page14

ANGDA report: Future of NikiskiLNG plant uncertain, offers options

Vol. 11, No. 23 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of June 4, 2006 • $1.50

● J U N E A U , A L A S K A

● C A N A D A A R C T I C

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

● B A R E N T S S E A

5 Global trend reaches Canada High Arctic: International

turmoil sharpens focus on secure northern resources

6 Tesoro ready for upgrades in Nikiski: Plans to add $45Msulfur-stripping operation to meet need for ultra-low-sulfur diesel

11 Orders for offshore drilling rigs climb: Scramble on forrigs; 65-70 jack-ups, 25-30 deepwater rigs believed on order

Summer at the Prudhoe Bay field

Pictured above is Nabors drilling rig 4ES working at the GreaterPrudhoe Bay oil field on Alaska's North Slope The photo was taken afew years ago by Judy Patrick who does contract photography workfor companies in Alaska and elsewhere in North America. She can bereached by email at jpphoto@mtaonline.net or by telephone at 907223-4704. Nabors rig 4ES is currently doing workover operations onNGI Pad at Prudhoe.

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Barents bargaining chip?U.S, Russia trade political shots; Gazprom again delays Shtokman gas project

By RAY TYSONFor Petroleum News

ussia appears to be using its giant Shtokman gasproject in the Barents Sea as a bargaining chip togain U.S. support for its bid to become a mem-ber of the World Trade Organization. Caught in

the middle of the brouhaha are Shtokman hopefulsand U.S.-based majors ConocoPhillips and Chevron.

ConocoPhillips and Chevron were said to be on theshort list of companies being considered to partner upon Shtokman with Russia’s gas monopoly Gazprom.The project includes field development and construc-tion of a gas liquefaction terminal in northern Russia.Other contenders for the Shtokman job are Norway’sStatoil and Norsk Hydro and France’s Total.

However, just as some industry analysts had pre-

dicted, Gazprom in May again delayed naming theShtokman winners until August. The estimated $20billion project has been on the table for more than adecade, and forecasts for field startup have rangedfrom 2011 to 2015 to as late as 2020. Shtokman has

RCaught in the middle of the brouhaha areShtokman hopefuls and U.S.-based majorsConocoPhillips and Chevron. … were saidto be on the short list of companies being

considered to partner up on Shtokmanwith Russia’s gas monopoly Gazprom.

…Shtokman has estimated gas reserves of110 trillion cubic feet.

see BARENTS page 22

Arctic assets scrutinizedPetro-Canada, Canada Southern duel puts High Arctic gas under microscope

By GARY PARKFor Petroleum News

ow much Canada’s most distant hydrocarbonprospects are worth in an age when the industryis chasing assets in politically stable regions isbeing put to the test.

Petro-Canada has made a hostile, all-cash bid ofUS$113 million to swallow Canada SouthernPetroleum and lock up what the junior company esti-mates is 927 billion cubic feet of natural gas reservesin the High Arctic.

Operating through Nosara Holdings, a whollyowned unit, Petro-Canada said it has no intention ofrevising the bid that is due to close June 20.

Canada Southern counters that the unsolicited offer

H

see ASSETS page 22

Syncrude Canada execs Ruigrok,Carter up front on a smelly issue

IT WASN’T THE SORT OF GRAND OPENING oil sandsconsortium Syncrude Canada had in mind for the launch of anC$8.4 billion expansion.

The ribbon cutting on May 23 wasrelocated from the project site to avoidsending noxious, potentially hazardouswaste gas up the nostrils of its honoredguests.

But Syncrude took it on the chin, whenothers might have crawled underground.

The brass — Chief Executive OfficerCharles Ruigrok and Chief OperatingOfficer Jim Carter — fronted up to a gath-ering of global media and admitted theydidn’t know exactly how long it would take to remove the badsmells emanating from a unit installed to reduce sulfur dioxideemissions.

Ruigrok said the cost of solving the problem will not be

see INSIDER page 20

Gas bills dropGov. Murkowski sends stranded gas changes, pipeline corp., challenge bills

By KRISTEN NELSONPetroleum News

hile the administration of AlaskaGov. Frank Murkowski contin-ues with public hearings aroundthe state on the proposed gas

pipeline fiscal contract it negotiated withthe North Slope project sponsors — BP,ConocoPhillips and ExxonMobil — italso sent three bills related to the gaspipeline contract to the Legislature.

On the same day, May 31, the Senate passed aresolution setting up a Special Committee onNatural Gas Development, consisting of the mem-bers of the Finance and Resources committees, to

consider the contract and related legisla-tion, including oil and gas taxation.

Ultimately, after the administrationcompletes its hearings and negotiatesany changes to the draft contract, theLegislature will vote up or down on thecontract.

First, however, it is being asked toamend Alaska law to accommodate avery different project than the one itenvisioned when it passed the AlaskaStranded Gas Development Act in 1998.

The proposal now, the governor said in a transmit-tal letter for House and Senate Bill 2004, amend-

see BILLS page 20

WGov. FrankMurkowski

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

2 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

NATURAL GAS

LAND & LEASING

PIPELINES & DOWNSTREAM

ON THE COVERGas bills drop

Gov. Murkowski sends stranded gaschanges, pipeline corp., challenge bills

Barents bargaining chip?

U.S, Russia trade political shots; Gazprom again delaysShtokman gas project

Arctic assets scrutinized

Petro-Canada, Canada Southern duelputs High Arctic gas under microscope

19 New group looks to ease sands tensions

16 Alberta, British Columbia land still hot

17 Contractor availability an issue in mega projects

15 Another option: Convert to an LNG import facility

GOVERNMENT

EXPLORATION & PRODUCTION

FINANCE & ECONOMY

11 Orders for offshore drilling rigs climb

E&P companies scrambling for dwindling supply of available rigs; 65-70 jack-ups, 25-30 deepwater rigs believed on order

10 Bush praises House for ANWR green light

Proponents say bill may be best chance to see oil and gas development in Arctic coastal plain approved by U.S. Congress this year

14 Future of Nikiski LNG plant uncertain

Stone & Webster report says continued export of liquefied natural gas after 2011 dependent on new gas supplies, plant renovation

17 Expert: Success in big projects upfront

Al Rogers with Independent Project Analysis giveslegislators heads up based on company’s upstream project evaluation system

16 Enbridge out to satisfy oil sands thirst

Planned pipeline would bring 180,000 bpd of diluent from Midwest to Edmonton;

150,000 bpd line from Kitimat already planned

12 BP to try new waterflood for viscous

Drawing hot, clean water from deep undergroundand injecting it into the viscous oil reservoir should increase production rates

8 Knowles pledges to redo gas line deal

Former Alaska governor enters gubernatorial race against incumbent, promising to scrap and redo fiscal contract with North Slope producers

6 Tesoro ready for upgrades in Nikiski

Petroleum refiner plans to add $45 million sulfur-stripping operation to meet Alaska’s need for ultra-low-sulfur diesel

16 Connacher untroubled by regulatory snags

4 New trust rises from consolidation

4 State will file reopener claims in EVOS

5 Global trend reaches Canada High Arctic

9 Oil sands get mining sector attention

9 Canaport LNG project in full swing

10 Energy close to 19% of Canada’s exports

1 Syncrude Canada execs Ruigrok, Carter up front on a smelly issue

OIL PATCH INSIDER

PETROLEUM NEWS • WEEK OF JUNE 4, 2006 3

Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Workovers W-22 BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 1J-127 ConocoPhillipsDreco 1000 UE 16 (SCR) Workover DS11-11 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD2-404 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk 1J-184 ConocoPhillipsTSM 7000 Arctic Fox #1 Stacked in Yard Pioneer Natural Resources

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES (SCR) R-35 BPMid-Continental U36A 3-S Milne Point MPH-09 BPOilwell 700 E 4-ES (SCR) Prudhoe Bay NGI-09 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay E-15C BPDreco 1000 UE 9-ES (SCR/TD) Aurora S-121 BPOilwell 2000 Hercules 14-E (SCR) Stacked at Cape Simpson AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked, Prudhoe Bay AvailableOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableOIME 1000 19-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Stacked, Kuparuk AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Prudhoe Bay AGI-07A BP

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay C-04B BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay L5-16 BPIdeco 900 3 (SCR/TD) Kuparuk 3S-23a ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E Moving BP

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Rigging up for workover at Nicolai Aurora Gas

Creek 1b workover

Kuukpik 5 Preparing to mobilize to Swanson UnocalRiver.

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Ninilchik State #2 Marathon

Nabors Alaska DrillingNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Stacked in Kenai Available

Cook Inlet Basin – Offshore

Unocal (Nabors Alaska Drilling labor contractor)Not Available

XTO EnergyNational 1320 A Platform A C21A-23 XTONational 110 C (TD) Idle XTO

Mackenzie Rig StatusCanadian Beaufort Sea

Seatankers (AKITA Equtak labor contract)SSDC CANMAR Island Rig #2 SDC In cold shutdown at Paktoa Devon ARL Corp.

Mackenzie Delta-OnshoreAKITA EqutakDreco 1250 UE 62 (SCR/TD) Stacked in Tuktoyaktuk, NT Available

Yukon Territories Rig StatusNorthwest Territories

Ensign Resources Svc. Grp.Jackknife Double 55 Racked in Ft. Nelson

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of June 1, 2006.

Active drilling companies only listed.

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

This rig report was prepared by Alan Bailey

Baker Hughes North America rotary rig counts*May 26 May 19 Year Ago

US 1,649 1,639 1,331Canada 325 267 271Gulf 92 96 91

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

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4 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

Dan Wilcox CHIEF EXECUTIVE OFFICER

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Paula Easley DIRECTORY PROFILES/SPOTLIGHTS

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Judy Patrick Photography CONTRACT PHOTOGRAPHER

Mapmakers Alaska CARTOGRAPHY

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CANADANew trust rises from consolidation

The ranks of the Canadian energy industry have shrunk again, with NAVEnergy Trust and Clear Energy announcing a stock-swap merger carrying a mar-ket value of about C$473 million.

The new entity, operating under the name of Sound Energy Trust, will pro-duce 12,500 barrels of oil equivalent, almost two-thirds of it natural gas.

Sound will incorporate a diversified portfolio including strong prospects incentral Alberta and the Peace River Arch, along with adjoining lands in thecoalbed methane plays of Horseshoe Canyon and Mannville.

NAV President Thomas Stan said the combined assets will allow a more bal-anced year-round operation, with less reliance on winter access to properties.

Sound will have distributions of less than 60 percent of cash flow, reflectinga trend among trusts that were once counted on to channel 90 percent or more tounit holders.

But Stan believes the higher-payout trusts may have difficulty sustainingthose levels.

—GARY PARK

ALASKA

State will file reopener claims in EVOSState and federal claims against Exxon Mobil Corp. to restore damage from the

1989 Exxon Valdez oil spill will be filed in time to meet the June 1 deadline, Gov.Frank Murkowski said the last weekend in May.

The claims are being made according to the 1991 reopener provision of theExxon civil settlement suit, requiring the oil company tocommit $100 million for environmental restoration of PrinceWilliam Sound.

The reopener provision in the settlement expires Sept. 1.The state and federal governments must file a claim 90 daysbefore that date.

Murkowski and State Attorney General David Marqueztold The Daily Mirror the state may file another lawsuit ifExxon refuses to pay the money.

U.S. Sens. Ted Stevens and Lisa Murkowski earlierrequested ExxonMobil voluntarily commit the money forrestoration damages.

But Exxon maintains it is sticking to the original settle-ment, which requires them to pay only if the court agrees the damage was unex-pected and the restoration projects are narrowly defined.

Lucinda Jacobs, a consultant analyzing oil-spill damage for the state, said stud-ies show there remain areas with lingering impact.

She said scientists have dug 6,775 test pits, and of those more than 500 werefound to have traces of subsurface oil.

Jacobs listed sea otter, sea birds, harlequin ducks, clams and mussels, harborseals and killer whales showing various stages of recovery.

Jacobs said Pacific herring is not recovering, but the herring fishery is being hitby a virus that scientists are not sure is linked to the oil spill.

—THE ASSOCIATED PRESS

State AttorneyGeneral DavidMarquez

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By GARY PARKFor Petroleum News

he tsunami washing over some of theleast predictable oil and gas regionson the planet has managed to lap atthe shores of Canada’s Arctic

Islands.The unexpected hostile run Petro-

Canada is taking at minnow CanadaSouthern Petroleum has been directly tiedto the turmoil over how far countries suchas Venezuela, Ecuador, Bolivia, Peru,Russia, Kazakhstan and various nationsin Africa and theMiddle East are pre-pared to go innationalizing theirresources or extract-ing greater econom-ic “rent.”

The asset grabthat seems to begathering pace on aglobal scale may beat the root of Petro-Canada’s uninvitedbid for CanadaSouthern.

Richard McGinity, chairman of thejunior E&P company, said May 25 thatwidespread geopolitical instability that isendangering major oil and gas supplies issuddenly pushing North America’s fron-tiers to the forefront as potential sourcesof “significant, discovered and secureresources.”

Venezuela’s mercurial President HugoChavez is identified as the most troublingcurrent bogeyman for the industry.

But others seem eager to operate in thedust storm he has created as they trashlegal deals negotiated in good faith intheir quest for a larger chunk of resourcerevenues.

Producers who have fought backagainst crippling increases in royaltiesand taxes have suddenly faced expropria-tion of their investments.

Here’s a sampling of the recentupheavals:

Venezuela — In his assault on Big Oil, Chavez

has set his sights on majority control ofthe Orinoco River basin’s four projects,developed at costs running into billions ofdollars by Chevron, ExxonMobil,ConocoPhillips and Total and now pump-ing about 620,000 barrels per day of syn-thetic crude, second only to the compara-ble fields of northern Alberta.

He wants to hand 51 percent control offields worth an estimated US$33 billionto state-run Petroleos de Venezuela,PDVSA, which currently has an average40 percent stake, leaving the private oper-ators as minority joint venture partners.

The Chavez government’s plan alsoincludes a hike in royalties to 30 percentfrom 16.7 percent, while taxes wouldclimb to 50 percent from 34 percent.

As if that’s not enough, PDVSA direc-tor Eulogio del Pino said May 25 that thegovernment may even seek a 60 percentstake.

PDVSA has already taken over 32smaller conventional oil production proj-ects that had been run by private compa-

nies, including the seizure of two fieldsrun by Total and Eni, without a hint ofcompensation.

Turning up the rhetoric, Chavez hasthreatened to divert crude now exportedto the United States to China, Europe andother nations, suggesting that wouldboost oil prices to US$100 per barrel.

Analysts and a former PDVSA direc-tor Alberto Quiros are among those warn-ing that the specter of nationalization willface major legal and economic chal-lenges, not least the exposure of theOrinoco projects to Wall Street financing— issues Quiros said the governmentseems to have overlooked.

Bolivia— President Evo Morales, a Chavez

buddy, nationalized his oil and gas indus-try and has so far refused to compensatethe companies.

The two leftist presidents held a jointrally May 26 in Bolivia and participatedin a series of agreements betweenPDVSA and Bolivia’s YBFB to, in thewords of Chavez, “unite in a strategicalliance to advance together in certifyingnatural gas fields, in exploring natural gasfields, oil fields and in petrochemicals.”

PDVSA is expected to commit majorinvestments to Bolivia’s industry, helpingto certify gas reserves that are the secondlargest in South America and, accordingto some speculation, contribute US$1.5billion to joint ventures.

Meantime, PDVSA has announced itmay borrow US$20 billion from interna-tional banks to promote its objective ofdoubling production to 5.8 million bpd by2012.

Ecuador— Under President Alfredo Placio, the

government and state-ownedPetroecuador have been at logger heads

PETROLEUM NEWS • WEEK OF JUNE 4, 2006 5

● C A N A D A

Global trend reachesCanada High ArcticTurmoil in South America and other regions sharpens focuson remote ‘discovered and secure’ northern frontier resources

T

see TREND page 8

Venezuela’s mercuri-al President HugoChavez is identifiedas the most trou-bling current bogey-man for the industry.

6 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

● K E N A I P E N I N S U L A

Tesoro ready for upgrades in NikiskiPetroleum refiner plans to add $45 million sulfur-stripping operation to meet Alaska’s need for ultra-low-sulfur diesel

By ROSE RAGSDALEFor Petroleum News

esoro Alaska is moving ahead with plans to add ahydro-treating facility to its 72,000 barrel-per-daypetroleum refinery in Nikiski.

The $45 million project will enable Tesoro, one ofAlaska’s leading petroleum fuels manufacturers, to supplythe state with most of the ultra-low-sulfur diesel it will needwhen federal rules mandate use of the 15 parts-per-millionsulfur fuel in 2010 and 2012.

Tesoro, meanwhile, will provide the relatively smallamount of ultra-low-sulfur diesel needed this year forAlaska’s urban highway fleet, using its existing refiningcapacity, according to Vern Miller, chief engineer at TesoroAlaska.

“As time goes along in the future, we will need morefuel, but we can make the 10 percent needed right now, offour existing hydrocracker,” Miller told members of theAlaska Support Industry Alliance Kenai Chapter at a meet-ing May 16.

He said the Alaska Department of EnvironmentalConservation estimates that Alaska motorists use 3,000bpd, or roughly 165,000 gallons per day, of diesel on thestate’s non-rural highways during the high-demand sum-mer months and a lesser amount in winter.

This does not include the marine and home-heating fuelconsumed in rural Alaska nor the 3,300 bpd of diesel usedby oil producers on Alaska’s North Slope.

Alaska’s rural and urban users together consume about60 million gallons of diesel a year, according to DEC.

Miller gave the Alliance a brief overview of changingregulatory requirements for diesel fuel in Alaska as well asTesoro’s plans for modifying its Nikiski refinery to meetUSLD needs.

Groundbreaking this summerHe said Tesoro plans to break ground for the major

upgrade this summer and complete that project by June 1,2007.

The construction will include a 10,000 bpd diesel distil-late desulfurizer comprised of a standard hydrotreater witha fracturenator instead of a stripper, Miller said.

“This will allow us to produce No. 1 diesel for winterand (other) summer blends of fuel,” he explained.

How does a distillate desulfurization unit work?Once high-sulfur diesel or jet fuel is manufactured, it is

then heated to temperatures hotter than 600 degreesFahrenheit, according to a company illustration.

Next, hydrogen gas is mixed with the hot distillate androuted into a reactor where the mixture is subjected to highpressure in the presence of a catalyst. The resulting chemi-cal reaction causes sulfur to leave the hydrocarbon mole-cules and bind to the hydrogen, forming H2S.

The mixture then is moved to a fracturing unit where theH2S is stripped from the diesel or jet fuel. The resultingfuel product is clean enough to meet regulations, and theH2S can be further processed to produce elemental sulfur.

Modifications begun this springTesoro Alaska also began modifications this spring to

the refinery’s existing hydrotreater aimed at bringingonline the limited stream of ultra-low-sulfur diesel neededthis year. This enabled the company to meet theEnvironmental Protection Agency’s deadline of June 1,2006, for the refiner to supply the highway market thissummer. Filling stations, distributors and owners of diesel-burning vehicles must meet subsequent deadlines inSeptember and October.

To avoid contamination of ULSD with high-sulfurdiesel, every operator in the supply chain, from the refinerto the trucking fleet manager, will be required to keep thecleaner fuel separated from the older product. This meansseparate refining facilities, pipelines, terminals, tankers andstorage tanks.

Construction of a new dock, tank farm and terminal areunder way at Tesoro, Miller told the Alliance.

Tesoro began flushing pipelines and stripping storage

tanks for ULSD in Anchorage in April. “We will have adedicated facility this year and a second terminal in 2007,”Jeff Evans told the Alaska Truckers Association in April.

Tesoro aims to manufacture ULSD with 6 ppm at therefinery that will average 8 ppm at the terminal and leavethe terminal at 12 ppm, Evans said.

Tesoro already makes ultra-low-sulfur gasoline, so therefiner plans to sandwich the new diesel between batchesof the gas in the same pipeline. In addition, the companyalso manufactures gasoline, liquefied petroleum gas, heavyoils and bunker fuels and liquid asphalt.

Tesoro plans to offer four grades of diesel this year,including ULSD and five grades next year. Some of thediesel will be exported to the West Coast, according toEvans.

Tesoro’s competitor North Pole refiner Flint Hills ishelping to pay for the refinery upgrades thanks to a multi-year agreement the company entered with Flint Hills inNovember. That company contributed capital to cover partof the cost of the $45 million project in exchange forreceiving a guaranteed minimum in-state supply of 6,000bpd ultra-low-sulfur diesel.

Miller declined to say how much capital Flint Hillscontributed to the project, but Flint Hills’ officialsreportedly have said their company put $15 milliontoward the construction. ●

Tesoro’s competitor North Pole refiner FlintHills is helping to pay for the refinery upgradesthanks to a multiyear agreement the company

entered with Flint Hills in November.

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PETROLEUM NEWS • WEEK OF JUNE 4, 2006 7

8 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

with the industry and the United Statesafter scrapping an operating contract withOccidental Petroleum in a dispute overtaxes, then targeting a 14.5 percent shareof the consortium that operates a 450,000bpd pipeline.

Petroecuador is already operating

Occidental’s former fields that averageoutput of 100,000 bpd on a trial basis.

The Occidental fields were seized whenEcuador ruled the company failed to noti-fy the government when it sold a 40 per-cent stake in its production block toEnCana, which, in turn, unloaded the assetlast year to a joint venture of Sinopec andChina National Petroleum Corp. (both ofthem from China’s stable of government-

owned enterprises) for US$1.42 billion.Occidental countered with an arbitra-

tion claim against Ecuador, seeking morethan US$1 billion in damages.

Ecuador insists it did not expropriateOccidental’s fields, but only claimed themafter a judicial process ruled the U.S. com-pany violated its production sharing.

The Chinese joint venture said it maynow ask for a refund of up to US$284 mil-lion from EnCana — a claim the Canadianindependent has not dismissed out of handgiven the government seizure of Block 15.

In retaliation, China NationalPetroleum Corp. has now said it may optout of developing two new discoveriestotaling 100 million barrels on Block 11because of the harsh new tax/royaltyregime imposed on foreign companies bythe Ecuadorian government.

The spill over could also affect otherAsia companies that are major investors inEcuador, including Japan’s Teikoku Oil.

In another development PDVSA hasagreed to refine crude from Ecuador —250,000 bpd of which is currently export-ed to the U.S. — to tighten links betweenthe two countries.

Peru— A June 4 second-round presidential

run-off is expected to see a change in theenergy investment rules, regardless of whowins between radical nationalist OilantaHumala and former president Alan Garcia,described as a center-leftist.

The industry had its first taste of changein 1990 when most assets of state-ownedPetroperu were sold off, including Peru’slargest gas project, Camisea.

The parties behind both Garcia andHumala have pledged to renegotiate thefour Camisea contracts, key among theissues behind the yardstick used to deter-mine gas and condensate prices.

There has also been talk of imposing anextraordinary tax on companies wheninternational prices rise above a set level.

Both candidates are also resolved torenegotiate the transport terms, unhappywith five pipeline breaks since the linestarted operations in August 2004.

Trend not all one wayBut the trend sweeping South America

is not all in one direction.

In fact, Bolivia’s nationalization movehas angered Brazil’s President Luiz InacioLula da Silva, aggravated by Morales’sclaims that Brazil’s Petrobras, which hasinvested US$1.5 billion in two refineriesand controls 45 percent of its gas fields,has been operating illegally in his country.

Marching to his own drum-beat isColombia’s President Alvario Uribe, whohas taken an active role in signing an arrayof new exploration contracts with foreigncompanies he hopes will reverse a rapiddecline in oil output from 830,000 bpd in1999 to 530,000 bpd.

Colombia’s upstream regulator is aim-ing to rebuild volumes to 700,000 bpd by2010, which requires the participation ofcompanies such as Amerada, Anadarkoand BG.

More than government interference, theconcerns of foreign companies are likely tobe concentrated on the interminable battleswith insurgent groups and anti-govern-ment forces, who have kidnapped manyworkers, and on the difficult terrain.

Russia— In a climate of rising tensions with

the United States, the Russian administra-tion of Vladimir Putin is talking about tak-ing control of massive energy undertakingsin the Far East and dismantling the part-nership for the giant Shtokman gas field(see Shtokman story on page 1 of thisissue).

A report by the Resources Ministry saiddevelopment of ExxonMobil’s Sakhalin-1,Shell’s Sakhalin-2 and Total’s Kharyagaproduction-sharing agreements are behindschedule, over budget and lacking Russianinvolvement.

The ministry said Russia’s Academy ofNatural Science urged Russian companiesin the projects should have a 51 percentpresence to solve the problems.

Meanwhile, Putin is reportedlydemanding changes to resources law tocategorize all oil and gas fields as “strate-gic” and thus off-limits to foreigners.

With Moscow-Washington relationsincreasingly strained there has been amounting threat to dump ConocoPhillipsand Chevron from the partnership assem-bled to develop the 3.2 trillion cubic footShtokman field, along with Total, andNorway’s Norsk Hydro and Statoil. ●

continued from page 5

TREND

● A L A S K A

Knowles pledges to redo Alaska gas line dealFormer governor enters gubernatorial race against incumbent, promising to scrap and redo fiscal contract with North Slope producers

PETROLEUM NEWSormer Alaska Gov. Tony Knowles says he will runfor governor, challenging Republican incumbentGov. Frank Murkowski who is serving his firstfour-year term. At the top of Knowles’ list of prom-

ises is a pledge to scrap and redo a $20 billion natural gaspipeline contract negotiated by Murkowski with theNorth Slope oil producers and cur-rently before the Legislature andpublic for review.

“We just need to start fromscratch,” Knowles, a Democrat andtwo-term governor from 1994 to2002, was quoted as saying in aReuters article following a late Maypress conference in Anchoragewhere he announced his candidacy.Murkowski, at 73 the nation’s oldestgovernor and a former U.S. senator,is a Republican and has served asAlaska’s governor since Knowlesleft office.

Knowles has pledged to “open negotiations up to allproposals,” including restarting discussions with theNorth Slope producers while working with other inter-ested parties.

“If we want to speed up the probability of getting a

pipeline, we should say that anyone who meets our termsshould come forward with a proposal,” he said in a June1 Fairbanks Daily News-Miner story.

Knowles said the governor should choose one pro-posal but send them all to the Legislature for review:“Why wouldn’t you want to know what other proposalsare out there that could be advantageous to the state? …(The state needs) to open it up to all parties who expressan interest, to lay out conditions under which we want tosee it developed and take the best proposal.”

Other entities that have applied under the state’sStranded Gas Development Act to construct a pipelinefrom the North Slope are TransCanada, the AlaskaGasline Port Authority and MidAmerican. Those pro-posals were rejected or put on hold by Murkowski infavor of pursuing a deal with the oil producers who con-trol the mineral rights to the 35 trillion cubic feet ofproven natural gas reserves on the North Slope.

Knowles said that the agreement negotiated byMurkowski with the producers provides no assurancethat a gas pipeline will be built, freezes oil and gas taxesfor a period of 45 years, and makes other major conces-sions involving both oil and gas development and pro-duction that are not in the state’s best interest.

“I think people are very disturbed that we wouldattempt to give away or lock in a set price so that wecould induce somebody to build a gas pipeline,” said

Knowles, who did not run for re-election in 2002because state law does not allow a governor to servemore than two consecutive terms.

At Knowles’ side during the news conference wasHouse Minority Leader Ethan Berkowitz, who until May30 had been a Democratic gubernatorial candidate.Berkowitz filed paperwork to run instead for lieutenantgovernor and said he expects to be Knowles’ runningmate.

If a third party built the gas line Knowles said it wasunlikely the state would have to legally force the pro-ducers to sell their gas by threatening to pull leases. Theproducers, he said, would have a difficult time defendinga decision not to sell their gas at the wellhead.

Murkowski, who has announced his intention to runfor a second term, says major concessions are needed togive the producers incentive to move forward with whatthey see as a high-risk project.

Both Murkowski and Knowles must win crowded pri-mary elections on Aug. 22 if they are to advance to theNov. 7 general election. Former legislator and Fairbanksbusinessman John Binkley and former Wasilla MayorSarah Palin are challenging Murkowski in theRepublican primary; Rep. Eric Croft of Anchorage isfacing Knowles in the Democratic primary.

—The Associated Press contributed to this report

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Tony Knowles, for-mer Alaska gover-nor, enters Alaskagubernatorial raceagainst incumbentFrank Murkowski

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By GARY PARKFor Petroleum News

hen Teck Cominco, one of theworld’s largest zinc producers,paid C$475 million last year totake a 15 percent stake in the Fort

Hills oil sands project and started talkingabout evaluating other oil sands opportu-nities it was seen as the most significantentry by the mining industry into theworld of bitumen recovery in Alberta.

There had been an earlier break-through when employees of BHPBilliton, after being laid off as part of aNorth American downsizing by theAustralian mining giant, formed WesternOil Sands, which now has a 20 percentshare of Shell Canada’s Athabasca proj-ect.

But Teck Cominco was the answer to along search by Fort Hills’ partners Petro-Canada and UTS Energy to find someonewith mining expertise.

Adding a mining partner to the mix

was saluted by analysts as innovative andsensible and possibly the beginning of anew trend in the oil sands, where extract-ing raw bitumen had always been con-ducted in-house by the oil companiesthemselves.

Not that Teck was given bargain mem-bership in Fort Hills. It is required tocover 34 percent of the project costs up tothe C$2.5 billion market, then contribute15 percent to cover its equity stake.

Although Suncor Energy andSyncrude Canada believe they have accu-mulated enough expertise not to need out-side mining expertise, analysts have sug-gested companies such as France’s Totalmight be on the look-out for a suitablemining partner.

Newmont, Kinross express interestSo far, action on that front has been

quiet, but two major mining companies— Newmont Mining and Kinross Gold— have recently expressed interest in oilsands investments, one as a possible sell-er and the other as a buyer.

Newmont, the world’s largest goldproducer, said it is ready to capitalize ongrowing international interest in the oilsands by offering leases that wereacquired in 1999 for US$1 million andcould now fetch C$600 million.

In a notice of offering posted by ScotiaWaterous, a unit of the Bank of NovaScotia, Newmont said it is looking atoptions for its three BlackGold leases thatcover almost 10,000 acres alongside

properties held by EnCana, DevonEnergy and Nexen.

The resources are too deep to berecovered through open pit mining andneed in-situ technology, such as steaminjection to melt the bitumen deposits, tobe developed.

The assets are valued in the range ofC$2 per barrel and are expected to attractoffers from both established and emerg-ing oil sands players.

Kinross funding start-upMeanwhile, Kinross is funding the

start-up of a new junior company to huntfor oil sands and uranium investments inCanada, the United States and Russia.

The as-yet-unnamed private company,to be based in Reno, Nev., and headed byformer Kinross Chief Operating OfficerScott Caldwell, hopes to land stakes inearly-stage energy projects, the companysaid.

Kinross plans to be the “primaryinvestor” in the unit, but gave no indica-tion how much it is prepared to con-tribute. ●

● A L B E R T A

Oil sands get mining sector attentionTeck Cominco already part of Fort Hills oil sands project; Newmont ready to capitalize on internationalinterest by marketing oil sands leases; Kinross funding company to look for oil sands investments

PETROLEUM NEWS • WEEK OF JUNE 4, 2006 9

Newmont, the world’s largest goldproducer, said it is ready to

capitalize on growinginternational interest in the oil

sands by offering leases that wereacquired in 1999 for US$1 million

and could now fetch C$600million.

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ATLANTIC CANADACanaport LNG project in full swing

More pieces have fallen into place for the Atlantic Canada liquefied natural gasproject, with momentum on its side.

Canaport owners, Irving Oil of New Brunswick and Repsol of Spain, have award-ed the contract to design and build an import terminal to a partnership led by engi-neering firm SNC-Lavalin.

Canaport also said it has com-pleted an agreement to transportgas from the terminal to marketsin Canada and the northeasternUnited States via the Brunswickpipeline, an expansion of theexisting Maritimes & NortheastPipeline that carries about 400million cubic feet of gas fromNova Scotia’s Sable field to thenortheastern U.S.

In addition, a contract for theterminal’s offshore facilities went to a consortium of Peter Kiewit Sons Co. ofNewfoundland, Sandwell Engineering of Vancouver and Weeks Marine of NewJersey.

Terms of the contracts were not disclosed.However, Emera of Nova Scotia said it plans to invest C$350 million to assume

full ownership of the proposed 85-mile Brunswick pipeline to carry 850 million cubicfeet per day of gas over 25 years.

Emera is a partner with Duke Energy and ExxonMobil in the Maritimes &Northeast system.

The Canaport terminal will handle LNG imported from Trinidad & Tobago.While Canaport keeps rolling ahead, the clouds continue to gather over Anadarko’s

Bear Head project in Nova Scotia.Anadarko’s Chief Financial Officer Al Walker told an energy conference in Texas

in late May that the clock is running down in the company’s search for an LNG sup-plier. If the company is unable to negotiate a supply arrangement in “coming months… then we will probably move to mothball (the Bear Head) facility unless somebodywalked in with an extremely attractive price and wanted to buy it from us.”

Anadarko announced in March that it was slowing construction of the terminalafter the hunt for a supplier failed to yield success by the late 2005 target date.

Company officials have said since then that they see Bear Head as a good projectand their priority is to find long-term LNG supply, not a sale of the assets.

—GARY PARK

Canaport also said it has completed anagreement to transport gas from the

terminal to markets in Canada and thenortheastern United States via the

Brunswick pipeline, an expansion of theexisting Maritimes & Northeast

Pipeline that carries about 400 millioncubic feet of gas from Nova Scotia’sSable field to the northeastern U.S.

The as-yet-unnamed privatecompany, to be based in Reno,Nev., and headed by former

Kinross Chief Operating OfficerScott Caldwell, hopes to landstakes in early-stage energyprojects, the company said.

10 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

● W A S H I N G T O N , D . C .

Bush praises Housefor ANWR green lightProponents say bill may be best chance to see oil and gas developmentin Arctic coastal plain approved by U.S. Congress this year

By ROSE RAGSDALEFor Petroleum News

he U.S. House of Representativesvoted May 25 to allow limited ener-gy development in the coastal plainof the Arctic National Wildlife

Refuge, marking the 12th time the bodyhas signed off on ANWR drilling andpotentially creating a strong vehicle towin over the U.S. Senate this year.

House members voted 225-201 todirect the Interior Department to sell oiland gas leases on the 1.5 million acres inANWR known as the 1002 Area.Geologists say thearea could holdmore than 10 billionbarrels of recover-able oil that can beaccessed using only2,000 acres.

The legislation,House Resolution5429, the American-Made Energy andGood Jobs Act, came to the House floorjust before the Memorial Day recess.

The House vote fell heavily alongparty lines. Twenty-seven Democratsjoined the Republican majority in sup-port of the legislation, while 30Republicans opposed the measure.

The House action won praise fromPresident Bush, who immediately urgedthe U.S. Senate to join the House inpassing ANWR legislation.

“I applaud today’s vote in the Houseto allow for environmentally responsibleenergy exploration in a small part of theArctic National Wildlife Refuge,” Bushsaid May 25. “A reliable domestic sup-ply of energy is important to America’ssecurity and prosperity. This project willkeep our economy growing by creatingjobs and ensuring that businesses canexpand. And it will make America lessdependent on foreign sources of energy,eventually by up to a million barrels ofcrude oil a day — a nearly 20 percentincrease over our current domestic pro-duction.”

Bush also singled out HouseResources Chairman Richard Pombo, R-Calif., for praise. Pombo introduced themeasure and, along with other HouseGOP leaders, hemmed it in with proce-dural rules to limit opponents’ chancesto derail the measure.

Viewed by many as being mostlysymbolic, the legislation prevailed afteronly a couple of hours of debate.Opponents say the House has approved

ANWR drilling repeatedly in past years,only to see it fail in the Senate.

Approval of the legislation, they say,more accurately reflected the desire ofHouse members to take home legislationduring the holiday break that will showconstituents they are working to curbhigh gasoline prices.

Test will be in SenateThe real test, they say, will come later

this summer, when the Senate takes upANWR legislation. In the past, ANWRbills have been blocked in the Senate bythe threat of a Democratic filibuster.ANWR supporters have been unable togather the 60 votes needed to overcomea filibuster, coming closest in Decemberwith 57 ballots in favor of development.

Currently, a provision allowing oildrilling on ANWR’s coastal plain is partof a fiscal 2007 budget resolution pack-age in the Senate that narrowly wonapproval 51-49 in March. That legisla-tion includes language instructing theSenate Energy Committee to raise $3billion by immediately openingANWR’s coastal plain, or 1002 Area, tooil and gas leasing.

The House, however, did not includeANWR drilling in its budget bill andboth houses do not appear to be inclinedto conference on the budget, said JerryHood, a lobbyist working Arctic Power,a pro-ANWR development group repre-senting many Alaskans. “So the budgetprocess is no longer available for ANWRlegislation unless something drasticallychanges. Thus, the vote in the Housebecomes so much more than symbolic. Itis fast becoming the only chance forANWR in this Congress.”

Meanwhile, a host of external forces,including world events and high energyprices, are putting pressure on Congressto do something meaningful, Hood saidMay 31.

“This makes the House vote veryimportant,” he said. “We will be in dis-cussions with folks in the Senate nextweek to see what we can do to move for-ward.”

“I am ever the optimist,” Hood said,and ANWR supporters have tools avail-able to them this time around that theyhave never had before. We can mountpressure on the Senate to take action.”

Many observers, however, predict theelection in November will bring achange in the majorities of both housesof Congress.

“If that happens,” says Hood, “it willput ANWR on ice for a long time.” ●

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JERRY HOOD

CANADAEnergy close to 19% of Canada’s exports

Revenues from Canada’s energy exports rose 15 percent in 2005 to C$79.2 billion,despite slippage in volumes for crude oil, natural gas and refined petroleum products,the National Energy Board reported.

The latest figures from the Canadian government show a further surge in the firstquarter of this year as the value of shipments jumped another 28.5 percent over theopening three months of 2005 to C$22.5 billion.

For 2005, net energy export revenue wasC$46 billion compared with C$38.6 billion in2004.

Energy represented 19 percent of allCanadian exports of goods and services last year.

The industry accounted for close to 6 percentof Canada’s Gross Domestic Product and pro-vided direct employment for 330,000 or 1.9 per-cent of the labor force.

Domestic energy consumption upPetroleum at 36 percent and natural gas at 38

percent were the dominant forms of energy production last year, while coal account-ed for 8.3 percent, due largely to higher demand from China, and hydroelectricity for8 percent. Nuclear energy covered 5.7 percent of total Canadian energy output.

Preliminary estimates show domestic energy consumption was up 2.4 percent andaveraged a 2.3 percent annual gain over 2001-2005.

Alberta’s overall exports increased almost 33 percent year-over-year, the bulk ofthe gain coming from shipments to the United States that were valued at C$20.5 bil-lion, or 91.4 percent of the province’s total exports.

Shipments to most of the other top 10 destinations declined, including a 36 percentdrop in exports to China, 25.7 percent to South Korea and 2 percent to Japan.

—GARY PARK

The latest figures from theCanadian government showa further surge in the firstquarter of this year as thevalue of shipments jumpedanother 28.5 percent over

the opening three months of2005 to C$22.5 billion.

PETROLEUM NEWS • WEEK OF JUNE 4, 2006 11

● I N T E R N A T I O N A L

Orders for offshore drilling rigs climbE&P companies scrambling for dwindling supply of available rigs; 65-70 jack-ups, 25-30 deepwater rigs believed on order

By RAY TYSONFor Petroleum News

onstruction orders for new offshore drilling rigs arepouring into shipyards around the world as explo-ration and production companies scramble forwhat’s left of a rapidly dwindling supply of rigs.

Industry analysts believe there could be 65 to 70orders in for new jack-ups and around 25 to 30 orders fordeepwater rigs, but the actual new-build total is difficultto pin down and therefore largely a matter of specula-tion.

“Someone told me today that another deepwaterfloater was ordered. If that continues then at some pointwe’re going to overbuild this cycle,” Robert Long, chiefexecutive officer of big offshore drilling contractorTransocean, warned in a May 24 presentation to the UBSOil & Gas Conference in Austin, Texas.

In addition to known orders for new-builds, 35 to 40refurbished drilling rigs are expected to re-enter the mar-ket over the next few years. But right now the issue is rigavailability.

“The main thing is finding a rig,” Carl Thorne, chiefexecutive officer of another large drilling company,Ensco International, said at the UBS conference.

He added: “We can talk all we want about operatorpreference. But when you have a shortage of equipmentlike we have today, the overriding concern is to find a rigthat can drill within the timeframe of some of these peo-ple who need work done.”

There’s no question the world needs more offshoredrilling rigs, especially in places like the Gulf of Mexicowhere thousands of federal oil and gas leases are expect-ed to expire over the next few years without ever seeinga drill bit.

Fine balance between supply and demandHowever, there is a fine balance between supply and

demand when it comes to rig markets. For sure, thedrilling industry does not want to see a repeat of the1980s when soaring oil prices collapsed, leaving drillersholding the bag with too many rigs and too few cus-tomers. It took industry years to recover from that mis-calculation.

Once again, orders for new rigs are rapidly escalatingwith no sign the current drilling boom will end anytimesoon.

“We heard one of our competitors say recently thatwe are in the third inning of an extra inning game, with-out (mentioning) exactly how many extra innings therewere going to be. Clearly, there is a lot of forward visi-bility,” said Bruce Streeter, chief executive officer ofvessel supply company GulfMark Offshore.

“We think the long-term fundamentals of the industryare very good,” added Michael Dawson, chief financialofficer for offshore contract drilling companyGlobalSantaFe.

“We remain very bullish on the outlook going for-

ward,” echoed Transocean’s Long. “Right now we don’tsee anything that indicates this up cycle … is ready toturn around.”

Still, one of the most frequently asked questions putto industry leaders these days centers on how many addi-tional drilling rigs can safely enter the market withoutcausing rig day rates, the drilling industry’s lifeblood, tocollapse.

“If demand continues to be like it is today, I think thenew-build capacity is going to be absorbed,” Long said.“But the two big questions (are) will the demand contin-ue as it is today, and will industry stop adding newcapacity?”

Fifth-generation rates pushing half a millionFor the moment, exploration and development com-

panies appear willing to pay any amount of money tosecure a drilling rig in today’s tight market. For example,rates for high-specification, fifth-generation deepwaterrigs are pushing toward the $500,000 per day mark,twice what the going rate was a few years ago.

Transocean’s contracted rig backlog alone isapproaching a staggering $18 billion, causing manage-ment to rethink how it spends company money. For one,Transocean increased its share repurchase program to $4billion from $2 billion.

“We get a lot of questions about the use of our cash,”Long said. “With the backlog, we’re going to generatemuch more cash than we reasonably could expect toreinvest. Our interest here is to return excess cash to ourshareholders.”

Dawson said GlobalSantaFe’s ultra-deepwater fleet isbooked through mid-2008, with “a little more time avail-able in the mid-water depth category. This is a group ofrigs that are seeing some eye-popping day rates.”

GlobalSantaFe is another drilling company that

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Transocean’s contracted rig backlog alone is approaching astaggering $18 billion, causing management to rethink howit spends company money

see ORDERS page 13

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s part of its ongoing efforts todevelop the huge viscous oildeposits under Alaska’s NorthSlope, BP Exploration (Alaska) is

trying a novel technique that involvesextracting hot water from an undergroundrock formation and then injecting thatwater into the viscous oil reservoir.Samson Ning, a senior reservoir engineerworking on viscous oil development atMilne Point and adjunct professor at theUniversity of Alaska Fairbanks,described the technique at the joint meet-ing of the Cordilleran Section of theGeological Society of America, thePacific Section of the American Societyof Petroleum Geologists and the WesternRegion of the Society of PetroleumEngineers on May 10 in Anchorage,Alaska.

Ning talked about BP’s viscous oildevelopment in the OA and OB sands ofthe Schrader Bluff formation, above theMilne Point field, between the PrudhoeBay and Kuparuk River fields. BP is pro-ducing viscous oil from horizontal pro-duction wells, using waterflood from ver-tical injection wells.

The water for the waterflood comesfrom neighboring oil production facili-ties, where it is separated from oil and gascoming from producing oil wells. Thisproduced water contains impurities and iscold by the time that it is injected into theviscous oil reservoir.

Matrix bypassIn the interests of flushing as much oil

as possible from the Schrader Bluffsands, the injection pressure for thewaterflood needs to be as high as possible— the higher the pressure, the more oilflows towards the production well.

The problem is, however, that highwater pressures can cause a phenomenoncalled “matrix bypass,” in which theinjected water breaks through the rockmatrix to the production well bore.Instead of flushing oil from the reservoirrock, the water simply flows straight outthrough a production well.

And that’s a disaster when it comes to

maintaining oil production rates.“We have sudden water breakthrough

… the injection rate goes up instantly. …On the producer side, the oil productiongoes down, the water production goes up,the bottom hole pressure and temperatureincrease,” Ning said.

The whole process, from the increasein injection rates to the impact on the pro-duction well typically happens withinabout an hour, thus indicating a directfluid communication between the injec-tion and production wells, Ningexplained.

The phenomenon relates to fracturingof the reservoir rock when the injectionpressure exceeds the rock fracture pres-

sure, he said. But that’s not the entireexplanation.

“Our fracture model only goes a cou-ple of hundred feet at most, so it doesn’tgo all the way from the injector to theproducer, which is about 1,500 feet orso,” Ning said.

So something else must be happeningcloser to the production well. Reservoirengineers theorize that oil production intothe production well erodes “worm holes”in the reservoir sands. Then, when frac-tures propagating from the injector meetthe wormholes, injected water can flowdirectly to the production well bore.

The reservoir engineers have foundthat they can eliminate matrix bypass bychoking down the injector to reduce theinjection pressure. But that significantlyreduces oil production rates.

“We’ve had a 40 percent drop in pro-duction capacity,” Ning said.

And to make matters worse, thereduced pressure increases the gas to oilratio in the production well. Thisdegassing of the oil in the reservoirincreases the viscosity of the oil, thus

12 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

● N O R T H S L O P E

BP to try new waterflood for viscousDrawing hot, clean water from deep underground and injecting it into the viscous oil reservoir should increase production rates

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But it will take a long time for thehigher temperatures to permeate

the reservoir — reservoirmodeling indicates that it wouldtake about 20 years of injection

before most of the reservoirreaches the elevated temperatures.

see WATERFLOOD page 13

making the oil more difficult to extract.Reservoir models show that the viscosityof the oil in a pressure-supported reser-voir hardly changes over time, while theviscosity in an unsupported reservoiralmost doubles during the course of ayear’s production, Ning said.

SolutionsIt would be possible to increase pro-

duction without using high injection pres-sures by increasing the number of injec-tion wells. But that is an expensive solu-tion.

Instead, the BP viscous oil team haswhat it thinks is a much more cost-effec-tive solution — the injection of hot, cleanwater for the waterflood, instead of usingcold and relatively dirty produced water.And there’s a ready source of suitablewater in the Ivishak formation at a depthof about 9,000 feet under the Milne Pointfield. The Ivishak forms the main reser-voir for the nearby Prudhoe Bay field butonly contains water under Milne Point.

So in November BP drilled a waterwell into the Ivishak.

“We drilled a well which can produceabout 20,000 barrels (of water) per day,”Ning said. The water is at a temperatureof about 230 F at depth and about 210 Fwhen it reaches the surface, he said.

BP plans to inject this water into theSchrader Bluff reservoir from S pad atMilne Point. The water will cool to about150 to 160 F in the well bore. The oil inthe Schrader Bluff formation is normallyat a temperature of about 80 F and has aviscosity of 40 centipoise, Ning said. Thehot injected water should raise the oiltemperature in the neighborhood of theinjection well to about 135 F, thus reduc-ing the oil viscosity to about 10 cen-tipoise.

That reduction in viscosity will causethe oil to flow more easily. But it will takea long time for the higher temperatures topermeate the reservoir — reservoir mod-eling indicates that it would take about 20years of injection before most of thereservoir reaches the elevated tempera-tures.

Higher injection pressuresBecause of the very slow heating of the

reservoir, the economic benefit of reduc-ing the oil viscosity is likely to prove low.

But the technique of using hot watershould result in major benefits byenabling higher injection pressures to beused without causing matrix bypass. Infact, both the high temperature and thecleanliness of the water appear to enablethe reservoir rock to withstand higherinjection pressures. And those higherpressures will translate to higher oil pro-duction rates.

Rock mechanics calculations indicatethat the technique will increase the reser-voir’s fracture pressure from 2,500pounds per square inch to 2,900 poundsper square inch, although it may take up toa year of injection for that full increase tobe realized. The increase in fracture pres-sure should translate to an increase of 50percent in water injection rates and animprovement of 15 percent in oil recov-ery, Ning said.

The hot water will also prove moreeffective for waterflood than cold water.

“It also reduces the injection water vis-cosity … and gives you a higher injectionrate,” Ning said.

BP expects to start injecting the Ivishakwater into the Schrader Bluff formation atS pad in August. The project needs mini-mal surface infrastructure and does notrequire surface heating of the water. ●

PETROLEUM NEWS • WEEK OF JUNE 4, 2006 13

decided to use excess cash from oper-ations to repurchase $2 billion of itsstock. Dawson said the companywould not invest in “speculative”new-builds and that existing rigs aretoo expensive to purchase. He saidGlobalSantaFe also does not plan totake any of its rigs out of service for“marginal upgrades” because of highcosts. Moreover, he said the companyalready pays its shareholders a hand-some dividend.

“We really didn’t have investmentopportunities with the cash build ofthe magnitude that we were expect-ing,” Dawson said. “We landed onstock repurchases as a way to returncash to shareholders.”

Meanwhile, Ensco’s Thorne saidthat over the next year another eightto 10 shallow water jack-up rigscould depart the Gulf of Mexico forbetter drilling contracts abroad. “I’veheard estimates as high as 15 to 20,”he added. ●

continued from page 11

ORDERS

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14 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

Future of NikiskiLNG plant uncertainStone & Webster report says continued export of liquefied naturalgas after 2011 dependent on new gas supplies, plant renovation

By ALAN BAILEYPetroleum News

n a recent report commissioned by theAlaska Natural Gas DevelopmentAuthority, Stone & WebsterManagement Consultants has pre-

dictably concluded that the future of theLNG plant on Alaska’s Kenai Peninsulais uncertain.

The Nikiski plant, owned byMarathon and ConocoPhillips, beganexporting liquefiednatural gas in 1969when the Cook InletBasin enjoyed amajor surplus ofstranded natural gas.

But today, withSouthcentral gasproduction startingto drop below localdemand and a feder-al LNG exportlicense due forrenewal in 2009,people are speculat-ing on how long theplant can continuein operation.

The ANGDA-c o m m i s s i o n e dreport looks at somefuture options for the plant, showinghow the viability of each hinges onuncertain future economic factors andproviding perspectives on what mightdrive the ultimate decision on the plant’sfuture.

Harold Heinze, ANGDA chief execu-tive officer, told Petroleum News in lateMay that the intention of the report is toprovide some general information toAlaskans about future options for theplant, assuming that the federal exportlicense would be renewed. It also dis-cusses in less detail what might happenshould the license not be renewed (seesidebar).

And, although the plant has beenexporting LNG to Japan since 1969,Stone & Webster assume that will stopand instead uses LNG delivery to theU.S. West Coast as the basis for assess-ing the plant’s future viability.

Exporting to the West Coast wouldrequire a waiver to the federal Jones Actfor the LNG carriers that serve theNikiski plant (the Jones Act requiresU.S. flagged vessels be used betweenU.S. ports). However, Heinze said that,in the event of a waiver not being grant-ed, alternative export routes to westernCanada or Baja California involve simi-lar economics to U.S. West Coast deliv-ery. Or a cross-trade with Indonesia, inwhich LNG carriers transportingIndonesian LNG to the West Coastwould then deliver Alaska LNG to Japan,would also result in similar economics,he said.

The report says that a key factor in thefuture economics of the plant is agingequipment. In particular the GeneralElectric Frame 5 combustion gas tur-bines that drive the LNG compressorshave been in continuous service for 37years and “will require replacement inthe next five years,” the report says. Andsince the replacement of the turbines andthe associated upgrade of the facility islikely to be very expensive, the need toupgrade would likely trigger a shutdownof the facility in its current form, unlessadditional gas reserves become availableto justify investment in a new plant.

“These new reserves could be in theCook Inlet basin or provided via a spurpipeline constructed from the NorthSlope gas transmission pipeline,” thereport says.

However, the report focuses on theeconomics of obtaining continuing gassupplies using the gas spur line option.

Maintaining current capacityThe current LNG plant capacity of

220 million cubic feet of natural gas perday forms part of a Southcentral Alaskapeak daily gas demand that may run ashigh as 800 million cubic feet per day inthe winter, with an average demand ofabout 500 million cubic feet per day, thereport says. Those demand levels wouldsuggest the need for a spur line capacityof 1 billion cubic feet per day, “to ensureyear-round supply to domestic andindustrial users.”

● C O O K I N L E T

ConocoPhillips (70%) and Marathon (30%) own the Nikiski, Alaska, LNG plant. ConocoPhillipsis the plant operator; Marathon operates the LNG tankers.

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Harold Heinze,ANGDA CEO, hastold PetroleumNews that theintention of thereport is to providesome general infor-mation to the publicabout futureoptions for theplant, assuming thatthe federal exportlicense would berenewed.

see LNG PLANT page 15

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PETROLEUM NEWS • WEEK OF JUNE 4, 2006 15

Under that scenario Stone & Websterhas estimated the capital cost of doing alike-for-like replacement of equipment atthe LNG plant to be $300 million, withan annual operating cost of $60 million.Economic analysis indicates that, atthose costs, the plant would be viable ata price of $2.10 per thousand cubic feetfor liquefying gas in the plant, assuminga payout period of three years for theplant costs. Add in estimated pipelinetariffs for shipping gas from the NorthSlope and transportation costs for deliv-ering LNG to the U.S. West Coast, andyou arrive at a price uplift of $3.10 perthousand cubic feet over the base price ofNorth Slope natural gas.

Assuming a netback price of $2.50per thousand cubic feet for the NorthSlope natural gas and adding in down-stream gas processing and transportationcosts of 50 cents per thousand cubic feetresults in a West Coast delivered pricefor natural gas of $6.10 per thousandcubic feet. That compares favorably withrecent Henry Hub gas prices in theLower 48, thus suggesting that the LNGplant modernization would be viable.

Increasing the capacityBut it might also be possible to

upgrade the LNG plant using state-of-the-art equipment, to make maximumuse of the spur line capacity. A modernLNG train typically has a capacity of 3million tonnes per year, the report says.That capacity translates to a natural gasfeedstock requirement of 500 millioncubic feet per day.

Stone & Webster has estimated thecapital cost of this type of upgrade to be$1.5 billion, with annual operating costsof $120 million per year. Those costsbecome economic at an LNG liquefac-tion price of $3.91 or $2.65 per thousandcubic feet, depending on whether thepayout period for the plant costs contin-ues for three years or five years. Thoseliquefaction prices translate to deliveredgas prices of $7.91 and $6.65 on the U.S.West Coast. Although both of theseprices seem to compare favorably withcurrent Henry Hub prices, a cash flowanalysis of the LNG plant upgrade sug-gests that an acceptable rate of return onthe investment would require the longerpayout period and higher price.

Insufficient gas?But what if a spur line for delivering

North Slope gas is not built?That could result in the shutdown and

dismantling of the LNG plant, unlesssufficient new Cook Inlet gas reservesare found to render the plant viable.

However, the conversion of the plantto an LNG receiving and regasificationterminal could present another futureoption — the plant could convert import-ed LNG into natural gas to meet residen-tial and commercial needs inSouthcentral Alaska. Stone & Websterhas assessed this type of conversion to bea viable option, with a tolling rate of 45cents per thousand cubic feet of naturalgas converted from imported LNG (seethe sidebar). Assuming a price of $5 perthousand cubic feet for imported LNG,natural gas would leave the plant gates ata price of $5.45 per thousand cubic feet.

It might also be possible to use theplant as a “peak shaving facility,” inwhich LNG would be generated andstored during periods of low gas demand.The LNG would later be regasified tomeet peak demand. However, Stone &Webster thought this use of the plantunlikely, because the use of old gas fields

as gas storage facilities is likely to be amore economic supply balancing mecha-nism. Stone & Webster also said that thecurrent gas pipeline capacities aroundthe Cook Inlet assume the Beluga River

gas field on the west side of the inlet tobe a prime source of gas. Making Nikiskithe prime source of gas would probablyentail some reconfiguration of thepipeline systems, the report says.

The report also discusses the futurepossibility of converting the Nikiskiplant into a facility for fractionating andexporting LPG from North Slope feed-stock. The feedstock could come througha spur line or from LPG removal facili-ties on the North Slope gas transmissionpipeline at Fairbanks or Delta Junction.

Stone & Webster estimated a cost ofabout $200 million for this type of plantconversion at Nikiski, with the LPGbeing stored in the existing LNG tanks.The economics derived from this costlook unfavorable for selling propane intothe U.S. West Coast, especially as U.S.LPG prices are typically tied to naturalgas prices. However, with relatively lowNorth Slope gas prices “there may besufficient LPG price mark-up in theJapanese or other Far East markets tojustify such an investment,” the reportsays, adding that this type of marketanalysis is beyond the scope of thereport.

It all dependsSo what does all this mean in terms of

the future of the Nikiski plant?It all depends on whether a spur line

for delivering gas to Southcentral Alaskais built, how much additional gas isfound in the Cook Inlet area and whathappens to future natural gas prices. Andthe report also points out that the chang-ing gas industry in the Cook Inlet, cou-pled with changes in the function of theNikiski plant, could impact both theownership of the plant and the ownershipof the gas that the plant processes —these ownership changes would impactthe economics of the Nikiski plant.

“The natural economic life of theKenai LNG plant is nearing its end,” thereport concludes, saying that the plantcould continue to operate in its currentform through 2011 given sufficient addi-tional gas reserves and a renewed LNGexport license.

Operation beyond 2011 will requiresignificant investment in plant upgrade,requiring guaranteed gas supplies for atleast a 15-year period.

“As a minimum, major elements ofthe plant would be replaced on a like forlike basis,” the report says. “More likelythe plant would be upgraded and opti-mized, possibly increasing the capacityof the plant to 3 million metric tonnes peryear of LNG. In this instance, additionalinvestment would be required in theLNG carrier fleet too.” ●

continued from page 14

LNG PLANT

According to a recent report by Stone & Webster Management Consultants forthe Alaska Natural Gas Development Authority one future option for the NikiskiLNG plant is to convert the aging plant into a facility for importing liquefied nat-ural gas for use in Southcentral Alaska.

In fact, Enstar Natural Gas Co., the main gas utility in the region, is consider-ing the import of LNG as a future gas supply option, if Cook Inlet gas productionis unable to meet gas demand and a spur gas line from the North Slope is not con-structed (see “Enstar gives imported LNG another look” in the May 22 edition ofPetroleum News).

Also, Northern Dynasty Mines Inc., the would-be developer of the PebbleMine near Iliamna, has seen the import of LNG at Nikiski as a possible source ofnatural gas to generate electricity for the mine (see “Don’t call Alaska’s Pebbleproject isolated” in the March 26 edition of Mining News).

The ANGDA report on future options for the LNG plant, which is owned byConocoPhillips and Marathon, points out that the plant drives a significant com-ponent of current Southcentral natural gas demand — 214 million cubic feet perday, out of an annual average demand of 548 million cubic feet per day for theregion. So, conversion of the plant to an import facility would result in a drop intotal gas demand in the region.

And swings of about 2.7:1 between winter and summer residential and com-mercial natural gas demand complicate the economics of an LNG import facility.The ANGDA report suggests that the facility would need to be sized for a winterdemand of about 400 million cubic feet per day from residential and light com-mercial gas users.

The two relatively small LNG carriers that currently export LNG from Nikiskiwould probably prove adequate to transport imported LNG to the converted plant,the ANGDA report says. But the report comments that some additional spot car-gos might be needed to bolster supplies to meet peak winter demand — the addi-tional gas might be stockpiled in Cook Inlet gas storage facilities.

Although the basic infrastructure at Nikiski would work as an LNG receivingterminal some major modifications to the existing plant would also be necessary.Modifications would include the installation of several LNG vaporizers, eachrated at 150 million cubic feet or 125 million cubic feet per day. Other new equip-ment would include LNG transfer pumps, a metering station, piping and instru-mentation. The report says that total capital cost for the plant conversion wouldrun to about $62.5 million, with an operation and maintenance cost of $12 millionto $14 million per year.

At an average annual send-out rate of 200 million cubic feet of natural gas perday, the conversion project would appear to be viable at a tolling fee of 45 centsper thousand cubic fee of gas converted from LNG over a payout period for theplant costs of three years, the report says.

Assuming an import price of $5 per thousand cubic feet for imported LNG,natural gas would leave the plant gates at a price of $5.45 per thousand cubic feet.

Increasing the capacity of the converted Nikiski facility significantly above thecurrent natural gas Southcentral Alaska demand levels or to accommodate the useof modern, larger LNG carriers, would require additional LNG storage capabili-ties at the facility, the report says. That additional storage would probably addabout another $100 million to the capital cost of the facility conversion.

—ALAN BAILEY

Another option: Convert to an LNGimport facility

16 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

● A L B E R T A

Enbridge out tosatisfy oil sands thirstPlanned pipeline would bring 180,000 bpd of diluent from Midwestto Edmonton; 150,000 bpd line from Kitimat already planned

By GARY PARKFor Petroleum News

nbridge is ready to add a second legto its strategy of delivering conden-sate to Alberta’s oil sands.

It is seeking shipping commit-ments for a US$920 million, 180,000 bar-rel-per-day diluent pipeline from Chicagoto Edmonton to help meet a growinghunger for the thinning agent to improvethe flow of heavy oiland bitumen throughpipelines.

It is already plan-ning a 150,000 bpdline from Kitimat,British Columbia, toEdmonton, hopingto import diluentfrom the Pacificbasin.

With condensatesupplies growingscarce in Alberta andoil sands producerssuch as Imperial Oiland Husky Energyrethinking plans forupgraders in Albertathere is a pressingneed for condensate to support pipelineprojects from Alberta to U.S. refineries.

Enbridge Chief Executive Officer PatDaniel said the new Southern Lights pro-posal “will assist in ensuring adequatesupplies of reasonably priced diluent” tosupport oil sands expansion to 3.5 millionbpd by 2015 from 1 million bpd current-ly.

The pipeline has an in-service date of2009 provided shippers make formalcommitments during an open season thatends June 30.

Enbridge said that although access todiluent is shrinking in Alberta, the com-modity is relatively plentiful in the U.S.Midwest and the Pacific basin.

Diluent to be extracted However, the company also expects

Southern Lights will recycle diluentextracted from oil sands productionshipped to refineries in the Chicago areaon its parallel Southern Access pipelinethat will add 400,000 bpd to its existing

export capacity.Enbridge said Southern Lights will

involve construction of a 16-inch pipeover 674 miles from Chicago toClearbrook, Minn., changes to its operat-ing crude pipeline network and the rever-sal of its Line 13 from Clearbrook toEdmonton.

Other elements include a new 20-inchpipeline to carry 185,000 bpd of light sourcrude from Cromer, Manitoba, toClearbrook and an expansion of the exist-ing Line 2 to add another 45,000 bpd oflight crude capacity from Edmonton to theMidwest.

Overall, the Southern Lights proposalraises Enbridge’s oil sands-related invest-ments to about C$13 billion over the nextfive years as Canada’s leading oil shipperstrives to protect its dominant role.

Competition from othersOther major undertakings on the table

include the proposed C$4 billion, 400,000bpd Gateway pipeline from Edmonton toKitimat, where 75 percent is tentativelyearmarked for shipment to Asian marketsand 25 percent for California.

It is also moving ahead with plans for a400,000 bpd Alberta Clipper line fromSuperior, Wis., to Chicago, as it duels withrival TransCanada to put a lock on theexport market.

Enbridge’s proposed Gateway diluentpipeline faces competition from a partner-ship of Pembina Pipeline Income Fundand Kinder Morgan which is seeking con-tractual commitments for a 100,000 bpddiluent system from Kitimat to Edmontonto come on stream in 2008.

The relatively short open season beingconducted by Enbridge for SouthernLights is expected to demonstrate whichcompany has the edge in the diluent raceand whether there is room for all. ●

E

CANADA

Connacher untroubled by regulatory snagsOil sands junior Connacher Oil and Gas expects to remain on its fast-track

course to coming on stream and reaching targeted output of 10,000 barrels per dayin 2007, regardless of regulatory hitches.

Connacher Chief Executive Officer Dick Gusella said the company expectsinitial production within 330 days of starting construction and full output within90 days of oil flowing.

Those goals still hinge on approvals from the Alberta Energy and UtilitiesBoard, which is dealing with concerns raised by a natural gas producer in thevicinity of the Great Divide lease, which holds 90 million barrels of recoverablebitumen.

Connacher said there is no assurance that the issues will be resolved on an“expeditious basis,” although it believes the board is satisfied with all technicalmatters.

The company has already made bold strides in locking up a natural gas supplyto fuel Great Divide and acquiring a Montana refinery to process its bitumen.

Earlier this year it bought Holly Corp’s 8,300 bpd Great Falls, Mont., refineryand made a C$196.6 million takeover of Luke Energy to secure 15.7 million cubicfeet per day of gas production.

—GARY PARK

Enbridge CEO PatDaniel said the newSouthern Lights pro-posal “will assist inensuring adequatesupplies of reason-ably priced diluent”to support oil sandsexpansion to 3.5million bpd by 2015from 1 million bpdcurrently.

Enbridge said Southern Lights willinvolve construction of a 16-inchpipe over 674 miles from Chicagoto Clearbrook, Minn., changes to

its operating crude pipelinenetwork and the reversal of its

Line 13 from Clearbrook toEdmonton.

Alberta, British Columbia land still hotGovernment land sales in Alberta, despite an easing of the frantic rush to cor-

ner oil sands properties, and in British Columbia are easily outpacing last year.For the first five months of 2006, the Alberta government has collected C$1.86

billion from 4.3 million acres, compared with C$558 million for 2.78 millionacres, more than doubling per-acre prices.

British Columbia has racked up C$253 million for about 770,000 acres, morethan C$100 million and 235,000 acres ahead of a year earlier.

The latest Alberta auction, which fetched C$73 million for 343,000 acres,included a robust C$31.5 million for oil sands leases and C$3.27 million forrights in the Athabasca region.

But, by far the highest per acre bids occurred in the Bigstone area of the west-central Foothills play where C$8.47 million was paid for 15,656 acres, pushingthe total for the region this year to almost C$223 million.

The May sale in British Columbia attracted almost C$82 million in successfulbids for licenses covering 200,000 acres and C$22.4 million for leases totaling93,500 acres.

—GARY PARK

JUD

Y P

ATR

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PETROLEUM NEWS • WEEK OF JUNE 4, 2006 17

● J U N E A U , A L A S K A

Expert: Success in big projects upfrontAl Rogers with Independent Project Analysis gives legislators heads up based on company’s upstream project evaluation system

By KRISTEN NELSONPetroleum News

n Alaska natural gas pipeline project would be amega project, with a price tag estimated at $20 bil-lion to $25 billion.

Members of the Alaska Legislature got anoverview of the risks associated with such projects —and mitigation measures that can address some of thoserisks.

Al Rogers of Virginia-based Independent ProjectAnalysis told legislators May 19 at one of the adminis-tration’s gas pipeline fiscal contract overview sessionsthat IPA got its start as a result of the 1980s oil boom, thebig projects of that time and the track record of thoseprojects.

An abbreviated version of those projects, he said,goes something like this: “They ended up costing twiceas much as predicted. They took twice as long. And theyonly worked half as well as predicted.”

Rogers, who has a Ph.D. in geology and geophysicsand worked on operations and research assignments forExxon and a small independent, has for the last 10 yearsbeen with Independent Project Analysis, a company thatlooks at projects and analyzes the outcomes compared towhat was authorized. The company’s founder Ed Merrillworked at Rand Corp., and had the task under a U.S.government contract of identifying the drivers of thoseunsuccessful outcomes for 1980’s projects, Rogers said.

Merrill founded Independent Project Analysis, or IPA,and focused on statistical analysis of projects, both largeand small.

IPA, Rogers said, “is the only company in the world”with extensive databases comparing what was promisedwhen projects were authorized with the final outcomes.

Schedule acceleration guarantees difficulties“The primary thing you can do to guarantee difficulty

in a project of this magnitude is to try to accelerate theschedule,” Rogers said.

Mega projects, such as the proposed Alaska NorthSlope gas pipeline, aren’t like the broad range of some10,000 projects IPA has in its database, Rogers said.Other projects have an outcome distribution from goodto bad while mega projects have two outcomes: about aspredicted and disasters.

Front-end loading, all the activities that occur beforea project is authorized with a firm cost estimate, is some-thing IPA has historically been associated with, he said.In IPA’s experience people want to get on with megaprojects — selecting the route, cutting steel, welding —but successful mega projects involve what Rogers called“early-time preparatory activities.”

He said a mega project is one that meets one or morecriteria: the cost is greater than $1 billion; “it’s beingexecuted in a region where the project alone changes anenvironment” such as labor needs or infrastructure; or itrepresents a major step-out of complexity, size or loca-tion for the company.

Mega projects also attract a lot of attention, he said,both from formal stakeholders and from people who arenot formal stakeholders but believe they have a right tobe involved in the project.

Rogers said industry tends to have a narrow focus forprojects and from looking at very big and mega projectsit is necessary very early on to expand the scope of peo-ple who “legitimately or at least in their own mind mightbe stakeholders. Because the success for running fastafter authorization is to make certain that all of thoseearly-time potential stakeholders have either been satis-fied or you’re reconciled somehow you’re going to han-dle their objections.”

He said that in studying mega project failures, “thecommon thread was pushing past somebody whothought they had a legitimate right to be a stakeholder”because if they raise objections later, the risk of delay“goes significantly higher.”

High failure rateRogers said IPA evaluates a project in four ways:

compare it what IPA estimates industry would have spenton the project; how well did the project stay on schedule;how did it do against its own proposed budget; and onwhether it had “severe and continuing operational prob-lems” following completion. By these measures only 44percent of mega projects were successful, with 42 per-cent failing on one measure, 32 percent on two measures,21 percent on three and 5 percent failing on all fourmeasures.

Compared to other projects, mega projects “ratherthan being robust because of their size are inherentlyvery fragile,” Rogers said, can get off track very easily,and once they get off track “they’re almost impossible toget back. And so you lose control.”

Public information about Sakhalin provides an exam-ple, he said: they have had significant cost increases. Butmore important, he said, “the project team essentiallylost control of what was happening. They eventually hadproject manager changes. Things had changed so muchthat they no longer had a guide or blueprint by which togo forward in the execution of the project.”

That is why IPA focuses so much on front-end work,he said.

All projects need front-end work to define, plan andschedule, he said, “but particularly mega projects.”

“If that work is left undone or it is allowed to slip, thatturns out to be one of the primary attendant drivers ofmega project failure.”

AContractor availability anissue in mega projects

There has been a lot of consolidation amongcontractors and a lot have gone out of business,leaving some 10 major contractors with 75 percentof the upstream and downstream oil and gas work,Al Rogers of Independent Project Analysis toldAlaska legislators May 19 as part of a summary ofmega project requirements.

He said he believes there is less capability formajor projects now than in 1985, when the first oilbust occurred, “yet we’re trying to do more proj-ects.”

And those contractors are coming out of a timewhen they had to bid on contracts, even thoughreturns weren’t acceptable, because the alterna-tives were to bid and risk losing money on a con-tract or not to bid and have no work.

Rogers said IPA believes that has changed. In2002 and early 2003, under the old regime, teamswould build an estimate for a project and take it tomanagement, comfortable that there would be lit-tle difference between that estimate and bids fromcontractors.

But starting in 2004, he said, bids are departingfrom estimates, sometimes significantly.

In some places project teams are getting bidsbefore they go for project authorization to have abetter feel for the market.

The other problem is not getting enough bids:where a project used to get three to five bids, nowit might get one or two.

Rogers said Saudi Aramco is now paying con-tractors to develop the estimate to ensure that theyget enough bids — three are required by the Saudigovernment — because contractors now have asmuch work as they want.

He also said the quality of bids is declining. Therange between the low bid and the next highest bidhas “increased dramatically,” Rogers said. Arequirement to take the lowest bid wasn’t a prob-lem where the range between the bids was reason-able. But the range is now greater between the lowbid and most other bids, and “what we’re seeing isthe low bidder does not understand the job and theproject.” The low bidder will tend to have morecost increases because they didn’t understand theproject.

Who bears risk an issuePart of this is because the contractors are hav-

ing risks pushed on them and their profit marginhas been severely cut. Many major contractorshave told IPA they will no longer accept engineer-

see SUCCESS page 18see AVAILABILITY page 19

Compared to other projects, mega projects“rather than being robust because of their sizeare inherently very fragile,” can get off track

very easily, and once they get off track “they’realmost impossible to get back. And so you lose

control.” —Al Rogers, Independent Project Analysis

And how is success measured? Good mega projects come in plus or

minus 10 percent on cost and schedule, hesaid.

Front-end loadingRogers said as much as 5 percent of

the project’s cost may need to be spent onthe front-end. One project offshoreEastern Canada had a 100 percent costoverrun and was two years late. He saidthose in charge of the project said the up-front costs were too high, that manage-ment would never approve them, andwent ahead without any front-end defini-tion, just began executing the project.

Integrated teams are also important, hesaid, and while industry does that prettywell, with mega projects they only do ithalf as well.

Joint venture projects are more suc-cessful, Rogers said: “Our data show thathaving more joint venturers leads to bet-ter results at the end even though thepathway is rockier and more contentious.The thing that more partners do is theybring different points of view.”

He said anecdotal evidence suggeststhat joint ventures are problematic but thedata IPA has collected doesn’t supportthat. The data, he said, shows that megaprojects with fewer JV partners haveworse outcomes. That’s because the JVpartners will have different experiencesand different areas of expertise and willbring things to the team’s attention thatneed to be done early vs. late in theprocess.

“Projects that have a higher number ofowners, JV partners, develop better front-end loading. They do their homework to astatistically significant better level,” hesaid.

Asked about how successful the gaspipeline sponsors, BP, ConocoPhillipsand ExxonMobil, have been with megaprojects, Rogers said they all have donesuccessful mega projects. And all havedone unsuccessful mega projects.

“And I’ll say this pretty loudly: it’s notthe company, the company culture orpolicies and practices. It’s the team theyput together and the amount of front-endwork they do.”

Looking at the upstream industry ingeneral, he said, “There’s a wide variationin outcomes based on the quality andeffort of the team.”

Clear understanding of objectivesRogers said there are a number of

things to be considered when doing amega project.

All members of the project team musthave a clear understanding of the objec-tives when the project is authorized. IPAdata shows that in 20 percent of megaprojects that clear understanding is lack-ing. It’s easy to have multiple objectiveswhen things are going smoothly: “Thetough thing comes when you have a prob-lem and you have to decide,” decisionssuch as what’s more important — cost orschedule; cost or operability? It is onearea where having a joint venture maycause a problem, he said, because if theJV partners aren’t agreed on projectobjectives, then they have conflictingobjectives and the project team doesn’thave clear guidance.

In addition to a definition of the proj-ect, the team needs to be robust — not alot of holes in the organization chart andnot a lot of boxes filled by the same per-son; and full staffing needs to occur earlyon in the front-end process.

If a project team can’t meet objectivesthe reason is likely that owners didn’tgive them enough time, or enough money

or enough people. Rogers said that unsuccessful projects

are not the result of stupid people, or peo-ple who didn’t work hard. “What hap-pened is things occurred that distractedthe project management,” drew them offto fight fires. There have to be enoughpeople on staff that there is “the capabili-ty to fight fires as they occur to keep theproject on track.”

The people who are going to operatealso need to be involved early on so thattheir comments about what will work andwhat will make things reliable are heardearly on. “One of the major sources oflate changes in mega projects is bringingthe operations people in late” and beingtold then that something won’t work forsafety or reliability reasons.

As for the cost, Rogers said theamount of money saved by not doing itright upfront will be more than made upby cost overruns and late completion ifthe upfront work isn’t done. “That’s theentire thesis that the data says the late-time costs are significantly more than theearly-time investment in all of thesethings we’re touting,” he said.

And a crucial part of doing that upfrontwork is having the team in place: “Youcan’t get to good FEL (front-end loading)unless you start with an adequatelystaffed good team.”

Team needs enough authorityJoint venture partners will bring differ-

ent large-project processes to the table,Rogers said, and IPA’s data shows that it’simportant to pick one of the processes,not to try to create a hybrid from all of thesystems, because “nobody has experiencewith the hybrid system. Nobody knowshow to operate in it.”

An issue that will probably be difficultfor the state is giving the project teamenough decision-making authority, hesaid. Otherwise so much time is wastedtaking things to the governing committeefor approval that the project gets off track.

What IPA recommends, he said, is thatas long as a team is within an approvedbudget for each phase of the project theauthority should rest with the team. “Andif you’re not willing to give that teamthose authorities, then the question iswhether you really trust the people thatyou’ve detailed to do this job.”

What drives lack of trust, Rogers said,“is nonalignment on business issues,”nonalignment on objectives.

With a project process the team asksfor money to do things in “Gate 2” at theend of “Gate 1.” With a budget and aschedule the team has permission to dothose things.

While integrated teams and adequateauthority are important drivers of success,“the underlying driver is those character-istics are associated with better preparato-ry work — better front-end loading.That’s what the data says.”

What is front-end loading?Rogers said front-end loading, where

IPA puts its emphasis, is everythingbefore project authorization.

This includes appraisal: what are thedifferent ways things could be done? Itincludes selecting — making some finaldecisions about the scope of the project,such as the diameter of the pipeline, theroute, major equipment, degree of instru-mentation and degree of automation.Then the project is defined and engineer-ing is done to specify how the project willimplement the decisions.

That detail provides the informationfor a firm cost estimate, he said.

Rogers said he realized legislatorswere concerned because they didn’t knowhow much the project would cost andhow long it would take, and are worriedabout what could happen in the bad case.That, he said, is a function of how muchthe project team does before the projectgets final authorization.

How much is enough? Advanced engineering status before

final approval includes 18-30 percent ofdesign complete; extensive input intodesign from owner/operator; and final-ized process technology. About 55 per-cent of mega projects achieved advancedengineering status. The results: 3 percentcost deviation compared to 29 percent forother projects; 7 percent schedule slipcompared to 21 percent; 11 percent ofprojects had operating problems com-pared to 50 percent; and 70 percent proj-ect success compared to 20 percent.

SchedulingThe long lead times required for some

items is the biggest issue for project exe-cution planning and scheduling, Rogerssaid.

Labor is also important, he said, notingthat Alberta oil sands projects are running

18 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

continued from page 17

SUCCESS

see SUCCESS page 19

into a problem because labor is not asproductive as expected.

The temptation is to let the contractorworry about labor, but Rogers said unlessthe project team “has their own resourcelevel schedule (for labor), they reallydon’t know what is doable and what theimpact is going to be on the environmentof execution.”

The objection to doing resource load-ing is that it costs time, but he said theonly way a team can “evaluate whethercontractor bids are credible or not” is byhaving their own “independently devisedschedule and manpower loading.”

And resource loading isn’t just man-power, he said: “It’s vehicles to lay pipe.It’s a whole host of equipment — thingsthat may or may not be in short supply.”

Late changes — things not included inthe plan — can have a big cost on theproject, Rogers said. “If it’s late, it hascascading effects in terms of more costs... a stretched schedule as well as pooroperability,” he said. And late changeshappen to even the best defined projects:almost half of mega projects “have majorlate changes,” he said. But, he said, 100percent of projects with poor definitionhave late changes.

How much time does front-end load-ing take?

About half the time it takes to executea project, Rogers, said, two and a half tothree years of front-end loading for aproject that takes five to six years to exe-cute.

Aggressive schedule targets contributeto premature starts on detailed engineer-ing and fabrication: 73 percent of projectsdriven to fulfill a schedule were failures,he said.

And when do you know how long aproject will take, he asked. That is possi-ble only after you look at all of the com-ponents, all of the activities that it takes todo the project. “And the tendency foreverybody before they look at the inputsis to do what? Underestimate the time,”Rogers said.

While schedule-driven projects are

expensive, “they’re not significantlyfaster,” he said, because once you getbehind you spend more money trying tocatch up and costs balloon.

Based on some mega projects thathave “recaptured control” after bad thingshappened, “the best thing to do is to admitthat you may not make the schedule, re-baseline and calibrate,” and don’t spend alot of money trying to recapture the orig-inal schedule.

When should commitment be made?Rogers was asked when during front-

end loading the companies, and the Stateof Alaska, should commit to a project.

With three phases of FEL, he said,commitment would be at the end of FEL2. At this point the team knows what themajor scope decisions are, and the com-mitment can be made to approve the proj-ect if the team comes back at the end ofFEL 3 with an estimate within the rangeof what they had at the end of FEL 2. Alot of money will be spent in FEL 3,Rogers said, “and you really don’t wantto go forward and do that and at the endsay, whoops, I don’t like the answers.”

As to whether the participation of agovernment increases or decreases thechances of project success, Rogers said“it’s how well that government companyparticipated in team selection, businessobjectives and FEL.” He offered exam-ples that went both ways. “The participa-tion of a government in equity is not, inand of itself, a driver of success or failure.It’s how the government behaves andwhether they endorse or demand goodbehavior.”

Asked about work commitment lan-guage in the gas pipeline contract Rogerssaid he thinks “there’s more work com-mitment language than there is in most ofthe other ones that I’ve looked at. And somy opinion is that it’s a pretty good bal-ance.” Successful mega projects haveearly-time work, he said, and some of that“is characterized by the statements thatare made in the work commitments pack-age. In fact, it’s getting more than is in thework commitments package done that’sgoing to give you success, not just hew-ing to the letter,” he said. ●

PETROLEUM NEWS • WEEK OF JUNE 4, 2006 19

ing, procurement and constructionlump-sum contracts because of thesubstantial risks involved. Lump sumcontracts pay a larger penalty as theproject gets larger, entirely related torisk, and some companies have startedbreaking projects up into a number ofsmaller lump-sum contracts. The prob-lem with this is that the more contractsyou have, the more oversight issuesyou have.

Two kinds of risks have been trans-ferred to contractors with lump-sumcontractors: not enough people, thestaffing risk; and the economic risk ifthings go wrong. “Contractors havenot been able to charge a risk premi-um,” Rogers said. “Today they cancharge a risk premium.”

In addition to the differencebetween the lowest and other bids forlump-sum contracts, Rogers saidanother phenomenon on large projectsthat is becoming worrisome is the fre-quency of contractor claims forchanges made in the contract. Becausemega projects are complex and rela-tively unstable there are going to bechanges, he said, “which are opportu-nities for claims,” and the frequency of

those claims is up and the value of theclaims as a percentage of the contractsis up significantly.

The gas line project has a lot ofinherent risks, and by project defini-tion and upfront work the project own-ers can get a handle on those risks,Rogers said, but that doesn’t mean therisks can be eliminated. And once theowners have a handle on the risks, they“have to be able to assure the contrac-tors that most of the major risks aregoing to be handled by the owners.Because at the bottom line ... the riskscome back to the owners anyway.”

“If the owner assumes most of therisks going forward, the delta betweenthe bid and the owner’s estimate is notthat great. It’s acceptable,” Rogerssaid. The alternative, when most risksare passed on to the contractor, is thatthe contractor asks for a significantrisk premium.

Prices have increased some 50 to 70percent since 2004, he said, driven bya tight labor market; the escalation inmaterials’ prices, such as steel, but alsoa shortage of line pipe; and an increasein contractor profit margins, whichdropped to 5-6 percent in the 1990sand are now being pushed back up tothe 10-12 percent they were in the pre-1985 timeframe.

—KRISTEN NELSON

continued from page 18

SUCCESS

continued from page 17

AVAILABILITYALBERTANew group looks to ease sands tensions

The Alberta government has formed a multi-stakeholder committee to coordinatethe overall consultation process and gather public input related to oil sands projects.

Chaired by Mel Knight, a member of the provincial legislature, the Oil SandsConsultation Group will be a forum to deal with mounting concerns over the eco-nomic, environmental and social impact of the massive oil sands expansion.

It will cover the three primary oil sands, regions — Athabasca, Cold Lake and PaceRiver. The group wants to ensure that development takes place in harmony with otheractivities in those regions and looks for ways to improve existing policies and proce-dures.

Chris Severson-Baker, a director with the Pembina Institute for AppropriateDevelopment, the most frequent critic of oil sands policies in Alberta, said the groupis a vast improvement over earlier consultation processes that focused exclusively onmining ventures and ignored the fast-emerging in-situ projects to tackle productionfrom deep bitumen deposits.

He said his institute and other environmental organizations want to ensure there isa chance to discuss the overall purpose of developing oil sands, to maximize the ben-efits for all Albertans, to ensure energy security and to promote a transition to a moresustainable energy future.

—GARY PARK

20 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

material to Syncrude while Carteradmitted production losses in theinterim are about 80,000 barrels perday.

But the two executives are givingjust as much attention to the longer-term goals for the operation.

They said the Stage 3 expansionwill eventually increase output to350,000 bpd from 250,000 bpd anddebottlenecking will contribute anoth-er 30,000-50,000 bpd by 2012.

A Stage 4 expansion could pushthe world’s largest producer of syn-thetic crude to 500,000 bpd within adecade.

Taking its lumps is not new forSyncrude, which had the even greaterembarrassment of a major fire thenight before its gala launch in 1978.

Like everyone in the oil sandsbusiness it has hit plenty of potholesover the last 26 years with unsched-uled shutdowns and cost overruns inthe multi-billion-dollar range. It hasalso immeasurably advanced theexpertise and technology needed todevelop a 175 billion barrel resource.

Stage 3, part of a project calledUE 1, ended up costing more thandouble the initial estimate of C$4 bil-lion.

But its contribution during con-struction and beyond is good newsfor the consortium and governments.

During the construction peak thelabor force was 6,500; at 350,000 bpdthe value of daily production will beC$28 million; annual royalties start-ing this year will be C$660 million;UE 1 has tallied 43 million workforcehours.

Marcel Coutu, chief executiveofficer of Canadian Oil Sands Trust,the largest partner in Syncrude, saidthe consortium always anticipatedthat the massive Stage 3 expansion“might be a bumpy process” but that“does not detract from the long-termvalue” of the addition.

But he said the consortium isworking around the clock with tech-nology experts to find a solution that“alleviates the odor issues experi-enced by the local communities.”

—GARY PARK

continued from page 1

INSIDERing the act, is for state equity ownershipin the pipeline and payments in lieu oftaxes “that are roughly equivalent to thetaxes in effect for the 2005 tax period.”

The original intent of the act was toprovide fiscal certainty on gas taxes. “Thesponsor group made a compelling argu-ment that fiscal certainty must extend totaxes on oil as well as on gas,” the gover-nor said. The amendments in the bill pro-vide “express authority” for the terms ofthe proposed contract, broadening thescope of the act “to include fiscal termsrelating to oil as well as to gas.”

The bill also expands the subjects thatmay be negotiated to include equity own-ership, payment of obligations in gasrather than money “and changes in exist-ing leases and other agreements with thestate regarding oil and gas properties.”Under the bill contract terms would pre-vail over contrary provisions in state leas-es or unit agreements.

The bill will be heard by the HouseResources and Judiciary committees, andby the Senate Special Committee onNatural Gas Development.

Alaska Pipe would be public corporation

House and Senate bill 2002 wouldconfer original jurisdiction on the AlaskaSupreme Court to provide judicial reviewof a contract executed under the AlaskaStranded Gas Development Act, the gov-ernor said in his transmittal letter, requir-ing challenges to be mounted within 60days of the date the contract was execut-ed. The bills were referred to theJudiciary committees in both the Houseand the Senate.

House and Senate bill 2003 wouldestablish the Alaska Natural Gas Pipeline

Corp. to finance, own and manage thestate’s interest in the Alaska North Slopenatural gas pipeline project. Alaska Pipe,as the governor calls the corporation inhis transmittal letter, would be a publiccorporation of the state within theDepartment of Revenue.

Alaska Pipe’s board would includecommissioners of the departments ofRevenue and Transportation and PublicFacilities and five public members with“experience and recognized competencein either finance, investments, businessmanagement or the oil or gas industries,”the governor said. HB 2003 was referredto Judiciary and Finance; SB 2003 washeld pending formation of the SenateSpecial Committee on Natural GasDevelopment.

Alaska Pipe would be authorized toincorporate subsidiaries, probably for-profit corporations. The governor said itis likely that at least one Canadian corpo-ration would be established to holdAlaska Pipe’s interest in a Canadian lim-ited liability partnership that would buildand own the Canadian segment of the gaspipeline.

In addition to these bills, the specialsession of the Legislature is working onthe production profits tax. SB 2001passed the Senate May 23, just prior toadjournment for the Memorial Day week-end. House Finance was scheduled totake up the bill June 1.●

continued from page 1

BILLS

The bill also expands the subjectsthat may be negotiated to include

equity ownership, payment ofobligations in gas rather than

money “and changes in existingleases and other agreements with

the state regarding oil and gasproperties.” —Gov. Frank Murkowski

The original intent of the act wasto provide fiscal certainty on gas

taxes. “The sponsor group made acompelling argument that fiscal

certainty must extend to taxes onoil as well as on gas,” the

governor said.

PETROLEUM NEWS • WEEK OF JUNE 4, 2006 21

Companies involved in Alaska and northernCanada’s oil and gas industry

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AAce Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Acuren USA (formerly Canspec Group). . . . . . . . . . . . . . . . . . 4AeromedAES InspectionAES Lynx EnterprisesAgrium. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Air LiquideAir Logistics of Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Alaska Airlines CargoAlaska AnvilAlaska CoverallAlaska DreamsAlaska Frontier ConstructorsAlaska Interstate Construction. . . . . . . . . . . . . . . . . . . . . . . . 13Alaska Marine Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Alaska Railroad Corp.Alaska Rubber & SupplyAlaska Steel Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Alaska TelecomAlaska Tent & TarpAlaska Textiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Alaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Alliance, The . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Alpine-MeadowAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Arctic ControlsArctic FoundationsArctic Slope Telephone Assoc. Co-op.Arctic Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Arctic Wire Rope & SupplyASRC Energy Services

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N-PNabors Alaska DrillingNANA/Colt EngineeringNatco Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Nature Conservancy, TheNEI Fluid TechnologyNMS Employee LeasingNordic CalistaNorth Slope TelecomNorthern Air CargoNorthern Transportation Co. . . . . . . . . . . . . . . . . . . . . . . . . . . 9Northland Wood ProductsOffshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oilfield ImprovementsOilfield TransportPacific Power ProductsPDC Harris GroupPeak Oilfield Service Co.Penco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Perkins CoiePetroleum Equipment & ServicesPetrotechnical Resources of Alaska. . . . . . . . . . . . . . . . . . . . . 6PGS OnshorePipe Wranglers Canada. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5ProComm Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Prudhoe Bay Shop & StoragePTI Group

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Preston Miller, Mining Engineer

By PAULA EASLEY

Usibelli Coal Mine Inc.

Coal mined at Healy by Alaskansfor Alaskans is the basis for low-costpower that helps maintain the state’sgrowth. The team of workers atUsibelli is proud to do its part towardimproving the state and building itfor future generations.

Preston Miller earned his B.S. inmining engineering at UAF in 2005before joining Usibelli. As an intern,he participated in the Alaska SpaceGrant Program, the missile defenseproject at Fort Greely, the KennecottGreens Creek mining project, and theBlair Lakes military facility. Prestonand wife Sarah have a 3-year olddaughter, Devin. Many friends andpersonal heroes are professionalengineers, which Preston plans tobecome. His favorite quote: “If itcan’t be grown, it must be mined.”

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

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Eric Wieman, Project Engineer

Peak OilfieldService Co.

Peak Oilfield Service Co. operateson the North Slope, Kenai and Valdez,and has corporate offices inAnchorage. Peak provides cost-effec-tive construction, maintenance, indus-trial cleaning, power generation andtransportation services to supportAlaska resource development. Thecompany is also known for construct-ing and maintaining more ice roadsthan any other North Slope contactorand providing a complete range ofdrillsite services.

Lifelong Alaskan Eric Wiemanattended West High in Anchorage andgraduated from the University ofNevada in 2004 with a B.S. in civilengineering before joining Peak. Hisprior experience includes interningwith the State of Alaska DOTConstruction Division. This outdoorsysingle guy, who lives in Anchorage, isactive in many sports, from telemarkskiing and ultimate Frisbee to golfing.

estimated gas reserves of 110 trillion cubicfeet. Just prior to the latest announced delay,analysts had speculated Russia might post-pone the massive project due to the high costof Arctic development or due to politicalinfighting over Shtokman taxes. Anothertheory had Russia deliberately holding backdevelopment to drive up natural gas priceson the world market.

More political wrinklesThere are a few more political wrinkles

to this story: the allegation Russia is holdingShtokman hostage over the WTO issue andharsh remarks made in early May by U.S.Vice President Dick Cheney that Russia wasplaying energy politics with its neighbors.

Russia was widely criticized earlier this

year when it briefly halted gas exports toUkraine in a price dispute that disrupted sup-plies to Europe. Moscow also warnedEurope that Gazprom could divert suppliesto Asia if it was barred from the Europeanmarket.

Cheney’s remarks came at about thesame time Gazprom planned to announcethe Shtokman winner or winners and couldhave put U.S. contenders ConocoPhillipsand Chevron at a disadvantage, analystsspeculated. Cheney, speaking in theLithuanian capital Vilnius, called on Russiato return to the path of democratic reformand accused its leaders of using oil and gasas tools of “intimidation and blackmail”against other countries.

The Kremlin said May 18 that anyattempts to “discriminate” against Moscowin its negotiations to join the WTO wouldbring tougher terms for foreign companiesseeking access to Russian markets — a pol-icy some analysts think could affect U.S. oilcompanies hoping to develop the massive

Shtokman field. “In general, if you discriminate against us

in the World Trade Organization, you can’texpect us to welcome you with open arms,”Kremlin spokesman Dmitry Peskov said,according to Dow Jones Newswires.

However, Peskov denied that theKremlin was making a direct link betweenAmerican companies’potential participationin the multi-billion-dollar development ofthe Shtokman gas field and talks with theUnited States on Russia’s WTO entry. Thestatement was intended to reflect Kremlinpolicy “in general,” he insisted.

Relations have chilledNevertheless, there’s no question ties

between Moscow and Washington havechilled since the Sept. 11 attacks on theUnited States, amid differences over Iran,the war in Iraq and competition for allies inthe former Soviet Union.

Representatives for Statoil andConocoPhillips, in May 23 comments at theUBS Global Oil & Gas Conference inAustin, Texas, largely skirted U.S.-Russiadisagreements and focused on what theircompanies would bring to the Shtokman gasproject.

“We think we provide a lot of technicalexpertise both on the upstream and liquefac-tion side,” Jeff Lowe, vice president incharge of ConocoPhillips’ commercial divi-sion, said, noting that ConocoPhillipsalready holds a stake in Lukoil, Russia’slargest oil producer.

However, in addition to expertise,

Gazprom “has made it fairly clear” what itwants in the way of a U.S. partner, Lowesaid.

“They would really like to have access toU.S. markets as an outlet for the gas … andwe’re the number two gas marketer in NorthAmerica,” he added. “They are looking for away to participate in assets outside of Russiato give them an international presence. Andwe are prepared to do something with themon that. And they are also looking for value.”

Statoil may be best positionedNorway’s Statoil, with its huge Snohvit

gas development in the Norwegian sector ofthe Barents Sea, is perhaps the best posi-tioned of the five applicants to participate inRussia’s Shtokman project.

“Because of the proximity in Norwayand the rest of our operations in the area, wewould like to take a leading role in develop-ment,” Geir Bjonstad, Statoil’s vice presi-dent of investor relations, said at the UBSconference.

Bjonstad also made it clear that Statoil isin no rush to join the Shtokman project andits huge $20 billion price tag. And he saidStatoil has “substitute” plans in the event thecompany’s bid to join the Shtokman projectis turned down.

“I would say that Shtokman is not some-thing that we have to do, but it’s very inter-esting because of the size,” Bjonstad said.“There are other opportunities in Russia thatwe will be interested in (and) we’re lookingat other energy development opportunitiesaround the world.”●

does not reflect the value of those interests.Its board of directors has urged share-

holders to sit tight while it pursues a betterdeal with as many as four other suitors,described as “significant companies” withan understanding of the area.

Among those companies with varyinginterests in the Arctic discoveries are BP,ExxonMobil, Imperial Oil andConocoPhillips.

Poison pill swallowedTo ward off Petro-Canada for now,

Canada Southern swallowed a “poison pill”on March 25.

Under the terms of the shareholder rightsplan, existing investors will have the chanceto buy half shares at half the prevailing mar-ket value once any potential acquisitoraccumulates 20 percent of the outstandingshares.

Petro-Canada said May 30 it is pursuinglegal action to have the rights plan over-turned.

It’s a tussle without precedent in a regionthat attracted extensive exploration in the1960s and 1970s, fueled by billions of dol-

lars in federal government incentives forCanadian-controlled companies to probethe frontier in the interests of energy securi-ty.

During that time, Canada Southern gath-ered minority working interests in 39,000net acres in the Drake Point, Hecla andWhitefish areas; Petro-Canada, initially cre-ated as a state-owned company, arrived onthe scene later, inheriting interests fromanother northern explorer sired by the fed-eral government.

For all of its desire to expand those hold-ings, Petro-Canada views its offer ofUS$7.50 a share as fair, representing a pre-mium of better than 50 percent at the time itwas made, although Canada Southern hassince climbed almost 80 percent to passUS$8.60 as the market counts on a higherbid.

Canada Southern officials declined torespond in a May 25 conference call whenasked to put a price on their shares, althougha Petro-Canada circular said the target com-pany sought a “significantly higher” num-ber than the bid.

Petro-Canada said that amount is unreal-istic given the challenges of extracting gasfrom the Arctic and, in a May 30 statement,suggested Canada Southern may have over-stated its reserves.

McGinity: Arctic Islands coming to fore

Canada Southern Chairman RichardMcGinity said his company believes thePetro-Canada offer is “financially inade-quate and fails to recognize the economicand strategic value of the Arctic assets.”

“At a time when geopolitical instabilityin Nigeria, the Middle East, Russia andSouth America is threatening the supply ofoil and natural gas, the Arctic Islands arecoming to the fore as a significant, discov-ered and secure resource with the potentialfor ready access to key North Americanmarkets, including Petro-Canada’s pro-posed LNG plant at Gros Cacouna,Quebec,” he said in a statement.

“Strategically, what Petro-Canada’s hos-tile offer has done is to indicate that the timefor Arctic Islands natural gas developmentis approaching,” McGinity told a confer-

ence call. “How soon, I don’t know.”A series of independent studies conduct-

ed between 1975 and 2001 rated discoveredgas in the Arctic Islands at 19.8 trillioncubic feet, of which Canada Southern has acarried or working interest in 16 significantdiscovery licenses, which reflect an indus-try and National Energy Board belief thathydrocarbon accumulations are sufficient toachieve sustained production.

Canada Southern has interpreted thatinformation and what it knows of the dis-coveries into a net marketable gas resourceof about 927 billion cubic feet equivalent or68 times greater than the junior company’sdisclosed proved and probable reserves of13.7 bcf equivalent.

But current disclosure rules in Canadaand the United States prevent CanadaSouthern from claiming proved or probablereserves where there is no means of gettingthe gas to market.

However, McGinity said that “unless therocks have moved, we believe that whatwas there in 1985 is there today.”

Petro-Canada pitched LNG in ‘80sThe company is also certain that Arctic

gas development will be economicallyviable, given that 26 years ago Petro-Canada and others pitched the idea of anArctic pilot project to deliver gas by LNGtanker to southern markets — a prospectthat has since been endorsed by theCanadian Energy Research Institute, whichsuggested commercial development couldbe achieved through LNG or the emerginghopes for compressed natural gas shipmentsto terminals or northern pipelines.

Regardless of those prospects, McGinityconcedes production from the Arctic regionwould be unlikely to occur before 2015,about six years after the Gros Cacouna ter-minal is scheduled to come on stream.

Petro-Canada insists it has no intentionof developing Arctic gas because of a longlist of challenges — technology; fiscalregime; financial strength of potential part-ners; commodity prices and the lead time toinitial production — that stand in the way ofany assurance of the gas being brought onstream in a “reasonable timeframe.”

22 PETROLEUM NEWS • WEEK OF JUNE 4, 2006

continued from page 1

ASSETS

see ASSETS page 23

continued from page 1

BARENTSJust prior to the latest announced

delay, analysts had speculatedRussia might postpone the massive

project due to the high cost ofArctic development or due to

political infighting over Shtokmantaxes. Another theory had Russia

deliberately holding backdevelopment to drive up naturalgas prices on the world market.

PETROLEUM NEWS • WEEK OF JUNE 4, 2006 23

It said significant consolidation of theexisting diverse ownership in the variousdiscoveries is required before any operatingagreement can be negotiated allowingdevelopment plans to proceed.

In summary, Petro-Canada said there is“significant uncertainty” relating to thetechnical and economic development of the

resources.

Tensions go back three monthsThe tensions between the two compa-

nies date back three months when CanadaSouthern began a third-party evaluation ofits gas resource and Petro-Canada regis-tered its initial expression of interest.

The geological data needed to undertakethat assessment had its origins in the 1960swhen Canada Southern was one of the firstcompanies to gain exploration rights.

One of its partners then was PanarcticOils, a venture by the Canadian governmentand several companies, which was in theforefront of Arctic exploration and for sev-eral years made an annual tanker shipmentfrom Bent Horn to a Montreal refinery.

Panarctic was dissolved in 2000 and itsassets, along with the geological data andseismic surveys were bequeathed to Petro-Canada.

That accumulation is reportedly storedin 700 boxes and has been delivered to

Canada Southern over recent weeks, exceptfor the seismic information that Petro-Canada is converting to an electronic for-mat.

Canada Southern, which says it does nothave time to examine all of the data by June20, views the urgency in the Petro-Canadabid as suspicious, even though Petro-Canada has insisted it has “no immediateplans for any Arctic development.”

“They have more information than wedo about our assets,” McGinity said. ●

continued from page 22

ASSETS

24 PETROLEUM NEWS • WEEK OF JUNE 4, 2006