE AMOS RUNNER Chilkoot 2,596

Chevron U.S.A. GC 205 G05909 NABORS 85 (MAYRONNE 162) Genesis 2,590

BHP Billiton Petroleum (GOM) GC 282 G26302 NOBLE MAX SMITH Boris North(GC) 2,346

Chevron U.S.A. GC 236 G15562 THERALD MARTIN Typhoon 1,987

Chevron U.S.A. VK 786 G12119 ENSCO 25 Petronius 1,754

Amerada Hess Corporation GB 200 G17307 DIAMOND OCEAN CONCORD Northwestern 1,736

Eni US Operating Co EW 965 G12145 T.O. AMIRANTE Morpeth 1,694

W & T Offshore GC 178 G25123 NOBLE LORRIS BOUZIGARD Baccarat 1,404

LLOG Exploration Offshore GB 205 G23278 THE 100 GB 205 1,330

BP E&P VK 989 G06898 NABORS POOL 143 Pompano I 1,290

Total Deep Water Prospects with Drilling/WO Activity: 38

New Deepwater ActivityArea/ OCS Prospect Water

Operator Block Lease Rig Name Name Depth (ft)

Kerr-McGee Oil & Gas EB 602 G14205 Nansen 3,646

Shell Offshore GC 434 G21207 Pathfinder 3,448

Walter Oil & Gas MC 161 G21163 2,924

The Gulf of Mexico Activity Report as of July 4, 2005. Active drilling companies only listed.

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

This platform report was prepared by Tom Kearney

Baker Hughes North America rotary rig counts*July 1 June 24 Year Ago

US 1,370 1,370 1,201Canada 348 257 397Gulf 96 94 93

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

*Issued by Baker Hughes since 1944

BP’s Holstein Spar rig

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Transocean’s Deepwater Millennium

Gulf of Mexico Activity Report

4 PETROLEUM NEWS • WEEK OF JULY 10, 2005

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NEW YORKU.S. attorney ends investigation of Shell

A federal prosecutor in Manhattan has decided not to prosecute the RoyalDutch/Shell Group of Cos. for overstating oil and gas reserves, officially ending aJustice Department probe of the company.

U.S. Attorney David Kelly announced June 29 he had concluded that “a criminalprosecution of Shell would not serve the public interest at this time.”

Kelly credited the world’s third-largest publicly traded oil company with cooperat-ing with an investigation launched last year after it disclosed it had overstated its provenoil and natural gas reserves by 4.47 billion barrels, or about 23 percent, from 1997through 2002. The prosecutor also cited Royal Dutch/Shell’s payment of a $120 mil-lion fine imposed by the Securities and Exchange Commission for accounting fraud.Under the SEC settlement, the company also agreed to spend $5 million on an internalcompliance program.

Any further penalties “would likely have a severe and unintended disproportionateeconomic impact upon thousands of innocent Shell employees,” Kelly said.

Shell said it was pleased with the decision and that its cooperation had been appre-ciated. “The conclusion of this investigation is a most important step toward putting thematter of the reserves recategorizations behind us,” said Chief Executive Jeroen van derVeer.

The company’s disclosure of the reserve inflation stunned shareholders and the oilindustry and led to the dismissal of several top executives.

—THE ASSOCIATED PRESS

MEXICO CITYMexican Congress lowers Pemex tax rate

Mexico’s lower house of Congress has approved changes in tax rules for state oilmonopoly Petroleos Mexicanos, or Pemex, that will leave the company with moremoney for exploration and production.

Presidential spokesman Ruben Aguilar said June 29 that Pemex and the EnergyMinistry will analyze the changes to gauge the effects on the oil company and publicfinances, but that “in principle” the executive branch hasn’t thought about vetoing it.

The lower house voted 330-131 on June 28 in favor of the bill, which had alreadybeen approved by the Senate.

The changes will give Pemex a lower tax rate on oil and gas production from newprojects, where investments raise the cost of production compared with costs at estab-lished operations.

The high rate of taxation on Pemex, which pays 61 percent of its sales to the fed-eral government, has left the state company with net losses in recent years despiterecord high crude oil prices.

Pemex’s budgets are included in the federal budget. The new tax rules would give Pemex sufficient incentive to invest in exploration

of new deposits and to step up production, Congress said in a press release. The new tax treatment has been estimated to save Pemex between $2 billion and

$3 billion in 2006 and as much as $13 billion over four years. —THE ASSOCIATED PRESS

● R U S S I A

Russia’s crude oilproduction hits recordBut analyst says it’s a temporary bump after eight stagnantmonths; oil output in first half the year lower than expected

PETROLEUM NEWSccording to a July 4 Dow JonesNewswire report out of Moscow,Russia’s crude oil production hit anew post-Soviet high of 9.43 mil-

lion barrels a day in June – an event thatfollowed eight months of stagnation.

The story followed a monthly statisti-cal report released the same day fromRussian officials.

But the monthly spurt doesn’t provethe trend of slowing oil output growth isreversing, an analyst told the newsagency.

Oil production increased by almost100,000 barrels per day from May, com-pared with the previous record of 9.41 setin September, but most of the increase isseasonal, analysts say. Oil from Siberiafields is “easier to extract in the summerand export ports are usually free fromstorms,” the story said.

“There’s nothing to celebrate at thispoint,” said Valery Nesterov, an analyst atthe Moscow-based Troika Dialog broker-age. Troika Dialog recently downgradedits growth forecast to 2.8 percent, DowJones Newswires reported.

In the first half of the year, Russia oilproduction averaged 9.33 million bpdcompared to the Russian government’sprojection of 9.65 million bpd for 2005.

Most new oil from PSA projectsThe bulk of the jump in June produc-

tion came from projects being developedunder production sharing agreementswith foreign partners, including RoyalDutch/Shell-led Sakhalin-1, which beganits seventh oil-producing season in early

June, the news agency reported.PSAs ensure a stable fiscal regime and

tax rate for oil and gas projects but havealso been severely criticized by manyRussian politicians who claim the specialterms PSAs offer are detrimental to gov-ernment coffers.

According to the news agency report,TNK-BP posted a slight increase in June,plus its production was up 8.4 percent inthe first six months of 2005, which is thebiggest increase among Russia’s oilmajors with the exception of state oilcompany OAO Rosneft.

Rosneft’s output was up due to pro-duction from the Yuganskneftegaz unit,which Yukos lost at a state auction to helpcover its debts in December.

According to the Dow JonesNewswires report, Yuganskneftegaz post-ed a slight on-month increase in June asits production stabilized at slightly over 1million bpd.

In late June Rosneft lowered its oilproduction forecast for Yuganskneftegaz,a sign that the company won’t be able toremedy production problems springingfrom Yukos’s underinvestment as fast asoriginally expected, the news agencyreported. ●

TNK-BP posted a slight increasein June, plus its production was up8.4 percent in the first six months

of 2005, which is the biggestincrease among Russia’s oil majors

with the exception of state oilcompany OAO Rosneft.

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PETROLEUM NEWS • WEEK OF JULY 10, 2005 5

CANADANexen spins off chemicals, sells assets

Canadian independent Nexen is immersed in a top-to-bottom reshaping of thecompany as it cuts ties with conventional plays in Western Canada, unloads itschemicals unit and puts its emphasis on the oil sands, Gulf of Mexico, North Seaand Yemen.

In the space of a week, Nexen announced its chemicals business would be con-verted to an income trust this summer, while the final touches were being appliedto the sale of oil and gas properties in northeast British Columbia, the Albertafoothills and Saskatchewan for about C$946 million.

Proceeds from the asset sale of about C$300 million and a projected C$800 mil-lion from the chemicals offering will be used to pay down net debt of about C$4.3billion and help finance its new projects.

Chief Executive Officer Charlie Fischer has C$3 billion invested in projectswhich have “yet to deliver a drop of oil” and that will rise to C$5 billion by late2006.

But the major projects, led by the Long Lake oil sands project in Alberta andthe North Sea’s Buzzard field, have 802 million barrels of proved and probablereserves that will turn around Nexen’s production trend.

Having slipped to 250,000 boe per day in 2004 from 270,000 boe per day in the2001-03 period, Nexen has set a target as high as 350,000 boe per day by 2007.

The big contributors to that turnaround will be the North Sea assets acquired forUS$2.1 billion in 2004 from EnCana that are yielding greater-than-projectedreserves and should deliver 85,000 boe per day in 2007 and the Long Lake jointventure with OPTI Canada that will come on stream at a gross 60,000 bpd of syn-thetic crude.

The conventional properties Nexen is divesting contain proved reserves of 49million barrels of oil equivalent and yielded 18,300 boe per day in the first quar-ter.

Potential buyers have not been identified, but are likely to come from theincome trust sector.

The chemicals division, which Nexen believes is undervalued, includes plantsin five Canadian cities and one in Brazil, although one in Ontario is being closedbecause of high electricity costs.

—GARY PARK

Alaska oil productiondrops 6.5% in JuneReduction from May driven by trans-Alaska oil pipeline plannedmaintenance shutdown; May numbers up slightly from April

By KRISTEN NELSONPetroleum News Editor-in-Chief

fter holding steady in May AlaskaNorth Slope crude oil productiondropped 6.5 percent in June, drivenprimarily by a planned 36-hour shut-

down of the trans-Alaska oil pipeline forscheduled summer maintenance. All NorthSlope fields saw a drop in production fromMay to June. Prudhoe Bay, Milne Point,Alpine and Northstar all had productionincreases from April to May.

ANS production averaged 923,882 bar-rels per day in May, up marginally — 0.17percent — from an April average of922,307 bpd. June ANS production aver-aged 863,755 bpd, down 6.5 percent fromMay.

Alyeska Pipeline Service Co. said theJune 19-June 20 shutdown allowed mainte-nance crews to work on projects fromPrudhoe Bay to the Valdez MarineTerminal, including: installing more infra-structure at Pump Station 4 for the new elec-tric driven pumps for the strategic reconfig-uration project; replacing both pig traplauncher valves at Pump Station 4;installing a 48-inch check valve at PumpStation 7; and some 40 work tasks at otherpump stations, remote valve sites and at themarine terminal. The second shutdown ofthe summer, July 23-24, will also lastapproximately 36 hours. Producers also per-form North Slope maintenance during theshutdowns.

Endicott has largest percentage dropThe BP Exploration (Alaska)-operated

Endicott field had the largest percentagedrop in production in June, down 10.8 per-cent to 18,365 bpd. The field’s May produc-tion averaged 20,596 bpd, down just 0.95percent from an April average of 20,793bpd. The Alaska Department of RevenueTaxation Division said Endicott reported aninjection pump problem May 7-8, and amain gas compressor shut down May 28,but listed no Endicott problems for June.

Production at the BP-operated MilnePoint field (which includes Schrader Bluff)was down 9.2 percent in June, averaging44,451 bpd, compared to 48,942 bpd inMay, a 5.9 percent increase from April pro-duction averaging 46,204 bpd. Revenuelisted no Milne problems in June, but saidthe field was shut down May 23 due to ablown turbine fuse.

BP-operated Northstar had a drop of8.83 percent in June, averaging 59,243 bpd,compared to 64,980 bpd in May. The field’sMay production was up 1.6 percent from anApril average of 63,960 bpd. Revenue saidNorthstar shut down its gas compressorJune 30 to conserve fuel. In May, a com-pressor shut down at the field May 8 andminor maintenance was done at the fieldMay 15-16.

Prudhoe down 33,000 bpd BP-operated Prudhoe Bay field (which

includes production from the Midnight Sun,Aurora, Polaris, Borealis and Orion satel-lites) averaged 407,435 bpd in June, down7.49 percent (33,000 bpd) from a May aver-age of 440,435 bpd. May production atPrudhoe was up 1.2 percent from an Aprilaverage of 435,262 bpd. Revenue listed noMay events at Prudhoe, but said the field’s

Central Gas Facility was shut down June30.

Production at BP-operated Lisburne(which includes Point McIntyre and Niakukproduction) averaged 42,706 bpd in June,down 6.96 percent from a May average of45,901 bpd, a drop of 0.9 percent from anApril average of 46,313 bpd.

The ConocoPhillips Alaska-operatedKuparuk River field (which includes pro-duction from West Sak, Tabasco, Tarn,Meltwater and Palm) averaged 180,644 bpdin June, down 1.65 percent from a Mayaverage of 183,680 bpd. May production atthe field had dropped 5 percent from anApril average of 193,365 bpd.

Production at the ConocoPhillips-oper-ated Alpine field averaged 110,911 bpd inJune, down 7.1 percent from a May averageof 119,348. The field’s May production wasup 2.5 percent from April production of116,410 bpd. Revenue said Alpine had anelectronic breakdown May 27 and wasdown again May 29 for vessel maintenance.The Alpine plant went down June 8 when awire shorted during electrical work.

The June temperature at Pump Station 1on the North Slope averaged 38.9 degreesFahrenheit (compared to a three-year aver-age of 41.2 degrees F), up from a May aver-age of 26.8 degrees F (compared to a three-year average of 26.4 degrees F). The Apriltemperature averaged 6.6 degrees F, com-pared to a three-year average of 6.9 degreesF.

Cook Inlet production averaged 20,294bpd in June, up 3.8 percent from a Mayaverage of 19,546, that down 0.9 percentfrom an April average of 19,715 bpd. ●

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● A L A S K A

BP’s Northstar field had a drop of 8.83 percent in June, averaging 59,243 bpd, compared to 64,980bpd in May. Revenue said Northstar shut down its gas compressor June 30 to conserve fuel.

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ANS production averaged 923,882barrels per day in May, up

marginally — 0.17 percent — froman April average of 922,307 bpd.June ANS production averaged

863,755 bpd, down 6.5 percent fromMay.

6 PETROLEUM NEWS • WEEK OF JULY 10, 2005

● B E I J I N G

CNOOC chairman saysUnocal bid going aheadUnocal mails proxy materials on Chevron offer; Chinesegovernment says offer a purely commercial transaction

By JOE MCDONALDAssociated Press Writer

hinese oil company CNOOC Ltd.will press ahead with its takeoverbid for Unocal Corp. despite aplanned shareholder vote on a lower

offer by Chevron Corp., which Unocal’sboard says should be accepted, CNOOC’schairman said June 30.

In an interview with The AssociatedPress, Fu Chengyu expressed confidencethe state-controlled oil company will per-suade Washington the proposed $18.5 bil-lion deal for the ninth-largest U.S. oilcompany doesn’t pose any risks toAmerican national security.

“We’ll continue to talk in negotiations,and we will meet with government figuresfor the (security) review,” Fu said. “Ibelieve that our superior offer, which willhelp shareholders, this will convince theU.S. government this is a good offer.”

Fu’s comments came after Unocal sentits shareholders proxy materials June 30with a letter reiterating its board’s recom-mendation to accept the $16.6 billion offerby Chevron.

CNOOC says its all-cash offer willbenefit the United States by payingUnocal shareholders more and resulting infewer job losses. Chevron has counteredthat its offer already has received regula-tory approval and a switch to CNOOCcould require lengthy new reviews.

Fu wouldn’t say whether CNOOCmight raise its offer.

“I think this is a kind of strategy thatshouldn’t be discussed,” he said. “Wedon’t have firm plans as to what we’ll do.But we do have something that we aredeveloping.”

CNOOC: offer driven by economicsFu rejected suggestions that CNOOC,

which is based in Hong Kong but is 70percent-owned by a Chinese governmentoil company, was acting on behalf ofChina’s government.

“This company is driven purely byeconomics,” he said. “If there’s a goodmarket, the more we can supply, themore value we can add for shareholders.Not because the government asked us todo it, but because we believe it’s theprofitable thing to do.”

He said that although CNOOC’s par-ent company is promising to supply $7billion of the proposed purchase price,none of that money would come from theChinese government.

“Not a cent,” he said. Earlier June 30, the Chinese govern-

ment tried to mollify American anxietyabout the bid, insisting it is a purely com-mercial transaction and saying it hopes tosee both the United States and China

benefit. “China wants to find a ‘win-win’

result,” said Foreign Ministry spokesmanLiu Jianchao.

Liu repeated Beijing’s plea toWashington not to let politics interferewith what he insisted is a purely commer-cial affair.

“This issue is a commercial transactionbetween two companies, and a normalexchange between China and the UnitedStates,” Liu said. “It should stay free ofpolitical interference.”●

CChina tellsCongress to stopinterfering

China on July 5 demanded thatCongress “correct its mistakenways” and stop interfering in theproposed takeover of the Unocal oilcorporation by China’s state-ownedCNOOC Ltd.

American politicians had warnedthe $18.5 billion takeover bidannounced in June could pose risksto U.S. national security and calledfor a full review by the Bush admin-istration.

The Chinese company’s officialshave welcomed a security reviewand denied that CNOOC was actingon behalf of China’s government,which is in the midst of a multibil-lion-dollar campaign to secure for-eign oil and gas supplies to power itsbooming economy.

“We demand that the U.S.Congress correct its mistaken waysof politicizing economic and tradeissues and stop interfering in thenormal commercial exchangesbetween enterprises of the two coun-tries,” the Chinese Foreign Ministrysaid in a statement released July 5.

China has been insistingCNOOC’s offer is pure business.“CNOOC’s bid to take over Unocalis a normal commercial activitybetween enterprises and should notfall victim to political interference,”said the statement.

Developing bilateral economicand trade cooperation is in the inter-ests of both sides, the statement said.

CNOOC is bidding againstChevron Corp. for Unocal, theninth-largest U.S. oil and gas firm.The Chinese firm has argued that itsoffer will benefit the United Statesby paying Unocal shareholders moreand causing fewer job losses.

—THE ASSOCIATED PRESS

BEIJINGChina to increase imports of Russian oil

China said July 5 it hopes to increase oil imports by rail from Russia by 50 per-cent next year to 105 million barrels as it looks for foreign energy to fuel itsbooming economy.

The statement by the Chinese Foreign Ministry came after President Hu Jintaovisited Moscow at the end of June and discussed possible joint development of oiland gas fields.

China expected to import 70 million barrels of Russian oil by rail this year, andexpects that to grow to 105 million barrels next year, said Foreign Ministryspokesman Liu Jianchao.

China relies on rail shipments to receive Russian oil due to lack of a pipelineconnecting the two countries.

China is competing with Japan for access to a planned Russian pipeline toexport Siberian oil.

—THE ASSOCIATED PRESS

NORWEGIAN NORTH SEANorth Sea platform restarts after gas leak

The Statoil ASA oil company said its Kvitebjoern offshore field was restartingJuly 1 after a natural gas leak shut it down and had the crew in lifeboats ready toevacuate this week.

The 375 million cubic feet per day natural gas field was shut down June 28 fol-lowing the gas leak, which did not cause damage or injuries.

The leak was attributed to increased pressure in a pipeline system on the restartof a land-based gas processing unit.

“The plan is to start up today, and reach full production by July 2,” companyspokesman Harald Schjelderup said by telephone.

The leak was the third reported by the state-controlled oil company in ninemonths, including a serious gas blowout that closed Statoil’s Snorre-A oil and gasplatform for weeks but caused no injuries.

Explosions and fires from natural gas can endanger entire platforms and theircrews. The field is about 95 miles off Bergen, the main city on Norway’s westcoast.

Norway’s offshore fields make it the world’s third-largest oil exporter, afterSaudi Arabia and Russia. It is also a major natural gas exporter.

—THE ASSOCIATED PRESS

PETROLEUM NEWS • WEEK OF JULY 10, 2005 7

● A T L A N T I C C A N A D A

Anadarko Canada takes thelead, signs LNG shipping dealTransportation agreement inked with Maritimes & Northeast Pipeline to deliver gas from NovaScotia to U.S., Canadian markets; deal puts it slightly ahead of Irving-Repsol project

By GARY PARK Petroleum News Canadian Correspondent

he thinking that there is room for twoliquefied natural gas plants in AtlanticCanada is being put to the test.

Anadarko Canada and the partner-ship of Irving Oil and Spain’s Repsol showno signs of wavering in their plans to bringimport terminals on stream by late 2008.

Anadarko took another step forwardJune 30 when it signed a transportationagreement with Maritimes & NortheastPipeline to deliver gas from its Bear Headproject in Nova Scotia to markets in theUnited States and Canada. That gave it anedge over the Irving-Repsol project whichhas yet to conclude a contract for shippinggas from its Canaport facility in NewBrunswick.

Karl Hurz, an Anadarko senior vicepresident, said the deal with Maritimes &Northeast is a “critical step” in the plansfor an integrated LNG venture and givesAnadarko added “visibility” as it movesahead with LNG supply negotiations.

The company has indicated it hopes toannounce a supplier this summer or fall —with most speculation focused on surplussupply in Qatar, Russia or Algeria.

The US$650 million Bear Head projectis expected to make initial shipments of750 million cubic feet per day.

Possible expansion already announced Maritimes & Northeast currently car-

ries about 400 million cubic feet per day ofgas from Nova Scotia’s Sable offshorefield to New England.

It announced in April that it might

expand the pipeline by 1.5 billion cubicfeet per day following an overwhelmingindustry response to an open season. Aspokesman said the Anadarko deal givesMaritimes & Northeast a basis to file anapplication with the National EnergyBoard later this year.

He said Maritimes & Northeast is intalks with other possible shippers that alsoindicated they wanted capacity on anexpanded pipeline.

It is not known if Canaport is part ofthose negotiations.

However, design and engineering forthe New Brunswick terminal is welladvanced and construction could start thissummer.

Repsol is responsible for arrangingLNG supplies and will market the regasi-fied LNG in the United States, while Irvinwill control distribution in Canada.

Anadarko also announced June 30 thatit has an agreement with Horton CBI, asubsidiary of Chicago Bridge and Iron ofHouston, for engineering services and pro-curement of materials needed to build twoLNG storage tanks.

In addition, there is a short list of bid-ders to participate in the engineering, pro-curement and construction contract for theterminal, which is expected to be awardedlater this year. ●

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CALGARYNew M&A firm ready for consolidation

Canada’s third largest bank and its top acquisitions and divestitures firm have har-nessed up their resources to take advantage of a fragmented North American industry.

Through its Scotia Capital division, Scotiabank acquired Calgary-based Waterous& Co. for an undisclosed amount, gaining 75 employees from offices in Calgary,Houston, Denver, London, Singapore and Gibraltar.

Over the last three years, Waterous has worked with 24 of the 30 largest privatesector oil and gas companies in the world on transactions valued at US$15 billion and,this year alone, has had a role in five major transactions totaling US$3.5 billion.

Adam Waterous, president and vice chairman of the new Scotia Waterous unit, saidthe transaction establishes one of the first firms to combine global, in-depth oil andgas M&A with full-service financing.

It also comes at a time when the North American industry is in a highly fragment-ed state and ripe for consolidation, said Brian Porter, Scotia Capital’s deputy chair-man. There are 600 firms producing at least 1,000 barrels per day and worth morethan C$50 million, Waterous said.

He said that with so many firms operated with such a limited range of assets, andwith most companies unloading the bottom 5 percent of their assets every year, thestage is set for substantial consolidation.Bringing the two firms together bridges a gapbetween the specialist dealers working with junior E&P companies and the big banks,which have concentrated on large deals and energy trusts.

Acquisitions and divestitures in Canada exceeded C$15 billion in 2004, comparedwith C$9.3 billion in 2003, according to Sayer Securities, powered by juniors andtrusts and show no signs of slackening this year.

Jeffrey Waterous, who founded his firm in 1987, will also give Scotia Waterous awindow on the international deal-making from his base in Gibraltar.

—GARY PARK

COOK INLETMMS delays Cook Inlet 2006 sale

The U.S. Minerals Management Service has postponed a Cook Inlet lease salescheduled for May 2006 due to lack of interest.

The agency said July 5 that Cook Inlet Sale 199 has been postponed until May2007.

MMS requested comments on the sale earlier in the year, and said it confirmed thatcompanies were not interested in a sale in 2006.

“We will evaluate early next year whether we will restart planning for a sale in2007. If conditions change, we could proceed,” MMS Alaska OCS Regional DirectorJohn Goll said in a statement.

“The Cook Inlet region faces future shortages in natural gas supplies, and we wantto be ready to respond if companies decide to renew exploration offshore,” he said.

May 2004 was the last Cook Inlet sale; there were no bidders, MMS Alaska regionspokeswoman Robin Lee Cacy told Petroleum News. MMS has two active leases inCook Inlet, she said, 9,766 acres leased in Sale 149 in 1997. The tracts are part of thejoint state-federal Cosmopolitan exploration unit off the lower Kenai Peninsula.

The next sale MMS has scheduled is Beaufort Sea Sale 202 in March 2007; theagency leased $46.7 million dollars worth of tracts at Beaufort Sea Sale 195 held inMarch.

—KRISTEN NELSON

8 PETROLEUM NEWS • WEEK OF JULY 10, 2005

● J U N E A U

Alaska tax chief joinsgas line negotiationsDickinson joins Clark on state negotiating team, says hewon’t return to state government after negotiations concluded

By MATT VOLZAssociated Press Writer

laska’s tax director will work full timeon gas pipeline negotiations as theMurkowski administration tries toclose financial terms for a gas line by

a self-imposed fall deadline.Dan Dickinson will leave the Alaska

Department of Revenue’s Tax Division onJuly 11. On July 1, Dickinson said he ismoving to the negotiating team because ofGov. Frank Murkowski’s “aggressive sched-ule to get the negotia-tions going.”

The state is talkingwith three separateapplicants underAlaska’s StrandedGas Act: the producergroup of BP PLC,ConocoPhillips andExxon Mobil Corp.;TransCanada; and theAlaska Gasline PortAuthority.

“The path is to geta deal put togetherbetween the produc-ers and the state underthe Stranded GasAct,” Dickinson said.

Asked if thatmeant the producers’application was beingviewed as the mostlikely to be approved,Dickinson said all three applications were inplay but any deal would have to include theproducers in some way.

The producers own the rights to 90 per-cent of the known gas reserves on the NorthSlope.

Dickinson said proposals like the portauthority’s plan to run a line to Valdez wereinteresting ideas, “but that doesn’t get gas tomarket.”

The producers favor a route throughCanada to markets in the Midwest, and havecalled the plan to pipe the gas to Valdez tooexpensive.

TransCanada proposes a pipeline that

would tie into its Canadian network.

Dickinson: ‘Gas has to be part of the deal’

In the end, one of the applications couldbe modified to bring in elements of another,Dickinson said.

“Clearly the gas has to be part of the dealand some of the things TransCanada broughtforward could be part of the deal,”Dickinson said.

Dickinson said he will continue workingwith the producers and their application inhis new role.

“People are looking at how to breakimpasses, how to re-conceptualize things soboth sides can find where there is commonground,” Dickinson said.

Dickinson is the second recent additionto the state’s negotiating team. Earlier thisweek, Murkowski announced that his chiefof staff, Jim Clark, was going to lead thenegotiators.

Murkowski spokeswoman BeckyHultberg called Clark and Dickinson “theclosers” and said they were brought inbecause of the increased pace of negotia-tions.

Many state lawmakers had hoped to bepresented with a contract proposal this leg-islative session. When that didn’t material-ize, Murkowski said he planned to have adeal made by fall.

“They certainly have been making regu-lar progress, and they are getting to the pointwhere they will be delivering something tothe Legislature by November,” said DeputyRevenue Commissioner Tom Boutin.

Dickinson acknowledged that the gover-nor may be frustrated with the negotiations,spurring the need to bring in his new“closers,” but then he said frustration maynot be the right way to put it.

“The governor is very anxious and hewants to make sure the right resources arebeing brought to the job,” Dickinson said.“He’s going to be the final closer.”

Tax Division Deputy Director LarryMeyers will become the division’s actingdirector. Boutin said no date has been set topermanently fill the position.

Dickinson said he does not plan to returnto state government once the negotiationsare concluded.●

A

CALGARYViking makes another raid in Canada

Calgary-based Viking Energy Royalty Trust is in full expansion mode, making itsthird acquisition of 2005 by taking over privately held Krang Energy for C$136 mil-lion and adding 5,000 barrels of oil equivalent per day.

The purchase comprises 2,500 boe per day of heavy oil and 14 million cubic feetper day of natural gas, almost 110,000 net undeveloped acres and 16.6 million boe ofproved and probable reserves, boosting Viking’s projected year-end output to 28,000boe per day — 50 percent gas, 40 percent light oil and gas liquids and 10 percentheavy oil. The purchase price, which includes assumed debt of C$36 million, reflectsa cost of C$32,600 per flowing boe.

—GARY PARK

Asked if the NorthSlope producers’application wasbeing viewed as themost likely to beapproved, DanDickinson said allthree applicationswere in play butany deal wouldhave to include theproducers in someway. The producersown the rights to 90percent of theknown gas reserveson the North Slope.

“The governor is very anxious andhe wants to make sure the right

resources are being brought to thejob. He’s going to be the final

closer.” —Dan Dickinson, Alaska gas pipeline

negotiating team

Dan Dickinson is the secondrecent addition to the state’s

negotiating team. Earlier thisweek, Murkowski announced that

his chief of staff, Jim Clark,pictured above, was going to lead

the negotiators.

CANADAPetro-Canada puts oil sands pieces in place

Petro-Canada is hot on the trail of achieving more than 200,000 barrels per day ofoil sands output within the next decade.

It closed a deal June 27 with UTS Energy to cover 90 percent of the C$1 billion firstphase of the Fort Hills project and is primed to make two key decisions later this year— one to build a separate upgrader to handle bitumen from Fort Hills and one to choosea site for a second steam-assisted gravity drainage project.

Brant Sangster, senior vice president of oil sands, told a New York investment con-ference June 29 that Petro-Canada is narrowing down its selection of the size, timing,technology and location of the upgrader.

It is also pondering whether to raise the initial output from Fort Hills above the tar-geted 50,000 bpd. Having invested C$300 million earlier this year to obtain a 60 per-cent share of the project, Petro-Canada has indicated it expects to participate in a proj-ect that could grow to 190,000 bpd and cost up to C$5 billion.

Fort Hills comprises a 45,000-acre lease holding an estimated 4.7 billion barrels ofbitumen, of which 2.8 billion barrels are recoverable through mining.

On the second steam-assisted project, Sangster said Petro-Canada believes it has asufficient potential in several leases to produce 30,000-40,000 bpd.

The company has also spent C$1.2 billion on equipment and anticipates investinganother C$1.4 billion to convert its Edmonton refinery to become a totally oil sands-based facility.

Currently the refinery runs 50,000 bpd from the Syncrude Canada oil sands consor-tium and 85,000 bpd of conventional light crude.

—GARY PARK

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PETROLEUM NEWS • WEEK OF JULY 10, 2005 9

● A R C T I C

Experts say polar bear population will shrinkMelting ice could reduce polar bear population 30 percent over next 35-50 years; expert says bears ‘vulnerable to extinction’

THE ASSOCIATED PRESS elting ice could spell the ruin of polar bear popu-lations over the next century, warns a report byan international panel of experts on the subject.

If warming climate in the Arctic continues toerode sea ice, the white carnivores will be driven ashoreor onto increasingly smaller floes in their hunt for seals,the World Conservation Union warned at the end ofJune.

The 40 members of the polar bear specialist groupsaid the population of the Arctic’s top predator couldcrash by 30 percent over the next 35 to 50 years andshould now be rated as vulnerable on an international“Red List” of threatened species.

“This is the first time that we’ve evaluated the plightof polar bears (with) respect to climate change, and wefound that they were vulnerable to extinction,” said thegroup’s outgoing chairman, biologist Scott Schliebe,who oversees management of polar bears in Alaska forthe U.S. Fish and Wildlife Service. “Polar bears don’thave a place to go if they lose the ice.”

Sea ice has lost thicknessOver the past decades, sea ice has lost thickness,

melted faster in spring and re-formed later in fall,according to the international Arctic Climate ImpactAssessment. Vast stretches near Alaska have become ice-free during the last three summers, setting a record in2003 and a near-record in 2004 for least coverage evermeasured. The thick multiyear ice essential to polarbears has been shrinking 8 to 10 percent per decade.

Some climate models predict summer ice could dis-appear from the Arctic Ocean by the end of the century.

“It’s now abundantly clear that we’re looking at aretraction of the sea ice environment,” Schliebe said.

“The projection from the climatologists is very grim.”Politicians who could do something about reducing

the greenhouse gas emissions that are at least partlyresponsible for heating the earth have been reluctant toact. The U.S. Senate passed a nonbinding resolution lastweek acknowledging the role of human-generated green-house gases in causing the climate to warm and suggest-ing that U.S. emissions should be cut back, but AlaskaSens. Ted Stevens and Lisa Murkowski voted against ameasure that would have imposed limits on those emis-sions.

Murkowski has said she wanted to see more conclu-sive evidence tying climate change to man-made releas-es before taking actions that could hurt the U.S. econo-my.

Although the polar bear group named climate warm-ing and the destruction of the ice habitat as the mainthreat to the species, it also cited poaching in Russia andthreats by contaminants as other problems.

The group, which advises the United States and otherArctic nations on polar bear biology and treaty obliga-tions, last rated the animals in a category of “least con-cern” in 2001 but had not yet considered the impact ofclimate change, Schliebe said. ●

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● G U L F O F M E X I C O

Knotty Head discovery well looking goodGulf of Mexico exploration well has already found more than 300 feet of apparent pay; headed to 32,500 feet in search of more

By RAY TYSON Petroleum News Houston Correspondent

notty Head could turn out to be a much larger Gulf ofMexico discovery than disclosed June 30 by co-oper-ators Unocal and Nexen.

The partners said the Knotty Head explorationwell, so far drilled to a depth of 29,670 feet, had encounteredmore than 300 feet of “apparent hydrocarbon pay,” alreadya tidy discovery by U.S. Gulf deepwater standards.

But the 300 feet of apparent pay was found in a “second-ary objective,” Knotty Head prospect operator Nexen said,adding that the “primary objective” yet to be penetrated wasfarther downhole in the Lower Miocene section.

Unocal, which is operating the initial Knotty Head explo-ration well on Green Canyon Block 512, said it had another2,800 feet of drilling before reaching a planned well depth of32,500 feet.

Nexen and Unocal, along with fellow exploration andproduction independents BHP Billiton and AnadarkoPetroleum, each hold a 25 percent interest in the KnottyHead prospect.

Chilkoot non-commercialHowever, it wasn’t all good news on the U.S. Gulf

exploration front for Unocal, which is currently weighingseparate bids for the company from Chevron and Chineseenergy company CNOOC.

Unocal and partner Kerr-McGee separately reported a“non-commercial” exploration well at their deepwaterChilkoot prospect on Green Canyon Block 320. Unocalsaid it expected to record a $6 million pre-tax charge inthe 2005 second quarter to cover its share of the wellcosts.

The well, drilled to a depth of 32,023 feet, is beingtemporarily abandoned but will be considered for futurere-entry or sidetrack, Chilkoot operator Kerr-McGee saidJune 30, noting that Chilkoot set a well depth record forthe company and is the deepest penetration thus far inwestern Green Canyon area.

“Well data is being evaluated and upon completion,additional appraisal will be considered,” Kerr-McGeeadded. “Data obtained is important to the geological

understanding in this under-explored area where Kerr-McGee holds interests in approximately 35 blocks.”

Kerr-McGee holds a 33.33 percent interest inChilkoot, followed by Unocal with a 23.34 percent inter-est, Devon Louisiana with a 20 percent interest, PlainsExploration & Production with a 13.33 percent interest,and Dominion Exploration & Production with a 10 per-cent interest.

Rig will move to ConquestThe Chilkoot drilling rig will be moved to Kerr-

McGee’s Conquest prospect on Green Canyon Block767, in the company’s so-called Constitution corridor.Following the Conquest appraisal, Kerr-McGee said itexpects to spud the West Covington prospect on GreenCanyon Block 765.

Kerr-McGee operates Conquest and West Covingtonwith 50 percent working interests. The prospects haveestimated reserve potential of 90 million to 240 millionbarrels of oil equivalent “and could add significant valuein the Constitution area,” the company said. TheConstitution hub, which includes the development ofTiconderoga through a sub-sea tieback, is Kerr- McGee’ssixth-operated deepwater hub in the U.S. Gulf. First pro-

But the 300 feet of apparent pay was found ina “secondary objective,” Knotty Head prospectoperator Nexen said, adding that the “primary

objective” yet to be penetrated was fartherdownhole in the Lower Miocene section.K

see KNOTTY HEAD page 11

10 PETROLEUM NEWS • WEEK OF JULY 10, 2005

White Rose oil project on trackNewfoundland’s third offshore oil field is expected on stream before Christmas, joining

the Hibernia and Terra Nova projects.Five of 10 initial development wells for White Rose have been completed and the

remainder will be drilled during the summer.(See photos of the floating, production, stor-age and offloading vessel for the project on this page.)

The field, located about 210 miles southeast of St. John’s, has up to 250 million barrelsof recoverable reserves.

It is designed to produce a peak 100,000 barrels per day and have an operating life of12 to 15 years.

But Ruud Zoon, Husky general manager for East Coast development, indicated thatresults from drilling activities so far are “very much in line, or even better than what weexpected,” pointing to a productive life exceeding 20 years.

Husky is 72.5 percent operator and Petro-Canada holds 27.5 percent.Zoon said the C$2.3 billion White Rose venture is viewed by Husky as a “platform for

future growth” in the region, adding that the project is on budget and 96 percent finished.He said the next challenge is to figure out a way to tap into the natural gas potential of

Newfoundland’s oil fields.“We see gas as a very significant potential for Husky, for the province and for the

industry to be developed in the longer term,” he said.The options include using gas to fuel co-generation power plants in Newfoundland or

exporting the production to U.S. markets.Since last fall Husky has been examining proposals by nine companies to develop the

gas, which is estimated at 2.7 trillion cubic feet for White Rose alone.—GARY PARK

The SeaRose FPSO hull was constructed by Samsung Heavy Industries in South Korea. It hasa storage capacity of 940,000 barrels of oil and features an ice-strengthened double hull anddetachable mooring system to ensure safe operations on the Grand Banks. The vesselarrived in Marystown in April 2004 for fabrication, installation and commissioning of thetopside modules.

On July 4, Husky Energy and the federal, provincial and local governments of Canada com-memorated the upcoming sailing of the SeaRose FPSO (floating production, storage andoffloading vessel) to the White Rose offshore oil project. Above, Husky Energy President andCEO John C.S. Lau, right, tours the SeaRose FPSO with Newfoundland and Labrador PremierDanny Williams.

The SeaRose FPSO will depart Marystown within the next 30 days and, after a series of testsin Mortier Bay, Newfoundland and Labrador, sail to the field.

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duction is expected in mid-2006.

East Breaks estimatedat 10-20 million barrels

Meanwhile, Kerr-McGee said its EastBreaks 599 discovery in the U.S. Gulf con-tains potential reserves of 10 million to 20million barrels of oil equivalent. The field isto be developed as a sub-sea tieback to thecompany-operated Boomvang productionhub, located about three miles south on EastBreaks Block 643.

The East Breaks Block 599 discovery,located in 3,220 feet of water, is operated byKerr-McGee with a 33.34 percent interest.Kerr-McGee’s partners are Amerada Hessand Marubeni Oil & Gas, each with a 33.33percent interest.

The East Breaks 599 well, spud on May27, was drilled to a total measured depth of9,142 feet and encountered more than 135net feet of “high-quality” oil pay in severalsands, Kerr-McGee said, adding that thewell would be temporarily abandoned forcompletion in early 2006.

Dave Hager, Kerr-McGee’ senior vicepresident of exploration and production,said the company plans additional satelliteexploration in the East Breaks area, with afour-well exploratory program at NorthwestNansen near the company’s Nansen produc-tion hub.

“We expect to spud the first well laterthis summer and estimate that the combinedresource potential for the four fault blocks isin the range of 20 million to 50 million bar-rels of oil equivalent,” Hager said. ●

continued from page 9

KNOTTY HEAD

ANCHORAGEAlaska gets $7Mgrant for energytraining

On July 5 U.S. Secretary of LaborElaine Chao announced a $7 milliongrant to the Alaska Department of Laborand Workforce Development to increasethe state’s capacity to recruit and trainworkers for careers in the energy indus-try. U.S. Sen. Ted Stevens, R-Alaska,joined Chao for the announcement at theUniversity of Alaska Anchorage.

“Alaska’s vast energy resources con-tinue to create a demand for skilledworkers,” Chao said. This $7 milliongrant will help train a pipeline of work-ers with cutting-edge skills for goodjobs in the energy sector of Alaska’seconomy, she said.

The grant will operate through a part-nership between the Alaska VocationalTechnical Center, the University ofAlaska and industry associations. Andaccording to a Department of Laborpress release Alaska will use the grant tointegrate vocational and technical train-ing; to increase the use of apprentice-ships to train workers; and “to continueto develop the public workforce sys-tem’s One-Stop Career Centers tobecome more industry driven inaddressing local economic needs.”

The press release also says that thegrant will help create more than 43,000jobs in the state over the next eightyears.

The grant is the first in a series ofinvestments that the Department ofLabor will make in the energy sectorunder President Bush’s High GrowthJob Training Initiative.

—PETROLEUM NEWS

12 PETROLEUM NEWS • WEEK OF JULY 10, 2005

HOUSTONRowan subsidiary to provide jack-up kits

Contract drilling company Rowan said its subsidiary, LeTourneau, has agreedto furnish vessel design and components, known as the LeTourneau kit, for con-struction of two Super 116 Class jack-up drilling rigs.

The rigs will be built by Keppel AmFELS for Scorpion Offshore, Rowan saidJuly 6. The LeTourneau kits, which consist of the rig’s legs, jacking systems,cranes and other components, are to be delivered in stages in accordance withconstruction schedules, the company added. Rowan said it expects the kit contractto provide about $55 million in revenue during 2006 and 2007.

—RAY TYSON

NORTH AMERICA

Canada’s rig count up 91; U.S. unchangedThe number of rotary drilling rigs operating in the United States and Canada

during the week ending July 1 stood at a combined 1,718, an increase of 91 rigsfrom the previous week and an increase of 120 rigs from the same weekly periodlast year, according to rig monitor Baker Hughes.

Canada had a reported 348 rigs at the end of the recent week and accounted forthe entire 91-rig increase in North America when compared to the prior week.However, Canada’s rig count still was down by 49 compared to the same periodlast year.

The number of rigs operating in the United States stood at 1,370, in totalunchanged from the previous week but up 169 rigs from the year-ago period.Compared to the previous week only, offshore rigs were up by two to 99, whileinland water rigs were up by one to 24. However, the number of land rigs droppedby three to 1,247.

Of the total number of rigs operating in the United States during the recentweek, 1,211 were drilling for natural gas and 157 for oil, while two rigs were beingused for miscellaneous purposes. Of the total, 854 were vertical wells, 333 direc-tional wells and 183 horizontal wells.

Among the leading U.S. producing states compared to the previous week only,Texas lost eight rigs for a total 607 rigs, while New Mexico lost three rigs for atotal of 74 rigs. Wyoming’s rig count increased by four to 78, while Oklahoma’sincreased by three to 150 and Louisiana’s increased by two to 190. Alaska’s rigcount was unchanged at 10, as well as California’s at 26 and Colorado’s at 68.

—RAY TYSON

● W A S H I N G T O N , D . C .

Crude futures finishabove $61 a barrelPrices set record on July 6; analysts warn of spike in retailcost of gasoline due to refinery outages from Gulf storm

By BRAD FOSSThe Associated Press

il prices climbed nearly three percent to finish at a record above$61 US a barrel on July 6 and ana-lysts warned of an imminent spike

in the retail cost of gasoline as storm-related power outages disrupted someoil production and refining operations inthe Gulf of Mexico.

The refinery snags caused by tropicalstorm Cindy were minor and temporary,and with petroleum producers preparingfor another possible hurricane, the flowof oil from the region was reduced byalmost 200,000 barrels per day. Traderssaid the rally exemplified the energymarket’s skittishness about any lost out-put at a time when the global supplycushion is thin.

Predict $2.30 a gallon in U.S.With gasoline futures jumping by

more than a dime per gallon, one analystsaid he expects a new high at the pumpwithin a matter of days.

“We’ll probably cross the $2.30 agallon national level by this time nextweek,” said analyst Tom Kloza of OilPrice Information Service in Wall, N.J.Retail gasoline now averages $2.23 agallon U.S.-wide, a nickel below thepeak that was set during the week end-ing April 11, according to the U.S.Energy Department.

Light sweet crude for August deliv-ery rose $1.69 to settle at $61.28 a bar-rel and establish a new record on theNew York Mercantile Exchange, whereoil has been traded since 1983. The pre-vious closing high of $60.54 per barrelwas set on June 27.

In London, Brent crude futuresgained $1.57 to $59.87 per barrel, set-ting a new record on the InternationalPetroleum Exchange. The previous highwas $59.59.

Crude oil futures are about 60 percent above year ago levels, though stillbelow the inflation-adjusted high above$90 a barrel reached in 1980.

While the rapidly weakening Cindymoved inland, tropical storm Denniswas expected to make its way into theGulf this weekend and possiblystrengthen into a hurricane before then.The U.S. National Hurricane Center’slead forecaster dubbed Dennis “a mini-mal hurricane” late in the day July 6,contributing to a late-day rally in oilprices.

Ivan memories strong“The worry is how much more dam-

age would Dennis do if it takes the samepath,” said Aaron Kildow, a broker withPrudential Financial in New York.

Petroleum producers evacuated 85production platforms and 11 drillingrigs, according to the MineralsManagement Service, which said190,000 barrels per day of oil had beenshut-in as a result. That is less than oneper cent of daily demand in the UnitedStates.

Oil broker Tom Bentz at BNP ParibasCommodity Futures in New York saidthere was no evidence so far of any seri-ous or lasting damage to oil productionor refining facilities. What’s propellingenergy prices higher, he said, is theunderlying fear that a hurricane, a ter-rorist attack or some other uncontrol-lable event could stymie oil productionand refining at a time when demand isstrong and excess output capacity is lim-ited.

While that nervousness helped pushgasoline futures higher, Bentz said themarket appears to have overreacted toCindy’s impact. “We’re getting a littlebit out of control,” he said.

Gasoline futures jumped 10.81 centsto $1.7899 per gallon, while heating oilfutures climbed 6.24 cents to $1.7948per gallon.

“Memories are still strong of thesevere and lasting damage done alongthe U.S. Gulf Coast by hurricane Ivanlast autumn, and the fear is that anotherheavy season of tropical storms will bat-ter this key producing region again thisyear,” said Energyintel analyst TomWallin in a research note.

Hurricane Ivan damaged some oilplatforms in the Gulf of Mexico andcaused others to shut down for months.Almost 44 million barrels of oil produc-tion was lost between September 2004and February 2005, while natural gasoutput declined over the same period by172 billion cubic feet. ●

OThe refinery snags caused by

tropical storm Cindy were minorand temporary, and with

petroleum producers preparing foranother possible hurricane, theflow of oil from the region was

reduced by almost 200,000 barrelsper day.

PETROLEUM NEWS • WEEK OF JULY 10, 2005 13

ALASKATentatively scheduled Alaska lease sales Agency Sale and Area Proposed Date

DNR North Slope Areawide October 2005

DNR Beaufort Sea Areawide October 2005

DNR Alaska Peninsula Areawide October 2005

BLM NE NPR-A 2005

MMS Sale 199 Cook Inlet 2007

MMS Sale 202 Beaufort Sea 2007

MMS Chukchi Sea/Hope Basin interest based

MMS Norton Basin interest based

Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management,manages leasing in the National Petroleum Reserve-Alaska; DNR, Alaska Department ofNatural Resources, Division of Oil and Gas, manages state oil and gas lease sales onshoreand in state waters; MHT, Alaska Mental Health Trust Land Office, manages sales on trustlands; MMS, U.S. Department of the Interior’s Minerals Management Service, Alaskaregion outer continental shelf office, manages sales in federal waters offshore Alaska.

This week’s lease sale chartsponsored by:

PGS Onshore, Inc.

UNITED STATESNuclear answer to U.S. energy needs

A substantial increase in nuclear power will be a key element of solving energyneeds in the United States, said former Energy Secretary Spencer Abraham — echoingremarks by his former boss, President George Bush. He told an Investment Dealers’Association of Canada conference in Banff June 28 that “nuclear is the centerpiece.”

Bush recently listed nuclear power as the one energy source that is “completelydomestic, plentiful in quantity, environmentally friendly and able to generate massiveamounts of electricity.”

The U.S. Senate’s energy bill has also acknowledged that potential by includingnuclear power among the sources that should qualify for billions of dollars in tax incen-tives. Abraham said that nuclear power should be a “significant component” of the U.S.drive to reduce greenhouse gas emissions and slow the growth of energy imports.

He warned that today’s tight energy markets are “likely to continue well into thefuture” and consumers should grow accustomed to oil at US$60 per barrel.

He said the challenges include almost no spare oil production capacity in the world;an “almost infinite” increase in demand over the next 20 to 30 years; self-imposed con-straints on supply on many regions; uncertainties and fear factors.

Abraham said that unless nuclear plants are built over the next 20 years, nuclear-generated power will drop from 21 percent of U.S. supply to 14 percent and even loweras aged facilities are decommissioned.

To let that happen would result in even greater dependence on other energy sources,whose origin is unclear, he said.

—GARY PARK

● N O R T H S L O P E

Pioneer has a rangeof Alaska prospectsCompany expects to be first independent to operate productionon the North Slope, CEO Scott Sheffield tells symposium

By KRISTEN NELSONPetroleum News Editor-in-Chief

laska’s North Slope has a role inPioneer Natural Resources’ near-term, mid-term and long-termplans, the company’s chairman and

chief executive officer, Scott Sheffieldsaid July 7 at an Independent PetroleumAssociation of America Oil & GasInvestment Symposium in London.

Pioneer expectsto be the first inde-pendent to actuallyoperate on the NorthSlope with itsOooguruk discov-ery, scheduled forsanction this year,Sheffield said.Oooguruk, a satellitenear existing infra-structure, is a near-term prospect; mid-term prospectsinclude the Storms area, south of PrudhoeBay; long-term (five to seven years)include the National Petroleum Reserve-Alaska.

“One of the reasons that we’re seeingmuch higher crude prices is people ingeneral are not exploring,” Sheffield said.“We’re seeing less exploration in the lastseveral years than any time in history …People are not exploring.” Pioneer, hesaid, has taken a long-term strategy, “try-ing to find the right basins and also wewent out and raided the majors over thelast six to seven years, hired some of theirbest people.” Pioneer has put in a lot ofthe processes that the majors use, he said:“a very disciplined process” for peerreview and post audit.

Oooguruk coming on in 2008Sheffield said Pioneer acquired inter-

ests in 1.6 million acres on the NorthSlope starting two years ago, when it

expected oil prices to be in the $30 perbarrel range. This includes 20-30 percentworking interests in 1.4 million acres inNPR-A, 50 percent working interest inthe Storms area south of Prudhoe andKuparuk, where it is the operator; and a70 percent working interest in 53,000acres at Oooguruk.

Pioneer had the first independent-operated discovery on the North Slope,Sheffield said: “We’ll be sanctioningthat project later this year at Oooguruk.”The North Slope, where the company islooking for oil, has under-utilized capac-ity, he said. “

We’ll be drilling about five to sixexploration wells per year” in Alaska,Sheffield said, noting that Pioneer’spartner is ConocoPhillips Alaska, “themost active explorer” on the NorthSlope.

Pioneer is building a rig, “teaming upwith an Alaska Native company and aCanadian drilling contractor,” Sheffieldsaid. He described the rig as unique. Therig will be more mobile, “more efficient”and “less costly” for drilling on theNorth Slope, Pioneer said. The rig willbe ready this winter.

In a slide accompanying the presenta-tion current Oooguruk work is describedas moving the project to a go-forwarddecision: island, pipeline and rig designare under way as is permitting. If theproject is sanctioned, a gravel islandwould be built and offshore buriedpipeline would be installed in 2007;development drilling would also beginthat year, with first oil in 2008. ●

A

SCOTT SHEFFIELD

“One of the reasons that we’reseeing much higher crude prices is

people in general are notexploring.”

—Scott Sheffield, chairman and CEO, Pioneer Natural Resources

14 PETROLEUM NEWS • WEEK OF JULY 10, 2005

DENVERSt. Mary to acquire 18.7 bcfe of reserves

Denver’s St. Mary Land & Exploration, through its Nance Petroleum subsidiary,has agreed to buy 18.7 billion cubic feet of gas equivalent reserves from an undis-closed seller for $39 million in cash, St. Mary said June 29. The deal is expected toclose on Aug. 2.

The properties to be acquired are primarily in the Wind River and Powder Riverbasins of Wyoming and currently produce about 530 barrels of oil and 3.2 millioncubic feet of gas per day, or 6,400 million cubic feet of gas equivalent per day.

In addition, the acquisition would include about 7,200 net acres of undeveloped oiland gas leases, St. Mary said, adding that 100 percent of the estimated oil and gas pro-duction over the next two years is hedged at average Nymex prices of $56.70 per bar-rel of oil and $7.45 per thousand cubic feet of natural gas.

Payment for the properties would be made from cash on hand and money availableunder St. Mary’s existing credit facility, the company said.

—RAY TYSON

MOSCOWRussia halts pipeline surveying at Baikal

Russia’s natural resources ministry said June 30 that surveying work for an oilpipeline to Asian markets had been halted around Lake Baikal, the world’s biggestfreshwater lake, over ecology fears.

In a statement, deputy natural resources minister Valentin Stepankov said that sur-veying work had been conducted outside the limits specified in government approvedguidelines and trees had been felled illegally.

Stepankov sent a letter to Greenpeace Russia, thanking the environmental group forhelping to monitor the surveying work.

When complete, the pipeline will pump oil from Siberia to lucrative markets inJapan and other parts of Asia.

The project has already drawn fire from environmental groups. As well as its prox-imity to Baikal, it envisions an oil terminal on the shore of the Perevoznaya Bay onthe Pacific Coast, which ecologists warn would create the risk of major oil spills in apristine area that is home to popular beaches, fishing grounds and rich marine life.

The planned 1.6 million barrels per day pipeline will follow a route from the townof Tayshet in Siberia’s Irkutsk region to Skovorodino in the Amur region.

From there, crude will be piped east to the port of Perevoznaya in the Primoryeregion on the Pacific coast, with a possible branch south to China. Beijing is lobbyinghard to secure the main pipeline from Skovorodino.

—THE ASSOCIATED PRESS

● W A S H I N G T O N , D . C .

Caught between twobidders: Unocal’s optionsCNOOC $18.5B bid tops Chevron’s $16.6B offer, which hascleared regulatory hurdles; House concerned about CNOOC

By BRAD FOSSAssociated Press Business Writer

bird in the hand, or two in the bush.That’s the choice facing UnocalCorp., which agreed in April to bebought by Chevron Corp. for $16.6

billion but is now considering a rival$18.5 billion bid from CNOOC Ltd.

The less lucrative Chevron offercleared its final regulatory hurdle the lastweek in June and Unocal shareholders arescheduled to vote on it in August. Bycomparison, the larger CNOOC proposalis not likely to receive such swift regula-tory approval. It has already generated aminor political storm in Washington,where many in Congress have warned ofa national security threat in selling a U.S.oil company to a Chinese government-owned one.

On July 1, CNOOC voluntarily filed anotice with a federal committee thatreviews foreign investments, providinginformation about how its operations andacquisition of Unocal might affect U.S.national security.

If Unocal intends to pursue a deal withCNOOC, it will make a similar filing andthe review process will begin. If Unocaldoes not file papers with the Committeeon Foreign Investments in the UnitedStates, the secretive inter-agency groupwill assume CNOOC is attempting a hos-tile takeover.

“This is going to be one of the moreinteresting deals to watch unfold,” saidMatthew R. Simmons, a Houston-basedinvestment banker well-known in thepetroleum industry.

Unocal reiterated its support for theChevron bid at the end of June in a letterto shareholders and a Unocal spokesmansaid July 1 there was no immediate planfor a CFIUS filing. But discussionsbetween Unocal and CNOOC are ongo-ing in New York and analysts said it istough to tell who will prevail. A biddingwar is possible and a third suitor couldeven enter the competition.

Chevron could bow outIf Unocal decides to pursue the

CNOOC offer, however, Chevron has theright to bow out, pocket a $500 millionbreakup fee and look elsewhere for astrategic partnership.

“There are other assets for Chevron tobuy,” said oil analyst Gene Gillespie atHoward, Weil, Labouisse in NewOrleans. “Unocal isn’t so unique that ithas infinite value.”

Unocal has 1.75 billion barrels ofproven reserves of oil and natural gas —an amount that would boost Chevron’sreserve base by roughly 15 percent andCNOOC’s by about 80 percent.

Unocal’s daily output of 169,000 bar-rels of oil and 1.6 trillion cubic feet ofnatural gas amounts to less than 1 percentof U.S. consumption, though both suitorshave expressed interest in its assetsbecause of their location. The majority ofUnocal’s activity is in Asia, particularlyin Thailand and Indonesia, but also in theCaspian region.

Aside from the regulatory certaintysurrounding Chevron’s offer for Unocal,analysts pointed out that the deal, which

is a combination of stock and cash, givesshareholders in the merged companysomething the CNOOC bid does not: anopportunity to see their investment groweven further if Chevron’s stock pricerises.

The all-cash CNOOC deal may looksweeter to Unocal shareholders on thesurface but there is “the risk of gettingnothing down the road” if regulatorsdon’t approve the merger, Gillespie said.

For its part, CNOOC believes theappeal of its offer for Unocal, the ninth-largest oil and gas producer in the U.S., isquite simple: It exceeds Chevron’s bid byalmost $2 billion. Also, Unocal workersmight make out better under CNOOC,which has said it does not intend to slashjobs in El Segundo, Calif., where Unocalis based. Chevron, based in San Ramon,Calif., plans to shed workers to eliminateredundancies and meet cost-saving tar-gets.

Chevron stock price downSince CNOOC raised the stakes,

Chevron’s stock price has fallen andUnocal’s has risen. As a result, Chevron’soffer is now about $5 below Unocal’sstock price, while CNOOC’s offerremains about $2 above it.

“Investors vote their pocketbook,”said oil analyst Fadel Gheit atOppenheimer & Co. in New York. “Thereis no way that Unocal shareholders aregoing to give their stock to Chevron for$60. But that is the value of the offer fromChevron as we speak.”

On July 1, shares of Chevron closed at$56.84 on the New York Stock Exchange,where Unocal’s ended at $65.65.(Chevron offered Unocal shareholders achoice of accepting $65 per share cash,1.03 shares of Chevron stock or a combi-nation of the two, though it said 75 per-cent of the transaction would be a stockswap.)

Simmons cautioned that although themarket is signaling that Unocal is worthmore than Chevron’s initial offer,“Chevron has got to be very careful of notgetting into a bidding war.”

CNOOC’s parent company, theChinese National Offshore Oil Co., ispredominantly owned by the Chinesegovernment, giving it very deep pocketswith which to make acquisitions.

Indeed, a considerable amount of theopposition to the deal comes from mem-bers of Congress who say CNOOC, as agovernment-backed company, is not on alevel playing field with Chevron.

CNOOC chairman Fu Chengyu deniesthat his company is acting on behalf ofChina’s government, which is in themidst of a multibillion-dollar campaign tosecure foreign oil and gas supplies to helpfuel its booming economy.

“This company is driven purely byeconomics,” Fu told The AssociatedPress.

Concern over Chinese motivesOne concern in Washington is that

CNOOC’s bid for Unocal is part of abroader strategy by communist China tohoard energy supplies before they runout. Another is that the United States

A

see UNOCAL page 15

PETROLEUM NEWS • WEEK OF JULY 10, 2005 15

CARACAS, VENEZUELAVenezuela to begin selling Orinoco tar tracts

Venezuela will begin selling off 27 new oil exploration blocks in the Orinoco tar beltas soon as state oil company Petroleos de Venezuela S.A. finishes calculating the oilreserves in each zone, company President Rafael Ramirez said July 1.

“We’ve begun the certification of all these reserves,” Ramirez told a news confer-ence. Venezuela looks to increase oil output to 5 million barrels a day by the end of thedecade, with around 1 million new barrels coming from the Orinoco area, the largesthydrocarbons deposit on the planet.

Venezuela claims the Orinoco holds 235 billion barrels of oil reserves, and plans toadd those extra-heavy crude reserves to its 78 billion barrels of conventional oilreserves. With those unconventional reserves included, Venezuela would surpass SaudiArabia as the nation with the world’s largest reserves.

Venezuela currently has four projects that upgrade Orinoco tar oil into more than500,000 barrels a day of marketable synthetic crude. Six major oil firms are involvedin producing and upgrading the crude oil through joint ventures with the state oil com-pany, commonly known as PDVSA.

Ramirez said the 27 blocks would each cover 200 square miles. PDVSAhas plans to begin producing 20,000 barrels of oil a day at the San Cristobal

field in the Orinoco region shortly, and reach 400,000 bpd by 2008. Ramirez said theSan Cristobal crude will be refined at the El Palito refinery on the country’s northeastcoast. The Orinoco projects have proven highly profitable amid record oil prices, andVenezuela has hiked tax rates on the existing joint ventures to improve revenue fromoil production. Exxon Mobil Corp., one of the firms involved, has said it may seek arbi-tration over the tax hikes, but other major oil firms, such as Norway’s Statoil, say theyare interested in new Orinoco deals despite the tax increases.

Venezuela is the world’s fifth largest oil exporter and a major U.S. supplier. —THE ASSOCIATED PRESS

Norway, Britain treaty designed tostimulate North Sea development

Norway and Britain on July 1 approved the first two offshore oil fields under a newtreaty for cross-border cooperation.

The treaty, signed in April, is intended to stimulate development of oil and naturalgas fields that straddle the North Sea median line between the countries.

Although the fields, called Blane and Enoch, are relatively small, a Norwegian oilministry statement called the joint approvals “important milestones in the bilateralcooperation.” The new treaty is intended to encourage development of cross-borderfields at a time when the world thirsts after more oil with crude prices at record levelsof about US$60 per barrel.

“Over the last years, the cooperation between UK and Norway has improved,” saidNorwegian Oil Minister Thorhild Widvey in a statement. “I am excited to observe thatthe new Framework Agreement for Trans-boundary Projects signed in April 2005, nowtranspose into new projects.” In the past trans-boundary fields like Enoch and Blanehad to be handled with individual treaties between Britain and Norway.

The new framework treaty includes projects not already outlined in other agree-ments, and covers such things as building joint oil and natural gas pipelines, jointlydeveloping median-line fields and using infrastructure on one side of the border todevelop resources in the other country’s waters.

Norway, the world’s third largest oil exporter, has encouraged development of newfields to shore up the decline in its production of 3 million barrels per day plus naturalgas. Britain is also an offshore oil and gas producer, and some border-straddling proj-ects, such as Statfjord, Frigg and Murchison, are already in production.

The Blane field is partly in British waters, and partly in Norwegian waters. Whendeveloped by the Paladin Expro Ltd. by the end of 2006, the field is expected to pro-duce about 14,000 barrels of oil per day. The Enoch field also lies in shared waters,and is expected to begin producing about 12,000 bpd when development, also led byPaladin, is completed by late next year.

—THE ASSOCIATED PRESS

NORTH SEA

might regret handing over technology orassets that have military value.

For example, Unocal has a stake in theColonial Pipeline, which delivers fuelfrom the Gulf Coast to the Northeast, andit owns oil terminals that feed into thenation’s Strategic Petroleum Reserve.There is also fear that certain deepwaterdrilling technology could have applicabil-ity in submarine warfare.

Many energy and national securityexperts have said much of the outcryfrom Congress has been overblown, andCNOOC executives have publicly said

they are willing to shed assets and takeother steps necessary to address nationalsecurity concerns.

Nonetheless, on June 30, the Houseregistered its discomfort with theprospect of a state-owned Chinese com-pany taking over an American oil firm,voting 398-15 to ask the president for animmediate and thorough review if Unocalaccepts CNOOC’s offer.

However, even if Unocal’s leadershipwalks away from the proposed CNOOCdeal, analysts said it’s possible Chevronwill sweeten its offer.

“If Chevron doesn’t up the price,”Simmons said, “then Unocal directors aregoing to get sued for turning down a bet-ter offer.” ●

continued from page 14

UNOCAL

CALGARYExplorers: Mac line should be larger

Canadian Arctic explorers apparently have at least one of the same concerns asAlaska Arctic explorers: will a planned natural gas pipeline be large enough toaccommodate discoveries they make, or will they have to get in line behindknown reserves?

The Globe and Mail reported July 7 that the Mackenzie Explorer Group toldthe National Energy Board that there is more gas in the region to be served by aproposed Mackenzie gas pipeline than the line could handle. Members of thegroup include Devon Energy andChevron Canada, companies which areexploring but don’t have a stake in theproposed pipeline.

Imperial Oil, ConocoPhillips Canadaand Shell Canada, the major sponsors ofthe proposed Mackenzie pipeline, havereserves of about 6 trillion cubic feet ofgas onshore.

John Richels, president of OklahomaCity-based Devon, said the company’splanned $60 million well in the BeaufortSea is targeting prospects that might con-tain several trillion cubic feet of gas.Devon told the National Energy Board itsworry is the capacity of the gathering sys-tem in the Mackenzie Delta.

A report for the explorers by a Calgaryengineering firm said capacity of the main pipeline could be an issue. The firmsuggested that with discoveries there might be enough gas to support a line mov-ing 2.5 billion cubic feet a day; the proposed line will be 1.2 bcf a day, with pos-sible expansion to 1.8 bcf.

Imperial spokesman Hart Searle told The Globe and Mail that Imperial is try-ing to strike a balance in the size of the line: “If you size it too big and the gasisn’t there, the cost of service goes way up.”

The study done for the explorers said there could be some 46 tcf of undiscov-ered gas in the Mackenzie Delta and Beaufort Sea, more than four times higherthan an estimate submitted in a study done for Imperial; that study focused ondemonstrating that there was enough gas to justify a pipeline.

Explorers such as Anadarko Petroleum, along with U.S. federal and Alaskastate agencies, have expressed concerns that initial capacity in a North Slope nat-ural gas pipeline would all be taken up by known gas reserves from Prudhoe Bayand Point Thomson.

—PETROLEUM NEWS

The Globe and Mail reportedJuly 7 that the MackenzieExplorer Group told the

National Energy Board thatthere is more gas in the region

to be served by a proposedMackenzie gas pipeline than

the line could handle. Membersof the group include Devon

Energy and Chevron Canada,companies which are exploring

but don’t have a stake in theproposed pipeline.

River’s similarities to our Manatokan fieldand the success we have enjoyed there,” saidStephen Hadden, Devon’s senior vice presi-dent of exploration and production

Manatokan analogous to Iron RiverThe company said Manatokan is a

“direct analogy” to Iron River in its geolo-gy, reservoir characteristics, oil quality andoperations. Moreover, about 85 percent ofDevon’s wells in the field have been suc-cessful, and it is the largest and best per-forming field in Devon’s Lloydminsterproject area, according to the Oklahoma-based company.

Hadden said the ExxonMobil propertiesrepresent several years of “low riskdrilling,” including 70 locations that aredrill-ready. He said companies can gener-ally drill year-round in the Lloydminsterarea and that Devon plans to have four orfive rigs up and running at Iron Mountainin the 2005 third quarter.

“Iron River is exactly the kind ofrepeatable, cost- effective developmentproject that exemplifies Devon’s NorthAmerican onshore property base,” Haddensaid.

The company said it anticipates drillingmore than 800 wells on the Iron Riverproperty over the next four years, an effortDevon expects would boost productionfrom a current 3,000 barrels of oil per dayto about 30,000 barrels per day by 2010.Iron River is expected to add around700,000 barrels of oil equivalent toDevon’s 2005 production, the companynoted.

XTO purchases in Texas, N.M.Forth Worth, Texas-based XTO said

July 5 that it purchased ExxonMobil pro-ducing properties in the Permian Basin ofWest Texas and New Mexico for $215 mil-lion. Last year deal-minded XTO bought$340 million worth of onshore assets fromExxonMobil and $912 million worth ofChevron properties spread across sevenstates, including Texas and New Mexico.

XTO’s latest transaction withExxonMobil brought long-lived provedreserves of about 21.1 million barrels of oilequivalent, 75 percent of which are proveddeveloped, XTO said, adding that theacquisition will initially add about 3,800barrels of oil equivalent per day to XTOproduction, 83 percent of which is oil. Thecompany projected a 25 percent produc-tion rate increase over the next two years.

“This transaction highlights our ongo-ing focus in acquiring specific properties inregions where XTO has experience and ahistory of increasing production andreserves,” said Bob Simpson, XTO’s chiefexecutive officer. “This Permian Basinpackage is an ideal overlay to our currentoperations.”

XTO also in JV with ExxonIn a separate deal with ExxonMobil,

announced June 30, XTO said it executedan agreement with the mega-major todevelop acreage in the northeastern portionof the Piceance basin in northwestColorado.

Under the terms of the joint venture,XTO will farm-in about 69,500 contiguousgross acres east of ExxonMobil’s PiceanceCreek unit in Rio Blanco and Garfieldcounties. XTO will operate and earn a 50percent working interest in the entireExxonMobil leasehold by drilling fourwells. The first well would target theWilliams Fork (Mesaverde) formationwith drilling to begin year-end, XTO said.

“The Piceance basin is an ideal additionto our tight-gas and unconventional prop-erty base,” XTO President Keith Huttonsaid. “This acreage position exposes XTOto a portion of the trillions of cubic feet ofnatural gas the basin is projected to hold.”

In May 2004, ExxonMobil and inde-pendent Apache formed a joint ventureinvolving a broad range of their prospec-tive and mature properties in the UnitedStates and Canada. ExxonMobil gaineddeep gas rights to certain Apache proper-ties in the Gulf of Mexico and onshoreLouisiana, while Apache gained access toExxonMobil properties in Canada, thePermian Basin of West Texas and NewMexico.

Earlier this year the two companiessigned an agreement to expand their explo-ration and development activities inAlberta. The deal, which they said wouldcapitalize on each company’s strengths,added 800,000 acres to Apache’s existing6.9 million acres in Western Canada.

ExxonMobil Canada Energy farmed outits interest in about 650,000 acres of addi-tional undeveloped property interests toApache Canada over and above the morethan 370,000 acres conveyed last year.

Under the new agreement, Apache alsowas to test additional horizons on about140,000 acres of the property conveyed in2004. Apache committed to drill and oper-ate 145 new wells in both shallow and deepzones over a 36-month period. ●

16 PETROLEUM NEWS • WEEK OF JULY 10, 2005

continued from page 1

EXXONSAN FRANCISCOCalpine selling oil, gas assets for $1.05B

Power producer Calpine Corp. announced June 29 it will sell all its domestic oil andgas exploration and production assets to an indirect subsidiary for $1.05 billion.

Calpine said the subsidiary, Rosetta Resources Inc., is selling 45.3 million shares for$725 million in private placement, and will use the proceeds, plus $325 million in cred-it, to buy all of Calpine’s domestic exploration and production assets.

And since Rosetta will be privately held and Calpine will own no shares in the com-pany once the transaction is completed on July 7, Calpine spokeswoman KatherinePotter said she could divulge no more details about the deal — such as who will actu-ally own the assets. Analysts said the company did well to group its gas and oil explo-ration and production assets in one attractive package.

“It’s a pleasant surprise on the upside,” said Michael Worms, an energy analyst withHarris Nesbitt in New York. “There’s no question that this company needs to improveits financial condition and they’re addressing it with these asset sales.”

Calpine Chairman Peter Cartwright, who co-founded the company 21 years ago,pledged before May’s shareholder meeting to shed $3 billion in debt this year and trim$200 million from its annual expenses.

The struggling energy merchant has lost $390 million in the past five quarters,prompting a steep drop in its stock price, which had approached $60 in early 2001when electricity prices were soaring. Dramatically lower power prices have sincezapped Calpine and many other energy wholesalers.

“Owning gas fields isn’t as advantageous as it once was,” said Worms. “Calpine’score business is generation.”

Calpine is selling some of that, too — it recently announced it would sell four powerplants for about $360 million. Worms said the company could expect to lower its annu-al interest payments by $275 million after trimming its debt.

—THE ASSOCIATED PRESS

PETROLEUM NEWS • WEEK OF JULY 10, 2005 17

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Carolyn Tubbs, Moving Consultant

FOR

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By PAULA EASLEY

Sourdough TransferEstablished in 1898, Sourdough

Transfer and its employees provideprofessional, courteous service to cus-tomers. The company provides every-thing from full-pack service to con-tainers for self- loading. Local,intrastate, interstate and internationalservices are available. Sourdoughworks with folks coming to Alaska orleaving the state. The company coor-dinates the entire move, making itless stressful so customers can con-centrate on other moving issues.

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Steve Denton, Vice PresidentBusiness

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Usibelli Coal Mine, Inc.

Usibelli Coal Mine has suppliedInterior Alaska with cost-effective fuelfor heating and electricity productionfor more than 60 years. Using the lat-est technology and reclamation prac-tices, Usibelli produces about 1.5 mil-lion tons of coal annually for exportand instate customers.

Professional engineer SteveDenton attended Dimond High andthe University of Alaska. He’s heldnumerous jobs with Usibelli over thelast 18 years. He and his wife of 32years, Liz, have two daughters andfive grandchildren. Steve is active inthe Alaska Miners Association, RDC,NRA, and supports the Spinal CordSociety and Pacific Legal Foundation.Favorite quote: “Success is how highyou bounce when you hit bottom.”—Gen. George Patton.

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

Instead the draft plan says the PointThomson unit owners “have consideredthe most appropriate time to begin devel-opment drilling in the PTU and have con-cluded that field activities associated withdevelopment drilling should begin threeto three and one-half years before fieldstartup.” The draft plan says that wouldallow enough time for gravel pads to set-tle before drilling begins.

Work during the plan period (Oct. 1,2005, through Sept. 30, 2006) “willinclude further development of the GasSales Conceptual Depletion Plan” devel-oped during the previous plan period. Thework is necessary, ExxonMobil said, toallow the unit owners “to participate in apotential open season for major gas salesfrom the North Slope of Alaska.”

Expansion terms geared to oil Point Thomson leases were unitized in

1977. By the terms of the 2001 unit expan-

sion, the unit owners would contract theexpansion acreage out of the unit and paythe state $20 million if developmentdrilling does not begin by the 2006 date.If drilling begins, but the seven develop-ment wells are not completed by the 2008date, the expansion acreage would con-tract out of the unit and the owners wouldpay the state $27.5 million. These pay-ments are in lieu of what the statebelieves it could have gotten for the leas-es in lease sales if they had not been partof the unit.

In 2002 the unit owners decided not todrill a well on the western Red Dog leas-es at Point Thomson, and paid the state$940,000, as per the 2001 agreement.

In 2003, ExxonMobil requested a two-year extension of three deadlines in the2001 agreement: a one-time election byJune 15, 2003, to contract the unit; arequirement to begin developmentdrilling by June 15, 2006; and a require-ment to complete seven developmentwells by June 15, 2008. The Division ofOil and Gas extended the unit contractiondeadline until Jan. 15, 2004, andincreased the penalty from $8 million to$10 million, but declined to extend theother deadlines.

“It is premature to consider extendingany of the other dates” in the decision,division Director Mark Myers said in aMay 7, 2003, letter to ExxonMobil.

Standalone project not economic In late 2003 ExxonMobil told the divi-

sion that further work done in evaluatingthe Point Thomson resource had “resultedin a significant reduction in liquidresources.”

Point Thomson had been pegged at400 million barrels of recoverable con-densate and about 8 trillion cubic feet ofnatural gas. The division had been carry-ing Point Thomson oil reserves in itsannual reserves report at 435 million bar-rels; in the division’s 2004 report that vol-ume was reduced to 329 million barrels.

ExxonMobil also said that work dur-ing 2003 found increased facilities, per-mitting and environmental costs onlypartly offset by changes in developmentscope.

“Our conclusion is that a standaloneproject prior to gas sales is not economi-cally viable under the current fiscal sys-tem,” the company told the division. Thecompany said it was exploring otherdevelopment plans, and discussing alter-natives with the state, but said workrequirements of the 2001 expansion

agreement are no longer “aligned with theintent of the original agreement and not inthe best interests of the State of Alaska.”ExxonMobil proposed a change in therequirements of the agreement throughJune 15, 2006: the owners could elect tocontract the expansion acreage at anytime until June 15, 2006, and would paythe $10 million (effective Jan. 15, 2004)plus an additional amount based on eachmonth since Jan. 15, 2004.

The division responded in January2004, telling the companies that it did notbelieve the Point Thomson owners had“made any specific proposals that wouldwarrant a further extension” of the con-traction election date.

Exxon appeals 21st planExxonMobil submitted a 21st plan of

development, in which the PointThomson owners proposed to focus ongas. The Division of Oil and Gas wanteda broader review of hydrocarbon potentialin the unit, and various drafts of the 21stplan were exchanged. The division issueda conditional plan in September.

ExxonMobil appealed provisions inthe 21st plan of development requiringthe owners to provide specific data to thestate. The owners also required that thestate sign a confidentiality agreement.

In a November 2004 decision,Commissioner of Natural Resources TomIrwin said the primary question in theappeal was whether or not the division “isentitled to a copy of the data that was thebasis for Exxon’s proposed 21st POD”and the division’s decision. The commis-sioner said the division was entitled to thedata.

For several years, the commissionersaid, the Point Thomson owners hadfocused on a gas cycling project: gaswould be produced and condensatestripped from the gas and shipped downthe trans-Alaska oil pipeline. The gaswould be re-injected for later sale.

Once the unit owners determined thatgas cycling was not commercially viable,they focused on producing natural gasrather than on gas cycling. The draft 21stplan of development, submitted in June2004, focused on gas sales, rather than ongas cycling and condensate sales, but thedivision asked that the 21st plan “includeplans to evaluate all potential hydrocar-bon resources within the unit area and toevaluate alternate development scenar-ios.” The division also requested that thePoint Thomson owners “provide specifictechnical data it needed to complete itseconomic analysis of the gas cycling proj-ect and provided Exxon with draft word-ing describing the type of data needed.” Arevised plan included most of the changesrequested by the division, the commis-sioner said.

The Point Thomson owners “agreed toprovide some technical data, includingdigital data and interpretations, (but) theproposed plan did not commit to provideall of the technical data” the divisionneeded for its evaluation of the plan ofdevelopment.

A conditional approval of the 21st planissued in September 2004 conditionedapproval on Exxon providing copies of allof the data the division had requested nolater than Nov. 15, 2004, and without thedivision executing a confidentialityagreement.

In October Exxon appealed therequirement that technical data be provid-ed by Nov. 15 and the requirement thatthe 22nd plan include specific plans tofulfill the requirement to drill by June 15,2006.

Division could have denied 21st plan The commissioner said that since

ExxonMobil, the unit operator, did notincorporate requested changes into the21st plan, the director of the divisioncould have disapproved the plan, ratherthan issuing a conditional approval. Thatwould have left the Point Thomson unitwithout an approved plan, “which is aground for default under the PTUAgreement.”

Irwin said Exxon said in its appeal thatit could not be required to provide inter-pretations of confidential data and infor-mation. But, he said, documents on filewith the division show that Exxon hasbeen willing to share both informationand interpretations, and proposed thatdivision staff attend work sessions in itsHuston office to review the data and torun scenarios on its proprietary models.

At issue in the appeal is whetherExxon can be required to provide copiesof requested information to the divisionor can limit the review of certain infor-mation to its office in Houston, andwhether Exxon can require a confidential-ity agreement.

Exxon says gas cycling is not commer-cially viable and Irwin said the divisionneeds to evaluate whether the proposedgas sales project will conserve resourcesat the Point Thomson field, “prevent eco-nomic and physical waste, and protect theState’s interests.” In order to make thosedeterminations, the division needs therequested technical data, he said, needs“unfettered access to technical informa-tion” that is the basis of the PointThomson unit owners’ decisions andneeds access to that information in thedivision’s offices in Anchorage.

Irwin said the division also needs tohave custody of the complete record thatis the basis for its decisions, which itwould not have if it is limited to viewing

18 PETROLEUM NEWS • WEEK OF JULY 10, 2005

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POINT THOMSON

see POINT THOMSON page 19

information elsewhere. As for the confidentiality agreement,

Irwin said statutes, regulations and thePoint Thomson unit agreement “providefor submittal of confidential informa-tion.” The division is already required tohold data confidential upon request, and“interprets the regulations to extend con-fidentiality to all work product and inter-nal interpretations that are based on con-fidential data.”

The division has provisions in place tosecure confidential data, Irwin said, and“it is inappropriate for Exxon to conditionprovision of the requested information onthe execution of a confidentiality agree-ment.”

Drilling requirement will stay ExxonMobil also requested that a para-

graph in the 21st plan decision requiringthat the 22nd plan of development “mustcontain specific plans for developmentdrilling” in the Point Thomson unit bestruck from the decision. The commission-er said the division was reluctant to expandthe Point Thomson unit by 39 percent in2001, “given that no development hadoccurred in the unit during the preceding24 years” and the unit owners “had noplans to develop the known reservoirsunderlying the PTU in the foreseeablefuture.”

The division said in 2001 that approv-ing the unit expansion was only in thestate’s interest if the unit owners commit-ted to development.

ExxonMobil has repeatedly said it can-not find a commercial development. It isappropriate, the commissioner said, thatthe division make clear “what it is and isnot approving.” The division “agrees that itis appropriate for Exxon to evaluate devel-opment of the Thomson Reservoir throughmajor gas sales from the North Slope, butExxon is not relieved from the commit-ments” made in connection with the 2001unit expansion.

Governor gets involved The division did not get all of the infor-

mation it wanted. In February Alaska Gov. Frank

Murkowski wrote to ExxonMobilChairman and Chief Executive Officer LeeRaymond, requesting additional informa-tion. The data ExxonMobil provided inNovember was applicable to gas cyclingdevelopment, the governor said, but theunit owners have said that is uneconomic.“I understand the unit owners are nowstudying alternative field development anddepletion scenarios. I assume these includegas cycling followed by gas sales, gassales without any gas cycling, and varioussimultaneous gas sales/gas cycling combi-nations.” The governor asked for reservoirsimulation results for each scenario theowners have studied, and told Raymond

that the state can’t conduct the requiredanalysis “nor come to any meaningful con-clusions as to the best path forward atPoint Thomson without the requested dataand an understanding of the options thatare available to develop the field.”

In March, ExxonMobil presented infor-mation on Point Thomson developmenteconomics to the Department of NaturalResources and the governor’s gas cabinetand agreed to provide analysis of addition-al development scenarios and supportingdata.

Royalty work under way ExxonMobil Production told the divi-

sion in April that the North Slope naturalgas sponsor group (BP, ConocoPhillipsand ExxonMobil) has proposed convert-ing Point Thomson leases issued with dif-ferent royalty provisions to the same fixedroyalty. Some of the leases are net profitshare, and the company said converting allof the royalty to the same fixed percent“would greatly simplify unit administra-tion of royalty oil and eliminate the needfor audit” of the net profit share leases.

ExxonMobil said the state requestedthat the Department of Natural Resourceswork with the sponsor group to agree on afixed oil royalty percentage, and forward-ed a confidential explanation of the

methodology the company used to arriveat a recommended 14.5 percent blendedroyalty rate.

ExxonMobil said that in addition to thedevelopment scenarios mentioned in thegovernor’s February letter, PointThomson development scenarios include:condensate sale only with creative gasstorage options followed by gas sales;condensate sales only with creative gasstorage followed by gas cycling at moder-ated injection pressures and final gas blowdown in major gas sales; and developmentof Brookian oil accumulations as a stand-alone, as well as concurrently with theother two scenarios described. ●

PETROLEUM NEWS • WEEK OF JULY 10, 2005 19

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POINT THOMSON

day in 2006, although Chief ExecutiveOfficer Brian Dau concedes that acquisi-tions not major discoveries offer the besthope for growth.

For J.C. it’s a chance to recapturesome of his past by taking up the chal-lenge of building a public company.

Eni chief under pressureto buy; Italian giantlikes high-risk projects

ACCORDING TO A JULY 1 DowJones Newswires report, Eni SpA’s newchief executive is under growing pres-sure to put the oil and gas giant back onthe acquisition track.

The pressure comes from continued

high oil prices and an expectation ofmore consolidation within industry tosecure hydrocarbon resources.

Paolo Scaroni could resume his pre-decessor’s spending spree, the newsagency reported, noting that the cash-rich Italian company’s share price hasrisen 40 percent since January as the oilindustry looks at another round of con-solidating.

Eni is rumored to be considering anAlaska acquisition that would give theenergy giant a toe-hold in the northern-most state.

Dow Jones was quick to point out thatScaroni hasn’t “yet made any publiccomments on Eni’s growth strategy,” butthat an influential board member recent-ly voiced his support for expansion.

A Milan analyst told the news agencythat one of the companies Eni is expect-ed to make a bid for is PetroKazakhstan.

(Eni already controls key assets inKazakhstan.)

The news agency said another possi-ble bid target is U.K. oil major BG PLC.

But although analysts said Eni couldbe back on the acquisition trail, theydon’t expect the company to act aggres-sively, the news agency reported. Forinstance, they don’t expect Eni to getinvolved in a bidding war with Chevronand CNOOC over Unocal.

According to a recent report byGoldman Sachs, Scaroni has little expe-rience in the oil and gas sector, wherethe ability to conduct lengthy and toughnegotiations with foreign governments isa must.

The report also pointed out that Eni’sgrowth is more concentrated than otheroil majors in a few giant projects in non-OECD (Organization for EconomicCooperation and Development) coun-tries.

Goldman Sachs also said Eni’s port-folio contains projects with a high levelof risk and a high level of potentialreturn. Sounds like a perfect match forAlaska. ●

Editor’s note: Oil Patch Insider iswritten by Gary Park and Kay Cashman.News tips can be emailed to publish-er@PetroleumNews.com.

continued from page 1

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production in the region. BHP andWoodside, Australia’s largest producers,hold large exploration positions in theGulf. Neptune would be Enbridge’s firstoil line in the Gulf.

Neptune close to Green Canyonpipeline

Moreover, Neptune is a major devel-opment relatively close to Enbridge’sexisting Green Canyon pipeline infra-structure, the company noted.

“The Neptune lateral project is anotherpositive step in our strategy of buildingon Enbridge’s recently acquired deepwa-ter offshore businesses in the Gulf ofMexico,” Enbridge Vice President DanTutcher said June 30. Enbridge alreadyoperates natural gas pipelines in the Gulf.

In addition, Neptune would provide anew natural gas supply and potential foradditional supply sources for the existingCleopatra, Manta Ray and Nautilus off-shore pipeline systems, all partiallyowned by Enbridge.

Enbridge said oil from the Neptunewould be delivered to the existing CaesarOil Pipeline, which connects with theCameron Highway pipeline to Texas mar-kets.

Enbridge will build 23 miles of pipePlans call for Enbridge to construct

and operate a natural gas lateral pipelinethat would consist of 23 miles of 12-3/4-inch diameter pipe and an oil lateral madeup of 23 miles of 20-inch diameter pipe.The laterals would have the capacity todeliver more than 200 million cubic feetof natural gas per day and roughly 50,000barrels of oil per day.

Neptune, about 120 miles from theLouisiana coast in water depths rangingfrom 4,200 to 6,500 feet, has estimatedrecoverable reserves of 100 million to150 million barrels of oil equivalent. BHPhas a 35 percent stake in the field, fol-lowed by Marathon with 30 percent,Woodside with 20 percent and Maxuswith 15 percent.

Pipeline connection to offshore pro-duction facilities is scheduled for the sec-

ond quarter of 2007, with first productionexpected by year-end 2007.

“Neptune will be our first operated,deepwater standalone facility in the(Gulf) and represents a significant mile-stone towards building a core business inthat region,” said Philip Aiken, BHP’sgroup president of energy.

With the BP-operated Mad Dog field,

which came on stream this year; the BP-operated Atlantis field, which is sched-uled to come on line in 2006, and nowNeptune, BHP’s daily net productionfrom the U.S. Gulf would exceed 100,000barrels of oil equivalent.

The Neptune facility has a designcapacity to produce up to 50,000 barrelsof oil and 50 million cubic feet of gas perday. BHP’s share of the project is $300million.

The field comprises Atwater Valleyblocks 573, 574, 575, 617 and 618. Theproduction facility would be in about4,250 feet of water.

Tension-leg platform selected A standalone, tension-leg platform has

been selected for the development, BHP

said, adding that facilities, wells, andcompletions “are proven designs” thathave been used successfully in the deep-water Gulf.

The wells, subsea systems, flowlines,floating systems, topsides and risers willbe designed, procured, fabricated andoperated by BHP on behalf of theNeptune joint venture partners, BHP said.

Neptune, found in 1995, was the firstdiscovery in the western AtwaterFoldbelt, with an initial appraisal well(Neptune-2) drilled in 1997. Neptune-3,drilled in 2002, encountered about 130feet of net pay. Neptune-5, drilled in2003, found a whopping 500 feet of netpay in a 1,200-foot column. AndNeptune-7, drilled in 2004, intersected114 feet of net pay. ●

continued from page 1

NEPTUNE

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Neptune represents several firstsfor the U.S. Gulf. It would be

BHP’s first operated project andWoodside’s first production in the

region. … Neptune would beEnbridge’s first oil line in the

Gulf.