an explorer, alone

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

� N A T U R A L G A S

� G O V E R N M E N T

Q&A: Parnell seeks oil tax changes,more access to federal lands, water

page4

Ormat Technologies Inc. is exploring for geothermal energy on thesouthern flanks of the Mount Spurr volcano, about 80 miles west ofAnchorage, Alaska.

ALA

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Ormat confirms Spurr geothermal;needs utilities to purchase power

Ormat Technologies’ summer 2010 small-bore drilling pro-gram on the southern flanks of Mount Spurr volcano, on thewest side of Alaska’s Cook Inlet, has confirmed the likely exis-tence of a geothermal source that would enable power genera-tion for the Alaska Railbelt, Paul Thomsen, Ormat’s director ofpolicy and business development, told the Alaska HouseResources Committee Jan. 24.

Thomsen said that the purpose of the company’s drilling pro-gram is to determine whether there is an appropriate combina-tion of underground heat, underground water and permeablerocks to enable the construction of a viable geothermal powerplant.

And so far things look good.

Encouraging“Results to date have been very encouraging,” Thomsen said.

“The shallow water shows the mixing of geothermal fluids. Thegeochemistry indicates that there is a very high temperatureresource — we can look at water molecules and see how hotthey’ve ever been. All of this is indicating, as we thought, thatthis is a very hot, very good potential geothermal resource.”

Ormat picked up 15 leases on the southern flanks of MountSpurr in the State of Alaska’s September 2008 geothermal lease

Shell defers drilling plan to 2012;still needs air quality permit

Faced with continuing permitting uncertainty following theEnvironmental Appeals Board remand of the U.S.Environmental Protection Agency’s airquality permit for its planned BeaufortSea drilling, Shell has abandoned its planto drill in the Beaufort in the summer of2011, deferring that plan into 2012.

“This is not an environmental issue,”said Pete Slaiby, vice president for ShellAlaska, in a Feb. 3 media briefing aboutShell’s drilling decision. “We have madesignificant and voluntary capitalimprovements in the air emissions tech-nology we have applied to the entire(drilling) program that will allow us to have almost no materi-al impact on the Arctic air shed. It is an issue of processing apermit application in a timely way. We have been in thisprocess, trying to achieve an air permit, now for five years.”

Slaiby said that as a result of the deferral of its Beaufort Seadrilling, Shell expects to farm out in 2011 most of the assetsearmarked for the drilling operation.

An explorer, aloneBRPC, partners prepping North Slope’s only exploration well for 2010-11

By ERIC LIDJIFor Petroleum News

Amulti-company joint venture led by BrooksRange Petroleum Corp. has announced plans to

drill what will likely be the North Slope’s only explo-ration well this winter.

The Alaska-based independent plans to startdrilling at the North Tarn prospect in early March.The North Tarn No. 1 well site is about two mileswest of the Kuparuk River unit.

BRPC plans to drill the well using Nabors rig 9ES.“We are excited to get started at the North Tarn

well and feel that with the signing of the 9ES rig con-tract, we now have all the contracts in place to effec-tively execute a successful season,” said Bart

Armfield, vice president of field operations forBRPC.

The 6,300-foot well would test targets in theBrookian formation and the deeper Kuparuk forma-tion. The Brookian is the same formation producingat Tarn, the Kuparuk satellite to the south, while theKuparuk is the main formation producing at the

“Overall, we have a four-wellcommitment that we’re proposing for that

unit, plus a seismic program.” —Jim Winegarner, vice president of land and external

affairs for BRPC

see BRPC page 19

RCA approves CINGSACommission OKs the certificate and tariff for planned Kenai gas storage facility

By ALAN BAILEYPetroleum News

Just a month or so after approving a certificateof public convenience and necessity for Cook

Inlet Natural Gas Storage Alaska’s planned Kenaigas storage facility, the Regulatory Commission ofAlaska has approved a tariff for the facility.

In a final order issued Jan. 31 the commissionsaid that it was approving the tariff because allissues raised during a tariff hearing had beenresolved. Tariff approval is, however, subject tosome adjustments to the tariff ’s specification of thegas storage service area.

CINGSA is fast tracking the development of itsfacility in the Sterling C sands of the Cannery

Loop gas field, on the south side of the City ofKenai, to head off a potential Southcentral Alaskautility gas shortfall in the winter of 2012-13. The

Because CINGSA will not commence gasinjection into its facility until April 2012,there is sufficient time for the companiesinvolved in gas storage usage to figure

out the required routing of the stored gasand then implement any necessary

pipeline infrastructure upgrades, RCAsaid in its order.

see CINGSA page 18

NWT signs for transferAgreement in principle with Ottawa; 5 of 7 aboriginal groups not in agreement

By GARY PARKFor Petroleum News

Two decades of negotia-tions brought the

Canadian and NorthwestTerritories governments to asigning ceremony that theyhope will lead in a couple ofyears to a final transfer of con-trol over northern naturalresources to the NWT, but the gulf between the aspi-rations of the NWT government and a large portionof its aboriginals remains as wide and deep as ever.

NWT Premier Floyd Roland and federal IndianAffairs Minister John Duncan mustered as muchoptimism as they could in announcing a “devolution”

agreement-in-principle thatsets the stage for the NWT tocontrol resource developmenton public lands and the right tocollect royalties and taxes fromthe resources.

Roland said that much ofwhat Canada’s 10 provincialgovernments have as a matterof constitutional right is whatnortherners are now close to

achieving.He said the NWT, which occupies about 12 per-

cent of Canada’s land mass, is now at a point where it“can progress to a final set of negotiations where a

FLOYD ROLAND JOHN DUNCAN

see TRANSFER page 14

see SPURR GEOTHERMAL page 17

see SHELL DECISION page 20

PETE SLAIBY

http://www.PetroleumNews.com/

2 PETROLEUM NEWS • WEEK OF FEBRUARY 6, 2011

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

LAND & LEASING

EXPLORATION & PRODUCTION

ENVIRONMENT & SAFETY

PIPELINES & DOWNSTREAM

NATURAL GAS

FINANCE & ECONOMY

10 Exxon still waiting for right of way

13 Lieberman’s last chance to close ANWR?

14 Alaska Forum on the Environment Feb. 7

11 Exxon’s Sakhalin-1 extended-reach record

10 BP’s Carson refinery one of 2 to be sold

14 US drilling rig count up by 19 to 1,732

6 BP moves Liberty startup out to 2013

7 Rollercoaster: ANS production back on par7 Energia Cura names pipeline Arctic Fox

9 Legislature gets report on AGIA payments

12 Murkowski retains ranking member spot

14 Begich pushes for Jones Act waiver

8 Begich introduces Arctic oil spill bills

8 Seamount reappointed to AOGCC

INTERNATIONAL

GOVERNMENT

8 Weeks wants indie credit extended

Asks Parnell to remove 2016 sunset provision on theSmall Producer Tax Credit; credit pays for fields smaller than 50,000 bpd

4 Parnell: Changes promote jobs, more oil

Governor addresses tax proposals, access to federallands, natural gas pipeline, OCS exploration

5 Canada won’t lead the way

Environment minister rejects call for independent climatechange action, sticks with policy of harmonizingCanadian, US regulations

9 Wilcox: Alaska needs small independents

Co-founder of Cook Inlet Energy says big oilcompanies open basins, smaller companiesneeded for smaller geologic opportunities

12 Linc gets UCG exploration license

Alaska Mental Health Trust Land Office issues seven-yearlicense over 181,414 acres; can later be converted to traditional leases

11 RCA denies APE’s request for waiver

Requires Armstrong, partners to submit two years of financial data in order to get CPCN; Enstar pegs early March startup date

ON THE COVERAn explorer, alone

BRPC, partners prepping North Slope’s only exploration well for 2010-11

RCA approves CINGSA

Commission OKs the certificate and tariff for planned Kenai gas storage facility

NWT signs for transfer

Agreement in principle with Ottawa; 5 of 7 aboriginal groups not in agreement

Ormat confirms Spurr geothermal; needs utilities to purchase power

Shell defers drilling plan to 2012; still needs air quality permit

reach new horizons.

SIDEBAR, 0: Begich, Murkowski, Young, Parnell slam feds

SIDEBAR, Page 5: What comes down goes up

SIDEBAR, Page 7: AOGCC extended reinjection order

http://www.ukpik.com/

PETROLEUM NEWS • WEEK OF FEBRUARY 6, 2011 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay W-202 BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 2L-320 ConocoPhillipsDreco 1000 UE 16 (SCR/TD) Prudhoe Bay H-15/01 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD2-77 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk 1E-08A ConocoPhillipsTSM 7000 Arctic Wolf #2 Stacked at Prudhoe Bay FEX/Available

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableAC Coil Hybrid CDR-2 Kuparuk 2X-18L1 ConocoPhillipsDreco 1000 UE 2-ES Prudhoe Bay Stacked out AvailableMid-Continental U36A 3-S Prudhoe Bay Stacked out AvailableOilwell 700 E 4-ES (SCR) Milne Point MPF-65 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay DS 05-30 BPDreco 1000 UE 9-ES (SCR/TD) Going to Southern Miluveach Brooks Range Petroleum

Unit to drill North Tarn #1 on March 1

Oilwell 2000 Hercules 14-E (SCR) Prudhoe Bay Stacked out AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Stacked out AvailableOilwell 2000 17-E (SCR/TD) Prudhoe Bay Stacked out AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Stacked at Point Thompson AvailableAcademy AC electric Canrig 105-E (SCR/TD) Stacked at Deadhorse AvailableAcademy AC electric Heli-Rig 106-E (SCR/TD) Stacked at Deadhorse AvailableOIME 2000 245-E Oliktok Point 0107-04 ENI

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site 18-13C BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site A-39A BPIdeco 900 3 (SCR/TD) Kuparuk Wel1J-137 ConocoPhillips

North Slope - Offshore

BP (rig built & being assembled by Parker)Top drive, supersized Liberty rig Endicott SDI for Liberty oil field BP

Nabors Alaska DrillingOIME 1000 19-E (SCR) Oooguruk ODST-46i Pioneer Natural ResourcesOilwell 2000 33-E Prudhoe Bay Stacked out Available

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Stacked out on the west side of Available

Cook Inlet near TyonekCook Inlet EnergyAtlas Copco RD20 34 Undergoing winterization Cook Inlet Energy

at W. McArthur River UnitDoyon DrillingTSM 7000 Arctic Fox #1 Beluga Stacked Available

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Rig released by Armstrong Cook Inlet Available

Nabors Alaska DrillingContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Kenai Stacked out Available

Rowan CompaniesAC Electric 68AC (SCR/TD) Stacked Kenai, Cosmopolitan Pioneer Natural Resources

Kuukpik 5 Stacked, Kenai Available

Cook Inlet Basin – Offshore

Chevron (Nabors Alaska Drilling labor contract)428 M-11 Steelhead Platform Chevron

XTO EnergyNational 1320 A Coil tubing cleanout planned off Platform XTO

A in the near futureNational 110 C (TD) Idle XTO

Mackenzie Rig StatusCanadian Beaufort Sea

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

Central Mackenzie Valley

Akita/SAHTUOilwell 500 51 Racked in Norman Wells, NT MGM Energy Corp.

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of February 3, 2011.

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts*Jan. 28 Jan. 21 Year Ago

US 1,732 1,713 1,317Canada 637 621 531Gulf 26 27 41

Highest/LowestUS/Highest 4530 December 1981US/Lowest 488 April 1999Canada/Highest 558 January 2000Canada/Lowest 29 April 1992

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

http://www.conocophillips.com/

By STEVE QUINNFor Petroleum News

Gov. Sean Parnell didn’t wait for theLegislature to gavel in before intro-

ducing his plan to revamp the state’s oiland gas tax structure. He’s seeking tolower the 25 percent tax rate on net prof-its to 15 percent for production from newfields and reduce thesurcharge known as pro-gressivity. A few dayslater in his State of theState address, Parnellstressed additionalresource priorities including access tofederal lands and waters for resourcedevelopment. This means collaborationwith the industry as well as his peers; heserves as vice chair of the resources com-mittee for the National Governors

Association. Parnell sat down withPetroleum News and discussed a widerange of resource issues including oiltaxes; the prospects of a natural gaspipeline; the trouble jumpstarting outercontinental shelf exploration and produc-tion; and stemming the annual 6 percentto 7 percent decline of throughput in thetrans-Alaska oil pipeline.

Petroleum News: What areyour resource goals for thestate?

Parnell: There are severalequation changers when it

comes to creating more jobs in resourcedevelopment. One of those is tax regime.The other is permitting. The third isaccess to those resources. The fourth isaccessible affordable energy.

If our administration can change for

the better the taxregime and permit-ting regime, openup access, and cre-ate more opportuni-ties for lower costand lower abundantenergy, we can cre-ate more resourcedevelopment jobs.

That’s ultimatelywhat I’m trying to achieve. As a state wewere supposed to be able to access ourresources so we would not become award of the federal government. What Ican do is focus on state lands and thoseequation changers or game changers,which is what you’ll see us doing.

Petroleum News: Is the end game jobsor is it filling the pipeline?

Parnell: I’m interested in Alaskanshaving more opportunities. The produc-tion aspect comes with that: So greaterproduction means grater revenue, moreand better schools and public safety.They are all interconnected. I do tend tothink of private sector and economicgrowth. Then I think about product forthe state. I also think about our nationalsecurity. Having more domestic produc-tion is a good thing.

Petroleum News: Can the state affordyour tax reduction bill?

Parnell: I don’t think we can afford tostand still and cling to a parachute that’sonly half full. The pipeline will keepworking at a certain level. We can all dothe math. Unless we get more oil pro-duction into that pipeline then we are atrisk financially.

The notion that it costs money to dosomething is misguided because it’s ashort-term view of things. I understand itcomes from legislators who want tospend money right now. I’d rather pro-vide a lower tax environment, and createnew jobs, and new production. I’m notlooking at the next five, seven, 10 years.I’m looking farther down the road,longer-term.

If the companies’ reinvestment is at alevel of 50 percent of what they are tak-ing out, the cost to the state is a coupleof billion over the next 30 years. If youlook out across 30 years and you assumea particular level of reinvestment ofthose tax credits the cost to the state isminimal compared to thousand or tens ofthousands of jobs.

Think of the North Slope. You’ve gotPrudhoe Bay and Kuparuk and they havebeen punched full of holes — hundredsof wells. There is a lot of acreage thatrings those two fields, mostly to thesouth. It’s all leased but it hasn’t beendrilled for years. Why not take steps toincentivize hundreds of new wells, andthousands of new jobs?

Petroleum News: Why the change of

heart? Before you were re-elected youseemed to think ACES was working.

Parnell: Last session I introduced leg-islation to create infield drilling taxcredits along with several other tax bene-fits because I believed it would createjobs on the North Slope. The Legislaturesaid they were not going to do it for theNorth Slope. But we’ll create tax bene-fits in Cook Inlet and we have someincreased activity for Cook Inlet. WhatI’ve said this year has been entirely con-sistent with that. If there is a demonstra-tion there will be new jobs, new produc-tion, we are going to move forward withlower taxes. That’s entirely consistentwith what I did last year and it’s what Iwant to do moving forward.

Petroleum News: Can this be done in90 days?

Parnell: Sure it can. I’ve served inboth the House and the Senate. Whenlegislators start talking about a specialsession on Day 10 (of the regular ses-sion), it makes me wonder what’s reallygoing on in the background. Legislatorscan move on jobs for Alaskans if theyreally want to during the 90-day session.

Petroleum News: Do you have anygas line concerns?

Parnell: Because of the uncertainty ofwhether a gas line will occur in the nexteight or nine years, yeah that’s the con-cern. Any chance I get I push these com-panies to move together on commercial-izing Alaska’s natural gas, I take it.

Petroleum News: Have you lost anyfaith in the prospect of getting a gas linebuilt?

Parnell: What I’ve lost is patiencewith legislators who think that a $40 bil-lion deal comes together overnight.We’ve become this government that youorder a burger and get it in two minutes.These deals take time to put together. Weare still within the time line that AGIAcontemplated. Legislators who supportedAGIA ought to be willing to give AGIAa chance to work in the timelines con-templated.

Petroleum News: Are you worriedshale development affecting Alaska.

Parnell: Certainly shale developmentcan affect gas line economics. As long asthe largest companies in the worldappear to be seriously pursuing naturalgas in Alaska, which is already comingout of the ground, I’m not so worriedabout shale. Shale is potentially a short-er-term play. New York has already out-lawed it. It has its environmental con-cerns. It takes a lot of capital to punchthe holes for shale gas. I think there isroom for both. Everything we see saysthat natural gas will be needed fordecades to come. That’s a 50-year hori-


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� G O V E R N M E N T

Parnell: Changes promote jobs, more oilGovernor addresses tax proposals, access to federal lands, prospect of a natural gas pipeline, troubles jumpstarting OCS exploration

GOV. SEAN PARNELL

see PARNELL Q&A page 6

JUD

Y P

ATR

ICK

http://www.alaskarailroad.com/

http://www.gdiving.com/

By GARY PARKFor Petroleum News

Canada is not prepared to “go-it-alone”on a climate change program, despite

the urgings of an influential government-appointed panel that Ottawa should pro-ceed independently of the United States byintroducing a national cap-and-trade sys-tem and set a ceiling price for carbon.

A new report by the NationalRoundtable on the Environment and theEconomy, or NRTEE, said a made-in-Canada approach would allow Canada toachieve significant greenhouse gas reduc-tions over the next decade rather than wait-ing for the U.S. to act.

But newly installed EnvironmentMinister Peter Kent refused to budge fromhis government’s commitment to harmo-nize its policies with the Obama adminis-tration, which he described as a “sensibleand realistic” strategy.

Rejecting the panel’s call for aCanadian cap-and-trade system, he saidOttawa has “chosen to move ahead withregulation and we believe that we’re seeingearly results.”

“We believe we will achieve our targetsfor 2020,” Kent said, referring to the feder-al commitment to lower 2005 emissionslevels by 17 percent by 2020.

He said Canada is working with theU.S. on regulations to limit tailpipe emis-sions from vehicles and is continuing todevelop regulations for trucks and is aheadof the U.S. in tackling emissions fromcoal-fired electricity plants.

Two previous NRTEE reportsThe NRTEE, which has issued two pre-

vious reports examining the economicrisks and opportunities of taking climatechange action in Canada, has aligned itselfwith all three opposition parties in theCanadian Parliament which have criticizedPrime Minister Stephen Harper’s determi-nation to move in lockstep with the U.S.

Harper has insisted Canada should notmake any moves that would weaken tieswith its major trading partner.

The Canadian petroleum industry hasbeen especially concerned that independ-ent measures could damage the revival ofplans to develop Alberta’s oil sands, whichaccount for about half of Canada’s crudeoil exports to the U.S.

“Harmonization, where possible andwhen feasible, makes sense for Canada,”said NRTEE president David McLaughlin.

“In the face of persistent U.S. uncer-tainty as to its own climate policy future,Canada will need to look to its ownoptions, in the right way, at the right time,”he said.

NRTEE chair Bob Page said Canadaneeds to “understand how we can meet ourenvironmental responsibilities as a sover-eign state ... fully comprehending theunique economic ties we enjoy on this con-tinent. We are looking towards conformityin purpose, not uniformity in detail.”

Call for phased-in approachThe NRTEE, in calling for a phased-in

approach that would lay the groundworkfor greater harmonization as U.S. policiestake shape, has recommended action onfour options:

• Setting a price collar that limits theCanadian carbon price to no more thanC$30 per metric ton of carbon dioxideequivalent higher than whatever price may

be set in the U.S.;• A national cap-and-trade system with

auctioning of permits and revenue recy-cling to cap emissions and address region-al and sectoral concerns;

• Limited international permits anddomestic offsets to keep domestic carbonprices lower for Canadian companies; and

• A technology fund of up to C$2 bil-lion to stimulate investment in emission-reduction technologies.

The report said it will be more expen-sive for Canada to reduce emissions thanthe U.S., partly because U.S. industrialinfrastructure and coal-fired power plantsare older and will have to be replacedsooner.

Otherwise, if Canada and the U.S. set

an identical price, Canada would fall shortof matching the U.S. goal for loweringemissions by 2020, the NRTEE said.

Pembina: Report raises questionsWithout an independent policy, green-

house gas emissions would be 10 percentabove 2005 by 2020, creating a gap of 178million metric tons a year betweenOttawa’s goal and projected emissions, itestimated.

The Alberta-based Pembina Institutesaid the report shows that Canada wouldsee strong economic growth even if it ledthe U.S. in adopting a broad-based price ongreenhouse gas pollution.

Claire Demerse, associate director ofPembina’s climate change program, saidthe report “raises some fundamental ques-tions about the government’s long-stand-ing policy of waiting for the U.S. beforeimplementing strong climate policies inCanada.”

She said the NRTEE’s “detailed andcredible analysis shows Canada would seestrong economic growth across the coun-try even if we lead the United States inadopting a broad-based price on green-house gas pollution.”

Demerse said the NRTEE has demon-strated that quick action to introducestronger climate policies is “both afford-able and feasible … (and) there are nocredible excuses for delay.” �


� E N V I R O N M E N T & S A F E T Y

Canada won’t lead the wayEnvironment minister rejects call for independent climate change action, sticks with policy of harmonizing Canadian, US regulations

The Canadian petroleum industryhas been especially concerned that

independent measures coulddamage the revival of plans to

develop Alberta’s oil sands, whichaccount for about half of Canada’s

crude oil exports to the U.S.

What comes down goes upThe drive by Canadian oil sands producers to reduce their carbon emissions has

made headway with per-barrel output from in-situ projects dropping by 15 percent in2009 from 2008 and from mining projects by 18 percent in 2008 from 2007.

That was the positive spin derived from figures compiled by Evaluate Energy, aLondon-based source of energy information.

The flip side showed that the rapid growth in production levels also boosted over-all emissions by 45 percent in the 2004-2009 period to 44 million metric tons, a totalthat will continue climbing as production ramps up.

“On a micro level, they have been bringing (greenhouse gas emissions) down, buton a macro level the only direction emissions are going is up,” said Chris Wilson, ananalyst with Evaluate Energy.

He said that despite the progress being made by producers on a per-unit basis “therearen’t going to be any emissions reductions now or realistically any time soon. I don’tthink this will be acceptable to environmental groups.”

Wilson said further reduction gains are possible with the use of new thermal-recov-ery technologies such as solvent injection and large-scale carbon capture and storage.

Greg Stringham, vice president of oil sands at the Canadian Association ofPetroleum Producers, told the Calgary Herald that, even in a worst-case scenario, theoil sands will account for about 9 percent of Canada’s overall GHG emissions, com-pared with 5 percent at present.

However, he said that technologies that are just being brought into full-scale usewill continue to drive down the per-barrel intensity of emissions.

“Over the long term, it is wise policy to put a foot in the camp of an industry thatis focused on performance enhancement,” Stringham argued.

A study by CanOils, the Canadian division of Evaluate Energy, estimated that inte-grated producers (those who both extract and upgrade bitumen) lowered their averagecarbon dioxide emissions to 123 kilograms per barrel of synthetic crude in 2009against 150 kilograms in 2008, while in-situ emissions dropped to 93 kilograms in2008 from 110 kilograms in 2007.

—GARY PARK

Contact Gary Park through [email protected]

http://www.greertank.com/

zon, not a 10- or 20-year horizon.

Petroleum News: What do you do ifthe companies come to you and say thisdoesn’t pencil out. Do you find any newways to monetize the gas?

Parnell: I’m open to any ideas when itcomes to monetizing the gas. I’m not sit-ting there waiting. That’s whole reason Iwant to see hundreds of new wellsdrilled. Alaska needs to monetize all ofits resources. Just south of Prudhoe Bayand Kuparuk, that’s oil. We should not be

standing still and letting that land lan-guish. We should be providing incentivesto get new oil production and jobs. Thereis a lot of oil still left in the North Slope.We are just not going to sit still.

Petroleum News: The state will havespent about $100 million by the end ofthis fiscal year on gas line reimburse-ments. Is that money well spent so far?

Parnell: I think so, especially whenyou consider that Alaska has never beenin a place where companies have actuallynominated their gas for a gas pipeline.That’s the historic nature of where weare. Being in a place where companiesare negotiating precedent agreements.

That’s the historic nature of where weare.

Petroleum News: Let’s get back toTAPS (the Trans-Alaska Pipeline System).What are your concerns in both fillingthe pipeline but also the integrity of theinfrastructure?

Parnell: I’m concerned that Alyeskaoperates TAPS in an environmentally safeand sound way. That being said, one ofthe best ways to do that is put more oil inthe pipeline. It’s like your boiler and thehot water lines under your boiler. Whenyou shut down the water, then you haveto restart it, you discover the heat fromthe water helped keep everything sealed.

The valves work when everything isflowing full and hot. It’s the same thingwith a pipeline where you have largerquantities of oil flowing through atgreater temperatures. System integrity isnot the kind of issue it is when it’s downto 300,000 barrels a day or 400,000 bar-rels a day. That’s why my emphasis isputting more oil in the pipeline. It getshard to maintain at lower flow and lowertemperatures.

Petroleum News: With that in mind,some would like to see oil come from theChukchi and Beaufort. You spoke aboutfederal overreach. Realistically what canyou do about that?

Parnell: We cannot afford federalagency overreach that results in fewerjobs and diminished economic opportuni-ty. It doesn’t bode well for our future.What I’m seeing is the agencies workingto pick states off one by one. I thinkwe’re stronger together.

Petroleum News: Does it trouble youthat the federal government sold the leas-es but it’s the federal government whowon’t let them drill?

Parnell: That’s the issue. The federalgovernment has a leasing system. Fiveyears later Shell can’t even get an air per-mit that takes months to get in the Gulfof Mexico.

It’s kind of a bait and switch by thefederal government: to take money onone hand for a lease but not allow leaseexploration and development activity.

Petroleum News: You’ve touched on oila lot. Do you think the focus moved awayfrom oil for a couple of years in favor ofthe gas line and now it’s shifting back?

Parnell: The question really should bewhat do we need to do to move forward.We still have a lot of oil to find, a lot ofminerals to find and a lot of natural gas.Point Thomson is a priority for me. Thefirst order of priority is more oil forTAPS. What you’re seeing is I recognizethe value in all resources.

Petroleum News: Talk about PointThomson. Where would you like to seethis by year’s end?

Parnell: I’d like to see a settlement, aresolution that’s in the state’s best inter-est, and more work in Point Thomson.That’s been one of the state’s bright spotsin exploration activity. I think there is aresolution that’s in the state’s best inter-est. At this point I wouldn’t call it immi-nent, but I think it’s possible. It’s animportant key because it holds a lot ofgas that’s crucial for the pipeline. �


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PARNELL Q&A


BP moves Liberty startup out to 2013By KRISTEN NELSON

Petroleum News

BP has moved the startup date for itsoffshore North Slope Liberty project

out to at least 2013. Initial production had been pegged for

2012, and in its “Fall 2010 RevenueSources Book,” published last November,the Alaska Department of Revenue listedLiberty production beginning at 5,000 bar-rels per day in fiscal year 2012 with pro-duction estimated to peak at 39,000 bpd infiscal year 2013.

The 2013 startup date surfaced Feb. 1 inmaterials BP presented at its 2010 resultsand investor update.

Liberty was listed as a project for whichthe final investment decision has been

made, but shown with a startup date of2013 to 2016.

Steve Rinehart, BP’s Alaska spokesman,told Petroleum News in a Feb. 2 e-mail thatthe 2013 startup date “is a further stepalong the path we have been following.”

He said the last public schedule BP gavefor Liberty had drilling beginning in late2011, with oil production in 2012.

Rig work suspended in NovemberBut in November, “we said we would

suspend construction on the rig while weconduct a thorough engineering and designreview, and that we would develop a newschedule as that review moved forward.”

“The project review is progressing, andour current estimate is oil production couldbegin in 2013,” Rinehart said.

Rinehart told Petroleum News in lateNovember that BP was going to “suspendconstruction on the rig itself for a period oftime,” described much of what would be

done as “a thorough engineering review”and called it “a decision to move aheaddeliberately.”

In July BP said drilling would delayedfrom late in 2011 to “likely” sometime in2012, after statements by federal and stateagencies that they would seek an environ-mental and safety review of Liberty follow-ing the Deepwater Horizon disaster in theGulf of Mexico.

The 100 million barrel Liberty field isin the Beaufort Sea, some 15 miles east ofPrudhoe Bay. Drilling is planned from theEndicott satellite drilling island some eightmiles west of Liberty, using ultra-extend-ed reach wells. �

On the WebSee previous Petroleum News coverage:

“BP takes timeout for Liberty rig review;will mean 100 fewer jobs,” in Dec. 5,2010, issue atwww.petroleumnews.com/pnads/558437109.shtml

Contact Kristen Nelson at [email protected]

The 2013 startup date surfaced Feb.1 in materials BP presented at its2010 results and investor update.

By KRISTEN NELSONPetroleum News

A laska North Slope production was at647,255 barrels per day on Jan. 1;

by the end of the month it had almostreached that level again, peaking at646,075 bpd Jan. 30, following shut-downs after a leak was found at PumpStation 1 on Jan. 8, and again mid-monthfor repairs.

January production numbers from theAlaska Department of Revenue’s TaxDivision show normal production at thebeginning of the month, followed by asteep decline — Alyeska Pipeline ServiceCo. shut the trans-Alaska oil pipelinedown completely for four days beginningthe morning of Jan. 8 — and then a shal-lower dip Jan. 15 when the line was shutdown for almost two days for the installa-tion of bypass piping.

Because of the extensive downtimeduring the month, January average ANSproduction was 471,666 bpd, down 26.5percent from a December average of641,518 bpd.

BP Exploration (Alaska)’s Milne Pointfield had the largest percentage dropmonth-over-month, down 33 percent,with a January average of 17,999 bpdcompared to 26,874 bpd in December.

The largest per-barrel drop was at theBP-operated Prudhoe Bay field, whichaveraged 233,259 bpd in January, down101,670 bpd and 30.4 percent from aDecember average of 334,929 bpd.

Prudhoe Bay includes satellite produc-tion from Aurora, Borealis, MidnightSun, Orion and Polaris.

All production averages downThe ConocoPhillips Alaska-operated

Kuparuk River field had the second-highest per-barrel drop, averaging101,999 bpd in January, down 27,324bpd and 21.1 percent from a Decemberaverage of 129,323 bpd. Kuparukincludes satellite production fromTabasco, Tarn, Meltwater and West Sak,as well as production from the PioneerNatural Resources Alaska-operatedOooguruk field. Department of Revenuefigures do not break out Oooguruk pro-duction; the most recent figures availablefrom the Alaska Oil and GasConservation Commission are for

November, when Oooguruk averaged8,942 bpd.

The ConocoPhillips’ operated Alpinefield averaged 70,358 bpd in January,down 16,288 bpd and 18.8 percent froma December average of 86,646 bpd.Alpine production includes the Fiord,Nanuq and Qannik satellites.

The BP-operated Lisburne field aver-aged 23,824 bpd in January, down 8,221bpd and 25.7 percent from a Decemberaverage of 32,045 bpd. Lisburne produc-tion includes Point McIntyre and Niakuk.

The BP-operated Northstar field aver-aged 13,746 bpd in January, down 5,124bpd and 27.2 percent from a Decemberaverage of 18,870 bpd.

The BP-operated Endicott field aver-aged 10,481 bpd in January, down 2,350bpd and 18.3 percent from a Decemberaverage of 12,831 bpd.

Cook Inlet crude oil production aver-aged 9,673 bpd in January, down 8.3 per-cent from a December average of 10,547bpd.

The temperature at Pump Station 1 onthe North Slope averaged minus 9.7degrees Fahrenheit in January, comparedto minus 11.8 F in December.

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


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Rollercoaster: ANS production back on parBy end of January Alaska North Slope crude oil production almost level with beginning of month, following spill driven shutdowns

AOGCC extended reinjection orderThe Alaska Oil and Gas Conservation Commission had authorized BP

Exploration (Alaska) to pump crude oil into designated development wells on anemergency basis while the trans-Alaska oil pipeline was unavailable.

The order, issued Jan. 11, was extended an additional two weeks on Jan. 21because the pipeline was unavailable at full capacity.

In extending the emergency order, the commission said repairs to the pipelinewere taking “longer than anticipated,” and while Alyeska Pipeline Service Co. hadcompleted installation of a piping bypass the line was “still not operating at nor-mal capacity. In turn, BP cannot operate at normal production,” the commissionsaid.

The order allowing BP to pump crude oil into development wells was issuedbecause without the ability to ship oil down the pipeline at normal volumes,“some production must be maintained to protect the safety of operating personnelin the fields and Deadhorse by providing fuel gas” and to prevent damage to pro-duction equipment and pipelines from freezing.

The initial order expired after 14 days and the commission said BP requestedthe extension because the trans-Alaska oil pipeline was still not operating at nor-mal capacity.

—KRISTEN NELSON

On the WebSee previous Petroleum News coverage:

“Trans-Alaska oil pipeline up and run-ning,” in Jan. 23, 2011, issue atwww.petroleumnews.com/pnads/728512344.shtml

“Winter shutdown,” in Jan. 16, 2011,issue atwww.petroleumnews.com/pnads/951089528.shtml


NATURAL GASEnergia Cura names pipeline Arctic Fox

A proposed small gas pipeline from Alaska’s North Slope to the state’s Interiornow has a name: The Arctic Fox Pipeline.

Energia Cura, a Fairbanks-based energy consulting firm and parent toFairbanks Pipeline Co., said in a Feb. 2 statement that the line was named afterCongressman Don Young, R-Alaska, commented that the proposed line would besmall, smart and quick.

Energia Cura met with Young Dec. 27 to discuss the value of the line, whichwould be a small-diameter high-pressure line moving volumes of gas justified forInterior markets.

Energia Cura said it has also met with Mike Nizich, chief of staff to Gov. SeanParnell, to reiterate a request for a due diligence review of the project and contin-ues to meet with Alaska leaders and others in the industry.

“We have substantiated the viability and profitability of an all-Alaska naturalgas pipeline and we openly invite the public and our public officials to review ourfeasibility study and economic analysis,” said Alex Gajdos, FPC co-founder. “Wewant our public officials to see that that there is a valid alternative to waiting fora big pipe. We can move gas to Alaskans now and prosper by owning the pipelineourselves. We can get gas to Alaskans now.”

FPC said it will continue to provide its documents to interested parties and willcontinue to post detailed updates on the firm’s website,www.fairbankspipelinecompany.com.

Energia Cura has constructed pipelines in Alaska and operates and maintains apipeline system connecting the trans-Alaska pipeline system to both North Polerefineries.

—PETROLEUM NEWS

http://www.pdstech.com/

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http://www.pesiak.com/

� F I N A N C E & E C O N O M Y

Weeks wants indiecredit extendedAsks Parnell to remove 2016 sunset provision on the Small ProducerTax Credit; credit pays for fields smaller than 50,000 bpd


Atiny North Slope explorer is askingthe State of Alaska to extend a tax

credit for small producers.UltraStar Exploration Managing

Member Jim Weeks sent a letter to Gov.Sean Parnell on Jan. 28 asking him toindefinitely extend the Small ProducerTax Credit. Parnell recently proposed aseveral revisions to the state fiscal regimefor exploration and production.

The Small Producer Credit pays up to$12 million per year to companies thatproduce less than 50,000 barrels of oilequivalent per day (and an increasinglysmaller credit for companies that producebetween 50,000 and 100,000 barrels of oilequivalent per day).

The credit is set to expire in 2016(although if a company brings a fieldonline between 2006 and 2016, then thecredit lasts for nine years from the start ofproduction).

Weeks believes it should be extendedindefinitely.

“Rather than have a specific year whenthe Small Producer Credit expires, I rec-ommend that it stay in place for eachreservoir or unit until payout of the explo-ration, delineation and development costsnecessary to get the oil flowing,” Weekswrote.

Because of the long lead time neededto develop reserves on the North Slope,Weeks hypothesized that companies likelywouldn’t get to claim the credit on anyproduction from leases acquired last year.He noted that it took UltraStar, the small-est explorer on the North Slope, six yearper well to drill. UltraStar may never get

to claim the credit.

Credit dates to MurkowskiThe Murkowski administration created

the Small Producer Credit in 2006 withthe Petroleum Profits Tax, an overhaul ofthe fiscal regime. The Palin administrationkept the credit when it revised the tax codein 2007 under Alaska’s Clear andEquitable Share.

The Parnell revisions are popularamong independents. A group of sixsmaller explorers issued a statement say-ing the bill “addresses the fundamentalconcerns of all companies that would liketo explore for and develop reserves on theNorth Slope.”

The companies are Armstrong Oil andGas (through its subsidiary 70 & 148),Brooks Range Petroleum Corp. (the oper-ating arm of the Alaska Venture CapitalGroup), GMT Exploration, Great BearPetroleum, Savant Alaska andRenaissance Alaska.

UltraStar Petroleum is exploring theDewline unit north of Prudhoe Bay andsouth of Northstar. The company drilledthe Dewline No. 1 well in early 2009 andis preparing to drill a follow-up well andsidetrack in the winter of 2011 and 2012.

Winstar Petroleum, a sister company toUltraStar run by all the same players,drilled Oliktok Point State No. 1 in 2003,but that well ultimately proved to be a dryhole.

The Parnell bill would lower the taxrate at new fields, cap production taxesand extend some Cook Inlet tax credits tothe North Slope, among other proposedrevisions. �


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GOVERNMENTBegich introduces Arctic oil spill bills

U.S. Sen. Mark Begich, D-Alaska, has introduced three bills aimed at safe andresponsible oil and gas development in the Arctic. The bills would initiate compre-hensive Arctic oil spill research and planning; require transport of oil ashore bypipeline; and provide Alaska with revenues from offshore development.

“Arctic oil and gas development is a necessary part of anycomprehensive national energy policy which is needed if weare going to reduce our dependence on foreign sources ofenergy,” Begich said in a statement.

The senator said the U.S. needs to “build the necessaryinfrastructure and do everything possible to prevent oil spills,but we also need to get moving on our oil and gas develop-ment to secure economic and national security.”

“And there’s absolutely no reason Alaskans shouldn’t gettheir fair share of revenues from our OCS development,” he

said. Versions of the

bills were also introduced in the lastCongress.

• The Responsible Arctic EnergyDevelopment Act directs the NationalOceanic and AtmosphericAdministration, the U.S. Coast Guard andother federal agencies to conduct researchto improve oil spill prevention, responseand recovery in the Arctic.

• The Resources for Oil Spill Researchand Prevention Act funds Arctic oil spill research and planning efforts by increasingthe per barrel contribution to the Oil Spill Liability Trust Fund by 3 cents per barrelfor domestic oil and by 7 cents per barrel for imported oil, amounts estimated toraise some $300 million annually.

• The Alaska Adjacent Zone Safe Oil Transport and Revenue Sharing Act securesa share of federal revenues from offshore oil and gas development for the State ofAlaska and Alaska’s coastal communities equal to that provided to Gulf Coast statesfrom drilling in the Gulf of Mexico. The bill also requires oil produced in federalwaters in the Chukchi and Beaufort seas to be brought to shore by pipeline.

—PETROLEUM NEWS

SEN. MARK BEGICH

Seamount reappointed to AOGCCAmong appointments submitted to the Legislature for con-

firmation by Alaska Gov. Sean Parnell on Feb. 1 was DanSeamount, reappointed as a member of the Alaska Oil and GasConservation Commission.

Seamount was appointed to the commission in 2000 andreappointed in 2005.

The term for which Seamount has just been appointedexpires in 2017.

Seamount holds the geologist seat on the commission andcurrently serves as chairman.

—KRISTEN NELSON DAN SEAMOUNT

The senator said the U.S. needsto “build the necessaryinfrastructure and do

everything possible to preventoil spills, but we also need toget moving on our oil and gas

development to secure economicand national security.”

Contact Eric Lidji at [email protected]

JUD

Y P

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ICK

http://www.nascoinc.com/

http://www.umalaska.com/

http://www.univarusa.com/


The commissioners of the Alaskadepartments of Revenue and Natural

Resources reported to the state LegislatureJan. 28 on reimbursements made by thestate under the Alaska Gasline InducementAct.

TransCanada Alaska Co. LLC andFoothills Pipe Lines Ltd. received the statelicense under AGIA in December 2008,and in exchange for commitments relatedto the project schedule, tariffs and futureexpansions, TC Alaska is entitled toinducements from the state including up to$500 million in matching reimbursementsfor qualified project expansions.

Reimbursements are at a rate of 50 per-cent of qualified expenditures prior to theclose of the first binding open season and90 percent thereafter. Qualified expendi-tures include costs directly and reasonablyrelated to advancing the project, andexclude overhead, lobbying and litigationcosts, civil or criminal penalties or fines, orexpenditures for assets or work productacquired or developed before the licensewas issues.

TC Alaska submits expenditures on amonthly basis and requests for reimburse-ment each quarter.

The Department of Revenue does a duediligence review on the expenditures and aseparate, high-level due diligence review ifdone by the state’s technical pipeline mon-itor.

Delay at end of FY 2010At the end of fiscal year 2010 (June 30,

2010), TC Alaska was behind in submittingreimbursement expenditures, partly due tothe addition of ExxonMobil to the existingreimbursement process. The state and TCAlaska focused on getting the reimburse-ment current and that was accomplished bythe end of October.

In fiscal year 2011, $250,000 wasappropriated for development of an AGIAinformation reimbursement system toimprove the collection, tracking, reviewingand reporting of project expenditures. Theautomated system is expected to be com-plete this May.

The first annual audit of TC Alaska was

completed by Martindale Consultants Inc.in November and covered expendituresreimbursed by the state through the calen-

dar year ending Dec. 31, 2009, which cov-ered four months of activity because ofdelay in submission of reimbursements.

ReimbursementsBy the end of fiscal year 2010, TC

Alaska had been reimbursed some $4.4million for expenditures submitted throughthe second quarter of 2009. The state saidthe addition of ExxonMobil to the project

delayed the rate at which TC Alaska couldsubmit expenditures.

To date, TC Alaska has been reimbursedsome $36.7 million at the 50 percent ratefor work submitted through the secondquarter of 2010.

TC Alaska has submitted a total of$92.2 million in gross expenditures forreview. The state took exception to $13.8



Wilcox: Alaska needs small independentsCo-founder of Cook Inlet Energy says big oil companies open basins, smaller companies needed for smaller geologic opportunities


J.R. Wilcox, the president and one of the co-founders ofCook Inlet Energy, says Alaska needs small independ-

ents to develop smaller geologic opportunities in the state,to keep larger fields producing and basically to keep thelights and heat on after the super majors move on.

Cook Inlet Energy took over fields in Cook Inlet whichhad been shut-in and has been returning wells to produc-tion.

“We’re currently producing a proud one-sixth of 1 per-cent of Alaska’s oil production,” Wilcox said.

Wilcox told the Alaska Support Industry Alliance’sannual Meet Alaska conference in Anchorage Jan. 21 hisfocus was on the role of small independents — and what theState of Alaska needs to do to encourage small operators.

Wilcox is a fifth-generation Alaskan and said hisfocus is on the long-term: His great-great grandfathercame to Alaska and his focus is on where Alaska will be100 years from now and what his great-great grandchil-

dren will be doing.

A noveltyThe state has a problem to address

and “that’s that Cook Inlet Energy isa novelty,” Wilcox said. “The mostremarkable thing about Alaska as anoil basin north of the Mexican borderis the almost complete absence ofsmall independents.”

He said he loves big oil compa-nies because “they can do all the things that small compa-nies can’t,” from building facilities and pipelines to advanc-ing technology.

“They’re the basin openers,” Wilcox said. But there are 8,000 to 10,000 operators producing oil

and gas in Texas; in Alaska there are eight, he said. Andwhile super majors account for 10 percent of the oil and gasproduced from state lands in Texas and large independentsaccount for another 20 percent, 70 percent of that produc-tion is from small independents.

Texas is not an anomaly, he said — the same holds truefor states like Oklahoma and Kansas.

“Small producers, while not doing the big sexy projects,are actually giving you your bread and butter production,”Wilcox said.

More focus neededAlaskans tend to focus only on the super majors, Wilcox

said: on attracting new investment from super majors toslow North Slope production decline; on bringing NorthSlope gas to market; on opening federal lands onshore andoffshore for development. Addressing those issues involvesdiscussions around a more stable fiscal regime and battlingwith the federal government for development.

But Alaskans also need to focus on another issue: “Howdo we create a vibrant class of independent companies?”

Looking into the future, “the most significant thing wecan be doing is trying to create a vibrant class of entrepre-neurs and the infrastructure that is going to create a statecapable of taking advantage not just of the very, very large

J.R. WILCOX

JUD

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see WILCOX page 13

� N A T U R A L G A S

Legislature gets report on AGIA paymentsTo date, TC Alaska has been

reimbursed some $36.7 million atthe 50 percent rate for worksubmitted through the second

quarter of 2010.

see AGIA REPORT page 14

http://www.alaskacargo.com/


� F I N A N C E & E C O N O M Y

BP’s Carson refinery one of 2 to be soldFacility near Los Angeles is major processor of Alaska North Slope crude oil; Washington’s Cherry Point refinery also uses ANS crude

By WESLEY LOYFor Petroleum News

Amajor destination for Alaska NorthSlope crude oil — BP’s Carson refin-

ery near Los Angeles — is going on the saleblock.

BP announced Feb. 1 it would sell theCarson refinery along with its troublesomeTexas City refinery as part of a continuingcampaign to divest up to $30 billion inassets to cope with the Deepwater Horizondisaster.

The London-based company said it aims

to complete the refinery sales by the end of2012, reducing its U.S. refining capacity byhalf. BP said it “expects significant marketinterest” in the large refineries.

The sale of the two plants “will make BPthe smallest refiner among its internationalcompetitors,” the company said.

But it emphasized it still will have a sta-ble of “higher quality refineries and relatedmarketing networks,” and that it plans refin-ery upgrades.

BP’s other refinery assets include theCherry Point, Wash., refinery, which alsotakes major deliveries of North Slope crude;the Whiting, Ind., refinery; and a 50 percentinterest in the Toledo, Ohio, refinery.

“These refineries have greater flexibilityto refine a range of crude oils includingheavy grades, and on average are morediesel-capable than BP’s current portfolio,”the company said. “They are also well-inte-grated with BP’s marketing operations.”

Carson refinery specsBP picked up the Carson refinery

through the ARCO acquisition in 2000.Located on 630 acres near the Long

Beach and Los Angeles harbors, the Carsonrefinery “is at the heart of an integratedfuels value chain stretching across southernCalifornia, Arizona and Nevada,” BP said.

It supplies 25 percent of Los Angelesgasoline demand and 50 percent of the jetfuel at the LAX airport, a BP fact sheet onthe Carson refinery says. The plant employsabout 1,200 people.

Carson processes 265,000 barrels ofcrude oil per day, including Alaska North

Slope, Middle East and West Africa crudes.Alaska crude accounts for about 70 percentof the refinery’s intake.

Tankers load North Slope crude at theterminus of the trans-Alaska pipeline atValdez and haul it south through the Pacificfor delivery almost exclusively to WestCoast refineries.

“The assets associated with the Carsonrefinery also to be divested include BP’sinterests in a cogeneration plant on therefinery site, crude and product terminalsand also its marketing interests,” BP said.“As part of this sale, BP expects to divestthe ARCO brand (though retaining brandrights for northern California, Oregon andWashington) and to retain ownership of andlicense the ampm brand.”

Texas City refineryBP acquired the Texas City refinery in

the 1998 merger with Amoco.It has been a troublesome property for

BP, the scene of a 2005 explosion that killed15 workers.

Located south of Houston nearGalveston Island, Texas City is the thirdlargest U.S. refinery, producing 3 percent ofthe nation’s gasoline supply. It runs 475,000barrels of crude per day, and in 2009processed 54 different types of crude fromall over the world, a fact sheet says.

“During the last few years, over $1 bil-lion has been invested in modernizing andimproving the plant,” BP said. “However,Texas City lacks strong integration into anyBP marketing assets.”

PIPELINES & DOWNSTREAMExxon still waiting for right of way

Alaska officials don’t plan to issue ExxonMobil a pipeline right of way for its PointThomson development until after the U.S. Army Corps of Engineers decides on a wet-lands permit for the project.

A spokesman for the Alaska pipeline coordinator’s office said staff has been work-ing diligently to draft a lease for the line, which would run 22 miles over state landalong the Beaufort Sea coast to connect the Point Thomson field with the Badamipipeline to the west.

The coordinator’s office expects to finish the draft lease by March and then shareit with ExxonMobil, spokesman Graham Smith said.

But the coordinator’s office, part of the Alaska Department of Natural Resources,won’t issue a final, signed lease until after federal regulators act.

“Long story short, we’re going to be waiting for the Corps on this one,” Smith said.The feeling is it would be more efficient to withhold the lease until after the Corps

finishes its environmental impact statement and issues its record of decision on thePoint Thomson development, Smith said.

But this could mean a considerable wait, as the Corps at last report was runningabout eight months behind on the EIS. The Corps said it expects to sign its record ofdecision on March 15, 2012.

PTE Pipeline LLC, a Houston-based affiliate of ExxonMobil Pipeline Co., appliedfor the state right of way in August 2010.

The pipeline, with a diameter of 12.75 inches, will carry natural gas condensateExxonMobil intends to produce from the Point Thomson field, located some 60 miles

see REFINERY SALE page 11

see RIGHT OF WAY page 11

http://www.HooverSolutions.com/


INTERNATIONALExxon’s Sakhalin-1 extended-reach record

Exxon Mobil Corp. said Jan. 28 that subsidiary Exxon Neftegas Ltd. has set arecord for extended-reach drilling at the Odoptu field, offshore Sakhalin Island inthe Russian Far East.

The Odoptu OP-11 well reached a total measured depth of 40,502 feet, 7.67miles, to set a world record for extended-reach drilling, Exxon said. The well alsoset a world record with a horizontal reach of 37,648 feet, 7.13 miles.

Exxon said the well was completed in 60 days using ExxonMobil’s fast drillprocess and integrated hole quality technology to maximize performance in everyfoot of hole drilled.

Odoptu, one of three Sakhalin-1 project fields, is five to seven miles offshorenortheast of Sakhalin Island. The extended-reach drilling process enables drillingoffshore beneath the seafloor from an onshore drilling site.

Six world recordsExxonMobil said that since the first Sakhalin-1 well was drilled in 2003, six of

the world’s 10 record-setting extended-reach wells have been drilled at the proj-ect. The specially designed Yastreb rig, used throughout, has set multiple industryrecords for measured depth, rate of penetration and directional drilling.

Since startup, Sakhalin-1 has produced some 300 million barrels of oil forexport and has supplied approximately 235 billion cubic feet of associated natu-ral gas to customers in Khabarovsk Krai, in far eastern Russia, for home heatingand to meet growing energy needs.

Sakhalin-1 includes the Chayvo, Odoptu and Arkutun Dagi oil and gas fieldsoff the northeast corner of Sakhalin Island. Potential recoverable resourcesinclude 2.3 billion barrels of oil and 17.1 trillion cubic feet of natural gas.

Exxon Neftegas operates the Sakhalin-1 project on behalf of a consortium thatincludes affiliates of the Russian state company Rosneft RN-Astra andSakhalinmorneftegas-Shelf, the Japanese corporation Sodeco and the Indian stateoil company ONGC Videsh Ltd.

—PETROLEUM NEWS

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

RCA denies APE’srequest for waiverRequires Armstrong, partners to submit two years of financialdata in order to get CPCN; Enstar pegs early March startup date


Alaska regulators have denied AnchorPoint Energy’s request to waive cer-

tain financial requirements as part of itsefforts to operate a new pipeline in thesouthern Kenai Peninsula.

Anchor Point Energy, a subsidiary ofArmstrong Oil and Gas and its four part-ners, recently applied for a certificate ofpublic convenience and necessity to oper-ate the new North Fork Pipeline. Thepipeline runs 8 miles from the North Forkunit, north of Homer, to the city ofAnchor Point, where it will connect intothe Southcentral grid.

Normally, a company applying for thecertificate must also provide two years ofaudited financial statements for all thecompanies with an ownership interest inthe business.

Anchor Point asked for a waiver of thatrequirement.

Anchor Point tried to make the casethat the North Fork Pipeline was a fairlyrisk free business and that the companiesinvolved with running it were financiallystable.

Application incompleteFor instance, Anchor Point noted that it

didn’t expect any “significant capitalneeds” once the pipeline went into opera-tion and that its “revenues are virtuallyguaranteed” because Enstar Natural Gasis committed to buying North Fork gasunder an approved long-term contract. Inaddition, Anchor Point said it has “nodebt” and is “adequately insured.”

The Regulatory Commission of Alaskaissued a public notice about the waiverrequest in early January, and received nocomments, but ultimately denied AnchorPoint’s request because the company

“failed to show good cause for waiver ofthe requirements.”

Because the RCA denied the waiver,the entire certificate application becameincomplete.

Now, Anchor Point will need to reap-ply. The company previously asked theRCA to allow it to operate the pipeline ona temporary basis in order to completefinal tests.

Anchor Point must file a new applica-tion by the end of February. Armstrongpreviously said it could bring North Forkonline by mid-February, under good cir-cumstances.

Enstar aiming for MarchOnce complete, the North Fork

Pipeline will connect to the SouthPeninsula Pipeline (previously known asthe Anchor Point Pipeline). The AlaskaPipeline Co., a sister company of EnstarNatural Gas, is building that line. TheSPP would in turn connect to the KenaiKachemak Pipeline that feeds into theSouthcentral regional transmission grid.

Enstar believes its new pipeline couldbe ready by early March.

The RCA is currently considering aninterconnection agreement between theSouth Peninsula/Anchor Point Pipelineand the Marathon-operated KenaiKachemak Pipeline. �

Anchor Point must file a newapplication by the end of

February. Armstrong previouslysaid it could bring North Forkonline by mid-February, under

good circumstances.


BP revealed its intent to sell the refiner-ies on the same day it announced theresumption of quarterly dividend paymentsto shareholders, drawing the ire of someGulf of Mexico residents who said they’restill hurting economically from theDeepwater Horizon spill. BP said it wouldpay a dividend of 7 cents a share for thefourth quarter of 2010.

Chief Executive Bob Dudley called BP“a company in transition” as a result of theoil spill, and that 2011 will be a year of“recovery and consolidation.”

“BP remains on track to meet its targetof up to $30 billion of divestments by theend of 2011, having concluded agreementsfor divestments totaling around $22 billionby the end of 2010,” a company pressrelease said.

The release noted the divestment pro-gram has not included any of BP’s invento-ry of future major upstream projects. �


REFINERY SALE

Contact Wesley Loy at [email protected]

east of Prudhoe Bay.The Point Thomson pipeline will cost

about $80 million to build, with annualoperating and maintenance costs of $12million, the PTE application said.

ExxonMobil is anxious to secure regula-tory clearance and get on with the develop-

ment, as it has pledged publicly to beginproduction of 10,000 barrels a day of con-densate by the end of 2014.

Aside from ExxonMobil, major PointThomson stakeholders include BP, Chevronand ConocoPhillips.

—WESLEY LOY


RIGHT OF WAY


http://www.alaskadreams.com/

http://www.aecom.com/


The Alaska Mental Health Trust LandOffice has issued Linc Energy an

underground coal gasification explorationlicense over 181,414 acres of Southcentraland Interior Alaska.

The license is broken into three generalareas, one on the east side of Cook Inlet nearNikiski, another on the west side of CookInlet near the Beluga Power Plant and a thirdin the Interior region of the state aroundAnderson, Healy and Nenana. The licensecovers almost all of the 190,000 acres theMental Health Trust offered in June 2010.

Linc Energy is an Australian independ-ent focused on underground coal gasifica-tion, a process for generating synthesis gasfrom deep coal deposits, as well as tradi-tional oil and natural gas exploration. Thecompany completed its first Alaska well inNovember.

That well targeted a conventional naturalgas reservoir and encountered “a number ofgas bearing horizons” and “a number of sig-nificant coal seams,” the company said.Linc also hopes to soon drill at its acreage atTrading Bay, on the west side of the CookInlet basin.

However, that work represented only“stage one” of Linc’s plans for Alaska, a wayto generate revenue and experience that canbe used toward underground coal gasifica-tion.

“The gaining of this acreage marks Linc

Energy’s entry into stage two of its Alaskaplan. In conjunction with our continuing oiland gas program, coal exploration for UCGwill be conducted aggressively over the next24 months,” CEO Peter Bond said in a state-ment.

20 billion tons ‘known’Linc arrived in Alaska in March 2010,

acquiring 123,000 acres near PointMacKenzie and Trading Bay from SanFrancisco-based independent GeoPetroResources.

Prior to picking up the Mental Health

Trust license, Linc estimated that its Alaskaleases overlaid some 20 billion tons of“known” coal deposits. The company didnot offer an estimate for the license area,other than to describe its coal potential as“extraordinary.”

“Alaska is shaping up to be one of thekey territories for Linc Energy to launch itsglobal energy operations,” Bond said. “It isa progressive jurisdiction and has significantinfrastructure as an important energy hub.”

Land managers use exploration licensesto generate activity in underexplored areasor for underdeveloped resources. Through alicense, a company pays for the right toexplore a broad area. If that work yieldspromising finds, the company can form tra-ditional leases.

In its June offering, the Mental HealthTrust proposed a seven-year license at $1per acre. If the licensing leads to leasing, theTrust proposed to offer the land for an initialfive-year term at $4 per acre per year thatcould be extended by five more years byproduction. �


cggveritas.com

Environmental Responsibility

CGGVeritas is committed to environmental responsibility in all our seismic operations. With experience working in some of the most sensitive regions of

Canada and the world, coupled with an industry-leading QHSE record, we can acquire your seismic data with minimum environmental impact.

Count on CGGVeritas to help you explore, develop and produce with confidence.

� L A N D & L E A S I N G

Linc gets UCG exploration licenseAlaska Mental Health Trust Land Office issues seven-year license over 181,414 acres; can later be converted to traditional leases

“In conjunction with ourcontinuing oil and gas program,coal exploration for UCG will beconducted aggressively over the

next 24 months.” —Linc CEO Peter Bond


GOVERNMENTMurkowski retains ranking member spot

U.S. Sen. Lisa Murkowski, R-Alaska, has retained her spot asranking member of the Energy and Natural ResourcesCommittee. Robert Dillon, a spokesman for the committee’sRepublican members, says Murkowski’s spot was confirmedduring a caucus vote Feb. 1.

Murkowski resigned her leadership post within theRepublican conference when she announced plans to run a write-in campaign last year. She took the outsider route after losing herprimary to Joe Miller.

Questions were raised about whether the caucus would stripher of her ranking position while she ran for re-election. But itdecided to let her keep the spot.Since winning her race, she has expressed confidencethat she’d keep her ranking title.

Republican committee members voted on the ranking spot. Their vote was voted onby the full caucus.

—THE ASSOCIATED PRESS

SEN. LISA MURKOWSKI

LIN

C E

NER

GY

http://www.cggveritas.com/


By WESLEY LOYFor Petroleum News

We’ve seen no shortage of calls inrecent weeks to permanently

block oil and gas exploration on thecoastal plain of the Arctic NationalWildlife Refuge.

The latest cameJan. 25 when U.S.Sen. Joe Lieberman,a Connecticut inde-pendent, introduceda bill, S. 33, to des-ignate the coastalplain as wilderness.

Also known asthe 1002 area, thecoastal plain encom-passes more than 1.5 million acres.

Nineteen of Lieberman’s Senate col-leagues, all Democrats with the exceptionof one other independent, signed on asco-sponsors of S. 33.

But Alaska’s Democratic senator,Mark Begich, was not among them. Heimmediately panned the idea of closingoff the coastal plain to oil and gas explo-ration and drilling.

“Ain’t gonna happen,” Begich said in a

Jan. 25 press release.

‘A dozen defeats’Twelve times since 1989, Lieberman

has either introduced or been a co-spon-sor of legislation to protect the refuge.

Lieberman recently announced hewon’t run for re-election in 2012.

“I have long believed that we have aresponsibility to future generations topreserve the Arctic National WildlifeRefuge, and I have fought to protect it foras long as I have been in the Senate,”Lieberman said. “The fact is, we do nothave to choose between conservation andexploration when it comes to our energyfuture; we can do both simultaneouslywhile moving toward a sustainable anddiverse national energy policy.”

The press release from Begich’s officepredicted S. 33 will fail, marking “adozen defeats for Lieberman’s bill.”

Regardless of party affiliation, Alaskalawmakers typically have supportedANWR oil and gas exploration. Thecoastal plain is seen as one of the last U.S.hopes for a multibillion-barrel oil strike,development of which would yield jobsand other economic benefits for the state.

Other conservation effortsANWR encompasses a total of 19.3

million acres in Alaska’s northeast corner.Oil and gas exploration and production

already is prohibited on the coastal plainpending authorization from Congress.The big question now is whether this pro-hibition will be permanent.

The Alaska National Interest LandsConservation Act of 1980 designatedmuch of ANWR as wilderness, butSection 1002 of the act set aside thecoastal plain for certain biological, seis-mic and geological studies. These studiesare largely complete.

The U.S. Fish and Wildlife Servicenow oversees the 1002 area as a “minimalmanagement” area — a status intended tomaintain existing natural conditions —and likely will continue to do so “untilCongress takes further action to decidethe fate of the coastal plain,” the agency’sANWR website says.

A congressional wilderness designa-tion, or something akin to it, could fore-close any chance for drilling on thecoastal plain.

The Fish and Wildlife Service is nowconducting a review on whether to rec-

ommend new wilderness designations inANWR, including the coastal plain.

U.S. Rep. Edward Markey, D-Mass.,on Jan. 5 reintroduced his perennial legis-lation to designate the coastal plain aswilderness. The bill, H.R. 139, says suchaction “will still leave most of the NorthSlope of Alaska available for the develop-ment of energy resources, which willallow Alaska to continue to contributesignificantly to meeting the energy needsof the United States without despoilingthe unique Arctic coastal plain of theArctic National Wildlife Refuge.”

Using the refuge’s 50th anniversary asa hook, environmental groups inNovember urged President Obama to des-ignate ANWR as a national monument.Such a designation effectively could endchances for oil and gas activity on thecoastal plain. �


� E N V I R O N M E N T & S A F E T Y

Lieberman’s last chance to close ANWR?Connecticut senator again offers bill to designate coastal plain as wilderness; Alaska’s Sen. Begich responds: ‘Ain’t gonna happen’

SEN. JOE LIEBERMAN


geologic opportunities but of the small andmid-sized geological opportunities.

“And over the long term, that’s what it’sgoing to take to realize the sustainable pros-perity and energy security in our state.”

With locally focused companies a lotmore oil and gas revenues will stay in thelocal area and be invested in energy or othersectors of the local economy, he said.

What’s needed?Cook Inlet production has dropped from

200,000 barrels per day to 10,000 bpd, butthere’s more oil and gas to be found, hesaid, and looking at mature basins else-where production declines and then risesagain as new technologies allow more pro-duction or as the oil price rises.

Wilcox said Cook Inlet is the leastdeveloped, developed oil and gas basin inNorth America: the crude quality is high;it’s next to the Pacific Rim and ready mar-kets; there is a refinery optimized for CookInlet crude; there is a favorable fiscalregime — but there still isn’t much goingon.

That’s because there are barriers toentry, including access issues and complexand unique systems for permits and taxeswhich make it difficult for small compa-nies. Systems more similar to other basinsin the Lower 48 and Canada are needed, hesaid.

Wilcox said the oil and gas system inAlaska evolved at a time when there werebig companies and small government andis based on negotiation, but with smallcompanies and a large government the situ-ation is different.

“It’s very easy even if the governmentisn’t being aggressive to just bowl over thesmall guy. So you really need to … changethat paradigm from a negotiation paradigmto a fostering business paradigm,” he said.

“If you get enough of a critical mass ofsmall companies in the local economicecosystem — making money, sharingexpertise … you start cutting down infra-structure costs because you’re sharingthings.”

That sector can be grown by loweringbarriers, creating “a clear and consistentregulatory regime” and easing up on someland restrictions. That will “broaden anddiversify our oil and gas production oppor-tunities” and result in “more stable anddurable production for this state,” Wilcoxsaid. �


WILCOX


http://www.seekins.com/

http://www.rodguides.com/

million and has not reimbursed thatamount; $2.5 million is being held pendingreceipt of additional information.

TC Alaska has submitted third-quarter2010 reimbursement claims for grossexpenditures of $22.3 million, claimswhich contain costs reimbursable at boththe 50 percent and the 90 percent matchingrates.

The next reimbursement is expected inlate February.

Reimbursements by general cost cate-gories include: $545,172 in generalexpenses (2 percent); $20,716,088 inpipeline related expenses (56 percent);$10,508,139 in gas treatment relatedexpenses (29 percent); $1,619,235 in envi-ronmental, regulatory and land expenses (9percent); and $3,345,903 in law and otherthird-party expenses (4 percent).

By region, 70 percent of the qualifiedexpenditures were in Alaska, 24 percent insouthern Yukon and 6 percent in BritishColumbia. �


ENVIRONMENT & SAFETYAlaska Forum on the Environment Feb. 7

The 13th annual Alaska Forum on the Environment begins Feb. 7 at theDena’ina Convention Center in Anchorage.

AFE offers more than 80 break-out sessions with a range of topics that include:climate change, human overpopulation, green buildings, conservation and recov-ery for polar bears, community gardening in rural Alaska, landfill alternatives,invasive species in Alaska, mining issues, youth environmental summit, hydro-electric projects, North Slope methane hydrates and carbon dioxide exchange,shipping in arctic waters, environmental justice issues, and impacts of poor solidwaste management on village health.

AFE runs Feb. 7-11. Detailed information on the keynotes and breakout ses-sions is available at the AFE website at: http://akforum.com.

—PETROLEUM NEWS

Begich pushes for Jones Act waiverU.S. Sen. Mark Begich, D-Alaska, is asking the U.S. Department of Homeland

Security to grant Escopeta Oil a waiver of the Jones Act in order to get a jack-updrilling rig to Cook Inlet.

Escopeta got a Jones Act waiver in 2006, on a previous attempt to bring a rig toAlaska.

As Escopeta once again prepares to bring arig to Alaska, the company asked the federalgovernment for an assurance that the 2006waiver is still valid, but in November, the U.S.Customs and Border Protection called the waiv-er “neither open ended nor transferrable.”

Because that answer left the matter some-what up in the air, Begich asked the Departmentof Homeland Security to issue the waiver nowso Escopeta can bring the rig up this year.

The Jones Act requires goods movingbetween U.S. ports to be carried on shipsflagged and built in the U.S., but the heavy-liftvessel Escopeta plans to use to move its Spartan151 jack-up from the Gulf of Mexico to Alaska is a foreign vessel.

Without a waiver, Escopeta would be forced to pay a fine. Rowan, the last com-pany to operate a jack-up rig in the Cook Inlet, chose to pay the fine rather than getthe waiver.

Buccaneer Alaska, another company looking to bring a jack-up rig to Alaska thisyear, hopes to avoid the Jones Act by purchasing a rig currently cold stacked inMalaysia.

—ERIC LIDJI

GOVERNMENT

The Jones Act requiresgoods moving between U.S.ports to be carried on ships

flagged and built in theU.S., but the heavy-liftvessel Escopeta plans touse to move its Spartan

151 jack-up from the Gulfof Mexico to Alaska is a

foreign vessel.


AGIA REPORT


final set of decisions will be made by north-erners as to whether it’s good enough to pro-ceed.”

Anne Marie Tout, president of the NWTChamber of Commerce, said the milestoneagreement gives the NWT the long-awaitedand “rightful ability to manage and controlpublic lands and to secure a share of rev-enues generated from those lands.”

Dene boycott signing Only two of the NWT’s seven aboriginal

groups — the Metis and Inuvialuit, whohave negotiated land claims and self-gov-ernment settlements in the oil and gas-richnorthwest corner of the NWT — signed thedeal. The rest including the Dene, whoseland covers about 40 percent of the plannedright of way of the MGP pipeline, boy-cotted.

Those five have appealed to PrimeMinister Stephen Harper to overturn whatthey call a “secretive bilateral devolutionnegotiation.”

However, Duncan said the pact will notinfringe on the rights of aboriginal negotia-tors or groups, but he could not say whetherthe full participation of all seven groups islegally necessary.

“We think there will be full participa-tion,” he said. “The agreement is predicatedon that occurring.”

Roland said it will be at least two yearsbefore the legal text of a “devolution”agreement is in place, giving aboriginalleaders ample time to make their case.

“Now we’ve come to a place … where afinal set of decisions will be made by north-erners as to whether it’s good enough to pro-ceed,” he said.

At stake is about 6 trillion cubic feet ofdiscovered gas on the Mackenzie Delta,backing the proposed Mackenzie GasProject, and an estimated additional 55 tcf

in the Delta and Beaufort Sea, plus 6.2 bil-lion barrels of onshore and offshore oil.

The NWT government has insisted allalong that a transfer of federal powers isnecessary to attract industry investment inresource development.

NWT production has peaked over thepast decade at about 20,000 barrels per dayof oil and 670 million cubic feet per day ofgas from the southern NWT, but gas explo-ration has gone into decline pendingCanadian government approval and corpo-rate sanctioning of the 1.2 billion cubic feetper day MGP and an associated liquidspipeline.

Currently resource royalties from theNWT go directly to Ottawa, which fundsmost of the NWT’s budget. The NWT hasthe highest per capita GDP of all provincesand territories at about C$90,000 for a pop-ulation of 43,500.

If the transfer of power takes place,Ottawa will make a one-time payment ofC$27 million in transition costs and C$65million a year to cover the NWT’s increasedexpenses.

Dene National Chief Bill Erasmus said“we’re not against devolution, but our peo-ple want to be equal partners and they wantto participate in developing the North in apositive way.”

Dehcho Chief Sam Gargan said the cur-rent deal does not give the NWT a largeenough share of resource royalties and doesnot protect the rights of Dene groups intheir land-claim and self-government talkswith Ottawa.

Of Canada’s other two territories, theYukon, with an estimated 900 million bar-rels of oil and 17 tcf of gas, signed aresource deal in 2003. Duncan said Ottawais committed to starting negotiations withNunavut, which, based on limited explo-ration, has an estimated 320 million barrelsof oil and 16 tcf of gas. �


TRANSFER

Contact Gary Park through [email protected]

EXPLORATION & PRODUCTIONUS drilling rig count up by 19 to 1,732

The number of rigs actively exploring for oil and natural gas in the U.S.increased by 19 the week ending Jan. 28 to 1,732.

Houston-based Baker Hughes Inc. reported that 913 rigs were exploring for gasand 809 for oil. Ten were listed as miscellaneous. A year ago, the count was 1,317.

Of the major oil- and gas-producing states, Pennsylvania gained 10 rigs,Louisiana gained five, New Mexico gained four, Alaska gained three, Coloradogained two and Wyoming gained one.

Arkansas and Oklahoma each lost two rigs and California, North Dakota andTexas each lost one. West Virginia was unchanged.

The rig count peaked at 4,530 in 1981, the height of the oil boom. The recordlow of 488 was in 1999.

—THE ASSOCIATED PRESS


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

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

AAcuren USAAECOM Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11Air Liquide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Alaska Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Alaska Analytical LaboratoryAlaska AnvilAlaska Cover-AllAlaska Division of Oil and GasAlaska Dreams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11Alaska Frontier ConstructorsAlaska Interstate Construction (AIC)Alaska Marine LinesAlaska Railroad Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Alaska Rubber & Supply Alaska Steel Co.Alaska TelecomAlaska Tent & TarpAlaska West ExpressAlaskan Energy Resources Inc.Alpha Seismic CompressorsAlutiiq Oilfield SolutionsAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Arctic ControlsArctic FoundationsArctic Slope Telephone Assoc. Co-op.Arctic Wire Rope & SupplyASRC Energy ServicesAvalon Development

B-FBaker HughesBald Mountain Air ServiceBristol Bay Native Corp.Brooks Range SupplyCalista Corp.Canadian Mat Systems (Alaska)Canrig Drilling TechnologiesCarlile Transportation ServicesCGGVeritas U.S. Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12Chiulista ServicesColville Inc.ConocoPhillips Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Construction Machinery IndustrialCrowley AlaskaCruz ConstructionDelta LeasingDelta P Pump and EquipmentDenali IndustrialDowland-Bach Corp.Doyon DrillingDoyon LTD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20

Doyon Universal ServicesEEIS Consulting EngineersEgli Air HaulEngineered Fire and SafetyEra AlaskaERA HelicoptersExpro Americas LLCExxonMobilFairweather LLCFlowline AlaskaFluorFriends of Pets

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N-PNabors Alaska DrillingNalcoNANA WorleyParsonsNASCO Industries Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Nature Conservancy, The . . . . . . . . . . . . . . . . . . . . . . . . . . .17

NEI Fluid Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5Nordic Calista . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14North Slope TelecomNorthern Air CargoNorthwest Technical Services . . . . . . . . . . . . . . . . . . . . . . . .7Oil & Gas SupplyOilfield Improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Opti Staffing Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7PacWest Drilling SupplyPDC Harris GroupPeak Civil TechnologiesPeak Oilfield Service Co.PENCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Petroleum Equipment & Services . . . . . . . . . . . . . . . . . . . . .7PND Engineers Inc.PRA (Petrotechnical Resources of Alaska)Price Gregory International

Q-ZQUADCORain for RentSalt + Light CreativeSchlumbergerSeekins Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Shell Exploration & ProductionSTEELFAB . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Stoel Rives3M AlaskaTA StructuresTaiga VenturesTEAM Industrial ServicesThe Local PagesTire Distribution Systems (TDS)Total Safety U.S. Inc.TOTE-Totem Ocean Trailer ExpressTotem Equipment & SupplyTTT EnvironmentalTubular Solutions AlaskaUdelhoven Oilfield Systems ServicesUMIAQ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2Unique MachineUnivar USA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Universal WeldingURS Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6UsibelliWest-Mark Service Center . . . . . . . . . . . . . . . . . . . . . . . . . .18Western Steel StructuresWeston Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8XTO EnergyYenney & Associates

Oil Patch BitsBrice family to be inducted into JAA hall of fame

Calista Corp. said that the Brice family was inducted into the25th annual Junior Achievement of Alaska’s Business Hall of FameJan. 27 at the Dena’ina Civic & Convention Center in Anchorage.The Brice family, founders of Brice Inc. in 1961 in Fairbanks becamea wholly owned subsidiary of Calista Corp. in July 2010.

Brice Co. was awarded numerous contracts during constructionof the trans-Alaska oil pipeline in the 1970s. In 2009 they werenamed Contractor of the Year by Alaska Business monthly andnamed Regional Small Business of the Year in 2001 by the U.S.Small Business Administration.

The Junior Achievement of Alaska honors leaders of Alaska busi-nesses. Selection is made by peers based on commitment to JuniorAchievement, direct and successful impact to Alaskan business, and a positive commitmentto the Alaska business community.

“The Brice family is honored and humbled with this recognition,” said Brice PresidentSam Robert Brice. “Our work doesn’t just represent our companies, but also our family.”

Global Diving & Salvage welcomes Juettner to AK Global Diving & Salvage said Jan. 26 that it is pleased to

announce the advancement of John Juettner to operations manager,Alaska Region. Juettner has been in the Alaska commercial divingindustry for the past 17 years. He has been working in operationalsupport and as a dive supervisor for the past 7 years. As operationsmanager, Juettner’s responsibilities will include asset management,estimating, logistical support and project planning for the Alaskaregion. “The development of this new position in our region andmore importantly, having John move into it will ensure that our cus-tomers receive the highest in customer service as well as the abilityto utilize his background and knowledge in working in this challeng-ing environment,” said David DeVilbiss, Alaska regional manager,Global Diving & Salvage.

Sullivan to participate in 2011 ExxonMobil OpenThe Alaskan Sled Dog & Racing Association said Jan. 26 that on Feb. 12 Mayor of

see OIL PATCH BITS page 18

SAM ROBERT BRICE JOHN JUETTNER

sale and since then has moved ahead with ageothermal exploration program involvingaerial surveys, ground surveying, surfacesampling and the small-bore drilling.

To date the company has invested about$5 million in its Mount Spurr project,Thomsen said. The company has drilledtwo slim holes to depths of about 1,000 feet— the plan is to continue with the slim-holedrilling, with core holes to depths of up to4,000 feet in 2011, and with the possibilityof drilling a full-size production well in2012, to determine whether there is a com-mercially viable geothermal reservoir, hesaid.

Customer neededHowever, the project has reached a

point where Ormat needs to find a poten-tial customer, willing to sign up to a powerpurchase agreement that can underpin therisk of funding the Mount Spurr work.

“As a company, we’re reaching the verytough decision of how much capital can weoutlay without having a guaranteed con-tract to take that power, and at what price isthat contract going to be at,” Thomsen said.

The project should produce 50 to 100megawatts of power, Thomsen said. Andwith an expected year-round reliability of95 percent or better, and with a constant,self-refreshing underground heat source, ageothermal power plant could contribute tomeeting the Railbelt’s base-load powerneeds, he said.

Ormat typically self finances a geother-mal project until the geothermal powerplant goes into operation, at which pointthe company refinances the project usinglong term debt — the relatively low projectrisk at that stage leads to attractive interestrates on the debt.

In the case of Mount Spurr project, thecompany has been using a $2 million grantfrom the Alaska Energy Authority, with thecompany matching that grant with $2.1million of its own money. The companyhas been recommended for a further $2million AEA grant, subject to further com-pany expenditure in excess of $3 million,Thomsen said.

Infrastructure costHowever, coupled into the financing

issues for the project is the question of thelikely $70 million to $80 million cost ofthe necessary power plant support infra-structure: a 40-mile power transmissionline from Mount Spurr to the nearest pointon the Railbelt power grid and about 25miles of permanent access road. Ormatanticipates holding discussions with thestate and with Chugach ElectricAssociation, the operator of the Belugapower plant where a transmission line fromMount Spurr would connect with the grid,about the appropriate mechanism for infra-structure funding, whether by privateindustry or by the state.

With an estimated construction cost perkilowatt hour capacity of $5,000 to $6,000,the cost of a Mount Spurr power plantwould be somewhat higher than the typical$3,000 to $5,000 per kilowatt hour of acomparable plant in the Lower 48. And thecosts and possible performance of the plantlead to a likely electricity cost of around 12cents to 13 cents per kilowatt hour, a figurethat is a few cents higher than the avoidedcost of using current sources of Railbeltpower, Thomsen said.

A reduction in geothermal royaltiesenacted by the state legislature in 2010 hasshaved about one cent off the projectedpower rate, but some additional incentive,perhaps a refundable tax credit, would beneeded to allow geothermal to compete ona straight cost basis, he said.

Fixed costBut although currently more expensive

to produce than, say, power a from a natu-ral gas-fueled plant, much of the cost ofgeothermal energy involves the amortiza-tion of the initial cost of the plant, thusoffering the enticing prospect of locking ina fixed power price over a 20-year period,while also enabling the generation of base-load power with virtually no environmen-tal impact. And a typical geothermal powerpurchase agreement conveys to the powerutility all of the green attributes of thepower source, such as the elimination ofsulfur dioxide, carbon dioxide and nitrogenoxides emissions, Thomsen said.

The proposed design for a Mount Spurrpower plant involves bring hot geothermalwater to the surface through a well, usingthat water to heat a secondary, low-boilingpoint fluid and then using the boiling ofthat secondary fluid to drive a turbine. Theused water would be re-injected under-ground into the geothermal reservoir,where geothermal energy would reheat thewater for re-use. And the secondary fluidwould also be continuously recycled.

Air coolingTaking advantage of the low prevailing

air temperatures on the flanks of Mount

Spurr, the facility could be air cooled toprevent water evaporation, thus eliminat-ing water depletion and thereby extendingthe life expectancy of the geothermalreservoir almost indefinitely into thefuture.

“Once we develop this project we havea lifetime supply of free fuel,” Thomsensaid.

And, so, the thorny question is whetherthe utilities, and hence the electricityratepayers, are willing to pay a bit morenow than the going electricity rate, to gainthe geothermal benefits of locking infixed future pricing and gaining the usean environmentally friendly powersource.

Some states have renewable energyportfolio standards that drive energy eco-nomics in a direction that tends to makegeothermal energy viable, Thomsen said.But Alaska, despite a state policy toincrease renewable energy use, does nothave a mandated standard to move theeconomic playing field. And so Ormat isfacing this financial gap between currentpower prices and the potential cost ofgeothermal power.

“If the state wants to help us with thatgap, we can offer the ratepayers a muchlower price,” Thomsen said. “If the state

can’t help us with that, we need to offerthe ratepayers a higher price, and thatcould or could not make the projectviable.”

Multiple utilitiesThomsen also commented that having

to deal with several interrelated Railbeltpower utilities complicates power pur-chase agreement negotiations. In theLower 48, there are typically one, or atmost two, utilities involved, he said.

On the other hand, the Railbelt utilitiesand the local communities all endorse theMount Spurr project, viewing MountSpurr geothermal energy as a near-termmeans of addressing concerns over tight-ening natural gas supplies, he said.

With the use of proven geothermaltechnology, the Mount Spurr project pres-ents little technical risk; the geologylooks very encouraging; and the projectpermitting has progressed smoothly. Theimmediate project challenge is to secure amarket for the geothermal power,Thomsen said.

—ALAN BAILEY



SPURR GEOTHERMAL

Contact Alan Bailey at [email protected]

http://www.nature.org/alaska

company had asked RCA for facility cer-tification by Dec. 1 and tariff approval bythe end of January in order to be able toproceed with facility construction andobtain project financing in a timely man-ner.

CINGSA is a joint venture betweenSemco Energy and MidAmerican EnergyHoldings Co., while Semco is also theparent company of Enstar Natural GasCo., the main Southcentral Alaska gasutility.

Significant challengeBeing the first gas storage that RCA

has had to regulate, the tight time framefor the CINGSA project has presentedsome significant challenges to everyoneinvolved in the regulatory process.

And during the RCA tariff hearingmuch discussion focused on the questionof the cost of any gas losses from thefacility, a cost traditionally passedthrough to gas consumers — it is impos-sible to completely eliminate any gas lossfrom a storage facility, so that relativelyminor losses are generally viewed as partof the cost of doing business, along withthe cost of gas used as fuel to power the

facility’s compressors.The parties involved in the RCA hear-

ing negotiated tariff language requiringRCA approval for the recovery of thecosts of extraordinary gas losses and pro-hibiting the recovery of the cost of lossesresulting from negligence. However,Commissioner Paul Lisankie disagreeswith the approval of the gas-loss sectionof the tariff. CINGSA has not been suffi-ciently specific in stating what gas lossesconsumers would have to pay for,Lisankie wrote in a minority dissentingopinion.

Other tariff concerns included thespecification of the costs that CINGSAwould be able to recover from its gas stor-age fees, and the manner of reconcilingthe facility’s initial fees, based in part oncost estimates, with subsequent feesadjusted to reflect actual costs.

CINGSA will charge fees to reservestorage capacity, to reserve withdrawalcapacity and for actual gas injections andwithdrawals.

Initial ratesInitial inception rates will be based on

capital expenditures and the known costof debt at the point of facility startup, plusestimates of the facility’s other costs.After one complete year of facility opera-tion, CINGSA will revise the rates using

actual costs, including the actual costs ofoperation, with CINGSA absorbing anycost overrun during that first year. Afterfive years of operation CINGSA will sub-mit a complete, revised tariff to RCA forapproval, using information gleaned fromexperience of operating the facility.

And, under an agreement associatedwith the tariff, Alaska Electric and EnergyCooperative, the wholesale power suppli-er to Homer Electric Association, hasjoined CINGSA’s list of initial customers,with Enstar, Chugach ElectricAssociation and Municipal Light &Power being the other customers.

In a separate order, also issued on Jan.31, RCA approved the ability of Enstar,CINGSA’s largest customer, to recovergas storage fees from gas consumers —there had been some concern that RCAmight approve the gas storage facility butat a later date limit Enstar’s ability torecover its gas storage costs.

However, the commission does requireall CINGSA customers to file any firmstorage agreements with the commissionfor review and approval.

Approval decisionIn its order approving the facility tariff

the commission provided a full explanationof its December decision to approveCINGSA’s certificate — normally the com-mission would consider both the certificateand the tariff in a single hearing, but in theinterests of early approval for the storagefacility CINGSA had asked the commis-sion to deal with the certificate first.

A key element in the approval decisionwas testimony by all parties involved in theRCA hearing that the Cook Inlet basinneeds a gas storage facility of the type thatCINGSA wants to build, and that CINGSAhas the financial wherewithal and manage-ment ability to build and operate the facili-ty.

As production from the aging CookInlet gas fields declines, a storage facilityavailable for hire by third-party companieswill enable utilities to warehouse summergas to boost gas deliverability in the winterand to provide contingency gas supplies inthe event of a gas-field equipment failure.The pumping of summer gas into the facil-ity will also enable gas wells to continueoperating year round, thus avoiding gasreservoir damage from well shut-ins in thesummer and reducing the need for expen-sive gas supply contracts involving largegas delivery swings.

Gas to meet peak winter demand isbecoming increasingly expensive, hearingwitnesses testified. And, without new gasstorage, peak gas deliverability will beforelong fall short of peak winter demand atany price, witnesses also said.

“We also find based upon the testimonyof the Enstar, Chugach and ML&P wit-nesses that those utilities urgently needthose (storage) services,” the commissionwrote in its Jan. 31 order. “We find basedupon CINGSA’s choice to develop theCannery Loop reservoir, and the utilities’choice to sign binding contracts (precedentagreements) that obligate them to supportCINGSA’s Cannery Loop project … that

CINGSA’s Cannery Loop project is nowthe only facility that can meet the utilities’urgent needs.”

Reservoir integrityVincent Goddard, president of Inlet Fish

Producers of Kenai, whose business facili-ties sit over part of the proposed Sterling Cstorage reservoir, has raised questions overthe physical integrity of the Cannery Loopreservoir. Goddard and his companies, col-lectively referred to as Inlet Entities, pre-sented evidence to RCA, saying that an oldgas well, the KU 13-8 well, in his propertypresents a significant risk of gas migrationfrom the reservoir and that the well needsremediation.

However, the RCA commissioners saythat they are relying on the Alaska Oil andGas Conservation Commission’s technicalanalysis of the storage reservoir and thatCINGSA must comply with any AOGCCstipulations relating to the reservoir integri-ty — under Alaska statutes AOGCC regu-lates the safety and integrity of gas wellsand gas storage reservoirs. In earlyDecember AOGCC approved gas injectioninto CINGSA’s facility while requiring theremediation of three existing wells.AOGCC did not mandate remediation theKU 13-8 well but did require CINGSA toinstall gas detection equipment next to thewellhead.

On Dec. 14 the Inlet Entities askedAOGCC to reconsider the question ofwhether the KU 13-8 well should be reme-diated and AOGCC is reconsidering thataspect of its injection order.

Field monitoringRCA said that it is concerned about the

possible cost to gas consumers of gas loss-es, especially if the KU 13-8 is not remedi-ated. But the commission cited a reportcommissioned by MidAmerican from con-sultancy firm Netherland, Sewell andAssociates. The report said that there arerisks associated with well remediation.Moreover, the report continued, routinefield monitoring techniques could detect agas leak through the well. And were a leakto be discovered, the well could subse-quently be fixed.

Another issue relating to the viability ofthe CINGSA storage facility is the questionof whether the Southcentral Alaska gaspipeline infrastructure will have the neces-sary capacity to handle the flow of gas toand from the facility. In testimony to RCAEnstar said that operation of the facilitymay require the installation of additionalgas compressors on the Enstar gas trans-mission line from the Kenai Peninsula toAnchorage, with the conversion of theCook Inlet Gas Gathering System underCook Inlet to allow the flow of gas from theeast side to the west side of the inlet per-haps providing another route for CINGSAgas.

Because CINGSA will not commencegas injection into its facility until April2012, there is sufficient time for the com-panies involved in gas storage usage to fig-ure out the required routing of the storedgas and then implement any necessarypipeline infrastructure upgrades, RCA saidin its order.

“In our view, making these changes isnot CINGSA’s responsibility,” the commis-sion said.

In its final order, RCA rejected arequest by Kenai Landing, a landowner inthe area of the CINGSA facility, to inter-vene in the CINGSA hearing. KenaiLanding is concerned about CINGSA’sright to requisition land for the facility,but the commission said that the petitionto intervene had come too late in the reg-ulatory procedure for acceptance. �



CINGSA

Anchorage Dan Sullivan, along with sever-al other municipal leaders, will convene atTozier Track to participate in the inaugural“Top Dog” Charity Sled Dog Race. Theevent will be held as part of theExxonMobil Open, which is one of the sea-sonal races organized by the Alaskan SledDog & Racing Association leading up tothe Fur Rendezvous Open.

The participant with the fastest timewill designate a $10,000 donation fromExxonMobil to the charity of their choice,along with bragging rights for the remain-

der of the year. Second place will desig-nate a $4,000 donation; third place willdesignate $3,000; and the fourth and fifthplaces will designate $2,000 and $1,000,respectively.

The event is open to the public andactivities start at 10 a.m.

For more information visit the organiza-tion’s website at: www.asdra.org.

Editor’s note: All of these news items— some in expanded form — will appearin the next Arctic Oil & Gas Directory, afull color magazine that serves as a mar-keting tool for Petroleum News’ contract-ed advertisers. The next edition will bereleased in March.


OIL PATCH BITS


http://www.amarinecorp.com/


Kuparuk River unit.BRPC estimates that the Brookian reser-

voir could contain some 35 million barrelsof oil and that the Kuparuk reservoir couldcontain an additional 6 million barrels ofoil.

Dedicated processing plannedIf they make a commercial discovery,

BRPC and its partners would likely build adedicated micro-processing facility to bringtheir crude oil to sales quality, but the loca-tion of North Tarn near the Alpine pipelinegreatly improves its economics.

“It’s a common carrier pipeline and we’reless than a mile away from it,” JimWinegarner, vice president of land andexternal affairs for BRPC, told PetroleumNews on Jan. 28.

North Tarn doesn’t need to be huge to beeconomic. “We think we could get therewith a discovery in the Kuparuk at that 6million barrels number,” Winegarner said.

Although the Kuparuk is deeper andsmaller than the Brookian, BRPC sees it as abetter bet because of the compartmentalizedgeology of the Brookian, notorious for caus-ing challenges across the North Slope fromTarn to Badami. “The Brookian formationwould be a great upside to have, but that’s alot riskier prospect,” Winegarner said.

Work under wayWork is already under way to build an ice

pad at the drilling site and a four-mile iceroad connecting the pad to drill site 2Mwithin the Kuparuk River unit. The compa-nies expect the well to take about 40 days tocomplete, from construction to the end ofdrilling.

The joint venture farmed-in six EniPetroleum leases at North Tarn in January

2010 and recently applied to form theSouthern Miluveach Unit, covering 56,460acres over the leases. “This well that we’redrilling is going to be the first work commit-ment that we’re proposing in the SouthernMiluveach unit,” Winegarner said. “Overall,we have a four-well commitment that we’reproposing for that unit, plus a seismic pro-gram.”

The unit application is still pending withthe Alaska Division of Oil and Gas.

BRPC operates a multi-company jointventure on behalf of TG World Energy andRamshorn Investments. The group isresponsible for some of the most activeexploration campaigns on the North Slope inrecent winters. The joint venture also ownsthe Tofkat prospect west of North Tarn, theBeechey Point unit in the Gwydyr Bay areanorth of the Prudhoe Bay unit and the

Slugger prospect south of the PointThomson unit.

BRPC is the operating arm of theKansas-based Alaska Venture CapitalGroup.

Still eyeing other prospectsOver the past five years, BRPC and its

partners have been among the most activeexploration companies on the North Slope,and among the largest leaseholders as well.

In addition to North Tarn, the companieshold the Tofkat and Slugger prospects, andthe Beechey Point unit, as well as manysmaller exploration blocks across the NorthSlope.

Tofkat is less than 10 miles west of NorthTarn, but Winegarner said that the distancebetween the prospects and the location ofTofkat along the Colville River mean the

two prospects are not automatically candi-dates for joint development. However,because the leases at Tofkat start to expirenext year, BRPC is considering applying fora unit soon.

Slugger is a prospect south of the PointThomson unit where the joint venture wantsto shoot a seismic program. Winegarner saidBRPC would be looking for potential part-ners for that program at the upcoming NorthAmerican Prospect Expo in Houston.

Since arriving in Alaska more than adecade ago, the various companies involvedin the joint venture have spent most of theirtime and energies on what is now theBeechey Point unit. The unit is in theGwydyr Bay region at the delta of theKuparuk River.

The companies have conducted most oftheir existing exploration work on the westside of the Kuparuk delta and now want toexplore several known oil accumulations onthe east side of the delta, hopefully as soonas the winter of 2011 and 2012, Winegarnersaid.

JV likes tax revisionsThe joint venturers are the only explorers

on the North Slope this winter, butWinegarner believes more would be work-ing if Gov. Sean Parnell’s new oil tax passesinto law.

“We could be drilling multiple wells thisseason instead of just one,” he said.

In particular, Winegarner likes the provi-sion that would extend a Cook Inlet tax cred-it on “well lease expenditures,” or intangibledrilling costs, to explorers on the NorthSlope.

The credit would cover drilling expensesthat aren’t for material objects, like surfacefacilities. “In an exploration well, that’s amajority of our costs,” Winegarner said. �


BRPC


CO

URT

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BR

PC


800 jobsThe 2011 drilling program would have

resulted in about 800 jobs in Alaska, whiledeferral of the program will further delaythe prospect of bringing more oil into pro-duction, delaying the creation of thousandsmore jobs in the future, Slaiby said.

In October Shell applied to the Bureauof Ocean Energy Management, Regulationand Enforcement for an application to drilla single well in its Beaufort Sea Sivulliqprospect in 2011. BOEMRE is still pro-cessing that application together with arevised version of Shell’s Beaufort Seaexploration plan — the agency has alsobeen conducting a supplemental environ-mental assessment for Shell’s plan.

“We’re working very, very well with theBOEMRE,” Slaiby said. “They’re not onlyworking on that (the supplemental environ-ment assessment), they’re working judi-ciously right now on our application for apermit to drill. So we’re guardedly opti-mistic that we’re going to see all this workfall into place with the BOEMRE.”

But Shell also needs an EPA permit forair emissions from the Beaufort Seadrilling operation.

LitigationIn 2009, following litigation over a pre-

vious attempt to obtain air permits forArctic outer continental shelf drilling,

Shell applied for major permits rather thanminor permits for its planned Chukchi Seaand Beaufort Sea drilling in the summer of2010. But following issuance of these per-

mits by EPA in April 2010, the NativeVillage of Point Hope and eight environ-mental organizations, including ResistingEnvironmental Destruction on IndigenousLands (or REDOIL), appealed the permitapproval to the Environmental AppealsBoard, the panel of judges with finalauthority over EPA decisions.

On Dec. 30 the Environmental AppealsBoard remanded Shell’s Beaufort Sea per-mit back to EPA, finding fault with theEPA definition of a stationary emissionssource and saying that the permit shouldhave taken account of a new rule for theemissions of nitrogen oxides. The EABrejected one of the other arguments againstthe permit but also said that it had notreached any view on several other claimsin the appeal.

On Jan. 21 EPA filed a petition with theEAB, requesting some clarification ofEAB’s Dec. 30 ruling and asking the EABto either rule on all claims in the appeal orto exclude the unresolved claims from theremand of the permit. EPA is concernedthat the lack of resolution of all appealclaims will lead to continuing delays in the

permitting process.“We maintain that the board’s remand

order erred in its treatment of the otherissues addressed in this case and that, if leftunaddressed, these errors will lead to fur-ther uncertainty, inefficiency and delay inresolving the Shell OCS-PSD Permits,”EPA wrote in its petition.

And in the interests of dealing with thepermit in an expedient manner, EPA alsorequested a ruling that any appeal over therevised permit should proceed direct tofederal court, rather than go back to theEAB.

—ALAN BAILEY

DOYON, LIMITED, the regional Native corporation for Interior Alaska

across the nation

CORPORATE VALUES

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The members of Alaska’s congressional delegation andAlaska’s governor were united in condemning the federal gov-ernment following Shell’s Feb. 3 decision to cancel its plans todrill in the Beaufort Sea this summer because of the uncer-tainty of permitting.

All released statements critical of the ObamaAdministration and the U.S. Environmental ProtectionAgency.

“I put the blame for this squarely on the EPA and theObama Administration who have taken virtually every oppor-tunity to block responsible development of Alaska’sresources,” said Sen. Mark Begich, a Democrat.

“The actions taken by this administration will result in allof us paying more for gasoline — not to mention the loss ofjobs and revenue that responsible development bring,” saidSen. Lisa Murkowski, a Republican.

Congressman Don Young, a Republican, said: “We aremaking it near impossible for companies to do business in theU.S.; where’s the incentive? It is absurd and foolish and com-pletely indicative of an Administration that has no interest inresponsible resource development or a thriving economy.”

Alaska Gov. Sean Parnell, a Republican, speaking at apress availability, called it “just another example of the feder-al government dragging its feet, killing jobs and making useven more reliant on oil from the Middle East and elsewhere,where as we can see from the situation in Egypt it’s veryunstable.”

Begich said he has “talked to EPA Administrator Lisa

Jackson multiple times, and will continue to make the case forShell to be able to move forward with exploration.” He saidShell hopes to get the air permits it needs for 2012, and saidhe would continue to work with the company and EPA tomake that happen.

“It is shameful to see another season lost,” Begich said. Murkowski, the ranking member of the Senate Energy and

Natural Resources Committee, said, “The EPA’s refusal, orsimple inability, to issue key permits in a timely fashion isindefensible,” and called on the administration to reviewEPA’s handling of Shell’s permit applications.

She said the inability of the federal government “to processa straightforward air permit calls into question its willingnessto support a rational energy policy.”

Young said “any attempt at project development is shutdown by the EPA,” called the administration’s talk about jobsjust lip service and said the country is being crippled. “Theywon’t be happy until we’ve run all business out of the countryand we’re back to traveling on dirt roads in covered wagons.”

“It’s unfathomable that a company … can buy federal leas-es but can’t get onto them,” Parnell said. “It’s also unfath-omable that they cannot get an air permit after five years oftime that they can get in the Gulf of Mexico in a mattermonths.”

—KRISTEN NELSON


SHELL DECISION Begich, Murkowski, Young, Parnell slam feds


Slaiby said that as a result of thedeferral of its Beaufort Sea

drilling, Shell expects to farm outin 2011 most of the assetsearmarked for the drilling

operation.


http://www.kenworthalaska.com/

http://www.doyon.com/


an explorer, alone

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