Embed Size (px)
Citation preview
page9
Willie’s on the road pushingbiofuels across North America
Vol. 11, No. 25 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of June 18, 2006 • $1.50
● A N C H O R A G E
● C A N A D A ’ S A R C T I C
B R E A K I N G N E W S
● A N C H O R A G E
4 Much ado about Arctic gas: Canadian Superior enters fray as
deadline on Petro-Canada bid for Canada Southern nears
5 Thin project getting thinner: Imperial stops governmentMackenzie gas pipeline negotiations to revise budget
8 Going back to the future: C$1 trillion in oil and gas could beextracted in western Canada by spending C$15 billion
Taking a close look at the regs
On page 11 of this issue is an article about a Regulatory Commissionof Alaska hearing to gather views on pipeline regulations. Amongother things, RCA is trying to determine whether or not pipeline reg-ulation in Alaska is excessively complicated and if it provides a levelplaying field for all producers and shippers. The photo above is ofPeak Oilfield Service Company employees working on the construc-tion of a natural gas pipeline on the west side of Cook Inlet forAurora Gas in 2004.
JUD
Y P
ATR
ICK
JUD
Y P
ATR
ICK
CO
URT
ESY
EN
CA
NA
Looking forArctic partnersDevon, Chevron-BP JV hopes to continueMackenzie Delta-Beaufort exploration
By GARY PARKFor Petroleum News
hanges are afoot in Canada’s northernregions, with two key operators inviting newpartners to join them in exploring theMackenzie Delta and Beaufort Sea.
Both Devon and a Chevron-BP joint venture saythey are open to involving others to help pushahead with their programs.
In both cases, the response could determinewhen the next wells are drilled in a costly, chal-
CDevon Canada has not locked up the steel drilling cais-son (SDC) deployed by EnCana in 2003 at the McCoveyprospect in the Beaufort Sea off Alaska and used thisyear to drill the Paktoa C-60 Beaufort well offshoreCanada’s Mackenzie Delta, leaving the company with nochoice but to postpone its upcoming winter plans.see PARTNERS page 17
Group looking for oil andgas under west Anchorage
By ALAN BAILEYPetroleum News
wo of the more intriguing lease purchases inthe state of Alaska’s May Cook Inlet areawidelease sale consisted of a couple of tracts in thewestern part of the city of Anchorage. Bruce
Webb, a member of the investment group that pur-chased one of the leases, talked to Petroleum Newsrecently about the group’s intentions.
Anchorage lies on the northeast side of the pro-lific Cook Inlet basin and Webb said that DanDonkel, a veteran Alaska lease holder and anothermember of the bidding group, has a map from
T
see ANCHORAGE page 17
Two of the more intriguing lease purchases in the stateof Alaska’s May Cook Inlet areawide lease sale consistedof a couple of tracts in the western part of the city ofAnchorage.
Gas line economic?Econ One says it is, contends producers want more than pipeline return rate
By KRISTEN NELSONPetroleum News
con One Research President JeffreyLeitzinger told the AlaskaLegislative Budget and AuditCommittee June 14 that his firm’s
analysis of the proposed North Slope gaspipeline project, and of the state’s pre-liminary fiscal interest finding on theproposed contract, show the project to beeconomic.
If there is an issue, Leitzinger said, it is that theNorth Slope producers proposing to build the lineare exploration and production companies andwant an E&P rate of return from a pipeline project,not a pipeline return, which is generally in the 11percent to 12 percent range.
The state’s fiscal interest finding onthe contract the administration has nego-tiated with project sponsors BP,ConocoPhillips and ExxonMobil, said aNorth-Slope-to-market natural gaspipeline project is competitively disad-vantaged compared to other projectsworldwide because of limited capital andhigh transportation costs.
Leitzinger said he disagreed, citingmore than $120 billion of expected netflow in 2006 dollars to the producers
from a line to Alberta, making the Alaska projectone of the highest net-flow projects in the worldand very attractive by any normal economic met-ric. The expected net present value is among the
EJeffrey Leitzinger,president, Econ OneResearch
see ECONOMICS page 14
We interrupt this message ...Columbia stumbles; Firm protestsPN’s coverage of Arctic claim
TIMING BEING EVERYTHING, theColombian government must be won-dering what they did to have eventsconspire so nastily against them.
Right on the heels of a mission toCalgary to sell the Canadian petroleumindustry on Colombia’s efforts to sepa-rate itself from its nationalist-bentneighbors, the South American countrywas clobbered June 13 by panic sellingon its stock market.
After two years of being one of thebiggest gainers among global markets, the Colombian indexfell 8.7 percent June 14, contributing to a 45 percent declinein three months.
It didn’t help the government’s drive to tap into leading
see INSIDER page 18
contents Petroleum News A weekly oil & gas newspaper based in Anchorage, Alaska
2 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
NATURAL GAS
PIPELINES & DOWNSTREAM
ON THE COVERGas line economic?
Econ One says it is, contends producerswant more than pipeline return rate
Looking for Arctic partners
Devon, Chevron-BP JV hoping tocontinue Mackenzie-Beaufort exploration
Group looking for oil and gas under west Anchorage
GOVERNMENT
FINANCE & ECONOMY
EXPLORATION & PRODUCTION8 Going back to the future for C$1 trillion
Study estimates C$1 trillion in oil and gas could be extracted over next 15 years in western Canada
ALTERNATIVE ENERGY9 Willie’s way on the highway
Ethanol sparks interest across North America, boosted by environmental concerns and Bush’s drive to lower Middle East oil imports
4 Much ado about Arctic natural gas
Canadian Superior Energy enters fray as deadline on Petro-Canada bid for Canada Southern nears; others said to be interested
6 Former DNR officials: Contract a bad deal
Irwin, Rutherford say state is subsidizingthe North Slope gas pipeline to the tune of $13.25 billion in contract governor negotiated
10 Gas overhang a threat, says NEB
Canada’s National Energy Board sees storage spacerunning out by late summer, pushing prices down, triggering possible shut-ins
11 Can pipeline regulations be simplified?
Regulatory Commission of Alaska convenes special hearing to gather views from interested parties and determine way forward
9 Ethanol producers hit the stock market
5 Bush nominates Pearce as Alaska gas pipeline coordinator
5 Mac gas line: Thin project getting thinner
8 Election may slow pipeline project, BP executive says
10 Ingredients in place for price slump
15 ConocoPhillips pulls bid for LNG port
13 Agency: BP can operate pipelines with alternate safety tests
5 BP CEO sees long-term drop in oil prices
8 EIA expects $68 WTI spot price in ’06-’07
13 BP to spend $50B on E&P in the next five years
14 Alaska Crude prepares to re-enter Moose Point No. 1
12 Kaktovik’s Native village corporation, unlike village, will work with Shell
1 We interrupt this message ... Columbia stumbles
18 Firm protests PN’s coverage of Arctic claim
OIL PATCH INSIDER
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 3
Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status
Alaska Rig StatusNorth Slope - Onshore
Doyon DrillingDreco 1250 UE 14 (SCR/TD) Workovers H-30 BPSky Top Brewster NE-12 15 (SCR/TD) Kuparuk 1J-127 ConocoPhillipsDreco 1000 UE 16 (SCR) Workover D-9 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD4-209 ConocoPhillipsOIME 2000 141 (SCR/TD) Kuparuk 1J-170 ConocoPhillipsTSM 7000 Arctic Fox #1 Stacked in Yard Pioneer Natural Resources
Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableDreco 1000 UE 2-ES (SCR) F-10B BPMid-Continental U36A 3-S Milne Point MPC-24 BPOilwell 700 E 4-ES (SCR) MPL-20 BPDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay G-17A BPDreco 1000 UE 9-ES (SCR/TD) L-51 BPOilwell 2000 Hercules 14-E (SCR) Stacked at Cape Simpson AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked, Prudhoe Bay AvailableOilwell 2000 17-E (SCR/TD) Stacked, Point McIntyre AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableOIME 1000 19-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableOIME 2000 245-E Stacked, Kuparuk AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) DS-15 BP
Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay G-10c BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay L5-28 BPIdeco 900 3 (SCR/TD) Kuparuk 3M-14 ConocoPhillips
North Slope - OffshoreNabors Alaska DrillingOilwell 2000 33-E Moving BP
Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Nicolai Creek 1b workover Aurora Gas
Kuukpik 5 Plugging Swanson River SCU-428-05 Unocalfor abandonment
Marathon Oil Co. (Inlet Drilling Alaska labor contractor)Taylor Glacier 1 Ninilchik State #2 Marathon
Nabors Alaska DrillingNational 110 UE 160 (SCR) Stacked, Kenai AvailableContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked, removed from Osprey platform AvailableRigmaster 850 129 Stacked in Kenai Available
Cook Inlet Basin – Offshore
Unocal (Nabors Alaska Drilling labor contractor)Not Available
XTO EnergyNational 1320 A Platform A C21A-23 XTONational 110 C (TD) Idle XTO
Mackenzie Rig StatusCanadian Beaufort Sea
Seatankers (AKITA Equtak labor contract)SSDC CANMAR Island Rig #2 SDC In cold shutdown at Paktoa Devon ARL Corp.
Mackenzie Delta-OnshoreAKITA EqutakDreco 1250 UE 62 (SCR/TD) Stacked in Tuktoyaktuk, NT Available
Yukon Territories Rig StatusNorthwest Territories
Ensign Resources Svc. Grp.Jackknife Double 55 Racked in Ft. Nelson
Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of June 15, 2006.
Active drilling companies only listed.
TD = rigs equipped with top drive units WO = workover operations CT = coiled tubing operation SCR = electric rig
This rig report was prepared by Alan Bailey
Baker Hughes North America rotary rig counts*June 9 June 2 Year Ago
US 1,661 1,657 1,339Canada 443 293 319Gulf 92 96 92
Highest/LowestUS/Highest 4530 December 1981US/Lowest 488 April 1999Canada/Highest 558 January 2000Canada/Lowest 29 April 1992
*Issued by Baker Hughes since 1944
The Alaska - Mackenzie Rig Report is sponsored by:
JUD
Y P
ATR
ICK
4 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
Dan Wilcox CHIEF EXECUTIVE OFFICER
Mary Lasley CHIEF FINANCIAL OFFICER
Kay Cashman PUBLISHER & EXECUTIVE EDITOR
Kristen Nelson EDITOR-IN-CHIEF
Susan Crane ADVERTISING DIRECTOR
Amy Spittler SPECIAL PUBLICATIONS EDITOR
Tim Kikta COPY EDITOR
Gary Park CONTRIBUTING WRITER (CANADA)
Ray Tyson CONTRIBUTING WRITER
Alan Bailey STAFF WRITER
John Lasley STAFF WRITER
Allen Baker CONTRIBUTING WRITER
Rose Ragsdale CONTRIBUTING WRITER
Sarah Hurst CONTRIBUTING WRITER
Paula Easley DIRECTORY PROFILES/SPOTLIGHTS
Steven Merritt PRODUCTION DIRECTOR
Judy Patrick Photography CONTRACT PHOTOGRAPHER
Mapmakers Alaska CARTOGRAPHY
Forrest Crane CONTRACT PHOTOGRAPHER
Tom Kearney ADVERTISING DESIGN MANAGER
Heather Yates ADMINISTRATIVE ASSISTANT
Toby Arian CIRCULATION SALES MANAGER
Dee Cashman CIRCULATION REPRESENTATIVE
Flo Wright CIRCULATION REPRESENTATIVE
Petroleum News and its supplement,
Petroleum Directory, are owned by
Petroleum Newspapers of Alaska LLC.
The newspaper is published weekly.
Several of the individuals listed above
work for independent companies that
contract services to Petroleum
Newspapers of Alaska LLC or are
freelance writers.
ADDRESSP.O. Box 231651Anchorage, AK 99523-1651
EDITORIAL Anchorage907.522.9469
Editorial [email protected]@petroleumnews.com
BOOKKEEPING & CIRCULATION 907.522.9469 Circulation [email protected]
ADVERTISING 907.770.5592Advertising [email protected]
CLASSIFIEDS907.644.4444
FAX FOR ALL DEPARTMENTS907.522.9583
Petroleum News (ISSN 1544-3612) • Vol. 11, No. 25 • Week of June 18, 2006Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518
(Please mail ALL correspondence to:P.O. Box 231651, Anchorage, AK 99523-1651)
Subscription prices in U.S. — $78.00 for 1 year, $144.00 for 2 years, $209.00 for 3 years.Canada / Mexico — $165.95 for 1 year, $323.95 for 2 years, $465.95 for 3 years.
Overseas (sent air mail) — $200.00 for 1 year, $380.00 for 2 years, $545.95 for 3 years.“Periodicals postage paid at Anchorage, AK 99502-9986.”
POSTMASTER: Send address changes to Petroleum News, P.O. Box 231651 • Anchorage, AK 99523-1651.
www.PetroleumNews.com
● C A N A D A
Much ado aboutArctic natural gasCanadian Superior Energy enters fray as deadline on Petro-Canadabid for Canada Southern nears; others said to be interested
By GARY PARKFor Petroleum News
ompetition for a bundle of Arctic nat-ural gas assets has taken more twistsand turns as Petro-Canada’s unso-licited offer for Canada Southern
Petroleum winds down to its June 20 expirydate.
Offshore plays in Trinidad and Tobagoand Nova Scotia have been dragged into themix as Canadian Superior Energy, underrenegade Chief Executive Officer GregNoval, has tried to seize the controls.
With Petro-Canada refusing to sweetenits bid, Canada Southern had suggested toits shareholders that better deals were in theoffing, indicating as many as four “signifi-cant companies” might surface.
Chief Executive Officer JohnMcDonald told Canada Southern share-holders at their June 8 annual meeting thatother contenders have been invited to visita data room, a process he said is “ongoing,”building optimism that a better deal will betabled.
So far, only Canadian Superior, a juniorE&P with a considerable history of legaland regulatory tangles and internalupheavals, has publicly declared its interestin the frontier assets.
It has floated a cash-and-shares offer itfigures is worth upwards of C$130 million,estimating that is 11 percent better thanPetro-Canada’s all-cash offer.
In a statement, Noval built a case toCanada Southern shareholders around theventures his own company has in thewings.
He said Canadian Superior is presentingCanada Southern investors with a “tremen-dous immediate opportunity” to benefitfrom his company’s land position inTrinidad and Tobago “where some of themost prolific natural gas wells in the worldare located in proximity to CanadianSuperior’s acreage” and where two wellsare scheduled for the final quarter of thisyear.
He noted that wells offsetting CanadianSuperior’s Intrepid Block 5 (c) are produc-ing 400 million cubic feet per day and BPhas just started producing 800 million cubicfeet per day in an area where the super-major has 15 of its largest 25 yielding wellsin the world.
Noval said several majors, includingPetro-Canada, Total, British Gas, Huskyand Apache, have shown interest in theTrinidad block.
But, typical of his lone-ranger style,Noval said Canadian Superior and its finan-cial partner Challenger Energy have optedto drill the Caribbean prospect withouthelp.
Nova Scotia a turbulent episodeCanadian Superior also tied its pitch to
its 1.29 million acres offshore Nova Scotia,where it is the largest public holder ofexploration land and its onshore oil and gasoperations in Canada, including coalbedmethane acreage in Alberta where it notedEnCana has been paying up to C$2 millionper section for coalbed methane rights.
Nova Scotia has been one of CanadianSuperior’s most turbulent episodes after 50percent partner El Paso refused to financethe testing of the Mariner I-85 explorationwell — a C$30 million undertaking thatgenerated a dozen press releases of a most-ly upbeat nature during the drilling.
The fallout involved a spate of lawsuitsin the U.S. and Canada, accusing the com-pany of issuing “false and misleading”releases.
Canadian Superior ended a three-yearworking relationship in fall 2004 by acquir-ing all of El Paso’s Nova Scotia holdingsfor an undisclosed amount, still confidentthat the play has the potential to turn thecompany from a bread-and-butter producerto a high-impact frontier operator.
Although Noval made no mention ofCanadian Superior’s desire to add long-term Arctic prospects to its portfolio, com-pany director Richard Watkins said theappeal to his company is CanadaSouthern’s “great set of assets” in the ArcticIslands and Yukon.
He said Canadian Superior has been“watching” the properties for some timeand saw Petro-Canada’s offer as the “cata-lyst” to make a second hostile run atCanada Southern.
The magnet is Canada Southern’s mixedbag of carried and working interests inseven of 16 significant discovery licensesin Canada’s Far North, two of which arerated among Canada’s top five gas discov-eries.
The assets include Drake Point, a 1969find that is estimated to contain 54 trillioncubic feet, Hecla’s 1972 discovery of 3.2 tcfand Whitefish, a 1979 strike listed at 2.4 tcf.
Petro-Canada, as the largest leaseholderin the region, said it wants to consolidatethe scattered ownership and position itselfas the strongest contender to develop theresources.
But the company is just as adamant thatits offer for Canada Southern is fair andwon’t be improved.
Petro-Canada concedes obstaclesFrom the outset, Petro-Canada has con-
ceded many obstacles — technological, fis-cal and the outlook for commodity prices— stand in the path of developing suchremote resources and insisted it has no
C
see ARCTIC GAS page 7
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 5
GERMANYBP CEO sees long-term drop in oil prices
Oil prices could drop to about $40 a barrel in the medium term as new suppliesare found, and might fall even further in the long term, the chief executive of BPPLC said, according to an interview published June 12.
BP CEO Lord Browne cautioned that “we cannot reallyexpect that prices will drop back sharply in the short term,”the interview with German weekly Der Spiegel said.
However, he noted that large new oil fields are still beingfound and that regions such as West Africa have significantoil supplies, the report said.
Browne said sources such as Canada’s oil sands also canbe tapped profitably, adding that production costs stillamount only to a small proportion of the price.
“It is very likely that, in the medium term, prices willstand at about $40 on average,” Browne was quoted as say-ing. “In the very long run, even $25 to $30 are possible.”
Oil prices have soared recently, pushed up notably by tensions over Iran’snuclear ambitions. Iran said June 11 it had accepted some parts of a Western offeraimed at getting it to drop its nuclear program, but rejected others.
Light sweet crude for July delivery was up 36 cents June 12 to $71.99 a barrelin electronic trading on the New York Mercantile Exchange.
—THE ASSOCIATED PRESS
BP CEO LordBrowne
WASHINGTON, D.C.Bush nominates Pearce as Alaskanatural gas pipeline coordinator
Former state Senate President Drue Pearce has been nominated by PresidentGeorge W. Bush to be federal coordinator of an Alaska natural gas pipeline proj-ect.
Congress ordered the creation of the job in 2004 as part of legislation designedto speed federal review of the proposed pipeline.
Pearce now is senior adviser to the secretary of the Interior for Alaska affairs.Pearce will work until one year after the completion of the natural gas pipeline
project, according to a White House announcement.The 2004 law calls for the coordinator to oversee the
“expeditious discharge of all activities by federal agencieswith respect to an Alaska natural gas transportation project”and ensure that they follow the direction of Congress.
Coordinator can veto agenciesThe act states that the coordinator will be able to veto any
agency’s attempt to attach a “term or condition,” short ofthose required by law, if the coordinator determines that it“would prevent or impair” the rapid construction or expan-sion of the line.
The coordinator cannot overturn certain orders from the Federal EnergyRegulatory Commission. Also, the coordinator cannot impose her own terms andconditions.
The law directs the federal coordina-tor and the State of Alaska to set up ajoint surveillance and monitoring agree-ment like the one used for constructionof the trans-Alaska pipeline in the mid-1970s.
The agreement must be approved bythe president and the governor ofAlaska.
Under the agreement, federal agen-cies will have jurisdiction on federal and private land. The state will have juris-diction on state land.
Pearce, a Republican, was elected to the Alaska House of Representatives in1984 from Anchorage and to the Alaska Senate in 1988. She served as Senatepresident twice.
—THE ASSOCIATED PRESS
DRUE PEARCE
Pearce, a Republican, waselected to the Alaska House ofRepresentatives in 1984 fromAnchorage and to the AlaskaSenate in 1988. She served as
Senate president twice.
● C A N A D A
Mac gas line: Thinproject getting thinnerImperial Oil stops government negotiations to revise a budgetbeing squeezed by hyper-inflation in construction sector
By GARY PARKFor Petroleum News
he Mackenzie Gas Project has col-lided with the looming realities ofraging inflation in Canada’s oil andgas industry, forcing the proponents
to call a time out in their discussions withthe Canadian government on fiscal termsuntil they can complete a revised budgetthis fall.
“We don’t have a lot of confidence inthe cost estimates right now,” ImperialOil Senior Vice President Randy Broilestold reporters June 14.
While declining to get drawn intoguessing numbers, he left little doubt thatthe current projection of C$7.5 billionwill rise.
Because the construction industry haschanged so much in the past two years“it’s impossible to know what the newnumber is,” Broiles said.
Referring to what he called “the froth-iness ... in global conditions,” he said theMackenzie project along with more thanC$100 billion worth of oil sands venturesnow on the table are being hit with a fullspectrum of rising costs for labor, steeland equipment.
While the Mackenzie partners try toget a better fix on where those increases— which have climbed 30 percent to 50percent in the past two years and areexpected by some analysts to rise a fur-ther 30 percent — “we have paused dis-cussions with the government right now,to let us do the homework we need to onthe cost side,” Broiles said.
But he said that was not the same asthe halt in operational work ordered byImperial in April 2005 to resolve prob-lems such as the regulatory timetable andnegotiations with aboriginal regions onaccess and benefits agreements.
Imperial had previously indicated ithoped the current negotiations would pro-duce a result by mid-2006.
“Last year, we weren’t getting the helpwe needed to see a way through the hur-dles of the Mackenzie,” he said. “We’ve
got that help, so it’s not that sort of thingat all.”
However, he conveyed a strong mes-sage that Ottawa may be expected to hikeits contributions to the project, currentlyestimated at C$1.2 billion.
Reiterating a frequent theme fromImperial executives, Broiles said the proj-ect has been economically “thin from thebeginning and with more cost pressure,that’s bad news.
“So we have to finish that work andthen we’ll know what we need to talkthrough with the government,” he said.
The cost spiral started in late 2004,when estimates were hiked from C$5 bil-lion to C$7 billion. More recently, anoth-er C$500 million has been added.
Barge across top of AlaskaAs well as reviewing the budget,
Imperial is exploring cost-saving options,including the possibility of barging majorcomponents, such as a gas processingplant, across the top of Alaska to Inuvikin the Northwest Territories, rather thanmoving them in pieces along theMackenzie River Valley. Broiles said thathas the “potential to claw back big sav-ings.”
He said another alternative is extend-ing the pipeline construction season tothree summers from two, which wouldpush the start of production at 1.2 billioncubic feet per day beyond the current tar-get of 2011.
One of the few to attempt a new costforecast, Tristone Capital analyst ChrisTheal said earlier this month the projectcould cost C$9 billion, although he saidhigher gas prices by the completion datewould leave the return on investmentlargely unchanged.
He suggested to the Globe and Mailthat Imperial’s decision to announce abreak in the government negotiationsmight be mostly a bargaining ploy.
To attempt to negotiate better leveragefrom the government is a “great tactic,”Theal said. ●
T
JUD
Y P
ATR
ICK
PETROLEUM NEWShe proposed gas fiscal contract is a baddeal for the state, former Departmentof Natural Resource officials TomIrwin and Marty Rutherford told
Petroleum News following aCommonwealth North presentation on June9 in Anchorage.
Rutherford, a former DNR deputy com-missioner, said they believe the state shouldback away from the Stranded GasDevelopment Act under which the adminis-tration of Gov. Frank Murkowski negotiat-ed the gas fiscal contract.
“It was a law that was passed when theprice of gas was very low and its time haspassed,” she said. Projections for gas pricesand demand are much different than theywere four years ago. The gas is no longerstranded, she said, and a natural gaspipeline is viable without economic incen-tives.
The state might still decide it wants tooffer incentives, Rutherford said. “Wecould do what the federal government did:we could pass a law of general applicationthat is available to anyone who wanted tobuild the project with very clear, very quan-tifiable incentives available across theboard.” Such incentives might include noproperty taxes until gas flows, reducedproperty taxes, reduced production taxes oreven a direct subsidy. Such incentives, shesaid, would be “clear and concise withnothing hidden and nothing that willbecome obvious as a problem over time.”
And those incentives could be tied tocompletion of a project: 100 percent wouldbe available for a line completed in 2017,but only 80 percent if the completion datefell to 2019.
Economic without subsidies“My whole background’s in economic
development,” said Irwin, who was DNRcommissioner until Gov. Murkowski dis-missed him last fall after Irwin raised con-cerns about negotiations for a fiscal contractunder the Alaska Stranded GasDevelopment Act. Six department officials,including Rutherford and Mark Myers, thendirector of DNR’s Division of Oil and Gas,
quit in protest. Irwin said he did
the economics on aNorth Slope gas proj-ect himself and “I amstrongly andabsolutely convincedthis is an economicproject” (withoutincentives). TheDNR team workingon the projectreached the same conclusion, he said, as didEcon One, a firm hired by the Legislature tolook at the project.
Read the contract, he urged the audi-ence, and then approach it from a businessperspective.
He said his conclusion is that the com-panies got a good deal, but not the state.
“The state gets no deal,” Irwin said.First, the producers can get out of the con-tract in 60 days — the state has no way outshort of proving that the producers did notmeet a diligence standard to move aheadwith the project. Studying gas prices couldmeet that test, he said. “It’s a good deal forthem. We have no deal.”
The contract also removes the state’ssovereign authority, he said: “Would you,with your company, remove your authorityin a contract?”
Irwin said he believes that giving up thestate’s option to take royalty in kind or roy-alty in value is “an absolute mistake” andcreates significant cost and risk issues forthe state, putting the state “in a position ofweakness in getting capacity in the lines”and in competition with the best marketersin the world to sell the gas. We’re now told,he said, that another company will sell thegas for us. But we don’t pay for that now,and we get the highest price any of the sell-ers gets.
And if the state is going into this as abusiness, Irwin said, Alaskans need to seethe real costs, “not the political feel-good”cost. He said in presentations it appears ahigher gas price is used in discussing rev-enues — without costs deducted — and alower price when discussing supports need-ed for the project. In business both partiesuse a range of prices, he said.
The facts need tobe out on the table, hesaid, so that everyonecan answer the ques-tion: “Would yousign this if it was yourbusiness?”
Rewrite of state’sposition
Rutherford saidthere are more thanincentives in the con-
tract. “This contract is a total rewrite of ourentire oil and gas relationship with the pro-ducers,” turns the existing oil and gas leas-ing program on its head and “largely sur-renders the power of all three arms of gov-ernment, our sovereign powers, to the pro-ducers.”
The Legislature loses its power to tax theproducers for up to 45 years; the “executivebranch loses its right to manage and regu-late the producers’oil and gas leases and theability to ensure those leases are adequatelyand appropriately developed” for up to 45years; and the “judicial branch loses theability to oversee the contract enforcementfor up to 45 years.”
Forty-five years is a long time, “and thatalone, in my mind, is an unacceptable risk.Nobody thought that when ... the ELF (eco-nomic limit factor on the state’s productionseverance tax) was passed 15 years ago,that we were implementing a flawed taxa-tion structure on our oil and gas leases. Andyet, within 15 years, that’s what we discov-ered: it is a flawed structure.”
The period of time the contract is lockedin “is far too great a risk for us to accept,”she said.
The cost of contract subsidiesRutherford said the contract sets up a
system that is “a total destruction of ournormal, competitive environment” for oiland gas leasing, allowing the producers tolock up some 500 leases on the North Slopefor the term of the contract, “for 45 years, ifthey meet that weak diligence standard ...which does not require building a pipelineor doesn’t require significant investmentinto a pipeline.”
The state also loses its ability “to ensurethat leases are developed in a timely mannershould they be economic,” she said, andcreates a two-class system that discouragesinvestment by companies who don’t havethese advantages.
Rutherford said Econ One has found thatwith no state incentives and the producersowning 100 percent of the project under thecurrent fiscal system, if natural gas sells for$4 the producers have a 17.2 percent rate ofreturn; at $5, it’s 20.4 percent. She said thiscompares to a 15 percent rate of return oilcompanies generally use as a benchmark.
Then there is a $13.25 billion cost to thestate to sign the contract, “independent ofits own investment in the pipeline,”Rutherford said, which at a $4 gas price is adirect subsidy to the producers, independentof the state’s ownership position, worth“over half the value of the state gas.” At $3gas, the state’s position is negative. “So weare writing a check in order to produce ourgas.”
Compare that to the status quo, she said:If the price of natural gas goes below thetransportation cost — but the state is takingits gas in value, rather than in kind — “wedon’t get a check, we pay zero, but we don’tactually go negative.”
The risk at low prices is one that wouldalarm any company, she said.
Upstream cost allowance: $5.45 billion
The $13.25 billion comes from severalsubsidies, the first of which is the upstreamcost allowance.
The state made “a bad decision” in 1980,Rutherford said: it agreed to pay upstreamcosts it was not obligated to pay under itsleases on royalty oil and gas at the PrudhoeBay field. Later court decisions confirmedthe state did not need to pay these costs, butin 1980 it agreed to pay them to acceleratea royalty in kind sale for Prudhoe Bay oil.
The contract expands that paymentacross the North Slope, she said, not just forroyalty gas but for all of the state’s gas.
Rutherford described the contract as “arepeat on a much larger scale of what hap-pened in 1980,” a mistake, she said, that hasalready cost the state $2 billion on oil alone.
The upstream cost allowance in the con-tract, less what the state agreed to pay atPrudhoe in 1980, is a subsidy of $5.45 bil-lion over the life of the contract, she said.
Upstream credit: $4 billionThe proposed production profits tax
involves a subsidy of another $4 billion, shesaid, with credits against operating costsand capital costs in the field, even thoughthe state doesn’t get a profits tax on gas, justa flat 7.25 percent of the tax taken in kind.Once you net out the royalty share it’s actu-ally 6.8 percent.
Although the state gets no profits taxfrom gas, “we still pay all those develop-ment costs,” she said. And because there isa credit but “no upstream uplift or bump tothe state in terms of its percentage,” thatcredit is worth about $4 billion.
Rutherford said the $4 billion is based“on very conservative capital costs on theupstream. It may be far greater than that ...”in which case it could be “a much highernumber.”
She said gas that needs to be developedfor the project includes Point Thomson andthe National Petroleum Reserve-Alaska, aswell as other fields, and will require signif-icant capital investment in upstream gas
6 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
● A L A S K A
Former DNR officials: Contract a bad dealIrwin, Rutherford say state is subsidizing the North Slope gas pipeline to the tune of $13.25 billion in contract governor negotiated
T
former Alaska DNRCommissionerTom Irwin
Former Alaska DNRDeputyCommissioner Marty Rutherford
see OFFICIALS page 7
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 7
plans in place to develop the Arctic. It said studies of Arctic gas have gener-
ally been limited to the Drake and Heclafields because others are “remote, small,subject to harsh conditions and are notthought to be viable on their own.”
Petro-Canada said there is “significantuncertainty” surrounding the technical andeconomic prospects of Arctic resources,adding it believes Canada Southern’sclaims to hold 927 billion cubic feet of mar-ketable gas are too high.
Canada Southern, 95 percent of whoseshareholders are believed to be U.S. resi-dents, is adamant that Petro-Canada’s biddoesn’t properly value the Arctic interests.
McDonald told the annual meeting thatan announcement of Arctic developmentplans from a major company is “very near,”
without disclosing more details.However, company Chairman Richard
McGinity conceded that Canada Southern,with only six employees, is in no position tofinance development of the fields.
He said valuing the assets is not easywhen the future of the Arctic is so uncer-tain.
“It’s difficult for shareholders and it’s achallenge for their elected directors. It’s notsimple,” he said.
In one of the few attempts to forecast adevelopment schedule, the CanadianEnergy Research Institute has concludedthat Arctic gas could be produced econom-ically in 2014, using liquefied natural gas orgas-to-liquids technology.
But even if that date were realistic, itwould be five years after Petro-Canada andTransCanada are scheduled to start opera-tions at their proposed LNG terminal atGros Cacouna, Quebec. ●
continued from page 4
ARCTIC GAS
development. The state would get less gas than it wouldunder the present system, “where it makes zero invest-ment,” but through its credits would pay for 40 percent ofthe development.
Midstream pipeline and gas treatment plant: $2 billion
The 100 pages recently added to the contract include a35 percent credit for upstream pipelines leaving the unitboundaries and going to the gas conditioning plant, and a 35percent credit for the gas conditioning plant, Rutherfordsaid.
Those costs will include a big gas pipeline from PointThomson and as many as a dozen other pipelines to movethe additional 30 trillion cubic feet of gas needed, she said.
“We hope they get built,” Rutherford said. “But underthis contract the state pays 35 percent in direct cash credit tothe producers for the cost of those lines. Then on top of thatwe have agreed to pay 20 percent of that infrastructure as anowner.”
Rutherford said what it comes down to is the state pays48 percent of the cost and gets 20 percent ownership in themidstream pipelines and the gas treatment plant, which hasan estimated cost of $2.6 billion to $2.8 billion. By paying48 percent of the costs and only having 20 percent of theownership the state bears “far more proportional cost over-run risk than any of the producers,” she said.
The $2 billion midstream subsidy is independent of thestate’s 20 percent investment as an owner, she said.
Processing subsidy: $440 millionThe state will also pay a processing subsidy, Rutherford
said.
Under the present system if the state takes royalty-in-kind gas it takes it ready to go into the pipeline. And that’snot how it comes out of the ground, she said. Prudhoe Baygas contains some 12 percent CO2, carbon dioxide, someH2S, hydrogen sulfide, and a lot of water and it “costsmoney to remove those products,” Rutherford said. As partof the state’s lease agreements, in exchange for taking only12.5 percent royalty, the state does not pay to remove anddispose of those products.
The cost to remove them isn’t in the contract; it will haveto be negotiated. There’s another cost: the liability of takingthe gas includes the “physical liability to move it,” whichmeans insurance and liability issues, she said.
Conservatively it will cost the state some $440 millionover the life of the contract, for something the state nowgets for free.
Selling the gas: $1.4 billionSince the state will take its gas in-kind, rather than in-
value, it will have to sell the gas. And it loses the “higher-of” it got when it took gas in-value and the producers soldit — and delivered to the state a check reflecting the high-est value any of them got.
It was another compromise the state made for its 12.5percent royalty, Rutherford said.
So what will it cost to sell the gas? She said she’s heard the producers talk about half a cent
to market it. “That’s ridiculous: You can’t even cover yourinsurance liability for that and the DNR looked hard at thosemarketing costs,” Rutherford said.
“And we used outside experts,” she added. The equivalent of having producer marketing and skill,
and the value of the “higher-of” provision came to about$1.4 billion, Rutherford said.
Other costs and risksThe subsidies add up to $13.25 billion, she said: $5.45
billion in upstream cost allowance, $4 billion in mid-stream pipeline and gas treatment subsidies; $2 billionfrom the 35 percent credit; $440 million for the process-ing; and $1.4 billion for marketing.
But there are other costs and risks the state wouldn’tbear if it took its gas in-kind.
Rutherford said the big one is the take-or-pay capacitythe state will have in the gas pipeline over 25 years or so,whatever the pipeline sets for firm transportation com-mitment. If the state doesn’t have enough gas, it still paysthe transportation fees; if it has too much gas, “it’s a dis-tressed seller on the slope and has to find a buyer on theNorth Slope.” He characterized the protections in thecontract as “weak” and said “they don’t really work.”
The exposure over the life of the contract is billions ofdollars, Rutherford said. There are inefficiencies in anysystem, and the state will have some 900 million cubicfeet a day of gas to deliver to the pipeline. “So even ifyou’re only 10 percent inefficient (in the slope pipelinesand the gas processing facility) on this, there are $3 (bil-lion) or $4 billion ... of risk that we’re going to bearthere.”
That’s because the state won’t be able to tell the pro-ducers to produce more or less gas.
Irwin said he’s heard many times that the state is get-ting into the gas pipeline so it can be like the producers.“We will never be like them: ... We don’t own any wells,we don’t own any valves, so do not buy the story we willbe like them.”
The producers, he said, have flexibility: they canexpand the field if they don’t have enough gas; they cantrade reserves; for a short time, they can allow one pro-ducer to over or under produce. The state, he said, does-n’t have those options.
“What happens is the state is a disadvantaged minori-ty owner in a system where it doesn’t control theupstream.” ●
continued from page 6
OFFICIALS
8 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
● W E S T E R N C A N A D A
Going back to the future for C$1 trillionStudy estimates C$1 trillion in oil and gas could be extracted over next 15 years in western Canada with investment of C$15 billion
By GARY PARKFor Petroleum News
joint industry-government study estimates that aninvestment of up to C$1 billion a year for 15 yearscould apply new technology to retrieve 6 billion bar-rels of oil and 22.5 trillion cubic feet of non-associat-
ed natural gas that has been left in the ground by earlier gen-erations of Western Canadian producers.
The C$1 trillion treasure trove (based on today’s com-modity prices) doesn’t need rocket science to raise produc-tion of discovered reserves in the region to 36 percent from27 percent, says a study by Petroleum Technology AllianceCanada and EnergyINet, a joint partnership that is workingto accelerate the development and deployment of advancedenergy systems and technologies.
Technology alliance chief executive officer Michael
Raymont told reporters the answer lies in applying technol-ogy that is already available.
The report, Ramping Up Recovery: A Business Case forIncreased Recovery of Conventional Oil and Gas, costC$960,000, including contributions from the Alberta,British Columbia and Saskatchewan governments andmany firms.
As the title conveys, the focus was on the mainstay ofCanada’s production for the past 60 years and paid no atten-tion to the oil sands or coalbed methane.
EnergyINet president Eric Lloyd said the potentialbonanza can be exploited without any royalty or tax incen-tives, but some help might be needed to reduce the risk oftesting new recovery methods.
He said technology has the potential to “significantlyincrease our energy production to meet the world’s growingdemand for energy.”
Raymont said the research has generated importantinformation “that can help us better target our activities andresearch and development technology so that we can allshare significant benefits from energy sources we havebeen unable to recover.”
Lloyd said the key lies more in engineering than basicdiscovery, with a reliance on the use of advances in map-ping geological reservoirs, the handling and managementof “produce water” from wells (currently about 12 barrelsof brackish water for every barrel of oil produced), drillingmethods and the injection of carbon dioxide into reser-voirs.
He said a steering committee will be established to pressfor action of squeezing more from wells that date to thebeginnings of the Western Canadian industry in the 1950s.
The proprietary information is available only to compa-nies who participate in the two-year research effort. ●
A
INTERNATIONALEIA expects $68 WTI spot price ’06-’07
The U.S. Department of Energy’s Energy Information Administration expectsthe West Texas Intermediate crude oil spot price to average $68 in both 2006 and2007, the agency said in its June short-term energy outlook issued June 6.
It projects lower natural gas prices the rest of this year compared to 2005, witha 2006 Henry Hub spot price average of $7.74 per thousand cubic feet, down$1.12 from the 2005 average. “For 2007, theHenry Hub average price will likely moveback up to average $8.81 per mcf, assumingsustained oil prices, normal weather and con-tinued economic expansion in the UnitedStates,” EIA said.
U.S. natural gas consumption is projected tofall some 0.9 percent below 2005 levels thisyear and then increase by 3.8 percent in 2007.
There was a 2.7 percent drop in domesticnatural gas production in 2005, largely due tohurricane-induced disruptions in the Gulf ofMexico; production is expected to increase 0.7percent in 2006 and 1.2 percent in 2007. Total liquefied natural gas net importsare expected to increase from 631 billion cubic feet in 2005 to 710 bcf in 2005and 950 bcf in 2007.
As of May 26, working natural gas storage was estimated at 2.243 trillion cubicfeet, 477 bcf above a year ago and 706 bcf above the five-year average.
Consumption growth has slowedThe agency said the growth in world petroleum consumption has slowed because
of higher prices, but projected consumption growth remains strong at 1.7 millionbarrels per day in 2006 and 1.9 million bpd in 2007. Most of that growth will be metby non-Organization of Petroleum Exporting Countries’ production and shortfallwill be met by an increase in OPEC production or drawdown of inventories.
“Because of only limited surplus capacity throughout the forecast period, con-tinued concern about potential or existing supply problems in Nigeria, Iran, Iraq,Venezuela and elsewhere, as well as the threat of more hurricane damage and thecontinued tight supply-demand balance, we expect little change in the current high-price market,” EIA said.
—PETROLEUM NEWS
The agency said thegrowth in world petroleum
consumption has slowedbecause of higher prices,
but projected consumptiongrowth remains strong at
1.7 million barrels per dayin 2006 and 1.9 million
bpd in 2007.
● A L A S K A
BP: Election may slowgas pipeline project
By MATT VOLZThe Associated Press
n executive with BP Exploration(Alaska) Inc. says that if a new gov-ernor is elected this fall without leg-islative approval of a natural gas con-
tract, those contract negotiations may haveto start over, reported Radio Kenai.
John White, senior project manager ofBP’s Alaska Gas group, told the SoldotnaChamber of Commerce on June 13 thatcould mean a three-year delay of the NorthSlope gas pipeline.
Gov. Frank Murkowski’s contract pro-posal with BP, ExxonMobil andConocoPhillips is out for public review.The contract would set long-range tax androyalty terms between the state and three oilcompanies who propose building the gaspipeline. BP spokesman Daren Beaudo saidWhite’s comments were not an endorse-ment of Murkowski and that BP does notendorse any candidate.
Beaudo said an agreement was reachedafter three years of working with theMurkowski administration and the compa-ny would like to proceed under that deal.
White was in Soldotna to drum up sup-port for the contract, which must beapproved by the Legislature to take effectbut which does not guarantee constructionof a pipeline.
Murkowski, the Republican incumbent,faces challenges within his own party fromformer Wasilla Mayor Sarah Palin andFairbanks businessman John Binkley.
Palin supports a competing pipeline pro-posal to build a line from the North Slope toValdez, where the gas would be liquefiedand shipped to the West Coast. Binkley saysMurkowski’s contract proposal with the oilcompanies is flawed but fixable and that hewould get rid of the 30-year freeze on thecompanies’ oil taxes that Murkowski pro-poses to include.
The main Democratic challengers, for-mer Gov. Tony Knowles and Rep. EricCroft, also have strongly criticizedMurkowski’s contract proposal with thecompanies.
The Legislature did not pass two keybills this special session that would set up aratification vote of the contract. One wouldhave changed the state’s production tax sys-tem to one based on the net profits of oilcompanies’ Alaska operations. The provi-sions of that bill were to be inserted into thecontract. The Legislature also adjournedwithout amending the state’s Stranded GasDevelopment Act to give Murkowski theauthority to negotiate oil taxes as part of agas pipeline contract and to lock in thoseterms for multiple years.
The primary elections are Aug. 22. Thegeneral election is Nov. 7. ●
A
By GARY PARKPetroleum News
f you want to stay on the road you mightconsider hitching your wagon to WillieNelson’s promotion of biofuels.
The country crooner is putting hismoney where his mouth is by manufactur-ing and selling “BioWillie,” his own brandof alternative fuel.
For Nelson it’s a chance to convert U.S.-grown vegetable oil seeds into a clean-burn-ing replacement for diesel fuel, both givinga future to family farmers and lending ahelping hand to the environment.
A U.S. Department of Energy study con-cluded that the production and use ofbiodiesel slashed carbon dioxide emissionsfrom the use of petroleum diesel by 78.5percent.
Natural Resources Canada has calculat-ed that a liter of 10 percent ethanol blendcan lower greenhouse gas emissions by upto 5 percent compared to a liter of gasoline.
It’s a trend that has already made solidgains in the U.S. and that Canada is startingto embrace.
Ottawa in May launched a summer ofnegotiations with provincial governmentsthat it hopes will see renewable fuel levelsin Canadian gasoline rise from 0.5 percentto 5 percent by 2010.
Environment Minister Rona Ambrosesaid there is a “successful will to move for-ward,” while agreeing that the target isambitious.
For her and the government of PrimeMinister Stephen Harper it is a key elementin their determination to develop a made-in-Canada climate change strategy, furtherundermining their commitment to theKyoto Protocol.
More ethanol neededThe obvious challenge is to hike produc-
tion of ethanol — currently about 300 mil-lion liters a year from five major plants andtargeted at 650 million liters by 2010 basedon projects now in the works.
Even that increase will fall far short ofthe 1.4 billion liters the industry estimateswill be needed to achieve the 5 percent goal.
In comparison, the U.S. productioncapacity last year was 15 billion liters from101 plants (with another 32 under construc-tion) prompted by Energy Policy Actrequirements for U.S. ethanol production toreach 28 billion liters by 2012.
It’s all a pick-me-up for U.S. corn farm-ers, who have relied for years on annualfederal subsidies of $3.6 billion to offsettheir weak commodity prices.
That has changed dramatically now thatPresident George W. Bush has ordered a
huge hike in ethanol use in his drive toreduce Middle East oil imports by 75 per-cent over the next 20 years, lifting cornfutures to $2.55 per bushel from barely $2over the winter.
If all of the targets are achieved, the U.S.is expected to burn 15 billion gallons a yearof ethanol by 2015.
Leading the way in Canadian productionare Husky Energy, which expects to havetwo new facilities (one each inSaskatchewan and Manitoba) turning out acombined 260 million liters by late 2007,and Commercial Alcohols, which is work-ing on two plants totaling 530 million litersin Ontario and Quebec over an indefinitenumber of years, adding to its current out-put of 145 million liters.
But Commercial Alcohols VicePresident Bliss Baker said setting a target isnot enough.
He said the ethanol sector wants theCanadian government to offer incentivesalong the lines of those provided to oilsands operators to reduce the capital costsof expanding the processing capacity forbiofuels.
The oil sands incentives allow compa-nies to write off all of their upfront costs ina year, allowing them to defer corporatetaxes.
The Canadian Renewable FuelsAssociation said that in addition to incen-tives the challenge will be to introduce com-mon standards across Canada.
Currently, Saskatchewan requires ablend of ethanol in all fuel sold in theprovince; Manitoba has a law requiring that85 percent of gasoline sold in its jurisdictionbe blended with 10 percent ethanol; andOntario offers tax breaks to producers ofblended fuels and has pledged to have allgasoline contain 5 percent ethanol by2007. ●
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 9
● N O R T H A M E R I C A
Willie’s way on the highwayEthanol sparks interest across North America, boosted by environmental concerns and Bush’s drive to lower Middle East oil imports
IEthanol producers hit the stock market
Ethanol is fast becoming one of the hottest prospects among investors in the UnitedStates.
The leading producer, Archer Daniels Midland, is already a publicly traded compa-ny, VeraSun Energy hit the market earlier in June and two more — HawkeyeRenewables and Aventine Renewable Energy Holdings, which churn out 200 millionand 150 million gallons per year, respectively — are poised to launch initial publicofferings. The funds are tagged to build ethanol production at a time when domesticproducers are unable to meet the needs and imports from Brazil, the world’s largestexporter, will be unable to fill supply gaps.
Brian Kuzma, an analyst with RBC Dominion Securities in Houston, said theethanol cycle is now at its frenzy point, encouraging his firm to initiate coverage of themarket. Since several major U.S. refiners have started phasing out the gasoline addi-tive MTBE, methyl tertiary-butyl ether, the thirst for ethanol is rising faster than U.S.corn-ethanol producers can respond.
In parts of the United States ethanol is fetching as much or more wholesale as theretail price, which pushed fuel alcohol for blend-stock to $2.65 per gallon earlier thisspring.
Brazil is forecast to produce 16 billion liters of sugarcane-based ethanol in 2006, up600 million liters from last year, but its own domestic consumption will cut intoexports.
Some traders have estimated that Brazilian demand, where ethanol makes up 40percent of vehicle fuel, could slash exports to 1 billion liters this year from 2.4 billionin 2005 — a prospect that boosted ethanol pump prices by 14 percent in March alone.
Against that backdrop, the spot price of New York Harbor ethanol climbed to $4 agallon in early June from $1.30 a year earlier.
Hawkeye, in its IPO filing, said it believes the U.S. ethanol industry has insufficientcapacity to meet current and anticipated demand, projecting the market for oxygenates,including ethanol, will surpass 6 billion gallons within a few years.
Commercial Alcohols, Canada’s largest ethanol maker, is not preparing an IPO yet,despite growing interest from investment banks over the past two years, but VicePresident Bliss Baker said all options are on the table.
He rejected any thought that the company might be missing out on a hot market,contending that the interest in alternative fuels is not about to fade.
Similarly, other Canadian ethanol companies, Pound-Maker Agventures ofSaskatchewan and Permolex of Alberta, are neither ruling out, nor openly pursuing anIPO.
—GARY PARK
The Canadian Renewable FuelsAssociation said that in addition
to incentives the challenge will beto introduce common standards
across Canada.
Singer Willie Nelson is putting his moneywhere his mouth is by manufacturing andselling “BioWillie,” his own brand of alter-native fuel.
PAU
L N
ATK
IN
10 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
● C A N A D A
Gas overhang a threat, says NEBCanada’s National Energy Board sees storage space running out by late summer, pushing prices down, triggering possible shut-ins
By GARY PARKFor Petroleum News
anadian natural gas producers may be forced toscale back production by late summer if NorthAmerican storage space reaches capacity for thefirst time, driving down commodity prices, said
the National Energy Board.In its inaugural summer outlook, the federal regula-
tor said refilling storage facilities is one month aheadof schedule and, unless that pace changes, the “over-hang” could drive prices to US$5 per million Britishthermal units — the lowest point since September2004 and 16 percent below current futures prices.
Even worse is a growing sense of gloom amongsome Canadian analysts that junior producers carryinghigh levels of debt could be pushed over the brink iftheir capital spending outpaces their cash flow after ayear of watching record levels of activity drive up thecosts of drilling and other services by 50 percent.
Typical of those starting to feel the squeeze isBerens Energy, whose bankers have hiked an operatingfacility to C$57 million from C$45 million while thecompany has cut its 2006 budget to C$51 million fromC$71 million.
Their best hope is the one held out by the NEBwhich said a cold snap by late November or Decembercould see prices rebound to the $7-$9 range.
Barring a catastrophic hurricane season in the Gulfof Mexico or a scorching summer, the board believesstorage will hit its limit by late summer, leading to agas surplus of 620 billion cubic feet.
To right the market, exports from Canada will haveto fall, North American production will have to betrimmed, or consumption will have to rise, it said.
Of those options, the NEB is betting the most like-ly initial response will be for coal-fired electricityplants in the eastern U.S. to switch to gas, which coulddisplace about 40,000 metric tons of coal a day.
That could also be accompanied by high-cost pro-ducers, such as those in the U.S. Rockies, cutting backon production until prices recover.
Paul Mortensen, an NEB analyst, told reporters thatthe board expects drilling will continue in Canada inthe hope of a price recovery by mid-winter, but someproducers may delay start-ups or shut in wells whilehoping for a more normal winter.
Companies already cutting E&P spendingThe clouds over the Canadian gas sector have
already prompted EnCana, Husky Energy, Apache,Murphy Oil and several junior E&Ps and income truststo cut their E&P spending, lowering a forecast byCitigroup Global Markets for overall capital spendingin 2006 to C$27.8 billion.
That’s still up 8.6 percent from 2005, but short of the12 percent hike predicted by Citigroup six months ago.
Of the 72 companies with operations in Canada whoresponded to the survey, 35 percent expect to spend
more in the second half of 2006 than the first half and27 percent expect to trim their budgets.
“It appears there is limited upside potential toCanadian spending plans this year (unless there is a)strengthening of natural gas prices,” Citigroup said.“The price likely to yield 10 percent budget increases,on average, is now C$10.07 (per thousand cubic feet),up slightly from C$9.98 in December and above thecurrent 12-month futures strip of C$8.28.”
The survey found that 52 percent of Canadianrespondents expect to spend more on gas than oil,roughly unchanged from a year ago, but well short ofthe 65 percent among U.S. independents.
Coalbed methane permitting downThe first hint of a pullback from unconventional
plays because of price uncertainties and risingupstream costs has surfaced in Canada where new wellpermits have fallen behind 2005.
The Alberta Energy and Utilities Board issued1,034 coalbed methane permits over the first fivemonths, down just 12 wells from the same period lastyear, but May’s count was 143 compared with 232 inMay 2005, putting a dent in hopes of 4,000 coalbedmethane wells this year and 6,000 in 2007.
A disturbing sign has been the drastic scaling backof coalbed methane programs by the largest operators:Devon Canada has licensed eight wells compared with78 to the end of May 2005; Apache Canada, 70 vs.103; MGV Energy, 118 vs. 156; and EnCana 196 vs.259.
Offsetting those trends, rig counts remain ahead oflast year’s pace, with 60 percent of the activity target-ing gas, and well completions are 20 percent higherthan 2005.
David Hyman, an analyst with Raymond James,said in a research note that “field activity levels con-tinue to build toward what is expected to be a verybusy summer.
“While natural gas concerns remain rampant, wecontinue to believe that field level activity will contin-ue to be governed by a longer-term view on pricing,which is still above prior year levels.”
Aside from whatever jitters the prospects for therest of this year are causing in the industry, the Albertagovernment is likely to be on edge, having based its2006-07 budget on average gas prices of $6.78 per mil-lion Btu. Currently, gas accounts for 60 percent of theprovince’s energy royalties and is forecast to reachC$7.15 billion in the current fiscal year, but may needa major adjustment. ●
C Rattled by last winter’s dive in commodity prices, theNorth American natural gas sector is worried by a seriesof sign posts that are pointing in the wrong direction. Butnot everyone is reaching for the panic buttons.
The summer is forecast to be cooler than last year,lowering the demand for gas-generated electricity to runair conditioning systems, while gas storage systems mayhit capacity this fall, laying the groundwork for a priceslump around mid-September.
Ken Yeasting, a director of Cambridge EnergyResearch Associates, told a Calgary conference earlier inJune that because there is insufficient storage workingcapacity to absorb all of the gas available for injectionthere is likely to be a “sharp and swift drop in spot gasprices” unless summer temperatures soar or hurricanescause significant supply disruptions.
CERA is predicting that by early fall prices could dropfrom recent levels of just under US$6 per million Britishthermal units to $5, forcing some high-cost producers tosell at a loss for a period.
But Yeasting said that if prices drop towards $5, gas-fired power generation could displace coal-fired genera-tion, creating additional gas demand and thus supportprices and “rebalance the market.”
He said coal-fired plants likely to pay the price areolder, inefficient eastern U.S. facilities that burn high-costAppalachian coal without emission control equipment.
CERA has calculated that North American withdraw-
al capacity covers a spread from 37 billion cubic feet perday when inventory is below 20 percent of workingcapacity to 48 bcf when it is above 60 percent. Theresearch firm said North American injection capabilityranges from above 33 bcf per day when inventory isbelow 50 percent of working capacity to 15 bcf wheninventory is above 90 percent.
Thus, when storage inventories are at their peak insummer, the gas market has less ability to respond todaily drops in demand or increases in supply. As a result,it will need a greater decrease in gas prices to balance themarket when inventories are high and injection capabili-ties are low.
Record U.S. storage expected The latest forecasts project Lower 48 storage invento-
ries at a record level of 3.643 trillion cubic feet by the endof October, closing in on the working storage capacity of3.76 tcf.
Based on those levels, CERA believes daily storageinjection capability in the Lower 48 will drop to 10.7 bcfor lower at the end of the injection season.
However, despite growing storage inventories, pricesfor the upcoming winter have held firm around $10 permillion British thermal units.
Calgary-based FirstEnergy Capital is not surprised by
see SLUMP page 12
Ingredients in place for price slump
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 11
● A L A S K A
Can pipeline regulations be simplified?Regulatory Commission of Alaska convenes special hearing to gather views from interested parties and determine way forward
By ALAN BAILEYPetroleum News
overnment regulation of oil and gas pipeline tariffsand operating rules is intended to create a level play-ing field for all users of a pipeline transportationinfrastructure and to ensure fair tariff levels.
But is pipeline regulation in Alaska excessive? Somepipeline operators have complained about the excessivecost and time of the regulatory process, saying that the reg-ulatory burden inhibits oil and gas development.
And should a small pipeline that only carries productsfor the pipeline owner even be regulated? Or what about apipeline where would-be shippers have all reached anacceptable commercial agreement for the pipeline use?
In December 2005 the Regulatory Commission ofAlaska opened docket R-05-011 to investigate the possibil-ity of reducing the regulatory burden, perhaps by establish-ing two or more classes of pipeline with different levels ofregulation.
The commission sought comments on possible regula-tion changes. And an RCA public hearing on June 13 pro-vided an opportunity for interested parties to review anddiscuss the various comments that the commission hasreceived. At the hearing, counsels representing BP PipelinesTransportation (Alaska) Inc., Union Oil Co. of California (aChevron subsidiary), Marathon Oil Co. and Tesoro AlaskaCo. talked to the RCA commissioners.
Current issuesCounsels for Union Oil and Marathon expressed frustra-
tion with the time and cost involved in the regulatoryprocess for the construction of the Kenai Kachemak gasline that the two companies own on the west side of theKenai Peninsula. The KKPL regulatory process continuedfor three years, despite the fact that the pipeline has onlycarried gas for Union Oil and Marathon, said DavidRobinson, counsel for Marathon. The regulations requiremassive amounts of information, he said.
“At one point in the KKPL (regulatory) proceedings, asmuch as 25 percent of Union’s management time wasfocused with dealing with pipeline issues,” said BradfordKeithley, counsel for Union Oil.
Louis Veerman, counsel for BP, listed three BP pipelineson the North Slope solely used by affiliates of the pipelineoperator and one of which simply transports gas to an oilfield for enhanced oil recovery operations. Economic regu-lation of these pipelines serves no useful purpose and,unless a third party company requests access, regulationcould be eliminated, Veerman said.
“This would reduce the cost of operating these pipelines,which serve an important function but which also need torun in a cost effective way,” he said.
Two factorsKeithley said that overregulation results from two main
factors:1. RCA generally interprets Alaska statutes to mean that
any pipeline on state land outside a unit boundary is a reg-
ulated transportation line rather than a gathering line asso-ciated with oil or gas production (the statutes exclude gath-ering lines from regulation but do not provide a clear defi-nition of a gathering line).
2. RCA applies the same comprehensive regulations toall regulated pipelines, regardless of the pipeline use.
And Keithley compared the situation in Alaska with thatin Texas and Oklahoma, where he said that many pipelinesare classified as gathering lines and are regulated at a rela-tively low level. In these states, regulators respond to com-
G
see REGULATIONS page 12
12 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
this trend, forecasting winter prices willremain strong regardless of how full storagereservoirs become.
In a new analysis, the firm said factorsunderpinning winter prices include thecontinued strength of crude oil prices, con-cerns about the prospect of hurricanes inthe Gulf of Mexico (which drove gasfutures to US$15.78 last December), thechances of a “normal” winter and thediversion of LNG cargoes from the U.S. ifhigh prices take hold in overseas gas mar-kets.
FirstEnergy said the obsession withrecord volumes in storage is not likely tocause a “significant reduction” in strongpricing levels for the 2006-07 winter.
Don Warlick, president of Texas-basedconsultancy Warlick International, told a
Calgary conference that a hot summer andnormal winter will stall price declines andreduce the anxieties among “financialtypes.”
But if North America experiences acool summer and warm winter there wouldlikely be a sharp drop in activity such ascoalbed methane drilling, he said.
Warlick said Henry Hub prices areexpected to average between $6.83 and$7.04 per thousand cubic feet this year and$5.29-$5.36 in 2007, a sharp downturnfrom last year’s spike of $8.02, but more inline with earlier years — $3.36 in 2002,$5.24 in 2003 and $5.58 in 2004.
He doubts LNG imports will have anyimpact on North American prices until2012 because of the problems obtainingregulatory approvals in the face of com-munity and environmental opposition andthe competition for LNG supplies in Asia.
—GARY PARK
continued from page 10
SLUMP
plaints from third party shippers, using ratecomparisons or rules of thumb to determineequitable rate levels, he said.
Robinson said that in Louisiana the pub-lic services commission only regulates pub-lic utility pipelines while the office of con-servation (the state agency that regulates oiland gas production) regulates other lines.Just two people in the office of conservationregulate 100 intrastate pipelines, he said.
Tesoro’s viewsTesoro takes a different view of
pipeline regulation from the other com-panies represented at the RCA hearing.
“Our position is that the regulatoryregime that’s been in place has workedwell for 40 years and it’s created certain-ty for producers, explorers and owners,everybody involved,” David Wensel, thecompany’s counsel told the commission-ers. As well as using products deliveredto its Nikiski refinery through variouspipelines, Tesoro operates a regulatedpipeline that carries petroleum productsfrom Nikiski to Anchorage.
Businesses need access to pipelineswith fair tariffs and it is necessary to bal-ance the cost of the regulatory burdenagainst the benefits that regulationbrings, Wensel said.
Wensel emphasized the importance ofbeing able to assess future pipeline tariffsand regulatory requirements when plan-ning new projects. And achieving a levelof certainty in these assessments dependson “litigation quality numbers,” ratherthan the summary or approximate datathat might result from simplified regula-tion, he said.
Wensel said that much of the time andcost associated with pipeline regulationin Alaska results from litigation. RCAcould exert some control over theamount of litigation generated, he said.However, Keithley said that much of theregulatory burden derives from thenumerous meetings and negotiationsinvolved in developing acceptable tariffs.
Wensel also said that Tesoro finds itdifficult to comment on simplified regu-lations in the absence of specific propos-als for regulation changes.
“Today we’re here in a vacuum,”Wensel said. “We don’t have a specificproposal to kick around.”
Wensel also questioned ideas of tryingto apply simplified regulations to smallpipelines — it is difficult to define whatis meant by a small pipeline and a smallpipeline could prove just as important asa large pipeline to someone wanting todevelop a new oil or gas pool, he said.
Simplified regulationsHowever, Keithley suggested that
simplified regulations could apply to auser-owned pipeline where there is norequest for third-party transportation orto a pipeline where RCA has determinedthat the tariff is minor to the point of notsignificantly impacting exploration andproduction economics. He floated thefigure of 25 cents per thousand cubic feetas the “deminimus” tariff that a carriermight apply to a gas line.
Keithley also recommended obtainingideas for less burdensome regulationfrom other states.
Robinson thought that in the case of auser-owned pipeline, a regulation requir-ing just a one or two sentence tariff state-ment might suffice.
“In many of these cases there’s justnever a need for third party (pipeline)use,” he said.
And Keithley emphasized the value ofonly requiring full pipeline economicregulation at the time when a third partyshipper requires service. In this situationthe commission could perhaps require anindustry-standard rate as an interim tar-iff, while the pipeline operator appliesfor the regulated tariff, he said.
After some discussion the companycounsels at the meeting volunteered todevelop some proposed new regulationsfor consideration by RCA. And the RCAcommissioners agreed with this strategy.
However, Commissioner DaveHarbour pointed out that, as a rule mak-ing procedure, the proceedings are com-pletely open to all members of the public.
“Any member of the public can sub-mit to us a suggestion at any time aboutwhat the rule should be,” Harbour said.
Harbour also cautioned about the dan-gers of assuming that a pipeline willnever be used by a third party shipper.
“You have to assume that at sometime a third party will materialize … thenyou need the numbers that will give youa basis for going forward,” he said, refer-ring to data such as the cost base for tar-iff determination.
Harbour also said that some specificdetails, such as deminimus tariffs,require clear definition. He added thatthere is a probable need to ensure thatstate regulations mesh seamlessly withthe equivalent federal pipeline regula-tions.
Commissioner Mark Johnson said thatany revised regulations need to adequate-ly consider what happens when apipeline status change triggers a changein regulatory requirements.
“The real train wrecks are going to bewhen there’s a change of status,” he said.
And Commissioner Tony Price, inrecognition of Tesoro’s views, empha-sized the importance of taking intoaccount the needs of pipeline shippers aswell as the needs of the carriers.
“It’s important that more than the car-riers can sign onto any proposed regula-tion, or for me it becomes meaningless,”he said.
Plan of actionAt the end of the hearing Commission
Chair Kate Giard proposed a plan inwhich Union Oil, Marathon and BPwould arrange a presentation to the com-missioners on pipeline regulations instates other than Alaska and on federalpipeline regulations. The interested par-ties would then convene workshops,facilitated by RCA, to develop proposedregulations, for submission to RCA at theend of December. RCA would then havea further year to complete the publicprocess for a regulation change.
Giard said that RCA will draft anorder to review the plan at a public hear-ing in the near future. ●
NORTH SLOPEKaktovik’s Native village corporation,unlike village, will work with Shell
Kaktovik’s Native village corporation has distanced itself from a village gov-ernment resolution denouncing Shell Oil for pursuing oil exploration in whalinggrounds offshore northern Alaska.
The Kaktovik Inupiat Corp. said the week of June 5 that “the best way to dealwith Shell Oil Co. is to work out issues in a civil and cordial manner.”
In May, the village City Council passed a resolution calling Shell “a hostile anddangerous force” and authorizing the mayor to take legal or other actions neces-sary to “defend the community.”
Mayor Lon Sonsalla said Shell had failed to address village concerns abouthow it would keep seismic testing scheduled for this summer from disturbingmigratory bowhead whales and how the company would operate safely in unpre-dictable sea ice.
Last year Shell leased nearly a half million acres in federal waters of theBeaufort Sea, some near Kaktovik, an Inupiat village of nearly 300 people on theBeaufort coast.
Shell’s seismic tests this summer call for using airguns from a ship to sendsound pulses through the sea floor. The pulses bounce back up to the ship for animage of rock formations potentially bearing oil and gas.
Shell needs permits from the U.S. Minerals Management Service, which regu-lates offshore oil operations, and the National Marine Fisheries Service, whichmanages sea mammals such as the bowhead whale.
The Kaktovik Inupiat Corp. owns land near the Arctic National WildlifeRefuge coastal plain and has supported opening that area to oil development. Itsshareholders include Kaktovik residents and whaling captains.
However, the corporation “opposes all activity at our whaling grounds,” it saidin the statement, and it has concerns about how well oil spills can be prevented orcleaned.
But it noted that Shell has negotiated with North Slope whalers over itsBeaufort activity and has signed an agreement to shut down until Kaktovik,Nuiqsut and Barrow whalers meet their quotas.
“The reality is the federal government has already sold oil leases and activitywill take place,” the corporation said. KIC is “willing to work with Shell Oil Co.so that we may have a say on what goes on during whaling and other subsistencethat we engage in.”
—BILL WHITEAnchorage Daily News
continued from page 11
REGULATIONS
By DAN JOLING Associated Press Writer
ederal regulators have denied arequest by BP Exploration (Alaska)Inc. to postpone testing of NorthSlope low-pressure transit pipelines
with internal devices that clean lines ordetect physical problems.
The company, however, can continueoperating the lines as it uses alternatetesting methods to detect problems.
The Pipeline and Hazardous MaterialsSafety Administration, part of the U.S.Department of Transportation, on March15 ordered BP to test within three monthsthree low-pressure oil pipelines with a“smart pig,” which runs inside the pipeand detects anomalies and weak spots.
The order called for BP to run scraperpigs through pipes to push out sedimentand solids. The company also was to cor-rect problems and report its progress.
The agency ordered the testing twoweeks after BP discovered the largest oilspill in North Slope history, a leak of anestimated 201,000 gallons onto the tundrafrom a 34-inch pipeline in Prudhoe Bay’swestern operating area.
The agency’s corrective action ordercalled for maintenance pigging by June12 and inspection with the smart pig byJune 14.
Those deadlines will not be met butBP will be allowed to continue operatingthe transit lines to move oil to the trans-Alaska pipeline.
BP pleased with decision“We’re pleased that the Department of
Transportation has authorized the contin-ued operation of the BP transit lines andhave made a preliminary determinationthat the testing alternatives we have pro-posed will meet the agency’s intent,” saidcompany spokesman Daren Beaudo.
BP said factors outside its controlmade the deadlines impossible to meetand it petitioned for an extension.
One factor, Beaudo said, was a grandjury subpoena requiring BP to remove asegment of the line that leaked.
Also, BP has yet to work out a planwith Alyeska Pipeline Service Co., oper-ator of the trans-Alaska pipeline, for thecapture and disposal of the cubic yards ofsolids generated by pigging the line fromthe Prudhoe Bay eastern operating area,Beaudo said.
BP will continue to work to reach fullcompliance with the corrective order,
Beaudo said. It has met regularly with
agency officials in Anchorage, Denverand Washington, D.C., he said, keepingthem apprised of alternative monitoring.
Inhibitor now being directly injectedOne reason for the leak, Beaudo said,
is that corrosion inhibitor may not havereached the affected pipeline. Corrosioninhibitor is now being injected directly,he said.
The company has begun 30 alternatetesting methods, including radiography,ultrasonic testing and collection of datafrom 2,200 locations along the 22 milesof pipeline under review. The company isconducting monthly measurements ofcorrosion inhibitors and has installeddevices that allow monitoring of linesbeneath gravel roads and gravel cariboucrossings.
“We have a really good idea of thecondition of the lines,” Beaudo said.
The agency said the testing alterna-tives and BP’s enhanced monitoringappear to meet the agency’s intent.However, the requirement for the internaltesting will remain and it may addrequirements following a review of thecompany’s data.
“Our objective is to ensure theirpipelines are completely safe,” said TomBarrett, agency administrator.
In a letter to BP, associate administra-tor Stacey Gerard said the pipeline safetyoffice was not ready to complete its eval-uation and that it “reserves the preroga-tive to seek civil penalties for violationsof these requirements.”
Lisburne pigging began June 10Pigging of a line from the Lisburne oil
field began June 10.The earliest two sections of the eastern
area transit pipe could be inspected andcleaned is mid-July and mid-October,Beaudo said.
The earliest the western area could bestarted is the second quarter of 2007,Beaudo said. Another complicating factoris that the pig launcher is upstream of the34-inch line that’s now shut in.
“We’re going to have to put in a newpig launcher,” he said.
BP is part owner of the Prudhoe Bayoil field, the nation’s largest, but operatesit for all owners. ●
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 13
● N O R T H S L O P E
Agency: BP can operate pipelineswith alternate safety tests
The 800-mile trans-Alaska oil pipeline runs from Prudhoe Bay to the port of Valdez.
F
INTERNATIONALBrowne: BP to spend $50 billion onexploration, production next five years
According to a June 14 report in Forbes, BP Chief Executive Lord Browne toldreporters that BP plans to invest US$50 billion on oil and gas exploration and pro-duction over the next five years.
The money will be spent to bring online natural gas from Alaska, Indonesia,Egypt, the Caspian and East Siberia, while more oil will be extracted fromAngola, Russia and the Gulf of Mexico, Browne said at a news conference mark-ing the launch of BP’s Statistical Review of World Energy. The $50 billion represents a $3 billion increase over what BP has spent on E&Pworldwide in the last five years, the magazine reported.
—PETROLEUM NEWS
JUD
Y P
ATR
ICK
highest worldwide, he said, and theexpected rates of return on total capitalgreatly exceed costs of capital for thesponsors.
The project, he said, has ample rev-enue to support its expected costs.
Disadvantaged compared to what?The state’s fiscal interest finding
compared transportation costs of morethan $2 per million British thermal unitsfor the Alaska project to $1.20 per mil-lion Btu for liquefied natural gas.Leitzinger said Econ One’s estimatedtariff of $2.17 per million Btu is lowerthan the $2.25 the state used.
More significantly, the state’s trans-portation cost for LNG includes onlytanker transportation, he said, and doesnot include per-million-Btu costs of 75cents for liquefaction, 40 cents forregasification and 10 cents for trans-portation from the regasification facilityto market.
This kicks the total LNG transporta-tion cost up to more like $2.50 per mil-lion Btu, he said, somewhat higher thaneither $2.17 or $2.25, which are lev-elized nominal dollar figures for the lifeof the project. Since the ANS gaspipeline project wouldn’t start movinggas for some 10 years and then contin-ues for several decades, a comparisonwith today’s LNG transportation rates ininappropriate, he said. In today’s dollarsthe pipeline tariff is about $1.20.
Leitzinger said he sees no compari-son with LNG transportation costs thatplaces the Alaska project at a disadvan-tage.
The net present value per barrel of oil
equivalent reflects net value for energyincluding the cost of transportation, hesaid, and achieves a target level at pricesabove $4 in Alberta. At $5.50, the num-ber the state used, there is plenty of rev-enue left over after transportation tosupport costs, Leitzinger said.
Transportation, investment implications
What are the investment implicationsof the transportation costs? Eighty per-cent of the money for the project willcome from lenders as limited recourseloans backed by federal governmentloan guarantees that will reduce the loancosts and will be secured by shippingcommitments, Leitzinger said. Tariffrates are set on debt to allow recovery ofthe loan costs, he said, and if the regula-tors do their job the rate allowed onequity will be sufficient to attract capitalto the project. Leitzinger said the will-ingness of independent companies tobuild the project subject to regulatedreturns indicates those rates are not toolow.
He said the fiscal interest finding dis-cussion indicates the state believes theproducers are not willing to supply gasto a project they don’t build and that itwould take years to wrestle the gas awayfrom them.
Because the sponsors are explorationand production companies they want anE&P return for the project, he said, not apipeline return, and part of what is driv-ing the state’s analysis is how to getmore than a regulated return for theproject.
The sponsors have combined equitycapital of $676 billion, 95.9 percent oftheir capital structure, he said, with only4.1 percent debt. Taking on the debt tobuild the pipeline would only increasethe companies’ collective debt by 2 per-cent. Leitzinger said he didn’t think thedifference between 4 percent and 6 per-cent debt would have any significantimpact on the cost of capital to the com-panies or on their ability to raise it.
At a $6 per million Btu expectedprice and a transportation cost of around$2, Leitzinger said there is little ship-ping risk over the life of the project, not-ing that a $2 gas price in Alberta seemedto him a remote possibility.
IRR poor investment metricLeitzinger said the state’s fiscal find-
ing called internal rate of return the pro-ject’s “Achilles’ Heel,” but said IRRshows the relationship between earlycash out and later cash in and is a poorinvestment metric especially with dif-ferent risk profiles between projects,different time frames and differentcosts.
The fiscal finding treats the $21 bil-lion project cost as a cash outflow at thebeginning, he said: but it’s not a cashoutflow from the sponsors and not a cor-rect use of IRR.
In the comparison with projectsaround the world from PFC in the fiscalfinding there are some projects whichdon’t include full capital costs, he said,and unless you put all the right costs inother projects you won’t get valid com-parisons.
The Alaska project is also comparedto both oil and gas projects, and trans-portation economics are fundamentallydifferent between oil and gas projects,he said, with different expected returns,different uses for the oil or gas, differentreturns and different reasons to pursuethe projects.
Leitzinger said he doesn’t believe it,but even it if were true that it makessense to put all transportation costs intoIRR and compare projects, you wouldhave to recognize that the regulated gaspipeline business has a lower risk pro-file than energy marketing and energy
development. The Alaska project isheavily weighted with pipeline costs soan across-the-board comparison of oiland gas projects is like comparingapples to oranges, he said.
Leitzinger said that as an economicmatter he fails to see the case that theAlaska North Slope gas project is chal-lenged today based on market prices andcosts. It is economically viable on itsown terms in today’s market, he said,and with the needs of companies toreplace reserves it holds out the prospectfor adding one of the largest knownreserves bases and has one of the high-est net present values.
Leitzinger also said he sees no reasonto believe the Alaska project standsbehind other projects because otherprojects on the comparison list are sanc-tioned and moving ahead.
As for risk, the net present value of10 percent is more than enough to offsetand compensate for risk, he said.
How risky is the Alaska project? Tony Finizza, an Econ One consult-
ant, compared the Alaska project withother investment projects and said theproject is not disadvantaged under pres-ent fiscal terms.
He also assessed the cost overrun riskand price risk cited by administrationconsultant Pedro van Meurs in May tes-timony. Van Meurs had concluded thatbecause of the combination of cost over-run risk and price risk there is a 20 per-cent to 30 percent chance that the proj-ect will not be built, even with a fiscalcontract in which the state gave substan-tial financial incentives to the buildersof the line.
Finizza said Econ One believes theprobability of having an uneconomicproject is “far smaller” than 20-30 per-cent. If you examine two low-chanceevents the chance of both happening atthe same time is significantly smallerthan either happening by itself, he said.
The Econ One analysis assumed therisks are correlated because high capitalcosts are more likely when prices arehigh because there is increased industryactivity and competition for materials.
Finizza said the risk of an uneconom-ic project under various price and costoverrun distributions ranges from lessthan 1 percent under a U.S. Departmentof Energy, Energy InformationAdministration scenario to about 5 per-cent under the fiscal interest finding sce-nario. ●
14 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
COOK INLET BASINAlaska Crude prepares to re-enterMoose Point No. 1
Alaska Crude Corp. is about to re-enter the Moose Point No. 1 well, in pri-vately owned land near the northern end of the North Kenai Road on Alaska’sKenai Peninsula.
“The drilling will probably start next month,” Bruce Webb, vice president, reg-ulatory affairs, for Alaska Crude Corp, told Petroleum News. “… Right nowwe’re digging a trench around the pad to keep the pad drained.”
The company has two drilling rigs, either one of which can do the drilling.“Everything is out there except the choke manifolds and the blowout preven-
ter,” Webb said, adding that the company expects to obtain those two remainingitems in the next couple of weeks. All of the required permits are in place, Webbsaid.
Amorex Inc. drilled the Moose Point No. 1 well in 1978 to a depth of 10,058feet. The well had a gas show but Amorex was exploring for oil, Webb said.
Alaska Crude hopes to find commercial quantities of natural gas and has beennegotiating with Agrium as a possible purchaser for the gas, he said.
The well is fairly near the ConocoPhillips gas line from the North Cook Inletfield to Nikiski and penetrates a known structure that Webb described as a fault-ed nose off the Swanson River field.
Alaska Crude is a small independent oil company headed by Jim White, along-time oil and gas investor in Alaska leases.
—ALAN BAILEY
continued from page 1
ECONOMICS(Econ One Research PresidentJeffrey) Leitzinger said … theexpected net present value is
among the highest worldwide …and the expected rates of return ontotal capital greatly exceed costs of
capital for the sponsors. Theproject, he said, has ample revenue
to support its expected costs.
● A L A B A M A
ConocoPhillips pulls bid for LNG portGovernor opposes project offshore Alabama because of open loop vaporization; company uncertain it would look at closed loop
THE ASSOCIATED PRESSonocoPhillips is withdrawing its bid for a liquefiednatural gas terminal off the Alabama coast that wouldcool huge amounts of seawater, in a process that crit-ics say could cause massive harm to Gulf of Mexico
fisheries and marine life.Alabama Gov. Bob Riley said June 9 that the Houston-
based company was withdrawing its application in a letterto the federal Maritime Administration.
Riley had set a deadline of June 11 to veto or permit theapplication for an LNG terminal south of Dauphin Islandusing what is known as an “open loop” vaporization sys-tem. Riley had indicated he opposed that kind of system andwould veto the application in an announcement at Mobileon June 9.
“We’ve been having conversations with them for the lastfew weeks,” Riley said. “I was prepared to veto that. Theymade the decision they wanted to withdraw the applica-
tion.” Riley has said he would not allow “any activity that Ibelieve may adversely impact our marine resources if Ihave the power to stop it.”
Environmental and conservation groups urged Riley toveto the project, as Louisiana Gov. Kathleen Blanco did inMay on a McMoRan Exploration Co. application. Rileyhad publicly supported Blanco’s veto.
Critics concerned about harm to marine lifeCritics of the “open loop” vaporization system say it
could harm marine life, particularly fish eggs and larvae, asit uses massive amounts of warm waters to reheat the LNGand turn it back into a gas.
The proposed Compass Port terminal off Dauphin Islandwould be capable of importing the equivalent of 1 billioncubic feet of liquefied natural gas and vaporizing it eachday. Federal officials say the system would cool 136 millionto 177 million gallons per day of seawater.
Environmentalists have fewer objections to a closedloop system for LNG terminals, in which some of the LNGis used as fuel to reheat the rest.
While ConocoPhillips had no immediate comment,Riley said he believes the company is “going to look atsome different technologies now.”
“I think they are going to go back and look at a closedloop system that is a lot more environmentally sensitive. Ithink it’s going to give them an opportunity to reassess theirwhole LNG structure,” the governor said.
A ConocoPhillips spokesman said the process of gainingregulatory approval for the project is lengthy and expensiveand the company would have to review whether it wants tostart over with a closed loop system for the Compass Portterminal, which was projected to create 600 jobs.
“I’m not saying what we’re going to do. We would haveto think about it,” ConocoPhillips spokesman SteveLawless said June 8. ●
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 15
C
16 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
Companies involved in Alaska and northernCanada’s oil and gas industry
ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARSBusiness Spotlight
AAce TransportAcuren USA (formerly Canspec Group)Aeromed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13AES InspectionAES Lynx EnterprisesAgriumAir Liquide. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Air Logistics of AlaskaAlaska Airlines CargoAlaska AnvilAlaska CoverallAlaska DreamsAlaska Frontier ConstructorsAlaska Interstate ConstructionAlaska Marine LinesAlaska Railroad Corp.Alaska Rubber & Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Alaska Steel Co.Alaska TelecomAlaska Tent & TarpAlaska TextilesAlaska West ExpressAlliance, TheAlpine-MeadowAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Arctic ControlsArctic FoundationsArctic Slope Telephone Assoc. Co-op. . . . . . . . . . . . . . . . . . . 17Arctic StructuresArctic Wire Rope & SupplyASRC Energy Services
Engineering & TechnologyOperations & MaintenancePipeline Power & Communications
AutryRaynes Engineeringand Environmental Consultants . . . . . . . . . . . . . . . . . 17
Avalon Development
B-FBadger ProductionsBaker Hughes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Bombay Deluxe RestaurantBond, Stephens & Johnson. . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Brooks Range SupplyBW TechnologiesCapital Office SystemsCarlile Transportation ServicesChiulista Camp ServicesComputing Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7CN AquatrainCONAM ConstructionColdwell BankersColvilleConocoPhillips AlaskaConstruction Machinery IndustrialCoremongers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Crowley AlaskaCruz ConstructionDowland-Bach Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Doyon DrillingDoyon LTDDoyon Universal ServicesDynamic Capital ManagementEgli Air Haul . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Engineered Fire and Safety . . . . . . . . . . . . . . . . . . . . . . . . . . 11ENSR AlaskaEnterprise SteelEpoch Well ServicesESS Support Services WorldwideEvergreen Helicopters of AlaskaFairweather Companies, The . . . . . . . . . . . . . . . . . . . . . . . . . 10Flowline AlaskaFriends of Pets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Frontier Flying Service
G-MGreat Northern EngineeringGreat NorthwestHawk ConsultantsH.C. PriceHilton Anchorage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Holaday-ParksHorizon Well LoggingHotel Captain Cook
Hunter 3-DIndustrial Project ServicesInspirationsJackovich Industrial & Construction SupplyJudy Patrick PhotographyKenai AviationKenworth AlaskaKuukpik Arctic CateringKuukpik/VeritasKuukpik - LCMFLasser Inc.Lounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMapmakers of AlaskaMarathon OilMarketing SolutionsMayflower CateringMI SwacoMWHMRO Sales
N-PNabors Alaska DrillingNANA/Colt EngineeringNatco CanadaNature Conservancy, TheNEI Fluid TechnologyNMS Employee LeasingNordic CalistaNorth Slope TelecomNorthern Air CargoNorthern Transportation Co.Northland Wood ProductsOffshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Oilfield ImprovementsOilfield TransportPacific Power ProductsPDC Harris GroupPeak Oilfield Service Co.PencoPerkins CoiePetroleum Equipment & ServicesPetrotechnical Resources of Alaska. . . . . . . . . . . . . . . . . . . . . 2PGS OnshorePipe Wranglers CanadaProComm Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Prudhoe Bay Shop & StoragePTI Group
Q-ZQUADCORain for RentResidential Mortgage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Salt + Light CreativeSchlumbergerSeekins FordSpenard Builders SupplySTEELFABSuperior Machine and Welding3M Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Tire Distribution SystemsTOTETotem Equipment & SupplyTrinity Inspection Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Tubular Solutions AlaskaUAA Department of EngineeringUdelhoven Oilfield Systems ServicesUnique MachineUnitechUnivar USAUsibelliU.S. Bearings and DrivesVECOWelding ServicesWesternGecoWSI-Total Safety. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Xtel InternationalXTO Energy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
David Karp, Senior Vice President and Chief Operating Officer
By PAULA EASLEY
Northern Air CargoThis year Northern Air Cargo cele-
brates 50 years of providing servicesto rural Alaska. With the recentchange in ownership and recapital-ization of the airline, NAC is posi-tioned to continue to grow andimprove the overall quality of servicesit provides customers. NAC has justpurchased three 737-200 aircraft thatwill be put into service in the firstquarter of 2007.
Before joining NAC, David Karpserved four years as executive direc-tor of the Alaska Tourism MarketingCouncil and most recently sevenyears as chief operating officer atHawaiian Vacations. He joined theNAC team this February. Dave andwife Debbie have four children. Asidefrom family activities, Dave supportsnumerous Anchorage civic organiza-tions.
All of the companies listed above advertise on a regular basis with Petroleum News
FOR
RES
T C
RA
NE
lenging environment.Currently, the Chevron-BP JV is mak-
ing preparations to drill two wells thiswinter, while Devon has obtained alicense amendment to stall its next welluntil the 2007-08 winter.
The joint venture is open to farmingout stakes in four exploration licensescovering 1 million acres of the Delta-Beaufort including stake in the winterwells, Sharon Murphy, Chevron vicepresident of policy, government and pub-lic affairs, told Petroleum News.
For now, Chevron and BP have decid-ed that the four exploration licenses wereunlikely to match the scale or size neededto compete with other opportunities avail-able to the two companies, she said.
But Murphy said the licenses couldopen the door for a new player to “estab-lish a presence in a proven hydrocarbonregion at a reasonable cost” or allowestablished explorers to expand theirholdings.
She said the decision to look for a part-ner is not a sign of diminishing interest byChevron, which holds firm to its beliefthat the Delta-Beaufort will eventuallyemerge as a major producing area.
Devon remains open to third partiesThe same message came from Devon
Canada Vice President Michel Scott, whosaid the company has been unable tocome to terms in the past with potentialthird parties, but the door remains open.
Now that Devon has managed toextend by one year its commitment todrill a second well in the Beaufort “thereis more time for something that makessense” to develop, he told PetroleumNews.
In the meantime, Devon, after failingto make the hoped-for multi-trillion-cubic-foot discovery this year with itsPaktoa C-60 well in the Beaufort has, fora nominal refundable fee, persuaded theDepartment of Indian and NorthernAffairs to move the commitment to drill awell this winter to next.
In any event, Devon had not locked upthe steel drilling caisson (SDC) deployedby EnCana in 2003 at the Alaska BeaufortMcCovey prospect and used for Paktoa,leaving it with no choice but to postponeits upcoming winter plans, Scott said.
That is emphatically not a sign thatDevon has any thoughts of pulling backfrom the Arctic, Scott said, noting thecompany remains confident theMackenzie Gas Project will go ahead.
He said the one-year delay “workswell for us” because it narrows the gapbetween when a well has to be drilled andwhen gas could be delivered from theBeaufort to market — a prospect Devonhas indicated would be unlikely before2015.
“It just means we have a bit more timeon our side and lets us keep our optionsopen,” Scott said, emphasizing thatDevon’s objective is to “keep rolling” inthe Beaufort.
Devon applying for significantdiscovery license
Although the C$60 million Paktoawell did not unlock an elephant, Devonis still applying for a significant discov-ery license that indicates it has found asufficient accumulation of hydrocarbonsto produce at a sustained level, but notenough to provide the economic impetusDevon would have liked.
For all that, Scott said the Beaufortand Mackenzie Delta remain part ofDevon’s portfolio of long-term globalexploration opportunities that usually
receive 20 percent of the company’s cap-ital spending allocation.
The Chevron-BP JV completed twowells that were outside its four explo-ration licenses in April last year and isapplying for significant discoverylicenses for both, Murphy said.
The Olivier 2H-01 and 3H-01 wells,which reached depths of 9,765 feet and8,850 feet, respectively, and cost aboutC$30 million each, were part of the JV’sinitial plans to drill as many as fiveexploratory wells in hopes of laying thefoundation for a new North Americansupply source.
The company already has interests in28 significant discovery licenses in theDelta, Beaufort and Yukon, while BP hasinterests in more than 20 such licenses inthe Beaufort and Arctic Islands.
Explorers want fair access to Mackenzie gas line
All three companies are among sixMackenzie explorers trying to persuadethe National Energy Board to take regu-latory control over the entire gas-gather-ing and the Mackenzie Valley pipelinethat are part of the Mackenzie GasProject, placing regulation of tolls andtariffs under the board.
Imperial Oil, the chief Mackenzieproponent, is arguing at a board hearingthat the gathering system should fallunder the Canadian Oil and GasOperations Act, which covers explo-ration, drilling, production, processingand transportation of gas in theNorthwest Territories, while the NEBAct applies to pipelines that cross theterritories.
Gerry Farrell, a lawyer for theMackenzie explorer group, said regula-tion of the gathering system under theNEB Act is necessary to achieve fairtolls, non-discriminatory service and fairaccess to transmission systems.
For the foreseeable future, he said theproposed gathering system “is the onlyeconomic means of access to new andexisting fields in the Mackenzie Deltaportion of the basin.”
The board has indicated it will issue aruling before the end of July.
Scott said that whatever the verdict itis not a consideration in Devon’s drillingplans “at this time,” although what con-ditions will ultimately apply to accessingthe Mackenzie pipelines is “quite impor-tant to us.” ●
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 17
continued from page 1
PARTNERS
Cook Inlet oil exploration data show-ing an anticlinal structure underAnchorage. The group hopes to drill awell to tap into that structure.
The only significant existing well inthe area is the Romig Park No. 1, drilledto a depth of 11,566 feet in1964 by PanAmerican Petroleum Corp. in full-feeprivate land in the Sand Lake area. That
well was plugged and abandoned. But Webb said that there is a belief
that the Romig Park well did in fact findsome oil and gas.
What is the likelihood of being ableto drill another well in the Anchorage?
“I think there is going to be a way ofdrilling a well in an environmentallyconscious manner,” Webb said.
Nicholas Stepovich, David Lappiand Samuel Cade are also members ofthe group that purchased the acreage. ●
continued from page 1
ANCHORAGE
world technology and rebuild produc-tion.
However, Mines and Energy MinisterLuis Ernesto Mejia made a case forCanadian companies to take advantageof improving domestic security bybecoming partners in reversing a slide inproduction from 750,000 barrels per dayin 1999 to 530,000 bpd in 2005.
“The only way to find new reservesand maintain our double condition ofbeing self sufficient and an exporter is tofind new reserves and for that we needto have new investment from the privatesector,” he said.
Colombia hopes to attract Canadiantechnology to its oilfields and contributeto US$1 billion in direct annual foreigninvestment and hike production to700,000 b/d over the next 15 years.
In contrast to Venezuela, Bolivia andEcuador, who have disrupted the opera-tions of major global companies in theiroilfields, Colombia has never scrapped aproduction contract and is now wooingforeign companies with offers of royaltyincentives.
Mejia said his message to prospectiveinvestors is to look at Colombia in isola-tion and not pay attention to “what’shappening in other parts of the region.”
But he conceded that drug traffickingremains an overriding obstacle and isinvariably linked to assassinations ofgovernment officials and attacks oninfrastructure such as pipelines.
Although progress is slow towards anend to violence, Mejia noted thatColombia has Latin America’s healthiesteconomy, posting growth of 5 percentannually and boasting the lowest infla-
tion rate.Major Canadian companies with
operations in Colombia are Nexen,Enbridge and Talisman Energy, whilePetrobank Energy and Resources is hold-ing an initial public offering of itsColombian subsidiary which produces3,000 bpd and has close to 2.5 millionacres under lease.
Petrobank President John Wright toldreporters that Colombia is a “fantastic”place to do business.
—GARY PARK
Beverly Hills firmprotests PN’s coverageof Arctic claim
THE MAY 21 OIL PATCH INSIDERcarried a brief by Allen Baker titled“Unoilgas claims Arctic Ocean commonarea,” a reprint of which you will find onpage 19 of this issue.
www.unoilgas.com is the home pagefor a Beverly Hills, Calif. companycalled United Oil and Gas ConsortiumManagement Corp., which sentPetroleum News a press release in mid-May saying it “has claimed ExclusiveRights to the 3,000 square mile seabedwithin the international waters of theArctic Ocean Common area for oil andgas resource exploration.”
We chose to report this news as part
of Oil Patch Insider, which allows ourwriters to insert some opinion.
In this case, writer Allen Baker insert-ed both skepticism and humor.
United Oil and Gas Consortium’sPeter Sterling ([email protected])disagreed with what we wrote.
Following are the points he made inhis letter, and responses from the twoAlaska geologists Baker received infor-mation from regarding unoilgas’ Arcticclaim, as well as a comment from Baker.
The geologists are Bernard Coakley,co-chair of the Department of Geologyand Geophysics at the University ofAlaska Fairbanks, and Alan Bailey, staffwriter for Petroleum News.
PETER STERLING: Someone had todo it. The Law of the Sea allows formining operations in internationalwaters.
BERNARD COAKLEY: No one hasto do it. Allowing for mining operationsis considerably different than claimingmuch of the central Arctic for the pur-pose.
PETER STERLING: The two “geolo-gists” your journalist Allen Baker con-sulted obviously don’t know what’s hap-pening in the Arctic.
BERNARD COAKLEY: These guys(unoilgas) know just enough to confusethe issue.
PETROLEUM NEWS: Coakley hasspent much of the past 12 yearsresearching the geology of the variousridges, plateaus and sub-basins that liebeneath the Arctic Ocean. He led thegeophysics program of SCICEX, a seriesof unclassified cruises to the Arctic onU.S. submarines, and late last summerwas co-chief in a research cruise acrossthe Arctic Ocean by the U.S. CoastGuard icebreaker Healy.
That cruise, which crossed all of themajor ocean basins and ridges, collectedabout 2,200 kilometers of multi-channelreflection data that reveal the stratigraph-ic record of the ocean. The seismic sur-veys used two 250-cubic-inch airguns, a200- to 300-meter streamer and nearly100 sonobuoy deployments.
PN staff writer Alan Bailey has a doc-torate in geology. One of his main beatsfor Petroleum News is the Arctic.
PETER STERLING: Drilling can andhas been done in the shifting Arctic ice.The summer 2004 Arctic OceanLomonosov drilling project successfullydrilled to about 400 meters below the seafloor on the Lomonosov Ridge.
BERNARD COAKLEY: Drilling 400meters into pelagic sediments withoutblowout prevention is substantially dif-ferent than drilling for oil and gas. Infact, scientific drilling is a kind of anti-oil exploration. For safety reasons, theydo not want to find hydrocarbons, or anykind of geo-pressured fluids or gas.
PETER STERLING: One of the morestartling discoveries was rock with hightotal organic content in some of the sedi-ments. Gee. Just the sort of source rockwhere one would find oil....
BERNARD COAKLEY: They foundit (rock) there, but there is zero chanceof its having been buried to sufficientdepth so that it produced oil or gas. Orhaving migrated or resulting in anyreserves. It may, if preserved in thedeeper basin, be a significant sourcerock, but no one knows the extent ofthese rocks.
Comment – Correlative Azolla hori-zons have been recognized in the north-ern Atlantic. See article in Nature maga-zine, Volume 441, June 1, 2006.
There are good reasons for believingthat the Amerasian Basin was anoxic forthe first 100 million or so years it exist-ed, but this does not exempt you fromhaving to bury and mature the sourcerock to generate liquids that migrate intotraps.
ALAN BAILEY: The LomonosovRidge does have a horizon with highorganic content. However very little isknown about its geology. The majorityof the remaining area colored in the mapaccompanying the (unoilgas) pressrelease is an area of oceanic crust wherethere is virtually no chance of finding oiland gas.
PETER STERLING: Little chance offinding oil in the Arctic? Again your“geologist” sources must have been hid-ing under a rock for the last 40 years.Within the U.S. controlled Arctic OceanEEZ, the Minerals Management Service(MMS) has recently identified a total of39 plays, including 24 Brookian plays,in the Beaufort and Chukchi seas plan-ning areas. What makes the region par-ticularly intriguing is the size of some ofthe structures — more than 12 of theidentified structures exceed 150,000acres in extent, thus exceeding the sizeof either the Prudhoe Bay or KuparukRiver fields. There are 24 identifiedprospects more than 100,000 acres insize and 95 more than 40,000 acres, theapproximate size of the Alpine field.
The Arctic Ocean Burger field was
18 PETROLEUM NEWS • WEEK OF JUNE 18, 2006
continued from page 1
INSIDER
see INSIDER page 19
Right on the heels of a mission toCalgary to sell the Canadian
petroleum industry on Colombia’sefforts to separate itself from itsnationalist-bent neighbors, theSouth American country was
clobbered June 13 by panic sellingon its stock market.
then drilled in 1989-1990. Burger couldrepresent the largest offshore discoveryon the Alaska OCS with perhaps 7 Tcfgas and 724 Mmb condensate. “Plans toshoot seismic offshore Alaska’s Arcticare already picking up speed. Shell,ConocoPhillips and Houston-based GXTechnology Corp. all plan to shoot seis-mic this summer in the Chukchi Sea,ahead of the MMS Chukchi lease saleplanned for 2007.”
ALLEN BAKER: Looks like he’sdone a little reading on Alaska, but I’mskeptical when someone uses acreage assome measure for the size of an oil accu-mulation. One has nothing to do with theother.
BERNARD COAKLEY: His “claim”covers areas that have never beenexplored and cannot be while there issubstantial ice. All of the areas he citesare on land and the continental shelves— well within areas contained in thepresent EEZs of Russia and the UnitedStates.
ALAN BAILEY: Peter Sterling iscorrect about areas such as BeaufortianSea and the Chukchi Sea. But these areNOT international waters — they arepart of the economic exclusion zone ofthe United States. I think that almost allof the areas of continental shelf whereoil and gas potential is high fall withinsome country’s economic exclusionzone. There may be some areas of dis-pute, but adjoining countries will certain-ly claim these if they turn out to beextensions of the continental shelf.Canada, for example, has ambitions toclaim at least some of the LomonosovRidge.
BERNARD COAKLEY: So doesDenmark.
PETER STERLING: Meanwhile onthe Russian side of the Arctic Ocean:The Giant Shtokman gas and oil field isan early indicator of the potential forenergy within Russia’s Arctic Shelf terri-tory. The Shtokman gas condensatedeposit lies in the Barents Sea, in thenorth of Russia in the greater ArcticOcean. Reserves of gas have been put at3.2 trillion m3, with another 31 milliontonnes of condensate.
Perhaps this is just an invention of themind but to the casual observer this surelooks like commercial hydrocarbons inthe Arctic.
BERNARD COAKLEY: Again on theshelf in the Russian EEZ.
ALAN BAILEY: The perimeter of theArctic Ocean contains very broadexpanses of continental shelf — propor-tionally larger areas of continental shelfthan the Earth’s other oceans. Theseareas of continental shelf are prospectivefor petroleum and they may contain vastquantities of oil and gas. However, virtu-ally all of the areas of continental shelf
come under the jurisdiction of one ormore of the countries that border theocean.
PETER STERLING: Prudhoe wasonce a speculative possibility.
BERNARD COAKLEY: So wasmantle-derived natural gas (e.g. TommyGold). Prudhoe Bay was also associatedwith known oil seeps. It was, for a vari-ety of reasons, truly prospective and pro-ducible with existing (mostly) technolo-gy.
PETER STERLING: (in defense ofhis company’s location) Beverly Hillshas nicer weather than Anchorage 350days of the year. The airport is alwaysopen and it’s close to where the majorityof the consumers are. One thing is forsure, time will tell if commercially
viable hydrocarbons can be located anddeveloped in the Central Arctic
BERNARD COAKLEY: Wishfulthinking should not be confused withgeologic information. Much of the cen-tral Arctic Ocean is underlain by oceaniccrust. Most of the areas are also quitedeep (>3000 meters). This oil, if it existsin commercial quantities, would be quite
challenging to find, explore and produce.No one would put up the money untilsomething similar was found elsewhere.
That said, there could be somethingviable in the areas that are likely to beclaimed under Article 76 of the Law ofthe Sea, particularly the ChukchiBorderland or the Siberian slope. Thedeep ocean is, as far as we understand atthe moment, wishful thinking.
PETER STERLING: It may be soonerthan you think.
BERNARD COAKLEY: Anythingwould be sooner than never. This couldbe a very nice gift for his great-greatgrandchildren, but I doubt it.
ALAN BAILEY ON NEW YORKTIMES ARTICLE: I looked at the storythe New York Times recently publishedabout the Arctic’s oil and gas potential.The idea that the discovery of an azollahorizon on the Lomonosov Ridge indi-cates the potential for “vast” oilresources, as stated in that story, seemshyperbole, to say the least. For starters,azolla is a freshwater plant and oil isgenerally generated from marine organ-isms. And then there’s the issue thatBernard Coakley raises about the lack ofsufficient heat to generate oil or thermo-genic gas. I imagine it’s possible thatthere’s some biogenic gas in the ridge,but nobody knows that. An MMS geolo-gist familiar with Arctic Ocean geologyhas told me the azolla horizon on theLomonosov Ridge MAY extend into theTertiary of the continental shelf aroundthe perimeter of the Arctic Ocean, andcould form a petroleum source rockthere. But that is complete speculation atthe moment.
BERNARD COAKLEY ON 3,000SQUARE MILE CLAIM: Unoilgas saidit “has claimed Exclusive Rights to the3,000-square-mile seabed within theinternational waters of the Arctic OceanCommon area for oil and gas resourceexploration.” Three thousand squaremiles cannot be correct. Their documentrefers to all the Arctic outside the exist-ing EEZs. If it were 3000 square miles, Iwould like to know which region theywere thinking about. It is probably atypo or a grandiose mistake on the scaleof their chutzpah.
Editor’s note: Email addresses for theindividuals quoted above are as follows:Bernard Coakley([email protected]); PeterSterling ([email protected]); AllenBaker ([email protected]); Alan Bailey([email protected]).
PETROLEUM NEWS • WEEK OF JUNE 18, 2006 19
Unoilgas claims Arctic Ocean common area —Reprinted from the 5/21/06 issue of Petroleum News
From that hotbed of the oil industry, Beverly Hills, comes explosive news:The Arctic has been claimed.
Luckily, it’s been claimed by people who believe in Santa Claus. How else to interpret a press release we got this month from the United Oil
and Gas Consortium Management Corp.? After all, it’s titled: “Father Christmasis about to get some company.”
No, no, look at your calendar. It’s not the first of April. But right here (for those who believe in Santa) is the news that United Oil
and Gas “has claimed Exclusive Rights to the 3,000 square mile seabed withinthe international waters of the Arctic Ocean Common area for oil and gasresource exploration.”
Never mind little details like the International Law of the Sea. Our fearless United Oil and Gas (Unoilgas for short) has “duly claimed prior-
ity over (the area) by International proclamation on May 9th 2006.” ThoseInternational proclamations apparently work kinda like your basic magic wand.
Never mind other little details like the fact that two geologists we ran thispast say there’s little chance of finding commercial oil even if you could drill inthe shifting ice.
“There is one shelf area, the ‘keyhole’ north of Siberia, that could beprospective, that would be covered under their ‘claim,’ but this is a remote, dif-ficult area,” one geologist told us. “Some of the deep basin could be prospec-tive, but it is a very speculative possibility. At best, it could be an outstandinglegacy for their great-grandchildren.”
But hey, if it works out, those grandchildren will undoubtedly believe inSanta Claus.
In case you think we’re pulling your leg, you can find more about this excit-ing venture at www.unoilgas.com. They even want industry partners for theirStudy Group. Tell them the Easter Bunny sent you.
—ALLEN BAKER
continued from page 18
INSIDER
