exploration & production alaska at the front · 2008. 11. 26. · extremely complicated,”...

Trimming the sails in Alberta; Suncorto cut billions, says CEO Rick George

Vol. 13, No. 44 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of November 2, 2008 • $2

● 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

● G O V E R N M E N T

B R E A K I N G N E W S

4 Reacting to an Arctic oil spill: In-situ burning technique of

choice in sea ice; drift ice conditions present significant challenges

7 Dalmatian further proves up gas: Reserve in eastern U.S.Gulf estimated at more than 100 bcf; tie back development planned

12 Alaska grew proved reserves in ’07: Led nation in newoil reserves; showed gas growth but could face competition to market

Heavy-duty protection

Nanuq/AFC’s crane, and workers, installing slope protection inAugust for Eni’s Nikaitchuq Spy Island Drill Site, in shallow statewaters off Oliktok Point on Alaska’s North Slope. Each four-cubic-yard gravel bag weighs 13,000 pounds.

Alaska at the frontShell’s Odum says the state is central to future U.S. energy supplies

By ALAN BAILEYPetroleum News

laska is central to the question ofwhere the United States will obtainits future energy resources. Andthat’s critical to the issues of ener-

gy security and the need for major newresource development, Marvin Odum,president of Shell Oil Co., toldPetroleum News Oct. 23.

“The big picture for me is what does Alaskachoose to do with that. Do they choose as a state todevelop that area?” Odum said. “… I see this asthe bellwether on where we’re going on the energychallenge.”

Currently, progress on Shell’s plannedoffshore Alaska exploration drilling liesin the hands of the U.S. Court of Appealsfor the 9th Circuit.

More than a year after the courtplaced a temporary injunction on Shell’sBeaufort Sea drilling, the court has stillnot ruled on an appeal by the North SlopeBorough, the Alaska Eskimo WhalingCommission and several environmentalorganizations against the U.S Minerals

Management Service’s approval of Shell’sBeaufort Sea exploration plan. The court heardoral arguments in the case on Dec. 4, 2007.

AMARVIN ODUM

see ODUM page 18

Conoco files tariffsConocoPhillips asks for higher intrastate rates on TAPS; Tesoro protests

By ERIC LIDJIPetroleum News

nother debate over pipeline tariffs could beon the horizon.

In filings with state regulators in earlyOctober, ConocoPhillips proposed increasing

the rate shippers pay to move oil along the trans-Alaska oil pipeline to destinations within the state.The Regulatory Commission of Alaska is respon-sible for these intrastate rates, as opposed to inter-state rates for oil leaving the state which are set byfederal regulators.

North Slope crude bound for in-state marketstypically ends up at refineries in North Pole andValdez, which sit along the pipeline, or a refineryin Nikiski, accessed by tanker.

The newly proposed intrastate rates, whichConocoPhillips asked to go into effect on Nov. 1,would increase shipping charges to those intrastatemarkets by around 55 percent.

Being flexibly inflexibleAlberta won’t shift from Jan. 1 for higher royalties; will discuss economic strains

By GARY PARKFor Petroleum News

he Alberta government won’t budge from itsplan to impose higher royalties in two months,despite a nosedive in resource prices andreports pointing to a sharp decline in natural

gas production and revenues.Energy Minister Mel Knight said the province

will stay the course, scuttling any industry hopesof a reprieve in tough times, although he did say“trouble spots” are under review.

He said the “door is always open to discussissues with our industry partners,” conceding therehas been an economic upheaval in the last month.

Knight said “constructive, progressive” propos-als will get a hearing from him, but the Jan. 1,

2009, implementation date is fixed.Asked if the “open door” could see changes to

the new royalty regime, he replied: “No, what I’msaying is that we don’t always know all of theanswers.

“What we’re looking at is the economic pressure

see ROYALTIES page 17

TOne of the few suggestions to help the

Alberta government out of its impasse hascome from Michael Tims, chairman of

investment dealer Peters & Co., who saidthe new royalty structure could remain inplace along with a royalty holiday for a

set period to stimulate investment.

JUD

Y P

ATR

ICK

Kvisle: commercial work priorityHow is TransCanada’s work on an Alaska gas pipeline

progressing? Hal Kvisle, the company’s president and CEO, said dis-

cussions with the North Slope producers— whose gas will be crucial to a suc-cessful project — are continuing.

The bill approving TransCanada’slicense for an Alaska gas pipeline underthe Alaska Gasline Inducement Act wassigned by Gov. Sarah Palin in lateAugust. TransCanada has begun “thenext stage of engineering, environmen-tal, field and commercial work andexpect(s) to conclude an open season byJuly 31, 2010,” Kvisle said Oct. 28 dur-ing an analysts’ call on the company’s third-quarter results.

Kvisle said TransCanada expects the Alaska commission-ers of Revenue and Natural Resources to issue the AGIA

HAL KVISLE

see TRANSCANADA page 19

A“The State is concerned that the

increased tariff rates (and the underlyingcomponents of that rate) that

[ConocoPhillips] is requesting willsignificantly impact tariff rates after theTAPS Settlement Agreement is no longerin effect.” —Attorney General Talis Colberg in a filing

before the Regulatory Commission of Alaska

see TARIFFS page 15

http://www.PetroleumNews.com/

contents Petroleum News A weekly oil & gas newspaper based in Anchorage, Alaska

2 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2008

INTERNATIONAL

PIPELINES & DOWNSTREAM

LAND & LEASING

4 How to respond to an Arctic oil spill

In-situ burning is the technique of choice for cleaning up oil in sea ice, but drift ice conditions present significant challenges

5 EnCana, Nexen on the lookout

EnCana prepared to step up drilling with lower costs; Nexen flush with cash, no plans to look for capital, in position to acquire

7 Dalmatian further proves up eastern gas

Reserve in eastern U.S. Gulf of Mexico estimated at more than 100 bcf; development plans call for tie back to existing structure

6 More consolidation in Pt. Thomson cases

Judge Gleason leaves administrative action to run its course; does not appoint mediator, holding on settlement discussions

8 Looking for geologic links on North Slope

DGGS-led team is finding evidence for how the geologyand petroleum systems in different parts of the North Slope hook together

10 Trimming the sails — Alberta reversals

Suncor, Petro-Canada mull cutbacks, deferrals, hold out hope of better times, even in 2009; closure of U.S. refineries predicted

14 Gas OPEC: An idea going nowhere fast

Russia, Iran, Qatar form technical committee to discuss gas policy; long-term LNG sales contracts obstacle to powerful cartel

12 Alaska grew proved reserves in 2007

Alaska led the nation in new oil reserves and showedgrowth for gas, but could face competition bringing new resources to market

EXPLORATION & PRODUCTION

FINANCE & ECONOMY

6 Lawmakers hold 2nd gas price hearing

7 Corrosion suspect in gas line rupture

10 Syn-fuel project on hold

12 Industry grows in importance as employer

SAFETY & ENVIRONMENT14 Flint Hills refinery sets safety record

ON THE COVERAlaska at the front

Shell’s Odum says the state is central to futureU.S. energy supplies

Conoco files tariffs

ConocoPhillips asks for higher intrastate rates on TAPS, Tesoro protests

Being flexibly inflexible

Alberta won’t shift from Jan. 1 for higher royalties; will discuss economic strains

Kvisle: commercial work priority

1.1

1.3

1.2

http://www.bristowgroup.com/

PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2008 3

http://www.shiplynden.com/


veryone hopes that it will never hap-pen. But how would people respond toan oil spill in the offshore Arctic?

In the Arctic the presence of sea iceand snow can make the techniques for oildetection and recovery very different fromthose used in a marine spill in warmer cli-mates.

At the United States and CanadaNorthern Oil and Gas Research Forum inAnchorage, Alaska, on Oct. 28, Arctic oilspill response expert Ian Buist of S.L. RossEnvironmental Research Ltd. summarizedthe results of 20 to 30 years of research intodealing with an oil spill in Arctic offshoreconditions.

Complicated“The behavior of oil spilled on ice is

extremely complicated,” Buist said. The fateof the oil depends on factors such as the iceconditions and whether the oil lies above orbelow the ice, he said. And oil on icebehaves differently from oil on water.

“Oil spilled on top of ice or on snowspreads much, much more slowly and stays

much thicker than when it’s spilled onwater,” Buist said. “Thicknesses on ice are100 times more than they are on water.”

And any snow on the ice will rapidly andeffectively absorb oil, he said.

Oil discharged below sea ice will floatupward to accumulate in pools on the bot-tom surface of the ice. Downward growth ofthe ice will then encapsulate the oil as layerswith the ice sheet. The oil will later emergeduring the spring melt, rising through brinechannels or becoming exposed as the icemelts downward from the surface.

Oil spilled on water between ice floesmay be contained by the floes, depending onthe concentration of ice on the water surface— in high ice concentrations floes tend totouch, thus forming natural boom structures.

Delineating the oilWhen it comes to delineating the extent

of an oil spill, the spill responders can effec-tively locate oil on or under landfast ice —stable ice that is attached to the coast —using techniques such as ice coring, aerialsurveys or subsurface ice inspection bydivers, Buist said. Ground penetrating radaris also showing considerable promise as atechnology for locating oil in or under land-fast ice, he said.

And the successful recovery of oil fromthe surface of landfast ice can be achievedby the direct pumping of oil from oil pools,or by the manual scraping out of oil that hasbecome absorbed in snow.

But locating oil in pack and drift ice ismuch more challenging, especially duringwinter freeze up, when limited daylight andsmall temperature differences between theoil and ice make visual and infrared detec-tion techniques difficult to apply.

However, the good news is that once thelocation of oil in ice is known, the oil can betracked for extended periods of time by sim-ply tracking the ice movements.

“You just have to track the ice. The oilstays with the ice,” Buist said.

And whereas containment of the oil, toprevent the oil spreading over wide areas, isa prime consideration in open water, con-tainment is not generally an issue when seaice is involved.

“Spills on ice are naturally contained bythe ice and snow structures,” Buist said.“Additional containment is not usuallyneeded.”

Low ice concentrationsHowever, containment and recovery of

the oil can be difficult when ice concentra-tions are low. Even quite small quantities ofice floating on the sea surface can playhavoc with a conventional cleanup involv-ing the gathering of oil using boom — theboom tends to collect and concentrate theice, which can then disrupt the boomingoperation or prevent skimmers from remov-ing the oil from the water.

Current research is investigating the useof some novel techniques such as underwa-ter bubble barriers and chemical herdingagents to address the question of gathering

oil in relatively low concentrations of float-ing ice, Buist said.

The main issue for the subsequent recov-ery of spilled oil from around floating ice,once the oil has been contained in someway, is the speed at which skimmers canmove through the oil slick in ice-ladenwater.

“All of the recovery devices available forspills in drift and pack ice are extremelylimited in the rate at which they canencounter oil,” Buist said.

There are skimmers that have beendesigned for use in pack and drift ice. Butbecause these skimmers can only pick up oilalong a 2- to 3-meter-wide path, as opposedto the 200- to 300-meter-wide path of aboom and skimmer system used in openwater, oil recovery rates tend to be low.

Research continues in the developmentof new skimmer designs, Buist said.

In-situ burningHowever, in-situ burning has become the

technique of choice for removing oil thathas been spilled around, under or on sea ice,Buist said. Research experiments and expe-rience from actual spills has shown thatburning can remove from 60 percent to 80percent of the oil. That compares withrecovery rates of perhaps 15 to 20 percentfrom a conventional open water spillresponse using boom and skimmers, hesaid.

“Unless a net environmental benefitanalysis indicates that burning would causemore harm than good, in situ burning is thecountermeasure technology of choice forlarger spills in ice conditions,” Buist said.

Even oil mixed with up to 70 percent ofsnow can be burned, he said. And where oilis trapped in ice, responders would haveplenty of time to plan a burn operation forthe spring melt, when the oil would appearat the ice surface.

However, current research is focusing onthe question of how to ensure that an oilslick on water is thick enough to ignite insituations where there is too much ice todeploy fire boom but too little ice for the icefloes to corral the oil, Buist said.

The past five years have seen a programto test the use of chemical herder agents togather the oil for burning in this type of sit-uation, Buist said. The herder chemical issprayed in small quantities onto the wateraround the oil. The herder changes the prop-erties of water in a way that causes the oilslick to contract into small areas.

Four sets of experiments have evaluatedthe feasibility of the technique. In one testthe herder increased the thickness of theslick by a factor of 10 and the subsequentburn removed 90 percent of the oil, Buistsaid.

On the other hand the use of chemicaldispersants, to disperse the oil into the watercolumn, has not yet been proven in sea iceconditions, Buist said. Current research inthis area includes the use of stern-driven ice-breakers to mix the water-oil-dispersantcombination, he said. ●


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How to respond to an Arctic oil spillIn-situ burning is the technique of choice for cleaning up oil in sea ice, but drift ice conditions present significant challenges

“Unless a net environmentalbenefit analysis indicates that

burning would cause more harmthan good, in situ burning is thecountermeasure technology ofchoice for larger spills in ice

conditions.” —Ian Buist of S.L. RossEnvironmental Research

E

http://www.panalpina.com/


nCana and Nexen, two of Canada’slargest oil and gas independents, aredoing their utmost to put some shineon a gloomy outlook, figuring they

will not only ride out the current financialstorms, but could emerge larger than before.

EnCana Chief Executive Officer RandyEresman said his company is “very well-positioned” to handle the challenges stem-ming from the collapse of financial mar-kets.”

“Our strategy has positioned us very wellto withstand the impact, to adapt and topotentially react,” he said.

The market volatility could open the doorto acquisitions, although “at this early, earlystage I think it’s moreprudent for compa-nies to start trying tounderstand all of theimplications beforeacting too quickly,”Eresman said.

However, he alsosaid EnCana is pre-pared to step up itsdrilling to take advan-tage of lower costs,although its plans won’t be rolled out untilthe mid-December release of its 2009 capi-tal spending.

“We’ll be taking a measured approachwith an increased focus on capital preserva-tion as appropriate given current marketconditions,” he said.

During the second quarter EnCana pro-duced an average 3.9 billion cubic feet perday of gas, up 8 percent from a year earlier,and 133,600 barrels per day of oil, off 2 per-cent.

Chief Financial Officer Brian Fergusonsaid 1.6 bcf per day of gas production hasbeen hedged at an average US$9.30 perthousand cubic feet, about one-third morethan current prices, propping up a largeshare of its cash flow. It also has contractssetting a floor price of US$8.65 per thou-sand cubic feet.

Despite the success of the hedging pro-gram, Eresman injected a cautionary note,saying “market conditions have created agreat deal of uncertainty for the supply-demand balance in the future.

“We believe it is prudent to be conserva-

tive in the short termwith our capital pro-gram until we get abetter understandingabout how it will turnout,” he said.

Eresman saidEnCana’s hedging“gives us significantprotection for cashflow next year. Butthe unhedged amountis variable and our anticipation is that over-all cash flows will be reduced in 2009.”

Given that EnCana has been managing tofeed a maximum 90 percent of its cash flowinto its capital program, he said that in itselfwill “cause us to choke back a bit on theamount that we spend out of core capital.”

However, he said EnCana must firstcomplete its analysis over the next twomonths, which could identify a “greatopportunity to increase our drilling.”

Nexen flush with cashNexen is flush with cash from earlier

high oil prices, has available bank lines ofcredit, decades before its outstanding bondscome due and no plans to look for more cap-ital, putting it in an ideal position to takeadvantage of any acquisition opportunities,said Chief Financial Officer MarvinRomanow.

He said Nexen has solid businesses in theNorth Sea and the Alberta oil sands and isramping up its spending in BritishColumbia’s shale gas plays, adding “thoseare the kinds of places where (the company)might have some choices going forward.”

The company has the first, C$6.1 billionstage of the Long Lake project behind it,although the official launch on Oct. 23,despite blue and red balloons and an array ofhonored quests, was slightly tarnished bythe absence of synthetic crude.

The 50-50 joint-venture with OPTICanada involves the use of patented tech-nology to convert bitumen into high-gradelight synthetic crude, but the gasificationphase of the upgrading process has beendelayed by at least one month.

Chief Executive Officer Charlie Fischersaid he is not distressed by the upgraderhitches.

“The good news is that we aren’t findingany things that are showstoppers. When wechose the day for the launch, we had no idea

if we’d have synthetic crude or not and wedidn’t care.”

Alberta Energy Minister Mel Knightpraised Long Lake’s environmental fea-tures, noting it will use salt water from wellsand recycle 90 percent, while its new tech-nology will enhance carbon capture andstorage.

“This project helps us point the way tothe future ... there are great opportunities forenergy development — not just hydrocar-bons — across this province,” he said.

Husky: costs outpace inflationHusky Energy, in releasing its third-quar-

ter results, said the global financial crisis“has reduced liquidity in financial markets,restricted access to financing and causedsignificant volatility in commodity prices.”

“These will impact the performance ofthe economy going forward. However, com-

panies with strong cash generation fromoperations, availability of cash and cashequivalents, low debt with long maturitiesand unused committed credit facilities willbe better positioned to manage through thiscrisis.”

Husky warned that rising costs acrossthe board are outpacing inflation, affect-ing the cost of operating oil and gas prop-erties, processing plants and refineries,while capital projects are susceptible tocost volatility. ●


● F I N A N C E & E C O N O M Y

EnCana, Nexen on the lookoutEnCana prepared to step up drilling with lower costs; Nexen flush with cash, no plans to look for capital, in position to acquire

E

Randy Eresman,EnCana CEO

Nexen CEO CharlieFischer

ANCHORAGE FAIRBANKS KENAI

Fabrication at your fingertips.Full fabrication facility with multiple liner materials in stock

“We believe it is prudent to beconservative in the short term

with our capital program until weget a better understanding about

how it will turn out.” —EnCana CEO Randy Eresman

NATURAL GASDenali to headquarter on N. Lights

Denali—The Alaska Gas Pipeline LLC has selected space in the new 188 W.Northern Lights Building in Anchorage as its headquarters. The company said Oct. 30that it has reached an agreement to lease some 40,000 square feet in the new building,enough space for 175 people.

“We are excited to have secured Denali’s headquarters office in Anchorage,” DenaliPresident Bud Fackrell said in a statement. “This is another step in moving the projectforward.”

Denali spokesman Dave MacDowell told Petroleum News the company willremain in temporary offices at 36th Avenue and 711 H Street until December orJanuary. He said timing will depend on completion of the office interiors at the newbuilding.

Denali, a joint venture of BP and ConocoPhillips, is planning for the construction ofa pipeline to deliver 4 billion cubic feet of natural gas a day from the North Slope ofAlaska to markets in the Lower 48, Alaska and Canada.

Denali is staffing its management and leadership teams, as well as a portion of itstechnical team, with employees from BP and ConocoPhillips, the company said on itsWeb site. Workers required to gather field data as well as design and construct thepipeline will largely be from the contractor community.

—PETROLEUM NEWS

http://www.equipmentsourceinc.com/

By KRISTEN NELSONPetroleum News

damages suit by Exxon Mobil Corp.against the State of Alaska over thetermination of the Point Thomsonunit was rolled into the consolidated

Point Thomson case by Superior CourtJudge Sharon Gleason Oct. 23. A separateadministrative action pending before theDepartment of Administration was not con-solidated.

The Department of Natural Resourcesterminated the Point Thomson unit in a dis-pute with the working interest owners overan appropriate plan of development and themajor owners — ExxonMobil, BPExploration (Alaska), Chevron U.S.A. andConocoPhillips Alaska — are appealingDNR’s decision.

The court granted a 30-day extension forfiling briefs, which had been due Oct. 29,while denying a request for a status hearingto determine a new briefing schedule. Anattorney for ExxonMobil argued the courtshould grant the request for a schedulingconference “and reject the Department of

Natural Resources’ request to treat this atyp-ical case as a routine one.” DNR’s attorneysaid appellants were not asking for “adefined extension of time” but for an entire-ly new briefing schedule to be set after a sta-tus conference to be held at “some unspeci-fied time in the future.”

The court also denied a motion for a set-tlement conference and a court-appointedmediator, but “without prejudice to renewalof the motion by any party if informal set-tlement discussions are unsuccessful inresolving the parties’ dispute.”

Court cites common issuesIn consolidating the Superior Court dam-

ages suit with the other appeals the judgesaid: “There are common issues of law andfact involved in ExxonMobil’s damageappeal that warrant consolidation of thataction with this case.” The judge agreedwith the state’s assertion that “consolidationof the damages appeal should ‘allow thecourt system and the parties to administerthe Point Thomson Unit litigation in a moreefficient manner than would be the case ifthe eighth appeal were litigated separately.’”

ExxonMobil requested a stay of its dam-ages claim until final outcome of its applica-tion for review to the Department ofAdministration and final outcome on allremaining issues on appeal before theSuperior Court. The state opposed thatmotion, telling the court it wanted briefingon all issues. The judge stayed the damagesclaim, but only until the Department ofAdministration reached a final determina-tion on ExxonMobil’s application for reviewand any appeal, or until the appeal periodexpired.

But the judge denied ExxonMobil’smotion to stay its damages claim until allremaining claims currently on appeal beforethe Superior Court were completelyresolved. “The interests of judicial economyand the timely resolution of all of the issuesbetween the parties mitigate against such astay,” the judge said.

Where to try issuesThe state accused ExxonMobil of

“attempting to create confusion” by filingfor damages administratively and in court.The state argued that the damages argu-ments “belong in this appeal as part ofExxonMobil’s direct administrative chal-lenge to DNR’s unit termination decisions.”

“Notably, none of the other appellantsshare ExxonMobil’s alleged confusion andhave not joined ExxonMobil in its waywardjourney through the Alaska legal system,”DNR’s attorneys said Oct. 8.

Attorneys for ConocoPhillips Alaska, BPExploration (Alaska) and Chevron U.S.A.responded Oct. 23 that “DNR’s contentionas to the other appellants’ reasons for notjoining ExxonMobil in the damages pro-ceedings is presumptuous, incorrect andinappropriate.”

Attorneys for the other appellants saidthey share ExxonMobil’s view that Alaskalaw governing claims for damages againstthe state is “a mess.”

“Alaska law on this point is confusing, ifnot confused,” they told the court.

The overlying issue, they said, on whichall appellants agree, is that the department’sclaim for termination of the Point Thomsonunit agreement “for default must be broughtin Superior Court as an original action.” Theproceeding in Superior Court is an appealfrom a decision by the Department ofNatural Resources, not an original action.

If the case had been brought as an origi-nal action, the appellants’ attorneys said,

“the Superior Court would have originalexclusive jurisdiction over all claims arisingfrom the transactions and occurrences DNRalleges in support of its claim for termina-tion” of the Point Thomson unit, includingany claims against DNR for “wrongfulrepudiation” of the unit agreement.

Talks ongoingIn required updates on the status of set-

tlement talks attorneys for the appellantssaid ExxonMobil, BP Exploration (Alaska),Chevron U.S.A. and ConocoPhillips Alaskahad filed a motion for a settlement confer-ence in July, requesting that DNR “engagein settlement discussions” on the appeal ofthe termination of the Point Thomson unit;DNR said it was willing to engage in settle-ment discussions.

Appellants wanted a mediator appointedand in early September the judge said theparties could submit names of up to threemediators or settlement judges with theirstatus reports, due Oct. 15.

Appellants said Oct. 15 that “settlementdiscussions have commenced and are ongo-ing” and submitted three names: ElaineAndrews and Brian Shortell, both retiredjudges, and attorney Blythe Marston.

They requested the prompt appointmentof a mediator “so that the mediator canbegin to receive and review backgroundmaterials and settlement communicationsamong the parties. Appellants believe thatthe complexity and lengthy procedural his-tory of this dispute are likely to requireunusually extensive preparation by themediator,” and that prompt appointment of amediator would “facilitate the mediator’sefficient and effective involvement, shouldinformal discussions fail to progress.”

In its status report DNR said it “is inactive settlement negotiations” and notedthat the parties had met twice and werescheduled to meet again that day.

DNR objected to appointment of a medi-ator, calling it “premature to ask the court toappoint a mediator because the parties areengaged in ongoing discussions. The par-ties’ efforts are better focused on the cur-rent process.”

Time spent selecting and briefing amediator would divert resources for thediscussions the parties are having, DNRsaid, and “might also derail the ongoingdiscussions by undermining the parties’incentive to participate in the informalsettlement process.” ●


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PIPELINES & DOWNSTREAMLawmakers hold 2nd gas price hearing

State lawmakers are not finding easy answers in their investigation into highgasoline prices.

After a second hearing Oct. 23, they still have more questions than answers asto why Alaskans pay 70 to 90 cents more per gallon than drivers in Seattle orHawaii.

State Rep. Jay Ramras says the problem does not lie with retailers. The Fairbanks Republican says that leaves the distributor and the refineries

and lawmakers can’t seem to “peel the onion back” to find answers. Senior Assistant Attorney General Ed Sniffen says there is no price gouging

law in Alaska that says they have to charge any specific price. The Attorney General’s office conducted a similar gasoline investigation in the

late 1990s that produced inconclusive results. —THE ASSOCIATED PRESS

● L A N D & L E A S I N G

More consolidation in Pt. Thomson casesJudge Gleason leaves administrative action to run its course; does not appoint mediator, holding on settlement discussions

A

http://www.coscofire.com/

By RAY TYSONFor Petroleum News

hree U.S.-based exploration andproduction independents — opera-tor Murphy Oil and partnersNewfield Exploration and Mariner

Energy — have further proven up thenatural-gas-rich area along the Central-Eastern Gulf of Mexico border with theirrecently announced deepwater Dalmatiandiscovery on DeSoto Canyon block 48.

Dalmatian is the latest of a long stringof significant dry gas discoveries since asmall portion of the Eastern Gulf, knownas the Sale 181 area, was opened to fed-eral leasing in December 2001.Production from many of the these dis-coveries was routed to nearbyIndependence Hub, the largest gas devel-opment in the U.S. Gulf, with around 1billion cubic feet of daily capacity.

Murphy, to comply with the U.S.Securities and Exchange Commission’sstringent rules governing oil and gasreserve reporting, may have purposelyunderestimated Dalmatian’s true reservepotential to appease the SEC, indicatedDavid Trice, Newfield’s chairman andchief executive officer.

Trice, responding to an analyst’s ques-tion during Newfield’s third-quarterearnings conference call on Oct. 22, saidMurphy reported estimated Dalmatiangas reserves of between 60 bcf and 70bcf. “We get a higher number ... probablya bit north of 100 bcf,” Trice added.

The Dalmatian exploration well wasdrilled in just under 5,900 feet of waterand found 120 feet measured depth of“net high quality natural gas pay,”Murphy said, adding that current plansare to develop the well as a subsea tieback to existing infrastructure in the area,presumably Independence Hub. Murphy,in addition to operating the Dalmatianwell, is the majority owner with a 50 per-cent working interest.

However, while Dalmatian wasdubbed a success, Murphy alsoannounced that its 100 percent-ownedand operated Manhattan explorationwell, just south of DeSoto Canyon on

Lloyd Ridge 511, was unsuccessful andwas plugged and abandoned.

Mariner has area discoveriesScott Josey, Mariner Energy’s chair-

man, president and chief executive offi-cer, said the Dalmatian discovery, inwhich the company holds a 12.5 percentinterest, “leveraged off” previousMariner discoveries in the region,specifically at Swordfish in VioscaKnoll and Aconcagua in MississippiCanyon.

“The success at Dalmatian bodes wellfor our additional lease holdings in thearea, which consist of working interestsranging from 10 to 12.5 percent in fiveprospects on nine contiguous blocks,” heexplained, adding that another one of itsdeepwater prospects, Heidelberg, isexpected to spud in November on GreenCanyon block 859.

Newfield said that in addition to its37.5 percent working interest inDalmatian, the company owns workinginterests between 23 percent and 50 per-cent in nine contiguous blocks offsettingthe Dalmatian discovery.

“We have five additional amplitudeprospects in the area that we are evaluat-ing for future exploration and develop-ment potential,” the company said.

Other major gas discoveries in theEastern Gulf include Spiderman (DeSotoCanyon 620 and 621), San Jacinto(DeSoto Canyon 618), Atlas Northwest(Lloyd Ridge 5), Atlas (DeSoto Canyon50), Mondo Northwest (Lloyd Ridge 1and 2) and Cheyenne (Lloyd Ridge 399).Discoveries in the Central Gulf just westof the Sale 181 area include Jubilee(Atwater Valley 305 and 349), Vortex(Atwater Valley 261) and Merganser(Atwater Valley 37). ●



Dalmatian furtherproves up eastern gasReserve in eastern U.S. Gulf of Mexico estimated at more than

100 bcf; development plans call for tie back to existing structure

Dalmatian is the latest of a longstring of significant dry gas

discoveries since a small portionof the Eastern Gulf, known as the

Sale 181 area, was opened tofederal leasing in December 2001.

T

SAFETY & ENVIROMNENTCorrosion suspect in gas line rupture

BP’s old bugaboo, corrosion, might have struck again in the giant Prudhoe Bay oilfield. The oil company suspects corrosion contributed to a pressurized natural gaspipeline blowing apart on Sept. 29, BP spokesman Steve Rinehart said.

No one was hurt, though some workers were in the vicinity when the line rupturedviolently, hurling a length of pipe across the tundra.

Automated safety systems and field workers rushed to shut down the pipeline,which was 8 inches in diameter and carried gas for shooting underground, part of atechnique to help coax out additional crude oil.

The incident forced the shutdown of two well pads producing about 5,000 barrelsof oil per day — less than 1 percent of total North Slope oil output. The pads remainedout of service Oct. 24.

BP will do a metallurgical analysis of the failed pipe before declaring corrosion asthe culprit for the rupture, Rinehart said. Some possibilities have been ruled out, hesaid, such as a bad weld.

Investigators found the corrosion had attacked the outside surface of the above-ground pipe at a point where insulation that normally jackets the line was missing,Rinehart said.

Moisture had wicked beneath the exposed insulation and come into contact withthe steel, causing corrosion that can eat through metal and weaken a pipeline, he said.

As a safety measure, BP workers will look for any pipes that might be in a similarcondition, Rinehart said.

State and federal pipeline regulators are investigating the pipeline rupture.BP runs Prudhoe, the nation’s largest oil field, on behalf of itself and other owners

including ConocoPhillips and ExxonMobil.Corrosion has bedeviled BP since 2006, when oil leaks from major Prudhoe

pipelines drew intense regulatory and congressional scrutiny of the London-basedcompany. The lines were found to be riddled with corrosion.

The leaks ultimately forced BP’s Alaska subsidiary to plead guilty to a federal mis-demeanor pollution crime. A judge put the company on probation for three years andimposed $20 million in penalties.

BP executives acknowledged lapses in pipeline maintenance, but since have saidthe company is investing hundreds of millions of dollars to replace miles of badpipelines and improve upkeep.

Corrosion is a common industrial threat and a constant worry at Prudhoe with itsvast maze of pipelines and processing plants that have been producing oil since 1977.

—WESLEY LOYAnchorage Daily News

http://www.arcticfoundations.com/

Editor’s note: This article originallyappeared in the Oct. 12 edition ofPetroleum News. We are reprinting itbecause the original version contained anincorrect diagram.


t shouldn’t come as much of a surpriseto anyone that Alaska’s North Slopeholds some world class petroleum sys-tems in its subsurface geology. But, as

oil and gas exploration moves away fromthe Prudhoe Bay region where major oildiscoveries have been made in the past,there are many as yet unanswered ques-tions over how the various rock strata linktogether across the vast expanses ofnorthern Alaska.

And answers to those questions couldprove crucial in determining likely loca-tions for future oil and gas discoveries.

DGGS projectIn the past couple of years Alaska’s

Division of Geological and GeophysicalServices has led a team of geologistsworking an area of the east-central NorthSlope, around the Haul Road near HappyValley, to unravel the regional geologiclinkages. In many ways the east-centralNorth Slope is a linchpin area, connectingthe geology of the National PetroleumReserve-Alaska to the west with that ofthe Arctic National Wildlife Refuge to theeast, and with the geology of the PrudhoeBay area to the north.

The investigation in the Happy Valleyarea is the continuation of a multi-yearDGGS-led geologic investigation that hasworked its way along the northern side ofthe Brooks Range and in the BrooksRange foothills, using surface rock expo-sures to obtain information about rocksthat extend into the subsurface under theNorth Slope. These rocks include strati-graphic units equivalent to the reservoirand oil source rocks of the prolific NorthSlope oil fields.

And whereas geologic informationobtained by oil companies typicallyremains commercially confidential,

DGGS is able to find and publish publicdomain geologic information that isavailable for anyone interested in oil andgas exploration. The division’s NorthSlope program receives funding from thefederal government, the state and fromindustrial sponsors.

Geologic mappingIn the summer of 2008, as part of the

investigation of the Happy Valley area,DGGS geologist Bob Gillis led a surfacegeologic mapping effort in that area,Marwan Wartes, DGGS program managerfor the North Slope and Brooks Rangefoothills, told Petroleum News Sept. 22.

“That was really a big focus for most ofthe time we were out there, collecting thatbasic geologic information,” Wartes said.

The mapping area included the LupineNo. 1, Echooka No. 1, Ivishak No. 1 andAufeis No. 1 wells, all drilled between1972 and 1975, and was close to the Susiewell, drilled in 1966.

There is also some publicly availableseismic data for the area immediatelynorth of where the DGGS team did itsmapping, Wartes said.

“That is a big, big help in decipheringthe stratigraphy and the approximate(rock) thicknesses we’re likely to be deal-ing with,” he said.

Working from discontinuous rock out-crops along river cuts and, in some cases,picking out major geologic features usingaerial photographs, the team measuredand recorded detailed information aboutthe rocks.

It’s actually been known for manyyears that the area includes sandstoneswith deep oil stains. And some of thesestains can be smelled from as far away as100 yards, Wartes said. The geologistsengaged in the 2008 fieldwork also foundmany instances of light oil staining of thesandstones, he said.

“It further corroborates that there’s apretty prolific petroleum system and it’s amatter of finding the right combination offactors to get it trapped somewhere,”Wartes said.

There are also many places wherefreshly broken sandstone exhibited apetroleum odor.

“There were literally dozens of thoseoccurrences that we’ve made note of,” hesaid.

Brookian trendsUsing the mapping results and data

from the old wells, the geologists wereable to confirm some major geologictrends in what is known as the Brookiansequence. The Brookian is Cretaceousand Tertiary in age. It is the youngest ofthe oil and gas bearing rock sequences innorthern Alaska.

The Lower and Middle Cretaceousstrata of the Brookian thin by many thou-sands of feet from southwest to northeastin the area of the 2008 mapping. Thatthinning probably marks the early upliftof the mountains of the Brooks Range,with detritus from the mountains beingdumped along the north side of the range,Wartes said.

The strata that lie immediately abovethese older Brookian rocks are relativelythick in the east-central North Slope butthin considerably to the north where themajor North Slope oil fields are located.That thinning is largely associated with amajor geologic feature called the BarrowArch, an area of uplifted strata that isassociated with most of the major oil



Looking for the geologic links on North SlopeDGGS-led team is finding evidence for how the geology and petroleum systems in different parts of the North Slope hook together

I

~10 miles

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Happy Valley

Camp

As part of a research program led by Alaska’s Division of Geological and Geophysical Services, during the summer 2008 field season a teamof geologist did some surface geologic mapping in the east-central North Slope, near Happy Valley on the Haul Road more than 50 milesnorth of the Brooks Range.

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fields.The thickening of the Brookian to the

south results from the deposition of thematerial from the Brooks Range into asubsiding basin — Wartes likened theeffect to the filling of a moat runningalong the north side of the Brooks Range.

“The further south you go off theBarrow Arch, the more you’re gettinginto a much, much thicker sedimentarybasin,” Wartes said.

Hue shaleBut the intriguing point about this par-

ticular package of rocks is that it is in partequivalent to the Hue shale, a prolific oiland gas source rock. And, whereas in thearea of the North Slope oil fields the Hueshale is a relatively thin formation, in theeast-central North Slope the time-equiva-lent rock interval opens out into a thicksequence of sandstones with interspersed,organic-rich shales. That combination ofpotential sandstone reservoirs and shalesource rocks could give rise to a veryinteresting oil and gas play, Wartes said.

The Late Cretaceous and early Tertiaryrocks that lie above the equivalent of theHue shale have characteristics that indi-cate a west to east transition from anancient land environment into an ancientmarine basin. And those rocks on the eastside that were deposited in marine condi-tions include the Schrader BluffFormation. The Schrader Bluff Formationis of particular commercial importancebecause it is also found in the PrudhoeBay area where it reservoirs hugeamounts of viscous oil, including theMilne Point Schrader Bluff pool, and theoil pools for the Orion and Polaris fields.

The DGGS work is helping clarify thedetailed nature of these reservoir rocks,Wartes said.

“It’s important to have a good modelfor how the sands are distributed in thereservoir,” he said.

But given the huge geologic variationsacross that linchpin east-central NorthSlope area, a key objective of the geolo-gists has been to verify the correlationsbetween disparate rock units acrossnorthern Alaska. Mapping done in thepast tended to result in a plethora of

names for the various units, including dif-ferent names at different locationsapplied to the same units. The confusingnomenclature has compounded the diffi-culty in correlating the rocks across theregion.

A couple of years ago North Slopegeology experts Gil Mull, DaveHouseknecht and Ken Bird proposed arevised and simplified nomenclaturewhich the DGGS team is now testing.

“It really did extremely well,” Wartessaid. “… It made several predictions interms of where we ought to see certainunits, such as (ancient) regional floodingsurfaces, and that certainly came out to betrue.”

Field tourIn June DGGS hosted its annual show-

and-tell field tour to show industry spon-sors of the division’s North Slope pro-gram some of the geologic features thatthe DGGS-led team is investigating. Inexcellent weather conditions over a peri-od of two days a small fleet of helicoptersferried representatives fromConocoPhillips, Anadarko, Petro-Canada, FEX, ENI, the U.S. GeologicalSurvey (including USGS Director MarkMyers), Alaska’s Division of Oil and Gasand DGGS to 10 locations in the east-central North Slope. BP, Shell and BGalso sponsored the program this year butwere unable to attend the field tour.

Printed seismic sections were present-ed at some locations, so that tour partici-pants could discuss how rock observed atthe surface related to rocks found under-ground in wells.

“I think that went over very well,”Wartes said, adding that oil companygeologists often only work on subsurfacegeology.

But despite the progress that theDGGS-led team has made, many unan-swered question about the “missinglinks” between the rock stratigraphy atopposite ends of the North Slope remain.

“It wasn’t at all clear how some ofthose units correlated and we don’t quitehave the answer yet ourselves,” Wartessaid. But, in that east-central part of theSlope, the team is working right in thearea where the key changes in the geolo-gy occur, he said. ●

Modified from Garrity et al., 2005

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A schematic diagram of the rock stratigraphy of the east-central North Slope illustrates theextreme variation in that stratigraphy between the south and north of the area. Field map-ping in 2008 focused on the Brookian rocks.

continued from page 8

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t’s the equivalent of canaries chirpingtheir warning message in coal mines.

Companies of all sizes are involvedin what looks like a large-scale reversal

of plans to spend C$170 billion in northernAlberta over the coming decade.

The trend is shaping up as the boomthat went bust as Suncor Energy, the sec-tor’s second largest producer, and Petro-Canada point to actual and likely spendingcuts and project delays.

Suncor Chief Executive Officer RickGeorge said his company will slash its2009 spending plans to C$6 billion froman earlier C$9 billion-$10 billion.

He said that could be wound back evenmore if oil prices settle around US$65-$70a barrel and credit markets remain frozenin 2009.

The immediate impact is on the plannedVoyageur upgrader, designed to raise thecompany’s total synthetic crude volumesby 200,000 barrels per day to 550,000 bpd.

Stages five and six of Suncor’s Firebagoperations are expected to proceed, unlesscrude prices fall to US$60-$75 per barrel.Chief Financial Officer Ken Alley said heexpects crude prices to settle aroundUS$80 in 2009.

George said Suncor’s objective is to“ensure that we are living within ourmeans during a time of market uncertainty,while also making the strategic spendingdecisions that will allow us to continue onour growth path.”

He said that if Firebag stages five andsix were delayed, spending in 2009 couldbe dropped to the C$2 billion needed tokeep the basic business functioning.

But George said that would be a dra-conian step, adding that “if conditionsimprove, we also have the flexibility toimprove and bring on bitumen productionquicker.”

He reminded investors that Suncorwent ahead in 1998 with its Millenniumproject when crude prices were US$11 perbarrel and faced some doubters then.

“You have to have a lot of faith in thisbusiness,” he said. “I like staying as count-

er-cyclical as I can.So when other peo-ple start pulling backcapital, it’s actually atime you want tokeeping moving for-ward, even it is takesa little bit of nerve.”

George also saidhe expects refineriesin the United Statesto be put on the auc-tion block as a result of the financial crisis.“I think there will be some real fire sales.... We should actually see a number of U.S.refineries shut down.”

Fort Hills deferral possiblePetro-Canada, with UTS Energy and

Teck Cominco as junior partners, is poisedto defer construction of a C$10 billionupgrader connected to their Fort Hillsproject.

UTS said decision making on theC$23.8 billion venture may be stalledbecause of “costs, current commodity,equity and credit market conditions.”

Instead, it may limit construction to themining and extraction portion, whosecosts UTS estimates at up to C$15 billion.

“These are certainly turbulent times inthe financial markets and although thecentral banks appear to be making all therights moves to correct the situation, a fol-low-up economic slowdown of some mag-nitude and direction seems likely,” saidPetro-Canada Chief Executive OfficerRon Brenneman.

“Clearly one of the things we mustdecide — if we defer — is how long thatmight be. If it’s an extended period of timeand we’re marketing bitumen, what do thebitumen markets look like and how willthat impact the standalone mine situation.We’ve got to pull all that together,” hesaid.

UTS Chief Executive Officer WilliamRoach said proceeding “prudently” wouldreduce his company’s overall fundingrequirements and extend its current fund-ing arrangements into the first quarter of2010.

“This will allow more time for the equi-

ty and debt markets to recover,” he said.“Once we get through this downturn Ifully expect a return to the rising demandcurve we’ve seen for some time and areturn to a supply-driven market.”

Other delaysThose developments came on the heels

of word from Nexen and OPTI Canadathat they will put on hold the second phaseof their Long Lake project; backpedallingby Value Creation, which has delayed con-struction of its upgrader by one to threeyears; and deferrals by StatoilHydro andTotal of their own upgrader plans by twoyears each.

Pierre Fournier, executive vice presi-

dent with National Bank Financial, saidthat “more than anything, the future of theoil sands will depend on U.S. commit-ments to finance development of theresource and buy the oil,” with the empha-sis on U.S. energy independence in thepresidential campaign giving every reasonto believe the next president will “takeaggressive steps to diversify energysources and stop buying oil from ‘our ene-mies.’”

But the political opposition in Canadato accelerated development of the oilsands and the resistance to foreign invest-ment, notably from China, present someobstacles, including a threat to nationalunity, he said.

Fournier suggested that if the privatesector is unwilling or unable to guaranteelarge-scale development of the oil sandsover the long run, “major multibillion-dol-lar bilateral agreements between the U.S.,Canada and the producing provinces seemlikely.”

“The options would include guaranteedlong-term contracts at fixed prices, invest-ments in technology to enhance output,reduce costs and carbon emissions, aswell as subsidies and various fiscalincentives,” he said. ●


● F I N A N C E & E C O N O M Y

Trimming the sails — Alberta reversalsSuncor, Petro-Canada mull cutbacks, deferrals, hold out hope of better times, even in 2009; closure of U.S. refineries predicted

ISuncor CEO RickGeorge

Syn-fuel project on holdAlter NRG, an ambitious Calgary-based technology company, is stalling until

next spring a decision on a possible C$450 million power plant in Alberta thatwould rely on synthetic fuel derived from petroleum coke.

It said the state of the economy may “affect the outlook for power developmentin Alberta.”

The plant, 40 miles northeast of Edmonton, is designed to produce electricityusing a blend of natural gas and synthetic gas, using the company’s proprietarytechnology.

The facility is also intended for use in carbon capture and storage, with almost600,000 metric tons a year of captured carbon dioxide expected to be injected intonearby geological formations or sold for enhanced oil recovery.

As well, Alter NRG said the deepening credit crunch will make it more diffi-cult to raise funds for its C$4.5 billion coal-to-liquids project, but has yet to shelvethe undertaking.

It proposes turning coal reserves in northwestern Alberta into diesel fuel andnaphtha using processes that have been in commercial operation worldwide formore than 30 years.

—GARY PARK

“You have to have a lot of faith inthis business. I like staying as

counter-cyclical as I can. So whenother people start pulling backcapital, it’s actually a time you

want to keeping moving forward,even it is takes a little bit of

nerve.” —Suncor CEO Rick George

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By ERIC LIDJIPetroleum News

laska got a tiny feather in its cap aswell as a slight elbow in the side inOctober from a preliminary updateof the proved oil and natural gas

reserves in the U.S. Led by new finds in Alaska, proved oil

reserves in the U.S. grew last year for thefirst time since 2003, while proved natu-ral gas reserves increased more than anyyear on record, according to new figures

from the U.S. Energy InformationAdministration.

The figures mean that while Alaskahelped the country replace the crude oil

produced last year, the state could facecompetition as it works to bring massivegas fields online.

Nationally, domestic proved oilreserves increased 2 percent last year,while proved natural gas reserves jumped13 percent over the previous year, thelargest one-year jump since the EIAbegan tracking proved reserves in 1977.

The EIA calculates proved reserves bycombining new discoveries with theexisting reserve base, and then subtract-ing any resources produced during theyear. Discoveries come from new fields,new reservoirs in old fields and satellites.

The EIA determines new discoveriesand production through a survey of 1,379operators around the country, defining“proved reserves” as oil and gas reser-voirs expected to come into production inthe coming years “under current econom-ic and operating conditions.”

New oil discoveries in AlaskaOf the 2 billion barrels of proved oil

reserves added in the country last year,Alaska contributed 284 million new bar-rels, while Texas added 251 million bar-rels and North Dakota, fueled by devel-opment of the Bakken formation, added70 million barrels.

Most of the new reserves booked in2007 came from satellites to existingfields, and not from new discoveries. Butof the 66 million barrels of provedreserves connected with “new field dis-coveries,” about 70 percent, or 45 millionbarrels, came from Alaska.

Although the EIA breaks down thereserve figures by state, it would notrelease details behind the state-by-statefigures, citing the proprietary nature ofcompany filings.

As a result, it’s hard to know for surewhat new fields companies might havebooked in Alaska last year. PioneerNatural Resources spent much of 2007building an offshore island to supportdevelopment of the Oooguruk unit, butdidn’t actually bring the prospect onlineuntil the summer of 2008. The companyexpects the unit to produce as much as 90

million barrels of oil over the 25 to 30year life of the field.

Huge boom in gas explorationBut Alaska natural gas reserves

declined last year.The state saw a 12 percent decline in

“nonassociated” proved natural gasreserves during the year, to 1.27 trillioncubic feet.

Nonassociated reserves are those notconnected to oil fields, and in Alaska arefocused around the Cook Inlet.

Looking statewide, the EIA givesAlaska a net-gain in proved natural gasreserves, from 10.2 tcf to 11.9 tcf. Thatfigure is perplexing because it clearlyincludes only some of the 35 tcf ofproved natural gas reserves on the NorthSlope. Without a pipeline to carry thoseresources to markets outside the state,those natural gas reserves have been usedalmost exclusively for field operations.

Even considering the larger figure,though, Alaska lags behind much of themidcontinent region, which continues toexperience a boom in natural gas explo-ration and production: Texas, Wyoming,Colorado, New Mexico and Oklahoma alladded more than 2 tcf of proved naturalgas reserves last year.

Nationally, natural gas reservesjumped more than twice as much as anyyear on record.

Unlike domestic oil reserves, whichrarely replace the oil produced during theprevious year, domestic natural gasreserves have been rising every year since1998, and are now nearly 50 percenthigher than they were in 1993, the lowestyear on record.

Different definitions at playThe EIA aims to include only those

reserves that have a 90 percent probabili-ty of eventually being produced, and willoccasionally remove reserves that havesat on the books too long without comingonline, according to Steve Grape, theauthor of the report.

But the state classifies reserves asthose likely to be produced through 2035.As a result, the EIA estimates of provedreserves differ considerably from thoselisted in the most recent annual report ofoil and gas assets in Alaska, which coversall of 2006.

The EIA reports Alaska as havingabout 3.9 billion barrels of proved oilreserves at the end of 2006, while thestate reports having about 6.3 billion bar-rels.

However, state economists take a moreconservative view when forecasting rev-enue from oil and gas operations, onlycounting resources expected to come intoproduction within the next few years. Asa result, the state did not include manyheavy and viscous oil reserves, or oil andgas in federal lands and water, in its mostrecent forecast made earlier this year. ●



Alaska grew proved reserves in 2007Alaska led the nation in new oil reserves and showed growth for gas, but could face competition bringing new resources to market

The figures mean that whileAlaska helped the country replacethe crude oil produced last year,the state could face competitionas it works to bring massive gas

fields online.

A

FINANCE & ECONOMYIndustry grows in importance as employer

The growth in oil industry employment propelled private industry in Alaska lastyear.

Oil extraction and oilfield services jobs comprised some total 13 percent ofemployment for the 100 largest private employers in the state during 2007, accordingto Trends 100, published annually by econo-mists with the state Department of Labor andWorkforce Development.

For the past 21 years, the list has catalogedthe 100 largest private employers in the state.

Oil industry employment in Alaska isincreasingly consolidated among large com-panies. The 12 oil-related companies on thelist employ about 85 percent of the 12,700people who work in the industry.

The oil industry accounted for 5 percent ofall private sector employment in 2007.

The new list also shows the changes in oilindustry employment over the past decade.

First, the list represents the massive growthin employment since 1997. Back then the only oil industry companies represented inthe top 10 were ARCO Alaska and VECO, who together employed some 2,700 peo-ple. Today, three oil-related companies in the top 10 — BP Exploration Alaska,CH2MHill and ASRC Energy Services — together employ about 5,500 people. Also,there have been changes in the makeup of the oil industry.

Native corporations and subsidiaries play a much larger role in the oil industry thanthey did a decade ago. Of the 16 Native companies in the top 100, four work almostentirely in the oil industry and a fifth, NANA/Colt Engineering, is an important play-er.

Halliburton Energy Services made the Trends 100 for the first time in 2007, whileChevron and Nabors Alaska Drilling both jumped more than 10 spots since 2006.

—ERIC LIDJI

Contact Eric Lidji at 907-770-3505or [email protected]

Oil extraction and oilfieldservices companies comprisedaround 13 percent of the 100largest private employers in

the state during 2007,according to Trends 100,published annually by

economists with the stateDepartment of Labor andWorkforce Development.

For advertising information

Susan Crane: 907.770.5592Bonnie Yonker:

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ussia, Iran and Qatar, holding a com-bined 60 percent of the world’s nat-ural gas, are cooperating on “all lev-els” to establish a “Gas OPEC”

made up of global exporters — an initia-tive that, in the view of many analysts, haslittle hope of success because gas has yetto become a worldwide commodity.

They have struck a deal to establish atechnical committee and to hold up to fourmeetings a year to discuss gas policy,Russia’s Gazprom, the world’s largest gascompany, said in a statement Oct. 21.

Gazprom Chief Executive OfficerAlexei Miller said the “big gas troika”would discuss the “most important andmutually interesting issues of gas marketdevelopment.”

He said the cooperation would coverexploration, gas processing, transportationand sale of gas in an effort to “create a fairmarket for producers and consumers.”

Miller said the three-nation clubplanned to invite participation from othercountries, including gas consumers, butgave no further details on who might beinvolved.

It is expected the so-called GasExporting Countries Forum or GECFwould include Malaysia, Nigeria, theUnited Arab Emirates, Algeria, Bolivia,Brunei, Venezuela, Egypt, Indonesia,Libya, Oman, Trinidad and Tobago andEquatorial Guinea, but exclude NorthAmerica.

Long-term gas sales an issueAlgeria has argued in the past that cre-

ating an OPEC-style cartel for gas is achallenge given that most gas sales arebound by long-term contracts and lack theflexibility of the oil market.

Even senior Russian government andGazprom officials have previously said agas version of OPEC is not feasible, with

one describing the idea as “childish.” Alexander Medvedev, deputy head of

Gazprom, said last spring that even ifGECF became a formal organization itcould not exert the same powers as OPEC“because of obligations under long-termcontracts.”

Iran is only a small exporter of gas andnot a relevant player in the LNG world,but has failed to attract western-basedcountries to develop its gas resourcesbecause of unease over Iran’s nuclear pro-gram.

Qatar is the biggest global source ofLNG and wants to expand that marketshare by breaking the price link to crude.

It has no problems raising funds and iscapable of pursuing projects independent-ly, raising questions about why it wouldeven be interested in a Gas OPEC, saidLondon-based Middle East analystSamuel Ciszuk.

Russia hasn’t joined OPECRussia has never shown any desire to

join OPEC, preferring to act alone, withabout 95 percent of its current exports des-tined for Western Europe, which is alreadya matter of concern to consuming coun-tries who would view a gas cartel as fuel-ing their worries about security of supply.

Chris Theal, managing director ofresearch at Tristone Capital, told theCalgary Herald that LNG projects are tiedto 20-year contracts, without which therewould be no financing.

He said there is a structural aspect toLNG markets that doesn’t exist with crudeoil, limiting the ability of a natural gasconsortium to act like OPEC.

The best gas exporters can hope for isto create a global market with regionalelements, Bob Skinner, former director ofthe Oxford Energy Institute in England,wrote in a recent article.

“Continued growth in LNG demand,coupled with a willingness for manyemerging players to pay crude oil equiva-lent prices, we anticipate that markets out-side the U.S. will absorb 80 to 85 percentof undedicated supply in 2009 and 2010,”he said.

Currently Japan, South Korea andSpain claim about half of the 25 billioncubic feet of LNG produced every day, ofwhich only 1 bcf per day is delivered toNorth America, largely because of thesuccess in developing shale plays. ●


● I N T E R N A T I O N A L

Gas OPEC: An ideagoing nowhere fastRussia, Iran, Qatar form technical committee to discuss gaspolicy; long-term LNG sales contracts obstacle to powerful cartel

R

SAFETY & ENVIRONMENTFlint Hills refinery sets safety record

Flint Hills Resources Alaska North Pole Refinery employees have set a new markfor safety. The company said Oct. 28 that the refinery went more than 730 consecu-tive days — more than two years and 1.5 million hours — without a recordable safe-ty incident under the U.S. Occupational Safety and Health Administration standards,both a new plant record for the refinery and a new companywide safety record forFlint Hills’ refineries, the company said Oct. 28.

“This is a significant milestone that is very difficult to attain in any industry,” MarkGregory, vice president of manufacturing and refinery manager, said in a statement.“Our employees have performed remarkably well and they deserve all the credit fortaking personal ownership in always putting safety first.”

Recordable incidents are those that may require first aid, but not medical attention.In 2007, the average recordable incident rate for U.S. refineries was 1.40 per every200,000 hours worked, Flint Hills said.

The North Pole refinery previously received the Gold award from the NationalPetrochemical & Refiners Association for reducing its recordable incidents by 44 per-cent in 2006.

The North Pole Refinery has a crude oil processing capacity of about 220,000 bar-rels per day and produces gasoline, jet fuel, heating oil, diesel fuel, gasoil and asphaltfor supply to both local and international markets. About 60 percent of the refinery’sproduction is for the aviation market. Flint Hills Resources LP is a wholly owned sub-sidiary of Koch Industries Inc.

—PETROLEUM NEWS

http://www.amarinecorp.com/

http://www.evergreenhelicopters.com/

The rate for shipping a barrel of oilbetween Pump Station 1 and the NorthPole refineries would jump from $1.25 to$1.97, while shipping fees between theNorth Slope and Valdez would increasefrom $1.96 to $3.03 or $3.05, dependingon the final destination.

The pipeline runs 800 miles from theNorth Slope to a marine terminal in Valdez.

Updating the 2002 ratesState regulators set the current rates in

late 2002 as part of an important case thatdetermined previous rates to be too high,and forced the owners of the pipeline torefund nearly $10 billion to shippers. Theripple effects of that decision are still beingfelt today through appeals to the ruling, andexpansions of the arguments behind it.

The trans-Alaska oil pipeline is ownedby local subsidiaries of ConocoPhillips,BP, ExxonMobil, Unocal and Koch. Andwhile ConocoPhillips, BP andExxonMobil produce most of the oil goingdown the line, independent producers likeAnadarko and third-party refiners likeTesoro also use the pipeline, allowing forconflicting interests.

To add a level of complication, stateroyalties are based on the value of oil aftertariffs, meaning the rate directly impactsthe amount coming into the state treasury.

As a result, pipeline tariffs have longbeen a topic of debate in Alaska.

Following a decade of litigation, thestate and the pipeline owners reached a set-tlement in 1985 creating a system for set-ting rates, but the 1997 case challenged thesystem, leading to the 2002 decision, sub-sequent appeals and an on-going federalcase on interstate rates.

ConocoPhillips describes the new ratesas simply a way to update for six years ofchanging economics, a time of decliningthroughput on the pipeline and increasedcosts.

The pipeline owners typically file newrates annually. This past summer, the RCArejected the most recent rate increaserequested by the companies.

Several factors in the new case couldprovide fodder for debates: ConocoPhillipsfiled its rate request alone and not with theother owners; the company is requestingconfidentiality for several important docu-ments; the pipeline is undergoing anexpensive upgrade that could impact rates;and the 1985 settlement is about to expire.

Tesoro Alaska, Flint Hill Resources andPetro Star, the three refiners in Alaska,have all asked to be involved in the case, ashas the State of Alaska.

One rate for intrastateRegulators design pipeline tariffs to let

companies earn a specific amount of rev-enue based on recovering operating costsand turning a profit through a preset rate ofreturn.

ConocoPhillips is filing rates alone, andnot with the other four owners of thepipeline.

Although the 2002 ruling required allowners to maintain one tariff rate forintrastate shipping, it allowed the compa-nies to file individually as long as all thecombined rates don’t earn more than thetotal amount of revenues allowed by stateregulators.

However, ConocoPhillips said it couldnot figure out the rates the other companiesplanned to propose because of “anti-trust”concerns, and therefore estimated usingpublic information and data from AlyeskaPipeline Service Co., which operates thepipeline.

Through those calculations,ConocoPhillips projects the pipelineshould be allowed to bring in $797.9 mil-lion in revenues each year for its owners.Of that amount, the company estimates$91.2 million should come from theintrastate ratepayers.

Volumes down and costs upBlaming declining volumes and

increasing costs, ConocoPhillips argues the2002 rates “no longer adequately compen-sate” the company. The existing intrastaterates are projected to yield $58.3 million inrevenues, with $16.3 million going toConocoPhillips.

ConocoPhillips largely assigns theshortfall to declining North Slope oil pro-duction. The pipeline carried some 1 mil-lion barrels of oil every day in 2000, but in2007 carried only about 740,000 bpd,“without a corresponding decrease incosts.”

But Tesoro believes ConocoPhillips is“disproportionately” charging in-stateratepayers.

Although no one disputes the decline oftotal throughput on the pipeline, Tesoroclaims the figure isn’t relevant for this fil-ing, because the volumes of oil going to in-state markets have increased since 2000,and the intrastate rate only covers thosevolumes.

The claim is logical, but hasn’t yet beenverified in filings.

Alyeska did not have a ready estimateof in-state volumes. Neither did econo-mists with the state Department ofRevenue. The Prince William SoundAdvisory Regional Citizens’ AdvisoryCouncil, an independent monitor of oiloperations in Valdez, tracks the oil leavingthe pipeline, but some of that oil ends up at

the Tesoro refinery in Nikiski.Thomas Kuckertz with the council esti-

mated between 90 and 95 percent of the oilfrom the North Slope leaves Valdez, boundeither for markets outside Alaska or to theKenai Peninsula refinery. But consideringthe increase in state population anddemand for fuel, he added, “It seems fairlyobvious that the percentage of in-state vol-umes is going up.”

Comparing the amount ConocoPhillipshopes to earn from intrastate shippers ver-sus the total revenues it believes thepipeline should be earning as a whole,ConocoPhillips assigns roughly 11.4 per-cent of the oil moving through the pipelineto intrastate shippers.

Requesting confidentialityTesoro also challenged the cost esti-

mates ConocoPhillips offered as justifica-tion for the rate increase, but the argumentis hampered because ConocoPhillips isasking state regulators for confidentialityon six documents used to calculate expens-es on the line.

The documents cover the operationsand expenses of Alyeska andConocoPhillips, and the company said it“made every effort to keep the confidentialmaterial in its rate filing to a minimum,”and cites state statute as justification forthe request at this point.

Tesoro calls these documents “theheart” of the rate case. The companyshould have access to some information ifthe RCA includes Tesoro as a party in theany case that proceeds. But Tesoro says itneeds to see the information now to makeits case.

ConocoPhillips believes regulatorsshould hold off making the informationpublic until later in the case, when it

becomes clear which documents are rele-vant to the debate.

Increases and decreases to tariffs arecalculated by applying a preset methodol-ogy to a “test year,” using actual data froma recent year to set rates for upcomingyears.

But that test year needs to be typical inorder for rates to be accurate, and becauseno year is ever entirely typical, companiesand regulators adjust for inconsistencies.

Tesoro is charging that ConocoPhillipsdid not make some needed adjustmentsthough, including those for declines inthroughput caused by a series ofunplanned shutdowns.

Another issue is how the cost ofStrategic Reconfiguration will factor intothe proposed rates. The major pipelineupgrade is over-budget and past deadline.ConocoPhillips is asking regulators to“phase” investigation of the newly pro-posed rate by first considering costs notrelated to Strategic Reconfiguration andreturning to the issue later.

TSM set to expire soonThe State could become a major player

should the case become more than routinebecause the 1985 settlement is set to expiresometime between next January and 2011.

“The State is concerned that theincreased tariff rates (and the underlyingcomponents of that rate) that[ConocoPhillips] is requesting will signifi-cantly impact tariff rates after the TAPSSettlement Agreement is no longer ineffect,” Attorney General Talis Colbergwrote to state regulators in a request to beincluded in the case.

RCA is required by statute to decidehow it will proceed on the rate case byNov. 3. ●



TARIFFS

http://www.akcb.com/

http://www.efs-fire.com/


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

Business SpotlightNorthern Air Cargo

Northern Air Cargo is Alaska’s largest all-cargo operator, serving 14 communities plus theRed Dog Mine. NAC’s fleet of 737-200 cargo air-craft operates from Anchorage on a scheduledbasis with charter services throughout NorthAmerica. For more than 50 years the companyhas delivered everything from mail, groceries,cars and boats to the much-coveted realChristmas tree during the holiday season. Inaddition to Anchorage, NAC has bases in Bethel,Fairbanks and Deadhorse.

David Squier

Dave Squier has been in the air cargo industry24 years, including the last year at NAC. With hisextensive background in the Alaska Bush, he has a deep appreciation for the challengesrural residents face getting the necessities of life safely delivered. He has been instru-mental in modernizing and streamlining NAC’s cargo handling processes. Dave and his

David SquierVice President Cargo Services

CO

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PH

OTO wife Jenna have two grown children living in

Alaska; their son is an engineer and theirdaughter a nurse.

Wallace Niles

Wallace Niles joined NAC originally in 1980as a DC-6 first officer and advanced through theranks to become a captain in the B-727. He leftin 2001 for a Federal Aviation Administrationregulatory position, “coming home” to NAC inMay 2008. Wallace was appointed to his currentposition Oct. 1. He will continue overseeing allaspects of NAC’s flight operations. Wallaceenjoys interacting with people, spending timewith his family, hunting, fishing and gardeningduring the long Alaska summer days.

—PAULA EASLEY

Wallace NilesVice President Operations

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the industry is under. I think it’s unfair forme to say it’s all related to the royaltystructure, because there’s a tremendousamount of pressure around commoditypricing and access to capital,” Knight said.

“Costs are continuing to creep up ... sothose are some of the issues that we aretalking to industry about: Are there thingsthat we can do together to mitigate some ofthe serious consequences around thoseissues?”

Murray Edwards, vice chairman ofCanadian Natural Resources, said Knight’srefusal to shift on the Jan. 1 date virtuallyensures that Alberta “is the least attractiveregime for conventional gas in NorthAmerica” now that money is flowing intodevelopment of British Columbia andUnited States unconventional gas reserves.

“There’s a message for (Alberta). ... Wehave to remain competitive, but theCanadian regulatory framework is morechallenging, which boosts risk and the costof capital,” he said.

Royalties expected to dropA report by Tristone Capital forecast

the Alberta government will see its shareof natural gas revenues drop by close toC$1 billion in the next three years, basedstrictly on slumping gas production, com-pared with Premier Ed Stelmach’s rosyforecast a year ago that the new royaltieswould generate another C$1.4 billion ayear.

Tristone analyst Chris Theal said theflight of capital to jurisdictions with moreattractive fiscal regimes has contributedto declining output from Alberta’s moremature gas fields.

Adding to that problem, Alberta doesnot have the shale gas plays that haveseized the industry’s attention this year.

Theal said Alberta’s largest gas playsface supply costs that are at or above themarginal cost of supply in North Americaand the emergence of shale gas develop-ment has pushed Alberta “substantially”down the ranking list for capital alloca-tion.

He said Alberta production has slippedto 13 billion cubic feet per day, 500 mil-lion cubic feet per day short of the gov-ernment’s forecast, and 1 bcf per daybelow 2007.

(Alberta still accounts for about 80percent of Western Canada’s combinedgas production of 16.34 bcf per day).

The number of rigs in Alberta is off 9percent from a year ago and 40 percentfrom 2006, compared with increases of19 percent in British Columbia and 22percent in Saskatchewan.

Land sales are up 12 percent inAlberta, 318 percent in Saskatchewanand 365 percent in British Columbia.

Shortfall in gas supplyThe current shortfall in gas supply will

translate into a C$960 million drop in theprovince’s natural gas take over the nextthree years, while lower energy pricesand the credit squeeze will make 2009“tough slogging” in Alberta, Theal said.

Canada’s National Energy Board pre-dicts natural gas deliverability in Albertawill drop by 1.7 bcf per day to 11.48 bcfper day between 2007 and 2010, whilerising by 900 million cubic feet per day inBritish Columbia to 3.54 bcf per day. Thenumbers are based on a reference case ofC$9 per gigajoule at the AECO hub inAlberta.

The federal regulator also believes gasprices in Western Canada of C$7.88 pergigajoule, or C$8.30 per thousand cubicfeet will give producers a reasonable rateof return.

Coalbed methane drilling is predictedto shrink by 5 percent annually to 1,508wells in 2010 from 1,759 in 2007 as oper-ators chase tight and shale gas plays.

“It’s certainly not a continuation of thedeep ramp up earlier in the decade, it’smoving towards a sustaining kind ofapproach,” said the board’s technicalleader, hydrocarbon resources, PaulMortensen.

Despite that tapering off, coalbedmethane output is expected to grow to864 million cubic feet per day in 2010from 688 million cubic feet per day in2007, partly because the per-well declinerate is very low.

Leading the charge in BritishColumbia is the projected increase inMontney production to just over 1 bcf perday in 2010 from 245 million cubic feetper day in 2008, while Horn River, isforecast to reach 126 million cubic feetper day in 2010, from 9 million cubic feetper day currently.

Royalty an ‘aching sore’But the royalty overhaul remains what

University of Calgary political analystDavid Taras calls an “aching sore” inAlberta, arguing many fences have stillto be mended and more adjustments are

need to the regime.Regardless of this seething unhappi-

ness, Nexen Chief Executive OfficerCharlie Fischer insists “global financialissues dwarf anything to do with royal-ties.”

One of the few suggestions to help theAlberta government out of its impassehas come from Michael Tims, chairmanof investment dealer Peters & Co., whosaid the new royalty structure couldremain in place along with a royalty hol-iday for a set period to stimulate invest-ment.

However, Fischer was unwilling toendorse any moves to reopen the royaltydebate, despite the mistakes, advocating“behind-the-scenes” efforts to find cures.

Don Herring, president of theCanadian Association of Oilwell DrillingContractors, said there is “no interest bythe entrepreneurial investor in doingwork in Alberta, which is the 800 poundgorilla in all of this. When activity dropsin Alberta, it impacts all of WesternCanada’s averages.”

A spokesman for the Alberta govern-ment said the province is not in a battleto have the lowest royalties or the high-est land sales.

Putting the new royalty framework

aside, he said soft gas prices, high laborand materials costs and the creditsqueeze have had a greater impact onactivity.

There is backing from an unlikelyquarter for the Conservative governmentto stay the course.

Liberal leader Kevin Taft said the newregime should be implemented while thegovernment turns its attention to otherpressing matters, such as labor short-ages, credit problems and climatechange.

New Democratic Party leader BrianMason said there is “no good reason whythe changes should be cancelled ordelayed.”

Gary Leach, executive director of theSmall Explorers and ProducersAssociation of Canada, said the indus-try’s warnings of a year ago that Albertahad among the lowest rates of returnanywhere would become even worsewhen Albertans discovered that “theireconomic engine isn’t humming along.”

Frank Atkins, a University of Calgaryeconomist, said he remains optimisticabout the industry’s “ability to makemoney and that hasn’t changed much,”forecasting that crude prices willrebound over the next few months. ●



ROYALTIES

http://www.akrdc.org

No time limitOdum said that there’s no time limit for

the court to make a decision, no way oftelling how long the court will take to do soand no pressure on anyone to make a deci-sion within a certain time period.

“I think that the idea of the courts …deciding on the energy policy for the U.S. isa real problem we should all be concernedabout,” Odum said.

And meantime the lengthy court injunc-tion is costing a great deal of money anddelaying the drilling. To be properly pre-pared for a drilling season Shell has to hirehundreds of people and ensure that every-one is properly trained, both from a safetyand from a skill perspective.

“You can’t go into a drilling seasonwithout being totally prepared,” Odumsaid. “… And so you have to start spendingand developing very early in the year, inanticipation of drilling in the summer.We’ve done that for two years in a row nowand have nothing to show for that invest-ment.”

In 2008 Shell held out until June beforefinally cancelling the summer drilling. Inaddition to costing money, the cancellationresulted in disappointment when summerwork didn’t materialize for people. So, in2009 Shell will likely make a go-no godrilling decision much sooner.

“I can’t afford to do that again,” Odumsaid. “I’ll have to make it much earlier inthe year.”

Infrastructure in placeShell still has the Kulluk floating drilling

platform available for work in the BeaufortSea, as well as the company’s oil spillresponse equipment and the infrastructurefor marine mammal monitoring. And, even

in the absence of drilling, Shell has con-ducted some successful offshore opera-tions, including the acquisition of seismicdata in the Beaufort and Chukchi Seas.

“The seismic surveys have goneextremely well,” Odum said. “We’re in ourthird season now of collecting seismicdata.”

Odum said that the results of the seismicsurveying done so far have proved encour-aging but that Shell has not yet decidedwhether to acquire more seismic data in2009.

“We’re going to process and review theseismic we’ve just finished collecting … todecide whether we need more. … It couldbe we have enough,” Odum said.

And Odum said that Shell has madeprogress in its dialogue with North Slopecommunities over potential impacts of thecompany’s activities on subsistence huntingand concerns about the potential for an off-shore oil spill. In the past there have beenmore than 30 wells drilled in the BeaufortSea, and Shell drilled four out of the fivewells that have been previously drilled inthe Chukchi Sea, he said.

“We have listened to the whalers and thecommunities about what impact the earlierdrilling has had … what’s been measuredand what’s presumed,” Odum said. “… I’mvery confident that we can get to a work-able solution.”

Shell signed a conflict avoidance agree-ment with the whalers for each of the lasttwo open water seasons and those agree-ments defined the terms under whichdrilling would take place. There are periodsaround the whale hunt when operations

would cease, Odum said.

Internal challengeAnd when it comes to environmental

issues such as guarding against an oil spill,many of the hardest challenges come frompersonnel inside Shell — a new generationof employees is especially insistent aboutenvironmental safeguards, Odum said. Andan offshore oil spill is unthinkable, he said.

“I think it’s the realization from the com-pany point of view as well,” Odum said.“As a company we could never afford an oilspill in the Arctic. … We just can’t afford tohave that happen.”

At the same time, Shell sees support oflocal communities as critical to the successof its operations.

“If the community really doesn’t wantyou there, it’s not going to work,” Odumsaid. “It is important for us just as a compa-ny and as a sustainable business to get to thepoint where we’re aligned with the commu-nity on what we’re doing up there.”

And that’s a perspective that Shell isstarting to apply in the Bristol Bay area,where the company is in the early stages ofevaluating possible participation in a futurelease sale.

“We’ve been speaking with some of thecommunities in the Bristol Bay area,because we’re mindful of the fact that in2011 … there’s a lease sale to happen inBristol Bay,” Odum said.

However, there need to be several envi-ronmental studies to answer questionsabout whether exploration and develop-ment should take place in Bristol Bay,Odum said.

“Will we participate in that process? Isuspect, yes. We will,” he said.

Need factsOdum thinks that, although there are

some environmental activists who willalways oppose offshore oil drilling, factualanswers to scientific questions are the keysto dialogue with many in the environmentalcommunity. Factual data can provideanswers to questions about what is and isn’tpossible, he said.

Shell has been working with scientistson the North Slope to jointly design base-line environmental studies that will contin-ue when Shell operates offshore.

“So, not only can we say that this is whatscience tells us, but we’ll track it as we’regoing through and we’ll see if there is anyimpact out there,” Odum said. “… If thereis any impact we’ll adjust and mitigate.”

Shell already has established mitigationmeasures for the avoidance of polar bears,which the U.S. Fish and Wildlife Servicelisted as a threatened species. The measureswill ensure that the bears will be spottedand that they will not be interfered with,Odum said.

“For the activities that we’re proposingin the OCS we already have those mitiga-tions in place,” Odum said. “… From theperspective of our activities, the polar bearsare protected.”

Shell is also making increasing use ofthe traditional knowledge of Arctic commu-nities in addressing questions such as theimpact of climate change on the wildlife,Odum said.

Revenue sharingAnd, in recognition that offshore oil

industry activities impact local communi-ties, Shell strongly advocates outer conti-nental shelf oil and gas revenue sharing bythe federal government, Odum said.Because the federal government owns theouter continental shelf, the state and localcommunities are not currently entitled toroyalties and taxes from activities thatoccur more than three nautical milesbeyond the Alaska coastline.

Shell supported revenue sharing alongthe Gulf coast, where revenue sharing isnow in place, Odum said.

“It should just be automatic now forAlaska as well,” he said. “It’s not clear tome why it’s not.”

Odum said that Shell favors NorthAmerica as a place to invest in and that thecompany is already the largest producer inthe Gulf of Mexico. And the fact that thecompany has invested more than $2 billionin northern Alaska attests to Shell’s belief inthat region’s potential, he said.

But what about the impact on newinvestments of the recent slide in oil prices?

Shell takes a long-term view of oil pric-ing and sees market fundamentals as likelyto drive prices up again in the future, Odumsaid. In fact, the bigger worry is that thecurrent lower prices will cause people toforget about those longer term trends, hesaid.

“I really worry about our inability to stayfocused on something that’s going tobecome a bigger problem over time, not asmaller problem,” Odum said.

As far as the current turmoil in financemarkets is concerned, Shell’s main con-cerns focus on its network of suppliers andpartners.

“Shell has a strong balance sheet, ofcourse, but we don’t do anything by our-selves,” Odum said. “We have suppliers.We have joint venture partners. I thinkwe’re waiting to see how all this unfolds.”

And Shell remains optimistic about itsfuture in Alaska.

“We think we bring some unique skillsto working offshore Alaska, off the NorthSlope,” Odum said. “… We like beingsomewhat unique in that way. … And so,that’s where we’re going to focus. Wethink that resource is big enough anddeserves our full focus.” ●


“I think that the idea of the courts… deciding on the energy policyfor the U.S. is a real problem weshould all be concerned about.” —Marvin Odum, president of Shell Oil Co.


ODUM

http://www.peakalaska.com/

http://www.kenworthalaska.com/


license in late November, after therequired 90-day waiting period for thebill to become effective. AGIA, inexchange for a proposal meeting staterequirements for a gas pipeline, provid-ed up to $500 million in matching fundsfor work leading to a Federal EnergyRegulatory Commission certificate ofconvenience and necessity.

Kvisle noted that the commercialwork — discussions with the major NorthSlope shippers — didn’t begin in August.

“I would point out that I’ve been hav-ing discussions with the Alaska producerssince I took this job in 2001, so this hasgone on for a long time,” Kvisle said.“But I acknowledge that the pace of thosediscussions has picked up and is likely topick up in the next 18 months as we movetowards that open season in mid-year2010.”

TransCanada and predecessor compa-nies were involved in efforts to build agas pipeline from Alaska’s North Slopesome 30 years ago and the company hasremained active in those efforts.

What’s next?“The first critical step here is that by

mid-year 2010, we will have completedan open season,” Kvisle said.

He said there are two aspects to thatopen season. One is the formal open sea-son where companies are invited to nom-inate for capacity for long-term shippingagreements on the line. Those nominatinggas in an open season could be both exist-ing producers and those now exploringfor gas, he said.

“But of course the most likely shippers

that are going to underpin this pipelineare the three existing Prudhoe Bay pro-ducers (BP, ConocoPhillips andExxonMobil) and so while the open sea-son is out there, in parallel with that we’realso holding discussions with those peo-ple in advance of the open season andleading up to the conclusion of that.

“And that is probably the single mostimportant step in moving that project for-ward, are fruitful discussions with theexisting producers on the North Slope,”Kvisle said.

He said the discussions are complicat-ed and include the nature of the shippingcommitment, any ownership role the pro-ducers may want in the pipeline and theissues the North Slope producers havewith the State of Alaska. The producershave repeatedly told the state that theywill not commit to ship on any line —even the joint BP-ConocoPhillips Denalipipeline project — without “fiscal cer-tainty” from the state, guarantees of whattax and royalty rates will be over the lifeof any shipping commitment.

TransCanada is also working on per-

mitting, although Kvisle said the regula-tory permitting track “sometimes getsahead of itself in my view on these proj-ects.” Permits will be needed both fromFERC in the United States and from theNorthern Pipeline Agency for the portionof the pipeline through the Yukon andnorthern British Columbia, he said.

But “the commercial arrangementsand commercial discussions with themajor Alaska producers and any newshippers that might come along, that’sreally the critical step.”

So while work is beginning on the reg-ulatory front, TransCanada is “constrain-ing expenditures” on permitting because“historic projects sometimes get ahead ofthemselves in terms of going down thatregulatory path, spending a lot of moneywhen the real issue is sorting out the com-mercial arrangements and so that’s whereour focus will be for the next little while,”he said. TransCanada has a conditionalFERC certificate for the line planned inthe 1970s and 1980s. That project col-lapsed due to a drop in market prices fornatural gas following U.S. deregulationof the natural gas industry.

A Keystone-Alaska connection?Kvisle said he didn’t think the

announcement of the change in the 50-50ownership in the Keystone pipelinebetween TransCanada andConocoPhillips was a precedent for theAlaska project. TransCanada said Oct. 28that it would pick up a portion ofConocoPhillips’ equity share, taking itsequity share from 50 percent to 79.99percent, although other companies havethe option to acquire up to 15 percent.Conoco’s share would drop from 50 per-cent to 20.01 percent.

As for a precedent for the Alaska proj-ect, Kvisle said he didn’t think there wasanything directly significant in theKeystone announcement, adding that hethought “it should be recognized that it isindicative of the good relationship wehave with ConocoPhillips and you knowwe’ve worked diligently withConocoPhillips for seven years onexploring different ways to collaborate onthe Alaska pipeline project — and we willcontinue to do that.”

TransCanada had been talking with “acouple of the producers before we madeour AGIA filing, so this has gone on along time,” he said.

As to how the talks are going, Kvislesaid “we simply put to them the advan-tages of being involved in our projectincluding the fact that our project isstrongly supported by the State of Alaskaand that’s obviously pretty important.”

The talks cover many issues, he said,“and of course they’re not going toexpress a willingness to walk away fromtheir project until everything is agreedbetween us.”

The BP-ConocoPhillips joint pipelineproject, Denali — The Alaska GasPipeline LLC, was announced in earlyApril, as the Palin administration wasevaluating whether to recommend to theLegislature that TransCanada receive anAGIA license. None of the North Slopeproducers applied under AGIA — callingthe AGIA requirements too restrictiveand telling the state they preferred anegotiated format. ConocoPhillips didsubmit a separate, nonconforming pro-posal, which would have required fiscalnegotiations, to the state in conjunctionwith receipt of AGIA applications.

—KRISTEN NELSON


TRANSCANADA Kvisle said he didn’t think theannouncement of the change in the50-50 ownership in the Keystonepipeline between TransCanada

and ConocoPhillips was aprecedent for the Alaska project.TransCanada said Oct. 28 that it

would pick up a portion ofConocoPhillips’ equity share,

taking its equity share from 50percent to 79.99 percent, althoughother companies have the option

to acquire up to 15 percent.

http://www.denali-thealaskagaspipeline.com/


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exploration & production alaska at the front · 2008. 11. 26. · extremely complicated,”...

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