Petroleum News ebook

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Quebec sets continent’s first carbontax on hydrocarbon producers

Vol. 12, No. 24 • www.PetroleumNews.com Published weekly by Petroleum Newspapers of Alaska Week of June 17, 2007 • $1.50

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

● N A T U R A L G A S


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

4 Two Prudhoe gas owners looking at AGIA options:BP, Exxon express some interest in submitting North Slope gas line bids

6 Future is unconventional: Oil sands key to bolsteringAlberta's output; bitumen expected to account for 86% by 2016

7 Final chapter in CIGGS regulation? Following RCAacceptance of gas settlement, Marathon, Chevron apply for certificate

Senator visits geothermal project

Pictured here is Bernie Karl, owner of Chena Hot Springs Resort, andSen. Lisa Murkowski, R-Alaska, who recently visited the InteriorAlaska resort, which is home to the nation’s first low-temperaturegeothermal renewable electrical project. Diesel generators burnedabout 365,000 gallons of fuel annually until Karl turned to the hotsprings for power. The system, which powers most of the resort, isdubbed the “Chena Chiller” because it operates under cooler tem-peratures. Murkowski is co-sponsor of the National GeothermalInitiative Act of 2007, which calls for 20 percent of the nation’s elec-trical output to come from geothermal sources by 2030.

CO

URT

ESY

PH

OTO BP making changes

Brock gives Alaska legislators answers about what went wrong at Prudhoe

By KRISTEN NELSONPetroleum News

he reality of the past and the hope of thefuture collided June 7 when TonyBrock, head of BP Exploration(Alaska)’s new technical directorate,

talked to the House Resources Committeeabout how BP is moving ahead to fix corro-sion problems at Prudhoe Bay, both with anew oil transit line system and with organi-zational changes.

A number of the committee members, as well asother legislators who sat in, were more interested insome three dozen documents, including internal BPmemos dating back a number of years, which focusedon cost-cutting issues at the Prudhoe Bay field.

Brock, who arrived in Alaska in August to head up

the technical directorate, answered somequestions on terminology used in the docu-ments, but said he was not in a position tocomment on what went on in the past.

The committee’s concern was two-pronged: was cost cutting in the pastresponsible for the corrosion discovered lastyear which resulted in the shutdown of halfof Prudhoe Bay for several months and howwould the replacement oil transit lines BP isin the process of building impact state rev-

enues under the new Petroleum Profits Tax, whichpassed the Legislature just as the second Prudhoe Bayleak of the year was being discovered and BP wasannouncing a field shutdown.

Referring to presentation materials which Brock

BP’s Tony Brock

T

see CHANGES page 13

Don’t leave it to FERCPalin on right track, Murkowski gas line contract left important details up to feds

By KRISTEN NELSONPetroleum News

on’t leave anything to FERC. Fundthe state’s efforts on the gas pipeline.Get gas for Alaskans. Get access tothe line right. Get the tariff rates right.

And have a very good reason if you decideto give control of the gas pipeline to a fewmajor producers, because that will have animpact on access, an impact on rates and animpact on the State of Alaska’s power tomanage and tax its own resources.

Those are the lessons attorney RobinBrena sees for the gas line after more than20 years of being in the trenches on pipelinerate litigation, which he shared with aHouse Resources Committee hearing on June 7 inAnchorage.

A partner in the law firm of Brena, Bell& Clarkson, Brena said he is 100 percent infavor of a gas pipeline, but said Alaska’s oiland gas resources are transported throughpipelines with no competition. These aremonopoly-controlled lines, he said, andeconomic regulation of these noncompeti-tive pipelines must meet two basic goals:fair access and just and reasonable rates.

Getting access and rates right, he told thecommittee, will maximize the state’sincome from its hydrocarbon resources bybringing in more E&P companies to devel-op more oil and gas, which in turn willdeliver more royalty and severance taxesinto state coffers. Fair access and rates willalso yield more value-added manufacturing

and jobs in Alaska.

DLong-time tariff liti-gator Robin Brenasaid Murkowski’sgas line contract lefta lot of decisions toFERC. The detailswere not addressed,and that’s where themoney is, he said.

Ownership out of questionCabinet minister suggests Mac gas pipeline project may have to be ‘reinvented’

By GARY PARKFor Petroleum News

he Canadian government has no intention ofbridging the cost escalation gap between theC$5 billion Mackenzie Gas Project when itwas studied in 2000 and the revised budget of

C$16 billion, but it does want gas from theCanadian North delivered to market, Indian andNorthern Affairs Minister Jim Prentice said.

In what represents the most declarative state-ment yet by the government of Prime MinisterStephen Harper, he stated “categorically that wehave no interest in owning the pipeline ourselves

– this is not a business at which the government ofCanada has distinguished itself.”

Prentice said the government would not subsi-dize the Mackenzie Gas Project.

“If the project is not viable as a private sectorinvestment, then it should not proceed,” he toldthe Canadian Gas Association.

But, without entering the realm of a publicequity stake, he said the government is open tonegotiating:

• Acceptance of royalties in kind.• A royalty regime that is consistent with a proj-

ect to open exploration and development of

see FERC page 14

T

see OWNERSHIP page 15

Consumers should bearMackenzie gas line costs

The Canadian Gas Association wants consumers, not thefederal government to carry the financial burden of projectssuch as a natural gas pipeline from the Mackenzie Delta.

Association President Mike Cleland said there should beno federal incentives or subsidies to advance the developmentof oil, natural gas or electricity. His remarks were in responseto recent comments by ExxonMobil Chief Executive OfficerRex Tillerson who said that he doubted the Canadian govern-ment could create “enough room in the fiscal structure” tomake the Mackenzie Gas Project economic.

Cleland endorsed the Conference Board of Canada’s callfor the government to establish a “long-term vision and strat-

Icebreakers head toAlaska for Shell

OFFSHORE SHIPPING ONLINE saidJune 11 that Finstaship had reported thedeparture of the icebreaker Fennica fromNorway for the northern coast of Alaska.

The multi-purpose vessel is expectedto arrive off Prudhoe Bay in late July.

Fennica and Tor Viking II, theNorwegian icebreaker chartered byFinland-based Finstaship, will provideShell Offshore with Arctic offshore services, OSO reported.OSO said Tor Viking II left for Alaska from Stavanger,Norway on May 15, “visiting first Port Fourchon, Louisiana

see COSTS page 14

see INSIDER page 14

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

2 PETROLEUM NEWS • WEEK OF JUNE 17, 2007

GOVERNMENT

LAND & LEASING

NATURAL GAS

7 Final chapter in CIGGS regulation?

Following the Regulatory Commission of Alaska'sacceptance of the Cook Inlet Gas Gathering Systemsettlement agreement, Marathon and Chevron have applied for a certificate to operate the pipeline system as a common carrier

8 Naknek looks to geothermal energy

SW Alaska electric co-op plans seismic survey, deepdrilling to find energy source for Bristol Bay region, Shell lending a hand

6 Future is unconventional

Oil sands key to bolstering Alberta's output; bitumen expected to account for 86% by 2016

11 Newfoundland ready for test of wills

Williams: Hebron partners won't get better offer; set to demand equity stake of at least 5 percent in all new offshore projects

EXPLORATION & PRODUCTION

ON THE COVERBP making changes

Tony Brock gives Alaska legislators answersabout what went wrong at Prudhoe

Ownership out of question

Cabinet mininster suggests Mac gas pipeline project may have to be ‘reinvented’

Don’t leave it to FERC

Palin on right track, Murkowski gas line contract left important details up to feds

8 Alaska's gas team works Washington, D.C.

5 Government pressed to take more active role

5 Potential Alaska state and federal oil and gas lease sales

4 Two Prudhoe gas owners looking at 'options' under AGIA

4 Canadians fret over future energy supplies

PIPELINES & DOWNSTREAM

PUBLIC OPINION11 Noble scores another deepwater discovery

15 Mackenzie Gas Project review panel needs more time

13 Slemons: changing direction a challenge

14 BP applies to expand Prudhoe Bay pads

14 Quebec imposes continent's first carbon tax

ALTERNATIVE ENERGY6 CBM drilling starts at Wainwright

9 Unalaska takes the next step

Senator visits geothermal project

Consumers should bear Mac gas line costs

1 Icebreakers head to Alaska

OIL PATCH INSIDER

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PETROLEUM NEWS • WEEK OF JUNE 17, 2007 3

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

Alaska Rig StatusNorth Slope - Onshore

Akita Drilling Ltd.Dreco 1250 UE 63 (SCR/TD) Racked in Deadhorse Anadarko

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point MPS-COHO-01 BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 1J-158 ConocoPhillipsDreco 1000 UE 16 (SCR/TD) Workover Prudhoe B-15 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD4-302 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk 1J-120 ConocoPhillipsTSM 7000 Arctic Fox #1 Stacked in Yard Pioneer Natural Resources

Arctic Wolf #2 Racked at Cape Simpson FEX

Kuukpik 5 Stacked in Deadhorse Available

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES Prudhoe Bay F-09B BPMid-Continental U36A 3-S Prudhoe Bay GPB 11-18 BPOilwell 700 E 4-ES (SCR) Prudhoe Bay GPB DS02-29C BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay DS 12-12 BPDreco 1000 UE 9-ES (SCR/TD) Orion V-222i BPOilwell 2000 Hercules 14-E (SCR) Stacked AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked AvailableOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableOIME 1000 19-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Oliktok Point OPi2 AnadarkoEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Stacked

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay well DS2-12b BPSuperior 700 UE 2 (SCR/CTD) Kuparuk well 1B-15a BPIdeco 900 3 (SCR/TD) Kuparuk well 2L-327 ConocoPhillips

North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E Stacked

Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Stacked at Nikiski Available

Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 KBU 34-6 Marathon

Nabors Alaska DrillingNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Swanson River SRU 41-05 Chevron

Cook Inlet Basin – Offshore

Unocal (Nabors Alaska Drilling labor contractor)Not Available

XTO EnergyNational 1320 A Platform A no drilling or workovers at present XTONational 110 C (TD) Idle XTO

Alaska Interior

Cudd Pressure ControlCudd 340k Jack Unit Workover Ahtna #1-19 Rutter and Wilbanks

Mackenzie Rig StatusCanadian Beaufort Sea

Seatankers (AKITA Equtak labor contract)SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Devon ARL Corp.

Mackenzie Delta-OnshoreAKITA EqutakDreco 1250 UE 62 (SCR/TD) Rig Racked in Inuvik, NT Schlumberger

Modified National 370 64 (TD) Racked in Inuvik, NT Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of June 14, 2007.

Active drilling companies only listed.

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

This rig report was prepared by Alan Bailey

Baker Hughes North America rotary rig counts*June 8 Jne 1 Year Ago

US 1,760 1,774 1,661Canada 226 136 443Gulf 78 80 92

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

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

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Kay Cashman PUBLISHER & EXECUTIVE EDITOR

Mary Mack CHIEF FINANCIAL OFFICER

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Heather Yates OFFICE MGR./CIRC. BOOKKEEPER

Shane Lasley CIRCULATION DIRECTOR

Steven Merritt PRODUCTION DIRECTOR

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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

Judy Patrick Photography CONTRACT PHOTOGRAPHER

Mapmakers Alaska CARTOGRAPHY

Forrest Crane CONTRACT PHOTOGRAPHER

Tom Kearney ADVERTISING DESIGN MANAGER

Dee Cashman CIRCULATION REPRESENTATIVE

Petroleum News and its supple-ment, Petroleum Directory, are

owned by Petroleum Newspapersof Alaska LLC. The newspaper ispublished weekly. Several of theindividuals listed above work forindependent companies that con-

tract services to PetroleumNewspapers of Alaska LLC or are

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OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 12, No. 24 • Week of June 17, 2007

Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518(Please mail ALL correspondence to:

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Two Prudhoe gasowners looking at‘options’ under AGIA

By KAY CASHMANPetroleum News

efore the Alaska GaslineInducement Act was signed intolaw by the governor on June 7, thethree major Prudhoe gas owners

said they would not submit a bid tobuild a pipeline from the North Slopeunder AGIA as it was written.Representatives from BP,ConocoPhillips and ExxonMobil all tes-tified before the state Legislatureagainst the bill, saying AGIA did notprovide for a commercially viable proj-ect; specifically that it was too “pre-scriptive” — i.e. rigid and did not allowthem enough options.

Not giving upThe position of two of the companies

has since shifted, albeit slightly, aboutsubmitting a bid to build the pipelineunder AGIA.

Petroleum News recently asked BP,ConocoPhillips and ExxonMobil if theyplanned to submit bids, together or sin-gularly, for the gas line project.

BP’s press officer Steve Rinehartresponded: “We are very disappointedthat BP cannot submit a bid that con-forms to the requirements of AGIA,”which suggests BP is looking at puttingin a bid, but not necessarily one thatconforms to AGIA’s guidelines.

What’s the likelihood of BP submit-ting a bid?

“We have not given up, and will con-tinue to seek ways to help make thisproject happen. We are considering whatoptions may be open to us, but at thispoint can’t speculate,” Rinehart said.

Exxon, too, appears to be consideringits options. Its response to the first and

second question was simply: “We areevaluating our options,” per Exxon’supstream media advisor Susan Reeves.

ConocoPhillips would not respond toeither question, although Brian Wenzel,vice president of Alaska North Slopegas development for ConocoPhillipsAlaska, did offer criticism of AGIA,saying it had serious flaws.

MidAmerican: Free to make proposals

Pipeline giant MidAmerican, howev-er, said AGIA was not prescriptive. KirkMorgan told House Finance May 3 thatparties were free to make proposals andthe Federal Energy RegulatoryCommission was free to authorize themunder the legislation: “To put it anotherway, if a party thinks it has a superiorproposal, nothing in AGIA stops it fromputting that proposal in writing,” saidMorgan. He is president ofMidAmerican subsidiary Kern RiverGas Transmission Co., and has said hiscompany would very likely submit a bidunder AGIA.

Alaska Gov. Sarah Palin raisedanother option on June 6. She said the“beauty of AGIA” was that it “lets usconsider building this transportationinfrastructure … ourselves.”

State officials had said they hope tohave a request for applications out forbidders on July 2. ●

“If a party thinks it has a superiorproposal, nothing in AGIA stops it

from putting that proposal inwriting.” –Kirk Morgan, president ofMidAmerican subsidiary Kern River Gas

Transmission Co.

B

PUBLIC OPINIONCanadians fret over future energy supplies

A new poll shows that 82 percent of all Canadians are concerned – 44 per-cent of them “very concerned” — about their nation’s future energy supplies.

Conducted by Ipsos-Reid in late May, the poll found the highest levels ofconcern in Ontario and Atlantic Canada, where 48 percent were very concerned,dropping to 40 percent in Saskatchewan and Manitoba and 37 percent inQuebec.

Half of those polled strongly agreed that the federal, provincial and territori-al governments should create a common set of rules to standardize how energyresources are developed, transported and sold.

The support for regulatory harmonization ranged from a high of 56 percentin Quebec, which produces no oil or natural gas, to 46 percent in Alberta and 45percent in British Columbia, two of the leading producing regions.

Asked if progress could be made toward a cleaner environment by increas-ing natural gas supplies, 22 percent strongly agreed and 43 percent somewhatagreed, while 14 percent somewhat disagreed and 4 percent strongly disagreed.

—GARY PARK

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LAND & LEASINGPotential Alaska state and federal oil and

gas lease salesAgency Sale and Area Proposed Date

DNR Beaufort Sea Areawide Oct. 24, 2007

DNR North Slope Areawide Oct. 24, 2007

BLM NE NPR-A 2007

BLM NW NPR-A 2007

MMS Sale 193 Chukchi Sea Feb. 6, 2008

DNR Alaska Peninsula Areawide February 2008

DNR North Slope Foothills Areawide February 2008

DNR Cook Inlet Areawide May 2008

DNR Beaufort Sea Areawide October 2008

DNR North Slope Areawide October 2008






MMS Sale 209 Beaufort Sea 2009

MMS Sale 211 Cook Inlet 2009






MMS Sale 212 Chukchi Sea 2010

MMS Sale 214 North Aleutian basin 2011

MMS Sale 217 Beaufort Sea 2011

MMS Sale 219 Cook Inlet 2011

MMS Sale 221 Chukchi Sea 2012

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

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

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

This week’s lease sale chartsponsored by:

PGS Onshore, Inc.

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GOVERNMENTGovernment pressed to take more active role

The Canadian Energy Pipeline Association is pressing the Alberta government to bemore proactive in developing a policy to manage energy growth.

Failure by the province to become more engaged could mean projects will bedelayed and more oil will be stranded ifpipelines are not built by 2009 when existingpipelines will be operating at capacity, associ-ation president David MacInnis said.

He said the pressure is on Alberta to “devel-op an approach that is far more comprehensiveand addresses the fundamentals and I don’tknow if they have the game plan in place.”

MacInnis told the Financial Post that boththe administration of Ralph Klein and the cur-rent premier Ed Stelmach are “behind the eightball” at a time when companies need decisionsto proceed with C$20 billion worth ofpipelines to carry oil sands production to theUnited States by 2014. The pipeline association is calling for an “energy policy devel-opment framework” that requires a broader view of energy development and involvesgovernment, rather than the traditional hands-off style favored by industry.

But MacInnis said the marketplace is “not a perfectly functioning beast,” but neitherdoes he believe that government can solve all problems.

He said his own association is not troubled by government involvement because itis already long-accustomed to the regulatory function played by federal andprovincial governments.

—GARY PARK

Failure by the province tobecome more engaged could

mean projects will be delayedand more oil will be stranded ifpipelines are not built by 2009when existing pipeline will be

operating at capacity,association president David

MacInnis said.

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itumen production is on a roll, whileconventional crude and natural gas areheaded in the other direction – all fur-ther reinforcement of a trend that start-

ed to take shape in the early 1990s inAlberta and is gathering pace.

Canada’s largest energy storehouse is, toall intents, heavily dependent on its uncon-ventional oil and gas supplies to meetdemand, the province’s Energy andUtilities Board (EUB) said in its 2007-2016outlook report.

The regulator estimates Alberta can hikeits crude oil and equivalent production to3.5 million barrels per day by 2016, pro-vided nothing extreme occurs to derailexpansion of the oil sands.

The board makes no mention of theimpact from a possible hike in Alberta gov-ernment’s royalties, or higher costs stem-ming from federal and provincial environ-mental regulations.

Crude bitumen output surpassed con-ventional crude in 2001 and has maintaineda relentless growth trend ever since, totaling1.25 million barrels per day last year, up 18percent from 2005,while conventionalcrude slipped 5 percent to 543,700 bpd, put-ting bitumen ahead of Alberta’s traditionalsource by 231 percent.

Non-upgraded bitumen and syntheticcrude is expected to climb to 3.1 millionbpd by 2016, rising from 62 percent ofoverall production in 2006 to 86 percent.

The EUB offers no hope of a reversal inthe downward path for conventional crude,with large pools becoming increasingly dif-

ficult to find.It said 1,956 wells were placed on pro-

duction last year, up 4 percent from 2005,and expects that number will remain around2,000 for the rest of the forecast period,without stopping the decline in production.

Alberta exited 2006 with remainingestablished conventional crude reserves at1.6 billion barrels, down 2 percent for theyear despite additions of 171 million barrelsfrom drilling and revisions.

The ultimate potential for conventionaloil is estimated at 19.7 billion barrels, whichthe EUB said could benefit from technolog-ical advances raising the average recoveryefficiency from its current 26 percent.

Remaining established bitumen reservesare 173 billion barrels, which have beenreduced by only 3 percent since commercialoperations started 40 years ago, while theultimate potential relying on establishedtechnology is 315 billion barrels.

Finance Minister Lyle Oberg said thegrowth of oil sands production would betaken into account during the current reviewof Alberta’s royalty rates.

Indicating a shift in his thinking from anearlier support for higher royalties, he saidthe EUB statistics show that the provincewill derive higher revenues as productionclimbs.

On the conventional natural gas front,record drilling has slowed the decline ofmarketable reserves to 38.11 trillion cubicfeet (excluding 1.25 tcf of ethane and othernatural gas liquids) entering 2007, but theEUB anticipates production will declineover the forecast period by an average 2.5percent a year from last year’s 4.9 tcf – 76percent of Canada’s total production.

The trend won’t be affected by the regu-lator’s forecast of 13,000 successful wellsper year from 2007 to 2016.

Alberta ended 2006 with remaining gasreserves estimated at 40.5 tcf and an ulti-mate potential of 223 tcf, excluding coalbedmethane.

Record drilling replaced 68%Reserves from new drilling replaced 68

percent of conventional gas production lastyear, compared with 63 percent in 2005.

The pace of coalbed methane growth hasslowed after connecting 6,000 wells topipelines since 2001, with the well countforecast to decline from 2,434 in 2006 toabout 1,900 this year because of the scaled-based activities during low gas prices.

However, the EUB projects a recoveryto 2,400 wells in 2008 and 2009, followedby 2,500 a year to 2016.

Remaining established coalbed reservesare placed at 877 BCF, confined mainly to“dry” coal seams in central Alberta, butthere is no attempt to estimate the ultimatepotential, which the Alberta GeologicalSurvey (part of the EUB) has placed at 500tcf.

The EUB is not worried about Albertahaving sufficient gas supplies to meet theneeds of its core market and believes theprovince will “easily meet” its requirementsof 44 percent of total output by 2016.

But it warns that volumes available forshipment out of the province to the rest ofCanada and the United States will shrinkunder an EUB mandate that requires theprovince’s needs must be met before anylong-term removal permits are approved.

The outlook projects average WTI crudeprices of US$62 per barrel in 2007, rising toUS$69 in 2016 and average gas prices ofC$7.25 per gigajoule in 2007 and C$8.35 in2016. ●


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

Future is unconventionalOil sands key to bolstering Alberta's output; bitumen expected to account for 86% by 2016

B

ALTERNATIVE ENERGYCBM drilling starts at Wainwright

Test drilling for coalbed methane near the village of Wainwright on the ChukchiSea coast is underway. On June 11 the Alaska Oil and Gas Conservation Commissionissued a permit to drill the Wainwright No. 1 well 900 feet from the north line and2,278 feet from the east line of section 24, township 15 north and range 32 west,Umiat meridian. Drilling operations have begun, USGS co-project chief Art Clarktold Petroleum News on June 13.

The U.S. Geological Survey, the U.S Bureau of Land Management and ArcticSlope Regional Corp. are involved in drilling the well, with USGS as the operator. Thedrillers are using a lightweight drilling rig that was barged to Wainwright from thecentral North Slope last August.

“We are thinking of a total (well) depth somewhere between 1,500 and 2,000 feet,”Clark told Petroleum News in March.

The well forms part of a multi-year project to test the potential for the use ofcoalbed natural gas as an energy source in some rural Alaska villages. The projectteam drilled a test well at Fort Yukon in 2004 and another test well at Franklin Bluffsin the central North Slope in 2005.

At Wainwright coal-bearing strata probably extend down to a depth of between1,500 and 2,000 feet, although coalbed methane production is unlikely in the per-mafrost zone that probably extends from the surface down to a depth of about 1,000feet, Clark said. Whenever the well encounters a coal seam, the team will bring a coalsample to the surface to conduct a gas desorption test, he said. If the test result is favor-able, the drillers will use the hollow drill rod to pressure test the seam for parameterssuch as permeability and gas storage capabilities.

Upon completion of the drilling, if there appears to be a viable gas resource, the

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Final chapter in CIGGS regulation?Following the Regulatory Commission of Alaska's acceptance of the Cook Inlet Gas Gathering System settlement agreement,Marathon and Chevron have applied for a certificate to operate the pipeline system as a common carrier

By ALAN BAILEYPetroleum News

t’s been three years since Agrium,owner of the Nikiski fertilizerplant on Alaska’s Kenai Peninsula,first filed a complaint with the

Regulatory Commission of Alaskaregarding the unregulated operationof the Cook Inlet Gas GatheringSystem, generally known as CIGGS.But a June 7 RCA filing of an appli-cation by Marathon and Chevron fora certificate of public convenienceand necessity for CIGGS surelymarks the final chapter of the sagathat started with the Agrium com-plaint.

Marathon and Unocal (now part ofChevron) built CIGGS in the early1970s to move gas from their oil andgas fields on the west side of theCook Inlet to industrial facilities atNikiski on the east side of the inlet.At Nikiski CIGGS also connects withthe gas pipeline infrastructure on theKenai Peninsula. Marathon andChevron still own and operateCIGGS.

Under a grandfathering provisionin the Alaska Right-of-Way LeasingAct, CIGGS owners had been operat-ing the system as a private, unregulat-ed pipeline. But, in its complaint,Agrium claimed that the continuing private operation ofCIGGS was impeding the development of new gas sup-plies for industrial use at Nikiski and that the pipelineoperations contravened the Alaska Public UtilitiesRegulatory Act. RCA decided to investigate and deter-mined that, in operating CIGGS, Marathon and Unocalwere acting as public utilities. Subsequently, CIGGSowners Enstar (the major Southcentral Alaska gas utili-ty), the Cook Inlet gas producers and the state of Alaskabecame embroiled in intense discussions regarding theterms under which the gathering system should operate.

2005 settlement agreementIn September 2005, following mediated negotiations,

the various parties to the dispute filed a settlement agree-ment, under which CIGGS would come under regulationas a common carrier pipeline, rather than as a utility

pipeline. Under that agreement the pipeline owners guar-anteed a minimum capacity of 40 million cubic feet perday for the common carriage of gas for third-party ship-pers, with the owners retaining firm rights to use theremaining capacity (more than 40 mmcf per day mightbe available for third party use, depending on how muchgas the owners are shipping at any particular time).

Reserving only part of the system’s total capacity ofabout 120 mmcf per day for third party use would pre-serve the rights of the owners to transport gas from lega-cy west Cook Inlet oil and gas fields, while also openingthe pipeline system to regulated common-carrier opera-tion.

The rate base for the use of CIGGS was valued at theowner’s original investment cost and the remaining lifeof the system was assumed to be 30 years. The negotia-tors agreed on a methodology for calculating rates forthe use of the system and set an initial tariff rate of

$0.152 per mcf of gas shipped, witha provision for possible rate modifi-cation after the first year of regulat-ed pipeline service. And, becauseCIGGS metering and control sys-tems were not designed for commoncarrier operation, the negotiatorsdevised a self-policing procedure todeal with imbalances between gasvolumes delivered into the systemand volumes taken out of the sys-tem.

On Nov. 1, 2005, CIGGS ownersopened the system for the third-party transportation on a temporary,interim basis, pending an RCA deci-sion on whether to accept the settle-ment agreement.

RCA decisionThe RCAdecision came on Jan. 26,

2007, when the commission issued anorder approving the settlement.

“All parties of record have joinedin the settlement of issues in these dockets,” RCA said.“Accordingly, we should terminate this proceeding (thecomplaint against the unregulated operation of CIGGS)unless the public interest requires us to continue it. …All current parties have resolved all issues in dispute andwish to end their litigation under the terms and condi-tions of the settlement agreement.”

And, in agreeing that CIGGS should operate as acommon-carrier pipeline rather than a utility pipeline,RCA also withdrew its earlier finding that Marathon andUnocal were acting as public utilities.

The June 7 application for the CIGGS certificate ofpublic convenience and necessity represents the nextessential step in completing the legal process of makingthe Cook Inlet gathering system a regulated pipeline, fol-lowing RCA approval of the settlement agreement.Comments on the application must be filed with RCA byJune 22. ●

IAnd, in agreeing that CIGGSshould operate as a common-carrier pipeline rather than a

utility pipeline, RCA alsowithdrew its earlier findingthat Marathon and Unocal

were acting as public utilities.

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By ALAN BAILEYPetroleum News

aced with the double whammy ofdepressed salmon prices and escalat-ing energy bills, the SouthwestAlaska community of Naknek is

looking deep underground to alleviate theBristol Bay region’s economic woes.Local electric co-op Naknek ElectricAssociation plans to drill for a geother-mal energy source that could power elec-tricity generation for as many as 30 com-munities in the region, the NEA’s generalmanager Donna Vukich told PetroleumNews on June 12.

NEA has been investigating the poten-

tial for geothermal energy in the Naknekarea for about eight years, Vukich said.Initial research focused on the neighbor-ing Katmai Range, in the KatmaiNational Research and Preserve, wherethere is obvious surface volcanic activity.But although potential geothermalresources were identified in the Katmaiarea, the fact that these resources layinside the national park presented a majorobstacle to development.

Deep drilling advancesHowever, recent technological

advances in deep geothermal drillingpresent new opportunities for geothermalexploration in the Naknek area, to thewest of the park. Geothermal develop-ments in Iceland and by the U.S. Navy inCalifornia have demonstrated the effec-tiveness of deep drilling techniques,Vukich said.

A regional geologic fault called theBruin Bay fault passes through the area.Fracture systems from that fault couldprovide conduits for the passage of geot-hermal water, Vukich said. And thermaldata from oil exploration wells in the areashow that at depths below 8,000 to 9,000feet temperatures reach levels that couldsupport what is known as a binary geot-hermal system, a system in which geot-hermal fluid vaporizes a lower boiling-point fluid such as a refrigerant. Vaporfrom the lower boiling point fluid thendrives a turbine powered electricity gen-erator.

“At about 12,000 feet some bottomhole temperatures were up in the 250 to300 degrees Fahrenheit range (in wells atthe east end of the Alaska Peninsula),which is adequate for a binary facility,”Vukich said. It’s all a question of findinga spot where there is also a source of hot


NATURAL GASAlaska’s gas team works Washington, D.C.

Leaders of Alaska’s gas pipeline team were in Washington,D.C. the week of June 10, visiting with federal officials to facil-itate implementation of the Alaska Gasline Inducement Act, orAGIA, which Gov. Sarah Palin signed into law June 8.

The governor’s office said June 12 that Department ofNatural Resources Commissioner TomIrwin, Department of RevenueCommissioner Pat Galvin, and DNRDeputy Commissioner Marty Rutherfordplan to meet with the Bush administration,all three members of Alaska’sCongressional delegation, the FederalPipeline Coordinator’s Office, and offi-cials from the Federal Energy RegulatoryCommission and other “pertinent federalagencies, including the Department ofEnergy.”

The purpose of the meetings is toupdate key federal officials on AGIA, as passed by the AlaskaLegislature during the most recent legislative session. They alsowill discuss the roles that key federal players will have as theAGIA process moves forward, and the interaction of the stateand federal governments in “assuring expeditious progresstoward certification” of a natural gas pipeline from Alaska’sNorth Slope, the governor’s office said.

DNR CommissionerTom Irwin

RevenueCommissionerPatrick Galvin

DeputyCommissioner Marty Rutherford

● A L T E R N A T I V E E N E R G Y

Naknek looks togeothermal energySW Alaska electric co-op plans seismic survey, deep drilling tofind energy source for Bristol Bay region; Shell lending a hand

F

see NAKNEK page 9

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http://www.dog.dnr.state.ak.us/oil


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water that could be brought to the surface,she said.

The technology of binary systems hasimproved in recent years to a point wheregeothermal water at relatively low tem-peratures can produce viable quantities ofelectricity — in 2006 Chena Hot SpringsResort in Alaska’s Interior started up ageothermal power plant producing 200kilowatts of electricity from geothermalwater at just 165 degrees Fahrenheit (see“Geothermal powers resort” in the Aug.27, 2006 edition of Petroleum News andpage 1 of this issue for a related newsitem).

Where to look?NEA obtained some thermal imagery

in the Naknek area 12 to 15 years agowhile searching for coalbed methane,Vukich said. That imagery showed somethermal anomalies that could indicate thepresence of either hydrocarbons or geot-hermal energy. Subsequent soil samplingfound soil chemistry indicative of under-ground geothermal activity.

Based on this initial work NEA identi-fied three sites for potential geothermalprospects. Two of these sites lie on thenorth side of the Naknek River at KingSalmon, and the third site lies on thesouth side of the river halfway betweenKing Salmon and Naknek. NAE thenconducted shallow drilling at each ofthese sites, to test the soil chemistry andto test for bedrock under the soil. The soilchemistry in each of the wells confirmedthe geothermal potential of the sites,although two sites showed strongerpotential than the other. One well encoun-tered bedrock at a depth of 250 feet, withthe other two wells drilled down to 400

feet without encountering rock, Vukichsaid.

Having identified potential sites, NEAnow needs to do some 3D seismic sur-veying down to depths of 15,000 feet, topinpoint a target for deep drilling. Thecompany doesn’t anticipate drilling to15,000 feet, but needs the seismic data toextend below the likely drilling depth,Vukich said.

Oil company Shell has been assistingNEA with geologic and seismic expertise,to help interpret well data from the regionand plan the seismic operations, Vukichsaid.

“That’s where we’re at now,” Vukichsaid. “We’re hoping to get our seismictesting and modeling done this summer,so that we might be ready this winter toactually do a deep well drill.”

Funding“So far NEA has financed 100 percent

of the cost of the work we’ve done,”

Vukich said (according to the NEA website the company has invested about$400,000 in the project). The company isseeking financial assistance, although theNEA board is sanctioning the seismicwork with or without external funding.

“Our board has committed to gettingthis (seismic) testing done whether we getthe funding or not,” Vukich said. “… Wethink it’s the best use of our members’money to be able to … change the waywe do power generation and control ourcosts.”

However, the deep drilling will requireexternal funding — NEA has been work-ing with the Alaska congressional delega-tion and with the state to investigate pos-sible funding sources, although no fund-ing has yet been committed to the project.

And once NEA has found a geother-mal source, the development of a powerplant and electricity transmission networkwould involve major expense. The com-

Unalaska takes the next step

The City of Unalaska is now look-ing at a pre-feasibility stage for itsconcept of a geothermal power plant atthe side of the Makushin Volcano, CityManager Chris Hladick toldPetroleum News on June 6. The cityhas conducted talks about how toprogress the project with Richmond,Calif., based Geothermex, a companythat specializes in geothermal explo-ration and development, Hladick said.Geothermex would provide engineer-ing and geology services and overseeany drilling, if the project proceeds.

“We’re putting together a concep-tual design,” Hladick said.

Discovered in 1982The U.S. Department of Energy

discovered a 390-degree-Fahrenheitgeothermal water source on the flankof Makushin Volcano in 1982. Sincethen several ideas for harnessing thegeothermal energy have come to noth-ing, after foundering on the challeng-ing economics of geothermal develop-ment in a remote and isolated commu-nity. But advances in the technologyfor binary cycle geothermal powergeneration have led to renewed inter-est in the Unalaska geothermal site. In2005 Iceland America Energy, a sub-sidiary of Enex Corp., acquired geot-hermal rights on the slopes of the vol-cano and proposed a 50-megawattpower station, coupled with a heatexchanger that would enable hot freshwater to be pumped to town to heatbuildings.

However, Unalaska now wants to

continued from page 8

NAKNEK

Shallow drilling to test soil chemistry at the South Naknek geothermal exploration site

see NAKNEK page 10

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see UNALASKA page 10

http://www.epochwellservices.com

http://www.acsalaska.com


pany hopes to build a transmission gridfrom the Naknek/King Salmon areasouthwest to Pilot Point; northeast toIliamna and Port Alsworth; and northwestto Dillingham, New Stuyhok and Togiak.NEA says that the initial plant andapproximately 450 miles of transmissionlines connecting to regional villageswould cost about $200 million.

The transmission network forms amajor component of the project costs andVukich said that NEA would use a phasedapproach to extending out the network,starting in the Dillingham area.

“We’re looking at serving the region,”Vukich said. “(But) if we find hot waterwe would want to tie in Dillingham asquickly as possible, since they’re the nextlargest place.”

NEA would start with a 25-megawattplant and would expand the plant capaci-ty in 12.5-megawatt increments to 50megawatts, in tandem with extending thetransmission network across the region.

Regional supportBut why build such an extensive trans-

mission network?With Bristol Bay supporting the

world’s largest sockeye salmon run, all ofthe communities in the region areinvolved in a commercial fishing industrythat has in the past underpinned theregion’s economy, Vukich said. A primarymotivation in developing geothermalenergy is the provision of modest-pricedelectricity that would support a resur-gence of that industry across the region,she said.

“Our region has been known for devel-opment and being self-sustaining. Wewant to get back to that,” Vukich said.“… That’s why tying in the region is soimportant. That can change 25 to 30 vil-lages overnight if the cost of power isaffordable.”

For example, cheaper power mightencourage fish processors to extend thefish processing season and do secondaryfish processing in the Bristol Bay area,rather than shipping fish to Seattle forprocessing, Vukich said.

And possibilities like that are causinggreat enthusiasm for the Naknek geother-mal initiative.

It’s “a lot of work, a lot of excitementand a lot of money,” Vukich said. ●

investigate the potential for developing ageothermal facility in the valley floor nextto the volcano, rather than on the higherground on the volcano itself — DOE dis-covered the original geothermal sourcefrom a bench feature at an elevation of1,200 feet. Access to the bench involvesnegotiating a “hellacious switchback road,”while the bench is subject to relatively highsnowfall and suffers from unstable soil con-ditions, Hladick said.

By contrast the valley floor is at an ele-

vation of 400 feet. And construction of aroad from town to the valley floor sitewould be much simpler and involve a short-er route than building a road to the bench,Hladick said.

The plan now is to drill some 2.5-inch,slim-hole wells to a 1,000-foot depth in thevalley floor, to test for a geothermal source.That investigation will enable a decision onwhether the power plant should be locatedin the valley floor or at the original benchsite. Once the site is determined, it will bepossible to make the cost estimates neces-sary to carry out a feasibility study for theproject. “I think we’re looking at $3 millionto do the slim-hole work,” Hladick said.


NAKNEKcontinued from page 9

UNALASKA

drillers will set a 2.5-inch PVC well target-ing a specific coal seam. The well would beused to monitor the pressure and tempera-ture in the coal over the winter.

The next step might be another drillingprogram in 2008 to test the production char-acteristics of the coal.

The 5.25-inch Wainwright well will becored continuously to its total depth. Thosecores will provide information about the

subsurface geology — the nearest well toWainwright is about 25 miles away.

The team had planned to start drilling atthe end of May but delayed operations toallow more time for snow to melt at thedrilling site, Clark said. The plan is to com-plete the work in time to barge equipmentfrom Wainwright in July, if necessary. Inaddition, early knowledge of the drillingresults would enable additional equipmentrequired to be shipped on the North Slopebarge that departs from Seattle in mid tolate-July.

—ALAN BAILEY


CBM

http://www.dog.dnr.state.ak.us/oil


● G O V E R N M E N T

Newfoundland ready for test of wills Williams: Hebron partners won’t get better offer; set to demand equity stake of at least 5 percent in all new offshore projects


remier Danny Williams is immense-ly popular in his home province ofNewfoundland, where the polls indi-cate he is a prohibitive favorite for

re-election in October. But he’s immense-ly unpopular with oil producers who arethe leading contributors to his govern-ment’s treasury.

Having taken the industry to the mat ayear ago and lost out in his bid for anequity stake and enhanced royalties fromthe Chevron Canada-led Hebron project,he seems about to find out who is the irre-sistible force and who is the immovableobject.

The Williams’ government filed legis-lation in early June creating a new energycorporation, backed by C$600 million ofprovincial borrowing power, to invest inthe development of oil and gas, hydro-electric power and wind power. The cor-poration will be fully functional Jan. 1,2008 after the transfer of assets, employ-ees and contracts.

By then the government will haveunveiled a revised energy plan that isexpected to insist on a provincial equitystake of at least 5 percent in all future off-shore developments – more than the 4.9percent Williams demanded before nego-tiations with the Hebron consortium col-lapsed.

Wants to join ranks of state-run oil companies

The office of Natural ResourcesMinister Kathy Dunderdale confirmedremarks she made that Newfoundlandwants to join the league of state-run cor-porations such as Norway’s Norsk Hydrowho are full partners in projects.

Norsk, in fact, has interests in two ofNewfoundland’s three producing offshoreoilfields – 5 percent of Hibernia and 15percent of Terra Nova.

Dunderdale said that is what theHebron partners will have to accept ifthey have any notion of reopening nego-tiations on fiscal terms and proceedingwith what was once an C$11 billionundertaking – by Chevron 28 percent,ExxonMobil 37.9 percent, Petro-Canada23.9 percent and Norsk Hydro 10.2 per-cent — to develop estimated proved andprobable reserves of 731 million barrels.

Government will demand more in fallShe even suggested that the consor-

tium would be better off resuming negoti-ations – even though the project team hasbeen disbanded – rather than waiting untilthe new rules are announced this fall.

By then, the government will bedemanding an equity stake larger than the4.9 percent it sought from Hebron, “soit’s probably in their best interest to getthe matter settled before the plan isreleased,” Dunderdale said.

Williams had already suggested theindustry would be well advised to acceptthe current terms or face much tougherconditions.

Province got C$1B of $17B in profitsDunderdale indicated an underlying

reason for Newfoundland’s determinationto get a better shake out of its offshore isthe return it has received so far under afederal-provincial accord that specifiedthe province was to be the principle ben-eficiary of offshore development.

Instead, she said, it has received onlyC$1 billion of the C$17 billion in profitsgenerated by the three producing fields,while the companies have pocketed C$11billion and the Canadian government hascollected C$5 billion.

But the accord gives Newfoundlandthe right to establish royalty and other fis-cal terms, including equity participation.Dunderdale does not believe that pursu-ing that objective will drive investmentaway, but she does expect “some resist-ance.”

She said the companies benefitingfrom Newfoundland’s “world class”opportunities operate “in most parts ofthe world” under rules similar to thosebeing drafted by her government.

Must share in risk, says CAPPPaul Barnes, with the Canadian

Association of Petroleum Producers, toldthe Globe and Mail that the industry isopen to having the province as a partnerprovided it puts up the capital and takeson some of the risk.

But he said Williams can expect strongopposition if he seeks both equity androyalties.

Barnes said the breakdown in Hebronnegotiations has left the industry “uncom-fortable” with the Newfoundland govern-ment’s strategy, causing a hiatus in explo-

ration.What isn’t clear from the government

is whether it intends to follow throughwith a Williams’ threat to impose “use itor lose it” legislation, under which leaseswill be forfeited unless development pro-ceeds within a specified timeframe.

In an effort to reinvigorate activity, thegovernment has offered C$5 million for atwo-year exploration enhancement pro-gram to boost onshore oil and gas explo-ration.

The plan will help companies obtain

geoscientific information in exchange foran equity position in future projects.

The program will invest in seismicsurveys that will give the province and itsexploration partners a “clearer indicationof the opportunities that lie beneath thesurface of our onshore lands,”Dunderdale said in a statement.

It is designed to give a lift to explo-ration by providing funding for provin-cially owned Newfoundland andLabrador Hydro to strategically invest ingeoscientific activities. ●

P

EXPLORATION & PRODUCTIONNoble scores another deepwater discovery

Exploration and production independent Noble Energy has scored what looks likeanother commercial discovery in deepwater Gulf of Mexico.

The BP-operated Isabela discovery well, located beneath 6,500 feet of water onMississippi Canyon Block 562, encountered hydrocarbons in “two high-quality reser-voirs,” the company disclosed June 6.

“Isabela is an important discovery for us, which could add production as early aslate 2009,” said Chuck Davidson, Noble’s chairman, president and chief executiveofficer.

Noble has a 33.33 percent working interest in the discovery. BP holds the remain-ing 66.67 percent interest.

The well, drilled to a depth of about 19,100 feet, was temporarily suspended pend-ing development operations, the company said, noting that the most likely develop-ment concept for the Isabela project is a sub-sea tieback to BP’s nearby Na Kika pro-duction facility.

Noble said it also acquired an interest in adjacent acreage near the Isabela discov-ery with additional exploration potential.

When combining Isabela with upcoming development projects at Lorien,Ticonderoga, Swordfish and Raton-Redrock, Noble’s deepwater program “is wellpositioned to contribute strong production for several years to come,” Davidson said.

Noble’s deepwater program currently represents about 15 percent of the company’sworldwide production.

The Isabela prospect is situated roughly 150 miles southeast of New Orleans, La.The exploration well was spud Feb. 28.

Last January Noble announced a fast-track sub-sea development of a natural gasinterval discovered at the company’s Raton prospect on Mississippi Canyon Block292, with first production from the zone expected during the first half of 2008.

In May 2006, Noble announced that it had entered into a purchase and sale agree-ment to sell its Gulf of Mexico continental shelf assets to Coldren Resources for $625million.

This year the company plans to spend $1.42 billion on capital projects versus $1.87billion in 2006, including $520 million in acquisitions.

About 26 percent of the company’s capital program for this year has been allocat-ed for “exploration opportunities,” including lease acquisitions and seismic studies,and 74 percent is dedicated to production, development and other projects.

Noble’s domestic program of $1.09 billion represents about 77 percent of the com-pany’s 2007 capital program, and international expenditures are $300 million, or 21percent.

—RAY TYSON


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had brought, House Resources Co-ChairCarl Gatto, R-Palmer, said it was a wonder-ful-looking brochure, “but these e-mails arethe thing that really captures my attention.”

Gatto said he hoped Brock would conveyto BP management the frustration of legisla-tors that the brochure won’t “satisfy the dif-ficulties we’re seeing with the record.”

Brock: actions BP has takenBrock told Gatto he would take the mes-

sage back to BP. He agreed that “words are words; presen-

tations are presentations. They actually don’tmean anything unless you take action.”

BP has taken action, Brock said. Setting up the technical directorate which

he heads is one step. The directorate is “anindependent body,” he said. “So these typesof inquiries and queries (represented by thee-mails) actually have a functional oversightrather than being buried within the lineorganization.”

The technical directorate, he said, has“independence when it comes to issues ofsafety or integrity of our facilities. We havean independent body now that has oversighton the decision-making process.”

The corrosion group was formerly“imbedded in the Greater Prudhoe Bayorganization,” Brock said, but now reportsdirectly to him and he, in turn, reports direct-ly to Doug Suttles, the president of BPExploration (Alaska). Brock said that meansgreater transparency, and issues such asthose raised in the e-mails about the impactof cost cutting on corrosion “aren’t leftburied in the organization itself.”

The company has also reassessed itsunderstanding of risk, he said.

An analysis done for BP by Booz Allenindicated that cost cutting wasn’t the issue,but rather BP’s awareness of risk. Inresponse, BP has put in place a rigorous riskreview process. “And that process is beingimbedded at the field level; it’s being imbed-ded at the technician level; (and) at the oper-ator level” and is being “managed upthrough the field line to the senior members”of BP’s management team in Alaska.

That system will be reviewed on a regu-lar basis, Brock said. “It’s my role to presentthat to Doug Suttles, the president of BPAlaska, and to ensure that we take properaction on these types of issues so they getresolved.

“Overall we’re focused on reducing riskwithin our fields.”

Frustration disappointingAsked by Rep. Paul Seaton, R-Homer,

about a 2003 e-mail which talked about riskimpacts related to budget cuts, Brock saidemployees were obviously frustrated in “try-ing to get the balance right between what’sthe right amount of expenditure to ensurethat our systems are integrally safe and thatwe have a viable system.” Budget concernsare part of running any business he said, but“certainly the people were frustrated andthey felt they were compromised in some oftheir choices.”

The company is making changes, he said. The technical directorate currently has

more than 150 technical experts. “That isdifferent,” Brock said.

The corrosion management team reportsto Brock. “If they have concerns about com-promising the program then I will addressthem. And I will address them independent-ly of the line (organization) whether it relatesto production or to costs. My primary con-cern is about the integrity and the safety ofour operations.”

The management team is “committed tochanging some of the processes that we useto manage and make decisions,” he said andis also working on open communications. If

“our employees have concerns, we wantthem to be able to communicate them to sen-ior leadership without fear or concern.”Brock said BP is encouraging people “toraise these issues so they can be addressed.”

BP has a new leadership team in placeand is starting to address “the systemic cul-ture” and what that culture needs to be sothat it can be “a leading operator in Alaskafor the next 30 years.”

New pipelines smallerIn reviewing the replacement oil transit

line system BP is now putting in place,Brock said the existing system was made forfour times the capacity needed now and inlooking at lessons learned from the corro-sion found in 2006 BP determined it neededto redesign the system for the right level forthe next 50 years, with smaller diameter oiltransit lines. The new system will be sizedright so that velocities in the lines preventthe leak-causing corrosion that occurred in2006.

There will also be permanent pig launch-ing and receiving facilities which can beaccessed and used year round.

The work will include 20 new modulesand skids.

Resources Co-Chair Craig Johnson, R-Anchorage, said he was concerned about thenew system because of the way the state’sPetroleum Profits Tax is structured. “You’reresponsible to your shareholders (and) we’reresponsible to ours,” Johnson said.

Brock said BP believes a new system isnecessary for the continued operation ofPrudhoe Bay over the next 30 years. Newfacilities are necessary because more andmore water is now produced with the oil.Viscous oil is being developed from thewestern side of the field, which requiresmodifying the pipeline system to handle thatoil. Putting more viscous oil into the exitinglines would “actually further reduce thevelocity,” he said. Reduced velocity is one ofthe factors identified as causing corrosion inthe oil transit lines.

BP also has to address “integrity andstandards issues” put in place by the U.S.Department of Transportation and theAlaska Department of EnvironmentalConservation, and now by the PetroleumSafety and Integrity Office.

Those standards are higher, he said, andmeeting them with the current pipeline sys-tem would be a struggle going forward.

New leak detection systemBP is also trying a new leak detection

system. The Leos system “is sensitive to very

small leaks,” Brock said. The existing sys-tem did not detect pinhole leaks where dropsof oil were coming through.

The Leos system hasn’t been appliedaboveground in the Arctic before. “We havea similar system on our Northstar transit linebut that’s buried in the seabed,” Brock said.

Using the system above ground exposesit to a much harsher climate and “muchgreater swings in temperature.”

It will take a couple of years, throughsummer and winter operation, to prove upthe system.

Two sections of the replacement oil tran-sit line were constructed this winter, he said.“It has not been put in service yet; it needsmodules to be constructed to allow us to dothat.”

Overall replacement of 16 miles of the oiltransit lines are expected to be commis-sioned in the fourth quarter of 2008, he said.

Extensive tests and inspections arebeing carried out on the existing system,Brock said, “to ensure the integrity of thatsystem.” ●

Slemons: changing direction a challengeJonne Slemons, coordinator of the State of Alaska’s new Petroleum Systems

Integrity Office, updated House Resources June 7 on some of the regulatory issuesrelated to oil transit lines and other oil and gas facilities.

Prior to 2006, she said, there was “general ignorance of the fact that there was a reg-ulatory gap” for the oil transit lines, lines which take sales-ready oil from productioncenters to the trans-Alaska oil pipeline.

The Office of Pipeline Safety in the U.S. Department of Transportation typicallyregulates such lines, but North Slope lines were not covered because “there were someexemptions within the federal regulations … (for) lines that were in remote areas ofvery low population.”

That gap was filled by Congress in late 2006 when it expanded the authority of theOffice of Pipeline Safety, Slemons said.

And the Alaska Department of Environmental Conservation was in the process —even before the March 2006 spill — of expanding its regulatory authority to cover flowlines, those lines that run between the wellhead and the production centers.

“In terms of pipelines, I believe that regulatory gaps have been addressed,” Slemonssaid in response to a question from Rep. Max Gruenberg, D-Anchorage.

One of the primary tasks of PSIO, she said, is to do a statutory and regulatory gapanalysis “to ensure that any gaps remaining anywhere on state lands, regarding oil andgas, are discovered. And we are in the process of performing that gap analysis now.”

Rep. Paul Seaton, R-Homer, asked Slemons if she was comfortable with changesBP is making as operator.

“BP is implementing significant, very broad, very deep and far-ranging changes totheir organization,” Slemons said, most of which are “in response to requirementsplaced upon them by the Office of Pipeline Safety through various consent orders thathave come down.”

She said it is her impression that BP is “sincere in wanting to fix the problems thathave been discovered and to mend their ways, if you will. My own personal concern isthat a ship the size of BP doesn’t turn on a dime. And changing organizational cultureis a very difficult thing to do.”

Slemons said BP has been responsive to the PSIO and she understands it has alsobeen responsive to the Office of Pipeline Safety.

Asked by Seaton about the extent of PSIO authority, Slemons said facilities “suchas production centers, modules, gas processing facilities, those kinds of things” havelargely escaped regulatory oversight, other than labor, OSHA and fire detection.

“It is one of the missions of the PSIO to fill those gaps and we will be looking atfacilities, not just pipelines, in the system integrity plans that we will be requiring fromthe unit operators.”

Slemons said PSIO will be assessing the technical sufficiency of the plans and willbe performing on-site assessments to ensure the operators comply with the plans thatare established.

—KRISTEN NELSON



CHANGES

http://www.amarinecorp.com

http://www.GreatNorthernEngineering.com


Murkowski contract left a lot to FERCThe gas line contract negotiated by the

Murkowski administration with the threebig North Slope producers under theStranded Gas Development Act left a lot tothe Federal Energy RegulatoryCommission, Brena said. The details werenot addressed, and that’s where the moneyis, he said.

Brena said FERC isn’t viewed as anactive regulator because in the Lower 48pipelines generally have competition andFERC has evolved in response to that com-petitive situation and is not well suited toAlaska where there is no pipeline competi-tion.

He also said that FERC hesitates to getinvolved in massive cases between well-funded parties.

“These are your resources,” he told legis-lators and urged them not to try to solve alocal problem in D.C.

And he urged them to fund the work.Past administrations, he said, have been out-resourced in pipeline matters — out-litigat-ed, out negotiated and out staffed. Brenasaid this is not a comment on the Palinadministration, which he said has some verybright people and is aimed in the right direc-tion. But he warned that the state faces thebest of the best — oil company representa-tives who do this work for a living.

Tariff cases in process Brena is the attorney for Anadarko

Petroleum and Tesoro in the current trans-Alaska oil pipeline tariff case before FERC.He reviewed the status of that case for thecommittee, as well as the earlier case beforethe Regulatory Commission of Alaska thatresulted in a lowering of tariffs for intrastatetransportation of oil.

The 2002 RCA decision on the 1997case, which set a $1.96 rate for intra-stateshipment, was affirmed in Superior Court in2006, Brena said. The carriers appealed thedecision to the Alaska Supreme Court. Thecase has been argued before that court; thecourt has not yet issued a decision.

An initial decision favorable to Brena’sclients was issued in May on the FederalEnergy Regulatory Commission case by anFERC administrative law judge. The fullcommission has not yet heard the case,which Brena said would certainly beappealed to the D.C. Circuit Court. Anappeal to the U.S. Supreme Court is proba-ble, but Brena said he didn’t think theSupreme Court would hear the case.

The FERC case began in 2005 whenAnadarko and Tesoro claimed the tariff ratesranging from $3.78 to $4.41 proposed for2006 were unjust and unreasonable andrequested FERC to establish a $2.04 per-barrel rate for 2006 based on FERC Opinion154-B.

The initial decision established a $2.04rate, agreeing with Anadarko and Tesoro tothe penny, Brena said. ●


FERC

● G O V E R N M E N T

Quebec imposescontinent’s firstcarbon tax


uebec will lead the way as the firstNorth American jurisdiction toimpose a carbon tax on hydrocar-bon producers, raising C$200 mil-

lion a year to support measures to reducegreenhouse gas emissions.

The Liberal government in theprovince of 7.5 million people has deliv-ered on a year-long promise to introducethe tax that will affect 50 companies thatuse or retail oil, natural gas and coal.

Natural Resources Minister ClaudeBechard said the taxes will affect allhydrocarbons used in Quebec, whichaccounts for 22 percent of all refinedproducts consumed in Canada.

“Everyone wants to play their part (incleaning up the environment,” he said.“Well, the oil companies have to playtheir part.”

He said the measures are based on a“polluter pays” principle and is “notnegotiable.”

Bechard expressed the hope that theindustry will not pass the cost on to con-sumers, but admitted he has received noassurances.

Companies such as Petro-Canada,Shell Canada and Imperial Oil would notimmediately say whether they will absorbthe tax. The Canadian PetroleumProducts Institute, representing all ofCanada’s major refiners, said it will be ayear before the impact on refiners will beknown.

The tax on a per liter basis will be: 0.5

cents for propane, 0.8 cents for gasoline,0.9 cents for diesel fuel, 0.96 cents forlight heating oil, 1 cent for heavy heatingoil, 1.3 cents for coke used in steel mak-ing and C$8 per metric ton for coal.

Gasoline retailers are expected to payC$69 million a year, with C$43 millioncoming from heating oil firms, C$39 mil-lion from natural gas producers and C$36million from diesel fuel firms.

Bechard said the tax is modest whencompared with refinery profit margins,which have climbed this year from 8cents per liter to 19-22 cents.

The revenues will be channeled into agovernment “green fund” to spend on thedevelopment of commuter rail networksand other forms of mass transit.

Quebec Premier Jean Charest has set agoal of ethanol accounting for 5 percentof all transportation fuel consumed inQuebec by 2012.

To achieve that level, the provincemust produce an extra 300 million litersannually — 180 million liters more thanQuebec’s sole ethanol plant.

Quebecers have consistently been thestrongest supporters among all 10Canadian provinces of the KyotoProtocol.

Their province already has a head startover the rest of Canada because the vastbulk of its power comes from hydroelec-tricity, rather than gas-, oil- or coal-firedplants.

Other provinces are pondering caps ongreenhouse gas emissions, but none havemade any moves towards a carbon tax.●

Q

PIPELINES & DOWNSTREAMBP applies to expand Prudhoe Bay pads

BP has applied to the Alaska Department of Natural Resource for approval toexpand gravel facilities at Flow Station 1, Flow Station 2, Flow Station 3 and Skid 50to accommodate new modules that are required as part of the replacement of oil tran-sit lines in the Prudhoe Bay oil field. The pad expansion proposal has also been pub-lished by DNR for public review under the Alaska Coastal Management Program.

BP announced in February that it would rebuild the entire Prudhoe Bay transit linesystem in response to the leaks discovered in 2006 in the original field transit lines.The new system requires 20 new modules, to house facilities such as corrosion piglauncher and receiver systems; corrosion inhibitor injection systems; and leak detec-tion systems. The pad expansions will accommodate the new modules, as well asallowing vehicle turning space and traffic flow space.

—ALAN BAILEY

egy for the energy sector,” with greateremphasis on environmental issues.

Cleland said his association, whichrepresents more than 125 companies,organizations and individuals, has beenmaking a case for the past three years

to more closely align climate changeplans and energy development.

He said the Canadian governmentneeds to play a leading role in develop-ing a more “coherent framework” tomove from a market-focused and reac-tive energy policy to one that is moreclosely tied to environmental policies.

—GARY PARK


COSTS

on the Gulf of Mexico, and then DutchHarbor, Alaska. It is expected to arrive inlate June in Dutch Harbor.

According to OSO, under the terms of

a three-year charter contract betweenFinstaship and Shell, Finstaship is char-tering “two multi-purpose icebreakerswith crew” from May to December in theyears 2007, 2008 and 2009. (Paperworkfiled with permitting agencies by Shellindicates all work will be done sometimein November.)


INSIDER

Canada’s North.• Taking out shipping commitments to

reduce volume risk. • Other unspecified forms of support.

Wants to stay ahead of AlaskaPrentice said the government is also

“mindful of public policy developmentsin other jurisdictions, particularly Alaska,and we are cognizant of the need to havea competitive fiscal regime and to ensurethat we maintain the timing advantageover the Alaska pipeline project.”

He said the Mackenzie natural gaspipeline must be “cost-competitive withalternative sources of supply. … Recentdevelopments in the United States inrelation to a potential Alaska gas pipelinemay have shifted the competitive land-scape somewhat. We will follow thesedevelopments closely.”

However, he said that the rise in thebudget estimates makes it “difficult toimagine any significant progress on fis-cal framework discussions in the absenceof the proponents reinventing this proj-ect.”

Prentice touts importance of gas explorers

Pius Rolheiser, spokesman for theMackenzie Gas Project’s lead partnerImperial Oil, which is 69 percent ownedby ExxonMobil, welcomed what he saidwas an “expression of continued (gov-ernment) commitment to working withthe proponents and other parties to helpmove the project forward.”

He said Imperial was in completeagreement with Prentice’s stance that thenorthern gas project “must be economicon its own merits” and was not interested

in subsidies.But Rolheiser told Petroleum News

that Imperial needs to better understandwhat Prentice had in mind when he saidthe Mackenzie Gas Project should bereinvented and when he made a case forensuring that the gas pipeline is a “basin-opening piece of northern infrastructure.”

Prentice said it is “fundamental” thatthe project should serve not just the inter-ests of owners of the three anchor fieldsin the Mackenzie Delta, but theMackenzie Explorer Group made up ofindependent E&P companies such asDevon Canada, BP Canada Energy,Chevron Canada and MGM Energy.

“It will be the availability and marketpredictability of access to the pipelineand gathering system that drives the eco-nomic activity that is required to justifythe project,” Prentice said.

“If the pipeline and gathering systemare designed, constructed or regulated ina manner that only serves the anchor field(owned by Imperial, ConocoPhillipsCanada, Royal Dutch Shell andExxonMobil Canada) and the con-veyance of anchor field gas, it is impos-sible to make a compelling case, or evena strained one, that the project is in thenational interest,” Prentice said.

Urges revisit of access issueTo that end he urged the proponents

and the Mackenzie explorers to revisitissues that have stalled an agreement onaccess to the gathering system.

The Mackenzie Explorer Group wasunable to persuade the National EnergyBoard last year to bring the main pipelineand gathering system under a singlejurisdiction, with common tolls and tar-iffs.

But Prentice noted that the 2007-08federal budget committed the govern-ment to pursue amendments to legisla-tion regarding the authority to regulatepipeline access, tolls and tariffs.

Rolheiser said the gathering systemhas already been designed to handle 50percent more gas than the 830 millioncubic feet per day that is initially plannedfor production at the anchor fields.

On the broader question, Prentice saidCanada’s stranded northern gas reserves“must eventually be connected to NorthAmerican markets. … This will supportthe competitiveness of Canada’s energysector by ensuring existing pipelineinfrastructure is more fully utilized. Itwill also support our long-term energysecurity and help moderate price fluctua-

tions. … About one-third of remainingrecoverable gas in Canada is in the Northand more than half is in the MackenzieDelta and Beaufort Sea,” he said.

Prentice argued that accessing that gaswill become increasingly important asproduction declines in the WesternCanada Sedimentary Basin, where wellcompletions have multiplied seven-foldsince the 1990s, but production hasremained static – a trend that is expectedto continue, making a natural gaspipeline from the Mackenzie Delta evenmore vital.

Must generate benefitsfor northerners

But a pipeline along the MackenzieValley must generate tangible benefitsfor northerners, especially economicdevelopment in aboriginal communities,and “the gas itself must connect into theCanadian hub,” he said.

He said the participation of theAboriginal Pipeline Group, which isseeking a one-third equity stake in thepipeline, has been an important aspectfrom the outset.

“It is virtually impossible to imaginethe project proceeding on another basis,”Prentice said.

However, Hal Kvisle, chief executiveofficer of TransCanada, which has fund-ed the Aboriginal Pipeline Group’s par-ticipation in the planning and regulatorystages, told the same conference the fed-eral government should be willing tocompensate the proponents for the C$2billion they have spent on regulatory andland-access costs that would not be facedby other energy projects.

“We think in part the governmentshould think about what their role mightbe in covering part of that cost becauseit’s not a situation of the industry’s mak-ing,” he said. ●



OWNERSHIP Mac review panelneeds more time

CBC News reported June 14 thatthe Joint Review Panel for theMackenzie Gas Project has request-ed more time to finalize its hearingschedule. The panel is investigatingthe environmental and socio-eco-nomic impacts of the project andsays it wants to hear the interveners’comments on a motion filed by theSierra Club and the World WildlifeFund that asked the panel to studyall of the cumulative effects of gasdevelopment in the MackenzieValley, rather than just the impactsof the pipeline project.

Panel hearings are still inprogress. Once completed, the panelwill look at all of the informationand the hearing transcripts beforeissuing a report.

Editor’s note: Petroleum NewsCanadian correspondent Gary Parkwas out of the office June 14. Watchfor a full report in next week’s edi-tion.

http://AmericanConference.com/alaska/pn


http://alaska.bp.com

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