Duvall ‘on board’ · July 1 in-state gas line report could warrant special session just on that issue 9 AIDEA revises jack-up agreement Changes aim to give AIDEA more assurances

Vol. 16, No. 22 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of May 29, 2011 • $2

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

� G O V E R N M E N T

� L A N D & L E A S I N G

page3

House Speaker Mike Chenault saysAGIA, oil taxes, high priorities

The May issue of North of 60 Mining News is enclosed

May Mining News inside

PHOTO COURTESY HEATHERDALE RESOURCES LTD.

Heatherdale Resources Ltd. has spent some US$20million on exploration at the Niblack gold-copper-zinc-silver project in Southeast Alaska. Now con-templating the viability of building a mine at thatprecious metals-enriched volcanogenic massive sul-fide project, the young junior has added Delta, anearlier stage VMS prospect located in easternInterior Alaska, to its portfolio. Page 3

A special supplement to Petroleum NewsWEEK OF

May 29, 2011

A special supplement to Petroleum News

6 New CEO marks evolution of junior Tower Hill founder Pontius makes room for operations exec at Livengood

12 Golden Predator stalks Yukon gold Junior turns focus on past-producing Brewery Creek with C$6M exploration

17 Canadian diamonds glimmer in 2011Price recovery drives expanded exploration, development of NWT stones

Torok sandstones in Brooks Rangeshow evidence of gas accumulations

It sometimes seems as if optimism over natural gasresource potential in Arctic Alaska rises at about the samerate as optimism falls over finding a means of bringing thatgas to market. On May 9 at the annual meeting of the PacificSection, American Association of Petroleum Geologists, afew months after the U.S. Geological Survey rebranded theNational Petroleum Reserve-Alaska as a gas province, and afew days before ConocoPhillips and BP threw in the towel ontheir hopes of building a North Slope gas line, scientists fromSuncor Energy described an exciting gas play that they havebeen investigating in the Brooks Range foothills. The play

Tried-and-true options: Canada’sHarper mostly counts on veterans

Canadian Prime Minister StephenHarper said on election night May 2 thatCanadians don’t like surprises. He has-n’t pulled any.

He also promised “strong, stable”government if voters gave hisConservative party a majority win. Ifthat means sticking with tested perform-ers, he’s delivered.

In naming a cabinet that was littlechanged from its pre-election makeup,Harper showed he will rely heavily on proven veterans toguide Canada through the next four years and keep his gov-ernment on track.

see TOROK SANDSTONES page 20

STEPHEN HARPER

see HARPER page 19

Duvall ‘on board’Napolitano acknowledges SC Alaska energy needs; will mitigate jack-up fine

Sullivan names DNR teamBill Barron at DO&G, Brent Goodrum at DML&W, Kurt Gibson as AGIA

By KRISTEN NELSONPetroleum News

Department of Natural ResourcesCommissioner Dan Sullivan has

filled three positions at DNR, calling astrong leadership team critical in imple-menting the governor’s vision ofincreased throughput in the trans-Alaska oil pipeline.

He introduced the new members ofthe DNR team at an Alaska SupportIndustry Alliance meeting in Anchorage May 26.

Bill Barron, formerly of Marathon and mostrecently of CH2M Hill, is the new director of theDivision of Oil and Gas; Brent Goodrum, a retired

Marine Corps infantry officer, is the new directorof the Division of Mining, Land and Water; andKurt Gibson, formerly deputy director of theDivision of Oil and Gas, is the new Alaska Gasline

Chukchi sale EIS redoneNew draft considers potential of ‘very large oil spill’; final required by Oct. 3

By ERIC LIDJIFor Petroleum News

Federal regulators have released revised envi-ronmental documents for oil and gas leasing

in the Chukchi Sea, a small step toward allowingexploration in Arctic waters.

The Bureau of Ocean Energy, Management,Regulation and Enforcement, or BOEMRE,released a revised draft on May 20 of its supple-mental environmental impact statement for aFebruary 2008 lease sale in the outer continentalshelf of the Chukchi Sea where Shell,ConocoPhillips, Statoil and others purchased leas-es for oil and gas exploration.

“This Revised Draft SEIS offers additional sci-entific, environmental and technical analysis that

will assist in future decisions pertaining to theleases issued in Sale 193 in the Chukchi Sea,”BOEMRE Director Michael R. Bromwich said ina statement. “Because of what is at stake, it isextremely important that we continue to make thisa transparent process that encourages the maxi-mum amount of public participation.”

BILL BARRON BRENT GOODRUM KURT GIBSON

see DNR TEAM page 20

“Because of what is at stake, it isextremely important that we continue to

make this a transparent process thatencourages the maximum amount of

public participation.” —BOEMRE Director Michael R. Bromwich

see CHUKCHI EIS page 17

By KAY CASHMANPetroleum News

R obert Duvall won’t beon board the Kang

Sheng Kou when it offloadsEscopeta Oil’s jack-up rigMay 29, but he will be mak-ing a trip north once Escopetastarts drilling for oil and nat-ural gas in Alaska’s CookInlet.

A long-time friend of Houston-based EscopetaPresident Danny Davis, Duvall is a staunch sup-porter of domestic oil and gas drilling.

“Alaska’s got plenty of oil and gas that we needdown here,” Duvall said in a May 26 interview

with Petroleum News. It’spreferable to importing ener-gy from foreign sources, suchas the Middle East, he said.

“About the best thing wecould do is let Danny drill upthere. That would be great.”

An added bonus forAlaskans and the well knownactor and director is thatDuvall plans to visit

Escopeta’s Spartan 151 jack-up once it starts drilling, as a show of support.

“Alaska’s the only state I haven’t been to. I planto support what Danny’s doing up there, as well asget in a little fly fishing,” he said.

ROBERT DUVALL DANNY DAVIS

see JACK-UP RIG page 18

JOSH

JEN

SEN

http://www.PetroleumNews.com/

http://www.miningnewsnorth.com/

2 PETROLEUM NEWS • WEEK OF MAY 29, 2011

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

6 AEA seeking legal team for FERC permit

5 Kendall named Alaska regional director

8 Sullivan: Permitting a focus for DNR

4 Off-road travel closes on North Slope8 BP to replace Prudhoe VSMs this summer

7 Wildfires rage across Alberta

13 $1.2 million budgeted for hydro project

13 Interest builds for Arctic seaport

14 Loan guarantee boosts line’s prospects

11 Potential Alaska state and federal oil and gas lease sales

EXPLORATION & PRODUCTION

ENVIRONMENT & SAFETY

ALTERNATIVE ENERGY

UTILITIES

GOVERNMENT

11 Chugach to sell to Seward through 2016

Utility asks RCA to extend existing contract another five years; Seward soon to be Chugach’s only regular wholesale customer

12 Proposed unit off ANWR advances a bit

Donkel Oil & Gas unit would take in seven leasescovering 21,354 acres; unit application deemed‘complete,’ ready for public comment

10 Wielechowski appeals for ACMP renewal

Begich says loss of coastal zone program will hurt oil, gasdevelopment, jeopardize deepwater port off North Slope

3 AGIA justification remains high priority

Chenault says oil tax up to Senate, which has bill; July 1 in-state gas line report could warrant special session just on that issue

9 AIDEA revises jack-up agreement

Changes aim to give AIDEA more assurances thatit won’t lose investment if Buccaneer and Ezion default, could delay drilling

4 EPA re-proposing Cook Inlet discharges

EPA puts less stringent limits back out for publiccomment, but also adds more stringent limits as a possible back-up plan

6 Conoco seeks 17% TAPS increase

Request is the fourth since October 2008 for thecompany and would increase tariffs nearly threefold over last permanent rates

7 USGS plans seismic survey in Bering Sea

Shoot is part of effort to delineate potentially resource-rich extended continental shelf; survey also planned in Gulf of Alaska

NATURAL GAS

PIPELINES & DOWNSTREAM

Torok sandstones in Brooks Range showevidence of gas accumulations

Tried-and-true options: Canada’s Harper mostly counts on veterans

SIDEBAR, Page 19: Alberta’s oil sands cash cow

ON THE COVERDuvall ‘on board’

Napolitano acknowledges SC Alaska energyneeds; will mitigate jack-up fine

Sullivan names DNR team

Barron at DO&G, Goodrum at DML&W, Gibson as AGIA coordinator

Chukchi sale EIS redone

New draft considers potential of ‘very large oil spill’; final required by Oct. 3

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AGIA justification remains high priorityChenault says oil tax up to Senate, which has bill; July 1 in-state gas line report could warrant special session just on that issue

By STEVE QUINNFor Petroleum News

House Speaker Mike Chenaultbelieved it was time to go home, so

he adjourned the Legislature’s special ses-sion three days before the 30-day limitexpired.

The Legislature, he says, had done allit could, including failing to overcome animpasse with coastal zone managementlegislation, which failed by one vote inthe House.

He’s taking heat for not casting thedeciding vote in favor of a bill that divid-ed the House and Senate on two issues.

They are: Giving weight to localknowledge of an area versus scientificevidence; removing a coastal policy boardmember for cause rather than that mem-ber serving at the pleasure of the gover-nor.

The Legislature can stillcall itself back into anotherspecial session to iron outthe differences by July 1,the day the current lawexpires.

Meanwhile, Chenault says lawmakersstill have plenty of work to do until theyformally meet again.

And when they return, a priority willbe HB 142 which calls for “evidence ofprogress,” according to a bill analysis.

He sat down with Petroleum News todiscuss resource development prioritiesmoving forward.

Petroleum News: Just a few days afterthe special session ends, and you’re hitwith news that Denali no longer believesa large-diameter pipeline is economicallyviable. What does the announcementmean to you?

Chenault: Even the energy departmentsaid it could be delayed at a minimum of20 to 30, maybe 40 years because of theshale gas finds in North America. Theyare figuring they have a 100-year supplyof gas. So it wasn’t surprising that it cameout. It was a tough sell to start with.There were a lot of uncertainties.

Petroleum News: Does this lend cre-dence to your concerns outlined in HB142?

Chenault: I think that it does. We’llwait and see what, if anything,TransCanada comes back with. It’s beenquite a while. I don’t know why

TransCanada isn’tcoming out with anymore information.Tony Palmer saidthey are aboutthrough with every-thing they can final-ize. It will be up tothe State of Alaskato negotiate fiscalterms with the ship-pers and finalize what’s going on withPoint Thomson. They said when this thingwas passed that no gas line would moveforward without fiscal terms and the stateneeds to negotiate those with the shippers.

Petroleum News: Is it time to startdoing that or do you need to know morebefore you move forward?

Chenault: We have to have some kindof project out there that looks like it

might go forward before we getthere. I wouldn’t have a prob-lem negotiating terms, butuntil we see there is a projectthere to ship gas, I’m notsure exactly when the right

time is to negotiate terms.

Petroleum News: OK, so HB 142 did-n’t advance to the Senate. Will you con-sider recasting it with the appropriatedeadlines seeking answers from DNR andRevenue?

Chenault: It’s unfortunate that we gotaway from that to deal with budgetaryissues. I think it would have been a goodpiece of legislation to pass. It would haverequired DNR and Revenue to come backto say that project was still economicallyviable. In turn that would save the Stateof Alaska money. As it is right now, it’slaying dormant until next session. It willbe one of my high priorities to get itpassed out of the House at the beginningof next session and get it over to theSenate. We will be a year and a half fromthe open season by then. If that project isgoing to go forward, we should haveinformation back by then.

Petroleum News: You adjourned with-out a coastal zone management plan. Sen.Stedman said last week he thought thatyou or the Rules Chairman (Rep. CraigJohnson) should have changed your vote,accepted the conference committee ver-sion, then pursued a clean-up in January.

Chenault: They were offered another

deal twice on the last night of session.That was to accept the House version plusthe original five changes that were agreedon by the administration, industry and allof those who were involved without theother two the senate had tried to put intothe bill. They refused to do that. I wentdown later as a final olive branch andexplained I thought the bill would die onthe House floor if we couldn’t make somechanges. You know, they could have donethe exact same thing, accept the 40-0House vote that went to their side, thencome back next year and clean up someremaining issues.

It was a finely tuned compromise byindustry, administration and the Houseand I know (North Slope BoroughMayor) Edward Itta helped work on it.The House has worked for two years onthis. It was finely crafted. They made fivechanges and it was agreed upon. Thenthey made a couple more, and unfortu-nately it wasn’t agreeable for enoughHouse members to pass the bill. So itcould have worked both ways. They cer-tainly could have accepted the House’sversion and come back and tried to addmore things to it next year versus lettingit die.

Petroleum News: Just as you folkswere adjourning, President Obama saidthat he wants to loosen things up fordevelopment at NPR-A. Is that cause foroptimism or cautious optimism?

Chenault: I want to hear more.Certainly, there is optimism there but

what’s the time frame? Are we talking twoyears, five years, 10 years or 20 years?It’s always easy to talk about it. It’stougher to get it done, though. If thePresident is going to throw that out thereas an option, then he needs to get behindit as soon as possible.

Petroleum News: What are your otherpriorities during the interim?

Chenault: Around July 1, we shouldget a report back from the Alaska in-stategas line team headed by Dan Fauske. Wewill go through that information. Myunderstanding is there is a trove of infor-mation there. It’s not something we willbe able to glean in just a few minutes andsee what’s there. It’s going to take sometime to go through and see what allthey’ve researched, what all they’velooked at. What’s their best guess is interms of a project? And if we have a proj-ect there, what the cost is. I would suspectlater on that would all be rolled out to theLegislature and the Legislature wouldhave a chance to look at it. Depending onwhat’s there, I would be open to lookingat a special session to deal with it.

As a Legislature we need to look atprojects being proposed. You have GreatBear and their project. From what little Iknow of it. Seeing what they proposed asfar as 200 wells a year. We need to ask:What is that going to entail? Can ourdepartments handle that kind of load?What kind of infrastructure needs to be

PETROLEUM NEWS • WEEK OF MAY 29, 2011 3

see CHENAULT Q&A page 5

MIKE CHENAULT

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CORRECTIONCorrection: $875 million, not thousand

There was a page 1 article in the May 22 edition of Petroleum News aboutCook Inlet Energy, titled “Redoubt start-up close; CIE to drill up to 6 inlet gasprospects.” In background information about the company, we reported that thevalue of the assets it purchased from Pacific Energy Resources was $875,000, perCIE parent Miller Energy Resources.

In fact, Miller valued those assets at $875 million.

EXPLORATION & PRODUCTIONOff-road travel closes on North Slope

North Slope winter off-road tundra travel in the eastern and western coastal areasclosed May 21.

In announcing the closure, the Alaska Department of Natural Resources’ Divisionof Mining, Land and Water said all off-road travel must be completed by May 24.

The division said weather conditions in the western and eastern coastal tundraopening areas were expected to be near or above freezing for the foreseeable futureand combined with previously observed amounts of snow pack deterioration, condi-tions were no longer adequate for general off-road travel.

Snow may be adequate for travel in some areas and the division said it will con-sider granting travel extensions on a case-by-case basis. Exceptions must have priorapproval of an authorized representative of the division.

Foothills closed May 18Winter off-road travel in the upper and lower foothills tundra opening areas closed

May 18, with May 21 the deadline for completing any off-road travel in progress. The division said it was not aware of any off-road travel projects under way in the

upper and lower foothills area and said it would not be granting any new off-road trav-el requests.

Summer off-road travel in both foothills and coastal areas may begin on or afterJuly 15 and applies only to holders of valid permits with specific project approval.Summer off-road travel is further limited to vehicles approved by the division for off-road travel.

—PETROLEUM NEWS

� E N V I R O N M E N T & S A F E T Y

EPA re-proposingCook Inlet dischargesEPA puts less stringent limits back out for public comment,but also adds more stringent limits as a possible back-up plan


The U.S. Environmental ProtectionAgency’s attempt to permit discharges

from oil and gas facilities in Cook Inlet tooka step forward recently by taking two stepsback.

The EPA is re-proposing less stringentlimits for six substances commonly dis-charged from oil and gas operations —including mercury, copper and silver — intoCook Inlet. But it also re-proposed olderand more stringent limits for those samesubstances and came up with a strategy fordeciding when it would use one set of lim-its or the other.

The limits are categorized by platformand by substance.

The limits come as part of a GeneralPermit under the National PollutantDischarge Elimination System. Created in1972, the NPDES is a federal water pollu-tion control program, often managed by thestates, that regulates discharges into water-ways.

The permit is particularly knotty becausemore stringent limits could force operatorsto modify platforms in Cook Inlet, upgradesthat might prove uneconomic. But conser-vationists in the region worry about theimpact of discharges on local fisheries.

The EPA is taking comments on its re-proposal and plan through June 20.

Controversial exceptionsThe Cook Inlet drilling platforms built in

the 1960s discharged drilling waste and pro-duced water directly into the sea. The EPAintroduced zero-discharge standards for off-shore platforms in 1995, but gave an excep-tion to Cook Inlet platforms, saying it wouldbe impractical to retrofit the facilities, espe-cially considering their limited lifespan.

That exception continues to rile environ-mental groups, commercial fishermen andsome Native villages in the region, whoclaim that the discharges — even at regulat-ed limits — impact important subsistence,commercial and recreational fisheries inCook Inlet. The oil industry, meanwhile,argues that the strong tides in Cook Inletquickly disperse the waste materials, andpoint to studies finding no evidence of

industry contamination. When the EPA renewed the general per-

mit for oil and gas facilities in Cook Inlet inMay 2007, it increased previous limits fordischarges into the water. To avoid “back-sliding,” federal law requires the EPA tomake sure any less stringent standards stillcomply with state-level “anti-degradationpolicies” that guide water quality standards.

9th Circuit challengeThat June, a coalition led by Cook

Inletkeeper challenged the new general per-mit in the U.S. Court of Appeals for the 9thCircuit. Among other complaints, they saidthe anti-degradation policy in Alaska need-ed work. In particular, they said the AlaskaDepartment of EnvironmentalConservation needed to put the policy upfor public notice and comment, and neededto craft a plan explaining how it wouldimplement the policy.

The EPA ultimately agreed. In late 2010,the court told DEC to issue a public noticeabout the certification and take commentson it, and to issue an implementation plan.

In addition to Cook Inletkeeper, theplaintiffs included United Cook Inlet DriftAssociation, Cook Inlet Fishermen’s Fund,the Native Village of Port Graham and theNative Village of Nanwalek. Trustees forAlaska represented the coalition.

In early May 2011, the DEC gave theEPA a draft certification for the less strin-gent 2007 limits — a final certification willeventually be required — including an anti-degradation analysis. The EPA is now re-proposing the 2007 limits and taking publiccomment.

While the EPA said it believes the draftanti-degradation analysis will be enough tomeet the exceptions to the backsliding pro-vision, it is also re-proposing the more strin-gent limits from the earlier general permit incase that backsliding exception doesn’tapply.

The EPA is taking comments on thatstrategy, as well as on the re-proposed lim-its, but is not taking comments on howthose older, more stringent limits were cal-culated. �

Contact Eric Lidji at [email protected]

http://www.deltappump.com/

http://www.gdiving.com/

built in order to facilitate that amount ofdrilling? Do they have the backing and soforth? If they don’t what does the stateneed to do to incentivize or try to makethat project go forward to try to fillTAPS? It’s important on both aspectswhether it’s gas or whether it’s oil that wedeal with those issues. How do we putmore oil in the pipeline? How do we getmore investment into the state? That’swhat we, as a Legislature, need to worktoward.

Petroleum News: Oil tax, would youwant to revisit that during special session,too, or would you want to focus on in-state?

Chenault: If we had a special sessionin the fall to deal with the report backfrom Fauske on in-state gas, we wouldwant to limit ourselves to just that project.You get mired down in the politics if youwere to throw the oil tax back in the mix.It would just muddy the water. What wedon’t want to do is muddy the water.What we want to do is look at the optionthat they are going to propose. If it’s agood, sound project, then we need todecide whether we move forward basedupon that information and not try tomuddy it up with oil taxes or any otherissue out there. If we are going to take upoil taxes, then we need to take that up as aseparate issue. The House has passed abill. It’s on the Senate side. It would be upto them to run with that piece of legisla-tion to come up with a compromise ifthey pass it.

Petroleum News: A few things havehappened since then that some believecould change dynamics of the conversa-tion: heavy oil coming out of the ground;(ConocoPhillips CEO) Jim Mulva’s com-ments; (BP Alaska President) JohnMinge’s comments. Do you believe thesedevelopments could change the discus-sion?

Chenault: I think that it could. A lot ofthe conversation was how do we knowthey are going to invest here? I thinkMinge and Mulva’s comments were prob-ably as strong as they could give withouta 100 percent commitment. For Mulva tocome out and say what he did, or Mingeto come out and say what he did, thatcomes from a pretty high source. Thatdoesn’t come from a mechanic on a plat-form making that decision. As you wellknow there is nobody higher up inConocoPhillips than Mulva. The only one

he answers to is the board of directors.When he says something you ought to payattention. Can he guarantee it? No hecan’t, but he’s in a position of making ithappen.

All of us have different concerns, likelocal hire. I wish 100 percent of employ-ees at Prudhoe Bay were Alaskans.Should there be more Alaskans there, Ithink there should be. Will it be 100 per-cent Alaska? I don’t see that. Some of thetechnological advances in the productionof new wells are being done elsewhere. Iknow a little bit about coil tubing, butthere’s not a lot of Alaskans who knowabout that. Normally those people comefrom areas that use that type of technolo-gy. As we use more of that here, then wedo build a workforce that is able to bewith more Alaskans.

There will never be 100 percent localhire, which I would love to see, but hope-fully working with the industry peopleand also with the contractors, we will ableget those numbers up. We can’t forcethem too. I don’t think us incentivizingthem to hire Alaskans versus somethingelse is the right way to go. I think weneed to apply a little pressure and alsoneed to make sure we have a good work-ing relationship with them. It’s a two-waystreet. It’s always a two-way street.Hopefully we can meet to work some ofthose issues out and get more Alaskans inthat workforce.

Petroleum News: What progress canyou identify toward main goals of a gasline or putting more oil in the pipeline?

Chenault: I’ve tried to pass a numberof pieces of legislation. One was an in-state gas line account. We had a bill thatdealt with language issues in commoncarrier pipelines. We’ve tried to pass leg-islation to move us forward to get us offthe dime. All of that legislation is sittingover in the Senate. And that’s OK. I wouldlike to see it passed. It’s not the end of theworld, but it does delay things. We madesure in the operating budgets that we putin more money for DNR to try to get ridof the backlog of permits they have (near-ly $1.5 million). They have about 2,500permits in backlog. That causes delays.And that may be for mom and pop tryingto open up a gravel pit. If you are delay-ing it, you are delaying these people frombeing able to go to work and makemoney. So we put that much more moneyin DNR to get rid of those backlog of per-mits to make sure it’s not a permit that’sholding up a project.

Petroleum News: That seemed to be acommon priority among the legislators.

Do you see it that way?Chenault: I think it is that way. Let’s

say you have a drilling program that’sgoing to happen in Prudhoe Bay and youhave to build an ice road, and it’s a four-year project. Right now in order to buildan ice road, you’ve got to go get permits.Well next year, you’ve got to go get thesame permits again and you’ve got to gothrough the same problems. The next yearyou’ve got to get the same permit.Doesn’t it make sense to get that permitfor four years? So you permit the projectfor the entire time so if things change,then you can come back and address it.

As it is now with the backlog of per-mits, as soon as they get a permit to dothe ice road, if they are going to do the

same one next year, they have to startagain, so now they have the same peopleworking from now until they get the per-mit every year. Does that make sense?Wouldn’t it make sense to have a permitfor the length of the project? Give them apermit to build an ice road. If you’rebuilding the same road year after year,why do you have to keep getting a per-mit? Why do you have to do through thatprocess? Because that’s the only processwe know right now.

Things like that speed up the permit-ting process and allows these projects togo forward so we’re not spending valuablestate employee time. We are not spendingvaluable corporate time to get the samepermit over and over. �

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continued from page 3

CHENAULT Q&A


Kendall named Alaska regional directorPETROLEUM NEWS

Dr. James Kendall has been named director of theAlaska Outer Continental Shelf Region of the

Bureau of Ocean Energy Management, Regulation andEnforcement.

Kendall has been acting director for the region sinceJan. 1.

“Jim is absolutely the right person for the job. Wehave very difficult decisions to make regarding energydevelopment offshore Alaska, and the American publicmust have complete confidence that those decisions willbe informed by the best scientific information available,”BOEMRE Director Michael Bromwich said in a state-ment. “Jim embodies the principles of scientific integri-ty. He is committed to openness and transparency, and heis a dedicated public servant. The feedback I havereceived regarding Jim’s tenure over the last few monthsas Acting Regional Director from environmental organi-zations, industry groups, and other stakeholders has been

uniformly positive — they have praised Jim’s openness,his accessibility, and his willingness to listen to all pointsof view. This praise has been universal, including fromstakeholders who have been critical of our office in thepast. I am very pleased to have him at the helm of theAlaska Regional office.”

Formerly headed Environmental DivisionKendall most recently served as the chief of

BOEMRE’s Environmental Division, where he wasresponsible for overseeing the Bureau’s $30 millionapplied environmental and socioeconomic research pro-gram, its responsibilities under the NationalEnvironmental Policy Act, its environmental complianceresponsibilities and the Coastal Impact AssistanceProgram. Prior to joining the BOEMRE HeadquartersOffice in 2000, Kendall served as the chief of theEnvironmental Sciences Section of BOEMRE’s Gulf ofMexico Region.

“Working with the Regional BOEMRE team thesepast few months has been an honor. They are true pro-fessionals, committed to environmental protection,responsible energy development and our nation,”Kendall said. “The Alaska OCS is both an environmen-tal treasure and a vital, strategic national resource and Iam committed to ensuring safe and environmentallysound stewardship of its resources.”

BOEMRE’s Alaska Region oversees the explorationand development of oil and gas resources in federalwaters offshore Alaska. This includes assessments of theoil and gas resources, preparation of environmentalanalyses and research, coordination with local, state,tribal and federal governments, and others interested inthe OCS program.

Kendall will eventually transition to become the headof the Alaska region for the Bureau of Ocean EnergyManagement, one of the new agencies that will replacethe former Minerals Management Service on Oct. 1. �

http://www.fugro.com/


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

Conoco seeks 17%TAPS increaseRequest is the fourth since October 2008 for the company andwould increase tariffs nearly threefold over last permanent rates


ConocoPhillips is asking for a 17 per-cent increase to the rate it charges to

ship oil on the trans-Alaska oil pipeline tomarkets within the state, its fourth requestsince late 2008.

The proposed increase would raise thecost to ship a barrel of oil from the NorthSlope to North Pole to $3.37, up from$2.86, while shipping to locations inValdez would increase to about $5.26, upfrom some $4.48, depending on final des-tination. (There are two off-take points inValdez: the PetroStar refinery and theValdez Marine Terminal.)

ConocoPhillips wants the increase togo into effect on June 20.

The proposed rates would generate$30.4 million per year forConocoPhillips. The company brings in$25.8 million from its current rates forintrastate operations.

ConocoPhillips said the increase isneeded because throughput on thepipeline continues to fall while costs con-tinue to rise, the same reasons cited forprevious rate increases.

13 cases now outstandingThe request further complicates the

shipping rate on the pipeline.The Regulatory Commission of Alaska

last approved shipping rates on thepipeline in 2002. The pipeline ownersrequested increases in the years that fol-lowed, but the RCA denied those requestsbecause they used an outdated methodol-ogy to calculate rates.

But starting in 2008, four of the fiveowners — all but BP — began requestingincreases using a new methodology. Sincethen, those four companies have eachrequested three increases. Because of thesimilarity of those cases, and because ofthe need to simplify the proceedings, theRCA ultimately consolidated those 12cases into a single docket.

Midstream subsidiaries of BP,ConocoPhillips, ExxonMobil, KochIndustries and Union Oil Company ofCalifornia each own undivided shares ofthe 800-mile pipeline. Each company canset its own rates, so long as the combinedrates stay at or below a certain level.

Although the companies cannot dis-cuss ratemaking strategies among eachother, they can use filings from otherowners as a guide. Since the first filing inOctober 2008, ConocoPhillips has led theway, filing first and setting the bench-mark for other owners.

Not seeking consolidationBecause the RCA typically approves

rate increases on a temporary and refund-

able basis while it studies the legitimacyof a case, the approved shipping rates onthe pipeline are increasingly out of syncwith the existing rates on the pipeline.The 2002 rates charge $1.25 to ship a bar-rel of oil to North Pole and $1.96 to shipto various points in Valdez.

The newest ConocoPhillips applica-tion, if approved, would nearly triplethose rates.

Therefore, the four owners are increas-ingly at risk for having to refund millionsof dollars to shippers should the RCAultimately decide not to approve theincreases permanently.

As an example, while the newestincrease would bring ConocoPhillips$30.4 million in revenue per year, the2002 rates would generate only $11.3million per year.

While this newest case is based on thesame methodology as its 12 predecessors,ConocoPhillips notably asked the RCAnot to add the case to the consolidateddocket.

ConocoPhillips said that the previouscases have now progressed beyond theirinitial stages and that adding a new casenow would disrupt the current proceduralschedule.

That decision could add complexitiesdown the road, though.

FERC also has casesWhile the pipeline owners have been

asking the RCA to increase shipping rateson oil that stays in Alaska, they have alsobeen asking the Federal Energy RegulatoryCommission to increase shipping rates onoil bound to out-of-state markets.

Many of the issues of both sets of casesare similar, particularly in regard towhether and how companies can includethe cost of strategic reconfiguration intotheir rates.

Strategic reconfiguration is a multiyeareffort to upgrade pipeline operations.

Because the project is over budget andpast deadline, the State of Alaska andAnadarko Petroleum, both of which standto benefit in different ways from lowershipping rates, believe some of the costsare the result of imprudence and shouldnot be paid by shippers.

The companies that own the pipeline,though, see strategic reconfiguration as aseries of projects to reduce costs andincrease efficiency, including several suc-cessful ventures.

Later this year, the RCA and FERCplan to hold a series of concurrent hearingsin Washington, D.C., and Anchorage todiscuss issues relevant to both regulatorybodies. �


ALTERNATVE ENERGYAEA seeking legal team for FERC permit

The Alaska Energy Authority is looking for a legal team to help it license alarge hydroelectric power project with the Federal Energy RegulatoryCommission.

AEA is looking for legal counsel with at least 10 years of experience licensinghydroelectric projects before FERC and navigating the federal laws around largeenergy projects, as well as a firm with offices in both Washington, D.C., and onthe West Coast.

AEA is taking proposals throughJune 17.

Although the state has been studyinglarge hydroelectric projects for decades,the most recent push dates back to aRegional Integrated Resources Plan, aFebruary 2010 proposal for how Alaskashould move ahead on energy policydecisions in the Railbelt.

Project selected last yearThat plan recommended that the state

consider developing a large hydroelec-tric project, and last November AEA chose a hydroelectric project on the SusitnaRiver about 184 river miles upstream of the mouth of the river on the south sideof the Alaska Range.

By supplying roughly half of the power needs in the Railbelt, the $4.5 billionproject would help the state meet its self-imposed goal of generating half its powerfrom renewable sources by 2025. The proposed Susitna hydroelectric plant is ascaled down version of a project investigated in the 1980s that faltered in the faceof low oil prices.

AEA already owns a hydroelectric project at Bradley Lake that supplies powerto the Railbelt, but lost the authority to develop similar projects when it mergedits board of directors with that of the Alaska Industrial Development and ExportAuthority in 1993.

The Legislature recently passed a bill allowing AEA to buy or build powerprojects, as well as to maintain and operate those projects. The bill also specifi-cally allows AEA to acquire a Susitna hydroelectric project through “construction,purchase, gift or lease.”

—ERIC LIDJI

Although the state has beenstudying large hydroelectric

projects for decades, the mostrecent push dates back to a

Regional Integrated ResourcesPlan, a February 2010 proposal

for how Alaska should moveahead on energy policy

decisions in the Railbelt.

http://www.alutiiq.com/

http://www.alaskanenergyresources.com/


Alaska Department of RevenueTax Director

The Alaska Department of Revenue is seeking a dynamic individual to lead the Tax Division. The Tax Director overseesa 130 person division responsible for collection of oil and gasseverance taxes, corporate income taxes, fisheries businesstaxes, a variety of excise taxes, and charitable gaming program.

In addition, the Tax Division is responsible for revenue forecasting and development of state tax and fiscal policy. Thepreferred applicant may have experience with the oil and gasindustry and be able to work with industry, the Legislature andcommunity organizations. A CPA or Law Degree is preferred.The position in located in Anchorage, Alaska.

The Tax Division is comprised of tax professionals with legaland multi-state tax experience, with commercial analysts, auditmasters and research economists. The State of Alaska is anEEO/ADA employer.

Interested applicants should fully explain in their online coverletter their recent succinct experiences and their oil and gasknowledge.

For more information on how to apply for this vacancy, pleasevisit http://workplace.alaska.gov OR by calling 800-587-0430statewide and in Juneau call (907) 465-5342.

The last day to apply for this job is June 15, 2011; 5:00 PM Alaska Time.

ENVIRONMENT & SAFETYWildfires rage across Alberta

A seemingly unending winter that played havoc at times with upstream operationshas quickly been replaced with a spring drought and fires raging across northernAlberta that are scorching industry profits.

At their peak, the blazes have forced the shut-in of about 150,000 barrels of oilequivalent per day, while hundreds of workers have been pulled out of camps andinfrastructure has been threatened.

The greatest physical damage occurred in Slave Lake, where a mandatory evacua-tion was ordered for 7,000 residents ahead of a sudden wind shift that sent fire ragingthrough about one-third of the town, destroying 354 homes.

The Alberta government immediately launched a C$50 million disaster relief pro-gram.

So far the fires have claimed one life — that of a firefighting helicopter pilot.In addition to a spate of production cuts, work has been stopped at several oil sands

construction sites and on a C$440 million project by Pembina Pipeline Corp. designedto move 100,000 barrels per day of crude and 20,000 bpd of diluents.

Kyle Preston, an analyst with Canaccord Genuity, said the losses will affect theearnings of several producers this quarter.

Production haltedOil sands producer Cenovus Energy halted 22,000 bpd of production at its Pelican

Lake operation and Canadian Natural Resources slowed output of 40,000 bpd, also atPelican Lake.

Husky Energy said that although it is not directly affected by the fires, relatedpipeline shutdowns and power disruptions have impacted 17,000 bpd of its produc-tion.

Other shut-ins affected Royal Dutch Shell (an unspecified cutback at its 21,000 bpdCliffdale and Seal heavy oil projects in the Peace River area of northwestern Alberta);Penn West Energy (25,000-35,000 bpd in Alberta and 40,000 bpd because of floodingin southern Manitoba); Pengrowth Corp. (5,000 bpd); and smaller volumes byBlackPearl Resources, Baytex Energy and Exall Energy.

Canadian Natural and Royal Dutch Shell moved construction workers and non-essential workers from their oil sands operations.

The fires forced the closure of the southern leg of Plains All American Pipeline’sRainbow system. The northern leg had already been shut due to a 28,000 barrel spillin late April.

Petroleum industry donations to relief work quickly gathered momentum. Clientsof FirstEnergy Capital raised C$400,000 to help those who lost homes, whileCanadian Red Cross donations included C$80,000 from Apache, C$50,000 fromCenovus and C$10,000 from Gibson Energy.

—GARY PARK

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

USGS plans seismicsurvey in Bering SeaShoot is part of effort to delineate potentially resource-richextended continental shelf; survey also planned in Gulf of Alaska

By WESLEY LOYFor Petroleum News

The U.S. Geological Survey plans toshoot a seismic survey in August in

the Bering Sea to delineate the “extendedcontinental shelf.”

The survey will be conducted from theresearch vessel Marcus G. Langseth witha towed array of 36 airguns, says an envi-ronmental assessment prepared for theproject.

The 235-foot vessel is owned by theNational Science Foundation and operatedthrough a cooperative agreement byColumbia University’s Lamont-DohertyEarth Observatory.

National projectThe extended continental shelf is that

region beyond the U.S. ExclusiveEconomic Zone or EEZ, which reaches to200 nautical miles offshore.

The USGS seismic survey will be con-ducted under the auspices of the U.S.Extended Continental Shelf Task Force, aninteragency body chaired by theDepartment of State with vice chairs fromthe Interior Department and the NationalOceanic and Atmospheric Administration.

“The United States has an inherentnational interest in knowing, and declar-ing to others with specificity, the extent ofour sovereign rights with regard to theU.S. extended continental shelf,” an arealikely rich in resources that could be worthbillions or even trillions of dollars, thetask force’s website says.

“There are six areas in which the U.S.likely has an extended continental shelf(ECS): the Atlantic Margin, Arctic Ocean,Bering Sea, off the west side ofGuam/Northern Mariana Islands, and intwo areas in the Gulf of Mexico,” the web-

site says. “There are nine areas in whichthe U.S. may have an extended continentalshelf: the Gulf of Alaska, the western endof the Aleutian Islands, the NorthernMariana Islands, Hawaii’s Necker Island,Johnston Atoll, Kingman Reef andPalmyra Atoll, and three areas off the U.S.west coast.”

Preliminary studies indicate the U.S.extended continental shelf likely is an areaabout twice the size of California, says thetask force website at continentalshelf.gov.

Survey detailsThe R/V Marcus G. Langseth will

depart from Dutch Harbor around Aug. 7and return Sept. 1, the environmentalassessment says.

The survey will collect seismic reflec-tion and refraction profiles to be used todelineate the extended continental shelf,the assessment says.

The rules for defining the extendedshelf are based in international law,specifically Article 76 of the UnitedNations Convention on the Law of theSea.

“One of the conditions in Article 76 isa function of sediment thickness,” theassessment says. “The seismic profilesare designed to identify the stratigraphic‘basement’ and to map the thickness ofthe overlying sediments.”

The Langseth survey will take place inthe central-western Bering Sea, in boththe U.S. EEZ and adjacent internationalwaters, in depths greater than 3,000meters.

The USGS plans to use the Langsethon a similar seismic survey from June 5 to25 in the Gulf of Alaska. �

Contact Wesley Loy at [email protected]


What does the state’s permittingprocess look like for an explo-

ration well in Cook Inlet? Traced out onlarge pieces of poster board in aDepartment of Natural Resources confer-ence room in Anchorage, the existingprocess is clearly complex.

Permitting is an issue for Alaska devel-opment, DNR Commissioner DanSullivan said in a May 20 press briefingwhere the poster boards were displayed,and the department is working on identi-fying “what the challenges are — kind ofa baseline of what the issue is.”

Permitting became a big issue in thelast legislative session, he said, whenDNR discussed the backlog of permits inits Division of Mining, Land and Water:about 2,500 permits.

That resulted in $2.7 million in incre-

mental funding to the division to dealwith the backlog. Wyn Menefee,DML&W chief of operations and thedivision’s acting director, said the moneywould allow the division to fill manyvacant positions that were unfunded andalso add six new positions.

Sullivan said the goal is to get thatbacklog taken care of in the next threeyears.

System as a wholeSullivan said a task force headed by

DNR Deputy Commissioner Ed Fogels islooking at the permitting system as awhole, not just from DNR’s perspective,to see if the permits, regulations andstatutory requirements “continue to makesense” and if there are ways to gain effi-ciency.

Sullivan said the task force has metseveral times and is “looking at ways inwhich to make our system more efficient,bring more certainty to it and more time-liness with regard to the permittingprocess.”

The goal for the task force is to have itmake recommendations to the governor’soffice and eventually to the Legislature,he said.

There are three categories of issues,Sullivan said.

The first is DNR regulations, whichthe department has the authority to lookat and revise.

The second is regulations “closely tiedto a statutory mandate” where the depart-ment must be careful not to undertake aregulatory change that has a statutorybasis, and Sullivan said DNR would becoordinating with the Department ofLaw.

The third category is “just pure statu-tory requirements,” and there coordina-

tion would be with the governor’s officeand then eventually the administrationwould go to the Legislature with recom-mendations of any statutory changes.

While the charts showing permittingcomplexity weren’t ready for the last leg-islative session, Sullivan said “we talkedabout this with a number of legislators”and there was general recognition thatpermitting is a challenge for the state.

He said that if DNR comes back witha package of recommendations, “certain-ly there will be a lot of interest and Ithink we’ll start in a constructive waybecause we had a very constructive dia-logue about these issues during the lastsession down in Juneau.”

Federal liaison?Asked if there was room for a federal

liaison, Fogels said the task force is just“getting staged right now.” He said therehave been a couple of meetings, but it’sinternal to DNR “just to get our owninternal house sort of in order and evalu-ated.”

Fogels said DNR will then be reachingout to some other state permitting agen-cies such as the departments of Fish andGame and Environmental Conservationand will also pull in the Department ofLaw.

It will be fairly similar to one ofDNR’s standard large permitting teams,he said: “We’ll get some of the best andthe brightest people from the agenciesthat have been working on permittingissues for years.”

Establishing the state team is an initialstep, Fogels said, because for permittinglarge projects, “quite frankly some of thebiggest issues that we’ve faced permit-ting are federal issues.”

He said the state would be pulling insome federal permitting people at somepoint “because the federal permittingprocess is really key to making thiswhole thing work better.”

That will be the trickiest area to makeprogress, Fogels said, adding that he’salready trying to get a bit of an inroadinto the president’s permitting team,announced earlier in May.

Fogels said the state would love to seethe feds coordinate permits the way thestate does, “because we don’t have theauthority to coordinate for the feds, theyhave to do it voluntarily.”

EPA concernsFogels said a federal issue of concern

right now is a new guidance documentthe Environmental Protection Agency isproposing about how to determinewhether a wetland is under federal juris-diction.

“If that guidance goes forward, thensignificantly more wetlands will beunder federal jurisdiction,” he said.

Fogels was participating by phonefrom Washington, D.C., and told Sullivanthat federal officials were receptive toAlaska having a voice on the federal per-mitting group, but said it was too early totell whether they could pull states in.

But there was interest in Alaska’sstrong permit coordination process,Fogels said, and he was asked for follow-up information on the state’s coordina-tion process. �



Sullivan: Permitting a focus for DNRMaking permitting more efficient, timely and certain a building block in accelerating development in state; process under review

Establishing the state team is aninitial step, Fogels said, because

for permitting large projects,“quite frankly some of the biggestissues that we’ve faced permitting

are federal issues.”

DAN SULLIVAN ED FOGELS

PIPELINES & DOWNSTREAMBP to replace Prudhoe VSMs this summer

BP plans to replace 108 vertical support members at the Prudhoe Bay unit thissummer.

The VSMs slated for replacement support several pipelines located betweenGathering Center 1 and Gathering Center 3, but are currently deemed “structural-ly insufficient.”

The new VSMs will improve the integrity of the pipelines, BP said. Theprocess involves using a vibratory hammer to drive the 12-inch VSMs at least 34feet underground.

BP plans to install the new VSMs between June and September.The existing VSMs will be capped and abandoned.VSMs allow operators to elevate a pipeline above the ground. While pipelines

are simply buried in much of the world, Arctic permafrost makes that task diffi-cult in Alaska.

The trans-Alaska oil pipeline is supported by some 78,000 VSMs.—ERIC LIDJI

Contact Kristen Nelson at [email protected]

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http://www.aecom.com/

http://www.alaskadreamsinc.com/


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AIDEA revises jack-up agreementChanges aim to give AIDEA more assurances that it won’t lose investment if Buccaneer and Ezion default, could delay drilling


The Alaska Industrial Development and ExportAuthority approved changes to its agreement to pur-

chase a jack-up drilling rig on May 25 that aim to make thepublic-private project less risky, but will likely delay explo-ration activities for one year.

The board of the public corporation of the State ofAlaska approved the changes unanimously after an hour ofpublic deliberations and another half hour in executive ses-sion. In particular, board members wanted to knowwhether the imminent arrival of another jack-up rig inCook Inlet impacted the project or made it unnecessaryand whether the private partner would be able to raisemoney for a drilling program.

AIDEA is looking to contribute up to $30 milliontoward the cost of a jack-up rig, a mobile drilling unitdesigned for relatively shallow offshore areas, like CookInlet.

AIDEA is partnering on the project with KenaiOffshore Ventures LLC, a joint venture between Australianindependent Buccaneer Energy Ltd. and the marine com-pany Singapore-based Ezion Holdings Ltd. Using newlygranted statutory authority, AIDEA might join that LLC.

The AIDEA board previously approved an agreementwith KOV on April 1, allowing staff to execute the dealonce the companies in KOV complete a long to-do list.

The primary change to the agreement involves a lien onBuccaneer’s worldwide holdings that AIDEA could use torecoup its investment if the project fell apart in the future.

That lien appeared in the agreement the board approvedin April, but AIDEA staff later decided the security on thecollateral wasn’t “sufficient,” according to Mark Gardinerof Western Financial Group, the team negotiating the dealfor AIDEA, and spent a month renegotiating those details

with Buccaneer and Ezion. Gardiner said the revisedagreement “represents an improved legal security andfinancial position for AIDEA.”

Aiming to close June 30Even with the vote, AIDEA is not yet on the hook for

$30 million. Once AIDEA and KOV sign the agreement, Buccaneer

and Ezion must meet 15 conditions before AIDEA cuts itsfirst check. Those include contributing $5 million of theirown capital to the project, securing the remaining $50 mil-lion needed to fund the purchase of the rig, executing acontract to buy a jack-up rig — likely the Adriatic XI —from Transocean Ltd. and signing contracts to upgrade thatrig for use in Alaska.

“We still have a lot to do to get to that point,” Gardinersaid, estimating that the deal would close around June 30.If the partners close the deal earlier than that, Gardiner saidthere remains a slight chance the drilling program couldstill continue this year.

While the companies are far along on most of the con-ditions, with AIDEA in some cases already reviewing finaldocuments, none have been finalized, as of yet, Gardinersaid.

Asked by board member Gary Wilken if any of the con-ditions concerned AIDEA, Gardiner pointed to one thatrequired KOV to prove it could pay for a four-well programthat is the foundation of the business case for bringing ajack-up rig to Alaska.

“We’ve become more comfortable that the capability isthere,” Gardiner said, saying the exploration tax creditsoffered by ACES make the investment increasingly attrac-tive.

Concerns about workoutAs AIDEA and KOV move toward closing on a deal,

Houston independent Escopeta Oil is close to having itsown jack-up rig in place in the inlet. (See related story onpage 1).

Because AIDEA and KOV plan to lease the rig out toother operators across Alaska once Buccaneer drills itsfour wells in Cook Inlet, board member Robert Sheldonasked, “What confidence do we have that there is enoughbusiness for both of these rigs?”

Gardiner replied, “Our business premise here is basedon Buccaneer drilling their wells, not necessarily on addi-tional business from other parties using the rig.”

He added that both Ezion and OCBC Bank, the Asianfinancial institution being asked to fund the remaining $50million needed to purchase the rig after AIDEA’s invest-ment, knew about the possibility of having two rigs in theinlet before entering negotiations, and that having multiplerigs would allow more Alaska waters to be explored faster.

The deal is designed so that if Buccaneer shoulddefault, AIDEA would assume an overriding royalty inter-est on a small percentage of Buccaneer’s properties, allow-ing AIDEA to recoup its investment as those propertiesare sold, explored and developed.

Chair Hugh Short worried that AIDEA could losemoney, even with that mechanism.

“I’ve been involved in a number of workouts and noone ever wins in a workout. A workout is a pain,” Shortsaid, describing the process of recovering the investmentin the case of default as “Healy clean coal light. Very light,but it’s still a mess to clean up.”

An AIDEA lawyer said the various collateral provi-sions — ranging from the overriding interest onBuccaneer properties, to claims to any ACES tax credits asthey come in, to the right to buy the OCBC loan — “giveus a real chance of being made whole.” �


http://www.doyonemerald.com/


Sen. Bill Wielechowski, D-Anchorage,has appealed to all parties in the

debate over coastal management to dowhat’s best for Alaskans and renew theprogram.

Citing an overview of the AlaskaCoastal Management Program fromLegislative Research Services,Wielechowski said in a May 23 statementthat in less than sixweeks Alaskans willlose their most“direct and importanttool to influence fed-eral activities” inAlaska.

U.S. Sen. MarkBegich, D-Alaska,jumped in May25with an even morealarming analysis,that expiration ofACMP will affect oil and gas developmentoff the North Slope.

“The Deep Water Port Act requires astate to have, or be making progresstoward having an approved coastal zonemanagement program in order to build anoff-shore, deepwater port in federalwaters,” Begich said. Shallow waters offthe North Slope would require companiesto go many miles offshore to reach watersdeep enough to accommodate “the large,deep-draft vessels associated with oil andgas production and transportation. WithoutACMP, oil and gas operators will not have

the option to develop an offshore deepwa-ter port, which could significantly impairtheir operations.”

He said Alaska will also lose out onfunding from the National Oceanic andAtmosphere Administration, which hasinvested more than $141 million in theACMP to date, and has $2.5 million bud-geted for the program this year. The statewould no longer be eligible for grantsunder the federal Coastal and EstuarineLand Conservation Program, on track todistribute some $20 million nationwide in2011, including funding for a project onAnchorage’s Campbell Creek.

And the state would have to scramble tofind another entity to administer its sharein the final round of Coastal ImpactAssistance Program from outer continentalshelf leasing, which has been administeredby ACMP. Some $28 million remains ofthe state’s share, he said.

Loss of voice in federal decisionsBegich said loss of the program would

have severe impacts on both the state’senvironment and economy.

“It is critical that Alaskans have a voicein federal decisions regarding oceanresource development and are well posi-tioned to rapidly develop our enormousoffshore oil and gas resources,” he said.

The Legislative Research Servicesreport called the “loss of Alaska’s ability toreview and to object to federal activities,licenses and permits through the consis-tency review process” the most significantimpact of the loss of ACMP.

“The report paints a dire picture,”

Wielechowski said.“Many Alaskans arerightfully concernedabout the heavy handof the federal gov-ernment in Alaska.Loss of this programwill give the fedsmore authority todictate what happenson our lands and

waters, and it will throw roadblocks infront of companies wanting to do businessin Alaska.”

ACMP gives the state a formal role inreview of federal activities including thoseon the outer continental shelf. While thestate could still comment on federal activ-ities without the ACMP, it “could no longerensure those activities comply with ACMPstatewide and district enforceable poli-cies,” the report said.

ACMP Director Randy Bates toldLegislative Research Services that withouta formal review process, comments bystate agencies may become “disjointedwith conflicting responses from variousstate agencies.” Bates said that withoutACMP the state would not be part of theformal review process for federal projectssuch as OCS oil and gas lease sales, timbersales in the Tongass National Forest or oilleases under the jurisdiction of the federalBureau of Land Management.

Loss of consistency reviewWithout ACMP there will be no consis-

tency review, he said, thus eliminating orreducing pre-application assistance to

developers, coordination of the applica-tion process, coordination between stateagencies and affected coastal districts, areview of entire projects and considerationof local issues.

Bates also said that without ACMPdevelopers would have to work with eachpermitting agency separately, a process hedescribed as a “time-consuming, uncoor-dinated, duplicative, patchworkapproach.”

This is an argument supporters madeon the House floor, noting that ACMP isused for local projects as well as for largeresource development projects.

While the state could create a newagency to coordinate resource permits, itwould not have access to federal funds,some $2.5 million annually, and would nothave the ability to participate in a coordi-nated review process with federal agen-cies.

Each coastal district has a coastal coor-dinator, the report said, employed by themunicipality or borough in the case oforganized local governments and partlyfunded by ACMP. There are four coastalservice resource areas where organizedlocal governments do not exist, and thoseareas receive funding from ACMP forstaffing, training and an office.

Betty Svensson, deputy director of theAlaska Municipal League, told LegislativeResearch Services that the loss of ACMPwould be a “double hit” to coastal dis-tricts, because they would not only losetheir voice in the permitting process butwould also lose funding for training, coor-dinators and other projects. With the lossof the coordinator position, Svensson said,local concerns would have to be raisedwith each permitting agency by a volun-teer or another municipal employee whomay not have the training to understandand participate in the process.

Closing up shot“No state or federal agency will take

over or assume the function and responsi-bilities for coastal zone management inAlaska,” Bates said in a May 25 e-mail onthe ACMP shutdown.

He said the Division of Coastal andOcean Management staff is working on anorderly shutdown and plans to have itsoffices closed by June 30.

But, he said, DCOM will continue toaccept project applications, as required bylaw, and quoted guidance the division hasreceived from the Department of Law onorderly shutdown as it relates to ACMPproject reviews.

Law said consistency reviews shouldcontinue to be processed and revieweduntil the July 1 repeal date of the program.

“This is particularly important to appli-cants who will need a resource agencypermit or a federal consistency determina-tion prior to July 1, 2011,” Law said.

Bates said that for projects currently inreview that will be complete by June 30,“the coordinating agency should continuethe review and issue the final determina-tion.”

For projects received prior to June 30that could be completed because of expe-dited review or a 30-day review, the coor-dinating agency should process the review.

For projects received between now andJune 30 that will not be completed by June30, or for projects currently in review thatwill not be completed by June 30, “the


Wielechowski appeals for ACMP renewalBegich says loss of coastal zone program will hurt oil, gas development, prevent building offshore deepwater port off North Slope


L O C A L E X P E R T I S E I U N B E A T A B L E F R E Q U E N C Y A C R O S S A L A S K A I

T M

When it comes to oil and gas, teamwork is critical. For more

than 75 years, we’ve earned the reputation as a reliable partner

who delivers as promised. That’s why explorers and

producers across North

America call on Alaska

Air Cargo and employees

like Sachi every day.

We are Alaska Air Cargo. True partners delivering for you.

Proud to deliver.

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SEN. MARK BEGICH

see ACMP APPEAL page 11

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A I C L L C . C O M

AIC, LLC. 301 W. NORTHERN LIGHTS BLVD., STE. 600 ANCHORAGE, AK 99503 T: 907-562-2792 F: 907-562-4179

Natural resources continue to be the cornerstone for Alaska’s economic development and diversification. AIC is proud to provide the equipment and construction services to the resource development industries.

LAND & LEASING

This week’s lease sale chartsponsored by:

Geokinetics

Potential Alaska state and federal oil and gas lease sales

Agency Sale and Area Proposed Date

DNR Alaska Peninsula Areawide June 22, 2011

DNR Cook Inlet Areawide June 22, 2011

DNR Beaufort Sea Areawide October 2011

DNR North Slope Areawide October 2011

DNR North Slope Foothills Areawide October 2011

Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, manages leasing in

the National Petroleum Reserve-Alaska; BOEM, U.S. Department of the Interior’s Bureau of Ocean

Energy Management, Regulation and Enforcement (formerly Minerals Management Service), Alaska

region outer continental shelf office, manages sales in federal waters offshore Alaska; DNR, Alaska

Department of Natural Resources, Division of Oil and Gas, manages state oil and gas lease sales onshore

and in state waters; MHT, Alaska Mental Health Trust Land Office, manages sales on trust lands.

coordinating agency should processand/or continue the review but terminatethe review on July 1.”

Bates said the division and Law “arelooking at the issues concerning the legalfutility of initiating reviews that under theregulations cannot be completed prior tothe expiration of the ACMP,” and encour-aged applicants who are able to wait tosubmit a proposed project until after theJune 30 expiration of ACMP to do so.

Close to special session?The Anchorage Daily News reported

May 26 that the Legislature appears to beclose to calling itself back into special ses-sion to deal with ACMP.

The governor can also call legislatorsback, but the governor’s spokeswoman,Sharon Leighow, told Petroleum Newsafter the special session ended that therewere no plans to call another special ses-sion.

The Daily News reported that 15 of 20members of the Senate were in favor of aspecial session, and apparently the Housewas close to having two-thirds agreementamong members for what is expected tobe a two-day session.

Senate Majority Leader Kevin Meyer,R-Anchorage, told the Daily News it lookslike the Senate will accept a version of theACMP bill similar to what the governorand the House previously agreed on. �

—The Associated Press contributed to this story


ACMP APPEAL


� U T I L I T I E S

Chugach to sell toSeward through 2016Utility asks RCA to extend existing contract another five years;Seward soon to be Chugach’s only regular wholesale customer


Chugach Electric Association plans tosell power to the city of Seward —

its smallest and soon to be only wholesalecustomer — through at least the end of2016, the utility said.

Chugach and Seward asked theRegulatory Commission of Alaska inearly May to approve the extension.Chugach currently sells power to Sewardunder a contract approved in 2006. Thatcontract expires at the end of this year, butcan be automatically extended five yearswith the consent of both parties and theapproval of the RCA.

The news represents a constant duringa period of change for Chugach.

As the largest electric utility in Alaska,Chugach not only serves more than81,000 of its own customers, but also cur-rently sells power to three Southcentralwholesale customers: Seward, the HomerElectric Association and the MatanuskaElectric Association.

Chugach also maintains a connectionwith Golden Valley Electric Associationin Fairbanks, allowing it to send powernorth (or receive it from the north, asneeded).

More than half wholesaleThose three customers bought 352

million kilowatt-hours of electricity in thefirst quarter of 2011, up from 331 millionkWh during the same period of 2010. Bycomparison, Chugach sold just 319 mil-lion kWh to its retail customers during thefirst quarter of 2010.

However, HEA plans to stop buyingelectricity at the end of 2013 and MEAplans to do the same at the end of 2014.With the end of those two contracts,Chugach will lose roughly half its powersales load and around 40 percent of itsannual sales revenue.

“While financial management planscenarios indicate Chugach can sustainoperations and meet financial covenantsin the event these two customers leave thesystem, the remaining customers willhave to shoulder the burden imposed bythe remaining costs and will likely facehigher rates,” Chugach wrote in first-quarter financial filings.

By securing power sales agreementsand “wheeling” contracts (for renting outpower lines to third parties generators),Chugach believes it can recover some lostrevenue and mitigate the rate increasesexpected in 2014 and 2015, but added,“we cannot assure that we will be able toreplace sources of revenue or that anyreplacement of revenue sources or revisedtariffs will fully mitigate any anticipatedrate increases in this timeframe.”

see CHUGACH CONTRACT page 13

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GOVERNMENTBOEMRE, NOAA ink MOU

The federal Bureau of Ocean Energy Management, Regulation andEnforcement and the National Oceanic and Atmospheric Administration said May23 that they have signed a memorandum of understanding.

BOEMRE Director Michael Bromwich said the MOU “will broaden andenhance the communication, coopera-tion and collaboration between ouragencies.”

He said the MOU creates mecha-nisms ensuring early and close coordi-nation of the science and agency priori-ties to promote “stronger environmentalstewardship and stimulate greater effi-ciency in developing and implementing”energy policy and conservation on theouter continental shelf.

Jane Lubchenco, under secretary ofcommerce for oceans and atmosphereand NOAA administrator, said NOAAlooks “forward to continuing to work with BOEMRE to ensure NOAA scienceinforms offshore energy development and oil spill response.”

Commission recommendationsThe agencies said the MOU is consistent with recommendations from the

National Commission on the Deepwater Horizon Oil Spill and Offshore Drillingand specifies how BOEMRE and NOAA will cooperate and coordinate.

Specifics include: defining processes to ensure effective and timely communi-cations of agency priorities and upcoming activities; identifying and undertakingcritical environmental studies and analyses; collaborating on scientific, environ-mental and technical issues related to the development and deployment of envi-ronmentally sound and sustainable offshore renewable energy technologies; andincreasing coordination and collaboration on decisions related to OCS activities,including with respect to research and scientific priorities.

The agencies said they have a history of nearly 40 years of scientific collabo-ration and have had many successful partnerships.

—PETROLEUM NEWS

� L A N D & L E A S I N G

Proposed unit offANWR advances a bitDonkel Oil & Gas unit would take in seven leases covering 21,354acres; unit application deemed ‘complete,’ ready for public comment


The proposed Donkel Oil & Gas unitoffshore the Arctic National Wildlife

Refuge has moved one step closer toapproval.

In a notice published May 24, theAlaska Department of Natural Resourcessaid the unit application had been deemed“complete.”

The state Division of Oil and Gas willnow take public comments on the pro-posed unit until June 30.

The unit formation will be approved ifconsistent with certain state statutes, thenotice said.

Unit includes discovery wellDonkel Oil & Gas LLC, based in

Daytona Beach, Fla., applied in April forapproval of the new unit.

The company’s managing partner,Daniel K. Donkel, is a longtime player inAlaska oil and gas lease sales and landdeals.

The new unit would take in sevenBeaufort Sea lease tracts covering 21,354acres. The leases are offshore ANWR, notfar east of the ExxonMobil-operatedPoint Thomson oil and gas field.

One lease takes in the Stinson No. 1exploratory well that ARCO Alaska com-pleted in 1990. Although the 16,156-footwell made a discovery, ARCO successorPhillips determined the reserves were

insufficient to justify a standalone devel-opment and the acreage was dropped.

Dan Donkel and a partner, Samuel H.Cade, picked up the Stinson site in anOctober 2008 state lease sale.

Exploration planDonkel Oil & Gas is proposing a four-

year initial plan of exploration for theunit.

The plan calls for performing a 3-Dgeophysical exploration program by May30, 2013.

By Aug. 31, 2015, Donkel pledges todrill an exploration well or re-enter theStinson No. 1 well.

Under state law, a unit designation canserve to extend the life of old leases thatotherwise would expire.

Five of the seven leases in the pro-posed Donkel Oil & Gas unit are due toexpire on May 31, in which case theacreage would return to the state.

The lease with the now plugged andabandoned Stinson well, however, has anexpiration date of Aug. 31, 2016. �

Five of the seven leases in theproposed Donkel Oil & Gas unitare due to expire on May 31, inwhich case the acreage would

return to the state.


Jane Lubchenco, undersecretary of commerce for

oceans and atmosphere andNOAA administrator, saidNOAA looks “forward tocontinuing to work with

BOEMRE to ensure NOAAscience informs offshore energy

development and oil spillresponse.”

http://www.canrig.com/

http://www.akresource.org/


M omentum seems to be building forpotential development of one or

more seaports along Alaska’s Arctic Oceancoast.

The state Department of Transportationand the U.S. Army Corps of Engineers host-ed a planning session on the idea May 16-17 at the Dena’ina Civic and ConventionCenter in downtown Anchorage.

“The U.S. needs deep-draft Arctic portsalong Alaska’s coast,” said stateTransportation Commissioner MarcLuiken. Such ports are vital to project a U.S.presence in the region, to open up opportu-nities for economic growth, and to supportmineral development and scientific studies,he said.

By deep-draft, port planners meangreater than 20 feet, said a state DOT pressrelease on the planning session.

The state is proposing one or more deep-draft ports to support the exportation of nat-ural resources and the importation of bulkgoods and supplies, the release said.

The U.S. Coast Guard also could makeuse of a northernmost port, as well as theNational Oceanic and AtmosphericAdministration.

Participants in the planning sessionincluded Alaska Congressman Don Youngand Alaska Lt. Gov. Mead Treadwell, plusrepresentatives for Sens. Lisa Murkowskiand Mark Begich and Alaska Gov. SeanParnell. Commissioners of several statedepartments also took part.

Other attendees included representativesfrom the Navy, Alaska Homeland Security,the Alaska Industrial Development andExport Authority, the University of Alaskaand the Alaska Marine Pilots.

Because of climate change and thegrowing availability of open water as icecover recedes, the Arctic Ocean could seeincreased shipping and other activity with acorresponding need for ports.

In December 2009, Murkowski intro-duced the Arctic Deep Water Sea Port Act.The bill, S. 2849, would have required the

defense secretary to conduct a feasibilitystudy “to protect and advance strategicUnited States interests within the evolvingand ever more important Arctic region.”

“The United States needs to be able toguard its territorial claims and its economicinterests in the Arctic, especially as adecrease in seasonal ice is leading toincreased marine activity in the region,”Murkowski said in a press release at thetime she introduced the bill.

Young introduced a companion bill,H.R. 4576, in February 2010.

Murkowski and Young also have offeredlegislation “to authorize funds to acquirehydrographic data and provide hydrograph-ic services specific to the Arctic for safenavigation.”

More recently, the Alaska Legislatureincluded $972,000 in the state capital budg-et to “begin the study and mapping ofpotential arctic deepwater port sites with thehelp of the Corps of Engineers,” the stateDOT press release said. “It is estimated thatit will require $2 million more to completethe study by 2014.”

A port could be “a major infrastructureasset to any future potential endeavors toproduce oil and gas from deepwaterreserves in the Arctic,” the release said.

At the planning session, participants dis-cussed such topics as the design of the portand the size of vessels it would need toaccommodate.

“We accomplished a great deal,” saidCol. Reinhard Koenig, commander of theArmy Corps Alaska District. “We’re at thevery beginning of the planning stages, butwe determined that a deep-draft port isneeded and would be beneficial to Alaskaand the nation.”

The state and the Corps intend to use theplanning session results to help designdevelopment. �


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

SPP construction eminentThat projected revenue loss comes as

Chugach is working on bringing theSouthcentral Power Project, a new $300million natural gas fired power plant,online by 2012.

Chugach will own 70 percent of thepower coming from the 183-megawattplant and Anchorage Municipal Light &Power will own the rest. Chugach willoperate the plant.

Chugach said it has ordered the majorcomponents for the project, and that finaldesign and initial permitting are underway for construction to begin as soon asthis spring.

Chugach currently has contracts for allits fuel needs through the end of 2013. �


CHUGACH CONTRACT


ALTERNATIVE ENERGY$1.2 million budgeted for hydro project

The Alaska Legislature included nearly $1.2 million in the state capital budgetfor a controversial hydroelectric proposal on the Kenai Peninsula north of Seward.

The budget, which the governor is nowweighing, designates the money for KenaiHydro LLC’s Grant Lake project. Kenai Hydrois a Homer Electric Association company.

The project would involve building a dam toraise the level of Grant Lake, a mountain lakejust east of the Seward Highway near theMoose Pass community. Water would be with-drawn and sent down a tunnel to a powerhouseto generate 4.5 megawatts.

HEA, which currently buys all its powerwholesale from Anchorage-based ChugachElectric Association, has said it wants to develop its own generation capacity andsees Grant Lake as a small part of its supply mix.

FERC updateIn a March 31 update to the Federal Energy Regulatory Commission, which has

given the project a preliminary permit, Kenai Hydro said it and Homer Electric host-ed a legislative luncheon on Dec. 18 in Kenai to discuss the utility’s generationplans, including the Grant Lake project. Company representatives later met withSenate President Gary Stevens, R-Kodiak.

Over the next few months, Kenai Hydro said it plans to continue engineeringdesign and other work.

The Grant Lake project has generated some controversy. Opponents view it as athreat to the Kenai River watershed, which is rich in salmon and trout.

A FERC license would be required to actually build the project, at a cost thatcould exceed $30 million.

—WESLEY LOY

HEA, which currently buysall its power wholesale fromAnchorage-based ChugachElectric Association, has

said it wants to develop itsown generation capacityand sees Grant Lake as a

small part of its supply mix.

� E N V I R O N M E N T & S A F E T Y

Interest builds for Arctic seaportState, federal officials hold Anchorage planning session, say northernport could support resource development, Coast Guard, science


http://www.kasvcs.com/

http://www.judypatrickphotography.com/


By BILL WHITEResearcher/Writer for the Office of the Federal Coordinator

A federal loan guarantee authorized for the Alaska gaspipeline is intended to help smooth the path forward

for what could be the world’s most expensive private proj-ect ever.

The guarantee joins other measures in federal lawdesigned to ease the project ahead and lower its capitalcosts. The other measures include putting a key regulator ona timetable to act, accelerating the pipeline depreciation fortax savings, restricting court challenges of the project, andallowing tax credits for a massive gas treatment plant atPrudhoe Bay.

The loan guarantee is gargantuan. Congress authorized$18 billion in 2004 and linked its value to inflation, liftingthe guarantee’s size to about $21 billion today.

If the pipeline proceeds, the guarantee is intended tolower the cost of construction debt, which in turn wouldlower the cost of shipping gas through the pipeline. Theeffects would be to:

• Raise the prospects that the project gets built, is finan-cially sound and has more financing opportunities.

• Strengthen the profit potential of North Slope gas pro-ducers and the amount of state royalty and production taxrevenue.

• Arguably encourage U.S. industry and consumers toswitch to natural gas fuels because Alaska gas would bolsterthe nation’s long-term supply.

In 2004, when the $18 billion figure was born, theamount was considered adequate to back the entire amounta pipeline builder would borrow for construction. That nolonger is the case. The pipeline’s estimated cost has escalat-ed, and now the guarantee might cover just two-thirds of thedebt.

That’s not the only problematic event since 2004. Theglobal financial crisis caused the banking industry and cap-ital markets to unravel like a bad alibi. This has altered howcompanies that need to borrow a fortune get cash frombanks and investors.

Indeed, backers of an Alaska pipeline would need a for-tune. The project now is estimated to cost between $32 bil-lion and $41 billion. That means the builders might need toborrow roughly $25 billion to $30 billion. (The pipelineowners would put up the remainder of the money them-selves as their equity stake, just as a home buyer fronts thedown payment and borrows the rest of the purchase price.)

Still, with a federal guarantee, shouldn’t borrowingfunds be a relative snap?

It’s not that easy.The loan guarantee works only after a chain of other

events also happens. Not the least of these events: Thepipeline builders would need to pay a fee to cover the riskof a loan default, or Congress would need to appropriatemoney to cover the fee, or a combination of the two.

In addition, even with the guarantee, no one will lendmoney for the project unless it has locked up big gas ship-pers with gold-plated credit records, and secured scores ofgovernment permits needed for construction and operation.

Another challenge as mentioned already: the $18 billionloan guarantee no longer is enough to cover all of thepipeline project’s debt.

What Congress didInterest in building a gas pipeline from the North Slope

revived in the early 2000s when gas prices suddenly soared.Natural gas has had two historic price ranges. In the first,

from the 1920s to the mid-1970s, the average annual well-head price never topped 30 cents per thousand cubic feet.The second phase started in the late 1970s when federalprice controls began phasing out. Prices grew rapidly thengot stuck at roughly $2 for almost 20 years.

But in the last part of the 1990s, gas prices burst aheadamid concerns that the nation’s conventional gas productionhad peaked and could be headed for decline. The price dou-bled between 1998 and 2001. Prices continued rising forseven more years.

The higher price blew through the barrier that hadstymied the Alaska pipeline project for over two decades:The high cost of transporting the gas. Getting North Slopenatural gas to Lower 48 markets suddenly seemed possiblefinancially.

In the early 2000s, an Alaska pipeline project was esti-

mated to cost about $22 billion, with a transportation tarifffor shipping the gas at $2 to $2.50 per thousand cubic feet,or mcf. The project revived because market prices by thenhad reached about $3.50 or $4 per mcf. With those num-bers, the pipeline could turn an adequate profit and theNorth Slope producers could make money, too.

Still, the pipeline would be a massive undertaking thatwould be tricky to finance because of its huge cost ... andbecause it would flood the market with fresh gas. At thetime, Alaska’s 4.5 billion cubic feet a day of gas would haveboosted the U.S. supply by about 7 percent.

Believing that more domestic gas would be good for thecountry, Congress stepped in with a set of laws designed tospur the Alaska gas project.

The loan guarantee appears in the Alaska Natural GasPipeline Act of 2004. That law declared that the nationneeds Alaska’s gas to help meet growing demand. In sup-port of the project, the law also set an accelerated schedulefor permitting the pipeline and limited the timing and venueof legal challenges to the project.

The law set the loan guarantee ceiling at $18 billion.That provision, plus the tax benefits for the pipeline and gastreatment plant, apply only to projects delivering Alaska gasto the Lower 48. Where did that figure come from? It wasabout 80 percent of the $22 billion estimated project cost.And it was expected the pipeline builders would borrow upto 80 percent of the construction cost — or up to $18 bil-lion. The project now is expected to cost $32 billion to $41billion, meaning borrowings could reach $30 billion. (Thestate’s Alaska Gasline Inducement Act requires pipelinedeveloper TransCanada to use lower-cost debt rather thanhigher-priced equity for at least 70 percent of the projectcost.)

As written, funds covered by the loan guarantee may beapplied to the construction expense, interest owed duringconstruction, escalation and contingencies.

Although the law empowered the U.S. secretary ofEnergy to issue the guarantee, it did not require the secre-tary to guarantee the debt, and even more important, it didnot appropriate funding to cover the guarantee.

Issuing an actual guarantee and funding it are just two ofa series of actions needed before the debt guarantee canhelp the pipeline project. The pipeline builders also must:

• Secure long-term gas-shipping contracts from credit-worthy shippers.

• Line up the debt that the guarantee would back.• Obtain all the government permits the multibillion-dol-

lar project requires.• Negotiate state of Alaska tax terms on gas production

and the pipeline.

How the loan guarantee would workThe process of getting a loan guarantee would go some-

thing like this:Step one. Companies wanting to build the pipeline must

arrange for financing before applying for a guarantee. Thatfinancing likely will be contingent on getting a loan guar-antee.

Step two. With contingent financing in hand, the compa-nies will apply to the secretary of Energy for the guarantee.Department staff will vet the applicant. That process resem-bles what homebuyers endure to obtain mortgages: a creditcheck, a look at their income, a review of their job security,etc. For a pipeline project, those steps will include studyingthe quality of the applicant’s contracts with gas shippers tobe confident the pipeline owner will enjoy enough cashflow to repay its debt.

The staff will make a recommendation to their boss, theEnergy secretary. If the secretary grants the guarantee, thescene shifts to the federal Office of Management andBudget and the Treasury Department.

Step three. A 1990 law gives the OMB a say in the guar-antee. Congress enacted the Federal Credit Reform Act thatyear to provide a more realistic picture of how much feder-al loans and loan guarantees actually cost the governmentdue to non-payments and defaults.

The law requires the OMB to determine the “credit sub-sidy cost” of the guarantee — an estimate of how much thetreasury might be forced to pay if the loan goes bad and theguarantee kicks in. This cost gets built into the federal budg-et if the guarantee goes through.

Here’s a simplified example of how the OMB, withassistance from the Treasury Department, might determinethat credit risk fee:

Let’s say you get a $1,000 government loan, repayable intwo years. The OMB might say there’s a 4 percent proba-bility that you will default. It also might estimate that if youdo default, the government will eat 50 percent of the lossand it will get the other half out of your assets or collateral.So the OMB will decide the credit risk fee is $20, comput-ed by multiplying your $1,000 loan by 4 percent (chance ofdefault) and by 50 percent again (portion of the loss the gov-ernment will eat).

For the pipeline project, it’s unclear how big the creditrisk fee might be. OMB could calculate a figure of a fewhundred million dollars or more.

Step four. Somebody needs to pay the credit risk fee.Congress could write this check, though this appropria-

tion might be a hard sell.Another option would be for the pipeline builders to

front the credit risk fee. But this would add a cost to whatalready would be the most expensive project the companieshave ever undertaken.

Step five. The Energy Department staff and the pipelinebuilder must agree to terms. The federal agency will try tominimize the risk that the treasury will pay out anything.

These terms will define what constitutes a default, whatfinancial ratios the applicant must meet, how the loan guar-antee will be paid and under what conditions.

Some of these five steps must happen in sequence, somecan occur concurrently.

Still, a key takeaway is this: Securing the loan guaranteecould take a while.

How the guarantee would helpThe loan guarantee would help the pipeline in two key

ways.First, it would greatly lower the odds that the pipeline

project would be a financial loser for the lenders. This couldmake it easier to muster the mix of lenders from the bank-ing and bonding worlds needed to provide tens of billionsfor the project.

Second, the guarantee would give North Slope producersincentive to ship their gas through the pipeline and findmore gas.

Here’s how that second point would work.The guarantee would lower the interest rate on debt

incurred to build the pipeline.A lower rate means a lower annual interest payment.Lower interest payments mean lower tariffs for shipping

gas through the pipeline.Lower tariffs raise how much the gas is worth as oil com-

panies produce it. This “wellhead value” is a simple calcu-lation: Market price minus transportation cost. For example,if the market value is $6 per thousand cubic feet, and it costs$4.50 to clean, chill, compress and pipe that gas to market,the wellhead value is $1.50 per mcf. The transportation costwould include shipping through the Alaska pipeline as wellas any connector pipes on the way to market.

What’s unclear at this point is how much the lower inter-est rate would benefit tariffs, wellhead values, producerprofits, etc. This benefit will depend on the amount bor-rowed, the debt repayment terms, the size of the interest ratebreak and other factors. These are unknown at this point.

However, last year the joint venture proposing an Alaskapipeline made preliminary estimates of the interest ratebreak. The Alaska Pipeline Project of TransCanada andExxonMobil estimated in its open season documents thatthe guarantee could lower their interest rates by 2.25 per-centage points.

Applied to $18 billion in borrowings, that interest ratebreak would amount to billions of dollars in savings overtime.

As it is, even after a guarantee is affixed to the debt,TransCanada/ExxonMobil estimates its annual interest costat over $2 billion in the first full year it operates the pipelineto Alberta. That’s over one-third of the estimated total annu-al pipeline cost.

Increasing the guaranteeAPP, the governor, Alaska’s congressional delegation

and many of their colleagues want Congress to raise the2004-authorized loan guarantee to $30 billion.

Adjusted for inflation, what would raise the guaranteesize to about $35 billion today.

Alaska’s elected leaders and APP support another key

� N A T U R A L G A S

Loan guarantee boosts line’s prospectsCongress authorized $18 billion in 2004, linked to inflation — or about $21 billion today; goal to lower cost of construction loan

see LOAN GUARANTEE page 18




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Doyon Universal ServicesEgli Air HaulEra AlaskaERA HelicoptersEverts Air CargoExpro Americas LLCExxonMobilFairweather LLCFlowline AlaskaFluorFoss MaritimeFriends of PetsFugro . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5

G-MGarness Engineering Group . . . . . . . . . . . . . . . . . . . . . . . . .11GBR EquipmentGCI Industrial Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Geokinetics, formerly PGS Onshore . . . . . . . . . . . . . . . . . .11Global Diving & Salvage . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Golder AssociatesGreer Tank & WeldingGuess & Rudd, PC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17Hawk ConsultantsHoover Materials Handling GroupInspirationsJackovich Industrial & Construction SupplyJudy Patrick Photography . . . . . . . . . . . . . . . . . . . . . . . . . .13Kenworth AlaskaKuukpik Arctic Services . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Last Frontier Air VenturesLister IndustriesLounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMapmakers of AlaskaMAPPA TestlabMaritime HelicoptersM-I SwacoMRO Sales

N-PNabors Alaska DrillingNalco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19NANA Regional Corp.NANA WorleyParsonsNASCO Industries Inc.

Nature Conservancy, TheNEI Fluid TechnologyNordic CalistaNorth Slope TelecomNorthern Air CargoNorthwest Technical ServicesOil & Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Oilfield ImprovementsOpti Staffing GroupPacWest Drilling SupplyPDC Harris GroupPeak Civil TechnologiesPeak Oilfield Service Co.PENCOPebble PartnershipPetroleum Equipment & ServicesPND Engineers Inc.PRA (Petrotechnical Resources of Alaska)Price Gregory International

Q-ZRain for RentSalt + Light CreativeSeekins FordShell Exploration & ProductionSTEELFABStoel RivesTA StructuresTaiga VenturesTanks-A-LotTEAM Industrial ServicesThe Local PagesTire Distribution Systems (TDS)Total Safety U.S. Inc.TOTE-Totem Ocean Trailer ExpressTotem Equipment & SupplyTranscube USA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3TTT EnvironmentalUdelhoven Oilfield Systems ServicesUMIAQUnique MachineUnivar USA Universal WeldingURS Corp.US Mat Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3UsibelliWest-Mark Service CenterWestern Steel StructuresWeston SolutionsXTO Energy

Oil Patch BitsDoyon Emerald relocates to new office building

Doyon Emerald, an engineering andconsulting services firm headquartered inAnchorage, Alaska, said May 18 that is hasrecently relocated its corporate headquar-ters to South Anchorage. The new office islocated at 11500 C Street, Ste. 150,Anchorage, Alaska. The move to the newrelocation was perfect timing as theyexpect continued client growth andincreased staffing.

“This great new facility will allow us toeffectively meet the needs of our existingclients. It will also provide us with the opportunity for continued expansion of our businessoperations,” said Troy A. Johnson, president and general manager of Doyon Emerald.

The new office building will also house other members of the Doyon Ltd. family of compa-nies including the Doyon Ltd. Anchorage office, Doyon Associates Inc., Doyon Drilling Inc. andDoyon Universal Services.

Doyon Emerald specializes in services in the fields of program management, project man-

agement, process engineering, process safety, risk management, operational management,HSSE management, industrial multimedia regulatory compliance, and information technologyand telecommunications. For more information visit www.doyonemerald.com.

Schlumberger releases latest version of software Schlumberger said May 16 that it announced at the Society of Petrophysicists and Well Log

Analysts Annual Symposium the release of Techlog 2011 software, which delivers a next gen-eration application interface and expansion of customization capabilities.

“This latest release of Techlog enables customization at several levels of granularity —from the corporate perspective, within a project, and for the petrophysicist, geoscientist orengineer,” said Stephanie Gottlib-Zeh, vice president, Geoscience and Drilling, SchlumbergerInformation Solutions. “This ensures consistency and auditability, while still supporting produc-tivity and personalized workflows for individual users.”

The 2011 release delivers a complete modernization of the application interface. The newribbon interface combines highly intuitive icons with complete customization capability — tobring clarity and knowledge sharing directly into the application. A key innovation in usability,the convenient dashboard mode supports automatic window tiling to maximize the work-

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space and reduce mouse movements. Furthermore, an intelligent right-mouse-click in contextbrings frequently used tools and actions directly to the users’ fingertips. All of these newdevelopments ensure a significant increase in productivity.

For more information on the Techlog 2011 release, visit www.slb.com/techlog.

Crowley contributes to major safety milestone Crowley Maritime Corp. said May 23

that it provided 20 percent of the hourscontributed to the trans-Alaska pipelinesystem’s 10 million hours worked withoutan OSHA Day Away From Work Case.

This achievement is in part a result ofCrowley’s company-wide commitment toa strong safety culture.

For more than 30 years Crowley hasprovided tanker escort, response shipassist and vessel operations for the trans-Alaska pipeline operator, Alyeska Pipeline Service Co., in Valdez, Alaska. The safety milestoneis especially exceptional considering a majority of these employees work in the field and inenvironments with cold weather and heavy seas conditions.

“I am very proud of our Crowley Valdez team,” said Charlie Nalen, Crowley vice presi-dent, Valdez. “Together Crowley and the rest of the TAPS workforce have just completed anamazing accomplishment. This is no accident; it is the collective excellent performance ofeveryone involved in this operation that has allowed this to happen, and it is something wecan and must continue to do.”

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


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The revision addresses several con-cerns about the document raised duringlegal proceedings last year, and alsoincorporates public comment gatheredin recent months, looking in particularat the potential impact of a “Very LargeOil Spill” in the Chukchi.

BOEMRE is taking comments onthe revised draft through July 11 andplans to hold public hearings this sum-mer in Anchorage and in communitiesnear the lease area.

U.S. District Court Judge RalphBeistline recently set a deadline of Oct.3 for BOEMRE to finish the supple-mental EIS, a compromise between aSept. 15 deadline requested by Shell —which can’t drill until the case isresolved — and a late October deadlinerequested by the U.S. Department ofthe Interior and plaintiffs in the case.

Sen. Lisa Murkowski, the rankingmember of the Senate Energy andNatural Resources Committee, said shehoped the additional analysis wouldresolve the legal challenges around theChukchi, perhaps even allowing Shellto drill next summer. “There’s still a lotof process yet to occur, but this is a stepin the right direction,” she said in astatement.

Large spill ‘hypothetical’In response to an appeal against the

sale, the U.S. District Court for theDistrict of Alaska in July 2010 orderedBOEMRE to rework some aspects ofthe original EIS. The court also bannedlease related activities in the Chukchiuntil BOEMRE finished the new SEIS.

In particular, the court told BOEM-RE to address three deficiencies in theoriginal EIS: to consider the potentialenvironmental impact of offshore natu-ral gas development (distinct from oildevelopment), to determine the rele-vance of environmental informationmissing from the EIS and to adequate-ly assess the cost of getting that miss-ing information.

BOEMRE released an initial draftSEIS in October, but after reviewingpublic comments it decided to add ananalysis of a “Very Large Oil Spill,” orVLOS, in the Chukchi.

The original EIS considered theimpact of a 1,500-barrel spill from aplatform or a 4,600-barrel spill from apipeline, but did not consider theimpact of a “very large” spill, definedas 150,000 barrels of more, for two rea-sons: the court didn’t request it, andbefore the Deepwater Horizon explo-sion a spill of that size wasn’t “statisti-cally foreseeable” and many of the con-ditions in the Gulf of Mexico “were notgermane” to the Chukchi.

BOEMRE said the analysis of thatvery large spill is “based on the esti-mated size of an unlikely but possibleoil spill resulting from a hypotheticalblowout scenario.”

The analysis considers the impact ofa spill on a variety of systems, from airand water quality, to fish and birds andanimals, to plants and habitats, to com-munities located near the lease area, thesame categories BOEMRE would con-sider in a typical EIS when analyzingthe potential impacts of explorationand development on the environment.

VLOS hypotheticalThat very large spill scenario caused

a stir in early May when an internalBOEMRE memo describing the possi-

bility of a 1.4 million barrel spillleaked to the public.

Then and now, BOEMRE describedthe VLOS scenario as a purely hypo-thetical one, not an analysis of any real-world well that any real-world operatorintends to drill.

Operators must estimate and pre-pare for a worst-case spill in the pro-posed exploration plan they file beforedrilling begins. The size of that worst-case spill must is based on the specificdepth, pressure, oil and anticipatedreservoir properties for each proposedwell.

The VLOS model is created using“similar assumptions and identical ana-lytical methods” as the worst-case sce-nario in an exploration plan, but differsin a couple of ways.

First, the VLOS is a tool for analyz-ing potential environmental impacts,where the worst-case scenario includedin an exploration plan is the basis forcreating a response program.

Second, the VLOS model presentsan “extreme case,” the largest possiblespill in the lease area, not the largestspill likely from a specific well plannedwithin the lease area. The worst-casescenario for a specific well is typicallymuch smaller, BOEMRE said.

The VLOS scenario would requirean explosion, a fire and “a loss of wellcontrol during exploration drilling thatleads to a long duration blowout and avery large oil spill.” BOEMREdescribed that event as “unlikely,” but itresembles the Deepwater Horizon.

The scenario imagines a well initial-ly flowing at 61,000 barrels per day,but falling to around 20,000 bpd overthe first month as reservoir pressuredeclines. Over a 74-day period, thetime needed to kill the leak in the slow-est of three estimates, the VLOS sce-nario imagines the well dischargingaround 2.2 million barrels of oil alto-gether.

Drilling concerns remainThose explanations and figures did

little to alleviate concerns about Arcticdrilling.

“This revised draft shows that sucha spill could have catastrophic effectson the region’s species, such as theiconic polar bear as well as birds andwhales,” Cindy Shogan, executivedirector of the Alaska WildernessLeague, said in a statement that calledfor an additional halt to drilling untilBOEMRE conducted additional envi-ronmental analyses.

Shogan also criticized BOEMREfor its conclusion that while much ofthe incomplete, missing and unavail-able information in the original EISwas “broadly relevant to the importantissues at hand, none were essential fora reasoned choice among alterna-tives.” �


CHUKCI EIS U.S. District Court Judge RalphBeistline recently set a deadlineof Oct. 3 for BOEMRE to finish

the supplemental EIS, acompromise between a Sept. 15deadline requested by Shell —

which can’t drill until the case isresolved — and a late Octoberdeadline requested by the U.S.Department of the Interior and

plaintiffs in the case.


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Duvall would have been on the KangSheng Kou or one of the Foss tugs that willtow the jack-up to Nikiski, but he’s about tostart work on an independent film, “JayneMansfield’s Car,” directed by Billy BobThornton.

“Bobby Duvall is a true American patri-ot, 100 percent red, white and blue,” Davissaid.

Good, bad news on Jones Act waiverThe Spartan 151 jack-up is expected to

start drilling in late June in Escopeta’sKitchen Lights unit in upper Cook Inlet, andis due into Kachemak Bay for off-loadinglate May 29.

Escopeta recently got good and bad newsfrom the U.S. Department of HomelandSecurity in response to its request for a newJones Act waiver for the foreign-flaggedKang Sheng Kou. In a letter dated May 20,Secretary Janet Napolitano said no to a newwaiver. But she did not say what Escopetaexecutives most feared: and that was that theSpartan 151 rig would be confiscated orrefused entry into the inlet.

In fact, Napolitano made a point ofacknowledging the energy needs ofSouthcentral Alaska in her letter to Davis,offering the services of Glen Vereb, directorof U.S. Customs and Border Protection’sBorder Security and Trade Compliance divi-sion, to discuss “the facts and circumstances

of the transportation of the rig that may berelevant to the mitigation of the Jones Actpenalties that will likely result if your rig isoffloaded in Cook Inlet.”

A May 23 letter from Escopeta’sWashington, D.C., attorney, Jonathan K.Waldron of Blank Rome LLC, to Davis saidmembers of the firm had met with Vereb,who confirmed the vessel could land andoffload the rig in Cook Inlet without inter-ference.

In regard to the mitigation of penalties,Vereb asked for a letter outlining the cir-cumstances that support mitigation of thepenalties and assured Blank Rome attorneysthat CBP has no intention of pursuing anypenalty actions against any of the other par-ties involved in transporting or unloading thejack-up.

Existing Jones Act waiverEscopeta’s existing open-ended Jones

Act waiver was granted by the Bush admin-istration on the basis that the drilling and

development of the oil and gas prospects inthe company’s offshore Cook Inlet basinacreage was necessary for national securityreasons. Napolitano said “unlike in pastinstances” where the departments of Energyand Defense supported a waiver that wouldallow a foreign-flagged vessel to transportcargo from one U.S. port to another, in thiscase neither department found a waiver“necessary in the interest of self defense. …

“Nevertheless, the Department ofHomeland Security fully understands theenergy needs of the Cook Inlet/South-Central region and therefore wants to workwith” Escopeta to mitigate any penaltiesthat would normally be assessed against thecompany, the Secretary said.

Davis credits Napolitano’s decision tothe efforts of the three members of Alaska’scongressional delegation, who recently metwith Napolitano and other federal officialsto plead Escopeta’s case and explain theneed for increased oil and gas production inSouthcentral Alaska. That effort was startedseveral months ago by Sen. Mark Begich,D-Alaska.

“I think the people of Alaska are some ofthe most fortunate people in the UnitedStates, having Begich, Murkowski andYoung represent them in the fashion thatthey have in the last few months in trying toobtain a Jones Act waiver,” Davis said. “Noone could have better representation inWashington.”

Steve Sutherlin, an Escopeta contractor,said “Sen. Begich was instrumental in edu-cating DHS about the pain his constituents

were feeling from high natural gas pricesand supply worries. His leadership in theeffort to explore Cook Inlet was a proactiveresponse to the problem which we hope willprevent further suffering or disruption inSouthcentral Alaska.”

Escopeta’s initial Jones Act waiver wassecured by Republican Ted Stevens, formerU.S. senator from Alaska.

Three Foss tugs to take it to NikiskiWhen the Spartan 151 arrives, it will

“take shelter” in Kachemak Bay, where itwill be off-loaded and towed to the OSKdock at Nikiski, north of Homer, its homefor as long as four years, and possiblylonger if Escopeta moves on its option topurchase the rig.

“Foss Maritime will be using the twotugs it keeps in Cook Inlet to tow the jack-up. It’s also bringing in a larger tug fromSeattle, so three tugs will be involved,”Sutherlin said.

It will be the first time in more than adecade that a jack-up rig is headed toAlaska’s Cook Inlet.

The rig was supposed to arrive at thesouthern end of the Kenai Peninsula on May25, but because of “sea conditions”, theheavy haul vessel bringing it to Alaska “hasonly been able to travel at about 9 knots,”Vladimir Katic told Petroleum News May24. Katic heads up Escopeta’s operations inAlaska.

NPDES permit, DEC certificate issuedWhen it arrives at the OSK dock, the

jack-up’s “home” in Alaska, Escopeta willbe doing some final work on the rig to pre-pare it for drilling, which includes adding a15,000-pound blowout preventer, a majorstep-up in the equipment previously used onthe rig in the Gulf of Mexico — and thelargest blowout preventer ever employed inCook Inlet.

Once the work is complete, the rig has tobe inspected by the Alaska Oil and GasConservation Commission before drillingcan commence.

Escopeta has almost all its permits andauthorizations, the most recent being theCertificate for Proof of FinancialResponsibility from the Division of SpillPrevention and Response, which is part ofthe Alaska Department of EnvironmentalConservation, and the permit to dischargeunder the National Pollutant DischargeElimination System, or NPDES, from theU.S. Environmental Protection Agency.

“We have all but a couple of permits andauthorizations in hand,” Sutherlin said.

The company expects to be able to begindrilling between June 21 and June 30, Katicsaid. �


change to existing law: The federal government itself couldlend the billions the pipeline builders would borrow, not pri-vate markets.

Both amendments reflect a changed world from 2004,when Congress authorized the loan guarantee.

APP now expects a pipeline to cost $32 billion to $41billion, far above the earlier $22 billion estimate. The exist-ing loan guarantee no longer could cover all of the debt. Asa result, interest payments — and pipeline shipping fees —will be higher, making the project riskier. A higher loanguarantee would mitigate that risk.

The other big change since 2004 involves the bankingindustry. The global financial collapse of 2008-2009 makesit much harder today to assemble a loan package totalingtens of billions of dollars.

A possible solution: The federal government lends someor all of the money. APP and Alaska’s congressional dele-gation are eyeing help from an obscure agency called theFederal Financing Bank.

The FFB issues loans to federal departments as well asto private borrowers if the federal government guarantees100 percent of the loan. FFB loans carry the lowest interestrates available.

Congress created the FFB in 1973 in an effort to reducethe government’s borrowing costs. At the time, some feder-al agencies were issuing their own debt securities and pay-ing a higher interest rate than the normal federal rate.

As of last September, the FFB had $59 billion in loansout, with about half of that for rural utilities via Departmentof Agriculture programs. The FFB also is a source of lend-ing for the U.S. General Services Administration, for officebuildings and the like, and for the U.S. Postal Service.

An Alaska pipeline loan — whether for $18-plus billionor $30-plus billion — would be a herculean undertaking forthe FFB. But the agency did once tackle something bigger:20 years ago it loaned the Resolution Trust Corp. roughly$60 billion as the RTC cleaned up the collapse of thenation’s savings and loans institutions.

Inviting the FFB into the party would add a fifth level offederal scrutiny to the Alaska pipeline financing. After thesecretary of Energy, OMB, Treasury and Congress have

acted, the FFB would need to vet the project.It’s unclear if Congress will make the requested changes

to law. Congress is divided philosophically on many policyand spending matters, miring the flow of legislation.

Last summer, the Senate Energy & Natural ResourcesCommittee did move a bill that included raising the Alaskapipeline guarantee to $30 billion plus inflation and author-izing the FFB’s involvement. The pipeline language occu-pied about two pages of the massive American CleanEnergy Leadership Act, a comprehensive bill largelydesigned to promote green technologies.

But that bill died when Congress adjourned inDecember.

On May 9, committee chairman Sen. Jeff Bingaman, D-N.M., offered Senate Bill 916, the Oil and Gas FacilitationAct of 2011. This more modest 16-page bill includes the$30 billion and FFB language for an Alaska pipeline. �

Editor’s note: This is a reprint from the Office of theFederal Coordinator, Alaska Natural Gas TransportationProjects, online at www.arcticgas.gov/briefing-room/pipeline-topics/577.


LOAN GUARANTEE


JACK-UP RIG

Contact Kay Cashman at [email protected]

Napolitano made a point ofacknowledging the energy needs ofSouthcentral Alaska in her letter toDavis, offering the services of GlenVereb … to discuss “the facts and

circumstances of the transportationof the rig that may be relevant to

the mitigation of the Jones Actpenalties that will likely result if

your rig is offloaded in Cook Inlet.”

http://www.gci-industrialtelecom.com/

For the complex energy industry, whichoverlaps several departments, it will taketime to decide who wields the greatest influ-ence within cabinet and what prioritiesHarper has set beyond his expressed desireto build an “energy superpower” fromCanada’s extensive oil and natural gasresources.

Greg Stringham, vice president of mar-keting and oil sands at the CanadianAssociation of Petroleum Producers, hopesthe Harper government will use its newlywon control over the House of Commons todemonstrate that Canada already has strongenvironmental standards in place for oilsands development and is prepared to reducered tape to gain the confidence of interna-tional investors.

Gateway an initial testThe initial test of Harper’s “superpower”

goal will the government’s handling ofEnbridge’s Northern Gateway pipeline proj-ect to open export routes to Asia for oil sandscrude, freeing the resource from the con-fines of an economically and environmental-ly uncertain United States market.

That brings into play the ministers of nat-ural resources, environment, aboriginalaffairs and northern development (previous-ly Indian Affairs and northern development),industry and foreign affairs.

For natural resources, Harper has namedJoe Oliver, a political rookie, as his fourthholder of the office in five year.

Oliver, who turns 71 this year, brings awealth of other experience to the table,including stints as an investment banker atthree brokerage firms and head of both theOntario Securities Commission and theInvestment Dealers Association of Canada.

His understanding of the financial mar-kets was welcomed by CAPP PresidentDavid Collyer, who said an investment per-spective on the industry’s ability to attractcapital is “pretty fundamental.”

Collyer also suggested that Oliver’s expe-rience on what “makes an effective regulato-ry system” will be beneficial.

In a brief comment, Oliver said thatbecause he has “raised capital for companiesand governments in Canada and internation-ally, many of them located in Ontario,Quebec and Alberta, I think I have a back-ground that may be relevant.”

As well, he said the Harper governmentis committed to “responsible exploitation”of Canada’s natural resources, notably the oilsands sector.

Oliver’s agenda also includes negotiatinga fiscal agreement with partners in theMackenzie Gas Project, taking a leading rolein talks with the provincial governments ondrafting a national energy policy and settinga course for hydro, nuclear and renewableenergy.

GHG emissions to be curbedRetained as environment minister, Peter

Kent was quick to promise federal regula-tions to curb greenhouse gas emissions inthe oil sands and coal-fired electricity sec-tors.

But he was emphatic that Canada — inthe absence of any sign of action in theUnited States — will not introduce a carbon

tax or cap-and-trade system in the next fewyears.

“It’s been off the table for some timenow,” he said. “We just don’t believe it’spractical or advisable.”

Instead, Canada will introduce “flexibleguidelines” for Canada’s largest pollutingindustries, allowing individual sectors tomeet their targets through measures such astechnological improvements and carboncapture and storage, Kent said.

He said there is a “reasonable” chanceCanada can achieve its pledge to reduceGHGs by 17 percent from 2005 levels by2020, matching a target set by the Obamaadministration.

Kent said bitumen producers will begiven a period of grace rather than face a“hard line of sudden conversion.”

That seemed consistent with Collyer’sview that the government should avoidimposing absolute emission reductions inthe near term at a time when the oil sandssector is ramping up its crude output.

But Kent said all polluters, including oilsands operations, “will be expected toreduce GHGs.”

Project oppositionOliver, Kent and John Duncan, reap-

pointed as aboriginal affairs and northerndevelopment minister, will all have roles toplay in Northern Gateway along with KinderMorgan’s plans to increase its crude ship-ments out of Vancouver and three possibleLNG export ventures.

Those projects face daunting oppositionfrom First Nations and environmentalists tooverland pipelines and tanker traffic off the

British Columbia coast.Roger Gibbins, chief executive officer of

the independent Canada West Foundation,said the answer lies in a full public discus-sion over whether community groups shouldbe able to block the flow of oil and gas out ofBritish Columbia ports when the traditionalU.S. export market is “in trouble.”

On that issue, Harper has been clear:“We’re not going to create artificial bans on

the West Coast that don’t exist in other partsof the country.”

To varying degrees, the trio of ministers— Oliver, Kent and Duncan — will have todeal with an increasingly powerful andunbending aboriginal leadership over thedevelopment of oil and gas in northernCanada and emerging divisions within thosecommunities between those who welcomethe economic benefits of resource exploita-tion and those who fear the potential harm totraditional lifestyles.

Foreign ownershipChristian Paradis, who has been moved

from the natural resources portfolio to indus-try, will have the final say over whether spe-cific investments by state-owned foreignenterprises in the resource sector will meetCanada’s standard of corporate governance,yield a net economic benefit to the countryand pass a national security test.

The current focus is on PetroChina’s pro-posed US$5.4 billion acquisition of a 50 per-cent stake in Encana natural gas assets inBritish Columbia and Alberta — a deal thathas twice faced regulatory delays sincebeing announced in February.

Leo de Bever, chief executive officer ofthe Alberta Investment Management Corp.,which manages the province’s C$70 billionof public sector funds, said more publicdebate is needed about foreign investment,given that resources are “part of the nationalwealth” and as such Canada should “retainsome semblance of control over economicactivity.”

Also in the Canadian government’senergy picture is John Baird, the new for-eign affairs minister and a trusted lieu-tenant of Harper.

Known for his forthright manner, hewill need to mix that with diplomacy incountering international criticism ofCanada’s oil sands record and in present-ing its case for sovereignty over Arcticterritory and resource development.

—GARY PARK



HARPER Alberta’s oil sands cash cowFeeding off a recovery in crude oil demand and prices, the Alberta oil sands

could attract spending of more than C$2 trillion on new projects over the 2010-35period — C$1.85 trillion in operation, maintenance and sustaining capital andC$253 billion in initial strategic capital for construction — says the CanadianEnergy Research Institute.

The impact could contribute C$2.11trillion to Canada’s gross domestic prod-uct and C$521 billion to the UnitedStates GDP, although CERI said thesefigures should not be seen as the totaleconomic contribution of the oil sands.

The investment would boost relatedemployment in Canada (direct, indirectand induced) to 905,000 jobs in 2035from 75,000 in 2011 and in the U.S. to465,000 jobs from 21,000.

CERI Chief Executive Officer PeterHoward said the post-recession revivalof projects and the introduction of newventures has resulted in production targets of 2.1 million barrels per day by 2015(up 400,000 bpd from current output), 4.8 million bpd in 2030 and 4.9 million bpdby 2035.

The Canadian Association of Petroleum Producers is about to revise its ownforecast last spring of 3.5 million bpd, or 81 percent of Canada’s total crude pro-duction, by 2025.

CERI predicts in-situ bitumen production will match mined production by2025 and rise to 2.8 million bpd or 57 percent by 2035.

By 2035, natural gas requirements for oil sands operations are expected toreach 4.3 billion cubic feet per day — double today’s consumption — althoughnew technology and efficiency improvements will lower per-barrel gas needs.

CERI forecasts greenhouse gas emissions will rise to 89 million metric tons peryear by 2035.

Under the scenario, the Canadian government will collect C$311 billion intaxes from new oil sands projects over the next 25 years, while Alberta will receiveC$105 billion in taxes and C$350 billion in oil sands royalties. Annual royaltiesin Alberta are targeted at C$10.3 billion in 2023 and C$36 billion in 2035.

—GARY PARK

Contact Gary Park through [email protected]

CERI Chief Executive OfficerPeter Howard said the post-

recession revival of projects andthe introduction of new ventures

has resulted in productiontargets of 2.1 million barrels per

day by 2015 (up 400,000 bpdfrom current output), 4.8

million bpd in 2030 and 4.9million bpd by 2035.

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Inducement Act coordinator. Sullivan said implementation of the

governor’s plan to increase throughput onthe trans-Alaska oil pipeline to 1 millionbarrels per day within 10 years requiredan “all hands on deck effort” and saidthose he has named bring new leadershipto the effort.

Sullivan called the 1 million bpd goal“ambitious” and “audacious.”

“It’s a vision,” he told the Allianceaudience.

Alaska has the hydrocarbons, Sullivansaid, and is relatively underexplored com-pared to most basins, with only 500exploration wells on the North Slope —an area comparable to the state ofWyoming, which has 19,000 explorationwells.

It will take a comprehensive strategyto get there, he said, including: enhancingthe state’s global competitiveness;improving the permitting process (seestory in this issue); facilitating and incen-tivizing the next phases of North Slopedevelopment; unlocking the state’s fullresource potential; and promotingAlaska’s resources and positive invest-ment climate to world markets.

Sullivan said the governor’s tax reformis the cornerstone of enhancing the state’sglobal competitiveness.

Immediate improvements in handlingincoming land and water use applicationsare necessary, along with reducing per-mitting costs by streamlining the permit-ting process, he said.

Next phase of developmentThe next phase of North Slope oil

development — outer continental shelfresources, onshore federal resources,unconventional resources, smaller poolsof conventional oil and commercializa-tion of North Slope gas — needs to befacilitated and incentivized, Sullivan said.

And constructive partnerships need tobe established to unlock Alaska’s resourcepotential. Sullivan said the state is redou-bling its efforts to work with the federalgovernment. During the first two yearsthe Obama administration seemedfocused on shutting down resource devel-opment in Alaska, he said, but there aresigns that that is changing. Some of itmay be rhetoric, and the state will want tosee evidence, but the state’s goal is to

cooperate, he said. Sullivan also said that promoting

Alaska’s resources is important becausewhile Alaskans are aware of the state’sresource base, not everyone is. On arecent trip to Houston he met with leadersof companies operating in the state, butalso met with companies that don’t oper-ate here. Those companies seemed puz-zled that Alaska’s commissioner ofNatural Resources should be calling onthem when they don’t operate in the state,but Sullivan said he was there to tell themwhy they should operate in the state.

He said the reception he got inHouston was very positive.

Barron at DO&GSullivan said Bill Barron, a petroleum

engineer with more than 35 years experi-ence in oil and gas, the new director of theDivision of Oil and Gas, will be a keyplayer in DNR’s strategy to achieveincreased throughput. Barron has morethan 20 years of experience working inAlaska’s oil and gas fields, most recentlywith CH2M Hill, where he managedNorth Slope, Kenai Peninsula and CookInlet operations and maintenance. In thepast two years, Barron has managedCH2M Hill’s Canada and Lower 48 oper-ations.

He previously worked for MarathonOil in Alaska, the Lower 48 and overseas.

Barron replaces Kevin Banks, an econ-omist. Deputy DNR Commissioner JoeBalash said Banks is staying with thedivision in the commercial section.

Barron starts June 1.

Goodrum at ML&WBrent Goodrum, the retired Marine

Corps infantry officer, who started workMay 26 as director of the Division ofMining, Land and Water, is a graduate ofthe U.S. Naval Academy in Annapolis andhas a Master of Science in OperationsResearch from the Naval PostgraduateSchool in Monterey, Calif.

Sullivan said while Goodrum has noexperience in resource development, hestood out as an exceptional candidate forthe job due to his track record of leadingcomplex organizations and making themoperate more efficiently. He saidGoodrum will have a key role in manag-ing the division’s efforts to reform its per-mitting process and address the permitprocess.

Gibson at AGIAKurt Gibson, as AGIA coordinator,

will oversee state regulatory activitiesinvolving a large-diameter North Slopenatural gas pipeline. Gibson, currentlydeputy director of the Division of Oil andGas, has led the commercial branch of theAGIA team for the past four years. Healso provided key guidance on majornegotiations between the state and oilindustry players, such as the PointThomson litigation.

Gibson previously worked in theLower 48 as a natural gas trader and engi-neer specializing in natural gas pipelineprojects.

Gibson starts as AGIA coordinator onJune 1. �


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Prudhoe Bay, Alaska Phone (907) 659.2550

Fax (907) [email protected]

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involves the Cretaceous-age Torok for-mation, a sequence of shales, siltstonesand sandstones thousands of feet thick,deposited as detritus from the emergingBrooks Range along the northern sideof the mountain range.

In 2009 Calgary-based Suncorbought out Petro-Canada, the companythat had been working with AnadarkoPetroleum and the BG Group toexplore for gas in the foothills.

World-class resourceSuncor’s Jeff Bever told the AAPG

conference that the Torok formation inthe foothills appears to be gas charged,with estimates of gas in place running totens of trillions of cubic feet. To the north,near the Beaufort Sea coast, the forma-tion hosts the reservoirs of the Tarn andMeltwater oil fields. Scientists have longunderstood that because of the distribu-tion of subsurface temperatures, hydro-carbon source rocks have been cooked toform oil under the more northerly part ofthe North Slope, but that gas has prefer-entially formed to the south.

“We think there’s a lot of gas in thefoothills in the Torok. It’s world class,”Suncor’s Robin Slotboom told the con-ference.

In the foothills region there are exten-sive sandstone units with good reservoirpotential in the lower part of the Torok, inwhat geologists call “bottomsets,” sandsdumped towards the base of the subseaslope on the side of the marine basin thatonce lay on the north side of the moun-tains, Bever said.

Less than 10 wells penetrate the lowerpart of the Torok in the foothills, but thesewells all found strong gas shows, Beversaid. Unfortunately, however, none of thewells extensively tested the “bottomset”units and no gas production tests havebeen conducted in the Torok, he said.

But evidence from 2-D seismic dataand from well logs points to the excellentgas potential of these lower Torok sands.Analysis of potential source rocks andwell mud logs supports the likely pres-ence of extensive and contiguous gas-sat-urated reservoir rocks and a successionhundreds of feet thick of porous sand-stone reservoirs. The seismic data indi-

cate that the sandstones extend fairly con-tinuously across the region. There arethick shale units to seal the gas into thesandstone, and geologic faults give rise tostructural hydrocarbon traps tens of mileslong. Subsurface pressures within thereservoir rocks are high.

In addition to the proximity of tradi-tional North Slope hydrocarbon sourcerocks, geologists think that the Torokitself contains hydrocarbon sources.

Reservoir riskSlotboom said that the key geologic

risk in the Torok play is the reservoirquality. There is considerable variation inthe porosity (the ability to hold gas),while the permeability (the ability toflow the gas) is rather low. But there aresystems of fractures in the rocks thatwould provide flow routes for the gas,with the use of long horizontal wells forpenetrating clusters of fractures being apossible production technique, he said.

Reservoir modeling has indicated thatgas could flow from the reservoirs atrates greater than 5 million cubic feet perday, with a potential cumulative gas pro-duction per well of 10 billion cubic feet,Slotboom said. Analogues from produc-ing gas fields in similar geology in west-ern Canada support these flow estimates,with even the lower permeability reser-voir units providing acceptable flowrates in the Canadian fields, Slotboomsaid.

And, in addition to the potential fordeveloping gas fields involving con-ventional gas reservoirs in the BrooksRange foothills, the more deeplyburied Torok rocks have the potentialfor more economically challengingunconventional gas resources, in con-tinuous gas-saturated sands.

—ALAN BAILEY


TOROK SANDSTONES


DNR TEAMAlaska has the hydrocarbons,Sullivan said, and is relatively

underexplored compared to mostbasins, with only 500 exploration

wells on the North Slope — anarea comparable to the state of

Wyoming, which has 19,000exploration wells.


Contact Alan Bailey at [email protected]

Suncor’s Jeff Bever told theAAPG conference that the Torok

formation in the foothillsappears to be gas charged, with

estimates of gas in placerunning to tens of trillions of

cubic feet.

http://www.brooksrangesupply.com/

Duvall ‘on board’ · July 1 in-state gas line report could warrant special session just on that issue 9 AIDEA revises jack-up agreement Changes aim to give AIDEA more assurances

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