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Vol. 16, No. 33 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of August 14, 2011 • $2
� E X P L O R A T I O N & P R O D U C T I O N
� L A N D & L E A S I N G
� E N V I R O N M E N T & S A F E T Y
Pioneer says water injection shortagecauses light dip in Oooguruk rates
The Spartan 151 offshore near Homer, Alaska
STEV
E SU
THER
LIN
page3
A jack-up in Cook Inlet; Spartan151 arrives at Kitchen Lights unit
The Spartan 151 is at the Kitchen Lights unit inSouthcentral Alaska’s Cook Inlet.
The jack-up rig arrived at the offshore unit on Aug. 10,according to Escopeta Oil Co., the Houston-based independ-ent that plans to use the rig for an offshore drilling program.
“The rig is positioned overthe well,” Escopeta contractorSteve Sutherlin said.
Sutherlin is a former contrib-utor to and currently a minorityowner in Petroleum News.
The rig is currently undergo-ing technical operations work inpreparation for a drilling program. Crews are preparing tojack up the rig platform, set the casing and install blowoutpreventer equipment. “Once that’s in place then they’ll put thebit in and start rocking and rolling,” Sutherlin said, adding,“We’re confident we’ll spud in August.”
Under deadlines from the Alaska Division of Oil and Gas,Escopeta must drill a well in the Kitchen Lights unit to thepre-Tertiary zone by Oct. 31 in order to keep its leases.
The Kitchen Lights Unit No. 1 well will be in the Corsair
Apache could drill inlet well in’12; starting 3-D seismic shoot
Apache Oil Corp. hopes to start drilling in Alaska nextyear.
The Houston-based independent plans to begin shooting a3-D seismic campaign this year across itsexpanding acreage in the Cook Inletbasin.
“It’s an exploration play but the guyshave wowed me enough for me to believethat it’s a real opportunity,” CEO G.Steven Farris said during a conferencecall on Aug. 4.
He said the company hoped to havecompleted enough of the shoot byDecember of this year, and first-passprocessing, “and hope to drill a well in2012.”
Apache arrived in Alaska last summer and through dealssince then — and participation in the state’s Cook Inlet oil andgas lease sale in June — has amassed some 800,000 acres inthe Cook Inlet region, making it the largest leaseholder in thebasin.
Apache recently tested a new wireless nodal seismic tech-
“We’re confident we’llspud in August.”
—Steve Sutherlin, Escopetacontractor
see JACK-UP RIG page 20
STEVEN FARRIS
see APACHE PLANS page 19
North Slope boomsUpcoming exploration drilling season shaping up to be busiest in decades
By KAY CASHMANPetroleum News
A s Southcentral Alaska prepares for anincrease in oil and gas exploration and devel-
opment in the Cook Inlet basin, operators on theNorth Slope and nearshore Beaufort Sea arepreparing for what promises to be one of thebusiest exploration seasons since 1969, when 33exploration wells were drilled following the dis-covery of the Prudhoe Bay oil field.
If all goes as planned, as many as 28 explorationwells could be drilled between October 2011 andmid-2012, a longer than normal North Slopeexploration season because one company’s wellscan be drilled from old gravel sites along theDalton Highway and therefore are not subject tooff-road tundra travel restrictions.
Much of the stepped up activity appears to bepartly due to the exploration incentives offered bythe State of Alaska — and because Alaska’s gover-nor is committed to fix provisions in the state’s
Much of the stepped up activity appearsto be partly due to the exploration
incentives offered by the State of Alaska— and because Alaska’s governor is
committed to fix provisions in the state’sproduction tax that could make
development of any oil discoveriesnoncompetitive for investment capitalwith projects in other oil provinces.
see EXPLORATION DRILLING page 18
Companies defend ThomsonAlaska Supreme Court proceedings continue on disputed North Slope oil, gas field
By WESLEY LOYFor Petroleum News
T he major stakeholders in the disputed PointThomson oil and gas field have filed a uni-
fied defense of their interests with the AlaskaSupreme Court.
The filing is the latest legal twist in the fight forcontrol of the rich field — a fight that continueseven as all parties contend they’re trying to settlethe matter out of court.
Four oil companies signed onto the 83-pagebrief filed Aug. 5 with the high court:ExxonMobil, BP, Chevron and ConocoPhillips.
The brief is their reply to the 102-page openingbrief lawyers for the Alaska Department of Natural
Resources filed on May 5.The dueling documents lay the foundation for
the Supreme Court to decide whether the oil com-panies have been treated fairly in DNR’s efforts tobreak up the Point Thomson unit and reclaim thestate acreage it encompasses.
But no matter how the court rules, the conflict
see POINT THOMSON page 20
The primary question before the SupremeCourt is whether the companies, before
the unit was terminated, were due ahearing under Section 21 of the Point
Thomson unit agreement.
Arctic cleanup challengeConsultant says cleanup in Canada’s Arctic offshore impractical 20-84% of time
By GARY PARKFor Petroleum News
A n environmental consultant estimates thatvarious options for cleaning up oil spills in
Canada’s Arctic offshore would be impractical 20percent to 84 percent of the time during the June-November open-water season because of badweather or sea ice.
S.L. Ross Environmental Research, in a reportcommissioned by Canada’s National EnergyBoard, based its findings on 20 years’ of weatherdata for the near and far offshore Beaufort Sea andthe Davis Strait west of Greenland’s Disko Bay.
It concluded that using one of three options —burning oil slicks, deploying booms and skimmers
to contain and remove oil and conducting an aerialdispersant application — would not be possible aminimum of 20 percent of the time in June, wors-ening to 65 percent in October in the Beaufort.
For two sections of the Davis Strait, July condi-tions would prevent cleanup 27 percent of the time,worsening to 84 percent in November.
The consultant noted fickle weather conditions
The consultant noted fickle weatherconditions in the Arctic region change
from day to day and would make cleanupharder as oil emulsified with seawater.
see ARCTIC CLEANUP page 17
2 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
contents Petroleum News North America’s source for oil and gas news
3 MGM drafts Central Mackenzie plans
7 Citizens’ council for pipeline advocated
6 GVEA and Flint Hills to truck LNG
9 Miller files corrected financial report
17 Joint exercise tests Arctic towing system
10 Tesoro replacing ANS crude with Bakken
11 FERC begins Alaska gas line EIS process
13 Kenai LNG to stay open through October
13 AGPA again pushing Valdez LNG project
EXPLORATION & PRODUCTION
ENVIRONMENT & SAFETY
ALTERNATIVE ENERGY
GOVERNMENT
LAND & LEASING
PIPELINES & DOWNSTREAM
FINANCE & ECONOMY
14 Route probed for environmental impacts
Scientists working along Alaska Pipeline Project routefrom Prudhoe Bay to Canadian border; work this summer largest field program
12 Salazar says president backs drilling
Interior secretary tells Alaskans administration wantsmore oil drilling in Alaska, potentially including OCS
10 RCA wants Fire Island wind power hearing
Says that Chugach Electric has not provided enoughinformation to answer concerns about impact of wind power on Southcentral grid NATURAL GAS
3 Pioneer production falls year over year
Water injection shortage causes slight dip at Ooogurukbut company says new drilling and new completion technique should bump rates
7 Exxon resists $92 million ‘reopener’
Company argues to court it has no obligation to pay for additional cleanup stemming from 1989 oil spill in Prince William Sound
5 Old Alberta frontier gets new life
Liquids-rich Duvernay shale play underpins land grab in exploratory play; horizontal drilling, multistage fracturing the drivers
4 Kenai gas storage construction under way
CINGSA moves ahead with foundations of surfacefacility and directional drilling for gas gathering pipeline; drill rig mobilized
8 One step at a time for Shell’s OCS plans
BOEMRE conditional approval of company’s Beaufort Sea exploration plan is a major milestone but other permitting hurdles remain
A jack-up in Cook Inlet; Spartan 151 arrives at Kitchen Lights unit
Apache could drill inlet well in ’12; starting 3-D seismic shoot
ON THE COVERNorth Slope booms
Upcoming exploration drilling season shaping up to be busiest in decades
Companies defend Thomson
Alaska Supreme Court proceedings continue on disputed North Slope oil and gas field
Arctic cleanup challenge
Consultant says cleanup in Canada’s Arctic offshore impractical 20-84% of time
SIDEBAR, Page 8: NSB says Shell needs borough permits
By ERIC LIDJIFor Petroleum News
P ioneer Natural Resources Alaska Inc.said it lost around 1,000 barrels of oil
per day of production this year because of“third-party water injection supply short-ages.”
The Texas-based independent produced5,000 net bpd from Alaska during the sec-ond quarter, down from 7,000 bpd duringthe same period in 2010. Companywide,Pioneer produced 114,000 bpd during thesecond quarter, up from 102,000 bpd lastyear.
That reduction islargely because ofwater supply short-ages, the companysaid.
While Pioneerneeds around 15,700bpd of water for itsNorth Slope opera-tions, the company iscurrently gettingaround 6,000 bpd from its suppliers.
“So cumulatively, what happens is, wedon’t have enough water to inject,” COOTim Dove said during an earnings confer-ence call Aug. 4. “You’re basically notproperly sweeping the oil from the reser-voir. ... We’re working on internal fixes tostart generating our own water supply. Wedidn’t think in advance of this project thatwas going to be required, because the oper-ator in question we thought could deliverall the water we needed. We’re simply find-ing that that’s not the case. So our produc-tion would be higher this year, other thanfor the fact we’re losing production relatedto this lack of water.”
Pioneer currently gets water fromConocoPhillips through the Kuparuk Riverunit.
Dove said that solution might not be inplace until “the latter part of next year,” butthat oil production should increase in themeantime as the result of increased drilling.
Two wells in the worksThat drilling will largely come from two
“key” wells, this coming winter, CEO ScottSheffield said.
The first is a “deep test” in the Ivishak,the main producing zone at Prudhoe Bay.The second is a fracture stimulation opera-tion in the Torok zone, the third producingformation at the Oooguruk unit, where thecompany previously drilled two wells.
“They’ve been fairly good over the last12 months,” Sheffield said.
Pioneer plans to change-up its comple-tion strategy in Alaska, though, to use atechnique that improved production rates athorizontal Eagle Ford and Spraberry wellsin Texas.
Sheffield described the technique as a“plug and perf,” also known as “mechani-cal diversion” hydraulic fracturing system,as opposed to a “dynamic diversion” sys-tem.
“Unlike the dynamic diversion fractur-ing system used today, mechanical diver-sion is an advanced, multi-stage completiontechnology that is a more controlled, effi-cient and effective method of fracking ahorizontal wellbore,” Pioneer Natural
Resources Alaska spokesman CaseySullivan told Petroleum News by e-mail onAug. 10. “Mechanical diversion has beenshown to be more effective as it allows fora greater amount of focused energy at thepoint of fracking that stimulates a largerportion of the resource.”
Alaska still on agendaPioneer plans to spend $100 million in
Alaska this year as part of a $2.1 billioncapital budget. More than half of that budg-et — $1.3 billion — is going to theSpraberry.
To date, Pioneer has drilled 12 produc-tion wells and seven injection wells of theestimated 17 production wells and 16 injec-tion wells needed to develop Oooguruk.
Pioneer drilled its first Torok well in2010 and completed a follow up in early2011 and now plans to drill and complete athird Torok well in early 2012 “to furtherevaluate the productivity of the formationand the feasibility of future developmentexpansion.”
Pioneer owns a 70 percent workinginterest in Oooguruk. Eni Petroleum ownsthe rest.
Pioneer did not receive any PPT creditsin the second quarter, after receiving $13.6million in the second quarter of 2010 and$27.4 million in the first quarter of 2011.
With the company increasingly focusedon the midcontinent, its international andfrontier plays like South Africa and Alaskaincreasingly represent a smaller share ofcompany production. Sheffield said “it’salways an option in regard to whether or notto look at divesting those two assets,” butalso added that the company sees SouthAfrica as “running out” and sees Alaska as“growing significantly over the next sever-al years.” �
PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 3
Contact Eric Lidji at [email protected]
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EXPLORATION & PRODUCTIONMGM drafts Central Mackenzie plans
MGM Energy, one of the few active explorers in Canada’s North over recent years,expects to determine by Sept. 30, for parcels acquired last month in the CentralMackenzie Valley, whether it will start exploration in the 2011-12 winter.
It is also prepared to resume activity on its other Northwest Territories properties ifthere is sign of real progress on a Mackenzie Valley gas pipeline, but it does not expectto drill or conduct seismic work in the upcoming winter.
The Calgary-based junior and its 50-50 partner made a gross work commitment ofC$5 million to secure three Central Mackenzie Valley exploration licenses totaling628,000 acres. The same sale attracted work commitments of C$529 million for eightlicenses in the same region.
MGM said its new lands, along with its existing Exploration License 454 areprospective for multiple Devonian-aged shale plays, which it believes are liquids richat depths of about 2,500 feet to 8,200 feet, and Paleozoic structural plays.
They are all within about six miles to 19 miles of Enbridge’s existing oil pipelineinfrastructure, connecting the Norman Wells field with northern Alberta.
MGM, which has no current production, reported a net loss in the second quarterof C$1.3 million compared with a loss of C$2.35 million in the same period last year,partly because of lower exploration and evaluation spending. Its net loss for the firsthalf of 2011 was C$5.61 million, up $170,000 from a year ago.
The company said the time needed to complete a Mackenzie pipeline means itwill generate losses for the “foreseeable future,” but it has enough financial backingto cover the next couple of years, including C$20 million paid by Kogas Canada fora 20 percent stake in the Umiak Significant Discovery License on the MackenzieDelta, with another C$10 million due if and when there is approval for a commercialproject.
—GARY PARK
� E X P L O R A T I O N & P R O D U C T I O N
Pioneer productionfalls year over yearWater injection shortage causes slight dip at Oooguruk but companysays new drilling and new completion technique should bump rates
SCOTT SHEFFIELD
4 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
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� N A T U R A L G A S
Kenai gas storageconstruction under wayCINGSA moves ahead with foundations of surface facility anddirectional drilling for gas gathering pipeline; drill rig mobilized
By ALAN BAILEYPetroleum News
Intent on heading off a potential shortfallin Southcentral Alaska utility gas deliv-
erability in the winter of 2012-13, CookInlet Natural Gas Storage Alaska is forgingahead with construction of a new gas stor-age facility in the Cannery Loop gas field,south of the City of Kenai on the KenaiPeninsula.
In a July progress report to theRegulatory Commission of Alaska,CINGSA said that Conam ConstructionCo. has now completed the horizontaldirectional drilling required for placementof the storage facility’s gas gathering line,and that Conam has also welded half of the20-inch line that will connect the facilitywith the nearby Kenai Nikiski gaspipeline. Construction of the facility foun-dations is 70 percent complete and con-struction of the compressor building ispartway complete, the progress reportsays.
Drilling in AugustPlans to spud the first well for the facil-
ity in early August remain on track, withNabors Alaska Drilling having mobilizedits Rig 105 from the North Slope for theCINGSA project. Reservoir modeling forthe facility’s subsurface storage design isalmost complete, the report says.
Work is in progress on the engineeringof the surface facilities, with CINGSAhaving awarded the mechanical and elec-trical construction contract to Anchorage-based Udelhoven Oilfield SystemServices.
CINGSA has been continuing to seekrights to gas storage interests in the sub-surface land required for the storage facil-ity — the subsurface land in the CanneryLoop field involves a complex mixture ofstate and private ownership, with 45 dis-tinct private landowners. The State ofAlaska issued a storage lease to CINGSAfor the use of state land in the facility.CINGSA has the right of eminent domainover privately owned subsurface land thatit needs to use and has negotiated usagerights with some of the subsurface owners.On July 8 the state Superior Court granted
CINGSA possession of all subsurface landinterests it had not already obtained.CINGSA continues to negotiate termswith landowners who have not yet settledwith the company, with a hearing on landvaluation anticipated in late 2011 or early2012.
AppealsThe Superior Court is also considering
two as-yet unresolved appeals againstCINGSA’s plans by Cook Inlet entities, agroup of companies headed by business-man Vincent Goddard. Goddard’s busi-nesses operate on surface land above thestorage facility and Goddard has expressedconcern about the possibility of gas leak-ages from the facility. In one of theseappeals, an appeal against the City ofKenai’s permit for CINGSA’s surface facil-ities, briefs are due to the court on Aug. 26.In the other appeal, against the Alaska Oiland Gas Conservation Commission’s gasinjection order for the facility, briefs aredue in September.
Kenai Landing, another surfacelandowner in the area of the storage facili-ty, has appealed the Alaska Department ofNatural Resources approval of the contrac-tion of the Marathon-operated CanneryLoop unit, a contraction that has trans-ferred required subsurface land tracts fromthe unit into the CINGSA facility. DNRhas turned down that appeal after makingsome changes to the wording of the unitcontraction decision.
Meantime on Aug. 5 Southcentral gasutility Enstar Natural Gas Co. filed a pro-posed tariff revision with the RegulatoryCommission of Alaska, requestingapproval to include the cost of usage of theCINGSA facility in the gas costs thatEnstar charges its customers.
Critical needWith gas supplies from the aging gas
fields of the Cook Inlet basin becomingever tighter as the fields run down, thestorage of summer-produced gas for use inthe winter when gas demand peaks hasbecome critical to meeting SouthcentralAlaska utility gas supply needs. TheCINGSA facility will be the first storage
CORRECTIONMinimum depth required
In previous reports, Petroleum News reported that Escopeta Oil Co. must drilla well at its offshore Kitchen Lights unit by Oct. 31 to keep the unit from goinginto default. That is incorrect. Escopeta must drill the well “to a minimum bottomhole depth of the pre-Tertiary zone” by Oct. 31 to keep the unit from going intodefault.
Petroleum News regrets the error.
see CINGSA page 7
By GARY PARKFor Petroleum News
T he source rock that launchedAlberta’s petroleum industry in
1947 is making a comeback, powered bythe technology twins — horizontaldrilling and multistage hydraulic fractur-ing.
Despite its steep exploration costs andlargely unproven results, the Duvernayshale lies about 6,500 feet below the sur-face, covering a broad span across centraland northwestern Alberta, underlying 10other rock zones that contain commercialquantities of natural gas.
Over the past year, companies havegambled hundreds of millions of dollarsat land sales rounding up explorationrights, although there is no conclusiveproof yet that anyone has drilled a wellthat can deliver an acceptable profit.
Early results, according to CIBCWorld Markets, include initial flow ratesof 2.1 million and 5.2 million cubic feetper day from two Celtic Explorationwells, with a liquids content of about 75barrels per million cubic feet from bothwells, although the second well cost aboutC$17.5 million to drill and complete.
However, the level of industry confi-dence in the play has soared, peaking inJune when about C$330 million of win-ning bids were made for Duvernay leases,contributing to a single-auction record ofC$842 million for the Alberta govern-ment.
And analysts are hinting there could bemore to come on Aug. 24 when theprovince offers 704,000 acres — about35,000 acres more than the benchmarkJune sale — heavily loaded in favor ofdeep formations.
The postings include about 640,000acres in the Kaybob region, where mostdrilling into the Duvernay has takenplace.
‘Hold on to your hats’CIBC World Markets analyst Jeremy
Kaliel — who has estimated the newdrilling and completion techniques couldbring another 77 billion barrels of liquidsto the surface in North America — hasrated the Duvernay as “flavor of themonth” because of the oil-rich nature ofthe shale.
“Hold on to your hats,” he said, sug-gesting the upcoming sale could see com-panies lock up most of the prospectiveacreage and that by either late 2011 orearly 2012 the buzz over land speculationcould move to actual drilling results.
Canadian Discovery, a geosciencescompany, estimated that the C$672 mil-lion spent in the Alberta government’s
first July land sale averaged aboutC$2,500 per acre, compared withC$1,600 last December.
“It’s an impressive amount of moneyto spend on what is really an exploratoryplay,” said Neil Watson, consulting serv-ices director at Canadian Discovery.
“But there’s lots of reasons to havefaith in it,” he said, noting Duvernayshares geological characteristics withBritish Columbia’s prolific Horn Riverbasin.
It also helps that Duvernay is in themidst of a region that has abundantpipelines and other infrastructure.
Watson said those who think gasprices will rebound in the “next few yearswill look pretty smart it they get the lion’sshare of land that will be a major play.”
Most hotspots acquiredThe bidding has now reached the point
where most of the hotspots have beenacquired and more companies are liftingthe curtain of secrecy around theirinvolvement in the Duvernay.
In particular, Encana, TalismanEnergy, Canadian Natural Resources,Royal Dutch Shell, Trilogy Energy, CelticExploration, Athabasca Oil Sands,Daylight Energy, Tourmaline Oil,Bonavista Energy, Angle Energy andYoho Resources are ranked among thoseactive in the region, which is embraced byDeep basin, a liquids-rich tight gas for-mation on the eastern flank of theCanadian Rockies, where preliminaryestimates rate potential gas resources at400 trillion cubic feet.
“This is not a mom and pop thing,” TDNewcrest analyst Roger Serin said of theDuvernay. “This is a big boy thing.”
Encana has disclosed it spent US$300million in the first quarter for Duvernayrights, with Mike Graham, president ofEncana’s Canadian division, telling ana-lysts “we’re excited about results from theDuvernay,” comparing the play to theEagle Ford shale in south Texas.
Encana: liquids significantEncana CEO Randy Eresman had pre-
viously startled investors at his company’sannual meeting by suggesting Encanacould give away its Duvernay gas and stillmake money on the liquids.
The Duvernay underpins Encana’sstrategy of shifting into liquids-rich gasplays from dry gas rather than waiting atleast another two years for gas prices toachieve its forecast target of US$4-$5 perthousand cubic feet.
Talisman reported in July it laid outUS$510 million in the second quarter for360,000 net acres, paying at an averageUS$2,000 per acre, or about US$500 per
acre more than Encana paid, reinforcingits view that there is a “first mover advan-tage.”
Daylight has also stepped forward,reporting it has spent C$100 million atland sales to build its Duvernay portfolioto almost 130,000 acres and plans a four-well pilot project in the first quarter of2012.
Canadian Natural Resources, Canada’sthird largest gas producer, has joined theaction, setting aside its policy over thelast three years of shutting in productionand limiting drilling to lease retention inthe belief that a gas price rebound is twoto seven years away.
It has scheduled 15 wells this year inthe Deep basin, raising its gas spendingby 8 percent this year to C$750 million.
The company said it also is moving tohorizontal drilling and multistagehydraulic fracturing in Deep basin’stighter, thicker reservoirs because verticalwells have accessed only limited reserves.
Cam Kramer, Canadian Natural’s sen-ior vice president of gas operations, saidthat although the play is “still in its rela-tive infancy, there’s promise that technol-ogy will unlock significant value on ourlands.”
Talisman: liquids-rich shaleTalisman CEO John Manzoni said his
company believes Duvernay “will proveto be a liquids-rich shale play and someof the industry activity in the area so farhas proven to be encouraging in that
regard.”The company is taking a measured
approach, starting out with two wells thisyear that it is prepared to scale updepending on results.
Robert Spitzer, Apache Canada’sexploration vice president, cautioned thatDuvernay is still in its early stages, giventhat the formation’s true value remains indoubt, noting that it takes more than acouple of years to develop shale plays.
The extensive Cardium formation, theshallowest of Deep basin’s plays at about6,400 feet, is also attracting companiesthat say the basin’s liquids-rich gas offerscomparable returns to crude programs.
“There’s so much focus on theCardium oil and so very little on theCardium liquids-rich gas,” said DarrenGee, CEO of Peyto Exploration &Development, which is spending aboutC$100 million this year on its Cardiumgas program.
“But we’re getting more productivewells in the gas fairway at lower royaltyrates and just as good a netback, if notbetter,” he said.
Gee said horizontal wells are yielding90 barrels of liquids per million cubicfeet at an average cost of C$5 million todrill, complete and tie in, while verticalwells are averaging 40-45 barrels permillion cubic feet at an average cost ofC$1.7 million. �
� L A N D & L E A S I N G
Old Alberta frontier gets new lifeLiquids-rich Duvernay shale play underpins land grab in exploratory play; horizontal drilling, multistage fracturing the drivers
PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 5
Contact Gary Park through [email protected]
By ERIC LIDJIFor Petroleum News
A Fairbanks electric cooperative anda nearby oil refiner are teaming up
on a plan to truck liquefied natural gasfrom the North Slope to the Interior start-ing in early 2014, a similar but separateproject from one proposed by a regionalnatural gas distributor.
Golden Valley Electric Associationand Flint Hill Resources Alaska recentlysigned a memorandum of understandingto build and operate the new liquefactionfacility, the parties said Aug. 4. The com-
panies said engineering is already underway.
GVEA would use the gas to power itsNorth Pole Power Plant. That facility iscurrently running on naphtha, butdesigned to run on natural gas as well.Flint Hills, a subsidiary of KochIndustries, would use the gas as a supplyfuel for its crude oil refining operations atits North Pole refinery. The companieswould truck the LNG down the DaltonHighway.
The companies said they would eachget natural gas “at cost” through the deal,allowing GVEA to lower its rates andFlint Hills to become more competitiveand efficient.
The deal furthers the relationshipbetween the two companies. Currently,GVEA provides electricity for Flint Hillsoperations and Flint Hill supplies the fuelfor GVEA generation.
Another marketing optionThe new proposal adds another option
for marketing North Slope natural gas. That field is increasingly crowded, and
includes ongoing efforts to build a large-diameter pipeline through Canada or toValdez with a spur to Anchorage, a public-private effort to build a pipeline from theNorth Slope to Anchorage with a spur tothe Interior, and a plan by FairbanksNatural Gas LLC to build a North SlopeLNG trucking operation.
“While GVEA supports a gas pipelineto Fairbanks, trucking LNG would lessenour dependence on high-priced oil therebybringing energy cost relief sooner thanother proposed projects,” GVEA Presidentand CEO Brian Newton said in a statement.
Polar LNG LLC, an affiliate ofFairbanks Natural Gas, is currently work-ing on a plan to truck LNG from the NorthSlope to the existing natural gas grid inFairbanks.
Polar LNG recently applied for a certifi-cate of public convenience and necessityfrom the Regulatory Commission ofAlaska to operate a 3.8-mile pipeline froma natural gas supply at Prudhoe Bay to thesite of its proposed liquefaction facility inDeadhorse.
The company wants to begin construc-tion this winter and asked for a decision bythe end of November. In an application forexpedited consideration, an attorney forPolar LNG said the project “has beendelayed due to several factors beyond itscontrol, but Polar is now ready to begin
serious development of the LNG projectand the associated pipeline.”
Polar LNG and Fairbanks Natural Gasare both owned by Pentex Alaska NaturalGas Co. LLC. Fairbanks Natural Gas oper-ates a distribution operation in the Interior,while Polar LNG exists solely to build andoperate a North Slope LNG trucking oper-ation.
FNG currently uses inlet gasFairbanks Natural Gas currently gets its
supply from Cook Inlet, liquefies it at aplant at Point MacKenzie and trucks itnorth to Fairbanks. That supply contract,though, is set to expire in May 2013. In2008, Fairbanks Natural Gas signed a 10-year contract to buy Prudhoe Bay naturalgas from ExxonMobil that begins when theproject comes online.
Polar LNG needs big customers likeGVEA and Flint Hills to make its projecteconomic.
With those commitments, Polar LNGsaid it could begin construction this winterand begin installing the liquefaction facili-ty in the summer of 2013, but without anexpedited consideration from the RCA thecompany said the project could be delayeda full year.
GVEA previously considered joiningthat project and signed a 15-year agree-ment to buy LNG from Fairbanks NaturalGas and the Alaska Gasline Port Authority.AGPA once planned to buy FairbanksNatural Gas, but that deal recently fellthrough for now.
“This project would partially eliminatethe competitive disadvantage for our refin-ery due to high energy costs, and providean environmental benefit to Fairbanks andInterior Alaska,” Flint Hills Vice PresidentMike Brose said. “We are also excitedabout additional opportunities such aspropane production and LNG diesel pro-duction to provide more competitive cleanfuel for Alaska’s trucking and transporta-tion industry.” �
6 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
� N A T U R A L G A S
GVEA and Flint Hills to truck LNGProposal would provide natural gas at cost to both parties, but would compete against similar proposal by Fairbanks Natural Gas
“While GVEA supports a gaspipeline to Fairbanks, trucking
LNG would lessen our dependenceon high-priced oil thereby bringing
energy cost relief sooner thanother proposed projects.”
—GVEA President and CEO Brian Newton
Fairbanks Natural Gas currentlygets its supply from Cook Inlet,liquefies it at a plant at Point
MacKenzie and trucks it north toFairbanks.
Contact Eric Lidji at [email protected]
PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 7
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facility in Alaska to offer third-party stor-age to customers willing to rent storagespace and pay for gas injection andretrieval — all other Cook Inlet facilitiesare operated by gas producers for theirown use, to ensure the availability of gas tomeet the specifications of gas supplyagreements.
In addition to assuring the adequatedeliverability of gas during peak winterdemand, the CINGSA facility will enablethe temporary storage of summer-pro-duced gas, thus enabling some gas wells tocontinue operating year-round while alsoproviding new market possibilities for thesale of summer gas by gas producers.Without the availability of gas storage, theneed to shut in gas wells during the sum-mer when gas demand is low poses therisk of the wells not returning to previousproduction rates when restarted in thewinter. �
continued from page 4
CINGSA
Contact Alan Bailey at [email protected]
GOVERNMENTCitizens’ council for pipeline advocated
A Cordova-based nonprofit organization is pushing a petition calling for “citi-zen oversight” of the trans-Alaska pipeline system.
“Enough is enough,” the Copper River Watershed Project says on its website,citing a January oil spill at Pump Station 1 and other spills in North Slope oilfields.
The organization is advocating creation of a citizens’ council for TAPS, similarto the council already in place to overseeterminal and tanker operations at the endof the 800-mile pipeline in Valdez.
The worry is that the pipeline crossesseveral tributaries of the Copper River,and an oil spill could quickly reach andcontaminate the river famed for its wildsalmon, the Watershed Project says.
Letter to CongressPetitioners can sign onto a letter to
Congress available on the change.org website. The site indicated 227 signatureshad been collected as of Aug. 10.
The letter says in part: “Today the pipeline is 34 years old and already 4 yearspast what oil companies estimated was its useful life. Due to corrosion, lax regu-lation, natural disasters, vandalism, and human error the pipeline poses a constantthreat to the Copper River watershed.”
The Copper River Watershed Project was incorporated in late 1997. Its found-ing director is Riki Ott, a marine biologist and author known for her activism fol-lowing the Exxon Valdez oil spill.
Alyeska Pipeline Service Co., the Anchorage-based energy company consor-tium that runs the pipeline, says it has people and equipment ready to respondshould a spill occur at a river or stream crossing.
—WESLEY LOY
The organization is advocatingcreation of a citizens’ council for
TAPS, similar to the councilalready in place to oversee
terminal and tanker operationsat the end of the 800-mile
pipeline in Valdez.
� F I N A N C E & E C O N O M Y
Exxon resists $92million ‘reopener’Company argues to court it has no obligation to pay for additionalcleanup stemming from 1989 oil spill in Prince William Sound
By WESLEY LOYFor Petroleum News
ExxonMobil Corp. is asking a judge tosquash a request from the federal and
state governments for an additional $92 mil-lion to address lingering effects of the 1989oil spill in Alaska’s Prince William Sound.
In papers filed Aug. 9 in U.S. DistrictCourt in Anchorage, lawyers forExxonMobil argue the governments aim touse the money to reinitiate cleanup activi-ties, in violation of a 1991 civil settlement.
Under the settlement, known as a consentdecree, Exxon paid the governments $900million to settle damages claims from thespill of nearly 11 million gallons of NorthSlope crude.
The decree contained what’s known as a“reopener” provision allowing the govern-ments to request up to an additional $100million to deal with unanticipated futureinjuries to species or habitat.
In 2006, the governments exercised thereopener, requesting $92,240,982 fromExxon for a habitat restoration plan.
But lawyers for Exxon argue the plan is“nothing more than a plan to resurrect theclean-up of the oil spill,” an operation feder-al and state on-scene coordinators declaredcomplete nearly 20 years ago, in 1992.
The governments cannot now use thereopener to subject Exxon to further pay-ment for cleanup, as the consent decree“expressly released Exxon from such obli-gations,” says an Aug. 9 motion Exxon filedwith the court.
Lack of resolve?Exxon is asking the judge to issue an
order confirming that the consent decreefrees the company from any further finan-cial obligations with respect to cleanup.
As Petroleum News went to press, thegovernments had not yet responded toExxon’s motion.
While the governments did make the $92
million reopener request quite some timeago, in August 2006, they have not actuallysued Exxon for the money. A state lawyerhas said certain studies were proceeding onquestions such as whether attempts to cleanaway residual oil are advisable.
An oil industry critic, Rick Steiner, askedthe court to force Exxon to pay the $92 mil-lion, arguing it was clear to him that the gov-ernments lacked the resolve to aggressivelypursue the payment.
Federal Judge H. Russel Holland inMarch turned back Steiner’s effort. But thejudge did direct the governments andExxonMobil to provide him with a statusreport on the reopener issue by mid-September, and this possibly precipitated thecompany’s Aug. 9 motion.
‘Diminishing returns’In the motion, Exxon’s attorneys draw a
distinction between “cleanup” and “restora-tion,” and argue the consent decree’s reopen-er provision is limited to the latter.
When the on-scene coordinators declaredthe cleanup complete, it was “based on datacollected during the 1991 and 1992 shore-line assessments and clean-up, all of whichsuggested that although not all the oil hadbeen removed, further clean-up would notresult in any net environmental benefit.”
The on-scene coordinators concluded thecleanup had “reached the point of diminish-ing returns,” where continuing might domore harm than good, the Exxon motionsays. Now the governments want to resumethe cleanup using oil removal technologiessuch as bioremediation, which is “the samemethod utilized by Exxon in 1991 and1992,” the motion says.
But the reopener is limited to “restorationprojects,” Exxon argues, while the plan thegovernments have put forth “contemplatesnothing more than clean-up.” �
Contact Wesley Loy at [email protected]
By ALAN BAILEYPetroleum News
In the six years since Shell returned toAlaska with ambitions to explore in the
high-potential but remote Arctic outercontinental shelf, the company has sub-mitted several exploration plans for gov-ernment agency approval, only to bethwarted by appeals and litigation overpermitting decisions. But the Aug. 4 con-ditional approval of the company’sBeaufort Sea exploration plan by theBureau of Ocean Energy Management,Regulation and Enforcement, coming inthe shadow of the fallout from theDeepwater Horizon disaster in the Gulf ofMexico, marks a significant step towardsthe company finally being able to sink adrill bit into the shallow seafloor offAlaska’s North Slope.
In the wake of the Gulf of Mexico dis-aster BOEMRE has significantly tight-
ened its safety rules for offshore drillingand Shell’s plans are subject to therequirements of these rules.
“We base our decisions regarding ener-gy exploration and development in the
Arctic on the best scientific informationavailable,” said BOEMRE DirectorMichael Bromwich when announcing hisagency’s approval decision for Shell’splan. “We will closely review and monitor
Shell’s proposed activities to ensure thatany activities that take place under thisplan will be conducted in a safe and envi-ronmentally responsible manner.”
Reactions to decisionThe BOEMRE decision was met with
considerable enthusiasm from Alaskapoliticians.
“Approval of this exploration plan isfantastic news for Shell, for Alaska’s oiland gas industry and is a welcome shot-in-the-arm for Alaska’s long-term eco-nomic good health,” said Sen. MarkBegich. “I’m confident this will ultimate-ly be the first of many developments tokeep oil flowing through Alaska’s eco-nomic lifeline, the trans-Alaska oilpipeline. Development of natural gas inAlaska’s coastal waters also is key to ourstate’s long-awaited natural gas pipelineproject.”
“Shell has been working to secureapproval of this plan for over five years,”said Sen. Lisa Murkowski. “This is anoth-er positive step forward, and I’m hopefulthat they will soon be able to move for-ward with exploration and production inthe Beaufort. If this plan is allowed toadvance this time, it could help addressmany of our most pressing challenges,creating tens of thousands of new jobs,generating hundreds of billions of dollarsin new tax revenues, reducing ourdependence on foreign oil, and improvingour trade balance.”
However, organizations opposed toArctic offshore oil development reactedwith horror.
“The U.S. Department of the Interiortook a dangerous and disappointing leaptowards drilling in the remote and fragilewaters of America’s Arctic Ocean today,”said Earthjustice on Aug. 4 on behalf ofmore than a dozen environmental organi-zations. “Shell’s drilling risks a major oilspill, and neither Shell nor the govern-ment could respond adequately to such acatastrophe. It risks harming the endan-gered bowhead whale, a species central toAlaska Native subsistence traditions.Today’s decision to rubber-stamp Shell’sdrilling ignores many of the lessons of theGulf tragedy and the recommendations ofgovernment scientists and puts the ArcticOcean and its coastal communities atgreat risk.”
Two prospectsShell’s Beaufort Sea plan involves
drilling two wells in its Sivulliq prospectand two wells in its Torpedo prospect,starting in 2012 and probably using thecompany’s Kulluk floating drilling plat-form. Both prospects are located on thewest side of Camden Bay, east of PrudhoeBay. Sivulliq is the location of a known oilfield, previously called Hammerhead.
The Kulluk is a conical shaped vessel,held to the seafloor by 12 anchors anddesigned to be able to drill in moving iceup to four feet thick, with the ability towithstand more severe ice conditions ifsupported by ice management vessels,according to the BOEMRE environmentalassessment of Shell’s plan.
Drilling a well at a Torpedo drill sitewill likely take 44 days, with a Sivulliqwell taking 34 days to drill, the environ-mental assessment says.
And exploration plan approval is con-tingent on Shell complying with a series
8 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
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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
One step at a time for Shell’s OCS plansBOEMRE conditional approval of company’s Beaufort Sea exploration plan is a major milestone but other permitting hurdles remain
NSB says Shell needs borough permitsIn comments submitted to the Bureau of Ocean Energy Management,
Regulation and Enforcement on Shell’s Beaufort Sea exploration plan, the NorthSlope Borough said that Shell needs borough permits for some of its plannedactivities, despite a statement in the company’s plan that no local permits are need-ed. The activities in question involve onshore and nearshore operations, within thearea of borough jurisdiction, including the transfer of supplies from onshore atPrudhoe Bay, and crew changes by helicopter and fixed wing aircraft fromDeadhorse or Barrow.
“If Shell has contracted with another operator to provide these support servic-es, Shell must verify that the company has obtained the appropriate NSB permitand amended the permit to include the increased use resulting from Shell projectactivity,” the NSB said.
—ALAN BAILEY
see OCS PLANS page 9
of stipulations attached to the company’sBeaufort Sea leases, including the needfor a bowhead whale monitoring programand an agreed plan of cooperation withlocal subsistence hunters. Shell hasagreed to suspend its operations andremove its vessels from the region of theNuiqsut and Kaktovik subsistence bow-head whale hunts while those hunts are inprogress.
No significant impactA finding of no significant impact in
the environmental assessment thatBOEMRE has conducted for Shell’s planis the basis for the agency’s conditionalapproval of that plan — under the terms ofthe National Environmental Policy Act,were the agency to have determined a sig-nificant impact from Shell’s plannedactivities, it would have had to prepare anenvironmental impact statement, a proce-dure that could take perhaps a couple ofyears to complete.
BOEMRE did in fact prepare an EISfor the Beaufort Sea lease sale in whichShell purchased its leases and, under theagency’s procedures, the findings of thatEIS carry forward, or “tier,” into the envi-ronmental assessment for Shell’s plan. Ineffect, BOEMRE’s approval of Shell’splan indicates that the agency has foundno significant impacts beyond the impactsalready considered in the lease sale EIS.
But, with the Deepwater Horizon dis-aster having happened since the BeaufortSea lease sale and its EIS, many havequestioned the oil spill risks associatedwith Arctic offshore drilling.
In its assessment of Shell’s BeaufortSea plan, BOEMRE has concurred withShell’s view that drilling under the shal-low waters of the Beaufort Sea poses amuch lower well blowout risk than drillinginto a high-pressure reservoir under thedeep waters of the Gulf of Mexico.BOEMRE says that the Torpedo H well,the well with the highest potential oil flowrate of the four wells that Shell wants todrill, would be drilled to a depth of 10,000feet in water depths of about 120 feet,with anticipated oil reservoir pressures of3,600 pounds per square inch. That com-pares with a drilling depth of 18,000 feet,a 5,000-foot water depth and an 11,856-pound-per-square-inch reservoir pressurefor BP’s ill-fated Gulf of MexicoMacondo well.
Worst case scenarioAccording to a BOEMRE evaluation, a
worst case flow rate from a Torpedo wellwould be 2,498 barrels per day, a lowerfigure than the 9,468 barrels per day thatShell had estimated for the same well.Estimates for the rate of oil discharge dur-ing the Gulf of Mexico Macondo wellblowout range from 53,000 to 62,000 bar-rels per day.
Moreover, BOEMRE has concludedthat there is no likelihood of a major oilspill as a result of Shell’s drilling activi-ties. This conclusion is based in part onthe very low incidence of well blowouts inrecent decades; the small number of wellsthat Shell plans to drill; and the fact thatno previous wells drilled in the ArcticOCS have caused oil spills. The agencysays that it has also taken into accountnew drilling safety rules that it has intro-duced since the Deepwater Horizon inci-dent, including new blowout preventerinspection requirements and the requiredplacement of BOEMRE inspectors on off-shore rigs during drilling operations. Alsofactoring into the BOEMRE decision wasShell’s commitment to implement newwell capping and containment technology,in the light of experience from the
Macondo well.A significant concern expressed by
some is the lack of an Arctic supportinfrastructure, were it to become neces-sary to launch a major oil spill response inthe offshore. Shell says that it hasaddressed this issue by assembling a self-contained oil spill response fleet to be sta-tioned offshore ready to swing into action,should the need arise. The fleet includesice-strengthened oil spill response vesselsand an ice-strengthened tanker for storingrecovered oil. Shell has also madearrangements for nearshore and onshoreoil spill protection and cleanup.
Regional response planBOEMRE is still reviewing Shell’s oil
spill prevention and contingency plan but,in its environmental assessment of thecompany’s exploration plan, BOEMREsays that Shell’s contingency plan is a“regional oil spill response plan thatdemonstrates Shell’s capabilities to pre-vent, or rapidly and effectively manage,oil spills that may result from exploratorydrilling operations”
“The BOEMRE analysts found thatnone of the (public) comments or ques-tions (relating to oil spill prevention andresponse) contained credible new infor-mation … that would bring into questionwhether the proposed action would likelyresult in no more than minimal to minor,at most cases below measurable, effects,”wrote James Kendall, BOEMRE directorof the Alaska Outer Continental ShelfRegion, in his official notice of a findingof no significant impact. “While there ispublic controversy over the issue of verylarge oil spills, there is no scientific con-troversy or scientifically supported chal-lenge to the fact that very large oil spillsremain extremely low probability events.”
Permits neededHowever, Shell still needs to cross
some significant permitting hurdles
before finally seeing a clear way aheadclear for drilling in 2012.
Top of the hurdle list is theEnvironmental Protection Agency’s airquality permit for the operation of theKulluk floating drilling platform and thesupport fleet for the drilling operations.With previous attempts by Shell to obtainair permits for its planned drilling miredin appeals and litigation, a new air permitfor the Kulluk and its attendant fleet ismaking its way through the regulatoryprocess — on July 22 EPA published adraft permit for public review, with com-ments due by Sept. 6.
Other permitting requirements includean EPA approval to include dischargesfrom the drilling fleet within the terms ofa general National Pollutant Discharge
Elimination System permit for offshoreoil and gas operations — as part of itsBeaufort Sea exploration plan Shell hasagreed to transport the bulk of its wastedischarges out of the region, rather thandisposing of the waste into the ocean.Shell will also require a U.S. Army Corpsof Engineers permit for its drilling opera-tions. In addition, the company will needauthorizations from the National MarineFisheries Service and from the U.S. Fishand Wildlife Service for the incidentalharassment of marine mammals.
And, prior to drilling any well, Shellwill require a drilling permit fromBOEMRE. �
PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 9
FINANCE & ECONOMYMiller files corrected financial report
Miller Energy Resources Inc. on Aug. 9 filed an amended Form 10-K annual reportwith the U.S. Securities and Exchange Commission to correct errors in a previous fil-ing.
The report covers the fiscal year ended April 30.Miller’s announcement that it would need to file the amended annual report was
part of the turbulence that hit the Tennessee-based company beginning in late July.The price of Miller shares, traded on the New York Stock Exchange, closed Aug.
10 at $2.50, a huge drop from the $7-plus seen through most of July.At least a dozen law firms have announced they have begun “investigations” into
whether Miller Energy violated securities laws.Scott M. Boruff, Miller’s chief executive, has said the company is sound and its
assets are accurately valued. He said the firm has been the target of short-selling blog-gers seeking to profit by discrediting the company and driving down its stock price.
Boruff also said Miller Energy has grown quickly and is trying to shore up itsaccounting procedures, engaging major accounting firm KPMG to audit the compa-ny.
Miller’s subsidiary, Cook Inlet Energy LLC, operates oil and gas properties inAlaska’s Cook Inlet basin. These properties, acquired in late 2009, propelled Miller toa much higher profile financially.
Miller’s revised annual report shows a loss for the year of nearly $3.9 million. Theoriginal annual report, filed July 29, showed a $4.4 million loss.
—WESLEY LOY
continued from page 8
OCS PLANS
Contact Alan Bailey at [email protected]
By ALAN BAILEYPetroleum News
Buffeted by a gale of comments andquestions over Cook Inlet Region
Inc.’s proposed sale of power to ChugachElectric Association from a planned windfarm on Fire Island, offshore Anchorage,the Regulatory Commission of Alaskahas decided to conduct a hearing intoCEA’s purchase agreement for Fire Island
power.“We cannot approve the power pur-
chase agreement based on the existingrecord,” the commission wrote in anorder dated Aug. 8. The commission isinviting various interested parties to par-ticipate in the hearing and says that it willexpedite a final decision in the matter.CEA and CIRI had requested a Sept. 15deadline for a decision, to enable con-struction of the wind power facility to be
done in time to secure a federal grant forthe project.
Cost concernsIn the course of lengthy negotiations
between CIRI and various Alaska Railbeltpower utilities, the utilities have expressedconcern with the initial cost of the windpower, and with the cost and challengesassociated with integrating Fire Islandwind power into other power sources inthe grid.
The integration issues arise from thefact that wind power is subject to thevagaries of varying wind strengths, withthe resulting fluctuations in power outputhaving to be balanced from other powersources. The spare generation capacityneeded to balance the wind power fluctu-ations will cost money to maintain andoperate.
CIRI has played down the integrationissues, saying that the power output fromFire Island would constitute a relativelysmall portion of the Railbelt grid’s overallgeneration capacity. And, although CIRIaccepts that the initial cost of power fromFire Island would be higher than the costof power from other sources, the corpora-tion has said that stable pricing from therenewable wind energy would result inlong-term cost benefits. However, CEA isthe only one of the six Railbelt power util-ities to have thus far signed a Fire Islandpower purchase agreement. And, with thelack of multiple customers for its project,CIRI has scaled down its Fire Island plan.
ML&P statementAnchorage utility Municipal Light &
Power, a division of the Municipality ofAnchorage, has filed a statement withRCA, spelling out in some detail theproblems that it sees with the prospect ofCEA purchasing power from the FireIsland wind farm. Issues associated withCEA’s integration of wind power wouldlikely have the knock-on effect ofincreasing the cost of ML&P’s power,wrote ML&P Manager of RegulatoryAffairs, Daniel Helmick, in the ML&Pstatement to RCA. Before RCA approvesCEA’s Fire Island power purchase agree-ment CEA must file a specification ofhow it plans to integrate Fire Islandpower into its operations, with a require-ment that CEA eliminate, if possible, anyresultant cost to ML&P; CEA shouldcompensate ML&P for any unavoidablecost repercussions, Helmick wrote.
Helmick said that CEA would proba-bly balance the fluctuating output fromFire Island by making rapid adjustmentsto the power output from a new com-bined-cycle, gas-fired power plant thatCEA and ML&P are jointly building insouth Anchorage. Although the new gas-fired plant would be capable of sustain-ing the required power fluctuations, theresulting operation would make less thanoptimal use of the plant, with increasedwear and tear on the plant also increasingthe plant maintenance costs. The endresult would likely be an increase in thecost of power from the plant, with part ofthat cost passed on to ML&P as a jointplant owner and as a buyer of power fromthe plant, Helmick wrote.
The use of CEA’s existing gas-firedpower plants to balance the Fire Islandpower fluctuations would be relativelyexpensive because of the inefficiencies ofthose plants, Helmick wrote.
Gas contract issuesIn addition, contracts for natural gas
supplies in Southcentral Alaska do notinclude the kind of flexibility in supplyrates that would be needed to supportrequired short term fluctuations in powerfrom a gas-fired power station — diver-gences from prescheduled gas deliveriesincur penalty payments, Helmick wrote.
And, although CEA and ML&P bothobtain power from the Bradley Lakehydroelectric power station in the south-ern Kenai Peninsula, it would be difficultfor this power station to change its outputquickly enough to match wind powerfluctuations, Helmick wrote. Moreover,any use of Bradley Lake to balance outshortfalls in power supplies from FireIsland would adversely impact the abilityof utilities other than CEA to purchaseBradley Lake power, thus impacting thecost of power for those other utilities, hewrote.
Helmick also questioned the powercost calculations in the CEA power pur-chase agreement, saying that the pur-chase agreement understates the all-incost of integrating Fire Island power intoCEA power supplies.
10 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
� A L T E R N A T I V E E N E R G Y
RCA wants Fire Island wind power hearingSays that Chugach Electric has not provided enough information to answer concerns about impact of wind power on Southcentral grid
PIPELINES & DOWNSTREAMTesoro replacing ANS crude with Bakken
Tesoro Corp. plans to replace some Alaska North Slope crude oil with oil fromNorth Dakota shale at one of its West Coast refineries, the company announcedrecently.
Tesoro said it plans to ship 30,000 barrels per day from the Bakken Shale in NorthDakota’s Williston basin to its oil refinery in Anacortes, Wash., through a new railproject.
The company said that Bakken crude oil yields approximately 16 percent moreclean product and less fuel oil than Alaska North Slope crude, and that during thesecond quarter, the differential between those products was approximately $28 perbarrel.
Oil from source rock is cleaner than oil from conventional reservoirs because in aconventional reservoir the oil picks up impurities as it migrates from the source rock.
The $50 million project will include loading and unloading facilities and dedicat-ed rail cars at the Anacortes refinery. It is expected to take nine to 12 months to com-plete.
Tesoro reported refining throughput from its Alaska and Washington facilities of168,000 barrels per day during the second quarter, up from 84,000 bpd in the secondquarter of 2010, and a gross refining margin of $220 million, up from $98 millionlast year.
(The company does not break out figures by state or by specific facility.)—ERIC LIDJI
CEA said that it is in fact planningto use the Cooper Lake
hydroelectric power station in thecentral Kenai Peninsula, a powerstation over which CEA has full
control, to balance fluctuations inFire Island power.
see FIRE ISLAND WIND page 11
PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 11
� N A T U R A L G A S
FERC begins Alaska gas line EIS processPETROLEUM NEWS
The Federal Energy Regulatory Commission said in anAug. 5 Federal Register notice that its staff will pre-
pare an environmental impact statement for the plannedAlaska Pipeline Project.
FERC said the project, being advanced by TransCanadaAlaska Co. LLC and ExxonMobil Alaska Midstream GasInvestments LLC, would move gas from Alaska’s NorthSlope to the Alaska-Canada border for delivery to NorthAmerican markets.
The commission noted that the project proponent is con-sidering an alternative proposal to build a natural gaspipeline to Valdez for delivery into a liquefied natural gasplant for export of LNG, but said because it “has receivedvery little information on the LNG plant and the associatedpipeline, the Valdez proposal is not sufficiently developedfor the FERC to include in the environmental review at thistime.”
FERC said that because of the magnitude of the propos-al, the scoping period would remain open for an extendedperiod, through Feb. 27, 2012. A schedule of public scopingmeetings, tentatively scheduled for January and Februarynext year, will be issued at least a month prior to the meet-ing dates.
TransCanada and ExxonMobil plan to file a formalapplication with FERC in October 2012, begin constructionin the fourth quarter of 2014 and put the pipeline systeminto service in the third quarter of 2020.
Includes line from Point ThomsonThe project FERC will study in the EIS includes some
58 miles of 32-inch-diameter pipeline and associatedaboveground facilities from the processing plant at thePoint Thomson field to a planned gas treatment plant nearPrudhoe Bay; a new gas treatment plant near Prudhoe Baycapable of producing up to 4.5 billion cubic feet per day ofpipeline-quality gas; about 745 miles of 48-inch-diameterpipeline and associated ancillary and auxiliary facilitiesfrom the GTP to the Alaska-Yukon border; construction ofat least five delivery points, eight compressor stations, twometer stations, various mainline block valves and piglaunching-receiving facilities; and associated infrastruc-ture such as access roads, helipads, construction camps,pipe storage areas, contractor yards, borrow sites and dockmodifications and dredging at Prudhoe Bay.
The Alaska Mainline would start at the GTP, generallyfollow the existing trans-Alaska oil pipeline to DeltaJunction and then generally follow the Alaska Highway
southeast to the Alaska-Yukon border. At the border the Alaska Mainline would connect with
a new pipeline in Canada to deliver gas to North Americanmarkets through the Alberta Hub or other facilities nearthe British Columbia-Alberta border.
While no application has yet been filed, FERC said itis initiating the EIS under the National EnvironmentalPolicy Act under its pre-filing process. As part of the pre-filing process, FERC said it has already started to meetwith the project proponent, jurisdictional agencies, AlaskaNative tribes, local officials and other interested stake-holders.
The agency is requesting specific comments or con-cerns about the planned project, and said comments“should focus on the potential environmental effects, rea-sonable alternatives, and measures to avoid or lessen envi-ronmental impacts,” and said the more specific commentsare, the more useful they will be.
Comments may be submitted in writing to the com-mission or electronically at the commission’s website atwww.ferc.gov.
More information is available on FERC’s website, oron the Alaska Pipeline Project website atwww.thealaskapipelineproject.com. �
CEA: net benefitCEA, in a subsequent filing with
RCA, said that an analysis of the futurecost of power had indicated a net benefitto purchasing power from the Fire Islandwind farm. Initially, CEA’s customers’bills would increase by about 2 percentwhen Fire Island comes on line but with-in seven to 11 years wind power wouldrender CEA’s electricity less expensivethan otherwise, as gas prices rise.
CEA said that it is planning to use theCooper Lake hydroelectric power stationin the central Kenai Peninsula, a powerstation over which CEA has full control,to balance fluctuations in Fire Islandpower. As fallback positions, CEA couldfluctuate the power output from its shareof the Bradley Lake facility or fromwhichever of its gas-fired power stationsare in operation at the time, the utilitywrote.
A scaling down of the Fire Islandpower plant from 52 megawatts to 17.6megawatts, as a consequence of CEAbeing the only Fire Island customer, hasalso resulted in a situation where CEAcan contain the wind power integrationcosts using its own resources, with noadditional impact on the operation of thenew south Anchorage gas-fired powerplant, CEA said.
And CEA said that it is completing astudy into its wind power integrationarrangements and is willing to file theresults with RCA.
However, the commission said in itsAug. 8 order that it does not think thatCEA has responded adequately to ques-tions raised over its power purchase agree-ment and that a hearing is required. �
continued from page 10
FIRE ISLAND WIND
Initially, CEA’s customers’ billswould increase by about 2 percentwhen Fire Island comes on line but
within seven to 11 years windpower would render CEA’s
electricity less expensive thanotherwise, as gas prices rise.
Contact Alan Bailey at [email protected]
By SEAN COCKERHAMAnchorage Daily News
Interior Secretary Ken Salazar came toAnchorage on Aug. 8 and said the
Obama administration wants more oildrilling in Alaska, potentially includingoffshore Arctic development.
Salazar joined Alaska Sen. MarkBegich and Rhode Island Sen. Jack Reedfor a meeting with Alaska businesspeopleand said the president’s attitude towardArctic offshore drilling is “Let’s take alook at what’s up there and see what it iswe can develop.”
But he also said Alaska’s Arctic needsthe infrastructure for responding to poten-tial oil spills and that there are painful les-sons from the Deepwater Horizon spill inthe Gulf of Mexico.
“Not the mightiest companies withmultibillion-dollar pockets were able todo what needed to be done in a timely
basis, and the repre-sentations of prepa-ration simply turnedout not to be truefrom the oil compa-nies that had a legalobligation to shutdown that kind of anoil spill. ... Whenyou look at theArctic itself, we rec-ognize that there are different realities —the ocean is much shallower, conditionsare very different than we had in the Gulfof Mexico. (But) there are challenges thatare unique to the Arctic,” Salazar toldAlaska reporters.
Salazar said one solution is “having anagency within the United States govern-ment and Interior, the Bureau of OceanEnergy Management and Regulation, thatcan in fact do its job.” The agency is thesuccessor to the Minerals Management
Service, which was largely discreditedafter the Gulf spill.
Conditions will be imposed“Secondly, there will be conditions
that will be imposed on whatever drillingthat does occur in either the Beaufort orthe Chukchi on down the road that willincorporate the lessons that have beenlearned (from the Gulf),” he said. “Andthirdly, there is also a recognition wehave that there is additional work thatneeds to be done with respect to theunderstanding of the Arctic, the scienceand the need for having effective oil spillresponse,” Salazar said.
Begich said he was encouraged theadministration is moving forward onArctic development while working outwhat Coast Guard and other resourceswould be needed in the area.
Earlier in August the InteriorDepartment’s Bureau of Ocean Energy
Management, Regulation andEnforcement gave Shell a conditionalexploration permit that covers a programthat would drill four wells over two yearsin Camden Bay of the Beaufort Sea, duenorth of the coastal plain of the ArcticNational Wildlife Refuge. But the permitis contingent on many other federal per-mits and approvals, including oil-spillresponse plans and marine mammal pro-tection.
Shell is also seeking authorization todrill in the Chukchi Sea.
Shell’s Alaska government affairsmanager, Cam Toohey, was at the Aug. 8meeting with Salazar, Begich and Reed atthe Cook Inlet Region Inc. building inMidtown Anchorage. Toohey said the oilcompany has seen what it considers animproved attitude among the InteriorDepartment toward providing the certain-ty needed to invest in projects.
Federal working groupObama in July signed an executive
order to create a new federal workinggroup tasked with having agencies bettercoordinate Alaska oil and gas permittingand other regulatory oversight. TheWhite House said the working group,which is overseen by Deputy InteriorSecretary David Hayes, is designed tosimplify oil and gas decision-making inAlaska by bringing together federal agen-cies to collaborate as they evaluate per-mits and environmental reviews. Hayesjoined Salazar in traveling to Alaska.
Salazar said he hoped it would helpwith instances like the dispute amongagencies over a permit for a bridge cross-ing of the Colville River, which would letcompanies develop the onshore CD-5drill site within the National PetroleumReserve-Alaska.
Salazar on Aug. 8 reiterated Obama’ssupport for drilling in the NPR-A. Hesaid the president wants to increase thedomestic energy supply, reduce con-sumption through measures like greaterfuel efficiency, and look at alternativefuels.
The businesspeople that Salazar,Begich and Reed met with in Anchorageon Aug. 8 were particularly concernedabout what CIRI President Margie Browndescribed as the “regulatory morass thatwe find ourselves in.”
Begich and Salazar were also planningto meet with the Alaska Federation ofNatives Aug. 8 before Salazar, his deputy,Hayes, and Rhode Island Sen. Reed go onto Fairbanks to tour the Bureau of LandManagement wildfire fighting facilitiesalong with Alaska Sen. Lisa Murkowski.Salazar’s three-day Alaska trip alsoincludes a visit to the Alpine oil field onthe North Slope, a flyover of the NPR-Aand a meeting with Shell officials inBarrow on offshore exploration.
Salazar’s trip concludes Aug. 10 witha visit to the Eielson Visitors Centerwithin Denali National Park andPreserve. �
12 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
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For service in your area, call Crowley at 1.800.977.9771
� G O V E R N M E N T
Salazar says president backs drillingInterior secretary tells Alaskans administration wants more oil drilling in Alaska, potentially including outer continental shelf
The businesspeople that Salazar,Begich and Reed met with inAnchorage on Aug. 8 were
particularly concerned about whatCIRI President Margie Browndescribed as the “regulatory
morass that we find ourselves in.”
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PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 13
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� N A T U R A L G A S
AGPA again pushingValdez LNG projectPort authority’s Bill Walker tells chamber it’s time to dump AGIA,but cautions 2 wrongs — AGIA and ASAP — don’t make a right
By KRISTEN NELSONPetroleum News
It’s time for the State of Alaska to get outof its Alaska Gasline Inducement Act
contract with TransCanada, Bill Walker toldthe Anchorage Chamber of Commerce Aug.8.
It’s time for the state to decide, he said,whether Alaska will lead or lose the energyrace.
The Legislaturehas signaled thedesire to get out of theAGIA contract, aproject to take NorthSlope gas throughCanada to NorthAmerican markets,Walker said, by pro-moting the bullet line,the Alaska StandAlone Gas Pipeline project or ASAP.
But both are wrong for the state — andtwo wrongs don’t make a right, he said.
Walker, general counsel for the AlaskaGasline Port Authority, said the right step forthe state is to build a gas pipeline from theNorth Slope to Valdez, providing the infra-structure for natural gas to be shipped toValdez where it would be liquefied at a facil-ity built by private industry and shipped tothe Asian market.
Because Asian LNG prices are indexedaround crude oil prices, the state wouldmake a profit from LNG, as well as meetingin-state energy needs at the best possibleprice.
The port authority was formed in 1991and has been somewhat silent in recent yearsin face of enthusiasm for a pipeline to takeNorth Slope gas to North American mar-kets.
AGPA’s revived enthusiasm for its LNGproject is the result of booming shale gasdevelopment in the Lower 48 and Canadawhich is resulting in plans to export LNGfrom the Lower 48 and the conclusions of arecent study done for the group by WoodMackenzie which found an Alaska projectwould be competitive with other proposedprojects.
Alaska can competeAGPA asked Wood Mackenzie, an inter-
national energy consulting firm, to see ifAlaska would be competitive with proposedLNG projects (see story in Aug. 7 issue), inspite of the 800-mile gas pipeline required to
move North Slope gas to Valdez. Wood Mackenzie used data from
TransCanada’s Federal Energy RegulatoryCommission filings and concluded thatbecause ANS gas was already coming out ofthe ground, the upstream development costwould be 26 cents per million Btu.
That compares, Walker said, to Kitimat,which is trying to get financing for anupstream cost of $5.20.
Walker doesn’t believe that getting thegas wouldn’t be an issue. With reasonableexpectation of profits, the owners will ship,he said. They just don’t want to take all ofthe risk; and they don’t owe us a gas line.
As for exporting, he said projects havebeen getting export licenses to move LNGfrom the Lower 48.
He said the state needs to announce to theworld that Alaska’s gas will be available forthe Asian market, work with the North Slopeproducers to market North Slope natural gasto Asian markets, begin working towardfinancing of a gas line and the LNG projectand once long-term gas contracts andfinancing are secured, begin construction.
Pipeline as infrastructureThe gas pipeline should be viewed as
infrastructure, he said — and the stateshould share and shoulder some of the proj-ect risk. Walker said we wouldn’t expectLynden or Carlile, major truckers in thestate, to build a highway, and we shouldn’texpect the producers to build a pipeline.
It makes sense for the state to get the gasline built, he said, just as it made sense forthe Canadian government to own the firstgas pipeline across Canada. But once theCanadian line was built, it was immediatelysold, Walker noted.
ASAP, the small in-state line, wouldn’thave the same benefits as a larger line toexport LNG, he said, and wouldn’t providethe lowest-cost energy to Alaskans.
Because the gas moved by ASAP wouldbe for in-state use there would be no staterevenue.
And because of the small volume, therewould be no incentive for natural gas explo-ration on the North Slope, which is widelyexpected to result in more oil being found aswell as more natural gas.
Walker said only one gas line will bebuilt in the state, and it should be one thatbenefits all of Alaska. �
BILL WALKER
Contact Kristen Nelson at [email protected]
NATURAL GASKenai LNG to stay open through October
ConocoPhillips is keeping its Alaska liquefied natural gas plant open a little longer.The company plans to keep the Kenai Peninsula LNG facility and export terminal
operational through October to produce additional cargo, but still plans to mothball theplant this year.
ConocoPhillips and partner Marathon Oil announced plans this past February toplace the pioneering 42-year-old facility in warm storage because of declining vol-umes of local natural gas supplies and difficulty securing contracts overseas, but keptthe plant active through the summer to send additional, unexpected shipments to Japanand China.
ConocoPhillips is still working out the details of the cargo and cannot yet provideany information on where the shipment is going, spokeswoman Natalie Lowman said.
—ERIC LIDJI
14 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
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LET’S GO.
� N A T U R A L G A S
Route probed for environmental impactsScientists working along Alaska Pipeline Project route from Prudhoe Bay to Canadian border; work this summer largest field program
By BILL WHITEResearcher/writer for the Office
of the Federal Coordinator
Squads of scientists this summer have joined the cari-bou and Dall sheep, eiders and eagles, moose and
muskrat, salmon and grayling that inhabit the proposednatural gas pipeline route through Alaska.
The scientists are there to catalog, cross-check andverify the exact nature of that route — from the animalsto the permafrost and faults — before the first trench canbe carved for the major pipeline from Alaska throughCanada.
The data gathering this field season is a massiveeffort, a centerpiece in the most expensive push in yearsfor the decades-long quest to bring the flush North Slopenatural gas reserves to consumers and industry insideand outside the state.
The field season will document the soils, vegetation,streams, lakes, wetlands, water quality, wildlife and fishalong a roughly 200-foot-wide, 745-mile pipeline corri-dor from Prudhoe Bay to the Canadian border. A similareffort is under way for the pipeline’s 966-mile runthrough Canada.
Related efforts afoot now or planned for the next yearinclude:
• Studying how building the $32 billion to $41 billionpipeline project would affect Alaska itself, from newjobs and housing needs to school and police systemsstrained by a population bulge during construction.
• Analyzing how Alaskans who rely on fish, game andother subsistence resources found along the pipeline cor-ridor would be affected.
•Understanding and identifying how ancient Alaskansused the corridor and what traces they left behind.
• Mapping earthquake faults and other geological haz-ards the pipeline would cross.
• Refining the design of the pipeline itself as well as
the estimated $12 billion gas treatment plant at PrudhoeBay that would remove water, carbon dioxide and otherimpurities, then compress the raw gas before it enters thepipeline.
• Detailing the noise and air pollution emissions of thePrudhoe gas treatment plant and the eight compressorstations positioned along the pipeline in Alaska.
• Determining how much to deepen an offshore ship-ping channel to the Prudhoe cargo dock as well as whereto dispose of dredged sediment.
Humming in the background during this summer’sfield season work are two looming deadlines and a land-mark 42-year-old law — the National EnvironmentalPolicy Act — that transformed how federal agenciesapproach development projects across the United States.
The first deadline hits the pipeline sponsor,TransCanada and ExxonMobil (known as the AlaskaPipeline Project), in just 14 months.
A state license for the project gives them untilOctober 2012 to apply for a Federal Energy RegulatoryCommission certificate of public convenience andnecessity. In exchange, the state is reimbursing the ven-ture for some of its development costs. The companiesneed that FERC certificate to build and operate theirpipeline.
The second deadline comes next: FERC will have 18months to finalize the environmental impact statementfor the Alaska project. Congress imposed that tight dead-line in 2004 to hurry along approval of the Alaskapipeline — an EIS for other epic projects can take yearsto complete.
Both the project sponsor and FERC hope that thor-ough, air-tight work by the field season scientists willhelp jump-start the critical environmental impact state-ment.
Myron Fedak in chargeThe general overseeing this summer’s field season is
Myron Fedak.Fedak is a career ExxonMobil employee who has
been headquartered in a Midtown Anchorage officebuilding for the past two years. His official title is U.S.environment, regulatory and land manager for the AlaskaPipeline Project. He and his team are compiling 11 denseand detailed “resource reports” FERC wants filed withthe certificate application in October 2012. The resourcereports will form the foundation of the environmentalimpact statement FERC prepares later.
Before Alaska, Fedak did similar work for other bigExxonMobil development projects.
Those included the birth of a major oil industry in thenorthcentral African nation of Chad. Three new oilfields. A 665-mile pipeline strung through Chad andcoastal Cameroon. An offshore marine terminal wheretankers ingest the export oil. The first Chad oil flowed in2003 and new oil fields launched in the ensuing years,similar to how starting the Prudhoe Bay field and trans-Alaska oil pipeline in 1977 sparked development ofnumerous nearby North Slope fields in the 1980s.
Fedak said he worked mainly from the ExxonMobiloffices in Houston during Chad-Cameroon years, super-vising environmental field work probing the plains,plateaus and jungles of tropic Africa.
This time Fedak’s work in Alaska has transported himfar from the muggy Texas metropolis he formerly calledhome.
He oversees a crew of about 125 field workers plusperhaps 100 support workers. This is the second and big-ger of the two major field seasons for the Alaska gaspipeline project.
This is the biggest year all around for theTransCanada/ExxonMobil project as the companiesfinalize their plans before filing with FERC next year.The companies had spent an estimated $303 million onthe Alaska Pipeline Project from inception through June.
see FIELD SEASON page 15
Their budget for the 12 months that start-ed in July will add $209 million to thattotal, the largest annual budget to date forthe Alaska project. The field work is onlya fraction of the spending. (Under a 2007law, the state of Alaska is reimbursing thecompanies for up to $500 million of theirdevelopment work, a total expected to bereached in 2014. The companies estimatethat for the current fiscal year’s $209 mil-lion budget, they will fund $48 millionand the state will reimburse them for$161 million.)
The field workers include wildlife,fisheries and wetlands biologists; geolo-gists and engineers; archeologists andanthropologists; marine surveyors andhydrologists.
They are deployed in boats in theBeaufort Sea north of Prudhoe Bay andscattered in small crews along thepipeline route to the Canadian border nearwhere the Alaska Highway crosses.
They’ve installed one temporary fieldcamp, on an existing gravel pad in theBrooks Range’s Atigun Pass. The campfor 18 people, including a cook and care-taker, consists of nine trailers — five forsleeping, one each for a kitchen, din-ing/recreation, toilets/showers and gener-ator. From this station, the crews candeploy north or south for their field work.
Plugging holesMuch already is known about the
pipeline route.Most of it parallels the trans-Alaska oil
pipeline, subject of extensive study over theyears. Previous gas pipeline ventures,including one about a decade ago, com-piled information. State and federal agen-cies have vast databases on the animals,fish, birds and vegetation along the route.
The soils at this point hold little mystery,Fedak said. Many bore holes have beendrilled, “and the soil 20 feet down is notchanged much,” he said.
“There is a tremendous amount of infor-mation that is already available, with all theprevious work that’s been done, either onsome variation on a theme of an Alaska nat-ural gas pipeline going to the Lower 48through work that’s been done by operatorsin the Prudhoe Bay area, by TAPS along itsright of way, which we in essence in roughterms parallel until we get to DeltaJunction,” Fedak said.
So the field season workers are focusedon the gaps in required information, whereavailable data is incomplete — such asfinding all sites where drinking water istaken within three miles downstream ofproposed pipeline crossings — or data
might be old — such as identifying all sen-sitive wildlife habitats the pipeline wouldpenetrate.
Original work also is occurring. Thisincludes refining plans for keeping the pipefrom breaking when it’s buried in per-mafrost and perfecting plans to safely crossrivers. It includes understanding the earth-quake risks at sites proposed for compres-sor stations. It includes pinpointing theamount of acreage needed for constructionstorage yards, the sources of water for iceroads and the sites where they will minegravel. It includes marine surveys for deep-ening the Prudhoe Bay dock’s shippingchannel so the massive gas treatment plantmodules can be sealifted in over three sum-mers.
Biophysical, cultural teams“We’ve got two groupings of teams, one
doing biophysical investigations and onedoing cultural resources,” Fedak said. “Onthe biophysical side, wildlife — coupleteams go out in the spring up in the BrooksRange to look at Dall sheep. We have teamsthat are going out to do wetlands investiga-tions. We’ve done a lot of office work look-ing at very detailed photographic datawhich we have characterized for the varioustypes of uplands and wetlands, leveragingoff prior field work that has been done byus and others and set up a program in linewith U.S. Army Corps of Engineers State ofAlaska protocols to validate.”
For fish surveys, they follow state Fish& Game Department protocols, he said.
For archeological digs, they follow StateHistoric Preservation Office protocols. Andso on.
The biophysical teams typically numberthree or four people — a senior scientist, ajunior scientist, an assistant and sometimesa bear guard.
The archeological teams are larger,seven or eight people. These involve arche-ologists, with shovels in their backpacks,actually walking stretches of the route,looking for something visible — some sortof ground disturbance — that indicates asettlement might have existed there once.
Settlement sites are more likely to be foundalong rivers, which would have served astransportation corridors and sources ofwater and fish. “We have found new sites,”Fedak said. If necessary, the pipeline willbe rerouted around a site.
Each crew stays in the field for a fewweeks then returns for debriefing and rest.
Among the lessons from last year’s fieldseason: “We needed a better supply ofreplacement tires,” Fedak said, referring tothe punishing Dalton Highway and otherrugged tracks their vehicles follow.
Understanding the impactAll of this work, this cataloging of the
pipeline route to the minutest details —almost, but not quite, to a census of mos-quitoes and no-see-ums — stems from agreat gush of atonement that occurredroughly 40 to 50 years ago among a gener-ation of Washington, D.C., leaders.
These leaders confronted some of thenation’s chronic social and environmentalproblems: Civil rights, poverty, endangeredspecies, air pollution, water pollution, haz-ardous waste.
The National Environmental Policy Actof 1969 was a product of this purge of pastneglect.
NEPA requires federal agencies tounderstand the environmental conse-quences of their decisions. One catalyst forCongress passing NEPA was the bulldoz-ing of neighborhoods in the 1950s and1960s to route interstate highways throughcities.
For the Alaska gas pipeline project,Congress in its Alaska Natural Gas PipelineAct of 2004 named FERC as lead forassembling the environmental impact state-ment, and instructed other federal agencies— the Environmental Protection Agency,Fish & Wildlife Service, Bureau of LandManagement, etc. — to help FERC.
The same law also gave FERC one yearto draft the impact statement after getting acompleted certificate application from apipeline builder, and then 180 days to issuea final environmental impact statementafter the draft comes out.
The EIS will be one factor guiding theenergy regulatory commission’s decisionon whether to issue a certificate forpipeline construction and operation. It willexplore the positive and negative environ-mental effects, as well as alternatives to theproject as proposed.
Some draft reports postedIn advance of preparing the environ-
mental impact statement, FERC requiresthe project sponsor to compile extensiveresource reports — 11 of them for theAlaska project.
The Alaska Pipeline Project teamalready has posted two preliminary draftresource reports, a 189-page general proj-ect description and a 24-page considerationof alternatives. As expected, these are thinon many details, which should be coveredin the December drafts.
The resource reports will become a keypart of the public record on which FERCwill base its environmental impact state-ment. FERC will verify the resource reportinformation and expand the information ifneeded. FERC already has contracted withextra staff to help with its NEPA responsi-bilities for the Alaska project, and it plansmeetings in Alaska soon after the first ofthe year to hear from the public on the draftresource reports.
Meanwhile, this year’s field crews willcontinue to probe the pipeline route possi-bly into October, if the weather holds.
Then, after government agencies com-ment on the draft resource reports pub-lished in December, after other members ofthe public weigh in, it’s likely a smallerfield season will unfold next year. Thateffort will try to plug information holesbefore TransCanada and ExxonMobilfinalize the reports and apply to FERC thatfall for a construction certificate. �
Editor’s note: This is a reprint from theOffice of the Federal Coordinator, AlaskaNatural Gas Transportation Projects,online at www.arcticgas.gov/pipeline-route-probed-to-detail-environmental-impacts.
PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 15
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FIELD SEASON
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Transcube XT fuel tanks transportable while fullTranscube said Aug. 8 that its XT line of high-
capacity diesel fuel tanks delivers an environmen-tally friendly solution for fuel handling in a num-ber of specialized applications. Conforming to allapplicable government regulations, the tanks arelegally transportable while full, making them idealfor rapid fuel deployment to remote locations,natural disaster sites and military operations.
Standard models in the Transcube XT lineinclude the TCT100 and TCT200, which offercapacities of 2,450 gallons and 5,000 gallons,respectively. Each unit features a cylindrical inner tank that is specially designed to hold dieselduring transport. Internal baffles assist in minimizing fuel surges while the tank is in transit orbeing maneuvered on a jobsite. The inner tank is enclosed within an outer wall that ensures110 percent secondary containment to eliminate the risk of spills or ground contamination.
Built within ISO container dimensions, Transcube XT tanks are UL and ULC approved forsafe diesel fuel storage. The tanks are also certified to transport fuel by road, rail and sea undercodes and regulations issued by the U.S. DOT, American Society of Mechanical Engineers, UN
CFR49 part 178.274, International Maritime Dangerous Goods, International Union ofRailways, Transport Canada and Convention of Safe Containers. For more information visitwww.transcube.net/us.
Husband and wife team to buy five ANI publicationsCalista Corp. said Aug. 5 that it and Alaska Newspapers Inc., a wholly owned Calista sub-
sidiary, welcomes Jason Evans and Kiana Peacock as the new publishers of three weeklies andtwo specialty shoppers, effective late August. The newspapers are The Arctic Sounder, TheDutch Harbor Fisherman and The Bristol Bay Times. The specialty publications are TheEquipment Shopper and The Bush Shopper.
Evans, an Inupiat born and raised in Nome, is vice president of consulting for AlaskaGrowth Co. and owner of Financial Alaska. He graduated with a Bachelor of Arts degree fromAlaska Pacific University. Kiana Peacock, born and raised in Kotzebue, works for Alaska Airlinesand has a B.A. degree from Notre Dame University.
“Calista has been honored for the past 19 years to have provided a voice to communitiesacross Alaska, many of which are hundreds or thousands of miles off the road system,” saidCalista Corp. Senior Vice President Margaret Nelson. “We look forward to Evans and Peacockcontinuing that tradition.”
see OIL PATCH BITS page 17
Oil Patch Bits
in the Arctic region change from day today and would make cleanup harder as oilemulsified with seawater.
Final report next yearThe NEB is expected to deliver its
final report to the Canadian governmentin 2012 after being ordered by Ottawa toexpand a review that was already underway when BP’s Deepwater Horizonblowout occurred in the Gulf of Mexico.
The regulator said it is paying specialattention to recommendations made bythe U.S. National Commission on the BPincident.
The Canadian government is underpressure to toughen rules that have beenin place for 40 years and carry a liabilitycap of only C$40 million under a policythat requires a relief well to be drilled inthe same season as a blowout — arequirement that has been challenged bycompanies that are developing programsto explore the Beaufort.
Imperial Oil, ExxonMobil Canada, BP,Chevron Canada and ConocoPhillipsCanada have made work commitments inthe hundreds of millions of dollars tosecure exploration licenses.
None has scheduled any drillingbefore 2014, but all are urging the NEB todrop its requirement for same-seasonrelief wells in the event of a blowout orspill.
Rob Powell, of the World WildlifeFund’s Arctic program, said it is impor-
tant that research such as the S.L. Rossstudy is conducted before Canada’sapproves any more activity in the Arctic.
He said that what matters most is whatpercentage of oil can be recovered, notingthe report’s finding that even when weath-er conditions are at their best, technologydoes not offer a complete answer. �
continued from page 1
ARCTIC CLEANUP
PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 17
Even under the most optimistic forecasts, the U.S. will still depend on oil and natural gas for almost 65% of its domestic energy consumption in 2025.
We are currently importing 58% of our oil, much of it from regions of question-able stability and regimes not always friendly to the U.S.
Prudhoe Bay was initially estimated to hold 9.6 billion barrels of oil. So far, Prud-hoe Bay has produced over 15.9 billion barrels of oil.
Alaska believes predictability is a good thing. That’s why we hold annual lease sales for areas with known petroleum potential. And when our lease sales take place, the environmental challenges of potential oil and gas development have already been assessed. That way, you know before bidding on tracts what environmental issues you are likely to encounter, and what measures are required for exploration and development. So once your lease is issued, you are ready to start the environmental permitting process.
Alaska has many natural resources,and a constitutional mandate to develop them responsibly.
So we plan ahead.
Alaska: We’re Open For Business!Division of Oil and Gas550 West 7th Avenue, Suite 1100Anchorage, Alaska 99501-3560tel: 907-269-8800http://www.dog.dnr.state.ak.us/oil/
Crowley’s logistics group a Top 100 3PL provider
Crowley Maritime Corp. said Aug. 3 that itslogistics group has been selected as a Top 100third-party logistics provider by InboundLogistics magazine for the third consecutiveyear. The list serves as a qualitative assessmentof service providers deemed as the bestequipped to meet and surpass readers’ evolv-ing outsourcing needs.
IL editors selected this year’s class of Top100 3PLs from a pool of more than 300 candi-dates. The service providers selected are com-panies that, in the opinion of the editors, offer
the diverse operational capabilities and experi-ence to meet readers’ unique supply chain andlogistics needs, as well as enabling them scala-bility.
“We are thrilled to once again accept thisrecognition,” said Crowley’s Steve Collar, seniorvice president and general manager of logis-tics. “It reflects not only the continued growthof the company since we started in 1998, butalso the increasingly robust suite of services weare able to offer our customers and the solu-tion-oriented mindset of our employees.”
Editor’s note: All of these news items —some in expanded form — will appear in thenext Arctic Oil & Gas Directory, a full colormagazine that serves as a marketing tool forPetroleum News’ contracted advertisers. Thenext edition will be released in September.
continued from page 16
OIL PATCH BITS ENVIRONMENT & SAFETYJoint exercise tests Arctic towing system
The U.S. Coast Guard, the Alaska National Guard and Foss Maritime have con-ducted a joint exercise to test the delivery and use of an emergency marine towing sys-tem in the Arctic. The AlaskaDepartment of EnvironmentalConservation in conjunction with thecommunity of Unalaska and Alaska-based emergency response organiza-tions have developed the purpose-builttowing system following difficultiesexperienced in towing the crippledvessel Selendang Ayu in 2004. TheSelendang Ayu eventually ran agroundon Unalaska Island, spilling its fuelload of 336,000 gallons of crude oil and its cargo of soybeans into the Bering Sea.
The new emergency towing system was tested successfully in Dutch Harbor inAugust 2007, and in December 2010 the Tor Viking II, a vessel of opportunity, suc-cessfully used the system to tow a motor vessel to Dutch Harbor for repairs.
For the Arctic test a Coast Guard HC-130 Hercules aircraft stationed in Kodiakdelivered a towing system to the Red Dog Mine in northwest Alaska. The Coast GuardCutter SPAR then played the role of a commercial vessel with a disabled steering sys-tem, with a Foss tug in the area of the simulated incident transporting the towing sys-tem to the SPAR from the port of Kivalina, near the Red Dog Mine. The tug then putthe SPAR under tow.
The test came as part of the Coast Guard’s Operation Arctic Shield 2011.—ALAN BAILEY
The new emergency towing systemwas tested successfully in DutchHarbor in August 2007, and in
December 2010 the Tor Viking II, avessel of opportunity, successfullyused the system to tow a motor
vessel to Dutch Harbor for repairs.
Contact Gary Park through [email protected]
production tax that could make develop-ment of any oil discoveries noncompeti-tive for investment capital with projects inother oil provinces.
The operators that have talked toPetroleum News and/or government regu-lators about their plans are Alaska-grownindependents Brooks Range PetroleumCorp., or BRPC, and UltraStarExploration, and North Slope newcomersRepsol, Linc Energy and Great BearPetroleum, or GBP.
Also part of the upcoming explorationseason are several seismic surveys andAnadarko Petroleum’s rig-less testing ofits Chandler No. 1 gas well.
Seismic yields drilling opportunitiesfor future exploration wells andAnadarko’s work could mean it might res-urrect its multiyear drilling program at theGubik Complex on state, federal andNative acreage in the Brooks RangeFoothills. Inactive since 2009, the pro-gram was the first exploration effort innorthern Alaska to explicitly target natu-ral gas for other than local use. Anadarkois returning to the area as the state isramping up its efforts to sponsor an in-state gas line to Fairbanks and Anchorage.
Repsol: 5 rigs, up to 15 wellsThe largest of the three new players
looking to drill oil exploration wells thiswinter is Spanish major Repsol, whoserepresentatives have been talking to regula-tors and stakeholders about a five-rig pro-gram. All the rigs will be on separate icepads on state acreage — one offshore theColville River Delta, north of the ColvilleRiver unit; two onshore between theOooguruk and Colville units but drilling tooffshore targets; one onshore farther south,adjacent to the Colville unit and drilling toonshore targets; and one south and east of
the Kuparuk River unit. The company is looking at drilling one
vertical well and two sidetracks from eachpad with measured depths varying from12,000 to 16,000 feet.
Repsol’s 65-mile-plus ice roads for itsice pads will start at Kuparuk’s 2P pad,crossing the Colville River downstreamfrom ConocoPhillips’ Alpine Resupply IceRoad.
Repsol has interests in non-operatedfederal leases offshore northern Alaska,but acquired state acreage for the first timein March, when it bought majority interestin 157 North Slope and Beaufort Sea leas-
es on 494,211 acres from Armstrong sub-sidiary 70 & 148 and GMT Exploration.
Eighty-four of those leases are set toexpire in the 2012-14 time period, includ-ing several in or near where Repsol plansto drill this winter.
Linc: 1 rig, minimum 4 wellsLinc Energy, the Australian independ-
ent that acquired Cook Inlet basin acreagelast year and has already drilled its firstwell there, is planning to drill a minimumof four wells this winter at the undevelopedUmiat oil field in the Brooks RangeFoothills along the southeastern border of
the National Petroleum Reserve-Alaska,some 80 miles west of the trans-Alaska oilpipeline.
Earlier this summer Linc’s Alaska sub-sidiary purchased controlling interest intwo NPR-A and two state leases on 19,358gross acres in the Umiat field.
Umiat’s reservoir is between 200 and1,400 feet in depth, with a portion of theoil in permafrost.
Discovered by the U.S. Navy in 1946,the Umiat oil field was never developedbecause of its remoteness from infrastruc-ture and the lack of technology to unlockits shallow oil, the last of which haschanged in recent years.
The company plans to fly a drilling rigto Umiat’s 5,583-foot airstrip before theend of the year.
Linc said the State of Alaska’s plans tobuild an all-season gravel road from theDalton Highway to Umiat was a signifi-cant factor in its development decision.
Great Bear: 1 rig, 3 + 3 wellsIndependent GBP, which holds 500,000
acres of central North Slope acreage thatcontains three world-class source rocks,plans to drill up to three vertical wellsbetween October and the end of the yearbefore the start of the winter explorationseason. In the spring, after the off-roadwinter season drilling has ceased else-where on the North Slope and a rig is againavailable, the company will drill at leastone horizontal production sidetrack fromeach vertical well bore.
Drilling will be on “existing gravel fea-tures (roads, pads and material sites)”along the Dalton Highway “about 20 to 35miles south of Prudhoe Bay” according toGBP’s proposed oil spill contingency plan,allowing the company to drill year-round.
Up to four initial wells have been dis-cussed by GBP — each with an 11,000-foot vertical well bore that will first provide9-10 inch cores and from which 4,000-foothorizontal production sidetracks will laterbe drilled along the source rock strata andhydraulically fractured in order to prove oilcan be profitably produced from theShublik and possibly the HRZ shale, two ofthree source rocks stacked in the company’sleases. GBP is also targeting oil in conven-tional geologic traps.
In June, GPB said two to three, not four,vertical wells with at least one lateralextension from each well bore would ini-
18 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
continued from page 1
EXPLORATION DRILLING
see EXPLORATION DRILLING page 19
The well countincludes offshore
wells in statewaters, as well
as lateral andsidetrack wells.
ALA
SKA
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ISIO
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IL &
GA
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PETROLEUM NEWS • WEEK OF AUGUST 14, 2011 19
tially be drilled.
Brooks Range Petroleum: 1 rig, 2 wells
Using one drilling rig, a joint ventureled by BRPC plans to complete and test itsNorth Tarn No. 1 A well, last winter’s onlynorthern Alaska exploration well.
The North Tarn prospect has since beenrenamed Mustang and is part of the jointventure’s proposed South Miluveach unit,adjacent to the west side of Kuparuk unit(see story in the April 24 issue of PN athttp://bit.ly/oPG5Yt).
BRPC has said it will likely drill twomore wells this winter to delineateMustang, although drilling is contingenton North Tarn No. 1A results.
UltraStar: 1 rig, 1 well UltraStar Exploration should know in
the next few months whether it will be ableto drill a well at its Dewline unit this win-ter, or whether the project will need to waitanother year.
The Anchorage-based independent ledby managing member Jim Weeks is cur-rently “close to getting a deal” for the ven-ture capital it needs, Weeks said.
Weeks began permitting the NorthDewline No. 1 well several months ago,and said that once financing is in place heplans to find an available rig to drill onewell this winter.
“If we can’t find a suitable rig, we stillhave another season,” Weeks said, refer-ring to an Alaska Division of Oil and Gasdeadline to drill a follow-up well at theDewline unit by May 31, 2013. “I’d rathernot push it that far… but we can be some-what selective.”
Weeks said the entire program must bein place by October in order to drill thiswinter.
UltraStar drilled the vertical DewlineNo. 1 well in early 2009 to 9,900 feet totest a primary oil target in the Ivishak for-mation.
The North Dewline No. 1 well wouldbe a directional well from an onshore padto an offshore target. The 14,000 to 15,000foot well would have a 6,000-foot dis-placement.
That well would also test a primary oiltarget in the Ivishak formation, as well assecondary targets in the Sag River andKuparuk formations, Weeks said. �
—Eric Lidji contributed to this article.
continued from page 18
EXPLORATION DRILLING
nique in the Cook Inlet basin and nowplans to conduct a program of seismicsurveying. High quality seismic data isthe key to exploration in new plays inthe basin, Robert Swenson, director ofAlaska’s Division of Geological andGeophysical Surveys, told PetroleumNews in June.
Three years of workApache will start three years of 3-D
seismic acquisition in the Cook Inletbasin this year with a 1,050-square-mile program on the west side of CookInlet from West Forelands north toBeluga.
Over the three-year period, the com-pany told the Alaska Department ofNatural Resources in an Aug. 3 appli-cation, it plans to acquire 3-D seismicfrom the Susitna Flats in the north toaround Anchor Point in the south.
The company conducted a seismictest program this spring to evaluate thefeasibility of using new nodal technol-ogy seismic recording equipment in theCook Inlet environment and proposesto begin acquiring seismic this fall withmarine patches close to the coast.Apache said that as the ground freezesit will move operations to the transitionzone and cover as much of the coastline
as possible before sea ice makes marineoperations impossible.
Onshore work in winterCrews will acquire onshore seismic
during the winter and at the end of thewinter season, depending on groundand sea ice conditions, will resumeoperations in the transition zone or off-shore.
Marine offshore operations willgenerally take place from April toNovember, depending on the presenceof marine mammals and parameters ofthe incidental harassment authorizationissued by the National Marine FisheriesService.
Transition zone activities will befrom September to December and fromMarch to May, depending on sea ice;onshore operations will be generallyfrom September to April.
Apache said it expects to acquire abroad band, full azimuth seismicdataset capable of imagine structuraland stratigraphic features at targetdepths up to 20,000 feet subsurfaceacross all of the three defined targetarea.
—ERIC LIDJI & KRISTEN NELSON
continued from page 1
APACHE PLANSContact Kay Cashman
Contact Kristen Nelson at [email protected]
Contact Eric Lidji at [email protected]
likely will be far from over barring a set-tlement.
Origins of appealThe state appealed to the Supreme
Court in February 2010 after SuperiorCourt Judge Sharon Gleason reversed for-mer DNR Commissioner Tom Irwin’s ter-
mination of the Point Thomson unit.For months, DNR’s appeal lay dormant
as the state and the oil companies, withthe high court’s blessing, concentrated onsettlement talks.
Now, the appeal is back on track witheach side having filed its major writtenargument.
The state’s appeal is somewhat unusu-al because it is “interlocutory.” That is,DNR is appealing a midstream rulingfrom a case that remains undecided at the
trial court level. So, once the SupremeCourt rules, it will send the matter back tothe lower court for further proceedingsthere.
It’s easy to see how this process couldlead to years more conflict, given thecomplex issues surrounding PointThomson and the fact that the field isworth billions of dollars.
In reversing the unit termination,Gleason faulted the state on two counts.
First, she held that the Point Thomsonstakeholders were wrongly denied a hear-ing under a key section of the PointThomson unit agreement.
Second, she said DNR lacked theappearance of impartiality in dealing withthe oil companies.
At the heart of the Point Thomsonaffair is frustration — the state’s frustra-tion that ExxonMobil, as unit operator,and the other companies have yet to pro-duce any oil or gas from the field since itsdiscovery in the late 1970s.
The field, located along the BeaufortSea coast next to the Arctic NationalWildlife Refuge, holds trillions of cubicfeet of natural gas plus hundreds of mil-lions of barrels of petroleum liquids.
Point Thomson impatienceIn 2005, DNR began to insist that
ExxonMobil get on with development,and since has declared — twice — thatthe Point Thomson unit is terminated.DNR also has invalidated the underlyingleases. The oil companies are resisting allthese moves administratively and in court,with considerable success so far.
In their brief, the four oil companiessuggest to the Supreme Court justices thatthe state’s Point Thomson impatience ismisplaced.
“DNR’s argumentative and incompletestatement of ‘facts’ attempts to create theimpression that the Point Thomson Unitcontains vast quantities of readily accessi-ble oil and gas that the (companies) haveinexplicably refused to produce,” the briefsays.
It just isn’t that simple, the brief con-tinues, noting the historic lack of a NorthSlope natural gas pipeline and PointThomson’s difficult character.
“The PTU contains an estimated 8 tril-lion cubic feet of natural gas in theThomson Sand Reservoir, together with alesser volume of heavier hydrocarbons,”the brief says. “The liquid hydrocarbonsin the reservoir consist of a thin layer ofheavy oil plus ‘retrograde condensate,’which is gaseous in the reservoir butbecomes liquid at the surface. If allhydrocarbons in the reservoir could bebrought to the surface, over 90% of thetotal volume would be natural gas. The
PTU also contains some lighter oil in sep-arate accumulations called Brookiansands.
“As the state has acknowledged, thegeology of the PTU makes production ofthe gas, condensate, and oil located theretechnologically challenging. The maingas reservoir, 12,000 feet below the sur-face, is under extreme pressure — over10,000 pounds per square inch comparedto an average of 4,335 psi at Prudhoe Bay.The very high pressures create bothdrilling risks and production safetyissues. In addition, because the conden-sate is ‘retrograde,’ some liquids will con-dense deep in the gas reservoir as pres-sure declines, rather than only at the sur-face. This presents problems for recoveryof both condensate and gas. Finally, themain gas reservoir may be compartmen-talized, discontinuous, or poorly connect-ed. Production of hydrocarbons fromreservoirs of this nature requires morewells.”
In a footnote, the brief says PointThomson’s 10,000 psi “would approxi-mately equal the pressure of two 4x4pickup trucks resting on a person’sthumbnail.”
Right to hearing at issueThe company brief goes on to detail
other reasons why Point Thomson is amajor development risk.
The primary question before theSupreme Court is whether the companies,before the unit was terminated, were due ahearing under Section 21 of the PointThomson unit agreement.
Section 21 says the state has authorityto adjust the “rate” of development andproduction, but only after the unit opera-tor has the opportunity for a hearing toconsider, among other things, whetherany rate increase would violate “good anddiligent oil and gas engineering and pro-duction practices.”
Judge Gleason faulted DNR for failingto give ExxonMobil the hearing.
The state cites numerous reasons whyno such hearing was deserved, one beingthe fact that Point Thomson has no pro-duction.
Further, DNR has said a Section 21hearing would be an arduous exerciseinvolving years of preparation and legionsof geology and engineering experts.
But ExxonMobil and the other compa-nies argue Section 21 is a vital contractu-al protection when faced with “the abruptand enormous forfeiture that DNR wouldinflict” on the Point Thomson workinginterest owners. �
20 PETROLEUM NEWS • WEEK OF AUGUST 14, 2011
prospect within the unit.The rig officially arrived in the
United States on Aug. 7, once U.S.Customs and Border Protection inspect-ed it in Kachemak Bay and allowed it toenter U.S. waters. The tugs that broughtthe rig will stay in Cook Inlet throughone tide cycle and return to Seattle.
Several weeks off BC coastThe rig left the Gulf of Mexico in
March, sailed around the tip of SouthAmerica and spent several weeks offthe coast of British Columbia becauseof legal and repair issues.
The arrival, though, is only thebeginning.
Escopeta is preparing to drill in anage when offshore drilling is under amicroscope.
“I am concerned, given the shorttimeframe to drill this season, thatEscopeta conducts all operations in asafe and environmentally responsible
manner. We have been monitoring allactivities and been in constant contactwith state and federal regulators toensure that no corners are being cut,”Mike Munger, executive director of theCook Inlet Regional Citizens AdvisoryCouncil said in a statement after the rigarrived in Alaska.
CIRCAC said that its staff partici-pated in a two-day spill training exer-cise in late July involving the UnitedStates Coast Guard, the AlaskaDepartment of EnvironmentalConservation and Escopeta, andrecently completed a “thoroughreview” of Escopeta’s Oil DischargePrevention and Contingency Plan andsubmitted comments to DEC.
The Spartan 151 is the first jack-uprig in the Cook Inlet in nearly twodecades.
Buccaneer Energy Ltd. is workingto bring another jack-up to the Inletnext summer.
—ERIC LIDJI
continued from page 1
JACK-UP RIG
continued from page 1
POINT THOMSON
Contact Wesley Loy at [email protected]
Contact Eric Lidji at [email protected]
