clock ticks for alaska gas - petroleum news · page 11 alaska legislature goes for sliding scale...

Alaska Legislature goes for slidingscale oil production tax

Vol. 11, No. 12 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 19, 2006 • $1.50

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8 Study predicts: Alaska gas demand: Soon-to-be-released DOE

report looks at what industries could pay for Cook Inlet gas in future

9 Beaufort drilling hangs in balance: Devon to evaluatefirst well since 1989, wants to see Mac gas line progress before drilling

12 Stop that (oil sands) thief! Think tanks call for 5-year freezeto develop national policy; see U.S. as drain on Canadian security

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ANGDA: Alaskans must bid in open season to keep some NS gas in state

BY ALAN BAILEYPetroleum News

ith the current oil industry production profits tax debateand speculation about the stranded gas contract for theNorth Slope gas line consuming the attention of manyAlaskans, there is a danger of missing the boat for book-

ing intrastate capacity in the proposed North Slope gas pipeline.That was a key message during one of the sessions at the AlaskaNatural Gas Development Authority’s March 13 board meeting.

Intrastate capacity is North Slope natural gas that would beused in Alaska vs. for being shipped through Canada to theLower 48 states.

ANGDA is a public corporation of the State of Alaska, estab-lished in 2003 to bring North Slope natural gas to market via a

WHarold Heinze sees ANGDA pos-sibly helping businesses learnhow to bid for capacity — andperhaps combining the capacityrequirements of several busi-nesses. The corporation, he said,could also help in discussionswith RCA regarding approval ofutility contracts.see GAS page 18

Mac wells ‘significant’EnCana, Anadarko, Conoco partnership applies for discovery status at Umiak

BY GARY PARKFor Petroleum News

n EnCana-led partnership has given thestrongest hint yet that exploration drillingon the Mackenzie Delta over the past twowinters may have hit pay dirt.

Along with Anadarko Canada andConocoPhillips Canada, EnCana has applied toCanada’s National Energy Board to declare theUmiak N-05 and N-16 wells as a significant dis-covery.

If the board agrees it will open the way toextend Exploration License 384 beyond its termfor the area where the discovery was made.

The application is based on flow testing andother factors that point to a hydrocarbon accumu-

The Umiak N-16 was the first pure exploration wellby EnCana in the Mackenzie Delta region.

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see WELLS page 20

From left to right, Grey Mitchell, director of the Alaska Departmentof Labor and Workforce Development’s labor standards and safetydivision; Mike O'Connor, president, Peak Oilfield Service Co.; KennySchramko, ConocoPhillips’ supervisor of Cook Inlet production; andJim Bowles, president of ConocoPhillips Alaska.

Beluga field gets safety award

In mid-March the Alaska Department of Labor andWorkforce Development recognized ConocoPhillips Alaska’sBeluga River gas field in the Cook Inlet basin for top-notchsafety and health management programs. The facility wasawarded Star designation in the Alaska Occupational Safetyand Health Voluntary Protection Program in a ceremony at thecompany’s Beluga River Unit facility.

The award recognizes not only ConocoPhillips’ Belugaemployees, but also those of contractor Peak Oilfield ServiceCo., which has a significant presence at Beluga. BothConocoPhillips and Peak staff implemented the OSHA VPPprocess at the worksite in 2005.

VPP recognizes and promotes effective safety and healthmanagement. VPP sites are removed from general scheduledenforcement inspections for the approved period of time (from18 months up to 5 years). Participants have also reportedreduced Workers’ Compensation costs.

VPP is one of several consultation programs offered byAlaska Occupational Safety and Health. At a company’srequest, health and safety consultation officers visit the worksite to help employers identify and correct hazards in the workplace, and train their workforce in safe work practices. Thecompany then has the opportunity to address potential viola-tions before an official inspection occurs.

Best Gulf sale in 8 yearsCentral Gulf Lease Sale 198 draws $588.3 million in high bids on 405 blocks

BY RAY TYSONFor Petroleum News

merada Hess and a slew of other deep-pock-et bidders evidently came to Central Gulf ofMexico Lease Sale 198 March 15 armedwith three fundamental winning strategies —

spend, spend and spend.And spend they did — to the collective tune of

$588.3 million in apparent high bids on 405 off-shore exploration blocks, an astounding 66 percentincrease over last year’s roughly $354 millionCentral Gulf performance on 428 blocks.

It also was the first Gulf of Mexico lease saleheld in New Orleans since last year’s HurricaneKatrina caused levies to fail, putting 80 percent of

the city under water and rais-ing serious doubt whether the“Big Easy” could again hostthe traditional March sale.

Therefore, no one washappier with the sale resultsthan Chris Oynes, Gulfregional director for theMinerals ManagementService, the federal agencythat conducts offshore leasesales and collects the pro-ceeds for Uncle Sam.

“Our calculation is that this, from a high bidsstandpoint, is the highest in the Central Gulf in

Chris Oynes, Gulfregional directorMMS

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see SALE page 20Songa contracts withInlet Drilling for jack-up crew; Escopeta haspre-app, unitization meetings for CookInlet Kitchen project

Greg Carter with Songa Offshore isheaded to Alaska the week of March 19 tomeet with Kenai, Alaska-based InletDrilling, which is supplying the crews for Songa’s Tellus jack-

see INSIDER page 20

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

2 PETROLEUM NEWS • WEEK OF MARCH 19, 2006

GOVERNMENT

9 Canadian Beaufort drilling hangs in balance

Devon Canada to evaluate first well since1989, watch business environment, seeMackenzie progress before moving to second well

16 Borough mayor questions oil leak detection

Itta says clean-up effort first rate as crewspick up 60,000 gal. of an estimated 201,000gal.; crews also working Kuparuk spill

4 Interior Secretary Gale Norton resigns

Norton, former Colorado attorney general, one ofarchitects of Bush’s energy policy, led push for‘cooperative conservation’

EXPLORATION & PRODUCTION

PIPELINES & DOWNSTREAM

ENVIRONMENT & SAFETY

ON THE COVER

Best Gulf sale in 8 years

Central Gulf Lease Sale 198 draws $588.3 million in high bids on 405 blocks

Mac wells ‘significant’

EnCana, Anadarko, Conoco partnershipapplies for discovery status at Umiak

Clock ticks for Alaska gas

ANGDA: Alaskans must bid in openseason to keep some NS gas in state

1 Songa contracts with Inlet Drilling for jack-up crew

1 Escopeta has pre-app, unit meetings for Cook Inlet project

3 Alaska - Mackenzie Rig Report

8 Oil sands trim Canada’s oil production

13 Budget, hiring rise at Northern Lights

14 Spearheading new outlets: Oil moving south

4 Bush nominates Kempthorne for Interior

OIL PATCH INSIDER

Beluga field gets safety award

16 Slope slowdown costs state $1M per day

FINANCE & ECONOMY4 Canadian trusts get jolt from analysts

7 Consultant: $40 likely company base case

7 Tax impacts on exploration,production differ

Econ One looks at likely impacts on different activitiesfrom proposed State of Alaska tax/credit rates of 20/20and 20/25

10 Alaska Legislature goes for sliding scale tax

North Slope, Cook Inlet producers, independents,explorers all unhappy with committee substitute forgovernor’s PPT tax bill

10 Summary of committee substitute to HB 488

11 ‘Beyond petroleum’ talks scheduled

7 Consultant: too-high tax rate easier fix

Daniel Johnston tells legislators 20/20PPT would bring state up to standards of last century; recommends sliding scale tax

12 Stop that (oil sands) thief!

Think tanks call for 5-year freeze todevelop national policy; see U.S.military-industrial complex as drain onCanadian security

12 Alberta’s cash cow keeps delivering

13 Saskatchewan’s budget roller-coaster

LAND & LEASING5 Lawsuit aims to stall NPR-A development

NATURAL GAS5 Canadian LNG: One forward, one back

5 Shell CEO: B.C. offshore can be developed

8 ANGDA study looks at Alaska gas demand

6 Western Canada gas basin fading

6 Glimmer of life in aging play

13 NWT minister says labor shortage critical

14 Some pipeline reg changes elude harvest

Regulatory Commission of Alaska decides actions onmoving forward but finds some ‘low hanging fruit’ tobe just out of reach

PETROLEUM NEWS • WEEK OF MARCH 19, 2006 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) 2N-333 ConocoPhillipsSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 1D-41 ConocoPhillipsDreco 1000 UE 16 (SCR) Workover Endicott Well 222/L14 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD3-311 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk 1J-159 ConocoPhillipsTSM 7000 Arctic Fox #1 Drilling Cronus #1 Pioneer Natural Resources

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES (SCR) Well 16-16B BPMid-Continental U36A 3-S C-21 ConocoPhillipsOilwell 700 E 4-ES (SCR) WGI-03 BPDreco 1000 UE 7-ES (SCR/TD) PM2-18 BPDreco 1000 UE 9-ES (SCR/TD) L-214i BPOilwell 2000 Hercules 14-E (SCR) AKLAQ2 FEXOilwell 2000 Hercules 16-E (SCR/TD) Stacked, Prudhoe Bay AvailableOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableOIME 1000 19-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Stacked, Kuparuk AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Stacked on 12-acre pad Available

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Well P-37a BPSuperior 700 UE 2 (SCR/CTD) Drill Site 6-24a BPIdeco 900 3 (SCR/TD) 1R-East exploration well ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E NorthStar NS-30 BP

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Stacked in Nikiski Available

Kuukpik 5 Drilling Northern Dancer #1 Storm Cat

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 KU 21-7X Marathon

Nabors Alaska DrillingNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 Stacked, Kenai SoldFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Stacked in Kenai Available

Cook Inlet Basin – Offshore

Unocal (Nabors Alaska Drilling labor contractor)Not Available

XTO EnergyNational 1320 A On rig move XTONational 110 C (TD) Idle XTO

Mackenzie Rig StatusCanadian Beaufort Sea

Seatankers (AKITA Equtak labor contract)SSDC CANMAR Island Rig #2 SDC Paktoa C-60 Devon ARL Corp.

Mackenzie Delta-OnshoreAKITA EqutakDreco 1250 UE 62 (SCR/TD) Stacked in Tuktoyaktuk, NT Available

Central Mackenzie ValleyAKITA EqutakRigmaster 850 40 Drilling at Summit Creek K-44 Husky OilDreco 1250 UE 63 (SCR/TD) Drilling at Stewart D-57 location Husky Oil

Yukon Territories Rig StatusYukon

AKITA/KaskaNational 80UE 58 Drilling at Beaver River, BC. Talisman Energy

Ensign Resources Svc. Grp.Jackknife Double 55 Racked in Ft. Nelson

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of March 16, 2006.

Active drilling companies only listed.

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

This rig report was prepared by Alan Bailey

Baker Hughes North America rotary rig counts*Mar. 10 Mar. 03 Year Ago

US 1,532 1, 531 1,282Canada 690 688 441Gulf 84 82 89

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

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CANADACanadian trusts get jolt from analysts

Canada’s energy income trusts have been fingered as the worst culprits withintheir sector for overstating how much they have available for the cash distribu-tions that have made them so popular among investors.

Standard & Poor’s analysts Kevin Hibbert and Ronald Charbon said in a newstudy that 23 of the 40 trusts they surveyed excluded capital spending from theirdistributable cash.

As a result, by sidestepping what they need to spend to maintain their busi-nesses, the trusts are guilty of “materiallyoverstating the amount of operating cashon hand,” the report said.

Hibbert said capital spending to sustainoperations accounts for an average 22 per-cent of the cash generated by trust opera-tions, yet 57 percent of the trusts examinedexcluded those costs in stating how muchspare change they had for unit holders.

In an earlier phase of its study, S&P saidthat inconsistent definitions of availablecash posed “risks” for investors.

The analysts said then that calculations of “distributable cash should be morethoughtful and the related disclosures significantly improved.”

They said some of the cash-generation calculations used by trusts don’t con-form to generally accepted accounting principles and because of that distortionsin available cash averaged 12 percent over two years.

250 Canadian income trustsThe 250 income trusts in Canada carry a market value of C$180 billion — with

energy trusts making up the largest chunk — and have posted returns of about 33percent in the past three years compared with 20 percent for Canada’s benchmarkS&P/TSX composite index.

Hibbert said the findings should force investors to pay closer attention to theway in which trusts support claims of their ability to pay out the cash expected byunit holders.

He said some investors have failed to “appreciate the financial reporting anddisclosure nuances due to a tendency to take at face value the distributable cashand payout ratios that are reported by management.”

Other accountants and analysts have been waving warning flags in recentmonths about the accounting standards in the trust sector.

Independent analyst Harry Levant said some investors view trusts as “yield-based” investments carrying some kind of guarantee, then get upset when distri-butions are adjusted.

—GARY PARK

By sidestepping what theyneed to spend to maintaintheir businesses, the trustsare guilty of “materially

overstating the amount ofoperating cash on hand,” the

report said.

� W A S H I N G T O N , D . C .

Interior SecretaryGale Norton resignsNorton, former Colorado attorney general, one of architectsof Bush’s energy policy, led push for ‘cooperative conservation’

BY JOHN HEILPRINAssociated Press Writer

nterior Secretary Gale Norton resignedMarch 10 after five years of guidingthe Bush administration’s initiative toopen government lands in the West to

more oil and gas drilling, logging, grazingand commercial recreation.

Norton, the first woman to lead theInterior Department in its 157-year history,told President Bush in a letter she intendsto leave at the end of March, saying shehoped to eventually return to the moun-tains of the West.

“Now I feel it is time for me to leavethis mountain you gave me to climb, catchmy breath, then set my sights on new goalsto achieve in the private sector,” she said inthe two-page resignation letter.

A day shy of her 52nd birthday, Nortonemphasized in her resignation letter toBush and in her remarks to reporters thather reasons for leaving were entirely per-sonal. She said she hadn’t done any job-searching, adding she wanted to spendmore time with her husband, John, andtake time for recreational pursuits like ski-ing.

“This is really a question of accom-plishing the goals that I set out do here andwanting to return to having a private lifeagain,” she said.

“I’m looking forward to visiting anational park without holding a press con-ference there,” she said. “I’m looking for-ward to enjoying the wide-open spacesagain.”

An architect of Bush’s energy policyAs one of the architects of Bush’s ener-

gy policy, Norton eased regulations tospeed approval of oil and gas drilling per-mits, particularly in New Mexico,Colorado and Wyoming’s Powder RiverBasin.

In her first three years, the pace ofdrilling permits issued by Interior’s Bureauof Land Management rose 70 percent. Shealso was the administration’s biggest advo-cate for opening the Arctic NationalWildlife Refuge on Alaska’s North Slopeto oil drilling, areas considered sensitivefor caribou and other wildlife.

“We have improved the ways we areprotecting wildlife in ways that energy

development is responsible,” she saidMarch 10. “We spent billions of dollars inimproving wildlife habitat and otherwiserestoring the environment.

Many environmentalists and Democratshave been sharply critical of her steward-ship of public lands.

“Gale Norton was an unpopular symbolof unpopular policies,” said Carl Pope,executive director of the Sierra Club.“Americans do not believe their publiclands should be sold to the highest bidder,and they don’t believe in privatizing theirparks, forests, monuments. While the sym-bol of those unpopular policies may beleaving, we don’t expect those unpopularpolicies to change.”

But others, such as the NatureConservancy’s president, SteveMcCormick, praised her for working asclose partners in creating Colorado’s GreatSand Dunes National Park, the new GlacialRidge National Wildlife Refuge inMinnesota and the Rocky Mountain FrontConservation Area in Montana.

Norton led the Bush administration’spush for “cooperative conservation” —shifting more of the responsibility for landmanagement and recovery of endangeredspecies to states and local communities.The Interior Department oversees the gov-ernment’s ownership of one-fifth of thenation’s land. �

IBush nominatesDirk Kempthorne

PresidentBush select-

ed Idaho Gov. Dirk Kempthorne asInterior secretary on March 16. If con-firmed by the Senate, Kempthorne, aformer U.S. senator and two-termgovernor, would replace Gale Nortonin the Cabinet.

During his time as a senatorKempthorne served as chairman ofthe Senate Subcommittee on DrinkingWater, Fisheries and Wildlife and aschairman of the Senate ArmedServices Subcommittee on Personnel.

He has consistently supportedopening the coastal plain (1002 area)of the Arctic National Wildlife Refugeto oil and gas drilling.

� NEWS FLASH


CANADACanadian LNG: One forward, one back

Petro-Canada has edged ahead of its rivals in the pursuit of Russian LNG forNorth America, but another Canadian project has been stalled by an inability toround up supplies.

Petro-Canada made another advanceMarch 14 when it announced a deal withRussian gas giant Gazprom to work onan initial engineering design for aUS$1.5 billion gas liquefaction facilitywith capacity of 500-700 million cubicfeet per day near St Petersburg, Russia.

The two companies are committed tospend US$5 million at this stage andUS$25 million for more detailed engi-neering.

If Petro-Canada and Gazprom moveto a full-fledged partnership, it hopes tolock up gas supply for 20 years or more to support a C$500 million LNG regasi-fication plant in Quebec in partnership with TransCanada.

The two facilities are targeted for completion by 2010.Petro-Canada Chief Executive Officer Ron Brenneman told a conference call

that Petro-Canada and Gazprom are talking about a 50-50 interest in the St.Petersburg plant, “but the ultimate partnership in both ends of this project are partof what needs to be determined between now and the end of the year when we fin-ish the preliminary engineering work.”

He said his company would also like a stake in Russian gas production,although that would not be part of any Gazprom deal.

Anadarko slows progressMeanwhile, Anadarko has slowed progress on its US$650 million regasifica-

tion plant in Nova Scotia, giving a further boost to Irving Oil’s Canaport terminalin neighboring New Brunswick.

That facility, being developed in partnership with Spain’s Repsol, is due tocome on stream in 2008 — the same year Bear Head was supposed to be com-pleted.

An Anadarko spokeswoman said more time is needed to explore supply possi-bilities in regions such as Russia, the Middle East and Africa.

She said Anadarko remains committed to the project; it just needs more timeto work on negotiating long-term supplies.

—GARY PARK

� N O R T H S L O P E

Lawsuit aims to stallNPR-A development Environmental groups sue Interior over proposed leasing adjacentto Teshekpuk Lake; lease sale planned in late September 2006

BY WESLEY LOYAnchorage Daily News

coalition of environmental groupson March 10 sued the InteriorDepartment in federal court inJuneau in an effort to block expand-

ed oil and gas explo-ration in the north-east corner of theNational PetroleumReserve-Alaska.

The suit, whichbuilds on a prelimi-nary suit the groupsfiled a year ago,concerns the govern-ment’s decision inJanuary to allowdrillers to lease previously closed acreageon the shoulder of Teshekpuk Lake, oneof the state’s largest lakes and a magnetfor thousands of migratory geese. Thearea also is considered one of the petrole-um reserve’s most promising areas for oiland gas discoveries.

The groups contend the Bureau ofLand Management, an Interior agencythat acts as landlord for the Indiana-sizedreserve, violated the Endangered SpeciesAct and other federal laws in failing toproperly analyze the potential impacts ofoil and gas activity on the wildlife-richtundra.

The plaintiffs are the NationalAudubon Society, Alaska WildernessLeague, Center for Biological Diversity,Natural Resources Defense Council,Northern Alaska Environmental Center,Sierra Club and The Wilderness Society.

Defendants include Interior Secretary

Gale Norton, who resigned March 10after five years in the job.

Closures ended in JanuaryIn January, the Bush administration

said it planned to end long-standing clo-sures for the tundra north and east of thelake, giving drillers a chance to find andproduce an estimated 2 billion barrels ofoil and 3.5 trillion cubic feet of naturalgas needed for the nation’s energy securi-ty. The action makes 389,000 new acresavailable for leasing.

The BLM said its leasing plan includesa raft of protections for the region’swildlife, including migratory black brant,threatened spectacled and Steller’s eidersand caribou.

The environmental groups, however,contend the agency paid inadequate atten-tion to the potential for industrial sprawlincluding roads, pipelines and air stripsthat could chop up a unique Arctic havenfor animals of great importance to subsis-tence hunters.

Henri Bisson, the BLM’s Alaska chief,said March 10 he hadn’t yet read the 18-page lawsuit and couldn’t comment on itsspecifics. However, he said the agency isconfident it can lease the land and stillprotect wildlife.

“We absolutely plan to defend ourdecision,” Bisson said.

Jody Weil, a BLM spokeswoman, saidthe agency plans to hold a lease sale for theTeshekpuk region in late September. �

“We absolutely plan to defend ourdecision.” —Henri Bisson, BLM

Alaska state director

Henri Bisson, BLM

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B.C. OFFSHOREShell CEO: B.C. offshore can be developed

Shell Canada Chief Executive Officer Clive Mather gave one of the industry’smost upbeat assessments in recent years of the prospects foroffshore oil and gas development in British Columbia.

He said there is no reason why the offshore can’t beexploited in a way that balances social, environmental andeconomic concerns.

However, he conceded to the Vancouver Board of Tradethat despite tests indicating the “presence” of hydrocarbons,there is no proof of commercial accumulations of oil or gas.

What the tests did establish was the industry’s “ability towork safely and in an environmentally responsible manner”in the region, Mather said.

Shell calls for sustainable developmentHe argued that lifting moratoriums and allowing exploration and possibly

development of the offshore can be done by applying the principles of sustainabledevelopment — that is balancing the social, environmental and economic.

Even if the federal and provincial bans are lifted that is no guarantee of earlyaction, although it will “kick start the regulatory process” that includes tacklingFirst Nations concerns which require claims settlements or cooperative agree-ments, he said.

In addition, ecosystem protection measures must be implemented to ensureareas of environmental significance are protected, Mather said.

Shell Canada, which drilled 14 unsuccessful wells in the 1960s, has expressedhope that technological advances since then can both provide an accurate readingon the region’s potential and reduce dangers to the environment. Petro-Canadaand Chevron Canada are the other significant leaseholders.

—GARY PARK

Shell Canada CEOClive Mather

Petro-Canada made anotheradvance March 14 when it

announced a deal with Russiangas giant Gazprom to work on

an initial engineering design fora US$1.5 billion gas liquefactionfacility with capacity of 500-700million cubic feet per day near

St Petersburg, Russia.


� W E S T E R N C A N A D A

Western Canada gas basin fadingZiff Energy predicts output to drop 2 bcf per day over 8 years, regardless of drilling; worries about rigs, people, supplies, prospects


he importance of getting gas fromNorth America’s Arctic regions tomarket keeps gathering weight, notleast in the lat-

est assessment of theWestern CanadaSedimentary basinby Ziff EnergyGroup.

The highlyregarded Calgary-based energy con-sultant has paintedone of the bleakestpictures yet for abasin that currentlyproduces 16.6 bil-lion cubic feet perday, 70 percent ofwhich is exported,accounting for 16percent of U.S. con-sumption.

In a new outlook to 2014 covering pro-duction of existing gas, new conventionalgas, coalbed methane, tight gas and solu-tion gas from eight gas strategy areas,Ziff is unwavering in its conclusion thatproductivity is declining in the maturingbasin.

Its base case projects a drop in outputto 14 bcf per day over the next eightyears, by when 60 percent of the basin’sultimate potential resource will have beenproduced.

That’s a sharp reversal from the early1990s, when discoveries of BritishColumbia’s Ladyfern field and theNorthwest Territories’ Fort Liard playsuddenly elevated the basin to the futurehope for North American supply growth.

But the two biggest onshore finds inCanada for years have started to fizzle,limiting the WCSB to only marginalgrowth at best despite a succession ofannual drilling records.

Conventional output downConventional output has shrunk since

2001 and, according to Ziff, not helpedby a breakdown in the traditional correla-tion between well completions and gasprices.

The study said that relationship “nowappears to be constrained by availabilityof rigs, people, supplies, services andconventional opportunities in a maturingbasin.”

By 2014, Ziff expects coalbed methaneand tight gas will grow to 27 percent ofWCSB production, with coalbed methanecontributing 1.8 bcf per day; gas fromnew completions will comprise more than60 percent of 2014 production and willrequire completion levels similar to the2004 peak of 15,700 wells; and new gaswell maximum productivity will declineacross the basin, while new gas welldecline rates, currently 30 percent in thethird year, will increase.

Ziff noted than an annual average 2.5bcf of new gas is needed just to replaceproduction declines.

It said 16,500 well completions arepossible as long as the New YorkMercantile Exchange price averagedabout US$7 per million British thermalunits, but if the price slides below US$5Ziff expects more producers will follow

EnCana’s lead and take the scissors totheir budgets.

Even at US$7, marginal prospectswould likely be deleted from budgets,Ziff predicts.

Productivity highest in FoothillsOf the strategy areas, productivity is

highest in the Foothills region whichextends down the spine of the CanadianRockies in British Columbia and Alberta,but Ziff predicts decline rates will accel-erate in several regions.

Central and west-central Alberta, the“breadbasket” of WCSB gas at more thanone-third of total basin supply, are likelyto remain flat to slight growth as CBMincreases offset conventional declines.

Southern Shallow (in southeasternAlberta and southwestern Saskatchewan

along the Montana border) has 34 percentof last year’s gas well completions, downfrom 54 percent in 2003, as shallow rigsare directed to coalbed methane plays.

Over the forecast period, Ziff assumesno increases from Fort Liard and no pro-duction at all from offshore BritishColumbia, which it thinks is a more dis-tant commercial prospect than Alaskagas.

It does not factor in gas from theMackenzie project, which could come onstream in 2011 at 800 million to 1.2 bcfper day, but the Arctic venture figureslarge in Canada’s numbers game.

Arctic gas neededAt the Canadian Institute’s Arctic Gas

Symposium in Calgary in March the needfor the North Slope and Mackenziepipelines was repeatedly hammeredhome.

TransCanada Chief Executive OfficerHal Kvisle said balancing supply anddemand in North America will “need boththe importation of LNG and the develop-ment of the two major northern projects.”

He also took the chance to point anaccusing finger at the slow approvalprocesses for both pipelines, which hesaid have become “extraordinarily longand very difficult and can cause even themost determined and seasoned companyto at some point throw their hands in theair.”

Kvisle warned that despite the need forArctic gas, northern proponents have noreason to be complacent.

“It’s not necessarily a slam dunk thatnorthern gas can go ahead when facedwith the very much larger volume ofLNG that could come on,” he said.

“In our view the demand for naturalgas and electric power will continue togrow,” Kvisle said. “To that end we needto make major investments in infrastruc-ture here in North America.

“If some of this infrastructure does notget built and gas supply remains con-strained then we are going to see gasprices rise to levels that are very unpleas-ant. ...”

Randy Broils, Imperial Oil senior vicepresident, told the symposium that theMackenzie will be an important newsource of supply, although LNG isexpected to dominate new volumes.

“Our focus for the Mackenzie projectis ensuring we have a viable project thatcan compete head to head with LNG inthe long term,” he said. �

T

“It’s not necessarilya slam dunk thatnorthern gas can goahead when facedwith the very muchlarger volume ofLNG that couldcome on.”—TransCanada

Chief ExecutiveOfficer Hal Kvisle

Glimmer of life in aging playIncreasingly portrayed as a declining source of conventional oil and gas, the

Western Canada Sedimentary basin got a rare shot of hope earlier in March. Galleon Energy, a Calgary-based junior established only 30 months ago, report-

ed a light sweet oil discovery in northwestern Alberta that is rated as one of the bestfinds in Western Canada over the past decade.

The Puskwa well, about 40 miles north of Grande Prairie, flow tested at 2,559barrels of oil equivalent per day (90 percent oil and 10 percent natural gas) and isscheduled to come on stream by mid-year at 4,000 boe and possibly growing to8,000 boe in 2007 after full development drilling.

At that level it would provide a significant lift to Galleon, which currentlypumps about 9,200 boe per day, with 2,500 boe awaiting tie in.

Under the leadership of Chief Executive Officer Steve Sugianto, Galleon has seta goal of exploring for high impact, big reserve base projects in the Peace RiverArch region, which is one of the hottest plays in Western Canada.

The 100 percent owned well was drilled to 10,354 feet and encountered 33 feetof oil pay. The quality of the light sweet oil is 38 degree API.

Delineation program plannedThe company has the area’s largest land holding at almost 20,000 acres and is

now gearing up for a drilling program of 10-12 wells this year to delineate the poolsize and 26-30 wells at a cost of up to C$65 million, including facility costs ofC$20 million.

Galleon is the third junior oil company led by Sugianto and follows KeyWestEnergy, which achieved output of 8,800 boe per day before being sold to VikingEnergy Royalty Trust for C$320 million.

But Sugianto has told reporters he has no desire to see Galleon — which is 12percent owned by management — follow the same path.

Instead, he said there is enough running room in the Peace River Arch forGalleon to set its sights on passing the 10,000 boe per day mark, a level at whichmost juniors unload their assets in income trusts.

The flow data from the Puskwa well has been described as significant by ana-lysts, but some caution that the play has a record of sharp production declines.

Whatever the outlook, investors gave Galleon a resounding vote of confidencein the two days after the announcement, pushing Galleon shares from C$21 toalmost C$30 and boosting the company’s market value beyond C$1 billion.

—GARY PARK

Advertise in Petroleum News

Call Susan Crane at 907-522-9469

� J U N E A U

Tax impacts on exploration, production differEcon One looks at likely impacts on different activities from proposed State of Alaska tax/credit rates of 20/20 and 20/25

BY KRISTEN NELSONPetroleum News

mpacts of the governor’s proposedproduction profits tax could be differ-ent on explorers than on producers,economists representing Econ One

Research told legislators March 13. At low oil prices, for example, a 25

percent profits tax and a 20 percent cred-it rate helps companies that are exploringmore than a 20 percent tax rate and a 20percent credit.

Why is this?Tony Finizza, an economist working in

conjunction with Econ One, told legisla-tors that it’s because the explorer has anegative cash flow for so many yearsbefore it has any production, it is margin-ally better off with 25/20 than with 20/20.

Finizza, a Ph.D. in economics andfinance from the University of Chicago,and chief economist for ARCO from 1975to 1998, said that unless the coastal plainof the Arctic National Wildlife Refuge isopened to exploration, large oil discover-ies on the North Slope are unlikely. Butincentives are required at low prices, andeither the 20/20 or the 25/20 proposedPPT would be an improvement over thestatus quo as an incentive to exploration.And under either of the proposed tax andcredit rates the remaining resources areeconomic, except at low prices of lessthan $30 a barrel.

How an explorer looks at prospectsA new field has an exploration and

appraisal period of perhaps four years,development of three years and produc-tion over five to 20 years, depending onthe size of the field, Finizza said.

He used estimates from the U.S.Geological Survey of a mean of 4 billionbarrels for technically recoverable undis-covered oil on the central North Slope vs.10.4 billion barrels in ANWR.

But on the central North Slope theUSGS estimates that 51 percent of that oilwill be found in fields with fewer than 64million barrels, none in fields over 1 bil-lion barrels and only 2 percent in fieldsover 500 million barrels. The USGSmean for undiscovered central NorthSlope fields (excluding ANWR) is 21fields of 50 million barrels (60 percent),11 fields of 100 million barrels (25 per-cent), four fields of 150 million barrels(10 percent) and one 500 million barrelfield (five percent).

At $30 oil prices, the USGS estimates860 million undiscovered barrels on thecentral North Slope would be economic,at $40 oil 1.89 billion barrels, at $50 oil2.66 billion barrels and at $60 oil 3.2 bil-lion barrels.

One in six chance of finding oilBased on recent North Slope experi-

ence there is about a one in six chancethat an exploration well will find oil, soan explorer would calculate the net pres-ent value of outcomes based on that onein six chance. Cash flow from explorationwill always be negative; one-sixth of thetime that will be followed by positivecash flow from production.

The proposed $73 million standarddeduction helps the economics of anexploration program, he said, but netpresent value calculations still come upnegative at $30 oil prices based ondrilling six wells to make a discovery.

Finizza told legislators that by giving

incentives to exploration the state is basi-cally stepping in and saying well, themarket won’t do it, I’ll encourage it. Thestate is helping out, so “you could getexploration that won’t pay and you’regoing to hold some of the bill on that.”

ANWR is a critical point, Finizza said:Without it, smaller sized fields will befound and incentives for exploration willlikely be needed.

The proposed PPT likely would get thestate more exploration, but he said it’simpossible to say how much, because theexpected small central North Slope fieldsizes weigh against the economics. ThePPT helps, he said, and incentives wouldhelp; both tax credit combinations workbetter than the status quo.

Majority in known fieldsBarry Pulliam, senior economist with

Econ One Research, told lawmakers thatthe majority of North Slope production,more than 70 percent through 2030, willcome from existing major fields and theirsatellites: Prudhoe Bay, Kuparuk Riverand Alpine. Of a total estimated at 5.6 bil-lion barrels, only some 28 percent isexpected to come from other fields.

The reason the Legislature hiredEconOne, Pulliam said, was to look at thework done by Pedro van Meurs and theDepartment of Revenue and tell theLegislature whether or not that work wasreasonable. While different people willhave different assumptions, that doesn’tmean either set of assumptions is unrea-sonable and Revenue’s numbers look rea-sonable, he said.

Pulliam said Econ One addedOooguruk to future production numbers,since that project has begun sinceRevenue prepared production figures inthe fall. And he said he disagreed on thepoint of when the North Slope might shutdown without a gas line. Econ Onethinks, he said, that if oil is at $40, thenthe North Slope, particularly PrudhoeBay, would be economic for longer than24 more years. But, he said, he puts moreemphasis on the next 10 years becausechanges out farther than that are so hardto forecast.


By giving incentives to explorationthe state is basically stepping in

and saying well, the market won’tdo it, I’ll encourage it. The state is

helping out, so “you could getexploration that won’t pay andyou’re going to hold some of thebill on that.” —Tony Finizza, aneconomist working in conjunction

with Econ One

IConsultant: $40 likely company base case

As they work on a new oil tax regime for Alaska, the state’s legislators want toknow what the price of oil will be in the future, and they also want to know whatoil price the industry is using in its plans.

Tony Finizza, an economist working with Econ One Research, told legislatorsMarch 13 that he’s heard a lot of talk in Juneau about real high prices, $100 perbarrel and higher, and real low prices, $20 per barrel, but doesn’t believe those aresustainable.

Finizza, who has a Ph.D. in economics and finance from the University ofChicago and was chief economist for ARCO from 1975 to 1998, said factors sug-gesting that prices aren’t likely to stay low include strong oil demand, especially inAsia, and the growing gap between global demand and non-OPEC supply, whichwill lead to increases in Organization of Petroleum Exporting Countries marketpower.

The factors opposing long-term higher oil prices include alternative sources ofliquids at high prices, with tar sands, coal liquids and shale oil economic at, respec-tively, $20-$30 per barrel prices; prices above $30; and prices above $45-$50.

Because oil is primarily used as a transportation fuel, over the long run its posi-tion in that market can be eroded by hybrid vehicles, grid-connected hybrid vehi-

see IMPACT page 8

see BASE page 8


EIA forecast used for some workOver the next 10 years the U.S.

Department of Energy’s EnergyInformation Administration has recentlyforecast prices at an average of $54.70per barrel.

Using Revenue’s worst case scenario— no ANWR and no exploration — andthe EIA price forecast, Econ One estimat-ed $29.255 billion from a 20/20 (20 per-cent tax; 20 percent credit) PPT taxthrough 2030, $17.971 billion more thanthe state would have received under thestatus quo, and an effective tax rate of12.6 percent compared to 4.9 percentunder the status quo.

At a $40 oil price, the state would earn$8.888 billion, $3.434 billion more thanunder the status quo, and have an effec-tive tax rate of 10.2 percent, compared to6.3 percent under the status quo. Thebreakeven point would be an oil price of$30.50.

Pulliam also presented a case wheredeductible costs are 20 percent higher,which moved the breakeven pointbetween the PPT and the status quo to$34.60 per barrel, and resulted in sever-ance tax revenues of $7.419 billion at $40per barrel, an increase of $1.965 billionover the status quo.

The sliding scalePulliam said he talked with Daniel

Johnston (see story this issue) about mak-ing the plan more progressive with a slid-ing scale at higher oil prices.

He showed tables of what kind of achange a sliding scale would make whenadded to the PPT at higher oil prices.

While the effective tax rate at $40 oilis 10 percent with a 20/20 PPT (2007through 2030) compared to 4.9 percentunder the status quo, that effective taxrate goes to 11.9 percent if the price of oilrises to $50 and a 0.30 percent incrementkicks in at a $50 threshold price. (Seestory this issue on committee substituteprepared by House Resources, whichincludes a sliding scale.) �

cles and fuel cell vehicles. Then there is the “consumer tax”:

every $10 increase in the price of oil islike adding a $73 billion tax on con-sumers, and you don’t need many ofthose to tank the economy, he said.

Oil price forecastsPublicly available forecasts are

mostly looking at prices out into thefuture in the $40 per barrel range. Butforecasters have been “humbled in the

past,” he said, “and will continue to behumbled in the future.”

Producers have been burned by fore-casts of high oil prices in the past, hesaid, and will test projects against aprice well below their most likely view.Companies haven’t been willing toshare the prices they use for planningfor competitive reasons, but Finizzasaid there is evidence they are usingaround a $40 West Texas Intermediateprice as their base and $30 WTI as astress price, a price range that tends tobe confirmed by recent asset sales.

—KRISTEN NELSON

continued from page 7

IMPACT


BASE

� A L A S K A

ANGDA study looksat Alaska gas demandSAIC report for DOE expected to be released soon looks at whatindustries could pay for natural gas in Cook Inlet in future


t the March 13 board meeting of theAlaska Natural Gas DevelopmentAuthority Harold Heinze, ANGDACEO, spoke about a study into

Alaska natural gas demand that SAIC hasdone for the U.S. Department of Energy.The report from the study has gonethrough two reviews and will be releasedin a week or two Heinze said.

Heinze said that the SAIC analystshave constructed a series of gas scenariosand price regimes into the future, to esti-mate what the demand for different typesof Alaska gas usage might be and whetherthose demands would be viable at poten-tial gas prices.

“They have for a whole bunch ofindustries back calculated what pricesthey can afford to pay in Cook Inlet andbe competitive in the world market undera certain set of assumptions,” Heinzesaid.

As an example of the results of thework, a chart for 2025 shows projectednatural gas demand levels for a series ofgas usage sectors, set against a range ofprojected gas prices at that time. At 2025gas prices the chart indicated that residen-tial use and power generation would beviable uses of gas and might account forabout 300 million cubic feet per day ofdemand. Gas to liquids, liquefied naturalgas and fertilizer do not appear to be com-petitive on world markets at that time.

Devil’s in the detailsAlthough Heinze commended the

expertise and thoroughness that has goneinto the study he also expressed somenotes of caution regarding some of theassumptions that the analysts made.

“As with all these things the devil’s inthe details,” he said.

He pointed out, for example, that thereport assumes that LNG would beexported at Henry Hub prices.

“Right now that doesn’t mean any-thing,” he said. “… The LNG that’s beingsold, for instance, at the Kenai plant …the price for the LNG that is delivered inJapan is set by oil prices.”

And fertilizer is undervalued, hethinks.

“The price of fertilizer in the world isset by the marginal producer, who usesoil,” he said.

The 2025 chart also shows the possi-bility of gas demand from Alaska petro-chemical and LPG (propane and butane)industries. But Heinze commented thatthese industries do not currently exist inAlaska — who would bid for gas suppliesfor these industries in a pipeline open sea-son, he asked.

However, the analysts took a compre-hensive look at many different future sce-narios, he said.

“The basic analysis that is done thereis very usable in terms of modifying tothe situation at hand,” he said. �

A

CANADAOil sands trim Canada’s oil production

Operational hitches at oil sands mines were responsible for a 2.4 percent dropin Canada’s oil production last year to 2.51 million barrels per day — the firstannual decline since 1999, a federal government agency reported.

But gas volumes were up 1.5 percent to almost 6 trillion cubic feet or 16.41 bil-lion cubic feet per day, due entirely to higher output in Alberta.

Alberta production hit bottom in April at 1.53 million bpd and climbed backby 400,000 bpd to peak in December at 1.92 million bpd.

Despite the overall drop, crude oil exports from Canada rose again to a record1.64 million bpd, 20,000 bpd ahead of 2004.

For December, total Canadian production was 2.79 million bpd, of which 1.9million bpd or 68 percent was exported.

—GARY PARK

� C A N A D I A N B E A U F O R T

Canadian Beaufort drilling hangs in balanceDevon Canada to evaluate first well since 1989, watch business environment, see Mackenzie progress before moving to second well


ne down ... three more to go?The first wildcat in Canada’s

Beaufort Sea has been completedand is now being tested but whether

three more wells will be drilled over thenext three winters hangs on several fac-tors.

Devon Canada Vice President MichelScott confirmed the Paktoa C-60 well, thefirst exploration hole off the MackenzieDelta in 17 years, has reached its targeteddepth of about 7,900 feet and is beingperforated to test targeted formations.That work should wrap up by the end ofMarch.

Undertaken from a steel drilling cais-son (SDC), last used by EnCana in 2003to drill the McCovey prospect north ofPrudhoe Bay, the well was close to onschedule and on budget, he said.

Because the well remains a tight hole,specific details are not being released.

The drilling results can be kept confi-dential for up to two years while Devonanalyzes the data and decides when andwhat information will be made public.

The costs were previously pegged inthe range of C$55 million to C$60 mil-lion.

Devon will analyze resultsFor now, Devon Canada is “not com-

mitting to anything” until it is able to ana-

lyze the results of Paktoa and, amongother things, reaches a comfort level withprogress towards a Mackenzie Valleypipeline, Scott said.

To retain four Beaufort explorationlicenses covering 860,000 acres, acquiredin Devon’s 2001 takeover of AndersonExploration, the company has to meet awork commitment of C$225 million anddrill four wells by 2008-09.

Before moving to any further wells,Scott said the company will keep a closeeye on the business environment and theMackenzie regulatory hearings nowunder way before the National EnergyBoard.

Along with other independentMackenzie Delta explorers — includingAnadarko Canada, BP Canada Energy,Chevron Canada Resources, EnCana andNytis Exploration — Devon Canada isattempting to negotiate agreements withMackenzie project leader Imperial Oil ongas-gathering, processing and transporta-tion issues.

Scott said that if the explorers’ groupis unable to “reach some form of agree-ment” outside the National Energy Boardhearings it is prepared to wait for the fed-eral regulator to deliver a verdict on theMackenzie application by late 2007.

He said board decisions are “typicallyfair ... even if you don’t always get whatyou want.”

The explorers have previously clashedwith the producers’ group over Imperial’sinsistence on obtaining firm capacitycommitments from the independent pro-

ducers before it would disclose terms ofthe access and delivery agreements.

On the overall project, Scott said “wefeel the timing is essentially right,” giventhe North American hunger for new gassupplies.

“It looks like something that ought tohappen,” he said.

However, if gas prices slump, explor-ers will shelve their drilling plans and thechances of developing Canada’s Arcticgas will be “back in a tight scenario,”Scott said. �


To retain four Beaufortexploration licenses covering

860,000 acres, acquired in Devon’s2001 takeover of Anderson

Exploration, the company has tomeet a work commitment of

C$225 million and drill four wellsby 2008-09.

O

The first wildcat in Canada’s Beaufort Sea off the Mackenzie Delta was drilled with thesteel drilling caisson (SDC), last used by EnCana in 2003 to drill the McCovey prospectnorth of Prudhoe Bay. Photo above taken offshore Alaska in the Beaufort Sea duringMcCovey project

� J U N E A U

Legislature goes for sliding scale oil taxNorth Slope, Cook Inlet producers, independents, explorers all unhappy with committee substitute for governor’s PPT tax bill


he Alaska Legislature’s HouseResources Committee used the gov-ernor’s proposed production profitstax bill as a starting point for raising

taxes. Representatives of Alaska’s oil and

gas industry made it clear to the commit-tee March 15 that they considered thegovernor’s proposal the maximum indus-try would support.

Legislators said the issue was ensuringthat the state got a fair share of the profitsfrom its resources at high prices.

Industry said the issue was keepingprojects in the state competitive forinvestment and growing the pie for bothindustry and the state.

North Slope producers had told legis-lators in late February that their supportfor House Bill 488 was reluctant, andonly given because it was viewed as astep toward getting a gas pipeline projectmoving.

Cook Inlet producer Unocal said atthat time it was concerned about theeffect of higher taxes on a declining oilindustry in the basin and explorers saw abenefit from a $73 million standarddeduction.

None of the companies testifyingMarch 15 were in favor of the committeesubstitute. It wasn’t available yet, butHouse Resources provided a summary ofsubstantive changes March 14 (see side-bar to this story).

ConocoPhillips: negative impact on investment

Brian Wenzel, vice president offinance and administration forConocoPhillips Alaska, told legislatorsthat based on the summary handed outMarch 14, the committee substitute willhave a negative impact on the attractive-ness of Alaska for investment.

ConocoPhillips “absolutely” opposesthe committee substitute and any increasebeyond the $1 billion per year in addi-tional taxes proposed by the governor, hesaid.

Wenzel said the substitute wouldincrease taxes $1.8 billion a year attoday’s prices, an $18 billion increaseover the next 10 years.

You hired consultants — “we alsohired consultants” — but at the end of theday, he said, none of those consultantsmust make or live with the decision

before the Legislature and none of themwill ever make an investment decision forConocoPhillips.

The assertion of the Legislature’s con-sultants that additional taxes would haveno impact on investment is “absolutelywrong,” he said. Taking away the upsidepotential on the North Slope will have a

negative effect on decision making, notjust from the increased tax burden butfrom reduced confidence in the future fis-cal environment.

Wenzel said it is antipathy toward theindustry that concerns ConocoPhillips themost and called the committee substitutean exercise to see how much the state cantake from the private sector.

Nearly all provisions of the originalbill have been changed, he said, destroy-ing the balance.

The reduced transition provision is apenalty for those who invested in Alaskatoo early for being too optimistic, he said.

Wenzel also called the effective dateof April 1 impractical. Procedures andregulations can’t be adopted in time, hesaid, forcing companies to guess at taxesin an attempt to avoid the punitive 11 per-cent interest rate and the 5 percent penal-ty on top of that.

He said the changes are completelyinconsistent with the goals of fair and rea-sonable and urged the committee not tomove the bill until it can be revised.

Pioneer: Shooting too highPat Foley, manager of lands and exter-

nal affairs for Pioneer Natural ResourcesAlaska said a committee member hadcharacterized the choices in an oil taxchange as shooting a little low or a littlehigh.

“You chose early on to shoot low andleave a vibrant industry,” Foley said,“now you’re shooting high.”

He told the committee that the pro-gressive tax rate and the way the tax isstructured fails to take into account thatinvestors’ costs increase at high oil prices.The provision to extend explorationincentives created under Senate Bill 185for 10 years, he said, is only modestlyhelpful since those incentives are onlyavailable for certain activities.

The $10 million limit on credits thestate would purchase at face value mightbe beneficial to an explorer, but not to adeveloper, he said. He suggested either adiscount floor for sales of credits oradding broadening the pool into whichcredits could be sold by allowing them tobe used for state income tax.

Resources co-Chair Ralph Samuels,R-Anchorage, said the thinking on thatwas that the state was already taking aproduction task risk at low prices and did-n’t want to extend that risk to the incometax.

Rep. Paul Seaton, R-Homer, asked if a90 percent floor would be helpful andFoley said it would be.

Foley also asked that if the bill musthave a progressive tax rate triggered bythe oil price, that whatever price used beinflation-adjusted and that the benchmarknot be West Texas Intermediate butAlaska North Slope oil delivered on theWest Coast.

Anadarko: 20/20 a balanceMark Hanley, Anadarko Petroleum’s

Alaska public affairs manager, saidAnadarko thought the 20/20 proposal inthe governor’s bill struck a balance: thetax was a little higher but the companiesgot some exploration credits.

“On balance I think this goes a little bitthe opposite direction,” he said, and saidAnadarko thinks the committee substituteis a little worse for exploration.

Hanley said inflation was an issue with


T

see TAX page 12

Summary of committee substitute to HB 488Blame the April Fools’ Day effective date in the committee substitute for House

Bill 488 on Dan Dickinson. Ralph Samuels, R-Anchorage, co-chair of House Resources, told the committee

March 14 that when he suggested making the production profits tax effective, likeany other legislation, two weeks after the governor signed it, he saw the panic inDickinson’s eyes. Dickinson, former director of the Tax Division, said please, onbehalf of bureaucrats, make the tax effective on a quarter.

HB 488 had an effective date of July 1. The April 1 effective date will give thestate an estimated $200 million additional from the severance tax in the current fis-cal year, House Resources said in a summary of substantive changes to HB 488dated March 14.

Sliding scaleThe committee’s most significant change is a sliding scale which cuts in when

West Texas Intermediate oil prices reach $50 per barrel. The 20 percent tax rate then begins to increase at 0.3 percent for each $1

increase in the WTI oil price, capping at 50 percent at about $150 per barrel. The committee also reduced the transitional allowance in the governor’s bill,

which allowed five years of past investments to be deducted as costs. The com-mittee said it believed recovery of those costs has been “enhanced by extremelyhigh oil prices,” and replaced the 100 percent cost recovery of the previous fiveyears with a 75 percent allowance for 2005 expenditures, a 50 percent allowancefor 2004 expenditures and a 25 percent allowance for 2003 expenditures — all ofwhich can be deducted as costs.

The bill proposed a payback period of six years; that has been increased toseven years. The committee substitute contains the same $40 per barrel pricebefore recovery is allowed. An inflation indexing mechanism will be included instatute, not left up to regulators.

The committee said this change reduces the amount of deduction allowed from$5 billion to $2 billion, and the amount of credit from approximately $1 billion to$300 million.

Exploration tax credits extendedThe Senate Bill 185 exploration tax credit of 40 percent will be extended 10

years; the governor’s proposed credit rate of 20 percent remains in the bill. As theydo currently, the committee said, the company will choose the credit more benefi-cial to them.

The committee substitute says abandonment costs will not be eligible for taxcredits.

The committee substitute eliminates the $73 million allowance, which resulted

see BILL page 11

the committee substitute because, whilethe original PPT was on profit, it is hisunderstanding that the incremental taxwill be on the gross.

Hanley was also concerned about theprogressive tax effect on gas. “For thoseof us looking at gas, you’ve nowincreased the price of gas based on oilprice changes.” Not only are the two notrelated, he said, but the “risk of that canhave a real dampening effect on gasexploration.”

BP: getting barrels down the pipelineAngus Walker, BP Exploration

(Alaska)’s commercial vice president, toldthe committee BP is not in favor of a pro-gressive tax and cannot support the com-mittee substitute. The company makes nomoney in Alaska at low prices, he said,moderate profits at moderate prices andneeds profits from high prices to stay inbusiness.

Ramras told Walker he was takingoffense at industry’s assertion that theopportunity to profit at high prices waswhat kept companies in Alaska. The realquestion for legislators to be asking, hesaid, is “at what point does industry wantto share the windfall?”

Walker disagreed. What legislators need to be asking

industry and consultants, he said, is what itwould take to double investment onAlaska’s North Slope, because that is whatit will take to extend oil production out to2050 and keep the business healthy to sup-port a gas industry.

He cited a natural decline rate of 15 per-cent a year, an actual decline rate of 6 per-cent a year supported by $1 billion to $1.5billion a year in investment and a 3 percentdecline rate requiring $2 billion to $3 bil-lion a year in investment to extend produc-tion to 2050.

“The point we’re trying to make is bar-rels down the pipeline is what really mat-ters to Alaskans,” Walker said.

The North Slope is on a 6 percentdecline rate with the existing tax system.The new tax system “is a huge additionaltax burden on major producers on theNorth Slope,” Walker said, and BP is con-cerned that it may move production to asteeper decline than 6 percent. The goalshould be to find a solution that gets us to3 percent, he said, and that would requirelower taxes, not higher taxes.

Chevron: all levers pushed in one direction

John Zager, general manager ofChevron in Alaska, told the committee thathe had noted in his February testimonythat Cook Inlet was different and should beconsidered for special treatment, askedthat the committee consider all the leversavailable to it and not to pull them all at thesame time and to keep it simple.

“In general we find that none of thiscounsel was retained” in the summary ofthe committee substitute, he said.

The progressive tax proposed in thecommittee substitute is “very complex,”he said, and would take a large effort totrack. He also questioned profits for gasbeing tied to the oil market.

On the windfall issue Zager said takingaway the windfalls lowers the expectedvalue to investors — it’s as if you told thefishing industry that government wouldtake 50 percent on the best 50 fishing daysof the year. He called it “a move againstindustry and a move against additionalinvestment in Alaska.”

His biggest disappointment, Zager said,is that Cook Inlet is not recognized as aseparate area and he said the proposal

would “lower investment opportunities inCook Inlet” and said Chevron’s plannedinvestment would suffer due to the bill.

The committee pulled all the levers inthe state’s direction, he said, and zero inindustry’s direction, and changed the billfrom one Chevron could “reluctantly sup-port to one that’s lopsided in favor of thestate” and that Chevron cannot support.

ExxonMobil: Changes exacerbate concerns

Richard Owen, production manager andvice president for ExxonMobil AlaskaProduction, told the committee thatExxonMobil had concerns about HB 488,and the changes described “exacerbate”concerns he expressed to the committee inFebruary.

HB 488 as proposed was a “dramatic taxincrease,” he said, and there was concern“some of challenged resources wouldn’t bedeveloped.” Now the committee is consid-ering “higher taxes.” Companies will, hesaid, accept long-term risk when there isupside potential; but if the state caps or lim-its upside benefits that reduces the attrac-tiveness of investment opportunities and“will lead to reduced investments” and anegative impact on the state’s economy.

Ramras said the committee’s notion isthat the state is participating in rewards butis at risk at low prices.

Owens said the increase to 20 percent inthe tax level in the original bill “was bal-ance for low-side protection” andExxonMobil accepted that higher tax rate.The committee substitute, he said, goesbeyond that. �


The assertion of the Legislature’sconsultants that additional taxes

would have no impact on investmentis “absolutely wrong.” —BrianWenzel, ConocoPhillips Alaska


TAX

in a $14.6 million credit and substituted“an annual direct tax credit, dollar fordollar, for the first $10 million worth ofexpenditures.” This credit is annual,non-transferable, non-salable, cannotbe carried forward and can only beapplied to the current year’s severancetax.

If a company has income but spendsless than $10 million, they can onlyclaim credit up to the amount spent.

The state will buy back up to $10million per year per company of creditsat 100 percent of face value to help

explorers and new entrants, but compa-nies must show that an equivalentamount to the credit is being reinvestedfor exploration or lease purchase inAlaska.

The committee substitute also putsin place a 5 percent penalty for under-payment of the monthly severance taxbill for any amount below the 90 per-cent threshold. Interest will be chargedon any payment shortfall.

The committee substitute was notavailable as Petroleum News went topress, but both House and SenateResources committees were scheduledto take it up March 16.

—KRISTEN NELSON


BILL

ALASKA‘Beyond petroleum’ talks scheduled

Ken Deffeyes will be in Alaska the week of March20 giving talks on when world oil production willpeak.

Deffeyes is the author of two books on the subject:“Beyond Oil: The View from Hubbert’s Peak,” pub-lished in 2005, and “Hubbert’s Peak: The ImpendingWorld Oil Shortage,” published in 2001.

In addition to talking about the coming peak inworld oil production, Deffeyes will also give ananalysis of current energy requirements and solutionsto dependence on crude oil.

Four free lectures are scheduled: • March 21, Fairbanks, University of Alaska

Fairbanks, Salisbury Theatre, 7 p.m. • March 22, Anchorage, East High auditorium, 7

p.m.• March 23, Matanuska-Susitna, the Agate Inn on the Palmer-Wasilla Highway,

7 p.m.• March 25, Juneau, University of Alaska Southeast, Egan Library, 7 p.m.

� C A N A D A

Stop that (oil sands) thief!Think tanks call for 5-year freeze to develop national policy; see U.S. military-industrial complex as drain on Canadian security


il sands royalties will pour aboutC$1.2 billion into Alberta govern-ment coffers in fiscal 2005-06, up65 percent from the previous year,

the Canadian Association of PetroleumProducers forecast.

And that figure is scheduled to make aquantum leap as more projects cover theirconstruction costs and move from payingroyalties of 1 percent of gross revenues to25 percent of net revenues.

Meanwhile, a trio of think tanks hascalled for a moratorium on all new oilsands development for five years until allCanadians can debate how the resourceshould be exploited.

They also want the moratoriumextended to the Mackenzie Gas Project,arguing the gas will fuel oil sands opera-tions.

The policy groups, in a report entitled“Fuelling Fortress America: A Report onthe Athabasca Tar Sands and U.S.Demands for Canada’s Energy,” arguedthat Canada’s energy policy providescomplicit support for U.S. foreign policyin general and the U.S. military-industrialcomplex in particular.

The royalty prediction was issued onMarch 8, one day after the report by theParkland Institute (which operates underthe umbrella of the University ofAlberta), Canadian Center for PolicyA l t e r n a t i v e sand PolarisInstitute — allseen as organi-zations that tiltto the left.

Those twoevents neatlycaptured anational dilem-ma.

The oil sandsare Canada’sace in the holein terms of oilse l f -secur i ty.Without themCanada wouldrapidly becomea net importer.

Report callsfor public inquiry

But the think tanks have moved

beyond the concerns of environmentalistswho view the oilsands as the destruc-tion of northernAlberta’s landscapeand wildlife. Theywant an all-encom-passing publicinquiry that wouldfocus heavily onCanada’s energysecurity.

Hugh McCullum,the report’s author,while doubting thata moratorium wouldbe imposed, said thefindings weredesigned as a wake-up call and hopeful-ly the beginning of anational debate.

He said the residents of Canada havenever been involved in decision-makingon the oil sands.

The report says it may be possible to

develop the oil sands in a way that couldenhance Canada’s long-term energyneeds, but “shockingly, there is no coher-ent national or provincial energy policy toaddress this need.”

In the absence of a provincial ornational plan, the “rapid pace of extrac-tion has also led to inequities between theprovinces, with Alberta in an embarrass-ment of riches, part of which is beingthrown at local infrastructure spending,escalating the boom,” the report said.

Instead of pacing development tomaximize job creation and the returns toAlberta there is “instead a bonanza, usingforeign workers and union-busters in theshort-term, while offering royalty holi-days.”

Although the suggested policy actions“may sound like bold measures to some,the fact remains that much of what isneeded now was commonplace in thiscountry a quarter-century ago,” the reportsaid.

“The steady deregulation of the oilpatch in the years since then has nowbrought us to the brink. Either Ottawatakes action now, in collaboration withAlberta and other oil and gas producingregions, or Canada’s energy security willbe put seriously at risk.”

If, as forecast by some, oil sands out-put grows by six-fold over the next 25years to 6 million barrels per day, it is notpossible to avoid “screwing up the envi-ronment” by consuming vast amounts ofnatural gas in the extraction and process-ing phases, using valuable water andpumping more greenhouse gases into theatmosphere, McCullum suggested.

Canadian energy security a concernThe report extended its concerns to

Canada’s energy security, noting thatcostly oil sands and unconventional gassources (including Arctic gas) will beneeded to offset shrinking reserves ofconventional oil and gas.

In 2004, conventional crude (includingoffshore Newfoundland) yielded 1.4 mil-lion bpd (with heavier oil contributing 1.1million bpd). Of that total, 1.6 millionbpd were exported, while close to 1 mil-lion bpd were imported to the AtlanticCanada region, Quebec and Ontario.


O

see OIL SANDS page 13

Alberta’s cash cow keeps deliveringA thriving oil and gas sector will pump C$15 billion (excluding income taxes)

into Alberta government coffers in fiscal 2005-06, lifting the 5-year tally to C$46billion, the Canadian Association of Petroleum producers has calculated.

In examining the industry’s impact on Alberta, the association provides the fol-lowing breakdown:

• Annual spending to explore for and develop Alberta’s resources will includemore than C$20 billion this year on conventional oil and gas exploration, with oilsands investment topping C$10 billion in 2006 and about C$45 billion on newprojects by 2010.

• 275,000 direct and indirect jobs for a “growing and highly-skilled work force.”• A strong and growing corporate and personal tax base.While Alberta will be the chief beneficiary, the study emphasizes that oil sands

economic and employment benefits are distributed across Canada. Oil and gas revenues flowing to the government will account for more than 40

percent of revenues in 2005-06, double Alberta’s original budget forecast, and eas-ily surpassing the 2000-01 record of C$10.7 billion.

Revenues of C$9.8 billion in 2004-05 were one-third of the province’s rev-enues.

Each annual average price increase of US$1 per barrel for oil or C$0.10 pergigajoule for natural gas translates into an additional C$99 million paid to the gov-ernment.

The association said that although oil and gas royalties have historically beenabout equal, gas will account for 75 percent in 2005-06.

—GARY PARK

The researchers estimate that since theNorth American Free Trade Agreement wassigned in 1994, oil shipments to the U.S.have risen from 44 percent to 63 percent ofCanadian output, while gas exports haveclimbed from 41 percent to 56 percent.

“Canada has become the leading energysatellite of the U.S. at a time when Americahas reasserted itself globally with imperialambitions,” they said.

The study said the potential shortage ofnatural gas is an even greater concern thanthe outlook for oil, quoting a federal gov-ernment report that calculated Canada’sreserves of 56.5 trillion cubic feet representonly 8.7 years of supply (compared with 10years for conventional oil) at current rates ofconsumption, urging the government torestore its former policy of maintaining a25-year supply to meet domestic needs

before allowing any exports.

Klein rejects claimsAlberta Premier Ralph Klein, never a

friend of the Parkland Institute, rejectedclaims that Canada is running out of oil.

If ever Canada’s supply were threatened“we will do whatever is necessary to ensurethat Canada receives its supplies first,” hesaid, adding that the oil sands have 300years of supply listed as proven reserves.

Alberta Energy Minister Greg Melchin

said Albertans and Canadians have no causeto worry the U.S. is draining Canadian sup-plies. Neither did he agree that a newnational policy is needed when Alberta hasthe “ownership and stewardship and consti-tutional authority to develop its resources.

“Our policies are built on a lot of trade,the United States being our most valuablecustomer,” he said.

But he did endorse keeping a close eyeon long-term needs for Alberta and Canada.“Those are first and paramount,” Melchinsaid.

Greg Stringham, a vice president at theCanadian Association of Petroleum produc-ers, rejected arguments that energy exportsare tantamount to backing U.S. militaryintervention overseas.

He said that line of reasoning could beextended to cover almost any exports to theU.S.

David MacInnis, president of theCanadian Energy Pipeline Association, saidCanada confines oil and gas exports to sup-plies that are not used domestically.

He said the Parkland Institute’s options“will only result in higher prices forCanadian consumers as they will result in acurtailment of exploration, developmentand infrastructure investment.” �


Instead of pacing development tomaximize job creation and the

returns to Alberta there is“instead a bonanza, using foreignworkers and union-busters in theshort-term, while offering royalty

holidays.” —report, “FuellingFortress America”


OIL SANDS

NORTH AMERICANWT minister says labor shortage critical

Northwest Territories Industry MinisterBrendan Bell says “labor — or the lack ofit — is a critical issue” for proponents ofthe two northern gas pipeline projects.

But, like most political leaders, he seesno reason why the two undertakings would

need to overlap.Bell told a

Washington, D.C.,conference March 9that the Mackenzie pipeline, scheduled to start deliveries in2011, should be finished “long before Alaska proceeds,”although the gap between the two is no guarantee that short-ages of skilled labor will not pose a problem.

However, he said there is a concern about the productionof pipe, given the pressures on the manufacturing sector.

“If there are delays for one, there will be delays for theother,” he said.

Bell also gave assurances to his U.S. audience that at leastsome of the 6 trillion cubic feet of Mackenzie Delta known gas reserves will reachthe Lower 48 and will not all be diverted to the Alberta oil sands.

He said Canada’s commitment to be a “key part of the North American energyrelationship” requires that Mackenzie gas should find its way into U.S. homes.

—GARY PARK

NorthwestTerritories IndustryMinister BrendanBell

CANADABudget, hiring rise at Northern Lights

The pace is quickening for the Northern Lights oil sands project, 60 percent ownedby start-up Synenco Energy and 40 percent by a subsidiary of China’s Sinopec.

Synenco’s spending on the undertaking is budgeted at C$197 million for 2006,compared with C$108 million in 2005 and C$9.37 million in 2004.

The company has permission to drill 420 holes this year, although the final countwill depend on several factors, including weather.

Synenco expects to hire or retain about 150 staff, most of whom will be assignedto Northern Lights.

Independent consultant Norwest and Synenco’s own independent resource evalu-ator have put a “best” estimate on discovered resources of 1.5 billion barrels of in-place bitumen, of which Synenco considers 1.2 billion barrels to be recoverable.

The total capital cost of Northern Lights is forecast at C$5.3 billion to produce100,000 barrels per day of light, sweet synthetic crude, with the first output scheduledfor 2010.

—GARY PARK

Saskatchewan’s budget roller-coasterThe recent easing of commodity prices could take an C$80 million bite out of

Saskatchewan government oil and natural gas revenues for the 2005-06 fiscal year.Based on a third-quarter update, the province now expects to collect C$1.39 bil-

lion, down from the C$1.47 billion mid-year forecast, although the latest tally is stillahead of the original budget projection.

Gas royalties are now on track for C$270.4 million, compared with the mid-yearforecast of C$314.8 million and the initial budget which pegged revenues at C$191.4million.

Oil royalties are not predicted to hit C$1.116 billion, off C$46 million from themid-year report, but well ahead of the budget guess of C$656.3 million.

These fluctuations merely reflect the difficulty of trying to estimate resource rev-enues, said a spokesman for the Department of Finance.

—GARY PARK

Bell told a Washington, D.C.,conference March 9 that the

Mackenzie pipeline, scheduledto start deliveries in 2011,should be finished “longbefore Alaska proceeds.”


� A L A S K A

Some pipeline regulation changes elude harvestRegulatory Commission of Alaska decides actions on moving forward but finds some ‘low hanging fruit’ to be just out of reach


t its March 8 public meeting, theRegulatory Commission of Alaskadiscussed two dockets, R-05-11and R-05-12, both of which involve

potential changes to the regulation of oiland gas pipelines.

In docket R-05-12 RCA has publisheda draft regulation that would enable oper-ators to file for construction of a non-util-ity pipeline separately from filing foroperation of the pipeline. Under currentregulations operators must file for a cer-tificate for both construction and opera-tion prior to starting construction. Filingfor operation involves publishing pipelinetariffs — companies have complainedthat this tariff filing involves significanttime and expense before ultimate pipelinecosts and revenues become known.

The March 8 meeting provided thefirst opportunity for revisions to RCA’sinitial draft of the proposed regulation.And, in an effort to move forward,Commissioner Dave Harbour tried to findsome easy ways to simplify the draft lan-

guage.“I would suggest that today that we try

to identify the low-hanging fruit. That is,identify some rather easy changes tomake and redraft … before our next pub-lic meeting,” Harbour said.

Unfortunately it turned out that juicytidbits like changing the words “peopleand entities” to “people” proved a littleout of reach and had to be deferred forfurther research. It seems that achievinglegal and regulatory clarity isn’t necessar-ily straightforward.

“Gee. This isn’t as easy as I thought itwould be,” Harbour reflected after the

first plum swungaway.

However, thecommissioners, withthe advice of RCAstaff, did agree onsome changes, suchas simplifying thelanguage specifyingthe data needed inan application. RCAwill now review thedraft further andresearch issues asso-ciated with the pro-posed regulations.Further discussionof the proposed reg-ulation will bescheduled in thecommission’s nextpublic meeting.

Multiple pipeline classesIn the other docket, R-05-11, RCA is

proposing the introduction of two or moreclasses of pipeline for regulatory purpos-

es. The intent of this proposal is to reducethe regulatory burden for small, producer-owned pipelines, thus encouraging explo-ration and development of Alaskaresources. But although RCA has nowreceived several comments on its propos-al, most of these comments presentedgeneral opinions rather than providingspecific suggestions or ideas for a regula-tion, Commissioner Tony Price said.

“It was so general that it’s difficult forus to take that information and proceedwith it,” he said.

Commenters did make a specificrequest for a class of pipeline that couldbe exempt from regulation. But adminis-trative law Judge Janis Wilson told thecommissioners that all pipelines thatcome under Alaska statute 42.06, thestatute that relates to non-utilitypipelines, require regulation. So there isno way of exempting a pipeline from reg-ulation by placing it into a distinct class,Wilson said.

“There must be some level of regula-tion for any industry that meets the defi-

Commenters did make a specificrequest for a class of pipeline thatcould be exempt from regulation.

But administrative law Judge JanisWilson told the commissioners

that all pipelines that come underAlaska statute 42.06, the statute

that relates to non-utilitypipelines, require regulation.

A

Dave Harbour, RCAcommissioner

Kate Giard, RCAcommissioner

see RCA page 16

� N O R T H A M E R I C A

Spearheading new outlets: Oil moving southBY GARY PARK

For Petroleum News

anadian crude is flowing to its most southerly U.S.market, with the start-up of Enbridge’s Spearheadpipeline from Chicago to Cushing, Okla., and willsoon find its way to Houston.

Now there is also talk of a newgrade known as Western CanadianSelect — a blend of 19 Alberta heavycrudes — being listed on the NewYork Mercantile Exchange.

The Spearhead line, originallybuilt to deliver crude from Texas tothe U.S. Midwest, has struggled tooperate as the once-prolific fields ofTexas went into decline.

Enbridge bought Spearhead fromBP in 2003 and invested US$190 million to reverse the sys-tem, which has initial capacity of 80,000 barrels per day (10year contracts have been secured for 60,000 bpd) but isexpected to rise to 125,000 bpd, with plans under way toboost capacity to 190,000 bpd.

Although the initial deliveries involve only heavy crude,Enbridge is open to carrying synthetic crude.

Transit time of 47 daysThe oil being delivered to Cushing enters the Enbridge

mainline system at Edmonton and travels more than 1,500miles to Chicago before entering Spearhead and movinganother 625 miles — a transit time of about 47 days.

Enbridge Chief Executive Officer Pat Daniel said thatopening up Cushing gives producers an option and ensuresthat saturating the U.S. Midwest does not negatively impactprices for Canadian crude.

He said crude from Alberta is “slowly marching south.This is a big step … a first initiative to get Canadian crudesouth of the bottleneck market in Chicago.”

He said the ribbon-cutting March 2 “marks the begin-ning of a new era of North American crude supply,” notingthat Canadian exports could double in the next decade ifattractive markets could be established.

Daniel said refiners in the southern U.S. are eager toreceive more Canadian crude because it is a secure sourceand it is cheaper than heavy oils from Venezuela and

Mexico.

Volumes can affect pricesHe said that although the volumes reaching Cushing are

small compared with total Canadian exports they can affectprices.

“Often it only takes a small volume or a marginal barrelin order to be able to dramatically improve the pricing,” hesaid.

Current heavy oil is trading at US$30 per barrel less thanthe US$60 being paid for light crude.

Daniel is confident Spearhead will narrow the differen-tial, but he is not sure by how much.

Steve Laut, president of Canadian Natural Resources,said new markets in Oklahoma and Texas would “ultimate-ly close the gap between the prices we see in Chicago ver-sus areas in the Gulf Coast.”

Enbridge noted that heavy oil recently fetched US$10more per barrel in Cushing than Chicago, more than offset-ting the transportation cost of US$1.50 per barrel betweenChicago and Cushing.

Steven Kelly, a Purvin & Gertz analyst, said in a recentreport that Spearhead will give refiners in the U.S.Midcontinent “a measure of flexibility they haven’t had

Crude from Alberta is “slowly marching south.This is a big step … a first initiative to get

Canadian crude south of the bottleneck marketin Chicago.” —Enbridge CEO Pat DanielC

Pat Daniel,Enbridge

JUD

Y P

ATR

ICK

see OIL page 18

� J U N E A U

Consultant: too-high tax rate easier fixDaniel Johnston tells legislators 20/20 PPT would bring state up to standards of last century; recommends sliding scale tax


laska has every right to change itstax system, consultant DanielJohnston told the Legislature’sHouse and Senate Resources com-

mittees March 6. The governor’s pro-posed petroleum profits tax with a 20 per-cent tax rate and a 20 percent credit ratebrings the state up to the end of the lastcentury, he said.

To capture the high end of oil pricesJohnston recommended a sliding scale inaddition to the 20 percent rate.

At the lower end he recommended thattaxes not be allowed to go lower thanwhat the state would collect with its pres-ent severance tax system and the eco-nomic limit factor, or ELF.

Johnston said Alaska’s present sever-ance tax system is outmoded and called itmore regressive than a typical regressivesystem. In regressive tax systems govern-ment takes a greater percentage at low oilprices and a smaller percentage at high oilprices. The present ELF-driven tax, hesaid, is tied to production per well andproduction per field and creates a situa-tion where the interests of the companiesare not well aligned with those of thestate.

Johnston said he thought that becauseof the differences in Alaska’s oilprovinces — the North Slope with itshuge legacy fields and Cook Inlet with itsmature fields — it might be impossible todesign one severance tax system to fit allcases in the state.

Companies want Rolls RoyceHe said contract stability is a concern

to companies everywhere in the worldand companies in Alaska are demandingthe Rolls Royce of stability.

The state’s areawide leasing programis about as painless as it gets for oil com-panies, Johnston said, noting that someareas where Alaska looks good in com-parison to its competition are difficult toquantify.

As for comparisons with other coun-tries, Johnston said the much quoted 2004Wood Mackenzie report comparing inter-national competitiveness excludes gov-ernment participation.

About half of the countries in theworld reserve the right to “back in” andtake an interest in a development, he said.The companies take the exploration risk,and if there is a commercial find the gov-ernment has the right to take an interest inthe project, typically 30 percent.Government will then be involved inmanaging the project. Johnston comparedit to having your mother-in-law livingwith you and said it causes the companiesconsiderable financial pain.

Diverse circumstancesJohnston said he didn’t know if it

would be possible to create a system inAlaska that does all things for all peoplebecause of the diverse circumstancesbetween the North Slope and Cook Inlet.

The proposed $73 million standarddeduction is an attempt to take some painaway from explorers and Cook Inlet, buthe said it makes him squirm and he wasglad he didn’t have to explain that featureto constituents.

Johnston said he thought the adminis-tration’s consultant, petroleum economistPedro van Meurs, did “damn well with

what he had to work with” — the require-ment that one system had to fit all of thestate’s oil provinces. There are problemswith jurisdictions that treat areas differ-ently, he said.

At $40 oil Johnston said he didn’tthink Cook Inlet deserves any more painthan they’re already experiencing, andsaid he would like to see the state haveflexibility on an areawide basis. He saidthere is some economic logic behind thelook-back provision which allows com-panies to deduct for capital investmentsmade over the past five years. Companiesmade investments under the present sys-tem, he said, now the state is making achange and the look back will take someof the pain out of the change.

He said he didn’t think the look backwould be an easy sell politically.

The credit plan is a good system,Johnston said, noting that it exists in anumber of areas. He agreed with vanMeurs that the closest analogue to what’s

proposed in Alaska is in Norway. But hesaid the system was only instituted inNorway a couple of years ago and it’s tooearly to tell how it will work.

Line in the sand“You just have to have a progressive

system. ... Everybody is going in thatdirection and for good reason,” he said.

Johnston said a progressive system isstable and makes future citizens morecomfortable.

He said it doesn’t matter what legisla-

tors think the price of oil will be, “weshould try to design a system that willaccommodate a wide range of prices.”

At the low range of prices he said thestate should “draw a line in the sand” andnever allow taxes to go lower than thereare under the present ELF system.

You might, he said, calculate ELF andPPT and “take the higher of the two.”

There are jurisdictions that do that, hesaid in response to a question from Rep.Norm Rokeberg, R-Anchorage. Someeven calculate the tax three ways and takethe highest amount.

Johnston recommended adding a slid-ing scale to the proposed tax, and said inresponse to a question from HouseResources co-Chair Jay Ramras, R-Fairbanks, that the simplest sliding scale,based on oil price, is probably the best.

Both the tax and credit rate could beon a sliding scale, he said.


Johnston said he thought thatbecause of the differences in

Alaska’s oil provinces — the NorthSlope with its huge legacy fieldsand Cook Inlet with its mature

fields — it might be impossible todesign one severance tax system

to fit all cases in the state.

A

see TAX page 16

� N O R T H S L O P E

Borough mayor questions oil leak detectionItta says clean-up effort first rate as crews pick up 60,000 gal. of an estimated 201,000 gal.; crews also working Kuparuk spill

BY WESLEY LOYAnchorage Daily News

he ongoing effort to clean up theNorth Slope’s largest oil spill ever is“first-rate,” but pipeline leak-detec-tion equipment to prevent such

spills is lacking, the region’s mayor saidMarch 13.

A major pipeline carrying crude oilaway from a processing plant known asGathering Center 2sprang a leak, send-ing an estimated201,000 gallons, or4,790 barrels, ofcrude oozing overnearly 2 acres oftundra. That’senough oil to fill 25tractor-trailer tanktrucks.

Officials with thestate Department ofE n v i r o n m e n t a lConservation saidclean-up workershave recoveredabout 60,000 gallonsof the spilled oilusing vacuum trucksand other methodswhile working insubzero temperatures.

The spill is near the heart of pipeline-laced Prudhoe Bay, the nation’s largest oilfield. BP Exploration (Alaska) Inc. runsthe field on behalf of itself and otherowners, including ExxonMobil and

ConocoPhillips.“BP’s response to this spill has been

first-rate,” North Slope Mayor EdwardItta said March 13. “I’m very pleasedwith the speed of their response, theamount of resources they have mobilized,and the degree of communication theyhave maintained.”

Mayor calls for better technologyItta added: “The industry uses state-of-

the-art equipment to find the oil and get itout of the ground, and I’d like to see themuse the best available technology to pre-vent major spills like the one at GC-2.That’s not happening right now.”

Itta sent a letter to DEC CommissionerKurt Fredriksson, the state’s top pollutioncontrol official, endorsing a joint BP-stateinvestigation into the leak-detection sys-tem on the 34-inch pipeline. The boroughalso wants “an audit of other pipelineswith similar leak-detection systems.”

The North Slope Borough is the localgovernment for the Minnesota-sized terri-tory across the top of Alaska, includingthe slope’s many oil fields.

Over the past year, the borough twiceurged DEC to require better leak-detec-tion equipment than that used on thefailed Prudhoe Bay pipeline, Itta’s letteradds. The borough said currently avail-able leak detectors are capable of per-forming more than twice as well as thosethe state now requires.

Fredriksson could not be reached forcomment. DEC spokeswoman LyndaGiguere said the agency had not yet seenItta’s letter.

Line remains shut downCorrosion is suspected of causing a

quarter-inch hole in steel pipeline.Now patched and no longer leaking,

the line remains shut down and NorthSlope oil production is down by 95,000barrels a day, or 12 percent of total Slope

production. A BP spokesman has said itcould be weeks before the pipeline isfixed or engineers figure out a way toreroute oil to bring production back tonormal.

BP and DEC officials who are investi-


What’s changeable?Johnston said if too high a rate is set,

the risk lies with the oil companies. “If it’s too high and you agree it’s too

high, it’s easy to change,” he said. “If it’stoo low, you’re going to pay hell trying tochange it.”

He characterized the change in tax thestate is looking at as in the 5-10 percentrange and said he wouldn’t expect muchof a response from the companies interms of investment.

Sen. Fred Dyson, R-Eagle River,asked about the likely outcome for thelegacy part of Prudhoe Bay if the tax rateis set too high, and if the companieswould quit investing.

“They’re going to make decisions onwhether or not economics makes sense,”he said, adding that some projects mightbe put on the shelf for a while.

Dyson asked if the companies werelikely to walk away from the gas negotia-tions because of rates they considered toohigh in a new oil tax. Johnston said itwould probably impact share price if theydid, because probably shareholders arealready expecting gas. �


TAXnition of ‘pipeline’ under 42.06,” shesaid.

To move forward on the docket, thecommissioners all agreed that draft lan-guage of a new regulation is now need-ed. However, there was some debateregarding whether the commission orindustry should have a first go at draft-ing the regulation.

Given the current RCA docket load,Commission Chair Kate Giard recom-mended that industry should prepareproposed regulations and that RCAshould then hold a workshop to recon-cile and review the industry proposals.

That would be the most expeditiousway of moving the docket forward, shesaid.

So, the commissioners agreed on anorder requesting draft regulations forconsideration and providing for a futureworkshop.

During the course of their discus-sions of both dockets the commission-ers also considered the question ofwhether the dockets should be merged.Possible dependencies between the reg-ulations involved in the two docketsmight merit the regulations beingworked on as a single package.

However, the commissioners came to aview that, at least for the time being, theissues addressed are sufficiently distinct tomerit the dockets remaining separate. �


RCA

T

“The industry usesstate-of-the-artequipment to findthe oil and get itout of the ground,and I’d like to seethem use the bestavailable technolo-gy to prevent majorspills like the one atGC-2. That’s nothappening rightnow.” —NorthSlope MayorEdward Itta

see LEAK page 18

Slope slowdown costs state $1M per day North Slope crude oil production could remain significantly below normal for

two more weeks or longer due to the Prudhoe Bay pipeline leak that caused theSlope’s largest oil spill, BP managers said March 14.

The slowdown in production is costing the state nearly $1 million a day in rev-enue.

The BP managers also said they figure the pipeline leaked for at least five daysbefore the snow-covered spill was discovered.

And they said corrosion that ate a small hole in the steel pipe might have beencaused by peculiar chemical factors in the pipeline.

Production down by 12%BP managers said the shutdown of the leaky pipeline since March 2 has cut pro-

duction by 95,000 barrels per day, or 12 percent of overall North Slope output.They said it will be two weeks before some or all of the production can be restored.

The 95,000 barrels, plus an additional 4,000 barrels of idled production becauseof another pipeline leak in the neighboring Kuparuk field, is trimming state oil rev-enue by about $960,000 a day at current oil prices of around $60 a barrel, saidMichael Williams, chief economist with the Alaska Department of Revenue.

If the production cut lasts two more weeks, it’ll mean some $26 million less intostate coffers this budget year.

Kemp Copeland, BP’s Prudhoe Bay field manager, said company engineers areworking to restore at least some Prudhoe production by diverting oil that normal-ly flows through the damaged 34-inch pipeline into a nearby 24-inch line. To dothat, workers must link the two pipelines by laying a 10-inch “jumper” pipelineabout the length of a football field.

The bypass could start up in two weeks but would restore only 50 percent to 75percent of the idled production, said Maureen Johnson, a BP senior vice president.

Meanwhile, the 34-inch pipeline will be out of service for up to six weeks whileit is repaired and tested to make sure it doesn’t have any other serious corrosion

see SLOWDOWN page 18


Companies involved in Alaska and northernCanada’s oil and gas industry

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AAce TransportAcuren USA (formerly Canspec Group)AeromedAES Lynx EnterprisesAgriumAir LiquideAir Logistics of Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Alaska Airlines CargoAlaska AnvilAlaska CoverallAlaska DreamsAlaska Interstate ConstructionAlaska Marine LinesAlaska Railroad Corp.Alaska Rubber & SupplyAlaska Steel Co.Alaska TelecomAlaska Tent & TarpAlaska TextilesAlaska Trucking AssociationAlaska USA Mortgage CompanyAlaska West ExpressAlaska’s PeopleAlliance, TheAlpine-MeadowAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Arctic Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Arctic FoundationsArctic Fox EnvironmentalArctic Slope Telephone Assoc. Co-op. . . . . . . . . . . . . . . . . . . . 8Arctic StructuresArctic Wire Rope & Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . 14ASRC Energy Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Engineering & Technology. . . . . . . . . . . . . . . . . . . . . . 19Operations & Maintenance . . . . . . . . . . . . . . . . . . . . . 19Pipeline Power & Communications . . . . . . . . . . . . . . 19

AutryRaynes Engineeringand Environmental Consultants

Avalon Development

B-FBadger ProductionsBaker Hughes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Brooks Range SupplyBW TechnologiesCapital Office SystemsCarlile Transportation ServicesChiulista Camp ServicesCN AquatrainColvilleConocoPhillips AlaskaConstruction Machinery IndustrialCoremongersCrowley AlaskaCruz ConstructionDowland - Bach Corp.Doyon DrillingDoyon LTDDoyon Universal ServicesDynamic Capital ManagementEngineered Fire and Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . 5ENSR Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Epoch Well ServicesESS/On-Site Camp ServicesESS Support Services WorldwideEvergreen Helicopters of AlaskaFairweather Companies, TheFlowline AlaskaFriends of Pets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Frontier Flying Service

G-MGene's ChryslerGreat Northern Engineering. . . . . . . . . . . . . . . . . . . . . . . . . . . 7Great NorthwestHanover CanadaHawk Construction Consultants . . . . . . . . . . . . . . . . . . . . . . 16H.C. Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Hilton Anchorage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Holaday-ParksHotel Captain CookHunter 3-DIndustrial Project ServicesInspirationsJackovich Industrial & Construction SupplyJEMS Real EstateJudy Patrick PhotographyKenai Aviation

Kenworth AlaskaKuukpik Arctic CateringKuukpik/VeritasKuukpik - LCMFLasser Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13LCMFLCMF - Barrow Village Response Team (VRT)Lounsbury & Associates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Lynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMapmakers of AlaskaMarathon OilMarketing SolutionsMayflower CateringMI SwacoMWHMRO Sales

N-PNabors Alaska DrillingNANA/Colt Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9NANA Oilfield ServicesNatco CanadaNature Conservancy, TheNEI Fluid TechnologyNMS Employee LeasingNordic CalistaNorth Slope Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Northern Air CargoNorthern Transportation Co.Offshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oilfield ImprovementsOilfield TransportPacific Power ProductsPanalpinaPDC Harris GroupPeak Oilfield Service Co.PencoPerkins CoiePetroleum Equipment & Services. . . . . . . . . . . . . . . . . . . . . . . 6Petrotechnical Resources of AlaskaPGS OnshorePipe Wranglers Canada. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Prudhoe Bay Shop & StoragePTI Group

Q-ZQUADCORAE SystemsRain for RentRanes & Shine WeldingRenew Air TaxiSalt + Light CreativeScan Home . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8SchlumbergerSecurity AviationSeekins FordSpan-Alaska ConsolidatorsSpenard Builders SupplySteel Brothers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18STEELFABSuperior Machine and Welding3M AlaskaTire Distribution SystemsTOTETotem Equipment & SupplyTrinity Inspection Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Tubular Solutions AlaskaUAA Department of EngineeringUdelhoven Oilfield Systems ServicesUnique Machine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Unitech of AlaskaUnivar USAUsibelliU.S. Bearings and DrivesVECOWelding Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18WesternGecoWiggy's-AlaskaWorksafeWSI-Total SafetyXTO Energy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Jacob Nelson, Medic/H2S, SafetyTechnician

By PAULA EASLEY

WSI Total Safety Inc.(Alaska Division)

WSI Total Safety of Anchorage isdedicated to all things safety in theindustrial/oilfield industries. The compa-ny provides onsite advanced life sup-port medics, hazardous gas detectionand emergency breathing air systemsto remote and offshore locations. Bytraining WSI’s medics in multiple roles(safety, H2S, confined space, etc.) andcombining these services withadvanced emergency medical training,clients get more “bang for their buck.”

Jacob Nelson has nearly a decade’sexperience in Alaska emergency med-ical services. He’s an outdoorsman whothrives on risk-free pastimes (rockclimbing, scuba diving, skiing) and isworking for his rescue diver certifica-tion. Jacob is single and supports theAmerican Heart Association and theAlaska Blood Bank. He agrees withAlbert Einstein that “Imagination ismore important than knowledge. ...”

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

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Carl Grotts, Purchasing/TrafficManager

Alaska Steel Corp.Alaska Steel, a customer-driven, for-

ward-thinking metals company, oper-ates in Anchorage, Fairbanks and Kenai.It helped pioneer low-temperaturesteels in North America and raised thebar on wear application products. Thecompany’s 6,000-ton inventory givescustomers the variety they need fortackling any size project, from a handrail to a high rise.

Born in Fairbanks, Carl Grotts beganin the metals industry building thetrans-Alaska pipeline. He formerlyworked for Stack Steel, which AlaskaSteel took over in 1982, and remainedwith the new company. He becameAnchorage purchasing manager in1988. Carl and his wife Karen have twodaughters, Kristina and Karlyn. Theirgoals for now are finishing the cabinnear Talkeetna and getting the daugh-ters through college.

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gating the spill have said they’re not yetsure whether the leak-detection systemfailed to work as designed.

It’s possible, they said, that the leakwas small and slow enough to escapedetection. Under state regulations, thesystem is required to sound an alarm onlyif the flow through the pipeline drops by1 percent or more over a 24-hour period.A DEC official said earlier that theagency recently considered tightening

that standard but decided not to. Company spokesman Daren Beaudo

said the leak-detection system was testedand “it complies with regulations.”

Spill discovered March 2A BP worker who was driving along a

gravel road beside the pipeline early onthe morning of March 2 discovered thespill after smelling oil.

Beaudo said investigators looked intoa “rumor” that workers had first smelledoil many hours before that time.

“We have not been able to substantiate

it as a fact,” he said. “If someone knowssomething differently we would welcomethat input, but we have not confirmed it todate. Everything we’ve found suggests itwas discovered the morning of March 2.”

The spill, though the largest on theNorth Slope, ranks fourth in terms of allspills involving ANS crude. The biggestcame in 1989, when nearly 11 milliongallons of oil spilled into Prince WilliamSound after the tanker Exxon Valdez ranaground. In 1978 nearly 672,000 gallonsspilled near Fairbanks after saboteursdamaged the 800-mile trans-Alaska oilpipeline, which carries oil from Prudhoe

Bay to the tanker port at Valdez.Five years ago 286,000 gallons

sprayed out of a bullet hole in the trans-Alaska pipeline.

Clean-up workers continued workMarch 13 on a second but far smaller spillin the Conoco-run Kuparuk oil field westof Prudhoe Bay. An inspection has turnedup three breaches in a 24-inch line thatcarries water mixed with a trace of oil,DEC officials reported. Cleanup workersare still calculating the leak size, but DECofficials believe it’s likely less than 500gallons. �



LEAK

problems, she said.

Officials believe detection system working

BP managers and DEC officials said

the pipeline’s leak-detection system wasworking, but no alarm sounded for fieldworkers, most likely because the oilleaked too slowly over time to trigger it.

By regulation, the system must detectleaks involving 1 percent or more of apipeline’s daily oil flow. In this case, 1percent would equal about 1,000 barrels,leading Johnson to figure the leak must

have persisted for at least five days giventhe spill’s estimated size of nearly 5,000barrels. Otherwise, the leak volumewould have been large enough to set offan alert.

“We believe the leak probably startedas a pinhole and grew over time and wastoo small to be detected by our system,”Johnson said.

Johnson said BP and DEC investiga-tors are looking into whether too littleanti-corrosion chemicals were flowingdown the pipeline from Gathering Center2, a plant that separates water from oil.That or other chemical factors might have

caused the increased corrosion seen in thepipe over the last six months, eventuallyleading to a hole about a quarter-inchwide and a half-inch long, she said.

A different section of the samepipeline didn’t show the same corrosionproblem, Johnson said.

BP plans to work with DEC on ways todetect smaller spills that might evade leakdetectors, Johnson said. One idea mightbe to increase the use of aerial infraredsurveys, which can spot warm oilobscured by snow.

—WESLEY LOY, ANCHORAGE DAILY NEWS


SLOWDOWN

before.”More could come if TransCanada

moves ahead with its 450,000 bpdKeystone pipeline from Alberta toPatoka, Ill. — a system that could beoperational in 2009.

Enbridge has projects on the tableworth about C$12 billion to extend itsreach to U.S. and Asian markets.

Cushing doorway to GulfCushing, which has refining capacity

of only 500,000 bpd, is the doorway to the6.5 million bpd Gulf Coast refiningregion, which Canadian crude will passthrough within a few months.

Enbridge carries 63 percent of allCanadian oil exports to the U.S. in 70 dif-ferent blends.

Experts have been warning for yearsthat Western Canadian crude producersmust gain access to more markets if theyare to ease the painful price spread

between bitumen blends and light oil.Michael Lovett, president of Muse

Stancil, told an oil sands forum last yearAlberta bitumen producers were beingforced to sell most of their exports into aflooded markets consisting of only half adozen refiners in the U.S. Midwest.

He suggested bitumen prices mighthave improved if volumes could havebeen shipped westward to alternativebuyers in the Pacific basin.

Stephen Fekete, a principal withPurvin & Gertz, said the differential was“likely to remain wide,” but might shrinkif refiners in the Midwest and RockyMountain states proceeded with propos-als to build new cokers capable of crack-ing bitumen blends.

The new Western Canadian Selectblend currently amounts to 250,000 bpdwith an average 19-21 API.

Nymex officials say they are open tomeeting customer needs by establishing anew future contract if they are shown tobe viable, but for now the possibility isonly in the research stage. �


OIL

trans-Alaska pipeline route to Valdez. Thecorporation is currently in the process ofapplying for a state right of way for a spurgas pipeline between Glennallen andPalmer that would bring North Slope gasinto the Southcentral Alaska gas distribu-tion network.

Regulatory issuesIn the ANGDA board meeting Steve

Pratt of Steve Pratt Enterprises presenteda preliminary report on the regulatoryissues that relate to obtaining gas for in-state delivery from a North Slope line.

Pratt emphasized the importance of

Alaska businesses booking intrastatecapacity in the line by bidding during theFederal Energy Regulatory Commissionopen season.

“To pull gas off at a state off-takepoint somehow we’ve got to get gas onthat interstate pipeline to that off-takepoint,” he said.

And that will require Alaska commer-cial commitment to the use of thepipeline.

“Unless a commercial player showsup at the door you’re out,” said StevePorter, deputy commissioner of theAlaska Department of Revenue.

The FERC rules for a North Slope lineinclude opportunities for people to obtainin-state off-take of gas, Pratt said. Bookin-state capacity on the line during the

FERC open season and you’ll get it.Don’t book it and you’ll miss out.

FERC processPratt went on to describe the FERC

open season process for a North Slopepipeline.

The first step consists of pre-subscrip-tion capacity negotiations that can hap-pen any time between pipeline sponsorsand potential shippers. At some point thesponsors will then trigger a 180-day peri-od. The first 60 days of that period willallow public comments and will enablethe rules for conducting the open seasonto be defined, prior to issuance of a pend-ing open season notice. Thirty days afterthat notice a 90-day open season willstart.

Anyone who wants to ship gas on thepipeline will need to submit bids duringthose 90 days. And after the open seasonends the pipeline sponsors will start thefinal planning and design of the pipeline,to accommodate the required capacity.

“If we don’t tell them how much wewant delivered at that point then they willdesign the pipeline for the same volumedownstream of that point that they didgetting to that point,” ANGDA CEOHarold Heinze said. “If you come back tothem later and say ‘gee, I need somecapacity to get off at Delta,’ they’re goingto say ‘$2.50 please’ (the full pipelinetariff).”

Pratt even emphasized the value of


GAS

see GAS page 19

becoming involved in the pre-subscrip-tion negotiations, rather than waiting forthe open season to occur.

“(Then) I’m not bound by tariffs. I’mnot bound by anything. I can negotiate onanything,” he said. “… I really think weshould think about (whether we can) …play in this game,” he said.

Late biddingThe FERC rules do allow bids for

capacity after the end of the open seasonand before the completion of pipelinedesign. However, the pipeline sponsorneed only accommodate late bids if theadditional requirements don’t adverselyimpact the pipeline economics and oper-ation, Pratt said. Moreover, the late bid-der has to provide a solid justification forbidding late.

Heinze also pointed out that the openseason process in the Lower 48 normallyonly runs for 30 to 60 days.

“We fought hard to get this to be a180-day process. Nobody’s going to giveus 1 second longer,” he said. “… Theonly guarantee we’ve got is between dayzero and day 180. … It’s unclear whathappens after that.”

The board discussed the potentialramifications of not bidding during theopen season. These ramifications couldinclude the need for pipeline expansionor having to negotiate to lease someoneelse’s booked capacity.

2007 timeframeBut when might the open season hap-

pen?“Our view is spring ’07,” Heinze said.

“That is the scenario that is consistent inour minds with the Legislature passingthe production tax, a gas contract comingabout sometime during late summer, fall.… You’re out of this process by the win-ter of ’07.”

Part of the reasoning behind this pre-diction is the benefit to a pipeline spon-sor of an early open season.

“In my estimate they would be foolishnot to have the open season process asearly in this as they could for a wholebunch of reasons, not the least of whichis that it’s the key thing that influences(pipeline) design,” Heinze said.

But the clock is steadily tickingtowards that 2007 timeframe and Prattoutlined a list of things that need to hap-pen, to prepare for the open season:

* Completion of changes to the AlaskaPipeline Act (in November RCA recom-mended repeal of two amendments to theact);

• Completion of a U.S. Department ofthe Environment Study into Alaska in-state natural gas needs;

• RCA approval of gas utility supplycontracts;

• The identification of commercial andindustrial natural gas needs; and

• Alaska Department of NaturalResources and RCA approval ofANGDA’s Glennallen spur line.

Credible bidsHowever, a key problem is that a bid-

der for North Slope pipeline capacityneeds to establish a credible businessplan and fundingbefore the open sea-son starts.

“The commit-ment is for capacityin the pipeline, vol-ume and time,”Heinze said. “…You could be bid-ding easily for 20years worth ofcapacity and a tariffnumber, that in thecase of our localutilities could (addto) hundreds of millions of dollars, farexceeding their worth.”

A bidder needs to be able to providefinancial instruments to guarantee a bid,he said. And bidders need to establishmarkets for the gas and determine theirshipment requirements.

Heinze sees ANGDA possibly helpingbusinesses learn how to bid for capacity— and perhaps combining the capacityrequirements of several businesses. Thecorporation, he said, could also help indiscussions with RCA regardingapproval of utility contracts.

“The difficulty we see is for all theregulated utilities to make this pledge(for pipeline capacity and tariff),” Heinzesaid. “Whatever pledge is made it has tobe approved by RCA.”

Heinze also expressed concern aboutthe availability of contractors to work onspur line projects once work on the NorthSlope gas line is under way.

“If there is a deal struck say late sum-mer, early fall (this year) … the suckingup of contractors will get so huge thatwe’ll be shut down,” he said. “If we don’thave it done by … spring of ’07 we’renot going to get anybody for our work.”

Parks Highwaypipeline route

With the help offederal fundingEnstar Natural GasCo. is studying agas pipeline routealong the ParksHighway to theNenana basin andFairbanks. Thatpipeline could actas an alternative gasspur line for ship-

ping gas to Southcentral Alaska from aNorth Slope gas line.

One outcome of the study of the ParksHighway route will be a comparisonbetween the merits of that route and themerits of the ANGDA Glennallen spurline route. However, Heinze is concernedabout the possibility that fieldwork need-ed for the Parks Highway route right-of-way application will not be completedbefore a North Slope pipeline projectabsorbs all available contractors. He isalso concerned that the Parks Highwayroute will miss a 2007 open season for

the North Slope pipeline.Enstar spokesman Curtis Thayer has

told Petroleum News that the studies intothe Parks Highway route will not likelybe completed until the end of 2007,although an initial study funded by theU.S. Department of Energy will finish inAugust 2006. Enstar anticipates havingadequate staffing for all of the work.

“Our company has been in the busi-ness for 45 years and we anticipate usingour own employees and contractors forthe work,” he said.

Thayer said that the availability ofgovernment funds is driving the time-frame of the Parks Highway gas lineproject. However, he thinks that some ofthe concerns about the availability ofNorth Slope pipeline capacity are prema-ture, given the number of unknown vari-ables that play into the situation. Forexample, current exploration in theNenana basin, southwest of Fairbanks,may discover sufficient gas to meetEnstar’s needs. In that case Enstar maynot require North Slope gas for 20 years,he said.

Thayer also expects the state to takeaccount of intra-state gas transportationneeds in its contract with the North Slopepipeline sponsors.

Create awarenessAt the ANGDA board meeting Pratt

also talked about the number ofunknowns in the intra-state gas equation.

“There are questions but not a lot ofanswers, but these are things that we’retrying to figure out, understand and justcreate an awareness with all the in-statestakeholders,” he said.

It would be possible for a utility, forexample, to make a business decision notto opt for intrastate gas from the NorthSlope gas line until the first expansionopportunity, perhaps after 10 years, hesaid. But “if you want gas in the 2016 to2020 timeframe, you’ve got to be at thetable,” he said.

Heinze sees the current situation as adefining point for ANGDA, a pointwhere the corporation needs to decidehow it will help ensure a successfulfuture for the natural gas industry inAlaska. And an ANGDA aggregating andfacilitating role in intra-state gas trans-portation may become part of that future.

“If we cause it to happen, and happenin a good sort of way, that is sufficient,”Heinze said. “We do not need to be theactual owner-operator of the pipeline.”

Board members questioned howANGDA would be able to move ahead ofthe North Slope pipeline deal.

“Work like hell,” was Heinze’sresponse. �


Proposed spur line route from Glennallen to Palmer


GAS

It would be possible for a utility,for example, to make a businessdecision not to opt for intrastate

gas from the North Slope gas lineuntil the first expansion

opportunity, perhaps after 10years, Steve Pratt said. But “if you

want gas in the 2016 to 2020timeframe, you’ve got to be at the

table,” he said.


lation that might have commercial potential.A spokeswoman for EnCana told Petroleum News

that the partners hope for a board ruling in April whichwill determine their next steps.

For now, no further drilling plans have been made,she said.

N-16 was drilled to a depth of 10,200 feet in the 2003-04 winter and encountered hydrocarbons that weredescribed by EnCana as “encouraging.”

EnCana has a 37.5 percent interest in N-16, withAnadarko holding 37.5 percent and ConocoPhillips 25

percent.

First pure exploration wellIt was the first pure exploration well by EnCana in the

Mackenzie Delta region and is seen by the independentas part of its strategy to build long-term reserves.

The nearby N-05 was drilled last winter, targeting adepth of 11,900 feet according to National Energy Boardstatistics.

The two wells are about 47 miles north if Inuvik,Northwest Territories.

Anadarko said the partnership has begun reprocessingthree-dimensional seismic data for development plan-ning and to mature nearby exploration prospects.

ConocoPhillips is already one of four owners of thethree anchor gas fields that underpin the Mackenzie GasProject.

Following its takeover of Gulf Canada Resources, itgained 75 percent of the Parsons Lake find, estimated at1.8 trillion cubic feet, with ExxonMobil Canada holdingthe remaining 25 percent.

Anadarko became part of the Umiak play by acquir-ing a working interest from Alberta Energy Co. (one ofthe two founding companies of EnCana) in 2000. �


WELLSAnadarko said the partnership has begun

reprocessing three-dimensional seismic data fordevelopment planning and to mature nearby

exploration prospects.

eight years,” Oynes told Petroleum Newsin a post-sale interview. “I’m sure theU.S. Treasury will be happy.”

New players bidSale 198 also brought several new

players to the Gulf, most notably Spain’sRepsol, which knocked out eight biddersand bidding groups with a $20.2 millionbid for Green Canyon Block 304.

Though many Gulf producers werebadly shaken by back-to-back hurricanesKatrina and Rita, they came to CentralGulf Lease Sale 198 in high spirits andwith deep pockets, filled with windfallprofits from an exceptionally strong andenduring oil-and-gas price environment.

A sale-high $42.8 million bid submit-ted by Amerada Hess on Green CanyonBlock 287 was the highest single bid inany Gulf of Mexico sale during the past20 years.

Sale 198 also was one of the morecompetitive offshore lease sales in mem-ory, with an unusually high number ofblocks receiving multiple bids, and anunusually large number of blocks attract-ing bids greater than $1 million.

In fact, sale results show that about100 or one-fourth of the 405 winning bidsbroke the million-dollar mark. Moreover,the sum total of the 707 bids submitted inthe sale, including both winning and los-ing bids, came in at just over $978 mil-lion, further evidence of industry’s stronginterest in Sale 198.

“I talked to a couple of companiesbefore the sale … and they were antici-pating that they were going to have to bidpretty high in order to get blocks,” Oynesnoted. “They were anticipating thateverybody was going to be looking, to adegree, at some of the same stuff.”

Kerr-McGee, a major deepwater play-er, and its partners captured four leases inthe sale, bringing the E&P independent’s

total position in deepwater Gulf to 2.75million acres.

“These leases provide additionalopportunities in our core area,” said DaveHager, Kerr-McGee’s chief operatingofficer. “They also add to our growinginventory of sub-salt non-amplitudeprospects andenhance our overallportfolio in deep-water, which isspread across mul-tiple trends includ-ing the Mioceneand (deeper)Eocene.”

Hess the bigspender

However, it wasHess that emerged as the big spender withits $42.8 million Green Canyon bid. Butthere were plenty of other eyebrow rais-ers, including a nearly $34 million win-ning bid submitted by partners NewfieldExploration and Anadarko Petroleum onanother Green Canyon block (551).

Anadarko noted post-sale that Block551 contains a prospect called Lyell,which is situated “in close proximity toand targets” the same Miocene pay zonesfound in Anadarko’s Knotty Head and thenearby Tahiti and Tonga fields.

Anadarko said it also picked up alower tertiary lead called Fog Hat onWalker Ridge 414, and five wildcatprospects in a newly emerging play on theabyssal plain: the Antares prospect onAtwater Valley 890, 891 and 892; Siriuson Atwater Valley 636, 637 and 681;Cygnus on Atwater Valley 675 and 719;Aldebaran on Green Canyon 1009; andRigel on Lund 47 and 48.

But it was the prolific Green Canyonregion — home to such monster lowerand middle Miocene discoveries as Tahiti,Atlantis and Mad Dog — that accountedfor six of the highest 10 bids in the entiresale, or a combined $144.3 million, near-

ly 25 percent of total high bids in the sale.Hess had to beat seven other bids to

capture Green Canyon Block 287, whileNewfield-Anadarko topped five bids totake Green Canyon Block 551. Other bigwinners in the Green Canyon regionwere: Australia’s Woodside Energy, $26.6

million for Block452; Repsol, $20.2million for Block304; Hess, $12.8million for Block204; and Italy’s Eni,$8 million for Block340.

Mississippi Canyondraws bidders

Another deepwa-ter hot spot in the

Central Gulf and home to Thunder Horse,the largest discovery ever in the Gulf,Mississippi Canyon accounted for two ofthe highest ten bids in the sale. NobleEnergy and Samson Offshore teamed upto take Block 948 for $20.2 million, whilepartners Kerr-McGee and Dominion E&Pcaptured Block 945 with an $8.4 millionbid.

Other top-ten bidders were Dominionand Hydro Gulf of Mexico, which beat allcomers to take Atwater Valley Block 428with a $21.4 million bid, and SamsonOffshore, which took South Marsh IslandArea Block 38 with an $11 million bid.

In terms of the sheer number of tractswon, BP clearly got the most for itsinvestment, capturing 73 blocks with bidstotaling $22.2 million. However, many ofthe tracts won by BP were unchallengedand located in “ultra-deep” waters ofAtwater Valley.

Other top-ten winners in this categorywere Australia’s BHP Billiton, 26 blockswith $7.6 million in high bids; Hunt Oil,23 blocks with $10.9 million in bids;Dominion, 16 blocks with $41.4 millionin bids; Hydro, 14 blocks with $20.1 mil-lion in bids; Hess, 13 blocks with $62.6

million in bids; Anadarko, 13 blocks with$20.3 million in bids; RepublicExploration, 12 blocks with $3.3 millionin bids; Woodside, 11 blocks with $32.2million; and LLOG Exploration Offshore,11 blocks with $26.6 million in total highbids.

Gas of interest in shallower watersShallower waters of the Gulf’s conti-

nental shelf failed to attract the dollarmagnitude of high bids in the oil-pronedeepwater Gulf. Nevertheless, the gas-prone shelf, backed by enticing govern-ment drilling incentives, ignited intensecompetition, with 55 of 194 blocksreceiving multiple bids, including per-haps the most closely watched block ofthe entire sale, Ship Shoal 127.

Ship Shoal 127 brought a sale-high 10bids, with ConocoPhillips emerging asthe apparent winner on a lone $3 millionbid. Other shelf blocks attracted multiplebids ranging from as few as two to asmany as nine.

A number of blocks receiving strongbids in Sale 198, including Ship Shoal127 and Hess’ Green Canyon 287, wereamong more than 300 so-called “newlyavailable” leases, or blocks that wererelinquished by prior owners and justrecently became available. For example,Ship Shoal 127’s most recent owner wasbig Houston independent Apache, a majorplayer on the shelf.

Energy Partners Ltd, a small but grow-ing E&P independent based in storm-tornNew Orleans, partnered up with othercompanies to win two deepwater blocksand nine shelf blocks, with its share of theinvestment totaling $7.9 million.

“The competition at the last severalGulf of Mexico lease sales is evidence ofthe attractive targets and associated eco-nomics in the (shelf) area,” said RichardBachmann, EPL’s chairman and chiefexecutive officer. �

But it was the prolific GreenCanyon region — home to such

monster lower and middle Miocenediscoveries as Tahiti, Atlantis andMad Dog — that accounted for sixof the highest 10 bids in the entiresale, or a combined $144.3 million,nearly 25 percent of total high bids

in the sale.


SALE

up rig that will be headed to Alaska thissummer for Escopeta Oil to drill theKitchen prospect in Cook Inlet.

Bob Warthen, a consulting geologistworking with Escopeta, told PetroleumNews March 16 that some Inlet crewmembers will be sent to Port Arthur,Texas, to get familiar with the jack-updrilling rig. The Tellus is currently beingrefurbished in Port Arthur on the Gulf ofMexico.

Warthen has worked the inlet since1967, first for Union Oil where he was aregional geologist for 26 years, and thenas a consultant.

On March 15, Warthen and Escopeta’spermitting contractor, Entrix, had a pre-application meeting for the AlaskaCoastal Management Program. Severalgovernment agencies were represented in

the meeting, including the U.S. CoastGuard, U.S. Corps of Engineers, U.S.Fish & Wildlife, Alaska Department ofEnvironmental Conservation, the stateDepartment of Natural Resources’Division of Oil and Gas, and the coastaldistrict office of the Kenai PeninsulaBorough, among others.

“We have met with all the agenciesseparately, but this was our first meetingwith everyone in the same room,”Warthen said.

Escopeta, he said, has applied to joinCook Inlet Spill Prevention and ResponseInc., better known as CISPRI, an inletresponse contractor.

On March 16 Warthen was scheduledto meet with Division of Oil and Gas offi-cials regarding unitization of Escopeta’sKitchen prospect.

—KAY CASHMAN


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