kulluk departs dutch …jim paulin shell’s floating drilling platform, the kulluk, departs...

Vol. 16, No. 28 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of July 10, 2011 • $2

� N A T U R A L G A S


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

page5

EPA releases draft air quality permitsfor Shell’s planned Arctic OCS drilling

Kulluk departs Dutch HarborJI

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AU

LIN

Shell’s floating drilling platform, the Kulluk, departs Alaska’sDutch Harbor on June 30, bound for a Seattle shipyard for exten-sive upgrades. The work includes new control systems to decreaseair pollution and modifications to eliminate discharges of drillingmud, cuttings and wastewater. The job will be done at the formerTodd shipyard, which Vigor Industrial LLC purchased in February.The Kulluk is expected to be away for seven to 10 months, withShell then aiming to restage it at Dutch Harbor in anticipation ofdrilling wells in the Beaufort Sea in 2012, company spokesmanCurtis Smith told Petroleum News on July 6. Shell decided to makethe Kulluk a zero-discharge platform in deference to Native whalehunters concerned about waste going into the Beaufort Sea. Shellintends to capture the waste and dispose of it onshore.

Central Mac sizzles: Play drawsC$534M in winning bids fromHusky, Conoco, Shell, Exxon

Husky Energy has dug deep into its pockets in committingC$376 million to explore 432,000 acres of the highly-ratedCentral Mackenzie Valley play in the Northwest Territories.

ConocoPhillips, Shell Canada, a partnership of Imperial Oiland ExxonMobil Canada and a partnership of MGM Energyand 6362 NWT Ltd. all joined the bidding, ensuring that 11contiguous parcels covering 3.1 million acres attracted success-ful offers.

Colleen McConnell, a Husky spokeswoman, said that untilseismic data has been gathered the company is not speculatingon whether oil or natural gas would be the primary target.

But she said it’s “obviously an area of interest for us … wethink it’s prospective,” while noting there is an existing petrole-um system at Norman Wells.

Imperial spokesman Pius Rolheiser said it was too early forhis company to disclose exploration plans or discuss its interestin the region.

The other successful bidders were ConocoPhillips, pledging

Marilyn Crockett to retire from AOGA after 41 years

On July 7, the 41st anniversary of her service with theAlaska Oil and Gas Association, Executive Director MarilynCrockett announced she will be retiringfrom AOGA, effective Dec. 31.

“It has truly been an honor and a priv-ilege to work for the state’s largest pri-vate industry for my entire career andwith the many professional Alaskanswho, too, have contributed to the oil andgas industry in Alaska,” Crockett said.“My personal objective has been to growAlaska’s economy by advocating for avibrant oil and gas sector in our state.”

In her career with AOGA, Crocketthas held several different positions, including administrator,exploration and production affairs representative, managerfor environmental affairs, deputy director and, since 2007,

Anadarko back for gas?Pending partner OK, company looking to revive Brooks Range Foothills program

By KAY CASHMANPetroleum News

A nadarko Petroleum Corp. “intends to contin-ue” its multiyear drilling program at the

Gubik and Chandler prospects in the BrooksRange Foothills, according to a recent letter theTexas independent sent to the Alaska Departmentof Natural Resources.

W.C. “Chuck” Rowe, Anadarko’s drilling oper-ations manager in Alaska, made the announcementin a letter to DNR’s Division of Land, Mining andWater, as part of an application to modify an exist-ing land use permit. The permit would allowAnadarko to do summer preparatory work forbuilding a temporary access road this coming win-

ter to its previously drilled Chandler gas well,located west of the Colville River near Umiat.

Known as the “Gubik Complex” by Anadarkoand its partners, the program on state, federal andNative leases in the foothills was the first and stillthe only exploration effort in northern Alaska toexplicitly target natural gas, but has been inactivesince early 2009.

‘Rig-less’ well testAnadarko hopes to test the well this winter,

according to Petroleum News sources, but the offi-cial filings made to date are more ambiguous aboutthe timing of the program — Rowe’s cover letter

see ANADARKO page 14see MAC BIDDING page 14

MARILYN CROCKETT

see CROCKETT page 13

Alberta crude in TAPS?B.C. firm wants rail link from oil sands to Alaska to access Asian markets

By GARY PARKFor Petroleum News

T he long-touted idea of a “pipeline on rails” tocarry oil sands bitumen from Alberta to a

tanker port on North America’s West Coast has sur-faced again, with a new twist, along with a mount-ing push to increase the use of rail within NorthAmerica.

G Seven Generations, or G7G, a Vancouver-based company whose principals have strong tiesto aboriginal communities, has rolled out plans fora 1,200-mile link from Fort McMurray, Alberta, tothe trans-Alaska oil pipeline’s pump station nearFort Greeley in Alaska’s Interior. From there thecrude would be delivered south to the pipeline’sterminus at the Valdez Marine Terminal and

onward via tanker to Asian markets.G7G director Matt Vickers told an International

Indigenous Summit on Energy and Mining inOntario June 29 that the plan would “simply meanreplacing the declining supply of Alaska crudewith a new supply of Alberta crude. …

“Studies have already demonstrated that a raillink to Alaska is a viable alternative to the oil

see RAIL LINK page 16

Line now looks feasibleAGDC plan says Alaska in-state gas pipeline from North Slope appears economic

By ALAN BAILEYPetroleum News

Despite capacity restrictions and limitedend-user demand, a natural gas pipeline

from the North Slope to Southcentral Alaska iscommercially feasible, according to a muchanticipated report released July 5 by the AlaskaGasline Development Corp.

“This is a viable alternative for Alaskans totake a look at,” Dan Fauske, AGDC president,told a group of state legislators during a rolloutAGDC’s plan. Fauske himself had been skepti-cal about the economic viability of the line. Hetold lawmakers that he had been pleasantly sur-prised by the favorable pipeline economics

G7G said it has already receivedendorsement from leaders of First Nations

in British Columbia and the Yukon andsupport from Alaska Native tribes along

the rail route.

Wagoner urges CookInlet comparison

Responding to the AlaskaGasline Development Corp.plan for an in-state gas linefrom the North Slope toSouthcentral Alaska, Sen.Tom Wagoner (R-Kenai) July5 praised the work done byAGDC, but said it is impor-tant to avoid negative impactson the Cook Inlet gas indus-try if an in-state gas line is

see WAGONER page 15

TOM WAGONER

see IN-STATE LNE page 13

http://www.PetroleumNews.com/

2 PETROLEUM NEWS • WEEK OF JULY 10, 2011

contents Petroleum News North America’s source for oil and gas news

11 Escopeta gets C-plan approved by DEC

10 Strong interest shown in crude release

11 Parnell taps Hughes for AIDEA board

15 Buccaneer raises $14.5M for Alaska work

EXPLORATION & PRODUCTION

10 AOGCC approves Ivan River storage

Commission’s order allows Chevron to inject up to 20 million cubic feet per day into a depleted zone at Ivan River

LEGAL

TECHNOLOGY

GOVERNMENT

6 ANGDA gets funding, not board members

FINANCE & ECONOMY

3 BRPC plans eastern NS development

Brooks Range joint venture planning Telemarkdevelopment at proposed Greater Bullen unit west of ANWR, could produce by 2015

5 EPA releases draft Shell air permits

Agency says it has addressed questions raised by AppealsBoard in appeal over permits for planned Beaufort and Chukchi Sea drilling

NATURAL GAS

8 Canada mulls national energy strategy

Energy minister says strategy would end regulatory foot-dragging, opposition to pipelines,answering the crucial need for new markets

7 BP wins round in investor fraud case

Federal appeals court sides with oil company, reverseslower court in class action stemming from 2006 Prudhoe Bay pipeline leaks

4 DOG: Cook Inlet can provide through 2018

New State of Alaska report suggests that with properinvestment, Cook Inlet basin can meet gas demand for several more years

6 DNR issues CINGSA gas storage lease

State also OKs contraction of Cannery Loop unit to accommodate storage reservoir, while also approving CINGSA plan of operation

9 Conoco to use MPFM at Kuparuk, Colville

AOGCC allows ConocoPhillips to use a new version of the metering technology for select purposes at the two North Slope units

SIDEBAR, Page 1: Wagoner urges Cook Inlet comparison

Central Mac sizzles: Play draws C$534M inwinning bids from Husky, Conoco, Shell, Exxon

Marilyn Crockett to retire from AOGA

ON THE COVERLine now looks feasible

AGDC plan says Alaska in-state gas pipeline from North Slope appears economic

Anadarko back for gas?

Pending partner OK, company looking to revive Brooks Range Foothills program

Alberta crude in TAPS?

B.C. firm wants rail link from oil sands to Alaska to access Asian markets

Oil Sands to

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By ERIC LIDJIFor Petroleum News

A joint venture led by Brooks RangePetroleum Corp. is proposing an

exploration and development program onthe eastern North Slope that could yield pro-duction by 2015.

The local operating arm of Kansas-basedAlaska Venture Capital Group LLC andBrooks Range Development Corp. wants toform the 200,058-acre Greater Bullen unitover 68 State of Alaska leases of the easternNorth Slope. The proposed unit would sitjust west of the Arctic National WildlifeRefuge, between the Badami and PointThomson units.

Similar to its strategy for developing theproposed Southern Miluveach unit on thewestern end of the central North Slope,Brooks Range wants to develop a potentialreservoir at Greater Bullen to justify con-struction of standalone production facilitiesthat would in turn improve the economics ofother potential accumulations in the region.

The proposed Telemark DevelopmentProject would target a Brookian-age reser-voir in the Flaxman sand and potentially usethe proposed common carrier PointThomson Pipeline. The Greater Bullen unitwould also be near the existing Badami unitfacilities.

The development project is contingent onconfirmation of the reservoir by a seismicprogram and an exploration well, and sanc-tioning by the working interest owners, JimWinegarner, vice president of land andexternal affairs for BRPC, told PetroleumNews. The state is taking comments on theproposal through Aug. 4.

The working interest owners for the pro-posed unit include AVCG, TG World EnergyInc., Ramshorn Investments Inc. andBRDC. Those companies have not conduct-ed as much exploration work in the GreaterBullen area as they have at their other NorthSlope properties, such as the Beechey Pointunit or the proposed Southern Miluveachunit, and most of the $4 million spent to datehas been in preparation for a 3-D seismicprogram.

The joint venture acquired its first leasesin the area at a 2003 lease sale, and acquiredadditional acreage through lease sales andprivate deals in the years that followed.

Brooks Range is making a business offiguring out how to exploit marginal fields.

In filings for the unit application, thecompany told the Alaska Department ofNatural Resources “the other potentialhydrocarbon accumulations are currentlybelieved to be high risk, which then calcu-lates as marginally economic, and would notbe developed without existing infrastructureand processing facilities within” the pro-posed unit, adding that future developmentwould in turn extend the life of Telemarkinfrastructure.

Under a proposed development plan,Brooks Range must have all its permits inplace for the Telemark project by the end of2013, apply for a Telemark participating areaby the end of 2014 and begin productionfrom the development as soon as July 1,2015.

Concurrently, Brooks Range would alsostart an exploration program. According toBrooks Range, the proposed unit “encom-passes a large number of prospects.” As pre-viously reported in Petroleum News, thoseinclude Friezen and Red Dog.

Friezen was the main prospect in the for-mer 79,508-acre Slugger unit that BPformed over 14 leases in the region before itended its Alaska exploration program in2001. BP estimated that Slugger contained

some 280 million barrels of oil, but neverpublically estimated the recoverable reservesfor the unit. Depending on the source, RedDog is estimated to contain between 45 mil-lion and 85 million (P-50) barrels of recov-erable oil.

Under a proposed plan of exploration,Brooks Range would acquire 3-D seismicover the unit — aiming to cover around 300square miles — by March 31, 2012, or losethe unit.

The company would then kick-off a six-well exploration program, drilling a well byMarch 31 of 2012, 2013, 2014, 2016, 2018and 2020 in each of the six blocks of theunit. The initial unit agreement runs throughMarch 31, 2016.

Brooks Range is proposing to break theunit into six blocks — North, North East,North West, South, South East and SouthWest, prioritized: N, SW, S, SE, NE and NW.

The proposed Greater Bullen unitincreases the activity on the eastern NorthSlope.

ExxonMobil is still pursuing its develop-ment project at Point Thomson, althoughongoing legal and permitting issues contin-ue to be a drag on the venture. ExxonMobilis aiming to produce 10,000 barrels per dayof condensate, cycle natural gas and delin-eate other hydrocarbon resources includingoil and natural gas in the coastal area west ofANWR.

Denver-based independent Savant Alaskais working on applying horizontal well tech-nology and possibly advanced hydraulicfracturing techniques at the BP-operatedBadami unit to the west of Point Thomson.Savant and its minority partner, ASRCExploration, joined the project in 2008,drilling two wells and bringing the unit backonline in November 2010.

Savant and Donkel Oil & Gas each holdleases on separate prospects in the easternNorth Slope — Yukon Gold and Stinson,respectively — that could move forward inthe coming years, and Shell wants to drill upto two offshore Beaufort Sea wells in 2012in the region, and could theoretically expandits operations to other prospects if success-ful. �

PETROLEUM NEWS • WEEK OF JULY 10, 2011 3

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BRPC plans eastern North Slope developmentBrooks Range joint venture planning Telemark development at proposed Greater Bullen unit west of ANWR, could produce by 2015

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DOG: Cook Inlet canprovide through 2018New State of Alaska report suggests that with proper investment,Cook Inlet basin can meet gas demand for several more years


With the U.S. Geological Surveyrecently saying the Cook Inlet basin

could hold more gas than previouslythought, the next question is whether thatgas is economic.

The State of Alaska believes so.With the right amount of investment and

storage, the Cook Inlet could meetSouthcentral gas demand through at least2018, according to a new Division of Oil andGas report.

And if that investment yields goodresults, it might push the timeline out to2021.

The 34-page report compared the CookInlet basin to a 1990 pick-up truck: “In bothcases we have been served well and theprospect for more years is likely if we con-tinue to invest. Failure to provide sufficientinvestment will accelerate the end date.Conversely, even if we were to continue toinvest, at some point it will become moreeconomical to buy a new truck or in the caseof gas supply to import from anothersource.”

As a basin-wide look, the study evaluat-ed the potential of the whole region, but did-n’t claim to say whether any individual proj-ect is economic or not. Specifically, thestudy tried to figure out how much gas couldbe produced at various rates of return.

DOG estimated that the region needsaround 90 billion cubic feet per year, a fig-ure that does not include demand for apotential liquefied natural gas export opera-tion.

By defining a “project” as one season ofwork at an existing field and two seasons ata new field, the report identified 39 potentialprojects in the Cook Inlet, 26 in existingfields, 12 in new fields and one basin-widecompression project. The study team thenperformed an economic analysis on eachproject, considering costs under the existingfiscal system and timelines for bringing newproduction online. It considered variousprobabilities for success, as well as threepotential rates of return: 10, 15 and 20 per-cent.

The report measured the commercial via-bility of the Cook Inlet by calculating theinternal rate of return and expected mone-tary value of the basin, and compared thosemetrics against a projected supply curve forthe basin. The IRR results “strongly sug-gest” that the basin contains economic natu-ral gas, while “some of the EMV’s are smallcompared to other projects available forinvestment worldwide,” the report conclud-ed.

For the supply curve analysis, DOGrelied on its 2009 study of the potentialreserves remaining in the basin. That report

estimated that the Cook Inlet still holds atleast 863 billion cubic feet of proved, devel-oped and producing reserves, and could pos-sibly hold much more depending on theamount of industry investment pumped intothe region.

The 2011 report considers the currentlyproducing fields and undeveloped prospectsindentified in the 2009 study, but not explo-ration or unconventional development. Thereport also focuses exclusively on the poten-tial of the basin, without considering theimpact of possible LNG imports, or of NorthSlope gas being shipped to Southcentral.

Conjecture and contradictionsThe report comes amid much confusion

about the future of the Cook Inlet basin.After considering projected regional

demand, known drilling programs on thehorizon and plans to bring more efficientpower generation online, a group ofSouthcentral utilities recently said Alaskawill need to start exporting LNG into theregion as soon as 2014 to stave off a 2 bcfshortfall. That could easily climb to 27 bcfby 2017 and 47 bcf in 2018 if gas is neededto power operations at the proposed DonlinCreek mine.

Less than a week later, the USGS issueda report suggesting that the basin could hold19 trillion cubic feet of undiscovered gas and599 million barrels of undiscovered oil.

At least two independent companies —Escopeta Oil and Buccaneer Energy —believe at least some of those resources existin their offshore leaseholds. Escopeta plansto drill at its Kitchen Lights unit this sum-mer, while Buccaneer is aiming to drill at itsSouthern Cross and North West Cook Inletunits later this year, or more likely next sum-mer.

But while those companies prepare forthe first offshore exploration in the CookInlet in many years, the State of Alaska isconsidering plans to bring North Slope nat-ural gas into the region through either astandalone pipeline or a spur off a pipelineinto Canada.

The Alaska Gasline Development Corp.recently issued a report showing that thestandalone pipeline could be built for $7.52billion and come online as soon as 2019. �

“Even if we were to continue toinvest, at some point it will

become more economical to buy anew truck or in the case of gassupply to import from another

source.” —Alaska’s Division of Oil and Gas


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The multiyear saga of Shell’s effortsto obtain air quality permits for its

planned exploration drilling in Alaska’sBeaufort and Chukchi Seas took its latesttwist on July 1 when the EnvironmentalProtection Agency released yet anotherversion of the permits for public review.The air quality permits form a particular-ly critical component of the permittingrequirements for Shell’s OCS plans, withappeals over permit issuance being amajor factor in past deferrals of compa-ny’s Arctic OCS drilling program.

Needed for 2012Shell wants to drill in Alaska’s

Beaufort and Chukchi Seas during the2012 Arctic open water season and needsthe permits before it can proceed with itsplans. Comments on the draft permits arerequired by Aug. 5.

“We appreciate the work done by EPARegion 10 to issue Shell draft air permitsfor our upcoming drilling program,” Shellspokesman Curtis Smith wrote in anemail dated July 1. “The issuance of thesepermits is a critical milestone and keepsin motion a series of events that will ulti-mately determine our ability to drill in2012.”

The permits in question relate to theoperation of the drillship NobleDiscoverer – Shell plans to use both theDiscoverer and the floating drilling plat-form the Kulluk in 2012 and will need toseparately apply for an air quality permitfor the Kulluk. The company announcedrecently that it is moving the Kulluk toSeattle for power plant and generatorupgrades to reduce air emissions.

Shell has said the efforts to secure airquality permits for its Alaska drillinghave so far cost the company about $60million over a period of four and a halfyears.

EAB mandateFollowing unresolved litigation over

minor air quality permits that Shell hadoriginally tried to obtain for drilling inAlaska’s Beaufort Sea, in 2008 the com-pany elected to apply for majorPrevention of Significant Deteriorationpermits for planned drilling in both theBeaufort and Chukchi Seas. However,with no previous permits of this type hav-ing been issued for drilling in the Arcticoffshore, EPA was forging new groundwhen it published the new permits inApril 2010.

The permits were promptly appealedto the Environmental Appeals Board, apanel of judges within EPA, by the NativeVillage of Point Hope and eight environ-mental organizations. In December 2010the EAB issued a ruling on the appeal,sending the permits back to EPA for revi-sion and saying that EPA needed tochange the specification for when a drill-ship becomes a stationary emissionssource, as distinct from a regular vesselplying the oceans. The EAB also orderedEPA to take into account a new nitrogenoxides emissions rule that had come intoforce while EPA had been preparing thepermits.

After a request for clarity over someissues raised in the appeal but not initial-ly addressed by the EAB, the EAB inFebruary 2011 also ruled that EPA needs

to provide an explanation of why it decid-ed that the modeling of certain types ofparticulate emissions from the drillship isnot necessary.

Modifications madeIn the new draft permits EPA has mod-

ified the original permits to address therequirements of the EAB orders. The per-mits now state that Shell’s drillship willbe considered to be a stationary OCSemissions source when attached to theseafloor by at least one anchor at a drillsite. The original permits had consideredthe drillship to be a stationary sourcewhen Shell’s on-site representativedeclares that the vessel is secure, stableand able to conduct exploratory activity.The new permits incorporate the require-ments of new nitrogen oxides emissionsregulations, as well as revisions to certain


� G O V E R N M E N T

EPA releases draft Shell air permitsAgency says it has addressed questions raised by Appeals Board in appeal over permits for planned Beaufort and Chukchi Sea drilling

see PERMITS page 7Shell plans to use the drillship Frontier Discoverer for exploratory drilling in the Beaufortand Chukchi Seas in the 2012 Arctic open water season.

CO

URT

ESY

SH

ELL

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Cook Inlet Natural Gas StorageAlaska’s plans for a new gas storage

facility on Alaska’s Kenai Peninsula tookanother step forward July 1 when the

Alaska Department of Natural Resourcesissued a gas storage lease for state subsur-face land in the Sterling C sands of theCannery Loop gas field, on the south side ofthe City of Kenai. CINGSA is fast trackingthe development of its storage facility tohead off a potential Southcentral Alaska

utility gas delivery shortfall in the winter of2012-13.

Concurrently with issuing the lease,DNR issued a notice that it is approvingcontraction of the Cannery Loop unit toremove from the unit the land incorporatedin the lease. Any request for a reconsidera-tion of the unit contraction decision must besubmitted to DNR by July 21, before thedepartment issues a final decision.

In issuing the storage lease, Bill Barron,director of Alaska’s Division of Oil andGas, published a finding describing thepotential impact of the storage facility bothon the Alaska economy and on the state’senvironment.

Key roleWith the Cook Inlet gas industry no

longer able to rely on the use of gas supplyinterruptions to industrial users to bolsterthe delivery of utility gas during peak win-ter need, the new storage facility has thepotential to fulfill a key role in assuringyear-round gas deliverability inSouthcentral Alaska, Barron wrote.

In addition, CINGSA’s facility will allowopen access to paying customers, enablingutilities to purchase gas with separate pric-ing for high deliverability rates and helpinggas fields to optimize year-round produc-tion rather than being tied to the extremeups and downs of seasonal demand swings.

And, although the CINGSA projectcould have impacts on local wildlife, DNRhas taken these potential impacts into con-sideration in specifying environmental mit-igation measures associated with the stor-age lease; because of the small surface areaof the CINGSA facility, DNR does notanticipate the facility having any effect onthe uses of habitat, fish and wildlife, Barronwrote.

Complex ownershipThe subsurface land in the Cannery

Loop field involves a complex mixture ofstate and private ownership, with the statelease only applying to state-owned land.The Regulatory Commission of Alaska, aspart of its certificate of public necessity andconvenience for the CINGSA facility, hasgranted CINGSA the power of eminentdomain over land within the facility. Andaccording to a CINGSA progress reportfiled with RCA July 1, the company is stillnegotiating the acquisition of propertyrights with some of the 45 owners of privateland within the storage reservoir. Some landacquisition and valuation issues have beenappealed to the Alaska Superior Court andthe court is holding hearings July 8 to con-sider these issues. Meantime, the City ofKenai has granted CINGSA a right of entryto begin drilling operations in August, theprogress report says.

The progress report also confirmed that,prior to obtaining the state storage lease,CINGSA completed its negotiations withMarathon Oil Co. over access to theSterling Sands C reservoir.

CINGSA has now reached negotiatedagreements covering 100 percent of theoperating interest in the storage reservoir,88 percent of the storage interests and 95percent of the mineral interests, the reportsays.

Decisions appealedFrom the start of CINGSA’s moves to

develop its storage facility, VincentGoddard, president of Inlet Fish Producersof Kenai, whose business facilities sit overpart of the proposed storage reservoir, hasbeen raising questions over the physicalintegrity of the reservoir. Goddard and hiscompanies have appealed to Superior Courtover both the Alaska Oil and GasConservation Commission injection orderfor the facility and the City of Kenai’sapproval for the CINGSA surface facilities,the progress report says.

Meantime, CINGSA has contractedwith Conam Construction Co. to build thepipeline and gathering system for the facil-ity, and has contracted with Nabors AlaskaDrilling for drilling the facility’s wells. Thedriving of conductor pipe at the well padhas already begun, the progress reportsays. �


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GOVERNMENTANGDA gets funding, not board members

The Alaska Natural Gas Development Authority will live to see another year, butstill faces challenges as it tries to operate without a quorum on its board of directors.

Gov. Sean Parnell kept a $319,000 allocation for the public corporation of the Stateof Alaska in his fiscal year 2012 operating budget, giving ANGDA enough money tomeet its projected expenses for the coming year with a little bit left over for new con-tracts.

ANGDA finished out fiscal year 2011 with around $376,000 in the bank. With the$319,000 budget allocation and nearly $145,000 saved by cancelled or reducing exist-ing contracts, ANGDA goes into fiscal year 2012 with more than $840,000 on hand.

After spending the $592,000 required for payroll and basic operating expenses,ANGDA expects to have less than $250,000 available for new capital projects thiscoming year.

Among its ongoing contracts funded from previous allocations, ANGDA plans tocontinue funding its effort to set up a propane distribution network using resourcesfrom the North Slope and its efforts to improve gas supplies for utilities in the Railbelt.

President and CEO Harold Heinze previously said that with the $319,000 appro-priation, ANGDA could also continue open season negotiations on two gas pipelines.

Heinze and his staff will do much of that work on their own, though.The ANGDA board of directors is unable to hold meetings because it currently

doesn’t have the four members required by statute for reaching a quorum. At its lastmeeting, in June, the four sitting board members at the time anticipated that possibil-ity and preemptively gave Heinze the authority to issue small contracts without boardapproval.

Parnell made two appointments to the ANGDA board last summer and early fall,but none since being elected to his first full term in office last November. ANGDAmade several requests to discuss the issue with the governor, but received no response.

The Parnell administration said it has not made any decisions regarding ANGDA.—ERIC LIDJI


DNR issues CINGSA gas storage leaseState also OKs contraction of Cannery Loop unit to accommodate storage reservoir, while also approving CINGSA plan of operation

Contact Alan Bailey at [email protected]

http://www.fugro.com/

http://www.chiulista.com/

By WESLEY LOYFor Petroleum News

A federal appeals court has dealt asetback to a stock market investor’s

securities fraud case against BP.The case centers on the 2006 pipeline

leaks in the Prudhoe Bay field and lossesthe investor, Claude A. Reese, contendshe suffered due to misrepresentationsabout the soundness of BP’s operations inAlaska.

After BP moved for dismissal of thesuit, the district court in Seattle ruled thecase could proceed based on Reese’sargument that BP made false filings withthe U.S. Securities and ExchangeCommission indicating the company wascomplying with the “prudent operatorstandard” at Prudhoe Bay.

BP appealed to the 9th U.S. CircuitCourt of Appeals in San Francisco, and ina 22-page opinion rendered June 29, athree-judge panel reversed the lower courtruling.

Legal falloutReese’s suit was part of the legal fall-

out from leaks on major lines within the

Prudhoe Bay field in 2006. One of theleaks, discovered on March 2, 2006,resulted in a spill of 212,252 gallons ofsales grade crude oil, while a second leakthe following August led to a partial fieldshutdown — an event that briefly rattledoil markets.

Reese sued on behalf of a class of pur-chasers of BP shares during the periodMarch 31, 2005, through Aug. 4, 2006. Incourt papers filed with the original suit in2007, Reese certified that during the classperiod — on May 26, 2006, to be exact —he bought 11 shares in BP p.l.c. at $71.62per share.

Reese, according to the 9th Circuitopinion, argued that as a consequence ofthe leaks and the shutdown of Prudhoe,operated by BP Exploration (Alaska)Inc., parent company BP p.l.c.’s stockprice fell and investors lost billions ofdollars in market capitalization.

“According to Reese, the August 2006

leak occurred despite BPXA’s reassur-ances to investors that the corrosion lead-ing to the earlier leak was an anomaly andthat BPXA was taking necessary precau-tions to avoid another accident,” the opin-ion says. “The suit alleges thatDefendants knew about corrosion in thePrudhoe Bay pipelines but did not takecorrective action or disclose ‘the foresee-able risk’ that BPXA would need to cur-tail its oil production as a result. Reeseclaims to have suffered economic lossand damages as a result of purchasingoverpriced shares of BP p.l.c., in relianceon Defendants’ misleading statementsand omissions about BPXA’s PrudhoeBay operations.”

Case isn’t deadThe district court found that Reese

could use certain quarterly filings the BPPrudhoe Bay Royalty Trust made with theSEC as evidence of BP’s misleading

statements. Specifically, the filings rou-tinely attached to a document containinga “prudent operator standard” provision.

Created in 1989, the trust holds anoverriding royalty interest on a portion ofdaily Prudhoe crude production. Itsshares trade on the New York StockExchange.

Reese argued SEC filings suggestingBP was abiding by the prudent operatorstandard were misleading because thecompany didn’t disclose “that thepipelines at Prudhoe Bay were under-inspected, under-maintained, and subjectto a severe risk of corrosion-related fail-ure,” the 9th Circuit opinion says.

To bolster his complaint, Reese citedBPXA’s guilty plea to an environmentalcrime in connection with the leaks.

But the 9th Circuit judges, in reversingthe lower court, disagreed that the SEC


particulate emissions limits, based onShell’s air quality monitoring.

And recognizing that EAB’sDecember ruling had required EPA to“apply all applicable standards in effect atthe time of issuance of the new permitson remand,” the permits now mandate alimit on greenhouse gas emissions byShell’s drillship and its attendant fleet, toensure that these emissions remain belowlevels that would trigger greenhouse gaspermitting. EPA has recently implement-ed the regulation of greenhouse gases formajor emissions sources.

Additional changesEPA has made a number of other

changes to the permits “in response toadditional information and requests fromShell,” EPA says. Those changes includea specification that the drilling seasonwill end by Nov. 30 rather than Dec. 31; areduction in the total number of opera-tional days allowed under each permit; anincrease from 10 days to six months inthe advance notification required foroperations at a new drill site; the reduc-tion of some emissions from one ofShell’s icebreakers; the removal ofrestrictions on the relative positions ofvessels in the drilling support fleet; andthe removal of some limits on visibleemissions from that support fleet.

“While air permits must be issued as‘final’ to become usable, the movementfrom EPA on the draft permits for theDiscoverer is meaningful progress,”Smith said. “Many years of work havegone into achieving these permits and thesupport from Alaska to Washington D.C.has been tremendous. We believe thework we have done to further modify andreduce our air emissions to meet newstandards meets the goal of having nomeasurable impact on the environment orcoastal villages.” �

continued from page 5

PERMITS


� L E G A L

BP wins round in investor fraud caseFederal appeals court sides with oil company, reverses lower court in class action stemming from 2006 Prudhoe Bay pipeline leaks

see FRAUD CASE page 11

http://www.asrcenergy.com/


� G O V E R N M E N T

Canada mulls nationalenergy strategyEnergy minister says strategy would end regulatory foot-dragging,opposition to pipelines, answering the crucial need for new markets

By GARY PARKFor Petroleum News

Canada urgently needs a NationalEnergy Strategy (NES) to secure

future oil and natural gas markets andserve as a stepping stone to a NorthAmerican policy, said Alberta EnergyMinister Ron Liepert.

He will take his arguments toKananaskis, a mountain retreat west ofCalgary, on July 16-19, when Canada’sfederal, provincial and territorial energyand mines ministerswill again see if theycan resolve their dif-ferences over anNES.

They will havebacking from theCanadian Council ofChief Executives(which includes theleaders of 13 energycompanies and 13financial firms), the Canada WestFoundation (a Calgary-based think-tank)and the Calgary Chamber of Commerce.

In the build up to Kananaskis, Lieperttold a business audience in Calgary that a“coherent, collaborative Canadian energyframework is needed if we are going torealize our full potential as a globalresource powerhouse.”

But he is not going to the meeting withany greater hopes than reaching agree-ment on “some basic principles, goals andobjectives of what a strategy would looklike” as a prelude to involving the “realstakeholders” (Canadians) in the discus-sions.

If pipelines such as Enbridge’sNorthern Gateway to the British Columbiacoast and TransCanada’s Keystone XL tothe U.S. Gulf Coast are not approved,Alberta may not be able to sell all its bitu-men production by 2020, he said.

That in turn would put at risk estimatesthat oil sands development could con-tribute C$1.7 trillion to the Canadianeconomy over the next 25 years, or C$68billion a year, creating C$300 billion intax revenues, Liepert said.

“Every dollar invested in the oil sandscreates about $9 of economic activity and

a third of that is outside the Alberta bor-der,” he said.

Leading Canadian energy executivessay the real reason for an NES is to cir-cumvent an energy regulatory process thathas bogged down applications such asNorthern Gateway and the Mackenzie GasProject.

“If we had a national strategy that saidsomething like, ‘Canada needs to take allnecessary steps to ensure we are notreliant on only one customer for our prod-ucts,’ we wouldn’t be having a debateabout whether the Northern Gatewaypipeline should be approved or not. Eitherit would fit in that strategy or it wouldn’t,”Liepert said.

“If we had a continental strategy, itmight say something like ‘the U.S. shouldtake all available (steps to reduce itsreliance) on imported offshore crude,” hesaid. “If that were the case, we wouldn’t behaving debate today about TransCanada’sKeystone expansion.”

He said harmonizing regulations acrossCanada would also ensure all parties weretreated fairly on environmental issues andnot face different sets of regulations in dif-ferent provinces.

The Chamber of Commerce andCanada West Foundation, supported byutility company Enmax, have developed aposition paper calling for Canada tostrengthen its energy ties with the UnitedStates and Asia-Pacific markets, pursuecontinuous improvement on environmen-tal performance without hurting the econ-omy, build a national consensus on energyissues and foster development of renew-able and non-renewable energy.

It said the fact that the U.S. is thebiggest external consumer of energy“should not preclude diversifying our cus-tomer base to capitalize on high growthregions such as the Asia-Pacific andattract higher prices.”

The chief executives’ council wants toset up a bilateral energy and environmen-tal accord with the U.S. along with initiat-ing a national approach to climate policyand carbon pricing and launch a technolo-gy and innovation strategy. �

RON LIEPERT

Contact Gary Park through [email protected]

http://www.kenworthalaska.com/


The Alaska Oil and Gas ConservationCommission is allowing

ConocoPhillips Alaska to use multiphaseflow meters at the North Slope KuparukRiver and Colville River units.

The June 20 decision allows the compa-ny to use the metering system for well test-ing and production allocation, but not forcustody transfer or fiscal allocation meas-urements.

ConocoPhillips plans to use a system thatMulti Phase Meters AS of Norway devel-oped as part of a multiyear joint venture thatbrought together ConocoPhillips, Shell, theItalian major Eni, the Norwegian companiesStatoil and Hydro and the French majorTotal.

A multiyear testing program that beganin Norway in October 2006 included a fieldtest at the CD-1 pad at the Colville Riverunit in March and April 2010.ConocoPhillips installed the systemupstream of a traditional separator used formeasurements, and ran more than 80 testson 16 different production wells at the unitduring the trial run.

The field data at first suggested themeters under-read oil by 3.7 percent andwater by 5.4 percent, and over-read gas by7.3 percent. After some adjustments to howoperators processed the readings, though,the meters under-read all liquids by 2.6 per-cent — 2.1 percent for oil and 3 percent forwater — and under-read gas by 0.4 percent.

“The appearance of under-reporting inthis instance could be the function of theduration of the field trial and the wells thatwere tested. Since the MPM will be used for

well testing and allocation purposes a slightbias in one direction or the other would notbe significant due to application of an allo-cation factor to adjust the test results tomatch the results obtained from the custodytransfer meter,” AOGCC wrote in its ruling.

AOGCC also said it allowedConocoPhillips to use the metering systemin part because the Colville River unit testsresults were comparable to results fromother tests, showing that the system workedconsistently under numerous well and fluidconditions.

The system also switches between multi-phase metering and wet gas metering, allow-ing operators to measure “slugging” flowwithout having to partially separate thestream.

Use increasing on North SlopeTraditional metering systems required

operators to separate a three-phase streaminto its constituents — oil, natural gas and

water — and measure each stream separate-ly.

Multiphase flow meters can measure allthree phases without separation. The MultiPhase Meters AS system uses radio frequen-cies and other technologies to create a three-dimensional image of flow through multipleplanes that measures the individual parts.

Accurate metering is important becauseit allows operators to monitor the changingprofile of wells as they age, allocate produc-tion volumes among various royalty ownersand perform other tasks dependant on meas-uring the fluids coming out of the ground.

Accurate measurements are increasinglyimportant as new operators rent space atexisting North Slope facilities. For instance,because Pioneer Natural Resources usesKuparuk facilities to process the oil it pro-duces from its nearby Oooguruk unit, themeasuring systems for the two units are nowintertwined. And as a major royalty owner,the State of Alaska is particularly interested

in making sure that all measurements areaccurate.

AOGCC previously allowed Pioneer touse Schlumberger Vx Multiphase FlowMeters for fiscal and production allocationat Oooguruk, and BP applied in January2010 to use the same basic Schlumbergersystem at its offshore Liberty development.

The Oooguruk meters came under criti-cism in 2010 after a whistleblower com-plained about Pioneer and AOGCC opera-tions, including the use of multiphase flowmeters.

An independent investigation commis-sioned by AOGCC found no evidence ofinaccuracy in the metering system, but saidthat AOGCC staff needed to develop clearcriteria for overseeing the technology tomake sure it worked as well as Pioneerclaimed. �


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� T E C H N O L O G Y

Conoco to use MPFM at Kuparuk, ColvilleAOGCC allows ConocoPhillips to use a new version of the metering technology for select purposes at the two North Slope units


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GOVERNMENTStrong interest shown in crude release

The U.S. Department of Energy says it received “very high” industry interest incrude oil to be released from the Strategic Petroleum Reserve.

“Over 90 offers to purchase oil were received (by the June 29 deadline) and theDepartment’s offering of 30.2 million barrels of light, sweet crude oil was substan-tially oversubscribed,” DOE said in a June 30 press release.

DOE, auctioning the oil at President Obama’s direction, said it expects all con-tract awards to be completed by July 11, at which time details about purchasers andsale prices will be released.

The United States is releasing the oil as part of a multinational effort, theInternational Energy Agency announced June 23. The Paris-based InternationalEnergy Agency, or IEA, said its 28 member countries would release a combined 60million barrels over a one-month period. That equates to 2 million barrels per day.

Rationale for oil releaseThe release is necessary to protect a “fragile global economic recovery” and pre-

vent serious market tightening, particularly for some grades of oil, IEA said.It said the release will help make up for lost Libyan oil production, meet peak

refinery demand for crude during the northern hemisphere “driving season,” andbridge the gap until a pledged production increase from Saudi Arabia reaches themarket.

“We estimate that preventing further market tightening in the third quarter willrequire 2 million barrels per day of additional supply,” the IEA said in announcingthe oil release.

The IEA announcement caused an immediate and substantial drop in crude oilprices.

U.S. Strategic Petroleum Reserve oil is stored in huge salt caverns along the Gulfof Mexico coastline. The reserve recently has been filled nearly to its capacity of727 million barrels. It is the world’s largest supply of emergency crude oil.

Crude has been released from the reserve 17 times since 1985.This is only the third time IEA member countries have acted collectively for an

emergency release of oil stocks. They did it previously in 2005 after HurricaneKatrina damaged offshore platforms, pipelines and refineries in the Gulf of Mexicoand in 1991 after Iraq’s invasion of Kuwait.

Of the 60 million barrels to be released, North America will account for half thetotal, with European countries releasing 30 percent and Asian countries 20 percent,the IEA said.

—WESLEY LOY

KENAI, ALASKA JoAnn Zeringue, Sales

7048-893 )709( :hP ywH rupS ianeK 43124

Corporate Headquarters EN BS-12079 Standard Morgan City, Louisiana www.tanks-a-lotinc.com Ph. (985) 385-1913 [email protected]

CUTTING BOXES

BOTTLE RACKS

DRUM RACKS

PALLET RACKS

CARGO BOXES

BASKETS

TANKS

ON-SITE SPILL UNITS

“S U P P L I E R O F C C U ’ S”


The Alaska Oil and Gas ConservationCommission is allowing Chevron-

owned Union Oil Co. of California, orUnocal, to store excess natural gas suppliesat the Cook Inlet basin Ivan River unit.

The decision allows Chevron to inject upto 20 million cubic feet per day into “a near-ly depleted” sand on the west side of theCook Inlet near the mouth of the SusitnaRiver.

AOGCC is allowing Chevron to store gasin the Beluga 71-3 sand between a measureddepth of 6,829 feet and 6,856 feet using theIRU 44-36 well. Chevron said it coulddecide to drill a new well or work-over anold well at the unit in the future.

Chevron plans to use the storage for itsown needs, not for third party customers.

The Beluga 71-3 is an isolated zone at theunit, sandwiched between layers of siltstoneand coal that “act as seals,” as Chevronphrased it in its application to AOGCC.

Ivan River produces from the LowerSterling, Beluga and Tyonek formations,from shallowest to deepest. Unocal drilledIRU 44-36 in March 1993, penetrating twoSterling sands, as well as the Beluga 71-3,reaching peak gas production of 10.7 mil-lion cubic feet per day in September 1993.The well does not penetrate the Tyonek for-mation.

A water breakthrough occurred inJanuary 1995, though, and production ended

in September 1995 after Unocal tried unsuc-cessfully to plug the water chemically.

Unocal worked over the well inSeptember 2001, re-perforating the originalsands and drilling into deeper Beluga sands,but water, sand and coal prevented produc-tion from the deeper zones. Productionpeaked at 6.6 million cubic feet per day inJanuary 2002.

The Beluga 71-3 sand produced gas untilMarch 2004, but attempts to produce fromshallower zones repeatedly failed.

Through June 2005, IRU 44-36 produced3.1 billion cubic feet from the Beluga 71-3sand, or 79.5 percent of the original gas inplace. IRU 44-36 is the only well in the unitthat produces from the Beluga 71-3 sand.

Chevron initially proposed its Ivan Riverstorage venture in early 2010, but withdrewthat application several months later withouta public explanation.

That October, Chevron announced plansto market its Cook Inlet assets.

The company submitted a new IvanRiver application earlier this year that pro-posed using the same well bore to inject thesame volumes into the same gas sand at theunit.

Additional storage in the Cook Inletbasin is seen as one of the best ways ofimproving deliverability and extendingwell life by smoothing the huge seasonaldemand swing in the region. �


AOGCC approvesIvan River storageCommission’s order allows Chevron to inject up to 20 millioncubic feet per day into a depleted zone at Ivan River


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EMPLOYMENT OPPORTUNITYAlaska Department of Revenue

Tax Director

The Alaska Department of Revenue is seeking a dynamic individual to lead the Tax Division. The Tax Director oversees a 125person division responsible for collection of oil and gas severancetaxes, corporate income taxes, fisheries business taxes, and a varietyof excise taxes. In addition, the Tax Division is responsible for revenueforecasting and development of state tax and fiscal policy and oversees the State’s charitable gaming program. The Director is responsible and accountable for the planning, budgeting, staffingand operation of the division and has substantial responsibility forthe determination of policy and for the way in which policies are carried out as they pertain to tax administration.

The preferred applicant should have oil and gas tax and/or industryexperience and be able to maintain cooperative relationships with industry, community organizations, and the Legislature; speak effectively before public groups and legislative committees; successfully fulfill the mission of the division; analyze problems anddevelop solutions; and function independently. A Bachelor’s degree inbusiness, public administration, accounting, finance, economics or arelated field is required. Previous supervisory experience and a CPA,MBA or Law Degree is preferred. The position is located in Anchorage, Alaska.

Interested applicants should submit a cover letter and full resume, including three references to: Alaska Department of Revenue, DeputyCommissioner, Bruce Tangeman, 550 W Seventh Avenue, Suite 1820,Anchorage, AK 99501 in a sealed envelope marked Confidential. Applicants should fully and succinctly explain their applicable experience and their oil and gas knowledge.

The estimated annual salary for this position is between $110,000 and$150,000, DOE. The last day to apply for this job is August 1, 2011;5:00 PM Alaska Time. The State of Alaska is an EEO/ADA employer.

filings would mislead a “reasonableinvestor.”

Read literally, the prudent operatorprovision “was ‘forward-looking’ and nota misrepresentation of current fact,” the9th Circuit opinion says. The judgesadded they did not view the periodic SEC

filings “as the sort of traditional fraudu-lent misrepresentation of fact that couldinduce investors mistakenly to buy secu-rities.”

The ruling does not necessarily killReese’s case, as the 9th Circuit remandedit back to the district court. �


FRAUD CASE

Contact Wesley Loy at [email protected]

GOVERNMENTParnell taps Hughes for AIDEA board

Gov. Sean Parnell appointed Wilson Hughes to the joint boards of the AlaskaIndustrial Development and Export Authority and the Alaska Energy Authority July6.

Hughes is the chief operating officer of GCI, a position he has held since 1991.Prior to that, he worked as president of Northern Air Cargo, president of the con-struction firm Enserch Alaska Services and the engineering firm Frank Moolin &Associates.

During the 1980s, he partnered with several multinational companies on variousAlaska hydroelectric projects, including Terror Lake, Bradley Lake and early feasibil-ity studies for a proposed Susitna project. He contributed to the Red Dog Mine portand road, utility systems in Barrow and offshore gravel islands and causeways in theBeaufort Sea.

Hughes received a bachelor’s degree in electrical engineering from the Universityof Missouri at Rolla and a master’s degree in science and engineering managementfrom the University of Alaska. A 40-year resident of the state, he currently lives inAnchorage.

Hughes is also the past chairman of the Anchorage Economic Development Corp.and previously served eight years as chairman of the AIDEA board of directors.

—ERIC LIDJI

EXPLORATION & PRODUCTIONEscopeta gets C-plan approved byDEC, permit to drill from AOGCC

Escopeta Oil obtained its permit to drill July 1 from the Alaska Oil and GasConservation Commission for its offshore drilling program in the Cook Inlet basin.On June 30, the Alaska Department of Environmental Conservation approved thecompany’s Oil Discharge Prevention and Contingency Plan.

The company is working to have the Spartan 151 jack-up rig in Alaska’s CookInlet by the end of July.

“The rig is still in Victoria, British Columbia,” Escopeta contractor Steve Sutherlintold Petroleum News July 7.

Escopeta terminated its contract on the Kang Sheng Kou, the heavy lift vessel thatbrought the jack-up rig from the Gulf of Mexico to Canada around the tip of SouthAmerica, and now plans to use U.S. flagged tug boats to “wet tow” the rig to Alaska.

Escopeta plans to take the jack-up rig directly to the offshore Kitchen Lights unitwhere the company plans to drill its first well this summer.

The rig stopped in Canada for testing and repair of the legs and jacking systemsthat Escopeta suspected might have been damaged during storms the transport shipencountered on the first attempt to round Cape Horn.

While in Canada, crews also installed high-pressure piping on the rig. Crews planto perform some additional work on the jack-up while it is en route to Alaska,Sutherlin said.

Per paperwork filed with the State of Alaska, Escopeta ultimately plans to drill fivewells over five years at its Kitchen Lights unit in upper Cook Inlet.

Kitchen Lights is a combination of several distinct oil and gas prospects.—KAY CASHMAN

http://www.flowlinealaska.com/

http://www.alutiiq.com/

Crowley and Roundarch receive TMSA award of merit Crowley Maritime Corp said June 17 that it and its digital design partner, Roundarch, were

presented with an award of merit from the Transportation Marketing and Sales association forthe company’s newly redesigned web sites.

Mark Miller, Crowley’s director of corporate communications, accepted the web-based mar-keting award on behalf of both companies at TMSA’s 59th Annual Compass Awards Dinner,which recognized the best in marketing, sales and communications within the transportation,logistics and passenger transit industries for 2010.

Crowley partnered with Roundarch, a leader in digital design and implementation, to devel-op a new web presence for the corporation and its subsidiaries that organized content around ahighly intuitive, solutions-based navigation component. The new web sites includewww.crowley.com, www.titansalvage.com, www.jensenmaritime.com andwww.customizedbrokers.net.

“We now have sites that are more responsive to the needs of our customers, and with theincreased strategic use of imagery to back up our case studies, we feel like we’re presenting ourcapabilities and our brands in a far more compelling way,” Miller said. “We thank the TMSA forthis distinguished award and see it as further confirmation of the success of the project.”

ATI announces new President and CEO Daniel BooneAlaska Telecom Inc., a subsidiary of Calista Corp., said June 29 it

has welcomed Daniel Boone to the position of president and CEO.Boone previously led the marketing and business accounts for ICGCommunications Inc. in Colorado. He has also served as the chief crim-inal investigator and manager for the Alaska Department of Revenue,responsible for all criminal investigations in the Tax, Permanent FundDividend and Child Support divisions. Boone earned a bachelor’sdegree in Business Administration and Accounting from the Universityof Phoenix and a theological diploma from Charismatic Bible College.

The second largest of the original 13 Alaska Native corporations,Calista was established under the Alaska Native Claims Settlement Actof 1971 and represents over 13,000 shareholders. The Calista regionencompasses over 6.5 million acres and includes 56 villages, which are incorporated into 46individual village corporations.

Editor’s note: All of these news items — some in expanded form — will appear in thenext Arctic Oil & Gas Directory, a full color magazine that serves as a marketing tool forPetroleum News’ contracted advertisers. The next edition will be released in September.


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DANIEL BOONE

determined by the pipeline team.The in-state pipeline concept was previ-

ously referred to as the bullet line butAGDC’s new project name, the AlaskaStand Alone Pipeline, or ASAP, is anacronym presumably chosen to reflect thegrowing sense of urgency to do somethingabout tightening gas supplies from theCook Inlet basin

Under the terms of the Alaska GaslineInducement Act, or AGIA, an internalAlaska gas line cannot undermine the eco-nomics of a potential future gas export linefrom the North Slope by carrying morethan 500 million cubic feet of gas per dayfrom northern Alaska. The key to the com-mercial viability of the line is optimizingits design for that maximum throughput,coupled with strong interest by potentialindustrial gas shippers to use the fullcapacity of the line, Fauske and AGDCCommercial Manager Michael Roceretatold Petroleum News.

Fauske told the legislators that localAlaska gas usage in Fairbanks andSouthcentral Alaska amounts to 200-240million cubic feet per day but that AGDChas received expressions of interest fromindustrial shippers to fill the remainder ofthe pipeline capacity.

Industrial interest in the project remainsconfidential, but the production of lique-fied natural gas, or LNG, potentially at therate of 33,000 barrels per day, is the mostlikely option for gas shipped from theNorth Slope, Fauske said. The pipelinedesign also accommodates the shipping ofnatural gas liquids, or NGLs, from theNorth Slope. The monetizing of gasthrough the use of gas-to-liquids technolo-gy is another possibility, but seems theleast favorable of the industrial options,Fauske said.

Based on an estimated cost of around$7.52 billion, including the pipeline and anassociated gas conditioning plant on theNorth Slope, gas could be delivered to con-sumers in Southcentral Alaska at a cost of$9.63 per million British thermal units,compared with a current price of $8.85 permillion Btus, Fauske said. That estimatefor ASAP-delivered gas represents an all-in cost, including the pipeline tariff,assuming utilities would pay North Slopegas producers about $2 per million Btu forthe gas, and that the cost of local gas deliv-ery from the transmission line to con-sumers would be about $2 per million Btu.Using identical assumptions for the priceof North Slope gas and the cost of local gas

distribution, Fairbanks consumers wouldhave to pay $10.45 per million Btu for gas,compared with a current price of $23.35,he said.

The bulk of project funding wouldcome from bonds issued through theAlaska Railroad Corp.

The ASAP design envisages a gas con-ditioning plant on the North Slope, prima-rily to remove carbon dioxide and sulfurfrom the gas. A 24-inch pipeline would runsouth from the treatment plant, followingthe route of the trans-Alaska oil pipeline toa point near Livengood, northwest ofFairbanks. From Livengood the line wouldgo south, joining the Parks Highway corri-

dor near the town of Nenana. The linewould then follow the route of the ParksHighway, passing to the east of DenaliNational Park and eventually terminatingat a connection with Enstar Natural GasCo.’s Beluga gas line near Big Lake, northof Anchorage.

The pipeline route could accommodateinterconnections with possible additionalfuture natural gas sources, such as fieldsthat might be developed in the BrooksRange Foothills (see Anadarko story onpage 1) or in the Nenana basin, southwestof Fairbanks, the ASAP report says.

A spur line would run east from themain pipeline to Fairbanks from a point on

the line a few miles north of Nenana. Thesomewhat high tariff required for this spurline is because the estimated cost of gas inFairbanks is higher than the estimated costin Southcentral Alaska, despite Fairbanksbeing closer to the North Slope. Roceretatold Petroleum News that the primary driv-er for the high spur line tariff is the cost ofa gas processing facility, required at thepipeline junction to extract utility gradegas from the gas passing down the mainline. The cost of that processing facilitywould need to be spread across the rela-tively low volumes of utility gas needed inthe Fairbanks area.

Fauske said AGDC had investigated theoptions of using the Parks Highway routeor an alternative route following theRichardson Highway via Delta Junctionand Glennallen. Both routes share similarenvironmental issues, but the RichardsonHighway route would cost more because itis longer, he said.

“There is nothing on the RichardsonHighway that mitigates the fact that it’sabout $500 million to $600 million more incost because it’s 93 miles further,” he said.“We have analyzed and analyzed this issuebut the facts are the facts.”

Fauske cautioned against any furtherinvestigation of alternative routes, sayingthat a change of route would necessitate acomplete restart on the project’s federally-mandated environmental impact statement,a restart that would likely delay the projectby 18-24 months.

Under the current schedule, a draft EISis due out in August, with the final EISanticipated in the first quarter of 2012, atimeframe that Fauske characterized as “anincredible accomplishment.” The proposedpipeline route crosses 427 miles of stateland – AGDC has completed the state rightof way document, with the commissionerof the Alaska Department of NaturalResources expected to sign the documentsoon, he said.

“The route selected in this project planshould be adopted as the final route, in thatno more study or analysis of route selec-tion be undertaken or supported by AGDCor any other state agency,” Fauske said.

Although the legislation that authorizedand funded the ASAP project specified a2015 completion date, that date is not real-istic given the time required for activitiessuch as permitting, holding an open seasonand securing financing, Fauske said.Instead, AGDC envisages a completiondate near the end of 2018, with first gasflowing through the line in 2019.Southcentral Alaska utilities have


executive director. “Marilyn’s commitment and tenacity

for the industry and Alaska is unparal-leled,” said Ken Sheffield, both presidentof AOGA and president of PioneerNatural Resources Alaska. “We will missher, but wish her all the best on her well-deserved retirement.”

“I will miss AOGA, the issues, and thepeople very much,” Crockett said, “but Ilook forward to enjoying retirement withmy husband and spending time with myfamily and grandchildren. Alaska willcontinue to be our home, and we willremain engaged in the issues facingAlaska.”

Pete Slaiby, vice president of ShellAlaska, said “it feels like Marilyn tookthe reins at AOGA about the same timeShell was making the push back intoAlaska. Our strong focus on the offshoreadded a lot to her plate right away and she

never missed a beat. “Over the years Marilyn has proven an

excellent champion for industry and forAlaska,” Slaiby said, wishing her “all thebest” in future endeavors.

Carl Portman, deputy director of theResource Development Council ofAlaska, described Crockett’s career as“astonishing,” noting it began before theconstruction of the trans-Alaska oilpipeline.

“Marilyn has dedicated 41 years togrowing Alaska’s economy through theresponsible development of our vast oiland gas resources. Here at RDC, she hasserved many years on our executive com-mittee, working with executives across allof Alaska’s resource industries, to addresspressing issues, overcome challenges, andto expand Alaska’s economy.”

Phil Cochrane, vice-president of exter-nal affairs for BP in Alaska, agreed thatCrockett has made “an enormous contri-bution to our industry and the state ofAlaska,” but, he said, “it’s not just thework she has done, but how she has done

it — with integrity and honesty.”Bill Popp, president and CEO of

Anchorage Economic DevelopmentCorp., described Crockett as a “consum-mate professional” who “set a standard ofexcellence we should all aspire to.”

Popp said Crockett will be “sorelymissed in the important oil and gasdebates in the coming year and beyond.

“She has been a steady hand at thewheel of AOGA. … Marilyn’s logical andfact-based approach to the issues hasmade her exceptionally effective,” hesaid.

CH2M HILL Vice President and RDCPresident Tom Maloney portrayedCrockett as a “true pioneer. …

“Her contributions to the ResourceDevelopment Council … on oil and gas,mining, fishing, forestry and tourismissues has been greatly appreciated by somany Alaskans,” he said.

One of AOGA’s newest members,Statoil, was equally complimentary ofCrockett.

Bill Schoellhorn, the company’s explo-

ration director for Alaska, said, “one ofthe first things Statoil did when it decidedto make Alaska part of its explorationstrategy was to join AOGA. Marilyn,through her leadership at AOGA, has pro-vided us with invaluable insights andguidance into the important issues thatdrive the oil and gas industry in Alaska.”

Schoellhorn described Crockett as a“trusted friend for Statoil,” who madeemployees of the Norwegian company“feel welcome … easing our transition”into Alaska.

He congratulated her on “her long anddedicated service to AOGA” and wishedher “well as she moves onto new chal-lenges.”

AOGA’s board of directors has initiat-ed a search for a new executive directorand intends to fill the position beforeCrockett’s departure at the end of the year.

—KAY CASHMAN


CROCKETT

Contact Kay Cashman at [email protected]

Flow Schematic of ASAP Facilities


IN-STATE LINE

see IN-STATE LINE page 15

The Alaska Gasline Development Corp.’s proposed design for an in-state gas line from theNorth Slope includes a gas conditioning facility on the Slope, a spur line to Fairbanks andfacilities for the transportation of natural gas liquids.

ALA

SKA

GA

SLIN

E D

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OPM

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CO

RP.


indicates “this summer,” but the applica-tion itself said 2011 or 2012.

In the application, Anadarko said itplans to set thermistor strings along theroute to provide real-time ground temper-ature data in preparation for constructinga winter road when the tundra is frozenenough to support wheeled equipment.

PN sources said Anadarko is commit-ted to resuming the multiyear, multi-wellprogram, but does not yet have partnerapproval from BG Group and SuncorEnergy for the first step in that process —a “rig-less” test of the previously-drilled

Chandler well. Partner decisions are expected in mid-

July.The only reason Anadarko, operator of

the shared leases, began permitting aheadof partner approval was because waitinguntil mid-July to file for modification ofthe existing land use permit would havecost the project a season, PN sources atDNR said.

Sharing costs with LincIn a map accompanying the filing

(www.petroleumnews.com/pnfm/thermistorlocationsmap.pdf ), Anadarko pro-posed a temporary winter road beginningat the Dalton Highway and moving west-ward and slightly southward to theChandler site near the NationalPetroleum Reserve-Alaska.

PN sources said Anadarko is talking toLinc Energy about sharing the cost of thewinter road. Linc recently acquired acontrolling interest in the Umiat oil fieldand is looking for a rig to fly out to itsproject for winter exploration and delin-eation drilling.

Anadarko spud Chandler No. 1 inearly 2008, but cut drilling short that yearbecause of seasonal restrictions.Anadarko also drilled the much shallow-er Gubik No. 3 well that winter in theundeveloped Gubik gas field, east of theColville River. The company completedChandler No. 1 in early 2009, and alsodrilled two other new wells, Gubik No. 4and Wolf Creek No. 4. Wolf Creek is inthe NPR-A about 40 miles west of Umiat.

Together, these prospects make up theGubik Complex, a series of gas fieldsstretching across more than 100 miles ofNative, state and federal land. Petro-Canada, a former partner in the program,said the three wells that were tested “all

encountered natural gas.” The firstGubik well, in fact, tested at rates of up to15 million cubic feet per day, proving upthe previously discovered, but undevel-oped, Gubik gas field.

The natural gas in the foothills of theNorth Slope isn’t consolidated into a sin-gle massive deposit like Prudhoe Bay orPoint Thomson, though. Instead, it isspread across several larger deposits in aremote and undeveloped area of the state.

Anadarko had been trying to decidewhether it could strategically develop theregion.

“The determining factor? If we canfind three fields to make it that mightwork,” Anadarko official Mark Hanleysaid in early 2009. “If it’s going to take usseven that might not be economic.”

Anadarko wanted to test Chandler inearly 2010, but decided that launching awinter exploration program to test onewell wouldn’t be cost effective. The com-pany then hoped to conduct the test anddrill two more wells in early 2011, butthat also didn’t happen.

Suncor replaced Petro-CanadaThe program most likely did not move

forward in 2010 because Anadarko got a

new partner in August 2009, when oilsands senior Suncor took over Petro-Canada. Suncor has never said what itintends to do with its one-third ownershipin the foothills acreage.

Operator Anadarko said it hoped toship future gas from Gubik to marketthrough a future large-diameter NorthSlope gas line, or a smaller, in-state lineto Southcentral Alaska.

Late last year PN sources saidAnadarko was looking to sell most of itsundeveloped acreage in Alaska. That stillmight be the case, but PN sources nowsay that Gov. Sean Parnell’s apparent sup-port for an in-state gas line, a reduction instate oil production taxes and a year-round road to Umiat has revivedAnadarko’s interest in the area.

Either way, the company would wantto know the results of its Chandler well. �

Editor’s note: Anadarko’s most suc-cessful partnership to date in Alaska hasbeen with ConocoPhillips in the ColvilleRiver unit, which includes the Alpine oilfield.


ANADARKO

C$67 million for a 217,000 acre parcel;Shell, C$43.4 million for three parcelstotalling 498,000 acres; sister companiesImperial and ExxonMobil, with a com-bined bid of C$43 million, split equally tolock up two parcels totalling 443,000acres; and the MGM Energy-6362 NWTbidding, which landed three parcels cover-ing 629,000 acres for C$5 million.

The bidding round laid waste to previ-ous records for the Central MackenzieValley, easily beating previous highs for atotal sale, with the three leading parcelsestablishing new benchmarks by surpass-ing C$32.8 million by Talisman Energyand ARL Corp. in 2006, C$32.1 million byPetro-Canada in 2005 and C$24.8 millionby a consortium led by NorthrockResources in 2004.

Plus 521,000 acres in BeaufortIn addition, Arctic Energy & Minerals

made two bids of C$1 million each forparcels of 223,000 acres and 298,000 acresin the Canadian section of the Beaufort Sea.

NWT Industry Minister Bob McLeodsaid the bidding response is proof of indus-try confidence in northern oil and gasprospects.

He is eager to see the Canadian govern-ment negotiate a fiscal agreement with pro-ponents of the Mackenzie Gas Project andresolve infrastructure challenges to supporta pipeline along the Mackenzie RiverValley.

McLeod said he was encouraged by apromise Prime Minister Stephen Harpermade during the recent federal election todevelop a package of infrastructure meas-ures that would enable the MGP to proceedon a commercial basis.

Chris Feltin, an analyst with MacquarieCapital Markets, said Husky’s spendingcommitments compared with its peers inthe play indicate the company could be tar-geting an oil-rich prospect.

He said Husky may believe it has “keyedinto a new play,” having earlier signalled itwas not planning any activity in theNorthwest Territories this year.

Husky already holds exploration licens-es in the Central Mackenzie Valley, includ-ing interests for natural gas and light oil.


MAC BIDDING

see MAC BIDDING page 15

Contact Kay Cashman at [email protected]

http://www.alaskaminers.org/

http://www.akfrontier.com/

announced that they anticipate importingLNG, starting in 2014, to meet predictedshortfalls in Cook Inlet gas supplies. But areport published recently by the AlaskaDepartment of Natural Resources impliesthat the 2015 deadline for the delivery ofNorth Slope gas into Southcentral is notnecessary, Fauskesaid. (See article onpage 4 of this issue.)

Fauske also cau-tioned againstattempting toachieve an unrealis-tic schedule for whathe characterized as“an industrialmegaproject.”

“It’s very clear that where projects ofthis magnitude run into trouble is they startgetting goofy with the schedules,” he said.“There are certain things that must occur.”

The cost estimate for the entire pipelinesystem is based on an assumption that theState of Alaska would own the system.However, AGDC’s plan only envisages thestate putting $340 million into the project,to cover the costs of continuing the projectto a point where a final go/no-go decisioncan be made.

“A builder/owner/operator is not goingto come up here and spend $100 million oftheir own money to see if the project’sviable. That’s simply not in the cards,”Fauske said.

Project cost estimates currently haveuncertainties in the range of plus or minus30 percent, but that uncertainty shoulddrop to around 10 percent by the time thatthe system design is completed, he said.

An essential step prior to project sanc-tion would be the holding of an open sea-son to seek commitments from shippers,thus enabling the issue of bonds to financethe bulk of the project.

With state ownership of the pipelineenabling project financing through the

issue of Alaska Railroad bonds, anarrangement that would significantlyreduce project costs, state legislators mustdecide as soon as possible whether to rec-ommend legislation authorizing the publicownership model for the project, Fauskesaid. A lack of action by the Legislaturewould amount to a de facto approval of pri-vate project ownership, an arrangementthat would end up costing more, primarilybecause any company owning the linewould have a lower bond rating than thestate, he said.

According to AGDC’s plan, the ASAPproject will also verify with the InternalRevenue Service that the Alaska Railroadcan raise tax exempt bonds for the project,a capability that the Railroad enjoys underfederal law but which has not been tested.A fallback position would be some alterna-tive form of state bonding, the report says.

The main project risks are the possibili-ty of a failed open season, constructioncost overruns and project delays resultingfrom regulatory or environmental permit-ting, Fauske said. One specific permittingrisk is the need for a special federal permitfrom the U.S. Department ofTransportation Pipeline and HazardousMaterial Safety Administration – this per-mit could add significant cost and havescheduling implications, he said.

Fauske emphasized that he sees ASAPas complementary to other projects such asthe AGIA line, a planned major hydroelec-tric project on the Susitna River or the pro-duction of gas from the Cook Inlet basin:“I believe the state needs all of these

things. We’re not an impediment.”However, delivery of North Slope gas to

Southcentral Alaska could have a negativeimpact on the usage of Cook Inlet gas after2018, Fauske said. But ASAP is a viablepipeline option that people need to consid-er, he told the legislators at the July 5 meet-ing.

Lawmakers will now need to review theASAP report in detail, presumably ques-tioning the assumptions behind the projecteconomics and deciding where they wantto go from here on the vexing question ofAlaska gas supplies. �

As well, one license operated by Huskyhas tested at 20 million cubic feet per day ofgas and 6,300 barrels per day of oil just 50miles from the existing Enbridge crude oilpipeline from the Norman Wells oilfield tonorthern Alberta. The 26-year-old pipelineoperates well below its 45,000 bpd capaci-ty.

Pat Boswell, chief executive officer ofInternational Frontier Resources, a partnerwith Husky, said earlier this year it appearsa concerted effort is under way to round upthe entire land area west of the MackenzieRiver and south of Norman Wells whileland prices are low in the absence of largescale pipeline connections to southern mar-kets.

CNOOC affiliate in Yukon Territory In a separate development in Canada’s

north, an affiliate of China’s CNOOC hasinvested in Northern Cross to explore theoil and gas resource potential of Eagle Plainin the Yukon Territory.

Terms were not disclosed, but NorthernCross president Richard Wyman said July 5the funding will allow his company to fulfilwork commitments to acquire seismic dataand conduct drilling “over the next fewyears.”

He said that “for the first time indecades, a concerted effort can now occurto further evaluate the oil and gas potentialof Eagle Plain.”

Northern Cross said the investment

could diversify sources of primary energyfor the Yukon and contribute to the territo-ry’s energy self-sufficiency.

CNOOC is China’s largest producer ofoffshore crude oil and natural gas and oneof the largest E&P companies in the world.

—GARY PARK



MAC BIDDING



IN-STATE LINE

DAN FAUSKE

developed. A complete assessment ofthe Cook Inlet should be conducted forcomparison with any proposed in-stategas line, he said.

Wagoner pointed out that the AlaskaLegislature has passed new tax incen-tives for Cook Inlet exploration, the

state has just seen its best Cook Inletlease sale since 1983, two jack-up rigsare vying to be the first to reach theInlet for new offshore drilling andBuccaneer Energy has just seen suc-cess with an onshore exploration well.

Editor’s note: See related story onpage 4 of this issue.


WAGONER



FINANCE & ECONOMYBuccaneer raises $14.5M for Alaska work

Buccaneer Energy Ltd. is set to raise around $14.5 million for its exploration anddevelopment program in Alaska’s Cook Inlet basin through an institutional placement.

The Australian independent recently placed approximately 104 million ordinaryshares — 97 million shares left over from a previous placement and 97 million newshares. The placement required investors to subscribe to an equal number of eachshare type.

The funds have been committed and the settlement will take place July 15, thecompany said.

Buccaneer is raising the capital to fund its onshore Kenai Loop program, its stakein an offshore venture in the Cook Inlet and other working capital and transactioncosts.

Earlier this year, Buccaneer drilled its first Alaska well — Kenai Loop No. 1 —reporting an initial flow rate of 10 million cubic feet per day and 645 feet of gross pay.

Buccaneer is also working with the Alaska Industrial Development and ExportAuthority and the marine company Ezion Holdings Ltd. to buy the TransoceanAdriatic XI jack-up rig for a four-well exploration program at two offshore units oper-ated by Buccaneer.

Buccaneer plans to use the $14.5 million to build the infrastructure needed to bringKenai Loop No. 1 into production, to drill the Kenai Loop No. 2 well in the third quar-ter and to pay its mandatory $2.5 million stake in the roughly $85 million jack-up rigventure.

Buccaneer plans to drill the Kenai Loop No. 2 well around 1.25 miles east of theKenai Loop No. 1 location and recently said it has received all its surface permits forthe well.

—ERIC LIDJI

http://www.LFAV.com/

http://www.matsystems.ca

pipelines currently being planned throughBritish Columbia,” Vickers said, referringto Enbridge’s planned Northern Gatewayproject to Kitimat and Kinder Morgan’soptions which include expansion of itsTrans Mountain pipeline to the greaterVancouver area and construction of a newline to Kitimat.

“Diversifying markets for Canadian oilis an important challenge, but we need toachieve this goal in the most environmen-tally and socially responsible way possi-ble,” he said.

The Alberta-Alaska option “promisessignificant economic benefits whileavoiding many of the environmental risksassociated with current pipeline propos-als, Vickers said.

The G7G initiative offers the advan-tage of using the existing terminal atValdez, which faces a declining oil supplyfrom the North Slope, and does not facethe same moratorium that exists in north-ern British Columbia waters along withattempts to ban crude tankers along thetotal length of the British Columbia coast.

Northern Gateway, in particular, hasencountered a hostile reception from FirstNations and environmental groups inBritish Columbia as it prepares for regu-latory hearings next year before Canada’sNational Energy Board.

G7G said its proposal eliminates threebarriers to development of the oil sands— the cost, delays and financial risksinvolved in building pipelines out ofAlberta and obstruction from lawmakersand environmentalists in Canada and theUnited States —while offering better net-

backs to producers.However, the risks of derailments,

especially through sensitive mountainregions, could pose a challenge every bitas great as pipeline ruptures.

First phase C$12 billionG7G has put a price tag of at least C$12

billion on the first phase of its project,compared with the C$5.5 billion estimatefor the 525,000-barrels-per-day NorthernGateway plan, which includes a parallelsystem to import 193,000 bpd of conden-sate.

G7G said it has already receivedendorsement from leaders of First Nationsin British Columbia and the Yukon andsupport from Alaska Native tribes alongthe rail route.

It now expects to complete a feasibilitystudy, business plan and First Nations con-

sultation in the “coming months.”An Alberta-Alaska link is just the latest

in a campaign by Canada’s two dominantrailways — Canadian National, or CN,and Canadian Pacific, or CP — to drawthe petroleum industry back to its roots,when the only way to get crude oil to mar-ket was by rail.

Earlier this year they made presenta-tions to a Saskatchewan forum, making apitch to ship crude from that province’sBakken play, targeting business tradition-ally controlled by Enbridge pipelines.

Mike Foran, CP’s director of sales, saidthere is a “need for (shipping) alternativesduring unforeseen times of pipeline appor-tionment.

“Crude on rail is here to stay,” he said,confident that several U.S. refineries willexpand to take unit trains. “We can helpbuilt a network of markets — multiple ori-gins, multiple destinations.”

CN representative Mark Cvar said oneunit train would handle all of the dailyBakken production.

Although pipelines have lower costs,they require long-term shipping commit-ments, he said, adding that interest in railis being spurred by a spike in oil prices,space allocations on pipelines and produc-ers realizing that rail is a viable option.

Randy Meyer, CN’s manager of oilsands sales, has previously claimed that aninternational cost analysis showed movingpure bitumen by rail is cheaper than dilut-ed bitumen for pipeline transportation, buthe declined to provide per barrel costs, cit-ing confidentiality agreements with vari-ous oil sands producers.

He said the costs associated with estab-lishing a bitumen rail system would run tomillions of dollars “not billions,” whileshipper commitments would last for years,but not the 25 years sometimes required

by pipeline companies.Meyer also said rail transport is more

scalable than pipelines and can bedesigned to meet current demand, whichcould be as little as 5,000 bpd for smallerproducers — a significantly lower barrierto entry in return for the same marketaccess as “more pipeline sized” producers.

He said CN, rather than requiring pro-ducers to commit to provide specific vol-umes at a particular time or face a penalty,“would meet your timing based on yourbusiness requirements.”

Rail offers time savingsMeyer also said bitumen should be

shipped from Alberta to U.S. Gulf Coastrefineries in eight to10 days comparedwith 40 to 50 days for a pipeline.

James Cairns, CN’s vice-president ofpetroleum and chemicals, told producersthey “shouldn’t think of a rail project as anabsolute alternative to pipe. Our view isthat rail can be a companion to pipe, be amerging mechanism to pipeline infra-structure while permitting issues areworked out … or, in some cases, a replace-ment to pipe.”

Stephen Whitney, CP’s vice-presidentof marketing, said railway officials areworking on altering the oil industry’s per-ception that pipelines are the only choice.

“I don’t think it is rail versus pipe,though it can be in some cases. The modesare complimentary, but the best supplychain model is going to prevail,” he said.

Whitney said rail’s main advantage isits ability to ramp up faster than the yearsit takes to approve and build pipelines.

Industry welcomes another optionThe Canadian Association of

Petroleum Producers said the amount ofoil moving by rail is still very small, butthe industry welcomes having the extraoption available.

Diana McQueen, parliamentary assis-tant to Alberta Energy Minister RonLipert, said rail could have a bridging roleto play while the industry expandspipeline infrastructure to access new mar-kets.

“The pipeline-on-rail option may posea trade-off between bitumen transporta-tion costs by eliminating the need fordiluents and higher transportation costsfrom using rail instead of a pipeline,” shesaid.

In late 2008, CN approached theAlberta government with a plan to movebitumen, estimating it could carry 2.6million bpd if 20,000 railcars were addedto its fleet. �



RAIL LINK

Oil Sands to

MARKET

Alyeska Pipeline ( TAPS )

Watson Lake Valdez

Fort Nelson

Wrangell

Kitimat Prince Rupert

Fairbanks

Port MacKenzie

Delta Junction

Kitwanga Gitwangak

Skagway Haines

Edmonton

Fort McMurray

Whitehorse

Chugach

Doyon

United Yukon FNs

Kaska

Tahltan

Gitanyow

Gitxsan

Dene Tha

Treaty 8

Generating for Seven Generations

The United States of America

Europe Asia

4

CO

URT

ESY

G7G


http://www.pndengineers.com/

http://www.acuren.com/

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