Three in a row

Vol. 16, No. 34 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of August 21, 2011 • $2

� N A T U R A L G A S

� L A N D & L E A S I N G

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

Young brings colleagues to Alaska,continues to push ANWR drilling

The setting sun silhouettes oilfield equipment and facilities atDeadhorse on Alaska’s North Slope.

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Three in a rowEnstar files new Buccaneer, Aurora & Cook Inlet Energy gas contracts

By ALAN BAILEYPetroleum News

Southcentral Alaska gas utility Enstar NaturalGas Co. has submitted three new gas supply

contracts to the Regulatory Commission ofAlaska for approval. One of the contracts, for gasfrom Buccaneer Energy’s newly discoveredKenai Loop gas field on the Kenai Peninsula,commits firm gas supplies after Cook InletNatural Gas Storage Alaska’s new KenaiPeninsula gas storage facility goes into operationin 2012.

The other two contracts, with Aurora Gas andCook Inlet Energy, will enable those companiesto help bolster Enstar’s peak winter gas suppliesby participating in the gas bidding system that

Enstar pioneered in the winter of 2010-11 —Enstar has insufficient contracted, guaranteed gassupplies to meet projected peak winter demandand has instigated the bidding system to obtaingas to fill shortages on a day-to-day basis.

A provision in the Buccaneer contract will alsoenable Buccaneer to participate in the biddingprocess as soon as RCA approves that contract.

The pricing terms appear similar to thosein earlier Enstar supply contracts withMarathon, approved by RCA in May2010, and with Anchor Point Energy,approved by RCA in November 2009.

see GAS CONTRACTS page 19

Field fight over?Alaska, Exxon have ‘resolution in principle’ on Point Thomson, Sullivan says

By WESLEY LOYFor Petroleum News

A top Alaska official signaledstrongly Aug. 15 that the six-year

fight for control of the Point Thomsonoil and gas field might soon be over.

Dan Sullivan, commissioner of theAlaska Department of NaturalResources, told a legislative committeethe state and ExxonMobil, the PointThomson unit operator, have reached “resolutionin principle” on terms to settle the legal conflict.

“We believe that this is a resolution thatadvances the state’s interests,” Sullivan told theSenate Resources Committee, meeting in

Anchorage. “ExxonMobil now is dis-cussing the provisions of the settlementwith other working interest owners of theunit, who are also the other litigants in thecurrent lawsuit.”

Terms of the settlement remain confi-dential, Sullivan said.

He noted the matter is more involvedthan simply the state and ExxonMobilreaching a deal, as the Point ThomsonWIOs also are working out “internal

commercial terms between themselves.”Sullivan’s remarks are the most significant sign

yet that the struggle over the rich but undeveloped

DAN SULLIVAN

see FIELD FIGHT page 20

Beating a path to the GulfEnbridge enters contest to build lines from Alberta, Bakken, to Texas refineries

By GARY PARKFor Petroleum News

While its rival TransCanada waits anxiouslyfor the Obama administration to decide the

fate of the Keystone XL pipeline, Canada’s No. 2pipeline company Enbridge is on the verge ofoffering shippers a “huge variety of deliveryoptions,” said Chief Executive Officer Pat Daniel.

Topping the list, depending on results from acurrent round of industry discussions, is a possible300,000 barrel per day pipeline link from Chicagoto Houston, which could come on stream by late2013 and reduce a growing bottleneck at theCushing, Okla., trading hub.

The so-called Monarch pipeline carries the

added advantage of not needing a presidential per-mit — the major stumbling block for XL —because it does not cross the Canada-United States

The Cushing bottleneck and high pricedifferentials between West Texas

Intermediate and North Sea Brent hasclimbed as high as US$25 per barrel and is

costing Canadian producers as much asC$50 million a day because of their reliance

on a single export market, prompting theclamor for an alternative route to Asia.

see PATH TO THE GULF page 19

Deadhorse sunset

TransCanada: company still in talks with potential shippers

TransCanada Vice President TonyPalmer told the Alaska Senate ResourcesCommittee Aug. 16 that the Alaska PipelineProject is on schedule with technical andregulatory matters, but not on the commer-cial side.

TransCanada and its partnerExxonMobil completed an open season forthe project July 30, 2010. At that timePalmer said that if things went well, prece-dent agreements — the commercial side ofthe project — could be signed by the end of the year.

He told legislators at the mid-August hearing held by theSenate Resources Committee that negotiations are still going onfor commercial agreements.

The State of Alaska needs to resolve Point Thomson and gasfiscals issues, Palmer said, and told legislators he was encouraged

ANWR plan leans to wildernessexpansion; public comment open

The federal rollout of a draft management plan that couldlead to huge new sections of the Arctic National WildlifeRefuge being designated “wilderness,” including the poten-tially oil-rich coastal plain, drew immediate disdain from topAlaska politicians.

The U.S. Fish and Wildlife Service, which acts as landlordfor ANWR, is wasting time and money reviewing whether tomake more of the refuge wilderness, said Sen. Mark Begich,a Democrat.

“I’ll fight every step of the way any effort by federalbureaucrats to close off this enormous source of oil and gas byslapping it with more wilderness designation,” he said.

Oil and gas exploration and development already is pro-hibited in ANWR, but a wilderness designation could harden

TONY PALMER

see GAS LINE TALKS page 18

see ANWR PLAN page 12

http://www.PetroleumNews.com/

2 PETROLEUM NEWS • WEEK OF AUGUST 21, 2011

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

5 DOG approves various land deals in July

13 Guide to Alaska natural gas projects

9 Oil tops Western Canada drilling

18 US drilling count up by 39 to 1,959

19 US oil well celebrates 150th birthday

EXPLORATION & PRODUCTION

ALTERNATIVE ENERGY

GOVERNMENT

LAND & LEASING

PIPELINES & DOWNSTREAM

FINANCE & ECONOMY

11 EIA expects refiner crude cost of $100

Agency’s August short-term outlook based on globalspare production capacity, assumes US GDP growth of 2.4%, 2.6% this year, next

10 Settlement reached on pipeline tariff

Cook Inlet gas producers, utilities agree on booking and fee arrangements for transporting gas in key part of Beluga gas line infrastructure

NATURAL GAS

7 FERC holds tidal power scoping meeting

Staff from Federal Energy Regulatory Commission to be in Anchorage in August for Turnagain Arm Tidal Electric Energy Project plan

4 Young works to educate federal lawmakers

Alaska’s congressman brings colleagues to Alaska,stressing importance of state’s resources; continues to press for ANWR drilling

8 USCG commandant outlines Arctic needs

Papp emphasizes importance of U.S. icebreakers,support infrastructure and emergency responsecapabilities as sea ice recedes

6 In-state bullet line gets questions

Senate Resources Committee members wonder if newCook Inlet natural gas estimates could make line to Southcentral unnecessary

5 Canadian oil sands players on edge

Mining projects vulnerable to market turbulence, sliding oil prices; companies without existing operations face greatest threat

SIDEBAR, Page 7: Agencies to begin hydrokinetic studies

ANWR plan leans to wilderness expansion; public comment open

TransCanada: company still in talks with potential shippers

ON THE COVERThree in a row

Enstar files new Buccaneer, Aurora & Cook Inlet Energy gas contracts

Field fight over?

Alaska, Exxon have ‘resolution in principle’ on Point Thomson, Sullivan says

Beating a path to the Gulf

Enbridge enters contest to build lines from Alberta, Bakken, to Texas refineries

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Beluga River

Beluga Power Station

http://www.colvilleinc.com/

PETROLEUM NEWS • WEEK OF AUGUST 21, 2011 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay, Maintenance BPSky Top Brewster NE-12 15 (SCR/TD) Doyon Yard for Modification ENIDreco 1000 UE 16 (SCR/TD) Milne Point MPK-02 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD4-210 ConocoPhillipsAC Mobile 25 Prudhoe Bay A-25B BPOIME 2000 141 (SCR/TD) Kuparuk Standby ConocoPhillipsTSM 7000 Arctic Wolf #2 In Nisku, AB Available

Kuukpik 5 Preparing to start rig up on Savik #1 North Slope Borough

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableAC Coil Hybrid CDR-2 Kuparuk 3H-12A ConcoPhillipsDreco 1000 UE 2-ES Prudhoe Bay Stacked out AvailableMid-Continental U36A 3-S Prudhoe Bay Stacked out AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay X-22A BPEmsco Electro-hoist 7-E (SCR-TD) Prudhoe Bay DS12-27A BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay PBU 13-27B BPDreco 1000 UE 9-ES (SCR/TD) Has been released by Brooks Range Available

PetroleumOilwell 2000 Hercules 14-E (SCR) Prudhoe Bay Stacked out AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Stacked out AvailableOilwell 2000 17-E (SCR/TD) Prudhoe Bay Stacked out AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Canrig 1050E 27-E* Stacked at Deadhorse PioneerAcademy AC electric Heli-Rig 106-E (SCR/TD) Stacked at Deadhorse AvailableOIME 2000 245-E Oliktok Point OP18-08 ENI

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

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site K-05D BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Pad 10 Conducting BP

MaintenanceIdeco 900 3 (SCR/TD) Kuparuk Drill Site 1D-102 ConocoPhillips

North Slope - Offshore

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

Nabors Alaska DrillingOIME 1000 19-E (SCR) Oooguruk ODSK-13 Pioneer Natural ResourcesOilwell 2000 33-E Prudhoe Bay Stacked out Available

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Drilling NCU 10 Aurora Gas

Cook Inlet EnergyAtlas Copco RD20 34 Undergoing winterization Cook Inlet Energy

at W. McArthur River UnitDoyon DrillingTSM 7000 Arctic Fox #1 Beluga 224-23T ConocoPhillips

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Susan Dionne #7 Buccaneer Alaska

Nabors Alaska DrillingContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked AvailableAcademy AC electric Canrig 105-E (SCR-TD) Going to drill for CINGSA and should CINGSA

spud well CLU-3 in next couple of daysRigmaster 850 129 Kenai Stacked out Available

Rowan CompaniesAC Electric 68AC (SCR/TD) Demobilizing and prepping Pioneer Natural Resources

to ship to Lower 48

Cook Inlet Basin – Offshore

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

XTO EnergyNational 1320 A Coil tubing cleanout planned off Platform XTO

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

Mackenzie Rig StatusCanadian Beaufort Sea

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

Central Mackenzie Valley

Akita/SAHTUOilwell 500 51 Has left the NWT Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of August 18, 2011.

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts*August 12 August 5 Year Ago

US 1,959 1,920 1,640Canada 464 434 359Gulf 35 36 20

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Reportis sponsored by:

JUDY

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By STEVE QUINNFor Petroleum News

Any federal lawmaker who isn’t con-vinced about the prospects of

Alaska’s role toward increased domesticoil and gas production and in boosting theeconomy, check in with Alaska’s loneCongressman Don Young.

He’ll be happy to show you aroundthe state as long as you’re willing tomake the seven-hour flight to the stateand spend several more hours on a planesurveying the vast fields and Arcticwaters that contain billions of barrels ofreserves.

Young recently played host to HouseResources Committee Chairman DocHastings of Washington.

In July the committee passed theNPR-A Access Act designed to expeditepermitting.

Young recently discussed Alaska’resource development prospects withPetroleum News, highlighting his inten-tions to bring more lawmakers to Alaska

next year.

Petroleum News:Talk about this tech-nique of bringingpeople like DocHastings to thestate.

Young: Next yearI’m going to bring agroup to Alaska.We’ll show them Southeast; we’ll showthem the Railbelt; we’ll show them theInterior. So they can visualize the chal-lenges we have, the people who are thereand the resources we have. When I see15,000 high paying jobs leavingSoutheast, Alaska — that’s wrong. Itgoes to development of resources. Youwon’t get that employment back until westart manufacturing in the United States.A lot of people say it’s the cheap laboroverseas. To some degree it is. The reali-ty, labor is relatively high. It’s high inEurope. It’s relatively high in Japan. InChina, they are going huckly buck. It’s

really not labor. It’s the delay and returnon investment when we have to gothrough a process of getting a permit notonly from the federal government, butfrom the state, and from the borough andfrom the city to put a manufacturingplant in. If it takes 10 years to get yourmoney back why would you invest inthe United States? You wouldn’t. You’dgo where you can get a return in fiveyears. We have become over governed.We are over regulated. It’s not just feder-al. The state is equally as bad.

Petroleum News: Who do you thinkshould come to Alaska to see what it cancontribute to the nation?

Young: I want to get key players I’mgoing to try to get sixRepublicans and sixDemocrats that are interest-ed in resource developmentand investment and see ifthey can make sure theyunderstand it. They won’t always agreebecause their constituents don’t under-stand it. I remember Sen. BarbaraMikulski of Maryland landed in PrudhoeBay, went to Kaktovik and said is this it?She went back and voted against itbecause her people don’t know the dif-ference. That’s the real challenge. Weare a service-oriented state. We have agood fishing industry; we have the min-ing industry getting better; but the oil isdeclining, we have no timber industry,so we are living primarily with tourists.So, I’m going to bring people up there toshow them and warn them as we flyover so they can visualize it as we landand visit these communities.

Petroleum News: You said sixDemocrats and Republicans. Does ithelp to reach across the aisle like that?

Young: I’ve always done it that way.When I was chairman of transportation,(former Minnesota Congressman) JimmyOberstar, he and I worked real closetogether and we never had an adversarialvote during the six years I was there. Wehad united 75 members who were veryloyal to the committee. That’s how wegot a lot of things done.

Petroleum News: Why is it takingD.C. so long to view Alaska as aresource state?

Young: A lot of it is our fault. I saythat with no doubt in our mind. It’s when

this whole land battle started. I triedtalking Gov. (Jay) Hammond into shut-ting down the pipeline. It was our oiland draw attention to that. You shutdown 2 million barrels of oil and you gettheir attention about how important thisstate is. It’s a big state. Down here theyjust don’t quite understand that.

Petroleum News: Do you believe peo-ple still are taking the oil production forgranted with the consistently high pricethis year?

Young: That’s exactly right. We stillhave people in Anchorage that franklywho don’t know their broadside fromtheir backside when it comes to econom-ics. Unfortunately, too many Alaskans,

as long as they get their per-manent fund dividendchecks and they have a job,they are happy. They don’trealize that’s coming fromone source of income, a

diminishing source: oil. That’s from Prudhoe Bay, which has

been in place for about 35 years. Peoplethink well it won’t stop. The truth of thematter is that it can stop. That’s sadbecause we have tremendous oil and gascapability in Alaska and the rest of theUnited States by the way. We havetremendous gas. The (Obama) adminis-tration is coming down with new frackregulations to keep them from gettingthe gas.

That’s one reason the economy won’tgrow back. If we drop gasoline prices to$2.50, every family would have anincreased income probably from around$1,500 to $2,000 a year. That would be agreat boom for money to buy otherthings from money which right now theyare pouring money down the tank. We sithere on our backside while China is buy-ing everything they can as far as naturalresources They have to have 25 millionnew jobs a year to keep their economygoing. They are manufacturing from ournatural resources and sending it back tous.

Petroleum News: One of the key bat-tles is ANWR. Why do you keep pushingfor it? Some call it a wheel spinningexercise.

Young: I don’t believe that. I willpass it out of the House. It will be the12th time I get it out of the House. The


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� G O V E R N M E N T

Young works to educate federal lawmakersAlaska’s congressman brings colleagues to Alaska, stressing importance of state’s resources; continues to press for ANWR drilling

REP. DON YOUNG

see YOUNG Q&A page 17

http://www.gdiving.com/

http://www.umalaska.com/

By GARY PARKFor Petroleum News

T he one constant in the Alberta oil sands is volatility,with the latest round of stock market upheaval and

nose-diving crude prices threatening the profitability offuture projects and billions of investment dollars.

The greatest anxiety surrounds mining projects, whereopen pit operations strip away the bitumen deposits that areprocessed into synthetic crude for further refining.

Bob Dunbar, president of Strategy West, an oil sands con-sulting firm, estimates that a standalone mine needs oilprices in the $80-$100 per barrel range to be economic.

“Those are the kinds of projects that might be jeopardizedif investors take a more pessimistic long-term view of oilprices,” he said.

The current pressure is on companies that don’t haveexisting operations and must rely on access to capital mar-kets, which are in a jittery state at present, Dunbar suggest-ed.

Of less concern are the thermal recovery projects, domi-nated by steam-assisted gravity drainage technology, whichinjects steam to melt deep bitumen deposits, allowing themto reach the surface.

They probably need an oil-price threshold of $60-$80 togenerate acceptable returns, Dunbar said.

Canadian dollar robustCompounding the numbers problems is the robust

Canadian dollar, which has been trading above the U.S. dol-lar for several months, eating into returns from U.S.-dollar-denominated exports.

If that isn’t enough, the Alberta government has alsoraised the specter of rising interest rates in Europe and theU.S. — a prospect that currently seems unlikely.

But, just in case, Alberta warned earlier this year that a“rapid increase in interest rates and/or disruptions in finan-cial and credit markets could threaten global trade and

investment. The high capital-intensity of Alberta’s oil sandsprojects leaves Alberta particularly vulnerable to theseshocks, as witnessed in 2009.”

Suncor Energy, the largest oil sands producer, reported aforeign-currency charge of $684 million last year.

Adding to the pain has been the growing gap betweenCanada’s heavier crudes and the U.S. light sweet benchmarkWest Texas Intermediate which is currently running at a gapof $15 per barrel between Western Canadian Select bitumenand WTI.

The challenge is clear for a company such as Suncor,which posted cash operating costs of C$51 per barrel in thesecond quarter at a time when it is on the verge of finalinvestment decisions with its joint-venture partner Totalinvolving C$21.6 billion to build the Fort Hills and Joslynmines and the Voyageur upgrader.

Suncor has already shown it will not proceed in a stormyeconomic environment by delaying the C$6 billionVoyageur project when the financial meltdown occurred in2008.

Imperial in homestretchImperial Oil, owned 69.6 percent by ExxonMobil, has

entered the homestretch with construction of the C$10.9 bil-lion first phase of its Kearl mine, which is scheduled to comeon line late in 2012 at 110,000 bpd.

Although Kearl’s capital costs have reportedly beenclimbing, Imperial is refusing to flinch, noting the project isexpected to have a lifespan of 40 to 50 years.

Already battered and bruised since January by an explo-sion and fire at its 110,000 bpd Horizon mine, which had

previously been a victim of capital cost overruns, CanadianNatural Resources is resolved not to get caught in a repeatexperience.

CNR has so far spent C$1.4 billion on the next phase ofHorizon expansion and company President Steve Laut esti-mates capital spending must be kept under C$100,000 perflowing barrel for the project to be economic at US$80 oil.

If the market for labor and materials starts to overheat, heis blunt: “We will take a time out.”

To prepare for the worst, CNR said its plans for reaching250,000 bpd of production have been broken up into fivemajor components, which have been further divided into 46individual projects, which the company can start and stop atits discretion.

By creating smaller components “we are minimizing thechances of constraining capital and maximizing our abilityto control costs and adapt to changing market conditions,”Laut said.

Juniors especially nervousWhile the majors can ride out shorter-term storms and

take a longer-range view of their investments, junior opera-tors, many of them with little or no independent cash flow,are especially nervous.

Harvest Energy, taken over by Korea National Oil Corp.in late 2009, said its BlackGold thermal project has experi-enced enough cost and schedule pressure to force the com-pany to evaluate ways to minimize the impact on its plans todeliver its first oil in 2013 and produce 30,000 bpd over 25years.

When the stock markets took their precipitous plunge onAug. 8, BlackPearl lost 21.3 percent, Petrobank Energy andResources was down 16.3 percent, MEG Energy fell 11.5percent and Athabasca Oil Sands was off 10.8 percent,compared with a 6.9 percent decline for Suncor. �


� F I N A N C E & E C O N O M Y

Canadian oil sands players on edgeMining projects vulnerable to market turbulence, sliding oil prices; companies without existing operations face greatest threat

Bob Dunbar, president of Strategy West, an oilsands consulting firm, estimates that a

standalone mine needs oil prices in the $80-$100 per barrel range to be economic.

Contact Gary Park through [email protected]

LAND & LEASINGDOG approves various land deals in July

Alaska Venture Capital Group LLC completed its acquisition of a bundle ofleases on the eastern North Slope in July, according to recent Alaska Division ofOil and Gas files.

BG Group and Arctic Slope Regional Corp. transferred 40 percent and 10 per-cent working interest, respectively, in 23 leases to AVCG. Anadarko PetroleumCorp. transferred the remaining 50 percent working interest in June. The leasesare part of the Greater Bullen unit that AVCG and its partners want to form over200,058 acres just west of the Arctic National Wildlife Refuge, between theBadami and Point Thomson units.

The division also approved the transfer of 70 percent working interest and 56percent royalty interest in six Beaufort Sea leases from GMT Exploration Co.LLC to Repsol E&P USA Inc. The deal is one piece of a partnership between theSpanish major Repsol and Denver-based independents GMT and the Armstrongsubsidiary 70&148 LLC.

Chevron transferred a small working and royalty interest, less than 5 percent,of one North Slope lease, ADL 390506, to Pioneer Natural Resources Alaska Inc.

Finally, New Energy Alaska LLC transferred several small royalty interests, allin values of 1 percent or less, in two Cook Inlet leases to nine independentinvestors.

NOTE: A copyrighted oil and gas lease map from Mapmakers Alaska(www.mapmakersalaska.com/) was a research tool used in preparing this story.

—ERIC LIDJI

http://www.egliair.com/

http://www.flyera.com/

By KRISTEN NELSONPetroleum News

The State of Alaska is currently put-ting money into two gas pipeline

projects — a large line from the NorthSlope to major markets (with spur lineswithin Alaska) and a smaller line from theNorth Slope to Interior and Southcentralmarkets.

The Alaska Senate ResourcesCommittee met in Anchorage Aug. 15-17to hear updates, starting with Dan Fauske,president of the Alaska GaslineDevelopment Corp., established by theLegislature last year to determine if an in-state line was economic and to have itoperational by the end of 2015. (SeeTransCanada update on page 1 of thisissue.)

Available Cook Inlet gas was of con-siderable interest to legislators, followinga recent Buccaneer onshore discovery, thearrival of a jack-up rig to drill forEscopeta and the release of a U.S.Geological Survey estimate of undiscov-ered resources.

Rep. Peggy Wilson asked what theeffect would be of a big Cook Inlet dis-covery.

Joe Dubler, AGDC vice president andCFO, said the largest impact would be onthe amount of liquefied natural gas Enstarwould have to import between now and2019.

Sen. Bill Wielechowski asked ifAGDC’s work was done before the latest

USGS estimates of undiscoveredresources, a mean of 19 trillion cubic feet.

Lieza Wilcox, AGDC commercial ana-lyst, said it was.

Undiscovered resourcesBrenda Pierce, USGS resources man-

ager, told the committee Aug. 16 that theestimates are for technically recoverableresources, with today’s technology andindustry practices, and cover onlyonshore Cook Inlet and state waters, notthe outer continental shelf.

The range of undiscovered natural gasis 5 tcf (at a 95 percent confidence level)to 39.7 tcf (at a 5 percent confidencelevel). This compares, she said, to cumu-lative production of natural gas in CookInlet of some 7.8 tcf.

This does not include known reserves,Pierce said.

Those estimates are not all accessible— large areas are not open for drilling —and they do not indicate what volume ofthe technically recoverable would be eco-nomically viable, she said.

Pierce said USGS works closely withthe Alaska Division of Oil and Gas andthe Division of Geological and

Geophysical Surveys to understand therocks, but when it comes to running thenumbers, USGS does that by itself.

Resources co-Chair Joe Paskvan notedthat the 5 tcf at the 95 percent confidencelevel, combined with estimated reservesof 1.8 tcf, a total of 6.8 tcf, is in the rangeof the 7.8 tcf already produced.

Pierce said she thinks there’s realpotential in the Cook Inlet basin, but co-Chair Tom Wagoner noted that “untilsomebody proves it’s economic we can’tcount on any of this.”

Concerns about demandSen. Bert Stedman was concerned

about the assumption that there would beexport demand, and said he would like tosee more assured markets. If the state had$8 billion to spend, is this what we’dspend it on? He asked: Is this the onlyalternative for power for the Railbelt?

Fauske noted that AGDC only had ayear to do the work, and said not all ques-tions can be answered in a year. He alsonoted that a lot of information, such as theUSGS estimate, came in at the end.

But, he said, if there was a large find inCook Inlet, natural gas could be sentnorth to Fairbanks.

Wagoner said that while the studytakes account of the Watana dam project,there is no mention of the geothermalpotential Ormat is working on or CookInlet Region Inc.’s coal gas project.

Wilcox described the liquefied naturalgas alternative AGDC looked at, withestimated costs at $14 to $19 per millionBtu. She said they didn’t include all ener-gy options, but that LNG was the mostavailable to fulfill the entire energydemand of the area.

Tariff issuePaskvan was concerned about the dif-

ference between an estimated tariff toSouthcentral, $5.63 before gas and localdistribution costs of $2 each, and $6.45 toFairbanks.

Mike Elenbaas, a manager at Blackand Veatch, said tariff modeling wasbased on allocating costs to consumersreceiving benefit. Fairbanks pays a lowercost because of the gas going toAnchorage, he said.

Paskvan shot back that there is a lowertariff to Anchorage because of Fairbanksdemand, but that Fairbanks bears the costof a $255 million straddle plant, neces-

sary because the line as modeled carriesnatural gas liquids and they have to beextracted where a spur line goes toFairbanks. Ultimate NGL extractionwould be at a plant in Southcentral.

Elenbaas said the overall tariff is lowerbecause of NGL content in the gas.

The tariff modeling was based on whatwould be most defensible in front of reg-ulators, Wilcox said. The cost causerbeing the cost payer is a principle theRegulatory Commission of Alaska hasfollowed, she said.

Other offtake points could also requirestraddle plants, she said, calling a“postage stamp” rate — the same rate forall — less defensible.

Paskvan said he was concerned thatFairbanks subsidizes Anchorage andasked about moving NGL through the oilline; he said there had been discussions ofinjecting NGL south of Pump Station 1 tosolve vaporization issues.

Benefit of state ownershipFauske said a big drop in the tariff, $1

to $1.20, occurs if the state owns the line,because financing would be 100 percentdebt and the state has a triple-A ratingwhile most builder-owner-operators haveB-plus-plus ratings.

As to who finances, Stedman said thestate has typically put in half on hydroprojects, and asked how legislatorsshould set fairness across the state.

Fauske said his initial concern hadbeen that the state would have to put upcash, while this proposal is for revenuebonds. It’s a policy decision, he said, not-ing that for equity across the statepropane and LNG are possible.

All issues need to be explored, Fauskesaid, and the product has to beat importedLNG and propane already available.

Where the money goesLarry Persily, federal coordinator for

Alaska Natural Gas TransportationProjects, told the committee Aug. 17 thatan in-state line would have many of thesame problems as a main line, just on asmaller scale, including a need for fiscalterms.

He said Alaskans need to stop thinkingabout the big line and an in-state line ascompetitors and think about how to com-bine them.

Persily restated remarks he’s made in


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In-state bullet line gets questionsSenate Resources Committee members wonder if new Cook Inlet natural gas estimates could make line to Southcentral unnecessary

Paskvan was concerned about thedifference between an estimated

tariff to Southcentral, $5.63 beforegas and local distribution costs of$2 each, and $6.45 to Fairbanks.

see BULLET LINE page 12

http://www.bakerhughes.com/pressurepumping

http://www.alaska-analytical.com/


Could there be a new island inTurnagain Arm’s future — along with

240 megawatts of tidal-generated electrici-ty?

Dominic S.F. Lee of Anchorage is pro-posing a hydrokinetic energy project forTurnagain Arm which would include abank of turbines in Turnagain Arm, backedby a water reservoir 1 mile by 2 miles indiameter to store water for use during slacktides.

Federal Energy RegulatoryCommission representatives were inAnchorage Aug. 9 for scoping meetings onthe proposal.

Lee originally applied to FERC in 2009for a tidal fence project in Turnagain Armusing Davis turbines. The company spon-sor for that project was Anchorage-basedLittle Susitna Construction Co.

But in a May 10 filing from TurnagainArm Tidal Energy Corp., Lee told FERCthat after further engineering study “it wasdetermined that the Davis turbinesdeployed in tidal fence arrangement …were considered experimental and were notaccepted for current use.”

Lee said at the FERC scoping meetingthat Turnagain Arm Tidal Energy Corp.was formed in 2009 specifically for theCook Inlet energy project.

The revised plan, based on a tidal powerproject in La Rance, France, which hasbeen in operation since 1966, would use a“bulb type of turbine,” with a barrage 1,000feet long and 100 feet wide five miles fromPossession Point near Fire Island.

Lee said the bulb-type turbines havebeen in operation at La Rance for morethan 45 years with no recorded break-downs.

The construction cost is estimated at$760 million, Lee said, and would produce240 megawatts of power.

Reservoir 1 mile by 2 milesThe barrage would be backed by a

reservoir 1 mile by 2 miles — a storagetank for water to be used to drive the tur-bines during slack tide. The height of thetank would be 20 feet about high tide.

Lee said that while tidal power is pre-dictable, it is intermittent because of theslack tide period — hence the storage tank.He said the slack tide in Turnagain Arm isshort, 15 to 30 minutes, and the reservoirprovides moving water for energy produc-tion during the slack tide.

The project would be in Turnagain Arm,southwest of Fire Island, with a submergedcable running onshore to a switch yard inAnchorage and onshore to a control build-ing on Point Possession at the northern endof the Kenai Peninsula.

A new islandLee said at the morning scoping meet-

ing that Turnagain Arm is an ideal place fortidal power because it has the fourth-high-

est tides in the world. He said the RanceTidal Power Station in Brittany has beenproducing continuously since 1966 andproviding power at 1.2 cents per kilowatthour since costs were paid off in 1986.Because the tidal power project in Brittanyis connected to the national power grid,slack tide isn’t an issue with that project, hesaid.

But Anchorage is not on a national grid,so the storage tank provides water to movethe turbines during slack tide.

Slot gates would be open during floodtide and closed in ebb and slack tide.During flood tide a pump system would fillthe storage tank to 10 feet above high-tidelevel and during slack tide slot gates wouldbe raised and the turbines would be turnedby water coming out of the storage tank.

The reservoir would have a concretewall surrounded by rock. Lee said the bar-rage and reservoir would function as anisland; fish and sea mammals can swimaround it and it may provide habitat forbirds and sea mammals, he said.

Wildlife questionsIn response to a question about fish

studies for the French project, and whetherthere were whales in that area, Lee said thatfish 3-4 feet long swim through the Frenchproject. He said the turbines turn slowly,slower than a revolving hotel door.

Beluga whales, he said, would beblocked from the turbines in the TurnagainArm project.

Asked whether fish could be trapped inthe reservoir, Lee said water flows in andout and the gates open and close, so fishcould get in but could also get out when thegates are open.

Asked about rock for the project, Leesaid TATEC has a memorandum of under-standing with a rock quarry owner who has15-30 million cubic yards available; theproject, he said, would need 10-12 million

cubic yards. Asked about screening for water being

pumped into the reservoir, Lee said waterwould be drawn from an area more than180 feet deep, where fish are not expected.The project area itself is in water about 60feet deep.

Other questions and issues from regula-tors — including the Alaska Department ofFish and Game, the U.S. Fish and WildlifeService, the National Park Service and theNational Marine Fisheries Service includ-

ed: impact of pumping on marine species;ice formation in the tank in winter; affecton hydrology in Cook Inlet and on somedeeper channels in the inlet that may beimportant to belugas; possible changes intidal regime due to changes in geometryand bathymetry of Cook Inlet; possibilityof sedimentation around a new island; abil-ity to see sediment buildup in inlet condi-tions; whether project would cause morechannel movement in Turnagain Arm; andwhether an island a mile wide wouldimpact bore tides in 18-mile wide area.

EIS requiredKim Nguyen, the FERC project engi-

neer, said an environmental impact state-ment will be required for the project.

She said agencies need to submit studyrequests and comments within 30 daysunder the integrated licensing process forthe license.

There is a six to eight month period forFERC to define study plans, Nguyen said.

A second scoping document, if needed,would be issued Oct. 24; there is a resolutionprocess for any study disputes scheduled forApril through June of next year. The firststudy season would be in 2012; if necessarya second study season would be held.

TATEC would file a preliminary licens-ing proposal in September 2014; a final EISwould be issued in July 2015 and a licenseorder in September 2015. �


� A L T E R N A T I V E E N E R G Y

FERC holds tidal power scoping meetingStaff from Federal Energy Regulatory Commission to be in Anchorage in August for Turnagain Arm Tidal Electric Energy Project plan

Agencies to begin hydrokinetic studiesThe State of Alaska is interested in gathering data on Cook Inlet hydrokinetic

energy. The Alaska Energy Authority said Aug. 16 that it has signed a memorandum of

agreement with the National Oceanic and Atmospheric Administration to conducta baseline assessment of tidal hydrokinetic energy in Cook Inlet.

AEA said that over the next few years NOAA will be measuring and modelingwater levels and three-dimensional current, salinity and temperature fields withinCook Inlet to identify regions with promise for the generation of hydrokineticenergy.

“We are pleased to partner with NOAA on this project,” said Peter Crimp, AEAalternative energy and energy efficiency deputy director. “Many Alaskans knowthe power of Cook Inlet tides, and through these studies we will gain valuableinformation for harnessing that power.”

AEA and NOAA will hold a stakeholder meeting from 8:30 a.m. to 5 p.m. Aug.24 at the Clarion Suites Downtown, 1100 West 8th Ave., Anchorage.

AEA said the agencies hope to gather input from stakeholders with interest inCook Inlet hydrokinetic energy to compile needed observations, engineeringrequirements and environmental considerations.

The meeting is open to the public. —KRISTEN NELSON

Contact Kristen Nelson at [email protected]

http://www.alutiiq.com/


For several years the U.S. Coast Guardhas been making moves towards a

heightened presence in the seas aroundAlaska’s Arctic coastline, as summer seaice retreats in response to global warming.And, with companies like Shell anxious tomove forward with exploratory drilling onthe Arctic outer continental shelf, as wellas increased vessel traffic in newly acces-sible Arctic sea routes, many view rampedup Coast Guard operations north of theArctic Circle as a necessary component ofthe changing Arctic world.

On Aug. 12 in Anchorage, Alaska, Sen.Mark Begich convened a field hearing ofthe U.S. Senate Oceans, Atmosphere,Fisheries and Coast Guard Subcommittee,to hear testimony from Admiral RobertPapp, USCG commandant, on the futureof the Coast Guard in Alaska.

“I can report thatour Coast Guard isready to meet ourmission demands,but we’re also facingmany challenges,”Papp said. “There isincreased vessel traf-fic, including largeforeign tankers usingRussia’s ice-freenorthern sea route which exits through theBering Sea into our richest fishinggrounds.”

Limited capabilitiesThe Coast Guard has very limited

Arctic emergency response capabilities, noinfrastructure on Alaska’s North Slope tosupport its operations and only one opera-tional Arctic icebreaker, he said. And, withthe necessity to deploy personnel toremote locations around Alaska, providing

adequate accommodation for those per-sonnel, as well as appropriate supportfacilities, at a time of budgetary constraintspresents a significant challenge.

From the perspective of offshore oilspill prevention and response, as industryoil exploration advances, the Coast Guardcurrently has no pollution response capa-bilities and, working in conjunction withthe U.S. Department of the Interior, isentirely dependent on ensuring that oilcompanies have adequate responseresources in place, Papp said.

“While oil companies can assert thatthey have sufficient assets on site torespond to a worst-case (oil) dischargescenario, prudence dictates that we also

acquire an appropriate level of (federal)Arctic pollution response capabilities.Presently we have none,” Papp said.

After the hearing, Papp told PetroleumNews that the Gulf of Mexico DeepwaterHorizon disaster had demonstrated theimpossibility of knowing everything thatcan possibly go wrong with an offshoreoperation and, that without the necessaryresponse equipment available, people endup in a “stern chase,” trying to catch upwith the situation. So, although it is essen-tial to ensure that companies have theappropriate response equipment to supporttheir operations “we should have somelevel of federal response equipment aswell, so that we can join the fight and wecan take care of those unexpected inci-dents or consequences that might devel-op,” Papp said.

Papp also expressed concern about thelack of pre-authorization for the use of dis-persants to respond to an Arctic offshoreoil spill.

“We would like to have that in our toolpack,” he said.

New cuttersAs part of his testimony Papp said that

the Coast Guard is in the process of acquir-ing eight national security cutters, to con-duct high-seas missions such as fisheriespatrols in the Bering Sea. These high-endurance cutters need to be able to oper-ate anywhere from the Gulf of Alaska upto the Arctic Circle and beyond, he said.The first of the cutters has already goneinto service and successfully demonstratedits ability to conduct operations such aslaunching and recovering boats and heli-copters in sea conditions that would havepreviously rendered these operationsimpossible.

The second and third of these cuttersare nearing completion; the cutting of steelfor number four is under way; and contractnegotiations for the construction of num-ber five should be completed shortly, Pappsaid.

Need icebreakersHowever, the fact the Coast Guard now

only has one operational icebreaker pres-ents a major challenge when it comes tooperations in Arctic waters. Having ice-capable surface assets is vital for scientificresearch and the maintenance of sover-eignty, as well as for the provision ofemergency response assistance. A surfaceship, as distinct from an aircraft, can breaka ship out of the ice and tow it, Papp said.

Questioned about the possibility ofleasing icebreakers, given U.S. budgetaryconstraints on building new vessels, Pappsaid that, while this is an option worthy ofconsideration, leasing presents the risk of avessel not being available when the U.S.needs it — perhaps some mix of icebreak-er ownership and leasing might be a solu-tion to the icebreaker shortage, he suggest-ed.

Ice-capable buoy tendersPapp said that the Coast Guard is con-

sidering future roles for the 16 ice-capablebuoy tenders that it owns, with a plan tobring two of these vessels up to the U.S.Arctic in the summer of 2012. These ves-sels have demonstrated a capability tobreak ice on the Great Lakes and the CoastGuard deployed one of the vessels in theCanadian Arctic this summer. The main


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� G O V E R N M E N T

USCG commandant outlines Arctic needsPapp emphasizes importance of U.S. icebreakers, support infrastructure and emergency response capabilities as sea ice recedes

Papp said that he is not yetcertain whether some kind of

regional committee is needed forcommunity liaison in the Arctic.

see PAPP VISIT page 9

ROBERT PAPP

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

Oil tops Western Canada drillingBy GARY PARK

For Petroleum News

Western Canada’s petroleum industry is riding anoil wave, with Alberta tallying 2,556 develop-

ment wells in the first seven months, the highest point in30 years of record-keeping.

The four western provinces of Alberta, Saskatchewan,Manitoba and British Columbia racked up 3,727 devel-opment completions in the January-July period, 62 per-cent of completions for oil, gas, service and dry wells, up1,293 from the comparable oil count in the same time-frame last year.

Exploratory completions have also posted solid gainsat 554, compared with 407 a year ago, but exploratorydrilling has accounted for only 17 percent of all drillingso far this year, marking a continued decline.

The swing to oil, despite some volatility in crudeprices, looks certain to continue over at least the nextyear, with regulators in Western Canada issuing 6,678permits (which are valid for 12 months) for new oilwells, up 49 percent from the same seven-month periodlast year, while the total well permits rose 20 percent to10,388, the highest total since 2008.

A record 5,204 or 50 percent of the permits issued tothe end of July were for horizontal wells, compared with16 percent in 2008.

Completions up by a thirdIndustry and government regulators reported that

8,120 wells were completed across Canada in the sevenmonths, up 33 percent from last year’s 6,102 comple-tions.

The breakdown includes 4,295 oil wells, 2,755 gaswells, 827 service wells and 253 dry holes.

Saskatchewan was second to Alberta, with 1,492 oilcompletions, up 401 from last year, while Manitobadipped to 194 oil completions from 204.

An estimated 500 wells were completed acrossCanada in July, including 300 oil wells and 97 gas wells.

A total of 43.6 million feet of wells were drilled to the

end of July, including 2.9 million feet in July, which istypically the low point for the year.

Operators securing the most horizontal permits wereCanadian Natural Resources 357, Penn West Petroleum265, Crescent Point Energy 240, Husky Energy 188 andEncana 182.

The most popular zones were Viking at 745 licenses,Montney 556, Cardium 545, Bakken 359 and McMurray198.

The license count includes 1,083 oil sands evalua-tions, up from 783 a year ago and the most since 2008when the total was 1,737.

Regulators issued 893 permits for oil or bitumen tar-gets in July, up from 757 in July 2010 and the highest ina decade.

Of the seven-month total, 3,562 oil permits wereauthorized in Alberta, up from 2,280 last year; 2,756 inSaskatchewan, up from 1,766; and 324 for Manitoba,down from 325.

Gas and coalbed methane permits remained at adecade low 311 in July, down 47 from last year, and lag-ging far behind the peak 1,645 in 2004. �

A total of 43.6 million feet of wells weredrilled to the end of July, including 2.9 millionfeet in July, which is typically the low point for

the year.


limitation of a vessel of this type is thelack of a helicopter flight deck and hangar,he said.

The Arctic deployment of two buoytenders in 2012 would help achieve a goalof maintaining the presence of at least oneCoast Guard vessel at all times whenArctic offshore oil exploration starts, aswell as providing the Coast Guard withmore experience of Arctic operations,Papp said.

Papp told Petroleum News that theCoast Guard built oil skimming capacityinto its buoy tenders, a feature that couldprove valuable given the difficulty ofCoast Guard access to skimmers ownedby oil spill organizations but under con-tract to industry.

Community engagementPapp also stressed to the subcommittee

the importance of engagement with localcommunities, saying that the Coast Guardbecomes part of each community to whichit is assigned, listening to what peoplehave to say; promoting safety and securi-ty; and partnering with local people to dowhatever needs to be done. He said that hehad just spent nearly two days on theNorth Slope, listening to Mayor Itta of theNorth Slope Borough, the borough assem-bly and various members of the communi-ty. Papp said that he is not yet certainwhether some kind of regional committeeis needed for community liaison in theArctic. The Coast Guard must listen tocommunity concerns but may not needsomething as formal as a committee to dothat in the Arctic, he said. �

continued from page 8

PAPP VISIT

Papp also stressed to thesubcommittee the importance of

engagement with localcommunities, saying that the Coast

Guard becomes part of eachcommunity to which it is assigned,

listening to what people have tosay; promoting safety and security;and partnering with local people to

do whatever needs to be done.

Contact Alan Bailey at [email protected]

http://www.lynden.com/


The parties to a RegulatoryCommission of Alaska investigation

into a proposed new tariff for the Belugagas pipeline on the west side of Cook Inlethave reached a settlement over the termsof the tariff and have asked the commis-sion to approve the settlement within 30days.

The 100,000-cubic-feet-per-day capac-ity Beluga line connects gas fields on thewest side of Cook Inlet to ChugachElectric Association’s Beluga gas-firedpower plant and to the southern end ofEnstar Natural Co.’s gas transmission linethat carries gas north into the Matanuska-Susitna Borough area. With the line beinga critical link in the natural gas infrastruc-ture on the west side of the inlet, the tariffon the line is of great importance in deter-mining how gas producers and utilitiestransport gas to market, and in determin-ing the cost of that gas on delivery.

New tariffIn December 2010 Beluga Pipe Line

Co., a subsidiary of Marathon Oil Co.,filed a new tariff proposal, involving anannual fee of $46.67 to reserve one thou-sand cubic feet per day of line capacity,rather than charging for the volume of gasactually shipped. The tariff would haveenabled the shipping of gas in unreservedcapacity under certain circumstances, butat a greatly elevated volumetric fee of$2.5416 per thousand cubic feet. BelugaPipe Line had been charging its customers25.44 cents per thousand cubic feet totransport gas on the line.

Beluga Pipe Line said that the new tar-iff was addressing the problem of shippersonly using its line during spikes in gasdemand, especially during the winter, ausage pattern that renders a traditionalvolume throughput fee impractical tooperate. But the tariff proposal provoked aflurry of questions from gas shippers, con-cerned about the cost impacts of perhapshaving to reserve more pipeline capacitythan they need, or having to incur highfees for using unreserved space.

And the various parties involved in thedebate embarked on negotiations, assistedby an RCA-appointed judge, to find amutually agreeable tariff solution.

Choice of methodsUnder the terms of the resultant settle-

ment, gas shippers will be able to contin-ue to transport gas on the line at the cur-rent rate of 25.44 cents per thousand cubicfeet, but without a guarantee that therewill be space available on the line to shipthe gas. Shippers will be able to pre-bookguaranteed capacity on the line at a cost of25.44 cents per thousand cubic feet perday, a cost that would equal the currentcost of using the line if a shipper uses allof its reserved capacity. Any unusedcapacity can be carried forward for use ata later date in the same contract year.

And, as part of the settlement agree-ment, Chugach Electric Association andgas utility Enstar Natural Gas Co. signedfive-year contracts reserving capacity onthe line. CEA has reserved a capacity of21 million cubic feet per day for each

year, while Enstar has reserved 4 millioncubic feet per day in year one, declining to2 million cubic feet per day in year threeand reserving no capacity in years fourand five.

Pipeline infrastructureEnstar operates two gas transmission

lines for the delivery of utility gas intomain gas demand centers in theMunicipality of Anchorage and theMatanuska-Susitna Borough. One lineruns north from the west side of CookInlet and one, on the east side of the inlet,runs north through the northern KenaiPeninsula. Another gas line called theCook Inlet Gas Gathering System, orCIGGS, runs under Cook Inlet and carriesgas from oil and gas fields on the westside of the inlet into the gas pipeline infra-structure on the Kenai Peninsula, includ-ing the Enstar transmission line on that

side of the inlet.Although CIGGS connects with the

southern end of the Beluga pipeline, andhence with CEA’s Beluga power stationand with Enstar’s transmission line run-ning north into the Matanuska-SusitnaBorough, gas producers on the west sideof the inlet have tended to ship their gasthrough CIGGS to the Kenai Peninsulafor delivery to market. This pattern of gasmovement appears to result, at least inpart, from the fact that gas being deliveredinto CIGGS on the west side of the inletcan be transported through CIGGS to theeast side of the inlet at no incrementalcost, while also avoiding the cost of mov-ing the gas through the Beluga line.

Flexibility neededHowever, the Cook Inlet gas industry

is changing significantly, thus driving a

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

Settlement reached on pipeline tariffCook Inlet gas producers, utilities agree on booking and fee arrangements for transporting gas in key part of Beluga gas line infrastructure


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Port Nikiski

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Beluga River

Beluga Power Station

Gas Pipeline Oil Pipeline Major Road9 0 9 18 274.5

Miles

Cook Inlet, AlaskaPipeline System

MAPMAKERSALASKA

The Beluga gas pipeline runs between the Cook Inlet Gas Gathering System, or CIGGS, and the Beluga power plant on the west side of Alaska’sCook Inlet. The line can provide route to carry utility gas from the west side of the inlet into the Matanuska-Susitna valleys and Anchorage.However, much west-side gas destined for Anchorage currently flows through a Kenai Peninsula line via CIGGS under the Cook Inlet.

MA

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Based on U.S. real gross domesticproduct growth of 2.4 percent this

year and a continued decline in globalspare production capacity, the U.S.Energy Information Administration esti-mates that the refiner acquisition cost ofcrude oil in the U.S. will average $100 perbarrel this year and, with 2.6 percent GDPgrowth in 2012, $107 per barrel next year.

In its Aug. 9 short-term energy outlookEIA said its “assumptions do not fullyreflect recent economic and financialdevelopments that point towards a weakereconomic outlook and also contributed toa sharp drop in world crude oil prices dur-ing the first week of August.”

The agency said there “is a significantdownside risk for oil prices if economicand financial market concerns becomemore widespread or take hold.”

Supply disruptions an issueEIA said global oil demand growth, led

by China, is expected to outpace growthin supplies outside the Organization of thePetroleum Exporting Countries. As aresult, markets will rely on drawdown ofinventories and OPEC production increas-es, but the agency said OPEC countriesare not expected to increase productionmarkedly in the short term.

Major upside risks in the crude oilprice outlook include additional supplydisruptions in producing regions andhigher-than-expected demand growth,particularly in countries outside theOrganization for Economic Cooperationand Development. EIA said downsiderisks include rate of global economicrecovery and fiscal issues facing national

and sub-national governments. Non-OPEC supply is expected to

increase by an average of 650,000 barrelsper day of crude oil and liquid fuels, withthe greatest increasing in Brazil, Canada,China, Columbia, Kazakhstan and theUnited States, each averaging growth ofmore than 100,000 bpd. Productiondeclines are expected in the North Sea of140,000 bpd, particularly in the UnitedKingdom, and declines in Yemen of140,000 bpd based on ongoing strife.

Spot prices downWest Texas Intermediate crude oil spot

prices fell from an average of $110 perbarrel in April to $97 per barrel in July,EIA said, with world crude oil pricesfalling by about $10 per barrel in the firstweek of August, “reflecting market con-cerns about world economic and oildemand growth.”

The agency said it expects oil markets

to tighten as the demand for liquid fuelsgrows in emerging economies, continuingto outpace supply growth and puttingupward pressure on oil prices.

EIA said it expects WTI to average $96per barrel this year and $101 per barrel in2012, up from $79 last year.

Gas consumption growsNatural gas consumption rose with the

extremely hot weather in most of thenation in July, with U.S. population-weighted cooling-degree days 27 percenthigher than the 30-year norm and 8 per-cent higher than last year, contributing toan increase in natural gas use for electric-ity generation compared with July 2010.

EIA said it expects that total U.S. natu-ral gas consumption will grow by 1.8 per-cent to 67.4 billion cubic feet per day thisyear, with forecast industrial and electricpower consumption growth making upmost of the increase.

U.S. marketed natural gas productionis expected to average 65.5 bcf per daythis year, a 3.7 bcf per day (5.9 percent)increase over last year, with growth cen-tered in onshore Lower 48 production,which more than offsets projecteddeclines in the outer continental shelf Gulfof Mexico.

Growing domestic natural gas produc-tion is reducing reliance on imports, EIAsaid, and contributing to increasedexports.

The Henry Hub spot price averaged$4.42 per million Btu in July, 13 centslower than the June average. EIA said itexpects the Henry Hub price will average$4.24 per million Btu this year and $4.41in 2012, reflecting some tightening insupply as domestic production growthslows. �


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need for greater flexibility in the way inwhich gas is shipped. Changes include thedevelopment of new gas fields on the eastside of the inlet, the imminent moth-balling of an LNG export terminal atNikiski on the Kenai Peninsula and thedevelopment of a new gas storage facilitynear the City of Kenai. In addition, evertightening gas supplies from the CookInlet basin require utilities and gas pro-ducers to be able to make nimble changesto gas delivery routes, to ensure that gascan be delivered efficiently from gaswells to gas consumers during periods ofpeak gas demand.

Companies involved in the Cook Inletgas industry have for some time beennegotiating technical and commercialarrangements for bi-directional flow inCIGGS, arrangements that would enablegas to be shipped east to west under CookInlet and up through the Beluga line,when appropriate.

Bi-directional flow on CIGGS wouldadd greatly to the flexibility of gas trans-portation around the Cook Inlet basin,including the shipment of much neededgas from storage during peak winterdemand. But, pipeline tariffs, includingthe tariff on the Beluga line, play animportant role in determining the pricepaid for that flexibility. �


SETTLEMENT


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that policy.U.S. Sen. Lisa Murkowski, the top-

ranking Republican on the Senate Energyand Natural Resources Committee, arguedthe Fish and Wildlife Service lacks author-ity under ANILCA, the Alaska NationalInterest Lands Conservation Act of 1980, toeven study designating more wilderness inthe state.

“Instead of trying to lock up ourresources, we should be developing themas part of a balanced energy plan that cre-ates jobs and bolsters our failing economy,”Murkowski said. “There’s a tremendousamount of money buried in the ground inAlaska, and it’s time to withdraw it.”

Alaska’s Republican governor, SeanParnell, also objected to the draft 15-yearmanagement plan for ANWR.

“This is another unfortunate effort bythe Obama Administration to preventAmericans from developing Alaska’s vastresources for the benefit of the country,”Parnell said.

Conservation groups encouragedConservation groups, as well as a group

representing indigenous Gwich’in people,hailed the prospect of expanding wilder-ness within ANWR, the protection ofwhich has long been a top priority for theenvironmental community.

“We are encouraged that the Fish andWildlife Service is considering Wildernessrecommendations for the coastal plain, thebiological heart of the Arctic Refuge,” saidDan Ritzman, Alaska regional director forthe Sierra Club. “For decades Americansfrom all walks of life have asked for per-manent protection for these critical landsand waters and now they have the opportu-nity to move this one step closer to reality.”

“The Arctic Refuge is one of the coun-

try’s most treasured, pristine places, and asof yet remains unspoiled by widespreadindustrial scale oil and gas operations,” saidJamie Rappaport Clark, executive vicepresident of Defenders of Wildlife. “TheFish and Wildlife Service should seize theopportunity to strengthen protection for therefuge and its diversity of wildlife againstthe threat of Big Oil and pursue a wilder-ness recommendation.”

“Since President Eisenhower estab-lished the Arctic Refuge in 1960, our nationhas acted to embrace the bold wildernessvision of the refuge’s founders and to pro-tect it from oil and gas interests. In the faceof climate change and a renewed push todevelop the Arctic for oil and gas, ourcountry’s leaders should support the wishesof Americans by taking the necessary stepsto permanently protect the Arctic Refuge’scoastal plain — a globally significant, vitalhomeland and birthing ground for millionsof birds, polar bears and caribou, as well asa critical subsistence resource,” said NicoleWhittington-Evans, Alaska director for TheWilderness Society.

‘Preliminarily recommended’It’s far from assured that more ANWR

acreage will be designated wilderness.Such a measure would need to clear sever-al approvals before winning the ultimateOK from Congress.

The Fish and Wildlife Service in April2010 began work to revise what’s known asthe “comprehensive conservation plan” forANWR. The original plan was signed intoeffect in 1988, and the service says it’s time

to freshen it up.Already, the service has conducted a

scoping process, which generated morethan 94,000 comments from individualsand organizations.

Out of that has come the new draft com-prehensive conservation plan, which theservice announced on Aug. 12.

“The draft plan contains six alternativesfor long-term management, ranging fromthe continuation of current practices to thedesignation of three geographic areas(including the Arctic Refuge coastal plain)for potential inclusion within the NationalWilderness Preservation System, and thepotential designation of four additionalWild and Scenic Rivers on the refuge,” anagency press release said.

The draft plan does not identify a pre-ferred alternative, saying all options remainunder “active consideration.”

But it appears that sentiment within theFish and Wildlife Service favors establish-ing new wilderness areas within ANWR.

Located in the extreme northeast cornerof Alaska, the remote refuge takes in 19.3million acres — nearly the size of SouthCarolina. About 40 percent of ANWRalready is designated wilderness.

The draft plan — specifically AppendixH, the “wilderness review” — indicatesthree huge new chunks of ANWR are “pre-liminarily recommended for wildernessdesignation.”

These include the coastal plain at 1.6million acres; a southern ANWR areaknown as the Porcupine Plateau at 4.4 mil-lion acres; and the western Brooks Rangearea at 5.7 million acres.

All told, practically all of ANWR wouldbe wilderness if these three areas were des-ignated as such, with only relatively smallareas near villages remaining non-wilder-ness.

No oil, gas alternativesThe Fish and Wildlife Service is inviting

public comments on the draft plan throughNov. 15. The agency plans to hold publichearings around the state, including one in

Anchorage on Sept. 21 and another inFairbanks on Oct. 19.

The plan and details on how to submitcomments are online athttp://arctic.fws.gov/ccp.htm.

The agency aims to issue its “record ofdecision” by the end of 2012.

“If the final plan recommends additionalWilderness and/or Wild and Scenic Riverdesignations, the recommendation(s) wouldrequire approval by the Director of the Fishand Wildlife Service, the Secretary of theInterior, and the President,” the agencypress release said. “The President wouldthen submit the recommendation toCongress, which alone has the authority tomake final decisions on any proposedWilderness or Wild and Scenic River desig-nations.”

Although comments received during thescoping process overwhelmingly concernedthe coastal plain and the question of oil andgas activity, the Fish and Wildlife Servicechose not to include plan alternatives toallow oil and gas leasing or 3-D seismicshoots in ANWR, which the U.S.Geological Survey in 1999 estimated couldhold several billion barrels of oil.

The governor’s office criticized the serv-ice for excluding industry alternatives, call-ing that decision “inconsistent with existingfederal law.”

But nothing in the statutory mission ofthe National Wildlife Refuge Systemrequires the service to consider or proposedevelopment scenarios for oil and gas orother natural resources, the agency said.Anyway, the service added, Congress hasreserved the authority to make final deci-sions on oil and gas development inANWR.

As for criticism that its wildernessreview violates the “no more” clauses inANILCA, the service argues to the con-trary, saying the review is just a “tool” tomake sure ANWR is being managed right.

—WESLEY LOY


the past, telling legislators that if the stateis going to spend billions for higher-costnatural gas than the state would get froma big line, it needs to consider putting thatmoney into the big line. An in-state linebuilt as a spur line just from Fairbanks toSouthcentral is much more affordable, hesaid.

Persily said he was concerned aboutthe Alaska public, which appears tobelieve the big pipeline won’t happen andis turning to other less attractive options.

Getting gas to Southcentral drove thein-state gas pipeline project, but with therevised project schedule from AGDCnow shows first gas in late 2018.

Persily advised against letting CookInlet drive the decision, because, he said,you can’t get the gas there in time.

Fairbanks load issueHarold Heinze, CEO of the Alaska

Natural Gas Development Authority,said he questioned the Fairbanks vol-

umes attributed to the line, some 60 mil-lion cubic feet a day, based on the recentannouncement that Golden ValleyElectric Association and Flint Hills werelooking at trucking LNG from the NorthSlope.

He said it would be hard for the bul-let line to compete with that. He notedthat 500 million cubic feet a day requiresan anchor tenant, 250 million has beendiscussed as the baseline, but said thatcould drop to 167 million cubic feet aday with LNG trucked to Fairbanks, sub-stantially raising the tariff, with Alaskaconsumers paying that cost.

Wagoner asked why the GVEA-FlintHills proposal would benefit Fairbanksbeyond those entities and Heinze saidthe Fairbanks gas market is primarilyGVEA and Flint Hills, actually locatedin North Pole, and close to the nextbiggest users, the military. If needed, hesaid, it would be easy enough to makeLNG deliveries at some point in down-town Fairbanks. �


BULLET LINE



ANWR PLANIt’s far from assured that more

ANWR acreage will be designatedwilderness. Such a measure would

need to clear several approvalsbefore winning the ultimate OK

from Congress

Contact Wesley Loy at [email protected]

http://www.canrig.com/

http://www.pdstech.com/

By BILL WHITEResearcher/writer for the Office

of the Federal Coordinator

Ideas for moving Prudhoe Bay’s naturalgas bounty off Alaska’s North Slope

are as plentiful as cottonwood seed in theJune air.

Some are modest: Truck smallamounts of gas to Fairbanks consumers.

Some are epic: Pipe massive amountsto Lower 48 consumers — the mostexpensive North American private-sectorconstruction project ever.

Some are pinned to visions of anAlaska energy utopia, where gas for localuse is plentiful and relatively cheap, theoil industry reawakens to develop newfields by the dozen, the state treasuryoverflows with wealth, and new indus-tries sprout from the earth like wildlupine.

Some are backed by tens or even hun-dreds of millions of dollars to design,engineer and otherwise prepare for con-struction. These include the majorpipeline through Canada and a muchmore modest pipeline to SouthcentralAlaska.

Some are little more than a conceptlooking to catch on.

The great North Slope oil discoveriesof the 1960s and 1970s also found an esti-mated 35 trillion cubic feet of natural gas- one and a half times the entire volume ofU.S. production last year. The U.S.Geological Survey estimates an addition-al 221 trillion cubic feet await discoveryin Alaska’s Arctic, onshore and offshore.If only an economically viable way couldbe found to move the gas to consumers.

Below we summarize several propos-als — big and small — for transportingnatural gas from Alaska’s North Slope.

Pipeline to AlbertaThis involves an approximately 1,700-

mile, 48-inch buried pipeline from thePrudhoe Bay field on Alaska’s NorthSlope to the British Columbia-Albertaborder in Canada. From there, the gascould flow to the Lower 48 via an exten-sive network of existing pipelines.

The gas line would parallel the trans-Alaska oil pipeline from Prudhoe Bay toDelta Junction, then continue into Canadaroughly parallel to the Alaska Highway.

The pipeline would move up to 4.5 bil-lion cubic feet of gas per day.

The project includes a 58-milepipeline to Prudhoe Bay from the PointThomson gas field.

SponsorTransCanada and ExxonMobil, also

known as the Alaska Pipeline Project.

Estimated cost$32 billion to $41 billion (2009 dol-

lars).The cost includes a $12 billion gas

treatment plant at the Prudhoe Bay fieldto remove water, carbon dioxide andother impurities from the gas, then com-press the raw gas before it enters thepipeline.

Gas for AlaskansThe pipeline would provide at least

five points in Alaska from which spurlines could be built to provide gas toAlaskans. The APP project involves onlyproviding gas takeoff points, not construc-tion of the spur lines, which would be upto the state, utilities or private companies.

StatusIn the development stage. The project

sponsor is refining details — from thephysical pipeline to the exact route —and seeking customers to ship gasthrough the line.

The Alaska Pipeline Project spent anestimated $303 million from the projectonset through June 2011 and plans tospend $209 million more during the fol-lowing 12 months. Under the AlaskaGasline Inducement Act of 2007, the stateplans to reimburse the sponsor for up to$500 million of its estimated $717 mil-lion in pre-construction costs.

Besides refining the project’s designand engineering, they are gathering vol-umes of data on fish, wildlife, soils, veg-etation, cultural sites, air quality andother information that can be used for theenvironmental impact statement theFederal Energy Regulatory Commissionwill prepare. The sponsor plans to applyto FERC in October 2012 for a certificateto construct and operate the pipeline.FERC’s review is expected to take abouttwo years.

The sponsor held an “open season” in2010 at which it solicited pipeline cus-tomers. Alaska Pipeline Project officialssaid they are negotiating with major com-panies that bid significant volumes.

The sponsor needs commitments formuch of its pipeline’s capacity to obtainconstruction financing.

Proposed timelineOctober 2012 — Project sponsor plans

to apply to the Federal Energy RegulatoryCommission for a certificate of publicconvenience and necessity allowingpipeline construction and operation.

2012-2014 — FERC reviews theapplication and produces an environmen-tal impact statement

2014 — U.S. and Canadian approvals

issued2015-2020 — Construction and com-

missioning2020 — First gas flows

Pluses• Short-term economic boost to Alaska

during construction. Estimated 7,000 jobsduring peak construction.

• Likely long-term economic boost asbillions of dollars in revenue flows tostate treasury, the Alaska Permanent Fundand local governments along the pipelineroute.

• Outlet for natural gas now strandedon Alaska’s North Slope should spur oiland gas exploration, finding new crudefor the trans-Alaska oil pipeline and extragas for a gas pipeline.

• With a spur line, consumers inAlaska’s Railbelt could be assured of anaffordable supply of gas for decades. Theproject likely is the cheapest source ofnew natural gas to supplement Cook Inletsupplies in Southcentral Alaska. For theFairbanks area, relatively inexpensive gaswould ease high energy prices for heatingand power generation.

• The project might give rise to twoindustries in Southcentral Alaska, onethat exports natural gas liquids and anoth-er that exports liquefied natural gas.

• About half of the construction costcould be backed by federal loan guaran-tees; federal tax breaks are available forpipeline and gas treatment plant.

Minuses• High cost makes project risky for

lenders that would supply constructionfinancing.

• Requires major gas shippers - likelythe North Slope producers - to commit tousing the pipeline for at least 20 years.

• Not knowing what natural gas mar-ket prices will be over that long time hori-

zon makes the project extremely risky forgas shippers. Low prices could shrink oreliminate their profits.

• North Slope producers want state ofAlaska to set stable fiscal terms for gasproduction and the pipeline.

• Fairbanks area energy costs remainrelatively high until 2020 or later, whennatural gas is flowing. Pipeline might notbe running before Southcentral Alaskaneeds supplemental source of natural gas.

Pipeline to SouthcentralA 737-mile, 24-inch buried pipeline

from the Prudhoe Bay field on Alaska’sNorth Slope to the Big Lake area ofSouthcentral Alaska. From there, the gascould flow to consumers, utilities andother industry via the local distributionpipelines of ENSTAR Natural Gas Co.Pipeline also would supply Fairbanksarea.

The pipeline would parallel the trans-Alaska oil pipeline from Prudhoe Bay tojust north of Fairbanks, then continuesouth to Big Lake, roughly parallel to theParks Highway.

The pipeline would move up to 500million cubic feet of gas per day. Theproject also is known as the “bullet line,”the in-state line and the Alaska StandAlone Pipeline, or ASAP.

SponsorAlaska Gasline Development Corp., a

state agency the Legislature created in2010.

Estimated cost$5.3 billion to $9.8 billion (2011 dol-

lars). Sponsor is using midpoint of $7.52billion as a working number.

The cost includes a $1.84 billion gastreatment plant at the Prudhoe Bay fieldto remove water, carbon dioxide andother impurities from the gas, then com-press the raw gas before it enters thepipeline.

Project cost does not include a sepa-rate 35-mile spur line as well as local gasdistribution network needed forFairbanks. A local gas pipeline network


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The great North Slope oil discoveries of the 1960s and 1970s also foundan estimated 35 trillion cubic feet of natural gas - one and a half times

the entire volume of U.S. production last year. The U.S. GeologicalSurvey estimates an additional 221 trillion cubic feet await discovery inAlaska’s Arctic, onshore and offshore. If only an economically viable way

could be found to move the gas to consumers

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already exists in Southcentral.

Gas for AlaskansGas for Alaskans was the main idea for

this project when the state Legislaturefunded a feasibility study in 2010.

StatusProject is in its very early stages.

Feasibility study issued in July 2011 pro-vided a preliminary plan, and the sponsorrecommends the state spend $370 millionto firm up the design, cost estimates andengineering, acquire permits and seekcustomers that would ship gas through thepipeline.

Proposed timeline2011-2015 — Project sponsor sharp-

ens engineering and cost estimate, obtainspermits, solicits customers

2015-2018 — Construction and com-missioning

2018-2019 — First gas flows


during construction of multibillion-dollarproject.

• The project could deliver gas toFairbanks and Southcentral two yearssooner than the larger pipeline to Alberta.

• Consumers in Alaska’s Railbelt couldbe assured of an affordable supply of gasfor decades. In Southcentral Alaska, thegas could supplement Cook Inlet suppliesused for heating and power generation.Delivering natural gas to Fairbanks couldgreatly lower that community’s high costof energy.

• The project might give rise to new

industries in Southcentral Alaska, onethat exports natural gas liquids and anoth-er that exports liquefied natural gas.

Minuses• Likely requires state to issue billions

of dollars in revenue bonds.• The cost estimate is soft. A much

higher cost than the midpoint $7.52 bil-lion estimate would alter the project eco-nomics.

• Requires major gas shippers to makelong-term commitments to use thepipeline.

• The project would produce far lessnew state revenue than the Albertapipeline due to the small volume of gasmoved and the state’s tax structure.

• Requires the state to bear all of thepre-construction cost because no privatedeveloper will do so.

• Project sponsor wants state law toexempt the pipeline’s shipping charges, ortariffs, from regulation.

• The cost of gas to Alaskans would behigher than gas from the pipeline toAlberta.

• The project would not spark as muchArctic oil and gas exploration as the big-ger pipeline.

• The project relies on a chain ofassumptions about demand for gas thatmust come true to make the gas as afford-able to Alaskans as predicted. Theseassumptions include:

1) A revived liquefied natural gasexport plant will take almost half of thedaily gas flow.

2) A separate business will invest near-ly $1 billion to build a plant in theMatanuska-Susitna Borough to takepropane and butane from the gas stream,process them and find buyers for theminside or outside Alaska.

3) A major mine, such as the Donlin

gold prospect in Western Alaska, willstart up by 2019 and consume 6 percentof the daily gas flow.

4) A utility or utilities will build a spurline and a local gas distribution pipelinenetwork in Fairbanks by the time thepipeline from Prudhoe Bay is ready.

5) Cook Inlet gas production will fallto such a point that power plants and thelocal gas utility in Southcentral Alaskawill consume about 20 percent of thepipeline’s gas.

Pipeline to ValdezAn 803-mile, 48-inch buried pipeline

from the Prudhoe Bay field on Alaska’sNorth Slope to Valdez. From there, thegas would be chilled to minus 260degrees to create liquefied natural gas, orLNG, that can be shipped on specialtankers to markets worldwide.

The pipeline would parallel the trans-Alaska oil pipeline.

The pipeline would move up to 3 bil-lion cubic feet of gas per day, withAlaskans using some and 2.8 billionarriving in Valdez for export.

SponsorsTwo separate groups have proposed

similar concepts for a Valdez pipeline.TransCanada and ExxonMobil, which

are pursuing the pipeline from Alaska toAlberta, also asked potential gas shippersin 2010 if they prefer a Valdez route buthave not disclosed the results. Their con-cept calls for someone else to build themultibillion-dollar gas liquefaction plantand tanker port in Valdez and procuretankers. TransCanada and ExxonMobil inApril 2011 indicated they are focused onthe Alberta pipeline project rather thanValdez. (See “Status” below.)

The Alaska Gasline Port Authority,founded in 1999, also has proposed a

Valdez LNG project. The port authority isa joint venture of the Fairbanks NorthStar Borough and Valdez, two local gov-ernments along the pipeline route. Theport authority has no recent cost estimatesfor the project.

Estimated cost$43 billion to $49 billion?Pipeline: $20 billion to $26 billion

(2009 dollars). This TransCanada/Exxonestimate includes $11 billion for thePrudhoe Bay plant to remove water, car-bon dioxide and other impurities from thegas, then compress it before it enters thepipeline.

LNG plant and Valdez port: $23 bil-lion? This figure is derived from a July2011 study for the port authority. Tankerswould cost $200 million per ship, thestudy said.

A 2008 state of Alaska study estimatedthe liquefaction plant and port would cost$10.8 billion to $17.6 billion.

Gas for AlaskansThe TransCanada/Exxon pipeline

would provide at least five points inAlaska from which spur lines could bebuilt to provide gas to Alaskans. Thisproject involves only providing gas take-off points, not building the spur lines,which would be up to the state, utilities orprivate companies.

The port authority says gas could betaken from the pipeline at Fairbanks andthat a spur line from Glennallen couldprovide gas to Southcentral Alaska.

StatusThis project appears to be dormant.The TransCanada/ExxonMobil team in

April 2011 told the Federal EnergyRegulatory Commission that it is focusedon design, engineering and regulatoryapproval for the pipeline to Alberta, notValdez. FERC in August 2011 said it hasreceived little information on the Valdezproposal and has no plans to conduct anenvironmental review, which is needed tomove project ahead.

The port authority continues to tout theLNG export idea in speeches, op-edcolumns and interviews.


during construction.• With the right project economics,

long-term boost as billions of dollars inrevenue flows to state treasury, the AlaskaPermanent Fund and local governmentsalong the pipeline route.

• Valdez gets new industry based onLNG export.

• Outlet for natural gas now strandedon Alaska’s North Slope should spur oiland gas exploration there.

• Relatively inexpensive gas madeavailable for heating and power genera-tion in the Fairbanks area.

• For Southcentral Alaska, project withspur line likely an affordable source ofnew natural gas to supplement Cook Inletsupplies.

Minuses• Most expensive option. High cost

makes project risky for lenders that wouldsupply construction financing.

• Federal loan guarantees availableonly for pipeline project that delivers gasto the Lower 48, not projects that wouldexport gas. Lack of federal backing wouldraise project costs.

• Buyers needed immediately for hugeoutput from LNG plant, with little ramp-ing up of project over time.

• Shippers must commit gas to pipelinefor 20-plus years and find long-term buy-


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ers for the LNG in a Pacific LNG marketthat other exporters are targeting.

• Fairbanks area energy costs remainrelatively high until pipeline is running.

• Southcentral Alaska could need sup-plemental source of natural gas beforepipeline is finished.

Cook Inlet gas explorationIn June 2011, the U.S. Geological

Survey estimated the Cook Inlet regionstill holds an estimated 19 trillion cubicfeet of natural gas that could be producedusing current technology.

That’s more than double the totalCook Inlet gas production over the past50 years. But how much of the gas couldbe produced profitably with current tech-nology likely is a much smaller number,possibly as little as 10 percent.

Separately in June, the AlaskaDivision of Oil and Gas estimated thatCook Inlet alone could continue to prof-itably supply all of the region’s naturalgas needs until 2018-2020, at which timesupplemental supplies would be needed.The study said the gas industry must con-tinue investing in the Inlet for this pre-diction to hold.

The state Legislature over severalyears has created a package of incentivesto boost Cook Inlet gas production.

A key incentive offers up to $25 mil-lion in tax credits for the first explorationwell drilled from a jack-up rig, up to$22.5 million for the second well drilledby a different company and up to $20million for a third well by a third produc-er.

At least two companies are pursuingthose incentives. Escopeta Oil moved ajack-up rig to Cook Inlet in August 2011and hopes to start drilling in the fall.Buccaneer Energy hopes to bring in ajack-up rig, partly financed with statemoney, in 2012.

Another state incentive provides a 20percent to 65 percent tax credit for oiland gas exploration or development cap-ital spending, in Cook Inlet or elsewherein Alaska.

Importing LNGIn 2011, three Anchorage utilities

joined to consider the idea of importingliquefied natural gas to SouthcentralAlaska.

ENSTAR Natural Gas Co. suppliesgas for residential and business furnaces,and Chugach Electric Association andMunicipal Light & Power burn gas tomake electricity.

They estimate Cook Inlet fields mightnot produce enough gas by 2014 to fulfill

their needs. The supply gap would startsmall but grow to as much as 140 millioncubic feet a day on average by 2020, theytold state utility regulators in June 2011.Their idea is that an import projectshould be scalable so that more gas couldcome in as the utilities’ needs grow.

Since then, the USGS and AlaskaDivision of Oil and Gas have issuedrosier projections of Cook Inlet’s poten-tial gas supply.

The utilities continue to explore thecost, design, location, volumes needed,potential suppliers, regulatory issues andother aspects of opening an LNG importplant. While the USGS and state saythere’s a high probability that CookInlet’s gas prospects are better than pre-viously thought, that’s short of the cer-tainty of supply the utilities need.

Gas to Fairbanks by truck or pipe

Three ideas have been floated for get-ting North Slope natural gas to theFairbanks area, where energy costs aremuch higher than in Southcentral Alaska.

LNG trucked to Golden Valley Electricand the Flint Hills refinery

In August 2011, Golden ValleyElectric Association and Flint HillsResources announced a project to buyNorth Slope gas, superchill it to makeLNG and truck it about 500 miles toNorth Pole.

They pegged the cost at $180 million,including an LNG plant, about 40 trucks,storage, plus a plant to regasify the LNGin North Pole. Startup would be early2014. They said engineering has begun.

Both companies said they would usethe gas - about 20 million cubic feet a dayon average - to replace more expensivefuels. Golden Valley would burn the gasat its North Pole power plant. Flint Hillswould burn gas at its North Pole oil refin-ery.

Fairbanks community leaders saidsome extra gas could be sold elsewherein the Fairbanks area.

Trucked LNG by Fairbanks Natural Gas LLC

Fairbanks Natural Gas also has a planto truck North Slope LNG to Fairbanks.

The company, a subsidiary ofMinnesota-based Pentex Alaska NaturalGas, has been liquefying Cook Inlet gasand trucking it to Fairbanks since 1998.Last year it posted a $3 million profit on$16.1 million in gas operating revenue,according to filings with state utility reg-ulators.

Fairbanks Natural Gas has contractedfor Cook Inlet gas supplies into mid-2013. But with overall Cook Inlet output

falling, several years ago a FairbanksNatural Gas affiliate, Polar LNG, con-tracted with ExxonMobil to buy gas fromthe oil company’s Prudhoe Bay produc-tion. In 2009, it leased state land nearPrudhoe Bay as a site for an LNG plant.

The LNG plant hasn’t been built yet.With Golden Valley and Flint Hills pur-suing their own trucked LNG idea,Fairbanks Natural Gas may have lost twopotential major customers. It’s unclearwhat happens next to its trucked LNGproject.

In August 2011, the Alaska GaslinePort Authority dropped its idea to buyFairbanks Natural Gas to take over itstrucked North Slope LNG proposal.

Piped natural gas to FairbanksFairbanks Pipeline Co. started in 2010

and is proposing a Prudhoe Bay-to-NorthPole pipeline to deliver natural gas toInterior Alaska customers. FairbanksPipeline is owned by Energia Cura, aFairbanks energy consulting and servicebusiness.

The company said it is targeting GoldenValley Electric, military bases, trans-Alaska pipeline pump stations and mines,

as well as Fairbanks Natural Gas, the smalllocal gas utility. It has estimated the 514-mile, 12-inch buried pipeline would cost$709 million to $716 million, but the com-pany now believes the cost will be lowerafter hearing from steel mills that couldsupply the pipe. The route would followstate highways. The Energia owners arefunding development costs, the companywebsite says. They hope others, includingthe state, possibly through its PermanentFund savings account, become owners.

Fairbanks Pipeline held an open seasonsoliciting customer interest during thethird-quarter of 2010 and said it got non-binding interest for 32 million cubic feet ofgas a day as of 2014, ramping up to 52 mil-lion in 2019. Gas buyers would pay $9.66per thousand cubic feet, under the plan.The company also is considering a larger,18-inch pipeline project that, besides serv-ing Interior Alaska markets, also woulddeliver about 200 million cubic feet a dayto Southcentral. �

Editor’s note: This is a reprint from theOffice of the Federal Coordinator, AlaskaNatural Gas Transportation Projects,online at www.arcticgas.gov/guide-to-Alaska-natural-gas-projects.


Do you have an extra laptop you’d be willing to part with? No, I’mnot adding to my own stockpile of consumer electronics or trying tostrike it rich on the pawn shop circuit. Rep. Les Gara is working withFacing Foster Care Alaska to collect laptops for foster youth. Laptops are a critical tool for foster youth to keep up with schoolwork and stay connected with family and friends while theyare moved to different homes and schools.

If you are interested in donating a laptop, please make sure it isfully functional and meets the following standards:

Is in excellent working order;Is no more than 4 years old;Has a word processing program;Does not need any repairs.

For more information, or to donate a laptop, please contact eitherRep. Gara’s office at (907) 465-2647, or Amanda Metivier at FacingFoster Care Alaska at (907) 230-8237.

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Companies involved in Alaska and northern Canada’s oil and gas industry

AAcuren USAAECOM EnvironmentAir LiquideAIRVAC Environmental GroupAlaska Air CargoAlaska Analytical Laboratory . . . . . . . . . . . . . . . . . . . . . . . . .6Alaska Cover-AllAlaska Division of Oil and GasAlaska DreamsAlaska Frontier ConstructorsAlaska Interstate Construction (AIC)Alaska Marine Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Alaska Railroad Corp.Alaska Rubber Alaska Steel Co.Alaska TelecomAlaska Tent & TarpAlaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Alaskan Energy Resources Inc.Alpha Seismic CompressorsAlutiiq Oilfield Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . .7American Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Arctic ControlsArctic FoundationsArctic Slope Telephone Assoc. Co-op.Arctic Wire Rope & SupplyArmstrongASRC Energy ServicesAvalon Development

B-FBaker Hughes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Bald Mountain Air ServiceBristol Bay Native Corp.Brooks Range SupplyCalista Corp.Canadian Mat Systems (Alaska)Canrig Drilling Technology . . . . . . . . . . . . . . . . . . . . . . . . . .12Carlile Transportation ServicesCGGVeritas U.S. LandCH2M HillChiulista ServicesColville Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2ConocoPhillips AlaskaConstruction Machinery IndustrialCrowley AlaskaCruz Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Delta P Pump and EquipmentDenali IndustrialDowland-Bach Corp.Doyon DrillingDoyon Emerald

Doyon LTDDoyon Universal ServicesEgli Air Haul . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5Era Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5ERA Helicopters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Everts Air CargoExpro Americas LLCExxonMobilFairweather LLCFlowline AlaskaFluorFoss MaritimeFriends of PetsFugro . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17

G-MGarness Engineering GroupGBR EquipmentGCI Industrial TelecomGeokinetics, formerly PGS OnshoreGlobal Diving & Salvage . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Golder AssociatesGreer Tank & Welding . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Guess & Rudd, PCHawk ConsultantsHoover Materials Handling GroupInspirationsJackovich Industrial & Construction SupplyJudy Patrick Photography . . . . . . . . . . . . . . . . . . . . . . . . . .18Kenworth AlaskaKuukpik Arctic Services . . . . . . . . . . . . . . . . . . . . . . . . . . . .19Last Frontier Air VenturesLister IndustriesLounsbury & AssociatesLynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Mapmakers of AlaskaMAPPA TestlabMaritime HelicoptersM-I SwacoMRO Sales

N-PNabors Alaska DrillingNalcoNANA Regional Corp.NANA WorleyParsonsNASCO Industries Inc.

Nature Conservancy, TheNEI Fluid TechnologyNordic CalistaNorth Slope TelecomNorthern Air CargoNorthwest Technical Services . . . . . . . . . . . . . . . . . . . . . . .12Oil & Gas SupplyOilfield ImprovementsOpti Staffing GroupPacWest Drilling SupplyPDC Harris GroupPeak Civil TechnologiesPeak Oilfield Service Co.PENCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Pebble PartnershipPetroleum Equipment & Services . . . . . . . . . . . . . . . . . . . .15PND Engineers Inc.PRA (Petrotechnical Resources of Alaska)Price Gregory International

Q-ZRain for RentSAExploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20Salt + Light CreativeSeekins FordShell Exploration & ProductionSTEELFABStoel RivesTA StructuresTaiga VenturesTanks-A-LotTEAM Industrial ServicesThe Local Pages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15Tire Distribution Systems (TDS) . . . . . . . . . . . . . . . . . . . . . . .7Total Safety U.S. Inc.TOTE-Totem Ocean Trailer ExpressTotem Equipment & SupplyTranscube USATTT EnvironmentalUdelhoven Oilfield Systems ServicesUMIAQUnique Machine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Univar USA Universal WeldingURS Corp.US Mat SystemsUsibelliWest-Mark Service CenterWestern Steel StructuresWeston Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17XTO Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3

Lynden chosen a Top 100 3PL provider for 2011The Lynden family of companies said Aug. 9 that it was chosen as one of the Top 100

third-party logistics service providers by editors of Inbound Logistics magazine. Editors select-ed the companies from hundreds of contenders, choosing only those that offer the diverseoperational capabilities and experience to meet readers’ unique supply chain and logisticsneeds.

Inbound Logistics’ Top 100 3PL Providers list serves as a qualitative assessment of serviceproviders. Each year, editors solicit questionnaires from more than 400 3PLs, detailing theservices they provide and their areas of expertise. The magazine also polls more than 5,0003PL users with a similar series of questions to provide a counter-perspective of the forcesshaping the industry

“Whatever the company size — from Fortune 500 to small businesses — world-classlogistics performance is crucial. It is impressive to see Lynden providing the kinds of solutionsthat companies large and small rely on to solve the tactical logistics issues of serving cus-tomers better, faster and more efficiently,” said Felicia Stratton, editor of Inbound Logisticsmagazine.

The Lynden family of companies’ combined capabilities include: truckload and less-than-truckload freight to Alaska, scheduled and charter barges, rail barges, intermodal bulk chemi-cal hauls, scheduled and chartered air freighters, domestic and international shipping via air

and ocean forwarding, customs brokerage, trade show shipping, remote site construction,sanitary bulk commodities hauling and multi-modal logistics.

Hawk wins Governor’s Safety Award of ExcellenceHawk Consultants said April 6 that the Alaska Safety Advisory Council announced that it

has won the Governor’s Safety Award of Excellence for 2011. Hawk was presented the awardby Commissioner of Labor Click Bishop at the 30th Annual Governor’s Safety and HealthConference Awards Luncheon on March 24 in Anchorage.

The award was in recognition of Hawk’s milestone achievement of 1 million hours workedwithout an injury or lost-time accident. Hawk has worked in the Alaska oil patch since 1985and has never had a lost time accident.

This remarkable achievement is a tribute to the quality and dedication of Hawk’s employ-ees and the support of its clients and a strong belief in the conference motto “Safety Isn’tExpensive — It’s Priceless”.

Hawk Consultants LLC is an Alaskan-owned firm specializing in project management serv-ices supporting client organizations with people and resources to deliver projects safely, ontime, on budget and without adverse environmental impact. For more information visit

see OIL PATCH BITS page 17

Oil Patch Bits

Senate probably won’t pass it because ofHarry Reid of all people. If Obama weresmart, he’d come out in favor of it. Wecould put 2 million barrels in thatpipeline, and it would drop the price ofgasoline dramatically because the othercountries would see we are serious aboutthis, and we can get this economy backon a road to recovery. I’ll pass it out ofthe House, then it will get over to theSenate. If we control the Senate next ses-sion, we’ll probably get it passed andhopefully we’ll have a new president andsomeone will see the logic of openingANWR. It is not the pristine area they aretalking about. Never has been; never willbe. We have an infrastructure in placethat needs more oil. It isn’t (Alaska’s) oil.It will be federal oil, so we won’t getmuch money out of it. It’s important tocreate the jobs to keep the pipeline going.I do think we will eventually get it done.I said I want to live long enough to get itdone. In fact I told (U.S. Rep. Ed)Markey, if we get ANWR opened up, Imight quit. He damn near took me up onit, but I’m going to get ANWR donebefore I get out of here.

Petroleum News: Moving offshore,what are your thoughts on Shell’s effortsto get permits to begin drilling and someof the hurdles they’ve encountered?

Young: My biggest concern is theymight drop out. They’ve got $5 billionout there invested, starting with $2.5 bil-lion on the lease bid. This is all gob-bledygook. One thing that’s bad aboutthe president. He says I’m all for leaseson the Beaufort; I’m all for leases on theChukchi Sea. The reality is that doesn’tsolve the problem. If the agency doesn’tprovide the permits, we aren’t going any-where. I’d be dog gone reluctant to bidon a lease if I didn’t have some assurancethat I could actually drill the area. I’vesaid all along in the new ANWR bill, weare going to put a provision, if we open itup, it will be drilled — like we did thepipeline. That’s the reason we got thepipeline built. It was my provision thatsaid there will be no lawsuits.

Petroleum News: Speaking of pipeline,what are your concerns about throughputin the pipeline?

Young: I have big concerns.Everybody knows it’s declining. It’sheavier oil. It’s more waxy in content aseverybody knows and that makes it moredifficult to keep the line moving smooth-ly. If it weren’t for the refinery in NorthPole, the oil might not be warm enoughto go all the way to Valdez. We have toincrease that. I think we have to look atnew ways to do it or get the Chukchiopen. The goal of the environmentalcommunity is to make sure the pipelinefinally gets to 300,000 barrels and theyhave to shut down and can’t run it, and ithas to be pulled up. This is the Pelosi,Waxman, Schumer, no fossil fuels philos-ophy. I’m a big believer we will get thatpipeline moving. If we don’t it will be abigger problem, not only financially tothe state, but the bigger problem is to therest of the nation, which is really scary.We still import 72 percent of our oil, yetwe have a tremendous amount of oil inthe north, and we have a tremendousamount of oil in other areas such as offthe coasts of California, Virginia andFlorida. We just have lacked the will todo it because it wasn’t popular. Look atthe battle of the (Alberta to Texas)Keystone pipeline, which is still not over.It’s well and good and I would support it.It’s a still a foreign oil source. Now they

are better neighbors but we should beusing our own oil; instead, we are stillgoing to pay $100 a barrel.

Petroleum News: Are you OK with thepipeline coming into this country?

Young: Oh, yeah I’m fine with it. Weget more oil from Canada than we dofrom Venezuela. People don’t quite knowthat but we do. At least they are friendlyneighbors, but still, why are we buyingfrom a friendly neighbor when we can beproducing our own? That’s the thing Idon’t understand. To me that’s not beingvery smart. It’s better buying from themthan having it shipped in from Kuwaitand Iran and Libya.

Petroleum News: There have beenissues with pipelines the last five years.There were leaks on the North Slope;Enbridge had a leak in Michigan; Exxonhad one in a Montana river. Are you con-cerned about pipeline integrity?

Young: I have concerns about trans-portation of any form. None of it is fail-safe. There is no other way to move oil.The biggest way is to make sure it’s keptup. Remember this pipeline is 35 yearsold. The one in Montana, who in theworld would have thought that wouldhave flooded? The one in Michigan,that’s another old system. Anybody whocan show me another way to bring oiland gas in years old, I’m listening.

Petroleum News: If pipelines aren’tmaintained, does it make it more difficultfor you in D.C?

Young: The money being spent is inmaintenance; it’s not being spent indevelopment. It’s like trying to get richby using funny money. You have to digand be developing new wells.

They said they saw two rigs leavingthe Port of Seattle and going to Alaska.In the first place they didn’t check it out.Second place, they were probably goingup as those rigs they were replacing havebeen worn out.

So the money being spent is on main-tenance. That’s great for work now, but itdoesn’t increases the flow of oil. Then itdecreases over time and that’s a big prob-lem.

Petroleum News: Do you still believethere can be a market for a large-diame-ter gas line?

Young: No. No one is going to investwhat I expect to be a $40 billion projectand bring gas down to a market that isalready saturated. There won’t be a returnon the money. I always said that wouldbe a challenge. Frank Murkowski missedthat open window and he told us that. Ifwe had that agreement then (2005), wewould have had a pipeline started. Welost that. I still insist we’ve got to look atthe possibility of export because there

will be a use for it in China and Japan.The state itself has got some real chal-lenges. Whether we find some more gasin Cook Inlet or not, I don’t know. We’vegot the rig up there, but it will relieve thepressure on the Railbelt. But Fairbanks isdying because of the high cost of energy.No one can expand stores. Those are thequestions we are going to be faced with.Either we build a bullet line and bring itinto Fairbanks, then Anchorage anddown, or we build a larger line at least asfar as Delta, maybe to Fairbanks, so lateron if there is a market in the Lower 48,then we can take into the Midwest. Butthat’s not going to happen for another 40or 50 years. You know I’m paying $7.50for heating oil in Fort Yukon right now.It’s something you have to have. There’sno doubt about that. We’ve got a lot ofopportunities right now, if we would justdo it. The other solution would be if youdon’t build a gas line, is Susitna Dam,which I have seen the Legislature andgovernor attempt to do. That might becheaper than building a pipeline. The gasis there. We know it’s there. We’ve gotthe energy; we just don’t have the will orthe desire to replace it. I think that’s whatwe have to do.

Petroleum News: Is it up to the state

Legislature to make it work, the industryor a combination?

Young: I don’t know whether anybodyis going to the industry to say would yoube interested in a tidewater pipeline. Ifthey said yes, then, that’s not a bad idea.I think it would be a good idea. The statecan be partners, but I don’t particularlythink the state should own it or manageit. Old man (Roy) Huffington atHuffington Oil he told me once ‘don’tever let the government ever get involvedin the industry because eventually it willcorrupt the government.’ I think we’veseen that in places like Venezuela. Thegovernment doesn’t police itself. The pri-vate industry can be policed by the peo-ple.

Eighty-five percent of Alaska wouldbenefit. That’s very crucial. Southeastwould not, so we would build up thosehydro sites. Then you would have exportto finance the line and make sure it’s notso expensive. That’s one reason you can’tbuild a big line for the state of Alaska.We don’t have the market. So I think ifsomebody would go and ask them to seeif they are interested in building a gasline, you might be surprised. �

www.hawkpros.com.

The Alliance calls for 2011 board nominations The Alliance board and elections committee said Aug. 15 that it is seeking members to

serve on the Alliance board of directors. There are seven three-year terms available in thefiscal year 2012 elections. Election results will be announced at the annual meeting on Sept.29. Newly elected members will begin serving their terms Oct. 1.

Alliance directors are leaders in the oil, gas and mineral resource industries. They arefocused on improving the business climate for contractors by communicating with legisla-tors and the administration in Juneau, serving on committees and participating in and sup-porting Alliance events throughout the year. These events are prime networking opportuni-ties for all members of the Alliance.

Board members review industry issues, voice Alliance positions and develop strategies toimprove and empower our organization. Directors may serve a maximum of two consecu-tive three-year terms.

If you are interested in running for a seat on the Alliance board of directors, please for-ward a written statement of candidacy to the Alliance office. Nominees must confirm theirintent to run for a seat on the board. This may be provided in a letter format. Include abiography; a brief summary of employment; involvement in industry and/or business-relatedorganizations and other pertinent information; and photograph, electronic headshot pre-ferred. Nomination must reach The Alliance office by Aug. 22. Email [email protected].

Editor’s note: All of these news items — some in expanded form — will appear in thenext Arctic Oil & Gas Directory, a full color magazine that serves as a marketing tool forPetroleum News’ contracted advertisers. The next edition will be released in September.


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YOUNG Q&A“We have become over governed.

We are over regulated. It’s not justfederal. The state is equally as

bad.” —Congressman Don Young, R-Alaska

Contact Steve Quinn at [email protected]

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by remarks Department of NaturalResources Commission Dan Sullivan madeAug. 15 that the state and ExxonMobil hadreached agreement in principle on PointThomson (see story on page 1.)

External factors, such as changes in gassupply and demand in North America andglobally over the last three years, are outsideof TransCanada’s control, he said, as aregas-price forecasts, liquefied natural gasexports and the condition of financial anddebt markets.

The shale gas impactAsked by Sen. Bill Wielechowski if the

development of shale gas in the Lower 48has made the Alaska Pipeline Project uneco-nomic, Palmer said the North American gassupply is higher today and public gas priceforecasts are lower than they were threeyears ago. It is one of the external factorswhere potential customers of the pipelinewill have to decide their own view, he said.

But to date, “we haven’t seen customerswalking away from the table,” because of

shale production, Palmer said. Resources co-chair Joe Paskvan asked

what the impact would be on the Alaskaproject if shale gas were developed inChina.

Palmer said the topic is highly specula-tive, but that in his view those looking atwhether China will have a shale gas revolu-tion, with timing and cost uncertain rightnow, will know more in two to five years.

Asian LNG is still tied to a crude oilprice, but some Asian buyers coming toNorth America have indicated they are seek-ing North American prices, Palmer said,noting that if they are successful, that couldbreak the linkage of LNG prices to oil.

China has a shortage of natural gas and isimporting both via pipeline and LNG and alow-price domestic source would impactboth where that country gets its gas and theprice.

On commercial sidePalmer said the project has advanced sig-

nificantly on the commercial side over thelast three years.

TransCanada and ExxonMobil havegone beyond the commercial terms included

in the license TransCanada obtained underthe Alaska Gasline Inducement Act, AGIA.

And TransCanada aligned withExxonMobil on the project — and has astanding offer to align with BP andConocoPhillips, he said. That gets the proj-ect part way toward having the five partnersTransCanada has said would be needed: theState of Alaska, TransCanada, ExxonMobil,BP and ConocoPhillips.

Global gas markets have become morecompetitive, Palmer said, and in the openseason documents for the project the offer inthe AGIA documents was enhanced by$500 million a year to customers, over thelife of the project a $12.5 billion total reduc-tion in tolls.

He said he couldn’t identify further con-cessions made in the negotiations, but saidthe companies will make more concessionsin trying to get over the finish line.

While customers would say you could golower, Palmer said, from the perspective ofa pipeline company there is a very competi-tive offer on the table.

Monies spentWielechowski asked how much money

would be spent until issuance of the license.TransCanada is committed under AGIA toadvance the project through receipt of aFederal Energy Regulatory Commissioncertificate of convenience and necessity,even in the absence of customers, one of theconditions the state extracted in exchangefor its $500 million participation.

Palmer said if the project is unsuccessfulat getting customers it will spend on theorder of $700 million by 2014, $500 mil-lion of which would be reimbursed by thestate.

If we have customers, we’d acceleratespending because we would be moving toput the line into service, he said.

Denali, the BP-ConocoPhillips spon-sored proposal, folded in May, citing lackof customer support.

Palmer said he always thoughtTransCanada had the advantage in Canada,and also had the skill set to advance theproject, a skill set which improved with theExxonMobil alignment in June 2009.

No one ever thought two lines would bebuilt, Palmer said: One had to go away orthey had to combine.

Asked by Sen. Hollis French how threeimpediments to the project — PointThomson, gas fiscals and long-term prices— should be ranked, Palmer said until thestate and the producers have resolved theirissues, it’s hard to get people to focus on thethird issue, whether the project is econom-ic.

At low gas prices, the first two condi-tions, while necessary, may not be suffi-cient, Palmer said, but the producers areused to taking price risk, and they are notmaking the call today.

Asked by Rep. Kurt Olson whenTransCanada would make the hard decisionto continue or not, Palmer said that whileTransCanada had assumed Point Thomsonand gas fiscals would be resolved by theend of the open season, as long as therecontinues to be optimism that they will beresolved, “we’ll let the game play out.”

Sunk costWielechowski was concerned that legis-

lators had to make decisions about fundingthe AGIA project and the in-state line,ASAP, and pressed Palmer for more infor-mation.

Palmer said that under AGIATransCanada has been able to share addi-tional information with the administration,but said Wielechowski was asking forsomething that goes beyond what’s instatute.

Sen. Bert Stedman, who co-chairs theSenate Finance Committee, said the stateneeds to come up with additional money inthe next two fiscal years to meet its AGIAobligations.

He described the $500 million as a sunkcost, if TransCanada has customers and ismoving ahead with the line or if it has nocustomers.

The only way we could not spend thefunds is if the state and TransCanada cometo a mutual agreement that the project isn’teconomic, which is not likely, Stedmansaid.

Building permitLarry Persily, federal coordinator for

Alaska Natural Gas TransportationProjects, told Senate Resources Aug. 17that AGIA had been oversold and misun-derstood. It was never going to get you apipeline, he said: It’s a path toward gettinga building permit for a line — the engineer-ing, design and permits.

The Stranded Gas Act, under whichtalks took place with North Slope producersunder the Murkowski administration,scared Alaskans away from negotiations,Persily said. But the producers have to takerisks including cost overruns and the pricein the market and state fiscal terms mustrecognize the risks, he said.

He encouraged Alaskans to look at thegas line as a 50-year project which providesgas for Alaskans, state revenues and moreexploration on the North Slope, which willfind oil as well as gas.

Having a gas line makes Alaska moreattractive, he said.

Persily also suggested that when thestate does sit down with producers, someprovisions of AGIA such as rolled-in tariffswould probably be back on the table.

—KRISTEN NELSON


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EXPLORATION & PRODUCTIONUS drilling count up by 39 to 1,959

The number of rigs actively exploring for oil and natural gas in the U.S.increased by 39 the week ending Aug. 12 to 1,959.

Houston-based drilling product provider Baker Hughes Inc. reported that 1,055rigs were exploring for oil and 896 for natural gas. Eight were listed as miscella-neous. A year ago this week the rig count stood at 1,640.

Of the major oil- and gas-producing states, Texas gained 20 rigs and NorthDakota 14. Colorado was up seven, California up three, Pennsylvania two andOklahoma one. Louisiana declined by five and Wyoming was down three. Alaska,Arkansas, New Mexico and West Virginia were unchanged.

The rig count peaked at 4,530 in 1981. A low of 488 was recorded in 1999. —THE ASSOCIATED PRESS


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Gas for storageHowever, the primary purpose of the

Buccaneer contract will be to ensure suf-ficient gas supplies to meet Enstar’s con-tracted use of the CINGSA storage facili-ty, Enstar spokesman John Sims toldPetroleum News Aug. 15. Enstar plans topull gas from the CINGSA facility duringperiods of high winter demand, starting inthe winter of 2012-13, to ensure that gascan be flowed fast enough to meet gasconsumers’ peak needs.

According to Enstar’s tariff filing, theBuccaneer contract for guaranteed gassupplies from 2012 involves pricingindexed to the New York MercantileExchange gas futures, but with a mini-mum gas price of $5.71 per thousandcubic feet between March and Novemberof each year, and a minimum price of$7.06 per thousand cubic feet betweenDecember and February. The maximumprice at any time of the year would be $10per thousand cubic feet. These floor andceiling prices would be adjusted for infla-tion, starting in 2012. Based on projec-tions of Nymex futures, Enstar anticipatesthe weighted average cost of gas pur-chased under the contract to rise from$5.89 per thousand cubic feet in 2012 to$6.16 per thousand cubic feet in 2014.

The pricing terms appear similar tothose in earlier Enstar supply contractswith Marathon, approved by RCA in May2010, and with Anchor Point Energy,approved by RCA in November 2009.Those earlier contracts both had inflation-adjusted price floors and ceilings of $6.85and $9.70 year round. Anchor PointEnergy is selling gas from the ArmstrongCook Inlet-operated North Fork gas fieldin the southern Kenai Peninsula.

However, Sims said that based on acomparison of the price floors betweenMarch and November, the Buccaneercontract pricing should work out a bitlower than that for the Anchor PointEnergy contract.

Up to 31.5 bcfThe Buccaneer contract requires the

delivery of a total of 12 billion cubic feetof gas to Enstar, with an option toincrease that total volume to 31.5 bcf,with these volumes likely taking until2018 to deliver, Enstar says. The contractrequires Buccaneer to complete thedrilling of two new wells at Kenai Loop,one well by Nov. 1 this year and the otherwell by Nov. 1, 2013.

According to a Buccaneer pressrelease, Buccaneer will initially deliver

gas from Kenai Loop at the rate of 5 mil-lion cubic feet per day in 2012, with anoption to increase that rate to 15 millioncubic feet per day after six months,depending on progress with the drilling ofnew wells.

Although the Buccaneer contract forfirm gas supplies will help fill a loominggap in Enstar’s annual gas supply needs,Enstar’s customers will still likely facesupply shortfalls, starting at 5.9 bcf in2013 and growing to 18.9 bcf in 2018, inthe absence of further gas supply con-tracts, Enstar says. On the other hand, thestorage of Buccaneer’s gas in theCINGSA facility should stave off anyshortfall in the rate of delivery of wintergas until 2018.

And Enstar presumably hopes that therecent startup of new Cook Inlet gasexploration will further bolster its sup-plies. The new contracts and recententhusiasm by small independent gasexplorers operating in the Cook Inletbasin appear to reflect the impact ofincentives for gas exploration that theAlaska Legislature has enacted, Simssaid.

Bidding systemMeantime, with insufficient gas under

firm contract to meet potential deliveryneeds in the winter of 2011-12, beforeCINGSA comes online, Enstar will beoperating its day-to-day bidding system,to try to fill any supply shortfalls as nec-essary.

None of the contractual arrangementsfor gas supplies through the biddingprocess guarantee to make gas availablebut do allow qualified gas producers tobid to deliver to Enstar any gas that theyhave available for immediate sale.Enstar’s three new contracts addBuccaneer, Aurora Gas and Cook InletEnergy to the list of qualified producers,thus increasing the likelihood of findingany necessary short-term supplies —Enstar already has contracted arrange-ments for the potential purchase of “non-firm” gas from Unocal, Marathon,ConocoPhillips and Anchor PointEnergy. �

border. Daniel said that although a date has

not yet been set for an open season, theMonarch proposal will “come to a head ina matter of months” because of the pres-sure to start moving crude from theAlberta oil sands and the Bakken play inNorth Dakota and Saskatchewan to U.S.Gulf Coast refineries.

He said many prospective customersare “coming close” to endorsingMonarch.

Saturation point fast approachingEnbridge Chief Financial Officer

Richard Bird said there is now so muchlight crude coming out of western NorthAmerica that the saturation point is fastapproaching in U.S. Midwest markets,where refineries are being converted tohandle greater volumes of heavy crude.

The Cushing bottleneck and high pricedifferentials between West TexasIntermediate and North Sea Brent hasclimbed as high as US$25 per barrel andis costing Canadian producers as much asC$50 million a day because of theirreliance on a single export market,prompting the clamor for an alternativeroute to Asia.

Monarch, although only one-third ofthe 1.1 million bpd capacity on the com-bined Keystone pipelines, would offersome shorter-term relief along with accessto the PADD III region, which encom-passes the Texas refining hub, whereCanadian imports currently amount to lessthan 3 percent of the volumes.

But PADD III is a natural outlet forCanadian heavy crude, which comparesfavorably with the shrinking supplies ofMexican Maya and Venezuela Orinococrudes, as well as Saudi medium.

Others in race to GulfThe race to the Gulf Coast is not con-

fined to the two Canadian companies. Enterprise Products Partners and

Energy Transfer Partners are proposing a450,000 bpd line from Cushing toHouston by 2012.

Enbridge is also exploring otheroptions to deliver more light crude toEastern Canada and the U.S.

They include greater access toMinnesota and the Chicago area to takeadvantage of increased heavy crudecracking capacity and the reversal ofEnbridge’s existing 240,000 bpd Line 9from Montreal to Sarnia, Ontario, whichDaniel said “has very good prospectivi-ty.”

Enbridge enters the competition armedwith a new tolling agreement for theCanadian portion of its mainline and aninternational joint tariff for cross-bordershipments, which Daniel said offersmainline shippers a stable and competi-tive long-term toll.

He is not concerned about the flurry ofinterest in the use of railroads to transportcrude, including announcements byOklahoma-based Musket to increase itsrail capacity from North Dakota’s Bakkenplay to 70,000-80,000 bpd from 10,000-16,000 bpd and by Plains All Americanthat it plans to double capacity at itscrude-by-rail terminals in Illinois andLouisiana.

Daniel said rail offers “relatively low-cost, early entry into the transportationbusiness, but long-term we can definitelybeat rail in terms of tolls and reliability.”

“Even though these rail facilitiesmight be put in place initially, they’re justa precursor of even more pipeline oppor-tunities for use out of the Canadian andU.S. Bakken,” he said. Bakken produc-tion is forecast by the U.S. EnergyInformation Administration to exceed 1million bpd within a few years, enough toalmost displace current Saudi imports. �


GAS CONTRACTS


PATH TO THE GULF


Enstar plans to pull gas from theCINGSA facility during periods ofhigh winter demand, starting inthe winter of 2012-13, to ensure

that gas can be flowed fastenough to meet gas consumers’

peak needs.


EXPLORATION & PRODUCTIONUS oil well celebrates 150th birthday

A tiny oil well in northwestern Pennsylvania has celebrated its 150th birthday asthe world’s oldest continually producing well.

The Titusville Herald reports dozens of people gathered in Rouseville, about 70miles north of Pittsburgh, to mark the occasion at McClintock Well No. 1 on Aug. 16.

Officials at the nearby Drake Well Museum say the former Quaker State oil com-pany donated the well to the museum in 1955.

The well was drilled on Aug. 16, 1861, and produced about 175 barrels a daybefore slowing to 50 barrels some years later. The well still produces about 40 barrelsof oil a year, which goes to the American Refining Group in Bradford.

The National Park Service declared the well an American Treasure in 1999. —THE ASSOCIATED PRESS

http://www.kasvcs.com/

field is coming to a close, heading offwhat easily could be years more litigationbetween DNR and the major PointThomson stakeholders. BesidesExxonMobil the major players includeBP, Chevron and ConocoPhillips.

Alaska economic development boost-ers are anxious to see the legal cloud lift-ed from Point Thomson, as it containsroughly a quarter of the North Slope’s 35trillion cubic feet of natural gas. Manybelieve that all the gas, including thePoint Thomson reserves, are needed tomake a North Slope gas pipeline a viableproject.

A settlement also conjures intriguingpossibilities for how the field’s consider-able endowment of oil and other hydro-carbon liquids might be exploited. Full-blown development of these resourcescould generate a boomlet of industryactivity on the Slope.

Private briefing offeredDNR began taking firm steps to break

up the Point Thomson unit and reclaimthe state-owned acreage in 2005, during

the administration of Gov. FrankMurkowski.

The state’s beef is the lack of any pro-duction to date from Point Thomson,despite its discovery decades ago in thelate 1970s.

The field is located along the BeaufortSea coast next to the Arctic NationalWildlife Refuge.

The oil companies went to court toblock the state’s effort to break up theunit, and today the case rests before theAlaska Supreme Court.

In recent weeks, DNR and the oil com-panies have filed heavy legal briefs, sug-gesting that no out-of-court settlementwas near.

Yet the two sides have been negotiat-ing for a year or more, with Gov. Sean

Parnell and ExxonMobil executives stat-ing publicly they wanted to settle the dis-pute.

Sullivan offered to brief legislators onthe settlement terms “in a confidentialsetting.”

“Thank you, commissioner, I thinkthat we would probably seek to takeadvantage of that offer because I think ...it is a material step forward,” replied Sen.Joe Paskvan, a Fairbanks Democrat andcommittee co-chairman.

Sen. Hollis French, D-Anchorage,asked Sullivan whether it was “fair to saythat the state and Exxon are throughnegotiating and that negotiations that aretaking place now are between Exxon andits partners. In other words, we made sortof our last best offer.”

Sullivan: “I think it’s fair to say.”During the court proceedings, some

friction emerged among the PointThomson working interest owners, withChevron, BP and ConocoPhillips com-plaining that they had been shut out of thenegotiations between the state andExxonMobil.

Deal timing unclearExxonMobil was measured in its

response to Sullivan’s remarks. The com-

pany provided this statement via e-mail toPetroleum News and other media outlets:

“We’re aware of the State’s testimonyon August 15, 2011 at the legislative com-mittee hearings. We remain committed toworking with Governor Parnell’s admin-istration and the other working interestowners to finalize a settlement.

“Settling Point Thomson litigation andsecuring necessary local, state and feder-al permits is imperative to maintain thepace of Point Thomson development.”

The question naturally came up at thelegislative hearing as to when a settle-ment could be finalized.

“When would you anticipate that thedeal would be official and could be madepublic?” Paskvan asked Sullivan.“What’s the timeline on that — is that 90days, 45 days?”

Sullivan replied: “You know, Mr.Chairman, I really don’t know. Our inter-est would be soon. In some ways thosediscussions right now are ... the timelineof those, we’re not necessarily drivingthat anymore.”

The other committee co-chairman,Republican Sen. Tom Wagoner of Kenai,said he’s been involved with the issue ofPoint Thomson development throughthree administrations, and he congratulat-ed Sullivan on getting this far.

“I know it’s been a real battle thatstarted with the Murkowski administra-tion and went right on through,” Wagonersaid. “Well, it’s very, very essential to thecompletion of the large pipeline.”

“Sen. Wagoner, we’re not, it’s not overyet,” Sullivan said. “As you know, any-time you work on settling litigation it’snever easy. You never get fully everythingyou want.”

What sort of development?Sullivan noted that, while Point

Thomson gas is considered important for aNorth Slope gas pipeline, the field also isrich in petroleum liquids, and productionof those liquids could help stem the oilthroughput decline on TAPS, the trans-Alaska pipeline system.

While construction of a gas line appearsfar from imminent, with no project yetconfirmed, ExxonMobil itself created anincentive for wrapping up a PointThomson deal as quickly as possible.

The company has pledged to begin pro-duction of 10,000 barrels a day of naturalgas condensate, a liquid hydrocarbon,from Point Thomson by year-end 2014.

Already, the company has drilled twowells at Point Thomson, having obtainedspecial permission from DNR in 2009 tosink the holes on two of the unit’s 31 leas-es. ExxonMobil and its partners proceededwith the drilling as part of a strategy tohang onto the field, which is worth billionsof dollars.

But the Nabors 27-E rig used to drill thewells has been demobilized, andExxonMobil would appear to have a tightwindow now for installing facilities to pro-duce the condensate by the 2014 deadline.

A 22-mile pipeline also must be built toconnect the remote Point Thomson field tothe Slope’s existing pipeline network.

Of course, the deal now on the tablebetween DNR and ExxonMobil might fea-ture a whole new development scenario.

“The settlement is focused on the devel-opment of the Point Thomson unit whichcontains both hydrocarbon liquids and gasand we believe that the settlement of thislitigation should help advance the strategicgoals of filling TAPS and commercializingNorth Slope gas,” Sullivan told legisla-tors. �

—Kristen Nelson contributed to this article



FIELD FIGHT

Contact Wesley Loy at [email protected]

Sullivan noted that, while PointThomson gas is considered

important for a North Slope gaspipeline, the field also is rich in

petroleum liquids, and productionof those liquids could help stem

the oil throughput decline onTAPS, the trans-Alaska pipeline

system.

http://www.saexploration.com/

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