� N A T U R A L G A S

� G O V E R N M E N T

� N A T U R A L G A S

Vol. 18, No. 29 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of July 21, 2013 • $2.50

Q&A: Wielechowski pushes recall,focus on Cook Inlet, big gas line

page4

An Anchorage audience got a Washington, D.C., perspective on LNGdevelopment at the K&L Gates Second Annual Alaska Oil and GasConference July 10. LNG panel participants, left to right: StevenSparling, K&L Gates; Larry Persily, federal coordinator in the Office ofthe Federal Coordinator for Alaska Natural Gas TransportationProjects; Christopher Goncalves, Berkeley Research Group; and DavidWochner, K&L Gates. See story page 9.

Talking LNGJU

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PA

TRIC

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&L

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Buccaneer completes Cosmo No. 1planning Lower Tyonek flow test

Buccaneer Energy Ltd. recently finished drilling theCosmo No. 1 well and now plans to test a relatively shallowoil discovery at the Cook Inlet prospect, the company saidJuly 16.

The local subsidiary of the Australian independent said ithas drilled the offshore well to a total depth of 7,599 feet,slightly shallower than its initial target of 8,000 feet. Now,Buccaneer plans to install a 7-inch liner in the well to accom-modate a production test of an oil discovery at the base of theTyonek formation, according to the company.

Buccaneer said it collected 60 sidewall core samples, sixhydrocarbon samples (one gas and five oil) and 27 pressureresults using a Modular Formation Dynamics Tester.

As previously announced, Cosmo No. 1 encountered oil-bearing sands in the Lower Tyonek, some 400 feet shallowerthan the oil shows in previous Cosmopolitan wells. All told,according to Buccaneer, Cosmo No. 1 encountered some 488feet of “indicated oil and gas pay,” including 18 gas zone and

Through to 2018Chugach Electric’s new Hilcorp contract will ensure adequate gas supplies

By ALAN BAILEYPetroleum News

Chugach Electric Association, a major electric-ity utility in Southcentral Alaska, has asked

the Regulatory Commission of Alaska to approve anew gas supply agreement with gas producerHilcorp Alaska. The new agreement, together withChugach Electric’s existing contracts, will ensurethat the utility has sufficient gas to meet its antici-pated power generation needs through the firstquarter of 2018, Chugach Electric says.

Faced with pending gas supply shortages fromthe Cook Inlet basin, Southcentral utilities hadbeen anticipating having to import gas into the

region within the next couple of years or so. Butwith Hilcorp, a newcomer to the basin, pursuing anaggressive development program across many ofthe basin’s gas fields, the utilities have recentlybeen talking about the projected gas shortfall mov-ing out to 2018. The new supply agreement with

All clear for Shadura gasFWS grants NordAq access to proposed development on Alaska’s Kenai Peninsula

By WESLEY LOYFor Petroleum News

A recent decision from the U.S. Fish andWildlife Service could usher in a new natural

gas development on Alaska’s Kenai Peninsula.An agency official on June 28 signed a “record

of decision” that gives NordAq Energy Inc. theaccess it wanted to the proposed Shadura develop-ment.

The site is northeast of the Nikiski community,inside the Kenai National Wildlife Refuge. TheFish and Wildlife Service manages the refuge.

More than a year ago, in May 2012, the servicereceived a right-of-way application from NordAqto develop the Shadura site. The agency then pro-

ceeded with writing an environmental impactstatement.

The service considered a number of alternativesfor road and pipeline access to the site, including acouple that would’ve had the road come out of theSwanson River oil field to the east. NordAqobjected to these alternatives, saying they posed“financial costs and complications” that could killthe project.

In the end, the Fish and Wildlife Service grant-ed NordAq’s favored alternative, with the 4.3-mileaccess road coming in from the northwest off theKenai Spur Highway at Captain Cook StateRecreation Area. Buried gas lines and a communi-cations cable will parallel the road.

Northern resource pushAlaska, Canadian governments probe of options to get stranded oil, gas to market

By GARY PARKFor Petroleum News

The governments of Alaska, Alberta,Northwest Territories and Yukon are

making an all-out effort to get some oftheir prodigious oil and natural gasresources to market.

Energy leaders of the four jurisdictionsagreed in Anchorage July 16 to exploreevery means possible to free the strandedresources of the North Slope, Beaufort Sea,Mackenzie Delta and Central Mackenzie Valley.

Having watched the evaporation of their grandplans to ship Arctic natural gas to southern Canadaand the Lower 48, they are working on a regional

strategy that could see Canadian produc-tion shipped to Asia through Valdez, orfrom Tuktoyaktuk in the NWT.

“These are early days, but we havemany options on the table,” NWT IndustryMinister David Ramsay told PetroleumNews. “We will continue our discussionsto find the best fit.”

He said the participants hope to “meetagain sometime soon.”

Alberta Energy Minister Ken Hughessaid the governments are “pursuing all options ...south, west, east and north.”

Ramsay said they include a possible pipeline orig-

see BUCCANEER MOVES page 19

After the end of 2016 the new Hilcorpcontract would be Chugach Electric’s solesource of gas, unless the utility chooses to

take less gas than it needs by using thecontract’s flexible terms.

see GAS CONTRACT page 19

see SHADURA GAS page 20

DAVID RAMSAY

see RESOURCE PUSH page 15

ConocoPhillips to pay $263M to BP for TAPS cost pooling

In a major milestone in continuing wrangles over the ratesthat owners of TAPS, the trans-Alaska pipeline, charge for ship-ping oil in the pipeline, the Federal Energy RegulatoryCommission, or FERC, has approved an agreement by the own-ers over the pooling of costs associated with pipeline operations.And under a settlement between the owners over how pipelinecosts were allocated prior to Aug. 1, 2012, the retrospective datethat the new pooling arrangement goes into effect,ConocoPhillips has agreed to pay BP $263 million.ConocoPhillips will pay ExxonMobil nearly $9 million, whileBP will pay ExxonMobil $1.8 million.

Pipeline ownershipFollowing changes in pipeline ownership over the past year,

the pipeline is now owned by BP, ConocoPhillips, ExxonMobiland Unocal. Unocal, a subsidiary of Chevron, has previouslyannounced its intention to sell its relatively small ownershipinterest in the pipeline to the three other owners, subject to thesettlement of a dispute regarding its interests in the cost poolingagreement. And as part of the newly announced settlement, BPhas agreed to pay $5 million to Unocal, thus paving the way forUnocal’s departure from pipeline ownership.

see COST POOLING page 18

2 PETROLEUM NEWS • WEEK OF JULY 21, 2013

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

NATURAL GAS

LAND & LEASING

PIPELINES & DOWNSTREAM

EXPLORATION & PRODUCTION

ENVIRONMENT & SAFETY

11 Canadian regulators apply squeeze

Conditional approval for Shell Canada’s oil sandsexpansion suggests environmental damage likely to be severe and ‘irreversible’

10 Hilcorp finds Trading Bay gas

Asks Department of Natural Resources to add 2 held-by-production leases to the Trading Bay unit to avoid redundancies

14 Reform coming on state land management

Proposed regulations would let DNR authorize oil and gas exploration and development generallyover large geographical areas

5 Judge ‘dismayed’ over oil spill studies

Federal and state governments report delays in wrappingup research related to unresolved Exxon Valdez ‘reopener’ demand

6 A responsible route to shale development

Experts argue for comprehensive risk management, open communications when addressing concerns around the use of fracking techniques

contents

6 USCG targeting mid-August for Kulluk report

8 BSEE developing new Arctic regulations

7 Chevron denied refinery status

7 New oil sands play going commercial

5 Radioactive tracers OK’d at Prudhoe plant

15 9th Circuit rejects Greenpeace request

13 India close to deal for 10% of LNG venture

15 Homer-area hospital moving to gas

18 AOGCC to revisit 1995 NGL-MI decision

Buccaneer completes Cosmo No. 1planning Lower Tyonek flow test

ConocoPhillips to pay $263Mto BP for TAPS cost pooling

4 Wielechowski pushes SB 21 ballot recall

Anchorage Democrat says oil tax change ‘giveaway,’ bill ‘fundamentally flawed’; calls for natural gas focus on big line, Cook Inlet

8 RCA diving into Interior gas case

Asking Fairbanks Natural gas and Interior Alaska NaturalGas Utility to answer questions about existing statute, case law

9 US LNG exports — where does Alaska fit

Oil and gas conference panel reviews liquefied naturalgas market, says many projects — like Alaska’s export line — won’t go soon

GOVERNMENTThrough to 2018

Chugach Electric’s new Hilcorp contract will ensure adequate gas supplies

All clear for Shadura gas

FWS grants NordAq access to proposed development on Alaska’s Kenai Peninsula

Northern resource push

Alaska, Canadian governments probe of options to get stranded oil, gas to market

ON THE COVER

5304 Eielson Street • Anchorage, AK 99518 907.563.9060 • www.gdiving.com

COMMERCIAL DIVINGOFFSHORE SUPPORTMARINE CONSTRUCTIONENVIRONMENTAL SERVICESPROJECT MANAGEMENTLOGISTICAL SUPPORT

MORE THAN JUST A DIVING COMPANY

SIDEBAR, Page 20: NordAq seeks approval for Smith Bay work

SIDEBAR, Page 7: Pengrowth chases oil sands growth

PETROLEUM NEWS • WEEK OF JULY 21, 2013 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay NG1-01, workover BPDreco 1000 UE 16 (SCR/TD) Prudhoe Bay, rig maintenance BPDreco D2000 Uebd 19 (SCR/TD) Alpine CD4-292 ConocoPhillipsAC Mobile 25 Prudhoe Bay J-29 BPOIME 2000 141 (SCR/TD) Kuparuk 2G-11 ConocoPhillips

Kuukpik 5 Rigged up on Umiat Disp#1 Linc Energy Operations Inc. to spud November 2013

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Prudhoe Bay StackedAC Coil Hybrid CDR-2 Kuparuk 2F-18 ConocoPhillipsDreco 1000 UE 2-ES (SCR-TD) Prudhoe Bay Available Mid-Continental U36A 3-S Prudhoe Bay AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay AvailableDreco 1000 UE 7-ES (SCR/TD) Kuparuk ConocoPhillipsDreco 1000 UE 9-ES (SCR/TD) Prudhoe Bay AvailableOilwell 2000 Hercules 14-E (SCR) Prudhoe Bay AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Available Oilwell 2000 17-E (SCR/TD) Prudhoe Bay StackedEmsco Electro-hoist-2 18-E (SCR) Prudhoe Bay StackedEmsco Electro-hoist Varco 22-E (SCR/TD) Prudhoe Bay StackedTDS3Emsco Electro-hoist Canrig 27-E (SCR-TD) Prudhoe Bay Available 1050EEmsco Electro-hoist 28-E (SCR) Prudhoe Bay StackedOilwell 2000 33-E Prudhoe Bay Available Academy AC Electric CANRIG 99AC (AC-TD) Prudhoe Bay AvailableOIME 2000 245-E (SCR-ACTD) Oliktok Point ENI

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site F-01B BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site Y-33A BPIdeco 900 3 (SCR/TD) Kuparuk Well 30-04 ConocoPhillips

Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay DS 18 BPNOV ADS-10SD 273 Prudhoe Bay W-51 BP

North Slope - OffshoreBPTop Drive, supersized Liberty rig Inactive BP

Doyon DrillingSky top Brewster NE-12 15 (SCR/TD) Spy Island SP 36-W5 ENI

Nabors Alaska DrillingOIME 1000 19AC (AC-TD) Oooguruk ODSN-02 Pioneer Natural Resources

Interior AlaskaNabors Alaska DrillingAcademy AC electric CANRIG 105AC (AC-TD) Nenana Basin Doyon Ltd.

Cook Inlet Basin – Onshore

Kenai Land Ventures LLC (All American Oilfield Associates, labor Contract)Taylor Glacier 1 Kenai Loop Drilling Pad #1 Buccaneer Energy Ltd.

All American Oilfield AssociatesIDECO H-37 AAO 111 On the West side for

NordAq Energy’s Tiger Eye Central Well NordAq EnergyAurora Well ServicesFranks 300 Srs. Explorer III AWS 1 Plans to spud NCU 14 Aurora Gas

for Aurora Gas this weekDoyon DrillingTSM 7000 Arctic Fox #1 North Kenai, stacked Available

Nabors Alaska DrillingContinental Emsco E3000 273E Kenai AvailableFranks 26 Kenai StackedIDECO 2100 E 429E (SCR) Kenai AvailableRigmaster 850 129 Kenai AvailableAcademy AC electric Heli-Rig 106-E (AC-TD) Kenai Available

Cook Inlet Basin – Offshore

XTO EnergyNational 110 C (TD) Idle XTO

Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151 Furie

Upper Cook Inlet KLU#1Cook Inlet EnergyNational 1320 35 Osprey Platform RU-1, workover Cook Inlet Energy

Hilcorp Alaska LLC (Kuukpik Drilling, management contract)Monopod A-3 RD3, workover Hilcorp Alaska LLC

Mackenzie Rig StatusCanadian Beaufort Sea

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

Central Mackenzie ValleyAkitaTSM-7000 37 Racked in Norman Well, NT Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of July 18, 2013.

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

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

US 1,759 1,757 1,953Canada 294 214 296Gulf 55 57 48

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

By STEVE QUINNFor Petroleum News

Sen. Bill Wielechowski is adamantthat the new tax regime enacted in

Gov. Sean Parnell’s Senate Bill 21 is soflawed that the state’s voters need toweigh in and get a chance to overturnthe legislation.

A referendum he calls “truly grass-roots” could be on the ballot in August2014. For now, the state is reviewingmore than 50,000 signatures to see if thereferendum can be put to the voters.

Wielechowski sat down withPetroleum News to discuss what hebelieves are the flaws and strengths ofSB 21.

Petroleum News: Critics of SB 21have called the new regime a giveaway.And that word keeps coming up. Why isthis giveaway?

Wielechowski: The biggest concernthat I have with the bill — and that many

have with the bill —is the fact that everypenny of the $5 bil-lion that’s beinggiven to the oilindustry through thetax cut is for oil thatthey already prom-ised they weregoing to produce.The oil companiesare required to let(Natural Resources Department) knowand (Revenue Department) know whattheir forecasts are: how much oil theyare going to produce and where are theygoing to produce it. Every penny of thistax cut is for oil the oil companies havealready told us they planned to produceunder ACES (Alaska’s Clear andEquitable Share, the tax regime enactedin 2007). So that’s why it’s a giveaway.That’s one of the biggest fundamentalproblems that many of us have with thisbill. There are some things in SB 21 that

we supported, but this was the biggestfundamental problem, in my opinion, ofthe bill.

Petroleum News: So what things didyou support?

Wielechowski: There were provisionsfor incentives — the gross revenueexclusion in new fields and new produc-ing areas — those are things we had inthe Democratic bill. The problem we hadwith SB 21, it was expanded way beyondwhat it needed to be. It was expandedagain to include oil that wasalready going to be pro-duced. It was expanded toinclude oil in the legacyfields where the rates ofreturn according to theParnell administrationexperts are over 100 percent. You didn’tneed to provide gross revenue exclusionsin those areas. I didn’t support that and Idon’t support that.

Petroleum News: Was there anythingabout ACES that you believe was work-ing?

Wielechowski: I think ACES wasvery successful in increasing the numberof companies coming to Alaska. If youlook from the time we passed ACES(November 2007) to the present, weincreased the number of companies com-ing to Alaska by 383 percent. The funda-mental problem we saw with the old oilstructures — PPT and ELF — was thatyou had very little taxes and yet you did-n’t have companies increasing invest-ment. In fact for 30 years you had a zeropercent tax structure on 15 of the 19fields under ELF. Yet you had productiondeclining from 2 million barrels per dayto 750,000 barrels per day. You had jobsdeclining. You had investment declining.So it was a failed philosophy. PPT went

from a gross structure to a net tax struc-ture, but it didn’t fix the problem. Ourexperts told us the industry was in har-vest mode, taking very large profits andinvesting in other countries around theworld, like Libya where you had 95 per-cent tax rate, like Venezuela where youhave a 90-plus percent tax rate, likemany other countries around the world.What we said with ACES was how dowe fundamentally change the dynamichere? You have an oligopoly on theNorth Slope and you’ve had it for

decades. So we created alarge tax credit, tax deduc-tion system, which hasbeen wildly successfulbecause it’s brought in ahuge number of new com-panies. We wanted to

encourage new investment, which Iwould say was wildly successful. Youhad investment increase to all-time highsevery year except for one. It was suc-cessful in creating jobs to all-time highson the North Slope. The investment wasnot just for operating investment formaintenance, it was also for capitalinvestment. It was successful of coursefor the state because for years we hadvery low, if not no tax structure, on theNorth Slope, and we were practicallybroke by the end of 2006, so it was suc-cessful to the extent that the state got itsfair share and we were able to grow oursavings to over $17 billion. What wewere saying with ACES was what wehad going over three decades was notworking. It cost us tens, if not hundreds,of billions of dollars in lost revenue. Itdidn’t increase production. It didn’tincrease jobs. It didn’t increase revenue.

Petroleum News: Now you have a new

� G O V E R N M E N T

Wielechowski pushes SB 21 ballot recallAnchorage Democrat says oil tax change ‘giveaway,’ bill ‘fundamentally flawed’; calls for natural gas focus on big line, Cook Inlet

4 PETROLEUM NEWS • WEEK OF JULY 21, 2013

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CORRECTIONInsufficient evidence on sinking

The issue of Petroleum News for the week of July 14 incorrectly reported IHSCERA as concluding that oil sands bitumen blends sink more rapidly than othercrudes of similar density. The consulting firm’s special report said “there is insuf-ficient evidence to conclude that bitumen blends are more or less prone to sink-ing than heavy oil of comparable density. To date, practical experiences have beenlimited, tests have been lab scale and methodologies have been debated. Moreresearch is warranted.”

SEN. BILLWIELECHOWSKI

see WIELECHOWSKI Q&A page 12

By WESLEY LOYFor Petroleum News

A federal judge said he’s “dismayed”at the slow progress on studies that

could determine whether the state andfederal governments try to collect a hugesum of money for the 1989 Exxon Valdezoil spill in Alaska’s Prince WilliamSound.

Seven years ago, in 2006, the govern-ments hit ExxonMobil with a demand formore than $92 million for habitat restora-tion. The governments say lingering oilremains embedded in Prince WilliamSound and Gulf of Alaska beaches, and itcould be harmful to wildlife.

To date, ExxonMobil hasn’t paid thedemand, and the governments haven’tsued to collect the money.

The governments made the demandunder a 1991 civil settlement that sawExxon pay $900 million for the oil spill.

The settlement contained a “reopener”clause entitling governments to request upto $100 million extra to address unantici-pated injury to habitats or species.

Contracting and other snagsSince making the $92 million reopener

demand, the governments say certain stud-ies have been under way to clarify justwhat sort of actions, if any, might beappropriate to restore the injured habitats.

Government lawyers outlined the statusof these studies in a June 28 report to U.S.District Judge H. Russel Holland, wholong has presided over Exxon Valdez mat-ters.

The status report indicated the conclu-sion of a number of studies had beendelayed for various reasons.

One study looks at the feasibility ofinjecting nutrients and oxygen into sedi-ments to speed up the natural breakdownof oil. The field work included visits to 23beaches to evaluate, from an engineering

standpoint, their suitability for bioremedi-ation, the status report said.

A final report on this work was due tothe Exxon Valdez Oil Spill TrusteeCouncil by April 15. But the analysis ofdata from the field work was “delayed sig-nificantly due to unforeseen contractingissues,” the governments said, and the finalreport now is due at the end of January2014.

Other studies have to do with theimpacts of oil on harlequin ducks and seaotters. These studies also have beendelayed, or are still undergoing analysis orpeer review, the status report said.

Once the field studies are complete, thegovernments will “determine the nextsteps,” taking into consideration the envi-ronmental benefit, likely costs and publicinput.

“The Governments anticipate dis-cussing with Exxon its interest in partici-pating in those next steps, as appropriate,and a possible resolution of theGovernments’ demand to Exxon under theReopener,” the status report said.

Spilled oil still toxic, activists sayIn a brief July 1 order, Judge Holland

said he accepted the status report, butadded: “The court is dismayed that so fewof the projects that the Governments hadexpected to be completed by now havebeen completed. The court urges that thosewho are assisting the Governments in theirendeavors be required to complete theirwork by the revised completion dates.”

He directed the governments to submitanother status report by March 14, 2014.

Lawyers for ExxonMobil previouslyhave said the $92 million demand isinvalid, that the oil spill cleanup concludedlong ago, and that the company owes noth-ing more.

An organization called PublicEmployees for EnvironmentalResponsibility, or PEER, on July 15 issueda press release calling attention to the lat-est status report and Holland’s order.

“Amazingly, it’s been seven years sincethe governments demanded this paymentfrom Exxon but they have yet to collect adime,” said Rick Steiner, a PEER boardmember and retired University of Alaskaprofessor who has pushed the court toforce Exxon to pay.

Holland has declined to order payment,

saying it’s up to the governments, not thecourt, to press a reopener claim.

“The coastal ecosystem injured by theExxon Valdez spill is still a long way fromfull recovery,” the PEER press release said.“Lingering oil has been degrading at a farslower rate than anticipated and is still

affecting natural resources at toxic levels.Several marine species, from herring tootters to orcas, have not yet recoveredfrom the spill.” �

PETROLEUM NEWS • WEEK OF JULY 21, 2013 5

� E N V I R O N M E N T & S A F E T Y

Judge ‘dismayed’ over oil spill studiesFederal and state governments report delays in wrapping up research related to unresolved Exxon Valdez ‘reopener’ demand

EXPLORATION & PRODUCTIONRadioactive tracers OK’d at Prudhoe plant

The Alaska Oil and Gas Conservation Commission recently approved a requestfrom BP to inject low-level radioactive tracers into a plant that processes crude oilin the Prudhoe Bay field.

The company said it planned to use the tracers in a capacity study at GatheringCenter 2, in Prudhoe’s western operating area.The plant separates oil, gas and water.

The study will look at the efficiency of variousvessels in GC2 and guide “appropriate upgradesto the facility for increased separation capacity,”BP said in a May 14 letter to the commission.

Radioactive tracers are chemical compoundswith widespread application in industry, medicineand research.

The tracers can be detected or measured easily by their emissions, and canshow the movement of liquids within piping and vessels.

BP told the commission the half-lives of the tracers it planned to use in theGC2 study would be less than two days.

‘Exceedingly small’ volume“Radioactive tracer is needed to calculate the residence time of the oil and

water phases in the slugcatchers and the water residence time in the skim tanks,”the company said.

BP said it considered using alternatives to radioactive tracers, but decidedagainst them.

“A non-radioactive tracer would require frequent sampling, and there is a pos-

Lawyers for ExxonMobilpreviously have said the $92

million demand is invalid, that theoil spill cleanup concluded longago, and that the company owes

nothing more.

see TRACERS page 10

Radioactive tracers arechemical compounds

with widespreadapplication in industry,medicine and research.

By ALAN BAILEYPetroleum News

With concerns about possible impactsincluding groundwater contamina-

tion, excessive water consumption and gasleakages, the shale oil and gas revolutionthat is upending the North American oil andgas industry has been facing many ques-tions regarding safety and environmentalprotection.

But ensuring safe shale developmentsand dealing with the uncertainties inherentin development projects requires a compre-hensive risk management approach, twoexperts told the K&L Gates Alaska Oil andGas Conference on July 10.

Five issuesDavid Wochner, a partner with K&L

Gates, said that there are typically fivemajor issues facing a shale development,with each issue having the potential toderail a development project: the siting ofwells; water supplies for fracking opera-tions; the flow-back and disposal of frack-ing fluids; air quality; and the disclosure ofinformation about chemicals used in frack-ing fluids.

In the United States the issues surround-ing well siting are being worked out on astate-by-state basis, with an emerging con-sistency regarding requirements such asminimum distances from occupied struc-tures, Wochner said.

But the issue of water withdrawals forfracking operations is huge, despite thewater usage actually being lower than thatof some other applications such as the irri-gation of golf courses, he said. States suchas Illinois are implementing regulationsrequiring companies to submit water with-drawal and management plans, while thereis also a question of the extent to whichstates have policies for the use of non-fresh-water.

Operators are increasingly trying to savewater consumption through re-use,Wochner said. Richard Green, director ofinnovation in North America for Det

Norske Veritas (USA) Inc., said that the oilindustry is also investigating the potential tosubstantially reduce the use of chemicaladditives in areas where water can be recy-cled. And some companies are interested inthe possibility of using materials such aspropane, nitrogen or carbon dioxide asalternatives to water in fracking operations,he said.

Fluid disposalThen there is the question of how to dis-

pose of the fluids that flow back out of awell after fracking, if the fluids are notbeing recycled. Usually 25 to 30 percent ofthe injected water re-emerges as flow-back— apparently about 80 percent of these flu-ids are recycled in operations in the north-eastern U.S., Wochner said. Storage andmanagement of the waste fluids are hugeissues, with the possibility of having totruck the fluids to storage tanks or pits. Inaddition to the underground injection of thefluids, other disposal possibilities includeevaporation of the fluids in dry regions suchas Texas, or the use of brine for salting roadsin winter, as in West Virginia, Wochner said.

Issues surrounding air quality includenew Environmental Protection Agencyrules for green well completions, to mini-mize the unintended release of natural gasinto the atmosphere. Following commentsfrom the industry, the agency is using aphased approach to introducing these regu-lations, Wochner said.

Chemical additivesThe disclosure of information about

chemicals added to fracking fluids has beena major issue but was probably overempha-sized by companies concerned aboutdivulging trade secrets, Wochner said.States have been implementing regulationsfor the disclosure of fluid additives. In addi-tion, it is essential that emergency respon-ders have full information about any mate-rial they have to deal with. Regulations haveprovisions for trade secrets, which are alsostrongly protected under U.S. common law,Wochner said.

Both Wochner and Green emphasizedthe importance of considering the likeli-

hood as well as the potential impact ofissues that might impact a shale project. Forexample, a federal moratorium on shaledevelopment would have a massive impacton the industry but is extremely unlikely tohappen, Wochner said. On the other hand,local moratoria, such as the moratorium inthe state of New York, do happen but havejust a moderate impact on the industry as awhole.

Limitations on water consumption,water treatment and water disposal scorerelatively high both in terms of likelihoodand impact.

Fear of the unknownWochner said that, while shale develop-

ment creates jobs, brings new state andlocal revenues, and can spawn new sectorsin the economy, new shale technologiesbring a fear of the unknown.

“Getting citizens comfortable with this‘in your backyard’ … is an important step,”Wochner said.

And, while North America is in themidst of a shale revolution, this revolutionhas yet to catch on in other parts of theworld, Green said.

“In many parts of the world the reasonthat things are lagging is because they’restill fighting to get a social license to oper-ate,” Green said. Det Norske Veritas hasdeveloped a code of best practice for shalegas development, driven initially by consul-tations in Europe over concerns about safe-ty and environmental issues associated withshale development techniques.

Green said that, while companies need toworry about the subsurface impacts offracking, surface-related issues such aswater rights and waste disposal can presentsome of the biggest challenges.

“It’s the surface issues that can really getthe juices flowing in opposition,” he said.

And, in addition to identifying and man-aging potential project pitfalls and uncer-tainties, consistent and truthful communica-tions with the public are a key to success,Green said.

“It’s all about transparency,” he said. �

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

A responsible route to shale developmentExperts argue for comprehensive risk management, open communications when addressing concerns around the use of fracking techniques

6 PETROLEUM NEWS • WEEK OF JULY 21, 2013

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ENVIRONMENT & SAFETY

USCG targetingmid-August forKulluk report

The U.S. Coast Guard hopes topublish the report from its investiga-tion of the Dec. 31 grounding of theKulluk, Shell’s Arctic floatingdrilling platform, by Aug. 12, Lt.Cmdr. Dan Buchsbaum, chief ofinspections for the Coast Guard’sAnchorage sector, told the K&LGates Alaska Oil and GasConference on July 10.

The Coast Guard has been con-ducting a formal marine casualtyinspection of the grounding incidentand as part of that investigation helda nine-day hearing in Anchorage atthe end of May. The Agency hadoriginally planned to publish theresults of its investigation in July.

—ALAN BAILEY

“It’s the surface issues that canreally get the juices flowing in

opposition.” —Richard Green, director ofinnovation in North America, Det Norske

Veritas (USA) Inc.

PETROLEUM NEWS • WEEK OF JULY 21, 2013 7

Alaska Department of Environmental Conservation

2013 Arctic/Cold Regions Oil Pipeline Conference

September 17-19, 2013

The Alaska Department of Environmental Conservation (ADEC) is hosting an Arctic/Cold Regions OilPipeline Conference. The Conference will be held on September 17, 18, and 19, 2013 at the De-na’ina Conference Center in Anchorage, Alaska. The objectives of the conference are to:

• Inform new entrants to the Alaska Oil Industry of the unique challenges of operation in Alaska;

• Share current best practices, proven technologies, and lessons learned for challenges unique toAlaskan pipelines in the Arctic/Cold Regions;

• Provide information from federal and state government agencies regarding regulatory oversightunique to Alaska; and

• Avoid preventable environmental impacts to Alaska.

The Alaska Risk Assessment project authorized by the State Legislature provides funding to sponsor an Arctic/Cold Regions Oil Pipeline Conference that will be open to the public. This Conference aims to provide a forum to share information from established operators, governmentalagencies, and private contractors. Even though this conference will be sponsored by ADEC, the par-ticipation of other Alaskan and Federal governmental agencies will be necessary to better meet theobjectives of this conference.

Presentations will be given by engineers, planners, scientists, and research and development entities that have expertise in the construction and operation of oil pipelines in an Arctic environment. Topics relevant to this conference are summarized in the Preliminary Agenda. Q&ASessions will be held with the presenters following the presentations.

An Exhibit Hall adjacent to the Conference Room will be available each day of the conference to par-ticipants and interested public during breakfast, coffee breaks, lunch, and refreshment breaks, andduring a reception at the end of the first day (4:30 p.m. to 5:30 p.m.).

Attendee registration for the conference is $100 and exhibitor registration is $175 (includes$100 attendee registration fee). Online registration is required by the September 12, 2013deadline. Please register on line at: https://www.SignUp4.net/Public/ap.aspx?EID=20132984E. Please print your registration confirmation page and bring it with you to the on-site check in.

TECHNICAL CONTACTTim Terry, Project Manager

Shannon & Wilson, Inc.tmt@shanwil.com

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

New oil sands playgoing commercial

By GARY PARKFor Petroleum News

A lberta oil sands startup LaricinaEnergy is positioned for a break-

through in the previously untappedGrosmont formation, aiming to bring onthe first phase of its Saleski project in 2015at 12,500 barrels per day.

The company has earmarked C$520million to launch commercial developmentof a resource estimated to hold 466 millionbarrels of proved plus probable resourcesand 4.2 billion barrels of contingentresources.

Laricina Chief Executive Officer GlenSchmidt said his company hopes to intro-duce more phases over time to reach ulti-mate output of 280,000 bpd.

Laricina is 60 percent operator ofSaleski, with Osum Oil Sands holding thebalance. Korea Investment Corp. also hasan indirect investment because of its finan-cial role with the two companies.

The partnership has been testing a 1,800bpd cyclic steam-assisted gravity drainagepilot at the site since 2010.

Schmidt said Alberta governmentapproval to embark on the commercialstage “adds to the recognition of the pilot’sdemonstrated commercial production.”

Four wells drilledHe said four horizontal wells have been

drilled in the Grosmont and are “behavingas we expect.”

Schmidt said that as Saleski goesthrough steam-assisted gravity drainageproduction cycles, Laricina is continuing tovalidate the design.

“There obviously will be opportunitiesto continue to optimize further and we havesome work ongoing in the pilot to do that,such as the solvent application,” he said.

The regulatory approval covers 32wells, 12 more than are needed to supportproduction.

Although Grosmont is a new produc-tion area infrastructure such as natural gasand power lines are already in place.

Schmidt said the partnership will needexternal financing sources and plans toraise money from the markets.

Public offering expectedRandy Ollenberger, a BMO Capital

Markets analyst, said Laricina will likely

issue an initial public offering in 2014.“Technology will play a key role in

unlocking the new barrels at Grosmont andsome other producers are also lining up toinvest in pilot plants,” he said in a researchnote.

Those participants include ShellCanada, Husky Energy, Suncor Energyand Cenovus, all of them operating pilotplants.

Pengrowth chasesoil sands growth

Calgary-based Pengrowth Energyhas received final Alberta regulatoryapproval for the first commercialphase of a thermal oil sands project— a C$590 million plant to initiallyproduce 12,500 barrels per day.

The Lindbergh project is expect-ed to come on stream by late 2014and ramp up over time to 50,000bpd.

Pengrowth Chief ExecutiveOfficer Derek Evans said that“based on an outstanding pilot per-formance, we expect the commercialproject will be a highly economic,low steam-oil ration, low-declineproject that, once at full capacity,will provide the backbone for a long-term, dividend-paying” operation.

The pilot has produced 2,300 to2,500 bpd over the last two months.

Subject to company and regulato-ry approvals, Pengrowth plans tostart production from the secondphase in early 2017 and add a thirdphase by late 2018.

Unlike most of the thermal-recovery projects in northeasternAlberta, Lindberg is in east-centralAlberta near Cold Lake, whichoffers the advantage of all-seasonaccess and close proximity topipelines.

To help pay for its oil sandsexpansions, Pengrowth sold assets inWeyburn, Saskatchewan, for C$316million in March and is targeting anadditional C$700 million of disposi-tions before the end of 2013.

—GARY PARK

see OIL SANDS PLAY page 8

PIPELINES & DOWNSTREAMChevron denied refinery status

Chevron Canada lost a battle of refineries in its bid to have its Burnaby facili-ty in Port Metro Vancouver declared a “priority destination” for crude shipped onKinder Morgan’s Trans Mountain pipeline from Alberta.

The company filed the application with Canada’s National Energy Board 15months ago, claiming it was unable to access enough crude for the 55,000 barrelsper day facility.

The bid was opposed by BPCanada, Tesoro Canada, Phillips 66Canada and Shell Trading Canada,which have refineries with com-bined capacity of 590,900 bpd inthe Puget Sound area ofWashington State and which alsoaccess Canadian crude on the TransMountain pipelines.

They said that if Chevrongained the designation less crude would be available off Trans Mountain for theirrefineries, putting them at a competitive disadvantage.

Imperial Oil, which operates a refinery in the Edmonton area, also opposed theapplication.

If the board had approved the request, Chevron would have been able to receiveall 57,000 bpd of the crude it could process without being subject to apportion-ment on Trans Mountain.

Refineries curtailedCurrently, all five refineries connected to the pipeline system are curtailed on

a pro rata basis when nominations exceed the pipeline’s capacity.The NEB said that for Chevron to be rated a priority destination it would have

had to prove it was unable to meet, or was at substantial risk of not meeting, itsminimum run rate and could not reasonably ensure its long-term viability.

The regulator said, in fact, that Chevron had consistently met its minimum40,000 bpd rate and concluded that it was up to Chevron to make sure it hadenough supply options to remain afloat.

The NEB also said Kinder Morgan has until the end of September to eitherchange its procedures for allocating pipeline space or explain why they are ade-quate.

Kinder Morgan is also working on plans to expand its Trans Mountain systemto 890,000 bpd from 300,000 bpd.

—GARY PARK

The regulator said, in fact, thatChevron had consistently met itsminimum 40,000 bpd rate and

concluded that it was up to Chevronto make sure it had enough supply

options to remain afloat.

8 PETROLEUM NEWS • WEEK OF JULY 21, 2013

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continued from page 7

OIL SANDS PLAY

GOVERNMENTBSEE developing new Arctic regulations

The federal Bureau of Safety and Environmental Enforcement, or BSEE, is devel-oping new regulations for offshore oil and gas operations in the Arctic, Mark Fesmire,BSEE’s Alaska regional director, told the K&L Gates Alaska Oil and Gas Conferenceon July 10.

“BSEE is expediting the development of new Arctic standards and regulations,”Fesmire said. “The regulations will go through the normal Administrative ProceduresAct rule-making process.”

In the interests of developing appropriate draft regulations prior to the start of theformal public process, thus making the formal rule making as efficient as possible,BSEE is in the process of holding meetings with various stakeholders, including pri-vate organizations, local governments and oil companies, to discuss the agency’s pro-posals. “We’re contacting those people and talking to them about these regulationsbefore we start the formal process,” Fesmire said.

Fesmire told Petroleum News that BSEE hopes to start the formal rule-makingprocess in December.

People can expect new rules for the Arctic to include requirements for the use ofbest available and safest technology, Fesmire told conference attendees. And BSEE istaking into account unique aspects of operating in the Arctic, including issues sur-rounding the securing of a well at the end of the Arctic open water season; the possi-bility of having to move a rig from a drilling site because of encroaching sea ice orsevere weather; and the need to avoid interference with bowhead whale migration andthe associated subsistence hunting, Fesmire said. Also, with no deepwater port on thecoast of the North Slope, companies will generally have to bring their own logisticscapabilities to the Arctic offshore, he said.

BSEE has been recruiting new staff to support its Arctic activities, but budgetsequestration in Washington, D.C., has brought the hiring process to a halt at themoment, Fesmire said.

—ALAN BAILEY

� N A T U R A L G A S

RCA diving intoInterior gas caseAsking Fairbanks Natural gas and Interior Alaska Natural GasUtility to answer questions about existing statute, case law

By ERIC LIDJIFor Petroleum News

With an eye toward resolving thecompeting applications, state reg-

ulators want information from two naturalgas distribution utilities looking to servethe Interior.

The Regulatory Commission of Alaskais asking Fairbanks Natural Gas LLC andthe Interior Alaska Natural Gas Utility toanswer a series of questions designed tohelp the regulatory body discern how thetwo applications fit within existing statestatutes.

The privately held Fairbanks NaturalGas currently provides service to theurban core of the city of Fairbanks, but islooking to expand to North Pole, EielsonAir Force Base and other less-denselypopulated sections of the borough. TheInterior Alaska Natural Gas Utility is amunicipal entity wants a certificate toserve a region similar to that expansion.

The answers the utilities provide to thesix questions could have significantimplications for plans to expand naturalgas distribution across the FairbanksNorth Star Borough.

For instance, the RCA wants to knowwhether the utilities believe their applica-tions are “mutually exclusive” or would“compete to furnish identical utility serv-ice.”

If the applications are mutually exclu-sive, the RCA is required to hold a hear-ing to compare the proposals. If the appli-cations compete to the determent of thepublic interest, the RCA is allowed to

divvy up the service area or take othermeasures to improve the system for con-sumers. And while the Interior AlaskaNatural Gas Utility would typically beexempt from regulation because it is agovernmental entity, state statute waivesthe exemption when a municipal utilitycompetes directly against a regulated pri-vate utility.

Currently, Fairbanks Natural Gas canset its rates relatively at will, but under arecent settlement the utility agreed to vol-untarily become rate regulated within thecoming year.

Lisankie ponders precedentWhile the situation in the Interior is

rare in Alaska, there are previous caseswhere a municipal utility sought to servea similar area as a certificated utility. In apair of 1967 decisions — the first involv-ing the City of Anchorage and ChugachElectric Association and the secondinvolving the City of Kenai and HomerElectric Association — the AlaskaSupreme Court allowed the municipalutilities to compete against certificatedutilities within their municipal bound-aries. Today, statutes require municipalutilities to become certificated, butCommissioner Paul Lisankie said the rul-ings still create uncertainty.

If a municipal utility must prove itscredentials through the certificationprocess, he asked, could state regulatorslater deny the utility the right to provideservice simply because a “better quali-

see RCA PROBE page 9

By KRISTEN NELSONPetroleum News

A proposal to liquefy and export AlaskaNorth Slope natural gas as LNG has

advantages and disadvantages over com-petitors. That was the general consensus ofa panel at the K&L Gates Second AnnualAlaska Oil and Gas Conference inAnchorage July 10. Panel members includ-ed: Steven Sparling, the panel moderator,and David Wochner, both partners in K&LGates Washington, D.C., office;Christopher Goncalves, director of theBerkeley Research Group’s global gas andLNG advisory practice, also based in D.C.;and Larry Persily, federal coordinator in theOffice of the Federal Coordinator forAlaska Natural Gas Transportation Projects.

The panel provided a D.C.-perspectiveon Alaska’s efforts to export its North Slopegas as liquefied natural gas.

Alaska, because it isn’t connected to theLower 48 gas distribution system, isn’texpected to face concerns about exportingnatural gas that could be used domestically,but it will face federal agency approval forthe project.

Federal approvals requiredThat approval comes from two major

agencies, Wochner said: The FederalEnergy Regulatory Commission, whichhas jurisdiction over facilities for import-ing and exporting LNG, and the U.S.Department of Energy, which has author-ity over the import and export of the gas.

FERC has a “very well-establishedprocess,” Wochner said, which is similarfor environmental reviews to what theagency does for Lower 48 gas pipelines,so the agency has “a robust staff in place”with environmental and hearing experi-ence. Even with an experienced staff it’s alengthy process, taking 18 to 24 months.But because it’s a regular process projectdevelopers know what to expect fromFERC, he said, unlike the Department ofEnergy which he characterized as “any-thing but predictable.”

“And this is where all of the uncertain-ty right now here in the U.S. lies,”

PETROLEUM NEWS • WEEK OF JULY 21, 2013 9

fied” utility wanted to serve the samearea? If not, it would seem the RCAshould be allowed to issue two overlap-ping certificates, Lisankie hypothesized.

And if the RCA were forced to choosebetween two applicants, wouldn’t themunicipal utility always win, simply bythe benefit of its “privileged” status?“That is not a situation I believe we or theapplicants have considered or raised tothis point,” Lisankie wrote.

The results of the questionnaire willalso determine whether the RCA choosesto consolidate the two cases and whetherit allows a third natural gas distributionconcern eyeing the Interior market,Spectrum Alaska LLC, to intervene in theproceedings.

The utilities are required to respond byJuly 26.

The RCA is holding a public hearingon the issue on July 30.

Time is of the essenceThe distribution system is a crucial

component of a much larger program.Using state funds approved earlier this

year, the Alaska Industrial Developmentand Export Authority is spearheading aneffort to build a liquefaction facility onthe North Slope, a trucking operationalong the Dalton Highway and anexpanded distribution grid in the Interior.The goal is to reduce energy costs andimprove air quality until a more perma-nent solution — such as a large-diametergas pipeline — becomes available.

AIDEA is currently working on theNorth Slope end of the system, but soonit will need to know which utility (or util-ities) would be re-gasifying and deliver-ing the product at the Interior end of thesystem. The goal is to have the systemoperational by late 2015. �

continued from page 8

RCA PROBE

� N A T U R A L G A S

US LNG exports — where does Alaska fitOil and gas conference panel reviews liquefied natural gas market, says many projects — like Alaska’s export line — won’t go soon

Participants in panel on impact of U.S. LNG exports at K&L Gates Second Annual Alaska Oiland Gas Conference in Anchorage July 10, left to right: Steven Sparling, K&L Gates, panelmoderator; Larry Persily, federal coordinator in the Office of the Federal Coordinator forAlaska Natural Gas Transportation Projects; Christopher Goncalves, Berkeley ResearchGroup; and David Wochner, K&L Gates.

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10 PETROLEUM NEWS • WEEK OF JULY 21, 2013

� L A N D & L E A S I N G

Hilcorp finds Trading Bay gasAsks Department of Natural Resources to add 2 held-by-productionleases to the Trading Bay unit to avoid redundancies

By ERIC LIDJIFor Petroleum News

Hilcorp Alaska LLC is looking to addtwo leases to the Trading Bay unit to

accommodate production from a recentnatural gas discovery at the offshore fieldin the Cook Inlet.

The local subsidiary of the privatelyheld Houston-based company is askingthe state to expand the unit on the westside of Cook Inlet to include ADL 18731and ADL 392193.

The leases cover 5,289 acres and arecurrently held by production.

Although Trading Bay is historicallyan oil field, Hilcorp is looking to developa “newly discovered natural gas deposit”from the Monopod platform, which islocated on ADL 18731. The other lease isadjacent to it. Without expanding the unitto include the leases, Hilcorp will berequired to “install duplicative infrastruc-ture and operation systems,” according tothe company. The duplication could haveenvironmental impacts, and the timeneeded to install the systems could resultin lost royalties to the state, and lostresources too, if Hilcorp has to flareexcess gas during the interim, the compa-ny said.

Hilcorp is asking the state to expediteits decision.

The state is taking comments on theapplication through August 12.

The request extends the saga of ADL

18731.The Union Oil Company of California

and the Ohio Oil Co. acquired the lease inJune 1962 and before the end of the sum-mer Marathon Oil Co. acquired the OhioOil interest.

In 1965, Unocal and Marathon discov-ered the Trading Bay field, and the statecertified the Trading Bay No. 1A well,located on ADL 18731, as capable of pro-ducing in paying quantities. The stateincluded the lease in the Trading Bay unitin February 1967.

The Department of Natural Resourcescontracted the lease out of the unit in1972, but the certified status of theTrading Bay No. 1A well protected thelease from expiration.

A sidetrack Unocal drilled from theMonopod platform in 2002 producedfrom the Trading Bay unit, leading thestate to expand the unit in 2003 to includea segment of ADL 18731. The newrequest would bring the remainder of thelease into the unit.

Because Unocal and Marathon bothsold their Cook Inlet assets to Hilcorp inrecent years, Hilcorp now has full owner-ship of the Trading Bay unit and the un-unitized leases.

The state created ADL 392193 in2011, segregating it from an existinglease. �

Because Unocal and Marathonboth sold their Cook Inlet assets to

Hilcorp in recent years, Hilcorpnow has full ownership of theTrading Bay unit and the un-

unitized leases.

Although Trading Bay ishistorically an oil field, Hilcorp is

looking to develop a “newlydiscovered natural gas deposit”

from the Monopod platform, whichis located on ADL 18731.

HIL

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sibility the tracer would pass through thesystem between samples, yielding nodata,” BP said. “The ability to character-ize vessel inefficiencies would be com-promised with a non-radioactive tracer.”

To allow the use of radioactive tracers,the commission on June 20 amended areainjection orders for Prudhoe and relatedoil pools including Aurora, Borealis,Polaris and Orion.

“After passing through the productionfacility the radioactive tracers would beentrained in the produced water injectionsystem and injected in enhanced oilrecovery and disposal wells,” the orderfor the Prudhoe oil pool said.

The order added: “The volume ofradioactive tracer material will beexceedingly small in proportion to themillions of gallons of produced water thatGC2 handles on a daily basis.”

—WESLEY LOY

continued from page 5

TRACERS

By GARY PARKFor Petroleum News

Shell Canada battled its way throughstrong opposition from First Nations

and environmentalists to gain conditionalregulatory approval for expansion of itsJackpine oil sands mine in Alberta to300,000 barrels per day — only toencounter an unparalleled list of warningsabout the project’s negative impacts.

The conclusions are also seen as possi-ble pointers to another two controversialregulatory decisions involving the oilsands: Enbridge’s Northern Gatewaypipeline to export 525,000 barrels per dayof crude bitumen to Asia and Athabasca OilCorp.’s 250,000 bpd Dover project, withPhoenix Holdings (wholly owned byPetroChina) as a 60 percent partner.

The 100,000 bpd addition to Jackpinecovers an area of 25,000 acres and willwipe out a large chunk of wetlands, about85 percent of which are peatlands that cannever be reclaimed.

Lack of effective mitigationA joint review panel of the Alberta

Energy Regulator Board and EnvironmentCanada concluded that the addition would“likely have significant adverse environ-mental effects” on the wetlands, whichwould harm migratory birds, caribou andother wildlife and wipe out traditionalplants used by First Nations for genera-tions.

“There is also a lack of proposed miti-gation measures that have been proven tobe effective,” the JRP said.

In some of the bluntest language everused in a regulatory report, a 413-pagereport by the JRP conceded the damage islikely to be severe and “irreversible.”

“It is clear that critical issues about oilsands development are increasingly notproject specific,” the report said.

“Many of the concerns and issues relat-ed to this proposal have to do with the paceof development of the mineable oil sandsand the capacity of the regional environ-ment to absorb these developments.”

Simon Dyer, policy director at the

Pembina Institute, an Alberta-based envi-ronmental think-tank, said Canada’s envi-ronmental reputation is being put further atrisk as it keeps approving oil sands projectsin the absence of adequate rules for globalclimate change or wetland protection.

“It’s the same old stuff,” he said.

Shell reviewing conclusionsShell Canada, which has Chevron and

Marathon Oil as partners, said in a state-ment it was reviewing the JRP conclusions,which include 22 conditions, includingconservation offsets.

“Since 2007, we have strived to improvethe public’s understanding of the projectthrough extensive consultation with peopleacross the region and have submitted over18,000 pages of information and evi-dence,” it said.

The company said it has bought about1,800 acres of former cattle pasture innorthwestern Alberta to help compensatefor the loss of wetland.

A company spokesman, StephenDoolan, said the regulatory green lightdoes not mean Jackpine will be built.

“Right now our focus is on remainingcompetitive, economically and environ-mentally, and that means efficienciesthrough debottlenecking, or getting themost out of the steel you have in theground,” he said.

The report now goes to the Alberta gov-ernment and Canada’s EnvironmentMinister Peter Kent.

A decision from the federal cabinet onwhether to accept, reject or modify the JRPreport is expected within four months.

The JRP Jackpine report is seen as thefirst project review to tackle the cumulativeeffects of oil sands development, whileleaving the larger decisions on environ-mental concerns and questions about asocial license to operate to governmentlawmakers.

First Nations issuesThe legal tussle with First Nations may

not be over given the determinationshown by the Athabasca Chipewyan FirstNation, ACFN, in the northeastern corner

of Alberta.The ACFN made two unsuccessful bids

in the Alberta Court of Appeal to block theexpansion, then suffered the ultimate set-back in the Supreme Court of Canada,which refused to consider whether thecommunity had been adequately consulted.

ACFN Chief Allan Adam said “we havediligently proceeded through legal avenuesto have our (constitutional) rights upheld.”

The ACFN has hinted it may mountanother bid to block the regulatory ruling.

“We will have to decide if we moveahead with different legal strategies touphold our rights,” Adam said.

Rights guaranteedThe Canadian Constitution guarantees

aboriginals and First Nations the right tofishing, logging and hunting in their tradi-tional areas and the ACFN has argued thatthe Jackpine expansion would cause sub-stantial loss of habitat for birds, woodlandcaribou, bison and elk.

The community also said that in its finalstages the project would create a pit lakethat could hold 486 billion liters of minetailings waste, including mercury, lead and

arsenic, while contributing 1.18 millionmetric tons of greenhouse gas emissions tothe atmosphere.

Separate pipeline filingSeparately, a joint venture of

TransCanada and the Dover partnershiphas filed a regulatory application for thefirst major pipeline from new oil sandsprojects west of the Athabasca River — thelargest waterway through the oil sandsregion — targeting an in-service date ofspring 2017.

The C$3 billion Grand Rapids projectwould consist of two parallel pipelines cov-ering 300 miles and transporting 900,000bpd of blended bitumen to the Edmontonmarket and delivering 330,000 bpd of dilu-ents from Edmonton to the oil sands area tohelp with the pipeline transportation of theviscous bitumen.

In addition, Grand Rapids wouldinclude four tank farms with 350,000 bar-rels of capacity and 150,000 barrels ofdiluents capacity. �

� E N V I R O N M E N T & S A F E T Y

Canadian regulators apply squeezeConditional approval for Shell Canada’s oil sands expansion suggests environmental damage likely to be severe and ‘irreversible’

PETROLEUM NEWS • WEEK OF JULY 21, 2013 11

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tax regime and an initiative that mayfind its way on the ballot. Is this referen-dum realistic?

Wielechowski: I have never seen asmuch energy and enthusiasm behind areferendum or initiative as I have behindthis one. Many times you have referen-dums driven by certain interest groups.This referendum, it truly was grassroots.It was people coming out of nowhere andhaving very strong interest in this. Thereis no special interest driving this. It istruly a grassroots effort with very littlemoney and strong bipartisan support.The chances for success are probablyvery good. It will no doubt be chal-lenged. There will be a huge amount ofmoney spent by the oil industry to per-suade people that it’s a bad thing.

Petroleum News: Getting back to thegiveaway term for a second, some sayit’s giving away. Some say it’s takingless. Is there a semantics issue here?

Wielechowski: The constitution saysyou have got to get the maximum benefitfor the resource. I have a hard timeunderstanding how we are following theconstitution when we are giving $5 bil-lion to the oil industry to produce oilthey already said they are going to pro-duce under the ACES tax structure, soyou really get nothing for it. By its verynature, it’s a giveaway. You have a prod-uct that is very valuable that is going tomake the oil industry a tremendousamount of money. They have agreed theyare going to produce it at a certain rateand you just cut their rate. No businessin the world would operate like that. It’sa terrible way to run government.

Petroleum News: A ConocoPhillipssenior executive told Wall Street during aspring presentation that SB 21 will make

a difference. It’s one thing to tell theLegislature one thing, but telling WallStreet that could be another altogether.What are your thoughts on that?

Wielechowski: When the oil industrytestified six years ago when we passedACES, there were three different chartsproduced: a 15 percent decline; a 6 per-cent decline; a 3 percent decline, andthat was the best case scenario underACES. We expect we will have a 2 or 3percent decline in the next few years.That’s proof by the metrics they set thatACES was working. It’s interesting tohear what companies are telling WallStreet because you can go back to state-ments made by senior executives overthe years where they say Alaska offersstrong rates of return or they say Alaskaoffers strong cash margins, or the saythey are going to invest hundreds of mil-lions of dollars at very high rates ofreturn.

People can say whatever they want, Isuppose. When you look at the companyprofits, when you look at the rates ofreturn, when you look at the cash mar-gins, there is no denying Alaska isamong the most profitable places in theworld to do business. You compare theprofits per barrel in Alaska — it was $28to $29 per barrel. Globally it was $12 to$15. The profit per barrel is $28 or $29versus $3 to $4 in the Lower 48.Executives can say anything, but whenyou look at the numbers, you can see theindustry has made profits of $36 billionsince we passed ACES. According toParnell’s own experts, you’ve got rates ofreturn between 65 and 123 percent rangein Alaska compared to 20 to 30 percentin North Dakota, Norway and Canada.The numbers show Alaska is one of themore profitable places in the world. Infact Alaska is more profitable to do busi-ness in than it is to do business in NorthDakota at $115 or below. That’s accord-ing to Parnell’s experts.

Petroleum News: So would you sayAlaska is competitive under ACES?

Wielechowski: Absolutely. We arecertainly competitive in the legacy fields.If you look at the rates of return, wewere still competitive on the new fields.One of the areas we wanted to focus onwere the new fields. That’s what theSenate Democrats and the HouseDemocrats said: if you’re going to makechanges make it for new oil from newfields. That’s where we were less com-

petitive. For the newer fields, we couldhave tweaked that and be more competi-tive. That’s why we proposed legislationto do that.

Petroleum News: The proponents of SB21 say you need to give it time and let itwork. So what will you be looking for overthose next several years to gauge the suc-cess?

Wielechowski: Again, the problem withSB 21 is it’s a fundamentally flawed billand it’s flawed because you have givenaway $5 billion for oil that they werealready going to be produce. Nothing cancorrect that. That is a flaw which can onlybe fixed next August when the voters goto the polls. If for no other reason torepeal SB 21, it should be for that reason.You can cut that part out and leave the restin the bill and have a vastly improved bill.Just for that reason alone, you shouldoverturn that bill. Alaska will never beable to recoup the money it’s losing fromthis sheer giveaway. You can’t correct thebill. You don’t need to give away $5 billionand get nothing in return. That’s just terri-ble business. There is not a business in theworld that would do that. There is not agovernment in the world that would dothat.

Petroleum News: OK, but just the sameif this is an issue of giving the bill time towork, what other things would you belooking for if this is about the bill thatneeds time?

Wielechowski: The very structure ofthe bill is critically flawed in that you’regiving away $5 billion. There are otherprovisions in the bill — gross revenueexclusions — that I think will have animpact worth watching on the NorthSlope. Those are things we proposed inthe Senate and House Democratic bills.But you can’t get around the fact that thisis a bill that gives away money for noth-ing. It will never be a success becauseyou’re giving away money for oil that theysaid would be produced during ACES. Wehad an amendment that said you don’t getthe credits for oil you already said you’regoing to produce. If you got rid of thatprovision, then come back and ask me thequestion.

Petroleum News: You’ve talked aboutthe constitution earlier. Both sides of theargument say it’s the constitution that’sdriving their position. How do you rec-oncile that?

Wielechowski: The constitution saysyou’ve got to get the maximum benefit forthe resource. I’m eager to hear how givingaway $5 billion for nothing is meeting ourconstitutional requirements to get the max-imum benefit the resource. There is noway this meets the constitutional obliga-tion. It’s patently violating the constitution.

Petroleum News: Let’s move on toanother subject. Gas lines. What kind ofprogress would you like to see during theremainder of the interim?

Wielechowski: I’d like to see the bigline move forward. I’d like to see the bigthree come together with a plan and let’sget moving on it. Let’s start the project.We’ve been waiting a long time. I thinkthe problem with the smaller line hasalways been volume. You’re spending $8billion to build an 800-mile line and thetariffs are going to be extremely high.When I talk to people in my district and Iask them do you want a small-diametergas line from the North Slope, manyhands in the room go up. When I ask peo-ple are you willing to pay double for gasto get it, most hands go down. We’ve got19 trillion cubic feet of gas according tothe USGS right in our backyard in CookInlet. That’s enough gas to last 200 years.The idea that you can bring gas from theNorth Slope and ship it 800 miles cheaperthan you can move it 25 miles out of yourbackyard will be proven to be incorrect,whereas the big line, the economics aremuch better.

Petroleum News: There are two schoolsof thought when it comes to negotiatingtax terms on the big line. One says waituntil the companies have a firm project.The other says the companies need thesecosts understood before they embark on amultibillion dollar commitment. Where doyou fall?

Wielechowski: It’s a good question andone that’s been kicked around over theyears. It’s hard for the state to set fiscalterms without having some idea of whatthe gas line is going to look like and whatsort of fiscal terms the industry is going toneed. I would like to see what the industryproposes and what their cost structure isgoing to be. If you set fiscal terms firstand the industry comes in and says that’snot enough, well you don’t have the num-bers from the industry to know whetherit’s enough or not enough. It would be pre-

12 PETROLEUM NEWS • WEEK OF JULY 21, 2013

continued from page 4

WIELECHOWSKI Q&A

see WIELECHOWSKI Q&A page 14

PETROLEUM NEWS • WEEK OF JULY 21, 2013 13

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NATURAL GASIndia close to deal for 10 percent of Pacific Northwest LNG venture

India is on the verge of making its entry into Canada’s LNG industry, with twoof its state-owned companies expected to pay C$1 billion for a 10 percent stake inthe Pacific NorthWest LNG venture controlled by Malaysia’s Petronas.

After years of hints, speculation and expressions of interest, Indian Oil Corp.and Petronet LNG are aiming to conclude a deal towards the end of 2013, sourcesin the company said.

Pacific NorthWest has already signed on Japan Petroleum Exploration as a 10percent partner for an undisclosed amount. That transaction will give Japex a rolein shale gas assets in northeastern British Columbia and the liquefaction plant tobe built at Port Edward, near Prince Rupert on the northern B.C. coast.

Export starting in 2019So far, Pacific NorthWest has a Canadian National Energy Board permit to

export 19.68 million metric tons of LNG a year starting in 2019 and has threeinternational contractors working on the final engineering design.

The Canadian Environmental Assessment Agency has also issued guidelinesfor public hearings and Pacific NorthWest intends to submit its regulatory appli-cation by late 2013.

Pacific NorthWest President Greg Kist said in June that the company’s doorswere open to more partners in the $11 billion project.

He said Asia is “our target and clearly Canadian LNG companies have anadvantage of reaching out to that market due to shorter sailing times.”

“Historically, LNG producers have favored an oil-indexed pricing like JCC(Japan crude cocktail) but we will establish an acceptable pricing structure as partof negotiations with offtake customers,” he said.

China ruled out as partnerIndustry sources have ruled out any prospect of Pacific NorthWest selling a

stake to Chinese companies if the deal with India falls through because of China’sextensive involvement in the global LNG sector.

Kazakhstan earlier in July blocked India’s plan to buy ConocoPhillips’ stake inthe giant Kashgan oil field for $5 billion, with sources predicting China will winthe same stake for up to $5.4 billion.

Banking sources say Indian Oil will choose an investment bank advisor soonand expects to make an early announcement on a “long-term attractive offtake”sales contract for Pacific NorthWest.

—GARY PARK

Wochner said. Other than the Kenai LNG facility, the

U.S. has not been an LNG exporter — infact the Lower 48 was for decades short ofnatural gas, he said.

With the natural gas surplus in theLower 48 the Department of Energy has20 applications pending for export. Whilea license is automatic for countries withwhich the U.S. has a Free TradeAgreement, the only big importer amongthose 19 nations is South Korea, andWochner described the DOE process forexports to other countries as “robust” withlogistics complicated by the very smallstaff, four to five, in DOE’s Office ofFossil Energy which handles import-export licenses.

He said that office went from an officewhich occasionally got an application forimport “to an agency that is at the fore-front of a major political debate inWashington right now. They don’t have thestaff to be able to handle that,” Wochnersaid.

The result is a holding pattern, he said,with one license issued a couple of monthsago, although “the hope is that they’regoing to begin to move through these fair-ly quickly.”

The competitionPersily described the competition —

countries that want to get into the LNGexport business.

Last year there were 16 countriesexporting LNG and “half again as many”that want to get into the business in thenext decade, he said.

Persily said Alaskans tell him they areconcerned about the competition, but hesaid those competitors also have chal-lenges.

Among existing producers, for exam-ple, Egypt is already running short of gas;Yemen has political problems; Norway hashad technical issues; and Angola, whichjust came on line, was 18 months behindschedule.

There is space in the market, Persilysaid: Papua New Guinea — coming online soon — and Australia, with sevenprojects under construction, have most oftheir LNG already sold.

“They’re not our competitors as welook ahead to the 2020s and beyond,”Persily said. While Russia, the Lower 48and British Columbia are all working toget into the market (or to get more gas intothe market in Russia’s case), most of thoseprojects won’t be built in the next decade,he said: “The world just doesn’t need thatmuch LNG.”

So who will get into the market? Persily said “the winners are going to

be the ones where the project developerscan get together with government and de-risk the project so that they can sell gas ata competitive price and win customers.”Alaska isn’t out of the running, he said.

The market of the futureThe impact of exports on the domestic

natural gas price has been a concern, butGoncalves said “so far we haven’t seen

that it’s slowing any permits down,”though it may become more of an issuewith the next wave of export terminals.

Even if the Department of Energy iscomfortable with the price impact, thereare the issues of whether prices are sus-tainable and global impacts, and whetherthe banks will “take the risk on multibil-lion-dollar investments.”

The price spread between NorthAmerican traded hub prices “primarilydriven by abundant — I won’t say cheap— but economic, affordable shale gas pro-duction” and Asian LNG prices makesexport LNG projects attractive, Goncalvessaid. He said shale gas production repre-sents more than 35 percent of Lower 48production and will represent 50 to 60 per-cent within a few years.

The price spread relates to the fact thatin most places, particularly Asia, LNG isindexed to oil, and the focus is on chasingthose high LNG prices, in the $17 to $18range, compared to the U.S. hub-tradedprice of about $4.

Is that spread sustainable? It’s a “short-term phenomenon — it’s

really only been a factor for the last sever-al years,” he said.

There wasn’t much of a spread asrecently as 2006 but with more “tighten-ing of the market” following theFukushima nuclear disaster in Japan thespread has grown.

The current spread comes from twofactors, Goncalves said: tightening of theLNG market and the Lower 48 productionboom.

And while U.S. concern has been aboutexports driving up domestic prices,Goncalves said work done by his firmdoesn’t find any major impact on U.S.prices over the next 10 to 15 years fromLNG exports. The impact is expected tobe 90 cents to a dollar, he said, which isn’t“major insofar as most of the people whoare thinking about burning more gas forpower plants, for industrial, petrochemicalfacilities or transportation infrastructure,shipping, rail, LNG trucking and so forth.”

And as shale production catches upwith an expected level of exports thedomestic price impact of exports isexpected to drop to 40 to 50 cents.

The price angle which hasn’t receivedmuch attention is the possible impact ofincreasing U.S. production on the Asian orEuropean prices for natural gas, he said.

Then there is the impact of U.S. exportson projects worldwide.

Looking at proposed export projects“terminal by terminal, project by project,”Goncalves said “on balance about half ” ofthe proposed projects out of Australia andsome from East Africa “could be impact-ed or delayed by the North American sup-ply.”

Which projects will go forward?He said it will be “the projects that are

the best designed, that have the criticalpath variables put in place sooner, andhave good economics, supply chain logis-tical solutions to offer the customers thatare going to go forward faster” while otherprojects won’t go away, but will “keeptheir powder dry for another day.” �

continued from page 9

PANEL DISCUSSION

By WESLEY LOYFor Petroleum News

The Alaska Department of NaturalResources is proposing new regula-

tions that could revolutionize explorationand development approvals on state land.

The regulations spring from enablinglegislation (House Bill 129) state law-makers passed in April.

Gov. Sean Parnell offered the legisla-tion as part of his efforts to reform per-mitting and quickly boost Alaska’s oil andgas production.

The new law allows DNR to “reviewand authorize oil and gas exploration ordevelopment across a geographical arearather than by individual project,” says afour-page explanatory letter posted onlineat http://tinyurl.com/pkjo7ls.

Fewer steps Within an area authorized for explo-

ration or development, an oil and gas les-see still would have to submit a plan ofoperations for DNR approval before workbegins, the explainer says.

If the plan complies with certain termsand conditions, DNR may approve suchplans “without a separate public notice.”

The Parnell administration says thebill will cut out “repetitive” steps in thepermitting process, such as some of thepublic notice and comment periods asso-ciated with pushing a project through theseismic, exploratory drilling and develop-ment phases.

Some industry players endorsed thelegislation, saying it would provide relieffrom the current “inefficient and cumber-some” permitting process.

But critics, including environmental-ists, said allowing DNR to establish “gen-eral conditions” for exploration anddevelopment would short-circuit publicreview of specific project plans.

Size limits specifiedThe lands DNR could approve for

exploration and development would bewithin previously offered oil and gaslease sale areas.

The proposed regulations include lim-its on the size of these areas, though theystill could be very large.

“A geographical area for explorationwill not exceed 35 percent of a lease salearea,” the explainer says. “For the NorthSlope Areawide lease sale area, thatmeans a single geographical area forexploration will not exceed 1.785 millionacres. A geographical area for develop-ment will not exceed 300,000 acres. Forcomparison, the Prudhoe Bay Unit on theNorth Slope is about 255,000 acres.”

DNR would exclude land adjacent toincorporated communities, such asNuiqsut on the North Slope and Homeron the Kenai Peninsula, as well as unin-

corporated communities with a popula-tion of more than 200 people.

The proposed regulations spell out thecriteria and information DNR will con-sider when authorizing exploration ordevelopment in a geographical area. Theadministration says people will have achance for input at the front-end of theprocess.

An exploration and developmentauthorization could last up to 10 years.

“Under the new law, the DNR and thepublic can look holistically at a broadergeographical area when evaluating howoil and gas exploration or developmentshould occur on state land,” the explainersays. “Through this process, the DNR canminimize adverse effects on state landand resources, ensure the state is develop-ing its resources by making them avail-able for maximum use consistent with thepublic interest, and provide an opportuni-ty for the public to comprehensivelyreview oil and gas activities within a geo-graphical area. For the lessee, a geo-graphical area approval also provides cer-tainty about conditions under which it canexplore or develop in that area. And whenapproving exploration or development fora geographical area, the DNR will still beable to safeguard environmental, subsis-tence, community, recreational, and his-torical concerns through special stipula-tions and conditions.”

The new law does not cover the trans-portation, or pipeline, phase of oil and gasdevelopment. Transportation will contin-ue to be evaluated under existing laws andregulations, the explainer says.

The state has set an Aug. 19 deadlinefor people to comment on the proposedregulations. �

14 PETROLEUM NEWS • WEEK OF JULY 21, 2013

mature to set fiscal terms on gas until youhave a pretty firm understanding on thecosts and economics are going to looklike on the big line.

Petroleum News: On to the Arctic. It’sbeen discussed a lot during the interim.What do you believe the state’s roleshould be, whether it’s ANWR or off-shore?

Wielechowski: I think the state needsto take an aggressive role in responsibleresource development in the Arctic.There’s an enormous amount of oil andgas onshore and offshore. The stateabsolutely needs to lead the charge onthat. The federal government has shownvery little inclination in the Arctic forwhatever reason. I’m glad the state is tak-ing a more aggressive role on that. That’simportant to our future; it’s important toour country’s future. It’s the next GoldRush in my opinion. You’re going to seeopen shipping lanes that will dynamicallychange the way trade is done, not just inthe Arctic but across countries. There istremendous opportunity there. Now is thetime that we need very strong leadershipand assert our rights over the oil and gasthat’s there and over the resources in theArctic. �

Thank You

Kennedy & AssociatesKim Heacox PhotographyKoniag, Inc.Northern Economics, Inc.Oasis Environmental, Inc. Pacific Star EnergyStoel Rives, LLP Trident Seafoods CorporationUdelhoven Oilfield System Services, Inc.

Lead Corporate Partners ($25,000 & above)Alaska Airlines & Horizon Air . BP ConocoPhillips Alaska, Inc. . Petroleum News

Corporate Partners

ABR, Inc. Accent Alaska.com-Ken Graham AgencyAlaska Business Monthly Alaska Journal of CommerceAlaska Rubber & Supply, Inc. Alaska Sportsman’s LodgeAlaska Wildland Adventures Booz Allen HamiltonBristol Bay Native Corporation

Calista CorporationCarlile Transportation Systems, Inc. CIRIClark James Mishler Photography CONAM Construction Company Denali National Park Wilderness Centers, Ltd. Fairweather, LLCFlint Hills ResourcesJenner & BlockKachemak Bay Wilderness Lodge

Commercial salmon fishing near Prince of Wales Island in Alaska’s Tongass National Forest. Annually, healthy salmon runs contribute one billion dollars to the economy of Southeast Alaska.

Corporate Council on the Environment

We work with people to conserve the lands and waters that sustain us all. Join us in protecting and restoring the places that make Alaska a great place to live, work and play.

The Nature Conservancy715 L Street . Suite 100 . Anchorage, AK 99501 . alaska@tnc.org . 907-276-3133 . nature.org/alaska

� L A N D & L E A S I N G

Reform coming on how state manages landProposed regulations would let DNR authorize oil and gas exploration and development generally over large geographical areas

continued from page 12

WIELECHOWSKI Q&A

inating in the Alberta oil sands, picking upcrude from the NWT’s Central MackenzieValley and Beaufort Sea, then swingingacross the northern Yukon to connect withthe Trans Alaska Pipeline System toValdez, opening tanker routes to Asia.

Also being studied are possible LNGexports out of Alaska, drawing on 6 trillioncubic feet of gas reserves in the NWT’sMackenzie Delta and more than 30 tcf onAlaska’s North Slope, both losing out onplans to build pipelines to southern marketsafter being overwhelmed by the develop-ment of shale gas.

As well, Ramsay said the NWT andAlberta are studying the feasibility of apipeline along the Mackenzie River Valleyto Tuktoyaktuk on the Beaufort, with ship-ments reaching Asia through the BeringStrait.

He said the NWT favors a northernpipeline over a rail link from Alberta toAlaska because it would provide an outletfor the NWT’s prospective oil fields.

Hughes said a study of the Tuktoyaktukplan is nearly complete and an assessmentof a pipeline to Alaska is due to be finishedby 2014.

Exploration success keyTo augment the NWT case for pipelines,

the government is counting on early oil andnatural gas exploration success in two keyareas — the Devonian Canol and theBeaufort, Ramsay said.

Those two plays have a combined workcommitments of more than C$2 billionthrough federal exploration licenses.

Husky Energy, Shell Canada,ConocoPhillips Canada and MGM Energyare in advanced exploration stages in theDevonian Canol and Ramsay said hebelieves a partnership of Imperial Oil,ExxonMobil and BP is “ready to answerthe call. ... We’ve got a big spend comingthere.”

He said the companies “don’t want tosay specifically at this point when theyhave in mind,” but he anticipates announce-ments within a year.

Ramsay said his meetings in recentweeks with industry leaders in Calgary andHouston “have been positive.”

Changed ‘mindset’He said the NWT government’s opti-

mism is further strengthened by a changed“mindset” among northern aboriginal lead-ers.

They are “tired of seeing unemploymentrates of 30 percent to 40 percent in theircommunities” and are open to negotiatingequity stakes in major projects along thelines of a deal they have in place for a pos-sible one-third ownership position in the

Mackenzie Gas Project pipeline, Ramsaysaid.

He said a significant step forward isscheduled for April 2014 when control overresource development is transferred fromthe Canadian government to the NWT,meaning the petroleum industry will haveto deal with only one government.

Although sensitivities over crude-by-railplans are high, Hughes did not rule out aproposal by Vancouver-based G SevenGenerations, which has strong ties withCanadian First Nations, to build a rail linefrom the oil sands to connect with thetrans-Alaska oil pipeline.

He did not believe the disaster at Lac-Megantic in Quebec would stop theincreasing use of rail to carry crude,although safety precautions should beramped up.

“The Quebec tragedy reminds us that ifwe’re able to handle the immense amountsof oil we see being developed we’ll have toup our game in all aspects,” Hughes said.

Alaska officials were not available tocomment on the rail idea, but State Rep.Bob Herron, Democrat of Bethel, toldPlatts Oilgram News the rail option “willget a chilly reception here after the Quebecdisaster.”

Representatives of G SevenGenerations have made contacts inAlaska in recent months and have spokenof a system capable of hauling 1 millionbarrels per day, but industry sources haveargued that number is unrealistic. �

PETROLEUM NEWS • WEEK OF JULY 21, 2013 15

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GOVERNMENT9th Circuit rejects Greenpeace request

The U.S. Court of Appeals for the 9th Circuit has rejected a request byGreenpeace that the entire court should rehear the decision in March by a panelof three 9th Circuit judges to uphold an injunction barring Greenpeace frominterfering with Shell’s Arctic offshore drilling operations. After the federalDistrict Court in Alaska imposed the injunction on Greenpeace in May 2012, theenvironmental activist organization appealed the District Court decision to the9th Circuit.

But the 9th Circuit judges have been farfrom unanimous in their views of the injunc-tion. The March decision upholding theinjunction was a majority verdict, with onejudge on the panel expressing a dissentingview. And the rehearing request, which hadto be considered by all eligible 9th Circuitjudges, also resulted in a majority decision,with six judges disagreeing with the rejec-tion of the request.

The legal contention over the Greenpeaceinjunction revolves around the fact that,while Shell had cited actions by Greenpeace organizations around the world asevidence that Greenpeace intended harm to the company’s Arctic activities, theinjunction was against Greenpeace U.S.A., an entity that, while verbally sup-porting actions taken by other Greenpeace organization, had not itself partici-pated in those actions.

Separate entityApparently Greenpeace U.S.A. is a completely separate legal entity from

other Greenpeace organizations, with each organization licensing theGreenpeace name but acting independently. Greenpeace had argued — andsome of the judges had agreed — that a court could not impose an injunction onGreenpeace U.S.A. based on the actions of other entities over which it had nocontrol.

“In doing so, the decision disregards corporate norms of limited liability andrelies on a guilt-by-association model that offends justice,” the dissentingjudges wrote. The dissenting judges also said that penalizing Greenpeace U.S.A.for statements endorsing the actions of other Greenpeace organizations likelyinfringed Greenpeace U.S.A.’s rights to free speech under the U.S. constitution.

Meantime in London six Greenpeace protesters were arrested for trespass onJuly 11 after climbing the Shard, Europe’s tallest building, in protest at Shell’splans for drilling in the Arctic. According to a report in the Guardian newspa-per three Shell office buildings, including the company’s London headquarters,are in line of sight of the top of the Shard.

—ALAN BAILEY

Apparently GreenpeaceU.S.A. is a completely

separate legal entity fromother Greenpeace

organizations, with eachorganization licensing the

Greenpeace name butacting independently.

NATURAL GASHomer-area hospital moving to gas

After decades of waiting, Homer has gas.The South Peninsula Hospital is hosting a “valve-turning ceremony” on July 25 to

celebrate becoming the first public building in the city to convert to natural gas.The rest of the region is close behind.As of July 8, Enstar Natural Gas Co. contractors were constructing the Homer

trunk line and expected to connect the line from Anchor Point to Homer High Schoolwithin two weeks. Additional contractors are working on the distribution system with-in Homer.

The work to extend the line to Kachemak City should be completed imminently, atwhich point crews plan to begin installing service lines through the local project area.

While the majority of the Southcentral region already uses natural gas, the south-ern tip of the Kenai Peninsula remained on diesel fuel for decades because of the lackof transmission infrastructure. The state recently helped pay for a trunk line to Homerand the remainder of the project is being funded by a surcharge added to local utilitybills.

—ERIC LIDJI

continued from page 1

RESOURCE PUSHAlso being studied are possible

LNG exports out of Alaska,drawing on 6 trillion cubic feet of

gas reserves in the NWT’sMackenzie Delta and more than30 tcf on Alaska’s North Slope,

both losing out on plans to buildpipelines to southern markets

after being overwhelmed by thedevelopment of shale gas.

Vigor Industrial, community college, opened centerVigor Industrial said that it has part-

nered with South Seattle CommunityCollege launching an industrial trainingcenter at the shipyard on Harbor Island.The Harbor Island Training Center, whichopened with a ribbon cutting ceremonyJune 7, will provide students with theindustrial skills they need to get family-wage jobs at the region’s industrial man-ufacturers. Classes began July 1.

“There’s a disconnect between indus-try and a lot of talented, hardworkingpeople in this country,” explained Sue Haley, Vigor’s senior vice president of humanresources. “People want to work and industry needs a highly skilled workforce. However,Vigor and other manufacturers can’t find enough workers with the right skills to fill good-paying jobs. This training center will bridge that disconnect by providing motivated localpeople with critical industrial skills.”

Partnering with South Seattle was a natural fit, she said, with Vigor providing the loca-tion, equipment and a real-world industrial workplace, and South Seattle Community

College’s welding and manufacturing programs bringing their long expertise in skills train-ing and instruction. The center is already garnering wider community support, including apartnership with the United Association of Plumbers and Pipefitters and Local 32, whichdonated welding machines and will provide additional training options.

The center is located on-site at the shipyard, and includes a computer lab, classroomspace and an industrial training floor with weld-booths and industrial machining equip-ment. The shipyard location will also allow students to experience how the facility worksand learn from veteran workers. For more information visit www.southseattle.edu/harbor-island-training-center.

GCI announces launch of new business website General Communication Inc. announced the launch of a new business website July 15,

www.gci.com/business, now offering customers more solutions, more support, and moreexpertise.

“The new website was designed to be engaging, dynamic and user-friendly while fea-turing smart technology solutions for Alaskan businesses,” said Rochelle Marshall, directorof commercial marketing & sales operations. “We’re excited to provide our customers withaccess to relevant content for a wide range of sectors including small business to enter-

16 PETROLEUM NEWS • WEEK OF JULY 21, 2013

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

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PETROLEUM NEWS • WEEK OF JULY 21, 2013 17

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prise.”The site includes extensive product information to help customers understand GCI’s

complete range of business solutions. Key features offer users the ability to: read cus-tomer case studies from businesses like Jack White Real Estate, CIRI Alaska Tourism andAssociated General Contractors, to name just a few; watch videos; take a tour of GCI’sstate-of the-art Data Center; learn about industry specific technology from governmentand resource development to healthcare and tourism; find solutions based on businesssize and budget from small business to Fortune 100 companies.

Created with user experience firmly in mind, the website is optimized for compatibilitywith today’s browsers and mobile devices.

14th annual Calista Golf Classic another big successCalista Heritage Foundation, a 501(c)(3) nonprofit, announced July 10 that $252,000

in contributions was received at the 14th Annual Calista Golf Classic. Held June 19 atMoose Run Golf Course, the event to raise scholarship funds was hosted by Ariel Twetoand Stephen Qacung Blanchett.

“Since 2003 the scholarshipsawarded each year has increased,”said CHF President/CEO ReaBavilla. “This remarkable achieve-ment is only possible due to thegenerous participation of business-es and organizations. We areextremely grateful as hundreds ofstudents have earned and continueto earn pilot certification, bache-lor’s, master’s and doctoratedegrees, vocational training andmore.”

In 2012, CHF awarded $460,000 in scholarships and, most recently, $177,000 in schol-arships for the spring 2013 semester. Since the scholarship program was formally createdin 1994, more than $3.2 million in scholarships have been awarded with $1.2 million ofthat total awarded since 2010.

More than 1,500 students have benefited from this program. In 2012 the top fiveschools scholarship recipients attended were University of Alaska Anchorage, UAFairbanks, Alaska Career College, UA Fairbanks-Kuskokwim Campus and Bethel’s YuutYaqungviat flight school.

Editor’s note: All of these news items — some in expanded form — will appear inthe next Arctic Oil & Gas Directory, a full color magazine that serves as a marketingtool for Petroleum News’ contracted advertisers. The next edition will be released inSeptember.

continued from page 16

OIL PATCH BITS

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The new agreement for cost pooling willonly apply to the three remaining owners:BP, ConocoPhillips and ExxonMobil. Theofficial pipeline owners are in fact whollyowned affiliates of these oil companies —the affiliates charge oil shippers fees fortransporting oil through the pipeline andpay a share of the costs of pipeline opera-tion. Under the new cost pooling agree-ment, the costs will be distributed betweenthe affiliate owners in proportion to the vol-ume of oil that each owner ships. The coststo be pooled consist of “non-variable” oper-ating expenses, pipeline property taxes,depreciation and interest payments. Variableoperating expenses excluded from the pool-ing include items such as the cost of fuelused to pump oil through the line — appar-ently these costs are already allocated backto the owners on the basis of volumes of oilshipped.

Longstanding disputesThe concept of cost pooling for TAPS

goes back many years and relates to long-standing disputes over the shipping ratesthat the pipeline owners charge.

When the pipeline started up in 1977 itoperated under a rather unusual arrange-ment in which each pipeline owner’s portionof the line was viewed in effect as a separatepipeline, with the owners competing witheach other for shipping business and witheach owner free to set its own rate forpipeline use. But, as a single pipeline, theline had to be managed on behalf of theowner companies by a single, jointly ownedoperating company called Alyeska PipelineService Co. Under the original pipelineoperating agreement, total pipeline operat-ing costs incurred by Alyeska were allocat-ed back to the owner companies in propor-tion to each owner’s percentage ownershipof the line.

But, given the huge amounts of moneyin oil company profits and state oil revenuesat stake in TAPS shipping fees, the settingof rates for oil shipments on the line wasdisputed as soon as oil started flowing fromthe North Slope, with the owners beingaccused of setting rates that were too high.

In 1985 relative peace was achieved by asettlement involving what was referred to as

the “TAPS Settlement Methodology,” orTSM. Under TSM, an initial attempt atpipeline cost pooling across the pipelineowners, a formula involving total pipelinecosts and total pipeline throughput deter-mined a maximum rate that pipeline ownerscould charge for shipping oil. The ownerswere allowed to set their own rates, provid-ed those rates did not exceed the TSM max-imum.

TSM started to fall apart in the early2000s when the Regulatory Commission ofAlaska, the agency that regulates TAPS oiltransportation to destinations within Alaska,issued an order, saying that the rates setunder TSM were unfair and requiring ratesfor oil shipped in Alaska to be lowered. In2005 and 2006 several parties started dis-puting the rates charged for interstate oiltransportation. And in a 2008 order FERCsaid that TAPS needed to move to a systemof uniform rates for all pipeline owners.With all owners basing their rates on essen-tially identical total pipeline costs, there wasno justification for each owner to assess adifferent rate, FERC said.

Meantime, disputed rates were suspend-ed, with the possibility of refunds to ship-pers should these rates subsequently bedetermined to be too high.

But the establishment of a uniform raterequires an agreement over exactly whatcosts can be recovered from the rate, howthose costs are calculated and the basisunder which the costs are allocatedbetween the pipeline owners. These con-siderations led to negotiations over costpooling arrangements, the result of whichis the settlement that FERC has nowannounced, with fairness in pipeline costallocation under a uniform rate driving aneed to allocate the costs by oil throughputrather than by percentage pipeline owner-ship.

The settlement over cost pooling doesnot resolve another major bone of con-tention, the question of the extent to whichthe cost of a major TAPS upgrade calledstrategic reconfiguration can be recoveredfrom TAPS shipping rates. That dispute isthe subject of a major investigation stillbeing conducted by FERC and theRegulatory Commission of Alaska.

—ALAN BAILEY

EXPLORATION & PRODUCTIONAOGCC to revisit 1995 NGL-MI decision

The Alaska Oil and Gas Conservation Commission said July 10 that it “is consid-ering whether changes in circumstances occurring since Conservation Order 360 ...was issued in 1995 warrant revision of CO 360” and has scheduled a public hearingon the issue for Sept. 19.

The commission said it would consider, among other issues: “The continuing via-bility of the findings and conclusions contained in CO 360” and any affect an annualaverage miscible injectant volume less than 600 million cubic feet per day will haveon ultimate recover from the Prudhoe Bay oil pool.

The issues addressed in CO 360 arose because the owners at Prudhoe Bay — thenprimarily ARCO, BP and Exxon — held different proportions of the gas cap and oilrim at Prudhoe. Those holding more natural gas (ARCO, Exxon) benefitted morewhen natural gas was extracted and sold down the trans-Alaska oil pipeline as naturalgas liquids, while those holding more crude oil (BP) benefitted more when the natu-ral gas was made into miscible injectant and used for enhanced oil recovery.

ARCO and BP both testified that levels of miscible injectant, MI, and natural gasliquids, NGL, production were causing waste to occur at Prudhoe. BP told the com-mission that 670-700 million standard cubic feet per day of MI needed to be injectedin the reservoir to recover additional oil, while ARCO said that anything less thanmaximum blending of salable NGLs constituted physical waste.

In its 20-page order, issued in August 1995, the commission noted that lack ofalignment between gas cap and oil rim ownership. When the Prudhoe Bay ownersunitized the field in 1977 they created two participating areas: the gas cap and the oilrim, with production allocated by participating area ownership and the participatingareas to be developed from common facilities.

The commission said Prudhoe was the only oil pool in Alaska unitized with dis-parate equities between the oil rim and gas cap, and said none of the parties identifiedany other unitized reservoir in the United States with disparate equity interests

continued from page 1

COST POOLING

see DECISION REVISITED page 20

Chugach Electric, which runs from thebeginning of 2015 to early 2018, wouldappear to confirm that more optimisticview of the gas supply situation.

Price-cap pricingAccording to a July 12 tariff advice

filed with the Regulatory Commission ofAlaska by Chugach Electric, the utilityanticipates purchasing about 17.7 billioncubic feet of gas from Hilcorp during theterm of the purchase agreement, withpricing following price caps specifiedunder a consent decree agreed betweenHilcorp and the State of Alaska to addressanti-trust concerns following Hilcorp’stakeover of both Chevron’s and MarathonOil’s Cook Inlet gas fields.

The price for base gas — the relativelyuniform volumes of gas purchased byChugach Electric on a routine basis —will range from $7.13 per thousand cubicfeet in 2015 to $8.03 per thousand cubicfeet in 2018. There are higher prices for“swing load gas,” used to meet high win-ter demand, and for any extra emergencygas supplies. However, Chugach Electricsays that it anticipates meeting its season-al swings in gas usage by storing gas inthe Cook Inlet Natural Gas StorageAlaska facility on the Kenai Peninsuladuring the summer and retrieving theexcess summer gas during the winter.

Under the new supply contractChugach Electric will purchase about2.43 billion cubic feet of gas in 2015, 5.22billion cubic feet in 2016, 7.98 billioncubic feet in 2017 and 2.01 billion cubicfeet in 2018.

FlexibilityHowever, the contract does accommo-

date some flexibility in the volumes ofgas purchased at the base rate by allowingChugach Electric to adjust the base vol-ume up or down 5 percent annually and

up or down 3 percent monthly. The gasprices cover the basic production taxesand royalties that Hilcorp pays for gasproduction but do not cover the cost oftransporting the purchased gas around theCook Inlet gas pipeline system.

Chugach Electric has an existing gassupply agreement with ConocoPhillipsand another agreement, previously withMarathon but taken over by Hilcorp.Those two contracts cover ChugachElectric’s gas supply needs until the endof 2014, after which the new gas supplyagreement with Hilcorp will come intoplay. The old Marathon contract expires atthe end of 2014, with the ConocoPhillipscontract continuing until the end of 2016but only meeting some of ChugachElectric’s needs. After the end of 2016 thenew Hilcorp contract would be ChugachElectric’s sole source of gas, unless theutility chooses to take less gas than itneeds by using the contract’s flexible

terms.Phil Steyer, director of government

relations and corporate communicationsfor Chugach Electric, told PetroleumNews in a July 16 email that flexibility inthe new contract could open up futureopportunities for other gas suppliers.

In its tariff advice Chugach Electricsays that it prefers not to be dependent ona single gas supplier but that at presentthere are no additional independent gassellers capable of meeting the utility’s gasvolume and deliverability requirements.

Drop in gas usageChugach Electric’s ability to fill its gas

supply needs through to 2018 stems in partfrom a predicted substantial drop in theutility’s gas usage between 2013 and 2015.That drop in usage will result from HomerElectric Association and MatanuskaElectric Association bringing their ownpower generation facilities on line ratherthan buying Chugach Electric’s power, andfrom Chugach Electric’s use of a new,modern combine-cycle power station inAnchorage, a power plant that is muchmore efficient than the utility’s old powerstation on the west side of Cook Inlet.

According to Chugach Electric’s tariffadvice, the utility’s annual gas demand willdrop from more than 20 billion cubic feetin 2013 to around 8.5 billion cubic feet in2015 and thereafter.

However, Homer Electric andMatanuska Electric will need to purchasegas to fuel their new power generationplants. Homer Electric has said that it hassecured adequate gas supplies for its newfacilities through to March 2016 and isoptimistic about meeting its needs through2018. Matanuska Electric has been seekinggas supplies for a new power station it isconstructing at Eklutna, north ofAnchorage — that power station is slatedto come on line in 2015.

Steyer said that the new contract withHilcorp will help his utility but still leavesquestions over the long-term gas supplysituation from the Cook Inlet.

“While the contract with Hilcorp ispositive news regarding Chugach’s fuelsupply in the near-term, we remain con-cerned about the long-term continued sup-ply of gas for Southcentral Alaska,” Steyersaid. �

PETROLEUM NEWS • WEEK OF JULY 21, 2013 19

eight oil zones, in the Tyonek formation.The well also found oil in the Starichkof and Hemlock

formations, where previous Cosmopolitan wells discov-ered hydrocarbons. Cosmo No. 1 found 43 feet of indi-cated oil pay in the Starichkof and 149 feet of indicatedoil pay in the Hemlock, according to the company. “Notall of the zones intersected will be flow tested,”Buccaneer said.

Buccaneer is the operator of the Cosmopolitanprospect and holds a 25 percent working interest in theleases there, with BlueCrest Energy Inc. holding themajority stake.

The prospect is in the southern Kenai Peninsula, offthe coast of Anchor Point.

Fourth attemptCosmopolitan is a legacy discovery left undeveloped

because of geology and economics.Pennzoil discovered the prospect in 1967 with the

Starichkof State No. 1 and the Starichkof State Unit No.1, but the results did not justify development at the time.

ConocoPhillips formed the Cosmopolitan unit in2001. The following year it drilled the Hansen No. 1 wellup dip of Starichkof State No. 1, encountering oil in theStarichkof and Hemlock intervals. ConocoPhillips drilledthe Hansen 1A sidetrack in 2003, and a 50-day flow testaveraged 550 barrels per day of oil. The company shot a3-D seismic survey over the unit in 2005, but also ulti-mately chose not to development the prospect.

Pioneer Natural Resources Alaska subsequentlyacquired Cosmopolitan. In 2007, the company drilledHansen 1A-L1, a lateral from the Hansen 1A wellboretargeting the upper Starichkof interval. Pioneer re-enteredand flow tested the lateral in early 2010.

In a plan of operations around that time, Pioneerdescribed the reservoir as being “lower quality than mostother producing oil fields of the Upper Cook Inlet.” Stillthe company launched a unique pilot project to truckcrude oil from Cosmopolitan flow tests to the Tesororefinery in Nikiski. The field produced 33,504 barrels ofoil and 119,006 thousand cubic feet of gas, according toAlaska Oil and Gas Conservation Commission figures.

Even though it proposed plans to expand production,Pioneer went the way of Pennzoil and ConocoPhillips inearly 2011, saying, “subsequent flow test results and engi-neering studies indicated that the resource potential wasnot as large as originally estimated.”

The departure split the unit in two. Much of theacreage returned to the state to be offered up in a speciallease sale, but Pioneer sold two leases to Buccaneer andBlueCrest.

Cosmo No. 1 is the first well drilled in Alaska usingthe Endeavour jack-up rig. Buccaneer owns the rigthrough its joint venture Kenai Offshore Drilling LLC.The Alaska Industrial Development and Export Authorityhelped the joint venture purchase the jack-up rig.

Buccaneer believes the rig will improve the economicsof Cosmopolitan by keeping the company from having todrill all its wells from an onshore pad, the company hassaid.

The Endeavour rig will move next to the Buccaneer-operated Southern Cross unit.

—ERIC LIDJI

continued from page 1

BUCCANEER MOVES

continued from page 1

GAS CONTRACT Enstar has new ConocoPhillips gas contractEnstar Natural Gas Co., the main Southcentral Alaska gas utility, has a new gas

purchase agreement with Cook Inlet gas producer ConocoPhillips. The newagreement, which covers the years 2016 and 2017, will enable Enstar to purchasea total of 4.75 billion cubic feet of gas. The gas will come from theConocoPhillips-operated Beluga River and North Cook Inlet gas fields.

Enstar has filed a tariff advice with the Regulatory Commission of Alaskarequesting commission approval of the purchase agreement. Gas prices under theagreement will be $7.27 per thousand cubic feet in 2016 and $7.57 in 2017. Thoseprices are a little less than price caps set for the sale of gas by Hilcorp Alaska,another Cook Inlet gas producer, under the terms of a consent decree agreedbetween Hilcorp and the State of Alaska following Hilcorp’s purchase ofChevron’s and Marathon Oil’s Cook Inlet gas fields.

The purchase agreement with ConocoPhillips will provide for 1.8 billion cubicfeet of gas in 2016 and 2.9 billion cubic feet in 2017, relatively modest volumesin comparison to Enstar’s total predicted gas needs of 33.3 billion cubic feet and34.9 billion cubic feet in those years. And, assuming that the RegulatoryCommission of Alaska approves the new agreement, Enstar will still be left with16.6 billion cubic feet of unmet needs in 2016 and 20.7 billion cubic feet of unmetneeds in 2017. However, with Hilcorp having recently said that it anticipates beingable to close the gap on Southcentral utility gas supplies through to 2018, thereare presumably further new gas supply agreements in the offing.

—ALAN BAILEY

20 PETROLEUM NEWS • WEEK OF JULY 21, 2013

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What now?NordAq is a small, Anchorage-based

independent. It is among a number of com-panies looking to prove up new supplies ofnatural gas to replace declining reserves inthe Cook Inlet region.

A company executive did not respond torequests for comment on the agency deci-sion.

In early 2011, NordAq laid a temporaryice road to its Shadura prospect and drilleda wildcat exploratory well, the Shadura No.1.

The company hasn’t made clear the sizeof its apparent discovery. But the tentativedevelopment plans suggest a find worthy ofsome excitement.

The proposed Shadura development padis more than a mile due east of the wildcat.For the EIS analysis, NordAq offered a two-stage development plan.

The first stage would include construc-tion of a “minimal” drilling and processingpad. One gas well would be drilled and test-ed.

If the test results were unfavorable, allequipment and gravel would be removedand the affected areas would be restored toa preconstruction state, the EIS said.

If the testing results were favorable, asecond stage would be built. This wouldinvolve expanding the pad and drilling fivemore gas wells, plus an industrial water welland a disposal well. Production facilitiesalso would be installed on the pad.

The gas would tie into a ConocoPhillipsAlaska natural gas pipeline to the north-west.

Overall, construction would take about16 months, and the project would operatefor 30 years, the EIS said.

Lease with CIRIThe Shadura project is in the northwest-

ern section of the Kenai National WildlifeRefuge.

While the federal government owns thesurface estate, Cook Inlet Region Inc. ownsthe subsurface estate of oil, gas and coal inthe project area. NordAq has a lease withCIRI to develop the gas resource.

That NordAq would have access to thegas was never in question. Access to inhold-ings is provided for under ANILCA, the

Alaska National Interest LandsConservation Act.

The question was whether NordAqwould get the kind of access it wanted.

At one point, the company told the Fishand Wildlife Service it would not move for-ward with the project if the access route hadto come out of the Swanson River unit.Another company, Hilcorp, operates thatunit, which has an existing road system.

In deciding to grant NordAq’s wish(Alternative 2), Geoffrey L. Haskett, Alaskaregional director for the Fish and WildlifeService, wrote in the record of decision:“Alternative 2 reflects the Service’s intent tomanage Kenai Refuge to achieve the mis-sion of the National Wildlife RefugeSystem, meet the purposes for which theRefuge was established, and meet our legalobligations.” �

Editor’s note: A copyrighted oil and gaslease map from Mapmakers Alaska was aresearch tool used in preparing this story.

continued from page 1

SHADURA GAS

NordAq seeks approval for Smith Bay workNordAq Energy Inc. is planning a multiyear oil and gas exploration program in

the Smith Bay area off the National Petroleum Reserve-Alaska and onshore inNPR-A.

The company holds a block of State of Alaska oil and gas leases in Smith Bayand a block of federal leases in the NPR-A northwest planning area. The NPR-Aleases are inland to the southwest from Smith Bay.

NordAq, which has been exploring in the Cook Inlet area in recent years,applied to the Alaska Department of Environmental Conservation for an oil dis-charge prevention and contingency plan “on current and future lease holdings off-shore at the southern extent of Smith Bay,” DEC said in a notice published July18. DEC said “drilling is proposed in shallow water and on shore in the NorthwestNational Petroleum Reserve-Alaska.”

NordAq plans to drill as many as eight exploratory wells during the winterdrilling seasons from 2013 to 2015, the agency said, with operations proposed“only during the frozen winter seasons” and a proposed drilling end date of April21 each season to allow for demobilization and completion of any potentialresponse activity prior to May 15, which is the average date of tundra travel clo-sure, or loss of grounded sea ice in Smith Bay, which typically occurs in June orJuly.

DEC said access would vary depending on exploration location but would gen-erally be via ice road, snow trail, Rolligon and/or airstrip.

—KRISTEN NELSON

between oil and gas. In its order the commission said: “It

appears that all persons’ correlative rightswill be best protected by complete integra-tion of interests in the Prudhoe Oil Pool,”and scheduled a hearing for January 1996to develop a plan for compulsory unitiza-tion of the Prudhoe Bay oil pool unless thecommission determined that the unit own-ers were working “to integrate the separateand competing equities of the gas cap andoil rim within the Prudhoe Bay Unit.”

Integration was finally accomplished in2000 when Prudhoe Bay interests werealigned following BP’s acquisition ofARCO and the acquisition of ARCO’sAlaska interests by Phillips Petroleum Co.

In addition to ordering maximum pro-duction of NGLs through August 1996, thecommission required submission of agree-ments that might affect the operation of thePrudhoe oil pool so it could “investigatewhether the agreement contains anythingthat may impair correlative rights, reduceultimate recovery or otherwise lead towaste,” a provision which also expired atthe end of August 1996.

—KRISTEN NELSON

continued from page 18

DECISION REVISITED