Vol. 16, No. 45 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of November 6, 2011 • $2

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

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

� L A N D & L E A S I N G

page12

State looks at shale developmentissues; conventional impediments

MINING

Mining Explorers is an annual publication from Petroleum News

e x p l o r e r sInvesting in the future of Alaska and Northwest Canada

Mining Explorers provides a comprehensive overview of the miningcompanies investing the capital and time needed to unlock the enor-mous mineral potential of Alaska and northern Canada.

2011 Mining Explorers inside

Pump station plumbingAlyeska to spend millions to reconfigure piping as safeguard against corrosion

By WESLEY LOYFor Petroleum News

The operator of the trans-Alaska oil pipeline isembarking on an expensive, three-year pro-

gram to replace piping in several pump stations.The work stems from a settlement Alyeska

Pipeline Service Co. reached with federal regula-tors following a corrosion-caused oil spill inJanuary at Pump Station 1 on the North Slope. Theleak forced a lengthy shutdown of the pipeline.

Alyeska has told the U.S. Department ofTransportation’s Pipeline and Hazardous MaterialsSafety Administration it has completed a riskassessment of pump station piping that’s subject tocorrosion and difficult to inspect. It was piping ofthis sort that leaked at Pump Station 1.

As a result of the assessment, Alyeska is design-ing plans for work at pump stations 1, 3, 4, 5 and9.

“These designs will replace buried non-inspectable crude oil piping with piping in anabove ground alignment,” says a summary docu-ment Alyeska provided at the request of PetroleumNews.

Halliburton in the game2nd largest oilfield service firm partners with Great Bear on Alaska shale

By KAY CASHMANPetroleum News

Skeptics beware. If you thought Great BearPetroleum’s plan to drill 200 wells per year in

its North Slope shale acreage was unrealistic, theworld’s second largest oilfield service companythinks you’re wrong.

Halliburton, an expert in extracting oil and gasfrom source rock in major resource plays outsideAlaska, has partnered with Great Bear. In the nextyear Halliburton will be conducting a parallel“proof of concept” multi-well program on GreatBear’s acreage along the Dalton Highway — at thesame time Great Bear is executing a similar pro-gram to the south, along the highway. In the next

year, each company plans to drill as many as threevertical wells and a lateral off of each of those.

“We are partnering with Halliburton on an area-limited basis where they are bringing in world-class technology,” Great Bear President and COOEd Duncan told a special meeting of the AlaskaLegislature’s House Resources Committee Nov. 1.(Go online to http://bit.ly/rtkXIZ for eight slidesused by Duncan in his presentation.)

A PN source at Halliburton said the giant oil-field service company is covering all of the costsof its proof of concept program, except permitting,including the cost of actually drilling wells, whichwill likely be outsourced to a rig contractor.

Four new units for BRPCState divides 2 unit proposals into 4 with drilling commitments through 2014

By ERIC LIDJIFor Petroleum News

Over the past year, Brooks Range PetroleumCorp. applied to form two units in the central

North Slope fairway between the Colville River andKuparuk River units.

Instead, it got four, with much less total acreage.In separate decisions in late October, the Alaska

Department of Natural Resources divided the pro-posed Putu unit into the smaller Tofkat and Putuunits, and the proposed Southern Miluveach unit intothe smaller Southern Miluveach and Kachemachunits.

With the decisions, BRPC must now drill as manyas 11 wells and sidetracks, and decide whether tosanction two development projects at the four units

by mid-2014. BRPC is the local operating arm of Kansas-based

independent Alaska Venture Capital Group LLC andthe operator of a multi-company joint venture that

Pump Station 1 will see “the mostcomplex and critical” project, Alyeska

says. It will be the first station to have itsbelow-ground crude oil piping rerouted to

an above-ground configuration.

see ALYESKA PIPING page 15

see ALASKA SHALE page 19

see BRPC UNITS page 17

CIRI drilling confirms coal seamssuitable for UCG; seismic planned

After an explorationprogram involving thedrilling of 13 core holes,Cook Inlet Region Inc.has confirmed the exis-tence of a significantcoal resource likely tobe suitable for under-ground gasification in the corporation’s land on the west side ofAlaska’s Cook Inlet.

“We’ve done a significant amount of exploration work,”Ethan Schutt, CIRI senior vice president for land and energydevelopment, told the Alaska Senate Resources Committee onOct. 20. “Through that work we’ve confirmed that we have a sig-nificant commercial coal resource in a geological setting that isfavorable for UCG (underground coal gasification) develop-

see CIRI COAL page 18

Canada tells US it will export‘elsewhere’ if its oil not wanted

The battle over TransCanada’s Keystone XL pipeline hasshifted from shadowboxing to a bare-knuckles contest inCanada.

Federal Natural Resources Minister Joe Oliver has sent ablunt message to Obama administration officials telling themthat “if they don’t want our oil, it is obvious we are going toexport it elsewhere.”

By way of stirring the pot, he said that as part of a “broadstrategic objective” Canada must diversify its markets andChina “has emerged as the largest customer of energy in theworld, so it is utterly obvious what we must do. They are hun-gry for our (mineral and petroleum) resources.”

However, Oliver did not specifically endorse Enbridge’sNorthern Gateway proposal, which is designed to export525,000 barrels per day of oil sands crude to the Asia-Pacific

see KEYSTONE DEBATE page 15

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Schutt said that the StoneHorn Ridge joint venture has

found multiple, thick coalseams at depths below 650 feetin the Stone Horn Ridge area.

2 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

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

PIPELINES & DOWNSTREAM

EXPLORATION & PRODUCTION NATURAL GAS

6 Potential Alaska state and federal oil and gas lease sales

8 Moriarty to replace Crockett at AOGA

4 Escopeta, North Slope exploration updates

5 Pioneer production drops in third quarter

6 October Alaska North Slope production down 3 percent

LAND & LEASING

FINANCE & ECONOMY

12 Shale development requirements tackled

Task force led by Division of Oil and Gas; DNR also moving ahead with issues impeding conventional oil, gas development in state

16 Kinder Morgan tests waters

Calls open season to double capacity of Trans Mountainto 600,000 bpd, fueling competition with Enbridge on routes to Asia-Pacific

ASSOCIATIONS

GOVERNMENT

5 Upbeat in the upstream

Canadian land auctions, horizontal drilling, lead the way to C$3.41B in exploration bids, 13,400 new well permits; optimism for 2012

7 State, BLM lease sales set for Dec. 7

Oil & gas lease sales cover adjacent areas in state,National Petroleum Reserve-Alaska; 14.7 million state acres, 3 million federal

8 Gas line player Yukon Pacific winds down

Company surrenders federal right-of-way grant for its LNG project; despite $100M investment,construction never started

7 Courts give Rutter Umiat prospect royalty

Alaska Supreme Court affirms lower court rulingon small overriding royalty interest at the North Slope oil prospect

4 Parnell meets with top BP execs in London

Shell, Eni CEOs next on European trip; main topics with BP were gas pipeline and Asia market, oil tax cuts, infrastructure integrity

UTILITIES8 Keeping the Railbelt power flowing

Main Alaska population centers face challengeswith electricity delivery amid tightening gas supplies and an aging infrastructure

contents

13 BSEE appoints regulatory programs chief

14 Parnell voices Point Thomson impatience

13 George joints AGDC as admin director

10 Oil industry biggest source of AK jobs

SIDEBAR, Page 10: Alaska needs nonresident workers

CIRI drilling confirms coal seams suitable for UCG; seismic planned

Canada tells US it will export ‘elsewhere’ if its oil not wanted

ON THE COVERPump station plumbing

Alyeska to spend millions to reconfigure pipingas safeguard against corrosion

Halliburton in the game

2nd largest oilfield service firm partners with Great Bear on Alaska shale

Four new units for BRPC

State divides 2 unit proposals into 4 with drilling commitments through 2014

reach new horizons.

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PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay Z-65 BPDreco 1000 UE 16 (SCR/TD) Prudhoe Bay S-09/OH BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD4-03 ConocoPhillipsAC Mobile 25 Prudhoe Bay 04-350 BPOIME 2000 141 (SCR/TD) Kuparuk 2A-11 ConocoPhillipsTSM 7000 Arctic Wolf #2 In Nisku, AB Available

Kuukpik 5 Drilling Savik #2 North Slope Borough

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableAC Coil Hybrid CDR-2 Kuparuk 2K-22A ConocoPhillipsDreco 1000 UE 2-ES Prudhoe Bay Stacked out AvailableMid-Continental U36A 3-S Prudhoe Bay Stacked out AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay X-22A BPEmsco Electro-hoist 7-E (SCR-TD) Prudhoe Bay DS12-27A BP Dreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay R14-B BPDreco 1000 UE 9-ES (SCR/TD) Has been released by Brooks Range Available

PetroleumOilwell 2000 Hercules 14-E (SCR) Prudhoe Bay Stacked out AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Stacked out AvailableOilwell 2000 17-E (SCR/TD) Prudhoe Bay Stacked out AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Stacked at Deadhorse, Pioneer

will go to Oooguruk for exploration drilling in JanuaryAcademy AC electric Heli-Rig 106-E (SCR/TD) Stacked at Deadhorse AvailableOIME 2000 245-E Oliktok Point OP10-09 ENI

*Nabors 27-E will be under contract at Oooguruk/Nuna for Pioneer this winter

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site R-03B1 BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site 18-03C BP Ideco 900 3 (SCR/TD) Kuparuk Well 2A-07 ConocoPhillips

Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay final construction and commission BPNOV ADS-10SD 273 Prudhoe Bay final construction and commissioning BP

North Slope - Offshore

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

Nabors Alaska DrillingOIME 1000 19-E (SCR) Oooguruk ODSN-26I Pioneer Natural ResourcesOilwell 2000 33-E Prudhoe Bay Stacked out Available

Doyon DrillingSky Top Brewster NE-12 15 (SCR/TD) Spy Island SP18-N5 ENI

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Rigging down from Three Mile Creek 3, Aurora Gas

will stack out south of Tyonek

Cook Inlet EnergyAtlas Copco RD20 34 Undergoing winterization Cook Inlet Energy

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

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Kenai Loop #3 Buccaneer Alaska

Nabors Alaska DrillingContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked Available Academy AC electric Canrig 105-E (SCR-TD) Kenai CLU-2 CINGSARigmaster 850 129 Kenai Stacked out Available

Cook Inlet Basin – Offshore

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

XTO EnergyNational 1320 A Coil tubing cleanout planned off Platform XTO

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

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

Upper Cook Inlet KLU#1

Mackenzie Rig StatusCanadian Beaufort Sea

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

Central Mackenzie Valley

Akita/SAHTUOilwell 500 51 Has left the NWT Available

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

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

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

US 2,021 2,013 1,672Canada 499 497 433Gulf 33 33 22

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 KAY CASHMANPetroleum News

Gov. Sean Parnell told Petroleum Newsin a phone interview from London

that he had a lengthy meeting on Nov. 2with BP Chief Executive Bob Dudley, theirconversation centering on three majorissues of concern to the governor — gettinga natural gas pipeline from the North Slopebuilt soon, how Alaskans might benefit ifoil taxes are cut, and the integrity of NorthSlope infrastructure.

Also attending the meeting were BPExploration Alaska President John Mingeand Bob Fryar, the executive vice presidenton BP’s senior management team who isresponsible for safe and compliant BPexploration and production operations andthe stewardship of resources, including nat-ural gas, around the world.

On a natural gas pipeline, Parnell said hethought it important to repeat what he hadsaid in an Oct. 27 speech at the Alaska Oiland Gas Association luncheon inAnchorage, which was that if the best long-

term gas market hadtruly shifted from theLower 48 to Asia, hewanted the majorholders of provenNorth Slope naturalgas reserves —E x x o n M o b i l ,ConocoPhillips andBP — to consider liq-uefied natural gasexports to Asia.

TransCanada, the licensee with the stateof Alaska under the Alaska GaslineInducement Act, has always said it will bethe gas producers who decide on the routeof the gas pipeline.

Parnell also wanted to “signal that I amflexible about how to commercialize Alaskagas as long as it is in Alaska’s interest …and that I want to see BP get better alignedwith our licensee on the project.”

The governor said a face-to-face meet-ing with BP’s top executive was veryimportant.

“I wanted to speak directly with Dudley.

I wanted to be sure heknew what Alaska’sconcerns were andthat I was also willingto work to bringinvestment toAlaska.”

Parnell told TheAssociated Press thathe left the meetingbelieving the two

held a similar view that the region’s marketwas worth investigating.

TransCanada is working withExxonMobil to advance a natural gaspipeline project but it has not yet announcedany agreements with shippers.

On Nov. 2, the president and chief exec-utive of TransCanada, Russell K. Girling,said in a quarterly financial conference callthat the continued focus of the AlaskaPipeline Project remains the Lower 48. Buthe said it is a market-driven project, “andwe’ll move the gas to wherever the marketdecides it wants to move the gas to.”

A BP spokesman in Alaska, SteveRinehart, said the company has studied andwill continue to study the potential for liq-uefied natural gas. He said the goal is get-ting North Slope gas to market.

Parnell is in the midst of his first state-sponsored trip overseas, what he’s callingan “investment mission.” It is the latest in aseries of trips that Parnell or other membersof his administration have taken in an effortto tout Alaska’s development and invest-ment potential.

Parnell still plans to meet with the CEOsof two other energy firms, Royal Dutch

Shell, Europe’s largest oil company, andEni SpA.

He began his trip in the UnitedKingdom, where in addition to meetingwith Dudley, he also promoted one of thestate’s top exports, seafood.

Parnell said he was “professionally andgraciously” received by Dudley, whoParnell said he also pressed to be more spe-cific on what kind of benefits Alaskanscould see if oil production taxes were cut.

Minge said earlier this year that he sup-ported the $5 billion investments that aConocoPhillips executive envisionedwould occur if Alaska’s oil production taxregime were changed, and said he saw thatas a start “in terms of what is possible.”

Minge’s comments came as Parnell’s taxcut bill stalled in the Senate, with leadinglawmakers saying they didn’t have theinformation they needed to make a soundpolicy call and some seeking firm commit-ments from energy companies for whatAlaska would see in return if taxes were cut.

“I think that number they put out there,the $5 billion number, of new investment oradditional investment, I think that’s a bareminimum from one company,” Parnell said.

While other companies would benefitfrom tax changes, too, “I’m in this to assurethat Alaskans see more investment and seemore jobs.”

Parnell plans to revive the tax issue whenthe Legislature convenes in January. �

—Becky Bohrer of the Associated Presscontributed to this article.

4 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

Kay Cashman PUBLISHER & EXECUTIVE EDITOR

Mary Mack CHIEF FINANCIAL OFFICER

Kristen Nelson EDITOR-IN-CHIEF

Clint Lasley GM & CIRCULATION DIRECTOR

Susan Crane ADVERTISING DIRECTOR

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Shane Lasley IT CHIEF

Marti Reeve SPECIAL PUBLICATIONS DIRECTOR

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Alan Bailey SENIOR STAFF WRITER

Wesley Loy CONTRIBUTING WRITER

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Rose Ragsdale CONTRIBUTING WRITER

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Allen Baker CONTRIBUTING WRITER

Judy Patrick Photography CONTRACT PHOTOGRAPHER

Mapmakers Alaska CARTOGRAPHY

Forrest Crane CONTRACT PHOTOGRAPHER

Tom Kearney ADVERTISING DESIGN MANAGER

Amy Spittler MARKETING CONSULTANT

Dee Cashman CIRCULATION REPRESENTATIVE

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

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

tract services to PetroleumNewspapers of Alaska LLC or are

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OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 16, No. 45 • Week of November 6, 2011

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� G O V E R N M E N T

Parnell meets with top BP execs in LondonShell, Eni CEOs next on European trip; main topics with BP were gas pipeline and Asia market, oil tax cuts, infrastructure integrity

GOV. SEAN PARNELL BOB DUDLEY

EXPLORATION & PRODUCTIONEscopeta, North Slope exploration updates

In early October there were more wells planned for the upcoming North Slopeexploration season than ever before — 34, as compared to a record 33 drilled in 1969.

But by the end of October, some drilling plans were in jeopardy. Following are thecompanies that planned to drill between November of 2011 and November 2012, themaximum number of wells they were looking at, and the status of their programs:

• Brooks Range: 1 rig, 2 wells/on schedule.• Great Bear: 1 rig, 12 wells, including six laterals/on schedule but could face a few

months delay due to rig availability and final permits.• Linc (Renaissance Umiat): 1 rig, 5 wells/company said Oct. 31, “Rigs are tight

but we are making headway.”• Pioneer: 1 rig, 2 wells/on schedule.• Repsol: 5 rigs, 15 wells/on schedule but there’s a chance permitting challenges

could delay part of the program until next winter.• Savant: 1 rig, 1 well/subject to rig availability, likely will be delayed until next

winter.• UltraStar: 1 rig, 1 well/subject to rig availability, likely will be delayed until next

winter.In Southcentral Alaska’s Cook Inlet basin, as of Oct. 31, Escopeta Oil had drilled

down to 8,800 feet, a little over half the distance to the targeted depth for its first wellin the offshore Kitchen Lights unit. The company was preparing to conduct its week-ly blowout preventer test, followed by wireline testing.

On Nov. 3, Escopeta officials would not say if drilling would continue once test-ing was complete, despite the fact the Department of Environmental Conservationgave Escopeta permission to continue drilling until Nov. 15, weather and ice con-ditions permitting, and that both conditions were still favorable.

—KAY CASHMAN

Contact Kay Cashman at publisher@petroleumnews.com

By GARY PARKFor Petroleum News

Canadian governments, pulled alongby a soaring producer appetite for

oil and liquids prospects, raised C$3.41billion from land sales in the first ninemonths of 2011, the third highest returnin the last decade.

That rush to secure exploration rights,which fattened provincial coffers byC$3.04 billion in the same period of lastyear, is now reflected in upstream activi-ty, with operators securing 13,440 newwell permits in the January-Septemberperiod this year, up 16 percent from 2010.

Those upbeat numbers have been rein-forced by a decisive swing to horizontaldrilling, with 6,973 of this year’s licensesusing a technology that made a quietdebut in 1988 with 16 wells.

The nine-month count this year hastoppled the 12-month record of 6,668horizontal wells set last year as producersembrace a technology that enables themto exploit Western Canada’s less perme-able reservoirs by using multistage frac-turing on well laterals.

Permits obtained to the end of the thirdquarter included 8,820 oil and bitumenprospects, setting a 10-year high and 46percent above last year’s count for thesame period.

Natural gas permitting posted a lowfor the last decade of 2,531 wells, off 31percent from last year and a far cry fromthe January-September record of 14,837wells set during a period of peak gasprices in 2005.

The permit count also included 1,113oil sands evaluation wells, 228 ahead ofthe same period last year.

PSAC: No sign of tapering offMark Salkeld, president of the

Petroleum Services Association ofCanada, said the pace of drilling showsno signs of tapering off, with all equip-ment either working or booked to workand new rigs being manufactured to bet-ter handle deeper horizontal wells and lat-

eral sections.He said PSAC, which has forecast that

rigs will be released on 13,325 wells thisyear, an increase of 10 percent over the2010 total, is developing a “good degreeof optimism” about 2012 as operatorsturn their attention to liquids-rich gas.

Salkeld said that although the numberof rigs released will remain below pre-recession levels, the service sector bene-fits from the additional time needed todrill and complete horizontal wells.

Canadian National leadsAmong the operators, Canadian

Natural Resources leads in all categories,obtaining 1,181 well licenses, completing939 wells in the first three quarters anddrilling 1.06 million meters of hole.

Husky Energy obtained 897 welllicenses and rig-released 799 wells, fol-lowed by Canada’s biggest gas producerEncana at 659 permits and 510 rig releas-es, while oil sands producer CenovusEnergy received 466 permits and released401 rigs.

Government agencies report that oper-ators released rigs on 9,181 wells over thefirst nine months, up 14 percent from thesame period of 2010, with about 70 per-cent listed as oil or bitumen wells.

Alberta increased its permit count 9percent to 5,816 wells, with 3,767 target-ing oil or bitumen, compared with 2,607in first three quarters of last year.

Saskatchewan posted a 38 percentincrease to 2,536 permits, with gas limit-ed to 31 wells, while gas-weightedBritish Columbia declined to 466 wells

from 517 and Manitoba was down 4 per-cent at 341 wells.

The land sales revenues to the end ofSeptember trailed the C$4.12 billion thatwas raised in 2008 and C$3.71 billion in2006, years that were dominated by ascramble to secure oil sands rights inAlberta and shale gas prospects in BritishColumbia.

The average price so far this year isC$847 per hectare, compared with C$873in the same period of 2010 and is the thirdhighest on record, while the amount ofland sold increase 15 percent from lastyear to 4.02 million hectares (9.93 mil-lion acres).

Alberta outpaces other provincesAlberta easily outpaced the other

provinces, pocketing C$3.06 billion from3.46 million hectares at a per-hectareaverage of C$884, a record at the three-quarter point.

Northern Alberta, where companiesare gearing up to probe the region’s shalegas prospects, attracted the bulk of spend-ing at C$2.66 billion, double last year.

British Columbia continued its nose-dive, with successful bids sliding toC$123 million at an average C$1.016 perhectare, compared with C$780 million atan average C$2.329 per hectare for thesame period last year.

Saskatchewan raised C$214.9 millionfrom its auctions, down from C$371.6million last year, but the total landinvolved rose to 420,746 hectares from316,506 hectares.

In addition to cash bonus payments,producers acquired rights through workcommitments to 363,681 hectares in theNorthwest Territories. �

PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011 5

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� L A N D & L E A S I N G

Upbeat in the upstreamCanadian land auctions, horizontal drilling, lead the way to C$3.41B in exploration bids, 13,400 new well permits; optimism for 2012

Contact Gary Park through publisher@petroleumnews.com

E&PPioneer productiondrops in third quarter

Pioneer Natural Resources AlaskaInc. produced 4,000 net barrels of oilequivalent per day during the thirdquarter, down from 7,000 net boe perday in the same period in 2010.

The Texas-based independent pro-duced 128,000 net boe per day acrossall its properties during the quarter, upfrom 104,000 net boe per day duringthe same period last year, an increaselargely attributable to increasing EagleFord Shale and Permian Basin produc-tion.

Pioneer operates the Oooguruk unitin the nearshore waters of the BeaufortSea.

The company is planning two “keywells” this winter, a “deep test” in theIvishak and a fracture stimulation oper-ation in the Torok formation, accordingto CEO Scott Sheffield.

Sheffield said the company wouldhave results no earlier than May.

—ERIC LIDJI

By KRISTEN NELSONPetroleum News

A laska North Slope production forOctober was down 3.4 percent from

September, averaging 588,287 barrels perday compared to 608,680 bpd in September.

With the exception of the BPExploration (Alaska)-operated Northstarfield, all other North Slope fields hadmonth-over-month decreases in production.

Except where noted, volumes are fromthe Alaska Department of Revenue’s TaxDivision, which tracks oil production bymajor production centers and provides dailyproduction and monthly averages.

The largest percent decrease, 15.6 per-cent, was at BP’s Milne Point field, whichaveraged 18,826 bpd in October, downfrom 22,312 bpd in September, a differenceof 3,486 bpd.

The largest barrel difference was at theBP-operated Prudhoe Bay field, whichaveraged 293,643 bpd in October, down 4.3percent, 13,053 bpd, from a Septemberaverage of 306,696 bpd.

Prudhoe Bay includes satellite produc-tion from Aurora, Borealis, Midnight Sun,Orion and Polaris. The most recent data byfield and pool from the Alaska Oil and GasConservation Commission is for August. Inthat month, Prudhoe Bay itself produced5,863,649 barrels. The satellite with thelargest production was Borealis at 349,510barrels, followed by Aurora at 266,807 bar-rels, Orion at 256,508 barrels, Polaris at162,582 barrels and Midnight Sun at 45,303barrels.

Kuparuk RiverThe smallest production drop was at the

ConocoPhillips Alaska-operated KuparukRiver field, which averaged 137,657 bpd inOctober, down 0.2 percent, just 311 barrels,from a September average of 137,968 bpd.

Kuparuk includes production from satel-lites at Meltwater, Tabasco and Tarn, as wellas West Sak viscous oil production, andproduction from the Eni-operatedNikaitchuq field and the Pioneer NaturalResources Alaska-operated Oooguruk field.AOGCC figures for August show themajority of Kuparuk oil is from the mainreservoir, 2,826,328 barrels, with West Sakcoming in second at 489,228 barrels, fol-lowed by Tarn at 320,743 barrels,

Meltwater at 86,187 barrels and Tabasco at49,888 barrels.

August production from Nikaitchuq was196,442 barrels, some 6,337 bpd; AugustOooguruk production was 186,161 barrels,some 6,005 bpd.

Colville River Alpine, operated by ConocoPhillips

Alaska, averaged 82,194 bpd in October,down 1.6 percent, some 1,315 bpd, from aSeptember average of 83,509 bpd.

The Alpine field is the main producer atthe Colville River unit, the farthest westproduction on the North Slope, but the unitalso has production from the Fiord, Nanuqand Qannik satellite fields. AOGCC figuresfor August show Alpine accounting forsome 71 percent of production, followed byFiord at 26 percent, Qannik at 2 percent andNanuq at 1 percent.

The BP-operated Lisburne field aver-aged 31,041 bpd in October, down 6.6 per-cent from a September average of 33,250bpd. Lisburne includes production from thePoint McIntyre and Niakuk fields.

The BP-operated Endicott field aver-aged 11,893 bpd in October, down 3.8 per-cent, some 466 barrels, from a Septemberaverage of 12,359 bpd. Endicott includesproduction from Badami, which accordingto AOGCC figures for August, averaged1,143 bpd in that month.

The BP-operated Northstar field, theonly North Slope field with increased pro-duction October-over-September, averaged13,033 bpd in October, up 3.6 percent, 447bpd, from a September average of 12,586bpd.

Cook InletThe temperature at Pump Station 1 on

the North Slope averaged 26.3 degrees F inOctober, compared to an average of 38.8 Fin September.

Cook Inlet production averaged 10,641bpd in October, down 18.9 percent, some2,485 bpd, from a September average of13,126 bpd.

ANS crude oil production peaked in1988 at 2.1 million bpd; Cook Inlet crudeoil production peaked in 1970 at more than227,000 bpd. �

6 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

LAND & LEASING

This week’s lease sale chartsponsored by:

Geokinetics

Potential Alaska state and federal oil and gas lease sales

Agency Sale and Area Proposed Date

DNR Beaufort Sea Areawide Dec. 7, 2011

DNR North Slope Areawide Dec. 7, 2011

DNR North Slope Foothills Areawide Dec. 7, 2011

BLM NPR-A Dec. 7, 2011

DNR Cook Inlet Areawide spring 2012

DNR Alaska Peninsula Areawide spring 2012

DNR Beaufort Sea Areawide fall 2012

DNR North Slope Areawide fall 2012

DNR North Slope Foothills Areawide fall 2012

BLM NPR-A 2012

Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, manages leasing inthe National Petroleum Reserve-Alaska; BOEMRE, U.S. Department of the Interior’s Bureau of OceanEnergy Management, Regulation and Enforcement (formerly Minerals Management Service), Alaskaregion outer continental shelf office, manages sales in federal waters offshore Alaska; DNR, Alaska

Department of Natural Resources, Division of Oil and Gas, manages state oil and gas lease sales onshoreand in state waters; MHT, Alaska Mental Health Trust Land Office, manages sales on trust lands.

Contact Kristen Nelson at knelson@petroleumnews.com

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

October Alaska NorthSlope production down 3 percent

By ERIC LIDJIFor Petroleum News

A ffirming a lower court ruling, theAlaska Supreme Court is allowing a

Texas-based independent to keep an over-riding royalty interest in a North Slope oilprospect.

The Oct. 28 ruling allows Rutter andWilbanks Corp. to retain half of a 3.75 per-cent overriding royalty that it and formerpartner Renaissance Alaska LLC kept onthe leases they held in the Umiat area undera joint venture called Renaissance UmiatLLC.

While the interest is small, it could bevaluable.

Earlier this year Australian independentLinc Energy Ltd. acquired RenaissanceAlaska, giving it 100 percent workinginterest and 80 percent net revenue interestin the Umiat oil field in the foothills of theBrooks Range Mountains, straddling theColville River.

Linc plans to begin exploring theprospect this winter and previously esti-mated that its stake in the prospect couldyield more than 200 million barrels of oilequivalent.

The case concerns lease documents forthe prospect.

Renaissance Alaska and Rutter andWilbanks began considering a partnershipat the Umiat oil field in 2004 and 2005. Asthe companies moved forward on the proj-ect, they kept all lease documents inRenaissance’s name alone to simplify fed-eral paperwork.

After purchasing leases at Umiat, thecompanies sought an additional lease in thearea owned by Arctic Falcon ExplorationLLC. The three companies eventuallyformed Renaissance Umiat in early 2007.While the negotiations involved in creatingthat joint venture set the stage for the cur-rent lawsuit, Arctic Falcon is not a party inthe case.

When the companies joined together,

Arctic Falcon insisted on retaining an over-riding royalty interest on its lease.Renaissance’s Mark Landt told the courts,“Our position was, if he’s going to retain anoverride, then we’re going to retain anoverride,” and as a result, RenaissanceAlaska decided to keep a 3.75 overridingroyalty interest in its Umiat leases.

The operating agreement betweenRenaissance and Rutter and Wilbanksrequired the two companies share develop-ment costs at Umiat up to $25 million, orforfeit their interest.

As Renaissance began developing theprospect, it asked Rutter and Wilbanks forits share of the money. When it didn’t pay,Rutter and Wilbanks forfeited its interest inUmiat.

In August 2008, Rutter and Wilbanksclaimed in court that it was entitled to halfof the 3.75 percent overriding royalty inter-est and the Superior Court ultimatelyagreed.

Although the companies never madeany agreement about the overriding royal-ty, Renaissance said it should be allowed tokeep the entire 3.75 percent for two rea-sons.

First, Renaissance argued that it heldlegal title to the overriding royalty, and thatRutter would need a court order to obtain atitle. Second, it argued that the contractessentially implied Rutter would forfeit itsshare of the royalty by forfeiting its interestin the leases.

While Renaissance argued that it alone

held legal title to the overriding royaltyinterest, the courts decided that the compa-nies always intended to proceed as an equalpartnership, and used only Renaissance’sname on federal filings to simplify thepaperwork process.

Concerning the idea that the contractimplied forfeiture of the overriding royaltyshould one of the companies fail to pay itsshare of the operating expenses, the courtsdecided that “had Renaissance and Rutterwished to include an express term linkingthe (overriding royalty interest) to the min-imum spending requirement, they couldhave done so.” �

PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011 7

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� L A N D & L E A S I N G

State, BLM lease sales set for Dec. 7Oil & gas lease sales cover adjacent areas in state, National Petroleum Reserve-Alaska; 14.7 million state acres, 3 million federal

By KRISTEN NELSONPetroleum News

In September the Alaska Department of NaturalResources delayed the state’s fall areawide oil and gas

lease sales from Oct. 26 to Dec. 7 to allow potential biddersmore time to do due diligence and to allow the state theopportunity to add acreage fromexpired leases.

The Bureau of Land Managementwas already planning a lease sale inthe National Petroleum Reserve-Alaska and said Oct. 28 that its NPR-A oil and gas would be held the sameday as the state’s sale.

The state Division of Oil and Gaswill open bids beginning at 9 a.m. onDec. 7 in the Dena’ina Civic andConvention Center in Anchorage. Bids for BLM’s NPR-Asale will be opened at 1 p.m. in the Denali Room at theAnchorage Federal Building.

DNR called it “a rare opportunity” for investors “to bidon the same day for adjacent state and federal oil and gasleases on the North Slope.”

The department said its North Slope and North SlopeFoothills sales include tracts adjacent to federal tracts avail-

able at the BLM lease sale, giving a bidder the potential topick up adjacent acreage on state and federal lands, thusgaining more flexibility in accessing oil and gas pools.

“This should greatly improve a company’s ability toexplore and develop both state and federal acreage,” DNRCommissioner Dan Sullivan said in an Oct. 28 statement.He said the state has been coordinating with the federalgovernment on the lease sale dates “in the hope that work-ing together will enhance opportunities for successful stateand federal oil and gas lease sales.”

Two known prospectsDNR cited two known prospects, Umiat and Gubik,

which straddle state land and NPR-A, but said “much of theacreage along the state-federal border has seen minimalexploration in recent years,” and said it is offering thoselands at minimum royalty rates and rental rates to enticeinterest.

DNR noted that according to a 2005 U.S. GeologicalSurvey assessment there are 19 oil plays straddling stateand NPR-A acreage, 17 of which are included in the BLMsale area.

The state’s lease sale includes nearly 15 million acres. While BLM is offering selected tracts, the state is offer-

ing unleased acreage in its sales areas under its areawideleasing program.

BLM sale areaBLM is offering tracts 283 tracts, some 3 million acres,

in Northeast and Northwest NPR-A, including 178 tracts,1.8 million acres, in Northeast NPR-A and 105 tracts, 1.2million acres, in Northwest NPR-A.

BLM said in an Oct. 28 statementthat there are currently 169 oil andgas leases in NPR-A totaling1,361,105 acres in the Northeast andNorthwest planning areas of NPR-A.

BLM-Alaska State Director BudCribley called NPR-A energyresources “essential to meeting ournation’s energy demands” and saidthose resources would “enhancedomestic energy production anddecrease dependency on foreign oil sources.”

“I believe it is possible to develop oil and gas resources,while protecting important surface and subsistenceresources,” Cribley said in BLM’s Oct. 28 release. He saidthe oil and gas lease sale reflects BLM’s “mission to bal-ance the protection of the natural resources and rural sub-sistence with the nation’s need for oil and gas developmentwithin the NPR-A.” �

DAN SULLIVAN

BUD CRIBLEY

Contact Kristen Nelson at knelson@petroleumnews.com

� F I N A N C E & E C O N O M Y

Courts give Rutter Umiat prospect royaltyAlaska Supreme Court affirms lower court ruling on small overriding royalty interest at the North Slope oil prospect

Contact Eric Lidji at ericlidji@mac.com

SHA

NE

LASL

EY

By ALAN BAILEYPetroleum News

The average shopper walking throughan Anchorage mall probably takes for

granted the flow of electrons that powershop lights, keep the heating system work-ing and enable that quick cell phone call tohome. But with manyof those electronsoriginating frompower stations burn-ing a continuous flowof natural gas fromthe aging Cook Inletgas fields, and withthe electrons travelingfrom power stationsto power demandcenters through afragile power transmission network, muchof it built many decades ago, staff in theregion’s electric utilities worry about thereliability of those vital power supplies.

Winter concernOn Oct. 20 Joe Griffith, president of the

Alaska Railbelt Cooperative Transmissionand Electric Co., otherwise known asARCTEC, described to the Alaska SenateResources Committee the steps that theutilities are taking to ensure power supplyreliability.

The bulk of the power used in theAlaska Railbelt grid, stretching fromHomer in the south, through Anchorage toFairbanks in the north, comes from gas-fired power stations. But with most of thegas flowing from gas fields that aredecades old, gas and power utilities havestruggled in recent years to ensure an ade-quate flow of utility gas to meet peak win-ter demand. In the event of a serious gasshortfall, the power utilities would have toprotect the pressure in gas distributionpipelines by instituting a series of rollingblackouts to reduce gas usage — the utili-ties have already worked out a plan for howto allocate the blackouts among them-selves, Griffith said.

Griffith expressed particular concernabout the coming winter, saying that the

8 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

ASSOCIATIONSMoriarty to replace Crockett at AOGA

Kara Moriarty, deputy director of the Alaska Oil and Gas Association, has beennamed to replace Marilyn Crockett as the association’s executive director.

AOGA said in a Nov. 1 release that its board of directors unanimously namedMoriarty to replace Crockett, who is retiring from AGOAeffective Jan. 1 after more than 41 years with the association.

“Marilyn Crockett has spent her entire professional careerdedicating herself and her strong work ethic to AOGA and hasearned the right to enjoy retirement after so many years of serv-ice to our industry,” Dale Pittman, Alaska production managerfor ExxonMobil and current president of AOGA, said in astatement.

“At the same time, I want to say how pleased we are thatafter an extensive nationwide search, we found our next leaderright here at home in Kara Moriarty. She has the talent, com-petence and ability to lead AOGA in the days ahead as our industry faces many newchallenges and opportunities, especially with declining oil production.”

Moriarty at AOGA since 2005Moriarty started her career in 1996 as a teacher in the small Inupiat village of

Atqasuk on the North Slope, and since then has held various policy positions in boththe public and private sectors. She worked for a U.S. congressman in Washington,

D.C., and served as legislative staff in Juneau. Prior to coming to AOGA, she was the pres-

ident and chief executive officer of the GreaterFairbanks Chamber of Commerce for fouryears.

She joined AOGA in 2005 as a programassociate and served as external affairs manag-er before becoming deputy director in 2007.

“I can think of no single individual who isbetter positioned than Kara to take over thereigns as AOGA’s executive director,” Crockettsaid. “She has strong connections throughout

the state and is highly respected.”Moriarty said she looked “forward to building onto our strong team to foster the

long-term viability of the most important private sector industry in Alaska. It is agreat honor and I look forward to the opportunity.”

Moriarty will be the fifth executive director in the association’s 45-year history.—PETROLEUM NEWS

KARA MORIARTY

DA

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HA

RB

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Moriarty said she looked“forward to building ontoour strong team to fosterthe long-term viability of

the most important privatesector industry in Alaska. Itis a great honor and I look

forward to the opportunity.”

� U T I L I T I E S

Keeping the Railbeltpower flowingMain Alaska population centers face challenges with electricitydelivery amid tightening gas supplies and an aging infrastructure

JOE GRIFFITH

� N A T U R A L G A S

Gas line player YukonPacific winds downCompany surrenders federal right-of-way grant for its LNGproject; despite $100M investment, construction never started

By WESLEY LOYFor Petroleum News

A longtime contender for constructionof an Alaska natural gas pipeline is

bowing out of the game.Yukon Pacific Corp., in correspondence

with federal officials, said its Trans-AlaskaGas System project, or TAGS, “has official-ly come to a close,” and the company is inthe process of dissolution and windingdown its business affairs.

Efforts related to TAGS “reflect aninvestment in Alaska of more than $100million with no return,” said a June 2 letterfrom an Anchorage law firm representingYukon Pacific.

The letter was in support of the compa-ny’s request to surrender its federal right-of-way grant for the TAGS project, construc-tion of which never got under way.

The U.S. Bureau of Land Managementon Oct. 26 issued a decision honoringYukon Pacific’s request and terminating theright-of-way grant.

Yukon Pacific had held the grant since1992, and was incurring expenses such asannual rent in keeping it.

Company’s rise and fallYukon Pacific, whose major owner is

transportation giant CSX Corp., was incor-porated in Alaska in 1983. For many years,Wally Hickel, the late governor of Alaska,was involved with the company.

The company’s aim was to build an 800-

mile pipeline to carry the huge North Slopegas reserves to the city of Valdez for lique-faction and shipment aboard tankers toAsia.

But the enormous cost of building a gasline across Alaska frustrated YukonPacific’s efforts.

The company suffered serious setbacksin recent years.

In 2008, the Alaska Department ofNatural Resources took away the compa-ny’s conditional pipeline right of wayacross state lands. The department held thatYukon Pacific had not shown enoughprogress for a renewal.

In April 2010, Yukon Pacific asked theFederal Energy Regulatory Commission fora three-year extension of the deadline tocommence construction of its liquefied nat-ural gas export terminal at Anderson Baynear Valdez. FERC’s Office of EnergyProjects denied the extension, saying a1995 environmental impact statement forthe project was outdated.

Yukon Pacific cleared out of its officespace in downtown Anchorage in 2003.

Even with Yukon Pacific’s departure, theidea of shipping LNG overseas is still partof Alaska’s ongoing gas line discussion.

Indeed, on Oct. 27, Gov. Sean Parnellsuggested energy companies come togetheron an LNG project, as efforts to build apipeline to the Lower 48 seem to havestalled. �

Contact Wesley Loy at wloy@petroleumnews.com

see RAILBELT POWER page 9

mothballing of a liquefied natural gas facil-ity on the Kenai Peninsula will lead to lessrobust gas supplies during periods of peakwinter demand, while a new gas storagefacility being built on the peninsula byCook Inlet Natural Gas Storage Alaska willnot come on line until the spring of 2012.

“Every one of us believes that this willbe the most difficult year to face,” Griffithtold the lawmakers.

Griffith said that, although there are pro-posals for delivering North Slope gas toSouthcentral Alaska by pipeline, a pipelinecannot be built in time to solve the imme-diate gas shortage problem. New gas devel-opment in the Cook Inlet basin is the leastexpensive energy option and should beencouraged through appropriate incentivesand rapid permitting, he said. However, theimport of liquefied natural gas intoSouthcentral Alaska, to bolster local gassupplies, appears to be inevitable at somepoint, he said.

“Unfortunately I don’t see any way ofgetting out of importing LNG,” Griffithsaid.

Generation & transmission co-opIn December 2010 five of the six

Railbelt electric utilities formed ARCTECas a power generation and transmissioncooperative to pool their resources, toachieve economies of scale for grid opera-tions and to provide a vehicle for the fund-ing of grid upgrades. Founding memberswere Chugach Electric Association,Matanuska Electric Association, HomerElectric Association, Seward Electric andGolden Valley Electric Association.

And the cooperative has what it termsthe “Railbelt Energy Plan,” derived froman earlier plan developed by the AlaskaEnergy Authority and designed to address anumber of issues that the Alaska Railbeltpower grid faces, Griffith explained.

Within the power generation compo-nents of this plan, Chugach ElectricAssociation, in partnership with Anchorageutility Municipal Light & Power, is build-ing the Southcentral Power Project, a state-of-the-art, high-efficiency gas-fired powerstation in Anchorage. At the same time,Matanuska Electric Association, or MEA,is pushing ahead with a plan to build a newpower station at Eklutna, at the base of theChugach Mountains to the north ofAnchorage. MEA plans to run the Eklutnapower station on natural gas but the plantwill also be able to accept other fuels, thusenabling the use of diesel fuel or perhapspropane in the event of a gas shortage.

HydropowerHydropower, especially from the

Bradley Lake power plant in the southernKenai Peninsula, makes a significant con-tribution to the Railbelt power generationcapacity. One component of the RailbeltEnergy Plan is an upgrade to the BradleyLake facility, adding 30,000 megawatthours to the capacity of that plant throughthe diversion of an additional creek into thefacility’s water supply, Griffith said.

And, looking further into the future, theAlaska Energy Authority is moving aheadwith a plan to build a major hydropowerplant at Watana on the Susitna River, 125miles or so upstream of the town ofTalkeetna. ARCTEC supports this projectand the Alaska Energy Authority has justasked the utilities for information abouthow much power they are likely to needfrom the plant, Griffith said.

From the perspective of wind power,Chugach Electric Association has recentlyagreed to buy power from Cook InletRegion Inc.’s Fire Island wind farm, off-shore Anchorage, with that wind power

purchase agreement now before theRegulatory Commission of Alaska forapproval. Matanuska Electric Associationhas also agreed to take 15 percent of thepower from Fire Island but has yet to final-ize a price agreement for the power — theprice looks like being somewhere in therange $90 to $95 per megawatt hour,Griffith said.

Fairbanks utility Golden Valley ElectricAssociation is in the process of buildinganother wind farm at Eva Creek nearHealy, on the north side of the AlaskaRange.

And on another front, OrmatTechnologies is proceeding with a geother-mal power project on the flanks of MountSpurr, an active volcano to the west ofAnchorage.

$56 millionIn the last legislative session, the Alaska

Legislature appropriated $56 million forupgrades to the Railbelt power infrastruc-ture, with much of that money going intoupgrades of aging power transmissionlines. One series of transmission intertiesconnects Fairbanks to a coal-fired powerstation at Healy, and hence to theMatanuska and Susitna valleys andAnchorage. Another intertie system con-

nects Bradley Lake with Nikiski andQuartz Creek on the Kenai Peninsula, withthis system also connecting through toAnchorage.

Those are the highways that carry thepower to our people, Griffith said.

“It’s a weak system … but it’s so impor-tant,” he said.

Coordinating the operation of the com-plete transmission grid can be a majorheadache, with the potential for a majorpower outage if things go awry.

“The last big one we had in 1989 tookfive days to put … back together, so it’s nosmall undertaking to coordinate that,”Griffith said.

The utilities operate the transmissionnetwork under the terms of a joint Alaskaintertie agreement. However, a new IntertieManagement Committee is being formedto oversee intertie operations — this com-mittee will replace the committee that usedto operate the intertie north from theMatanuska and Susitna valleys, Griffithsaid.

“We think we will have that in placewithin 60 days,” he said.

New requestsAnd ARCTEC anticipates a number of

further intertie upgrades as part of a pack-

age of legislative requests that the coopera-tive is preparing for the upcoming legisla-tive session.

Some of the current state funding is alsogoing into work on the pipeline system thatcarries natural gas under Cook Inlet. Thesystem, known as the Cook Inlet GasGathering System, is being modified toallow gas to flow east to west under theinlet, rather than just west to east as at pres-ent. Bidirectional flow in the line willenable greater flexibility in transporting gasto locations such as Chugach ElectricAssociation’s Beluga power station on thewest side of the inlet.

Looking more broadly at energy issuesalong the Alaska Railbelt, Griffith com-mented on the difficult energy cost situa-tion in Fairbanks, a city with limited accessto natural gas supplies in the form oftrucked-in LNG. The high cost of fuel oilfor heating homes drives people to use fire-wood, a cheaper fuel option, while theburning of wood is leading to air qualityproblems. Energy cost issues in Fairbankscould place at risk some of the federalinstallations that are so important to theAlaska economy, Griffith said. �

PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011 9

continued from page 8

RAILBELT POWER

Contact Alan Bailey at abailey@petroleumnews.com

10 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

� F I N A N C E & E C O N O M Y

Oil industry biggest source of AK jobsReport finds that the industry directly and indirectly created 44,800 jobs and $2.65 billion in payroll for Alaska residents in 2010

By ALAN BAILEYPetroleum News

The McDowell Group, in a report pre-pared for the Alaska Oil and Gas

Association, or AOGA, has found that theoil and gas industry is directly and indirect-ly responsible for nearly 45,000 jobs forAlaska residents. That amounts to about 13percent of all private sector jobs in Alaskaand 10 percent of all employment in thestate, the report says.

Proprietary dataRather than using U.S. Department of

Labor employment data, which categorizesemployment in ways that only provide apartial view of the industry’s impact, theMcDowell Group relied heavily on detailedproprietary data from individual companieswhen preparing its report, Jim Calvin, amanaging principal in the McDowell group,told people attending AOGA’s annual lunchon Oct. 27.

By thus gaining insights into wherecompanies spend money and what theyspend the money on, it is possible to devel-op a model of how the oil industry moneymoves through the Alaska economy, creat-ing the financial multiplier effect of a cas-cading chain of company and employeespending, Calvin explained.

Looking at data for 2010, the McDowellGroup analysts assessed the employment ofAlaska residents in terms of employment by“primary companies” and employment byoil industry service companies. The ana-lysts then proceed to assess what they

referred to as “induced employment,” jobsthat result from spending by the employeesof primary and service companies and fromspending by the service companies them-selves.

Primary companies, at the front end of

the oil industry cash flow, consist of oil andgas producers, partners in exploration proj-ects, refineries and the operating companyfor the trans-Alaska pipeline. In addition tocompanies providing traditional oilfieldservices, service companies operating

directly in support of the primary compa-nies include companies providing profes-sional, technical and management services;construction companies; and transportationcompanies.

60% traditional servicesIn fact, the McDowell Group has found

that the use of traditional oilfield services,presumably including activities such asdrilling and well logging, only accounts forabout 60 percent of the total oil industryspend on the services that it uses, Calvinsaid.

In 2010 primary companies in the oiland gas industry employed 4,000 Alaskaresidents, Calvin said. Traditional oilfieldservice companies employed 7,700Alaskans, while other companies providingservices to the oil industry employed 7,100people in state. Spending by these employ-ees and by service companies spawnedanother 26,000 Alaska jobs.

Adding up all of the figures leads to aconclusion that in 2010 the oil and gasindustry ultimately filled the pay packets of44,800 Alaskans to the tune of a total of$2.65 billion in payroll. Of those jobs,25,400 were located in the Municipality ofAnchorage. And for every job in a primaryoil industry company, there are nine otheroil industry related jobs, Calvin said.

Government revenuesCalvin said that the McDowell Group

analysis did not include jobs created from

Alaska needs nonresident workersThe Alaska economy, in general, is very dependent on nonresident labor, Jim

Calvin, a managing principal in the McDowell Group, told people attending theAlaska Oil and Gas Association’s annual lunch on Oct. 27. Calvin was presentinga report by the McDowell Group on the role of the oil and gas industry in theAlaska economy.

In highly seasonal industries, such as seafood processing and visitor-relatedindustries, the proportion of out-of-state workers is particularly high. But in theoil and gas industry, the relative number of non-resident workers varies consider-ably between different industry sectors.

Using data from the Alaska Department of Labor, the McDowell Group foundthat 20 to 30 percent of the people employed in the oil and gas production com-ponents of the industry live out of state, a proportion somewhat similar to that inthe mining industry, Calvin said. Resource extraction activities tend to be charac-terized by high labor mobility and have work rotas convenient for people travel-ing long distances from home, either from out of state or from many differentparts of the state, Calvin said.

By contrast, refineries and the operator of the trans-Alaska pipeline have workforces consisting of more than 90 percent state residents, he said.

And over the past 10 years, the relative numbers of resident and nonresidentoil and gas workers have tended to remain somewhat consistent, trending up anddown in parallel, he said.

However, Calvin cautioned that the Department of Labor data used for theMcDowell Group report may somewhat overstate the number of nonresidentworkers. The data comes from Alaska permanent fund dividend applications thatrequire a person to live in state for nearly two years before being considered astate resident, he said.

—ALAN BAILEY

see MCDOWELL REPORT page 13

PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011 11

By KRISTEN NELSONPetroleum News

What can the State of Alaska do toget more barrels of conventional

oil into the trans-Alaska oil pipeline —and to ensure that the potential of shaleoil production on the North Slopebecomes a reality?

Bill Barron, director of theDepartment of Natural Resources’Division of Oil and Gas, addressed thosequestions from a permitting perspectiveat a meeting of the House ResourcesCommittee in Anchorage Nov. 1.

DNR has been working with otherdepartments on permitting issues in thestate and has also established a multi-departmental shale task force to lookspecifically at requirements for shaledevelopment.

The state wants to make sure it is pre-pared for shale oil development, hence

the task force, which includesDNR, the Department ofEnvironmental Conservation,the Alaska Oil and GasConservation Commission, theDepartment of Fish and Game,the Department ofTransportation and PublicFacilities and the governor’soffice.

Immediate development possible

Barron said that successful explorationof the state’s shale resources could lead toimmediate development, but cautionedthat drilling is required. He said all indi-cations are that the Shublik and Kingakformations are very prospective for shaleoil, but drilling will be required to verifythe viability of the resource on the NorthSlope. Some shale plays in the Lower 48,such as the Marcellus and Bakken, have

been very successful, he told thecommittee, but others have not.He said the Eagle Ford isexpected to be an analogue forthe Shublik, but Eagle Fordwells haven’t been on line longenough to determine how longproduction will last.

Barron said that drillingshale wells is no different thandrilling conventional wells, and

said the state is well positioned to manageshale resource play development basedon current statutes and regulations.

But, he cautioned, the pace and magni-tude of permitting and development forNorth Slope shale oil could be signifi-cant, with a total well count comparableto wells currently in place on the NorthSlope — and with those new wells beingdrilled over a 10-year period, comparedto the 30 years it has taken to drill the cur-rent North Slope well inventory.

Asked by Rep. Peggy Wilson, R-Wrangell, what staff increases agencieswould need to handle that, Barron saidthe task force hadn’t gotten that far yet,but would have information for theLegislature when it reconvenes next year.

The unit issueConventional oil production in the

state takes place from units, groups ofleases usually with different owners. Theleases are unitized for production toensure that there is no waste in producingthe resource, a reaction to early days ofdrilling in the Lower 48 when landownersdrilled as many wells as they could, com-peting with adjacent landowners toextract the oil, resulting in damagedreservoirs and less than maximum oilextraction.

State regulators in oil producing areas— the Alaska Oil and Gas ConservationCommission in Alaska — now ensurethat drilling and production is done insuch a way that resource extraction ismaximized.

And landowners, in Alaska DNR’sDivision of Oil and Gas or the Bureau ofLand Management for federal acreage,require that the acreage over a field beunitized.

But shale oil or gas doesn’t occur inpools or fields. It is continuous overbroad areas.

One of the main reasons for unitization— that oil or gas can be sucked fromadjacent properties — doesn’t apply toshale.

Unitization is for reservoir manage-ment, Barron told the committee inresponse to a question from Co-ChairPaul Seaton, R-Homer. Whether unitiza-tion is even appropriate for shale is indoubt.

There is no pressure communicationfrom well to well, Barron said, and welldrainage is limited.

Alaska regulators are discussing theunitization issue with regulators in areaslike North Dakota where shale develop-ment is under way. Barron said most

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Shale development requirements tackledTask force led by Division of Oil and Gas; DNR also moving ahead with issues impeding conventional oil, gas development in state

BILL BARRON

see SHALE DEVELOPMENT page 13

PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011 13

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government oil and gas royalties and taxes.In 2010 oil industry royalties and taxes of$4.9 billion accounted for 89 percent oftotal state revenues, he said.

A report from the University of AlaskaAnchorage Institute of Social andEconomic Research has indicated that oilindustry related state government revenuesgenerate as many as 60,000 jobs, Calvinsaid. That would suggest a total of morethan 100,000 oil industry generated jobs inthe state, a figure that is nearly one quarterof the total number of full- and part-time in-state job positions, he said.

And the oil and gas industry accountsfor nearly 25 percent of Alaska’s state grossproduct, the measure of the overall value ofeconomic activity in the state, Calvin said.

“There’s no other industry in state thatcomes anywhere near oil and gas in termsof its contribution to our gross state prod-uct,” Calvin said. �

continued from page 10

MCDOWELL REPORT

Contact Alan Bailey at abailey@petroleumnews.com

NATURAL GASGeorge joints AGDC as admin director

The Alaska Gasline Development Corp. said Nov. 2 that Jamilia George has joinedAGDC as director of administrative services.

George has most recently been with the Denali Commissionas chief of staff for the state’s executive branch.

A 30-year Alaskan, she has 27 years of government service,including more than 17 years as chief deputy for the U.S.Bankruptcy Courts in Alaska.

She received her juris doctor from Gonzaga University,holds a certificate in professional mediation from the Universityof Washington School of Law and is admitted to practice beforethe Alaska state and federal courts and the U.S. Supreme Court.

AGDC President Dan Fauske said George’s “extensiveexperience makes her a valuable asset to AGDC as we contin-ue to develop the Alaska Stand Alone Gas Pipeline project to access secure NorthSlope gas supplies for Interior and Southcentral Alaska.”

AGDC, a subsidiary of the Alaska Housing Finance Corp., was mandated byHouse Bill 369 to produce a project plan for the development of an in-state natural gaspipeline, a plan presented to the Alaska Legislature on July 5.

—PETROLEUM NEWS

JAMILIA GEORGE

BSEE appoints regulatory programs chiefThe Bureau of Safety and Environmental Enforcement has appointed Doug

Morris as the new chief of the agency’s regulatory programs, BSEE announcedNov. 1. Morris will be responsible for developing and maintaining technical andoperational standards; developing new regulations; and enhancing inspectionsand enforcement programs. He willalso lead efforts to improve offshoreoperational safety and superviseBSEE’s National Offshore Learningand Training Center, BSEE said.

Morris comes from the EnergyInformation Agency, or EIA, wherehe was director of the Reserves andProduction Division and thenbecame responsible for the Oil andGas Supply and Financial StatisticsTeam. Prior to serving in EIA heserved as group director forupstream and industry operations inthe American Petroleum Institute. Morris had previously worked in the U.S.Minerals Management Service and in private industry.

“Throughout the recruitment process, we have looked for people who are tech-nically skilled and experienced, who have a strong commitment to public serv-ice, and who can spearhead our ongoing efforts to enhance the safety of offshoreexploration and production,” said BSEE Director Michael Bromwich whenannouncing Morris’s appointment.“Because of his vast and diverse experience,both within the federal government and in private industry, Doug Morris bringsto the agency a blend of personal qualities and professional qualifications thatwill help us achieve our goals. I look forward to having Doug on our team in thisvery important job.”

—ALAN BAILEY

GOVERNMENT

Morris comes from the EnergyInformation Agency, or EIA, wherehe was director of the Reserves and

Production Division and thenbecame responsible for the Oil andGas Supply and Financial Statistics

Team. Prior to serving in EIA heserved as group director for

upstream and industry operations inthe American Petroleum Institute.

jurisdictions have just changed spacingrequirements for shale wells, rather thanunitizing.

Hydraulic fracturing, natural gasHydraulic fracturing has been a big

issue in Lower 48 shale development. Barron said about 25 percent of Alaska

wells — both on the North Slope and inCook Inlet — are fractured, so theprocess isn’t new to the state, or unique toshale play development. A large numberof horizontal multistage hydraulic frac-tured wells are required to maintain pro-duction and economic feasibility fromshale plays.

Frac fluids are approximately 98 per-cent water and sand and there would beno surface disposal of water in Alaska,Barron said.

Seaton asked about natural gas pro-duced along with the oil.

Barron said that in the Bakken, wherethe oil wells are very low-rate, the associ-ated gas is also produced at a low rate.

But it’s not the same as conventionalproduction — you can’t re-inject naturalgas into a shale formation, so disposal ismore complex. With more wells, pumpswill need power and gas could be used forthat, he said.

But since the resource hasn’t beendrilled yet, it’s not known whether theamount of gas will be small or large.

Conventional issuesBarron also reviewed issues impeding

conventional North Slope development. The permitting task force led by

Deputy DNR Commissioner Ed Fogels islooking for overlaps and gaps in thestate’s permitting requirements, Barronsaid.

But, he told the committee, in permit-ting, “one man’s impediment is anotherman’s protection.”

One issue is that smaller companies,and companies new to Alaska, are bid-ding on leases. These companies have lit-tle experience in permit sequencing andtimeframes, may not have allottedenough time to address public concernsand local government requirements andare not familiar with conducting businessin Alaska.

There is also a new issue, since thedemise earlier in the year of the Alaska

Coastal Management Program:Applicants are now responsible for proj-ect coordination with local, state and fed-eral agencies. Barron said the permittingtask force recognizes how critical coordi-nation is; an Alaska project questionnaireis being developed to serve as a road mapfor permitting.

Drilling season, roadsBarron said finding a way to extend

the drilling season would reduce oneimpediment.

And the “Roads to Resources” concepthas value beyond the Foothills area.

Roads came up in the shale develop-ment discussion, with Sen. Cathy Giessel,R-Anchorage, asking about a requirementfor gravel roads for shale play develop-ment. Barron said the state’s best interestfindings require ice roads for exploration,but not for development. And once GreatBear Petroleum, which acquired some500,000 acres in last fall’s state leasesales specifically for shale resources,drills its first four wells, in concept therewould never be another exploration wellfor shale. Barron said once the resource isidentified, every well will be drilled,fracked and produced.

All development on the North Slope isfrom gravel roads, he said, except Alpineand Badami which were done as roadlessdevelopments.

He said roadless developments haven’tbeen beneficial for adjacent lease explo-ration, citing Badami as an example. Ifthere had been a road into Badami, itwould have significantly reduced the costof exploring east of existing fieldsbecause ice roads would have beenrequired just from the gravel road. Atremendous expanse of the North Slopehas remained unexplored because of cost,he said.

“Roadless” was viewed as the rightway to go, Barron said, but it may not bethe right way in terms of long-term devel-opment.

Resources Co-Chair Eric Feige, R-Chickaloon, asked if there were areasother than the North Slope that wouldbenefit from permanent roads.

Barron said the west side of Cook Inletwould also benefit. The area has pipelineaccess, he said, but no roads, and a per-manent road would increase the explo-ration opportunities. �

continued from page 12

SHALE DEVELOPMENT

Contact Kristen Nelson at knelson@petroleumnews.com

By WESLEY LOYFor Petroleum News

Alaska Gov. Sean Parnell is unhappythe legal conflict over Point

Thomson, a rich but undeveloped NorthSlope oil and gas field, remains unre-solved.

Speaking at the Oct. 27 annual lunch-eon of the Alaska Oil and GasAssociation, a trade association of thestate’s oil producers, Parnell said a dealstruck weeks ago between the state andPoint Thomson unit operatorExxonMobil still lacked the endorsementof the field’s other working interest own-ers.

The major working interest owners,aside from ExxonMobil, include BP,Chevron and ConocoPhillips.

“We got that Point Thomson settle-ment done last August, hammering out aresolution of that litigation with the unitoperator, ExxonMobil. So what’s the

holdup?” Parnell said, speakingto a large audience at theAOGA event in downtownAnchorage. “Well, still, there’sno public word from the otherworking interest owners aboutwhether they’re going to join usin the settlement with the unitoperator and the state.”

Parnell continued: “It’sdeeply troubling to me, andshould be troubling to you as Alaskans,that this litigation has been pendingthrough three administrations. The statenegotiated a resolution with the unit oper-ator, like we were supposed to. But theother working interest owners have yet tofinalize the settlement.”

Key for gas lineParnell made his remarks in the con-

text of the state’s longtime goal of build-ing a pipeline to carry North Slope natu-ral gas to market.

Point Thomson gas, coupled with gasreserves in the giant Prudhoe Bay field, isconsidered important for supporting apipeline, the governor said.

“Point Thomson gas represents one-fourth of the 35 trillion cubic feet of nat-ural gas reserves that we know existbetween Prudhoe and Point Thomson,”he noted.

Point Thomson is located on the east-ern North Slope, along the Beaufort Seacoastline next to the Arctic NationalWildlife Refuge.

Although discovered long ago, withwells drilled in the 1970s, Point Thomsonhas seen no production to date. The fieldis rich not only in gas but holds hundredsof millions of barrels of petroleum liq-uids. Development would generate jobs,taxes and royalties.

State officials reached the end of theirpatience with the leaseholders in 2005,launching efforts to break up the unit andtake back the state acreage at PointThomson. Frank Murkowski was gover-nor at the time.

ExxonMobil and its partners havesince fought in court to preserve the unit,and the case currently sits before the

Alaska Supreme Court.ExxonMobil has cited the lackof a multibillion-dollar gaspipeline as a primary reasonwhy Point Thomson hasn’t beendeveloped.

Reaction to Parnell’s remarksOn Aug. 15, during a legisla-

tive hearing, Alaska NaturalResources Commissioner Dan

Sullivan revealed that a “resolution inprinciple” had been reached withExxonMobil to settle the Point Thomsoncase.

He said ExxonMobil was discussingthe settlement provisions with the otherworking interest owners, and the compa-nies were working out “internal commer-cial terms.”

But little has been heard publicly sinceSullivan’s revelation.

One factor holding up the deal couldbe the discontent among the other fieldowners over how they were treated duringsettlement talks between the state andExxonMobil. In court filings, lawyers forBP, Chevron and ConocoPhillips com-plained that the companies had been shutout of the negotiations.

Representatives of those companieswere present at the Dena’ina Civic andConvention Center to hear Parnell’sremarks.

Spokespersons for two companies,Chevron and ConocoPhillips, had little tosay after Petroleum News asked for com-ment.

“Chevron does not have any com-ments to offer on the Governor’sremarks,” Chevron’s Roxanne Sinz saidin an email.

“We do not generally comment onpending litigation issues,” said NatalieLowman, of ConocoPhillips.

BP was a little more talkative.“The proposed agreement is com-

plex,” BP spokesman Steve Rinehart saidby email. “We and other owners hadasked to be involved in the discussions,but were not allowed. We are now work-ing with the state and Exxon to under-stand both the settlement agreement and

the development project that is embeddedwithin the agreement.”

ExxonMobil’s David Eglinton offeredthis: “We are continuing to make progresson settlement, but additional workremains. We remain committed to work-ing with Governor Parnell’s administra-tion and the other working interest own-ers to finalize a settlement. Settling PointThomson litigation and securing neces-sary local, state and federal permits isimperative to maintain the pace of PointThomson development.”

What sort of development?If the other working interest owners are

mad, hopefully they aren’t mad at the statefor negotiating, as it customarily does, withthe unit operator, Parnell told PetroleumNews after his speech.

Even amid the legal conflict,ExxonMobil has made a start toward aPoint Thomson development.

Between May 8, 2009, and Oct. 27,2010, the company drilled a pair of wells atPoint Thomson, the first sunk there sincethe early 1980s. It did so, ostensibly, withthe blessing of the other working interestowners.

The “development wells,” asExxonMobil termed them, are part of apromised $1.3 billion project to start pro-ducing 10,000 barrels a day of natural gascondensate by year-end 2014.

That’s a modest volume by North Slopeproduction standards, and the state likelywants something more.

It will be interesting, then, to see whatsort of development is called for under thestate settlement with ExxonMobil, andwhether the deal includes any commitmentsof Point Thomson gas to a pipeline project.

On another front, ExxonMobil is seek-ing a federal wetlands permit for PointThomson production facilities, and the U.S.Army Corps of Engineers is drafting anenvironmental impact statement. The Corpsis scheduled to release a draft EIS any daynow, with a record of decision to be signedin August 2012. �

� L A N D & L E A S I N G

Parnell voices Point Thomson impatienceAlaska governor calls out other working interest owners yet to sign onto state deal with ExxonMobil on disputed oil and gas field

14 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

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

Kinder Morgan tests watersCalls open season to double capacity of Trans Mountain to 600,000 bpd, fueling competition with Enbridge on routes to Asia-Pacific

By GARY PARKFor Petroleum News

Quietly operating below the radar while its Canadianrivals TransCanada and Enbridge are entangled in

raging pipeline controversies, Kinder Morgan Canada istaking another step towards offering Alberta oil sands pro-ducers greater access to the Asia-Pacific region.

It has launched an open season that expires Jan. 19 totest shipper response to a proposed 300,000 barrels per daydoubling of capacity on its Trans Mountain system fromAlberta to the Port of Vancouver and Puget Sound inWashington state.

If it receives sufficient commitments for a project thatcould cost C$3.8 billion, Kinder Morgan will have strong-ly positioned itself to either fill the void should Enbridge’sNorthern Gateway project unravel, or go head-to-headagainst its competitor.

Currently, it is the only pipeline operator serving theemerging Asian market through small shipments from theWestridge marine terminal in Vancouver.

Planned in-service date of 2017The open season aims to expand the role of that termi-

nal by seeking binding 15- and 20-year transportationagreements on the 715-mile Trans Mountain system, witha planned in-service date of early 2017.

Although Kinder Morgan is putting its emphasis onexpanding Trans Mountain’s long-established southernroute, it has not ruled out a second line to the deepwater

port at Kitimat, on the northern British Columbia coast.Kitimat is also Enbridge’s planned terminal location for

the 525,000 bpd Northern Gateway pipeline, which is fac-ing a possible two-year hearing process before a joint panelof the National Energy Board and EnvironmentalAssessment Agency.

The pressure is already on Kinder Morgan to enlargeWestridge. The Trans Mountain system is currently over-subscribed by up to 50 percent, partly because a pipelineleak in Alberta during the summer led the NEB to order a20 percent reduction in volumes, forcing Kinder Morgan torestrict shipments to 44 percent of nominated volumes inNovember. Of the accepted nominations of 280,920 bpd,44,877 bpd are destined for Westridge.

Ruling by end of yearThe NEB is expected to rule before year’s end on a

Trans Mountain application to provide 54,000 bpd of firmdock service out of 79,000 bpd of dock capacity atWestridge, leaving the balance for spot shippers. That pro-posal is in response to an oversubscribed open season lastyear.

Kinder Morgan said 25 percent of the crude on the threeor four tankers leaving Westridge every month is destinedfor Asia, compared with about 10 percent a year ago, andthe rest for the U.S. Pacific Coast, strongly hinting at grow-ing producer interest in accessing the Far East.

Cenovus Energy, one of Alberta’s leading oil sandsdevelopers, has openly identified Asia as one of its likelyalternative if the TransCanada Keystone XL pipeline from

Alberta to the Texas Gulf Coast loses its struggle forapproval by the Obama administration.

Kinder Morgan is confident it can use the existing TransMountain right of way for an additional 300,000 bpd with-out posing additional environmental concerns and said ithas strong backing from First Nations, unlike the NorthernGateway proposal.

But Enbridge has countered that Northern Gatewaycould operate tankers out of Kitimat with twice the capac-ity of those using Westridge.

Tankers out of VancouverAlthough tankers from Westridge use a narrow and

shallow channel through the densely populated center ofVancouver and close to the city’s scenic treasures, KinderMorgan has attracted only limited interest from environ-mentalists compared with the opposition facing NorthernGateway.

However, those days may be drawing to a close asmunicipal and federal politicians start to discuss the risks.

Derek Corrigan, mayor of Burnaby, where theWestridge terminal is located, said his community doubtsKinder Morgan’s ability to manage an emergency situa-tion, while federal Natural Resources Minister Joe Oliveris being pressured to hold a full consultation on the project.

So far, Oliver has said only that every major proposalwill be reviewed by regulators and his government“respects the regulatory process.” �

Contact Gary Park through publisher@petroleumnews.com

Costly campaignThe piping replacement work actual-

ly consists of several major projects,each to cost “tens of millions of dollarsto complete,” said Alyeska spokes-woman Michelle Egan.

Firms under existing contracts willhandle part of the work, with some jobsto be put out for bid, Egan said.

The piping to be replaced is charac-terized as “dead leg, low and intermit-tent flow, and concrete encased piping,”the summary document says. Such pip-ing can’t be excavated for inspection, orinspected internally with tools calledpigs.

Alyeska has given regulators a sched-ule for doing the piping replacements.Pump Station 1 will see “the most com-plex and critical” project, Alyeska says.It will be the first station to have itsbelow-ground crude oil piping reroutedto an above-ground configuration.

The final design for Pump Station 1

will be finished by year’s end, with con-struction to start in the first quarter of2012 and conclude in the fourth quarterof 2013, the schedule shows.

Projects will follow at pump stations3, 4, 5 and 9, with all the piping replace-ments to be finished by the fourth quar-ter of 2014.

“Each of the pump stations will havea two year construction season to com-plete all of the piping work,” theAlyeska summary says. “The first con-struction season will install civil founda-tions, pipe supports, trenches, and otherpreparatory work and the second seasonwill install the piping and make the finaltie-ins.”

Aging pipelineAlyeska is the Anchorage-based con-

sortium that runs the trans-Alaskapipeline on behalf of owners BP,ConocoPhillips, ExxonMobil, Chevronand Koch Industries.

The pipeline has been moving oilfrom Prudhoe Bay and other North Slopefields since June 20, 1977.

Federal pipeline regulators hit

Alyeska with a “notice of proposed safe-ty order” in February, following the leakinside a Pump Station 1 building base-ment. The leak forced a pipeline shut-down lasting about three and a half days.

The leak was described as a boosterpump manifold failure. A manifold is anarrangement of piping or valves designedto control, distribute or monitor fluidflow.

The mainline, 48-inch pipe was notinvolved.

Alyeska retained Det Norske Veritas,a Norwegian concern specializing in riskmanagement, to do an independentinvestigation of the Pump Station 1 leak.

A 6-foot section of piping, containingthe location of the leak, was removed andshipped to Det Norske Veritas for metal-lurgical analysis, the Alyeska summarysays.

In their proposed safety order, federalpipeline regulators cited “multiple condi-tions” on the pipeline that appeared topose an integrity risk. The concerns cen-tered on the pipeline’s declining oilthroughput and the potential for freeze-ups and corrosion.

As part of the settlement Alyeskasigned with PHMSA in August, Alyeskaagreed to replace or remove hard-to-inspect oil piping.

Marine terminal involvement“It’s important to emphasize that a lot

of these piping issues can be attributed todeclining flow through our systems andthat many of these piping projects werealready planned,” Alyeska’s Egan said.

Aside from the pipeline itself,Alyeska operates the Valdez MarineTerminal, where the line ends and wheretankers pick up crude for delivery toWest Coast refineries. The terminal is asprawling, waterfront complex of tanks,pipes and piers.

The Alyeska summary says a riskassessment was done not only for pumpstation piping, but also for marine termi-nal facility piping.

The summary, however, says nothingabout any planned piping replacementsat the terminal. �

region, saying he will respect the regulatoryprocess that is now evaluating the project.

Alberta: Northern Gateway optionNewly installed Alberta Premier Alison

Redford joined the pro-oil sands chorus,describing criticism of the sector as “short-sighted, misinformed and exaggerated” andmaking it clear her government will supportboth Keystone XL and Northern Gateway.

“If Keystone isn’t approved, it’s got to beNorthern Gateway,” she said. “We alsohave to look at Kinder Morgan’s (TransMountain pipeline) because they have aregulatory corridor that allows for expan-sion.”

If the Gateway pipeline and TransMountain expansion proceed, the UnitedStates would lose first call on Canadiancrude and undermine its goal of energysecurity, Redford said.

The latest hiccup for Keystone has sur-faced in Nebraska, where the state senate isholding a special session to discuss the pro-posed routing of Keystone.

Asia attracting interestRegardless of whether the project is

approved at the federal level later this year,Asia is attracting interest from pure-play oilsands producer Cenovus Energy, which hasopened a data room to prospective jointventure partners for its 90,000 bpdTelephone Lake project and nearby unde-veloped lands.

Chief Executive Officer Brian Fergusonsaid the “billions of barrels of recoverableoil” that are up for bids have allowedCenovus to pre-qualify “several” potentialpartners.

They cover national oil companies,supermajors and multinationals based inCalgary, Houston, London, India andChina, he said.

There is speculation that India’s energygiant Reliance Industries has been evaluat-

ing oil sands assets and may have been theSeptember buyer for C$60 million of Oilsands Quest’s Wallace Creek assets near theCenovus joint venture properties.

In addition, Oil and Natural Gas Corp.,based in New Delhi, reportedly entered dis-cussions last spring to acquire oil sandsreserves.

Ferguson said the timing of a Cenovusdeal will hinge on what progress is madeover the next few months, adding the endresult could involve, cash, asset swaps orother options, while Cenovus will file anapplication before yearend to upsize the ini-tial Telegraph Lake project to 90,000 bpdfrom 35,000 bpd.

—GARY PARK

continued from page 1

ALYESKA PIPING

Contact Wesley Loy at wloy@petroleumnews.com

continued from page 1

KEYSTONE DEBATE There is speculation that India’senergy giant Reliance Industries

has been evaluating oil sandsassets and may have been the

September buyer for C$60 millionof Oil sands Quest’s Wallace Creek

assets near the Cenovus jointventure properties.

Contact Gary Park through publisher@petroleumnews.com

16 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

CGGVeritas seismic vessel to be used in NorwayCGGVeritas said Oct. 27 that the first project for its recently launched Oceanic Sirius

X-BOW® seismic vessel will be a 3-D BroadSeis™ survey on the Avaldsnes field, poten-tially estimated to be the third largest oil discovery in Norway, on behalf of LundinPetroleum.

As one of the most advanced, high-capacity seismic vessels worldwide, the OceanicSirius is designed for superior acquisition data quality combined with the highest envi-ronmental standards and the minimum operational downtime. Her operational efficiencyis expected to match if not exceed the outstanding seismic performance already shownby her sister ship, the Oceanic Vega.

BroadSeis, the new CGGVeritas broadband marine solution, was selected to improvethe resolution and imaging of the field. The vessel will acquire BroadSeis data with SercelSentinel® solid streamers equipped with the Sercel Nautilus® streamer control device.DoveTailTM, a proprietary CGGVeritas acquisition and processing solution designed toachieve more regular sampling and to reduce infill, will also be deployed on this project.

CGGVeritas is a leading international pure-play geophysical company delivering awide range of technologies, services and equipment through Sercel, to its broad base ofcustomers mainly throughout the global oil and gas industry.

TOTE president honored with 2011 achievement awardTotem Ocean Trailer Express Inc said Oct. 25

that its president, John Parrott, was honored earli-er in the month by his alma mater, the U.S.Merchant Maritime Academy, with the 2011Outstanding Professional Achievement Award.

The Outstanding Professional AchievementAward is given to the USMMA graduate “whobest exemplifies the finest tradition of the Corps,‘Acta Non Verba’ (meaning act, don’t talk), byattaining personal achievement in their chosenfield and thus lending honor and prestige to theUSMMA.”

Parrott graduated from the USMMA, located in Kings Point, N.Y., 1986 with a bachelorof science degree in Marine Transportation, continuing on to earn a master’s of businessadministration from Seattle University. He holds a commission in the U.S. Naval Reserveand is a licensed master in the U.S. Merchant Marine, having sailed for 10 years aboard a

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includes Brooks Range Development Corp.(the local development affiliate of BRPC),the Calgary-based independent TG WorldEnergy Inc. and Nabors subsidiaryRamshorn Investments Inc.

he Tofkat and Putu unitsBRPC applied to form the Putu unit in

March 2011, but DNR didn’t deem theapplication complete until July. The originalproposal covered some 39,993 acres over39 leases, including 28 owned jointly by thestate and Arctic Slope Regional Corp.,along the eastern edge of the Colville River,south of the Colville River unit, nearNuiqsut.

The original Putu unit proposed threeexploration blocks — North, Southwest andSoutheast — but DNR ultimately brokethose into two units. The North block is nowthe Tofkat unit, while the Southwest andSoutheast blocks are now the Putu unit totake advantage of the differing geologiesand exploration histories within the region.

The Tofkat unit includes 21 leasesowned jointly by the state and ASRC cover-ing some 9,131 acres, while the Putu unitincludes nine state leases covering some21,946 acres.

The nine leases not included in eitherunit will expire at the end of their terms,unless unitized at some point in the future(although two leases expired on March 31,2011).

DNR also increased the rental rates onnumerous leases to make up for the poten-tially lost revenue it could collect by leasingthat acreage out to another company.

Once the 15 leases in the Tofkat unit setto expire between July 31, 2012, and Aug.31, 2013, reach the end of the primaryterms, the rental rates will jump to $4.50 peracre, up from $3 per acre, as will the nineleases in the Putu unit set to expire Aug. 31,2012.

The working interest owners must alsoexecute a new agreement with ASRC.

Tofkat geology knownThe Tofkat unit includes three wells

BRPC drilled in the area in early 2008.BRPC drilled the Tofkat No. 1 well and

the Tofkat No. 1-A and Tofkat No. 1-B side-tracks in the N Block in 2008, and in later2008 acquired proprietary seismic over thearea.

The primary target of those wells was“Kuparuk C sands, Brookian Albian-ageturbidite fans and Jurassic-age Alpinesands,” three geologic intervals with oil pro-ducing reservoirs in the Colville River unitsome six miles north of the Tofkat unit.

After reviewing geologic and geophysi-cal information in the application, DNR

determined that “a portion of the N blockdoes encompass an oil reservoir within theC member of the Kuparuk Formation, andtwo reasonably defined and delineatedpotential hydrocarbon accumulations in theshallower Nanushuk and Torok forma-tions.”

Because the wells drilled in early 2008penetrated and evaluated both the reservoirand the two potential accumulations, theTofkat unit is more defined than the newPutu unit.

Under the plan of exploration for theTofkat unit, BRPC must drill and completethe Tofkat No. 2 well and Tofkat No. 2-Asidetrack into the Kuparuk formation byMay 31, 2013. The working interest ownersmust sanction the Tofkat development proj-ect by Oct. 1, 2013 — and keep it sanc-tioned through production — or terminatethe unit.

Putu needs more drillingAlthough not home to any previous

exploration drilling, the new Putu unit sitsmostly within a 220-square mile 3-D seis-mic package that BRPC acquired in 2008and used to identify “prospective targetsthey believe have a higher probability ofencountering reservoir quality sand” thanthe four previous wells drilled within twomiles of the unit.

Those wells, drilled between 1972 and2006, all encountered hydrocarbon-bearingzones in the Brookian Torok formation,“but so far these strata have lacked suffi-cient reservoir quality to likely produce orwarrant development by the operators,”DNR noted in its decision, adding,“encountering reservoir quality strata withsufficient connectivity has historically beenthe crux to unlocking the Brookian potentialon the North Slope.”

ARCO drilled the Itkillik River Unit No.1 to 15,321 feet in 1972, attempting ninedrill stem production tests and taking threeconventional core samples from the well.The deepest of those tests — at an intervalin the Kekiktuk formation between 14,510and 14,726 feet — flowed at an estimatedrate of 3,500 cubic feet per day over sixhours.

Phillips Alaska drilled the Atlas No. 1well and Atlas No. 1-A sidetrack to 7,335and 8,454 feet respectively in 2001, findinghydrocarbon-bearing zones in the TorokFormation but not gathering fluid samplesor conducting production tests at eitherwell.

Pioneer Natural Resources Alaskadrilled the Cronus No. 1 well to 7,941 feetin 2006 to explore a Brookian sourced tar-get in the Torok formation similar to theAtlas wells.

Cronus No. 1 encountered two zones inthe Torok formation that appeared to behydrocarbon bearing, but Pioneer ultimate-ly decided they were too tight to produce.

Under the agreement for the new Putuunit, BRPC must post a $10 million per-formance bond by Feb. 1, 2012, to guaran-tee that it will commit to a four-well drillingprogram.

The first payment of $1 million is due onMay 31, 2012.

The company must then drill four wellsinto the Upper Jurassic-age strata of theKingak formation by May 31, 2013, twotargeting the Musketeer trend (BrookianSequence Boundary C) and two targetingthe Big Foot trend (Brookian SequenceBoundary BC).

S Miluveach and Kachemach BRPC applied to form the Southern

Miluveach unit in December 2010 andDNR deemed the application complete inlate June after the company submitted tworevisions.

The original proposal covered some60,864 acres over 40 leases, including 11owned jointly by the state and ASRC, a mileto the northeast of the new Tofkat and Putuunits.

The initial application proposed sixexploration blocks: Northeast, Southeast,Northwest, Southwest, West and South. Thestate ultimately created the SouthernMiluveach unit out of the Southeast blockand the Kachemach unit out of the West andNorthwest blocks.

The Southern Miluveach unit nowincludes five state leases covering some8,960 acres, while the Kachemach unitincludes 11 state/ASRC leases covering

some 16,487 acres.The leases not included in either unit will

expire at the end of their terms.DNR also increased the rental rates on

18 leases in the Kachemach unit and fiveleases in the Southern Miluveach unit to$4.50 per acre from $3 per acre to make upfor the lost revenue it might have collectedby leasing the acreage out to another com-pany.

Oil shows in the TorokThe first wells drilled in the area — the

Colville No. 1 in 1966 and the KookpukNo. 1 in 1967 — targeted Lisburne forma-tion, but considered it unsuccessful after anevaluation.

The Kuparuk River unit to the east pro-duces from the Lower Cretaceous-ageKuparuk River formation at the KuparukPA and the shallower Upper-CretaceousBermuda sands of the Seabee formation atthe Tarn PA. The Colville River unit to thewest produces from the Jurassic-age Alpineand Nechelik sands in the Kingak forma-tion, from the Lower Cretaceous-ageKuparuk C sand and from UpperCretaceous-age Nanuq sands in the Torokformation and shallower Qannik sands ofthe Nanushuk formation.

ARCO drilled the Colville River No. 1well to 7,300 feet in 1993. Although theoriginal objective in the Cretaceous-agesands of the Kuparuk formation proved tobe unsuccessful, the company did encounter

PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011 17

wide range of vessel types and traderoutes.

The USMMA was formed in 1938 toprovide quality education and training forthe U.S. maritime trade. Today, approxi-mately 300 students are accepted to theprogram each year. Graduates receivedbachelor’s of science degrees and arespecifically trained for careers in the mar-itime industry. Approximately one-third ofgraduates go on to serve as merchantmarine officers, another third seek careersin private industry, with the remainingthird choosing to be commissioned officersin the U.S. military.

Canrig licenses selectedMPO Drilling Technologies

Nabors Industries Ltd. said Sept. 19 thatits wholly owned subsidiaries CanrigDrilling Technology International Ltd. andCanrig Drilling Technology Ltd. haveentered into long-term agreements withManaged Pressure Operations

International Ltd., whereby Canrig willlicense from MPO certain technologiesrelated to managed pressure drilling. MPOis a leading provider of MPD (managedpressure drilling) solutions including itsNon-Stop Driller and Total Control Driller.The Canrig license is exclusive to severalmajor onshore markets, including North,Central and South America and SaudiArabia. In addition, Canrig will havenonexclusive rights to other onshore mar-kets. The agreements also facilitate techno-logical and engineering collaborationbetween Canrig and MPO in developingmore advanced, cost-efficient MPD sys-tems.

“Over 70 percent of Nabors U.S. rigsare doing some form of managed pressuredrilling utilizing third-party equipment andtechnology. A primary goal of this ventureis to develop and implement a fleet ofMPD-Ready™ rigs across the global oper-ations of Nabors utilizing these leadingedge technologies. We extensively evaluat-ed the various MPD systems and conclud-ed that MPO was the best alternative tofacilitate our entry into this growing area,while creating economies and efficienciesfor our customers,” said Chris Papouras,president of Canrig.

continued from page 16

OIL PATCH BITS

continued from page 1

BRPC UNITS

PetroleumEquipment &Services Inc.

Anchorage: (907) 248-0066Prudhoe Bay: (907) 659-9206

fax: (907) 248-44295631 Silverado Way, Suite G

Anchorage, AK 99518www.pesiak.com

is proud to representWeatherford/Gemoco Casing Accessories

see BRPC UNITS page 18

“weak oil shows” in the Torok formation.ConocoPhillips drilled the KRU-2L-03

well as an exploration step out from theTarn 2L drill site in 2002, reaching a bottomhole location in the southeast corner of theSouthern Miluveach unit at 11,316 feet totarget Kuparuk C sand, but later gave up thelease.

ConocoPhillips drilled the Oberon No. 1well eight miles west of KRU-2L-03 in2003 to 7,580 feet targeting the Kuparuk Csand and the Alpine sands in the Kingak for-mation.

BRPC participated in the Ataruq No. 2and Ataruq No. 2A well and sidetrack thatKerr McGee drilled in the proposed unitarea in 2005 to 7,400 feet and 11,242 feetrespectively to target Cretaceous-ageBrookian submarine fans and the deeperLower Cretaceous Kuparuk formationbefore reaching a total depth in theMiluveach formation, encountering oilshows in the Brookian formation but not inthe Kuparuk formation.

The 2008 seismic survey covered thewestern half of the original SouthernMiluveach unit and this year BRPCacquired a license for an earlier survey cov-ering the eastern half, identifying potentialstratigraphic traps in both the Brookian andKuparuk formations.

BRPC drilled North Tarn No. 1 in early2011 to 6,223 feet, identifying an oil reser-voir in the Kuparuk C sand in the SE Block.BRPC also believes there could be a poten-tial accumulation in the Nanushuk forma-tion in the W and NW Blocks. TheNanushuk produces oil at the Qannik sandsof the Colville River unit 11 miles west ofthe unit.

Six wells in the two unitsUnder the agreement for the new

Southern Miluveach unit, BRPC must com-plete three wells — the North Tarn No. 1-Awell, the Mustang No. 1 well and theMustang No. 2 well or sidetrack — into theKuparuk formation by May 31, 2012, and

the working interest owners must sanctionthe Mustang development project by Oct. 1,2012.

The Kachemach unit is now divided intotwo exploration blocks, Block A and BlockB.

Under the Kachemach unit agreement,BRPC must complete one well in Block Atargeting the Caribou trend (BrookianSequence Boundary F) and one well inBlock A targeting the Moonlight trend(TP4-2 Nanushuk prospect) by May 31,

2013.If BRPC meets those commitments the

company must then commit to completeone well in Block B targeting the Moonlighttrend (TP4-1 Nanushuk prospect) by May31, 2014.

Adds to other unitsThe two decisions make BRPC the oper-

ator of five units on the North Slope.In addition to the four new units, DNR

approved the formation of the 52,876-acre

Beechey Point unit in the Gwydyr Bayregion north of Prudhoe Bay in September2009.

Earlier this year, BRPC also applied toform the Greater Bullen unit in the areabetween the Point Thomson and Badamiunits on the eastern North Slope, but recent-ly withdrew that application and announcedplans to apply for a smaller unit in the areanext year. �

18 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

continued from page 17

BRPC UNITS

ment.”

CIRI landStone Horn Ridge LLC, a joint venture

between CIRI and Laurus Energy, is inves-tigating the potential UCG development at asite called Stone Horn Ridge, northeast ofthe Beluga River, in an area where CIRIowns both the surface and subsurface land.Laurus Energy is a Houston-based affiliateof Ergo Exergy, a UCG technology compa-ny based in Montreal, Canada.

UCG involves the pumping of com-pressed air through a well into a coal seamdeep underground to enable the controlledunderground combustion of some coal; theheat from the burn converts excess air andthe bulk of the coal to synthetic gas fordelivery to the surface through productionwells. It would be possible to burn the syn-thetic gas for power generation or to convertit to methane, the prime ingredient of natu-ral gas. Other potential applications includethe production of jet fuel by a gas-to-liquidsprocess, or the production of fertilizer.

And, since the coal is processed deepunderground, the UCG process eliminatesmuch of the environmental impact of con-ventional coal mining and burning.

“We believe that UCG is a technologyby which you can access this world-classenergy resource in an environmentallyacceptable manner,” Schutt said.

Schutt also assured the legislators thatthe underground burn required for the UCG

process could be stopped very easily byclosing off the flow of air required for com-bustion.

Multiple coal seamsSchutt said that the Stone Horn Ridge

joint venture has found multiple, thick coalseams at depths below 650 feet in the StoneHorn Ridge area. The geologic setting ofthe coal appears favorable for the develop-ment of a UCG plant, although the jointventure is still in the process of collectingdata and modeling the geology of the proj-ect site, he said.

The 13 core holes drilled for the explo-ration phase of the project penetrated depthsranging from about 700 feet to about 2,600

feet — the project team collected rock coreand wireline data from the holes. Field andlaboratory examination of rock samples;logging of the drilling mud; and field testsof the desorption of gas from coal samplesalso added to the data from the project site.That data have enabled the construction of acomprehensive computer-based geologicmodel of the site that has provided a pre-liminary validation of the existence of acommercial UCG resource.

The next step will be to carry out a high-resolution shallow seismic survey, gather-ing eight line-miles of data along three linesover a period of about 25-30 days.

“With that data we’ll complete our pre-liminary model of the site, incorporating

that with the data that we already have, andthat will help us move to the next phase ofthe program, which is the (resource) char-acterization phase,” Schutt said.

Conceptual engineeringThe joint venture has already commis-

sioned and obtained a conceptual engineer-ing and cost analysis for a UCG develop-ment at Stone Horn Ridge, with the analy-sis considering various options for the useof UCG-generated synthetic gas, Schuttsaid.

The geologic modeling indicates theexistence of about 300 million tons of coalin the Stone Horn Ridge site, a UCGresource equivalent to perhaps a little morethan 4.8 trillion cubic feet of natural gas,with potential gas production rates in therange of 20 billion to 90 billion cubic feetper year, Schutt said.

And CIRI thinks that UCG-fueled elec-tricity generation, for example, would provesignificantly cheaper than generation fromCook Inlet basin natural gas, Schutt said.

But, with the project being at the leadingedge of UCG technology deployment, CIRIis taking its time, being “pretty deliberateand responsible” and talking to stakeholdersas the project moves forward, Schutt said.

“We’re pretty excited about the projectand its potential, but we do also realize thatwe’ve got a lot of work in front of us,” hesaid.

—ALAN BAILEY

continued from page 1

CIRI COAL

Contact Eric Lidji at ericlidji@mac.com

Cook Inlet Region Inc. wants to develop an underground coal gasification plant at StoneHorn Ridge on the west side of the Cook Inlet.

CO

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IN

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REG

ION

IN

C.

Contact Alan Bailey at abailey@petroleumnews.com

PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011 19

In the year since Great Bear firstentered Alaska by winning approximately500,000 acres in the state’s Oct. 27, 2010,North Slope areawide lease sale, Duncansaid his company has “made a hugeamount of progress” and is “workingvery, very closely” with its “industry part-ners, the service industry, the state agen-cies, the North Slope villages … to findgood solutions to the challenges that weface in developing shale resources for thestate of Alaska.”

Lots and lots of brackish waterBut none of those challenges, he said

in the course of his presentation, aremajor impediments, including water forfracking.

Unlike North Dakota and Texas, GreatBear’s acreage south of the giant PrudhoeBay and Kuparuk River oil fields, has anear limitless supply of subsurface,brackish water sources, between 2,000and 5,000 feet deep, that are “very likelyideal for frack make up,” Duncan said.

“We thought this going in but it hasbeen confirmed repeatedly in the last sev-eral months of work. … That’s a reallygood thing for Alaska,” he said.

Water makes up about 98 percent ofthe solution needed for the hydraulic frac-turing that Great Bear will have to do inorder to coax the hydrocarbons fromAlaska’s three world class shale sourcerocks beneath its acreage.

Current water cycling technologiesallow Great Bear to recover about 90 per-cent of the used water for reuse in frack-ing operations. The remaining water,Duncan said, “will be disposed of ineither existing disposal facilities in northAlaska or in our own infield, custom-built, facilities as our program grows andthose facilities become … necessary.”

This time next year“We have worked very, very hard in

the last year to build a testing programthat will allow us to have … a very tech-nically based, hard science discussionabout what this play means for Alaska,”about a year from now, he said.

Assuming the partners are successfulwith their proof of concept programs, thistime next year Duncan hopes Great Bearwill be “moving toward constructing apilot development pad … built with amodular processing unit on it that is capa-ble of processing the produced fluids toTAPS-spec oil.”

“We want to deliver oil to Alyeskathat’s ready to go in the pipeline,” he said,explaining the pilot development oil willbe trucked from the gravel pad to PumpStation 1.

Great Bear intends to produce from thedevelopment pad for one year in order tocreate “a collection of well productioncurves for North Slope shale oil develop-ment.”

Great Bear’s overhead slide titled,“Plan of Development, A StagedDevelopment Approach,” shows the pilotgravel pad having up to 24 wells with asmany as two production modules that canhandle 5,000 to 10,000 barrels of liquidsper day each, but he thinks six wells andone 5,000 barrel a day module will likelybe sufficient.

Sen. Tom Wagoner asked whetherDuncan expected to produce 5,000 bar-rels a day from the six wells.

Duncan said he would be able providea definitive answer after the proof of con-cept test wells are drilled, fracked andtested. Once Great Bear has all its permitsand authorizations in place — and hassecured a drilling rig — that program

could get under way in November orDecember, state regulators said.

However, Duncan does not expect pro-duction from the wells on the develop-ment pad to be significant.

“A certain amount of water productionis expected; a certain amount of gas pro-duction is expected,” he said. “Gas pro-duction’s good. Gas provides us reservoirenergy to help lift oil to surface. … All ofour rigs, all of our pumps, all of ourequipment are AC. We will have a hugepower demand from our infield opera-tions. It’s our expectation that much of thegas production will be for infield use. Inour plan … we are also budgeting for agas line to Prudhoe. If we have excess gasproduction we have no intention of vent-ing it, we have no intention of flaring it.Our gas will be taken to Prudhoe or, justas with water disposal, we will build asubsurface storage facility on our ownacreage. We have the capability of doingthat. Our objective is not to waste themolecules. Not one Btu, actually, will bethrown away. That’s our objective.”

Two years from now“Roughly two years from now,”

Duncan hopes to be “holding up” a graphthat shows a tight curve and saying,

“Here’s the flush production in the firstfew months, here’s what the decline curvelooks like after a year of production.”

Wells that produce liquids and gasfrom source rocks such as shale tend toproduce at relatively strong rates for thefirst few months and then drop off fairlydrastically, leveling out to produce at alower, but steady, rate for many years.

Having a year of production underGreat Bear’s belt, “allows all of us tomake a very educated judgment on howaggressively we pursue full field develop-ment,” Duncan said.

Next, full field development, 200wells per year

“As that decline curve, or as that tightcurve develops, we will be in constantcommunication with you,” he told law-makers. “You have to be as informed aswe are about what is happening becausethat really qualifies and allows us all tojudge how aggressively we want to pur-sue the full field development that we allhope for, because that’s a really goodthing for the state. But that’s two yearsout. One year from now we’ll be going topilot development; a year after that we’llhave tight curves in front of us and we’llbe sanctioning then, hopefully, corridor

development — that’s the 200 hundredwells a year.”

In talking to legislators about the eightslides that were part of his presentation,Duncan referred them to “Plan ofDevelopment, Phased DevelopmentApproach — 3 Main Phases,” which pre-sumes success in the company’s initialtesting program.

The slide “captures both the concept ofa pilot pad (and) … illustrates what wesee as a corridor, full field, developmentprogram,” involving eight pads and 192wells per year, he said.

Duncan cautioned that the corridorillustration was schematic.

“It’s not necessarily going to be north-south continuous. It may have a series ofeast-west or northwest-southeast or north-east-southwest spurs to it. The idea is,once we hit the full field developmentprogram we’ll have a large activity setknitted together with infrastructure. Ourcurrent plan, our proposal, calls for a ded-icated Great Bear pipeline system thatconnects all of our corridor developmentwells to the north, to TAPS.”

Central processing facilityAt some point Great Bear will move

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from modular processing units on indi-vidual pads to a central processing facili-ty, or CPF.

Will it be shared with other operators?“We presume that if others move at the

same pace that we’re moving, and devel-op oil and gas in the general area of ourcentral processing facility that we’re pro-posing, simultaneously than certainly adiscussion can be had about shared facil-ities,” Duncan said after posing the ques-tion himself.

“Currently we’re planning central pro-cessing facilities specifically for our pro-duction, but we’re not opposed to sharedfacilities. There’s no one else doing thisright now, so for the sake of planning it’sour central processing facility.”

Where will the workers come from?When asked where the work force to

execute Great Bear’s plans would comefrom, Duncan said, “The short answer is,the work force doesn’t exist today inAlaska,” but he is hoping that by workingwith local educators, that will change.

“Early on we visited the FairbanksPipeline Training Center, specifically totalk to the staff there about the sheer scaleof what we were embarking on — thesheer number of jobs that we expected tobe required. Imagine the hundreds ofmiles of gathering lines, the pipefitters,welders, truck drivers, skilled labor of allkind that will be employed here.”

And Duncan is quick to point out,source rock exploitation doesn’t involvejust a temporary increase in jobs.

“In full field development, this pro-gram will generate, long-term, thousandsof jobs. Not a spike. There’s constantupward pressure on activity. … There’sconstant, long-term, accretive investment.That backdrop of activity requires atremendous number of skilled people, andfor that matter a tremendous number ofgrocery store clerks and teachers and allthe rest,” he said.

The “sheer life span” of what GreatBear is proposing, “40-years plus. It’s agenerational thing. It’s not flipping a lightswitch to fix this. It’s starting now, stayingreally focused, building and having itaccretive. Two hundred this year, 500next year, a 1,000 the next year, 2,000new staff trained the following year,”Duncan said.

Duncan is also looking at tapping peo-ple who are exiting the military.

Less than one month’s wellsSo what about those 200 wells Great

Bear expects to drill every year, starting in2014?

Duncan said the reaction he gets to thatnumber from some Alaskans is “almostrecoil,” because it’s so many more wellsthan are drilled annually in the entire state.

What’s more, Great Bear’s earlier pre-sentations showed that level of drillingwould continue for 45 years.

How does 200 wells compare to thenumber of wells drilled in the Bakken andEagle Ford shale plays?

According to Duncan, more than 200wells are drilled each month in bothSouth Texas’ Eagle Ford and NorthDakota’s Bakken. �

20 PETROLEUM NEWS • WEEK OF NOVEMBER 6, 2011

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Contact Kay Cashman at publisher@petroleumnews.com

According to Duncan, more than200 wells are drilled each monthin both South Texas’ Eagle Ford

and North Dakota’s Bakken.