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Vol. 17, No. 17 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of April 22, 2012 • $2

page8

‘Middle earth,’ frontier basinscredits, tax cuts pass Legislature

The volatility of U.S. natural gas prices is a major part of the story ofAlaska’s attempts to commercialize North Slope natural gas. Seestory on page 10.

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A tight situationBuccaneer announces financing & rig purchase after contractor complaints

By ALAN BAILEYPetroleum News

Following complaints about unpaid bills due tocontractors for work done at the company’s

Kenai Loop gas field on Alaska’s Kenai Peninsula,on April 18 Buccaneer Energy announced that ithad secured $20 million in project financing andthat it had also agreed to the purchase ofMarathon’s Glacier No. 1 drilling rig for $7.5 mil-lion.

$20 million facilityThe new $20 million finance facility will enable

Buccaneer to pay its vendors and purchase theGlacier rig, in addition to paying some other com-

pany expenses, Buccaneer said. The prospectivelender is currently conducting due diligence priorto finalizing the deal, the company said, addingthat it expects the deal to close in the next 14 to 28days.

Legislators back at workSpecial session called on oil taxes, in-state line; bill based on Senate’s new field tax

By KRISTEN NELSONPetroleum News

It looked like Senate Finance had anoil tax compromise senators could

live with when, after weeks of work onthe measure, it moved Senate Bill 192out of committee April 11.

But SB 192 never reached the Senatefloor.

The bill, a fundamental change ofAlaska’s oil and gas production tax system withdifferent tax rates for existing production fromlegacy fields, incremental production from legacyfields and new oil, couldn’t garner enough supportfrom members of the Senate Bipartisan Working

Group. On April 14 another plan surfaced, a

tax change affecting only productionfrom new fields. Senate Finance addedthat measure to House Bill 276, creditsfor exploration and seismic work in fron-tier basins (see story in this issue).

The Senate passed HB 276 by a voteof 17 to 3, but it got no traction in theHouse, with portions of HB 276 movedto other legislation and HB 276 with-

drawn by its sponsor. The tax change proposed by Gov. Sean Parnell

last year, an across-the-board production tax cut,passed the House last year but stalled out in the

Pipe dreams showdownKinder Morgan proposes larger-than-expected line to Vancouver for Alberta crude

By GARY PARKFor Petroleum News

The all-out contest to open new markets forAlberta crude oil producers, who are losing an

estimated C$18 billion a year because of currentexport bottlenecks, and the battle against the risingtide of pipeline projects has reached a crescendo.

Kinder Morgan has emerged from virtual obscuri-ty with plans to almost triple capacity on its TransMountain system from Alberta to the Pacific Coast,joining rivals TransCanada and Enbridge in the con-flict over the shipment of oil sands crude to the TexasGulf Coast and Asia.

After two years of low-key negotiations withpotential shippers, Kinder Morgan has disclosed its

plans to seek regulatory approval to enlarge TransMountain to 850,000 barrels per day from its current300,000 bpd, setting the stage for what will be theultimate showdown over pipelines and tankers in theBritish Columbia region.

The little-known Trans Mountain system has beenoperating for decades, carrying crude to aWashington state refinery and Port Metro Vancouverfor shipment to California and Asia.

However, concerned about the potentialramifications of a “mechanic’s lien”

against property on city land, the councilvoted to only issue a new special use

permit for Buccaneer’s operations up toMay 4, rather than for the term of one

year that Buccaneer had requested.

see TIGHT SITUATION page 23

GOV. SEAN PARNELL

see SPECIAL SESSION page 22

see PIPE DREAMS page 21

“I am fiercely opposed to (an increasednumber of tankers) in Vancouver’s

harbor.” —Vancouver Mayor Gregor Robertson

‘Arctic Opening’ report predictshuge but risky investment ahead

A new report out of London takes a sweeping look at theArctic and reckons it could attract investment topping $100billion over the next decade.

Most of the investment will be in the oil and gas and min-ing sectors, says the study, which also looks at shipping, fish-eries and tourism.

“The epicenter of that investment is likely to be in theBarents Sea area, north of Norway and Russia, and in north-ern Alaska,” it says. “Smaller investments, but with majorlocal and international consequences, could occur inGreenland, Canada and elsewhere in the Arctic.”

The study comes from Lloyd’s, the global insurance con-cern, and Chatham House, also known as the Royal Instituteof International Affairs.

The report is titled “Arctic Opening: Opportunity and Riskin the High North.”

Lloyd’s is an outfit that certainly knows something aboutrisk. It describes itself not as a company, but “a market where

see ARCTIC REPORT page 19

2012 North Slope explorationwell count likely 13-14, not 34

Of the eight operators who hoped to drill as many as 34exploration wells on Alaska’s North Slope in 2012, two couldnot get rigs so postponed drilling, one will be drilling startingmid-May since it can drill year round, four have completedtheir wells, and one is just about to finish drilling as the winterexploration season in northern Alaska winds down to a close.

Of the 34 wells the eight oil companies had hoped to drill,six to eight wells might still be drilled this year by Great BearPetroleum; Repsol drilled two out of the 15 wells it hadplanned; Brooks Range Petroleum drilled one out of twoplanned wells; Savant Alaska is close to finishing its one outof one; ConocoPhillips drilled one out of one; Pioneer NaturalResources Alaska drilled two out of two; and UltraStarExploration and Linc Energy’s wells were cancelled until nextwinter.

If Savant is able to finish its well, a total of seven wells willhave been drilled, with another six to eight in the works forGreat Bear.

If all the wells planned would have been drilled, 2012would have been the busiest exploration season since 1969,when 33 exploration wells were drilled following the PrudhoeBay discovery.

Still, 13 to 15 wells for 2012 compares favorably to the sin-gle well drilled in the winter of 2011 by Brooks Range.

see EXPLORATION UPDATE page 23

http://www.petroleumnews.com

2 PETROLEUM NEWS • WEEK OF APRIL 22, 2012

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

EXPLORATION & PRODUCTION

ENVIRONMENT & SAFETY LAND & LEASING

ALTERNATIVE ENERGY

FINANCE & ECONOMY

NATURAL GAS

15 Senators weigh in on commodity lawsuit

They say Congress meant for regulators to imposetrading limits to curb ‘excessive speculation’ on oil; Obama offers get-tough plan

16 Congressional delegation questions DEIS

Says document addressing future Arctic offshorepermitting is flawed and threatens excessive restrictions on offshore exploration

12 New study favors Valdez as LNG port

Cook Inlet’s ice, big tides make it less desirable as a place to load huge tankers for exporting North Slope gas, report says

13 Pioneer files ops plan for Nuna project

Module fabrication would get under way this year, first pad 2013, development drilling through 2018, first oil production 2014

GOVERNMENT

9 TDX continues to pitch Chakachamna

Sponsor discusses competing public and privateinterest in hydropower project, but Stateof Alaska denies involvement

3 Repsol completes two North Slope wells

Gas blowout at Qugruk No. 2 disrupts drilling program;Kachemach No. 1, Qugruk No. 4 completed by end of winter exploration season

6 Another stab at Telemark

BRPC and its partners are proposing a smaller unit on the eastern North Slope after withdrawing initial plans last September

5 Asian money eyes Canada

PetroChina, Petronas intensify pressure for actionon LNG, crude export projects; Canada works regulatory and workforce constraints

contents

‘Arctic Opening’ report predictshuge but risky investment ahead

2012 North Slope explorationwell count likely 13-14, not 34

A tight situation

Buccaneer announces financing & rig purchaseafter contractor complaints

Legislators back at work

Special session called on oil taxes, in-stateline; bill based on Senate’s new field tax

Pipe dreams showdown

Kinder Morgan proposes larger-than-expectedline to Vancouver for Alberta crude

ON THE COVER

14 Some Prudhoe wells idled after pipe bursts

16 BOEM requests comments on Ion survey

14 Royale hires K&L Gates for shale project

17 MGM writes down Arctic assets

17 F&W issues new polar bear ESA rule

10 2000 to today: Alaska gas interest revives7 Marathon serious about sands 6 Walakpa gas field expansion requested

4 On to the 9th

8 Frontier basins credits, tax cut approved

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A fter a North Slope exploration sea-son that might be characterized as a

“full Alaska experience” Spanish oilmajor Repsol, a newcomer to the Alaskaoil scene, has been reviewing the lessonslearned following a gas blowout on oneof its exploration wells, Bill Hardham,Repsol’s Alaska operations manager, toldPetroleum News March 13.

Although the blowout on the compa-ny’s Qugruk No. 2 well caused delay anddisruption to Repsol’s drilling program,the company dideventually completetwo wells: theKachemach No. 1,to a depth of about10,100 feet, and theQugruk No. 4, to adepth of about 7,700feet, Hardham said.

The Qugruk wellis located near theBeaufort Sea coaston the Colville River Delta, with theKachemach well some distance to thesouth, just east of the Meltwater partici-pating area of the Kuparuk River unit.

Repsol is partnering in its drilling pro-gram with 70 & 148 LLC, a subsidiary ofDenver-based Armstrong Oil & Gas, andwith GMT Exploration Co. LLC.

Ambitious planHaving acquired interests in about

500,000 acres in North Slope leases thatwere already part way through their leaseterms, with some due to expire within thenext year or two, Repsol has been anxiousto forge ahead with drilling in its acreage,Hardham said. So the company initiallyplanned to concurrently use five drillingrigs to drill multiple well penetrations atfive locations. However, after listening toconcerns expressed by residents ofNuiqsut, a community near the planneddrilling locations, the company decidedto scale back its plan, opting instead touse four rigs at four locations while onlydrilling concurrently with up to three rigs.

“That was something that the commu-nity thought was more reasonable thanwhat we initially proposed,” Hardhamsaid.

The revised plan would have resultedin four wells: the Kachemach 1, theQugruk 1, the Qugruk 2 and the Qugruk 4(abbreviated as K-1, Q-1, Q-2 and Q-4),with the three Qugruk wells being drilledat different locations in the same generalarea.

Successful startAs the winter approached, Repsol

started the construction of the ice roadsthat it would need for access to thedrilling sites, collaborating with PioneerNatural Resources to share part of theannual ice road that Pioneer constructs toits offshore Oooguruk oil field. To sup-port its operations, Repsol had to installseveral temporary camps, including acamp on an ice pad next to aConocoPhillips well pad on the westernside of the Kuparuk River unit. And thecompany chartered an aircraft for flyingpersonnel to and from Anchorage.

Repsol started drilling the K-1 well inearly-February and shortly afterwardsstarting drilling Q-2.

At that point the company’s challeng-

ing logistical exercise in support of thedrilling was progressing pretty much toplan.

“Up to that point we had, I think, donepretty well pulling it off,” Hardham said.

Shallow gasBut a few days after the start of

drilling of Q-2, about half an hour beforea group of Repsol managers was due tovisit the drill site, the drill bit penetratedan unanticipated shallow gas pocket,causing the well to kick and shoot drillingmud onto the snow and ice adjacent thedrill pad. The incident occurred while thecrew was drilling the surface section ofthe well, before setting the surface casingand installing the blowout preventers,Hardham explained.

The drilling crew responded well,ensuring that gas flowing from the wellpassed through a diverter pipe, awayfrom the rig, and shutting down the poweron the rig to prevent a gas explosion. Therig crew did nothing wrong, Hardhamsaid.

No oil was spilled. And there were noinjuries or major damage. Gas flowedfrom the well for about eight hours, withwater from the underground rock forma-tion then flowing for another day or so.

Incident responseInvoking its pre-prepared incident

response plan, Repsol activated its con-tracts with incident response companiesand established an incident commandcenter managed by a unified command.The company also stopped drilling its K-1 well — the company wanted to focuson dealing with the Qugruk incident anddid not wish to risk the possibility of asecond incident while it was still bringingthe Q-2 well under control, Hardhamsaid.

Once the Q-2 blowout happened, theresponse to the incident proceeded verysuccessfully, he said.

And drilling at K-1 stopped for aboutthree weeks, restarting around March 8,Hardham said.

To enable the plugging of the unse-cured well it was first necessary to thaw

out and clean up the drilling rig whichhad been shut down in severely cold con-ditions. Eventually, about a month afterthe incident, it became possible to plugthe well with cement.

Drilling mud that had spilled from thewell, being water based, had formed asolid, frozen slab on top of a sheet of icein an area of less than an acre adjacent theice drilling pad. The water-based mudwas environmentally benign, Hardhamsaid. It took about three weeks to breakup and remove the frozen mud, with thecleanup finishing around April 8. Repsolplans to inspect the site in the summer toevaluate any need for follow up work,Hardham said.

Permits withdrawnFollowing the Q- 2 incident the Alaska

Oil and Gas Conservation Commissionwithdrew the drilling permits for Repsol’sremaining Qugruk wells. The commis-sion wanted new permit applications,demonstrating Repsol’s understanding ofwhat had caused the Qugruk incident andexplaining how the company wouldaddress the blowout risk when drillingthose other wells, Hardham said.

The gas pocket that caused theblowout was in a shallow rock formationthat cannot necessarily be seen in seismicsection — Repsol submitted reviseddrilling plans involving the setting of sur-face casing and installing the blowoutpreventer before drilling to the depth of

this formation, Hardham said. The com-pany also specified the use of a heavierdrilling mud, he said.

The commission re-issued the permits.But at this point Repsol decided that therewas insufficient time left in the season todrill the planned Q-1 well.

“In the end we did not pursue that wellthis year — we just didn’t have enoughtime left,” Hardham said.

Two wells completedHowever the company did proceed

with the drilling of the Q-4 well, a welldesigned to be drilled from an ice island.

“We reached TD (total depth) on thatwell a few days ago and we are doing thelogging right now,” Hardham said.

And meantime the drilling and loggingof the K-1 well had been completed, withRepsol planning to finish all of its drillingoperations by April 15.

Repsol is still assessing the data fromthe two wells that it finally completed andis not yet in a position to announce theresults of the drilling, Hardham said.

ExtremesLooking back on its experiences from

the winter, Repsol has found Alaska to bea land of extremes, both in terms of theclimate and the remoteness of the land.

“The logistics is every bit as challeng-ing as we were led to believe, but that

PETROLEUM NEWS • WEEK OF APRIL 22, 2012 3

40 Years...Thanks to our customers and employees, we’ve been privileged to serve Alaska’s oil industry for over 40 years. Our goal is to build a company that provides a service or builds a project to the complete satisfaction of its customers.

We shall strive to be number one in reputation with our customers and our employees.

We must perform safely.

We must provide quality performance.

We must make a profit.

We shall share our successes and profits with our employees.

Work can be taken away from us in many ways, but our reputation is ours to lose.

Our reputation is the key that will open doors to new business in the future.

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

Repsol completes two North Slope wellsGas blowout at Qugruk No. 2 disrupts drilling program; Kachemach No. 1, Qugruk No. 4 completed by end of winter exploration season

BILL HARDHAM

see REPSOL WELLS page 17

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On to the 9thGroups opposed to exploration in Chukchi Sea take ’08 lease saleappeal to higher court following District Court February decision


In the latest move by those opposed tooil and gas development in the Arctic

offshore, the Native Village of PointHope, the Inupiat Community of theArctic Slope and 12 environmental organ-izations have taken an appeal against theDepartment of the Interior’s 2008Chukchi Sea lease sale to the U.S. Courtof Appeals for the 9th Circuit.

The groups had appealed the lease salein the federal District Court in Alaska.However, following a court case that last-ed several years and that involved arewrite by Interior of the environmentalimpact statement, or EIS, for the leasesale, in February District Court JudgeRalph Beistline dismissed the case.Beistline said that, following the EISrewrite, Interior had complied with allapplicable laws in approving the sale.

And so the groups challenging thelease sale have now appealed the DistrictCourt’s decision to the 9th Circuit.

Shell, ConocoPhillips, Statoil andother companies bought leases in the sale— Interior received $2.6 billion in bonusbids. A ruling by the court that the leasesale was invalid would presumably inval-idate the leases that the companies pur-chased.

Plans and schedulesShell plans to drill in its Chukchi Sea

leases this year, while ConocoPhillipsand Statoil plan to start drilling in 2014.

The 9th Circuit court has set a sched-ule for the lease sale appeal, with openingbriefs by the appellants due on July 23and Interior’s reply brief due by Aug. 22.

The court is already processing threeother appeals against Shell’s plannedArctic drilling. One of those appeals,against the Environmental ProtectionAgency air quality permits for the NobleDiscover, the drilling vessel that Shellplans to use in the Chukchi, has a briefingschedule due for completion at the end ofMay. The other two appeals are againstthe Bureau of Ocean EnergyManagement’s approval of Shell’sChukchi Sea and Beaufort Sea explo-ration plans: these two cases have beenconsolidated, with oral arguments sched-uled for May 15.

Shell plans to start drilling in theChukchi Sea in July.

Drilling controversyPeople opposed to Arctic offshore

drilling say that too little is known aboutthe delicate Arctic marine environment torisk the potential negative impacts of

industrial activities. These people alsoquestion the feasibility of responding toan oil spill in Arctic waters, especiallygiven the severe Arctic climate, theprevalence of sea ice and the paucity ofan infrastructure for logistical support.Native groups are concerned about thepotential impacts of industrial pollutionand disturbance on the marine wildlifethat form a core component of subsis-tence food supplies.

Shell says that enough is now knownabout the Arctic offshore environment toconduct a limited program of explorationdrilling; that there are proven techniquesfor dealing with an Arctic marine oil spill;and that its planned wells present little oilspill risk. The company is assembling amajor oil spill response fleet, with theintention of having a self-sufficient, on-site spill response capability should anemergency arise. Shell and the other com-panies planning offshore drilling havebeen conducting environmental researchin the Chukchi and Beaufort seas, withInterior having also sponsored environ-mental research programs in the regionfor a number of years.

Government regulatory agencies havenow endorsed Shell’s plans, although thecompany still needs approved drillingpermits and approvals for the accidentalminor disturbance of marine mammals.The U.S. Coast Guard, while acknowl-edging the logistical challenges of mount-ing an oil spill response in offshore north-ern Alaska, has said that it thinks thatShell is adequately prepared for itsplanned drilling.

EIS questionedThe District Court Chukchi Sea lease

sale appeal that has now moved to the 9thCircuit focused on what the petitionersclaimed were deficiencies in the leasesale EIS. And the court upheld claimsthat, in preparing the EIS, Interior hadfailed to adequately consider the environ-mental impacts of potential natural gasdevelopment in the Chukchi and had notadequately considered the significance ofmissing Chukchi Sea environmentalinformation.

In a subsequent rewrite of the EIS,Interior added an analysis of the potentialimpacts of natural gas development; iden-tified and commented on every instanceof documented missing information; andvoluntarily added a new section analyz-ing the potential impacts of a hypotheticalvery large oil spill in the Chukchi Sea.Judge Beistline accepted the adequacy ofthe EIS changes. �

Contact Alan Bailey at [email protected]

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B illions of dollars are flowing acrossthe Pacific into development and dis-

tribution of Canada’s oil and natural gasresources and billions more are set follow.

In the latest moves to accelerate theopening of Asian markets, PetroChina isbidding to help build and own part ofEnbridge’s C$5.5 billion NorthernGateway project, Malaysia’s Petronas saidit wants to spend C$5 billion more secur-ing Canadian natural gas supplies, whileJapan’s Mitsubishi and South Korea’sstate-owned Korea Gas are hoping for aninitial agreement in April on a Shell-oper-ated LNG project that could cost US$12billion.

As industry plans unfold at a rapid rate,the Canadian government is answeringthe call for help to accelerate regulatoryapprovals and to head off a looming short-age of skilled tradespeople.

Immigration Minister Jason Kenneysaid in a Calgary speech that his govern-ment will create a separate entry arrange-ment by the end of 2012 to allow “tens ofthousands” of foreign workers to find jobsat resource-based projects, notably in theLNG and oil sands sectors.

That coincided with confirmation fromNatural Resources Minister Joe Oliver ofa 20-year export permit for 230,000 mil-lion cubic feet per day of liquefied gas bythe BC LNG Export Co-operative, addingto an earlier license for Apache-operatedKM LNG Operating General Partnership,to convert 1.4 billion cubic feet per dayinto LNG.

Oliver, who is spearheading his gov-ernment’s promise in March to streamlineenvironmental reviews of major energyprojects, said the LNG permits “show theworld we are serious about getting ourenergy resources to market” as Canadapursues its goal of becoming a “globalenergy super-power.”

He said that the government “does notwant any project to proceed unless it’ssafe for the environment and safe forCanadians.”

Pressure grows for outletsThe pressure to find new outlets for

Canadian gas is building as NorthAmerican prices shrink, threatening theability of producers to remain in businesslong enough to capture a chunk of theAsian markets.

That prospect was reinforced bySpectra Energy Chief Executive OfficerGreg Ebel, who said Eastern Canadacould soon dramatically curtail its ship-ments of gas from Western Canada infavor of buying gas from the Marcellusshale in Pennsylvania and New York.

He said Union Gas, Spectra’s Ontario-based subsidiary, is seeking expressionsof interest from producers and customersto expand a pipeline that was previouslyused to export Western Canadian gas intoNew York state and is now being reversedto tap into production from the prolificMarcellus shale.

In a speech in Ottawa and an interviewwith the Globe and Mail, Ebel said heexpects the development of U.S. shalegas to cut deeply into Canadian exportsinto the U.S. Northeast and even erodetraditional markets in Ontario andQuebec.

“With the price of natural gas in NewYork and Pennsylvania versus the deliv-ered cost of gas, it’s just very difficult forthe Western Canadian gas to compete insome markets in the United States,” hesaid.

EIA forecasts exports to US to dropThe U.S. Energy Information

Administration buttressed that view fore-casting that Canada’s gas exports to theU.S. will decline by 62 percent over thenext 25 years, having already fallen to 6billion cubic feet per day from 9 billioncubic feet per day in the last five years.

Ebel said the loss of sales in easternNorth America make it even more urgentfor Western Canadian producers toadvance plans for LNG exports to theAsia-Pacific region.

Spectra itself is investing C$1.5 billionon its British Columbia gas transportationand processing system and is looking forfirm shipping commitments that wouldsupport an expansion of its pipeline to thePacific coast.

Against that backdrop, PetroChina andPetronas have positioned themselves to

play key roles in developing Alberta’s oilsands and Western Canada’s shale gas.

PetroChina in ‘open bid process’PetroChina has entered an “open bid

process” by expressing interest in build-ing the 525,000 barrels per day NorthernGateway pipeline and is pondering anequity stake in the project, EnbridgeChief Executive Officer Pat Daniel toldthe Financial Post.

He said PetroChina has “made thepoint to us that they are very qualified inbuilding pipelines and we will take thatinto consideration when we are lookingfor contractors.”

However, if PetroChina were toacquire an ownership stake it would haveto purchase an equity interest from one ofNorthern Gateway’s 10 existing ownersbecause there is no opportunity to expandthat group, Daniel said.

What PetroChina could bring to thetable is access to a workforce of about 2million and cheaper labor costs, whichwould ease growing concerns overCanada’s ability to proceed with its slateof potential LNG and crude oil exportpipelines and terminals and expansion ofthe oil sands, although there could beanxiety over the transfer of Canada’sresource assets to Chinese owners.

British Columbia’s powerful laborunions might also raise objections to theuse of non-unionized foreign workers andenvironmentalists and First Nations

would likely intensify their opposition toshipping Canada’s oil and natural gasacross the Pacific.

PetroChina was involved as a prospec-tive 49 percent equity partner in NorthernGateway until 2007 when it withdraw,accusing Canadian governments and pro-ducers of hindering its attempts to aggre-gate 200,000 bpd of production for thepipeline.

Petronas seeks to invest C$5 billionPetronas pulled a surprise when its

Chief Executive Officer Shamsul AbharAbbas told news agency Bloomberg thathas company was seeking an investmentof C$5 billion in Canadian gas plays aspart of its strategy to “grow big inAustralia and Canada.”

Petronas paid C$1.07 billion last yearto acquire a 50 percent stake in 150,000acres of Progress Energy gas properties inBritish Columbia’s North Montney playand was ready to take 80 percent owner-ship of a related LNG export terminal onthe British Columbia coast.

At the request of the Toronto StockExchange, Progress issued a statementsaying it was not involved in any negoti-ations with Petronas to enter into businesstransactions beyond its existing joint-ven-ture deal.

But it said results of an LNG feasibili-ty study with Petronas should be releasedno later than September.



Asian money eyes CanadaPetroChina, Petronas intensify pressure for action on LNG, crude export projects; Canada works regulatory and workforce constraints

Eric Nuttall, portfolio manager atSprott Asset Management, said the

three announced LNG exportprojects for British Columbia willneed liquefaction capacity of 4.2billion cubic feet per day, or 35.2

tcf of dedicated reserves.

see ASIAN MONEY page 7

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NATURAL GASWalakpa gas field expansion requested

The Alaska Oil and Gas Conservation Commission has tentatively scheduled apublic hearing for May 29 at 9 a.m. at its Anchorage offices on a request for expan-sion of the area covered by the Walakpa gas pool rules.

Walakpa, along with the East Barrow and South Barrow gas fields, supplies nat-ural gas to the City of Barrow, with the majority of gas coming from Walakpa,according to AOGCC production data.

The North Slope Borough, operator of the Walakpa gas field, is drilling addition-al development wells in the field. Petrotechnical Resources Alaska is providing tech-nical and management services for the project.

PRA told AOGCC in an April 4 letter that Walakpa wells 11 and 12 have beencompleted in the eastern portion of the field and drilling of the Walakpa 13 is underway, targeting the Walakpa gas pool in the western portion of the field.

Walakpa 13 extends into section 22 of township 20 north, range 20 west, UmiatMeridian. That section is not included in current pool rules for the Walakpa gas pool,PRA told the commission. The North Slope Borough is requesting that all of section22 and the north half of section 27 of township 20 north, range 20 west, UM, beincluded in the pool rules area for the Walakpa gas pool.

These wells are part of a drilling program which includes two wells in the EastBarrow field and four wells in the Walakpa field.

Drilling started last fall. —KRISTEN NELSON

� L A N D & L E A S I N G

Another stabat TelemarkBRPC and its partners are proposing a smaller unit on the easternNorth Slope after withdrawing initial plans last September

By ERIC LIDJIFor Petroleum News

A joint venture operated by BrooksRange Petroleum Corp. is proposing

to form the Telemark unit over nine leasescovering 16,235 acres on the eastern NorthSlope.

The proposed unit would sit between theBadami unit and the western edge of theArctic National Wildlife Refuge. The groupproposed a four-year term running throughDec. 31, 2015, with a possible five-yearextension if the companies meet their workrequirements.

The companies are proposing to conducta 3-D seismic survey at the unit by the endof the year, chose a drilling location by Dec.1, 2013, and drill the well by March 31,2014, or risk losing the unit. The companieswould apply for a second unit plan by Dec.31, 2015.

The Alaska Department of NaturalResources is taking comments through May21.

The working interest owners in the pro-posed unit are Brooks Range Petroleumparent company Alaska Venture CapitalGroup LLC and affiliate Brooks RangeDevelopment Corp. and Nabors affiliateRamshorn Investments Inc. The companieshave spent “well over” $4 million exploringthe region since acquiring their first leasesin October 2003, primarily through fieldwork in 2007 and 2009 and a 3-D seismicprogram sanctioned in 2008 but delayed bytundra closings.

The proposed Telemark DevelopmentProject would produce oil from theFlaxman Sands, a Brookian age reservoirdiscovered with the East Mikkelsen well in1971.

Standalone processingBrooks Range Petroleum would build a

standalone processing facility at the unit,which would be close to the existingBadami pipeline and the future PointThomson pipeline.

“The proposed Telemark DevelopmentProject will create a vital processing facilityfor (the Telemark unit), providing synergies

which will lower the economic hurdleallowing other potential hydrocarbon accu-mulation within and around the (Telemarkunit) to be developed,” the company wrotein its application. “The other potentialhydrocarbon accumulations are currentlybelieved to be higher risk, which character-izes them as marginally economic and theywould not likely be developed withoutexisting infrastructure and processing facil-ities with the (unit). Likewise, future devel-opment of the other potential hydrocarbonaccumulations within (the unit) using theTelemark processing infrastructure willextend the economic life of Telemark pro-duction.”

A second attempt at unitTelemark is the second attempt at a unit

in the region.Brooks Range Petroleum applied last

summer to form the 200,058-acre GreaterBullen unit over 68 State of Alaska leases ina similar area of the eastern North Slope,but withdrew the application and relin-quished some 100,000 acres a few monthslater.

The acreage the companies kept includ-ed nine leases in the “N” block, also knownas the Telemark prospect, located betweenthe existing Badami and Point Thomsonunits.

With Telemark, Brooks RangePetroleum would operate six units acrossthe North Slope: the Putu, Tofkat, SouthernMiluveach and Kachemach units nestled inthe fairway between the Kuparuk River unitand the Colville River unit; the BeecheyPoint unit north of the Prudhoe Bay unit andthe proposed Telemark unit on the easternNorth Slope. �

The proposed TelemarkDevelopment Project would

produce oil from the FlaxmanSands, a Brookian age reservoir

discovered with the EastMikkelsen well.

Contact Eric Lidji at [email protected]

http://www.pndengineers.com

http://www.chiulista.com


M arathon Oil Canada is stepping upits presence in the Alberta oil

sands by filing an application with theEnergy Resources Conservation Boardand Alberta Environment for an in-situoperation due on stream in 2016 at 12,000barrels per day and aiming for an eventu-al 40,000 bpd.

Approval from the government andthe Alberta Energy ResourcesConservation Board is expected to takeabout 18 months, allowing constructionto start in the fourth quarter of 2013.

The Birchwood property, acquiredfrom Western Oil Sands in October 2007,has independently evaluated recoverableresources of 100 million to 615 millionbarrels, based on 100 exploration wells,the filing said.

Marathon said computer simulationsand results from other steam-assisted

gravity drainage or SAGD projects indi-cate 60 percent of the bitumen originallyin place is recoverable using SAGD tech-nology.

First oil is planned between the firstand third quarters of 2016 and the operat-ing life s projected at 20 years.

Marathon said capital costs for the ini-tial phase are estimated at C$510 million,or C$42,500 bpd of production, whileannual operating costs are expected toaverage C$65 million to C$85 million.

Funding from MarathonThe Birchwood project will be

financed through internal funding provid-ed by parent company Marathon Oil.

Marathon said it is targeting a steam-oil ratio of 3.5 for the first project, withinthe range of other SAGD projects, andaims to recycle more than 95 percent ofthe produced water for steam.

The company said the plant will bedesigned to maximize heat recovery andeconomize on the use of natural gas.

Vapor emissions will be captured andused as fuel, or reclaimed into the dilutedbitumen product.

Marathon owns a 20 percent workinginterest in the Athabasca Oil SandsProject, operated by Shell Canada with a60 percent stake, with Chevron Canadaholding 20 percent.

Marathon also has ownership interestsin 143,000 acres of in-situ leases, includ-ing its 60 percent operated Namur proj-ect, 33 percent of the Shell-operatedSaleski project and 20 percent of theChevron-operated Ells River project.Recoverable resources are estimated at 1billion barrels of net bitumen from these

projects.

Cenovus seekingpartnersAnother oil sands project has also

entered the regulatory stream, withCenovus Energy seeking approval for its90,000 bpd Telephone Lake project to bebuilt in two equal phases, with first bitu-men production targeted for 2018.

Since late 2011, the Calgary-basedcompany has been seeking partners,probably from Asia, for Telephone Lakeand another project at its Borealis lease.

Meanwhile, the Alberta EnergyResources Conservation Board, citing acomplaint from an intervening party, hasdelayed by seven weeks to July 17 thestart of hearings into an application byOsum Oil Sands to own and operate the35,000 bpd Taiga project in the ColdLake area of Alberta. �


Michael Culbert, chief executive officerof Progress, said the LNG study is focusedon a two-train facility with a total capacityof 7.4 million metric tons a year, requiring560,000 million cubic feet per day of gasfeedstock.

He said an LNG scheme of the sizeenvisioned by Progress and Petronas wouldneed proven reserves of 9 trillion cubic feetto supply a liquefaction plant for 20 years.

Progress currently has 1.9 tcf equivalentof proved plus probable reserves, 58 per-cent assigned to the North Montney play,and a market capitalization of C$2.5 bil-lion. It also holds 450,000 acres of liquids-rich properties in northwestern Alberta’sDeep Basin.

35.2 tcf of dedicated reservesEric Nuttall, portfolio manager at Sprott

Asset Management, said the threeannounced LNG export projects for BritishColumbia will need liquefaction capacityof 4.2 billion cubic feet per day, or 35.2 tcfof dedicated reserves.

To book those reserves companies willhave to “drill aggressively or buy aggres-sively,” he said, estimating that wouldrequire a combined 626 wells a year overthree years in British Columbia’s Montneyand Horn River plays.

A source in the British Columbia gov-ernment said it was unlikely Petronaswould signal a possible acquisition withinthe next three months unless negotiationswere well advanced, otherwise it wouldonly be driving up share values of prospec-tive candidates.

He said Petronas may have issuing anearly signal to Canadian lawmakers andregulators of its interest in making an out-right takeover bid.

Under Canadian legislation a foreigninvestment review is required for any pur-chase valued at more than C$312 million.

David Collyer, president of theCanadian Association of PetroleumProducers, said that “diversifying mar-kets for Canadian oil and natural gasproducts is vital to ensuring Canada con-tinues to grow its production and receivefull value for its natural resources.” �

continued from page 5

ASIAN MONEY

Contact Gary Park through [email protected]



Marathon serious about sandsFirst oil is planned between thefirst and third quarters of 2016

and the operating life s projectedat 20 years.

http://www.lynden.com

By KRISTEN NELSONPetroleum News

R ep. Steve Thompson, R-Fairbanks,designed House Bill 276 to help

solve high energy prices in Fairbanks byproviding exploration credits for theNenana basin, which could supply energyfor Fairbanks.

Another of Thompson’s bills, HB 289,provided credits for construction of lique-fied natural gas storage tanks.

Both measures passed the LegislatureApril 15, not as separate bills, but rolledinto Senate Bill 23, a bill on firm taxcredits which passed the Senate last year.

When the House Majority held a pressavailability after the Legislature gaveledout April 16, Thompson described gettingthe bills passed as a rollercoaster ride. Hesaid while the bills didn’t provide a near-term fix to high energy costs, he said thebills put some things in place that would

bring energy relief toFairbanks and rural areas in themid-term.

The House ResourcesCommittee spent considerabletime on HB 276 and a commit-tee substitute applied theexploration credits to fiveother unexplored or underex-plored basins close enough tocommunities that hydrocar-bons found would help reduce energycosts.

The House passed HB 276 by a vote of35 to 2.

North Slope vehicle in SenateIn the Senate Finance Committee,

however, HB 276 became the vehicle fora North Slope tax reduction for new oil.This was after the Senate’s more compre-hensive oil tax change, SB 192, couldn’tgarner enough support in the Senate

Bipartisan Working Group to beadvanced to the floor.

The Senate passed the amend-ed HB 276 by a 17 to 3 voteApril 14.

Had the House concurred inthe Senate amendment to HB276 that would have meantHouse acceptance of the Senate’sNorth Slope new-oil tax reduc-tion without a hearing.

Had the House voted not to concur, the“frontier basins stampede” credits couldwell have died because the Legislaturewas so close to gaveling out.

House Rules, meeting April 15, thelast day of session, came up with anothersolution and Thompson withdrew HB276 on the House floor.

The Rules Committee added the so-called “middle earth” or “frontier basinsstampede” provisions of HB 276, alongwith HB 289, to Senate Bill 23, which

started life in January of 2011 as anextension of the state’s film tax credit andhad passed the Senate 18 to 1 in April2011. The new oil tax provisions added toHB 276 in Senate Finance were notincluded.

The House Rules version of SB 23 —now containing frontier basin tax creditsand tax credits for LNG tank storage inaddition to film credits — passed theHouse by a vote of 37 to 2; the Senateconcurred by a vote of 19 to 1.

Frontier basinsThe “frontier basins stampede” por-

tion of SB 23 provides exploration creditsfor drilling and seismic, and a reducedproduction tax for the first seven years ofproduction.

Thompson told House Rules thatincentives combined in SB 23 “have beenthoroughly briefed in both bodies bymany committees.” He said the incen-tives in the bill “will encourage com-merce with credits for the film industry,new oil and gas in under, unexploredregions and the commercialization of nat-ural gas to Alaskans, quite possibly byAlaskans.”

The production tax will be reduced to4 percent for the first seven years of com-mercialization or production for oil or gasproduced outside the Cook Inlet sedimen-tary basin and not including land north of68 degrees latitude (i.e. the North Slope)for production beginning after Dec. 31,2012, and before Jan. 1, 2022.

The exploration drilling credit is forthe lesser of $25 million or 80 percent oftotal exploration drilling expenditures;the seismic credit is the lesser of $7.5 mil-lion or 75 percent of total seismic explo-ration expenditures.

According to cost estimates for aNorth Nenana well prepared for DoyonLtd. and included with House ResourcesCommittee documents, costs for wellsbetween 8,000 and 12,000 feet measureddepth would range between $22.8 millionand $27.6 million; these wells assume asummer barging operation and includethe cost of barging, mobilizing and demo-bilizing a rig from Nenana.Petrotechnical Resources of Alaska,which prepared the estimate, said time forthe drilling was based on the 2009Nunivak No. 1 well; drilling rig costswere assumed to be $51,000 per dayreflecting the current tight rig market;equipment, materials and other costswere based on the Nunivak No. 1 escalat-ed by 12.5 percent for inflation; comple-tion costs were based on a current Kenaidrilling program with 25 percent increasefor the remote operation; and a contin-gency was added for delays from drillingproblems, fire delays or weather condi-tions.

Pre-approval requiredBefore work is done the explorer must

submit to the commissioner of theDepartment of Natural Resources “theinformation necessary to determinewhether the geologic objective of thewell is a potential oil or gas trap that isdistinctly separate from any trap that hasbeen tested by a preexisting well,” SB 23says.

The credits are available for the firstfour exploration wells within the areasspecified and are limited to the first two


Advertising has its benefits with Petroleum News Bakken

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Pumping algae, corn byproduct geldownhole for frac vs water.

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Rail rates to dropRumor of lower railroad charges to ship smaller volumes of oil confirmed

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Identifying sweet spotsSuccess of one company’s geoscience team and its CEO’s take on tailored completions

By XXXXX XXXXXXXPetroleum News Bakken

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Well shows 530 foot zoneBand of oil-rich Niobrara shale could be thickest yet; nearby rancher demands 35%


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see XXXXXXXXX page xx


Another 40,000 cars in the works

Recoverability in very tightshale jumps from 1% to 4 to 9%

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Takeover would combine Top 3and 7 E&P players in the Bakken


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Variations in levels of thermal maturity for theNiobrara Formation and equivalent rocks.

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Vol. 1, No. 2 • www.PetroleumNewsBakken.com Note: Spoof headlines for display only Released May 6, 2012 • $2

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Major proves Sheffield right,making “beeline to the Wolfcamp”

The company hard at work on new rig designs for tight oil drilling inthe Bakken and Eagle Ford petroleum systems remains silent ondetails, including visuals. See story on page 23. Existing rig fromanother firm pictured above.

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Obama shockerPresident orders agencies to speed up review of northern Keystone route




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Capital from Hong Kong?2 small Bakken, Three Forks producers look to Hong Kong Stock Exchange for capital









Pressure up to use gasAs gas flaring becomes less palatable to the Bakken public, a strong option emerges



Hush is word on new rig designs

Flush with oil, potash revenuesSaskatchewan debt at 25-year low






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Refiners talk buying criteria,what attracts them to Bakken oil


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Japanese group funds new E&P firmformed by Montana, ND ranchers

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Flare gas solution?$7.5M study on commerciality of using wasted gas to fuel electricity offers optimism




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Targeting best workersSaskatchewan puts ads in farm magazines world-wide, touting high paying oil jobs









Schweitzer: Taxes okayMontana’s outgoing governor says state’s regs and taxes not discouraging development



Case study on well performancedrivers full of holes says producer






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Top Republican contender said permitting is less expen-sive in North Dakota, including permitting of gravel pits,necessary for tight oil operations (pit near Watford City,ND pictured here).

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Frontier basins credits, tax cut approved‘Middle earth’ bill started out as exploration credits for Nenana basin; expanded to include five other areas close to communities

STEVE THOMPSON

see FRONTIER BASINS page 9

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exploration wells within a single area.Work must be done between June 1,2012, and July 1, 2016.

Seismic credits are available for thefirst four seismic exploration projects andare limited to one seismic exploration pro-gram per area.

In exchange for the tax credits, therecipient must agree to provide to the statespecific data acquired through the project.

The frontier basin areas covered in thebill include: within 100 miles ofKotzebue; within 150 miles of Fairbanks(Nenana and Yukon Flats basins); within50 miles of Emmonak; within 50 miles ofGlennallen; within 100 miles of Egegik;and within 100 miles of Port Moller.

LNG storage creditsThe other oil and gas bill consolidated

under SB 23, HB 289, provides a tax cred-it for investment in a liquefied natural gasstorage facility that begins operationbefore Jan. 1, 2020.

The facility must be regulated as a util-ity and available to furnish LNG storageto customers, utilities or industrial facili-ties.

A sponsor statement by Thompson saidHB 289 provides an incentive for the pri-vate sector delivery of lower cost naturalgas to Interior Alaska by extending taxcredits to an LNG trucking project for theInterior.

The bill provides tax credits to tankedstorage with a minimum volume of25,000 gallons with the credit limited to50 percent of construction costs up to $15million, allowing areas of Alaska whichlack the depleted gas reservoirs availablein Cook Inlet a monetary incentive forcosts associated with constructing above-ground tanks for storing LNG. The creditalso applies to expansions of existingfacilities as long as the expansion is aminimum of 25,000 gallons.

The bill also provides for an exemp-tion from land lease payments for up to10 calendar years for lands leased fromthe state for LNG storage facilities.

The bill passed the House 36 to 1April 4. �


FRONTIER BASINS

Contact Kristen Nelson at [email protected]

� A L T E R N A T I V E E N E R G Y

TDX continues to pitch ChakachamnaSponsor discusses competing public and private interest in hydropower project, but State of Alaska denies involvement

By ERIC LIDJIFor Petroleum News

A lthough pushed to the back burner by the State ofAlaska, a hydropower project at Lake Chakachamna

continues to be on the mind of the company sponsoring theproject.

In an update submitted to the Federal Energy RegulatoryCommission in early February, TDX Power Inc. said twocompeting coalitions continued to study the project.

“The State of Alaska, though its development agency(AIDEA), has been seeking funding partners with friendlygovernments and private equity funds,” TDX Director ofBusiness Systems Jolene Lekanof wrote in the six-monthstatus update to FERC on Feb. 9. “The State hopes to forma coalition that will lead to a successful public/private part-nership.”

The State, however, denies involvement in the project.“We are not involved in any discussions with TDX,”

Alaska Industrial Development Authority spokesmanKarsten Rodvik told Petroleum News by email on April 4.

The office of Gov. Sean Parnell said no other state agen-cies are involved in the project.

The update also mentioned that a “competing coalitionis forming that would be 100 percent private sector based,”noting the current attractiveness of energy investments.“Also both sets of investors appreciate the fact that thisproject is environmentally friendly. The Chakachamnaproject, since it generates power underground, has no needfor a dam or reservoir, a common impediment to otherpotential hydroelectric projects.”

That statement most likely refers to the proposed Susitnahydroelectric project.

No clarification responseTDX did not return several requests for clarification.FERC issued a preliminary permit in February 2010 for

TDX to study the hydroelectric project, requiring the com-pany to provide updates on its progress every six months.

As considered, the project would involve diverting waterfrom Chakachamna Lake about 85 miles west ofAnchorage through an 11-mile tunnel to an undergroundpower plant.

The 300-megawatt project is estimated to cost $2.9 bil-lion in 2008 dollars.

For the coming six months through August, TDX told

FERC that it “intends to continue exploring developmentoptions including evaluating the financial feasibility of thehydroelectric project and options for reducing costs and/orsecuring continued funding from the State of Alaska,friendly foreign governments and the private sector to con-tribute to the project. A positive funding coalition looksvery promising at the point.”

Although both projects have long histories and bothhave been recently reconsidered as the scarcity of naturalgas and the price of diesel fuel have forced policymakers toconsider alternative energy sources, the Alaska EnergyAuthority issued a report in November 2010 recommend-ing the Susitna project over the Chakachamna project.

Calling Chakachamna a worthy alternative, AEA choseSusitna because it would produce cheaper power and posefewer potential cost overruns. While the Susitna projectwould cost roughly 50 percent more than Chakachamna, itwould produce more than twice as much power, accordingto AEA. The report also raised concerns about the under-ground engineering at Chakachamna and the geologic riskfrom nearby volcanoes and faults. �

Contact Eric Lidji at [email protected]

http://www.ch2mhill.com/alaska

By BILL WHITEResearcher/writer for the Office

of the Federal Coordinator

Editor’s note: This is the first part ofthe concluding section of a three-partstory.

The Alaska gas pipeline project gotanother life in the late 1990s as

North Slope producers showed renewedinterest in tackling the job.

Oil productionfrom the flagshipPrudhoe Bay fieldhad plunged about 50percent since its peaka decade earlier. With Prudhoe fading,perhaps the time was near for marketingthe megafield’s natural gas, which largelyhad been reinjected for 20 years to pushmore oil from the reservoir. But there wasstill that pesky problem: Could a gas linemake money?

The market targeted in the 1970s —the Lower 48 — remained unattractive.Natural gas prices were too low.

But Japan showed promise. The

Japanese gas marketwas just one-ninththe size of the Lower48 market in 1999— too small toabsorb the massivevolume of liquefiednatural gas anAlaska projectwould produce. Butthe appetite of utili-ties there and in South Korea had beengrowing, and with continued growthmight reach the critical mass an Alaskaproject needed. They also paid more forLNG than U.S. buyers paid for pipelinegas.

The lack of a gas project gnawed atsome Alaska leaders. One in particular,state Rep. Ramona Barnes of Anchorage,chairwoman of a House-Senate gas taskforce, made an LNG project her crusade.

In early 1997, Barnes lectured a room-ful of oil lobbyists and executives:“We’re going to build this project in mylifetime.” (She died in 2003.)

The main producers — BP, Exxon andARCO — had been talking for a year or

two about how Asia might want AlaskaLNG, perhaps as early as 2005, morelikely closer to 2010. But the project’s$15 billion estimated cost was a barrier,making Alaska LNG too expensive tocompete for the growing demand, thepresident of ARCO Alaska said after vis-iting Asia buyers in fall 1995.

In March 1997, the producers saidthey would study how to shave costs froman LNG project. But they wanted the stateto change taxes and/or royalties toimprove the economics, too.

In 1998 Alaska enacted the StrandedGas Development Act. “Stranded” due tono pipeline to carry the North Slope’sestimated 35 trillion cubic feet of gasreserves to market. The new law didn’tchange taxes, but it allowed the producersand state to negotiate a fiscal contract toreplace the normal set of taxes. It wasunclear whether this was constitutional.At Rep. Barnes’ insistence, the contractcould apply only to an LNG project.

That law lapsed a few years later withno takers. Asia prices and demand wereup, but not nearly enough.

Then the LNG project all but faded

from view, eclipsed again when a freak ofnature put new energy behind the oldplan: Pipe Alaska gas to the Lower 48.

This time, the Lower 48 route had realtraction.

First, government — initially the statebut Congress as well by the early 2000s— was actively looking for ways to help.

Second, North Slope producers nowwere publicly engaged in trying to solvehow to move Prudhoe Bay gas to marketprofitably.

Government and producer enthusiasmwasn’t enough, however. Somethingneeded to shore up Lower 48 natural gasprices. Without higher prices, the cost ofpiping Alaska gas 3,000 miles to Chicagowould make the gas too expensive toattract buyers.

On that front, good fortune for theproject was coming.

As 2000 began, anxiety resurfaced thatthe United States was running short ofnatural gas — the same anxiety thatbirthed Alaska gas pipeline plans 30 yearsearlier. The nation’s old reliable gas fieldswere petering out.

Soon, enflaming that anxiety, theLower 48 was whacked with a nasty win-ter — the coldest in years.

Natural gas prices spiked during thewinter of 2000-2001.

And a race was on to pipe Alaska gassouth to the rescue.

New energy for a gas pipelineFor utilities and other buyers, their

affection for natural gas flip, flopped,then flipped again during the span ofyears starting in about 1999. It becamethe fuel of choice, then the fuel of risk,then back to the fuel of choice again.

The buyers’ manic responses wereswayed by the breathtaking volatility ofnatural gas prices during this period.

As gas-shortage anxiety bloomed inthe early 2000s, several Alaska gaspipeline ideas came forward. These pro-posals exposed schisms among Alaskansand among the oil producers over whichidea was wisest, complicating efforts tounify behind a single project.

Most of the ideas responded to thesame cue: Natural gas prices that blastedoff like a rocket.

In 1999, Lower 48 gas prices averageda ho-hum $2.20 per thousand cubic feet atthe wellhead, roughly the average of the


� N A T U R A L G A S

2000 to today: Alaska gas interest revivesChanging gas supply situation in Lower 48 sparks pipeline interest; Far East prices put liquefied natural gas back on the boards

see GAS WARS page 11

BILL WHITE OFF

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http://www.alaska-analytical.com

http://www.emeraldnw.com

previous few years. But as the anxiety sank in during the

next year, prices began to creep up.The benchmark Henry Hub spot price

topped $3 in April 2000 and $4 in Junebefore leveling off. Then it got very coldin November. The price spiked to $6around Thanksgiving, and by Christmas ittopped $10, more than four times higherthan at the start of the year.

The catalyst was an unusually coldweather — the 26th coolest winter in theprevious 106 years, the National Oceanic& Atmospheric Administration Reportedat the time.

“The winter began with record or near-record cold across much of the nation inDecember as arctic air spread from theRocky Mountains to the East Coastbehind a series of strong cold fronts,”NOAA said. “Severe winter storms andrecord snowfall fell in many cities fromAmarillo, Texas, to Buffalo, New York.”(Meanwhile, Alaskans were enjoyingtheir mildest winter since statewiderecords began in 1918.)

In California, power companiesimposed rolling blackouts on customers.

The cold weather broke later that win-ter. Gas prices deflated like a botchedsoufflé. The Henry Hub price plungedunder $6 in February and pierced $5 inMay. By Thanksgiving 2001, the spotprice had even penetrated below $2briefly.

But the shortage fears lingered and anew paradigm of high prices took root inthe U.S. gas industry. The Lower 48 well-head price averaged $4.92 per thousandcubic feet from 2001 through 2006, dou-ble the price of the late 1990s.

The answer to high prices seemedobvious: Get more supply. Besidesrenewed interest in the Alaska gaspipeline project, billions of dollars wereinvested in Lower 48 LNG import termi-nals.

In 2000, the three major North Slopeproducers formally teamed up on a freshlook at piping Alaska’s gas to market.

Easing their effort was a recent détentethat took hold among them. On the sur-face, the oil industry can appear mono-lithic, hand-in-hand sharing risks andrewards while jointly developing fields.To some extent that does describe theindustry’s dynamic.

But a closer look often reveals divi-sions not readily apparent from afar. Andthis was true for Prudhoe Bay’s big three.

A gnarly schism involved their unbal-anced ownership of the oil and gas rights.BP owned 51 percent of Prudhoe’s oilproduction but only 14 percent of the gas.ExxonMobil and ARCO (soon to bebought by Phillips) each owned 23 per-cent of the oil and 43 percent of the gas.

BP wanted the gas retained to help pro-duce more oil. ExxonMobil and ARCOhad a stronger urge to move some gas tomarket.

This schism flared among the compa-nies from time to time, but for the mostpart it was invisible to the public. Thedétente occurred in April 2000. The threecompanies announced a major shuffling


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GAS WARS

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of their ownership interests so that eachcompany’s share of oil was the same as itsshare of gas.

That ownership shuffle more closelyaligned their interests in developingPrudhoe Bay gas.

Within a few months, they were zero-

ing in on a project. In September 2000,BP and Phillips told the U.S. SenateEnergy and Natural ResourcesCommittee they hoped to “achieve con-sensus on route and timing” within a year.

Internally, the three companies werenot fully aligned on the project.ExxonMobil was pushing a route that wasabout to ring alarm bells within Alaska,the national environmental communityand even Congress.

Over the topBesides ExxonMobil’s Alaska North

Slope holdings, its Imperial Oil sub-sidiary had smaller gas discoveries in theMackenzie Delta across the Canadianborder.

In the 1970s, Exxon (and the other twoproducers) backed the unsuccessfulArctic Gas project that would have strunga pipeline eastward from Prudhoe Bay tothe Mackenzie Delta then south throughCanada and into the U.S. Midwest andWest.

That project died in 1977 whenPresident Jimmy Carter and the Canadiangovernment backed a competing proposalthat would pipe North Slope gas southinto Interior Alaska then southeast alongthe Alaska Highway to the Lower 48.

In 2000, ExxonMobil saw an opportu-nity to resurrect the Prudhoe-to-Mackenzie project, dubbed the “over-the-top” route. This time it would pick up gasfrom the company’s big Point Thomsondiscovery east of Prudhoe then wade off-shore coastal Alaska to avoid trenching

the Arctic National Wildlife Refuge as the1970s project proposed. Conservationistshad spent decades lobbying to keep oiland gas development out of ANWR.

BP and Phillips were more attuned tothe mood of Alaskans about wanting asouth-bound pipeline that would bringsome North Slope gas to the state’s popu-lation center.

In late September 2000, Dick Olver,BP’s global production chief, said in anAnchorage speech that speculation abouta route or even a project was premature.BP was considering all options, includingLNG and converting gas to a liquid thatcould flow down the underused trans-Alaska oil pipeline.

But mostly he discussed a pipeline intoCanada. In a nod to the controversy stir-ring on the over-the-top route, Olver saidthe project ultimately must be “in the bestinterests of U.S. consumers, the people ofAlaska and our Canadian stakeholders.”

“The stars appear to be aligning forAlaska,” he said.

The CEO of Phillips had a similarmessage in an Ohio presentation. “Thetime is right, the technology is here andthe market is here,” said Jim Mulva. “Weare completely committed to making thisa reality.”

In December 2000, the big three pro-ducers announced they had formed theNorth American Natural Gas PipelineGroup to assess costs and technology,pick a route and apply for constructionpermits. They budgeted $75 million andultimately spent $125 million.

The prospect of an over-the-top linealarmed Alaska political leaders. Gov.Tony Knowles in November 2000declared that route off-limits, dropping aslogan that caught on: “My way is thehighway.”

The Alaska Legislature followed in2001 with a law that prohibited grantingstate rights of way for an over-the-toproute. Some in Congress also began dis-cussing a ban on the route. �

See the concluding part of this story inthe April 29 issue of Petroleum News.

Editor’s note: This is a reprint fromthe Office of the Federal Coordinator,Alaska Natural Gas TransportationProjects, online atwww.arcticgas.gov/print/Interest-in-Alaska-gas-revives-2000-to-today.


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� N A T U R A L G A S

New study favors Valdez as LNG portCook Inlet’s ice, big tides make it less desirable as a place to load huge tankers for exporting North Slope gas, report says

By WESLEY LOYFor Petroleum News

Port Valdez would be a better choicethan Cook Inlet for loading giant

tankers to export liquefied natural gas fromAlaska, a new study concludes.

Valdez, in Prince William Sound, alreadyserves as the pickup point for tankers haul-ing North Slope crude that comes down thetrans-Alaska oil pipeline.

Port Valdez has distinct advantages overAnchorage or other potential LNG ports inCook Inlet, says the comparative risk analy-sis prepared for the Alaska Gasline PortAuthority.

“The Port of Valdez has already proventhat it is a world-class oil export facility,with the infrastructure in place to exportlarge volumes of North Slope gas in theform of LNG from Alaska,” the study says.

Jeff and Jonathan Pierce conducted thestudy for the port authority. The authority isa partnership of the Fairbanks North Star

Borough and the city of Valdez seeking tocommercialize Alaska’s stranded NorthSlope gas reserves.

Jeff Pierce is a licensed oil tanker pilotwith extensive experience in Alaska waters.

Recently, interest has flared anew in theidea of piping North Slope gas to a tidewa-ter port somewhere along the state’s south-ern coast. There, it would be converted toliquid form and loaded onto special LNGtankers for shipment to Asia, where the priceof gas currently is high compared to gasprices in North America.

Something of a regional rivalry exists asto where a gas pipeline would terminate —the Cook Inlet area or Valdez. For local eco-nomic development boosters, an LNG ter-minal would be a real prize.

When it comes to the practical and safe-ty considerations of shipping, Valdez is the“port of preference,” the study concludes.

And Bill Walker, spokesman for the portauthority, noted that Yukon Pacific Corp.once held government approvals to export

LNG from Port Valdez. Valdez is a deepwater port and the north-

ernmost North American port free of iceyear-round, the study says. It has hosted oiltankers since 1977, when crude began flow-ing down the pipeline.

Port Valdez waters are relatively docilecompared to Cook Inlet, the study says. Afleet of powerful escort tugs are stationedthere, as well as a U.S. Coast Guard systemto monitor vessel traffic.

In contrast to Port Valdez, Cook Inlet ischaracterized by extreme tides, shoals,strong currents, less tug and Coast Guardsupport, and the need for dredging to main-tain adequate depth for ships arriving atAnchorage, the state’s largest city and mainseaport.

The Matanuska-Susitna Borough isdeveloping a new port at Point MacKenzie,just across Knik Arm from Anchorage.

The study also describes ice floes thatcan choke Cook Inlet during winter months.The current-driven floes are dangerous,

capable of exerting enough force to tear aship from its moorings. This happened in2006 with the oil tanker Seabulk Pride,which broke away from a dock at Nikiski.

Prince William Sound does have thethreat of icebergs from Columbia Glacierdrifting into the shipping lanes. This threatwas a factor in the Exxon Valdez tanker dis-aster in 1989. But the port authority studysays the amount of ice coming from thereceding glacier has diminished over the last20 years.

Very large LNG ships — larger than theoil tankers calling at Valdez, with three timesthe capacity of ships loading at theConocoPhillips LNG facility at Nikiski —likely would be needed to carry the hugevolumes of North Slope gas.

The study concludes Cook Inlet isn’twell-suited presently to accommodate largeLNG ships in winter. �

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Pioneer files ops plan for Nuna projectModule fabrication would get under way this year, first pad 2013, development drilling through 2018, first oil production 2014

PETROLEUM NEWS

Although Pioneer Natural Resources Alaska has notyet announced the results of its Nuna 1 appraisal

well from this past winter, it has filed a lease plan ofoperations with Alaska’s Division of Oil and Gas, indi-cating it hopes to move forward with its two-pad Nunadevelopment, which would involve between 35 and 65horizontal wells, targeting primarily the Torok reservoir,although other zones might include the Kuparuk,Nuiqsut and Ivishak.

The plan of operations was similar to the original planfiled with the division about a year ago.

Per its agreement with the state for expanding itsnearshore Oooguruk unit to include the Nuna projectleases, Pioneer has to decide by June 30, 2014, whetherit plans to sanction development.

Pioneer spokesman Casey Sullivan told PetroleumNews April 19 that the project has not been sanctioned.

Both pads on shoreIn Pioneer’s plan both pads are onshore, targeting off-

shore targets, with production expected to begin in 2014.In a smaller Torok participating area in the main part

of the Oooguruk unit, Pioneer estimated in 2011 that theTorok PA contained as much as 690 million barrels oforiginal oil in place and believed it could recover asmuch as 25 percent of that using primary and enhancedrecovery techniques. But in 2011 the company has alsomentioned 50-100 million barrels of recoverable oil inconnection with the Nuna development.

In the division’s April 16 public notice, asking forcomments on the development, the state said Pioneerplanned to build “two onshore production drillsites,roads, flowlines and power lines elevated on verticalsupport members, and a pig launching and receiving tie-in pad on state of Alaska oil and gas leases,” includingtwo Pioneer leases (390505, 390697) and six

ConocoPhillips leases (390506, 025528, 025844,380107, 025532, 025531).

Hydrocarbon resources, the target mainly being oil,would be accessed using horizontal drilling into the fol-lowing state leases: 355038, 355039, 391459, 390504,380505, 390434 and 390505, all held by Pioneer andEni, with one lease owned 100 percent by Pioneer. (PNwas unable to locate information about the status of leas-es 390504 and 380505 prior to going to press.)

NDS1 at site of Nuna 1One of the proposed gravel drillsites, NDS1, which is

at the site of the Nuna 1 well Pioneer drilled this winter,would be two and a half miles northwest of Drillsite S-3S, commonly known as DS-3S, in the Conoco-operated

Kuparuk River unit. It is approximately 1,000 feet fromthe Colville River.

The other proposed gravel drillsite, NDS2, would beabout 4 miles upriver from NDS1, approximately 600feet from the Colville.

Flowlines would transport production, gas and waterbetween the drillsites and the Oooguruk tie-in pad, OTP.

North of DS-3S a junction tie-in pad would be built tolaunch and receive NDS2 flowline cleaning and inspec-tion pigs.

Pioneer wants to build gravel roads from DS-3S foryear-round access and support activities.

The flowlines would be separated from the gravelroads by at least 500 feet.

Power would be generated using existing and expand-ed power generation equipment at the OTP and transmit-ted to the drillsites on lines suspended on the flowlinevertical support members.

Pioneer’s plan includes 25-50 wells at NDS1 and 10-15 at NDS2.

About half would be producers and half injectorwells, and one at each drillsite would be a Class I/IIUnderground Injection Control disposal well.

Multiphase flowlines for oil, gas and water wouldtransport the produced fluids from the drillsites to theOooguruk tie-in pad and “eventual transmission throughthe Trans Alaska Pipeline System.”

Economic benefits to boroughIn the economic benefits portion of its proposed plan

for Nuna, among other things Pioneer said about theNorth Slope Borough that, “The tax valuation for capitalin place will likely be $165 million over the first 10years,” and that the borough “would likely receive $33million” in property taxes from Nuna.

Activity Schedule

Conceptual Engineering and Design Initiated 4th Qtr. 2010

Permit Review and Approvals 2011

Long Lead Procurement 2012

Commence Module Fabrication 2012

Appraisal Drilling Winter 2012

Mine Site Construction 2013

Ice Road Construction 2013

Gravel Construction, NDS1 2013

Flowline Construction 2014

Module Installation 2014

Development Drilling 2014 to 2018

First Production 2014

Development of NDS2 2015 or later

Site Decommissioning and Closure End of Field Life

Nuna project’s plan of operations

April 16, 2012, lease/unit plan of operations filed by Pioneer Natural Resources withAlaska’s Division of Oil and Gas.

see NUNA PROJECT page 19

http://www.golder.com

http://www.miswaco.slb.com


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ENVIRONMENT & SAFETY

Some Prudhoe wells idled after pipe burstsA pipeline leak on the afternoon of April 10 prompted BP to shut-in some wells

at drill site 1 in the eastern operating area of the Prudhoe Bay oil field.The production impact was limited, within the range of daily fluctuations nor-

mally seen in overall North Slope output, BP Alaska spokesman Steve Rineharttold Petroleum News.

The failed pipe was an above-ground, 8-inch seawater injection line running betweena manifold building and well 11 at drill site1. The drill site was among the earliestinstalled at Prudhoe Bay, the nation’s largestoil field.

Because the well had been shut-in forservicing, the pipeline was filled with freezeprotection fluids, Rinehart said. The fluidsconsisted of about 60 percent methanol and40 percent seawater.

The pipeline failure occurred “during awell warm up procedure conducted in preparation for a mechanical integrity teston Well 11,” said a situation report from the Alaska Department of EnvironmentalConservation.

3,675-gallon spillField workers were moving seawater into the line and noticed pressure at the

manifold but not at the wellhouse, Rinehart said. Then they saw fluids sprayingfrom the pipeline.

The burst pipe, as well as an adjacent line, dislodged off the rack elevatingthem above the ground, the DEC’s John Ebel said.

No one was injured in the incident.Several wells were shut-in as a precaution, Rinehart said.Well 11, formerly an oil producer, now serves as an injection well to send sea-

water into the Prudhoe Bay reservoir to help enhance oil recovery.BP estimated the spill at 3,675 gallons, based on the engineered volume of the

8-inch line between the manifold building and well 11, the DEC said. Aside frommethanol and seawater, a small amount of crude oil also spilled, the agency said.

The fluids were released onto the snow-covered gravel drill pad and flowedinto a reserve pit, the DEC said. Responders surveyed a contamination area ofabout 3.85 acres.

BP worked to remove contaminated snow, ice and gravel. The pipeline wasblocked and blinded at the manifold building and at the well.

The company was looking into what caused the leak, such as ice perhaps plug-ging the line despite freeze protection.

—WESLEY LOY

Royale hires K&L Gates for shale projectRoyale Energy Inc. recently hired law firm K&L Gates LLP to advise the com-

pany through its attempt to explore the source rock potential of its North Slopeacreage.

K&L Gates attorney and former AlaskaDepartment of Revenue CommissionerPatrick Galvin will lead the effort, accordingto the San Diego based independent.

“Patrick shares our desire to approach theappropriate regulatory and community enti-ties with deference and respect,” Co-CEOStephen Hosmer said in a statement. “Weare guests on this land and we want to develop this resource in a responsible man-ner.”

Royale plans to announce details in the coming months of its program to drillbetween three and six wells to assess the potential of the Shublik and Kingakshale on its acreage.

The company picked up more than 100,000 acres in three blocks in December2011.

—ERIC LIDJI

ALA

SKA

DEC

The failed pipe was anabove-ground, 8-inch

seawater injection linerunning between a manifoldbuilding and well 11 at drill

site 1. The drill site wasamong the earliest installedat Prudhoe Bay, the nation’s

largest oil field.

FINANCE & ECONOMY

K&L Gates attorney andformer Alaska Departmentof Revenue Commissioner

Patrick Galvin will lead theeffort, according to the SanDiego based independent.

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By WESLEY LOYFor Petroleum News

A laska’s Mark Begich is among 19U.S. senators, all Democrats,

jumping into a federal lawsuit concern-ing regulation of possible “excessivespeculation” in commodity markets.

The action comes amid a rising elec-tion year backlash over high gasolineprices across the nation. On April 17,President Barack Obama announced afive-part plan to strengthen oversight ofenergy markets and safeguard againstwhat the White House called “illegalmanipulation, fraud and market rig-ging.”

The president’s plan centers on pro-viding more manpower and technologyto the Commodity Futures TradingCommission.

“I’m pleased the Obama administra-tion is finally proposing tough newactions to rein in oil speculators, whoseactions have slowed our economicrecovery,” Begich said in an April 17press release. “It’s easy to blame ‘bigoil’ for high oil prices, but in fact it’s thelargely unregulated speculators whodrive up prices, forcing many drivers inAlaska and across the country to paymore than $4 a gallon for gas. The costof speculation is estimated at 56 centsfor every gallon of gas.”

Court brief filedOn April 13, Begich and 18 of his

Senate colleagues filed an amici curiaeor “friends of the court” brief in a law-suit now pending in U.S. District Courtin Washington, D.C.

Two trading industry groups, theInternational Swaps and DerivativesAssociation and the Securities Industryand Financial Markets Association, suedthe CFTC in an effort to block a newregulation to impose position limits onthe trading of commodities on U.S. mar-kets, a Begich press release said.

A key issue in the suit is whetherCongress, in passing the Dodd-FrankWall Street Reform and ConsumerProtection Act of 2010, mandated thatthe CFTC establish position limits ormerely gave the agency the option to doso if needed.

The intent of position limits is torestrict the ability of any single trader tomanipulate oil markets.

“High gasoline prices are choking oureconomic recovery,” said Michigan Sen.Carl Levin, who led the effort to file theamici brief. “Oil supplies are plentifuland demand is down, so high gas pricescan’t be explained by ordinary marketforces of supply and demand. An ongo-ing contributing factor is excessive spec-ulation in U.S. commodity markets. Twoyears ago, the Dodd-Frank Act directedthe CFTC to clamp down on excessivespeculation by imposing trading limitson speculators, and the CFTC issued anew regulation to do just that. The finan-cial industry slapped the CFTC with alawsuit claiming Congress never meantfor the trading limits to prevent exces-sive speculation to be mandatory, butour amicus brief shows that is exactlywhat we meant and what the lawrequires.”

Aside from Levin and Begich, othersenators signing onto the amici curiaebrief included Richard Blumenthal ofConnecticut, Barbara Boxer of

California, Sherrod Brown ofOhio, Maria Cantwell ofWashington, Ben Cardin ofMaryland, Dianne Feinstein ofCalifornia, Tom Harkin ofIowa, Patrick Leahy ofVermont, Joe Manchin of WestVirginia, Claire McCaskill ofMissouri, Robert Menendez ofNew Jersey, Barbara Mikulskiof Maryland, Bill Nelson ofFlorida, Bernie Sanders of Vermont,Jeanne Shaheen of New Hampshire,Sheldon Whitehouse of Rhode Islandand Ron Wyden of Oregon.

Obama’s plan, and reactionObama’s five-part plan includes a

request that Congress fund more “copson the beat” to oversee oil markets. Hewants “at least a six-fold increase in thesurveillance and enforcement staff foroil futures market trading at the CFTC,”

a White House fact sheet said.The president also wants

funding for information tech-nology upgrades at the CFTCto “strengthen monitoring ofenergy market activity.”

And Obama proposed “aten-fold increase in maximumcivil and criminal penalties formanipulative activity in oilfutures markets.”

House Speaker John Boehner, R-Ohio, panned the Obama plan as a “gim-mick.”

“The White House can’t produce oneshred of evidence that this manipulationis taking place. And if they thought itwas taking place they have the tools andthe laws already in place to go after it,”Boehner said.

American Fuel & PetrochemicalManufacturers, a trade association, saidthis:

“To the extent that there is anymanipulation in the marketplace, thegovernment should investigate and takecorrective actions. Historical data showsspeculators are not the primary forceimpacting prices at the pump. In fact,U.S. refiners count on financial marketsto hedge against potentially higher crudeoil costs, which work to prevent con-sumer costs from increasing further.

“We have vast untapped resourcesunder our feet and off our shores andavailable from our good friend andneighbor Canada via the Keystone XLpipeline. If the president is serious aboutmeeting our energy and national securityneeds, it’s time we take the appropriatesteps to increase our North American oiland natural gas production and bring ournation back to economic prosperity.” �



Senators weigh in on commodity lawsuitThey say Congress meant for regulators to impose trading limits to curb ‘excessive speculation’ on oil; Obama offers get-tough plan

SEN. MARK BEGICH


http://www.fairweather.com


A laska’s congressional delegation hasraised concerns about a draft envi-

ronmental impact statement, or DEIS,that the National Marine FisheriesService, a division of the NationalOceanic and AtmosphericAdministration, has prepared for Arcticoffshore oil and gas exploration.

The Fisheries Service published theDEIS in December for public comments

with, as reported by Petroleum Newsshortly afterwards, the intention of havingan EIS that would establish future poli-cies for the issue of marine mammalharassment authorizations for explorationdrilling in state and federal waters off-shore northern Alaska, and for the issueof geophysical permits for seismic sur-veys on the federal Arctic outer continen-tal shelf. The EIS would apply to theyears 2012-17.

The Fisheries Service has not yetdecided on its preferred option from arange of alternative policies presented inthe DEIS, but all of the alternatives wouldplace restrictions on exploration activi-ties, with those restrictions ranging froma possible ban on all exploration to limitson the amount of drilling or seismic sur-veying that could be carried out in a sin-gle year.

Lubchenco meetingIn a statement issued on April 18 the

three members of Alaska’s congressionaldelegation said that they had met withNOAA Administrator Jane Lubchenco toemphasize the importance of oil and gasexploration and development in theArctic offshore and to raise concernsabout the effects that the EIS might haveon oil and gas activities. The delegationnoted that the more aggressive alterna-tives in the EIS would prevent Shell,Statoil and ConocoPhillips from conduct-ing simultaneous drilling in the ChukchiSea.

“I understand the importance ofNOAA’s role in ensuring explorers in theArctic avoid conflicts with marine mam-mals but, as it stands, the DEIS is flawedand goes beyond the agency’s missionand expertise,” said Sen. LisaMurkowski.

“I appreciate AdministratorLubchenco taking the time to hear from aunited delegation on this pressing issue,”said Sen. Mark Begich. “We all under-stand that marine mammals are impor-tant, but the document, as it stands, isflawed. I believe she understands that andam encouraged about our prospects toimprove it moving forward.”

“As I made clear to AdministratorLubchenco today, this document — aswritten — is not only troubling to me, butto the entire Alaska delegation,” said Rep.Don Young. “Moving forward, it’s impor-tant that this document advances not hin-ders responsible development in theArctic, and after today’s meeting,Administrator Lubchenco understandsour concerns.” �


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EXPLORATION & PRODUCTIONBOEM requests comments on Ion survey

The Bureau of Ocean Energy Management has asked for public comments foran environmental assessment for a seismic survey that Ion Geophysical plans tocarry out in Alaska’s Beaufort Sea during the early winter of 2012. Ion hasapplied for a BOEM geological and geophysical permit for its planned survey:Under the terms of the National Environmental Policy Act BOEM has to conductan assessment of the potential environmental impacts of the project. Public com-ments are required by April 30.

Ion has developed a technique for gathering seismic in sea ice, using a geo-physical vessel working in tandem with an icebreaker. The geophysical vesseltows a streamer of seismic recorders deeper in the water than usual, allowing therecorders to operate below the ice. By thus operating after the end of the Arcticopen water season Ion says that it can avoid conflicts with subsistence whalehunting.

Ion wants to carry out a deep, basin-wide 2-D survey along the entire lengthof the U.S. Beaufort Sea and into the northeastern Chukchi Sea, connecting sur-veys that the company has previously conducted in the Canadian Beaufort Seawith a similar survey conducted in 2006 in the Chukchi Sea. The survey wouldprovide insights into large-scale geologic features in the Beaufort Sea continen-tal shelf.

In March Ion told the National Marine Fisheries Service’s Arctic Open WaterMeeting that the company anticipates recording 7,177 kilometers of seismic linesin the Beaufort, operating in nine-tenths to ten-tenths cover of ice less than twofeet thick.

—ALAN BAILEY

� G O V E R N M E N T

Alaska congressionaldelegation questionsArctic offshore DEISSays document addressing future Arctic offshore permitting isflawed and threatens excessive restrictions on offshore exploration

The delegation noted that themore aggressive alternatives in the

EIS would prevent Shell, Statoiland ConocoPhillips from

conducting simultaneous drillingin the Chukchi Sea.


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FINANCE & ECONOMYMGM writes down Arctic assets

Northern Canadian explorer MGM Energy has joined the write-down of resourcesrelated to the troubled Mackenzie Gas Project by reducing the value of its Arcticassets by 70 percent while shifting its attention to the Central Mackenzie Valley.

The one active driller in the Mackenzie Delta region in recent years, MGM post-ed a net loss of C$153.3 million for the fourth quarter of 2011, due mainly to writ-ing down its northern holdings to C$60 million from C$214 million.

It said the move reflects the significant decrease in forecasted long-term naturalgas prices and the continued delay in restarting the Mackenzie Valley pipeline.

Company President Henry Sykes said MGM holds to its belief that its substantialnatural gas assets in Canada’s North hold tremendous potential which will eventual-ly be realized.

But, without offering any specifics, he said that given the current uncertain tim-ing of the Mackenzie pipeline MGM is considering alternative means of commer-cializing the Mackenzie Delta assets.

Concentrating on Canol shaleSykes said in a statement that MGM is concentrating on advancing the regulato-

ry process for the Canol shale rights it obtained last year.MGM had working capital of C$10.7 million at the end of 2011, enough to fund

current expenditure levels into 2013, but not sufficient to fund the cost of a CentralMackenzie Valley well next winter.

As a result, MGM said it is looking at various forms of financing, including far-mouts, joint ventures, asset sales and/or equity issues, adding it anticipates consider-able interest in its land position.

The company believes it will attract the necessary financing because of the cur-rent and pending activity in the Canol play, notably the large successful bids on adja-cent parcels by Husky Energy, ConocoPhillips Canada, Shell Canada, Imperial Oiland ExxonMobil Canada, along with MGM and its partner 6362 NWT Ltd.

—GARY PARK

F&W issues new polar bear ESA ruleOn April 19 the U.S. Fish and Wildlife Service published for public review a new

rule for the protection of polar bears under the Endangered Species Act, or ESA. Thenew rule replaces a similar rule issued in December 2008.

In May 2008 Fish and Wildlife listed the polar bear as threatened under the ESAon the grounds that the bear’s sea ice habitat is being eroded by global warming. But,recognizing the difficulty of using the ESA to regulate the greenhouse gas emissionsthat many blame for rising world temperatures, the agency subsequently issued aspecial rule for the polar bear listing. That rule said that activities outside Alaska can-not be considered as harassment of the bears; the rule also allowed the bears to beconserved under the terms of the Marine Mammals Protection Act.

Environmental groups, who argued that the polar bear listing required Fish andWildlife to address greenhouse gas emissions, appealed the polar bear rule. InOctober 2011 Judge Emmet Sullivan in the U.S. District Court in Washington, D.C.,rejected this claim but upheld another claim that the agency, in issuing the rule, hadneglected to carry out an environmental analysis of the impact of the rule, as requiredunder the terms of the National Environmental Policy Act.

The agency says that it has now completed the environmental analysis requiredby the court — the proposed new rule contains the findings of that analysis and isalmost identical to the original rule. However, the proposed new rule exempts activ-ities outside the polar bear’s range from being considered as harassment, rather thanactivities outside Alaska.

Fish and Wildlife requires comments on its proposed rule by June 18.—ALAN BAILEY

GOVERNMENT

went well for us — we had a strong logis-tics plan,” Hardham said.

And it was a particularly cold winter,with multiple days where operations hadto be shut in because of the low tempera-tures. The company even encountered apolar bear situation, with a sow and twocubs causing an interruption to the indus-trial operations.

“It approached our sea-ice road and sowe had to close down our operations andmonitor the bear,” Hardham said.

Taking advice from locals, the fieldcrew waited for the night and, with notraffic about, the bears crossed the roadand headed north towards the sea.

Return next winterDespite the challenges, Repsol plans

to return to the North Slope next winter.“We’ll be looking at a program next

winter,” Hardham said. “We need to eval-uate the results of the two wells that we

drilled and we would be looking to permitat a minimum the two locations that wedid not get to drill this winter, the Q-1 andQ-2.”

Repsol feels confident about findingoil in its acreage. But, with expectationsof finds that are fairly modest in size,development costs and production taxlevels will be key factors in the viabilityof field development, Hardham said.

And Repsol hopes that the open man-ner in which company dealt with govern-ment agencies and the local communitieswhen responding to the Q-2 incident hasgained everyone’s respect, he said.

“We hope we’ve gained some respectin how we reacted to this and how weconducted ourselves,” Hardham said.“We’re not disheartened going forward.Obviously it’s a setback and it’s costly,but we intend to proceed. The company isquite enthusiastic about the opportunitiesup here.” �


REPSOL WELLS


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our members join together as syndicatesto insure risks.” Lloyd’s says it’s often thefirst to insure new, unusual or complexrisks.

Arctic risks are in many ways particu-larly daunting, but companies are likely tobrave those risks if, for example, oil pricesstay high, the study says.

‘Increasingly significant’The Lloyd’s report notes that prior to

the 20th century, “the overall role andscale of the Arctic in the global economywas minimal.” It wasn’t until the secondhalf of the century that the Arctic becamea significant factor in oil production withthe startup of Alaska’s Prudhoe Bay fieldin 1977.

Today, the Arctic — comprising theArctic areas of Canada, Denmark(Greenland), Finland, Iceland, Norway,Russia, Sweden and the United States —has about one-twentieth of 1 percent ofthe world’s total population, the reportsays.

“The Arctic region is undergoingunprecedented and disruptive change. Itsclimate is changing more rapidly thananywhere else on earth,” the report says.“The combined effects of global resourcedepletion, climate change and technologi-cal progress mean that the naturalresource base of the Arctic — fisheries,minerals and oil and gas — is nowincreasingly significant and commerciallyviable.”

In terms of Arctic access, however, thewarming climate has “double-edged con-sequences.” Sea-borne access is improv-ing as ice cover dissipates. But on land,infrastructure such as roads and pipelinesbuilt on permafrost will become moreexpensive to maintain, the report says.

Oil and gas landscapeThe report offers a brief country-by-

country summary of oil and gas invest-ments in Canada, Greenland, Norway,Russia and the United States, and discuss-es political, market, tax and environmen-tal risk considerations.

“In general, the Russian Arctic is con-sidered to be more gas-prone and the off-shore Norwegian and American Arctics(including Greenland) more oil-prone,”the report notes.

High oil prices, coupled with uncer-tainly about access to resources else-where, make Arctic projects more attrac-tive to investors.

“Falling commodity prices wouldprobably put many Arctic projects onhold,” the report says.

“For the most commercially marginalArctic oil and gas developments, the taxregime applied may be a decisive factor indetermining their viability,” it adds.

In Russia, the largest potential offshoreproject is the Shtokman gas developmentin the Barents Sea. Investment couldreach $50 billion.

“However, the Shtokman project hasbeen repeatedly delayed owing to con-cerns about drifting icebergs, negotiationsover the tax regime with the Russian gov-ernment, and concerns about export mar-kets,” the report says.

Investment in Norway’s Arctic fields ismore predictable, given that country’s“arguably more stable regulatory andoperating environment.”

In Alaska, the report’s authors makenote of Shell’s long-frustrated plans todrill in the Beaufort and Chukchi seas, andsee “an increasingly supportive approachtaken by the Obama administration toArctic development.”

Politics and risk“Within most Arctic countries, oil and

gas development is politically controver-sial on environmental grounds and canhave a significant influence on the politi-cal dynamics between central and localgovernments,” the Lloyd’s report says.

In the United States, support for open-ing more Arctic areas to oil and gas explo-ration is strong in Alaska, but limited else-where.

“In Canada, Arctic energy and miningprojects play into complex federal politicsand the domestic politics of indigenouspeoples across the north,” the report says.“In Greenland, exploration for offshorehydrocarbons is widely accepted as apathway to greater economic prosperityand a guarantee of self-government. InRussia, maintaining oil production andincreasing production of natural gas is astrategic imperative. In Norway, govern-ment and public support for developmentis contingent on strong environmental reg-ulation.”

As for environmental risk, the remoteArctic presents a special case, the reportsays.


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.

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

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Corporate PartnersABR, Inc.Accent Alaska.com-Ken Graham AgencyAlaska Business Monthly Alaska Rubber & Supply, Inc.Alaska Steel CompanyAlaska Wildland Adventures Alyeska Pipeline Service Company American Marine Corporation Arctic Slope Regional CorporationArctic Wire Rope & SupplyBristol Bay Native Corporation Calista Corporation

Carlile Transportation Systems, Inc. Chevron CIRI Clark James Mishler Photography CONAM Construction Company Denali National Park Wilderness Centers, Ltd. Fairweather, LLCFlint Hills Resources Holland America Lines Westours, Inc. Kim Heacox PhotographyKoniag, Inc.LGL Alaska Research Associates, Inc.

Thank You

The Nature Conservancy715 L Street . Suite 100 . Anchorage, AK 99501 . [email protected] . 907-276-3133 . nature.org/alaska

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Fish printing workshop at Salmon Camp, a conservation program of the Bristol Bay Economic Development Corp. with support from The Nature Conservancy

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First drillsite design, facilitiesPioneer plans to build NDS1 first,

using about 275,000 cubic yards of grav-el.

NDS1will support drilling and produc-tion operations, the company said.

The drillsite will encompass about 23acres, and be designed to support as manyas 50 wells on 30-foot spacing.

The spacing between the wells is“based on potential drilling rigs capableof reaching the reservoir targets and tominimize the thawing of the permafrostsoil,” Pioneer said.

The pad is L-shaped with the base ofthe L to contain support facilities and theremaining area the row of wells.

Dimensions will be about 750 by 360feet for the support facilities section and300 by 1,600 feet for the well row, with anominal thickness of 8-10 feet of gravelfill, bringing the surface elevation toabout 12 feet mean sea level.

“Gravel bag slope erosion protectionwould be provided by a system of 1.5-4cubic yard gravel-filled bags,” Pioneer

said in its operations plan.

Second drillsiteThere is a chance the second drillsite,

NDS2, would be developed with the first,but Pioneer said it “will probably be con-structed near the end of the drilling cam-paign at NDS1.

NDS2 will be about 12 acres, designedfor as many as 15 wells.

Also L-shaped, the dimensions will beabout 750 by 360 feet for the supportfacilities section and 300 by 490 feet forthe well row, with a nominal thickness ofabout 5-7 feet of gravel.

The amount of gravel fill would beabout 120,000 cubic yards.

In Pioneer’s plan heated modularbuildings, production modules, would beinstalled at each drillsite. They would be15 by 40 by 14 feet high.

Pioneer’s proposed developmentschedule (see adjacent chart) includesmodule fabrication getting under way thisyear, the first pad built in 2013, anddevelopment drilling from 2014 through2018. �


NUNA PROJECTcontinued from page 1

ARCTIC REPORT

Contact Kay Cashman at [email protected]

see ARCTIC REPORT page 22

http://www.nature.org/alaska


Fairweather sponsors Petroleum Club event April 26 Fairweather LLC, an Anchorage-

based provider of remote medical,meteorological and expediting services,said April 16 that it will sponsor asocial event Thursday, April 26, from 5to 7 p.m. at the Petroleum Club ofAnchorage to unveil details about itsnew medical clinic at DeadhorseAviation Center on the North Slope.

Opening in June, the FairweatherMedical Services clinic will provide afull spectrum of acute care, emergencymedicine and occupational health serv-ices, including advanced cardiac life support, on-site labs and ambulance services. The clinicwill be open to the public and staffed around the clock, 365 days a year, with state licensedphysician assistants, paramedics and occupational health technicians. Medical services willinclude teleradiology, EKG tests, physical exams, pulmonary function testing, respiratory FITtesting, audiometry testing, and drug and alcohol screenings, as well as return-to-work and

fit-for-duty evaluations. The DAC clinic will offer 24-hour telemedicine consultation with theemergency room at Providence Hospital in Anchorage, as well as case management andMedEvac support for immediate hospital transport, if necessary.

The Petroleum Club of Anchorage is located at 3301 C Street, Suite 120. For additionalinformation, contact Lori Davey at 907-267-4602, e-mail: [email protected], orvisit www.deadhorseaviationcenter.com.

UAF makes mark at Shell Eco Marathon in HoustonShell said April 5 that colleges and universities

once again gathered in the sweltering heat ofHouston, Texas to participate in the 2012 ShellEco Marathon competition. But once again, itwas the scrappy team from the coldest, northern-most university in the United States that gar-nered a great deal of the attention.

A team of ten UAF engineering students notonly wrapped-up the 2012 marathon with anoth-

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But there is no longer anywhere for it tohide. By targeting an addition of 550,000bpd, Kinder Morgan has surpassed the525,000 bpd planned for Enbridge’sNorthern Gateway proposal.

It now hopes to file an application withCanada’s National Energy Board in 2014,start construction in 2016 and commenceshipments in 2017, close to the schedule setfor Northern Gateway.

Support existsThe indications are that both projects

have enough support to succeed.During an extended open season, Kinder

Morgan received binding commercial sup-port for 660,000 bpd of pipeline capacity,all for 20-year terms.

Ian Anderson, Kinder Morgan’sCanadian president, said the level of com-mitment equates to about 25 to 30 tankers amonth (compared with the current five to10) loading at the Westridge terminal inPort Metro Vancouver and navigatingthrough a densely populated area to thePacific Ocean.

He said the proposal has attracted somuch interest from customers because itoffers new access in Asia through a facilitythat already exists.

Anderson said the port, facilities, tankerpilots, tug operators and first-responders arealready in place, supporting a belief thatexpansion of Trans Mountain and theWestridge terminal “has merit … and is afeasible way to go.”

He said Kinder Morgan also has thebacking of the Alberta government andCanadian Prime Minister Stephen Harper.

“We share respectful, open relationshipswith many communities and organizationsinterested in our business,” Anderson said.“We are committed to an 18- to 24-monthinclusive, extensive and thorough engage-ment of all aspects of the project with localcommunities along the proposed route andmarine corridor …”

He said Kinder Morgan will considerproviding financial support to communitiesfor environmental initiatives.

Testing to comeBut Anderson`s confidence that the peo-

ple of British Columbia will ultimately sup-port Kinder Morgan’s proposal is about tobe tested.

Opposition to Northern Gateway fromFirst Nations, environmentalists, landown-ers and municipal governments took yearsto surface, but has now coalesced into a for-midable challenge.

Feeding off that campaign, the samegroups, bolstered by municipal govern-ments in the Greater Vancouver region,have wasted no time tackling KinderMorgan, setting the stage for a battle thatcould rival U.S. opposition toTransCanada’s Keystone XL pipeline andfar exceed Northern Gateway, which direct-ly affects a small and scattered population.

Ben West, a spokesman for theWilderness Committee, said the 40 percentincrease in what Kinder Morgan had origi-nally talked about will only strengthen pub-lic efforts to halt the project he described as“simply outrageous.”

“Every new tanker that is in (PortMetro Vancouver) is carrying at least twoto three times as much crude as the ExxonValdez spilled. More tankers mean more

risk,” he said.

Opposition from VancouverVancouver Mayor Gregor Robertson

said he does not believe the people of hiscity endorse a “huge oil port. … It is totallyat odds with our city brand and our identityand ethic.”

“I am fiercely opposed to (an increasednumber of tankers) in Vancouver’s harbor.We are gearing up as a city to deal with this,working with other local governments inthe region and around the southern coast,”he said.

Burnaby Mayor Derek Corrigan said theKinder Morgan plan is a wrong-headeddecision that will generate no economicbenefit for his city.

“We are well aware of the potential dan-gers and even when people claim to have allthe safety procedures in place human errorcan cause a serious problem,” he said.

Corrigan acknowledged that theCanadian and British Columbia govern-ments can override local concerns, butargued the Trans Mountain proposal is sopolitically charged that Kinder Morganfaces many obstacles.

A spokesman for Kinder Morgan con-ceded the company faces a “lot of workspeaking to landowners and people on the(pipeline) right-of-way.” �


er impressive showing, they became the most talked-about team for their ability to useleftover scraps and parts to build cars that would eventually make it on the track. Makingmore with less, after all, symbolizes what Shell Eco Marathon is all about.

“This is the second time we’ve had UAF at Shell Eco Marathon and we are happy tohave them back,” said Shell Alaska VP, Pete Slaiby.

The idea behind Shell’s annual Eco Marathon competition is to design and build avehicle that uses the least amount of energy and travels the furthest distance.

Teams can enter futuristic “prototypes” that are designed to reduce drag and maxi-mize efficiency or they can enter “urban concept” vehicles that meet the needs of today’sdrivers. Entries in both divisions use conventional fuels like diesel and gas, or they canrely on alternatives — gas to liquids, solar, ethanol, bio-fuels, or electric plug-in power.

Golf Classic tees off Wednesday, June 20Calista Corp. said April 17 that it cordially invites you to kickoff the summer with the

13th Annual Calista Heritage Foundation Golf Classic Tournament, June 20 — the firstday of the new season at the Moose Run Golf Course.

Please join by fielding a team or becoming a sponsor. There are many donation levelsavailable for this well-attended event, but there are a limited number of team sponsor-ships. Be sure to take a swing at securing the hole-in-one prizes provided by MercedesBenz of Anchorage and Yukon Equipment.

The Calista Heritage Foundation awards scholarships to Alaska Native students fromthe Yukon-Kuskokwim Delta Region. These scholarships enable them to study engineering,business, aviation, medicine and biology to acquire skills they can apply to their commu-nities and society.

Last year, more than $200,000 was raised at the Golf Classic and the proceeds directlybenefited more than 200 students from the Calista Region.

The registration deadline is June 6, but don’t delay — teams fill up fast. For moreinformation visit www.calistacorp.com or call 907-279-5516 to signup.

Editor’s note: All of these news items — some in expanded form — will appear inthe next Arctic Oil & Gas Directory, a full color magazine that serves as a marketingtool for Petroleum News’ contracted advertisers. The next edition will be released inSeptember.


OIL PATCH BITS


PIPE DREAMSIan Anderson, Kinder Morgan’s

Canadian president, said the levelof commitment equates to about 25to 30 tankers a month (compared

with the current five to 10) loadingat the Westridge terminal in PortMetro Vancouver and navigatingthrough a densely populated area

to the Pacific Ocean.

Opposition to Northern Gatewayfrom First Nations,

environmentalists, landowners andmunicipal governments took yearsto surface, but has now coalesced

into a formidable challenge.


http://www.alaskacargo.com


Senate, with senators saying they neededmore information before making taxchanges.

So the session ended with no majorchanges in the state’s oil tax system.

Within the hour of legislators gavelingout the governor had called a special ses-sion to begin April 18, with the oil taxissue, House Bill 9 (the in-state gaspipeline bill) and HB 359, sex trafficking,on the agenda.

‘A new dynamic’At an April 16 press conference the

governor said he was interested in theapproach the Senate took in HB 276, andsaid with the “Senate’s action there’s anew dynamic now at work that I thinkmight lead to a compromise that couldproduce new production, both now and inthe future.”

Parnell said the Senate proposal wasn’tthe whole answer because any new oildiscovered as a result of the creditswouldn’t be going into the pipeline for anumber of years, and he was concerned“that vast resources in our legacy fieldswill remain untapped.”

The governor also said the Senate’sapproach, focusing only on new fields,“will cost the state billions of dollarsacross 10 years while we have decliningproduction and no new revenues fromnew production.”

He cited the example of a companyproposing to spend $9 billion in the stateover the next 10 years on new fields.Under the state’s existing tax structurethat company would get credits ofbetween 45 and 65 percent, “so the statewill pay half of the cost of that explo-ration across the next 10 years,” meaningthe state would have to come up with $4billion to $6 billion in that timeframe,while production from existing fields isdeclining.

The governor said he wants to see aproposal which would incentivize newproduction from existing fields, alongwith new field production, and believesthat with “a significant tax change inexisting fields” the state could see asmuch as 100,000 new barrels a day “with-in a year and a half or two years.”

“I want to see whether we can takewhat the Senate has already agreed ismeaningful in the new field context and

make it material enough to do the same inexisting fields,” Parnell said.

If the Legislature reaches an impasse,Parnell said he would understand.

“But I think it’s worth a try to create acompetitive environment where moreproduction can be produced,” he said.

HB 9On House Bill 9, a bill moving along

work on a small-diameter in-state gaspipeline, Parnell said that if the key pro-visions in HB 9 don’t pass, “Alaska’s gasline efforts, in my view, will be set backfor one to two years.”

The governor said he was asking theHouse and Senate to waive the uniformrules and take up HB 9 where it was whenthe session ended; both bodies did thatApril 18.

Parnell said he disagrees with HouseSpeaker Mike Chenault on whether theAlaska Gasline Development Corp. needsto come back to the Legislature before apipeline gets built, and said he’s “not try-ing to empower AGDC at this moment togo and contract and have an open seasonand sanction a pipeline; I think we have tohave some gates they have to go throughwhere they are held accountable by theLegislature and by the executive.”

On the other hand, the governor saidhe doesn’t agree with legislators whobelieve AGDC’s “efforts should be killedoff.”

“I’m not in that camp,” he said,explaining that the state needs alterna-tives — the large line from the NorthSlope to markets and the smaller in-stateline — because without an option, theprocess would slow down, as it did underthe Stranded Gas Act negotiations “whenone party’s negotiations were swept off tothe side and ... the process slowed downand the state had no other alternative.”

The new billThe governor submitted a new oil tax

bill to the House and the Senate April 18,describing it as “a piece of legislation thatblends the positions of the House and

Senate into a comprehensive approachthat will bring economic opportunity toAlaskans for generations to come.”

New North Slope oil and gas produc-tion is incentivized with a 30 percentexclusion, based on gross value at thepoint of production or GVPP, from theproduction tax value used to calculate thebase rate and progressivity for the first 10years of sustained production. Thisapplies to fields not in production or in aunit on Jan. 1, 2008 — which wouldexclude Point Thomson but includeOooguruk and Nikaitchuq.

For currently producing North Slopefields, there is an exclusion, but only fromthe value used to calculate progressivity:40 percent of the GVPP would be exclud-ed from the monthly production tax valueused to calculate progressivity; progres-sivity would be capped at 60 percent.

The bill also extends tax incentives forwell lease expenditures available else-where in the state to North Slope activi-ties and allow producers to apply taxcredits in one year.

The new-oil provisionSo what would the 30 percent exclu-

sion in calculating base rate and progres-sivity for the first 10 years of sustainedproduction look like?

Senate Finance had PFC Energy modelthe lifecycle effects for a new smalldevelopment — a 70 million barrel fieldwith peak production of 10,000 barrelsper day at $100 oil.

Finance co-Chair Bert Stedman, R-Sitka, said at the April 14 hearing whenthe proposal was first aired publicly thatthe “concept of the 30 percent gross rev-enue allowance was derived out of ourprevious work on trying to enhance newoil production” with a gross progressivitycalculation, and is an approach to incen-tivizing oil outside of existing develop-ments within the current ACES structure.

Gerald Kepes, a partner in PFC Energyand head of the consultancy’s upstreamand gas practice, showed models run atthe 30 percent gross revenue allowancefor new developments at three differentdevelopment costs: $17 per barrel; $25per barrel; and $34 a barrel.

Kepes said with a $17 per barrel capi-tal cost under the current tax, Alaska’sClear and Equitable Share or ACES, alifecycle analysis showed a net presentvalue or NPV of $112 million and aninternal rate of return or IRR of 16 per-

cent, with total government take rangingfrom 67 percent at $60 oil to 75 percent at$100 oil and 79 percent at $150 oil.

With the gross revenue allowance of30 percent applied to ACES, NPV rose to$201 million and IRR to 20 percent; gov-ernment take ranged from 56 percent at$60 oil to 64 percent at $100 oil and 66percent at $150 oil.

“So it’s a substantial difference forthese lower-cost new developments,”Kepes said.

Capex of $25 a barrelAt development costs of $25 a barrel

for the same new development, whichKepes said “is more in line with the coststhat we see with these new developments... away from existing infrastructure,”NPR under ACES would be $24 millionand IRR 11 percent, with governmenttake ranging from 68 percent at $60 oil to75 percent at $100 oil and 79 percent at$150 oil.

At the $25 a barrel capital cost with the30 percent gross revenue allowance, NPVis $121 million and IRR 14 percent, withgovernment take ranging from 51 percentat $60 oil to 62 percent at $100 oil and 67percent at $150.

At a capital cost of $34 a barrel, whichKepes characterized as “among the high-er or highest cost rates that we’re lookingat,” under ACES NPV is a negative $90million and IRR 7 percent, with govern-ment take ranging from 80 percent at $60oil, to 77 percent at $100 oil and 79 per-cent at $150 oil.

With the 30 percent gross revenueallowance, NPV on this type of project isa positive $3 million and IRR 10 percent,with government take ranging from 49percent at $60 oil to 62 percent at $100 oiland 66 percent at $150 oil.

Legislators received a letter from 70 &148 LLC, a partner with Repsol in newdevelopments which have been cited atcapital costs of $9 billion over 10 years,expressing “strong support” for passage ofthe new oil provisions Senate Financeadded to HB 276, calling the new field taxchanges “exactly what is needed in orderto have the oil industry focus on Alaskaover other oil producing regions,” but alsonoting that the company hopes modifica-tions can be made in the tax code “thatwill make operations within the legacyfields more competitive as well.” �


SPECIAL SESSION

“The resilience of the Arctic’s ecosys-tems in terms of withstanding risk eventsis weak, and political sensitivity to a dis-aster is high. Worst-case scenarios may beworse in the Arctic because the ability tomanage evolving situations is limited byenvironmental conditions and the lack ofappropriate infrastructure.”

The authors conclude that majorspending on science and research isurgently needed to close “knowledgegaps” on the Arctic’s environmentalchange and geological potential.

They further conclude: “Full-scaleexercises based on worst-case scenariosof environmental disaster should be runby companies with government involve-ment and oversight to provide a transpar-ent account of the state of knowledge andcapabilities, to foster expertise and toassuage legitimate public concerns.”

Find the 60-page report online athttp://bit.ly/HDSRxo.

—WESLEY LOY


Contact Kristen Nelson at [email protected]


ARCTIC REPORT

... with the “Senate’s action there’sa new dynamic now at work that Ithink might lead to a compromise

that could produce newproduction, both now and in the

future.” —Alaska Gov. Sean Parnell

http://www.gci-industrialtelecom.com

“Putting together a funding facility ofthis type is a significant milestone forBuccaneer Energy,” said Dean Gallegos,executive director of Buccaneer Energy,when announcing the new financing. “Weare pleased to be working with thisprospective lender and we appreciate thecooperation of all our stakeholders whilewe work through the process. Buccaneeris firmly committed to its Alaska strategyand we are looking forward to progresson our Kenai Loop project, including ournext well at Kenai Loop and our first off-shore well later this year.”

Buccaneer completed its first well atKenai Loop, near Kenai airport, in May2011 and, having made a natural gas find,proceeded to develop a gas productionfacility connected to the Kenai gaspipeline infrastructure. The company alsodrilled a second Kenai Loop well thatturned out to be a dry hole.

The first well, the Kenai Loop No. 1,went into production in January, supply-ing gas at the rate of 5.1 million cubic feetper day.

Kenai Loop contractorsBut it has emerged that Buccaneer still

owes considerable sums of money to thecontractors that have worked on theKenai Loop project.

Employees of several of these contrac-tors testified during the April 4 meeting ofthe Kenai City Council — the KenaiLoop surface facilities are located insidethe city of Kenai and Buccaneer hadasked the city to renew the company’sland use permit which had expired onMarch 1.

Sagen Juliussen, NANA Constructionvice president for business development,told the city council that his company hadexhausted the options for coming to termswith Buccaneer and that he was con-cerned about Buccaneer’s talk of furtherdevelopments when the company had notyet paid for work already completed.

“If they continue to do business theway they’re doing, they’re going to runout of contractors and venues … inAlaska because people aren’t going tojump on board,” Juliussen said.

On March 30 Nana Construction fileda claim of lien for $5.1 million againstBuccaneer for work that Nana had com-pleted for the Kenai Loop project, includ-ing the tie-in in of the well head to the gasmetering pad and a substantial amount ofcivil work at the facility.

“We’re not here to shut anyone down,”said a NANA Construction worker whotold the council that Buccaneer had at thispoint paid a bit less that 10 percent ofwhat it owed. “To the contrary we would

like to make sure that there is more devel-opment in the state. But it needs to beresponsible development.”

Need paymentMike Sheppard, district manager for

Conam Construction, told the council thatBuccaneer owed his company money.Commenting that everyone wants smallcompanies like Buccaneer to progressnew developments in the Kenai area,Sheppard said that the community hadexecuted the Kenai Loop project safelyand in an exceptionally short time. Butthe people now need payment, he said.

Representatives from Inlet Drillingsaid that their company had already paidmoney into the community as a conse-quence of its involvement in the KenaiLoop project but that Buccaneer stillowed Inlet Drilling a substantial sum ofmoney for the work.

“You could probably more than halffill this room with the people they owemoney to,” said one of the company’srepresentatives.

During a discussion about the renewalof Buccaneer’s land use permit membersof the city council expressed sympathywith the contractors’ plight while alsosaying that the city could not involveitself in a business dispute. Some councilmembers also expressed their desire thatBuccaneer’s ventures in the Cook Inletbasin should succeed.

Short-term permitHowever, concerned about the poten-

tial ramifications of a “mechanic’s lien”against property on city land, the councilvoted to only issue a new special use per-mit for Buccaneer’s operations up to May4, rather than for the term of one year thatBuccaneer had requested. The idea was toallow some time for the city administra-tion to determine how to protect itselffrom any financial liability relating to thelien. The council anticipates making adecision on a longer term permit at itsMay 1 meeting.

In recent months Buccaneer has beendescribing ambitious exploration anddevelopment plans including the drillingof a further well at Kenai Loop; the shoot-ing of a seismic survey and the drilling ofan exploration well in the southern KenaiPeninsula; and a program of offshoredrilling in the Cook Inlet using a jack-updrilling rig.

In a quote emailed to Petroleum Newson April 19, Gallegos said that since thebeginning of 2011 Buccaneer had putmore than $30 million into the Cook Inletregion and had hired more than 130 ven-dors for a variety of projects.

“We are currently working withNANA to resolve the issues surroundingtheir invoices,” Gallegos said. “Senior

management has been in discussions withthe company and continues to worktoward a suitable resolution. We look for-ward to a speedy outcome, but moreimportantly to continuing our corporatecitizenship with the state and to being amajor employer for the citizens ofSouthcentral Alaska for years to come.”

Glacier rigIn announcing the purchase of the

Glacier drilling rig, the rig already used todrill the wells at Kenai Loop, Buccaneersays that it anticipates being able to leasethe rig to other companies as well asusing the rig for its own drilling projects.

“The purchase of the Glacier rig is asignificant milestone and key componentof our onshore Alaska strategy, as it willallow us to immediately secure enablingassets in the Cook Inlet,” Gallegos said.“The purchase of the rig ensures timelydrilling of our Kenai Loop project andalso assists in the control of costs associ-

ated with the project.”The jack-up rig that Buccaneer plans

to use for its offshore drilling has beenpurchased by a joint venture betweenBuccaneer and Ezion Holdings Ltd.involving a public-private partnershipwith the Alaska Industrial Developmentand Export Authority, or AIDEA. AIDEAis contributing up to $24 million to thejack-up rig acquisition.

AIDEA spokesman Karsten Rodviktold Petroleum News April 16 thatAIDEA’s only involvement withBuccaneer concerns the deal to obtain thejack-up rig. The rig is currently in aSingapore shipyard undergoing upgrades,in preparation to set out for Alaska in thelate spring, he said.

“We’re looking forward to it getting toAlaska and commencing work in theCook Inlet this summer,” Rodvik said.�


The reasons behind the lower-than-expected number of wells drilled includ-ed everything from a shortage of rigs orrig crews for UltraStar and Linc, to thechallenges Repsol faced with gettingapproval from the North Slope Boroughfor five ice pads, three wells each. Itstarted the season with green light todrill from four pads, but with only threerigs running at any one time.

Then Repsol had a blowout at one ofits pads and although the equipmentworked as expected, no one was hurtand no oil was spilled on the tundra, the

company was forced to kill drillingplans at that pad and one other, as wellas delayed from re-starting drilling else-where.

Brooks Range cut its well count fromtwo to one at its Mustang prospectbecause it got all the information itneeded from the first well, and is pro-ceeding with development.

Savant’s permitting was held up afterthe Repsol blowout — one agencywanted to give all well plans a closerand longer look — otherwise it wouldhave likely been finished drilling bynow.

—KAY CASHMAN


TIGHT SITUATION


EXPLORATION UPDATE


Contact Kay Cashman at [email protected]

http://www.totemocean.com

http://www.matsystems.ca


exxonmobil.com

Committed to responsibly developing Alaska’s natural resources

http://www.exxonmobil.com

Documents

OFFICE OF THE FEDERAL …