two-bits could be first
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9Anadarko’s Marco Polo fallsshort of production goal
Vol. 9, No. 45 • www.PetroleumNews.com North America’s source for oil and gas news Week of November 7, 2004 • $1.50
● C A N A D A
● N O R T H A M E R I C A
● N O R T H S L O P E
B R E A K I N G N E W S
6 West Coast LNG gains: ExxonMobil drops Mobile plans;
Sempra gets OK for Mexican terminal;Woodside joins offshore project
7 Chesapeake grows: Independent ups production outlook, reserveestimates through 2006; gains through drilling vs. initial property deals
15Gazprom moves: Far East Report news includes Gazprom in
Sakhalin, Siberia; Sakhalin gas and China; TNK-BP and Siberia, and more
Talisman I.D.s big Alaska prospects
Two-Bits could be firstIf drilling successful at North Slope prospect, independent Armstrongexpects to begin production by late 2005 from its own modular facilities
By KRISTEN NELSONPetroleum News Editor-in-Chief
moother, faster, better, cheaper is ArmstrongOil and Gas’s mantra.
“Smoother, faster, better, cheaper: everyday that’s what we try to do; without that we
think the competition will go by us,” Stu Gustafsontold the Alaska Support Industry Alliance Oct. 28in Anchorage.
Armstrong Oil and Gas hit the ground runningin Alaska three years ago, acquiring a major NorthSlope acreage position and bringing in two largeindependents as operating partners, PioneerNatural Resources and Kerr-McGee, in the interim.The Denver-based independent participated in five
S
This is the type of modular processing facility thatArmstrong Oil and Gas is looking at for its Two-Bitprospect just west of the Kuparuk River unit onAlaska’s North Slope, if exploration prospects thecompany plans to drill this winter prove commercial. see ARMSTRONG page 12
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EnCana gets a makeoverPulls out of British North Sea, plans to sell Ecuador, Gulf of Mexico holdingsto ‘sharpen’ focus on North America’s unconventional gas and oil sands
By GARY PARK Petroleum News Calgary Correspondent
t’s not yet a full-scale pullback toFortress North America, but theglobal super-independent that wasEnCana’s destiny in 2002 is now
emerging as a leaner operation.Gone, other than the formalities, are
British North Sea interests for US$2.1billion in cash.
Going are assets in Ecuador and theGulf of Mexico, both areas nowdeemed to be non-core.
With them, the Calgary-based com-pany will shed about 300 North Seaemployees and 600 in Ecuador.
“These combined transactions willfocus EnCana as the leading NorthAmerican natural gas producer and thepremier in-situ oil sands developer,”the company said.
Chief Executive Officer GwynMorgan told a conference call Oct. 29that the objective is a strategic realign-ment of EnCana’s premium-growth,
China confuses CanadaNoranda bid prompts federal legislators to press for updated foreign investmentrules as China embarks on aggressive global shopping spree for resource assets
I“It’s not about size,
it’s about value.” —EnCana CEOGwyn Morgan see ENCANA page 18
By GARY PARK Petroleum News Calgary Correspondent
here has not been a fussquite like it since the turn ofthe century when a C$50billion wave of takeovers
pushed U.S. control of Canadianoil and gas production close to 60percent and never such a clamorfor updated foreign investmentlimits since 1977 when foreign ownership of pro-duction stood at 74 percent.
Although the debate is currently being driven by
a pending C$7 billion takeoverof mining giant Noranda by met-als trader China Minmetals, thepetroleum industry is waiting offstage to see what happens next.
After decades of blockingChinese companies from spend-ing money overseas, the Beijinggovernment is pushing them toinvest abroad to round up naturalresource assets.
By the end of 2003, Chinese companies hadinvested US$33 billion in 7,470 companies in
see CHINA page 16
TPrime Minister Paul Martin
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Pictured above is a ConocoPhillips Alaska exploration site in theNational Petroleum Reserve-Alaska where Talisman Energy’s U.S.subsidiary Fortuna Exploration holds oil and gas leases. Talismanexecutive vice president, exploration, John ‘t Hart, said Nov. 2 thatthe Canadian independent has identified a “couple of very bigprospects” within its 560,000 acres in northern Alaska.
Crude futures continue to fall Oil futures prices fell Nov. 3 after a government report showed
U.S. supplies of crude rising sharply, allowing traders to shrug offthe fact that inventories of heating oil are still tight.
“The psychology of the market has completely flipped,” saidMichael Guido, director of commodity strategy for SocieteGenerale in New York, noting that prices have fallen about 10 per-cent in the past week as oil production in the Gulf of Mexicorecovers and traders anticipate a boost in heating oil productionbefore the month is up.
The Nov. 3 drop came even as uncertainty about internationaloil output swirled around the market.
The chief executive of Russian oil giant Yukos said the compa-ny is “close to insolvency.” Iraqi oil officials said exports from thenorth could suffer for 10 days as a result of an attack on a keypipeline. And in Nigeria a strike scheduled for later in Novemberthreatens the country’s oil exports.
Nevertheless, the reported rise in U.S. oil supplies and thegrowing sense among traders that refiners will be able to produceenough heating oil this winter kept crude futures on the downwardtrend that began last week.
Dropping prices projected Ed Silliere, vice president of risk management at Energy
see FUTURES page 16
2 PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004RIG REPORT
Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status
Alaska Rig StatusNorth Slope - Onshore
Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point, drilling MPG-19 BPSky Top Brewster NE-12 15 (SCR/TD) Deadhorse yard, expected start 2005 ConocoPhillipsDreco 1000 UE 16 (SCR) J-pad. J-2 sidetrack BPDreco D2000 UEBD 19 (SCR/TD) Alpine, drilling CD1-11 ConocoPhillipsOIME 2000 141 (SCR/TD) Infield Kuparuk, drilling 1E-168
multilateral ConocoPhillips
Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES (SCR) Prudhoe Bay, 5-24A BPMid-Continent U36A 3-S Stacked, Deadhorse AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay, NGI-11 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay, Z-13A BPDreco 1000 UE 9-ES (SCR/TD) Prudhoe Bay, V-210i BPOilwell 2000 Hercules 14-E (SCR) Stacked, Deadhorse AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked, Prudhoe Bay AvailableOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableOIME 1000 19-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Stacked, Kuparuk Available
Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Kuparuk, E-17 BPSuperior 700 UE 2 (SCR/CTD) Kuparuk, 1-D-11 BPIdeco 900 3 (SCR/TD) Kuparuk, stacked at 1-Q ConocoPhillips
North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E (SCR/TD) Stacked, NorthStar BPEmsco Electro-hoist Canrig 1050E 27-E (SCR/TD) Stacked at 12-acre pad Kerr-McGee
Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Stacked in Nikiski Available
Evergreen Resources AlaskaWilson Super 38 96-19 Stacked in Wasilla yard Evergreen Resources
Alaska Corporation
Inlet Drilling Alaska/Cooper ConstructionKremco 750 CC-1 Stacked, Kenai Available
Kuukpik 5 West Forelands, drilling #2 Forest Oil
Marathon Oil Co.(Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Working on KBU 42-6 Marathon
Nabors Alaska DrillingRigmasters 850 129 Happy Valley #11 UnocalNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 Stacked, Kenai Available
51 Steelhead platform, done 12-1-03 UnocalFranks 26 Swanson River, 24-A05 UnocalIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform Available
Water Resources InternationalIdeco H-35 KD Moving to Beluga area Pelican Hill
Cook Inlet Basin – Offshore
Cudd Pressure Control 340K Stacked Available
Unocal (Nabors Alaska Drilling labor contractor)Not Available
XTO Energy (Inlet Drilling Alaska labor contract)National 1320 A Idle XTONational 110 C (TD) drilling well C22A-26LN XTO
Mackenzie Rig StatusMackenzie Delta-Onshore
AKITA EqutakDreco 1250 UE 62 (SCR/TD) Barges at staging site EnCanaDreco 1250 UE 63 (SCR/TD) Barges at staging site Chevron CanadaNational 370 64 Stacked, Inuvik, NT EnCana
Central Mackenzie ValleyAKITA/SAHTUOilwell 500 51 Stacked, Fort Good Hope, NT Apache Canada
Nabors Canada62 Racked Available
Yukon Territories Rig StatusYukon
AKITA/KaskaNational 80UE 58 Kotaneelee, drilling L-38 Devon Canada
Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of November 4, 2004.
Active drilling companies only listed.
TD = rigs equipped with top drive units WO = workover operations CT = coiled tubing operation SCR = electric rig
This rig report was prepared by Wadeen Hepworth
Baker Hughes North America rotary rig counts*
October 29 October 22 Year AgoUS 1,251 1,250 1,107Canada 372 356 375Gulf 88 90 101
Highest/LowestUS/Highest 4530 December 1981US/Lowest 488 April 1999Canada/Highest 558 January 2000Canada/Lowest 29 April 1992
*Issued by Baker Hughes since 1944
The Alaska - Mackenzie Rig Report is sponsored by:
Rig start-ups expected in next 6 monthsRig Owner/No. Rig Location/Activity Operator
Akita Equtak62 Umiak No. 5 camp and construction
equipment are on barges at staging siteat Mason Bay. EnCana
Akita Equtak63 West Ellice rig camp and construction
equipment are on barges at staging siteat Ellice Island. Chevron Canada
Akita/Sahtu Drilling51 Will be drilling in the Colville Lake area Apache Canada
Akita/Sahtu Drilling40 Will be drilling in the Summit Creek
area, west of Tulita NT. Northrock Resources
Doyon Drilling15 Will start drilling in January 2005 ConocoPhillips
Drill bits
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PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004 3ON DEADLINE
EXPLORATION & PRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9FAR EAST REPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15FINANCE & ECONOMY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7GOVERNMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14MINING NEWS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15NATURAL GAS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7,13
North America’s source for oil and gas news
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FAIRBANKS, ALASKAWhitaker considers annexing moreacreage under trans-Alaska oil pipeline
Fairbanks North Star Borough Mayor Jim Whitaker said his administration is con-sidering annexing land from the Yukon River in the north to the banks of theGoodpaster River to the south.
The annexation could bring more of the trans-Alaska oilpipeline and the multi-million-dollar Pogo gold mine ontoFairbanks North Star Borough tax rolls, bringing in roughly $8
million, Whitaker said. “We’re reviewing it
from two perspectives,”economic and political,Whitaker told theFairbanks Daily News-Miner in earlyNovember.
He’ll know by the end of the year whetherhe will move the idea to the borough assembly.
If the assembly approves, the matter would have to be approved by the local boundarycommission, and would then go before borough voters and people who live in the areasconsidered for annexation. Hank Bartos, the assembly’s presiding officer, said theassembly would look at how much annexation will cost, how much revenue it willbring and whether the borough can provide enough services to the areas.
Bartos said annexation could pit the state against the borough over the state’s shareof pipeline revenue. The state is allowed to collect up to 20 mills of taxes on the partsof the 800-mile-long pipeline that don’t fall under a local government, he said.
Curtis Thomas, a spokesman for Alyeska Pipeline Service Co., said the issue wouldfall to the pipeline’s owners
—THE ASSOCIATED PRESS
JIM WHITAKER
The annexation could bringmore of the trans-Alaska oil
pipeline and the multi-million-dollar Pogo gold mine onto
Fairbanks North Star Boroughtax rolls, bringing in roughly$8 million, Whitaker said.
4 PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004ON DEADLINE
QUEBECQuebec LNG plan in trouble
The anti-LNG sentiment shows signs of spilling over the border from the UnitedStates into Quebec.
The tiny village of Beaumont on the St. Lawrence River may have unraveled plansby Enbridge, Quebec gas distributor Gaz Metropolitain and Gaz de France for theC$700 million Rabaska project.
Enbridge Chief Executive Officer Patrick Daniel conceded Oct. 26 that the plug willbe pulled before Christmas if a referendum in Beaumont opposes the development.
The city council of Levis to the west of Beaumont has already voted against plansthat would see tankers off-load LNG every six days.
Daniel said the partners failed to make early contact to educate and build confidenceamong the residents. Because of the “misconceptions” about LNG, “we should havestarted months earlier” to develop what he described as a favorable bedside manner.
But defeat for Rabaska won’t scuttle the partnership’s ambitions to build a facilityto handle 500 million cubic feet per day.
Daniel said several other sites are under consideration and will be approached dif-ferently to prevent fear taking hold among the affected residents.
If Rabaska is derailed there won’t be any sorrow in TransCanada, Enbridge’s chiefenergy pipeline competitor in Canada. Along with Petro-Canada, TransCanada is push-ing ahead with a proposed C$660 million receiving terminal near the village of GrosCacouna, about 120 miles northeast of Quebec City.
TransCanada Chief Executive Officer Hal Kvisle said “we’re optimistic we can get(Gros Cacouna) to the finish line to meet the growing hunger for gas in the northeast-ern United States. Dismissing any talk of a rivalry, he said the markets could absorb gasfrom both the TransCanada and Enbridge ventures.
—GARY PARK
Company symbol earnings % liquids % gas %
BP BP $3,937 +43 2,479,000 +21 8,275 -1
EnCana ECA $559 +104 259,408 +19 3,128 +24
ExxonMobil XOM $5680 +56 2,506,000 +1 8,428 +1
Can. Natural CNQ.TO C$311 +55 297,000 +20 1,396 +8
ConocoPhillips COP $2,006 +54 953,000 -4 3,183 -6
ChevronTexaco CVX $3,201 +62 1,678,000 -5 3,727 -9
Devon DVN $517 +26 276,400 +5 2,414 -5
Burlington BR $389 +46 151,600 +37 1,906 +1
Husky HSE.TO C$286 +15 208,100 +3 700 +20
Petro-Canada PCZ C$410 +42 292,000 -5 863 +3
Kerr-McGee KMG $7 -76 166,400 +18 1,051 +50
Nexen NXY.TO C$220 +22 196,800 -11 285 -5
Talisman TLM C$122 -5 218,441 +8 1,263 +19
Apache APA $432 +57 252,800 +6 1,234 -2
Suncor SU.TO C$337 +16 237,500 +3 201 +4
Williams WMB $99 -7 582(2) +18
Pogo PPP $87 +28 50,948 -22 339 +19
XTO XTO $141 +37 33,054 +62 857 +19
Forest FST $32 +21 30,000 +30 326 +25
Dominion D $337 +32 31,708 +32 1,003 -9
Occidental OXY $758 +70 431,000 +3 649 +7
Newfield NFX $82 +65 20,750 +30 530 +3
Unocal UCL $330 +117 155,000 -2 1,511 -11
EOG EOG $170 +48 27,700 +22 1,045 +10
Imperial IMO C$539 +44 257,000 -5 581 +12
Pioneer PXD $81 -58 67,383 +20 676 +5
Marathon MRO $222 -21 156,600 -20 901 -15
Merit Private company does not report results
Chesapeake CHK $97 +10 19,935 +51 905 +31
Penn West PWT.TO C$77 -0- 52,966 +15 316 -7
Spinnaker SKE $9 +88 4,000 +4 98 -4
BHP Billiton BHP Does not report quarterly figures
El Paso (1) EP -$206 (-) 30,756 -26 782 -31
Anadarko APC $399 +46 232,000 -2 1,813 -1
RD/Shell RD $5,397 +120 2,279,000 –5 7,706 +4
Earnings from Top 35 North American E&P Capex SpendersEarnings third quarter 2004 • Change from third quarter 2003
Liquids production third quarter 2004 • Change from third quarter 2003Natural gas production third quarter 2004 • Change from third quarter 2003
OIL COMPANY EARNINGS
Liquids production in barrels per day. Natural gas production in millions of cubic feet per day.NOTE: Top 35 is based on Petroleum News research
(1) El Paso figures for first quarter 2004, comparisons with 1Q 2003(2) Millions of cubic feet of gas equivalent daily
OKLAHOMA CITYMulti-state commission recognizes BP,Fidelity for environmental stewardship
In late October at its annual meeting in Oklahoma City, the Interstate Oil and GasCompact Commission recognized “the best of the best” among companies and organ-izations for environmental stewardship. The awards fall into four categories; majorcompany, independent company, environmental education, and environmental partner-ship.
BP America Production, Fidelity Exploration and Production, the NEED Projectand the San Juan County Cleanup and Prevention of Illegal Dumping Committee werethose selected to receive an award, which IOGCC said recognizes those “making vol-untarily strides to protect our environment and make a difference.”
BP received the award for majors, receiving credit for developing “a process thatconverts drill mud and cuttings, a regulated waste, into a non-regulated beneficial reuseproduct. The product is a low cost substitute for construction aggregate. The advan-tages include; reduced consumption of natural resources, stronger construction materi-als, reductions in land use for disposal, reduced potential for groundwater contamina-tion, reduction of waste generated, lower construction cost and reduced disposal cost.”
Fidelity, recipient of the independent’s award, sponsored a soil and crop testing pro-gram that IOGCC said “helps irrigators, relying on water from Montana’s TongueRiver, to better understand the potential effects of coalbed natural gas development totheir irrigated crops.”
The Energy Education award, presented to the NEED Project, recognizes a groupor organization that has created a program to educate the public about petroleum.
“Since its inception in 1980, the NEED Project has become the nation’s authorita-tive source for comprehensive energy education materials and teacher training pro-grams. More than 6,000 schools in 35 states use the NEED program in their class-rooms,” IOGCC said.
The San Juan County CUPID Committee received the environmental partnershipaward for its efforts over the past two years in mapping dumpsites, identifying recy-cling opportunities and organizing large numbers of people and equipment to clean upthe public lands.
“The committee has gathered more than 1,000 people comprised of 140 companiesand organizations with more than 100 pieces of heavy equipment to clean up more than1,500 cubic yards of refuse from public lands, recycled 2,700 tires and removed 200appliances and 64 vehicles from the public lands,” IOGCC said.
Established in 1935, IOGCC represents governors of 30 member and seven associ-ate states. The commission’s goal is to promote “the conservation and efficient recov-ery of domestic oil and natural gas resources while protecting health, safety and theenvironment.”
PONCA CITY, OKLA.ConocoPhillips to close demonstration plant
ConocoPhillips will shut down its demonstration plant in Ponca City, Okla., elimi-nating up to 120 jobs, the Houston-based company said.
“It never is easy to make this kind of announcement,” said George Paczkowski,ConocoPhillips’ vice president of downstream technology in Ponca City, “but we’veknown this demonstration plant was temporary since we built it.”
The plant was built to test technology designed to convert natural gas into liquidfuels. Paczkowski called the experiment a strong success and said Ponca City likelywill be home to research and development projects in the future.
The plant is to close in early July 2005, he said Oct. 29, and the move will eliminateabout 80 full-time positions and up to 40 contract jobs.
Many of the full-time workers will be reassigned to other positions at the company,Paczkowski said.
Employment at the Ponca City plant has dropped from about 2,100 to about 1,600since Conoco Inc. and Phillips Petroleum Co. merged in August 2002.
—THE ASSOCIATED PRESS
By KAY CASHMANPetroleum News Publisher & Managing Editor
assandra Energy has decided to cutback its Katalla drilling programfrom two or three wells to one well,company President Bill Stevens
told Petroleum News Oct. 28.Stevens is in the process of amending
his operating plan to reflect the downsiz-ing of the project which will be on privateland near the former town of Katalla, thesite of Alaska’s first commercial oil pro-duction in 1902. The field, 56 milessoutheast of Cordova, was shut in follow-ing a refinery fire in 1933.
Cassandra, which is owned by a groupof private investors, is looking for part-ners or investors for the Katalla projectand is hoping to mobilize equipment inthe spring or fall of 2005.
Cassandra’s story began in July 2000when the Alaska-based entered into alease-option for oil and gas rights on10,134 acres from Chugach Alaska, anAlaska Native regional corporation. Thesurface rights were controlled by theChugach National Forest.
A Sept. 17, 1982, settlement agree-ment between the U.S. Department of theInterior and Chugach Natives Inc. (prede-cessor to Chugach Alaska) gave theNative corporation exclusive rights todrill for, mine, extract, remove and dis-pose of all oil and gas deposits in a liquidor gaseous state from the date of signinguntil midnight Dec. 31, 2004, “and solong thereafter as oil and gas are pro-duced in paying quantities,” U.S. ForestService officials said.
If a well capable of producing in pay-ing quantities within the 10,134 acreKatalla area was not completed duringthat time period, all rights, title and inter-est of CNI would revert back to theUnited States.
Native corporation opts out But Chugach Alaska canceled the
agreement with Cassandra in August.Rick Rogers, Chugach Alaska’s vice
president for land and resources, toldPetroleum News Oct. 28, “Cassandra’sbeen unable to find capital for the project.The terms of our conveyance from the
federal government are very clear. Wedon’t have any oil and gas rights unlesswe can prove there are commercial quan-tities of oil and gas by Dec. 31, 2004, andwe didn’t see it happening by that date.”
But the 465-acre Katalla oil field, ofmost interest to Stevens, was still inCassandra’s hands per a 2001 lease-pur-chase agreement with the Welch family ofCordova.
And Stevens, safety and health pro-gram coordinator for Inlet Drilling Alaskain Kenai, Alaska, doesn’t give up easily,as evidenced by the 30 months it took himto get federal approval for the Katallaproject which is surrounded on threesides by the Chugach National Forest.Cassandra was the first company to per-mit a well in the area in more than 16years.
In a 2003 interview, Rogers said theKatalla project had gone through anextensive review process, including “anACMP review, two environmental assess-ments by the Forest Service. It was a veryexhaustive public process.”
Stevens said Cassandra lost the inter-est of several potential investors duringthe drawn out permitting period, but assoon as his new plan of operations isamended, he’ll be ready to go – and withonly one test well, he’ll need lessmoney. ●
Editor’s note: This story appears inThe Explorers 2004, an annual magazinepublished by Petroleum News that wascalled The Independents in 2002 and2003. The Explorers will be released atthe annual Resource DevelopmentCouncil for Alaska conference, held inAnchorage Nov. 18 and 19.
PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004 5ON DEADLINE
● S O U T H C E N T R A L A L A S K A
Cassandra Energyseeks investors for Katalla wellAlaska-based independent has permits to drill test well atstate’s first oil field 56 miles southeast of Cordova
C
TEXASMagnum Hunter closes $40M acquisitionof properties in Texas’ Permian basin
Exploration and production independent Magnum Hunter Resources said Nov. 2that it has completed the previously announced $40 million acquisition of oil and gasproperties in the Permian basin of West Texas from an undisclosed privately held com-pany. Magnum Hunter said it financed the acquisition through borrowings under itsrecently increased $525 million senior bank credit facility.
The company estimated that the properties acquired represent about 51 billioncubic feet of gas equivalent proved reserves, consisting of 59 percent natural gas. Theproperties include 100 proved undeveloped locations in the Canyon, Clearfork,Spraberry and Wolfcamp formations.
Magnum Hunter acquired 170 producing wells that are 100 percent operated andcurrently produce about 3.4 million cubic feet of gas equivalent per day.
—RAY TYSON
Anadarko sells Colorado propertiesAnadarko Petroleum has agreed to sell its southeast Colorado producing properties
to an affiliate of Citation Oil & Gas Corp. for $107.6 million, Anadarko said Nov. 1.The Houston-based independent, as part of a property divestiture program announcedin June, now has agreements in place to sell about $2.5 billion of non-core assets andhas additional agreements pending on about $800 million of assets.
Together, the divestitures represent year-end 2003 proved reserves of about 285 mil-lion barrels of oil equivalent and production of about 120,000 barrels of equivalent perday. Anadarko has said it intends to use sale proceeds to pay down debt and to buy backshares of the company. Anadarko’s latest sale includes an estimated 9 million barrelsof oil equivalent in proved reserves and net production of about 3,000 barrels of equiv-alent per day. About 80 percent of the properties are operated, with roughly 90 percentof the proved reserves classified as oil and nearly 100 percent developed.
The transaction is expected to close by year-end 2004.—RAY TYSON
By ALLEN BAKERPetroleum News Contributing Writer
empra Energy’s proposed MexicanLNG terminal now has all its permitsin hand and the company is planning tostart major construction in the next
couple of months, giving it a jump on otherprojects seeking to serve the California mar-ket.
“We have all our permits in hand,” saidArt Larson, a spokesman for San Diego-based Sempra. “We’re going forward. Wehave already started building the access roadto the project, and major construction beginslate this year or early next year.”
The terminal and associated pipelines areexpected to cost about a billion dollars, withfacilities to regasify a billion cubic feet ofgas daily when the project is finished in2008, he said. Half of that would initially goto the Mexican market. If future demand
warrants more capacity, “we do have roomto increase the size of the facility based onthe land we have.”
The facility, called Energia Costa Azul, is14 miles north of Ensenada and about 40miles south of the U.S. border. It will con-nect with a 140-mile east-west pipelineowned by Sempra International, which willprovide access to markets in Mexico andArizona.
Woodside moves inMeanwhile, a rival terminal project just
north of Los Angeles got a boost whenAustralia’s big Woodside Petroleum Ltd.joined forces with Crystal Energy LLC onits Clearwater Port project.
The plan there is for an old offshore oilplatform to be turned into a docking facilityfor LNG tankers and a regasification centerat a cost of about $350 million. Despite theport’s location 12.6 miles off the coast, the
plan has drawn sharp opposition from thecommunity of Malibu, which sits on thecoast nearby.
Woodside adds a lot of muscle to theproject. It is Australia’s second-biggest oilcompany, and has an extensive track recordin the LNG arena, operating Australia’shuge North West Shelf LNG venture thathas sent out more than 1,600 tanker loads.
Under the deal with Crystal Energy,formed specifically to develop the facility,Perth-based Woodside will help design theterminal and has agreed in principal to be theoperator. It also gets 80 percent of the termi-nal capacity.
“Woodside has substantial gas reservesand world-wide experience in LNG produc-tion and transportation while Crystal pro-vides an ideal potential entry point to theworld’s largest gas market,” said DonVoelte, Woodside’s chief executive officer.
Crystal has applied to the U.S. Coast
Guard for a deepwater port license thatwould allow conversion of the Grace oil andgas platform into an unloading and regasifi-cation facility.
There will be no LNG storage at the plat-form, which sits in 97 feet of water. The ter-minal will be able to handle about 800 mil-lion cubic feet daily, converting roughly 6million tonnes of LNG annually. The gaswould be gas piped along existing ease-ments to onshore infrastructure.
Crystal filed permit applications inFebruary and has signed a long-term leasefor the platform. A 54 percent majority ofCrystal’s shares are owned by SmallVentures USA LLC, which in turn is ownedby William O. Perkins III, who is Crystal’schairman. The agreement is with Woodside(USA) Energy Inc., a wholly owned sub-sidiary of the Australian firm.
Second Aussie entryWoodside isn’t the only Australian com-
pany with an interest in an offshore LNGterminal in southern California. BHPBilliton is proposing another offshore proj-ect a bit farther north, with a cost of $600million and a capacity of 1.5 billion cubicfeet daily. There are other projects on thedrawing board — involvingChevronTexaco, ConocoPhillips, andMarathon — to serve the huge market.
It’s unlikely all of them will end up beingbuilt, but there is currently no terminal forimporting LNG on the western coast ofNorth America. And there are big LNG pro-duction centers ramping up in Asia, includ-ing projects at Sakhalin Island and aroundAustralia and Indonesia.
But the West Coast market would have togrow substantially to support more than acouple of the costly terminals. The Semprafacility alone could supply roughly 15 per-cent of California’s total current consump-tion of about 6.5 billion cubic feet daily.
Sempra recently signed supply agree-ments for LNG from the Sakhalin projectled by Shell and from Indonesia’s Tangguhproject, led by BP. The two 20-year con-tracts involve more than 110 million tons ofLNG valued at around $18 billion.
Shell controls half of the initial capacityof 7.5 million tons of LNG annually at theSempra terminal, and holds an option onhalf of any capacity additions there.
ExxonMobil drops MobileExxonMobil has shelved its plans for a
$600 million terminal on Mobile Bay inAlabama, deciding Oct. 28 not to keep itsoption on a former Navy base that wouldhave been the terminal site. The companyplanned a capacity of as much as 3 billioncubic feet daily, with the LNG coming fromQatar.
The Irving, Texas, company said it hadmade progress on several other LNG termi-nal sites and it was no longer inExxonMobil’s interest to maintain theMobile site by making a $1.2 million optionpayment due by Nov. 1. The company orig-inally bought the option on the site from theAlabama State Port Authority in October of2003, and had already made $1.75 million inoption payments.
But like many other LNG proposals, itran into heavy local opposition from resi-dents concerned about accidents or terroristattacks. Among those questioning the termi-nal on safety concerns was Alabama Gov.Bob Riley.
Mitsui and Co. Ltd. has signed up to
6 PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004NATURAL GAS● W E S T C O A S T U . S .
LNG projects gain; Exxon drops Mobile plansWestern U.S. projects moving: Sempra gets go-ahead for Mexican terminal, while Woodside joins in offshore project
S
see LNG page 16
PETROLEUM NEWS 7WEEK OF NOVEMBER 7, 2004
finance&economywww.PetroleumNews.com
ALBERTAImperial pumps C$10 millioninto Alberta oil sands research
Imperial Oil has cast a vote on the future of Alberta’s oil sands bykicking in C$10 million over the next five years to establish a newresearch facility at the University of Alberta.
One of the largest oil sands and heavy oil operators in northeast-ern Alberta, Imperial said the sector can play a major role in meetingenergy needs, but faces economic and environmental challenges thatwill be “costly and energy intensive.”
It said the center for oil sands innovation will seek ways to devel-op “new energy-efficient and environmentally responsible technolo-gies for the integrated production and upgrading of Alberta’s oilsands resources, to provide clean-energy and value-added products.”
The center, attached to the engineering faculty, will hire five newprofessors and generate work for more than 100 researchers, saidfaculty dean David Lynch.
Alberta’s Innovation and Science Minister Victor Doerksen saidhe is counting on the center to build on new technologies to developthe oil sands and clean energy research and thus sustain the oil sandsand heavy oil industry.
Imperial Chief Executive Officer Tim Hearn told the EdmontonJournal he hopes the research facility will make the oil sands andheavy oil resources economic even when oil prices fall.
He said Imperial believes the oil sands should be able to surviveoil prices of US$20 per barrel, suggesting that prices above US$30“test the reality and veracity of the market fundamentals.”
—GARY PARK
● O K L A H O M A C I T Y
Chesapeake Energy dumpsconservative forecastUps production forecast, reserve estimates through 2006, largely becauseof gains made through drilling rather than initial property acquisitions
By RAY TYSON Petroleum News Houston Correspondent
apidly growing independentChesapeake Energy, abandoning itsconservative growth forecasts, hasincreased both production and
reserve estimates through 2006, largelybecause of “organic growth” or gains madethrough drilling rather than initial propertyacquisitions.
The Oklahoma-based company, whichover the past five years invested $4.5 bil-lion in acquisitions and $2.6 billion indrilling, posted an enviable 33 percentincrease in total 2004 third-quarter produc-tion versus the same quarter last year.
Sixty percent of the production growth in the thirdquarter was attributed to acquisitions and 40 percent
to the drill bit, a ratio that simply does notstand up to the company’s previous fore-casts of just 5 percent annual organicgrowth.
In fact, Chesapeake said it has deliveredan average 11 percent increase in drill bitproduction annually over the past threeyears and expects no less than a 13 percentincrease for full-year 2004 over 2003.
“We are now officially abandoning ourlong-term organic production of 5 percent,”Aubrey McClendon, Chesapeake’s chiefexecutive officer, said in a Nov. 2 confer-ence call with industry analysts.
He said that in addition to the 13 percentannual organic production increase expect-
ed in 2004, the company has increased anticipated
MEXICO CITYDirector of Mexico’s state-runoil company resigns
The director of Mexico’s state-run oil company resigned Nov.1 and was replaced by the head of the company’s explorationand production unit, the Energy Department said.
Raul Munoz Leos stepped down as director of PetroleosMexicanos, or Pemex, after four years of trying to open the com-pany to more private investment, a controversial campaign thatdrew widespread criticism as a first step toward privatization.
A statement sent out by the Energy Department didn’t speci-fy why Munoz Leos stepped down, saying only the change wasdue to the “actual and perceived future circumstances of thecompany, and to renew the strength and drive needed for thecompany’s leadership in its final administrative phase.”
Pemex executives were not immediately available to com-ment.
The statement said Luis Ramirez, who has been head ofPemex’s exploration and production unit since 2001, will imme-diately take over as director.
It said Ramirez has “a strong knowledge of the company’s
R
● L O N D O N
Royal Dutch/Shell unveilssurprise merger, rise in 3QTwo parent groups, Shell Transport & Trading and Royal Dutch Petroleum,will be merged, run by one board to eliminate likelihood of reserve errors
By JANE WARDELLAssociated Press Writer
he Royal Dutch/Shell Group of Cos. unveiledplans Oct. 28 to merge its two holding compa-nies after nearly a century apart, a response to ascandal over its downgrading of oil reserves.
The company also said it could further reduce itsproven oil reserves as it posted third-quarter earningsdouble those of a year earlier.
Shell said that scrapping its twin-board structurewas the best way to eliminate accounting failures thatled it to admit in January that it had vastly overesti-mated reserves, its most precious asset. Since then ithas reduced the total of its reserves by 23 percent, or
4.47 billion barrels, and said Oct. 28 it may have tocut estimates by 900 million more.
The proposal to merge Shell Transport & TradingCo Ltd., which holds 40 percent of RoyalDutch/Shell, and Royal Dutch Petroleum Co., whichholds 60 percent, was largely welcomed by the mar-ket.
Shell shares soared on the London StockExchange, hitting a 2004 high of US$8.26 beforeclosing at US$7.97. Royal Dutch shares were up 1.37percent on the Euronext exchange to $54.61.
Investec analyst Bruce Evers said the shake-upwould go “a long way to meet the demands of
“We are now offi-cially abandoningour long-termorganic productionof 5 percent.” —Aubrey McClendon,Chesapeake EnergyCEO
see CHESAPEAKE page 8
T
see DIRECTOR page 8see MERGER page 8
8 PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004FINANCE & ECONOMY
operations, plans and projects.” Reforma newspaper reported Nov. 1
that Munoz Leos, former president andgeneral manager of Dupont Mexico,was angry that President Vicente Fox’sCabinet members had not fully sup-ported him. The newspaper also report-ed in October that Munoz Leos bor-rowed company money to pay for hiswife’s plastic surgery.
Munoz Leos has held his post forfour years, and was appointed whenFox took office in 2000.
His resignation was the latest in aseries of Cabinet shakeups within Fox’sfour-year administration.
Former Energy Secretary FelipeCalderon resigned in May after Foxcriticized him for an early jump into the2006 presidential races. Calderon, a
prominent figure in Fox’s NationalAction Party, said Fox’s complaintswere “unjust and out of proportion.”
It wasn’t entirely clear why MunozLeos stepped down, although he hasoften been criticized for efforts he saidwere aimed at modernizing Mexico’soil monopoly, including streamliningstaffing levels and trying to allow moreprivate investment.
Pemex also has been criticized forthe nearly $700 million contract itsigned earlier this year with the oilworkers union. The contract includes avariety of housing and other benefits.
—THE ASSOCIATED PRESS
annual organic growth rates in 2005 by atleast 10 percent and in 2006 by at least 8 per-cent, for a three year average of 10 percentorganic growth per year.
Gas production estimates of 350 bcf in 2004
The gas-weighted company also hasincreased its overall production estimates to350 billion cubic feet of natural gas equiva-lent in 2004, to 407 billion cubic feet in2005, and to 438 billion cubic feet in 2006.Over the past 13 quarters, Chesapeake’s pro-duction has increased 141 percent,McClendon noted.
“There will be very few companies thatcan deliver this level of production growthto investors for the next few years,” heasserted.
If Chesapeake manages to accomplish itsproduction goals, the company would haveroughly quadrupled in size over six years,certainly ranking it at or near the top of thefastest growing exploration and productionindependents in the United States.
Chesapeake already is the fifth largestindependent producer of natural gas in theUnited States, owning working and royaltyinterests in more than 18,000 onshore pro-ducing oil and gas wells that should producean average of nearly 1 bcf of gas equivalentper day during 2004.
Chesapeake also said its year-end proved
reserves would reach 4.6 trillion cubic feetof gas equivalent in 2004, 5 tcf in 2005 and5.4 tcf in 2006. The company said it has anadditional 4 tcf of probable and possiblereserves that should increase “in tandem”with its proved reserves.
“Given the stability of our producingproperty base and the predictable nature ofour drilling results, we now feel more com-fortable than ever in estimating our year-endproved reserves,” McClendon said.
Majority of reserves in U.S. Midcontinent
About 74 percent of Chesapeake’sproved reserves are in the U.S.Midcontinent, including Oklahoma, westernArkansas, southwestern Kansas and the
Texas Panhandle. During the fourth quarterof 2003 and the first half of 2004, the com-pany significantly expanded its activities inthe Permian Basin of West Texas and easternNew Mexico, the South Texas and TexasGulf Coast regions, and the Ark-La-Texbasin of eastern Texas and northernLouisiana.
On increased production and robust com-modity prices, Chesapeake’s 2004 third-quarter revenues soared to nearly $630 mil-lion from $454.5 million for the year-agoquarter. Net income increased to $85.6 mil-lion from $81.9 million.
At the end of the 2004 third quarter,Chesapeake’s long-term debt was $2.76 bil-lion, representing a hefty debt-to-total capi-talization ratio of 49 percent. ●
investors” angered by the reserves crisis,which led to three senior executives beingousted and almost US$150 million in finesimposed by U.S. and British regulators.
Royal Dutch Shell PLCwill be new company
Under the Oct. 28 proposal, the two par-ent groups, which have been managed as aunit since 1907, will merge and form thesupervisory board of the new company, tobe named Royal Dutch Shell PLC. The con-solidation is expected to take place in thesecond quarter of 2005, with the new com-pany to be nominally based in London buthave its physical headquarters and tax homein The Hague, Netherlands.
“Our proposals will not satisfy everyonein every respect but we firmly believe thatwe have come up with the best solution pos-sible,” said Chairman Aad Jacobs.
If the deal is approved by stockholders,they will receive shares in the new compa-ny on a one-for-one basis. Dividend pay-ments will be shifted to a quarterly basisfrom their current semiannual frequency.
The current chairman of the RoyalDutch/Shell Group’s board of managers,Jeroen van der Veer, will continue as thenew company’s chief executive.
“This is the end of 60:40, we becomeone company with one share,” Van der Veersaid. “There is one set of directors, onechief executive, one person who has to takefull accountability.”
Van der Veer said the company’s reviewof reserves is still not complete, and it mayhave to downgrade estimates by another900 million barrels. He said the effort toreach a final number on the reserves adjust-ment was “not a very simple exercise, ascame out today again. But we are deter-mined to get this reserves issue behind us.”
Shell said that definitive figures on thepossible shortfall would be provided withannual financial results in early 2005. ●
continued from page 7
CHESAPEAKE
continued from page 7
MERGER continued from page 7
DIRECTORHis resignation was the latest in
a series of Cabinet shakeupswithin Fox’s four-year
administration.
PETROLEUM NEWS 9WEEK OF NOVEMBER 7, 2004
exploration&productionwww.PetroleumNews.com
NORTH AMERICACanada, U.S. rig counts climbby 17 to 1,623 in weekly survey
The number of rotary drilling rigs operating in Canada and theUnited States during the week ending Oct. 29 stood at a combined1,623, up 17 rigs compared to the previous week and up 140 rigs ver-sus the same weekly peri-od last year, according torig monitor BakerHughes.
Canada accounted formost of the increase inNorth America during therecent week, rising by 16to 372 rigs compared tothe prior week. However,Canada’s rig count was down by four rigs compared to the same peri-od last year. The U.S. rig count increased by one to 1,251 from theprevious week, while increasing by 144 compared to the same periodlast year. Compared to the previous week alone, the number of inlandrigs increased by one to 1,136, while inland water rigs increased bytwo to 22. Offshore rigs decreased by two to 93.
Of the total number of rigs operating in the United States, 1,071were drilling for natural gas and 179 for oil, while one was being usedfor miscellaneous purposes. Of the total, 787 were vertical wells, 331directional wells and 133 horizontal wells.
Among the leading producing states, Oklahoma gained 10 rigsfrom the prior week for a total of 160 rigs. California picked up onerig for a total of 26 rigs. However, Texas lost five rigs for a total of529 rigs. Louisiana’s rig count fell by two to 175, while NewMexico’s dipped by two to 63 and Wyoming’s slipped by two to 80.Alaska lost one rig for a total of 10.
—RAY TYSON
CANADAEnCana powers Canadiandrilling activities
EnCana, the big Canadian independent, gave conclusiveproof of just how big it is in the first three-quarters of 2004.
The 25 most active drillers accounted for 12,092 well com-pletions; EnCana claimed 3,793 — 31 precent — of that num-ber.
The nearest thing to a race came from the next four, withHusky Energy posting 1,239 wells, Apache Canada 998, EOGResources 943 and Canadian Natural Resources 873.
On the exploration front, EnCana tallied 2.29 million feet,followed by Burlington Resources Canada at 1.08 million feetand Husky at 896,000 feet.
Leading the way in discoveries, Husky claimed 82 oil finds,while EnCana has 394 gas discoveries.
—GARY PARK
● G U L F O F M E X I C O
Marco Polo falls shortof production goalAnadarko says it may have to drill more wells or reduce booked reservesat deepwater GOM field; facilities designed as hub for future satellite finds
By RAY TYSON Petroleum News Houston Correspondent
nadarko Petroleum is facing a possible writedown of booked oil reserves at its Gulf ofMexico Marco Polo field, which the compa-ny said is not performing according to expec-
tations. Marco Polo, which came on stream in July with
an initial three wells, is the big independent’s firstdeepwater discovery in the U.S. Gulf. Offshorefacilities were designed to serve as a hub to accom-modate future production from satellite discover-ies, which now include K2, K2 North and possiblyGenghis Khan.
The field, with all six production wells on lineby the end of October, reached peak production of
A
● B R I T I S H C O L U M B I A / A L A S K A
Talisman identifies bigprospects on North SlopeIndependent is stepping up its activities in northern Alberta and B.C.
By GARY PARK Petroleum News Calgary Correspondent
ith 560,000 acres of North Slopeexploration rights in the bank,Talisman Energy is quietly bring-ing Alaska onto its radar screen,
along with its core Monkman area innortheastern British Columbia.
Talisman executive vice president,exploration, John ’t Hart, told a confer-ence call Nov. 2 that the Canadian inde-pendent has identified a “couple of verybig prospects” in its 560,000 acres that are
both onshore and offshore the NationalPetroleum Reserve-Alaska.
But he said drilling by Talisman’s U.S.subsidiary, Fortuna Exploration, is unlike-ly before the 2005-2006 winter drillingseason because of the time needed to gath-er seismic data. ’t Hart also said drillingwill be done with “other companies.”(Talisman’s partnership with Total wentaway when Total assigned the Caribouleases to Fortuna in October, as per reportin the Oct. 31 issue of Petroleum News.)
Chief Executive Officer Jim Buckee
see MARCO POLO page 10
JIM BUCKEE
W
see TALISMAN page 10
The Marco Polo platform
CO
URT
ESY
O
F A
NA
DA
RKO
Of the total number of rigsoperating in the United States,1,071 were drilling for naturalgas and 179 for oil, while one
was being used formiscellaneous purposes.
42,000 barrels of oil equivalent produc-tion per day, below the forecasted peak ofaround 50,000 barrels per day.
“Production pressures from the wells arenot holding up as expected,” Jim Hackett,Anadarko’s chief executive officer, said inan Oct. 29 conference call with industryanalysts.
If the wells do not stabilize, he added, itlikely means the Marco Polo field is more“compartmentalized” than seismic imagingand pressure tests initially indicated.
“Continued monitoring will tell uswhether we need to drill more wells to getbooked reserves, or it could require revisionof reserves that webooked on the bestdata available back in2002,” Hackett said.
The 100 percentAnadarko ownedMarco Polo field,located in more than4,000 feet of water,was discovered inApril 2000 and islocated on GreenCanyon Block 608about 160 milessouth of NewOrleans, La.
In its conference call, the companydeclined to discuss reserve estimates forMarco Polo, saying only that initial volumeestimates were reviewed by an independentreservoir consultant based on seismic stud-ies and the drilling of several wells to con-firm the structure.
“So we know the oil is there (and) weknow the sands are where we said theywould be. Then (we) used those volumetricsto estimate how much oil is in place,” saidMark Pease, Anadarko’s senior vice presi-dent of exploration and development.
He said the company then used the pro-duction histories of “typical” Gulf ofMexico fields in the region to determinehow much of the in-place oil at Marco Polocould be recovered.
SEC generally requires flow test to surface
However, none of the Marco Polo wellsactually was flow tested to the surface and“that was the subject of a lot of discussion”with the U.S. Securities and Exchange
Commission, Hackett conceded. “We weretrying to go through the definition of whatyou need offshore.”
Although Hackett did not elaborate onthe company’s talks with the SEC, agencyrules generally require a flow test to the sur-face to help establish a field’s recoverablereserves. However, because of the time andexpense, explorers rarely conduct flow testson deepwater discoveries and often use adown hole tool called a Modular DynamicTester, or MDT, to help measure well pres-sure.
“The type of pressure support andresponse that we’re looking for you wouldnot have seen in a short-term flow test,”Pease said. “You would not have seen thatfor three to four months.”
He said it would take another two tothree months of production history onrecently completed wells before the compa-ny could determine the exact cause of thepressure drop at Marco Polo.
“We’re going to learn a tremendousamount more about how those things per-form over the next few months,” Pease said.
Anadarko believes K2, K2 North largerthan Marco Polo
However, he said that even when consid-ering the worst case scenario at Marco Polo,production from the K2 and K2 North satel-lites would more than offset productionlosses at Marco Polo. They are scheduled tocome on stream in the middle of next year.
“As we continue to do more drilling …we have seen that K2 and K2 North aregoing to be a much bigger field than we everthought Marco Polo was,” Pease said.
Anadarko does not expect pressure prob-lems at K2 and K2 North, in part becausethey are situated farther down on the struc-ture and are not as geologically faulted asMarco Polo. “So we don’t expect thosereservoirs to behave similarly,” Pease said.
In late July, there were five wells down atK2 and K2 North, each capable of produc-ing from 5,000 to 10,000 barrels of oil perday. That means the two fields could pro-vide an average 25,000 to 50,000 barrels perday of production.
Marco Polo’s floating production facili-ty, which is owned by GulfTerra andCalDive and operated by Anadarko, wasbuilt to handle 120,000 barrels of oil a dayand 300 million cubic feet of gas a day. Sothere is plenty of room to handle K2 Northand K2, as well as another potential satel-lite called Genghis Khan, the companysaid.
Deep waters of the Gulf of Mexico rep-resent a significant component ofAnadarko’s growth strategy. In fact,Anadarko said several months ago that itsU.S. Gulf program was expected to be thesingle largest contributor to the company’stargeted 5 percent to 9 percent annualgrowth rate through 2009.
Anadarko is still holding to its overallproduction forecast, despite the apparentsetback at Marco Polo. In addition to K2and K2 North and what Marco Poloalready has contributed to companygrowth, production increases are expect-ed from the company’s enhanced oilrecovery program in Wyoming, as wellas in West Texas and Louisiana’s Vernonplay where “we are doing a lot of gooddrilling,” Pease said. ●
10 PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004EXPLORATION & PRODUCTIONcontinued from page 9
MARCO POLOsaid Talisman plans to acquire furtheracreage in an area he rated as having thelargest remaining undiscovered convention-al oil potential in North America.
Although Talisman is not ready yet toplunge north of the 60th parallel, it is step-ping up its activities in northern Alberta andBritish Columbia, where it is part of the bigleague of deep gas operators.
Monkman well tests 40 mcfThe latest breakthrough was announced
Nov. 1, when Talisman said its b-60-eMonkman well tested at a restricted rate of40 million cubic feet per day and is expect-ed to start producing at that level in January2005, with the potential to surpass 75 mil-lion cubic feet per day.
Buckee said the discovery could repre-sent 200 billion cubic feet of original-gas-in-place. Three or four other structures couldyield a similar result.
Talisman plans four wells next year in thePaleozoic formation, but cautioned that thewells cost up to C$18 million each and takeas long as six months to complete.
Talisman has identified 30 potentialdrilling locations which it believes couldyield targets of 35 billion cubic feet or moreper well. Alandmark discovery in mid-2002at Monkman could unlock a regional playexceeding 1 trillion cubic feet of recoverablereserves, Talisman said at the time.
Paleozoic discovery could beas prolific as Triassic
Buckee said the Paleozoic discoverycould be as prolific as the region’s Triassicplay that has so far produced 2 tcf.
Gas sales from the Paleozoic reservoirare anticipated to reach 50 million cubic feetper day and will be fed into spare capacityon Duke Energy’s British Columbia pipelinenetwork.
Talisman made its Monkman break-through in mid-2002 with a well that testedat up to 37 million cubic feet per day.
It acquired 9,400 acres in a BritishColumbia land sale in October, increasingits portfolio to 331,000 acres.
Talisman is also a major player in theDeep basin area, which straddles theAlberta-British Columbia border and aver-aged third-quarter output for the company of66 million cubic feet per day of gas and2,270 barrels per day of oil and natural gasliquids, up 19 percent from a year earlier.
A study completed last spring by PetrelRobertson Consulting for the BritishColumbia Ministry of Energy and Minesestimated the ultimate tight gas resourcepotential at 111 tcf to 260 tcf in place, butdid not set a figure on how much might berecoverable.
Established Deep basin reserves on theBritish Columbia side were projected at 3tcf, with potential for up to 10 tcf.
In the British Columbia Foothills, theconsultants estimated the tight gas resourceat 95 tcf to 230 tcf. ●
“Production pres-sures from the wellsare not holding upas expected.” —JimHackett, AnadarkoPetroleum CEO
In its conference call, the companydeclined to discuss reserve
estimates for Marco Polo, sayingonly that initial volume estimateswere reviewed by an independent
reservoir consultant based onseismic studies and the drilling of
several wells to confirm thestructure.
continued from page 9
TALISMAN
Company opens Anchorageoffice; moves Ehm to VPAlaska operations; hires Rose
By KAY CASHMANPetroleum News Publisher & Managing Editor
elican Hill Oil and Gas said Nov. 1 thatits first well in the Cook Inlet basin, theIliamna No. 1, was a dry hole, but thecompany is moving forward to drill as
many as four onshore west Cook Inlet gasexploration wells between mid-Novemberand spring 2005.
The San Clemente, Calif. independent,which bought its first leases in Alaska in2001, has opened an Anchorage office andhired its local oil and gas consultant, ArlenEhm, as vice president of its Alaska opera-tions.
Pelican has also hired Jim Rose as oper-ations superintendent for Alaska.
Close twin to Burglin well“We’ve got a sign on Iliamna No. 1,
‘Opened by mistake,’ Ehm told PetroleumNews. Iliamna No. 1 was a vertical hole in
section 31, township9 north, range 14west, SewardMeridian. It was onstate oil and gas leaseADL 0388133,onshore at TradingBay, northwest of theTrading Bay produc-tion facility.
“We’re in theprocess of clearing everything out at thatdrill site at the moment; most of its alreadygone,” he said. “What we’re doing is mobi-lizing enough supplies to run all winter forfour wells.”
Pelican Hill will be spudding N Beluga
No. 1 in the first section north of theConocoPhillips-operated Beluga River gasfield mid-month.
“We’re driving conductor pipe now,”Ehm said.
N Beluga No. 1 is “2,000 feet from theeast line and 1,750 from the south line ofsection 12, township 13 north, range 10west,” he said. “It’s a close twin to theAlaska Energy Development well — theBurglin X33-12 — which is about 250 feetaway.”
“That well,” he said, “was pronounceddry and plugged and abandoned withouttesting in 1977.” Pelican Hill’s well is on aTrading Bay Oil and Gas lease.
“We’re farming in the acreage by drilling
the well,” Ehm said. “Once it has been spud-ded the lease will be assigned to PelicanHill.”
Next drilling at Pretty CreekUnder Pelican Hill’s agreement with
Trading Bay Oil and Gas, if the N BelugaNo. 1 is spud by Dec. 1, Pelican Hill has “aright to farm in all of the Trading Bay Oiland Gas Pretty Creek leases,” Ehm said. “Iam preparing to permit two wells at PrettyCreek.”
The Pretty Creek leases are betweenUnocal’s Pretty Creek and Lewis River units–— all the acreage between those two units.
PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004 11EXPLORATION & PRODUCTION
● A L A S K A
ANS production up 8.6% from SeptemberOctober average is 961,506 barrelsper day, with Prudhoe up 14.8% at449,188 bpd, Alpine hits new high
By KRISTEN NELSONPetroleum News Editor-in-Chief
laska North Slope production averaged 961,506 bar-rels per day in October, the highest ANS productionhas been since May, when it averaged 966,869 bpd.The October average was up 8.6 percent from
September, when planned and unplanned maintenance keptproduction below 900,000 bpd through the middle of themonth, holding the average to 885,142 bpd as numbersclimbed back from 722,559 bpd in August, when there weremaintenance shutdowns and restart problems at PrudhoeBay.
Production at Alpine hit a new high, reflecting work com-pleted this summer on the first phase of facility expansion atthe field.
North Slope production peaked in 1988 at 2.028 millionbarrels per day and 2002 was the last year in which produc-tion averaged more than 1 million barrels a year, hitting1.002 million. Only in March and January of this year hasproduction topped 1 million barrels: 1,006,790 bpd in Marchand 1,001,832 bpd in January.
BP Exploration (Alaska)-operated Endicott had the high-est percent increase: at 22,247 bpd in October the field’s pro-
duction was up 29 percent from a September average of17,241 bpd.
Prudhoe up from SeptemberThe BP-operated Prudhoe Bay field averaged 449,188
bpd in October, up 14.76 percent from a September averageof 391,430 bpd. The Department of Revenue said requiredsafety testing at Prudhoe Sept. 29 through Oct. 1 decreasedproduction by 90,000 to 100,000 bpd, and also noted thatproduction at all fields was affected by a 25-hour day Oct.31 because of the change in daylight savings time.
Production at Prudhoe includes satellite production fromMidnight Sun, Aurora, Polaris, Borealis and Orion.
Production at the ConocoPhillips Alaska-operatedKuparuk River field, which includes West Sak, Tabasco,Tarn, Meltwater and Palm, averaged 203,372 bpd in
October, up 5.8 percent from a September average of192,227 bpd.
New record at Alpine ConocoPhillips-operated Alpine averaged 113,350 bpd
in October, a new monthly high and up 3.58 percent from aSeptember average of 109,430 bpd. The first phase of facil-ity expansion was completed this summer at Alpine, increas-ing the field’s capacity to handle produced water, and wasexpected to increase oil throughput by about 5,000 bpd.When work on the second phase of the facility expansion iscompleted next summer, the field’s capacity will be at140,000 bpd.
BP-operated Lisburne, which includes Point McIntyreand Niakuk production, averaged 46,672 bpd, up 1.58 per-cent from a September average of 45,944 bpd.
BP-operated Milne Point production was nearly flatmonth-to-month, with an average of 52,287 bpd in Octoberdown 0.6 percent from a September average of 52,579 bpd.
BP-operated Northstar had a production drop of 2.49 per-cent, averaging 74,390 bpd in October vs. 76,291 bpd inSeptember. Revenue said Northstar had a generator failureOct. 11.
The temperature at Pump Station No. 1 on the NorthSlope averaged 20.7 degrees Fahrenheit in October, downfrom an average of 34.6 degrees in September. Revenue saidthe three-year average temperature for October is 21.1degrees.
Cook Inlet averaged 23,689 bpd in October, down 7.55percent from a September average of 25,624 bpd. ●
A
● C O O K I N L E T
Pelican set to drill four more Cook Inlet wells
The trans-Alaska oil pipeline
JUD
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P ARLEN EHM
see PELICAN HILL page 16
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12 PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004EXPLORATION & PRODUCTION
exploration wells with its partners,announcing discoveries at both Ooogurukand Nikaitchuq.
Gustafson, Armstrong’s vice presidentof operations, spoke to the AlaskaChapter of the International Associationof Drilling Contractors and the Alliancethe last week of October, updatingAnchorage audiences on the company’sthree-year history in Alaska, on its plansfor drilling with Kerr-McGee this winterin the Nikaitchuq and Tuvaaq units in theshallow waters of the Beaufort Sea (seesidebar), and on Armstrong’s plans for itsonshore Two-Bit prospect, just off thewestern edge of the Kuparuk River unit.
Production in a box Armstrong could become the first
independent to do its own North Slopeproduction processing, if this winter’sdrilling at its Two-Bits prospect is suc-cessful.
At Two-Bits “we’ll drill twoexploratory wells over this winter. It’stwo prospects,” Gustafson said, and if oneof those prospectsproves up, “we willstart productiondrilling and we willbe online by yearend (2005).”
A r m s t r o n gAlaska, subsidiaryof Armstrong Oiland Gas, would getTwo-Bits on linequickly with an ideaGustafson had whenfaced with NorthSlope Native con-cerns about offshoreproduction.
They don’t wantto see a single dropof oil in the water,he said. The solutionto that concern started as an idea sketchedon a napkin in the Brower Cafeteria inBarrow: Put all of the facilities inside atank, a containment vessel, so that if thereis a leak the leak is automatically con-tained.
This production-in-a-box plan hasbeen refined by ASRC Energy Services,Gustafson said, but basically conductorpipe is put through the floor of the tank,wellhead and piping is inside and it’smonitored from offsite by cameras andheat sensors inside the tanks. The concepthas been embraced by Kerr-McGee, hesaid, and variations on the idea are beinglooked at by Pioneer Natural Resources.
Gustafson said that while production
in a tank began as a response to an envi-ronmental concern — keeping oil con-tained — it is also proving economic,with drill site costs estimated at $12 mil-lion for a 12-well site, compared to $29million for a conventional North Slopefacility.
Modular processing facilities But there’s more. Armstrong is also
planning a standalone production facilityat Two-Bits: “we believe we have to doall our own processing,” he said, and planto bring in modularprocessing facilities,a technology alreadyin use elsewhere, andprocess oil on site.“We’re looking atArctic Serviceunits,” Gustafsonsaid, truckable, skid-mounted productionunits.
With modular facilities, he said,“we’re looking at repetitive designs,”which will speed up permitting. And sincethese facilities are already in use “you cancall up and order them.”
There is nothing new here, he said:“this is proven technology: it works.”
Two-Bits would use “no unit power,no unit processing, we do it ourselves, all
the way to the LACT (lease automaticcustody transfer) meter.”
In a question and answer session at theend of his Alliance presentationGustafson was asked about using existingprocessing facilities. He said you don’tbid millions at lease sales and drill mil-lions of dollars worth of exploration wells“and hope that you can go to somebodyelse.” The risk capital Armstrong has putup, he said, is based on doing it “on ourown.”
If Ed Kerr, Armstrong’s vice presidentof land and business development, “is
able to negotiate a bet-ter business environ-ment for us … we’lllook at it.” There havebeen North Slopeprojects that couldn’tmove without guaran-teed access to existingfacilities, Gustafsonsaid: “The only thing
that we were counting on is common car-rier pipelines.”
And road use: North Slope roads werebuilt with state gravel, “so they really arestate roads, and we’re delighted to paymaintenance” and help the unit operatorsthere, “but working deals gets to be longand can be convoluted, and that’s not‘smoother, faster, better, cheaper.’”
Flexible transport pipe To move the oil off the Two-Bits pad,
Armstrong is looking at the type of fluidtransport line used in the Gulf of Mexico.
The flexible pipe comes in 3,200-footrolls, he said, and is typically used for oilor gas gathering lines, injection lines andwater or fuel transfer lines. This pipewould be laid pipe-within-a pipe insideof an outer pipe, and buried in the road.
And what’s next? Armstrong pickedup some 115,000 acres of state oil andgas leases Oct. 27. It first acquired stateleases in 2002, and had brought in a part-ner (Pioneer), was drilling within sevenmonths of lease issuance and completedthree wells offshore in one season, a sin-gle-company record, Gustafson said. In2003, Armstrong doubled its acreage,brought in Kerr-McGee and drilled twowells in 2004.
“We buy prospects … to drill,” hesaid. We have brought in Pioneer and wehave brought in Kerr-McGee, Gustafsonsaid, and “we’re working on otheroptions.” ●
continued from page 1
ARMSTRONG
CO
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“We’ll drill twoexploratory wellsover this winter. It’stwo prospects” andif one of thoseprospects proves up,“we will start pro-duction drilling andwe will be online byyear end (2005).” —Stu Gustafson,Armstrong’s vicepresident operations
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“We buy prospects … to drill.”We have brought in Pioneer and
we have brought in Kerr-McGee, and “we’re working on
other options.” —Stu Gustafson,Armstrong’s vice president of operations
To move the oil off the Two-Bitspad, Armstrong is looking at the
type of fluid transport line used inthe Gulf of Mexico.
By GARY PARK Petroleum News Calgary Correspondent
anada’s two leading oilfield supportassociations are like-minded in set-ting their drilling targets for 2005.
In forecasts released at the end ofOctober, the Canadian Association ofOilwell Drilling Contractors predicted24,205 wells, while the PetroleumServices Association of Canada has itssights on 24,035 wells.
The contractors’ association forecastwould exceed its anticipated 2004 countby almost 3,000 wells, or 13.5 percent, andachieve a new benchmark.
It hinges partly on whether contractorscan wipe out a backlog accumulated byweather setbacks through 2004 and reachthe contractors’ association goal of 21,312.
But helping the outlook is a reduction inthe average drilling time per well in thefinal quarter to 6.1 days from 6.4 days, anincrease in active rigs to 504 from 432 anda subsequent increase in operating days to36,945 from 33,613.
The contractors’ association forecast isbased on projected commodity prices ofUS$40 per barrel for oil and US$6.12 perthousand cubic feet for NYMEX naturalgas — both assumptions that the associa-tion acknowledges are on a low side.
But contractors’ association ChairmanDon Herring does not expect that higherprices will translate into a significantlygreater number of wells.
He said company budgets are being tiedto prices of US$35-$40 per barrel.
Herring said that although the availabil-ity of rig hands is a concern, the industryhas the equipment to test the 25,000-wellbarrier.
But the contractors’ association hunt formanpower includes jobs fairs in BritishColumbia that netted 500 workers fromVancouver Island in mid-October, andCanada’s Atlantic region.
Rig count expected to be up by 40 in 2005
The rig count is predicted to average473 in 2005, up by 40 rigs from 2004 andfleet utilization is expected to reach 64 per-cent.
Operating days next year are forecast toclimb to 142,485 from 129,840 this year.
The services association is counting ona three-fold surge in coalbed methanewells to about 3,000 as a key driver in
bumping the well total about 8 percentabove its 2004 prediction.
Otherwise, the count for 2005 would belargely unchanged from 2004, saidPetroleum Services Association of CanadaPresident Roger Soucy.
The breakdown will see 18,610 wells inAlberta (up 10 percent from this year),3,935 in Saskatchewan (up 3 percent) and1,300 in British Columbia (up 6 percent).
Soucy agreed with Herring that thebiggest constraint is the lack of skilledlabor, not equipment.
The services association also raised its2004 count to 22,160 wells, about 17 per-cent ahead of its original estimate inOctober 2003 and a record year by a smallmargin. ●
PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004 13E&P/NATURAL GAS
● C A N A D A
Chasing 24,000 wellsin Canada for 2005Drilling contractors, petroleum services group offer similarforecasts for 2005; industry worried about shortage of skilled labor
C
SOUTHWESTERN ALASKAState of Alaska asks for comments onarea in Holitna exploration license
On July 2, Holitna Energy Co. submitted a request to convert its shallow natu-ral gas applications in southwestern Alaska to a Holitna basin exploration license,as per language in House Bill 531, which essentially legislated out of existence thestate’s non-competitive, shallow gas leasing program, commonly referred to as itscoalbed methane program.
On Oct. 22, the Alaska Department of Natural Resources, Division of Oil andGas, issued a public notice saying it intended to evaluate Holitna Energy’s explo-ration license proposal, which encompasses 26,880 gross acres.
Must issue best interest findingBefore issuing an exploration license the division must issue a best interest find-
ing to determine if an exploration license in the area is in the state’s best interest. In its public notice the division asks for comments on the proposed license area.
The 60-day comment period begins today, Oct. 22 and ends on Dec. 21.Holitna Energy has said the gas produced on its acreage will likely be used to
supply power and heat for Donlin Creek mining project and for nearby villages. OnMay 25, the company’s top executive, Phil St. George, told Petroleum News thatDonlin Creek may not be the only potential large mine customer for Holitna basingas. St. George said he was approached by state development employees interest-ed in taking Holitna gas about 100 miles south to Iliamna Lake, to the Pebble gold-copper-molybdenum project.
—KAY CASHMAN
WEEK OF NOVEMBER 7, 200414 PETROLEUM NEWS
governmentwww.PetroleumNews.com
ALBERTA● P R U D H O E B A Y
AOGCC hits BP with fine for annulus pressureviolation at Prudhoe unitAlaska Oil and Gas Conservation Commission proposes $117,500 fine,corrective action, increased monitoring by agency; BP preparing a response
Klein seeks re-election onhow to spend bulging surplus
The voters of Alberta are heading for what seems to be a fore-gone conclusion on Nov. 22, when political observers believe theonly unanswered question is how wide a margin Premier RalphKlein’s Conservative party will accumulate in retaining power.
In what Klein, 62, has said will be his final campaign, the rum-pled, to-the-point, mostly good-natured premier is seeking afourth term.
But his short-temper and the fact that hekeeps reminding voters this is his last elec-tion could rebound in the final count.
Klein has a campaign war chest of C$4million and use of a plane to fan out acrossAlberta, while his three rivals are left tochase after Klein in mini-buses and operateon a shoestring.
The Liberals, currently the largest oppo-sition party in the legislature, are still strug-gling to pay off 90 percent of a C$1 milliondebt from the last election.
Awash in oil and gas revenues, the Kleingovernment has taken some heat for ramp-ing up government spending by 40 percent(after taking into account inflation and pop-ulation growth) over eight years.
Alberta on track to C$10 billion surplusBut Klein is deflecting those concerns by preparing Albertans
to become a debt-free province in 2005, wiping out the last C$3billion of a C$22.7 billion overrun that he inherited in 1994.
Alberta is currently on trackto notch a C$10 billion surplusin 2003-04.
The toughest decision fac-ing the government is how tohandle its windfall in aprovince of 3.5 million.
It has recently tried askingthe voters by e-mail and mail-out questionnaire what theywant to do with future surplus-
es — raise spending in health care and education, cut taxes or putthe money into a “rainy-day” fund.
The evidence suggests only a minority of Albertans took partin the exercise.
In 2005 Alberta celebrates 100 years in the Canadian confed-eration. The smart money has Klein stepping down after the cen-tennial, pocketing a C$500,000 severance as a retiring premierand taking up new career in fishing or golf.
Under Klein, the Conservatives over the last three electionshave captured, in succession, 51, 63 and 74 of the 83 seats in thelegislature.
—GARY PARK
Alberta PremierRalph Klein has acampaign war chestof C$4 million anduse of a plane tofan out acrossAlberta, while histhree rivals are leftto chase after Kleinin mini-buses andoperate on a shoe-string.
By KRISTEN NELSONPetroleum News Editor-in-Chief
he Alaska Oil and Gas ConservationCommission is proposing to fine BP Exploration(Alaska) for failure to record annular pressureproblems, notify the commission of those prob-
lems and to bleed down pressure at Prudhoe Bay wellH-11 at the BP-operated Prudhoe Bay field onAlaska’s North Slope.
The commission notified BP Oct. 25 that it wasproposing to fine the company $117,500 and ordercorrective action.
The commission said in a letter to BP that itappears the company violated Conservation OrderNo. 492, “by failing to record and make available onrequest the results of monitoring the H-11 tubing andannulus pressures” between Aug. 19 and Sept. 8. Thecommission said the violations are indicated by gapsin the record of H-11 tubing pressure, inner annuluspressure and outer annulus pressure.
A second violation was failure to notify the com-mission of outer annulus pressure exceeding 1,000psig at H-11 from Sept. 9 through Sept. 21. The com-mission said it received a report on the outer annuluspressure from BP only after it inquired.
In a third violation, of both the conservation orderand of the commission’s regulations, BP failed tobleed off H-11’s outer annulus pressure before it wasrestarted Sept. 9, after the well had been shut-in.
Corrective action ordered In addition to the fine, the commission said it is
proposing to order corrective actions by BP. Within 30 days BP is to provide the commission
“with a detailed description of actions, planned andaccomplished, to prevent recurrence of violationssimilar to those that appear to have occurred in con-nection with the start-up of H-11” and monthlyprogress reports until the planned actions are com-pleted.
For 180 days BP will provide the commission with24-hour advance notice of all Prudhoe Bay wellrestarts so that the commission will have the opportu-nity to witness the restart operations, and documenta-tion of well pressure bleeds in connection with well
restarts. The commission is proposing a lighter fine ($2,500
a day vs. the maximum of $5,000 a day) for the firstgroup of violations because, the commission said, itunderstands “that the pressures in question were infact monitored and that the failure to record the obser-vations may have been due at least in part to confu-sion about the workings of BPXA’s well data record-ing system.”
BP has 15 days from Oct. 25 date to notify thecommission that it “concurs in whole or in part withthe proposed action …, requests informal review, orrequests a hearing …,” otherwise the commission willconsider BP has accepted by default and will issue anenforcement order.
BP reviewing BP said in an Oct. 29 statement that it “is review-
ing the matter to develop a response to the proposedenforcement action. Options available to us includerequest for informal or formal hearings to the pro-posed enforcement action.”
BP said it is investigating “why H-11 operatedabove policy guidelines of 1,000 psi (pounds persquare inch) on the outer annulus for several days.”The company said according to its policies and proce-dures “the well should have been monitored closelyduring start-up to ensure pressure remained below1,000 psig during start-up operations.” To keep pres-sure below 1,000 psig, BP said, pressure can be bleedfrom the outer annulus either prior to the well beingbrought online, or while the well is being brought online.
“Bleeding pressure out of an annulus is a routine,relatively simple procedure that well site operatorsand contractors are trained to safely perform,” BPsaid.
On the issue of recording data — the violation forwhich the commission has proposed a lesser penalty— BP said its preliminary investigation found that theworkers were uncertain “about whether data that hadnot changed over the identified period of time (Aug.19-Sept. 8) needed to be entered into the computerdatabase. Operators felt that if the data did not change
see BP page 15
T
The smart money hasKlein stepping down afterthe centennial, pocketing
a C$500,000 severance asa retiring premier and
taking up new career infishing or golf.
ussia’s huge OAO Gazprom, set to become evenlarger and come under majority control by theRussian government, is looking aggressive lately.Reports are surfacing of various partnerships with
the majors, particularly in Sakhalin projects. The com-pany is already inheriting a stake in Sakhalin-1 andSakhalin-5 when it takes over Rosneft later this year.
Alexander Ananenkov, Gazprom’s chief executive,met with Jeffrey Woodbury, head of ExxonMobil’sRussian operations, on Nov. 2, and the Russian compa-ny said afterwards in a press release that they discussedSakhalin-1, led by the U.S. firm.
The Russian statement also said the companiestalked about cooperating on a system Gazprom is set-ting up to export gas from eastern Siberia and the FarEast.
Sakhalin gas to China?Also on Nov. 2, ExxonMobil confirmed talks with
China National Petroleum Corp. on selling Sakhalin gasto China, rather than sending it to Japan in a 1,000-milepipeline as the company had planned earlier, accordingto Itar-Tass. The Japan option might still be available aswell, since drillers have found huge quantities of gas.
A few days earlier, Shell said Gazprom might take astake in Sakhalin-2. That would strengthen the project,according to Shell executives. It would also be a plusfor Gazprom, since Shell is a leader in LNG technolo-gy. On Sakhalin, Shell is leading the group buildingwhat will become the world’s largest LNG productionfacility. Gazprom sees LNG as a way to expand its
sales to North America and other remote markets, andis eager to learn more about the technology.
TNK-BP adds to Siberian holdingsTNK-BP is moving aggressively in Siberia, despite a
Gazprom roadblock in its attempts to sell gas from theKovykta field to China.
The Russian-British venture announced Oct. 28 thatit had acquired four companies holding Siberian pro-duction licenses. The fields in the Bolshekhetskayadepression hold an estimated 830 million barrels of liq-uids and 4 billion cubic feet of gas.
The major holdings acquired from Slavneft are theTagulskoye, Suzunskoye, and Russko-Rechenskoyefields, near the Vankor deposit. TNK-BP also getsPayakhskoye, which is remote from the others but closeto the year-round port of Dudinka.
TNK-BP plans to develop the resources in coopera-tion with Rosneft and Lukoil, which also have targetsnearby. The area is expected to start producing in 2008,with peak production of 250,000 barrels daily.
Pipeline decision soonRussian officials say they’ll decide by the end of the
year just where a proposed Far East pipeline will run.Deputy Foreign Minister Alexander Alekseyev also saidNov. 3 that the government will make a comprehensive
decision that will also provide for transportation of gastowards the Pacific. He also said the project envisagesan extension to China, according to an Itar-Tass report.
He dropped a hint that Russia is leaning moretoward the Chinese side of the equation when he saidthat economic cooperation between Russia and Japan islagging behind, compared to other countries.
China backstops with LNGChina is hedging its energy bets with plans to build
a ring of LNG terminals along the coast. China Daily reported Oct. 27 that China National
Offshore Oil Corp. has reached tentative deals withlocal government for three terminals that would handlea total of 1.1 billion cubic feet of gas daily. Those ter-minals are in Liaoning, Jiangsu, and Guangdongprovinces.
CNOOC is already building its first two terminals,in Guangdong and Fujian. Plans are set for terminals atShanghai and Tianjin, the port city near Beijing, andthe company is considering one in Zhejiang.
All those terminals will need supply. Sinopec Grouphas signed a $70 billion oilfield development contractwith Iran. The memorandum of understanding signedOct. 28 calls for the Chinese company to get 250 mil-lion tonnes of LNG over 30 years as part of the deal todevelop the giant Yadavaran oilfield. Sinopec wouldalso get 150,000 barrels of crude daily for 25 years atmarket prices, according to Iranian officials.
—ALLEN BAKER
PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004 15MINING/FAR EAST REPORT
from day to day no entry was requiredbecause the computer would automaticallyuse the previous reading. We have sincereinforced the need to input this data.”
Rules established last year The commission issued rules regulating
sustained annulus pressures in Prudhoe Baydevelopment wells in June 2003, followingan explosion and fire at Prudhoe Bay wellA-22 in August 2002 which seriouslyinjured a BP employee.
The commission fined BP for the inci-dent and said when it finished its investiga-tion in late 2003 that BP “may have violat-ed” the commission’s regulations “by failingto carry on operations and maintain theproperty in a safe and skillful manner in
accordance with good oil field engineeringpractices.”
BP revised its Prudhoe Bay annular pres-sure management policies, and the commis-sion said in mid-2003 when it issued its newrules that while BP’s policies “provide a rea-sonable starting point for establishing rulesregulating annular pressure,” those policiesneeded to be supplemented by a rule requir-ing BP to notify the commission when“wells exhibit annular pressures that exceedspecific thresholds,” by a rule requiring sub-mission by the operator of proposed correc-tive actions for affected wells, by specificannular pressure limits necessitating correc-tive action and “operator accounting forannular pressure increases due to well heat-ing during start-up.”
The commission has established annularpressure rules for wells at Kuparuk, Alpineand Milne Point similar to those forPrudhoe. ●
continued from page 14
BP
● I L I A M N A , A L A S K A
Pebble Mine pencils nicely, says ThiessenDevelopment would be conventional,large-scale open pit mine with 31 to 62year life, depending on production rate
By STEVE SUTHERLIN Petroleum News Associate Editor
he future looks bright for the Pebble gold-copper-molybdenum project near Iliamna in southwesternAlaska. Northern Dynasty Minerals Ltd. President andCEO Ronald W. Thiessen said a preliminary assess-
ment of the project indicates excellent potential for a long-life mine, having large-scale, low cost metal production.
The company said it undertook the assessment to quanti-fy the Pebble project’s cost parameters and to provide guid-ance for on-going engineering work to define the optimalscale of production. Preliminary forecasts and estimates inthe report were developed to an order of magnitude level andare not based on systematic engineering studies, the compa-ny said in a Nov. 3 statement. The company said that at thisearly stage, data is incomplete and estimates were developedbased on the expertise of the engineers involved.Independent engineer Derek Barratt, and Peter Beaudoin, anin-house engineer, were lead-authors of the study.
The preliminary assessment said the Pebble gold-copper-molybdenum porphyry deposit would be developed by con-ventional, large-scale, open pit mining methods. Four openpit stages were designed based on the block model proposedby Norwest Corp. in its February 2004 inferred mineralresource estimate of the Pebble deposit. The estimatedinferred mineral resource is 2.74 billion tonnes grading 0.5percent copper-equivalent (0.30 grams per tonne gold, 0.27percent copper and 0.015 percent molybdenum above a cut-off grade of 0.30 percent copper-equivalent), containing26.5 million ounces of gold and 16.5 billion pounds of cop-per.
Processing will produce concentrate Processing of mill feed from the open pit will produce a
flotation copper sulphide concentrate with gold and silvervalues as well as a separate molybdenum sulphide concen-trate. Estimated metal recoveries of 88 percent for copper, 76
percent for gold and silver, and 60 percent for molybdenumwere used in financial modeling.
Estimates are based on on-going test work, and are com-parable to other large gold-copper porphyry mines, the com-pany said. Copper concentrate was estimated to grade 28percent copper, 26.6 grams per tonne gold, and 100 gramsper tonne silver. Molybdenum sulphide flotation concentratewas estimated to grade 50 percent molybdenum. Copperconcentrate would be transported via pipeline to astorage/dewatering/port facility at tidewater. Molybdenumsulphide concentrate would be packaged and shipped tomarket separately.
The preliminary assessment examined three productionrate scenarios: 100,000 tonnes per day, 200,000 tonnes perday and a phased expansion from 100,000 tonnes per day to200,000 tonnes per day in year six. The analyses show thatat the lowest production rate considered, the project wouldproduce an annual average of 256 million pounds of copper,365,000 ounces of gold, 8 million pounds of molybdenum,and 1.4 million ounces of silver during the first 10 years ofa 62 year mine life. At the largest scale studied, the projectwould produce an annual average of 470 million pounds ofcopper, 674,000 ounces of gold, 15 million pounds ofmolybdenum, and 2.5 million ounces of silver during thefirst 10 years of a 31 year mine life. ●
T
Gazprom may move on Sakhalin, SiberiaFAREAST reportR
Copper concentrate would be transported viapipeline to a storage/dewatering/port facility attidewater. Molybdenum sulphide concentratewould be packaged and shipped to market
separately.
16 PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004THE REST OF THE STORY
“We’d like to drill two wells there — NPretty Creek 1 and N Pretty Creek 2 — andthen go back and drill a second well atBeluga, the NE Beluga 1, which I’mpresently permitting. But drilling NE Beluga1 is conditional upon N Beluga 1 being suc-cessful, just as drilling a second Pretty Creekwell is conditional upon the success of thefirst Pretty Creek well,” Ehm said.
The last three wells, he said, are in theSusitna Flats state game refuge.
Pelican Hill plans to use its own drillingrig, a Water Resources International rig,the Ideco H-35 KD, to drill the wells. Usedto drill water wells in Hawaii and broughtto Alaska by Pelican Hill President AlGross, the rig was completely refurbishedthis past year.
Ehm said camp operations are beingrun by Kuukpik Arctic Catering. Othercontractors include Tesco, Quadco,Baroid, BJ Services and MRO Sales. ●
continued from page 10
PELICAN HILL
more than 160 countries, including US$6billion in 58 overseas oil and gas projects.
That is far short of the US$60 billion offoreign investment in China, but the gapcould rapidly be closed as Beijing openlyurges its state-owned enterprises to “goglobal.”
Bob Broadfoot, a Hong Kong-basedconsultant, told The Associated Press thatChina has the “ability to argue with foreigncompanies that ‘if you want access to ourmarket, you will have to sell us a stake inyour company.’”
Noranda would be largest purchase to date
The Noranda purchase would beChina’s largest foreign acquisition to dateand represents the first time any state-owned Chinese enterprise has made a bidfor a Canadian com-pany.
The result hasbeen confusion anduncertainty withinCanadian govern-ment ranks.
Prime MinisterPaul Martin has wel-comed the move byMinmetals, butIndustry MinisterDavid Emerson has confessed to someunease about allowing such deals, givenChina’s human rights record.
“Fundamentally, I think it is a goodthing. We’re investing heavily in China andI think it’s a sign of China’s increasinggrowth and maturity,” Martin said, whileadding Canada will not step around humanrights issues.
Emerson said that having a state enter-prise own Canadian resources is differentfrom private ownership, indicating thatCanada could attach conditions to any deal,including export controls.
“I don’t think that you should assumethat somehow it’s a wholesale sale of theCanadian resource case,” he said. “It wouldnot be that.”
But he said Canada can’t “complainendlessly about being too dependent on theUnited States” and then take steps to jeop-ardize its relationships with China, its sec-ond largest trading partner.
Bilateral trade with China hit a recordC$23 billion in 2003, up 16 percent from2002 and Chinese foreign direct invest-ment in Canada climbed to C$422 millionin 2003.
Members concerned investment act inadequate
Members of Parliament from all fourparties represented in the House ofCommons expressed concern Oct. 26 thatthe 19-year-old Investment Canada Act isoutdated or inadequate.
The act currently calls for governmentreviews of direct acquisitions worth morethan C$237 million by member countriesof the World Trade Organization.
Andy Savoy and Denis Coderre, bothfrom the governing Liberal party, agreedthere is a need for change in a time of glob-alization, especially with China sendingout signals it is ready to go on a shoppingspree for resources.
Brian Masse, an MP from the left-wingNew Democratic Party, said the issue wasfar larger than the Minmetals-Norandadeal.
“The stakes are higher than peopleunderstand,” he said, suggesting that if for-eign ownership legislation was amendedand the deal was turned down it could harmCanada’s relationships with China and its
growing trade.“This is a very hungry dragon and its
demand for copper and nickel and oil havelong outpaced domestic supply,” saidHoward Balloch, a former Canadianambassador to China. “Domestic supplywill never again satisfy its hydrocarbon orbase metal needs.”
Matthew Simmons, a Houston-basedeconomist, said China’s need for “reliableenergy in massive supply is profound.”
China’s Foreign Minister Li Zhaoxinghas left no doubt that companies from theChinese government’s vast stable of state-owned enterprises are poised to makemany resource takeover bids as the countrygains influence.
Greatest stirrings in oil patch Although the Minmetals-Noranda trans-
action has captured the spotlight, the great-est stirrings are taking place in the oilpatch.
Sinopec, China Petroleum Corp., is con-ferring with Beijingabout buying intoAlberta’s oil sandsand PetroChina hastalked with officialsof the Canadian OilSands Trust, whichowns 35.49 percentof the SyncrudeCanada oil sandsoperation.
Alberta Premier Ralph Klein saidSinopec officials have held discussionswith key oil sands players — Syncrude,Suncor Energy, Shell Canada, HuskyEnergy and Canadian Natural Resources— as well as Alberta’s Energy Department.
He said Sinopec officials are talkingwith their government about the prospectof a direct investment in the oil sands.
Meanwhile, a PetroChina delegationmet with oil sands trust executives in thelate summer, said trust President and ChiefExecutive Officer Marcel Coutu.
He said the focus was on the possibilityof a long-term agreement to ship produc-tion from the oil sands to China, rather thanPetroChina taking a stake in the trust.
Coutu said the “ball’s in their court,” asthey evaluate whether Chinese refineriescould process synthetic crude.
He said it is possible rather than likelythat the Chinese will either reach a supplyagreement or acquire outright ownership ofpart of Syncrude.
“Their interest in supply is serious,”Coutu said. “I don’t think there’s any doubtabout that.”
Pipeline to British Columbia neededFor now the greatest barrier is the
absence of a pipeline to carry productionfrom Alberta to a port on the BritishColumbia coast, but a solution sits at thetop of Enbridge’s priority list as it contem-plates a 400,000 barrel-per-day pipelinebefore the end of the decade.
Enbridge has also been in discussionsthat could see Sinopec either buy produc-tion or invest in the pipeline.
On the sidelines, there is fresh specula-tion that Sinopec is interested in staging atakeover of Husky Energy, which has sub-stantial plans for the oil sands that couldsee it pumping 235,000 bpd from two proj-ects by 2010-2014.
Currently Hong Kong billionaire Li Ka-shing and his family control 72 percent ofHusky, through the Hutchison Whampoaconglomerate and individually.
Li has already stood on the brink of asale in early 2002, when Husky confirmedit was in talks with PetroChina, butprospects of a deal crumbled whenChinese officials disclosed they wereoffering US$4.4 billion and immediatelydrove up the value of Husky shares.●
continued from page 1
CHINA
Although the debate is currentlybeing driven by a pending C$7billion takeover of mining giantNoranda by metals trader China
Minmetals, the petroleum industryis waiting off stage to see what
happens next.
acquire a 25 percent equity share of a pro-posed LNG terminal at Altamira, Mexico,from Shell Gas B.V. Planned capacity at theterminal is about 1.1 billion cubic feet daily,and the terminal consortium has a 15-yearsupply contract with the Mexican ComisionFederal de Electricidad.
With the Mitsui investment, Shell willretain a 50 percent interest and Total willhave 25 percent. The agreement was
announced Nov. 2. More than 40 LNG terminals are at var-
ious stages of planning or development inNorth America, with four currently operat-ing. Those four have a capacity of about 4.5billion cubic feet daily.
Construction was started recently on onenew terminal in eastern Canada. AnadarkoPetroleum Corp. of Houston started work inlate October at Bear Head, on Cape BretonIsland in Nova Scotia. That terminal has aplanned capacity of a billion cubic feetdaily. Completion is planned for late 2007.●
continued from page 6
LNG
Merchant Corp., said he believes marketsentiment has shifted so strongly that oilprices will fall below $40 a barrel before theyear is up. The financial incentive is strongfor refiners to make as much heating oil asthey can right now, Silliere said.
Light crude for December delivery trad-ed 42 cents lower at $49.20 per barrel inNov. 3 morning trading on the New YorkMercantile Exchange, recovering from anintraday low of $48.65. A record Nymexclosing price of $55.17 per barrel wasreached Oct. 22 and again on Oct. 26.
The Energy Department reported thatcommercially available stocks of crude oilrose by 6.3 million barrels to 289.7 millionbarrels, about 1 percent below year ago lev-els. Distillate fuel inventories fell by900,000 barrels to 115.7 million barrels, or12 percent below last year. While the U.S.presidential election appeared to generatesome market speculation about which direc-tion oil prices would move depending onwhich candidate won — up on a Bush vic-tory, down on a Kerry triumph, some pre-dicted — the focus of trading Nov. 3returned to fundamentals, in particular eas-ing concerns about heating oil supplies.
“I don’t think anything is going to stopthe refiners” from producing enough heatingoil, Silliere said, brushing off the actual andpotential supply disruptions globally.“That’s all forgotten when you build 6 mil-lion barrels in inventory.”
Stephen Theede, the chief executive ofRussian oil giant Yukos, said Oct. 3 that the
company is “close to insolvency” and willcall an emergency shareholders meeting forDecember to consider bankruptcy.
Theede’s comments came after taxauthorities served new, crippling back taxbills on Russia’s floundering No. 1 producerNov. 1 for nearly $10 billion, bringing thefirm’s total tax debt to some $17.6 billion.
Yuganskneftegaz, Yukos’ core unit thatproduces 1 million barrels per day, is expect-ed to be sold to cover Yukos’ tax arrears.
In northern Iraq on Nov. 2, saboteursblew up an oil pipeline and attacked an oilwell. The attacks were expected to hinderexports for the next 10 days.
In Nigeria, oil giant Royal Dutch/ShellGroup of Cos.’s first-round bid to block astrike targeting oil exports failed, againthreatening the flow of crude from theworld’s seventh-largest exporter.
Societe Generale’s Guido said the markethad already factored the Yukos affair and theinsurgency in Iraq into the price of oil.Moreover, economists around the worldhave noted in recent weeks that the surgingcost of oil was slowing growth and coolingoff red-hot demand.
Prices also have been declining as oiloutput in the Gulf of Mexico returns closerto normal levels following disruptionscaused by Hurricane Ivan. The MineralsManagement Service reported Nov. 2 thatdaily oil production in the region remainsdown by 13 percent, or 218,000 barrels aday.
Oil prices would need to surpass $90 perbarrel to approximate the all-time high, ininflation-adjusted terms, set in 1980.
—BRAD FOSS, Associated Press Writer
continued from page 1
FUTURES
PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004 17ADVERTISER INDEX
Companies involved in NorthAmerica’s oil and gas industry
ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS
Business Spotlight
AAeromap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7AeromedAES Lynx EnterprisesAgriumAir LiquideAir Logistics of AlaskaAlaska Airlines CargoAlaska AnvilAlaska CoverallAlaska Dreams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Alaska Interstate ConstructionAlaska Marine LinesAlaska Massage & Body WorksAlaska Railroad Corp.Alaska SteelAlaska TelecomAlaska Tent & TarpAlaska TerminalsAlaska TextilesAlaska USA Mortgage CompanyAlaska West ExpressAlliance, TheAlpine-MeadowAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Anchorage HiltonArctic ControlsArctic Fire & SafetyArctic FoundationsArctic Slope Telephone Assoc. Co-opArctic StructuresASRC Energy ServicesASRC Energy Services
Engineering & TechnologyASRC Energy Services
Operations & MaintenanceASRC Energy Service
Pipeline Power & CommunicationsAvalon Development
B-FBadger ProductionsBaker HughesBrooks Range SupplyCapital Office SystemsCarlile Transportation Services. . . . . . . . . . . . . . . . . . . . . . . . . 5Carolina MatChiulista Camp ServicesCN AquatrainColvilleConam ConstructionConocoPhillips Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2CoremongersCraig Taylor EquipmentCrowley AlaskaCruz ConstructionDowland - Bach Corp.Doyon Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Doyon LTDDoyon Universal ServicesDynamic Capital ManagementEngineered Fire and Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . 3ENSR AlaskaEpoch Well ServicesEra Aviation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Evergreen Helicopters of AlaskaFairweather Companies, TheFriends of PetsFrontier Flying ServiceF.S. Air
G-MGolder Associates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Great Northern EngineeringGreat NorthwestHanover CanadaHawk ConsultantsH.C. PriceHorizon Well Logging, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Hunter 3DIdentity WearhouseIndustrial Project ServicesInspirationsJackovich Industrial
& Construction SupplyJudy Patrick Photography
Kakivik Asset ManagementKenai AviationKenworth Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Kuukpik Arctic Catering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Kuukpik/VeritasKuukpik - LCMFLounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMapmakers of AlaskaMarathon OilMarketing SolutionsMayflower CateringMEDC InternationalMI Swaco. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Michael Baker Jr.Millennium HotelMWHMRO Sales
N-PNabors Alaska Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Nabors IndustriesNANA/Colt Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Natco CanadaNature Conservancy, The . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19NEI Fluid TechnologyNordic CalistaNorth Slope TelecomNorthern Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Northern Transportation Co.Northwestern Arctic Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Offshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oilfield ImprovementsOilfield TransportPacific Rim Institute
of Safety and Management (PRISM)Panalpina. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18PDC/Harris Group. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Peak Oilfield Service Co.Penco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Perkins Coie . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Petroleum Equipment & ServicesPetrotechnical Resources of Alaska. . . . . . . . . . . . . . . . . . . . . 9PGS Onshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Precision PowerPrudhoe Bay Shop & Storage
Q-ZQUADCORanes & Shine WeldingRenew Air TaxiSalt + Light CreativeSchlumbergerSecurity AviationSeekins FordSmith Consulting ServicesSOLOCO Dura-BaseSpan-Alaska ConsolidatorsSpenard Builders SupplySTEELFABStorm Chasers Marine ServicesTaiga VenturesThrifty Car RentalTOTE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Totem Equipment & SupplyTravco Industrial HousingUBS Financial Services Inc.Udelhoven Oilfield Systems ServicesUmiat CommercialUnique MachineUnitech of Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Univar USA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14U.S. Bearings and DrivesUsibelli Coal MineVECOWeaver Brothers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Welding Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5WorksafeXTO Energy
Robert “Rob” M. Retherford, partner
FOR
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By PAULA EASLEY
Alaska EarthSciences, Inc.
For nearly 20 years Alaska EarthSciences has helped companies interest-ed in Alaska find mineral deposits. It hasconsulted for every Native corporation,the University of Alaska and govern-ment agencies. One particularly excitingventure has been the Donlin Creek dis-covery. After surviving the downturnyears, AES is operating at full speedwith a team of energetic, talented geol-ogists. The partnership also includeslong-time Alaskans Bill Ellis and DaveLappi.
Rob Retherford earned his mastersin geology from the University ofColorado and learned tricks of the tradeworking with mining giant ChuckHawley. Rob, his wife Dixie (CFO ofCalista Corp.), and their combined fami-lies enjoy year-round outdoor sports andtheir McCarthy-area cabin. He’s a strongsupporter of several civic and youthorganizations.
Karl Schaeffer, manager, projectmanagement
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Alaska Anvil, Inc.Alaska Anvil provides high-quality
engineering, procurement, constructionmanagement, project management, andstart-up services for its heavy industryand commercial clients. Located indowntown Anchorage, the Alaska oper-ation is dedicated to upholding thehighest standards of integrity and pro-fessionalism. The parent company, AnvilCorp., serves the western and centralUnited States, Hawaii and Canada.
Karl Schaeffer is a certified projectmanagement professional with an MBAin finance. He has 28-plus years experi-ence in all facets of oil production,transportation and processing, includingsix years managing diverse projects forAlaska Anvil. Karl, l00 percent Irish bymarriage to Bernadette, has three chil-dren – Geoff, Brent and Brielle, allgrown. Community theatre, familycamping trips and the PhiladelphiaEagles keep him a happy man.
All of the companies listed above advertise on a regular basis with Petroleum News
highest-return assets, by sharpening thefocus on North American resource plays“where we have a clear competitiveadvantage.”
In emphatic terms, he said: “It’s notabout size, it’s about value.”
In spring 2002, after the blockbustermerger of PanCanadian Energy andAlberta Energy Co., Morgan declared thatEnCana would be a company “that cancompete with the best in the world, wher-ever it goes in the world.”
At that time EnCana was exploring insuch far-flung regions as the United ArabEmirates, Azerbaijan, Australia and WestAfrica, in addition to two of its productionstrongholds, Ecuador and the British NorthSea.
Morgan said he was determined tobuild the strongest, highest-performanceglobally independent oil and gas company.
“We are not on the kind of treadmillthat a lot of our competitors are,” hegushed. “We believe we can have a com-pany whose asset base is the strongest,whose growth curve is the best, whose costof production is the lowest, whose balancesheet is the best and who operates in coun-tries that are very stable and very soundplaces to be.”
North Sea included Buzzard The North Sea holdings included oper-
atorship of the Buzzard oilfield, theregion’s biggest find in the past decade,plus major stakes in the Scott and Telfordfields, yielding net production of 23,200barrels of oil equivalent per day fromreserves of 129 million boe, and 744,000exploration acres.
The buyer was EnCana’s cross-townrival and fellow Canadian independent,Nexen, which has bolstered its North Seaoutput to 80,000 bpd to establish a fourthcore area in its portfolio, along withYemen, the Gulf of Mexico and theAlberta oil sands.
In the process, the Calgary Factor inBuzzard was merely transferred ratherthan diluted. Nexen now links up withPetro-Canada, which acquired a 30 percentstake in May, although it paid the equiva-lent of 40 percent less for the propertiesthan Nexen.
EnCana is counting on an after-tax gainfrom the North Sea deal of better thanUS$1 billion, which it will channel intodebt repayment and buying back shares.
EnCana’s long-term debt was US$8.04billion on Sept. 30, up almost US$2 billionfrom the end of 2003, largely the result ofits US$2.7 billion takeover of Tom Brown.
Ecuador had lost its luster The Ecuador interests include 78,100
bpd of production, 162 million barrels ofproved reserves and a 36.3 percent stake ina 300-mile pipeline with capacity of450,000 bpd, but what was once seen as ajewel has lost its luster because of a dis-pute with the government over valued-
added taxes on oil exports and clashes withenvironmental activists.
Morgan said several parties have showninterest in the assets, which he said pose agreater political risk to EnCana than any ofits other operating regions, and a deal islikely in 2005.
Gulf of Mexico stakes include interestsin five discoveries and an average 40 per-cent holding in 224 exploration blockscovering 516,000 net acres, but Morgansaid the deepwater is not one of EnCana’score competencies.
Even when those deals are closed,EnCana will be left with some “small pro-grams” in foreign fields, such as offshoreBrazil, Chad,
Oman and Qatar, which Morgan saidcould “create some upside potential,” buthe left no doubt that all will have to paytheir way on the same terms as the NorthAmerican operations.
Against the flow He said EnCana’s decision to go against
the flow by the major Canadian-controlledcompanies, including Petro-Canada,Nexen, Talisman Energy and CanadianNatural Resources, all of whom are scout-ing for international opportunities, wasbased on EnCana’s view that “our interna-tional activities became optional.”
“We think we are in the best business— North American natural gas — that youcould possibly be in,” he said.
Conventional North American produc-tion has entered what Morgan described asa “classic period of increasing costs andaccelerating declines. We expect thatonshore North America’s future will bedominated by unconventional tight gasand oil sands, which we classify asresource plays.”
That, in turn, requires “unconventionalthinking,” Morgan said, noting that in con-trast to conventional reservoirs, resourceplay decline rates and costs typicallydecrease and cumulative booked reservesincrease over time.
He said EnCana, prior to and since itscreation, has accumulated NorthAmerica’s strongest resource play positionto become the continent’s No. 1 gas pro-ducer.
A key element of the strategy isMorgan’s belief that there will be only onesignificant addition to imported liquefiednatural gas in the next five years, while gasfrom the Mackenzie Delta is five to sixyears away and the North Slope is at least10 years off.
He said EnCana’s North Americanposition is “so strong and so sustainableand the returns are so good” that thecompany can afford to “go back to ourroots … where we can create the greatestvalue.” ●
18 PETROLEUM NEWS • WEEK OF NOVEMBER 7, 2004THE REST OF THE STORYcontinued from page 1
ENCANADoubts persist for Nova ScotiaIt was a day for Nova Scotia to finally soak up the warmth of a groundbreaking at its
first liquefied natural gas terminal.Anadarko Petroleum brought hope to the province Oct. 28 when it turned the sod at
Bear Head for a C$450 million LNG facility that is scheduled for start-up in late 2007and achieve peak output of 1 billion cubic feet per day of gas.
“Nova Scotia is turning the corner on yet another exciting chapter of our growing nat-ural gas industry,” Premier John Hamm said at the ceremony.
Yet, in less than 24 hours, there was the feeling in some quarters of a cold shower.In announcing that EnCana was pulling out of the British North Sea, Ecuador and the
Gulf of Mexico, Chief Executive Officer Gwyn Morgan said the giant independentviewed “offshore natural gas as not consistent with our real focus on a North Americanonshore resource-play strategy.” That was interpreted by some as trouble for NovaScotia’s Deep Panuke field, which was once anticipated to start producing in spring 2005at 400 million cubic feet per day, giving Nova Scotia a second gas project after Sable.
(Deep Panuke is actually a shallow-water play. It inherited its name because the gaswas found in 1999 under an oil field that has since been abandoned).
The Deep Panuke project has been on hold for almost two years, giving EnCana achance to improve the economics by drilling for more reserves and seek faster regulato-ry approval.
EnCana wants Deep Panuke on stream But Morgan was emphatic that his company wants to get the 930 billion cubic foot
field on stream.He also said that “I can’t tell you that over the real long term, if it does come on
stream, that we’ll continue to own it.”Since early 2003, EnCana has entered discussions with ExxonMobil, Sable’s opera-
tor, and Shell Canada to explore ways to share infrastructure.That has generated rumors that ExxonMobil might buy Deep Panuke to prolong the
rapidly depleting Sable reserves.Bolstering that prospect is a well drilled earlier this year by a partnership of
ExxonMobil 30 percent, Imperial Oil 30 percent and Shell Canada 40 percent, that wasabandoned “after encountering non-commercial quantities of hydrocarbons.”
But that well has the advantage of being a step-out from Deep Panuke.EnCana spokesman Alan Boras told Petroleum News Nov. 1 that EnCana continues
to explore a “variety of ways to make Deep Panuke as economically robust as possible,”although he declined to be more specific.
He noted that the infrastructure exists with Sable, partly because the dynamics havechanged since that project came on stream (with reserves and output shrinking), open-ing some space on the Maritimes & Northeast Pipeline.
Boras said EnCana’s hope is to capitalize on Deep Panuke and for now is “not rulingout anything.” Meanwhile, EnCana is sitting on six exploration licenses carrying workcommitments of C$48.2 million that are due to expire Dec. 31, 2004, and two otherswith combined commitments of C$86.3 million that expire Dec. 31, 2006.
Boras said EnCana is not currently prepared to discuss its intentions for those licens-es, even with time fast running out for the first batch.
Given the fading prospects, Paul McEachern, managing director of theOffshore/Onshore Technologies Association of Nova Scotia, said he would sooner seeDeep Panuke sold rather than retained by a company that has no interest in moving it tocommercial production.
—GARY PARK
“We think we are in the bestbusiness — North Americannatural gas — that you could
possibly be in.” —EnCana CEO Gwyn Morgan
