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

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Vol. 18, No. 40 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of October 6, 2013 • $2.50

page4

Q&A: Herron, Bethel Democratsays Arctic policy voice important

Oil & Gas DirectoryCovering Arctic oil and gas operations

and the logistics, construction and service firms that support them

A biannual supplement

Vol. 18, No.2October 2013

ArcticArcticLatest Arctic Directory released

Hilcorp: 2nd oil exploration well,Frances 1, planned for Ninilchik

Hilcorp is about to drill a second exploration well, theFrances 1, in the Ninilchik unit on the west coast of Alaska’sKenai Peninsula, Hilcorp spokeswoman Lori Nelson toldPetroleum News in a Sept. 30 email.

Earlier this year the company applied to change its plan ofoperations for the Susan Dionne pad in the unit to allow thedrilling of a 12,000-foot-deep oil exploration well from thepad. The application said that the company might drill a sec-ond well if that first well proved successful.

BP seeks in-state TAPS hike; wouldclose gap with other line owners

Every year, for six years, the owners of the trans-Alaska oilpipeline have separately sought increases to rates they charge toship North Slope crude to markets in Alaska.

All the owners except BP, that is.While the other owners have been incrementally bumping up

their rates year after year since 2008, the operator of Prudhoe Bayand three other producing North Slope units has maintained thein-state shipping rate established after a major regulatory rulingin 2002.

BP’s Liberty islandRegulators reveal company’s thinking on how to proceed with stalled Alaska project

By WESLEY LOYFor Petroleum News

In June 2012, BP Exploration (Alaska) Inc.made the startling announcement that it was

dropping its ambitious plan to develop the offshoreLiberty field using ultra extended-reach drillingfrom shore.

In the 15 months since, it has been less thanclear what alternate approach, if any, BP mighttake on Liberty.

But now, the company’s direction is becomingevident.

On the U.S. Bureau of Ocean EnergyManagement website devoted to Liberty, this state-ment has appeared:

“BP Exploration (Alaska) is now proposing a

stand-alone drilling and production processingisland as the safest and most environmentallyresponsible course of development for the LibertyProspect.”

Suspension of production grantedDawn Patience, spokeswoman for BP Alaska,

told Petroleum News on Oct. 2 she had no reason

In a Nov. 20, 2012, letter to the BSEE, thecompany said recovery from the Libertyleases could be as much as 15 percenthigher using “development concepts”

other than ultra extended-reach drilling.

see LIBERTY’S FATE page 24

A license for AhtnaNative corporation wants to explore for gas in state land near Glennallen

By ALAN BAILEYPetroleum News

The director of Alaska’s Division of Oil and Gashas published a finding, saying that it is issuing

an oil and gas exploration license to Ahtna Inc., theNative regional corporation for the Copper Riverregion. The license, called the Tolsona ExplorationLicense, encompasses about 72 square miles of stateland west of Glennallen in the Copper River basin.The finding, published on Sept. 30, says that, in eval-uating the license application, the state studied envi-ronmental and other factors in a 950-square-mile areastraddling the eastern end of the Glenn Highway.

State exploration licenses provide a means ofaccess to state lands for oil and gas exploration in

regions outside the state’s major oil and gasprovinces. Any requests for reconsideration ofAhtna’s license must be submitted to the divisionwithin 20 days of the issuance notice.

Address energy costsMichelle Anderson, president of Ahtna, told

Petroleum News in an Oct. 1 email that the Native

“Exploration activities will begin late2013 with a minimum investment of$415,000 (US) over the next 1 to 2

years.” —Michelle Anderson, president of Ahtna

see AHTNA LICENSE page 19

Umiat horizontal plannedLinc’s 1-to-2 well program smaller, but can start more quickly than deferred plan

By ERIC LIDJIFor Petroleum News

L inc Energy Ltd. could drill as many as twowells at the Umiat prospect this winter to test

horizontal drilling techniques at the oil field in thefoothills of the Brooks Range.

The Australian independent plans to drill andflow test the Umiat No. 23H this coming winter.Time permitting, Linc might also drill an UmiatNo. 24H well this winter.

The program picks up where Linc left off earli-er this year at Umiat, but not entirely.

Linc had originally planned to drill betweenfour and six wells at Umiat this past winter, butweather-related delays forced the company todefer all but one — the Umiat No. 18 vertical well.

By cold-stacking the Kuukpik No. 5 rig at the per-manent Seabee drilling pad, Linc had intended toget a head start on completing the program thiscoming winter.

The work Linc deferred this past winter includ-

According to Ryder Scott, the 154.5million barrels of oil equivalent of P2

reserves at Umiat now has a net presentvalue (at 10 percent return) of $2.465

billion, up 65 percent from a net presentvalue of $1.496 billion estimated before

the changes to the tax code.

see UMIAT DRILLING page 22

see FRANCES WELL page 21

see TAPS HIKE page 21

Canadian Beaufort plans; JV inregulatory phase for 2020 drilling

An Imperial Oil partnership with ExxonMobil and BP Canadahas entered the formal regulatory phase that could see an initialexploration well start drilling in the Canadian sector of theBeaufort Sea in summer 2020.

But even if a commercial-size strike was made the joint ven-ture has no thoughts on how development would proceed.

Imperial spokesman Pius Rolheiser told Petroleum News thecompanies view the area as “potentially prospective for explo-ration, but it has a high degree of exploration uncertainty and has

see BEAUFORT JV page 19

2 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

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

LAND & LEASING

FINANCE & ECONOMYPIPELINES & DOWNSTREAM

EXPLORATION & PRODUCTION

ENVIRONMENT & SAFETY

ALTERNATIVE ENERGY

6 ANS crude production up 19% from August

North Slope production up on completion of summermaintenance; August Cook Inlet production, led by Trading Bay, up 8% over July

14 Alaska searches for energy alternatives

Yakutat community aims to generate electric power from waves; AEA awarded federal grant to develop rural wood energy projects

12 Utilities review gas supply situation

New Cook Inlet supplies have brought welcome reliefbut future remains uncertain until sufficient new reserves established

NATURAL GAS

contents

13 AOGCC sets 2014 CO 360 hearing date

15 BSEE extends comment period for safety rule

17 Obama signs bill with legacy well money

11 Norway methane hydrate research center starts up

11 Canada, Japan seek LNG fit

13 Arrest made on pipeline graffiti threats7 Bristol Bay Native Corp. buying Peak

4 Herron: Alaska needs Arctic policy voice

Bethel Democrat has key seat on Arctic PolicyCommission while advocating for state to have crucial role in advancing its interests

7 Sullivan confirms unitization policy

Says DNR will only approve an exploration unit if applicant has demonstrated the existence of a potential hydrocarbon accumulation

8 BLM sets NPR-A bid opening for Nov. 6

Agency offers 408 tracts covering 4.5 million acres for lease in a broad area east to west through the central part of the reserve

5 LNG dangles as big gas prize

Producers in US, Canada, count heavily on LNG exportsto support operations; little hope for Alberta, where gas in downward spiral

GOVERNMENT

INTERNATIONAL

10 10,000 walrus come ashore in NW Alaska

13 Forget XL — oil sands will grow

14 Potential ‘game changer’ for Canada

16 Update from Conoco on Alaska investments

Hilcorp: 2nd oil exploration well,Frances 1, planned for Ninilchik

BP seeks in-state TAPS hike; wouldclose gap with other line owners

Canadian Beaufort plans; JV in regulatory phase for 2020 drilling

BP’s Liberty island

Regulators reveal company’s thinking on how to proceed with stalled Alaska project

A license for Ahtna

Native corporation wants to explore for gas in state land near Glennallen

Umiat horizontal planned

Linc’s 1-to-2 well program smaller, but can start more quickly than deferred plan

ON THE COVER

SIDEBAR, Page 12: RCA OKs Hilcorp gas contract with CEA

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay L3-31, workover BPDreco 1000 UE 16 (SCR/TD) Prudhoe Bay DS 04-03, workover BPDreco D2000 Uebd 19 (SCR/TD) Alpine CD4-291 ConocoPhillipsAC Mobile 25 Prudhoe Bay Y-13A BPOIME 2000 141 (SCR/TD) Kuparuk 1C-150 ConocoPhillips

Kuukpik 5 Rigged up on Umiat Disp#1 Linc Energy Operations Inc.

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

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site Z-08B BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site F-09C BPIdeco 900 3 (SCR/TD) Kuparuk Well 3K-23 ConocoPhillips

Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay DS 18 BPNOV ADS-10SD 273 Prudhoe Bay DS W-59 BP

North Slope - OffshoreBPTop Drive, supersized Liberty rig Inactive BP

Doyon DrillingSky top Brewster NE-12 15 (SCR/TD) Spy Island SP08-N7 ENI

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

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

Cook Inlet Basin – Onshore

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

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

NordAq Energy’s Tiger Eye Central Well NordAq EnergyAurora Well ServicesFranks 300 Srs. Explorer III AWS 1 NCU 2, workover Aurora Gas

Doyon DrillingTSM 7000 Arctic Fox #1 North Kenai, stacked Contracted to ConocoPhillips

Winter of 2013/2014

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

Cook Inlet Basin – Offshore

XTO EnergyNational 110 C (TD) Idle XTO

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

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

Hilcorp Alaska LLC (Kuukpik Drilling, management contract)Monopod A-32, workover Hilcorp Alaska LLC

Mackenzie Rig StatusCanadian Beaufort Sea

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

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

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of October 3, 2013.

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts*Sept. 27 Sept. 20 Year Ago

US 1,744 1,761 1,848Canada 390 388 359Gulf 62 63 48

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

By STEVE QUINNFor Petroleum News

R ep. Bob Herron hasn’t sat in hisoffice for too long during the

Legislature’s interim. He’s been to Barrowand Unalaska for work as co-chair with theArctic Policy Commission. He sharesthese duties with Sen. Lesil McGuire, bothof whom are also Arctic policy co-chairsrepresenting the Pacific NorthwestEconomic Region group.

Herron steadfastly believes Arctic poli-cy and Alaska having a voice at an interna-tional level should be a statewide priority.

Herron is a Bethel Democrat whoaligns himself with the State House’sRepublican caucus, but that doesn’t meanhe completely agrees with some of theheavier hitting legislation. Herron support-ed a change to the state’s oil tax system,

but not the new lawushered in calledSenate Bill 21.

Herron discussedboth issues plus afew others withPetroleum News.

Petroleum News:What do you see asthe value of the com-mission to the state?

Herron: Arctic policy, Arctic issues —pardon the pun — is hot right now. I’m nottrying to make light of it. We live in theArctic. We live in Alaska. Under the defi-nition of the Arctic by U.S. law, almosthalf of Alaska is within those boundaries,including the Bering Sea, which is veryimportant to many people not only aroundthe world, but specifically Alaskans, espe-

cially along the Yukon River and theKuskokwim because both of those majortributaries flow into the Bering Sea and theBering Sea — quote-unquote — feedsAlaska in so many different ways.

So should we be involved in Arctic pol-icy? You bet we should be. Should we bedefending and protecting our own inter-ests? Should we be making sure that Arcticpolicies at the international level, nationallevel and sub-national level are in our bestinterests? You bet. The only reason theU.S. is an Arctic nation is because ofAlaska. So Alaskans should be, must beand will be a part of that debate.

Petroleum News: Whathave you learned so farsince the commission hasbeen formed?

Herron: A lot of peopleare looking at Alaska and doing their stud-ies and we don’t even know what they aredoing. We need to be out there telling peo-ple that we are not just a bunch of fron-tiersmen or indigenous people who havebeen here a long time. We’re not just herebecause it’s fun and cool; it’s our lives.The executive branch — the Parnelladministration — has got to do its job. TheAlaska Legislature, when it comes toArctic policy, has to have an importantrole in that — maybe in a parallel trackwith the administration.

We are going to make policy decisionsthat affect Alaskans. We are going to makebudget decisions that affect Alaskans, yetshould we be sensitive to international andnational Arctic policy decisions? I believewe should. One of the things the commis-sion is learning is that it’s a very largeproject; it’s a very large issue; it’s dynam-ic; it’s ever changing. There is a very largeinterest by the public sector, the privatesector and by the people who live here.

There are a lot of studies going on andthere are a lot of studies under way thatpeople don’t know are taking place. Thereare hundreds of silos of research projectsthat don’t know about one another. We arelearning that a lot of those projects are pro-prietary or the people doing the researchthink they are proprietary. Alaskans shouldbe concerned about what is being studiedand how can Alaskans benefit from it.

Petroleum News: OK, let’s go with that.How can Alaska benefit from an Arcticpolicy?

Heron: There are two kinds of people Ilike to characterize and they are not bad

people. The first is you’re in some largecity in the Lower 48 who will never, everget to Alaska. They want this place that’spristine and untouched. They don’t recog-nize there are people who live up here andhave families with a whole infrastructurethat’s been going on for a long time. Sosomehow these people want to take asnapshot and that’s the way they wantAlaska to be forever.

Then there is the other side, people whohave been to Alaska but would never livehere. They want to make rules about howwe should live up here. They want to putus in a snow globe. They want us to be in

this perfect zoo, this littleecosystem that’s perfect.They want us to be this nicelittle people who live in nicelittle igloos with subsistencelifestyle and pat us on the

head and say everything is perfect. Theywant to make decisions for us.

So the commission has decided that weare not going to be part of those two sce-narios in a negative way. We are going tobe proactive. We are going to be partnerswith our federal counterparts. We want tobe part of a decision process where we arenot merely stakeholders. We are sovereigncitizens of this land. When you are a sov-ereign citizen, you don’t come begging toyour partners with whom you are going toset national and state policy. We are goingto be equal partners. That’s what Alaskaneeds to demand of this Arctic policydebate.

Petroleum News: You folks had a meet-ing in Unalaska recently. Do you see thatas a particular hub for Arctic oil produc-tion and exploration?

Herron: I didn’t realize this until wesaw a presentation and that’s duringCaptain Cook’s voyages around the northPacific, he limped into Unalaska with abroken rudder. The history in Unalaska forthe last couple hundred years is remark-able. The most recent history comes duringWorld War II and now the fishing industry.

Just the strategic location of Unalaskaand Dutch Harbor is tremendous. Unalaskais considered part of the Arctic. It has adeepwater port that is strategically located.It’s year-round. It will play an importantrole as will other ports like Nome, whichis not as large as far as capacity or PortClarence below the Bering Straits. Futureinfrastructure we build on north of the

� G O V E R N M E N T

Herron: Alaska needs Arctic policy voiceBethel Democrat has key seat on Arctic Policy Commission while advocating for state to have crucial role in advancing its interests

4 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

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see HERRON Q&A page 18

By GARY PARKFor Petroleum News

While gas producers in the UnitedStates and Canada battle for a

diminishing share of the “home” pie,hopes for a resurgent market increasinglyfocus on LNG exports.

For now, though, it’s a much grimmermood in Canada, which has seen theshare of its production destined for theU.S. shrink from two-thirds to one-half ofoutput in the last five years.

Consider Alberta, still the mainstaygas region, where royalties have plungedto an estimated C$965 million this fiscalyear from C$6 billion in 2006-07, withfield activity falling to about 1,000 wellsthis year from 16,000 during the bonanzayears.

Production in the province hasdeclined to about 10 billion cubic feet aday this year from 14 bcf a day in 2006,while the industry has seen one of its pre-viously key markets in the U.S. Northeastevaporate as the Marcellus shale hasraced to almost 8 bcf a day from 2 bcf aday in 2005 and, according to PeterHoward, president of the CanadianEnergy Research Institute, could be des-tined for 23 bcf a day.

B.C. immediate beneficiaryEven if LNG export projects do get off

the ground, the immediate beneficiarywill be British Columbia, which holds thelargest untapped resources in its north-eastern corner and the best access to liq-uefaction and tanker terminals on thePacific Coast.

Howard doubts LNG exporters fromCanada will include Alberta production intheir mix any time soon because of theirfocus on the more cost-effective Montneyformation in British Columbia.

Those looking for a shred of hopewere offered a morsel by Mike Ekelund,assistant deputy minister at AlbertaEnergy, when he spoke to a LNG confer-ence in Calgary.

He said that based on years of cooper-ation between Alberta and BritishColumbia to promote the natural gasindustry there should be opportunities forboth provinces to supply internationalmarkets through LNG terminals.

Ekelund said the two provinces havefor decades shared gas pipeline networksand he is counting on working withBritish Columbia “to expand the networkto provide buyers with access to worldclass resources.”

But the chances of British Columbiagiving up much, or any, of its dream tocash in on LNG is remote.

Howard acknowledged the reality.“There are no easy answers for Albertaproducers,” he told the Financial Post.“The next several years are going to bechallenging.”

Ziff sees B.C. in leadThe importance to North American

producers of seizing a role in the LNGindustry is reflected in a new forecast byCalgary-based Ziff Energy, now a divi-sion of Solomon Associates, which pre-dicts British Columbia has the bestchance of leading a production recoveryin Canada.

If export projects from the PacificCoast are up and running by 2018 theywill set the stage for British Columbia gas

production of more than 4 bcf per day by2020, more than a four-fold increase fromcurrent output, the study said.

Otherwise Alberta will be left to relyon its oil sands operations and a shift togas-fired power plants which the studypredicted should see demand rise tobetween 5 bcf and 6 bcf a day in 2020,compared with present levels of 3.4 bcfper day.

Bill Gwozd, senior vice president ofgas services, forecasts 90 percent ofAlberta’s growth will come from the oilsands.

Ontario, by far Canada’s most popu-lous province at 13 million people, isforecast to top 3 bcf a day, an increase of500 million cubic feet per day as powergeneration shifts to gas from coal.

Collective revenues tumbleBut Peter Tertzakian, chief energy

economist at ARC Financial Corp., alsoputs the numbers into a more rigorousperspective, noting that Alberta producerscollective revenues have tumbled C$30billion from their 2005 peak and produc-tion has nosedived 30 percent as U.S.shale plays have claimed market sharefrom Western Canada, led by theMarcellus which now accounts for 13percent of U.S. output.

Tertzakian said Marcellus expansion is“unlikely to slow, with high quality rocksmaking the cost of the gas relatively low”and the play’s close access to major con-suming regions.

He said the best chance of recovery forWestern Canadian producers is accessingAsian markets with LNG, noting thatBritish Columbia gas operations are

“ramping up output in anticipation.”Gwozd conceded that cheaper types of

coal are also causing a shift away fromgas by power producers and said thatcould be a short-term issue until govern-ments start tackling climate-change con-cerns.

He suggested there could also be goodnews on the horizon, with the Ziff reportpredicting “very strong” gas demand inCanada and the Southwest region of theU.S., “moderate” gains in the interiorWest and “minor” gains in the Midwestand Northeast, while the Southeast andPacific Coast remain flat.

Backing off predictionsFor now, many forecasters are having

to back off recent predictions that NorthAmerican demand would rise to 30 tril-lion cubic feet a year, or about 82 bcf aday. Current consumption is in the rangeof 72 bcf-80 bcf a day, but SolomonAssociates is counting on 95 bcf a day by2020, with the 30 tcf-a-year mark beingreached in 2016 or 2017.

Gwozd said world LNG demand forgas should double to 60 bcf a day by

2020.Calgary-based Peters & Co. said that

although 20 percent fewer rigs aredrilling for gas than last year, averageU.S. production for 2013 is likely toremain unchanged at 66 bcf a day, edgingup to 67.4 bcf a day in 2014.

“Production from shale gas drillingcontinues to drive supply growth in theU.S. with the Marcellus and associatedgas from oil/liquids plays — includingthe Bakken, Eagle Ford, Utica and partsof the Permian — offsetting declines thathave occurred in all other areas over thepast year,” the investment dealer said.

Peters said U.S. shale plays accountedfor about 19 bcf a day, or 32 percent ofU.S. production, in 2010 and, by the endof 2014, should be at 50 percent or 34 bcfa day, further stiffening competition forWestern Canadian gas.

Bentek is counting on U.S. productionrising by about 23 percent over the nextfive years to 80 bcf a day, driven by moreefficient shale gas drilling, projectingyear-end 2013 production of 65 bcf a day.

� N A T U R A L G A S

LNG dangles as big gas prizeProducers in US, Canada, count heavily on LNG exports to support operations; little hope for Alberta, where gas in downward spiral

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 5

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Consider Alberta, still themainstay gas region, whereroyalties have plunged to an

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during the bonanza years.

see THE LNG PRIZE page 6

By KRISTEN NELSONPetroleum News

A laska North Slope crude oil produc-tion was up in September following

the August completion of scheduled sum-mer maintenance on the trans-Alaska oilpipeline, averaging 523,554 barrels perday, a 19.2 increase over the August aver-age of 439,152 bpd.

August figures for Cook Inlet, the lat-est available, show the Southcentral basinaveraged 16,247 bpd, up 7.6 percent fromJuly, with the largest increase, 61.9 per-cent, at Trading Bay.

On the North Slope, all fields exceptEndicott showed month-over-month pro-duction increases in September.

The largest per-barrel increase was atthe BP Exploration (Alaska)-operatedPrudhoe Bay field, which averaged291,150 bpd in September, up 52,653bpd, 22.1 percent, from an August aver-age of 238,507 bpd.

Prudhoe Bay production includes vol-umes from western Prudhoe satellites(Aurora, Borealis, Midnight Sun, Orionand Polaris) as well as from the BP-oper-ated Northstar and Milne Point fields.

Production figures for September arefrom the Alaska Department ofRevenue’s Tax Division which reportsANS crude oil production consolidatedby major production centers and providesdaily production and monthly averages.Detailed data, including Cook Inlet andindividual North Slope fields and pools,

is reported by the Alaska Oil and GasConservation Commission on a month-delay basis.

Kuparuk biggest percent increaseThe ConocoPhillips Alaska-operated

Kuparuk River field had the largestmonth-over-month percentage increase,averaging 134,525 bpd in September, up22.5 percent, 24,741 bpd, from an Augustaverage of 109,784 bpd. Kuparuk vol-umes include satellite production fromMeltwater, Tabasco, Tarn and West Sak,as well as production from the Eni-oper-ated Nikaitchuq field and the PioneerNatural Resources Alaska-operatedOooguruk field.

August AOGCC figures forNikaitchuq show an average of 14,074bpd, up 2,012 bpd, 16.7 percent, from aJuly average of 12,062 bpd. Ooogurukaveraged 8,266 bpd in August, commis-sion figures show, up 790 bpd, 10.6 per-cent, from a July average of 7,476 bpd.Oooguruk produces from three forma-tions — Kuparuk, Nuiqsut and Torok —with Kuparuk and Torok production

roughly flat, month-over-month, andNuiqsut production, which accounts forthe bulk of Oooguruk volume, up 13.7percent, to 7,030 bpd in August from6,202 bpd in July.

BP-operated Lisburne, which includesPoint McIntyre and Niakuk production,averaged 29,984 bpd in September, up20.3 percent, 5,049 bpd, from an Augustaverage of 24,935 bpd.

The ConocoPhillips-operated Alpinefield averaged 61,188 bpd in September,up 8.5 percent, 4,800 bpd, from anAugust average of 56,388 bpd. Alpineproduction includes volumes from threesatellites: Fiord, Nanuq and Qannik.AOGCC data for August shows 64 per-cent of Alpine production coming fromthe main field in that month, with Fiordmaking up 31 percent, followed byQannik at 3 percent and Nanuq at rough-ly 2 percent.

The BP-operated Endicott field wasthe only one on the North Slope to showa decline in production from August toSeptember. The field averaged 6,707 bpdin September, down 29.7 percent, 2,831bpd, from an August average of 9,538bpd. Endicott production includes theSavant-operated Badami field, whichAOGCC data shows averaged 1,243 bpdin August, down 7 percent, 97 bpd, froman August average of 1,340 bpd.

Climbing well above 15,000 bpdIn July, Cook Inlet oil production

broke through the 15,000 bpd barrier; in

August it broke through 16,000, averag-ing 16,247 bpd, up 7.6 percent from aJuly average of 15,099 bpd.

The Hilcorp-operated Trading Bayfield had the largest month-over-monthincrease, averaging 2,208 bpd in August,up 61.9 percent from a July average of1,364 bpd. Hilcorp has been reworkingwells it acquired in January 2012 when ittook over Chevron’s Cook Inlet assets,increasing production in the basin.

The Hilcorp-operated Swanson Riverfield averaged 2,450 bpd in August, up13.2 percent from a July average of 2,165bpd.

Cook Inlet Energy, which has alsobeen reworking existing fields it tookover after Pacific Energy went into bank-ruptcy in 2009, produced 1,690 bpd fromRedoubt Shoal in August, up 12.3 percentfrom a July average of 1,505 bpd.

Hilcorp averaged 4,471 bpd in Augustat McArthur River, up 3.7 percent from aJuly average of 4,311 bpd.

Other Cook Inlet fields had month-over-month declines.

Cook Inlet Energy’s West McArthurRiver field averaged 588 bpd in August,down 16 percent from a July volume of700 bpd.

Middle Ground Shoal, operated byExxonMobil subsidiary XTO, averaged2,467 bpd in August, down 5.5 percentfrom a July average of 2,610 bpd.

Hilcorp’s Granite Point averaged2,221 bpd in August, down 3 percentfrom a July average of 2,290 bpd, andHilcorp’s Beaver Creek averaged 152 bpdin August, down 1.3 percent from a Julyaverage of 154 bpd.

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

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

ANS crude production up 19% from AugustNorth Slope production up on completion of summer maintenance; August Cook Inlet production, led by Trading Bay, up 8% over July

6 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

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US LNG exportsJack Weixel, director of energy analy-

sis at Bentek, told a Pittsburgh confer-ence the forecast is based on a steady risein gas use for manufacturing and powergeneration, while counting on LNGexports starting in 2015 or 2016.

Based on those assumptions, he fore-cast gas prices will reach a 2018 averageof $4.09 per million British thermal unitscompared with the current $3.40, withmost U.S. producing basins seen as prof-itable at about $2 because of associatedhydrocarbons, such as crude oil and gasliquids.

At $4, Weixel said all U.S. producingbasins would be profitable.

He said U.S. LNG exports should con-sume 8.8 bcf a day by 2023 based onsigned memoranda of understandingbetween shippers and customers covering11.6 bcf a day.

Weixel doubted that LNG will havemuch impact on U.S. domestic gasprices, meaning the U.S. will “be the nextgreat natural gas exporter by the time weget to 2018 because we can afford to.”

Of the challenges facing gas, he saidthe chief threat could be posed by legisla-tion banning hydraulic fracturing. �

continued from page 5

THE LNG PRIZE

The ConocoPhillips Alaska-operated Kuparuk River field had

the largest month-over-monthpercentage increase, averaging134,525 bpd in September, up

22.5 percent, 24,741 bpd, from anAugust average of 109,784 bpd.

By ALAN BAILEYPetroleum News

Rumblings of discontent over theAlaska Division of Oil and Gas’

apparent reluctance to approve explorationunits surfaced in June, when executivesfrom several companies engaged in Alaskaoil exploration sent a letter to Dan Sullivan,commissioner of the Alaska Department ofNatural Resources, complaining aboutwhat the companies claimed to be the divi-sion’s infringement of state laws relating tooil and gas unitization. The Division of Oiland Gas is a division within theDepartment of Natural Resources.

The companies involved consist ofASRC Exploration, Brooks RangePetroleum Corp., Buccaneer Alaska, GreatBear Petroleum Operating LLC, LincEnergy, Royale Energy, Savant Alaska andUltraStar Exploration.

But in a letter dated Sept. 24 Sullivanresponded by affirming his department’sunitization policies and saying that theDivision of Oil and Gas approves explo-ration units in situations where the unitapplicant has sufficiently established thepresence of a “potential hydrocarbon accu-mulation” in the proposed unit.

Purpose of a unitA unit, a lease-management tool nor-

mally applied during the development of aproven oil or gas field, is a vehicle where-by several oil and gas leases with disparateleaseholders can be tied together as a singleentity with a single ownership structure, toavoid ownership complications and con-flicts when developing the field. However,Alaska laws also allow the formation of aunit over an exploration prospect, in a situ-ation where the prospect spans multipleleases — the idea is to encourage an effi-cient exploration and delineation drillingprogram in a situation where different leas-es are owned by different people.

But the formation of a unit also has theeffect of extending the terms of leasesbeyond their original expiry dates. So ques-tions can arise over whether an applicationto form a unit is intended to aggregate leaseownership or whether it is a tactic to deferlease termination.

And the state regulations for unit forma-tion give the commissioner of theDepartment of Natural Resources, or DNR,wiggle room to use discretion over unitiza-tion decisions: The commissioner mustevaluate whether unitization will “promoteconservation of all natural resources” and“promote the prevention of economic andphysical waste,” while considering factorssuch as the geologic characteristics of apotential hydrocarbon accumulation andthe unit applicant’s exploration and devel-opment plans, the regulations say.

In conflict with law?The companies objecting to current

exploration unit policies said that DNR hasbeen in conflict with state laws by onlyallowing unitization in situations wherethere is a proven hydrocarbon reservoir,rather than an unproven potential hydrocar-bon accumulation.

“Companies are not going to invest in

acquiring and exploring state acreage ifDNR refuses to unitize leases where geo-logic data demonstrates resource poten-tial,” the companies wrote in their letter toSullivan. “Further, the division’s new poli-cy has prevented multiple companies fromconducting exploration activity, includingdrilling wells.”

Current policies, only allowing unitiza-tion of acreage where development isimminent, result in development delays,wastage and unnecessary environmentalimpacts, the companies wrote.Furthermore, the Division of Oil and Gashas changed its unitization policies withoutconsulting with industry, the companiesargued.

10 units approvedIn his response Sullivan said that every

unitization application is unique and thatthe Division of Oil and Gas continues toapprove applications “on the basis of a suf-ficient showing of a potential hydrocarbonaccumulation.” Since January 2011 thedivision has received 15 applications ofwhich 10 were approved, with five of thoseapprovals being based on the existence ofpotential hydrocarbon accumulations,Sullivan wrote. The other five approvedapplications demonstrated both potentialaccumulations and the existence of hydro-carbon reservoirs, he wrote.

“DNR will continue to ensure that uniti-zation promotes conservation, preventswaste and maximizes the ultimate recoveryof oil and gas resources,” Sullivan wrote.“DNR will also continue to comply with itsunitization regulations and state law andfollow the established practice of formingunits over a reservoir or potential hydrocar-bon accumulation to develop the unitizedarea.” �

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 7

FINANCE & ECONOMYBristol Bay Native Corp. buying Peak

Bristol Bay Native Corp. has signed an agreement to acquire Peak OilfieldServices Company LLC from Nabors Alaska Services Corp. The companies saidSept. 30 that the acquisition is subject to customary closing conditions, with closingexpected in the fourth quarter.

Peak provides support for the oil and gas industry companies in four primary areas:the Alaska North Slope, Cook Inlet,Valdez and North Dakota.

BBNC is a diversified Alaska Nativecorporation, with subsidiaries operating inoilfield and industrial services, construc-tion, government services, petroleum dis-tribution and tourism.

Nabors Alaska Services Corp. is a sub-sidiary of Nabors Industries Ltd., whichowns and operates the world’s largest land-based drilling rig fleets and has one of thelargest completion services and workover and well services fleets in North America.

“This divestiture is consistent with our objectives to streamline our businesses andextract value from core operations while enhancing our financial flexibility,” TonyPetrello, Nabors Industries chairman, president and CEO, said in a statement.“Proceeds from this transaction and other third quarter asset sales will more than coverthe approximate $207 million premium paid to refinance $785 million of higher-costdebt through our recent tender offer which reduced annual interest expense by over$40 million,” he said.

“Peak’s commitment to providing the highest quality professional services fits wellwith BBNC’s long-term strategic objectives,” Jason Metrokin, president and CEO ofBBNC, said in a statement. “Peak’s business model enhances BBNC’s ability toaccomplish our core mission of enriching our shareholders’ Native way of life,” hesaid.

BBNC already has two companies providing services to the oil and gas industry:CCI Industrial Services and Kakivik Asset Management.

—PETROLEUM NEWS

Peak provides support for theoil and gas industry companies

in four primary areas: theAlaska North Slope, Cook Inlet,

Valdez and North Dakota.

� G O V E R N M E N T

Sullivan confirmsunitization policySays DNR will only approve an exploration unit if applicant hasdemonstrated the existence of a potential hydrocarbon accumulation

By ALAN BAILEYPetroleum News

The federal Bureau of LandManagement has set bid opening for

its 2013 National Petroleum Reserve-Alaska oil and gas lease sale for 1 p.m. onthe afternoon of Nov. 6. The State of Alaskapreviously announced bid opening for itsfall North Slope, Beaufort Sea and Foothillsoil and gas lease sales for the morning ofthat same day.

The same-day sales are aimed at allow-ing bidders to acquire acreage on both stateand federal lands simultaneously.

BLM said in a Sept. 30 Federal Registernotice that sealed bids are due Nov. 4, withthe Nov. 6 opening of the bids taking placeat the BLM offices in Anchorage.

President Obama has directed BLM tohold annual lease sales in NPR-A as part ofhis strategy for the development of U.S.energy resources, the agency said.

“The energy resources of the NationalPetroleum Reserve in Alaska are essential tomeeting our nation’s energy demands andwill enhance domestic energy productionand decrease dependency on foreign oilsources,” said Bud Cribley, BLM-Alaskastate director. “The November sale is in linewith the president’s direction to continue toexpand domestic energy production, safelyand responsibly.”

408 tractsThe agency is offering for lease 408

tracts covering a total area of about 4.5 mil-lion acres in a broad swath of land runningwest to east across the central and easternparts of the reserve. This represents a bit lessthan half the total acreage that might havebeen offered from land earmarked forpotential oil and gas exploration in BLM’sNPR-A activity plan.

During the summer BLM invited nomi-nations and comments on tracts that mightbe made available in the sale, to gaugeindustry interest and give conservationgroups and other stakeholders an opportuni-ty to provide input to the scope of the sale— the selection of tracts for inclusion in thesale was “based on evaluation of commentsreceived, natural resource information,resource potential, industry interest and sub-sistence values,” BLM said.

When recent NPR-A lease sales began in1999, BLM included in sales all land tractsavailable for lease within what were thenthe Northwest and Northeast planning areas

of the reserve. However, in 2011 the agencybegan asking for nominations for tractsprior to sales, to limit the sales to those tractsthat industry might want to bid on.

Activity planAnd following the issuance in February

of BLM’s new integrated activity plan forthe entire NPR-A, this year’s lease saleencompasses the whole of the reserve, albeitwith large chunks of the reserve deemed bythat plan to be out of bounds for oil and gasleasing. BLM said that the land on which oilexploration could take place likely holdsabout 72 percent of the undiscovered oil inNPR-A. But some people have expressedvehement concern that BLM’s planexcludes from leasing much of the northern

part of the reserve, a region that may behighly prospective for oil and gas.

The lease sale does include the handfulof remaining unleased tracts in the extremenortheast of NPR-A, an area that BLM cat-egorizes as “high potential” and whereConocoPhillips has been conducting anactive exploration program. ConocoPhillipsis in the process of developing what will bethe first operational oil field in NPR-A inwhat the company refers to as its CD-5 proj-ect, in the northeastern part of the high-potential area.

Land tracts in the high-potential area arehalf the size of tracts on offer elsewhere inthe reserve and require relatively high bidsof at least $25 per acre. The rental rate onhigh potential tracts is $5 per acre.Elsewhere in the reserve the minimum bidper tract is $5 per acre, with a rental rate of$3 per acres. And should oil be successfullydeveloped in any of the tracts, the royaltiesfrom oil production would be 16 2/3 percentin high-potential tracts and 16 1/2 percentelsewhere.

Detailed information on the sale is avail-able on the BLM Alaska website atwww.blm.gov/ak. �

� L A N D & L E A S I N G

BLM sets NPR-A bid opening for Nov. 6Agency offers 408 tracts covering 4.5 million acres for lease in a broad area east to west through the central part of the reserve

8 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

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NPR-A is locatedwithin Umiat Meridian

0 10 20 305Miles

August 16, 2013

National Petroleum Reserve in AlaskaSale Map

2013 Lease Sale Tracts

¯High/Low PotentialHL

Current Leases

Legend

Tracts offered for 2013

Tracts Available not offered for 2013Unavailable for Leasing

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On the webSee previous Petroleum News coverage:

“Nominations sought for NPR-A sale,” inJune 9, 2013, issue atwww.petroleumnews.com/pnads/350375313.shtml“Interior issues NPR-A plan decision,” inMarch 3, 2013, issue atwww.petroleumnews.com/pnads/577223115.shtml

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 9

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By DAN JOLINGAssociated Press

A n estimated 10,000 walrus unable tofind sea ice over shallow Arctic

Ocean water have come ashore onAlaska’s northwest coast.

Scientists with the National Oceanicand Atmospheric Administration on Sept.27 photographed walrus packed onto abeach on a barrier island near Point Lay,an Inupiat Eskimo village 300 milessouthwest of Barrow and 700 milesnorthwest of Anchorage.

The walrus have been coming to shoresince mid-September. The large herd wasspotted during NOAA’s annual arcticmarine mammal aerial survey, an effortconducted with the Bureau of OceanEnergy Management, the agency thatconducts offshore lease sales.

An estimated 2,000 to 4,000 walruswere photographed at the site Sept. 12.The U.S. Fish and Wildlife Service, theagency that manages walrus, immediately

took steps to prevent a stampede amongthe animals packed shoulder to shoulderon the rocky coastline. The agency workswith villages to keep people and airplanesa safe distance from herds.

Young animals are especially vulnera-ble to stampedes triggered by a polarbear, a human hunter or a low-flying air-

plane. The carcasses of more than 130mostly young walruses were countedafter a stampede in September 2009 atAlaska’s Icy Cape.

The gathering of walrus on shore is aphenomenon that has accompanied theloss of summer sea ice as the climate haswarmed.

Winter in Bering SeaPacific walrus spend winters in the

Bering Sea. Females give birth on sea iceand use ice as a diving platform to reachsnails, clams and worms on the shallowcontinental shelf.

As temperatures warm in summer, theedge of the sea ice recedes north. Femalesand their young ride the edge of the seaice into the Chukchi Sea. However, inrecent years, sea ice has receded northbeyond continental shelf waters and intoArctic Ocean water 10,000 feet deep ormore where walrus cannot dive to thebottom.

Walrus in large numbers were firstspotted on the U.S. side of the ChukchiSea in 2007. They returned in 2009, andin 2011, scientists estimated 30,000 wal-ruses along one kilometer of beach nearPoint Lay.

Remnant ice kept walrus offshore in2008 and again last year.

The goal of the marine mammals sur-vey is to record the abundance of bow-head, gray, minke, fin and beluga whalesplus other marine mammals in areas ofpotential oil and natural gas development,said NOAA Fisheries marine mammalscientist Megan Ferguson in anannouncement.

“In addition to photographing the wal-rus haulout area, NOAA scientists docu-mented more bowhead whales, includingcalves and feeding adults in the BeaufortSea this summer compared to 2012,” saidFerguson. “We are also seeing more graywhale calves in the Chukchi Sea than wehave in recent years.”

Environmental groups say the loss ofsea ice due to climate warming is harm-ing marine mammals and oil and gasdevelopment would add to their stress. �

10 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

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PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 11

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By GARY PARKFor Petroleum News

Canada and Japan need each other so badly in the liq-uefied natural gas sector that they have started bilat-

eral efforts to speed development of projects by rampingup Japanese investment in natural gas production andattempting to find common ground on LNG prices.

The two prime ministers — Canada’s Stephen Harperand Japan’s Shinzo Abe — agreed to an early start to talksat the level of cabinet ministers, pointing to the growingpressures on Japan to find energy sources to replace theshutdown of its nuclear industry after the Fukushima dis-aster in 2011.

Japan has already established a foothold in BritishColumbia gas fields and as a minority partner in LNGprojects, with an array of companies such as Mitsubishi,Idemitsu Kosan, Japan Petroleum Exploration, SumitomoHitachi, Toyota and Inpex acquiring stakes, and Japanesefinancial institutions expected to join the list.

At his Ottawa meeting with Harper in late September,Abe praised Canada as a stable source of natural gas thatcould provide the commodity at competitive prices.

Japan wants diversificationSusumu Fukuda, Japan’s consul general in Calgary,

said that with more than 90 percent of Japans oil import-ed from the Middle East Canada is a “very important pos-sibility to promote diversification” of Japan’s naturalresource supplies.

He said that next to Australia, Japan prefers to do busi-ness with Canada rather than the United States, whereenergy exports pose greater complications.

Japan also takes an edge by preferring “more friendly”partnerships and joint ventures over China’s push for cor-porate control, which collides with Canada’s foreigninvestment barriers.

The test of the new alliance will come when they try toattach a value to LNG.

As the world’s largest LNG consumer, Japan pays the

highest prices anywhere — sometimes up to US$16 per mil-lion British thermal units, while the rest of Asia is drivingbargains that are tied to world oil prices.

Kyodo News, the Japanese news agency, said Abe’s gov-ernment was ready to help finance pipelines and infrastruc-ture to accelerate Canadian LNG shipments to Japan, possi-bly as early as late 2018.

Keisuke Tsujimoto, general manager in Canada for theJapan Oil, Gas and Metals National Corp., said the Japanesegovernment is eager to build a relationship with the BritishColumbia government to achieve a memorandum of under-standing for natural gas.

He said that such a deal, along with working out anacceptable LNG pricing mechanism, would encourageJapanese investment in midstream and upstream sectors.

Tsujimoto said such a deal could be finalized inDecember when British Columbia Premier Christy Clarkvisits Asia.

Tokyo Gas has suggested a more realistic price forLNG could be about US$11 per million British thermalunits, based on a Henry Hub gas price of US$4 per mil-lion Btu. �

� N A T U R A L G A S

Canada, Japan seek LNG fitKyodo News, the Japanese news agency, saidAbe’s government was ready to help finance

pipelines and infrastructure to accelerateCanadian LNG shipments to Japan, possibly as

early as late 2018.

INTERNATIONALNorway methanehydrate researchcenter starts up

A new center for research into Arcticmethane hydrate deposits has opened inthe Arctic University of Norway inTromso. Called the Center for ArcticGas Hydrate, Environment andClimate, or CAGE, the center will bringtogether a variety of geologists, geo-physicists, oceanographers and otherscientists to carry out research into theproperties of the hydrates and the waysin which hydrate deposits interact withthe Earth’s atmosphere, oceans and cli-mate system, according to a report byscience news service phys.org.

Methane hydrate is an ice-like mate-rial consisting of molecules of methane,the main component of natural gas,trapped in a lattice of water molecules.The material, only stable within a cer-tain range of relatively high pressuresand relatively low temperatures, occurscommonly below the seafloor in coastalshelf areas and, onshore, under Arcticpermafrost.

Although some of the hydrates areviewed as a potential future source ofnatural gas as a fuel, there are alsomajor concerns about the potential dis-association of the material as a conse-quence of global warming. Such disas-sociation could release huge quantitiesof methane, a potent greenhouse gas,into the atmosphere, thus acceleratingthe warming of the climate and ulti-mately generating carbon dioxide thatwill add to ocean acidification.

CAGE will carry out basic researchinto both the energy resource and envi-ronmental aspects of methane hydrate,phys.org says.

—ALAN BAILEY

Methane hydrate is an ice-likematerial consisting of

molecules of methane, themain component of naturalgas, trapped in a lattice of

water molecules.

By ALAN BAILEYPetroleum News

A relative boom in exploration activi-ty in the Cook Inlet basin coupled

with several new utility gas supply con-tracts coming in quick succession fromgas producer Hilcorp Alaska has pro-duced a sense of euphoria over what haduntil recently been viewed as an emer-gency over pending shortages inSouthcentral utility gas supplies. And,with both the Alaska Department ofNatural Resources and the U.S.Geological Survey having publishedreports indicating the likelihood that sub-stantial volumes of as yet undiscoveredand undeveloped gas remain in the basin,some people view the gas supply situationas having been resolved.

But the utilities, with a duty to ensuresupplies of gas and electricity to their cus-tomers for years into the future, require

certainty in the form of adequate proven,commercially viable gas reserves, behindpipe and linked to firm gas supply con-tracts with producers, if their officials areto sleep soundly at night, assured thatlights will stay on and that buildings willremain heated.

And, on that basis, the Southcentralutilities still see significant future uncer-tainty, despite emerging news about gasdiscoveries and gas field developments inthe Cook Inlet basin.

During a meeting of the AnchorageMayor’s Energy Task Force on Oct. 2 theutilities overviewed their current gas sup-ply situations.

Gas to 2018Moira Smith, Enstar Natural Gas Co.

vice president and general counsel,explained that a new contract betweenEnstar and Hilcorp, coupled with severalother existing contracts, provide Enstarsufficient gas under contract to meet itsanticipated annual gas demand through tothe first quarter of 2018. However, Enstardoes not have sufficient contracted gas tomeet all of its 2018 needs and has no gasunder contract beyond the end of 2018,Smith said.

A new gas storage facility, the CookInlet Natural Gas Storage Alaska, orCINGSA, facility on the Kenai Peninsula,now provides a key service for all of theutilities by storing excess summer-pro-duced gas to support high levels of gasdemand during the winter. However, thewithdrawal of gas from CINGSA duringthe winter requires careful management,Smith explained, because gas with-drawals reduce the reservoir pressure inthe facility, thus reducing the maximumrate at which gas will flow from the facil-ity to support gas deliverability needs.

And meeting those deliverabilityneeds remains tight.

Deliverability gaps?Currently, with the ConocoPhillips liq-

uefied natural gas export facility on theKenai Peninsula having closed its doors,there is an excess gas supply from theCook Inlet basin. But, based on its exist-ing firm gas supply and gas storage con-tracts, Enstar does see theoretical gaps inits ability to deliver gas sufficiently rapid-ly to meet possible peak winter demand infuture winters, Smith said. However, theutility anticipates being able, in practice,to meet that demand by obtaining addi-tional gas through a gas bidding systemthat it has established, potentially supple-mented by some contractual arrangementsfor the supply of gas that is not guaran-teed. It is also typically possible to add gasinto CINGSA during some of the warmerwinter weather, she said.

CINGSA is likely to hold an open sea-son next year, to explore the possible needto expand its storage capacity, Smith said.

Insurance optionsWith annual gas supply volumes pro-

12 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

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� N A T U R A L G A S

Utilities review gas supply situationNew Cook Inlet supplies have brought welcome relief but future remains uncertain until sufficient new reserves established

The utilities are discussing withConocoPhillips the potential toimport liquefied natural gas at

Nikiski, the port whereConocoPhillips’ mothballed LNG

export facility is located.

RCA OKs Hilcorp gas contract with CEAThe Regulatory Commission of Alaska has approved a gas supply contract

between Hilcorp Alaska and Chugach Electric Association that will ensure thatChugach Electric can obtain all of the gas that it needs to operate its gas-firedpower plants until the end of the first quarter of 2018. The commission hasalready approved a similar contract between Hilcorp and Enstar Natural Gas Co.

In a letter order issued on Sept. 10 the commission said that it approvesChugach Electric’s ability to recover the cost of the gas through the rates that itcharges its customers.

The contract, which goes into operation in 2015, specifies prices ranging from$7.13 to $8.03 for regular “base load” gas supplies, with price markups of 25 and50 percent for gas needed to meet peak demand and to meet emergency needs.

Commissioner Norman Rokeberg, while concurring with the commission’sdecision, has raised concerns about the potential difficulty for Cook Inlet gasexplorers in finding markets for newly discovered gas, given the manner in whichHilcorp’s contracts have tied up the utility gas market until 2018.

Chugach Electric, saying that it is concerned about providing a gas market forindependent producers, has now submitted a gas supply contract with Cook InletEnergy Inc. to the commission for approval. Cook Inlet Energy is an oil produc-

see GAS SUPPLIES page 15

see CEA CONTRACT page 15

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

Forget XL — oil sands will grow

By GARY PARKFor Petroleum News

Whether or not Keystone XL isstalled or scrapped, capital spend-

ing in the Alberta oil sands will continueunabated, peaking in 2016 at C$29.7 bil-lion if the TransCanada project goesahead, said a report by RBC DominionSecurities analyst Mark Friesen.

Even if XL faces delays and removesC$8.1 billion from investment in the2014-17 period, C$7.8 billion of thatdeferral will be transferred into the 2018-20 period, he said.

The analysis estimates that if XLremains on hold, 300,000 barrels per dayof an expected 1.6 million bpd ofincreased output will be affected in the2015-17 timeframe, but expects crude-by-rail could largely offset that setbackand might have the positive result of eas-ing short-term inflationary pressures inthe oil sands region of northern Alberta.

In fact, investment bank CanaccordGenuity said in a September study thatother pipeline and new rail terminal pro-posals mean XL is “no longer a necessi-ty.”

Investment bank Peters & Co. expectsCanadian companies to spend US$1 bil-lion on rail terminals in Western Canadaover the next two years and up to C$5 bil-lion on new rail tanker cars.

Capital biggest issueThe RBC report said the biggest issue

facing oil sands growth — even greaterthan the risks posed by pipeline capacityand technology development — is theavailability of capital for projects, espe-cially for smaller operators.

It said about C$26 billion has been ear-marked by oil sands producers, more thanhalf of it budgeted for thermal recoveryprojects, noting that the 10 largestspenders will account for 84 percent of thecapital outlay and control more than 90percent of the approved capacity additions.

RBC forecasts that cost inflation in thethermal sector will average 3 to 4 percenta year over the next seven years, a changefrom the runaway inflation in recent yearsthat resulted in budget overruns of up to 40percent.

Pressures on skilled labor will comefrom two current megaprojects — theNorth West Redwater Partnership’s150,000 bpd refinery near Edmonton(which is expected to need a peak work-force of 8,000) and a 109,000 bpd expan-sion of ConocoPhillips’ Surmont operation(peaking at 3,000 workers).

The report pegs the long-term supplycosts of greenfield in-situ projects atUS$76.38 per barrel of West TexasIntermediate, assuming a heavy oil pricedifferential of 18 percent and 12 percentafter-tax return.

However, RBC said higher quality bitu-men resources and existing investments ininfrastructure could help industry leaderssuch as Cenovus Energy, MEG Energyand Suncor Energy build thermal recoveryprojects at lower oil prices. �

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 13

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GOVERNMENTAOGCC sets 2014 CO 360 hearing date

The Alaska Oil and Gas Conservation Commission has set a Jan. 7 public hear-ing date to gather information on disposition of gas liquids at the Prudhoe Bay oilpool.

The commission said field operator BP Exploration (Alaska) is disposing ofnatural gas liquids under Conservation Order 360 which the commission issued inthe mid-1990s, and is transporting the maximum amount of NGL that can be han-dled by the trans-Alaska oil pipeline, with the remaining NGL used to create mis-cible injectant for enhanced oil recovery.

The commission noted that at a June 2012 hearing BP offered evidence thatPrudhoe Bay oil production would increase if additional miscible injectant wereavailable, testifying that for every barrel of propane used for MI, 0.6 barrels of oilwas recovered and 0.7 barrels of propane recovered for re-use as MI.

The commission said that after the 2012 hearing BP advised the commissionthat the commission had misinterpreted BP’s evidence on the quantity of MI perinjected barrel which is recoverable.

The commission said the purpose of the January hearing is to gather evidenceon two issues: whether the commission should alter CO 360 to require that addi-tional MI be used to extract oil; and whether the commission has misinterpretedBP’s 2012 testimony.

The commission said the outcome of the inquiry may lead it to reopen CO 360and/or Other Order 75 (issued following the 2012 hearing) for amendment.

The hearing will take place at 9 a.m., Jan. 7, at the commission’s Anchorageoffice, with any pre-filed testimony to be offered due Dec. 6.

—PETROLEUM NEWS

Subscribe to Petroleum News:call 907.522.9469

PIPELINES & DOWNSTREAMArrest made on pipeline graffiti threats

The 800-mile trans-Alaska pipeline, much of which courses above groundthrough lonely countryside, occasionally has been the target of vandals.

Most infamous, perhaps, was the 2001 incident in which a man shot thepipeline with a high-powered rifle near Livengood, causing a hole that spewed alarge volume of oil.

Now we have more mischief to report, this time near the village of Tazlina.The Alaska State Troopers said pipeline security on Sept. 25 reported graffiti

on the line, including “Car Bomb” and death and sexual threats toward a trooperand his family in the Glennallen area.

Troopers responded to the scene and saw graffiti on six sections of the pipeline,an agency press release said. The graffiti included multiple statements regardingdeath to law enforcement, and a death list with the names of Glennallen troopers.

A black spray paint lid was found at the scene, the press release said.Further investigation revealed Ryan Vukson, 29, of Glennallen, had purchased

the paint the day prior and was seen the night of the crime with the same colorpaint on his hands, troopers said.

Vukson was arrested without incident on charges of terroristic threatening,criminal mischief and criminal trespass. He was jailed in Palmer on $30,000 bail.

—WESLEY LOY

By WESLEY LOYFor Petroleum News

Both urban and rural Alaska are heavilydependent on expensive fossil fuels for

electricity and heat.As a result, innovators, communities and

government agencies continually pursuealternative sources of energy.

Two projects generating attentionrecently include an effort to harness the

power of ocean waves at Yakutat, northwestof Juneau.

Another effort will focus on furtherdeveloping wood as an energy resource inrural Alaska.

Yakutat wave projectYakutat is located on the Gulf of Alaska,

and is known for large waves that attractadventurous surfers. About 700 people liveat Yakutat.

“Like many rural Alaskan communities,Yakutat faces an energy crisis driven byhigh costs of electrical power and heatingfuel and by complete dependence on out-side sources of petroleum products,” theCity and Borough of Yakutat website says.“The municipal power company operatesdiesel generators for 100 percent of theelectricity used locally.”

To face what it calls an energy crisis,Yakutat has embarked on a “renewable

energy self-sufficiency program.”“Yakutat aims to be the first municipali-

ty in North America to generate electricalgrid power from wave energy,” the websitesays. “Our community offers close proxim-ity to a tremendous source of power, theGulf of Alaska!”

On Jan. 30, the Federal EnergyRegulatory Commission issued a prelimi-nary permit to Resolute Marine Energy Inc.for a Yakutat wave energy project.

The Boston-based company is focusingon development of patented nearshorewave energy technology, and a prototypedevice could be deployed in Yakutat by fallof 2014, the Yakutat website says.

On Sept. 23, the Alaska Department ofNatural Resources said it would issue a one-year land use permit to Yakutat to place sci-entific instruments on submerged stateacreage. Data will be collected about twomiles seaward, a DNR public notice said.

Wood to energyAlaska Sen. Lisa Murkowski and

Congressman Don Young recentlyannounced the Alaska Energy Authorityhad been awarded federal funding to pro-mote the development of rural wood energyprojects.

“Alaska has always relied on wood-based resources for heat and power, andrecent technological advancements havedramatically increased their efficiencywhile decreasing their impact and cost,”Young said in a joint press release withMurkowski.

Agriculture Secretary Tom Vilsack onSept. 11 announced $1.1 million in grants toorganizations in Alaska, California, Idaho,Minnesota and New Hampshire to formstatewide teams to stimulate developmentof wood energy projects.

Vilsack called it part of the Obamaadministration’s “all of the above” energystrategy.

Under terms of the grants, private, stateand federal organizations will work togeth-er on wood energy projects.

“Collectively, $2.9 million will be spenton this effort — $1.1 million in federalfunds and $1.8 million in non-federalfunds,” a U.S. Department of Agriculturepress release said. �

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

Potential ‘game changer’ for CanadaBy GARY PARK

For Petroleum News

Statoil, drawing on its experience in Norway’s off-shore, and its minority partner Husky Energy have

added a large building block to what shapes up as a newproduction basin in Atlantic Canada.

Statoil as operator, with Husky holding a 35 percentstake, have reported their third oil discovery in the pastthree years and are estimating they have up to 800 mil-lion barrels of recoverable crude from just two of thosefinds.

The Norwegian company said that after more explo-ration Flemish Pass could become a core producing areapost-2020 and be a “game changer for Canada.”

‘New petroleum system’Statoil spokesman Ola Moreten Aanestad said the

partnership’s latest discovery is “the largest pure oil dis-covery made by Statoil outside Norway. We are opening

up a new petroleum system.”The find, about 310 miles northeast of St. John’s,

Newfoundland, resulted from a sidetrack well of theoriginal discovery announced in August.

The Mizzen discovery in Flemish Pass in 2010 isbelieved to have up to 200 million barrels of recoverablereserves, while volumes will not be confirmed for theHarpoon discovery made during the summer until evalu-ation work has been completed.

All three finds are in about 3,600 feet of water andhave yielded light oil of 34 API from Jurassic reservoirswith high porosity and high permeability.

Seismic, additional drillingStatoil Executive Vice President Tim Dodson said an

“optimal development solution” depends on more work,including seismic and additional exploration anddrilling, given that only a few wells have been drilled inthe large license area.

Aanestad was reluctant to compare Flemish Pass with

other mega-finds, including Statoil’s Sverdrup discoveryoffshore Norway, which holds about 3.3 billion barrels.

“I can’t speculate on that ... but this is an area we havegreat faith in,” he said.

Lars-Henrik Roren, a Norwegian analyst withEnskilda, doubted the Flemish Pass will match theSverdrup play, but suggested there could be a “fewmore” finds in the range of 100 million barrels. He saidmore complete details will probably not be known for 12to 15 months.

Roren said Statoil does not have any more rig slotsavailable until 2016, although the company could be“more flexible with its rig capacity.”

Offshore Newfoundland has been producing since1997 and expects to average 230,000 barrels per day thisyear from the shallow-water Hibernia, Terra Nova andWhite Rose fields, with Herbon due to join the trio in2018 with another 150,000 bpd. �

� A L T E R N A T I V E E N E R G Y

Alaska searches for energy alternativesYakutat community aims to generate electric power from waves; AEA awarded federal grant to develop rural wood energy projects

jected to fall short of demand less than fiveyears into the future, the utilities are stilllooking at “insurance” options for guaran-teeing continuing energy supplies beyondearly 2018. And, with continuing uncer-tainty about the future construction of apipeline system that might deliver NorthSlope gas into Southcentral Alaska, theimport of gas, probably from Canada orthe Pacific Northwest, remains a possibili-ty. Although the utilities had consideredthe import of gas in compressed form theynow view the import of liquefied naturalgas as a more practical option, Smith said.

The utilities are discussing withConocoPhillips the potential to import liq-uefied natural gas at Nikiski, the portwhere ConocoPhillips’ mothballed LNGexport facility is located. And, with thelikely need for an environmental assess-ment or an environmental impact state-ment for the import arrangements, estab-lishing these arrangements would likely bea multiyear project, Smith said.

Lee Thibert, senior vice president ofChugach Electric Association, said thatthe ability to bring in or store extra gas at

Nikiski would be an excellent backstopfor winter gas supplies. An import facilitymight cost somewhere in the range of $50million to $135 million, he said.

Chugach ElectricThe gas supply situation for Chugach

Electric, a major Southcentral electric utili-

ty, appears somewhat similar to that ofEnstar, with existing gas supply contractsand a new contract with Hilcorp carryingthe utility through to the first quarter of2018, but with no gas currently under con-tract beyond the end of that year.

Chugach Electric wants to offset its gasconsumption by diversifying further intorenewable energy resources, includingincreased hydropower capacity from theKenai Peninsula and, eventually, powerfrom a planned major hydropower facilityat Watana on the Susitna River, Thibert said.However, the Watana-Susitna system,potentially a supplier of a significant portionof Chugach Electric’s needs, is not expectedto come on line until 2024-25, he said.

Matanuska Electric AssociationJoe Griffith, general manager of

Matanuska Electric Association, said thathis utility also now has secured gas suppliesthrough to 2018 for the new gas-fired powerplant that the utility is building at Eklutna,north of Anchorage. The engines beinginstalled in the new plant are dual-fuelreciprocating engines, rather than turbines,with the capability of switching instantlyfrom gas to diesel fuel, should need arise,Griffith said.

A key issue that now needs to beaddressed is ensuring a healthy gas marketfor the several companies that are currentlyengaged in Cook Inlet exploration, giventhe small size of the local utility gas marketin relation to the investment required to findand develop Cook Inlet gas, Griffith com-mented. He said that the ability to exportLNG from the basin seems the only obviousway to resolve this conundrum.

Municipal Light & PowerJim Posey, general manager of

Anchorage electric utility Municipal Light& Power, commented on the importance offinding new gas supplies from Cook Inletand having a means of ensuring gas sup-plies beyond 2018. ML&P obtains most ofits gas through its partial ownership of theaging Beluga gas field on the west side ofCook Inlet. The utility also has a small gassupply contract with Hilcorp through to thefirst quarter of 2014 and has requestedRCA approval of a new contract withConocoPhillips that would run fromApril 2014 to December 2019, Poseysaid. �

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 15

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continued from page 12

GAS SUPPLIES

er and active oil and gas explorer inthe Cook Inlet basin.

The prices in the contract, rang-ing from $6.12 to $7.31 per thou-sand cubic feet, are 10 percent lowerthan those in Chugach Electric’sapproved contract with Hilcorp. Butthe Cook Inlet Energy contractmakes no firm commitment, eitherfor Cook Inlet Energy to supply gasor for Chugach Electric to purchaseany gas that Cook Inlet energy mayoffer for sale.

—ALAN BAILEY

continued from page 12

CEA CONTRACT

GOVERNMENTBSEE extendscomment periodfor safety rule

The Bureau of Safety andEnvironmental Enforcement, or BSEE,said Sept. 26 that it is extending by anadditional 45 days the public commentperiod for a proposed offshore safetysystems rule. Comments must now befiled by Dec. 5, BSEE said.

The proposed rule relates to safetyregulations for systems such as subseapumping, foam firefighting equipment,emergency shutdown systems and gaslift used in oil production facilities onthe U.S. outer continental shelf.

The rule was originally published onAug. 22 with a closing date of Oct. 21for public comments. But BSEE hasreceived “multiple requests from vari-ous industry representatives to extendthe comment period” and the agencydetermined that an additional 45-daycomment period was warranted, BSEEsaid. With no major revision havingbeen made to the relevant regulationssince they were published in 1988, it isnow necessary to update the regulationsto take account of new technologiessuch as the use of subsea well trees,BSEE said.

“These new technologies are morecomplex than those that were tradition-ally used for shallow water drilling onshelf areas, where equipment was tradi-tionally placed on the rig itself, ratherthan on the seafloor,” BSEE said. “Withthe shift to deeper water in the pastdecade, more specialized require-ments and regulations are required forthese newer and emerging safetytechnologies.”

—ALAN BAILEY

The proposed rule relates tosafety regulations for systemssuch as subsea pumping, foam

firefighting equipment,emergency shutdown systems

and gas lift used in oilproduction facilities on the

U.S. outer continental shelf.

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

Update from Conoco on Alaska investmentsTrond-Erik Johansen, president of ConocoPhillips Alaska, reviews work under way since passage of bill reducing state taxes on oil

By KRISTEN NELSONPetroleum News

In April ConocoPhillips Alaska laid outwork it planned in response to passage

of Senate Bill 21, Gov. Sean Parnell’s oiltax revision.

In late September Trond-Erik Johansen,president of ConocoPhillips Alaska, gavethe Alaska World Affairs Council anupdate on that work.

The addition of a rig at theConocoPhillips Alaska-operated KuparukRiver field has resulted in 1,300 barrels ofoil per day of new production online since

May, Johansen said Sept. 27, andalso supports 95 direct new jobsas well as some 700 indirect jobs.

In April the company also saidit was working with Kuparuk co-owners to fund a new drill site onthe southwest flank of the unit.Johansen said gravel will be laidthis winter in preparation for con-struction of that new drill site,Kuparuk drill site 25.

The drill site will develop adiscovery ARCO Alaska made with theKRU 21-10-08 well in the late 1980s.ConocoPhillips appraised the discovery

with the Shark Tooth No. 1well in the winter of 2012. Thecompany began permittingwork for the drill site and anaccess road in early 2013, with300,000 cubic yards of gravelto be placed this winter andpipelines and power linesinstalled the following winter.

Johansen said first oil isexpected from drill site 25 in2015 with estimated peak pro-

duction of 8,000 bpd; he pegged the devel-opment cost at $595 million.

NPR-AJohansen said the Greater Moose’s

Tooth-1 development in the NationalPetroleum Reserve-Alaska, a major newdevelopment, would cost an estimated$890 million, with first oil in 2017 andestimated peak production of 30,000 bpd.He characterized the development as simi-lar to CD-5 and said ConocoPhillipsAlaska would seek approval for GreaterMoose’s Tooth-1 in late 2014.

CD-5, sanctioned in late 2012, is a sin-gle-pad development, with a road and abridge and pipelines over a channel of theColville River, with crude oil sent to theAlpine facilities for processing.Construction on that project, also calledAlpine West, is projected to begin in 2014with partner approval. While first oil isestimated for late 2015 or 2016, the devel-opment is facing court challenges fromenvironmental groups.

ConocoPhillips also plans two winter

exploration wells in NPR-A, wells thatJohansen said were questionable last year.

There are also projects at Prudhoe Bay,operated by BP Exploration (Alaska), andJohansen said BP has discussed those proj-ects.

In late June Janet Weiss, president ofBP Alaska, told the ResourceDevelopment Council that in addition to a$1 billion increase in Prudhoe Bay invest-ment for the next five years, previouslyannounced, and $3 billion in westernregion Prudhoe projects under evaluation,the Prudhoe owners are moving forwardon development of the Sag River forma-tion. BP is also reworking economics forNorthwest Schrader at its wholly ownedMilne Point field, she said.

The repeal issueAnswering audience questions after his

presentation, Johansen said that eventhough there is a referendum scheduled onSenate Bill 21, engineering for Kuparukdrill site 25 and for NPR-A is going ahead.

If the August 2014 vote turns the taxchange upside down, some things may bestopped, he said.

But he noted that ConocoPhillips hashired 50 people since May and expects tohave hired 120 by the end of the year. And,he said, they wouldn’t have done all theseprojects without SB 21.

Some would have been done, he said,but at a much slower pace. �

16 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

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By WESLEY LOYFor Petroleum News

President Obama on Oct. 2 signed legis-lation that could steer millions of dol-

lars toward cleanup of derelict federal wells,known as legacy wells, in the NationalPetroleum Reserve-Alaska.

The new law, titled the HeliumStewardship Act of 2013, is designed toeventually close the Federal HeliumReserve in Texas.

What to do with the reserve had formany years been the subject of controversyand debate in Washington.

Alaska Sen. Lisa Murkowski helpedauthor the helium act. Murkowski is thetop-ranking Republican on the Democrat-controlled Senate Energy and NaturalResources Committee.

Closure of the helium reserve is expect-ed to generate about $500 million in rev-enue over the next decade, Murkowski saidin a press release.

The new law dedicates some of themoney to reduction of the federal debt.

It provides $50 million to remediate andclose abandoned oil and gas wells on cur-rent or former national petroleum reserveland. Wells in Alaska and in other states areeligible for the funding.

But the vast majority of the $50 millionis expected to come to Alaska, a Murkowskiaide told Petroleum News.

‘An environmental crime’The NPR-A is a vast tract on Alaska’s

North Slope.Murkowski and other Alaska elected

officials and regulators have been poundingthe Interior Department for months to dosomething about the reserve’s legacy wells.

Federal departments drilled 136 testwells between 1943 and 1982.

Today, the wells are the responsibility ofthe Interior Department’s Bureau of LandManagement, which manages the petrole-um reserve and also operates the FederalHelium Reserve.

Murkowski and the other critics say theBLM has neglected the legacy sites, someof which are junk-strewn and have wellsthat were never properly plugged and aban-

doned.They have complained the BLM is mov-

ing far too slowly to clean up the legacywells. BLM officials have countered thatcleanup is extremely costly, and that manyof the wells don’t really need any attention.

After the helium act cleared Congress,Murkowski said the funding should helpspur action.

“For years, we fought just to get a coupleof million dollars dedicated to the cleanupof the legacy wells, so I’m pleased we wereable to obtain $50 million to begin serious-ly addressing what is nothing short of anenvironmental crime against Alaska,”Murkowski said. “Securing the fundingduring these days of tight budgets and com-peting federal priorities was challenging,but the legacy wells are a federal responsi-bility that has been ignored for far too long.”

BLM’s cleanup planNorth Slope Borough Mayor Charlotte

Brower welcomed the helium bill’s pas-

sage.“For many years, BLM has lacked the

resources necessary to clean up and remedi-ate high-priority wells in a timely manner,”she said.

She noted how the Obama administra-tion proposed a fiscal year 2014 InteriorDepartment budget that would pay for lega-cy well cleanup by diverting Alaska’s shareof revenue generated from oil and gas activ-ity in the NPR-A.

Brower called that proposal “unaccept-able,” and Murkowski said it would be“dead on arrival.”

Murkowski is the ranking Republicannot only on the Senate Energy Committee,but also the Senate Interior AppropriationsSubcommittee. Both have jurisdiction overthe BLM.

The helium law allocates the wellcleanup money across three fiscal years, aNorth Slope Borough press release said.

On Sept. 23, the BLM released a final“strategic plan” to plug and clean up NPR-

A legacy wells.The BLM said half, or 68, of the legacy

wells require no action “because they havebeen remediated or pose no threat to thepublic or the environment.”

The U.S. Geological Survey continues touse another 18 wells as part of climatechange studies.

The plan identifies 50 wells as requiringattention, including 16 priority wells.

The first wells slated for cleanup workare at Barrow and on the Simpson Peninsulasoutheast of the village.

The BLM didn’t specify a total cost tocarry out the cleanup plan. But the moneyavailable from the helium bill is likelyinsufficient.

“BLM’s plan is a good start,”Murkowski said. “It doesn’t cover all of thesites, but it takes care of the most seriousenvironmental threats first.” �

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 17

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Obama signs bill with legacy well moneyFunds from closure of Federal Helium Reserve to be used to remediate old federal wells sites in National Petroleum Reserve-Alaska

Bering Straits is going to play a key part.Yes, Unalaska has been for centuries

and will continue into the future to play ahuge role for Arctic exploration.

Petroleum News: Still on the Arctic,Shell got off to a slow start last summerand had to postpone operations until nextyear. Do you have any concerns aboutfurther delays?

Herron: Sure we’ve got to be prudentand do things correctly, and I think that’sthe intent of everyone involved. You’vegot to look at it from a half full glassrather than a half empty glass. I tend touse this philosophy in everyday life:things I attempt are not failures; they aresuccessful attempts. I’ll give them thebenefit of the doubt. It didn’t work out theway they wanted. They took those steps.Those are lessons that are hard learned.Sometimes you have to take those stepsthat don’t succeed. I hope they and othermembers of the industry keep at it.

Petroleum News: Shifting to oilalready under production, SB 21 contin-ues to be a hot-button topic long after it’spassed and now we have an effort to over-turn it before the voters next year. Whatare your thoughts on this as it unfolds.You’ve got two issues on the table: the ref-erendum and the concerns over draftingregulations defining new oil?

Herron: I voted no on SB 21. I signedthe referendum because I believe SB 21went too far. Did there need to be changesto ACES? Absolutely. I said that all along.It went too far, too fast. So should SB 21be overturned and then rethought? That’s

why I signed the petition and that’s whyI’m going to support the ballot initiative.

On the House floor, I advocated forchanges. I debated and talked with mycolleagues. I told them it went too far. Thequestion I asked was, is this being fiscallyconservative? Is this fiscally responsible?

What I mean by that is, if it were myhousehold, and of the two wage earners,one of them lost their job for whateverreason. So you cut back on the extras andyou pay your mortgage and you feed yourkids. You spend on what’s necessary. Butyour savings account you protect it at allcosts. You save it for real emergencies,catastrophic events.

So where I disagreed on SB 21, the taxis immediate (Jan. 1, 2014), so we’ll justtake from the savings account to sort ofback feed it. I disagree with it. I asked lit-erally every oil company who came to myoffice to confirm that I was voting no andI asked them this. I don’t care what theformula is, but let’s call the “n” number“x,” so the way SB 21 is we come to acertain date and revenue drops to that “x”factor in the formula. What if it wasplayed out three or four years? In the firstyear there would be 25 percent reductionin taxes, then the next year there would be50 percent until the fourth year we wouldhave 100 percent of that “x” factor. Iasked all of the oil companies if theywould accept that. They all said yesbecause they were getting that numberthat advocated for.

That’s why I believe SB 21 was toomuch, too fast. That’s why I voted no. Idon’t think it’s fiscally conservative or fis-cally responsible.

Petroleum News: OK, on to the secondissue of drafting a regulation that clearlyand concisely defines new oil.

Herron: Whoever writes that regulationis going to be the wordsmith of 2013.There will be so many ‘ifs,” “ands” and“ors.” I just don’t think they are going tocome up with regulatory language thatmakes sense. I don’t think I’ll understandit. I just don’t know if I’ll know what newoil is. Maybe my glass has changed fromhalf full to half empty. I’m just not confi-dent that the regulation will make anysense to me.

Petroleum News: On to the gas lineissue, what would you like to see happento advance a gas line project, be it thelarger line or the smaller line?

Herron: I was on an ExxonMobil-sponsored trip to Coldfoot to see whattheir crews are doing on the ground. Iasked them that specific question. Whenis the line going to go? They said we arenot going to come up with an answer untilwe have gas tax certainty. I think we havea ways to go yet. Whether it’s a small lineor a big line, the producers are going toneed gas tax certainty. So is that going tobe a debate in 2014 or a debate in a spe-cial session? Probably (a special session).I don’t know when that special session isgoing to be. I’m just a believer the pro-ducers are not convinced they have gastax certainty.

Petroleum News: What else did youlearn on that trip?

Herron: That the producers are seri-ous about spending billions on a facilityon the North Slope. But what I tookaway still is they are not prepared tomake the decision until they get the gastax certainty.

Petroleum News: There are twoschools of thought: You don’t provide gastax certainty until you have a firm projecton the table; you won’t get a firm projectwithout the gas tax certainty. The negotia-tions rest with the executive branch. Whatwould you like to see happen?

Herron: I think for some, let’s givethem the certainty. For a lot of legislators,it’s show me first, then if it’s going towork then you will get the certainty. Wewant to push the envelope. We want theproject that makes the most sense. I agreewith critics and pundits who have com-mented on this since I’ve lived in Alaska.We are going to move forward. It’s goingto take the producers as well to push gasthrough any vessel, any gas line. At themoment for me, it’s show me what yougot. Show me what makes sense. This iswhy you need gas tax certainty — thenwe’ll talk about it.

Petroleum News: Do you have anyclosing thoughts to what we discussed?

Herron: There’s a lot going on in ourstate. For Alaska and the United States,plus the Yukon and Northwest Territories,and their national government, we havemuch more in common than we do differ-ences. The things that Alaska, Yukon andthe Northwest and how much these juris-dictions have in common and can benefitfrom the Beaufort Sea, I believe we havetremendous opportunities in the next threeto four years with Canada being the chairof the Arctic Council and the UnitedStates coming up after that.

That’s why I think the Alaska ArcticPolicy Commission in its preliminaryreport to the Legislature in 2014 and itsfinal report in 2015 right before the U.S.takes over as chair of the Arctic Councilis important.

The Legislature in working with theParnell administration or any futureadministration — it doesn’t matter if youare a legislator from Ketchikan, Barrow,Bethel, Anchorage or Fairbanks — theseissues of the Arctic are going to play ahuge role in our daily lives. Whatever theArctic policy is, it all has to be about whatbenefits Alaska, because we know manyof these policies are going to impact usand not in a policy way. The Legislatureand the Parnell administration, we have somany things to deal with, so many con-stituencies that are asking for help. By theconstitution we are required to assistthem. Because of the opening of theArctic and the potential of oil and gas —and many other minerals — these policiesaffect us.

What our Canadian partners do in rela-tion to Prince Rupert is going to have atremendous effect to Alaskans. One ofthem is the great circle route. Right nowwe’ve got 3,000 quote-unquote innocentpassage ships going through our watersbecause it’s the shortest route. If PrinceRupert opens up for all the resourcesCanada wants to export, that number ofships could go up to 6,000 annually. Itdoesn’t take but a few close calls and onedisaster and Alaska could be impacted ina negative way, tremendously for a long,long time.

What Arctic policy means to anyAlaskan — it doesn’t matter where he orshe lives — is if we are not on top of it,if we are not talking about Arctic policy,all the way from oil and gas to shipscoming through our waters, we have tobe aware of it and protecting ourselves.At the same time, those policies have tobenefit you and me, not benefit justsomeone else. If it doesn’t benefitAlaska, we should work to minimizethose potential impacts to us. �

18 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

continued from page 4

HERRON Q&A

significant challenges.”In filing a project description with the Inuvialuit

Environmental Impact Screening Committee, which acts asadvisor to Canada’s National Energy Board, and theNorthwest Territories government, the partnership has indi-cated growing confidence following the collection of seis-mic data in 2008 and 2009 and three years of gathering fielddata in 2009-11.

Rolheiser said the submission “in effect initiates the for-mal regulatory review,” which operator Imperial hopes willbe completed by 2016.

Sanctioning after approvalAssuming regulatory approval, the joint venture would

then make a sanctioning decision, allowing it to secure afloating drilling system which it believes is best suited to thearea.

A well would be expected to take two years to completebased on an annual drilling season of 120 days from May toNovember.

The two exploration licenses — 476 (Ajurak) and 477(Pokak) — carry combined work commitments of C$1.76billion.

The water depths are estimated at about 5,000 feet andtarget subsea vertical depths of 12,500 feet to 22,300 feet.

Rolheiser said the licenses, which are about 110 milesnorthwest of Tuktoyaktuk on the shores of the Beaufort,

would be the farthest offshore and deepest that Imperial hasever drilled in the area.

The venture is at the leading edge of possible revival ofBeaufort exploration which has included 92 wells that haveso far yielded two major discoveries — the 1984 Amauligakstrike by Gulf Canada Resources, since taken over byConocoPhillips, estimated at 235 million barrels of oil and1.36 trillion cubic feet of natural gas and a 2005 find byDevon Energy, reported to hold 240 million barrels of oil.Neither has advanced to commercial development plans.

Chevron Canada is evaluating results from its 2012 seis-mic program covering 1,412 square miles, 145 miles north-west of Tuktoyaktuk, while Norway’s Statoil has farmed inon a 508,000-acre parcel in the Beaufort, which is west ofthe joint-venture licenses.

NWT wants venture to proceedNorthwest Territories Industry Minister David Ramsay

said his government is now “anxious” to see how far theImperial venture can proceed given its importance to theregional economy since the sidelining of the Imperial oper-ated Mackenzie Gas Project, which had been designed toship up to 1.8 billion cubic feet per day natural gas from theMackenzie Delta to southern Canadian and U.S. markets.

The next three years, building up to a final investmentdecision in 2016, could include a public environmentalhearing, authorizations for drilling operations, agreement ona plan to employ and train Canadians and northerners and aprogram to dredge and install facilities at TuktoyaktukHarbor.

Still to be resolved is how the partnership would complywith a National Energy Board regulation, which followedthe BP Macondo well rig explosion and oil spill in 2010, thatoperators must be prepared to drill a same-season relief wellif there is a blowout.

Imperial said its primary well control approach, whichwill be outlined in future applications for specific wells,would be prevention, including wells designed for the rangeof expected risk.

Industry interest in Canada’s Arctic region, despite a flur-ry of drilling in the Central Mackenzie Valley, is otherwiselukewarm.

Aboriginal Affairs and Northern Development Canadareported the annual call for bids in the Central MackenzieValley that closed Sept. 19 yielded only two successful bids,with four other parcels bypassed.

High Level Energy bid C$18 million for 100 percent ofa parcel covering 200,000 acres, while International FrontierResources landed rights to a lease covering 163,000 acresfor C$1.2 million. The leases require qualifying explorationwork within five years to gain an extension to a nine-yearpermit.

—GARY PARK

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 19

Flint Hills Resources AlaskaJenner & Block LLPKoniag Inc.Northern Economics Inc.Pacific Star EnergyStoel Rives LLPTrident Seafoods CorporationUdelhoven Oilfield System Services Inc.

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

Corporate Partners

ABR Inc.Alaska Business MonthlyAlaska Journal of CommerceAlaska Rubber & Supply Inc.Alaska Wildland AdventuresBear Track InnBooz Allen HamiltonBristol Bay Native Corporation

Calista CorporationCarlile Transportation Systems Inc.CIRIClark James Mishler PhotographyCONAM Construction CompanyCopper Whale InnDenali National Park Wilderness Centers Ltd.Fairweather LLC

Thank You

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

Corporate Council on the Environment

The mission of The Nature Conservancy is to conserve the lands and waters on which all life depends.

The Nature Conservancy is proud to collaborate with a wide range of partners to ensure Alaska’s lands and waters continue to support abundant

salmon and wildlife populations. We thank these corporations for sharing our vision of a healthy and productive Alaska for many generations to come.

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corporation considers obtaining the licenseto be a first step towards addressing energycosts in the Glennallen area while also pro-viding employment opportunities for thecorporation’s shareholders.

“Ahtna Inc., an Alaska Native corpora-tion headquartered in Glennallen, fully sup-ports the Alaska DNR commissioner’sfinding in issuing an oil and gas explorationlicense to Ahtna in the Tolsona Lake areawest of Glennallen,” Anderson said. “TheAhtna Inc. board will be assessing theirfinancial investment scenarios to developnatural gas in the Copper River area.Exploration activities will begin late 2013with a minimum investment of $415,000(US) over the next 1 to 2 years.”

Huge basinThe Copper River basin, occupying a

huge lowland area between the AlaskaRange, the Chugach Mountains, theTalkeetna Mountains and the WrangellMountains, has petroleum geology quitesimilar to that of the prolific Cook Inletbasin to the west. However, although theMesozoic rock unit that sources oil in theCook Inlet region is known to exist in theCopper River area, differences in the pre-cise nature of the rocks are thought to makethe Copper River basin more prospectivefor natural gas than for oil.

Any commercial gas resource discov-ered in the Copper River area, especially ifclose to the road system, could presumablybe used for local power generation.

The new exploration license area liesimmediately west of Ahtna land whereTexas-based independent Rutter andWilbanks drilled a gas exploration well anda series of sidetrack wells between 2005and 2009. Rutter and Wilbanks reported apossible gas find in its Glennallen well.However, the company eventually aban-doned the drilling project, having beenstymied by severe technical problems asso-ciated with water production and abnormal-ly high subsurface pressures.

Sparse explorationAnd, in general, exploration of the

Copper River basin has been very sparse.According to information provided in

the state’s finding for Ahtna’s exploration

continued from page 1

AHTNA LICENSE

see AHTNA LICENSE page 23

continued from page 1

BEAUFORT JVThe venture is at the leading edge of possible

revival of Beaufort exploration which hasincluded 92 wells that have so far yielded two

major discoveries.

20 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

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

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

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Crowley presents scholarships to maritime cadetsCrowley Maritime Corp. awarded three Thomas B. Crowley Sr. Memorial scholarships to

California Maritime Academy students Andrew Leonard, Jeff Harcq and James McSweeneyduring the 2013 Containerization andIntermodal Institute’s Connie Awardsdinner in Long Beach, Calif.

Leonard has had a long-time pas-sion of the water and boating, andbegan researching maritime academieswhile still in high school. He now servesas the residential assistant for his fresh-man class, is a member of theAssociated Students of the CaliforniaMaritime Academy and is an activesupporter of the greater City of Vallejo,Calif.

When Harcq applied to Cal Maritime, he had already obtained his 50-ton master’slicense and had more than 10 years experience as a mechanic for the Correct Craft boatdealer in San Diego. As a student, he has fully embraced his role as a valuable mentor forhis younger classmates by sharing his real-world experiences in the classroom.

During one of the fishing seasons, McSweeney was approached by a Cal Maritime alum-nus who encouraged McSweeney to return to school. After being accepted to the school,he began pursuing his U.S. Coast Guard 3rd Mate Unlimited license and a Bachelor ofScience degree in marine transportation.

Crowley Chairman, President and CEO Tom Crowley Jr., established the Thomas B.Crowley Sr. Memorial Scholarship Program in honor of his father, who guided the companyto extraordinary heights before passing away in 1994.

Fairweather’s Tulugaq launch bolsters data collectionFollowing the recent acquisition of

VDOS, a worldwide leader in airborneremote sensing operations,Fairweather LLC has announced theformation of subsidiary Tulugaq LLC, apartnership between Fairweather,Olgoonik Corp. and Kaktovik IñupiatCorp. Tulugaq (pronounced “too-lu-gak”) is the Native Alaskan word for“raven.” The company was formed to

see OIL PATCH BITS page 22

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Even though the prior increases remaintemporary until regulators officiallyapprove or reject them, the changes havecreated a disparity between the BP and theother owners.

Now, BP is catching up.Under a proposed increase, BP would

charge $3.97 per barrel to ship oil from theNorth Slope to North Pole, up from a cur-rent rate of $1.25 per barrel. And the currentrate of $1.96 per barrel to ship to off-takepoints in Valdez would increase to $6.31 perbarrel to the PetroStar Valdez Refinery and$6.34 per barrel to the Valdez MarineTerminal.

BP wants the higher rates to go intoeffect on Oct. 23.

While the increase would more thantriple the rate BP charges to ship NorthSlope oil to local markets, the higher rateswould still leave BP as the cheapest localshipping option on the pipeline.ConocoPhillips currently charges $4.32 perbarrel to ship to North Pole and as much as$6.87 per barrel to ship to Valdez, whileExxonMobil currently charges $4.09 perbarrel to ship to North Pole and as much as$6.47 per barrel to ship to Valdez.

Historically, Koch and Union OilCompany of California have owned smallstakes in the pipeline system, but Kochrecently transferred its 3.0845 percent inter-est to the three largest owners and Unocal isin the process of transferring its 1.3561 per-cent interest.

For ratemaking purposes, each companyowns an “undivided” stake in the pipeline,meaning each can set its rates individually,so long as the combined rates stay below acertain cap. A company looking to ship oilthen “rents” space from one of the owners.

In filings, BP said it needs the increase tooffset declining throughput and rising advalorem taxes — the same reasons the otherowners have given for their rate increases.

Between 2000 and 2013, throughputwent from 1 million barrels per day to some550,000 barrels per day while ad valoremtaxes went from $57 million to $237 millionannually.

Those trends have been consistent yearafter year, though. As for why BP is lookingto increase its rates now, after six years ofholding firm, the company declined to elab-orate.

BP estimates it would earn nearly $53million per year under the higher rates, upfrom some $16.4 million per year under thecurrent rates. The majority of the earnings— some $48.8 million — would come fromshipments to the Valdez Marine Terminalwith the rest coming from shipments to theGolden Valley Electric Association off takein North Pole. BP does not expect to makelocal shipments to the PetroStar Refinery inValdez.

A complex caseThe request adds yet another layer to a

complex regulatory matter.The State of Alaska and the owners of the

pipeline have long debated the appropriatemethod for determining the shipping rates.The two sides reached a settlement in 1985,but a 1997 court case challenged the system.In 2002, the RCA decided the previous rateswere too high, and forced the pipeline own-ers to refund nearly $10 billion to shippers.

For years after the ruling, the pipelineowners continued to propose rate changescalculated using the older methodology andthe RCA in turn rejected every request.

Starting in 2008, though, ConocoPhillipssought a rate increase calculated under thenewer methodology. ExxonMobil, Unocaland Koch quickly followed suit.

As is typical, the RCA approved thoseincreases on a “temporary and refundablebasis,” meaning the companies could chargethe higher rate while regulators investigatedthe matter, but ran the risk of having to issuerefunds if regulators rejected the increases.

Those four companies continued to seekrate increases year after year, creating anoverlapping series of temporary and refund-able rates, and high exposure for refunds.

The RCA eventually consolidated 12cases — three each from the four companies— to consider a range of issues, particularlyaround whether and how to incorporate thecosts of the over-budget StrategicReconfiguration project into shipping rates.Because many of those same issues are also

before the Federal Energy RegulatoryCommission, which handles shipping ratesfor out-of-state-markets, the two bodies heldnumerous concurrent hearings on the con-solidated cases over a period of months lastyear and this year.

While those cases progressed, though,the pipeline owners continued to file annualrate increases, which the RCA also acceptedon a temporary and refundable basis. Thefate of those requests will largely depend onwhat the RCA decides in the consolidatedcase.

BP, though, considers its request to be“significantly different” than the others, andsaid the RCA should consider it separately,rather than consolidating it into the largercase.

And BP is also asking the RCA to adopta “simplified tariff procedure,” a commonregulatory practice allowing companies toadjust rates quickly within certain parame-ters.

The stakes for an increaseEven when appropriate, higher tariffs are

a burden to third parties. The State of Alaska calculates its royal-

ties after deducting tariffs, which meanshigher shipping rates decrease the amountof revenue the state earns from oil produc-tion.

Higher shipping rates also make it moreexpensive for independent companies onthe North Slope. While AnadarkoPetroleum Corp. has been fighting increas-es for years, the North Slope is now home tomore independent producers than at anypoint in its history.

Finally, higher shipping rates increasethe cost of running the refineries that buy oilfrom the pipeline, which is why Tesoro andPetroStar often push back against increases.

—ERIC LIDJI

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 21

Nelson said that Hilcorp had recentlycompleted the drilling of the first explo-ration well, the Ninilchik Unit SusanDionne No. 8, using the Saxon 147drilling rig.

“We will be using the same rig, theSaxon 147 rig, to drill Frances 1,” Nelsonsaid. “We should begin rigging up nextweek.”

No results are publicly available from

drilling of the first well.The Ninilchik field, which was discov-

ered in 1961 and went into production in2003, is a natural gas field. There havebeen six oil exploration wells previouslydrilled in the Ninilchik unit, with one ofthese, a well drilled in 1978 at ClamGulch, having minimal oil shows, Nelsonhas previously said.

—ALAN BAILEY

continued from page 1

FRANCES WELL

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TAPS HIKE

ed the Umiat No. 23H well, but it alsoincluded four proposed wells that are noton the agenda for this coming winter.Those four wells are the Umiat DSP No.1 Class II disposal well, the side-by-sideUmiat No. 16 vertical and Umiat No. 16Hhorizontal wells, and the Umiat No. 19vertical well.

Linc now plans to defer the disposalwell until the development phase of theprogram.

Earlier this year, Linc described UmiatNo. 18 and Umiat No. 23H as a verticaland a horizontal well into the same intervalof the Lower Grandstand formation. Theidea was to conduct “comparative flowtesting” for economic purposes, but Lincultimately delayed the flow test at UmiatNo. 18 because of an apparent blockage inthe well.

Linc said it “employed multiple tech-

niques to clean the perforations such asmethanol, solvents, and surfactants toremove any ice or other debris in anattempt to re-establish flow,” but wasunsuccessful and has since been reviewingthe mechanical issue.

With Linc now eying a horizontaldevelopment program at Umiat, the com-pany no longer plans to flow test UmiatNo. 18, saying it is more important to learnhow horizontal wells flow at the field.

While drilling Umiat No. 18, Linc col-lected some 300 feet of core samples,which the company described as “drippingoil.” Having completed an analysis inHouston, the company now says the sam-ple indicated “outstanding rock properties”for a lighter oil reservoir, including 16-18percent porosity, air permeability of 70-270 millidarcies and “friable” (or soft)sandstones that Linc believes is “preferredfor optimal oil flow.”

More valuable?The results of this initial analysis have

also convinced Linc that the Lower grand-stand reservoir is “completely saturatedwith hydrocarbons,” the company said in astatement.

“We have captured many learningsfrom last year and confidently approachthis winter’s drilling program with theknowledge and expertise to successfullyachieve our current goals,” Linc EnergyCEO and Managing Director Peter Bondsaid in a statement. Among the goals forthis year, he added, is to flow oil from hor-izontal wells, which he said could poten-tially move some of the “probable”reserves at the field into the “proved” cat-egory.

Considered among the largest undevel-oped oil fields in Alaska, Umiat is believedto hold more than 1 billion barrels of oil inplace. In September 2012, the consultingfirm Ryder Scott Co. LP estimated the fieldcontains reserves of 154.5 million barrelsof proved and probable (P2) oil equivalentand 194 million barrels of proved, proba-ble and possible (P3) oil equivalent, with“probable” meaning at least a 50 percentchance of actual recovered volumes meet-ing or exceeding the P2 estimate, and“possible” meaning at least a 10 percentchance of actual recovered volumes meet-ing or exceeding the P3 estimate.

Those reserves are more valuable sinceAlaska revised its oil production tax earli-er this year, according to a recent thirdparty valuation Linc included with itsdrilling plans.

According to Ryder Scott, the 154.5million barrels of oil equivalent of P2reserves at Umiat now has a net presentvalue (at 10 percent return) of $2.465 bil-lion, up 65 percent from a net present valueof $1.496 billion estimated before thechanges to the tax code.

“We see this legislation as a win-win

for the citizens of Alaska and for LincEnergy,” Bond said in a statement. “Theultimate addition of 50,000 barrels per dayto the (trans-Alaska oil) pipeline as well asthe utilization of multiple Alaskan contrac-tors employing hundreds of Alaskan citi-zens presents a significant positive eco-nomic impact.”

In August 2013, Linc sold “rights tocertain oil and gas tax credits” from theState of Alaska to the investment firmApollo Investment Corp. for some $24.7million.

Another snow roadAs it did this past winter, Linc plans to

construct a 102-mile snow road this com-ing winter to connect the remote Umiatdrilling operation to the Dalton Highway.

With the rig and associated equipmentalready stacked near the drilling location,though, Linc will be able to begin drillingas soon as it can build shorter in-field iceroads.

The company described the drilling andtesting of Umiat No. 23H as its “proposedminimum program,” and described theUmiat No. 24H well as “a good secondoption.”

Umiat No. 24H was not among the welllocations Linc previously permitted at thefield.

The U.S. Navy discovered and delineat-ed Umiat with 12 wells drilled between1946 and 1979. Umiat No. 18 was the firstwell drilled since modern technology andhigher prices led explorers to investigatewhether the complex Umiat reservoir —which is shallow, low pressure and partial-ly buried in permafrost — could now bedeveloped economically.

Linc had previously said it intended tobring Umiat online by late 2017, butrecently told Petroleum News it “plans toaggressively develop this field once com-merciality is determined.” �

22 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

provide specialized airborne support to further Fairweather’s remote sensing and real-time scientific data collection capabilities, and offer greater efficiency to oil and gasexploration and production efforts through the ability to share assets and programmingcosts between projects.

Tulugaq’s operations are bolstered by the purchase of a new Diamond DA42 optional-ly manned aircraft outfitted with live streaming high-definition video, infrared and ultra-high resolution digital cameras. Future integration will include the addition of multispec-tral sensors. Tulugaq is one of the few operators of the DA42 in the U.S. and the onlyoperator in Alaska. Originally designed for government work, the DA42 is designed to col-lect data in harsh weather and no-light conditions. The aircraft’s low profile and quietoperation allows Tulugaq to conduct complex missions without disturbing the Arctic’smany species of protected wildlife.

Tulugaq flight operations will be performed by an Alaska team with more than 40,000hours of flight experience in Alaska and more than 2,000 hours of manned andunmanned flight experience worldwide. For more information visit www.fairweather.com.

Trimble receives UAA 2013 Alumni of Distinction Award Stephen Trimble of URS Corp. was recently honored with the UAA Alumni of

Distinction Emerging Leader Award. UAA describes the nominees as alumni who have made a significant impact on their

industry or profession or contributed to the community, and have strived to make a differ-ence in the lives of others.

Trimble has built a career on connecting the dots and bringing people together. Heserves as a political appointee on three commissions for the State of Alaska: the AlaskaArctic Policy Commission, Alaska Minerals Commission and the Alaska Emerging EnergyTechnology Fund Advisory Committee. He also serves as a trustee for the NatureConservancy, as chair of the UAA Geological Sciences Advisory Board, co-chair of the UAACollege of Arts & Sciences Advisory Board and president of the Gold Cord DevelopmentCorp. Trimble is also currently involved in the development of the state’s first Arctic policy,advising the governor and the Legislature on ways to mitigate constraints on the devel-opment of minerals in the state, advising the state in funding emerging energy technolo-gy projects, ensuring the natural wealth and vast landscapes of Alaska remain healthy forfuture generations and advising the university on strategic matters in the college anddepartment of which he is an alum.

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

continued from page 20

OIL PATCH BITS

continued from page 1

UMIAT DRILLINGThe U.S. Navy discovered anddelineated Umiat with 12 wellsdrilled between 1946 and 1979.

PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013 23

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license, a total of 14 exploration wells havebeen drilled in the basin, starting in 1953.One well, the Moose Creek Unit No. 1,drilled in 1963 near the future site of theRutter and Wilbanks well, encountered gasand water at a depth of 5,430 feet, but pro-duction testing was not conducted. And,like the Rutter and Wilbanks well, this wellencountered subsurface overpressure at adepth of 6,075 feet.

The Salmonberry Lake Unit No. 1 welldrilled in 1963 to the north of the newexploration license area encountered multi-ple zones with high contents of organic car-bon and with associated methane gas atdepths ranging from 2,600 feet to 3,900feet.

The Ahtna Inc. No 1 well drilled in 1979near the village of Gulkana, to the northeastof the exploration license area, encountereda trace of gas in one subsurface zone.

Earlier licenseThe Rutter and Wilbanks Glennallen

well was an offshoot of an exploration pro-gram initiated in 2000 when AnschutzExploration Corp. obtained a state explo-ration license in the Copper River basin.That license included the area of the newAhtna license but covered a much largeracreage of state land. In addition to the ter-ritory included within the state explorationlicense, Anschutz’s area of explorationinterest included some Ahtna land.

Forest Oil became a 50-50 partner withAnschutz in the Copper Valley explorationventure; Rutter and Wilbanks, together withits partner Delphi, also bought into the proj-ect. Some 2-D seismic was shot within theexploration area.

In 2005, with the exploration license dueto expire, Forest Oil and Anschutz success-fully converted a part of the license area rel-atively close to Glennallen to state leases.And, at about the same time, Rutter andWilbanks started its ill-fated drilling projecton Ahtna land.

Pacific Energy subsequently boughtout all of Forest Oil’s Alaska properties,including the Copper River basin leases.However, Pacific Energy later becamebankrupt. The Division of Oil and Gashas told Petroleum News that the leasessubsequently terminated because of thenon-payment of lease rents. �

continued from page 19

AHTNA LICENSE

Ahtna’s Tolsona exploration license encompasses state land just west of where Rutter and Wilbanks drilled its Ahtna 19-1 gas explorationwell between 2005 and 2009.

AH

TNA

IN

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24 PETROLEUM NEWS • WEEK OF OCTOBER 6, 2013

to doubt the accuracy of the statement onthe BOEM website.

BP has been working with govern-ment officials on how to proceed withLiberty, located on federal leases in shal-low water, about 20 feet deep, in theBeaufort Sea about six miles offshore and15 miles east of Prudhoe Bay.

In December 2012, the BOEM’s sisteragency, the Bureau of Safety andEnvironmental Enforcement, granted BPa two-year “suspension of production”for Liberty unit leases OCS Y-1585 andY-1650.

The agency gave the company untilDec. 31, 2014, to submit a new develop-ment and production plan for the unit,and cited the end of 2020 as the goal forfirst oil.

Back to initial ideaBP originally had hoped to put Liberty

into production in 2011.Those plans, however, crumbled amid

technical problems with the custom rigParker Drilling Co. built for the project,as well as federal regulatory complica-tions apparently stemming from theDeepwater Horizon disaster in the Gulfof Mexico in April 2010.

Today, the gigantic rig remains idle ona pad at BP’s Endicott field. The pad waswhere BP had planned to drill what it saidwould be the longest extended-reachholes ever attempted to tap the offshoreLiberty reservoir.

BP had said drilling these superwellsfrom land was the best approach.

But now, the company has returned toits initial idea of constructing a gravelisland at Liberty with production facili-ties and a buried subsea pipeline to carryoil to shore.

That’s what BP did for its Northstarfield, which sits in federal and statewaters northwest of Prudhoe Bay.

150 million barrelsBP drilled and tested Liberty No. 1,

the discovery well, in early 1997.The company’s most recent publicly

stated resource estimate for the Libertyfield is “approximately 150 million bar-rels of recoverable, high-quality lightoil.”

Proceeding with an artificial produc-tion island offers some difficult chal-lenges. Questions will be raised about thepotential impact to bowhead whales,which Native hunters pursue for food.Also, a unique kelp bed known as theBoulder Patch is in the vicinity ofLiberty.

The fate of the Liberty drilling rigremains undecided, Patience said.

In its June 2012 announcement, BPsaid it decided against extended-reachdrilling after doing “a detailed 18-monthreview of the rig systems, an analysis ofthe project’s risk and economics, and anassessment of the evolving regulatoryframework.”

The rig needed substantial modifica-tions to its mud, hydraulics, pipe han-dling, heating and other systems, BP said.

Retrofitting the rig is now seen as toocostly, Patience said.

In a Nov. 20, 2012, letter to the BSEE,the company said recovery from theLiberty leases could be as much as 15percent higher using “development con-cepts” other than ultra extended-reachdrilling.

That letter said BP already had spentin excess of $1 billion toward develop-ment of the Liberty unit. �

0 5

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LIBERTY’S FATE

CO

URT

ESY

BP