Tight situation6 - TANK TRAILERS 22 - BOAT STORAGE 7 - CAMP 23 - WASTE ... he surge in exploration...

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Apache’s Hendrix tells RDC company’sCook Inlet seismic shoot under way.

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Proposed Thomson pad layout

ExxonMobil has submitted this proposed central pad layout to theCorps of Engineers as part of its application for Point Thomsonfacilities and pipeline work. See story on page 13.

Tight situationAlaska oil explorers hit the limits on winter drilling rig availability

By ALAN BAILEY & KAY CASHMANPetroleum News

The surge in exploration activity planned forAlaska this winter has placed a major strainon the supply of drilling rigs suitable for use in thedemanding conditions of a long Arctic winter. Atlast count four companies with exploration drillingplans — Linc Energy, Savant Alaska, UltraStarExploration and Great Bear Petroleum — had yetto sign contracts for drilling rig use. And given therelatively small inventory of Arctic rigs it seemshighly improbable that all of these companies willend up drilling in the coming months, assumingthat companies with rig contracts do in fact pro-ceed with their planned drilling.

Three other companies, Repsol, Brooks RangePetroleum and Pioneer Natural Resources have

seven rigs under contract for this coming winterexploration season: Repsol expects to drill 12wells; Brooks Range, two wells, plus re-enter athird; and Pioneer, two wells.

Nabors operates 12 rigsOn Nov. 29, David Hebert, general manager of

Nabors Alaska Drilling, talked to Petroleum Newsabout some of the issues involved in supplying rigsfor Arctic Alaska exploration. Nabors currentlyoperates 12 rigs that are suitable for Arctic use andthat are in a fully operational status, Hebert said.An additional Nabors rig on the Kenai Peninsulahas not been winterized for the Arctic.

Two of the Arctic rigs are workover rigs for in-field use, while another has a design that is not

see RIG DEMAND page 18

Mackenzie project livesNWT premier reports ‘some progress’ on fiscal issues; Imperial confirms ‘dialogue’

By GARY PARKFor Petroleum News

Canada’s Mackenzie Gas Project has received afresh infusion of hope with confirmation thatdiscussions on a fiscal framework are under waybetween project leader Imperial Oil and the Canadiangovernment.

The election in May of a majority federal govern-ment under Prime Minister Stephen Harper is viewedas the spark that has ended what Imperial spokesmanPius Rolheiser said was a “temporary hiatus” in thedialogue.

Bob McLeod, newly elected premier of theNorthwest Territories, said he understands “someprogress” has been made.

He said the Aboriginal Pipeline Group, which hasbeen offered a one-third equity stake in the proposedMackenzie Valley gas line, and its members haveheld meetings with a number of federal governmentcabinet ministers.

“They seem to have received some positive sig-

see MACKENZIE LIVES page 20

The study, which forecast Mackenzie gascan start flowing when prices rise above

US$5.50 per million British thermalunits, said the Arctic gas will be needed

regardless of the projected growth ofshale gas production.

Co-op members objectCommittee wants more information as Naknek Electric works through bankruptcy

By WESLEY LOYFor Petroleum News

M embers of a troubled Southwest Alaskaelectric power cooperative have raised con-cerns about the utility’s proposed bankruptcy reor-ganization plan.

Naknek Electric Association in September 2010was forced to file for Chapter 11 protection fromcreditors due to complications with a geothermalenergy program.

A committee representing the interests ofNaknek Electric members on Nov. 28 filed a six-page objection to the co-op’s disclosure statementfor its reorganization plan. The filing was in

advance of a scheduled Dec. 1 hearing on the planin U.S. Bankruptcy Court in Anchorage.

The members committee raised concerns aboutthe possibility of the co-op continuing with itsgeothermal drilling project, and the risks this couldpose to the utility and to ratepayers.

see CO-OP OBJECTIONS page 20

A big worry for the co-op, and for themembers, is retaining the utility’s majorcustomers, which could elect to generate

their own power if rates increasesignificantly.

Spartan 151 jack-up drilling rigarrives safety in Port Graham

The only jack-up rig in Cook Inlet is now in hibernation forthe winter.

Furie Operating Alaska LLC, formerly Escopeta Oil Co.,brought the Spartan 151 into Port Graham on ThanksgivingDay, according to Furie Strategic Officer Steve Sutherlin.

The rig will spend the winter getting light maintenance andrepairs at the ice-free Cook Inlet port on the southern KenaiPeninsula before heading back out sometime next spring.

Furie used the rig this summer and early autumn to drill thefirst half of Kitchen Lights Unit No. 1, an offshore explorationwell in the upper Cook Inlet. The company suspended opera-tions at 8,805 feet on Oct. 28, but plans to drill to a total depthof about 16,500 feet.

—ERIC LIDJI

BRPC plans 3 Mustang wells innew Southern Miluveach unit

A joint venture led by Brooks Range Petroleum Corp. couldcomplete as many as four wells this winter at its North Tarnprospect on the central North Slope of Alaska.

In addition to re-entering a sidetrack started this past winter,the local independent operating arm of Kansas-based AlaskaVenture Capital Group plans to drill as many as three wells todelineate the prospect on the western boundary of the KuparukRiver unit.

The Mustang exploration program would take place fromthe North Tarn ice pad that Brooks Range Petroleum plans tobuild in its newly formed the Southern Miluveach unit.

The company expects to use Nabors rig 7ES for the pro-gram.

Brooks Range Petroleum drilled the North Tarn No. 1 wellthis past winter and began drilling the North Tarn No. 1-A side-track on leases farmed-in from Eni Petroleum.

The company expects to begin construction soon on an iceroad running approximately four miles from an existing gravelroad in the Kuparuk River unit to the to-be-built North Tarn icepad, and plans to mobilize its camp and drilling rig toward theend of the year.

In early January, Brooks Range Petroleum plans to spendsome 15 days re-entering and completing North Tarn No. 1-A

see MUSTANG WELLS page 19

http://www.PetroleumNews.com/

2 PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011

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

EXPLORATION & PRODUCTION

NATURAL GAS

5 Record number of vessels transit Arctic

9 Europe — a loosening link to oil prices

6 Potential Alaska state and federal oil and gas lease sales

PIPELINES & DOWNSTREAM

LAND & LEASING

FINANCE & ECONOMY

12 BP Alaska involved in big EPA settlement

Subsidiaries agree to pay $426,500 penalty, arrange‘financial assurance’ to close and clean up contaminated industrial sites

13 Corps public notices Thomson application

Comments due Jan. 3 on ExxonMobil proposal for facilities, pipeline project; construction projectedto begin winter of 2012-13

INTERNATIONAL

6 Deep Creek on hold pending Hilcorp sale

Alaska Division of Oil & Gas, Cook Inlet Region Inc.,agree to delay discretionary contraction until 6 months after sale or Sept. 1

7 When is an OCS commitment a commitment?

BSEE publishes appeal decision that agency says clarifiesconditions for extending offshore lease term through commitment to produce

8 Black & Veatch study recommends stubs

Natural gas off-take stubs would be built as line from Alaska North Slope is built; activated when commercial agreements reached

4 Cook Inlet energy projects under way

RDC annual conference hears updates from Apache, Buccaneer, Furie, Cook Inlet Energy, Enstar, CINGSA and CIRI

5 Tensions simmer in Syncrude ranks

Operator and largest shareholder unable to agree on timing for C$15 billion expansion of world’slargest synthetic crude plant

contents

12 November production up 6% from October

17 Groups appeal Shell’s Beaufort air permit

15 Trio secures Newfoundland parcels

15 Evaluation of VMT remote control planned

11 Chart: Alaska's Average Daily Oil and NGL Production Rate 1960 - 2010

11 Chart: Alaska Oil Industry Employment Statewide and North Slope Borough 2000-2010

Spartan 151 jack-up drilling rig arrives safety in Port Graham

BRPC plans 3 Mustang wells in new Southern Miluveach unit

ON THE COVERTight situation

Alaska oil explorers hit the limits on winter drilling rig availability

Mackenzie project lives

NWT premier reports ‘some progress’on fiscal issues; Imperial confirms ‘dialogue’

Co-op members object

Committee wants more information as Naknek Electric works through bankruptcy

reach new horizons.

SIDEBAR, Page 18: Four-month jobs tough sell

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http://www.ukpik.com/

PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay Z-116 BPDreco 1000 UE 16 (SCR/TD) Prudhoe Bay 01/11i BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD4-03 ConocoPhillipsAC Mobile 25 Prudhoe Bay 04-350 BPOIME 2000 141 (SCR/TD) Kuparuk 3H-34 ConocoPhillipsTSM 7000 Arctic Wolf #2 In Nisku, AB Available

Kuukpik 5 Standbye, waiting on ice road North Slope Boroughconstruction to Walakpa #11

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableAC Coil Hybrid CDR-2 Kuparuk 2K-28A ConocoPhillipsDreco 1000 UE 2-ES Prudhoe Bay Stacked out AvailableMid-Continental U36A 3-S Prudhoe Bay Stacked out AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay X-22A BPEmsco Electro-hoist 7-E (SCR-TD) Prudhoe Bay DS12-27A BP Dreco 1000 UE 7-ES (SCR/TD) Milne Point MBS BPDreco 1000 UE 9-ES (SCR/TD) Has been released by Brooks Range Available

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

will go to Oooguruk for exploration drilling in JanuaryAcademy AC electric Heli-Rig 106-E (SCR/TD) Stacked at Deadhorse AvailableOIME 2000 245-E Oliktok Point OP12-01 ENI

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

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site U-12AL1 BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site 6-12B BP Ideco 900 3 (SCR/TD) Kuparuk Well 2T-03 ConocoPhillips

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

North Slope - Offshore

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

Nabors Alaska DrillingOIME 1000 19-E (SCR) Oooguruk ODST-39 Pioneer Natural ResourcesOIME 2000 245-E Oliktok Point OI13-03 ENIOilwell 2000 33-E Prudhoe Bay Stacked out Available

Doyon DrillingSky Top Brewster NE-12 15 (SCR/TD) Spy Island SP27-N1 ENI

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Stacked out south of Tyonek Available

Cook Inlet EnergyAtlas Copco RD20 34 Undergoing winterization Cook Inlet Energy

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

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Stacked Marathon Yard Available

Nabors Alaska DrillingContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked Available Academy AC electric Canrig 105-E (SCR-TD) Kenai CLU-1 CINGSARigmaster 850 129 Kenai Stacked out Available

Cook Inlet Basin – Offshore

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

XTO EnergyNational 1320 A Coil tubing cleanout planned off Platform XTO

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

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

Upper Cook Inlet KLU#1

Mackenzie Rig StatusCanadian Beaufort Sea

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

Central Mackenzie Valley

Akita/SAHTUOilwell 500 51 Has left the NWT Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of December 1, 2011.

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts*November 23 November 18 Year Ago

US 2,000 2,001 1,687Canada 484 487 415Gulf 38 36 20

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

http://www.conocophillips.com/

By KRISTEN NELSONPetroleum News

The Resource Development Councilincluded a fairly complete CookInlet update on the program of its annualconference.

From oil and gas, through wind andunderground coal gasification, to naturalgas storage, companies involved in thecurrent upsurge in Cook Inlet activitieswere on the podium Nov. 17.

ApacheApache Corp., Cook Inlet’s newest big

player, with more than 800,000 acres, wasrepresented by its newly named Alaska

general manager,John Hendrix, whotold the RDC audi-ence he remembersCook Inlet in itsheyday, before thediscovery ofPrudhoe Bay. But bythe time he graduat-ed from college andwent to work forSchlumberger, the work was on the NorthSlope.

“All the focus, all the money, weregoing into Prudhoe Bay,” Hendrix said.

Apache is focused on the historic oilplay in Cook Inlet and is looking for oil“with new 3-D seismic technology,” hesaid.

“We feel there’s potential out there.

We’re more focusedon oil — gas willcome along with theoil … but we’re oilfocused.”

Apache hasbegun a three-year12,000-square mile3-D seismic shoot inCook Inlet using anew nodal technolo-

gy. Hendrix said there are 220 people on

the west side of Cook Inlet deployingnodes with the first actual shoot doneNov. 11. He said crews will work untilmid-December and then start back upJan. 15. Twelve small drill rigs will beused to drill the holes onshore; offshoreair guns will be used.

In all of its operations, Apache shootsa lot of seismic, Hendrix said.

“We’re a very seismic, geo-scienceoriented company … and you have toknow the data before you drill. You gath-er the data, you put your strategy forwardand then we drill.”

He also said that Apache’s “chairman,in a number of meetings I’ve been withhim, he doesn’t want us to stop drillinguntil we hit bedrock. We don’t want any-body to come behind us and turn over astone and find there’s oil reserves; wewant to make sure when we drill, that weleave no … stone untouched.”

BuccaneerJim Watt, president and COO of

Buccaneer Alaska, said Buccaneer seesmajors moving out and independentsmoving into Cook Inlet, “normal for a lotof maturing basins.”

But, he said, Cook Inlet is an underex-plored basin where recent U.S.Geological Survey reports show “tremen-dous upside” and where there is existinginfrastructure, a strong local market andattractive natural gas prices.

Buccaneer has some 66,000 acresonshore and at one prospect, Kenai Loop,just north of the city of Kenai, it “leased,permitted and drilled our first well withinnine months.” That natural gas well willbe on production in December, he said.Buccaneer has a contract with Enstar fordelivery beginning in April, “but we hopewe will sell in the spot market” beforethen, Watt said.

At West Nicolai on the west side of

Cook Inlet Buccaneer expects to acquireseismic in 2012 and drill in 2013.

And at West Eagle on the southernKenai Peninsula Buccaneer is reprocess-ing seismic and would like to drill in2012.

The company also has offshoreprospects and has completed purchase ofthe Endeavour jack-up drilling rig for usein Cook Inlet. Buccaneer is also lookingat the potential for liquefied natural gasfor use in Alaska. Watt said “we feel wecan move LNG from the Cook Inlet toFairbanks and be very competitive.”

Furie/EscopetaDrilling engineer Bob Laule, filling in

for Furie Operating Alaska (formerlyEscopeta Oil) President Ed Oliver, gave abrief update.

“Furie came; wedrilled; and wefound gas,” he said.

He said the com-pany got a late startand wasn’t able tocomplete its well,but drilled to 8,800feet and did “sometesting which gaveus some very goodindications of gas in the Sterling and inthe Beluga formations.”

Laule said they will re-enter the wellnext spring, approximately mid-April anddrill to total depth, “set a couple of extraadditional stands of pipe and go into atesting program.”

Then Furie will drill a second well.Laule said he didn’t know if they’d get totesting the second well next year.

Cook Inlet EnergyJR Wilcox, president of Cook Inlet

Energy, said his company “is one of thefew small independent oil producers inthe state.” Cook Inlet Energy re-estab-lished production after Pacific Energydeclared bankruptcy in 2009.

Production was shut down inSeptember and Cook Inlet Energy wasapproved as successor operator inDecember, hired a staff and “within abouttwo weeks we had some productiongoing.”

Over the next four months the WestMcArthur River unit was restarted and


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ThinkingRESOURCEFULRESOURCEFUL

Thinking


Cook Inlet energy projects under wayRDC annual conference hears updates from Apache, Buccaneer, Furie, Cook Inlet Energy, Enstar, CINGSA and Cook Inlet Region Inc.

JOHN HENDRIX JIM WATT

see INLET ENERGY page 14

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Tensions simmer in Syncrude ranksOperator and largest shareholder unable to agree on timing forC$15 billion expansion of world’s largest synthetic crude plant

By GARY PARKFor Petroleum News

An apparent rift among owners ofSyncrude Canada, the world’slargest single synthetic crude operation,is stalling plans to increase capacity by250,000 barrels per day to 600,000 bpdby 2020.

First announced in February 2010, theC$15 billion expansion proposal hasoperator Imperial Oil (69.6 percentowned by ExxonMobil) and CanadianOil Sands, the largest stakeholder, atodds over the timing.

The original plans called for an initial50,000 bpd “debottlenecking” followedby a two-phase hike in bitumen produc-tion of 100,000 bpd each in 2014 and2020, placing about 115,000 bpd ofexcess raw bitumen supply on the openmarket.

But a spokesman for Imperial, a 25percent owner, has told reporters that hiscompany no longer believes the expan-sion will take place this decade, althoughhe said it would be “premature to talkabout specific project plans or timing orsequencing.”

However, he said Imperial remainscommitted to “the economic develop-ment of the entire resource at Syncrude.”

A spokeswoman for Canadian OilSands, whose stake is 36.74 percent,countered that all of the partners agreedto the last strategic plan, suggesting thatImperial was simply “putting out theirown view.”

She said there has been talk aboutcooperation between Syncrude and thenearby Kearl project, a joint venture byImperial and ExxonMobil to build a110,000 bpd mine at a cost of C$10.9 bil-lion.

The spokeswoman said the discus-sions have involved sharing labor andsome of the project management, but theImperial spokesman insisted his compa-ny views Syncrude and Kearl separately.

The other Syncrude partners areSuncor Energy 12 percent, China’sSinopec 9.03 percent, Nexen 7.23 per-cent, Murphy Oil 5 percent and MocalEnergy 5 percent.

ExxonMobil hired 4 years agoFollowing a series of unplanned out-

ages, the Syncrude partners hiredExxonMobil four years ago to improveoperations and reduce per barrel costs.

Currently, two processing units at theupgrading plant are offline, including a100,000 bpd coking unit.

Imperial insists that its immediate pri-ority is to improve reliability of the baseoperations.

FirstEnergy Capital analyst MichaelDunn said in a research note he hasreduced capital spending forecasts forCanadian Oil Sands after indications byother partners — “either subtly or direct-ly” — that expansions will not come online this decade.

“Since major expansions requireunanimous partner approval, we havereduced our cap-ex estimates materiallyin the 2012 to 2015 time frame.” Dunn

wrote.He said a spending cut could be posi-

tive for Canadian Oil Sands by easing thestrain on its balance sheet and allowing itto maintain dividend payments.

Suncor has been less than emphaticwhen asked about the future of itsSyncrude stake and the role of Sinopec,which acquired ConocoPhillips’ 9.03percent interest for C$4.65 billion lastyear, has yet to take shape.

Export vs. value-addedMost observers believe Sinopec wants

to pursue exports of raw bitumen fromSyncrude to its refineries in China,which is inconsistent with the Albertagovernment’s goal to see more of thevalue-added end of the oil sands remainin Alberta. But achieving the province’sobjective of upgrading 66 percent ofbitumen production compared with 58percent last year is not a simple matter.

Todd Hirsch, senior economist at ATBFinancial, said that building morerefineries and upgraders in Albertawould satisfy those “who believe weexport too much raw resource when weshould keep those jobs at home.”

“But that doesn’t solve the main prob-lem of cost, which is the primary reasonindustry is not racing to build refineriesin Alberta,” he said.

Alberta currently has 1.2 million bpdof upgrading capacity and expects to add270,000 bpd by 2016, but it is likely to beoutstripped by the growth in bitumen out-put to 3 million bpd in 2016 from 1.6million bpd in 2010.

In the process, the cost of labor, steeland other materials is expected toincrease inflationary pressure, making anuneconomic aspect of the oil sands sectoreven more expensive.

C$5 billion upgrading projectThe biggest upgrading project on the

table is a C$5 billion joint venture byNorth West Upgrading and CanadianNatural Resources to build a 150,000 bpdrefinery near Edmonton in three equalstages.

The Alberta government has alreadyagreed to provide 37,500 bpd of feed-stock bitumen to the plant from its royal-ty-in-kind program.

North West Upgrading Vice PresidentJerry Crail said a final investment deci-sion is targeted for late this year or early2012 as the partners try to head off risingcapital costs.

He said a final plan is in place and pri-vate investors and financial institutionshave pledged funding.

Canadian Natural Resources, which isexpected to supply 12,500 bpd of bitu-men, has indicated it hopes to gain boardapproval for the project in 2012.

Crail agreed there are operational andfinancial risks associated with building arefinery, but noted that substantial workhas already been completed for initialconceptual studies and detailed engineer-ing is due to start in March 2012. �

INTERNATIONALRecord number of vessels transit Arctic

According to a report in the Barents Observer a total of 34 vessels transited theNorthern Sea Route along the Russian coast of the Arctic Ocean this year. Withshrinking Arctic sea ice cover, both the Northern Sea Route and the NorthwestPassage through the Canadian archi-pelago have started to become ice freeafter the summer ice melt. And Russiahas a fleet of nuclear powered ice-breakers to escort ships around itsroute, and assist with navigating theroute when the sea is not entirely icefree.

According to the Barents Observer, the sailing season along the Northern SeaRoute lasted five months this year, from the end of June to the end of November.

The route remained open about one month longer than has become the norm, withthe total of 34 vessels being a record for the number of vessels transiting the route ina single open water season, the Barents Observer said. Of those 34 vessels, 15 carriedliquid cargos, three carried bulk cargo, four carried salmon under refrigeration, twocarried general cargo and 10 sailed in ballast. Of particular note were the fact that asupertanker — the Vladimir Tikhonov — plied the route for the first time, and the75,600-tons-deadweight bulk carrier Sanko Odyssey became the largest bulk carrierever to use the route, the Barents Observer said.

According to the Voice of Russia website, developing the Northern Sea Route, theshortest marine route between Europe and the Far East, has become one of Russia’stop priorities in the far north. In September at the International Arctic Forum, RussianPrime Minister Vladimir Putin said that Russia is developing the Northern Sea Routeby expanding existing ports and building new ports along the route; upgrading thetransportation infrastructure in the region; and expanding the country’s icebreak-er fleet.

—ALAN BAILEY

According to the Barents Observer,the sailing season along the

Northern Sea Route lasted fivemonths this year, from the end of

June to the end of November.

Contact Gary Park through [email protected]

http://www.nascoinc.com/http://www.carlile.biz


LAND & LEASING

This week’s lease sale chartsponsored by:

Geokinetics

Potential Alaska state and federal oil and gas lease sales

Agency Sale and Area Proposed Date

DNR Beaufort Sea Areawide Dec. 7, 2011DNR North Slope Areawide Dec. 7, 2011DNR North Slope Foothills Areawide Dec. 7, 2011BLM NPR-A Dec. 7, 2011DNR Cook Inlet Areawide spring 2012DNR Alaska Peninsula Areawide spring 2012DNR Beaufort Sea Areawide fall 2012DNR North Slope Areawide fall 2012DNR North Slope Foothills Areawide fall 2012BLM NPR-A 2012BOEM 2013 Cook Inlet (special interest)BOEM Beaufort Sea 2015BOEM Chukchi Sea 2016

Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, manages leasing inthe National Petroleum Reserve-Alaska; BOEM, U.S. Department of the Interior’s Bureau of Ocean

Energy Management (formerly Minerals Management Service), Alaska region outer continental shelfoffice, manages sales in federal waters offshore Alaska; DNR, Alaska Department of Natural Resources,Division of Oil and Gas, manages state oil and gas lease sales onshore and in state waters; MHT, Alaska

Mental Health Trust Land Office, manages sales on trust lands.

� L A N D & L E A S I N G

Deep Creek on holdpending Hilcorp saleAlaska Division of Oil & Gas, Cook Inlet Region Inc., agree todelay discretionary contraction until 6 months after sale or Sept. 1


The Alaska Department of NaturalResources’ Division of Oil and Gasand Cook Inlet Region Inc., which jointlymanage Union Oil Company ofCalifornia’s Deep Creek unit, have agreedto delay any “discretionary contraction”of the unit “for a reasonable period oftime after close of the pending asset salebetween Union and Hilcorp EnergyAlaska, LLC.”

Division Director Bill Barron toldUnion in a Nov. 23 letter that because ofthe pending sale he will delay any discre-tionary contraction of the unit until sixmonths after the closing of Union’s saleof its Cook Inlet assets to Hilcorp or Sept.1, 2012, whichever occurs earlier.

The ninth plan of development for theDeep Creek unit is due Dec. 31, andBarron said he is extending the expirationdate of the eighth plan for the unit to coin-cide with the discretionary contractiondelay, making the ninth plan due the ear-lier of six months after closing of the saleor Sept. 1, 2012.

Sale announced in JulyThe sale of Union Oil’s Cook Inlet

assets was announced July 19. Union OilCompany of California parent Chevronand Hilcorp did not disclose financialterms, but said in a statement that thetransaction was expected to close by yearend pending customary regulatoryapprovals.

Assets in the sale include Union Oilcontracts and interests in the GranitePoint, Middle Ground Shoals, TradingBay and MacArthur River fields; interestsin 10 offshore platforms; interests inonshore gas fields including the Ninilchikunit and the Beluga River unit; and twogas storage facilities.

The sale also includes interests in theCook Inlet Pipe Line Co. and KenaiKachemak Pipeline LLC.

Unit formed in 2001The 20,000-plus acre Deep Creek unit

is on the southern Kenai Peninsula, somefive miles inland from Ninilchik, and pro-duces natural gas from the Happy Valleyparticipating area in the northern part ofthe unit. The division and CIRI approvedthe formation of the unit effective Dec.31, 2001. Union Oil is 100 percent work-ing interest owner in the unit. The divi-sion and CIRI approved formation of theHappy Valley participating Area Nov. 4,2004.

Alaska Oil and Gas ConservationCommission records show gas productionbegan in 2004; current production is from

seven completions. In its eighth plan of development, sub-

mitted in December 2010, Union said ithad no plans for any exploration drillingin the unit, but said it planned to continueefforts to farm out southern Deep Creekexploration acreage.

Barron said a ninth plan of develop-ment “must provide for the exploration ofthe unitized area and for the diligent andexpeditious drilling necessary for deter-mination of the unit area or areas capableof producing unitized substances in pay-ing quantities in each and every produc-tive formation. The plan must be as com-plete and adequate as necessary for time-ly exploration and development of theremaining unit area outside the HappyValley Participating Area, and must spec-ify the number and locations of any wellsto be drilled and the proposed order andtime for such drilling.”

Several potential accumulationsIn a December 2004 decision denying

a request by another leaseholder toexpand the unit, the division said“Unocal’s initial interpretation indicatedthat the unit area may encompass severalpotential hydrocarbon accumulations andexploration to date has confirmed thepresence of the Happy Valley reservoir inthe northern unit area.”

The 2004 decision said that since theformation of the Deep Creek unit, thecompany drilled 10 wells and acquired105 miles of proprietary seismic data.ConocoPhillips previously acquired fiveseismic lines over the unit area.

Current Alaska Oil and GasConservation Commission records show13 Happy Valley wells drilled between2003 and 2009; two of the 13 are showingas suspended.

The division said it “agrees withUnocal’s assessment that the Deep CreekUnit may contain multiple accumula-tions,” but said in its 2004 decision thatthe only confirmed commercial produc-tion is from the Happy Valley reservoir.

It said “Unocal’s interpretation of thedata also indicates a potential accumula-tion south of the Happy Valley reservoirthat Unocal refers to as the Middle HappyValley Prospect,” and said that the com-pany had planned to drill two wells froma new pad to evaluate the prospect, and inMarch 2004 requested approval of a planto build a road and construct the HappyValley Middle Saddle Pad.

Neither the road nor the pad was con-structed and no Middle Happy Valley wellwas drilled. �

Contact Kristen Nelson at [email protected]

http://www.alutiiq.com/

By ALAN BAILEYPetroleum News

As illustrated by a long-standing disputebetween the State of Alaska and oilcompanies over delays in the developmentof the Point Thomson field on the NorthSlope, governments expect firms owningoil and gas leases on public lands to active-ly explore for and develop publicly ownedresources. And a recent “notice to lessees”published by the Bureau of Safety andEnvironmental Enforcement, or BSEE,illustrates something of the federal govern-ment’s expectations for activity by lease-holders on the federal outer continentalshelf.

On Nov. 15 the agency published anappeal decision over a request to extend theterms of some leases in the Gulf of Mexico.The decision will act as guidance over thecircumstances under which the term of anOCS lease may be extended, a procedureknown as a “suspension of production,”BSEE said.

“Suspensions can be granted to lease-holders to extend a lease past the primaryterm for oil and gas leases on the outer con-tinental shelf,” BSEE said. “Typically alease will have a primary term of five, eightor 10 years, depending on the water depth.”

The appeal decision published by BSEErelated to three leases owned byExxonMobil Corp. and Statoil Gulf ofMexico LLC in an area of the Gulf ofMexico known as Walker Ridge.

Due diligenceUnder the terms of the Outer

Continental Shelf Lands Act, a lessee hasthe right to explore for, develop and pro-duce oil and gas in an OCS lease, providedthat the lessee shows “due diligence” indoing so. If a lessee requests a lease termextension the federal government deter-mines whether the due diligence criterion isbeing met by assessing what is termed thelessee’s “commitment to produce,” a criteri-on that requires the lessee to have complet-ed sufficient exploration and appraisalwork within the leased land to enable adecision to proceed to the production of oiland gas.

Apparently, ExxonMobil and Statoilpurchased the Walker Ridge leases in June1998. About three years later the companiesabandoned an initial plan to drill into rocksof Miocene age in their leases afterexploratory wells in neighboring leases hadfailed to encounter oil in equivalent rockunits. But in December 2006, prompted by

some nearby oil discoveries in older anddeeper Paleocene rocks, the companiesdrilled a well into the Paleocene withintheir Walker Ridge leases and found oil.That well was completed in April 2007, bywhich time the leases were in the ninth yearof their 10-year terms.

In February 2008, with only a fewmonths of life left in the leases, MMSapproved lease unitization, withExxonMobil as operator. At about the sametime ExxonMobil started drilling a secondwell in the new unit, again finding pro-ducible oil.

That second well was completed in June2008. And under federal regulationsExxonMobil had 180 days from that date toapply for an extension of the lease beyondthe original lease termination date.

Extension requestIn October 2008 the company duly

applied for a seven-year lease extension, “toallow for proper development,” the appealdecision says. The company said that thistimeframe would accommodate a develop-ment concept in which production wellsfrom the new unit would be tied back tofacilities to be developed by Chevron forsome adjacent fields.

However, ExxonMobil’s extensionapplication expressed some caution aboutwhether Chevron’s development wouldactually take place. The company said thatit was also considering other options for itsown field, including the possibility of astandalone development, but that it couldnot commit to a standalone developmentusing the information that it currently hadavailable.

In February 2009 MMS turned down theapplication for the lease extension, sayingthat, because ExxonMobil’s plan dependedon Chevron’s facility development, a devel-opment not yet under way and not subjectto any form of agreement between the twocompanies, ExxonMobil’s commitment toproduce claim was not based on activitieswithin the company’s control.

Decision appealedFollowing an appeal by ExxonMobil,

the Interior Board of Land Appeals, theDepartment of the Interior’s internal landdecision review body, subsequently over-turned the MMS decision, saying that anagreement between ExxonMobil andChevron to share the cost of front-end engi-neering design for shared field facilitiesdemonstrated a commitment to produce.The board also said that MMS had previ-

ously granted lease extensions in situationswhere there was even less evidence for that“commitment to produce” criterion.

In February 2010 MMS asked RobertMore, the director of Interior’s Office ofHearings and Appeals, to review the board’sdecision — the board is a section within theOffice of Hearings and Appeals. And onMay 31 2011, More issued his review deci-sion, upholding the original MMS decisionto decline the lease extension. It is this deci-sion that BSEE has now issued as guidanceover the circumstances under which leaseextensions may be granted.

Lack of commitmentMore said that the lack of commitment

by ExxonMobil to either a tie-in to the pro-posed Chevron facility or to a standalonefield development demonstrated, at most, acommitment to development, but not therequired commitment to produce.Moreover, under federal regulations, therequested lease extension of seven yearsexceeded a five-year extension limit, hesaid.

The signing of the agreement betweenExxonMobil and Chevron to share the costof developing the facility engineeringdesign came after the date by whichExxonMobil had to establish a commitmentto produce from its unit, More said. And,although by May 2009 MMS had satisfieditself that Chevron was going to build itsfacility for its fields, at that pointExxonMobil had not come to an agreementwith Chevron for the use of that facility, norhad ExxonMobil committed to a standalonedevelopment should negotiations with

Chevron fail, More said. Under the terms ofthe Outer Continental Shelf Lands Act,negotiations to use a third-party productionfacility are not considered to be field devel-opment, he said.

More also said that previous MMS deci-sions over lease extensions did not set aprecedent for the decision under appeal. Headditionally said that the Interior Board ofLand Appeals had erred in not referring theboard’s decision back to MMS for verifica-tion that the decision met the national inter-est in resource development on publiclands.

Agency dutyOn Nov. 15, in commenting on the

appeal decision, Michael Bromwich, thethen director of BSEE, emphasized hisagency’s duty to ensure appropriate devel-opment of public resources.

“BSEE takes its responsibilities astrustee of offshore public lands extremelyseriously,” Bromwich said. “The energyresources that are located on the outer con-tinental shelf belong to all American tax-payers, and BSEE’s responsibilities includeensuring that public resources are devel-oped in an expeditious and orderly way. TheOffice of Hearings and Appeals decisionhighlighted in this notice to lessees under-scores the need for lessees to take concretesteps to develop their holdings in a mannerthat is consistent with the terms of theirlease agreements.” �


Courtesy of Northrim Bank’s Partnershipwith the Alaska World Affairs Council

LOOK WHAT’S COMING!A very special series of speakers discussing

“Oil, Gas and Energy”

December 9, 2011 Jose Lima, Vice President of LNG, Gas Monetization & Wind Energy, Shell Upstream Americas – “Global LNG – A Shell View.”

January 20, 2012 Larry Persily, Federal Coordinator for Alaska Natural Gas transportation Projects. Presentation - “Alaska’s Natural Gas: Does any Country need it?”

February 3, 2012 Kevin Book, Managing Director, Research Clearview Energy Partners, LLC.

April 20, 2012 Lou Pugliaresi, President of the Energy Policy Research Foundation Presentation – “The Coming Renaissance in North American Oil & Gas.”

May 11, 2012 Edward Chow, Senior Fellow, the Energy & National Security Program, CSIS.Presentation – “Shifting the International Petroleum Landscape.”

For more information, please visit: alaskaworldaffairs.org

� L A N D & L E A S I N G

When is an OCS commitment a commitment?BSEE publishes appeal decision that agency says clarifies conditions for extending offshore lease term through commitment to produce

Contact Alan Bailey at [email protected]

http://www.amarinecorp.com/http://www.alaskaworldaffairs.org



A study by Black & Veatch for theAlaska Gas Pipeline Project Office,GPPO, is recommending that the bestway to provide local off-take from alarge-diameter natural gas pipeline wouldbe to install stubs during construction.

Kurt Gibson, GPPO director, said in aNov. 28 press release that installing stubsas the line is built would provide gas off-takes that “are both reasonable and adapt-able to community needs.”

The focus of the Alaska PipelineProject continues to be a line to commer-cialize Alaska North Slope natural gas,GPPO said.

Gibson said the Black & Veatch“study identified the possibility ofinstalling stubs at strategic locationsalong the route that could be activated —‘hot tapped’ — at some point in time aftercompletion of a big gas line.”

He said that “approach provides flexi-bility for communities, utilities and otherparties interested in accessing natural gasto enter into commercial agreements forobtaining gas on their own schedule.”

Capital costs for a community gas off-take system — not including the localdistribution system — were in the$150,000 to $200,000 range, per loca-tion, with an estimate of $50,000 to$75,000 per year in operation and main-tenance costs per location.

Two options consideredThe Black & Veatch report said GPPO

identified two potential options to facili-tate delivery of natural gas to small com-munities and industry: compressor sta-tion side stream and stub gas delivery.

There will be eight compressor sta-tions along the line to maintain gas pres-sure and they require natural gas atreduced pressures to fuel compressor tur-bines and other utilities, typically 600 psicompared to the 2,500 psi mainline oper-ating pressure.

Drawing off gas at compressor sta-tions would take advantage of thereduced pressure, but Black & Veatchsaid it found that “business and regulato-ry concerns” were likely to make suchdelivery points unfeasible. Also, such gaswould be available only to communities“within a feasible distance to a particularcompressor station.”

The other option studied, the use ofstubs, would include installation of stubsat points on the line identified for off-take during mainline construction.

A small diameter stub piece of pipe“would be welded on and tested duringconstruction of the pipeline. The stubwould not have live gas in it and its endlocation would be marked with a standardpipeline marker for future reference oncea commercial agreement has beenreached for the community the stubwould serve,” the report said.

Hot tappingOnce a local community or industry

reached a commercial agreement to buygas, the pipeline would need to be tapped.

“The hot tapping procedure wouldinvolve removing the stub cap and secur-ing an isolation valve to the end of thestub. Hot tapping equipment would thenbe connected to the isolation valve, the

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Black & Veatch study recommends stubsNatural gas off-take stubs would be built as line from Alaska North Slope is built; activated when commercial agreements reached

see PIPELINE STUDY page 10

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http://www.CCIIndustrial.com/

By BILL WHITEResearcher/writer for the Office

of the Federal Coordinator

A s occurred in Japan, the Arab oilembargo of 1973 hit European util-ities between the eyes. The six-monthembargo slashed world oil production byabout 4 percent. An assertive OPECpushed a doubling of world oil pricesfrom 1972 to 1975.

Western European demand for oilplunged 23 percent during those years.Europeans wanted new suppliers of ener-gy, and in natural gas they had somegood options.

Russia had giant gas fields lookingfor an export market. Norway had bignew discoveries in the North Sea. AndAlgeria, too, was home to some giantfields.

Gas trading was relatively new inEurope at the time. Belgium, Germanyand France were the first to import natu-ral gas, from a major Netherlands fieldcalled Groningen discovered in 1959.

In trying to figure out how to pricegas to provide a fair return as well as thefortune needed to develop the field andpipelines, the Dutch linked natural gasprices to the prices of substitute fuel oilsand insisted on long-term contracts.

Russia, Norway and Algeria adoptedthat pricing structure for similar reasons,and it persists today for much ofEurope’s pipeline-gas imports. Thosethree nations and their handful of mega-fields remain Europe’s top source of for-eign gas supplies. (Russia, Norway andAlgeria were the world’s No. 1, 2 and 5gas exporters last year, joined by Qatarand Canada in the No. 3 and 4 positions,with the Netherlands at No. 6. As for gaspricing in Europe, the United Kingdomgas market is more like North America’sthan continental Europe’s, as will be dis-cussed below.)

The price link to oil in Europe wasn’tas iron-clad as in Japan, however.Exporters discounted gas prices toreflect the cost of competing fuels —heavy fuel oil for industry and distillatefor power plants, the EIA said. Othernotable contract features: the gas desti-nation was locked in to prevent a buyerfrom diverting gas from a lower-pricedmarket to a higher-priced market theexporter also was serving — blockingunwanted competition — and the gasprice could get renegotiated periodically.

Since the pivotal economic year of2008, this decades-long system has beenunder attack by gas buyers.

The oil-gas price linkWith oil prices currently near historic

highs and the local economies wobbly,many European gas buyers are demand-ing price relief. They’re aiming theirfrustrations at Russia’s Gazprom, whosepipelines dominate the European gastrade.

The big European gas buyers areplaying tough. To show Gazprom theymean business, they have boosted theirspot and short-term buys of LNG, oftenfor lower prices than the pipeline gas.They’ve got a motivated LNG exporterin Qatar, which has far more capacity tomake LNG than it has buyers. Qatar willnegotiate its LNG price. Last year, Qatarsent some 40 percent of its LNG toEurope.

(Qatar gas sold for $15 to $16 per

million Btu in East Asia in June, whileselling for $9 to $12 in Europe thatmonth and $4.25 in Texas, according toArgus.)

European imports of LNG grew by 26percent last year, while pipeline-gasimports from Russia fell by 2 percent,the EIA said.

Gazprom is not powerless in this fight— long-term supply contracts are apotent weapon.

But Gazprom doesn’t want to jeop-ardize its European market share, whichunderpins its export business.



Europe — a loosening link to oil prices

� Part 3 of 4

In some cases Gazprom ischanging the basket of oil prices ituses, often adding spot gas pricesto the formula, so gas-compared-to-gas pricing is gaining a toehold

over gas-linked-to-oil pricing.

see EUROPE’S OIL LINK page 11

OFF

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valve would be opened, and the pipelinewould be tapped whilst in operation.With the isolation of the valve andremoval of the hot tapping equipment,the gas delivery location would be readyfor service,” the Black & Veatch reportsaid.

The stub would have to be extendedand a metering/regulating stationinstalled, consisting of three sectionswhere the pressure would be reduced inthree steps from the 2,500 psi on themainline to an outlet range of 125-300psi.

Four stages of gas heating would alsobe required.

Black & Veatch said the meter-ing/regulating sections would be prefab-ricated offsite and installed once the sitehas been prepared.

The estimated cost for the meter-ing/regulating station of $150,000 to$200,000 is based on discussions withequipment suppliers, prefabricators andcontractors who build equipment, thereport said. The estimate is also based onthe assumption that several meter-ing/regulating stations are built at thesame time, “and does not include anyline items for the stub, hot tapping oper-ations or the distribution system down-stream of the M/R station,” Black &Veatch said.

Heating value issueThe report said that in addition to the

difference between the mainline operat-ing pressure and gas pressures neededfor local distribution, the mainline gas“will likely have a heating value higherthan what is typically delivered to resi-dential customers.”

Based on available gas analysis pro-vided under the Alaska GaslineInducement Act, Black & Veatch said“The gas specification proposed fortransmission in the pipeline is relativelyuncommon in a number of its character-istics, namely the high calorific value ofthe gas and its low water content.” AGIAincluded “rich” and “lean” gas cases,with the rich gas having a heating valueof 1,118 British thermal units per cubicfoot and the lean case having a heatingvalue of 1,067 Btu.

Black & Veatch said parts of gas sys-tems in Alberta, Canada, and in the east-ern United States, have Btu content rang-ing from 1,000 to 1,110 Btu per cubicfoot without “significant issues” relatedto the high Btu content.

Black & Veatch also looked at vol-umes of potential gas usage by commu-nities along the pipeline in NorthernEconomics’ “In State Gas DemandStudy,” and estimated that the majorityof communities along the pipeline(Wiseman, Coldfoot, Stevens Village,Harding-Birch Lakes, Dot Lake,Tok/Tanacross/Tetlin, NorthwayJunction/Northway Village, Paxson,Gakona, Gulkana, Glennallen, CopperCenter, Willow Creek and Tonsina)would have average usage of less than 1million cubic feet per day. Big Delta,Delta Junction and Deltana are estimatedat 1 million cubic feet per day. Valdez isestimated at 7 million cubic feet per dayand Livengood at 9 million cubic feet perday.

Black & Veatch said it anticipates“that the small diameter stub size willallow for sufficient gas supply volumesfor all potential delivery point sitesexcept for Fairbanks or Anchorage.” �

continued from page 8

PIPELINE STUDY

Contact Kristen Nelson at [email protected]

http://www.akresource.org

In some cases Gazprom is changing thebasket of oil prices it uses, often addingspot gas prices to the formula, so gas-com-pared-to-gas pricing is gaining a toeholdover gas-linked-to-oil pricing. Usually, thenew price is good for a fixed period, suchas two or three years. This suits the buyers,who know that oil prices can fall as well asrise.

European buyers also are playing toughwith LNG suppliers, not only by some-times getting better prices than they payfor pipeline gas. Supply contracts areshorter — five to 10 years instead of per-haps 25-year terms from a few years ago.And new language is letting buyers divertcargos to other markets — such as the pre-mium-priced Japan spot market in 2011.

It’s unclear how loose the oil-price linkwill become for continental Europe gasprices. But Norway recently “switched asmuch as 30 percent of their contracted vol-umes to spot-market pricing,” the EIAsaid.

The British differenceNatural gas pricing in the United

Kingdom is different from pricing on thecontinent.

Natural gas is the top fuel source inGreat Britain, while in many Europeancountries gas is a mere sidekick to oil as anenergy source — in Germany gas was No.3 behind oil and coal last year.

Like North America, the gas market inthe U.K. developed over the past severaldecades based on its own gas reserves,often from small to medium-sized fields,not imports. That is different from conti-nental Europe’s high dependence onimports from giant fields, according to theEnergy Charter Secretariat, a group thatupholds international laws to ensure thesmooth flow of energy between exportersand importers.

Further, Great Britain began liberaliz-ing its markets in the 1980s, while conti-nental Europe is still deregulating its ener-gy markets.

The nation even developed a hypotheti-cal trading hub called the NationalBalancing Point, through which gas in thecountry must “pass.” NBP is akin to theHenry Hub in the United States, an actualtrading hub, and the NBP price is typicallycited in lists of European gas prices. Anactive futures market tied to the NBP alsohelped Great Britain separate itself some-what from the rest of Europe on natural gaspricing.

During the peak years of Britain’sNorth Sea production, some gas was dirtcheap, creating another departure from thecontinent’s oil-linked gas prices. Thischeap gas came up wells with oil or valu-able gas condensate. Because gas flaringwas not allowed and gas injection some-times wasn’t cost-effective, producers dis-counted the gas just to get rid of it — justas occurred in Alaska’s Cook Inlet duringthe 1960s and 1970s, the early years ofproduction there.

All this let U.K. price its gas based onsupply and demand within the country, notoil prices. The continent’s oil-linked pricesdid influence U.K. gas prices, however,because excess British production wasexported.

But those exports have ended. GreatBritain hasn’t been self-sufficient in natu-ral gas since 2003. The U.K.’s gas produc-tion plunged 45 percent from 2003through last year, while gas consumptiondipped 2 percent.

As a result, British utilities and othergas consumers import some gas, mainlyvia pipeline from Norway’s North Seafields, but also via pipeline from the

Netherlands, especially during winter. Thismeans the nation’s gas price is not com-pletely divorced from the long-term, oil-linked-pricing contracts found on the con-tinent. But the NBP price usually is a littlelower than prices found on the continent.

Last year, the U.K. also was officiallyEurope’s No. 2 LNG importer, behindSpain. But much of the LNG gas landed inthe U.K. was then piped to the continent —with Britain’s well-developed gas infra-structure and better-developed gas tradingmarkets a catalyst for delivering the LNGthere rather than elsewhere in Europe.(Russia’s Gazprom is a minority investorin one pipeline connecting Britain to thecontinent.)

Editor’s note: This is a reprint fromthe Office of the Federal Coordinator,Alaska Natural Gas TransportationProjects, online atwww.arcticgas.gov/print/Europe-a-loos-ening-link-to-oil-prices.


0

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Annual Average Employment — StatewideAnnual Average Employment — North Slope Borough

Alaska Oil Industry EmploymentStatewide and North Slope Borough 2000-2010*

*Preliminary2010 annual average employment numbers for the North Slope Borough were not available as of the publish date for this chart

Source: Alaska Department of Labor and Workforce Development, Research and Analysis Section and U.S. Bureau of Labor Statistics

Alaska Statistics

Petroleum News will be reproducing this standalone chart from the Alaska Oil and Gas Conservation Commission on a regular basisbecause of the interest in the decline in Alaska’s oil production.

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continued from page 9

EUROPE’S OIL LINK

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By WESLEY LOYFor Petroleum News

BP Exploration (Alaska) Inc. is amongseveral subsidiaries of BP AmericaInc. involved in a complex, multistate set-tlement of “financial assurance” viola-tions with the U.S. EnvironmentalProtection Agency.

“Financial assurance protects taxpay-ers from having to foot the bill for costlycleanups,” Cynthia Giles, assistant

administrator for the EPA’s Office ofEnforcement and Compliance Assurance,said in a Nov. 29 press release out ofWashington, D.C.

The EPA determined that BP Alaska,BP Products North America Inc., BPWest Coast Products LLC, BPCorporation North America Inc. andAtlantic Richfield Co. had inadequatefinance assurance.

The settlement “will ensure that BP’ssubsidiaries have the funds available tocover any necessary cleanup costs,” Gilessaid.

Terms of settlementThe settlement covers hazardous waste

facilities and Superfund sites in eightLower 48 states, plus 10 “non-hazardouswaste underground injection control(UIC) wells” on Alaska’s North Slope.

The BP subsidiaries have agreed topay a $426,500 penalty and ensure thatmore than $240 million in funds aresecured to resolve violations of hazardouswaste, drinking water and Superfundfinancial assurance requirements, the

EPA press release said.Under the settlement, BP has lined up

financial assurance such as letters ofcredit, insurance policies and other formsof coverage, the EPA said.

In Alaska, the 10 injection wells weresubject to financial assurance require-ments under the Safe Drinking Water Act.

BP has provided assurances of $19.2million to address the closure, pluggingand abandonment of the UIC wells, theEPA said.

BP also had inadequate financialassurance coverage for facilities, includ-ing the wells, for which the states haveprimary enforcement responsibility, theagency said.

“EPA worked with its state partners toobtain from BP a total of $76.4 million incompliant financial assurance coveragefor these obligations,” the EPA said.

Petroleum News on Nov. 29 asked BPfor additional information on the allegedAlaska violations, including the fieldlocation and function of the injectionwells.

BP Alaska uses the injection wells “todispose of non-hazardous waste at remoteoil field sites at Prudhoe Bay, Badami,Northstar, Milne Point and the DuckIsland/Liberty project,” BP spokesmanScott Dean said by email. “Most of theinjected fluids are brine, which is pro-duced when oil and gas are extractedfrom the field.”�


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BP Alaska involved in big EPA settlementSubsidiaries agree to pay $426,500 penalty, arrange ‘financial assurance’ to close and clean up contaminated industrial sites

Under the settlement, BP has linedup financial assurance such as

letters of credit, insurance policiesand other forms of coverage, the

EPA said.

Your environmental, engineering and sustainability partner.

Program and Project ManagementConstruction/Design BuildPermitting and ComplianceRemediation and RehabilitationNational Environmental Policy Act Contact:

Judd Peterson Industrial Business Team Manager 276.6610

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Contact Wesley Loy at [email protected]

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

Novemberproduction up 6% fromOctober


A laska North Slope production aver-aged 624,687 barrels per day inNovember, up 6.2 percent from anOctober average of 588,287, according tofigures based on pipeline receipts asreported by the Alaska Department ofRevenue’s Tax Division.

The BP Exploration (Alaska)-operatedPrudhoe Bay field had the largestincrease, 11.1 percent, averaging 361,656bpd compared to 325,502 bpd in October.

October production figures forPrudhoe Bay as reported by PetroleumNews in early November have beenadjusted by adding production from MilnePoint and Northstar. Beginning withNovember, Revenue is reporting MilnePoint and Northstar as part of PrudhoeBay. Previously Prudhoe Bay productionfigures included only Prudhoe Bay and itssatellite fields, Aurora, Borealis,Midnight Sun, Orion and Polaris.

The BP-operated Lisburne field hadthe second-largest month-over-month pro-duction increase, 7.2 percent, averaging

see PRODUCTION page 15

http://www.ch2mhill.com/Alaska


The Alaska District of the U.S. ArmyCorps of Engineers has publicnoticed an application from Exxon MobilCorp. and PTE Pipeline LLC for PointThomson project development. The pro-posed work in federal waters at PointThomson, some 60 miles east of PrudhoeBay and 60 miles west of Kaktovik,would initiate commercial hydrocarbonproduction and delineate and evaluatehydrocarbon resources in the PointThomson area.

Three gravel pads, an export pipeline,an airstrip, mine site and support pad areproposed, the corps said in a Nov. 18 pub-lic notice; comments are due on the pro-posal Jan. 3, which is also the closing datefor comments on the draft environmentalimpact statement which was released forpublic comment in mid-November.

The corps said it will prepare a finalEIS after the close of the draft EIS publiccomment period in response to commentsreceived and will make a permit decisionafter the final EIS has been published.

A record of decision will describe itsdecision on the permit application.

The draft EIS analyzes environmentalimpacts of the project proposed by the

applicant, and compares that proposaland three other alternatives to the humanand environmental impacts associatedwith the no action alternative.

Wetland fillThe corps said that the total acreage of

wetland fill for the project as proposed byExxonMobil would be approximately267.5 acres, and would include gravel fordrilling-production pads and connectingroads, airstrip, gravel mine and overbur-den replacement, vertical support mem-bers for in-field pipeline and exportpipeline and pilings for a proposed bargeoffloading facility and service pier. Thefill material would come from a newmine site approximately 2.5 miles inland.

The project would include three gravelpads, five development wells, infieldgathering lines, 12 miles of infield gravelroads, a 5,600-foot airstrip, a gravel mine,processing facilities and support infra-structure and a sales oil pipeline toBadami.

Two of the wells were drilled in 2009-10 from the existing central pad and didnot require new fill.

Long-reach directional drilling will beused to develop the primarily offshoreThomson Sand reservoir from onshorepads near the coast.

The central pad (56 acres including13.2 acres of existing fill) involvesexpansion of the existing Point ThomsonUnit No. 3 pad. Processing facilities atthe central pad would separate hydrocar-bon liquids from natural gas, re-inject thegas and stabilize liquid hydrocarbons fortransport in the Point Thomson export

pipeline. The west pad, approximately 19 acres,

would be a new pad 4 miles west of thecentral pad; the east pad would connect anew 11-acre pad on the coast to the exist-ing 4.6-acre North Staines River No. 1


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MOORING DOLPHINS

Zone KeyDrillingLiving FacilitiesBarge OffloadingOperationsProcessing Unit

CENTRAL PAD FOOTPRINT

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1 - DISPOSAL WELL 17 - ACS LAYDOWN AREA2 - DRILLING UTILITIES 18 - VAC TRUCK3 - GRIND & INJECT 19 - COLD STORAGE4 - CUTTINGS STORAGE 20 - WAREHOUSE5 - DRY BULK STORAGE 21 - ACS & MAINTENANCE6 - TANK TRAILERS 22 - BOAT STORAGE7 - CAMP 23 - WASTE8 - INJECTION COMPRESSORS 24 - WATER & SEWAGE9 - UTILITY MODULE 25 - CAMP PARKING10 - SEPARATION/DEHYDRATION 26 - INCINERATOR11 - POWER GENERATORS 27 - STANDBY GENERATORS12 - DRILLING FLUID TANKS 28 - CAMP COMMON AREA13 - PIPE MATERIAL 29 - LIVING QUARTERS14 - DIESEL 30 - CONSTRUCTION EQUIPMENT15 - DIESEL/METHANOL 31 - MATERIAL16 - SUPER SUCKERS 32 - FUEL

3031

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TEMPORARYRAMP SUPPORT

DATE: OCTOBER 2011

WATERBODY: BEAUFORT SEA

REFERENCE: POA-2001-1082-M1

LOCATION: NORTH SLOPE BOROUGH, ALASKA

PROJECT: POINT THOMSON PROJECT

APPLICANT: EXXON MOBIL CORPORATION &PTE PIPELINE LLC.


Corps public noticesThomson applicationComments due Jan. 3 on ExxonMobil proposal for facilities,pipeline project; construction projected to begin winter of 2012-13

see THOMSON APPLICATION page 14

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production was up to 400 percent of whatit was when it was shut-in.

Wilcox said the company has contin-ued to optimize wells at its onshore prop-erties.

It took longer to get the Osprey plat-form back into operation, but first oilcame off the platform in June, he said.With a $100 million credit facility workbegan on a big rig for the Osprey platformso the company could begin drilling side-tracks from the platform and increase pro-duction. About a third of that rig is now inNikiski, Wilcox said, and work will beginon the platform in the next few months.

Cook Inlet Energy is also building asmall rig on the west side that will betruck mounted and “should be just anideal rig for drilling gas on the west side.”

The company is “getting set up to exe-cute our second phase of development onthe Osprey platform” with the new rig, iscontinuing to optimize production fromexisting wells and continuing to exploitoil and gas reserves near its facilities,Wilcox said.

Enstar, CINGSAJohn Sims, director of corporate com-

munications for Cook Inlet Natural GasStorage Alaska and Enstar Natural Gas,told the RDC audience that while Enstaris “very cautiously optimistic about allthe activities going on here in CookInlet,” it has concerns until it has a con-tract for gas delivery before theRegulatory Commission of Alaska.

Semco Energy, Enstar’s parent compa-ny, and MidAmerican LLC, partners inCook Inlet Natural Gas Storage Alaska, orCINGSA, were joined in October by FirstAlaska and Cook Inlet Region Inc., Simssaid.

The five injection-withdrawal wellsare being drilled for the storage project,with the project on schedule and slightlyunder budget. The first well cost about $7million and the second two came in atabout $5 million each, prior to perforat-ing.

The middle three wells, technically theeasiest, were drilled first, Sims said. It hastaken about 30 days per well, with abouthalf of that time required to move the rig.The wells should be completed byFebruary.

With four customers for storage capac-

ity — Enstar,Chugach ElectricAssociation, ML&Pand Homer Electriccoming in later —CINGSA is at 11percent capacity forthe 11 billion cubicfeet of gas storage.

There is expan-sion capacity at thefacility and Sims said expansion will be“dependent on performance and also themarket demand.”

Having storage, which will be avail-able for withdrawal in the winter of 2012-13, helps with swing demand in the win-ter, he said, helps producers with produc-tion in the summer when gas is injectedand acts as an insurance policy shouldthere be equipment failure.

Asked whether with successful gasexploration and storage the utilities willstill need LNG, Sims said, “storage isn’tthe savior for Cook Inlet by any means;it’s a part of the puzzle.”

“Another piece involves the additionalexploration and development that we’reseeing.”

But, he said, Enstar and the utilities arestill evaluating the LNG option, “not just

for gasifying going forward put also foran insurance policy.”

And, he said, “until we actually havethose contracts that erase that need, it’ssomething that we’re still going to have tomove forward with.”

Cook Inlet Region Inc. Ethan Schutt, senior vice president,

land and energy development, for CookInlet Region Inc., said the Fire Islandwind project has regulatory approval forcontracts from the RegulatoryCommission of Alaska.

Financing for the project needs to beclosed, “so that we can move into projectconstruction in April,” he said, adding thatthe project has all its permits.

CIRI is also working on an under-ground coal gasification or UCG project.

The Cook Inlet basin has a “world-class coal resource that’s really never beenexploited at a commercial level,” Schuttsaid.

CIRI has been working on UCG foralmost three years, he said, and to date has“drilled 13 stratigraphic core holes to testboth the geology and the resource,” andcollected a suite of oil and gas type dataduring that program, “so we have a prettyrobust data set from that site, a place justnorth of the Beluga River on the northside of Cook Inlet on CIRI surface andsubsurface land.”

The data has been incorporated into ageological model.

CIRI is currently shooting some eightand a half line miles of “shallow high-res-olution 2-D … to tie together all the datapoints that we collected with the drillingprogram and enhance our data set as wemove towards a … characterization pro-gram to begin sometime in 2012.”

The project represents some 300-plusmillion tons of coal, Schutt said, “theequivalent of more than 4 (trillion cubicfeet) of natural gas on an energy basis, sojust in our little site we have quite aworld-class resource in that coal.” �


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Tight situation6 - TANK TRAILERS 22 - BOAT STORAGE 7 - CAMP 23 - WASTE ... he surge in exploration...

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