endeavour to embark · ciri working on fire island installation; see story page 3 ... canada’s...

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

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


Vol. 17, No. 30 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of July 22, 2012 • $2

page13

Goldsmith: $170B in oil revenuescollected; $100B more possible

CIRI working on Fire Island installation; see story page 3

Turbines going upA

LAN

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ILEY Endeavour to embark

Buccaneer executes heavy lift contract to bring jack-up rig to Cook Inlet

By ERIC LIDJIFor Petroleum News

Buccaneer Energy Ltd. is getting ready to bringits jack-up rig to Alaska.

Kenai Offshore Ventures LLC, a subsidiary ofthe Australian independent, recently completed aheavy lift contract to move the Endeavour rig toAlaska from Singapore.

Buccaneer expects the rig to depart in late Julyand arrive 21 days later in the Cook Inlet, wherethe company plans to use it at as many as three off-shore prospects this year.

After completing summer work at SouthernCross and Northwest Cook Inlet, Buccaneer willmove the rig south sometime in early November to

drill at the Cosmopolitan project.In partnership with the Alaska Industrial

Shell’s still waitingCompany needs Chukchi ice to clear & barge certification before drilling start

By ALAN BAILEYPetroleum News

Shell’s two drilling vessels, the NobleDiscoverer and the Kulluk, are still moored at

Dutch Harbor in the Aleutian Islands, waiting forice to clear in the northern Chukchi Sea beforeembarking on the company’s much anticipatedArctic drilling venture. However, the companyalso needs U.S. Coast Guard certification of itscontainment barge Arctic Challenger, still dockedin Seattle, and the transfer north of that vessel,before drilling can begin.

In addition, at the time Petroleum News went topress the Environmental Protection Agency hadyet to issue decisions on requests by Shell forchanges to the air quality permits for its drillingvessels, following a discovery that some engines

on the vessels could not fully meet the emissionslimits set in the approved permits. And, in what hasturned out to be a less than smooth start to itsplanned drilling season, Shell has been fending off

Pipeline pressure buildsFormer Alberta regulatory chief says BC has means to stall progress

By GARY PARKFor Petroleum News

Not a day goes by without Enbridge — and, indi-rectly, TransCanada and Kinder Morgan —

feeling the heat of public and political opposition totheir plans for shipping oil sands crude from Albertato new markets.

Even a respected former regulator has discountedclaims that the British Columbia government can donothing to prevent a federally regulated pipeline fromcrossing its territory.

Neil McCrank, an attorney and former chair ofAlberta’s energy regulator, said British Columbia can“put hurdles in the way if it really choose to do so,”effectively undermining the traditional role of

Canada’s National Energy Board to approve andimpose conditions on inter-provincial pipelines.

He told the Globe and Mail that a provincial gov-ernment has “authority with respect to environmentalcomponents within a jurisdiction.”

That could raise barriers to Enbridge’s Northern

see BUCCANEER JACK-UP page 20

see SHELL DRILLING page 18

see PIPELINE PRESSURE page 15

Gas to Homer next year; Enstar’snew pipeline plan twice as long

A pipeline to Homer will be both bigger and smaller thanoriginally envisioned.

Enstar Natural Gas Co. is beginning the permitting and regu-latory work this year for a $10.7 million pipeline running 22miles from Anchor Point to Kachemak City.

The Homer Extension is around twice as long as an earlieriteration of the project outlined in 2004, but Enstar now expectsthe project to consume less gas than it once anticipated.

The transmission line project is moving forward followingdecades of stops and starts after policymakers recently approvedan $8.15 million grant. To fund the remainder, ratepayers willpay Enstar a $1 per thousand cubic foot surcharge for roughly 10years.

As currently envisioned, the Homer Extension involves threephases: an 8-inch plastic main running 17.2 miles from Anchor

Shell unlucky with Chukchi ice;exceptionally low cover elsewhere

With the Arctic sea ice cover steadily retreating in recentyears, Shell really seems to be out of luck in having to delaythe start of its planned Chukchi Sea drilling because of anexceptionally heavy ice cover in the area when it wants to siteits drilling rig.

Mark Serreze from the National Snow and Ice DataCenter, or NSIDC, told Petroleum News July 16 that the iceconditions that are impacting Shell’s drilling plans representa regional variation within a continuing trend of sea ice lossfor the Arctic as a whole. Essentially, weather conditions, par-ticularly the wind, have pushed exceptional amounts of iceinto the Chukchi and western Beaufort seas, while in the east-ern Beaufort, for example, there is relatively open water.

“If you take the total Arctic sea ice extent for Arctic as awhole, it’s very low and at or near a record low for the date,”

see GAS TO HOMER page 19

see ICE CONDITIONS page 20

The Endeavour jack-up rig

Adrian Dix, leader of the BritishColumbia New Democratic Party and a

clear favorite to win next year’s provincialelection, has assembled a legal team tofind ways to stop Northern Gateway.

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Shell's new ice-class anchor handler, the Aiviq, tows thefloating drilling platform, the Kulluk, to Dutch Harbor.

http://www.PetroleumNews.com/

2 PETROLEUM NEWS • WEEK OF JULY 22, 2012

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

ALTERNATIVE ENERGY

ENVIRONMENT & SAFETY

EXPLORATION & PRODUCTION

LAND & LEASING

PIPELINES & DOWNSTREAM

FINANCE & ECONOMY

GOVERNMENT

INTERNATIONAL

3 Fire Island wind farm taking shape

First turbine assembled as construction moves towards end-September startup for CIRI’s pioneering renewable energy project

8 AEA files plan for Susitna hydro studies

Proposed plan includes 58 studies into the potentialenvironmental impacts of dam and power plant at Watana on the Susitna River

9 Alaskans rip BLM over ‘legacy wells’

Hearing before a U.S. Senate committee elevates thorny issue to higher profile; federal official outlines near-term plugging plans

4 State, BP continue with arbitration

Proceeding concerns huge royalty claim linked to Prudhoe pipeline leaks of 2006; decision expected to take at least two more months

6 AGPA applies to export LNG from Valdez

Alaska Gasline Port Authority asks Department of Energyfor authorization for 2.5 bcf per day to Asian-Pacific rim countries

NATURAL GAS

contents15 US oil, gas rig count down by 12 to 1,953

17 Tundra opens for authorized summer travel

13 After 35 years, a staggering oil fortune

14 Non-OECD demand to exceed OECD in ’13

17 Oil tops $91 for 1st time since late May

14 Donkel challenging Cohoe ruling

15 DNR finds no substantial new sale info

13 Pipelines bypass the Strait of Hormuz

13 TNK-BP investors eye BP’s share in oil firm

10 Can gas-to-liquids technology get traction?12 Carbon capture project gets nod

5 Boost for oil sands next phase

7 DO&G denies certain royalty deductions

7 Exxon gets TAPS tariff extension

6 Two camps this year for Point Thomson

12 Senators urge U.S. Arctic strategy

15 Administration seeks taxes consultant

6 Coast Guard moves 2 helicopters to Barrow

Gas to Homer next year; Enstar’snew pipeline plan twice as long

Shell unlucky with Chukchi ice;exceptionally low cover elsewhere

Endeavour to embark

Buccaneer executes heavy lift contract to bring jack-up rig to Cook Inlet

Shell’s still waiting

Company needs Chukchi ice to clear & barge certification before drilling start

Pipeline pressure builds

Former Alberta regulatory chief says BC has means to stall progress

ON THE COVER

SIDEBAR, Page 8: Susitna project seeks independent estimate

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It has been many years since peoplestarted looking at harnessing the abun-

dant and often strong winds that funnelout of Alaska’s Turnagain Arm over FireIsland, offshore Ted Stevens AnchorageInternational Airport. But the years ofeffort to build a wind farm on the island,initially by Chugach Electric Associationand then by Cook Inlet Region Inc., orCIRI, the island’s majority landowner, arefinally paying off as CIRI’s team of con-tractors hoists the farm’s 270-foot diame-ter wind turbine blades into place on topof white, tubular towers that projectabove the island’s spruce forest. One tur-bine is now complete and other turbinesare scheduled to follow in short order.

17.6 megawattsThe wind farm will use 11 General

Electric turbines to supply up to 17.6megawatts of power to Chugach ElectricAssociation, currently the farm’s onlycustomer. CIRI, the Native regional cor-poration for the Cook Inlet region, saysthat, taking into account the variablenature of the wind energy source, thefarm will likely deliver about 51,000megawatts annually to Chugach Electric,an amount of power needed to supplyabout 6,000 households and representingabout 4 percent of the utility’s total powerneeds.

The price of the power, $97 permegawatt hour, equivalent to 9.7 centsper kilowatt hour, is fixed for the 25-yearlife of the Chugach Electric power supplycontract. The State of Alaska is providinga $25 million grant towards constructionof the transmission line between FireIsland and the electrical grid on the main-land, with CIRI picking up the remainderof the transmission line cost and the $65million cost of the wind-farm itself.

The wind farm is slated to go on line atthe end of September, said SuzanneGibson, CIRI’s senior director for energydevelopment, during a July 18 media tourof the Fire Island project.

Challenging projectThe Fire Island wind farm venture has

proved something of a nail-bite-inducingobstacle course, especially given the prox-imity of the site to a major airport andconcerns among Alaska utilities about thepotential cost of integrating wind powerinto the Railbelt electricity grid. At vari-ous times the wind farm development hasinvolved negotiations with the FederalAviation Administration over issues relat-ing to possible interference with the radarsystems at the airport and the location of aradio navigation system on Fire Island.After lengthy discussions with power util-ities, in 2011 CIRI signed a power pur-chase agreement with Chugach Electric.

And that agreement had to cross the hur-dle of obtaining Regulatory Commissionof Alaska approval, the first contract of itstype that the commission has had to con-sider.

The power purchase negotiations andsubsequent regulatory approval processtook place against the backdrop of a dead-line to complete the project this year orlose some federal renewable energy fund-ing seen as critical to the project econom-ics.

And, just to add some spice to the chal-lenges, the wind farm’s island locationgives the project some of the characterand challenge of a remote, rural develop-

ment despite its proximity to Anchorage.For the development of the Fire Island

site CIRI originally partnered withEnXco, a company that specializes in theconstruction of wind power systems.However, EnXco, feeling uncomfortableabout the unique challenges of the project,eventually opted out of the venture,Margaret Brown, president and chiefexecutive officer of CIRI, told PetroleumNews during the July 18 media tour.

Pride in successCIRI subsequently took on sole

responsibility for managing the project,obtaining wind power consultancy servic-es from Summit Power Group and con-tracting with Tetra Tech Construction forbuilding the facility. STG Inc., a companywith extensive experience of wind farmconstruction in Alaska, has been operatingthe cranes that are so critical to the assem-bly of the tall wind-farm turbines.

CIRI now takes particular pride in itssuccess with such a unique and challeng-ing project, Brown said. The corporationsees wind energy as an important compo-nent of its business portfolio — CIRI alsohas a wind farm business in the Lower 48,she said.

The Fire Island wind farm has permit-ted capacity for an additional 22 turbinesif CIRI can find additional customers forits facility.

Ethan Schutt, Cook Inlet Region Inc.senior vice president, land and energydevelopment, has been extensivelyinvolved in the Fire Island project over theyears. Standing near the first completedturbine on the island, the turbine’s tall,slender structure dwarfing the smallthrong of people who had come to see it,Schutt reflected on the roller coaster ridethat had led to the construction of thefacility.

“There’s a lot of corporate pride. We’vedone a lot of hard work. … A day like thisis just a validation of all that effort andfaith in a project like this,” Schutt said.“It’s been a very long haul.” �

PETROLEUM NEWS • WEEK OF JULY 22, 2012 3

Contact Alan Bailey at [email protected]

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Fire Island wind farm taking shapeFirst turbine assembled as construction moves towards end-September startup for CIRI’s pioneering renewable energy project

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Clockwise from top, pn July 18 the towers ofthe 11 wind turbines that will form the FireIsland wind farm were in various stages ofcompletion. CIRI has now completed the construction ofthe first of the 11 wind turbines to beinstalled on Fire Island. The steel turbinetower is 262 feet high and the turbine bladesare 270 feet in diameter.The huge blades of a wind turbine, assem-bled on the ground in readiness for hoistinginto position, dwarf nearby cars and people.

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CORRECTIONSPHMSA not NTSB

A headline on a story in the July 15, 2012, edition of Petroleum News wasincorrect due to an editing error: PHMSA, the U.S. Department ofTransportation’s Pipeline and Hazardous Materials Safety Administration, wascited by National Transportation Safety Board Chairwoman Deborah Hersman forlax regulatory oversight in findings on the 2010 Enbridge spill in Michigan, so theheadline should have read: “Enbridge takes heat; 2010 rupture handling likenedto Keystone Kops routine; PHMSA also blamed.”

Petroleum News apologizes for the error.

Cook Inlet Apache well locationsAn article in the July 8, 2012, issue of Petroleum News (“An ‘oil museum’”)

incorrectly identified the location of two proposed Apache exploration wells inCook Inlet.

The article said Apache planned to drill a well on the west side of the inlet, fol-lowed by a well on the east side of the inlet, if time permits both this year. WhileApache originally intended to drill one well each on both sides of the Inlet, itrecently changed its plans.

In June, Apache Alaska Corp. General Manager John Hendrix told PetroleumNews that the company now plans to drill both wells this year on the west side ofthe inlet. Apache had not yet gathered seismic on the east side and wanted goodquality 3-D seismic to identify drilling targets, rather than attempting to use old2-D data, Hendrix said.

Petroleum News regrets the error.

� F I N A N C E & E C O N O M Y

State, BP continuewith arbitrationProceeding concerns huge royalty claim linked to Prudhoe pipelineleaks of 2006; decision expected to take at least two more months

By WESLEY LOYFor Petroleum News

Adecision in the high-stakes arbitra-tion proceeding between the state

and BP appears to be still months away.The arbitration centers on the state’s

claim for damages stemming from the2006 pipeline leaks in the Prudhoe Bayoil field on Alaska’s North Slope.

State lawyers are seeking potentiallyhundreds of millions of dollars in royal-ties they argue the state is owed on oilthat was not produced due to the leaks,which forced partial field shutdowns anddisruptive pipeline replacements.

BP operates Prudhoe, the nation’slargest oil field, on behalf of itself andpartners ConocoPhillips, ExxonMobiland Chevron.

BP’s lawyers have resisted the state’sclaim.

Hearing has concludedThe state first laid out its claim in a

March 2009 lawsuit filed in stateSuperior Court against BP Exploration(Alaska) Inc.

The suit alleged negligence on the partof BP for its pipeline maintenance, andclaimed a host of damages.

Most significantly, the suit soughtback taxes and royalties to compensatethe state for what it contended were pro-duction shortfalls of at least 35 millionbarrels of oil and natural gas liquids fromPrudhoe and the neighboring Milne Pointfield.

A judge threw out the state’s tax claim,hugely reducing BP’s potential liability inthe lawsuit.

In January, the court stayed the caseafter the state and BP said they would goto binding arbitration on the royaltyclaim.

Since then, closed proceedings havebeen held before a three-member panel of

arbitrators.BP Alaska spokeswoman Dawn

Patience on July 11 provided PetroleumNews with this status report:

“The matter was presented to an arbi-tration panel and the hearing concludedon June 26. The arbitrators asked the par-ties to submit written legal briefs, whichwill be filed in August and September,after which the panel will take the matterunder advisement and render a decision.”

Stakes involvedIt is not known exactly how much

money the state is seeking.But conceivably, if at arbitration the

state is able to show it is due a 12.5 per-cent royalty on the full 35 million barrelsof lost production alleged in the suit, thatwould be about $328 million at $75 perbarrel.

The two Prudhoe pipeline leaks were abig problem for BP. The corrosion-relatedleaks drew criticism from members ofCongress and federal pipeline regulators,and forced costly replacement of oil tran-sit lines that feed sales-grade crude intothe trans-Alaska pipeline.

One of the leaks, at 212,252 gallons,was the largest oil spill ever on the NorthSlope.

BP Alaska was convicted of a federalenvironmental misdemeanor, whichresolved the criminal aspect of the matter.

Subsequently, the federal and stategovernments each filed a civil suit againstBP.

The federal suit was settled in July2011 with BP agreeing to pay a $25 mil-lion civil penalty, implement a Prudhoepipeline integrity management program,and hire an independent monitoring con-tractor to report to the government oncompany compliance. �

Contact Wesley Loy at [email protected]


A lthough only a fraction of Alberta’sexisting 170 billion barrels of oil

sands resources has been removed, thenext, even larger deposit is making head-way towards commercial development,spearheaded by two junior startup compa-nies.

Laricina Energy, a 60 percent operator,and Osum Oil Sands have made a signifi-cant progress towards demonstrating thatthermal extraction of bitumen of theGrosmont carbonate formation at Saleskiin northeastern Alberta is commerciallypossible.

Backed by a C$500 million privateequity issue last year, Laricina has reportedthat the production rate from its fourthwell-pairing reached 1,200 barrels per day,compared with 800 bpd in the first quarter.

Company President Glenn Schmidt saidin a statement that “although we areencouraged by these preliminary results,we note that the initial cycle was over ashort time period.”

“Further and extended cycles arerequired to confirm production perform-ance as we apply what we have learnedfrom previous cycles and continue toemploy a variety of systems and applica-tions in startup and recovery to fully under-stand the Grosmont formation,” he said.

The Grosmont underlies much of theAthabasca oil sands deposit, which domi-nates Alberta’s oil sands production, and

has an estimated 406 billion barrels of oilin place.

The Laricina-Osum joint venture pilotbegan in 2010 and has now completed fourwell pairs using horizontal steam-assistedgravity drainage, SAGD, technology, withthe horizontal sections limited to about1,500 feet to enhance early startup byreducing the volume of steam needed fortesting.

Laricina said the latest well pair — oneto inject steam and one to produce bitumen— occurred through May and June.

The company said the results “supportboth our confidence in the drilling tech-niques which we expect to use in theplanned 10,700 bpd Phase 1 commercialexpansion at Saleski and our goal to drivedown the costs and improve performanceof future well pairs.”

Laricina and Osum are now evaluatingthe incorporation of cyclic steam stimula-tion into an amended Phase 1 regulatoryapplication, but is not attempting to fore-cast when a commercial operation might bepossible.

Phase 1 cost estimate raisedCalgary-based investment dealer Peters

& Co. has noted that Laricina has alreadyraised the Phase 1 cost estimate to C$660million from C$400-C$450 million, point-ing to the “potential for general cost infla-tion in the oil sands.”

Laricina has earmarked C$402 million(up about 33 percent from last year) for itscapital and operating program this year toadvance thermal recovery work in northernAlberta, targeting both its Saleski pilot andGermain commercial demonstration proj-ect, which is designed to start producing30,000 bpd in the third quarter of 2015 at acost of C$330 million and build to 150,000bpd.

Proven technology exists for recoveringmore than 25 percent of Alberta’s bitumenresource locked in tight, low-permeabilitycarbonate rock, but industry observers areclosely watching the current efforts to opena new geological and technological frontierfor Alberta oil production.

Pilot tests were run in the 1970s and1980s, with reports by a now-defunctprovincial government research agencyestimating production rates of up to 550bpd were possible from a single steamstimulation well.

But companies suspended the pilotsbecause of concerns about the viability ofproduction.

Impact of SAGDInterest in the resource was jolted back

to life with the evolution of SAGD andother technologies.

In 2006, Husky accumulated Grosmont

holdings for small outlays, estimating itsproperties contain 19.5 billion barrels of oilin place.

Husky, with 100 percent working inter-ests in three carbonate formations totaling241,000 acres, said it is evaluating the“optimal development” of the assets, butdoes not expect commercial developmentwithin the next 10 years.

Royal Dutch Shell sent the Grosmonttemperature soaring in 2006 when it invest-ed C$1.6 billion for land parcels in theGrosmont and established SURE NorthernEnergy to evaluate and potentially developthe resources using unspecified “new”technologies.

SURE was later absorbed into Shell’sCanadian division when its plans to testelectric heaters for bitumen recovery and insitu upgrading were indefinitely delayed inlate 2008.

Shell has provided little updated infor-mation over the past four years beyondindicating it would proceed at a “moremodest pace.”

Athabasca Oil Corp., with 788,000gross acres of rights, started an electro-heatpilot early last year, using extreme down-hole heat to convert the viscous bitumendeposits into medium crude which could beforced to the surface.

It is keeping a low profile on the workother than saying work is progressing on apilot/demonstration project. �


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Boost for oil sands next phaseJV by two startup companies raises production level with results over short time period; other Grosmont carbonate players stay low

The Grosmont underlies much ofthe Athabasca oil sands deposit,

which dominates Alberta’s oilsands production, and has an

estimated 406 billion barrels of oilin place.

PIPELINES & DOWNSTREAMExxon gets TAPS tariff extension

State regulators are extending a temporary rate increase that ExxonMobil can chargeusers on the trans-Alaska oil pipeline while they continue to deliberate on a larger case.

In 2011, the Regulatory Commission of Alaska allowed Exxon to increase the rateit charges shippers to move oil to in-state markets, the third just increase in three years.

Although the temporary period usually lasts six months, the RCA can extend thetimeline to accommodate complex proceedings. The RCA previously extended the rateby one year and with the current extension Exxon can collect the higher rates for anoth-er year.

The matter is one of 12 similar cases in a consolidated docket currently under reviewin concurrent hearings between the RCA and the Federal Energy RegulatoryCommission.

The RCA is also studying four additional cases outside the docket, including anoth-er increase Exxon recently requested on top of the one it is now getting extended.

All the increases are subject to refund if the RCA finds them unjust.—ERIC LIDJI

Contact Gary Park through [email protected]

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By KRISTEN NELSONPetroleum News

The Alaska Gasline Port Authorityhas applied to the U.S. Department

of Energy for long-term authorization toexport liquefied natural gas from Valdez.

The Alaska Gasline Port Authority,AGPA, is a municipal port authorityformed in 1999 by the Fairbanks NorthStar Borough, the City of Valdez and theNorth Slope Borough; the North SlopeBorough dropped out in 2010.

AGPA has been promoting an LNGproject since its formation and in the pastproposed a gas treatment plant on theNorth Slope, a gas pipeline from theNorth Slope to Valdez and a liquefactionfaction at Valdez.

AGPA’s general counsel, Bill Walker,said in a July 5 filing to the Department ofEnergy that the authority now anticipatesthat facilities upstream of the ValdezLNG terminal would be constructed bythe Alaska Gasline Inducement Actlicensee, TransCanada Alaska, and itsproject partners.

He said the AGPA project is nowfocused on the terminal, which is “sub-stantially similar” to that previously pro-posed by Yukon Pacific Corp., foundedby former Gov. Wally Hickel in 1981.Yukon Pacific spent some two decadesworking on an LNG export project to theFar East, from the early 1980s throughthe early 2000s.

Anderson BayAGPA is in the process of applying to

lease land at Anderson Bay some 5 milesfrom the existing trans-Alaska oilpipeline terminal, the same site leased fora number of years to Yukon Pacific,Walker said.

Yukon Pacific received FERCapproval for a liquefaction terminal atAnderson Bay, as well as a long-termauthorization from the Department ofEnergy for export of 14 million metrictons of LNG per year to Japan, Korea andTaiwan, he said.

Walker said AGPA is requestingauthorization to export some 2.5 billioncubic feet of natural gas per day, approx-imately 19 million metric tons per year, tocountries with which the United Stateshas a Free Trade Agreement. He said theport authority “has received significant

interest from the market” in the project. Because Alaska statutes provide

“favorable language regarding the leaseof state land to port authorities,” Walkersaid, AGPA should receive “preferentialtreatment” on its lease application.

He described two other options for theliquefaction facility.

It could be co-located with the existingtrans-Alaska oil pipeline marine oil ter-minal, which was built to handle 2.1 mil-lion barrels per day and currently isreceiving some 600,000 bpd. Walker saidAGPA contracted with an engineeringcompany for an evaluation of the feasibil-ity of co-locating the LNG terminal adja-cent to the Valdez Marine Terminal andthat work indicated that would be “aviable option.”

A third option would be use of floatingliquefaction terminal facilities in thewaters of Port Valdez, an option underconstruction for LNG projects in bothAustralia and the U.S. Gulf Coast, withone of the projects set for operation in2015, he said.

Gas from North SlopeWithout discussing specific sources,

Walker said, “Natural gas to be liquefiedand exported will come from Alaska’sNorth Slope.”

He discussed known reserves on theNorth Slope, 36 trillion cubic feet, andU.S. Geological Survey estimates of 127tcf of technically recoverable natural gaswhich remains to be discovered, as wellas the expectation that current “aggres-sive oil and gas exploration efforts off-shore” the North Slope will result in thediscovery of large volumes of natural gas.

“AGPA requests long-term, multi-con-tract authorization for the exportation ofdomestically produced LNG” for 25years from the earlier of the date LNG isfirst exported or eight years from the dateof the authorization.

Authorization is requested to export toany country with the capacity to importLNG and with which the U.S. has a FreeTrade Agreement.

Walker said AGPA also requests“authorization to act as an agent for thirdparties seeking to liquefy and exportLNG under liquefaction tolling agree-

� N A T U R A L G A S

AGPA applies to export LNG from ValdezAlaska Gasline Port Authority asks Department of Energy forauthorization for 2.5 bcf per day to Asian-Pacific rim countries

On the webSee previous Petroleum News coverage:

“New study favors Valdez as LNG port,”in April 22, 2012, issue atwww.petroleumnews.com/pnads/592149781.shtml“AGPA again pushing Valdez LNG proj-ect,” in Aug. 14, 2011, issue atwww.petroleumnews.com/pnads/843872007.shtml“Wood Mac: LNG could pay at $75 oilwith state-owned pipeline,” in Aug. 7,2011, issue atwww.petroleumnews.com/pnads/31939602.shtml


®Providing integrated environmental and engineering solutions for the oil and gas industry

GOVERNMENTCoast Guard moves 2 helicopters to Barrow

The Coast Guard has stationed two helicopters in Barrow in anticipation ofincreased activity in the Arctic.

The Coast Guard says two Kodiak-based MH-60 Jayhawk helicopters werestationed July 16 at a seasonal forward operating location in Barrow. Support air,ground and communication crews also are in Barrow.

Rear Adm. Thomas Ostebo says in a statement that the Barrow location allowsthe Coast Guard to react quicker to an emergency in the Arctic since the closestbase is 900 miles away, in Kodiak.

—ASSOCIATED PRESS

Two camps this year for Point Thomson A record of decision from the U.S. Army Corps of Engineers on ExxonMobil’s

proposed Point Thomson project is expected by the end of the summer (see“Permit decision in sight” in July 15 issue of Petroleum News) and informationprovided to the Alaska Department of Environmental Conservation for an AlaskaPollutant Discharge Elimination System permit describes the company’s pro-posed camp system for work at the field.

Background in the APDES permit preliminary draft fact sheet says that winter2012 work will include beginning expansion of the existing 13-acre Central Padat Point Thomson to a 56-acre pad and the beginning of construction of an initialproduction system.

Construction is expected to last three years and will require three constructioncamps: an initial 32-person camp, a 340-person construction camp and at a laterpoint, a 200-person construction camp that will later become the long-term 50-person Central Pad operations camp.

The camps will be operated independently and will be relocated as needed toaccommodate expansion of the Central Pad and construction of the initial pro-duction system.

The 32-person camp is scheduled to arrive this December. The 340-personcamp is also scheduled to arrive in the early winter of 2012 and is expected to beoperated until about 2016.

The 200-person construction camp is expected to begin operation in 2013.—PETROLEUM NEWS

EXPLORATION & PRODUCTION

see LNG EXPORT page 7

http://www.alaskasteel.com/

http://www.ewaterpro.com/

http://www.westonsolutions.com/

By KRISTEN NELSONPetroleum News

The state has denied transportationdeductions for royalty oil moved on

two gathering lines at the Redoubt unit inCook Inlet.

In a July 16 findings and decision, BillBarron, director of the Alaska Division ofOil and Gas, withdrew a 2006 director’sdecision and denied transportation deduc-tions for royalty oil moved on the Redoubtand Kustatan pipelines.

Both lines, Barron said in the decision,are “upstream from the point of production,”and under terms of the leases and applicableregulations, “associated costs are not eligi-ble deductions for calculating royalty valueon oil production” from the Redoubt unit.

Forest Oil Corp. constructed the Redoubtand Kustatan pipelines in 2002 and 2003,the decision said.

The Redoubt Pipeline carriesunprocessed fluids from the Osprey plat-form to the Kustatan Production Facilitywhere gas, water and sediment are removedfrom the crude oil, producing marketablepipeline quality oil.

The processed oil is transported from theproduction facility to the Cook Inlet Pipelineat the Trading Bay Production Facility onthe Kustatan Pipeline.

Neither of the pipelines is regulated bythe Regulatory Commission of Alaska or theFederal Energy Regulatory Commission.

Original request from Forest OilThe original request, for transportation

deductions for royalty oil for both theRedoubt and Kustatan pipelines, came from

Forest Oil Corp. in 2006. In 2006 the director determined that the

Redoubt Pipeline primarily performed agathering function and that those costs werenot deductable for valuing royalty oil.

The director in 2006 also determined thatForest’s proposed methodology for deter-mining deductions on the Kustatan Pipelinewas unsound and “concluded that he wouldaccept the deductions if based on modifica-tions to Forest’s proposed methodology.”

Forest appealed the decision to theDepartment of Natural Resources commis-sioner, but while that appeal was pendingForest sold its interest in the Redoubt unitand associated pipeline and processing facil-ities to Pacific Energy Alaska OperatingLLC. That company subsequently peti-tioned for bankruptcy.

Cook Inlet Energy acquired the Redoubtand Kustatan pipelines and other PacificEnergy Alaska assets, including the leases atthe Redoubt unit, out of bankruptcy and in

2011 approached the division requesting atransportation deduction for the KustatanPipeline.

2012 findingThe director said in the July 16 finding

and decision that neither the lease agree-ments nor the applicable regulations allowfor a transportation deduction against thevalue of royalty oil produced at Redoubt andtransported via the Redoubt and Kustatanpipelines.

“Pipelines located upstream of the pointof production are not entitled to a trans-portation deduction,” Barron said in thedecision.

He said that by statute, the state’s royaltyis free of lease and unit expenses, including,among other things, the cost of gathering;the leases similarly provide that royalty paidin value will be free of all lease expenses,including, among other items, gathering.

By the terms of the leases and state regu-

lations, “a transportation deduction for roy-alty valuation purposes is permitted only forreasonable costs of transportation down-stream from the ‘point of production’,”Barron said. “Costs upstream of the point ofproduction are not allowed as a deductionfor royalty valuation purposes.”

Under the Redoubt unit leases and stateregulations, Cook Inlet Energy “is not enti-tled to deduct transportation costs incurredupstream of the point of production,” hesaid, and the point of production “is wherethe oil is first metered and enters a regulatedpipeline, i.e. the interconnection between theKustatan pipeline and the CIPL — the firstregulated pipeline that transports oil fromthe Redoubt Unit.”

Eligible affected parties have 20 calendardays to appeal the decision to the DNR com-missioner. �


ments ... whereby AGPA will not holdtitle to the natural gas, but rather receivethe natural gas at the liquefaction facili-ty” and provide the third party with LNGto load onto tankers.

He said the Department of Energy hasgranted export licenses using the lique-faction tolling agreement model in placeof or in addition to the traditional long-term contract model.

“AGPA anticipates entering into oneor more LTAs as well as long-term (morethan two years and up to 25 years) con-tractual agreements with customer fornatural gas liquefaction and LNG exportservices,” Walker said.

He said, “Long-term authorization toexport LNG is required in order to nego-tiate long-term contracts with cus-tomers.”

The Federal Energy RegulatoryCommission would have authority oversiting, construction and operation of theLNG terminal facilities, Walker said, andAGPA would initiate FERC’s NationalEnvironmental Protection Act pre-filingprocess after receiving the requestedauthorization from the Department ofEnergy and would then file an applicationwith FERC for liquefaction of natural gasand export of LNG from Valdez.

AGPA is requesting a conditionalorder authorizing LNG export, Walkersaid, “conditioned on completion of theenvironmental review by FERC.” �

continued from page 6

LNG EXPORT

Contact Kristen Nelson at [email protected]

Contact Kristen Nelson at [email protected]


DO&G denies certain royalty deductionsCook Inlet Energy requested transportation deductions for oil movement on the Kustatan line; director finds that a gathering line

http://www.lynden.com/



In another significant step towards theconstruction of a major hydroelectric

power plant at Watana on the SusitnaRiver, south of the Alaska Range, theAlaska Energy Authority, or AEA, hassubmitted a proposed environmentalstudies plan to the Federal EnergyRegulatory Commission (known asFERC).

“Over the last year we’ve workedclosely with stakeholders and listened tothe public in drafting this robust studyplan,” said Wayne Dyok, the manager ofthe Susitna-Watana project, whenannouncing the filing of the plan withFERC on July 16. “We’re committed todelivering cost-effective, reliable energysolutions that meet the urgent needs ofAlaskans in a responsible manner. Thisplan is a significant step in that direc-tion.”

Design conceptThe design concept for the project is a

dam 2,700 feet long and 700 feet high atWatana, to create a 39-mile long reser-voir. A 600-megawatt or perhaps largerhydro power plant at the dam would betied into the Alaska Railbelt electricitygrid, probably producing an average ofabout 250 megawatts of power during thewinter months when power demand in theregion is especially high.

Hydro electricity from the Susitna-Watana project could diversify the meansof power generation in the Railbelt,

reducing the region’s dependence on nat-ural gas from Cook Inlet and helpingmeet a state goal of meeting 50 percent ofthe state’s power needs from renewablesources.

With the environmental impacts ofsuch a large hydroelectric system certainto be significant, the environmental stud-ies proposed in AEA’s newly publishedplan form a key component of the proce-dure for obtaining a license from FERCfor the project — information obtainedfrom the studies will be used in develop-ing any necessary environmental protec-tion measures that will be included in the

terms of the FERC license.

58 studiesAEA proposes 58 individual studies

addressing issues within 11 environmen-tal categories.

Under the first of these categories,investigators will characterize the geolo-gy and soils of the project area.

A series of studies relating to waterresources will address questions such aswater quality, the structure of the SusitnaRiver below the planned dam and iceprocesses in the river during the winter.

Other studies will investigate the

potential impacts of changes in the riverflow resulting from operation of the damon the natural habitats provided by theriver for vegetation, fish and otherwildlife. And a series of studies will char-acterize those habitats and the fish popu-lations, assessing the feasibility ofenabling fish passage in the river afterdam construction. Studies will analyzesport and commercial fish harvests down-stream of the dam site, as well as assess-ing any possible impacts of changes in theriver habitat on Cook Inlet beluga whales.

Studies will characterize various natu-ral and other resources potentiallyimpacted by the dam, including wildlifesuch as moose, bears, caribou, Dall’ssheep, raptors and waterbirds; vegetationand wildlife habitat, including wetlands;recreational and aesthetic resources; sub-sistence resources; and socioeconomicand transportation resources, includingpotential health impacts and air quality.

Finally, two studies will address safetyconcerns associated with the dam. One ofthese studies will investigate how the damwould handle maximum flood levels dur-ing periods of high precipitation, whilethe other study will assess seismic haz-ards.

Public reviewInterested parties have 90 days to com-

ment on AEA’s proposed plan. Publiccomments must be filed with FERC byOct. 15 — AEA will attempt, as needed,to resolve any issues raised through aseries of meetings scheduled for the sec-ond half of October. By Nov. 14 AEA willsubmit to FERC a revised study plan,with public comments on the revised planthen due by Nov. 29.

FERC will subsequently issue its ver-sion of the study plan by Dec. 14. Therewill then be an opportunity for federalagencies to question the plan, with FERCresolving any challenges to the plan byMarch.

Studies carried out under the final ver-sion of the plan are then expected to be

� A L T E R N A T I V E E N E R G Y

AEA files plan for Susitna hydro studiesProposed plan includes 58 studies into the potential environmental impacts of dam and power plant at Watana on the Susitna River

Susitna projectseeks independentestimate

The Alaska Energy Authority isseeking a suitably qualified contrac-tor who can develop an independentpreliminary cost estimate for theconstruction of a hydroelectric damat Watana on the Susitna River. Theidea is to validate and identify anyassumptions that may need furtheranalysis in the authority’s own costestimates for the hydro project. Thecontractor will be expected to pre-pare a cost estimate using informa-tion and assumptions provided bythe authority and, hence, to identifypotential cost issues or any assump-tions requiring additional analysis,the authority says.

The contractor needs experienceof cold-climate construction inAlaska and with the construction oflarge roller-compacted concretedams, of the type envisaged for theSusitna-Watana project, the authori-ty says.

—ALAN BAILEY

The proposed Watana Dam would stand about 700 feet high and create a reservoir 39 milesin length.

ALA

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ITY

Natural resources continue to be the cornerstone for Alaska’s economic

development and diversification. AIC is proud to provide our Alaska-based

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A L A S K AI N T E R S TAT EC O N S T R U C T I O N

see SUSITNA HYDRO page 9

http://www.aicllc.com/


The issue of unplugged federal “lega-cy wells” on Alaska’s North Slope

took on new prominence with a July 12hearing before the U.S. SenateCommittee on Energy and NaturalResources.

The committee’s top-rankingRepublican, Lisa Murkowski of Alaska,and a pair of state officials used the hear-ing as a chance to rip the InteriorDepartment, which is responsible for thewells.

Murkowski said it shouldn’t be thecase that it is “literally taking an act ofCongress” to push the federal govern-ment to properly plug the old wells andclean up junky drill sites.

“Senators, I can’t express my disap-pointment and shame at the InteriorDepartment’s failure to address theseenvironmental ticking time bombs,” testi-fied Cathy Foerster, who heads the stateagency that regulates drilling in Alaska.

“Allowing these unsafe and unsightlywells to litter Alaska’s wilderness whilethreatening wildlife, human safety anddamaging the pristine arctic environmentis unacceptable,” testified state Rep.Charisse Millett, an AnchorageRepublican who has been pushing foraction on the legacy wells.

On the receiving end of the blisteringwas Bud Cribley, state director of theBureau of Land Management, the InteriorDepartment agency that acts as landlordfor the National Petroleum Reserve-Alaska, in which most of the legacy wellsare located.

Cribley said his agency is committedto squaring away the wells as fundingallows, and he talked of a plugging oper-ation to be mounted soon. He also seemedto deflate one of the main arguments fromthe critics.

The legacy wellsThe BLM says the legacy wells are

136 exploratory wells and boreholes theNavy and the U.S. Geological Surveydrilled between 1943 and 1982.

Previously, the Maine-sized NPR-Awas known as the Naval Petroleum

Reserve No. 4. President Warren G.Harding created it in 1923 after geolo-gists found oil seeps. The idea was to setaside an emergency oil supply for theNavy.

The legacy wells and boreholes, from100 to 20,335 feet deep, were drilled toestablish the feasibility of modern petro-leum exploration and production methodsin arctic conditions.

None of this drilling, nor more recentindustry exploration efforts, have resultedin any production to date from NPR-A

leases.Alaska officials say the federal gov-

ernment never properly remediated manyof the legacy well sites. They contendmany wells were never properly plugged,are filled with drilling fluids or diesel, areopen to the air, and have wellheads juttingup dangerously from the tundra. Theexact location of a couple of wells isunknown, and some well sites are strewnwith rusty barrels or other junk, the offi-cials say.

‘Out the yazoo’With the legacy wells, the federal gov-

ernment is getting away with environ-mental violations that never would beallowed for private industry, the Alaskaofficials argue.

“I want to emphasize to my colleagues


completed by the end of 2014, althoughstudies of river ice processes will likelytake until March 2015. AEA plans to sub-mit its application for a FERC license bymid-September 2015.

In March FERC held scoping meet-ings in Alaska in preparation for anassessment of the project under theNational Environmental Policy Act, inexpectation of preparing an environmen-tal impact statement for the hydro projectafter AEA applies for the FERC license.

Assuming that the FERC licensingproceeds as planned, AEA anticipatesdesign and construction of the Watana-Susitna facility to be completed at the endof 2023. For further information aboutthe project see the project website atwww.susitna-watanahydro.org. �


SUSITNA HYDRO


� E N V I R O N M E N T & S A F E T Y

Alaskans rip BLM over ‘legacy wells’Hearing before a U.S. Senate committee elevates thorny issue to higher profile; federal official outlines near-term plugging plans

With the legacy wells, the federalgovernment is getting away with

environmental violations thatnever would be allowed forprivate industry, the Alaska

officials argue.

The Iko Bay No. 1 well

CO

URT

ESY

BLM

see LEGACY WELLS page 17

http://www.saexploration.com/

By BILL WHITEResearcher/writer for the Office

of the Federal Coordinator

This is the second part of a two-partstory.

How GTL worksMaking gas-to-

liquids products iscrazy expensivebecause a GTL plantinvolves three steps,each of which iscostly all by itself.

Think of a GTLplant as three dis-tinct factories linked into a single assem-bly line: A gas processing plant, a chemi-cal plant and a refinery.

Here’s the basic program:First, a product called syngas, or syn-

thetic gas, gets made. The feedstock is

methane purified ofgas liquids and suchcontaminants as sul-fur and metals. If themethane hasn’t beenpurified before arriving at the GTL plant,the cleansing occurs there. Separately, airalso is processed to remove nitrogen andother elements to leave pure oxygen.Then the oxygen and methane are com-bined under ferocious heat and pressureto generate syngas — two atoms of

hydrogen plus one each of oxygen andcarbon, or H2 plus CO in chemistry lingo.The process binds the atoms together tocreate the syngas.

It sounds simple, but it’s not. In factthe syngas stage comprises perhaps 50percent or more of the GTL manufactur-ing cost. Air is superchilled (minus 292degrees) to separate out oxygen. Methaneand oxygen are combined under super-heat (2,000 degrees) and superpressure(perhaps 1,000 pounds per square inch).

It takes a fantastic amount of energy tomake gases that cold and that hot. Justthink of your air-conditioner bill during aheat wave or furnace bill during a coldsnap, then multiply by a “super” number.

(Syngas also can be made from coal orbiomass rather than methane.)

The second step flows syngas into areactor that makes synthetic crude, orsyncrude. A process called Fischer-Tropsch does this conversion. (More lateron Fischer and Tropsch’s role in history.)A variety of Fischer-Tropsch processesexist. Shell licenses one variation. Sasolanother.

Essentially, Fischer-Tropsch forces thesyngas under heat to react to a catalystthat accelerates the conversion into a liq-uid hydrocarbon. Typically cobalt is thecatalyst, but sometimes others get used,especially iron, which is cheaper but lessdurable.

At Shell’s gargantuan Pearl plant inQatar — the world’s newest GTL plant —cobalt is the catalyst. It’s distributedthroughout tens of thousands of tubes —each with microscopic inner channels —packed inside two 1,200-ton reactors. Thesurface of the cobalt is so vast that if itwere spread out horizontally it wouldencompass an area almost 18 timesgreater than Qatar itself, Shell says.

The Fischer-Tropsch step typicallyconsumes 25 percent or more of the totalGTL capital cost. The end result is thatsyncrude is made, sometimes called GTLwax or long-chain hydrocarbons.

This product then flows to step three.Essentially a refinery makes the finishedproducts. This step can total 15 to 25 per-cent of the cost.

As was said, the Fischer-Tropsch out-put is long-chain hydrocarbons — anexample would be 100 atoms of carbon— C100 — plus associated hydrogenatoms.

The refinery cracks apart these chainsinto such products as naphtha (C4 to C10,plus associated hydrogen atoms),kerosene (C10 to C13), diesel (C14 toC20) and so on.

This three-step processing adds apainful cost: Up to 40 percent of themethane that enters at step one burns upby the time GTL products exit after stepthree. By contrast, a liquefied natural gasplant might consume about 15 percent ofthe gas during production.

GTL operators can recoup some of thiscost by using the waste heat to power theplant, or sell waste carbon dioxide or sul-fur pellets, if they can find buyers.

But the short lesson is that gas-to-liq-uids manufacturing is spectacularlyexpensive.

Some champions of the industry sayan entire plant can be built for roughly$30,000 to $50,000 per barrel of outputper day (a 35,000 barrel-a-day plant thenwould cost about $1 billion).

That hasn’t been the reality.Construction delays are chronic. Costsescalate as the giant projects create theirown economic weather for engineering,labor, steel, shipping and other services.

Shell’s Pearl development cost an esti-mated $18 billion, or over $100,000 perbarrel of daily output. The spendingincluded costs for offshore platforms,wells and pipes as well as gas liquids pro-cessing.

Chevron’s Escravos plant in Nigeria isyears behind schedule, and at the new


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Better.

� N A T U R A L G A S

Can gas-to-liquids technology get traction?GTL has struggled to establish foothold, use of technology for stranded Alaska North Slope natural gas lacks has been floated

BILL WHITE

see GTL TRACTION page 11

http://www.nabors.com/

estimate of $8.4 billion will cost over$200,000 per barrel of daily output.

By comparison, a rule of thumb is thatbuilding a typical LNG plant costs about$45,000 per barrel equivalent of dailyoutput, according to global energy con-sultants Wood Mackenzie.

High cost, high riskThe spectacular and unpredictable cost

helps explain why so few GTL plantsexist. It’s the kind of cost and risk thatonly a few companies in the world willtake on.

The economics of GTL work bestwhen natural gas prices are low and oilprices are high. That creates an enviablecompetitive position: Feedstock is cheapand substitute products are expensive.That same dynamic let plastic trumppaper at the supermarket checkout.

When the reverse is true — gas isexpensive and oil is cheap — GTL can bea disastrous investment. That partlyexplains why, despite the world’s abun-dance of natural gas, few GTL plantshave opened.

Qatar is a special case. Two GTLplants started-up there in the past fiveyears. Qatar holds modest oil reserves fora Persian Gulf nation but is spectacularlyendowed with natural gas. The NorthField, the world’s largest natural gas field,lies offshore Qatar. It holds about 900 tril-lion cubic feet of natural gas, nearly 40times the size of Prudhoe Bay, Alaska’snatural gas crown jewel.

The two new plants are part of theQatar government’s bid to turn its naturalgas bounty into long-term wealth. Thegovernment is majority owner of bothplants, partnering with Shell for one andSasol for the other. Qatar provides the gascheaply to ensure the plants make money.

Nigeria GTL is another special casethat, as in Qatar, is an attempt to convertstranded gas reserves into cash. (Nigeriaalso started LNG exports in the pastdecade to monetize its natural gasresources.)

But the Nigeria plant under construc-tion also reflects a modern sentiment thatis driving some contemporary talk aboutthe need for more GTL production. Foryears Chevron has disposed of natural gasthat rises up its oil wells by flaring it orventing it into the atmosphere. In part todeflect condemnation of this practice —and government edicts to stop — thecompany is pursuing a GTL option. Butconstruction is years behind schedule andbillions over budget.

Among Chevron’s many woes in com-pleting the Escravos plant in Nigeria: Theproject has been plagued by maraudingkidnappers.

Dark historyTurning an idle resource into money

was not the original idea behind gas-to-liquids science, or that of its older brothercoal-to-liquids.

Fear was.In the early 1900s, coal was losing

steam as the fuel of choice. The automo-bile and airplane were showing that crudeoil, which mainly had been refined intokerosene, could be used as a transporta-tion fuel and in other new ways.Discovery of giant fields in Texas,Azerbaijan, Indonesia and elsewherespurred along the switch to oil. It also did-n’t hurt that oil packed more energy thancoal and burned cleaner.

Some countries well-endowed withoil, such as the United States, were well-positioned for an industrialized futurefueled by oil.

But German leaders were worried.Their country had plenty of coal but littleoil. Necessity focused the mind ofGerman scientists.

In 1913, just before World War I, agifted chemist named Friedrich Bergiusdeveloped a technique for liquefying coalunder high pressure. Bergius was award-ed a Nobel Prize in 1931. (Bergius laterturned his research toward obtainingsugar from wood cellulose. He died inArgentina after World War II.)

After Bergius’ breakthrough, coal-to-liquids fever seized German chemists. In1923 Franz Fischer and Hans Tropschdevised the alternate technique that bearstheir name.

German industry then advanced andcommercialized coal-to-liquids technolo-gy, helping allow Germany’s menacingterritorial expansion and the madness ofWorld War II that followed.

Coal-to-liquids plants provided wellover half of Germany’s wartime fuelneeds for its navy, army and air force.Germany built 12 plants based onBergius’ breakthrough by the end of thewar, and nine based on Fischer-Tropsch.(The chemical cartel IG Farben had aplant under construction at the Auschwitzconcentration camp at war’s end.)

The two technologies complementedeach other. Bergius’ hydrogenation madeaviation fuel and gasoline, and it was themore abundant approach. Fischer-Tropsch synthesis made diesel, lubricat-ing oil, waxes and lower-grade gasoline.

Japan’s war machine got into the coal-

to-liquids game, too. During the 1930sand 1940s, Japan’s quest for industrialnatural resources led to invasions ofChina and Southeast Asia. With more rawmaterials in hand, Japan chemists tried toperfect coal-to-liquids manufacture, buttheir efforts flopped.

Japan “did excellent laboratoryresearch on the coal hydrogenation(Bergius) and Fischer-Tropsch conver-sion processes, but in their haste to con-struct large synthetic fuel plants theybypassed the intermediate pilot-plantstage and failed to make a successful tran-sition from small to large-scale produc-tion,” according to a history of Japan’seffort.

As occurred in Germany and Japan,leaders in South Africa during the 1930srecognized that their nation was vulnera-ble to being left behind in an industrial-ized world. The country had no domesticoil reserves, but lots of coal.

That decade, South Africa flirted withoil-shale production, but produced littleoil that way. After World War II ended in1945, the government turned to coal-to-liquids conversion. Newly formed Sasolopened the first plant in Coalbrook —now called Sasolburg — in 1955.

Around the same time, a consortiumled by Texaco ran a small plant inBrownsville, Texas, using the Fischer-Tropsch process to make liquids from nat-ural gas this time, not coal. The consor-tium closed the plant in 1953 when natu-ral gas prices started rising.

Except for in South Africa, coal- and

gas-to-liquids essentially went into hiber-nation until the oil-price spikes of the1970s. Then, the U.S. Department ofEnergy poured funding into research. Butthose efforts faded when oil pricescrashed in the mid-1980s.

Meanwhile in South Africa, the coal-to-liquids industry kept the country ener-gized when international embargoes lim-ited oil imports during the 1970s and1980s due to the nation’s apartheid policyof racial segregation. South Africanindustry diversified into gas-to-liquidsafter finding offshore natural gas fields inthe 1980s. PetroSA, South Africa’snational oil company, opened a gas-to-liq-uids plant at Mossel Bay in 1992. Thatplant is the oldest of today’s GTL plants.

GTL for the future? With low North American natural gas

prices and high oil prices worldwide,Sasol is giving GTL a fresh look.

The South African fuel maker has twofeasibility studies under way. One is con-sidering a roughly $10 billion, 96,000-barrel-a-day plant in Louisiana usingplentiful U.S. natural gas. The otherwould involve a similar plant in westernCanada, tapping shale-gas fields there. (ACanadian partner recently bailed out ofthe Canada study.) The studies are expect-ed next year.

Last year Sasol also signed an agree-ment with the government of Uzbekistanto develop a GTL plant that would usethat land-locked Central Asia nation’sample gas reserves to lessen its oilimports.

What about GTL for Alaska’s 35 tril-lion cubic feet of stranded gas reserves atits North Slope oil fields?

That idea has been looked at but neverhas obtained much traction. ExxonMobil,the largest gas leaseholder on the NorthSlope, considered GTL in the 1980s and1990s. But now the company and its fel-low North Slope producers are looking atthe possibility of piping the gas to aSouthcentral Alaska liquefaction plant forLNG export.

BP’s demonstration plant at Nikiskifrom 2003 to 2009 was aimed at testing aGTL production technique that could beapplied elsewhere in the world, notspecifically at Prudhoe Bay.

An energy industry veteran namedRichard Peterson has been touting aNorth Slope GTL option without success



GTL TRACTION

Aerial photo of Shell’s Pearl GTL plant in Qatar.

CO

URT

ESY

SH

ELL

see GTL TRACTION page 12

http://www.emeraldnw.com/


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since the late 1990s. He believes the GTLprocess can be tweaked so that the plantwould specialize in supplying jet fuel forthe state’s international airports and mili-tary bases.

Last year, a study commissioned bythe Alaska Gasline Development Corp., astate agency, concluded that such a planttaking gas delivered by a smaller-diame-ter pipeline from Prudhoe Bay probablywouldn’t make enough money to attractinvestors.

Hatch, a global engineering consultantbased in Canada, looked at locating aGTL plant either near Anchorage orFairbanks that would make diesel, jet fuel

and naphtha for in-state use and export.Neither site would work, the study

concluded, even if the plant could sellexcess energy into the local electrical-power grid and waste carbon dioxide toproduce more crude from Cook Inlet-areaoil fields in Southcentral Alaska.

The plant would cost perhaps $3 bil-lion to build and almost $1 billion a yearto operate. The feedstock gas would haveto be almost free to make the plant’s eco-nomics work, Hatch concluded in itsreport for the state agency. �

Editor’s note: See part 1 of this storyin the July 15 issue of Petroleum News.

This is a reprint from the Office of theFederal Coordinator, Alaska Natural GasTransportation Projects, online atwww.arcticgas.gov/can-gas-liquids-tech-nology-get-traction.


GTL TRACTION

� E N V I R O N M E N T & S A F E T Y

Carbon captureproject gets nod


The Alberta government’s goal ofusing carbon capture and storage

technology to remove millions of tons ofcarbon dioxide from the atmosphere wasthrown life by its own regulator withoutending debate over the economic viabili-ty of the strategy.

The province’s Energy ResourcesConservation Board, ERCB, gave ShellCanada conditional approval for a C$1.35billion carbon capture and storage facilitynear Edmonton to permanently store 1.2million metric tons a year of CO2 fromthe company’s heavy oil upgrader.

However, while welcoming the deci-sion, Shell said it must still review theeconomics with its partners, ChevronCanada and Marathon Oil, before decid-ing later this year whether to proceed withthe Quest project.

The uncertainty surrounding one of thekeys to Alberta`s goal of becoming aworld leader in reducing greenhouse gasemissions remains firmly in place, lessthan three months after utility companyTransAlta, Enbridge and Capital PowerCorp. cancelled plans for their C$1.4 bil-lion Project Pioneer, which would havestored CO2 from coal-fired power plants.

That venture would have used C$436million in Alberta government money

over 15 years, but failed when the part-ners were unable to find buyers to use theCO2 for enhanced oil recovery.

Quest qualified for C$745 millionfrom the province and C$120 millionfrom the Canadian government to pipeliquefied CO2 to injection wells.

Further review requiredThe ERCB imposed 23 conditions,

while the proposal must still be reviewedby Alberta Environment and SustainableResource Development, which couldattach further conditions.

The regulator said the undergroundreservoir identified by Shell is a suitablelocation for the long-term storage of CO2and the plans “mitigate any potential risksthe project might pose.”

The federal government said Quest is“not likely to cause significant adverseenvironmental effects.”

Alberta Energy Minister Ken Hughessaid the province has yet to decidewhether to divert the money earmarkedfor Project Pioneer to other CCS projects.

He said three of the four initial proj-ects are still in various planning stages,indicating that carbon capture and storage“works for some; all you need is someoneto take on the challenges.” �


GOVERNMENTSenators urge U.S. Arctic strategy

Sen. Mark Begich, D-Alaska, and Sen. Lisa Murkowski, R-Alaska, have askedPresident Obama to prepare a U.S. strategy for the Arctic, tying together the policiesand visions of the multiple government agencies that deal with energy developmentand other Arctic opportunities.

President George W. Bush issued a brief Arctic policy paper towards the end of hisadministration, but since then “dozens of federal agencies have been working on vari-ous aspects of Arctic development and protection with little coordination,” the senatorswrote in a July 12 press release.

Other Arctic nations such as Canada and Norway have developed strategies identi-fying national needs and priorities, and setting goals for issues such as energy devel-opment, marine resources, Arctic infrastructure and vessel monitoring, the senatorswrote.

“Developing an American Arctic strategy is especially timely now, with the hope foroffshore oil and gas exploration in Alaska’s Arctic this summer. The number of cargoships transiting the Bering Strait is increasing to new record highs and America’sindigenous peoples are justifiably concerned with the impacts of these developmentsand changing conditions on their subsistence ways of life,” the senators wrote.

—ALAN BAILEY

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You probably know the state of Alaskahas raked in a lot of oil revenue over

the years. You might also know it standsto collect a lot more.

But on both counts, how much is a lot? Scott Goldsmith is here to tell us. The longtime economist with the

University of Alaska Anchorage’sInstitute of Social and EconomicResearch has put together the numbers ina five-page research note.

He begins by observing that 35 yearsago, on June 20, 1977, crude oil producedfrom state-owned land on the North Slopebegan flowing south through the trans-Alaska pipeline.

“Since then, the state has collected$170 billion in oil revenues, in today’sdollars,” he writes. “Petroleum (both oiland gas) still in the ground might gener-ate another $100 billion for the state.”

More than everGoldsmith retired June 30 but will

continue working part-time as a professoremeritus.

In his research note, he explains howstate oil revenue has been higher thanever in recent years, even though NorthSlope production now runs at less than athird of its 1988 peak of 2.1 million bar-rels per day.

“Oil revenues were high in the earlyyears of pipeline operation, because boththe throughput and the price of oil werehigh,” the note says. “In the seven-yearperiod from 1980 through 1986, the statecollected $47 billion in revenues, meas-ured in today’s dollars.

“But in the last seven years revenueshave been higher, in spite of lowerthroughput, due to a combination of thehighest oil prices on record and a restruc-tured production tax. Between 2006 and2012, the state collected $52 billion inrevenue. It collected close to $12 billionjust in the peak year of 2008.”

Alaska, of course, does have otherindustries, and other sources of revenue.But oil utterly dominates, Goldsmithexplains.

From 1977 to 2012, total state spend-ing was $177 billion, not including out-lays of federal dollars or state restrictedfunds. Of this amount, $159 billion or 90percent was from oil-related sources.

The oil revenue stream was so strongthat the state was able to eliminate its per-sonal income tax in 1980.

Where did it go?Oil accounts for 98 percent of state

natural resource revenues, dwarfing col-lections from other industries such asfishing and mining, Goldsmith writes.

In terms of what Alaska has done withits oil bonanza, the professor explains that$125 billion or 74 percent was spent ongovernment services and programsthrough the state’s general fund, with $45billion or 26 percent going into savingsaccounts such as the Alaska PermanentFund.

“The savings accounts have generated$46 billion of investment earnings overthe years,” Goldsmith writes.

His note is part of ISER’s Investing forAlaska’s Future research initiative, fund-ed by a grant from Northrim Bank.

Find the note online athttp://bit.ly/PT3Dph. �


www.doyon.com

Celebrating 40 Years of LEADING in All We Do

INTERNATIONALPipelines bypass the Strait of Hormuz

The United Arab Emirates and Saudi Arabia have each opened a new oilpipeline that bypasses the Strait of Hormuz, the sea route through which tankerscarry oil produced in the Middle East. Iran has been threatening to close the straitin response to international pressure over the Iranian nuclear program.

According to a report in the Financial Times the two new pipelines willincrease total pipeline capacity for bypassing the strait to 6.5 million barrels perday, about 40 percent of the daily volume of oil that passes through the strait.

The new United Arab Emirates pipeline links oil fields near Abu Dhabi withthe port of Fujairah in the Indian Ocean, while Saudi Arabia has converted anexisting natural gas pipeline to an oil line — that line runs from the Gulf coast toan oil terminal near Yanbu in the Red Sea, the Financial Times said.

—ALAN BAILEY

TNK-BP investors eye BP’s share in firmRussian shareholders TNK-BP, the

U.K. oil company’s joint venture inRussia, said July 18 that they are interest-ed in buying a 25 percent stake in thecompany.

TNK-BP, Russia’s third-largest oilproducer, is owned on 50-50 basis by BPand AAR, a consortium of Russian bil-lionaire shareholders. The company hasbeen mired in a lengthy dispute afterAAR blocked BP’s deal with anotherRussian oil company, Rosneft.

AAR said in a statement on July 18that it would like to buy a half of BP’s stake, or 25 percent of the company, at whatit described “a market price.” Based on the oil firm’s market valuation at Moscow-based MICEX exchange, a quarter share in TNK-BP is worth some $9.7 billion.

Although mired in boardroom disputes for much of its existence, TNK-BP hasgenerated healthy returns for both parties. Over the past years, TNK-BP’s output hasaccounted for more than a quarter of BP’s total global production. The British oilcompany drew some $3.7 billion in dividends from the venture last year alone,receiving a total of $19 billion since the company’s formation in 2003.

—ASSOCIATED PRESS


After 35 years, astaggering oil fortuneUniversity economist tallies just how many billions of bucks thestate of Alaska has collected, shows what became of the money

CO

URT

ESY

ISE

R


TNK-BP, Russia’s third-largestoil producer, is owned on 50-50

basis by BP and AAR, aconsortium of Russian

billionaire shareholders. Thecompany has been mired in a

lengthy dispute after AARblocked BP’s deal with anotherRussian oil company, Rosneft.


http://www.doyon.com/

By ERIC LIDJIFor Petroleum News

Acase before the Alaska SuperiorCourt could impact the relationship

between the State of Alaska and ancillaryinvestors in the oil and gas sector, partic-ularly smaller players.

The court is considering whether tohear an appeal from the small independ-ent Donkel Oil & Gas and its managingpartner Dan Donkel over a proposedCook Inlet unit.

After more than a year of delibera-

tions, the Alaska Department of NaturalResources denied the formation of theCohoe unit last September and upheldthe decision in May.

While it’s not uncommon for compa-nies to appeal unfavorable unit rulings,appeals typically come from leasehold-ers. But Donkel Oil & Gas holds nointerest in the leases proposed for uniti-zation and Donkel holds only an overrid-

ing royalty interest on them.An overriding royalty interest entitles

the holder to a cut of the production froma lease, but does not require the holder tofund operations or allow it to guidedevelopment, according to the state. Forthat reason, the state wants the court todismiss the appeal.

Regardless of his rights to the lease,though, Donkel stands to gain or losebased on the outcome of the case.Without unitization, the leases expireretroactively to late 2010.

State denied unit twiceThe saga over those leases goes back

nearly a decade.Donkel and fellow independent

investor Kenneth Mehaffey picked upthe two leases — ADL 390364 and ADL390365 — for a seven-year term in anOctober 2003 lease sale.

The onshore leases are near Kasilof,between Soldotna and Clam Gulch.

Donkel and Mehaffey eventuallytransferred their working and royaltyinterests in the leases to Aurora GasLLC, while each retaining a 1.5 percentoverriding royalty interest.

With the two state leases only a littlemore than two months from expiring,Aurora applied in July 2010 to form theCohoe unit over the two state leases andan adjoining lease owned by Cook InletRegion Inc. (The CIRI lease expired onAug. 17, 2011.)

The leases include the Cohoe UnitNo. 1 well Unocal drilled in 1973.

The unit request took more than ayear to process, because state officialswanted Aurora to submit a unit agree-ment that included both the state andCook Inlet Region Inc.

Two-year exploration planThe eventual unit agreement included

a two-year exploration plan whereAurora proposed re-entering the oldCohoe well and gathering new 3-D seis-mic data. Aurora wanted to look for nat-ural gas Unocal might have missed inthe search for oil.

The state ultimately denied the appli-cation. “The Cohoe unit plan of explo-ration does not demonstrate that unitiza-tion will encourage earlier delineationdrilling activities upon the subject leasesthan if these activities were conductedon a lease-by-lease basis, other than toprovide Aurora an extension to the leas-es’ primary terms,” Division of Oil andGas Director William Barron wrote in aSeptember 2011 ruling. “(Earlier)drilling operations on any one of theseleases would have extended the drilledlease’s primary term.”

Aurora appealed, but in May DNRCommissioner Dan Sullivan said it was“not in the state’s interest to allowAurora to retain the leases and benefitfrom the lease term extensions providedby unitization without having demon-strated the need for unitization.”

Donkel appealed the case to theAlaska Superior Court in June.

On its points of appeal, Donkel saidthe state erred when it said Aurora failedto demonstrate the existence of a reser-voir at Cohoe, and also erred by claim-ing the unit was not in the public interestand claiming Aurora hadn’t proven theneed for unitization.

Could establish precedentThe state made its argument against

the Donkel appeal using existing statuteand code, and referencing case law fromother cases in Texas concerning overrid-ing royalty interests, but also acknowl-edged the Alaska Supreme Court hasnever decided “whether ORRIs havestanding to enforce the terms of a leaseor appeal DNR decision related to alease.”

In at least two cases from the pastdecade, though, the Alaska SupremeCourt discussed the question as part of alarger matter, attorneys for the statewrote in court filings.

Donkel filed his response to the stateafter Petroleum News went to print. �


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FINANCE & ECONOMYNon-OECD demand to exceed OECD in ’13

The International Energy Agency is now predicting that in 2013 oil demandfrom developing countries will for the first time overtake that of developed coun-tries in the Organization of Economic Cooperation and Development. Thecrossover in demand will likely take place in the second quarter of 2013, theagency said in its July Oil Market Report.

For some time oil demand has been climbing steadily in developing countries,especially in China, as the economies of these countries grow and there is anincreasing demand for liquid fuels, particularly for transportation. At the sametime, demand in the developed world has slackened as developing countries copewith the aftermath of the 2008 financial crisis and the subsequent economic reces-sion.

In the United States, characterized in the report as the largest global consumerof oil, demand for oil products has continued to decline in 2012. The sharpestreductions were seen in residual fuel oil and naphtha demand, with gasolinedemand dropping less as the mileage travelled by U.S. car drivers moves towardssome lower limit, the agency said.

In China, characterized as the largest single source of oil demand growth, oilconsumption has eased back so far in 2012 but demand growth is expected toresume in the second half of the year, the agency said.

Key uncertainties in predicting future world oil demand include the ramifica-tions of the European debt situation and the problems in the European MonetaryUnion, and continuing concerns about the momentum of both the U.S. and theChinese economies, the report says.

—ALAN BAILEY

� L A N D & L E A S I N G

Donkel challenging Cohoe rulingDonkel appealing Cohoe unit denial; state believes Donkel’s overriding royalty doesn’t give him standing before the court

Without unitization, the leasesexpire retroactively to late 2010.

Contact Eric Lidji at [email protected]

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

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Gateway project, Kinder Morgan’s plan toexpand capacity of its Trans Mountain sys-tem from Alberta to Vancouver and propos-als by Enbridge and Trans Canada to startcarrying crude from Alberta to EasternCanada and the Atlantic coast.

Delay tacticsTactics the British Columbia govern-

ment could use to delay Northern Gatewaywould include requiring the NorthernGateway twin pipelines to pass under thehundreds of streams and creeks they musttraverse, or introducing a new rule mandat-ing public hearings in communities thatwould be affected by the pipeline.

The province could also mount a courtchallenge of the National Energy Boardproceedings if they resulted in approval forNorthern Gateway, effectively raising theproject costs to prohibitive levels or simplystalling progress to the point where Asiancustomers would look elsewhere for theircrude.

Adrian Dix, leader of the BritishColumbia New Democratic Party and aclear favorite to win next year’s provincialelection, has assembled a legal team to findways to stop Northern Gateway.

“We’re looking at all of the options theprovince might use,” he said, but would notdiscuss specifics.

Under extreme pressure to take a standon Northern Gateway, British ColumbiaPremier Christy Clark finally issued a warn-ing to Enbridge about Northern Gateway inthe wake of severe criticism by U.S. regula-tors about Enbridge’s handling of its 2010pipeline spill in Michigan.

“I think the company should be deeplyembarrassed about what unfolded (in

Michigan),” she said. “If they think they’regoing to operate like that in BritishColumbia, forget it.”

Clark said Enbridge needs to be askedmore pointed questions about its operatingpractice “if they think they want to do busi-ness here.”

Confusing NDP messageDix’s ally, federal New Democratic

Party leader Thomas Mulcair, made a whis-tle-stop visit to Western Canada to declarethat the U.S. National Transportation SafetyBoard report on the Michigan spill was “thefinal nail in the (Northern Gateway) coffin.”

But he caused confusion in Calgary byconceding that Alberta oil sands producersneed wider market access for their produc-tion.

“Should we be looking for positive waysto find markets for oil from the oil sands?Of course we should. That’s part of our obli-gation,” Mulcair said. “Alberta’s companiesin order to properly evolve and develophave to have access to other markets.”

He made no attempt to identify whatmarkets he was referring to, or how thatcrude would be delivered.

In the face of what Enbridge PresidentAl Monaco described as “unrelenting oppo-sition,” he and Janet Holder, the executivevice president in charge of NorthernGateway, focused on easing fears about theproject and leaving the door open to discus-sion.

Monaco said Enbridge has made signifi-cant improvements to its safety proceduresin the wake of the 2010 spill, includingchanges to leak-detection systems.

He also said “we need to engage com-munities early and often and do a better jobof explaining the benefits (of pipelines) atthe local level. We need to put the public atease and give them confidence that we can

operate safely.”Holder, conceding Enbridge is engaged

in a struggle in British Columbia, said thecompany will continue seeking ways tohelp residents “understand that we can buildthis pipeline in a very safe, reliable and sus-tainable way.”

Bruce March, president and chief execu-tive officer of Imperial Oil, which plans todouble its output to 600,000 barrels per day

by 2020 through investments totaling C$22billion in the oil sands, said he is confidentpipelines will be available when needed.

“Pipeline access is the best approach. It’sthe cheapest, it’s got the least environmentalrisk when you transport oil over long dis-tances,” he said. �


� G O V E R N M E N T

Administration seeks taxes consultantRFP out for expert economic analysis, requests identification of issues with current oil taxes that might limit industry investment

By BECKY BOHRERAssociated Press

The Parnell administration, criticized for rushing abill into the special session this year that some law-

makers considered ill-conceived, is seeking a new con-sultant to advise it on oil and gas taxes.

The Department of Revenue is soliciting proposalsfor a consultant to provide expert economic analysis.The consultant will be asked, among other things, toidentify issues with the current oil and gas tax structurethat might limit industry investment in the state and tomake recommendations for improving the existing sys-tem.

Revenue is “not automatically jumping to, ‘We see aproblem.’ We do see a problem, but we want them tocome to us, with what they see the issues are and someproposals and fixes that might be possible,” deputyRevenue commissioner Bruce Tangeman said July 13.

Gov. Sean Parnell, who sees cutting production taxesas a way to boost industry investment and declining oilproduction, failed in efforts to get his oil tax-cut planspast the Legislature during regular and special sessionsthis year and last.

The proposal quickly put together by the administra-tion before this year’s special session — building off atax break on new oil production passed by the Senatenear the close of the regular session — was criticized bylawmakers in both parties as ill-conceived. Some law-makers also deemed Revenue Department officials, whocarried the bill, unprepared.

Consultants frequently hiredIt isn’t unusual for either the administration or

Legislature to hire outside consultants to aid in work onhighly technical oil and gas issues. Senators, who tookthe lead on oil taxes this year after refusing to act on aParnell tax plan last year, looked to consultants as they

worked to draft an oil tax plan. The state also recentlyextended for six months a contract it has had withGaffney, Cline & Associates, Tangeman said.

The goal with the solicitation is to “get a fresh per-spective on the situation Alaska’s in,” Tangeman said.

The contract would run for two years, beginningAug. 20, with an optional one-year renewal. The budg-et for the work is estimated between $400,000 and$700,000, though Tangeman said July 13 he’s not surehow far that money will stretch. He said it’s probablynot enough to last until this time next year.

“We do see this (oil taxes) coming up next year, butthe funding is limiting us right now to how far down thisroad we can walk,” he said.

Besides oil taxes, which remain a top priority forParnell, the Legislature also could face issues related to agas pipeline project. Parnell has said that if all the mile-stones he has set out for a project are accomplished, theLegislature can take up the issue of gas taxes next year. �

LAND & LEASINGDNR finds no substantial new sale info

The Alaska Department of Natural Resources issued a decision of no substan-tial new information July 13 for this fall’s Beaufort Sea, North Slope and NorthSlope Foothills areawide oil and gas lease sales.

DNR issued a call for new information in February; the comment period closedin March.

The Division of Oil and Gas was looking for any substantial new informationthat had become available since the best interest findings for the sales wereissued: in 2009 for the Beaufort Sea; in 2008 for the North Slope; and in 2011 forthe North Slope Foothills.

Best interest findings are good for 10 years once issued; substantial new infor-mation is requested annually prior to sales.

DNR Commissioner Dan Sullivan said in the decision that the departmentreceived comments from Peter McKay of Kenai on the sales stating that the Feb.15 blowout at Repsol’s Qugruk No. 2 well set a new benchmark for well blowoutresponse in the Arctic during winter and stating that the state must develop leasestipulations and mitigation measures ensuring that the permit holder does a betterjob of responding to and controlling releases of oil and gas when they occur.

Supplement not justifiedThe Division of Oil and Gas said in the decision that the current findings con-

tain lessee advisories alerting lessees that the Alaska Department ofEnvironmental Conservation requires an approved oil discharge prevention andcontingency plan before operations can begin. The division that that plan mustinclude a response action plan describing how a spill response would occur, a pre-vention plan describing spill prevention measures at the facility and supplemen-tal background and verification information.

The division said the comments do not mention “any research, studies, or datadirectly relevant to the matters listed” in statute that have become publicly avail-able over the last year, and therefore do not contain or reference substantial newinformation justifying a supplement to the current findings.

A date for the sales has not been published, but the division has indicated itplans to coordinate the sales with the U.S. Bureau of Land Management’s 2012National Petroleum Reserve-Alaska oil and gas lease sale and BLM has said thatsale is planned for November.

—PETROLEUM NEWS


PIPELINE PRESSURE

EXPLORATION & PRODUCTIONUS oil, gas rig count down by 12 to 1,953

The number of rigs actively exploring for oil and natural gas in the U.S. wasdown by 12 the week ending July 13 to 1,953.

Houston-based oilfield services company Baker Hughes Inc. reported that1,427 rigs were exploring for oil and 522 for gas. Four were listed as miscella-neous. A year ago, Baker Hughes reported 1,905 rigs.

Of the major oil- and gas-producing states, New Mexico gained seven rigs,North Dakota and Wyoming gained three and Oklahoma gained one.

Texas lost 17 rigs, Louisiana lost five, Colorado lost three and Alaska andCalifornia each lost one.

Arkansas, Pennsylvania and West Virginia were unchanged. The rig count peaked at 4,530 in 1981 and bottomed out at 488 in 1999.

—ASSOCIATED PRESS



Calista Corp. donates $10,000 to senior centerCalista Corp. said July 13 that it has

authorized a $10,000 donation to bemade to the Eddie Hoffman SeniorCenter in Bethel, Alaska. Bethel is thehub community for the large Yukon-Kuskokwim Delta region, a region thatis approximately 10 percent of the landarea of Alaska. The Y-K region is hometo approximately 24,000 people andmore than 6 percent of the populationis 65 years of age or older, according to 2010 State of Alaska DCED data.

To celebrate the donation Calista and the center will hold a brief ceremony on July 31 at10:30 a.m. at the Senior Center. Calista staff members will also provide a photo booth sothat each elder can have a portrait photo taken. Calista will arrange to have keepsake 8x10inch photos printed and sent to the center. Calista staff will also be on hand to acceptupdates of shareholder information, necessary to provide Calista shareholders withnewsletters, dividends and other special mailings.

Owned and operated by the Orutsararmiut Native Council, the Bethel Native tribal cor-

poration, the center provides a host of services to the elders in the community. Services areprovided in part through nutrition, transportation and support services grant funding.Extremely high heating and electrical costs strain the center’s budget and limit services.

Hengen named new president of NANA WorleyParsonsNANA WorleyParsons said July 13 that Rock Hengen, a veteran engineer with more than

two decades of experience in project management, engineering, construction, maintenance,startup and operations has been named its new president.

Hengen joined NANA WorleyParsons in 2009 and previously held the position of NANAWorleyParsons’ vice president Project Delivery and general manager. He holds a MastersCertificate in Project Management from the University of Lethbridge in Canada. Hengensucceeds Allan Dolynny, who is the new general manager for Western Operations ofWorleyParsons USAC (United States and the Caribbean).

“Like his name implies, Rock brings a significant and distinguished background of lead-ership roles in the delivery of both large and small projects in the oil and gas industry,”said Helvi Sandvik, president, NANA Development Corp.

NANA WorleyParsons provides multidisciplinary engineering and design, project man-


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see OIL PATCH BITS page 19

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how dire the situation in the NationalPetroleum Reserve-Alaska really is, and Ithink shed a little bit of light on thehypocrisy that is on display here in thefederal government,” Murkowski saidduring the committee hearing, which veryfew senators attended.

Failure to clean up the wells “just con-tinues the failed and broken promises thatthis federal government has made to thestate of Alaska,” she said.

“While the federal government rightful-ly demands proper environmental steward-ship on development in Alaska, and oftenuses its administrative powers to delay —stop — our responsible developers in thename of environmental protection, it turns ablind eye to its own environmental disas-ter,” Millett said. “This hypocrisy outragesAlaskans and should outrage allAmericans.”

Foerster, chair of the Alaska Oil and GasConservation Commission, said many lega-cy well sites are out of compliance withstate regulations. Her agency has been try-ing to obtain data on the wells from theBLM.

U.S. Sen. Joe Manchin, D-W.Va., askedFoerster what would happen to a privatesector operator who left behind sites like thelegacy wells.

“They would be fined out the yazoo,”she replied, flicking her left pinkie as shetalked. “Excuse me, they would be finedexcessively, and we would refuse toapprove permits to drill for them.”

Finding the moneyMurkowski and Millett emphasized that

the federal government certainly has themoney, if not the will, to clean up the lega-cy wells — and to not take years and yearsto do it. They noted the government hadcollected $9.4 billion from lease sales in theNPR-A and on Alaska’s outer continentalshelf.

Cribley told the committee his agencycould put together a plan “as big as the sky”to plug legacy wells, but obtaining themoney through the budgeting process “isprobably remote, at least from our perspec-

tive.”Committee chairman Sen. Jeff

Bingaman, D-N.M., said the legacy wellsituation “cries out for an earmark,” aremark that drew laughter and agreementfrom his colleagues. Congressional ear-marks have fallen out of favor politically inrecent years.

Offering a “point of clarification,”Cribley told the committee the federal gov-ernment has netted only $125 million fromlease sales in the NPR-A in the past decade.Of that, $86 million was spent remediatinglegacy wells.

Plugging plans The BLM has plugged 18 wells since

2002, Cribley said. The Navy plugged onewell in 1952.

In 2004, the BLM did an inventory ofthe legacy wells. It identified a number thatposed a potential hazard, but found thatmany sites presented no significant threat.

For example, 34 wells are uncased coretests that didn’t penetrate producing oil andgas zones and are now “naturallyreclaimed,” the BLM says. It plans to askthe AOGCC to remove these from the lega-cy well list.

The BLM has dealt on an emergencybasis with several wells jeopardized byextreme erosion along the Beaufort Seacoast.

The agency is now preparing an updatedlegacy well inventory, and has a strategy toaddress 13 legacy wells over three seasons.

The BLM plans to plug the Iko Bay No.1 well, and two nearby wells, during thewinter of 2013. The Navy drilled the 2,733-foot Iko Bay No. 1, about 15 miles south-east of Barrow, in 1975.

Foerster told the Senate committeethat North Slope Natives have dubbed IkoBay No. 1 “the whistling well,” becausethe wellhead is leaking natural gas. �



LEGACY WELLS

EXPLORATION & PRODUCTIONTundra opens for authorized summer travel

The Alaska Division of Mining, Land and Water said July 18 that it has openedNorth Slope tundra to authorized off-road travel by summer-approved off-roadvehicles.

The division said the opening applies only to operators with valid off-roadvehicle travel permits for state-owned North Slope lands. Approvals are issued ona case-by-case basis, the division said, and operators need to contact the divisionprior to each off-road travel event.

Only vehicles tested and approved for summer travel by the division areauthorized to access tundra and operators are required to avoid damaging tundra.The division has stipulations for summer off-road vehicle travel which provideguidelines.

For information contact the division’s northern regional office at 907-451-2740 or its North Slope office at 907-659-2830.

—PETROLEUM NEWS

FINANCE & ECONOMYOil tops $91 for 1st time since late May

Oil prices rose above $91 a barrel forthe first time since late May July 19 onsigns of increased demand in the U.S.and amid rising tensions in the MiddleEast.

Early in New York, benchmark crudewas up $1.56 at $91.43 a barrel. Theprice has risen about $14 per barrel sinceoil hit its low for the year three weeks ago.

U.S. drivers are seeing a corresponding increase at the pump. A gallon of regu-lar gas now costs an average of $3.44, up 11 cents from July 1.

The Energy Information Administration reported July 18 that average oildemand increased the week ending July 13 in the U.S. for the third week in a row.The escalating conflict in Syria and renewed tensions between Iran and Israel arealso contributing to oil’s rise.

—ASSOCIATED PRESS


The agency is now preparing anupdated legacy well inventory, and

has a strategy to address 13legacy wells over three seasons.

U.S. drivers are seeing acorresponding increase at thepump. A gallon of regular gasnow costs an average of $3.44,

up 11 cents from July 1.

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criticism over the snafu in which theNoble Discoverer dragged its anchor atDutch Harbor, coming perilously close tothe shore.

Sea iceShell has told Petroleum News that the

unusually heavy Chukchi Sea ice, whichis delaying the start of the company’sdrilling into August, is the most signifi-cant factor in causing the drilling fleet toremain in a holding pattern. The companyhad originally hoped to move its fleetnorth through the Bering Strait in earlyJuly.

The Coast Guard has cautioned that it

will take at least until July 20 to “see somemovement” on the barge certificationissue. And assuming that the barge iseventually certified for its intended use,the vessel will still need to travel north tojoin the rest of Shell’s fleet.

The need for certification of the bargearises from the fact that Shell commis-sioned modifications to the vessel toaccommodate the new Arctic containmentsystem that the company plans to deploy,ready to move into action to contain oilspilling from an out-of-control well in theunlikely event of a well blowout. TheCoast Guard needs to certify that the bargeis seaworthy for its intended purpose —certification, among other things, involvesinspecting the vessel and conducting a testto ensure that new equipment installed onthe barge has not adversely impacted the

vessel’s stability.

Certification standardApparently, the Coast Guard inspection

brought to light some mechanical defi-ciencies, including some deficient welds,with those deficiencies needing to be cor-rected before certification. However, thebiggest problem with the certificationappears to be a request to change the stan-dard under which the vessel is to be certi-fied. At the end of last year the CoastGuard had provisionally agree to certifythe vessel under the standard for a floatingproduction installation. But in early JulyShell informed the Coast Guard that thevessel could not meet the requirements ofthat standard and asked, instead, for certi-fication under the standard for a mobileoffshore drilling unit. The Coast Guardneeds to determine whether the requestedstandard is appropriate to the vessel’sintended use and, if so, whether the vesselphysically meets the standard.

The issue of drilling permits to Shell bythe Bureau of Safety and EnvironmentalEnforcement is contingent on the contain-ment barge being in operation.

Air permitsIt is also not yet clear what impact, if

any, the requested changes to the air per-mits will have on Shell’s plans. TheKulluk is operating under a minor air per-mit that allows Shell to continue operatingthe vessel while EPA reviews the request-ed change, with EPA having 90 days inwhich to make a decision over the changerequest.

Noble Discoverer, on the other hand, isoperating under a major permit — EPAhas said that changes to that permit requirepublic review before approval and imple-mentation. Shell has said that the request-ed changes are minor in nature, involvinga small increase to the permitted ammoniaand nitrous oxide emissions from the ves-sel’s generator engines, with total emis-sions from the vessel remaining below

permitted levels. The company has saidthat it is working with EPA to obtain acompliance order that would enable thevessel to operate this summer, while trig-gering a review process for the modifiedpermit for subsequent years.

Noble DiscovererThe incident on July 14 in which the

Noble Discoverer dragged its anchor,coming close to the shore near DutchHarbor, has become the subject of muchdebate in the media, with people question-ing whether the vessel had in fact runaground, and also questioning how longthe incident had lasted.

Apparently a tug, stationed by Shell insupport of the Noble Discoverer, hadmoved into action, towing the drilling ves-sel back into deep water after the vesselhad drifted towards the shore. Although,according to a report in the AnchorageDaily News, one eyewitness claimed thatthe drifting of the drilling vessel had takenplace over a period as long as two hours,Shell vehemently denies that claim.

A second vessel, the Harvey Gulf, wasalongside the Noble Discoverer at the startof the incident and it took 28 minutes fromthe time when the Discoverer was report-ed to have slipped anchor to the time whenbrought the Discoverer under tow, Shellspokesman Curtis Smith told PetroleumNews in a July 17 email.

Hull inspectionsPhotos and eyewitness accounts of the

Discoverer apparently very close to shorehave given rise to the speculation aboutthe possible grounding of the vessel.According to media reports Shell says thatit used a remotely operated vehicle toinspect the vessel’s hull after the incidentand found no evidence of a grounding.Since then divers have also confirmedthose initial findings, Smith toldPetroleum News.


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SHELL DRILLING

see SHELL DRILLING page 19

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Shell's floating drilling platform, the Kulluk. The Kulluk in Dutch Harbor, being maneuvered by the Crowley tug Guardsman.

http://www.canrig.com/

Point to Homer High School, a 6-inch plas-tic main running 3.5 miles to East End Roadand a 4-inch plastic main running 1.6 milesto Kachemak City.

Gas in fall of 2013Enstar expects to build the pipeline in

2013 and begin offering service later thatfall.

Enstar originally drafted the Homer sur-charge in 2004, during a previous attempt tobring gas to the region. At the time, the proj-ect involved a 4-inch plastic line running 11miles at a cost of $3.5 million. The sur-charge would have also paid off the projectin 10 years.

Even though ratepayers will now becovering a smaller cost than they wouldhave in 2004, Enstar still expects the $1 sur-charge to take about 10 years to pay backthe project costs.

The reason is Enstar expects to sell lessgas now than it envisioned selling in 2004.

“We have done a lot of independentanalysis on consumption over the last fiveyears to better understand our customersand their gas consumption for supply analy-sis and load forecasting,” Enstar spokesmanJohn Sims told Petroleum News by email.“Most of the buildings in the area are notlarge consumers and comparable buildingsin other areas around our service territoryshow they will consume less gas than orig-inally forecasted.”

Additionally, Enstar believes increasedconservation awareness efforts are chang-ing consumption habits. “Enstar has seen asignificant reduction in gas use due to con-servation and people building tighterhomes, which also will lower consump-tion,” Sims added.

Progress in NikolaevskThe project is one of two expanding nat-

ural gas access in the southern KenaiPeninsula.

Despite technical qualms, state regulato-ry staffers are in favor of moving along aproposal to connect Nikolaevsk to theregional natural gas transmission system.

Under a deal signed earlier in the year,Enstar Natural Gas Co. intends to build ashort pipeline branching off the AnchorPoint Energy LLC-owned North ForkPipeline.

As outlined, the project involves using a

$447,000 state grant to build a regulatorstation and a two-inch mainline running8,930 feet to the Nikolaevsk CommunitySchool.

The Regulatory Commission of Alaskainitially rejected the application to create aninterconnection, saying Anchor PointEnergy did not provide enough informationabout the project, or the financials of itsowners, to meet regulatory requirements. Inits second application, Anchor PointEnergy addressed the issues, but also askedthe RCA to waive certain reporting require-ments and keep some financial informationconfidential.

Anchor Point Energy is a subsidiary ofArmstrong Oil & Gas Inc. and its partnersat the nearby North Fork unit, all smallindependents. Anchor Point Energy askedfor its owners’ financials be kept confiden-tial, saying the risk of a competitive orfinancial disadvantage if the recordsbecame public would “outweigh the publicinterest.”

Although it called sections of theAnchor Point Energy application “poorlywritten” and “poorly supported,” the RCAstaff said existing regulations could justifythe waivers.

According to the analysis, “there is apublic interest in facilitating this applica-tion” and “operational costs and character-istics are not likely to be significantlyimpacted by the interconnection,” and sothe RCA should grant the waivers andaccept the application.

Interconnection requiredWith prompt approval, Enstar believes it

could connect Nikolaevsk in time for com-munity institutions and residents to converttheir heating systems before winter.

Nikolaevsk is home to some 308 people,according to the most recent state estimates.

While the school is expected to be thelargest customer, Enstar expects the initialbuild out to also include the community firestation and 12 homes. Enstar could poten-tially extend the line 1,700 feet to connect acommunity church and nine additionalhomes.

In addition to the public benefit,Armstrong Cook Inlet is required to con-nect Nikolaevsk to the transmission grid inorder to meet the terms of its unit agree-ment at North Fork.

—ERIC LIDJI


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FROM THE JUNGLES OF BRAZILTO THE NORTH SLOPE OF ALASKA

DESIGN.BUILD.DELIVERCHALLENGES ARE OUR SPECIALTY

agement, project controls, procurement and construction management to the oil and gas,power and mining industries. Headquartered in Anchorage, about half of its staff workson the North Slope in customer field operations facilities providing plant engineeringservices. The remaining staff works in Anchorage.

Nabors to implement shareholder rights plan Nabors Industries Ltd. said July 17 that its board of directors has adopted a sharehold-

er rights plan under which shareholders will receive rights to purchase shares of a newseries of preferred stock. The rights will expire on July 16, 2013, unless extended or earli-er redeemed or exchanged by Nabors pursuant to the terms of the plan. Further detailsabout the plan will be contained in a current report on Form 8-K to be filed by the com-pany with the Securities and Exchange Commission.

As previously announced, the company has responded to shareholder requests bydeclassifying its board of directors and adopting a director-resignation policy for directorsfailing to obtain a majority of votes cast in an uncontested election. The plan adopted bythe board is designed to ensure the fair and equal treatment of the company’s sharehold-ers in connection with any initiative to acquire effective control of the company. It isintended to reduce the likelihood that any person or group would gain control of Naborsby open market accumulation or otherwise without paying a control premium for all com-mon shares. Because the rights may be redeemed by the board under certain circum-stances, they will not prevent the board from considering any transaction that is deter-mined by the board to be fair, advisable and in the best interests of all the company’sshareholders.

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


OIL PATCH BITS

“Divers have confirmed the NobleDiscoverer did not run aground afterslipping anchor in Dutch Harbor,Alaska,” Smith wrote in his email. “Weappreciate the effort the Coast Guardhas made to investigate this incidentand will apply any learnings from thatinvestigation to future operations. Ourgoal remains flawless operations andthis is an incident Shell and NobleDrilling take very seriously. While weare pleased with the speed and effec-tiveness of the mitigation measures wehad in place, even a ‘near miss’ is unac-ceptable.”

U.S. Coast Guard Petty Officer 1stClass David Mosley told PetroleumNews in a July 18 email that the CoastGuard had been on hand during Shell’sdiver inspection of the NobleDiscoverer and that the Coast Guard

concurs with the conclusion that therewere no signs of damage to the vessel.

“While this is not conclusive evi-dence that the vessel did not comeashore, it does suggest that if it did itwent soft aground resulting in no dam-age,” Mosley wrote.

The Coast Guard investigation of theincident is continuing and may takeweeks, or even months, to complete, hewrote. �


GAS TO HOMER continued from page 18

SHELL DRILLING

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Shell's new ice-class anchor handler, theAiviq.


http://www.matsystems.ca

Development and Export Authority,Kenai Offshore Ventures bought theTransocean Adriatic XI jack-up rig lastSeptember for $68.5 million and renamedit Endeavour — Spirit of Independence.The rig has since been undergoing repairsand upgrades at the Keppel FELSShipyard in Singapore.

While in Singapore, the rig underwent“substantially” more work thanBuccaneer originally planned, accordingto the company. Those additionalupgrades include increasing the lifeboatcapacity to meet new U.S. regulations,improvements allowing Endeavour to beused as a standby rig for activities in theBeaufort and Chukchi seas, pushing upwork planned for next winter to accom-modate the Cosmopolitan drilling pro-gram, and work to extend its certificationwith the American Bureau of Shipping.

With the upgrades, Endeavour canoperate in water depths up to 300 feet inboth Cook Inlet and the Arctic Ocean.The rig includes two sets of blowout pre-venters, both 10,000 and 15,000 PSI.Additional upgrades allow the rig to carryheavier-than-usual loads and to performdrilling or repair operations in conjunc-tion with existing platforms.

New capital infusionBuccaneer also recently said it is rais-

ing another $13.5 million for its Alaskaoperations.

The company said July 18 that it hadexecuted binding agreements for the issueof 292,682,927 shares in the company toraise a total of $12 million and a SharePurchase Plan to eligible shareholderscapped at $1.5 million.

The capital will go toward onshore,offshore and exploration ventures inAlaska.

The placement will take place in twoparts. The first, to raise some $5.8 mil-lion, will take place immediately. Thesecond, to raise some $6.2 million, is sub-ject to shareholder approval. Buccaneerexpects to hold a general meeting some-time in late August.

Zenith Securities Pte Ltd andAugsburg Investments Ltd have each sub-scribed to 48,780,488 shares in the firsttranche, each corresponding to a 4.3 per-cent interest in Buccaneer, according tothe company. Zenith and Augsburg willjointly hold a non-executive seat on theBuccaneer board as part of a “long termstrategic relationship.”

The remaining shares in the $12 mil-lion placement were “supported by exist-ing institutional shareholders and a rangeof new international and domestic institu-tions and sophisticated investors and washeavily oversubscribed,” according toBuccaneer.

“The company is about to embark on asignificant period of activity and growthin its Alaskan operations and to do thiseffectively will require the companyforming solid business relationships notonly within Alaska but also globally,”Buccaneer Director Dean Gallegos said.“The company’s ability to complete alarge equity capital raising relative to itssize is confirmation of the strong underly-ing strength of its Alaskan projects andbusiness plan. We look forward in work-ing with Zenith and Augsburg to maxi-mize and monetize the value of theCompany’s asset base for the benefit ofall shareholders.”

Offshore and onshore workBuccaneer plans to use the capital for a

variety of projects.Those include drilling another devel-

opment well at the onshore Kenai Loop

project, progressing its offshore explo-ration efforts, completing its acquisitionof a 25 percent interest in theCosmopolitan project, funding its 50 per-cent stake in its rig-operating subsidiaryKenai Offshore Ventures and paying forgeneral day-to-day operations.

The initial effort will focus on “maxi-mizing production delivery” at KenaiLoop, Gallegos said. Buccaneer broughtthe onshore gas field online in Januaryand plans to drill an additional develop-ment well at the field this summer. “Tooptimize its capital expenditure program,offshore exploration will be phased to fol-low the development of its onshore KenaiLoop project,” Gallegos added. “Toreduce operational expenditure while thecompany focuses on its Kenai Loopdevelopment, the company will seek tocontract out the recently acquiredEndeavour jack-up rig to third party oper-ators.”

Under its unit agreements, Buccaneermust drill one well each at its SouthernCross and Northwest Cook Inlet units bySept. 30, 2012, or lose the units. “Weintend meeting our commitments beforeleasing out to third parties,” Gallegos toldPetroleum News.

Although Kenai Offshore Venture andAIDEA based their business case for buy-ing the rig on Buccaneer projects, theyalways intended to lease the rig out tothird parties.

Southern Cross sits between theGranite Point and Trading Bay oil fields.Northwest Cook Inlet lies on the north-west side of ConocoPhillips’ North CookInlet gas field.

The infusion of capital also allowsBuccaneer to close on Cosmopolitan.

Buccaneer and BlueCrest Energy II,LP, a privately held energy company outof Fort Worth, Texas, purchased two off-shore leases at the prospect from PioneerNatural Resources Alaska Inc. inFebruary and initially anticipated closingas soon as March 30.

Through the deal, Buccaneer wouldacquire a 25 percent interest in the leases.

The Cosmopolitan leases are offAnchor Point, in the southern KenaiPeninsula. �


Serreze said. “This is just a matter ofthe regional patterns of variability andwhat you are seeing there is just whatthe effects of the weather patterns havebeen this year.”

Record lowsAccording to NSIDC, June saw an

especially rapid melt of sea ice acrossthe Arctic, with record low sea-iceextents occurring for brief periods inthe middle of the month.

“Strong ice loss in the Kara, Beringand Beaufort seas, and Hudson andBaffin bays, led the overall retreat,”NSIDC wrote in its report for June.

A field worker from the ColdRegions Research Laboratory makingmeasurements in landfast ice in the

Beaufort Sea offshore Barrow reportedice that was thicker than had beenobserved in previous years but that wasmelting relatively rapidly, NSIDC said.

At 4.24 million square miles theArctic sea ice extent in June was456,000 square miles below the 1979to 2000 average. By the end of June theice extent had dropped to a level thatwould normally be expected on July21, thus putting the ice melt about threeweeks ahead of its long-term averageschedule, the NSIDC report says.

This year’s June ice extent was thesecond lowest since satellite ice obser-vations began in 1979, with 2010 hav-ing the lowest June extent. The Arcticsea ice extent decline since 1979 istrending at 3.7 percent per decade.

—ALAN BAILEY


ICE CONDITIONS


BUCCANEER JACK-UP“The company is about to embarkon a significant period of activity

and growth in its Alaskanoperations and to do thiseffectively will require the

company forming solid businessrelationships not only within

Alaska but also globally.”—Buccaneer Director Dean Gallegos



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