pioneer touts nuna · 2 petroleum news • week of may 13, 2012 petroleum news north america’s...
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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
� F I N A N C E & E C O N O M Y
� E X P L O R A T I O N & P R O D U C T I O N
Vol. 17, No. 20 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of May 13, 2012 • $2
page3
Parnell looks back at tax debates,defends oil plan, promotes LNG
A gas pipeline from the North Slope would provide natural gas toAlaskans, but getting it to Fairbanks in Interior Alaska off of a mainline, and then distributing it throughout the city could cost as much asa billion dollars. See story on page 16.
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NordAq plans two wells at TigerEye on west side of Cook Inlet
NordAq Energy Inc., the small independent that has beenquietly pursuing a program of oil and gas exploration inAlaska’s Cook Inlet basin for the past couple of years or so,says that it nowplans to drill twoexploration wells inits Tiger Eyeprospects onshorethe west side of theinlet. The well loca-tions are betweentwo and three milesinland, to the immediate north of West Foreland.
In October NordAq filed a plan of operations with theDivision of Oil and Gas for the drilling of the Tiger Eye Northwell. The company has since changed its plans, adding a sec-ond well, the Tiger Eye Central well, to its Tiger Eye project,
Imperial, Exxon eye LNG for BCHorn River shale gas development
Imperial Oil and ExxonMobil Canada, the Canadian sur-rogates of ExxonMobil, are taking baby steps towards export-ing LNG from their stranded natural gas reserves in BritishColumbia.
Their key joint holding covers 340,000 acres of shale gasproperties in the Horn River basin of northeastern BritishColumbia where the two companies are working on a pilotproduction venture to get a better grip on the cost of develop-ment, while at the same time examining a potential LNGfacility, Imperial Chief Executive Officer Bruce March toldreporters at the company’s annual meeting.
“Long term, it is a good proposition,” he said, rating as“critical” the development of an LNG export industry toadvance development of Horn River.
But he conceded Imperial’s plans are less advanced thanother British Columbia gas producers.
March said the joint venture has drilled 30 to 35 wells atHorn River which have yielded only methane.
Directional drilling will berequired at each location, with theNorth pad well involving extended
reach drilling and requiring adrilling rig that is suitable for that
type of drilling operation.
see NORDAQ WELLS page 22
see HORN RIVER page 24
Pioneer touts NunaA 50 million barrel discovery south of Oooguruk; Ivishak test a bust
By ERIC LIDJIFor Petroleum News
P ioneer Natural Resources AlaskaInc. is announcing a 50 million bar-
rel discovery at its budding Nuna devel-opment based on exploration drillingcompleted this past winter.
The Nuna No. 1 well tested at an ini-tial production rate of 2,000 barrels of oilper day, the Texas-based independentsaid during a first quarter conference call on May3. Pioneer suspended the onshore well at the end ofthe exploration season, but expects to conduct alonger test next winter in addition to drilling anadditional appraisal well at the prospect.
Pioneer also announced the results from two
other wells drilled this winter, a suc-cessful development well into theNuiqsut formation and an unsuccessfultest of the Ivishak.
Altogether, the encouraging resultscould make Oooguruk more attractivefor Pioneer after a more than a year ofdeclining production from its flagshipasset in Alaska.
Nuna No. 1 tested the southernextent of the Torok formation, the third
and shallowest producing formation at thenearshore Oooguruk unit in Beaufort Sea, and itproved to be “one of the best wells we drilled in theTorok,” according to Pioneer Chief OperatingOfficer Tim Dove. Although Pioneer primarily
Oil, gas from old assetsIndependent Hilcorp reworking Cook Inlet wells, fields, formerly held by Chevron
By KRISTEN NELSONPetroleum News
H ilcorp Alaska is focused on findingand producing more oil and natural
gas from legacy Cook Inlet assets. Itacquired Chevron’s Cook Inlet assets lastyear and is in the process of acquiringMarathon Oil’s inlet assets.
Producing from old wells and fields isthe company’s strength, John Barnes,Hilcorp’s senior vice president for Alaska, told theRegulatory Commission of Alaska May 9 and theAlaska Support Industry Alliance May 10; thisstory combines comments from both presenta-tions. Barnes said there are lots of opportunities in
Cook Inlet, and Hilcorp is a fast-movingindependent with enough financial cloutto do the work that needs to be done.
Among the challenges Hilcorp isworking on, he said, are predictable per-mitting timelines — with predictabilitythe real issue, not how long it takes.
“If it takes a year, you’d better have aninventory that lets you plan out a yearahead of time; if it’s a week, that’s great,”Barnes said.
He said the biggest obstacle he sees is caused bythe decline of the service industry in the inlet.
Hilcorp “can’t move fast enough because we
China ready to waitSome C$20B invested in Canada; investment could grow 10-fold over 10-15 years
By GARY PARKFor Petroleum News
China’s stable of state-owned energy compa-nies has invested about C$20 billion in
Canada’s oil sands and shale gas assets — proofpositive that Beijing is ready to ride out a stormypassage for pipelines from Alberta, across BritishColumbia to ship production across the Pacific,says Zhang Junsai, China’s ambassador to Canada.
The delays in approving the key infrastructureelements will not deter China from seeking a keyrole in the development of those resources, he toldreporters in Calgary.
Typifying the Chinese reputation for taking along-range view of its investments, he said China
has access to ample imports of oil and natural gasfrom Australia, Qatar and Russia, so, if necessary,supplies from Canada can wait.
“There`s investment opportunity becauseCanada is open for international investment,”Zhang said.
“If there’s opportunity, Chinese companies will
TIM DOVE
see NUNA DISCOVERY page 22
see CHINA INVESTMENT page 24
“World economic power and wealth areshifting in a way that is historic and we
as Canadians must decide that we will beon the right side of that history.” —Canadian Prime Minister Stephen Harper
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JOHN BARNES
see HILCORP page 23
2 PETROLEUM NEWS • WEEK OF MAY 13, 2012
Petroleum News North America’s source for oil and gas news
EXPLORATION & PRODUCTION
ASSOCIATIONS
UTILITIES
GOVERNMENT
LAND & LEASING
FINANCE & ECONOMY
NATURAL GAS
10 Touting Alaska gas in nation’s capital
DNR commissioner goes to Washington, DC, to talk up state’s energy agenda, and to urge prompt Point Thomson permitting
15 Study says US LNG exports feasible
Brookings Institution study: There should be enough L48natural gas to export some as LNG to benefit of US
12 Great Bear’s Duncan: ‘In it together’
A more conservative, but not subdued, Duncan declines to testify to Senate ResourcesCommittee on tax breaks needed for project
5 Murkowski endorses NOAA relocation
Alaska senator says Obama’s proposal to move agencyfrom Commerce Department to Interior ‘makessense on a number of levels’
7 DNR upholds rejection of Cohoe unit
Says Aurora Gas has not shown proposed KenaiPeninsula unit overlies oil or gas pool; lease expiry not a reason for unitization
4 TransCanada terminates 1st open season
2010 initial open season ended with bids from ‘majorindustry players;’ company says producers not ready to make commitments
9 EIA forecasts lower WTI crude oil prices
US total crude oil production expected to average 6.2million bpd this year, up 500,000 bpd from 2011and highest level since 1998
contents
NordAq plans two wells at TigerEye on west side of Cook Inlet
Imperial, Exxon eye LNG for BCHorn River shale gas development
9 US oil, gas rig count up by 20 to 1,965
3 Parnell defends tax plan, promotes LNG
8 Interior requires chemicals disclosure
8 Nikolaevsk next up for natural gas
6 HEA moving ahead with system upgrades
14 AEDC releases annual resource forecast
10 Potential Alaska state and federal oil and gas lease sales
11 FNG gets Cook Inlet supply extension
16 Distributing North Slope gas challenging
14 ConocoPhillips still planning for CD-5
11 State, BP heading into arbitration
14 Shell asks court to declare IHAs valid
18 Red Wolf exploration well comes up dry
SIDEBAR, Page 24: NWT sees LNG as option
Pioneer touts Nuna
A 50 million barrel discovery south of Oooguruk; Ivishak test a bust
Oil, gas from old assets
Independent Hilcorp reworking Cook Inlet wells, fields, formerly held by Chevron
China ready to wait
Some C$20B invested in Canada; investment could grow 10-fold over 10-15 years
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By STEFAN MILKOWSKIFor Petroleum News
For Gov. Sean Parnell, simple econom-ics dictate that lower oil production
taxes will make more North Slope projectsprofitable. It’s also clear that declining oilproduction is not okay, putting at risk thou-sands of direct and indirect jobs.
Parnell has made tax reform a top pri-ority but has struggled to win legislativesupport for his proposals. After his HB110 died this year in the Senate, he calledlawmakers into special session to considera new proposal. Hesurprised many whenhe pulled the billfrom considerationon April 25, blamingthe Senate for intran-sigence.
In an interviewMay 9, Parnell out-lined the next stepsto getting a gas line,defended hisapproach to tax reform, and discussed thePoint Thomson settlement.
Petroleum News: Let’s start with gas.This winter you encouraged North Slopeproducers to get behind an LNG exportline, and on May 2, your administrationgave TransCanada permission to focus onthat project instead of an overland routethrough Canada. Why is that a better proj-ect?
Parnell: I actually led the charge lastOctober when I announced that I wantedto see the producers, TransCanada, and allparties focus on a line from the NorthSlope through Alaska to tidewater. It wasclear that the Lower 48 market had shiftedto shale gas — the large volumes therehad depressed the price. And the tsunamiin Japan and the Japanese shift fromnuclear power clearly created another rea-son to move to an LNG export scenario.
I then began calling on, working with,cajoling the CEOs of the producer compa-nies towards alignment and towards reso-lution of Point Thomson, because each ofthose was necessary to get a large-diame-ter gas line approved and constructed.
Petroleum News: Will you require thatan APP (Alaska Pipeline Project) and pro-ducer pipeline adhere to the “must-haves”in the Alaska Gasline Inducement Act?
Parnell: In my state of the state address,I called for alignment of the producers andTransCanada by the end of March, andthat occurred. I called for resolution of thePoint Thomson settlement among workinginterest owners, and that has occurred.
The reason I said I wanted the align-ment “under an AGIA framework” isbecause of the benefits the Alaska GaslineInducement Act provides Alaskans. Itassures offtakes for Alaskan communities.It assures that Alaskan lands will be fullyexplored for gas because the pipeline willbe accessible to future explorers. It assuresthat Alaskans will pay a distance-sensitivetariff on the gas they receive.
So I believe it has significant benefitswithin its framework, and I would muchprefer to start any negotiation over fiscalterms with those benefits in place forAlaskans, instead of starting from scratch.
Petroleum News: Will you stick to all ofthe must-haves, or are some of them nego-tiable?
Parnell: Obviously some of them willneed to be negotiable. But again, we’restarting from a position of strength, whereAlaska’s must-haves are already clearlydefined by law.
Petroleum News: When do you plan toaddress fiscal terms?
Parnell: The next benchmark for thesecompanies to achieve is a project conceptselection of an LNG project, which, underthe benchmarks I set in my state of thestate address, should occur in Septemberof this year.
If that occurs, if the companies’ harden-ing of their numbers and their alignmentof interests come together around thisLNG project, then fiscals will be the nextstep. Assuming all the benchmarks weremet, I had offered to take those up duringthe legislative session of 2013.
Petroleum News: Why did you also sup-port HB 9, which was aimed at jumpstart-ing a competing, in-state line?
Parnell: In every commercial negotia-tion, it’s in a party’s interest to have analternative. When the producers, between2001 and 2003, were negotiating withTransCanada over a “bullet line” fromAlberta to Chicago, the producers werepromoting their own line as an alternative.
I don’t want Alaska to be dependentupon the producers’ goodwill. Having analternative, in this case the Alaska GaslineDevelopment Corporation alternative, isvery important to getting the best deal forAlaskans when it comes to a large-scalepipeline.
Petroleum News: So what’s the nextstep?
Parnell: The next step is for the produc-ers and TransCanada to get together withthe Alaska Gasline DevelopmentCorporation to determine whether there isinterest and value in merging, combiningthose efforts. The other benchmark thatneeds to be met by third quarter 2012 isfor the producers and TransCanada toharden their numbers and finish their proj-ect concept selection stage of an LNGproject.
Petroleum News: Moving to oil taxes,why did you decide to introduce a new billfor the special session?
Parnell: The new bill was merely a con-tinuation of the two-year discussion we’vebeen having. It reflected the methodologyused by the Senate in passing tax creditsfor new fields. The bill Iintroduced used theSenate’s methodology toincentivize not only newfields but also new oilfrom existing fields.
I made the mistake ofthinking senators would be consistent inapplying the same rationale to trying toextract new oil from existing fields as theyhad used to incentivize development atnew fields.
Petroleum News: Why did you removethe proposal from consideration?
Parnell: I removed the proposal fromconsideration because it was clear thatthere were a few senators in controllingpositions who think status quo decline is
fine, who think the existing tax structure isfine. These senators don’t have a plan foraltering our production decline, but theywere extremely critical and had hardenedtheir positions against any notion of apply-ing lower taxes to existing fields.
My view is very clear, that both exist-ing fields and new fields have new oil that
will not otherwise be pro-duced without a taxchange. That’s simple eco-nomics. And to think thatan oil company will extract100 percent of the oil in afield anyway is not based
on fact.
Petroleum News: Sen. Joe Paskvan, oneof the Resource Committee co-chairs,requested that Gaffney Cline (a consultantto the administration) testify. Why werethey not made available?
Parnell: Our work relied on GaffneyCline. The Legislature had their consult-ants in PFC Energy. The issue was that
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� G O V E R N M E N T
Parnell defends tax plan, promotes LNGGovernor calls criticism that administration wasn’t prepared ‘nonsense’; sticks with AGIA requirements ahead of gas line negotiations
GOV. SEAN PARNELL
see PARNELL Q&A page 21
JUD
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4 PETROLEUM NEWS • WEEK OF MAY 13, 2012
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� N A T U R A L G A S
TransCanadaterminates 1st open season2010 initial open season ended with bids from ‘major industryplayers;’ company says producers not ready to make commitments
By KRISTEN NELSONPetroleum News
TransCanada Alaska filed a notice withthe Federal Energy Regulatory
Commission May 3 terminating its firstbinding open season.
The open season for the Alaska PipelineProject, APP, began April 30, 2010, andended July 30, 2010.
APP is the project licensed toTransCanada in late 2008 by the State ofAlaska under the Alaska GaslineInducement Act, or AGIA. ExxonMobiljoined TransCanada in APP in mid-2009.
“During the open season, producersexpressed significant interest in theAlberta Project in the form of conditionedbids for capacity on that pipeline,”TransCanada told FERC. The companysaid there were “concerted negotiations formany months” between APP and theAlaska North Slope producers, but despite“good faith efforts” by all parties to thenegotiations, no precedent agreements —binding commitments to “ship or pay” onthe line — were signed.
TransCanada said it is APP’s “assess-ment that the producers are not prepared tomake commercial commitments to theAlberta Project at this time,” and it is with-drawing the transportation service offer-ings in the 2010 open season notice.
APP is working with the ANS produc-ers on the feasibility of a project includinga pipeline to a liquefied natural gas facili-ty at tidewater in Southcentral Alaska,TransCanada said.
If those evaluations lead to a projectthat appears commercially viable, or ifthere is renewed interest in taking gas toAlberta, TransCanada said APP would ini-tiate a new open season.
Amendments to the plan in the AGIAlicense approved by the state May 2 call forinitial work on an LNG project to be com-pleted by September with an open seasonby the end of the year.
Multiple bidsAfter the initial open season closed in
2010, Tony Palmer, vice president ofAlaska development for TransCanada, saidthat while results of the open season wereconfidential, “The Alaska Pipeline Projectcan report that we have received multiplebids from major industry players and oth-ers for significant volumes.”
Confidentiality agreements betweencustomers and the pipeline company pre-vented description of the open seasonresults in any detail, Palmer said at thetime. He said the confidentiality agree-ments “exist because the gas business is socompetitive,” with gas from Alaska com-peting with gas supplies coming into NorthAmerican or international markets.
At the time of the APP open seasonthere was also a competitive pipeline proj-ect, the BP-ConocoPhillips Denali project,with an open season which continued twomonths beyond that for APP, although
Denali is no longer a factor. It was discon-tinued in May 2011 and the company saidin a statement that its open season effortshad not resulted in customer commitmentsnecessary to continue work.
Typically open seasons for pipelines areconfidential, but FERC has specialrequirements for an Alaska gas pipelineproject because the remoteness of theNorth Slope and the expense of the projectpreclude competitive pipelines from beingbuilt.
The APP open season accepted bids forboth the Alberta line and for a line toValdez for LNG export. While Palmer didnot comment in 2010 on which proposalreceived bids, TransCanada’s statements toFERC would seem to indicate that only theAlberta project received bids, or that ifthere were bids for an LNG project, thatnegotiations over those bids hadn’t beenongoing.
AlignmentAlaska Gov. Sean Parnell has been
encouraging participation by all NorthSlope producers in an LNG project sincelast fall and at the end of March the threeNorth Slope majors — BP, ConocoPhillipsand ExxonMobil — said they had reachedan agreement to work with TransCanada,under an AGIA framework, to evaluate aline to Southcentral for LNG export.
The companies told Parnell in a March30 letter that they were making progress on“the next generation of North Sloperesource development.” That commitment,released in conjunction with a settlementof the long-standing Point Thomson litiga-tion between the owners of that unit andthe state, was directed toward natural gasdevelopment.
The companies said that “under theright business climate, the full commercialpotential of this world-class resource canbe unlocked.” Point Thomson containsabout a quarter of known natural gasresources on the North Slope (at 8 trillioncubic feet the largest accumulation next toPrudhoe Bay’s 24.5 tcf.)
The Alaska Gas Pipeline Project Officesaid May 2 that Natural ResourcesCommissioner Dan Sullivan and RevenueCommissioner Bryan Butcher hadapproved a project plan amendment for theAlaska Pipeline Project under AGIA,allowing a shift of focus to LNG.
The governor has said that if bench-marks are met, the Legislature wouldaddress gas taxes next year. �
Amendments to the plan in theAGIA license approved by the
state May 2 call for initial workon an LNG project to be completedby September with an open season
by the end of the year.
Contact Kristen Nelson at [email protected]
By WESLEY LOYFor Petroleum News
Alaska Sen. Lisa Murkowski says shesees “real merit” in the Obama
administration’s proposal to move theNational Oceanic and AtmosphericAdministration from the CommerceDepartment into the Interior Department.
Murkowski, a Republican, explainedher view on the matter in a recent op-edcolumn published in Alaska media out-lets.
The Obama administration on Jan. 13proposed the NOAA move as one prongof a reorganization plan meant to makethe government more efficient and help-ful to business with less duplication.
Formed in 1970, NOAA is an agencyof considerable importance to the off-shore oil and gas industry. NOAA con-ducts extensive scientific research, and ishome to subagencies such as the NationalMarine Fisheries Service, the NationalWeather Service and the National OceanService.
‘Fish out of water’“There are many issues on which I dis-
agree with President Obama,” Murkowskibegan her op-ed column. “When someoneis right on something, however, it isimportant to give credit where it’s due.”
The senator said that after reviewingObama’s plan for NOAA, she had con-cluded it “makes sense on a number oflevels.”
“From a basic structural perspective,NOAA is increasingly out of place atCommerce — like a fish out of water,”she wrote. “Its stated mission is to pro-vide the scientific data necessary to pro-tect lives and property, as well as to con-
serve and help man-age our nation’sfisheries, oceans andcoastlines. Now con-sider the two depart-ments it could belocated in.Commerce is prima-rily focused on thepromotion of eco-nomic growth andinternational trade, dealing with patentsand other commercial issues. Interior,meanwhile, manages natural resources,public lands, and fish and wildlife. Basedon that alone, it’s easy to see why Interioris a more natural fit.”
She noted the story of how NOAA wasplaced where it is today: BecausePresident Nixon “was upset with one ofAlaska’s great statesmen, Wally Hickel,who was serving as Interior Secretary atthe time.”
Murkowski said both NOAA andInterior focus on the same types of work,such as offshore mapping and managingmarine mammals, fish stocks and habitat.
Arctic exploration EIS citedOne unified agency would be better
than “two in conflict,” Murkowski said.“For example, NOAA and Interior reg-
ularly conduct separate environmentalreviews of the same projects, adding timeto the approval process and crossing pur-poses,” Murkowski wrote. “Case in pointis NOAA’s Draft Environmental ImpactStatement for Arctic oil and gas develop-ment, which contemplates a needlesslyrestrictive and unrealistic program and isat odds with Interior’s own assessment.Instead of coordination, the currentarrangement routinely leads to conflict
and confusion — and an uncertain pathforward for those who wish to invest inour state.”
NOAA Fisheries Service is the leadfederal agency preparing the EIS, whichlays out policy alternatives for issuance ofpermits and authorizations for seismicsurveys and exploratory drilling over afive-year period through 2017. Interior’sBureau of Ocean Energy Management,which handles offshore leasing, is helpingwrite the EIS as a “cooperating agency.”
The draft EIS considers how industrialnoise, vessel traffic and pollution mightaffect whales and other marine mammals.
The alternatives concern industry,placing annual limits on the number ofseismic surveys and allowing only one ortwo exploratory drilling programs peryear in each of the Beaufort and Chukchiseas.
The bipartisan Alaska congressionaldelegation, in a joint press release, said ithad met April 18 with NOAAAdministrator Jane Lubchenco to raiseconcerns “that the final EIS could createa set of further timing and spatial restric-tions beyond those already listed in theleases held by oil companies.”
Sen. Rockefeller ‘appalled’Obama can’t move NOAA by himself.
He has asked Congress to “reinstate theauthority that past presidents have had tostreamline and reform the ExecutiveBranch.”
A May 2 press release fromMurkowski’s office cites a “growing
movement” in Washington, D.C., regard-ing the NOAA proposal.
Murkowski noted that both CommerceSecretary John Bryson and InteriorSecretary Ken Salazar have indicated sup-port for the move.
But consolidating NOAA withinInterior certainly has opposition.
“I’m appalled by that thought,” Sen. JayRockefeller, a West Virginia Democrat andchairman of the Senate CommerceCommittee, said in a March 7 hearing onNOAA’s budget. “I’m appalled by it. And Iwant to serve notice that I will do every-thing I can to make sure that it does nothappen. And that’s not because of territori-al concerns, jurisdictional concerns. Itsimply doesn’t make any sense.”
Rockefeller said NOAA is an excellentorganization now, with an excellent leader,and “I just want to make sure that NOAA’sday-to-day performance stays on track.”
Frances Beinecke, president of theNatural Resources Defense Council, hassaid relocating NOAA within Interior “isnot merely some technical, bureaucraticshift.”
She wrote in a January blog post:“Housing NOAA within a departmentwhose focus on the oceans is almostentirely extractive (permitting offshore oildrilling and exploration, for example)could erode the capability and mute thevoices of the government’s chief oceansexperts.” �
PETROLEUM NEWS • WEEK OF MAY 13, 2012 5
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� G O V E R N M E N T
Murkowski endorses NOAA relocationAlaska senator says Obama’s proposal to move agency from Commerce Department to Interior ‘makes sense on a number of levels’
SEN. LISA MURKOWSKI
Contact Wesley Loy at [email protected]
By ALAN BAILEYPetroleum News
Connected to the rest of the AlaskaRailbelt electrical grid by a single
intertie and with its power supply contractwith Chugach Electric Association due toterminate at the end of 2013, HomerElectric Association, or HEA, the mainpower utility on the Kenai Peninsula, hasbeen moving ahead with its so-called“independent light” program for futurepower supplies.
New generationThe independent light program, decid-
ed on by the HEA board in 2008, consistsessentially of building and obtaining newpower generation capacity on the penin-sula to enable the utility to meet its ownpower generation needs. However, HEAwill also purchase power from otherRailbelt utilities when that makes eco-nomic sense, Brad Janorschke, HEA gen-eral manager, told the RegulatoryCommission of Alaska on April 11 duringan update to the commission on the cur-rent status of the utility.
“It’s certainly different than treating
ourselves as an island like Kodiak,”Janorschke said.
Currently the utility obtains most of itspower from Chugach Electric, while alsoobtaining about 39 megawatts from itsown gas-fired power station at Nikiski onthe west coast of the peninsula. TheBradley Lake hydroelectric facility in thesouthern Kenai Peninsula also providesabout 14 megawatts for the peninsula,according to the HEA website. HEA’stotal annual demand is 84 megawatts,with a total system generation require-ment of about 110 megawatts, the websitesays.
Of three short-listed options for HEApower supplies after the termination ofthe utility’s Chugach Electric contract, theindependent light program offered thelowest cost to HEA’s ratepayers,Janorschke told the commission. Theother options on the shortlist consisted ofHEA participating in the new gas-firedpower station that Chugach Electric andMunicipal Light & Power are building inSouth Anchorage; and the continuation ofthe power supply contract with ChugachElectric, he said.
Main componentsThe two main components of the inde-
pendent light plan consist of a majorupgrade to HEA’s Nikiski plant and theinstallation of gas-fired power generationin Soldotna, to the east of the city ofKenai.
HEA has also purchased the 69.9-megawatt Bernice Lake gas-fired powerstation near Nikiski from ChugachElectric, with that deal completing in late2011.
In April 2011 HEA broke ground for anew power house at its Nikiski power sta-tion, to add a new high-efficiency, com-bined cycle, gas-fired, steam turbine gen-erator to that facility.
“It will go from a 40-megawatt facilityto a 58-megawatt facility with no moreadditional fuel,” Janorschke said. The useof additional fuel would enable the plantto produce about 78 megawatts of power,he said.
The new turbine at Soldotna will havea 49-megawatt capacity, according to theHEA website.
The upgraded Nikiski plant should goon line late this year or early in 2013, withthe Soldotna unit going on line in thesummer of 2013, Janorschke said.
And the utility has built a new dispatchcenter at Nikiski to manage its power gen-eration systems.
“We’ve got a lot of new investment ingeneration and we want to make sure itgets operated and maintained properly,”Janorschke said.
Nikiski plantThe high-efficiency power plant in
Nikiski will meet HEA’s base load needs,while the Soldotna plant, located at thehub of the Kenai Peninsula grid and at theconnection point with the transmissionintertie to Anchorage, will meet peakpower needs and also provide what arereferred to as “spinning reserves,” theextra power capacity that utilities keep intheir back pockets to cover any potentialsupply shortfalls.
However, since the upgraded Nikiskipower station will operate at maximumefficiency at 58 megawatts, upping the
power output there or starting up relative-ly inefficient plants at Soldotna orBernice Lake would increase the cost ofthe power. So if, say, HEA needed anextra two or three megawatts to cover asmall spike in demand, the utility wouldfirst try to obtain cheaper power fromactive power units operated by otherRailbelt utilities rather than starting upsome of HEA’s own systems to cover theload, Janorschke explained.
Contracted gasJanorschke said that HEA has con-
tracted with Hilcorp Alaska to meet all ofthe utility’s natural gas needs from Jan. 1,2014, to March 31, 2016, after the termi-nation of the Chugach Electric powersupply contract, with an option to extendthe Hilcorp contract up to a further twoyears. Beyond that HEA faces the samegas supply uncertainties as otherSouthcentral utilities.
“In the long term we are going to becontinuing to work with the other utilitiesand other entities to try to find out wherewe are going to get long-term gas forAlaska,” Janorschke said.
Small gas producers in the Cook Inletbasin have been unwilling to commit toproviding the bulk of HEA’s gas suppliesbecause, having very few wells, theseproducers do not wish to risk becoming autility’s sole-source provider, Janorschkesaid.
“They said go find a base load supplyof gas from a large producer and thencome back and talk to us about smallerincrements. So that’s what we’ve done,”he said.
HydropowerLooking out into the future, HEA has
been working with other Railbelt utilitiesand with the Alaska Energy Authority onproposed new hydropower systems atWatana on the Susitna River and at BattleCreek. HEA has also proposed buildingits own small five-megawatt hydroelectricfacility at Grant Lake, near Moose Passon the Kenai Peninsula. The Grant Lakeproposal has met with opposition frompeople concerned about potential envi-ronmental impacts — HEA has beenaddressing the concerns and is continuingwith a study for the project, Janorschkesaid.
HEA has also signed an agreementwith Ocean Renewable Power Co. for thedevelopment of a pilot tidal current gen-eration system in Cook Inlet at EastForeland near Nikiski. And HEA’s netmetering system — the arrangementwhereby the utility’s members can con-nect their own small-scale renewableenergy generators to the grid — has takenoff, with 52 members now interconnectedwith HEA’s system, Janorschke said.
Transmission upgrades In parallel with its independent light
power generation program HEA isupgrading the sparse and aging powertransmission infrastructure on the KenaiPeninsula. The transmission lineupgrades are being funded through a stategrant.
Particularly critical are the transmis-sion circuits between Soldotna, Nikiskiand Kenai where, because of capacityconstraints, there is in effect a singletransmission line connecting the critical
6 PETROLEUM NEWS • WEEK OF MAY 13, 2012
� U T I L I T I E S
HEA moving ahead with system upgradesKenai Peninsula utility in process of building new natural gas generation facilities as part of its independent light program
see HEA UPGRADES page 9
By ALAN BAILEYPetroleum News
Since July 2010 Cook Inlet independentAurora Gas has been trying to per-
suade the State of Alaska to combine acouple of state leases near the communityof Kasilof on the Kenai Peninsula with anadjoining Cook Inlet Region Inc. lease toform the Cohoe unit. The state leases hadbeen due to expire in September 2010, butAurora said that it wanted to conduct aseismic survey and do exploratory drillingin the proposed unit — unitization of theleases would head off the lease termina-tion.
But all came to naught on May 3 whenDan Sullivan, commissioner of the AlaskaDepartment of Natural Resources, issued adecision upholding an earlier Division ofOil and Gas rejection of the unitizationrequest.
Sullivan said that he affirmed the find-ing of the division’s director, WilliamBarron, that it is “not in the state’s interestto allow Aurora to retain the leases andbenefit from the lease term extensions pro-vided by unitization without havingdemonstrated the need for unitization.”
“Aurora is obviously disappointed bythe commissioner’s decision to affirm thedirector’s denial of the Cohoe unitization,”Ed Jones, president of Aurora Gas, toldPetroleum News in a May 8 email. Auroradoes not plan a further appeal of the deci-sion, he said.
Cohoe wellThe leases in question include the
Cohoe Unit No. 1 well, drilled by Unocalin 1973 to a depth of 15,683 feet, presum-ably in search of oil. The well bottomedout in the West Foreland formation. Drillstem tests conducted in nine zones at vari-ous levels in the well detected smallamounts of natural gas in three of thezones, two in the Sterling formation andone in the Beluga formation.
Two consortia acquired the state leasesin the 2003 Cook Inlet areawide lease sale,with Aurora subsequently acquiring theleases in March 2004. And in August 2006Aurora leased the Cook Inlet Region Inc.acreage that forms part of the package thatAurora has subsequently wished to unitize.
According to Sullivan’s May 3 decisiondocument, no one has conducted anyexploration work on the three leases inquestion over the past seven years,although Aurora has conducted a re-assessment of seismic and well data relat-ing to the leases — in addition to thedrilling of the 1973 Cohoe well, a seismicsurvey was conducted on the acreage in1972.
After Aurora submitted its unitizationrequest in 2010 there was a delay of a yearor so in dealing with the request, whilestate officials waited for Aurora to submita unit agreement that included both thestate and Cook Inlet Region Inc.
And under that unit agreement Auroraproposed a two-year plan of explorationinvolving the re-entry of the old Cohoewell and the gathering of some new 3-Dseismic data. Aurora told Petroleum Newsin 2010 that its preference would be to firstconduct the seismic survey, to determinewhether the Cohoe well had penetrated thecrest of the geologic structure at Cohoe —depending on the seismic results the com-pany might drill a new well in a differentlocation, the company said.
The company also said that it hoped tohead off lease termination, if necessary, byre-entering the Cohoe well before the leaseexpiry date. The company subsequentlysaid that, because of drilling commitmentson the west side of the Cook Inlet, it hadnot proved possible to move the AuroraWell Services No. 1 drilling rig to theCohoe location prior to that lease expirydate.
Timely developmentIn his decision document Sullivan said
that the primary purpose of state oil andgas leasing is to secure the timely develop-ment of state resources and that, understate statutes, the unitization of leases isintended for conserving an oil or gas poolto prevent waste; to ensure the maximumrecovery of oil and gas; and to protect thecorrelative tights of people owning inter-ests in the affected land.
“Thus, to justify a unit, the lesseeshould demonstrate that the leases containa pool or field, that unitization will pro-mote the efficient recovery of oil or gas,and that the lessee’s plan to move the unit-ized leases into production requires uniti-zation to conserve the resource and pre-vent waste,” Sullivan wrote.
In the case of the Cohoe leases, AuroraGas has not demonstrated that the pro-posed unit area lies over a hydrocarbonreservoir or pool, Sullivan wrote. No wellhas been drilled and tested that demon-strates the existence of hydrocarbons inpaying quantities in any of the leases pro-posed for unitization, he wrote. And datapresented by Aurora do not define anddelineate a geologic structure that wouldbe capable of trapping an oil or gas pool,he wrote.
Aurora had argued that the proximity ofthe Cohoe well to the border of the Cook
Inlet Region Inc. land led to a need for uni-tization of the state and private leases, toenable development of the land to proceed— the Cohoe well is in state land but islocated within 20 feet of the boundarywith the Cook Inlet Region Inc. land,Aurora said.
However, Sullivan said that the lack ofevidence for a hydrocarbon pool in theleases rendered moot any other argumentsfor unitization.
Lease expiry irrelevantMoreover, no statute or regulation gives
lease expiry as a basis for unitizing leases,and the expiration of the leases does not initself justify the formation of a unit,Sullivan wrote. And a review of past stateunitization decisions does not support acontention by Aurora that the state has pre-
PETROLEUM NEWS • WEEK OF MAY 13, 2012 7
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� L A N D & L E A S I N G
DNR upholds rejection of Cohoe unitSays Aurora Gas has not shown proposed Kenai Peninsula unit overlies oil or gas pool; lease expiry not a reason for unitization
see COHOE UNIT page 9
8 PETROLEUM NEWS • WEEK OF MAY 13, 2012
NATURAL GASNikolaevsk next up for natural gas
The tiny village of Nikolaevsk could soon become the second community inthe southern Kenai Peninsula to be added to the Southcentral natural gas distribu-tion grid.
The Armstrong Oil & Gas Inc. subsidiary Anchor Point Energy LLC recentlyasked state regulators to approve an agreement with Enstar Natural Gas Co. thatwould deliver supplies from the North Fork unit to the small community just northof the city of Homer.
Approval from the Regulatory Commission of Alaska would allow Enstar touse a $447,000 grant from the state to add an interconnection to the North ForkPipeline.
With “prompt approval” by the RCA, the Nikolaevsk Community School andthe local fire station could convert their heating systems this summer in advanceof next winter.
8,930-foot 2-inch lineIf given the go ahead, Enstar would build a regulator station at the North Fork
Pipeline and a two-inch pipeline running 8,930 feet to a recently built regulatorstation at the school. While the school will likely be the largest customer, Enstarexpects to eventually add the fire station and 12 homes during the initial build out.As of October 2011, Enstar had installed nearly two miles of distribution mainpipelines throughout Nikolaevsk.
The RCA added Nikolaevsk to the Enstar service area in 1997.The community is home to some 308 people, according to the state.While the North Fork Pipeline is currently feeding into the regional distribu-
tion grid, communities in the southern Kenai Peninsula see it as a chance to getoff heating oil.
The pipeline is currently delivering supplies to the coastal community ofAnchor Point, but is not yet connected down to Homer and Kachemak, home tonearly 6,000 people.
The Alaska Legislature approved an $8.15 million line item for that project, butGov. Sean Parnell has yet to release his final vetoes for the fiscal year 2013 cap-ital budget.
—ERIC LIDJI
� G O V E R N M E N T
Interior requireschemicals disclosureNew drilling rules on public land set standards for wellconstruction, wastewater disposal; chemical disclosure after drilling
By MATTHEW DALYAssociated Press
The Obama administration said May 4 itwill for the first time require compa-
nies drilling for oil and natural gas on pub-lic and Indian lands to publicly disclosechemicals used in hydraulic fracturing oper-ations.
The proposed “fracking” rules also setstandards for proper construction of wellsand wastewater disposal.
Interior Secretary Ken Salazar said thelong-awaited rules will allow continuedexpansion of drilling while protecting pub-lic health and safety.
“As we continue to offer millions ofacres of America’s public lands for oil andgas development, it is critical that the publichave full confidence that the right safetyand environmental protections are in place,”Salazar said.
The proposed rules will “modernize ourmanagement of well-stimulation activities,including hydraulic fracturing, to make surethat fracturing operations conducted onpublic and Indian lands follow common-sense industry best practices,” he said.
The new rules, which have been underconsideration for a year and a half, weresoftened after industry groups expressedstrong concerns about an initial proposalleaked earlier this year. The proposal wouldallow companies to file disclosure reportsafter drilling operations are completed,rather than before they begin, as initiallyproposed. Industry groups said the earlierproposal could have caused lengthy delays.
Some environmental groups criticizedthe change as a cave-in to industry, butSalazar said the rules were never intended tocause delays, but to ensure that the public is“fully aware of the chemicals that are beinginjected into the underground” by compa-nies seeking to produce oil and natural gas.
Some 90% use fracturingThe Bureau of Land Management,
which oversees drilling on public lands,estimates that 90 percent of the approxi-mately 3,400 wells currently drilled on fed-eral and Indian lands using hydraulic frac-turing techniques.
The rules would not affect drilling onprivate land, where the bulk of shale explo-
ration is taking place. A nationwide drillingboom in formations such as the MarcellusShale in the Appalachian region and theBakken in North Dakota and Montana, aswell as in traditional production states suchas Texas, Oklahoma and Louisiana, has ledto 10-year lows in natural gas prices.
Still, Salazar said he hopes the new rulescould be used as a model for state regula-tors.
“We hope our leadership is followed,” hesaid at a news conference.
Industry groups and Republican law-makers say federal rules are unnecessary,arguing that states already regulatehydraulic fracturing, in which water, sandand chemicals are in injected undergroundto break up dense rock that holds oil andgas.
Trade secrets an issueThe industry also has complained that
disclosure of chemicals used in frackingcould violate trade secrets, although Salazarsaid the rule would include exemptions forspecific formulas. Some of the chemicalsused in fracking include benzene, toluene,ethylbenzene and xylene, all of which cancause health problems in significant doses.
Critics say fracking chemicals have pol-luted water supplies, but supporters saythere is no proof.
Tom Amontree, executive vice presidentfor America’s Natural Gas Alliance, anindustry group, said the Obama administra-tion “may not fully appreciate” significantregulatory steps taken by states such asColorado, Texas and Wyoming to overseehydraulic fracturing.
“State regulatory bodies have repeatedlyproven that they have the understanding oftheir state’s own unique geologic condi-tions, the on-the-ground expertise needed tooversee this important work, and mostimportantly, the ability to respond to rapidchange,” Amontree said. As drafted, the fed-eral proposal would create reportingrequirements and “regulatory impedi-ments” that could substantially affect theability of companies to drill on public lands,he said.
The proposed rules will be subject topublic comment for 60 days, with a finalorder expected by the end of the year, saidBLM Director Bob Abbey. �
By KRISTEN NELSONPetroleum News
C rude oil prices are dropping and U.S.crude oil production is rising, the U.S.
Energy Information Administration said inits May short-term energy forecast, releasedMay 8.
EIA is now forecasting a $110 per barrelU.S. refiner acquisition cost this year, down$2.50 per barrel from the April outlook, anda West Texas Intermediate crude oil price of$104 per barrel this year, down about $2 perbarrel from the April outlook.
The WTI price is $9 a barrel higher thanthe average price last year and the U.S.refiner acquisition cost is about $8 per bar-rel higher than in 2011. EIA said it expectscrude oil prices to remain relatively flat in2013.
US production highest since 1998U.S. crude oil production is expected to
average 6.2 million barrels per day this year,up 500,000 bpd from 2011 — the highestlevel of production since 1998, EIA said.
In 2011, U.S. crude oil productionincreased an estimated 190,000 bpd, 3.4percent, to 5.66 million bpd, with anincrease of 450,000 bpd in Lower 48onshore production partly offset by a30,000 bpd decline in Alaska and a 230,000bpd decline in the federal Gulf of Mexico.
The EIA’s forecast of 6.17 million bpdfor this year is up 150,000 bpd from theagency’s April forecast, “and the highest
level of production since 1998.” The agency said the rise in production is
driven “by increased oil-directed drillingactivity, particularly in onshore tight oil for-mations,” with the number of oil-directedrigs reported by Baker Hughes up from 777at the beginning of 2011 to 1,355 on May 4.
The share of U.S. consumption met byliquid imports (including crude oil andproducts) has been falling since 2005, EIAsaid, averaging 45 percent in 2011, downfrom 49 percent in 2010.
The total net import share of U.S. con-sumption is expected to “continue todecline to 43 percent in 2012 and 42 per-cent in 2013,” the agency said.
US natural gas increasesEIA said total marketed production of
natural gas in the U.S. grew by an estimated4.8 billion cubic feet per day (7.9 percent)in 2011, “driven in large part by increases inshale gas production.”
The agency said it expects year-over-year production to continue to grow thisyear, but “at a slower rate than in 2011 aslow prices reduce new drilling plans.” EIAsaid Baker Hughes reported a natural gasrig count of 613 at the end of April, the low-est gas-related rig count since 2002, anddown from a 2011 high of 936 in mid-October.
EIA attributes a drop in natural gas mar-keted production from January to Februaryto declining production from less-profitabledry natural gas plays such as the
Haynesville Shale being offset by more pro-duction from liquids-rich areas such as theEagle Ford and wet areas of the MarcellusShale.
Gross pipeline imports are expected tofall by 0.3 bcf per day (3.3 percent) this yearas domestic supply displaces Canadiansources, with warm weather in the U.S.adding to the year-over-year decline inimports, particularly in the Northeast.
Gross pipeline exports grew by 1 bcf perday last year, driven by increased exports toMexico the EIA said, and are expected tocontinue to grow at a slower rate in 2012and 2013.
Henry Hub natural gas spot prices aver-aged $1.95 per million British thermal units
in April, down 23 cents per million Btufrom March “and the lowest averagemonthly price since March 1999, whichalso was the last time the Henry Hub priceaveraged less than $2 per MMBtu,” EIAsaid.
The agency said abundant supplies andlower winter heating demand contributed torecent low prices.
EIA said it expects the Henry Hub natu-ral gas price to average $2.45 per millionBtu this year and $3.17 in 2013, down fromApril forecasts of $2.51 and $3.40 per mil-lion Btu, respectively. �
PETROLEUM NEWS • WEEK OF MAY 13, 2012 9
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power generation system at Nikiski to therest of the power grid. An upgrade of theline that carries power between Nikiskiand Soldotna from 69 kilovolts to 115kilovolts will rectify that particular prob-lem — work on that upgrade will proba-bly start next winter, Janorschke said.
HEA is also upgrading some electrici-ty substations on the peninsula.
The best option for further improve-ments to the stability of the power supplieson the Kenai Peninsula would be theinstallation of a second transmission inter-tie between Anchorage and the peninsula,Janorschke said. That “would do wondersfor everybody and I think is where wehave to go eventually,” he said. �
continued from page 6
HEA UPGRADES
Contact Alan Bailey at [email protected]
viously granted the unitization of leaseswhen needed for exploration, he wrote.
“Unitizing state leases in this situationwould make the primary term of the leasemeaningless,” Sullivan wrote. “If thesenon-producing leases that have not beenadequately explored during the primaryterm can be unitized on eve of their expi-ration date, and then remain in forcethrough unitization, this essentially cir-cumvents the lessee’s statutory and con-tractual obligation to explore and developduring the primary term of the lease.” �
continued from page 7
COHOE UNIT
Contact Alan Bailey at [email protected]
EXPLORATION & PRODUCTIONUS oil, gas rig count up by 20 to 1,965
The number of rigs actively exploring for oil and natural gas in the U.S. was up20 the week ending May 4 to 1,965.
Houston-based oilfield services company Baker Hughes Inc. reported that1,355 rigs were exploring for oil and 606 were looking for gas. Four were listedas miscellaneous. A year ago this week, Baker Hughes reported 1,836 rigs.
Of the major oil- and gas-producing states, Texas gained eight rigs, Louisianaand New Mexico each gained four, California gained two and North Dakotagained one.
Alaska and Colorado each lost two rigs while Pennsylvania and West Virginiaeach lost one. Arkansas, Oklahoma and Wyoming were unchanged.
The rig count peaked at 4,530 in 1981 and bottomed at 488 in 1999. —ASSOCIATED PRESS
� F I N A N C E & E C O N O M Y
EIA forecasts lower WTI crude oil pricesUS total crude oil production expected to average 6.2 million bpd this year, up 500,000 bpd from 2011 and highest level since 1998
Contact Kristen Nelson at [email protected]
By WESLEY LOYFor Petroleum News
Dan Sullivan, Alaska’s naturalresources commissioner, recently lit
out for Washington, D.C., with a 22-pagepresentation under his arm titled, “AlaskaGas Opportunities.”
By the time his weeklong visit was over,the report was marked up and dog-earedfrom showing it over and over to seniorObama administration officials, businesspeople, diplomatsand one notably con-trarian congressman.
Sullivan’s inspira-tion for the April 23-27 trip was the recentevolution of Alaska’senergy developmentstrategy.
On March 30, thethree major oil com-panies operating in Alaska — BP,ConocoPhillips and ExxonMobil — saidthey would work together to assess a possi-ble liquefied natural gas export project.Sullivan’s boss, Gov. Sean Parnell, hadencouraged the companies to align on theLNG idea, a departure from their previousfocus on constructing a gas pipeline intoCanada.
On the same day, the state announced ithad finalized a settlement withExxonMobil over the disputed PointThomson field. The field is consideredimportant for any gas development, holdingperhaps a quarter of the North Slope’s gasreserves.
‘Not just waiting’Sullivan, in a May 7 interview with
Petroleum News, said he took theWashington trip to tout Alaska’s “compara-tive advantages,” and to urge federal offi-cials not to allow further permitting delaysfor the inaugural Point Thomson develop-
ment.ExxonMobil is waiting for a wetlands
permit from the U.S. Army Corps ofEngineers for its planned gas condensateproject at Point Thomson, located on theBeaufort Sea coast next to the ArcticNational Wildlife Refuge. The company’soriginal target date for first production hasslipped by more than a year due to repeateddelays in finishing an environmental impactstatement. The Corps now expects to issuethe final EIS in June.
With the alignment of the major oilcompanies, and the strong market for gas inAsia, the time to promote Alaska is now, hesaid.
“We’re not just waiting,” Sullivan said.That presentation he took on his trip was
designed to explain, starting with thebasics, what Alaska has to offer in terms ofbillions of barrels of oil and many trillionsof cubic feet of gas.
Sullivan pointed out that Alaska alreadyhas a long and unique record of Asianexports via the ConocoPhillips LNG facili-ty on Cook Inlet.
Further, Sullivan made sure to point outthat Alaska gas is “not part of the shaleLNG export debate in the Lower 48,” asAlaska exports wouldn’t affect Lower 48gas supply and prices.
And he explained that exporting NorthSlope gas would “help Americans —they’re called Alaskans.”
Long visitation listCertainly, Sullivan knows his way
around Washington. Under PresidentGeorge W. Bush, Sullivan served as theassistant secretary of state for economic,energy and business affairs.
After that, he served as Alaska’s attorneygeneral from June 2009 until December2010, when Parnell appointed him naturalresources commissioner.
Sullivan’s Washington visitation list waslengthy. He said he had meetings with:
• Deputy Secretary of Energy DanielPoneman, the department’s second highestranking official.
• Deputy Interior Secretary DavidHayes, the department’s second highestranking official.
• Bob Cekuta, principal deputy assistantsecretary in the State Department’s newBureau of Energy Resources, assigned toTokyo from 2007-09.
• White House official Heather Zichal,the deputy assistant to the president forenergy and climate change.
• Daniel Yergin, prize-winning author,CNBC energy analyst and chairman andfounder of IHS Cambridge EnergyResearch Associates.
• Ichiro Fujisaki, Japan ambassador tothe United States.
Sullivan said he also made a presenta-tion at the Center for Strategic andInternational Studies, heard from GoldmanSachs investment bankers on global LNGtrends, and met with potential LNG cus-tomers.
Export resistanceSullivan isn’t the first Alaska official to
come calling in the nation’s capital, and he
10 PETROLEUM NEWS • WEEK OF MAY 13, 2012
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LAND & LEASING
This week’s lease sale chartsponsored by:
Geokinetics
Potential Alaska state and federal oil and gas lease sales
Agency Sale and Area Proposed Date
DNR Cook Inlet Areawide May 16, 2012
DNR Alaska Peninsula Areawide May 16, 2012
DNR Beaufort Sea Areawide fall 2012
DNR North Slope Areawide fall 2012
DNR North Slope Foothills Areawide fall 2012
BLM NPR-A late 2012
BOEM 2013 Cook Inlet (special interest) late 2013
BOEM Beaufort Sea 2015
BOEM Chukchi Sea 2016
Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, manages leasing inthe National Petroleum Reserve-Alaska; BOEM, U.S. Department of the Interior’s Bureau of Ocean
Energy Management (formerly Minerals Management Service), Alaska region outer continental shelfoffice, manages sales in federal waters offshore Alaska; DNR, Alaska Department of Natural Resources,Division of Oil and Gas, manages state oil and gas lease sales onshore and in state waters; MHT, Alaska
Mental Health Trust Land Office, manages sales on trust lands.
� N A T U R A L G A S
Touting Alaska gasin nation’s capitalDNR commissioner goes to Washington, DC, to talk up state’senergy agenda, and to urge prompt Point Thomson permitting
DAN SULLIVAN
see SULLIVAN IN DC page 14
SHA
NE
LASL
EY
� F I N A N C E & E C O N O M Y
State, BP heading into arbitrationAt issue is potentially hundreds of millions of dollars in compensationfor production shortfalls after 2006 spills at Prudhoe Bay
By WESLEY LOYFor Petroleum News
The state and BP are about to begin arbi-tration proceedings over the 2006
pipeline leaks in the Prudhoe Bay oil field.The stakes are high, with potentially
hundreds of millions of dollars on the line.The arbitration stems from a civil suit the
state filed against BP Exploration (Alaska)Inc. in March 2009 in state Superior Courtin Anchorage.
The suit came after a pair of oil spills atPrudhoe, which BP operates for an owner-ship group that also includesConocoPhillips, ExxonMobil and Chevron.
One spill, at 212,252 gallons, was thelargest oil spill ever on Alaska’s NorthSlope.
The spills were from corroded oil transitlines that feed sales-grade crude into thetrans-Alaska pipeline.
BP Alaska was convicted of a federalenvironmental misdemeanor, whichresolved the criminal aspect of the matter.
Back taxes, royalties soughtThe state’s subsequent civil suit alleged
negligence and sought a range of damagesfrom BP.
Most significantly, the suit sought backtaxes and royalties to compensate the statefor what it contended were productionshortfalls of at least 35 million barrels of oiland natural gas liquids from Prudhoe andthe neighboring Milne Point field.
These shortfalls, from 2006 through2008, resulted from “massive productionshut-ins” due to the spills and subsequentreplacement of corroded pipelines, the suitsaid.
A judge in December 2010 threw out thestate’s tax claim, hugely reducing BP’spotential liability in the lawsuit.
The case is now on hold while the stateand BP take the remaining royalty claim tobinding arbitration.
Private proceedingsOn May 3, lawyers for the state filed a
brief status report saying: “An arbitrationpanel has been selected, and the arbitrationin this matter is scheduled to begin on May22.”
Steve Mulder, the state’s lead attorney onthe case, did not respond by press time to aPetroleum News request for more informa-tion. However, he previously has provideddetails about the arbitration.
The panel of three arbitrators was agreedto by each side. The arbitration will be con-ducted privately, but the result will be madepublic.
“Much of the information likely to bepresented at the arbitration is subject to pro-tective orders entered by the Superior Courtbecause it is considered confidential busi-ness information,” Mulder said in a March1 email. “For this reason, the arbitrationproceeding itself will not be open to thepublic.”
How much money?The state will ask the arbitration panel to
award an amount to compensate the statefor the royalties it did not receive due to pro-duction shut-ins stemming from thepipeline leaks.
“The arbitration will focus on whetherBP ‘made-up’ the lost production shortlyafter putting into service replacementpipelines or whether the production oppor-tunity lost in 2006-08 will not be realizeduntil the end of field life, if ever, due toknown gas and water handling constraints,”Mulder said in a Jan. 10 email.
It’s not known exactly how much moneythe state is seeking.
But conceivably, if at arbitration the stateis able to show that it is due a 12.5 percentroyalty on the full 35-million-barrel produc-tion shortfall alleged in the suit, that wouldbe about $328 million at $75 per barrel. �
PETROLEUM NEWS • WEEK OF MAY 13, 2012 11
NATURAL GASFNG gets Cook Inlet supply extension
Fairbanks Natural Gas LLC recently extended its Cook Inlet supply contract byone year.
The extension now gives the Fairbanks gas distribution utility until May 31,2014, to switch its supply source to the North Slope, the company recently toldregulators.
In March, the Regulatory Commission of Alaska granted Fairbanks NaturalGas-affiliate Polar LNG LLC a certificate to build and operate a common carrierpipeline at Prudhoe Bay that would eventually feed a liquefied natural gas plantto be built at Deadhorse.
Polar LNG recently applied for a pipeline right-of-way lease from the StatePipeline Coordinator’s Office. The pipeline would run some 3.5 miles from FlowStation 1 at the Prudhoe Bay unit to the Polar LNG Pas, formerly known as Child’sPad) in Deadhorse.
Fairbanks Natural Gas currently trucks LNG north from Cook Inlet, but inearly 2008 secured a 10-year contract to buy North Slope gas from anExxonMobil subsidiary.
The Cook Inlet supply currently serves as a feedstock for an LNG facility atPoint MacKenzie. Fairbanks Natural Gas currently trucks LNG north along theParks Highway.
While Fairbanks Natural Gas and Polar LNG work to bring the project online,Golden Valley Electric Association and Flint Hill Resources Alaska are also con-sidering a plan to truck LNG from the North Slope to the Interior starting in early2014. The Polar LNG project would likely require big anchor customers like thepower utility and the refinery.
—ERIC LIDJIContact Wesley Loy at [email protected]
12 PETROLEUM NEWS • WEEK OF MAY 13, 2012
� E X P L O R A T I O N & P R O D U C T I O N
Great Bear’s Duncan: ‘In it together’A more conservative, but not subdued, Duncan declines to testify to Senate Resources Committee on tax breaks needed for project
By KAY CASHMANPetroleum News
Hours before Gov. Sean Parnellabruptly withdrew his revised pro-
duction tax bill from consideration by aspecial session of the Alaska Legislaturebecause of lack of support in the Senate,Great Bear Petroleum’s top executive, EdDuncan, addressed the Senate Resourcescommittee, in testimony that was sup-posed to address the governor’s compro-mise tax bill, Senateand House bills3001.
Although moreconservative interms of what hiscompany’s pioneer-ing efforts in oilextraction fromNorthern Alaska’sthree great sourcerocks might con-tribute to the state’s declining oil produc-tion, Duncan did not offer a positive ornegative comment on SB 3001, althoughhe did say that Great Bear officials “areamazed at the cost differential betweenNorth Alaska” and the much lower-costSouth Texas, “whether it’s rig rates,whether it’s labor costs, whether it’s thecost of pipe, wellheads, you name it, it’sthere.”
But with Great Bear just starting itsmulti-well, proof of concept drilling andtesting phase, expected to last until the
end of December,followed by a one-year pilot productiontest, Duncan made itclear that he stilldoes not know whether Alaska’s sourcerocks can be enticed to produce commer-cial qualities of oil and natural gas liq-uids, and thus what the state of Alaskacan do to help his company and others.
So when asked by Sen. Lesil McGuireto contribute to the tax dialogue about“any potential (production tax) bill thatcould come out of this session” andwhether he had “a preference in what typeof incentive the state would offer,”Duncan responded with a question thatdefined his goal for state participation in
what he referred to numerous times in histestimony as shared state/industry/societalconcerns and challenges.
Make Alaska competitive with lower 48 states
“What are the things that the state cando, realistically do, to help us push thefinding and development costs in NorthAlaska down to something that competes(with), or is better than — let’s make itbetter than — the Lower 48. Let’s turnthis thing around,” he said.
But Duncan said he “preferred” thatthe answer(s) “be the product of a differ-ent type of discussion than the answer toa simple question because we can lay outto you where our big cost points are,
things that keep me awake at night, andlet’s engage the bigger brain of the stateand the industry to solve that problembecause it doesn’t just solve it for us — itsolves it for everybody on the map.”
“We’re all in this together — that’s theother thing that is critical here. The chal-lenge isn’t just Great Bear’s, or the chal-lenge isn’t just the state of Alaska’s … thechallenge effects everyone from the supermajors on the Slope to the smallest com-pany,” he said many times, in differentways, in his testimony.
Duncan was “happy” to answerMcGuire’s question, but not then andthere.
Rather, he wanted to begin the discus-sion after May 8, explaining that “theweek after next our all-internal task forceon cost-reduction meets. I guess it’s theeighth of May. And I would propose …we join with the state following thosemeetings — and we’ll have those regular-ly — and work through where we seemajor cost drivers and places where thestate maybe could facilitate significantcost reductions. … I consider those thingsgood and proper incentives for us withoutme trying to prescribe what those would
ED DUNCAN
see GREAT BEAR page 19
JUD
Y P
ATR
ICK
CO
URT
ESY
GR
EAT
BEA
R P
ETR
OLE
UM
“So for our operations in NorthAlaska we don’t see shallow
aquifers as being a significantchallenge.” —Ed Duncan,
Great Bear Petroleum
PETROLEUM NEWS • WEEK OF MAY 13, 2012 13
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14 PETROLEUM NEWS • WEEK OF MAY 13, 2012
EXPLORATION & PRODUCTION
Shell asks court to declare IHAs validIn the latest of a series of court actions designed to pre-empt last minute litigation
against its planned Arctic outer continental shelf drilling this year, Shell has filed apetition with the federal District Court in Alaska, asking the court to rule that theNational Marine Fisheries Service properly issued incidental harassment authoriza-tions, or IHAs, for Shell’s drilling operations.
The IHAs mandate measures that Shell must take to avoid disturbing marinemammals or subsistence hunting when drilling in the Beaufort and Chukchi Seas,while also allowing the accidental disturbance of small numbers of marine mammalswithout the company running afoul of the Marine Mammals Protection Act.
The court petition targets 14 environmental groups which Shell says oppose thecompany’s Arctic drilling plans and which the company says have a track record ofappealing permit decisions.
“Their prior statements and past practice make it a virtual certainty that they willlitigate the approval of the IHAs,” wrote attorney Kyle Parker in Shell’s petition, filedMay 3. Shell’s pre-emptive court action will provide the court with sufficient time tomake a reasoned evaluation of the Fisheries Service decision, Parker wrote. Shellplans to start its initial drilling operations in July in the Chukchi Sea. The companyhas already filed a similar petition with the District Court, asking the court to affirmapproval of the company’s oil spill response plans by the Bureau of Safety andEnvironmental Enforcement.
The U.S. Court of Appeals for the 9th Circuit is already considering appeals byenvironmental groups and some Native organizations against the approval of Shell’sChukchi Sea and Beaufort Sea exploration plans, against the air permit for the NobleDiscoverer drillship that Shell plans to use, and against the lease sale in which Shellobtained its Chukchi Sea leases.
—ALAN BAILEY
ConocoPhillips still planning for CD-5It has been four or five months since the Corps of Engineers approved the Colville
River crossing that ConocoPhillips needs for its CD-5 oil field development in thenortheastern corner of the National Petroleum Reserve-Alaska, and the company isprogressing its planning for the project, with the objective of obtaining boardapproval for the field development.
“We are evaluating and incorporating the terms of the Corps of Engineers permitinto our project plan, and working out engineering and design details in order to takethe project to the COP board for sanctioning later this year,” ConocoPhillips spokes-woman Natalie Lowman told Petroleum News in a May 4 email. Lowman toldPetroleum News in December, after the Corps decision, that ConocoPhillips antici-pates starting construction at CD-5 in the winter of 2014, with construction continu-ing during the following winter and first oil coming on line in 2015.
—ALAN BAILEY
surely won’t be the last.The fact is, gas development has
defied one Alaska governor afteranother. Any project to develop thestate’s gas involves long lead times,enormous cost and huge risk. And sothe gas has stayed stuck in the grounddecades after its discovery.
An explosion of shale gas in theLower 48 has stoked interest in possibleU.S. gas exports, and this in turn hasprovoked a backlash from people suchas Rep. Ed Markey, D-Mass. He hasintroduced bills to discourage exports,saying the gas is needed at home.
After the announcement about BP,ConocoPhillips and ExxonMobil align-ing on a possible Alaska LNG project,Markey put out a March 21 pressrelease saying in part: “When webought Alaska from the Russians foronly $7 million, we got a great deal. IfAmerica now turns around and allowsthe big oil companies to sell offAmerica’s natural gas resources inAlaska and elsewhere to the Chinese,Uncle Sam really would deserve to becalled Uncle Sucker.”
Markey asserted that exportingAlaska gas could increase domesticprices, hurting American manufactur-ing.
Naturally, Sullivan made a point ofmeeting with Markey, too, during hisWashington week. �
continued from page 10
SULLIVAN IN DC
Contact Wesley Loy at [email protected]
ASSOCIATIONS
AEDC releases annual resource forecastOn May 2, the Anchorage Economic Development Corp. held its annual event
celebrating the release of its latest resource extraction projection report at theDowntown Marriott Hotel.
Sponsored by Northrim Bank, the 2012 AEDC Resource Extraction 10-YearProject Projection focused on the oil, gas and mining projects in the state over thenext 10 years and the economic impacts of those developments.
The event, which included hors d’oeuvres and a no host bar, featured a livespeech by U.S. Senator Mark Begich, D-Alaska, and a DVD presentation by U.S.Senator Lisa Murkowski, R-Alaska, who shared their thoughts on the oil and gasand mining opportunities in Alaska over the next decade from a federal perspec-tive.
AEDC’s President and CEO Bill Popp said the 2012 job estimate for the proj-ects increased this year to 19,341 and also noted that the total dollars proposed forinvestment decreased slightly from $33.7 billion in 2011 to $30.4 billion in 2012.
Most projects moved back another year in the timeline for varying reasonsincluding permit challenges, litigation, project plan changes, etc.
Popp said AEDC has seen modest progress in moving projects forward butchallenges still remain for many of the developments.
The research for the report was provided by North of 60 Mining News editorShane Lasley and by Dan Dickinson and Mary Ann Pease under contract to
CO
URT
ESY
AED
C
see AEDC FORECAST page 19
Alaska Sen. Mark Begich addresses attendees at the 2012 Anchorage EconomicDevelopment Corp. Resource Extraction 10-Year Project Projection event.
PETROLEUM NEWS • WEEK OF MAY 13, 2012 15
LET’S BE MORE PREPARED THAN EVER.Shell is dedicated to preventing and preparing for any safety challenges we may face. To support 2012 plans for drilling up to five exploration wells off the northern coast of Alaska, Shell has created an unprecedented spill response plan. Offshore, onshore and near-shore response teams and Arctic-appropriate equipment will be ready 24 hours a day, and operational within an hour. The purpose built, ice-class, spill response vessel Nanuq and the newly launched Aiviq, a 360-foot ice-class anchor handler, add to Shell’s capabilities. A sub-sea containment system, enhanced response plan and upgraded blow out preventor further strengthen the available assets. With these capabilities in place, Shell is more prepared than ever before. www.shell.us/alaska
� N A T U R A L G A S
Study says US LNG exports feasibleBrookings Institution study finds that there should be enough L48 natural gas to export some as LNG to the benefit of the US
By ALAN BAILEYPetroleum News
Ayear-long study by the BrookingsInstitution, a non-partisan public poli-
cy organization, has found that the export ofat least some LNG from the United States islikely to be both feasible and in the country’sbest interests. The study, which focused onthe export of LNG from the Lower 48 statesrather than from Alaska, found that althoughthe export of LNG would likely somewhatincrease natural gas prices in the UnitedStates, the economic benefits derived fromthe exports would more than offset any neg-ative impacts from the higher cost of gas forU.S. consumers.
And the study authors cautioned againstgovernment interference in the LNG market,saying that this type of interference wouldlikely cause undesirable, unintended conse-quences as a result of, in effect, subsidizingU.S. gas consumers at the expense of gasproducers.
To inform its research the institutionassembled a task force of 17 experts fromconsulting firms and academia.
Shale gasThe starting point for the study report is
the rapid growth in shale gas production inthe United States. This production growth iscreating a situation where the country has anexcess of gas supply over internal gasdemand, thus potentially creating a source ofgas to export into international LNG mar-kets.
Experts in the gas industry say that
evolving shale gas technologies are over-coming problems with the sustainability ofproduction from shale gas plays, althoughquestions over the environmental impacts ofshale gas development are still causing con-cern and some uncertainty. And there aresome significant issues associated with theshortage of sufficient pipeline and storagecapacity to handle elevated levels of gas pro-duction, and hence to ship gas to futureLNG facilities, the study says. The availabil-ity of people and equipment for shale gasdrilling is also tight.
On the gas demand side of the situation,the study authors say that most internal U.S.gas demand will come from power genera-tion and industrial gas usage, with the U.S.demand for gas in transportation and in thecommercial and residential sectors likely tobe quite modest.
Taking into account the various U.S. sup-ply and demand factors, together with theassociated uncertainties, the increasedexport of gas as LNG from the United Statesdoes appear technically feasible, the studyhas found.
Global marketBut what about the global gas market
into which the LNG would need to be sold?In what the study refers to as the Pacific
basin, the region including the countries ofsoutheast and east Asia, growing gasdemand, limited local supplies and high,rigid gas prices linked to oil prices providethe United States with a near-to-mediumterm gas export opportunity, the study says.There are, however, uncertainties relating to
the possibility of indigenous shale gas devel-opment in, say, China or India. ExpandedLNG exports from Alaska and new LNGsupplies from Canada could also competewith LNG from the U.S. Gulf coast, thestudy says.
The study says that the transportationcost of LNG from Alaska to the Pacific Rimcould be higher or lower than from the Gulfof Mexico, depending on the scale of AlaskaLNG production.
In the Atlantic basin U.S. LNG would becompeting with piped gas, especially fromRussia, and with global LNG in a marketwhere European countries have been push-ing for gas prices lower than the traditionaloil-indexed levels.
U.S. pricesSeveral studies, including a study by the
Energy Information Agency, have investi-gated the potential impact of exporting LNGon domestic U.S. gas prices. All of thesestudies have concluded that the linkage ofthe U.S. gas market to the global LNG mar-ket would push up gas prices in the U.S., butthere is a very wide range in the estimates ofthe scale of the price impact. A comparisonof the assumptions behind these variousstudies suggests that, taking into account forexample constraints on the realistic scale ofLNG export facilities, the price impactwould be fairly modest, the study conclud-ed. And constraints on export volumesresulting from the relatively stable capacityof the export facilities would dampen anyprice volatility.
In addition to providing a valuable
export, thus lowering the U.S. trade deficit,the overseas sale of LNG would provide amarket for surplus “dry” natural gas, largevolumes of which are currently being flaredas companies push ahead with the produc-tion of valuable natural gas liquids from“wet” gas.
Dry gas consists of methane, while wetgas contains both methane and natural gasliquids such as ethane and propane.
In fact, the ability to readily sell dry gasmight actually boost wet gas production,thus providing increased volumes of low-cost feedstock for an increasingly competi-tive U.S. petrochemical industry, the studyreport says.
Energy securityFrom the perspective of U.S. energy
security, the volumes of LNG likely to beexported would not have any material effecton the availability of gas in the U.S. domes-tic market, while creating a market for gasproduced along with oil could improve theeconomics of U.S. shale oil development,the study report says.
Internationally, the introduction of com-petitively priced U.S. LNG into the globalgas market would likely put downwardspressure on global gas pricing. And the entryof the U.S. into the global market for gassupplies would strengthen U.S. foreign poli-cy interests and enable the United States toassist its strategic allies in meeting theirenergy needs, the study concluded. �
Contact Alan Bailey at [email protected]
By BILL WHITEResearcher/writer for the Office
of the Federal Coordinator
Fairbanks: the cost of getting warmFairbanks North Star Borough resi-
dents currently are out in the cold when itcomes to low-cost energy to heat theirhomes, stores and office buildings.
Mostly they burn fuel oil to generateheat, with the price chained to today’s highoil prices — the highest winter prices everfor Alaska NorthSlope oil.
Fuel oil costabout $27.67 permillion Btu of ener-gy (or $3.84 a gal-lon) during the just-ended winter, accord-ing to a preliminary study for the boroughreleased in February. (The price thisspring was over $4 a gallon, but for thisarticle we’ve stuck with the $3.84 used inthe new study.)
Fairbanks lies far off the natural gasgrid built for Anchorage and other com-munities near Alaska’s Cook Inlet fields tothe south. About 1,100 customers inFairbanks — mostly commercial accounts— burn natural gas that a distributor pur-chases from Cook Inlet producers, super-chills into liquefied natural gas for ease oftransport, then trucks 300 miles to town.Of roughly 25,000 homes in the borough,
fewer than 500 burn gas, thepreliminary study by NorthernEconomics found.
All that handling and thesmall economies of scale makedelivered natural gas pricey forFairbanks consumers — $23.35per million Btu, compared withabout $8.60 in Anchorage and asimilar price in the Lower 48.But $23.35 looks attractivecompared with heating oil prices —Fairbanks households would save an aver-age of $820 a year if they were burninggas at $23.35 rather than oil at $27.67, thestudy estimated.
If the delivered cost could be slashed to$14 per million Btu through mass conver-sions to gas heating, economies of scaleand other efficiencies, the average house-hold savings would approach $2,600 ayear, the study found.
Fairbanks-wide, the heating-cost sav-ings for all users, not just households,would total $114 million a year at today’soil and gas prices, or $238 million if thedelivered gas price were $14 and today’shigh oil prices lingered, the report said.
The North Pole Expansion Plant cur-rently runs on naphtha, but could be con-verted to natural gas.
The report also noted additional sav-ings in electricity bills if a Golden ValleyElectric Association turbine in North Polethat now burns a costly oil-based fuel
called naphtha switched to natu-ral gas. But it did not quantifythe potential savings to con-sumers.
A 2009 study for the AlaskaNatural Gas DevelopmentAuthority pegged the potentialannual savings to Golden Valleyin the low millions of dollars ayear if it switched from naphthato propane extracted from North
Slope natural gas. Last year, GoldenValley began investigating how much itmight save if it switched to LNG truckedfrom Prudhoe Bay; its rough estimate isthat its fuel savings would reach as muchas about $20 million a year at today’s oilprice of about $120 a barrel.
A billion-dollar build out?Piping natural gas to Fairbanks homes
and businesses would be an expensiveundertaking, according to estimates col-lected from a variety of studies andreports.
Someone would need to snake a net-work of gas pipelines through town toindividual furnaces.
In a sense, the network would resemblea road system. The big North Slope gasline through Alaska would be the freeway.Gas would exit that line into a multimil-lion-dollar lateral pipe that would channelgas to Fairbanks (think of this pipe as afour-lane highway, as opposed to an inter-state freeway). Once in Fairbanks the gaswould enter transmission lines that wouldroute gas to different parts of town (likemain streets routing traffic), then intofeeder pipes (neighborhood feederstreets), then distribution lines (neighbor-hood streets) and finally service lines tohouses and buildings (driveways).
No one has definitively nailed downthe cost of such a system. But rough esti-mates put the total cost at possibly $580million to $930 million for infrastructureto handle gas after it leaves an Alaska gaspipeline somewhere outside of Fairbanks.That price range is obtained by combiningestimates from two studies released in thepast 12 months. Consider the cost range tobe soft.
Here’s how that cost breaks down:
Delivering gas to FairbanksFrom a North Slope methane and gas-
liquids pipeline$210 million • Straddle plant
$60 million • Spur pipeline$309-$662M • Gas pipelines within town$25-$200 million? • Conversion of homesto use natural gas
Sources: Northern Economics; AlaskaGasline Development Corp.
$210 millionThis is an estimated cost of a straddle
plant alongside a big gas trunkline.The plant would solve two problems:• Gas in the big line would be under
high pressure, and that pressure must bereduced.
16 PETROLEUM NEWS • WEEK OF MAY 13, 2012
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� N A T U R A L G A S
Distributing North Slope gas challengingEnough gas exists to meet Alaska’s needs for decades, but at a cost; and getting gas to rural areas more difficult and costly yet
BILL WHJITE
see FAIRBANKS ENERGY page 17
• Gas in the big line would contain ablend of ethane, propane, butane and othernatural gas liquids besides the main com-ponent, methane, which is the gas burnedin furnaces.
Gas in the big pipeline would be com-pressed to a potent 2,500 pounds persquare inch, or psi, to propel the mole-cules through the pipe.
But methane when it passes a home’sgas meter is pressurized to as little as alazy quarter-pound psi, less than the pres-sure exerted when a child blows bubblesinto a glass of milk through a straw.
So a lot of decompressing needs tohappen along the way.
Much of the decompression wouldoccur at the straddle plant.
This plant also would extract propaneand other liquids so that just methanewould flow toward the Fairbanks users.The extracted liquids then would get rein-jected into the main pipeline flow, unlessan industry sprouted there that couldprocess and sell the liquids.
The Alaska Gasline DevelopmentCorp. in July 2011 estimated that a strad-dle plant would cost about $210 million.
The plant likely would be located welloutside of where most Fairbanks residentslive. Development is restricted in theFairbanks core because of poor air quality,especially during winter’s cold-weatherinversions as oil, coal and even wood areburned for fuel.
Cleaner air would be a welcome bonusof piping natural gas to Fairbanks. TheFebruary 2012 Northern Economics pre-liminary report says widespread use ofnatural gas rather than oil or coal wouldcleanse Fairbanks air now dirtied by par-ticulate matter — soot, smoke and such —as well as carbon monoxide, nitrogenoxide and sulfur dioxide.
$60 million This is a rough cost estimate for a 35-
mile pipeline connecting the straddle plantto town.
The estimate also comes from the July2011 Alaska Gasline Development Corp.report. The report said the gas would bepressurized at 1,400 psi within a 12-inch-diameter pipe.
$309 million to $662 millionThis is the estimated cost range for a
pipeline network within Fairbanks.The Northern Economics preliminary
study figured Fairbanks would need 111miles of 8- to 10-inch transmission pipe,118 miles of 6-inch feeder lines, 804 milesof 2-inch distribution lines and 325 milesof 5/8-inch to 1-inch service lines (thesmaller diameter for houses, the larger forbusinesses).
Fairbanks also would need nine pres-sure-regulating stations – stops along thepipeline network where the gas pressuregets reduced.
Separately, Fairbanks residents wouldneed to convert their homes and business-es to gas systems. This would be expen-sive, too.
$25 million to $200 million or more?This is a cost range for converting
Fairbanks home water heating and furnacesystems to natural gas. To be blunt aboutit: The wide range reflects imprecise costestimates.
For hot-water boilers, FairbanksNatural Gas, the local gas utility thattrucks in LNG from the Cook Inlet area,estimates converting an oil-fired gun to agas-fired gun costs $1,000 to $1,500.
The National Energy TechnologyLaboratory in 2006 pegged the cost in
Fairbanks at $1,400 for replacing theburner to $3,000 for replacing the entireunit.
Changing out furnaces could be morepricey. The 2012 preliminary NorthernEconomics study estimated the furnacereplacement cost at $8,000 to $15,000,depending on the extent of work needed.The authors said they will refine their costestimates in their final report later thisyear, and they’re still investigating the cost
of commercial-building conversions.
What price for Fairbanks gas?It’s unclear how much delivered gas
would cost Fairbanks consumers.The 2012 Northern Economics prelim-
inary study said, “It is too soon to developpreliminary distribution costs. ... As theproject evolves, the number of miles ofpipeline and prospective connections persegment will generate preliminary distri-
bution costs.”Among other variables, the cost would
depend on who paid for the infrastructure,how many customers signed up, wherethey live and how quickly gas became thefuel of choice in Fairbanks.
There’s some sentiment in Fairbanks toask the state for money to build a local gaspipeline network. Separately, the AlaskaLegislature has considered a measure tocreate a state loan fund to help Fairbankshomeowners convert their heating systemsto natural gas. �
Please see part 1 of this story in theMay 6 issue and part 3 in the May 20issue.
Editor’s note: This is a reprint from theOffice of the Federal Coordinator, AlaskaNatural Gas Transportation Projects,online at www.arcticgas.gov/challenges-distributing-north-slope-gas-alaskans.
PETROLEUM NEWS • WEEK OF MAY 13, 2012 17
Lynden Family of Companies McKinnon & Associates, LLCNANA Development CorporationNorthern Economics, Inc.Oasis Environmental, Inc. Pacific Star Energy Shell Exploration & Production CompanyStaser Consulting Group, LLC Stoel Rives, LLP Trident Seafoods CorporationUdelhoven Oilfield System Services, Inc. XTO Energy, Inc.
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FAIRBANKS ENERGYIf the delivered cost could be
slashed to $14 per million Btuthrough mass conversions to gasheating, economies of scale andother efficiencies, the average
household savings would approach$2,600 a year, the study found.
ALA
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18 PETROLEUM NEWS • WEEK OF MAY 13, 2012
� L A N D & L E A S I N G
Great Bear dividesNorth Slope holdingsEni hands over Mustang prospect leases to Alaska VentureCapital Group, numerous small deals approved in March, April
By ERIC LIDJIFor Petroleum News
Great Bear Petroleum LLC formed anumber of affiliates earlier this year to
manage its massive North Slope land hold-ings, according to recent state leasingreports.
The Alaska independent transferredcomplete working interest and sizable royal-ty interests — between 83 and 87 percent —in its North Slope acreage to two compa-nies: Great Bear Petroleum Ventures I, LLCand Great Bear Petroleum Ventures II, LLC.
Great Bear Petroleum Ventures I nowholds 126,186 onshore acres and Great BearPetroleum Ventures II now holds 372,856onshore acres, according to state leaserecords.
Great Bear Petroleum formed four affili-ates on March 12. The first, a holding com-pany called Great Bear Petroleum OperatingLLC, is the owner of the other three: GreatBear Petroleum Ventures I, Great BearPetroleum Ventures II and Great BearPetroleum Ventures III. Currently, GreatBear Petroleum Ventures III holds noacreage.
Alaska statues limit the amount ofacreage a single entity can hold in the state.
Eni Petroleum US LLC transferred itsremaining 20 percent working interest and16 percent royalty interest in six NorthSlope leases in and around the SouthernMiluveach unit to Alaska Venture CapitalGroup LLC. The Italian major originallyretained the interest when it farmed-out theNorth Tarn prospect to the company inJanuary 2010.
Through its operating arm Brooks RangePetroleum Corp., AVCG and its partnersrecently announced a 40 million barrel dis-covery at the prospect, now called Mustang.
Southern Miluveach sits on the south-western boundary of the Kuparuk Riverunit.
Union Energy (Alaska) LLC transferred100 percent working interest and 81.25 per-cent royalty interest in two foothills leases— ADL 391326 and ADL 391327 — toAuxillium Alaska Inc. A man named FrankJ. Hariton incorporated Auxillium in August2011.
BP Exploration (Alaska) Inc. transferreda minor royalty interest in three leases at the
Milne Point unit — ADL 047433, ADL047437 and ADL 047438 — to Black StoneAcquisitions Partners I, LP, an arm of theglobal investment firm. BP also allowedthree Beaufort Sea leases to expire — ADL391469, ADL 390836 and ADL 390828.
Five corporate and independent investorstransferred varying interests in fourOooguruk unit leases — ADL 355036, ADL355037, ADL 355038 and ADL 355039 —to operator Pioneer Natural ResourcesAlaska, Inc. The entities include AnadarkoPetroleum Corp., Oxy USA Inc., XH LLC,Herbaly Exploration LLC and George AlanJoyce Jr.
Bill Armstrong, president of ArmstrongOil & Gas, transferred a small royalty inter-est — all less than 0.1 percent — in numer-ous North Slope leases to Jeffery A. Lyslo.
The state also finalized leasing activityrelated to the Point Thomson unit settle-ment.
In Cook Inlet, the Victor Wynden LPtransferred a small royalty interest in threeleases at the Redoubt unit to independentinvestor Victor Rogers. The interests were allless than 0.03 percent. The leases were ADL381003, ADL 381201 and ADL 381203.
The Alaska Division of Oil and Gasdenied the transfer of small to moderate roy-alty interests in seven leases contiguous tothe Kitchen Lights unit to Escopeta Oil Co.LLC.
The four entities requesting to transferinterests were A. Lawrence Berry (0.984375percent), Danny S. Davis (0.859375 per-cent), Taylor Minerals LLC (0.65625 per-cent) and Escopeta Oil of Alaska LLC (10percent). The leases were ADL 391598,ADL 391599, ADL 391603, ADL 391604,ADL 391605, ADL 391606 and ADL391607.
Cornucopia Oil & Gas LLC transferred a1 percent working interest and 0.75 percentroyalty interest in 30 leases at KitchenLights to operator Furie Operating AlaskaLLC.
Annette Troseth transferred a small roy-alty interest in five leases in an around theNicolai Creek unit to Gregory Scott Pfoff,president of unit operator AuroraExploration. �
Contact Eric Lidji at [email protected]
EXPLORATION & PRODUCTIONRed Wolf exploration well comes up dry
The Red Wolf No. 2 exploration well in the eastern North Slope’s Badami unitwas “a dry hole,” operator Savant Alaska’s president told Petroleum News May8.
“The well was a dry hole. … our target zone was wet (contained water),” GregVigil said.
Red Wolf No. 2 targeted the Kekiktuk formation, which contains the oil reser-voir for the Endicott field, west of Badami. The Kekiktuk is a deeper formationthan the Brookian, where previous Badami development occurred.
Savant drilled the B1-38 well into the Red Wolf prospect in early 2010 andfound oil in two horizons: the Kekiktuk and the shallower late Cretaceous Killiansands. Although Red Wolf is still an exploration prospect, it is currently produc-ing from the Killian.
Red Wolf No. 2 was about two miles northwest of the bottom hole for B1-38.Savant is on an ongoing mission to improve production rates at Badami, which
has been shut down and restarted numerous times since startup in 1998. Alaska Oil and Gas Conservation Commission figures for March show 1,197
barrels of oil per day from Badami, an increase of 8 percent from February.In addition to drilling Red Wolf No. 2, this past winter Savant did workovers
in the B1-16 and B1-21 wells, installing gas lift to be able to produce the wellsto the Badami plant.
The company has already started planning next winter’s drilling program,Vigil said.
—KAY CASHMAN
PETROLEUM NEWS • WEEK OF MAY 13, 2012 19
be today. Because quite frankly we areworking very, very hard across the boardwith some very smart people internallyand close to us consultants to say, ‘lookwe can move this cost significantly bydoing things this way,’ and ‘maybe doingthings this way will require the state tohelp us’ … ‘maybe in a regulatory way tobecome more efficient’ — again, that’snot Great Bear exclusively but the indus-try as a whole.”
A more conservative DuncanAlthough clearly pleased at the
thought of spudding his first well in lateMay or early June, nonetheless in hisApril 25 presentation of Great Bear’splans and expectations Duncan talked interms of the company’s play being“drilled out at a very high rate for at leastthe next 10 or 15 years, maybe longer”with 200 wells per year for a total of3,000 wells,” as compared to previouspresentations where three consecutivedrill-outs totaling 9,000 wells were pro-posed.
Also, in his recent presentationDuncan went into more detail about thegeologic risk of the North Slope’s threemajor source rocks, the HRZ/GRZ,Kingak and Shublik than he has in thepast.
While emphasizing the three sourcerocks were very well known, “there is amodeled outcome based on the domi-nance of oil, natural gas liquids, gas-phased production that has a huge impacton the commercial outcome. If the rocksare too ductile, if they’re too plastic, tooplay-rich, too gooey to frac well, thatcould cause a significant challenge thatcould be terminal to certain portions ofthe play early on.”
But, he said, the problem was “not nec-essarily long-term,” his inherent optimismback in place.
“Technology is evolving very, veryrapidly. I am a great believer that if we putthe challenge out to the Halliburtons, theSchlumbergers, the Baker Hughes, theWeatherfords and the others of the world,that it’ll get cracked — the code will getcracked. Whether today, next year, or sub-sequent, I am a great believer in that,”Duncan said, noting that geologic riskwould be addressed “very early on” inGreat Bear’s work program.
Duncan: State could help with sandChallenges to source rock exploitation
have been compiled by the state Divisionof Oil and Gas’ shale task force, Duncansaid, having composed a list of them withhis response to each in blue in the Slide 6he used in his April Senate ResourcesCommittee presentation (see adjacentgraphic titled North Alaska ShaleResource Play Realization: Challengesand Business DevelopmentOpportunities).
The items that “appear to be hot but-tons in the discussion,” Duncan said, areas follows:
• Access to gravel for infrastructuresupport.
• Water for supporting the work forcein the context of drinking water, but alsofrac water used in the stimulations.
• Developing an in-state supply ofproppant for hydraulic fracturing opera-tions.
Proppant, Duncan said, is “sand, silicarich sand.” Something, “in a state this sizewith the big rivers and mountain belts andthings of that nature, the mining opera-tions that have gone on in this state foryears, my expectation is that, with time,we’ll sort out an in-state supply of prop-
pant, or silica rich sand. It’s something weare working on right now, but the statecertainly could facilitate that, too.
Mother Nature’s gift of waterSen. Bill Wielechowski asked Duncan
to “talk a little bit about fracking, whereyou intend to get the water, whether youforesee problems with the fracking herein Alaska impacting the aquifers or caus-ing other environmental problems.”
Wielechowski also asked whetherGreat Bear was looking at using propaneinstead of water in fracking operations.
“Water’s a big one,” Duncan replied.“There’s little doubt that the public outcryin certain regions of the U.S., the need forbetter oversight of the industry in all ofthese operations, (has been) clearlyplayed out in newspapers over the lastcouple of years. For Alaska, we have anumber of gifts that are provided us byMother Nature on the North Slope.”
“There is, to my knowledge, virtuallyno fresh water aquifers that are not frozenas permafrost on the North Slope ofAlaska,” he said. “The water sources thatwe see as potentially available to usregionally lie subsurface between the baseof the permafrost and depth of about5,000 feet. There are very thick, regional-ly extensive, sandstone aquifers that con-tain, predominantly, brackish waters —saline water that has a salinity that is notacceptable for human consumption (and)agricultural use, if that was ever an issueon the Slope, but serendipitously, chemi-cally very suitable for fracking.
“There’s very active research on, in thedirection of making or providing, seawa-ter as an allowable component for fracmake-up. Obviously if that bit of researchis successful then there isn’t a shortage ofwater that would be suitable for frackingoperations.
“The operation of fracture stimulatinga well and flowing it back and testing itfor commercial production involves cap-ture of the flowback water. The water thatyou pumped into the subsurface, as wellany water that comes back out of it as partof post-frac operations; that water is cap-tured and cleaned,” Duncan said.
“We expect, as I think most of theindustry now, that recycling operationsand technologies of captured water forflowback operations will become veryprevalent. I know that our current venturepartner Halliburton (is) very activelyinvolved in that kind of research of usingfiltering, actually reverse osmosis filter-ing, in part of flowback water before it’sreinjected and then the captured chemi-cals that are oftentimes naturally occur-ring, that flow back with the flowbackwater are disposed of appropriately.”
“So for our operations in North Alaskawe don’t see shallow aquifers as being asignificant challenge. We believe thatwater supply regionally through the sub-surface aquifers is something that ulti-mately will be extremely valuable to theplayers that are exploiting this play,” hesaid.
But access to gravel is another issue,Duncan said.
“We see challenges with access togravel, perhaps being one that we’regoing to need help with. There’s plenty ofgravel around but we have to access grav-el in an appropriate and reasonable way.So that’s certainly something we need towork on.”
“As far as propane fracking is con-cerned, that’s not part of our plan at thispoint,” he said.
Level of activityWielechowski also asked the amount of
activity that could be generated by GreatBear’s development program; specificallythe number of wells that would be drilled.
Referring to an article he’d recentlyread, Wielechowski said, “a shale wellmay initially produce oil at a high rate,perhaps a 1,000 barrels a day, (but) pro-duction tends to decline rapidly … stabi-lizing at a long-term rate of maybe 100 to200 barrels a day. It goes on to say that inthe Bakken play of North Dakota, forexample, total production from the play(at the time) was running at about 488,000barrels a day from 6,000 wells, indicatingan average daily well production of just 80
barrels. Could you comment on what thatwould mean — the number of wells youwould need to drill to fully commercializethe shale development that you’re lookingat?”
Duncan said, “It’s our expectation that awell spacing in North Alaska will ulti-mately be somewhere around 160 acresper well” with 200 new wells and eightpads per year. … If we’re trying to devel-op the Shublik, the Kingak and the HRZall at the same time it portends a signifi-cant number of wells.”
Great Bear’s focus, he said, “in additionto getting an effective test of the play, isalso to focus on reducing surface footprintand have more things going on under theground with pipe than above the groundwith wellheads and things of that nature.So 200 wells a year, which is less than thenumber drilled per month in the EagleFord will support an operation here thatgoes well past my career and probablymost of the folks in this room, in fact,”Duncan said. �
continued from page 12
GREAT BEAR
Contact Kay Cashman at [email protected]
®Providing integrated environmental and engineering solutions for the oil and gas industry
Petroleum News and compiled byAEDC.
This highly anticipated event drewmore a hundred business professionalsagain this year.
AEDC also released its 2011
Annual Report focusing on its accom-plishments and projects from 2011.
Both reports and AEDCConnections 2nd Edition DigitalNewsletter, Live. Work. Play., wentpaperless — i.e. digital — this year.
They can all be found at AEDC’swebsite at www.aedcweb.com/
—PETROLEUM NEWS
continued from page 14
AEDC FORECAST
20 PETROLEUM NEWS • WEEK OF MAY 13, 2012
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Oil Patch Bits
All of the companies listed above advertise on a regular basis with Petroleum News
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ASCE invites participants to the 2012 symposium The ASCE said April 25 that it is requesting a call for papers for the upcoming 10th
International Symposium on Cold Regions Development in Anchorage, Alaska, June 2-5,2013.
The Technical Council on Cold Regions Engineering of the American Society of CivilEngineers and the Alaska Section of ASCE will sponsor the ASCE 10th InternationalSymposium on Cold Regions Development in Anchorage at the Dena’ina Civic andConvention Center.
The symposium theme is “Planning for Sustainable Cold Regions.” You are invited tosubmit paper abstracts and session proposals online athttp://content.asce.org/conferences/coldregions2013/index.html. Authors are expected toorally present their papers in a technical session or poster session. Deadline for abstractsand or papers is June 20, 2012. Papers and poster presentations are encouraged on allaspects of cold regions engineering and development, including: frozen ground and per-mafrost; building design; construction techniques; oil and gas; structure and foundationfailures; water and wastewater systems, and much more. For information, please contactSteering Committee Co-Chairs Thomas G. Krzewinski at [email protected], or Jon E.Zufelt at [email protected].
Harvey Gulf and Shell Vessel winner tours New OrleansShell said April 18 that Rita Ramoth, winner of the Harvey
Gulf International Marine and Shell Vessel naming competi-tion, was accompanied by her Aunt Janet Mitchell and ShellCommunications Specialist Michelle Malerich for a three daytrip to New Orleans including a tour of the city and of thevessel “Sisuaq” on April 9.
Shell and Harvey Gulf International Marine held a vesselnaming competition throughout the Northwest ArcticBorough in December of 2011. Ramoth won with her submis-sion of “Sisuaq,” the Inupiat word for beluga. Along with a$5,000 dollar grant to the Inupiat language and culture pro-gram and a $500 dollar gift card to the local store, Ramothwas also given an all expenses paid trip to New Orleans.
During Ramoth’s visit, she and her aunt experienced theFrench Quarter, the Audubon Zoo and Aquarium, the French Market, participated in aSwamp Tour, witnessed the beauty of the Mississippi River and sampled plenty of local
see OIL PATCH BITS page 21
CO
URT
ESY
SH
ELL
Sen. Paskvan appeared not to trust theLegislature’s own consultants, when PFCEnergy’s work actually agreed with ouradministration’s position.
There’s no sense in us putting forwardour experts when the Legislature alreadyhad its experts testifying the way theywere.
Petroleum News: If Gaffney Cline hadtestified to the Legislature, what wouldthey have told lawmakers?
Parnell: I don’t know. I’m not going tomake assumptions or speculate because Idon’t know what the questions would be. Ican just tell you that we set forth a propos-al that was in Alaska’s interest to developexisting fields and new fields.
Petroleum News: Did Gaffney Clinehelp draft the legislation?
Parnell: I worked directly with the com-missioner and deputy commissioner on it.I do not know exactly what occurred with-in the Department of Revenue. Literally,they had two years of working together. SoI don’t know exactly when and wherethose communications happened.
Petroleum News: How do you respondto charges from people like SenatePresident Gary Stevens that your adminis-tration couldn’t adequately defend the pro-posal?
Parnell: I think that notion was simplynonsense. What the senator is failing to tellyou is they could not get 11 votes withinthe Senate for a comprehensive change tobring about an increase in oil production.
We had hundreds if not thousands ofpeople who testified, sent messages, andwhose livelihood in our state dependsupon more work in the oil patch. To saythat we can maintain ourselves and thateverything is fine while we’re experiencingthis production decline really is a slap inthe face to Alaskans who want to work,who want to grow this economy, and whodepend upon oil and gas.
And it’s not just oilfield workers — it’srestaurant owners, office supply storeworkers, realtors, auto dealers and theiremployees. We are all dependent upon thisindustry.
I will continue to do everything I can toassure that we grow production and growAlaskan opportunity rather than sayingthat status quo decline is fine.
Petroleum News: Sen. Bert Stedman,one of the Finance Committee co-chairs,claimed there was widespread agreementthe tax doesn’t work at very high oilprices. Did you consider just focusing onthat?
Parnell: We did, and therein lies the rub.
Because we could only get to 10 votes inthe Senate. It was split down party lines.Ten Republicans were willing to engage inthat discussion and vote for change. TenDemocrats were not. That’s the raw truthof what happened there.
Petroleum News: Well, I’m guessing thisissue won’t go away.
Parnell: Not as long as productiondecline continues.
Petroleum News: What’s your nextstep?
Parnell: I’m going to continue workingto convince a few more senators that pro-duction decline is not fine, that we canpull new oil from existing fields with taxchanges, and work these issues again in2013.
Petroleum News: Will you try a differentproposal or just hope that a newLegislature sees things differently?
Parnell: It’s too early to tell now. I’ll bemaking those decisions in November,December. That’s when I put in my legisla-tive package of bills.
Petroleum News: Does the difficultysettling on an oil tax affect the gas line
project in any way?Parnell: It very well could. The
Legislature is not structured to take upboth oil tax terms and gas tax terms relat-ed to a pipeline in the same session. Thoseare two weighty issues that require a lot oftime and effort, and we’re likely going tohave to choose one or the other to take upin 2013.
Petroleum News: About Point Thomson,former Oil and Gas Division directorMark Myers criticized your administrationfor giving up too much control in the set-tlement with Exxon Mobil. How do yourespond to his critique?
Parnell: The attorney general, the com-missioner of natural resources, and I allfirmly believe that the state resolved thePoint Thomson litigation in the state’sinterest, for a number of reasons.
First, it maximizes development ofAlaska’s resources for Alaskans. Weobtained solid work commitments requir-ing billions of dollars of spend by thesecompanies. If they don’t meet those workcommitments, the companies lose acreageat the unit.
Second, the settlement will provide jobsfor Alaskans now and into the future.Third, it brings us closer to a major gas
line. And fourth, it resolves a case that hasalready been going on for seven years andby all estimations could have gone another10-15 years.
Everything in this settlement was meas-ured and weighed with Alaskans’ interestsin mind. Frankly, this settlement is pointedat getting Alaskans a major gas line.
Petroleum News: Does the languagespecifically require Exxon to complete itsgas cycling project?
Parnell: I’m going to point you to ourdepartment personnel on that.
Mark Myers was arguing to delay anymajor gas sale in favor of what’s calledfull-field cycling. The information he wasrelying on, from a 2008 PetroTel study, hassince been updated, both by PetroTel andby DNR, with a more realistic view ofPoint Thomson’s reservoir performance.Full-field cycling, as he’s urged, is simplynot a viable option.
The choice in the settlement was reallybetween the initial production system andcontinued litigation, as well as balancingour interest as a state in getting to a majorgas sale. �
PETROLEUM NEWS • WEEK OF MAY 13, 2012 21
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Alaska Petroleum Section
Cajun cuisine, including beignets from theinfamous Café Du Monde. They also met anddined with several Harvey Gulf and Shellemployees.
The trip concluded with an escorted tourof the Harvey Gulf’s New Orleans office andof the “Sisuaq” by Harvey Gulf PresidentRobert L. Guinn III, where Ramoth signed hername on one of the vessel doors, and boxseats to an NBA game, courtesy of HarveyGulf.
Editor’s note: All of these news items —some in expanded form — will appear inthe next Arctic Oil & Gas Directory, a fullcolor magazine that serves as a marketingtool for Petroleum News’ contracted adver-tisers. The next edition will be released inSeptember.
continued from page 20
OIL PATCH BITS
continued from page 3
PARNELL Q&A
Contact Stefan Milkowski at [email protected]
produces from the Nuiqsut and Kuparukformations at Oooguruk, essentially everywell in the unit passes through the Torok.
Three laterals in testIn a recent pilot project to test the
potential of the Torok, Pioneer drilledthree lateral wells from its existing gravelisland at Oooguruk and the directionalNuna No. 1 well starting on ADL 25528,some 2.5 miles northwest of KuparukRiver unit drill site 3S.
The Torok formation would underpinthe Nuna development that Pioneer pro-posed for the region last year and recent-ly revised in an updated plan of opera-tions for its leases.
As outlined, Pioneer would drillbetween 35 and 65 horizontal wells fromtwo onshore pads, primarily targeting theTorok but also possibly the Kuparuk,Nuiqsut and Ivishak.
Under the terms of its recent expansionof the Oooguruk unit to include its Nunaarea leases, Pioneer must decide by June30, 2014 whether or not it will sanctionthe project.
When the state approved the Torokparticipating area at Oooguruk last sum-mer, Pioneer estimated area contained690 million barrels of original oil in placeand said it could recover as much as 25percent using primary and enhancedrecovery techniques.
Sikumi non-commercialWhile Nuna No. 1 appears to be a suc-
cess, Pioneer wasn’t as fortunate on itsother exploration well this winter, the off-shore Sikumi No. 1 two miles southwestof Oooguruk.
A “deep test” of the Ivishak formationwas wet and although the well encoun-tered some gas another zone, it was “basi-cally non-commercial,” Dove said.Pioneer plugged and abandoned SikumiNo. 1 and wrote down a $19 million lossfor the unsuccessful well.
The exploration wells cost Pioneerslightly more than $50 million, combined.Pioneer budgeted $135 million of its $2.4billion drilling program this year to activ-ities in Alaska.
Pioneer holds a 100 percent workinginterest in the Nuna No. 1 well and a 70percent in the Nuiqsut development wellwith the remaining 30 percent held by EniPetroleum.
While the company used two rigs toconduct its exploration and developmentcampaigns this winter, activity continuesthrough the summer with one rig on theOooguruk gravel island in Harrison Baycurrently drilling into the Kuparuk,Nuiqsut and Torok formations.
Nuiqsut test successfulPioneer is also reporting success from
its development efforts.Using a “plug and perf ” completion
technique borrowed from its Eagle FordShale operations, a development wellPioneer drilled into the Nuiqsut formationproduced at an initial rate of 4,000 barrelsper day, making it “by far our bestNuiqsut well,” Dove said, adding that theresults suggested the technique could beused on other Nuiqsut wells.
The “plug and perf ” method, alsoknown as a “mechanical diversion” frac-turing system, is thought to be moreeffective because it can stimulate a largerportion of a reservoir.
If the well continues to produce nearits initial levels, it could have a substantialimpact on production rates at Ooogurukand could make Alaska more attractive toPioneer.
Pioneer produced 4,000 barrels per
day from Alaska in the first quarter, flatfrom the fourth quarter of 2011 and downfrom 5,000 barrels per day in the firstquarter of 2011.
Companywide, Pioneer produced147,000 barrels per day in the first threemonths of the year, a 37 percent increaseyear over year attributable largely to thegrowth of three unconventional plays inTexas: the Spraberry, Eagle Ford and theBarnett Shale Combo.
Staying put in Alaska?Analysts have wondered whether
Alaska is a divestment candidate for thecompany as it continues to grow itsunconventional oil production in Texasand the midcontinent.
When asked last August about thefuture of its Alaska and South Africaassets, CEO Scott Sheffield said “it’salways an option in regard to whether ornot to look at divesting those two assets,”but said he saw South Africa as “runningout” and Alaska as “growing significantlyover the next several years.” Pioneerrecently sold its South Africa assets to thenational oil company Petroleum Oil andGas Corporation of South Africa(PetroSA).
When asked again recently about thefuture of Alaska, Sheffield said the deci-sion would be made “down the road” butnoted that Oooguruk production has beenflat or declining for a year. “If the team upthere can show us they have huge poten-tial to grow production and frac severalmore Nuiqsut wells and look at someTorok, then we’ll look at keeping andkeep growing it,” he said. “And so that’sthe key: Do we have enough upside ongrowth to able to reinvest the cash flowand grow the asset. And we love growingassets.” �
22 PETROLEUM NEWS • WEEK OF MAY 13, 2012
NordAq’s president, Bob Warthen, toldPetroleum News May 10. The plan is todrill first at Tiger Eye Central, probablylater in this summer once all the permitsare in place, Warthen said.
NordAq Energy Inc. has submitted anoil spill prevention and response plan forboth wells to the Alaska Department ofEnvironmental Conservation. Accordingto this plan the drilling will be conductedfrom two separate gravel drilling pads,with each pad connected by a temporarygravel road less than three miles long toan existing lease road along the coast —the prospect area, situated in two stateleases, is close to the existing TradingBay and West McArthur River oil and gasfacilities on the Cook Inlet coast.
Directional drillingDirectional drilling will be required at
each location, with the North pad wellinvolving extended reach drilling andrequiring a drilling rig that is suitable forthat type of drilling operation. Warthensaid that NordAq is still working outwhich rig or rigs to use.
Both wells will be drilled to a depth ofabout 12,000 feet, targeting “oil-bearingzones within the Tyonek and Hemlockformations,” NordAq’s spill responseplan says. The drilling of each well willtake about 45 days, with well testing tak-ing another 10 to 30 days, the plan says.
The plan of operations for Tiger EyeNorth said that the company is seekingboth oil and natural gas.
According to a spacing exception
continued from page 1
NORDAQ WELLS
continued from page 1
NUNA DISCOVERY
Contact Eric Lidji at [email protected]
see NORDAQ WELLS page 23
have to get the service industry movingwith us.”
The problem is that the service indus-try needs to know its crews will be work-ing day in and day out on “continuousdrilling programs,” which will allow boththe service industry and Hilcorp to bemore efficient.
Urgency is one of Hilcorp’s core val-ues, Barnes said, noting he’d recently toldhis managers that if their plates were fullnow, they’d better get platters, becausethings would get busier.
The same would apply to the serviceindustry, he said.
Increasing production the goalHouston-based Hilcorp Energy Co. is
the “third largest privately held oil andgas producer in the United States,” givingit the financial strength to do the workthat needs doing on the Chevron CookInlet assets it acquired last year and on theMarathon Cook Inlet assets it is in theprocess of acquiring, Barnes said.
The focus is not on new drilling: In allits operations Hilcorp drilled 60 newwells last year; but it did 1,500 workovers.
“That’s the hard work to get productiongoing,” he said.
He told RCA commissioners clearlyconcerned about declining Cook Inlet nat-ural gas production that Hilcorp’s produc-tion in the Lower 48 has gone up yearafter year.
“And it goes up because of hard workand capital being spent in existing legacyassets. That’s one opportunity that existsin the inlet; that’s one that we are choos-ing to pursue primarily.
“I can’t probably overemphasize theamount of work that’s actually required totry to take the risk and spend money andtry to improve recovery from thesefields,” Barnes told the commissioners.
Offshore drillingHilcorp has a “derricks’ down” project
under way, with derricks being taken offthree platforms in the Trading Bay unitand from the Granite Point platform.
Those derricks were old technology, hetold the Alliance audience.
“One way or another we’re going to geta modern drilling rig here,” whetherHilcorp builds it or someone else buildsit. It’s similar to the model Marathon used,
he said, where you get a rig with moderntechnology and just knock out wells;Hilcorp will do the same thing with aworkover unit, he said.
The company will also be drillingonshore.
Barnes told the Alliance it’s embar-rassing, but the company is excited aboutjust running a workover rig in theSwanson River field. “That’s how low thebar is,” he said.
Drift RiverBarnes said Hilcorp has a C-plan, an
oil discharge prevention and contingencyplan renewal, out for public commentwhich references work at the Drift RiverTerminal. The company plans to raise theberms protecting the tanks this summerand install some new ones, with a goal ofstoring oil at Drift River again.
Storage of oil stopped at Drift Riverdue to activity at the Mount Redoubt vol-cano, but the berms around the tanks didwhat they were supposed to do and pro-tected the tanks, Barnes said.
Hilcorp is working closely with theDepartment of EnvironmentalConservation on the C-plan, he said.
“It’s very important to try to get thatterminal open again so that you’reallowed to manage your tanker trafficmore effectively in the inlet,” Barnes said.Right now oil has to be stored at produc-tion facilities where there is a finiteamount of storage “and it can result intankers being curtailed, production shut-in, when you run out of storage.”
It’s not the way Hilcorp wants to man-age oil storage, he said.
In response to a question about analternative for storage at Drift River,Barnes told the Alliance audience thatthere has been discussion about a subseapipeline, but sizing it would be a problem.
Because Hilcorp intends to grow pro-duction, “I don’t know how to size it yet,”Barnes said.
It’s the Goldilocks’ problem, he said:You don’t want it too small and you don’t
want it too large. A subsea pipeline may be a considera-
tion for the future, but Barnes saidHilcorp needs to “establish a track recordof getting production up” so that it couldbetter determine a pipe size for such aproject.
Gas production downBarnes showed the commission recent
Cook Inlet natural gas production figures.From 2008 to 2011 production declinedfrom more than 400 million cubic feet perday to just over 300 million last year, hesaid.
“That represents about a 23 percentdecline and I think we’re all aware thatmost majors have significantly slowedtheir spend in the Cook Inlet and that isnot surprising because of this decline.”
But others are coming into the inlet, hesaid, calling it “an opportunity for compa-nies to come in and try to perform andmake a business.”
Different companies play to differentstrengths, Barnes said, mentioningApache’s large lease position and exten-sive exploration program.
“Hilcorp’s strength is we acquire oldassets,” he said.
About half shut-inThe Marathon assets Hilcorp is acquir-
ing include 157 wells, 75 producing and74 shut-in.
“Hilcorp looks at those shut-in wells asassets,” Barnes said. “We’re very much
about trying to stare into every well, everywellbore and look at every sand and max-imize production from the assets thatwe’re acquiring.”
Marathon is exiting the Cook Inletbasin, and that was important for Hilcorpin the acquisition, Barnes said, because,“It’s a chance for us to consolidate inter-ests in legacy fields, which we believepresent tremendous opportunities foradditional work and additional develop-ment.”
Barnes noted that McArthur River andNinilchik represent about 50 percent ofMarathon’s production, and those are bothfields in which Hilcorp already has aninterest. Consolidation of ownership infields which are late in life allows forcommercial alignment which may notexist with multiple owners, he said.
Barnes said Hilcorp’s long-range planis “pretty simple: It’s all hard work.”
“You want to invest significantamounts of capital to exploit the assetsthat we will be acquiring and in in-filldrilling, recompletions and workoversand compression.”
As for what Hilcorp will be doing inCook Inlet, Barnes said, “We are not acompany that will be performing lots ofbig projects: We make our living throughlots of small projects and ... workingevery wellbore, every sand and seeingwhat’s there.” �
PETROLEUM NEWS • WEEK OF MAY 13, 2012 23
request submitted to the Alaska Oil andGas Conservation Commission, thesurface location of the Tiger EyeCentral well will be 690 feet from thewest line and 550 feet from the northline of section 19 of township 8 north,range 14 west, Seward Meridian. Thebottom hole location will be 839 feetfrom the west line and 1433 feet fromnorth line of section 24 of township 8north, range 14 west, Seward Meridian.The well location is in State of Alaskalease ADL 391104.
Response servicesNordAq is contracting with
O’Brien’s Response Management and
Alaska Chadux Corp. for oil spillresponse services. The company saysthat in the unlikely event of a loss ofwell control it will call in Boots &Coots Well Control International forassistance. Oil spill prevention meas-ures include careful well planning anddesign, as well as the use of blowoutpreventers on the wells. NordAq alsosays that it has access to well cappingtechnology and could drill a relief well,should these response techniques provenecessary.
NordAq’s oil spill response plan isavailable for public review and com-ment until June 1.
—ALAN BAILEY
continued from page 22
NORDAQ WELLS
Contact Alan Bailey at [email protected]
continued from page 1
HILCORP“We are not a company that willbe performing lots of big projects:We make our living through lots of
small projects and ... workingevery wellbore, every sand and
seeing what’s there.” —John Barnes, Hilcorp senior vice president
for Alaska
Contact Kristen Nelson at [email protected]
“For it to be developed more aggres-sively, it will need something like LNG ora big change in gas prices,” he said.
An Imperial spokesman said it is tooearly to put a nameplate capacity, cost,location or timing for a project by hiscompany, but indicated that Imperialmight be open to linking up with otherdevelopers.
Oil-linked contract keyThe numbers game in the LNG equa-
tion was also underscored by StevenFarris, chairman and chief executive offi-cer of Apache, which is operator of theKitimat LNG project, currently the largerof two schemes to obtain CanadianNational Energy Board export permits.
But Farris told a conference call thatobtaining an oil-linked contract will becritical to making the Kitimat projectwork for partners Apache, Encana andEOG Resources, who have backed awayfrom previous indications that a corporatesanctioning decision would be made earlythis year.
Farris said the front-end engineeringand design work is “pretty much done”and the partners are now in the “throes ofnegotiations for a tenant to underpin thatdevelopment. But we’re not there untilwe’re there.”
He also said efforts to clear a right ofway for a pipeline and make progress
toward constructing an LNG terminal arealso needed before a final go-ahead canbe given.
Farris said the most important missingpiece is to have a memorandum of under-standing “that is good enough on the salesside to take the project forward on an eco-nomic basis.”
March noted that LNG developmentsbased on shale gas feedstock “face highertechnical and capital cost challenges thanthose being built in Qatar and Australia,which draw on big long-life conventionalgas reserves.”
“In the Horn River, we are committedto sustained drilling activities that practi-cally will never stop for the life of thedevelopment,” he said.
Mike Dawson, president of theCanadian Society of UnconventionalResources, suggested that even if it costs$10 to liquefy and ship one thousandcubic feet of gas, producers are bankingon landed prices of $17-$18 per millionBritish thermal units.
—GARY PARK
24 PETROLEUM NEWS • WEEK OF MAY 13, 2012
NWT sees LNG as optionThe Northwest Territories government is open to supporting an LNG export proj-
ect to develop Canada’s stranded Arctic gas resources, said NWT Industry MinisterDavid Ramsay.
He said that although his government prefers to build a pipeline down theMackenzie River Valley to southern markets, LNG is not off the table.
That notion got support from the Aboriginal Pipeline Group, which could ownone-third of a Mackenzie pipeline if it is able to secure matching gas supplies fromoutside the main gas owners group, led by Imperial Oil.
APG President Bob Reid told Reuters said his group is “absolutely” open to aroute change for the pipeline to participate in an LNG project.
“We’re not constrained by routing at all,” he said. “But, at the moment, there’s nota plan to … go from the Mackenzie Delta westward (to the North American coast).”
Reid said that could see Mackenzie gas moved to the Alaska coast.“There is an obvious connection there, but it does have some challenges,” he said,
referring to any proposal that would require gas to be shipped across the ArcticNational Wildlife Refuge.
Imperial Chief Executive Officer Bruce March was hesitant about usingMackenzie gas for world-scale LNG development.
“It is too early for us to comment on that today because we’re still in the earlystages of looking,” he said.
Ramsay said that although the NWT supports the stalled Mackenzie Gas Projectover all other options “we’re willing to discuss any opportunities or options withanybody who’s interested in developing our resources.”
—GARY PARK
continued from page 1
HORN RIVER“In the Horn River, we are
committed to sustained drillingactivities that practically willnever stop for the life of the
development.” —Imperial CEO Bruce March
come to take some shares, as I say, tolearn from Canada.
“We buy our resources, our energy,from other channels. There are a lot ofchannels. But we’ll work on Canada’sexports to China or oil and gas. That willhappen in the next few years.”
He said the investment to date is pri-marily directed at improving China’sknowledge of developing unconventionalresources and turning a profit.
Prime Minister Stephen Harper haspledged to turn Canada into a global ener-gy superpower by diversifying exports ofCanadian oil sands crude and LNG toAsia, but opposition to plans by Enbridgeand Kinder Morgan to build pipelinefrom Alberta’s oil sands to tanker termi-nals on the British Columbia coast hasraised concerns about Harper’s chances ofachieving his goal.
However, on the first anniversary ofhis sweeping election victory, Harper saidCanada must align itself with the eco-nomic winners of the world to ensurecontinuing prosperity.
“The financial and debt crisis of thepast few years may not in many countriesbe a passing phenomenon,” he said.
“World economic power and wealthare shifting in a way that is historic andwe as Canadians must decide that we willbe on the right side of that history.”
Harper said the latest federal budget,which contained provisions to streamlineregulatory approval of major energy proj-ects, is aimed at sustaining a “vibrant,growing economy for all Canadians,
while protecting our environment.”He said the government’s economic
plan looks at the bigger picture and focus-es on the longer term.
Investment growth expectedThe importance of winning over the
Chinese was emphasized by GordonHoulden, director of the University ofAlberta’s China Institute.
He said Chinese investment couldgrow ten-fold from the current level ofC$20 billion over the next 10 years to 15years.
Beijing-based lawyer Robert Kwaukof Blake, Cassels & Graydon, said that ifEnbridge’s Northern Gateway project isapproved it is likely Chinese investmentsin Canada’s energy sector will top thelargest single deal so far, when Sinopecacquired ConocoPhillips’ 9 percent stakein the Syncrude Canada oil sands consor-tium for C$4.65 billion.
“The ball is really in our court to getthat pipeline built,” he said.
Xu Xiaojie, a senior researcher at theBeijing-based Institute of WorldEconomics and Politics, said China’sfirms want to profit by taking cheapCanadian gas and building LNG pipelinesand export facilities and selling the LNGto Asian buyers — not just those in China— who are willing to pay eight timesmore than North American buyers.
He noted that the gap between supplyand price in Asia is currently running ashigh as US$16 per million British thermalunits. �
At Flowline Alaska, we’ve spent decades helping to keep oil flowing on the North Slope.It’s a record we’re proud of, and we look forward to a future where we can provide the service and support necessary to grow and expand Alaska’s energy industry.Because we want to keep Alaska’s oil flowing, today and tomorrow.
flowlinealaska.com
907.456.4911
We know pipes.Inside and out.
continued from page 1
CHINA INVESTMENT
Contact Gary Park through [email protected]
Contact Gary Park through [email protected]