page3

BP enters Alberta oil sands, partnerswith Husky, billions at stake

Vol. 12, No. 49 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of December 9, 2007 • $1.50

● N A T U R A L G A S

● L A N D & L E A S I N G

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

● F I N A N C E & E C O N O M Y

8Access could prevent gas shocks: Study suggests trading

Alaska gas development for closed Lower 48 federal lands

13 AEnergia not new to Alaska: Proposed North Slope gasline would support ancillary lines to Kenai and Valdez, including LNG

20 Enstar touts Parks spur line: Would connect Mat-Su gasgrid with Nenana, Fairbanks and future North Slope gas line

No stay for Point ThomsonAOGCC asks for submissions; Superior Court wants briefing on DNR issues

By KRISTEN NELSONPetroleum News

oint Thomson is currently playing in multiplevenues: the Alaska Superior Court is hearingan appeal of the Department of NaturalResources’ decision terminating the unit;

DNR is holding a decision on an appeal of the sta-tus of leases at Point Thomson pending the court’sdecision; and the Alaska Oil and Gas ConservationCommission is hearing a petition by ExxonMobilfor compulsory unitization at Point Thomson.

Judge Sharon Gleason of the Alaska SuperiorCourt heard oral arguments Oct. 5 and said it washer goal to have a decision out by the end ofNovember, but definitely by the end of the year, onthe appeal of the DNR decision terminating the

unit. The Nov. 30 target went by the wayside Nov.21, when Gleason requested supplemental briefingon three issues: Is the current administrative codeinconsistent with the regulations in effect when thePoint Thomson unit agreement was entered into;did these formal procedural regulations, in con-

“The petitioner and others arechallenging DNR’s decision in Superior

Court,” the commission said, so thepetition to the commission “implicates the

relationship between the respectiveunitization authorities” of AOGCC and

DNR.

P

see POINT THOMSON page 17

Time for second thoughtsRe-jigging likely, but Alberta premier firm on overall 20% hike; industry cuts begin

By GARY PARKFor Petroleum News

he sounds wafting out ofthe Alberta governmentthese days suggestPremier Ed Stelmach and

Finance Minister Lyle Obergare getting the message.

And if they’re not, it washammered home with realforce on Nov. 27 whenCanadian Natural Resourceslaid out its response toplanned royalty hikes.

Canada’s second largest gas producer and acompany with billions of barrels of oil sandsresources to develop, aiming for 500,000 barrels

per day over the next 12 years, said its conven-tional operations in Alberta will be slashed in 2008— natural gas by 44 percent and oil by 22 percent.

Its total capital budget will tumble from this

T

see THOUGHTS page 18

Alberta Premier EdStelmach

On Nov. 27 … Canadian NaturalResources laid out its response to plannedroyalty hikes. Canada’s second largest gasproducer … with billions of barrels of oil

sands resources to develop … said itsconventional operations in Alberta will beslashed in 2008 … gas by 44 percent andoil by 22 percent. Its total capital budgetwill tumble from this year’s C$6.5 billion

to C$4.5-$4.92 billion.

Petro-Canada weighs Arctic LNGPetro-Canada is not ready to forsake the frontier mindset

that was part of its birthright when it was created as a state-owned company in 1975.

Chief Executive Officer Ron Brenneman told a company-sponsored investment conference that Petro-Canada is ponder-ing ways to develop an estimated 12 trillion cubic feet of natu-ral gas resources that it holds in Canada’s High Arctic.

Despite losing a bidding war in mid-2006 for CanadaSouthern Petroleum, which has an estimated 927 billion cubicfeet of Arctic reserves, and despite the distance from market,Brenneman said his company is diverting a small investment toevaluate those holdings and look at ways to exploit them.

He said a “small team” has been formed to look at the fea-sibility of using liquefied natural gas.

“To me that makes a pretty ideal project,” he said, while

MMS releases EA on BP's Libertyproject, expects no significantadverse effects from development

With required mitigation, no significant adverse effects areexpected from BP Exploration (Alaska)’s plan to develop itsLiberty prospect off Foggy Island Bay on Alaska’s North Slopefrom the secondary drilling island at Endicott.

The U.S. Department of the Interior’s Minerals ManagementService has released an environmental assessment and a findingof no significant impact on the project. There is a 30-day publicreview period before MMS makes a final determination whetherto prepare an environmental impact statement and takes finalaction on the proposed development and production plan, theagency said in a Dec. 3 Federal Register notice.

The finding of no significant impact notes that by developingLiberty with ultra-extended-reach drilling from the Endicott

Court hears oral arguments onShell Beaufort Sea exploration

On Dec. 4 a three-judge panel of the U.S. Court ofAppeals for the 9th Circuit heard oral arguments in theappeals by the North Slope Borough, the Alaska EskimoWhaling Commission and several environmental organiza-tions against U.S. Minerals Management Service approval ofShell’s oil and gas exploration plans in the U.S. Beaufort Sea.

The 9th Circuit Court judges must now rule in the case. Itis not clear how long it will be before that ruling will appear.

Shell had planned a multi-year exploration drilling pro-gram in the Beaufort Sea and had assembled a fleet of ves-sels to drill three wells in its Sivulliq prospect on the westernside of Camden Bay in the summer of 2007. The companyplanned further drilling in subsequent years, with precisedrilling plans for those years dependent on the results of the

see PETRO-CANADA page 20

see LIBERTY page 19

see SHELL page 16

AGIA bids inAdministration begins completeness review; no producers among five applicants

By KRISTEN NELSONPetroleum News

he State of Alaska received five applicationsunder Gov. Sarah Palin’s Alaska GaslineInducement Act — the state’s bid to get devel-opment of a gas pipeline project with $500

million in state matching funds and other benefitsin exchange for a project which meets 20 “musthaves.”

After applications closed Nov. 30 the governorand her gas line team displayed boxes andenvelopes containing the applications and MartyRutherford, deputy commissioner of the

TTransCanada steppingin to jump-startMackenzie line?

According to the Financial Post,TransCanada Corp. appears to be steppinginto the jump-start the stalled Mackenzie nat-ural gas pipeline.

On Dec. 5 the newspaper reported that adeal restructuring the stalled Mackenzie line“appears to be close at hand, and wouldinvolve TransCanada Corp. and the

see BIDS page 14see TRANSCANADA page 15

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

2 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

GOVERNMENT

EXPLORATION & PRODUCTION

NATURAL GAS

PIPELINES & DOWNSTREAM

8 Chinese bidder faces political hurdles

Sinopec has pipeline expertise and financial muscle, but it does business in many politically unpopular places around the world

7 Momentum builds behind energy report

Anchorage Chamber findings, recommendations could spur critical public policy changes across Alaska as briefings continue

3 Husky, BP move to the beat

Form two joint ventures to develop, process heavy oil and bitumen from Alberta; deal signals BP’s entryinto oil sands upstream, with ‘billions of dollars’ at stake

5 Eni wins Nikaitchuq royalty reduction

Second time’s a charm: earlier Kerr-McGee requestdenied; this time around 11 leases get 5 percent rate, based on price of oil

6 British Columbia going ‘carbon neutral’

8 Chart comparing Sinopec with ConocoPhillips

8 Access to federal lands could prevent gas shocks

9 Alaska's Enstar positions for the future

4 ANS crude stays close to 700,000 bpd

4 Energy trusts: Goin’ to the chapel, and we’re…

6 Canada studies CO2 collection, delivery

17 Former ARCO chief Anderson dies

15 Agrium’s last Alaskacargo ship sets sail

11 ConocoPhillips goes its own way

18 Alberta to set bitumen ‘benchmark’

ON THE COVERAGIA bids in

Administration begins completeness review; noproducers among five applicants

No stay for Point Thomson

AOGCC asks for submissions; Superior Court wants briefing on 3 DNR issues

Time for second thoughts

Re-jigging likely, but Alberta premier firm on overall 20% hike; industry cuts begin

10 BG Group ‘remains extremely interested’

Company didn’t apply under AGIA; tells governor ‘we are keen to have a role in facilitating natural gas development in Alaska’

11 MidAmerican wants ‘new way forward’

Company doesn’t apply under AGIA, says ‘deepening and ongoing investigations’ make compliant application ‘unrealistic’

13 AEnergia not new to Alaska gas line

Burkhard says North Slope pipeline would go to Calgary AECO hub, and support ancillary line to Kenai or Valdez, including LNGFINANCE & ECONOMY

TransCanada to take over Mac line?

Petro-Canada weighs Arctic LNG

Court hears oral arguments on Shell Beaufort Sea exploration

MMS releases EA on BP's Liberty project,expects no significant adverse effects from development

Alaskagas pipelineupdate

By GARY PARKFor Petroleum News

usky Energy has moved from a slow waltz to a quickstep in laying out its long-term plan for processingheavy oil and bitumen from Alberta and dragged BP onto the dance floor in the process.

The companies announced Dec. 5 what had long been spec-ulated. They will form two independent 50-50 joint ventures— one to develop upstream resources andone for the downstream — mirroring lastyear’s blockbuster deal by EnCana andConocoPhillips.

BP will take a half-share in the Sunriseproject that is scheduled to come onstream at 60,000 barrels per day in 2012and expand in two more phases to200,000 bpd over the 2015-2020 period.

BP will contribute its Toledo, Ohio,refinery which has crude distillationcapacity of 155,000 bpd and currentthroughput of 135,000 bpd, including60,000 bpd of heavy sour crude. BP plansto increase bitumen processing capacity atthe refinery to 120,000 bpd, boosting totalthroughput to 170,000 bpd by 2015.

BP had been last holdoutThe deal with BP is the final conces-

sion by the global super major that the oilsands have an economic role to play inNorth America’s supply equation, follow-ing an earlier plan to modify its Whiting,Ind., refinery to process heavy crude from Alberta.

Until this year, BP had been the last holdout from the oilsands of all the major companies operating in North America.

It signaled a change in outlook in its latest annualStatistical Review of World Energy by crediting the oil sandswith holding 163.5 billion barrels of undeveloped reserves,representing oil that it believes could be produced using cur-rent technologies in today’s economy, and separately listed10.3 billion barrels of reserves that are under active develop-ment.

BP said at the time that its standard is not how much oil isburied in the sands, but whether it can be economically pro-duced.

Bob Malone, the chairman and president of BP America,said the joint ventures “will be investing billions of dollars toexpand North American energy supply and enhance NorthAmerican energy security.”

He said the result will be the development of a major new

Canadian oil field along with the modernization and expan-sion of the Toledo refinery to permit “far greater use ofCanadian heavy oil and to increase clean fuels production byas much as 600,000 gallons a day.”

The refinery currently produces 3.8 million gallons per dayof gasoline, 1.1 million gallons of diesel and 756,000 gallonsof jet fuels — about 0.5 percent of total US refining capacity.

BP said a joint investment of about US$2.5 billion isexpected up to 2015 to sustain and reposition the refinery toprocess increased amounts of heavy oil and bitumen, withHusky having first call on up to 50 percent of the refinerycapacity for Sunrise bitumen.

Upstream costs about US$3 billionAt the upstream end, Husky estimates the Sunrise project

will be about US$3 billion up to 2012.Husky will also move ahead with repositioning its Lima,

Ohio, refinery, acquired in May from Valero Energy forUS$1.9 billion. The 160,000 bpd facility is being reconfiguredto handle Husky’s growing heavy oil production, with someanalysts putting that cost at US$2.9 billion.

Backed by discovered resources estimated at 41 billionbarrels, Husky has a full slate of prospects and HuskyPresident and CEO John Lau admitted that he is expecting“more deals” to emerge from the joint ventures, but was tightlipped beyond that point.

It currently produces 106,000 bpd from its heavy oil andbitumen operations, including the Tucker oil sands projectwhich is expected to peak at 30,000 bpd by late 2008.

In addition, it is nearing completion of a pilot project for itsCaribou lease of 2.5 billion barrels and has identified 12 loca-tions for winter drilling at its 24.1 billion barrel Saleski lease.

But the BP deal will not sit well with the Alberta govern-ment, which is planning incentives to keep more of the value-added upgrading and refining end of oil sands production inAlberta.

Husky has long hinted that inflationary construction costsand access to the major consuming markets might drive it tothe United States.

Lau said the upgrading credits proposed in Alberta’s newroyalty framework were not sufficient to persuade Husky tobuild capacity in the province. Because the government hasyet to unveil a specific plan, he said it was difficult to com-ment. ●

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 3

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

Husky, BP move to the beatForm two joint ventures to develop, process heavy oil and bitumen from Alberta; deal signalsBP’s entry into oil sands upstream, with ‘billions of dollars’ at stake

Backed by discovered resources estimated at 41billion barrels, Husky has a full slate of prospects andHusky President and CEO John Lau admitted that he

is expecting “more deals” to emerge from the jointventures, but was tight lipped beyond that point. H

John Lau, HuskyEnergy

Bob Malone, BPAmerica

By GARY PARKFor Petroleum News

he scramble to exchange marriagevows among Canadian income trustscarries a high cost these days —more than C$32 billion in market

value over the past two months.Enerplus Resources Fund and Focus

Energy Trust were latest to unite in acompatible match that will establish acombined entity with a market-cap ofC$7.6 billion and output in 2008 a tickover 100,000 barrels of oil equivalent perday (80,000 boe per day from Enerplus).

The deal, announced Dec. 3, creates an

operation that is No. 3 among trust pro-ducers in Canada and with a portfolio thatis sufficiently diversified — conventionaloil, shallow and deep, tight natural gas,the oil sands and a major stake in theUnited States — to reduce the risks ofasset concentration, said Focus ChiefExecutive Officer Derek Evans.

The C$1.38 billion merger, if complet-ed in February, will “provide greaterfinancial capacity to pursue additionalM&A activity and large capital projects,”the two trusts said.

With increased trading volumes on theNew York Stock Exchange and theToronto Stock Exchange there will be

improved access to debt capital markets,while a broader investor base will includeboth Canadian and U.S. retail and institu-tional markets.

Williston key operating areaOne of the key operating areas is the

Williston basin, which spills fromMontana and North Dakota across the49th parallel to Saskatchewan andManitoba.

Focus brings to the marriage a keystake in the Shackleton shallow gas playof Saskatchewan, which produces 69 mil-lion cubic feet per day and provides about1,500 drilling locations.

To the south in Montana, Enerpluspumps 11,500 boe per day, or 13 percentof its total output, from the Bakken oilplay, which has 280 million barrels of oilin place.

Focus also has strong interests in deeptight gas positions in British Columbia,allowing it to contribute 110 millioncubic feet per day of gas production toEnerplus’ forecast 259 million cubic feetper day in 2008.

But Enerplus Chief Executive OfficerGordon Kerr is not fazed by the increasedgas weighting.

He said that although it “may appear

counter-intuitive to increase natural gasexposure at a time when North Americangas prices are depressed, (the Focus)assets have attractive economics at cur-rent prices and cost structures and we seesigns of potential cost savings.”

Kerr said he is bullish on the long-termoutlook for gas prices, given the declinein U.S. and Canadian basins, the need formore gas to fuel Alberta’s oil sands oper-ations and the likelihood of a changingglobal economy placing limits on lique-fied natural gas imports to NorthAmerica.

A rarity among trusts, Enerplus alsoholds an estimated 443 million barrels ofcontingent resources in the oil sands andfuture production potential of 60,000 bpd.

It is starting out with a 15 percentstake in the Total-operated Joslyn project,and 100 percent of the Kirby projectwhich is due to come on stream in 2011 at10,000 bpd and grow to 30,000 bpd by2015.

Kerr was not greatly troubled by theimpact on cash flow of Alberta’s plannedroyalty hikes, suggesting the new trust,which will carry the Enerplus name, isshielded by the nature of its assets andplay types and the government’s decisionnot to introduce an oil sands severancetax. ●

4 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

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● F I N A N C E & E C O N O M Y

Energy trusts: Goin’ to the chapel, and we’re…

T

EXPLORATION & PRODUCTIONANS crude stays close to 700,000 bpd

Alaska North Slope crude oil production was relatively flat in November, stay-ing above the 700,000 barrel-per-day level most of the month and averaging727,517 bpd for the month, 0.9 percent above the 720,999 bpd October average.

Production was up 16.8 percent at the BP Exploration (Alaska)-operatedLisburne field, averaging 34,040 bpd vs. 29,144 bpd in October. Lisburne pro-duction includes Niakuk.

BP-operated Northstar averaged 36,712 bpd in November, up 6 percent froman October average of 34,644 bpd.

The BP-operated Endicott field (which includes Sag Delta, Eider and Badamiproduction) averaged 48,369 bpd in November, up 3.2 percent from an Octoberaverage of 46,853 bpd. Endicott currently includes some 33,000 bpd of PrudhoeBay crude from Flow Station 2.

The Kuparuk River field, operated by ConocoPhillips Alaska, averaged151,451 bpd in November, up 1.8 percent from an October average of 148,794bpd. Kuparuk production includes West Sak, Tabasco, Tarn and Meltwater.

BP-operated Prudhoe Bay was basically flat, averaging 302,247 bpd inNovember vs. 301,967 bpd in October. Prudhoe production includes Prudhoe Baynatural gas liquids, Aurora, Borealis, Midnight Sun, Orion, Polaris, 400-600 bpdfrom Lisburne and Point McIntyre.

Greater Prudhoe Bay (including Lisburne and the 33,000 bpd of Prudhoe oilcurrently coming through the Endicott line) averaged 369,287 bpd in November,up 1.4 percent from an October average of 364,111.

BP’s Milne Point field averaged 36,637 bpd in November, down 0.5 percentfrom an October average of 36,827 bpd. Milne Point production includesSchrader Bluff.

The ConocoPhillips-operated Alpine field (including Fiord and Nanuq) aver-aged 118,061 bpd in November, down 3.8 percent from an October average of122,770 bpd.

The average November temperature at Pump Station 1 was 13.8 degreesFahrenheit, compared to 22.4 degrees in October, and compared to a five-yearaverage for November of 1.9 degrees.

Overall Cook Inlet production averaged 15,073 bpd in November, down mar-ginally from an October average of 15,124 bpd.

—KRISTEN NELSON

By KRISTEN NELSONPetroleum News

ni has succeeded where Kerr-McGeefailed and has won royalty reductionfor leases in the Nikaitchuq unit offAlaska’s North Slope.

When Kerr-McGee Oil and Gas Corp.applied for royalty reduction at Nikaitchuqin 2006 the request was denied, based onwhat the Alaska Department of NaturalResources called “materially improved”economics for the project following thepassage of the state’s new petroleum prof-its tax in August 2006. DNR said high cap-ital expenditures for Nikaitchuq would“serve to offset other statewide incomestreams and lower the overall tax obliga-tions for the corporation” and its parentAnadarko Petroleum, resulting in a taxreduction of some $120 million comparedto the previous fiscal regime. Anadarko hasproduction from the ConocoPhillipsAlaska-operated Alpine field in which it isa partner; it acquired Kerr-McGee in 2006.

Circumstances are different for the newNikaitchuq operator, Eni US OperatingCo., which has no production in Alaska,and its proposal has won a royalty reduc-tion on 11 leases in the 18-lease unit, tied toa number of requirements and to the WestCoast price for Alaska North Slope crudeoil.

In 2007 Anadarko sold its majorityinterest in the area to Eni, which had comein as a minority partner when it acquiredthe Alaska interests of Armstrong Oil &Gas in 2005.

The unit has also changed in the interim. Kerr-McGee applied for royalty relief

on a group of tracts, some of them in theTuvaaq unit, as well as the Nikaitchuqtracts.

The Tuvaaq unit is now part ofNikaitchuq, which more than doubled insize when DNR approved expansion ofNikaitchuq this October, rolling in leasesfrom Tuvaaq as well as a portion of a leaseformerly part of the Kuparuk River unitand two adjacent leases. Nikaitchuq isnorth of Kuparuk in the shallow waters ofthe Beaufort Sea off Alaska’s North Slope.

Project must be sanctionedby end of February

DNR said first oil from Nikaitchuq isexpected in 2010.

The planned development includes agravel pad with drilling, gathering and pro-duction facilities on Oliktok Point near the

existing ConocoPhillips Alaska seawatertreatment plant. Because the projectincludes production facilities, this wouldbe the first development on the NorthSlope with facilities not operated by BPExploration (Alaska) or ConocoPhillips.

There will also be a gravel drillingisland constructed near Spy Island withproduction tied back to Oliktok Point forprocessing.

Sales-quality oil from Oliktok Point willbe sent to the Kuparuk Transportation com-mon carrier pipeline via a new pipelinesome 14 miles long. Seventy-three wellsare expected to be drilled between 2008and 2011, 31 of which would be producers.

Eni has said it expects to sanctionNikaitchuq development by the end of thisyear; if the project is not sanctioned by Feb.28, 2008, DNR said the royalty modifica-tions will be rescinded.

Leases must be committed to anapproved participating area within sixyears of project sanction to be eligible forroyalty modification. After six years anylease or portion of a lease not committed toa participating area for the NikaitchuqSchrader Bluff reservoir will revert to theindividual lease royalty rates in effect priorto the royalty modification.

If project spending beginning Dec. 1,2007, does not meet $822 million in nomi-nal dollars by six years from project sanc-tion, the royalty modification is rescinded.If project spending does not reach $1.398billion in nominal dollars 11 years fromproject sanction, the royalty modification isrescinded.

Royalty reduction will be for the first 25years following the date of first sustainedproduction, and requires that the ANS WestCoast delivered crude price be below thethreshold price, which starts at $42.54 perbarrel and is adjusted annually for inflation.

For the 18th through the 120th monthsfollowing first commercial productionfrom the Nikaitchuq Schrader Bluff OAreservoir, if production from all subjectleases averages below 4,000 bpd for anyprevious 12 month period, full royaltymodification rates of 5 percent will be ineffect for production from that reservoir,regardless of oil price.

DNR also required that if any third-party petitions to use Nikaitchuq unit facil-ities, “the cost of use shall be based on mar-ket rates” and resulting contract data willbe shared with DNR, which will keep theinformation confidential.

Thirty-day public noticeIn the preliminary findings and determi-

nation issued Nov. 30, DNR said Eni, theNikaitchuq operator, applied for royaltymodification on 12 leases and the state isproposing to grant royalty relief on 11 of theleases.

The 30-day public comment periodbegan Nov. 30. Within 30 days of the end ofthe public comment period DNR will pre-pare a summary of public comments andmake a final findings and determination.

Eni, 100-percent working interest ownerin the leases, originally applied for royaltymodification on the Schrader Bluff and SagRiver reservoirs, but later requested that theSag River reservoir be withdrawn from theroyalty modification application.

The company requested fixed royaltyrates of 12.5 percent on a net profit sharelease and 16.67 percent on the 11 other leas-

es be reduced to the minimum rate allowed,5 percent, with an annual sliding-scale roy-alty percentage adjustment based on thelevel of the ANS West Coast crude oil price.

DNR said the 30 percent net profit sharerate on ADL 391283 will remainunchanged.

DNR approved royalty modification forADLs 388571, 388572, 388575, 388574,388577, 388581, 388582, 388583, 390615,390616 and 391283. It denied royalty mod-ification for ADL 388580 “because therewas no apparent resource allocated to thislease.”

There are 18 leases at Nikaitchuq. Thoseproposed for royalty reduction form the cen-tral core of the unit; leases not included inthe application — and the one lease whichdidn’t get state approval for royalty reduc-tion — are on the eastern, northeastern andwestern boundaries. ●

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 5

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● F I N A N C E & E C O N O M Y

Eni wins Nikaitchuq royalty reductionSecond time’s a charm: earlier Kerr-McGee request denied; this time around 11 leases get 5 percent rate, based on price of oil

E

By GARY PARKFor Petroleum News

ritish Columbia’s resolve to outdoCalifornia in curbing greenhouse gasemissions has moved into high gear,with the tabling of legislation that

Premier Gordon Campbell boasts has the“most aggressive” reduction targets in

North America. The trouble is, Campbell’s own

Environment Minister Barry Penner is notquite so emphatic.

Bill 44, the centerpiece of BritishColumbia’s pledge to create a “carbon neu-tral government,” legislates a 33 percentcut in 2007 GHG levels by 2020 and 80percent by 2050.

It also requires that “realistic, economi-cally viable interim targets” be set by theend of 2008 for the 2012-16 period.

Shane Simpson, environmentalspokesman for the opposition NewDemocratic Party in the B.C. legislature,accused the Campbell government of“backpedaling on its long-term commit-ment,” by using 2007 as the baseline for its2050 target, compared with the 1990 base-line used by California and some EuropeanUnion countries.

He said that means B.C. is committed toreducing GHGs by only 58 percent by2050, compared with California’s 80 per-cent goal.

Penner conceded B.C. will not lead theway in 2050, but insisted the province willlead the way in 2020 and remain “compet-itive” by 2050.

B.C. would be first province to legislate GHG reductions

Bill 44 makes B.C. the first of Canada’s10 provinces to enshrine GHG reductionsin legislation and, Campbell said, signals a“turning point in confronting global warm-ing and protection of the environment.”

The seven-page bill also includes:• A cap-and-trade system, imposing firm

limits on the emissions from large (as yetunspecified) industries, while allowingthem to participate in emissions tradingsystems;

• Adopting California tailpipe standardsfor new vehicles, requiring car manufactur-ers’ vehicle fleets to be “progressivelymore efficient and clean”;

• Introducing a low-carbon fuel stan-dard, requiring distributors of fuels such asgasoline and diesel to reduce the carboncontent of those fuels by 10 percent by2020; and

• Providing authority for the regulationand capture of landfill gases.

“Climate change is a monumental chal-lenge that means we have to think beyondthe present and to imagine and plan for thetype of future that we want the next gener-ation of British Columbians to inherit,”Campbell said.

“We are taking decisive and necessaryaction to confront the global warming cri-

sis, but we’re doing it in a way that willincrease our quality of life and support oureconomy through increased innovation andnew technologies.”

Government will go carbon neutralThe government plans to set its own

example by requiring all departments andagencies and educational institutions tobecome carbon neutral in 2010.

Penner said B.C. will be the first gov-ernment in North America to order all pub-lic sector organizations to issue an annualpublic report on their emissions levels, onsteps they have taken to reduce those levelsand what plans they have to minimizeemissions.

Lisa Matthaus, a spokeswoman for theSierra Club of B.C., downplayed argu-ments that B.C. will trail California by2050 and credited the government for“continuing to show leadership” in tacklingclimate change.

“Having the government set targets forboth 2020 and 2050 puts in motion a wholebunch of requirements in terms of gettingtools and incentives and regulations inplace,” she told reporters.

“Once we have that ball rolling, I thinkwe will not only meet, but exceed the tar-gets. But given this is setting a precedentfor Canada, we hope that B.C.’s emissionslaw will be an effective one, with account-ability provisions hardwired into it,”Matthaus said.

There was also praise for the govern-ment from Andrew Weaver, one of 22 peo-ple named to a government advisory panel,which will recommend interim GHG tar-gets for the 2012-16 period.

A professor at the University ofVictoria’s School of Earth and OceanSciences, he was one of nine team mem-bers on an Intergovernmental Panel onClimate Change, a joint winner of the 2007Nobel Peace Prize.

Weaver was unhesitating in describingthe Campbell government’s action as a“dream come true. … Here in B.C. we aretaking leadership on the climate portfolio,not only in Canada, but internationally.”

A self-described skeptic of governmentand political measures on climate change,he said the B.C. targets are “completelyrealistic and utterly necessary,” adding thatthe panel has been “asked not to hold back”in its recommendations.

However, Matthaus gave the petroleumindustry cause for some anxiety, saying thelegislation will place a “carbon lens” on allgovernment policies and programs, includ-ing oil and gas subsidies which have beenat the core of B.C.’s robust exploration anddevelopment efforts in its conventional oiland gas activities and a growing interest inunconventional plays, including tight gas,shale gas and coalbed methane. ●

6 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

● G O V E R N M E N T

British Columbia going ‘carbon neutral’Shows way to Canadian provinces by targeting 33% reduction in greenhouse gas emissions by 2020, but takes easier road than California

Matthaus gave the petroleumindustry cause for some anxiety,saying the legislation will place a“carbon lens” on all governmentpolicies and programs, includingoil and gas subsidies which havebeen at the core of B.C.’s robust

exploration and developmentefforts in its conventional oil and

gas activities and a growinginterest in unconventional plays,including tight gas, shale gas and

coalbed methane.

B

PIPELINES & DOWNSTREAMCanada studies CO2 collection, delivery

A coalition of Canadian oil producers, pipeline companies and provincial govern-ments has hired SNC-Lavalin to undertake a C$500,000 study of a carbon dioxide col-lection and pipeline system that could reduce greenhouse gas emissions in the refin-ery area east of Edmonton.

The Petroleum Technology Alliance Canada said the study will provide design andcost estimates for a CO2 collection system from various petrochemical plants, refiner-ies and upgraders and look at the transportation of CO2 through a common pipelinesystem. PTAC said a steering committee believes there will be sufficient CO2 fromthe area to support “commercial scale enhanced recovery” of conventional oil inAlberta, although its work will not cover pipelines to enhanced recovery fields.

PTAC President Soheil Asgarpour said the work will be a “major step forward inproducing clean energy from Alberta’s hydrocarbon resources” creating a win-win sit-uation for producers, transporters and CO2 emitters.

The National Energy Board has said so-called carbon capture storage has the“potential to significantly reduce greenhouse gas emissions,” but conceded there aretechnological and economic challenges to achieving that objective on a major scale,while noting that combining existing technologies has yet to be proven.

A number of producers and industry associations have been putting pressure ongovernments to take a more active role in tackling the problems confronting carboncapture storage.

—GARY PARK

By ROSE RAGSDALEFor Petroleum News

report on energy-related problemsfacing Alaska, released two weeksago, has ignited little more thanpositive comments so far,

but its authors hope the reportcalling for changes will light afire under government leaders tosecure the state’s energy future.

Early indications from theTri-Borough Commission ofSouthcentral Alaska, the PalinAdministration and the AlaskaState Chamber of Commercealso suggest they may get theirwish.

The Anchorage Chamber ofCommerce published the report,“Hope is not a Strategy:Findings and Conclusions aboutAlaska’s Energy Crisis,” Nov.19, after a special 12-membervolunteer task force studied theproblems and drafted recom-mendations for possible solu-tions.

Things have been prettyquiet since, according to Joe Griffith, co-chairman of the Chamber task force andformer head of Chugach ElectricAssociation in Anchorage. “After a fewearly comments, there’s been a strangesilence,” Griffith said.

“I’ve heard some positive comments,”said energy consultant Tony Izzo, whoalso co-chaired the task force and former-ly ran Enstar Natural Gas Co.

Presentation Dec. 10Griffith and Izzo are scheduled to pres-

ent the energy report at a chamber lunch-eon forum in Anchorage Dec. 10.

“We’ve offered to brief other groupsstatewide, and we’ve gotten some takers

but not many in government,”Griffith said.

When Chamber memberslearned that after-tax natural gascosts in Southcentral Alaskajumped 126 percent since 2004,they decided to study the issuefrom a business perspective,Izzo said.

“That’s a $166 millionimpact on the economy, and itdoesn’t include the cost of elec-tricity!” he said. “We wanted toidentify things that would helpus get to a long-term solution.”

Griffith said Alaska is “like aThird World Country” when itcomes to energy consumption.

The state’s rural communitiesface serious energy related prob-lems and have no easy solutions.Moreover, high energy costs are

forcing rural residents to flee the Bush infavor of Alaska’s urban areas, he said.

The most positive response from gov-ernment leaders, so far, has come from theTri-Borough Commission headed byAnchorage Mayor Mark Begich and themayors of the Kenai and Mat-Su bor-oughs.

The commission formed an energy pol-icy task force which Izzo and Griffith

have been asked to join. It aims to devel-op a rough outline of a regional energypolicy by January, Izzo said.

The Alaska State Chamber ofCommerce, meanwhile, has adopted theAnchorage Chamber’s resolution callingfor a state energy policy as one of its topthree legislative priorities for 2008.

Shively likes statewide perspectiveJohn Shively, former vice chairman of

the state chamber and president of theResource Development Council ofAlaska, said he sup-ported the statechamber’s actionand will support theenergy resolutionagain when the RDCboard takes up thequestion Dec. 12.

Shively said thereport impressedhim because it offersa very good statewide perspective.

“I’ve always thought it interesting thatAlaska economy is fueled by energy, but ithas people in the rural areas that pay thehighest energy costs of anywhere, by far,”he said.

Shively said power cost equalization isan attempt to address disparities but itdoesn’t touch the high costs of fuel forheating, snow machines and boats, all crit-

ical for life in Bush Alaska.Part of the problem, he said, is that

Alaska’s rural residents who are mostaffected by rising energy costs don’t haveready access to government to demandchanges. Instead, he suspects theyattempt to cope by consolidating house-holds in both rural and urban areas, hesaid.

The energy report also may haveimpressed the governor.

“Gov. Palin has tasked several of hercommissioners (for the departments ofNatural Resources; EnvironmentalConservation; and Commerce,Community and Economic Development)to develop a long-term energy plan. She isalso planning to hire an energy coordina-tor,” a spokeswoman said Nov. 30. ●

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 7

● G O V E R N M E N T

Momentum builds behind energy reportAnchorage Chamber findings, recommendations could spur critical public policy changes across Alaska as briefings continue

A

JOE GRIFFITH

TONY IZZO

JOHN SHIVELY

Griffith said Alaska is “like aThird World Country” when itcomes to energy consumption.

For PetroleumNews advertisinginquiries, contact

Susan Crane at 907.770.5592

8 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

● N A T U R A L G A S

Chinese bidder faces political hurdlesSinopec has pipeline expertise and financial muscle, but it does business in many politically unpopular places around the world

By ALLEN BAKERFor Petroleum News

he surprise pipeline bid from a subsidiary of China’sSinopec could provide an interesting new linkbetween Alaska and Asia’s mainland. But it’s unlike-ly to get out of the starting gate due to an impressive

load of political baggage.The formal bid comes from Sinopec’s oil services sub-

sidiary, Sinopec ZhongyuanPetroleum Exploration Bureau,along with Little SusitnaConstruction Co. ofAnchorage, founded by HongKong-born Dominic S.F. Lee,P.E., in 1980.

Little Susitna Constructionhas substantial credentials as anAlaska engineering, design and con-struction management firm, participating in more than500 Alaska projects including design work for the ServiceHigh School swimming pool and some North Slope facil-ities back in the ARCO days. But there’s not much oilindustry connection. Neither Lee nor anyone else fromLittle Susitna was willing to talk with Petroleum Newsabout the pipeline project at this point.

Plenty of expertiseSinopec itself (formally China Petroleum and

Chemical Corp.) has plenty of technological expertise andfinancial muscle. It’s China’s largest refiner and a majoroil producer.

In size, it’s roughly in the same league withConocoPhillips, producing 790,000 barrels a day of oiland 767 million cubic feet of gas, while refining 3.1 mil-lion barrels of crude each day, 70 percent of that import-

ed. Net income last year was nearly $7 billion, on $140billion in revenues. With 30,000 gas stations, the compa-ny has 365,000 employees.

Sinopec has experience building and running crudeand product pipelines for its refining operations. On thegas front, it recently began construction on a major linerunning about 1,100 miles from its Puguang field inSichuan, in western China, to Shanghai.

The line will cross the Yangtze River five times andrun across mountains and other challenging terrain, carry-ing 1.2 billion cubic feet daily. Cost of that project,including field development, is more than $8 billion.

Sinopec carries the muscle of the Chinese government,which owns nearly 76 percent of the shares through aholding company. China already showed once, in the bat-tle over Unocal, that it’s willing to provide capital for amajor investment by one of its national oil companies, inthat case CNOOC.

Political hurdles But the political implications in this case are daunting.

China has been shopping around the world for energy to

feed its expanding domestic appetite, and the Alaska proj-ect would logically provide LNG for export to China.That could be a tough sell in the current political climate.

Plus, Sinopec has been doing business in plenty ofplaces where big U.S. and European companies fear totread for political reasons. Name a country that’s consid-ered a pariah in the United States, and Sinopec is proba-bly deeply invested.

Back in 2004, the company signed an agreement withIran for a 51 percent stake in the Yadavaran field, a dealthat could involve as much as $70 billion and likely willinclude LNG shipments to China.

China’s interest in the Sudan is substantial, and whileSinopec has taken a secondary role to PetroChina, it’s stilla significant one. Sinopec ZPEB, the subsidiary that madethe formal bid in Alaska, has 750 employees in Sudan,including 430 Chinese, running more than a dozendrilling rigs and also providing seismic, logging and otheroilfield services. That won’t be a political plus in the U.S.

And this month, Korea’s Daewoo International indi-cated it would sell gas from its Myanmar fields toSinopec, which is expected to build a $1 billion pipelineto bring the gas from the fields to China. Myanmar isanother country whose leaders have faced criticism in theUnited States. ●

Little Susitna Construction has substantialcredentials as an Alaska engineering, design

and construction management firm,participating in more than 500 Alaska projects

including design work for the Service HighSchool swimming pool and some North Slopefacilities back in the ARCO days. But there’s

not much oil industry connection.

TSinopec vs. ConocoPhillips

Sinopec ConocoPhillipsMarket Capitalization $138B $130B2006 revenues $155B $160B2006 profits $9.2B $10.7B Crude oil production 790,000bpd 801,000bpdNatural gas production 767mmcf/d 4,916mmcf/dRefining throughput 3.1mmbpd 3.1mmbpd

COP production figures don’t include Lukoil investmentAlaskagas pipelineupdate

● N A T U R A L G A S

Access to federal lands could prevent gas shocksRice University study recommends trading Alaska gas development for E&P access to closed Lower 48 federal lands

By ROSE RAGSDALEFor Petroleum News

pening federal lands to oil and gas explorationwon’t free the United States from its growingdependence on natural gas imports, but it couldprotect the country from future global supply dis-

ruptions caused by possible formation of an OPEC-likegas cartel, according to a study released in November byRice University researchers.

Given the importance of the changing outlook for nat-ural gas supplies and energy prices, the James A. BakerIII Institute for Public Policy at Rice University con-ducted a two-year study, “Natural Gas in North America:Markets and Security,” to investigate factors that will

influence security of supply and pricing.About 3 percent of current U.S. natural gas supplies

come from overseas via liquefied natural gas tankers,another 17 percent comes from Canada in pipelines andthe remaining 80 percent is produced domestically.

In recent years, environmental and land-use consider-ations have prompted U.S. policy makers to deny accessto large areas that were once available for explorationand development. Twenty years ago, nearly 75 percent offederal lands were available for private lease to oil andgas exploration companies. Since then, the share hasfallen to 17 percent.

The study said LNG imports could rise to as much as30 percent by 2030 if the United States does not permitaccess to the 58 percent of federal lands now off limits,

including offshore areas and the Rocky Mountains.

More domestic production neededOpening restricted areas in the outer continental shelf

and Rocky Mountains will not render the United Statesenergy independent nor will it even lower U.S. depend-ence on LNG imports in 2015 by a significant volume.

Opening these lands to drilling, however, would cutLNG demand to 22 percent of the country’s gas needs by2030, the study said. It also would help keep priceslower.

But the larger benefit of reducing LNG imports wouldbe to undermine efforts by big gas exporters, including

O

see ACCESS page 10

By ALAN BAILEYPetroleum News

hange has become the norm for theSouthcentral Alaska gas utilitybusiness. While the winter gasdeliverability crunch from the Cook

Inlet oil and gas fields has been keepingthe gas dispatchers on their toes on a day-to-day basis, the tight balance betweensupply and demand is also impactinglonger-term issues relating to gas supplycontracting and pricing.

Since the Regulatory Commission ofAlaska rejected a proposed new gas sup-ply contract between Marathon andEnstar Natural Gas Co. in September2006, Enstar has been seeking new con-tracts to meet its projected supply short-fall in 2009. In February 2007 the compa-ny issued a request for proposals for newcontracts and is now negotiating contractswith Cook Inlet gas producers Marathonand ConocoPhillips. Those contracts willbreak new ground.

“The contracts we’re negotiating noware very different from what we’ve seenin the past in a number of ways,” ColleenStarring, Enstar’s regional vice president,told Petroleum News Nov. 28.

Full service The Marathon contract that RCA

rejected was a full service contract inwhich Marathon would have taken fullresponsibility for both the regular basegas load and peak winter gas demand allwithin a single gas price. The contractwould have run until 2016.

The new contracts, which Starring saidshould be ready for submission to RCAby the end of the year, will unbundle thepricing into three separate price tiers forbase load, seasonal swing during the win-ter and needle peak supplies during thecoldest days of the year. And the contractswill only run for five years.

With tight gas deliverability from themature oil and gas fields of the Cook Inletbasin, the cost of supporting the extremedemand swings for utility gas betweensummer and winter has become a signifi-cant issue — the new unbundled pricingwill take into account the cost of meetinghigh winter demand. The new contractswill also represent a move towards Enstartaking responsibility for handling the sea-sonal swing.

“The contracts shift the deliverabilityto Enstar and they’re volume driven,”Starring said.

Detailed contractual terms are stillunder negotiation, but Enstar expects amechanism in which the utility will fore-cast demand 12 months in advance forboth the base load and the demandswings.

“They’re required to commit to vol-umes, based on our forecast,” Starringsaid. “If we were to have volumes overand above what the producers haveagreed to give us, then that’s Enstar’sobligation to fill those wedges.”

Contract pricing for the three demandtiers is still under negotiation — theprime reason that RCA rejected theMarathon contract was that a majority ofcommissioners viewed the pricing in thatcontract as too high. The Marathon priceformula used a price indexed to the HenryHub market in the Lower 48 (Cook Inletgas producers have argued that gas pricesin the Cook Inlet need to reflect Lower 48prices, to attract investment in new Cook

Inlet gas exploration).

RCA approvalEnstar hopes that

RCA will view thenew contracts favor-ably. The regulatoryprocedure can take ayear to complete, atimeframe thatwould run close tothe projected 2009 gas shortfall.

“As we negotiate we believe we havea good thing that might be approved, andof course the producers have an opinionof what they can sell internally as well aswhat they believe the commission willapprove,” Enstar spokesman CurtisThayer said.

Enstar, rather than the producers, willmake the case before RCA for the newcontracts — Marathon spent one year and$1 million trying unsuccessfully to getthe previous contract approved, Thayersaid.

“They don’t want to have that experi-ence again,” he said.

But the shorter-term contracts thistime around may present opportunitiesfor independent gas producers to enter theCook Inlet utility market. Enstar is alsoopen to discussions with independents onfilling any potential gas shortfalls duringdemand peaks, Starring said.

If a small producer wants to sell gas toEnstar “we’d love to buy it,” Thayer said.But the current regulatory processinhibits that possibility, he said. Enstarcan’t purchase gas under a contract with-out RCA approval and an independentproducer is reluctant to invest in explo-ration without a contract, he said. Theregulatory process takes a long time tocomplete and may end up with contractrejection — there needs to be some wayof fast tracking this arrangement.

“We’re in a regulatory environmentwhere we’re reacting to situations and notbeing pro-active in solving things. That’sjust the way it is set up,” Thayer said. “…It’s just the way we’ve done business for40 years and times are changing.”

Gas storageOne symptom of

change in the CookInlet gas business isthe introduction ofgas storage to ensurewinter gas deliver-ability — excess gasproduced during thesummer is stored to

help meet high demand during the winter.Gas producers Chevron and Marathonnow operate gas storage facilities in theSwanson River, Pretty Creek and Kenaifields.

But faced with the potential for adeliverability shortfall as early as 2011under the new supply contracts, Enstar ismoving towards operating its own gasstorage.

One possibility is an LNG facility,with excess gas liquefied for later use,that would primarily serve as a peakshaving unit, to ensure adequate deliver-ability during extreme demand on thecoldest winter days. An LNG peak shav-ing facility would likely cost $180 mil-lion to $200 million and take more thanthree years to build, Starring said.

“If we were to build a peak shavingplant, if we were to start today, it wouldbe 46 months out before we had this plantin place,” Starring said. “… It’s a hugetime consideration.”

Another possibility would be to usethe existing LNG plant at Nikiski on theKenai Peninsula for gas storage, if thatplant loses its LNG export license in2011. The current export license expiresin 2009, but the plant ownersConocoPhillips and Marathon haveapplied for a two-year license extension— Enstar has supported the license exten-sion, provided that local gas needs arealso met.

The Nikiski plant has LNG tankcapacity of 2.2 billion cubic feet, Thayersaid.

“It’s a little larger than our needs, butit might be something where we partnerwith somebody or an electrical facility fortheir peak shaving,” Thayer said.

Enstar is also looking into the possibil-ity of obtaining an underground in-fieldgas storage facility by 2011, Thayer said.Because of the relatively low rate at

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 9

● N A T U R A L G A S

Alaska’s Enstar positions for the futureMoving toward unbundled contract pricing, shorter contracts, handling gas demand swings, including operating its own gas storage

CCOLLEEN STARRING CURTIS THAYER

see ENSTAR page 10

Russia, Iran and Qatar, to form a cartellike the Organization of the PetroleumExporting Countries that could limit sup-plies and drive costs up, according to theanalysis.

“As time passes, our high-cost domes-tic production will increasingly have tocompete against a swath of more compet-itively priced imports,” predictedKenneth B. Medlock, a fellow for energystudies at the Baker Institute.

“In the short term,” Medlockexplained, “the net impacts on U.S. sup-ply security are not all that worrisome.But in the long term, as our demandgrows, we will have to worry more aboutsecurity of supply.”

Opening up the outer continental shelfand Rockies gas supplies means the restof the world will have a bigger basket ofalternative supplies to pull from, signifi-cantly reducing market power that a car-tel might try to create, he added.

Alaska gas too costlyWhile Alaska is believed to hold sub-

stantial natural gas reserves, the high costof developing these distant supplies willmake it difficult for them to compete withlow-cost sources, the researchers said.Under a moderate oil price, unrestricteddrilling, market scenario, Alaska gasresources would not get fully developed.They would in effecttake a back seat tolow-cost domesticnatural gas produc-tion and cheap, mar-ginal supplies ofLNG imports, thestudy said.

“Another alterna-tive would be toexploit the potentialfor ‘net conservation benefit trades’ inlands that have potential for natural gasresource development,” the researcherssaid. “Essentially, a net conservation ben-efit trade is an exchange of resources thatresults in a net gain in conservation out-comes, while at the same time releasingresources for other uses.

“Examples of net conservation benefittrades include multiple land use, whereproductive practices are adjusted to main-tain or enhance conservation values insitu. For example ... a productive activityin one location is used to finance a con-servation activity, or purchase conserva-tion rights, elsewhere. Indeed, the trade ofincreased Lower 48 production forreduced Alaskan production could beviewed as an implicit net conservationbenefit offset,” the researchers said.

The study, which Medlock co-authored, was released as part of a Nov.16 conference at Rice about the future ofnatural gas in the United States. It was co-sponsored by McKinsey & Co. and theIndependent Petroleum Association ofAmerica. ●

10 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

● N A T U R A L G A S

BG Group ‘remains extremely interested’Company didn’t apply under AGIA; tells governor ‘we are keen to have a role in facilitating natural gas development in Alaska’

By KRISTEN NELSONPetroleum News

G Group did not submit an applicationunder Gov. Sarah Palin’s AlaskaGasline Inducement Act to build a gaspipeline to move North Slope natural

gas to market, but the company wants to stay inthe game.

In a Nov. 29 letter to the governor, Martin Houston,executive vice president and managing director of BGGroup, said BG “remains extremely interested” in partici-pating in bringing Alaska gas to market.

“We remain staunch supporters of your efforts to launcha transparent and competitive process that guaranteesaccess to pipeline capacity for Alaska’s new explorers,”Houston told the governor.

BG established “a large multi-discipline team” andspent “many hours” developing options with the intentionof bidding under AGIA, he said, and believes “more thanever, that a major infrastructure project is economic andwill be developed.”

“However, given the number of moving parts around allaspects of the project, there was still too much economic

uncertainty for us at this stage,” Houston said. BG does believe “there is potential for

robust projects in which we would be keen toparticipate as the picture firms up.”

BG plans to share its work with the state,Houston said, and a Dec. 12 meeting with

Deputy Commissioner of Natural ResourcesMarty Rutherford and her team is planned to

share the results of BG’s work. While “BG’s original bid consortium failed … it is

my sincere desire that BG be considered a partner to thestate, one that can add value to the process going forward,”he said.

BG believes LNG the way to goHouston told the governor that based on the work it did,

BG believes “that LNG should and will be part of the solu-tion for the future development of Alaska’s natural gasresources.” Liquefied natural gas could be an anchor proj-ect or part of a larger highway project, he said.

In addition to providing in-state gas and revenues to thestate, Houston said LNG would allow the state “to benefitfrom market diversification and the flexibility to target thehighest value markets in any given time.”

David Keane, BG’s vice president policy and corporateaffairs for North America, Caribbean and global LNG, toldthe Arctic Energy Summit Technology Conference inAnchorage in mid-October that BG believes LNG wouldbe an effective way to monetize North Slope natural gas.

“LNG, I believe, is an industry that holds the key to thefuture evolution of gas markets worldwide and I believeAlaska can be a critical part of that world market,” Keanesaid.

BG is the largest supplier of LNG to the United States,and supplied almost 50 percent of LNG imported to theU.S. in 2006, he said.

BG believes LNG is the way to monetize Alaska’s gasbecause of changing world markets: Gas markets, tradi-tionally regional, became global when long-distance ship-ment of LNG became viable, he said.

“In the early years of this decade the cost-price balancebroke the so-called ‘tyranny of distance,’ making MiddleEastern LNG economically viable into the U.S. gas mar-ket,” Keane said, creating the potential that some of theworld’s largest gas reserves could be linked to the world’slargest gas market, the United States (see story in Oct. 28,2007, issue of Petroleum News atwww.petroleumnews.com/pnads/597284068.shtml). ●

BAlaskagas pipelineupdate

which it is possible to retrieve the gasfrom this type of facility, in-field stor-age tends to support general increasesin demand during the winter rather thanneedle peaking.

Energy conservationEncouraging energy conservation is

another approach to the issue of tight gassupplies from the Cook Inlet basin —Enstar provides information on energyconservation on its Web site. But the cur-rent rate structure, in which Enstar’sservice charge for transporting gas to acustomer is based on the volume of gasthat the customer uses, encouragesEnstar to sell more gas rather than less.So Enstar is considering a flat fee, per-haps in the range of $20 to $30 permeter, for gas delivery.

“Basically, it’s like your cable televi-

sion — you get a flat fee for the serviceand it doesn’t matter how much televi-sion you watch,” Thayer said.

Because the bulk of a typical gas billconsists of the charge for the gas used,rather than the fee for the gas deliveryservice, gas consumers would continueto have a strong incentive to conservegas. But, at the same time, Enstar wouldhave no incentive to increase gasthroughput.

“It’s something we’re looking at forthe next rate case,” Thayer said. “… Itmakes sense. It helps conservation. Ithelps the customer, especially the low-income customer.”

But with new supply contracts in theoffing, a new rate case to put beforeRCA in 2008 and the need to look at newways of dealing with gas deliverabilityissues, Enstar is in for a busy time.

“We’re going to be spending a lot oftime downtown,” quipped Thayer, refer-ring to the location of the RCA officeand hearing room. ●

continued from page 9

ENSTARcontinued from page 8

ACCESSThe researchers suggested “netconservation benefit trades,”

essentially allowing companies totrade gas production on closed

Lower 48 federal lands inexchange for reducing Alaska gasproduction, where development is

more expensive.

KENNETH MEDLOCK

By KRISTEN NELSONPetroleum News

idAmerican EnergyHoldings Co. waswidely anticipated asan applicant to build a

natural gas pipeline projectunder Gov. Sarah Palin’s AlaskaGasline Inducement Act.

The company demurred, telling thegovernor in a Nov. 30 letter that “thedeepening and ongoing investigationsinto political and corporate corruption inAlaska make a thorough and thoughtfulproposal in compliance with AGIA anunrealistic exercise for our organization.”

David Sokol, the company’s chairmanand chief executive officer, made it clearthat he did not consider the Palin admin-istration to be a problem, telling the gov-ernor: “… your leadership and that ofyour administration has been outstandingand your integrity and transparent styleare a breath of fresh air in what hasproven to be a rather shady and smokefilled past in regard to energy issues inAlaska.”

Sokol said “integrity must be the foun-dation upon which all project elements

are based” if a project of themagnitude of the Alaska gaspipeline is to succeed.

“As you are painfullyaware the ongoing corrup-tion investigations coupled

with previous indictments,guilty pleas and convictions

draw into question virtuallyevery major Alaskan project participant

and government levels from State toFederal. Obviously your administrationhad no involvement in these previousshenanigans nor did we; however, youand we alone cannot develop the pipelineproject through AGIA’s expectedprocess.”

Alternative way forwardSokol said that with “ongoing criminal

investigations, recent related perform-ance issues in Alaska and elsewhere byone of your major producers, ongoing lit-igation regarding natural gas leases withthe producers and the current and project-ed complications in the heavy industrialconstruction industry we would respect-fully suggest that an alternate way for-ward be considered.”

Sokol did not offer details on what that

alternate way forward might be, but saidthe State of Alaska and the federal gov-ernment, “teamed with a proven and non-conflicted project development partner,will be required to successfully move thisproject forward.”

MidAmerican tried in 2004MidAmerican applied to build an

Alaska gas pipeline project in early 2004under the Stranded Gas DevelopmentAct, but withdrew its application in a dis-

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 11

● N A T U R A L G A S

ConocoPhillips goes its own wayCompany rejects AGIA, submits own proposal to state for North Slope natural gas project; says it requires no matching funds

By KRISTEN NELSONPetroleum News

onocoPhillips did not submit an appli-cation under Gov. Sarah Palin’sAlaska Gasline Inducement Act butthe company has put a non-AGIA pro-

posal before the state. None of the major gasholders on the North Slope — BP,ConocoPhillips and ExxonMobil — submitted anapplication under AGIA to move North Slope natural gasto market.

In a Nov. 30 letter accompanying the company’s pro-posal ConocoPhillips Chairman and Chief ExecutiveOfficer Jim Mulva told the governor that the company“is prepared to make significant investments, withoutstate matching funds, to advance the natural gas pipelineproject towards our shared objective of seeing the con-clusion of a successful open season within 36 months.”

While the company doesn’t want thestate’s money, and is willing to meeta number of the requirements inAGIA, it wants something AGIAdoesn’t offer — fiscal certainty.

“While we believe our proposalto advance the natural gas pipeline

project is a significant step, the ulti-mate realization of the project depends

upon the establishment of natural gas fiscalterms that will apply to the shippers makinglong-term shipping commitments during theinitial open season,” Mulva said.

It is “critically important,” he said, that the “frame-work for gas fiscal terms” be defined now so that a suc-cessful open season can be completed in 2010.

Fiscal certainty was one of the issues that blockedlegislative approval of the contract former Gov. FrankMurkowski struck in 2006 with the large North Slope

gas holders, BP, ConocoPhillips andExxonMobil, raising sovereignty and constitu-tional issues.

The three companies objected to AGIAwhen the bill was discussed, telling legislatorsthat the bill did not adequately address fiscalcertainty and required applicants for the AGIAlicense to meet specific requirements.

The companies campaigned hard for whatthey described as a more flexible bill where thestate would give applicants an opportunity tosay how they would respond to general goals,

rather than requiring applicants to meet specific require-ments. The companies also said that fiscal terms, cover-ing the whole range of state take from industry, wouldhave to be negotiated.

All three of the companies told legislators before the

CJim Mulva,

ConocoPhillips

see CONOCO page 12

● N A T U R A L G A S

MidAmerican wants ‘new way forward’Company doesn’t apply under AGIA, says ‘deepening and ongoing investigations’ make compliant application ‘unrealistic’

Msee MIDAMERICAN page 12

Alaskagas pipelineupdate

Alaskagas pipelineupdate

12 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

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New

bill was passed that they would not beable to make applications under AGIA.

A choiceConocoPhillips said in a summary of

its proposal that it is “purposely present-ing the State of Alaska with a choice: Thisproposal provides an alternative path for-ward for the ANS gas pipeline projectwhich is, in our view, the most certainway to create a vibrant and successfuldevelopment effort for this project.”

The company said the pipeline ship-pers “will be required to bear the burdensof multi-billion dollar financial commit-ments” through their long-term commit-ments to ship gas on a pipeline. Becauseof that, “a natural gas pipeline develop-ment effort will only be sustainable andultimately successful if there is recogni-tion of the need for an appropriate bal-ance of risk and reward among thepipeline owners, the state and the produc-ers and prospective shippers.”

The company said it was submitting itsproposal “to foster cooperative engage-ment” with the State of Alaska to help

find the balance of risk between the par-ties.

ConocoPhillips also said it shares thestate’s “sense of urgency” to get an ANSgas pipeline project moving. Since 2002,the company said, there have been signif-icant increases in both steel and laborcosts. The high-price environment willalso affect upstream natural gas explo-ration and development costs.

Continuing volatility in natural gasprices “creates uncertainty and riskaround a long payout project like theANS gas pipeline.”

What is the project?ConocoPhillips is proposing a 48-inch

high-pressure pipeline to carry some 4billion cubic feet a day of natural gasfrom the Alaska North Slope along theDalton, Richardson and Alaska highwaysto the Alberta border.

A large-diameter, high-pressurepipeline may possibly be needed to carryapproximately 4 bcf per day from Canadato Chicago, although alternatives to newconstruction are interconnection with theexisting Nova Gas Transmission Ltd. sys-tem in Alberta for some or all of ANS nat-ural gas. ●

pute with the administration of then-Gov. Frank Murkowski over a five-year exclusive development right forthe Alaska gas line.

The issue for the company was appar-ently one of commitment: When the stateturned down a proposal that the statereimburse it for half of the company’sestimated $100 million in developmentcosts, MidAmerican then said it would goahead with development work if the stategranted it a three-year exclusive right tobuild the pipeline;that was laterextended to fiveyears.

The companyclearly felt burnedby the Murkowskiadministration.

Sokol said at aMarch 26, 2004,press conferenceafter MidAmerican pulled out of thestranded gas contract negotiations thatMidAmerican “would have no interest inre-entering the project.”

He added that it is hard to do businesswith the state “when people don’t tell thetruth.”

The company argued that theMurkowski administration knew of therequest for exclusive rights beforeMidAmerican ever submitted its applica-tion, although the governor said at theadministration’s March 26, 2004, pressconference on the MidAmerican with-drawal:

“For me to arbitrarily go out and nego-tiate a binding contract for five years … is

something that I would be derelict in pro-posing,” Murkowski said. “In five yearswe could very well get the project back.”

Back in 2007Although in 2004 MidAmerican

bowed out, in 2007 it was back talking tolegislators about the proposed AGIA leg-islation, although it appeared to be skittishafter its 2003-04 experience.

Kirk Morgan, president ofMidAmerican subsidiary Kern River GasTransmission Co., told Senate ResourcesMarch 29: “We felt like, frankly, we werea stalking horse to create leverage for thelast administration. And we’re not com-ing up here to go through another beautycontest.”

Morgan said while alignment withboth the state and the producers is neces-sary for a successful project, it would goahead with project work while the statesettled alignment issues with the produc-ers.

And he said that while MidAmericandid not ask the state for the $500 millioncommitment in AGIA, “The alignmentthat the $500 million creates is extremelyimportant,” and not just to MidAmerican:“It’s an important signal to the market-place; it gives the project much morecredibility.” ●

continued from page 11

MIDAMERICAN

DAVID SOKOL

Sokol did not offer details onwhat that alternate way

forward might be, but said theState of Alaska and the federal

government, “teamed with aproven and nonconflicted

project development partner,will be required to successfully

move this project forward.”

continued from page 11

CONOCO

By KAY CASHMANPetroleum News

ne of the five proposals receivedunder the Alaska GaslineInducement Act to build a gaspipeline from Alaska’s North Slope

came from AEnergia, a recently formedAlaska limited liability corporation with aSacramento, Calif., address.

While the LLC might be new, itsmembers have been working on getting agas pipeline builtsince 2001under thejoint venture nameof GSS/TC.

But the experi-ence of AEnergia’smembers with anAlaska gas line pro-posal dates backmuch further thanthat. During the orig-inal effort to build anAlaska natural gaspipeline in the late1970s and early1980s, AEnergiacore members wereworking for the con-sulting firms thatprovided the earthsciences designexpertise.

AEnergia execu-tive Bill Burkhardtold Petroleum Newsin 2003 that by “pro-ject’s end, we hadcompleted about 70percent of the alignment geology, 50 per-cent of the surface and groundwaterhydrology, 30 percent of the geotechnicalengineering including thermal modelingand climatology, and a substantial portionof the environmental work.”

In 1982, after the project was termi-nated, “we went on to further our careerswith other firms,” he said. “Although wemoved to positions throughout the Westand Midwest, several of us kept in touchbecause of the strong relationships builtduring our ‘pipeline’ days. … We’vewanted to see a North Slope gas line builtfor 30 years.”

Reunited in 2001Burkhard and his associates contacted

their previous employers “to see if therewould be any possibility of continuingwork” on the latest proposal for a gasline. “We discovered they had essentiallymoved on and had no apparent interest inpursuing the work again,” he said. So, inthe fall of 2001, Burkhard reassembledthe “core group” and created “a newteam to pursue the earth sciences designwork should a pipeline project actuallystart up again” – a team that includedmost of the senior and staff-level person-nel working on the first gas line project’s

the earth sciences.GSS joint ventured with

Taber Consultants, becomingGSS/TC, “for business sup-port and project managementexpertise.” Burkhard saidTaber is “one of California’soldest geotechnical firms.”

Andy Taber, president of TaberConsultants, has participated in the pre-sentations Burkhard has made to compa-nies interested in seeing an Alaska gas linebuilt.

Goal to get pipeline builtBurkhard told Petroleum News this

Dec. 1 that since 2001 he has met with“Williams, BP, ConocoPhillips,ExxonMobil, JPO, DNR, a few differentcommissioners, Bechtel andWorleyParsons. (Among others), I’ve hadconversations on the phone with Fluor,Gulf Interstate, Michael Baker, Parsons,

Duke Energy, Alaska Gasline PortAuthority, TransCanada andKen Thompson.”

GSS/TC’s goal has been“to get the pipeline going,” hesaid.

Although Burkhard wasunwilling to provide details

about AEnergia’s AGIA proposaluntil the Palin administration’s review

was complete, he did say AEnergia’s pro-

posed pipeline would go from the NorthSlope to Calgary’s AECO hub where thegas would be distributed to the Lower 48through existing infrastructure, and thatAEnergia’s proposal would “support anancillary project to Kenai or Valdez,”including an LNG project.

If AEnergia’s proposal gets a greenlight from the State of Alaska, Burkhardsaid the company would begin fieldworkby April or May. ●

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 13

● N A T U R A L G A S

AEnergia not new to Alaska gas lineBurkhard says North Slope pipeline would go to Calgary AECO hub, and support ancillary line to Kenai or Valdez, including LNG

O

If AEnergia’s pro-posal gets a greenlight from the Stateof Alaska, BillBurkhard said thecompany wouldbegin fieldwork byApril or May.

Alaskagas pipelineupdate

ANDY TABER

Although Burkhard was unwillingto provide details about AEnergia’s

AGIA proposal until the Palinadministration’s review wascomplete, he did say … if

AEnergia’s proposal gets a greenlight from the State of Alaska, …

the company would beginfieldwork by April or May.

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Department of Natural Resources and thegas team leader, said the completenessreview of the applications by stateemployees and 11 consulting firms wouldbegin that night.

The five entities who applied underAGIA are: AEnergia LLC; the AlaskaGasline Port Authority; the AlaskaNatural Gas Development Authority;Sinopec ZPEB and Little SusitnaDevelopment Co.; and TransCanadaCorp. and Foothills Pipeline — threefamiliar players and two new entrants(see stories on AEnergia and Sinopec inthis issue).

Two companies which explored theopportunity but didn’t bid were BG andMidAmerican; the state also received anon-AGIA proposal from ConocoPhillips(see separate stories in this issue).

The applications will be available forpublic review once the completenessreview is done, a process which is expect-ed to take several weeks. The administra-tion had set Dec. 21 as the target date forputting applications online, but said thatbecause of the number of applications itmay take longer.

Once the applications are public therewill be a 60-day public review period.The commissioners of Natural Resourcesand Revenue will then recommend a proj-ect for legislative approval — or not, ifnone of the applications are found to be inthe state’s best interest.

Palin: ‘committed to AGIA’Asked about the non-AGIA applica-

tion the state received fromConocoPhillips, the governor said “weare committed to AGIA and to theprocess.” The entities who applied“played by the rules and followed thebenchmarks that we have asked for andhopefully will be fulfilling the ‘musthaves’ in Alaska’s requirements … arenot stalking horses,” she said.

The governor also said she hoped the

applications would“spur some interestby the producers.”

“Just because amajor producer has-n’t applied underAGIA doesn’t meanthat they cannot beparticipants in thisgas line. Once alicensee is chosen— Alaska’s best partner — then a third-party partner will no doubt be attractedalso by the licensee,” the governor said.

“Today’s progress, under AGIA,demonstrates to the world that Alaska iswell on our way to bringing this longsought after and necessary infrastructure,a natural gas pipeline, to fruition.” Palinsaid the gas line would “feed hungry mar-kets and help secure our United Stateswith Alaska’s abundant North Slope ener-gy.”

What state will look forRutherford said that chief among what

the state will look for in the applicationsis “access for all gas explorers; expansionassured for companies with new gas vol-umes; a reasonable and hopefully verylow tariff structure; and moving the gaspipeline project forward expeditiously.”

DNR Commissioner Tom Irwin saidAGIA represents “a change in howAlaska really moves forward on the gasline.” He said the message to the appli-cants is that the administration “clearlysupports AGIA” and now that the appli-cations have been submitted, they will bereviewed on the foundation set by thegovernor: “integrity, fairness, transparen-cy.”

Revenue Commissioner Pat Galvinsaid AGIA “was designed to set up a com-petition and that’s what we have.” Thestate’s obligation now is “to review theapplications and ensure that in the end wehave a project that meets the state’s inter-ests and moves forward as expeditiouslyas possible.”

The producer issueRutherford con-

curred with the gov-ernor’s remarks onthe ConocoPhillips’proposal: It is “out-side AGIA andwe’re committed toAGIA.”

She also said thatsince the administration began talkingabout AGIA to the Legislature its stancehas been that even if the major NorthSlope producers — BP, ConocoPhillipsand ExxonMobil — “chose not to partici-pate as applicants to build the project, weare convinced that these world-class cor-porations will in fact ship gas when theyknow what the construction costs and thetariff structure will be.”

“They need to monetize that asset;they need to book those reserves; andthey need to honor their lease responsibil-ities to the State of Alaska,” Rutherfordsaid. She added that although the produc-ers talk about owning the leases, “theyown the leases with obligations to theState of Alaska to move our resource tomarket when it’s economic to do so. AndI believe they will honor that and so Idon’t think it makes much of a differenceto our process” that the producers haven’tapplied under AGIA.

Rutherford said the state will move theproject forward and predicted that “at theend of the day” the producers will agreeto ship gas.

The evaluation processUnder AGIA, Rutherford said, the

evaluation process involves determiningwhat the proposals do “in terms of the netpresent value for the State of Alaska andwe have to weight that by the likelihoodof success. So there’s both a quantitativeand a qualitative aspect to that evaluationprocess.” The consultants involved in theevaluation will assist the state with arange of issues including financial, mod-eling and engineering.

Compared to the previous StrandedGas Development Act negotiations,Rutherford said “one of the things that’sso critical about AGIA is that we haveidentified what requirements are neces-sary in a gas pipeline to ensure Alaska’slong-term economic interests.” Thoserequirements are laid out in AGIA, andensure “that this is truly an open-accesspipeline, with reasonable, low initial tar-iff structure and a real commitment andresponsibility to expand when new gas isavailable.”

She said “probably one of the mostsignificant differences between whatoccurred under the previous administra-tion and this one is that our long-termfinancial interests and the nation’s inter-ests in getting gas to market are protectedby these must haves, these commercialelements.”

The benchmarks to move the projectforward expeditiously are also critical,Rutherford said, “because we do not wantAlaska’s gas displaced by other energy

sources moving into the marketplace.”

The in-state entitiesTwo in-state entities, one representing

municipalities and the other part of thestate, were among the applicants.

The Alaska Gasline Port Authority, ajoint venture of the North Slope Borough,the Fairbanks North Star Borough and theCity of Valdez, is a municipal entityestablished in 1999 to build a gas pipelinefrom the North Slope to Valdez and takeAlaska North Slope natural gas to marketas liquefied natural gas.

In a statement after the port authorityapplication was turned in its board chair-man, Jim Whitaker, the mayor of theFairbanks North Star Borough, said theport authority’s “mission, since day one,has been focused on bringing the maxi-mum benefits of North Slope gas devel-opment to the people of Alaska in theform of access to gas, greater competitionin the development of gas, new andexpanded value added industries through-out the state and jobs for Alaskans.”

The port authority’s project managerand general counsel, Bill Walker, said theport authority has “worked with some ofthe biggest companies in the world in thefields of project engineering, finance,shipping and marketing, to put this pro-posal together” and look forward to work-ing with the Palin administration to pro-vide any further information needed.

The other in-state entity, the AlaskaNatural Gas Development Authority, wasestablished by statewide voter initiative.Its original purpose was to build a line toValdez for an LNG project, but ANGDAhas taken on ensuring that natural gasreaches Alaska consumers, both thosealong the main gas pipeline and in otherareas of the state. ANGDA’s AGIA appli-cation is designed to bring natural gas toSouthcentral Alaska via a spur line.

Unlike the other applications, thatfrom ANGDA is already public as it isposted on ANGDA’s Web site atwww.angda.state.ak.us/. There are twoapplications, one of which would workwith an Alaska Highway line, the other ofwhich would work with a line parallelingthe trans-Alaska oil pipeline to Valdez.

ANGDA’s applications are designed toaccompany a mainline application.

The pipeline: TransCanadaAn AGIA application from

TransCanada, the big Canadian pipelinecompany, was not a sure thing.

The company told legislators duringAGIA hearings that it was not comfortablewith the AGIA requirement to proceedthrough a Federal Energy RegulatoryCommission certificate even if an initialopen season failed to attract shippers to theline, a provision the administration saidwas crucial to ensure that producers could-n’t kill the project by not nominating gasfor the pipeline in an initial open season.

Tony Palmer, vice president of Alaskabusiness development for TransCanada,told legislators early this year, when AGIAwas being debated, that TransCanadawould not want to continue past a failedopen season to get a FERC certificate. Hesaid monies spent after a failed open sea-son to get a FERC certificate “are truly atrisk if the project does not proceed.”

And it’s not just the money, he said,people would have to be dedicated to theproject and it would “take a significantdedication of our corporation’s talent topursue the project.”

TransCanada, an independent pipelinecompany, is the holder of the rights grant-ed for the original North Slope gas pipelineand as such has a 30-year history with theproject, Palmer said in March.

14 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

continued from page 1

BIDS

GOV. SARAH PALIN MARTY RUTHERFORD

see BIDS page 15

He also told legislators thatTransCanada believes a compromise mustbe reached between the producers and theState of Alaska. “TransCanada believes themost expeditious and equitable path for-ward for the project is a collaborativearrangement between the state and the pro-ducers, the state and TransCanada,” hesaid.

Palmer said TransCanada believes afive-party arrangement is necessarybetween the producers, the state and

TransCanada. The company holds a FERC certificate

dating from the original Alaska Highwaygas pipeline project, under the AlaskaNatural Gas Transportation Act. “It is aconditional certificate, but there has been aFERC certificate for this project for 30years,” Palmer told legislators: “It’s cus-tomers this project has lacked.”

TransCanada would prefer, he said, thatif an initial open season fails the focuswould be on obtaining customers “asopposed to doing the engineering and reg-ulatory and legal work to capture a FERCcertificate.” ●

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 15

continued from page 14

BIDS

PIPELINES & DOWNSTREAM

Agrium’s last Alaska cargo ship sets sailOn Dec. 5 the last cargo ship left Agrium’s nitrogen facility in Nikiski, Alaska,

for Korea, carrying 27,000 tons of fertilizer. In September, Agrium USA’s parent company, Agrium Inc., based in Canada,

said it was closing its Alaska facility because it was unable to find enough natu-ral gas to purchase. Natural gas is necessary for the production of fertilizer. Thecompany purchased 53 billion cubic feet of natural gas in 2001, but this yearcould only purchase 10 billion cubic feet.

Agrium officials say 80 workers lost their jobs the week of Dec. 2. An addi-tional 50 will be laid off in coming months as the plant is mothballed.

The company has set up a temporary job center to help displaced workers findemployment.

Agrium said in September its remaining Alaska staff would continue to workon the “feasibility of a coal gasification project to use coal as a feedstock” insteadof natural gas for the Kenai facility. A decision on whether to proceed with thenext stage of the project is anticipated later this year. The earliest a gasificationfacility could be operational is 2012, the company said.

Agrium said it had “diligently attempted to encourage development of naturalgas supply and to negotiate contracts for 2008 and beyond,” but “despite theseefforts, and after offering what it believed to be competitive prices and incentives,Agrium was unable to secure gas supply.”

—KAY CASHMAN

Agrium’s facility in Nikiski, Alaska.

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Aboriginal Pipeline Group taking con-trol away from a consortium of oilcompanies led by Imperial Oil Ltd.,sources said yesterday.”

After six months in limbo becauseof increasing costs to build the line, “itappears the producers are prepared tostep aside and let TransCanada,Canada’s largest pipeline company,take the lead with 60 percent owner-ship, with the rest going to the APG, aCalgary-based organization represent-ing aboriginal groups in the North,” thenewspaper reported.

“The new partnership is expected toseek help from Ottawa in the form ofloan guarantees, shipping commit-ments or other breaks for the multi-bil-lion-dollar project,” Financial Postsources said.

Under what the newspaper referredto “the so-called Plan B,” the oil com-panies that are part of the MackenzieGas Project — Imperial (almost 70 per-cent owned by ExxonMobil), Shell,

ConocoPhillips and ExxonMobil —would become shippers with long-termcommitments.

TransCanada involvement in theMackenzie pipeline to date has beenfinancing APG. The Financial Post saidsaid its involvement in Plan B “wouldbe welcomed by oil companies outsidethe Imperial partnership that wouldalso like to ship gas on the system.”

The newspaper also saidTransCanada’s “involvement is seen asimproving the pipeline’s chances ofsuccess because the regulated companyhas lower profit expectations than oilcompanies.”

Rumors of the new deal surfaced inlate November, around the time thattwo years of regulatory hearings on theMackenzie line ended.

Imperial spokesman Pius Rolheiserwould not comment on the rumors, theFinancial Post said. Rolheiser told thenewspaper that a decision from theNational Energy Board on whether theproject can move ahead is expected inmid-2009. A spokesman forTransCanada would also not comment.

—KAY CASHMAN

continued from page 1

TRANSCANADA

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16 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

2007 drilling.On Aug. 14 the court placed a tempo-

rary injunction on Shell’s drilling activi-ties until the appeals against the explo-ration plan approval were resolved, thuseliminating any realistic possibility ofShell starting its drilling program in 2007.

The oral arguments presented on Dec.4 revolved in part around the question ofwhether the MMS lease sale environmen-tal impact statement considered in enoughdetail the types of activity described inShell’s exploration plan, or whether theexploration plan should have triggered anew EIS.

Tiered approachUnder the terms of the National

Environmental Policy Act, MMS uses atiered approach to environmental permit-ting, in which a broad EIS prior to start-ing an offshore lease sale program deter-mines whether lease sales should pro-ceed. Further EISs may be done subse-quently, targeting specific exploration ordevelopment activities that might have asignificant environmental impact notfully considered in the earlier, broaderEIS. A proposal to develop an offshoreoilfield, for example, would almost cer-tainly trigger the need for a new EIS spe-cific to that development.

MMS had published a multi-sale EISfor its Beaufort Sea oil and gas leasingprogram. Then, when Shell submitted itsBeaufort Sea exploration plan, MMS con-ducted an environmental assessment thatconcluded that the company’s plannedoperations came within the scope of the

multi-sale EIS and could proceed.Not so, said the appellants.“Here you have a cursory EA (envi-

ronmental assessment for Shell’s explo-ration plan) that, fails to assess the actualdrilling proposals effects on whales andcompletely refuses to analyze the poten-tial for a crude oil spill and its effects onthat environment,” Dierdre McDonnell,the attorney representing the AlaskaWilderness League and environmentalorganization REDOIL, told the judgesduring oral arguments. “… The multi-saleEIS … looks at general past informationand studies about the effects of noise onbowhead whales. What that informationshows is that those effects can be signifi-cant.”

The environmental impact mitigationmeasures spelled out in the leasing pro-gram EIS do not support the MMS deci-sion to forgo an EIS specific to Shell’sdrilling program, Christopher Winter,attorney for the North Slope Borough andAlaska Eskimo Whaling Commissiontold the judges.

“The Minerals Management Servicesimply does not know enough about thepotential impact on the Arctic environ-ment to approve a three-year explorationplan and environmental assessment,”Winter said. The noise from drill shipsand icebreakers would deflect bowheadwhales from their normal migrationroutes, thus creating a major safety risk towhaling captains and crews and threaten-ing a key source of food for North Slopecommunities, he said.

Winter said that in its EIS and environ-mental assessment MMS had concludedthat Shell’s exploration activities mayhave a significant impact on the subsis-tence hunt of bowhead whales. To avoid

the need for a further EIS MMS mustdemonstrate that specified mitigationmeasures would prevent those significantimpacts, he said.

“In this case the Minerals ManagementService cannot make that showing,”Winter said. “MMS has not imposed anyspecific mitigation measures on Shell as apart of this project.”

MMS: specific mitigationBut MMS has imposed very specific

mitigation measures through the terms ofits leases, said David Shilton, attorney forMMS. One of those measures is therequirement for a conflict avoidanceagreement with the subsistence hunters,he said.

“Shell must sit down with the subsis-tence whalers and hammer out an agree-ment to protect their subsistence hunting,and that is something that has been doneover the years successfully,” Shilton said.“… This year there was a conflict avoid-ance agreement which would have hadShell pull all of their assets off of thedrilling for the time that whale hunterswere out there.”

Shell also has to obtain an incidentalharassment authorization from theNational Marine Fisheries Service,Shilton said. NMFS applies a very strictstandard that requires Shell to demon-strate that it will have a negligible effecton the stock of whales.

“The mitigation is specific, it’s beentested, it was evaluated in the multi-saleEIS and found to be effective,” Shiltonsaid.

Shilton also commented that the analy-sis in the multi-sale EIS considered thetype of activities that Shell plans to carryout.

As part of their challenge to the ade-quacy of the multi-sale EIS, attorneys forthe appellants questioned how the broadmulti-sale EIS could apply to Shell’sdrilling plans without considering thespecific location and timing of thedrilling. Not only that, but MMS hadapproved the exploration plan withoutspecific information about where thedrilling would take place after 2007, theattorneys said.

The multi-sale EIS says that the timeand location of activities need to be con-sidered in evaluating potentially signifi-cant impacts on bowhead whales,MacDonnell said.

“This is what needed to be consideredthe EA, but it was not,” she said.

“As MMS stated in the multi-sale EISit’s extremely important, especially withrespect to subsistence, to consider thesite-specific nature of exploration activi-ties,” Shilton said. “… It’s the specific

timing and location which can interferewith the subsistence hunt.”

The bowhead whale migration route isvery broad, so that the precise location ofdrilling activities would have little bear-ing on bowhead migration, counteredHilton. Not only that, but knowing whereShell’s leases are located, it is possible toassess the Shell’s potential drilling loca-tions within an area of just a few squaremiles, he said. Also, Shell has to apply fordrilling permits each year and the appli-cations to drill give MMS the opportunityto fully evaluate the impact of drilling atspecific sites.

Shell: transitory activityShell attorney Kyle Parker character-

ized Shell’s planned drilling as a transito-ry activity to gather information about oiland gas prospects.

“Our exploration project is limited intime. … We’re not going to leave any per-manent facilities on location,” Parkersaid. “That is why the agency (MMS) hasadopted this program … whereby we dothe comprehensive environmental impactstatement prior to the (lease) sale. It cov-ers all of the anticipated activities. …Provided the activities we’re proposingwere analyzed … they’ll approve our planof exploration and allow us to go forwardwith our work.”

The multi-sale EIS adequatelyincludes an analysis of all of the issuesraised by the organizations appealing theexploration plan approval, he said.

In the past, 30 exploration wells havebeen drilled in the Beaufort Sea, with 12of those wells drilled near the Sivulliqprospect, Parker said.

“All of the data related to the drillingof those wells, all of the data related to theinteractions with the whaling, all the datarelated to the ice management activitiesthat took place during those open waterdrills, all of that is encompassed in thethree-volume, multi-sale EIS,” Parkersaid. “That forms the basis for our planapproval.”

Shell identified four specific well loca-tions for the first year of its drilling pro-gram. The MMS director determined thatthere was sufficient information aboutShell’s drilling plans in subsequent yearsto approve the exploration plan, providedthat Shell submits an amended plan onceit has determined where specifically todrill next, Parker said.

“In fact he is obligated at that point togo through an analysis and determinewhether something we’ve proposed inyears two and three falls outside theanalysis that was done in the multi-saleEIS,” Parker said.

—ALAN BAILEY

continued from page 1

SHELL

junction with other regulations, “accordto the DNR the administrative authorityto either adjudicate default or to terminatea unit agreement?” And if state regula-tions can be read to “permanently certifya well as capable of producing hydrocar-bons in paying quantities for regulatorypurposes, would that regulation be incon-sistent” with the Point Thomson unitagreement? These supplemental briefsare due Dec. 7.

AOGCC won’t stay decisionThe Alaska Oil and Gas Conservation

Commission, meanwhile, said recently thatit will not stay a decision on ExxonMobil’spetition for compulsory unitization of thePoint Thomson sand unit.

The commission held a hearing July 10to consider whether its proceedings shouldbe stayed pending resolution of the admin-istrative appeal of the status of the PointThomson unit in state court. The commis-sion said both DNR and ExxonMobilopposed a stay and no party argued in favorof a stay, so the commission is exercising itsdiscretion and will not order a stay.

In its Nov. 28 order the commission saidExxonMobil’s petition “involves highlyunusual circumstances that raise novel andprobably unique legal issues,” with the peti-tioner seeking “compulsory unitization ofan area that has already been in a voluntaryunit” approved — but recently terminated— by the Department of Natural Resources.

“The petitioner and others are challeng-ing DNR’s decision in Superior Court,” thecommission said, so the petition to the com-mission “implicates the relationshipbetween the respective unitization authori-ties” of AOGCC and DNR.

Multiple issuesThe Commission said parties identified a

number of issues related to unitizationauthority:

• Does the commission have “jurisdic-tion or authority to unitize state oil and gasleases that DNR has ‘de-unitized;’”

• Can the commission “adopt a view thatis at odds with DNR’s view of how unitiza-tion of the area in question affects the pub-lic interest;”

• Whether compulsory unitization by thecommission “would interfere with DNR’smanagement of state lands and if sowhether administrative comity (legal reci-procity) bars the commission from so act-ing;”

• “Whether the commission’s compulso-ry unitization authority is triggered by thefailure of a lessor … to agree to voluntaryunitization when the lessees have agreed tovoluntary unitization;” and

• “Whether the petitioner’s interestswould be prejudiced by a stay.”

The commission said that if the petition-er prevails in court, its petition to AOGCC“and all of these issues will become moot,because the pre-existing DNR-approvedunit will have been reinstated or determinednot to have been terminated.”

If the petitioner does not prevail in court,the leases will have expired and “the peti-tioner may lack standing to proceed” andthe issues cited before the commissionwould also become moot. “Even if they donot become moot, they are likely to be nar-rowed and better illuminated as a result ofresolution of the administrative appeal,” thecommission said.

Issues to be addressedThe commission said DNR raised sever-

al issues that DNR believes would result ina dismissal of the petition without a hearingon the merits if the commission ruled inDNR’s favor. But the commission saidthose issues were raised in the context of thecommission’s proposal to stay proceedings,“and it is not clear, therefore, that other par-ties have had an adequate opportunity torespond, or for that matter whether DNRhas fully addressed the issues on their ownterms.”

The commission said it is providing anopportunity for all parties “to submit andrespond to potentially dispositive motions,including motions in the nature of motionsfor summary judgment.”

The commission has asked parties toconfer and agree on a schedule for submis-sion and has also asked the parties “to con-sider whether or not any factual issues mayexist that would require an evidentiary hear-ing to resolve.”

The parties have 30 days from theNov. 28 order to submit a schedule; ifthey cannot agree, then parties wishing tobe heard may each file schedules. ●

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 17

continued from page 1

POINT THOMSON EXPLORATION & PRODUCTIONFormer ARCO chief Anderson dies

Former oil executive Robert O. Anderson is being remembered by family andfriends as a successful businessman who had an impeccable reputation in the oilindustry.

Anderson, who served as chief executive officer of the Atlantic Richfield Co.for nearly two decades and later formed the Hondo Oil & Gas Co., died Dec. 2 athis home in Roswell, N.M., his family told the Roswell Daily Record. Andersonwas 90.

Gov. Bill Richardson said Dec. 3 he would order flagsaround the state to fly at half-staff in honor of Anderson,who he described as an outstanding New Mexican who wasdedicated to civic and environmental issues.

“He has left an everlasting impression on the petroleumindustry and New Mexico,” the governor said.

Anderson was born in Chicago on April 13, 1917. Hegraduated from the University of Chicago in 1939 and wenton to work for the American Mineral Spirits Co. He laterpurchased a small oil refinery in southeastern New Mexicoand bought and expanded several other refineries.

He served as chief executive officer of ARCO for 17 years. He also was chair-man of the board for 21 years. During his tenure, ARCO developed one of thelargest oil fields in North America.

He retired from ARCO in 1986 and formed the Hondo Oil & Gas Co. ofRoswell. He served as the company’s CEO until he retired in 1994.

“He was one of the greatest businessmen I think I have ever worked with,” saidDon Kendall, a former chief executive officer of PepsiCo.

U.S. Sen. Pete Domenici, R-N.M., called Anderson a “rare individual” whosecontributions went beyond energy and business.

“There is a Bible verse that says to whom much is given, from him much willbe required,” Domenici said. “Robert understood this and actively parlayed hisbusiness success to education, civic and charitable causes. That will be his lastinglegacy.”

Anderson sat on the board of regents at the New Mexico Institute of Miningand Technology from 1987 to 1992 and was named as a distinguished professorin 1994.

The University of New Mexico named its business school the Robert O.Anderson School of Management in his honor.

Anderson also served as chairman of the Federal Reserve Bank of Dallas from1961 through 1964 and was a member of numerous boards, including ChaseManhattan Bank, First National Bank of Chicago, the National Petroleum Counciland Pan American Airlines.

—THE ASSOCIATED PRESS

ROBERT O. ANDERSON

year’s C$6.5 billion to C$4.5-$4.92 bil-lion.

Conventional spending is budgeted atC$1.7 billion, off 33 percent from 2007,with C$645 million of that reductionblamed on Alberta’s royalty hikes.

Overall production will be cutAs a result, its overall production will

be cut for the first time in a decade, withoutput down 4 percent from this year’smidpoint at 554,000-618,000 barrels ofoil equivalent per day.

In case the government was missingthe point, senior Canadian Natural execu-

tives made little attempt to hide their feel-ings.

Vice Chairman John Langille said thenew royalties, scheduled to take effect in2009, would wipe out the “vast majorityof any increases in natural gas prices formost of our natural gas wells. As such, theability to increase natural gas drillingactivity with increasing gas prices isseverely impacted.”

President Steve Laut said the proposednew royalties pushed the economicthreshold for wells producing at least 600million cubic feet per day to C$11 perthousand cubic feet from C$8.

Drilling those deep, high volume wellsis “unsustainable … by taking away theprice upside and the (well) rate upside,”he said.

Laut indicated the new royalties forshallow and coalbed methane wells wasacceptable, but misplaced at a time whenAlberta needed “big reserve, big ratewells … so it’s counter-productive.”

He said the royalty plan has removedthe “error bar … so we have much lesstolerance for any kind of risk.”

Langille said the independent is “facedwith eroded economics due to low com-modity prices and a new royalty regimethat reduces the returns on certain typesof drilling.”

The immediate result will be a 12 per-cent drop in Canadian Natural gas outputin 2008 to 1.4 billion-1.5 billion cubicfeet per day.

Company says worse could comeBoth Langille and Laut drove home

the point that unless the governmentmakes changes to its royalty framework,there could be worse to come.

That warning was accompanied by asharp uptick in 2008 spending outsideAlberta.

In contrast to the 44 percent reductionin Alberta gas drilling, British Columbiaand Saskatchewan will see a combined 8percent increase, while the 20 percent cutin Alberta’s conventional crude oildrilling will be countered with a 30 per-cent hike in British Columbia andSaskatchewan.

The initial response from EnergyMinister Mel Knight was to assign mostof the blame to low gas prices, althoughhe grudgingly conceded that removing a“certain amount of capital from the indus-

try” would at some point be reflected inCanadian Natural’s budget.

But Greg Stringham, vice president ofthe Canadian Association of PetroleumProducers, said his organization has start-ed meeting with Knight and his depart-ment to discuss the “unintended conse-quences” of the royalty framework anddetermine what can be done to deal withthose concerns while maintaining theoverall royalty regime.

Stelmach used almost those exactwords in telling an Edmonton audiencethat “if there are unintended conse-quences as a result of the framework nextyear, then we need to discuss them andaddress them.”

“We heard the concerns being raisedby small producers, for example, and Iwant to assure industry and thoseAlbertans who work for these companiesthat we’ll listen closely to your concerns,”he said.

Royalty implementation teamTo explore those matters, the govern-

ment has formed a royalty implementa-tion team with CAPP and the SmallExplorers and Producers Association ofCanada prior to tabling legislation nextyear.

He said there could be changes to deepgas royalties and the royalty formulas theindustry argues would make drillinguneconomic in some regions of Alberta.

However, Stelmach assured theAlberta legislature he will not shift fromhis basic objective of a 20 percent overall

18 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

continued from page 1

THOUGHTS

Alberta to set bitumen ‘benchmark’The Alberta government is aiming for mid-2008 to set a “benchmark” value for

oil sands bitumen, a key element in its drive to keep more value-added upgrading andrefining in the province.

Finance Minister Lyle Oberg said the fact that bitumen is not deemed a “fullymarketable commodity” requires a careful tracking of product pricing and relatedmechanisms to arrive at the “benchmark” figure.

He said the 250,000 barrels per day of bitumen being traded on the New YorkMercantile Exchange will be taken into account, but that volume represents less thanone-quarter of Alberta’s output.

The process must be completed before Alberta can consider taking bitumen in lieuof royalties and strategically using the product to supply potential upgraders andrefineries in the province.

Premier Ed Stelmach has raised concern about the increasing bitumen exports tothe United States and the accompanying loss of jobs and revenues.

In its new royalty framework, the government said the province “needs to addvalue to its exports and expand its economy by upgrading resources in Alberta … tosecure jobs and prosperity for future generations of Albertans.”

It ruled out as ineffective the use of a 5 percent upgrader credit as an incentive forindustry to upgrade and refine in Alberta.

Renegotiation deadlineOn a more delicate matter, the government is facing a Jan. 22 deadline to renego-

tiate royalty agreements with Syncrude Canada and Suncor Energy that were due toexpire in 2016.

Determined to create a level playing field for all oil sands producers, the govern-ment stirred widespread unease when it decided existing agreements could not sur-vive its planned changes.

That has posed a dilemma for the government — to honor contracts or treat every-one equally.

One member of the royalty review panel, who did not want to be identified, saidthe only way the government will persuade Syncrude and Suncor to abandon theircurrent deals is through a buyout that could cost billions of dollars.

What is at stake has been underscored by Marcel Coutu, chief executive officer ofCanadian Oil Sands Trust, a 36 percent partner in Syncrude.

“We must ensure that our legal rights are preserved,” he said.—GARY PARK

see THOUGHTS page 19

increase in royalties, which is expected togenerate an extra C$1.4 billion in rev-enues in 2009, although the door is opento tweaking parts of the regime that areunreasonably punitive to some sectors.

Oberg told a Calgary conference thatsince the royalty package was released inOctober, some “inconsistencies” havesurfaced on deep gas and “we’re current-ly taking a look at how we’re going towork with deep gas.

“I think there is a case to be made fordeep oil, which is a very similar type ofarrangement. We may have to (provideincentives), we may have to be a contrib-utor to ensure the oil is brought out of theground,” he said. “It’s an advantage to(government) to get that oil out.”

One of the seven candidates defeated ayear ago by Stelmach in the contest forleadership of the Conservative party,Oberg also appeared to be putting somespace between himself and the govern-ment’s royalty overhaul.

He said the royalty review was trig-gered during the leadership campaign,when all candidates clambered aboard thebandwagon, under pressure from journal-ists and columnists who said a review waslong overdue.

Oberg noted that he raised concernsduring the review panel’s hearings aboutthe impact of higher royalties and wasrebuffed.

He said the government wants to be

sure its new royalties are consistent withits efforts to sell Alberta’s political stabil-ity to investors.

“It may be cheaper to produce oil inVenezuela, but (President Hugo) Chavezis unpredictable … in Russia there aregeopolitical issues,” Oberg said.

Stringham said there is no doubt the

deep oil and gas producers would take anunfair hit because of a framework thatonly covers wells as deep as about 13,100feet , where the royalties cap out.

Wells below that level “are really highcost, but bring a lot of gas for theprovince and a lot of royalties becausethey are high productivity wells, are very

negatively impacted,” he said.In addition, Stringham noted that even

with oil prices at US$85 per barrel, theroyalty rate for new oil being developedin Alberta goes up almost 300 percent,while the province’s oil exploration pro-gram has been eliminated, meaning a lotof oil would be left in the ground. ●

PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007 19

continued from page 18

THOUGHTS

satellite drilling island, six developmentwells will be drilled from an expansion ofthe satellite drilling island, a reduction of 17from the original plan.

Because the project will be drilled “fromthe existing Endicott industrial complex”

and because ultra-extended-reach drillingwill be used, “many potentially adverseimpacts to the human environment are miti-gated,” MMS said.

The original project, for which an envi-ronmental impact statement was prepared in2002, had a subsea sales oil pipeline, a newgravel offshore island for drilling and pro-cessing and required 23 wells.

MMS said the evolution in the plan fromthe original standalone project reflects,among other things, environmental mitiga-tion, advances in ultra-extended-reachdrilling technology, use of depth-mitigated3-dimensional seismic data and advances inreservoir modeling.

The environmental assessment is basedon a development and production plan BPsubmitted in April (see story in May 20 issueof Petroleum News at www.petroleum-news.com/pnads/801208341.shtml).

Amodification submitted in October out-lined redesign of the gravel mine site adja-cent to the existing Duck Island mine site, anupgrade of the Sagavanirktok River bridgesuperstructure (vs. replacement of the entirebridge) and a preliminary construction planfor the bridge, the agency said.

Both oil and gasMMS said potential recoverable

resources at Liberty include up to 105 mil-lion barrels of crude oil and up to 78.5 bil-lion cubic feet of natural gas, including nat-ural gas liquids.

“Liberty is one of the largest undevel-oped light-oil reservoirs near North Slopeinfrastructure,” MMS said. The estimatedrecovery of 105 million barrels would be bywaterflood and BP’s trademarked low-salin-

ity enhanced oil recovery, LoSal™. Production would be from one to four

producing wells and one or two water injec-tion wells. Oil would be sent from theEndicott satellite drilling island to theEndicott main production island for process-ing and then would be transported to thetrans-Alaska oil pipeline via the existingEndicott sales-oil pipeline. Produced gasfrom the project will be used for fuel gas andartificial lift for Liberty; the balance wouldbe reinjected into the Endicott reservoir for

enhanced oil recovery. Water for waterflood would be provided

from the existing produced-water injectionsystem available at the secondary drillingisland, and augmented if necessary by sea-water from the Endicott seawater treatmentplant, MMS said. The LoSal™ enhanced oilrecovery process to be employed during aportion of the waterflood will be supplied bya LoSal™ facility constructed on the mainproduction island.

Alternatives considered for Libertydevelopment include an offshore island, adrilling pad at Point Brower and a drillingpad at Kadleroshilik.

Both the environmental assessment andthe finding of no significant impact areavailable online at www.mms.gov/alaska.

—KRISTEN NELSON

continued from page 1

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MMS said the evolution in the plan from the original standalone projectreflects, among other things, environmental mitigation, advances inultra-extended-reach drilling technology, use of depth-mitigated 3-

dimensional seismic data and advances in reservoir modeling.

The finding of no significantimpact notes that by developing

Liberty with ultra-extended-reachdrilling from the Endicott satellite

drilling island, six developmentwells will be drilled from an

expansion of the satellite drillingisland, a reduction of 17 from the

original plan.

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conceding the challenge of producing thegas in a harsh climate and a sensitive envi-ronment.

He said there are environmental, techno-logical and regulatory hurdles to clear, but“this is a project that I think makes a lot ofsense from a resource point of view, fromCanada’s point of view.”

In the heat of the battle for Canada

Southern, Petro-Canada said it had no plansto develop Arctic gas because of the chal-lenges — technology, fiscal regime, finan-cial strength of potential partners, com-modity prices and the lead time to initialproduction — that blocked the delivery ofgas to market in a “reasonable timeframe.”

‘80s plan to ship LNGBut, in 1980, the company and others

promoted the idea of an Arctic pilot projectto ship LNG to southern markets.

That concept has gained some supportfrom the Canadian Energy ResearchInstitute which said three years ago thatHigh Arctic gas could be developed by2020, using LNG, compressed natural gasor gas-to-liquids, all of which it suggestedcould generate more than the 15 percentminimum rate of return needed to exploit10.2 tcf of gas-in-place on Melville Island.

That study said LNG presented twooptions — tanker shipments to regasifica-tion plants in Nova Scotia or New

Brunswick, or transshipping LNG fromicebreaking tankers to conventional vesselsin West Greenland, thus reducing capitalcosts for vessels and offering greater flexi-bility in the choice of markets.

On other, more immediate fronts,Brenneman said Petro-Canada was on theverge of correcting its public image of“overpromising and under delivering.”

“With the asset base and opportunitiesthat we have, it’s all about execution,” hesaid. “We have to deliver on what’s in frontof us.”

On the heels of record financial resultsin the first half of 2007, he said Petro-Canada is on track to boost production by15 percent in 2008, putting it somewhere inthe range of 400,000-420,000 barrels of oilequivalent per day.

Because of the company’s record ofmissed production targets, it has laggedbehind its Canadian peers on the Standard& Poor’s/Toronto Stock Exchange energyindex, returning 121 percent (includingdividends) over the past five years, com-pared with the index average of 208 per-cent.

Brenneman said that although Alberta’sroyalty proposals will see spending shift toother areas, such as the U.S. Rockies andSyria, the portfolio of oil sands projectsremains viable.

He said the projects at Fort Hills andMacKay River will be affected by the roy-alty increase, but “it’s not sufficient to real-ly impair the overall viability of them.”

“At this point, they still look like prettysolid projects and I think that’s because, forthe most part, we’re dealing with very highquality resources and very good projectsand they’re the ones that should survive thenew royalty regime.”

Petro-Canada’s confidence in the C$14billion Fort Hills venture was reinforcedwhen it acquired an additional 5 percentfrom partner UTS Energy for C$375 mil-lion after the original royalty review panelreport was issued in September.

Brenneman said the company is open totaking an even larger equity interest if onebecomes available.

In addition, Petro-Canada has hired anengineering firm to evaluate the potentialfor a 300,000 bpd oil sands project at itsLewis lease.

—GARY PARK

20 PETROLEUM NEWS • WEEK OF DECEMBER 9, 2007

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PETRO-CANADA

● N A T U R A L G A S

Enstar: Parks Highway gas spur line viableBy ALAN BAILEY

Petroleum News

gas spur line following the ParksHighway and connecting theMatanuska-Susitna valleys gas gridwith the Nenana basin, Fairbanks and a

future North Slope gas line would be viable,even without an industrial gas consumer to bolsterthe gas demand, Enstar spokesman Curtis Thayer toldPetroleum News Nov. 28.

“The approximate cost of that line that we’ve looked atis about $700 million,” Thayer said. “… A $700-millionline to Fairbanks or the Nenana basin — that clearly workswithout an industrial anchor.”

The spur line might take four to five years to complete,Thayer said.

In 2005 Enstar partnered with Arctic Slope RegionalCorp. and Michael Baker Engineering in a conceptualstudy of the Parks Highway spur line route. Meantime, theAlaska Natural Gas Development Authority has obtained aprovisional right of way for an alternative spur line routethat would follow the Glenn Highway from Glennallen inthe Copper River Valley.

Both routesIt is important to consider both pipeline routes, although

the Parks Highway option does have road, railroad and

electrical intertie rights ofway along its route,Thayer said. A ParksHighway line wouldpass close to theNenana basin, which

might hold 3 trillion to 5trillion cubic feet of natu-

ral gas, he said.Thayer also said that a provision

in the new state production tax thattaxes any Alaska gas produced foruse in state at the same favorable rateas Cook Inlet gas has improved thespur line economics. Enstar andNative regional corporation DoyonLtd. had lobbied for that tax provi-sion, he said.

Andex Resources and its partnersUsibelli Energy, Arctic Slope Regional Corp. and DoyonLtd. have been exploring for gas in the Nenana basin andcompleted a 2-D seismic survey in the basin in the springof 2005. But Tom Dodds, president of Andex, told theAlaska Legislature in 2006 that Andex and its partners hadplaced on hold the planning of a Nenana basin gas explo-ration well, pending resolution of the proposed petroleumproduction tax.

Enstar is also still looking at the concept of a “bulletline” connecting North Slope gas into Southcentral Alaska,

Thayer said.“Our engineering department is looking at it,” Thayer

said. “We had a meeting just two weeks ago on theprogress of that.”

With a price tag in excess of $2 billion and a raft of per-mitting and construction complexities, viability of the bul-let line would require an industrial anchor such as an LNGor fertilizer plant. So, proving out gas in the Nenana basinwith a view to building a spur line would seem to makesense as a first option, Thayer said.

FinancingAnd financing for a spur line or bullet line?Enstar would seek partners for the project, said Colleen

Starring, Enstar’s regional vice president. But Cap RockHoldings, the company that bought Enstar’s parent compa-ny Semco in October, also has a significant interest inAlaska developments.

“They’re very interested in Alaska — one of the reasonsthey purchased Semco was the Alaska properties,” Starringsaid. “They see tremendous opportunities up here.”

And Enstar has the necessary experience to build amajor Alaska gas transmission line, Thayer said.

“We own and operate more gas distribution and trans-mission lines than any other company in Alaska,” Thayersaid. “It’s how we make our money. We’re an expert in thatfield. This is not an issue for us. It’s a 250-mile transmis-sion line and we already operate over 400 miles” ●

A“The approximatecost of that line thatwe’ve looked at isabout $700 million,”Curtis Thayer said.“… A $700-millionline to Fairbanks orthe Nenana basin —that clearly workswithout an industri-al anchor.”

Alaskagas pipelineupdate