government exploration incentive credits bill moves · evergreen would buy local 9 knowles latest...

Vol. 7, No. 6 $1 • www.PetroleumNewsAlaska.com Alaska’s source for oil and gas news Week of February 10, 2002

I N S I D E

Tesoro posts record net 5

Evergreen would buy local 9

Knowles latest gasline proposal 11

History: Shell to explore Chukchi 6

Explorers, producers duke it out in Juneau 3

Doyon speaks on exploration incentive credits 2

“Some of the basic principles ofAmericanism:

The right to criticize.The right to hold unpopular beliefs.The right to protest.The right to independent thought.”

—SEN. MARGARET CHASE SMITH FROM MAINE, 1950

■ G O V E R N M E N T

■ A R C T I C G A S

Exploration incentive credits bill movesin House; Myers says needs some workHB 307 adds three years to existing program, would allow Andex Resources to applyfor work it plans in Nenana basin where it has applied for an exploration license

By Kristen Nelson PNA Editor in Chief

Two financial incentives the state has used toencourage exploration — exploration incen-tive credits and discovery royalties — arebeing discussed in the Legislature this year as

Andex Resources LLC looksfor ways to reduce its explo-ration risk in the NenanaBasin. (See related storyabout Andex and Doyon Ltd.on page 2.)

The bills, House Bill 307,extending the state’s explo-ration incentive credits pro-gram for three years, and HB308, expanding the currentCook Inlet discovery royaltyprogram to the Tanana Riverdrainage, were sponsored byRep. Hugh Fate, R-Fairbanks. Jim Dodson, exec-utive vice president ofAndex, testified in support ofthe bills.

HB 307, explorationincentive credits, moved outof the House SpecialCommittee on Oil and GasJan. 31 and out of House Resources Feb. 1 afterhearings in both committees.

HB 308, discovery royalty reduction, was heldin House Oil and Gas after vigorous oppositionfrom the Division of Oil and Gas. (See sidebar tothis story.)

Extension the issue

The exploration incentive credits program waspassed in 1994 for a 10-year period, state Divisionof Oil and Gas Director Mark Myers told the com-mittees. The program allows the commissioner ofthe Department of Natural Resources to grant a

credit against royalties, taxes, lease bonuses orrentals. The credit can be as much as 50 percent ofthe cost of geophysical information, stratigraphictest wells or exploration wells on non-leased statelands, Myers said, and up to 25 percent of the costof the same programs on Native or federal land.

DNR pans discovery royaltyThe second bill under consideration Jan. 31

by the House Special Committee on Oil and Gas,House Bill 308, would extend discovery royaltycredits currently provided for Cook Inlet fields toTanana River drainage. The Cook Inlet programprovides a 5 percent royalty for the first 10 years.That bill was held for further consideration in

Enbridge emerges from the shadowswith a northern route plan Declares its intention to participate in either or both Arctic pipelines, drawing onits experience as the only pipeline company operating inside Canada’s Arctic Circle

By Gary Park PNA Canadian Correspondent

Until now, Enbridge Inc. has kept a studiouslylow profile on the Arctic pipeline debate,beyond the occasional insistence of chiefexecutive officer Pat Daniel that the decision

on routing should be left to producers. That neutrality changed with a jolt on Jan. 30,

when Daniel, in an interview with the TorontoGlobe and Mail, said Enbridge would go solo, witha plan to build, own and operate a US$15 billion“over-the-top” line.

He said his Calgary-based energy services com-pany was pitching what it viewed as the most logi-cal, cost-effective and environmentally friendly sys-tem for delivering gas from the North Slope andMackenzie Delta.

“I think the producers and owners of the resourcewould rather evaluate the alternatives and concludewhat they think is best without having the publicpressure and shareholder pressure in this,” he said.

Having kept its cards close to its chest over thelast two years, while Calgary-based Foothills PipeLines Ltd. and Houston-based Arctic Resources Co.

Pictured here is Forest Oil’s Osprey platform atRedoubt Shoal in Cook Inlet. Redoubt Shoal is eli-gible for a discovery royalty under 1998 legislation.Supporters of that legislation say the field wouldnot have been developed without the royalty relief.

Rep. Hugh Fate

Jim Dodson, execu-tive vice president ofAndex Resources

see CREDITS page 12

see ROYALTY page 15

On the road againJu

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Judy

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see ENBRIDGE page 12

State receives four offers forroyalty-in-kind natural gas

The state of Alaska has received four offers to buy NorthSlope royalty-in-kind natural gas.

At a bid opening Feb. 1, Commissioner of Natural ResourcesPat Pourchot said the proposals were from Alaska Power andTelephone Co. in Tok; Anadarko Petroleum Corp. and AEC Oiland Gas (USA) Inc. and AEC Marketing (USA) Inc. — a jointproposal; Chevron U.S.A. Inc.; and Williams Energy Marketingand Trading Co.

Kevin Banks, petroleum market analyst with DNR’s Divisionof Oil and Gas, said before the bid opening that analysis of the

Most bids confidential Anadarko Petroleum Corp. and AEC Marketing (USA) Inc.

handed out copies of the joint offer they submitted Feb. 1 tobuy the state’s North Slope royalty gas.

Information on the other three offers the state received isscanty or confidential, in spite of an obvious desire by the stateto make information available. (See story above.)

Kevin Banks, petroleum market analyst with the Division ofOil and Gas, told PNA Feb. 6 that the bid from Alaska Powerand Telephone Co. is for 1.6 million cubic feet a day (the stateoffered approximately 350 million cubic feet a day). The com-pany said it would pay what the state receives for royalty-in-value gas for the royalty-in-kind gas and offered no premium.Banks said Alaska Power provided a white paper explainingthat they would use the gas for customers in Tok and Dot Lake,and also to generate electricity.

see OFFERS page 2

see BIDS page 2

Pictured here is a piece of Nabors Alaska Drilling Rig 14E being trans-ported via a CATCO Rolligon on an ice trail in the National PetroleumReserve-Alaska to drill an exploratory well. An estimated 180 loads willbe necessary to transport the entire rig to the site. Photo taken earlierthis month. See related story on page 8.

ON DEADLINE2 Petroleum News • Alaska Week of February 10, 2002

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

Exploration incentive credits play ‘significantrole’ in attracting Andex to Nenana Basin Doyon’s Jim Mery says the state program “was a bit ahead of its time” because when thelaw was first enacted, there were not many independents interested in Alaska

By Kay CashmanPNA Publisher

AHouston independent’s interest in exploring 538,000 acres ofstate and Native land in Interior Alaska is “proof positive”that exploration incentive credits work to draw oil and gascompanies to undeveloped basins in Alaska, Jim Mery told

PNA Feb. 5. Mery is Doyon Ltd.’s vice president of lands and nat-ural resources.

Andex Resources LLC, which has applied to the state for a500,000 acre exploration license in Interior Alaska’s NenanaBasin, is close to a deal with Doyon to explore a strategicallyplaced 38,000 acre parcel of Native land within the license area.

Andex is working on an agreement with the Native regionalcorporation that would give the privately owned independent theright to explore and develop oil and gas resources in what isthought to be the deepest part of the Nenana Basin, Mery said.

Andex hopes to get its exploration license early enough thisyear so it will be able to shoot seismic over the basin in the winterof 2002-2003.

But exploration incentive credits go away in 2004 — the firstyear Andex will be able to drill in the basin — unless House Bill307 passes the state Legislature, extending the exploration incentivecredit program for three years to 2007. (See related story on page1.)

Ahead of its time

Mery told PNA that Doyon was a supporter of the 1994 explo-ration incentive credit legislation and is solidly behind an extensionof its sunset date as provided for in House Bill 307, recently intro-duced by Rep. Hugh Fate, R-Fairbanks.

“In retrospect, the concept was a bit ahead of its time. We

thought that exploration companies large and small would respondpositively. The majors were only interested in oil and Interiorbasins for the most part are more prospective for gas. Now, wethink that these incentives are what will help attract some of theindependents to under-explored basins,” Mery said.

Andex’s interest in the Nenana Basin is “proof positive” thatexploration incentives credits work, he said.

“When the law was first enacted, there really were not manyindependents interested in Alaska. That is obviously changing.”

Andex: A good choice for Alaska Andex Resources LLC is a good choice for development in

the basin, Jim Mery, Doyon Ltd.’s vice president of lands andnatural resources, told PNA in August.

Mark Myers, director of the state Division of Oil and Gas,agreed with him.

Both men pointed to the fact that Andex is well-funded,involved with other projects in Alaska and looking to get evenmore involved in the state.

“A lot of them are old Shell Oil people. … Andex’s presi-dent, Ernie LaFleur, was head of Alaska exploration for Shell.I am very impressed with their geology staff,” Mery said inAugust.

Andex is already a 20 percent partner in BP Exploration(Alaska) Inc.’s Slugger prospect — an eastern North Slopeexploration unit near Badami. Andex is purchasing a 20 percentworking interest in Slugger by funding exploration of the unit.

see ANDEX page 4

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see CHOICE page 4

proposals would begin right away. Thecommissioner will then determine whetherto negotiate with any of the companiesmaking offers and then to craft contractsbased on the proposals, Banks said.

A finding of best interest would then beissued for public review and review by theRoyalty Oil and Gas DevelopmentAdvisory Board. After a final finding iscompleted, the contract would be submittedto the Legislature.

Commissioner Pourchot said after read-ing the names of those submitting bids thatthe state has not yet made any decisions toproceed. The process is being taken step bystep, with action taken only when the nextstep is seen as in the best interests of thestate, he said. The next step will be analyz-ing the proposals.

The state offered 70 percent of itsPrudhoe Bay and Point Thomson royaltygas Dec. 26, saying that selling royalty gasnow “responds to a commercial opportuni-ty” to improve future royalty revenues fromnatural gas and to promote new privateinvestment.

—Kristen Nelson

The Chevron U.S.A. Inc. bid is for 375million cubic feet a day with an offering aprice “based on the RIV value,” a non-monetary mechanism for the option toreduce volumes and a non-monetary bene-fit. Banks said Chevron wants details ofthe proposal kept confidential.

The Williams Energy Marketing andTrading Co. proposal is entirely confiden-tial, Banks said. Williams said in a state-ment that it is the company’s standardpractice to submit all such responses to bidrequests under confidential terms and con-ditions.

Anadarko-AEC

The Anadarko-AEC offer includes aminimum cash bonus of $350,000, basedon the assumption that the 70 percent ofthe state’s royalty Alaska North Slope gasoffered for sale will be 350 million cubicfeet a day. The base price would be theroyalty-in-value price and the companiesoffered a price premium of 2 cents per mil-lion Btu for each MMBtu purchased dur-ing the primary term with an increase of 2cents per MMBtu for each subsequentfive-year renewal period.

Anadarko-AEC also offered an optionpayment of $2 million for each five-yearterm with an initial payment of $2 millionupon execution of a contract and approval

by the Legislature.

In-state investments

Anadarko and AEC committed to a $50million five-year exploration work com-mitment, 2002 through 2007. If they fail tomeet the $50 million work commitment,they will pay the state the difference.

Northern Economics Inc. did a socioe-conomic impact assessment for Anadarkoand AEC and found, the companies said,that if they continue their explorationefforts beyond the five-year $50 millioncommitment, and if their efforts result in acommercial gas discovery, the economicmultiplier effect and state tax assessments

continued from page 1

OFFERS


BIDS

see BIDS page 4

ON DEADLINEPetroleum News • Alaska 3Week of February 10, 2002

ON DEADLINE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2FINANCE & ECONOMY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4EXPLORATION & PRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . .7COOK INLET . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9ENVIRONMENT & SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10ARCTIC GAS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11ADVERTISER INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14

Index

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ARCTIC GASProducers, explorers duke it outin House oil and gas committee

The House Special Committee on Oil and Gas heard opposing views Feb. 5 onwhether the state should sell its royalty North Slope gas, with existing gas pro-ducers telling the state to hold off and companies just exploring for gas telling thestate it should go ahead.

Michael Hurley of Phillips said a royalty gas sale “further burdens” an alreadyeconomically challenged project because space contracted by an explorer to shiproyalty-in-kind gas could be filled instead by the explorer’s own gas, forcing pro-ducers to allocate some of their own space to ship the state’s gas as royalty-in-value, theoretically reducing the producers’ ability shipping capacity from 3.5 bil-lion cubic feet a day to 3.2 bcf.

Ken Konrad of BP Exploration (Alaska) Inc. told the committee that knownresource owners are backing the line and unknown resource owners are backingthe RIK sale, which, he said, transfers the ability to ship without transferring therisk — and reduces the chance of the project getting built.

Richard Glenn, vice president of lands for the Arctic Slope Regional Corp., toldthe committee ASRC wants to continue working with existing North Slope pro-ducers, but has to speak out in favor of further exploration, access to capacity andaccess to the planning process for a North Slope pipeline. He said ASRC feels thatthe RIK sale is a necessary place marker for non-owners of gas.

Alan Sharp of AEC told the committee AEC wants to see the pipeline designedfrom the start with all the North Slope reserves in mind and said there would belittle or no additional cost if the line is designed for incremental expansion.

Mark Hanley of Anadarko Petroleum Corp. said it is a policy call for the state:If the producers control initial capacity in the pipeline you won’t have explorationin the state by companies like Anadarko and AEC — and are unlikely to get leasesale participation.

—Kristen Nelson

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The Houston independent is also a 25percent partner in Netricity LLC, the firmthat wants to build a $1 billion, gas-pow-ered, data center on the North Slope.

And Andex has already taken its knocks

in Alaska. The company is a working inter-est partner in West Gwydyr No.1, a BP-operated exploratory well south of BP’sNorthstar unit. The well was drilled, thenplugged and abandoned, in the winter of2000.

Dodson said Andex is also interested inother undeveloped basins in the state, partic-ularly Yukon Flats and Susitna Basin.

For several years Doyon has “activelypromoted oil and gas exploration” in theInterior, especially the Nenana Basin —including state and Doyon oil and gas inter-ests, Mery said. “The availability of explo-ration credits has been part of our presenta-tions. As a result of working with Andex,we know that these credits played a signif-icant role in attracting them to the NenanaBasin, pretty close in line behind veryfavorable geology for natural gas andpotential gas markets,” Mery said.

“Although the Nenana Basin is a goodplace to look for gas, the exploration risksare still very high. The credits help temperthose risks, including the ‘Alaska factor’ of

high costs, compared to opportunities in theLower 48. It would be a shame if this pro-gram is allowed to expire just as it begins tofulfill its initial promise,” he said.

HB 307, exploration incentive credits,moved out of the House SpecialCommittee on Oil and Gas Jan. 31 and outof House Resources Feb. 1 after hearings inboth committees.

Editor’s note: In the August 2001 editionof Petroleum News Alaska, PNA coveredAndex Resources’ plans for the NenanaBasin, which is thought to hold between 250Bcf to 1 Tcf of recoverable natural gas. Inthe article, Jim Dodson talks about supply-ing gas to Fairbanks, as well as possiblyAnchorage. See PNA archives athttp://www.PetroleumNewsAlaska.com fora complete report.

ON DEADLINE/FINANCE & ECONOMY4 Petroleum News • Alaska Week of February 10, 2002

EL SEGUNDO, CALIF.Unocal posts loss for fourth quarter

Unocal Corp. fell into red ink for the fourth quarter with a loss of $29 million, com-pared with a profit of $173 million in the last period of 2000. The company made$102 million in this year’s third quarter. Special items cut $88 million from the resultsin the fourth quarters of both 2001 and 2000. Without those items, the El Segundo,Calif., company would have recorded a $58 million profit for the 2001 quarter.

Special items in the 2001 quarter included a write-down of $86 million on thevalue of some properties in the Gulf of Mexico. The company also took a $24 millioncharge for environmental and litigation matters in the quarter, part of $95 million inreductions for those items for the year.

Unocal reported earnings of $615 million for 2001, down 19 percent from $760million in 2000.

Production in the fourth quarter averaged 497,000 barrels of oil equivalent, up 5percent from a year earlier. Prices were much lower — $2.42 per thousand cubic feetof gas, a decline of 36 percent, and $17.90 for each barrel of oil, also down 36 per-cent.

Alaska operations brought in $6 million in adjusted after-tax earnings, down from$23 million a year ago and $17 million in the third quarter. Lower 48 earnings fromexploration and production were $10 million for the fourth quarter, while Canadianoperations in the segment showed a loss of $12 million. Far East E&P is now the bigdriver, contributing $82 million to earnings in the quarter.

That figure was down from $127 million a year ago.Alaska produced 101 million cubic feet of gas daily in the fourth quarter for

Unocal, up 16 percent from 87 million cubic feet a year earlier. Third-quarter Alaskaproduction was 83 million cubic feet a day. Gas brought $1.57 per thousand cubicfeet, up from $1.20 a year ago. Liquids production from Alaska was 26,000 barrelsdaily, essentially unchanged from the year-ago figure and the third quarter of 2001.

Revenues from continuing operation in the quarter totaled $1.26 billion, down 55percent from $2.78 billion a year earlier. Unocal took in $6.75 billion from continu-ing operations in 2001, down 27 percent from 2000’s figure.

—Allen Baker


ANDEX

OIL COMPANY EARNINGSFourth Quarter 2001

4Q 2001 profits, % change from 4Q 20004Q revenues, % change from 4Q 2000,

4Q daily production, % change from 4Q 2000

profits % revenues % production %Alberta Energy AOG —Agrium AGU —Anadarko APC -$188 — $1,379 - 41 529,000BOE +9BP BPChevronTexaco CVX -$2,522 — $21,460 -33 2,014,000BBL/4,371MMCF 0/-1Conoco COC $127 -77 $8,491 -18 891,000BOE +32Evergreen EVG —ExxonMobil EOM $2,680 -49 $47,300 -26 2,527,000BBL/11,373MMCF -3/+1FoothillsForest FST —Marathon MRO -$1,074 — $6,846 -15 192,300BBL -1Murphy MUR $28.8 -69 $849 -33 70,687BBL +7Petro Canada PCZ C$71 -75 C$1,772 -39 205,000BOE -3Phillips P $162 -78 $10,000 +59 836,000BOE 0Semco SEN —Tesoro TSO $4.0 -84 $1,279 -11 — —Unocal UCL -$29 — $1,263 -55 497,000BOE +5Williams WMB —XTO XTO —

Dollar figures in millions

BOE: barrels of oil equivalentBBL: barrels of crude oil and condensate

MMCF: billions of cubic feet of natural gas

The fourth quarter information about the companies in the chart above are either included innews briefs and stories in this section of PNA or they were reported in the Feb. 3 issue of PNA.


CHOICE

would result in an overall benefit to thestate of $6.4 billion.

In addition, the Anadarko-AEC offerincludes a preference for local hire and apreference for in-state gas processing —natural gas liquids extraction and petro-chemical manufacturing.

—Kristen Nelson


BIDS

Week of February 10, 2002

FINANCE & ECONOMY

Petroleum News • AlaskA 5

ADVICEPortfolio strategy update

Perception versusrealityBy David Gottstein

Editor’s note: The following column was written in lateJanuary. David Gottstein is with Dynamic Research Group inAnchorage.

The end of the recession is near. Unemployment levels have bottomed out. Inventories

will have to be replenished. The Federal Reserve will likelycontinue to loosen its monetary policy. The Federal govern-ment will pass an effective stimulus package. In historicalterms autos and housing continue to remain robust.

The economy will likely turn positive in the second halfof the year. We are at the beginning of another bull market.

And the tooth fairy will make everything okay. By and large, just about everything, including the kitchen

sink, has been used to generate positive feelings about theeconomy, and to give people confidence about the future.This has lead to increased investor confidence, and a con-siderable recovery in stock valuations since the tragic eventsof Sept. 11. And in fact there has even been an up-tick in theindex of leading economic indicators.

There are a lot of reasons, however, for people and thegovernment to be reporting all this good news, many ofthem for self serving reasons.

News not all good

The reality is that even though the economy may current-ly not be as bad as it was, or expected to be last September,it doesn’t mean that we are on the road to recovery yet.Things are still pretty bad.

Layoffs continue to be reported almost on a weekly basis.When was the last time you heard about significant newhires, or plans to go forward with new plant capacity, atleast domestically instead of in China? Where any new pickup in demand may well be serviced by_________________.

Ford plans to close five plants, just to stay alive. Corningis ramping back up four plants due to inventory depletion,but they admit it will be at a very tepid pace.

Consumers have still been spending, but there is no otherleg in sight without increased employment because debt lev-els are already at historic highs.

The airline and travel industry are still in the pits, for theforeseeable future, with billions expected in losses againthis year.

And money supply has turned South, with the Fed havingtrouble keeping the punch bowl full.

Not all bad

We are not saying that all is bad; it’s just that mostly justthe good news is being reasoned for future economic per-formance, as a backdrop for stock market opportunitiesmoving forward. The problem is that once again all the goodnews is already priced into the market, without much roomfor error.

We believe employment, and therefore personal incomeand consumer spending, will not come back as soon as manyexpect.

And that the improvement in corporate earnings this yearwill be anemic at best.

In the final analysis there is much more room for nega-tive surprises than positive ones at current stock market val-uations. With PE ratios ranging between 24-30, dependingupon what kind of earnings you wish to use.

Seems pretty high for an earnings growth outlook notmuch greater than 8 percent on a realistic relative basis.

OUR CURRENT RECOMMENDATIONS■ Verisign Inc. (VRSN)

■ Pharmacia Corp. (PHA)

■ Andrx Group (ADRX)

■ H O U S T O N

Anadarko Petroleum quarterly net falls 76 percentAsset write-down brings 2001 into red; $1 billion reduction in valueattributed to internal accounting error

By Allen Baker PNA Contributing Writer

Sharply lower prices slashed profits at AnadarkoPetroleum Corp. to $109 million for the fourthquarter, down 76 percent from $457 million forthe same quarter of 2000.

For the year, Houston-based Anadarko posted a lossof $188 million, comparedwith earnings of $796 millionin 2000. That came after thecompany announced in lateJanuary that it was restatingthird quarter results with a$1.08 billion reduction in thevalue of its reserves after dis-covering an internal account-ing error. The company in thatquarter had already chopped the carrying value ofgas properties in Canada and South America by$483 million.

The January restatement actually boosted netprofits in the fourth quarter by $32 million because itreduced depletion and depreciation charges, TheWall Street Journal reported.

Factoring out “non-cash property impairments,”or changes in the value of its reserves, Anadarko’s2001 earnings rose 68 percent to $1.39 billion, thecompany said.

Natural gas volumes rose to 1,863 billion cubicfeet daily, a gain of 11 percent from the prior year.

That gas brought an average of $2.59 per thousandcubic feet, exactly half the $5.18 Anadarko receivedfor gas a year earlier.

Liquids production up

Liquids production rose 9 percent to 175,000 bar-rels daily. Liquids brought an average of $16.39,down 36 percent from $25.45 a year earlier.

The lower prices cut revenues for the quarter bynearly a billion dollars, to $1.38 billion from $2.35billion. For the year, revenues rose 52 percent to$8.37 billion from $5.5 billion.

Anadarko said it was changing strategies as aresult of the lower prices, deferring some drillingprojects in the last half of 2001 and cutting the capi-tal budget for 2002.

“We built an inventory of exploration prospectsand development drilling locations so we’ll be well-positioned to capitalize on the next market upturn,”said Anadarko president John N. Seitz in a statementincluded in the earnings report. “At the first sign ofdemand picking up and process recovering, we planto accelerate our drilling activity, just as we did in1999, in the last price cycle.” ◆

“At the first sign of demand picking up andprocess recovering, we plan to accelerateour drilling activity, just as we did in 1999,

in the last price cycle.” —John N. Seitz,Anadarko Petroleum Corp.

John N. Seitz,Anadarko Petroleum

■ S A N A N T O N I O

Tesoro profits dwindle in fourth quarter;company still posts record net for year


Weaker refining margins pushed TesoroPetroleum Corp. profits for the fourthquarter down to $4.0 million, just a sixthof the $24.4 million the company made a

year earlier. Third-quarter profits were $32.8 mil-lion.

For the year, Tesoro’searnings were $88 mil-lion, up 20 percent from2000 and a record for thecompany.

Operating earningsfrom refining and mar-keting, by far the biggestpart of the San Antonio,Texas-based company,dropped to $45.1 millionfor the quarter from $57.2million in the same period of 2000.

“This drop was due primarily to the decline inour realized refining margin as the overall weakeconomy and unseasonably warm weather causedmargin erosion,” Tesoro President Bruce A.Smith said in a statement.

Tesoro had a product spread for refining andmarketing of $7.16 per barrel in the quarter, downexactly a dollar from the figure a year ago. Overthe year, product spread increased to $7.65 from$6.99 in 2000.

Acquisitions triple debt

Offsetting part of the decline in margins forthe quarter was $19 million in operating profitsfrom the acquisition of two refineries and 130 sta-tions from BP, he reported.

But those acquisitions more than tripledTesoro’s debt at the end of the year to $1.147 bil-lion from $311 million a year earlier. Interestcosts for the quarter also tripled, to $21.4 millionin 2001 from $7.1 million a year ago.

The purchase of the refineries in Salt Lake andNorth Dakota didn’t slake Tesoro’s thirst forgrowth, however. The company announced Feb.5 that it’s buying a big 168,000-barrel-per-dayrefinery in California from Valero Energy, plus70 stations, for $1.08 billion. The refinery willincrease Tesoro’s total refinery production 47percent.

The company’s Nikiski refinery processed50,800 barrels daily in the fourth quarter, a cou-ple hundred barrels more than the figure for the2000 quarter. For the year, the facility averaged50,000 barrels daily, up from 48,500 in 2000.

In addition to its refineries and gas outlets,Tesoro has a marine services division thatbrought in $700,000 in operating profit in thefourth quarter, down from $1.7 million a yearago.

Total revenues for the quarter were $1.28 bil-lion, down 11 percent from the figure a year ear-lier. For the year, the company took in $5.22 bil-lion, up 2 percent from 2000. ◆

The company’sNikiski refinery

processed 50,800barrels daily in thefourth quarter, acouple hundred

barrels more thanthe figure for the

2000 quarter.

The federal government has approvedShell Western E & P Inc.’s plans tosearch for oil in the Chukchi Sea, anunexplored region noted for its harsh

climate and rugged ice conditions.Shell has selected 16 possible drill sites

and wants to sink up to eight wildcat wellsover four years at an estimated cost of$400 million.

The company plans to begin drillingthis summer from the ship CanmarExplorer III on federal leases up to 200miles from Alaska’s northwest coast.

The federal Minerals ManagementService approved the company’s plansTuesday, following a month-long review.The agency will now wait for the state toissue its findings before deciding whetherto grant Shell a drilling permit.

“Overall, it’s a good plan … and I’mpleased Shell made the financing avail-able and is going ahead,” MMS DirectorAlan Powers said.

Because of weather conditions andsubsistence whale hunting in areas of theChukchi Sea, Powers said MMS attacheda number of stipulations to Shell’s plans,including required practice drills to assurethe company can handle any oil spills.

“Generally, we require one right at thestart of drilling, to assure the people aretrained … and will be used to the equip-ment,” he said. “If environmental condi-tions change, we’ve required they go

through another response to make surethey are equipped to deal with thechange.”

Powers also said MMS wants Shellofficials to coordinate their drilling activi-ties with the Alaska Whaling Commissionand subsistence communities in theregion, including Wainwright and PointLay.

“This will reduce any interference withsubsistence whaling,” he said.

But Powers and Shell’s immediateplans call for drilling on remote parcels farfrom the whale migration corridor.

“Drilling isn’t expected to start untillate June or July, and by that time springsubsistence whaling would be completed,so we don’t expect much interference,” hesaid.

Powers said the Biological Task Force,consisting of several federal agencies, alsowill review Shell’s plans to decidewhether a survey needs to be conducted tomeasure the effects of drilling on wildlife.

The Alaska Division of GovernmentalCoordination currently is reviewingShell’s plans and is expected to issue afinding March 10, Director Bob Grogansaid.

Grogan said the division, which isattached to the governor’s office, wants tomake sure the plan is consistent with stateand federal coastal zone management pro-grams.

“We’re dealing with an area out therethat has never been explored, and it’s themost hostile offshore area,” he said.

“It raises technical questions abouthow exploration will take place. There areenvironmental concerns as well. But we’lltry to figure out a way we can go forward.We try to cooperate.”

The government has said the ChukchiSea may hold up to five billion barrels ofrecoverable crude oil, making it one of thehottest offshore prospects in the world.

“There are a lot of good-lookingprospects out there,” Powers said.

Meanwhile, Billye Lynn Ratliff ofShell’s office in Houston, Texas, said thecompany is gearing up to explore.

“We’re happy to be at this stage of thepermitting process and on schedule,” shesaid. “We’re pleased with the approval.” ◆

FINANCE & ECONOMY6 Petroleum News • Alaska Week of February 10, 2002

CANADAPetro-Canada shows record earnings;fourth quarter hurt by Enron issues

Petro-Canada bucked a decline in fourth-quarter earnings to post record profitsin 2001 of $904 million (Canadian), slightly above 2000’s C$893 million.

For the fourth quarter, operating earnings were C$71 million, less than a fourthof the C$287 million a year earlier. Those earnings were also less than half of theC$149 million the company made in 2001’s third quarter. The fourth quarter wasmarked by a C$15 million charge against earnings due to the bankruptcy filing ofEnron Corp.

Production totaled 205,000 barrels of oil equivalent daily for the quarter, downfrom 211,000 a year earlier but up from the third quarter’s 190,800.

Upstream profits were C$52 million, compared with C$244 million a year ear-lier. Downstream operations brought in C$48 million, down from C$66 million in2000’s fourth quarter.

Revenue for the quarter slid 39 percent to C$1.77 billion, from C$2.90 billiona year earlier. For the full year, revenues totaled C$8.69 billion, a decline of 9 per-cent from C$9.52 billion in 2000.

—Allen Baker

Murphy’s earnings take dive Murphy Oil Co. reported net income of $28.8 million in the fourth quarter,

down 69 percent from $93.2 million in profits a year earlier. The company made$41.7 million in the third quarter.

Liquids production rose 7 percent to 70,687 daily barrels, but the averageprice for that oil slid 34 percent to $16.90 per barrel. Gas volume was up 20 per-cent to 297 million cubic feet a day.

For the year, the El Dorado, Ark., company earned a record $330.9 million,which included a $71 million gain from selling Canadian pipeline assets. Theoverall profit figure was up 11 percent from $296.8 million in 2000 profits.While earnings from exploration and production declined $90 million to $188million for the year, refining and marketing profit was up 63 percent to $89 mil-lion.

The company is only expecting to break even in the first quarter of this year.Revenues for the quarter were $849 million, down 33 percent from a year ago.Annual revenues declined a bit to $4.48 billion from $4.64 billion.

—Allen Baker

ARKANSAS

■ H I S T O R Y

February 1989: Officials approveShell’s Chukchi oil search

This Month in HistoryThe article was originally publishedin the Anchorage Daily Times onFeb. 22, 1989.

Shell has selected 16 possible drillsites and wants to sink up to eightwildcat wells over four years at an

estimated cost of $400 million.

EXPLORATION & PRODUCTION/FINANCE & ECONOMYPetroleum News • Alaska 7Week of February 10, 2002

STATEWIDENorth Slope production down 1percent in January

Alaska North Slope production averaged 1.056 million barrels per day in January,down 1.2 percent from 1.069 million bpd in December, despite increased productionfrom Northstar, the slope’s newest field.

The Alaska Department of Revenuesaid there were two problems on the slopein January: mechanical failure led to a Jan.22 shutdown at Endicott and high vaporpressure led to a Kuparuk production pro-ration Jan. 26.

The largest percentage drop in produc-tion was at Endicott, which averaged31,150 bpd in January, down 5.1 percentfrom a December average of 32,820 bpd.Endicott production dropped from 31,477bpd Jan. 20 to 10,601 bpd Jan. 21, and28,540 bpd Jan. 22 — the date Revenuesaid there was a field shutdown. January peaked at 35,348 bpd Jan. 29.

Northstar and Alpine, the newest North Slope fields, both had production increas-es: Northstar averaged 35,736 bpd in January, an increase of 21.5 percent from aDecember average of 29,407 bpd. Revenue said Northstar production topped 48,000bpd Jan. 26. The field is expected to peak at 65,000 bpd in the first quarter. Alpine pro-duction averaged 100,817 bpd in January, up 1.2 percent from a December of averageof 99,600 bpd.

Prudhoe Bay production averaged 540,037 bpd, down 2.7 percent from a Decemberaverage of 555,028 bpd. Lisburne production averaged 76,758 bpd in January, down1.6 percent from a December average of 77,990 bpd. Kuparuk production averaged218,893 bpd in January, down 1.1 percent from a December average of 221,249 bpd.Milne Point production held almost even, down just 0.3 percent to 52,831 bpd inJanuary compared to 52,985 bpd in January.

Cook Inlet production averaged 32,641 bpd, down 13 percent from a Decemberaverage of 37,504 bpd.

Prudhoe Bay natural gas liquids production averaged 49,734 bpd in January, down2.6 percent from an average of 51,037 bpd in December.

The average temperature at Pump Station 1 was -15.1 degrees Fahrenheit inJanuary, compared to -7.4 degrees F in December.

—Kristen Nelson

The largest percentage drop inproduction was at Endicott, whichaveraged 31,150 bpd in January,

down 5.1 percent from a Decemberaverage of 32,820 bpd. Endicottproduction dropped from 31,477

bpd Jan. 20 to 10,601 bpd Jan. 21,and 28,540 bpd Jan. 22 — the date

Revenue said there was a fieldshutdown. January peaked at

35,348 bpd Jan. 29.

HOUSTONMarathon posts loss on breakup

Marathon Oil Corp. took some major charges in the fourth quarter as it broke awayfrom the steel unit of USX to realign its businesses and become independent again. Theoverall loss amounted to $1.07 billion, compared with a loss of $449 million a year ear-lier. But subtracting out split-off expenses and other unusual costs, the Houston-basedcompany said it had an operating profit of $98 million for the quarter, still barely afourth of the $386 million gleaned from oil operations in the same period of 2000. Inthe third quarter, Marathon had a group profit of $193 million.

For the year, operating earnings were $1.49 billion, up 14 percent from 2000. Overallearnings, with the special charges, were $157 million, down from $411 million in 2000.

With all the changes, Marathon still managed to boost production 2 percent for theyear as a whole, though liquids production dipped to 201,300 barrels daily for the fourthquarter from 209,100 barrels a year ago. Gas production rose a bit to 1.31 billion cubicfeet daily, up 6 percent from 1.24 billion cubic feet in the final 2000 quarter As with theother oil companies, sharply lower prices for its products drove down profits. Marathongot an average of $14.48 a barrel for its domestic oil, barely half of the $25.89 it receiveda year earlier. Domestic natural gas brought $2.08 per thousand cubic feet, less than halfof the $4.44 an Mcf that gas brought in the 2000 quarter.

Exploration and production brought in $117 million for the quarter, down from $403million in 2000. Refining, marketing and transportation profits were $221 million, downroughly a third from a year ago. Other energy businesses contributed $22 million, upfrom $15 million. Revenues for the quarter were $6.85 billion, down 15 percent from$8.05 billion in 2000. For the year, revenues reached $33.07 billion, down just 2 per-cent from $33.8 billion for 2000.

—Allen Baker

EXPLORATION & PRODUCTION8 Petroleum News • Alaska Week of February 10, 2002

■ N O R T H S L O P E

Pre-packing snow along proposed ice road routes saves seasonfor companies doing exploratory drilling on North Slope

By Steve SutherlinPNA Managing Editor

The state first opened portions of theNorth Slope to tundra travel Jan. 25— the latest ever tundra travelopening, breaking the previous

record set Jan. 14, 1999. Land closest to the coast was opened

first; the geographic line being 69degrees 40 minutes north latitude in thevicinity of the Franklin Bluffs area, LeonLynch of the state Division of Mining,Land and Water told PNA.

The late opening was blamed onheavy snowfall earlier in the winter that,despite extended cold temperatures,insulated the ground and kept the frostlevel from dropping to a level acceptablefor ice road construction.

But partial ice road construction wasallowed by the state on a case-by-casebasis in early January on routes thatwould lead to drilling sites in theNational Petroleum Reserve-Alaska,Lynch said.

Rolligons were used to pack the snowalong the routes, he said. Packed snowhas less insulating value than loosesnow, driving frost levels down morequickly.

Peak Oilfield Service Co. was able toconstruct 60 miles of road fromMeltwater to the Colville River crossingon a pre-packed route, Lynch said.

Pre-packing more important thisyear

Pre-packing ice road routes, which

has been done for about five years on theNorth Slope, costs the companies more,but it seems to have paid off this year,Lynch said, with tundra travel delayedunusually long.

Pre-packing can be effective to coun-teract uncertainties due to the weather,as well as uncertainties due to the permitprocess, Lynch said.

“We had lawsuits over water permits.Almost every permit was being contest-ed this year — it made pre-packing moreimportant,” Lynch said. “The consisten-cy determinations were challenged

through the ACMP process.” South of the 69 degree 40 minute

north latitude line, winter movement isbeing considered on a case-by-casebasis, he said.

Frost levels are marginal where PGSOnshore is doing seismic work nearHappy Valley, 80 miles south ofDeadhorse, but deep snow there protectsthe tundra, allowing some work toprogress. PGS is doing 3D seismic at alocation 30 miles west of the Haul Road,and it is doing 2D work at another site 10miles east of the road.

State officials were frustrated by poorflying weather the week of Feb. 4, whichturned back attempts to visit the PGSlocations to measure frost depth andobserve activity.

BLM approval Dec. 31

The Bureau of Land Managementapproved ice road construction and tun-dra travel on Dec. 31. Usually BLM fol-lows the state lead, but this year has beenunusual, Don Mears of BLM told PNA.He said NPR-A seems to be colder thanDeadhorse.

Phillips Alaska Inc. has been haulingsupplies and equipment by rolligon to itsNPR-A Hunter prospect and is buildingice roads now, Mears said.

Anadarko Petroleum Corp. is work-ing on ice pads for Altamura No. 1 well,south of Phillips and Anadarko’sMoose’s Tooth discovery in the NPR-A.Once the pad is complete, Nabors Rig14E will be used, the company said.

Nabors 14E is currently broken downto allow it to be transported to the site byrolligon, according to Jim Denney,Nabors Alaska Drilling Inc. president.Part of the camp is already in place tohouse pad construction crews, he said. ◆

South of the 69 degree 40 minutenorth latitude line, winter movement

is being considered on a case-by-case basis, Leon Lynch, state

Division of Mining, Land and Water,told PNA.

The state first opened portions of the North Slope to tundra travel Jan. 25 — the latest evertundra travel opening, breaking the previous record set Jan. 14, 1999.

Judy

Pat

rick

By Kay CashmanPNA Publisher

Marathon Oil Co.’s capital budget forAlaska is between $30 and $35million for 2002, up from justunder $30 million last year, John

Barnes told PNA Feb. 6. He is manager ofthe company’s Alaska business unit.

Barnes said spending will almost cer-tainly exceed $30million but probablynot surpass $35 mil-lion.

The estimate isnot exact because thecompany does notknow how much itwill spend this yearon the soon-to-be-built, 75-mile Kenai-Kachemak gas trans-portation pipeline.

The line will con-nect new sources ofgas from the recently announced discoveryat Ninilchik and other potential prospects tothe Kenai hub, where existing infrastructurewill make it available to residential, utility,and industrial users.

“In addition, the project will enableEnstar or other local distributors to considerexpanding their market areas to supply newcustomers south of Kenai,” he said.

The amount Marathon will spend on thepipeline this year will depend on the resultsof the open season, “which requests expres-sions of interest in contracting for pipelinespace,” Barnes said.

Marathon and Unocal, its partner inKenai Kachemak Pipeline LLC, started thisprocess late last year.

“The cost uncertainty is based on thefinal size and route of the pipeline. Once theopen season is complete, we’ll know what

our capacity requirements and timing willbe and therefore how much we have tospend on pipe. … It might be as much as$10 million this year, but I’d be surprised ifit were more,” he said.

Consistently increasing spending

Marathon has been “consistentlyincreasing” its Alaska staff and spendingfor the last several years, Barnes said:“Today we have 50 full-time employees inAlaska; three or four years ago we had 40.”

That head count does not include theInlet Drilling crew which mans Marathon’snew drill rig, the Glacier No. 1, which isworking in its Kenai Gas Field.

“We spudded our first well with the rigin April 2000 and in less than two yearshave drilled 100,000 foot of new hole.That’s the highest level of activity for a rigin the inlet in quite some time, at least,”Barnes said.

For now, just Cook Inlet and gas

Marathon’s Alaska exploration, produc-tion and processing activities in Alaskainvolve primarily gas in the Cook InletBasin, versus oil or the North Slope. Barnessaid that will likely remain the case for atleast the near future.

While the company “monitors” leasesales on the North Slope and opportunitiessuch as the state’s exploration licensing pro-gram, Marathon has not chosen to broadenits scope beyond the Kenai Peninsula whereit currently supplies more than 60 percent ofthe natural gas consumed by SouthcentralAlaska utility markets.

The company operates five gas fields —Wolf Lake, Beaver Creek, Cannery Loop,Kenai and Sterling. Wolf Lake, northeast ofSoldotna, came on line in November and isthe first Cook Inlet gas discovery to bedeveloped since 1979.

Marathon is also part owner of the

Phillips-operated liquefied natural gas plantat Nikiski.

In the last two to three years the companyhas gained a reputation on the Kenai for itsaggressive exploitation of existing fields,employing new technology there and in itsincreasingly active exploration program.

Too soon to tell

The impact of the new Enstar Natural GasCo./Unocal exclusive gas supply contract onthe Marathon’s search for more sources ofgas in the inlet?

“It’s too early to tell,” Barnes said.As Marathon’s supply contracts with

Enstar expire, Unocal will have the right tofill them — if Unocal is successful in findingand developing new sources of natural gas.

“The market uncertainty is definitely hav-ing a downward impact on how we look atexploration spending, but exploration is amulti-year plan and Marathon is not going tofrivolously cancel planned expenditures. Notyet. Not this year, anyway,” Barnes said.“Not until we know what’s going to happento the market.”◆

COOK INLETPetroleum News • Alaska 9Week of February 10, 2002

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MATANUSKA-SUSITNAEvergreen Resources would workwith local contractors

Evergreen Resources Inc. has a completely integrated approach to coalbedmethane development and owns its own drilling, completing, fracturing and wellcompletion equipment, the company’s president, Mark Sexton, told the HouseSpecial Committee on Oil and Gas Jan. 29.

But, he said, Evergreen also works extensively with local contractors, “once weget going and find the right combination of techniques” for a field.

Evergreen acquired the Pioneer unit in the Wasilla-Houston area in 2001 andwill start by re-completing existing wells, Sexton said, bringing in a coiled tubingcompletion unit.

The company operates more than 700 coalbed methane wells in the Raton Basinin the Rockies and is a coalbed methane technology leader, he said.

Coalbed methane is “very process oriented” and all the basins are different,Sexton said. Coalbed methane development also requires large economies of scale,and the company could drill hundreds or thousands of wells in Cook Inlet “if wecan crack the code” for the basin.

But Evergreen will start slowly, he said: In the Raton Basin, where the compa-ny now drills almost 150 wells a year, it started with four wells the first year andbuilt up gradually.

—Kristen Nelson

■ A N C H O R A G E

Marathon’s budget for Alaska up from last year

John Barnes saidMarathon has been“consistentlyincreasing” itsAlaska staff andspending for the lastseveral years.

By Kristen Nelson PNA Editor in Chief

The Alaska Supreme Court ruled Feb.1 in favor of Tom Lakosh’s chal-lenge to the Department ofEnvironmental Conservation’s regu-

lations for oil spill contingency plans. The Supreme Court said it agrees with

Lakosh that DEC’s definition of bestavailable technology in its regulations iscontrary to that specified by theLegislature in statute. It reversed aSuperior Court ruling in favor of the stateand declared the regulation invalid.

The state’s 1980 Oil Pollution ControlAct required that oil spill prevention andcontingency plans “provide for the use ofthe best available technology by theapplicant.”

The court said that in 1990, after theExxon Valdez oil spill, the Legislaturestrengthened the statute to require that allcontingency plans meet legislativelyspecified performance standards for con-taining, controlling and cleaning upspills. The Legislature also modified thebest available technology requirement,specifying that contingency plans “mustprovide for use … of the best technologythat was available at the time the contin-gency plan was submitted or renewed.”

Regulations effective in 1997

The Legislature left the phrase “bestavailable technology” undefined, thecourt said, but directed DEC to “establishthe procedures and time limits applicableto agency review of contingency plans.”

The agency adopted regulations in1997. Lakosh challenged the new defini-tion of best available technology in theregulations in Superior Court andappealed to the Supreme Court after thelower court found in favor of the state.

Alaska Statute 46.04.030 (k) requiresthat contingency plan holders complywith specified standards for spill contain-ment and cleanup. Subsection .030 (e)requires that oil spill contingency plans“provide for the use by the applicant ofthe best technology that was available atthe time the contingency plan was sub-mitted or reviewed.”

The court said DEC adopted a “three-tier” approach in defining best availabletechnology in its regulations. The firsttwo tiers, for cleanup and containmenttechnology and for oil spill preventiontechnology, DEC said technology meetsthe best available technology requirementif it can meet required performance stan-dards.

The third tier covers remaining tech-nology — not subject to either cleanup orprevention performance standards. There

DEC determines if best available technol-ogy criteria is met “by undertaking acase-by-case evaluation based on speci-fied criteria,” the court said.

Definitions inconsistent withstatute

The court said it should give DEC def-erence in its interpretation “only to theextent that the Legislature has actuallygranted DEC authority to define bestavailable technology.” The court said theLegislature “specifically required” theuse of best available technology. Lakoshemphasized, the court said, the statute’suse of the word best. “As commonlydefined, the superlative ‘best’ posits auniverse of suitable or satisfactory candi-dates and denotes selection of a smallergroup of those most desirable within thatuniverse.”

The Legislature adopted mandatoryperformance standards at the same time itrequired the use of best available stan-dards to meet those standards. Becausethose requirements are separate subsec-tions of the statute this indicates that theLegislature was requiring both the “abili-ty to comply with applicable performancestandards” and use of best available tech-nology, the court said.

“The first two tiers of DEC’s bestavailable technology regulation conflatethese separate requirements by collapsingbest available technology into compli-ance with requisite performance stan-dards,” the court said, effectively render-ing the statutory “best available technolo-gy requirement superfluous…” If theLegislature had wanted ‘appropriate andreliable’ technology, the court said, itcould have easily omitted the best avail-able technology language entirely.

Standards a proxy

The court said “DEC essentially arguesthat performance standards are a legitimateproxy for best available technology — thatgood technology is bound to follow if per-formance standards are set sufficientlyhigh.” The court said that while it assumes“DEC’s approach may have considerabletheoretical merit, it is legally incompatiblewith the approach that the Alaska legisla-ture adopted … the statute requires DEC toinsist on the use of best available technolo-gy in addition to demanding compliancewith performance standards.”

The court said that while it finds the reg-ulations invalid, “we emphasize the limitedscope of our ruling.” DEC does have theauthority and expertise to define best avail-able technology, and the court said itbelieves the agency has the authority bothto prescribe methods to select “the bestfrom among all available technologies thatare satisfactory” and to decide how manysatisfactory technologies should be accept-ed as ‘best.’

But, the court said, “DEC’s definitionmust at least include some winnowingprocess” and “requires something morethan accepting all available technology thatcan ‘appropriately and reliably’ complywith oil spill prevention and cleanup per-formance standards.”

What’s next

DEC spokesman Charles Fedullo toldPNA: “We’re going to look at regulatorychanges that could fix it, and some changesto contingency plans. We don’t think itchanges anything that’s in place now.We’re still analyzing it and if we find thatthose changes don’t fix it, we could ask theLegislature to clarify their intent.” ◆

ENVIRONMENT & SAFETY/ARCTIC GAS10 Petroleum News • Alaska Week of February 10, 2002


Supreme Court tells DEC to amend definitions Justices agree with Tom Lakosh that Department of Environmental Conservation regulations at odds with state statutes indefinition of best available technology

“DEC’s definition (of best availabletechnology) must at least include

some winnowing process” and“requires something more than

accepting all available technologythat can ‘appropriately and reliably’comply with oil spill prevention andcleanup performance standards.”

—Alaska Supreme Court

CANADAU.S. pays C$28 billion for Canadiangas in last contract year

Just how important Canadian gas exports are on both sides of the border is capturedin the latest National Energy Board statistics, showing sales for the 2000-01 contractyear of 3.85 trillion cubic feet and revenues at a staggering C$28.55 billion.

The sales year, which ended Oct. 31, 2001, far outpaced the returns for the previ-ous two years of C$16.62 billion on sales of 3.50 trillion cubic feet and C$10.44 bil-lion from exports of 3.29 tcf.

The exports of 3.85 tcf contributed towards total U.S. consumption for the year of19.58 tcf, which was down 6 percent from the previous year.

The revenue gains were boosted by last winter’s sky-high prices lifted the averagefor the year to C$6.91 per gigajoule from C$4.42 and C$2.95 the previous two years.

The peak months were December 2000 and January 2001, when prices averaged abreathtaking C$10.14 and C$13.06 versus C$3.13 and C$3.12 in the same months ofthe 1999-2000 contract year.

The U.S. Energy Information Administration has forecast a slight rise in Canadiangas imports this year, followed by a solid 10 percent increase in 2003 as demandsresumes a growth curve.

Posting the strongest increases in Canadian gas consumption for 2000-01 were theU.S. Midwest, which grew by more than 14 percent to 1.49 tcf, and the U.S. Northeast,up by almost 18 percent to 1.15 tcf.

Underpinning those surges were the Alliance pipeline, shipping 1.5 billion cubicfeet per day from British Columbia to Chicago, and Nova Scotia’s Sable OffshoreEnergy Project, which now delivers 550 million cubic feet per day to New England.

—Gary Park

Week of February 10, 2002

ARCTIC GAS

Petroleum News • Alaska 11

WASHINGTON, D.C.Murkowski’s Feb. 4 meetinggets mixed results

Reactions were mixed to the Feb. 4 meeting of Alaska NorthSlope gas producers, U.S. and Canadian pipeline companies andstate of Alaska officials who got together in Washington, D.C., atthe invitation of U.S. Sen. Frank Murkowski. Participants met forabout 2 1/2 hours behind the closed doors of a Senate hearing room.

Murkowski dubbed the meeting a success: “The fact that theywere all together — this was their second meeting (referring to theproducers and pipeline companies) I would suggest is progress insome measure.”

Prior to the meeting, Murkowski said part of its purpose was toidentify what role industry saw the state and federal governmentsplaying in the project, including what incentives were needed tomove an Alaska Highway gasline forward.

The senator said he was in favor of federal incentives but want-ed to know exactly what was needed before the Senate takes actionthis month on an energy bill that includes gas pipeline incentives.

State Rep. Joe Green, R-Anchorage, who also attended the meet-ing, said ExxonMobil was steadfast that financial incentives won'thelp the project, BP was leaning toward Exxon's view but open tolistening, while Phillips has proposed a guaranteed price floor.

ExxonMobil representatives have maintained that governmentincentives are transitory and the project has to stand on its own eco-nomic legs.

“Some of us have a little difficulty in understanding that,” Greensaid. “If it's close economics, it seems to me a small incentive mightbe enough to push you over.”

State Sen. John Torgerson, R-Kasilof, said the meeting mostlyidentified barriers to the project.

“They've got a long ways to go,” he said.

No progress on who will build gasline

Prior to the meeting, Murkowski said he hoped the meetingwould help determine who would build a natural gas pipeline fromAlaska’s North Slope to Lower 48 markets — the three North Slopeproducers or the 10 major pipeline companies that are part of theAlaska Natural Gas Transportation System group.

A pipeline company representative at the meeting, who pre-ferred not to be named, told PNA Feb. 5, “absolutely no progresswas made on the resolution of that question.”

The producers are “still very clear that they don’t have an eco-nomic project yet.” They “can’t seem to agree on what can helpmake a gasline economic.”

There also continue to be differences, he said, about the route ofthe proposed line — whether it should follow the trans-Alaskapipeline corridor south to the Alaska Highway through Canada toLower 48 markets or travel east along the Beaufort Sea to theMackenzie Delta gas field in Canada and then south to the Lower,which the producers still maintain would be cheaper.

After the meeting Murkowski said any federal energy legislationmust explicitly bar an “over-the- top” route that moves gas throughthe Beaufort Sea to Canada’s Mackenzie Delta.

■ J U N E A U

State Revenue report finds little benefit in pipeline investment


The state doesn’t have the money. It’s not a par-ticularly good investment. The state wouldn’tgain much of a voice in management. It would-n’t speed the project. And the oil companies

really don’t want Alaska as a partner in the proposedpipeline from the North Slope to North Americanmarkets.

Those are among the conclusions of a report bythe state’s Department of Revenue on state invest-ment in the pipeline project. The report, released Jan.31, was prepared at the direction of the Legislature.

Unlike a special committee of the Governor’sAlaska Highway Natural Gas Policy Council, theRevenue Department’s report doesn’t conclude flatlythat the state should avoid ownership in the pipeline,perhaps in deference to the politicians’ right to decidepublic policy.

“Although we believe the financial risks to thestate are substantial, it is possible that some woulddecide — as a matter of public policy — that the stateshould take such sizable risks in an attempt to exer-cise greater control over its own destiny,” says thereport’s cover letter from Revenue CommissionerWilson Condon.

While a state role mostly would have negativeimpacts on the deal, there is one area where the statemight improve the economics of a gas line, the reportindicates.

“If the state could provide a means for tax-exemptfinancing of the project, it might improve the eco-nomic feasibility of the project and therefore increasethe chances the project is actually constructed,” saysthe report.

But even that might not be persuasive to the com-panies that would build and operated the line.

“Even with the lower interest rate on tax-exempt

see REPORT page 16


Knowles wants tax-exempt bonds forgasline; could shave $1 billion off costRailroad authority to issue bonds which would be used under Knowles plan

By Allen BakerPNA Contributing Writer

Tax-exempt bonds issued by the Alaska RailroadCorp. could be used to shave $1 billion off thecost of a natural gas pipeline to the Lower 48,Gov. Tony Knowles says.

Estimates prepared by the state Department ofRevenue and Goldman Sachs provide the savings fig-ure, in today’s dollars, which would come over the lifeof the project, Knowles said.

In a speech prepared for a Feb. 7 meeting of theAlaska Highway Natural Gas Pipeline PolicyCouncil, Knowles said that when the state took own-ership of the railroad in 1983, Congress granted therailroad the ability to issue tax-exempt revenue bondsto finance industrial development.

The special exemption granted by Congress at thebehest of Sen. Ted Stevens supercedes restrictions intoday’s tax law, Knowles said.

Although the railroad would issue the bonds, nei-ther the railroad nor the state would own the gasline,

or be responsible for the debt, Knowles maintains.That would be the responsibility of the private com-panies that build, own and operate the line.

Bill to go to Legislature

Knowles said he was prepared to send theLegislature a bill to provide the railroad with stateauthority to issue the bonds to get the pipeline built.And he said he was asking the producers to give theidea a close, hard look.

The method has been used in Alaska previously,the governor said, notably when the city of Valdezissued tax-exempt bonds for $1.265 billion for con-struction of the terminal for the trans-Alaska oilpipeline.

For that project, as with most revenue bonds, theproject and its revenues constitute the sole source ofmoney for paying off the debt, though the creditcapacity of the oil company pipeline owners also pro-vided security, according to a recent report on statefinancing of a gas pipeline from the Department of

see KNOWLES page 16

The credit was established to allowthe state access to information itwouldn’t normally get and to allow itto show that information to companieswho might want to bid in a state oil andgas lease sale, Myers said.

Thirty million dollars was allowedfor the entire program, up to $5 millionper project.

Myers said that credits of more than$50 million have been given in previ-ous exploration incentive credit pro-grams, but none in the current pro-gram.

The state received two applications.Anadarko Production Corp. applied forseismic in the National PetroleumReserve-Alaska and was offered an 18percent incentive credit, but didn’taccept because the state could show thedata to other companies. Anotherapplication was received for geochem-ical data. Myers said the state didn’tgrant that application because italready had seismic data for the areaand didn’t think geochemical wasimportant enough to help pay for.

Value to state?

Myers said there is a wrinkle in thecurrent interest in exploration incentivecredits.

Rep. Fate said Andex, a privatelyowned independent based in Houston,Texas, was interested in explorationincentive credits for work it plans inthe Nenana Basin, at least some ofwhich will occur after the programends in 2004.

But, Myers said, the basin is not in a

traditional competitive oil and gaslease sale area. Andex has applied for a500,000 acre exploration license in thebasin and that license will precludecompetitive leasing for whateverlicense term the state grants, plus theinitial term of whatever leases Andextakes in the license area following itsexploration program.

This raises the issue, Myers said, ofwhether the data has value to the state.The exploration incentive credit pro-gram was set up, he said, to allow thestate access to data it could use in itscompetitive oil and gas leasing pro-gram.

Myers said DNR’s position on thislegislation is neutral: “We think it’s apolicy call for the Legislature.” But, hesaid, DNR would like the Legislatureto clarify its intent for the credit inexploration license areas.

If the Legislature now intends thatcredits be given to reduce companyrisk, it needs to put that purpose inplace in statute, he said, because rightnow the commissioner can only evalu-ate proposals based on the value of thedata to the state.

Myers also said that the Departmentof Law is researching whether a creditcan be given in a license area, since itapplies only to areas on non-leasedland.

Credit just like cash

Asked by House Oil and GasCommittee Chairman Ogan about thecommissioner’s discretion in grantinga credit, Myers said it is pretty clearthat the intent of the Legislature wasfor the commissioner to have discre-

THE REST OF THE STORY12 Petroleum News • Alaska Week of February 10, 2002


CREDITS

see CREDITS page 13

have done the bidding with their rival pro-posals, Enbridge has apparently decided toshow its hand.

Its version of a northern route system isphysically similar to that unveiled lastmonth by Arctic Resources and itsCanadian affiliate, ArctiGas ResourcesCorp.

Twinned 36-inch lines

The concept involves two, twinned 36-inch-diameter lines connecting the NorthSlope and Delta with pipelines buriedunder the Beaufort Sea and running aboutfour miles off the coast.

From the Delta, the system would rundown the Mackenzie Valley into Alberta,where it would feed into the Alliancepipeline, which ships 1.5 billion cubic feetper day from northern British Columbia toChicago.

Enbridge is a 21.4 percent stakeholderin Alliance, whose other partners areCoastal Corp. 14.4 percent, Fort ChicagoEnergy Partners LP 26 percent, TheWilliams Companies Inc. 14.6 percent andWestcoast Energy Inc., soon to be takenover by Duke Energy Corp., 23.6 percent.

Regardless of the stiff opposition to anorthern route from the Alaska and Yukongovernments and environmentalists,William Lacey, an analyst withFirstEnergy Capital Corp. in Calgary,rated the Enbridge proposal as having afair chance of success.

He noted that Enbridge, which carriedan average 2.196 million barrels per day ofcrude on its pipelines to eastern Canadaand the United States in 2001, has theadvantage of strong relationships with pro-ducers.

Offsetting that is the partnership withsuch pipeline giants as Dynegy Inc. andDuke Energy that favors TransCanadaPipeLines Ltd., the joint owner withWestcoast of Foothills.

Multiple lines required

But Lacey downplayed talk of a rival-ry, arguing that no single pipeline compa-ny would have either the means or thedesire to take on Arctic gas shipmentsalone.

He predicted that a final arrangementwould likely involve a consortium ofpipelines and producers.

In speaking to a New York energy con-ference last year, Daniel indicated thatEnbridge’s careful approach to Arcticdevelopment should not be interpreted asa lack of interest or ambition.

“Our approach is to work with the pro-ducers and provide a service to them tohelp them evaluate which route is best,rather than being out there proposing oneover the other,” he said. “We’re afraid thatwill only create confusion in the regulato-ry process.

“We’d rather work with the producersin the background rather than being outpounding our fist on the table and sug-gesting a particular route.”

To that end, Enbridge has been in dis-cussions with both North Slope and Deltaproducers.

“We intend to be involved in either orboth pipelines and that’s based on our

relationships in the North and the fact thatwe operate in the North. We’re the onlyCanadian pipeline that does that,” Danielsaid, referring to the Norman Wells oilpipeline and a small gas link from theDelta to Inuvik, Northwest Territories.

In other comments, Daniel has said that“probably cost will win out in the long runin the interest of southern consumers.”

Higher cost in two pipelines

He said two pipelines would be inEnbridge’s interests, but, given the highercosts, wouldn’t necessarily favor con-sumers.

As the race to secure pipeline rights inCanada tightens, TransCanada PipeLinesLtd. is promoting its “master plan” forgetting Arctic gas to Lower 48 markets.

TransCanada chief executive officerHal Kvisle told the Toronto Globe andmail last month that TransCanada’s exten-sive pipeline network in Alberta wouldneed only minimal help to carry whatevervolumes are produced in Alaska or theNorthwest Territories.

He said that means a new pipelinewould be required only to the Alberta bor-der, not right across the province to theU.S. border.

“Our existing infrastructure, given thesize of it, can accommodate significantincremental volumes,” Kvisle said.

“And with relatively modest expan-sion, we can accommodate a lot more.

Alaska gas for $10 billion

Under TransCanada’s plan, Alaska gascould be brought on stream for US$10 bil-lion — $8 billion for a pipeline from theNorth Slope to Alberta and another $2 bil-lion for upgrades and additions to theAlberta system — far less than the $17billion Alaska’s producers have projectedfor a standalone pipeline carrying 4.5 bil-lion cubic feet per day from the NorthSlope to Chicago.

Kvisle said even another 1 bcf per dayfrom the Mackenzie Delta could be han-dled by TransCanada’s Alberta pipelines.

In addition to cost savings, theTransCanada plan — advanced on behalfof Foothills Pipe Lines, the joint ventureof TransCanada and Westcoast EnergyInc. — “offer the huge advantage of pro-viding for different scenarios,” he said.

The master plan, which was presentedto Alaska producers last month, “is reallyfounded on flexibility,” Kvisle said.

He said the TransCanada and AlliancePipeline Ltd. system already have about2.5 bcf per day of spare capacity.

If gas production from the WesternCanada Sedimentary Basin falls fasterthan it already is, because of maturingfields, that surplus space will onlyincrease, he said.

But even if another 2 bcf per day isrequired that cold easily be achievedthrough capacity additions toTransCanada pipelines — a decision pro-ducers would not have to make for sometime.

The only downside, Kvisle said, is thatcurrent gas prices make it difficult forArctic producers to commit to such a mas-sive undertaking. ◆


ENBRIDGE

“Our existing infrastructure, giventhe size of it, can accommodatesignificant incremental volumes

(from Alberta to the U.S. border).And with relatively modest

expansion, we can accommodate alot more.” —Hal Kvisle,

TransCanada PipeLines Ltd.

Under TransCanada’s plan, Alaskagas could be brought on stream for

US$10 billion — $8 billion for apipeline from the North Slope toAlberta and another $2 billion for

upgrades and additions to theAlberta system — far less than the$17 billion Alaska’s producers haveprojected for a standalone pipelinecarrying 4.5 billion cubic feet per

day from the North Slope to Chicago.

tion on how much he valued the informa-tion.

Rep. Fate asked if the credit wouldcome out of the production stream andMyers said that while it can be applied onrentals, royalties and bonus bids, it wouldbe likely that the credit would be sold to acompany with production: “It’s just likecash in essence,” he said.

A licensee doesn’t have rentals orbonuses, taxes or royalties, “so they havenothing to take” the credit off of.

Myers said the state believes theNenana Basin is a “very attractive basin,especially for gas.” Two wells have beendrilled in the basin, he said, but neitherwas deep. It has “very prospective reser-voir rocks … gas was generated in thebasin,” he said.

The state held a competitive oil andgas lease sale in the basin in 1982 andreceived 14 bids and ARCO Alaska Inc.drilled following the sale.

The basin is also close Fairbanks andto highway infrastructure. With gas sell-ing at $8 a thousand cubic feet inFairbanks, there is an incentive forexploration and Myers said the stateexpects to issue the exploration licensethis fall.

A company pays $1 an acre for thelicense: all other money goes into explo-ration. But, Myers said, the state couldhave gotten some $10.5 million in bonusbids and rentals in a competitive oil andgas lease sale if those 500,000 acres hadreceived bids at $5 an acre.

Andex’s Nenana plans

Jim Dodson told House Oil and Gasthat Andex hopes to have its explorationlicense for the Nenana Basin this year.

ARCO walked away from explorationin the basin because the Fairbanks gasmarket wasn’t a significant market forthem, he said.

“It’s the right-sized project for a com-pany our size.” No one has ever drilledto 12,000 or 14,000 feet in the basin, so“we don’t know particularly what kindof seal rock we may have in the basin,”Dodson said.

Andex hopes to get its explorationlicense early enough this year that it canapply to shoot seismic over the basin inthe winter of 2002-2003.

The company would look at the seis-mic and then drill in 2003-2004. If morethan one prospect was apparent from theseismic data, he said, the company coulddrill two wells in 2004 and hook up withgas to Fairbanks as early as 2005.

Rep. Ogan asked Dodson to elaborateon the company’s drilling plans, andDodson said that after the companyshoots seismic it would use it to generateprospects, when drill a well in 2003-2004. Andex would also want “a goodset of sonic logs to tie into the seismicdatabase” to better define informationfrom the seismic with porosity and den-sity information from sonic logs. Thatwould probably happen in the summer of2004 and then in the winter of 2004-2005 the company could drill one tothree wells and then decide on apipeline.

The seismic would probably be pre-dominately two-dimensional, he said,

although some 3-D would also be shot. Initial costs are $500,000 for the

exploration license, $6 million for seis-mic and $6 million per well. Dodsonsaid Andex thinks three wells will berequired, so project cost would be morethan $24 million before the pipeline.

Risk reduction

Asked by Rep. Gretchen Guess, D-Anchorage, how the exploration licenseand exploration incentive credit wereviewed by Andex, Dodson said that inthe absence of a lease in the area, “thelicense was important to us because wedon’t want to be out spending money ona block of land unless data we acquirewill be beneficial to us.” The credit, hesaid, “makes the decision to drill lessrisky… we do see the two fitting handand glove: In the absence of a license wewouldn’t spend money on a well.”

Dodson said Andex’s interest in theexploration incentive credit “is to helpus in carrying out our exploration effortwhile reducing the capital risk.” Thestate, he said, would be promoting gas toFairbanks.

In response to a question from Rep.Reggie Joule, D-Kotzebue, Dodson saidAndex is also interested in other basins

in the state: “of most interest after thiswould be Yukon Flats and Susitna Basinand a possible joint venture with Forest.”

Who takes the risk?

HB 307 was passed out of House Oiland Gas Jan. 31 and the discussion con-tinued in House Resources Feb. 1.

Rep. Beth Kerttula, D-Juneau, askedMyers why the state would want toreduce the risk on a basin like theNenana, which looked so good for gas.

Myers said old 2-D seismic shows thebasin and there have been gas shows, butno commercial reservoir was encoun-tered in the two wells drilled. The deep-est part of the basin hasn’t been tested.

“It’s clearly not a slam dunk… Thestructures are there, reservoirs there, gasthere. The question is, are the trapsthere?”

Not only do they have to find gas,

they also have to find a large enoughquantity to justify possible gas treatmentplant and a gas transportation system,Myers said.

If the exploration incentive creditprogram is extended and if credits aregranted in the Tanana Basin, “otherbasins would want equal treatment,would have similar expectations,” hesaid.

Rep. Joe Green, R-Anchorage, saidthe risk is to the company, not to thestate.

“What are we giving up for what wemight get back? We’re risking someamount of money we might have gottenif they’d gone in without state help…even if we pass this, it’s no guarantee …the commissioner will grant explorationincentive credit… …if we can ease someof those concerns I think the returns tothe state would be huge…”

Rep. Fate said the risks to companiesare huge: “they have to decide whetherto spend millions for 3D seismic andmillions for a well.” The state, he said,risks “not developing an environmental-ly clean resource” if companies don’tdrill.

House Resources passed HB 307 outof committee at the end of the hearing. ◆

THE REST OF THE STORYPetroleum News • Alaska 13Week of February 10, 2002


CREDITS

“It’s clearly not a slam dunk… Thestructures are there (in the Nenanabasin), reservoirs there, gas there.

The question is, are the trapsthere?” —Mark Myers, Division of Oil and Gas

DNR would like the Legislature toclarify its intent for the credit inexploration license areas. If the

Legislature now intends that creditsbe given to reduce company risk, itneeds to put that purpose in place

in statute, Myers said.

ADVERTISER INDEX14 Petroleum News • Alaska Week of February 10, 2002

House Oil and Gas after receiving vigorousopposition from the Division of Oil and Gas.

Committee Chairman Scott Ogan saidhe wanted to do what he could to pro-mote energy for Fairbanks, but was con-cerned the discovery credit there couldbe a negative to the state. Ogan askedDivision of Oil and Gas Director MarkMyers what the division thought of theproposal.

Myers said with an exploration licensethe state is already foregoing bonus bidsand rentals of as much as $10.5 million.If you add an exploration incentive cred-it of as much as $5 million a project,combined with discovery royalty, it“wouldn’t give the state much,” he said.

In Cook Inlet, Myers said, six poolswere identified as eligible for a discoveryroyalty. On Redoubt Shoal alone thestate will lose about $29 million; ifPhillips Alaska Inc. is successful at itsStarichkof prospect (Cosmopolitan), thediscovery royalty at that project willprobably also cost the state $29 million,he said.

A discovery royalty program existedin Cook Inlet and on the North Slopebefore production began, a programrepealed in 1969, and Myers said therewas a long history of litigation with thatprogram. The state gave a discovery roy-alty on Alpine and is in litigation with BPand Phillips on a 37-year-old lease in thePrudhoe Bay unit.

“I don’t believe it’s been an effectiveincentive,” Myers said. The state has“given away millions” and “I don’tbelieve it has promoted exploration.”

The availability of a market and thecommodity price have a much greaterimpact on exploration activity than a dis-

covery royalty, he said.

Division opposes discovery royalty

The Division of Oil and Gas is opposedto this, he said: “The state has other pro-grams we think are much more effective”where a royalty reduction is given based ona company demonstrating that a project isnot economic without a royalty reduction.

“What part of the bill do you like?” Oganasked.

The state has a long history with this pro-gram, Myers said: “I don’t personally likediscovery royalty at all.”

Asked about a discovery royalty forremote basins, Myers said he thought“exploration license is the way to go.”Economic opportunity and ability to com-mercialize is what drives exploration, hesaid.

Andex doesn’t agree

Andex Resource’s Jim Dodson said heabsolutely thinks discovery royalties are anincentive to exploration. You “can’t wringout the risk in commodity pricing,” he said,so anything else that can help reduce yourrisk you should do.

Andex has applied for an explorationlicense in the Nenana basin where it plans toexplore for gas.

Andex is asking the state to extend theexploration incentive credit, he said, butexploration incentive credits are discre-tionary with the commissioner.

“We could get an answer of zero fromthe state on that,” Dodson said.

Rep. Gretchen Guess, D-Anchorage,asked why the company wouldn’t ask forroyalty reduction for economic reasons: youmight get a royalty of less than 5 percent, itmight be better, she said.

Dodson said the company was lookingfor certainty, and wanted to avoid “an ad hocdecision on every well we want to drill.”

—Kristen Nelson

THE REST OF THE STORYPetroleum News • Alaska 15Week of February 10, 2002

Sponsors of HB 380 wanted to encourageCook Inlet development

House Bill 380, sponsored by Rep. Mark Hodgins, R-Kenai, and cross sponsoredby then Sen. Drue Pearce, R-Anchorage, passed the Legislature in 1998 only to bevetoed by Gov. Tony Knowles. His veto was overturned and HB 380 became law.

It was designed to encourage the development of older, economically marginalCook Inlet oil and gas reserves by reducing the royalty rate lessees pay for six specif-ic fields if they were brought into production by Jan.1, 2004.

The reduced royalty rate of 5 percent would be in effect for 10 years and onlyextend to the first 25 million barrels of oil and first 35 trillion cubic feet of gas pro-duced. All of the fields specified in the bill were discovered more than 30 years ago,but industry representatives contended that had always been too expensive to develop.

The sponsor statement for HB 380 in 1998 read as follows:“The intent of House Bill 380 is to encourage the development of gas reserves

within the Cook Inlet sedimentary basin. New gas reserves developed as a result of theproposed legislation could be instrumental in maintaining reliable and economicallypriced gas supplies for Southcentral consumers, including residential and commercialusers.

“In addition to stimulating the development of several known undeveloped fields,many of which were discovered more than 30 years ago, House Bill 380 has the poten-tial to leverage additional exploration and development in the vicinity of new infra-structure, including pipelines and associated facilities, required to develop thoseknown fields. Any new oil and gas production resulting from the development of thesefields will in turn reduce the average cost of producing existing reserves, and extendthe economic life of both existing and new Cook Inlet production and transportationinfrastructure.


ROYALTY

see DEVELOPMENT page 16

THE REST OF THE STORY16 Petroleum News • Alaska Week of February 10, 2002

“Under the terms of the proposed legis-lation, lessees owning leases overlyingpreviously discovered oil or gas fields inthe Cook Inlet basin which have remainedundeveloped or shut-in from at least Jan. 1,1988 through Dec. 31, 1997, would havean incentive to develop those fields asrapidly as possible. The legislation wouldprovide that, for oil and gas produced fromundeveloped or shut-in fields brought intoproduction before Jan. 1, 2004, lesseeswould pay a reduced royalty of 5 percent,instead of the 12.5 percent specified in thelease, for a period of 10 years followingthe date on which oil or gas productionbegins.

“By establishing a short period of eligi-bility — ending on Dec. 31, 2003 —

House Bill 380 ensures that lessees dili-gently pursue development or forfeit theopportunity to pay reduced royalties. Bylimiting the period of reduced royalty pay-ments from qualifying fields to 10 yearsfollowing the beginning of production, thelegislation provides a reasonable and mea-surable limit to the state’s foregone royal-ties in exchange for oil and gas productionthat may otherwise not occur. The state’sroyalties from currently producing CookInlet oil and gas fields will not be affectedby House Bill 380.

“By encouraging the development ofexisting uneconomic oil and gas fields,House Bill 380 will benefit the state andlocal economies through taxation and roy-alties, encourage future development ofnew oil & gas discoveries by lowering thecosts of industry infrastructure, as well astaking care of job #1 — providing jobs forAlaskans.”


DEVELOPMENT

debt,” the report says, “it is still possiblethat the companies might choose to issuetheir own taxable debt in order to takeadvantage of the federal tax benefits ofowning and depreciating the line.”

The report says backers of a state stakein the pipeline project see three major ben-efits: getting a good return on the invest-ment, increasing Alaska’s control of its des-tiny, and improving the feasibility of theproject.

It doesn’t find much evidence that cashput into the pipeline would further any oneof those goals.

Investment return

As an investment, pipelines are similar toother utilities, with a return regulated by theFederal Energy Regulatory Commission inthe United States and a similar body inCanada.

The report says that “we expect thatreturn would not differ significantly fromwhat the state — or the Permanent Fund —could earn from other investments with sim-ilar risks.” State investment as a partnercould mean financial risks if the project wasdelayed or market conditions changed, “andit would be a difficult policy call to tell thepublic that key government services mightbe cut back to make money available forgasline expenses.”

Controlling destiny

Controlling the state’s destiny, at least byinfluencing pipeline development or man-agement, is problematic at best, the reportindicates.

Building the pipeline outright with statemoney would require a huge chunk of thePermanent Fund and major changes in thelaws governing that savings account.

Borrowing enough money to have

majority control or even a major influenceon the project would endanger the state’scredit ratings and raise interest costs foreverything from building schools to homemortgages backed by the Alaska HousingFinance Corp.

“Assuming the state was not the soleowner or majority owner of the gasline, itsseat at the table would most certainly be aminority seat with little or no ability to influ-ence any major corporate decisions,” thereport says. “The state would have moreauthority with its own statutes and regula-tions to influence project management deci-sions than as a minority business owner.”

Improving feasibility

While the pipeline will cost something inexcess of $10 billion to build, industryheavyweights have plenty of cash on hand,as well as traditional private financingoptions.

“Several of the companies interviewedare so large that they said they did not intendto borrow to finance their share of the $10billion to $18 billion project, but intended to`write a check’ off their balance sheet,” thereport said. ExxonMobil’s enterprise valuealone is about $266 billion, the report notes.

And since raising the money isn’t reallyan issue, the constraints of dealing with apublic entity are seen as an impediment.

“There was a general consensus amongindustry representatives interviewed that apublic/private ownership relationship withthe state either would not help or would be ahindrance to the project,” the report says inits conclusions.

The industry sees politics impeding deci-sion-making, a lack of state expertise inowning and managing a pipeline, problemswith having the state be an owner and regu-lator at the same time, and general differ-ences between public and private goals andcultures that would hurt decision-making,according to the report. ◆


REPORT

Revenue.But the financial markets likely would

finance no more than 70 percent of theproject with this kind of debt, the reportsaid. The state could ask the producers toput up the equity share as a prepaid tariff,it suggested.

In its report, Revenue noted that“Even though there almost certainlywould be an economic benefit from tax-exempt financing, whether the resultingstructure is attractive to the producers orpipeline companies is an open question.”

For while tax-exempt bonds offer alower interest rate (the report suggest adiscount of roughly 25 percent, i.e., 6percent financing with tax-exempt bonds

if taxable bonds cost 8 percent), stateownership would eliminate the benefit tothe private owner of accelerated depreci-ation.

Thus in the early years of ownership,taxable borrowing would be more bene-ficial to a private owner, since far moreof the value of the line could be deductedfrom taxable income. The report said that“under one set of reasonable assump-tions, tax-exempt financing is economi-cally advantageous, but it would take 13years for an owner to realize a costadvantage from tax-exempt financing.”

Revenue bonding for a gas pipeline isnot a new idea, the report notes.

“Authority for revenue bonds wasapproved for the Alaska PipelineFinancing Authority in 1978,” it said,although the amount was limited to $1billion. ◆


KNOWLES

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