page

3Devon finds positives in $60MBeaufort Sea exploration well

Vol. 11, No. 20 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of May 14, 2006 • $1.50

● A L A S K A

● C A N A D A

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

● G U L F O F M E X I C O

3 Canada's Beaufort beckons: Majors bid C$52 million;

EnCana partnership gets license, Shell dips in

4 FERC chief concerned about gas line: Does not wantdelay; Myers says contract gives producers 45-year exclusive

5 Joey Hall says Alaska a surprise: Pioneer‚s Oooguruk man-ager learns lessons, brings deepwater experience to Arctic

Step forward if you have a story

This summer Petroleum News is publishing a history of Alaska's oiland gas industry for the Alaska Oil and Gas Association's 40th anniver-sary. The magazine, titled "Oil and Gas Chronicle: A Time ofDevelopment in Alaska" starts with the first commercial productionfrom the Cook Inlet Basin in 1957 and ends with the presentation of agas pipeline contract to the Alaska Legislature. If you have stories orphotos to share from these years, please contact Steve Sutherlin at907 345-2565 or email steves@ak.net. Your experience does not haveto be directly tied to the industry; we're also interested in peripheralimpacts to your personal life and/or career. For example, where wereyou when Prudhoe Bay was discovered? When the trans-Alaska oilpipeline was built? There will not be any ads in the magazine, but ifyou want to purchase commercial space, contact Amy Spittler (at 907770-3506 or email aspittler@PetroleumNews.com) for informationabout a full page company profile (space is limited).

MMS predicts robust sales Strong interest in expiring GOM deepwater leases; sales likely top $588M

By RAY TYSONFor Petroleum News

he U.S. Minerals ManagementService believes Gulf of Mexico oiland gas lease sales over the next fewyears likely will top the $588 million

it collected in last March’s highly suc-cessful Central Gulf Lease Sale 198.

The MMS projection is based on morethan 2,200 deepwater leases set to expirein 2006 and 2007 alone and then re-offered toindustry in 2007 and 2008 as so-called “newlyavailable leases.” These leases carry 10-year termlimits and were issued during the deepwater boomof the middle-to-late 1990s.

MMS gulf director Chris Oynes is convinced

that at least 90 percent of the leasesscheduled to expire will be returned tothe federal government without ever see-ing a drillbit. In fact, agency recordsshow that of the roughly 3,330 deepwaterleases issued from 1996 through 2000,less than 8 percent have been drilled andeven fewer produced.

No discovery, no extension“Leases issued … are now starting to

come due,” Oynes said May 3 during a mediabriefing at the Offshore Technology Conference inHouston, Texas. “If they (leaseholders) have notbrought them into production nor had a commer-

TCHRIS OYNES

see SALES page 16

Kyoto has Canada in knotsNew regime pulls back from Kyoto spending; confusion on made-in-Canada policy

By GARY PARKFor Petroleum News

ess than four months into its man-date, the new Canadian governmentappears to be on an environmentalcollision course of its own making.

Openly dubious about the KyotoProtocol, to which it is legally bound, theadministration of Prime Minister StephenHarper is sending out a series of mixedmessages.

In his first budget on May 2, Finance MinisterJim Flaherty studiously avoided a single referenceto “Kyoto,” while abandoning the previous Liberalregime’s C$4 billion plan to meet Kyoto targets.

Instead, it talked about a C$2 billion “made-in-Canada” solution to climate change, tossing C$370

million into subsidized transit passesover two years.

Meanwhile, Environment MinisterRona Ambrose has floated the idea thatCanada may join the United States,India, China, Australia, South Korea andJapan in the Asia-Pacific Partnership onClean Development and Climate — agroup that accounts for half of theworld’s greenhouse gas emissions.

The group, known as the AP6, hasbeen scorned by environmentalists because it pro-poses no penalties and only small financial com-mitments.

Ambrose has also met with President GeorgeW. Bush’s senior advisor on environmental issues,

Prime MinisterStephen Harper

L

see KNOTS page 18

Talisman reports on FEX’s NPR-Adrilling, plans for next winter

Talisman Energy CEO Jim Buckeemade one discovery as his company’ssubsidiary FEX drilled its first wildcatwell in the National Petroleum Reserve-Alaska over the winter.

“It’s damn cold up there,” he ruefullytold a conference call May 10 when ananalyst asked what lessons Talisman haslearned from the Aklaq 2 well.

It’s also surprisingly warm at times,commented Executive Vice President ofExploration John ’t Hart.

A combination of those two extremes forced FEX to sus-pend drilling on its NPR-A exploration well in February in

JIM BUCKEE

see TALISMAN page 16

Gas contract on deck900-page summer reading list released: contract, fiscal finding, documents

By KRISTEN NELSONPetroleum News

hen Gov. FrankMurkowski greetedAlaska legislators onthe first day of the

special session, May 10, hejokingly told them he wasgoing to read the 900-pluspages of gas fiscal contractdocuments, starting at page 1,which were released that day, along with a fiscalbest interest finding by the commissioner of theDepartment of Revenue and back-up documenta-

see CONTRACT page 18

WGov. FrankMurkowski

New oil tax does notmake deadline

A bill to rewrite Alaska’s production taxsystem ended at midnight May 9, victim of aperfect storm: the imminent release of the gasline fiscal contract; politics; the complexity ofissues involved; and the mandatory end of theregular session of the Alaska Legislature.

Committees in both House and Senate spentcountless hours taking testimony from theadministration, their own and the administra-tion’s consultants, the state’s oil and gas pro-

see OIL TAX page 19

JUD

Y P

ATR

ICK

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

2 PETROLEUM NEWS • WEEK OF MAY 14, 2006

NATURAL GAS

3 Beaufort beckons; majors bid C$52M

EnCana partnership acquires offshore explorationlicense adjacent to Richard ‚s Island wells; Shell Canada dips into offshore

7 Shell builds castles in the sands

Mega-major makes bid for junior BlackRock Venturesto expand interests in Alberta’s Peace River region

SAFETY & ENVIRONMENT

ALTERNATIVE ENERGY

ASSOCIATIONSPIPELINES & DOWNSTREAM

LAND & LEASINGON THE COVERGas contract on deck

900-page summer reading list released:contract, fiscal finding, documents

MMS predicts robust sales

Strong interest in expiring GOM deepwaterleases; sales likely top $588M

Kyoto has Canada in knots

New regime pulls back from Kyoto spending;confusion on made-in-Canada policy

New oil tax does not make deadline

Talisman reports on FEX’s NPR-A drilling, plans for next winter

13 Group changes name to Cook Inletkeeper

14 Authority to participate in open season

GOVERNMENT4 AOGCC, NPR-A grant bills both pass

8 Oil sands and water — a bad mixture

13 DGGS releases Alaska Highway data

6 Stevens backs Kennedy on wind farm amendment

4 FERC chief: Alaska Legislature could delay gas pipeline

13 Hawaii governor signs legislation ending wholesale gasoline cap

6 BP shutting down two North Slope pipelines; might need to be replaced

5 1st Nations toss legal wrench at Gateway

12 Commission questions Enstar increase

18 Shell Canada leader touts emissions trading

8 Enbridge expanding crude oil terminals

EXPLORATION & PRODUCTION

5 Alaska a surprise, says Joey Hall

8 Technology keeps hope alive in Western Canada Sedimentary Basin

3 Devon finds positives in Beaufort well

FINANCE & ECONOMY

16 Oil company earnings chart

9 ISER forecasts two more years of growth for Alaska

15 EIA expects $68 oil this year, next

15 Pombo: Tax Big Oil by drilling in ANWR

14 200 turn out for Anchorage rally

Speakers want oil tax changes to wait until gas dealrevealed; rally draws former governor, several gubernatorial candidates

10 BP: Learning from oil spill lessons

Johnson, Beaudo explain what they think happened in Prudhoe Bay’s largest spill and what the company is learning from the incident

By GARY PARKFor Petroleum News

egardless of uncertainties surround-ing the Mackenzie Gas Project, whichholds the key to getting any gas out ofthe Mackenzie Delta-Beaufort Sea,

Canada’s northern exploration prospects areattracting strong interest.

In the latest rights sale, a partnership ofEnCana, Anadarko Canada andConocoPhillips Canada made a successfulbid of C$40.27 million for 140,000 acres onthe Mackenzie Delta and Shell Canada tookits first step into the Canadian Arctic off-shore, bidding C$11.55 million for 247,000acres in the Beaufort Sea, 120 miles north-west of Inuvik, Northwest Territories.

The auction was the first in two years bythe federal Department of Indian andNorthern Affairs.

In also going offshore, the trio of EnCana37.5 percent, Anadarko 37.5 percent andConocoPhillips 25 percent has signaledeven greater optimism in its adjacentRichard’s Island lease where two successfulwells were drilled in 2004 and 2005.

The Umiak N-16 exploration well and N-5 delineation well are now before theNational Energy Board for significant dis-covery licenses that allow the owners toextend the license term based on flow testingthat indicates a hydrocarbon accumulationand the potential for sustained production.

In applying for the licenses, EnCana saidthe wells produced “encouraging results.”

For now, however, EnCana is trying todecide if and when it might drill on the newproperty.

Shell: acquisition part of strategyShell said its acquisition is part of a strat-

egy to bulk up Arctic land holdings and isseparate from its wholly owned Niglintgakdiscovery, one of three anchor fields under-pinning the Mackenzie project. Niglintgakholds an estimated 1 trillion cubic feet of the5.8 tcf of proven gas reserves of those threefinds.

The company was not responsible forposting the Beaufort parcel and has said itswork commitment will probably involveonly seismic studies initially to evaluate thepotential, rather than drilling.

But Shell’s entry to the offshore and theEnCana partnership’s decision to stretch itshorizon are a positive note at a time whenMackenzie lead partner Imperial Oil haswarned that rising construction and laborcosts are pushing the C$7.5 billion venturecloser to a breaking point.

Companies pressing NEBAdding to concerns, EnCana and

Anadarko are two of the six companies inthe Mackenzie Explorer Group that is press-ing the National Energy Board to bring boththe Mackenzie gathering system and main-line under its regulatory control, a moveopposed by Imperial.

Failure to establish a single jurisdictioncould slow the development of gas prospectsoutside the Delta anchor fields.

Another test of the northern mood fol-lows the closure this month of a call for bidscovering six parcels in the centralMackenzie Valley.

In the meantime, International FrontierResources has bulked up its working interestin the same region, moving to 16.11 percentfrom 10.867 percent on six freehold acreageparcels — four covering 47,570 acres in theSummit Creek area where it is involved inan exploration program with Husky Energyand two of 21,100 acres in the southernColville Hills.

International Frontier has working inter-ests ranging from 3.1 percent to 10.875 per-cent in the early 2004 B-44 oil discovery byNorthrock Resources. ●

PETROLEUM NEWS • WEEK OF MAY 14, 2006 3

● C A N A D A

Beaufort beckons; majors bid C$52 millionEnCana partnership acquires offshore exploration license adjacent to Richard’s Island wells; Shell Canada dips into offshore

Devon finds positives in Beaufort wellThe first exploration well in the Canadian Beaufort Sea in 17 years fell short of

the multiple trillions of cubic feet Devon Canada was hoping for, but the companydoes not view the C$60 million well as a big disappointment, Vice President MichelScott said.

“We did encounter hydrocarbons and that is what we were after,” he toldPetroleum News.

The disappointment was in failing to uncork a grand prize. The exploration portfolio of the parent company, Devon Energy, spans from lower

to higher risk prospects, of which Paktoa was “in the high-riskcategory as far as reaching resource levels that would give uscommercial momentum,” Scott said.

Although results of the well are still being evaluated, thecompany has already decided to file an application with theNational Energy Board for a Significant Discovery License,which conveys the company’s belief, based on flow testing andgeological and engineering factors, that there is a hydrocarbonaccumulation and the potential for sustained production.

Devon Energy President John Richels told a conference callthat a Significant Discovery License would allow the companyto retain the mineral rights “in perpetuity.”

Scott said Paktoa C-60 was a successful operation, being drilled on time and onbudget.

He also said the steel drilling caisson, which was used in 2003 by EnCana to drillthe McCovey prospect north of Prudhoe Bay, “performed to our expectations.”

But this point, Devon does not have the SDC under contract from its Norwegianowner for any future drilling operation.

Under the terms of its C$225 million exploration commitment for explorationlicenses covering 846,000 acres in the Beaufort, Devon is required to drill four wellsby August 2009 to extend the terms of the permits.

For now, Scott said the company is “evaluating our alternatives and we have notmade final decisions.”

A number of factors weigh in that decision, including a decision to proceed withthe Mackenzie gas pipeline, along with the forecast economics of the gas industry.

—GARY PARK

R

JOHN RICHELS

Shell said its acquisition is part of astrategy to bulk up Arctic land

holdings and is separate from itswholly owned Niglintgak discovery,

one of three anchor fieldsunderpinning the Mackenzie project.

PETROLEUM NEWShe Alaska natural gas pipeline wouldbe delayed by many years if theAlaska Legislature rejects the pro-posed project, according to the

nation’s top energy regulator.Federal Energy Regulatory

Commission Chairman Joseph Kellihertold a natural gas industry conference inDenver May 4 that the stakes were high forthe proposed pipeline. “I hope theyapprove this important policy to go for-ward,” Kelliher said, referring at the time tothe proposed revision of Alaska’s produc-tion tax regime, which the big three NorthSlope producers and Alaska’s Gov. FrankMurkowski wanted passed before their gasline contract was released. (See update onthis situation on page 1 of this issue.)

If Alaska’s lawmakers reject thepipeline agreement currently being consid-ered, negotiations will have to start all overagain and that will take years, FERCspokesman Bryan Lee said May 9 after thegovernor announced he would release thegas line contract May 10 even though thelegislature had not yet passed the produc-tion profits tax proposed by his administra-tion and the producers.

“Notice, I said ‘reject,’ not modify,” Leesaid. “To the extent that this agreement was

put together fromscratch, it will haveto be done all overagain and that willtake years.”

But former AlaskaDivision of Oil andGas Director MarkMyers said onceFERC “has had timeto review the (gasline) contract theywill become veryconcerned about it.”

Myers was one of six top officials in theAlaska Department of Natural Resourceswho resigned last October in protest ofMurkowski’s termination of DNRCommissioner Tom Irwin. All seven offi-cials said the governor was giving up toomany financial concessions to the NorthSlope oil producers and gas owners (BP,ConocoPhillps and ExxonMobil) in negoti-ating a natural gas pipeline contract.

Myers told Petroleum News May 11that he hopes Kelliher and his staff will“receive a complete briefing from the LBA(Legislative Budget and Audit Committee)consultants on the contract as soon as pos-sible.”

The chairman’s comments “are perfect-ly understandable given that like Alaskansthe federal government wants to seeAlaska’s gas get to market quickly and hehasn’t yet seen the contract. However, aftera complete review of the contract, it willbecome apparent that the contract providesthe producers the exclusive 45-year right tobuild the project but doesn’t require themto do the project or even spend significantmoney toward advancing the project,”

Myers said.“The contract also fails to support or

enhance the FERC’s ability to compelexpansion of the pipeline to take explorer’sgas or to require a high debt to equityfinancing structure which will lead to lowertariffs,” he said.

Focus on new gas supply promptedFERC chairman’s remarks

Lee said Kelliher is focused on findingnew avenues of gas supply for the country.

“Given where natural gas prices aretoday, it’s important that we explore allavenues of supply,” he said. “The more gassupplies we have, the less upward pressurewill be on gas prices.”

FERC is reviewing proposals to buildliquefied natural gas terminals around thecountry to create more sources of gas sup-plies and the 4.5 billion cubic feet per dayof natural gas that the Alaska pipeline proj-ect is expected to deliver to the country is akey piece of the nation’s future gas supplypuzzle, Lee added.

The commission has approved eightLNG projects plus expansions of someexisting terminals. And if the further 19LNG projects pending were built, theU.S. could increase its gas supply by 26billion cubic feet per day, according toKelliher. ●

4 PETROLEUM NEWS • WEEK OF MAY 14, 2006

Dan Wilcox CHIEF EXECUTIVE OFFICER

Mary Lasley CHIEF FINANCIAL OFFICER

Kay Cashman PUBLISHER & EXECUTIVE EDITOR

Kristen Nelson EDITOR-IN-CHIEF

Susan Crane ADVERTISING DIRECTOR

Amy Spittler SPECIAL PUBLICATIONS EDITOR

Tim Kikta COPY EDITOR

Gary Park CONTRIBUTING WRITER (CANADA)

Ray Tyson CONTRIBUTING WRITER

Alan Bailey STAFF WRITER

John Lasley STAFF WRITER

Allen Baker CONTRIBUTING WRITER

Rose Ragsdale CONTRIBUTING WRITER

Sarah Hurst CONTRIBUTING WRITER

Paula Easley DIRECTORY PROFILES/SPOTLIGHTS

Steven Merritt PRODUCTION DIRECTOR

Judy Patrick Photography CONTRACT PHOTOGRAPHER

Mapmakers Alaska CARTOGRAPHY

Forrest Crane CONTRACT PHOTOGRAPHER

Tom Kearney ADVERTISING DESIGN MANAGER

Heather Yates ADMINISTRATIVE ASSISTANT

Toby Arian CIRCULATION SALES MANAGER

Dee Cashman CIRCULATION REPRESENTATIVE

Flo Wright CIRCULATION REPRESENTATIVE

Petroleum News and its supplement,Petroleum Directory, are owned by

Petroleum Newspapers of Alaska LLC.The newspaper is published weekly.

Several of the individuals listed abovework for independent companies that

contract services to PetroleumNewspapers of Alaska LLC or are

freelance writers.

ADDRESSP.O. Box 231651Anchorage, AK 99523-1651

EDITORIAL Anchorage907.522.9469

Editorial EmailAnchoragepublisher@petroleumnews.comCanadafarnorth@petroleumnews.com

BOOKKEEPING & CIRCULATION 907.522.9469 Circulation Emailcirculation@petroleumnews.com

ADVERTISING 907.770.5592Advertising Emailscrane@petroleumnews.com

CLASSIFIEDS907.644.4444

FAX FOR ALL DEPARTMENTS907.522.9583

Petroleum News (ISSN 1544-3612) • Vol. 11, No. 20 • Week of May 14, 2006Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518

(Please mail ALL correspondence to:P.O. Box 231651, Anchorage, AK 99523-1651)

Subscription prices in U.S. — $78.00 for 1 year, $144.00 for 2 years, $209.00 for 3 years.Canada / Mexico — $165.95 for 1 year, $323.95 for 2 years, $465.95 for 3 years.

Overseas (sent air mail) — $200.00 for 1 year, $380.00 for 2 years, $545.95 for 3 years.“Periodicals postage paid at Anchorage, AK 99502-9986.”

POSTMASTER: Send address changes to Petroleum News, P.O. Box 231651 • Anchorage, AK 99523-1651.

www.PetroleumNews.com

JUNEAUAOGCC, NPR-A grant bills both pass

A bill Petroleum News described in the May 7 issue as stuck in committeeearly in May was actually moving.

House Bill 300, introduced by Rep. Vic Kohring, R-Wasilla, in 2005 specify-ing qualifications for the public member of the Alaska Oil and Gas ConservationCommission, moved out of Senate State Affairs, had a reference to SenateResources waived, and passed the Senate May 9.

The bill originally had specific requirements for a legal or business manage-ment background for the public seat. It was amended to require “training or expe-rience that gives the person a fundamental understanding of the oil and gas indus-try in the state.”

The Senate bill on use of federal grants for National Petroleum Reserve-Alaskaimpacts, Senate Bill 171, as amended in the House, also passed the Senate May9. This bill, introduced last year by Sen. Gary Wilken, R-Fairbanks, was signifi-cantly amended in the House (see story in May 7 issue of Petroleum News),removing a legislative committee to determine grants. The bill requires that 25percent of the gross of the grants goes to the Permanent Fund.

Sen. Donny Olson, D-Nome, said on the Senate floor that a compromise hadbeen reached, and recommended passage of the House substitute.

—KRISTEN NELSON

Subscribe to Petroleum NewsCall 907.522.9469

● A L A S K A

FERC chief: Alaska Legislaturecould delay natural gas pipelineMark Myers says FERC needs briefing because contract negotiated by governor gives NorthSlope producers 45-year exclusive to build gas line, but does not require them to build it

T

Mark Myers, formerdirector, State ofAlaska’s Division ofOil and Gas

Federal Energy RegulatoryCommission Chairman Joseph

Kelliher told a natural gasindustry conference in Denver

May 4 that the stakes were highfor the proposed pipeline.

FOR

RES

T C

RA

NE

By RAY TYSONFor Petroleum News

oey Hall assumed managing PioneerNatural Resources’ $500 millionOooguruk project offshore Alaska’sNorth Slope would be a walk in the

park compared to the challenges he facedworking on Pioneer’s deepwater programin the Gulf of Mexico.

“I thought I’d go up to Alaska andcatch a few fish, kick my feet back andhave a nice easy project,” Hall recalled.“Well, I’ve learned a new lesson. The off-shore Arctic is equally and even morechallenging in many ways than deepwa-ter.”

However, Hall discovered that “manyof the things we learned in deepwaterwe’re now applying in the offshoreArctic. I think in the years to come you’regoing to be hearing a lot more about thethings … going on in the offshoreArctic.”

As Hall and Intec Engineering repre-sentatives John Stearns and Glenn Lananpointed out during a panel discussionMay 2 at the Offshore TechnologyConference in Houston, Texas, one hugelesson learned from the deepwater is thetricky business of constructing andinstalling sub-sea pipelines in a safe andreliable manner.

Pioneer’s Oooguruk oil pipeline isbeing designed by Intec and will be thesecond export pipeline ever installed off-shore Arctic. The first was installed aspart of BP’s Northstar oil project east ofOooguruk and north of Prudhoe Bay.Like the Northstar line, Oooguruk’s willbe buried in a trench to protect against seaice.

“Important to the pipeline design is theaffect on sub-sea soil,” said John Stearns,vice-president of Intec’s Marine PipelineSystems division.

Oooguruk’s “three-phase pipe bundlesystem,” stretching 5.7 miles from shoreto a six-acre man-made gravel island sup-porting a drilling rig, 40 to 60 productionand injection wells and related facilities,“is really the most challenging part of thisproject,” Pioneer’s Hall said. “This is thething that keeps me up at night.”

The Oooguruk line is actually twopipelines in one, with the main oil linewrapped in a protective outer shell thatwould contain any leaks from the primaryline. The entire line will then be wrappedin insulation to keep heat from the oilfrom melting the surrounding permafrost.

In deepwater, this pipeline system istraditionally used for its insulating value,but for the shallow water Ooogurukpipeline the mission is actually two-fold.

“First and most important is leakdetection,” Hall said. “The Arctic is avery pristine environment and we have toat all costs protect the environment. Theother thing it does is that if we did have aleak in the inner pipe, it provides contain-ment. Cleaning up a spill in the Arctic isextremely challenging.”

The pipeline bundle also includes sep-arate lines for water and gas injection,plus a diesel line to support drilling oper-ations on the island, which rests in just4.5 feet of water. The entire package will

be buried in a six-foot trench.“Because it is shallow water and every

winter the ice freezes to the bottom, if thepipeline puts out too much heat it canactually melt some of the ice on the top,”Intec’s Stearns said. “While this may notin itself hurt the pipeline, it is disruptiveto the environment and can cause weakspots in the ice.”

Island completed in April The six-acre island was completed in

late April, requiring three months and22,000 dump truck loads of gravel to fin-ish the job. Winter ice roads were used tohaul the gravel to the site.

“Building the island was quite a feat initself,” Hall said, noting that the islandrises 23 feet from the ocean floor and wasdesigned to withstand impacts from shift-ing ice.

Hall said the gravel island is expectedto “subside” or settle about four feet, aprocess he said would normally takeabout two and a half years. To speed upthe process, 3,000 holes were drilled onthe island to a depth of around 50 feet,allowing the underlying sand to bemanipulated by forcing water downhole,rather than off to the sides if allowed tosettle naturally. “We hope to acceleratethe subsiding to about nine months,” hesaid.

Oooguruk is expected to come on-stream in late 2007 or early 2008, pump-ing at peak rates of 15,000 to 20,000 bar-rels of oil per day. From a shore base, theoil will be transported via an over landpipeline 2.4 miles for processing at theConocoPhillips-operated Kuparuk pro-duction facility.

Nabors’ 19-E will be modifiedNabors’ 19-E drilling rig, located on

the North Slope, will undergo “significantmodifications” this summer and then bemoved to the island next winter, Hall

PETROLEUM NEWS • WEEK OF MAY 14, 2006 5

● H O U S T O N , T E X A S

Alaska a surprise,says Joey HallPioneer’s Oooguruk project manager learns ‘new lesson’ inAlaska, brings valuable deepwater experience to offshore Arctic

CANADA1st Nations toss legal wrench at Gateway

Aboriginal opposition is mounting against a proposed Enbridge oil sands pipelinefrom Edmonton and a deepwater port at Kitimat on the northern British Columbiacoast, but the company is confident the challenge will not derail efforts to open up newmarkets in Asia and California.

The Carrier Sekani Tribal Council, representing seven First Nations whose landcovers about one-third of the planned 720-mile route, alleges it has not been properlyconsulted and is threatening legal action before the Federal Court of Canada.

The tribal council has been pressing for greater involvement in a joint reviewprocess being conducted by Canada’s National Energy Board.

The NEB has argued that there will be “ample opportunity” for any affected partyto register its concerns before the joint review panel.

The Council of the Haida Nation, representing the Queen Charlotte Islands off theB.C. coast, has also told the NEB that the pipeline should not be approved before theimpact of oil tanker traffic in its region is fully examined.

Enbridge Chief Executive Officer Pat Daniel said the dispute is a matter for theCanadian government not Enbridge to handle.

“We don’t expect any delays associated with it,” he said. “Our discussions (withthe Carrier Sekani) have been very favorable.”

Although fully anticipating challenges, Daniel said he is confident they will besolved “in a timely way.” The clock is running on Enbridge’s hopes of filing a regu-latory application by mid-2006. The initial plans call for a C$4 billion pipeline to carry400,000 barrels per day (with PetroChina viewed as a potential candidate for 200,000bpd, 100,000 bpd going to other Asian markets and 100,000 bpd to California).

An open season that ended in December surpassed the 400,000 bpd threshold,prompting Enbridge to increase the planned diameter to 36 inches from 30 inches andcontemplate additional pumping stations that could eventually raise Gateway’s capac-ity to 800,000-1 million bpd.

The company also plans a parallel pipeline to import condensate to dilute oil sandsbitumen. A non-binding open season has pointed to a possible demand for a 200,000bpd system.

—GARY PARK

J

see SURPRISE page 6

Pioneer’s Oooguruk oil pipeline isbeing designed by Intec and will

be the second export pipeline everinstalled offshore Arctic. The first

was installed as part of BP’sNorthstar oil project east of

Oooguruk and north of PrudhoeBay. Like the Northstar line,

Oooguruk’s will be buried in atrench to protect against sea ice.

6 PETROLEUM NEWS • WEEK OF MAY 14, 2006

said, adding that 19-E will remain on theisland during Oooguruk’s entire “three-year drilling cycle.”

Hall said the project is on schedule butcautioned that “like everywhere else,we’re dealing with manpower issues upon the North Slope. The workforce isaging and there aren’t any younger peopletaking their place.”

Although 25 percent of the world’sundiscovered reserves are thought to be inthe Arctic, capturing them offshore willbe expensive, requiring various technolo-gies to fit the vast array of Arctic condi-tions around the globe, noted Lanan,Intec’s pipeline engineering disciplinemanager.

Lanan said hydrocarbon targets abovethe Arctic Circle, such as the Barents Seaoffshore Norway and Russia, are free of

ice year round. In contrast, the high Arcticregion near the pole is constantly lockedin ice and offers “no opportunity to movefloating equipment to do your construc-tion work.”

“The Caspian Sea is well south of theArctic Circle, but it has a lot of ice in thewinter time that would affect develop-ments in Russia and Kazakhstan,” Lanansaid.

More interest at $70 Because of the expense, there is obvi-

ously more industry interest in the Arcticwhen oil is $70 per barrel versus $10 perbarrel, Lanan said. “Having been in off-shore Arctic pipelines for over 25 years,you can see the interest goes up and downwith the price of oil. We’re in a high peri-od now.”

He said offshore Arctic “has severalinteresting features,” most notably thedifficulty in transporting workers, equip-ment and supplies to remote construction

sites, as well as extracting the oil andmoving it to market. “Pipelines are actu-ally a very key part of that,” he added.

“In terms of the environment, the cli-mate is quite cold with total darkness inthe winter time,” he said. “The key issueis sea ice. The soils on the bottom havepermafrost, which has implications whenyou try to chain things to it. It can causeice heaves. The ice moves and imposeslarge forces on structures that are on thesurface and actually can have significantimpacts on the sea bed.”

Sub-sea installations also are subjectto strudel-scour in shallow water and ice-gouging in deeper water.

In the summer, when there may be noice, “you’ve got the waves to contendwith,” Lanan said. “And you can get verysignificant wave activity in these areas.”

Despite the huge expense and techni-cal challenges, offshore Arctic provides“quite an opportunity” to develop newtechnologies, Lanan said.

Deepwater technology similarHe added: “One of the things we can

draw on is very similar to the develop-ment of technology for deepwater: howthat advanced over the past decade, theprogression of how deepwater is defined

and the technology applied for develop-ment of structures — pipelines, trans-portation systems and choice of equip-ment.”

Lanan said the future of Arctic devel-opment hinges on how industry appliesexisting and new technologies to suchthings as extended reach drilling, sub-seadevelopments and “where you can avoidhaving structures coming to the surface.”

He said that from man-made gravelislands such as Oooguruk and Northstar,offshore development in the Arctic couldevolve into steel and concrete-basedstructures, and ultimately to floatingstructures and sub-sea field development,as the hunt for oil and gas moves intodeeper waters.

Another potential stumbling block asindustry moves into deepwater Arctic isthe Jones Act, which prohibits the use ofnon-U.S.-flag vessels from operatingbetween U.S ports, Lanan said, notingthat currently there are no U.S.-flag ves-sels capable of operating in ice-cloggedenvironments.

“There are limited vessels available inthe world that can do this,” he said. “And ifyou have to have a U.S.-flag vessel that hasa major impact on both the cost and sched-ule of a lot of the project planning.” ●

continued from page 5

SURPRISE

NORTH SLOPEBP shutting down two North Slopepipelines; might need to be replaced

Two oil pipelines on Alaska’s North Slope are being shut down because of inter-nal corrosion _ a worrisome problem that was the cause of a huge spill earlier this yearin the aging Prudhoe Bay oil field.

One of the lines is a 24-inch diameter, 5-mile pipe at the Lisburne oil field. Theother is a 14-inch diameter, nearly 4-mileline at Milne Point, BP PLC said Tuesday.

Together, the pipelines account for22,000 barrels of the approximately825,000 barrels that flows each day downthe trans-Alaska pipeline to Valdez, wherethe crude is loaded onto tankers and takento West Coast refineries. At Tuesday’sprices of $69.09 a barrel for Alaska crude,the shutdown means the loss of about $1.5million a day.

The corrosion of the pipes comes as nosurprise to BP, which runs the Lisburneline on behalf of itself and two other own-ers. BP is sole owner of the Milne line.

Both pipes had a history of corrosionand were being treated with corrosion inhibitor, said Maureen Johnson, a BP seniorvice president. BP tried increasing the amount of corrosion inhibitor in the Lisburneline from 24 parts per million in 2002 to 200 parts per million in 2005.

It became increasingly apparent corrosion inhibitor was not doing the trick. The line was not producing a continuous flow. An X-ray of the pipe showed inter-

nal corrosion in an arrow shape, indicating the damage was being aided by the veloc-ity of fluid moving through the pipe, Johnson said.

``We started to conclude last year that corrosion inhibitor alone might not stop thisproblem,’’ she said.

The problem with the Milne oil field line is similar, she said. The corrosion is beingcaused by carbon dioxide in the lines, a problem BP and other North Slope operatorshave been aware of since Prudhoe Bay began production in June 1977.

BP is leaning toward replacing both pipelines, Johnson said. The earliest that workcould be done would be in 2007.

—THE ASSOCIATED PRESS

Together, the pipelines accountfor 22,000 barrels of the

approximately 825,000 barrelsthat flows each day down the

trans-Alaska pipeline to Valdez,where the crude is loaded onto

tankers and taken to West Coastrefineries. At Tuesday’s prices of

$69.09 a barrel for Alaska crude,the shutdown means the loss of

about $1.5 million a day.

● W A S H I N G T O N , D . C .

Stevens backs Kennedyon wind farm amendment

By ALLEN BAKERFor Petroleum News

en. Ted Stevens, R-Alaska, has pro-posed an amendment to the CoastGuard and Maritime TransportationAct to give Massachusetts an effec-

tive veto over a controversial offshorewind farm in federal waters off the north-eastern state.

In a speech on theSenate floor May 9,Stevens said that hisdecision to wade intothe issue far fromAlaska’s shores was“based upon mylong-held belief thatstates should havethe final say on proj-ects which willdirectly impact their land, resources, andtheir constituents.” Allowing federaldevelopments without state input wouldset a powerful precedent for federalwaters off his own state, he said.

For example, Stevens said, federalwaters in Cook Inlet south of Kenaiencompass about 2.5 million acres thatcould be used for similar projects, or otherfederal purposes, without Alaska’s con-currence. Like the Massachusetts site, thefederal waters in Cook Inlet are almostentirely enclosed by state waters.

“The debate over this project is similarto the fights that those of us in Alaskahave been engaged in for decades. Ourstate lands are surrounded by federallands, our waters are surrounded by feder-al waters, and we often do not have anysay in decisions regarding the develop-ment of our resources or the projectswhich will be located in our state,”Stevens said.

The proposed wind farm site is inNantucket Sound. As currently planned, itwould involve 130 huge wind turbinesspread over an area of 24 square miles, orabout 15,000 acres. The turbines would be417 feet tall, compared with the 296-footheight of the ConocoPhillips building inAnchorage, Alaska’s tallest building.

While the wind farm would be just afew miles from Massachusetts, Stevensnoted that other states have blockeddevelopments much further from theirshores.

“Just think, California blocked oil plat-forms; Oregon and Washington blockedthem even before they were built. We nowhave a dispute before the Congress over apotential development of gas resources170 miles off the State of Florida.”

Stevens said he supported the idea ofwind farms, but preferred to have suchfarms located further offshore, where theywouldn’t interfere with navigation andfishing. ●

S

SEN. TED STEVENS

JUD

Y P

ATR

ICK

By GARY PARKFor Petroleum News

he North American progeny of RoyalDutch/Shell are thrusting their way tothe forefront of Alberta’s oil sands.

Already rumored to be planning aC$17 billion investment over the nextdecade to boost output from their Athabascaproject from 155,000 barrels per day (cur-rently 77,400 bpd net to Shell) to as much as600,000 bpd, the company has broadened itshorizons even more this year.

Through SURENorthern Energy, asubsidiary of ShellExploration &Production in theAmericas, the globalgiant spent C$465million locking up220,000 acres of apossible new oil sandsplay outside the tradi-tional Athabascastronghold.

Now Shell Canadahas bid C$2.4 billionfor junior producerBlackRock Ventures,giving a bold lift to itsPeace River opera-tions in northwesternAlberta, setting a newstandard for oil sandsassets.

It is rated as easilythe highest per-barrelacquisition in the pastyear that has seen Petro-Canada, France’sTotal, China’s CNOOC and Sinpoec, andChevron Canada join Shell in a franticscramble to seize assets at a time when theindustry is being spooked by moves fromcountries such as Venezuela and Bolivia tonationalize their petroleum industries.

Per-barrel not disclosed Shell Canada did not disclose what it is

prepared to pay BlackRock on a per-barrelbasis, and Chief Executive Officer CliveMather refused to say whether the dealwould make sense even if oil fell to US$40per barrel — the approximate calculation ofhow much the offer is worth.

He said BlackRock is “not about currentproduction, it’s about what we can see in thefuture”; a spokeswoman conceded that “wedid pay a premium.”

Even Jim Buckee, chief executive officerof Talisman Energy, came close May 9 tobreaking the industry’s unwritten rule aboutnot criticizing your competitors.

He expressed surprise to reporters aboutwhat Shell Canada paid for the properties,hesitantly adding: “They must know some-

thing we don’t.”Earlier this year, Buckee said Talisman

was looking at ways to monetize its oilsands holdings, but he said May 9 that thehigh cost of developing the resource andreservations about the technology availablenow may encourage his company to eithersell the assets or look for a partner with min-ing and refining expertise.

Martin Pelletier, an analyst withCanaccord Adams, said it appears ShellCanada is digging deep to ward off anyother contenders.

BlackRock holds 268,000 acres in thePeace River region and Cold Lake in theheart of oil sands/heavy oil activity, alongwith estimated recoverable proved reservesof 142 million barrels and 67 million barrelsof probable reserves.

From quiet beginnings 10 years ago it isnow producing 15,000 bpd, is targeting30,000 bpd by the end of 2007 and 40,000bpd by the end of the decade.

The acquisition, if it clears all sharehold-er and regulatory approvals, will initiallygive Shell Canada 14,500 bpd of heavy oilvolumes from the Seal project in the PaceRiver, where

The Seal leases are adjacent to similarShell Canada holdings that are currentlyflowing 12,000 bpd and are targeted for

staged expansion to30,000 bpd by 2009on the way to a100,000 bpd opera-tion that could havean operating life of 30years, drawing on apotential 7 billionbarrels.

BlackRockrecognized potential

Ian Kilgour, acompany senior vicepresident, said lastyear that spending onthe Shell leases alonecould run to severalmillion dollars, butwas hesitant aboutbeing more specificgiven the inflationarypressures and cost uncertainties.

BlackRock President John Festival saidhis firm “recognized that the tremendouspotential identified on our properties out-stripped our financial and operational abilityto develop them in a timely manner,” refer-ring to a company that has only 22 employ-ees, 55 contract personnel and limited cashflow, which yielded first quarter earnings ofC$3.2 million. However, he said in a releasethat his company is on budget at C$225 mil-lion in total planned capital costs for the firstphase of production at its Orion project for10,000 bpd starting in late 2007.

The Seal area of the Peace River consistsof heavy oil of 10-11 degrees API, whichmeans it can be pumped.

Others with stakes in Seal include KochExploration Canada, Murphy Oil, PennWest Energy Trust and Baytex Energy Trust,with Penn West Chief Executive Officer BillAndrew saying the Peace River could rede-fine his company by adding “multiple mil-lions of barrels of reserves and very strongproduction.”

It has also attracted privately held PROUpgrading, which has raised more than halfof the C$800 million it has budgeted for a25,000 bpd upgrader, growing to 100,000bpd by 2020, turning raw bitumen into 28degree API crude. ●

PETROLEUM NEWS • WEEK OF MAY 14, 2006 7

● C A N A D A

Shell builds castles in the sandsMega-major makes bid for junior BlackRock Ventures to expand interests in Alberta’s Peace River region

T

Shell Canada … CEOClive Matherrefused to saywhether the(BlackRock) dealwould make senseeven if oil fell toUS$40 per barrel —the approximatecalculation of howmuch the offer isworth. He saidBlackRock is “notabout current pro-duction, it’s aboutwhat we can see inthe future;” aspokeswoman con-ceded that “we didpay a premium.”

Jim Buckee, chiefexecutive officer ofTalisman Energy,came close May 9 tobreaking the indus-try’s unwritten ruleabout not criticizingyour competitors.He expressed sur-prise to reportersabout what ShellCanada paid for theproperties, hesitant-ly adding: “Theymust know some-thing we don’t.”

Want to knowmore?If you’d like to read more about Shellin the oil sands, go to PetroleumNews’ Web site archives atwww.PetroleumNews.com.

2006• May 7 Beating the budget blues inCanada• April 30 Alberta aboriginals andShell team up• April 2 Shell pushes oil sands hori-zons• March 26 Shell breaking ground insands• March 12 Chevron goes big time inoil sands• March 5 Western Canada: And lookwhat we have here…. • Feb. 26 Grasping Alberta oil sandsnettles

By GARY PARKFor Petroleum News

he Alberta government has sent anervous tremor through the petrole-um industry by warning that it maystart charging for water, a lifeline to

oil and gas producers, especially oil sandsoperators.

Environment Minister Guy Boutiliersaid the province will decide by March2007 whether fees will be imposed to curbusage in an increasingly parched region.

In the meantime, he said no one shouldassume there will be a do-nothing strategy.

Quoting Mark Twain, he said: “Whiskyis for drinking, but water is for fightingover.”

By 2007, Alberta will have a new pre-mier, succeeding Ralph Klein who hasresisted any attempts to impose stringentwater-consumption limits on the industry.

But the pressure to act has been build-ing, with recent studies forecasting thatAlberta is heading for drought conditionsin the next 10 years, after a prolongedperiod of above-average rainfall andbecause of a population explosion in theprovince, generated mostly by the oil andgas sector.

Report calls for moratoriumIn a new report entitled “Troubled

Waters, Troubling Trends,” the PembinaInstitute for Appropriate Developmentrenewed a call for a moratorium on newoil sands projects until the governmentdecides how much fresh water companiesshould be able to take.

Failure by the government and industryto act could see Alberta run out of freshdrinking water long before it runs out ofbitumen deposits, said Pembina seniorpolicy analyst Mary Griffiths.

“A freeze on fresh water would providecompanies with an incentive to maximizeefficiency and to seek opportunities toeliminate or reduce water use,” she said.

The warning signals have not been con-fined to environmentalists.

Former Alberta premier PeterLougheed has predicted the province isheading into an era when water is morevaluable than oil.

Report conclusionsThe Pembina report reached the fol-

lowing conclusions on water usage by theindustry:

• Producing one barrel of oil from theoil sands requires two to four and a halfbarrels of water.

• In 2005, water withdrawn from theAthabasca River, the major waterwaythrough the oil sands region, for oil sandsmining and production was double thewater use in the City of Calgary, with apopulation of about 1 million.

• In situ oil sands projects, which injectsteam to melt deeply buried bitumendeposits, used 27 million cubic meters ofwater in 2004 — two to three times greaterthan the Alberta government predicted in2001.

• Projections made in 2001 showed theoverall industry reaching the 2004 level ofwater use in 2015, with the 2020 level notmuch higher.

Producers association troubledThe growing clamor for restrictions

troubles the Canadian Association ofPetroleum Producers, whose PresidentPierre Alvarez told reporters his industryalready pays indirectly for water throughroyalties, giving the province a “tremen-dous economic return.”

Although flatly opposed to water feesor a freeze on oil sands development, heemphasized the industry is making consid-erable efforts on its own and in coopera-tion with the government to use morerecycled and non-drinkable water.

“Do we recognize that we have toimprove our water use? Yes. Are we goingto keep working on it? Sure we are,” hewas reported as saying by the CanadianPress.

“Do we feel that a moratorium is inorder? Certainly not.”

Alvarez pointed out that growing com-munities and the agriculture industry usemore water than the oil and gas sector,asking whether the Pembina Institute wassingling out the industry.

The industry is currently licensed todivert 359 million cubic meters, doubleCalgary’s annual consumption, butreceived only 7 percent of Alberta’s totalwater allocation in 2004.

The argument that new technologiesare under development is not accepted bythe Pembina Institute, which said “nomajor breakthroughs” relating to water usein oil sands mining are expected before2030.

“It is unlikely that (any) reduction inwater use per unit of production will offsetthe rapid growth in oil production andhence gross demand for water,” thePembina study said.

The study also said Alberta does nothave a good grasp of its groundwaterresources.

“Monitoring is required to determinewhether the long-term, cumulative with-drawals are sustainable,” it said. ●

8 PETROLEUM NEWS • WEEK OF MAY 14, 2006

ALBERTATechnology keeps hope alive inWestern Canada Sedimentary Basin

Finding enough natural gas to sustain flows from the Western CanadaSedimentary Basin is a tough job, but the hope that drives explorers is still alive,bolstered by new seismic and drilling technologies.

It is becoming “harder than ever” to uncork “good gas wells,” said FirstEnergyCapital analyst Steven Paget in a new research note.

“High-production gas wells are getting fewer and further between” and thequality of the top wells has declined since 2002, he said.

FirstEnergy estimates the average initial production of the 25 best wells in thebasin in 2005 was 10 million cubic feet per day, off 10 percent from 2004 and 25percent from 2002.

Tay River discovery fuels optimismWhat fuels optimism, however, is the 2004 Tay River discovery in Alberta by

Shell Canada.Ranking among the top three finds of the last 20 years, but still outside the top

25 wells logged in the basin’s history, it started producing last May at 23 millioncubic feet per day from reserves of about 800 billion cubic feet.

Shell has since added new well tubing and added to a processing facility toboost output to 95 million cubic feet per day (57 million cubic feet per day afterremoving sulfur), generating daily revenues of about C$340 million.

The company has also started a second exploration well in the Tay area alongwith a separate well to evaluate the size of the first discovery.

What fuels hope is the proprietary seismic Shell used to identify the formationin the Foothills region of the Canadian Rockies, viewed as one of the best bets forkeeping the basin productive.

—GARY PARK

Enbridge expanding crude oil terminalsEnbridge has earmarked spending of C$1.5 billion as it embarks on a vigorous

program of building crude oil terminals.The extension of the company’s core pipeline business will start with a C$250

million facility at Hardisty, Alberta, including 16 tanks rang-ing in size from 250,000 to 530,000 barrels. Initial capacityof 5 million barrels is scheduled to start service in September2008.

The new facility is close to Enbridge’s 50 percent-ownedHardisty Caverns partnership and, like that facility, will beoffered on a long-term contract fee-for-service basis.

Chief Executive Officer Pat Daniel said the new terminalis a “key piece of our broader terminal development initia-tive. This is a significant new growth opportunity.”

He said the demand for terminals is “very strong” becauseof rising oil sands production, seasonality of markets andgreater price volatility.

Enbridge currently has 15 million barrels of tankage under long-term contract,with another 30 million barrels under development at eight locations spreadthrough the chain from upstream to downstream.

Enbridge also announced that it is expanding the diameter of its SouthernAccess pipeline to 42 inches from 36 inches, offering another 400,000 barrels perday by 2009 from Superior, Wis., to Chicago.

—GARY PARK

PAT DANIEL

JUD

Y P

ATR

ICK

● C A N A D A

Oil sands and water— a bad mixturePressure builds to curb usage in a thirsty region; fees considered;industry opposes ban on projects; hopes for tech solutions

T

PETROLEUM NEWShe Alaska Department of Labor andWorkforce Development expectsAlaska’s 18 consecutive years of eco-nomic growth to extend through 20

years, adding 2006 and 2007 onto thegrowth period at moderate rates, 1.7 percentthis year and 1.5 percent in 2007.

Department economist Dan Robinson,writing in the May issue of “AlaskaEconomic Trends,” said “high oil prices, agenerally favorable national and interna-tional economy and significant federalspending in Alaska practically assure con-tinued job growth over the forecast period.”

In the natural resources area Robinsonnoted that oil companies have been slow toadd jobs “because of past price volatilityand the state’s relatively high costs,” buthave added 500 jobs in 2005, for a total of8,700 oil and gas jobs in the state last year.That total was 200 fewer than in 2002 and800 fewer than in 2001, he said.

The University of Alaska’s Institute ofSocial and Economic Research is forecast-ing construction project spending by the oiland gas industry to grow in 2006 and 2007,Robinson said, with the 2006 growth fore-cast at 19 percent. Drilling is also expectedto increase, with total wells growing from243 in 2005 to 257 in 2006 and total wellfootage from 1.58 million feet in 2005 to1.67 million feet in 2006.

BP Exploration (Alaska) has said it plansto hire up to 200 new workers in 2006,Shell Oil has returned to Alaska and hassaid it plans to begin drilling in 2007 andthere is strong interest from a number ofsmaller producers, he said.

Although production continues todecline, employment in the oil and gasindustry is expected to grow by 300 in 2006and by an additional 200 in 2007.

Anchorage: upswing to continueDepartment economist Neal Fried said

the Anchorage growth cycle has nowstretched 17 years and while the city’s econ-omy is not likely to grow forever, anotheryear of growth “almost appears as certain asthe theory of thermodynamics.”

Growth rates are expected to be 1.8 per-cent in 2006 and 1.7 percent in 2007, hesaid, close to the 10-year 2 percent annualaverage employment growth rate.

Fried said high oil prices, the healthynational economy, low interest rates, a pos-itive outlook for the visitor industry, ahealthy flow of federal dollars, internation-al air cargo expansion, state revenue sur-

pluses, the emerging mining industry, thepossibility of a gas pipeline on the horizonand an overall sense of optimism are amongthe factors favoring continued growth inAnchorage’s economy.

The city is economically vulnerable inthe event of a collapse in oil prices, a dra-matic drop in federal dollars “or somethingbeyond our current imagination,” he said.

Fried said with high oil prices the fore-cast for employment in the oil and gasindustry is “for modest growth inAnchorage and more rapid growth on theNorth Slope.” He called the increase in oilindustry jobs in Anchorage modest, up 100from 2005 to 2006 for a 1.6 percentincrease to 2,100, but he said the directionis “significant.”

“Most of the players are planning someupswing in development work during theforecast period (2006-07),” Fried said,including satellite and West Sak develop-ment work by ConocoPhillips, with anincrease in spending of 8 percent in 2006.

BP is planning to hire new workers,some of whom will be based in Anchorage,some for existing North Slope projects,some for field development work and someto replace retirees.

Fairbanks: resource employment could decline

Fairbanks is also expected to see twomore years of employment growth, saiddepartment economist Brigitta Windisch-Cole, with up to 500 new jobs expectedboth this year and next, for an annualgrowth rate of 1.3 percent in those years.

Natural resource jobs, however, are

expected to decline since the automation ofmuch of the trans-Alaska pipeline as part ofthe Alyeska Pipeline Service Co. reconfigu-ration will mean fewer operating jobs at thepump stations, hence fewer workers need-ed.

Job losses are expected in Fairbanks in2007 after the reconfiguration project iscompleted among contract workers special-

izing in oil field services. ●

Editor’s note: ISER’s 2006 constructionspending forecast for Alaska was done forthe Construction Industry Progress Fund(CIPF) and the Associated GeneralContractors of Alaska (AGC). It is the thirdsuch annual report. CIPF and AGC pub-lished the 2006 forecast earlier this year.

PETROLEUM NEWS • WEEK OF MAY 14, 2006 9

● A L A S K A

State forecasts two more years of growthDepartment of Labor: jobs added in Alaska for 18 consecutive years; moderate growth should continue this year and next

T

ISER’s 2006 con-struction spend-ing forecast forAlaska wasdone for theConstructionIndustryProgress Fund(CIPF) and theAssociatedGeneralContractors ofAlaska (AGC). Itis the third suchannual report.CIPF and AGCpublished the2006 forecastearlier this year.

By ALAN BAILEYPetroleum News

n March 2 a BP well pad operatordiscovered a leak in the transit linethat delivers oil to the trans-Alaskapipeline from Gathering Center 2 in

the western operating area of the giantPrudhoe Bay oil field on Alaska’s NorthSlope.

The leak occurred in the transit line seg-ment between GC-2 and the point wherethe production from Gathering Center 1enters the line.

BP launched an immediate response towhat, with an estimated volume of around200,000 gallons, proved to be the largestspill in the history of Prudhoe Bay.

The cause of the leak became obviouswithin a few days of its discovery: internalcorrosion had caused a one-quarter-inchhole in the bottom of the transit pipeline.

The hole had formed in a section of lineburied under what is termed a cariboucrossing, a culvert designed to allow ani-mals to cross over a pipeline as opposed togoing under an elevated pipeline.

The winter snow covered the leaking oil,so the spill remained undetected, probablyfor several days. It was odor — the smell ofoil — that ultimately exposed the leak to aworker.

Cleanup of the spill site has now beencompleted, according to the AlaskaDepartment of EnvironmentalConservation. To date BP has spent $8 mil-lion responding to the incident, DarenBeaudo, spokesman for BP in Alaska, saidin a recent interview with Petroleum News.

Beaudo and Maureen Johnson, BP sen-ior vice president for Greater Prudhoe Bay,talked to Petroleum News about how theleak developed and BP’s actions to preventa similar problem in the future.

Microbiological corrosionAll indications are that the corrosion that

caused the hole in the transit line was bio-

logical in origin, caused by sulfate reducingbacteria inside the pipeline, Johnson said.

“The evidence has mounted that that istrue,” she said. “We’ve scanned what the(corrosion) pits look like in the bottom ofthe pipe.”

Also the way in which the corrosion inthe pipeline accelerated over time is charac-teristic of the way in which microbiologicalcorrosion develops, as the bacteria growand multiply.

The bacteria form in water, so that prob-lems associated with microbiological corro-sion tend to be associated with water carry-ing pipelines, such as the lines that are usedfor waterflood operations.

In fact, BP treats its water injection linesat Prudhoe Bay with anticorrosion chemi-cals and runs maintenance pigs down thelines at frequencies ranging from weekly tomonthly (a maintenance pig is a device thatpasses through the inside of a pipeline,scraping and cleaning the inside walls ofthe pipeline). The company pigged its

Prudhoe Bay pipelines more than 350 timesin 2005, Johnson said.

Transit lines less corrosion proneBP has viewed oil carrying transit lines,

such as the line from GC-2 that developeda leak, as much less susceptible to corrosionthan a water bearing line. But the companyhas regularly monitored the Prudhoe Bayoil transit lines for internal corrosion usingtwo techniques: ultrasonic testing and theuse of corrosion coupons.

Ultrasonic testing involves the use of anultrasonic device to measure the thicknessof the pipeline wall — a thinning of the wallindicates the presence of corrosion. A cor-rosion coupon is a small metal plate placedinside the pipeline and inspected for corro-sion every 90 days.

“We had 29 years of history that saidthese systems were not a great concern,”Johnson said. “All of those things told us‘not a big worry here’.”

In addition to the program of frequentinspections, BP runs what is known as asmart pig down each transit line every fewyears — a smart pig contains instrumentsthat can measure and test the condition ofthe pipeline, including the detection of cor-rosion damage.

The company ran a smart pig throughthe GC-2 transit line in 1990 and again in1998. According BP’s incident investiga-tion report for the transit line oil spill, the1990 pig run “noted nothing of signifi-cance” and the 1998 pig run “showed mod-erate internal and external corrosion”. Theevidence for corrosion in 1998 was con-firmed by ultrasonic testing — BP subse-quently used the ultrasonic testing to mon-itor any continuing development of corro-sion in the line.

However the BP report says that the cor-rosion detected in 1998 was “well withinthe BPXA ‘fit for service’ criterion” andthat the subsequent ultrasonic testing up to2004 indicated that “corrosion was nothighly active during this period.” It wasonly in an inspection in September andOctober of 2005, that evidence of increas-ing corrosion activity started to appear.

The increasing amount of corrosionfound in the fall of 2005 caused BP to stepup the inspection program on the pipeline— the company increased the number ofinspection points, increased the frequencyof inspections at some points and sched-uled a smart pig inspection for the summer

of 2006, according to the BP report.However, an inspection of the line after

the March 2006 leak showed evidence ofhigh rates of corrosion, even in place thathad been free of corrosion in the fall 2005inspection. Clearly, there had been an expo-nential growth of corrosion, culminating inthe hole that caused the oil spill.

“Whether it (the exponential corrosiongrowth) was over six months or 12 monthsor 18 months, that becomes a little bit moreof a judgment call, but it was pretty recent,”Johnson said.

And because the rate of corrosion accel-erated so rapidly, more frequent smart pig-ging would probably not have detected theproblem unless, perhaps, the pigging hadbeen done in the summer of 2005, Johnsonsaid.

Two factorsSo why did the corrosion accelerate so

rapidly?No one knows for sure. But the BP

investigation report theorizes two main fac-tors that came together at the same time.

The first factor relates to corrosioninhibitors. BP adds about 3 million gallonsper year of these inhibitors to Prudhoe Bayproduction fluids; the fluids carry theinhibitors into production facilities such asGC-2.

“We have been injecting something like3 million gallons of corrosion inhibitor ayear … And it’s going up every year as theamount of water we handle goes up,”Johnson said.

But the corrosion inhibitors appear tohave been present in relatively low concen-trations in the GC-2 production facilities,when compared with the other PrudhoeBay facilities. It is, therefore, likely that thefluids passing down the GC-2 transit linefrom GC-2 contained only small amountsof the inhibitors, thus providing opportuni-ties for corrosion-causing bacteria to grow.

The corrosion inhibitor shortfall mayhave occurred because GC-2 is the onlyfacility at Prudhoe Bay that processes vis-cous oil. The viscous oil production intro-duces more solids into the processing facil-ities than traditional production and BPthinks that these additional solids may haveadsorbed some of the inhibitor.

The second possible factor was the rela-tively low flow rate in the GC-2 transit line,upstream of GC-1. With Prudhoe Bay pro-

10 PETROLEUM NEWS • WEEK OF MAY 14, 2006

● N O R T H S L O P E

BP: Learning from oil spill lessonsJohnson, Beaudo explain what they think happened in Prudhoe Bay’s largest spill and what the company is learning from the incident

O

see LESSONS page 11

CO

URT

ESY

BP

EXPL

OR

ATI

ON

(A

LASK

A)

Diagram showing the pipelines connecting the various BP oil facilities to the trans-Alaska pipeline. Note that the spill occurred in the GC-2transit line, upstream of GC-1 — flow rates through the pipeline increase downstream of GC-1. Also, there are no separators for removingsolids between the transit lines and Pump Station 1.

duction in decline, the transit line was car-rying much smaller volumes of oil than theline was designed to handle — the resultingsluggish flow may have enabled anincreased build up of water in the line andprovided an environment conducive to theincubation of bacteria. There was much lesscorrosion downstream from GC-1, wherethe addition of the fluids from GC-1 wouldhave increased flow rates in the line.

“Downstream from GC-1 we don’t seereal high corrosion,” Johnson said.

There was also a build up of solids in theGC-2 transit line over a period of severalyears, as sediment carried by the fluids fromthe GC-2 processing facilities settled in thepipeline. Although it is not possible to dis-count the possibility that these solids con-tributed to the corrosion, it is unlikely thatthe solids were a significant factor, Johnsonsaid. Johnson pointed out that there areabout two inches of solids in the bottom ofthe east transit line, but that line does notappear to be corroding.

Also the BP incident investigation reportsays “under-deposit corrosion is usually alonger term corrosion issue and by itselfwould not be expected to suddenly increaseand produce the (corrosion) ratesobserved.”

Leak detection systemIn the wake of the transit line leak there

has been much discussion about the line’sleak detection system. The leak detectionsystem measures the volumes of fluid enter-ing each pipeline segment and the volumesof fluid leaving each segment. The systemtriggers an alarm if the volume measure-ments don’t match up.

So why did the system not detect a leakof the magnitude of the transit line oil spill?

In fact the leak detection alarm didsound four times during the week before thespill was discovered, although the alarm didnot go off during the two days prior to thediscovery.

Both before and after the discovery ofthe leak BP interpreted the leak detectionalarms as false alarms, Johnson said.

“It was a false alarm,” Johnson said.“What we thought then and what we thinknow … is that that was a process upset.”

Beaudo explained that a process upsetconsists of a sudden change in fluid flow,rather like the situation when you turn on agarden hose. The sudden pressure change in

the system causes false readings in themetering at the ends of a pipeline segment.However, although a process upset cancause an apparent loss of fluid in one seg-ment of the pipeline, the fluctuation in flowcauses an equal and opposite volume dis-crepancy in the next pipeline segment. The

resulting volume loss in one segment bal-anced by a mirror image volume gain in thenext segment is exactly what was observedwhen the false alarms sounded in the GC-2transit line.

Johnson said that the GC-2 facility alsoconfirmed that process upsets had occurred.

In fact none of the investigators of the oilspill incident were able to find any evidenceof the pipeline leak when they examined thedata from the leak detection system,Johnson said.

“We’ve looked at our leak detection dataand even in hindsight we cannot tell whenthe leak started,” she said.

It now seems clear that the leak occurredslowly over an extended period of time. Asa result, the leak rate was below the regulat-ed and practical threshold of the leak detec-tion system, Beaudo said. Beaudo also saidthat BP is now investigating the potentialfor developing a more sensitive leak detec-tion system.

Next actionsAs part of its reaction to the Prudhoe Bay

oil spill and in response to corrective actionsrequired by the U.S. Department ofTransportation, BP has started taking aseries of steps to ensure that anotherpipeline leak does not occur. The companyhas done 2,000 inspections of oil transitlines at Prudhoe Bay since the leak, Johnsonsaid.

“We’ve looked at all of the oil transitlines … none other has the same combina-

PETROLEUM NEWS • WEEK OF MAY 14, 2006 11

continued from page 10

LESSONS

see LESSONS page 12

UN

IFIE

D C

OM

MA

ND

Cleaning up the oil spill in the caribou crossing in the Gathering Center 2 transit line atPrudhoe Bay

12 PETROLEUM NEWS • WEEK OF MAY 14, 2006

tion of factors … bacteria in the facility, lowflow rate and low corrosion inhibitor carryover,” Johnson said.

But BP has committed to ratchet up itscorrosion prevention program by runningmaintenance pigs through its oil transitpipelines at regular intervals, by increasingthe frequency of smart pigging and byinjecting corrosion inhibitors into the lines— in effect the company will apply similarcorrosion prevention measures to its oiltransit lines as it already applies to its watersystems.

“Going forward we’ll pig out oil transitlines on a regular basis and we’ll look at ourpigging practices on all of our pipelines andsay ‘Does this make sense?’” Johnson said.

BP is also continuing with a $17 millionupgrade to GC-2, to improve the handlingof solids from viscous oil production,Beaudo said.

BP is also now using infrared heat detec-tors to improve leak detection on itspipelines.

“We have already initiated weekly over-flights with infrared,” Johnson said, addingthat the company has ordered handheldinfrared detectors for security people to useon the ground.

But the company has yet to determinewhat to do about the segment of the GC-2transit line where the leak occurred — thepipeline segment remains shutdown, with

GC-2 production partially restored througha bypass line.

“We aren’t clear at this point whetherwe’re gong to be able to patch it up wellenough to be able to smart pig the wholething … or whether it will be permanentlyout of service,” Johnson said.

BP has committed not to put the lineback into service until the company, theDOT and the Alaska Department ofEnvironmental Conservation are all confi-dent that oil can safely flow through it, shesaid.

Pigging issuesDOT has served BP with corrective

actions requiring maintenance pigging onthe transit lines. DOT also requires smartpigging within three months, Beaudo said.DOT has granted an extension of the periodwithin which BP has to do the maintenancepigging because of some practical problemsin carrying out the pigging.

BP plans to do the smart pigging withinthe DOT’s specified time frame. However,the smart pig run will require clearing of thelines of solids using the maintenance pigs.So, depending on when it is possible to dothe maintenance pigging, the company mayalso have to apply for a time extension forthe smart pigging.

“There’s been a lot of good, steady, reg-ular dialogue between our people and DOT— we’ve had some very constructive con-versations,” Beaudo said, adding that BPremains in compliance with DOT ordersand that DOT agrees with BP’s plan of

action.The problems with the maintenance pig-

ging result from the quantities of solids cur-rently lying in the transit lines — BP willhave to remove the solids in stages, using aseries of increasingly aggressive pigs.

And there are no separator facilitiesbetween the transit lines and the trans-Alaska pipeline. Consequently, the suddenremoval of a large quantity of solid materi-al from the lines would result in an abnor-mally large quantity of solids suddenlyflushing into the trans-Alaska pipeline. BPis working with Alyeska Pipeline ServiceCo., the trans-Alaska pipeline operator, toassess the risks involved in moving thesolids and to plan a course of action. Onesolution might be to install separator tanksto remove the solids before they enter theAlyeska facilities.

All of this takes time.“I’d rather take the criticism on taking

longer, and do it right, and that’s what we’redoing,” Johnson said.

Future strategiesJohnson went on to talk about BP’s

longer term strategy for the maintenance ofits pipelines on the North Slope. With thepotential for the export of natural gas fromthe North Slope, the company is talkingabout a 50-year future in Alaska, she said.Senior company management is encourag-ing people to think about the technologies,equipment and people that will be neededover that time frame.

And Johnson likened the Prudhoe Bay

field to a Cadillac that is 29 years old andhas 120,000 miles on the clock.

“We can drive it some more, safely,” shesaid. “If we’re going to go another 200,000miles, another 50 years from where we arenow, then we need to think about not onlythe car but the people driving it.”

In the past year the company hasembarked on a program of hiring and train-ing people in appreciable numbers, she said.

“We’ve also been on this journey, look-ing at the kit, the facilities themselves,”Johnson said.

And when it comes to pipelines the com-pany’s long-term strategy translates todoing things in a bigger broader way,although the company has yet to work outthe specifics of what this means, Johnsonsaid.

“You can count on us to not only do thereactive things we’ve done already — theinspections, the additional inhibitor, mainte-nance things, the smart pigging, the solidsremoval,” Johnson said. “… (But) theresponse will be bigger and more connectedthan that.”

And thoughts about the transit line spill,a month after the spill was discovered?

Johnson said that her feelings about theincident go much deeper than just regret,sadness or disappointment.

“We know that a spill of that size is com-pletely unacceptable. If I could find the bestway of apologizing to the people of Alaska,so they get how we feel, that’s what I’d do,”Johnson said. “A spill of that magnitude justdoesn’t fit BP’s values as a company.” ●

continued from page 11

LESSONS

● A L A S K A

Commission questions Enstar increaseRCA will investigate start date for hook-up increase; order specified April 21; participation of Attorney General requested

By KRISTEN NELSONPetroleum News

nstar Natural Gas Co., which got its connection rateincreased by the Regulatory Commission of Alaska inApril, has run afoul of the commission on implemen-tation of the increase.

RCA said in a May 5 order that it is initiating an inves-tigation and inviting participation by the Alaska AttorneyGeneral into the reasonableness of Enstar’s implementa-tion of the increase in connection fee.

Enstar had been charging $20 for a connection, and thecommission said in its April 21 letter order that the old tar-iff would apply to customers who have filed a completeapplication and paid the fee prior to the April 21 effective

date of the new rate. The commission also required thatEnstar allow customers who had paid for temporary serv-ice lines to receive permanent service lines without payingthe increased fees.

The new fee approved by the commission is $600 for aservice line plus $178 for a meter. The commission notedin its April 21 order that over the last three years Enstar’saverage cost for installing a service line was $1,178 and itsaverage meter installation cost was $304 for a residentialcustomer, a total of $1,482 which represents only 1.3 per-cent of the average total cost of a new single-meter serviceinstallation, leaving the remaining 98.7 percent to berecovered from all customers through rates in the form ofdepreciation and return.

“This is not in accordance with the ratemaking doctrine

of cost causer/cost payer,” the commission said. “From apublic policy standpoint, a lesser degree of subsidizationmay be desirable.”

The increased connection fee will reduce the level ofsubsidy paid by current customers from 98.7 percent to47.3 percent.

In opening an investigation docket May 5 the commis-sion said Enstar had notified customers of the increase inconnection charge and was required to notify the same cus-tomers of the commission’s action.

RCA investigating Enstar’s actionThe commission said Enstar sent a letter dated April 24

E

see RCA page 13

PETROLEUM NEWS • WEEK OF MAY 14, 2006 13

ALASKAGroup changes name to Cook Inletkeeper

Cook Inlet Keeper said May 8 that it has changed its name to “CookInletkeeper” to show support for more than 150 other grassroots waterkeeper pro-grams nationwide.

Cook Inletkeeper said the programs are part of the Waterkeeper Alliance witha Web site at www.waterkeeper.org.

The organization said the uniform naming convention — riverkeepers, sound-keepers, inletkeepers and waterkeepers — helps the groups “distinguish theirwork from industry-backed groups who have tried to adopt similar-soundingnames.”

Cook Inletkeeper is a community-based nonprofit with offices in Homer andAnchorage. For more information, see www.inletkeeper.org

DGGS releases Alaska Highway dataAlaska’s Division of Geological and Geophysical Surveys has announced the

release of airborne electromagnetic data and total field aeromagnetic data for about3,045 square miles of land along the Alaska Highway from Delta Junction to theCanadian border.

“This is an important corridor where we could hope to see development of a natu-ral gas pipeline, a railroad extension or other infrastructure,” DGGS Director BobSwenson said. “Minerals section chief Laurel Burns has done a great job managingthis project and acquiring a geophysical data set that will provide important informa-tion to those laying the foundation for potential development projects that could ben-efit the economy of the region and the state.”

Stevens Exploration Management Corp. acquired the data under a DGGS contract— the configuration of the electromagnetic data acquisition maximized informationabout near-surface materials, such as sand and gravel; conductive overburden; and thelocation of potential geologic hazards, such as permafrost and near-surface faults.DGGS says that the data could be used in planning future development in the area andas a source of critical information for bedrock geologic mapping.

All of the data are available to the public for the cost of reproduction from DGGS(phone 907 451-5020). Order forms and location maps are available on the DGGSweb site (http://wwwdggs.dnr.state.ak.us).

And after May 30 the materials will be also available for inspection at the AlaskaResources Library and Information Services, 3211 Providence Drive, Anchorage, AK,99508 (Phone 907 272-7547); and at the Alaska State Library in the State OfficeBuilding in Juneau, weekdays from 1 p.m. to 5 p.m.

—ALAN BAILEY

to notify customers of the new fees, tellingcustomers that the new fee schedule wouldapply to any customers who had not yethad service installed, “regardless of appli-cation date.” And if customers had appliedfor service prior to Feb. 1, Enstar said theymust complete an additional application onits new form and “make any required pay-ments.”

The commission said it had two con-cerns about the Enstar letter, since RCAregulations require: “If more than one tariffrate or charge can reasonably be applied forbilling purposes the one most advanta-geous to the customer shall be used.” Andits April 21 letter order said the new rateswould take effect on that date and not applyto customers who had already completedan application and paid the fee.

RCA also said that it appears Enstar pre-viously required fees when applications

were filed and the April 24 letter “conflictswith what appears to be customary prac-tice, if it refused to accept complete appli-cations filed before April 21st or refused toaccept tender of the $20 fee made withapplications filed in that same time period.”

Petitions to intervene are due May 19. RCA said because there are no parties

specifically representing the public inter-est, it has asked the Alaska AttorneyGeneral to participate as a party in thedocket.

T.W. Patch has been appointed hearingexaminer for the investigation into the rea-sonableness of Enstar’s implementation.RCA said Enstar has until May 10 to maila copy of the order to all customers towhom it sent its April 24 letter.

Persons who attempted to apply forservice or pay the $20 fee before April 21and were told by Enstar that it could orwould not accept the application or fee mayfile an affidavit explaining the circum-stances. ●

continued from page 12

RCA

● H O N O L U L U

Hawaii governor endswholesale gasoline cap

By TARA GODVINAssociated Press Writer

awaii Gov. Linda Lingle signed a billending the state’s cap on wholesalegasoline prices May 5 after sayingshe sees no situation in which she

would ever use the power the new law givesher to reimpose price controls.

However, before signing the bill, thegovernor suggested that lawmakers shouldconsider a system to limit oil company prof-its in the islands, saying she would submit aresolution to the Legislature next year seek-ing a study of possible state regulation ofthe industry.

“I can’t see any condition that I wouldreinstate the gas cap,” Lingle told reportersafter speaking at a convention of the HawaiiCredit Union League in Waikiki. “It’s a badidea and it’s not going to keep prices downfor Hawaii.”

The new law passed by the Legislatureon its last day May 4 gives Lingle, a long-time critic of the gas cap, the power to bringback the controls if she thinks fuel pricesare too high.

The original law brought Hawaii’swholesale gasoline prices under state con-trol when it went into effect Sept. 1.However, local retail fuel costs continued torise, making it difficult to know whatimpact the law has had for consumers.

“I am pleased that Hawaii consumerswill no longer be subject to the failed exper-iment to artificially control gas prices,”Governor Lingle stated,” Lingle said in astatement following the signing.

The new law went into effect immedi-ately with Lingle’s signature. But Linglesaid she couldn’t predict how soon con-sumers would see any difference in theirgas prices — either up or down — once fuelcompanies are again allowed to set theirwholesale prices as high or low as theywant.

“It’s such an artificial mechanism thatyou really don’t know what the true marketis right now,” she said.

Lawmakers’ efforts in combating risingfuel prices are better spent on helping todevelop other energy sources for Hawaii,such as the energy bills passed by legisla-tors this session, Lingle said.

One measure increases the cap on thestate income tax credit for installing solarpanels on a single family home from $1,750to $5,000 and for businesses from $250,000to $500,000. Another authorizes a pilotproject to begin installing the energy-gath-ering panels on the roofs of the state’sschools.

Lingle said Hawaii could also considerregulating gasoline companies similar to thestate’s electric companies and interislandbarge services. ●

H

14 PETROLEUM NEWS • WEEK OF MAY 14, 2006

WEST COASTAuthority to participate in open season

The Alaska Gasline Port Authority said May 9 that it intends to participate inthe open season for expansion of Sempra LNG’s Energia Costa Azul liquefiednatural gas receiving terminal. The authority’s project manager and general coun-sel, Bill Walker, attended an open season shippers’ meeting in Ensenada, Mexico,as part of the bidding procedures.

The Port Authority said the expansion volumes at thefacility are sufficient to provide start-up volumes for its proj-ect. Energia Costa Azul LNG terminal, currently under con-struction, is 14 miles north of Ensenada on the western coastof Baja California.

MOU with shipperThe Port Authority also said it has received a draft mem-

orandum of understanding from a world-scale shipper ofLNG which owns eight U.S. built LNG tankers that wouldbe Jones Act compliant for shipping LNG from Alaska to the

Lower 48. The Port Authority said this is inaddition to the proposal it received fromTOTE several months ago. The TOTE pro-posal would assist the authority with thebuilding of LNG tankers by a foreign ship-builder in a U.S. shipyard at rates competi-tive with foreign built LNG tankers.

“This is an opportunity for Alaska’s gasin LNG form to get into the West Coast mar-ket in 2012,” Jim Whitaker, chairman of thePort Authority, said in a statement. The proj-ect includes a 48-inch natural gas line whichwould run parallel to the trans-Alaska oilpipeline to Valdez for liquefaction and ship-

ment to the Lower 48. The project also provides for a future gas line throughCanada at such time as the legal and regulatory hurdles in Canada are resolved.

The Port Authority has an exclusive option to purchase Yukon Pacific Co.,which spent more than $100 million over a 15-year period to develop an LNGproject along the same route, and acquired significant state and federal permits forthis project.

—PETROLEUM NEWS

BILL WALKER

The Port Authority also saidit has received a draft

memorandum ofunderstanding from a world-scale shipper of LNG whichowns eight U.S. built LNG

tankers that would be JonesAct compliant for shippingLNG from Alaska to the

Lower 48.

● A N C H O R A G E

200 turn out forAnchorage rally Speakers want oil tax changes to wait until gas deal revealed;rally draws former governor, several gubernatorial candidates

By KYLE HOPKINSAnchorage Daily News

oliticians and activists got rock startreatment May 5 outside the stateheadquarters building downtown, asthey delivered a populist, “us before

the oil companies” message.“Please, ladies and gentlemen, make

some noise for Gov. Walter Hickel!” saidmaster of ceremonies Bob Lester, the Bobhalf of the “Bob and Mark” radio team,who announces Alaska Aces games in hisspare time.

“WALLY! WALLY! WALLY!”Looking fit and maybe a little tan, the

former governor talked about Alaska asan “owner state.” Inother words, its oiland gas belongs toAlaskans, he said,and the state’s lead-ers ought to makedeals that are betterfor residents than forindustry.

It’s not a newidea, but one thatrally organizershoped to turn into amovement as legisla-tors in Juneau pre-pare to change theway Alaska taxes oilcompanies.

The stakes arehigh.

Gov. Frank Murkowski spent the pasttwo years negotiating a multibillion-dol-lar pipeline deal with those companiesand has told lawmakers that if they raiseoil taxes too much the deal could fallapart.

Murkowski has said he’ll unveil thepipeline deal May 10. A version of therevamped oil taxes has already passed thestate Senate.

Speakers at the May 5 rally urged leg-islators to hold off on reworking oil taxesuntil they know what exactly is in thepipeline contract. (Four days later theygot their wish. See story on page 1 of thisissue.)

Irwin calls process ‘secret’Tom Irwin was Murkowski’s natural

resources commissioner until he wrote amemo critical of the gas line negotiationsand was forced out of his job. He dialed intothe conference call as he traveled to visit hismother-in-law in Idaho.

“It’s truly looking like a secret process.Maybe even an orchestrated and manipulat-ed process,” Irwin said, his voice some-times drowned out by a metallic buzz.

A similar rally was held May 6 in down-town Fairbanks, said All Alaska Alliance

director Lori Backes, who organized theAnchorage event.

Backes’ group favors a gas pipelineroute that stays in Alaska rather than goingthrough Canada. So did many of the speak-ers May 5.

That’s different from the routeMurkowski and the oil companies havefocused on.

The governor’s spokeswoman, BeckyHultberg, said May 4 that the rally would bemore about political theater than good poli-cy.

Earlier in the week, Alaska SupportIndustry Alliance general manager PaulLaird sent an e-mail to his group’s mem-bers, calling the rally a publicity stunt andurging members to send lawmakers a dif-ferent pipeline message: No delays.

“Tell them we’ve waited long enough,”Laird wrote.

The group’s communications manager,Hillary McIntosh, said the Alliance dis-agrees with some of the rally organizerswho want to freeze the pipeline effort untilMurkowski is replaced.

“Alaskans should have the opportunityto decide for themselves whether theupcoming (gas line) fiscal contract is goodor bad,” she said.

People at rally wanted to see contractThat’s what many people at the rally

wanted too — a look at the pipeline contractthe governor negotiated in private. (Again,attendees got their wish. See story on page1 of this issue.)

“The door should be open when they dostate business,” said Donna Grant, whostood near the front of the crowd. She heardabout the rally from a friend.

People squinted into the sun as they lis-tened with arms folded or stood leaning onsigns that said things like “Pass the petrole-um: We’re getting screwed” and “Thedeal’s too Murky.” Awoman in pigtails helda pole with a placard that read: “Whatwould J. Hammond do?”

The rally alternately resembled a revival,a civics lecture and a giant conference call.

Rep. Ethan Berkowitz, an AnchorageDemocrat and candidate for governor,dialed in from Juneau to address the crowd.Berkowitz’s fellow Democrat and opponentin the governor’s race primary, Rep. EricCroft, spoke in person.

Berkowitz said he stayed at the Capitolto work, calling it his first responsibility asHouse minority leader. Croft said puttingpublic pressure on the Legislature to passbetter oil reform was more important thanwaiting in Juneau.

As for some of the other candidates,Sarah Palin, a Mat-Su Republican attendedand spoke. Fairbanks Republican JohnBinkley had held a press conference on thegas line the day before, and AnchorageRepublican Andrew Halcro, who is run-ning as an independent, did not attend. ●

P

Former Gov. WalterHickel talked aboutAlaska as an “ownerstate.” In otherwords, its oil andgas belongs toAlaskans, he said,and the state’s lead-ers ought to makedeals that are betterfor residents thanfor industry.

“It’s truly looking like a secretprocess. Maybe even an

orchestrated and manipulatedprocess.”

—former Commissioner of Natural ResourcesTom Irwin

Gov. Frank Murkowski spent thepast two years negotiating a

multibillion-dollar pipeline dealwith those companies and has told

lawmakers that if they raise oiltaxes too much the deal could fall

apart.

JUD

Y P

ATR

ICK

PETROLEUM NEWS • WEEK OF MAY 14, 2006 15

● W A S H I N G T O N , D . C .

EIA expects $68 oil this year, nextAgency says less chance for significant improvement in world petroleum supply and demand due to steady demand growth

By KRISTEN NELSONPetroleum News

he U.S. Department of Energy’s Energy InformationAdministration said May 9 that “prospects for signifi-cant improvement in the world petroleum supply anddemand balance appear to be fading.”

The agency said while U.S. production will grow in 2006with recovery from 2005 hurricane damage from Rita andKatrina, it expects only moderate increases in productionfrom Organization of Petroleum Exporting Countries andother non-OPEC countries.

Demand growth will be steady and continued, with onlymodest increases in oil production capacity, and little roomfor production increases in response to political instability.

As a result the agency expects that crude oil prices willremain high through the end of next year, with West TexasIntermediate prices expected to average $68 per barrel inboth years, “up substantially from our prior forecast.”

In last month’s short-term forecast, released April 11, theagency projected a WTI average of $65 in 2006 and $61 in2007. Henry Hub spot prices for natural gas are expected toaverage $8.11 per thousand cubic feet in 2006, down about

90 cents per mcf from the 2005 average. EIA said the 2007Henry Hub average is expected to be more than $9 per mcf,“assuming sustained high oil prices, normal weather andcontinued economic expansion in the United States.”

Consumption growth has slowedWorld petroleum consumption has slowed because of

higher prices but consumption growth remains strong at 1.6million barrels per day for this year and a projected 2 millionbpd in 2007, with most of the consumption growth beingmet from non-OPEC production. A downward revision inU.S. consumption growth in 2006 is compensated byincreased Middle East consumption growth “driven by thelarge revenue flows into major petroleum exporters, contin-uing if not expanding consumer subsidies and increasingindustrial and petrochemical demand,” the agency said.

EIA expects non-OPEC production to grow by 800,000bpd in 2006. Large new projects in Angola and the CaspianSea are expected to produce increases in 2006 and 2007,while OPEC production in 2006 is expected to be similar to2005.

“World surplus crude oil production capacity, which isprimarily located in Saudi Arabia, is down slightly in 2006

compared to 2005” and the agency expects capacity todecline again in 2007 as OPEC crude oil production accel-erates. Because only limited surplus capacity exists concernabout political unrest and possible hurricane damage “willkeep upward pressure on oil prices.”

U.S. natural gas consumption downEIA said 2006 U.S. natural gas consumption is expected

to be about 1.1 percent below 2006 levels because of a warmJanuary “and much weaker expected cooling load this sum-mer compared to 2005.”

U.S. dry natural gas production declined 2.8 percent in2005, largely because of hurricane-related infrastructuredamage, is expected to increase by 0.8 percent this year andby 1.6 percent in 2007.

U.S. liquefied natural gas imports, which totaled 630 bil-lion cubic feet in 2005, are expected to increase to 740 bcfin 2006 and 970 bcf in 2007.

At the end of April working gas in storage was an esti-mated 1.904 trillion cubic feet, 455 bcf above year-ago lev-els and 699 bcf above the five-year average. EIA said warmJanuary weather accounts for much of the high storagelevel. ●

T

● W A S H I N G T O N , D . C .

Pombo: Tax Big Oil by drilling in ANWR House Resources chairman urges congressional colleagues to get companies to reinvest profits in U.S. energy resources

By ROSE RAGSDALEFor Petroleum News

ep. Richard Pombo, R-Calif., sent a letter to his col-leagues in the U.S. House of Representatives May 9titled, “Do you want to tax Big Oil? Open ANWR.”

Pombo went on to summarize findings in anassessment by the Congressional Research Service thatshows oil production from the coastal area of the ArcticNational Wildlife Refuge could generate anywhere from$112 billion to $173 billion in corporate income taxes androyalties for federal coffers.

The letter was directed primarily at Democrats who havecriticized the Bush administration for not taking action tocurb high oil prices from which oil companies are gleaningrecord profits. Democrats also have accused theRepublican-led Congress of providing $10 billion in taxcuts to oil companies at a time when Americans face risinggasoline prices.

First time tax revenue considered“With everyone screaming about taxing the oil compa-

nies, we decided to take a look at the tax revenue we couldexpect from oil production in ANWR,” Pombo aide DanKish said May 10. “To my knowledge, this is the first timeanyone has considered this. Up until now, we’ve been argu-

ing over whether revenue from thebonus bids during leasing would gen-erate $2.4 billion or $10 billion forthe federal government.

“I’d say $112 billion is a bit ofmoney, even in this town,” Kishadded.

The CRS report concluded thatfederal revenues in 2006 dollars overthe life of fields covering just 2,000acres in ANWR could generate $76billion in corporate income taxes and$35.5 billion in royalties from mean production of 10.3 bil-lion barrels of oil sold for an average of $75 a barrel.Geologists estimate that ANWR has a 50 percent chance ofcontaining 10.3 billion barrels of technically recoverablecrude.

If production from ANWR fields climbs to their upper-end estimate of 16 billion barrels, federal revenue wouldjump to $173.3 billion, $118 billion in corporate incometaxes and $55 billion in royalties.

The CRS assessment also estimated federal revenuefrom taxes and royalties if oil prices dropped to $60, $30,and even $10 a barrel. Projections with mean output fromANWR fields of 10.3 billion barrels totaled $89.3 billion,$44.7 billion and $14.9 billion in federal corporate income

taxes and royalties, respectively. At the upper-end produc-tion estimate of 16 billion barrels, federal revenue estimatestotaled $138.7 billion, $69.4 billion and $23.1 billion,respectively.

Alaska North Slope crude sold May 10 for $70.53 a bar-rel, up $1.44 from the day before. Oil produced in Alaska issold entirely on the West Coast, with sales to foreign mar-kets prohibited since 2000.

Kish said Pombo, who chairs the House ResourcesCommittee, is convinced that the best way for Congress toaddress the oil companies’ profits is to encourage them toreinvest in U.S. energy resources.

“Many Democrats have called for new taxes on ‘BigOil’ as record-high prices have led to massive profit mar-gins,” Pombo said in a statement May 2. “And for once Iagree with them — Congress should open ANWR, put ‘BigOil’ to work increasing American supplies to lower prices,and generate massive new tax revenues at the same time.How could tax-hungry Democrats say no to that?”

Enough is enoughPombo accused environmental fundraising groups and

obstructionists in Congress of using the ANWR energyissue as a cash cow for two decades. “Enough is enough. It

RU.S. Rep. RichardPombo, R-Calif.

see ANWR page 16

16 PETROLEUM NEWS • WEEK OF MAY 14, 2006

is time to make this resource a cash cow foreach and every American taxpayer,” hesaid. “This production would create jobs,lower prices, grow the economy and makeour country more secure. At today’s prices,the mean estimate of ANWR’s recoverableoil alone represents a $780 billion econom-ic decision.”

“If we applied that same calculus to the(outer continental shelf) in areas wheredrilling is now off limits, it would give useeight times the revenue projected from

ANWR, or over a trillion dollars,” Kishsaid.

The CRS assessment assumed the feder-al government and the state of Alaskawould split revenue from ANWR oil pro-duction 50-50. The estimate, however, doesnot include secondary economic benefitsfrom ANWR output nor federal taxes androyalties on potential natural gas produc-tion.

“Assuming the State of Alaska has simi-lar corporate income tax rates, the statewould collect a similar amount of revenue,”Kish said. “I don’t have to tell you what thatwould mean for Alaska.” ●

continued from page 15

ANWR

Company symbol earnings % liquids % gas %

BP BP $5,623 -15 2,533,000 -2 8,713 -0-

EnCana ECA $1,474 -0- 212,941 -7 3,343 +6

ExxonMobil XOM $8,400 +7 2,696,000 +6 11,199 +11

Can. Natural CNQ.TO C$57 — 323,662 +13 1,436 -1

ConocoPhillips COP $3,291 +13 1,016,000* -3 3,565* +8

Chevron CVX $3,996 +49 1,681,000 +2 4,947 +32

Devon DVN $700 +24 213,700 -19 2,125 -10

Husky HSE.TO C$524 +37 239,400 +16 685 +1

Petro-Canada PCZ C$206 +74 245,600 -13 787 -11

Kerr-McGee KMG $255 -28 106,000 -12 934 -7

Nexen NXY.TO (C$79) — 122,900 -15 214 -14

Talisman TLM C$197 -24 299,977 +27 1,338 +1

Apache APA $660 +18 230,191 -9 1,359 +8

Suncor SU.TO C$713 +964 269,600 +89 196 +3

Williams WMB $132 -34 714** +16

Pogo PPP $67 +14 39,561 +29 282 +9

XTO XTO $467 +181 55,689 +21 1,126 +22

Forest FST $4 -91 22,700 -19 238 -23

Murphy MUR $114 -0- 98,074 -10 84 -26

Dominion D $534 +25 67,800 +61 822 -4

Occidental OXY $1,230 +45 492,000 +15 708 +7

Newfield NFX $149 +148 17,778 -30 493 -13

EOG EOG $425 +111 29,200 -0- 1,304 +12

Imperial IMO C$591 +50 263,000 +1 580 -1

Pioneer PXD $543 +539 61,703 -10 591 -18

Marathon MRO $784 +142 210,700 +29 996 -3

Chesapeake CHK $624 +399 23,511 +21 1,378 +32

El Paso EP $356 +236 19,000 -21 578 -7

Anadarko APC $661 +35 191,000 -10 1,366 -6

RD/Shell RDS-A $6,893 +3 1,966,000 –8 10,324 +5

Earnings from Top 30 North American E&P Capex SpendersEarnings first quarter 2006 • Change from first quarter 2005

Liquids production first quarter 2006 • Change from first quarter 2005Natural gas production first quarter 2006 • Change from first quarter 2005

OIL COMPANY EARNINGS

* Does not include share of Lukoil production**Millions of cubic feet equivalent

Liquids production in barrels per day. Natural gas production in millions of cubic feet per day.

NOTE: Top 30 is based on Petroleum News research

anticipation of future testing. Buckee and ’t Hart said the challenges

ran the gamut from a deep freeze as FEXwas barging equipment to the Aklaq site,followed by a warm spell that affected thetundra, then another cold snap.

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

The weather aside, the company haslearned enough to decide it will do somethings differently as it gears up for thenext round of drilling in the winter of2006/07.

A number of drilling locations will beidentified this summer and if “everythingworks,” FEX will be ready to go on twoto five locations this coming winter, ’tHart said.

The big Nabors Rig 14E that FEXused this past winter is stacked at thestaging area in Smith Bay. Talisman saidFEX will attempt to bring in smaller,more mobile rigs over the summer, whichgives legs to the rumor the Arctic Wolfbeing built by Akita Drilling in partner-ship with Doyon Drilling might also beused for FEX’s NPR-A drilling program.

In the past Talisman officials havetalked about FEX using as many as threedrilling rigs in NPR-A next winter.

Smith Bay leases complementBolstering its longer term prospects,

in March FEX acquired 25 Smith Bayleases covering 120,000 acres in theState of Alaska’s Beaufort Sea areaw-ide lease sale. In addition to comple-menting the company’s land positionsouth of Cape Simpson, FEX’s newleases in Smith Bay could line up witha possible exploration fairway acrossthe northern part of NPR-A to the com-pany’s existing leases on the west sideof Harrison Bay, Paul Decker fromAlaska’s Division of Oil and Gas toldPetroleum News following the lease

sale.Decker sees some particularly inter-

esting exploration possibilities inSmith Bay.

“It’s a nice crestal position on theBarrow Arch, with shallow water andlogistically connected to their onshoreexploration program in NPR-A,”Decker said.

People have long known about fouroil seeps on the coast at Cape Simpson,just west of Smith Bay. It’s a natural oiltrap where Brookian topset sands comeup against shale in an ancient incisedcanyon, Decker said. The oil from theCape Simpson seeps likely originatesfrom an “oil kitchen” to the north, in alower Cretaceous source rock systemknown as the HRZ, he said.

“That would put this (Smith Bay)area squarely in between the kitchenand the seeps,” Decker said. “So youprobably have a pretty good plumbingstory to be able to charge this with nicelight oil.”

In addition to a possible Brookianplay, there are potential Ellesmerianplays below the lower Cretaceousunconformity (ancient erosion hasprobably scoured out the Beaufortianmiddle and upper Jurassic sands thatare found in nearby onshore wells).The East Simpson No. 1 and No. 2wells on the coast near Smith Bayfound some interesting Sadlerochit andEndicott sands below the lowerCretaceous unconformity, Decker said.

The 25 leases are 140 miles west ofPrudhoe Bay.

—GARY PARK & KAY CASHMAN

cial discovery, they will be turned back tothe government’s inventory.”

Because they have been off the marketfor years and in many cases not fullyevaluated, newly available blocks are typ-ically attractive to explorers, making upabout 25 percent of total blocks receivingbids in any given sale. Coupled withtoday’s high oil and gas price environ-ment, the next few sales should be barn-burners.

MMS anticipates that 2,270 leasescould expire in 2006-2007, 1,680 leasesin 2008-2009, 874 leases in 2010-2011,693 leases in 2012-2013 and 647 leasesduring the period 2014-2015.

“Presumably, the level of activitywould be very, very robust, just like thelast lease sale,” Oynes said of futuresales, noting that a block in GreenCanyon offered in last March’s salereceived a $42 million bid, the highest fora single block in some 20 years.

Lease hording, lack of rigsOynes said many expiring leases are

not being evaluated partly due to a lack ofdeepwater drilling rigs and partly due tocompany hording. “I think it is fair to saythey acquired a lease inventory (know-ing) there was no way they were going tohave time to evaluate all of this,” headded.

Leases expiring this year and nextshould contain at least some worthy

prospects, although Oynes agreed duringan interview with Petroleum News thatthe really good or “A” targets likely weredrilled following the first leasing round.However, many “B” and “C” prospectslikely will be turned back to the govern-ment for re-offering.

“Do I expect a record sale? No, interms of the number of tracts bid on —the dollars we’ll have to wait and see,” hesaid. “Do I expect a very robust sale? Yes,probably larger than this last Central Gulfsale.”

Meanwhile, explorers lucky enough tohave a deepwater rig under contractappear eager to drill as many prospects asthey can before their leases begin toexpire. Forty-six drillships and semi-sub-mersible rigs were actively drilling inearly May, just one rig away from therecord of 47.

Going all out in the 11th hour“They are going all out … trying to get

at some of these ‘A’ prospects before theyexpire,” Oynes said, but still holding tohis expectation that despite this 11thmaneuver at least 90 percent of the leaseswill be turned back to the government.

However, he said the actual pace ofdiscoveries in the deepwater Gulf ofMexico has picked up, noting that from1975 through 1999 there were 143 dis-coveries, compared to 44 from 2000through 2003 and 32 discoveries in 2004and 2005. “The progression is farther andfarther offshore and deeper and deeperwaters,” Oynes added. ●

continued from page 1

SALES

continued from page 1

TALISMANBuckee and ’t Hart said the

challenges ran the gamut from adeep freeze as FEX was barging

equipment to the Aklaq site,followed by a warm spell that

affected the tundra, thenanother cold snap.

PETROLEUM NEWS • WEEK OF MAY 14, 2006 17

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

ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARSBusiness Spotlight

AAce TransportAcuren USA (formerly Canspec Group). . . . . . . . . . . . . . . . . . 3AeromedAES InspectionAES Lynx EnterprisesAgriumAir Liquide. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Air Logistics of AlaskaAlaska Airlines CargoAlaska Anvil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Alaska Coverall. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Alaska DreamsAlaska Frontier ConstructorsAlaska Interstate ConstructionAlaska Marine LinesAlaska Railroad Corp.Alaska Rubber & Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Alaska Steel Co.Alaska TelecomAlaska Tent & TarpAlaska TextilesAlaska Trucking AssociationAlaska West ExpressAlliance, TheAlpine-MeadowAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Arctic ControlsArctic FoundationsArctic Fox EnvironmentalArctic Slope Telephone Assoc. Co-op.Arctic StructuresArctic Wire Rope & SupplyASRC Energy Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Engineering & Technology. . . . . . . . . . . . . . . . . . . . . . . 2Operations & Maintenance . . . . . . . . . . . . . . . . . . . . . . 2Pipeline Power & Communications . . . . . . . . . . . . . . . 2

AutryRaynes Engineeringand Environmental Consultants

Avalon Development

B-FBadger ProductionsBaker HughesBombay Deluxe RestaurantBond, Stephens & JohnsonBrooks Range SupplyBW TechnologiesCapital Office SystemsCarlile Transportation Services. . . . . . . . . . . . . . . . . . . . . . . . . 7Chiulista Camp Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Computing AlternativesCN AquatrainCONAM ConstructionColvilleConocoPhillips AlaskaConstruction Machinery IndustrialCoremongersCrowley AlaskaCruz ConstructionDowland-Bach Corp.Doyon DrillingDoyon LTDDoyon Universal ServicesDynamic Capital ManagementEngineered Fire and SafetyENSR Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Epoch Well Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9ESS Support Services WorldwideEvergreen Helicopters of AlaskaFairweather Companies, TheFlowline AlaskaFriends of Pets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Frontier Flying Service

G-MGreat Northern Engineering. . . . . . . . . . . . . . . . . . . . . . . . . . 18Great NorthwestHawk Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5H.C. PriceHilton AnchorageHoladay-ParksHorizon Well LoggingHotel Captain Cook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Hunter 3-DIndustrial Project ServicesInspirations

Jackovich Industrial & Construction Supply . . . . . . . . . . . . . 10JEMS Real EstateJudy Patrick PhotographyKenai AviationKenworth AlaskaKuukpik Arctic CateringKuukpik/VeritasKuukpik - LCMFLasser Inc.LCMFLCMF - Barrow Village Response Team (VRT)Lounsbury & AssociatesLynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Mapmakers of AlaskaMarathon OilMarketing SolutionsMayflower CateringMI SwacoMWHMRO Sales

N-PNabors Alaska Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11NANA/Colt EngineeringNatco CanadaNature Conservancy, TheNEI Fluid TechnologyNMS Employee LeasingNordic CalistaNorth Slope Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Northern Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Northern Transportation Co.Northland Wood ProductsOffshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oilfield ImprovementsOilfield TransportPacific Power ProductsPDC Harris GroupPeak Oilfield Service Co.Penco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Perkins CoiePetroleum Equipment & Services . . . . . . . . . . . . . . . . . . . . . 13Petrotechnical Resources of AlaskaPGS OnshorePipe Wranglers CanadaProComm AlaskaPrudhoe Bay Shop & StoragePTI Group

Q-ZQUADCORain for RentResidential MortgageSalt + Light CreativeScan HomeSchlumberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Seekins FordSpenard Builders SupplySTEELFAB. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Superior Machine and Welding3M Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Tire Distribution SystemsTOTETotem Equipment & SupplyTrinity Inspection Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Tubular Solutions AlaskaUAA Department of EngineeringUdelhoven Oilfield Systems Services . . . . . . . . . . . . . . . . . . . 3Unique MachineUnitech . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Univar USAUsibelliU.S. Bearings and DrivesVECOWelding ServicesWesternGecoWiggy's-AlaskaWSI-Total SafetyXtel InternationalXTO Energy

Clint Zaverl, Construction Manager

By PAULA EASLEY

Peak OilfieldServices

Clint Zaverl is contracted to ASRCEnergy Services E&P as a constructionmanager for FEX LLC, an Alaska sub-sidiary of Calgary-based TalismanEnergy. Talisman has numerous leaseholdings in the Northwest NationalPetroleum Reserve-Alaska. Its firstdrilling season was just completedand next season’s drilling operationsare being planned. The vast distancebetween the project area and estab-lished fields at Prudhoe and Kuparukhas posed challenges requiring exten-sive planning with numerous contrac-tors.

This is Clint Zaverl’s fifth yearworking for Peak. He has also workedin civil construction of roads, high-ways and runways as well as miningon the Yuba Bucket Dredges in Nome,Alaska. He enjoys drawing, reading,snow machining, and spending timeat the family’s Horseshoe Lake cabin.

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

FOR

RES

T C

RA

NE

CO

URT

ESY

PH

OTO

Alan Renshaw, Chief Engineer

Usibelli Coal Mine Inc.

Usibelli Coal Mine is a world-classAlaska mine using state-of-the-artengineering and equipment. Its safetyprogram is one of the best in thecountry. So is its environmentalrecord and reclamation program thatrestores all the ground disturbed inthe mining process to as good as, orbetter than, it was originally.

Alan Renshaw has worked forUsibelli in Healy 16 years and is pro-fessionally certified in engineeringand land surveying. He graduatedfrom the University of AlaskaFairbanks. He and wife Amber havethree boys, ages 16, 2 and 1, withanother surprise son on the way.Alan’s life goal is to be all he can befor the family — and to have nomore kids, now that he has discov-ered what causes them.

tion. He had a more serious threat. The Department of Energy has begun a

study looking at a federal corporation tobuild a gas pipeline from the North Slope,Murkowski said, reminding his audiencethat when Congress passed enabling leg-islation for the Alaska North Slope gaspipeline it directed the Secretary ofEnergy to conduct a study of an alterna-tive if an application for pipeline con-struction hadn’t been filed with theFederal Energy Regulatory Commissionwithin 18 months of enactment of the leg-islation. That was in 2004, he said, andthat clock is running. The study is underway, Murkowski said, in the pre-scopingphase to establish a staffing and fundingframework.

The enabling legislation passedCongress Oct. 11, 2004. It included a pro-vision directing the Secretary of Energyto “conduct a study of alternativeapproaches to the construction and opera-tion of such an Alaska natural gas trans-portation project,” if no application was

received within 18 months. Congress saidthe study was to consider establishing afederal government corporation to con-struct an Alaska natural gas transportationpipeline. (See story in Oct. 17, 2004,issue of Petroleum News.)

Murkowski said he doesn’t think any-one wants to see federal ownership of thepipeline, but if the contract is not con-summated, if the state and producersdon’t come to agreement and construct aline, “these issues could be taken awayfrom us and we could lose control of thedestiny of the State of Alaska.”

The carrot is the benefits a gas linecould bring to the state, he said.

Murkowski described the Alaska gaspipeline as “a real bridge to the future ofAlaska,” and told legislators “that’swhat’s so exciting about this Legislature.”

The administration has been negotiat-ing the contract for two years, the gover-nor said, calling it “a long road to get tothe milepost where we are today.” Butthere are more miles to go, he said, tellinglegislators “we must do what’s right forAlaska,” adding that the gas pipeline “isnot a partisan issue.”

Alaskans expect this administrationand this Legislature to get this job done,Murkowski said. After 30 years of wait-ing the economics support this projectnow and they didn’t before, he said,telling legislators their decisions wouldhave a “profound and lasting impact” andassuring them they “should have all thetime you need to get the job done.”

A 10-day reviewThe administration began a 10-day

review of the project for legislators thatafternoon at Centennial Hall in Juneau.

Administration consultant Pedro vanMeurs told legislators the “almostunimaginable” size of the Alaska gaspipeline project “may create large profitsand government revenues but also haspotential for risks.”

Van Meurs talked about barrels of oilequivalent for the project, which allows

comparison with both oil and gas projectsworldwide, and said there is only oneproject in the world that is larger, theKashagan oil field in the Caspian Sea. ButKashagan is estimated to cost $16-$17billion, while the Alaska gas pipeline isestimated at some $19 billion or $27 bil-lion if the project has to be built toChicago.

Because other projects, like Kashagan,involve a larger government royaltyshare, the Alaska project provides thecompanies with the largest bookablereserve in the world on a single project,he said, and provides the largest total netcash flow in the world.

But the risks are huge: under a low gasprice of $3.50 per million Btu and a 50percent cost overrun “this project has dis-mal economics,” he said, and woulddestroy corporate value of all three partic-ipants. If the project does not succeed,ConocoPhillips’ stock value could dropand it could become a takeover target.

The availability of takeaway gas linecapacity in Alberta is a particular risk, hesaid. The estimate of available gas capac-ity has changed almost every year, hesaid, and depends on oil sands develop-ment — if that slows down gas used inthose projects would have to go downexisting lines — and exploration success.Success in finding gas in western Canadawould also add to volumes that have togo down existing pipelines, he said.

Cost overrun is the biggest risk facingthe project, he said, noting Shell had a100 percent cost overrun at Sakhalin II.Cost overruns are common on long lead-time cumbersome projects, van Meurssaid.

At low prices the net present valuewould be $2.5 billion for the project; “ifthere is a 50 percent cost overrun, netpresent value approaches minus $3 bil-lion,” he said. ●

18 PETROLEUM NEWS • WEEK OF MAY 14, 2006

James Connaughton, and U.S. undersec-retary of state for global affairs, PaulaDobriansky to explore ways for the twocountries to co-operate in cleaning upNorth America’s air and water.

Ambrose: AP6 ‘very interesting’Ambrose said that although the U.S.

officials did not ask Canada to join theAP6, she views the partnership as a “veryinteresting group. … They’re doingthings that we’re very interested in partic-ipating in further down the road.”

Among other things, the AP6 presentsa unique opportunity for Canada to lookat investments in cleaner technology,” shesaid.

Otherwise, Ambrose said the Harpergovernment will remain in Kyoto,although the targets to reduce emissionsare unrealistic.

Later, under fire from opposition par-ties in Parliament, she declined to talkabout joining the AP6, saying the focus ison a “made-in-Canada” plan.

She said the Kyoto plan could haveseen Canada spend an average C$600 perfamily on international emissions credits,where she wants a plan that invests inCanadian solutions, technology and com-munities.

“The only model I’m interested in isone that puts Canadians first,” Ambrosesaid.

She is now developing a strategy forthe second phase of Kyoto, beyond theinitial 2008-2012 period, when Canada ispledged to cut emissions by 6 percentbelow 1990 levels.

The latest government figures showemissions are actually 24.4 percent above1990 and are expected to continue to riseas fast as oil sands development gathersmomentum.

According to observers, opting out ofKyoto would take two years or more, dur-ing which time Canada could face tradesanctions from Kyoto signatories or paybillions of dollars to buy greenhouse gas

credits.

Environmentalists skepticalWhile the government wrestles with

its options, environmentalists are skepti-cal about the administration’s commit-ment to tackling climate change.

Sierra Club spokesman John Bennettsaid the AP6 “relies entirely on voluntaryaction” when Canada should be workingon a program that has “real targets.”

Scientists are worried that even ifpromising research avenues were avail-able, federal funds will dry up.

The Harper government’s commitmentto pursuing its “made-in-Canada” pathwas reinforced when Flaherty withdrew apledge by the previous government tospend C$538 million defraying the costsof Ontario actions to fight climate change.

The funding was intended to helpOntario phase out its high-polluting, coal-fired power stations and lower green-house gas emissions by 30 million metrictons in 2009, the equivalent of taking 7million cars off the road.

Ontario Environment Minister LaurelBroten said her province will not waver inits determination to close coal-fired gen-erating stations — a course that mostobservers believe will require morenuclear power plants.

Currently, 50 percent of Ontario’selectricity comes from its nuclear opera-tions, which have involved massive costoverruns (one plant that was supposed tocost C$2.5 billion ended up at C$14.3 bil-lion) and expensive refurbishments.

In another blow to Kyoto, Ottawa axeda C$500 million, five-year program tohelp low-income households cope withhigh energy costs and cut greenhouse gasemissions.●

Shell Canada leader touts emissions tradingWhile the Canadian government is pulling back from the Kyoto Protocol to pon-

der its next move, one petroleum industry leader is growing tired of the uncertainty.Shell Canada Chief Executive Officer Clive Mather is pressing for industry and

government to join forces and accept the climate change treaty.In two speeches within a week, Mather has called for action on several fronts.“If we waited for everyone to sign up (to Kyoto), frankly, it would be too late,” he

told a group of business leaders in Toronto on May 5.A week earlier, at Shell Canada’s annual meeting, Mather proposed a domestic

greenhouse gas emissions trading market along with construction of “public infra-structure” to collect carbon dioxide from sources such as refineries and use it inenhanced oil recovery projects.

“Especially here in Canada, we must encourage bold initiatives which lever newtechnologies,” he said, arguing technology will play a critical role in bridging the gapbetween traditional hydrocarbon supplies and new fuels that “we can expect tobecome mainstream over the next half century.”

Conceding he has a “personal passion” for the issue of climate change, Mather hasbeen quietly campaigning for domestic emissions trading that would allow compa-nies to sell credits for eliminating greenhouse gases.

There would be rewards for those who exceeded their reduction targets, or devel-oped technologies to produce cleaner energy.

Mather, admitting Kyoto has its limitations, said he would also welcome any newinitiatives that would enable the United States and China to play leading roles in thesearch for solutions.

He also said Shell Canada is prepared to lead by example, noting the company’sown operations are close to meeting the Kyoto target to lower their 1990 emissionsby 6 percent.

Penn West Energy Trust Chief Executive Officer Bill Andrew has also urged theAlberta and Canadian governments to support carbon dioxide sequestration forenhanced oil recovery.

However, Mather said storing carbon dioxide does not “deliver commercialreturns” and needs government financial help as part of a collective effort to makeCanada a “technology showcase to the world.”

—GARY PARK

continued from page 1

KNOTS

continued from page 1

CONTRACTAdministration consultant Pedro

van Meurs told legislators the“almost unimaginable” size of theAlaska gas pipeline project “may

create large profits andgovernment revenues but also has

potential for risks.”

ducers and explorers and the public.Resources and Finance committees inboth the House and Senate wrote, andamended, committee substitutes for theadministration bill, and both House andSenate passed the bill, but not the sameversion.

The House voted shortly after 3:30a.m. May 9, the last day of the session,passing a committee substitute for the billthe Senate passed April 25. But there weretoo many changes for the Senate — andno time for a conference committee towork out the differences.

So the PPT, needed to complete thedraft gas line fiscal contract that wasreleased for public comment May 10, isexpected to become another special ses-sion order of business for the Legislature— which started what is expected to beonly its first special session May 10.

Political landminesWhen Gov. Frank Murkowski

addressed the Legislature on the first dayof the special session he said politicaldynamics are the reason legislative bodiesrarely have the chance to change tax law.The transfer of wealth is fraught withpolitical landmines, the governor said,noting that the last change, a relativelymodest adjustment of the economic limitfactor, occurred in 1989 in the aftermathof the Exxon Valdez oil spill.

Murkowski said his aggregation ofNorth Slope satellites last year, a $200million tax increase, was “not very popu-lar.”

The reason this administration and thisLegislature have the opportunity to makemajor changes in the oil tax is because ofthe gas line, he said: with development ofa gas line a tax change can take place.

“We all know after last night we haveto revisit the PPT,” the governor said,telling legislators that the state is losingmoney every day under the existing pro-duction tax system.

Work began in FebruaryThe Alaska Legislature began working

on the administration’s proposed rewriteof the state’s oil and gas production tax,the production profits tax or PPT on Feb.22. The bill had referrals to Resources andFinance committees in both houses.

The Senate was the first to pass themeasure, and House Finance reworkedthat bill, returning to the governor’s pro-posed 20 percent tax rate and 20 percentcredit, but including the progressivity fac-tor which has been in all the committeesubstitutes.

The House Finance progressivity sur-charge was based, like a Senate Financesdraft, but not the final version the Senatepassed, on the net, automatically includingincreases in the cost of production in thecalculation.

Debate on the House floor beganSunday, May 7, and continued Mondayevening May 8, running overnight intoMay 9, the last day of the session, beforetying up shortly after 3:30 a.m. with a 29-10 vote to move the bill.

The tax rate was raised to 21.5 on theHouse floor, but attempts failed to raisethe trigger point for the progressivity sur-charge, which House Finance set at aNorth Slope netback of $35.

Senate floor debate began on the billaround 7 p.m. May 9, just five hoursbefore the midnight end of session, withdebate 4 to 1 against the bill. The vote was10-10, defeating adoption. Senate leader-ship tried again shortly before 11 p.m., butcould only get nine votes to rescind theprevious vote. The PPT was not brought

up again when the Senate returned justbefore midnight to vote on the capitalbudget.

House debate lengthyThe House floor debate May 7-9 was

wide-ranging, and started with an amend-ment by Rep. Harry Crawford, D-Anchorage, to dump the profits-based taxin favor of a revision of the existing sev-erance tax on the gross, an amendmentwhich was defeated 28-12.

Anchorage Democratic Reps. EthanBerkowitz, the House minority leader, andEric Croft, both candidates for governor,led the charge against the PPT, concludingwith a proposal early in the morning May9 that a vote on PPT be delayed until thegas fiscal contract was public.

Current high oil prices have frequentlybeen the basis of discussion in commit-tees, with legislators pushing progressivi-ty options to increase government share athigh oil prices, but on the House floorthere was a lot of concern expressed bymembers of both parties about what wouldhappen under PPT if oil prices returned toa range of prices in the $20s, normalbefore the recent price run-up.

There was a proposal, which wasdefeated, to insert a floor in the PPT toprotect the state at low oil prices.Administration and legislative consultantshave said all along that when you replacea regressive system with a progressivesystem the proportion of the government’stake increases at high prices but may dropto zero at low oil prices: if the companieshave no profit, there is no profit to tax,although the administration testified thatone good year would make up for severalbad years.

Senate: 25 percent?Two Republican senators who voted

against the House bill, Gary Wilken ofFairbanks and Tom Wagoner of Kenai,

both said they wanted to see a 25 percenttax. The version the Senate voted out onApril 25 included a 22.5 percent tax.

Wilken said he was aligning himselfwith the consultants who said a 25 percenttax rate wouldn’t deter investment inAlaska.

He said the Department of Revenueidentified 15 changes the House made inthe Senate’s bill, and complained that theversion the House voted on was cobbledtogether in the middle of the night, ques-tioning whether the Senate even knewwhat was in the bill.

Sen. Hollis French, D-Anchorage, hadearlier criticized the way the House han-dled amendments on the floor and said hewouldn’t make an oil tax decision untilhe’d seen the gas contract. French earliersued the administration to get release ofthe gas contract.

Wagoner, like Wilken, objected to theadvertising campaign around the PPT, andsaid he wished there was time to take the

bill to a conference committee and workout differences between the House andSenate. He said he thought the tax changewas needed, but couldn’t vote for the billuntil there was more work done on it.

Sen. Bert Stedman, R-Sitka, whoworked on the bill in both SenateResources and Senate Finance, was theonly senator to speak in favor of the bill,noting that while the House tax rate waslower at 21.5 percent, with the House ver-sion of progressivity the state would dobetter at oil prices above $40 than underthe Senate version, and as prices advancethe state is “substantially better off” underthe House version.

Stedman also spoke in favor of a pro-gressivity surcharge on the net, whichtakes into account the cost of extraction.The cost of extraction will go up overtime, he said, and it’s important that thetax structure take that into account if it isgoing to stand up over time.

—KRISTEN NELSON

PETROLEUM NEWS • WEEK OF MAY 14, 2006 19

continued from page 1

OIL TAX

20 PETROLEUM NEWS • WEEK OF MAY 14, 2006