page7

Arctic delays raise need for LNG;Kvisle hasn't given up on Mac

Vol. 12, No. 18 • www.PetroleumNews.com Published weekly by Petroleum Newspapers of Alaska Week of May 6, 2007 • $1.50

● L A N D & L E A S I N G

● N A T U R A L G A S

● L A N D & L E A S I N G

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

8Alaska revenue outlook offers mixed bag: Forecast

calls for slow decline in oil prices, short-term increase in production

10 Nova Scotia makes low-key changes: Revises licenseregs to stop companies from sitting on exploration, development rights

14 New take on Mat-Su Valley CBM: Fowler plans horizon-tal drilling, patented separation technology to avoid enviro problems

One tricky step to goVirginia makes Bush administration’s proposed 2007-2012 offshore leasing program

By RAY TYSONFor Petroleum News

or the first time in years, the U.S. governmentis proposing an offshore oil and gas lease salein federal waters outside Alaska and the Gulfof Mexico. The distinction goes to the state of

Virginia, or rather to state and local politicians whopushed hardest for a lease sale off Virginia’s coast-line, in a region called the Mid-Atlantic PlanningArea.

Offshore Virginia is among 21 lease sales ineight of the nation’s 26 offshore planning areas pro-posed by the U.S. Minerals Management Servicefor the years 2007 through 2012. This final version

F

See Alaska OCS story and map on page 12 of this issue.see STEP page 21

Mackenzie gas project ‘not a second-hand effort,’ says Hearn

There is “no lack of will on anybody’s part” to make theMackenzie Gas Project happen, but neither should anyone under-estimate the challenges, said Tim Hearn, chief executive officer ofImperial Oil, the lead partner in the C$16.2billion venture.

He told reporters May 1 that “serious”money has been spent “trying to get to thisstage” — the latest estimates put the outlayby the proponents at more than C$600 mil-lion.

“This is not a second-hand effort,” Hearnsaid. “We’ve had all hands on deck trying tofigure out if we can make this go (in a way)that would meet all the stakeholders’needs.”

He said talks are under way with theCanadian government on a fiscal framework that could includeaccelerated depreciation rates, royalty breaks and cost-sharing oninfrastructure such as roads and airstrips in the NorthwestTerritories to benefit other resource development.

Imperial CEOTim Hearn

see IMPERIAL page 19

No stay on Pt. ThomsonCourt rules against companies, says DNR can move forward with lease termination

By KAY CASHMANPetroleum News

n May 1 Alaska’s Superior Court deniedmotions from Chevron, BP, ConocoPhillipsand ExxonMobil to stop the Department ofNatural Resources from moving forward

with the termination of the undeveloped PointThomson unit on the grounds that it was in thepublic interest to allow DNR to proceed with relat-ed lease termination.

DNR had made administrative decisions in late2006 to terminate the eastern North Slope unit, butthe four Point Thomson leaseholders wanted thecourt to stay (halt) any further action by DNR untiltheir judicial appeals, filed with the court inDecember, had run their course. In its decision todeny the four companies’ motions to stay, the

Superior Court was acting in its capacity as anappellate court for administrative decisions byDNR.

The judicial appeals filed by Chevron, BP,

O

see RULING page 22

Global LNG supplies tightWood Mackenzie: Keeping up with world demand will be challenging for decades

By ALLEN BAKERFor Petroleum News

he supply of LNG for the world market willbe tight for years or decades to come, evenwith huge new liquefaction facilities beingconstructed or planned in Qatar, Nigeria and

elsewhere, according to a top consultant in thefield.

The LNG industry “seems to have developed anobsession with LNG supply,” Frank Harris says.

His conclusion: That obsession is justified.“The big challenge facing the LNG industry in

the foreseeable future is actually getting access tosufficient gas reserves, or enough gas supplies tofeed growth,” Harris told the LNG15 conference inBarcelona, Spain, on April 24. Harris is head of

global LNG for Wood Mackenzie, the prominentenergy consulting firm based in Edinburgh,Scotland.

“The big issue is, is there actually going to beenough LNG supply to meet demand?” Harrissaid. “We think this is an issue in the short, medi-

Competition for limited supplies of theclean fuel could increase fuel prices

around the globe, while diverting LNGaway from North America, where gas

prices are comparatively low, says FrankHarris, head of global LNG for Wood

Mackenzie.

T

see LNG page 19

Rich on mega project financing:Alaska gas line would setrecord, federal loan guaranteemay only be for 80% of 80%

Last year the Alaska Legislature got aworkshop on building mega projects.

This year they got an introduction to whathas to happen before a shovel hits theground: megaproject financing.

Frederic Rich of the New York law firmof Sullivan and Cromwell said his firm developed the work-shop for agencies working on the federal loan guarantee forthe Alaska natural gas pipeline — the Department of Energy,the U.S. Treasury and the Office of Management and Budget

see FINANCING page 18

Alaska Legislature likely togive RCA new life, bills tightentimelines, create task force

As the 25th Alaska Legislature movesinexorably toward the close of its firstsession May 16, the fate of theRegulatory Commission of Alaska is oneorder of business yet to be decided.

Under a sunset provision in state law,the RCA is scheduled to cease operationJune 30, unless lawmakers act to extendthe life of the agency.

Created in 1999 upon reorganizationof the Alaska Public Utilities

see RCA page 16

RCA Chairman Kate Giard

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

2 PETROLEUM NEWS • WEEK OF MAY 6, 2007

GOVERNMENT

FINANCE & ECONOMY

LAND & LEASING

NATURAL GAS5 Statoil puts footprint in Alberta oil sands

Norwegian oil giant drawn by 'long-term' barrels inpouncing on privately held company with plans for bitumen production, upgrading

5 AOGCC schedules Rule 9 hearing

February public meeting summarized Prudhoe Bay gas offtake study; staff recommended depletion planning prior to gas sales

10 Nova Scotia makes low-key changes

Revises license regulations to stop companies fromsitting 'indefinitely' on exploration and developmentrights; lowers front-end deposits to attract 'adventurers'

15 Governor asks for O&G assessment

Asks Alaska Legislature for $5M, infrastructureassessment for DNR's new Petroleum Systems Integrity Office would be done by DEC

17 Getting an abrupt wake-up call

Alberta starts full-scale royalty review against backdropof forecast nosedive in revenues, internal study points to declining take

12 Chukchi, North Aleutian sales proposed

Interior releases five-year OCS leasing plan, 2007-12, with as much as 37 million acres newly available for lease off Alaska

15 Pioneer drops Cronus unit

Disappointing results from 2005-06 exploration wellbehind decision to relinquish former ConocoPhillips North Slope prospect

EXPLORATION & PRODUCTION

ON THE COVERNo stay on Point Thomson

Court rules against companies, says DNR can move forward with lease termination

Global LNG supplies tight

Wood Mackenzie: Keeping up with world demand will bechallenging for decades

One tricky step to go

Virginia makes Bush administration's proposed 2007-2012 offshore leasing program

4 Crunch time for gas line in Juneau

6 Oil prices up following attack in Nigeria

7 Bow Valley sells Canada assets

11 ANS production drops 1 percent in April

21 Gulf oil output expected to rise 40%

7 Arctic delays raise need for LNG

14 New approach to Mat-Su Valley CBM

18 How much will federal loan guarantee cover?

13 Pioneer says ConocoPhillips NPR-A Noatak, Intrepid exploration wells 'non-commercial'

13 PPT amendments amended; move on both sides

18 Oil company earnings chart

Mackenzie gas project 'not a second-hand effort,' says Tim Hearn

Alaska Legislature likely to give RCA new life

Rich on mega project financing:Alaska gas line would set record, federalloan guarantee may only be for 80% of 80%

8 Alaska revenue outlook offers mixed bag

Calls for slow decline in oil prices, short-term increase inproduction and temporarily higher unrestricted revenue

PETROLEUM NEWS • WEEK OF MAY 6, 2007 3

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

Alaska Rig StatusNorth Slope - Onshore

Akita Drilling Ltd.Dreco 1250 UE 63 (SCR/TD) Moving out from Jacob's Ladder Anadarko

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point F-99i BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 1J-135 ConocoPhillipsDreco 1000 UE 16 (SCR/TD) Workover Prudhoe DS6-03a BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD2-72 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk 1J-120 ConocoPhillipsTSM 7000 Arctic Fox #1 Stacked in Yard Pioneer Natural Resources

Arctic Wolf #2 Racked at Cape Simpson FEX

Kuukpik 5 Demobing from Intrepid #2 to ConocoPhillipsDeadhorse

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES Prudhoe Bay DS 09-15i BPMid-Continental U36A 3-S Milne Point MPL-28A BPOilwell 700 E 4-ES (SCR) Prudhoe Bay DS 17-05 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay PM 2-15 BPDreco 1000 UE 9-ES (SCR/TD) Orion V-215i BPOilwell 2000 Hercules 14-E (SCR) Aklaakyak FEXOilwell 2000 Hercules 16-E (SCR/TD) Stacked 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 Oliktok Point OPi2 AnadarkoEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Rig move/on standby BP

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay well D-30A BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay well DS4-01A BPIdeco 900 3 (SCR/TD) Kuparuk 1E-126 ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E Northstar NS-33 BP

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

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 KBU 12-5 Marathon

Nabors Alaska DrillingNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Swanson River SRU 41-05 Chevron

Cook Inlet Basin – Offshore

Unocal (Nabors Alaska Drilling labor contractor)Not Available

XTO EnergyNational 1320 A Platform A no drilling or workovers at present XTONational 110 C (TD) Idle XTO

Alaska Interior

Cudd Pressure ControlCudd 340k Jack Unit Workover Ahtna #1-19 Rutter and Wilbanks

Mackenzie Rig StatusCanadian Beaufort Sea

Seatankers (AKITA Equtak labor contract)SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Devon ARL Corp.

Mackenzie Delta-OnshoreAKITA EqutakDreco 1250 UE 62 (SCR/TD) Moving to Inuvik, NT Aurora College Institute

Modified National 370 64 (TD) Racked in Inuvik, NT Chevron

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of May 3, 2007.

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*April 27 April 20 Year Ago

US 1,747 1,769 1,608Canada 81 98 150Gulf 72 75 90

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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By KRISTEN NELSONPetroleum News

GIA is in its final committees in theAlaska Legislature and with the finishline in sight the pressure is on legisla-tors from both the administration and

the North Slope producers. The Alaska Gasline Inducement Act, the

vehicle Gov. Sarah Palin plans to use to geta gas pipeline built to move Alaska NorthSlope gas to market, provides inducementsto encourage competitive bids for a pipelineproject.

The producers — BP, ConocoPhillipsand ExxonMobil — were well on their wayto cutting a contract deal with the previousadministration, and do not want the proce-dure AGIA proposes, where fixed condi-tions must be met, favoring instead a moreflexible approach in which each applicantcould propose ways to meet the state’srequirements, rather than agreeing to meetthe requirements the administration has laidout in AGIA.

The administration introduced the bill inearly March and has worked with legislatorson a number of changes, ranging from tech-

nical to substantive. Committee substitutesare now in Finance committees in both bod-ies.

Senate Finance hopes to have its workcompleted May 6. House Finance, whichreceived the House version of the bill a fewdays behind the Senate committee, is target-ing May 9 to complete its work.

The Legislature gavels out May 16. House Speaker John Harris, R-Valdez,

said April 30 that legislators are trying toavoid a conference committee to reconcileHouse and Senate versions of AGIAbecause of concern that would drive theLegislature into a special session.

There were three special sessions lastsummer and legislators do not seem anxiousto spend another summer in Juneau.

House seeks flexibility as issueHouse Majority Leader Ralph Samuels,

R-Anchorage, said members are becomingmore and more educated on the subject mat-ter and the controversial spots in AGIA.These include the $500 million in matchingfunds that the state is proposing as one of theincentives in the bill. There is a question ofwhether the state should take an equity posi-tion in exchange for the $500 million.

As to the issue of whether the producerswould — as they have said recently — notapply under AGIA, Samuels said it’s hard toknow whether industry players are blowingsmoke over AGIA or would participate.

Harris said that while there is some pushto make AGIA as inviting as possible for asmany people, he understands the adminis-tration’s view that it can’t be an open-endedprocess. One of the issues legislative leader-ship planned to discuss with the governor inan April 30 meeting was how much wiggleroom there would be for requirements theadministration wants to see in applications.If an application doesn’t meet each one ofthese to the letter of the law but is pretty darnclose do you throw it out?

Samuels said he realized you couldn’thave complete flexibility, but would beinterested in seeing how the AGIA processcould be crafted to have more options with-out opening it wide open.

If the commissioners don’t want tochoose an application, he said, they don’thave to.

Senate Finance wants more on tableThe Senate Bipartisan Working Group

had their weekly press availability May 1,after the meeting with the governor.

Senate President Lyda Green, R-Wasilla,said she wasn’t sure that AGIA as writtenwould attract anyone, but she said the meet-ing with the governor was productive andthat the administration has heard areas ofconcern and was working on some of them.

Green said that some of the “musthaves” in AGIA are “very, very dear to theadministration” but that some legislatorsthink that 100 percent of the items should-n’t be required, although the more of thoseitems an application has, the more favor-ably it would be received.

Sen. Charlie Huggins, R-Wasilla, chair

of Senate Resource, the first Senate com-mittee to work on AGIA, said Alaskanswould like to have multiple applications.

“Does AGIA promote that? I don’t knowthe answer,” he said.

Sen. Bert Stedman, R-Sitka, co-chair ofSenate Finance, now hearing the bill, saidthe committee is trying to explore the prosand cons and get more information on thetable. He said he has asked companies com-ing to testify that they specify areas of thebill that they like and don’t like and providelanguage for changes they want to see.

He also said the Legislature has consult-ants coming onboard now and the commit-tee will be working on fixes to problems itfinds in the bill. The federal loan guaranteeexpires two years after a FERC certificate isissued, Stedman said, but the bill allowsfive years beyond issuance of a FERC cer-tificate for a company to get financing. Thefive-year provision could collapse thefinancing, and he said the committee hasbrought the problem to the administration’sattention.

Administration strikes backThe North Slope producers originally

said they wouldn’t be able to submit con-forming applications under AGIA orwouldn’t recommend it to their boards orcouldn’t work out the economics.

In their latest rounds of testimony beforeHouse and Senate Finance, in late April andearly May, the companies have now toldlegislators that unless AGIA is changed toallow for flexible applications they will notapply.

AGIA is too prescriptive, they have toldlegislators, referring to the administration’s“must-have” list.

The administration answered criticism ata May 3 press conference, bringing out theexperts who have helped it craft AGIA toanswer questions.

Commissioner of Revenue Pat Galvinsaid the administration expects AGIA topass the Legislature before the end of thesession. As for changes, he said it wouldhave been easier if the producers hadbrought forward specific changes they arerequesting earlier. He said with the specificson the table now there are some things thatthe administration can address and somethings it disagrees on. He said he thinkschanges can be made in the next few days.

Galvin said the producers are trying toview AGIA in an anti-producer manner andthere are some language changes that couldaddress some of those concerns.

But the administration is not consideringmajor changes to allow flexibility in appli-cations. Galvin said the administration hasalways been clear that it believes the gener-al structure of AGIA is sound and has heardnothing in testimony or discussions tochange that view.

As for the 20 “must haves” he said theyare all reasonable and they need to be metfor an application to be considered eligiblefor inducements. This is not a wish list, hesaid. Applicants have to do these things tobe eligible.●

4 PETROLEUM NEWS • WEEK OF MAY 6, 2007

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● N A T U R A L G A S

Crunch time for gas line in JuneauAlaska legislative committees in end stretch for AGIA; North Slope producers ask for options in bidding on pipeline project

A

By KRISTEN NELSONPetroleum News

ollowing a February public meeting onthe gas offtake rate for Prudhoe Bay,the Alaska Oil and Gas ConservationCommission has scheduled a hearing

for June 19 on whether it should requiredepletion planning and reporting prior to amajor gas sale.

The commission set an offtake rate of 2.7billion cubic feet a day in 1977 and its staffand a consultant said after a 2006 study thatthere was insufficient evidence to recom-mend increasing the established offtake rate,but recommended that the Prudhoe ownersbe required to do depletion planning prior tocommitting to selling gas.

The June hearing will consider amendingrule 9 of conservation order 341D, whichestablishes rates and conditions for Prudhoe

Bay oil pool gas offtake, to require a deple-tion plan for the Prudhoe Bay reservoir priorto significant gas offtake from the field.

The commission said it would considerrequiring the working interest owners todevelop near-term strategies to prepare forgas offtake, including methods to increasethe capture of oil prior to gas offtake and toensure that facility downtime and welldowntime are minimized; and a requirementthat the owners provide the commissionwith detailed, periodic updates on theprogress of depletion planning efforts.

Oil production needs to be increasedIn a public summary of the confidential

2006 study, commission staff said the onlymitigation measure in the modeling doneduring the study that significantly increasedtrends of total hydrocarbon recovery at

Prudhoe Bay was increased oil capture priorto gas sales.

Commission Chair John Norman told theSenate Finance Committee April 27 thathundreds of millions of barrels of oil andcondensate could be lost if gas offtake fromNorth Slope fields is not properly managed.He said that based on its 2006 Prudhoe Bay

study the commission is prepared to movevery quickly upon receipt of an applicationfor an increased gas offtake rate. He said anofftake rate is a multi-variable equationwhere the inputs include when gas sales areproposed, how aggressively oil has been

By GARY PARKFor Petroleum News

he Norwegian flag has been planted inthe oil sands of northern Alberta, withStatoil making a bid to acquire high-flying North American Oil Sands for

C$2.2 billion.Statoil, which is due to complete a merg-

er with domestic rival Norsk Hydro later thisyear, has consistently been high on the list ofprospective oil sands acquisitors.

Backed by its experience as a 15 percentstakeholder in Venezuela’s Sincor heavy oilventure, Statoil said it plans to spend up toUS$15 billion on the Alberta leases to pro-duce about 200,000 barrels per day of bitu-men by 2020.

Privately held North American operates257,000 acres of oil sands leases in theAthabasca region of northeastern Alberta,with estimated recoverable reserves of 2.2billion barrel.

Formed in 2001, North American hasmade one of the boldest entries into the oilsands, surfacing two years ago with plans toinvest C$12 billion on a 220,000 bpd pro-duction facility and a 160,000 bpd upgrader,setting a target date of 2015 for completionof both facilities.

If the Statoil deal is concluded as sched-uled in June, it is not clear what modifica-tions might be made to those projects ortheir timing.

North American is 50 percent owned byParamount Resources, which exchanged aninterest in oil sands assets for a share ofNorth American’s upstream action. Theother key shareholders are the OntarioTeachers’ Pension Plan Board and fundsmanaged by affiliates of ARC. Those threecontrol 69 percent of North American.

In short order, North American has raisedmore than C$600 million in a series of pri-vate placements and, before the Statoil deal,was eying regulatory filings by mid-2007for an initial public offering.

In addition to its C$7.5 billion Kais KosDehseh operation to develop the Athabascaleases, using steam-assisted gravity drainage

technology, it has been working on a C$4.5billion facility near Edmonton to upgradebitumen into synthetic crude.

Application before regulatorsA regulatory application is before the

Alberta Energy and Utilities Board andAlberta Environment for a 10,000 bpddemonstration upstream project to make itsdebut by late 2009, growing by 70,000 bpdby late 2011, then another 140,000 bpd bylate 2015.

The upgrader is scheduled to start pro-cessing 70,000 bpd in 2011 and reach160,000 bpd in 2014.

Statoil has calculated operating costs atUS$10 per barrel for the upstream portion

PETROLEUM NEWS • WEEK OF MAY 6, 2007 5

● F I N A N C E & E C O N O M Y

Statoil puts footprintin Alberta oil sands Norwegian oil giant drawn by ‘long-term’ barrels in pouncing onprivately held company with plans for bitumen production, upgrading

T

see STATOIL page 6

● N A T U R A L G A S

AOGCC schedules Rule 9 hearingFebruary public meeting summarized Prudhoe Bay gas offtake study; staff recommended depletion planning prior to gas sales

Fsee HEARING page 6

6 PETROLEUM NEWS • WEEK OF MAY 6, 2007

and US$4 per barrel to upgrade the bitumento synthetic crude. Those costs include buy-ing natural gas for steam and processingneeds.

Chief Financial Officer Eldar Saetrebelieves the undertaking can break evenwith oil prices at US$40 per barrel, whichhas prompted Statoil to consider taking aneven larger stake in the oil sands.

North American has won friends in theAlberta government by keeping its value-added upgrading operations within theprovince at a time when other majors havebeen looking to establish partnerships or buyrefining assets in the U.S.

Company Senior Marketing VicePresident Michael Langley has toldinvestors a domestic upgrader is an “essen-

tial element” of North American’s strategybecause it mitigates the price volatility ofbitumen, reduces transportation costs andrisks and provides alternatives fuels forsteam-assisted bitumen extraction, whichrelies heavily on natural gas.

Statoil world’s third-largestnet seller of crude

Statoil was formed in 1972 and is theworld’s third-largest net seller of crude oilafter Saudi Aramco and National IranianOil, with an average traded volume of 2.1million bpd.

It posted revenues from its integratedoperations of US$80 billion last year and hasestimated reserves of 4.185 billion barrels ofoil equivalent.

Statoil Chief Executive Officer HelgeLund said the North American acquisition isan “important strategic move which sup-ports our global growth ambition and

increases our reserve bookings in the longterm.”

Peder Sortland, Statoil’s senior vice pres-ident for non-conventional oils, said the“long-term” barrels in the oil sands pro-pelled the deal.

Looking beyond 2015, “we want to buildfurther in the North American energy marketand add on to our heavy oil portfolio,” hesaid.

North American: money needed for development

North American Chief ExecutiveOfficer Pat Carlson said his companystarted talks with Statoil and other largeinternational players as it exploredfinancing options for its project.

“A small company like ours needsmoney and Statoil has more financialcapacity than us to develop the oil sandsassets,” he said.

Carlson said the two companies’visions for oil sands development becameeven more strongly aligned on the issueof curbing the environmental impact ofthe Alberta resource, which is thought togenerate two to three times the green-house gases of conventional oil opera-tions.

Lund said the carbon dioxide footprintat the oil sands is “considerably higher”than Statoil’s North Sea fields.

But Statoil, through its carbon seques-tration offshore Norway, is in the “fore-front of the industry in this area.”

The Norwegian company has beenundertaking trail-blazing work in carboncapture including at fields in the NorthSea, Barents Sea and Algeria.

The company estimates those threeundertakings will see 2.9 million metrictons of carbon dioxide stored under-ground annually. ●

continued from page 5

STATOIL

produced in the meantime and what mitiga-tion measures are planned, such as injectionof water into the gas cap to fill voidage — apilot is under way now — and CO2 injec-tion.

In general, he told the committee, thelater gas sales begin the smaller the loss inoil production will be.But if gas sales aredelayed too longthere could be someloss in overall hydro-carbon productiondepending on the lifeof North Slope infra-structure.

Prudhoe Bay hasproduced some 11billion barrels,Norman said. But theremaining oil atPrudhoe, some 2 bil-lion barrels, if discov-ered today, would bethe sixth largest fieldever discovered in theUnited States. Thereis a lot of oil remain-ing, he said, and it’svery important thatattention not be wholly diverted to gas.

Norman said the thing that’s been mostdisappointing about Prudhoe Bay produc-tion is the interruptions. You may still beable to produce that oil, he said, but it’s at thetail end of field life years away and at thatpoint the tradeoff between oil and gas ismore acute.

He said the commission wants attentiongiven to aging infrastructure and mainte-

nance — things that could cause interrup-tions in production — and said that interrup-tions would be scrutinized when the com-mission receives an application for anincreased gas offtake rate. When an applica-tion comes in, the commission will askabout acceleration of production and pre-vention of downtime, he said.

Point Thomson study hasn’t begunNorman said the commission needs

about six months to conclude its work on anew Prudhoe Bay gas offtake rate.

Commissioner Cathy Foerster told thecommittee that the commission would need18 months at a minimum to complete aPoint Thomson gas offtake study — and thatwould be from the time it had access toPoint Thomson data.

That hasn’t happened yet (see story inApril 22 issue of Petroleum News).

The commission reached an agreementwith ExxonMobil and the other PointThomson working interest owners to do astudy but then the Department of NaturalResources found the Point Thomson unit indefault and Exxon put the study on hold.

Norman told the committee he has writ-ten to Exxon asking for their position on thestudy and said the commission’s desire is tocontinue an informational exchange whilethe legal issues at Point Thomson play out.

The situation has been on-off-on-off overthe last months, Forester said, and if Exxonputs it in writing that they’ve stopped thestudy process then the commission can pro-ceed differently.

The commission has subpoena powers togo after information, but Norman said itwould cost in the millions if it tried to do agas offtake study for Point Thomson on itsown, rather than in a cooperative study withthe working interest owners at the field. ●

continued from page 5

HEARING

JOHN NORMAN

CATHY FOERSTER

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FINANCE & ECONOMYOil prices up following attack in Nigeria

Oil prices edged up May 1 after gunmen in oil-rich Nigeria kidnapped six foreignoil workers and killed a Nigerian sailor on a Chevron Corp. ship.

“This incident has once again highlighted the instability in the region, with the coun-try’s output still below full capacity and the most recent presidential elections have onlymade the situation worse,” said Michael Davies, an analyst at Sucden in London.

A spokesman for California-based Chevron told Dow Jones Newswires that it hadshut down 15,000 barrels a day of oil production because of the attack. The spokesmansaid four Italians, one American and one Croatian were abducted. Italy’s ForeignMinistry also said four Italian technicians were among the kidnapped.

In a separate incident, gunmen seized the mother of the newly elected governor ofneighboring Rivers state, police said.

Light, sweet crude for June delivery on the New York Mercantile Exchange rose apenny to $65.72 a barrel in electronic trading by midday in Europe. On April 30, pricesfell 75 cents a barrel.

Brent crude for June on London’s ICE Futures exchange rose 13 cents to $67.78 abarrel.

Heating oil futures rose 0.14 cent to $1.8962 a gallon on the Nymex, while naturalgas fell 4.8 cents to $7.815 per 1,000 cubic feet.

U.S. refinery problemsAnalysts attributed some of the April 30 decline in oil prices to profit-taking from

April 27’s big rally, when crude surged above $66 a barrel after Saudi Arabiaannounced the arrests of 172 Islamic militants, some of whom allegedly planned toattack oil fields.

Gasoline prices rose April 30 on reports of another series of U.S. refinery prob-lems. Gasoline inventories have fallen for 11 weeks in a row. Last week’s U.S. EnergyDepartment report showed an unexpected drop of 2.8 million barrels in U.S. gasolinestockpiles and said U.S. refinery use declined to 87.8 percent of capacity.

With the start of the summer driving season about a month away, some analystswonder whether gasoline supplies will be adequate to meet demand.

“Although recent refinery runs have been on the low side, the real problem maynot be a spike in unplanned plant outages, of which there is no compelling evidence,but rather the failure of U.S. refining capacity to keep up with consumption growth,”said Antoine Halff, an analyst at Fimat. “As a result, U.S. dependency on gasolineimports has shot up, at a time when the latter’s availability has itself come under pres-sure.”

—THE ASSOCIATED PRESS

PETROLEUM NEWS • WEEK OF MAY 6, 2007 7

● N A T U R A L G A S

Arctic delays raise need for LNGTransCanada's CEO Hal Kvisle hasn't given up on Mackenzie gas pipeline project, but says whethergas comes on stream in 2010 or 2020 ‘is not critical,’ Tristone Capital study offers solutions

By GARY PARKFor Petroleum News

elays in moving natural gas pipelines from the NorthSlope and Mackenzie Delta through political, regulatoryand corporate hoops have reinforced for TransCanadaChief Executive Officer Hal Kvisle the urgency of bring-

ing liquefied natural gas into North America.And that puts Russian LNG supplies at the top of Kvisle’s

shopping list, regardless of the unpredictable and uncertainatmosphere in Russia.

For now, developing North America’s Arctic gas resources isa distant prospect that, coupled with Canada’s new greenhousegas regulations, means the continent will“need LNG sooner rather than later andfailure to get it will lead to a lot of discom-fort,” Kvisle told analysts in a conferencecall.

He said the Mackenzie Gas Project is “areally long-term initiative” that is provingan “enormously challenging project as itcontinues to move slowly through the reg-ulatory process.”

Although TransCanada, which has cov-ered the Aboriginal Pipeline Group’s pre-construction costs through a loan andstands to lose as much as C$115 million if the project folds, has“not given up hope on the Mackenzie. … It’s still important toTransCanada over the longer term that gas comes on stream andinto our system, but whether it comes on in 2010 or 2020 is notcritical.”

Kvisle, who has issued some of the most frequent warningsabout the consequences of slow progress, said there is no easysolution to the problems confronting the Mackenzie Gas Project,dominated by the time-consuming regulatory phase and therapid rise in overall costs to C$16.2 billion, against a backdropof uncertain natural gas prices.

He said the pipeline proponents have already invested a com-bined C$600 million to get the project to its current stage.

Tristone: Mackenzie uneconomicKvisle’s comments came on the heels of the latest assessment

by Tristone Capital which said the current proposal is uneco-nomic under the current fiscal regime, suggesting federal gov-ernment intervention is needed.

It listed options to improve the economics including: • Legislation enabling the National Energy Board to regulate

access, tolls and tariffs on the gas-gathering system to add gasfrom the Mackenzie Explorer Group to the Mackenzie Valleypipeline volumes and boost startup capacity in 2015 to 1.2 bil-lion cubic feet per day from the 960 million cubic feet per day

from the anchor fields;• An accelerated capital cost allowance tied to the 15-year life

of the gas fields rather than the 30-year physical life of thepipeline; and

• A loan guarantee along the lines of that available for the pro-posed Alaska gas pipeline, allowing producers to increase theirdebt-equity ratio from the assumed 70-30 split, lowering the costof service and the toll. The study estimates that incorporating thegas-gathering system into the rate base would result in a com-bined toll of US$3.14 per thousand cubic feet.

• Municipal, territorial and federal governments, acting indi-vidually or collectively, could issue bonds to fund regional infra-structure such as roads, airstrips and barge landings. The issuerof the bonds would then charge a toll to those using the facili-ties.

Lack of fiscal terms could delay project 15 yearsCo-author Chris Theal suggested the failure of the industry

partners and the federal government to settle on fiscal termscould delay the project by as much as 15 years.

“Under the current fiscal regime, there is no economicincentive to build the Mackenzie Valley pipeline,” Theal said.

Based on Imperial Oil’s updated budget of C$18 billion,including C$1.77 billion allowance for funds used during con-struction, the study said the revised budget requires gas pricesof US$5.78 per million British thermal units to achieve abreak-even level in developing 6.1 trillion cubic feet of gasreserves in the Mackenzie Delta anchor fields.

Theal said that made the Mackenzie project 8.4 percentmore expensive than importing LNG.

Kvisle said he “doubted this project would go” with gasprices at $5 or $6 per million Btu.

However, he gave “full marks to the Mackenzie” partners,suggesting “other companies might have given up a long timeago.”

But TransCanada has made it clear it has other majorundertakings that command its attention, including its fast-moving Keystone oil sands pipeline to deliver 435,000 bpdfrom Western Canada to Cushing, Okla., where it could con-tinue on to the Gulf Coast.

Kvisle said his company is open to buying an existingpipeline to take Keystone as far as the Gulf.

He also said building a nuclear power plant in WesternCanada could be an option for meeting long-term electricitydemand in the region.

“Does it make sense?” he asked. “Well, we have very largecoal reserves (in Alberta) so you would have to weigh themerits of power generation from a nuclear source versus elec-tric power generation from a coal source.”

TransCanada is already a partner in North America’slargest nuclear complex on the shores of Lake Huron inOntario. ●

“Under the current fiscal regime, there is noeconomic incentive to build the Mackenzie Valley

pipeline.” —Tristone study co-author Chris ThealD

FINANCEBow Valley sellsCanada assets

Bow Valley Energy Ltd. has sold itsCanadian assets for C$74.25 million toan unnamed buyer, the company saidApril 30.

“The Canadian operations providedstrong production and cash flow growthin the company’s early development butthese assets now represent less than 15percent of the company’s total provedplus probable reserves. With the signifi-cant growth of Bow Valley’s internation-al operations, the Canadian asset was nolonger strategic in our business plan. Thenet proceeds generated from the sale ofthe Canadian assets are intended to fundfuture growth opportunities in BowValley’s core operating areas of the U.K.North Sea and the North Slope ofAlaska, both of which offer superioreconomic returns when compared toCanada,” said R.G. Moffat, Bow Valleypresident and CEO.

The Canadian holdings were concen-trated in natural gas exploration anddevelopment acreage in a corridorextending from west central Alberta,through the Peace River Arch area andinto northeastern British Columbia.Proved plus probable reserves for theCanadian fields totaled 3.8 million bar-rels of oil equivalent, with production of660,000 barrels of oil equivalent lastyear.

After a strategic review, Bow Valleydecided to concentrate on its core areason Alaska’s North Slope and in theNorth Sea. It has 13.3 million barrels ofproved plus probably oil equivalent inthe North Sea. It has no reserves bookedin Alaska so far.

On the North Slope, Bow Valley par-ticipated in two wells drilled this pastwinter by BRPC Group. North ShoreNo. 1 was drilled from onshore to a tar-get under the Kuparuk River delta andencountered about 70 feet of oil pay inthe Ivishak sandstone. The ventureobtained 3-D seismic data for the area ofthe discovery and has cased the well as apotential producer. Another well, SagRiver No. 1, found no hydrocarbons andwas suspended for evaluation of a possi-ble sidetrack next winter.

Proceeds of the Canadian sale will beused to retire Canadian debt of around$26.6 million and to finance othergrowth opportunities, the company said.

—ALLEN BAKER

TransCanada ChiefExecutive OfficerHal Kvisle.

Co-author Chris Theal suggested the failure of theindustry partners and the federal government to

settle on fiscal terms could delay the project by asmuch as 15 years.

8 PETROLEUM NEWS • WEEK OF MAY 6, 2007

● F I N A N C E & E C O N O M Y

Alaska revenue outlook offers mixed bagState spring forecast calls for slow decline in oil prices, short-term increase in production and temporarily higher unrestricted revenue

By ROSE RAGSDALEFor Petroleum News

dhering to its trademark caution, the AlaskaDepartment of Revenue has projected a drop inAlaska North Slope oil prices and a modest jump inANS crude production for the coming year.

In a semi-annual forecast of Alaska’s revenue outlookreleased May 1, Revenue Commissioner Patrick Galvinsaid the state can expect to rake in nearly $5 billion inunrestricted revenue this year, up about 19 percent fromfiscal 2006. Oil revenues will account for some $4.3 bil-lion, or about 87 percent, of this discretionary portion ofthe state budget, he said.

“Despite production declines due to a series of pipelinecorrosion issues, revenues for fiscal 2007 are forecastedto increase primarily due to the increased production taxrevenues under the new Petroleum Profits Tax (PPT),”Galvin said in an April 30 cover letter to Gov. Sarah Palin.

The Revenue Department’s estimates show PPT rev-enues in FY 2007, which ends June 30, generating about$1 billion more for state coffers than would have collect-ed under the old economic limit factor or ELF system.

The trend, however, may be short-lived, according tostate economists.

They predict unrestricted revenues will decline in fis-cal 2008 due to lower oil prices, higher operating and cap-ital costs on the North Slope and unused tax creditsearned in FY 2007 applied against FY 2008 revenues.

The Department of Revenue publishes the RevenueSources Book twice a year, in the fall and spring. Theforecast is compiled by the Economics Research Groupwithin the department’s Division of Tax and Audit.

ANS crude prices to declineThe economists projected Alaska North Slope prices to

average $59.81 a barrel for FY2007, up 66 cents fromtheir November 2006 forecast of $59.15 a barrel. The fis-

cal year-to-date average is about $61 a barrel. “We believe there will be continued downward pres-

sure on oil prices, and our forecast for ANS crude pricesfor FY2008 is $54.72/bbl and for fiscal 2009 is$53.86/bbl, Galvin said. “Our long-run ANS crude oilprice forecast for 2014 and beyond is $41.03/bbl, increas-ing at the projected rate of inflation.”

Galvin acknowledged that the predicted prices arelower than current market prices and some expert predic-tions, but said the cautious approach is appropriate in fis-cal planning given the current pricing environment whereoil prices are high by historical standards.

Though oil prices may appear to be climbing everupward with no end in sight, Michael Williams, senioreconomist and head of Revenue’s research group, saysnothing could be farther from reality.

“It is basic market fundamentals. Long-term oil pricesare very cyclical. … If prices remain high for severalyears, there’s high likelihood you’ll change your habits,”and on the supply side, a lot of things become possiblesuch as more investment in developing unconventionalsources of crude such as heavy oil fields and using steamin the Canadian tar sands, according to Williams.

Likewise, when oil prices are low for a long time likein the 1990s, people go out and buy big SUVs and invest-ment in developing new sources of oil shrinks up, he saidin an interview May 2.

Over time, the effects of higher or lower oil prices fil-ter their way all through society. However, in the pastthree decades, the world has gotten a lot more efficient in

its use of energy, according to Williams.“This time around, efficiencies of economies world-

wide have improved, which means that it will likely takelonger for the effects of high oil prices to be felt,” heexplained. “Oil prices probably will have to go higherbefore you get the long-term impacts. It would affect thedevelopment of other fuels. When organizations are prof-itable, they can experiment more. But we see it coming toa head.”

Still, it’s difficult to predict exactly when prices willcome down.

“It’s not an exact science, but it is based on sound eco-nomic ideas,” he said.

Natural gas outlook uncertainRevenue economists also included a projection for nat-

ural gas prices in the forecast this spring, though Alaskacurrently produces no natural gas for sale on the NorthSlope.

“Our forecast for natural gas prices at the Henry Hubfor FY2007 is $6.64 per million Btu,” Galvin said.

The forecast reflects the extreme volatility that naturalgas prices exhibited during the past 18 months, plummet-ing 76 percent from $15.39 per million Btu in December2005 to $3.66 per million Btu in September 2006. SinceSeptember, prices have more than doubled, closing at$7.93 per million Btu April 13.

Williams said the research group started following nat-ural gas prices about two years ago in an effort to fullyunderstand the market fundamentals if and when anAlaska gas pipeline is developed.

Unlike oil markets, which have existed in the UnitedStates for at least 140 years and worldwide for decades,Williams said natural gas markets are a recent U.S. phe-nomenon and do not even exist overseas where naturalgas is sold using contracts between two parties.

He said deregulation of natural gas was begun in the

“It is basic market fundamentals. Long-termoil prices are very cyclical. … If prices remainhigh for several years, there’s high likelihood

you’ll change your habits.” —Michael Williams, senior economist and head of Revenue’s

research group

A

see OUTLOOK page 9

PETROLEUM NEWS • WEEK OF MAY 6, 2007 9

1970s and only completed in 1996. Sincethen the markets have sought their footingat a time of unusual weather events,including Hurricane Katrina.

“Looking forward, there is great uncer-tainty in the markets,” he said.

Large users of natural gas, such as util-ities, have the option of converting tomuch cheaper, but environmentally chal-

lenging coal. While coal supplies are plen-tiful, equipping plants to burn it withoutgiving off harmful emissions is an expen-sive proposition, Williams said.

At some point coal may become cheap-er and more reliable than natural gas evenwith the cost of the conversion, he said.

One thing that would help stabilizeU.S. gas markets is a clear signal that anAlaska natural gas pipeline is really in theworks, he added.

Rollercoaster ride for crude outputOn the production side, the outlook also

is mixed. ANS oil production is expected toaverage 740,000 barrels per day inFY2007, down from the economists’ fall2006 forecast due to pipeline corrosionproblems at the Prudhoe Bay, Lisburne andMilne Point fields.

ANS output is projected to climb slight-ly in FY2008 to average 764,000 bpd,assuming no major pipeline shutdowns andthe Oooguruk field comes on line during

the year as predicted with about 3,000 bpdof new production, according to Galvin.

Additional small increments of outputfrom Nikaitchuq, satellite fields in Alpine,and small pools in the National PetroleumReserve-Alaska along with contributionsfrom heavy oil accumulations are projectedto gradually boost ANS output to about807,000 bpd in 2012 before a slow declineresumes until a bump in 2017 when outputfrom the Point Thomson field is projectedto come on line, Williams said. ●

continued from page 8

OUTLOOK

By GARY PARKFor Petroleum News

hey have a lot in common — a struggleto attract new investment at a timewhen drilling success has been sparseand exploration licenses are being

abandoned. But that’s about where they part compa-

ny.In their efforts to revive offshore activity

they are taking different routes.Newfoundland is characterized by the

bluster of PremierDanny Williams, whohas threatened toimpose “use-it-or-lose-it” legislation onholders of explorationpermits and signifi-cant discovery licens-es.

Meanwhile, NovaScotia has quietlygone about overhaul-ing the terms and con-ditions of its licenses,ending up with apackage of changesthat offer incentiveswhile applying pres-sure to the industry.

Using a carrot-and-stick approach, it hasintroduced a new licensing system to reversea succession of dry holes, lapsed licensesand a sharp decline in drilling over recentyears.

The changes were announced April 19by Diana Dalton, chair of the Canada-NovaScotia Offshore Petroleum Board — a jointagency of the Canadian and Nova Scotiagovernments that manages the offshore —following a detailed comparison of theprovince’s regime against those of theBritish and Norwegian North Seas, Gulf ofMexico, Australia, New Zealand andGreenland.

Basin’s complex geology biggest hurdle

Viewing the basin’s complex geology asits biggest hurdle, the CNSOPB is “creatinga world-class digital data management facil-

ity, the first of its kind in Canada,” Daltonsaid.

The internet-based system will providenon-confidential digital well and seismicdata when it opens in October and couldeventually be linked to other regulatoryagencies and government departmentsacross Canada, she said.

That is just one aspect of a strategy toattract “the adventurers, the people who findoil and gas” and that isn’t always the majorssuch as ExxonMobil and Chevron, Daltonsaid.

The review of other offshore regimesproduced one glaring result — Nova Scotiais “virtually the only jurisdiction in theworld where a company can sit on explo-ration and development rights indefinitely,”she said.

“From this point on … any new explo-ration license … will contain certain provi-sions to ensure future significant discoverylicenses … will include terms and condi-tions intended to encourage explorationcompanies to get on with (development) anddiscourage land-banking.”

The CNSOPB is now offering newexploration licenses with initial terms of twoto three years.

Instead of being based on a percentage ofwork commitments made in bidding rounds,which can run to millions of dollars, NovaScotia will require deposits that could seecompanies “get in and out of the preliminaryexploration phase for as little asC$100,000,” Dalton said.

If license holders decide they want topursue further work, the permit can beextended to a maximum of nine years, ascontained in the existing rules.

But if those companies decide not tomove forward, others will be allowed to take

up the license and the CNSOPB will “beable to hold all of the data for public disclo-sure.”

Dalton said the objective is to attract “theadventurers, the people who find oil andgas” and not just the majors, such asExxonMobil and Chevron, who often buy inafter discoveries are made.

She told reporters that the regulatorwants to encourage companies “who believein our offshore, who know there is potentialthere and will come here to work.”

Other changes could include approval ofnew technology, such as slim-hole drilling,to help reduce costs, while terms and condi-tions could vary based on water depth, rigavailability and the maturity of the basin. Inaddition the changes will allow a 5 percentallowable expenditure for research anddevelopment.

Dalton said allowable expenditures willnow be based on actual annual costs as con-firmed by a third-party audit.

Agency will take more pro-active roleThe CNSOPB is also going to take a

more pro-active role by evaluating the datait has on “areas we believe have real poten-tial for oil and gas” and assemble packagesfor future bidding rounds, rather than relyingexclusively on the industry for nominations,she said.

Like Newfoundland, the NorthwestTerritories and Nunavut, Nova Scotia istroubled by the open-ended nature of its sig-nificant discovery licenses, which areawarded on the basis of proof that discover-ies can support sustained production.

In the future the new exploration licenseswill “encourage exploration companies(holding significant discovery licenses) toget on with (development) and discourageland-banking,” she said.

To that end the CNSOPB is contemplat-ing escalating rentals, the details of whichmay be announced later this year.

“We are involved in a global industry,”Dalton said. “Others have more experienceand we feel as though we’ve been on thesidelines. But this is changing.”

So far, offshore Nova Scotia has loggedonly about 200 wells (137 of them explo-ration), compared with 20,000 in the NorthSea and 50,000 in the Gulf of Mexico.

Industry spokesman welcomed theprospect of greater flexibility, especiallyindications from Dalton that the red tapecomplained about by exploration compa-nies will get some attention, but they cau-tioned against expecting any quick results.

Nova Scotia Energy Minister Bill Dooksand Barry Cloutier, chairman of theOffshore/Onshore TechnologiesAssociation of Nova Scotia, both held outhope that the strongest response is likely tocome from smaller companies, enticed bythe lower front-end costs.

Whether Newfoundland sees merit inthe Nova Scotia approach, or takes atougher line should be known later this yearwhen it unveils changes to its own offshoreregime. ●

10 PETROLEUM NEWS • WEEK OF MAY 6, 2007

● G O V E R N M E N T

Nova Scotia makes low-key changesRevises license regulations to stop companies from sitting ‘indefinitely’ on exploration anddevelopment rights; lowers front-end deposits to attract ‘adventurers’

T

Newfoundland ischaracterized by thebluster of PremierDanny Williams,who has threatenedto impose “use-it-or-lose-it” legislationon holders of explo-ration permits andsignificant discoverylicenses.

In the future the new explorationlicenses will “encourage

exploration companies (holdingsignificant discovery licenses) toget on with (development) and

discourage land-banking.” —Diana Dalton, chair, Canada-Nova Scotia

Offshore Petroleum Board

Like Newfoundland, the NorthwestTerritories and Nunavut, NovaScotia is troubled by the open-

ended nature of their significantdiscovery licenses, which are

awarded on the basis of proof thatdiscoveries can support sustained

production.

By KRISTEN NELSONPetroleum News

riven by a shutdown at GatheringCenter 2 at Prudhoe Bay, AlaskaNorth Slope production averaged757,181 barrels per day in April,

down 0.9 percent from a March average of764,273.

The BP-operated Prudhoe Bay field hadthe largest month-to-month productiondrop, down 7.6 percent, averaging 316,846bpd in April compared to 343,060 bpd inMarch. Prudhoe Bay production includeswestern satellites Midnight Sun, Aurora,Polaris, Borealis and Orion.

The Anchorage Daily News reportedthat North Slope output was down some90,000 bpd on April 25, following an April23 accident when a side-boom crane hit anelectric power line, shutting down GC-2.The plant had already been partially shutdown April 21-22 for maintenance andafter the accident BP told the Daily News itkept the plant idled to perform other main-tenance, rather than doing a partial restart.Full oil production was not expected to berestored until near the end of the month.

Production figures for Prudhoe Bayshow a drop from 332,494 bpd on April 23to 287,851 bpd April 24 and to 236,152bpd April 25. The rate then began toincrease slowly, reaching 286,355 bpdApril 29 and 327,783 bpd April 30.

BP spokesman Steve Rinehart toldPetroleum News May 3 that GC-2 cameback on April 29 with full production ofabout 90,000 bpd. He said BP “took advan-tage of the downtime to accomplish main-tenance that had been scheduled for thenear future.”

Greater Prudhoe Bay includes Endicottand Lisburne production, and the com-bined rate from the three was 369,995 bpdin April, down 6.2 percent from a Marchaverage of 394,430 bpd.

Kuparuk production also downProduction from the ConocoPhillips

Alaska-operated Kuparuk field was down3.3 percent, averaging 163,150 bpd inApril compared to 168,632 bpd in March.Kuparuk production includes West Sak,Tabasco, Tarn, Meltwater and Palm.

BP-operated Endicott was down 2.1percent, averaging 49,670 bpd in Aprilcompared to 50,750 bpd in March.Endicott production currently includessome 33,000 bpd of Prudhoe Bay FlowStation 2 oil. Satellites producing throughEndicott include Sag Delta, Eider andBadami.

Northstar, Milne Point, Lisburne, Alpine all up from March

The BP-operated Northstar field aver-

aged 45,661 bpd in April, up 38 percentfrom a March average of 33,043 bpd.Northstar was offline for gas pipelinereplacement beginning in mid-February

and came back online in early March, so afull month of production in April is beingcompared to about three-quarters of amonth in March.

BP’s Milne Point field averaged 32,023bpd in April, up 16.3 percent from a Marchaverage of 27,540 bpd. Milne Point pro-duction includes Schrader Bluff. TheDepartment of Revenue’s Tax Divisionreported that the Milne Point plant wasshutdown April 9, with output reduced byabout 12,000 barrels.

Production from the BP-operatedLisburne field, including Point McIntyreand Niakuk, averaged 20,149 bpd in April,up 9.7 percent from an average of 18,370bpd in March.

Production from the ConocoPhillips-operated Alpine field averaged 129,682bpd in April, up 5.5 percent from a Marchaverage of 122,878 bpd. Alpine includestwo satellites, Fiord and Nanuq.

The temperature at Pump Station No. 1on the North Slope averaged 12.1 degreesFahrenheit in April, compared to minus17.5 degrees F in March.

Cook Inlet crude production averaged15,550 bpd in April, down 1.4 percent froma March average of 15,773 bpd. ●

PETROLEUM NEWS • WEEK OF MAY 6, 2007 11

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

ANS production drops 1 percent in April

D

The trans-Alaska oil pipeline

JUD

Y P

ATR

ICK

By KRISTEN NELSONPetroleum News

ight outer continental shelf Alaskalease sales are included in the pro-posed five-year schedule releasedApril 30 by the U.S. Department of

the Interior. Congress has 60 days to reviewthe program, Interior Secretary DirkKempthorne said in a press briefing, and inthe absence of any action he is authorized toapprove the program. The current five-yearprogram ends June 30; the new programwould begin July 1.

Proposed lease sales in Alaska include:three Chukchi Sea sales (2008, 2010 and2012); two Beaufort Sea sales (2009 and2011); two Cook Inlet sales which would beheld only if there is industry interest (2009and 2011); and a North Aleutian basin sale(2011).

Estimated resources in the areas used inthe environmental impact statement for thesale are 1 billion barrels of oil each in theBeaufort Sea and Chukchi Sea sale areas;200 million barrels of oil each in the CookInlet and North Aleutian basin sale areas;and 200 billion cubic feet of gas in the CookInlet sales area and 5 trillion cubic feet ofnatural gas in the North Aleutian basin area.

MMS does not list natural gas resourcesfor either the Beaufort or Chukchi seas saleareas. The agency said that in frontier areasinfrastructure constraints may substantiallyreduce anticipated production in a foresee-able timeframe. It said the 2006 nationalassessment reported mean undiscoveredtechnically recoverable natural gasresources of 76.77 trillion cubic feet for theChukchi Sea province and potentially eco-nomically recoverable resources of 7.91 tcfat $6.69 per thousand cubic feet. No pro-duction is projected for the Chukchi“because there is no transportation systemto carry the gas production to outside mar-kets and it is unlikely that a pipeline systemwill be operational and have capacity totransport large volumes of Chukchi gasuntil at least 2025.”

“It is possible that construction of gastransportation systems from northernAlaska will be delayed even longer.Therefore, the gas resources in Arctic OCS

areas are considered ‘stranded’ for the fore-seeable future.”

The agency also said the estimates are“not precise predictions” especially “in off-shore areas that do not have a history ofOCS activity, such as much of offshoreAlaska and Virginia. Here our EIS esti-mates are more speculative than in provenoil and gas areas such as the Gulf ofMexico.”

37 million acres in Alaska not currently offered

Kempthorne said that the entire sale planincludes nearly 180 million acres. “Ofthese, more than 48 million acres are notcurrently offered” including more than 8million acres in the Gulf of Mexico and“more than 37 million acres offshoreAlaska of which more than 5 million are inthe North Aleutian basin, an area that hasnot been offered for more than 20 years.”

The agency’s 2006 scoping report for theChukchi described the area as some 34 mil-lion acres, excluding a 15- to 50-mile-widecorridor along the coast, so the consistent25-mile buffer in the proposed programpresumably accounts for the reduction to 32million acres in the Chukchi offering.

Kempthorne said the proposed five-yearprogram “sets aside migration corridors forthe bowhead whale that are vital to the sub-sistence whalers in Alaska.” In the Chukchiplanning area, the proposed final programremoves from leasing consideration a 25-

mile buffer area from the coast. MMS saidthat reflects the secretary’s intention thatthere be no leasing within 25 miles of thecoastline where there is no existing oil andgas activity unless the adjacent staterequests that the area be offered.

MMS said in 2005 that it was movingforward with an OCS leasing process forthe Chukchi because it received broaderinterest in the area than expected. TheChukchi Sea/Hope basin was included inthe 2002-07 five-year plan as a specialinterest lease sale. The agency received noindication of interest in the areas in 2003 orin 2004, but in response to a 2005 call forinterest, MMS said “industry nominated asubstantial portion” of the Chukchi Seaplanning area, greater than that envisionedin a special interest lease sale option.

In September 2005 MMS said it wouldprepare an areawide EIS for the Chukchi,but indicated that EIS would not be com-pleted in time for the sale to be held in thecurrent five-year program, which expiresJune 30.

In response to the draft of the currentplan, MMS received expressions of interestfrom 15 companies in the Chukchi Sea, 15in the Beaufort Sea, 14 in the NorthAleutian basin and six in Cook Inlet.

Nationwide, the highest level of inter-est for a specific planning area was 19companies for the Eastern Gulf ofMexico. ●

12 PETROLEUM NEWS • WEEK OF MAY 6, 2007

● L A N D & L E A S I N G

Chukchi, North Aleutian sales proposedInterior releases five-year OCS leasing plan, 2007-12, with as many as 37 million acres newly available for lease off Alaska

In response to the draft of thecurrent plan, MMS received

expressions of interest from 15companies in the Chukchi Sea, 15

in the Beaufort Sea, 14 in theNorth Aleutian basin and six in

Cook Inlet.

E

By KRISTEN NELSONPetroleum News

n amended proposal to change thepetroleum profits tax, or PPT, to pre-vent companies from deducting costsdue to improper maintenance is mov-

ing in both House and Senate. Senate Resources amended Senate Bill

80 April 27 and moved it out of committee;it goes next to Senate Finance.

On the House side, the bill had passedOil and Gas and been heard and assigned toa subcommittee in Resources. At a May 1meeting that subcommittee heard amend-ments and forwarded the bill back to thecommittee with recommendations frommembers.

The amendments adopted in SenateResources deleted a reference to standardpractice of the industry and replaced it withgood oilfield practice, made technical clari-fications and substituted the newly author-ized Petroleum Systems Integrity Office inthe Department of Natural Resources’Division of Oil and Gas for the Alaska Oiland Gas Conservation Commission as oneof the agencies the commissioner ofRevenue could consult in making a deter-mination of costs that would not be allowed.

John Norman, chair of the AOGCC, toldSenate Resources that AOGCC is one of thedesignated agencies that are part of thePSIO working group and said he thoughtthe PSIO would be the most efficient typeof coordinating lead agency.

Safety, prevention of waste, primary concerns

Senate Resources had a long conversa-tion with Norman about one provision inthe bill which would have added to costswhich couldn’t be deducted any “incurredto maintain the operational capability offacilities or equipment shut down becauseof a lack of or improper maintenance ofproperty or equipment” and finally deletedthat provision of the bill.

Norman said he shared the frustration allAlaskans felt over recent events but he saidhe was thinking ahead of a new operatorcoming into Alaska in a new basin and try-ing to figure out how taxes work in the state.He said the proposal was rather novel in hisexperience based on the relationships thatexist between the companies. Partnersaren’t responsible for sharing costs in casesof willful negligence or gross negligence —

already on the PPT list of costs which can’tbe deducted as leasehold expenses.Similarly strict liability is covered in thelaw, he said: any costs related to spillcleanup can’t be deducted.

But ordinary negligence, the target of thebill, is a way of saying someone made amistake. There are often young Alaskansworking in the oil fields and mistakes canhappen, Norman told the committee.

He said oilfield safety and the preventionof waste should be our primary concerns,and the provision which says you can’tdeduct costs of a shutdown related to main-tenance included in the bill might provide acertain incentive to continue to operatewhen they otherwise might shut down. ●

PETROLEUM NEWS • WEEK OF MAY 6, 2007 13

● F I N A N C E & E C O N O M Y

PPT amendmentsamended; move on both sides

A

EXPLORATION & PRODUCTIONPioneer: ConocoPhillips NPR-A Noatak,Intrepid exploration wells ‘non-commercial’

In a May 3 announcement of its first quarter earnings, Pioneer Natural Resourcessaid it had participated in two wells in the National Petroleum Reserve-Alaska thiswinter that were “non-commercial.”

The company was referring to the ConocoPhillips-operated Noatak and Intrepidwildcats, the only two wells Pioneer was involved in during the northern Alaska win-ter drilling season that just ended.

Other than confirming with Conoco that the two wells were drilled in partnershipwith Pioneer, prior to going to press Petroleum News was not able to find out ifConoco’s other NPR-A partner, Anadarko Petroleum, was also involved in the twowells. Last fall, ConocoPhillips Alaska President Jim Bowles said Noatak probablydid “not (have) large reserve potential,” but if the well was successful “the resourcecould be tied back to Kuparuk or Alpine (Colville River unit) or maybe even GreaterMoose’s Tooth if that’s developed at some future date.”

Noatak is south of Teshekpuk Lake; Moose’s Tooth is between Noatak and Alpine,in the area 15-25 miles southwest of Alpine where ConocoPhillips announced dis-coveries in 2001 at Spark 1 and 1A, Moose’s Tooth C, Lookout 1 and Rendezvous Aand 2. All the wells targeted the Alpine producing zone.

The Intrepid well is south of Barrow, more than 200 miles from Alpine, which isthe closest infrastructure to the remote prospect. Although the main target was oil,Intrepid is south of the gas field that serves Barrow.

Bowles said the company would need to find large reserves for the Intrepidprospect to be deemed commercial because of its distance from infrastructure.

—KAY CASHMAN

By ALAN BAILEYPetroleum News

t’s been three years since an attempt todevelop coalbed methane resources inAlaska’s Matanuska-Susitna Boroughcollapsed amid an acrimonious argu-

ment involving the would-be developer,the local residents, the borough and thestate. But a new company, Fowler Oil &Gas Corp., believes that it has the answerto developing coalbed methane withoutthe concerns about land access and possi-ble pollution that plagued the previouseffort.

Fowler Oil and Gas CEO Bob Fowler,a graduate of Palmer High School andlongtime Alaskan, told Petroleum NewsMay 2 that he fully understands the con-cerns of the residents of the Matanuskaand Susitna valleys.

“Our family has been in the Valley forover 50 years and so I’m very familiarwith the issues up in the Valley and howpeople would like to see economic devel-opment but also coupled with environ-mental protection,” Fowler said.

Fowler Oil & Gas is a publicly tradedcompany founded in 2005 to pursue oiland gas opportunities in Alaska. Sistercompany, Native American EnergyGroup, is engaged in the development ofoil and other minerals in Montana.Fowler Oil & Gas shares technical staff,including geologists and operations man-agers, with Native American EnergyGroup.

On private landFowler Oil & Gas is pursuing 11 sep-

arate coalbed methane sites, all on pri-vate land, in Southcentral Alaska, Fowlersaid.

“We’re working with privatelandowners who own their own mineralrights,” Fowler said (part of the 2003-04controversy stemmed from requiredaccess to privately owned surface land todrill into state-owned subsurface).

The first of these sites, the Kircherunit in 840 acres of forest and farmlandat the corner of Bogard Road and TrunkRoad between Wasilla and Palmer, hasreached the permitting stage.Negotiations with landowners are still in

progress at the other sites. Fowler Oil &Gas has applied for permits from both theMatanuska Borough and the Alaska Oiland Gas Conservation Commission fordrilling and development at Kircher.

“We’d like to be drilling in mid-sum-mer to late summer,” Fowler said.

Production from Kircher would hookinto an Enstar Natural Gas Co. pipeline,Fowler said.

Horizontal drillingOne key element in Fowler Oil and

Gas’s approach to coalbed methanedevelopment is the use of horizontaldrilling technology. The drilling contrac-tor will drill a single vertical well to adepth of about 4,000 feet from a centrallocation in a coalbed methane unit.Perforated horizontal wells sidetrackedfrom that central well will then thread outperhaps 2,500 feet through each coalseam penetrated by the vertical well.

“With that one vertical well bore wemight have eventually 100,000 feet ofperforated pipe in the coal,” Fowler said.And the huge length of perforated pipewill eliminate the need to frac the coal tosustain adequate gas flows, he said.

The drilling technique effectivelyeliminates the need for a profusion ofsurface wellheads. It will also eliminatethe need to drill additional wells from thesurface when earlier wells run short ofgas.

“We’re draining 600 to 1,000 acres offof one well bore,” Fowler said.

Not only that. The specially designedcoalbed methane drill rig has a mast just60 feet high, but a capability of drillinglaterally out to about a mile, Fowler said.And once a coalbed methane site goesinto production, the wellhead productionfacilities will be hidden inside a single20-foot barn-like enclosure.

“They won’t even see that it’s a well,”

14 PETROLEUM NEWS • WEEK OF MAY 6, 2007

● N A T U R A L G A S

New approach toMat-Su Valley CBMFowler Oil & Gas plans horizontal drilling and patentedseparation technology to avoid environmental problems

I

Schematic diagram of the technique that Fowler Oil & Gas proposes to use for coalbedmethane production in Southcentral Alaska. Patented technology will separate water fromgas downhole, thus enabling the water to be disposed into a deep sandstone formation.

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see CBM page 15

“With that one vertical well borewe might have eventually 100,000

feet of perforated pipe in thecoal.”

—Fowler Oil and Gas CEO Bob Fowler

By KAY CASHMANPetroleum News

ioneer Natural Resources is planningto terminate the North Slope Cronusunit where it drilled the Cronus 1exploration well in the winter 2005-06

drilling season. “While the well penetrated oil bearing

sands, further analysis did not support eco-nomic viability of the prospect. The wellwas deemed unsuccessful as disclosed inthe second quarter 2006,” Sam Hicks, man-ager of corporate communications and pub-lic affairs for Pioneer, told Petroleum NewsApril 26.

Under the three-year plan of exploration

the company has with the state’s Division ofOil and Gas, the working interest ownerscan voluntarily terminate the unit and sur-render the leases before the end of the sec-ond year without further obligation to thestate. The second year ends Oct. 28.

Cronus is southwest of theConocoPhillips-operated Kuparuk Riverunit and west of the company’s Meltwaterfield.

Conoco was the operator of Cronuswhen the unit was approved in October2005, but transferred its interest to Pioneer,which was in the process of farming into theunit. (The leases were originally part of thelarger Southeast Delta exploration unit, dis-solved in 2003 when ConocoPhillips elect-

ed not to drill the Cronus well.)

Too tight to produceIn May 2006, Pioneer announced the

discovery of oil in Cronus 1.“A thick, oil-bearing sand section in the

Torok and a thin, oil-bearing sand in theJurassic-aged Kuparuk C were penetratedby the well,” the company said. “Wirelineand core data are currently being analyzedand integrated with 3-D seismic to deter-mine if appraisal activities are warrantedduring the 2006-2007 winter drilling sea-son.”

But in August the company said the

hydrocarbon bearing zones were too tight toproduce.

“After analyzing data from the well and3-D seismic, it was determined that thehydrocarbon bearing zones were too tight toproduce. Therefore, the well was declared adry hole and expensed in Q2,” SusanSpratlen, Pioneer’s vice president, corpo-rate communications and public affairs, toldPetroleum News Aug. 15.

Currently, Pioneer has a 90 percentworking interest in the two-lease 11,343-acre unit near Meltwater; Alaska VentureCapital Group has the remaining 10 per-cent. ●

Fowler said. “… We’re in and out on thedrilling in about one month.”

Fowler Oil & Gas plans to deliver gasto the Enstar transmission pipeline with-out any compression, thus eliminatingany possible compressor noise.

No surface waterPatented technology will eliminate the

water disposal problems that have oftenplagued coalbed methane production inthe past, Fowler said. This technologywill entail using the bottom part of thevertical well, below the level of the coalseams, to dispose the water into relative-ly deep sandstone formations. Thus, noproduced water will reach the surface orenter the water table.

“We have a downhole separator whichseparates the gas from the water,” Fowlersaid. “The gas flows up (the well). Thewater flows down into some specialpumps that pump it into lower sandstoneformations below the coal.”

Downhole monitoring equipment willensure that the disposed water meets statestandards, Fowler said.

To prevent contamination of any waterwells in the region around the productionsite, no coal beds less than 1,000 feetbelow the surface will be tapped. That

will ensure that all production occursbelow the depth of the water table,Fowler said. And sealed well casing,cemented to prevent water migrationaround the pipe, will also protect thewater table.

EPA approvedFowler said that the U.S.

Environmental Protection Agency hasapproved the downhole separation of gasand water and that the technique hasalready been permitted in Texas andKansas. And he said the drilling contractor,Scientific Drilling, has experience ofdrilling more than 3,000 coalbed methanewells, including horizontal wells.

Great Northern Engineering is design-ing the production facility, Fowler said.

But what are the chances of findingeconomic quantities of coalbed methane inthe Kircher unit?

“The Cook Inlet basin is a river of coalthat comes all the way down fromTalkeetna and up around Chickaloon, allthe way down to Homer, onshore and off-shore,” Fowler said. The coal is very thick;the seams are abundant and continuousthroughout the area; and the coal containslarge quantities of gas, he said.

And who might purchase the gas?“We’re talking to a number of buyers,”

Fowler said, adding that he would prefer tosee use of the gas in the Cook Inlet arearather than supplying the gas for export. ●

By KRISTEN NELSONPetroleum News

laska Gov. Sarah Palin is asking theLegislature for $5 million to fund acomprehensive assessment of thecondition of Alaska’s oil and gas

infrastructure. “For our new Petroleum Systems

Integrity Office to do an effective job, itmust have access to comprehensive, thor-ough and objective assessment data to tellus the status of the infrastructure andwhat it should be,” the governor said in aMay 1 statement. “No such system-widerisk assessment has ever been conductedof this complex system.”

Palin established PSIO April 18 byadministrative order. It is an independentoffice inside the Department of NaturalResources’ Division of Oil and Gas andwill coordinate the state’s permitting,

oversight and com-pliance functionswith other agencies.

PSIO requiresindustry to establishand maintain qualityassurance programsand requires thestate to inspect facil-ities to ensure opera-tors comply withthose programs.

The infrastructure assessment the gov-ernor announced May 1 will be done bythe Department of EnvironmentalConservation.

“Good management requires that weunderstand the current state of the infra-structure,” said DEC CommissionerLarry Hartig. “We need to know what’s ingood shape, what’s not and where andhow serious the risks are. A risk assess-

ment is a structured process designed toanswer those sorts of questions.”

Department of Natural ResourcesCommissioner Tom Irwin said: “Theassessment will provide a firm foundationfor PSIO’s work. This is a critical step infacilitating the protection not only of ourenvironment but of our economy.”

Assessment would take 2-3 yearsThe assessment is expected to take two

to three years to complete and would befunded by a one-time capital budget requestof $5 million.

Larry Dietrick, Director of the Divisionof Spill Prevention and Response at DEC,told Petroleum News that the first step “willbe a scoping process to determine specifi-cally what will be included in the assess-ment.” Where the assessment will start —in a particular location or with a specifictype of facility — will also be determined in

the scoping step, Dietrick said. After the scoping step, the risk assess-

ment “will be independently conducted by anationally recognized contractor,” he said.

Dietrick said that if the assessment isapproved by the Legislature the fundingwould be available July 1 and the initialwork would begin shortly thereafter.

In describing the reason for the assess-ment the governor’s office said Alaska’s oiland gas infrastructure comprises a complex,integrated system and over the years newparts have been added and older parts mod-ernized. Changes have been made toincrease efficiency and production, toimprove integrity and to adapt to changes infield characteristics. At the same time therehave been advancements in oil and gas sci-ence and technology. The current state ofthe infrastructure is a result of the com-bined effects of age, change, industryoperations and government oversight. ●

PETROLEUM NEWS • WEEK OF MAY 6, 2007 15

● G O V E R N M E N T

Governor asks for O&G assessmentAsks Alaska Legislature for $5M, infrastructure assessment for DNR’s new Petroleum Systems Integrity Office would be done by DEC

AGOV. SARAH PALIN

continued from page 14

CBM

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● L A N D & L E A S I N G

Pioneer Natural Resources drops Cronus unitDisappointing results from 2005-06 exploration well behind decision to relinquish former ConocoPhillips North Slope prospect

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16 PETROLEUM NEWS • WEEK OF MAY 6, 2007

Commission, the five-commissionerRCA is responsible for ensuring safe, ade-quate, and fair public utility and pipelineservices. This is done by allowing regu-lated entities to charge users rates andprovide service in a manner best for thepublic and the regulated entity itself.

The RCA regulates pipeline, tele-phone, electric, natural gas, water, sewer,refuse, cable TV and steam services inAlaska, either through certification oreconomic regulation. The commissionalso has consumer protection, tariffreview, dispute resolution and significantadministrative responsibilities.

Despite the apparent 11th hour for thelegislation, prospects for the RCA gettingan extension of up to eight years appear tobe good, according to knowledgeablesources.

“Both the Senate President and theHouse Speaker have committed to pass-ing the legislation, and I expect it to hap-pen,” said RCA Chairman Kate GiardMay 4.

Ted Moninski, director of regulatoryaffairs for Alaska CommunicationsSystems, said he also expects lawmakersto reauthorize the RCA this session.

“In Alaska, these things manage toplay out right toward the end of the ses-

sion,” he said in a telephone interviewMay 3.

Auditors seek improvements“Several bills related to the RCA are

moving in the Legislature in both theHouse and Senate. House ConcurrentResolution 8 just passed out of theHouse Labor and Commerce Committee.It would create a task force that wouldwork between sessions, looking at thingslike staffing, qualifications and such, andreport back to the Legislature next year.”

Moninski praised the RCA’s perform-ance in recent years, noting that the com-mission has made considerable progressin managing its caseload, using adminis-trative law judges, and developing anelectronic filing system that it is aboutready to bring on line.

He also said the companies that theRCA regulates are eager to see evenmore improvements at the commission.

“The actual reauthorization bill willlikely go forward, and ACS would besupportive of that,” he added.

State auditors also praised the RCA’sperformance in a sunset review conduct-ed last fall. In an Oct. 20, 2006 report,the auditors concluded:

“In our opinion RCA meets a validpublic policy need and is servingAlaskans by:

“Assessing the capabilities of utility

and pipeline companies to safely andcapably serve the public;

“Evaluating tariffs and charges madeby regulated entities;

“Verifying the pass through chargesto consumers from electric and naturalgas utilities;

“Adjudicating disputes betweenratepayers and regulated entities;

“Providing consumer protection serv-ices; and,

“Performing financial reviews of util-ities for the State’s power cost equaliza-tion program.”

They also made suggestions for con-tinued improvement, including somerelated to earlier recommendations uponwhich the commission has not acted.

Essentially, the auditors urged theRCA to proceed with development ofregulations that will enhance the trans-parency, accountability, and efficiencyof the commission’s decision-makingprocess.

“Our identified improvement areasinclude establishment of additional time-lines, adoption of rules related to discov-ery; and defining when a record is con-sidered complete and the given timelinestarts,” the auditors said.

They also recommended that the ter-mination date for the commission beextended until June 30, 2015.

Higher salaries neededRCA Commissioner Dave Harbour,

whose term is set to expire in March2008, also weighed in with his opinionon changes that should take place at thecommission.

In a letter to Gov. Sarah Palin April20, Harbour urged state leaders to takeaction to update monetary compensa-tion for RCA commissioners after yearsof neglect.

“In this sunset year the Legislatureshould act to bring long-neglected RCAsalaries to an appropriate level,”Harbour said. “Commissioners signifi-cantly impact the lives of all Alaskans,regulating complex rate structures of our300 utilities and pipelines, from theNorth Slope to Ketchikan.

“Full-time, professional commission-ers should be much closer to the level ofjudges or industry executives than mid-dle-management supervisors,” he added.

Rid agency of time lagOne bill, House Bill 209, is currently

being reviewed in committee.Introduced in the House Labor andCommerce Committee, the measuresought to address some of the auditors’recommendations, including revisions tostatutory timelines for the commission’sdecision-making process.

Because longer timelines for deci-sions are more costly for industry, Giardsaid the proposed changes wouldstrengthen the RCA, an agency that rou-tinely handles about 2 million pieces ofpaper every year.

“When you can eliminate regulatorylag, it gives you a much better regulato-ry climate. And now that we are movingto an electronic format, we’re stronglysupportive of (shorter timelines),” shesaid.

HB 209 originally called for numer-ous other changes, but those have beenremoved from the bill’s language as law-makers have winnowed the measurefrom 19 pages to three pages in recentdays, Giard said.

She credited Rep. Jay Ramras, R-Fairbanks, with introducing strongamendments to the bill when it reachedthe House Judiciary Committee.

—ROSE RAGSDALE

continued from page 1

RCA

By GARY PARKFor Petroleum News

he days of breathtaking budget sur-pluses and rampant growth appearheaded for a slowdown in Alberta, theeconomic powerhouse of Canada over

the past decade.The latest provincial budget delivered a

jolt of reality, projecting a decline in oil andgas revenues from a peak C$14.35 billion in2005-06 to C$7.8 billion in 2009-10.

“We have money, yes, but looking five,10, 15 years out, we have to decide if thatmoney is going to be there,” said FinanceMinister Lyle Oberg, in the most soberassessment of their financial outlook thatAlbertans have heard in years.

There is no secret about the factors atplay. Conventional oil and gas production isin decline, land sales are in retreat and nat-ural gas prices have been sluggish.

The timing becomes even more signifi-cant as the Alberta government embarks onthe most comprehensive public review yetof its entire royalty structure.

While industry leaders have repeatedlycautioned against taking any action thatcould undermine investment there are sig-nals from cabinet ministers that change ispossible.

Report makes case for royalty hikesA government report entitled Prosperity

for Our Future Generations, that made apersuasive case for royalty hikes, was qui-etly tabled in the Alberta legislature in mid-April.

The document estimated “future oilsands royalties will be in the order of C$1.2billion when production reaches 3 millionbarrels per day in 2020, essentially the sameas the value for 2004-05” when output wasonly 1 million bpd.

It blamed the “relatively low royalty” onthe ability of oil sands producers to switchthe base for their royalty valuations fromupgraded synthetic crude to raw bitumen.

That gave further weight to the case

made by Premier Ed Stelmach and otherpoliticians for charging a higher royalty onbitumen exported to U.S. refineries forupgrading than that processed in Alberta.

The review concluded that Alberta’sroyalty share is 19 percent of the industry’snet operating revenue, down from 23 per-cent in 2001 and 2002, and well outside thegovernment’s target range of 20-25 percent.

The report noted that while Alberta’sroyalties are comparable with those in someU.S. states, Texas averages 25 percent,climbing to 40 percent in some price envi-ronments.

Budget: natural gas production shrinkingThe budget came only days later with its

blunt forecast of a sharp decline in oil andgas revenues over the next three years.

Oberg said that reflects lower produc-tion, lower returns from land license andlease sales (projected at C$1.2 billion in2009-10 compared with C$3.5 billion in2005-06), higher production and processingcosts and an increased share of oil royaltiespaid on bitumen rather than conventional orsynthetic crude.

Natural gas production, which generatestwo-thirds of resource income, is shrinkingby an average 4.3 percent a year, with gasroyalties predicted to slump to C$4.6 billionin 2009-10 compared with C$8.4 billion in2005-06.

Royalty rates decline to as little as 5 per-cent as output falls — a government policydesigned to encourage industry to squeezethe last reserves from aging fields ratherthan walking away from those wells.

The government estimates that 89 per-

cent of Alberta’s 92,000 gas wells currentlypay the “low-productivity rate,” leavingonly a small number paying the maximumrate of 25-30 percent.

Conventional oil royalties are predictedto slump to C$2 billion in 2009-10 as pro-duction slides, compared with C$3.8 billionin 2006-07, while oil sands royalties areprojected at C$1.2 billion in 2009-10 com-pared with C$2.4 billion in 2006-07.

Budget targets US$58 per barrel oil prices

The budget is targeting average oilprices of US$58 per barrel this year,US$54.25 in 2008-09 and US$52.50 in2009-10. Gas is forecast at C$6.75 per giga-joule in the current fiscal year, C$6.50 in2008-09 and C$6.25 in 2009-10.

Faced with these trends, both Oberg andEnergy Minister Mel Knight are leaving no

doubt that the royalty review, which willcover all oil and gas sectors, is needed.

Knight said the information availablefrom the government report “would indi-cate to me … that a royalty review is time-ly. Let’s ensure Albertans get a fair share.”

But both emphasized the importance ofstriking a fair balance.

Hugh MacDonald, energy spokesmanfor the opposition Liberal party, was lesssympathetic to the industry’s point of view,claiming Alberta is losing “billions and bil-lions of dollars. … We are certainly not get-ting our fair share.”

Greg Stringham, vice president of theCanadian Association of PetroleumProducers, told the Calgary Herald that anyroyalty changes could harm the industry ata time when capital costs are soaring.

“Certainty and stability are key parts ofthe investment,” he said. ●

PETROLEUM NEWS • WEEK OF MAY 6, 2007 17

● G O V E R N M E N T

Getting an abrupt wake-up callAlberta starts full-scale royalty review against backdrop of forecast nosedive in revenues, internal study points to declining take

The review concluded thatAlberta’s royalty share is 19percent of the industry’s net

operating revenue, down from 23percent in 2001 and 2002, andwell outside the government’starget range of 20-25 percent.

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FINANCE & ECONOMYJohn Browne resigns from BP

John Browne resigned as CEO of BP on May 1, immedi-ately following the release of court documents showing thathe had lied about the circumstances under which he had ini-tiated a personal relationship with a 27-year old named JeffChevalier. The court case involved Browne’s attempt toblock publication of details of that relationship and allega-tions of improper business conduct that Chevalier had sold toa British tabloid newspaper.

According to a statement by BP chairman PeterSutherland, Browne had earlier informed the company of theallegations of business misconduct and that a companyreview had concluded that the allegations were “unfounded or insubstantive.”

“The Board of BP has accepted John’s resignation with the deepest regret,” BPchairman Peter Sutherland said. “For a chief executive who has made such anenormous contribution to this great company, it is a tragedy that he should becompelled by his sense of honor to resign in these painful circumstances.”

JOHN BROWNE

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— to provide an understanding of thecontext in which guarantees might beused.

Rich runs the project finance group atSullivan and Cromwell, the only law firmwhere the average size of projects is morethan a billion dollars. The firm hasworked on half of the 10 largest oil andgas financings, either for the borrower orthe lenders, he said, and has been engagedby the North Slope producer group overthe last couple of years to advise them onfinance issues.

But the opinions and views expressed,he told legislators attending a HouseFinance presentation on April 25, aresolely his own, based on his 25-30 yearsof project work.

Alaska project will break new groundRich said the Alaska project will break

new ground for financing oil and gasprojects, where the largest financing hasbeen well under $10 billion. And, hewarned, what worked for other big projectfinancings may not work for this one.

“Big important projects make theirown market,” he said, but in general thecommercial and economic robustness of aproject determine what lenders will orwon’t accept.

In project finance “we like to use ahairy dog metaphor,” Rich said: Whenthere’s so much hair on the dog at somepoint lenders are going to balk. You don’tknow what the balking point will be, hesaid, but you try to identify what’sdescribed as hair on the dog.

Project finance, he said, is not corpo-rate finance. It’s not based on a form —it’s tailored to the risk profile of the indi-

vidual project. It’s highly structured, requiring a lot of

pieces. The project is nondiversified — the

debt gets paid in only one way. The proj-ect starts with reserves and the shipperpays the tariff, but where is yourrecourse? If you have a pipeline it is aseparate entity from the downstream util-ity and the upstream fields. If I’m the

lender, he said, the only thing I haverecourse to is the pipeline and whether Iget paid or not depends on other people,the shippers, who aren’t part of thepipeline.

The project is often greenfield —when you disperse the loan, there’s noth-ing there, no way to repay the loan.

In contrast to the Alaska gas pipeline,the great majority of the top 20 U.S. gaspipeline financings were expansion andacquisition financings, Rich said. Andthey were far smaller, with No. 20 on thelist dropping to just $10 million.

A project financing is cash-flow-basedcredit usually backed by contractual com-mitments and it is limited recourse: Theproject entity is the only one that owes.After completion, the lenders agree tolook only to the project entity for repay-ment.

What could go wrong?As lenders design financing to reflect

the economic profile of the project theylook at projected cash flow from theproject and they look at the risk to thecash flows: What could go wrong?

In the lending world, Rich said, thefocus is on what could happen thatresults in the debt not getting paid. Thewhole project finance field, he said, isbased on what could go wrong.

The first risk is will there be facilitiesand an enterprise to pay back the debt:Will the project get built on time, withinbudget — and will it work as promised.

Lenders don’t take this risk, Richsaid.

If a project is built to the specifica-tions and has contracts, then at comple-tion the loans will be non-recourse.

Before completion, however, the sponsoror shareholders of the project entity haveto guarantee the debt.

And that is the main reason that goodprojects don’t happen, Rich said.

It’s why most juniors in mining farm-in majors: They may have a great dis-covery and lenders may be enthusiasticabout a project once it is built, but thejuniors don’t have the balance sheets togive completion support.

The federal loan guarantee legislationfor the Alaska natural gas pipeline says ifthe federal government gives guaranteesit will require completion support orguarantees.

Risk allocation and mitigation And while some companies can

finance completely with equity, thenthey take all the risk, which is whylenders are brought in — to share therisk. That way companies limit the firstcall on their equity.

Rich said that leverage is important tolenders, having skin in the game,because lenders want the owner of theproject to be well motivated to fixthings. Lenders want the owner to sufferbefore the lender does. And that is whatequity is, Rich said, the first layer of lossin a project. If the project goes bad theequity suffers before the debt.

There is risk allocation within thedebt portion, he said. You take all thethings that could go wrong and make alist of who bears those risks proportion-ately. The markets like gas, but lenderswon’t bear the risk naked and are goingto demand that those with offtake con-tracts bear risk.

The tax and regulatory risk is quite abig deal in project financing, Rich said,and is often shifted to or borne by thehost government, because for lendersone thing that could go wrong is that thetax burden is higher and the cash avail-able for debt service is lower.

Completion riskWhen considering completion risk,

lenders look at the quality of the feasi-bility and budget work for a project:Who did it? What is the contractingstrategy? Have any of the risks been laidoff?

They look at what the quality of proj-ect execution is expected to be based onthe track record of the shareholders andthe size of the budget contingency.Sometimes they require pre-committedoverrun financing.

All of these things can mitigate, but ifthey don’t work and there is a cost over-run, the lenders will not take the risk.

The sponsor bears that risk with com-pletion support or guarantee from share-holders. The risk is allocated away fromthe lenders.

It all goes in a risk matrix, Rich said.You identify the risk and how each ismitigated and those risks need to be mit-igated as part of commercial and govern-mental agreements negotiated before theproject is financed.

—KRISTEN NELSON

18 PETROLEUM NEWS • WEEK OF MAY 6, 2007

Company symbol earnings % liquids % gas %

ExxonMobil XOM $9,280 +10 2,747,000 +2 10,131 -9

RD/Shell RDS-A $6,932 +14 1,961,000 -0- 8,981 -13

Chevron CVX $4,715 +17 1,779,000 +6 4,994 +1

ConocoPhillips COP $3,456 +5 1,133,000* +12 5,322* +49

Occidental OXY $1,212 -2 469,000 +5 719 +2

Can. Natural CNQ.TO C$269 +372 327,001 +1 1,717 +20

Devon DVN $651 -7 214,300 +23 2,243 +6

Talisman TLM

Imperial IMO C$774 +31 266,000 +1 525 -9

Petro-Canada PCZ C$590 +186 280,400 +14 748 -5

XTO XTO $383 -18 56,460 +1 1,264 +12

Pioneer PXD $30 -95 42,801 -31 330 -44

Newfield NFX -$96 — 23,800 +35 575 +17

Pogo PPP -$21 — 34,722 -12 286 +1

Marathon MRO $717 -9 198,000 +9 849 -15

Husky HSE.TO C$650 +24 283,300 +18 640 -7

Apache APA $492 -25 242,726 +5 1,761 +30

Suncor SU.TO C$551 -23 248,200 -6 209 -3

Nexen NXY.TO C$121 — 199,300 +11 233 -6

Chesapeake CHK

EOG EOG $217 -49 28,800 -1 1,420 +9

Swift SFY $28 -26 22,400 -6 60 -4

EnCana ECA $497 -76 223,000 -30 3,400 +2

Anadarko APC $105 -84 286,000 +56 2,204 +102

BP BP $4,664 -17 2,446,000 -3 8,502 -2

Earnings from Petroleum News Top 25Earnings first quarter 2007 • Change from first quarter 2006

Liquids production first quarter 2007 • Change from first quarter 2006Natural gas production first quarter 2007 • Change from first quarter 2006

OIL COMPANY EARNINGS

* Excludes Lukoil investment**Millions of cubic feet equivalent

Liquids production in barrels per day. Natural gas production in millions of cubic feet per day.

NOTE: Top 25 is based on Petroleum News research on exploration spending

How much will federal loan guarantee cover? Frederic Rich of the New York law firm of Sullivan and Cromwell told an

Alaska House of Representatives Finance Committee April 25 that the amount ofthe federal loan guarantee for an Alaska gas pipeline project is an issue.

The statute says the Department of Energy may guarantee up to 80 percent ofthe total project cost. If the project were 80 percent debt and 20 percent equity,that means the guarantee could cover 100 percent of the debt.

But, he said, standard practice in the U.S. government is 80 percent of 80 per-cent. That is the firmly held position of Treasury and the Office of Managementand Budget: They want the lender to have skin in the game.

If the guarantee only covers 80 percent of the debt, the uncovered portion couldbe the largest oil and gas financing every done by itself.

In thinking about the markets there are a lot of different forks in the road, Richsaid, and the 80 percent is one of the biggest.

If you have 100 percent of the debt guaranteed you’d be in one world and ifit’s 80 percent you’re in a very different world.

The one good thing about this financing is that the construction period islengthy, so you wouldn’t be looking to do all the financing at one time, Rich said.

Rich said the federal loan guarantee for the project is interesting. When you have a guarantor, he said, all that means is that to the extent of guar-

antee that entity is the lender and has all the same requirements as the lender has.The federal government becomes in effect the worrier-in-chief, and that’s some-thing the government takes very seriously, he said.

If the federal government guaranteed the loan and the project defaulted the fed-eral government would pay the lender and then has all the same rights and reme-dies as the lender. The project still has to replay the money, but instead of havinga private lender with discretion, the project now has the federal government,which by statute has to deal with assets in a responsible manner, Rich said.

Rich said the only benefit of a federal loan guarantee is that it lowers the costof debt; there’s no other difference once the debt is dispersed.

—KRISTEN NELSON

continued from page 1

FINANCING

um and long term.” Wood Mackenzie forecasts world

LNG demand will triple by 2020, withconsumption by then of more than 500million tonnes a year, the equivalent of 25trillion cubic feet of natural gas. That’s upfrom 141.5 million tonnes in 2005, oraround 7 tcf.

While technical and cost issues domi-nate the short-term picture, there’s actual-ly a shortage of available gas around theworld that’s suitable for LNG develop-ment after around 2012, WoodMackenzie figures. Harris even sees arole for small independents in findingnew supplies to feed the world LNG mar-ket later in the century.

Short-term squeezeOn the surface, it appears that there

should be sufficient LNG from existingprojects or those under construction tomeet market demand until around 2010.But Harris notes that things aren’t so rosyin the real world of complex and expen-sive liquefaction trains.

“In the last two or three years, we’veseen more problems than we would haveexpected (in liquefaction plants), particu-larly with the new LNG plants,” he said.“At the same time, we’re seeing a numberof countries now trying to fast-track theirplans to import LNG. So the demand isactually picking up above our base fore-cast.

“Putting those two things together,between now and 2010, we think thereare going to be times when there’s notenough LNG to go around.”

Competition for limited supplies of theclean fuel could increase fuel pricesaround the globe, while diverting LNGaway from North America, where gasprices are comparatively low. U.S.imports have actually declined the lasttwo years as shipments were diverted tomore lucrative markets in Europe.

Overruns and delaysDemand for LNG is rising steadily as

developing countries import the productto power their manufacturing bases anddeveloped countries try to reduce theirdependence on dirtier and more carbon-intensive fuels such as coal.

Taiwan, for example, uses LNG for 90percent of its gas use, the bulk of that forpower generation. The island’s LNG con-sumption is expected to rise 38 percent by2010 to 10.5 million tonnes that year.

Meanwhile, mushrooming costs andenvironmental issues have delayed somebig LNG projects around the globe.

It was a shot heard round the industrywhen Shell announced that its bigSakhalin 2 LNG project was going to costaround $20 billion to develop, rather thanthe original projection of $10 billion, andits completion date was pushed back. Afinal investment decision on the Chevron-led Gorgon project off Australia has beenpostponed repeatedly, partly becausecosts are rising so quickly.

“We’re seeing huge increases in capi-tal costs for LNG projects,” Harris said.“A lot of the players are sort of takingtime to sit back and say, ‘Are there thingswe can do to the project to change theeconomics, to improve the economics?’

“This takes time to work through,leading to delays.”

Near-term supply constraints are pop-ping up due to political and geopoliticalissues as well. “For example, it’s very dif-ficult to see how Iranian LNG projectsare going to move forward in the currentenvironment,” he said. Iran holds 15 per-cent of the world’s proven recoverable

gas reserves, second only to Russia. Exporting countries also are seeing ris-

ing demand in their local markets, whichmeans supply that would have gone toLNG export is instead being burned in thehome country.

NOCs flex musclesMeanwhile, the big international oil

companies are being locked out of alarge portion of the supply. The vastmajority of known gas reserves in theworld are owned by government-con-trolled oil and gas concerns, known asnational oil companies or NOCs.

Just the three top national oil and gascompanies, in Russia, Qatar and Iran,control more than half of the currentknown reserves. Those companies areflexing their muscles, as Gazprom did inits essentially forced purchase of a stakein Sakhalin 2 and in its negotiations overdevelopment of the giant Shtokman off-shore field.

“Whilst there’s still scope for theinternational oil companies to getinvolved in developing those reserves,the outlook is getting bleaker,” Harrisnoted. With high oil prices, the nationalfirms are flush with cash.

“The NOCs don’t need capital. Theydon’t need technology. And the nationaloil companies want to work together,”Harris says. They’re picking each otheras partners rather than the supermajors.NOCs such as Petrobras and Petronasare now well-established players. On topof that, big service companies such asSchlumberger are eager to sell theirexpertise, and global drilling firms willpunch the holes.

The deep pockets and operating expe-rience of the big international oil compa-nies aren’t as vital as they once were,and the elephant fields are scarce, socompanies are willing to cut their profitmargins ever thinner to get new busi-ness.

New frontiers The current known reserves of gas in

the ground total around 6,400 tcf,according to BP’s annual count. Thatseems flush when you figure that a typi-cal LNG project will consume some-thing like five to 10 tcf in a 20-year peri-od.

But there is one reason or anotherwhy much of it is not suited to LNGdevelopment.

Some gas has too much carbon diox-ide. Some deposits are spread over toolarge an area. Other fields are closeenough to markets that the gas can bemoved there by pipeline.

Or the gas may be far from the coast,as in eastern Siberia, “so it makes nosense to transport gas thousands of kilo-meters by pipe, then liquefy and turn itinto LNG,” he says. “It makes sense tobuild the pipeline a bit longer and take itto market by pipe.

“There’s a lot of that 6,400 tcf that’snot available for LNG,” Harris con-cludes.

For the international majors and evensome of the smaller private companies,“it creates a strong strategic imperativefor the industry to start exploring,”Harris says.

Less above-ground risk“A number of LNG players are taking

something of a gamble, going into newareas with more subsurface risk,” Harrissays. They may not find gas, or the gasthey find may not be adequate to supportthe billions of dollars that an LNG traincosts.

“Why take on the risk?“If they do find gas and it’s the right

quality for LNG, the above-ground risk isa lot lower. There are no national oil com-panies or domestic market.”

For Woodside’s Pluto discovery offAustralia, Harris pointed out, the compa-ny is expecting to start shipping LNGabout six years after discovery.

“That’s really quick by historic stan-dards,” he said, noting that many gas dis-coveries have waited in the ground for acouple decades.

“If you find gas now, the ability tomonetize the gas quickly is much betterthan it used to be.”

With big oil discoveries coming a lotless frequently, the industry is focusingmore on LNG-related exploration, Harrissaid. Some is in areas where LNG plantsare already operating, such as Australiaand Nigeria, where the existing opera-tions will take the new gas at some pointor can be expanded. Other exploration iscoming in genuinely new areas such asPapua New Guinea.

“Exploration needs to be a key part ofany company’s strategy in LNG,” Harrisconcludes. “The national oil and gas com-panies’ strategies are evolving. To keepgrowing, the international companieshave to do more exploration. And there’san interesting role for the smaller compa-nies in this business as we go forward.” ●

PETROLEUM NEWS • WEEK OF MAY 6, 2007 19

A new Tristone Capital report por-trayed the Mackenzie Valley pipeline asuneconomic without as much as C$2 bil-lion in federal aid or incentives.

Imperial — and its industry partnersConocoPhillips Canada, Shell Canadaand ExxonMobil Canada — have left lit-tle doubt that without some form of fiscalconcessions the Mackenzie project eco-nomics are too shaky to proceed.

Almost 70 percent of Imperial isowned by ExxonMobil.

Imperial trying to restrain Kearl costs

On another front, Hearn said Imperialis exploring alternatives to restrain costsat its planned C$8 billion Kearl oil sandsproject, including a number of construc-tion options.

“The model we are trying to do forKearl for Phase 1 is just to do the miningportion and upgrade in a number ofrefineries in Canada and elsewhere ifthere is extra product available, and notget into a huge mega-project,” Hearnsaid.

Traditionally, he noted, the miningportions have been easier to execute.

Kearl is designed to start at 100,000barrels per day, with the potential to triplethat volume.

Final regulatory approval is anticipat-ed later this year.

UBS Securities Canada analystAndrew Potter put out a research noteMay 1 that underscored the obstaclesImperial faces in trying to build theMackenzie project and Kearl.

He said they both “face considerable

development risk reflecting the highcosts.”

Compounding those problems is theloss of the federal government’s acceler-ated capital cost allowance in the oilsands, the climate-change regulationsbeing imposed by the Alberta andCanadian governments, changes to theincome trust tax structure and theprospect of higher Alberta royalties.

Hearn said that with so much on thetable he hopes for concise and balancedpublic policy results.

He said the industry must have a clearunderstanding of public policy because“we make huge capital decisions withsignificant risks in a commodity environ-ment and these investments are not forone or two years — they’re around 30,40, 50 years.”

Under those circumstances, Hearnsaid it is essential to “understand the con-text in which we’re going forward.”

On the climate-change front alone, heurged the governments to ensure Canadadoes not lose its competitive place glob-ally.

While not opposed to paying the costof environmental improvement, he cau-tioned that it “serves no purpose if we getregulatory aspects that really put ourindustries at a competitive disadvantage.”

—GARY PARK

continued from page 1

IMPERIALImperial — and its industry

partners ConocoPhillips Canada,Shell Canada and ExxonMobilCanada — have left little doubtthat without some form of fiscal

concessions the Mackenzieproject economics are too shaky

to proceed.

continued from page 1

LNGWood Mackenzie forecasts worldLNG demand will triple by 2020,with consumption by then of more

than 500 million tonnes a year,the equivalent of 25 trillion cubicfeet of natural gas. That’s up from141.5 million tonnes in 2005, or

around 7 tcf.

20 PETROLEUM NEWS • WEEK OF MAY 6, 2007

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

ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARSBusiness Spotlight

AAce TransportAcuren USA (formerly Canspec Group)AeromedACE Air CargoACSAgriumAir LiquideAir Logistics of Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Alaska Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Alaska Anvil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Alaska CoverallAlaska DreamsAlaska Frontier ConstructorsAlaska Marine LinesAlaska Railroad Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Alaska Rubber & Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Alaska Steel Co.Alaska TelecomAlaska Tent & TarpAlaska TextilesAlaska West ExpressAlliance, TheAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Arctic Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Arctic Foundations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Arctic Slope Telephone Assoc. Co-op. . . . . . . . . . . . . . . . . . . 17Arctic Wire Rope & Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . 17ASRC Energy Services

Engineering & TechnologyOperations & MaintenancePipeline Power & Communications

Avalon Development

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G-MGreat Northern EngineeringGreat NorthwestGPS EnvironmentalHawk ConsultantsH.C. Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Hilton Anchorage

Holaday-Parks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Horizon Well LoggingHotel Captain Cook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Hunter 3-DIndustrial Project ServicesInspirationsJackovich Industrial & Construction SupplyJudy Patrick PhotographyKenai AviationKenworth AlaskaKing Street StorageKuukpik - LCMFLast Frontier Air Ventures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Lounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMapmakers of AlaskaMarathon OilMarketing SolutionsMayflower CateringMI Swaco. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4MRO Sales

N-PNabors Alaska Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13NANA/Colt EngineeringNatco CanadaNature Conservancy, TheNEI Fluid TechnologyNMS Employee Leasing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Nordic CalistaNorth Slope TelecomNorthern Air CargoNorthern Transportation Co.Northland Wood ProductsNorthwest Technical ServicesOffshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oilfield ImprovementsOilfield TransportP.A. LawrencePanalpina. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15PDC Harris GroupPeak Oilfield Service Co.PencoPetroleum Equipment & ServicesPetrotechnical Resources of AlaskaPGS OnshorePrudhoe Bay Shop & Storage. . . . . . . . . . . . . . . . . . . . . . . . . 12PTI Group

Q-ZQUADCORain for RentSalt + Light Creative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15SchlumbergerSeekins Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Spenard Builders Supply. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18STEELFAB. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103M AlaskaTire Distribution Systems (TDS)Total Safety U.S. Inc.TOTE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Totem Equipment & SupplyTubular Solutions AlaskaUdelhoven Oilfield Systems ServicesUnique MachineUnivar USAUsibelliU.S. Bearings and DrivesVECOWelding ServicesWesternGecoXtel InternationalXTO Energy

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

Barrie Pritchard, Estimator

STEELFABSTEELFAB is a full-service fabrica-

tion facility run by people who’vebeen around the block a time or two.They build almost anything that canbe made out of steel — bridges,modules, structural steel buildings,etc. They roll their own tanks andform steel on Alaska’s biggest pressbrake. STEELFAB is an A.I.S.C. certifiedshop that prides itself on keepingcustomers satisfied.

Barrie Pritchard was born inCaerphilly, South Wales, U.K. Heattended a technical college for twoyears and did a four-year apprentice-ship with highly skilled fabricatorsbefore moving to Alaska in 1980. Foreight years he worked for SteelFabricators, which owners Richardand Janet Faulkner renamedSTEELFAB. Barrie’s big project athome is fixing up a 1978 Datsun 280Z (for his midlife crisis).

CO

URT

ESY

PH

OTO

PETROLEUM NEWS • WEEK OF MAY 6, 2007 21

of the agency’s five-year outer continentalshelf program was released to the publicon April 30.

“Among the many decisions I willmake as secretary of the Interior, I con-sider this to be one of the most importantbecause of its far-reaching impact,” U.S.Interior Secretary Dirk Kempthorne saidduring a press conference in Washington,D.C.

MMS estimates that the new leasingprogram could generate production of 10billion barrels of oil and 45 trillion cubicfeet of natural gas, with $170 billion innet benefits for the United States over a40-year time span.

A dozen Gulf sales proposed As expected, the lion’s share (12) of fed-

eral offshore lease sales from 2007 to 2012would be for exploration blocks in the Gulfof Mexico, America’s number one produc-ing region. Eight sales are planned for off-shore Alaska and only one for offshoreVirginia, near the tail-end of the proposedfive-year program.

However, while some polls conductedin Virginia indicated public support for anoffshore lease sale in the Mid-Atlanticregion, actually getting the necessaryapproval for one in the Democrat-con-trolled Congress could be tricky.

Between presidential withdrawals andcongressional moratoria, the majority ofthe OCS around the Lower 48 states hasbeen off limits to new leasing for nearly aquarter century, including all areas offVirginia. Therefore, the so-called “specialinterest sale” off Virginia’s coastline couldonly take place should the current presiden-tial withdrawal be modified and the con-gressional moratorium discontinued in theMid-Atlantic Planning Area.

“I think the leadership of Virginia wouldplay a key role in what ultimately mayoccur there,” Kempthorne said.

Interestingly, the last offshore federallease sale held outside the Gulf of Mexicoand Alaska was Mid-Atlantic Lease Sale 76in April 1983, which takes in the same gen-eral area as Mid-Atlantic Lease Sale 220proposed for 2011.

48 million acres not currently available

The five-year program includes 48 mil-lion acres that have not been available since

the early 1980s. In total, the program wouldmake available for leasing some 180 mil-lion acres, 8 million acres of which arelocated offshore Virginia.

MMS, in an obvious move to make theproposed Mid-Atlantic lease sale moreacceptable to the public, excluded a 50-mile coastal buffer from leasing considera-tion as requested by the Commonwealth ofVirginia, as well as a wedge-shaped “no-obstruction zone” to avoid conflicts withnavigation activities in and out ofChesapeake Bay. Moreover, the sale couldnot proceed without more site-specific

analysis of its environmental effects underthe National Environmental Policy Act,according to MMS.

“The offshore energy industry has aremarkable safety record,” Kempthornesaid. “Two major hurricanes passedthrough the Gulf of Mexico in 2005 with-out causing a single significant spill froman OCS well. That’s a remarkable achieve-ment.”

As required by the OCS Lands Act, theplan was submitted to President Bush andCongress. They had 60 days from April 30to review the plan before the Interior secre-

tary signs off on the final program. Ifapproved, it would take effect on July 1.

The 2007-2012 leasing plan includedthree periods of public comment, resultingin more than 125,000 responses. MMS saidit received comments from states, localgovernments, Native groups, tribes, the oiland gas industry, federal agencies, environ-mental and other interest organizations, andthe general public to assist in the prepara-tion of the leasing program.

“Seventy-five percent of the commentswe received from the public supportedsome level of increased access to thedomestic energy resources of the outer con-tinental shelf,” Kempthorne said.

Two events during programdevelopment

Two events occurred during the pro-gram development — enactment of theGulf of Mexico Energy Security Act of2006 and modification of the presidentialwithdrawal in Alaska and small portions ofthe Central Gulf of Mexico.

The Act, signed by President Bush onDec. 20, 2006, requires oil and gas leasingin 2 million acres in the Central GulfPlanning Area known as the Sale 181 Areaand an area of about 580,000 acres in theEastern Gulf Planning Area. Bush modifiedthe presidential withdrawal for two areas inthe OCS — the North Aleutian basin inAlaska, and an area in the Central Gulf ofMexico, referred to as the 181 South Area.These areas were earlier withdrawn fromconsideration for leasing through 2012 byformer President Bill Clinton.

Congress lifted the moratorium on the181 South Area with the Energy SecurityAct. The five-year program includes aCentral Gulf sale in 2007 that involves aportion of the Sale 181 area and, as man-dated by the Act, one lease sale in theEastern Gulf in 2008. There is no leasingproposed within 125 miles of the Floridacoast or east of the military mission line inthe Eastern Gulf.

“In developing the OCS oil and gasleasing program, the administration consid-ered all potential energy resources that canbe developed in a safe and environmental-ly sound manner,” Kempthorne said.

He added: “The OCS is a vital source ofdomestic oil and natural gas for America,especially in light of sharply rising energyprices and increasing demand for theseresources. It would be irresponsible not tomake maximum use of our own domesticenergy resources.” ●

continued from page 1

STEP Gulf oil output expected to rise 40%U.S. Gulf of Mexico oil production is expected to increase over the next 10

years to a possible 2.1 million barrels per day, roughly a 40 percent increase overpre-2005 hurricane levels of 1.5 million bpd.

In a recent report entitled “Gulf of Mexico Oil and Gas Production Forecast:2007-2016,” the U.S. Minerals Management Service also projected that naturalgas production in the U.S. Gulf would recover from declines over the next threeyears to a possible 8.3 billion cubic feet per day. However, this still would beabout 17 percent below pre-hurricane levels of around 10 billion cubic feet perday.

The production forecast was released May 1 at the annual Offshore TechnologyConference in Houston.

One of the nation’s major sources of oil and gas, the Gulf of Mexico was dealta one-two punch by category-five hurricanes Katrina and Rita, causing destruc-tion and substantial damage to offshore platforms within a four week period inAugust and September of 2005.

MMS estimated that 3,050 of the Gulf’s 4,000 platforms and 22,000 of the33,000 miles of Gulf pipelines were in the direct path of either Katrina or Rita,resulting in the destruction of 115 platforms, damage to 52 others, damage of 535pipeline segments and near total shut-down of the Gulf’s offshore oil and gas pro-duction weeks after the disasters.

In mid-June 2006, when the last official hurricane damage report was issuedby MMS, 12 percent of daily oil production and more than 9 percent of daily gasproduction remained shut-in, resulting in the loss of 166 million barrels of oil and804 billion cubic feet of gas.

Katrina, Rita two of 10 most intenseKatrina and Rita are still ranked as two of the 10 most intense hurricanes to

ever hit the Atlantic Region and the greatest natural disasters to oil and gas devel-opment in the history of the U.S. Gulf.

MMS’ recent production forecast takes into account currently producing proj-ects, oil and gas companies’ expectations for production over the next five yearsand estimates of undiscovered resources in the Gulf of Mexico.

Activity used for the forecast included the expectation of 16 new deepwaterprojects coming into production by year-end 2007. A major contributor would bethe Independence Hub facility in the Eastern Gulf, which is designed to produceup to 1 billion cubic feet per day from multiple fields. First gas is expected in thesecond half of this year.

“With the continued interest and activity in the deepwater area of the Gulf, weanticipate that oil and gas production will continue to be strong with a large por-tion of the production coming from the projects in deeper water depths,” said LarsHerbst, acting regional director for MMS.

—RAY TYSON

22 PETROLEUM NEWS • WEEK OF MAY 6, 2007

Conoco and Exxon asked the SuperiorCourt to reverse both a Nov. 27 decisionby DNR’s commissioner to terminate thePoint Thomson unit and a Dec. 27 deci-sion on reconsideration of the unit termi-nation decision. The leaseholders’ briefson appeal are due in June. The SuperiorCourt will decide based on the briefs filedby the Point Thomson leaseholders andthe state whether or not the commissionerwas correct in finding Exxon’s 22nd planof development inadequate and terminat-ing the unit.

Since the department issued its finaldeterminations on Point Thomson,DNR’s Division of Oil and Gas hasmoved forward with the unit terminationprocess, including canceling PointThomson’s core and expansion leases.Because of the defunct status of the unitand its leases, the agency also tabled aplan of operations and well permits filedon March 23 by Point Thomson operatorExxon to drill up to seven wells in the unitbetween 2008-09 and 2015 — an effortdesigned to hold onto the leases, not a23rd plan of development for the 30-yearold unit, Exxon’s Susan Reeves toldPetroleum News in April.

The four leaseholders also filed admin-istrative appeals with DNR’s commis-sioner on the division’s lease terminationnotices for Point Thomson. On March 27,the commissioner granted unit operatorExxon an additional 30 days to file sup-plemental materials in support of admin-istrative appeals on the leases — materi-als that were filed the last week in April.The leaseholders asked for hearings.

Palin, Irwin pleased with decisionAlaska Gov. Sarah Palin was pleased

with the court’s May 1 decision.“This decision represents forward

progress in our efforts to put these leasesin the hands of a company that willresponsibly develop them and bring thesignificant gas reserves in the PointThomson area to market,” Palin said in apress release.

“This ruling tells us that standing up toprotect Alaska’s interests, in seeing itsresources produced, is the right thing todo,” said DNR Commissioner Tom Irwin.“We will continue to stand firm in pro-tecting the state’s rights in the face of theinevitable barrage of criticism from thestate’s major producers. The debate overAGIA (Alaska Gasline Inducement Act)is a good example. In protecting theirshareholders’ financial interests, the pro-ducers are seeking to change the rulesbecause competition means that they may

not get a deal on their terms. I hope theychoose to participate in building a gaslineand will meaningfully engage in theAGIA process.”

The state had opposed the motions forstay on the grounds that halting the unittermination process would impede thepublic’s overriding interest in the devel-opment of Point Thomson’s oil and gasreserves, which are thought to hold about300 million barrels of oil and natural gascondensates, as well as 8 trillion to 9 tril-lion cubic feet of natural gas.

In its April 5 filing, the state also toldthe court that the leaseholders had notfiled a supersedeas bond, a requirement ofAppellate Rule 603, which says, “whenan appeal is taken” the appellant (in thiscase the Point Thomson leaseholders)may get a “stay of proceedings toenforce” an administrative judgment byfiling a supersedeas bond. The stay can beeffective only when the bond is approved.The filing of a supersedeas bond does not,however, prohibit the court from consid-ering the public interest in decidingwhether or not to impose or continue astay on an administrative (or districtcourt) judgment that is not limited tomonetary relief.

Wells capable of producing paying quantities

In her May 1 decision Judge SharonGleason noted that the leaseholderssought to halt primarily the non-monetaryportions of the administrative decisions,quoting a 1995 Alaska Supreme CourtCase that gave her the right to be “guidedby the public interest” in granting or notgranting a stay.

The judge said the “primary con-tention” between the parties “at this initialstage of the unit termination appeals wasthe appropriate interpretation” of subpartsC and D of a DNR regulation, 11 AAC83.374, and the applicability of a separateregulation, 11 AAC 83.361.

Part C of 11 AAC 83.374 says if adefault occurs in a unit in which there isno well capable of producing paying

quantities of hydrocarbons the commis-sioner can terminate the unit agreementby mail if the defaulting party is givenreasonable notice and an opportunity tobe heard. Termination is effective uponmailing the notice.

In part D, if a default occurs in a unitthat has a well capable of producinghydrocarbons in paying quantities, thecommissioner can seek to terminate theunit, but has to do so by judicial proceed-ings vs. administrative ones — i.e. file amotion in the State of Alaska’s SuperiorCourt.

11 AAC 83.361 deals with certificationof well test results. It says the lessee orunit operator will consider a well capableof producing hydrocarbons in payingquantities when so certified by the com-missioner.

Another regulation defines payingquantities as “sufficient to yield a returnin excess of operating costs, even ifdrilling and equipment costs” can neverbe recouped and the undertaking as awhole “may ultimately result in a loss.”The quantities have to be enough to“induce a prudent operator to producethose quantities,” not considering “thecosts of transportation and marketing.”

No dispute overinitial well certification

None of the parties dispute that thereare wells within the Point Thomson unitthat had been certified by DNR as capableof producing paying quantities of hydro-carbons, the judge noted.

Because several Point Thomson wellshave been certified, the leaseholders saypart C of 11 AAC 83.374 applies — thatthe commissioner should have sought toterminate the unit through judicial pro-ceedings.

The appellants also contend that theirconstitutional rights to due process andequal protection were violated at theadministrative level because they claimthe Alaska Gasline Port Authority submit-ted extensive materials it identified asconfidential to DNR that containedAGPA’s legal analysis of the state’s abili-ty to terminate the Point Thomson unit —materials that were not served on theleaseholders during the course of theadministrative proceedings.

In BP, Chevron, Conoco and Exxon’sview, they have demonstrated a clearprobability of success on these issues, sothe Superior Court should rule in theirfavor and stay DNR’s administrativeactions while the appeal is still pending inSuperior Court.

The leaseholders also contend that it’sin the public interest to grant the staybecause they will be able to continue

development of the Point Thomson unit ifthe unit agreement is reinstated andbecause if the state puts the PointThomson leases up for sale, bidders willdiscount their offers because of the pend-ing appeal.

Leaseholders want to keep leasesThe state told the court what BP,

Chevron, Conoco and Exxon “actuallywant is a stay of the lease terminationappeal proceedings now pending beforethe DNR commissioner.”

In her May 1 order, the judge referredto the commissioner’s November unit ter-mination decision, in which he acknowl-edged that former division directors hadcertified seven Point Thomson unit wellsas capable of producing paying quanti-ties, all of which where certified in the1970s and 1980s and have since beenplugged and abandoned. The commis-sioner said there were no existing certi-fied Point Thomson wells capable of pro-ducing in paying quantities, noting that noproduction wells had ever been drilled inthe unit.

The commissioner said, and the judgequoted him, that “the primary basis of the(unit termination) decision is the unequiv-ocal statement that the leaseholders can-not find a way to put the unit into produc-tion and their refusal to submit an accept-able” plan of development to DNR.

In their replies the leaseholders saidthe plugged and abandoned wells in theunit that had been certified must still beconsidered capable of producing hydro-carbons, as so defined by DNR’s own reg-ulations, so judicial proceedings to seektermination of the unit were required.

The judge pointed out that while thePoint Thomson leaseholders want thecourt to consider the wells capable of pro-ducing hydrocarbons in unit default pro-ceedings, when it comes to filing devel-opment plans for Point Thomson they“appear to assert that the wells that werecertified are in fact not currently capableof producing hydrocarbons in payingquantities.”

The judge wrote that “according toDNR’s director of the Division of Oil andGas, the appellants proposed 22nd plan ofdevelopment for the unit ‘states that PointThomson unit development is not possi-ble without modifying the laws regardingthe state’s right to taxes and royalties onoil and gas production and on construc-tion of a North Slope gas pipeline.’”

Despite the fact that the departmentcertified the seven Point Thomson wellsin the 1970s and 1980s, which makesthem capable of producing hydrocarbonsin paying quantities for the purpose of 11

continued from page 1

RULING

see RULING page 23

The judge pointed out that whilethe Point Thomson leaseholderswant the court to consider the

wells capable of producinghydrocarbons in unit default

proceedings, when it comes tofiling development plans for PointThomson they “appear to assertthat the wells that were certified

are in fact not currently capable ofproducing hydrocarbons in paying

quantities.”

PETROLEUM NEWS • WEEK OF MAY 6, 2007 23

AAC 83.374, the state asked the court tolook at the current actual status of thewells. But the court said “parties appear-ing before an agency are entitled to reliefwhen an agency has substantially failed tofollow its own procedural regulations.”

Over the course of the judicial appeal“the public interest could be adverselyaffected by DNR’s decertification actionto the extent that the action generatesuncertainty and instability among lesseesor potential lessees throughout the statewith respect to their rights in the state’soil and gas reserves,” Gleason said.

Leaseholders have strong case, but….After reviewing the regulations,

Gleason determined that BP, Chevron,Conoco and Exxon had made a “clearshowing of probable success on the mer-its with respect to the proceduresemployed by DNR to terminate thePoint Thomson unit,” but she said “it iscertainly possible that upon furtherbriefing of the many complex andunprecedented legal issues presented inthis case,” that “this court may be per-suaded by the state that the department’sdecisions should be affirmed.”

Still “at this initial stage of theappeal” leaseholders BP, Chevron,Conoco and Exxon have “made a clear-ing showing of probable success” withrespect to procedural challenges, and“specifically with DNR’s apparent vio-lation of its own procedural regula-tions.”

But her decision on whether or not togrant the stay requested by the lease-holders was “guided by the public inter-est,” which Gleason said was to seePoint Thomson’s oil and gas reserves

produced, which means making themavailable for development.

The judge also said the leaseholdersargument that the public interest is bestserved by allowing a stay so that BP,

Chevron, Conoco and Exxon can “con-tinue development” of the unit is notpersuasive because it’s “somewhat atodds with the appellants’ own proposed22nd plan of development, which didnot propose to put the unit into produc-tion.”

Sixty day notice on lease offeringGleason said the state had “persua-

sively demonstrated that it is in the pub-lic interest” to give DNR a reasonableopportunity to address the related leasetermination proceedings at the adminis-trative level.

And, if DNR wants to re-offer thePoint Thomson tracts in a lease sale, thejudge said the state has agreed to give atleast 60 days notice of its intent, whichwould allow the leaseholders sufficienttime to renew their motions for staywith the court.

With respect to the commissioner’sfinding that the leaseholders owe thestate $20 million for breach of the 2001unit expansion agreement, Gleason saidthe appellants are entitled to a stay ofthe monetary portion of the commis-sioner’s decision if they post a $25 mil-lion supersedeas bond with the court. ●

continued from page 22

RULING

If DNR wants to re-offer the PointThomson tracts in a lease sale, thejudge said the state has agreed togive at least 60 days notice of its

intent, which would allow theleaseholders sufficient time to

renew their motions for stay withthe court.

24 PETROLEUM NEWS • WEEK OF MAY 6, 2007