l N A T U R A L G A S

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

l N A T U R A L G A S

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Q&A: SB 138 clears Finance, Kellytalks about equity plan issues

Vol. 19, No. 12 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 23, 2014 • $2.50

ALY

ESK

A P

IPEL

INE

SERV

ICE

CO

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Due to declining North Slope crude production, only four pumpstations along the trans-Alaska pipeline currently are used tomove oil: 1, 3, 4 and 9. Even retired stations contribute to lineoperation (see story page 7).

Fewer operating

SB 138 in HouseGovernor’s proposal for state equity in LNG project passes Senate 15-5

By KRISTEN NELSONPetroleum News

Senate Bill 138, Gov. Sean Parnell’s legislationenabling the state to take an equity share in the

Alaska LNG project, has passed the Senate.Hearings began in House Resources March 19.

The 15-5 Senate floor vote on SB 138 cameMarch 18 following hours of debate on amend-ments proposed by minority Democrats, none ofwhich passed. The Senate did approve, withoutobjection, an amendment by Sens. Mike Dunleavy,R-Wasilla, and Lyman Hoffman, D-Bethel, tochange the name of a fund established in the bill.The rural capital energy fund became the Alaska

affordable energy fund, which Dunleavy said inintroducing the amendment reflected the intentionthat all sections of the state would benefit.

The fund, which Hoffman added to the bill inSenate Finance, would use 10 percent of revenuefrom state royalties transported in an Alaska LNGproject — after payment to the Alaska permanent

CD-5 work to proceedFederal judge declines to halt construction of ConocoPhillips Alaska oil project

By WESLEY LOYFor Petroleum News

A federal judge has denied a motion to stopconstruction on the CD-5 oil project within

the National Petroleum Reserve-Alaska.The ruling cheered ConocoPhillips Alaska Inc.,

the project developer. A work stoppage now, smackin the middle of the short winter construction sea-son, would have been enormously troublesome andexpensive, the company argued.

U.S. District Judge Sharon Gleason’s March 12decision comes in a case in which some residentsof Nuiqsut, a predominantly Inupiat Eskimo vil-lage near the CD-5 site, are suing to challenge the

federal permit issued for the project.In her 12-page order, Gleason questioned the

timing of the motion, saying it appearedConocoPhillips was correct in asserting the villageplaintiffs waited to file for an injunction “until themoment it would inflict the maximum possible

Shuffles, hiccups in LNGMalaysia’s Petronas locks up potential gas supplies in BC; Enbridge secures land

By GARY PARKFor Petroleum News

Shuffling and maneuvering among the key play-ers in British Columbia’s LNG field continues

unabated.The latest developments that reinforce who the

serious contenders are — assuming the pundits areaccurate that no more than three of a dozen large-scale ventures will ever get to the starting line —involve Malaysian global super-major Petronas andCanadian pipeline power Enbridge.

But trouble is looming for what is supposed to bethe lead off project.

The minnow BC LNG Cooperative venture,which was scheduled to start exports by either late2015 or early 2016, is suddenly seeking courtapproval to reorganize under the Companies’

Creditors Arrangement Act, which allows financial-ly-troubled corporations to juggle their affairs.

Operator Houston-based equity firm LNGPartners, with the Haisla First Nation and Bermuda-based shipping company Golar as partners, is unableto pay its creditors more than C$100 million, accord-ing to a Supreme Court of British Columbia filing.

LNG Partners is reportedly seeking an agreementwith Calgary-based utility AltaGas, along withBelgium-based Exmar NV and gas marketer EDTTrading, leaving the Haisla and Golar to pursue aseparate project.

Rounding up gasState-owned Petronas, operator of the Pacific

NorthWest LNG project, showed how serious it is

Pioneer lowering Oooguruk pricePioneer Natural Resources is dropping the price of its

Alaska subsidiary.Under an amendment to a sale agreement announced last

year, the Texas-based independent will now sell its PioneerNatural Resources Alaska Inc. subsidiary to Caelus EnergyAlaska LLC for some $300 million, the companies announcedMarch 13.

The original deal announced last October called for the pri-vately held Caelus to pay $550 million for the subsidiary,which operates the Oooguruk unit on the North Slope.

The amended deal is expected to close in the second quar-ter, retroactive to the start of the year, according to Pioneer.The original deal was supposed to close by the end of 2013.

Under the amendment, Pioneer expects to report a $30 mil-lion noncash loss in the first quarter of the year, in addition tothe $350 million noncash loss expected last year.

Caelus said it will take on a $300 million second-lien termloan and a $115 million asset based loan facility to fund thepurchase and to provide working capital for its operations.

Caelus declined to comment further on the amendment. —ERIC LIDJI

Shell CEO sees Alaska challenges,potential; hard decisions needed

In an investor presentation on March 13, accompanyingShell’s publication of its 2013 annual report, Ben VanBeurden, the company’s new CEO, characterized Shell’sAlaska Arctic program as one of some major initiativesdesigned for the company’s potential future growth, but wherethe current pause in activity demonstrates the company exert-ing discipline in its capital spending on programs that are stillin their relative infancy.

“There’s a clear capital ceiling in the company and so weneed to take some hard choices, and this means looking moreclosely at our options at an earlier stage and asking ourselves‘are these indeed the projects? Are these projects really a goodfit for Shell?’” Van Beurden said.

Along with “no drilling this year in Alaska,” Van Beurdencited a U.S. gas to liquids plant and liquefied natural gasdevelopment in the Asia Pacific region as projects on pause,where hard decisions are needed.

Court decisionShell’s annual report contains a section on its Alaska explo-

ration program, citing a 9th Circuit Court of Appeals decision

see SHELL IN ALASKA page 15

see SB138 page 14

see CD-5 WORK page 15

see LNG MANEUVERING page 16

Gleason also found that an injunctionwasn’t in the public interest. She noted, for

example, that “residents from variousNorth Slope Borough communities,

including Kuukpik shareholders who live inNuiqsut, could lose their jobs and income.”

Senate Finance amended the bill toincrease the tax on gas from 10.5 percent

to 13 percent. That tax, combined withthe state’s royalty, would give the state a

25 percent equity stake in the project.

2 PETROLEUM NEWS • WEEK OF MARCH 23, 2014

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

10 Apache gathering more Cook Inlet seismic

10 BSEE to fund spill response research

10 State sues Williams and Flint Hills

15 Economic challenges for cellulosic ethanol

4 Umiat well reaches target depth

9 Shale drilling efficiency increasing

EXPLORATION & PRODUCTION

5 Kelly steers LNG bill through Finance

Fairbanks senator talks about issues his committee faced with enabling legislation giving Alaska an equity stake in an LNG project

4 MGM Energy close to fading

Describes NWT regulatory process as too complicated,unpredictable and costly for small company; NWT promises improvement

13 Goldsmith counsels state to trim spending

University economist surveys Alaska’s savings andexpected oil revenue and predicts calamity with ‘business as usual’ budgeting

11 DOE funding for methane hydrate research

Agency looking to share the cost of projects aimed at field tests in Arctic Alaska and the sampling of subsea deposits on the OCS

11 Alberta top of class

Leads Canada in job creation, economic growth, despiteuncertainties over major energy projects; windfall from oil sands forecast

14 Parnell continues to press on ANWR

State sues federal officials in bid to force them to consider the governor’s plan to conduct 3-D seismic survey of coastal plain

6 Return on natural gas long time coming

Persily cites differences, similarities to state’s 2002 efforts; sees value of TransCanada in letting state use cash elsewhere

7 They’re retired, but still relevant

Status, disposal plans updated for several pump stations no longer used to move North Slope crude oil down the trans-Alaska pipeline

9 US LNG exports vital for Canada

NATURAL GAS

PIPELINES & DOWNSTREAM

8 An independent operator for the grid?

Efficient and reliable operation of the evolving AlaskaRailbelt power transmission grid appears to depend on unified management

UTILITIES

FINANCE & ECONOMY

GOVERNMENT

Shell CEO sees Alaska challenges,potential; hard decisions needed

Pioneer lowering Oooguruk price

SB 138 in House

Governor’s proposal for state equity in LNG project passes Senate 15-5

CD-5 work to proceed

Federal judge declines to halt construction of ConocoPhillips Alaska oil project

Shuffles, hiccups in LNG

Malaysia’s Petronas locks up potential gas supplies in BC; Enbridge secures land

ON THE COVER

Alaska’sOil and GasConsultants

GeoscienceEngineeringProject ManagementSeismic and Well Data

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(907) 272-1232(907) 272-1344

www.petroak.cominfo@petroak.com

PETROLEUM NEWS • WEEK OF MARCH 23, 2014 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay DS 07-16A, workover BPDreco 1000 UE 16 (SCR/TD) Prudhoe Bay MPF-78, workover BPDreco D2000 Uebd 19 (SCR/TD) Alpine CD3-316B ConocoPhillipsAC Mobile 25 Prudhoe Bay B-19 BPOIME 2000 141 Flat Top 1, Exploration ConocoPhillipsTSM 7000 Arctic Fox #1 Rendezvous 3, Exploration Contracted to ConocoPhillips

Winter of 2013/2014

Kuukpik 5 Umiat Well 23H, Completing Linc Energy Operations Inc.

Nabors Alaska DrillingAC Coil Hybrid CDR-2 Kuparuk 2F-18 ConocoPhillipsDreco 1000 UE 2-ES (SCR-TD) Prudhoe Bay Available Mid-Continental U36A 3-S Prudhoe Bay AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay AvailableDreco 1000 UE 7-ES (SCR/TD) Kuparuk ConocoPhillipsDreco 1000 UE 9-ES (SCR/TD) Kuparuk ConocoPhillipsOilwell 2000 Hercules 14-E (SCR) Prudhoe Bay AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Available Emsco Electro-hoist-2 18-E (SCR) Prudhoe Bay StackedEmsco Electro-hoist Varco 22-E (SCR/TD) Prudhoe Bay StackedTDS3Emsco Electro-hoist Canrig 27-E (SCR-TD) Prudhoe Bay Available 1050EEmsco Electro-hoist 28-E (SCR) Prudhoe Bay StackedOilwell 2000 33-E Prudhoe Bay Available Academy AC Electric CANRIG 99AC (AC-TD) Working for Repsol RepsolOIME 2000 245-E (SCR-ACTD) Oliktok Point ENIAcademy AC electric CANRIG 105AC (AC-TD) Working for Repsol RepsolAcademy AC electric Heli-Rig 106-E (AC-TD) Working for Repsol Repsol

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site 9-47A BPSuperior 700 UE 2 (SCR/CTD) Milne Point Well Drill Site L-09 BPIdeco 900 3 (SCR/TD) Kuparuk Well 1D-108 ConocoPhillips

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

North Slope - OffshoreBPTop Drive, supersized Liberty rig Inactive BP

Doyon DrillingSky top Brewster NE-12 15 (SCR/TD) Spy Island SP24—SE1 ENI

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

Cook Inlet Basin – Onshore

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

All American Oilfield AssociatesIDECO H-37 AAO 111 Kenai Yard Available

Aurora Well ServicesFranks 300 Srs. Explorer III AWS 1 Stacked out in Sterling Available

Nabors Alaska DrillingContinental Emsco E3000 273E Kenai AvailableFranks 26 Kenai StackedIDECO 2100 E 429E (SCR) Kenai StackedRigmaster 850 129 Kenai Available

SaxonTSM-850 147 Ninilchik Unit, Bartolowits pad Hilcorp Alaska

drilling Frances #1TSM-850 169 Swanson River Hilcorp Alaska

Cook Inlet Basin – Offshore

XTO EnergyNational 110 C (TD) Idle XTO

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

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

Hilcorp Alaska LLC (Kuukpik Drilling, management contract)Monopod A-31, Preparing to drill Hilcorp Alaska LLC

Patterson UTI Drilling Co LLC 191 West McArthur River Unit #8 Cook Inlet Energy

Kenai Offshore VenturesLeTourneau Class 116-C, Endeavor Port Graham Buccaneer Energy Ltd. jack-up

Mackenzie Rig StatusCanadian Beaufort Sea

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

Central Mackenzie Valley

AkitaTSM-7000 37 Racked in Norman Well, NT Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of March 20, 2014.

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts*March 14 March 7 Year Ago

US 1,809 1,792 1,776Canada 522 587 503Gulf 52 53 51

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

By GARY PARKFor Petroleum News

P aramount Resources has made itspredicted move to reabsorb control of

MGM Energy.If the deal is concluded, it will consign

one of the smallest and boldest explorersin Canada’s North to the history books andsend a strong message to the NorthwestTerritories government to do as it haspromised and accelerate regulatoryapprovals when the Canadian governmentrelinquishes control over resource devel-opment to the NWT on April 1.

In what could be a parting message tothe NWT, MGM President Henry Sykessaid MGM’s downfall stemmed partlyfrom complicated, unpredictable and cost-ly processes, despite what he described asa “tremendous job” within his company.

Typical of the barriers confrontingNWT explorers is a regulatory applicationfiled by Husky Energy to drill four wellsin the Canol oil shale of the Central

Mackenzie Valley, subjecting itself toreviews by 40 different agencies, havingso far invested C$160 million in the pro-gram.

Paramount’s takeover offer involves the86 percent of MGM shares it doesn’talready own for the equivalent of 15 centsa share — one of its shares for 300 MGMshares — or a total transaction value ofabout C$47 million.

Clayton Riddell, chief executive officerof both Paramount and MGM, personallyowns 31.6 percent of MGM and hasagreed to support the deal.

MGM shares immediately fell 23 per-cent to 15.5 cents, less than half their trad-

ing value of a year ago.Sykes, who has been president of

MGM since it was spun off fromParamount in 2007, told reporters thedevelopment is the “most frustratingaspect of our time operating in the North,”which was initially spurred on by hopes ofmaking enough natural gas discoveries inthe Mackenzie Delta to become a signifi-cant shipper on the planned MackenzieGas Project pipeline.

Sykes and other MGM officials haverepeatedly warned that delays in gainingapprovals for exploration work are beyondthe economic capacity of a small company.

They said that obtaining a permit for ahorizontal well in the NWT was takinglonger than a year and costing millions ofdollars, a process that was extended byeven more years if an environmentalassessment was ordered.

Sykes told the Calgary Herald thatdelays in the natural gas sector madeMGM’s gas reserves irrelevant and he isnow concerned that if the United Statesmakes the advances with unconventionaloil that it has with unconventional gas thecostly NWT oil will not be needed for a“significant time.”

MGM drilled one of its 11 wells inpartnership with Royal Dutch Shell, butwas forced to concede on Feb. 27 that ithad failed to find a replacement partner,despite estimates that the ExplorationLicense 466 held estimated oil-in-place of625 million barrels.

When an application by the MGM-Shell partnership to drill a horizontal wellon the license was referred for an environ-

mental assessment — even though MGMhad already drilled and tested a verticalwell in the 2012-13 winter — Shell decid-ed it was time to quit.

MGM had submitted a project descrip-tion to regulators entailing more than1,000 pages, listing all of the chemicalsthat would be used for hydraulic fracturingand outlining how the land and subsurfacewould be protected.

Overall, MGM had a positive workingcapital of C$11.2 million at the end of thethird quarter 2013 and holds about 3,700net hectares (9,140 acres) of NWT land,valuing the Paramount offer at aboutC$127 per hectare.

Sykes said that companies in the Canolplay, led by Husky and ConocoPhillipsCanada, have indicated the outlook ispromising, but until the road to commer-cialization is opened up investors are notinterested.

The one glimmer of hope, when regula-tory control of the NWT’s onshore is trans-ferred to the NWT government, is a com-mitment by the NWT to streamlinereviews and approvals.

FirstEnergy Capital analyst CodyKwong said in a research note that if theParamount offer is accepted, MGM’sassets would be transferred to a “bettercapitalized company.”

Geoff Ready, an analyst with DundeeCapital Markets, doubts that a rival bidderwill emerge because of the failed searchfor a joint venture partner. l

l F I N A N C E & E C O N O M Y

MGM Energy close to fadingDescribes NWT regulatory process as too complicated, unpredictable and costly for small company; NWT promises improvement

4 PETROLEUM NEWS • WEEK OF MARCH 23, 2014

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EXPLORATION & PRODUCTIONUmiat well reaches target depth

The Umiat No. 23H well has reached its target depth, according to its operator.Linc Energy Ltd. said the horizontal well at the Umiat oil field has reached a

total measured depth of 4,100 feet and the company soon plans to conduct a flowtest.

The flow test will use an open-hole configuration with a slotted liner requiringno cementing or perforations, according to the company. The company decided topursue an open-hole configuration for its flow tests at the Umiat field aftermechanical problems last winter compromised a planned flow test on the UmiatNo. 18 vertical well.

Umiat No. 23H is the first horizontal well at the oil field in the foothills of theBrooks Range Mountains along the border of the National Petroleum Reserve-Alaska.

—ERIC LIDJI

Sykes said that companies in theCanol play, led by Husky andConocoPhillips Canada, have

indicated the outlook is promising,but until the road to

commercialization is opened upinvestors are not interested.

By STEVE QUINNFor Petroleum News

L ast year Sen. Pete Kelly let his SenateFinance Committee co-chair Kevin

Meyer handle the oil tax reform legislation,one of Gov. Sean Parnell’s signature laws toadvance through the Legislature.

This year, Kelly, a FairbanksRepublican now in his second year of hissecond tenure in the Senate, handledParnell’s major resource offering: SenateBill 138, Parnell’s LNG legislation.

A few days after the committee passedSB 138 and one day before the Senateapproved the bill, 15-5, Kelly sat downwith Petroleum News to discuss the workSenate Finance did to advance the bill,including provisions for rural Alaskaderived from project-driven state earnings,giving the Alaska Gasline DevelopmentCorp. more authority and giving the state25 percent equity into the project.

Petroleum News: Can you give us anoverview on how you approached the bill?

Kelly: We began to have presentationsbefore the bill came into the committee. Iknew it was going to take a long time;there were things we needed to be sure onas best as we can. I mean, we are lookingpretty far into the future. You can’t be 100percent. So I had asked that we get theinformation in committee going before wehad the bill. I thought the consultants thatwe had and the consultants the administra-tion had made a case that this is a fairlyelegant package that’s been put together.

Clearly the state can’t do this on itsown. If we just did the taxing scenario,which most sovereigns do, we’d probablyend up with a lot less money and morerisk, risking future money wouldn’t bethere. Obviously, there is risk involved inbeing a partner in this. I don’t mean tominimize that. I think they made the casethat the state is better off being a partnerbecause we can get into it at a more sig-nificant participation if we have a partnerand we can make more money being inthe gas business given that we’ll have todo that through some surrogates.

So I thought the case was made and Ithought it was important, as I looked athow we were going to proceed as a sover-eign, did we want to start remaking every-thing that we had done in HB4 last year.The administration didn’t make the case,but others made the case that we probablyshould give AGDC more authority thanthe governor wanted to give them. That’swhy you saw that we put a program direc-tor in there. We fought a little overwhether the Attorney General should bethe lead counsel on this. Ultimately it wasthe feeling of the committee that heshould not. That may be resolved in theHouse, I don’t know, but that was part ofthe bill that was a bit contentious.

We thought we should be in at 25 per-cent. We were at 20. We moved it up to25. The reason was that this is so early inthe process. You can stake your claim at25 percent now. In the future, you canback off of that and sell your share actual-ly at a premium. If you go in at a loweramount, and say we want more, you willhave to pay someone else at a premium.Fact is, you probably couldn’t get in at agreater amount anyway. So the best thingto do is go in higher and you always havethe opportunity to drop back, and you canprobably drop back and get some money

out of the process inthe first place.

Then we went tothe rural energyfund. I actually likechanging the nameof that because Ithink there is somemisunderstanding ofwhat we created. Ihad discussions withpeople who think it should be an outreachenergy fund. What you have is this linegoing down the middle of the state. Thereare people on the other sides of the linewho will benefit from that fairly quickly.There are people that going all the wayout who will probably need some helpfrom an energy fund to make sure gas orlower cost energy gets to them. Thosepeople might live on Chena Hot SpringsRoad in Fairbanks, they might live inNenana, the might live in Wasilla. Thereare a lot of places that don’t have gas thataren’t necessarily deep rural Alaska.

We also want to make sure people ofrural Alaska have it also, that we didn’tmiss this opportunity to set something up.I think Lyman (Hoffman, Bethel senator)made a pretty good case that we’ll lookback on this and we’ll wish we had donesomething like this. We’ll take incomestream from this project and put it into anoutreach energy fund.

Petroleum News: OK, you guys startedworking on this before the bill got to yourcommittee, so what was your thinkingdoing it that way and is 90 days reallyenough to accomplish something this big?

Kelly: Ninety days is a bad ideawhether it’s something this big or some-thing else, so we adjust and we do the bestwe can. You saw we did HB4 last year, wedid the gas trucking to Fairbanks last year,we did the oil taxes. So we can do it, but90 days doesn’t serve the people of Alaskawell at all. It kind of dawned on me thatthis is the second committee of referral(between the Senate and House). We’vehad exhaustive presentations and therecame a time we had to get the bill out.That’s why I’m a little inoculated from

criticism from when people say we arerushing this. We’ve known there has beengas up there on the North Slope since thefirst headline in 1954 or something likethat. We’re not rushing.

Petroleum News: There is this prevail-ing thought that the window of opportuni-ty is now, and it’s always been there. So isit necessary to get it done in 90 days or isit that it can be done in 90 days?

Kelly: The minority is always going tofind a way to criticize it. The less meatthere is to their criticism, the more you’llhear things like you’re rushing it, or thepeople in Alaska haven’t had input —those kinds of clichés. I don’t take it veryseriously. I refer the last two to fellas whowe serve with here who are in the minori-ty and more from certain people in thepress who just complain about everything.It’s always the same stuff:going to fast; not listening tothe people of Alaska. Theyjust ask questions but theyhave no substantive contri-bution. They ask questionsthat can’t be answered but are designed todamn the actions of the Legislature orwhoever happens to be in power that theydon’t agree with.

Petroleum News: Let’s go to your pointabout giving AGDC more power. What’sdriving that?

Kelly: they seem to be the entity that’savailable that can do this. You don’t wantgovernment trying to accomplish thesetypes of things. You can’t have the talentthat you need for something like thisbecause you have all kinds of pay restric-tions. AGDC was created to be fairly pow-erful, fairly nimble and you need thosekinds of things to pull off a project likethis. I have great trust in the board andparticularly the executive director DanFauske. He’s a home run hitter.

Petroleum News: The chairman (JohnBurns) is an attorney, as well as a formerattorney general; does that enhance yourconfidence in the board?

Kelly: I’m not sure I need more confi-

dence. This is the type of project whereyou need the F. Lee Bailey of pipelineattorneys. I’m not sure who that is. That’swho you want and you want access tothem. If you wanted to go through theattorney general’s office, you have toremember they have a lot on their plateand they are distracted. They are not moti-vated like a law firm is money wise.

We structured the bill so you didn’thave that separate subsidiary, that separatecorporation the governor wanted. You arereally handing AGDC the ball on this one.There may be some criticism in there andI may be one of them that there still mayneed to be some changes to boost AGDC’srole in this.

Petroleum News: There are people whostaunchly support AGDC, so what else is itthat you like about this body?

Kelly: They are powerfuland they are nimble. Wegave them plenty of statuto-ry authority to do thesekinds of projects. We havetalented people in place.

We’ve given them lots of money in theoriginal fiscal note, plus in the fiscal notethis year. They should be able to deliverfor us. I’ll be really curious to see if thebig line doesn’t go forward and we areremoved from the requirements underAGIA, I’ll be interested to see how quick-ly AGDC adapts itself to the needs of in-state energy of getting gas to the burnertip. They will have to take that 36-inchline down to something quite a bit smaller.There are so many restrictions with AGIAright now. Later on when AGIA is off thetable and there is no major LNG line, theyare going to still deliver gas to Alaskans, Ihope.

Petroleum News: Has the bill doneenough to set aside AGIA?

Kelly: I honestly don’t know theanswer to that. I really don’t.

Petroleum News: OK, let’s go to yourpoint about the 25 percent. How did you

l G O V E R N M E N T

Kelly steers LNG bill through FinanceFairbanks senator talks about issues his committee faced with enabling legislation giving Alaska an equity stake in an LNG project

PETROLEUM NEWS • WEEK OF MARCH 23, 2014 5

see KELLY Q&A page 13

SEN. PETE KELLY

By KRISTEN NELSONPetroleum News

In 2002, the year the Alaska Departmentof Revenue put out a report on potential

state participation in an Alaska natural gaspipeline, Larry Persily was a deputy com-missioner in the department.

Today, he’s the federal coordinator forAlaska gas line projects.

On March 10 he discussed with theAlaska Senate Finance Committee the dif-ferences between the state participationproposed in a natural gas project in 2002and the participation the AlaskaLegislature is considering today.

Persily told the committee that whathas really changed since 2002 is the worldmarket for natural gas, with growingdemand in Asia and double-digit growthin China’s demand.

Alaska, he said, could be a “victor ofcircumstances” where things work out in

the state’s interestafter a 40-year waitto commercializeNorth Slope naturalgas.

The price issuePersily said diver-

gence in prices isalso a change,demonstrating with achart from the BP Statistical Review ofWorld Energy showing the differencebetween gas prices in Japan, the UnitedKingdom and the United States between1996 — when the range was between $2per million Btu in the U.K. and just under$4 in Japan — to 2013 when the price inJapan was above $17 per million Btu,compared to $11 in the U.K. and $4 in theU.S.

He cautioned against an assumptionthat the gap in prices will continue to grow

or to be as wide as it has been. Supply anddemand doesn’t work that way, Persilysaid, adding that the price won’t comedown enough so that LNG will be uneco-nomic, because prices accommodate thehigh cost of LNG production. Alaska willhave to be competitive in the world market— and the economics for an Alaska LNGproject are “much more attractive” at thelower end of the $45 billion to $65 billionestimated cost.

He also said there won’t be cheap gasfrom new projects, because they cost toomuch to build.

‘Patience’ the key wordChanges Persily cited include a transi-

tion on the North Slope from oil to oil andgas, especially with Point Thomson com-ing online.

And producers and the state are willingto put up serious money to see if the proj-ect will work — there’s never been a will-

ingness to spend that much, he said. But, Persily cautioned, Alaskans need

to keep reciting the word “patience.”He said he’s not aware of any LNG

project which has lost money. You may notmake as much money as projectedbecause costs may turn out to be higher,but you still make money, Persily said.

There is, however, a long payback peri-od on projects like this. He compared it toinvestments the Norwegian governmentmade in oil and gas projects where it hadto wait years for any money to come back— a decade before profits really cameback in.

Persily said the 2002 Revenue reportlooked at a pipeline to the Lower 48 and ata time when the state was down to $2 bil-lion in the constitutional budget reserve.That was not a time when there wasmoney to invest, he said, compared totoday when the state has $17 billion in theCBR.

What hasn’t changed?The 2002 report recommended that the

state take royalty in kind and match uproyalty share with gas pipeline ownership,Persily said.

And there was the conflict of owningsomething you also regulate, although astate-owned entity minimizes those con-flicts, he said.

Persily urged Alaskans to keep politicsout of business and said it would takemoney to get answers and the informationneeded to make a decision, hence the costto the state for pre-FEED (front-end engi-neering and development) and FEEDwork.

He said that looking back over the2002 report as an Alaskan, the state needsto be careful not to fall too much in lovebefore we know more about each other.The project could produce revenues, butthere are also risks, and while oil is likedating, gas is like getting married, Persilysaid.

As to the expense of pre-FEED andFEED, he said it’s what you have to do toget to a decision.

TransCanada issueAsked about TransCanada, Persily said

he wanted to be careful not to be a federalofficial telling the state what to do.

He said the state has unfunded needsand by taking on TransCanada as a partnerthe state reduces the money it has to comeup with in pre-FEED and FEED.

If the state takes 25 percent, Persilysaid, that’s probably more than the statecan afford and having someone else put upthe money is an advantage.

He said that as an Alaskan he recom-mended that the committee not chart outthe project at high prices, but rather lookat the lowest possible gas price, becausewhile there won’t be loses long term inLNG, projects have made less than theyexpected.

If the state looks at the worst case, thenit can make a risk decision, Persily said. l

l N A T U R A L G A S

Return on natural gas long time comingPersily cites differences, similarities to state’s 2002 efforts; sees value of TransCanada in letting state use cash elsewhere

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By WESLEY LOYFor Petroleum News

As Alaska North Slope oil productionhas declined over the years, the opera-

tor of the trans-Alaska pipeline hasn’t need-ed to run as many pump stations to move thecrude.

Today, only four pump stations do themain work along the 800-mile line.

Several others are, for the most part,retired.

But the retired stations aren’t entirelyirrelevant. All continue to contribute some-thing to the job of safely operating thepipeline. And they continue to consume sig-nificant dollars for maintenance, and forwork toward the day when the stations couldbe dismantled.

The pipeline owners — BP,ConocoPhillips, ExxonMobil and Chevron— recently filed required annual updateswith the Regulatory Commission of Alaskaon the status of work at pump stations 2, 6,7, 8, 10 and 12.

Alyeska Pipeline Service Co., whichoperates the line on behalf of the owners, haseffectively disconnected most of these sta-tions from the pipeline, and has done con-siderable work toward their permanent dis-posal.

Concurrently, the company has mounteda hugely expensive program to upgrade thefour workhorse stations that today movearound 550,000 barrels of oil per day. That’sa lot of oil, but far less than the peak of 2.1million barrels seen in 1988.

Alyeska spokeswoman Michelle Egantold Petroleum News the company has con-ducted work such as “straight pipe” projectsto route oil through idle stations, bypassingvalves and other equipment.

The company has no immediate plans toremove entire pump stations, she said.

Here are a few notes from each of the sixstatus reports the owners filed with the com-mission in February under docket No. P-04-021.

Pump Station 2 — This station, locatedtoward the northern end of the pipeline, hasbeen in “ramp down status” since 1997. Thestation is now permanently isolated from themain oil line, and is currently unmanned.

The station still has support equipmentsuch as a communications module and pres-sure and temperature instruments.

“Preparation for final dispositionremains to be done for some buildings,structures, systems and piping,” the updatesays. “Final disposition of these items maymean abandonment-in-place, removal foruse elsewhere, salvage, or removal and dis-posal.”

Removal of structures and equipment isscheduled for no earlier than 2016. Assetretirement costs are estimated at $6 millionto $10 million.

Pump Station 6 — This station has been

in “ramp down status” since 1997, and ispermanently isolated from the main oil line.

“Facilities that are currently active at thissite include a refrigeration skid, vehicle fuel-ing station, microwave communicationstower, the pump station control room con-taining communications and control equip-ment, and a new communication modulecontaining control and communicationequipment,” the update says. “In addition,this site serves as an oil spill response base.”

Several buildings remain active for hous-ing workers, and the site also serves as thebase for the Yukon River bridge securitydetail.

“Preparation for final disposition anddemolition is ongoing, with work currentlyplanned for 2016 or later for some buildings,structures, systems and piping,” the updatesays.

Pump Station 7 — This station is nolonger required to move crude. However,since 2011 it has played an important role incombating problematic chilling of oil insidethe pipeline.

A single mainline pump at PS 7 has beenconfigured to recirculate oil, which addsheat, the update says.

This pump will be operated in wintermonths when required to maintain crudetemperatures above 31 degrees. The stationalso can assist with a “cold restart” of thepipeline.

The station will remain in service forcrude oil heating until 2016, and is not cur-rently scheduled for permanent isolationfrom the pipeline.

Capital improvements at the stationtotaled more than $12 million in 2013.

Pump Station 8 — The station has beenin “ramp down status” since 1996, and isnow permanently isolated from the main oilline.

Equipment such as flow meters forpipeline leak detection remains active at thestation.

Future asset retirement costs are estimat-ed at $6 million to $10 million.

Pump Station 10 — The station has beenin “ramp down status” since 1996, and isnow permanently isolated from the main oilline.

Work in 2013 included straight-lining theoil pipeline through the station, and drainingand cleaning in preparation for demolitionwork.

A new generator module and a controlsystem upgrade are planned for the station in2014, at a total cost of up to $10 million.

Pump Station 12 — The station was per-manently isolated from the main oil line in2005-06.

The site continues as a base for spillresponse and cold restart equipment. Acontrol system upgrade is planned. l

l P I P E L I N E S & D O W N S T R E A M

They’re retired, but still relevantStatus, disposal plans updated for several pump stations no longer used to move North Slope crude oil down the trans-Alaska pipeline

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Due to declining North Slope crude production, only four pump stations along the trans-Alaska pipeline currently are used to move oil: 1, 3, 4 and 9. Pump stations 2, 6, 8, 10 and 12have been ramped down and permanently isolated from the main oil pipeline. Pump Station5 serves as a relief station to ease pressure that builds up in the pipeline as oil descendsAtigun Pass. Pump Station 7 is available for winter operation to recirculate crude, whichadds heat to ward off freezing in the oil stream. Pump Station 11 was never built, as thedevelopment of drag reducing agent — a chemical additive that makes oil flow more easily— reduced the need for pump stations. The site now serves as the Glennallen Response Basefor oil spill response along the southern pipeline route.

By ALAN BAILEYPetroleum News

The question of how to better managethe Alaska Railbelt power transmis-

sion grid, a recurring topic of debate andconcern, came up again at the March 12meeting of the Anchorage Mayor’sEnergy Task Force. Currently various sec-tions of the grid are owned and managedby six independent electrical utilities andthe State of Alaska. But, while the gridhas worked reliably over the years, therewill be costly inefficiencies and potentialreliability issues in the operation of thegrid unless the grid is upgraded and itsmanagement structure unified, officialsfrom the Alaska Energy Authority andelectricity utility Chugach ElectricAssociation told the task force.

The grid extends from Homer in thesouthern Kenai Peninsula throughAnchorage and the Matanuska andSusitna valleys, north to Fairbanks in theInterior.

Many rolesBradley Evans, CEO of Chugach

Electric, told the task force that the trans-mission network performs many criticallyimportant roles, in addition to the obviousrole of carrying electrical power fromwhere it is generated to where it is used.The network, for example, enables therapid connection of reserve generationfrom different locations, to enable thecontinuity of electrical supplies should anoperational problem occur somewhere inthe system. The transmission network

also provides flexibility in hooking upelectrical supplies for new applications orfacilities requiring electrical power.

“You’ve got a suite of benefits that youreally should be thinking about when youthink about the benefit of the grid,” Evanssaid.

Rethink neededBut changes in power generation

arrangements, including new power sta-tions and the startup of some independentpower producers, are driving a need for arethink of how the grid is managed. As aconsequence of new power generationcoming on line, for example, the numberof utilities involved in handling the dis-patch of power around the grid is increas-ing, thus complicating the manner inwhich the grid is managed and resultingin disagreements over factors such as gridreliability rules, Evans said.

The current business structure formanaging the grid does not support the

inter-regional transmission of power; nordoes it support the economic and mostefficient usage of power generation facil-ities on the grid. And the management ofdifferent segments of the grid by differententities leads to an over-complex layeringof the recovery of operating costs throughthe various tariffs charged for the variousgrid segments.

While the grid ownership, operationand control is fragmented and decentral-ized, ideas of somehow integrating theutilities into a single entity have neverprogressed, Evans said.

Independent system operatorEvans argued instead for the formation

of an independent organization for oper-ating the entire grid, along the lines of theindependent system operators that man-age transmission networks in a number ofregions of the Lower 48.

“I myself believe this is doable,” Evanssaid. “I believe we can take an existingmodel that doesn’t look too weird to myrating agencies, my bond lenders … Ithink we can scale it down here and makethis work.”

Ownership of the various componentsof the grid by the utilities and the statecould remain much as it is at present, butthe independent operator would have theauthority to ensure non-discriminatoryaccess to the grid; to maintain reliabilitystandards; to plan and approve projects;to develop an efficient system-wide tariff;and to manage the dispatch of power, bal-ancing power generation with power

loads throughout the grid.A board of stakeholders in the grid,

including representatives from the utili-ties, independent power producers andelectricity consumers, would providestrategic oversight of the independentoperator.

Bills introducedThe Regulatory Commission of

Alaska, or RCA, would have regulatoryjurisdiction over the independent opera-tor: During the current state legislativesession bills have been introduced in theHouse and the Senate proposing that theRCA work with the utilities to prepare areport, assessing whether the establish-ment of an independent system operatorwould be beneficial to the operation ofthe transmission grid and recommendingany legislation or regulation changes thatwould be required to make the independ-ent system operator concept work.

Asked about comparison betweenthese bills and a bill for unification of theRailbelt power grid that the Legislaturefailed to pass in 2010, Gene Therriault,deputy director of the Alaska EnergyAuthority, or AEA, told the task force thatthe 2010 bill encompassed the manage-ment of both power transmission andpower generation, while the new proposalonly considers the transmission network.

And Evans emphasized that the ques-tion of establishing an independent sys-tem operator for the grid is completelyseparate from and does not depend onanother possibility, the formation of acompany to own facilities within thetransmission grid and hence to achieveeconomies of scale in facility construc-tion and operation. By not owning assetsin the grid, the system operator can inde-pendently adjudicate over issues relatingto grid operation, he said.

Need for upgradesTherriault told the task force there are

growing issues, both with the way theoperation of the grid is governed and withthe need for grid upgrades.

He said that an AEA evaluation of theneeds for grid upgrades highlighted theway in which the current grid configura-tion is constraining the amount of powerthat can be shipped out of the KenaiPeninsula from the Bradley Lakehydropower station, the cheapest powersource on the grid. The inability of someelectrical utilities to make use of BradleyLake power at times when they need itresults in the use of more expensivepower generation, thus increasing elec-tricity costs for consumers, Therriaultsaid. And the movement of power fromBradley Lake around an unduly longtransmission route leads to high transmis-sion losses, a wastage that also increaseselectricity costs.

The AEA study recommended severalupgrades to alleviate the Bradley Lakecongestion, including the construction ofa high voltage direct current transmissionline under Cook Inlet, between the north-ern Kenai Peninsula and the west side ofthe inlet.

The AEA evaluation also said thatsome upgrades to the transmission net-work are needed in the Anchorage andPalmer areas. And the study recommend-ed major upgrades to the transmissionintertie between Southcentral Alaska and

l U T I L I T I E S

An independent operator for the grid?Efficient and reliable operation of the evolving Alaska Railbelt power transmission grid appears to depend on unified management

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By GARY PARKFor Petroleum News

Oregon is shaping up as the doorwayto Asia for Canadian natural gas pro-

ducers who are struggling to find outletsfor their production.

Canada’s National Energy Board hascleared the way for one Oregon LNG proj-ect to use up to 1.55 billion cubic feet perday of feedstock gas from Western Canadaand is expected to decide soon on anotherapplication to use 1.3 bcf per day.

Veresen, a Calgary-based diversifiedenergy infrastructure company, hassecured a 25-year permit from the NEB totap into Western Canadian gas for its $6.8billion Jordan Cove operation, but it is stillwaiting for a ruling from the U.S.Department of Energy on its proposal toship LNG from the U.S. West Coast.

Next in line for the NEB is an applica-tion from the Oregon LNG project, whichis proposed by Leucadia National Corp., adiversified holding company based in NewYork.

Canadian gas sidesteps US export issues

Gaining access to Canadian gas bringsthe proponents closer to reality by enablingthem to sidestep the U.S. government’s gasexport threshold of 12 bcf per day.

So far U.S. regulators have given thego-ahead to six LNG projects with a com-bined capacity of 8.5 bcf per day, to shipgas to countries that do not have free tradeagreements with the U.S.

U.S. businesses, especially petrochemi-cal companies, have raised concerns aboutrisks they face if large-scale exports ofshale gas are allowed from the Eagle Ford

and other U.S. basins and have warned thatU.S. domestic gas prices could increase asa result.

The NEB has also approved export per-mits for seven LNG projects on the BritishColumbia coast which could consumeabout 15 bcf per day of gas supplies, not-ing it is not yet concerned that exports ofthose volumes would undermine Canada’senergy security.

Although NEB permits require finalratification from the Canadian govern-ment, the regulator has been unhesitatingin estimating that the gas assigned to LNGexports would be surplus to Canadianrequirements for the 25-year permit peri-ods.

Robert Kwan, an analyst with RBCCapital Markets, said in a note to clients hedid see approval of the NEB permit as a“major hurdle,” suggesting that obtainingU.S. Department of Energy permits fornon-FTA countries as a much tougherobstacle.

Lifeline for producersAmong producers, LNG shapes up as

their lifeline, with export pipelines fromBritish Columbia and Alberta to the U.S.carrying about 8.2 bcf per day of availablecapacity of 15 bcf per day, with ZiffEnergy Group forecasting those levels willdrop to about 5 bcf per day by 2020.

Canadian gas exports to the U.S. weredown to about 2 bcf per day lastNovember, off one-third from the peak in2007, while benchmark prices at theAECO trading hub in Alberta have beendragged about $1 per thousand cubic feetbelow the U.S. benchmark at Henry Hubover the past year.

Don Althoff, chief executive officer ofVeresen, told the Financial Post that theJordan Cove project offers some relief tomid-size Canadian producers.

“It will utilize existing infrastructure totake advantage of Canadian resources andwe think it is a great Canadian project — itjust happens to be in a different part ofNorth America,” he said.

Veresen is looking for investors andpartners for its project and has securedheads of agreements with three unnamedAsian buyers.

The company hopes to have its off-take

contracts in place this fall, allowing a finalinvestment decision by either late 2014 orearly 2015, with the first LNG consign-ments targeted for shipping in 2019.

If the venture goes ahead, gas will beshipped through the TransCanada pipelinenetwork and a 230-mile connectorpipeline, jointly owned with WilliamsPartners, in Oregon which will gather gasfrom Western Canada and the U.S.Rockies. l

l N A T U R A L G A S

US LNG exports vital for Canada

PETROLEUM NEWS • WEEK OF MARCH 23, 2014 9

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Fairbanks, to increase the capacity of thetransmission system to ship powerbetween Anchorage and the Fairbanksregion and to improve the stability of thesystem.

“What we’re looking for is animprovement in the system to increasethe capacity, but also increase the relia-bility by having some redundancy in thesystem,” Therriault said.

More than $900 millionThe AEA study put a total price tag of

more than $900 million on its completelist of recommended upgrades. But,although the study estimated electricitycost savings from the upgrades thatwould more than offset the cost and couldthus reduce electricity rates by from 1.5cents to almost 3.5 cents per kilowatthour for consumers, the utilities have saidthat they do not have the financial capac-ity to meet this huge upgrade bill.

One obstacle to possible state assis-tance with funding for grid upgrades maybe questions over how the improved sys-tem is operated to the benefit of the elec-tricity consumers, Therriault commented.

“I think right now perhaps we’re at alittle bit of a standoff,” he said. “We knowwe’ve got these needs to answer somepolicy questions on the governance sideand then we also know we need someinvestment on the infrastructure side.” l

continued from page 9

GRID OPERATOR

EXPLORATION & PRODUCTIONShale drilling efficiency increasing

A steady increase in the efficiency with which companies are drilling intoshale oil and gas plays in the Lower 48 is playing a role in the rise in U.S. oil andgas production, according to the U.S. Energy Information Administration. EIAsays that the increasing precision and efficiency of horizontal drilling andhydraulic fracturing, the two techniques at the heart of the shale oil and gas revo-lution, are enabling each drilling rig to create more new production.

EIA tracks production and drilling from six shale plays: the Bakken, the EagleFord, the Haynesville, the Marcellus, the Niobrara and the Permian. Despite thediverse nature of the geology across these plays, five of the plays have seenincreases in production per drilling rig over the past few years, with the EagleFord leading the pack for increased oil production and the Marcellus leading inincreased gas production, EIA says.

Data from April 2013 show that each drilling rig in the Eagle Ford added 400barrels per day more to production than it would have done in the same shale for-mation in January 2007. And in the Marcellus shale, the corresponding increasefor gas productivity was 6 million cubic feet over the same period, EIA says.

According to EIA data, the Permian has shown a slight drop in gas productiv-ity since 2007, although oil productivity in that basin has increased.

—ALAN BAILEY

10 PETROLEUM NEWS • WEEK OF MARCH 23, 2014

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EXPLORATION & PRODUCTIONApache gathering more Cook Inlet seismic

Apache Alaska Corp. has resumed its program of seismic surveying in the CookInlet basin and in February started an onshore survey in the Kenai National WildlifeRefuge, in the northern Kenai Peninsula, Lisa Parker, Apache Alaska’s manager, gov-ernment relations, told Petroleum News March 18. In July the U.S. Fish and WildlifeService issued a special use permit, allowing Apache to conduct a seismic survey onsurface land in the refuge.

“We have some plans for conducting additional seismic operations and currentlyhave seismic operations in the area north of Nikiski,” Parker said.

The company expects to soon start a new marine seismic survey in the northernCook Inlet, offshore the area where the onshore survey is taking place, Parker said.This new offshore survey will be to the north of a marine survey that the companyconducted in 2012 along a fairway across the upper Cook Inlet to the west of thenorthern Kenai Peninsula.

Parker did not comment on any other exploration activities that Apache might beplanning.

“We are evaluating our options and our alternatives,” she said.On March 4 the National Marine Fisheries Service issued an incidental harass-

ment authorization, allowing Apache to conduct offshore seismic surveys acrossmuch of the upper Cook Inlet in 2014. The authorization allows the unintended minordisturbance of marine mammals in the inlet, provided that Apache implements spec-ified mitigation measures for minimizing wildlife impacts.

Apache is conducting a major multiyear program of 3-D seismic surveying in theCook Inlet basin, exploring primarily for oil but also with an interest in natural gas.In addition to the marine survey across the northern part of the inlet, the companyhas conducted an onshore survey on the west side of the inlet. The company, whichhas said that it sees the gathering of 3-D seismic as essential to finding new oppor-tunities in the basin, is using a high-tech system of wireless seismic recording nodesthat simplify the logistics of conducting surveys while also reducing environmentalimpacts. In 2012 the company spud an exploration well onshore the west of the inletbut later commented that the results from that well had proved disappointing.

—ALAN BAILEY

GOVERNMENTBSEE to fund spill response research

The Bureau of Safety and Environmental Enforcement is inviting proposals foroil spill response research projects relating to operations on the U.S. outer conti-nental shelf. The agency says that it will invest up to $5 million in appropriate proj-ects in 2014. The deadline for proposal submission is April 10. A previous solicita-tion for research proposals, with potential funding of $7 million, closed in January.

In the latest round of research funding BSEE is seeking projects that fit withinthe following topic areas:

• Best practices for emergency response exercises.• The comparison and ranking of worst-case oil discharge scenarios.• Technology and methods for separating oil from slush or frazil ice.• The effectiveness of dispersants in slush and broken ice conditions.• The geo-referenced identification tagging of response equipment to enable

inventory management and for locating equipment.• The in-situ disposal of the decanted oil-water mix from oil skimmer operations

in the Arctic.• The use of remote controlled equipment to minimize risks to spill response per-

sonnel when marking and tracking the location and movement of oil under ice.Further information about the types of project that BSEE is looking for can be

found on the FedBizOps website at www.fbo.gov.—ALAN BAILEY

l P I P E L I N E S & D O W N S T R E A M

State sues Williamsand Flint Hills

By ALAN BAILEYPetroleum News

The State of Alaska has sued WilliamsAlaska Petroleum Inc. and Flint Hills

Resources over environmental contamina-tion from the North Pole refinery nearFairbanks. The refinery processes some ofthe oil passing through the trans-Alaska oilpipeline, primarily for the production of jetfuel for use at Anchorage InternationalAirport.

Leakage from the plant has caused con-tamination of groundwater around the plantby sulfolane, a chemical solvent used in therefinery.

Flint Hills, the current owner of therefinery, purchased the refinery fromWilliams in 2004 but now wants to closethe facility, citing the environmental con-tamination as a factor in its closure deci-sion. The company says that the contami-nation took place when Williams owned therefinery and that, because the state ownedthe land under the refinery at that time,Williams and the state are responsible forthe pollution. Flint Hills wants any futurepurchaser of the refinery to takeover liabil-ity for the contamination, with that liabilitybeing reflected in the refinery’s price.

However, the state claims that sulfolane

contamination continued and spread afterFlint Hills acquired the refinery, and that along history of spills and leaks of petrole-um products from the refinery also contin-ued through to 2012. Sulfolane has migratebeyond the land occupied by the refineryand Flint Hills has taken steps to providealternative water sources for more than 300properties impacted by contaminated waterwells, the state says.

The state alleges that both Williams andFlint Hills have polluted the soil andgroundwater, rendering the groundwaterunfit for human consumption. And thecompanies have not made reasonableefforts to contain and clean up the dis-charges and releases, the state says. Thestate wants a court injunction prohibiting“continuing violations” of state environ-mental laws. And the state is seeking com-pensation for the costs to the state ofresponding to and cleaning up the contam-ination, in addition to civil penalties forinfringement of state laws.

In early March Gov. Sean Parnellauthorized the state to release any futurepurchaser of the refinery from responsibil-ity for groundwater contamination. l

PETROLEUM NEWS • WEEK OF MARCH 23, 2014 11

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By GARY PARKFor Petroleum News

B y all rights, Alberta should be reel-ing and gasping for air.

It has been hammered by a prolongedstretch of lower natural gas prices whichreduced its royalty take from the resourceto C$1 billion from C$8 billion.

The deep price discounting on NorthAmerican markets for its crude bitumenand heavy oils have further punished theprovince’s budgets.

And unmatched opposition hasdelayed and threatened to scuttle plans forbig pipelines to deliver its oil sands pro-duction to markets in Canada, the UnitedStates and the Asia-Pacific region.

Yet ...Alberta is credited with creating nine

out of every 10 net new jobs in Canadaover the past year (82,000 out of a total94,700), raising its employment growthby 3.8 percent, seven times greater thanthe national average, and unemploymenthas dropped to 4.7 percent.

Economic growth in Alberta is fore-cast at 3.5 percent, far outstripping anyother province, while the median hourly

wage is almost C$3 above the nationalaverage.

Mood upbeatAnd now, despite the uncertainties

hanging over pipelines and the challengefaced by energy companies beyond themajors in raising capital, the mood withinAlberta is upbeat.

The forecast result in a new provincialbudget is for a windfall from the oil sandsover the next three years, with royaltiesfrom bitumen targeted at C$5.6 billion inthe 2014-15 fiscal year, up C$2 billionfrom two years ago, and projected toexceed C$7 billion in 2016-17.

Those numbers have enabled FinanceMinister Doug Horner to target a C$1.1billion surplus in the new budget year,ending six straight years of deficits.

But clouds still hang over a govern-ment that expects record-high revenues ofC$44.4 billion.

It plans to borrow C$5.1 billion forinfrastructure alone this year, raising theaccumulated debt to C$14.5 billion, just adecade after Alberta led North Americanjurisdictions in wiping out a debt of C$23billion.

Horner told the legislative assemblythat Alberta, faced with populationgrowth that is triple the national average,“will not sit idle because of some ideolo-gy against debt at all costs.”

He said there is no sense for Alberta tospend provincial savings, which earn an11 percent return, when it can borrowmoney at less than 4 percent interest.

Horner said rising bitumen output andstrong commodity prices will see oilsands projects moving into a higher royal-ty payout tier as capital costs are paid off.

Investment projected at C$34 billionThe province expects overall oil sands

investment will reach C$34 billion thisyear, with production from the resourceexpected to top 2.8 million barrels perday in 2016-17, an increase of 900,000bpd in four years.

Before capital payout, oil sands proj-ects deliver 1 percent to 9 percent of grossrevenues to the provincial treasury; afterpayout, that rate is 25 percent to 40 per-cent of net revenues.

As of a year ago, the government esti-mated 61 of 112 oil sands projects hadmoved to the second tier.

Scotiabank commodity economistPatricia Mohr said the forecast for lightcrude prices could be a shade optimistic,warning there is a “definite risk” bench-mark prices could slide across NorthAmerica in the next few years because ofrising U.S. output.

For the 2014-15 fiscal year, theprovince is counting on West TexasIntermediate prices averaging US$95.22per barrel, with heavy oil/oil sands pricesaveraging C$77.18 a barrel.

In addition, auctions of explorationlands are forecast to bring in C$623 mil-lion, compared with C$3.3 billion in2011, but Horner said stagnant gas priceshave been a drag on those sales, but heheld out some hope that a recovery in thegas sector could encourage explorationand production companies to tackle newformations. Gas prices for the new yearare set at C$3.29 per gigajoule.

The 2014-15 fiscal year is expected togenerate C$9.2 billion in non-renewableresource revenue, up 6.7 percent from2013-14. l

l G O V E R N M E N T

Alberta top of classLeads Canada in job creation, economic growth, despite uncertainties over major energy projects; windfall from oil sands forecast

l G O V E R N M E N T

DOE funding for methane hydrate researchAgency looking to share the cost of projects aimed at field tests in Arctic Alaska and the sampling of subsea deposits on the OCS

By ALAN BAILEYPetroleum News

The U.S. Department of Energy, or DOE, hasannounced a government funding opportunity for

methane hydrate research. The agency is inviting applica-tions for projects in two areas: methane hydrate field test-ing in Alaska, and the characterization of naturally occur-ring methane hydrate on the U.S. outer continental shelf.

Methane hydrate is a naturally occurring ice-like mate-rial that concentrates methane, the primary component ofnatural gas, in a lattice of water molecules within a spe-cific range of relatively low temperatures and high pres-sures. In certain situations methane hydrate deposits couldbecome a prolific source of natural gas for use as a fuel, ifviable ways of producing gas from the hydrates can bedeveloped.

DOE says that total federal funds of up to $20 millionmay be available over financial years 2014 and 2015, with

individual projects having values of up to $80 million —the government funding will be contingent on applicantssharing the costs of the projects. The agency says that itanticipates making one to four funding awards, dependingon the sizes of the individual awards.

North SlopeThere are known, extensive deposits of methane

hydrate around the base of the permafrost under Alaska’sNorth Slope. Some significant research has already beencarried out into the nature of these deposits and twomethane hydrate test wells have been drilled. In April

2013 the state signed a memorandum of understandingwith DOE for collaboration in research into Alaska’sunconventional fossil energy resources, includingmethane hydrates.

DOE says that its new funding opportunity for Alaskaresearch is intended to target projects that will evaluate theoccurrence and nature of Arctic methane hydrate depositsand the response of the material to extended-durationdestabilization through depressurization and other tech-niques. Particular preference will be given to projects thatuse some North Slope land tracts that the State of Alaskaearmarked in 2013 for methane hydrate field testing.

The concept behind the outer continental shelf researchis the collection of samples from sub-sea methane-hydrate-bearing sediments within high potential areas thathave recently been identified by the Bureau of OceanEnergy Management, DOE says. l

Particular preference will be given to projectsthat use some North Slope land tracts that the

State of Alaska earmarked in 2013 formethane hydrate field testing.

12 PETROLEUM NEWS • WEEK OF MARCH 23, 2014

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

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Delta Leasing welcomes Schouten to teamDelta Leasing has named Josh Schouten vice president of sales and

marketing. He has been welcomed onboard to continue cultivating anddeveloping Delta’s reputation as the premier leasing company in thestate of Alaska.

Schouten comes to Delta with nearly a decade of sales and heavyduty truck design experience, as well as print and web marketingexperience. He will be responsible for overseeing all new businessdevelopment, as well as refining and improving on what Delta hasalready built. Schouten has been brought on to the Delta team as apart of their commitment to being the premier leasing company forAlaska’s industries.

Rudi von Imhof, President of Delta Leasing, said “Josh’s knowledge and experience willmake him a key addition to the Delta Leasing team. We view his appointment as a crucial stepin furthering our reach as a company. Hiring Josh is a part of Delta’s commitment to continuingto provide exceptional service for our current and potential clients.”

Andrew DeNittis joins URS as IT coordinatorURS announced that Andrew DeNittis has joined its team as an IT coordinator with seven

years of experience working in the information technology field. As ITCoordinator, DeNittis is responsible for all tasks involving informationtechnology within the firm. His technical expertise includes Windowsoperating system environment, computer hardware and software instal-lation and maintenance, LAN/WAN/wireless networking, OSI/ TCP/IP/firewalls, and troubleshooting. Previously, DeNittis was employed withCGI as an engineering technician, task manager, and training develop-ment specialist.

Calista provides $177,750 in scholarshipsThe Calista Heritage Foundation announced that $177,750 in scholarships was distributed

to 203 students for the spring semester. To-date more than $3.5 million in scholarships havebeen awarded. All scholarship recipients are Calista Corp. shareholders or descendants.

For this spring semester 6 percent are in graduate programs, the average GPA is 3.19 and41 of the 56 villages in the Calista region are represented. More than 80 percent are recipientsof the fall 2013 scholarship distribution.

The top five fields of study this semester are business, nursing, biology and health, educa-tion and engineering. The top five schools students are attending the University of Alaska

see OIL PATCH BITS page 13

Oil Patch Bits

JOSH SCHOUTEN ANDREW DENITTIS

By WESLEY LOYFor Petroleum News

Scott Goldsmith, a University ofAlaska Anchorage economist, long

has warned the state government not tooverspend.

Recently, he repeated that admonitionin an update to his “maximum sustainableyield” research series.

Goldsmith endeavors to estimate howmuch Alaska’s state government canafford to spend without risking suddenbig budget deficits and a painful econom-ic recession.

In general, he says, the state has over-spent. And if it continues “business asusual,” it will outstrip its lifeblood oil rev-enue and deplete its billions of dollars insavings.

Most worrisome, perhaps, is his con-clusion that not even new taxes on the cit-izenry could save the day.

His advice: Spend less, save and investmore.

Are legislators listening?Goldsmith’s advice is timely, as the

Alaska Legislature is in session now,crafting the budget for fiscal year 2015.

The session is scheduled to concludeon April 20.

In his research paper, Goldsmith saysthe state government can afford to spendabout $5 billion from its unrestricted gen-eral fund in 2015. It can then increase thatamount in subsequent years commensu-rate with population growth and inflation.

Goldsmith bases his recommendationon an analysis of the state’s expected rev-enue from oil and gas yet to be produced,combined with the Alaska PermanentFund and other savings accounts.

His 2015 spending recommendation isnearly 10 percent lower than his guidanceof $5.5 billion for fiscal year 2014.

Two factors account the decrease: abig drop in the state Department ofRevenue’s projection of future petroleumrevenues from conventional oil, and alarge draw on the state’s cash reserve tocover the 2013 and 2014 deficits.

Coming into the legislative session,Gov. Sean Parnell proposed a fiscal 2015budget of $5.6 billion, down considerablyfrom the prior year, Goldsmith writes.

Goldsmith projects the final budgetwill be about $6 billion after legislativeadd-ons. Spending at that level, he says, is“not sustainable.”

$74 billion in oil revenue“If this year’s spending is $6 billion

(“business as usual”), and it grows at an

annual rate just 1 percent faster than pop-ulation and inflation, the cash reserves(not including the Permanent Fund)would be exhausted by 2024 and the fis-cal gap could reach $3.5 billion,”Goldsmith writes. “But if the fiscal year2015 budget were $5 billion, and it grewonly as fast as population and inflation(“maximum sustainable yield”), the cashreserves would last much longer and agrowing petroleum nest egg could pro-duce enough earnings to sustain the statebudget long into the future.”

Goldsmith says the state has two rev-enue sources available for general fundspending once the cash balance runs outin 2024 — new taxes and the PermanentFund. (One might also imagine highertaxes on oil production.)

“But adding both a statewide incomeand a statewide sales tax at rates compa-rable to other states would not bring in

enough new revenue to offset the loss ofthe cash reserve,” he writes. “Spendingwould still need to fall to the level ofavailable revenues. The simultaneouscombination of new taxes and less publicspending ... would knock the economyinto a sustained recession and put it per-manently onto a slower growth path.”

Goldsmith’s study includes an estimateof the state’s future petroleum revenue,expressed as “net present value.”

The total is about $74 billion, brokendown this way: $47.4 billion from con-ventional oil produced from known fieldsthrough 2064; $9.8 billion from uncon-ventional and new oil; and $16.5 billionfrom natural gas.

Goldsmith’s 16-page paper is availableat http://bit.ly/1jcBxj5. l

l F I N A N C E & E C O N O M Y

Goldsmith counsels state to trim spendingUniversity economist surveys Alaska’s savings and expected oil revenue and predicts calamity with ‘business as usual’ budgeting

PETROLEUM NEWS • WEEK OF MARCH 23, 2014 13

reach this figure?Kelly: Early on everybody said we

need to go to 25 percent. The consultantssaid go to 25 percent because if you don’tlike it you can pull back on it a bit. One ofthe great challenges of this bill is that peo-ple want to discuss things that aren’t in it.They want to discuss the larger pipelineand from time to time, you have to remindyourself this bill is getting us to pre-FEED(pre-Front-End Engineering and Design).The consultants are saying you’re justgoing to pre-FEED, establish yourselfearly on. It was kind of a general consen-sus. I didn’t hear anyone in the FinanceCommittee object even once.

Petroleum News: And back to the out-reach fund. Several said 20 years fromnow you’ll look back and be glad you’vedone this. You’ve got the five off-takepoints, so how does this outreach fundmake this a statewide endeavor?

Kelly: I think that is probably going todevelop over time. Just as we don’t knowexactly where the off-take points are now,we don’t exactly know what the needs forrural Alaska are or even 100 yards overthere are going to be years from now. Idon’t have an answer for that. It’s going totake some crystal ball gazing. The point iswe want to make sure that in this funddelivers lower cost energy to Alaska. Itdoesn’t have to be LNG. That’s one of thereasons I don’t like the renewable energyfund. It’s too esoteric. It’s wind. It’s solar.It could be construed by some that it’s aslush fund for rural Alaskan projects. Idon’t care if it’s coal. I don’t care if it’s oil;I don’t care if it’s LNG; as long as it’s

lower cost. We got off on all of this solar,which is interesting, but our needs aremuch greater than that. We have theresources to get lower cost energy to ruralAlaska. Our challenge is transportation.

Petroleum News: Your committee wascriticized for not considering two reportscritical of this plan. The first was by RogerMarks and the second by Rick Harper,which was posted on LB&A’s website afew days after you passed the bill out ofcommittee. What are your thoughts onthose reports?

Kelly: It’s mostly against Trans Canada(Marks report). I like the Trans Canadamodel. You’ve got a company that’s builtpipelines, that’s willing to fund our portionand willing to get us a larger share, a com-pany that’s got $130 million worth of datathat’s relevant to this project and by theway a company that has met the terms ofAGIA. We are the ones who created theterms of AGIA. They signed off on it withus. There are people who wanted to criti-cize them for being part of AGIA or theyare carrying around sour grapes becausethey are part of AGIA. The big problem isyou say let’s go to somebody else. It’sgoing to take a year to develop the RFP togo out to get people and it’s going to takea year to get a response. The last time weput an RFP out, TC was the only one whoresponded (with a conforming bid), so wemight have anybody in the future and theyare willing to go now. Like I said they’vegot $130 million invested in the project.

Petroleum News: So without playingMonday morning quarterback, is thereanything that you wish you had workedinto the bill?

Kelly: My answer is no but maybe notfor the reason you think. I’m more of a

quarterback than a coach. I don’t have tohave my personal paw prints on every-thing that goes through my committee.Sometimes you’ve got to realize you’vegot to get a decent product through yourcommittee and keep it moving throughthe process. That was only the secondcommittee of referral. We massaged itand squeezed it. If we had examined itanymore, we would have just been takingup time and not made any changes thatwere worth the time.

Petroleum News: You’re in your sec-ond year of co-chair this go-around.What’s the learning curve been like?

Kelly: It’s been a pretty steep learningcurve because I wasn’t around for thedebates — the oil debates (ACES) andpipeline debates (AGIA).

Petroleum News: So do you think ithelps to bring fresh eyes and ears to thedebate?

Kelly: Not necessarily. You needsomebody who doesn’t get wrapped upin a lot of the nonsense that accompaniesa bill like this. If you don’t have a chair-man that ultimately comes to the pointand realizes this is the second committeeof referral and the bill has to get throughthe floor, over to the other body, then it’sgot Resources, Labor & Commerce andFinance. If you don’t have chairmen whounderstand that, they don’t know how toget a bill through the process. That’s onething I do understand, whether it’s oiland gas or anything else. That’s probablywhat I bring to the table. You don’t needa fresh set of eyes as far as the substanceof the bill, but you do need people whoare willing to move the process alongand who don’t get caught up too deeplyinto the politics. Yes, politics is what we

do here. But what we saw a few yearsago with the bi-partisan working group,stuff got stalled and stalled and stalled.And there were always reasons forkilling something. I just don’t play thosegames.

Petroleum News: As someone who hasbeen in leadership positions, and in thisstate watching this debate go back andforth for decades, do you see this as theonly window of opportunity? We’ve heard“the time is now” a great deal in thisbuilding.

Kelly: At a certain point, you’ve gotto believe the people that you hire, andthat’s kind of what they are telling us. Idon’t know if it’s the only, but it’s thenext window. There is the old adagedon’t let the perfect become the enemyof the good. I was down on the floortoday and a guy that I really like —Hollis French — was talking about rush-ing the process. Come on. Every time weget close on this thing, there is some-thing you can dangle. With our AGDCstructure, we are so not confined that wecan’t shift courses a little bit. This is thebiggest project in the world of its kind toget what we know is somewhere in theneighborhood of 36 trillion cubic feet ofgas off the North Slope. There are mar-kets in Asia who will say we’ll take it orit’s anticipated that they’ll say we’ll takeit. There are companies are who willingto put a lot more on the line than we are.If it doesn’t work out, we’ve got off rampafter off ramp after off ramp built intothis thing. This is an opportunity. It’sprobably worth the investment. Weshould take it. l

continued from page 5

KELLY Q&A

Anchorage, UA Fairbanks, AVTEC in Seward, Alaska Career College and Alaska PacificUniversity.

“It is exciting to see a technical field like engineering make the top five majors,” saidCalista Heritage Foundation President Rea Bavilla. “As we begin preparing for the annual GolfClassic, the main fundraiser for the scholarship program, we would like to remind local andstate businesses that nothing compounds interest like education.”

Registration is open for the 15th Annual CHF Golf Classic, which sells out each year.Sponsorships are also available. It will be held June 18 at the Moose Run “Hill Course” atArctic Valley near Anchorage. For more information please visit CHF’s website atwww.CalistaHeritage.org.

continued from page 12

OIL PATCH BITS

“If this year’s spending is $6billion (“business as usual”), andit grows at an annual rate just 1

percent faster than population andinflation, the cash reserves (notincluding the Permanent Fund)

would be exhausted by 2024 andthe fiscal gap could reach $3.5

billion.” —Scott Goldsmith

14 PETROLEUM NEWS • WEEK OF MARCH 23, 2014

By WESLEY LOYFor Petroleum News

The state of Alaska has gone to court totry to force federal officials to consid-

er Gov. Sean Parnell’s proposal for a seis-mic survey across the Arctic NationalWildlife Refuge coastal plain.

The state’s lawsuit, filed March 14 infederal court in Anchorage, names InteriorSecretary Sally Jewell and ranking officialsin the U.S. Fish andWildlife Service asdefendants. The serv-ice manages ANWR.

These officialshave all rejectedParnell’s exploratoryproposal, citing alack of authority inthe law to entertainthe plan.

Parnell and hisattorney general, Michael Geraghty, insistthe law does allow for seismic exploration.And they’re asking the court to order thefederal officials to seriously consider it.

The suit drew both cheers and jeers.State Rep. Ben Nageak, who says he’s

the only legislator born in ANWR, hailedthe lawsuit.

“Quyanaqpak, Gov. Parnell andAttorney General Geraghty, thank you,” theBarrow Democrat said in a press release.“We have been trying to open ANWR todevelopment through the federal processfor decades, only to be met with road-

blocks, push-back, disinterest, and environ-mental extremists. The area was set asidefor exploration. The federal governmenthas not held up its end of the bargain. Ourpeople need the energy underneath theground there, and the economic opportuni-ty it will bring.”

Reading ANILCAParnell in 2013 offered two exploratory

plans, the most recent of which wouldinvolve conducting a three-dimensionalseismic survey on the coastal plain but nodrilling.

The Republican governor pledged toask the Alaska Legislature for $50 millionto fund the plan.

He says existing seismic data is outdat-ed, and a modern 3-D survey could betterinform everyone regarding the coastalplain’s oil and gas potential.

The coastal plain has long been thoughtto be highly prospective for perhaps bil-lions of barrels of oil. But leasing anddevelopment would require congressionalapproval.

Parnell and the state’s lawyers contendthat a provision in ANILCA, the AlaskaNational Interest Lands Conservation Actof 1980, allows for exploratory activity.

But federal officials disagree with thestate’s reading of ANILCA and certain reg-ulations, saying any authorization forexploration expired long ago.

The state’s lawsuit asks the court for adeclaratory judgment that the federaldefendants violated the law by “summarily

refusing” to consider the state’s explorationplan and application for a special use per-mit.

The court should “vacate and set asidethat refusal,” and order the federal defen-dants to review the state’s plan, the suitsays.

‘Enough is enough!’Opening ANWR to oil development has

long been a top economic developmentobjective for Alaska elected officials. Butthey have been unable to overcome opposi-tion in Congress and the White House.Environmentalists and others say industryactivity is incompatible with the coastalplain’s caribou and other wildlife.

U.S. Sen. Lisa Murkowski of Alaska,the top-ranking Republican on the SenateEnergy and Natural Resources Committee,issued this statement:

“I support Gov. Parnell’s decision tomove forward with litigation against theU.S. Fish and Wildlife Service. As I haverepeatedly said, the agency has clearly lostsight of its responsibility to Alaskans. Anylegitimate ‘all of the above’ energy policymust include all 50 states, especiallyAlaska. Right now, however, we are beingshut out by this administration, with goodideas and great opportunities for neededproduction rejected out of hand. Congressspecifically reserved the 1002 Area for fur-ther study and production — but today, wecan’t even survey the resources locatedthere. Litigation is warranted.”

The coastal plain is also called the 1002

area, after a section in ANILCA.Cindy Shogan, executive director of the

Alaska Wilderness League, had this to say:“Enough is enough! The state of Alaska

and Gov. Parnell continue to pursue thesame dead-end, roundly rejected drillingproposal in the sensitive Arctic Refuge overand over again. The latest chapter: Gov.Parnell has brought a wasteful suit againstthe U.S. Fish and Wildlife Service despitethe fact his quest for seismic oil testing inthe Arctic Refuge is prohibited without anact of Congress.”

Shogan added that the Obama adminis-tration “has been clear — oil developmentin the Arctic Refuge is ‘off the table.’ It istime for the state of Alaska to take no for ananswer and move on.”

Parnell, in a press release announcingthe lawsuit, said: “It is both disappointingand disturbing that the Obama administra-tion, which claims that it is pursuing an ‘allof the above’ energy policy, is afraid to letthe people of the United States learn moreabout ANWR’s oil and gas resources. Themodern technology that we are seeking touse is responsibly utilized all across theNorth Slope with extremely limited envi-ronmental impact, and would dramaticallyimprove our understanding of ANWR’sresources. The state has filed this lawsuit toensure all Americans have an opportunityto learn about the vast resource baseAmericans own in the 1002 Area ofAlaska.” l

l G O V E R N M E N T

Parnell continues to press on ANWRState sues federal officials in bid to force them to consider the governor’s plan to conduct 3-D seismic survey of coastal plain

fund — to address the energy needs ofAlaskans. If we can’t address the energyneeds of Alaskans, what good are wedoing? Hoffman asked in Senate FinanceMarch 14, the day the committee movedthe amended bill.

Senate Finance had earlier amendedthe bill to direct the Alaska EnergyAuthority to develop a plan extendingenergy infrastructure to parts of the statewithout direct access to a North Slopenatural gas pipeline. The Dunleavy-Hoffman amendment also added direc-tion that for citizens with no economical-ly viable infrastructure available, theAEA plan must recommend means forunderwriting energy costs to make energymore affordable. The AEA plan is due tothe Legislature in January 2017.

Equity at 25%Senate Finance amended the bill to

increase the tax on gas from 10.5 percentto 13 percent. That tax, combined withthe state’s royalty, would give the state a25 percent equity stake in the project.Both production tax and royalty would bepaid in molecules, based on negotiatedchanges to leases, giving the state a shareof natural gas matching its share in theproject.

The bill gives the administrationauthority to negotiate contracts with theparties to the heads of agreement andmemorandum of understandingannounced in January. The HOA isbetween the state, the Alaska GaslineDevelopment Corp., BP, ConocoPhillips,ExxonMobil and TransCanada and is thefirst step to legally binding contracts for

an Alaska LNG project. The MOU,between the state and TransCanada, is astep away from the license whichTransCanada holds under the AlaskaGasline Inducement Act, and provides fornegotiation of a commercial agreementbetween the state and TransCanada underwhich TransCanada would hold the state’sinterest in the gas treatment plant on theNorth Slope and in the pipeline, andinvest necessary monies for the pre-FEED (front-end engineering and devel-opment) and FEED phases of the project.AGDC would hold the state’s interest inthe LNG facility.

The project would be phased, with anyparty able to step aside after pre-FEEDand again after FEED, before a finalinvestment decision is made.

Under the bill the Legislature willreview and approve contracts for the proj-ect and confidentiality provisions allowlegislators to be briefed and provide inputas the administration works on agree-ments so that contracts presented for finalapproval do not fail, as was the case withthe agreement negotiated by theMurkowski administration under theStranded Gas Development Act.

No AGDC subsidiarySenate Finance also changed the gov-

ernor’s bill to eliminate a proposedAGDC subsidiary for the LNG project,instead giving that authority directly toAGDC, with separate funds for the in-state gas pipeline AGDC was chargedwith last year and its work on the AKLNGproject.

The AGDC board is also instructed tohire a project manager for the LNG proj-ect.

continued from page 1

SB 138

see SB 138 page 16

GOV. SEAN PARNELL

PETROLEUM NEWS • WEEK OF MARCH 23, 2014 15

PIPELINES & DOWNSTREAMEconomic challenges for cellulosic ethanol

The production of ethanol biofuel from cellulosic material, a technology thatseems to offer much benefit over the corn ethanol that has been added to gasoline inrecent years, is facing an uphill economic struggle, according to an article publishedin the March 11 issue of Nature.

Although produced and marketed as a biofuel, the benefits of corn ethanol overgasoline in terms of reduced carbon dioxide emissions are fairly modest, given theuse of fertilizers and fossil fuels in corn production and processing. Corn productionhas benefited from government subsidies, while the production of corn for the man-ufacture of fuel has proved controversial because of potential knock-on effects onfood prices.

Cellulosic ethanol, on the other hand, offers the possibility of manufacturing fuelfrom agricultural waste: the cellulose-rich leaves and other materials remaining aftercorn has been harvested, for example.

But the relative complexity of processing cellulose into ethanol means that theproduction cost of cellulosic alcohol is higher than that of either gasoline or cornethanol, the Nature article says. In addition, the U.S. market for ethanol as an addi-tive to gasoline has hit a wall, given the limit on the percentage of ethanol in the fuelmix and a decline in U.S. gasoline demand.

In November, recognizing the constraints on U.S. cellulosic ethanol production,the Environmental Protection Agency proposed changing its renewable fuel standardby substantially reducing the volume of cellulosic ethanol mandated for use in trans-portation fuel. The agency has yet to publish a final ruling on this question.

—ALAN BAILEY

faulting the Interior Department environ-mental analysis for the 2008 Chukchi Sealease sale as the prime reason for a con-tinuing delay in moving ahead withdrilling in Alaska’s Arctic offshore. InJanuary the court upheld an appealagainst the validity of the lease sale andremanded the case to the federal DistrictCourt in Alaska. On March 17 the DistrictCourt ordered the parties in the case tosubmit a report by March 31, to indicatehow they wish to proceed in the light ofthe 9th Circuit opinion.

Shell drilled top-hole sections of twoexploration wells, one in the Beaufort Seaand one in the Chukchi, in 2012. Thecompany wants to continue drilling inChukchi Sea leases that it purchased inthe 2008 lease sale, but the court decisionin January has put the legal status of theleases into question. Damage to theKulluk drilling rig when the rig ranaground in the Gulf of Alaska after the2012 drilling season has stymied Shell’sdrilling efforts in the Beaufort Sea.

“A 9th Circuit Court decision against

the Department of the Interior in January2014 raises obstacles to our plans fordrilling offshore Alaska,” Shell’s annualreport says. “As a result, we have decidedto suspend our exploration program forAlaska for 2014. We look to relevantagencies and the court to resolve theiropen legal issues as quickly as possible,and review our options going forward.”

Next stepThe report says that if the regulatory

and legal issues are sufficiently resolved,the next step for the company would be toreview the readiness of its Alaska drillingfleet and the timeline for securing therequired permits for the drilling. Thereport also acknowledges that issuesrelating to meeting the requirements ofEnvironmental Protection Agency per-mits during the 2012 drilling season, andproblems with moving the Kulluk drillingrig out of Alaska at the end of that season,had caused a pause in the company’sdrilling activities in the Chukchi andBeaufort seas in 2013.

—ALAN BAILEY

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SHELL IN ALASKA

damage and disruption” on the company.The ruling applies only to the current

winter construction season. Gleason leftopen the possibility for the villagers toseek injunctive relief for future construc-tion seasons.

Industry expands westCD-5 takes its name from the nearby

Colville River Delta.It will function as a satellite to the

large Alpine oil field, whichConocoPhillips operates in partnershipwith Anadarko and Petro-Hunt.

In addition to the Nuiqsut villagers,the Center for Biological Diversity also ischallenging the CD-5 permit, which theU.S. Army Corps of Engineers issued inDecember 2011.

Lawyers for ConocoPhillips havecalled CD-5 an unremarkable projectthat’s being used as a “proxy” in thedebate over oil industry expansion intothe western frontier.

CD-5 is poised to become the first oilproduction drill site inside the vast petro-leum reserve. The site, however, is on aprivate inholding owned by KuukpikCorp.

ConocoPhillips is aiming for first oilfrom CD-5 in December 2015, with pro-duction expected to peak at about 16,000barrels per day. CD-5 oil will be piped toAlpine for processing.

ConocoPhillips had a tough time get-ting the green light for CD-5.

The Corps initially denied the permit,saying the satellite could be a roadlessdevelopment. ConocoPhillips appealedwith support from state officials, and ulti-mately the Corps issued a permit author-izing construction not only of the drillsite, but also a six-mile gravel access roadand four bridges.

The challengers question why theCorps reversed position on the permit,and charge the agency failed to conduct aproper, up-to-date environmental impactstudy.

The village plaintiffs filed theirmotion for a temporary restraining orderand preliminary injunction on Feb. 5.They argued the construction could causeirreparable harm to the environment andtheir subsistence way of life.

‘Could not be a worse time’ConocoPhillips told the judge an

injunction halting construction on theremote project could actually increase thechances for environmental degradation.For example, partially finished bridgescould be vulnerable to river ice and erosionduring spring breakup.

James Brodie, a ConocoPhillips capitalprojects manager, said in a written declara-tion “there could not be a worse time toface an unplanned work stoppage than theMarch to April time frame.”

The project was more than 10 years inthe planning, Brodie said. ConocoPhillipsstarted driving bridge pilings on Jan. 17.The company was to open a gravel mineand build 25 miles of ice road and 170acres of ice pads. As of February, morethan 35 million pounds of project materialshad been staged.

Interrupting the work would haveaffected hundreds of workers and put theproject “a year behind schedule and mas-sively over budget,” Brodie wrote. Havingto mobilize for an extra ice road seasonwould have cost $105 million, he said.

What’s more, Brodie said, a delay onCD-5 would in turn have delayed anotherplanned oil project, known as GreaterMooses Tooth 1, eight miles farther west.

In considering the legal hurdles for aninjunction, Gleason found it was “ques-tionable” whether the plaintiffs had shownthey were likely to suffer irreparable harm.

They didn’t help their case by waitinguntil two months after the constructionseason began to file their motion, Gleasonwrote.

Lawyers for the villagers said they filedfor the injunction “almost immediatelyafter learning that Conoco had begun con-struction.”

But Gleason held the plaintiffs weren’trequired to wait until construction began tofile their motion, particularly where forover two years ConocoPhillips had “con-sistently declared its intention to beginconstruction on CD-5 during the 2013-2014 winter.”

Gleason also found that an injunctionwasn’t in the public interest. She noted, forexample, that “residents from variousNorth Slope Borough communities,including Kuukpik shareholders who livein Nuiqsut, could lose their jobs andincome.” l

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CD-5 WORK

16 PETROLEUM NEWS • WEEK OF MARCH 23, 2014

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about rounding up natural gas sources in British Columbiaby closing its previously announced acquisition, along withC$130 million for additional acreage in the prolificMontney formation.

Progress Energy Canada, the Petronas unit that is driv-ing the search for gas, said in a March 12 release that thenew element of the asset accumulation covers 33,500 unde-veloped acres in the Julienne area of northeastern BritishColumbia.

The company did not identify the seller, but Calgary-based Enerplus said late last year that it was sellingJulienne Montney assets for C$130 million to an unnamedbuyer.

Chief Executive Officer Michael Culbert said the acqui-sitions set the stage for Progress Energy to “build on ournatural gas resource base in the north Montney” throughassets that he described as “strategic” and capturing “oper-ational synergies.”

The Talisman transaction includes 127,000 net acres ofMontney lands and has current production of 12,500 bar-rels of oil equivalent per day in the Kobes area, whereProgress Energy has existing joint operations withTalisman.

In addition, Progress will acquire Talisman’s 50 percentstake in the Farrell and Cypress areas.

Under the terms of the agreement, there is a “capital

carry” of C$870 million that will be used to fund themajority of Progress Energy’s share of upstream capitalinvestments in the joint venture area and will offset theacquisition cost of about C$1.5 billion.

Earlier in March, Pacific NorthWest filed it projectapplications with the British Columbia and Canadian envi-ronmental assessment agencies, setting in motion a 180-day review of the initial C$11 billion phase of the project.

Enbridge acquires landIn a separate deal, Enbridge said it has paid C$20 mil-

lion for land on the northern British Columbia coast thathints it plans to enter the LNG arena.

The 160 acres is at Grassy Point alongside land blockswhere Australia’s Woodside paid C$17 million for about2,500 acres and Nexen, owned by China National OffshoreOil Corp., has agreed to pay C$24 million for almost 2,000acres to acquire the provincially owned land from theBritish Columbia government.

Enbridge competitors TransCanada, Spectra Energy andPacific Northern Gas have already secured stakes inpipeline plans to deliver gas to liquefaction plants on thePacific coast.

But Enbridge will not disclose what plans it has for theland beyond saying it is “always looking for possible busi-ness opportunities.”

That lends weight to comments Chief Executive OfficerAl Monaco made to an investors conference last fall thatEnbridge was engaged in “very preliminary” discussions

with producers to deliver gas to LNG terminals.

Fiscal issueThe stumbling BC LNG Cooperative points to growing

concerns within British Columbia’s LNG sector as themajor players stall on final investment decisions, pending afinal resolution of the provincial government’s planned fis-cal regime.

So far British Columbia’s framework for a two-tier taxhas failed to gather the unanimous support of LNG opera-tors and the signs of confusion within the BC LNGCooperative lend weight to those who have claimed thatLNG projects need those with deep pockets and long expe-rience.

The venture has National Energy Board approval toexport as much as 1.8 million metric tons per year fromtwo trains for an initial capital outlay of C$500 million.

The Haisla First Nation could not be reached for com-ment and AltaGas was keeping tight-lipped.

AltaGas, in a joint venture with Japan’s Idemitsu Kosan,is separately working on the Triton LNG project to export2.32 million metric tons per year of LNG and is also plan-ning to ship LPG over 25 years, starting in 2017.

It has also negotiated transportation agreements withBC LNG Cooperative to expand its Pacific Northern Gaspipeline from northeastern British Columbia to a liquefac-tion terminal at Kitimat’s deepwater port. l

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LNG MANEUVERING

Other changes included a request thatthe governor establish an interim advisoryboard to advise on municipal involvementin a North Slope natural gas project. TheHOA calls for PILT, payments in lieu ofproperty tax, based on the volumes mov-ing through the gas pipeline. The trans-Alaska oil pipeline is taxed based onvalue of the line and there has routinelybeen litigation over the value of the line.

Under a proposal by Sen. LesilMcGuire, R-Anchorage, SenateResources amended the bill to allow indi-vidual ownership in the line, and requir-ing the Department of Revenue to report

on how that might be done. SenateFinance added local governments andNative organizations to those who couldhave ownership portions.

Sen. Click Bishop, R-Fairbanks, spon-sored amendments in Senate Finance tostrengthen training for Alaska workers toensure that Alaskans will be trained andavailable for jobs on the project.

The three ‘Ps’“I applaud the Senate for voting today

to advance the Alaska LNG Project andensure Alaska’s gas is maximized forAlaskans’ benefit,” Parnell said in a state-ment following passage. He said the leg-islation “paves the way for Alaskans tobecome owners in the project and ensures

an open, public process going forward.”Sen. Anna Fairclough, R-Eagle River,

who led debate in favor of the bill on theSenate floor, said in a statement followingpassage: “The Senate took into accountthree principles as it considered this legis-lation: Should we participate? If so, atwhat percentage? And lastly, what will bethe process to advance Alaska’s LNGproject.”

Fairclough said she believes that withthe work the Senate did on the bill, “weare looking at the right gas at the righttime,” and said the project would “bringaffordable energy to Alaskans” while for-tifying the treasury and economy “forgenerations to come.”

Senate Resources Chair Cathy Giessel,R-Anchorage, said the bill “allows us todevelop the project engineering and con-struction plans, while the fiscal details arealso scrutinized.”

“Business as usual has prevailed in oureffort to get gas from the North Slope.But business as usual has gotten us nogas,” said Finance co-Chair Pete Kelly, R-Fairbanks. “That’s why I like the approachof SB 138. It’s different from anythingwe’ve done and I think it will work.”

Sen. Peter Micciche, R-Soldotna, aformer Soldotna mayor, said the advisoryboard addresses “concerns we heard fromaffected municipal leaders along the routeof the project from the North Slope to theNikiski terminus.”

McGuire said she believes the individ-ual ownership proposal “will get Alaskansreinvigorated about our robust oil and gasindustry by allowing them the opportuni-ty to have an equity share in the project,or, in other words, own a piece of thepipe.”

On job training Bishop said the statelearned an important lesson from con-struction of the trans-Alaska oil pipeline:“And that was if we want to hire Alaskans,we have to train them for the jobs."

Opposition to the billIn 16 proposed amendments — none

of which passed the Senate — Senateminority members argued a number ofpoints: that the state should have a major-ity ownership position (Sen. HollisFrench, D-Anchorage); that leaseholdersare required under the terms of their leas-es to develop hydrocarbons (Sen. BillWielechowski, D-Anchorage); that thestate needs to go to open bidding for apipeline partner, rather than partneringwith TransCanada (French); that any con-tract should be subject to a 90-day publiccomment period (Sen. Berta Gardner, D-Anchorage); and that contracts notauthorize payments in lieu of taxes to amunicipality (Sen. Johnny Ellis, D-Anchorage). l

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SB 138