page11

State sees ANGDA as playing early,technical role in bullet line work

Vol. 14, No. 11 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 15, 2009 • $2

� F I N A N C E & E C O N O M Y

� G O V E R N M E N T

� F I N A N C E & E C O N O M Y

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

6 Up and down for BP in ’08: BP Exploration (Alaska) reportsrevenues up 15%, taxes rise — profits down 21%; production falls

10Armstrong preps supply contract: Successful North Fork

test means gas pricing will return to RCA; company asking for $7 to $10

17Court withdraws ’08 decision on Shell: 9th Circuit willissue new decision; ’08 ruling upheld NSB, AEWC appeals against MMS

Redoubt Volcano and the Drift Glacier seen from the northeast.The Drift River Marine Terminal near the base of the volcano hasflood protection, in case an eruption melts the glacier, sendingflood water down the Drift River. The terminal is on the south sideof the river, next to the Cook Inlet coast. For more, see page 12.

Keeping a watchful eyeM

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RY PERL files Chapter 11Citing falling oil prices and big debt load, Pacific Energy files for bankruptcy

By ERIC LIDJIPetroleum News

One of Alaska’s smallest producers filed forChapter 11 bankruptcy protection March 8.

In court documents, Pacific Energy ResourcesLtd. said the drop in oil prices toward the end oflast year weakened the company’s cash flow, mak-ing it hard to pay off debt.

Pacific Energy owns producing oil and gasassets offshore California and in the Cook Inletregion of Alaska, and said its revenue stream is“largely dependent on the market price for theunderlying crude oil produced, in addition to thelevel of production.”

After peaking around $145 a barrel last July, thedelivered price of Alaska North Slope crude oil fell

to nearly $25 a barrel before climbing back tobetween $40 and $50 a barrel.

Pacific Energy produced some 5,000 barrels ofoil equivalent per day in Alaska in 2007.

Pacific Energy reported earned around $226.2

To facilitate that deal, Pacific Energy tookout two loans with the Goldman Sachs

affiliate J. Aron and Co. and Silver PointCapital. As of March 8, the company saidit had nearly $91 million outstanding onthe first loan and around $322 million on

the second.

see PACIFIC ENERGY page 21

Swimming against US tideCanada hammers home belief technology solutions beat cap-and-trade

By GARY PARKFor Petroleum News

Increasingly on edge as PresidentBarack Obama presses ahead with

plans for a cap-and-trade system for car-bon emissions and fully awake to threatsof environment-based protectionistmeasures in the United States, theCanadian government is pulling out allstops to keep Washington focused ontechnological solutions.

In a hasty follow-up to the mid-February sum-mit when Obama and Prime Minister StephenHarper agreed to jointly pursue the development ofcarbon capture and storage answers to greenhouse

gas emissions from coal-fired powerplants and oil sands projects, Canada sentEnvironment Minister Jim Prentice toWashington earlier in March to meet withtop U.S. officials.

He ended his two-day visit by insist-ing the two governments will worktogether to develop clean energy andreduce emissions, including the negotia-tion of an international accord at the cli-mate change talks in Copenhagen in

December.But Prentice also said Canada is not prepared to

pay an unreasonable price as the new Obamaadministration sets its sights on climate change

JIM PRENTICE

$15.3 billion for Alaska?New study projects state revenue, employment from AK offshore oil and gas

By ALAN BAILEYPetroleum News

Shell has long championed the poten-tial economic benefits to Alaska of

oil and gas development on the state’souter continental shelf, a region that thecompany sees as strategic to its futureArctic plans.

And a new Shell-commissioned studyby Northern Economics and the Instituteof Social and Economic Research, University ofAlaska Anchorage, has concluded that bringing oiland gas fields into operation in the Beaufort Sea,Chukchi Sea and North Aleutian basin would sub-stantially swell the coffers of state and local gov-ernment treasuries, as well as stem the decline in

Alaska oil and gas production and creat-ing thousands of new jobs.

All development consideredOn March 9 when announcing publi-

cation of the study report, Shell’s Alaskageneral manager Pete Slaiby said that thestudy considered the potential impact ofall Alaska OCS oil and gas development,not just that of Shell. However, Slaibyalso commented on the scale of Shell’s

Alaska program.“The investment we have already made in

designing infrastructure, gathering seismic data,(doing) baseline scientific studies and acquiring

PETE SLAIBY

see SOLUTIONS page 18

Oklahoma’s not doin’ fine —OK? ANGDA pondering lifeafter Harold? Yes, Isenberg’soptimistic and ExxonMobil isspending more money, not less

HAROLD HAMM HAS LOCKED horns with Mexico,Venezuela, Saudi Arabia and Iraq.

Now he’s doing battle with Canada.The U.S. producer is heading up a group of Oklahoma oil-

men, operating under the name Domestic Energy Producers’Alliance.

They have persuaded their state’sAttorney-General Drew Edmondson toinvestigate whether Canada is illegallydumping crude in the United States.

For Hamm, ranked 42nd on Forbes’ listof richest Americans last year, this is famil-iar territory, it comes 10 years after he led ahandful of drillers in suing the LatinAmerican and Middle Eastern quartet,accusing them of selling crude at pricesbelow production costs.

His effort then fizzled, although it threatened to turn into aninternational trade dispute.

Hamm, whose efforts this time are aimed at oil sands pro-duction, said Oklahoma producers are getting less for their oilthan it’s worth because of the alleged Canadian dumping.

He said that if Canada adds another 1.5 million barrels perday from the oil sands to the 2.2 million bpd it already shipsinto the U.S. that “would be a disaster.”

Hamm estimated that Oklahoma, whose output is about200,000 bpd, received 300,000 bpd of synthetic crude fromCanada at the Cushing supply hub.

He claims to have backing from producers in eight other

see STUDY page 22

see INSIDER page 19

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

2 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

14 More satellites to come on at Alpine

West North Slope development discussed by both fieldpartners ConocoPhillips and Anadarko at analyst meetings in early March

5 Alberta gets mild applause for changes

Some small operators say changes will help; analysts say government package not enough; big independents still cutting budgets

NATURAL GAS

12 Drift River Terminal ready for anything

Following Redoubt Volcano eruptions in ’89, ’90 the oilterminal has bolstered defenses against a natural disaster

10 Armstrong prepping supply contract

Successful test well at North Fork means issue of gas pricing will return before state regulators; company asking for $7 to $10

FINANCE & ECONOMY

PIPELINES & DOWNSTREAM

SAFETY & ENVIRONMENT

LAND & LEASING

EXPLORATION & PRODUCTION

OIL PATCH INSIDER

ALTERNATIVE ENERGY

ASSOCIATIONS

GOVERNMENT

1 Oklahoma’s not doin’ fine — OK?

3 Alaska - Mackenzie Rig Report

6 MGM explains last year’s dry hole costs

4 AAEP to hear Phelps on land decisions

19 Heinze tells ANGDA board to start looking

19 Nabors optimistic in challenging times

15 Declining economy hits renewable fuels

21 ExxonMobil bucking trend, sticks to investment plandespite recession, lower prices

16 Chevron cutting production growth forecast

16 New alliance for low-impact drilling

17 Decision on Shell exploration withdrawn

17 Arctic sea ice extent approaches maximum

17 Oklahoma investigates Cushing oil glut

19 Potential Alaska state and federal oil and gas lease sales

11 What role for ANGDA in bullet line?

7 State, carriers settle tariff dispute

6 Up and down for BP in 2008

9 House committee moves ACMP rewrite

5 DNR asks for new North Slope lease sale information

4 Energy Council provides entry to D.C.

7 Interior to hold April Anchorage meeting

7 EIA lowers 2009-10 crude price forecast

8 Oil company earnings chart

ON THE COVERPERL files Chapter 11

Citing falling oil prices and big debt load, Pacific Energy files for bankruptcy

Swimming against US tide

Canada hammers home belief technology solutions beat cap-and-trade

$15.3 billion for Alaska?

New study projects state revenue, employment from AK offshore oil and gas

SIDEBAR, Page 22: Itta: Sounds good, but is it too good?

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colvilleinc.comFuel Services I Solid Waste Services I Industrial Supplies

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Serving the entire North SlopePrudhoe Bay, Alaska

PETROLEUM NEWS • WEEK OF MARCH 15, 2009 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay 2-3OB/ME-01 BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 2N 305A ConocoPhillipsDreco 1000 UE 16 (SCR/TD) Badami B1-28, moving SAVANTDreco D2000 UEBD 19 (SCR/TD) Alpine CD3-117 ConocoPhillipsOIME 2000 141 (SCR/TD) Grandview 1, mobilizing ConocoPhillipsTSM 7000 Arctic Fox #1 Gubik #4, mobilizing Anadarko

Arctic Wolf #2 Dew Line 1, mobilizing UltraStar

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES Prudhoe Bay B-10A BPMid-Continental U36A 3-S Milne Point MPL-40 BPOilwell 700 E 4-ES (SCR) Prudhoe Bay DS 09-34 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay MPF-96 BPDreco 1000 UE 9-ES (SCR/TD) DS 03-32B BPOilwell 2000 Hercules 14-E (SCR) Stacked AvailableOilwell 2000 Hercules 16-E (SCR/TD) AvailableOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Under modification ExxonMobilAcademy AC electric Canrig 105-E (SCR-TD) Chandler #1 AnadarkoAcademy AC electric Heli-Rig 106-E (SCR/TD) White Hills Bluebuck6-7-9 Chevron

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site DS5-27B BPSuperior 700 UE 2 (SCR/CTD) Milne Point Drill Site MP 7-33A BPIdeco 900 3 (SCR/TD) Kuparuk Well IJ-137 ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOIME 1000 19-E (SCR) Oooguruk ODSN-36 Pioneer Natural ResourcesOIME 2000 245-E Oliktok Point OP04-P07 ENIOilwell 2000 33-E Northstar NS-33A BP

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Stacked out on Westside of Cook Inlet

near Tyonek Aurora Gas

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Shut down awaiting permit Marathon

Nabors Alaska DrillingContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Kenai SLU 41-33RD Chevron

Rowan CompaniesAC Electric 68AC (SCR/TD) On site at Cosmopolitan Pioneer Natural Resources

Cook Inlet Basin – Offshore

Chevron (Nabors Alaska Drilling labor contract)428 Rig shut down by operator request Chevron

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

Kuukpik 5 Tyonek Platform A-15 Completion ConocoPhillips

Mackenzie Rig StatusCanadian Beaufort Sea

SDC Drilling Inc.SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available

Mackenzie Delta-Onshore

AKITA EqutakModified National 370 64 (TD) Drilling MGM Energy Group

Central Mackenzie Valley

Akita/SAHTUOilwell 500 51 Racked in Norman Wells, NT BG Canada

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of March 12, 2009.

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 Marti Reeve

Baker Hughes North America rotary rig counts*March 6 February 27 Year Ago

US 1,170 1,243 1,802Canada 299 394 623Gulf 50 51 60

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:

JUD

Y P

ATR

ICK

By KRISTEN NELSONPetroleum News

Alaska legislators were in Washington,D.C., the first week of March for

Energy Council — and for an opportunityto lobby elected officials and regulatorsabout Alaska’s energy issues, particularlythe gas line.

Since the new administration isDemocratic, Democrats scored big: Ameeting with Senior Advisor Pete Rousein the White House.

Rep. Les Gara, D-Anchorage, said inhis constituent e-mail that he andAnchorage Sens. Hollis French and BillWielechowski, both AnchorageDemocrats, arranged the meeting to talkabout the Alaska gas pipeline.

“It’s a major part of President Obama’s

long-term energyplan,” Gara said.“It’s not clear that thestate can make thisproject happen onour own,” becausethe North Slope pro-ducers can block theproject by refusing tosell their gas into apipeline. The statehas tools to fight back, he said, but pres-sure from the federal level would help.

“Pete Rouse sounded fascinated, hiscomments were thoughtful, and heappeared to appreciate the Alaska insight.I really like it when I get to see bright peo-ple running the country,” Gara said.

French and Wielechowski described themeeting in a March 6 Senate Bipartisan

Majority Coalitionpress call from D.C.

“ P r e s i d e n tObama has spokenabout the natural gaspipeline on the cam-paign trail; he’s spo-ken about it sincethen; it’s on theirradar,” French said,and they were able to

spend half an hour “down the hall from theOval Office talking about the gas pipelineand how important it is to our economicfuture.”

Wielechowski said the Obama adminis-tration hasn’t decided “exactly what spe-cific steps they can take in Congress to tryto make the gas pipeline more viable, orhappen sooner or happen ... more on ourtimeline than the producers’ timeline.”

But it was “extremely encouraging tobe able to speak to someone, to bring himup to speed on some of the hearings thathappened last summer” and on some of thedetails on rates of return and tariffs.

“This project is our lifeline; this is whatwe need to keep our state viable in the next20 years and it was just thrilling to be ableto discuss it with someone who has the earof the president,” Wielechowski said.

Notes from the FERCSenate President Gary Stevens, R-

Kodiak, said legislators met with thestate’s congressional delegation, with JohnKatz from the governor’s Washingtonoffice, with Federal Energy RegulatoryCommission commissioners and staff andwith Drue Pearce, the federal coordinatorfor Alaska Natural Gas TransportationProjects.

Sen. Lesil McGuire, R-Anchorage, saidthat when meeting with FERC commis-sioners the group learned that FERC feltthey have exclusive jurisdiction over theKenai liquefied natural gas plant (see storyin Feb. 1 issue of Petroleum News).

McGuire said legislators had heardrumors and found out when visiting FERC

that the regulator had sent a letter earlier inthe year “letting the Kenai plant know thatthey intended under the 2005 Energy(Policy) Act to assert control over LNG,over that LNG plant.”

There is a section in the Energy PolicyAct talking “about pipes leading into andfeeding LNG facilities also being undertheir jurisdiction,” she said, so there is anopen question of whether an in-state gaspipeline selling to an LNG plant could alsobe under FERC regulation, rather thanunder the Regulatory Commission ofAlaska.

She said the Legislature is going to askFERC for an advisory opinion on whetherFERC would assert control over an in-state gas pipeline which also provided gasto an LNG facility.

A public works project?Rep. John Coghill, R-North Pole, said

at a House majority press availabilityMarch 9 that he was not encouraged aboutthe prospects for an Alaska gas line afterthe trip to Washington for the EnergyCouncil.

He said because of the amount of natu-ral gas that gas shales will be supplying tothe Lower 48 the price is expected to staylow, so financing for the line will be understress. Information presented on Lower 48gas shale production included a need formore pipelines to move that gas to marketand the tricky part for Alaska is how eco-nomically those lines can be built, Coghillsaid.

While the Alaska gas pipeline is a pri-ority for the new administration, Coghillsaid he was worried that the federal gov-ernment would be tempted to turn it into apublic works project.

Asked about possible federalization at aMarch 10 Senate Bipartisan MajorityCoalition, senators were quick to say theyhad not heard any suggestion of that whilein Washington.

Wielechowski said that the AlaskaNatural Gas Transportation Act allows the

4 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

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www.PetroleumNews.com

CORRECTIONA story in the March 8 issue of Petroleum News omitted the Minerals

Management Service from a list of Department of the Interior agencies in Alaska.

ASSOCIATIONSAAEP to hear Phelps on land decisions

The Alaska Association of Environmental Professionals will hear a talk March16 by Bruce Phelps on “How the State of Alaska makes decisions regarding itsland.”

Phelps is chief of the resource assessment and development section of theAlaska Department of Natural Resources.

The meeting is at 11:45 a.m. at the BP Energy Center. —PETROLEUM NEWS

� N A T U R A L G A S

Energy Council provides entry to D.C.Alaska legislators visit White House, FERC, Interior, Congress while in Washington; push gas line issues, hear concerns

HOLLIS FRENCH LESIL MCGUIRE

see COUNCIL page 8

By GARY PARKFor Petroleum News

The Alberta government got a nicewarm shower of praise where it was

most expected and a lukewarm dousingwhere it was also expected after rolling outits latest attempt to revive exploration anddevelopment activity.

In dangling a bundle of royalty breaksworth about C$1.5 billion, primarilybefore the small and midsized sector, thegovernment was told that some juniorsmight even raise their capital budgets thisyear.

But in offering to impose Alberta’s low-est royalty rate of 5 percent over the firstyear of production from any well thatcomes onstream during the 12 monthsstarting April 1, Alberta fell short of uni-versal acclaim.

Even the Small Explorers andProducers Association of Canada —whose members are best-positioned tobenefit from the incentives — said themeasures leave unresolved “some signifi-cant long-term issues that we hope can beaddressed during the competitivenessreview the government said it wants toengage in this year.”

“We would like the results of thatreview to place Alberta among the leadersin attracting oil and gas investment.”

Some response positiveOn the positive side, Canext Energy

said the stimulus plan will have an “imme-diate positive impact” on its operations andcash flow, noting that one horizontal wellwill be brought onstream at the 5 percentroyalty instead of the 25-30 percent at C$5per thousand cubic feet of gas under thecurrent royalty framework.

Canext also said the drilling credit ofC$200 per meter will reduce its findingand development costs to C$1.72 per thou-sand cubic feet of Montney gas from C$2in 2008 and for Sweeney Triassic oil toC$8 per barrel from C$10.

Berens Energy Chief Executive OfficerDan Botterill said his company will nowhave the ability to drill more wells thanwere otherwise possible under the current

gas prices.He said that Berens will probably boost

the C$28 million it budgeted for 2009,even if gas prices remain around C$5.

Glenn Carley, executive chairman ofGalleon Energy, said his company is plan-ning a “significant” increase in drillingunder the program and is hopeful theincentives will improve his ability to bor-row more from banks.

Peter Knapp, president of Bryan MillsIradesso, which tracks junior companies,said the program will do little for compa-nies that are already in a financial bind,noting that only those in good financialhealth will be able to take advantage of theprograms.

AJM Petroleum Consultants said thesteps taken are not sufficient to revive theindustry in a climate where companiesmust base drilling decisions on weak com-modity prices, a lack of access to capitaland high drilling costs.

Peter Doig, an analyst at Scotia Capital,listed Galleon, Birchcliff Energy, DelphiEnergy, Daylight Resources Trust andNAL Oil & Gas Trust as companies thatstand to benefit, but Compton Petroleum,despite holding assets in the sweet spot forthe incentives, lacks the balance sheet toexploit the opportunity.

Doig said in a report that “further actionwill be required to attract capital back tothe mature Alberta basin. We see the gov-ernment having to take further stimulusaction eventually (sooner than later).”

Big independents not affectedAt the upper end of the spectrum, big

independents such as Canadian NaturalResources and Talisman Energy said theroyalty and drilling incentives will notaffect their capital programs, despite somesigns that upstream costs are shrinking.

Canadian Natural President Steve Lautsaid that given commodity prices and costs“all but the very best prospects are margin-al.”

He said gas prices must recover to therange of C$6-$7.50 per thousand cubic feetbefore his company will ramp up drilling.

But Canadian Natural has lopped anoth-er C$800 million off its 2009 capital

spending, reducing its budget to C$3.2 bil-lion from the C$4 billion anticipated lastNovember and the C$7 billion spent in2008 and cautioned that another C$1 bil-lion could be removed if commodity pricesdon’t improve.

Talisman Chief Executive Officer JohnManzoni offered a glimmer of hope whenhe told analysts some rig rates in NorthAmerica are falling by 30 percent or more,adding that when rig contracts come up forrenewal he no longer expects to facedemands for increases.

He also said there are signs of 15-20percent reductions in bidding and re-bid-ding on some capital projects because of asofter market.

Of the 37 Canadian producers who haveupdated their spending plans, field activi-ties are headed for a C$16.6 billion cut-back from last year’s level of C$49.9 bil-lion.

Underscoring the Alberta government’sconcern about the drift in drilling this year,the province issued 629 new well licenses

in February (the lowest seen for Februarysince 1992). For the first two months of2009, the province approved 1,072 gas-tar-geted permits (more than 50 percent downfrom last year), while oil sands evaluationpermits plunged to 725 from 1,663.

The latest land sale on March 4 gener-ated C$10.588 million, raising the year-to-date total to C$52.92 million comparedwith C$168.32 million last year.

Gas prices, which hit a six-year low ofUS$3.845 per million British thermal unitson March 9, are the biggest drag on activi-ties.

Martin King, an analyst at First EnergyCapital, does not rule out a further down-ward drift, possibly through the US$3.50threshold.

“There’s just too much gas in the sys-tem and we’re coming to the end of theheating season,” he said.

King said so many small and midcapplayers are struggling “just to make endsmeet, let along dig up cash to go out anddrill wells.” �

PETROLEUM NEWS • WEEK OF MARCH 15, 2009 5

I want in!

� G O V E R N M E N T

Alberta gets mild applause for changesSome small operators say changes will help; analysts say government package not enough; big independents still cutting budgets

LAND & LEASINGDNR asks for newNorth Slope leasesale information

The Alaska Department of NaturalResources’ Division of Oil and Gas isasking for new information on propos-als to offer all available acreage in NorthSlope and North Slope Foothills areaw-ide oil and gas lease sales in 2009.

The call is for information that hasbecome available since the most recentbest interest finding for the lease salearea. The North Slope areawide bestinterest finding was issued in July 2008;the Foothills finding was issued inJanuary 2002.

The call for new information closesMay 4; a supplement to the best interestfinding or a decision of no substantialnew information is scheduled for July;the sales are proposed for October.

—PETROLEUM NEWS

6 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

UNITED STATES DEPARTMENT OF THE INTERIORBUREAU OF LAND MANAGEMENT

ANNOUNCEMENT NOTICE FOR COMMENTS ON

PROPOSED NOTICE TO LESSEES (OIL AND GAS)Comment period open through April 15, 2009

UNITED STATES DEPARTMENT OF THE INTERIORBUREAU OF LAND MANAGEMENT

Notice to Lessees/Operators of Onshore Federal and Indian

NTL 2009-1Standards for the Use of Electronic Flow Computers Used On

Differential Type Flow Meters For Gas Measurement

TO SUBMIT COMMENTSE-mail:

Mail:

To view a copy of the proposed NTL:

To view industry comments on the proposed NTL

For information regarding this proposed NTL:

EXPLORATION & PRODUCTIONMGM explains last year’s dry hole costs

MGM Energy, the lone current explorer in Canada’s Arctic, added a net loss ofC$100.16 million last year to the C$62.33 million it reported in 2007, but paintsan upbeat picture of its activities.

Company President Henry Sykes said in a statement that MGM, unlike mostCanadian juniors, uses “successful efforts accounting rather than full costaccounting,” which allows dry-hole costs to be capitalized.

Under that method, the costs of dry holes are written off as they occur.But Sykes noted that “writing something off does not mean it’s not a discov-

ery or that you wouldn’t produce it in the right circumstances.”

Langley discovery written offHe said costs of the Langley E-07 discovery last year were written off, but “we

still found a commercial quantity of hydrocarbons” which were sufficient toobtain a Significant Discovery License from the federal government.

Sykes said the fact that, under “suc-cessful efforts,” MGM can’t justify keep-ing the Langley well on the books at Dec.31 gas prices does not mean that if apipeline is built from the MackenzieDelta the well would not be tied in.

The northern explorer reported dry-hole costs of C$74 million for 2008 and C$26.7 million in exploration expenses,hiking the net loss despite a C$22 million gain on future income taxes.

Capital spending last year totaled C$95.86 million down from C$244.26 mil-lion in 2007.

Sykes said MGM is “very pleased” with results of Ellice J-27, its first well ofthe 2008-09 winter program.

The last of the three wells, Ellice A-25, was spud March 2 and should be com-pleted by late March or early April.

MGM will then be able to provide further updates on Ellice A-25 and estimatethe resource size of the Ellice J-27 find, which he said is sufficient to justify astandalone development.

Sykes reported that Ellice A-25, being drilled by Akita Drilling, has reached adepth of about 2,500 feet in pursuit of gas targets in the range of about 5,900-6,560 feet.

MGM management said that at current gas prices, its Mackenzie Delta dis-coveries would be uneconomic even if a Mackenzie Valley pipeline had beenbuilt.

—GARY PARK

Sykes said MGM is “verypleased” with results of ElliceJ-27, its first well of the 2008-

09 winter program.

� F I N A N C E & E C O N O M Y

Up and down for BP in 2008Alaska revenues and taxes rise while profits and production fall

By ERIC LIDJIPetroleum News

BP Exploration (Alaska) Inc. earned$1.95 billion last year, down 21 per-

cent from 2007 even as revenues increased15 percent, the result of a progressive pro-duction tax paired against record high oilprices and declining production from agingNorth Slope oil fields.

In year-end financial documents filedwith the U.S. Securities and ExchangeCommission on March 4, the Alaska sub-sidiary of London energy giant BP P.l.c.reported total annual revenues of $7.76 bil-lion in 2008, up from $6.59 billion in 2007and $6 billion in 2006.

The company reported net profits ofsome $2.5 billion in 2007 and $2.4 billion in2006.

BP paid $3.3 billion in taxes in Alaskalast year, a 36 percent increase from theroughly $2.1 billion paid in 2007. The com-pany paid nearly $1.7 billion in total taxes in2006. Of the total taxes the company paidlast year, some 71 percent, or $2.3 billion,came in the form of production taxes, upfrom about $1 billion in 2007 and $665 mil-lion in 2006.

The consecutive annual jumps can likelyboth be traced to a revised production taxcode pushed by the governor and passed bylawmakers in late 2007, but for different rea-sons.

The jump between 2006 and 2007 ismost likely a result of an increase to thebasic tax rate on profits from producing oil,while the doubling between 2007 and 2008most likely came from a progressive featurethat increases the tax rate as the price of oilincreases.

ConocoPhillips recently reported similarincreases in Alaska production taxes.

Oil price critical factorIf oil prices stay below $50 a barrel

through the rest of the year, it stands to rea-son the tax payments of BP andConocoPhillips would drop significantlybetween 2008 and 2009.

The delivered price of Alaska NorthSlope crude oil stayed above $90 a barrel formost of 2008 before dropping to a low of$26 a barrel. It is currently around $48.50per barrel. BP reported an average delivered

price of $98.86 per barrel for Alaska NorthSlope crude oil in 2008, up from $71.68 perbarrel in 2007 and $63.57 per barrel in 2006.

The profit and taxation figures BP is nowreporting for 2007 and 2006 don’t match thefigures the company reported at the time,showing a larger profit and smaller tax bur-den.

BP shifted $26 million in 2007 taxes and$238 million in 2006 taxes from BPExploration (Alaska) to “Other sub-sidiaries,” a change made “to reflect the allo-cation of tax changes between BPExploration (Alaska) Inc and other Alaskansubsidiaries in the BP group.”

Internationally, the BP Group earned$21.7 billion in net profits on $367 billion intotal revenues, compared to $21.2 billion inprofits on $291.4 billion in revenues in2007.

ConocoPhillips, the leading oil and gasproducer in Alaska, earned $2.3 billion inprofit on $9.2 billion in revenue in Alaska in2008 and paid $3.4 billion in non-incometaxes.

Production decliningBP Exploration (Alaska) produced

197,000 barrels of liquids per day on aver-age in 2008, down 5.7 percent from 209,000bpd in 2007 and down 12 percent from224,000 in 2006.

The company saw a 2.7 percent produc-tion decline at Prudhoe Bay, a 3.6 percentdecline at Milne Point, a 7.7 percent declineat Kuparuk and a 21.4 percent decline atNorthstar.

BP produced 97,000 barrels of liquidsper day in the Lower 48 last year, down 10percent from 2007, and 244,000 bpd in theGulf of Mexico, up 19.6 percent from 2007.

BP Exploration (Alaska) produced 41million cubic feet of gas per day last year,down 25 percent from 55 million cubic feetper day in 2007 and 38.8 percent from 67million cubic feet per day in 2006.

BP operates Prudhoe Bay and 12 otherNorth Slope oil fields, and holds an interestin six other oil fields. The company ownsseveral North Slope pipelines and the largestshare of the trans-Alaska oil pipeline. Thecompany employs some 2,000 people inAlaska. �

PETROLEUM NEWS • WEEK OF MARCH 15, 2009 7

� P I P E L I N E S & D O W N S T R E A M

State, carriers settle tariff dispute Alaska reserves right to pursue recovery of strategic reconfiguration costs if FERC ruling is overturned, from 2007 and 2008 rates

By ROSE RAGSDALEFor Petroleum News

The State of Alaska told the Federal EnergyRegulatory Commission March 11 that it was close

to settling its differences with owners of the trans-Alaskaoil pipeline regarding claims that the carriers incorrectlyincluded the costs of a strategic reconfiguration project ininterstate rates charged shippers in 2005 and 2006.

Attorneys representing the state said in an 11-page fil-ing that they were persuaded by the argument the trans-Alaska oil pipeline’s five carriers made in a Feb. 12 filing.BP Pipelines (Alaska) Inc., ConocoPhillips Alaska,ExxonMobil Production Co., Unocal Pipeline Co. and

Koch Pipelines (Alaska) LLC argued that the commis-sion’s decision in the tariffs case June 21, commonlyreferred to as Opinion No. 502, rendered moot the state’scontention that the carriers had overcharged in their rate-setting when they included the strategic reconfigurationcosts.

Rates rolled backIn Opinion No. 502, FERC essentially rolled back the

interstate shipping rates charged in 2005 and 2006 to 2004levels, thereby nullifying the effects of increases levied forevery reason, including strategic reconfiguration projectcosts.

While the state acquiesced to the carriers’ arguments, it

also filed a stipulation to the resulting settlement March11, telling the commission that it reserved the right toresume pursuit of claims for the strategic reconfigurationcosts included in the 2005 and 2006 tariffs if Opinion No.502 is overturned in any subsequent challenge. The statealso stipulated that it reserved the right to continue pursu-ing claims for strategic reconfiguration costs included inthe 2007 and 2008 interstate rates charged by the carriers.

State of Alaska attorneys also noted that all parties tothe long-running interstate tariffs case, including AnadarkoPetroleum Corp., Tesoro Corp. and Tesoro Alaska Co.,Arctic Slope Regional Corp. and Petro Star Inc., Flint HillsResources Alaska LLC, Williams Alaska Petroleum Inc.,and FERC’s trial staff, agreed to the stipulation. �

� F I N A N C E & E C O N O M Y

EIA lowers 2009-10 crude price forecastPETROLEUM NEWS

West Texas Intermediate averaged$100 per barrel in 2008. The price

is expected to average less than half of thatin 2009, as the global economic contractioncontinues to depress energy demand, theU.S. Department of Energy’s EnergyInformation Administration said March 10.

EIA is now projecting a WTI average of$42 per barrel this year and $53 in 2010 —both averages down from last month’sforecast, the agency said in its short-termoutlook.

The U.S. economic downturn “is theprincipal cause for the decline in domesticnatural gas consumption, particularly in theindustrial sector — where it is projected tofall by 6 percent in 2009,” leading to pro-jected lower natural gas prices. EIA saidthe Henry Hub natural gas spot price is pro-jected to decline from an average of $9.13per thousand cubic feet in 2008 to some

$4.70 per mcf in 2009, increasing to anaverage of almost $5.90 in 2010.

Relative stabilityThe global oil market has been relative-

ly stable since the beginning of 2009, EIAsaid, a situation which the agency expectsto continue through most of the year, “untileconomic recovery in the United States andelsewhere leads to a rebound in oil demandgrowth.”

EIA said if economic growth rebounds

sooner than expected in its modeling, therecould be stronger-than-expected growth,outpacing production, resulting in risingprices.

But upward movement in oil prices“will be muted by the relatively high levelsof commercial inventories” in countrieswhich are members of the Organization forEconomic Cooperation and Development,along with surplus production capacity inmembers of the Organization of PetroleumExporting Countries.

EIA expects annual world oil consump-tion to drop by almost 1.4 million barrelsper day this year, a 200,000-bpd largerdecline in world consumption than theagency projected last month and down 3million bpd from its September 2008 fore-cast.

Non-OPEC supply is expected toremain flat over the next two years, follow-ing a 300,000-bpd decline last year.

OPEC is reported to have trimmed pro-duction significantly over the past severalmonths, down an estimated 1.1 million bpdin the fourth quarter of last year, to 30.6million bpd. An OPEC production declineof an additional 2 million bpd is expectedin the first quarter of this year, down to 28.6million bpd, the lowest first-quarter levelsince 2003.

EIA expects that OPEC will have sur-plus production capacity averaging 4 mil-lion to 5 million bpd over the next twoyears, which should reduce the likelihoodof sharp price increases.

“There remains a risk, however, thatfinancial constraints and prospects ofweak demand could lead OPEC membersto further delay expansion programs,reducing future surplus capacity and set-ting the stage for higher prices once theeconomic recovery is under way,” theagency said. �

EIA said the Henry Hub naturalgas spot price is projected to

decline from an average of $9.13per thousand cubic feet in 2008 to

some $4.70 per mcf in 2009,increasing to an average of almost

$5.90 in 2010.

LAND & LEASINGInterior to hold April Anchorage meeting

Secretary of the Interior Ken Salazar said March 11 that one of four region-al public meetings on Interior’s findings on outer continental shelf energyresources and potential environmental impacts will be held in Anchorage April14.

No times were given for the meeting, an all-day affair scheduled for theDena’ina Convention Center.

The meeting will include opening remarks by Salazar followed by a presen-tation of a report being prepared by Interior on offshore energy resources. Thedepartment said the rest of the day’s meeting will be devoted to hearing fromelected officials and public and private interests.

The meetings are part of a strategy Salazar announced Feb. 10 for develop-ing a new comprehensive energy development plan for the U.S. OCS whichincluded: extending the public comment period 180 days to Sept. 21 on the draftfive-year OCS leasing proposal prepared by the last administration; a report byMarch 30 from Minerals Management Service and U.S. Geological Survey sci-entists on conventional and renewable offshore energy resources; regionalmeetings to review report findings and gather input; and expediting renewableenergy rulemaking for the OCS required under the Energy Policy Act of 2005.

Other meetings are April 6 in Atlantic City, N.J.; April 8 in New Orleans, La.;and April 16 in San Francisco.

—PETROLEUM NEWS

8 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

Company symbol earnings % liquids % gas %

ExxonMobil XOM $7,820 -33 2,472,000 –2 9,849 -5

RD/Shell RDS-A -$2,810 — 1,772,000 –6 9,531 +4

Chevron CVX $4,895 -0- 1,707,000 -2 4,813 -5

Total TOT -$1,018 — 1,434,000 –6 5,127 -2

ConocoPhillips COP -$31,764 — 1,442,000* +3 5,254 +2

Eni E -$1,126 — 1,079,000 +3 4,449 +1

Occidental OXY $443 –69 478,000 +3 873 +12

Can. Natural CNQ.TO C$1,770 +122 309,570 -8 1,427 -10

Marathon MRO -$41 — 249,000 +31 1,006 +2

Talisman TLM C$1,202 +83 222,132 +2 1,200 +4

Imperial IMO C$660 -26 250,000 -6 297 -23

Petro-Canada PCZ -C$691 — 292,000 +1 699 -4

XTO XTO $351 -24 78,979 +48 2,166 +30

Pioneer PXD -$65 — 51,206 +14 400 +5

Newfield NFX -$789 — 34,400 +50 488 +16

EOG EOG $462 +29 72,500 +49 1,664 +11

Swift SFY -$452 — 18,444 -14 54 -6

Anadarko APC $824 +211 203,000 -15 2,197 +9

Devon DVN -$6,816 — 230,200 +4 2,697 +10

Husky HSE.TO C$232 -89 263,200 -0- 571 -8

Apache APA -$2,946 — 252,478 -4 1,539 -14

Suncor SU.TO -C$215 — 243,800 -3 213 -7

Nexen NXY.TO -C$181 — 199,700 -9 184 -30

Chesapeake CHK -$866 — 31,640 +4 2,178 +4

StatoilHydro STO $294 -67 1,095,000 –1 4,572 +7

EnCana ECA $1,077 -0- 136,000 -0- 3,858 +4

BP BP -$3,344 — 2,460,000 -0- 8,613 +3

Earnings from Petroleum News Top 25Earnings fourth quarter 2008 • Change from fourth quarter 2007

Liquids production second fourth 2008 • Change from fourth quarter 2007Natural gas production fourth quarter 2008 • Change from fourth quarter 2007

Liquids production in barrels per day, including oil sands. Natural gas production in millions ofcubic feet per day. *Includes Lukoil investment

Top companies chosen based on exploration spending and commitment to Alaska and Canada

OIL COMPANY EARNINGS � F I N A N C E & E C O N O M Y

Talisman to spend$8M in Alaska in ’09Spending focused on finding prospects in NPR-A, announcementfollows major seismic shoot in 2008, no plans to drill this year

By ERIC LIDJIPetroleum News

D espite a decision not to drill until atleast 2011, Talisman Energy Inc.

plans to spend $8 million in Alaska thisyear “on identifying prospects and leads,”part of a $660 million exploration pro-gram, according to a U.S. Securities andExchange Commission filing.

The large Canadian-based independ-ent, which operates in Alaska through itssubsidiary FEX L.P., considers Alaska tobe among a group of key explorationareas listed as “basins that have the poten-tial to create future core areas that canrenew the company.”

Other areas of future exploration arethe Barents Sea in Norway, Peru andColumbia, offshore Indonesia, Vietnamand the Kurdistan region of Iraq. Thecompany considers its “existing coreareas” to be the United Kingdom, theNorth Sea in Norway and Malaysia.

Those two groups come from a com-panywide strategy review unveiled inMay 2008.

FEX holds more than 1 million netacres in the National Petroleum Reserve-Alaska, most west of Teshekpuk Lake,making the company one of the largestleaseholders in the state.

Talisman’s $660 million explorationprogram for 2009, which includes up to24 wells, is part of a $4 billion capitalprogram, cut from $5.8 billion inresponse to falling oil prices.

Talisman crafted the 2009 budget on

the assumption of oil prices around $40per barrel and natural gas prices around$5 per million British thermal units,President and CEO John Manzoni saidduring a conference call with investorsback in January.

Manzoni called the budget a “flexibleapproach to spending,” allowing the com-pany to either spend more or “dial back”if oil and gas prices are higher or lowerthan projected.

No drilling until 2011Talisman’s Alaska drilling venture is

promising, but also very expensive. The five exploration wells FEX has

drilled in the NPR-A are among the mostremote in Alaska, some more than 100miles beyond the existing North Slopeinfrastructure grid.

FEX put its exploration program onhold in 2007 while it considered where todrill next.

FEX spent $25 million last year shoot-ing 3-D seismic near Smith Bay, north-west of Teshekpuk Lake. Speaking at anindustry conference in Anchorage inFebruary 2009, John ‘t Hart, then-execu-tive vice president of global explorationfor Talisman, said the company neededtime to process the information gatheredfrom that seismic shoot.

“As a result we won’t expect to bedrilling either in 2009 or in 2010,” ‘t Hartsaid. �

federal government to step in and buildthe line if the state and producers don’tget it built. He said he didn’t hear anydiscussion of that happening, but saidbased on evidence from last year’s spe-cial session “the project is clearly eco-nomic and I do think that if gas is notcommitted to the project that I certainlywouldn’t rule out the federal govern-ment stepping in and facilitating thebuilding of a project.”

Sen. Bert Stedman, R-Sitka, saidboth projects, Denali and TransCanada,are on schedule to hold open seasons.

“We’ll know in probably 18 monthswhere we stand. The federal govern-ment is not just going to get up one dayand federalize that gas line,” he said.

Stedman said he was fairly confidentthat one of the proponents would have asuccessful open season “and then we’llhave the discussion on when we’regoing to have first gas and what kind ofinfrastructure improvements the statereally needs to get done and when.”

But with gas at less than four dollarsand a tariff around that range, and withLower 48 markets potentially beingflooded with shale gas and LNG, “weneed to keep our eye on the project at 15and 20 years out and not get wrapped upin the moment,” Stedman said.

Watch the FERCOther “heads up” came out of the

Washington trip. McGuire said to keep an eye out for

the appointment the White House makesto FERC, noting that there are now threeRepublicans and two Democrats andthere will soon be three Democrats andtwo Republicans.

Names being circulated indicatedthat the appointment would be anadministration insider, she said, so thenew commissioner will likely be “some-body who ... has the ear of the presidentof the United States.”

McGuire said they were told it wasunusual for a FERC appointment tocome directly from the president.

Another rumor that was circulating,she said, was that a federal reserve taxon gas in the ground is being consid-ered, “that this administration may tryto incentivize development of gas inthe ground on the federal land holdingsthat it has by implementing a reservestax.” �

continued from page 4

COUNCIL“This project is our lifeline; this

is what we need to keep ourstate viable in the next 20 years

and it was just thrilling to beable to discuss it with someone

who has the ear of thepresident.”

—Sen. Bill Wielechowski, D-Anchorage

By KRISTEN NELSONPetroleum News

T he Alaska Legislature has passed themidway point of this year’s session,

and bills reworking the Alaska CoastalManagement Program have yet to be heardin second committees of referral, whilebills introduced by Gov. Sarah PalinMarch 2 to expandthe authority of theAlaska Natural GasD e v e l o p m e n tAuthority and revisethe Alaska PipelineAct and the AlaskaR i g h t - o f - W a yLeasing Act have yetto see a first hearing.

A bill from thegovernor to create the Greater RailbeltEnergy and Transmission Corp., SenateBill 143 introduced March 9, also awaitsscheduling for a first hearing.

These are among the energy-relatedbills before the Legislature. This sessionends April 19.

House Rules Chair John Coghill, R-North Pole, said he expects legislators towork on policy this session that will allowthe state to meet immediate short-termenergy needs while working on long-termsolutions such as a Susitna dam — and thatdoesn’t necessarily make for fast action, hesaid at the House Majority press briefingMarch 9.

As for the governor’s in-state gas andutility bills, she may plan to discuss thosewith legislators over the interim, Coghillsaid, adding that if the bills are “mustpass” items, the governor hasn’t told legis-lators that. He advised watching what theadministration says in front of committees.If the bills are described as “must do” theyare “pretty heavy lifts” for one session, andbeing introduced in the middle of the ses-sion doesn’t make it any easier, Coghillsaid.

Work for next sessionSenate President Gary Stevens, R-

Kodiak, said March 10 in the Senatemajority press availability that he does notbelieve there is time to complete work onthe governor’s bills, given the timerequirements of the budget and the stimu-lus package.

The in-state gas bills and the Railbeltutilities are “big issues,” he said. “I per-sonally do not believe that we will com-plete those before the end of the session,but we’ll make progress on them and beready to begin again when we come backin January of next year.”

Sen. Charlie Huggins, R-Wasilla, theSenate Rules chairman, said he’d beenencouraged by members of the AlaskaPower Authority to “go about it very delib-erately” when working on the Railbelt util-ities bill because of the long-term impacts.The infrastructure consolidation approachhas to be thought through, he said: “I’mone of those that says we should talk aboutit; we should study it; we should hear fromthe experts,” but not try to move a billthrough quickly.

The governor’s transmittal letter forSenate Bill 143 says the bill would createthe Greater Railbelt Energy andTransportation Corp. and empower thecorporation “to plan for the financing,acquisition, construction, ownership andoperation of necessary electric power gen-eration and transmission assets and servic-

es that would be necessary to provide theRailbelt with adequate, reliable, safe andstable electric power and transmissionservices, at the lowest feasible long-termcost.”

ACMP substitute bill The House Community and Regional

Affairs Committee moved a committeesubstitute for House Bill 74, the Alaska

Coastal Management Program rewrite, outof committee March 3. The bill’s nextcommittee is House Resources, where nohearing was scheduled as of March 11.

Senate Community and RegionalAffairs moved a committee substitute ofSenate Bill 4, the companion legislation,on Feb. 6. The bill is scheduled to be heardin Senate Resources March 16.

House Community and RegionalAffairs made a final amendment to thecommittee substitute before passage,changing one of the requirements forenforceable policies from “supported byevidence, including contemporary or tradi-tional local knowledge, if the policies aremore specific than state or federal statutesor regulations” by eliminating the word“traditional” and replacing contemporarywith “scientific.”

Randy Bates, director of the Division ofCoastal and Ocean Management in theDepartment of Natural Resources, told thecommittee in testimony in February that

there was no definition of contemporarylocal knowledge in the ACMP:“Contemporary is a new term that wedon’t have in our current coastal programso I think that that would take a little bit ofeffort to define exactly what the intentionwas,” he said. Traditional local knowledgeis a term used in the coastal program,Bates said.

“We do consider traditional localknowledge; we consider local usage,which is another term of art within the reg-ulations.”

The committee had approved severalsponsor-suggested amendments Feb. 24,amendments designed to address somelack of clarity in the original bill as well asremove, where possible, objections to thebill.

DNR opposes the bill; Bates told thecommittee in February that the programwas designed as a state program with localinput; the bill proposes a program withlocal control, he said. �

� G O V E R N M E N T

House committee moves ACMP rewriteCoastal zone bill scheduled for second Senate committee; governor’s ANGDA, in-state gas bills not yet scheduled for hearings

On the WebSee previous Petroleum News coverage:

“State lays out plan for bullet line,” inMarch 8, 2009, issue atwww.petroleumnews.com/pnads/568762635.shtml

“ACMP at play in House,” in March 1,2009, issue atwww.petroleumnews.com/pnads/315484230.shtml

JOHN COGHILL

PETROLEUM NEWS • WEEK OF MARCH 15, 2009 9

By ERIC LIDJIPetroleum News

For Cook Inlet explorers, finding gas isonly half the battle. Selling it is the

other half.Following a successful test well in the

southern Kenai Peninsula last summer,Armstrong Cook Inlet seems to have wonthe former half, and is now gearing up forthe latter half.

“We are going to be moving forward inan attempt to get a gas contract with anyutility that we can … ,” Ed Kerr, vice pres-ident of land and business development forArmstrong, told the House ResourcesCommittee March 9. “It’s going to have aprice associated with it.”

The head’s-up is warranted: Over thepast decade, and increasingly over the pastfew years, contracts have led to intensedebates over how best to price natural gassupplies.

Armstrong drilled an onshore explo-ration well last summer east of AnchorPoint.

The North Fork 34-26 well found gas,and combined with test results from a pre-vious exploration well drilled nearby 44years ago, Armstrong is now “very com-fortable” the prospect holds between 7.5billion and 12.5 billion cubic feet of naturalgas reserves and said it is “realistic” theprospect could hold between 20 billion and60 billion cubic feet.

“There is some potential that it could besubstantially larger than that,” Kerr said.

The company won’t know for sure,though, without more wells and it won’tdrill more wells without a supply contract

guaranteeing a mar-ket to sell into at anagreeable price.

“Our intentionwould be to sell gasas soon as a pipelineis built,” Kerr said,estimating a pipelinecould be ready bylate 2010. The lengthof pipe depends onthe ultimate route the project takes, but“We have wells that are ready to producetoday,” Kerr said.

Another blow to cheap gas?Because of the limited market in

Southcentral Alaska, where only a few pro-ducers sell supplies to a few large buyers,there is no spot market for natural gas, andtherefore the Regulatory Commission ofAlaska has traditionally set prices, oftenafter great debate.

To make North Fork profitable, Kerrsaid Armstrong needs a price above $7 permillion British thermal units, but possiblyas high as $10, and needs the price to trackwith broader trends, so that if gas pricesrise and push up costs, the company canstill turn a profit.

The Henry Hub price for gas is around$4 per million Btu, down from highs near$13 last year. The average cost of Enstar’sgas supply contracts is around $9 per mil-lion Btu.

Consumers around Southcentral havehistorically enjoyed some of the lowest nat-ural gas prices in the country, the result ofhaving a prolific basin supplying an isolat-ed market.

But ongoing production declines fromthe largest of those Cook Inlet fields haverecently prompted policymakers to consid-er new ways to either spur new exploration

or replace supplies with natural gas fromsome other source most likely from muchfurther north.

Lawmakers and the public need to shiftfrom thinking about “cheap” gas suppliesto the cost of not having enough gas sup-plies to meet Railbelt demand, according toRep. Craig Johnson, an AnchorageRepublican and co-chair of the HouseResources Committee.

“Cheap gas may not ever be available tous again, but I certainly want to have gas,”Johnson said during the March 9 meeting.

That old question of costWhen finished, North Fork 34-26 is

expected to cost between $8 million and$10 million, which Kerr estimated was 400to 600 percent more expensive than a sim-ilar well drilled in the Permian basin inWest Texas. “It is more expensive here tofind gas,” Kerr said.

Companies frequently point to the high-er production costs in Alaska as a way tojustify the need for higher natural gasprices in Cook Inlet. The RCA keepsrejecting that argument, though, sayingcompanies haven’t put actual productioncosts on the record.

“So when people come and just statethat they need a price and don’t produceany evidence, what are we to do?”Commissioner Anthony Price said onMarch 11.

It’s been nearly eight years since theRCA last approved a gas supply contract inCook Inlet. Over the past few years, the

commission considered and ultimatelyrejected a pair of contracts Enstar NaturalGas made separately with ConocoPhillipsand Marathon.

The debate over production costs playeda large role in those deliberations. Becausethe RCA does not regulate producers, itcannot require the companies to provideinformation.

Asked by RCA Chair Robert Pickettwhether Armstrong would add to therecord in the future, Kerr said, “I think wewould do whatever we could to try to facil-itate the process.”

Sell gas north or south?Denver-based Armstrong arrived in

Alaska in 2000, taking a previously unseenstrategy on the North Slope. The companydrilled nearly a dozen exploration wells,but turned over its assets to other, largercompanies to ultimately bring the fieldsinto production.

That approach lead to the Ooogurukunit, which Pioneer Natural Resourcesbrought online last June, and theNikaitchuq unit, which Eni Petroleum iscurrently developing.

Armstrong acquired North Fork in late2007, starting a third chapter for the unit.

Standard Oil of California drilled theoriginal North Fork well in 1965, but neverdeveloped the field. Through the late 1990sand early 2000s, a series of smaller inde-pendents owned the field, but failed tosegue into sustained commercial produc-tion.

There have long been two likely optionsfor selling North Fork gas: north and south.

Armstrong could sell natural gas to thecity of Homer, about 10 miles to the south.

Homer predominately uses fuel oil forspace heating, and therefore would neednot only a transmission pipeline fromNorth Fork to the city, but also a new dis-tribution grid.

Or Armstrong could feed to the existingpipeline grid crisscrossing the Cook Inletregion, which would mean finding demandnot served by the existing, longer-termcontracts.

That option might also requireArmstrong to build a small feeder pipelinefrom North Fork to Anchor Point, an optionKerr said shouldn’t be a problem for thecompany.

Kerr mostly ruled out industrial cus-tomers like the liquefied natural gas exportfacility in Nikiski or the mothballedAgrium plant, focusing instead on possibleutility customers. �

10 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

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� N A T U R A L G A S

Armstrong prepping supply contractSuccessful test well at North Fork means issue of gas pricing will return before state regulators; company asking for $7 to $10

ED KERR

“So when people come and juststate that they need a price and

don’t produce any evidence, whatare we to do?”

—RCA Commissioner Anthony Price

JUD

Y P

ATR

ICK

By ERIC LIDJIPetroleum News

The Palin administration envisionsthe Alaska Natural Gas

Development Authority handling earlytechnical pieces of a renewed push tobuild an in-state natural gas pipeline.

“I see ANGDA as being the storehouseof the engineers and the technical peopleneeded to put this work together for thisproject,” Harry Noah, recently broughton as project manager for the pipeline,told the ANGDA board at a March 9meeting in Anchorage.

The work would include permittingand rights of way, helping to define thetariff on the pipeline and working on“interim measures” between now and thestart of the pipeline.

Much of the work over the next fourmonths involves comparing the possibleroutes for pipeline. ANGDA favors a pathdown the Richardson Highway toGlennallen, while Enstar Natural Gas, aprivate utility, favors a route down theParks Highway to Wasilla.

The “bullet line” proposed by Gov.Sarah Palin on March 3 would run froman undecided natural gas source, throughFairbanks and into Southcentral at a costof around $4 billion.

Following the announcement,ANGDA was unclear about its role in theproject.

The state plans to handle much of theearly work on the pipeline, including thekey challenge of aligning potential gasproducers with potential gas users, buthand over the actual construction andoperation, and presumably some financ-ing, to a private company.

Several agencies involvedANGDA will be one of several state

agencies involved in this early work,Noah said.

Noah envisions the Department ofNatural Resources would most likelyhandle the negotiations with natural gasproducers to get supply contracts, whilethe Department of Revenue could verylikely be called on to handle certain taxissues related to the venture.

Noah expects ANGDA would be“heavily involved” in choosing the pri-vate company, and would “represent thepublic” as the state transfers its work tothat company.

Enstar, which is weighing plans tobuild a nearly identical $4 billion bulletline into Southcentral, is the most likelycandidate, but Noah said, “Once youspend public money, you can’t hand it tosomebody. So it will essentially have tobe a bidding process.”

Noah doesn’t yet know whether orhow the state might be involved infinancing the bullet line. The state plansto decide whether to sanction the projectby June 2011. “We will know a lot morein a year. We will know a whole lot morein two years,” Noah said.

Noah expects ANGDA’s work wouldcost around $10 million. The originalbudget Palin sent to lawmakers late lastyear included $5 million for ANGDA, buta recent supplemental budget upped thatto $8 million, even as it cut funding forother efforts.

ANGDA Board Member Kate Lamalasked Noah how the new role would dif-fer from the work ANGDA is already

doing toward building a spurline and other natural gas proj-ects.

Noah said, “The governorhas turned her focus” to addressin-state gas, and the change isthat ANGDA now has “a wholebunch of new best friends hereall of the sudden.”

Over the next month,ANGDA plans to collect theprevious work on the bullet line, and crafta proposal showing the steps and costsassociated with accomplishing Palin’splan.

ANGDA contracts held upBecause it maintains relationships

with many contractors that work onpipelines, in many ways ANGDA is theideal state agency for handling the kindof work Noah described.

But half of ANGDA’s contractor

workforce has lapsed due toadministrative holds over thepast three months, ANGDAChief Executive Officer HaroldHeinze told the board.

“We face a very significantchicken and egg situation. Thevery help (Harry Noah) wants isnot under contract right now,”Heinze said.

Heinze said he received aletter from Pat Galvin, commissioner ofthe Department of Revenue, saying thehold on the contracts is because of aDepartment of Law review.

“I believe the hold has been becausethe administration has been shaping itswhole approach to the in-state issue,”Heinze said, saying he did not“begrudge” the administration for hold-ing contracts while it worked up an over-arching strategy for dealing with in-statenatural gas issues, but adding, “I believe

that we are at the moment to move for-ward and I think it’s a detriment to every-body if we don’t,” Heinze said.

Marcia Davis, deputy Revenue com-missioner and department liaison toANGDA, said she believed the hold wasto ensure ANGDA and Noah proceededin a “coordinated fashion.”

Heinze asked his board for permissionto issue the held contracts on his own,saying the statutes that created ANGDAgive the agency authority to act inde-pendently of the state.

Getting closer to propaneOne of the “interim measures” Noah

described could be propane distribution.ANGDA is nearing a deal to buy

propane from the North Slope, Heinzesaid.

“We have been in discussion with a

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PETROLEUM NEWS • WEEK OF MARCH 15, 2009 11

� N A T U R A L G A S

What role for ANGDA in bullet line?State sees public corporation handling early technical pieces; ANGDA weighs lapsed contracts, looks at North Slope propane facility

HAROD HEINZE

see ANGDA page 15

12 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

� P I P E L I N E S & D O W N S T R E A M

Drift River Terminal ready for anythingFollowing the Redoubt Volcano eruptions in 1989 and 1990 the oil terminal has bolstered defenses against a natural disaster

By ALAN BAILEYPetroleum News

O n Jan. 25 the Alaska Volcano Observatory raised thealert level for the Redoubt Volcano on the west side

of the Cook Inlet to code orange, indicating the strong pos-sibility of an eruption and triggering concerns about thepossibility of a cloud of volcanic ash heading for the pop-ulation centers on the Kenai Peninsula or aroundAnchorage.

But, although the seismic activity in the volcano hassince subsided somewhat, allowing AVO to reduce thealert level to yellow on March 10, people may be wonder-ing about the level of risk that the volcano poses for theDrift River Marine Terminal, the facility at the foot of thevolcano, where oil produced from several Cook Inlet oilfields is loaded onto tankers for transportation to the refin-ery at Nikiski on the Kenai Peninsula.

Cook Inlet Pipe Line Co., jointly owned by Chevronand Pacific Energy Resources, owns the terminal and theCook Inlet pipeline that feeds oil into the terminal.Chevron Pipe Line Co., a Chevron subsidiary, operates theterminal on behalf of the owners.

At a distance of some 23 miles from the Redoubt sum-mit, the terminal lies well out of range of any lava or ashflows from the volcano’s crater, Rod Flicken, team leaderwith Chevron Pipe Line Co., assured Petroleum News onMarch 10. In fact, ash belching from the volcano’s craterduring an eruption tends to be carried into the jet stream, tofall from the sky many miles away — when Redoubt lasterupted in 1989-90 no ash or any other kind of materialfrom the volcano landed on the terminal facilities, Flickensaid.

Built 41 years agoThe Drift River facility was built 41 years ago to sup-

port several companies that were producing oil in CookInlet, Flicken said. Oil from offshore fields on the westernside of the inlet comes ashore into production facilities atTrading Bay and Granite Point, where crude oil is separat-ed from water and any associated natural gas. The oil pass-es through custody meters into the Cook Inlet pipeline thatcarries the oil south down the west side of the Inlet to DriftRiver. The more northerly of the production facilities, theone at Granite Point, lies about 42 miles north of DriftRiver.

The oil arriving at the Drift River terminal flows intostorage tanks. Whenever sufficient oil has accumulated inthe tanks, Tesoro, the operator of the Nikiski refinery,schedules a tanker to offload oil from the terminal.

“Tankers come from all over the world and they’ve gotto be geared to come into the Cook Inlet,” Flicken said.

The terminal has seven storage tanks, but given the

decline in Cook Inlet oil production over the years, onlytwo tanks are currently active, with two other tanks keptoperational for standby use.

The terminal is completely self-contained, with its own

power generation, for example. Access is by aircraft, usingan airstrip adjacent to the facility. An average of 15 peoplework on site.

And the safety of those people is a paramount concern,Flicken said.

“At Chevron we give people and the environment ourtop priority,” Flicken said. “… My number one priority inthe event of a volcano eruption, or any disaster for thatmatter, is the folks that work out there.”

Main riskThe main risk to the terminal, in the event of Redoubt

Volcano erupting, is the melting of the Drift Glacier on theedge of the summit crater at the head of the Drift River.Melting of the glacier can cause a torrent of water and mudto flow down the river, with the potential to inundate someof the terminal structures.

Given that risk, the terminal was built on relatively highground with dikes around the tanks — the dikes providecontainment in the event of tank oil leakage, as well asaffording some level of protection from floodwater.

However, when Redoubt last blew in a series of erup-tions in 1989-90, a massive flow of water and mud downthe Drift River eroded the river banks in some places while

A section of the massive flood protection dike at the Drift River Marine Terminal dwarfs construction equipment and personnel

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The Drift River Marine Terminal lies northeast of RedoubtVolcano, on the south side of Drift River, where the riverenters the Cook Inlet. Drift River originates in a glacier onthe edge of Redoubts summit crater.

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PETROLEUM NEWS • WEEK OF MARCH 15, 2009 13

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also silting up the river, causing the river todivert to the south, to the opposite side ofthe oil terminal from the normal river chan-nel, and resulting in some flooding in theterminal area.

“(The river) came up against the exist-ing dikes … and they had some water flowinto the facility,” Flicken said. “… Ourtank farm didn’t get any damage. … Wesustained some water and mud within thebuildings.”

However, it became immediately clearthat flood protection needed to be beefedup.

New flood protectionConsequently in 1990 Cook Inlet Pipe

Line Co. contracted with engineering com-pany PDC to build a massive two-mile-long dike structure around the Drift Rivertank farm and to construct some diversion-ary dikes on the river itself. This major $18million project, located more than 100miles from the Alaska road network,involved building a broad, flat-toppedembankment, armored with concrete toprotect against scouring from a prolongedflood, and more than sized to protectagainst worst-case flooding events.

Rock for the construction came from asite three to four miles from the terminal,under the terms of a special State of Alaskaland lease.

“Then they came and poured all thecement, on site,” Flicken said.

In 1991 the National Society ofProfessional Engineers named the DriftRiver Terminal flood protection project asone of nine outstanding U.S. engineeringachievements in 1990.

The 1989-90 Redoubt Volcano erup-tions revealed another vulnerability at DriftRiver — the possibility that a large block ofice or rock carried down the river duringflood could scour the river bottom andsever the Cook Inlet pipeline at the pointwhere the pipeline passed just 6 feet underthe riverbed before reaching the terminal.Although the eruption-triggered floodnearly 20 years ago did not cause a pipelinebreach, Cook Inlet Pipe Line Co. contract-ed with Cruz Construction to move thepipeline to a depth of nearly 60 feet belowthe river, passing the pipeline through adirectionally-drilled, 1,800-foot hole.

That has taken the pipeline to a depthbelow the level of anything that couldcome through the riverbed, Flicken said.

Another possibility is that floodwatercould float a storage tank off its founda-tions in the highly unlikely event of a dikebreach. To counter this eventuality,

Chevron has set minimum volumes of oilthat must be present in any tank that con-tains any hydrocarbons — that minimumoil volume provides sufficient ballast toprevent a tank from floating in water.

“I’ve actually hired an engineering firmhere locally to double check our (minimumvolume) numbers,” Flicken said. The ter-minal doesn’t run oil volumes anywhereclose either to those minimums or to maxi-mum tank capacity, he said.

EvacuationBut, despite all the precautions in place

at the terminal, a red alert — an indicationthat the volcano is about to erupt or hasstarted erupting — would trigger an imme-diate shutdown and evacuation. Chevronstations one helicopter permanently on siteat the terminal and has another on theKenai Peninsula on 24-hour call, withpilots immediately available, ready tomount an evacuation if necessary. TheKenai helicopter is certified for operationin cloud, Flicken said.

“We go to red, we’re moving everybodyout,” Flicken said.

It is possible to shut down field produc-tion, production facilities, the Cook Inletpipeline and the marine terminal all withina few minutes of a red alert. And remotelyactivated valves on the pipeline wouldclose, isolating different pipeline segmentsfrom each other, Flicken said

And in a procedure honed through reg-ular drills, some involving actual shut-downs and some occurring at night whenpeople are in bed, Flicken has establishedthat it typically takes a little more than anhour to complete the shutdown procedureand muster everyone at the landing strip forevacuation. Each person has clearlyassigned evacuation duties. The order inwhich people leave is also specified, so thatthe people who perform the last tasks arealso the last to leave.

And, were there to be a problem withthe evacuation, a “safe haven” shelter at theterminal has its own generator plus sup-plies of fuel, water and food.

Assists AVOThe terminal has formed an agreement

with the Alaska Volcano Observatory, toassist AVO when its personnel visitRedoubt Volcano to install or maintainmonitoring equipment and cameras —AVO maintains a constant vigil over vol-cano activity, especially during periods ofheightened activity such as have beenobserved recently, activity that has causedAVO to upgrade its Redoubt instrumenta-tion, Flicken said.

“They’ve asked permission to come

continued from page 12

TERMINAL

KITCHEN UNIT

REDOUBT UNIT

KENAI UNIT

TRADING BAY UNIT

N COOKINLET UNIT

S GRANITE POINT UNIT

SWANSON RIVER UNIT

LONE CREEK UNIT

MOQUAWKIE UNIT

W MCARTHUR RIVER UNIT

STERLING UNIT

BEAVER CREEK UNIT

CANNERY LOOP UNIT

BIRCH HILL UNIT

N TRADING BAY UNIT

S MIDDLE GROUNDSHOAL UNIT

NICOLAI CREEK UNIT

CORSAIR UNIT

Kenai

Tyonek

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EAST FORELAND

DRIFT RIVER TERMINALCHRISTIE LEE LOADING FACILITY

PORT NIKISKI FACILITIES & TERMINALS

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The Drift River Marine terminal lies on the west side of the Cook Inlet directly west of Kenai.The Cook Inlet pipeline connects the Granite Point and Trading Bay oil production facilitiesto the terminal.

see TERMINAL page 14

By KRISTEN NELSONPetroleum News

A lpine, the most westerly of NorthSlope development, got national

play on successive days in March asAnadarko Petroleum and ConocoPhillipsheld annual analyst meetings. Both com-panies talked about the most recent satel-lite to produce through the Alpine facili-ties, Qannik, and about satellites sched-uled to be added to the facility in comingyears.

Chuck Meloy, Anadarko’s senior vicepresident, worldwide operations, citedAlpine as an example of Anadarko’s busi-ness model.

“The key to making money and deliv-ering a great business here is building aneconomy of scale through anchor fieldsand then leveraging that infrastructure toyour advantage to gather up the fieldsaround,” Meloy said March 10.

There are a lot of examples of this, hesaid, but cited Alpine, noting that thecompany rarely talks about Alaska.

Anadarko is a partner in theConocoPhillips Alaska-operated Alpinefield, the anchor field in the ColvilleRiver unit adjacent to the NationalPetroleum Reserve-Alaska.ConocoPhillips has a 78 percent workinginterest in the Colville River unit;Anadarko has a 22 percent interest.Alpine came online in late 2000.

The field has been a success, Meloysaid, “and in the last two or three yearsand for the next two or three years we’veessentially been adding one satellite ayear into the central processing facility tokeep the production flat or near flat on aplateau,” he said, calling it “a businessmodel that adds a lot of value toAnadarko.”

Qannik last yearRyan Lance, ConocoPhillips’ presi-

dent of exploration and production forEurope, Africa and the Middle East, saidat the March 11 ConocoPhillips’ analystmeeting that startups in 2008 included theQannik satellite at Alpine; startupsplanned for 2010-13 include Alpine West;and 2014-plus startups include Lookoutand Fiord West.

That would bring the total of satellitesproducing into Alpine to six: Nanuq,south of the main field, started producingin 2006, along with Fiord, north of themain field. Qannik produces from anextension of the Colville Delta 2 drill sitewest of the main Alpine processing facil-ities.

Alpine West, which would be the firstdevelopment within NPR-A, is just westof the Alpine field. In November of lastyear ConocoPhillips Alaska President JimBowles said the company is still workingto permit development of the CD-5 pad,also known as Alpine West, a satellitewhich would allow the company tobridge some of the gap between GreaterMooses Tooth in NPR-A and existingAlpine processing facilities.

Lookout is a discovery in NPR-A inthe Mooses Tooth unit approved by theU.S. Bureau of Land Management inearly 2008. Last year ConocoPhillips saidit hoped to have production from MoosesTooth perhaps as early as 2012 or 2013 —that clearly now has slipped to at least

over and utilize our facility to housetheir folks and fuel their helicopter,”Flicken said. “… It’s a win-win for thepublic, for industry and for the AVO.”

The terminal also played host to per-sonnel from the Alaska Department ofFish and Game, when Fish and Gameinstalled new salmon ladders to bypassnew waterfalls formed as a result of thelast Redoubt Volcano eruption.

But some of the precautions needed

when accommodating anyone at DriftRiver illustrate a unique feature ofAlaska wilderness living — dealingwith bears.

“We’ve got bears all over the place,”Flicken said. “That’s something we’reconcerned about all the time.”

In fact, when someone arrives at theterminal, even the half-mile or so trans-fer from the airstrip to the terminal liv-ing quarters requires transportation.

“In the summer I’ve got to worryabout bears,” Flicken said. “… I can’tlet (people) walk from the airstrip to thefacility.” �

14 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

continued from page 13

TERMINAL

A part of the Drift River Marine Terminal tank farm, showing the flood protectiondike that was constructed in 1990

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

More satellites to come on at AlpineWest North Slope development discussed by both field partnersConocoPhillips and Anadarko at analyst meetings in early March

The Alpine field

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see SATELLITES page 15

Prudhoe Bay producer. We believe wehave reached commercial terms withthem,” Heinze said, adding that the pro-ducer wanted to define “business andtechnical” details about the project beforefinalizing those terms.

Heinze declined to name the producerbefore the agreement is finalized.

The facility would commercialize NorthSlope gas before construction of a pipeline.

Gas at Prudhoe Bay is currently separat-ed from oil and sent through gas facilitiesand compressors where it is primed to beinjected back into fields to increase oil pro-duction.

ANGDA wants to tap that stream as itleaves the gas facility to remove some, butnot all, of the propane molecules that makeup about 2 percent of the natural gasstream.

“We would run it through a processingplant, separate out the propane moleculesand return the rest of the gas, the 98.5 per-cent gas, back to the Prudhoe Bay unit,”Heinze said.

After some processing, the propanecould then be trucked to communities onthe road system, barged to communities onthe river system, or loaded into ISO con-tainers and sold almost anywhere, provid-ing an alternative fuel option for thousands

of Alaskans.The facility would sell propane whole-

sale. At “moderate” oil prices, Heinze saidthe facility could supply consumers foraround $1 a gallon, or around $10 per mil-lion British thermal units, roughly equiva-lent to the going rate for natural gas in theCook Inlet.

Private firm would buildANGDA wants to get the project con-

ceptualized, permitted and financed, andthen look for a private firm for constructionand operation. Heinze said several Alaskacompanies have expressed interest in thefacility, including companies that alreadysell propane and companies that want todistribute propane and might be willing tofollow it to the source.

Heinze said he has identified two“major” industrial tenants interested in theproject.

“Either of these two entities is bigenough that it would allow us to proceed,”he said.

ANGDA is looking to put the facilitynear the mouth of the Putuligayak River,about five miles northwest of Deadhorse,near the North Slope Borough Landfill.The ultimate site needs to be close enoughto existing facilities to tap the gas stream,but discreet enough not to get in the way ofan eventual gas treatment plant associatedwith a major pipeline.

By tapping the gas stream, the facilitywould become integrated into PrudhoeBay.

“We are in the midst of the guts andfeathers of the Prudhoe Bay field, stillNorth America’s largest field,” Heinze said.“If this screws up in any way, you shut thefield down. So this has to be done extreme-ly carefully.”

The actual propane plant is relativelyconventional. Heinze suggested ANGDAor a contractor might even be able to pickone up second hand from the Lower 48.

“You find them all over the UnitedStates,” Heinze said.

The Palin administration recently pro-posed legislation to expand the authority ofANGDA, a move they said in part wouldbe to help move the propane facility along.

ANGDA and the Anchorage EconomicDevelopment Corp. are sponsoring a con-ference in April to highlight the opportuni-ties for value-added industries in Alaska. �

PETROLEUM NEWS • WEEK OF MARCH 15, 2009 15

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continued from page 11

ANGDA

2014. Lookout would be produced from aproposed CD-6 drill site.

ConocoPhillips discussed a FiordWest satellite in a fall 2008 update to itsColville River unit development plan.

The company said then that beyond2011 it “intends to develop additionalsands in the southern Nechelik reservoirand also both the Kuparuk and theNechelik sands in the Fiord West satel-lite area, located southwest of the currentFiord development.” ConocoPhillipssaid these longer-term plans “are contin-gent on obtaining viable permits to crossthe Nigliq channel” of the ColvilleRiver.

Into the ChukchiLarry Archibald, ConocoPhillips’

vice president, exploration, said at theMarch 11 analysts’ meeting that theChukchi is “another giant province” andnoted that Conoco and Shell spent“much more than the industry” in acquir-ing acreage there last year for a reason:“We had differential data,” including“new seismic that allowed us to seesome of these giant structures that were

known about” and well control data fromwells drilled a couple of decades ago.

ConocoPhillips had $506.4 million inhigh bids for 98 tracts at the February2008 Minerals Management ServiceChukchi Sea outer continental shelflease sale; Shell had $2.1 billion in highbids for 275 tracts.

ConocoPhillips “picked up virtuallyall of what we call the Devil’s Paw struc-ture and a significant amount of theBurger structure and some of the othersatellites around there,” Archibald said.

He said ConocoPhillips is “tentative-ly planning work that includes drillingan operated-well in the Devil’s Paw asearly as 2011.” He said Shell has target-ed drilling the Burger prospect in 2010-11.

The value of the Chukchi depends onhow much gas is there, oil vs. gas,Archibald said, telling an analyst thatConoco’s bids were based on “someunique differential knowledge of thehydrocarbon systems up there.”

While ConocoPhillips is “pretty con-fident” in its view of the prospect — i.e.,that its acreage is oil- rather than gas-prone — Archibald acknowledged thatthere has been very little exploration inthe Chukchi, so it is much more of afrontier basin than the Beaufort. �

continued from page 14

SATELLITES ALTERNATIVE ENERGYDeclining economy hits renewable fuels

Hit by the double whammy of declining energy prices and frozen credit mar-kets, renewable fuel businesses are struggling to survive, industry experts told theU.S. House of Representatives Small Business Committee March 4.

“Until recently the biofuel industryhad been a small business success story,revitalizing rural economies while reduc-ing our dependence on foreign sources ofoil,” said committee chair Rep. NydiaVelázquez, D-N.Y. “Now, these enter-prises are struggling to stay afloat, find-ing themselves locked out of the capitalthey need, while demand for their prod-uct dwindles.”

Entrepreneurs in fuels such as ethanoland biodiesel told the committee that, with a shortage of venture capital and banksunwilling to issue loans, the development of a new generation of biofuels is atrisk. Potential new fuels include cellulosic ethanol, generated from materials suchas recycled waste paper, rice hulls and switch grasses. Energy experts say thatthese fuels could compete with imported oil while also reducing the environmen-tal impacts of current biofuels, according to a House of Representatives pressrelease.

“A fully developed renewable fuels industry offers the potential to grow ourenergy sources here at home,” Velázquez said. “However, the current economicconditions are blocking the kind of investments we need to produce the fuels ofthe future.”

—ALAN BAILEY

Entrepreneurs in fuels such asethanol and biodiesel told the

committee that, with a shortageof venture capital and banksunwilling to issue loans, the

development of a newgeneration of biofuels is at risk.

By CHRIS KAHNAssociated Press Writer

Supertankers that once raced aroundthe world to satisfy an unquenchable

thirst for oil are now parked offshore, fullyloaded, anchors down, their crews killingtime. In the United States, vast storagefarms for oil are almost out of room.

As demand for crude has plummeted,the world suddenly finds itself awash inoil that has nowhere to go.

It’s been less than a year since oilprices hit record highs. But now producersand traders are struggling with the newreality: The world wants less oil, notmore. And turning off the spigot is aboutas easy as turning around one of thosetankers.

So oil companies and investors arestashing crude, waiting for demand to riseand the bear market to end so they canturn a profit later.

Meanwhile, oil-producing countriessuch as Iran have pumped millions of bar-rels of their own crude into idle tankers,effectively taking crude off the market tohalt declining prices that are devastatingtheir economies.

Traders have always played a game ofstore and sell, bringing oil to market whenit can fetch the best price. They say thistime is different because of how fast thebottom fell out of the oil market.

“Nobody expected this,” said AntoineHalff, an analyst with Newedge. “Themajority of people out there thought themarket would keep rising to $200, even$250, a barrel. They were tripping overeach other to pick a higher forecast.”

Strategy storageNow the strategy is storage. Anyone

who can buy cheap oil and store it mightbe able to sell it at a premium later, whenthe global economy ramps up again.

The oil tanks that surround Cushing,Okla., in a sprawling network that holds10 percent of the nation’s oil, have beenswelling for months. Exactly how closethey are to full is a closely guarded secret,but analysts who cover the industry say

Cushing is approaching capacity. There are other storage tanks in the

country with plenty of extra room to takeon oil, but Cushing is the delivery pointfor the oil traded on the New YorkMercantile Exchange. So the closerCushing gets to full, the lower the price ofoil goes.

Some oil is ending up in giant shipsand staying there. On these supertankers,rented by oil companies such as RoyalDutch Shell, there is little for crews to dobut paint and repaint the decks to passtime.

More than 30 tankers, each with theability to move 2 million barrels of oilfrom port to port, now serve as little morethan floating storage tanks. They aremoored across the globe, from the Texascoast to the calm waters off Europe andNigeria.

“It gets expensive to do this,” said PhilFlynn, an analyst at Alaron Trading Corp.“If you’re sitting on a bunch of oil andyou’re stuck paying storage and insur-ance, and you can’t find a buyer, you mayhave to sell it at a discount just to get ridof it.”

On the other hand, as storage units onland have filled up, the companies thatown the tankers have profited. Tankercompanies charge an average of $75,000 aday, three times as much as last summer,to hold crude, said Douglas Mavrinac, ananalyst with Jefferies & Co.

Demand increase began in ‘80sDemand for oil began to increase

steadily in the early 1980s, and it wentinto overdrive in recent years as theChinese economy surged and as producerspumped lakes of oil out of the ground totake advantage of a spike in prices. Thenrecession gripped the globe, frozen creditmarkets made things worse, and invento-ries swelled.

Refineries in the U.S. have cut wayback on production of gas as the economyweakens and millions of Americans, manyof them laid off, keep their cars in thegarage.

The latest government records showU.S. inventories are bloated with a virtualsea of surplus crude, enough to fuel 15million cars for a year. Inventories havegrown by 26 million barrels since thebeginning of the year alone. Oil fromSaudi Arabia, the United Arab Emiratesand Nigeria is finding few takers, eventhough much of it is used to make gasolinein the United States.

There are so many players in the inter-national oil market that no one has enoughcontrol to sway prices. OPEC slashed pro-duction by more than 4 million barrels aday, and still the price of a barrel of crudelanguishes near $40. At its peak, it tradedat $147 a barrel.

Experts aren’t sure what will happenwhen all that oil finally comes ashore.

One fear is that with oil prices so low,companies will slash drilling and produc-tion, setting the world up for an energycrunch that would send prices soaring.The number of oil and gas rigs operatingin the United States has fallen a staggering39 percent since August.

Others say prices would plummet ifcompanies forced millions of barrels ontothe market at once.

“If everyone’s running for the exits atthe same time, they’ll engineer a price col-lapse,” Flynn said. �

16 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

EXPLORATION & PRODUCTIONChevron cutting production growthforecast in response to lower prices

In response to lower oil prices, Chevron slowed its production growth forecast,saying it planned to reduce investment in some fields until economics on thoseprojects improve.

However, the company still plans to spend “heavily in the new, complex proj-ects that underpin its long-term growth strategy,” according to a report from DowJones newswire.

Local Chevron representatives declined to say how the new plans might impactthe White Hills exploration program south of the Kuparuk River unit, calling it a“tight” program.

There have been reports that Chevron suspended work at the prospect this win-ter.

Chevron recently received four drilling permits for exploration work at WhiteHills this winter, following three wells the company drilled at the oil and gasprospect last year.

—PETROLEUM NEWS

New alliance for low-impact drillingHouston Advanced Research Center, a nonprofit organization dedicated to sus-

tainable development, and Texas A&M University have announced a partnershipwith seven other U.S. universities to fund research into the development of oil andgas drilling technologies that havelow environmental impacts, and toshare the results of that research.

“We will consider all aspects ofenergy resource recovery, not onlytraditional oil and natural gas produc-tion but also unconventional produc-tion such as natural gas from shale orcoalbed methane,” said Rich Haut,manager of the new alliance.

The partnership is an offshoot of a U.S. Department of Energy National EnergyTechnology Laboratory-funded project to identify and develop low-impactdrilling systems, DOE said Feb. 25. That project, which ends on March 31, iden-tified 90 technologies that could significantly reduce the environmental impact ofoil and gas operations; established an oil and gas desert test center near Pecos,Texas; established an approach for optimizing drilling decisions; and developed aprocess to convert drilling waste into a useable product, DOE said.

The development of technologies that make oil and gas accessible in environ-mentally sensitive areas could contribute to future job growth, DOE said.

—ALAN BAILEY

The partnership is an offshoot of aU.S. Department of EnergyNational Energy TechnologyLaboratory-funded project to

identify and develop low-impactdrilling systems, DOE said Feb. 25.

� F I N A N C E & E C O N O M Y

With demand sapped,world awash in oil

By SEAN MURPHYAssociated Press Writer

Oklahoma Attorney General DrewEdmondson is investigating con-

cerns that Canadian oil is pouring intoOklahoma markets, driving down theprice Oklahoma oil producers receive fortheir product.

Edmondson’s office confirmed March4 he has opened a preliminary inquiryinto whether the oil dump is a violation ofstate and federal antitrust laws.

“Attorney General Edmondson lastweek met with a group of Oklahoma oil-men to discuss the Canadian oil situa-tion,” said Charlie Price, a spokesman forEdmondson. “The information was givento our antitrust attorney for his review.”

Price said they also are seeking apetroleum market and pricing expert toconsult with their attorneys on the issueto determine how best to proceed.

Cushing major storage hubA pipeline that carries Canadian oil

from Chicago has nearly overwhelmedthe storage capacity in Cushing, a majoroil hub where nearly 10 percent of thenation’s oil is stored, said CodyBannister, a spokesman for the OklahomaIndependent Petroleum Association.

“There’s a whopping amount of oil (inCushing),” Bannister said. “The big issueis takeaway capacity. If there is sufficienttakeaway capacity added to send it away

to other places, it’s really not a big issue. “But if you’ve got a bunch of stuff

coming in and nothing going out, you’regoing to get backlogged.”

As a result, independent oil producersin Oklahoma, who produce 96 percent ofthe crude oil in the state, along with pro-ducers in Kansas, Illinois, Texas andother states are seeing the price of domes-tic oil sold at Cushing being driven downbelow market prices, said Harold Hamm,chairman and chief executive officer ofEnid-based Continental Resources.

“Everything that’s fed into theCushing market is basically disadvan-taged,” Hamm said. “It’s not justOklahoma, although Oklahoma is takingthe brunt of it.”

Pipeline reversal blamedHamm singled out Canada-based

Enbridge’s Spearhead pipeline, which hasreversed its flow to pump tens of thou-sands of gallons of Canadian oil intoCushing each day.

“The flow of crude normally is to

Cushing and on up to the northeast and theMidwest refineries,” Hamm said. “What’schanged is reversal pipelines coming theother direction and the lack of takeawaycapacity.

“They don’t know when to quit.” Larry Springer, a Houston-based

spokesman for Enbridge, said less than 8percent of the company’s 16.7 million bar-rels of storage capacity at Cushing is takenup by Canadian oil and that the companysimply ships oil where its customers want.

“It’s fair to say that a vast majority ofthe oil in our terminal at Cushing is not

from Canada,” Springer said. “We wouldnot be doing this unless the customers onthis pipeline were asking us to.

“There was a real demand, apparently,for bringing this crude down into theCushing hub.”

Because the sale of oil is taxed inOklahoma, Hamm said the deflated pricefor oil sold at Cushing also impacts statecoffers.

“Oil and gas is Oklahoma’s mostimportant resource,” he said, “and so Ithink this inquiry is something that forsure needs to be done.” �

PETROLEUM NEWS • WEEK OF MARCH 15, 2009 17

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

Decision on Shell exploration withdrawnBy ALAN BAILEYPetroleum News

T he U.S. Court of Appeals for the 9th Circuit haswithdrawn its Nov. 20 decision by a panel of three

judges that upheld appeals by the North Slope Borough,the Alaska Eskimo Whaling Commission and severalenvironmental organizations against U.S. MineralsManagement Service approval of Shell’s Beaufort Seaexploration plan.

“The opinion vacated and withdrawn will be replacedby a new opinion,” the court said in an order issued March6. The court did not indicate when the new opinion wouldbe issued.

As a consequence of the November court decisionShell deferred its planned 2009 Beaufort Sea explorationdrilling program. The company also filed a petition for a

rehearing of the case by the full court.But the court now says that its decision to vacate the

November decision renders moot the Shell rehearing peti-tion and any other motions that relate to that petition.

Majority decisionIn the November decision a majority of the judges on

the court panel said that MMS had not conducted an ade-quate environmental evaluation of Shell’s Beaufort Seaexploration plan and that the agency must prepare arevised environmental assessment. Among its findings thecourt said that MMS had not sufficiently analyzed theimpact of drilling noise on bowhead whale migration pat-terns and, hence, the impact on subsistence whale hunting.

However, one judge dissented from the opinion, sayingthat MMS had thoroughly analyzed the potential impactsof Shell’s Beaufort Sea program and commenting that it

was not appropriate for the court to overrule MMS expert-ise regarding the interpretation of research results pertain-ing to the potential impacts of exploration activities onbowhead whales.

But no one seems clear why the court has now with-drawn its November opinion.

“It’s difficult to know what the intent of this decisioncould mean,” Shell spokesman Curtis Smith toldPetroleum News March 9. “Obviously, we disagreed withthe court’s original ruling that vacated MMS’s approval ofour plan of exploration. While we await the new opinionfrom the court, we will continue to engage with the com-munities on the North Slope about our exploration plans.”

Smith said that Shell recognizes that a key ingredientof the company’s success involves finding commonground with the people of Alaska to develop offshoreresources for everyone’s benefit. �

SAFETY & ENVIRONMENTArctic sea ice extent approaches maximum

As the Arctic sea ice extent increased in February toward its March wintermaximum the average area of ice cover was the fourth lowest on record, as deter-mined by satellite surveillance, the National Snow and Ice Data Center saidMarch 3. The February average extent of 5.73 million square miles was 309,000square miles less than the 1979 to 2000 average, NSIDC said.

An image of the polar region shows ice cover across the whole of the ArcticOcean, the Chukchi Sea and the northern part of the Bering Sea.

“A temporary decline in ice extent from Feb. 18 to 22 illustrates the sensitivi-ty of Arctic sea ice extent to transient weather conditions,” NSIDC said.“Conditions along the southern boundary of the ice cover, such as in the BeringSea, are typically just barely cold enough for ice to exist and ice there can quick-ly expand or retreat in response to changes in the temperature or winds.”

In fact, ups and downs in the ice extent are not unusual at this time of year,NIDC said.

—ALAN BAILEY

� P I P E L I N E S & D O W N S T R E A M

Oklahoma investigates Cushing oil glutLarry Springer, a Houston-basedspokesman for Enbridge, said lessthan 8 percent of the company’s16.7 million barrels of storage

capacity at Cushing is taken up byCanadian oil and that the

company simply ships oil where itscustomers want.

regulations that place caps on greenhousegas emissions covering a broad sweep ofthe U.S. economy.

He said Canada must continue its dis-cussions with “our American neighborsrelative to their domestic policy becausewe share the same economic space andenvironmental space and we need tomake sure that our policies are workable.”

Prentice’s actions and commentsunderscore the concerns in Canada that,regardless of the apparent harmony at theObama-Harper summit, the U.S. may beon a path that poses threats extending farbeyond the oil sands to the chemicalindustry, steel production, electricityexports and energy-intensive manufac-tured goods.

CCS promotion a reliefWhen the two leaders agreed to a

“clean energy dialogue,” with the empha-sis on promoting the unproven carboncapture and storage or CCS technology,the Canadian petroleum industry andresource-based provinces breathed a pal-pable sigh of relief.

Alberta Premier Ed Stelmach wel-comed what he interpreted as proof thatObama was “clearly speaking Alberta’slanguage,” by favoring an economic andenvironmental balance by investing inCCS.

Dave Collyer, president of theCanadian Association of PetroleumProducers, said he heard nothing fromObama to indicate that the U.S. was intenton “an immediate change in regulationsor anything that would cause me to beconcerned about discrimination against

oil sands production.”He said the joint U.S.-Canada

approach should be able to achieve the“right balance” between economicgrowth, energy security and environmen-tal protection.

However, within a week of his returnto Washington, Obama was again turningup the volume on environmental meas-ures that have Canadian exporters wor-ried about duties and other trade measuresif the U.S. imposes tough rules on theindustrial sector and places Canada in theenvironmental-laggard category.

Trade agreements possible toolLisa DeMarco, a Toronto attorney with

MacLeod Dixon and a climate-changepractitioner, told the Globe and Mail thatthe U.S. could use environmental exemp-tions in trade agreements as a “shield toallow for trade protectionism in goods ofhigher or different emissions intensity.”

Obama’s initial budget request toCongress for fiscal 2010 gave weight tothat view by indicating the U.S. govern-ment will start collecting revenue in 2012from a mandatory cap-and-trade programfor carbon emissions from power plants,oil refineries and other industrial sources.

DeMarco said Obama’s budget pro-

posal reflected his ambition to cap GHGsby 2012 and require fossil-fuel users topurchase permits to emit any carbon diox-ide that results from the combustion ofcoal, oil or natural gas.

The budget projected those emissionsallowances would raise US$645 billionover seven years, while earlier estimatesfrom the Congressional Budget Officeprojected that anywhere from US$50 bil-lion to US$300 billion could be generatedannually from an emissions tradingscheme by 2020.

If Obama sticks resolutely to hard capsand ends up imposing a carbon tax, oradopting import tariffs and other tradeactions against countries deemed to havea competitive advantage over the U.S. byapplying less-stringent climate-changeregulations, the mood of collaborationbetween the U.S. and Canada will quick-ly evaporate.

Harper promoting targetsHarper forcefully made his case before

Obama at a news conference on Feb. 19that he sees little difference betweenCanada’s strategy of setting “intensity tar-gets” to limit GHGs per unit of produc-tion, and Obama’s preference for hardcaps, which impose absolute limits.

Harper said those approaches are “twoways of measuring the same thing,” whilemaking his case that Canada is aiminghigher than the U.S. by vowing to cut2006 GHGs by 20 percent by 2020,whileObama is targeting a 14 percent reductionin 2005 U.S. emissions by the same year.

In addition, the Canadian governmentis planning to rely on incentives, taxbreaks and higher efficiency standards toreduce energy consumption.

High roadFor now, however, Canada is taking

the high road, with Prentice telling a newsconference in Washington on March 3that the U.S. and Canada are establishingjoint working groups to coordinate in anestimated US$7 billion worth of CCStechnology projects to lower carbon emis-sions from the twin evils — U.S. coal-fired power plants and the Alberta oilsands.

He said the U.S. has earmarkedUS$3.5 billion, while Canada has a simi-lar amount, including C$2 billion fromthe Alberta government and C$1 billioneach from the Canadian andSaskatchewan governments.

“The focus of the clean-energy dia-logue has been to ensure that we collabo-rate on those investments … and, frankly,make sure that the investments are appro-priate and advantageous for both CCS inthe context of the oil sands as well as inthermal electricity,” Prentice said.

“We share the largest free-marketenergy system in the world and it’s diffi-cult to imagine acceptable policies on theregulation of carbon in the environmentthat are discordant,” he said.

But Prentice also acknowledged theregional differences in Canada — withOntario and Quebec supporting andAlberta and Saskatchewan opposing cap-and-trade and British Columbia introduc-ing a carbon tax — pointing to the chal-lenge of building collaborative relation-ships.

He said development of CCS technol-ogy has been “proceeding apace” inWestern Canada’s hydrocarbon industryand holds promise for thermal coal appli-cations.

CCS projects by 2015That message was reinforced by Jim

Carper, president of the Alberta CarbonCapture and Storage DevelopmentCouncil — a joint government-industry-academic group — who said Alberta’sC$2 billion innovation fund for CCS putsthe province in the forefront of a globaleffort to get pilot projects under way.

He said Alberta will have three to fiveprojects operating by 2015 to betterunderstand the technology.

Each of the projects could capture andstore 5 million metric tons of CO2 peryear — a start, though a long way fromAlberta’s goal of using CCS to reduceemissions by 139 million metric tons by2050.

Carter doubted a cap-and-trade mar-ketplace could achieve those results.

“You buy someone’s credit, but thisdoesn’t offer a technological solution,” hetold the Edmonton Journal. “At the end ofthe day people have to figure out how toreduce the amount of CO2 going into theatmosphere and that takes research anddevelopment, science and engineering.”

Carter believes government assistancewill be needed until 2020, at which pointCCS could be self-funding.

In the meantime, Harper is takingevery opportunity to reach U.S. audiencesto drive home the importance of Canada’soil and gas in the U.S. energy-securityequation and to warn of the consequencesif the U.S. cuts off oil sands-derivedimports.

Interviewed on CNBC’s The LudlowReport he said, “If you look at Americanneeds for energy and where Americanscan get it at a reasonable price, (an importban) is completely unrealistic.

“We will do what we can to reduce thecarbon footprint, but there should be noillusion,” he said.

“Economic reality will hit (oil sands)environmental policies pretty hard whensomeone goes to implement them.” �

18 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

continued from page 1

SOLUTIONSBut Prentice also said Canada is

not prepared to pay anunreasonable price as the newObama administration sets its

sights on climate changeregulations that place caps on

greenhouse gas emissions coveringa broad sweep of the U.S.

economy.

states.It’s a problem that could get worse once

TransCanada’s Keystone pipeline, partlyowned by ConocoPhillips, connects upwith Cushing later this year, saidOklahoma driller Mickey Thompson.

He said the group is not trying to shutdown Canadian crude, but the membersare worried about their ability to survive ina marketplace.

Thompson figures the cost of turningCanadian oil sands crude into light oil islikely in the range of $60-$70 per barrel,although the Canadian Association ofPetroleum Producers estimates that themost expensive synthetic crude costs about$30-$35 to prepare for export.

Because their crude is easily refined, theOklahoma producers say it has been fetch-ing $4-$6 per barrel below the U.S. crudefutures price, or less than $40 per barrel,compared with recent months when theyhave gone from fetching a premium priceto selling for a $10- to $12-a-barrel dis-count to Brent, a major world benchmark.

Thompson said the question is whetheroil sands producers are delivering oil to themid-continent below their cost and, if thatis the case, “Is it legal?”

A spokesman for Edmondson said thestate is looking to consult with someonewho has petroleum marketing and pricingexpertise.

Alec Avramenko, executive vice presi-dent of Calgary-based Global PetroleumMarketing, told the Globe and Mail theOklahoma strategy is naked protectionism.

He accused the Oklahomans of saying“We’re fighting for survival and we justdon’t want you Canadians around any-more.”

—GARY PARK

Heinze tells ANGDAboard to start looking

ANGDA IS PONDERING LIFE AHH:after Harold Heinze.

In 2003, the board of the newly formedpublic corporation hired the past presidentof ARCO Alaska and former Departmentof Natural Resources commissioner to beits first CEO.Heinze, 66, said it’sthe longest he’s everheld a single positionin his entire career.

Toward the end ofa long meeting inAnchorage on March9, Heinze remindedthe Alaska NaturalGas DevelopmentAuthority board ofdirectors about a deal he struck with themat a meeting last July.

“I asked for more money, and you gaveit to me, and in return I promised that Iwould stay for a year,” he said. “Okay.And we both kept our promise, as far asI’m concerned.”

Heinze continued, “And I am not serv-ing notice in any way, shape or form, but Ithink it is appropriate for the board to beserious about thinking about the fact thatthere is a life after Harold Heinze.ANGDA has meaning far beyond justme.”

He said, “Beyond July, both of us havelived up to our deal,” but added that hewas “not against” making a new deal, onlythat he wanted the board to consider hisreplacement.

For much of the past five years,ANGDA has been gathering permits, con-ducting studies and making plans for avariety of natural gas projects to serveAlaska markets with the goal of eventually

handing over its work to a private sectorcompany for construction.

Heinze suggested ANGDA should finda new boss before handing over its proj-ects.

“The organization is going to face moreand more financial type issues than projectengineering type issues, and so I wouldsuggest serious consideration of someonewho has more of a financial backgroundwith pipelines,” Heinze said.

He continued: “Given the general stateof the economy, this would also be a timeto look more nationwide for such a person,and they might be readily available.There’s a lot of good financial people outthere that are having a hard time finding ahome right now.”

Vice Chair Don Benson took a morecolloquial approach: “I hope some of thoseguys that are jumping out those ten-storywindows, we can catch one of them andpull them in.”

Smiling, Chairman Scott Heyworth,who sponsored the 2002 ballot measurethat created ANGDA, scribbled a name ona sheet of yellow legal paper and handed itto Heinze.

“I think I got the right guy,” Heyworthsaid.

Heinze read the name to himself, andbegan laughing. “NO!” he said.

—ERIC LIDJI

Nabors optimistic in challenging times

IN ANNOUNCING NABORSIndustries’ 2008 results, Gene Isenberg, thecompany’s chairman and CEO, expresseda note of optimism amid the current eco-nomic turmoil. Nabors is a major oil andgas drilling contractor that operates severalhundred land rigs and nearly 30 offshorerigs in the United States, as well as a sub-stantial number of other rigs worldwide.

“The fourth quarter (of 2008) was notas bad as it could have been and the futureis probably going to be better than theprice of our stock seems to indicate,”Isenberg said. “Our North American landdrilling markets are adjusting to a new par-adigm in natural gas drilling with the com-mercialization of abundant shale deposits.Over time this will benefit Nabors sincemuch of the investments we have madeover the last few years were in assets thatgive us disproportionate exposure and dis-tinct competitive advantages in these areasthat are increasingly strategic to the U.S.energy supply.”

Isenberg also said that, despite a slow-down in international drilling markets,Nabors has “high-specification rigs” thatmake the company poised to grow.

Two 2008 startup rigs and a new com-bined coiled tubing and stem drilling rigwill boost 2009 results in Alaska, Isenbergsaid. However, other factors have loweredNabors expectations in Alaska: Somedrilling projects have been postponed,while the sinking of the only ice-reinforcedworkboat in the Cook Inlet has resulted ina temporary suspension of platformdrilling in the inlet, he said.

Nabors Alaska drilling operations creat-ed $53 million in operating income in2008, a 40 percent increase from the previ-ous year. That compares with 2008 incomeof $629 million from the company’sLower 48 land operations, and $408 mil-lion from international operations.

But the economic crisis is taking its tolland Isenberg said that Nabors expects aprecipitous decline in activity and pricingas customers abruptly adjust spending. Thebrunt of this decline will likely occur in thefirst quarter of 2009, he said.

“Our U.S. Lower 48 land drilling busi-ness improved during the (last) quarter

PETROLEUM NEWS • WEEK OF MARCH 15, 2009 19

Northern Air Cargo announces NAC Can –a new program to improve customer service and make shipping with NAC easier than ever.

• Faster drop-offs and streamlined pickups.• Individual kiosks for small packages, oversize, and general freight.• Dedicated service agents for custom shipping solutions.

NAC CANmake air cargo easier!

800.727.2141 www.nac.aero

LAND & LEASINGPotential Alaska state and federal oil and

gas lease salesAgency Sale and Area Proposed Date

DNR Alaska Peninsula Areawide May 2009

DNR Cook Inlet Areawide May 2009

DNR Beaufort Sea Areawide October 2009

DNR North Slope Areawide October 2009

DNR North Slope Foothills Areawide October 2009

MMS Sale 209 Beaufort Sea 2009

MMS Sale 211 Cook Inlet 2009

DNR Alaska Peninsula Areawide May 2010

DNR Cook Inlet Areawide May 2010

DNR Beaufort Sea Areawide October 2010

DNR North Slope Areawide October 2010

DNR North Slope Foothills Areawide October 2010

MMS Sale 212 Chukchi Sea 2010

MMS Sale 217 Beaufort Sea 2011

MMS Sale 214 North Aleutian basin 2011

MMS Sale 219 Cook Inlet 2011

MMS Sale 221 Chukchi Sea 2012

Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, man-ages leasing in the National Petroleum Reserve-Alaska; DNR, Alaska Department of

Natural Resources, Division of Oil and Gas, manages state oil and gas lease sales onshoreand in state waters; MHT, Alaska Mental Health Trust Land Office, manages sales on trust

lands; MMS, U.S. Department of the Interior’s Minerals Management Service, Alaskaregion outer continental shelf office, manages sales in federal waters offshore Alaska.

This week’s lease sale chartsponsored by:

PGS Onshore, Inc.

continued from page 1

INSIDER

see INSIDER page 21

HAROLD HEINZE

20 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

Companies involved in Alaska and northern Canada’s oil and gas industry

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

Business SpotlightMRO Sales Inc.

MRO Sales Inc. is an Alaska-incorporatedmanufacturer’s representative company involvedin oilfield, mining and government sales.Projects range from Prudhoe Bay to the end ofthe Aleutian Chain. In November 1999Petroleum Equipment & Services Inc. purchasedMRO Sales. While the companies represent twoprofit centers, there is significant synergy fromthe merger and a bright future forecasted.

Troy Mears has spent 20-plus years in sales,mostly in industrial safety and fire and rescueequipment, before joining MRO Sales. For threedecades he’s been an avid scuba diver; todayhe’s earning his tae kwan do black belt and alsoenjoys golfing and riding his motorcycle. Troy andwife Charmagne have a son and two spoiled yellow labs who cavort joyously at theirEagle River home.

—PAULA EASLEY

MACTEC Engineering and Consulting Inc.

MACTEC Engineering and Consulting Inc., for-merly Harding Lawson Associates, has been pro-viding civil, permitting, NEPA, environmental,water-wastewater and geotechnical engineeringservices to Alaska’s oil and gas industry since1969. Providing engineering services to morethan 200 locations in the state, it has the staff toassure on-budget and on-time performance thatmeets expectations.

After working for Deloitte & Touche, a top-four accounting firm, Kelly Findlay fulfilled a life-long dream and moved to Alaska, joining MACTECin October 2008. With a B.S. in InformationSciences, she brings experience in corporate procurement management, audit reportingand marketing proposals to MACTEC. She’s a huge fan of the Pittsburgh Steelers andPenguins, but Kelly says the Anchorage Aces are growing on her.

—MARTI REEVE

Troy Mears, Accounts Manager

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although the outlook is for substantiallylower operating income over the next twoquarters,” Isenberg said. “The number ofrigs working has fallen rapidly from a highof 273 in October and, after averaging 260for the quarter, stands at 181 today. Dayrates are less relevant now as customersare more focused on reducing total costs tobe in line with cash flow.”

—ALAN BAILEY

ExxonMobil buckingtrend, sticks to investment plan despiterecession, lower prices

UNLIKE OTHER GIANT, multinationaloil companies, ExxonMobil is going tocontinue investing at “record levels” incapital and exploration projects.

Oil prices have dropped by more than$100 a barrel since their peak last summer,but at the company’s annual presentation atthe New York Stock Exchange on March5, Exxon’s Chairman and Chief ExecutiveRex Tillerson said Exxon had not plannedfor $100-per-barrel oil prices in the five-year investment plan it released in 2008.

“We told our people to ignore all thisnoise about $100 oil,” he said. “We werenot planning for a world of $100 oil, or$200 oil. …We really are making noadjustments to our business strategy. … Itfeels pretty much business as usual.”

Exxon plans to increase capex spendingby 11 percent in 2009, an increase of $3billion over 2008 to $29 billion, and plansto invest about $150 billion over the nextfive years.

Two things could reduce that number:• Cutbacks by some partners on shared

projects;• Cost reductions on materials and serv-

ices. A large portion of the planned spending

is tied up in projects already under way, sothe increase between 2008 and 2009 waslargely due to cost increases that skyrock-eted as oil and gas prices rose. But thoseprices are coming down and Exxon, likemost oil companies, is negotiating with itssuppliers and contractors for lower rates.

Tillerson said Exxon is limited in itsability to cut costs where contracts arealready in place, and it’s not looking totake unfair advantage of the current marketenvironment.

“We are in active discussions with all ofour suppliers and contractors,” he said.“Our objective is to work collaborativelywith them. It’s not in our long-term interestto drive a lot of these folks out of businessby hitting them over the head with a ham-

mer because of the environment we’re in.”

What next for Exxon?At the end of 2008 Exxon had $32

billion in cash, only $7 billion in debt,and almost $200 billion of its own sharesin its treasury. In 2008 the companyspent a record $32 billion on buybacks,$8 billion more than its capital andexploration budget and, in the first quar-ter of 2009, will spend $7 billion on buy-backs.

According to Bloomberg reporter JoeCarroll, using its treasury shares Exxon“could make a deal for more than thecombined value of its two biggest U.S.rivals, Chevron Corp. andConocoPhillips, without borrowingmoney, issuing stock or tapping its cash.”

Tillerson sees the dramatic rise andfall of crude prices, and the meltdown ofglobal credit markets that pushed theworld into a recession, as a “supreme testof a company’s business model.”

So besides sticking to its spendingplan, how does Exxon plan to flex itsfinancial muscle in the years ahead?

As analysts have predicted, Tillersonsaid Exxon is looking at purchasing com-petitors, but not companies with a declin-ing resource or production base.

He also said the mergers and acquisi-tions market was “very much in a stateof change,” and “has not settled in myview.”

What he seemed most interested inwas partnering with some of the world’sstate-run oil companies that are resource-rich but cash-poor.

“There are any number of resourcecompanies and oil companies aroundglobe where we would think we have theability to bring ... success,” Tillersonsaid.

He would like to replicate the successExxon has had working with Qatar’sstate-run oil entity. Exxon has ninemajor projects scheduled to start thisyear, many centered on the developmentof large natural gas fields in Qatar.

According to Brian Youngberg, ananalyst at Edward Jones & Co. in DesPeres, Mo., who Carroll quoted, nationswith state-owned oil companies “arelooking for partners with deep pockets aswell as the expertise to reach very deepand remote reserves.”

At their peak, the 2009 startups areprojected to add the equivalent of485,000 barrels a day to Exxon’s produc-tion.

By 2015, the company expects itscapital and exploration investments toadd about 1.5 million barrels a day ofnew production to its 2007 level of pro-duction, which was 4 million barrels perday, bringing its total daily production to

5.5 billion barrels of oil by 2015. Exxon’s 2008 production actually fell

below 4 million barrels per day — forthe first time since its acquisition ofMobil in 1999. It dropped by 6.2 percent,prompting even louder criticism of thebuyback program from analysts, whosaid Exxon should be investing more infuture production, given the growing dif-ficulties of finding oil and gas.

In response, Exxon insisted the buy-back program had not cut into its invest-ment plan, reminding critics that its netexploration acreage had increased by 40percent since 2003.

Not interested in alternative energyWill Exxon invest in alternative and

renewable energy projects?No, Tillerson said, Exxon remains

committed to developing fossil fuels,which government forecasters say areneeded to meet at least 60 percent ofworld demand through 2030.

Exxon will continue to focus onimproving energy efficiencies andinventing new technologies to reduceemissions.

He also said the company plans tocontinue to invest only in research onalternatives and renewables, until theycan be profitable without governmentsubsidies.

“If I wanted to kill (tax subsidies), thething to do is for ExxonMobil to go andinvest heavily in them and then Congresswould immediately cancel the tax sub-sidy. Actually what they would do is theywould just cancel it for us.”

—KAY CASHMAN

PETROLEUM NEWS • WEEK OF MARCH 15, 2009 21

million in revenue in 2008.

Heavy debt load in AlaskaPacific Energy bought the Alaska

assets of Forest Oil in August 2007 for$464 million.

To facilitate that deal, PacificEnergy took out two loans with theGoldman Sachs affiliate J. Aron andCo. and Silver Point Capital. As ofMarch 8, the company said it had near-ly $91 million outstanding on the firstloan and around $322 million on thesecond.

The company’s Alaska assetsinclude 100 percent interest in theRedoubt unit, the West Foreland fieldand the West McArthur River unit,fields on the west side of Cook Inlet.

Pacific Energy also owns a minorityinterest in Trading Bay and McArthurRiver, offshore fields operated byChevron, and a 50 percent share of theCook Inlet Pipeline.

Pacific Energy said it owes Chevronsome $25.2 million in unpaid expenses.

Those liabilities are all listed assecured, using existing assets as collat-eral.

Pacific Energy still owes Forestnearly $32 million, the largest unse-cured creditor listed in the filings. Theremaining $9 million in liabilities islisted as “unsecured obligations.”

Altogether, Pacific Energy reportedAlaska liabilities of some $480 millionas of March 8, as well as more than $39million in additional liabilities relatedto California prospects.

Last year, Pacific Energy sold two

onshore prospects in California for$135 million to help pay down debtand raise money for future explorationactivities in Alaska.

Pacific Energy is based in LongBeach, Calif., but maintains offices inAnchorage and Bakersfield, Calif. Thecompany employs some 100 peopleacross its operations.

Chapter 11 of the bankruptcy codeis designed to rehabilitate the financesof a company through a court-approvedreorganization plan that protectsagainst creditor lawsuits.

Questions for other prospectsThe bankruptcy creates uncertainty

for several other Alaska operations.Through the 2007 purchase, Pacific

Energy picked up undeveloped acreagein Cook Inlet, including eight leases inand around the offshore Corsair unit,south of Tyonek.

Earlier this year, Pacific Energyfarmed out Corsair to Escopeta Oil, aTexas company looking to combineseveral offshore prospects in upperCook Inlet into one large unit.

The state is expected to make a deci-sion about the proposal sometime inmid-March.

Pacific Energy said it receivedapproval of the deal from its lenders,which could keep the bankruptcy fromimpacting continued attempts toexplore for oil and gas on the leases.

Through the 2007 sale, PacificEnergy also picked up a minority inter-est in the Three Mile Creek No. 1 andThree Mile Creek No. 2 gas wells oper-ated by Aurora Gas LLC. �

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PACIFIC ENERGY

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22 PETROLEUM NEWS • WEEK OF MARCH 15, 2009

the leases themselves make Alaska one ofthe largest investments in Shell’s globalportfolio,” Slaiby said.

However, although Shell expects oilprices to rebound from their current rela-tively low levels, viable oil and gas devel-opment in the remote waters aroundAlaska will be no slam dunk.

“The development of offshore Alaskais not a foregone conclusion,” Slaiby said.

But Shell is itching to mobilize itsdrilling team in the Beaufort Sea, despitecontinuing delays as a result of lawsuitsquestioning the potential environmentalimpacts of offshore exploration.

“We are shovel ready,” Slaiby said.“We have been shovel ready for a numberof years.”

The economic study that has now beencompleted only considered the quantita-tive economic impacts of OCS oil and gasdevelopment. It did not consider socialand environmental impacts, said NorthernEconomics Principal Patrick Burden —Slaiby said that Shell is carrying out aseparate social impact study.

And, for the purposes of the economicevaluation, the study considered a 50-year timeframe ending in 2057 and withoil prices averaging $65 per barrel.

Base caseThen, as a base case, the analysts tried

to forecast what would happen to Alaskain the event that OCS oil and gas devel-opment does not take place, taking intoaccount the ensuing shutdown of thetrans-Alaska pipeline in perhaps 2046, adate determined by uneconomic pipelinedeliveries of declining oil production.Closure of TAPS would necessitate thesubsequent use of expensive marinetransportation for the shipment of NorthSlope oil.

The analysts assumed that a NorthSlope natural gas export pipeline wouldgo into operation in 2020 and that thispipeline would operate at a full capacityof 4.5 billion cubic feet per day through2057, without the need for any natural gasfrom the OCS.

“This is something that’s based on aU.S. Geological Survey resource assess-ment which suggests that there are yet-to-be-found (onshore) gas resources that aresufficient to keep the pipeline full for thatentire time period,” Burden said.

The end result of all of this would be apeak in Alaska job growth during gaspipeline construction, with petroleumindustry jobs declining thereafter, Burdensaid. And, although other industrieswould grow while oil and gas declines,household income and population growthwould tend to slow.

And eventual state revenues from nat-ural gas production would be insufficientto replace oil revenues.

“We’ve assumed that new revenuesources will be needed to meet the needsof the population,” Burden said. “Thisresults in a general tax being imposed andusing earnings from the permanent fund.The general tax that we’ve modeled hereis a (personal) income tax, but it could

also be a sales tax.”

MMS scenariosThe analysts then assessed the impact

of adding OCS development into the mix,using various U.S. Minerals ManagementService environmental impact statementdevelopment scenarios, modified as nec-essary to accommodate the assumed con-struction of a North Slope gas line and the

use of up-to-date technologies. Oil andgas production estimates came from a2006 MMS assessment of economicallyrecoverable resources, Burden said.

Based on the current MMS lease saleprogram, the analysis assumed for the 50-year study period the development ofseven Beaufort Sea platforms producing atotal of 6.3 billion barrels of oil and 7 tril-lion cubic feet of natural gas; four mas-sive, gravity-based Chukchi Sea plat-forms, a Chukchi Sea shore base, with oiland gas transportation pipelines acrossthe National Petroleum Reserve-Alaska,delivering 6.2 billion barrels of oil and7.8 trillion cubic feet of gas; and, in theNorth Aleutian basin, two offshore plat-forms coupled with pipelines across theAleutian Peninsula to export 390 millionbarrels of oil and 5 trillion cubic feet ofgas.

First offshore oil would flow in 2019from the Beaufort Sea, in 2021 from theChukchi Sea and in 2022 from the NorthAleutian basin. And, on the assumptionthat factors such as shale gas in the Lower48 states and gas production from theGulf of Mexico would depress natural gasprices for several years, the analysts esti-mated that first gas from the Arctic off-shore would not flow to market until 2029for the Beaufort Sea and until 2036 forthe Chukchi Sea.

After a 10-year ramp-up, oil produc-tion rates would peak at about 1.5 mil-lion barrels per day before entering amultiyear decline, with the peakthroughput necessitating an upgrade tothe trans-Alaska oil pipeline. OCS gasproduction would require the capacity ofthe North Slope gas line to also beexpanded.

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The assumed schedule of oil and gas-related activities on the Alaska outer continental shelf, based on information from U.S. MineralsManagement Service environmental impact statements and resource estimates.

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Itta: Sounds good, but is it too good?Mayor Edward Itta, mayor of the North Slope Borough, said March 9 that he

likes the sound of the new Shell-commissioned evaluation of the potential eco-nomic benefits of oil and gas development on Alaska’s outer continental shelf. Butthe mayor also questioned whether the report paints too bright a view of a futurein which OCS hydrocarbon resources might provide major numbers of jobs andsignificant new income for the state.

“With state revenues and the national economy in suchtough shape, it sounds like music to our ears,” Itta said. “Idon’t want to rain on Shell’s parade, but this report paints apicture that is so rosy it’s hard to believe.”

Alaskans, battered by a downward slide in oil revenuesand job losses in the oil industry, will welcome any goodnews about the future. But although the analysts fromNorthern Economics and the Institute of Social andEconomic Research who carried out the study say that theyused information from the U.S. Minerals ManagementService as a prime source of data, the estimates contained in the study report vary“dramatically” from the MMS data, Itta said.

Need to be realisticIn addition, recent experience of oil price fluctuations suggests that “50-year

projections are as much about guesswork as they are about science,” Itta said. It isimportant to be wary of setting unrealistic expectations about the future, he said.

Itta added that the North Slope Borough does support oil and gas development.“I will continue to work with the state and the industry on development issues,”

Itta said. “In particular, I look forward to working with Shell to make sure that,along with economic benefits, social and cultural impacts are analyzed closely,too.”

—ALAN BAILEY

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PETROLEUM NEWS • WEEK OF MARCH 15, 2009 23

A generation of jobsFor more than 20 years direct employ-

ment from OCS work could exceed7,000, with average annual employmentlevels during the complete 50-year time-frame for OCS development and produc-tion running at about 6,000.

“Potentially it’s a generation of OCSactivity,” Burden said. “It’s a generationof jobs for people in the state.”

Taking into account the in-state spend-ing of people directly employed in OCSwork, the resulting indirect employment,including service jobs in transportation,health care and public utilities, wouldraise peak Alaska employment levels toperhaps an annual average of 35,000.That total employment figure could peakas high as 50,000 around 2038, Burdensaid.

Many direct jobs would be done off-shore and in the boroughs adjacent to theoffshore oil and gas fields. However, his-toric patterns suggest that the majority ofpeople doing these jobs would reside inAnchorage, in the Matanuska-SusitnaBorough, on the Kenai Peninsula and inFairbanks.

“But it represents an opportunity forthe residents of those regions (close to theoil and gas fields) to take those jobs ifthey desire to do so,” Burden said.

And although many of the peopleengaged in indirect work would likelylive and work in the population centers ofSouthcentral Alaska and Fairbanks, therecould be 2,000 indirect jobs in the NorthSlope Borough, adjacent the Beaufort andChukchi seas, and 1,000 indirect jobs inthe Aleutians East Borough, adjacent theSouth Aleutian basin.

Because OCS oil and gas fields wouldbe in federal waters, the State of Alaskawould miss the production tax and royal-ty bonanza that the state has enjoyed fromonshore and nearshore oil and gas —assuming, that is, that the federal govern-ment does not introduce some newarrangement for state revenue sharing forAlaska OCS production.

$5.8 billionHowever, local governments would col-

lect property taxes assessed on onshorefacilities and, under state tax law, the statewould be able to collect corporate incometax from companies with any onshoreinfrastructure. Estimated local propertytaxes of $4.5 billion, mostly on the NorthSlope, added to state property taxes andcorporate income tax would result in a totalgovernment tax take of $5.8 billion over 50years.

Then, given the expected drop in staterevenues as onshore oil and gas productiondeclines, the analysts think that the statewill be forced at some point to raise addi-tional revenues from a new general tax,despite the fact that OCS oil and gas wouldbe coming online. But, since OCS activitywould increase the number of employedstate residents, the state’s revenue from a

general tax would be higher than it wouldhave been in the “no OCS” case.

Moreover, the addition of OCS oil to thethroughput of the trans-Alaska pipelinewould reduce the unit cost of transportingoil in the pipeline, thus increasing the well-head value of North Slope oil, encouragingthe development of additional onshore oilreserves and extending the life of the

pipeline. The increased value and quantityof onshore oil would push up the state’sproduction tax and royalty take.

“Filling the TAPS pipeline … accountsfor about $5.7 billion of indirect benefits,”Burden said.

Adding OCS gas to the North Slope gasline would also drive down the tariff on thatpipeline, he said.

Adding up the direct and indirect rev-enue increases from OCS oil and gas pro-duction, and subtracting back out some costfactors such as government services associ-ated with the OCS industry, the total stateand local government income could beincreased by $15.3 billion over the 50-yearstudy period, if OCS development were totake place, the analysts determined.

And although the data presented in thestudy report represent just one view of thefuture, other plausible scenarios also indi-cate substantial economic benefits fromOCS development, Burden said.

“We know right off the bat that thefuture will not unfold as we have laid itout,” Burden said. “… Different scenarioswould have different results, but we thinkthat any reasonable set of assumptions for areasonable scenario would end up with asimilar finding that the OCS provides ben-efits to the State of Alaska. … Our model-ing suggests that the benefits and these rev-enues that we see are robust through a widevariety of changes in the assumptions.”

The state needs to think through its poli-cies and determine how to capture thosebenefits, he said. �

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Figure ES-3. Potential Total Employment Effects from OCS Development by Category

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20,000

30,000

40,000

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2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056

Direct Infrastructure Support State-Local

Source: Northern Economics, Inc. and ISER estimates.

The potential total Alaska employment that could result from oil and gas development onthe state’s outer continental shelf. Direct employment consists of jobs in the OCS oil and gasindustry. Indirect employment resulting from offshore oil and gas would occur in infrastruc-ture support, a range of support services, and state and local governments.

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energy in focusCreative photography for Alaska’s oil and gas industry

24 PETROLEUM NEWS • WEEK OF MARCH 15, 2009