exploration & production federal agencies in alaska gear ... · steven breaks silence on anwr 3...

I N S I D E

Steven breaks silence on ANWR 3

Don’t forget Canada’s Arctic oil 8

Ward Whitmore to head Yukon Pacific 4

North Slope, Beaufort Sea lease sale map 9

RCA okays Unocal-Enstar gas sales deal 7

Gas policy council offers recommendations 12

One of Alaska’s most daring frontier explorers— and the company that discovered theNorthstar field — is back. Shell Explorationand Production Inc., the U.S. E&P arm of the

Royal Dutch/Shell Group of Companies, was oneof two high bidders in the state’sfourth North Slope areawide leasesale on Oct. 24.

Houston-based Shell Explor-ation bid on 13 leases and washigh bidder on 10, committing a

total sum of $2.4 million. The company’s tracts areat the southern edge of the sale area south of theColville River area and Kuparuk. (See sale map onpage 9.)

Tract 109, on which Shell bid $297 an acre for atotal bonus bid of $1,710,720, was the highest bidper tract at the sale. It is at the southern end of agroup of tracts held by Phillips Alaska Inc. andChevron between the Itkillik and Kuparuk rivers.

Shell Western — which had a piddling 320-acrestate lease position prior to Oct. 24 — bowed out ofAlaska in 1999 when it sold the last of its majorassets, the Middle Ground Shoal field in CookInlet, to Cross Timbers Oil Co. (now XTO EnergyInc.).

Following the Sept. 11tragedy, a shift occurred inhow Americans viewed theirincreasing reliance on oil and

gas imports from foreign coun-tries.

Polls assessing national opin-ion about oil and gas in theArctic National WildlifeRefuge, for example, showedgrowing public support fordrilling.

C o n c e r nthat long-timeally SaudiArabia, suppli-er of approxi-mately 16 per-cent of the United States’ crudeoil, was politically volatile lentweight to the Bush administra-tion’s position that nationalsecurity was tied to producing

more oil and gas in this countryand being less dependent onenergy imports.

5 to 20 years to production

So, what is the U.S. govern-ment doing to stimulate explo-ration and production in one ofits most energy prolific states?

Lots, Cam Toohey told PNA.Toohey is special assistant to the

Secretary of the Interior forAlaska.

“We are working to gainaccess to lands that, for the most

part, have been closed to oil andgas — or recently opened. …We’re working exceedinglyhard to open the coastal plain ofANWR (see update on page 3),which would have the most sig-nificant impact on domestic oilproduction if allowed to pro-ceed,” he said. “If our estimatesare correct, the amount of oilfrom ANWR will be about the

Vol. 6, No. 15 $1 • www.PetroleumNewsAlaska.com Alaska’s source for oil and gas news Week of November 4, 2001

■ A N A L Y S I S

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

“Let every nation know, whether it wishesus well or ill, that we shall pay any price,

bear any burden, meet any hardship, supportany friend, oppose any foe, to assure the sur-

vival and success of liberty.”

—JOHN F. KENNEDY

Alpine facilties might be expanded

Phillips Alaska Inc. is the operator of the Alpine field, pictured here.

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a In

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Anadarko Petroleum Corp. said in its third quarter opera-tions report that it expects Alpine's facility to be expanded to135,000 barrels per day, with the expansion to be completed inmid to late 2003.

Anadarko said the Alpine field averaged 94,000 bpd in thethird quarter and continues to set production records, produc-ing more than 103,000 barrels during a single day, Sept. 25,and averaging more than 97,000 bpd in July.

With higher than expected production from Alpine and newproduction anticipated from satellite fields, Alpine's facility isexpected to be expanded to 135,000 bpd by mid to late 2003.

Anadarko also said the development drilling rig has beenmoved to Pad 2. One of the first wells to be drilled was AlpineWest, a step out well to identify the western boundary of the

see ALPINE page 13

Ahmaogak says kill Donley billor lose North Slope Borough’ssupport for energy projects

Recent attempts in the stateLegislature to cap the bonding authorityof the North Slope Borough will preventany new public construction projects andmake it nearly impossible to repair andmaintain existing infrastructure, NorthSlope Borough Mayor George Ahmaogaksaid at the Oct. 25 meeting of the AlaskaSupport Industry Alliance in Anchorage.

Ahmaogak said a handful ofAnchorage and Fairbanks legislatorshave sponsored “bills to cut the legs out from under the NorthSlope Borough.”

“They have identified us as a target, an enemy, and they’renot afraid to say so,” Ahmaogak said.

The mayor said SB 186, which was sponsored by Sen. DaveDonley, would siphon away $320 million of local money from

George Ahmaogak

see DONLEY page 13

By Kay CashmanPNA Publisher

Federal agencies in Alaska gear upto meet U.S. energy needsBLM gets money from Washington for Northwestern NPR-A pre-sale work;MMS moves forward with OCS lease program; Toohey says stateregulatory policies critical to federal leasing programs’ success

see ENERGY page 14

Cam Toohey, assistant tothe Secretary of the Interiorfor Alaska

“It’s the earliest we havehad a budget approved in

several years. Oct. 1 is thestart of our fiscal year butwe generally don’t get ourprograms funded until laterin the calendar year. … It’sgreat to get it now.” —Ed

Bovy, BLM

Forr

est

Cra

ne

A wait and see game: Shell returns By Kay Cashman

PNA PublisherOn Deadline: Northstaroil moves to TAPS

By Kristen NelsonPNA Editor-in-Chief

Oil has begun flowing from the Northstaroil field in the Beaufort Sea off Alaska.

Interior Secretary Gale Norton and hersenior advisor for Alaska affairs, DruePearce, announced first oil from the BPExploration (Alaska) Inc. project Nov. 1.

Northstar thus becomes the first outer con-tinental shelf development project since fed-eral offshore leasing began in 1976 offAlaska, Interior Department officials said.

The Joint Pipeline Office told PNA that BPstarted oil flowing down the Northstarpipeline at 5 p.m. Oct. 31. JPO said BP antic-ipated oil arriving at pump station No. 1 at 6p.m. Nov. 1.

"We're producing right now from a singlewell," BP spokesman Ronnie Chappell toldPNA Nov. 1. He said the current rate is about3,000 barrels a day, "and we will be rampingup production and bringing on another wellwhen we think it's appropriate to do so."

Chappell said the production rate will

see NORTHSTAR page 13see SHELL page 13

ON DEADLINE2 Petroleum News • Alaska Week of November 4, 2001

The Alaska Rig Report as of 10/31/01, active drilling companies only listed.

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

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

Cook Inlet Basin-Onshore

Kuukpik / H & R DrillingRigmasters 850 9 Pretty Creek Unocal

Inlet Drilling AlaskaTaylor Rig Glacier Rig 1 Grassom Oskolkoff #2 MarathonInlet Drilling Alaska/Cooper ConstructionKremco 750 CC-1 Stacked/Tyonek AvailableNabors Alaska DrillingNational 154 Stacked/Kenai AvailableWilson 120 158 Stacked/Beluga AvailableNational 110-UE 160 (SCR) Stacked/Kenai AvailableContinental Emsco E3000 273 Anchor Pt. Phil l ips

Cook Inlet Basin-Offshore

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

Bering Sea-Port ClarenceSeatankers, Inc.Dreco 147 SDC-1 Stacked/Port Clarence Fairweather

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

The Rig Report was prepared by Dan Wilcox

Rig startups expected in the next 6 months:

Akita EqutakRig 63 startup expected Dec. 15 on Mackenzie Delta-Onshore

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

Nabors Alaska DrillingRig 33E expected to resume November 2001 at NorthstarRig 2-ES expected to resume in November 2001 at Prudhoe Bay

UnocalRig 58A startup expected June 2002 on King Salmon Platform

Phillips Alaska Inc.

Doyon Drilling rig, photo courtesy Judy Patrick

ON DEADLINEPetroleum News • Alaska 3Week of November 4, 2001

ON DEADLINE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3FINANCE & ECONOMY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5EXPLORATION & PRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . .7LAND & LEASING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8ARCTIC GAS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11

Index

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Petroleum News Alaska, ISSN 10936297, Week of November 4, 2001 Vol. 6, No. 15

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Stevens breaks silence on ANWRSen. Ted Stevens took the Senate floor Oct. 31 and urged the Senate to recog-

nize the opening of the Arctic National Wildlife Refuge to oil exploration as vitalto national security. Stevens has been largely absent from jawboning on the issuefollowing removal of the Energy Security bill from the Energy Committee byDemocratic leadership. The timing of the comments may indicate Stevens thinksSenate action on ANWR is imminent.

Stevens noted that among national security issues facing the Senate, ANWRalone suffers the threat of filibuster, and further noted that in 1973 when the Senatedebated the right of way for the trans-Alaska pipeline, it was with a tacit under-standing that any item dealing with national security would not be filibustered.

Stevens also made a connectionbetween ANWR and other issues.

“Economic stimulus, health care,transportation — all are tied to energyand oil,” he said.

ANWR proponents in the Senate areeyeing an Economic Stimulus bill expect-ed to reach the floor soon as a vehicle tobring an energy discussion to the fore-front in the absence of a comprehensivebill from Senate Majority Leader TomDaschle, Arctic Power in Washington,D.C., told PNA.

Sen. John F. Kerry, D-Mass., criticized the strategy in an Oct. 31 press confer-ence. “They threaten to attach it to every piece of legislation before Congress,”Kerry said. “They say it’s security; it's not. They say it's stimulus; it's not.”

“Before September 11th, we believed in protecting the Arctic National WildlifeRefuge. We still believe it — and we say that knowing that drilling there will donothing to make us any safer, will do nothing to make our economy stronger forthe working men and women hurting today.”

Stevens, however, offered a study just completed by the AmericanPetroleum Institute that says transporting oil from the ANWR coastal plainwould require construction of 19 tankers to transport the oil to the West

WASHINGTON D.C.

see ANWR page 4

Among national security issuesfacing the Senate, ANWR alone

suffers the threat of filibuster, andfurther noted that in 1973 whenthe Senate debated the right of

way for the trans-Alaska pipeline,it was with a tacit understanding

that any item dealing withnational security would not be

filibustered.

Coast. With 2,000 direct construction jobs and 3,000 support jobs created pership, more than 90,000 new jobs would be created in the U.S. shipbuilding indus-try alone.

Stevens closed with words he used in debate over the trans-Alaska pipeline in1973.

“We cannot afford to bury our heads in the snow and freeze, nor must weallow our economy and the jobs of thousands to be endangered while we standidly by,” he said, adding, “It was true then and it is even more true now.”

Alaska’s worldwide exports fell 3.9percent to $2.5 billion in 2000 due togreater amounts of North Slope oilshipped to refineries in the United

States rather than being exported to mar-kets overseas, according to the AlaskaDivision of International Trade andMarket Development. Oil, gas and coalexports in 2000 were $572 million versus$722 million in 1999.

The division said that in previousyears BP Exploration (Alaska) Inc. hadbeen the state’s major exporter of oil, butin 2000 the company sent a greateramount of its production to West Coastrefineries acquired in its merger withARCO.

“While this shift in markets will notmake any appreciable change in employ-ment or revenue to the state, it willimpact the bottom line of the state’s inter-national trade statistics,” said Greg Wolf,state director of international trade and

market development. Oil and gas shipments to Japan,

Alaska’s number one export partner,increased from $359 million in 1999 to$401 million in 2000. Oil and gasaccounted for 30 percent of Alaska’sshipments to Japan, following seafood,which represents 54 percent of the state’sexports to the country. Japan buys 100percent of the state’s LNG exports, andhas received shipments from Nikiskisince 1969 without interruption. LNGshipments rose slightly in 2000, to $145million.

Japan is the number one foreign buyerof crude oil with $185 million in ship-ments, followed by Korea at $103 mil-lion. Crude oil was 22 percent of exportsto Taiwan, with a value of $10 million in2000. Total Alaska exports to Taiwan fell31 percent, due to reductions in crude oilshipments.

Seafood is Alaska’s leading exportcommodity. Seafood shipments rosefrom $990 million in 1999 to $1.034 bil-lion in 2000. ◆

ON DEADLINE4 Petroleum News • Alaska Week of November 4, 2001

■ F I N A N C E & E C O N O M Y

Alaska exports drop as ANScrude goes to West CoastBP ships oil to refineries gained in ARCO merger, shiftimpacts foreign trade figures but doesn’t affect employmentor state revenue

By Steve SutherlinPNA Managing Editor

SERVICE & SUPPLY/ASSOCIATIONSCrowley reorganizes MarineServices subsidiary

Crowley Maritime Corp. said Oct. 31 that it has reorganized its Crowley MarineServices subsidiary into three operating groups: Ship Assist and Escort Services;Petroleum Services and Energy; and Marine Services.

Tom Crowley Jr., chairman, president and CEO, said the three operating groupswill be more autonomous and able to respond more quickly to customers.

The managers, who report directly to Tom Crowley, are: Steve Peterson, seniorvice president and general manager, Energy and Marine Services; Rob Grune, vicepresident and general manager, Ship Assist and Escort Services; and Bruce Barto,vice president and general manager, Petroleum Services.

Crowley Marine was divided into East Coast and West Coast groups which inmany cases dealt with the same customers and offered the same services, Crowleysaid: "Under this new structure, we will have operating units that will be able toconcentrate on distinct markets and customers without regard to geography."

—Petroleum News • Alaska

New area manager atWesternGeco

Bruce Clulow has been named area manager for WesternGeco LLC, and will bebased at the company’s Anchorage office. Clulow replaces Peter VanBorssun,who is transferring to the company’s London office.

Petroleum Engineers host BBQ The 18th Annual Society of Petroleum Engineers barbecue and raffle will be at

the Petroleum Club Nov. 7. Event proceeds provide scholarship opportunities for Alaska high school and

college students interested in engineering careers. In 2001, the Alaska section ofthe SPE awarded nine scholarships totaling $13,500.

For more information contact: Lyndon Ibele, 564-6327 or Russ Douglass, 565-4269.

ARCTIC GASWhitmore to head Yukon Pacific

The parent company of Yukon Pacific Corp. has announced a new director forthe corporation.

John Snow, CSX Corp. chairman and chief executive officer, said WardWhitmore will be director of project development and will direct day-to-day oper-ation for Yukon Pacific.

Yukon Pacific holds the major state and federal permits and authorizations foran 800-mile natural gas pipeline and liquefaction facility. Under the company'sTrans-Alaska Gas System project, natural gas would move via pipeline from theNorth Slope of Alaska to Valdez, where it would be refrigerated to produce lique-fied natural gas for shipment to Asia.

Whitmore has worked on the project for 12 years. An Anchorage resident since1989, Whitmore joined Yukon Pacific after holding several engineering-relatedpositions with Union Pacific Resources and Phillips Petroleum. He replaces JeffLowenfels.

—The Associated Press

continued from page 3

ANWR

XXXXXXXPetroleum News • Alaska 5Week of November 4, 2001

FINANCE & ECONOMY

CANADAPetro-Canada net slides

Slumping prices and production brought Petro-Canada profits down 35 percentin the third quarter to $149 million (Canadian) from C$229 million in the thirdquarter of 2000.

Overall production totaled 190,800 barrels of oil equivalent, a decline of 6 per-cent from the 203,000 barrels daily in the period a year earlier. Upstream profitsslid by a third to C$125 million from C$185 million. Total refined sales were vir-tually unchanged from a year earlier, but margins slid, bringing profits down athird to C$50 million from C$74 million.

Revenues were C$2.07 billion, down from C$2.43 billion a year earlier.Upstream revenues dropped to C$415 from C$521 million in the 2000 quarter,including sales to downstream segments of the company. Downstream revenueswere C$1.84 billion for the quarter, down from C$2.06 billion a year earlier.

—Allen Baker

CANADAAnadarko takes hefty write-downon Canadian reserves

Anadarko Petroleum Corp. has become the first major energy company inCanada to swallow the medicine and take a write-down against its Canadian oiland gas reserves because of low commodity prices.

The Houston-based company, one of the world's largest independent E&Ps,said it took a write-down of US$464 million in the third quarter, much stemmingfrom its February takeover of Calgary-based Berkley Petroleum Corp. for $1.03billion.

That deal gave Anadarko an estimated 95 million barrels of oil equivalent inproven reserves, of which gas accounted for about 855 billion cubic feet.

Anadarko also has other Canadian assets in Western Canada, the MackenzieDelta and off the East Coast, including its June acquisition of GulfstreamResources Canada Ltd. for $137 million.

“We continue to be enthusiastic about our business in Canada and this write-down will not have a significant affect on our operations there,” said Anadarkochairman and chief executive officer Robert J. Allison.

He said the current low gas prices donot represent what the market believesthe assets are worth.

“This write-down effectively valuesour Canadian proved reserves at less thanC$0.60 per thousand cubic feet of gasequivalent, which is about half what com-panies have recently paid for Canadianreserves,” said Allison.

Under Canadian regulations, write-downs are usually postponed until as close as possible to year-end and, followingacquisitions, there is a grace period of up to two years.

Victor Vallance, a Toronto analyst with Dundee Securities Corp, said that withgas prices where they are, some companies which have made recent takeovers“may have to take some pretty severe write-downs on those acquisitions. So I thinkthey may try and wait it out and hopefully the price of gas will increase down theroad.”

—Gary Park

“We continue to be enthusiasticabout our business in Canada and

this write-down will not have asignificant affect on our

operations there.” —Anadarkochairman and chief executive

officer Robert J. Allison

■ C A L I F O R N I A

Unocal earnings drop despitehigher productionAlaska operations contributed $17 million in profits

Unocal Corp. earnings dipped 46 per-cent for the third quarter to $102million as prices weakened and thecompany poured more money into

its infrastructure. The company made$190 million a year ago.

But the company, based in ElSegundo, Calif., boosted capital spendingsignificantly in the quarter. Unocal put$437 million into exploration and otherimprovements in its operations, com-pared with $314 million spent in that areaa year earlier.

And production volumes were up.Worldwide production averaged 506,000barrels of oil equivalent daily, up 8 per-cent from 470,000 a year earlier.

The figure was down from the secondquarter’s 516,000 barrels daily. And thenet result for the third period wasnowhere near the second quarter’s $247million in after-tax profits.

The decline came as petroleum pricesdropped sharply. Unocal’s average pricefor liquids was $22.37 per barrel, downfrom $27.45 a year ago. Natural gasbrought $2.85 per thousand cubic feet,down from $3.60 in the year-ago quarter

By Allen BakerPNA Contributing Writer

see UNOCAL page 6

and $4.62 in the second quarter of this year.Revenues from continuing operations

were $1.58 billion in the quarter, down37 percent from the 2000 period.Reduced crude oil trading made up partof the difference, with the lower pricesalso contributing.

Unocal’s Alaska operations con-tributed $17 million in profits, down from$22 million in the year-ago quarter,which included operations at the Nikiskifertilizer plant sold to Agrium Inc. inSeptember 2000.

Alaska gas production down

Alaska’s liquids production held fairlysteady at 26,000 barrels daily. The figurewas 25,000 a year ago and 24,000 in thesecond quarter.

Gas production slid, however, to 83million cubic feet a day from 93 millionin the second quarter and 128 million ayear ago. Unocal did get a price increaseon the gas, however, receiving $1.57 perthousand cubic feet instead of the $1.20of other recent quarters.

The company predicts profits will con-tinue to slide in the fourth quarter, withan estimate of 25 to 35 cents per share,compared with the third quarter’s 52cents before adjustments. ◆

President Hugo Chavez said Oct. 29that the Organization of PetroleumExporting Countries is willing to cutproduction to bolster prices if inde-

pendent producers cooperate with deci-sion.

Chavez said he secured support for aproduction cut from Saudi Arabia, Libyaand Algeria during recent visits to thosecountries. He added that those nationsand Venezuela support a cut “as long aswe coordinate with non-OPEC coun-tries.”

“In OPEC, we are willing to cut,”Chavez said during a late night speechbroadcast nationally. “It would be a tragedyfor our countries ... if a price war erupts thatcould run oil (prices) into the ground.”

Earlier Oct. 29, Venezuelan OilMinister Alvaro Silva Calderon insistedindependent producers must take “con-crete steps” to defend oil prices, whichhave been sliding since the Sept. 11 ter-rorist attacks in the United States.

OPEC is trying to convince indepen-dent producers to trim or freeze output in

the event of an OPEC cut at the Nov. 14ministers' meeting in Vienna.

Chavez returned from a foreign tour torally OPEC and independent producersinto defending prices. Chavez, who hassuggested a cut of 1 million barrels a day,has warned that an OPEC cut could beineffective without support from inde-pendent producers.

Major non-OPEC producers, includingMexico, Norway and Russia, have shownreluctance to commit to any OPEC effortto boost prices. Mexican President VicenteFox said Oct. 28 “there will be no produc-tion cut at this moment” by Mexico's state-owned oil company, Pemex.

The average price of crude in OPECcountries was $19.18 a barrel Oct. 26; ithas been below the group's target rangeof $22 to $28 a barrel for more than amonth.

On Oct. 29, crude oil futures rosemodestly at the New York MercantileExchange as traders greeted with someskepticism reports that major oil produc-ers are considering cutting output. Lightsweet crude for December deliveryended at $22.15 a barrel, up 12 cents. ◆


UNOCAL

FINANCE & ECONOMY6 Petroleum News • Alaska Week of November 4, 2001

■ V E N E Z U E L A

OPEC willing to cutproduction if independentproducers cooperate

By The Associated Press

CANADALower gas prices squeeze AlbertaEnergy

Alberta Energy Co. Ltd. reported record gas sales for the third quarter, but dra-matically lower prices cut into profits. The company recorded earnings of $190million (Canadian), down 21 percent from the figure a year earlier.

Third-quarter daily gas sales were 1.4 billion cubic feet, up 27 percent from thefigure a year earlier. The figure is up a whisper from the second quarter, but prof-its dropped from C$215 million then. Meanwhile, AEC injected 70 million cubicfeet daily into storage for the quarter, getting ready for the winter heating season.That brings stored reserves to 22 billion cubic feet.

AEC got an average of C$3.37 for its gas in the third quarter, down 37 percentfrom a year earlier. With the lower prices for its gas , the company chose to per-form maintenance projects that reduced volumes about 50 million cubic feet daily.

AEC’s oil and gas liquids production rose 13 percent over the prior year’s thirdquarter to 136,000 barrels daily.

In the quarter, Alberta Energy drilled 173 wells in North America, 149 of themin western Canada, and had a 99 percent success rate. The company also drilled adozen wells in Ecuador, all successful. Revenues were C$1.52 billion, down 4 per-cent from the prior year’s third quarter, when the company took in C$1.58 billion

—Allen Baker

MICHIGANSemco, Enstar’s parent, losswidens in quarter

Semco Energy, the parent company of Alaska’s Enstar, reported a net loss of$6.6 million for the third quarter, compared with a loss of $4.7 million in the samequarter of 2000. Temperatures in Enstar’s service area in Alaska were 5 percentwarmer than normal in the third quarter, but that was balanced out by cooler-thannormal conditions in Michigan, where the company also sells gas.

Nevertheless, the gas distribution business swung from a $1.1 million operat-ing profit in the 2000 quarter to a $2.2 million operating loss in the third quarterof this year. The company bought gas with a higher thermal content this year, thecompany said, and there was more unaccounted-for gas.

The Farmington Hills, Mich., company’s other major division, engineering andconstruction services, had operating income of $3.4 million, down a bit from $3.5million in the 2000 quarter. Minor amounts came from Semco’s propane andinformation technology segments.

Revenues rose to $80.8 million from $70.3 million, a gain of 15 percent.In conjunction with its earnings, Semco’s management under new president

Marcus Jackson announced the company was restructuring some of its business-es, including divestiture of the engineering services sector.

—Allen Baker

TEXASAnadarko writedown triggers loss

Anadarko Petroleum Corp. reported a loss of $270 million for the third quarterafter chopping the carrying value of gas properties in Canada and South Americaby $483 million. Without those writedowns, earnings were $213 million, stilldown 14 percent from $247 million a year earlier.

Revenues dipped 4 percent to $1.74 billion from $1.82 billion even though pro-duction rose significantly.

Volume was up 29 percent to 558,000 barrels of oil equivalent daily from434,000 in the same quarter a year earlier. That figure was down from 570,000equivalent barrels in the second quarter, when Anadarko earned $401 million. Thevolume drop was attributed to the sale of 20,000 barrels a day of low-margin pro-duction in Guatemala.

And Anadarko’s bottom line was a far cry from the $656 million in profits thecompany generat-ed back in thefirst quarter.

Company offi-cials put on agood face any-way. Houston-based Anadarkopulled up more oil and gas than expected due to higher production at the Alpinefield in Alaska, where Anadarko has a 22 percent stake, and in Algeria, accordingto Robert J. Allison Jr., Anadarko chairman and chief executive officer. Increasedrecovery of natural gas liquids also helped the operating results, which he calledbetter than expected.

With natural gas bringing an average of $2.89 per thousand cubic feet, insteadof the $3.83 of a year earlier, it was tough to keep profits up. Oil brought an aver-age of $21.66, down $6.02 per barrel.

Anadarko also poured $739 into capital spending, up 40 percent from the $526million the company spent in the year-earlier quarter.

But the money is being redirected a bit, away from pure natural gas prospects.“In response to relatively weak natural gas prices and higher service costs over

the last few months, we have slowed the pace of U.S. gas development drilling andshifted some of our capital to concentrate on more high-potential exploratorydrilling and oil-prone projects,” Allison said.

The company was running 94 of its own rigs in July, and now has just 74 work-ing. But there are four deep-water wells in the Gulf of Mexico that are goodprospects, Allison said.

He predicts production in the current quarter will be about even with the third-period figures.

—Allen Baker

XTO boosts earnings on bigproduction gain

XTO Energy Inc., formerly Cross Timbers Oil, earned $70.3 million in the thirdquarter. That was more than double the year-ago figure of $31.8 million, makingXTO one of the few production companies to show an increase.

Price-hedging moves contributed to the strong showing, but the company stillcouldn’t reach the second-quarter profit of $90.5 million.

While most companies received far less for their gas in the recent quarter, XTOof Fort Worth, Texas, received an average of $4.08 per thousand cubic feet, up 11percent from the third-quarter 2000 average of $3.68. The company earlier lockedin a price of $4.30 for 90 percent of its gas through next March.

Gas production rose to an average of 426 million cubic feet daily. That’s up 25percent from the 342 million cubic feet for each day of the 2000 quarter, and alsosignificantly more than the 403 million cubic feet for the second quarter. The com-pany expects to average about 450 million cubic feet in the fourth quarter.

Oil production was up 5 percent from the year-ago figure to 13,309 barrels aday, while natural gas liquids were down a bit at 4,491 daily barrels. Those figuresare expected to remain stable for the rest of the year.

Revenues were up 23 percent over the 2000 quarter, at $197.3 million from$160.5 million. That was still short of the second-quarter revenues of $209 million

—Allen Baker

“We have slowed the pace of U.S. gas developmentdrilling and shifted some of our capital to conentrate

on more high-potential exploratory drilling and oil-proneprojects.” —Robert J Allison Jr.

By Kristen Nelson PNA Editor-in-Chief

Forest Oil Corp. announcedOct. 26 the successfuldrilling and logging of athird well, Redoubt Unit No.

3, at the company's Redoubtdevelopment in Cook Inlet.

Forest said the Redoubt No. 3was drilled to extend the field anddefine the downdip limits of thereservoir in the south fault blockdiscovered by the No. 2 well.

The No. 3 was drilled to atotal depth of 16,940 feet andlogged approximately 436 feetof net oil pay. The company said

drilling extended the reservoir'sdowndip limit by approximately300 feet without encountering

the oil-water contact at totaldepth. Since logs indicatedreservoir quality similar to theNo. 2 well, the No. 3 was notproduction tested for oil.

Forest said it believes the No.3 well will produce at rates sim-ilar to the No. 2.

Results from the RedoubtUnit No. 2 well were announcedin June.

The No. 2 was drilled to atotal depth of 15,325 feet,logged approximately 452 feetof net pay and tested at a stabi-lized flow rate of 1,170 barrelsof oil per day from two intervals

Petroleum News • Alaska 7Week of November 4, 2001

EXPLORATION & PRODUCTION

■ C O O K I N L E T

RCA conditionally approves Unocal-Enstar gas sales agreement

By Kristen Nelson PNA Editor-in-Chief

The Regulatory Commissionof Alaska has conditionallyapproved a natural gas salesagreement between Unocal

and Enstar Natural Gas Co. —an agreement which pegs theprice of Cook Inlet natural gasto Henry Hub futures prices.

The RCA said that Enstarand Unocal characterize the gassales agreement as an “explo-ration contract” because focus ison exploration for new gassources to meet Enstar's needs.While Unocal is confident newgas will be discovered, the com-mission said, “the fields arelikely to be small and the cost ofproduction and transporting thegas to market will be high.”

In an Oct. 25 decision theRCA said it was conditioning itsapproval by limiting the term ofthe agreement to delivery of 450billion cubic feet, limitingUnocal's ability to sell third partygas to 15 percent of the annual

gas volume sole and providingEnstar with a first right of refusalto purchase non-economic gasbefore Unocal may sell non-eco-nomic gas to other parties.

Parties opposing the gas salesagreement told the RCA that itshifts the risk for future CookInlet gas exploration to Enstarratepayers. The RCA said that,while it understands the concern,it finds “that Enstar has identifiedits future requirements and devel-oped a credible compendium ofgas supply contracts to meetthose requirements.”

The RCA said it was satisfiedthat negotiations were at arms-length, and that, with the modi-fications included in the order,the agreement is in the publicinterest.

Price based on Henry Hubfutures

The price in the gas salescontract will be determined

see RCA page 10

■ C O O K I N L E T

Forest Oil pleased with results ofthird Redoubt unit well No. 3 logged 436 feet of net oil pay, a natural gas zone was encounterd

Gary Carlson, Forest Oil Senior VicePresident, told PNA that theRedoubt unit wells were taking 75to 90 days to drill.

see FOREST page 10

WESTERN CANADAFinding, operating costs up

Record oil and gas drilling in Western Canada in 2000 alsoyielded some of the highest reserve-replacement figures posted inrecent years, but those successes were accompanied by a sharprise in finding and operating costs, say two reports by Ziff EnergyGroup.

The Calgary-based consultant said oil replacement jumped to154 percent of production from 86 percent in 1999, due to strongresults in southeastern and northern Alberta and southwesternSaskatchewan. The study said the rate of replacement, althoughshort of the 178 percent to 201 percent in 1996 to 1997, were thethird highest in the past eight years and the reversal of negativetrends in 1998 and 1999.

Heavy oil drilling bounced back in 2000, up 114 percent, whileother oil categories increased by 60 percent to 90 percent. On thegas side, drilling and improved recovery boosted the replacementlevel to 120 percent, helped by a 30 percent gain in medium anddeeper drilling as part of a record 8,926 well completions.

Ziff project manager Razvan Sima said Canadian E&P com-panies are also taking a more conservative approach to theirreserve bookings, now that the Alberta Securities Commission ismoving towards tougher rules after a series of high-profilereserve write-downs in the late 1990s.

The study said the industry average finding and developmentcosts rose to C$8.60 per barrel of oil equivalent, based on a gas-to-oil conversion rate of 6:1 for proven reserves and C$11.40,based on the U.S. standard conversion rate of 10:1.

In a separate study, Ziff said average oil operating costsclimbed 30 percent to C$6.10 per barrel of oil equivalent, at a 6:1conversion rate, from C$4.70 in 1999. The average cost of gasrose 39 percent to C$0.58 per thousand cubic feet equivalent fromC$0.42 in 1999.

Project manager Court Mackid said the sharp rise was a resultof operators scrambling to obtain as much production as possibleduring a period of high commodity prices. “Your marginal costsusually go up when that happens,” he said. But Mackid said thenew price cycle means companies will “have to be very observantof their operating costs,” or they risk draining their resources.

The breakdown for field overheads, contract services andtrucking climbed 47 percent for oil and 28 percent for gas, whilecombined labor and field supervision costs accounted for 18 per-cent of the total compared with 6 percent in 1999.

The biggest oil increase occurred in eastern Alberta whereoperating costs for pumping heavier crudes rose 50 percent. Gasoperations in southeast Alberta and southwest Saskatchewanshowed a 65 percent jump.

Ziff chief executive officer Paul Ziff said that as producers tryto maximize cash flows “reducing operating costs is their quick-est lever,” noting that those who failed to heed warnings in 2000to launch energy efficiency programs “suffered the full impact ofhigher costs.”

—Gary Park

“Exploration is needed inorder to ensure an adequate

supply of gas for Enstarratepayers. The risk

associated with explorationmust be compensated or

exploration will goelsewhere.” —RCA

By Gary Park PNA Canadian Correspondent

In the helter-skelter of debate overArctic gas and pipelines, Canada'sMackenzie Delta-Beaufort Sea oilreserves risk being overlooked, despite

their potential to rival those of Alaska,says a consulting geologist.

Murray Rodgers, with CanadianDiscovery Ltd., said a 1994 GeologicalSurvey of Canada estimate of Delta-Beaufort reserves is likely conservativebecause it has been based solely on drillingto date.

The Geological Survey of Canada putsthe resource at up to 7.2 billion barrels, ofwhich 585 million to 1.44 billion barrelsare discovered, with the remaining poten-tial rated at 4.7 billion to 5.8 billion barrels.

Because the Delta-Beaufort lands sharea close geological similarity to PrudhoeBay and the Arctic National WildlifeRefuge, the ultimate resources could chal-lenge those of Alaska, Rodgers said.

But he conceded, in a speech to arecent Calgary conference, that “frontierareas are notorious for being difficult toquantify in the early stages” and as suchusually generate a “healthy amount ofskepticism.”

U.S. projections have raised ANWR'spotential to 31 billion barrels from 17 bil-lion barrels without any drilling, whilePrudhoe Bay discoveries are estimated at9.5 billion barrels with another 3.5 billionbarrels of remaining potential, he said.

The 237 wells drilled so far in theDelta-Beaufort region have yielded 53discoveries from 20 play types.

Arctic success rate high

Rodgers said there has been a “phe-nomenally high success rate” of 28 percentfrom 130 onshore and 59 offshoreexploratory wells, comparing that withWestern Canada's 25 percent success ratein the last five years.

The major find so far was the 500 mil-lion barrel Amauligak offshore discoveryby Gulf Canada Resources Ltd. (now

Conoco Canada Ltd.) in 1984 during awave of exploration sustained by govern-ment incentives, although reserves havenever reached commercial levels. Very fewof the other finds have exceeded 100 mil-lion barrels, but because of their wide-spread nature they point to high potential indeeper waters, Rodgers said.

He said the region contains four mainplay types: onshore/shallow water, off-shore delta, West Beaufort and deepwater,with the onshore/shallow water play atdepths of about 50 feet being the dominantgas fairway.

The offshore delta, including theAmauligak field, offers the most promisefor oil and could, given its potential to con-tain up to 2.3 billion barrels, produce dis-coveries exceeding Amauligak, Rodgerssaid. Although more oil than gas has beenfound in the deep water, the play may begas prone, he said.

Because only one well has been drilledand tested data is scarce on the WestBeaufort and offshore delta, but the geolo-gy is similar to that of ANWR, Rodgerssaid, adding “watch what happens alongthis trend in the next decade” if drillingstarts on some of the 60 structures definedby seismic coverage. ◆

■ C A N A D A

Don't forget Canada's Arcticoil, says consulting geologist Mackenzie Delta Beaufort Sea oil reserves have potential torival those of Alaska, geology similar to ANWR

EXPLORATION & PRODUCTION/LAND & LEASING8 Petroleum News • Alaska Week of November 4, 2001

Because only one well has beendrilled and tested data is scarce on

the West Beaufort and offshoredelta, but the geology is similar to

that of ANWR, Murray Rodgers said.

Nellie Cournoyea, left, and J.C. Anderson posein front of Akita Equtak Rig. 63. The new rigwill drill two exploration wells in the Arcticthis winter.

Cou

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And

erso

n Ex

plor

atio

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STATEWIDEMMS issues proposed 2002-2007OCS leasing program, DEIS

The U.S. Department ofthe Interior MineralsManagement Service saidOct. 26 that its proposedouter continental shelf oiland gas leasing program for2002-2007 is now available,along with a draft environ-mental impact statement.

MMS said it is proposingto hold 20 oil and naturalgas lease sales in the federalouter continental shelfbetween 2002 and 2007.The proposed programincludes sales in the Gulf of Mexico's Western, Central and part of the Easternplanning areas; and Alaska's Beaufort Sea, Norton Basin, Cook Inlet/ShelikofStrait and the Chukchi Sea/Hope Basin. The proposed program does not includeany areas currently under moratoria or presidential withdrawal.

MMS is required by law to prepare a new five-year program to succeed the cur-rent one that ends June 30, 2002. The planning process began in December 2000with a request for comments and information. A draft proposed program wasissued this July and MMS requested public comments. Those comments have beenconsidered in the development of the proposed program, which will be availablefor comment for 90 days, until Jan. 24.

Comments received will be considered in the development of the proposed finalprogram and final EIS and made available in April 2002 to the president andCongress for 60 days. The new five-year program will take effect on July 1, 2002,if approved by the Secretary of the Interior.

MMS will hold public hearings on the draft EIS in early December. Alaska sales in the 2002-2007 proposed program include: sale 186 Beaufort Sea

2003; sale 188 Norton Basin 2003; sale 191 Cook Inlet-Shelikof Strait 2004; sale193 Chukchi Sea-Hope Basin 2004; sale 195 Beaufort Sea 2005; sale 199 CookInlet-Shelikof Strait 2006; sale 202 Beaufort Sea 2007; and sale 203 Chukchi Sea-Hope Basin 2007.

Editors note: Map provided by Minerals Management Service.

LAND & LEASINGPetroleum News • Alaska 9Week of November 4, 2001

that this possibility is unlikely because theCook Inlet basin is old, fields are produc-ing on a flat or declining basis and do nothave the swing capabilities to meet Enstar'sneeds.

But, Unocal told the commission, “itshould not be prevented from buyingthird party gas to meet Enstar's unmetrequirements.” Unocal said it envisioneda situation where it would take gas fromflat or declining fields or from a one-wellproducer, inject it into storage and thenproduce it at a rate that would matchEnstar's needs. Unocal would be increas-ing the value of the gas through storageand it could then be used to meet Enstar'sneeds.

“Although Unocal believes a prohibi-tion against purchasing third-party gaswould strand a lot of gas that could beused by consumers,” the commissionsaid, “limiting its ability to sell gas to 15percent of the total annual gas volumesold would not affect its ability to insurecertain supply.”

The third change the commissionmade in the agreement was to give Enstarthe first right of refusal of non-economicgas. If Unocal and an independent engi-neer agree that gas production will not beeconomic, Unocal's obligation to pro-duce, deliver and sell gas will be sus-pended as long as production is notexpected to be economic.

The commission said it understandsthat exploration and production of newgas at the contract price may not be eco-nomic, and does not find the uneconomicclause to be unreasonable, but orderedthat “before Unocal sells gas to third par-ties under this provision, Enstar shouldhave a right of first refusal to purchasethe gas at a flatter swing rate.” ◆

annually by using a 36-month daily aver-age of the Henry Hub natural gas futuresand a floor price of $2.75 per thousandcubic feet adjusted for one-half of theinflation rate after 2002.

“Exploration is needed in order toensure an adequate supply of gas for Enstarratepayers,” the RCA said. “The risk asso-ciated with exploration must be compen-sated or exploration will go elsewhere.”

The commission said it weighed “therisk that Enstar will not have an adequatenatural gas supply in the future against ahigher exploration price” and is persuad-ed that Enstar must pay a competitiveprice to attract capital and encourageexploration in Cook Inlet.

Peaking fee part of contract

On any day when Unocal suppliesmore than its pro rata share of maximumdeliverability, Enstar must pay Unocal apeaking rate of $1 per thousand cubic feetin addition to the price for the excess.Unocal and Enstar have told the RCAthat they estimate peaking fees will notexceed $10,000 a year.

Peaking gas covers times when

Enstar's suppliers do not supply all thegas that Enstar customers need on a par-ticular day and allows Enstar to get thatgas from Unocal, at a premium becauseof additional costs Unocal bears to pro-duce and deliver it. RCA said that when aparticular shipper does not supply itscommitted gas to Enstar, the peaking feewill be passed back to that shipper.

Peaking gas also covers times whenthe demand for gas is greater than normaldue to extremely cold temperatures.Enstar can then get additional gas fromUnocal and that peaking fee would bepassed on to the ratepayer throughEnstar's gas cost adjustment.

Other charges

Enstar will reimburse Unocal forRCA-approved tariff charges up to $1 perthousand cubic feet on pipelines con-structed after the effective date of thecontract. The parties must agree to anyreimbursement in excess of $1 per Mcf.

The commission said that its PublicAdvocacy Section argued that such capitalexpenditures should be paid for by Enstarstockholders, not Enstar ratepayers. Butthe commission found no reason to inter-fere with this portion of the agreement.

It said that if new gas is discovered,

new pipelines may need to be built. Thecost of construction and operation ofpipelines are covered in tariffed rates andnew pipeline transportation costs arecapped at $1 per Mcf.

Since the commission must approvethe tariff before these costs may bepassed through to ratepayers, it has anopportunity to determine if the rates arejust and reasonable.

Changes to agreement

On the issue of the length of the gassales agreement, the commission saidthat while having the agreement openended might encourage exploration, italso bound Enstar and Enstar ratepayersindefinitely. Unocal testified that a vol-ume of 450 billion cubic feet created suf-ficient incentive to explore, so the com-mission limited the agreement to deliveryof 450 bcf — preserving the explorationincentive and also providing the commis-sion the opportunity to review whethercontinuation of the agreement is in thepublic interest.

The Public Advocacy Section alsoargued that the agreement would allowUnocal to purchase gas from other sourcesand sell it to Enstar at the higher HenryHub futures contract price. Unocal argued

THE REST OF THE STORY10 Petroleum News • Alaska Week of November 4, 2001


RCA


FORESTin the Hemlock formation. Forest esti-mated that production rate for the well,using artificial lift, will be 3,000 bopd.

Forest said that the No. 3 well alsoencountered a natural gas zone. Logsindicated approximately 40 net feet ofgas pay, which was tested at 8.5 millioncubic feet a day. The company said it isexamining the implications of this natur-al gas discovery, but believes that, at aminimum, the natural gas will reducefield level fuel costs associated with oilproduction.

Forest expects to spud the No. 4 wellwithin the next 30 days. That well will bean attempt to delineate the easternboundary of the north fault block previ-ously discovered by the No. 1 well. Fullfield development of Redoubt Shoal isunder way, Forest said, with first produc-tion estimated to occur prior to 2003.

In recent presentations to analysts,Forest said it is estimating 450 millionbarrels of original oil in place at theRedoubt Shoal unit. At a 25 percentrecovery rate, Forest said, that would be113 million barrels of oil. ◆

Kristen NelsonPNAEditor-In-Chief

The Department of Natural Resourcessaid Oct. 26 that rising interest in a gaspipeline project, coupled with the pos-sibility of an open season for nomina-

tion of pipeline capacity as early asJanuary, has created a unique opportunityfor the state to sell its North Slope royaltygas.

DNR’s Divisionof Oil and Gas issueda preliminary bestinterest finding anddetermination to sellAlaska North Sloperoyalty gas in a com-petitive sale Oct. 29.The Alaska RoyaltyOil and GasD e v e l o p m e n tAdvisory Board will hold a public meetingNov. 13 to discuss the proposed sale andtake public testimony.

DNR will then complete a final find-ing and prepare an invitation to bid,which must provide at least 30 daysnotice to bidders and specify some condi-tions of the royalty in kind gas offeringincluding quantity, length of contract anddelivery point.

There will be a bid opening andbecause there will be multiple bid vari-ables, DNR will evaluate proposals, con-tracts will be drafted and submitted to theroyalty board which will prepare a rec-ommendation to the Legislature.

Tentative dates Dec. 12 for a finalfinding and invitation to bid, bid openingJan. 16, royalty board hearing Feb. 4 andcontracts submitted to Legislature forapproval Feb. 14.

Purchaser would have to provideshipping

The producers also have an interest inwhat the state does with its royalty gas.

Division of Oil and Gas DeputyDirector Bonnie Robson said Oct. 26 thatpurchasers of the state’s royalty gaswould buy at the lease or unit, so theywould be responsible for shipping. But ifthe state lets the producers sell the gasand takes royalty in value, then the pro-ducers must ship the state’s gas. Becauseof that, she said, the state has already had

inquiries from the producers as towhether the state will take its gas in valueor in kind.

Robson told the governor’s AlaskaHighway natural gas policy council accessto in-state gas subcommittee that whilethere could be an open season for a gaspipeline in January, but there is some indi-cation the open season may be pushed back.

If we are not in open season during aroyalty gas sale, that gives the state moretime to work with the bids, if there areattractive bids and room for negotiation,she said. The goal is to get proposalsthrough the royalty board and to theLegislature — which must approve anyroyalty sale — so that the Legislaturewould have a month or so to hold hear-ings and consider the bid.

Robson said bidders can request vol-ume, although in no case, she said, wouldthe state be deposing of 100 percent of itsroyalty gas. Bidders can also propose alength for a contract, she said, but mostinterest now seems to be for shorter peri-ods of time.

Benefits of a sale now

DNR said in the preliminary findingand determination for an ANS royalty gassale that the state is considering an imme-diate ANS royalty in kind gas salebecause “potential buyers are motivatedto bid for RIK gas in order to be able tonominate capacity on the gas pipelineduring an open season” and because “thesale of RIK may contribute to earliercommercialization of ANS gas and thesuccessful completion of a pipeline bybringing additional participants to theopen season.

“Additionally, there is potential forgenerating greater royalty revenues in thebidding process for the opportunity toparticipate in an ‘open season’…” Thestate must receive at least as much forroyalty in kind sales as it would if it took

ARCTIC GASPetroleum News • Alaska 11Week of November 4, 2001

■ N O R T H S L O P E

State goes after opportunityto maximize gas royalty salesFollowing up on interest from potential bidders, DNR issuespreliminary best interest finding, schedules royalty boardmeeting for November

Bonnie Robson, divi-sion of oil and gasdeputy director

“Additionally, there is potential forgenerating greater royalty revenues

in the bidding process for theopportunity to participate in an

‘open season’…” —Department ofNatural Resources

see SALES page 12

ANCHORAGENorth Slope producersgasline study on track

Dave MacDowell, external affairs manager for the North Slope producers gasstudy group, told PNA it was “interesting to note the attention, and to some extent,the surprise generated by the information we released over the past several months.… The (July) update was really more of an interim release of numbers than areport.”

The preliminary numbers provided by the Alaska Gas Producers Pipeline Teamin July indicated that a gas pipeline from the North Slope to the Lower 48 couldcost as much as $15 billion to $20 billion.

Those numbers were rough estimates, MacDowell told PNA Oct. 25. “Thecosts could be as much as 20 to 30 percent higher — or lower. …

“We are still telling people what we have said from the beginning: This projectis not yet economic. It has never been economic. That’s what we’ve been asked todo from the start — find a way to make iteconomic. … That’s why the producers(BP Exploration (Alaska) Inc., PhillipsAlaska Inc. and ExxonMobil) are spend-ing millions of dollars on this. We wantto find a way to make the project eco-nomic,” he said.

The study group’s budget initially was$75 million, but in a September interviewwith team spokesman Curtis Thayer, PNA was told that the costs would exceedthat number. More than 600 people are working on the study, including the 100people assigned to the team by the producers and 500 to 600 people who workedduring the peak of summer field activity for the team’s contractors in Alaska,Canada and the Lower 48.

“We’re still on track to get our engineering and cost data in by the end of theyear. … That’s the culmination of all the work we have been doing. ... At whichpoint we’ll analyze the information and the three companies involved will each dothe same. Following that review, “decisions about potential next steps” will bemade,” MacDowell said.

“We’re working hard to develop an economic project, but we won’t know if wehave one until all the numbers are in,” he stressed.

MacDowell said that a number of things have to come together to make the pro-ject economic. Technology plays an important part in the project’s economics, asdoes “overall risk management.”

Federal regulatory enabling legislation is a “must have,” he said. “It will helpcreate a clear, efficient, regulatory framework. It is an essential part of reducingproject risk and assessing economic viability. …The capital side of this thing ishuge. We have to look at every opportunity to reduce costs,”

Another critical factor MacDowell identified was state fiscal certainty:“Progress on that will be needed. We are in conversations with the state, of course,and hope they will continue.”

“This project is not yeteconomic. It has never beeneconomic. That’s what we’ve

been asked to do from the start— find a way to make it

economic.” —Dave MacDowell

Mar

ti P

eter

son

The Governor's Alaska HighwayNatural Gas Policy Council has spenteight months and hundreds of hoursdeveloping recommendations to pro-

mote an Alaska Highway natural gaspipeline to the Lower 48 that also createsa natural gas business in Alaska.

The policy council unanimously adopt-ed the recommendations of its committeesOct. 31, recommendations which will befinalized for the governor by the end ofNovember. But much of what the councilrecommends depends on federal action.

The council concluded that federal lawneeds to be changed to modernize theAlaska Natural Gas Transportation Act:the state is at the mercy of Congress forthose changes.

The Alaska Highway route, selected bythe president and ratified by Congress in1977, is based on ANGTA. If the Federal

Energy Regulatory Commission receives apipeline application based on the NaturalGas Act, routing and in-state access to gasspecified in ANGTA do not apply.

And even if an Alaska Highway pro-

ject based on ANGTA moves forward,the council said that a new environmentalimpact statement — or a substantial revi-sion of the 25-year old EIS done for theAlaska Highway route — needs to bedone. Another federal action.

Reports adopted unanimously

The gas policy council, reviewed andapproved — with some amendments —recommendations from its five commit-tees at its Oct. 31 meeting.

The Alaska hire-buy-build committeerecommended Alaska hire language similarto that used in the BP-ARCO merger “char-ter commitment”, including a quarterlyreport to the Department of Labor. Thecommittee noted that the record in Alaskaon local hire litigation is not encouraging.“We believe it will be difficult to constructlocal hire legislation that will withstandchallenges under the U.S. and AlaskaConstitutions…” But the biggest problem,said committee chair Mike Navarre, is thatthe size and scope of the project is largeenough that an already taxed work forcewill be further taxed.

The environmental considerationscommittee recommendations, presentedby Brian Davies for committee chair PegTileston, included a recommendation forstudy of “lessons learned” from the

design, construction and operation of thetrans-Alaska oil pipeline and a “rigorousenvironmental review” — either a sup-plemental EIS building on the EISs donefor ANGTS or a full EIS using informa-tion from the original work.

Anchorage Mayor George Wuerchobjected, saying that two very compre-hensive studies were done in the 1970s.Davies said the committee had discussed

this at length, and concluded it was veryhard to make the case credibly to just usea 25-year old EIS.

State ownership notrecommended

The state pipeline ownership and taxstructure committee concluded thepipeline is economically feasible for cer-tain investors and recommended that it beundertaken with private financing, saidcommittee chair Bill Corbus. The com-mittee is also recommending that whilestate tax policy could play a role inpipeline development, but believes it ispremature to decide how to use that tooluntil the project and its ownership aremore defined.

Corbus said the committee believesthe private sector can build a gas pipelinewithout state help. If the producers don'tbuilt it, he said, the state should look atother options.

The federal-international action com-mittee recommended modernizing theAlaska Natural Gas Transportation Act.Committee chair Charlie Cole noted thatthe policy council voted agreement to 10policy goals for federal legislation at itsSept. 25 meeting.

In-state use, access

The access for in-state gas use andfuture opportunities committee, chairedby Ken Thompson, submitted 17 pages ofrecommendations and conclusions, cov-ering a range of issues from in-state gasaccess to royalty in kind to netback pric-ing valuation.

The committee recommended that thestate establish a natural gas group withinthe Department of Natural Resources, andThompson told the council that the statewould benefit from expert advice on awhole range of natural gas issues, startingwith the open season for a gas pipeline.

The committee also recommended ajoint state-federal board at the FERC toadvise that commission on tariff and accessissues for the Alaska portion of a gaspipeline.

Federal legislation concerns

Council member Jack Roderick saidthat three of the committees made recom-mendations which required joint state-federal agreement, with changes in lawsuch as a joint state-federal board to makerecommendations for the Alaska portionof the line to the Federal EnergyRegulatory Commission.

“My guess,” he said, “is that it will behard to get through Congress.” He suggest-ed that the attorneys check on the state'soptions if FERC receives an application inJanuary under the Natural Gas Act. ◆

ARCTIC GAS12 Petroleum News • Alaska Week of November 4, 2001

royalty in value. DNR said that companies faced with

securing a gas supply as a precondition toparticipation in an open season haveapproached the state with proposals tobuy its ANS royalty gas in kind, some formarketing in the Lower 48 and some forpotential in-state petrochemical plants.Companies with unexplored leases seek

the state’s royalty gas to ship before theirown gas is developed. The state alsoreceived a proposal last December to sellits gas to fuel a power plant for a largeInternet data center on the North Slope,and has been directed by legislative reso-lution to consider royalty gas sales forthis purpose.

The state said it may also attract bidsfrom other in-state buyers who would usethe gas on the North Slope or for in-stateutilities or industrial uses along thepipeline route. ◆


SALES

■ A N C H O R A G E

Federal action key to gas policy council recommendations Gas pipeline should be built with private financing, say recommendations; new or supplemental EIS required; councilmembers worried about federal influence if Natural Gas Act rather than Alaska Natural Gas Transportation Act prevail

By Kristen NelsonPNA Editor-in-Chief

… the committee believes theprivate sector can build a gas

pipeline without state help, but, ifthe producers don't built it, the

state should look at other options.—Bill Corbus, chair, state pipeline

ownership and tax structurecommittee

Council member Jack Roderick saidthat three of the committees maderecommendations which required

joint state-federal agreement, withchanges in law such as a joint

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BP’s assets in Alaska?

Traditionally, Shell moves into an oiland gas province in a big way or not atall. A $2.4 million investment is a smallinvestment for this energy giant, one ofthe three largest oil companies in theworld.

In 1997, Rich Hansen, public affairsmanager for Shell Exploration then andnow, told PNA that the main reason Shellwas pulling out ofAlaska after almost 35years was because,“Shell has such a smallposition, land holdings,in Alaska. It’s notstrategic to take a smallposition a zillion milesfrom Houston anddevelop it. You need acritical mass to make itstrategic; you need potential for growthand expansion.”

So what’s next? Is the purchase ofBP’s assets in Alaska a possibility?

In an interview following the Oct. 24lease sale, Hansen would not comment onShell’s acquisition plans or strategy butwhen asked if Shell Exploration was inacquisition mode, he said, “Yes. End ofcomment.”

BP Exploration (Alaska) Inc. appearsto be in harvest, versus even minor explo-ration, mode right now. Officially, thereason is “reorganization.” But BP hashad three significant negative experiencesin Alaska in the last two years: 1. permit-ting problems with the state of Alaska onits offshore Beaufort Sea Northstar devel-opment, which contributed to major costover-runs and a limited drilling season; 2.reservoir problems at the Badami projectwhich resulted in lower oil productionthan anticipated, and; 3. governmentopposition to BP buying ARCO Alaska’sassets in its acquisition of ARCO.

According to former AlaskaDepartment of Natural ResourcesCommission John Shively, Shell was oneof a few companies that expressed inter-est in acquiring ARCO Alaska Inc.’sassets in 1999 when it became clear thefeds were not going to allow BP to buythe assets as part of its purchase ofARCO.

BP’s Alaska assets would give Shell apiece of the trans-Alaska pipeline andsought-after North Slope facilities.

Other speculation has centered on abid from Shell for Anadarko PetroleumCorp. or Alberta Energy Co., both Alaskaleaseholders. Both hold acreage nearShell’s newly acquired North Slopeacreage. And both, like Shell Canada,hold leases in the Mackenzie Delta. Shell,

in fact, is one of the big five leaseholdersthere, has petrochemical interest inAlberta and is a player in the Alberta oilsands.

But Rich Hansen said, “Don’t put toomuch stock in these connections.”

Gregg Nady heads Alaska group

Speculation aside, Hansen said the fol-lowing: Shell’s Alaska group consists of10 people, all based in Houston, andheaded Gregg Nady, Alaska regionalmanager. Charlie Harvie is the group’sonshore exploration manager.

“We have no plans at this time to openan office in Alaska, but we are making theairlines and hotels happy,” Hansen said.

Oil is Shell’s primary objective for theleases it acquired in the Oct. 24 sale, “butbeggars can’t be choosy, so we’ll takewhat we can get.”

Initially a Cook Inlet player in theearly 1960s and an explorer in just aboutevery area of the state, including theChukchi Sea, Gulf of Alaska and theBeaufort, Shell has never been majorplayer on the North Slope. It intends tobe, Hansen said.

Why is Shell back in Alaska now?“This is the first time we bid on Alaska

properties in some time. The world haschanged considerably since we sold ourholdings up there. Those holdingsweren’t strategic to long-term growth atthe time. Some were mature assets andthat’s not where we want to be. Shell iscommitted to growth in North America.Alaska looks very promising. … We’revery interested in establishing a presenceon the North Slope,” he said.

At this point, he said, Shell is primari-ly interested in just onshore assets.

“We will carefully evaluate the leaseswe picked up in Alaska with seismic andother data. It will be two years before weget down to serious drilling. I’d say thewinter of 2003-2004,” he said.

Hansen’s first involvement withAlaska was “about 20 years ago whenShell partnered with Dow Chemical tolook at the possibility of a petrochemicalsplant in Valdez.” ◆

Editor’s note: Shell Exploration andProduction Inc. bid in the North Slopeareawide as Shell Western Explorationand Production Inc. Rich Hansen, publicaffairs manager for Shell Exploration,said the name a company name ShellWestern Exploration and Production Inc.was “no longer in use. The companyoperating those leases will be ShellExploration and Production Inc., the U.S.E&P arm of the Royal Dutch/Shell.”

climb over the next few days. There are currently two producing

wells, one injection well and one dispos-al well completed at Northstar.

Production to peak at 65,000 bpd

BP said production is expected toreach a peak rate of 65,000 barrels perday in first quarter 2002.

Northstar reserves are about 175 mil-lion barrels. Gas re-injection is occurringfrom startup to maintain reservoir pres-sure and improve recovery.

BP holds a 98 percent working interestin the field. Murphy Exploration &Production Co., a subsidiary of MurphyOil Corp., holds a 2 percent workinginterest.

BP acquired the leases at Northstar in1995 and the following year the AlaskaLegislature approved amended terms forthe leases. In 1999, the U.S. Corps ofEngineers issued a construction permitand later that year the state issued a right

of way permit for the pipelines. Islandconstruction began in the winter of 1999-2000; the first modules were installed in2000 and the large process modules thisfall.

American oil

"In the aftermath of the Sept. 11 ter-rorist attacks, Americans charged ourgovernment to strengthen national securi-ty. This is a positive step in that direc-tion," Secretary Norton said. "Truenational security must expand conserva-tion programs, reduce our dependence onforeign oil from evil dictators, such asSaddam Hussein, and create new jobs —all while protecting the environment."

"The successful completion of theNorthstar project proves that by workingtogether, federal and state governmentsand the energy industry can combine pro-tection of the environment with cuttingedge technology to bring America's ener-gy resources safely to market," Pearcesaid. "We celebrate this addition to theU.S. energy supply and are pleased withthe Department's involvement." ◆

THE REST OF THE STORYPetroleum News • Alaska 13Week of November 4, 2001

the borough over the next ten years.“I wish I could say that SB 186 is just

an exception, a mistake that slippedthrough the legislative cracks,”Ahmaogak said. “That bill goes to theHouse of Representatives next year, andif it slips through the cracks again, theNorth Slope Borough and its residentswill be in serious financial trouble.”

The financial trouble would alsoextend to Anchorage businesses,Ahmaogak said, because it would affectthe borough’s spending in Anchorage,which was estimated from boroughrecords to amount to $139 million in2000. The borough spent $13 million inFairbanks in 2000, according to the samestudy.

“If we lose our ability to bond or ourlocal taxing structure is compromised,where’s the incentive for us to take aleading role in the energy future ofAlaska?” Ahmaogak said. “When youhave asked us to put a Native face on theeffort to open ANWR or build a gas linedown the highway, we’ve always beenthere. That’s not just because we’re nicepeople. We have a financial incentive,and if people who act in your name starttaking that away from us, you can be surewe’ll give it a second look. We know howto use a monkey wrench as well as Sen.

Donley does. As long as he thinks he canplay that game without any consequencesfrom you folks, he’ll keep doing it. I’dhate to have you learn the hard way thatwe’ve got some cards, too.”

Urban/rural divide

Ahmaogak said the borough thinksthere is an urban/rural divide, wideningbecause of the actions of Donley, co-chairof the Senate Finance Committee, andcommittee members Gary Wilken andPete Kelly of Fairbanks. He said a varietyof bills aimed at the borough have led toa climate in the Legislature that “makes itokay to bash the North Slope Borough,”adding, “It turns us into fair game whenthe Legislature is looking for ways toplug a hole in its budget; it makes ourlocal tax base into a revenue source forthe State.”

Ahmaogak said drastic bills directed atthe borough make less drastic legislationlook okay by comparison.

“They make it seem almost friendly tochange the North Slope Borough’s prop-erty taxing authority that has been inplace for 28 years,” he said. “Our proper-ty tax method is the result of a compro-mise that was struck at the time our bor-ough was formed; it was legitimate then,and it’s legitimate now.”

Ahmaogak said attempts at this pointto whittle away at the borough’s taxingauthority and divert its tax revenues tourban Alaska were unfair.

“A deal’s a deal. It’s like a treaty tous,” he said.

“My message is clearly a challenge,but more than that, it’s a plea for help,”Ahmaogak told the Alliance audience.“We need it, and you are the kind of peo-ple who can help us to squash this anti-North Slope mentality that has poisoned afew of your legislators.”

—Steve Sutherlin

North Slope Borough Mayor GeorgeAhmaogak said a handful ofAnchorage and Fairbanks

legislators have sponsored “bills tocut the legs out from under the

North Slope Borough. … They haveidentified us as a target, an enemy,and they’re not afraid to say so.”


DONLEY

field. The Alpine satellites are Fiord to the

north, estimated at 50 million barrels andNanuq to the south, estimated at 40 mil-lion barrels.

Anadarko said that both of theseAlpine satellites will be developed andproduced through the expanded Alpinefacility beginning in the 2005-2006 time-frame. Construction, the company said,should begin in 2002.

Anadarko said it expects to drill itsfirst winter exploration well on the North

Slope in the National Petroleum Reserve-Alaska, using Nabors Rig 14E, which ithas under contract. The company alsosaid it plans to participate in the acquisi-tion of 1,900 square miles of three-dimensional seismic and 600 square milesof two-dimensional seismic, and to con-tinue its Foothills exploration program.

The NPR-A well, the Altamura No. 1,is south of the Moose's Tooth discovery,Anadarko said. The company expects toparticipate in as many as 11 additionalexploration wells with partners, includingdelineation of last year's announced dis-coveries at Moose's Tooth.

—Kristen Nelson


ALPINE


NORTHSTAR


SHELL

Rich Hansen

same as the amount we have importedfrom Saudi Arabia over the last 30 yearyears.”

“We’re not just concentrating on theNorth Slope or Cook Inlet. And we’re notjust looking at conventional oil and gasplays, we’re looking at all power sources,such as coalbed methane,” he said.

Most of the federal government’s oiland gas leasing programs, Toohey said,are expected to “bear fruit in the next 5 to

20 years. But a tremendous amount of ouractivity is dependent on a state regulatorysystem that is efficient and predictable.…

“Our leasing programs will only be assuccessful as the state regulators allow,”he said.

“On top of the leasing programs, we’retrying to adequately process and quicklyissue the TAPS reauthorization to assurecontinued and future production of oil andgas from the North Slope,” Toohey said.

Northwest NPR-A planning movesforward

Interior’s Bureau of LandManagement is the agency responsiblefor leasing onshore federal lands.

On Oct. 17, BLM secured its $2 mil-lion in funding, Toohey said, to launchthe planning effort that is necessary tohold the first Northwest NPR-A oil andgas lease sale in 2004.

“Before we can offer any leases in theNorthwest area we have to go through theEIS process, which is a two yearprocess,” BLM public affairs officer EdBovy told PNA.

“It’s a carbon copy of the effort we

undertook for theNortheast area. Westill have access tothe same talent, so alot of the same peo-ple will be involved.We will also be ableto use some of thesame data our teamgathered for theNortheast environ-mental impact state-ment, so we’re not starting from scratch.”

THE REST OF THE STORY14 Petroleum News • Alaska Week of November 4, 2001


ENERGY

see ENERGY page 15

John Goll, MMSAlaska regional direc-tor

The EIS, Bovy said, is expected to becompleted by the end of the 2003.

“Depending on the results of the EIS,we could potentially hold a sale in theearly summer of 2004,” he said.

The $2 million in funding was approvedin a Senate conference committee. Fromthere it goes to the president where it isexpected to be signed without a hitch.

“It’s the earliest we have had a budgetapproved in several years,” Bovy said.“Oct. 1 is the start of our fiscal year butwe generally don’t get our programsfunded until later in the calendar year. …

It’s great to get it now.”

MMS proposes eight Alaska OCSsales

The Interior agency responsible forhandling oil and gas leasing in federalwaters is the Minerals ManagementService.

The first Alaska outer continental shelfproduction is expected to begin shortlywhen BP Exploration (Alaska) Inc.begins pumping oil from the Northstarfield. Northstar lies in federal and stateleases in the Beaufort Sea.

Most of MMS’s active oil and gasleases are in the Gulf of Mexico, theagency’s Alaska region director JohnGoll told PNA in a recent interview.

MMS is proposing to hold 12 oil andgas lease sales in the Gulf of Mexico andeight offshore Alaska from mid-2002 tomid-2007.

The Alaska sales are in the BeaufortSea, Norton Basin, Cook Inlet/ShelikofStrait and the Chukchi Sea/Hope basin.(See related story on page 8 and chartwith this story.)

“Alaska has tremendous potential butthat potential is largely in areas thatwould take more time to develop becausethere is no infrastructure in most of our

areas,” Goll said. The Chukchi Sea, where Shell

Western Exploration & Production Inc.(see related page 1 story on Shell) was thelast company to drill an exploration wellin 1990, is an area that “companies wouldlike to look at, but realistically with theprojects the companies have goingonshore, we’re not going to see thingshappen overnight in the Chukchi,” hesaid. “I don’t foresee a great rush (onleases). … We’re offering options tocompanies. If someone is interested, theoption will be there.”

Goll also sees parts of Norton Soundand the Chukchi Sea as good sources forgas. It might be a resource, he said, that

could be developed for local use but devel-opment would depend on economics.

“What might be possible is some kindof scenario for local use combined withLNG export to Japan,” he said.

Two proposed MMS Cook Inlet leasesales in 2004 and 2006 could “help openthe door to future gas reserves for theKenai Peninsula, Anchorage and the MatValley,” he said.

Goll's thoughts mirrored Toohey’sregarding the need for reasonable stateregulatory policies for OCS development:“Any federal project — be it onshore oroffshore — that affects the coastal zoneof the state of Alaska would have to gothrough some sort of coastal zone processwith the state.”

That process, he said, would be some-thing oil and gas companies would look atbefore they proceeded with development.◆

Editor’s note: In the first part of thisseries, PNA’s writer Derek Brower wroteabout what the United Kingdom was doingto fast-track oil and gas development in theinterest of national security. Next week,PNA will look at what the state of Alaska isdoing to stimulate oil and exploration andproduction to meet domestic energy needs.

THE REST OF THE STORYPetroleum News • Alaska 15Week of November 4, 2001


ENERGY

The Chukchi Sea, where ShellWestern Exploration & ProductionInc. was the last company to drillan exploration well in 1990, is an

area that “companies would like tolook at, but realistically with the

projects the companies have goingonshore, we’re not going to seethings happen overnight in the

Chukchi.”—John Goll, MMS Alaskaregion director

Lynden line up

Lynden Air Cargo's L-382 Herculesaircraft lined up at Ted StevensAnchorage International Airport.The “Hercs”s can carry up to48,000 pounds of cargo and landon packed earth, gravel, ice orshort runways. Its rear-loadingcargo hold is 54 feet long, 10 feetwide and 9 feet high. In PNA’sOct. 21 weekly edition an articletitled, “Alpine airstrip crash blowto Alaska's air cargo fleet,” refersto “Lynden Air Freight's LockheedC-130 Hercules.” We stand cor-rected. Lynden’s Hercs belong toLynden Air Cargo.

Lynd

en A

ir C

argo

Proposed Alaska MMSLease Sales

Area YearBeaufort Sea 2003Norton Basin 2003Cook Inlet/Shelikof Strait 2004Chukchi Sea/Hope Basin 2004Beaufort Sea 2005Cook Inlet/Shelikof Strait 2006Beaufort Sea 2007Chukchi Sea/Hope Basin 2007

ADVERTISEMENT16 Petroleum News • Alaska Week of November 4, 2001

exploration & production federal agencies in alaska gear ... · steven breaks silence on anwr 3...

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