page7

MGM Energy deal to deliver naturalgas to proposed Mac Valley pipeline

Vol. 12, No. 42 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of October 21, 2007 • $1.50

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

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

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

● N A T U R A L G A S

6Burglin ruling upheld: AOGCC says well cannot be classified

as gas well; based on DEC reinterpretation of regs, flow likely reduced

8 On the teeter-totter: Alberta premier reportedly tells execs hewon’t ‘trounce’ royalty pacts, putting him at odds with own review panel

9 Chena gets Prudhoe geothermal grant: Plans to test useof geothermal power plant to extract energy from oilfield-produced water

Latest PNA Book Club selection

Royalty dread spreadsNatural gas, which adds more to Alberta coffers than conventional crude, under attack

By GARY PARKFor Petroleum News

or the past year it has all been aboutthe oil sands. Now it’s starting to beall about natural gas.

As the Alberta government closesin on the bewitching decision-makinghour, which could determine whether it isturned into rags or riches, the spotlight inthe Royalty Ruckus is shifting to theprovince’s most valuable, yet most fragileresource.

No aspect of Alberta’s natural resourceindustry has experienced a more sicken-ing ride in the last two years than conven-tional gas, which had a fleeting taste of anunparalleled windfall two winters ago and

is now close to a tipping point.In fiscal 2005-06, the government

enjoyed a windfall from its gas royaltiesof C$8.388 billion before tumbling bymore than C$2 billion in 2006-07 and fac-ing a projected fall to C$4.6 billion in2009-10.

Just how sour things have turned isreflected in an Oct. 15 short-termCanadian gas deliverability report by theNational Energy Board — a forecast thatshould cause some anxiety in the UnitedStates, which depends on Canada forabout 15 percent of its gas supplies.

If the Alberta government adopts therecommendations of its royalty review

F“The decisionsbeing made nowaffect the invest-ment required tomake future naturalgas discoveries. Youcan’t get royaltiesfrom wells that arenot drilled.” —JimBuckee, former CEOof Talisman Energysee DREAD page 15

Nikaitchuq OK’dExpansion approved; Eni applies for royalty reduction, needs project sanction

By KRISTEN NELSONPetroleum News

ni US Operating Co. has receivedstate approval for expansion of itsNikaitchuq unit and has appliedfor royalty modification for a

dozen leases in the expanded unit. The Alaska Department of Natural

Resources Division of Oil and Gasapproved Nikaitchuq unit expansionOct. 5, more than doubling the size ofthe unit which is north of the KuparukRiver unit in the shallow waters of theBeaufort Sea off Alaska’s North Slope.

On Oct. 16 Eni applied for royaltymodification on Schrader Bluff andSag River production for 12 leases in

the expanded 18-lease unit. Nikaitchuq development is expected

to include the first independent produc-tion facilities on the North Slope as Enihas said it intends to construct a pro-cessing facility for Nikaitchuq withinthe boundaries of the expanded unit atOliktok Point. Existing processingfacilities are owned by the major NorthSlope leaseholders — BP,ConocoPhillips and ExxonMobil.

Eni expects to go for managementsanction of development by the end ofthis year and to see first production in2009.

The Nikaitchuq expansion merged

EActing DivisionDirector KevinBanks toldPetroleum NewsOct. 12 that unitexpansion was a“good sign” that Eniwill move intodevelopment ofNikaitchuq. “It lookslike things are mov-ing ahead,” he said.see NIKAITCHUQ page 18

Beaufort find is oil, not gasDevon Canada gas hunt yields oil; company seeks partners; oil poses challenges

By GARY PARKFor Petroleum News

evon Canada has posted the first oil find inthe Canadian Beaufort Sea in 25 years — atwist of fortune for the company which hadbeen hoping for trillions of cubic feet of gas

to spur progress on the Mackenzie Gas Project.“We had expected gas, so we are somewhat sur-

prised, but this is a lot better than just water,”Dennis Johnston, Devon Canada’s frontier explo-ration manager, told Petroleum News.

The National Energy Board has issued a decla-ration of a significant discovery covering about

37,000 acres — the largest such designationawarded for the region.

Devon Canada, 100 percent owner of thePaktoa C-60 discovery well drilled in 2006, esti-mates the recoverable oil at 240 million barrels.

USGS: 25% Arctic oil, gas estimate areporter’s mistake

IF YOU THINK THE ARCTIC con-tains 25 percent of the world’s remain-ing undiscovered petroleum, you’re notalone. So do numerous writers, speakersand industry experts who have beenquoting that figure since 2000.

see INSIDER page 17

There is also support for the idea that anyoil produced in the Beaufort could find itsway to market through the trans-Alaskaoil pipeline rather than a new pipeline

along the Mackenzie Valley.D

see BEAUFORT page 3

Herrera: ‘Cool It’ hugely logical“Cool It: The Skeptical Environmentalist’s Guide to Global

Warming” by Bjorn Lomborg is PNA Book Club’s third memberselection.

A “Cool It” book review by Roger Herrera appears on page 5of this issue of Petroleum News.

“‘Coot It’ takes on an issue that has become more emotionalthan scientific, but it does so by accepting much of the dogmaassociated with global warming without rancor or dispute andthen politely re-analyzing the conclusions reached in the KyotoProtocol to show that they are stupidly expensive and are coun-

see BOOK CLUB page 3

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

2 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

GOVERNMENT

EXPLORATION & PRODUCTION

ALTERNATIVE ENERGY

GUEST EDITORIAL

NATURAL GAS

BOOK REVIEW LAND & LEASING

OIL PATCH INSIDER

6 Commission confirms Burglin decision

AOGCC says well cannot be classified as gas well; based on DEC reinterpretation of regulations, reduces likely flow to 600 bpd

9 Chena gets Prudhoe geothermal grant

With DOE funds plans to test use of geothermal powerplant to extract energy from oilfield-produced water on Alaska’s North Slope

8 Premier Stelmach on teeter-totter

Alberta premier reportedly tells execs he won’t “trounce”royalty pacts; head of review panel warns government can’t “cherrypick”

7 MGM Energy breaks new ground

Mackenzie explorer strikes agreement to deliver gas to gathering pipelines; company wants assurance it can deliver what it finds

10 FEX puts NPR-A drilling on pause

Independent remains committed, but concerned about land access, high costs, fiscal regime, postpones drilling for two years

ON THE COVERNikaitchuq OK’d

Expansion approved; Eni applies forroyalty reduction, needs project sanction

Beaufort find is oil, not gas

Devon Canada gas hunt yields oil; company seeks partners; oil poses challenges

Royalty dread spreads

Natural gas, which adds more to Alberta coffersthan conventional crude, under attack

8 JPO centralizes lease compliance section

6 Potential Alaska state and federal oil and gas lease sales

5 Corruption trials are painful, but necessary

5 Therriault’s letter goes unanswered

3 Shell, Frontier sign JV to build drillships

4 “Cool It: The Skeptical Environmentalist’s Guide to Global Warming”

1 USGS: 25% Arctic oil, gas estimate a mistake

13 Advice for Alaska, U.S. governments

17 No “time out” for Alberta oil sands

Herrera says ‘Cool It’ hugely logical

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 3

But the company has no plans or meansto bring the oil into production.

The Significant Discovery designa-tion, reflecting a “common reality” that adiscovery may not be sufficiently eco-nomic in size or location to be developedimmediately, effectively gives DevonCanada indefinite tenure, allowing it timeto make further discoveries or developnew infrastructure.

Devon needs timeFor now, Johnston said Devon Canada

needs more time to weigh its optionsbefore deciding what to do next.

He said the economic, environmentaland regulatory challenges of oil develop-ment in the Beaufort have to be evaluat-ed, given the fact that the closest liquidspipeline in the Northwest Territories endsat Norman Wells in the CentralMackenzie Valley.

However, the MGP plans allow for apossible twin gas liquids pipeline fromthe Mackenzie Delta to Norman Wells,with Calgary-based Enbridge seen as thelogical operator.

Enbridge’s existing pipeline fromNorman Wells to Zama in northwesternAlberta has about 20,000 barrels per dayof unused capacity.

Without referring directly to Enbridge,Johnston said he would “love to see aCalgary-based company extend a pipelineto the Delta.”

Otherwise, he said oil is “a lotmessier” to contemplate bringing on-stream in the Beaufort, given concernsabout the fragile environment and marinelife.

Johnston said Devon Canada, as it hasbeen for some time, is ready to involvepartners in the Beaufort

The declaration of a significant dis-covery covers Exploration License 420,created from a 2002 Department ofIndian Affairs and Northern Developmentapproval for Devon Canada to consoli-date four ELs, which meant the companyhad to drill four wells to meet its workcommitment of C$224 million and retainits exploration rights.

Johnston said Devon Canada “will notdrill another 100 percent well” in the EL.The Paktoa well cost about C$60 million.

As a result, he said, the balance of theEL will expire and Devon Canada willhonor its commitment to pay a percentageof the work deposit, minus any allowableexpenditures.

Discovery could be shiftThe Beaufort oil discovery represents

a turning back of the clock in Canada’sNorth and could be a shift in the dynam-ics of the region.

During the height of an explorationboom in the 1970s and 1980s, whendrilling was supported by billions of dol-lars in federal government incentives,companies were chasing oil, but manyfound gas at a time when prices were solow that development was uneconomic.

Johnston said other companies arenow likely to be chasing oil because, asDevon Canada has learned “the hardway,” the area is oil prone, with an esti-mated 840 million barrels of recoverableoil in large nearby fields. The GeologicalSurvey of Canada believes the onshoreand offshore region has 1.3 billion barrelsof oil and 13 trillion cubic feet of gasfrom 194 exploration wells and 49 decla-rations of a significant discovery.

The Paktoa well is about 20 milessouth of the 1979 Tarsiut discovery, esti-mated at 150 million barrels of oil and 29billion cubic feet of gas, and about 60miles southwest of Amauligak, which hasan estimated 350 million barrels of oiland 1.3 trillion cubic feet of gas.

A 1984 discovery by Gulf CanadaResources, since absorbed intoConocoPhillips Canada, Amauligak car-ries a 25-year production license issued in1989 that has never been activatedbecause there is no means to get the oil tomarket.

EL 420 is also south of an EL acquiredin the summer by a joint venture ofImperial Oil and ExxonMobil Canada.

It covers 508,000 acres and a workcommitment of C$585 million, whichrequires combined spending of aboutC$146 million within five years to gain afour-year extension, while ChevronCanada bid C$1 million for an EL justwest of Devon.

Imperial has declined to talk about itsplans, beyond insisting the bid was “sep-arate and independent” from the MGPand would be approached in its “ownright.”

Company spokesman Pius Rolheisertold Petroleum News exploration plan-ning is at a “very preliminary stage,”although no activities are scheduled forthis winter.”

He said the normal procedure would beto acquire some seismic prior to drilling.

Pending firmer guidance fromImperial, some analysts have speculatedthe objective could be oil because of thehistory of significant finds in that portionof the Beaufort.

There is also support for the idea thatany oil produced in the Beaufort couldfind its way to market through the trans-Alaska oil pipeline rather than a newpipeline along the Mackenzie Valley. ●

continued from page 1

BEAUFORT EXPLORATION & PRODUCTIONShell, Frontier sign JV to build drillships

Shell EP Offshore Ventures Ltd. and Frontier Drillships Ltd., a subsidiary ofFrontier Drilling, have signed a deepwater/Arctic drillship joint venture agree-ment, Shell said Oct. 16.

Under the JV, Shell and Frontier will build and rollout a new drillship con-cept known as the “Bully” rig, a design that was developed by Frontier in coop-eration with Shell’s deepwater experts.Shell said the design offers a flexible,smaller but highly capable, vessel suitedfor deepwater and Arctic drilling, whilereducing the construction and opera-tional costs compared to current new-build drilling rigs of similar capability.

Shell said the Bully drillship’s innova-tive design offers flexibility and rapiddeployment, setting the standard fortechnologically advanced vessels.

The vessel will be capable of drilling with surface blowout preventers in upto 12,000 feet of water, and will feature an ice class hull, which Shell saidallows for safe and efficient operation in Arctic conditions.

The design calls for less crew and fuel, allowing for competitive day rateswhile offering safer operations.

The new drillship will have a significantly reduced environmental impactdue to lower emissions through reduced fuel consumption, high efficiency/lowemission engines and lower steel use for construction, Shell said.

The Shell/Frontier JV expects to deliver the first Bully rig to the Gulf ofMexico by early 2010. The vessel will be operated by Frontier under a sepa-rate management services contract.

“In meeting the energy challenge, Shell has a significant requirement fordrillships in the short to medium term to enable us to undertake our deepwaterand potential arctic drilling programs,” Shell E&P executive vice president ofdevelopment and technology, Dr. Matthias Bichsel, said, the Bully “concept willlead to our drillship requirements being met at lower cost and with improvedenvironmental performance. This, coupled with the ability to rapidly deploy the‘Bully’ rig to Shell deepwater projects between areas like the Gulf of Mexico,Nigeria, Brazil, the Far East and Northwest Europe brings tremendous advan-tages for managing our drilling prospects and their sequencing.”

—PETROLEUM NEWS

terproductive to the best interests of theworld’s population,” Herrera said.

Lomborg concludes that Kyoto, if putinto practice, would succeed in reducing theworld’s average temperature by 0.3 Ftowards the end of the century at a cost ofmore than $5 trillion. “Hardly a bargain or asolution,” Herrera said.

“Cool It” is unusual for a PNA BookClub selection in that it deals with the sci-ence of the oil and gas industry on only acursory level.

But Herrera thinks every oil industryemployee and every energy CEO shouldread it. He said the book has “the greatattributes of being short … highly readableand hugely logical.”

So instead of being recommended read-

ing, the book club’s editor decided to makeit a club selection.

A member forum review for “Cool It”starts Nov. 26, at www.pnabookclub.com.(The member forum for “Oil on the Brain,”the book club’s second selection, just gotstarted.)

PNA Book Club is owned by PetroleumNewspapers of Alaska LLC, which publish-es Petroleum News, a weekly oil and gasnewspaper based in Anchorage, Alaska.

Whereas the newspaper’s goal is to pro-vide objective news about the oil and gasindustry in Alaska, and northern and west-ern Canada, PNA Book Club is set up to putpeople from the energy industry in touchwith authors of popular books: sometimesto educate them about the industry if theirbooks contain misinformation; sometimesto congratulate them for accurately portray-ing the science behind the industry.

—PETROLEUM NEWS

continued from page 1

BOOK CLUB

Under the JV, Shell andFrontier will build and rollouta new drillship concept knownas the ‘Bully’ rig, a design thatwas developed by Frontier in

cooperation with Shell’sdeepwater experts.

By ROGER HERRERAFor Petroleum News

anish pragmatist Bjørn Lomborg hasdone it again. His first book, “TheSkeptical Environmentalist” infuriat-ed the Green lobby and propelled

him to become “one of the world’s 100most influential people.” His new book,“Cool It” confirms that opinion.

Cool It is a book that should be read byevery oil industry employee and everyenergy CEO. It hasthe great attributes ofbeing short (160pages of text, plus150 pages of notesand references), high-ly readable and huge-ly logical.

Once again it willbe hated by theGreens and manynational governments that have weddedthemselves to the Kyoto principles for solv-ing global warming.

It takes on an issue that has becomemore emotional than scientific, but it doesso by accepting much of the dogma associ-ated with global warming without rancor ordispute and then politely re-analyzing theconclusions reached in the Kyoto Protocolto show that they are stupidly expensiveand are counterproductive to the best inter-ests of the world’s population.

In essence he concludes that Kyoto, if

put into practice, would succeed in reduc-ing the world’s average temperature by 0.3F toward the end of the century at a cost ofmore than $5 trillion — hardly a bargain ora solution.

Most importantly Lomborg uses costsand other figures produced by theIntergovernmental Panel on ClimateChange, known as IPCC, which was set up

to publish policy-neutral, scientificallypeer-reviewed information on climatechange for use by decision makers.Unfortunately, IPCC, despite its brief, hastaken an extreme position and opts for verydeep cuts of CO2. Thus his arguments usehis opponents data, not his own.

Courteously shreds Gore’s slide showObviously, to make his point, Lomborg,

has to rebut Al Gore’s slide show, “AnInconvenient Truth” together with theinfluential report authored by Sir NicholasStern and published by the BritishGovernment last year. He gently tears bothopinions into shreds, but without an unkindword or emotion. He is deferential in thecare he takes not to personalize his analy-sis, but he shows with certainty and clarityhow both authors have exaggerated andemotionalized their conclusions and by sodoing have potentially damaged the worldrather than helped to save it.

Up front Lomborg accepts man’s influ-ence on the present phase of global warm-ing. There is no discussion in the book tosuggest anything but human induced car-bon dioxide as the cause of the world tem-perature increase.

Also, although he is opposed to Kyoto-

like solutions, he is a strong supporter ofways to reduce carbon dioxide production.His thesis is that most of the world, exclud-ing the United States, Australia, India andChina and most third world countries, aregoing about it in the wrong way.

He points out that more people die ofmalaria, an easily eradicable disease, thanwill ever be baked by temperature increas-es.

Cold kills more people than heatHe also gives convincing statistics to

suggest that world deaths induced by coldweather are far more numerous than thosecaused by heat, consequently a temperaturerise, especially in winter, saves many morelives than it causes.

His bottom line is that the only moralway of approaching CO2 reduction is bycomparing its costs against the benefits toall of us. If the cost of slightly reducingCO2 levels exceeds by orders of magnitudethe expense of eradicating malaria or thecost of supplying clean water to the thirdworld, Lomborg has no doubt where themoney should be spent. It should be usedto save the tens of millions of lives that areeasily savable.

He reaches this conclusion because ofwhat he shows to be the gross exaggera-tions of the warming lobby. For example,he argues that Al Gore’s 18 to 20 feet risein world sea level will actually be a maxi-mum of 12 inches — an amount easilycontainable by logical policies.

Consequently saving lives does notautomatically place them at greater riskfrom climate change. Lomborg thinks thatmoney wasted in trying to reduce CO2should be allocated, among other things, tonon-carbon emitting energy technologieswhich, he believes, are now woefullyunderfunded. The end result would be lessmoney wasted and less carbon dioxide pro-

4 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

● B O O K R E V I E W

‘Cool It: The Skeptical Environmentalist’sGuide to Global Warming’

DPNA Book Club Member ChoiceTITLE: Cool It: The Skeptical Environmentalist’s Guideto Global WarmingAUTHOR: Bjørn Lomborg TYPE: NonfictionPAGES: 272PUBLISHER: Knopf; 1st edition DATE PUBLISHED: September 2007BOOK CLUB FORUM ACTIVE: Nov. 26-Jan. 14BOOK CLUB WEB SITE: www.pnabookclub.com

BJØRN LOMBORG

In essence he concludes thatKyoto, if put into practice, wouldsucceed in reducing the world’saverage temperature by 0.3 F

toward the end of the century at acost of more than $5 trillion —hardly a bargain or a solution

see REVIEW page 6

By SEN. GENE THERRIAULT For Petroleum News

he recent jury verdicts in the publiccorruption trials of former Alaskalegislators have been disturbing, tosay the least. As a strong supporter

of the legislative process in our demo-cratic system of checks and balances, Itake no pleasure in seeing Alaskans’ con-fidence in our repre-sentative system ofgovernment shakento its very founda-tion.

As difficult asthis is to bear, Ibelieve it is neces-sary to begin restor-ing confidence inthe Legislature. Forthis reason, I recent-ly chose to attendportions of the trialof former speaker ofthe House Pete Kottto show that mem-bers of theLegislature arewatching to fullyunderstand the ille-gal activities thattranspired in therecent oil and gastax debate.

Not just RepublicansWhile some observers take satisfac-

tion that the current investigations reflectbadly on Republican legislators, areview of the past indicates that impro-priety by elected officials is not limitedto a particular party.

A quick review of Alaska legislatorswho have crossed legal and ethicalboundaries shows that individuals ofboth major parties have succumbed tothe siren song of money, power andinfluence.

The last legal proceedings against amember of the Legislature for corruptionoccurred in the early 1980s when both aDemocrat and Republican were forcedfrom office. Democratic Sen. GeorgeHohman of Bethel was convicted ofbribery in 1981 for trying to steer thestate into the purchase of a controversialaircraft for fire suppression efforts. Oneyear later Republican Sen. EdDankworth of Anchorage left office afterformal charges of corruption werebrought against him, although he ulti-mately avoided prosecution on a legaltechnicality.

These gentlemen tried to use theirpositions of influence in the Legislatureto obtain a personal monetary benefitwith little or no regard for what was bestfor the state.

There is no surprise that individualshoping to secure influence in ourLegislature search out officials who holdthe reins of power at the time. In thecases cited above, Hohman and

Dankworth tried to use the strength oftheir committee positions to enrichthemselves. In both instances, those whowere interested in circumventing thelegitimate process approached legislatorsin positions to “git er done.”

Reminiscent of North Carolina caseOn the day the Pete Kott trial began, I

was reminded of a recent conviction in asimilar case in North Carolina where aformer speaker of the House surrenderedto authorities to begin serving a five-yearsentence for corruption. The differencewas that the corrupt official there hadrisen to power as a Democrat, whereasKott is a Republican. The similarity inthese cases has reinforced my belief that,although those indicted, searched andquestioned here in Alaska have been pri-marily Republicans, bad actors are not aproduct of a particular political philoso-phy or party, but rather a reflection of ageneral human failing. That failing issusceptibility to the lure of power, wealthand influence.

For the past two years I have beenpart of a group of senators who openlyquestioned the previous administration’spetroleum tax proposal. This group cutacross party lines in open defiance ofSenate leaders at the time, and demandedindependent analysis of how to protectthe state’s best interest. What transpiredin that debate is perhaps the longest andnastiest policy battle since statehood.

Numerous votes and actions in thepetroleum tax debate caused me to ques-tion the motives and loyalties of bothRepublican and Democratic colleagues.The ongoing federal investigation andprosecutions have answered some of

these questions; however, others are like-ly to persist until the investigation con-cludes.

As discomforting as the current situa-tion is, I believe what will emerge is astrengthened legislative process thatAlaskans can be proud of.

However, there will always be a needfor elected officials to be constantly onguard for the sense of privilege that cansneak up on anyone who is given even amodicum of power. ●

Sen. Gene Therriault is a Republicanfrom North Pole.

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 5

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● G U E S T E D I T O R I A L

Corruption trials are painful, but necessary

Sen. Gene Therriault, R-North Pole sent the following letteron Aug. 30 to the Legislature’s independent economic consult-ants via Rep. Ralph Samuels, R-Anchorage, chairman,Legislative Budget and Audit Committee and is still awaiting aresponse.

Dear Ralph:

Although the Legislature cannot start evaluating GovernorPalin’s proposed changes to oil and gas tax law until she pres-ents her plan next week, I believe it would be prudent to askEconOne to review recent developments that could impact theeffectiveness of the current PPT mechanism.

Primarily, I want to know why the economic modelingused during the PPT debate miscalculated expected revenuesby such a wide margin. Administration staff have disclosedthat the operations and capital expenses on oil and gas activi-ties are significantly higher under PPT than were anticipated.Consequently, I believe we should review the data set that wasused in the PPT model to estimate these cost components. Iwould also like to know if EconOne agrees with the adminis-tration regarding how much of the estimated “shortfall” can beattributed to higher costs.

I would also like an opinion on whether the higher thanexpected costs in Alaska match the escalation in other areas ofthe world. I would like to determine what portion of the highercosts stem from the expenses associated with the corrosion

response and cleanup on the North Slope. This emergencyresponse may be responsible for a “spike” in the cost of doingbusiness in Alaska that outpaces increases in other oil and gasproducing regions. If so, knowing whether expenses will comedown from a temporary high point could be crucial in ourupcoming deliberations.

Because only a portion of the lower than expected revenueappears to be attributable to cost factors, I would like an expla-nation of other factors that contribute to the difference.

While I expect the Governor to provide this informationwhen she presents her special session package, I would like toknow if EconOne agrees with the administration’s assessmentof the items that account for the total revenue difference.

I also have the following direct questions for the adminis-tration on the subject of revenue modeling during the PPTdebate. Because the majority of the model was built in 2005,does that mean the administration used 2004 data? If so, didnew cost data become available as we proceeded through thePPT debate in 2006 that would have indicated higher thanexpected costs? If new data was available, when was it avail-able, and was it used?

Rather than submit questions to the administration separate-ly, it may be advisable for the inquiries to come from theLegislative Budget and Audit Committee. I would welcomeyour thoughts on this.

Sincerely,Gene Therriault

T

For the past twoyears Sen. GeneTherriault, R-NorthPole, has been partof a group of sena-tors who openlyquestioned theMurkowski adminis-tration’s petroleumtax proposal. Thisgroup cut acrossparty lines in opendefiance of Senateleaders at the time,and demandedindependent analy-sis of how to pro-tect the state’s bestinterest.

Therriault’s letter goes unanswered

duced. Obviously a win-win.

Escaping poverty crucialAlthough he is very careful in express-

ing his personal opinions, Lomborgbelieves that restrictions and barriers to freeand fair trade between nations cause moreharm than global warming ever will. Suchrestraints prevent most of the world’s poor-er people from ever escaping out of pover-ty. Only economically self-sufficient peoplehave the opportunity of controlling theircarbon output and protecting their environ-ment, therefore continued poverty imposedby restraints on trade, compounds globalwarming.

This book is crammed with interestingdetails, but despite the heaviness of theissue it is a good read and it is very wellwritten.

The author acknowledges help fromfriends with the English text, but his writ-ing ability shines through, as does his per-sonality. His approach to such a controver-sial and important issue is very likeable andfair, and friend or foe of global warmingcan learn a lot from this book.

The rest of us should read it to under-stand the politics and options that mightcloud the rest of our lives because of globalwarming.

We should read it to counter the “chore-ographed screaming” of “Fear, terror anddisaster,” being bandied about.

And we should read it to prevent ourpoliticians imposing excessive, counter-productive taxes and constraints thatalways seem to affect us after the politicianhas left office.

There is much to fear in global warm-ing, but little of that fear will be induced bytemperature rises.

Read this book! ●

6 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

continued from page 4

REVIEW

LAND & LEASINGPotential Alaska state and federal oil and

gas lease salesAgency Sale and Area Proposed Date

DNR Beaufort Sea Areawide Oct. 24, 2007

DNR North Slope Areawide Oct. 24, 2007

MHT 2007 Oil & Gas Sale Nov. 14, 2007

MMS Sale 193 Chukchi Sea Feb. 6, 2008

DNR Alaska Peninsula Areawide Feb. 27, 2008

DNR North Slope Foothills Areawide Feb. 27, 2008

DNR Cook Inlet Areawide May 21, 2008

DNR Beaufort Sea Areawide October 2008

DNR North Slope Areawide October 2008

BLM NE NPR-A To be determined

BLM NW NPR-A To be determined

DNR Alaska Peninsula Areawide February 2009

DNR North Slope Foothills Areawide February 2009

DNR Cook Inlet Areawide May 2009

DNR Beaufort Sea Areawide October 2009

DNR North Slope Areawide October 2009

MMS Sale 209 Beaufort Sea 2009

MMS Sale 211 Cook Inlet 2009

DNR Alaska Peninsula Areawide February 2010

DNR North Slope Foothills Areawide February 2010

DNR Cook Inlet Areawide May 2010

DNR Beaufort Sea Areawide October 2010

DNR North Slope Areawide October 2010

MMS Sale 212 Chukchi Sea 2010

MMS Sale 217 Beaufort Sea 2011

MMS Sale 214 North Aleutian basin 2011

MMS Sale 219 Cook Inlet 2011

MMS Sale 221 Chukchi Sea 2012

Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, man-ages leasing in the National Petroleum Reserve-Alaska; DNR, Alaska Department of

Natural Resources, Division of Oil and Gas, manages state oil and gas lease sales onshoreand in state waters; MHT, Alaska Mental Health Trust Land Office, manages sales on trust

lands; MMS, U.S. Department of the Interior’s Minerals Management Service, Alaskaregion outer continental shelf office, manages sales in federal waters offshore Alaska.

This week’s lease sale chartsponsored by:

PGS Onshore, Inc.

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

Commission confirmsBurglin decisionAOGCC says well cannot be classified as gas well; based on DECreinterpretation of regulations, reduces likely flow to 600 bpd

By KRISTEN NELSONPetroleum News

he Alaska Oil and Gas ConservationCommission has confirmed its deter-mination that the Burglin 33-1 well inthe Arctic Fortitude unit on the North

Slope cannot be classified as a gas well.Alaskan Crude Corp. plans to re-enter theBurglin 33-1 to test the Ugnu and West Sakformations.

The commission said “neither new infor-mation nor compelling arguments weresubmitted to justify amending the determi-nation.”

However, the commission said, itamended its second recommendation on theamount of oil flow likely from the well“based on a submission of the AlaskaDepartment of EnvironmentalConservation.”

These decisions relate to spill responserequirements: DEC determines spillresponse requirements for explorationdrilling; the commission advises DEC onhow much oil, if any, a particular well mayencounter and whether a well can be classi-fied as a gas well exempting it from spillplanning.

In its Oct. 1 reconsideration order thecommission said Gregory Micallef, anoverriding royalty owner, and AlaskanCrude, the unit operator, appealed the com-mission’s June 26 decision, asking that theBurglin 33-1 be classified as a gas well.

Alaskan Crude’s original request hadbeen for an 85 percent reduction in theresponse planning standard for an oil explo-ration well.

The commission said in June thatbecause there were signs of oil in coresfrom the Burglin 33-1 well, drilled in 1985,and the Ugnu and West Sak formations con-tain moveable oil elsewhere on the NorthSlope, “it is inappropriate to classify thisexploratory well as a gas well.” The com-mission then applied the Alaskan Crude-requested 85 percent response planningstandard, based on DEC’s interpretation ofits regulations at that time, and said the por-tion of the Ugnu and West Sak formationsAlaskan Crude proposed to test wereunlikely to produce liquid hydrocarbons tothe surface in counts greater than 825 bar-rels per day of oil.

Micallef, Alaskan Crude appealIn July, Micallef and Alaskan Crude

appealed the commission’s decision, askingthat the well be classified as a gas well,removing the need to meet a response plan-ning standard for a potential oil spill.

The commission held a hearing on theappeal Sept. 6.

The commission said Oct. 1 that whileno parties appeared at the hearing, itreceived comments from DEC.

DEC noted that Alaskan Crude had notsought a determination that the Burglin 33-1 was a natural gas exploration well, butinstead applied for an oil discharge preven-tion and contingency plan to develop thewell as an oil and gas exploration well.

DEC also said it has changed how itinterprets the reduction limitation in its reg-ulations. Under the original interpretation

T

see BURGLIN page 7

For Petroleum News advertising inquiries, please contact Susan Crane

at 907.770.5592

By GARY PARKFor Petroleum News

GM Energy, the Calgary-based junior explorerwith big ambitions for Canada’s Far North, hassigned the first “outside” deal to deliver naturalgas to the proposed Mackenzie Valley pipeline.

The capacity request agreement secures 200 millioncubic feet per day of space on the gathering system con-necting the Mackenzie Delta fields to the main pipeline.

MGM President Henry Sykes said the agreementgives the Mackenzie Gas Project proponents, govern-ments and other parties “tangibleevidence that additional volumes ofnatural gas are committed” to theproject.

Until now, the only assured vol-umes are from the Delta anchorfields owned by Imperial Oil, ShellCanada, ConocoPhillips Canadaand ExxonMobil Canada.

“This agreement enables the nat-ural gas MGM Energy currentlyowns (estimated at 400 billion cubicfeet of contingent resources) and forwhich it is exploring to be delivered to the MackenzieValley pipeline on startup, assuming that the project pro-ceeds,” Sykes said in a statement.

Imperial spokesman Pius Rolheiser told PetroleumNews “we definitely see this as a positive step, althoughthe project obviously has outstanding issues to resolvebefore we can decide to proceed.”

But he welcomed the firm expression of interest byMGM as a means of reducing some of the “surpluscapacity” built into the 1.1 billion cubic feet per daydesign for the gathering system and a signal of “activeexploration interest in the region.”

In return, MGM will gain observer status, allowing it

to provide input on system design and other issues.Rolheiser said that regardless of the built-in surplus, it

makes economic sense to run the pipelines “as close tocapacity as we can.”

MGM actively exploringSykes told the Globe and Mail MGM took the step

because of the money it plans to spend in the upcomingwinter exploring for gas in the Delta.

“People need to know if we find it that we’ll deliverit,” he said.

He said the deal positions MGM, a spinoff early thisyear from Paramount Resources’ assets in the CentralMackenzie Valley, to eventually negotiate for capacity onthe main pipeline.

But for now it is simpler to reach an agreement on thegathering system, Sykes said.

E&P companies operating in the Delta outside of theMGP partners along with the Northwest Territories gov-ernment have been waging a regulatory battle over thelast two years to have both the main line and gatheringsystem operate under a single regulator.

MGM is positioned to be the most active explorernorth of the 60th parallel this winter, with plans to spendC$60 million on three wells, plus C$35 million for seis-mic testing and C$7 million for general and administra-tive expenses, totaling C$102 million for 2008, comparedwith its anticipated expenditures of C$236 million thisyear, C$38 million for drilling.

Through public offerings, the company raised C$168million in May and C$106 million in August.

The only other scheduled activities for the winter aretwo wells by Husky Energy, one by Petro-Canada and avariety of seismic programs.

Two of MGM’s wells will be on Exploration License427 on the Delta’s west side and one is on EL 399 atTaglu near Tiginlikak.

Work continues on Mackenzie gas lineAlthough the Mackenzie Gas Project has been operat-

ing outside the public spotlight over recent months,Rolheiser said work continues on three major fronts:Completing regulatory hearings; negotiating benefits andaccess agreements with aboriginal communities along thepipeline right of way; and negotiating fiscal terms withthe federal government.

The NEB held oral hearings at Yellowknife, NWT,Oct. 10-16 to “test updated written evidence submittedsince the NEB’s scheduled hearing sessions ended in2006,” said review panel Chairman Ken Vollman.

The regulator now expects to wrap up its oral hearingsessions when it considers final argument, which willtake place after the Joint Review Panel releases its reportand recommendations on the potential socio-economicand environmental impacts of the project.

The NEB has indicated it expects the Joint ReviewPanel report will be completed in the second quarter of2008. The regulator then expects it will need five to sixmonths to respond to those recommendations before issu-ing its final go-no go decision.

Rather than either approving or rejecting the MGPapplication outright, the NEB is widely expected toapprove the project subject to certain conditions when itissues a verdict by about mid-2009.

Rolheiser said the 2009 target is “not inconsistent withwhat we have in mind,” and would still allow the MGP tostart delivering gas by 2014, in line with the revisedtimetable.

On the benefits-and-access negotiations, he said thereare some agreements-in-principle that must still be devel-oped into “full-blown” agreements, while talks withthe Deh Cho First Nations are “at a much earlierstage.”

He said the fiscal negotiations are “on-going andconfidential” and would say no more about them. ●

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 7

● N A T U R A L G A S

MGM Energy breaks new groundMackenzie explorer strikes agreement to deliver gas to gathering pipelines; company wants assurance it can deliver what it finds

M

MGM PresidentHenry Sykes

the absolute floor for the response planningstandard was set at 15 percent of 5,500 bar-rels per day or 825 bpd.

DEC told the commission that even ifthe commission determined that the expect-ed flow from a stratum is zero bpd thatwould not dictate that DEC set the RPS vol-ume at zero bpd.

Under its new interpretation of its regu-lations, however, DEC said the responseplanning standard for the Burglin 33-1would be reduced. Based on DEC’s amend-ed interpretation, the commission said itsnew determination is that the maximumflow rate for the Burglin well is 600 bpd.

One conclusion incorrectThe commission said it initially deter-

mined that there was reasonable certaintythat wells to the Ugnu or West Sak “in thisarea will not encounter liquid hydrocarbonbearing sands” in those formations.

The commission said that on reconsider-ation, it determined that conclusion to beincorrect.

Under statute, “at issue is not a determi-nation regarding the likelihood that a partic-ular well may encounter hydrocarbon bear-ing sands, but a determination regarding the

likelihood that a well ‘at a natural gasexploration facility’ may penetrate ‘a for-mation capable of flowing oil to the groundsurface.’ The Burglin 33-1 well is neither anatural gas exploration facility; nor couldthe Commission determine that the evi-dence demonstrates with reasonable cer-tainty that it will not penetrate a formationcapable of flowing oil to the ground sur-face,” the commission said.

The commission said the Burglin 33-1well “is not a natural gas exploration facili-ty,” which is defined in statute as a facility“used solely for the exploration for naturalgas.” The commission said Alaskan Crudesaid in its April 26 application that it intend-ed to produce liquid hydrocarbons and thatthe test zones, based on similar nearbywells, were expected to contain high-vis-cosity oil. Alaskan Crude did say it assumedthat oil would not flow to the surface andwould “mobilize equipment to pump ormechanically lift fluids to the surface.”

The commission also said it “could notfind that the available evidence demon-strates with reasonable certainty that theBurglin 33-1 well will not penetrate a for-mation capable of flowing oil to the groundsurface.” It said the West Sak formation,“even in the vicinity of the Burglin 33-1well — is indisputably capable of flowingoil to the ground surface.” ●

continued from page 6

BURGLIN

By GARY PARKFor Petroleum News

remier Ed Stelmach is expected to deliver a tele-vised fireside chat to Albertans on or close to Oct.24. The primary thrust of his message is equallyvague.

He may deliver the government’s final or partial ver-dict on royalty changes, although his office says he willnot duck the matter altogether.

But recent days have suggestedthat the sooner he takes a stand thebetter it will be for his governmentand the industry.

Amid a series of private meet-ings between cabinet ministers andthe corporate world, Stelmachspread confusion and was accusedof wilting under oil patch pressureon October 11 when he delivered aprivate speech to 50 business exec-utives in Calgary.

He was widely reported as saying he would “nottrounce” existing royalty agreements, putting himself atodds with his own appointed review panel, whichopposed allowing deals negotiated in past years toremain unchanged.

The National Post, which broke the story, reportedfrom notes compiled by some of the executives, whosaid Stelmach opposed rewriting agreements already inplace for fear of destroying international investor confi-dence in Alberta.

He told the gathering his objective is “fairness, stabil-ity and predictability” for the industry, leaving some ofhis audience hopeful that the premier understands thecomplexities of what he is dealing with.

Spokesmen for Stelmach said the National Post report

“sounds like something he might have said” and did notattempt to “disavow the quote.”

They insisted no final decisions have been made, butwere emphatic that Stelmach was not making any formalpronouncements.

Panel: don’t cherrypickHowever, there was a swift, sharp reply from panel

chairman Bill Hunter, who said the government hasbeen urged to apply the recommendations across theboard.

“If you start taking things away, it has an impact onthe total government take,” he said, adding the paneltold Stelmach “not to cherrypick” from the recommen-dations.

Hunter said that grandfathering would create dis-crepancies between existing and future projects, deny-ing Albertans the fair return they want from their natu-ral resources.

“Our intent is to simplify the royalty regimes andtaxes and fees, get rid of some of the historical stuff andthen apply the regime to all players within the oil andgas sector,” Hunter told the Globe and Mail.

Opponents say Stelmach cavingBrian Mason, leader of the Alberta New Democratic

Party, said Stelmach is clearly caving in to industrypressure and is selling Albertans out.

Noting the governing Conservative party collectedC$580,000 in funding from oil and gas companies in2005 and 2006, he said the government does not have“sufficient independence” from the industry, referring tothe closed doors sessions with industry executives tobolster that point of view.

“I think this premier is about as transparent as a slabof granite,” Mason said.

Liberal party energy spokesman Hugh MacDonaldsaid there is now plenty of evidence that Stelmach willfold in the face of industry threats to pull billions of dol-lars in spending from Alberta at the cost of thousands ofjobs.

“I would hope the premier doesn’t turtle,” he said.“But (the industry) certainly appears to be swayinghim.”

Pierre Alvarez, president of the CanadianAssociation of Petroleum Producers, although not at themeeting, reiterated that royalty agreements now in placemust be handled “very carefully,” assuming those dealshave the force of law.

There seems little doubt inside or outside govern-ment that doing nothing is not an option for theStelmach government.

What troubles many observers is how a largelyuntried and untested premier will handle such a monu-mental issue and whether he will be influenced by theneed to look bold and decisive if he plans to call an elec-tion this fall when two-thirds of Albertans reportedlywant to see the review panel’s recommendations imple-mented without change. ●

8 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

● G O V E R N M E N T

Premier Stelmach on teeter-totterAlberta premier reportedly tells execs he won’t ‘trounce’ royalty pacts; head of review panel warns government can’t ‘cherrypick’

Stelmach was widely reported as saying hewould “not trounce” existing royalty

agreements, putting himself at odds with hisown appointed review panel, which opposedallowing deals negotiated in past years to

remain unchanged.

P

Alberta Premier EdStelmach

There seems little doubt inside or outsidegovernment that doing nothing is not an option

for the Stelmach government.

GOVERNMENTJPO centralizes lease compliance section

State Pipeline Coordinator Mike Thompson has reorganized lease compliancepositions into a lease compliance section at the Joint Pipeline Office in Anchorageeffective Oct. 16.

Laura Chase, JPO public affairs officer, told Petroleum News that with the leasecompliance section centrally located in Anchorage JPO technical staff, including engi-neers, will be easily accessible to the entire section. The section includes positions thatwere formerly in Anchorage, Valdez and Fairbanks.

Chase said neither the State Pipeline Coordinator’s Office nor JPO are taking onadditional responsibilities. “This is an internal reorganization of positions that fallwithin the State Pipeline Coordinator’s Office,” she said.

The section, with five positions, will be responsible for all SPCO jurisdictionalpipelines, including the trans-Alaska oil pipeline and state pipelines. The reorganiza-tion combines both non-TAPS and TAPS surveillance staff, enabling cross trainingand providing additional coverage when staff are on leave. All five positions are cur-rently budgeted, so the change will not increase the budget, Chase said.

Bruce Novinska will be acting manager until the section manager position is filled. —PETROLEUM NEWS

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 9

www.asrcenergy.com

● A L T E R N A T I V E E N E R G Y

Chena gets Prudhoe geothermal grantWith DOE funds plans to test use of geothermal power plant to extract energy from oilfield-produced water on Alaska’s North Slope

By ALAN BAILEY & KAY CASHMANPetroleum News

ature oil fields such as Prudhoe Bay and Kuparukon Alaska’s North Slope produce vast quantitiesof water along with oil. That water is pumpedback into the oil reservoirs to continue to flush

oil out of the reservoir rocks.But heat in the water equates to vast quantities of

energy. Could some of that energy be captured, beforepumping the water back into the ground?

Bernie Karl, a passionate advocate for the use ofrenewable energy and owner of the Chena Hot SpringsResort in Alaska’s interior, thinks so. Karl has pioneeredthe use of low-temperature geothermal power in a 200-kilowatt electricity power plant at Chena and wants totry that same technology to generate electricity from pro-duced water on the North Slope.

“In Prudhoe Bay they have 1.2 million barrels of pro-duced water every day. … That water is at 150 degrees(F),” Karl told Petroleum News. “There’s no powerbeing made off that — all that energy … is being wast-ed.”

$724,000 grantThe U.S. Department of Energy has backed Karl’s

concept by awarding a $724,000 grant, matched by equalfunds from Chena Power and United TechnologiesCorp., and with assistance from BP, to modify the low-temperature geothermal turbine system developed atChena to use produced water from the Prudhoe Bay oilfield.

Sen. Lisa Murkowski, R-Alaska, announced the fed-eral grant on Oct. 15.

“This is an important project for Alaska. … Using thewater that today is just a waste product of oil and gasproduction can save energy in fossil fuel production and

could add clean electricity to our nation’s power grid. Itis an important project for the nation and the state,”Murkowski said in an Oct. 15 press release. The senatorhas been seeking a variety of grant aid from the federalgovernment to advance geothermal development, heroffice said.

The Chena Hot Springs power plant uses what isknown as an organic rankine cycle — geothermal waterat 165 degrees F evaporates a refrigerant that then drivesa generator turbine. Success with this system at Chenahas opened the door to power generation from relativelylow temperature geothermal sources.

In the North Slope application, Chena Power wants toinstall a single 225-kilowatt turbine to prove the conceptof generating electricity from produced water. If suc-cessful, the system could be expanded to supply a sig-nificant amount of power for the North Slope oil fields,

Karl said.“They can make 20 megawatts, if they so desire, but

you have to prove the concept,” Karl said.

Use anywhereKarl also said that a successful demonstration of the

technology on the North Slope would pave the way foruse of the technology anywhere in the world that thereare oil fields.

“There are 250,000 oil and gas wells in Texas alone.There are another 250,000 oil and gas wells that areclosed and shut-in,” Karl said. “They can produce10,000 megawatts within 24 months. They have 265degree (F) water they’re wasting.”

And rankine cycle power generation units of the typeused at Chena Hot Springs resort are available on requestfrom United Technologies Corp., Karl said.

“You can call up and order one of these units and getit,” he said.

But can the units be scaled to, perhaps, a single oilwell?

“In many oil wells there’s enough (water) out of onewell,” Karl said. “… At 163 degrees (F) you need 550gallons per minute.”

Oil companies view produced water as a nuisance, hesaid.

“I would like to turn that water into a positive forthem and I believe we can do that,” Karl said. ●

M

Then Gov. Frank Murkowski, Bernie Karl and Sen. TedStevens admire the Chena Chiller geothermal power plant atthe official opening ceremony in August 2006.

SAR

AH

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RST

“In Prudhoe Bay they have 1.2 million barrelsof produced water every day. … That water is

at 150 degrees (F). There’s no power beingmade off that — all that energy … is being

wasted.” —Bernie Karl, Chena Hot Springs Resort

By KAY CASHMANPetroleum News

EX L.P.’s decision to put its Alaskadrilling program on pause for twoyears came as a surprise to everyoneexcept those paying attention to the

federal government’s cancellation ofNational Petroleum Reserve-Alaska leasesales. Land access is the number one issuefor the Alaska subsidiary of Calgary-basedTalisman Energy, but the independent isalso concerned about what it refers to as the“increasing high cost of doing business” onAlaska’s North Slope.

In an Oct. 10, 2007, interview withPetroleum News, Talisman’s senior manag-er of global new ventures, Tim England,said “Alaska is increasingly less competi-tive in attracting exploration capital due tothe very high costs of remote explorationoperations, long timelines for development,many levels of regulatory oversight and lessattractive and unstable fiscal terms.”

But FEX would have been back to drillthe next winter if the U.S. Bureau of LandManagement had not deferred a NortheastNPR-A lease sale from 2007 to sometime inthe last half of 2008.

“FEX contemplated amulti-well, multiyeardrilling program in NPR-A.… Because the Northeastlease sale was cancelled, wecould not move our drillingrig to locations into theNortheast NPR-A for thisyear. Because we needed tostop and shoot seismic in theNorthwest, there wasnowhere for the rig to go sowe sent it back toDeadhorse,” England said.

To reduce capital expo-sure per well, he said, acompany has to do multi-well drilling programs ratherthan single drilling pro-grams. For FEX to developa multi-well program in theNortheast, it needed landreleased through lease sales.

“BLM has not held a salein the Northeast planningarea of the NPR-A since2002, contrary to the original plan of con-ducting sales every other year,” Englandsaid.

He said FEX’s activity inthe Northeast NPR-A plan-ning area, which was sup-posed to include wells in theupcoming 2007-08 season,“will be driven by access toland.”

This coming winter FEXwill be conducting a $25million seismic program onand offshore Smith Bay.

“One, we’re looking tocomplete our subsurfacecoverage over existing dis-coveries and, two, if we geta good ice year, we’ll con-tinue to shoot into SmithBay,” where FEX has Stateof Alaska leases, he said.

In both cases FEX islooking to identify drillingtargets.

“Realistically, the earli-est we could get back tooperations in the NorthwestNPR-A will be 2009-10,”

England said, because by the time the seis-mic acquired in 2007-08 has been evaluat-ed it will be late 2008, too late to plan andprepare for 2008-09 drilling.

Five wildcats, one sidetrack in less than five years

But despite its concerns and its decisionto put its Alaska drilling program on a two-year hold, FEX has made a lot of progresssince it first entered the state in late 2003.

Initially operating as FortunaExploration — later changed to FEX —Talisman’s Alaska subsidiary’s first stepwas to farm in to Total E&P USA’s Caribouprospect in Northeast NPR-A, where Totaldrilled a wildcat in the winter of 2003-04.

In mid-2004 Total E&P USAdropped allbut three of its 20 NPR-A leases, assigningeight leases covering the Caribou prospectto Talisman’s Alaska subsidiary.

When asked if FEX would drill a side-track or second well on the Caribouprospect the following winter, David Mann,manager of investor relations and corporatecommunications for Talisman, said thecompany would drill a NPR-A well in the

winter of 2005-06, but he didn’t know if itwould be at Caribou.

“Obviously we already have seismic onthe Total acreage. And obviously we haveour own views on geology and prospectivi-ty,” he said in regard to the 9,362 foot,Caribou 26-11 No. 1 well Total drilled, thenplugged and abandoned.

That same year FEX dominated a BLMsale for the Northwest NPR-A planningarea where it was the highest bidder withalmost $26.5 million in high bids. It alsooffered the highest amount for a single tractwith its winning bid of more than $13.7million for a lease near the Ikpikpuk Riverat the junction of the Northwest andNortheast planning areas.

The independent next dominated anOctober 2004 state Beaufort Sea lease sale,where FEX bid $3.5 million for a block of19 leases in Harrison Bay offshore NPR-A.

Eight wells in three yearsIn a July 2005 conference call, Talisman

executives said FEX would be drilling twowells in the Northwest planning area duringthe following winter’s exploration drillingseason.

In the same time period a newsletter wasdistributed to residents of the North SlopeBorough saying the two wells would be partof a three-year program for the winters of2005-06, 2006-07 and 2007-08 in which “atotal of two to three drill site ice pads will beconstructed per year” east and north of thevillage of Atqasuk and southeast of Barrowon the company’s acreage in NorthwestNPR-A.

In September 2005, paperwork filedwith the State of Alaska said FEX was look-ing at drilling a total of eight explorationwells in the three-year program.

Nabors Rig 14E and supplies werebarged to Cape Simpson from West Dock inthe summer of 2005. Mobilization via low-pressure vehicles into the area would hap-pen later that year after the tundra wasfrozen and covered with snow.

Looking for big numbersBy mid-2005 FEX’s acreage in and off-

shore NPR-A had grown to 443,000 acres.Talisman Executive Vice President John

‘t Hart, to whom England reported at thattime, said FEX was “looking at very bignumbers” from its Alaska acreage — on theorder of 250 million barrels of oil equiva-lent per prospect — with the potential toexceed 1 billion boe from something hereferred to as “the structure” within theNorthwest area that was to be drilled in thewinter of 2005-06. Because of the remote-ness of Alaska, he said “we are going for abig prize, bigger than we have ever drilled.”

In early 2006, Talisman CEO JimBuckee said his company spent C$49 mil-lion in Alaska in 2005 on seismic andpreparations for exploration drilling.

FEX did drill two wells that winter,although one was a sidetrack — not a sepa-rate prospect as originally planned. Theexploration drilling season on the NorthSlope, which is always in the winter whenthe delicate tundra is frozen and has a pro-tective snow cover, was exceptionally shortin 2005-06 due to a lack of snow coverearly in the season, preventing tundraaccess, and an earlier-than-usual spring.

In between, drillers had to shut downmore than once for some of the coldestweather on record.

The Aklaq 2 and sidetrack were drilled

10 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

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

FEX puts NPR-A drilling on pauseIndependent remains committed, but concerned about land access, high costs, fiscal regime, postpones drilling for two years

FThe Explorers, an annual publication from Petroleum News $1.95

2007

This article will appear inThe Explorers magazine,which will be released atthe annual ResourceDevelopment Council con-ference in mid-Novemberin Anchorage. TheExplorers features oil andgas companies that are invarious stages of exploringfor oil and gas in Alaska.For more information con-tact Amy Spittler,Petroleum News associatepublisher, ataspittler@petroleumnews.com or (907) 770-3506.

see FEX page 11

west of the Ikpikpuk River near the easternborder of the Northwest planning area, 154miles west of Prudhoe Bay.

Acreage number keeps growingIn the March 1, 2006, State of Alaska

areawide Beaufort Sea lease sale FEX took25 tracts covering 120,000 acres in SmithBay offshore NPR-A for a total of $1.46million, bidding from $10.29 to $20.48 anacre. Some of those leases were adjacent tofederal leases the company held onshore inNPR-A. (Smith Bay is west of HarrisonBay.)

In addition to complementing the com-pany’s land position south of CapeSimpson, FEX’s leases in Smith Bay couldline up with a possible exploration fairwayacross the northern part of NPR-A to thecompany’s existing leases on the west sideof Harrison Bay, Paul Decker fromAlaska’s Division of Oil and Gas toldPetroleum News following the lease sale.

Decker saw some particularly interest-ing exploration possibilities in Smith Bay.

“It’s a nice crestal position on theBarrow Arch, with shallow water and logis-tically connected to their onshore explo-ration program in NPR-A,” he said.

People have long known about four oilseeps on the coast at Cape Simpson, justwest of Smith Bay. It’s a natural oil trapwhere Brookian topset sands come upagainst shale in an ancient incised canyon,Decker said. The oil from the CapeSimpson seeps likely originates from an“oil kitchen” to the north, in a lowerCretaceous source rock system known asthe HRZ, Decker said.

“That would put this (Smith Bay) areasquarely in between the kitchen and theseeps,” he said. “So you probably have apretty good plumbing story to be able tocharge this with nice light oil.”

In addition to a possible Brookian play,there are potential Ellesmerian plays belowthe lower Cretaceous unconformity(ancient erosion has probably scoured outthe Beaufortian middle and upper Jurassicsands that are found in nearby onshorewells). The East Simpson No. 1 and No. 2wells on the coast near Smith Bay foundsome interesting Sadlerochit and Endicottsands below the lower Cretaceous uncon-formity, Decker said.

Alaska an exercise in logisticsIn addition to discovering oil at his com-

pany’s first wildcat in NPR-A, the Aklaq 2and sidetrack, Buckee said his companylearned just how cold it could be onAlaska’s North Slope.

“It’s damn cold up there,” he said in aMay 10, 2006, conference call.

It’s also surprisingly warm at times, said’t Hart.

A combination of those two extremesforced FEX to suspend drilling Aklaq 2 andits sidetrack in February in anticipation offuture testing.

Buckee and ’t Hart said the challengesran the gamut from a deep freeze as FEXwas barging equipment to the Aklaq site,followed by a warm spell that affected thetundra, to another cold snap.

“Alaska is an exercise in logistics,” said‘t Hart.

Weather aside, FEX was soon gearingup for its next round of drilling in the win-ter of 2006-07, this time with two drillingrigs.

Akita to build new Arctic rigThe big Nabors Rig 14E that FEX used

in 2005-06 was stacked at a staging area onthe shores of Smith Bay. But FEX was also

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 11

Arctic Wolf drilling rig ordered by FEX from Akita-Doyon joint venture for drilling in NPR-A. In the above photo the rig is drilling the Amaguk2 well in the winter of 2006-07, the first season it was used.

CO

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LISM

ANcontinued from page 10

FEX

see FEX page 12

interested in bringing a second, lighter-weight exploration rig to NPR-A — onedesigned to withstand the rigors of the FarNorth.

Calgary-based Akita Drilling wouldbuild it, FEX said, and Anchorage-basedDoyon Drilling would operate it. Each com-pany would own 50 percent of the rig,which would be under contract to FEX andTalisman for an unnamed number of years.

The rig, which would be brought in fromthe other side of the Colville River via low-pressure vehicles as soon as conditionsallowed, was named the Arctic Wolf.

Akita said the new rig would cost $13.2million to build.

Shooting for five wellsInitially FEX hoped for a favorable

2006-07 season in which five wells south ofCape Simpson and west of the IkpikpukRiver in Northwest NPR-A could be drilledwith the two rigs.

The program would involve building upto five ice pads and 81 miles of ice road, aswell as one 5,000-foot ice runway and sev-eral smaller airstrips, FEX said in paper-work filed with BLM.

Although FEX had nine well locationsstaked, it said in its plan of operations forthe 2006-07 exploration season that “proba-ble well sites would be at Aklaqyaaq No. 1and Aklaq Nos. 3, 6, and 7” and that “two tothree reservoir penetrations may be drilledat each of the locations during the 2006-07drilling season.”

Picks up more acreage While making preparations for the 2006-

07 drilling season, FEX was picking upmore acreage on Alaska’s North Slope.

In the September 2006 BLM lease salefor Northwest NPR-A more than 75 percent($10 million) of the high bids came fromFEX and its 60/40 bidding partner, Petro-Canada.

The partners took some 562,000 acres,paying an average of almost $18.50 an acre,and winning all 48 tracts on which they bid.

FEX/Petro-Canada also had the highestbid per acre for a tract when they took lease272 at $201.03 per acre for a total price ofalmost $2.3 million. It was adjacent to atract for which FEX paid $5.09 an acre in

the 2004 Northwest NPR-A sale. The companies’2006 bids were on tracts

south and west of a large block on the north-eastern edge of the sale area in which bothcompanies took acreage in the 2004 sale.The new acreage extended as far west asAtqasuk. In the north the companies filledin north and east of 2004 tracts.

Richard Garrard, geoscience managerfor FEX and the company’s top man on theground in Alaska, told Petroleum Newsafter the sale that the sale area is where thecompany shot proprietary 3-D seismic theprevious winter. This was followed by a 2-D program, England said Oct. 10, 2007.

First onshore state acreageIn the October 2006 North Slope areaw-

ide lease sale held by the State of Alaska,FEX took its first onshore state acreage —a block of seven leases west of the trans-Alaska oil pipeline including the oldAtlantic Richfield Susie 1 well. The compa-ny bid $413,805 for the tracts.

The Susie 1 was drilled in 1966 byRichfield, which would soon merge withAtlantic, at a surface geological structurenorth of Sagwon on the SagavanirktokRiver. Richfield drilled down through thecrest of the surface anticline at Susie.

“That well went down to 13,500 feet andhad some oil shows in the … upper part ofthe hole,” Gil Mull, an on-site geologist,told Petroleum News in 2002.Unfortunately, the shows did not prove eco-nomic for a remote well by 1968 standardsand Richfield abandoned the well inDecember 1966. A year later AtlanticRichfield, predecessor to ARCO, andHumble Oil, predecessor to Exxon, drilledthe discovery well at Prudhoe Bay, about 60miles north of Susie 1.

Mull, who gained a reputation as one ofthe top geologists working northern Alaska,also said “some of us were pushing hard tocontinue the Susie well on down to test theSadlerochit before that well was aban-doned.” (The top of the Sadlerochit group isthe Ivishak formation that forms the mainreservoir in the Prudhoe Bay field.)

FEX, Petro-Canada formally team upIn December 2006 a 30-day public

notice was posted by the State of Alaskasaying that Calgary-based Petro-Canada’sAlaska subsidiary had submitted an oil dis-charge prevention and contingency plan fora “multi-year exploration drilling program”in NPR-A. Drilling was to begin in the win-ter of 2007-08.

But while the company’s spill plan wasbeing processed by the Alaska Departmentof Environmental Conservation an explo-ration partnership between FEX and Petro-Canada was being hashed out for all of theirtracts in NPR-A, except for Petro-Canada’sacreage in the Brooks Range Foothillswhich it shared with Anadarko Petroleumand BG Group.

Three wells instead of fiveOn Jan. 19, 2007, at the Alaska Support

Industry Alliance’s annual Meet Alaskaconference, England was less enthusiasticabout Alaska than he and his superiors hadbeen in the past.

On the one hand FEX was forging aheadwith an aggressive exploration program inNPR-A, he said. On the other hand, issuessuch as land access, rising costs, permittinginefficiency and Alaska’s tax regime threat-ened the viability of the state’s petroleumexploration and development, England said.

He said that FEX, with almost 1.5 mil-lion gross acres under lease, was continuingdeep drilling done by industry in the early1980s. But modern drilling equipmentenabled the drilling to be done much morequickly than in the past, he said.

FEX, he said, was planning to spud

12 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

continued from page 11

FEX

see FEX page 13

Nabors Rig 14E drilling Aklaqyaaq No. 1 exploration well in NPR-A for FEX in the winter of2006-07.

CO

URT

ESY

TA

LISM

AN

another deep well, the Aklaqyaaq No. 1, onJan. 27.

“We should have completed our secondice pad today and we’re expecting to spudour Amaguq No. 2 well on Feb. 7,” Englandsaid.

FEX also hoped to spud a third NPR-Awell, the Aklaq No. 6, later in the winter,which totaled three wells in NPR-A for2006-07. This was down from the previousgoal of as many as five wells because oflater than expected tundra access.

Continuing challengesIn his January 2007 speech England said

NPR-A exploration continued to face manyof the challenges that existed during explo-ration of the region 20 years earlier. In par-ticular, operational costs were very high andbecoming higher.

While industry could manage its coststhrough partnerships, cost sharing, bybecoming more efficient and through theuse of new technologies, England said theState of Alaska could also help with costissues. He especially praised the state’sexploration incentive tax credit program.

“Without those substantial explorationincentive credits we wouldn’t be here,”England said. “That substantially affects ourability to compete for cash to explore inAlaska.”

The state might also be able to help inother ways, he suggested, perhaps throughtax credits for operational efficiencies suchas the use of modern drilling rigs. Taxincentives for drilling multiple wells in asingle drilling season might be another pos-sibility.

England also slammed the state’s switchfrom a petroleum severance tax to PPT, thenew oil and gas production tax passed in2007, saying it “effected a 25 percent loss inNet Present Value.” (The Alaska Legislatureconvenes in a special session Oct. 18, 2007,to look at changing the new tax in a mannerthat might increase the state’s take.)

Land accessAccess to North Slope land was also

proving problematic, England said in hisJanuary 2007 speech, noting there had beena time lag of two years between successiveNPR-A lease sales, and third-party pressurehad caused lease sale cancellations andpostponements.

“The federal administration should real-ly think about holding more frequent leasesales, providing greater access to its lands,”England said.

He also said that industry and govern-ment needed to take the appropriate steps tocurtail “nuisance litigation,” saying that hehad estimated that industry had expendedabout $40 million in preparing for theSeptember 2006 NPR-A lease, a substantialpart of which was pulled from the salebecause of a court ruling.

“Those (costs) are large numbers and weare less receptive to keep doing that in thefuture. … We’ve got to get it fixed,”England said.

Extend North Slope drilling seasonHe also urged people to seek ways of

extending the North Slope explorationdrilling season with a review of the criteriafor the tundra travel opening date. He saidthat FEX supported ideas for state or feder-al staging areas in remote areas, to enableequipment to be stored close to explorationareas during the summer.

“That could be a joint federal and stateinitiative, and we’ve had some discussion inthat regard,” England said.

Regulatory process too cumbersomeEngland also criticized the regulatory

process for North Slope operations aslengthy, repetitious and expensive. Peoplemust find ways of reducing the redundancyinvolved in doing multiple environmentalassessments in the same area year after year.Multiyear permitting might provide onesolution, he suggested.

From the state’s perspective, the crucialquestion was how to stem the decline in oilproduction, England said: “We need to drill

a lot more exploration wells on the NorthSlope to even have a chance to offset thatdecline.”

Still bullish on NPR-A England emphasized that FEX and

Petro-Canada remained bullish on theprospects for oil and gas development inNPR-A.

“We’re taking a long-term view to devel-oping our subsurface knowledge and ourexperience in building in our second operat-ing season,” England said. “… We aredeveloping good partnerships with theNorth Slope Borough stakeholders and wehope that will help us bring future develop-ment. … We have 157 people out in thefield right now.”

England ended his January 2007 presen-

tation with a photograph of the CapeSimpson oil seep on the Beaufort Sea coastof NPR-A.

“It’s still there and it’s massive,” he said.“… There is the potential for massivedeposits untapped … out in NPR-A, but weneed to drill a whole bunch more wells tofind them.”

Hints 2006-07 drilling successIn early March 2007 there were rumors

of FEX hauling truckloads of crude fromthe Aklaqyaaq No. 1 well.

Unfortunately for all companies drillingexploration wells on Alaska’s North Slope,the weather once again interfered withscheduling. Most exploration programs gotunder way in February, not December orJanuary.

The first official word from FEX on itsdrilling results came March 1, 2007, fromtop executives in Calgary to analysts.

This is part of what they had to say:

Q: Progress in Alaska?A: Talisman CEO Jim Buckee: “I think

there are six or seven wells drilling up there(referring to work of all operators) and weall spud approximately the same time inmid-February. ... The weather conditionsaffect everybody. Now that we’ve starteddrilling, though, the operation’s been goingvery well. ...We have seen some uphole gas.Hydrocarbons are not a problem.”

Q: P-50 reserve potential for the three

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 13

Advice for Alaska, U.S. governmentsWhen asked if he had any advice for Alaska Gov. Sarah

Palin and the federal government that owns much of theacreage in the National Petroleum Reserve-Alaska, TalismanEnergy executive Tim England said if the governor wants tosee continued investment in Alaska, the state should maintainfiscal stability and provide “regular, unencumbered access tolands.” Both are very important to Talisman Energy’s Alaskasubsidiary, FEX L.P., he said Oct. 10.

“For the federal government, royalty relief for marginalprojects and lease extension provisions need to be ratified forBLM lands, which are challenged by their remote and harshoperating environment,” England said.

England is senior manager of global new ventures for FEX’s parent, Calgary-based Talisman.

TIM ENGLAND

see FEX page 14

continued from page 12

FEX

JUD

Y P

ATR

ICK

Alaska prospects?A: Executive Vice President of

Exploration John ‘t Hart: “Yeah, actuallyAklaqyaaq could be the biggest … but Jimis quite correct in the hundreds of millionsof barrels for a P-50 (median reserve poten-tial) number, is the ... right number, but asignificant upside to these numbers.”

Q: On Alaska what is the lead time forthese fields going onstream?

A: Ronald J. Eckhardt, executive vicepresident, North American operations: “InAlaska the timeline’s pretty long ... very,very best — you know miraculous —would be 2012; I think 2014 — 13, 14 isprobably better.”

Hits in several formationsIn May 2007, Talisman had more to say,

this time in a press release and an inter-view with Petroleum News.

All three of the wells FEX drilled inNPR-A in 2007 encountered hydrocarbon-bearing sandstones in several formations,Talisman said.

One well — Amaguq No. 2 — was

plugged and abandoned and the other twowells — Aklaqyaaq No. 1 and Aklaq No. 6— were suspended, Talisman said.

Although weather conditions did notallow enough time to test the three wells— or the well and sidetrack that FEX haddrilled the previous winter — the “initialestimate of contingent resources present”in the formations of the two 2007 suspend-ed wells was “300-400 million barrels” netto FEX, which has a 60 to 80 percentworking interest in the leases.

In addition to the 300-400 million bar-rels, Talisman said “there is significant fol-low-up potential on many similar struc-tures on Talisman’s acreage if commercialproductivity is proven.”

The announcement was based on loganalysis and “strong gas and oil shows,including oil staining and free oil in thedrilling mud in one of the wells,” the com-pany said. The two wells encounteredmore than 225 feet of net hydrocarbon-bearing sandstones.

“I am very encouraged by the results ofour winter drilling program in Alaska,although disappointed that we did not havetime to test the wells,” Buckee said in theMay press release. “The presence of blackoil on the shakers is very positive as it con-firms the presence of mobile oil as

opposed to gas.” Although the well that was plugged and

abandoned encountered hydrocarbon-bearing sandstones, Talisman said AmaguqNo. 2 would be “subcommercial given cur-rent infrastructure” — a challenge all threeprospects face west of the Ikpikpuk River.The company said “recently acquiredhigh-fold seismic” will be used to analyzeAmaguq No. 2.

Talisman said FEX would test the restof the wells during the winter drilling sea-son of 2007-08, but soon after canceledthose plans when it appeared there wouldbe no NPR-A lease sales until the last halfof 2008.

Taking two years off After three years of wildcat drilling in

NPR-A, FEX said it would take two yearsoff to evaluate its five project areas innorthern Alaska with the goal of identify-ing drillable prospects for the 2009-10winter season, England told PetroleumNews July 20, 2007.

During that time FEX would be acquir-ing new 3-D seismic in the Smith Bayarea, onshore and offshore.

Drilling results looked promising, hesaid, but the cost of the NPR-A explorationprogram had been high. FEX wanted as

much data as possible before choosingwhere it would drill next amongst its fivenorthern Alaska projects.

“Drilling so far from infrastructure isvery expensive in Alaska. Before we spendadditional money on drilling and testingwe need to complete our seismic data,because we want to be sure we are drillingin optimum locations,” England said. (Theclosest FEX well in Northwest NPR-A isabout 150 miles from a common carrierpipeline.)

“Once you’re out of the field in thespring you only have about four weeks todecide if you’re going to keep the equip-ment out there and go back in the follow-ing winter,” he said, noting that “even ifyou just go out to test wells the costs arestill very high … because so much of whatyou’re paying for is fixed costs … formaintaining a presence in the area. Youhave to have similar equipment out thereno matter what you’re doing, drilling orjust testing.”

Five project areasAs of mid-October 2007, FEX’s five

project areas in Alaska include Smith Bayonshore in Northwest NPR-A; Smith Bayoffshore in state waters; Caribou inNortheast NPR-A; Harrison Bay offshoreNPR-A, where the company has alreadyshot 3-D seismic; and onshore stateacreage near the trans-Alaska oil pipelineon the central North Slope, where the com-pany plans “subsurface evaluation andgeophysical surveys” during the next twoyears, England said.

To date, FEX has invested $185 millionin drilling and seismic and acquired950,725 net acres since entering the state,he said.

The company’s 2007-08 Smith Bayseismic program would “provide 60 to 70jobs, mostly to contractors,” England said.“Kuukpik-CGGVeritas will carry out thesurvey.” FEX will be “consulting with thecommunity of Barrow about our plans onOct. 23,” England said.

“During drilling this past winter we hadabout 220 people, mostly in the field work-ing for contractors.”

During the coming year’s evaluationphase, he said FEX would continue toemploy five full-time employees in itsAnchorage office. (As of mid-October,there were still eight people working in itsAlaska office.)

Is FEX looking to sell its North Slopeacreage or bring in another partner (inaddition to Petro-Canada)?

“FEX is not looking to sell its Alaskaacreage. This winter we are acquiring sub-stantial new seismic data, which will bereviewed in 2008, and from those reviewswe will be able to set our plans for futureexploration activity. Additional partnerscould be considered at that point,” Englandsaid.

On May 30, 2007, Jim Buckee, 62,resigned as Talisman’s chief executiveofficer, a position he had held for 14 years,to spend more time with his grandchildren.He passed the controls to John Manzoni,47, most recently the head of BP’s refiningand marketing operations and once seen asa leading candidate to replace chief execu-tive officer John Browne.

Buckee, backed by a doctorate in astro-physics from Oxford University, was pres-ident and chief operating officer of BPCanada in 1991 when it spun off itsCanadian assets at that time to createTalisman. ●

Editor’s note: In addition to RichardGarrard in Anchorage and Tim England inCalgary, another lead individual workingon FEX’s Alaska operations and assets isCalgary-based Kim Safton, Talisman’sNorth America frontiers exploration man-ager, who reports to England.

14 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

continued from page 13

FEX

panel and raises its take from gas to 63 per-cent from 58 percent, the message from theindustry is that the gas will effectivelyreturn to its dismal past, when it was large-ly an unwanted byproduct of oil production.

Drillers: increase would makegas drilling too expensive

Don Herring, president of the CanadianAssociation of Oilwell Drilling Contractors,said implementing the royalty increase willmake gas drilling in Alberta too expensiveand will result in fewer wells and more jobsbeing lost.

He said the wheels are already starting tofall off the gas industry cart, with disastrousresults for his member companies, whichderive 70 percent of their work from gasdrilling.

Paul Ziff, chief executive officer of theconsulting firm Ziff Energy Group, hasquestioned whether the government hasbeen provided with enough accurate infor-mation from an Energy Department techni-cal report to make a correct decision on con-ventional gas royalties.

That report said that “despite theincrease in costs in recent years, there is evi-dence that (gas) costs are still competitive,”contending that Alberta still ranks “belowaverage in terms of profitability in NorthAmerica.”

Citing a case study by IHS/CERA, theEnergy Department contends that the aver-age total cost including capital, operating,return on capital, severance tax and royal-ties for new wells in the United States andCanada is US$6.83 per thousand cubic feet,a figure that is “substantially” higher thanthe average cost in Alberta.

The study rates three conventional andthree unconventional areas in Albertaamong the lowest of 76 areas in the US andCanada.

Ziff challenges gas costsBut a news release by the Ziff Energy

Group said the conclusion that the AlbertaFoothills gas play is the “lowest cost andmost economically attractive gas play” inthe province “flies in the face of both empir-ical knowledge and Canadian E&P industryexperience.”

Ziff said that rather than being the low-est-cost gas play the Foothills region, basedon its own F&D costs since the mid-1990s,has had the highest F&D costs of any play.

The firm also suggested the governmentdata “may be somewhat dated (using 2005numbers) and the foreign exchange is notcurrent … a major issue when comparingthe economics of U.S. and Canadian plays.”

Paul Ziff has been unable to find anycompany in Canada ready to confirm thatCanada offers the best netbacks in NorthAmerica or that the Foothills is the bestplace to be.

If that were the case, he said Albertawould be outperforming U.S. gas opera-tions, instead of being barely above averagelevels of the last six years, while the U.S. is50 percent higher.

Buckee: data suspectSuch technical analysis aside, leaders

among Alberta’s gas producers have flat outtold the government it could ruin the gassector by hiking royalties.

Although retired as chief executive offi-cer at Talisman Energy, Jim Buckee is notabout to ride quietly into the sunset.

With typical forthrightness, he sent a let-ter to Premier Ed Stelmach saying the roy-alty panel’s findings were based on suspectdata, especially relating to gas.

“The decisions being made now affectthe investment required to make future nat-ural gas discoveries,” he said. “You can’t

get royalties from wells that are not drilled.”Buckee predicted Talisman, rather than

pay higher royalties, would cut C$500 mil-lion from its Alberta gas spending in 2008and move the money to the U.S. and over-seas.

Noting that gas accounted for 60 percentof the 2006-07 royalties, he said Albertawould be foolish to harm a sector alreadyreeling from low commodity prices.

“It’s the dominant product,” Buckeesaid. “There’s the potential for huge blun-ders here.”

Companies say higher royalties will hurt investment in gas

Petro-Canada Chief Executive OfficerRon Brenneman, while conceding there isroom for increasing gas royalties, said “thereality is that in the (Western CanadaSedimentary basin) the industry is prettymuch tapped out in terms of investmenteconomics. Right now, at current prices,investment can’t tolerate much higher roy-alties.”

EnCana, Canadian Natural Resourcesand ConocoPhillips have all joined that cho-rus, while the junior sector has warned itfaces virtual extinction, compounded by thefact that it faces an added 40 percentincrease in 2008 in the base fee for a gov-ernment-approved levy on oil and gas wellscollected by rural municipalities.

Martin King, an analyst withFirstEnergy Capital, said any royalty adjust-ments will only intensify the cost-drivenslump in gas drilling and production in theWestern Canada Sedimentary basin andcould prevent the sector from taking advan-tage of a decline in domestic production andslowing liquefied natural gas imports in theU.S., which FirstEnergy believes couldcause prices to improve in the first half of2008 from the predicted 2007 average ofUS$7.08 per million British thermal units.

King said that price will be the ultimatedecider for companies to readjust theirdrilling programs, but “it will take six to 12months to feel the positive impact ofstronger prices on production.”

NEB: deliverability droppingWithout being able to factor in higher

royalties, the National Energy Board fore-cast for the 2007-09 period said Canadiangas deliverability (the total amount of gasthat could be supplied at any given time)could shrink by 7 percent to 15 percent overthe period from 17.1 billion cubic feet perday at the end of 2006 to 14.5 bcf-15.8 bcfper day in 2009, sharply below its earlier

predictions of 17 bcf per day.Daily output from the WCSB over the

forecast period is expected to drop to 13.7bcf from, 16.2 bcf.

Currently about 60 percent of allCanadian gas is shipped to U.S. markets.

The NEB said deliverability has beenfairly stable at about 17 bcf per day since2000, with 98 percent originating from theWCSB and the rest from Atlantic Canada,which is expected to average about 440 mil-lion cubic feet per day in the short term.

Deliverability from the WCSB hangsprimarily on the price of gas in NorthAmerica, which is volatile because ofweather-driven market demand, the avail-ability of imported LNG and possible sup-ply disruptions in the Gulf of Mexico.

“There is a pervasive drilling downturnthat’s impacting most resources in theWestern Canada basin,” said NEB gas sup-ply analyst Ken Martin, echoing NEBchairman Gaetan Caron who said “thedrilling that has sustained Canadian gasdeliverability is gone, for the moment.”

The federal regulator said factors con-tributing to the projected downturn arematuring fields in the WCSB and the com-bination of high costs, low commodity

prices and a strong Canadian dollar whichis eating into profit margins from exports tothe U.S.

Production from the WCSB is alreadydown 800 million cubic feet per day ascompanies have slashed their budgets by25-30 percent, deferring an estimated C$6billion in drilling programs.

Chris Theal, an analyst with TristoneCapital, said any decision to implementpunitive royalty measures will make theproduction outlook “worse than what theNEB is suggesting.”

He said the recommendation to hikegas royalties to 65 percent from 36 percentfor wells producing more than 600,000cubic feet per day would remove theincentive to chase bigger gas targets,given that 5 percent of the higher-deliver-ability wells represent 47 percent ofAlberta’s volumes and 63 percent of theroyalties.

Based on current trends, Ziff analystBill Gwozd said the current ratio, whichsees 10 bcf per day of Canada’s 17 bcf ofoutput shipped into the U.S., will bereversed by 2010 and by 2015 the volumeavailable for export will be down to 5 bcfper day. ●

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 15

continued from page 1

DREAD

16 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

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Univar USA Inc.From the early days of mining to

today’s petroleum industry, Univarhas kept pace with clients’ industrialchemical needs. It has providedAlaska industries more chemicals andchemical distribution services thanany other company. Univar’s manage-ment encourages full employee par-ticipation in continually reviewingand improving Univar’s business andtotal quality processes.

Rick Holland joined Univar as acustomer service rep and quality con-trol chemist in 1979. He moved topurchasing in 1984, and in 1989 Rickmoved to Alaska for a Univar salesposition. Rick and his wife Janet havetwo children, Sarah and Eric, both incollege. Camping — and catching theelusive monster king salmon — insummer and cross-country skiing inwinter are Rick’s favorite ways toenjoy Alaska.

—PAULA EASLEY

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By GARY PARKFor Petroleum News

he Alberta oil sands aren’t exactly frozen in timewhile the industry awaits word on its royalty future.

EnCana and Canadian Natural Resources, two ofthe most vigorous opponents of higher royalties, are

moving ahead with two C$1 billion projects and twostartup operators have rolled out development plans, butthe Alberta government has sent another junior into alegal huddle by canceling its plans to remove bitumenfrom beneath a lake.

EnCana, despite word from Chief Executive OfficerRandy Eresman that the company might slash its Albertaspending by C$1 billion in 2008, remains on track withits Borealis in-situ bitumen recovery project, which couldcome on stream at 35,000 barrels per day in 2012 andgrow to 100,000 bpd by 2018, extracting 1.4 billion to 3.4billion barrels of resources.

A preliminary regulation document has been filed,consistent with the Borealis project schedule, but a finaldecision on capital investment will be “impacted” bywhat happens to the royalty recommendations, a compa-ny spokesman said.

Although EnCana has not put a price tag on the proj-ect, analysts believe the first-phase outlay would be aboutC$1 billion, now that construction costs for steam-assist-ed gravity drainage projects are running at C$30,000 perflowing barrel.

Borealis is one of three EnCana ventures that aim fora combined 500,000 bpd of oil sands output by 2015-18as part of the Canadian independent’s joint-venturearrangement with ConocoPhillips.

Canadian Natural disclosed in a preliminary regulato-ry filing that it hopes to expand initial production from itsKirby in-situ project to 45,000 bpd from the initial 30,000bpd, starting with four pads in 2011 and adding eight aspart of its eventual goal of producing 100,000 bpd.

The application points to an initial capital investment

of C$620 million and C$300 million in royalties andtaxes over 20 years.

Alberta cancels leaseIn other developments:• The Alberta government cancelled a lease awarded to

OSUM Oil Sands, which planned to test methods ofremoving bitumen from under a lake in northeasternAlberta.

A month after suspending seismic testing at MarieLake, Energy Minister Mel Knight decided explorationand development of a potential 252 million barrels wasnot in the public interest, his office said.

A government spokesman said OSUM would only beeligible for compensation covering the cost of its lease,which is believed to be about C$3.6 million.

The company, which had expected to invest aboutC$750 million to produce 30,000-40,000 bpd, has raisedC$100 million based on the estimated value of its bitu-men resource.

An OSUM spokesman said the cancellation amountsto “confiscation” and the unprecedented cancellation of alease before any work was done. The company is nowexploring its legal options.

Meanwhile, Imperial Oil has no plans to develop itsown leases either under or close to Marie Lake, althoughit has been operating close in the area for about 30 yearsthrough its Cold Lake heavy oil operation.

• Little-known Patch International is pressing aheadwith plans for a 10,000 bpd steam-assisted project at its80 percent working interest Ells River play.

Targeting initial production by 2010, with a possibleexpansion to 40,000 bpd, Patch said an independent eval-uation points to recoverable resources of 139 million to203 million barrels.

The company has budgeted C$322 million for its10,000 bpd pilot project and an extra C$950 million toexpand by 30,000 bpd.

Chief Operating Officer Jason Dagenais said there is a“lot of upside opportunity as 75 percent of our acreagehas yet to be completely exploited and explored. We havea management estimate of 1.4 billion barrels in place.”

But he conceded Patch is in a “holding pattern” untilthe royalty issue is resolved.

• MEG Energy, with state-owned China NationalOffshore Oil Corp. as a 15 percent partner, is applying tohike production from the second phase of its ChristinaLake project to 60,000 bpd from 25,000 bpd.

The first phase of 3,000 bpd is scheduled to reach fulloutput within about a year. Recoverable bitumen from thelease is estimated at 2 billion barrels.

• OSUM and MEG, along with Athabasca Oil SandsCorp and Laricina Energy have made a joint appeal to theAlberta government for fiscal stability after payingC$300 million for oil sands leases, investing a combinedC$2.5 billion in seismic, core hole drilling, plant con-struction and steam-assisted drilling activities and plan-ning an overall outlay of C$7 billion by about 2012.

The four companies have formed an alliance to makea public case against recommended royalty hikes, arguingthat because they have no cash flow they need stability toraise capital.

OSUM Chairman Richard Todd said his company is“completely dependent on foreign equity. Of the billionswe need to raise, 90 percent or more comes from inter-national sources.” ●

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 17

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

No ‘time out’ for Alberta oil sands

TEnCana, despite word from Chief Executive

Officer Randy Eresman that the company mightslash its Alberta spending by C$1 billion in

2008, remains on track with its Borealis in-situbitumen recovery project, which could come onstream at 35,000 barrels per day in 2012 andgrow to 100,000 bpd by 2018, extracting 1.4

billion to 3.4 billion barrels of resources.

Unfortunately it’s based on a mis-understanding between a newspaperreporter and the U.S. GeologicalSurvey about the findings of a 2000USGS assessment of worldwide,undiscovered oil and gas resources.

“We never really said that,” saidUSGS’ Brenda Pierce, who made apresentation on circum-Arcticresource appraisal at the ArcticEnergy Summit in Anchorage on Oct.16.

The 25 percent figure came froman assessment of seven oil and gasbasins that were broadly described as“Arctic” in the USGS report, butwhich contained substantial tracts ofland that were not, strictly speaking,within the Arctic, Pierce said. Onebasin, the East Siberian basin, liesentirely south of the Arctic Circle,she said.

If you deduct the East Siberianbasin from the 25 percent, you’re leftwith 14 percent, Pierce said.

But because the 2000 USGSassessment didn’t include estimatesof undiscovered resources from allbasin areas north of the Arctic Circle,14 percent could understate theArctic’s potential, she said.

“Keep in mind that these (sixbasins) are very few of the Arcticbasins,” Pierce said, noting the“Arctic was the big hole that we did-n’t do” in the worldwide assessment.

Lack of dataOne of the reasons USGS did not

fully assess the Arctic in 2000 wasbecause of a lack of data about the

area, she said.However, the agency is now in the

process of carrying out a resourceassessment of all Arctic regions,using available geologic informationand a methodology adapted to a gen-eral shortage of well and seismicdata.

“We have spent the last two yearsfocusing solely on the Arctic, lookingat how we adapt our methodologies,”Pierce said.

But, even as USGS completes itsArctic assessment, probably over thenext year, don’t expect more than avery broad view of the petroleumresources the region contains becausethe geologic uncertainties are veryhigh in the Arctic, and the technicaluncertainties relating to the feasibilityof oil and gas extraction are evenhigher.

“Obviously the Arctic has tremen-dous potential, but it’s pretty largelyunexplored even although there areall of these oil and gas basins,”Pierce said. “Its resources are prettypoorly understood.”

—ALAN BAILEY

continued from page 1

INSIDERThe 25 percent figure came

from an assessment of seven oiland gas basins that were

broadly described as “Arctic” inthe USGS report, but which

contained substantial tracts ofland that were not, strictlyspeaking, within the Arctic,

Pierce said. One basin, the EastSiberian basin, lies entirely

south of the Arctic Circle, shesaid.

18 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

Nikaitchuq with the former Tuvaaq unit— adjacent to Nikaitchuq — and added alease segment formerly in the KuparukRiver unit and two adjacent leases.

Nikaitchuq formerly had 12,968 acres;the expanded unit has 33,870 acres.

Acting Division Director Kevin Bankstold Petroleum News Oct. 12 that unitexpansion was a “good sign” that Eni willmove into development of Nikaitchuq. “Itlooks like things are moving ahead,” hesaid.

Eni acquired 100% this yearThe Nikaitchuq and Tuvaaq units were

formed by Kerr-McGee and ArmstrongOil & Gas. Eni acquired Armstrong’sNorth Slope interests in 2005; AnadarkoPetroleum acquired Kerr-McGee in 2006;and Eni acquired Kerr-McGee’s interestsin the prospects earlier this year.

“Successful appraisal drilling has beencompleted, confirming the potential via-

bility of the development project,” Enisaid in April in announcing its acquisitionof Kerr-McGee’s 70 percent interest inNikaitchuq. “Plans for a phased develop-ment are currently being evaluated withthe target of sanctioning the project byyear end and first oil to flow by the end of2009.”

Eni said in the plan of explorationwhich accompanied the expansion appli-cation that it will use results from on-iceseismic shot in 2006-07 to determineappropriate 3-D seismic acquisition forthe expanded unit.

It has committed to acquire 74 squaremiles of 3-D seismic by September 2010.

Because a producible resource hasbeen delineated on the acreage, the divi-sion proposed benchmarks requiring Enito commit specific leases in the expandedunit to participating areas by specificdates.

The division said that as part of Eni’sexpansion application and an earlier roy-alty modification application (the stateturned down that application from then-operator Kerr-McGee in October 2006),

Eni “has stated their intent to construct aprocessing facility within the boundary ofthe expanded Nikaitchuq unit at OliktokPoint.” Initial drilling would be from the313,000-square-foot gravel pad housingthe production facilities, which will bebuilt near the ConocoPhillips Alaska sea-water treatment plant. Future drilling willbe from a small gravel island shorewardof the barrier islands.

New royalty applicationThe new royalty modification applica-

tion was received Oct. 17, Division of Oiland Gas commercial analyst Tim Ryherdtold Petroleum News. Ryherd said Eni isasking for royalty modifications onSchrader Bluff and Sag River production.

The application wasn’t for the wholeunit, but for 12 leases in the center-south.The very northwest and very northeastcorner leases of the reconfigured unit areexcluded from the application, he said, asis one lease in the very southwest corner.

Leases included in the royalty applica-tion are: ADLs 388571, 388572, 388574,388575, 388577, 388580, 388581,388582, 388583, 390615, 390616 and391283.

Ryherd said there is no statutory timerequirement for evaluation of royaltymodification applications, other than the30-day public comment period on the pre-liminary decision. He said the divisionhopes to issue this decision in a shortertime than the previous two.

The state received an Oooguruk royal-ty modification application in May 2005;and an amended application in November2005, after Armstrong sold its leases toEni; the preliminary decision went out fora 30-day public comment period Dec. 20;the final decision was issued Feb. 1, 2006.

The previous Nikaitchuq royalty mod-ification application, which the staterejected, was received Jan. 11, 2006; thepreliminary decision went out for a 30-day public comment Sept. 1; the finaldecision was issued Oct. 30, 2006.

Earlier modification deniedThe Department of Natural Resources

denied the Kerr-McGee application forroyalty reduction in October 2006, statingthat under the new petroleum profits taxpassed that August the company wouldpay, over the life of the project, on a dis-counted basis “about $120 million less intaxes than under the previous fiscalregime.”

DNR said high capital expendituresfor Nikaitchuq “serve to offset otherstatewide income streams and lower theoverall tax obligations for the corpora-tion” and its parent Anadarko PetroleumCorp.

Anadarko is a partner in and has pro-duction from the ConocoPhillips-operat-ed Alpine field. DNR projected thatAnadarko would “realize very large prof-its from Alaska production if oil pricesstay at current high levels over the nextseveral years.”

Since that decision was issued,Anadarko has sold Kerr-McGee’s interestin Nikaitchuq to Eni, which currently hasno production in Alaska.

Unit formed in 2004The original Nikaitchuq unit, formed

in April 2004, included eight state oil andgas leases north of the Kuparuk River unitand east of the Tuvaaq unit.

Eni proposed including an additional10 leases in the Nikaitchuq unit, seven ofwhich composed the Tuvaaq unit andthree additional leases, ADL 390615,390616 and segment 2 of ADL 355024.

ADL 355024 was committed, in part,to the Kuparuk River unit in 1985 and in1988 was committed in its entirety to theKRU in that unit’s third expansion. Thereare two aerially differentiated segmentsof this lease, the division said, and thesouthern portion of the lease is not part ofthis application. Kuparuk working inter-est owners previously agreed to a farm-out of segment 2 to Eni as 100 percentworking interest owner. Segment 2 iscommonly referred to as the Kigun por-tion of the lease. It received a new ADL,391283, was contracted from Kuparukand committed to the expandedNikaitchuq unit.

As a result of assignments of workingand royalty interest shares, 100 percent ofthe working interest in each of the exist-ing Nikaitchuq unit leases and the expan-sion leases are held by Eni.

Schrader Bluff, Sag RiverThere are two different formations at

Nikaitchuq, heavy oil at the shallowerSchrader Bluff formation and light oil atthe deeper Sag River.

The division said in its decision that“potentially commercially recoverablereserves” have been tested in both theCretaceous Schrader Bluff and theTriassic Sag River formations.

Kerr McGee, the original operator atNikaitchuq, drilled six wells in theNikaitchuq and Tuvaaq units between2004 and 2005. Three of the six tested oilfrom the Schrader Bluff or Sag River for-mations; Kerr McGee drilled two addi-tional Schrader Bluff wells in 2006.

The Nikaitchuq No. 4, the Tuvaaq No.1 and the Kigun No. 1 all penetrated theSchrader Bluff formation, the divisionsaid. Only the first was tested: using an

continued from page 1

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electric submersible pump to aid in pro-duction of the 16-17 degree API crude,the well tested at rates of up to 1,200 bar-rels per day.

The Nikaitchuq Nos. 1 and 2 encoun-tered both Schrader Bluff and Sag Riverformations. The Nikaitchuq No. 3 hadsome 1,834 feet of net pay in the SagRiver sandstone in a 3,000-foot horizon-tal section.

The No. 1 production tested at morethan 960 bpd of 38-degree API crude inthe Sag River and the No. 3 tested, with apump, a range of 1,327 bpd to 760 bpd, of32-degree API oil. The No. 2 was not test-ed.

Two additional wells were drilled fromOliktok Point in the 2006-07 winter sea-son.

Horizontal wells plannedThe division noted that Eni has stated its

intention to develop the NikaitchuqSchrader Bluff formation with horizontalwells, and said there are some five years ofSchrader Bluff well performance from ini-tial completions at the Milne Point andKuparuk River units. Eni “appears toassume” its development at Nikaitchuq willimprove on previous Milne Point andKuparuk River Schrader Bluff completions“by using the latest technology — horizon-tal and multilateral completions,” the divi-sion said.

Sag River has been developed on astandalone basis at Milne Point and those“wells consistently show initial flush pro-duction followed by steep decline within thefirst year to less than 50 percent of the ini-tial rate” the division said. Tests done byKerr McGee “showed similar initial pro-duction rates and comparable if not morepronounced decline,” the division said,adding that stimulation and innovativeenhanced oil recovery techniques mightimprove recovery from the Sag River atNikaitchuq.

Future exploration possibleEni said in its exploration plan that it

conducted an “on-ice seismic experiment”in the vicinity of Nikaitchuq with ShellOffshore “at a cost of several million dol-lars.” The results of the experiment “mayresult in substantial benefit to theNikaitchuq Unit and other State of Alaskaoffshore leases in shallow waters by allow-ing parties to acquire seismic data on suchleases during the winter season in a mannerthat should have greater stakeholder accept-ance.”

Eni said further unit evaluation wouldfollow “in reasonable steps. The timeframeand activities will be determined byresults.”

Following the expected submittal of aplan of development to Eni’s managementfor project sanction prior to the end of 2007,Eni said it would approach the State ofAlaska soon after project sanction forapproval of the plan of development andone or more participating areas.

“The results of the drilling of the initialunit wells will provide information neces-sary to evaluate potential development ofother areas” of Nikaitchuq, the companysaid.

Eni said the schedule is to use results ofthe on-ice seismic to develop a plan by July2008 for “potential 3-D seismic acquisitioncovering parts of the expanded” unit withapproximately 74 square miles of 3-D seis-mic to be acquired by September 2010.

Eni also said it would closely monitorimprovements in drilling technology overthe next few years “to determine if addi-tional areas can be reached for developmentfrom then existing facilities.”

Newly acquired seismic would be used— along with prior seismic and drillinginformation — to develop future explo-ration plans by October 2011.

Development benchmarks addedThe Nikaitchuq development was sum-

marized in the division’s 2006 royalty mod-ification decision and includes constructionof a gravel pad with drilling, gathering andproduction facilities on Oliktok Point nearthe ConocoPhillips Alaska seawater treat-ment plant; construction of a gravel drillingisland near Spy Island tied back via a 3.8-mile subsea flow line and utility bundle toOliktok Point for fluid processing; construc-tion of an approximately 14-mile pipelinefrom Oliktok Point to a tie-in near Kuparukdrill site 1Y for connection to the KuparukTransportation common carrier pipeline;and future modifications as required toaccommodate actual results of well per-formance.

The division said Eni’s studies indicate“extended reach horizontal producing andinjection wells required for pressure mainte-nance were needed to economically recoverthe hydrocarbons in place.”

Initial drilling would be from a 313,000-

square foot pad at Oliktok Point. The smallgravel island would be constructed shore-ward of the barrier islands for futuredrilling.

Because Nikaitchuq has a “producibleresource” that has been delineated, the divi-sion proposed — and Eni agreed — to aseries of development benchmarks.

The division said in its Oct. 5 decisionthat Eni “intends to produce at Nikaitchuqby 2009” and requiring formation of a par-ticipating area by 2009 commits Eni todevelopment of the expansion leases.

The segment of ADL 355024 committedto Nikaitchuq has the new ADL 391283. OnOct. 5, 2009, any portion of ADL 391283not committed to a participating area wouldbe segregated and the portion not committedwould automatically contract from the unitunless that area is covered in an approvedplan of exploration or plan of development.

Other leases would contract out of theunit on Oct. 5, 2011, and Oct. 5, 2012,unless committed to a participating areacovered by an approved plan of explorationor plan of development. ●

PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007 19

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20 PETROLEUM NEWS • WEEK OF OCTOBER 21, 2007

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THE TRANS-ALASKA PIPELINE IS

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