alaska’s beef with blm · yonker, who nurture the magazine into existence every year. ak-wa...

Vol. 15, No. 32 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of August 8, 2010 • $2

� G O V E R N M E N T

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

� N A T U R A L G A S

Multiple bids from major players,others, received in open season

page3

8 Alaska hotels offer value-added lodging packages

14 Alaska mining brightens region’s economic outlook

33 North West Co. moves to port space in Tacoma

37 Wealth of entertainment awaits Seattle’s visitors

EXPLORING THE ALASKA-WASHINGTON CONNECTION. 2010

The annual Alaska-Washington Connection magazine is inside thisissue of Petroleum News. It is published by Business to BusinessMagazines, a division of Anchorage-based Petroleum Newspapers ofAlaska LLC, which owns Petroleum News. Kudos to PN's special pub-lications director Marti Reeve for pulling it all together, and thank youcontract editor Rose Ragsdale and contract marketing director BonnieYonker, who nurture the magazine into existence every year.

AK-WA Connection inside

Alaska’s beef with BLMState accuses feds of drilling violations, mismanagement of legacy wells

By WESLEY LOYFor Petroleum News

A laska regulators have accused the U.S. Bureau ofLand Management of violating state well safety

regulations on an exploratory drilling project near theremote North Slope village of Wainwright.

The case brings to a head months of simmeringtensions between state and federal officials not onlywith respect to the Wainwright project, but also theBLM’s handling of dozens of old “legacy wells” onthe North Slope.

The Alaska Oil and Gas ConservationCommission on June 22 hit the BLM with a “notice ofviolation,” saying the federal agency appeared to be inviolation of state regulations in drilling wells withoutrequired safety equipment, and improperly securingsuspended wells.

“BLM’s cavalier approach to well safety and regu-latory compliance is unacceptable,” said the noticesigned by Dan Seamount, a geologist and chairman ofthe three-member commission.

The Wainwright project is a joint effort involvingthe BLM, the U.S. Geological Survey, the North SlopeBorough and Arctic Slope Regional Corp. The goal isto test a local coalbed as a potential source of naturalgas to meet energy needs in the remote village ofabout 550 people on the Chukchi Sea coast. Ninewells have been drilled on the project since 2007.

The AOGCC has authority to regulate drillingstatewide, whether on federal, state or private land.

‘Bad worms’Petroleum News obtained letters, e-mails and other

Eni modules reach siteSealift for Nikaitchuq production facilities has arrived off Oliktok Point

By ALAN BAILEYPetroleum News

Two large modules for Eni Petroleum’sNikaitchuq oilfield production facilities have

arrived off the central North Slope, the company toldPetroleum News Aug. 2.

“Both of the modules, the processing facilities andutilities modules, weigh roughly 4,000 tons each andwere loaded on two barges along with other smallmodules and miscellaneous structural componentsand departed from Louisiana on June 1st , 2010,” thecompany said. “The modules arrived off OliktokPoint on July 29th.”

The barges completed the final stage of their jour-ney after spending several days off Barrow, at the

western end of the Beaufort Sea, waiting for sea iceconditions to improve, Eni said. The company plansto offload the modules onto the Nikaitchuq surface

Enstar gets new GSAContract with ConocoPhillips would provide non-firm supplies on peak days

By ERIC LIDJIFor Petroleum News

Enstar Natural Gas recently signed anatural gas supply contract with

ConocoPhillips.The contract is for non-firm supplies

over the next few years, but the exact termsand pricing of the deal won’t be knownuntil Enstar submits it to the RegulatoryCommission of Alaska for approval. Thecompany expects to file the contract in mid August.

Enstar announced the contract in comments to theU.S. Department of Energy supporting an extensionof the federal license that allows liquefied natural gasexports from Alaska.

ConocoPhillips and Marathon Oil jointly own the

LNG export facility on the Kenai Peninsulaand have asked the government to continueexports through March 31, 2013.

Enstar said the ConocoPhillips contractwould provide supplies during that period.Non-firm supplies typically cover volumesabove average demand, such as on verycold days.

Enstar previously negotiated two supplycontracts with Marathon that provide firmgas commitments during the proposed

extension period, which would begin April 1, 2011.Enstar, the largest natural gas user in Alaska, said

its 2010 contracts were “the result of extensive nego-tiations and are the best terms the producers werewilling to offer.”

The process module for Eni’s Nikaitchuq field produc-tion facilities travels by barge off a Beaufort Sea bar-rier island, en route for Oliktok Point.

see ENI MODULES page 16

JUD

Y P

ATR

ICK

/CO

URT

ESY

EN

I

Still on hold: Statoil’s Chukchiseismic in doubt after injunction

The question of whether Statoil will be able to carry outits planned Chukchi Sea seismic surveys in 2010 still hangsin the balance, with continuing uncertainty over the scope ofa federal court injunction over activities associated with theU.S. Minerals Management Service 2008 Chukchi Sea leasesale. Cancellation of Statoil’s 2010 seismic shoot would pre-sumably delay the company’s Chukchi Sea exploration pro-gram by a year, besides upping the cost of the program as aconsequence of putting a seismic fleet on hold.

The injunction came on July 21 in response to an appealchallenging the 2008 lease sale, with Alaska District CourtJudge Ralph Beistline banning actions associated with leas-

Imperial-Exxon, BP form JV forCanadian Beaufort exploration

A major ownership shift has occurred in nascent explorationin the Canadian Beaufort Sea, with word that sister companiesImperial Oil and ExxonMobil have formed a joint venture withBP to continue work on two adjoining parcels.

News of an agreement was disclosed by Indian and NorthernAffairs Canada, which must formally approve the transfer ofoperatorship on Exploration License 449 from BP.

EL 449 was acquired two years ago by BP for a startlingwork commitment of C$1.18 billion, while EL 446 was securedby Imperial and ExxonMobil a year earlier for a pledge ofC$585 million.

Under the deal, BP will hold 50 percent of the partnership,with the balance divided equally between Imperial andExxonMobil, one of which will be operator.

Negotiations between the two sides started in 2009, predat-ing BP’s Macondo well blowout in the Gulf of Mexico that has

see BEAUFORT JV page 14

COLLEEN STARRING

see ENSTAR GSA page 15

see STATOIL page 14

see BEEF page 13

http://www.PetroleumNews.com/

contents2 PETROLEUM NEWS • WEEK OF AUGUST 8, 2010

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

FINANCE & ECONOMY

EXPLORATION & PRODUCTION

NATURAL GAS

3 Suncor puts Alaska assets up for sale

9 Linc permitting well at Point MacKenzie

11 BLM begins new NPR-A planning effort

13 Regulators reconsider Usibelli gas plan

GOVERNMENT

10 ANS production down 1.3% on maintenance

Alyeska’s second planned summer shutdown of trans-Alaska oil pipeline slows production

PIPELINES & DOWNSTREAM

7 Oooguruk production rates hit new high

Pioneer says oil production at the near shore unit is above 11,000 gross barrels per day and could gain 2,000 bpd per year

8 Quicksilver looks for gold

Financially squeezed unconventional gas player rumoredto be candidate for BC shale gas JV with India’s Reliance Industries

3 Multiple bids received in open season

TransCanada’s Tony Palmer describes initial openseason bids as from ‘major industry players and others for significant volumes

4 Alberta claims gas experience counts

Trails British Columbia in shale gas development; cites track record of regulating gas E&P; hopes it can avoid US shale debates

5 Homer to get first phase of gas line

City plans to use appropriation to build a regulatorstation and a short pipeline this year, plans to seek out additional funding

9 State, feds, pay for gas line route data

Information from $1.75 million aerial lidar survey to be available to public; study will identify potential geological hazards

6 Trouble in the pipelines

Consequences of Enbridge rupture could be far greaterthan barrels spilled; concerns build about corrosion in Canada’s aging lines

Still on hold: Statoil’s Chukchi seismic in doubt after injunction

Imperial-Exxon, BP form JV for Canadian Beaufort exploration

Alaska’s beef with BLM

State accuses feds of drilling violations, mismanagement of legacy wells

Eni modules reach site

Sealift for Nikaitchuq production facilities has arrived off Oliktok Point

Enstar gets new GSA

Contract with ConocoPhillips would provide non-firm supplies on peak days

ON THE COVER

SIDEBAR, Page 14: State requests Chukchi reconsideration

SIDEBAR, Page 10: Alyeska completes 2nd scheduled shutdown

SIDEBAR, Page 3: ANGDA has placed bid

http://www.petroak.com

By KRISTEN NELSONPetroleum News

I t was question which evoked thoughtsof a worst-case scenario: what if the

AGIA-licensed Alaska Pipeline Projectgot no bids in its initial open season?

According to the terms of the AlaskaGasline Inducement Act, theTransCanada-ExxonMobil project isrequired to continue through receipt of aFederal Energy Regulatory Commissioncertificate of convenience and necessityfor the North Slope to market gas pipelineproject even if there is no customer inter-est.

As Tony Palmer, vice president ofAlaska development for TransCanada,told the Alaska Legislature repeatedlyduring hearings on the AGIA legislation,the company’s preference in the event ofno bidders at an initial open season wouldbe to focus its time and energy on devel-oping customers, rather than proceedingto a FERC certificate after receiving nobids in an open season — or insufficientbids to back the project.

AGIA provided $500 million in reim-bursement for project costs throughFERC certification in exchange for cer-tain state “must haves,” including thecommitment to continue through FERCcertification.

Commissioner of Natural ResourcesTom Irwin told a Commonwealth Northbriefing before the bids were opened July30, that if potential shippers boycotted theopen seasons and the state didn’t keepmoving forward, then the state wouldhave no leverage. Irwin also said, howev-er, that the three major companies withgas reserves on the North Slope havespent hundreds of millions of dollarsstudying this: They are not spending thatmoney because they think it won’t work,he said.

TransCanada received the state’sAGIA license; ExxonMobil later joinedthe project, which proposes to bringNorth Slope natural gas to market eitherin the Lower 48 via a line into Canada oron a line to Valdez where another party

would build a liquefied natural gas plant.

Multiple bidsBut the worst case didn’t happen. While details aren’t known, the results

of the initial open season for the AlaskaPipeline Project, which closed July 30,were positive.

In a statement following bid opening,Palmer said that while results of the openseason are confidential:

“The Alaska Pipeline Project canreport that we have received multiple bidsfrom major industry players and othersfor significant volumes.

“We’re encouraged about the futureadvancement of the project if key condi-tions can be resolved. Although we needto further assess the results, we’re encour-aged by the bids received, the interestexpressed in our initial open season andshippers’ willingness to take the ongoingsteps needed to continue to advance theproject.”

“Our next step will be to work with ourpotential customers to resolve those con-ditions — that’s what we’ll be doing overthe next several months,” Palmer said.

Confidentiality agreementsPalmer told Petroleum News in a July

29 background briefing that he wouldn’tbe able to describe results of the open sea-son in any detail because of confidential-ity agreements between customers andthe pipeline company, agreements whichare standard in every open season acrossNorth America.

Those confidentiality agreements

PETROLEUM NEWS • WEEK OF AUGUST 8, 2010 3

FINANCE & ECONOMYSuncor puts Alaska assets up for sale

Suncor Energy is putting its Alaska leases up for sale.“That asset is off strategy and it is for sale,” Suncor spokeswoman Sneh Seetal

said.In its second quarter financial filings, the Canadian company said it “recognized a

charge of $44 million to reflect the write-down of certain land leases in the NaturalGas operating segment. These assets are in areas of Western Canada and Alaska thatthe company does not plan to pursue given its strategic business alignment.”

Suncor picked up almost 300,000 acres in the Brooks Range foothills and theNational Petroleum Reserve-Alaska when it acquired the assets of the Petro-Canada.

In the foothills, Suncor became a partner of BG and Anadarko Petroleum. In NPR-A, Suncor became a partner of FEX, a subsidiary of Talisman. In March 2010,Talisman announced plans to sell more than 1 million net acres in the NPR-A and thefoothills.

In September 2009, Suncor announced plans to divest much of its natural gasassets by the end of 2010, but the company had not reached as decision as of late May.

Suncor already divested land in the Rockies, Western Canada and Trinidad andTobago, and proposed divesting other Western Canada lands and “non-core” NorthSea assets.

Suncor has been focusing its attention on its oil sands operations, but planned tohold on to some natural gas production as “a natural price hedge against the cost ofenergy consumption” at oil sands operations, according to a May 2010 investor pres-entation.

Alaska natural gas, however, is stranded in the state until a major pipeline is built.—ERIC LIDJI


Multiple bids received in open seasonTransCanada’s Tony Palmer describes initial open season bids as from ‘major industry players and others for significant volumes’

TONY PALMER TOM IRWIN

see OPEN SEASON page 11

ANGDA has placed bidWhile TransCanada will not announce bidders in the

Alaska Pipeline Project open season until after precedentagreements are signed, one entity said it put in a bid forcapacity for in-state gas transportation requirements of theRailbelt electric utilities.

The Alaska Natural Gas Development Authority said in aJuly 30 statement that should the project go forward, it hassecured a 30 percent discount for transportation costs on theline for the Railbelt electric utilities.

“Securing this placeholder at a discounted rate for gas transportation in theAlaska Pipeline Project is aimed at providing Alaskan consumers a significantlong-term benefit,” ANGDA CEO Harold Heinze said in a statement.

He said the ANGDA board had directed him to submit a bid for a volume ofgas consistent with the in-state gas study that was done as a part of the open sea-son.

“I expect additional negotiations over the next several months will be neces-

HAROLD HEINZE

see ANGDA BID page 11

http://www.maritimehelicopters.com

http://www.nstiak.com

By GARY PARKFor Petroleum News

However much Alberta might betrailing British Columbia in the

development of its shale gas — whichcould exceed 1,000 trillion cubic feet —the province is confident it has a longenough track record of regulating gasexploration and production to handledevelopment of the resource.

Environment Minister Rob Renner,amid speculation that producers recentlyspent more than C$450 million to roundup shale exploration rights in the PeaceRiver Arch area of northwestern Alberta,said his government is hopeful it canavoid the contentious debates that areerupting in the United States over thepotential environmental impacts ofhydraulic fracturing that is an integral

part of shale produc-tion, along with theuse and contamina-tion of water sup-plies.

He said the “sig-nificant” experienceaccumulated inAlberta from con-ventional gas devel-opment gives theprovince an edge over jurisdictions thathave not had that opportunity.

But Renner concedes “we have to keepan eye on the issue, we have to ensurethat we’ve got the appropriate technologyin place and that we protect our preciousresource that is ground water.”

“We will continue to keep an eye veryclearly focused on technology (related tothe protection of ground water) as it pro-

gresses and moves into Alberta,” he toldan unconventional oil and gas forum inCalgary.

15 prospective formations identifiedThe Alberta Geological Survey has

identified about 15 prospective shale gasformations in the Western CanadaSedimentary basin, although the Albertagovernment is unwilling to get drawn intoforecasting the eventual scope of theresource until it has decided what regula-tory measures are needed for large-scalecommercial development.

The pressure on the governmentincludes regulations governing the use ofsurface water in drilling; the pumping ofwater into tight and shale gas formationsfor reservoir stimulation; the productionof water from reservoirs where it occursnaturally, but is not drinkable; and thepenetration of ground water aquifers bywells drilled for gas production.

It helps Alberta that Encana andTalisman Energy have extensive shalegas experience in British Columbia andacross the United States.

Jim Fraser, Talisman’s senior vicepresident of North American operations,said each play has different nuances in thesupply, usage and disposal of water.

He said the Pennsylvania Marcellusplay uses surface water from creeks andrivers; Eagle Ford in south Texas drillswater supply wells; and northeasternBritish Columbia takes surface water aswell as drawing water from a large lake.

But the mounting concerns over thegas industry’s impact on water haveprompted the Environmental ProtectionAgency to study the effects of fracturingon groundwater, targeting early findingsby late 2012.

Aside from the water-related issues,access to equipment and sand impose fur-ther burdens on development of the HornRiver basin in the far northern reaches ofBritish Columbia, says a report by invest-ment dealer Peters & Co.

But the analysis estimates Horn Riverproduction could reach 5 billion cubic

feet per day by 2020, assuming about 290wells are drilled annually over the nextdecade to develop about 24 trillion cubicfeet of gas resource.

At that level it would need 7.1 crewsand hydraulic horsepower of 151,200;raising the target to 400 wells wouldrequire 10.1 fracturing rig crews and403,200 in hydraulic horsepower.

Volumes of water an issueThe volumes of fresh water consumed

in fracture stimulating just one HornRiver well can be as high as 180,000cubic meters, or the equivalent of 72Olympic-sized swimming pools — levelsthat Peters & Co. said “are not sustain-able.”

In addition, water needs to be heatedduring winter, which “presents an enor-mous cost to operators,” which will like-ly accelerate the trend towards summerfracturing programs.

The study said its base-case HornRiver well, assuming 12 fracture stimula-tions per well, requires about 200 metrictons of sand per stimulation interval.

The flip side of the Alberta-BritishColumbia argument was laid out byDavid Smith, executive vice president atKeyera Facilities Income Fund, who saidplanning for British Columbia’s gas pro-cessing needs will hopefully avoid whathas happened in Alberta, where more than700 processing plants are working atabout 50 percent utilization rates.

He urged producers to take a longer-term view in the design and developmentof processing facilities as they decidewhether to proceed on their own orthrough third parties.

Smith said producers such as Encanaare “more comfortable with third-partysourcing,” while Talisman likes to takecontrol.

“The challenge for the industry is tomake sure that competition doesn’t leadto over-investment in under-utilized facil-ities,” he said. �

4 PETROLEUM NEWS • WEEK OF AUGUST 8, 2010

Kay Cashman PUBLISHER & EXECUTIVE EDITOR

Mary Mack CHIEF FINANCIAL OFFICER

Kristen Nelson EDITOR-IN-CHIEF

Clint Lasley GM & CIRCULATION DIRECTOR

Susan Crane ADVERTISING DIRECTOR

Bonnie Yonker AK / NATL ADVERTISING SPECIALIST

Heather Yates BOOKKEEPER

Shane Lasley IT CHIEF

Marti Reeve SPECIAL PUBLICATIONS DIRECTOR

Steven Merritt PRODUCTION DIRECTOR

Alan Bailey SENIOR STAFF WRITER

Wesley Loy CONTRIBUTING WRITER

Gary Park CONTRIBUTING WRITER (CANADA)

Rose Ragsdale CONTRIBUTING WRITER

Ray Tyson CONTRIBUTING WRITER

John Lasley STAFF WRITER

Allen Baker CONTRIBUTING WRITER

Sarah Hurst CONTRIBUTING WRITER

Judy Patrick Photography CONTRACT PHOTOGRAPHER

Mapmakers Alaska CARTOGRAPHY

Forrest Crane CONTRACT PHOTOGRAPHER

Tom Kearney ADVERTISING DESIGN MANAGER

Amy Spittler MARKETING CONSULTANT

Dee Cashman CIRCULATION REPRESENTATIVE

Petroleum News and its supple-ment, Petroleum Directory, are

owned by Petroleum Newspapersof Alaska LLC. The newspaper ispublished weekly. Several of theindividuals listed above work forindependent companies that con-

tract services to PetroleumNewspapers of Alaska LLC or are

freelance writers.

ADDRESSP.O. Box 231647Anchorage, AK 99523-1647

NEWS [email protected]

CIRCULATION 907.522.9469 [email protected]

ADVERTISING Susan Crane • [email protected]

Bonnie Yonker • [email protected]

FAX FOR ALL DEPARTMENTS907.522.9583

OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 15, No. 32 • Week of August 8, 2010

Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518(Please mail ALL correspondence to:

P.O. Box 231647 Anchorage, AK 99523-1647)Subscription prices in U.S. — $98.00 1 year, $176.00 2 years, $249.00 3 years

Canada — $185.95 1 year, $334.95 2 years, $473.95 3 years Overseas (sent air mail) — $220.00 1 year, $396.00 2 years, $561.00 3 years

“Periodicals postage paid at Anchorage, AK 99502-9986.”POSTMASTER: Send address changes to Petroleum News, P.O. Box 231647 Anchorage, AK 99523-1647.

www.PetroleumNews.com

CORRECTIONCalgary-based oil and gas consultant Doug Matthews was misreported in an

Aug. 1 article in Petroleum News headlined “US a friend in need.” He was refer-ring only to the hearing by Canada’s National Energy Board into offshore Arcticexploration and made no link between that hearing and the Mackenzie GasProject.


Alberta claims gas experience countsTrails British Columbia in shale gas development; cites track record of regulating gas E&P; hopes it can avoid US shale debates

ROB RENNER

Contact Gary Park through [email protected]

http://www.LFAV.com

http://www.gdiving.com


Enstar Natural Gas plans to start workon a gas pipeline to Homer later this

year.The Homer City Council recently

agreed to revise the description of the proj-ect to construct what city officials are call-ing the first phase of an eventual transmis-sion line.

The city of some 5,500 people on thesouth tip of the Kenai Peninsula currentlyuses diesel fuel and has been trying to con-vert to relatively cheaper natural gas fordecades.

This early step involves paying Enstar$525,000 to build a pressure reduction sta-tion outside Anchor Point and a shortpipeline, less than a mile, down the SterlingHighway.

That plan sets the stage for somedaycontinuing the pipeline all the way toHomer and would bring natural gas toChapman Elementary School, which cur-rently runs on diesel.

The plan also allows Anchor Point tostart switching over to natural gas muchsooner.

That gas will come from North Fork, agas field about 10 miles east of AnchorPoint, operated by Armstrong Cook Inlet. Asubsidiary of Armstrong is currently build-ing the North Fork Pipeline from the fieldto just outside the city, where it will connectto an extension of the Kenai KachemakPipeline that Enstar is currently permitting.

Construction this yearThe Legislature approved a $4.8 million

line item to build a gas pipeline to Homerearlier this year, but Gov. Sean Parnellvetoed all but $525,000 of it, saying the restcould come in a future funding cycle, afterquestions about the project had beenanswered.

Those questions came from the legisla-tive intent attached to the appropriation,requiring that gas from a pipeline to Homerbe priced equal to gas in other parts of theCook Inlet basin; that a Homer pipeline notharm other customers across the region;that state funding for the pipeline help off-set rates throughout the region; and that thecity of Homer plan a distribution system tobring as many locals as possible onto thegrid.

Elected officials in Homer, includingRep. Paul Seaton, believed those questionshad already been answered by the time theLegislature approved the funding, but theyworried the intent language might force thecity to use some money for studies, insteadof pipe.

The appropriation included $300,000for a pressure reduction system in AnchorPoint, needed to make gas from a regionalpipeline usable in distribution grids. Homerwanted to use the remaining amount onpipe, even if it meant only modest con-struction this year.

Homer City Manager Walt Wrede,though, told the city council that the stateDepartment of Commerce, Communityand Economic Development, the agencyadministering the appropriation, assuredhim the money could be used entirely forpipeline construction.

Wrede said that moving ahead with aproject located, for now, entirely outsidethe city limits of Homer would “help usleverage additional money to complete theproject.”

While the city could construct the proj-ect itself, and theoretically become a gasutility in the future, Wrede recommendedhiring Enstar to build, own and operate the

project.Wrede said the city still needs to com-

plete some contracts and draft some workscopes before it can officially pull start theproject, but on Aug. 3 Enstar spokesmanJohn Sims told Petroleum News, “Our hopewould be to get that done this constructionseason.”

Seaton wants remaining fundsSeaton told Petroleum News he planned

to go after the remaining funding for theproject, but said he wants Homer to be aprecedent for other cities looking for newenergy.

“Is the establishment to the grid and theconnection to the grid going to be solely theresponsibility of the community on the end,unless they have gas they’re producingflowing back to the whole grid? It’s a ques-tion that will come up in the future,” hesaid.

Seaton’s office has been researchinghow Enstar expanded into the Matanuska-Susitna area in the 1980s. At the time, reg-ulators spread the cost across the entireSouthcentral system.

This first stage of a gas pipeline toHomer differs from that Mat-Su extensionbecause Enstar will be constructing theproject but not paying for it, and thereforenot applying the cost to system-wide tariffs.(However, as a state-funded project, thepipeline cost is in essence being borne by amuch larger constituency: the entire popu-lation of the state.)

Seaton said he wants to make the casethat helping communities around the statesecure stable sources of energy is astatewide issue and broader than any singlecommunity. �


The Division of Oil and Gas is helping to pave the way for solutions to current Cook Inlet deliverability concerns by working with industry on processing gas storage leases and exploring new storage possibilities.

We are committed to doing our part in creating a predictable production climate for Cook Inlet gas producers.

Alaska: We’re Open For Business!Division of Oil and Gas550 West 7th Avenue, Suite 1100Anchorage, Alaska 99501-3560tel: 907-269-8800http://www.dog.dnr.state.ak.us/oil/

“It is our opinion that the Cook Inlet is a vastly underexplored province and with good science there’s a tremendous amount of gas yet to be found in the area.”

Armstrong Oil & Gas, 2009

Oil and gas producers in Alaska’s Cook Inlet enjoy one of the most favorable tax and royalty environments in the United States, with total rates at or below every other major producing state.

Cook Inlet Oil: 0% gross production tax 12.5% royalty rate

Cook Inlet Gas: 3.6% gross production tax* 12.5% royalty rate

*15 AAC 55.440 tax equals 18 cents/mcf; at $5.00/mcf effective tax rate equals 3.6%. Assumes no capital credit write-off.

I“I“ t is oi r ouou iot is our opipun ed exer xprexprexexp rlunderexplorloa trretrtreremmen on ouda tremendouou

inniin n ni thio atthat th the th Cthinion that the Cred rere oop viro irovovi evi e in anc anred province anan

s amu oamam ntou t ou f gao gaus amount of gaga

C k oo nIn t nllet is a i vCook Inlet is a vd win witthwith oith go d goo ccisnd with good scicisas eas t yeyet to t e fb ooufoas yet to be foufou

ArrmrmAArmAr

aasasva tlvas lylytlvastlytlyeie een e n thc rth eth reer ’sre’sience there’s

d u nn n thi e th arth reaarare .reund in the area.amsstrm romsstr ngtrong ron On ill O & Oi aasasG , Ga 0mstrong Oil & Gas, 202

””900090

Cook Inle

Cook Inle

Assumes nAAC 55.*15

12.5% roy3.6% groset Gas:

12.5% roya0% gross pet Oil:

o capital credit write-off.440 tax equals 18 cents/mcf;

yalty ratess production tax*alty rateproduction tax

at $5.00/mcf effective tax rat

*

te equals 3.6%.

for Cook Inlet gWe are committ

storage leases aCook Inlet delivThe Division of

Al

Assumes n

gas producers.ted to doing our part in

and exploring new storaverability concerns by wf Oil and Gas is helping

k W ’ O

o capital credit write-off.

n creating a predictable

age possibilities.working with industry o

to pave the way for sol

O F B

production climate

on processing gaslutions to current

i !

Alas

ska: We’re O

Open For Bu

http://www.dtel: 907-269-880Anchorage, Ala550 West 7th AvDivision of Oil

usiness!

og.dnr.state.ak.us/oil/00aska 99501-3560venue, Suite 1100l and Gas


Homer to get first phase of gas lineCity plans to use appropriation to build a regulator station and a short pipeline this year, plans to seek out additional funding

Contact Eric Lidji at [email protected]

http://www.dog.dnr.state.ak.us/oil

http://www.tomco.ca


BP’s Macondo well blowout in theGulf of Mexico spewed 1.9 million

barrels of crude before it was choked offon July 15. Or was it 3.3 million? The fulland final count is awaited.

Enbridge’s pipeline rupture inMichigan spilled an estimated 19,500barrels.

No contest. Right?For the public and politicians, BP’s

reputation will be sullied for decades and,fairly or not, associated forever with theDeepwater Horizon explosion, just asExxonMobil will have to wait many moreyears to shake off what the Exxon Valdezdid to its image.

What’s in store for Enbridge needstime to evolve. What does seem likely,however, is that the consequences couldbe far greater than the simple numbers.

Exclude the Macondo events and it’slikely Enbridge would have stirred a briefflurry of concern and negative publicitybefore the blog media found somethingelse to chase.

Right now, Enbridge is doing its

utmost to avoid the blunders by BP andits departing CEO Tony Hayward.

It has pulled a page from the Johnson& Johnson strategy book of 1982 whenthe drug maker set the standard for crisismanagement after seven customers diedfrom cyanide-laced Tylenol.

Daniel to MichiganIn Enbridge’s case, the boss Pat Daniel

headed to Michigan to oversee theresponse, apologized to residents for “themess we have made,” mobilized an armyof cleanup workers and promised to coverthe costs, which have been estimated byone analyst at US$40 million.

Michigan Gov. Jennifer Granholm,who initially accused Enbridge of takingan “anemic” approach to the spill, endedthe week by praising the Calgary-basedcompany for its aggressive efforts.

D’Arcy Levesque, Enbridge’s vice

president of public affairs, told the Globeand Mail: “It’s about communications,communications, communications.People have been impacted and are upsetand we need to provide factual informa-tion about what we are doing to respond.”

What might trouble Enbridge and itspipeline peers and oil and natural gasshippers even more is how governmentsand regulators respond.

Aging pipeline systemIn Canada, an aging pipeline system

poses constant worries about corrosion,creating a possible temptation to impose amuch stricter regulatory regime, from theapproval stage, through inspections andpenalties.

Daniel acknowledged that prospect bytelling reporters on July 30 that Enbridgewill work with the industry and federalregulators to introduce new technologythat would better detect flaws in pipelinesto reduce the odds of ruptures.

But he dismissed a report in theDetroit Free Press that Enbridge had beenwarned in January by the U.S.Department of Transportation’s Pipelineand Hazardous Materials SafetyAdministration that the company hadlikely violated federal regulations relatingto corrosion in Line 6B, which starts inAlberta, enters the U.S. and crosses backinto Canada.

He said the warning affected a differ-ent section of the pipeline and the matterhad been handled.

Far more troubling to Enbridge is thefallout on its heavily contested plans tobuild the Northern Gateway pipelinefrom the Alberta oil sands to the BritishColumbia coast — crossing 1,000streams and rivers in the process — fortanker shipment to Asia.

Nikki Skuce, senior energy campaign-er for ForestEthics, essentially said whatwas on a lot of minds that the Michiganspill “reinforces a lack of trust and alsothe incredible risk this pipeline poses toBritish Columbia in particular.”

Those issues are destined for an earlyairing before a Joint Review Panel,

entrusted with conducting an environ-mental assessment of the project.

There’s been no rush by Enbridge’speers and rivals to gloat over its misfor-tune.

Russ Girling, newly installed chiefexecutive officer at TransCanada, toldanalysts July 29 he had no idea how theMichigan events would affect the reviewprocess for his company’s proposed andopposed extension of its Keystonepipeline from the oil sands into the Lower48.

“I don’t know the answer to that ques-tion,” he said. “It’s a very unfortunate cir-cumstance and I’d say it’s premature tosay whether it has any impact on the per-mitting process for our pipeline system.”

Pipeline network immenseWhat Michigan has done is open the

door on a little-examined aspect ofCanada’s immense pipeline network —more than 60,000 miles and generatingexport revenues of about C$70 billion ayear.

Partly that’s because safety has beensuch a high priority.

Of the latest statistical reports, theAlberta Energy and Utilities Board hasreported a 30 percent drop in pipelinefailures in the province over the lastdecade, with the number of failures forevery 600 miles of pipeline at 2.1 in 2008compared with 3.3 in 2000, most of themin small-diameter gathering lines.

Spills in 2006 rose to 1,516 from 1,429in 2005, only 5.5 percent of them listed as“priority one” that amounts to a seriousimpact on the environment and the pub-lic.

Canada’s National Energy Board saidthe six-year average to 2006 of releasesfrom pipe bodies was 0.05 per 600 milesof line.

One source estimates that 3.5 barrelsare spilled annually from Canadianpipelines for every 1 million barrels car-ried.

In 2008 the number of spills reportedto the NEB dropped to 1,461 from 1,508


Alaska Frontier Constructors is the team to count on for your resource development project. With a proven track record that spans decades, AFC is the contractor with the right experience to take your project from exploration to production. Getting the tough jobs done safely, on time, and on budget, that’s what we do.

Ready for tomorrow. Today.

6751 S. Airpark Place Anchorage, Alaska 99502 | (907) 562-5303 | akfrontier.com

Ready for Anything

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

Trouble in the pipelinesConsequences of Enbridge rupture could be far greater than barrels spilled; concerns build about corrosion in Canada’s aging lines

The NEB’s goal of zero rupturesper year was attained in 1984,

1988 and 2003, with the annualaverage edging down over the past

20 years to 1.4 from 2.3.

see PIPELINES page 9

http://www.pndengineers.com

http://www.akfrontier.com


Pioneer Natural Resources is reportingits highest quarterly production rates

from the Oooguruk unit since bringing thenearshore North Slope unit online two sum-mers ago.

The Texas independent reported produc-ing 7,000 net barrels per day in the secondquarter, up 1,000 bpd from the first quarterand more than double what the unit pro-duced in the second quarter of 2009, butabout 1,000 bpd lower than forecasted ratesas a result of curtailments caused by a shut-down of the trans-Alaska oil pipeline in Mayand pipeline repairs at the Kuparuk Riverunit, through which Pioneer processesOooguruk oil, Scott D. Sheffield, chairmanand CEO of Pioneer, said during a July 29conference call.

Pioneer operates the unit in the waters ofHarrison Bay and holds a 70 percent work-ing interest in the field. The Italian major EniPetroleum holds the remaining interest.

Sheffield said Pioneer is currently pro-ducing more than 11,000 gross bpd fromOooguruk, and expects production toincrease by around 2,000 bpd each year, orperhaps more depending on the results ofdrilling this winter at a newer horizon at thefield.

The company expects production rates toremain up through the rest of the year, pro-jecting a 50 to 60 percent increase over2009. That forecast is down slightly fromthe 60 to 70 percent year over year increasethe company projected after the first quarter.

Companywide, Pioneer produced 113.5million barrels of oil equivalent in the quar-ter.

At least four wells this yearPioneer expects to spend $1.2 billion this

year, including $960 million for drilling. Ofthat, $120 million is budgeted for Alaska,where the company currently runs one rig.

That makes the North Slope the secondlargest expense area for Pioneer, after itsassets in the Permian basin. So far this year,Pioneer has spent nearly $15 million inexploration expenses and more than $44million in development expenses on itsproperties in Alaska.

Pioneer plans to spend some $580 mil-lion on its large Spraberry play in WestTexas. The company is also budgeting $100million on the Eagle Ford Shale play insouth Texas, $65 million on its properties in

Tunisia and $50 million for the BarnettShale.

During the second quarter, Pioneer com-pleted a horizontal water injector and starteda dual lateral horizontal production well,both into the Nuiqsut horizon at Oooguruk.The injector well is currently producingabout 600 bpd before Pioneer begins waterinjections.

In the second half of the year, Pioneerplans to drill four more Oooguruk wells: twointo the deeper and larger Nuiqsut horizon,one into the middle Kuparuk horizon andthe last into the Moraine horizon, a new andshallower target announced earlier this year.

Sheffield said Moraine testing flow rateshave been steady at 600 bpd, with nodecline.

“And so obviously we’re going to dosome more drilling this coming winter,” hesaid.

One of the Nuiqsut wells will test thedual lateral is expected to come online thissummer.

Flow test at CosmoAt Cosmopolitan, an oil prospect off the

coast of the southern Kenai Peninsula,Pioneer is planning an extended flow test ofthe Hansen 1A-L1 sidetrack well for the sec-ond half of the year. Pioneer may drill anoth-er appraisal well during 2011, the companysaid in financial filings. Pioneer drilled theHansen 1A-L1 well in 2007, repaired wellcasing during a workover in late 2009 andfracture stimulated the well earlier this year.

In the first half of the year, Pioneer drilled193 wells across all its properties and plansto drill 440 wells altogether by the end of theyear, according to Tim Dove, president andchief operating officer of Pioneer. The com-pany is running 20 rigs, which it plans toramp up to 30 by the end of the year in orderto hit its target of drilling 700 wells nextyear.

Pioneer reported earning nearly $14 mil-lion in Alaska Petroleum Production Taxcredits in the quarter, down from more than$87 million collected in the second quar-ter of 2009. �



Oooguruk productionrates hit new highPioneer says oil production at the near shore unit is above11,000 gross barrels per day and could gain 2,000 bpd per year

“And so obviously we’re going todo some more drilling this coming

winter.” —Scott D. Sheffield, chairmanand CEO of Pioneer


PIO

NEE

R N

ATU

RA

L R

ESO

UR

CES

http://www.alutiiq.com

http://www.nanaworleyparsons.com


Industrial Strength Expertise.

A n c h o r a g e / P r u d h o e B a y / H o u s t o n1 8 7 7 4 1 1 1 4 8 4

w w w . G C I - I n d u s t r i a l T e l e c o m . c o m

GCI Industrial Telecom provides innovative solutions to the most complex communication issues facing global clientele. We deliver reputable expertise and safely operate under the most severe working conditions in the world, all at a competitive price.

GCI-your best choice for full life cycle, expert, proven, industrial communications.

INDUSTRIAL TELECOM

� F I N A N C E & E C O N O M Y

Quicksilver looks for goldFinancially squeezed unconventional gas player rumored to be candidate for BC shale gas JV with India’s Reliance Industries


Quicksilver Resources, one of theleading edge unconventional gas

players in North America, is seizing thespotlight in northern British Columbia,with speculation that it is exploring a pos-sible joint shale gas venture with India’sReliance Industries and its own disclosureof an oil strike in its B.C. acreage.

Without commenting directly on theReliance reports initiated by an Indiannewspaper, a Quicksilver spokesman saidhis company expects to embark on “sometype of transaction” to reduce its debt loadin 2010.

He said that would be most likely toinvolve Horn River, where Quicksilver hasa 100 percent interest in 20 licenses cover-ing 130,000 acres, where it bookedreserves of 250 billion cubic feet of gasequivalent at the end of 2009 and has indi-cated a gas resource potential of 5 trillion to10 trillion cubic feet.

Reliance, India’s largest private compa-ny, has long been rumored as the next

major foreign entry into Canada’s oil andgas sector, with the oil sands identified asthe likeliest target.

However, the company has shown moreimmediate interest in shale gas, investing$1.7 billion in April for a 40 percent stakein Pittsburgh-based Atlas for 120,000 netacres in Pennsylvania’s Marcellus Shale.

On the heels of that deal, it added anoth-er 42,000 acres in the same region for $192million and in late June established a com-bined $1.35 billion joint venture withPioneer and its partner Newpek, taking 45percent in about 212,000 net acres in theEagle Ford play in southern Texas.

Quicksilver had previously entered ajoint-venture with Italy’s Eni, which paid$280 million for a 27.5 percent share of theBarnett Shale properties.

JVs key in BC playsJoint ventures have become a key strat-

egy in the Horn River and Montney playsof British Columbia.

Korea Gas has committed to spend$1.1 billion through a partnership withEncana, while signing a memorandum ofunderstanding to take 40 percent of theLNG volumes from the proposed KitimatLNG project along with an option tobecome an equity owner in the export ter-minal.

Encana and China National PetroleumCorp. are also exploring a possible jointventure to develop B.C. gas.

Quicksilver is currently producing 7million cubic feet per day from two B.C.wells and expects to complete another twolater this year.

Analysts have set the economicbreakeven threshold for Horn River at$5.20 per million British thermal units,compared with $3.50 in Marcellus,reflecting the lack of infrastructure in B.C.and believe a joint venture with Reliancewould be worth about $500 million.

Word of a possible deal pumped freshlife into Quicksilver shares raising themfrom the $11-$12 range to $13, wherethey have remained for the past twoweeks, still far short of their all-time peakof $40 in 2008.

As it grapples to bring its debt undercontrol, Quicksilver has trimmed capitalspending and production over the past twoyears, conserving its resources during thegas price slump.

Although some analysts have ruled out

a complete takeover bid for Quicksilver,Subash Chandra, with Jefferies & Co.,said the bruising the company has takensuggests it could be bought for “not allthat much.”

Horn River oil strikeHowever, the company has delivered a

surprise in the last month by claiming alight oil strike in the Horn River basin,which company Chairman Toby Dardensaid has shown “significant mobile oil sat-uration in the rock, which means it canmove and that’s important.”

He is now hoping tests later this yearwill “encourage us to go forward withsome serious stratigraphic testing of theplay.”

Darden said a horizontal leg will bedrilled from an existing gas well to proveup the oil potential of the Bakken andExshaw formations, which are at abouthalf of the 10,000-foot depths of the gasdeposits.

He said it’s possible oil in commercialquantities could “help carry the develop-ment economics during times of low gasprices.”

Darden rated Horn River as a “world-class basin. … It is the best resource rockwe have seen after studying all of thebasins available in North America.”

“Pound for pound, we are the mostweighted toward the Horn River of anypublic company in our space and aroundus.” �

“Pound for pound, we are the mostweighted toward the Horn River ofany public company in our space

and around us.” —Toby Darden,chairman, Quicksilver Resources


http://www.pdstech.com

http://www.GCI-IndustrialTelecom.com

http://www.hawkpros.com

in 2007, with more than 75 percent at lowvolumes that were contained on lease.

The federal agency, which regulates9,000 miles of pipeline, has constantlypressured the industry to step up the“detectability and accuracy” of in-lineinspection tools used to scan the inside ofpipelines and recommended improve-ments in the selection of coatings for new

and rehabilitated pipelines.The NEB’s goal of zero ruptures per

year was attained in 1984, 1988 and 2003,with the annual average edging down overthe past 20 years to 1.4 from 2.3.

Regardless of how solid this recordappears, there’s an expectation that thepressures on pipeline companies willintensify as the public spotlight on allaspects of the industry intensifies. �


continued from page 6

PIPELINES


EXPLORATION & PRODUCTIONLinc permitting well at Point MacKenzie

Linc Energy is permitting a natural gas exploration well near Point MacKenzie.The Australian exploration company wants to drill the LEA No. 1 well on the north

banks of the Knik Arm of Cook Inlet. The vertical well would be on lease ADL390588.

Linc is asking the Alaska Oil and Gas Conservation Commission for an exemptionto the rule requiring drilling and testing of a well to be at least 1,500 feet from a prop-erty line. Linc acquired the Point MacKenzie acreage earlier this year from SanFrancisco-based independent GeoPetro. Although GeoPetro didn’t drill in Alaska, thecompany built a drill pad and access road to a proposed Point MacKenzie well calledFrontier Spirit No. 1 that would have targeted conventional gas in the middle andlower Tyonek Formations.

Linc previously said it hoped to drill by September.The company is also interested in unconventional gas supplies in the Cook Inlet by

extracting synthesis gas from deep coal deposits, or Underground Coal Gasification.—ERIC LIDJI


State, feds, pay for gas line route dataInformation from $1.75 million aerial lidar survey to be availableto public; study will identify potential geological hazards

PETROLEUM NEWS

The State of Alaska and the federal gov-ernment are funding a project to gath-

er detailed aerial laser-imaging data for pro-posed gas pipeline routes, with results to bemade available to the public.

Tom Irwin, commissioner of the AlaskaDepartment of Natural Resources, said theAGIA coordinator’s office would providemost of the funding for the project, $1.5million of an estimated $1.75 million. Thefederal coordinator’s office for the Alaskanatural gas pipeline is contributing$250,000.

Irwin said “data obtained from the sur-vey will be released to the public.”

“The state needs the data, federal agen-cies and the public need the detailed infor-mation, so it just makes sense to chip in andhelp the state pay for the work so that every-one can share and save money,” said LarryPersily, federal coordinator for Alaska natu-ral gas transportation projects.

Rod Combellick, deputy director ofDNR’s Division of Geological andGeophysical Surveys, said the survey willuse lidar — light detection and ranging —along with global positioning system andinertial navigation technology to obtain pre-cise locations and elevations of the ground,vegetation and above-ground features. Thedivision issued a request for proposals July26 and will oversee the study.

Alaska Gasline Inducement ActCoordinator Mark Myers said the “surveywill significantly improve our geotechnicalunderstanding of the route for an Alaska gaspipeline or other existing or proposed

pipelines from the North Slope to either theCanadian border or Valdez.” He said thatmaking the survey results public will enableAlaskans to be better informed during theregulatory and permitting phases of anAlaska gas pipeline project.

Combellick said lidar is useful in identi-fying “potentially active faults and otherland structures and potential hazards, espe-cially in areas of dense vegetation.” He saidthe bare-earth view “of undetected or poten-tial geological hazards” helps minimize thechance that those hazards could jeopardizea future gas pipeline or other facilities. Inaddition to identifying active faults andlandslides, the data will be useful for “locat-ing potential future of construction materi-als and planning other future developmentthat may occur along these corridors,”Combellick said.

The state request for data collection cov-ers 2,440 square miles, including the pro-posed natural gas pipeline route to theCanadian border along with the proposedpipeline route from Delta Junction toValdez. Aerial work will cover a corridorapproximately one mile wide, with widerzones of laser imaging at active faults andother areas of potential hazards. Existingprimary oil pipeline support roads and adja-cent highways will also be included, theoffice of the federal coordinator said.

DNR said data from the survey will alsobe useful for planning and future develop-ments in the corridors, including mappingland cover, vegetation, wetlands drainagepatterns, environmental assessments andfor locating potential construction materi-al sources. �

http://www.dowlandbach.com

http://www.jackovich.com

By KRISTEN NELSONPetroleum News

A laska North Slope oil productionheld almost level between June and

July, dropping just 1.25 percent, from547,212 barrels per day in June to540,368 bpd in July, driven primarily bya scheduled maintenance shutdown of thetrans-Alaska oil pipeline at the end ofJuly.

Production volumes cited are from theAlaska Department of Revenue.

While production from all North Slopefields dropped at the end of the monthwhen production was prorated forAlyeska Pipeline Service Co.’s secondscheduled maintenance of the summer,shutdowns for maintenance at the BPExploration (Alaska)-operated Lisburneand Northstar fields were more extensive.

North Slope field maintenance is rou-tinely scheduled around the summermaintenance shutdowns of the pipeline,but Lisburne went down for maintenancein early June, before the first Alyeskaplanned shutdown of the summer, andproduction didn’t come back at the fielduntil July 18. Northstar went offline July25 prior to the second pipeline shutdownand hadn’t come back online when thisissue went to press Aug. 5.

BP spokesman Steve Rinehart toldPetroleum News in an Aug. 4 e-mail thatas much work as possible is scheduledaround trans-Alaska oil pipeline shut-

downs to minimize impacts on produc-tion.

The situation at Northstar alsoinvolves moving the rig off the island,Rinehart said.

“To move the rig safely, workingaround pipes and other equipment, theyneeded to shut down the plant. Knowingthat, they took advantage of the opportu-nity and are doing some turnaround main-tenance,” Rinehart said.

He said he did not have an estimate forproduction to restart at Northstar.

In its latest Northstar plan of develop-ment, dated June 23, BP told regulatorsthat it had completed an additional pro-

duction well under the previous develop-ment plan for a current total of 21 pro-ducers, six injectors and two waste dis-posal wells. “Drilling activity was com-pleted in May 2009,” the company said.(The rig, Nabors 33-E, has been stackedout at Northstar.)

The company said it would “continueto appraise other acreage and formations”within the Northstar unit, integratinginformation from recent developmentwells. The most recent production infor-mation from the Alaska Oil and GasConservation Commission, for May,shows 17 producing completions atNorthstar.

Increased production at some fieldsThe July-over-June percentage

increase at Lisburne was the largest ofany field, 70 percent, but was based onextensive downtime for maintenance.The field averaged only 3,770 barrels perday in June after going down for plannedmaintenance early in the month. While ithad only partial-month production inJuly, it produced for more days than ithad in June, averaging 6,412 bpd, hencethe large percentage increase. In May,prior to the maintenance shutdown, thefield averaged 27,677 bpd. Lisburne pro-duction includes Point McIntyre andNiakuk.

BP’s Milne Point field averaged26,340 bpd in July, up 16 percent from aJune average of 22,689. The field was atzero or reduced production for severaldays in June for scheduled maintenanceat the time of the June maintenance shut-

down of the trans-Alaska pipeline. The other field which had increased

month-over-month production was theConocoPhillips Alaska-operated Alpinefield, which averaged 90,552 bpd in July,up 10.8 percent from a June average of81,732 bpd. Alpine had a 7.2 percentMay-to-June production drop; the fieldwas down for several days around theJune maintenance shutdown of the trans-Alaska oil pipeline. Alpine includes pro-duction from three satellites — Fiord,Nanuq and Qannik.

Northstar down 22 percentThe largest June-to-July production

drop was at the BP-operated Northstarfield, which averaged 13,635 bpd in July,down 21.8 percent from a June averageof 17,426 bpd.

The BP-operated Prudhoe Bay fieldaveraged 252,809 bpd in July, down 6.6percent from a June average of 270,696bpd. During July Prudhoe productionranged from a low of 100,541 barrels onJuly 31, when production was proratedfor the scheduled pipeline shutdown, to ahigh of 285,705 barrels on July 18.Prudhoe includes satellite productionfrom Aurora, Borealis, Midnight Sun,Orion and Polaris.

Production from the BP-operatedEndicott field averaged 13,399 bpd inJuly, down 1 percent from a June averageof 13,542 bpd.

The ConocoPhillips-operatedKuparuk River field averaged 137,221bpd in July, down 0.1 percent from aJune average of 137,357 bpd. Kuparukincludes production from Tabasco, Tarn,Meltwater and West Sak, and from thePioneer Natural Resources Alaska-oper-ated Oooguruk field. The most recentfigures available for Oooguruk areAOGCC numbers for May, which showan average of almost 8,500 bpd.

The temperature at Pump Station 1 onthe North Slope averaged 60.2 degreesFahrenheit in July, compared to 40.2 F inJuly.

Cook Inlet production averaged10,042 bpd in July, up 9.6 percent from aJune average of 9,159 bpd.

ANS crude oil production peaked in1988 at 2.1 million bpd; Cook Inlet crudeoil production peaked in 1970 at morethan 227,000 bpd. �


Anchorage Honolulu Los Angeles

PPEE

RRFFOO

RR

MMAANNCCEE UUNNDDEERR PPRREESS

SSUU

RREE

• Commercial Diving• Marine Construction Services• Platform Installation, Maintenance and Repair• Pipeline Installation, Maintenance and Repair• Underwater Certified Welding• NDT Services• Salvage Operations• Vessel Support and Operations

• Environmental Services• Oil-Spill Response, Containment and Clean-Up• Hazardous Wastes and Contaminated Site Clean-

Up and Remediation• Petroleum Vessel Services, e.g. Fuel Transfer• Bulk Fuel Oil Facility and Storage Tank

Maintenance, Management, and Operations

American MarineServices Group

6000 A Street, Anchorage, AK 99518

907-562-5420www.amarinecorp.com • www.penco.org

[email protected]


ANS production down 1.3% on maintenanceAlyeska’s second planned summer shutdown of trans-Alaska oil pipeline slows production; BP moving Nabors E-33 rig off Northstar

Alyeska completes 2nd scheduled shutdownAlyeska Pipeline Service Co. has completed the summer’s second scheduled

maintenance shutdown of the trans-Alaska oil pipeline. The shutdown, which began July 31, ended Aug. 1 at about 1:35 p.m., the com-

pany said in an Aug. 2 statement. Major work completed during the shutdown included replacement of a 36-inch

valve at Pump Station 9 that is used for weekly pig passage; replacement of thegas supply lines to the Pump Station 3 and Pump Station 4 turbine generators; andreplacement of the six-inch bypass piping on a check valve near Pump Station 1

Numerous other work tasks were completed at the pump stations and at theValdez Marine Terminal.

Alyeska said it conducts line-wide shutdowns annually to allow maintenancecrews time to work on projects simultaneously along the pipeline and at theValdez Marine Terminal. Alyeska’s shutdowns typically coincide with producers’routine maintenance on equipment and facilities on the North Slope, the compa-ny said.

—PETROLEUM NEWS

Contact Kristen Nelson at [email protected]

http://www.amarinecorp.com

http://www.chiulista.com

“exist because the gas business is so com-petitive,” Palmer said. Gas from Alaskawill compete with gas supplies cominginto North American or international mar-kets.

Then there is the competitive pipelineproject (the BP-ConocoPhillips Denaliproject), with an open season that continuesfor more than two months beyond theAlaska Pipeline Project, “and we of coursedon’t want to disadvantage our project rel-ative to that competitor.”

Palmer said the confidentiality agree-ments are also necessary because potentialshippers on the line “compete bothupstream and downstream of the pipeline.The customers compete upstream for cur-rent production, but they also competeupstream for future land access for futureproduction and they … don’t want to signalto their competitors what land they maywish to acquire until they’ve got a contrac-tual arrangement with the pipeline.”

Potential shippers also compete down-stream “in every market, be it internationalor domestic.”

That’s the rationale behind the confiden-tiality agreements, Palmer said, adding thatin any other open season there would be nostatement until precedent agreements aresigned.

Palmer said the goal is to have thoseagreements signed by the year’s end.

If conditions are simpler, it may takeless time, he said.

On the other hand, “If we get manycomplex conditions we may not be able toachieve it in 100 business days,” whichwould extend beyond the end of the yearwhen precedent agreements could besigned, Palmer said.

Once precedent agreements are signed,he said, FERC requires that within 10 daysthe pipeline “reveal the names of the cus-tomers, their volumes and the term of theiragreement — the term being the date that itcommences and the date that it terminates.”

Precedent agreements must be submit-ted to FERC within 20 days of signing, butother than the names, volumes and terms,

the agreements remain confidential, hesaid.

Sophisticated playersPalmer said in his pre-opening briefing

that the Alaska Pipeline Project has “whatwe think are the most sophisticated groupof players as potential customers on thisproject that we could have.”

Those potential customers are active “inthe global LNG market” and “in every sup-ply region and market in North America.”

Palmer said prior to bid opening thatwhatever those customers decide to do, anysignal they provide in the open season willindicate whether they view the LNG marketor the Alberta market to North America assuperior, or whether “they want the projectto advance by committing gas at this stage.”

In addition to negotiating terms of bids,Palmer said the project needs regulatoryapprovals and financing.

“All three of those items are required tomake a project advance to the constructionphase,” he said.

The project schedule calls for submittalof a FERC application in the fall of 2014.

“We’ve targeted project sanction for the2014 timeframe and in order to make that asuccess and build the pipeline we musthave our customers; we must have our reg-ulatory approval; and we must have ourfinancing. That’s standard for any pipelineproject. This one is no different,” Palmersaid.

The schedule for having the line in serv-ice is 2020. �


Safer. Smarter.

Our CDR2-AC rig reflects the latest innovations in Arctic drilling to provide our customers with incident free performance and operational and technical excellence.

CDR2-AC is the first Arctic rig designed and built by Nabors specifically for Coil Tubing Drilling operations. The rig was built to optimize CTD managed pressure drilling to provide precise control

of wellbore pressures for improved safety, decreased costs, and increased wellbore lengths.

Combining safety and environmental excellence with greater efficiency means CDR2-AC can deliver the high value results customers have come to expect from Alaska’s premier drilling contractor.

Learn more about Nabors’ new drilling technologies at Nabors.com.

nabors.com

Better.

GOVERNMENTBLM begins newNPR-A planningeffort

The Bureau of Land Managementsaid July 28 that it will begin prepara-tion of an integrated activity plan andenvironmental impact statement for theNational Petroleum Reserve-Alaska.

This is the first time a plan has beendone for the entire NPR-A, BLMAlaska spokeswoman Ruth McCoardtold Petroleum News July 29.

“We need to update our plans andwe need to establish the planning guid-ance for the large unplanned southernportion” of NPR-A, McCoard said.The new plan, which has been in theworks for some time, will give BLMthe opportunity to have consistentmanagement for the entire NPR-A, shesaid.

BLM said the new plan will incor-porate the most current informationand lay out management goals, objec-tives and actions that would be consis-tent across the entire NPR-A. The planwill also take into account emergingissues such as climate change and therecent listing of polar bears as a threat-ened and endangered species, theagency said.

The public scoping process beganJuly 28; BLM said it would last at least60 days, with the final ending date tobe posted on the BLM website.

Public scoping meetings will beheld at Anaktuvuk Pass, Anchorage,Atqasuk, Barrow, Fairbanks, Nuiqsutand Wainwright.

—PETROLEUM NEWS


OPEN SEASON

sary as we see how the APP projectunfolds,” he said.

Heinze also said the board had direct-ed that he submit a bid for the Denaliline; that open season closes Oct. 4, andhe said, “Details of the ANGDA capaci-ty bid will not be released until after thatdate, to assure that the maximum benefitto Alaskan consumers is maintained thruthis competitive commercial process.”

Bid authorized in JuneThe ANGDA board authorized

Heinze to submit the bids at a June 23meeting. Heinze told the board that as far

as he knew, ANGDA “may be the onlyones from the state’s point of view hav-ing done the work to participate” in theopen season. He said that by participat-ing in the FERC-sponsored open season,ANGDA can lock up the ability to takegas off in-state.

Heinze said at the June 23 meetingthat ANGDA didn’t yet have a source ofgas, although there have been goodactive discussions with three suppliers.He said he wouldn’t submit a bit withoutsome encouragement that ANGDA had agas source, but also said he had a gutfeeling that somebody was going to beinterested in being the in-state gas sup-plier.

—KRISTEN NELSON


ANGDA BID

Contact Kristen Nelson at [email protected]

http://www.nabors.com


Oil Patch Bits

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

ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS

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

AAcuren USA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15AECOM EnvironmentAir LiquideAlaska Air CargoAlaska Analytical LaboratoryAlaska AnvilAlaska CoverallAlaska Division of Oil and Gas . . . . . . . . . . . . . . . . . . . . . . .5Alaska DreamsAlaska Frontier Constructors . . . . . . . . . . . . . . . . . . . . . . . . .6Alaska Interstate Construction (AIC)Alaska Marine Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Alaska Railroad Corp.Alaska Rubber & Supply Alaska Sales & ServiceAlaska Steel Co.Alaska TelecomAlaska Tent & TarpAlaska TextilesAlaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Alaskan Energy Resources Inc.Alliance, TheAlutiiq Oilfield Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Amercable Inc.American Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Arctic ControlsArctic FoundationsArctic Slope Telephone Assoc. Co-op.Arctic Wire Rope & SupplyASRC Energy ServicesAvalon Development

B-FBadger ProductionsBald Mountain Air ServiceBrooks Range SupplyBuilders Choice Inc.Calista Corp.Canadian Mat Systems (Alaska)Canrig Drilling TechnologiesCarlile Transportation ServicesCGGVeritas U.S. LandCH2M HILLChiulista Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10ColvilleConocoPhillips AlaskaConstruction Machinery IndustrialCrowley AlaskaCruz ConstructionDelta LeasingDelta P Pump and EquipmentDenali IndustrialDepartment of Labor & Workforce DevelopmentDowland-Bach Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Doyon Drilling

Doyon LTDDoyon Universal ServicesEEIS Consulting EngineersEgli Air HaulEngineered Fire and SafetyEra AlaskaERA HelicoptersExxonMobilFairweather LLCFlowline AlaskaFluorFriends of Pets

G-MGarness Engineering GroupGBR EquipmentGCI Industrial Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Geokinetics, formerly PGS OnshoreGES Inc.Global Land ServicesGlobal Offshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Guess & Rudd, PCHawk Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Ice ServicesInspirations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Jackovich Industrial & Construction Supply . . . . . . . . . . . . .9Judy Patrick PhotographyKenai AviationKenworth AlaskaKuukpik Arctic ServicesKuukpik - LCMFLaBodegaLast Frontier Air Ventures . . . . . . . . . . . . . . . . . . . . . . . . . . .4Lister IndustriesLounsbury & AssociatesLynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Mapmakers of AlaskaMAPPA TestlabMaritime Helicopters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Marketing SolutionsMayflower CateringM-I SwacoMRO Sales

N-PNabors Alaska Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11NalcoNANA WorleyParsons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7NASCO Industries Inc.Natco CanadaNature Conservancy, The

NEI Fluid TechnologyNMS Employee LeasingNordic CalistaNorth Slope Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Northern Air CargoNorthland Wood ProductsNorthrim BankNorthwest Technical Services . . . . . . . . . . . . . . . . . . . . . . . .8Oil & Gas SupplyOilfield ImprovementsOpti Staffing GroupPacWest Drilling SupplyPDC Harris GroupPeak Civil TechnologiesPeak Oilfield Service Co.Penco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Petroleum Equipment & ServicesPetrotechnical Resources of Alaska . . . . . . . . . . . . . . . . . . . .2PND Engineers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Polar SupplyPrice Gregory International

Q-ZQUADCORain for RentSafety OneSalt + Light CreativeSchlumbergerSeekins FordSTEELFABStoel Rives3M AlaskaTA StructuresTaiga VenturesThe Local PagesTire Distribution Systems (TDS)TOMCO Group of Companies . . . . . . . . . . . . . . . . . . . . . . . . .5Total Safety U.S. Inc.Totem Ocean Trailer ExpressTotem Equipment & SupplyTTT EnvironmentalTubular Solutions AlaskaUdelhoven Oilfield Systems ServicesUmiaqUnique MachineUnivar USA Universal WeldingURS AlaskaUsibelliWest-Mark Service CenterWeston SolutionsWestern TowboatXTO EnergyYenney & Associates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9

Veerman in Who’s Who for the oil and gas industryLouis R. Veerman of Guess & Rudd was recently listed in the

International Who’s Who of Business Lawyers for oil and gas.Veerman, whose main area of practice is pipeline and relatedissues, has been practicing law in Alaska since 1976.

Other recognitions he has received include, AV rating fromMartindale-Hubbell; The Best Lawyers in America for energy law;Chambers USA — America’s Leading Lawyers For Business, envi-ronment, natural resources, and regulated industries; and SuperLawyers for energy and natural resources.

Since 1996 Who’s Who Legal has identified the foremost legalpractitioners in multiple areas of business law. The site featuresmore than 10,000 of the world’s leading private practice lawyersfrom more than 100 national jurisdictions. Who’s Who Legal prides itself on its integrity,and says on its website that it is impossible to buy entry into the publication.

With law offices in Anchorage and Fairbanks, Guess & Rudd’s extensive experience innatural resources law includes multiparty trials, complicated administrative and regulatoryhearings and disputes, and lawsuits involving pollution and environmental issues. For moreinformation visit www.guessrudd.com.

Lounsbury offers bear guard and hazing servicesLounsbury & Assoc. said July 29 that it has expanded

its offerings to include professional bear guard and haz-ing services. Lounsbury has an experienced team of indi-viduals with specialized training in U.S. Fish & Wildlifecertified bear guard and hazing techniques. Team leaderA.J. Rookus is also certified by the federal agency toprovide individual training for bear hazing. In addition-al, all members of the team have extensive training forwildlife behavior, habitat, hazing techniques, firearms,safety and more. “Team members have had extensiveformal and informal training regarding what to do whenencountering the predators of the north — brown bearsand polar bears,” said Rookus. “Brown bears are gener-ally a lot easier to deal with than polar bears. Polar bears are the top of the food chain sowe treat them with an extra-special respect and wariness.” As a part of his U.S. Fish &Wildlife training, Rookus also learned to depart the area after use of bear spray because itis likely to draw curious bears to the area investigating the new smell. For more informa-tion please contact Ken Ayers at 907-272-5451 or by e-mail at [email protected].

LOUIS VEERMAN

CO

URT

ESY

LO

UN

SBU

RY



Regulators reconsider Usibelli gas planTHE ASSOCIATED PRESS

The Department of Natural Resources is reviewing itsdecision to grant an exploration license for coalbed

methane near Healy. The state gave Usibelli Coal Mine a license June 28. But

Alaska Division of Oil and Gas Director Kevin Banks saidseveral people raised concerns and the agency decided toaddress those issues.

One concern is over designated wildlife habitat in thearea.

Usibelli wants to explore for natural gas in roughly200,000 acres along the Parks Highway between Healy andNenana. The area has a high potential for methane or othershallow gas.

DNR Commissioner Tom Irwin will have the chance toreject the license, accept it or modify its terms, the

Fairbanks Daily News-Miner reported. The state DNR issued a preliminary finding for a pro-

posed exploration license in 2005, but other priorities at theagency stalled the process for years.

“I think the parties involved would prefer we get mov-ing,” Banks said. “It’s been an embarrassingly long time asit is.”

Some people who raised concerns requested larger set-backs next to creeks and watersheds, greater rights for resi-dential subdivisions and a longer comment period.

The Denali Citizens Council, an environmental groupbased in Healy, asked that areas already designated by thestate for public recreation and wildlife habitat in theStampede townships be set aside.

The group’s president, Nancy Bale, said that wouldrestrict about one-sixth of the licensing area.

Steve Denton, Usibelli’s vice president for business

development, said the company is turning its attention tothe area. “We need to take it off the shelf now and take afresh look at it,” Denton said.

Coalbed methane exploration has been a controversialissue in the past.

In 2003, shallow gas extraction became contentious inthe Matanuska and Susitna valleys in Southcentral Alaskawhen a Colorado company was awarded leases in thearea. The licenses allowed exploration on private land,since the state still owns mineral rights beneath that land.Some residents said it conflicted with their propertyrights.

Denton said Usibelli is aware that similar issues couldemerge in the Healy area.

“I think it’s the same concerns, basically, and the samekind of constituency — people who want to buy 5 acres,but want to control 5,000,” he said. �

documents about the Wainwright conflictafter filing a public records request with theAOGCC. The documents show the builduptoward the notice of violation, and includethe BLM’s response.

On June 10, AOGCC senior petroleumengineer Guy Schwartz sent an e-mail toCathy Foerster, an engineer and one of thethree commissioners, and Jim Regg, a petro-leum engineer and commission investigator.

Schwartz wrote that “according to” ArtClark, a USGS project leader on theWainwright drilling, a rig safety devicecalled a diverter wasn’t run on most of thewells, as the AOGCC had required.

A diverter, which sits atop the well, isdesigned to direct any unexpected release ofdangerous hydrocarbons safely away fromthe rig work area. Diverters, like blowoutpreventers, are a last line of defense fordrillers to control an unruly well.

Schwartz also wrote that “wells havebeen left open ended to the world over thewinter … the PVC pipe is basically stickingout of the ground with no covering at all.”

He concluded his e-mail: “A can of verybad worms for sure.”

In the June 22 notice of violation,Seamount said it appeared seven wells weredrilled without the required diverter, that is,“without any secondary well control equip-ment.”

The notice further said an AOGCCinspector, on June 10, saw two Wainwrightwellbores that were “open to the atmospherewith no mechanical or cement plugs withinthe wells” to secure them pending abandon-ment. A project representative, however,said the wells had ice plugs in them about600 feet down.

The inspector also noted a lack of mark-ers to identify specific wells, and copies ofcertain permits weren’t on-site in violationof state regulations.

The notice gave BLM two weeks to pro-vide the commission with “an explanation ofthe violations.” It didn’t specify any poten-tial fine or other penalty.

‘Egregious mischaracterization’On June 25, Greg Noble, energy section

chief in the BLM Alaska office, sent an e-mail to Seamount and Foerster about thenotice of violation.

“It is apparent from the letter that theCommission is not in possession of all thefacts regarding the operation atWainwright,” Noble wrote. He noted theUSGS, not the BLM, was the well operator,adding “your accusation that BLM has acavalier approach to well safety and regula-tory compliance is an egregious mischarac-terization of both the BLM’s and USGS’sconduct of operations and comes as yetanother surprising blindside.”

Noble proposed a meeting includinghimself, Clark of the USGS, and the twocommissioners.

Foerster replied in an e-mail: “Greg,Since we have issued a notice of violationand are considering enforcement action, theonly way that any of the commissioners canmeet with you is if we first publicly noticethe meeting. If that’s agreeable, let me knowand I’ll ask … to docket something. Pleasenote that we must give at least 30 days noticeof any public meeting. Cathy.”

On July 1, Clark e-mailed Schwartz, theAOGCC petroleum engineer: “For yourinformation: I mispoke when I told you wedidn’t drill the various Wainwright wellswith the diverter head installed — we did. Iforgot that we routinely used it as the mud

diverter on the wells, therefore it was alwaysinstalled. My mistake.”

Schwartz replied: “Art, Interesting … Iwas looking in the well records to try andtrack down the specs on the Diverter youguys used. Was it rented or does USGS ownthe diverter?? If you rented it could you for-ward me the rental company where you gotit. I can get the info from them hopefully.Thanks.”

‘A misunderstanding’On July 7, Julia Dougan, the BLM’s act-

ing state director for Alaska, sent a two-pagereply letter to Seamount answering thenotice of violation.

The well operator, she said, stated thewells were drilled in compliance with theAOGCC’s June 6, 2008, conservation orderNo. 604, which said in the findings section:“USGS plans to use a rotating drill head,which seals around the drill stem and directsthe annular mudflow to the pits. If gas isencountered, the rotating drill head functionsas a diverter.”

Dougan wrote that “the diverter head wasused for each well in question,” and added:“The operator’s discussions with AOGCCinspectors concerning the necessity of adiverter for plugging and abandonmentoperations at these wells may have created amisunderstanding.”

As for the allegation that two wellboreswere open to the atmosphere without adownhole plug, Dougan wrote: “This is cor-rect as these wells were being used as mon-itoring wells.” She said four other wells alsowere left open.

“The BLM plans to plug these wells thisAugust and will fully comply” withAOGCC requirements, Dougan said.

Regarding well markers, she wrote: “Asverified by the operator each protective well

enclosure has the USGS designation numberclearly welded to its lid.” But the informa-tion on the existing markers doesn’t conformto AOGCC regulations, Dougan said.

The BLM “will insure that their operatorconforms to the requirements … and correctmarkers will be put in place during pluggingoperations,” she wrote.

Dougan also conceded that copies of per-mits were not on-site. “All copies are nowon location,” she said.

Dougan’s response was less than satisfy-ing to the AOGCC, which stayed on theoffensive with new demands and deadlines.

“BLM now states a diverter was used onall the wells and that the earlier statementswere the result of a ‘misunderstanding,’”wrote chairman Seamount in a July 28 letterback to Dougan. “BLM is requested to pro-vide the Commission the current location ofthe diverter … and all documentation con-cerning or referencing transportation of thediverter since its use in the drilling opera-tions.”

Seamount continued: “As to wellboresopen to the atmosphere and the absence ofproper well markers, BLM concedes theseviolations but advises that it will properlymark, plug and abandon all such wells inAugust. Based upon BLM’s representations,the Commission will defer further action onthese violations. BLM must complete theproper plug and abandonment — consistentwith Commission requirements — no laterthan August 31, 2010. BLM should contactthe Commission to arrange a time thatCommission staff can inspect all suchwells.”

Seamount also directed the BLM to sub-mit well completion reports on each aban-doned well, concluding: “Failure to provideall of the information requested herein by


BEEF

see BEEF page 15


placed a cloud over its future as an offshoreoperator.

The parcels are in water depths rangingfrom about 265 feet to 4,000 feet and areabout 70 miles to 85 miles north of Inuvik,Northwest Territories.

Imperial spokesman Pius Rolheiser saidneither oil nor natural gas has been estab-lished as the primary target of the explo-ration program.

“We are aware of other situations (in theCanadian North) where companies wentlooking for oil and found gas, or vice versa.Our target would be viable hydrocarbons.”

He said decisions on “future explorationactivity have yet to be made,” althoughImperial Chief Executive Officer Bruce

March said in a speech in May that “we areat least four to five years out from everdrilling a well.”

To date, Rolheiser said, Imperial andExxonMobil gathered 3-D seismic data insummer 2008 and BP did the same in 2009.

In addition, he said, Imperial has inde-pendently engaged in marine, field andtechnical data gathering, including scientif-ic collaboration with a number of industry,government and Inuvialuit organizations inthe Beaufort area, while consultations areoccurring with Inuvialuit organizations.

Offshore regulations under reviewWhat happens next will be heavily influ-

enced by a comprehensive review of off-shore regulations by Canada’s NationalEnergy Board, which depends partly onwhat is learned from the cause and responseto the Macondo events.

For now, Imperial, ExxonMobil,Chevron Canada, Royal Dutch Shell,ConocoPhillips Canada and MGM Energyhave asked the NEB to reconsider its same-season relief well requirements, althoughBP Canada President Anne Drinkwater tolda House of Commons committee in Maythat BP was not rejecting the option ofdrilling a relief well despite the “technicalchallenges.”

Imperial said the emphasis should be onpreventive measures, pointing out thatBeaufort wells are multiyear operations.

In a 1990 hearing involving a GulfCanada Resources (now ConocoPhillipsCanada) application it was estimated that aBeaufort blowout could release 40,000 bar-rels per day for 45 days into an area fromTuktoyaktuk to McKinley Bay on the northside of Richards Island — many times morethan what was released from the Exxon

Valdez. Gulf Canada also conceded at thetime that it might not have the financial abil-ity to cover the costs of cleanup and restora-tion.

That application was rejected, with theInuvialuit Environmental Impact ReviewBoard ruling there was a “startling lack ofpreparedness” by Gulf Canada and theCanadian government to deal with aBeaufort blowout in an open waters season.

Gulf made the 1984 Amauligak discov-ery in the Beaufort that is estimated to con-tain 360 million to 380 million barrels of oiland 2.3 trillion cubic feet of gas. The nextfind was reported by Devon Canada in fall2007, claiming 240 million barrels of recov-erable oil from its Paktoa C-60 well.

—GARY PARK


BEAUFORT JV


es purchased in the sale until the U.S.Department of the Interior reworks someaspects of the sale’s environmental impactstatement.

Statoil has said that during the 2010 openwater season it plans to conduct a 3-D seis-mic survey focused on leases purchased inthe lease sale, possibly followed by a 2-Dsurvey over a broader area of the Chukchi.The company owns most of its leases inpartnership with Italian major EniPetroleum, with Statoil as operator.

Beyond leased areaIn a statement filed with the district court

on July 30, Martin Cohen, Alaska explo-ration manager for Statoil USA Explorationand Production Inc., said that Statoil’s sur-vey would include a large area outside the

company’s leases.“Statoil estimates that its leases comprise

approximately two percent of the total areathat is the subject of the permits for the seis-mic survey; areas leased to others compriseapproximately 33 percent of the total area;and areas not subject to lease compriseapproximately 65 percent of the total area,”Cohen said.

But, although the Statoil surveys wouldbe done under the terms of a Department ofthe Interior geology and geophysical explo-ration permit, rather than under the terms ofoil and gas leases, uncertainty following thecourt injunction is delaying the issue of theG&G permit and the National MarineFisheries Service incidental harassmentauthorization, both of which the companyneeds before the seismic survey can start,Cohen said.

And the Bureau of Ocean Energy


STATOIL State requests Chukchi reconsiderationThe State of Alaska has also weighed in on the U.S. District Court injunc-

tion against exploration activities under oil and gas leases in the ChukchiSea.

“There are enormous consequences for Alaskans if this development isstymied,” Alaska Gov. Sean Parnell said in a statement. “The public interestis in preventing the hardship Alaskans will suffer from lost jobs and eco-nomic growth if the injunction remains in place.”

Alaska is an intervening party in the lawsuit, arguing that the balance ofinterests weighs heavily in favor of the jobs, economic development and staterevenue at stake, as opposed to minimal environmental risks with explo-ration.

Alaska Attorney General Dan Sullivan said that where jobs are affectedbut “risks to the environment are minimal … the U.S. Supreme Court hasindicated that injunctions are not appropriate.”

In its brief requesting reconsideration the state noted that a lease confersthe right to conduct only very limited activities, such as seismic testing, andthat further administrative approval would be required for full-blown devel-opment.

—KRISTEN NELSON

see STATOIL page 16


Starring: Gas would be divertedIn her Aug. 2 letter to the DOE, Enstar

President Colleen Starring saidConocoPhillips and Marathon both “agreedto divert gas from the Kenai LNG exportfacility to the local market to meet their con-tractual obligations and, during periods ofhigh gas demand, to make interruptible gassales” as part of their contractually agree-ments with Enstar.

Currently, despite the recently approvedcontract with Marathon, Enstar anticipates a900 million cubic foot shortfall in 2011 anda 1.1 billion cubic foot shortfall in 2012.

“Neither Marathon nor ConocoPhillipswas willing to meet all the unmet needs ofEnstar’s customers for gas during the exportperiod on a firm basis, meaning that Enstarwill be relying on as-available, non-firmvolumes (including flowing gas divertedfrom the LNG export facility) to meet fore-casted peak needs of its customers,”Starring wrote.

However, neither the ConocoPhillips northe Marathon contracts require the compa-nies to divert gas to the local market if thosediversions “will result in any material oper-ational difficulties or technical harm to theLNG Facility.” If Enstar can’t get enough

gas from ConocoPhillips or Marathon tomeet peak local demand, Starring said thecompany would “be obliged to find othergas supplies, rely on fuel-switching or elec-tricity imports by local electric utilities,and/or ask customers to conserve gas onpeak days.”

Enstar still supports exportsDespite those uncertainties, Enstar still

supports an extension of the export license.Starring said the facility is needed until

Enstar, through its parent company SemcoEnergy, can complete an in-field gas stor-age facility in Cook Inlet. The company iscurrently seeking regulatory approval forthe project and doesn’t expect it to comeonline anytime before late 2012. Until thatstorage facility is up and running, Enstarsaid diversions from the LNG plant are “acritical supply resource on the coldest win-ter days.”

Enstar also supports the extensionbecause demand for exports in the summeroffsets seasonal swings in Alaska duringthe winter, allowing producers to draw onwells more evenly throughout the year, thusmaintaining deliverability and protectingreservoirs.

Enstar also wants the export licenseextended to maintain supplies. Marathoncan contractually reduce deliveries toEnstar by 14 million cubic feet per day if

the LNG facility shuts down between 2011and 2013. “Said more simply,” Starringwrote, “DOE’s denial of the requestedLNG export license extension would likelyput Enstar and its customers in a worse gassupply position during the export licenseextension period.”

Some support for exports …The DOE received seven other com-

ments on the extension request.Aside from Enstar, only two comments

supported an extension. All three membersof the Alaska Congressional delegationnoted that the facility not only provideslocal jobs and revenues, but also is de factostorage that levels seasonal swings indemand.

The delegation also noted thatConocoPhillips and Marathon Oil, theowners of the plant, were not asking to shipmore gas to Asian markets, but for moretime to ship volumes already approved forexport during a previous extension requestgranted in early 2009.

At that time, the DOE gaveConocoPhillips and Marathon permissionto ship 99 trillion British thermal units ofliquefied natural gas to Asia between 2009and 2011, but because the companiesdecreased the number of tankers sailingoverseas, they now anticipate having abouthalf of that allotment unshipped by the time

the deadline arrives next April.The Resource Development Council

echoed the Congressional delegation, andadded that studies have indicated that theCook Inlet basin can meet local demandthrough 2013.

And some oppose exportsOf the five comments opposing an

extension, four came from citizens in theregion who worried about exporting naturalgas at a time when Cook Inlet reserveswere in decline.

Those concerns echoed comments fromseven Democratic state lawmakers whosaid they couldn’t support exports unlessthe companies first agreed by contract tomeet local needs. They noted that despitethe recent supply agreements Marathonnegotiated with Enstar and ChugachElectric Association, shortfalls remained in2011 and 2012, and increased considerablyin 2013, during the final months of the pro-posed extension period.

The companies have requested an expe-dited decision, preferably by earlySeptember.

This year, the facility exported 11.5 bil-lion cubic feet of LNG through the end ofMay. �


ENSTAR GSA


September 30, 2010 constitutes an addition-al violation of the Commission’s regula-tions.”

Conflict over legacy wellsApart from the Wainwright flare-up, the

AOGCC also has been out of sorts overBLM’s management of dozens of old wellsprimarily in the National PetroleumReserve-Alaska. The Navy, the USGS andtheir contractor, Husky Oil, drilled numer-ous holes between 1944 and 1982.

Petroleum News requested and receivedcorrespondence between the AOGCC andthe BLM on the legacy well issue.

In January 2009, Foerster and theAOGCC began pressing for a status reporton the old wells — where they suspended,shut-in or what?

In a Dec. 15, 2009, letter to the BLM’sNoble, Foerster said AOGCC recordsshowed “many BLM-managed wells” hadnever been plugged and abandoned in con-formance with AOGCC regulations. Sheasked the BLM to submit its plans for 45wells, including a timetable.

“The BLM has, at enormous expense,plugged thirteen legacy wells over the lastseven winter seasons, including the Drew

Point No. 1 well that we are currently plug-ging,” Noble wrote back to Foerster onMarch 3.

Noble went on to say that the wellsFoerster had inquired about “have all beendetermined to pose no risk or cannot belocated.” The plan, he said, was to keep thewells under observation, making sure theyposed no risk with changing conditions.Plugging the wells could wait until the oilindustry expands closer to them, greatlyreducing the cost of accessing the veryremote sites.

On March 17, Foerster replied to Noblethat his contention the wells posed no riskwas “problematic.”

“By definition any well not in compli-ance with AOGCC regulations poses arisk” to human health and the environment,she wrote.

“The fact that BLM ‘lost’ several wellsunder its authority calls into question theveracity of, and basis for, BLM’s assertionthat the other wells have been ‘determinedto pose no risk,’” Foerster said.

A 2004 BLM report featuring picturesof legacy well sites “littered with rottinglumber, rusting metal drums and poolingliquid waste” underscores the “dubiousvalidity” of the federal agency’s position,she said.

If the BLM failed to comply with stateregulations, the AOGCC would pursue

other avenues such as bringing theEnvironmental Protection Agency into thematter or taking legal action, Foersterwrote.

BLM’s olive branchNoble, in a March 22 e-mail to the

AOGCC’s Regg, wrote he was “a littletaken aback by the tone” of Foerster’sMarch 17 letter. He noted the BLM hadspent $54 million plugging the 13 legacywells, and asked Regg for help finding per-tinent state regulations.

On April 7, Regg e-mailed Noble back,saying: “BLM’s non-compliance withAOGCC regulations has been a problemfor years.” He added: “BLM has suggestedthe AOGCC should hold it to a differentstandard than other operators. …” Reggcopied an EPA official and Pat Pourchot,the Interior secretary’s special assistant forAlaska affairs, on the e-mail.

On May 14, the BLM’s Dougan wroteFoerster saying the “lost” wells were shal-low, uncased well borings the Navy con-ducted 60 years ago, and with freezing andthawing the borings “have decayed andblended in with the surrounding environ-ment.”

BLM monitoring led the agency to seekemergency funding about five years ago toplug and abandon the J.W. Dalton well,which was under threat from Beaufort Sea

coastal erosion, Dougan said.She extended an olive branch, inviting

an AOGCC inspector to accompany BLMstaff on a planned visit to all the legacy wellsites.

“What we want to do, and continue todo, is work with the AOGCC to resolvesome of these issues,” Wayne Svejnoha,BLM Alaska’s branch chief of energy andminerals, told Petroleum News in an Aug. 4interview.

But the conflict over the legacy wellsappears far from resolved.

On July 27, all three AOGCC commis-sioners including Seamount, Foerster andJohn Norman signed a letter to the Alaskacongressional delegation urging them tooppose a piece of pending legislation, H.R.5626, the Blowout Prevention Act of 2010.The bill, offered in the wake of the cata-strophic BP oil spill, contains controversiallanguage that could make state regulationof drilling subject to federal oversight.

The letter said it’s “simply ludicrous” tosuggest the federal government can do abetter job of regulating oil and gas drillingthan the states, noting that “the only entitywhich has had difficulty complying withAlaska’s regulations” is a federal agency,the BLM. �


BEEF

Contact Wesley Loy at [email protected]

http://www.acuren.com


site at Oliktok Point within seven days, inpreparation for mechanical completion,functional checkout and commissioning ofall facilities.

Onshore initiallyNikaitchuq crude oil, to be produced ini-

tially from onshore wells at Oliktok Pointbut later also from wells on a manmade off-shore island, will be the first North Slopeproduction not processed through facilitiesoperated by either BP or ConocoPhillips.

“Everything is moving forward asplanned for first oil around the beginning of2011,” Eni said. “Of course, any number ofvariables could impact that timeline, but atthis point the Nikaitchuq development is onschedule.”

Eni had originally planned field startupfor December 2009 but early in that year,faced with issues including plunging oilprices, poor economic conditions and hurri-cane-related fabrication delays, the companyslowed the Nikaitchuq development downfrom what the company characterized as “anaccelerated pace of development” to a morenormal pace, thus delaying anticipated first

oil from the field by about a year.And development of the field has moved

ahead steadily.In addition to the massive modules that

needed transportation by barge, Eni has beentransporting smaller modules and otherequipment to the North Slope by truck, withtruckable modules being constructed inAnchorage. Modules associated with theonshore Oliktok Point component of theproject started shipping in December 2008and will continue arriving until Septemberof this year, Eni said. The most important ofthe offshore truckable modules will bemoved on site before the end of the 2011 ice-road season, the company said.

“Currently more than 90 percent of theonshore truckable modules are in place,” Enisaid.

The offshore site consists of an 11-acregravel drilling pad 3.8 miles offshore, on theinner shore of Spy Island just north ofOliktok Point.

In 2009 Eni trenched a pipeline bundleinto the seafloor, between the offshore islandand Oliktok Point. And on April 13 of thisyear the company completed the 10-inchexport pipeline from the Oliktok Point site,to deliver Nikaitchuq production to theKuparuk pipeline for transportation to pumpstation 1 of the trans-Alaska oil pipeline.

“An associated 13.8-kilovolt power cableand a communications cable to the tie-inmodule at the Kuparuk pipeline were com-pleted on May 6, 2010,” Eni said. “Final tie-ins and commissioning of the pipeline willbe before year end.”

And the company has awarded ATCO acontract for the installation of the on-sitecamp to house personnel at Oliktok Point.

The 180 million barrel Nikaitchuq fieldcontains two distinct oil pools — light oil ina relatively deep, poor quality Sag Riverreservoir and a larger accumulation of moreviscous oil in the shallower Schrader Bluffformation.

To develop the field, Eni plans to direc-tionally drill seven production wells andeight injection wells from Oliktok Point, andto drill 24 production wells and 24 injectionwells from the offshore island. All of thesewells would target the Schrader Bluff, withthree additional offshore wells potentiallytargeting the Sag River.

Horizontal injector wells in the SchraderBluff will inject water to flush oil towardshorizontal production wells.

Eni is going to use an existing OliktokPoint test well as an initial injector, togetherwith a production well that had been drilledprior to Eni taking a 100 percent interest inthe field in 2007. More recently Nabors rig

245E has been busily drilling at Oliktok,completing another producer well and onedisposal well in 2009. So far in 2010 the righas completed one water source well andtwo more producers.

Offshore drilling is scheduled to begin inSeptember 2011.

Disposal wellsDisposal wells will enable the disposal of

almost all Nikaitchuq non-hazardous wasteby injecting the waste into a non-hydrocar-bon bearing underground rock reservoir,several thousand feet below any potentialdrinking water sources, Eni said. This is amuch better waste disposal system than theuse of landfills — landfill waste has thepotential to seep into otherwise drinkablewater or into fish-bearing water bodies, thecompany said.

Eni, one of the world’s largest oil compa-nies, also has leases on the North Slope atNorth Tarn and Maggiore, and offshore inthe Beaufort and Chukchi seas. The compa-ny has been working with Shell to collectsome 3-D seismic data on joint-venture leas-es in Harrisons Bay, in the Beaufort Seaouter continental shelf. �


ENI MODULES

Contact Alan Bailey at [email protected]

Management, Regulation, andEnforcement, the recently formedsuccessor agency to MMS, has saidthat it will not issue the G&G permitwithout clarification from the courton whether Statoil’s planned activi-ties fall within the scope of theinjunction.

Aug. 6 deadlineIn his July 30 statement, Cohen

said that if the company does notobtain the two remaining permits byAug. 6 it will likely have to cancel its2010 seismic program. The seismicsurvey will probably take 60 days tocomplete, but sea ice may form in thesurvey area by late September, Cohensaid.

Also on July 30, BOEM filed amotion with the court, asking forexpedited consideration of the clarifi-cation request by Aug. 3, bearing inmind the time constraints on Statoil’splans.

On Aug. 2, without explanation,the court declined the BOEM request.

But, also on Aug. 2, the court didrespond to a parallel request fromShell for clarification over that com-pany’s planned 2010 Chukchi Seaactivities. Following the impositionof a DOI Arctic outer continentalshelf drilling moratorium, Shell hashad to cancel its planned 2010Chukchi and Beaufort Sea drillingprograms. However, the companyhas been planning to continue withsome Chukchi Sea environmentalstudies, geotechnical surveys andshallow hazard surveys during the2010 open water season. In its Aug. 2ruling the court agreed that Shell’s2010 activities fall outside the scopeof the injunction and can continue.

“The contemplated activity doesnot include drilling and may have thebenefit of assisting the parties indetermining the propriety of futureactivities,” Judge Beistline said.

—ALAN BAILEY


STATOIL

Contact Alan Bailey at [email protected]

http://www.lynden.com

alaska’s beef with blm · yonker, who nurture the magazine into existence every year. ak-wa...

Documents