page

14TransCanada chief visits Alaska;gas pipeline contract in fall

Vol. 10, No. 24 • www.PetroleumNews.com North America’s source for oil and gas news Week of June 12, 2005 • $1.50

● N O R T H S L O P E

● H O U S T O N , T E X A S

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

● A L B E R T A

7 Firebrand leader at it again: Newfoundland premier threat-ens to leave resources in ground unless companies pay more royalties

13 Glennallen well holds promise: Rutter and Wilbankscompletes exploration well in Alaska’s undeveloped Copper River basin

15New Brunswick LNG moves forward: Encouraged by

25-year freeze on property taxes, Irving, Repsol sign project agreement

Techies lead the wayResearch speeds ahead in hunt to replace gas for Alberta oil sands development

By GARY PARKPetroleum News Canadian Correspondent

t’s a veritable alphabet soup that maycontain the ingredients of economichealth in the Alberta oil sands.

What, for instance, do you make ofSAGD, MSAR, VAPEX, SAP andTHAI?

Try steam-assisted gravity drainage,multi-phase superfine atomized residue,vapor extraction, solvent aided processand toe-to-heel air injection.

They’re just part of the latest batch ofadvances that have turned what somemight have viewed as pure science fictioninto a profitable business.

Whether it is drilling, pumping, engi-

neering, shipping or refining, Canadianinnovators have figured out ways to turnsludge into liquid gold.

Through skill and risk-taking, theyhave developed methods to extract bitu-men that is buried too deep in the Albertamuskeg to be removed by open-pit min-ing. Now technology lets operators pumpsteam into the ground, forcing themolasses-like bitumen to the surfacewhere it can be refined into a wide rangeof petroleum products from gasoline todiesel fuel.

It all started in 1893Getting to this point has been a long,

Pioneer wants a breakWithout lease royalties reduced, independent will not ‘vigorously pursue’ Oooguruk

By KAY CASHMANPetroleum News Publisher & Managing Editor

he Alaska subsidiary of Pioneer NaturalResources has formally applied for a royaltyreduction for four leases adjacent to its pro-posed Oooguruk oil development offshore the

North Slope. All four leases will be included in aunit expansion request that Pioneer expects to filearound June 15, the company said in a letter sent inlate May to Tom Irwin, commissioner of theAlaska Department of Natural Resources.

Located in Harrison Bay near Thetis Island, theOooguruk discovery includes “potentially com-mercial reserves” within the Kuparuk and Nuiqsut

I“If we are going to

exploit and properlydevelop the oilsands, we have tofind a way thatinvolves somethingmore than truck andshovel or conven-tional mining tech-niques.” –JohnRichels, president ofDevon Energy

TWells drilled by othersin expansion area

Three exploratory wells were drilled byPioneer Natural Resources Alaska in 2002 inwhat is now called the Oooguruk unit –Oooguruk No. 1, Ivik No. 1 and Natchiq No. 1.

In its application to the state of Alaska forroyalty relief on four leases that will beincluded in an upcoming unit expansion,Pioneer said eight additional wells have beendrilled within the expansion area, six of whichfall in the boundaries of the four leases.

see OIL SANDS page 19

see PIONEER page 18see WELLS page 18

Bass Boys raise Nova Scotia’shopes; Parnell leaves division

THE TIGHT-LIPPED BASS BILLIONAIRES of Texas areputting themselves in the spotlight – likeit or not.

Through Bass Enterprises Productionof Fort Worth they are moving ahead withplans for a wildcat well offshore NovaScotia in early 2006.

In the process they are switching thefocus in the Nova Scotia waters from nat-ural gas, which has yielded little otherthan dry holes in recent years, to oil.

But the gamble isn’t likely to causeheart beats to skip in the Bass family, ledby patriarch Perry 90 and comprising fourbrothers – all five of whom have accumulated fortunes throughreal estate, news media and technological investments.

see INSIDER page 16

New players outline strategies

Storm Cat and Alaska Energy Alliance talk about their plans forleases won in the May Cook Inlet lease sale in story on page 9.

Chinese company still looking atmaking an offer for Unocal

CNOOC, the Chinese offshore oil company, is still ponderinga competing bid for Unocal, CNOOC said in a statement to theHong Kong Stock Exchange June 7. Unocal has agreed to beacquired by Chevron for about $16 billion in cash and stock.

CNOOC’s statement was in response to an article on theBloomberg news wire June 6, saying it was not considering aUnocal offer.

“The company announces that it is continuing to examine itsoptions with respect to Unocal,” the CNOOC statement said.“These options include a possible offer by the company forUnocal, but no decision has been made in this respect.”

see BID page 16

Weatherford pumps upOilfield services company to buy two divisions from Canada’s Precision Drilling

By RAY TYSONPetroleum News Houston Correspondent

eatherford International, in what analystscalled a bold move for the big U.S.-based oil-field services company, has agreed to buy twoof Precision Drilling’s major divisions for

$2.28 billion in stock and cash, signifying further con-solidation of a once floundering industry now revivedby the unprecedented strength in worldwide oil andgas prices.

Wall Street immediately warmed up to the deal asinvestors stepped in with their wallets to pushWeatherford shares higher on announcement of thetransaction June 6.

Investment bank Jefferies & Co. raised

Weatherford’s target price to $70 per share from $65per share. The stock closed June 6 at $56.27 per share,up 4.2 percent from the previous close.

“Weatherford’s new product introductions,acquired assets from (Precision Drilling) and its cost-cutting measures combined with our bullish outlookfor the oil service sector should drive strong earnings

W

see WEATHERFORD page 15

Weatherford’s CEO, Bernard Duroc-Danner, said that in large part industry’sincreasing move toward directional andhorizontal drilling prompted the deal

with Precision Drilling.

2 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

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

ON THE COVERTechies lead the way

Research on fast forward in hunt to replacenatural gas for Alberta oil sands development

Pioneer seeks relief

Without royalties reduced on leases, independent will not“vigorously pursue” Oooguruk

Weatherford pumps up

Big oilfield services company to buy two divisions fromCanada’s Precision Drilling for $2.28B

CNOOC still looking at Unocal

Unocal and Chevron reach agreement with Federal TradeCommission staff

EXPLORATION & PRODUCTION

OIL PATCH INSIDER1 Bass Boys raise Nova Scotia’s

hopes 16 Parnell leaves division16 Sempra’s investment in Alaska

LNG project hit $6.3 million

FINANCE & ECONOMY

GOVERNMENT

INTERNATIONAL

LAND & LEASING

4 Weeks headed back into North Slope facility-sharing negotiations

13 Glennallen well looks promising

16 Meridian logs another Louisiana discovery

20 Canada’s rig count jumps by 104, U.S. count up by 22

20 Pioneer launches production from new Raptorgas well in deepwater Gulf

6 EIA forecasts oil above $50 through 2006

6 Murkowski signs permitting bills

16 DEC proposes financial responsibility increases

13 First Calgary seeks pact with Repsol

20 BLM lease sale fetches over $6.5M, Wyoming gets half

15 Irving, Repsol sign New Brunswick LNG agreement

16 Long Beach votes to continue LNG talks

13 Enbridge takes full control of U.S. pipeline

6 G8 to look at tax breaks to spur refinery investment

8 Alberta regulator kept busy; sulfur emissions down by 26 percent

6 State to back Arctic shuttle study to study routefrom Alaska to Iceland

10 Executives blame oil price for slow growth

5 $24 oil will increase the ‘fear factor,’ says Herrera

NATURAL GAS

PIPELINES & DOWNSTREAM

14 TransCanada chief visits Alaska

Governor says a gasline contract should go to a specialsession of the state legislature for approval in the fall

8 Trans-Alaskapipeline worth$3 billion

State review board upholdsRevenue’s decisionregarding value of TAPS, keeps line’s value at aboutsame level as last four years 5 Fear itself carries a price

Research institute estimates “fear premium”at 45-50%of world oil price; sees no change through ’06

6 Crude futures climb back above $55

Oil prices are 40 percent higher than a year ago; EIAofficial says demand growth going to be there,inventory surpluses “pretty paltry,” going to disappear

7 Firebrand leader at it again

Newfoundland premier threatens to leaveresources in the ground unless companiesagree to cough up more in royalties

14 Far East Report: Shell wins3 more Sakhalin LNG sales

New agreements with Japanese utilities give Sakhalin 2commitments for 75% of initial output capacity; BP-ledTangguh LNG project gets $1.4B; Conoco plans moreTimor drilling this year for big Darwin LNG plant

9 New inlet playersoutline strategies

Storm Cat and Alaska EnergyAlliance talk about their plansfor leases won in the MayCook Inlet lease sale

12 U.S. oil shale: real,or just a mirage?

New processes mightturn the mirage of futureoil shale development into a viable source of vastquantities of petroleum products

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 3

Current Deepwater Activity

Area/ OCS Prospect WaterOperator Block Lease Rig Name Name Depth (ft)

Anadarko Petroleum AT 305 G18556 T.O. DEEPWATER MILLENNIUM Jubilee West 8,750

BHP Billiton Petroleum (GOM) WR 206 G16965 GSF C.R. LUIGS Casade 8,160

Spinnaker Exploration L.L.C. MC 961 G26281 T.O. CAJUN EXPRESS Q 7,928

Chevron U.S.A. Inc. WR 758 G17015 T.O. DISCOVERER DEEP SEAS Jack 6,959

BP E&P GC 826 G09982 DIAMOND OCEAN CONFIDENCE Mad Dog 6,736

BP E&P MC 822 G14658 T.O. DISCOVERER ENTERPRISE Thunder Horse South 6,262

ConocoPhillips GB 783 G11574 NABORS MODS 201 Magnolia 4,674

BP E&P GC 782 G15610 PRIDE MAD DOG SPAR RIG Mad Dog 4,430

BP E&P GC 645 G11081 HOLSTEIN SPAR RIG Holstein 4,344

Murphy E&P MC 734 G21778 T.O. MARIANAS Thunderhawk 5,710

Dominion E&P MC 773 G16647 NABORS POOL 140 Devil's Tower 5,610

ConocoPhillips GB 783 G11574 NABORS MODS 201 Magnolia 4,674

BP E&P GC 782 G15610 PRIDE MAD DOG SPAR RIG Mad Dog 4,426

BP E&P GC 645 G11081 HOLSTEIN SPAR RIG Holstein 4,344

BHP Billiton Petroleum (GOM) GC 654 G20085 T.O. DEEPWATER HORIZON Shenzi 4,342

Anadarko Petroleum GC 652 G21810 ENSCO 7500 Genghis Khan 4,331

Anadarko Petroleum GC 518 G21801 NOBLE PAUL ROMANO K2 North 4,047

Eni Petroleum Co. Inc. GC 562 G11075 GSF CELTIC SEA K2 3,934

Kerr-McGee Oil & Gas EB 646 G20725 DIAMOND OCEAN VALIANT Northwest Navajo 3,905

Shell Offshore Inc. MC 934 G07969 NOBLE JIM THOMPSON Europa 3,875

Union Oil of California GC 512 G26315 T.O. DISCOVERER SPIRIT Knotty Head 3,570

Pioneer Natural Resources GC 299 G15571 DIAMOND OCEAN AMERICA Clipper 3,452

Shell Offshore Inc. GB 516 G11528 DIAMOND OCEAN VICTORY Serrano 3,392

Shell Offshore Inc. AT 267 G18537 T.O. DEEPWATER NAUTILUS Vrede 3,341

Murphy E&P GC 338 G22950 NABORS MODS 200 Front Runner 3,328

Kerr-McGee Oil & Gas EB 599 G19028 DIAMOND OCEAN VOYAGER Hack Wilson 3,220

Shell Offshore Inc. VK 956 G06896 H&P 205 Ram-Powell 3,214

Kerr-McGee Oil & Gas GB 667 G17407 DIAMOND OCEAN STAR Gunnison/Durango 3,103

Shell Offshore Inc. GC 158 G07995 H&P 202 Brutus 2,985

Shell Offshore Inc. MC 807 G07962 H&P 201 Mars 2,945

Shell Offshore Inc. GB 426 G08241 AUGER Auger 2,862

Kerr-McGee Oil & Gas GC 320 G25139 NOBLE AMOS RUNNER Chilkoot 2,450

BHP Billiton Petroleum (GOM) GC 282 G26302 NOBLE MAX SMITH Boris North(GC) 2,346

Murphy E&P MC 582 G16623 NABORS S.D. XVI Medusa 2,223

Noble Energy, Inc. GC 199 G24160 DIAMOND OCEAN QUEST Lorien 2,200

Chevron U.S.A. Inc. GC 236 G15562 THERALD MARTIN Typhoon 1,987

Chevron U.S.A. Inc. VK 786 G12119 ENSCO 25 Petronius 1,754

Amerada Hess Corporation GB 200 G17307 DIAMOND OCEAN CONCORD Northwestern 1,736

Eni US Operating Co. Inc. EW 965 G12145 T.O. AMIRANTE Morpeth 1,694

BP E&P VK 989 G06898 NABORS POOL 143 Pompano I 1,290

Apache Corporation MC 400 G21754 NOBLE LORRIS BOUZIGARD Ben 1,139

Total Deep Water Prospects with Drilling/WO Activity: 38

New Deepwater ActivityArea/ OCS Prospect Water

Operator Block Lease Rig Name Name Depth (ft)

Anadarko Petroleum AT 305 G18556 Jubilee West 8,750

Spinnaker Exploration MC 961 G26281 Q 7,928

Kerr-McGee Oil & Gas EB 646 G20725 Northwest Navajo 3,905

Pioneer Natural Resources GC 299 G15571 Clipper 3,452

Kerr-McGee Oil & Gas EB 599 G19028 Hack Wilson 3,220

Amerada Hess Corporation GB 200 G17307 Northwestern 1,736

The Gulf of Mexico Activity Report as of June 6, 2005. Active drilling companies only listed.

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

This platform report was prepared by Tom Kearney

Baker Hughes North America rotary rig counts*June 3 May 27 Year Ago

US 1,353 1,331 1,168Canada 375 271 256Gulf 94 91 90

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

*Issued by Baker Hughes since 1944

BP’s Holstein Spar rig

CO

URT

ESY

BP

CO

URT

ESY

TR

AN

SOC

EAN

IN

C.

Transocean’s Deepwater Millennium

Gulf of Mexico Activity Report

By KAY CASHMANPetroleum News Publisher & Managing Editor

t this time only one facility-sharing agreement forproduction exists between North Slope producersand a non-facility owner and that was negotiatedbetween Kuparuk River unit operator ConocoPhillips

and Jim Weeks, managing member of Winstar Petroleum,for his company’s Oliktok Point State No. 1 well. The well,which turned out to be a duster, was drilled in 2003 fromonshore drill site 3-R on the northern edge of the KuparukRiver unit to an offshore target was that part of Winstar’slease.

Weeks, who believes in getting afacility-sharing agreement for pro-duction in place before drillingexploration wells, is headed backinto negotiations with North Slopeproducers. This time he is hoping toget an agreement put together for theexploration and development of leas-es west of the Point McIntyre operat-ing area – leases that are owned byWinstar’s sister company, UltraStarExploration LLC.

At Prudhoe Bay, where somePoint McIntyre oil is processed, it will “only take the Big 3to make it happen,” Weeks said, because the Prudhoe PointMcIntyre Participating Area owners require only 90 percentapproval of a facility-sharing agreement.

“The structure of the Point McIntyre deal will probablyneed to be different than the one at Kuparuk, but the sub-stance shouldn’t be much different since the same threecompanies have already agreed once to a deal for us non-unit participants. At least there is precedent out there,”Weeks said.

The KPA owners require 100 percent agreement for allnon-owner use of Kuparuk River unit facilities andpipelines, which meant Weeks had to win the approval ofConocoPhillips, BP, Unocal, ChevronTexaco and

ExxonMobil. Only two of the owners — ConocoPhillips and BP —

were bound by a charter agreement with the state of Alaskathat required them to provide reasonable access to theirNorth Slope infrastructure.

“It was a tiny deal for the big guys. Not a lot of moneyin it for them; more headaches and dilution of their attentionaway from more leveraging issues,” Weeks said, quick topoint out that the intentions on the part of the KPA ownerswere always to make the deal happen.

“They’re clearly willing to put agreements together toenable a little guy like us to do something up there. It justtook us a long time to put the deal together at Kuparuk,”Weeks said, crediting that to the fact it was the first deal ofits kind with a non-facility owner.

Backouts the biggest hurdleThe biggest economic challenge in North Slope facility-

sharing agreements, Weeks said, is the cost of the backouts,which can “make or break an independent’s economics.”

Backouts represent the amount of oil (owned by thefacility owners) from mature fields that must be deferred inorder to make room for new oil. The oil from mature fieldsoften has a high water and/or gas content, which can push aprocessing facility’s water and gas handling capability tothe max and so oil from those wells often has to be backedout to make room for new wells.

North Slope facility owners want to be compensated forthe amount of their own oil that they have to back out of thesystem in order to free up capacity to process the new oil.

At Kuparuk, ConocoPhillips uses a computer simulationprogram to model the day to day processing operations atthe facilities which has resulted in a “detailed dynamic plantmodel,” from which a complex backout methodology iscreated. Non-facility owners are not allowed access to themodel and so have to trust in what the facility operator tellsthem.

This resulted in non-facility owners stressing the needfor a more transparent methodology; perhaps simpler mod-els to be built which were accessible by all, Weeks said.

But after working with the North Slope producers,Weeks is no longer as concerned about transparency.

“One of my objections to backout was it was a giant‘trust me,’ but I got beyond that. I don’t think they (majorNorth Slope producers) will purposely rig the numbers. Ithink they will model it straight up the way they see it.”

Backout costs can be 30-50% per barrelWeeks said if a non-facility owner is looking at testing

what he thinks will be a small North Slope field – 50 mil-lion barrels or less – he should “get somewhat of an under-standing of which facility it’s going to have to go into andwhat constraints that facility has in terms of backouts andfees. You can’t firm up the costs – but the costs can be stag-gering.”

Backout costs alone for going into the Kuparuk unit, hesaid, can be as high as 30 to 50 percent of your per barreldevelopment cost.

“In our case (with Oliktok Point State No. 1 well), wecould drill from an existing pad on the road system so wedidn’t have the expense of an ice road and ice island to dealwith. … (and) CPF3, which we were going into, wasn’t asheavily loaded.”

One of the biggest hurdles with backouts is that theNorth Slope facility owners do not include in their backoutcalculation the possibility of being able to produce thebacked oil at a later date. It’s calculated as lost forever,which is not what state officials and Petroleum News’ oilindustry sources say happens in other parts of the world.

Weeks agreed it was a problem. “That was my biggestobjection, but they (North Slope facility owners) arguedthat on a present value basis we would get it back so latethat is would be worthless; plus they have concerns thattheir field may not have enough life in it to ever allow forthe deferred oil to be produced.” ●

Editor’s note: Pioneer Natural Resources is in theprocess of negotiating a production facility-sharing agree-ment for Kuparuk facilities for development of its Ooogurukunit. See related story in this issue.

4 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

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● N O R T H S L O P E

Weeks heading back into North Slopefacility-sharing negotiations with producers

A

Jim Weeks, manag-ing member ofWinstar Petroleum

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 5

● C A L G A R Y

Fear itself carries a price, says CERICanadian research institute estimates “fear premium” at 45-50 percent of world oil price; sees no change through 2006

By GARY PARKPetroleum News Canadian Correspondent

he price of fear will likely continueto pump an extra US$22 per barrelinto world oil prices through 2006,says the Canadian Energy Research

Institute.Otherwise CERI estimates that the

price of oil based solely on market funda-mentals would be only $21.50-$25.50 perbarrel.

The Calgary-based agency expectsthat rising geopolitical uncertainty will“act as an upward force” on what itdescribes as the “fear premium,”although improving supply flexibilityshould have an offsetting effect, barringany major and sustained disruptions.

CERI said the War on Terror, includ-ing the war in Iraq, have added to politi-cal instability in the Middle East, height-ening concerns about security of supply,especially among major oil importingcountries.

That has spawned a revival of geopo-litical competition among major powers(the United States, Europe, China, Russiaand Japan) and a scramble to secureaccess to foreign oil.

Civil unrest in Venezuela, NigeriaIn addition to the Middle East conflict,

CERI said the civil unrest in Venezuelaand Nigeria has curtailed production inboth countries, while Hurricane Ivanremoved 2 million barrels per day of U.S.Gulf Coast production in the third andfourth quarters of 2004.

The lack of supply flexibility shows upin several ways, including low levels ofOPEC spare production capacity, a short-age of global facilities to process lowerquality crude and low commercial inven-tories.

A surge in oil demand in 2004 causedOPEC spare capacity to dwindle toaround 1 million bpd in the latter part ofthe year from 4 million bpd, 5.5 millionand 3 million in 2001, 2002 and 2003,respectively, the study said.

Uncertainty regarding OPEC decline rates

CERI said that OPEC countries havestarted investing heavily to increase pro-duction capacity and attempt to regain con-trol over the world market.

Although there is uncertainty over bothexisting field decline rates and the timingof new additions, the International EnergyAgency has projected an increase in OPECproduction capacity of 1 million bpd in2005 and 700,000 bpd in 2006, raising

spare production capacity from 1.9 millionbpd in 2004 to 2.6 million bpd this year and3.6 million bpd in 2006.

CERI is also counting on two majoradvances to ease constraints on the globalrefining system – an improving crude slate,notably from Saudi Arabia and Nigeria,and additions of desulfurization capacity torefineries to take advantage of large pricedifferentials between various crude quali-ties.

In the realm of geopolitical uncertainty,CERI believes Iraq and Nigeria are the

“most likely to suffer a major supply dis-ruption,” while Saudi Arabia andVenezuela have quelled local opposition totheir regimes, making them less likely can-didates.

Iran and nuclear weaponsNext on the list of potential sources of

the “fear premium” is Iran, which CERIsays could change the dynamic in theMiddle East if it develops nuclear weapons,which could occur in another two years.

“Unfortunately, Western options to dis-courage Iran from developing nuclearweapons are limited,” with an invasion bythe U.S. unlikely, leaving “surgical” airstrikes as the most likely choice, the insti-tute said.

It said the “war drums might grow loud-er through 2006 … although the Iraniannuclear situation likely will not lead to asupply disruption until at least 2007, if atall.”

CERI excludes traders and speculatorsfrom its list of “fear premium” contribu-tors.

It said speculators on the NYMEXfutures exchange decreased their bets onhigher prices for most of the year when theprice of WTI closed at US$55.17 per barrelin October 2004.

Refiners concerned about the availabili-ty of crude oil to meet winter demandswere responsible for driving up prices,CERI said.

In contrast, when WTI hit US$57.27 perbarrel on April 1, speculators were movinginto the market on the upside, despiteexpectations of lower spring and summerdemand.●

THerrera: $24 oil will increase the ‘fear factor’

“We should all hope that the Canadian Energy Research Institute is wrong inits estimate that a non-fearful world would reduce the price of a barrel of oil toabout $24. If, in fact, we can forget that the Middle Eastern producer nations con-tain most of the world’s oil reserves and that those producing nations have notbeen exactly politically stable over the past generation or two, then we can per-haps reduce our concern about future reliable supplies from that region and lookforward to low priced oil,” Petroleum News’ favorite oil price guru, Anchorage-based oil and gas consultant Roger Herrera, said about CERI’s analysis.

The problem, he said, is that $24 for a barrel of oil is “not an incentive toexplore for new oil anywhere else in the world. Despitegreat new technology, oil is proving more and more difficultto find and the cost of successful exploration is increasing.

“Therefore $24 oil will only increase our reliance on theMiddle East and thereby inevitably increase the ‘fear fac-tor.’

“When one looks carefully at the CERI logic,” Herrerasaid, “it is difficult not to conclude that world demand hasbeen largely responsible for the increase in the price of oil.”

CERI figures, he said, show that world demand for oilhas led to the “effective elimination of any spare OPECcapacity. However, it then goes on to say that the International Energy Agencyforecasts that plenty of new oil will be found in the near future so everything willbe hunky-dory. Such a forecast is obviously designed to eliminate fear, but thewidespread lack of success in finding significant large new reserves of oil over thepast decade or so would suggest that a logical concern about our future suppliesof oil might be a healthy reaction.”

Herrera said it is “worth remembering that even if the world is close to its peakoil output (a theory CERI does not mention), it only indicates that about half theworld’s oil has been used. That is hardly a fearful prognosis.” On the other handthe “various political misfortunes that CERI mentions as contributing to its ‘fearpremium,’ are not unique to this time. World wars, cold wars, dictators etc havecharacterized the whole of the Oil Era. It would be naive not to expect similarinfluences during the second and final half of the oil era. We will undoubtedlyhave to pay for them even if we are not afraid of them,” Herrera said.

—PETROLEUM NEWS

Heightening concerns aboutsecurity of supply, especiallyamong major oil importing

countries … have spawned arevival of geopolitical competitionamong major powers (the UnitedStates, Europe, China, Russia andJapan) and a scramble to secure

access to foreign oil.

ROGER HERRERA

JUD

Y P

ATR

ICK

By BRAD FOSSThe Associated Press

rude futures climbed 3 percent to set-tle above $55 a barrel June 3 astraders’ supply fears were bolsteredby an Energy Department official

who predicted new record highs for oil

prices because of “paltry” domestic invento-ry levels.

Analysts have noted a variety of factorsputting upward pressure on oil prices inrecent days — from U.S. refinery snags tothe hospitalization of Saudi Arabia’s KingFahd — though the most prominent hasbeen concern that as refiners strive to meet

today’s strong demand for gasoline anddiesel, they could end up having difficultyproducing enough heating oil later in theyear.

As a result, heating oil futures havesurged more than 10 percent in the pastweek, climbing 5.73 cents to $1.5595 a gal-lon June 3 on the New York MercantileExchange.

Cook says might see $60 oilJohn Cook, director of the petroleum

division at the agency’s Energy InformationAdministration, helped justify the oil mar-ket’s nervousness, telling Dow JonesNewswires “I think we’ll see new records,not necessarily by much, but I think we mayeven average $60 for a month.”

“The demand growth is going to be there,and the inventory surpluses we have arepretty paltry to begin with and they aregoing to disappear,” Cook was quoted assaying.

Light sweet crude for July deliveryclimbed $1.40 to $55.03 a barrel June 3 onNymex, rising eight out of the nine past trad-ing sessions. On June 2, prices finished 97cents lower at $53.63.

Gasoline futures increased by 4.17 centsto $1.5571 per gallon.

Oil analyst Tim Evans of IFR EnergyServices in New York said he consideredCook’s comments to be irresponsible, giventhe climate of fear already permeating themarket.

“He’s acting more like a cheerleader forthe rally than he is an analyst, or a keeper ofthe numbers,” said Evans, whose ownanalysis has led him to conclude that hypeand speculation — not genuinely tight sup-plies — have pushed oil prices to record lev-els.

“There is this ingrained belief that even ifthe market’s not tight today, it’s going to betomorrow,” Evans said.

But broker Tom Bentz of BNP ParibasCommodity Futures in New York saidCook’s comments merely confirmed whatmany traders have been saying for months.Still, Bentz said he was “a little surprisedthat he would make those comments ... Itjust sparks fear.”

Jonathan Cogan, a spokesman for theEIA, said he spoke with Cook after the pub-lication of the Dow Jones story and thatCook emphasized to him that the predictionof $60 a barrel oil was not considered “ourmost likely scenario, though it was certainlya possible scenario.”

On June 2, the EIA said inventories ofcrude oil rose last week by 1.4 million bar-rels to 333.8 million barrels, or 11 percentabove last year, while gasoline inventoriesgrew by 1.3 million barrels to 216.7 millionbarrels, up 6 percent from a year ago.

But distillate fuel supplies rose by only700,000 barrels to 106.4 million barrels, orroughly equal to year-ago levels. That addedto worries that there might not be enoughheating oil and diesel output for the nextwinter season in the Northern Hemisphere.

Xie: Growing inventories should lower prices

But Morgan Stanley economist AndyXie said “the market is making a mistake inassuming linkages between distillate pricesand crude prices,” adding that the growingcrude inventories should lower prices.“With higher inventory numbers and a sub-stantial number of investors backing off inthe summer, declining price levels to $40 ispossible.”

At the moment, oil prices are 40 percenthigher than a year ago.

The Organization of PetroleumExporting Countries meets June 15.Analysts believe the 11-member group willnot reduce its current output of 30 millionbarrels daily.

On June 1, OPEC President SheikAhmed Fahd Al Ahmed al-Sabah said thegroup would maintain its current productionceiling until the third quarter of 2005. ●

6 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

JUNEAUMurkowski signs permitting bills

In early June, Alaska Gov. Frank Murkowski signed two bills into law intended tostreamline the permitting process for oil and gas development.

Senate Bill 103, introduced at the request of the governor, gives the Alaska Oil andGas Conservation Commission the authority to regulate all underground injection wellsused in the oil and gas industry. Currently, the state regulates Class II wells while theEPA regulates Class I wells.

“This change will result in quicker action on permit applications and create a single,uniform process for regulating underground injection to improve efficiency and reduceconfusion in the permitting process,” the governor’s office said in a press release.

Senate Bill 144, sponsored by Senate Resources Committee, is part of theMurkowski administration’s efforts to streamline permitting. The bill updates statestatutes to mirror federal definitions relating to air quality permits, making it easier toissue and enforce air permit compliance more effectively, Murkowski’s office said.

—PETROLEUM NEWS

G8 to look at tax breaks to spurrefinery investment

Next month the Group of Eight industrialized nations will consider tax breaks foroil companies to stimulate investment in new refineries in the United States and otherwestern countries, the Financial Times reported June 7.

The information, garnered from an unnamed senior energy official by the FT, fol-lows International Monetary Fund warnings about the lack of spare refinery capacity.The issue is expected to be on the agenda for the G8 meeting in Scotland in July.

The G8 consists of leaders from the United States, Japan, Germany, Britain, France,Italy, Canada and Russia.

News reports said the proposal would likely encounter opposition from environ-mentalists and advocates of poverty relief.

No new oil refineries have been built in the United States since the 1970s due topoor financial returns for their owners and strong local and environmental opposition.

The Bush administration is also looking to encourage new refineries, possibly onmilitary bases, but oil companies say it makes more financial sense to expand capaci-ty at existing facilities.

—PETROLEUM NEWS

LONDON

● W A S H I N G T O N

Crude futures climb back above $55 a barrelOil prices 40% higher than year ago; EIA official says demand growth will be there, inventory surpluses going to disappear

CEIA forecasts oilabove $50through 2006

As predicted last week by JohnCook, director of the petroleum divi-sion at the U.S. Energy InformationAdministration, on June 7 EIArevised its estimate for the averageU.S. oil price in the third quarter to$52.83 a barrel from its previousestimate of $51.58.

In its monthly forecast, EIA saidit expects the price for U.S. crude toaverage $55 a barrel during thefourth quarter, up from its previousestimate of $53.

The agency also said it expectsthe average monthly U.S. oil price tostay above $50 through 2006.Gasoline prices were forecast to stayabove $2 a gallon through 2006.

“Oil prices remain sensitive toany incremental oil market tight-ness. Imbalances (real or perceived)in light product markets could causelight crude oil prices to rise above$55,” the agency said in a release.

—PETROLEUM NEWS

John Cook, director of the petroleumdivision at the agency’s Energy

Information Administration, helpedjustify the oil market’s nervousness,

telling Dow Jones Newswires “Ithink we’ll see new records, not

necessarily by much, but I think wemay even average $60 for a month.”

By GARY PARKPetroleum News Canadian Correspondent

emember Danny Williams? He’sthe blustering, bare-knuckles, no-holds-barred premier ofNewfoundland who ordered

Canadian flags removed from govern-ment offices earlier this year when hewasn’t getting his way with PrimeMinister Paul Martin in his demands for alarger share of offshore royalties.

With the Martin government in a pre-carious state, Williams went straight forthe throat, squeezing out a commitment tokeep all of its royalty revenues, withoutpenalty.

For Newfoundland, the deal is worthC$2.6 billion, notincluding any newprojects.

Seems determinedto punish industry

Fresh from thattriumph, Williams isback – only now heseems determined topunish the industrythat has been responsible for almost halfhis province’s economic growth since1997.

He warned energy industry executivesthat Newfoundland wants to extract evengreater royalties from its naturalresources.

If tough talk doesn’t work, Williamssaid he is ready to leave oil, natural gas,minerals and hydro-electric projects onthe shelf rather than see them proceedunder what he views as bargain-basementarrangements.

“We have sought and achieved agreater return from the federal govern-ment based on arguments of fairness andequity and we hope to accomplish thesame with the industry,” he told theAtlantic Oil and Gas Summit in Halifax.

“Our oil and gas, our hydro, our min-erals are all extremely valuable assets. Weshould not be of the mindset that devel-opers are doing us all a favor by utilizingthem.”

His pledge is to “negotiate fearlesslywith the goal of getting a great deal forthe province. We are fully prepared to dono deal at all. That was our approach withthe federal government and that will beour approach for the industry.”

First target: Hebron-Ben Nevis-WestBen Nevis oil project

The first venture to put this commit-ment to the test could be the Hebron-BenNevis-West Ben Nevis oil project, whichis just coming back to life, more thanthree years after being halted because ofshaky economics, complex geology andthe heavy nature of the field’s 400-700million barrels.

Project operator Chevron CanadaResources, with a 28 percent stake,announced two months ago that it hadreached a joint utilization and operatingagreement with its three partners(ExxonMobil Canada 37.9 percent,Petro-Canada 23.9 percent and NorskHydro Canada Oil & Gas 10.2 percent) to

restart evaluation of the resource.Chevron Canada said it has found

ways to improve the value of the Hebron-Ben Nevis-West Ben Nevis crude.

If the partners can keep the projectmoving forward, the first oil could flowas early as 2011, a spokesman said.

But Chevron Canada president AlexArchila said a “significant amount ofwork” must be completed before regula-tory applications can be filed.

If Hebron-Ben Nevis-West Ben Nevisis to join Hibernia, Terra Nova and WhiteRose as Newfoundland producing fields,the partners have insisted on a “preferredroyalty regime.”

That’s a non-starter for Williams. “Wedon’t see that,” he told reporters.

He said royalties negotiated fromHibernia, which has been producingsince 1997 and is now pumping 200,000barrels per day, were “on the low end …we had to give something in order to getsomething. I see that as money wellspent.”

That overlooked the deal struck withthe Hibernia consortium to build a pro-duction platform anchored to the seafloor that created hundreds of construc-tion jobs in Newfoundland and pushedcapital costs to C$6.2 billion.

By opting for a floating producing,storage and offloading vessel, rather thanHibernia’s gravity base system, the TerraNova partners incurred capital costs ofC$2.5 billion for a slightly smaller proj-ect.

Now Williams wants a better return onNewfoundland’s assets by not allowingfuture projects to proceed at what heviews as bargain basement prices.

He even suggested that jurisdictionslike Russia and Venezuela are obtaininggreater returns through taxation,increased royalties and equity.

“It is time for industry to treatNewfoundland … as partners, not merelysuppliers of their needs,” Williams said,declaring that his province is embracingthe concept of “share the wealth … asour mantra.”

Uneasy about this new direction,industry spokesmen note thatNewfoundland is an expensive area inwhich to operate, because of its harsh cli-mate and offshore environment, andtougher royalties would have it even lesscompetitive at a time when a lack ofexploration success has hurt activity.

In addition to Hebron-Ben Nevis, apartnership of Chevron Canada, ImperialOil and ExxonMobil has been quietlylaying the groundwork for possibleexploration of the Orphan Basin aftermaking work commitments of C$673million for 5.25 million acres which holdfour pools each with possible reservesgreater than Hibernia’s 884 million bar-rels.

Other plays on the horizon are theLabrador Shelf, with about 123 millionbarrels of natural gas liquids and 4.2 tril-lion cubic feet of gas; the deepwaterFlemish Pass, where Petro-Canada hasidentified five targets each in the 500million barrel range; and the potential foropening up 50 tcf of gas in the Grandbanks area where the producing oil fieldsare located. ●

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 7

● N E W F O U N D L A N D

Province’s firebrandleader at it againNewfoundland premier threatens to leave resources in theground unless companies agree to cough up more in royalties

R

DANNY WILLIAMS

ALASKAState to back Arctic shuttle study tostudy route from Alaska to Iceland

Marine transportation in the Arctic Ocean could become a reality in the next fewdecades as climate change thins Arctic sea ice, allowing icebreaker ships to plowthrough, scientists say.

Now Adak, a fishing town of about 120 on the far eastern tip of the Aleutian Islands,is set to begin plowing through the political and logistical waters of establishing theroute.

This year’s state capital budget, which still awaits the governor’s signature, sends$50,000 to Adak to study the social and economic returns of an Arctic Ocean cargoshuttle to Iceland. The passage would be a competitive route to the Panama Canal.

“The question that needs to be addressed is what are the economics that would drivean arctic shuttle concept,” said Ben Ellis of the Anchorage-based research groupInstitute of the North.

The group has worked closely with Adak officials to study the shuttle concept. Ellissaid it likely would be at least a couple of decades before the ice melts enough to openthe Arctic passages, but other countries such as Russia, Canada, Iceland and Greenlandalready are working toward utilizing the routes once they are available.

“Experts from Alaska and Iceland will work with Finnish icebreaker technologists,Russian administrators of the Northern Sea Route and other appropriate sources ofinformation in completing the study,” the budget proposal states. “The study will deter-mine what further public and private investment might initiate service this decade.”

Ellis said the study could aim to answer questions such as whether a seasonal oryear-round route would be more economical.

“If the economics says it has to be year-round, you are looking at a different sce-nario,” he said.

It also would examine the political landscape of operating in international waters,he said.

Lamar Cotton, a project manager for the city of Adak, said the route could providealternative passages between Europe and the Northern Pacific, allowing ships a routequicker than the Panama Canal.

“We recognize this is a long-term look at things,” Cotton said.According to the project proposal, the money would help establish an agreement

between the Aleutian and Icelandic ports to share information and pursue gatheringother logistical information to establish the route.

The study would likely be commissioned by the Institute of the North, the city ofAdak and the Aleut Corp.

—TIMOTHY INKLEBARGER,Associated Press writer

By MATT VOLZAssociated Press Writer

t’s pumping half the oil it did in itsprime, and tariffs could drop sharply inthe coming years, but the Trans-AlaskaPipeline System is still worth $3 bil-

lion, according to a state review board.The five oil companies that own the

800-mile pipeline had appealed thatassessment by the Alaska Department ofRevenue, which this year changed the wayit values the pipeline in figuring the prop-erty tax owed.

The owners say under the method usedpreviously — basingthe assessment ontariff income — thepipeline’s value isactually $1.5 billion.

The local govern-ments through whoseland the pipeline runsalso appealed thestate’s assessment,but took the oppositeline: The state’s pricetag is as much as $11billion short of thereal value.

The Departmentof Revenue’s numberwas upheld recentlyby the StateAssessment ReviewBoard, keeping thepipeline’s value at about the same level asit has the past four years.

Taxes the reason for disputeThe reason for the dispute is taxes.

Upholding the $3 billion assessment for2005 means the pipeline owners will haveto pay $60 million in property taxes to besplit between the state, five municipalitiesand the North Slope Borough.

“The last time it went to a hearing wasfour years ago,” said Dan Dickinson, TaxDivision director. “All the parties agreed

looking at it, the revenue stream was theway to go.

“This year when we looked at it, wesaid there is a good chance for a reductionin tariffs.”

If tariffs are reduced in 2009, when asettlement expires in calculating thosefees, the property tax would go down usingthat method of calculation, Dickinson said.

Because of that possibility, the divisionused a new way of calculating thepipeline’s value. Using that method, thevalue is based on how much it would taketo replace the entire pipeline system, minusthe cost of depreciation.

The division figures the oil pipeline isabout halfway through its life, and isexpected to last until 2034, according toRandy Hoffbeck, state petroleum property

assessor.The review board said continuing to use

tariff income as the basis for the assess-ments would “understate the full value ofthe TAPS.”

“The board agreed with the divisionthat valuation of the TAPS based on its tar-iff income stream is likely to become lessand less reliable as an indicator of theTAPS’ full and true value,” wrote boardchairman Steven Van Sant in the May 26decision.

Appeal possibleDaren Beaudo, spokesman for BP

Exploration (Alaska), said since 2001,there has been depreciation and a reductionin oil flowing through the pipeline, point-ing to a lower overall value of the pipeline.He said the company stands by its $1.5 bil-lion assessment, but has not decidedwhether to pursue the appeal in court.

“We’re challenging the appraised valuejust as homeowners have the right to chal-lenge the appraised value of their homes,”Beaudo said.

Dawn Patience, spokeswoman forConocoPhillips Alaska, saidConocoPhillips also believes the $1.5 bil-lion is the appropriate appraisal, butdeclined to go into details, saying it was“an ongoing dispute.”

The municipalities’ assessments, whichranged from $8.9 billion to $13.9 billion,includes costs the state kept out of itsassessment — road and bridge construc-tion, legal fees, program management andother costs. The municipalities also arguedthat the pipeline’s life is through 2040, not2034.

The review board said the state didnothing wrong in excluding those costs,but the division should review the 2040date in future assessments. ●

8 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

ALBERTAAlberta regulator kept busy; sulfuremissions down by 26 percent

It’s all in the numbers for Alberta’s energy regulator, which conducted morefield inspections, found a higher industry compliance rate and logged fewerpipeline failures through the energy boom of 2004.

The Energy and Utilities Board is also brushing off criticisms that it is notequipped to handle such unparalleled activity.

Employee numbers now stand at 845, compared with 675 in 2000, and theboard’s funding has soared 85 percent over the same period to C$130 million.

Statistical highlights for 2004, showed:• A compliance rate with major EUB regulations at 98 percent, up from 97 per-

cent in 2003 and 96.5 percent in 2000.• Initial field inspections rose to 10,167 from 7,910 the previous year.• Public complaints about upstream operations were up 4 percent year-over-

year at 850, but down 8 percent from 2000.• The pipeline failure rate has shrunk by 27 percent since 2000, with failures

for every 1,000 kilometers (600 miles) of pipeline at 2.4 last year against 3.3 in2000.

• Sulfur emissions from Alberta gas plants have been slashed by 26 percentsince 2000 – 58,000 metric tons compared with 78,000 – and by 75 percent sincethe 229,000 metric tons in 1974.

• The regulator suspended 118 energy facilities and operations in 2004, raisingthe total this century to 734.

—GARY PARK

● A L A S K A

Trans-Alaska pipeline worth $3 billionState review board upholds Revenue’s decision regarding value of TAPS, keeps line’s value at about same level as last four years

I

The 800 mile trans-Alaska oil pipeline stretches from Prudhoe Bay in the north to the port of Valdez in southern Alaska.

JUD

Y P

ATR

ICK

“The last time itwent to a hearingwas four years ago.All the partiesagreed looking at it,the revenue streamwas the way to go.This year when welooked at it, we saidthere is a goodchance for a reduc-tion in tariffs.”—Dan Dickinson,Tax Division director

AL

GR

ILLO

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 9

● C O O K I N L E T

New inlet players outline strategiesStorm Cat and Alaska Energy Alliance talk about their plans for leases won in the May Cook Inlet lease sale

By ALAN BAILEYPetroleum News Staff Writer

torm Cat Energy Corporation andAlaska Energy Alliance Inc. adopteddistinctly different strategies in buy-ing leases at the state of Alaska’s

Cook Inlet areawide sale in May. Bothcompanies are new to Alaska, althoughStorm Cat had already bought some leas-es near Big Lake, northeast of Anchorage,in the November 2004 Mental HealthTrust lease sale.

Storm Cat’s state leases all lie in theMat-Su Valley at the northern end of thestate’s lease sale area.

“The recent (state) acreage we pickedup complements theMental Health Trustacreage, so we’reputting together theacreage position forboth conventionalgas and coalbedmethane,” ScottZimmerman, presi-dent of Storm Cat,told PetroleumNews. “… StormCat believes in the potential of northCook Inlet and that we’ll be able to(work) in an environmentally safe andsound manner.”

Storm Cat is registered in BritishColumbia and has offices in Denver,Calgary and Ulaanbaatar, Mongolia.Zimmerman used to be vice president ofEvergreen Resources, a Denver-basedcompany that had been working acoalbed methane prospect in theMatanuska-Susitna Borough. PioneerNatural Resources bought out Evergreenand subsequently dropped the Mat-Suacreage, to focus on the North Slope.

Conventional gas firstStorm Cat’s new venture in the Mat-Su

Valley will initially focus on finding con-ventional gas.

“We will probably look first at theconventional possibilities,” Zimmermansaid. However, the company expects to beable to evaluate coalbed methane poten-tial using the same well that it drills forconventional gas, he said.

The company’s preliminary geologicalevaluation has identified some promisingstructures in the area of the leases. And

the nearby ARCO BLT well, drilled nearBig Lake in 1992, has caught Storm Cat’sattention.

“The old BLT well has a lot of inter-esting gas shows within it,” Zimmerman

said. That’s one of the key wells thatwe’re looking at, he said.

However, coalbed methane develop-ment is a future possibility. Zimmermanis familiar with the recent controversy

surrounding this type of development. Hethinks that the regulatory framework forcoalbed methane in the MatanuskaSusitna Borough is inappropriate.

S

see LEASES page 10

SCOTT ZIMMERMAN

“The borough has not fully understoodand has not really done the proper workand the regulations are inappropriate andimproper,” he said.

Drilling next winterStorm Cat is using existing seismic

data and has assembled a geologicalteam, with a view to start drilling in thewinter of 2005/2006.

“We’ve put together our geologicalteam and they’re putting together an eval-uation to pick a location to drill sometime late third quarter or early fourthquarter (2005),” Zimmerman said.

A consulting firm in Anchorage isdoing the geological investigation andStorm Cat may itself establish an office inAlaska.

“We do not have an office but we havesome consultants working for us andwe’re looking at possibly getting anoffice up there soon,” Zimmerman said.

Alaska Energy AllianceAlaska Energy Alliance is based in

Newport Beach, California, and wasformed by Stan Snyder and his wifeAlexis Snyder to enter the Alaska oil andgas business, Stan Snyder told PetroleumNews. The Snyders have been in the oiland gas business for nearly 30 years, pri-marily with gas interests in Colorado,Snyder said.

“We’re primarily land speculators …that’s the primary focus of our businessalthough we are involved in some explo-ration,” Snyder said. “We would like tobe involved in Cook Inlet exploration.”

Alaska Energy Alliance bought 10leases scattered across the lease sale area.Four leases are on the Kenai Peninsula,four are in the Cook Inlet near TradingBay, one is near Granite Point and one isonshore west of the mouth of the SusitnaRiver.

“The strategy is in our first year of bid-ding on tracts in Alaska is to take more ofa scattered or shotgun approach,” he said.

But Snyder said that his company hadnot expected to win so many tracts.

“In most of our bidding … we’re luckyenough if we put in 10 or 12 bids to comeout with three or four tracts,” he said. “ Ifeel very, very fortunate that we were ableto do as well as we did but I had no idea… that we would acquire what was basi-cally 10 out of 11 applications we put in.”

Some of the leases are near AllianceEnergy Group LLC’s North Fork Unit atthe southern end of the Kenai Peninsula.However, Snyder said that there is noconnection between Alaska EnergyAlliance and Alliance Energy Group,despite the similarity in the names.

Exploration plansThe company did some preliminary

geological evaluations when determiningwhich tracts to bid for and now plans tohire a consulting geologist to do adetailed evaluation of each tract.

“What we’ll do now that we’veacquired the tracts is … some extensivegeology on the areas and (determine)what we might do with them at somepoint in the future,” Snyder said.

The company is primarily interested ingas plays.

“I understand there’s … a contract onthe table for any gas that’s produced thatwill be sold at prevailing prices, so thatcertainly is intriguing for us,” Snydersaid.

He emphasized how pleased his com-pany was to be entering the Alaska oil andgas business and how welcome it felt inthe state.

“We found everybody to be very, veryfriendly and very to receptive — the atti-tude seems to be if you do it right and youdo it clean we’re more than welcome tohave to you up here,” he said.

And Snyder thinks that the new leasesprovide a good starting point for his com-pany.

“We are certainly delighted that wehave our holdings now covering all quad-rants of the Cook Inlet — it will give usquite a bit of insight as to the specificareas that we want to focus on in futureacquisitions,” he said. ●

10 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

Storm Cat is using existingseismic data and has assembled a

geological team, with a view tostart drilling in the winter of

2005/2006.

Snyder said that there is noconnection between Alaska Energy

Alliance and Alliance EnergyGroup, despite the similarity in

the names.

continued from page 9

LEASESUNITED STATESExecutives blame oil price for slow growth

Executives of leading U.S. corporations expect their growth to slow over thenext year, and many think rising oil prices are part of the reason. That’s amongthe conclusions of a quarterly survey of 147 chief financial officers and other topmanagers of U.S.-based multinationals.

The PricewaterhouseCoopers survey says the executives expect revenuegrowth of 8.1 percent during this calendar year, compared with an increase of 10.1percent in 2004. A third of the survey participants, and nearly half of those in themanufacturing sector, cited rising oil prices as a factor.

For the first quarter, 47 percent of executives reported increased costs at theircompanies, compared with 21 percent who said their costs went down.Meanwhile, 46 percent of the companies boosted their own prices, compared withjust 12 percent who cut prices for their products.

“The economy appears to be stuck in neutral, waiting for oil prices to stabi-lize,” said John O’Connor, vice chairman of PriceWaterhouseCoopers LLP.“Companies that are vulnerable to rising oil prices expect notably slower growth,and report weaker margins and considerably more cost increases.”

But the executives still see the glass as half-full, with 77 percent optimisticabout the U.S. economy and 67 percent bullish on the world economy. Only 3 per-cent are pessimistic on each of those issues. And 57 percent expect their compa-ny’s workforce to grow, compared with 10 percent who expect to have few work-ers at the end of the year.

More information on the survey and others by the firm is available atwww.barometersurveys.com

—ALLEN BAKER

By F. JAY SCHEMPFPetroleum News Contributing Writer

he federal government is takinganother serious look-see at whetherU.S. shale oil reserves can be tappedeconomically and in an environmen-

tally friendly way.So what’s new? After all, government

and industry have searched over morethan a century for a way to coax oil eco-nomically from the vast U.S. oil shaledeposits — the largest in theworld — most of which arelodged in a 16,500-square-mile area encompassing theGreen River, Uinta andPiceance basins in south-western Wyoming, north-eastern Utah and northwest-ern Colorado.

It’s also well known thatthe hydrocarbons in westernoil shale reserves are theequivalent of 1.2 to 1.8 tril-lion barrels of crude oil. Ofthat, according to U.S.Department of Energy fig-ures, anywhere from 130billion to 1 trillion barrelsultimately may be recoverable. A trillionbarrels is roughly equivalent to all thecombined proven conventional oilreserves in the world today.

Rock that burnsWhat is oil shale, anyway, this “rock

that burns?” For one thing, it isn’t shale. For anoth-

er, it doesn’t contain crude oil. Instead,it’s hard, black or dark brown marl that’srichly infused with bituminous material.It was formed eons ago by the simultane-ous deposition of silt and organic debrison the sea bottom that once covered thewestern U.S. As these deposits piled up,heat and pressure transformed them into astable mixture of inorganic minerals andsolidified organic sludge. However, theheat and pressure did not reach highenough levels to form crude oil.

Although solid at ambient tempera-tures, super-heated oil shale yields ahydrocarbon vapor called kerogen that,when condensed, can be captured andrefined into gasoline, diesel and jet fuel.

You can dig itThe oil shale recovery and kerogen

extraction technology that has been mostwidely employed combines subsurfacemining with surface retorting. Producersextract the shale using explosives ordraglines at the surface and by burrowingdeeper with mining equipment. Thechunks of extracted oil shale are brokenup and then introduced into retort ovenswhere, aided by steam, the entrainedkerogen and gases are condensed. Thenext step, refining, cracks the kerogenmolecule and adds hydrogen to yield ahigh-grade synthetic crude oil known assyncrude.

When heated, the oil shale expandsmuch like popcorn, so that even afterproduct removal, the volume may be aslarge or larger than it was originally.Producers must move this spent materialto a proper disposal site and stabilize it —the remnants hold a variety of undesirablemineral compounds that can leach outwith rain. What’s more, shale retorts his-torically have released vile-smelling

vapors, some of whichmay be harmful.

And, of course, pro-ducers still have to sealup the excavated area,filling it with soil, reshaping surface con-tours and then planting it with trees,native grasses, etc.

Not viableEven if the mine/report method were

to be environmentally friendly, the

method has not proved to be financiallyviable and several attempts at exploitingoil shales in the United States have failed.

In one notable episode, the MiddleEast oil embargo and several Middle Eastwars spurred the federal government tocreate a new shale oil business in the westin the late 1970s. Several companies —confident that oil prices would remain

high — placed orders for largemining/retorting operations in the areaaround the communities of Rifle andParachute, Colo.. The resulting economicboom burst on May 2, 1982 – a fewmonths into construction – when thebiggest shale operator, Exxon Corp.,abruptly shut down its Colony mine/retortproject near Parachute. The companycited construction cost overruns, but thetruth was, crude oil prices had returned topre-embargo levels. Unocal and Tosco

(The Oil Shale Corp.), amongothers, kept smaller projectson track for a while longer, butby 1991, all Colorado oil shaledevelopment had petered out.

Rebirth of the industryCurrently, however, in vir-

tually the same geographicarea, the hint of a quiet, meas-ured rebirth of oil shaleexploitation is again beingdebated in local governmentoffices, civic clubs, cafes andbeauty parlors. The differencenow is that one company,Shell Exploration andProduction, thinks it has

extraction technology to develop shale oilefficiently without surface retorts, crush-ers or landfills. In fact, Shell’s newprocess leaves a footprint no larger thanthat of conventional oil field develop-ment.

But mindful of the earlier oil shalebust, Shell has done everything possibleto forestall any local — or national —

perception that another oil shale ‘boom’is in the offing.

And Shell isn’t flying solo. Severalother companies, including ExxonMobil,Chevron and others, still hold largeblocks of acreage in all three oil shalestates, and have themselves continuedtheir oil shale research. And while Shell isthe only major company talking aboutshale oil extraction these days, a fewsmaller — much smaller — companiesare either retorting shale already or soonplan to do so.

New shale bill‘Hatched’

Meanwhile, theindustry says oilshale developmentneeds federal gov-ernment interest.Such interestalready exists —DOE, for example,has conducted oilshale research fordecades. What’smore, the U.S.Department of theInterior Bureau ofLand Management,which oversees fed-eral shale properties,is now working on anew leasing policy.

And recently, powerful governmentlawmakers from the three western states

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 11

● U N I T E D S T A T E S

U.S. oil shale: Real, or just a mirage?New processes might turn the mirage of future oil shale development into a viable source of vast quantities of petroleum products

T

see OIL SHALE page 12

Utah Sen. OrrinHatch hopes toamend the omnibusenergy bill nowpending in theSenate, with pro-posed legislation toopen RockyMountain oil shaleand oil sands forleasing and to pro-mote new extrac-tion technologies —all by 2010

Simplified here, Shell’s In-Situ Conversion Process (ICP) heats oil shalekerogen below ground. The resulting light, gaseous compounds areclaimed via conventional production wells and are condensed into alight oil ideal for refining into motor fuels.

with oil shale deposits have seen U.S. oilshale exploitation as a way to stave offperceived crude and products shortfallsand perhaps lower the unprecedentedmotor fuel price hikes seen in recentmonths. They also view shale develop-ment as a major boon to their states’economies.

Concern about domestic supplies ofconventional oil and gas is also prompt-ing some action inside the WashingtonBeltway to look at supplies from oil shale,oil sands and heavy oil deposits.

On May 19, Utah Republican SenatorOrrin Hatch introduced the Oil Shale andTar Sands Development Act. Hatch andfellow western state lawmakers hope totack the bill — or at least its main points— on as an amendment to the Senate ver-sion of the omnibus energy bill, which itsEnergy & Natural Resources Committeereported out May 26 to be brought soon tothe floor for a vote. The House alreadyhas passed its version, and President Bushwants a final bill for his signature by Aug.1.

The Hatch bill would create a StrategicFuels Task Force to accelerate and inte-grate a five-year commercial develop-ment of fuels from shale and oil sands.The bill also directs DOI to kick off acomprehensive public lands leasing pro-

gram (the one BLM already is workingon), and calls for a DOE cost-sharing pro-gram to demonstrate promising extractiontechnologies.

Finally, the bill would allow producersimmediate expensing of new technologyoutlays for shale and oil sands develop-ment. The bill also suggests sliding-scalefederal royalty reductions for initial pro-duction.

Backing the Hatch bill are fellow UtahRepublican Sen. Bob Bennett, as well asSens. Wayne Allard, R-Colo., and KenSalazar, D-Colo., among others.

“Who would have guessed that in justColorado and Utah, there is more recov-erable oil than in the Middle East?” Hatchasked recently. “We just don’t count itamong our nation’s oil reserves becauseit’s not yet being developed commercial-ly.”

Shell’s downhole heaterThough Shell is loath to say that it has

a commercial process, the company isblazing a trail to just the kind of oil shaledevelopment Hatch envisages. The com-pany has conducted numerous field testsin Colorado during the last five years thatindicate its In-situ Conversion Process,known as ICP, actually works.

With the ICP, the company insertselectric resistance heaters into cased holesin the shale, and then heats the subsurfacearound each bore hole gradually over athree to four-year period until the sur-rounding zone reaches a temperature ofaround 650 F, driving vaporized kerogeninto offset producers. This leaves thespent shale, or “char” — heavier hydro-carbons and all those nasty mineral com-pounds — in the formation.

Testifying at an April 12 Energy &Natural Resource Committee hearing onoil shale potential, Steve Mut, chief exec-

utive officer of Shell’s UnconventionalResources unit, said the latest ICP test,performed over several months, producedmore than 1,200 barrels of light oil andgas liquids. Some 32 downhole heatershave been placed in wells spaced 10 to 20feet apart over a five-acre parcel at thecompany’s 20,000-acre Cathedral Bluffsproperty in Rio Blanco County, nearRifle, about 200 miles west of Denver.

Heating the shale source rock torelease kerogen, said Mut, “…acceleratesthe natural process of oil and gas matura-tion by literally tens of millions of years.”

The process produces about 65 percentto 70 percent of the original subsurface“carbon” in place, he noted. The remain-ing carbon products, if brought to the sur-face, would require broad, energy inten-sive upgrading and hydrogen saturation.So, he inferred, these products are bestleft in place.

The method of keeping the heatedshale products fromescaping intogroundwater flowsforms a unique fea-ture of Shell’s ICPprocess. Mut saidthat engineers canisolate the ICP-affected under-ground area byadapting 100 year-old mining and con-struction technologythat freezes ground-water to form an icebarrier or to reducewater flow.

According toMut, Shell use arefrigeration system,based on the sameprinciple as a resi-dential air condition-er. The system circulates cold fluidthrough a series of wells, so that icegrows around the wells to connect into asolid ice wall.

The new process uses a lot of electricalenergy, said Mut. However, each unit ofenergy used to generate electricity yieldsabout 3.5 units of energy to be treated andsold, he said, adding that the processcompares favorably with steam injectionin conventional heavy oil reservoirs.

The ICP produces a different hydrocar-bon mix than traditional crude oils — it’smuch lighter, with almost no heavy ends,Mut said. However, the process can con-trol product quality by using changes inheating time, temperatures and pressures,he said.

Much to be doneBut don’t bet the farm on the ICP just

12 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

continued from page 11

OIL SHALE

To isolate the useful and waste products of its ICP system from intruding into surroundingformations, Shell circulates water to absorb heat around injection/production wells to cre-ate an “ice barrier.”

see OIL SHALE page 13

Steve Mut, CEO ofShell E&P’sUnconventionalResources unit, saysthe company’s In-Situ ConversionProcess (ICP) forproducing oil fromshale, still underdevelopment inColorado, “…accel-erates the naturalprocess of oil andgas maturation byliterally tens of mil-lions of years.”

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 13

CALGARYFirst Calgary seeks pact with Repsol

First Calgary Petroleums has signed an agreement in principle with Spain’sRepsol to jointly develop its large natural gas finds in Algeria.

If a final pact is signed it will see the Calgary-based junior grow into a pro-duction company from a pure explorer.

But First Calgary President and Chief Executive Officer Richard Anderson hascautioned that there are major obstacles still to be cleared in resolving how quick-ly the reserves can be developed.

Repsol is eager to participate in a liquefied natural gas terminal to open updevelopment of the Berkine Basin, which is believed to hold 13 trillion cubic feetof reserves.

In the meantime, First Calgary is no longer reviewing strategic options, whichmany investors had hoped for more than six months would result in an outrightsale.

—GARY PARK

Enbridge takes ownership of U.S. pipelineEnbridge has locked up total ownership of a U.S. pipeline that forms a vital link in

its plans for eventually delivering oil sands production to Gulf Coast refineries.The Calgary-based pipeline company

paid US$12.4 million to BP for the final 10percent it did not already own of what isnow the Spearhead pipeline.

The majority stake cost EnbridgeUS$112 million in 2003, leaving it with anoption to acquire the remainder.

Earlier this year the company obtainedapproval from the U.S. Federal EnergyRegulatory Commission to reverse the flowof the now unused 650-mile pipeline fromCushing, Okla. to Chicago.

It is aiming to complete the reconfigur-ing work in the first quarter of 2006, offer-ing initial capacity of 125,000 barrels perday to offer a “more varied grade mix of crudes with physical characteristics that willbe available for the first time to refineries in Kansas, Texas and Oklahoma.”

Enbridge has said the line could be expanded to 160,000 bpd.It also has FERC permission to offer discounted shipping rates to help offset

“dwindling U.S. oil supplies and … increase refineries’ security of supply.” —GARY PARK

It is aiming to complete thereconfiguring work in the firstquarter of 2006, offering initialcapacity of 125,000 barrels per

day to offer a “more variedgrade mix of crudes with

physical characteristics that willbe available for the first time torefineries in Kansas, Texas and

Oklahoma.”

yet. Mut said that while Shell has spentmany millions of dollars on the processand has eliminated a great deal of risk anduncertainty, “much work and expenditurestill remain before the ICP process can becommercialized.”

Recent reports, however, say Shellplans to expand ICP research during thenext two to three years as a next steptoward commercialization, drilling morewells, and taking them deeper. But amongother technical needs, the company

reportedly is still looking for a heater effi-cient enough to hold a constant downholetemperature of 600 F for months or years.

Shell officials hope the ICP will becommercial by about 2010, although thatmay not lead to a major ICP-based proj-ect, at least in the U.S.

But while industry observers have longmaintained that crude oil prices wouldhave to be at least $40 a barrel to makeextracting shale oil profitable, Shell offi-cials say the ICP could make kerogen pro-duction profitable at world oil prices of$30 per barrel. With today’s price bounc-ing around $50, the decision to go aheadseems to be a ‘no-brainer.’ ●

continued from page 12

OIL SHALE

Shell’s ICP shale oil layout resembles an oilfield production complex typical of those foundin Colorado’s conventional “oil patch.” Some piping carries condensed shale kerogen fromheated well bores to processing facilities, while others are used to surround undergroundwell bores with an “ice barrier.”

Glennallen gas welllooks promising

By STEVE SUTHERLINPetroleum News Publisher & Managing Editor

utter and Wilbanks Corp. has com-pleted its gas exploration well nearGlennallen in Alaska’s undevelopedCopper River basin. The results are

encouraging enough to test the well, BillRutter III told Petroleum News June 7.

The Midland, Texas-based independentwill know if Ahtna No.119 contains com-mercial potential by July 4, Rutter said.

The company started drilling the well inFebruary, but encountered high geologicpressures at a depth of 1,200 feet — earlierthan expected, company officials toldPetroleum News in early March.

Later, Rutter and Wilbanks had to switchfrom winter operations and using an icedrilling pad to summer operations with agravel pad system.

Forest Oil and Anschutz Exploration arepartners in the prospect, part of an explo-ration license obtained from the state ofAlaska. The drill site was on land owned byNative regional corporation Ahtna Inc.

Hoping for 100 bcf and spur lineRutter and Wilbanks hopes a major gas

discovery will stimulate the North Slopespur line concept and convince the stateto build a section of the line fromGlennallen to Palmer, to get the compa-ny’s gas into the Enstar system forSouthcentral Alaska consumers to helpreplace dwindling Cook Inlet basin pro-duction.

Eleven wells have been drilled inAlaska’s undeveloped Copper Riverbasin, but there have been none sinceCopper Valley Machine Works drilledAlicia No. 1 in 1983.

Rutter and Wilbanks hopes to find 100billion cubic feet or more natural gas tojustify building a pipeline to more popu-lous areas, Rutter said. If the field provesconsiderably smaller, the company is eye-ing the local market, supplyingGlennallen and the Copper Valley ElectricAssociation, a Glennallen-based ruralelectric cooperative with 3,600 customersin the Copper River basin and Valdez. ●

R

By ALAN BAILEYPetroleum News Staff Writer

n June 6 Gov. Murkowski held a press conference toreport on the status of negotiations regarding anAlaska gas pipeline and to introduce Hal Kvisle, chiefexecutive officer and chairman of TransCanada.

TransCanada executives were in Alaska for discussions withthe state negotiators.

“We had an interesting and fruitfuldiscussion and as you know we arelooking forward to presenting this fall(a contract) to the mandatory 30-dayhearing process … after that … (we’llpresent) a submission to the legisla-ture in a special session,” Murkowskisaid.

TransCanada and the North Slopegas producers have both submittedgas pipeline proposals to the state. Athird proposal by the Alaska PipelinePort Authority has until Aug. 5 to show the state it has accessto natural gas for its project or to provide a financial guaran-tee of its performance in order to be eligible to negotiate withthe state for a gas project under the under the AlaskaStranded Gas Development Act.

When quizzed about the length of time that the negotia-

tions were taking, Murkowski pointedout the complexity of the issues andthe amount of detail that needs to besorted out. There are benefits and risksassociated with different options andwe have an obligation to flush that outand determine what’s in the best inter-ests of the state, he said.

“We’re moving quite well on thetwo proposals that we have beforeus,” Murkowski said.

And, at a time when the state hasthree gas pipeline applications, thegovernor dismissed as premature any threats to force gasproduction by imposing a gas reserves tax or retracting leas-es.

TransCanada’s positionKvisle said that TransCanada had conducted many dis-

cussions with both the state and the producers. He said thatthe Alaska and Canada portions of the project are quite dis-tinct and by not objecting to U.S. enabling legislation for thepipeline, TransCanada had “effectively opened the door fora variety of different ways that the project could go aheadwithin the state of Alaska.”

But, ”We’ve shown no such flexibility on the Canadianside,” Kvisle added, referring to his company’s adamant

position that it owns legal rights to build the Canadian por-tion of the Alaska pipeline, under the terms of Canada’sNorthern Pipeline Act.

And with many of the right-of-way arrangements in theYukon already in place Kvisle said that TransCanada candeliver the right of way on the Alaska project more pre-dictably than other proposals.

Expanded systemKvisle characterized the Canadian segment of the Alaska

pipeline as an expansion to TransCanada’s existing pipelineinfrastructure.

“We would have to augment our Canadian system byabout 20 percent in order to accommodate the Alaska gas atthe Yukon-Alaska border and that is our intention and that iswhat we’re proposing to do,” he said.

In the 1990s TransCanada built more miles of pipelinethan would be required in the Alaska pipeline project, Kvislesaid.

When asked about the potential for a partnership betweenTransCanada and the gas producers Kvisle said that he did-n’t know what the producers wanted as a final outcome andthat at least two of the producers had challengedTransCanada’s rights to build the Canadian portion of theproject. However, Kvisle sees TransCanada as an essentialplayer in getting Alaska gas to market.

“We’ll continue to work towards that,” he said. ●

By ALLEN BAKERPetroleum News Contributing Writer

hell Gas & Power has announcedthree new deals with Japanese com-panies for LNG shipments from theSakhalin 2 project. The agreements

give the $12 billion project an outlet for 75percent of the 9.6 million tonnes of lique-fied natural gas that will be produced annu-ally, starting in 2007. Sakhalin 2 will alsoproduce oil.

Shell says it now has eight LNG salesagreements with Japanese utilities, remov-ing many of the potential customers for anundersea pipeline that had earlier been

planed for gas from the ExxonMobil-ledSakhalin 1 project.

Shell said June 6 that Toho Gas Co. Ltd.had signed a full sales and purchase agree-ment for 200,000 tonnes annually for 20years. Earlier this month, Tohoku ElectricPower Co. signed a Heads of Agreementfor 420,000 tonnes annually, and in lateMay Hiroshima Gas Co. Ltd. signed a sim-ilar Heads of Agreement for 210,000tonnes annually. A metric tonne of LNGconverts to about 50,000 cubic feet of natu-ral gas, so the Hiroshima deal would yield

about 10 billion cubic feet a year. The Sakhalin project also has long-term

sales agreements to supply up to 2 milliontonnes annually to Korea and nearly 2 mil-lion tonnes annually to Sempra’s BajaCalifornia terminal. More than 3.4 milliontonnes annually is slated for Japan.

Shell holds 55 percent of Sakhalin 2,with Mitsui & Co. at 25 percent andMitsubishi Corp. at 20 percent. There havebeen reports that Russia’s Gazprom willtake a stake in the project by trading gasreserves to Shell for a 25 percent stake.

$1.4 billion for Tangguh Meanwhile, eight Japanese companies

have committed to invest $1.4 billion ingas fields that will provide the fuel for theBP-led Tangguh LNG project in Indonesia,set to begin exporting 7.6 million tonnesannually starting in 2008, according to theJapan’s Asahi Shimbun newspaper.

The paper said total development costfor the project is now estimated at $6 bil-lion. Proven reserves total more than 14trillion cubic feet of gas. A unit ofHalliburton Co. and JGC Corp. of Japanwon $1.8 billion contract in March to buildthe LNG facilities.

BP, which has a 37 percent stake in theTangguh field, signed the construction dealafter getting lease extensions on the threefields that will supply the LNG plant 1,900miles east of Jakarta in Papua province.CNOOC has nearly 17 percent of theTangguh project and various Japanese enti-ties, including Mitsubishi, Sumitomo andKanematsu, hold the rest.

Up to half of the Tangguh LNG will goto Sempra’s Baja facility, with 2.6 milliontonnes set to go to China and about halfthat slated for Korea.

14 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

● I N T E R N A T I O N A L

Shell wins 3 more Sakhalin LNG salesNew agreements with Japanese utilities give Sakhalin 2 commitments for 75 percent of initial output capacity; BP-ledTangguh LNG project gets $1.4 billion; Conoco plans more Timor drilling this year for big Darwin liquefied natural gas plant

SFAREAST report

● A L A S K A

TransCanada chief visits AlaskaGov. Murkowski says a natural gas pipeline contract should go to a special session of the state legislature for approval in the fall

O

Alaska Gov. FrankMurkowski

Hal Kvisle, CEO andchairman ofTransCanada

see FAR EAST page 15

JUD

Y P

ATR

ICK

ConocoPhillips plans Timor drilling

Another source for both Japan andthe U.S. West Coast is Australia, whereConocoPhillips is planning new drillingthis year in the Timor Sea to provide gas

for the big LNG plant it’s buildingWickham Point, near Darwin, Australia,according to Bloomberg.

Drilling with partner Santos Ltd. willbe at the Caldita prospect near EvansShoal. Another well is planned atFirebird, near the Bayu-Undan field.

The $1 billion Wickham Point lique-faction plant is expected to go into oper-ation early next year with an initialcapacity to ship out 3.5 million tons a

year and potential expansion possibili-ties. Feed gas will come initially fromthe 57 percent owned Bayu-Undandevelopment, now producing condensateand reinjecting the dry gas.

ConocoPhillips has contracts to sup-ply LNG from Australia to TokyoElectric Power Co. and Tokyo Gas Co.,and has said it may send some of the gasto the Long Beach, Calif., terminal it isplanning with Mitsubishi Corp.

Another potential source of addition-al gas for Wickham Point is the GreaterSunrise field, where WoodsidePetroleum (33 percent) is the operatorand ConocoPhillips has a 30 percentinterest.

But that field is in a murky borderarea and development has been stalledas Australia and East Timor work out anarrangement on splitting royalties. ●

continued from page 14

FAR EAST

growth over the next several years,”Jefferies analyst Stephen Gengaro said in anote to clients.

Money-making dealWeatherford’s acquisition of the

Canadian-based company’s Energy ServicesDivision and International Contract DrillingDivision was done for no other reason thanto make money, said Bernard Duroc-Danner, Weatherford’s chief executive offi-cer.

“It’s really all we’re after,” Duroc-Danner told analysts in a conference callexplaining the deal. “This is not an exercisein industry aesthetics. It’s not an exercise insome sort of crusade. This is just money.”

Investors were not as kind to PrecisionDrilling, Canada’s largest contract drillingcompany, as Precision’s share price fell threepercent on news of the transaction.Moreover, Standard & Poor’s RatingsServices put the company on its CreditWatch with negative implications. S&Pnoted that while the pending sale likelywould not affect Precision’s dominant posi-tion in Canada, it would remove about halfof the company’s assets.

Under terms of the agreement,Weatherford agreed to pay PrecisionDrilling $900 million in cash plus 26 millionWeatherford shares for Precision’s two divi-sions. The acquired net book value is about$1.63 billion, according to Weatherford.

Weatherford is already a strong player in

drilling services. But the inclusion of thePrecision Drilling business would signifi-cantly improve Weatherford’s directionaldrilling and wireline capabilities, as well asadd more “underbalanced” drilling capabili-ties, according to Weatherford.Underbalanced maintains wellbore pressurebelow formation pressure while drilling.

Precision’s international division a carrot

The odd part of the deal is PrecisionDrilling’s international contract drilling divi-sion, consisting of 48 land rigs with a strongpresence in the Middle East-North Africaregion. While Weatherford already has astrong position in the region, actually oper-ating rigs in the area would be a first forWeatherford. However, the company plansto target national oil companies that desire“one-stop shop” services, Weatherford’sDuroc-Danner said.

“They are showing a keen interest in hav-ing engineering planning, logistic coordina-tion, drilling efficiencies … managed withas few contractors or vendors as possible,”he added. Duroc-Danner said Precision alsohas developed innovative technologieswhich Weatherford is anxious to harvest. Hesaid Weatherford intends to accelerate thegrowth of the technologies with the full sup-port of its worldwide infrastructure.

“And that’s why I am very grateful thatwe were able to pick up Precision, which hasdone a wonderful job at developing thosetechnologies,” Duroc-Danner said.“Frankly, we could not duplicate what theydid, and we need it.”

He said that Weatherford brings its vastworldwide infrastructure to the deal, whilePrecision brings technology and the productand service lines that Weatherford lacks.

“So for us it’s very much a harvesting oftheir product and service lines and the tech-nology work they’ve done,” Duroc-Danneradded. “For them it’s harvesting our infra-structure. It consolidates what we have. Itbroadens what we have and gives us whatwe want.”

5,300 employees in 25 countriesIn the 12 months ending December

2004, Precision Energy Services andInternational Drilling had combined rev-enues of C$1.1 billion. The combined divi-sions have about 5,300 employees operat-ing in 25 countries.

“After careful consideration of variousstrategic alternatives, the board determinedthis opportunity to be the best for our share-holders and for employees of the respectivedivisions,” said Hank Swartout, PrecisionDrilling’s chief executive officer.

The transaction is expected to be com-pleted during the third quarter of 2005 andis subject to regulatory approvals, includingU.S. and Canadian competition filings.

Weatherford’s Duroc-Danner said that inlarge part industry’s increasing movetoward directional and horizontal drillingprompted the deal with Precision Drilling.

“One thing we found out is how verysuccessful the underbalanced business is(and) that pretty much all the wells that weare getting involved in are either directionalor horizontal,” he said.

“We also found out that in much of ourmarket the client wants us to coordinateclosely with the directional people. We alsofound out that we did not have a substantivedirectional competency. Directional was themissing link. And that (acquisition) to us issort of being able to get all the right arrowsin our quiver.” ●

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 15

● N E W B R U N S W I C K

Irving, Repsol sign New Brunswick LNG pactTHE ASSOCIATED PRESS

ncouraged by a 25-year freeze on property taxes,Irving Oil Ltd. and Madrid-based Repsol YPF havesigned definitive agreements to develop a $750-mil-lion liquefied natural gas terminal in Saint John,

New Brunswick.The agreements create a new company, Canaport

LNG, which will construct own and operate the terminalby 2008, the firms said June 7.

The terminal will initially be capable of delivering onebillion cubic feet per day of regasified LNG, as providedin an existing permit. Repsol will be responsible for pro-viding all of the LNG while Irving will market the regasi-fied LNG in Atlantic Canada, and Repsol will sell it else-where in Canada and in the United States.

“The parties have nearly completed front-end engi-neering design for the terminal, and plan to request pro-posals for engineering, procurement and constructioncontracts during July of this year,” the companies said in

a release. In May, people opposed to a lucrative tax break by the

City of Saint John presented a petition at the NewBrunswick legislature that called for the deal to berevoked. It’s estimated the tax concessions will cost thecity as much as $125 million.

Eyeing spin-off benefits, Saint John common councilvoted to freeze property taxes for the terminal at$500,000 a year for 25 years, with no adjustment forinflation. ●

E

continued from page 1

WEATHERFORD

CNOOC, which is controlled by theChinese government, has hired the invest-ment bank Rothschild to provide an inde-pendent assessment of the deal, according toS&P Equity Research.

Going after Chevron on its own U.S. turfwould be a difficult battle for CNOOC,which had considered a bid earlier this year.But the firm held back as Unocal’s boardaccepted Chevron’s April offer, whichincludes a $500 million breakup fee toChevron if anyone else buys Unocal.

When asked to comment on CNOOC’sstatement, Chevron spokesman DonCampbell told the Los Angeles Times, “It’sinappropriate for us to comment on the pos-sible actions of others.” But, he said, “Webelieve our offer, accepted by the Unocalboard, is attractive and has a high degree ofcertainty as to completion.” Unocal had nocomment.

Some analysts doubted if CNOOCwould make an offer for Unocal.

“The Unocal shareholders are perfectlyhappy to hold Chevron paper (stock) andtake some of it in cash. But Unocal’s share-holders would be less inclined to holdCNOOC paper, so CNOOC would have totop Chevron with an all-cash bid,” saidDerek Butter, head of corporate analysis atthe Edinburgh, Scotland, office of WoodMackenzie.

To trump Chevron’s offer for Unocal,CNOOC would have to pay at least US$18billion, which represents 80 percent of itsmarket capital, said DBS Vickers June 9.

It went onto say, “In our view, the finan-cial risks are very high for CNOOC to paysuch a price for Unocal at cycle peak;” also,Unocal’s U.S. assets offer little synergy, pre-senting higher operating risk for CNOOC asit lacks experience in United States. “Weexpect that CNOOC is only interested inacquiring Unocal’s assets in Asia either fromUnocal or Chevron.”

Meanwhile, Chevron and Unocal aremoving forward on their merger. On June 8,the companies reached an agreement withFederal Trade Commission staff on a pro-posed settlement that would allow theirmerger to close.

But it remains to be seen whether FTC’scommissioners will approve the companies’proposal, said Joe Simons, an attorney forPaul Weiss Rifkind Wharton & Garrison,and former director of the FTC’s Bureau ofCompetition. “I don’t know if the commis-sion will approve it or not. They might sendit back to adjudication. … The commission-ers may ask for additional conditions thatUnocal may or may not agree to.”

CNOOC now produces about 380,000barrels of oil equivalent daily; Unocal about430,000 BOE.

—Allen Baker and AP contributed to thisPetroleum News report

16 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

LONG BEACH, CALIF.Long Beach votes to continue LNG talks

The Long Beach City Council has voted to continue talks on a proposed LNG ter-minal at its port, the Los Angeles Times reported. The 5-4 vote early June 8 was a defeatfor residents who wanted to stop the facility planned by a joint venture of MitsubishiCorp. and ConocoPhillips.

About 400 people came to hear the debate over the proposed terminal, which couldhandle 5 million tons of liquefied natural gas annually, turning it into 700 million cubicfeet of gas each day.

Some council members said they had concerns about the project, but the councildecided to go ahead with an environmental impact report and consider the matter againonce that is completed next spring. Council members opposing the project cited con-cerns about terrorist attacks at the site, about two miles from downtown Long Beach.

The $450 million terminal had supporters as well as opponents at the packed hear-ing, with some union leaders saying the use of LNG for terminal vehicles would cleanthe air, and the project would provide jobs.

Three other terminals are proposed in California, two to be sited far offshore. Oneterminal just across the border in Ensenada, Mexico, is already under construction andanother in Baja California is planned. California’s current natural gas consumption isabout 6.5 billion cubic feet daily, and even the relatively small Long Beach terminalcould supply more than 10 percent of that. So it’s unlikely that all of the terminals willgo forward.

—ALLEN BAKER

LOUISIANA

continued from page 1

BID

Meridian logs another gas discoveryMeridian Resources Corp. has another significant gas find with the Avoca 6-1 well

in the N.W. Bayou Chene area of Louisiana. The well was drilled to 11,500 feet, andlogged more than 40 feet of pay in the Big Hum 2 sands at 10,748 to 10,791 feet, thecompany said June 7.

A test of the well through 40 feet of perforations showed a gross daily flow rate of6.5 million cubic feet of gas and 214 barrels of condensate with no water production ata flowing tubing pressure of 3,608 pounds per square inch through an 18/64th-inchchoke. The successful well follows another nearby discovery May 16 in the Avoca 5-2well at Bayou Chene, in the coastal area south of Baton Rouge. That well showed agross daily flow rate of 2.3 million cubic feet, also from the Big Hum 2 sands but at adepth of more than 11,000 feet.

Meridian, based in Houston but exploring and producing mostly in the marshlandsof Louisiana, has a 92 percent working interest in both wells, and expects to build apipeline and facilities to put the wells into production during the early part of the thirdquarter.

The rig used for both of those wells was moved to the company’s nearby Turtle Bayprospect to drill the CL&F D-1 well. The company is expecting to keep three or fourrigs busy for the rest of the year as part of a $139 million capital budget.

—ALLEN BAKER

Since obtaining an exploration license in2002, Bass Enterprises has gatheredenough 3-D seismic through modern digitalprojections to stir optimism.

The well, named Mon Cherie, will bedrilled in 4,800 feet of water to a totaldepth of about 10,700 feet.

It is in the same vicinity as a wellplugged and abandoned 20 years ago byPetro-Canada and Texaco.

For the Nova Scotia government andindustry, the results could be crucial to theregion’s chances of reviving hope afteryears of setbacks.

Parnell leaves Divisionof Oil and Gas

SEAN PARNELL,DEPUTY DIREC-TOR of the state ofAlaska’s Division ofOil and Gas, has leftthe agency, MarkMyers, director ofthe division toldPetroleum NewsJune 6.

Parnell received“an offer he couldn’t refuse” from the

Anchorage office of Patton Boggs, an inter-national law firm, Myers said, whereParnell will be a partner.

Parnell, a former state senator, also wasa member of the state’s gas pipeline negoti-ating team.

In the interim, the division’s petroleummanager, Bill Van Dyke, will be actingdeputy director. Myers said no decision hasbeen made on a long-term replacement.

Sempra’s investment inAlaska LNG hit $6.3M

THE SAN DIEGO UNION TRIBUNEpicked up a tidbit concerning Sempra’swithdrawal from its alliance with theAlaska Gasline Port Authority’s proposedLNG project that as of June 9 (PetroleumNews’ press date) no other publication hadreported.

The Tribune reported that at the time ofits withdrawal, San Diego-based Semprahad invested $6.3 million in the portauthority’s LNG project, which will berecovered only if the project is successfullycompleted. The company had been paying$750,000 per month under its deal withSempra.

Editor’s note: Oil Patch Insider is writ-ten by Gary Park and Kay Cashman.Please send news leads topublisher@petroleumnews.com or call 907770-3505.

continued from page 1

INSIDER

SEAN PARNELL

JUNEAUDEC proposes financial responsibilityincreases for pollution response regulations

The Alaska Department of Environmental Conservation is proposing increases tothe dollar amounts of financial responsibility required for pollution response from awide range of oil facilities in Alaska. DEC periodically increases the dollar amounts inline with inflation, as measured by the Anchorage consumer price index.

“We do this regulatory process every three years,” Christopher Pace, environmen-tal specialist with DEC, told Petroleum News in early June. The original dollar amountswere set in 1990 and the amounts have increased to 1.435 times the 1990 levels, Pacesaid. The dollar amounts are specified by regulation and details of the proposedchanges can be obtained from DEC. Comments on the changes must be submitted byJuly 6.

Facility operators are responsible for ensuring compliance with the regulations but,once the regulations change, DEC will try to contact companies whose proofs of finan-cial responsibility fall below the new levels, Pace said.

—ALAN BAILEY

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 17

Companies involved in NorthAmerica’s oil and gas industry

ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS

Business Spotlight

AAeromapAeromedAES Lynx EnterprisesAgriumAir LiquideAir Logistics of Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Alaska Airlines CargoAlaska AnvilAlaska CoverallAlaska DreamsAlaska Interstate ConstructionAlaska Marine Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Alaska Railroad Corp.Alaska Rubber & SupplyAlaska SteelAlaska TelecomAlaska Tent & TarpAlaska TextilesAlaska USA Mortgage CompanyAlaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Alaska’s PeopleAlliance, TheAlpine-Meadow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Alyeska Prince HotelAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Arctic ControlsArctic FoundationsArctic Fox EnvironmentalArctic Slope Telephone Assoc. Co-op . . . . . . . . . . . . . . . . . . . 7Arctic StructuresArctic Wire Rope & SupplyASRC Energy Services

Engineering & TechnologyOperations & MaintenancePipeline Power & Communications

Avalon Development

B-FBadger ProductionsBaker HughesBroadway SignsBrooks Range SupplyCanspec GroupCapital Office SystemsCarlile Transportation Services. . . . . . . . . . . . . . . . . . . . . . . . . 5Carolina MatChiulista Camp Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15CN AquatrainColvilleConocoPhillips AlaskaConstruction Machinery IndustrialCoremongersCrowley AlaskaCruz ConstructionDowland - Bach Corp.Doyon DrillingDoyon LTDDoyon Universal ServicesDynamic Capital ManagementEngineered Fire and SafetyENSR Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Epoch Well Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12ESS/On-Site Camp ServicesESS Support Services WorldwideEvergreen Helicopters of AlaskaFairweather Companies, The . . . . . . . . . . . . . . . . . . . . . . . . . 18Friends of Pets

G-MGene's ChryslerGreat Northern EngineeringGreat NorthwestHanover CanadaHawk Construction Consultants . . . . . . . . . . . . . . . . . . . . . . 13H.C. PriceHilton AnchorageHoladay-ParksHorizon Well Logging, Inc.Hotel Captain CookIdentity WearhouseIndustrial Project ServicesInspirationsJackovich Industrial

& Construction SupplyJEMS Real EstateJudy Patrick PhotographyKenai Aviation

Kenworth AlaskaKuukpik Arctic CateringKuukpik/VeritasKuukpik - LCMFLasser Inc.LCMFLCMF - Barrow Village Response Team (VRT)Lounsbury & AssociatesLynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Mapmakers of AlaskaMarathon OilMarketing SolutionsMayflower CateringMEDC InternationalMI SwacoMichael Baker Jr.MWHMRO Sales

N-PNabors Alaska Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10NANA/Colt EngineeringNANA Oilfield ServicesNatco Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Nature Conservancy, TheNEI Fluid TechnologyNordic CalistaNorth Slope Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Northern Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Northern Transportation Co. . . . . . . . . . . . . . . . . . . . . . . . . . 13Offshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oilfield ImprovementsOilfield TransportPacific Detroit Diesel-AllisonPanalpinaPDC/Harris GroupPeak Oilfield Service Co.PencoPerkins CoiePetroleum Equipment & ServicesPetrotechnical Resources of AlaskaPGS OnshorePrecision PowerPrudhoe Bay Shop & StoragePTI Travco Modular Structures

Q-ZQUADCORAE SystemsRain for RentRanes & Shine WeldingRenew Air TaxiSalt + Light CreativeScan HomeSchlumberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Security Aviation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Seekins FordSmith Consulting ServicesSOLOCO Dura-Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Sourdough ExpressSpan-Alaska ConsolidatorsSpenard Builders SupplySTEELFAB. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Storm Chasers Marine ServicesSunshine Custom PromotionsSuperior Machine and WeldingTaiga VenturesTire Distribution SystemsTOTETotem Equipment & SupplyTrinity Inspection ServicesUdelhoven Oilfield Systems ServicesUmiat CommercialUnique Machine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Unitech of Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Univar USAUsibelliU.S. Bearings and DrivesVECOWelding ServicesWorksafeXTO Energy

Erling Young, PE, PMP

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By PAULA EASLEY

NANA/ColtEngineering

NANA/Colt is a full-service, multi-discipline industrial engineering compa-ny with deep roots in the oil industry.Its innovative engineering solutions aregeared to reducing surface, construc-tion and operating costs, as it did on anew production facility last year.Application of new technologies tosmaller independent oil company proj-ects has brought cost-effective productsto these clients. The company takesgreat pride in its sophisticatedAutoCAD design system.

Erling Young is a longtime Alaskanwhose career has centered on NorthSlope oil field development, from TAPSconstruction to Alpine. He received hismaster’s degree in civil engineeringfrom UAF. For 15 years Erling workedfor ARCO and has been withNANA/Colt five years. Married to Lynn,the couple has three grown children(and multiple foster children).

Stephanie Holthaus,Vice President, Cargo

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Northern Air CargoUsing Douglas DC 6, Boeing 727

jets, and ATR 42 aircraft, Northern AirCargo has been a pioneer of commer-cial aviation in Alaska for five decades.Scheduled cargo and charter operationsserve as a primary supply chain forrural areas. NAC’s three subsidiaries— Naclink, Northern Air MaintenanceServices, and Northern Air AviationServices — help serve the needs of anexpanding, diverse customer base.

Stephanie Holthaus has worked inevery aspect of service, sales, opera-tions and management during her 18years with NAC. She loves challenges.In May she finished her first-evertriathlon at the 2005 Nugget. Otherrewarding challenges have been beinga Big Sister and supporting youthorganizations. Husband Ken Acton con-sults on aviation issues, and when timeallows, they’re hopping on a jet plane.

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

(Jurassic) formations; however, the eco-nomics of … the project are marginal,”Pioneer told the state.

If it doesn’t get its royalties on the fourleases dropped from 12.5 percent to 5 per-cent, the Dallas-based independent said it“cannot vigorously pursue” developmentof the Oooguruk unit.

Pioneer has been working with thestate for the last six months, reviewingdata and trying to find ways to modify theexisting lease terms to “encourage timelydevelopment” of Oooguruk, a develop-ment Pioneer is quick to point out, thathas not yet been sanctioned by its boardof directors.

The company has said Ooogurukwould produce less than 20,000 barrelsper day and would be developed in fourfeet of water from a five-acre drill site.Pioneer hopes to commence constructionactivities in the first quarter of 2006 andbegin production near the end of 2007.

State can make big bucks Once part of ARCO Alaska’s Kuukpik

unit, which has since expired, the fourleases in the royalty reduction applicationbear a lower royalty than the leases cur-rently in the Oooguruk unit, which carry a16.67 percent royalty. But unlike those inthe unit, the four leases are subject to anet profit share interest that allows thestate to collect an additional 30 percentonce the costs of development have beenrecovered by Pioneer.

In its royalty relief request, receivedby the state May 25, Pioneer noted thatbecause of the net profit share provisionthe state will be able to participate “at alarge and significant level in all the proj-

ect success which results from favorablechanges in the price of oil or gas, produc-tion rates, projected ultimate recovery,development costs, and operating costs,lower cost performance or production rateupside.”

At Alaska North Slope West Coast oilprices of greater than $40 per barrel, the“expected financial benefits to the state”under the royalty reduction regime pro-posed by Pioneer “will exceed the bene-fits associated with a flat one sixth royal-ty,” which has become the state’s standardroyalty in and around existing infrastruc-ture, the company told the state.

$80 million in development costs In its application Pioneer also asked

the state to lump the four leases into a sin-gle development account, treating themas one lease. (A state statute establishesan accounting system for the administra-tion of net profit sharing leases which

consists of three separate accounts —development, production revenue, and netprofit payment.)

The company wants the aggregateddevelopment account balance to be for-mally set at $80 million as of Jan. 1, 2005,which Pioneer said will save audit andaccounting expenses — and giveinvestors in the project “relative fiscalcertainty.”

Royalty reductions can be a challengeAccording to Tim Ryherd of the state

Division of Oil and Gas, no applications forroyalty relief have been approved by thestate to date.

“There is a fairly high hurdle” to quali-fy, he said.

The applicant has to prove its projectneeds relief; that without it the project can’tgo forward, the division’s senior commer-cial analyst Kevin Banks told PetroleumNews June 7.

“To prove that often requires informa-tion that the company may not have or con-siders confidential, (including) … delin-eation, a fair amount of information aboutthe resource and pretty good informationabout the cost of developing the field,”Banks said.

“What we have found in the past is thatthis kind of information is not available atthe time they come in and apply for royaltyrelief. … They haven’t done the work yet.

“It’s a chicken and egg kind of problemfor producers,” Banks said, explaining thatproducers are often loathe to commit to theamount of investment it takes to obtain theinformation needed to qualify for the reliefuntil they can be sure they will get therelief.

When asked what kind of investmentwould be needed, he said to adequatelydelineate a prospect an applicant mighthave to drill additional wells, etc.

“It’s a major hurdle for them,” Bankssaid.

Setting a standard with Pioneer’s royalty relief

“We’re going to work with Pioneer

and see if we can thread the needle withthis project.” The division will be work-ing under new legislation that streamlinedthe process for applying for and deter-mining royalty relief – a process that wasseverely hampered by legislation passedin the mid-1990s, Banks said.

“We have enough tools available to usnow,” he said. “For example, a slidingscale royalty could be designed to allowfor changes in costs and oil prices.”

Although Banks had not yet reviewedPioneer’s application, he said if “there issome uncertainty about the resource, wecan craft the royalty provision so that thestate will get its full royalty if it turns outthe resource is bigger than expected.We’re going to look at that and otherthings with Pioneer.”

Although Pioneer clearly states in itsapplication that it is looking for fiscal cer-tainty for investors and therefore wantsdevelopment costs fixed at $80 millionand a flat royalty reduction to 5 percent,the company also refers to the part of thestatute that requires the state to modifythe royalty for an increase or decrease inthe price of oil or gas by using a slidingscale royalty or other mechanism. Thatportion of the statute also says a slidingscale royalty “may be based on other rel-evant factors such as a change in produc-tion rates, projected ultimate recovery,development costs, and operating costs,”Pioneer wrote.

Phillips, Unocal, BP once asked for royalty relief

Prior to the 2002 legislative change inthe royalty relief statute, the most recentroyalty relief request came from Phillipsfor its Tyonek Deep prospect in CookInlet, Banks said.

“My understanding is they backed outbecause they got caught up in the mergerwith Conoco,” he said, but there were alsoproblems because of a lack of informationto make the determination, he said.

“Before that, an application came infrom Unocal for royalty relief on all oftheir Cook Inlet platforms and through thecourse of the evaluation the state puttogether a proposal to provide relief forsome of the platforms but not all; somewere fine, some were beyond rescue, suchas Spark which is shut-in now, and somewould have qualified for relief.

“Before a final determination could bereached,” Banks said Unocal “began pur-suing a legislative fix and got it.”

The new law allows a platform to“automatically get royalty relief whenproduction falls to a certain amount,” hesaid.

Before Unocal’s application, BPapplied for royalty relief at Milne Point,“but fairly quickly withdrew their applica-tion … they elected not to pursue it.”

On fast track to get decision for Pioneer

Banks said the division has “notimetable for making a decision onPioneer’s (royalty relief) application otherthan to say that the company undoubtedlyneeds a decision fairly quickly.”

Whatever is decided, he said, has to beapproved by the governor.

“We’re going to try to work on this asfast as we can,” Banks said.

The application for royalty relief wasmade on behalf of Pioneer and its workinginterest partner Armstrong Alaska, anaffiliate of Denver-based Armstrong Oil &Gas. Armstrong originally assembled theprospect, which was initially calledNorthwest Kuparuk.

In addition to the four leases, Pioneersaid the June 15 unit expansion requestwill include other state leases adjacent tothe Oooguruk unit.●

18 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

Following is the informationPioneer provided about the wells withits application, beginning with thelease number, well driller and name,and the year the well was drilled. Thosewith an astrix were certified to be capa-ble of production in paying quantities.

• ADL 355036 ARCO Kalubik No.1 1992*

• ARCO Kalubik No. 2 1998• ADL 355037 Texaco Colville

Delta No. 1 1985*Texaco Colville Delta No. 1A 1985

• ADL 355038 Texaco ColvilleDelta No. 2 1986*

• ADL 355039 Texaco ColvilleDelta No. 3 1986*

• ADL 379301 Exxon Thetis IslandNo. 1 1993*

• ADL 389959 ARCO Kalubik No.3 1998

The four state leases included inPioneer’s royalty relief applicationhave gone through several transfers ofownership over the years. As a result,current working interest ownersinclude a number of companies.Pioneer and Armstrong have the largestchunks, but OXY and Herbaly LLCalso hold substantial portions.Anadarko, Hunt, and Joyce hold 2-4percent pieces, depending on the leaseand the interval.

—KAY CASHMAN

continued from page 1

WELLS

continued from page 1

PIONEER

Oil MILLIONAIRES

Aging mgmnt of Calif public colooking for successors wanting to

become millionaires thru options onstock they help increase in value.Currently seeking expl. mgr. (geo)to develop expanding exploration

programs and petroleum engineersto develop producing properties.

Salaries DOE, also medical and401K. Prefer 10+ yrs exp. includingCalif. Fax resume in confidence to

310/478-6070 attn JRK.

often agonizing struggle since theParliament of Canada passed legislation in1893 approving funds for the GeologicalSurvey of Canada to probe the oil sands asa source of energy.

There was even a time when the Albertagovernment was ready to approve the use ofatomic bombs almost on the scale of thosethat destroyed Hiroshima and Nagasaki totrigger an underground nuclear inferno toturn bitumen into a liquid that would even-tually be brought to the surface.

Canadian atomic energy and defenseauthorities had given preliminary approvalto the idea, but some suspect the govern-ment deliberately avoided controversy bynever completing a necessary technicalreport.

It wasn’t until 1967 that the first modernoil sands project, now owned by SuncorEnergy, started commercial production nearthe tiny river town of Fort McMurray.

Science drops costs by $25 per barrelSince then, the technological improve-

ments have seen the cost of separating thebitumen from a mixture of sand, water andclay fall from more than C$25 per barrel toless than half that – savings that afford com-panies a “safety net” for a time when oilprices fall.

“It’s technology that got us where we aretoday and it’s going to be technology thatgets us where we need to go,” says EricNewell, who retired after 14 years as chiefexecutive officer of Syncrude Canada, theconsortium that will soon pump 350,000barrels per day from the oil sands.

Scorning those who question the eco-nomics of the oil sands, he says there’s awave of new technology being developedthat makes him very bullish about the

resource.

Advances neededThe need for advances is critical.Natural gas is a vital element in the

extraction and processing of raw bitumen.In simple terms, you need energy to pro-duce energy.

To achieve the ambitious target of fivemillion barrels per day of oil sands outputwould consume an “unthinkable” 60 per-cent of all the natural gas from WesternCanada and the Arctic, the Alberta Chamberof Resources warns.

But the chamber acknowledges thatmany areas of fundamental science havebrought the oil sands to their currentadvanced stage and new science has thepotential to provide long-term answers.

The need for breakthroughs is empha-sized by John Richels, president of DevonEnergy, who says that “if we are going toexploit and properly develop the oil sands,we have to find a way that involves some-thing more than truck and shovel or con-ventional mining techniques.”

What are the possibilities?So what answers might lie in the alpha-

bet soup?SAGD – Developed in 1978 by Roger

Butler at Imperial Oil, it involves drillingtwin wells to bitumen deposits that areburied too deep to scoop out with mechani-cal shovels.

One well injects steam that breaks downthe bitumen and forces it to the surfacethrough the second well. EnCana and Petro-Canada have advanced to using SAGD forfull-scale production.

Because SAGD projects can be devel-oped in phases, construction costs are easi-er to manage than the massive mining ven-tures.

But there are drawbacks. SAGD requiresnatural gas to produce steam and needs

water – two commodities that are expensiveand limited.

MSAR – A possible fuel alternative tonatural gas that is made from a mixture ofbitumen, water and detergent and has com-bustion characteristics matching that of gas.

It was first developed by BP andPDVSA, Venezuela’s state-owned oil com-pany, in the 1980s for the heavy oil fields ofVenezuela.

MSAR is now being tested in a pilotproject involving Petro-Canada,ConocoPhillips, Deer Creek Energy andParamount Resources.

Quadrise Canada Fuel Systems, a privateCalgary-based firm, has assembled a 14-member team to promote the use of MSARin oil sands in-situ projects over the nextfew years, projecting the fuel will lower thecosts of bitumen production by US$2.50per barrel compared with natural gas,although it will require the reinjection ofcarbon dioxide emissions.

VAPEX – It’s a technology that is beingtested, using a vaporized solvent such aspropane, to reduce the stickiness of bitu-men. VAPEX proponents believe their tech-nology will use less steam and water thanSAGD, thus lowering costs. VAPEX isthought to be a couple of years away fromcommercial application.

SAP – A pilot project in Saskatchewanthat added a small amount of solvent tosteam indicated the flow rate of oil wasincreased by more than 50 percent. Moretests are underway in Alberta.

THAI – Yet another revolutionary tech-nology, this involves pumping air to ignitethe bitumen, allowing the oil to flow almostimmediately through a second well – thusfrom the “toe” of the well to the “heel”using air injection, or THAI.

Proponents estimate the method canrecover 80 percent of the original oil inplace and partially upgrade the crude at thesame time. ●

PETROLEUM NEWS • WEEK OF JUNE 12, 2005 19

continued from page 1

OIL SANDS

20 PETROLEUM NEWS • WEEK OF JUNE 12, 2005

GULF OF MEXICOPioneer begins production from new Gulf well

Exploration and production independent Pioneer Natural Resources said June 8 thatit has begun production from a new gas well at the company’s deepwater Gulf ofMexico Raptor field in the Falcon Corridor, located in the East Breaks area. The Raptorwell tested at about 30 million cubic feet of natural gas per day, Pioneer said, addingthat system pressure will limit the incremental production impact. But the new Raptorwell is expected to extend the productive life of the Falcon Corridor system and gen-erate a return on investment in excess of 100 percent, the company said.Pioneer holdsa 100 percent interest and operates the three fields which are tied into the Falcon facil-ities. Over the remainder of 2005, Pioneer said it plans to drill and operate two addi-tional wells in the deepwater U.S. Gulf of Mexico.

They are the Clipper prospect, an amplitude play located in the Green Canyon areain which Pioneer has a 55 percent interest, is currently drilling. The Paladin prospect, asub-salt well located in the Garden Banks area in which Pioneer expects to own abouta 40 percent interest, is expected to spud during the third quarter.

The company said it also plans to drill three to four wells on the Gulf’s continentalshelf before year-end.

—RAY TYSON

NORTH AMERICACanada’s rig count up by 104, U.S. up by 22

The number of rotary drilling rigs operating in the United States and Canada duringthe week ending June 3 totaled 1,728 rigs, up by a combined 128 rigs from the previ-ous week and up by 304 rigs from the same period last year, according to rig monitorBaker Hughes. The rig count in Canada alone surged by 104 to 375 rigs from the pre-vious week and was up by 119 rigs compared to the year-ago period.

The number of rigs operating in the United States stood at 1,353, an increase of 22rigs from the prior week and an increase of 185 rigs from last year. The number of landrigs increased by 18 to 1,231 rigs, while offshore rigs increased by four to 98 rigs.Inland water rigs were unchanged with 24 rigs.

Of the total number of rigs operating in the United States during the recent week,1,206 rigs were drilling for gas and 146 rigs for oil; one rig was being used for miscel-laneous uses. Of the total, 844 wells were vertical, 333 directional and 176 horizontal.

Among the leading U.S. producing states during the recent week, Texas gained 12rigs for a total of 611, Louisiana picked up six for a total of 187; Colorado increased bythree to 70; Oklahoma increased by three to 154; and California increased by one to 24.Alaska’s rig count was unchanged with nine rigs.

—RAY TYSON

WYOMINGBLM sale fetchesover $6.5 million

Receipts totaling $6,586,982 werereceived for leasing rights on parcelsoffered by the Bureau of LandManagement at the bi-monthly federaloil and gas lease oral auction held inCheyenne, Wyo. on June 7, BLM saidin a press release.

Bids totaling $6,330,437 rangedfrom the federally mandated minimumof $2 per acre to $500 per acre. That bidwas for a 241 acre parcel in CarbonCounty that was won by Marshall andWinston Inc., of Midland, Texas.

The highest bonus bid of $478,400was for a 1,195 acre parcel in CarbonCounty, which was won by BaselineMinerals Inc., of Denver, Colo.Successful bidders also pay a $75 perparcel administrative fee and yearlyrental of $1.50 per acre.

In addition to the bids, the sale net-ted $243,570 in first year rental fees,and $12,975 in administrative fees.Half of bid and rental receipts go to thestate of Wyoming.

A total of 175,311.740 acres in 189parcels were offered at the sale. A totalof 162,339.320 acres in 173 parcelswere sold. Average bid per acre for eachacre sold was $39 and the average par-cel sold netted $36,592.12 from bid-ding.

The next auction will be held onAug. 2 in Cheyenne.

—PETROLEUM NEWS