page12

New weekly PN section:Tacklingthe Alaska workforce deficit

Vol. 11, No. 51 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of December 17, 2006 • $1.50

● N A T U R A L G A S

● G O V E R N M E N T

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

● N A T U R A L G A S

8Looking for hazards on Alaska gas line route: DGGS

geophysical survey pinpoints geologic faults in transportation corridor

10 Brooks Range files drilling plan: Two wells, sidetrack totest three North Slope Gwydyr Bay area prospects; possible fourth well

11 U.S. approves first FPSO in Gulf: Petrobras plans to usefloating, production, storage and offloading system in ultra deep water

Latest Petroleum Directory inside

GOM energy act passes8.3M exploration acres opened in eastern Gulf of Mexico; industry reaction mixed

By RAY TYSONFor Petroleum News

he Republican-led Congress, before turning overthe reins to the Democrats, passed 11th hour leg-islation opening an additional 8.3 million acresin the eastern Gulf of Mexico to oil and gas

exploration.The drilling measure was viewed as a political

compromise, wrapped in a broad tax and trade pack-age that the U.S. Senate approved Dec. 9 by a 79-9vote, just hours after the House of Representativesokayed the legislation.

Earlier versions of the bill pushed by Republicanswould have opened offshore areas of the U.S. Westand East coasts to exploration drilling. But with the

clock ticking down to adjournment of the 109thCongress and no clear consensus, both houses settledfor passage of the Gulf of Mexico Energy SecurityAct of 2006.

Democrats, who mustered enough seats in theNovember election to take control of Congress nextyear, largely supported the offshore bill. However,they also are expected to try to repeal oil and gas sub-sidies.

Gulf Coast states get more royaltiesThe final bill passed by both houses also provides

the Gulf Coast states of Texas, Louisiana, Mississippiand Alabama with a 37.5 percent share of federal roy-

LNG threatens costly gasEIA expects liquefied natural gas imports to Lower 48 will climb to 4.5 tcf by 2030

By GARY PARKFor Petroleum News

ot only might imports of liquefied natural gas toNorth America offset the anticipated loss ofCanadian supplies over the next decade, theycould also spell trouble for the more expensive

plays that are starting to dominate the gas sector inCanada.

In its latest annual energy outlook the U.S. EnergyInformation Administration said shipments fromCanada will start to slow at the midpoint of its fore-cast covering 2005-2030. The report predicts that gasfrom Canada will hold steady between 2.3 trillioncubic feet and 3 tcf over 2003-2015, then begin asteady descent to 900 billion cubic feet.

The EIA said the decline will stem from depletion

T

N

see ENERGY ACT page 17

British Columbia bearsbrunt of Devon cutbacks

Unhappy about the high-cost operatingenvironment in Canada, Devon Energy isreining in its 2007 spending north of the 49thparallel — and it is not alone, much to theconcern of British Columbia’s booming natu-ral gas business.

Although Devon has no plans to pull out ofCanada, company President John Richels, for-merly head of Devon’s Canadian subsidiary,said the budget trimming is a necessary partof fiscal discipline.

Speaking to analysts in November, he said:

see CUTBACKS page 17see LNG page 17

A 6-month windowCommission, gas and electric utilities need to be ready for open season

By KRISTEN NELSONPetroleum News

laska is well positioned to take gasoff in-state under an initial openseason for a North Slope naturalgas pipeline project. But if for any

reason potential in-state users don’t takecapacity on the main line in that initialopen season, they are not well positionedto ask to take gas off later.

It’s the way the Federal Energy RegulatoryCommission’s open season rules for Alaska work,Harold Heinze, chief executive officer of theAlaska Natural Gas Development Authority, toldthe Regulatory Commission of Alaska Dec. 13.

“We have an outstanding position during the

initial phase,” he said. “If we speak up,then it’s very clear” that in the initialopen season, requirements for in-stateAlaska gas have to be accommodatedboth in pipeline design and in tariff struc-turing.

“It is also clear that if we miss thewindow and we come back, say, a yearlater” requesting to take off 100 millioncubic feet a day in Delta Junction,“they’d say … sorry, but you have to pay

the full fare to Chicago because you’re asking meto let gas off early and I have … financed it on thebasis of all the gas going to Chicago.”

That initial open season window is six months

NW NPR-A open for travel, otherareas still closed; Pearce sworn in

THE BUREAU OF LAND MANAGEMENT said Dec. 13that it is allowing tundra travel in the northwest planningarea of the National Petroleum Reserve-Alaska, providedthat operators ensure that they meet the stipulations of theIntegrated Activity Plan and Environmental ImpactStatement for the area. The northeast NPR-A and state landin the central North Slope and BrooksRange foothills remain closed —Petroleum News understands that anabnormally low snow cover on theNorth Slope is the prime reason for thedelay in the openings.

The tundra travel stipulations for theNPR-A northwest planning area state“ground operations shall be allowedonly when frost and snow covers are atsufficient depths to protect the tundra.”Except for low ground pressure vehiclessuch as Rolligons, all travel must occur on ice roads.

But the northeast area requires frost to a depth of 12 inch-es and an average snow cover six inches deep.

“Frost conditions have been met within the northeast,while the average snow cover is not yet six inches,” BLMsaid. However, the bureau said that it might entertain excep-tions to the stipulations on a case-by-case basis.

see INSIDER page 18

AHAROLD HEINZE

see WINDOW page 18

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

2 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

LAND & LEASING

NATURAL GAS

GOVERNMENT

INTERNATIONAL

FINANCE & ECONOMY

PIPELINES & DOWNSTREAM

WORKFORCE DEVELOPMENT

EXPLORATION & PRODUCTION

ALTERNATIVE ENERGY 7 Oooguruk expansion application complete

Pioneer picked up needed leases to fill in unit, got royalty reduction, built gravel island; pipelines next

8 Seeking hazards on the AK Highway route

DGGS geophysical survey pinpoints locations of geologicfaults, areas of permafrost in transportation corridor

9 Synenco accessing Asian answers

Canadian company turns to Chinese partner in search for cost-cutting solutions, but faces opposition; plan includes shipping to Arctic

10 Brooks Range files drilling plan

Two wells and a sidetrack will test three North Slopeprospects in the Gwydyr Bay area; possibility of an additional well

11 U.S. OKs first FPSO in Gulf of Mexico

MMS approved use of floating, production, storage and offloading systems 4 years ago; Petrobras will use in ultra deep water

12 Tackling the Alaska workforce deficit

Anchorage conference looks at how Alaska’s education, training systems might gear up to address looming shortage of skilled workers

ON THE COVERA 6-month window

Commission, gas and electric utilities needto be ready for open season

GOM energy act passes

8.3M exploration acres opened in eastern Gulf of Mexico;industry reaction mixed

LNG threatens costly gas

EIA expects liquefied natural gas imports to Lower 48 will climb to 4.5 tcf by 2030

6 Alaska tidal energy conference scheduled

6 Anadarko, Devon score oil at Mission Deep

8 Petro-Canada rethinks project

4 Paramount sets Mackenzie spin-off terms

6 Trust merger plan takes a dive

4 Produced water: could it be a valuable resource?

4 Chevron wins approval for Gorgon

5 PPT regulations out for comment, hearing set

5 Buyers aplenty for oil sands assets

9 Face-to-face with a pledge

13 Canada: 2005 was a very good year

14 No boom from GOM Thunder Ridge field

13 Comments invited on wind energy test

British Columbia bears brunt of Devon cuts

1 NW NPR-A open for travel, other areas still closed

18 Chena geothermal project wins national awards

19 Pearce sworn in as federal coordinator for Alaska gas line

14 Nexen ready to take control of CBM play

18 EPA fines Flint Hills for clean air violations

OIL PATCH INSIDER

PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point MPF-99i BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 1J-136 ConocoPhillipsDreco 1000 UE 16 (SCR/TD) Workover DS12 12-32 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD4-211 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk 1J-103 ConocoPhillipsTSM 7000 Arctic Fox #1 Stacked in Yard Pioneer Natural Resources

Arctic Wolf #2 Racked in Prudhoe awaiting tundra FEXtravel

Kuukpik 5 Mobilizing to 2P pad, for eventual ConocoPhillipsmobilization to Noatak

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES DS 15-12B BPMid-Continental U36A 3-S GPB W-29 BPOilwell 700 E 4-ES (SCR) GPB M-15 BPDreco 1000 UE 7-ES (SCR/TD) S-31A BPDreco 1000 UE 9-ES (SCR/TD) V-122 BPOilwell 2000 Hercules 14-E (SCR) Stacked at Cape Simpson FEXOilwell 2000 Hercules 16-E (SCR/TD) Under contract for drilling

at Gwydyr Bay Brooks Range PetroleumOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableOIME 1000 19-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Stacked, Kuparuk AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Rig move BP

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) In Lynden yard for upgrades BPSuperior 700 UE 2 (SCR/CTD) Kuparuk 1C-01 BPIdeco 900 3 (SCR/TD) Kuparuk 2T 203 ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E Northstar NS-34 BP

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

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Rig maintenance Marathon

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

Cook Inlet Basin – Offshore

Unocal (Nabors Alaska Drilling labor contractor)Not Available

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

Alaska Interior

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

Mackenzie Rig StatusCanadian Beaufort Sea

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

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

Yukon Territories Rig StatusNorthwest Territories

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

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of December 14, 2006.

Active drilling companies only listed.

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

This rig report was prepared by Alan Bailey

Baker Hughes North America rotary rig counts*Nov. 10 Nov. 3 Year Ago

US 1,693 1,739 1,479Canada 446 376 569Gulf 82 87 77

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

4 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

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● G O V E R N M E N T

Produced water: could itbe a valuable resource?

By ALAN BAILEYPetroleum News

roduced water — the undergroundwater that comes to surface as part ofoil and natural gas production — hastraditionally enjoyed few uses other

than reinjection into oil reservoirs to flushout more oil.

But could the water provide additionalvalue?

On Dec. 5 the U.S. House ofRepresentatives passed the More Water forMore Energy Act of 2006, legislation thataims to push value-adding uses for pro-duced water. The act directs the Secretary ofthe Interior, acting through the commission-er of Reclamation and the director of theU.S. Geological Survey, to conduct a studyinto making more use of the water. Thestudy will identify the obstacles to increas-ing the use of produced water for irrigationand other purposes and will establishactions to overcome those obstacles. Theact also directs the secretary of the Interiorto award grants to assist in the developmentof facilities that demonstrate how the use ofproduced water can increase.

IOGCC has done national researchThe Interstate Oil and Gas Compact

Commission, an agency that promotes theconservation, the efficient recovery and thesafe recovery of the U.S. oil and gasresources on behalf of the governors of 30member states and seven associate states,has conducted a national research program

into the uses of produced water. The U.S.Department of Energy funded the research,while representatives from ALLConsulting, the Montana Board of Oil andGas Conservation, the Wyoming Oil andGas Conservation Commission, the AlaskaOil and Gas Conservation Commission, theOklahoma Corporation Commission, theKansas Corporation Commission, Citizensfor Resource Development and the oil andnatural gas industry assisted with theresearch.

Among the research findings was adetermination that U.S. oil and natural gasoperations yield approximately 14 billionbarrels of water every year. The salinity ofsome of this water is too high for crop irri-gation but large quantities of producedwater could be used in applications such aspower generation or enhanced oil recovery.

In September IOGCC used the researchresults in expert testimony in support of theMore Water for More Energy bill. The com-mission believes that more use could bemade of produced water.

“Water produced as a result of oil andgas exploration represents a valuable natu-ral resource to this country, especially in thearid western United States and in areasexperiencing prolonged drought,” saidChristine Hansen, IOGCC executive direc-tor. “The IOGCC is pleased that this billrecognizes the benefits of this resource so itwill not be wasted.”

The report from the IOGCC research isavailable athttp://www.iogcc.state.ok.us/news_pubs.aspx. ●

P

FINANCE & ECONOMYParamount sets Mackenzie spin-off terms

Shareholders of Paramount Resources will get a front-line opportunity to par-ticipate in northern oil and gas exploration when the Canadian independent spinsoff its Northwest Territories assets.

Under a plan of arrangement announced Dec. 11, the investors will get oneshare of the new Arctic company and five warrants for every 25 Paramount sharesthey hold.

The deal will be voted on by the shareholders on Jan. 11, with the spinoutexpected to be in place the next day.

Paramount will initially own 87 percent of the so-called Newco.Once in place, the publicly traded company will own rights under a farm-in

agreement Paramount negotiated in September with Chevron Canada and BPCanada Energy covering about 1.019 million gross acres on the Mackenzie Deltaand oil and gas properties in the Colville Lake area of the Mackenzie Valley cov-ering 1.483 million gross acres.

Company has drilling plansWhen it first announced the plan, Paramount said the new company would drill

on the Delta lands, where Chevron and BP have recorded some success. Meanwhile, Paramount will retain its existing producing assets and its unde-

veloped acreage, which will be run by the existing management team. The chief executive officer of Newco will be Clayton Riddell, Paramount’s

president and chief executive officer.The proceeds from the exercise of the short and longer term warrants will be

used to fund programs under the Delta farm-in, which are expected to be aboutC$130 million to the end of the 2007-2008 winter drilling season.

—GARY PARK

INTERNATIONALChevron wins approval for Gorgon

Chevron’s giant Gorgon LNG project passed a major hurdle Dec. 12 when thestate environmental minister for Western Australia overturned an agency reviewrecommending the development be blocked. The project still needs approval fromthe federal environmental minister, Ian Campbell, before work can begin.

Chevron and the other Gorgon partners appealed the rejection by the state’senvironmental authority last summer. That authority said the project should behalted because it would cause too much disruption of nesting sites for an endan-gered turtle.

Gorgon pivots on a two-train gas liquefac-tion plant on Barrow Island. The plant wouldproduce 10 million tonnes of LNG each year.The site is near beaches where the turtles nest.

Mark McGowan, the state’s environmentalminister, mandated that the partners spend $47million to protect the turtle and other species,and ordered strict ecological controls. He saidhe was confident the turtles wouldn’t be hurt by activities in and around the plant.

Gorgon was originally projected to cost around $11 billion, but is now expect-ed to run at least $15 billion.

Chevron, based in San Ramon, Calif., is the operator with 50 percent ofGorgon. Shell and ExxonMobil each hold a quarter of the project, which is saidto hold about 40 trillion cubic feet of gas.

ConocoPhillips hits more gas Meanwhile, there’s a nice new find for ConocoPhillips in the Timor Sea. The

company announced Dec. 12 that the Barossa-1 exploration well yielded a gasflow of 30.1 million cubic feet a day through a 56/64-inch choke. Even at that, theflow rate was limited by the capabilities of equipment on the surface. A secondinterval showed a flow of 800,000 cubic feet per day.

Drilling started in July at Barossa-1 in the Timor Sea about 180 miles north-west of Darwin. It was drilled in 765 feet of water to a total depth of just over14,000 feet. The well was plugged and abandoned.

Barossa is less than 20 miles from the Caldita-1 well, which showed a similarflow rate in the fall of 2005. Both are within range of the LNG plant at Darwin.Conoco, based in Houston, is now drilling a second Caldita well, and a 3D seis-mic survey over both Barossa and Caldita will begin shortly.

Both fields are in a block where operator Conoco has a 60 percent interest andSantos Offshore Pty. Ltd. has 40 percent.

—ALLEN BAKER

Gorgon was originallyprojected to cost around$11 billion, but is nowexpected to run at least

$15 billion.

PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 5

● L A N D & L E A S I N G

Buyers aplenty for oil sands assetsBy GARY PARK

For Petroleum News

alisman Energy has completed a large part of itsplanned exit from the oil sands, but an extensive list ofleases is still up for grabs.

As expected, Canadian Oil Sands Trust landedTalisman’s 1.25 percent stake in the Syncrude Canada con-sortium for C$475 million, while Suncor Energy hookedTalisman’s 2 percent gross overriding royalty on Suncor’sLease 23 near its Steepbank mine for C$107.5 million.

The Syncrude deal consisted of C$237.5 million in cashand 8.19 million units of COST, raising its dominant stakein Syncrude to 36.74 percent from 35.49 percent.

Talisman’s share of production was rated at 4,375 barrelsper day, although it has averaged only 3,400 bpd this year.

In placing its Athabasca assets on the block to clear theway for a concentrated push on its new natural gas play inthe Foothills region of Alberta, Talisman attracted interestfrom more than 50 companies.

It hopes to have other sales concluded by the end of2006, collecting about C$800 million in additional pro-ceeds. They involve a 100 percent working interest in Lease10, a 6,800 acre lease immediately south of Suncor’sSteepbank mine and a 75 percent working interest in Lease

50 covering 21,800 acres north of the OPTI Canada-Nexenjoint venture at Long Lake.

Koch, Petro-Canada also seeking buyersKoch Exploration and Petro-Canada are also seeking

buyers for major leases.Koch is offering 374,000 net acres in the Athabasca

region consisting of an estimated 23 billion barrels ofMcMurray, Wabiskaw and Grand Rapid resource potentialand 24 billion barrels of resource potential in theNisku/Grosmont carbonates. The offerings, which could beup to C$500 million, are divided into four packages.

Petro-Canada is selling various interests in five in-situproperties — Chard, Stony Mountain, Liege, Thornburyand Ipiatik — estimated to contain 1.7 billion barrels ofbitumen resource and likely to fetch as much as C$850 mil-lion.

Industry observers are counting on strong internationalinterest in the assets, especially from Korean interests afterKorea National Oil Corp. bought leases from NewmontMining in July, but Norway’s Statoil, Norsk Hydro, JapanCanada Oil Sands and state-controlled Chinese companiescould emerge as well.

Other possible contenders include Nexen-OPTI,

EnCana, Devon Canada, North American Oil Sands, MEGEnergy (which has China National Offshore Oil Corp. as a16.69 percent partner in a project) and Connacher Oil andGas.

Athabasca project partners Chevron and Western OilSands are also viewed as active acquisitors.

November sale nets C$78.2 millionThe hunger for oil sands property shows no signs of

diminishing at Alberta government sales, with bidders pay-ing C$78.2 million Nov. 29 for oil sands parcels.

Scott Land & Lease, acting for an unidentified client,paid C$37 million for rights to 27,800 acres, whileSaskatoon Assets paid C$28 million for a connecting par-cel.

The parcels are northwest and northeast of the FirebagWest and Muskeg area interests held by Value Creation andShell Canada.

Shell combined with RSX Energy to bid C$1.19 millionfor 1,265 acres in the same area where it paid C$6.2 millionfor 2,530 acres in July.

So far this year, oil sands rights have claimed more thanhalf the C$3.29 billion the government has collected at itsbi-monthly auctions. ●

T

GOVERNMENTPPT regulationsout for comment,hearing set

The Alaska Department of Revenuesaid Nov. 13 that it has proposed regula-tions for the new oil and gas productiontax passed by the Legislature in Augustout for review, and has scheduled a hear-ing in January to take comments on theregulations. The department said manyof the proposed regulations changeswould apply retroactively to April 1,2006, although in some cases thechanges are proposed to apply retroac-tively to March 1, 2007, in the eventchanges take effect after that date.

The proposed regulation languageis available online atwww.legis.state.ak.us/folhome.htm.Select “The Alaska AdministrativeCode,” “Title 15 Revenue” and then“Chapter 55 Oil and Gas PropertiesProduction Tax.”

The department is seeking publiccomment on the proposed regulations.

Written comments may be submittedto Gary Rogers, Tax Division,Department of Revenue, State of Alaska,550 W. 7th Ave., Ste. 500, Anchorage,AK 99501, or by email to:gary_rogers@revenue.state.ak.us or byfacsimile to: (907) 269-6644, attentionGary Rogers, Tax Division. Rogers isalso the contact for a copy of the pro-posed regulations.

The department said comments mustbe received by 5 p.m. Jan. 17, 2007, andnoted that both written and oral com-ments received are public records andare subject to public inspection.

The department will also take oral orwritten comments at a public hearingJan. 11-12 in Room 240, 550 W. 7thAve., Anchorage, Alaska. The hearingwill be held on both days from 9 a.m. to12 p.m. and the department said thehearing might be extended to accommo-date those present before 12:00 p.m.who have not had an opportunity tocomment. Comments in the public hear-ing may be made by phone. The numberis (800) 315-6338. When prompted forthe code enter 1014#.

6 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

● F I N A N C E & E C O N O M Y

Trust merger plangoes down in flames

By GARY PARKFor Petroleum News

he Canadian government’s plan totax income trusts has sent one pro-posed merger down in flames, withShiningbank Energy Income Fund

and Rider Resources bailing out of aC$496 million deal.

Unable to obtain government guidanceon rules that will govern the trust sector,they announced on Dec. 8 that the dealthey unveiled in September has been ter-minated.

Completing the transaction wouldhave boosted Shiningbank’s proved andprobable reserves by 24.8 million barrelsof oil equivalent and its production by8,800 barrels of oil equivalent per day.

But even before the federal govern-ment stunned the trust world by announc-ing its tax-favored status would beremoved in 2011, investors were nothappy with the planned transaction.

They said Shiningbank was paying toomuch for gas-weighted assets in the midstof a commodity price slump and at a timewhen the trust’s units had tumbled from a52 week high of C$30.94 to around C$15.

However, Shiningbank ChiefExecutive Officer David Fitzpatrickpinned the failure of the merger on thegovernment’s refusal to clarify the rulesthat will govern trusts in the future as wellas its failure to indicate whether therewould be any retroactive application ofthe rules to transactions that were in theworks before the Oct. 31 announcementthat trusts would be taxed at the same rateas conventional companies.

“We had sought clarity and hadn’treceived it,” he said.

Guidance promised before ChristmasThe best Finance Minister Jim

Flaherty has promised is that the guid-ance for the transition period to 2011 willbe released before Christmas, althoughlegislation is not expected to be tableduntil early 2007.

What makes the trusts anxious isFlaherty’s intention to prevent “undue”expansion of the trusts before 2011.Analysts have speculated that could meana 15 percent cap on expansions.

Also in an uncertain state is a proposedtakeover by Crescent Point Energy Trustof Mission Oil & Gas for C$760 million.

Crescent Point and Mission say theyare still trying to evaluate the impact ofthe tax changes before deciding whetherto proceed.

The only sign of the government’sthinking was a “comfort” letter fromFlaherty’s department that encouragedPengrowth Energy Trust to stick with itsplanned C$1.04 billion purchase ofAlberta oil and gas assets fromConocoPhillips.

But the frustration in the trust worldwas expressed Dec. 6 by GeorgeKesteven, president of the CanadianAssociation of Income Funds, who saidthat even if the government provides thedetails of the tax changes beforeChristmas it will likely take much longerto grasp the consequences.

“Part of the problem we have rightnow is there is no road map from the gov-ernment over the four-year time frame,”he told the Calgary Herald’s editorialboard.

“In addition to the lack of clarityaround ‘undue expansion’ and growth noone has told us what we’re supposed tolook like in four years. (Does the govern-ment) want us to convert to corporation?”

In a meeting with Flaherty earlier inDecember, the association representing250 trusts covering a wide business spec-trum, with about one-fifth from the ener-gy sector, asked the minister to allowexisting trusts to continue as they do nowunder the legislation.

Failing that, the association requesteda 10-year transition period.

Kesteven said the market is in a stateof “suspended animation until we getclarity,” adding that the “bad policy” ofOct. 31 is continuing to inflict damage. ●

T

EXPLORATION & PRODUCTIONAnadarko, Devon score oil at Mission Deep

Deepwater partners Anadarko Petroleum and Devon Energy said they made an oildiscovery on their Mission Deep prospect in the Gulf of Mexico, adding that the explo-ration well encountered more than 250 feet of net pay in the primary middle Miocenetarget.

Located on Green Canyon block 955, thediscovery well was drilled to a depth of about25,000 feet, including 7,300 feet of water.Future plans include deepening the well to asecondary Lower Tertiary objective and drillinga sidetrack well to further delineate the extent ofthe reservoir, Mission Deep operator Anadarkosaid Dec. 11.

Mission Deep is Anadarko’s ninth discoveryout of a dozen tests so far this year in the deep-water Gulf of Mexico, following up on lastyear’s deepwater exploration program in which the company was successful on five ofnine attempts.

Anadarko has an inventory of about 150 prospects and leads in the U.S. Gulf, rep-resenting an estimated 13 billion to 18 billion barrels of “gross un-risked” resourcepotential, said Bob Daniels, Anadarko’s senior vice president of worldwide exploration.

“Anadarko plans to drill 10 to 15 exploration tests over the next two years to eval-uate this potential within our focused position in the Miocene and emerging LowerTertiary plays,” he said.

Devon also successful in Walker RidgeAnadarko and Devon are 50-50 partners in the Mission Deep prospect. Devon also

has had success in the highly acclaimed Lower Tertiary play with its Cascade, St. Maloand Jack discoveries in Walker Ridge. Devon and Anadarko own a share of anotherLower Tertiary discovery called Kaskida, located in Keathley Canyon and operated byBP.

“With 15 additional prospects in our Miocene inventory and nearly 20 LowerTertiary prospects, we are very optimistic about continued success from our Gulfexploration program in 2007 and beyond,” Stephen Hadden, Devon’s senior vice pres-ident of exploration and production, said, adding that Devon’s deepwater Gulf prospectinventory represents up to 7 billion barrels of resource potential.

Devon said it is paying 100 percent of the cost of the Mission Deep well pursuantto the terms of a joint venture agreement entered into with Kerr- McGee Corp. prior toits recent acquisition by Anadarko. Mission Deep is the final well subject to the jointventure, Devon noted.

—RAY TYSON

Anadarko and Devon are50-50 partners in the

Mission Deep prospect.Devon also has had success

in the highly acclaimedLower Tertiary play with itsCascade, St. Malo and Jackdiscoveries in Walker Ridge.

ALTERNATIVE ENERGYAlaska tidal energy conference scheduled

The Alaska Energy Authority is holding Alaska’s first tidal energy confer-ence in the Ted Ferry Conference Center in Ketchikan on Jan. 23 and 24. A vari-ety of experts will give presentations and the public is invited to attend.

AEA is investigating alternative energy sources, including tidal power, asreplacements for diesel fuel in some areas of Alaska.

Conference presentations will include:• A tidal energy overview;• A report on Verdant Power’s New York city East River environmental

study;• The tidal energy resources of selected southeast Alaska sites;• Environmental and regulatory permitting;• Tidal energy devices nearing commercialization; and • Opportunities and obstacles to project development. Speakers will include Roger Bedard, Electric Power Research Institute ocean

energy project manager and co-author of EPRI’s international studies andreports on wave and tidal energy; and Trey Taylor, co-founder and president ofVerdant Power, a company that specializes in generating electricity from natu-ral underwater currents.

In addition to AEA, Ketchikan Public Utilities; Alaska Electric Power andLight Company; Alaska Power and Telephone; and the Denali commission aresponsoring the conference.

For more information or to register contact Kim Hendricks atKIMH1@city.ketchikan.ak.us or (907) 228-5446.

—ALAN BAILEY

PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 7

● L A N D & L E A S I N G

Oooguruk expansionapplication completePioneer Natural Resources picked up needed leases to fill inunit, got royalty reduction, built gravel island; pipelines next

By KRISTEN NELSONPetroleum News

ioneer Natural Resources Alaska hascompleted an application to expandits North Slope Oooguruk unit,which now includes 12 State of

Alaska oil and gas leases, with an addi-tional seven state leases. The AlaskaDepartment of Natural Resources saidNov. 30 that the expansion wouldincrease the unit’s size by 150 percent,from 20,394 acres to 50,883 acres.

Pioneer applied to have state leasesADL 355036, 355037, 355038, 355039,389959, 389960 and 379301 added to theunit last year; the Alaska Department ofNatural Resources’ Division of Oil andGas asked for more information andfound the application complete in lateNovember. The application is now out for30-day public comment; the division thenhas 60 days to issue a decision.

Oooguruk is offshore the North Slopeand adjacent to the Kuparuk River unit onthe east.

Six of the seven additional leases arein a block on the southwest of the existingunit, which was approved in 2003; theseventh lease is on the eastern edge of theunit, between existing unit leases.

Pioneer did not control these sevenleases when the unit was formed. It sub-sequently acquired four of the leases fromConocoPhillips and the other three fromAnadarko Petroleum.

Company has drilled three wellsPioneer originally partnered with

Armstrong Alaska, which subsequentlysold its Alaska interests to ENI PetroleumExploration; unit leases are now held 70percent by Pioneer and 30 percent byENI.

Armstrong submitted a plan of opera-tions for Oooguruk in July 2002; inDecember of that year, Armstrongassigned 70 percent of its working inter-est in nine leases to Pioneer, whichbecame operator and began an explo-ration drilling program targeting theKuparuk C sands.

Pioneer submitted an application forthe Oooguruk unit in January 2003,which the division approved in July 2003.Pioneer spud the Ivik 1 well in February2003 and went on to drill the Oooguruk 1and the Natchiq 1.

DNR approved royalty modificationfor nine leases in February 2006, thesame month in which Pioneer approvedunit development.

Four of the leases were acquired in1983 on a net profit share basis, with 10-year primary terms of a fixed 12.5 percentroyalty rate and 30 percent net profitshare for the state. These four leases werecommitted to the Kuukpik unit, whichterminated in 2001. Prior to lease termexpiration, a well was drilled on eachlease and the wells were certified capableof producing in paying quantities, extend-ing the leases, primary terms indefinitely.

The royalty modification requested a 5percent royalty rate and a 30 percent netprofit share to the state for the NPS leas-es and a modification from 16.6667 per-cent to 5 percent on five other leases.

DNR implemented royalty relief as

follows: a 5 percent royalty rate for pro-duction from delineated pools until NPSpayments first become due to the statefrom ADL 355036, which occurs whencosts of the development are paid off.

In the first month following the monthwhen NPS payments first become due, afour-year royalty modification phase-outbegins for all nine leases subject to theroyalty modification, with a 1.875 per-cent increase in the royalty rate until thatrate reaches 12.5 percent for the four leas-es with a 12.5 percent royalty; NPSremains at 30 percent for those leases.

At the beginning of the fourth 12-month period after NPS paymentsbecome due from ADL 355036, the royal-ty rate will immediately be restored to16.6667 percent for the non-NPS leases.

The decision also required that theproject be sanctioned by Dec. 31, 2007;sanction occurred in 2005, with gravelisland construction the winter of 2005-06,production modules going in in 2007, aswell as the subsea pipeline. Developmentdrilling is expected to start in 2007, withfirst production in 2008.

Area of known discoveriesThe state said there are six wells cer-

tified capable of production in payingquantities within the proposed expansionarea — five on net profit share leases forwhich Pioneer received royalty relief —and two other certified wells in thevicinity of the unit.

The eight wells certified by the stateare: Exxon Thetis Island 1, in the north-east part of the unit; ARCO Kalubik 1;and four Colville Delta wells (TexacoColville 1, 1A, 2 and 3) that lie on thefour net profit share leases. The twoother certified wells, outside and to thewest of the unit, are the Kuukpik 3(approximately two and one half miles)and the Amerada Hess Corp. Colville25-13-6 (approximately a quarter of amile).

Pioneer Natural Resources Presidentand COO Timothy Dove said in aNovember analysts’ call that the compa-ny is looking at adjacent opportunities topossibly tie into Oooguruk.

He said there are “known reserves inand around Oooguruk that we’re nowevaluating for potential tie-ins as we getcloser to actual production. In fact weknow that there’s a known resourceabout two to three miles away that’s 20million to 30 million barrels, which hasseveral wells already having penetratedit.”

“If you’re standing on Pioneer’sisland and look around in a two- tothree-mile radius you’ll see an area thatwas initially drilled mainly by Texacoand ARCO,” Bill Van Dyke of theAlaska Division of Oil and Gas toldPetroleum News in November.

“To the southwest are ConocoPhillipsleases and the Makua wells Conoco islooking at drilling,” he said.

While Pioneer is developing a reser-voir similar in age to Alpine, there is“also a chance to pick up a Kuparukreservoir.”

“There’s always been good oil chargein the area from Oooguruk to Alpine,”Van Dyke said. ●

P

8 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

EXPLORATION & PRODUCTIONPetro-Canada rethinks project

Petro-Canada and its two junior partners may take smaller steps as they moveahead with their Fort Hills oil sands project.

The operator, already behind schedule in releasing a detailed plan for Fort Hills, isnow pondering whether to scale back in planned startup from 170,000 barrels per day,said Neil Carmata, senior vice president for oil sands.

The schedule currently calls for the project to come on stream in 2011 Although the ultimate production goal of 340,000 bpd is unchanged, he said staff

working on the project have been asked to “go back to the drawing board and look atsomething smaller ... to see what that looks like and how many people it would taketo build. Does that look easier to pull off?”

Carmata said it may now take three steps to achieve full capacity, once a decisionon the first phase and final costs estimates are available by mid-2007, about sixmonths behind the earlier timetable.

But for now, the partnership has filed applications with Alberta regulators for anupgrader near Edmonton.

The facility is expected to eventually process up to 340,000 bpd from the Fort Hillsmine and other production sources, yielding 280,000 bpd of synthetic crude whichwould be marketed for refining into gasoline and diesel.

Carmata said the filings show Petro-Canada is serious about Fort Hills, eventhough it is faced with a “diseconomy” of scale in Alberta because of labor shortagesand the rising cost of materials.

He said the bigger the project “the more risk there is in being able to execute it suc-cessfully.”

He would not indicate how much smaller the startup phase could be, although therehas been speculation it could be reduced to 100,000 bpd.

Petro-Canada owns 5 percent of Fort Hills, with UTS Energy holding 30 percentand Teck Cominco 15 percent.

UTS Chief Executive Officer Will Roach said his company is eager to proceedwith exploiting a resource estimated at 4.7 billion barrels.

“It is just a matter of how quickly we get to the huge project of 340,000 bpd,” hesaid.

—GARY PARK

● N A T U R A L G A S

Looking for hazards on the AK Highway routeDGGS airborne geophysical survey pinpoints locations of geologic faults, areas of permafrost in an important transportation corridor

By ALAN BAILEYPetroleum News

purred by the possibility of future pipeline, railroador other infrastructure along the route of the AlaskaHighway, Alaska’s Division of Geological andGeophysical Surveys is conducting a study into

geologic hazards and possible sources of constructionmaterials in a land corridor bordering the highway.Geologic hazards to be investigated include active faults,areas of permafrost and areas of slope instability.Construction materials might include sand and gravelfrom near-surface deposits.

Faced with an area where river deposits and other sur-face sediment largely obscure the bedrock, DGGS initi-ated its study with an airborne magnetic and electromag-netic geophysical survey. Through a contract withDGGS, Stevens Exploration Management Co. subcon-tracted Fugro Airborne Surveys to conduct the surveyalong a 16-mile-wide highway corridor, covering about3,000 square miles in the almost 200-mile distancebetween Delta Junction and the Canadian border.

In a presentation to the Alaska Geological Society onDec. 7 Laurel Burns of DGGS described some of theresults of the survey and the plans for the second phaseof the Alaska Highway corridor study.

“Most geologic mapping in the area is reconnaissancefrom the 1960s and 1970s,” Burns said. “… There’s alsoa very poor knowledge of the material resources andgeologic hazards along this route, particularly per-mafrost and recent faulting in this area.”

Burns pointed out that the Alaska Highway corridorsits between two major fault systems, the Denali faultsystem and the Tintina fault system. And although ingeneral the area only experiences low levels of seismicactivity, movement on the Denali fault caused a magni-tude 7.9 earthquake in 2002. The highway corridor isonly about 12 to 25 miles from the Denali fault zone,Burns said.

Helicopter surveyThe helicopter-borne magnetic and electromagnetic

geophysical survey used transmitting and receivingequipment housed in what is known as a “bird,” a torpe-

do-shaped device hung below the helicopter.A magnetometer in the bird recorded the magnetic

values of a relatively wide and deep area below theinstrument. This type of data generally shows variationsin the amount of iron in the rocks and can be used to helpdistinguish and delineate geologic features such as rocktypes and faults.

The electromagnetic data were collected using elec-tromagnetic transmitting and receiving coils in the bird,with different coils operating at different electromagnet-ic frequencies. Each transmitting coil emits a primarymagnetic field at the frequency at which the coil oper-ates. The magnetic field induces an alternating current inany material in the ground that can conduct electricity.That alternating current produces a secondary magneticfield that a receiving electrical coil in the bird can detect.

The time taken for the secondary magnetic signal toreach the receiving coil and the strength of that signalprovide information about the depth of a subsurfaceelectrical conductor and how well that subsurface featureconducts electricity.

Different types of rock tend to have different electri-cal conductivity, so that an electromagnetic survey canreveal information about the near surface geology. Anelectromagnetic survey can also detect subsurface con-ducting material such as water or metal pipelines. Thetechnique has been used for applications such as detect-ing old river channels (potential sources of gravel), leak-ing water and buried pipelines.

Depth of penetrationA key factor in determining the depth of penetration

below the land surface of a survey is the frequency of thesignal that is used — the higher the frequency the shal-lower the depth of the electromagnetic measurement.The Alaska Highway corridor survey used a frequencyrange from 140,000 hertz to 400 hertz to map featuresfrom about 5 meters to about 150 meters below the sur-

face. And, because the survey was targeting sediment and

rock strata, the electromagnetic coils were configured toemphasize horizontal subsurface features.

Acquiring airborne magnetic and electromagneticdata together provides more criteria to aid in geologicmapping than can be obtained from the individual typesof data — some features show up well from magneticdata, while other features can be detected better fromelectromagnetic data.

The helicopter flew a series of parallel survey linesaligned slightly west of north and one quarter of a mileapart. Fugro Airborne Surveys then used the survey datato derive an electromagnetic profile for every third sur-vey line.

Burns showed some subsurface cross-sections thatdemonstrated the results of the survey — cross-sectionsof the subsurface resistance to electrical currents depict-ed features such as presumed permafrost. A typical sec-tion near the town of Tok showed a shallow, electricallyresistive layer of presumed sediments lying over a moreconductive layer that probably represents the water table.Another resistive layer underlies the conductive layer.

Fault patternsA complex pattern of faults proved to be a particular-

ly interesting finding from the survey — because of thelack of surface rock outcrops in the area these featureswere previously unknown. In fact the survey showed amuch higher density of faults than existing geologicmaps of the surrounding area have depicted. And the vastmajority of the interpreted faults appear to slope down-wards at steep angles.

A key issue from the point of view of the constructionof a transportation infrastructure is the question of whichfaults are currently active.

“A lot of what we are observing is likely related toolder faulting and it will take detailed geologic mappingand geophysical modeling to determine what’s recentand considered a potential geologic hazard,” Burns said.

Surface field mappingIn phase two of the survey project, DGGS plans to do

SThe Alaska Highway corridor survey used afrequency range from 140,000 hertz to 400

hertz to map features from about 5 meters toabout 150 meters below the surface.

see ALASKA HIGHWAY page 19

By GARY PARKFor Petroleum News

il sands startup Synenco Energy isready to exploit its Asian connec-tions to ship prefabricated mod-ules for its Northern Lights project

across the Pacific into the Arctic Ocean,then by barge along Canada’s northernriver system.

It’s an unparalleled strategy to fendoff soaring labor and materials costs inthe oil sands that is already attracting theire of organized labor.

But Synenco and its 40 percent part-ner, SinoCanada Petroleum (a whollyowned subsidiary of China’s Sinopec),estimate it can slash their latest estimat-ed upstream capital costs from C$5.6billion to C $4.4 billion, or C$49,170 perdaily barrel of production to C$38,532.

The approach is “going to be differentfrom other oil sands developers, but it’sone we think is best for our company,”said Synenco President and ChiefOperating Officer Todd Newton.

“Our approach should provide relieffrom the current cost environment (inAlberta) while recruiting the vast capa-bilities of our partner.”

He noted that Sinopec is a “function-ally integrated construction group,” withaccess to the full array of engineering,technical, fabrication, construction andprocurement expertise.

Modules will weigh up to 2,000 tonsThe plan calls for building modules

weighing up to 2,000 tons — 12 timesthe size of modules normally built forthe oil sands — in China, South Korea orMalaysia.

They would then be shipped acrossthe Pacific and into the Arctic Ocean fortransfer to barges, which would takeabout 24 days on the Mackenzie, Slaveand Athabasca rivers, as well as crossingGreat Slave Lake and Lake Athabasca,to reach the Northern Lights site innortheastern Alberta.

If components were manufactured inthe Edmonton area they would faceweight limits on the highway of 175tons.

The river route got a fresh workoutlast summer when NorthernTransportation Co. operated a tugboatand barge to Fort McMurray in Alberta— the first such voyage since 1979.

The results have convinced NorthernTransportation (a partnership ofInuvialuit and Inuit aboriginal enterpris-es) the Synenco idea is feasible,although no contracts have yet beensigned.

Synenco has hired AMMOET, alogistics firm, to coordinate the trans-portation plan.

Plan faces opposition from unionsThere are some reservations about the

plan, given the uncertainty of Arcticweather, which could limit the barge sea-son.

But the toughest opposition is likelyto come from the Alberta BuildingTrades Council, representing 16 unions

and 50,000 workers.Synenco has said its Asian solution

will shrink the on-site constructionworkforce to about 900 from 2,000.

Building trades Chairman RichardWassill told the Edmonton Journal thatAlbertans should be concerned about theprospect of seeing jobs exported as muchas the current export of bitumen toupgraders and refineries in the UnitedStates.

He suggested Alberta’s new premierEd Stelmach, who wants measures takento keep more of the value-added conver-sion of bitumen into synthetic crude inAlberta, is likely to hear from the unionsalong with industrial suppliers, fabrica-tors and truckers.

Newton said Northern Lights will stillhave a tough job recruiting 900 workersand has not ruled out going overseas toaccomplish that task.

He also emphasized that it is mucheasier to negotiate fixed-price contractsin Asia than it is in Alberta.

Responding to the anticipated criti-cism, Newton said Northern Lights willgenerate major benefits for Alberta bycreating 1,100 jobs once it comes onstream at an expected 100,000 barrelsper day in 2010 — a peak that is project-ed to last 30 years.

Payout sooner, so royalties go to 25% sooner

In addition, because of the expectedcut in capital costs, payout will beachieved sooner, which means royaltiessoar from 1 percent to 25 percent.

Reflecting the inflationary pressureson the oil sands, the project at one timewas estimated to cost C$1.7 billion forthe mining and extraction facilities.

But Synenco noted that approximatecapital costs per barrel of productionhave surged from C$100 per barrel in2003 at Shell Canada’s Athabasca proj-ect to C$200 for Syncrude Canada’sthird-phase expansion completed thisyear, to C$225 for the Long Lake jointventure by Nexen and OPTI Canada and,most recently, something in the range ofC$350 at Shell’s Athabasca expansion of100,000 bpd scheduled to start opera-tions in 2010.

However, Synenco cautioned that itslatest upstream forecast is based on con-stant 2006 dollars and could still missthe mark by as much as 30 percent on thehigh side and 10 percent on the low end.

The lease holds 1.67 billion barrels ofbitumen in place, an increase of 180 mil-lion barrels following drilling last win-ter. The recoverable resource is estimat-ed at 1.3 billion barrels.

The project also includes plans for anupgrader in the Edmonton area, but anupdate of the budgeted C$3.6 billion forthat job won’t be released until 2007.The use of Asian manufacturers is alsobeing considered for that portion. ●

PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 9

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

Synenco accessingAsian answersCanadian company turns to Chinese partner in search for cost-cuttingsolutions, but faces opposition; plan includes shipping to Arctic

Synenco has said its Asiansolution will shrink the on-siteconstruction workforce to about

900 from 2,000.O

Face-to-face with a pledgeEd Stelmach chose a Friday to be sworn in as the 13th Premier in Alberta’s 107-year

history as a Canadian province.That would suggest he is not prone to superstitious leanings.But he won’t have much time to revel in his stunning leadership victory.No sooner was he in office, than he collided head-on with one of his key election

pledges.Stelmach gave priority to protecting the jobs of Albertans in the oil sands by decry-

ing the loss of high-end employment from the export of raw bitumen for upgrading tosynthetic crude in the United States. Just a day after his victory on Dec. 3, he conced-ed that stopping the shipments is unrealistic, but he plans to take whatever steps arewithin his government’s power to keep more of the upgrading within the province.

What he likely didn’t count on was the loss of oil sands’manufacturing jobs to Asiaif Synenco Energy and its Chinese partner Sinopec to fabricate components of itsupstream and downstream facilities in Asia — a loss of 900 construction jobs at theupstream end alone.

Stelmach has yet to spell out in detail what he can do to keep the upgrading and themanufacturing jobs in Alberta.

But his political opponents have wasted no time pouncing on the issue.Hugh MacDonald, energy spokesman for the Liberal party, said that Synenco’s plan

to “do everything offshore is a total sellout of this province.”New Democratic leader Brian Mason said Synenco’s drastic measures to avoid cost

inflation and labor shortages in Alberta should trigger a sweeping review of oil sandsdevelopment.

The job facing Stelmach is to tackle the question of whether Alberta is getting valuefrom its own resources, given the indications that the province is being shoulderedaside in the extraction and processing of bitumen.

During the leadership campaign, Stelmach, speaking from his experience as afarmer, said that giving U.S. companies a free pass to process bitumen was like “scrap-ing off the topsoil, selling it, and thinking we have a rich farm because we have cash inthe bank.”

He suggested economic incentives might be needed, rather than financial penaltiesor inflexible rules, to keep the upgrading at home.

“I know we can’t add value to every ton of bitumen, but we can improve,” he saidDec. 4.

MacDonald favors a tougher line, requiring oil sands developers to hire aboriginal,local, provincial and Canadian companies for their construction and procurement work.

Unless action is taken, the Synenco move could put the Alberta steel fabricationindustry “in the trench,” he said.

Others, including Andre Plourde, a University of Alberta energy economist, said theSynenco decision was probably inevitable to arrest spiraling costs.

He cautioned that any moves to curb costs, such as slowing the pace of oil sandsdevelopment, would only cause investment uncertainty and damage Alberta’s careful-ly crafted reputation as a good place to do business.

—GARY PARK

10 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

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

Brooks Range files drilling planTwo wells and a sidetrack will test three North Slope prospects in the Gwydyr Bay area; possibility of an additional well

By ALAN BAILEY & KAY CASHMANPetroleum News

rooks Range Petroleum Corp. has submitted itsplan of operations to the Alaska Department ofNatural Resources for the company’s North Slopewinter 2006-07 exploration drilling program. That

program consists of two wells and a sidetrack targetingthree oil prospects north of the Prudhoe Bay unit. Thecompany may also drill an additional well if time per-mits and if the results from the other wells look promis-ing.

Brooks Range Petroleum, a wholly owned subsidiaryof Alaska Venture Capital Group, has formed a joint ven-ture with TG World Energy Inc., Ramshorn Investmentsand Bow Valley Alaska Corp. forthe exploration and development ofAVCG-operated North Slope oiland gas leases. Brooks RangePetroleum was formed in 2004 todeal with AVCG’s operations, tech-nical services and administrativeservices.

On Nov. 15 at the ResourceDevelopment Council annual con-ference in Anchorage KenThompson, managing director ofAVCG, said that in addition todrilling exploration wellsAVCG/Brooks Range is planningan extensive 3D seismic survey atGwydyr Bay this winter. And, if time permits, the com-pany will also acquire 3D seismic in the Titania areaonshore immediately south of the Colville River unit.The company is also negotiating with the major oil pro-ducers for access to existing seismic data, Thompsonsaid.

“Our company is playing a key role in discoveringnew reserves in the main central part of the NorthSlope,” Thompson said. “As the fields become smallerand smaller in that area, we’ll be looking for 25 millionto 50 million-barrel fields, hoping we’ll also stumbleinto a 100 million or 200 million barrel field that stillmay be left.”

Ice road and ice padThe winter exploration schedule anticipates con-

structing an ice road to ice pads once the tundra travelseason has opened in December. The first well, the NorthShore No. 1, will then be drilled from an ice pad at sec-tion 12, township 12 north, range 12 east of the UmiatMeridian. The second well and its sidetrack, Sak RiverNo. 1 and Sak River No. 1A, will be drilled from an icepad at section 1, T12N, R12E, UM. Both of the ice padsare onshore: the North Shore well will use directionaldrilling to target a prospect under the Kuparuk RiverDelta, while the Sak River well and sidetrack will usedirectional drilling to target offshore prospects understate waters of the Beaufort Sea.

The main ice road will start at the S-Pad in the

Prudhoe Bay field and extend approximately six milesnorth to the Sak River pad, the more northerly of the twoice pads. A short spur ice road will extend east from themain ice road to the North Shore pad. Generally the iceroads will be 35 feet wide and six inches thick. The icepads will be no larger than 600 feet square and will havemaximum depths of two feet under the locations of thedrilling rig. An on-site camp will support most of thepersonnel involved in the exploration activities.

Brooks Range has contracted with Nabors DrillingAlaska to use the Nabors rig 16E for the drilling. BakerEnergy, a subsidiary of Michael Baker Corp., will pro-vide oversight of drilling operations and, in the event ofan oil discovery, will provide engineering, facility designand operations management services, Thompson said.

Jim Winegarner, vice president of land and externalaffairs for Brooks Range Petroleum, told PetroleumNews that the North Shore No. 1 well will target a struc-tural high, updip of a prospect where the Mobil GwydyrBay South No. 1 well tested oil in 1974. The targetprospect lies in an Exxon, Chevron and ConocoPhillipslease — the lease owners have expressed support for afarm-out for the prospect, Winegarner said.

The Sak River well and sidetrack will target offshoreGwydyr Bay prospects in AVCG acreage.

“Our Sak River No. 1 and No. 1A well will first drilla leg to test what we can see on seismic as a thick upperKuparuk sand,” Winegarner said. “We’ll come back andsidetrack the well to a structural closure that we see inthe lower Kuparuk.”

The Sak River prospects used to be in the BP-operat-ed Sak River unit. BP had planned to drill in the unit inthe winter of 2002-03, with AVCG holding a 38 percentworking interest in the well. But that well was never

drilled and the Sak River unit was later terminated.

Environmentally responsibleWinegarner emphasized the efforts AVCG/Brooks

Range has made to support environmentally responsibleexploration and development. According to the plan ofoperations “the proposed ice road and pads were sited tominimize the number of future exploration/appraisal wellsneeded prior to future development. … In order to use theexploration wells in a development/production effort, thesurface locations will be selected to maintain the BeaufortSea coastline and the Kuparuk River main channel set-back distance of 500 feet and one-half mile, respectively.”

And the use of directional drilling from onshore wellpads will eliminate the need to drill from offshore loca-tions.

“BRPC’s proposed exploration activities were wellreceived by both the North Slope Borough PlanningCommission and the Alaska Eskimo WhalingCommission,” the plan of operations says. “Both groupsrecognize and appreciate the selection of onshore direc-tional drilling, which is the environmentally preferredalternative for field development, for exploration phaseactivities.”

Thompson also emphasized the critical importance ofsafety and the environment in AVCG/Brooks Range’sbusiness strategy.

He also said that the company is a niche independent,exploring in the central North Slope, onshore near theexisting pipeline infrastructure, and also building a port-folio of satellite exploration prospects. Since 1999 thecompany’s North Slope acreage has grown from a littleless than 5,000 acres to about 180,000 acres, he said.

B

The locations of the well pads and directionally drilled wells for the AVCG/Brooks Range 2006/2007 exploration drilling pro-gram. The target prospect for the North Shore No. 1 well lies under the Kuparuk River Delta, while the Sak River No. 1 welland sidetrack target prospects are under state waters of the Beaufort Sea.

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see BROOKS RANGE page 11

“Keep your eye onus because we’regoing to grow fromhere.” —Ken Thompson,managing directorof AVCG

JUD

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PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 11

Focus on ‘billion-dollar fairway’The company is particularly focusing

on what is known as the “billion-dollarfairway,” an area that Thompson hasdescribed to Petroleum News as “a north-south trending long rectangle” with awestern edge a few miles inside NPR-Aand an eastern boundary reaching theKuparuk and Tarn oil fields. The fairwayextends north to south from the near-shoreBeaufort Sea to an area several milessouth of Tarn. The Alpine oil field and itssatellites lie inside the fairway.

“We think this is a rich area still, notfully explored,” Thompson said.

AVCG/Brooks Range had an interest inthe Cronus unit that Pioneer drilled in thewinter of 2005-06; Cronus lies south ofthe Colville River unit. The Cronus wellencountered a vertical oil section but thereservoir quality was too poor to produce,Thompson said, adding that his companyis looking at areas where it thinks that thereservoir quality is better.

The company also holds a smallacreage position in the Slugger unit, in theeastern North Slope, southwest of PointThompson and immediately west of theArctic National Wildlife Refuge.

Thompson said that AVCG/BrooksRange has a more than $60 million explo-ration budget for land acquisition, seismicacquisition and drilling. Plans include twowells per winter drilling season in 2007-08 and 2008-09.

“Keep your eye on us because we’regoing to grow from here,” Thompsonsaid. ●

continued from page 10

BROOKS RANGE

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

U.S. OKs first FPSO in Gulf of MexicoMMS approved use of floating, production, storage and offloading systems 4 years ago; Petrobras will use in ultra deep water

By RAY TYSONFor Petroleum News

he federal regulatory agency that over-sees oil and gas activities offshoreUnited States has approved what likelywill be the first-ever floating, produc-

tion, storage and offloading or FPSO systemto operate in U.S. territorial waters.

The honor goes to three companies head-ed by Brazil’s Petrobras, an experiencedFPSO manager and operator of the yet unde-veloped Cascade and Chinook fields inultra-deepwater Gulf of Mexico.Oklahoma’s Devon Energy and France’sTotal also hold shares in the Walker Ridgeproject. The partners anticipate field startupin 2009.

Cascade and Chinook evidently are toodistant from the Gulf’s massive sub-sea pipeline system towarrant the expense of a separate oil line that would tie intothe existing system. However, Petrobras did not discloseplan specifics for the two fields. Under a typical operation,the oil would be produced and stored in an FPSO vesseland later offloaded to a shuttle tanker and transported toshore.

FPSOs are widely used around the globe as an alterna-tive to expensive pipelines. Petrobras alone has an exten-sive track record in FPSO use in Brazilian waters since1979, where 15 units are currently in operation and anoth-er nine in construction.

MMS approved Gulf use four years agoAfter addressing the potential for oil spills and other

environmental concerns associated with FPSOs and shuttletankers, the Minerals Management Service approved theiruse in the U.S. Gulf more than four years ago. Earlier thisyear MMS predicted it would have its first FPSO applica-tion in hand by the end of 2006.

MMS recently approved the Petrobras’ “conceptual

plan” to develop Cascade and Chinook, Petrobras saidDec. 11.

“This is the first time the use of an … FPSO-type plat-form gets this level of approval to operate in the Gulf ofMexico,” Petrobras said in a prepared statement. “UsingFPSOs has proven to be efficient to improve oil and gasreserve development capacity in deep and ultra-deepwaters.”

Petrobras said it would use six new technologies thathave never been applied in the U.S. Gulf, including FPSOswith disconnectable turrets, which allow them to beremoved in the event of hurricanes or other storms, oiltransportation by relief vessels, submerged pumps, self-sustainable risers, torpedo piles and polyester anchoringlines.

The plan calls for the installation and operation of anFPSO at water depths of about 8,202 feet. In the first phase,two subsea wells in Cascade and one in Chinook, each at adepth of nearly 26,900 feet, would be interconnected.

The oil would then be offloaded by relief vessels andthe associated gas via a pipeline. “Depending on reservoir

behavior, new wells may be interconnectedin the future,” Petrobras said.

Petrobras said detailed engineering stud-ies would shed more light on projectspecifics, including elaboration of its DeepWater Operational Plan, “which will includethe entire technical detailing, demonstratingthese new technologies will attend to or sur-pass current requirements for operations inthe Gulf of Mexico.”

Petrobras is the designated project opera-tor with a 50 percent interest in Cascade anda 66.7 percent interest in Chinook. Devonholds a 50 percent stake in Cascade, whileTotal E&P USA holds a 33.33 interest inChinook.

Fields could be first to produce zoneCascade and Chinook, in addition to

being the first U.S. project to use an FPSO, could be thefirst offshore fields to produce from the Gulf’s emergingbut highly acclaimed Lower Tertiary zone.

The Lower Tertiary play stretches several hundred milesfrom Walker Ridge westward through Keathley andAlaminos canyons, and is now believed to hold potentiallybillions of barrels of recoverable oil in dozens of individ-ual prospects primed for exploration drilling based on thepositive outcome of a recent production test conducted onthe Chevron-operated Jack No. 2 well in Walker Ridge.

Also in the Lower Tertiary race are three AlaminosCanyon oil discoveries — Great White, Tobago andSilvertip — that would produce about 130,000 barrels ofoil equivalent per day into a “hub” or centrally locatedfacility.

Project operator Shell is expecting first production fromthe so-called Perdido Regional Host Project around 2010.The offshore production facility is being designed togather production within a 30-mile radius of the hub.Other Perdido participants are Chevron, BP andCanada’s Nexen.●

T

Bluewater’s Munin FPSO at work for Statoil in the South China Sea.

By ALAN BAILEYPetroleum News

ost of the current debate about anAlaska North Slope gas linerevolves around the economics ofthe line, what route it will

take and who will build it. But amassive construction projectof this type will require anarmy of workers. And that’sin addition to the workforcethat might be required forother major projects such asa Southcentral gas spur line,new oil and gas field develop-ments, a coal gasification plant atNikiski and various mining developments.

Where are the skilled workers requiredfor these huge projects going to comefrom?

Representatives of various Alaska enti-ties involved in workforce development

met at an Anchorage EconomicDevelopment Corp. conference in Octoberto establish a common understanding of alooming Alaska workforce crisis. A primepurpose of the conference was to developrecommendations for the next Alaska gov-

ernor and Legislature on how toaddress the future needs for

skilled Alaska personnel. “It doesn’t matter how

many employers or projectswe have, if we don’t havethe prepared, available and

vibrant workforce, Alaska’sgoing to be in trouble,” said

Vince Beltrami of the AFL-CIO,one of the speakers at the conference.

Construction industry growthThe fact that all of the major projects on

the horizon involve the construction ofindustrial facilities and infrastructureplaces the construction industry and itsskilled trades at the center of the workforceproblem. Dick Cattanach, executive direc-tor of the Associated General Contractorsof Alaska, explained that an injection ofpetrodollars from the burgeoning oil indus-try fueled an initial construction growth inthe late 1970s. And, after a dip in activityduring the oil price slump of the mid-1980s, the industry has grown steadily.

“Since that time construction has beenin a steady upward growth,” Cattanachsaid. “… It’s also one of the highest payingindustries, paying just under $60,000 peryear for construction workers, second onlyto the oil and gas industry.”

The growth rate has been significantlyexceeding U.S. Department of Labor pro-jections of growth of 1.5 percent per year,Cattanach said.

But many of the current constructionworkers are starting to approach retirementage. For example, 30 percent of carpentersare now over 45 — construction workerstend to retire early.

“Usually by 55 most workers are leav-ing the industry,” Cattanach said.

The combination of continuing growthin the industry and the high rate of retire-ment will drive a need for large numbers ofnew craftspeople. Without even taking intoaccount the needs of new mega-projects,1,200 new carpenters will be needed overthe next decade, Cattanach said.

And that doesn’t take into account adesire to increase the number of workerswho are resident in Alaska — 18 percent ofAlaska workers are currently non-resident,Cattanach said. Increasing the proportionof carpenters who are resident to 90 percentwould raise the quantity of new carpentersrequired to 2,100 over the decade.

Unfortunately, Alaska is unlikely to beable to import enough new craftspeoplebecause unemployment rates in U.S. urbancenters are already quite low and only aportion of unemployed people are interest-ed in entering a craft trade.

“We’re going to have to grow our own,”Cattanach said.

Not enough graduatesBut the statistics on the numbers of

Alaska school graduates don’t look toopromising.

There has been an annual average ofabout 7,000 high school graduates inAlaska since 1999, Cattanach said. Onaverage 30 percent of these graduates go tocollege, leaving 4,900 to enter the work-

12 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

Nabors Alaska Drilling recognizes that our employees are an important reason for our success.

Thanks to their commitment to safety,operational excellence and the environment, we continue to be the premier drilling contractor in Alaska today.

nabors.com

The Reason for Our Success

Marvin Rogers, Toolpusher

● W O R K F O R C E D E V E L O P M E N T

Tackling the Alaska workforce deficitAnchorage conference looks at how Alaska’s education, training systems might gear up to address looming shortage of skilled workers

M

The projected need for labor from growth in the construction industry, the retirement ofexisting construction workers and an increase in the proportion of Alaska-resident workers.These data do not take into account the needs of new mega-projects.

see WORKFORCE page 15

By GARY PARKFor Petroleum News

benchmark drilling year contributedto some healthy gains in Canada’s oiland gas reserves in 2005, but the juryis out on what to expect this year and

next.In its latest annual update of the num-

bers, the Canadian Association ofPetroleum Producers reports that newestablished crude oil and natural gasreserves stayed ahead of production.

Conventional crude oil (including minedand in-situ bitumen) surpassed output by327 percent, ending the year at 14.25 billionbarrels, while natural gas replaced 123 per-cent of production, contributing 7.63 trillioncubic feet in gross additions, after produc-tion of 6.23 tcf, pushing the total to 57.95tcf.

Capital spending for 2005 totaled C$45billion, a figure CAPP estimates will easeoff to C$44 billion this year and C$42 bil-lion in 2007.

Natural gas drilling drops from ’05 record

Natural gas drilling set a new record of15,931 wells in 2005, but the slump in com-modity prices this year is forecast to lowerthe count to 15,400 and produce an evensharper decline to 14,400 in 2007.

Conventional oil wells are projected toslip from 4,210 in 2005 (a 10 percent gainfrom 2004) to 4,000 this year and 3,900 in2007.

Total wells are expected to slide from25,150 to 23,400 in 2006 and 22,000 next

year.That is already reflected in separate

industry statistics covering the first 11months of 2006.

The utilization rate for the average 800rigs dropped to 63 percent in the January-November period compared with last year’srecord 70 percent. The number of inactiverigs averaged 292 to the end of November,up 30 percent from the same period lastyear and the highest level since 2002.

However, the active rig count of 508 forthe 11 months was only eight rigs below the2005 count, making it the second highest onrecord.

Capital spending expected to shrinkCAPP estimates conventional capital

spending will shrink from C$35 billion in2005 to C$33 billion this year and C$29 bil-lion next.

Only the oil sands will cushion theimpact, edging from C$10 billion last yearto C$11 billion in 2006 and C$12 billion in2007.

CAPP chair Kathy Sendall noted thatrecord spending — three times the outlay of10 years ago — was needed to achieve thelevel of reserves growth seen in 2005.

But she said that investment is “onlysustainable in a strong price and responsiveregulatory environment.”

The association’s outlook for 2007points to a moderation of conventionalupstream activity and conventional capitalinvestment “due to a number of factors, par-ticularly softening gas prices and escalatingcosts.”

CAPP has calculated that Canada ended

2005 with remaining conventional crudereserves of 5.2 billion barrels, up 20 percentfrom the 4.4 billion barrels in 2004.

Those additions covered revisions due todrilling, pool reassessment, enhancedrecovery schemes and new discoveries,replacing 271 percent of production.

In Western Canada, Alberta dropped by2.7 percent to 1.7 billion barrels and BritishColumbia was off 2.9 percent to 100 mil-lion barrels, but Saskatchewan posted a 5.2percent gain to 1.24 billion barrels andManitoba was up 4.2 percent to 25 millionbarrels.

The Northwest Territories and Yukonsaw reserves drop by 7 million barrels to 36million barrels, although the MackenzieDelta/Beaufort Sea, where no commercialdevelopment has occurred, is unchanged at340 million barrels.

The major contributor was offshoreNewfoundland, where reserves at the threeproducing fields — Hibernia, terra Novaand White Rose — surged to 1.72 billionbarrels from 873 million barrels in 2004,due largely to revisions.

Combined mining and in-situ oil sandsreserves grew by 16.6 percent to 8.6 billionbarrels — a 440 percent replacement ratereflected in the C$10 billion of capitalspending.

Developed oil sands mining projectssaw reserves grow by 813 million barrels to6.13 billion barrels, while in-situ reservesgained 18.8 percent to 2.47 billion barrels.

CAPP numbers short of Alberta energy board

CAPP confines its oil sands numbers toprojects that are either developed or wheresubstantial investment has either beenmade or is under way.

As a result its numbers fall well short ofthe Alberta Energy and Utilities Board’sestimates of 174 billion barrels of estab-lished reserves out of 315 billion barrelsdeemed to be ultimately recoverable.

On the gas side, the Western CanadaSedimentary basin reserves gained 1.5 tcf,with British Columbia logging year-endreserves of 12.35 tcf after replacing 309percent of production, a gain of 20.2 per-cent reflecting an unprecedented year ofactivity.

A significant portion of B.C.’s gainscame from recognition of the Deep basinby the British Oil and Gas Commission.

CAPP said the application of new wellcompletion techniques and three-dimen-sional seismic took a major role in thedevelopment of the Deep basin play.

Alberta replaced 83 percent of produc-tion, exiting 2005 with reserves of 40.94tcf — a loss of 12.9 percent.

Saskatchewan gained 7.8 percent at3.25 tcf; the Northwest Territories andYukon were off 5 percent at 400 billioncubic feet and the East Coast offshore tum-bled 20.9 percent to 541 bcf because of thecontinued slide in Nova Scotia’s Sablefield. ●

PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 13

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

Canada: 2005 a very good yearBut Canada’s conventional spending, drilling in trouble in 2006 and 2007; industry says return to 2005 levels needs strongcommodity prices, responsive regulatory environment; CAPP’s oil sands numbers to projects in development or developed

A

ALTERNATIVE ENERGYComments invited on wind energy test

Alaska Wind Power LLC has applied to Alaska’s Division of Mining, Land andWater for a land use permit for a proposed wind energy test site east of theRichardson Highway, in the vicinity of the Jarvis Creek coal mine area approxi-mately 20 miles south of Delta Junction. Members of the public should submitcomments, objections or expressions of interest to the DMLW Fairbanks office by5:00 p.m. on Jan. 8.

The project would involve erecting 10 wind energy towers on a total of fiveacres of state land, to assess the wind energy resources available for a possiblefuture wind energy development. Stu Pechek at (907) 451-2733 can answer ques-tions about the permit application.

—ALAN BAILEY

14 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

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

No boom from GOMThunder Ridge fieldMurphy: Deepwater exploration well in Gulf of Mexicoencounters wet sands and ‘small oil accumulation’

By RAY TYSONFor Petroleum News

ield operator Murphy Oil, followingdeepwater exploration successes atThunder Hawk and Thunder Bird,appears to have come up short at

Thunder Ridge. All three of Murphy’s“Thunder” prospects are within spittingdistance of the BP-operated ThunderHorse field, the largest ever oil discoveryin the Gulf of Mexico.

The Thunder Ridge exploratory welland sidetrack, drilled on MississippiCanyon Block 737 in over 6,100 feet ofwater, encountered wet sands in the pri-mary objective and “a small oil accumu-lation” in a shallower secondary objec-tive, Murphy said Nov. 30.

“Post-drilling analysis will continueto determine if the resource found can becommercially viable as a tie-back toanother facility,” Murphy said ofThunder Ridge drilling results, addingthat the Thunder Ridge exploration wellwas “temporarily” plugged and aban-doned.

However, with predrill reserve esti-mates of 100- to 200-million barrels ofoil equivalent, Thunder Ridge’s small oilaccumulation would have to be consid-ered a disappointment. Weeks earlierThunder Hawk was sanctioned as astandalone development with just 50-to80 million barrels of estimated reserves.

Murphy holds a 37.5 percent workinginterest in Thunder Ridge. PartnersDominion Exploration & Production,Inc., a subsidiary of U.S.-basedDominion Resources, and Norway’sHydro Gulf of Mexico each holds a 25percent share of Thunder Ridge.Marubeni Offshore Production (USA)Inc., a subsidiary of Japan’s MarubeniCorp., holds a 12.5 percent interest in thefield.

Semisubmersible production unit for Thunder Hawk

Murphy’s Thunder Hawk discovery,on Mississippi Canyon Block 736 in5,700 feet of water, is to be developedusing a semisubmersible production unitcapable of handling 45,000 barrels of oilequivalent per day and expandable to60,000 barrels per day with slight mod-

ifications. First oil is scheduled for2009.

Murphy said the Thunder Hawkfacility could be further expanded toreceive production from future satellitediscoveries or third-party tie-backs.Thunder Ridge is located just six mileseast of Thunder Hawk, suggesting thatThunder Ridge production, if develop-ment is approved, could be a candidatefor tie back to the standalone ThunderHawk production facility.

Murphy has said its Thunder Birddiscovery likely would be developed,with production tied back via a sub-seapipeline to the Dominion-operatedDevil’s Tower platform on MississippiCanyon Block 773.

Predrill reserve estimates forThunder Bird range from 50- to 75 mil-lion barrels of oil equivalent. The dis-covery is located about 15 miles west ofThunder Hawk.

Murphy says sidetrack required at Thunder Bird

However, Murphy has said thatanother exploratory well — a sidetrackoff the discovery well — would berequired before the owners decidewhether to pursue development atThunder Bird.

Thunder Hawk, Thunder Bird andThunder Ridge are on the edge of theBoarshead Basin, a highly fertile regionof the Central Gulf of Mexico that hadindustry analysts speculating overresource potential before the colossalThunder Horse discovery wasannounced in 1999.

Thunder Horse, scheduled to come onstream in mid-2008 after several delays,contains an estimated 1 billion barrels ofoil equivalent reserves. The ThunderHorse North satellite contains an addi-tional 400 million barrels of estimatedreserves. Owned by BP (75 percent) andExxonMobil (25 percent), ThunderHorse is expected to produce 250,000barrels of oil and 200 million cubic feetof gas per day.

Murphy and its partners, beforedeciding on a standalone facility forThunder Hawk, considered tying backThunder Hawk production to theThunder Horse facility. ●

F

NATURAL GASNexen ready to take control of CBM play

Nexen will not let any financial stumbles by its joint-venture partner get in theway of developing what is potentially Alberta’s largest coalbed methane resource.

The Canadian independent will exercise its right to serve notice on any wellsthat privately held Trident Exploration is unable to support financially, ChiefExecutive Officer Charlie Fischer told analysts Dec. 6.

But, despite some financial uncertainty and a recent staff layoff, Trident hasrestored some confidence by arranging a US$270 million loan that enabled it topay off debts of US$125 million and finance continued development of the UpperMannville coalbed methane formation.

Recoverable gas estimated at 260 tcfThe two companies are partners in a C$400 million project to achieve the first

commercial production from the Mannville, where recoverable gas has been esti-mated at 260 trillion cubic feet.

While leaving no doubt that Nexen is prepared to act on its rights, Fischer saidTrident’s financing deal has eased some concerns about the company’s ability tocover its share of Mannville costs.

He said that conversations with Trident indicate Mannville is “their area of pri-ority and they’re going to do everything they can to stay on track. That’s some-thing we just have to monitor.”

Nexen has budgeted C$200 million for 2007 to continue development of63,000 acres of the Mannville play.

Fischer said production from the area is expected to grow to 75 million cubicfeet per day by the end of 2007 and double that volume by 2011.

The focus is on developing the Upper Mannville assets in the Corbett, Thunderand Doris fields, using multiple-leg horizontal wells.

—GARY PARK

PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 15

force. The construction industry would need 23 percent ofthose available high school graduates to meet its annualneeds, despite the fact that construction only employsabout 6 percent of the total Alaska workforce.

Cattanach also said that the current rate of completionof apprenticeships in Alaska only meets about 15 percentof the construction industry’s needs. Most constructionjobs require on-the-job training, he said.

And Beltrami described the trade union apprenticeshipprograms, funded by labor and management under jointapprenticeship and training committees.

“Our skill training, on-the-job training and in the class-room, is absolutely unparalleled in my opinion,” Beltramisaid, adding that these courses provide a viable alternativeto college. “… We have the infrastructure that we’ve builtby committing money out of our own pockets, manage-ment and labor, to build facilities, curriculum, keepingclassroom structures on the cutting edge of our respectivetrades.”

However, Beltrami said that there is in general a short-age of educated applicants for the programs and that manypeople struggle with essential math and science skills.

“There’s an inability of many of the applicants that wesee to transpose simple fractions on a tape measure intoreal-world applications needed to turn a blueprint into abuilding, and that is a travesty,” Beltrami said.

And Jeff Staser, principal of the Staser Group, alsoemphasized the necessity for entrants to the job market tobe work ready. People need verbal and written communi-cations skills; problem solving ability; math and scienceability; management skills; and an ability to work withthings, Staser said.

So, how well does the Alaska education system preparepeople for work?

Career and technical trainingSeveral speakers talked about the issue of integrating

career and technical training (otherwise known as voca-tional training) into school and post-secondary educationprograms.

Mary Lou Madden, president of Madden Associates,reviewed the results of two past analyses of vocationaltraining in Alaska. The Alaska Department of Educationdid one of these studies in 1996-97, while the AlaskaDepartment of Labor carried out the other study in 2003.Considerable changes in Alaska vocational trainingoccurred in the time between the two studies, Madden said.

In the 1990s the state funded approved vocationalcourses for high school students and three out of five stu-dents underwent some form of vocational training,Madden said. But at that time the University of Alaskaoffered little vocational training. The university did nothave categorical funding for career and technical trainingand did not account for the number of students enrolled intechnical courses.

The state provided some funding for technical trainingoutside of the university and there was private-sector tech-nical training, fueled by the Alaska student loan program.

By 2003 the emphasis on career and technical trainingmoved from secondary schools to post-secondary educa-tion, with categorical funding for vocational training dis-appearing from the secondary level and fewer career-relat-ed electives available in the secondary system, Madden

said. On the other hand “there has been a lot more activityhappening at the university level,” Madden said.

Madden urged the need to do something about second-ary vocational education and even to introduce career ori-ented education in elementary schools.

“We need to have industry involvement at the locallevel,” Madden said. “… We need to get back to careereducation.”

Beltrami urged the need for adequate school funding tominimize class sizes, attract qualified teachers and attackthe problem of “spiraling (student) dropout rates.” He par-ticularly praised the King Career Center for its vocationalclasses but said that only a few Anchorage School Districtstudents are able to attend those classes.

“Otherwise, shop classes or other forms of vocationaleducation are virtually non-existent in the individualschools and districts around the state,” Beltrami said. “It isthese … hands-on programs that help reinforce the con-cepts of math, English, science.”

Cattanach also sees a need to emphasize more voca-tional training.

“We need to change Alaska’s approach to secondaryeducation,” Cattanach said. “We need more vocationaltraining. … What other work opportunities do (students)have? Flipping hamburgers is not a career path.”

Staser said that a survey done by the Dittman groupindicated a problem with the availability of informationabout training and jobs.

“About 80 percent of people find jobs through word ofmouth and around 6 percent … find their jobs through thejob centers,” Staser said.

Beltrami said that the unions are forming agreementswith the King Career Center and with school districts toprovide pathways into the unions’ training programs. Thereare other initiatives, such as a planned expansion to theKing Career Center, and “we have a $3 million pipelinetraining facility in Fairbanks,” Beltrami said.

Cattanach said that the University of Alaska Anchorageis developing a construction management program and thatwork has started on building an Anchorage constructionacademy. The academy will provide after-hours programs,as well as serving unemployed people, he said.

Growing Native workforceM.J. Longley, chief of operations for the Cook Inlet

Tribal Counsel, talked about the growing size of the AlaskaNative workforce. The Native population in Alaska is pro-jected to grow from 120,000 to 165,000 by 2020, with 50percent of Native Alaskans living in an urban environmentby that time, Longley said.

But although Native corporations and non-profit organ-izations constitute major employment drivers in Alaska,unemployment levels in the Native population remain rel-atively high.

“The statistics … indicate that close to half of AlaskaNative women and men are working in the cash economy,”Longley said. The unemployment rate in Anchorage forAlaska Natives is 18.37 percent, compared with an overallaverage unemployment rate of 6.9 percent, she said.Transportation, training and work experience can all pres-ent problems for Native people looking for work, she said.

“A huge percentage of our people are not work ready,particularly those who are new to the urban environment,”Longley said, adding that people are moving from ruralcommunities into the urban areas because of economicissues in rural Alaska. She said that more vocational train-ing centers are needed to provide intensive training for a

Native population that is in transition.Longley said that training programs for Alaska Natives

are available with funding through section 166 of the U.S.Workforce Investment Act. And the Cook Inlet TribalCounsel has made workforce development a top priority— the counsel has opened a large new Anchorage trainingoffice that provides a wealth of services, she said.

PARWPutting Alaska Resources to Work, or PARW, an

alliance of the oil, gas and mining industries and of work-force development organizations, is moving ahead with aninitiative to tackle the shortage of skilled labor in the indus-tries represented by the alliance members. Although theseindustries are not in themselves especially labor intensive,major capital projects will require huge numbers of work-ers, particularly for construction, Dave Rees, senior techni-cal resourcing specialist for BP, explained.

“We’ve got consistent growth in a lot of construction,consistent growth in retirement in the state,” Rees said.

PARW’s planning committee has reviewed studies ofworkforce development done by other organizations. Fromthese studies the committee identified four main strategiesthat PARW is now pursuing.

1. Engage the stakeholders in workforce development“to move Alaskans from a vague awareness of the issues toactive participation in solving the challenges.”

2. Train the workforce, with a focus on lifelong learningand providing career pathways.

3. Employ skilled Alaskans by communicating specifictraining needs to training providers and using web-basedcommunications for job placement.

4. Adaptively sustain the training system by adequatelyfunding vocational training.

RecommendationsAt the end of the workforce development conference,

the conference participants made four main recommenda-tions for the governor and state Legislature.

1. Establish, in collaboration with private sectoremployers, a clearly articulated career and technical edu-cation program in Alaska that has long-term funding. Theprogram should encompass a wide range of different edu-cation institutions and should include options such asapprenticeships, internships and private education pro-grams.

2. Establish a career and technical education outreachprogram where employers can partner with the State ofAlaska, the University of Alaska, local schools and tribalpartners to help people learn about training, internships,apprenticeships and employment opportunities.

3. Build on an existing Internet-based system thatenables prospective employees to find training and jobopportunities, and that helps employers find employees.

4. Restructure the Alaska Workforce Investment Boardby establishing a direct reporting relationship with the gov-ernor, making the board industry pertinent and establishingfull-time professional staff. The board provides policyoversight of state and federally funded job training andvocational education programs.

The conference participants elected not to recommendre-instatement of a state student loan program, nor a sug-gestion that the state should be required to use apprenticesfrom accredited apprenticeship programs in state capitalprojects. ●

continued from page 12

WORKFORCE

16 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

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

Verna Fonoti, Administrative Assistant

FOR

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Hawk Consultants LLC

Hawk Consultants LLC is ownedand managed by three professionals— Maynard Tapp, Mike Jens andDave Norton — who have more than100 years of combined experienceserving Alaska’s energy, public works,telecommunications, and privatedevelopment industries. Hawk profes-sionals provide dependable staff aug-mentation and management supportservices to advance client projectsfrom concept to completion, short orlong-term.

Verna Fonoti joined HawkConsultants this year as an adminis-trative assistant and is enjoyinglearning the ropes of this multifac-eted business. Off duty, she playsclarinet and tenor sax in concerts andfor fun. She’s single, adventurous andbelieves Nike has the right philoso-phy: “Just do it.” For Verna, this canapply to anything in life.

PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 17

of conventional fields in Alberta, the domi-nant producing region, along with risingdomestic demand in Canada and a reevalu-ation of the potential for unconventionalproduction from coal seams and tight gasformations.

It said LNG will be essential to deal withthe shortfall, although delays in buildingliquefaction plants, supply constraints at anumber of liquefaction facilities and fast-rising global demand for LNG will combineto keep the U.S. LNG market tight until2012.

However, total net imports of LNG tothe Lower 48 are expected to climb from600 bcf in 2005 to 4.5 tcf in 2030.

Unconventional plays threatened by LNG

As those imports start to increase, ana-lysts such as U.S. consultant BenSchlesinger are waving a cautionary flagover the future of expensive unconvention-al plays.

Speaking to an oil and gas market out-look conference sponsored by CanadianEnerdata, he offered a much bolder view ofLNG’s role in meeting U.S. demand, sug-gesting that the U.S. is already launching aspate of LNG terminal construction.

He said that “without question” NorthAmerica will have LNG receiving capacityof about 7.3 tcf over the next five years andthat doesn’t include the stalled developmentby Anadarko of its planned Bear Head ter-

minal in Nova Scotia. Schlesinger said LNG arriving at the

U.S. Gulf Coast will force the deferral ofnatural gas projects because LNG, regard-less of where it lands, will lower prices.

Four Canadian projects plannedCanada still has four LNG projects that

are planned or under construction — one inNew Brunswick (the Canaport project byIrving Oil and Spain’s Repsol), one inQuebec (the Rabaska project by Enbridge,Gaz Metro and Gaz de France) and two inBritish Columbia (the Kitimat and Westpacprojects).

Schlesinger expects gas-fired powergeneration will continue on a growth curve,adding to Lower 48 demand, with the gen-eration sector likely to pass the industrialsector as the largest customer for gas.

He predicted gas prices will remain on avolatile path, with Henry Hub prices fluctu-ating between US$4-$9 per million Britishthermal units over the next 12 to 18 months.

On the oil front, the EIA expectsCanada’s conventional output to taper off to1.93 million barrels per day in 2010 from2.12 million bpd in 2005 and then reboundto 2.01 million bpd in 2015 before droppingby 1.1 percent annually over the next 15years.

But it said Canada will play a leadingrole in elevating North America’s uncon-ventional production from 1.09 millionbpd in 2005 to 1.91 million bpd in 2010and 2.32 million bpd in 2015, with oilsands leading the way, followed by liquidsfrom energy crops, natural gas, coal andshale.●

“I hesitate when I say (WesternCanada) is the most expensive marketin the world, but I think it really is.

“So we are going to constrain ourspending there.”

He said competition for equipment,services and supplies has created a“highly inflationary cost environment”in Canada, while a stronger Canadiandollar has cut into Devon’s profits.

For now Devon has not releaseddetails of its expected production cutsin Canada (it has lowered its world-wide production guidance for 2006 by1 percent).

But it plans to operate only four rigsnorthwest of Fort St. John, B.C., thiswinter, down from seven in 2005-2006and 12 in 2004-2005.

The company also plans to focus onshallower wells of 4,000 feet or less,rather than those in the 8,200 footrange to achieve faster completion.

Devon has been joined by CanadianNatural Resources in scaling back B.C.drilling and EnCana could be next inline when its 2007 budget is releasedabout mid-December.

The Petroleum Services Associationof Canada, assuming an average gasprice of C$6.25 per thousand cubic feetin 2007, is predicting a 28 percentdecline in B.C. drilling next year to1,050 wells from the 1,450 expected

this year — the first reversal in theprovince since 2002.

Association President Roger Soucysaid costs, while varying from serviceto service, have risen about 30-40 per-cent in B.C. over the past three years,driven mostly by the costs of labor andsteel.

Canadian Natural is moving capitalfrom gas to oil projects, reducing con-ventional drilling near Fort St. John to71 wells from 132, suggesting theemphasis in future years will shift tomore expensive, lower-yield uncon-ventional plays.

To mirror that view, it is currentlybudgeting for 47 conventional wells in2007, down 71 percent from the 164planned for 2008 and off 75 percentfrom the 186 planned for 2011.

EnCana is likely to shrink itsdrilling programs in the prized GreaterSierra and Cutbank Ridge plays as partof an overall US$1 billion budgetreduction. The company’s well countdropped by 33 percent at Greater Sierrain the first nine months of 2006 and by28 percent at Cutbank Ridge.

—GARY PARK

continued from page 1

LNG continued from page 1

CUTBACKS

alty revenues from production on outer con-tinental shelf leases. According to congres-sional estimates, that provision could redis-tribute about $60 billion in federal leasingfees to the four coastal states over the next25 years.

On a related issue, Louisiana convinceda federal judge in October to halt futureGulf of Mexico lease sales until environ-mental damage caused by hurricanesKatrina and Rita could be thoroughlyassessed. A portion of royalty revenues thatwill go to the four states under the new leg-islation will be used to help clean up thewidespread mess.

“I appreciate the commitment by theState of Louisiana to use revenues fromthese leases to restore coastal wetlands,”President George W. Bush said in a pre-pared statement following passage of theGulf security act.

The offshore legislation, which isexpected to be approved by President Bush,

ends a 25-year drilling ban in deep waters ofthe U.S. Gulf about 125 miles south ofFlorida’s Panhandle, but extends a morato-rium on drilling in other Florida waters until2022.

Area believed to hold substantial resources

Geologists believe the new area openedto drilling could hold 1.26 billion barrels ofoil and 5.8 trillion cubic feet of natural gas.

“Developing these reliable domesticresources in an environmentally soundmanner will help address high energyprices, strengthen our energy security andprotect manufacturing jobs,” PresidentBush said. The new offshore legislationbrought an immediate and mixed reactionfrom various industry trade groups, includ-ing the 450-member National Petroleumand Refiners Association.

“While the bill doesn’t open as muchacreage to exploration as NPRA and otherswould have liked, we hope that additionalaction affecting other OCS areas will even-tually take place,” NPRA President Bob

Slaughter said, adding that allowing fullaccess to the OCS could bring as much as633 trillion cubic feet of natural gas to theU.S. domestic market.

Tom Fry, president of the 300-memberNational Ocean Industries Association, saidthat while the bill would not solve all of thenation’s energy challenges, “we have atleast begun to take a step in the right direc-tion.”

He added: “Congress recognized that theUnited States has been operating under aflawed public policy for decades that refus-es to allow energy supply to keep pace withincreasing demand. As a result, we haveexperienced increasing prices for oil andnatural gas as well as an increasing relianceon imported energy.”

Fry noted that with 80 percent of theOCS off limits to drilling, the offshore stillaccounts for roughly 30 percent of the U.S.oil and natural gas produced each year. “Weare the only nation in the world to consis-tently limit access to our own domesticresources,” he said.

AGL Resources, an Atlanta-based ener-gy services holding company with utility

subsidiaries in six states, echoed the con-cerns of other energy companies respondingto passage of the new offshore legislation.

“While we are disappointed that morecomprehensive legislation — which wouldhave given states more discretion overresources off their respective coasts — didnot pass this term, we are pleased with theresults of this measure,” said JohnSomerhalder, AGL’s president and chiefexecutive officer.

The energy portion of the bill alsoincludes a dozen energy tax incentives,including inducements for renewable ener-gy, marginal oil and gas wells, energy effi-ciency investments and an extension on the54 cents a gallon tariff on ethanol imports.

Other provisions of the bill would allowindependent oil and gas producers to writeoff depletion costs at a higher level for the2006 and 2007 tax years, extend the exist-ing research and development tax credit forqualified energy projects through 2007,increase credit rates and simplify theresearch and development credit for 2007,and modify the coke and coke gas produc-tion tax credit.●

Devon has been joined byCanadian Natural Resources inscaling back B.C. drilling andEnCana could be next in line

when its 2007 budget isreleased about mid-December.

continued from page 1

ENERGY ACT

long. And it could come soon. In response to

a question from Commissioner DaveHarbour, Heinze said an open seasoncould come as soon as six months aftersomebody decides to move a gas projectforward, “because the first thing that willhappen, logically, is some sort of openseason.”

Heinze said he thinks “it’s realistic tosay you absolutely have to be preparedfor say, a year from today,” for the open-ing of that open season. “It might occurunder certain circumstances quicker thanthat, but I wouldn’t count on it being a lotfurther out in the future than that.”

It’s the six-month windowCommission Chair Kate Giard said six

months seemed like an awfully short timeand asked if the FERC regulations don’tallow for an extension.

Heinze said the initial draft of theFERC open season rules for the Alaskagas pipeline project had a 60-day openseason. He said he and Tony Izzo, then

president of Enstar Natural Gas Co., theSouthcentral local gas distribution com-pany, both pleaded for more time.

The regulations FERC adopted call forsix months, and Heinze said he reads thatas “a balance of their giving us moretime.”

He said it is ANGDA’s intention “totry to open some sort of dialogue withFERC on this issue from the point of viewof the enormity of the decision faced byour utilities,” but said he had a chance toplead for a longer open season beforeFERC before they adopted rules and “Ithink they’ve given us all we’re going toget.”

Heinze said Alaska could always askfor more time, “but I think that would bea real risk you don’t want to take.”

It’s the bet your utility decisionHeinze has talked about the decision

facing utilities before, and he reviewedthis for the commission.

The value of the commitment utilitieswould have to make for natural gas in anopen season is in the range of $6.5 billionfor 75 percent of the gas needs of Alaskautilities for heating and power over a 15-

year period. “It’s a bet your company two or three

times over type decision,” Heinze said. And what if not all the utilities are

willing to commit?First, as noted above, in-state users are

not in a good position to come back afterthe open season and ask to have gas takenoff in the state.

And it impacts the economics of a spurline to Southcentral Alaska.

At 100 million cubic feet a day —about the volume Enstar uses — a spurline into Southcentral Alaska is not eco-nomic, Heinze said. If one of our majorutilities, or the gas company, says it’s notwilling to make a billion-dollar decision,and there are no industrial partners, “thenwe don’t get a spur line.”

ANGDA is working with utilities nowto help them understand what is comingand wants to do a practice open season,Heinze said.

As for the RCA, “you could be facedwithin a six-month period with a dozen ortwo dozen applications” for the purchaseand transmission of gas, “and I can assureyou that if only half of those decisions getmade, we won’t have a (spur line) proj-ect.” ●

18 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006

PIPELINES & DOWNSTREAMEPA fines Flint Hills for clean air violations

The U.S. Environmental Protection Agency has fined Flint Hills ResourcesAlaska $15,867 for Clean Air Act emergency planning violations at the company’sNorth Pole refinery The company has also agreed to buy three hazardous substancespill response vehicles and an incident command post trailer for Fairbanks North StarBorough.

According to an EPA press release the agency alleged 10 separate violations of theClean Air Act, including “failure to establish procedures for reviewing and updatingthe company’s emergency response plan, and failure to establish procedures forinforming the public and local emergency response agencies about accidental releas-es of flammable substances.”

The Clean Air Act requires the development of a risk management program forany facility that manufactures, processes, uses, stores or handles more than a speci-fied amount of regulated substances, including flammable gases and toxic chemicals.

“Flint Hills needed a better management system to ensure that their emergencyprocedures were continually updated and also needed a way to inform the publicabout accidental releases,” said Kelly Huynh, EPA’s risk management plan coordi-nator. “The program is designed to protect public health and the environment in theevent there is an accidental release of hazardous or flammable substances.”

Occurred before purchaseBut Flint Hills has told Petroleum News that the Clean Air Act violations at North

Pole relate to issues that existed at the refinery before the company purchased therefinery from Williams on April 1, 2004. After the refinery purchase Flint Hills hireda third-party consultant to identify any environmental or process issues that existedprior to the purchase, Jeff Cook, director of external affairs for Flint Hills, said.

The consultant delivered a report in August 2004 and Flint Hills corrected theproblems that the consultant discovered, including the issues that have resulted in theEPA fine.

“All issues were reported and addressed, and we now meet or exceed all regula-tory standards,” Cook said. “…Safety and the environment are the top priority ofFlint Hills Resources.”

—ALAN BAILEY

The Alaska Department of NaturalResources said Dec. 14 that all areas ofstate North Slope and foothills landsremain closed to tundra travel.

“Soil temperatures are cold enough insome tundra opening areas, but othersare still too warm,” DNR said. “Snowdepths are below what is required fortundra opening at all stations.”

The foothills tundra opening requiresnine inches of snow and a 23 degreeFahrenheit soil temperature at a 30 cen-timeter depth. The coastal areas requiresix inches of snow and a 23 degree Fsoil temperature.

DNR said the east and west coastalareas are mainly cold enough for proj-

ects to begin, provided the work takesaccount of thin snow cover and DNRapproval is obtained.

“Lower and Upper Foothills areasneed more cold and much more snow,”DNR said. “Only off-road travel withsummer approved vehicles or other low-impact vehicles will be authorized.”

Apparently the snow cover is espe-cially low in the Franklin Bluffs areanear the Haul Road.

—ALAN BAILEY

Chena geothermal projectwins national awards

THE NEW GEOTHERMAL POWERPLANT at Chena Hot Springs Resort inAlaska’s interior has won two awards forthe innovative use of renewable energy.

On Dec. 1 the Alaska EnergyAuthority announced that PowerEngineering Magazine had named theChena development as “Project of theYear” in the renewables category of aninternational competition with hundredsof submissions. And hot on the heels ofthat announcement came the “2006 On-Site Generation Award” from the U.S.Department of Energy and the U.S.Environmental Protection Agency.

Funded in part by an Alaska EnergyAuthority power project fund loan, theChena power plant, known somewhatperversely as the “Chena Chiller,”pumps energy out of the ground using aprocess rather like a reversed refrigerator— hot water from underground vapor-izes a refrigerant that then powers a tur-bine electrical generator before beingcondensed and recycled through the sys-

tem. The refrigerant cools the geother-mal water, which is then recycled under-ground.

The truck-sized 400 kilowatt plant,the first of its kind in Alaska, was builtby United Technologies to replace a 200kilowatt diesel generator that consumedmore that 97,500 gallons of diesel fuelper year. Eventually geothermal energyfrom the new plant will meet all of theChena Hot Springs Resort’s electricityneeds.

The resort received the DOE/EPAaward at a ceremony in San Francisco onDec. 4, in conjunction with the 11thNational Renewable Energy MarketingConference.

“It is the outstanding leadership ofcompanies like Chena Hot Springs

continued from page 1

WINDOW

continued from page 1

INSIDER

see INSIDER page 19

PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006 19

Register today at www.alaskaalliance.com

field mapping in the highway corridor toverify features identified from the geo-physical survey and from air photo inter-pretations of the area — surface geologicmapping is essential for the refinementand verification of the geophysical analy-sis and interpretation. The ground map-ping will target features identified fromthe geophysics and then use the geophys-ical data to extrapolate surface featuresbelow the sedimentary cover.

The geologists will also use handheldmeters to measure the magnetic suscep-tibility of all rocks seen in surface out-crop.

An investigation of potentially activefaults will involve trenching across eachfault and assessing any evidence for thedirection and timing of fault movement.Where possible the geologists will veri-fy the actual existence of permafrost inpotential permafrost areas identifiedfrom the geophysics and air photo inter-pretations. The field program will alsoprovide a means of calibrating the use ofremote sensing data from satellites, forexample, to locate areas of permafrost.

Laboratory data, test hole data andrecords from the 2002 Denali faultearthquake will provide insights intoareas where there is potential for the liq-uefaction of the ground during an earth-quake. Air photo interpretations andfield observations will provide informa-tion about potential slope instability.And air photo interpretations, fieldobservations and historical records willprovide insights into areas of potentialflooding.

Geophysical data availableMeantime, the data from the geo-

physical survey are becoming availableto the public.

Maps containing the basic data canbe downloaded from the DGGS web siteor purchased as paper copies from thedivision. The original survey data andgridded data used to make the DGGSmaps are available from the division onCD or DVD. DGGS hopes to soon makeavailable electrical resistivity profilesand additional gridded data producedfrom some of the profiles, Burns said. ●

continued from page 8

ALASKA HIGHWAY

A map of aeromagnetic data for part of the Alaska Highway corridor, showing some of the major features that can be recognized.

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Resort that is significantly advancingthe development of renewable elec-tricity sources through green powermarkets,” said Susan Carollo, awardscoordinator for DOE and EPA.

—ALAN BAILEY

Pearce sworn in asfederal coordinator for Alaska gas line

VICE PRESIDENT DICK CHENEYswore in Drue Pearce Dec. 13 as the firstfederal coordinator for Alaska naturalgas transportation projects. Pearce wasconfirmed Aug. 4 by the U.S. Senate.

Pearce was accompanied at the cere-

mony by her husband, MichaelWilliams.

As federal coordinator, Pearce willintegrate activities by federal agenciesfor permitting and construction of apipeline to bring North Slope gas tomarkets in the Lower 48. She will reportdirectly to the president.

Pearce said she looks forward “toadvocating for the Alaska Gas Projectthroughout the nation and in Canada.”

In addition to close family andfriends, the ceremony was attended bySecretary of the Interior DirkKempthorne, Deputy Secretary ofEnergy Clay Sell, Deputy Secretary ofTransportation Maria Cino, FederalEnergy Regulatory CommissionChairman Joe Kelliher and Canada’sAmbassador to the United StatesMichael Wilson.

continued from page 18

INSIDER

Pearce with her husband Michael Williams and Vice President Dick Cheney

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20 PETROLEUM NEWS • WEEK OF DECEMBER 17, 2006