a holding pattern

Giessel: resource issues will be oiltax focus for Senate committee

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

� N A T U R A L G A S

� F A C I L I T I E S

Vol. 18, No. 6 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of February 10, 2013 • $2

Utilities take over new plantC

HU

GA

CH

ELE

CTR

IC A

SSO

CIA

TIO

N

The new Southcentral Power Project gas-fired power plant inAnchorage will substantially reduce the region’s demand for nat-ural gas for power generation. See story page 9.

A holding patternShell waiting on Kulluk investigations before deciding on next Alaska steps

By ALAN BAILEYPetroleum News

On Feb. 1 while answering questions during amedia webinar for Shell’s announcement of

its 2012 results, Shell CEO Peter Voser said that hiscompany is waiting for the outcome of investiga-tions following the grounding of the Kulluk, thecompany’s floating drilling platform, before decid-ing on next steps in Alaska.

Work needs to be done on both of Shell’s Arcticdrilling rigs, to make the rigs ready for the 2013drilling season, Voser said. The Noble Discoverer,the rig that Shell is using for Chukchi Sea drilling,requires “a series of upgrades,” while the Kulluk

Arctic port sites eyedArmy Corps, Alaska DOT select Nome and Port Clarence for feasibility analysis

By WESLEY LOYFor Petroleum News

A new report recommends development of adeep-draft seaport to support resource devel-

opment, Coast Guard operations and other activityin the increasingly ice-free Arctic Ocean.

And the report picks two sites for port feasibil-ity analysis: Nome and nearby Port Clarence. Boththese locations are south of the Bering Strait, gate-way to the polar ocean.

The draft report, titled “Alaska Deep-DraftArctic Port System Study,” is a product of the U.S.Army Corps of Engineers and the AlaskaDepartment of Transportation and PublicFacilities.

It’s part of efforts that began in 2008 to consid-er Alaska port needs, including along the remoteArctic Ocean coast.

As ice cover thins and recedes with climatechange, and with Arctic shipping and offshore oiland gas exploration on the rise, many recognize theneed for one or more northern ports capable of

Chevron sets LNG termsCompany’s chairman says prices need to be ‘close to oil parity’ to support cost

By GARY PARKFor Petroleum News

Chevron has wasted no time sending a clear-cut message to potential Asian buyers of

Canadian LNG: Unless sales are closely tied to, oron par with oil prices they can forget any contractdeals.

Just over a month after striking a deal to becomeoperator of Kitimat LNG, with Apache holding theremaining 50 percent, Chevron Chairman andChief Executive Officer John Watson took a hardline, unwilling to continue the struggle Kitimat’sformer ownership group (Apache, Encana andEOG Resources) experienced in trying to arrangeofftake orders.

No sooner had Chevron moved into the venturethat the “phone started ringing,” he said. “We’re acredible buyer in the marketplace and I think buy-ers throughout Asia, Japan and Korea are veryinterested in Chevron and interested in the proj-ect.”

see KULLUK PROBE page 19

see PORT SITES page 18

see LNG TERMS page 20

Shell wants to see the outcome of investigations ofthe grounding of its Kulluk floating drilling platformbefore deciding on its next steps in Alaska. Thedrilling platform will require repair before it can con-tinue its Beaufort Sea drilling operations.

U.S

. C

OA

ST G

UA

RD

The study considered marineinfrastructure needs over a vast area,from the Southwest Alaska village of

Bethel west and north then east to theCanadian border.

“What we see is continuing growth in(LNG) demand. There’s a lot of gas out

there, but pulling these projects togetherand getting them online ... in time to meet

that demand, is a different matter.” —Chevron Chairman and CEO John Watson

Interior LNG requires privatecapital in addition to state funds

Although the Parnell Administration is asking lawmakersto approve a $325 million financial package this year to truckliquefied natural gas to the Interior, it is imagining a systemcosting as much as $1 billion, with the difference covered bythe private sector.

“We’re not just talking about building the plant. We’retalking about providing a complete integrated system thatcreates the gas, trucks the gas and distributes the gas,” AlaskaIndustrial Development and Export Authority DeputyDirector for Infrastructure Mark Davis told the SenateSpecial Committee on In-State Energy at a Jan. 31 hearing.

Although one lawmaker called the $1 billion figure a“what if ” number designed to estimate the cost of the projectat its largest — including near-complete market saturation inthe Interior with excess going to Southcentral — even thesmallest version of the project would require at least $30 mil-lion of private money beyond the state package.

The Alaska Legislature is currently considering the pack-age as Senate Bill 23 and House Bill 74, which both include

Senate tax discussions continue;PFC says state seen as tinkering

What factors have the most impact on Alaska’s future oil andgas revenues?

Not the state’s fiscal system, Janak Mayer told the SenateSpecial Committee on TAPS Throughput Jan. 31. The largestrevenue impact is fromsomething over which thestate has no control, hesaid: oil prices, followed byproduction rate. The Senatecommittee was wrappingup its throughput-focusedreview of the governor’sproposed tax changes asthis issue of PetroleumNews went to press, with the bill expected to move on to theSenate Resources Feb. 7 or Feb. 9.

Mayer, a manager in PFC Energy’s upstream practice andTony Reinsch, senior director in the firm’s upstream practice,presented an overview of how companies make investment deci-sions, where Alaska fits in the portfolios of the major NorthSlope producers and how competitive investment is in Alaskaunder the state’s current production tax, Alaska’s Clear andEquitable Share, or ACES, compared to competitiveness underthe governor’s tax change proposal, Senate Bill 21 (House Bill72 is the companion bill).

see INTERIOR LNG page 20

see TAX DISCUSSIONS page 17

The largest revenue impactis from something overwhich the state has no

control, he said: oil prices,followed by production

rate.

http://www.PetroleumNews.com/

2 PETROLEUM NEWS • WEEK OF FEBRUARY 10, 2013

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

PIPELINES & DOWNSTREAM

FINANCE & ECONOMY

EXPLORATION & PRODUCTION

ENVIRONMENT & SAFETY5 Questions over Arctic dispersant use

Environmental consultant questions feasibility of usingoil dispersant chemicals in responding to an Arctic offshore oil spill

7 Finding ways of seeing oil under ice

OSRI tests the use of surveillance balloons andunderwater vehicles for detecting oil caught below ice following an oil spill

8 AOGCC halts new Meltwater drilling

AOGCC wants more information about why MI is migrating into shallower formations beforeConocoPhillips can continue drilling

6 State sets May 8 date for spring sales

Augustine geothermal competitive sale addedto schedule; Cook Inlet, Alaska Peninsula areawideoil and gas sales offered annually

4 Clearing way for Canol shale

Infrastructure, regulatory streamlining gain attentionas activity picks up in Central Mackenzie; development could be 5 years away

9 Utilities take over new power plant

Combined cycle power generation replacing old plant will significantly reduce gas consumption by Southcentral power utilities

10 NA LNG looks to exporting to survive

In a change from a decade ago, the North Americanliquefied natural gas industry is now gearingup to export billions of cubic feety

13 Cook Inlet Energy gains gas security

Anchorage company reworks gas well on its Ospreyplatform to provide a cost-effective source of fuel for its oil field operations

NATURAL GAS

contentsGOVERNMENT

UTILITIES

12 Sen. Murkowski rolls out energy ‘vision’

14 Obama nominates Jewell as interior secretary

15 Going public with a ‘critical issue’

13 Canada lags behind resource boom

3 Oil tax bill headed for Senate Resources

6 BSEE, NEB partner on Arctic safety

8 Canada to raise offshore liability cap

12 January ANS production down almost 1%

9 Repsol and Linc get AOGCC permits

Interior LNG requires privatecapital in addition to state funds

Senate tax discussions continue;PFC says state seen as tinkering

A holding pattern

Shell waiting on Kulluk investigations before deciding on next Alaska steps

Arctic port sites eyed

Army Corps, Alaska DOT select Nome and Port Clarence for feasibility analysis

Chevron sets LNG terms

Company’s chairman says prices need to be ‘close to oil parity’ to support cost

ON THE COVER

Alaska’sOil and GasConsultants

GeoscienceEngineeringProject ManagementSeismic and Well Data

3601 C Street, Suite 1424Anchorage, AK 99503

(907) 272-1234(907) 272-1344

[email protected]

http://www.petroak.com

By STEVE QUINNFor Petroleum News

In sports terms, Sen. Cathy Giesselspent her first legislative term on the

bench. But she took copious notes andnow she’s batting cleanup.

Giessel chairs Senate Resources andis about to have Senate Bill 21 land inher committee for review. It will be thesecond Senate committee to hear Gov.Sean Parnell’s oil tax reform bill, follow-ing the Special Committee on TAPSThroughput.

Getting to runthe committeerequired paying spe-cial dues. Giesselspent two years in aminority caucus thatdid not receivemany committeeassignments.

That didn’t stopthe AnchorageRepublican from attending nearly everycommittee hearing — House or Senate— that dealt with resource developmentissues.

She was as much a fixture as anycommittee member, but Giessel took aseat among the audience, armed with anote pad and a few pens, taking copiousnotes, ultimately preparing herself tohandle some of the heavier hitting piecesof legislation almost immediately.Giessel sat down with Petroleum Newsand talked about what she learned andthe resource development priorities shesees for the Legislature.

Petroleum News: You seem to haveserved a self-appointed apprenticeshipfor two years. You attended more hear-ings in some cases than committee mem-bers themselves. What drove you deci-sion to do that?

Giessel: I feel it was my responsibili-ty to be as educated as I could be.Whether I served on the committee ornot, I wanted to be there hearing first-hand the discussion. So I felt it was myduty and still feel it is my duty, thoughmy calendar is a bit more full these days,so I don’t get to quite as many commit-tees that I don’t serve on. I have focused,however, on attending the two specialcommittees: TAPS Throughput and In-State Energy. I’m not assigned to thosecommittees but they are doing the pre-liminary work for subjects that willcome to Resources. Again, I just want tobe there and hear the discussion.

Petroleum News: So that style of com-mitment hasn’t changed?

Giessel: No, it hasn’t changed. I’mhere to work. That’s what my con-stituents elected me to do, to come andwork for them.

Petroleum News: So with that styleover those two years, what did you learneither about the job or about our state’sresources?

Giessel: Wow, I learned a lot aboutour resources. As I look at (Legislature’sconsultant) PFC Energy presentationsnow — for example last week they werein the TAPS Throughput Committee — Ilook at the slides presented and compareto the information that PFC gave us lastyear and some of the metrics havemoved a little as the world changes. Of

course the petroleum industry is a world-wide market; it’s dynamic, so some ofthe elements have changed in their pres-entation. I’m going to be asking themabout that when they come before mycommittee. So it’s been really good tohave that background. Before I waselected I used to watch Gavel to Gavelpretty regularly, watching the (Senate)Finance Committee, and I particularlyremember the in-depth discussions theyhad on decoupling and when (consultant)Pedro Van Meurs was before them, so ithelps to have more of that historicalbackground, I think.

Petroleum News: So knowing therewas a change in that metric as you say,your investment into those two yearsseems to be paying off either with anappointment as a committee chair or anunderstanding of context.

Giessel: I think it’s paid off signifi-cantly for me and in the information thatI can share with my constituents basedon those two years of sitting in commit-tees and hearing all of the discussion. Ofcourse, I couldn’t participate in the com-mittee itself, but certainly I could askquestions afterward of individuals andpeople testifying. But it gives me moreinformation I could share with my con-stituents. Our founders believed stronglythat our democracy would be heldtogether by an informed citizenry. Peopleare busy these days. They don’t all watchGavel to Gavel. So I feel it’s my respon-sibility to learn as much as I can andshare that information with them.

Petroleum News: Moving to this year,what would you say are your prioritiesthis two-year session?

Giessel: No. 1 we’ve got to increasethe amount of oil going through ourpipeline, for a couple of reasons, thebiggest one being that’s our main sourceof revenue. The second one being thatpipeline is being very stressed with thelow throughput. It’s becoming a realchallenge to keep that equipment in tip-top shape. The best remediation is put-ting more oil through it.

The second one is energy. I live downin the Cook Inlet area. We are dependenton natural gas from Cook Inlet, but I’ma born-and-raised Fairbanks girl. Mymother still lives in Fairbanks. She buysdiesel to heat her home at a very highcost. My hometown is dying frankly. I’mvery concerned we get natural gas fromthe North Slope down that central corri-dor of our state and branches out intorural areas as much as possible. There isof course other energy potential with theWatana Dam. I’m a verybig supporter of hydro-electric: It’s clean,dependable, durable and agreat source of energy.

The third one I don’thave quite so much say in it, but we haveto ramp back our spending to a moresustainable level. I’m a grandmotherwith three beautiful grandchildren and afourth one on the way in about a month.I want those kids to be able to live herefar into their lifetime. That means ourbudget has to be sustainable so we arenot spending everything we earn today.

Petroleum News: You’re going to getthe oil tax bill very soon. How did hav-ing the bill spend time in the TAPSThroughput Committee help you?

Giessel: Having it in TAPSThroughput initially helped me in thatI’ve heard the presentations already; I’vealready been thinking about what mightbe altered or not in the bill. I’ve seen

some of the modeling already. So that’sbeen helpful. Truly I haven’t just beenwaiting for the bill to get to my commit-tee. Our committee has been laying thegroundwork. We’ve been looking atterms that are used in the oil fields. Youknow, what is a participating area; howare leases managed; how much resourceis actually up there; what does the geolo-gy look like?

So laying that groundwork to prepareto manage that bill and altering our taxes

to be more competitive andget more oil out of ourfields. Our committee hasnot been just sitting therewaiting.

Petroleum News: What are yourthoughts on the bill?

Giessel: I think it’s a pretty innovativebill. I like the elements in it. When Ilook at the governor’s priorities, the fea-tures he wanted in it, they align with thethings I’m interested in also: fairness toAlaskans. At this point we are giving outcredits that never result in any produc-tion. That’s not a fairness for Alaskans. Itdoesn’t align our interests with the oilcompanies. We are paying for infrastruc-ture, but does that result in more oil?

New production is a key piece. I wasalso very concerned about simplifyingour tax. Again, listening to Pedro VanMeurs and PFC, a frequent message that

� G O V E R N M E N T

Oil tax bill headed for Senate ResourcesCommittee Chair Cathy Giessel preparing by attending other hearings, a practice she began in the last session as a minority member

PETROLEUM NEWS • WEEK OF FEBRUARY 10, 2013 3

��

��

��

��!"�� #��

�� $�� %� ��

��#�� $��

�� !�

Alaska’s Premier Motorola DealerProviding Alaskans with two way radio and wireless communications.

The future of two-way radio.

NORTH SLOPETELECOM, INC.

907.751.8200 | www.nstiak.com

MOTOTRBOTM PROFESSIONALDIGITAL TWO-WAYRADIO SYSTEM.

SEN. CATHY GIESSEL

see GIESSEL page 15

http://www.nstiak.com

http://www.maritimehelicopters.com/


Kay Cashman PUBLISHER & EXECUTIVE EDITOR

Mary Mack CHIEF FINANCIAL OFFICER

Kristen Nelson EDITOR-IN-CHIEF

Clint Lasley GM & CIRCULATION DIRECTOR

Susan Crane ADVERTISING DIRECTOR

Bonnie Yonker AK / NATL ADVERTISING SPECIALIST

Heather Yates BOOKKEEPER

Shane Lasley IT CHIEF

Marti Reeve SPECIAL PUBLICATIONS DIRECTOR

Steven Merritt PRODUCTION DIRECTOR

Alan Bailey SENIOR STAFF WRITER

Eric Lidji CONTRIBUTING WRITER

Wesley Loy CONTRIBUTING WRITER

Gary Park CONTRIBUTING WRITER (CANADA)

Rose Ragsdale CONTRIBUTING WRITER

Ray Tyson CONTRIBUTING WRITER

John Lasley DRILLING CONSULTANT

Allen Baker CONTRIBUTING WRITER

Judy Patrick Photography CONTRACT PHOTOGRAPHER

Mapmakers Alaska CARTOGRAPHY

Forrest Crane CONTRACT PHOTOGRAPHER

Tom Kearney ADVERTISING DESIGN MANAGER

Amy Spittler MARKETING CONSULTANT

Renee Garbutt ADVERTISING ASSISTANT

Julie Bembry CIRCULATION DEPARTMENT

Dee Cashman CIRCULATION REPRESENTATIVE

Joshua Borough ASSISTANT TO THE PUBLISHER

Petroleum News and its supple-ment, Petroleum Directory, are

owned by Petroleum Newspapersof Alaska LLC. The newspaper ispublished weekly. Several of theindividuals listed above work forindependent companies that con-

tract services to PetroleumNewspapers of Alaska LLC or are

freelance writers.

ADDRESSP.O. Box 231647Anchorage, AK 99523-1647

NEWS [email protected]

CIRCULATION 907.522.9469 [email protected]

ADVERTISING Susan Crane • [email protected]

Bonnie Yonker • [email protected]

FAX FOR ALL DEPARTMENTS907.522.9583

OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 18, No. 6 • Week of February 10, 2013

Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518(Please mail ALL correspondence to:

P.O. Box 231647 Anchorage, AK 99523-1647)Subscription prices in U.S. — $98.00 1 year, $176.00 2 years, $249.00 3 years

Canada — $185.95 1 year, $334.95 2 years, $473.95 3 years Overseas (sent air mail) — $220.00 1 year, $396.00 2 years, $561.00 3 years

“Periodicals postage paid at Anchorage, AK 99502-9986.”POSTMASTER: Send address changes to Petroleum News, P.O. Box 231647 Anchorage, AK 99523-1647.

www.PetroleumNews.com

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

Clearing way for Canol shaleInfrastructure, regulatory streamlining gain attention as activitypicks up in Central Mackenzie; development could be 5 years away

By GARY PARKFor Petroleum News

A lthough commercial development ofthe Devonian Canol shale play in the

Central Mackenzie Valley of theNorthwest Territories is as far as five yearsdown the road, the pressure is building tostart planning for major oil and natural gaspipelines and to relieve a regulatory bottle-neck in Canada’s North, according to keyplayers in the region.

John Hogg, vice president of explo-ration and development with MGMEnergy, told a symposium in Calgary thatif the Canol play takes off producers wouldneed significantly more capacity than iscurrently available on Enbridge’s existingNorman Wells oil pipeline to northernAlberta.

That system can carry up to 39,500 bar-rels per day, but is currently down to13,000 bpd as the productive life ofImperial Oil’s Norman Wells oil field con-tinues to wind down after yielding about300 million barrels.

However, Hogg said the Enbridge lineis “nowhere near big enough”, while theregion does not have a gas line and “we’regoing to need one of those too.”

He said the question that is looming ishow fast Enbridge or TransCanada couldbuild pipelines and what size would beneeded.

“The next couple of drilling seasonswill really tell us what the potential of thisplay is,” Hogg said.

Approval time a challengeAdding to the challenges is the length

of time it would take to gain approval totwin a line that already exists, he said, not-ing that it currently requires six to 15months for MGM’s regulatory group toobtain a permit for an exploration well,compared with six to eight weeks inAlberta.

Hogg said MGM is involved in onlyone or two wells a year, asking: “Whathappens if we go to development and wewant to drill 20 or 30 wells a year?”

He said that if the Canol is deemedcommercial, year-round drilling woulddramatically reduce costs, assuming theCanadian government and industry build aroad to Norman Wells, estimating that one-third of the drilling costs in the CentralMackenzie Valley are spent just getting tothe site, including the use of a 240-mile iceroad.

Hogg said the answer is to build all-weather roads as Husky Energy is doingthis winter, overcoming the loss of iceroads in the spring melt and the constantmaintenance to support heavy trucks.

Some help could be at hand if theCanadian government strikes a deal totransfer control over land, resources andwater to the Northwest Territories govern-ment, ending years of inconclusive negoti-ations.

NWT officials in OttawaA large delegation from the NWT gov-

ernment, including Premier Bob McLeod,spent two days in Ottawa at the end ofJanuary meeting Prime Minister Stephen

Harper and federal officials.McLeod entered the meetings in an

upbeat mood, suggesting the NWT is “onthe verge of achieving devolution (of pow-ers). We are advancing on many fronts. Itseems like everything is coming together.”

The prospect of a breakthrough is espe-cially important for the mining industry,which the Conference Board of Canadapredicted could see the value of output riseto C$1.3 billion in 2020 from C$732 mil-lion in 2011, with five new mines sched-uled to open over the next four years.

A spokesman for Aboriginal andNorthern Affairs Minister John Duncansaid his government is determined to reacha deal “which will be an important andpositive step in the evolution of Northerngovernance and will deliver economic ben-efits to the NWT.”

The NWT government is confident thatdevolution will ease the regulatory burdenthat has been identified by Hogg and oth-ers as a barrier to development of theNWT’s vast oil, natural gas and hydro-electric resources.

With four of seven aboriginal govern-ments in the NWT having signed agree-ments-in-principle on devolution, McLeodbelieves there is sufficient backing fromnative communities to proceed if a pact isreached with the federal government.

MGM, Shell drillingIn the meantime, MGM, with Shell

Canada as a partner, has spudded its firstvertical exploration well in the Canol play,estimating it will take until about mid-February to drill, core and log.

Once drilling has reached target depthof about 6,700 feet, the well will be com-pleted in the Canol and Bluefish zones andflow tested — operations that MGM hopesto complete by the second week of March.

Husky drilled two exploration wells lastwinter and plans to repeat the effort thiswinter.

MGM, Shell and Husky have joinedConocoPhillips and Imperial Oil in form-ing an explorers’ group because, in Hogg’swords, “we need to have synergies andshare.”

He said results from MGM and Huskydrilling this winter should provide someclarity around oil and gas rates.

Although it will be difficult to achieve astabilized flow over a short period of time“at least we’ll get a sense of what the gas-oil ratio is. That’s the critical element thatwe would all like to know.”

Conoco spudsIn addition to the MGM and Husky

drilling, the National Energy Board hasreported that ConocoPhillips spudded anexploration well Jan. 26 and has approvalfor two more wells.

see CANOL SHALE page 5

“Everything that is working in theHorn River you can now start tolook for in the Canol and your

opportunity for development startsto move forward.” —Roy Benteau,

petrophysical advisor for Vermilion

http://www.usaee.org/usaee2013


Lauded by some as a major contributorto the cleanup of spilled oil following

the 2010 Deepwater Horizon disaster inthe Gulf of Mexico and slammed by oth-ers as environmentally dangerous, the useof chemicals to disperse oil slicks hasbecome a controversial topic.

The concept behind dispersant use issimple. The dispersant chemicals, acting abit like dishwashing liquid, break the oilinto tiny particles, greatly increasing thesurface area of oil exposed to water andhence greatly accelerating the rate atwhich oil-consuming microbes devour theoil, causing the oil to disappear.

But do dispersants, demonstrated inlaboratory conditions, work in the hurly-burly of a real spill response situation?And, more particularly, would dispersantswork, were there to be an oil spill catas-trophe in the Arctic offshore?

SkepticalJeffrey Short, an environmental con-

sultant working for Oceana, a marine con-servation organization, is very skepticalabout the potential effectiveness of dis-persants in the Arctic. Short, who workedas a research chemist for the NationalOceanic and Atmospheric Administrationfor 31 years and has published more than60 scientific papers on Arctic pollution,spoke at the Alaska Forum on theEnvironment on Feb. 4, giving his viewsregarding the problems associated withdispersant use in the Arctic.

Short, who said he had been involvedin the Deepwater Horizon response,working for private entities, said thatclaims about the effectiveness of disper-sants during that response had been over-stated, and that there was a lack of evi-dence for dispersant chemicals havinghad any impact in boosting the naturalbiodegradation of oil that had spewedfrom the out-of-control, seafloor well. Forexample, no one observed the milkyappearance of dispersed oil in the water,he said.

And, although the government-pub-lished oil budget calculator for theDeepwater Horizon response indicatedthat dispersants had been somewhat effec-tive, the technical underpinnings of thatconclusion, as expressed in the budget

calculator report, appear far short of con-vincing, he said.

Goldilocks circumstancesThe effective use of dispersants

requires a “Goldilocks” set of circum-stances, in which the wind is strongenough to cause the necessary waveaction for mixing oil with dispersantchemicals, but not so strong as to blowaway the fine spray of dispersant, normal-ly applied from an aircraft, Short said.And seas that are too rough can cause dis-persants to escape into underlying water,rather than mix with an oil slick on thesurface, he said.

Also, there is typically a relativelyshort time window following an oil spill,during which dispersants can be used, asevaporation and emulsification of the oileventually renders the oil unresponsive todispersant chemicals.

Given seasonal ice, the frequency ofstrong winds and the prevalence of seafog in the Arctic Ocean, the appropriateconditions for the application of disper-sants in Arctic seas may only occur for 10percent of the time, Short said.

Lab testsShort said that 10 years ago he had

conducted some laboratory tests for thePrince William Sound Regional Citizens’Advisory Council, testing the effect of acommonly used oil dispersant on AlaskaNorth Slope crude oil in sub-Arctic con-ditions. Those tests demonstrated that thedispersant did not work well in cold water,with dispersant effectiveness droppingwith reduced water temperatures and withlow water salinity, Short said. Theseresults do not bode well for dispersanteffectiveness in the Arctic — in additionto the effect of low water temperatures on

dispersant action, melting ice in the Arcticseas tends to create a layer of low salinitywater near the sea surface, he said.

Compounding the technical issuesrelating to the potential effectiveness ofdispersants in the Arctic is the sparsetransportation architecture for the resup-ply of dispersant chemicals to fieldresponders, Short said.

Asked about the possibility that lowwater temperatures would slow oil degra-dation, thus extending the time windowwithin which dispersants would be effec-tive, Short responded that the weatheringof oil is less sensitive to temperature thanto wind, of which there is plenty in theArctic. The rate of incorporation of waterinto the oil, a phenomenon that takesplace quite quickly, depends on the com-position of the oil, he said.

Continuing debateShort’s comments come amid a contin-

uing debate over the realistic feasibility ofconducting an offshore oil spill responsein the Arctic. And a report, issued inNovember by the U.S. Arctic ResearchCommission and the U.S. Army Corps ofEngineers, after overviewing the consid-erable body of research already done intooil spill response in the Arctic offshoremade a number of recommendations forfurther research, including a recommen-dation that people evaluate the effective-ness of dispersants in Arctic conditions.

A joint industry program, known asSINTEF and based in Norway, conducteda series of large-scale field experiments inthe mid-2000s, testing the use of variousresponse techniques, including disper-sants, using oil deliberately spilled in the

sea under carefully controlled conditionsat an Arctic location. SINTEF reportedthat it had found rates of oil weathering inbroken ice conditions to be considerablylower than rates observed for the same oilin open water. The final report for the pro-gram also said that researchers had expe-rienced success in dispersing oil in wateraround ice floes, by applying the disper-sants from spray arms deployed from ves-sels and using the prop wash or jet motorsof response boats to mix the dispersantwith the oil.

Oil budgetA read of the technical documentation

for the Deepwater Horizon oil budget cal-culator makes it clear that there was awide range of expert opinion and no gen-eral agreement on the effectiveness ofdispersants in the response to that disas-ter. A December 2012 paper in theProceedings of the National Academy ofScience presents an overview of the sci-entific findings from Deepwater Horizon.Written by senior officials from severalfederal agencies, including the U.S.Geological Survey and the NationalOceanic and AtmosphericAdministration, the paper says that moni-toring of oil in the water through a varietyof techniques had provided oil particlesize data consistent with expectationsfrom chemical oil dispersion. The oilbudget calculator subsequently concludedthat chemical dispersion accounted forabout 16 percent of the oil that hadescaped from the well, the paper says. �

� E N V I R O N M E N T & S A F E T Y

Questions over Arctic dispersant useEnvironmental consultant questions feasibility of using oil dispersant chemicals in responding to an Arctic offshore oil spill


AlphaSeismicCompressors.com

1-888-800-2232

Offshore Rentals | Air Source Solutions Risk Management | After Market Services

[email protected]

Booking Now

The conference, sponsored by CIEnergy Group, also heard ColleenSherry, senior tight oil regional geolo-gist for Vermilion Energy, draw similar-ities between the Horn River Basin ofnortheastern British Columbia and theCentral Mackenzie Valley shales.

She and Roy Benteau, petrophysicaladvisor for Vermilion, had identified theCanol play when looking to replicate the

Horn River in the oil window, but theircompany opted not to post the land,leaving MGM to snap up a large portionof the rights.

“Everything that is working in theHorn River you can now start to look forin the Canol and your opportunity fordevelopment starts to move forward,”Benteau said, describing the larger poresin the Canol as similar to what might beseen in the Eagle Ford in Texas. �

continued from page 4

CANOL SHALE

A joint industry program, knownas SINTEF and based in Norway,conducted a series of large-scale

field experiments in the mid-2000s, testing the use of variousresponse techniques, including

dispersants, using oil deliberatelyspilled in the sea under carefullycontrolled conditions at an Arctic

location.

http://www.AlphaSeismicCompressors.com/

By KRISTEN NELSONPetroleum News

Bids will be opened beginning at 9 a.m.May 8 for three state competitive

lease sales — two oil and gas and the thirdgeothermal.

The Alaska Department of NaturalResources, Division of Oil and Gas, said inFeb. 1 notices of sale that the AlaskaPeninsula areawide 2013 and Cook Inletareawide 2013 oil and gas lease sales, and

the Augustine Island geothermal competi-tive bid sale will take place at the Dena’inaCivic and Convention Center inAnchorage.

Detailed sale information is available

on the division’s website athttp://dog.dnr.alaska.gov. The division saida tract maps for the three sales will bereleased after March 18.

Fourth geothermal saleIn a Feb. 4 press release on the upcom-

ing sales the division said the AugustineIsland sale is the fourth geothermal leasesale the state has held. The most recentsale was in 2008 for acreage on MountSpurr on the west side of Cook Inlet.

The Augustine geothermal sale, thefirst geothermal sale in the Augustine areaof Cook Inlet, has a minimum bid of $1per acre; the primary term of leases will be10 years, renewable for an additional fiveyears; the annual rent will be $3 an acre;and the royalty rate will be 1.75 percent ofgross revenues from production, sale oruse of geothermal resources during thefirst 10 years the resource generates grossincome and 3.5 percent of gross revenuesafter that first 10-year period. Rent androyalties will be renegotiated 20 years afterinitiation of commercial production.

The 65,992-acre area is divided into 26tracts from 2,489 to 2,560 acres coveringthe entire Augustine Island including sometidelands and adjacent waters.

(There is a story on the Augustine leas-ing proposal in Jan. 27 issue of PetroleumNews.)

Alaska Peninsula saleFor the Alaska Peninsula areawide 2013

oil and gas lease sale the minimum bid is$5 per acre with a fixed royalty rate of 12.5percent and a 10-year term for all tracts.

There are 1,047 tracts in the AlaskaPeninsula sale, ranging in size from 1,280to 5,760 acres of state-owned uplands andtide and submerged lands on the north sideof the Alaska Peninsula from theNushagak Peninsula to just north of ColdBay.

The 2005 Alaska Peninsula areawidesale drew $1.15 million in high bids fromShell Offshore Inc. and Hewitt MineralCorp. on 37 tracts, some 190,494 acres.Hewitt picked up an additional tract in the2007 sale; sales held annually in 2008

through 2012 drew no bidders and thereare no remaining active leases in the area.

Cook Inlet saleThe division noted that “the Cook Inlet

hydrocarbon basin has seen a resurgencein investment by small, medium-sized andlarge energy companies” in the past twoyears.

“Cook Inlet still holds significantresources and we are hoping for a contin-ued trend of successful lease sales andincreased drilling activity,” divisionDirector Bill Barron said Feb. 4.

There are 815 tracts ranging from 1,280to 5,760 acres in the Cook Inlet sale with aminimum bonus bid of $25 an acre for alltracts, a fixed royalty of 12.5 percent and alease term of 10 years.

Cook Inlet lease rental rates are $10 anacre for the first through the seventh yearsof the lease and $250 an acre for the eighththrough the 10th years of the lease. Annualrentals may revert to $10 an acre after sus-tained production or “at the state’s discre-tion after the lessee meets certain condi-tions.”

The division said that after sustainedproduction has begun “or the state other-wise determines in its sole discretion,upon request, that the lessee has exercisedreasonable diligence in exploring anddeveloping this lease” the annual rentalmay be set at $10 per acre or fraction ofacre.

In its Cook Inlet sale announcement thedivision said: “In evaluating a request todecrease rental based on the exercise ofreasonable diligence, the state will consid-er the funds expended by the lessee toexplore and develop this lease and thetypes of work completed by or on behalf ofthe lessee on this lease.”

The state first set these variable-rentlease terms in its fall 2011 lease sales, andBarron said at that time that the state’s goalwas to “encourage people to prudently andresponsibly explore and delineate theiracreage within the primary lease term.” �

� L A N D & L E A S I N G

State sets May 8 date for spring salesAugustine geothermal competitive sale added to schedule; Cook Inlet, Alaska Peninsula areawide oil and gas sales offered annually


Cook Inlet lease rental rates are$10 an acre for the first through

the seventh years of the lease and$250 an acre for the eighth

through the 10th years of the lease.

GOVERNMENTBSEE, NEB partner on Arctic safety

The U.S. Bureau of Safety and Environmental Enforcement and the CanadianNational Energy Board are partnering to promote Arctic offshore safety.

The agencies said Feb. 5 that a memorandum of understanding was signed byBSEE Director Jim Watson and NEB Chair and CEO Gaetan Caron in Washington,D.C., Feb. 4. The MOU encourages information sharing and cooperation between theregulators on government energy policy, regulatory development, specific energyprojects and best practices.

“BSEE and NEB both have a shared commitment to reduce the risks associatedwith offshore drilling in the Arctic,” Watson said in a statement. He said the MOU“establishes a means for our two agencies to share data and experiences as expedi-tiously as possible so that we can identify and react effectively to industry-wide risks.”

Gaetan said the agreement “lays the groundwork for cooperation on matters ofmutual interest between our two agencies, and it’s an important step in sharing bestpractices and supporting effective regulatory outcomes.”

The MOU is effective for five years and renewable every five years; it may be mod-ified jointly or discontinued at any time by either participant.

—PETROLEUM NEWS

http://www.LFAV.com/

http://www.ReactiveGel.com/mav


If the unthinkable happens and oil isspilled in sea ice conditions in the

Arctic, spill responders will be faced withthe challenge of locating oil trappedunder ice floes. Oil, being lighter thanwater, would float towards the sea surfacebut would likely become caught in hol-lows in the underside of the floating icecover.

The Oil Spill Recovery Institute, orOSRI, an organization based in Cordova,Alaska, that supports oil spill research,has recently been conducting a couple ofprojects, aimed at finding new ways ofdetecting oil trapped in this sub-ice situa-tion, Scott Pegau, OSRI research programmanager, told the Alaska Forum on theEnvironment on Feb. 4.

One project, involving the use of teth-ered surveillance balloons, is aimed atdetermining whether the warmth of theoil can be detected from above the iceusing infrared cameras. The other projecthas entailed researching the possibility ofdetecting oil from under the ice usingremotely operated or autonomous under-water vehicles.

Cheap and portableA particular appeal of the tethered sur-

veillance balloon concept is the low costand easy portability of the technology,coupled with the ease of permitting of itsuse, Pegau explained. The use of drones,an alternative means of achieving aerialsurveillance, is very difficult to permit hesaid.

With limitations on how much flyingmay be practical along the Alaska coast-line, the OSRI researchers sought sometype of technology that could be deployedfrom a boat in a wide variety of differentweather conditions, Pegau said. And mod-ern kite-style balloons can be operated inwind strengths up to 80 knots, he said.

An infrared camera mounted on a bal-loon, which is tethered to a boat, can usewireless transmission to send videoimages to a receiver operated by respon-

ders on the boat. Thus, the responders canobtain an immediate, elevated view of seaice in their vicinity.

“They’re moving their eyes from 30feet off the water to 500 feet off thewater,” Pegau said.

A test using a balloon tethered to atruck on the North Slope demonstratedthat the infrared camera could detectwarm water that the researchers hadallowed to seep under the snow. Anothertest, using an Alaska Clean Seas vessel inHarrison Bay, to the west of Prudhoe Bay,

enabled people on the boat to obtain abirds-eye view of an adjacent ice sheet,with the infrared image showing that theice was sufficiently weak to allow passageof the boat, an observation that could notbe made from the level of the boat’s deck.

Underwater observationsThe underwater vehicle concept

involves both the visual detection of darkoil against a reflective ice surface and thedetection of oil using a sonar system,rather like a depth sounder as used byfishing vessels. The visual detection sys-tem would entail shining a beam of lightupwards at the underside of the ice andthen using a camera system to detect lightreflected back downwards.

Tests using oil injected under half-meter-thick saltwater ice in the ColdRegions Research and Engineering Lab’s

test tank in New Hampshire proved prom-ising. A camera system mounted on anunderwater cart could easily detect darkmaterial juxtaposed against the ice, Pegausaid. And the acoustic system, alsomounted on the cart, provided informa-tion about the depth of the oil and theextent to which the oil had been disturbed,he said.

Future tests of the underwater systemswould evaluate how far it might be possi-ble to see into the ice, and the extent towhich it would be possible to detect oilencapsulated in the ice, Pegau said. AndOSRI sees its system as complementaryto ground penetrating radar, a technologythat is used above an ice sheet to seektrapped oil, he said. �


Finding ways of seeing oil under iceOSRI tests the use of surveillance balloons and underwater vehicles for detecting oil caught below ice following an oil spill


A test using a balloon tethered toa truck on the North Slope

demonstrated that the infraredcamera could detect warm waterthat the researchers had allowed

to seep under the snow.

http://www.PetroleumNews.com/

http://www.lynden.com/


GOVERNMENTCanada to raise offshore liability cap

Canada’s offshore players — explorers, producers, pipelines and marine ship-pers — have been told by Environment Minister Peter Kent they can expect a newregime that will include “significant” changes to liabilities for polluters.

He said legislation will shortly be introduced in response to the pressure todiversify Canada’s oil and natural gas markets, offshore drilling and greaterpipeline shipments.

Government sources have indicated the liability cap could be raised to “billionsof dollars” from the current C$40 million in the Beaufort Sea and C$30 millionoff the East Coast, which have been described since BP’s Macondo well blowout,as de facto subsidies for offshore operators.

The sources suggest that the industry will have to either buy insurance or “self-insure” to cover the financial risks from a blowout or spill.

Natural Resources Minister Joe Oliver said the liability system is beingreviewed “to make certain that Canada’s polluter-pay system remains among thestrongest in the world” at the same time the government is strengthening maritimeprotection by requiring double-hulled vessels, enhanced navigational aids andincreasing inspections of federally regulated pipelines by 50 percent.

Pressures intensifyingThose pressures have been intensifying as the petroleum industry has advanced

plans to export oil sands bitumen and LNG from the British Columbia coast andcompanies move forward with plans to explore the Beaufort and the Atlantic off-shore regions.

Travis Davies, a spokesman for the Canadian Association of PetroleumProducers, said the organization is working with its member companies inAtlantic Canada to develop an industry position on changes to the existing regimein hopes of being consulted on what changes the government is contemplating.

“Once we have a position, we’ll be constructive participants in the governmentprocess, submitting input which will be public,” he said.

Will Amos, director of the Ecojustice environmental law clinic at theUniversity of Ottawa, said companies “should face unlimited absolute liability forspills, in accordance with the polluter-pays principle,” arguing that an “offshorespill lingers forever.”

Scott Vaughan, Canada’s commissioner of the Environment and SustainableDevelopment, is scheduled to release a report in February that examines what sys-tems are in place to protect taxpayers against the cost of accidents in the mining,nuclear, offshore oil and gas and marine transportation sectors.

—GARY PARK

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

AOGCC halts newMeltwater drillingAOGCC wants more information about why MI is migrating intoshallower formations before ConocoPhillips can continue drilling

By ERIC LIDJIFor Petroleum News

The Alaska Oil and Gas ConservationCommission is telling

ConocoPhillips Alaska Inc. to hold off ondrilling at a Kuparuk River unit satelliteuntil the company and regulators can bet-ter understand why injected fluids havebeen migrating into shallower formations.

Starting in April 2002, ConocoPhillipsnoticed elevated pressures in the outerannulus — the area between the outerwalls of a well at the surrounding geolog-ic formation — of development wells inthe Meltwater Oil Pool. Gas samples sug-gested that the miscible injectant used toenhance oil recovery in the field wasmigrating into the outer annulus.

For years, ConocoPhillips provided“periodic updates of monitoring and diag-nostic efforts to the AOGCC” while it con-tinued to make injections, but last year thecompany said a recent 4-D seismic evalu-ation determined that MI fluids were, infact, migrating to shallower strata in thearea. After ConocoPhillips made someadjustments to its reservoir managementpractices at Meltwater, the AOGCC inOctober 2012 allowed the company tocontinue MI injections under certainreporting requirements and pressurerestrictions.

Because there are no potential under-ground sources of drinking water inMeltwater, the migration should not con-taminate drinking water, but does violateAOGCC regulations.

Subsequently, ConocoPhillips askedthe AOGCC to make six changes to theArea Injection Order for enhanced oilrecovery at Meltwater, first among thembeing to expand the definition of the reser-voir to include the shallower strata wherethe MI is migrating.

Currently, the reservoir only includesthe Bermuda interval of the Meltwatersands, defined as extending from 6,785feet to 6,974 feet in the Meltwater NorthNo. 2A well.

ConocoPhillips wanted to move the topof the zone to 2,503 feet. The changewould have included the Cairn — an inter-val extending from 6,411 feet to the top of

the Bermuda.When Phillips Alaska Inc. initially

applied for Meltwater pool rules in 2001,it asked the AOGCC to include the Cairnin the reservoir, but the AOGCC decided“insufficient information is available toinclude the Cairn interval in the(Meltwater pool) at this time.”

Following a November 2012 hearing— where ConocoPhillips presented sometestimony confidentially — the AOGCCdenied the request, saying it would haveviolated existing state regulations. TheAOGCC also denied a request fromConocoPhillips to allow it to skip weeklywell monitoring during extreme weatherand other emergencies. The AOGCC did,however, grant ConocoPhillips’ request toadd several rules to the Area InjectionOrder covering well integrity, confine-ment of fluids, and injection pressures.

Now, the AOGCC is tellingConocoPhillips not to drill any new wells,or to convert any existing productionswells to injection wells, at Meltwater untilthe issue is resolved.

While noting that ConocoPhillips’reservoir management adjustments at thepool appeared to be “allowing migrationpathways to close,” the AOGCC said“more data are needed to assess the effec-tiveness of these migrating practices.”Starting in November, ConocoPhillipslaunched an 18-to-24-month study of theoverburden in the area that the AOGCCcalled “critical” for understanding thecharacteristics of the Meltwater Oil Pool.

The AOGCC also determined that thereasons ConocoPhillips gave during thehearing for keeping certain material confi-dential did not meet state standards, butdecided not to add those materials to thepublic record until after the end of theappeal period for the case.

Phillips Alaska Inc. discovered theMeltwater satellite in May 2000 andbrought the satellite — the fourth at theKuparuk River unit — into production inNovember 2001.

The company began its MI programat Meltwater in January 2002. �

http://www.arctosak.com

http://www.dowlandbach.com/


www.lrog.com

AUTONOMOUS MARINE VEHICLE

Wave Glider

Reduce cost and lower risk A new way to collect data offshore in the Arctic.

A joint venture with Schlumberger

■ Low profile and easy to launch ■ Powered by sea waves and solar panels ■ Piloted remotely to hold position or navigate courses ■ Satellite link for commands and data transmission

For oil and gas applications contact Schlumberger at [email protected]

� U T I L I T I E S

Utilities take overnew power plantCombined cycle power generation replacing old plant willsignificantly reduce gas consumption by Southcentral power utilities


On Jan. 31 Chugach ElectricAssociation took over the operator-

ship of the new Southcentral PowerProject electricity generation facility thatChugach Electric and Municipal Light &Power have constructed in Anchorage. Thenew power station had been deliveringpower to the Railbelt electrical grid forseveral months as part of the testing andcommissioning of the facility but the han-dover from SNC-Lavalin Constructors,the contractor that built the facility, repre-sented the facility’s formal completion.

The transfer of the $369 million projectto Chugach Electric took place well aheadof its originally planned June date, thepower utility said in a Feb. 4 press release.Chugach Electric is operating the plant onbehalf of itself and Municipal Light &Power, the joint owner.

Natural gas savings“I’m very proud of the work by

Chugach staff and managers to bring thisproject to fruition on behalf of the two

utilities and the thousands of consumersthey serve,” said Janet Reiser, chair of theChugach Electric Board of Directors.

And, with modern, combined-cyclepower generation equipment, the 183-megawatt gas-fired power plant will con-sume about 25 percent less gas per kilo-watt-hour than the decades-old and ineffi-cient Southcentral power generationcapacity that the plant is displacing. Theconsequence will be a reduced demand fornatural gas from the declining gas fieldsof the Cook Inlet basin and a reduced costof power generation for Southcentral elec-tricity consumers.

Chugach alone estimates that the newplant will cut its annual natural gas con-sumption by 3 billion cubic feet a year, anannual savings of more than $15 millionfor its customers, the utility said.

However, consumers can expect an ini-tial rise in electricity rates by 4 to 6 per-cent, to enable the utilities to recover thecost of building the new facility, ChugachElectric said. �

The new Southcentral Power Project gas-fired power plant in Anchorage will substantiallyreduce the region’s demand for natural gas for power generation.

EXPLORATION & PRODUCTIONRepsol and Linc get AOGCC permits

The Alaska Oil and Gas Conservation Commission issued two drilling permits atthe end of January for Repsol E&P USA Inc. to explore its Qugruk prospect on theNorth Slope.

On Jan. 25, the AOGCC issued a permit for Repsol to drill the Qugruk No. 6 wellon ADL 391394. The coastal well would be mostly vertical but move slightly to thenorth. On Jan. 31, the AOGCC issued a permit for Repsol to drill the Qugruk No. 3well on ADL 391445. The onshore well is also mostly vertical, but moves slightly tothe south.

Repsol is planning a three-well program this winter across the Qugruk prospect. Theprospect is in a narrow fairway between the Oooguruk and Colville River units.

The AOGCC also issued a permit Jan. 25 for Linc Energy Operations Inc. to drillUmiat DSP No. 1, a Class II disposal well at the oil field in the Brooks Range foothills.

The company received a corresponding drilling permit Jan. 18 from the U.S. Bureauof Land Management, the agency that oversees drilling on federal lands.

The well would be on federal lease AA081726. The well is the first in a four-to-sixwell program Linc is planning at Umiat this winter.

In January, Linc also applied for BLM permits to drill the Umiat No. 16 and UmiatNo. 18 wells. Umiat No. 16 would be vertical well on federal lease AA084141 to testan oil-bearing interval in the Lower Grandstand formation. Linc previously describedthe Umiat No. 18 well as an alternate location it planned to drill this winter if time per-mitted.

—ERIC LIDJI

CH

UG

AC

H E

LEC

TRIC

ASS

OC

IATI

ON

http://www.lrog.com/

http://www.aecom.com/

http://www.lwsurvey.com/

By BILL WHITEResearcher/writer for the Office

of the Federal Coordinator

Japanese, Korean and Taiwanese offi-cials told foreign LNG makers in

September 2012 that their prices are out ofwhack given what’s going on in NorthAmerica. Japan is enduring its first tradedeficit since the early 1980s in part due topaying high LNG prices.

Some think today’s price gap could nar-row quickly.

As one formerEnergy Departmentofficial told The NewYork Times recently,“I know the pitchabout our price dif-ferentials will justifythe high costs ofLNG. We will see.Gas by pipeline is agood deal. LNG?Not so clear.”

Medlock, the Rice University energyeconomist, published a paper in 2012 pre-dicting North American LNG exports willlose money.

Today’s extremely low North Americaprices are an aberration due to the new-found glut of shale gas, Medlock argued.Producers and markets will adjust,prompting the price to rise.

Today’s extremely high prices else-where, especially in Japan, the world’s topLNG buyer, also are an aberration dueLNG prices linked to soaring oil prices,exacerbated by a demand spike after

Japan’s Fukushima nuclear power plantdisaster in 2011, Medlock said.

Today’s extremes cannot last. Othercountries will start producing shale gas.More pipelines will get built to supplyChina, freeing more LNG for Japan andSouth Korea. New liquefaction projectscould sprout in Russia, East Africa andelsewhere besides North America.

When prices migrate to more reason-able and sustainable levels, the arbitrageopportunity will vanish, he said.

The global gas price differences willnot be “sufficient to support long-termbaseload LNG exports from the U.S. GulfCoast to these regions (Asia and Europe),”he said.

North American export sites could beprofitable as seasonal suppliers or as

providers of storage capacity for Europeanand Asian markets. “In fact, it would notbe surprising to see Asian utilities takingstorage positions in the U.S. to hedge sea-sonal price fluctuations. ... This is a dis-tinctly different type of arrangement froma baseload LNG supply deal,” Medlocksaid.

Cheniere Energy, the first mover to addliquefaction to its Louisiana import termi-nal, has found buyers for all of its 2-bcf-a-day output. British trader BG Group,Spain’s Gas Natural Fenosa, Korea GasCorp. and GAIL (India) have signed 20-year contracts.

Cheniere’s 2011 annual financial reportsays that collectively the four companieshave committed to pay $2.3 billion annual-ly for liquefaction services.

For Charif Souki, Cheniere CEO, toshift to liquefaction is an act of survival.

The company was near bankruptcy, hetold a London gas conference in October2012. He needed to find a way to salvageCheniere’s investment in storage tanks,tanker berths and the rest.

“For us it was a matter of life anddeath,” Souki said.

Import maniaTen years ago, the world looked very

different to Souki and other industry exec-utives.

They were joining the stampede tobuild or expand LNG import terminals.

“At one point in the early 2000s therewere over 47 regasification (import) termi-nals with certification for construction,which was a clear signal regarding indus-trywide expectationsfor significantdeclines in futureU.S. production,”Medlock said.

U.S. productiondid drop. From 2001 to 2005, productionfell 8 percent, the equivalent of 4.3 bcf aday.

The pressure was on to bring more sup-ply to U.S. consumers.

In late 2002, while considering anapplication for the Cameron LNG terminaleventually built in Hackberry, La., FERCmade a significant decision: It would nottake into consideration the financial viabil-ity of LNG projects brought to the com-mission. The project developer and its cus-tomers would bear the “economic risk.”FERC would focus on environmentalimpacts, operational safety and other mat-ters. The new policy lowered the hurdle aproject needed to clear to get FERC’sblessing.

Applications to build or expand LNGimport terminals flooded in. Big namesbacked some of them: producerExxonMobil; global gas trader BG Group;pipeline companies Veresen, Trunklineand El Paso; gas utility Sempra Energy.

In a 2004 letter to FERC’s chairman,U.S. Sen. James Inhofe, R-Okla., chairmanof the Committee on Environment andPublic Works, urged quick action in theface of a looming “energy crisis” fromfalling gas production and rising demand.“The government can help the countrymeet its energy challenges by increasingaccess to new LNG sources and permittingnew LNG receiving terminals in the com-munities that want them,” he wrote.

Federal Reserve Chairman AlanGreenspan said “our limited capacity toimport LNG effectively restricts our accessto the world’s abundant supplies of naturalgas,” and that “we need to get in place, assoon as we can, the capability of fairly sub-stantial imports that enable our manufac-turers who use natural gas to competeinternationally.”

In 2006, a FERC official reported to thecommission that the agency had approved14 projects — 11 new terminals and threeexpansions — that could supply NorthAmerican consumers with up to 25 bcf aday of imported LNG.

That wasn’t all. FERC had pendingapplications for 10 more new terminalsand two expansions, with nine other sitesin preliminary planning for terminals.Another federal agency that oversees off-shore LNG terminals was considering


THE

TEAMTHAT

DELIVERS

(907) 562-5303 | akfrontier.com


NA LNG looks to exporting to surviveIn a change from a decade ago, the North American liquefied natural gas industry is now gearing up to export billions of cubic feet

BILL WHITE

see LNG EXPORT page 11

U.S

. EI

A;

OFF

ICE

OF

FED

ERA

L C

OO

RD

INA

TOR

EST

IMA

TE

http://www.akfrontier.com/


www.miswaco.slb.com/deepclean

The DEEPCLEAN* pill combines solvents and surfactants to create the world’s first double emulsion cleanup pill.The unique application of water-in-oil-in-water technology improves film removal and droplet dispersion, and can deliver water-wet tubulars just six minutes after contact, with lower chemical concentrations than conventional displacements.Without the abilities of rotation or reciprocation, an Alaskan operator achieved a clean displacement from mineral oil-base mud (MOBM) to clear kill-weight brine using a one-drum DEEPCLEAN displacement pill with minimal interface and a high percentage of MOBM recovery. Maximize production efficiency and reduce total costs by avoiding NPT during completion, minimizing future interventions and protecting near wellbore reservoir permeability.

Introducing the world’s fastest water-wet wellbore cleanup.

*Mark of M-I L.L.C

eight proposals.LNG started pouring into the United

States. Imports more than tripled from2002 to 2007, when they reached morethan 2 bcf a day — averaging about a shipevery other day.

Import terminal construction continuedwith a rose-tinted view of the future. Itturned out the optimism was misguided.Unfortunately for investors, import termi-nals take years to build and the momentumwas too strong for some projects to stopwork even when it became clear the marketwas changing.

The last two terminals started up in2011: The Qatar Petroleum/Exxon GoldenPass project at Sabine Pass, Texas, (practi-cally next door to Cheniere’s terminal) andthe Kinder Morgan/GE Energy terminal atPascagoula, Miss. Neither of those termi-nals received any LNG in 2012. Both haveapplied to add export capability.

Some projects, however, do have cashflow, despite little or no gas movingthrough the plant. Customers havereserved import capacity whether or notthey use it. Those contracts allowed devel-opers to obtain construction money.

For example, Chevron and Total eachare obligated to pay Cheniere $125 milliona year to 2029 for rights to its Louisianaplant, according to Cheniere’s annualfinancial report.

But mostly Cheniere’s and the otherplants stand idle.

As it turned out, 2007 was the peak yearfor LNG imports — at roughly 4 percent ofU.S. supply.

In 2012, net LNG imports averagedabout 0.4 bcf a day, or less than 1 percentof supply. Half went to New England,where gas-pipeline constraints cause a big-

ger demand for LNG.

A future of exports?As was said, Cheniere hopes its first

LNG will depart its plant in 2015, withmore production trains (or units) to comeonline in 2016 and 2017.

Soon thereafter, sponsors of other pro-posed Louisiana plants as well as some tar-geted for Texas, Maryland and Oregonhope to start up.

First they’ll need regulatory approval.The Department of Energy, which

authorizes exports, expects to be busy thisyear processing applications now that itseconomic impact studies of exports aredrafted. The reports concluded exportswould cause U.S. consumers to pay some-what more for natural gas but that virtual-ly any amount of exports would boost thenation’s economy more than they wouldhurt.

FERC authorizes LNG plant construc-tion and operation. As of early January ithad formal environmental reviews underway for three proposed projects and pre-liminary environmental work begun on ahandful of others.

Authorizations take a project only sofar, however. Projects need customers sothey can convince the financial communi-ty to lend or invest the billions needed forconstruction.

Cheniere’s Louisiana project is the soleterminal to have customers locked in.

Some proposals have struck tentativedeals with possible buyers, for example aFreeport, Texas, project with two Japaneseutilities, and a Hackberry, La., project withmultinational Japanese and French tradingcompanies.

Separately, Japanese, Korean, Chineseand Malaysian companies have talked ofinvesting in West Coast Canada export pro-posals.

North American projects, including one

under consideration in Alaska, aren’t alonein believing there’s money to be made sup-plying the world with LNG.

Projects proposed in East Africa, Israeland Russia are getting at least preliminarylooks, adding to the seven export terminalsunder development in Australia.

As with the plethora of North Americanprojects, handicappers don’t believe all canproceed in the next decade.

Meanwhile, in the United States, adiverse set of groups oppose LNG exports.

Environmental groups say exports willencourage more shale-gas drilling, leadingto the potential for greater air and waterpollution. They oppose individual projectson specific grounds. For example, beforeFERC authorized Cheniere’s construction,two groups attacked from 360 degrees:They said tanker ballast water will harmaquatic life, construction will throw dustinto the air, wastewater will impair drink-ing-water quality, air emissions will wors-en atmospheric ozone formation, hurricanestorm surges will flood the site, and LNG-tanker traffic will tax Coast Guardresources.

Terminal neighbors worry about indus-trial activity worsening their quality of life.

Gas utilities warn that exporting domes-tic gas will raise U.S. prices and burdenconsumers.

The chemical industry cautions thathigher prices for its gas feedstock coulddampen their desire to expand U.S. opera-tions.

For the Cheniere project, FERC consid-ered all of the concerns before approvingthe project. The commission generally heldthat the environmentalist concerns were ill-founded or speculative. The commissiondid acknowledge that if a cluster of neigh-boring LNG projects all apply, they couldhave a collective environmental impactthat FERC needs to consider.

At least four other proposed export

projects lie in the same “air quality controlregion” as Cheniere’s plant, the commis-sion said. But none had applied to FERCfor a construction certificate when thecommission sanctioned the terminal.

“The project sponsors have not yet filedan application or started the pre-filingprocess at the commission, and construc-tion timelines and in-service dates areunknown,” FERC said in its Cheniereorder. “It is speculative to assume con-struction emissions would overlap. In addi-tion, each facility can vary by size and pro-posed power source for the liquefactionequipment, which can greatly vary theresulting operating emissions of criteriaand greenhouse gas pollutants.

“Thus, without additional informationregarding equipment sizes and fuelsources, we are unable to identify theseother facilities’ operating impact on airquality or climate change.”

For LNG export entrepreneurs, thestakes of their new direction are big —multibillion-dollar big.

A decade ago they looked out over thehorizon and saw a fantastic future ofinbound LNG tankers queued up to deliverliquid methane to needy North Americanconsumers. The fleet never set sail, andnothing but blue breakers came to shore.

The vision was a chimera, but it leftroom for a new vision, one of outboundtankers, laden with North American LNG,steaming to distant ports to help feed theworld’s growing appetite for natural gas. �

Editor’s note: This is a reprint from theOffice of the Federal Coordinator, AlaskaNatural Gas Transportation Projects,online at www.arcticgas.gov/north-ameri-can-lng-industry-looks-survival-through-exports.

Note: Part 1 of this story appeared inthe Feb. 3 issue of Petroleum News.


LNG EXPORT

U.S

. O

FFIC

E O

F FO

SSIL

EN

ERG

Y

BP

STA

TIST

ICA

L R

EVIE

W O

F W

OR

LD E

NER

GY

http://www.miswaco.slb.com/deepclean


Energy is good. So begins a new reportfrom U.S. Sen. Lisa Murkowski titled

“Energy 20/20: A Vision for America’sEnergy Future.”

Murkowski, an Alaska Republican,released the 123-pagereport on Feb. 4 inWashington.

She said the docu-ment is not the mak-ings of a comprehen-sive energy bill.Rather, it is “meant tobegin a conversation”for the new 113thCongress.

Murkowski is the top-rankingRepublican on the Democrat-controlledSenate Committee on Energy and NaturalResources. The chairman is Sen. RonWyden, D-Ore.

Murkowski’s “Energy 20/20” is a sweep-ing and largely familiar wish list of projectsand policies for Alaska and the nation. Thedocument includes sections on conservation,clean energy technology, environmentalresponsibility and “effective government.”

During a press conference on the report,the senator said developing new technolo-gies is key for reducing harmful greenhousegases. But she said policies that inflate ener-gy costs won’t fly at home, where ruralAlaskans already face crushing prices forfuel.

The first and largest section of the reportis called “Producing More,” and covers oiland gas, coal, unconventional fossil fuelssuch as shale oil and methane hydrates,renewables such as hydro and solar, andnuclear power.

“The United States should establish anational goal to produce enough additionaloil, biofuels, and synthetic fuels to becomeindependent of OPEC imports by 2020,” thereport says.

It notes that domestic crude oil produc-tion is running higher now than at any pointsince 1997.

“Claims that very recent federal policieshave had a significant role in the increase indomestic oil production are ... deeply mis-leading,” the report says. “About 96 percentof the increase in domestic oil production isattributable to growth on state and privateland.”

Alaska has a great deal of federal land,and an expansive outer continental shelf.

To reach energy independence fromOPEC, access to federal resources must beincreased, Murkowski said. And more col-laboration with Canada and Mexico is need-ed.

Among the steps she supports:•Streamline and simplify the federal per-

mitting process to ensure that offshore leas-es are developed in the Gulf of Mexico andelsewhere.

•Open the coastal plain of the ArcticNational Wildlife Refuge to oil industryexploration and production. This shouldinclude “timely lease sales” and a 50-50split of revenue between the federal govern-ment and the state.

•The National PetroleumReserve Alaska “must be immediatelyplaced into full availability for oil and natu-ral gas leasing, consistent with its statutorydesignation. The reserve must be thought-fully developed with roads, bridges, andpipeline facilities to promote broad onshoredevelopment of the diffuse resource base,while simultaneously accommodating thetransportation of oil and natural gas fromoffshore fields in the Chukchi Sea to theTrans Alaska Pipeline System. ‘Roadless’options for the NPR A should be expresslywithdrawn from consideration.”

Murkowski makes many other points inher report.

She disagrees with using the StrategicPetroleum Reserve, a stockpile of crude inGulf Coast caverns, as a tool for temporari-ly relieving high retail gasoline prices. Theoil should be held for true emergencies.

“Oil scarcity is a myth,” the report says,noting the United States has not only bil-lions of barrels of proved reserves, but vastquantities of shale oil and crude classified as“technically recoverable” or “undiscovered.”

The report also says...Better energy storage technologies are

key to the future of solar and wind.Nuclear energy “must remain a viable

contributor to America’s power supply.”Tax increases on fossil fuel producers

“are ill advised, as higher taxes on a goodor service will result in less of it — notmore.”

U.S. alternative fuels policies “havecome to rely on burdensome mandates,inappropriate restrictions, and erratic subsi-dization.” Yet alternative fuels hold greatpromise.

“From algal biofuels to natural gas andcoal derived products, as well as combina-tions of these and other feedstocks, thepotential options for diversification of ourtransportation sector’s energy supply haveperhaps never been greater.”

The “Energy 20/20” report is postedonline at bit.ly/Energy2020Doc. �


ON DEMANDFORKLIFT RENTALS

CALL 338-LIFT

3000 - 36000 AVAILABLE •907-338-5438

� G O V E R N M E N T

Sen. Murkowski rollsout energy ‘vision’Describes her wide-ranging report as a conversation starter,calls for opening ANWR and improving NPR-A access

SEN. LISA MURKOWSKI

EXPLORATION & PRODUCTIONJanuary ANS production down almost 1%

Alaska North Slope crude oil production averaged 576,959 barrels per day inJanuary, down 0.9 percent from a December average of 582,149 bpd.

Cook Inlet, with its much smaller volumes, saw a 7.4 percent increase in Decemberover November, averaging 12,072 bpd compared to 11,243 bpd in November.

Except where noted, North Slope volumes are from the Alaska Department ofRevenue’s Tax Division, which reports oil production consolidated by major produc-tion centers and provides daily production and monthly averages for the most recentmonth.

Cook Inlet volumes, and those for individual North Slope fields, are from theAlaska Oil and Gas Conservation Commission, which reports production by pool andfield on a month-delay basis.

Cook InletThe 7.4 percent December-over-November production increase from Cook Inlet

was driven by Hilcorp Alaska’s Swanson River field, which averaged 2,028 bpd inDecember, up 158 percent from a November average of 786 bpd.

John Barnes, Hilcorp Alaska senior vice president, said in a December talk atCommonwealth North that there were a lot of wells that needed to be fixed at SwansonRiver when Hilcorp took it over (in January 2012). He said Hilcorp has been operat-ing a drilling rig and using a pulling unit for well remediation at the field, as well asbringing in a workover rig (see story in Dec. 16 issue of Petroleum News.) Barnes saidSwanson River was producing 300 bpd when Hilcorp took it over, but Dec. 7, the dayof his talk, the field was producing 2,200 bpd, with one recently completed well pro-ducing at more than 1,000 bpd.

With the increase at Swanson River, there are now four Cook Inlet fields produc-ing more than a thousand barrels a day: the Hilcorp-operated Granite Point field,which averaged 2,130 bpd in December, down 0.5 percent from November; theHilcorp-operated McArthur River field, which averaged 3,947 bpd in December,down 8.9 percent from November; and Middle Ground Shoal, operated by

see ANS PRODUCTION page 14

SHA

NE

LASL

EY

http://www.gci-industrialtelecom.com/


Cook Inlet Energy LLC has cured itsproblem of securing affordable natu-

ral gas to fuel oil field operations.The Anchorage-based company says it

ran a successful test Jan. 26 on a recentlyrecompleted gas well in its offshoreRedoubt unit, then immediately put thewell into production.

The RU-4A well, on the company’sOsprey platform, tested at a peak flow rateof 1.7 million cubic feet of gas per day, aJan. 30 press release said. The well taps theLower Tyonek gas sands at a measureddepth of about 9,200 feet.

“Based on log analysis and well testresults, the average net pay is 11 feet withan aerial extent of 130 acres,” the pressrelease said. “Initial estimates of recover-able reserves by the company’s geologistsare in excess of 1 billion cubic feet of gas.”

‘Critical’ needThe new production from the RU-4A

well allowed Cook Inlet Energy to suspendpurchases of gas supplies from third par-ties on Jan. 28.

The company had made establishing itsown fuel gas supply a high priority due toa tight area gas market.

“We could clearly see that a secure sup-ply of fuel gas was critical to keep operat-ing costs down and to provide for securityof supply,” said David Hall, Cook InletEnergy chief executive. “Therefore, we’veconcentrated on developing fuel gas sup-plies before executing our oil developmentprogram.”

The company is working to restore pro-duction from shut-in and damaged oilwells on the Osprey platform, which thecompany and Miller acquired out of abankruptcy sale in late 2009.

The Osprey platform is the newest andsouthernmost of the platforms in CookInlet.

Aside from the Redoubt unit, CookInlet Energy operates an assortment ofother properties on the inlet’s west side,including the West McArthur River oilfield.

Cook Inlet Energy is a subsidiary ofTennessee-based, publicly traded MillerEnergy Resources Inc.

Mounting costsThe Jan. 30 press release from Miller

said: “In the last three months CIE’s natu-ral gas expenses have been approximately$450,000 per month. Declining gas sup-

plies in the region have caused prices toincrease significantly and have made it dif-ficult to obtain contracts for the purchaseof natural gas. The Cook Inlet lacks a spotmarket for natural gas, and all gas must bepurchased under a contract. CIE’s fuel gasacquisition costs reached $15 per thousandcubic feet this winter and were projected toincrease over the winter months.”

Aside from its Cook Inlet production,Miller Energy also has production inTennessee.

The company, listed on the New YorkStock Exchange, on Feb. 1 announced ithad retained MZ Group as its investor rela-tions adviser.

MZ Group will help tout what Miller’schief executive, Scott M. Boruff, called “atremendous base of both producing andundeveloped assets in Alaska andTennessee.” �


Alaska’s North Slope is about as remote as it gets. But to Alaska Air

Cargo, it might as well be just around the corner. With 20 destinations

in Alaska, two flights daily to Prudhoe Bay and single-carrier service

to Houston, we keep the oil and gas industry close and connected.

Oil and gas deliveries begin at alaskacargo.com.

TM

THE #1 ON - T IME A IRL INE IN NORTH AMER ICA * I May has been a valued cargo team member since 1975.

Your team at the top of the world.

*201

0–2

012

FLI

GH

TSTA

TS.C

OM


Canada lags behind resource boomBy GARY PARK

For Petroleum News

Canada’s pace of natural resource development hasbeen outstripping measures to protect the environ-

ment, the government’s Environment and SustainableDevelopment Commissioner Scott Vaughan said Feb. 5.

In a series of audits that wraps up his five-year appoint-ment, he was critical of the government’s efforts to safe-guard ecosystems from oil spills, the use of toxic chemi-cals and the rapid increase in hydraulic fracturing.

Vaughan said that “given the central role of naturalresources in the Canadian economy, it is critical that envi-ronmental protection keeps pace with economic develop-ment. I am concerned by the gaps we found in the wayfederal programs related to natural resources are man-aged.”

The findings coincide with a host of major develop-

ments, including expansion of Alberta oil sands produc-tion, greater use of hydraulic fracturing in shale oil andgas deposits and pipelines to support the export of bitu-men and LNG to Asia.

Audit sees imbalanceHe identified an imbalance between government finan-

cial incentives for the petroleum industry and what it isdoing to protect the environment, noting that although thelevel of federal subsidies is declining, the Canadian gov-ernment over the past four years has made more thanC$500 million in direct grants for research and develop-ment and given C$1.47 billion in tax breaks, mainlyinvolving accelerated write offs for oil sands producers.

But the government has failed to establish more pro-tected marine areas even as offshore resource develop-ment proceeds, he said.

The audit also said the federal-provincial offshore

petroleum boards in Newfoundland and Nova Scotia lackcoordination in monitoring oil and gas activities and are“not systematically tracking measures to prevent or reduceenvironmental impacts.”

Vaughan also urged the government to develop a betterunderstanding of the risks associated with hydraulic frac-turing given that the 200,000 fracking wells in Canada areexpected to double in the next 20 years.

The audits were issued a week after EnvironmentMinister Peter Kent said the government is on the verge ofintroducing “significant” changes to liabilities for off-shore spills, which are currently C$40 million for theBeaufort Sea and C$30 million for the Atlantic Coast.

Government sources have said the liability cap couldbe raised to “billions of dollars” and that the industrywould have to either buy insurance or self-insure. �


Cook Inlet Energy gains gas securityAnchorage company reworks gas well on its Osprey platform to provide a cost-effective source of fuel for its oil field operations

“In the last three months CIE’snatural gas expenses have been

approximately $450,000 permonth.” —Miller Energy Resources

http://www.alaskacargo.com/


Where you want to be in Fairbanks…for a day, a week, or a month.

Sophie Station SuitesYour First Choice! And Best Choice!

FountainheadHotels.com Locally Owned in Fairbanks Reservations 800.528.4916

Business Meetings catered by Zach’s Restaurant

OHMY!

ExxonMobil subsidiary XTO, whichaveraged 2,197 bpd in December, up 5.4percent from November.

North SlopeThe BP Exploration (Alaska)-operat-

ed Prudhoe Bay field averaged 337,827bpd in January, down 0.7 percent from aDecember average of 340,253 bpd.Prudhoe Bay includes satellite produc-tion from Aurora, Borealis, MidnightSun, Orion and Polaris, as well as fieldproduction from Northstar and MilnePoint.

The ConocoPhillips Alaska-operatedKuparuk River field averaged 131,197bpd in January, down 1 percent from aDecember average of 132,526 bpd.Kuparuk includes satellite productionfrom Tarn, Meltwater and West Sak, aswell as field production from the Eni-operated Nikaitchuq field and thePioneer Natural Resources Alaska-oper-ated Oooguruk field.

AOGCC December data forNikaitchuq shows 9,844 bpd, up 1.9 per-

cent from November, and 6,270 bpd fromOooguruk, down 3.1 percent fromNovember.

The BP-operated Endicott field aver-aged 10,923 bpd in January, up 0.8 per-cent from a December average of 10,837bpd. Endicott volumes include the SavantAlaska-operated Badami field. AOGCCdata shows Badami averaged 1,315 bpdin December, down 1.4 percent fromNovember.

The BP-operated Lisburne field,which includes Niakuk and PointMcIntyre production, averaged 30,499bpd in January, up 5.4 percent from aDecember average of 28,949 bpd.

The ConocoPhillips-operated Alpinefield averaged 66,513 bpd in January,down 4.4 percent from a December aver-age of 69,584 bpd. Alpine includes satel-lite production from Fiord, Nanuq andQannik.

ANS crude oil production peaked in1988 at 2.1 million bpd; Cook Inlet crudeoil production peaked in 1970 at morethan 227,000 bpd.

—KRISTEN NELSON


ANS PRODUCTION

• Field Heat Trea�ng• NDE/NDT and Inspec�ons • Leak Repair • Hot Tap • Line Freeze • Field Machining • Technical Bol�ng • Valve Repair • Emissions Control • Valve Inser�on • Engineering and Manufacturing • Turnkey Tank Program • Isola�on Test Plugs • Line Stop • Fitness for Service

Combining the exper�se,

innova�on and technology

that keep your facili�es online and in produc�on.

42730 Kenai Spur Hwy.

Kenai, Alaska

Team’s Alaska loca�on specializes in NDT Services and Field Heat Trea�ng

907-335-1446 Statewide: 907-252-6703

GOVERNMENTObama nominates Jewell as interior secretary

President Obama has nominated Sally Jewell, CEO of outdoor recreational equip-ment firm REI, as secretary of the Interior, to replace Ken Salazar, who announced inJanuary that he would leave his position as Interior secretary after serving in theObama administration for four years.

As Interior secretary Jewell will inherita raft of difficult issues relating to govern-ment oil and gas development policies forfederal lands in Alaska, including theNational Petroleum Reserve-Alaska, theArctic National Wildlife Refuge and thefederal outer continental shelf.

According to a statement from theWhite House Jewell has previously“worked in oil fields in Oklahoma andColorado” and as an energy expert inbanking.

And in announcing the nomination onFeb. 6, Obama said that Jewell is an expert on energy and climate issues.

“She is committed to building our nation-to-nation relationship with IndianCountry,” Obama said. “She knows the link between conservation and good jobs. Sheknows that there’s no contradiction between being good stewards of the land and oureconomic progress; that in fact, those two things need to go hand in hand. She hasshown that a company with more than $1 billion in sales can do the right thing for ourplanet.”

With Congress yet to approve the Jewell nomination, Alaska’s U.S. senatorsexpressed interest in learning more about the president’s nominee.

“So many of the decisions made by the Interior secretary have a profound impacton Alaska, and other western states,” said Sen. Lisa Murkowski. “I look forward tohearing about the qualifications Ms. Jewell has that make her a suitable candidate torun such an important agency, and how she plans to restore balance to the InteriorDepartment.”

“While I am pleased the president moved quickly to fill this critical post, I thinkthere is more we need to learn about Sally Jewell and what this decision means forAlaska,” said Sen. Mark Begich. “The Department of Interior has enormous influenceover Alaska’s land, resources and its relationship with our state’s First Peoples.”

—ALAN BAILEY

As Interior secretary Jewell willinherit a raft of difficult issuesrelating to government oil andgas development policies for

federal lands in Alaska,including the National

Petroleum Reserve-Alaska, theArctic National Wildlife Refuge

and the federal outercontinental shelf.

http://www.nac.aero

http://www.FountainheadHotels.com/


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

Going public with a ‘critical issue’ By GARY PARK

For Petroleum News

Enbridge and Kinder Morgan are emerging fromyears in the shadows to make a public case for their

plans to ship bitumen from the Alberta oil sands to Asia.For Enbridge, the Northern Gateway project is Plan A

and, for that matter, Plan B, the company’s ChiefExecutive Officer Al Monaco told a meeting of businessand government leaders in Edmonton, emphasizing thathis company has no alternative proposal.

He said the project, which includes shipping 525,000barrels per day to Asia and U.S. West Coast refineries,has become a national priority if Canada is to overcomethe current slump in prices for its crude.

“There is no more critical issue facing Canada today,”Monaco said.

“Failure to develop a consensus around energy devel-opment will have serious consequences for this genera-tion and generations to come,” he said, estimating theprice gap between U.S. and Canadian crudes is costinggovernments and companies about C$75 million a day.

‘Sense of urgency’On the same day Monaco was delivering his message,

Kinder Morgan’s Canadian President Ian Anderson wastelling analysts in Houston that “there is a significantsense of urgency throughout Canada to access and tapinto (the Asian) market” at a time when producers inRussia, Saudi Arabia, North Africa and Venezuela are allcompeting for a share of the Chinese market.

Kinder Morgan’s hopes are pinned on expanding itsTrans Mountain pipeline to 890,000 bpd by 2017 fromthe current 300,000 bpd, taking advantage of bindingcommitments from 13 companies to cover 708,000 bpdof those volumes.

The long-term contracts have prompted KinderMorgan to build an additional 1.2 million barrels of stor-age at Trans Mountain’s Edmonton terminal boostingcapacity there to 9.4 million barrels.

The $5.9 billion Trans Mountain expansion is prima-rily targeted at increasing tanker traffic from theWestridge dock in Port Metro Vancouver to 30-34tankers per month from the current five to six vessels,

the likely trigger for heated community opposition.Some of the additional volumes would also be destinedfor refineries in Washington state’s Puget Sound.

Monaco said that with “so much at stake, this is notime to be standing on the sidelines,” conceding thatEnbridge and Trans Canada had failed to appreciate thattheir Northern Gateway and Keystone XL projects hadsuch potential to be lightning rods for “conflict andprotest.”

He admitted Enbridge should have been better pre-pared by reaching out earlier to affected communitiesand doing a “lot more ground work in terms of buildingtrust.”

Monaco said opponents of the pipelines have figuredout that by stopping pipelines they also achieve theirobjective of stopping energy development.

He said industry’s answer is to “build effective coali-tions” by drawing on governments, service providers,labor unions and people “within communities that weoperate in.” �

was repeated over and over was you’vegot the most complex tax regime in theworld and it’s frankly off-putting to com-panies who are looking at it and say I’mnot sure we understand this, how can weinvest here? So simplification is impor-tant. I sure would like this to be a bill, atax regime, that’s durable. It adapts to thedifferent kinds of hydrocarbons we haveon the slope. So we don’t have to becoming back and tweaking it all thetime. It is going to accommodate heavyoil, shale, viscous. This bill has somevery creative elements in it that will dothat.

Petroleum News: Are there any ele-ments that you see that need tweaking?

Giessel: Well we have a loss carryforward for the companies, and thatgains value as they hold onto it, and itgains value at 15 percent a year. As Ilook at that I understand Australia actu-ally offers 20 percent. But how is 15 per-cent arrived at? Is it too high? You knowinflation rate is 3 percent. That’s a pieceI’d like to look at and perhaps modify,but I don’t know enough about that yet.That will be a discussion, a question I’llask in committee. Our committee isgoing to focus on the resource issues,that is, what it takes to get our hydrocar-bons out of the ground and into the

pipeline and revenue for the state. Thereally deep dive on the fiscal elementswill be left to Finance, but some of thesewe’ll be looking at in Resources simplybecause you can’t separate fiscals fromthe oil and gas itself.

Petroleum News: What about the criti-cisms that this is simply going to getpushed through?

Giessel: Well on the Senate sidewe’ve got three committees looking at it.In my committee we have scheduled longmeetings going into the evening to hearthis bill thoroughly and allow multipleopportunities for public input. I plan tohear it thoroughly. At the same time,because it’s already been seen in TAPSThroughput and I’ve got some of thesame members in Resources, we are notgoing to spend months looking at it, butit will be a thorough hearing.

Petroleum News: On to natural gas,what are your thoughts on the generalstatus of the state advancing a pipelineproject?

Giessel: I really like what the AlaskaStand Alone Pipeline has been doing,that’s being headed up by AGDC (AlaskaGasline Development Corp.). They havelooked at the fiscals and altered them.Now they are going to be transportingdry gas. It lowers the tariff. It lowers thecost to communities, but also because it’sdry gas, it will allow multiple take off

points. So I really appreciate the workthey have been doing, not just lockinginto that initial plan, but being nimbleand critical of their own plan and revis-ing it to the best possible project.

So I really like what they are doing.At the same time, I really appreciatewhat the governor is doing by kind ofpushing the three producers andTransCanada to tell us exactly whatthey’re planning to do. Give us some ofthe precise elements. He keeps pushingthem on that, so it’s a good thing.

Petroleum News: What are yourthoughts on the prospects on an LNGexport market and following that, do youthink Alaska should be lumped in withthe Lower 48 on LNG export debate?

Giessel: First of all, Alaska should bethe exception on any restrictions forexport. We are not like the Lower 48states. We are an island economy. Wehave to be able to export our resources. Iactually have met some of the gentlemenfrom Japan who are interested in our nat-ural gas. South Korea is interested in ournatural gas. I’ve heard it said that Chinais interested. Bravo. I believe the marketis out there. But we also have a potentialin-state for industrial users. DonlinCreek has also surveyed in the potentialfor a natural gas pipeline to tidewater topower that mine.

My understanding is the communitiesaround that mine are saying we don’t

want you barging in fuel oil. It’s toomuch traffic on our rivers. Find a way toget natural gas so that’s what they’vedone. International Tower Hill inLivengood, another massive gold deposit,these mine projects are very energyintensive. There’s another potentialindustrial user.

These are just a couple that come tomind right off the bat, so I believe we’vegot the industrial users in the state.We’ve got the Agrium plant in Nikiskithat could potentially be restarted. We’vegot refineries that can’t get natural gasnow because we don’t have enough. Ibelieve the markets are there.

I’m excited about our future, but thenhaving been born here before statehood,I’ve seen what our oil and gas potentialhas done for our state. I tell people Iused to think asparagus and spinach weresupposed to be kind of gray and mushybecause that’s how it came out of thecan. We didn’t have Fred Meyer andCarrs and fresh vegetables and fruit.We’ve changed a lot and it’s because ofour resource development, so I’m veryoptimistic about our future, but itrequires us to make those courageousdecisions now. We can’t keep waitingand studying and hoping that somethingis going to come over the horizon. We’vegot to seize the day. �


GIESSEL

http://www.ArcticFoundations.com/

ASRC’S Ty Hardt sets sights on top of the worldArctic Slope Regional Corp. said Jan.

14 that in late March, its director ofcommunications, Ty Hardt, will head toKathmandu and attempt a climb ofMount Everest, the tallest mountain onEarth at an elevation of 29,035 feet.Identifying a need for the children of theNorth Slope, Hardt is using the climb toraise money for the Boys & Girls Club ofBarrow, as well as other clubs statewide.

“I’ve been fortunate to be able toclimb other big mountains around theworld, but Himalayan expeditions pres-ent another level of difficulty, both in theamount of training and logistics,” saidHardt. “I’m working hard to make sureI’m up to the challenge of MountEverest, and am very excited to get this

under way.”The Boys & Girls Club of Barrow is located inside Ipalook Elementary School and has

more than 130 members, out of the more than 800 kids from Ipalook and Eben HopsonMiddle School. ”Our mission has always been to help enable our young people, and thisunique fundraising effort will help us to extend our reach,” said Alana Humphrey, CEO ofBoys & Girls Clubs Alaska. “We will be following Ty on every step of his Mt. Everest expe-dition, and wish him the very best.”

The expedition and fundraising effort is being called Going to Extremes. You can findmore information regarding the climb at: www.g2extremes.com.

Carlile opens employee health clinic in AnchorageCarlile Transportation Systems said Jan. 16 that it is very excited to announce the open-

ing of its very own employee health clinic. The Carlile Employee Clinic is located on theAlaska Regional Campus at 2751 DeBarr Road and is managed by H2U.

The clinic partnership with Alaska Regional is designed to make it easier for employeesto get well, stay healthy and is dedicated to serving Carlile employees and their familieswho participate in the company health plan. Employees will receive personalized atten-


ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS

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

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

AAcuren USA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20AECOM Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Aggreko LLCAir LiquideAircaft Rubber Mfg. (ARM-USA)AIRVAC Environmental GroupAlaska Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Alaska Analytical LaboratoryAlaska DreamsAlaska Frontier Constructors . . . . . . . . . . . . . . . . . . . . . . . .10Alaska Interstate Construction (AIC)Alaska Marine Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Alaska Rubber Alaska Ship & DrydockAlaska Steel Co.Alaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7All Pro Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12Alpha Seismic Compressors . . . . . . . . . . . . . . . . . . . . . . . . . .5American MarineArctic ControlsArctic Foundations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15Arctic Fox EnvironmentalArctic Slope Telephone Assoc. Co-op.Arctic Wire Rope & SupplyARCTOS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8ArmstrongAspen Hotels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17ASRC Energy ServicesAT&TAvalon Development

B-FBaker HughesBald Mountain Air ServiceBombay DeluxeCalista Corp.Canadian Mat Systems (Alaska) . . . . . . . . . . . . . . . . . . . . .19Canrig Drilling TechnologyCarlile Transportation ServicesCGGVeritas U.S. LandCH2M HillCharter CollegeClearSpan Fabric StructuresColville Inc.Computing AlternativesCONAM ConstructionConocoPhillips AlaskaConstruction Machinery IndustrialCook Inlet EnergyCraig Taylor EquipmentCrowley SolutionsCruz Construction

Denali IndustrialDonaldson CompanyDowland-Bach Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Doyon DrillingDoyon LTD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19Doyon Universal ServicesEgli Air HaulEmerald AlaskaEra AlaskaERA HelicoptersEverts Air CargoExpro Americas LLCExxonMobilFairweatherFlowline AlaskaFluorFugro

G-MGBR EquipmentGCI Industrial Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Global Diving & SalvageGMW Fire ProtectionGolder AssociatesGreer Tank & WeldingGuess & Rudd, PCHawk ConsultantsHDR AlaskaInspirationsIntertek MoodyJackovich Industrial & Construction SupplyJudy Patrick PhotographyKenworth AlaskaKuukpik Arctic ServicesLarson Electronics LLCLast Frontier Air Ventures . . . . . . . . . . . . . . . . . . . . . . . . . . .6Lister IndustriesLittle Red Services, Inc. (LRS)Lounsbury & AssociatesLW Survey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7MagTec Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Mapmakers of AlaskaMAPPA TestlabMaritime Helicopters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3M-I Swaco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11MRO SalesM.T. Housing

N-PNabors Alaska DrillingNalcoNANA WorleyParsonsNASCO Industries Inc.Nature Conservancy, TheNC MachineryNEI Fluid TechnologyNordic CalistaNorth Slope Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Northern Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Northwest Technical ServicesOil & Gas SupplyOpti Staffing GroupPacWest Drilling SupplyPENCOPebble PartnershipPetroleum Equipment & ServicesPND Engineers Inc.Polyguard Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6PRA (Petrotechnical Resources of Alaska) . . . . . . . . . . . . . .2Price Gregory International

Q-ZRedi ElectricSAExplorationSalt + Light CreativeSeekins FordShell Exploration & ProductionSophie Station Suites . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Sourdough Express Inc.STEELFABStoel RivesTaiga VenturesTanks-A-LotTEAM Industrial Services . . . . . . . . . . . . . . . . . . . . . . . . . . .14The Local PagesTire Distribution Systems (TDS)Total Safety U.S. Inc.TOTE-Totem Ocean Trailer ExpressTotem Equipment & SupplyTTT EnvironmentalUdelhoven Oilfield Systems ServicesUMIAQUnique MachineUnivar USA URS AlaskaUsibelliWeston SolutionsXTO Energy

see OIL PATCH BITS page 17

Oil Patch Bits

CO

URT

ESY

ASR

C

PFC Energy is back for the second year,hired to advise the Alaska Legislature in oiltax change discussions.

Mayer also noted that production andprice are related, as more projects will beeconomic — increasing production — in aperiod of sustained high oil prices, and con-versely, in a period of sustained low pricesfewer projects will be economic, decreasingproduction.

Current production decline is some 6percent a year and to hold revenue flat thatdecline rate under the SB 21 proposal wouldneed to drop to 1 percent, he said.

Because it removes progressivity, thegovernor’s proposal in SB 21 is slightlyregressive — the state’s share of revenuedrops somewhat as oil prices rise.

Mayer said PFC Energy was asked tolook at what it would take to remove thatregressivity. By adding back 0.1 percentprogressivity, to a maximum 35 percent pro-duction tax, the state’s take would remainflat with rising prices. That 0.1 percent pro-gressivity would also reduce the productiondecline level required to keep revenues con-stant from 1 percent to 2 percent.

The tinkering issueThe focus of PFC’s presentation was on

how competitive Alaska is under the currentfiscal system, compared to how competitiveit could be under the changes proposed bythe governor.

There is, however, another issue: Alaska,like Alberta, is perceived in the oil and gasindustry as a jurisdiction that tinkers with itstax system and tries to micro manage.

That, PFC Energy told the committee,makes investment decisions difficult forcompanies.

Mayer said Alberta is characterized ashaving high sovereign risk because it fre-quently changes its oil and gas fiscal terms.The province also is seen as pulling levers inthe system to attempt to manage at themicro level.

Both of those characterizations absolute-ly apply to Alaska, especially over the lastseveral years, Mayer said.

In addition to instability due to fiscalsystem changes, the state has tended to takean approach based on pulling specificlevers, he said, citing the tax credit providedfor the first jack-up in Cook Inlet as anexample of pulling micro levers in the fiscalsystem.

Changing project economicsCompanies want stability when making

large capital investments with long payoutperiods, Mayer said. He said he could thinkof no better example of lack of fiscal stabil-ity in Alaska than Pioneer NaturalResources’ experience with its North SlopeOooguruk field.

The discovery and investment decisionwere made under ELF, Mayer said. That isthe state’s former gross production tax,including an economic limit factor, hencethe acronym ELF.

Oooguruk was challenged under ELF,Mayer said. (Pioneer applied for andreceived royalty relief for some of the leas-es in the project in 2005.) AlthoughOooguruk was a high-cost challenged proj-ect with a lot of issues, Pioneer sanctionedthe project, he said.

That was in early 2006. In the fall of 2006, during project devel-

opment, the state passed PPT, the PetroleumProfits Tax, and by the time the field cameinto production in mid-2008, ACES orAlaska’s Clear and Equitable Share hadbeen enacted.

The project economics were much,much more challenging under ACES thanthey were under ELF when the project wasstarted, Mayer said.

Lots of potentialReinsch told committee members that

industry sees a lot of potential in Alaska, butit is a very difficult operating environmentand entry is difficult because there isn’t a lotof what he called “asset churn” with com-panies selling producing properties.

Offshore prospects are going to be verychallenged, Reinsch said, citing Shell’s dif-ficulties as an example. There is the ques-tion, he said, whether the technology is thereto exploit the resource.

So while the state has many opportuni-ties, Reinsch said he had yet to meet the oiland gas team that prefers chaos to stabilitywhen they are making multiyear investmentdecisions.

Minimizing tinkeringCommittee Co-Chair Mike Dunleavy

asked if there were areas with minimum tin-kering where companies are active.

Mayer said there were many examples,and cited two: the U.S. federal system andAustralia.

There have been changes, he said, butboth are systems with simple straightfor-ward rules leaving private sector companies

to compete within the system. The Australia federal system is profit

based, but the level of government take isthe same at any price range, isn’t differentfor different types of projects and makessure taxes are at a level to make the overallsystem competitive.

The U.S. federal offshore system is veryregressive, with a fixed royalty, Mayer said,but is all about shedding risk from the gov-ernment. Whereas typically signing bonus-es, what a company pays for its leases, areso relatively small that PFC Energy doesn’teven model them, in the federal offshorethose bonuses are very substantial, he said,substantial enough to impact project eco-nomics.

The federal offshore system takes riskfrom the public sector and puts it on the pri-vate sector, but at high oil prices the privatesector can make very high returns.

Characteristics of both systems includelong-term stability and an avoidance ofmicro managing, he said.

Co-Chair Peter Micciche wanted toknow why economics are better in Texasthan in Alaska, and Mayer said it’s a combi-nation of a substantially lower cost ofdrilling in Texas and a substantially lowergovernment take which produce better eco-nomics in Texas. Alaska, he said, has theburden of increasingly high costs.

The major playersIn a review of the portfolios of Alaska’s

major players — BP, ConocoPhillips andExxonMobil — Reinsch said all have faced

major strategic challenges in the last fewyears: BP following the Macondo well dis-aster in the Gulf of Mexico; ConocoPhillipsfollowing its 2010 commitment to restruc-turing, a significant divestiture of assets andsplitting the company; and ExxonMobilbecause of the challenge of replacing largeinternational projects and its acquisition ofXTO, which he described as almost the lastplay standing of material impact forExxonMobil. XTO’s play type, however,isn’t one that makes sense for ExxonMobil,he said. They’re efficiency experts, Reinschsaid, and are now into the treadmill game ofdrilling thousands of wells.

PFC Energy categorizes Alaska as a har-vest area for both BP and ExxonMobil, butas a core area for ConocoPhillips.

Sen. Berta Gardner, the committee’s soleDemocrat, asked if harvest mode didn’tmean that companies would simply take anymonies from tax reductions and invest themelsewhere, to which Reinsch respondedthat, all things being equal, a better fiscalenvironment was positive for investment inan area.

Initial company reactionsThe governor’s proposal removes pro-

gressivity but also removes the 20 percentcapital credit which was placed in ACES asa balance for progressivity.

In industry reactions on Feb. 5 — fromthe Alaska Oil and Gas Association, AOGA,and ConocoPhillips Alaska, the North


CommercialOil Field Experienced

Machining

Fabrication

Field Services

Structural

Welding

Piping

Crane / Truck Boom Repair

Cast Iron

Explosion Proof Boxes

Aluminum

Steel / Stainless

Axle Repair

Hand Rail

Boiler Piping - Main & Headers

FOR SALETURN KEY OPPORTUNITY

Only $1,375,000.00Includes 43, 500 sq. ft. land,

4,516 sq. ft. buildingEquipment valued over $500,000.00

Call Kevin Elfrink at Globe Real Estate LLC907-727-2150 (24/7)

Set-up your private showing


TAX DISCUSSIONS

see TAX DISCUSSIONS page 19

tion, quality care; spend less time in waiting rooms and save money with free officevisits.

Board certified nurse practitioners will care for employees with common illnessessuch as allergies, ear infections, strep throat, minor infections and rashes. Additionalservices include blood pressure checks, flu diagnoses, x-rays, lab work and the adminis-tration of various vaccines. As an added convenience, employees can have prescrip-tions written by the nurse practitioner filled right at the clinic.

In addition to having an easy-to-access location, the clinic’s hours were chosenwith the employees’ needs in mind. The clinic’s operating hours are Monday throughFriday with extended hours on Thursday. “We welcome Carlile Transportation Systemsemployees and dependents to our campus, and look forward to sharing the conven-ience of our clinic services with them,” said Annie Holt, CEO Alaska Regional Hospital.

Editor’s note: All of these news items — some in expanded form — will appearin the next Arctic Oil & Gas Directory, a full color magazine that serves as a market-ing tool for Petroleum News’ contracted advertisers. The next edition will bereleased in March.


OIL PATCH BITS

accommodating deep-draft vessels. Atpresent, no such harbor exists.

The 77-page report doesn’t includecost estimates. It recommends publicagencies and banks or other private enti-ties collaborate on funding and construc-tion.

Vast area studied“The Arctic is changing,” says the

report forward. “Diminishing sea ice andexpanded natural resource extraction arehappening now. From drilling in theChukchi Sea, dredging for gold in Nome,to ore and gas concentrate tankers comingover the top from Europe, Alaska is expe-riencing more and more traffic past itsshores. Alaska’s western and northerncoastline is mostly shallow with very lit-tle marine infrastructure. Coast Guardand other support vessels may be manydays of ship travel away. Proper planningand responsible development is importantto Alaska’s future.”

The study considered marine infra-structure needs over a vast area, from theSouthwest Alaska village of Bethel westand north then east to the Canadian bor-der. That’s more than 3,000 miles ofcoastline, or one and a half times thelength of the eastern U.S. coast fromCanada to the tip of Florida.

Aside from the recommendations to“invest strategically” in an “Arctic portssystem,” including “deep-draft solutions,”and to focus feasibility work on Nomeand Port Clarence, the report makes sev-eral other suggestions:

*Make the Army Corps the lead feder-al agency for permitting, design and con-struction of the deep-draft port system.

*Use public-private partnerships,known as P3s.

*Increase funding to the NationalOceanic and Atmospheric Administrationand other agencies for hydrographic andbathymetric mapping to support marineinfrastructure development.

*Explore and develop navigationalaids such as ship routing, vessel trackingand traffic separation.

The report defines a deep-draft port asone that can accommodate large vesselssuch as cargo ships. It should have waterdepth greater than 35 feet.

Alaska has deep-draft ports in suchlocations as Anchorage, Valdez, Kodiak

and Unalaska, but none along the Arcticcoastline.

Sites consideredThe study team considered several

potential port sites, some actually on theArctic Ocean coastline and some to thesouth in the Bering Sea.

The “candidate sites” were: St. PaulIsland, St. Lawrence Island, Nome, PortClarence/Teller, Kotzebue/Cape Blossom,Mekoryuk, Cape Thompson, Wainwright,Point Franklin, Barrow, Prudhoe Bay,Mary Sachs Entrance, Bethel and CapeDarby.

The primary site evaluation criteriawere proximity to oil and gas and miningactivity, intermodal connections, uplandsupport, natural water depth and naviga-tion accessibility.

The team whittled the candidates to ashortlist of four sites: Nome, PortClarence, Cape Darby and Barrow.

From there, the team recommendedtwo, Nome and Port Clarence, for feasi-bility analysis considering, among otherthings, “alignment with potentialinvestors.” The study says the two top-ranked sites will be the focus of feasibili-ty work for 2013-14.

Nome’s proximity to oil and gas activ-ity and mining operations, along with itsupland support, make the city “an attrac-tive choice for deep-draft operations,” thestudy says.

Nome is a small Bering Sea city on thesouth coast of the Seward Peninsula,about 100 miles south of the ArcticCircle. Although it is a regional trade cen-

ter, Nome is disconnected from the state’sroad system. It already has a medium-draft port, and is seeking to expand anexisting causeway and related breakwaterto accommodate deep-draft vessels, thereport says.

Port Clarence, 67 miles northwest ofNome, is a former Coast Guard Loran sta-tion. The village of Teller is nearby.

“The natural protection offered withinPort Clarence and its proximity to BeringStrait has led to the use of this natural har-bor since whaling vessels were active inthe region in the 1860s,” the study says.“It is currently used by barge operators asthey await ice retreat north of BeringStrait each summer.”

Nome-based Bering Straits NativeCorp. has been working with a marinetransport company, Crowley Maritime, ona deep-water port development plan forPort Clarence, the study says. The portfacilities would be designed to supportoffshore oil and gas operations.

Lots of planning under wayNotable sites that didn’t make the

shortlist for deep-draft port feasibilityanalysis include the villages of Barrowand Kotzebue, as well as Prudhoe Bay,epicenter of the North Slope oil industry.

Barrow, a large and well-equipped vil-lage, is about midway between active oiland gas exploration targets in theBeaufort and Chukchi seas. At present,Barrow has no protected harbor.

At Prudhoe Bay, a causeway and docksystem services barges that transportdrilling and production equipment to the

North Slope.Kotzebue is another major village that

supports the large Red Dog zinc mine.Kotzebue currently has a shallow-draftport.

The city of Kotzebue is pursuing a 10-mile road and deep-water port at nearbyCape Blossom, the report says. The stateDepartment of Transportation is expectedto start construction of the $30 millionroad from Kotzebue to Cape Blossom in2014, and the city’s mayor said “expres-sions of interest” have been received forliquefied natural gas and copper export,the report says.

The big challenge in siting a deep-draftport for the Arctic is the generally shallownature of the region’s coastal waters.

Cape Darby, another site on theSeward Peninsula, southeast of Nome, is“one of the very few naturally deep-waterports in the study area,” the report says.Cape Darby potentially could serve as adeep-draft port for resource export, but nocommunity or infrastructure is there.

Another site, Cape Thompson on theChukchi Sea about 26 miles southeast ofPoint Hope, also holds some appeal. Thereport says Barrow-based Arctic SlopeRegional Corp. and a state agency, theAlaska Industrial Development andExport Authority, are interested in the siteas a terminal for coal exports, and possi-bly as a Coast Guard hub.

“Cape Thompson gained notoriety in1958 as the proposed site for an artificialharbor to be dug by nuclear bombs knownas ‘Project Chariot,’” the report says.“The proposal was never implemented.”

‘Wild West’ or ‘Golden Days’An Arctic port would serve more than

industry.“Navy, Coast Guard, NOAA and other

research vessels are traveling the north-ern waters with little or no infrastructuresupport,” the report says. “The agencieshave each expressed interest in utilizing adeep-draft port and enhanced port facili-ties, but they lack funding and authorityto build such infrastructure. Long-termfederal leases could provide a partnershipopportunity.”

The report sketches out a number ofpossible scenarios “to examine the uncer-tainties of what lies ahead.”

The study team facilitated a scenariowork session in July 2012 with more than20 Arctic experts and stakeholders, withan outlook to 2060.

Under what the report calls a “WildWest” scenario, high demand forresources creates an “undisciplined worldof boom and bust with everyone for him-self.”

“The Wild West scenario could resultin numbers of isolated single-purposeports led by private investment,” thestudy says. “There would be no regionalor state port authorities. Siting would bedriven by independent business agendasand resource proximity. Public and pri-vate investment would not be coordinat-ed. This scenario would not yield a high-ly functioning Alaska Arctic port sys-tem.”

A more favorable scenario, called“Golden Days,” would see collaborationin an environment of high and sustainedresources prices.

“The Golden Days scenario couldresult in a number of regional portauthorities, or even a statewide portauthority to manage the high level of portoperations in the Arctic,” the study says.

The draft study is posted at1.usa.gov/12ghRFE. Comments may besubmitted to [email protected] Feb. 28. �


• SUPPORTING THE NORTH SLOPE & COOK INLET• HEATERS, GENERATORS, VEHICLES, MANLIFTS, LIGHT PLANTS,

ENVIROVACS, RIGMATS & MOBILE BUILDINGS• CAMPS & CAMP SERVICES• FULL PROJECT LOGISTICS SERVICES & STAFFING

Magtec Alaska, LLC(907) 394-6350Roger Wilson, Prudhoe [email protected]

Skeeter Creighton, Kenai(907) [email protected]

TOTAL PROJECT SUPPORTTOTAL PROJECT SUPPORT


PORT SITES POINT FRANKLIN

BARROW

CAPE THOMPSON

WAINWRIGHT

RED DOG PORT

KOTZEBUE

PORT CLARENCE

NOME

CAPE DARBY

SAINT MICHAEL

BETHELMEKORYUK

PRUDHOE BAY

MARY SACHS ENTRANCE

CANADA

RUSSIA

Gulf of Alaska

Beaufort Sea

Bering Sea

Bristol Bay

Chu

kchi

Sea

ST LAWRENCE ISLAND

ST MATTHEW ISLAND

NUNIVAK ISLAND

ST PAUL

ST GEORGE

ALA

SKA

DEE

P-D

RA

FT A

RC

TIC

PO

RT S

YSTE

M S

TUD

Y

http://www.magtecalaska.com/


CENTRAL ALASKAContinental Rift Basins

1.8 million acres (730,000 hectares) in large contiguous blocks

For more information and data displays, go todoyonoil.com

Contact: James Mery, Doyon, Limited 1 Doyon PlaceFairbanks, Alaska USA Phone: 907-459-2039Email: [email protected]

will require repair following the NewYear’s Eve grounding incident, he said.

“It is too early to say how this willimpact the (the program) going forward,”Voser said, referencing the Kulluk ground-ing. “We need to wait for the investiga-tions which some external bodies aredoing, but we also internally assess therisks and the learnings and then actuallylay out our plans for the years to come.”

The Kulluk ran aground to the south ofKodiak Island on the evening of Dec. 31and was refloated on Jan.6, before beingtowed to a safe anchorage on the followingday.

Shell Chief Financial Officer SimonHenry said that Shell had provided for $40million in Kulluk salvage costs in the last

quarter of 2012. The company anticipatesanother $50 million in Kulluk relatedcosts in early 2013, including costsincurred by the U.S. Coast Guard and thecosts of using Shell’s contracted vessels.But none of these costs include the even-tual bill for repairing the Kulluk — thatcost is not yet known, Henry said.

So far Shell has spent about $5 billionon its Alaska program, including a spendof about $1 billion in 2012, Voser said.

Voser vehemently denied a story thathas been doing the rounds, that Shellmoved the Kulluk south to avoid taxes inAlaska.

“This played no factor in the decisionto move the Kulluk,” he said. “We had tomove the Kulluk to a safe, bigger harbor todo the repairs.”

The tax avoidance story had resultedfrom a statement by a Shell employeebeing taken out of context, Voser said.

Alaska challengesAsked whether the grounding of the

Kulluk in a severe storm demonstrated thetype of challenge that operating in theAlaska offshore presents, Voser said thatwhile harsh weather is a factor in Alaska,it is also a factor in many other parts of theworld.

“We are actually used to dealing withthat,” Voser said, citing a recent situationin Australia where the company had beenforced to mobilize and demobilize a rigcrew three times because of typhoons.

All businesses have to manage risks, hesaid.

“I can never say that there will never bean incident,” Voser said. “That’s just notgoing to work.”

Asked whether Shell might leaveAlaska in the fallout from the groundingof the Kulluk and the ensuing investiga-tions into the company’s Alaska opera-tions, Voser said that responsible operatorslike Shell, who are prepared to spend sig-nificant sums of money to prepare fordrilling, are needed for development in theArctic, a region with huge undiscoveredresources.

“This is an area where we see the Shellstrengths actually playing and, therefore,in the longer term we want to develop inthe Arctic,” Voser said. �


KULLUK PROBE

Slope’s largest producer, the committee wastold that removing progressivity was a pos-itive, but removing the credits was a nega-tive.

Kara Moriarty, the executive director ofAOGA, said the organization’s memberssupported elimination of progressivity butwere concerned with how the bill addressedtax credits. She said AOGA supported grossrevenue exclusions (a 20 percent taxallowance for new oil, either from new unitsor new participating areas within existingunits), but said the concept should beexpanded to fit projects in legacy fields.

Bob Heinrich, vice president of financefor ConocoPhillips Alaska, and ScottJepsen, the company’s vice president ofexternal affairs, said the governor’s propos-al would improve Alaska’s business climateand make the state more competitive at oilprices above $100 a barrel but didn’t doenough to encourage investment in legacyfields and didn’t encourage investment atlower oil prices.

Jepsen said the potential for additionaloil production lies in the state’s legacyfields, and said taxes, along with high oper-ating costs, are a problem for Alaska inattracting investment. He recommendedeliminating progressivity and keeping thecredits provided under ACES.

Heinrich said that of the billion dollars incredits frequently cited, less than half goesto producers, more than half to explorers.He also said cash margins forConocoPhillips are “significantly less” inAlaska than in new projects in which thecompany is investing in the Lower 48 andsaid it is difficult to compare the company’searnings in Alaska with those in the Lower

48, because in Alaska 90 percent of thecompany’s production is oil, whereas in theLower 48 more than 70 percent of its pro-duction is gas and gas liquids, subject tocurrent very low gas prices.

On a barrel of oil equivalent, whichincludes natural gas and natural gas liquids,there is higher net income per barrel inAlaska, he said, but not on an oil-to-oilcomparison basis.

SB 21 impact at low pricesThe high Alaska tax rate impacts overall

investment decisions, with ACES impactingcash flow in the long term, Jepsen said. Hesaid Alaska is impaired in comparison toother investment opportunities because ofthe portion of profit taken in taxes and isjust not able to attract discretionary cash forinvestments.

The “easy oil” on the North Slope isgone and what remains is challenged oilwith complex, high-cost wells, smallerreserve targets, isolated fault blocks, satel-lites and viscous oil, Jepsen said.

Heinrich said that the proposed changesunder SB 21 would increase the tax at loweroil prices, less than $93, and said that withhigh operating costs in Alaska, it doesn’t tiltthe equation enough.

While SB 21 would make Alaska morecompetitive at prices above $100, that isn’tConocoPhillips’ perspective on the priceoutlook, Heinrich said.

Jepsen noted that the potential forincreased production lies primarily in lega-cy fields, and Heinrich said the gross rev-enue exclusion should be extended to lega-cy fields.

—KRISTEN NELSON

ORDER TODAY

Learn how the Trans-Alaska Pipeline System was built, andchanged not only Alaska but its Legislature as well.

To order please send $25 per copy ($30 in Canada) to A. Spielman, P.O. Box 106, Anchorage, AK 99515.


TAX DISCUSSIONS

Voser vehemently denied a storythat has been doing the rounds,

that Shell moved the Kulluk southto avoid taxes in Alaska.

http://www.doyonoil.com/

http://www.matsystems.ca


three components: a $50 million GeneralFund allocation to AIDEA, $125 millionin AIDEA loans through the SustainableEnergy Transmission and Supply fundand authorization for AIDEA to issue upto $150 million in bonds.

Under the financial outline it present-ed to lawmakers, AIDEA would help athird party partner pay for the roughly$220 million North Slope LNG plantusing the $50 million grant, the $125million in SETS loans issued at 3 percentinterest and a $15 million storage creditalready on the books with the remaindercoming from the private sector.

“We need SB 23 as a tool to workwith the private sector,” Davis said.

Of the 16 responses AIDEA receivedto its late December request for interestin the project, several came from banks,private equity groups and financial con-sortiums, Davis said, includingGuggenheim Partners, KeyBanc CapitalMarkets and Northrim Bank.

Local distribution neededThe $150 million in bonding, which

AIDEA also expects to issue at 3 percentinterest, would go to expand the localdistribution system through the high andmedium density population centers andto major industrial users in the Interior.Although Fairbanks Natural Gas LLCcurrently operates a small grid servingsome 1,100 customers in Fairbanks, thevast majority of businesses and home-owners in the city rely on fuel oil orwood for space heating, and the

Fairbanks Natural Gas certificate onlycovers the city proper, without reachingthe surrounding rural areas or the nearbycity of North Pole.

AIDEA expects the two sides of this“first phase” to cost about $400 million.

Because the private sector is unlikelyto fund an LNG plant without guaran-teed customers and unlikely to fund adistribution expansion without a gas sup-ply, the Parnell administration believesthe financial package is the best way tokick-start the project.

“Both the demand side and the pro-duction side have to be financed almostin tandem for this to really work. ... Thisplant will allow you the ability to startbuilding out that distribution system,”AIDEA Executive Director Ted Leonardtold the Senate committee.

Once the system is in place, AIDEAbelieves the Interior could see another$400 million to $600 million in privateinvestment to expand the grid into lower-density corners of the region. Daviscompared it to a bank being skepticalabout offering an initial mortgage, butwilling to offer refinancing once thehomeowner establishes a positive trackrecord.

And because the distribution grid willalso be necessary should Alaska get alarge-diameter gas pipeline, or a smallerin state pipeline, AIDEA sees it as agood investment.

Questions remainWhile Interior lawmakers are eager

for the project, both to alleviate the costof heating and to improve air quality,some Southcentral lawmakers have

expressed skepticism.AIDEA currently envisions a 9 billion

cubic feet per year plant that could bescaled up to 20 billion cubic feet ifdemand warrants, but Sen. PeterMicciche, a Republican from Kenai,warned against touting the benefits of alarger plant. While a larger plant wouldlower the wholesale cost of gas, “the restof this system does not benefit fromscale.”

Unlike a pipeline, trucking comeswith fixed labor and transportation costs,he said.

And while AIDEA is presenting a$400 million cost estimate, Miccichebelieves lawmakers still have “a lot tolearn” about the project before they canbe confident in the price tag. He pointedspecifically to the cost to removepropane from gas on the North Slope,and the cost to move the plant should afuture pipeline render it obsolete.

While acknowledging AIDEA canonly give a rough estimate for the projectuntil it goes through the responses indetail, Davis noted that the bill beforelawmakers would only give AIDEA theability to move forward, and decidewhether to sanction the project.

In addition to questions about theaccuracy of cost estimates, Sen. BillWielechowski, a Democrat fromAnchorage, wanted to know about thelikelihood of bringing excess LNG tosupply-constrained Southcentral, andmade “a pitch” for those hypotheticalsupplies to be priced on a postage stamprate — meaning all end users would paythe same price.

And although AIDEA expects the

plant to someday be replaced by a gaspipeline, Wielechowski wanted to knowwhat would happen if the plant and thedistribution grid were instead replacedby electric power from the proposedSusitna-Watana Dam.

In a cautionary note, Sen. ClickBishop, a Fairbanks Republican, recalledhow Interior residents bet money on theproposed Rampart Dam of the YukonRiver in the 1950s, only to have the proj-ect never come to pass. And Sen. JohnCoghill, a North Pole Republican, saidInterior residents needed cheaper energylong before the 2025 start date of thedam.

What about HCCP?And what about an infamous AIDEA

energy plant of old?At a Feb. 4 House Energy Committee

hearing, Rep. Doug Isaacson, a NorthPole Republican, asked about the “ele-phant in the room,” the Healy Clean CoalProject, the $300 million AIDEA powerplant built in the mid-1990s but offlinesince 2000.

The troubled facility, currently beingsold to Golden Valley ElectricAssociation, taught AIDEA some impor-tant lessons about “how to structuredeals,” Leonard said. Instead of owningfacilities outright, “we should be in part-nership with the private sector,” he said.

This philosophy guided how AIDEAfinanced the Endeavour jack-up drillingrig, he said.

—ERIC LIDJI


INTERIOR LNG

And his message to them it that“substantial (LNG) prices” are neededto underpin multi-billion dollar exportschemes that include the high cost ofdeveloping resources in northeasternBritish Columbia, building pipelinesand completing liquefaction and tankerterminals on the British Columbiacoast.

Similar challenges have seen the costof new Australian projects get caught inan inflationary spiral.

U.S. projects on the other hand havethe advantage of existing gas pipelinenetworks and existing import terminalsthat can be easily converted to exports.

“I can tell you it takes a large capital

commitment and most companies in theworld aren’t going to make that com-mitment without having pricing thatgives them a fair return. That pricing isgoing to need to be something close tooil parity, or the projects won’t getbuilt,” Watson told analysts.

“What we see is continuing growthin (LNG) demand. There’s a lot of gasout there, but pulling these projectstogether and getting them online ... intime to meet that demand, is a differentmatter.”

He declined to discuss a possibletimeline for Kitimat LNG until a salesagreement is negotiated. “We hope toclose the transaction soon.”

Push by Asian utilitiesChevron’s entry into Western Canada

coincides with a push by Asian utilities

to link LNG sales to North Americangas prices.

“You’ve got this trend of Henry Hubindexation, which is perceived to be alower level of pricing, creeping into theexpectations of Asian buyers nowadaysin an attempt to squeeze seller mar-gins,” said Asish Mohanty, an LNG ana-lyst with energy consultant WoodMackenzie.

Some of those objectives were bol-stered last summer when CheniereEnergy, operator of the Sabine PassLNG project, signed contracts thatrequire offtakers to pay 115 percent ofHenry Hub gas prices, plus US$2.25-$3per million British thermal units tocover the costs of liquefaction.

Most existing LNG deals are linkedto oil, usually Brent prices, making theprice about 14-15 percent of the price of

a barrel of Brent, although some oldersales contracts are as low as 13 percentof Brent.

Although somewhat late on thescene, Chevron is seen as bringing heftto the Kitimat project, which alreadyholds the only large-scale export permitfrom Canada’s National Energy Board,covering 10 million metric tons peryear.

Tom Valentine, a partner in the lawfirm of Norton Rose Canada that playedan advisory role in the Kitimat transac-tion, said that “if you look around theworld there is only a handful of compa-nies that can legitimately say they areworld leaders in the LNG space.Chevron would be one of them.” �


LNG TERMS

http://www.acuren.com/

a holding pattern

Documents