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A7Alaska legislators gets briefed onproposed new oil tax
Vol. 11, No. 7 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of February 12, 2006 • $1.50
● N O R T H S L O P E
● A L A S K A
B R E A K I N G N E W S
● C A N A D A
A4Gravity tracks Prudhoe gas cap waterflood: Meters,
precision GPS receivers measure minute gravity changes from waterflood
B1 Alaska gas tax proposal moving: Croft says bill incentiveto develop gas; ConocoPhillips says it’s bad public policy
B4 Oil sands competition stiffens: India latest to join line-up at Alberta’s door; could do land deal, partnership or takeover this year
One week down, one year to go
Kyoto’s role, using Arctic gas in oil sands and access to pipeline byindependent explorers get aired in first week of Mackenzie gaspipeline hearings. See story on page A6.
Pioneer OKs projectWork begins at Oooguruk, first independent-operated North Slope field
By KAY CASHMANPetroleum News
ioneer Natural Resourcessaid Feb. 6 that it hasapproved and is beginningdevelopment of its
Oooguruk field offshoreAlaska’s North Slope.
In the shallow waters of theBeaufort Sea, Oooguruk wasdiscovered in 2003 and isapproximately eight milesnorthwest of the ConocoPhillips-operated KuparukRiver unit.
Oooguruk will be the first independent-operatedoil field on the North Slope, which has long been
dominated by majors BP andConocoPhillips. Togetherwith ExxonMobil the threemega-majors own most ofthe infrastructure on theslope, including the 800 miletrans-Alaska oil pipelinewhich transports crude fromnorthern Alaska to the port ofValdez for shipment to Lower48 markets.
Pioneer’s board had beenwaiting for both a U.S. Corps of Engineers’ permitand final issuance of a royalty modification on arealeases from the State of Alaska to approve the project.
PScott Sheffield,Pioneer NaturalResources chairmanand CEO
Ken Sheffield, pres-ident of Pioneer’sAlaska subsidiary
see PIONEER page A12
Gary Lunn has full plateArctic gas, labor shortage, B.C. offshore confront Canada’s new energy chief
By GARY PARKFor Petroleum News
rom journeyman carpenter, to con-struction superintendent, tolawyer, to cabinet minister in thefederal government, Gary Lunn
brings a varied skilled set to his job asCanada’s new energy minister.
He might need to draw on his fullbag of tricks as he tackles a mountain ofunfinished business from the previousLiberal administration, with the devel-opment of natural gas in the Arcticregions of Alaska and Canada near thetop of the heap.
Much as the Alaska governmentmight hope for a quick resolution ofwho will build and operate theCanadian section of a gasline from theNorth Slope to the Lower 48, there arestill matters relating to the MackenzieGas Project needing government atten-tion.
One commitment made by theLiberals seems certain to survive — thepledge of C$500 million over 10 yearsto address social and economic issuesstemming from a pipeline along theMackenzie Valley.
Prime Minister Stephen Harper, in a
F
see LUNN page A11
British gas major partners withAnadarko, Petro-Canada onAlaska’s North Slope
Last fall Glenn McNamara said BGGroup would not only become involvedin gas exploration and production inCanada, but that the international gas
major’s frontier strat-egy would eventuallyextend from the
Northwest Territories to Alaska (seePetroleum News’ Oct. 16 issue, Oil PatchInsider column).
McNamara, the president of Calgary-based BG Canada Exploration andProduction, was right.
London-based BG Group plc, a spin-off 20 years ago from the privatization ofthe British government-owned gasmonopoly British Gas, entered Alaska onJan. 26 when its Brooks Range Foothills“participation agreement” with AnadarkoPetroleum and Petro-Canada went intoeffect.
Formally announced Feb. 7, the dealgives BG Group’s new Alaska subsidiary,BG Alaska E&P Inc., a “33.33 percentequity share in 2.1 million acres of land inthe Foothills area of the Alaskan NorthSlope,” also referred to as the BrooksRange Foothills.
Each partner now owns a one-third working interest in theacreage. Anadarko will continue to serve as operator.
Alaska assets managed in CalgaryBG’s Alaska subsidiary will be managed by McNamara in
Glenn McNamara,president of anoth-er BG Group sub-sidiary, BG CanadaExploration andProduction, will bemanaging the BGAlaska subsidiary’sassets from Calgary.McNamara, formerpresident ofExxonMobil’s opera-tions in WesternCanada (includingthe Mackenzie Deltaassets), told theFinancial Post in2005 that BG is inNorth America forthe long haul andwants to be a mate-rial player in thecontinental market.
see BG GROUP page A11
NEW PLAYER
MMS plans to study leasingNorth Aleutian basin’s OCS2007-12 five-year plan includes proposed sales in Chukchi Sea, Beaufort Sea
By KRISTEN NELSONPetroleum News
esponding to a request from Gov.Frank Murkowski the Department ofthe Interior’s Minerals ManagementService has included a study of the
North Aleutian basin in its draft 2007-2012outer continental shelf leasing plan.
The North Aleutian basin planning areais currently withdrawn from leasing bypresidential order.
The draft plan includes Alaska sales in theBeaufort and Chukchi seas and Cook Inlet.
MMS said Feb. 8 that Gov. Murkowski requested
that the North Aleutian area be included sothat the public can provide informationwhich would allow the state and the Interiorsecretary “to decide whether or not to askthe President to lift the current withdrawaland allow a sale during the 2007-2012 pro-gram.” MMS said it included the NorthAleutian basin planning area in the 2007-12draft program in order to have the opportu-nity to gather further information.
MMS Director Johnnie Burton said theagency would be looking for public com-
ment in further North Aleutian basin studies to allow
R
Some in the industrythink the most press-ing issue before Lunnand the governmentis the shortage ofskilled labor andmaterials, and a needto fast-track the pro-cessing of immigrants.
see MMS page A12
MMS DirectorJohnnie Burton
JUD
Y P
ATR
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contents Petroleum News A weekly oil & gas newspaper based in Anchorage, Alaska
A2 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
NATURAL GAS
SAFETY
INTERNATIONAL
GOVERNMENT
A5 Gravity tracks Prudhoe gas cap waterflood
Gravity meters coupled with precision GPS receivers measure minute gravity changes from waterflood in the Prudhoe gas cap
B4 Oil sands competition stiffens
India latest to join line-up at Alberta’s door; could do land deal, partnership or takeover this year
B6 Weather clouds some Canadian regions
Mild winter in Western Canada, with early thaw, restricts access to northern Alberta well sites; drilling still at record levels
A7 Alaska oil tax: PPT with numbers
Pedro Van Meurs and Roger Marks give Alaska legislators numeric examples for proposed production profit tax
A3 WTI to average $65 in ’06, $61 in ‘07
EIA expects continued market tightness, high oil, natural gas prices for next 2 years; U.S. demand contracted 0.3 % in 2005
B5 Specter to look at oil industry antitrust
Consolidations concern chairman of Senate Judiciary Committee, who calls for Congress to look at modifying antitrust laws
B2 Grounder tanker eased off inlet mud flats
Inspection by divers finds minor damage to outer hull of double-hulled tanker after successful refloating operation at high tide
EXPLORATION & PRODUCTION
ALTERNATIVE ENERGY
PIPELINES & DOWNSTREAM
FINANCE & ECONOMY
ON THE A COVERPioneer OKs project
Work begins at Oooguruk, firstindependent-operated North Slope field
Jostling among giants
TransCanada, Enbridge keep raising stakes to win support for pipelines to U.S.
Gary Lunn has full plate
Arctic gas, labor shortage, B.C. offshoreconfront Canada’s new energy chief
MMS plans to study leasingNorth Aleutian basin’s OCS
2007-12 five-year plan includes proposed sales in Chukchi Sea, Beaufort Sea
Gas tax proposal moving
Croft says bill incentive to develop gas; Conoco says it’s bad public policy
White House: ANWR lease revenue could triple
State of Alaska sets North Slope,Beaufort Sea lease sales for fall
IEA: No downturn in oil demand
ON THE B COVER
A3 Native switchgrass could produce ethanol
A10 Total focuses U.S. E&P in Gulf of Mexico
B3 North Slope production down marginally
B4 Cupboard is sparse, but big deals predicted
B12 Oil company earnings chart
B7 Sheriff investigating rant against Exxon
B7 MMS trims royalties due to storm damage
A3 Russian agency rejects Siberia pipeline
A6 Mackenzie: One week down, one year to go
B7 Chavez threatens to sell U.S. refineries
B7 Companies honored for safety
A4 Agrium restarts Kenai nitrogen plant
A4 Coalition slows Norway’s oil and gas development
A10 Kurds invite foreign companies to explore
B3 Cuban officials, U.S. energy execs meet
B5 Petrobras to buy 50% of Texas refinery
B5 Revealing the history of the Arctic Ocean
British gas major partners with Anadarko,Petro-Canada on Alaska’s North Slope
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 A3
MOSCOWRussian agency rejects Siberia pipeline
Russia’s environmental safety body rejected a plan for a controversial crude oilpipeline that ecologists have said could threaten the world’s biggest freshwaterlake.
The proposals for the pipeline from eastern Siberia to the Pacific coast werenot in line with environmental legislation, the Federal Service for Ecological,Technological and Nuclear Supervision — known by its Russian abbreviationRostekhnadzor — said in a statement posted on its Web site Feb. 3.
The decision is a blow for state pipeline monopoly Transneft, which hadbacked a route passing within a kilometer (less than a mile) of Lake Baikal, whichis a UNESCO protected site and home to 20 percent of the world’s fresh water.
Transneft’s proposal had also envisaged the construction of an oil terminal ina pristine Pacific Coast bay instead of closer to the port of Nakhodka, which ana-lysts say would have been a more expensive variant.
The pipeline route, as proposed by Transneft, would run from the town ofTayshet in Siberia’s Irkutsk region through Skovorodino in the Amur region to theport of Perevoznaya in the Primorye region on the Pacific coast.
Separately, Russia’s Industry and Energy Minister Viktor Khristenko said in aninterview published Feb. 6 in the Vedomosti business daily that tax breaks wouldbe offered to investors developing fields in Eastern Siberia and the Far East thatcould be used to fill the pipeline.
—THE ASSOCIATED PRESS
OKLAHOMA CITYNative switchgrass could produce ethanol
Switchgrass, a plant that is native to Oklahoma, has been getting more atten-tion as a possible source of alternative fuel since it was mentioned in PresidentBush’s State of the Union address.
Bush said his goal was to replace three-fourths of the country’s oil importsfrom the Middle East over the next two decades by developing alternative fuels,including switchgrass, which could be used to make ethanol.
The plant can grow up to seven feet tall and is one of the four major species inthe Tall Grass Prairie. It grows naturally throughout much of the eastern half ofthe country, and each acre can produce about 1,150 gallons of ethanol, accordingto the National Bioenergy Center in Golden, Colo.
Switchgrass could be grown on the more than 1 million acres of Oklahomaland that have been taken out of production because they are susceptible to ero-sion, said Charles Taliaferro, emeritus regents professor at Oklahoma StateUniversity. The state currently pays farmers to leave susceptible land bare.
Research still neededOne drawback is that switchgrass contains large amounts of lignin, a glue-like
substance. Research is needed to find ways to convert this substance more effi-ciently into sugars that can be used in ethanol production.
Corn and soy have already been used to produce ethanol. “Our best guess is when ethanol gets to 10 (percent) to 20 percent of our gaso-
line usage, we will run out of cheap corn,” said John Ashwood of BioenergyCenter. “That’s still a big number, but it’s not something that’s going to reduce ourdependence on foreign oil.”
Switchgrass research is under way at Oklahoma State. “We don’t have the technology that is cost effective to compete with the corn
fermentation process of the Midwest,” said Ray Huhnke, an OSU biosystems andagriculture engineering professor.
Huhnke and a research group at OSU are working on a gasification fermenta-tion process that will convert switchgrass to ethanol and make it more affordablefor consumers.
—THE ASSOCIATED PRESS
● W A S H I N G T O N , D . C .
WTI to average $65in ’06, $61 in ‘07EIA expects continued market tightness, high oil, natural gasprices for next 2 years; U.S. demand contracted 0.3 % in 2005
PETROLEUM NEWShe Department of Energy’s EnergyInformation Administration expectsmany of the same global factors thatdrove oil markets in 2005 to contin-
ue to affect markets in 2006 and 2007.The agency said Feb. 7 that low worldspare oil production capacity and rapidworld oil demand growth are expected tocontinue while otherfactors, such as thefrequency and intensi-ty of hurricanes, otherextreme weather andgeopolitical instabili-ty, are less certain.
EIA said it expectsthe price of WestTexas Intermediatecrude oil to average$65 per barrel in 2006and $61 in 2007, com-pared to a 2005 aver-age of $56 per barrel.The retail price of reg-ular gasoline, which averaged $2.27 pergallon in 2005, is projected to average$2.45 in 2006 and $2.34 in 2007.
Henry Hub prices are projected todrop: natural gas averaged $9 per thou-sand cubic feet last year; the 2006 price isexpected to average $8.87 per mcf; andthe 2007 price $8.70 per mcf.
Domestic energy demand growingDomestic energy demand is expected to
increase at an average rate of about 1.4 per-cent in 2006 and 2007, “contributing tocontinued market tightness and projectedhigh prices for oil and natural gas,” theagency said.
It said January in the United States was25 percent warmer than normal, pushingnatural gas prices lower than projected inJanuary.
Oil prices, by contrast, were kept highby cold weather in parts of Asia and Europeand by uncertainties over supplies fromNigeria, Iran and Iraq.
While recovery of production afterstorm damage from hurricanes Katrina andRita continues, the Minerals ManagementService expects some 255,000 barrels per
day of oil production and 400 million cubicfeet per day of natural gas to remain offlinewhen the next hurricane season starts June1.
Production slowed by mature fieldsOn the global oil market, while new
supplies are expected from bothOrganization of Petroleum Exporting
Countries and non-OPEC over the nexttwo years, world oilproduction capacity isexpected to increaseonly slightly becausemany mature fields,particularly in theNorth Sea, Mexico andthe Middle East, “areshowing substantialdeclines,” the EIA said.
Non-OPEC supplygrew an average of800,000 bpd between1995 and 2005, and is
projected to grow by 800,000 bpd in 2006and by 1.6 million bpd in 2007, with pro-duction increases of 100,000-200,000 bpdexpected in the Caspian, Canada, Angola,Russia, Brazil and Mexico. Large newprojects coming on in 2007 are expected toresult in increases of almost 500,000 bpd inAngola, almost 400,000 bpd in the Caspianand more than 200,000 bpd in both Braziland Canada.
World oil demand growth is expected toincrease from 1.2 million bpd in 2005 to1.6 million bpd in 2006, largely becauseU.S. demand is projected to recover from anet decline in 2005 to show growth of350,000 bpd in 2006.
The EIA attributed a 0.3 percent declinein U.S. petroleum demand in 2005, thefirst since 2001, to record high prices, hur-ricane-related disruptions, airline consoli-dations and a mild winter.
World demand growth is projected toincrease to 1.9 million bpd in 2007 due toeconomic growth in developing Asiancountries excluding China, where demandgrowth is projected to stay on an overallannual trend of some 500,000 bpd peryear. ●
T
On the global oil market, whilenew supplies are expected fromboth Organization of PetroleumExporting Countries and non-OPEC over the next two years,world oil production capacity is
expected to increase only slightlybecause many mature fields,particularly in the North Sea,
Mexico and the Middle East, “areshowing substantial declines,”
the EIA said.
A4 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
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COOK INLET
Agrium restarts Kenai nitrogen plantAgrium Inc. is restarting its Kenai, Alaska nitrogen fertilizer plant after a shutdown
due to a cold snap that boosted home heating demand and tightened natural gas sup-plies in the Cook Inlet region, the company said in its quarterly earnings conferenceFeb. 2.
“Kenai is in the process of restarting,” said Ron A. Wilkinson, Agrium vice presi-dent of wholesale. “We’ve got just enough gas cobbled together to do that.”
Agrium shut down one plant at the Nikiski complex Jan. 23 and another Jan. 25,after scraping by for a couple of weeks on a marginally sufficient supply of gas forproduction.
The company said the shutdown was something it had planned for.“We anticipate a little bit of cold in Alaska,” Wilkinson said.Agrium has contracts in place with suppliers for 2006 operations, but the contracts
give priority to utilities when demand for gas rises. Delivery of gas to the company’splant dropped to less than half of the 80 million cubic feet per day needed for pro-duction. Wilkinson said the company expects anticipated warmer temperatures toallow Nikiski plant operations to continue as normal for the rest of the heating season.
—STEVE SUTHERLIN
● N O R W A Y
Coalition slows Norway’soil and gas developmentMinority Socialist Left Party opposes Barents, Lofoten developments;now holds reins at finance, enviro ministries; could lose Arctic lead
By ALAN BAILEYPetroleum News
he election of a coalition of left-lean-ing political parties in Norway’snational election in September maylead to a slowdown in that country’s
oil and gas industry, according to a recentDow Jones Newswires article. Norway isthe third largest oil exporter in the world.
The country’s new environment minis-ter, Helen Bjornoy, has forced a delay inawarding some oil and gas blocks in theBarents Sea and has suggested denial ofdevelopment approval for the 250 millionbarrel Goliat oil field in the Barents,according to the report. The delayedblocks lie between the Goliat field and the200 billion cubic meter Snohvit naturalgas field, Dow Jones reported.
SV partyBjornoy is a member of Norway’s
Socialist Left Party, or SV, the junior part-ner in a coalition led by the country’sLabor Party. SV’s election campaignincluded a commitment to halt oil and gasdevelopment in environmentally sensitiveareas such as the Barents Sea and the areaaround the Lofoten Islands. In addition toraising environmental concerns, the partywants to see Norway developing industrysectors other than the oil and gas businessthat has come to dominate the country’seconomy, according to the Dow Jonesarticle.
According to a story in theScandinavian Oil and Gas Magazine,published prior to the 2005 election, SVwants to see oil gas investment focus onareas that have already been involved indevelopment, rather than opening up“new and vulnerable areas.”
SV controls Norway’s finance min-istry as well as the environmental min-istry — the party’s leader, KristinHalvorsen, has become Norway’s financeminister. Halvorsen was reported in theDow Jones story as saying “We need tobalance out development of industries ...to have several legs to stand on in addi-tion to the oil and gas industry. ... Wehave a lot of opportunities in the environ-mental field” — such as renewable ener-gy and carbon dioxide technology —“and great opportunities for tourism.”
Compromise likelyBut the Labor Party supports explo-
ration and development. So it is unlikelythat SV can completely block new oil andgas initiatives, although Labor may haveto compromise on a management plan forfuture Norwegian oil and gas develop-ment. That compromise could slow downdevelopment — Bjornoy’s managementplan for northern Norway will include atimetable for when or if areas such as theBarents Sea will open for petroleumdevelopment.
However, a quarter of Norway’s rev-enue comes from a petroleum industrythat also drives half of the country’s man-ufacturing industry, according to the DowJones story.
“The tax coming from oil and gasfields is the most important revenue forthe state budget,” Per-Kristian Foss, for-mer finance minister and a member of the
Right opposition party, is reported as say-ing.
And Tor Steig, chief economist for theConfederation of Norwegian Businessand Industry, reportedly said that it isn’trealistic for Norway to focus on tourism,as an alternative to oil and gas.
“It’s not possible,” he said. “The wagelevel is far too high to build a big tourismindustry.”
Negative signalsHelge Lund, chief executive of Statoil
ASA, reportedly said that stoppingdevelopments such as Goliat would senda strong negative signal to oil and gascompanies interested in investing inNorway. And, although Goliat itself onlyaccounts for less than 1 percent ofNorway’s remaining reserves, failure tofind and develop new sources of oil andgas could accelerate the decline inNorwegian oil and gas output to 70 per-cent in the next 10 years, the oil industryhas warned. New development couldslow that decline to between 20 percentand 40 percent.
Lund said that Norway could lose outin future exploration.
“When there are open industrialopportunities, we as an industry have totake those opportunities,” Lund said. “Ifwe are not doing it, others will. ... That’swhy I think it’s not an applicable policyfor Norway to just opt for a delayingpolicy.”
Erik Bruce, Nordea Markets chiefeconomist, said that a slowdown in thepace of oil and gas development wouldimpact Norway’s 3.5 percent annualgrowth. Bruce was reported as sayingthat “at the moment we’re in a very pos-itive environment” for shipyards, tech-nology, drilling and manufacturing. “Butif oil investment turns down, then theyare going to be in big trouble.”
The oil industry and members of theformer conservative government havealso argued that a slow down in the oilindustry could damage Norway’s lead-ing edge in offshore development, engi-neering and technology.
Opening up the Barents “is a terrificopportunity for Norwegian industry tofurther strengthen its position as theleading Arctic industry cluster,” Lundsaid.
And Russia’s OAO Gazprom hasrecently shortlisted Norwegian companiesStatoil and Norsk Hydro for the develop-ment of the huge Shtokman gas field inthe Russian sector of the Barents. ●
The oil industry and members ofthe former conservative
government have also argued thata slow down in the oil industrycould damage Norway’s leadingedge in offshore development,engineering and technology.Opening up the Barents “is a
terrific opportunity for Norwegianindustry to further strengthen its
position as the leading Arcticindustry cluster,” Helge Lund, chief
executive of Statoil ASA, said.
T
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 A5
● P R U D H O E B A Y
Gravity tracks Prudhoe gas cap waterfloodGravity meters coupled with precision GPS receivers measure minute gravity changes from waterflood in the Prudhoe gas cap
By ALAN BAILEYPetroleum News
etroleum engineers have been tracking the progressof the waterflood in the Prudhoe Bay gas cap underAlaska’s North Slope by measuring surface gravitychanges that occur as water replaces gas in the reser-
voir more than 8,000 feet underground.BP Exploration (Alaska) petroleum engineer Jerry
Brady told a Geophysical Society of Alaska audience onFeb. 2 how this state-of-the-art reservoir surveillance tech-nique requires global positioning system receivers that canmeasure ground elevations to within 2 centimeters andgravity meters that take gravity readings to within a fewmicrogals. A microgal is a gravitational acceleration of onemillionth of a centimeter per second squared — roughlyequivalent to a house fly landing on the back of a 20-tonwhale, Brady said.
The history of the waterflood monitoring project goesback to a decision several years ago to use waterflood tomaintain reservoir pressure in the Prudhoe Bay gas cap.Petroleum engineers faced the issue of how to monitor themovement of the injected water underground withoutdrilling observation wells.
“One of the questions was how do we adequately mon-itor this waterflood, given that there are very few wells inthe gas cap at Prudhoe,” Brady said.
Gravity measurement has solved the problem.
Precision gravity metersA key technology in this solution is the modern gravity
meter, used to take gravity measurements at about 200observation stations on a surface grid above the PrudhoeBay reservoir. There are two types of meter in use atPrudhoe Bay: one type measures the relative weight of atest mass between different locations and the other typemeasures the absolute gravity at a location.
The tool of choice has become the absolute gravitymeter, Brady said. This type of meter measures the gravi-tational acceleration by dropping a crystal inside an evacu-ated chamber. It works like the timing of Newton’s famousapple, except that laser-based movement sensors and anatomic clock give the device a precision that might haveastounded the discoverer of the laws of gravity.
The meters can read to 3 to 5 microgals or less in idealconditions. But on the North Slope background noise lev-els in the readings come in somewhat higher than that.
“In a survey that we’re doing on the slope right nowwe’re getting about plus or minus 10 microgals of noiselevel,” Brady said.
GPSA precision global positioning system receiver deter-
mines the exact position of a gravity meter at an observa-tion station during a gravity measurement. A technicianmakes repeated GPS measurements at a station, to ensurethat the accuracy is within required limits.
“By using differential GPS we can usually get our ele-vation to, hopefully, within about a centimeter,” Brady
said. Measurements exhibiting errors of more than about 2centimeters are rejected, he said.
Accurate elevation measurement is critical because itimpacts the gravity value. A 1-centimeter elevation errorequates to about a 3-microgal gravity error, Bradyexplained.
However, North Slope surface movement caused byheaves in the permafrost and varying ice conditions canplay havoc with precision terrain measurements. The engi-neers working at Prudhoe Bay have addressed this issue byinstalling four permanent GPS stations.
“Everything moves a little bit from time to time,” Bradysaid. “… So when you’re talking about getting somethingthat’s a centimeter, you’ve got to do something a little bitdifferent.”
The fixed GPS stations, with theoretical accuracies ofabout 5 millimeters, record positional information continu-ously. Then, during a survey, triangulation of observationstations back to the fixed stations enables checking of theintegrity of the mobile GPS stations used for the observa-tions.
Baseline and repeat surveysPrior to the start of waterflood, two baseline surveys
provided gravity readings when gas still filled the gas cap.“We actually performed two baseline surveys … which
really worked out well, because by having two baselines itgave us a good idea of what our noise level was,” Bradysaid.
After the start of the waterflood operation, repeat sur-veys, typically carried out each winter, measure changes ingravity as the injected water moves radially though thereservoir from seven central injector wells. The replace-ment of gas by water in the reservoir causes an increase inreservoir density that results in an increase in gravity, orpositive gravity anomaly, at the surface.
“We’re simply taking the difference between a repeatsurvey and the baseline survey, and from that we get thegravity anomaly,” Brady said.
Calculating the densityCalculations performed on the pattern of gravity anom-
alies measured at the surface during the repeat surveysenable the calculation of the pattern of reservoir densities.And that calculated density pattern tells engineers theextent of the waterflood in the reservoir, Brady explained.
A computer simulation enables an assessment of theaccuracy of the method. That simulation shows that thegravity anomalies accurately determine the area of an aver-age amount of water front fill. However, the gravity anom-alies place the leading edge of the waterflood about 2,000feet too far out from the center of the waterflood area.
“So if you want to know where the bulk of that water iswe can nail that pretty tight,” Brady said. “The leadingedge — we’re going to be off a couple of thousand feet ormore, probably on that.”
It is also possible to verify the accuracy of the methodby performing a mass balance on the amount of waterinjected. The 4 billion barrels of water to be injected intothe gas cap during the entire multi-year waterflood projectshould result in an eventual gravity anomaly of about 250microgals. To date, the anomaly is up to 80 or 90 micro-gals, a value consistent with the amount of water injectedso far, Brady said.
“So it’s fitting in really close to close to what we pre-dicted,” he said.
Borehole gravity surveysBrady is also intrigued with the use of borehole gravity
meters for gravity surveys within well bores. A borehole gravity meter, especially in a horizontal
well, could monitor fluid drainage around the well withoutbeing impacted by well liners and other well features. Anda gravity meter also ought to provide greater accuracy thanlogging techniques currently used — the gravity metershould particularly enable the determination of the area ofdrainage into a well.
“When you look at horizontal wells really, to me, itwould revolutionize how we do our surveillance,” Bradysaid.
And Brady thinks that the permanent installation ofborehole gravity meters in wells offers particularly strongpotential for reservoir surveillance, once suitable instru-ments for this type of metering become available. Thereare currently a couple of patents out for permanent bore-hole gravity sensor designs, he said. One of these designsconsists of an absolute gravity meter in which a piezo-elec-tric device flips a crystal in a vacuum chamber, he said.
Other applicationsHowever, success with the surface gravity surveys at
Prudhoe Bay shows that that particular technique couldfind applications elsewhere. The relatively large densitycontrast between water and gas makes the technique workwell with waterflood in gas — waterflood in oil would bemore challenging because of the much lower density con-trast between the two fluids involved.
The depth and thickness of the reservoir are also criticalparameters for success. The Prudhoe reservoir is 100 to500 feet thick, but modeling of the technique suggests thatit could work reliably with reservoirs down to about 50 feetthick — 25 feet would be the absolute minimum thickness.
“It’s certainly not for every field, but there are lots offields out there where it would work,” Brady said. ●
PGravity meters used to monitor the Prudhoe Bay gas capwaterflood on the North Slope
BP
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By GARY PARKFor Petroleum News
t took less than a week for some of theanticipated stickier issues to formallysurface in the Mackenzie Gas Projectregulatory hearings.In the first round that ended in Inuvik
on Feb. 2, there were few surprises, leastof all when the Sierra Legal DefenceFund — representing the World WildlifeFund Canada and the Sierra Club ofCanada —asked whether the KyotoProtocol has been taken into account byImperial Oil when it estimates the futuredemand for natural gas and raised thestandard bogey-man that Arctic gas maymerely be used as feedstock for develop-ing Alberta’s oil sands.
Defence fund spokesman Paul Falvotold National Energy Board hearings thatImperial may have blundered by not con-sidering whether changes to Canada’senergy policy under Kyoto could affectthe long-term viability of the Mackenzieproject.
He said any major energy projectsshould take a serious view of Kyoto if thefederal government imposes limits on theconsumption of fossil fuels which con-tribute to greenhouse gas emissions.
Harper may move away from KyotoThat, however, may be a moot point if
the new government of Prime MinisterStephen Harper delivers on its promise toshift Canada away from its Kyoto com-mitment and seeks a “made-in-Canada”approach to cutting emissions along withan energy policy that ensures maximum
benefits are achieved from technology.One of the nagging questions sur-
rounding the Mackenzie project was alsoaired by Falvo.
Critics have argued that the bulk ofproduction, whether it’s 1.2 billion or 1.8billion cubic feet per day, will be shippeddirectly to the oil sands to support opera-tions by the anchor field owners,Imperial, ConocoPhillips, Shell Canadaand ExxonMobil Canada.
Imperial spokesman Pius Rolheisertold the hearing he has grown weary ofthe claims that there is a direct linkbetween the Mackenzie project and theoil sands.
“It’s simply not true … I don’t knowhow to say it plainer than that,” he said.
Rolheiser insisted the two develop-ments are completely separate and theMackenzie would have proceeded with orwithout the oil sands.
Shipping cost concernsE&P companies outside the main own-
ers group also introduced their concernsabout the cost of shipping gas on thepipeline.
Imperial says all gas producers willhave a chance to access the pipeline, butthey should be ready to make 15- to 20-year commitments — a demand that trou-
bles smaller companies such asParamount Resources, who say theirmedium-sized finds, including an esti-mated 250 billion cubic feet in ColvilleHills, might have only an 8-year lifespan.
Allen Hollingworth, for Paramount,said Imperial’s threshold would force hiscompany to find more gas, or pay more intolls.
A report by GLJ PetroleumConsultants for Imperial laid out the chal-lenge facing the industry if theMackenzie pipeline is to have an ade-quate supply at a price that is profitablefor the next 23 years.
It estimates companies will need todrill at least 124 exploration wells in theMackenzie Delta, 161 in Colville Hillsand 23 in the Beaufort Sea to achieve thatgoal — a drilling level that Falvo worrieswill put protected areas at risk.
The next round of hearings is due tostart by mid-February in Inuvik.
Furor in Northwest Territories legislature
Separately, a furor has surfaced in theNorthwest Territories legislature, wherePremier Joe Handley has been accused ofselling out the territory in a “letter ofcomfort” delivered to the gas producersin November.
Bill Braden, a member of the legisla-ture from Yellowknife, said that in prom-ising the companies his governmentwon’t raise the resource royaltiesHandley failed the Northwest Territories.
He said the letter is one of “extremedisappointment” for legislators, commu-nities and northerners.
Handley suggested that Braden did notseem to grasp that while his governmentwas “looking at making a fair fiscal envi-ronment, we are looking at resource-rev-enue sharing.”
In a budget tabled Feb. 3, FinanceMinister Floyd Roland unveiled cuts inthe corporate tax rate to 11.5 percent from14 percent effective July 1 to build on thesuccess of a diamond industry and theeconomic promise of the Mackenzie proj-ect.
“To encourage businesses and industryto locate and do business here in theNorthwest Territories we have to competeon taxes,” he told the legislature.
“We simply cannot afford to see busi-nesses continue to file their income taxoutside of the NWT in order to avoidhigher tax rates.”
In a special appeal to Harper, Rolandreiterated the NWT’s case to keep moreof its resource revenues. Currently itkeeps only 20 cents of every dollar it gen-erates. ●
A6 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
● C A N A D A
Mackenzie: One week down, one year to goKyoto’s role, using Arctic gas in oil sands and access to pipeline by independent explorers all get aired at Mackenzie gas line hearings
I
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 A7
● A L A S K A
Alaska oil tax: PPT with numbersPedro Van Meurs and Roger Marks give Alaska legislators numeric examples for proposed production profit tax
By KRISTEN NELSONPetroleum News
here isn’t a bill yet — and legislators aren’t surewhen they’ll see one.
But they did get a walkthrough Feb. 1 of what rev-enues from the administration’s proposed profit shar-
ing production tax on oil would look like compared to thepresent system.
Consultant Pedro van Meurs and Department ofRevenue petroleum economist Roger Marks presentedscenarios based on tax and credit rate numbers requestedby legislators to a joint meeting of House and SenateFinance committees. A number of legislators attended,leading Senate Finance Chair Lyda Green, R-Matanuska-Susitna, to quip to House Finances Co-Chair Kevin Meyer,R-Anchorage, that she thought the House had a quorum.
Van Meurs had briefed House andSenate Resources committees on theproposal Jan. 18 (see story in Jan. 22issue of Petroleum News), and legis-lators asked for examples of what thechange in tax would mean at specificrates.
The production profit tax, or PPT,would replace the state’s current pro-duction severance tax with its eco-nomic limit factor.
Alaska Commissioner ofRevenue Bill Corbus, introducingthe Feb. 1 presentation, said thestate’s oil tax system must bereformed. “The current productiontax system with its ELF exclusions isno longer working for Alaska, partic-ularly in an era of high oil prices.”
The proposed profit sharing taxsystem, Corbus said, is based on thestate getting a fair share of profits onoil “based on what the producers arealready paying in similarly situatedoil regimes around the world”; onincentives needed to “induce explo-ration, investment and reinvestmentin Alaska”; and on “what is needed to protect explorersand independents and small operators.”
Van Meurs told legislators that the state’s current sever-ance and ELF worked well to encourage development ofsmaller fields in the economic conditions of the late 1980s,when the system was developed, but said the benchmarksfor the system “are now completely outdated and thereforean overhaul of the production tax is in the interests of thestate.”
Van Meurs listed four “serious deficiencies with theproduction tax,” all related to the ELF, a formula whichproduces a number from zero to one which is then multi-plied by the severance tax to determine the tax rate foreach field. He said the ELF is no longer “rational in rela-tionship to well productivity and field production”; it isn’t
responding to field production decline; it “does not pro-vide for a reasonable balance under a range of oil prices”;and it “does not provide for sufficient incentive to re-invest.”
PPT a consolidated taxThe profit sharing production tax, or PPT as the admin-
istration has dubbed it, would be “a consolidated tax at thecorporate level,” van Meurs said, unlike the present pro-duction tax which is on a field-by-field basis. The PPTwould be based on cash flow: gross revenues,net of royalty, based on wellhead prices (whichexclude transportation costs), less lease expendi-tures.
There will be tax credits to encourage invest-ment, van Meurs said, and a loss in any yearmultiplied by the tax base can be claimed as acredit. “Tax credits can be transferred and trad-ed,” he said, making this an important incentivefor new investors, allowing them to monetizetheir investments immediately.
Sen. Ben Stevens, R-Anchorage, said thenumbers used to run scenarios for the presenta-tion were numbers legislators requested theadministration to use: Tax rates of 25 percent, 20percent and 17.5 percent; and tax credit rates of15 percent and 20 percent.
Van Meurs said he believes the rates are “areasonable range.”
Benefits to small producersVan Meurs had told legislators in January
that the administration was considering taxbreaks for small producers because the adminis-tration wants to “encourage them to invest inAlaska.”
Alternatives suggested in the Feb. 1 presentationincluded: a zero tax rate on the first 5,000 barrels of oilequivalent per day; or a tax-free allowance in the range of$50 million to $100 million a year on “actual profits percompany.”
Van Meurs said the administration was also looking atways to provide a tax credit on heavy oil, perhaps with ahigher tax credit on capital investments in heavy oil. VanMeurs said the administration is still working on a precisedefinition of heavy oil and how a company would qualifycapital expenditures for heavy oil.
He said the administration wants to create incentivesfor investment in Alaska, and believes the new tax system,along with the gas pipeline, will make Alaska “a wholenew core area for investment by a wide variety of compa-nies.”
What the numbers look likeMarks said the PPT starts with the wellhead value of
gas, the market price less transportation costs. The basis of the current tax is also the wellhead value,
sometimes called the netback, he said: the market price
less the royalty, the marine transportation cost and thetrans-Alaska oil pipeline tariff.
The goal of the PPT, he said, “is to actually bring in theupstream costs as well and recognize the full economics ofproduction.”
From the current wellhead value the operating cost,property tax and capital costs would be deducted, and thatamount would be subject to whatever the tax rate is, and toa credit for the capital costs.
The volume of oil in the future was an important issuein modeling the scenarios, Marks said, and thedepartment looked at two significant parameters.The first addresses future oil exploration andsuccess: an enhanced volume scenario, he said,includes “a series of eight analogues to theAlpine field coming on spaced five years apartover the next 45 years.”
The other parameter is whether or not there isa gas pipeline.
Marks said the gas pipeline affects oil vol-umes in three ways: initially a gas line wouldreduce Prudhoe Bay oil production because ofthe decline in pressure, but in the long run itwould increase the life of the field and increasethe total volume of oil recovered.
The assumption in the modeling, he said, “iswithout a gas line Prudhoe Bay shuts down in2030.”
With a gas line Point Thomson is developed. “And also with a gas line we believe there’ll
be a lot of additional exploration for gas and withnew gas fields there will be associated oil.”
Depending on whether or not there areenhanced volumes of oil and whether or not thereis a gas line there are four scenarios.
Marks said the department was presenting thebookends: a low-volume scenario with no gas
line and no enhanced volumes of oil and a high-volumescenario with a gas line and enhanced volumes of oil.
No gas: North Slope shuts down in 2030“We believe it’s not unreasonable to think that without
the enhanced volumes and without a gas line that thewhole North Slope could shut down in 2030,” he said, sothe low-volume scenario only runs to 2030, while thehigh-volume scenario runs to 2050.
Total oil production (from the present to 2030) is 6.5billion barrels in the low-volume scenario and 10.5 billionbarrels (present to 2050) in the high-volume scenario.
The cost and price assumptions used in the scenario arereal 2005 dollars escalating at 2 percent a year. Cost esti-mates include: $100 million a year in exploration; $1 perbarrel on-going capital; $4 per barrel developmental capi-tal on two-thirds of the oil in existing fields; $4 a barreldevelopment capital on new fields; and $4 a barrel operat-ing costs.
Marks presented a series of graphs comparing the sta-
T
The proposed profitsharing tax system,Alaska Commissionerof Revenue BillCorbus said, is basedon the state gettinga fair share of profitson oil “based onwhat the producersare already paying insimilarly situated oilregimes around theworld”; on incen-tives needed to“induce exploration,investment and rein-vestment in Alaska”;and on “what isneeded to protectexplorers and inde-pendents and smalloperators.”
Consultant Pedrovan Meurs told leg-islators that thestate’s current sev-erance and ELFworked well toencourage develop-ment of smallerfields in the eco-nomic conditions ofthe late 1980s,when the systemwas developed, butsaid the benchmarksfor the system “arenow completelyoutdated and there-fore an overhaul ofthe production taxis in the interests ofthe state.”
see NUMBERS page A8
A8 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
tus quo with five combinations of tax and credit rates. For the low-volume case (no gas line, no enhanced vol-
umes of oil), the cumulative PPT taxes (2006-2030) com-pared to the status quo ranged between $3 billion less and$61 billion more, depending on the price of oil (the sce-nario looked at a range from $15 a barrel to $65 a barrel)and the tax and credit rates.
The upper side scenario (with both a gas line andenhanced oil volumes) from 2006-2050, had total revenuesranging from $6 billion less than the status quo to $134 bil-lion more than the status quo.
Cross-over pointMarks said there has been a lot of interest in the cross-
over point: the oil price at which the PPT will bring in lessthan under the status quo. On the low-volume case Markssaid the cross-over looked to be in the low to mid twenties.But, he said, what’s really important is the slope of the line(on the graph) after it crosses the cross-over point.
In a series of graphs of annual revenues at prices of $20,$40 and $60 a barrel, Marks noted that a $20 low-volumecase demonstrates that “at low prices we make lessmoney” with the PPT than with the status quo, from $100million to $180 million less in a year. But at a $40 price, inthe low-volume case, average annual revenues are $400million to $900 million more than with the status quo.
The significance of the cross-over point is evident at$40, Marks said: “The money we would make at $40 inone year is more than the money we would lose at $20 forfour years.”
A $60 per barrel low-volume scenario showed averageannual revenues of $1.1 million to $2 million more thanthe status quo. This, Marks said, is the low-volume sce-nario, without a gas line: “What’s interesting here is thatthese revenues are equivalent to how much money wewould make with a gas line at $5 per million Btu marketprice in Chicago. So in this scenario you’re getting gas linerevenues without a gas line and at prices less than whatthey are today.”
Van Meurs echoed that thought: in the range of tax ratesthat the Legislature requested, the proposed PPT “is not aminor thing: this is equal to the whole gas line, the onlydifference is that it comes in right away rather than havingto wait for the gas line coming on stream.”
What prices will be in the future is unknown, Markssaid, calling the scenario “interesting.”
Gas revenues not includedFor the high-volume scenario (a gas line and enhanced
volumes of oil), Marks said the revenues do not includemoney from a gas severance tax, but the upstream gascosts are deductible for the PPT, “so this includes the gasline costs, but the gas line revenues are not here, but arereceived per our in-kind marketing receipts per the strand-ed gas act.”
Again, at $20 a barrel, the state loses money on the PPTcompared to the status quo, an average of $150 million to$200 million a year less. At $40 a barrel annual revenuesare $600 million to $1.2 billion more than the status quo,and at $60 oil, average annual revenues are $1.5 billion to$2.6 billion more than the status quo.
Even though the tax rates are flat, “this creates a pro-gressive system ... because your upstream costs aredeductible and those costs are a smaller and smaller per-
centage of the value as prices go up,” Marks said. Underthe low-volume scenario the effective tax rate would bebetween 10 and 16 percent, and under the high-volumescenario the effective tax rate is between 12 and 18 per-cent.
And what does the PPT do to the corporate take? If you look at gross volumes over 45 years (the high-
volume scenario with a gas line), and use the Departmentof Energy’s Energy Information Administration’s currentprojection of $58 per barrel oil, the total is about a trilliondollars, Marks said, compounded at 2 percent over 45years.
Corporate take goes from 39 percent of gross revenues,under the status quo, to 33 percent of gross revenues underthe PPT at a 20 percent tax rate and 15 percent credit rate.The state take increases under the PPT, but the federal takedecreases. Marks said the federal government picks up thetab on about a third of the PPT.
How big a hit would the PPT be to the producers over45 years under this scenario? Of the trillion dollars “theywould get 6 percent less and walk away with 33 percent ofa trillion dollars, which is $333 billion. And the questionyou need to ask yourself is, is that painful or not, to walkaway with $333 billion?” And, he noted, the status quo,with the ELF, “is a modest standard of comparison.”
International comparisonVan Meurs told the legislators that high oil prices have
had an important impact on international government take.Countries with progressive regimes have deals “for pro-duction sharing or contracts or taxes whereby it is alreadyagreed beforehand that taxes will go up very significantlywith price or other profitability indicators.” In Russia, hesaid, deals in place vary from the equivalent of a 10 per-cent PPT at low prices to as much as 70 percent.
In countries where tax formulas didn’t account for high-er prices there have been legislative or contractual changesto increase the take, including the United Kingdom,Trinidad & Tobago, Kazakhstan, Bolivia and Venezuela.
In December the United Kingdom indicated it wouldincrease its take from 40 percent to 50 percent, an increaseof 10 percent. The change for Alaska with the PPT wouldonly be a 6 percent increase, he said.
Higher oil prices have created a worldwide trend ofhigher government take, van Meurs said, “either becausethe terms were already negotiated or countries decide thatit is fair to get a better share because of the higher ... oilprices.”
The PPT from an investor’s viewpointVan Meurs said he analyzed the PPT from the perspec-
tive of an investor, looking at a range of field sizes from 50million barrels with low well productivity to 500 millionbarrels with high well productivity, and also looking at firstinvestment and re-investment.
For a 50 million barrel field Alaska collects nothingunder the current system because the ELF would be zero,he said, so the state collects more production tax at highprices with the PPT. At low prices under the PPT, when asmall field would become unprofitable, the tax creditwould help the field: “under very uneconomic conditions,there will be some tax credits and they can be traded withanother oil company.”
For a big field, 500 million barrels, the state would col-lect more production tax under the PPT with both averageand high oil prices.
Those are cases where a large oil company is re-invest-ing.
He said the most interesting case was what he called theCook Inlet case: first investment in a 50 million barrel oilfield with high costs and low well productivities. A smallproducer would not pay PPT because they have anallowance (5,000 barrels per day without tax), “but theystill get the credits.” At 20 percent tax and 15 percent cred-it for capital investment a small operator can lower its cap-ital cost by 35 percent.
“Now if you want to give an incentive to look at CookInlet, this is the way to do it,” van Meurs said.
He said with this kind of a tax structure, “a few smalloil companies would look with new eyes at their smallertargets, maybe smaller targets on the North Slope ... andfirst investors would see a very attractive system to comeinto.”
If a large new player, such as Petrobras, came intoAlaska looking at large new fields, the new investorallowance doesn’t mean very much because even with thatallowance on a large field they pay more in taxes. But, hesaid, with the capital credit, “we have modified the ... ini-tial investment required,” so even with the new PPT, “therate of return actually goes up despite the higher taxes.”
With the tax credit for capital investment, the invest-ment costs a company less and the company can trade itstax credits and its rate of return goes up. The tax creditsimprove the internal rate of return for both new investorsand re-investors, van Meurs said, “and that means thatcompanies who are interested in a strong rate of returnwould find that a very attractive aspect of the PPT.”
Comparison with competitionVan Meurs compared the current Alaska system and the
proposed PPT with eight areas, selected because large oilcompanies active in Alaska are also active there: Norway,the United Kingdom, U.S. Gulf Coast, Alberta oil sands,Nigeria, Angola, Russia-Sakhalin and Azerbaijan.
He rated 48 economic criteria, 1 for the best, 48 for theworst.
The U.S. Gulf of Mexico scored 52 for first investment,Russia-Sakhalin 444 (out of a hypothetical 48 best and 480worst). Alaska’s current system scored 364 and the AlaskaPPT 272. Of the 10, the eight countries and the two Alaskatax systems, an Alaska PPT system was No. 5 out of 10,Alaska’s current system No. 8 out of 10.
Van Meurs concluded that “from a competitivenesspoint of view for a new investor ... on average, Alaskawould look far more competitive, far more attractive, withthe PPT than with the current system.”
Large investors that are already in Alaska wouldn’t getthe 5,000 barrel per day allowance, so Alaska’s PPT does-n’t look as attractive as it does for a new investor, he said.For what van Meurs labeled “next investment,” Alaskawith a PPT system had a rating of 322 and was No. 6, com-pared to Alaska’s current system with a score of 353 and arank of No. 8.
Alaska’s attractiveness for a large re-investor under thePPT “would depend very much on how they weigh rate ofreturn and other profitability criteria relative to the gov-ernment take, what kind of sizes they’re actually lookingat, what kind of costs they’re looking at. In some cases itwould compare, in other cases it may come out somewhatless,” he said.
Van Meurs said he thinks the PPT for a large re-investorin Alaska “is somewhat better” than the current system,“but not dramatically better.”
Any of the cases that were analyzed “look like reason-ably competitive cases” from an international perspective,van Meurs said. ●
continued from page A7
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PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 A9
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FOR
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By SCHEHEREZADE FARAMARZIAssociated Press Writer
urdish officials are inviting foreign oil companiesto explore untapped reserves in their northernregion, angering Arab countrymen and raising con-cern about chaos in Iraq’s oil industry.
Kurds, their self-ruled federation firmly enshrined inIraq’s constitution, believe they are reclaiming their rightto control northern oil fields after successive Iraqiregimes purged Kurds from the industry to bring it underexclusive Arab control.
Despite the Iraqi industry’s many problems — fallingproduction, crumbling infrastructure and relentless insur-gent attacks — the prospect of drilling in the world’s sec-ond-largest proven reserves has led eight small foreigncompanies to invest in Kurdish-ruled territory.
One of them, Det Norske Oljeselskap, or DNO, ofNorway, struck oil in December, less than a month afterstarting to drill in Zakho near the Turkish border.
Major oil companies have so far shied away fromKurdistan until the new Iraqi parliament elected inDecember clarifies articles in the constitution on the con-trol of oil, and until security improves.
The constitution stipulates that the federal and region-al governments will share management of existing oilfields, as well as strategies for developing future areasand distributing the profits.
The document, however, also makes ambiguous refer-ences providing compensation for areas such as theKurdish and Shiite regions that were “damaged” and“unjustly deprived” under Saddam Hussein.
The constitution, ratified in a referendum in October,defers a decision on the future of Kirkuk, the center of thenorthern oil fields, which Kurds want to be part of theKurdish federation.
Each region will control discoveriesBecause each region will control future oil discoveries
in its own area, the Sunni minority, which lives in Iraq’soil-poor center, may not benefit equally from the riches.
However, Western oil officials in northern Iraq say theentire country is floating on unexplored oil reserves,including the central regions.
Iraq is estimated to have 265 billion barrels ofunproven reserves and 125 billion barrels of provenreserves.
Of those, an estimated 36 billion barrels are in north-ern Iraq. Less than 10 percent of the region has beenexplored, according to Heritage Oil, one of the eight for-eign companies carrying out studies in Kurdistan.
Iraq is also estimated to have 100 trillion cubic feet ofnatural gas.
“Saddam regarded the oil in Kurdistan as his personalproperty,” said Delshad Abdul-Rahman Mohammed,head of the Oil Projects in the Kurdish regional govern-ment of Sulaimaniyah.
“Kurdistan’s share of the profits was the moneySaddam received to buy chemical weapons to decimatethe Kurdish people.”
Kurdish officials in both Sulaimaniyah and Irbil insistthat they will share the oil wealth with the rest of thecountry and that agreements made with foreign compa-nies are made in coordination with the central govern-ment in Baghdad.
“This oil belongs to all Iraqis. Profits from the oildon’t only go into the pockets of Kurdistan,” saidMohammed.
He said oil companies signed a memorandum ofunderstanding with the Kurdish regional governmentsand the central government “so that the regional govern-ment will not have any problems in the future.”
In addition to DNO, oil companies exploring inKurdistan include Petoil and General Energy Corp., bothof Turkey; Woodside of Australia; and Canadian compa-nies Western Oilsands Inc. and Heritage Oil Corp., whichhas formed a joint venture with Eagle Group of Iraq,based in northern Iraq.
Western experts predict frictionWestern oil experts predict friction between the
Kurdish regions and the central government on future oilexplorations, but according to Western oil company offi-cials, it’s a risk worth taking.
Iraqi oil experts are not as confident. “Without a central unified policy it is expected that
disharmony and competition ... would be the rule of theday, a situation which is in contrast to that of a unifiedfederated country, and which shall have serious conse-quences for technical reasons,” said oil consultant TariqShafiq in a report.
Iraqi and Western oil experts say Kurds lack technicaland managerial skills needed to go it alone. They say offi-cials in the ministry of natural resources in the newKurdistan regional government are inexperienced in theoil business.
But Kurdish officials are not apologetic and blame theprevious regimes for purging the oil industry of Kurdishtalent and skills, especially in Kirkuk, and replacing themwith mostly Arabs.
“We can buy trained men,” said Mohammed.“Saddam’s ethnic cleansing policy against Kurds drainedthe region of its best qualified men. There are scores ofeducated Kurds who currently work with internationalcompanies and who can help us.”
The region, he added, will also seek the help of IraqiArabs in the field. ●
A10 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
● I R B I L , I R A Q
Kurds invite foreign companies to exploreIraqi constitution says each region will control future oil discoveries; Det Norske Oljeselskap found oil in north in December
K
GULF OF MEXICOTotal focuses U.S. E&P in Gulf of Mexico
Total said Feb. 7 that its wholly owned subsidiary, Total E&P USA Inc., hasagreed to sell two mature fields, Bethany and Maben, in east Texas andMississippi, respectively, to XTO Energy Inc. The transaction is scheduled toclose by the end of February.
Total said it will now focus its exploration and production projects in theUnited States in the offshore Gulf of Mexico.
XTO Energy said the purchase price for the producing properties is $300 mil-lion and said the effective date is Jan. 1.
XTO said its engineers estimate the proved reserves to be 120 billion cubic feetof gas equivalent, 60 percent of which are proved developed and 95 percent ofwhich are attributable to natural gas. XTO said it estimates development costs forthe proved undeveloped reserves at $1.20 to $1.40 per thousand cubic feet, andsaid the acquisitions will initially add production of about 15 million cubic feet ofnatural gas per day.
—PETROLEUM NEWS
January letter to Northwest TerritoriesPremier Joe Handley said theConservative party (now the govern-ment) endorsed the “general principlesand objectives of the socio-economicfund,” although it would still be an issuefor discussion.
But Randy Broiles, Imperial Oil’ssenior vice president in charge of theMackenzie project, said in mid-Januaryhe did not think a change of governmentwould jeopardize the Liberal promises.
“We’re not concerned about the elec-tion,” he said. “We are committed toworking with whichever government isin place.”
Fiscal enhancements a challengeA bigger challenge for the Harper
administration is picking up where theLiberals left off in offering federal fiscalenhancements to improve the Mackenzieeconomics, including assuming some ofthe downside risks provided the govern-ment could “increase its share in thepotential financial rewards.”
Questioned by a lawyer for theMackenzie Explorer Group, in the open-ing round of National Energy Boardhearings, Imperial executive RandyOttenbreit said he did not know whattypes of investment the federal govern-ment might make.
The Liberal government turned downa request for subsidies of C$1.2 billionand Imperial has made it clear it is notopen to a government equity interest.
Ottenbreit said fiscal terms wereexpected to be settled by mid-year,although that target might have to berevised because of the change in govern-ment.
Part of those negotiations mightinvolve Ottawa becoming a significantshipper on the pipeline if the governmentis prepared to accept royalties in kind, hesaid.
Otherwise, Ottenbreit again took upImperial’s message that the Mackenzieeconomics are “thin” and the projectfaces substantial risks if it hopes to com-pete with other gas supplies, includingimported liquefied natural gas.
Getting to grips with the Mackenzie issure to claim a large chunk of Lunn’stime and does not bode well for a quickdecision on the Alaska pipeline.
Kyoto Protocol changes promisedThe initial reaction to the arrival of
Lunn, 48, has been positive.Since his election to the House of
Commons in 1997 he has built a reputa-tion for handling his assignments effi-ciently, openly and cheerfully.
Those characteristics will quickly beput to the test.
Along with Environment MinisterRona Ambrose, he will be thrown anearly nettle.
Prime Minister Stephen Harper, aharsh critic of Canada’s decision to signthe Kyoto Protocol, has promised to setnew made-in-Canada targets for reduc-ing greenhouse gas emissions withoutsaying whether he was withdraw fromthe climate change treaty.
He said during the election campaignthat Kyoto’s targets of a 6 percent cut inemissions from 1990 levels by 2012,when Canadian levels have alreadyclimbed 24 percent since 1990.
Harper said Kyoto will “not succeedat achieving its objectives” and theConservative government will do whatits Liberal predecessor didn’t by consult-ing with the provincial governments onaspects of the international agreement
that touch on provincial jurisdiction.He also said any future international
treaty would have to include the world’slargest polluters — the United States,China and India — all of whom havejoined an Asia-Pacific partnership ofcountries to pursue voluntary emissionreductions.
Lunn Member from Vancouver IslandAs a Member of Parliament from
Vancouver Island, Lunn is also underpressure from his own provincial gov-ernment to end the 35-year moratoriumon offshore exploration.
British Columbia Energy MinisterRichard Neufeld said progress towardslifting the ban was being made in discus-sions with the Liberal government andhe hopes the pace will accelerate underthe Conservatives, even though the otheropposition parties (New DemocraticParty and Bloc Quebecois) are not seenas backers of exploration.
Because the moratorium was not cov-ered by legislation it can be ended by thegovernment not parliament, he said.
In one of his few comments sincebeing appointed, Lunn said theConservatives have an open mind on themoratorium.
He said the government will probablywant updated research data on theimpact of exploration before making upits mind.
Neufeld suggested that before drillingoccurs, the industry will need a chanceto use modern seismic technology toupdate the resource potential of the off-shore.
For now, he said the British Columbiagovernment will work constructivelywith Ottawa, First Nations, coastal com-munities and others who want to beinvolved “in a meaningful way.”
Some in the industry think the mostpressing issue before Lunn and the gov-ernment is the shortage of skilled laborand materials, and the need to fast-trackthe processing of immigrants.
Just one indication of the pressuresthat are inhibiting upstream activitycomes from drilling and service rig con-tracts who say new rig construction ishampered by the demand on raw materi-als, labor and plant capacity which haveadded 12 weeks to delivery times forconventional products and as much asone year for major components, forcingcustomers to place orders for the firstquarter of 2007. ●
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 A11
Calgary, “leveraging the technical capabili-ties we have developed since we com-menced our operations there,” MartinHouston, BG executive vice president andmanaging director, North America,Caribbean and Global LNG, said in thecompany’s Feb. 7 release.
“This agreement builds on our existingNorth American E&P business in Canadaand creates the potential for increasingBG’s natural gas supply position into theU.S. gas market, which is underpinned byour LNG importation business,” Houstonsaid.
BG has already made its mark in north-ern and western Canada, spending morethan C$100 million on exploration there in2005, and planning a more ambitious pro-gram in 2006, along with establishing afoothold in the Northwest Territories.
According to the Oct. 16 report inPetroleum News, the company sent outstrong signals of its northern intentions inearly 2005 when it took a 75 percent sharein a C$16.5 million purchase of 275,000
acres of exploration rights on two leases inthe Colville Hills area of the MackenzieValley, with International FrontierResources as a 25 percent partner.
BG is hoping the Mackenzie GasProject will proceed and aboriginal regionswill become more confident in their deal-ings with the industry, allowing moreexploration land to become available.
McNamara former Exxon execMcNamara, former president of
ExxonMobil’s operations in WesternCanada, including the Mackenzie Deltaassets, told the Financial Post in 2005 thatBG is in North America for the long hauland wants to be a material player in thecontinental market.
The company also has oil and gas prop-erties in British Columbia and Alberta.
BG Group is a publicly listed companyon the London and New York StockExchanges and has operations in 20 coun-tries.
The company has four key business sec-tors — exploration and production, lique-fied natural gas, transmission and distribu-tion, and power generation — with most of
its profits coming from the E&P sector,David Keane, vice president of policy andcorporate affairs in Houston for BG NorthAmerica, told Petroleum News Feb. 7.
Open to other Alaska investmentsWhen asked if BG was looking for more
oil and gas properties in Alaska, Keanesaid, “We’re always looking at opportuni-ties to expand our reserve base; as long asit made economic sense and was do-ablewe would probably welcome other oppor-tunities in Alaska.”
In respect to offshore properties, he said,BG has “a lot of offshore operations aroundthe world. … As for Alaska offshore, wewouldn’t rule anything out. … Right nowwe’re real excited about working with ournew partners in Alaska.”
Drilling in Foothills possible soonMark Hanley, Anadarko’s spokesman in
Alaska, is also upbeat about the Foothillspartnership.
“It can only be seen as a positive — forthe state of Alaska, for our partners and forus,” he told Petroleum News Feb. 7.
“Frontier exploration tends to be riskier
and we’ve always said we preferred havinga third partner for the Foothills acreage,” hesaid, referring to two partners that havewalked away from the Foothills consortiumin past years for reasons not connected to it.
“So we’re back to where we wanted tobe all along with three good companies inthe partnership. Each brings a little some-thing to the table, but our motivations areall in the same place and we’re technicallyaligned, so I think this is a good partner-ship,” Hanley said.
The inclusion of BG in the Foothillsacreage, he said, could mean Anadarko will“consider some exploration drilling in theFoothills in the near feature. …”
“It was hard to move forward beforeeven if we wanted to until we had (a three-way) partnership worked out … but we’regoing to talk to our partners because we’dlike to drill in the near future — at leastlook at that as a possibility.”
But how much drilling will, in part, bedependent on whether or not Anadarko andits partners can get fair access to the pro-posed gas pipeline from the North Slope,Hanley said.
—KAY CASHMAN
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BG GROUP
the agency “to understand better the envi-ronmental impact that drilling would havein this area. There would be a draft EIS,”she said, and that would “teach us a little bitmore about the area.” She said there wouldbe more comments from people who live inthe area and “all of the pieces of informationare going to help us formulate a betterunderstanding of this area.” Burton said sheknows that the governor of Alaska “is verymuch interested in learning more and so arethe local governments.”
She noted that Congress lifted its mora-torium three years ago, although the area isstill under presidential withdrawal.
If the information gathered on the arealeads MMS, and the governor, “to say thatmaybe this is a good area to lease, then thepresident will have to take a look at it anddecide if he wants to modify his withdraw-al,” Burton said.
U.S. Sen. Lisa Murkowski said in a Feb.8 statement that the decision by MMS willallow additional time to study whether leas-ing can safely be done in the NorthAleutian area in the future; she called theMMS decision “the continuation of a verythoughtful and reasonable process.”
Cook Inlet a special interest areaWhile multiple sales are proposed for
the Beaufort Sea (2009 and 2011) and
Chukchi Sea (2007, 2010 and 2012), theCook Inlet planning area is included on theschedule as a special interest sale area.Before MMS proceeds with 2009 and 2011sales, it will issue a request for nominationsand comments and will move forward withthe sales only after consideration of thecomments. If comments do not support asale, the sale will be postponed and arequest for nominations and commentsissued in the following year, a processwhich would proceed throughout the five-year schedule until a sale is held or theschedule expires.
There were no bids in the most recentMMS Cook Inlet sale in 2004. MMS saidthe governor and the Kenai PeninsulaBorough supported the current approach,
while Cook Inlet Keeper and a consortiumof 28 environmental groups believe furthersales should not occur due to lack of indus-try interest. Three oil and gas companiesexpressed interest in the area.
The 2007 Chukchi Sea is continuedfrom the previous five-year schedule,MMS said, due to the time needed to com-plete the necessary pre-lease steps andenvironmental documentation.
While the governor supported ChukchiSea leasing, he told MMS it should onlyoccur with adequate local stakeholder con-sultation, planning and environmentalanalysis. Nine companies expressed inter-est in the area; the same number expressedinterest in the Beaufort Sea OCS area. Thegovernor supports inclusion of the Beaufort
Sea and asks companies to work with localcommunities.
The North Slope Borough believes oiland gas leasing should be focused onshore,and questions why both the Beaufort andChukchi Seas are not off limits to drillinglike so much of the Lower 48. TheNorthwest Arctic Borough and the NativeVillage of Point Hope also oppose leasing,along with environmental groups.
North Aleutian basinThe Aleutians East and Lake and
Peninsula boroughs, the City of Wasilla andthe Becharof Corp. supported inclusion ofthe North Aleutian planning area. TheBristol Bay Borough and Choggiung Ltd.opposed inclusion. The U.S. Fish andWildlife Service recommended retention ofthe moratoria and 41 environmental organ-izations opposed lifting the presidentialwithdrawal, MMS said. Of some 40 com-menters recommending expanded access tothe Alaska OCS, 18 specifically mentionedthe area.
MMS said 11 oil and gas companiesexpressed interest in the North Aleutianbasin, making it the second most men-tioned area nationwide after the EasternGulf of Mexico.
The area is under presidential withdraw-al through 2012, and was under annual con-gressional restrictions from fiscal year1990 through fiscal year 2003. MMS saidthere has been no exploratory activity in thearea and there are no existing leases.
Two North Aleutian basin sales, in 2010and 2012, are on a potential lease saleschedule for areas subject to restrictions. ●
A12 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
Both the royalty modification and the Corpspermit were received Feb. 1 making it pos-sible for the Dallas-based independent toimmediately begin operations to install anoffshore gravel drilling and production site.
Pioneer said in a Feb. 6 press release thatit plans to complete gravel hauling activitiesin the 2006 winter construction season.
Pioneer has a 70 percent working inter-est in the field. Houston-based EniPetroleum Exploration, an affiliate of Italy’sEni SpA, has a 30 percent working interest.Pioneer said Eni is expected to make its par-ticipation election for the project during thefirst quarter of 2006.
Pursuant to a January 2004 farmoutagreement, ConocoPhillips retains the rightto elect to participate in the project, Pioneersaid. (ConocoPhillips, Pioneer andConocoPhillips are partners elsewhere onthe North Slope, including in the NationalPetroleum Reserve-Alaska.)
Flowline, facilities in ‘07A subsea flowline and facilities will be
installed during 2007 to carry produced liq-uids to existing onshore processing facilitiesat the Kuparuk River unit. Some 40 hori-zontal wells will be drilled to develop 50million to 90 million barrels of estimatedgross oil resources, the company said in itspress release. According to past reportsOooguruk is expected to hold some 70 mil-lion barrels of recoverable oil and produce15,000 to 20,000 barrels per day.
In its Feb. 6 release Pioneer said drillingcould begin as early as fall 2007. In JanuaryPioneer Natural Resources Chairman andCEO Scott Sheffield said first oil could beproduced as soon as 2008.
Total gross capital investment for theproject, including drilling and facility costs,is estimated at $450 million to $525 million.
Production is expected to peak in 2010. “Using current oil prices, the field is
expected to produce for at least 25 yearsbefore reaching its economic limit,” Pioneersaid.
First of many projects“The Oooguruk field development is the
first of what I believe will be many suc-cessful projects for Pioneer in Alaska andadds a new long-lived asset to our strongU.S. base,” Scott Sheffield said in the Feb.6 release.
Ken Sheffield, president of Pioneer’sAlaska subsidiary, said the company appre-ciated “the cooperative spirit demonstratedby the State of Alaska, the North SlopeBorough and the federal regulatory agen-cies in working with Pioneer” on its planand allowing it to maintain its projectschedule.
The Corps permit includes a list ofapproved maintenance work on the island,as well as six general conditions and 18special conditions, including directivesregarding abandonment of the site onceproduction has ceased, the terms and con-ditions listed in U.S. Fish and Wildlife’sJanuary biological opinion, Mine Site Erehabilitation and navigation-relatedrequirements.●
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Pac Com set for Feb. 22 & 23
The 11th annual Pacific Rim Construction, Oil and Mining Expositionand Conference will be held Feb. 22 and 23 in Anchorage at the SullivanArena. The Pac Com magazine will be in the Feb. 19 issue of PetroleumNews. Go to www.sourdough.net to see the speaker list and register.
PETROLEUM NEWSVolume 11, No. 7
WEEK OFFebruary 12, 2006www.PetroleumNews.com ● A weekly oil & gas newspaper based in Anchorage, Alaska
Jostling among giantsTransCanada, Enbridge keep raising stakes to win support for pipelines to U.S.
By GARY PARKFor Petroleum News
tussle between two ofNorth America’s largestcarriers of oil and gas towin over shippers for
their oil sands pipelines proj-ects has all the marks of aheavyweight showdown.
Just two days afterTransCanada achieved a coupof sorts by announcing it has enough long-term con-tracts in hand to proceed with its US$2.1 billion,340,000 barrel per day Keystone pipeline fromHardisty, Alberta, to Patoka, Ill., Enbridge was seiz-ing the spotlight by announcing plans for Alberta
Clipper — a new proposal toship 400,000 bpd fromHardisty to Superior, Wis.
Enbridge Chief ExecutiveOfficer Pat Daniel was atpains to tell analysts that thenew pipeline “is not in com-petition with anything” andjust as quick to note that it isan “important next phase ofour expansion that will be
very difficult to beat.”“We don’t see there being any alternative threat or
competition,” he said.Enbridge spokesman Jim Rennie told Petroleum
News that Alberta Clipper and Keystone are not in a
ATrans-Canada CEOHal Kvisle
Enbridge CEO Pat Daniel
see GIANTS page B8
Gas tax proposal movingCroft says bill incentive to develop gas; Conoco says it’s bad public policy
By KRISTEN NELSONPetroleum News
hen the House SpecialCommittee on Waysand Means moved a gasreserves tax out of com-
mittee Feb. 3, Republicanmembers said they were notmoving the bill because theyagreed with it, but because it isthe subject of a ballot initiativeand they wanted the bill to havepublic debate, something it ismore likely to get in the Legislature than as an itemon the general ballot.
The bill was introduced in March and heard andheld in Ways and Means in April; the committee
heard the bill again at a series ofmeetings in January.
Rep. Eric Croft, D-Anchorage, sponsor of HouseBill 223, began a signature drivein August to get a gas reservestax initiative on the Novembergeneral ballot, and said inJanuary that more than 40,000signatures had been gathered.The lieutenant governor’s officehas not yet certified the initia-tive.
Croft was the main proponent of the bill before thecommittee; ConocoPhillips Alaska offered the onlyopposition.
The bill goes next to House Oil and Gas, and
W
see GAS TAX page B9
IEA: No downturn in oil demandThe head of the International Energy Agency said Feb. 6 that
he expected no downturn in world demand for OPEC’s crude oilin the historically weaker April-June period, despite forecastssuggesting otherwise.
IEA Executive Director Claude Mandil said at a conference inLondon that he expected “no decline in demand for OPEC crudein the second quarter.”
The Organization of Petroleum Exporting Countries has saidthat the world’s implied need for its crude in the second quarteris 2.4 million barrels a day below the estimated 30 million bar-rels a day that was needed — and is currently produced — in thefirst three months of this year.
OPEC said in its report earlier in January that outright worldoil demand will fall more than 2 percent, or 1.9 million barrels aday, in the second quarter to 83.57 million barrels a day, com-pared with the first three months of the year.
Mandil also said that the oil industry faced oil capacity con-straints for some time ahead and this made it “puzzling to seehow investment has been lagging for years,” though “politicalrisks don’t seem to be diminishing.”
—THE ASSOCIATED PRESS
White House says ANWRlease revenue could triple
By ROSE RAGSDALEFor Petroleum News
rilling for oil on the coastal plain of theArctic National Wildlife Refuge figuresprominently in the Bush administration’s fis-cal 2007 budget proposal, thanks to lease
sale revenue estimates that triple the $2.4 billionprojected a year ago.
The U.S. Department of the Interior said Feb. 6it expects to collect more than $7 billion from leas-ing tracts in the barren, but potentially oil-rich,1002 Area of ANWR based on revised calculationsfrom the Energy Information Administration andthe Congressional Budget Office.
The $7 billion figure, to be split 50-50 withAlaska under terms of the current budget proposal,is drawn from a recent Congressional BudgetOffice report on the long-term projected price ofoil exceeding $50 per barrel in 2010. Interior pre-viously estimated the first sale would attract $2.4billion in bids, based on $25 per barrel oil.
If Congress approves oil drilling in ANWR thisyear, the first sale would occur in 2008. A secondsale in 2010 could generate nearly another $1 bil-lion, according to Interior.
“The issue of ANWR is one that continues,”Interior Secretary Gale Norton told reporters in
D
see ANWR page B10
State of Alaska sets North Slope,Beaufort Sea lease sales for fall
The Alaska Department of Natural Resources Division of Oiland Gas has tentatively scheduled North Slope Areawide 2006Aand Beaufort Sea Areawide 2006A lease sales for October, andhas issued a call for new information.
This returns the sales to their original schedule. What wouldhave been the North Slope and Beaufort Sea 2005 areawide sales,now North Slope Areawide 2006 and Beaufort Sea Areawide2006, will be held March 1. They were delayed to allow the divi-sion to focus on the first Alaska Peninsula Areawide sale whichwas held in October.
Any new information for these areas for the October sales isdue April 12. For additional information see the division’s Website at www.dog.dnr.state.ak.us.
—KRISTEN NELSON
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Rep. Eric Croft
GasReservesTax Primer
By ALAN BAILEYPetroleum News
t 8:34 a.m. on Feb. 3 three tugseased the 575-foot, double-hulledtanker Seabulk Pride off mud flatsnext to the shore about half a mile
north of the Nikiski Kenai Pipeline Dockon Alaska’s Kenai Peninsula. The opera-tion ended a tense period that started at5:25 a.m. on Feb. 2, when a wind andtide-driven ice floe plucked vessel awayfrom the dock, snapping all 16 mooringlines. The tanker grounded on the mudbefore the crew and pilots on board hadtime to react to the situation.
“When the ice builds up, you get over-flow and overlap,” Petty Officer SteveHarrison of the Coast Guard’s commandcenter in Juneau said. “It will strain theropes when the tide comes in.”
Extreme ice rulesAt the time of the accident the Seabulk
Pride, under charter to Tesoro Alaska Co.from Seabulk Tankers Inc., was loading atthe dock and had onboard more than116,225 barrels of vacuum tower bottomblend and other petroleum products, lessthan half of the tanker’s 342,000-barrelcapacity. Small amounts of the vacuumblend and some gasoline were spilled onthe deck and into the sea when the vesselparted from the dock.
Capt. Mark Devries of the U.S. CoastGuard said that the Coast Guard extremeice rules in the Cook Inlet were in effect.Under those rules the Coast Guard canclose a port or stop cargo-loading opera-
tions, although the pilot and the ship’scaptain are responsible for making anyimmediate decisions in response to wors-ening ice. An inspection on the evening ofFeb. 1 had found the Nikiski port clear ofice.
An incident management team, headedby Tesoro Alaska, the U.S. Coast Guard
and the Alaska Department ofEnvironmental Conservation, respondedpromptly to the grounding by dispatchingtwo tugs from Anchorage; a tug andresponse barge from Seldovia; and twotugs and another response barge fromValdez. The team also prepared for ligh-tering of the tanker’s cargo into barges orburning any spilled cargo, should theneed for either of those contingenciesarise.
An initial attempt at refloating thetanker during the high tide immediatelyfollowing grounding, with the assistanceof a Nikiski-based response vessel, didnot succeed.
Three tugs arrivedThe three tugs from Anchorage and
Seldovia arrived at the incident site by theafternoon of Feb. 2. Removal of ballastwater from the tanker commenced, tolighten the vessel. A planned attempt torefloat the tanker at high tide on theevening of Feb. 2 turned out not to bepossible, because of ice conditions andother factors. Instead, the tugs moved intoaction during the next high tide at about 8a.m. the following morning. Support ves-sels stood ready to skim and store any oilthat might spill.
That refloat attempt succeeded and,once afloat, the Seabulk Pride was able tomake way under its own power. Therewere no indications of any form of oilspill.
“There is no sign the ship is leaking atall,” Kip Knudson, a spokesman forTesoro Alaska, said.
Escorted by tugs and other vessels, thetanker sailed down Cook Inlet to the shel-tered waters of Kachemak Bay, wheredivers could make a thorough inspectionfor any damage caused by the grounding.The incident response team also arrangedfor the tug and response barge fromValdez to make for Kachemak Bay, tosupport operations there.
Two small cracksDuring the weekend of Feb. 4 divers
found dents and two small cracks in thetanker’s outer hull.
“This is a good-news story,” saidStewart Wade, communications vicepresident for the American Bureau ofShipping, which had a marine surveyor inHomer for the damage assessment. Wadetold the Anchorage Daily News suchcracks might have produced a slight“weeping” spill on a single-hulled ship.Temporary repairs to the tanker werecompleted on Feb. 8 and the tankershould leave Kachemak Bay by the endof the week, Knudson told PetroleumNews.
Petty Officer Sara Francis of the U.S.Coast Guard told Petroleum News thatthe Coast Guard expected to issue a per-mit on the evening of Feb. 8 for the tankerto transit south. Cracks in the hull hadbeen plugged from the inside with con-crete, she said. The tanker will deliver itscargo at Tesoro’s Puget Sound refinery,before going into dry dock for permanentrepairs.
Dock reopenedThe Nikiski Kenai pipeline dock
reopened on Feb. 7, following completionof repairs to the dock, Lynda Giguere ofthe Alaska Department of EnvironmentalConservation told Petroleum News. TheCoast Guard had already reopened theother docks at Nikiski on a ship-by-shipbasis.
The Coast Guard is investigatingwhether the winter ice rules were fol-lowed during the loading of the SeabulkPride, although Devries said on Feb. 3that there was no immediate evidence ofhuman negligence or misconduct.
“Obviously they were caught by sur-prise,” he said. “Some force operated onthis vessel that they were not prepared toreact to in time.”
And Francis said that the Coast Guardis clarifying some points in the extremeice rules, as a result of lessons learnedfrom this incident. ●
B2 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
● C O O K I N L E T
Grounder tanker eased off inlet mud flatsInspection by divers finds minor damage to outer hull of double-hulled tanker after successful refloating operation at high tide
The tanker will deliver its cargoat Tesoro’s Puget Sound refinery,
before going into dry dock forpermanent repairs.
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The tanker grounded on the mud before the crew and pilots on board had time to react to the situation.
By JULIE WATSONAssociated Press Writer
meeting between U.S. energy execu-tives and Cuban government oil offi-cials was forced out of a U.S.-ownedhotel in Mexico City under pressure
from Washington, organizers said, the latestsign that U.S. President George W. Bush’sadministration is tightening policy againstCuba.
The meeting resumed Feb. 4 at theMexican-owned Colon Mission ReformaHotel, where about 50 participants discussedthe merits of lifting restrictions under thelong-standing U.S. trade embargo designedto undermine Fidel Castro’s government.
Kirby Jones, the event’s organizer andpresident of the U.S.-Cuba TradeAssociation, said the U.S. governmentcalled Starwood Hotels & ResortsWorldwide Inc., which owns the SheratonHotel where the meeting began, and pres-sured the chain to ask the Cubans to leave,arguing that it was violating U.S. law. Hotelofficials in Mexico City refused to com-ment.
Judith Bryan, a spokeswoman for theU.S. Embassy in Mexico City, did not con-firm that the U.S. government pressuredStarwood, but she said that “U.S. law pro-hibits U.S. persons and entities from provid-ing services to Cuban national persons orentities, and the Sheraton, as a subsidiary ofa U.S company, is bound by U.S. law.”
Jones argued that the interpretation of thelaw was too broad.
“If you take this to its logical extreme, noCuban can stay at any American hotel in theworld and no Cuban can buy a McDonald’shamburger anywhere,” he said.
Jorge Martinez, a lawmaker on theForeign Relations Committee of lowerhouse of Congress said the Mexican govern-ment should punish the hotel company overthe incident.
“This is a violation of basic civil rights,”said Martinez, who is a member of the left-ist Democratic Revolution Party. “This wasa trade issue outside of North American ter-ritory.”
In 1996, Mexico’s Congress enacted alaw forbidding companies here to complywith provisions of the Helms-Burton act thattightened the U.S. economic embargoagainst Cuba.
The office of President Vicente Foxdeclined to comment.
First private-sector oil summitCuba and the United States have been
without full diplomatic relations for 45years, and the U.S. government in recentyears has steadily tightened trade and travelsanctions.
The three-day meeting, which beganFeb. 2, was the first private-sector oil sum-mit between the two countries. Participantsincluded Valero Energy Corp., the UnitedStates’ biggest oil refiner, as well as theLouisiana Department of EconomicDevelopment and the Texas Port of CorpusChristi.
Over the past two years, the island hasinked exploration deals with Canadian,Chinese, Indian and Norwegian firms, hop-ing to expand its current production of oil,mostly along its northern coast.
But U.S. corporations, their hands tied bythe embargo, have been forced to watch theflurry of activity taking place less than 60miles off the coast of Florida.
On Feb. 4, as the meeting resumed, JayBrickman, of Crowley Maritime Services,said he has sent some 200 shipments of agri-cultural products to Cuba since the U.S.began allowing limited agricultural trade in2000.
“There’s no question in my mind,” hesaid. “Cuba is a market worth the effort, andit is one we should be committed to.”
Raul Perez, who led the 16-memberCuban delegation sent to the meeting, saidthe Cuban officials were asked to leave theSheraton without a refund.
“We haven’t done anything to violateU.S. laws,” he said.
Alberto Lopez, an official with Cuba’s oilmonopoly, said he and others were given anhour to pack and leave late Feb. 3.
“We didn’t resist,” he said. “It affects ourdignity because it is discriminatory. But weare used to this deplorable attitude.”
Philip Peters, of The Lexington Institute,an Arlington, Virginia,-based think tank,called the incident “petty and surprising.”
It’s “an attempt to regulate speech andprevent people from talking to each otherand exchanging information and even dis-agreements,” he said. “We’ve got commu-nist officials and capitalists here. This is nota love fest.” ●
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 B3
● M E X I C O C I T Y
Cuban officials, U.S.energy execs meetU.S. government forces meeting out of U.S.-owned hotel inMexico; 50 participants discussed lifting trade restrictions
ALASKANorth Slope production down marginally
Alaska North Slope crude oil production averaged 857,271 barrels per day inJanuary, down marginally (0.3 percent) from a December average of 859,838 bpd.
BP Exploration (Alaska)’s Northstar field had the largest month-to-month pro-duction drop, down 10 percent. The field’s production averaged 49,462 bpd inJanuary compared to 54,990 bpd in December. The Alaska Department ofRevenue said an engine was replaced in a gas compressor at the field, slowingproduction Jan. 17-27. The field averaged more than 55,000 bpd most days dur-ing the first half of the month. During the second half of the month the field neverbroke the 50,000-bpd mark, and production fell as low as 40,575 bpd Jan. 27.
Production at BP’s Milne Point field, which includes Schrader Bluff produc-tion, averaged 42,165 bpd in January, down 5.6 percent from a December averageof 44,659 bpd.
The BP-operated Endicott field averaged 20,726 bpd in January, down 1.6 per-cent from a December average of 21,072. Endicott production includes Sag River,Eider and Badami.
The ConocoPhillips Alaska-operated Alpine field averaged 127,880 bpd inJanuary, down 1.6 percent from a December average of 129,910. Revenue saidAlpine production slowed Jan. 3-4 for minor pipeline repairs. Production from thefield averaged more than 130,000 bpd Jan. 1-2, dropped to 112,818 barrels Jan. 3,101,179 barrels Jan. 4 and 119,039 barrels Jan. 5 before climbing back up into the130,000-bpd range Jan. 6.
Lisburne production up 3.2%Production from the BP-operated Lisburne field averaged 40,124 bpd in January,
up 3.2 percent from a December average of 38,894 bpd. Lisburne includes PointMcIntyre and Niakuk.
Production from BP-operated Prudhoe Bay averaged 406,578 bpd in January, up1.4 percent from a December average of 400,965 bpd. Prudhoe Bay productionincludes the western Prudhoe satellites: Midnight Sun, Aurora, Polaris, Borealis andOrion.
ConocoPhillips Alaska-operated Kuparuk averaged 170,336 bpd in January, up0.6 percent from 169,348 bpd in December. Kuparuk production includes West Sak,Tabasco, Tarn, Meltwater and Palm.
The average January temperature at Pump Station 1 on the North Slope averagedminus 12.3 degrees Fahrenheit in January, compared to a three-year average ofminus 8.1 degrees F and a December temperature averaging minus 2.5 degrees F.
Production in Cook Inlet averaged 17,816 bpd in January, down 5.7 percent froma December average of 18,893 bpd.
—KRISTEN NELSON
A
By GARY PARKFor Petroleum News
etting formal global recognition forits oil sands reserves was one thing,but that was little more than a nicewarm feeling all over for the Alberta
government.What has happened in the last year gives
weight to decisions by the U.S. EnergyInformation Administration and theInternational Monetary Fund to include 175billion barrels of oil sands resource in theglobal oil supply.
More important is the growing beliefthat crude prices are unlikely to fall belowUS$60 in the foreseeable future and couldspike this year at US$90, due to combinedglobal unrest and the challenge by PresidentGeorge W. Bush for the United States tosharply reduce its imports from unstablenations in the Middle East.
On the same night that Bush deliveredhis State of the Union speech, former U.S.energy secretary Spencer Abraham said theU.S. recognizes that the oil sands will like-ly be the largest source of incremental sup-ply growth over the coming years.
He said in Calgary the oil sands are an“incredible success story … you are to beadmired for the incredible success that’staken place here.”
Avery Shenfeld, senior economist withCIBC World Markets, said Alberta willeventually represent the largest contributorto global supply growth, supplanting Russiaand Saudi Arabia. Doubts over the com-mercial viability of oil sands extraction andprocessing have dispersed in this new oilenvironment to the point where the EIA
now estimates U.S. oil imports fromCanada will climb over the next 20 years to2.7 million bpd from 1.6 million bpd,according to data obtained by Reuters newsagency.
By far the bulk of that increase willcome from the oil sands, which are expect-ed to yield 3 million bpd within 15 to 20years, triple current output.
U.S. won’t have exclusive accessBut any thoughts that the U.S. will have
exclusive access to those volumes are fastbeing eroded by the interest China, Japanand India are showing in northern Alberta.
India indicated earlier in February that itmay be on the verge of investing C$1.5 bil-lion-$4 billion to buy leases, form partner-ships or take over a production company —a bolder program than the meek entry lastyear by China into the oil sands sector.
M.S. Srinivasan, secretary for India’sMinistry of Petroleum & Natural Gas, toldreporters his country’s state-owned oil com-panies are taking a close look at acquiring astake in the burgeoning oil sands this year.
“The whole world is turning to Alberta,”he told an energy conference in Calgary.“Most countries are (looking for oil sandsinvestment opportunities), including India.”
He told the Financial Post that one of thefour largest Indian companies — ONGCVidesh, Indian Oil, Oil India and HindustanPetroleum — “could invest $1 billion, or itcould be two together. It’s a distinct possi-bility that if all four say they want in thesum could go to $4 billion.”
For India, the crucial need is to ensurethat energy supplies do not impede its GDPgrowth, currently about 7 percent a year.
“We aren’t moving in small measures,”Srinivasan said. “Ideally we would like tohave a partner, but if we can’t find one,we’ll keep all options open.”
As well as attending the conference, theIndian delegation — including ManiShankar Aiyar, who was replaced as oil andgas minister in a Jan. 29 cabinet shuffle —met with Alberta Premier Ralph Klein aswell as production and pipeline companies.
Alberta Energy Minister Greg Melchinwelcomed the prospect of an investmentfrom India provided it joins efforts to studyoptions for processing heavy crude.
“As long as it doesn’t detract from theAlberta and Canadian objective, then thatcertainly could be satisfactory,” he said.
Melchin said he expects Alberta to
become the world’s largest oil producer atsome time this century.
Whatever else, the promised entry ofIndia could provoke China and Japan tostep up their involvement.
For all the advance hoopla, China barelyscuffed the surface last year when Sinopecbought 40 percent of Synenco Energy’sNorthern Lights project and CNOOCacquired 16.69 percent of the shares in start-up MEG Energy.
Engaging in competition with Chinadoes not trouble Srinivasan, who said a raceby the two Asian economic powers for newoil supplies is “unavoidable”: and wouldnot be unhealthy.
However, not everyone is persuaded thatIndia is ready to acquire an oil sands stake.
Tom Collins, vice president ofPricewaterhouseCoopers, said India’s strat-egy seems to favor “direct government-to-government negotiations,” rather than oper-ating through independent or internationaloil companies.
Japan has sent delegationJapan has been a minor player for 30
years through a project that now produces8,000-9,000 bpd, but it sent a major delega-tion to Alberta in January to explore theprospects of becoming a customer.
Japanese government officials werejoined by executives from Japan’s two lead-ing refiners — Nippon Oil and Cosmo Oil— along with executives from Mitsubishi,Mitsui and Idemitsu Kosan in meeting withenergy and pipeline firms.
“A lot of companies are interested ininvesting,” said a spokesman at Japan’sconsulate in Calgary.
Trade Minister Toshihiro Nikai toldreporters that Japan, which imports 90 per-cent of its oil from the Middle East, is eagerto diversify those sources.
Its first opportunity could come fromEnbridge’s Gateway pipeline, which has setan economic threshold of 400,000 bpd ofshipper commitments, of which half wouldbe earmarked for PetroChina, up to 100,000bpd to California with the rest available tobuyers in China, Japan or South Korea.
With France’s Total also setting an ambi-tious path in the oil sands, the U.S. facesstern competition for supplies.
The major U.S. commercial interests arecurrently dominated by Imperial Oil,Devon Energy and ConocoPhillips, all con-trolled by U.S.-based parent companies. ●
B4 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
● A L B E R T A
Oil sands competition stiffensIndia latest to join line-up at Alberta’s door; could do land deal, partnership or takeover this year
GCupboard is sparse, but big deals predicted
Even if India and China go shopping in a big way for oil sands assets they may findthe shelves have been emptied of the best buys.
The surface-mining leases holding the richest, most accessible raw bitumen aremostly in the hands of leading producers who are not eager to take on partners and theadjacent thermal properties that require the use of steam-injection and other technolo-gies to free deeply-buried deposits could require investment of C$1 billion for a projectcapable of producing 50,000 barrels per day.
That leaves takeovers of such junior companies as Synenco Energy and MEGEnergy — both of which already have Chinese partners — as the best options.
But Jeff Rubin, chief economist at CIBC World Markets, expects that there will bea scramble in coming years for assets.
In a new report, he said the oil sands will become the largest single contributor to netnew global energy supply by 2010.
Rubin’s report said that the “combination of depleting reserves and sweeping stateownership has left each of the world’s six largest publicly traded oil firms looking atdeclining production over the next two years.”
“That sets the stage for a mad scramble for whatever proven reserves the market stillhas access to. And there are no greater reserves accessible to private investment than theCanadian oil sands.”
While conceding the resource poses costly development challenges he expectsmultinational firms will “make very aggressive acquisitions … in the next three or fouryears.”
—GARY PARK
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 B5
ARCTICRevealing the history of the Arctic Ocean
Even taking into account concepts of global warming, it’s difficult to envisagea time when the climate was warm enough for dinosaurs to roam the Earth’snorthern latitudes. And, although we know that dramatic climate changes haveoccurred in the Arctic since the dinosaur age, much of thedetailed evidence of the history of the Arctic lies hidden inrocks beneath the Arctic Ocean.
Bernard Coakley, associate professor of geophysics at theUniversity of Alaska Fairbanks, will speak at the Pac Comconference on Feb. 22 in Anchorage on the results of geo-logical and geophysical research in the Arctic Ocean.Coakley has spent much of the past 12 years researching thegeology of the various ridges, plateaus and sub-basins that liebeneath the ocean.
Submarine and ice breakerCoakley led the geophysics program of SCICEX, a series
of unclassified cruises to the Arctic on U.S. submarines.And in the late summer of 2005 Coakley was co-chief in
a research cruise across the Arctic Ocean by the U.S. CoastGuard icebreaker Healy. That cruise collected about 2,200kilometers of multi-channel reflection data that reveal thestratigraphic record of the ocean — the cruise crossed all ofthe major ocean basins and ridges. The seismic surveys usedtwo 250 cubic inch airguns, a 200 to 300-meter streamer and nearly 100 sonobuoydeployments. At one point a Swedish icebreaker helped with surveying in rela-tively heavy pack ice.
Plate boundariesIdentifying boundaries between the Earth’s tectonic plates under the Arctic
Ocean will shed light on the Mesozoic history of the ocean, Coakley says. And anunderstanding of the Mesozoic history will particularly aid understanding ofmajor ocean features such as the Lomonosov Ridge, the Alhpa-Mendeleev Ridge,the Makarov Basin and the Canada Basin. Knowledge of the marine geology willhelp elucidate the history of terrestrial features such as the Brooks Range and theNorth Slope of Alaska.
Deciphering the geologic history, together with data from sediment and icecores, will enable the study of global climate changes in ancient times and permitthe construction of climate models during periods of high carbon dioxide con-centration.
—ALAN BAILEY
Bernard Coakley,associate professorof geophysics at theUniversity of AlaskaFairbanks, willspeak at the PacCom conference onFeb. 22 inAnchorage on theresults of geologicaland geophysicalresearch in theArctic Ocean.
● W A S H I N G T O N , D . C .
Specter to look at oilindustry antitrustConsolidations concern chairman of Senate Judiciary Committee,who calls for Congress to look at modifying antitrust laws
By H. JOSEF HEBERTAssociated Press Writer
he chairman of the Senate JudiciaryCommittee said Feb. 1 he wants totake a close look at possibly changingantitrust laws to better police oil
industry consolidation. Sen. Arlen Specter, R-Pa., noted that
the Federal Trade Commission hasapproved thousands of mergers in theindustry over the past 15 years, creatinghuge companies, perhaps to the detrimentof consumers.
“It is time the Congress took a veryserious look at modifying the antitrustlaws” in light of such consolidation,Specter told reporters after a hearing onindustry’s market concentration.
One of the agency’s five commission-ers, William Kovacic, said most parts ofthe industry “generally remain unconcen-trated or moderately concentrated” despiteincreased consolidation in some oil pro-duction since the mid-1990s.
The growth of independent companies,he said, “has increased competition at thewholesale and retail levels in many areas”of the industry.
Companies’ immense profits at the timeof high energy costs for consumers havebrought renewed attention on the impact ofindustry consolidation on oil markets.
Just this week, Exxon Mobil Corp., theworld’s largest publicly traded oil compa-ny, reported it earned more than $36 bil-lion last year, the largest annual reportednet income of any company in U.S. histo-ry.
Kovacic: FTC analyzes each mergerKovacic said the FTC analyzes each
merger with an intent of protecting con-sumers against market abuses.Connecticut’s attorney general, RichardBlumenthal, told senators that the emer-gence of such large companies has leftconsumers “at the mercy of increasingprices and unnerving market volatility.”
Blumenthal said the government’s“lax and lackluster enforcement ofantitrust laws has led to an explosion ofmergers in the oil industry.” He saidthere have been more than 2,500 oilcompany mergers in the past 15 years.
After the hearing, Specter said theremight be a need for some changes inantitrust law and that his staff was work-ing on proposals that could be intro-duced this year.
Blumenthal mentioned refocusingthe burden of proof about complianceon the oil companies, rather than onmerger foes, and examining whethercurrent penalties against abuses are ade-quate.
The American Petroleum Institute,which represents large oil companies,said in a statement to the committee thatthe FTC has “thoroughly analyzed”each of the large oil company mergerssince 1981 and required “significantdivestitures” to maintain competitionbefore approving them.
“Any allegation that the federal gov-ernment has been lax in its oversight ...is simply not credible,” according to theinstitute. ●
T
SAO PAULO, BRAZILPetrobras to buy 50% of Texas refinery
Brazil’s state-owned oil company announced Feb. 3 it will pay $370 million for a50 percent stake in a Texas refinery as part of its plan to expand into the United States.
Petroleo Brasileiro SA, or Petrobras, will buy the stake from Astra Oil Trading NV,a division of Belgium’s Transcor International NV.
The refinery in Pasadena, Texas, can process 100,000 barrels of petroleum productsdaily and is being upgraded to handle more, Petrobras said in a statement.
The Latin American energy titan, which will operate the refinery with Astra, is seek-ing direct access to the huge North American market.
Within four years, the refinery will have the capacity to process about 70,000 bar-rels of heavy crude oil daily, some of which could come from a Petrobras field off thecoast of Rio de Janeiro.
“This acquisition is in line with Petrobras’s strategic plan that aims at consolidatingthe company as an integrated energy firm with a strong international presence, expand-ing its refining and sales activities, both at home and abroad,” Petrobras said.
Petrobras to be net exporterPetrobras expects to become a net oil exporter this year for the first time as domes-
tic production surges. The company says it will produce an average of 1.91 million bar-rels of oil a day in 2006, up from an average of 1.68 million in 2005. Brazil’s domes-tic oil consumption is estimated at 1.85 million barrels daily.
Petrobras is making a good investment with the purchase, said oil analyst MarkRoutt of Energy Security Analysis Inc.
The refinery has good access to shipping routes, he said, although there are linger-ing concerns about environmental liabilities from the refinery and a history of strikesby refinery workers.
Petrobras’ strategic plan calls for the company to produce 100,000 barrels of oilequivalent in the Gulf of Mexico starting in 2010.
The company plans to spend $8 billion over the next five years to upgrade its refin-ery facilities and improve the quality of its petroleum derivatives for export to theUnited States. Currently, Petrobras’ refined products don’t meet U.S. standards for sul-fur content.
—THE ASSOCIATED PRESS
By GARY PARKFor Petroleum News
apital budgets up, land sales up,operator ranks up, drilling predic-tions up — all the ingredients foranother scorching year in Canada’s
upstream, except for another mild winterin Western Canada that threatens to turnoil fields mushy.
Across some pockets of BritishColumbia, Alberta and Saskatchewan thepeak drilling season is experiencing somesetbacks.
An early thaw is restricting access towell sites in northern Alberta, where adeep freeze is vital to build ice bridgesand carry the heavy rig loads.
However, a report by investment deal-er Peters & Co. in January said the condi-tions have not yet caused “wholesaledelays in E&P programs,” althoughweather is “rearing its ugly head” as it didwhen record spring and summer rains
saw producers struggling ever since tomeet production goals.
And the first reports on upstreamactivity show record drilling levels inAlberta, Saskatchewan and Manitoba,with only Northern Canada and BritishColumbia lagging.
Of the 722 rigs available acrossCanada a staggering 94 percent were atwork during January, compared with 93percent a year earlier.
Alberta had an average 537 rigs oper-ating, rising to 543 in the final week ofJanuary, when 136 were at work inBritish Columbia and 51 inSaskatchewan.
Association sticks to predictionMeanwhile, the Petroleum Services
Association of Canada is sticking to itsprediction of a record 25,295 well com-pletions in 2006.
Peters & Co. is going one better, fore-casting 25,500 wells this year and 27,500in 2007, while the Canadian Associationof Oilwell Drilling Contractors is bettingon 26,000 wells in 2006.
Drilling contractors President DonHerring and petroleum services PresidentRoger Soucy said the winter melt has yetto affect early-year operations, withactive rigs climbing from 539 in the firstweek of January to 743 by late in themonth.
Soucy said with the industry’s grow-ing emphasis on spreading drilling moreevenly through the year weather has lessaffect on operations.
Also contributing to a positive outlookis an increase in the number of operators
to 572 in 2005, up 50 from 2004.A total of eight companies increased
their well completions last year by 100 ormore wells than in 2004, includingCanadian Natural Resources (up 570wells), coalbed methane producer TridentExploration (up 277), Apache Canada (up264), Compton Petroleum (up 188),Nexen (up 156), Pioneer NaturalResources (up 122), Tundra Oil & Gas(up 107) and coalbed methane producerMGV Energy (up 101).
Those whose tally declined includedEnCana (down 510), EOG Resources(down 377), Husky Energy (down 221)and Petro-Canada (down 184).
Capital budgets for 76 companies up 27%
Capital budgets for 76 companies standat C$42 billion, 27 percent above 2005 forthose same firms, with heavy spending ear-marked for the oil sands.
Heading the list are Canadian NaturalC$6.8 billion, EnCana C$6.75 billion,Talisman Energy C$4.4 billion, SuncorEnergy C$3.5 billion, Petro-Canada C$3.4billion, Nexen C$2.89 billion, HuskyEnergy C$2.85 billion and Shell CanadaC$2.7 billion — all except Talisman andHusky heavily committed to the oil sands.
FirstEnergy Capital is predicting thatjust over C$2 billion will go to coalbedmethane, more than C$600 million above2005, which was affected by the heavyrains, and expects more aggressive coalbeddevelopment this year after 2005 saw onlya modest increase of 175 million cubic feetper day of production after a net gain of412 million cubic feet per day in 2004.
The scramble to accumulate explorationrights shows no signs of easing, withAlberta posting a new record C$378 mil-lion at the second sale of January when583,257 hectares (1.44 million acres) at anaverage C$1,012 per hectare, including209,152 hectares of oil sands leases thatfetched C$217 million.
That has pushed the year-to-date returnsto C$591 million, compared with C$108million for January 2005.
British Columbia has been equally hot,collecting C$52 million from 59,235hectares and its January auction, beatingthe comparable 2005 sale by C$24 million,with the per hectare average climbing toC$874 from C$578.
With many observers expecting the landbuyers will waste no time moving aheadwith their exploration programs, themomentum built up in the second half of2005 should extend into 2006, weather andavailable rig hands permitting.
Boosted by the addition of new rigs, adrilling surge after mid-year resulted in92.46 million feet of hole drilled by all con-tractors, up 17 percent from the same peri-od of 2004.
For all of last year, the average well took6.36 days to complete compared with 5.61in 2004 – the first time in many years thatdrilling times increased, partly due to a 7percent rise in average well depth to 3,779feet.
The dominant contractors werePrecision Drilling which posted 27.9 mil-lion feet of hole and Ensign EnergyServices which tallied 20.4 million feet.
The other major contractors wereSavanna Energy Services 8.1 million feet,Nabors Drilling 6.46 million feet, TrinidadDrilling 6.4 million feet and AkitaDrilling, the leading contractor inNorthern Canada, 4 million feet. ●
B6 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
● C A N A D A
Weather clouds some Canadian regionsMild winter in Western Canada, with early thaw, restricts access to northern Alberta well sites; drilling still at record levels
Of the 722 rigs available acrossCanada a staggering 94 percent
were at work during January,compared with 93 percent a year
earlier.C
By NATALIE OBIKO PEARSONAP Business Writer
enezuelan President Hugo Chavezhas stepped up threats to sell off hisnation’s oil refineries in the UnitedStates, but some oil experts argue a
quick break with the key U.S. marketwould hurt Venezuela.
Tensions between the U.S. andVenezuela escalated with the expulsion ofa U.S. Embassy official accused of spy-ing. In return, Washington expelled aVenezuelan official.
Chavez threatened to sell off all ofVenezuela-owned Citgo PetroleumCorp.’s refineries and divert U.S. oilexports to other countries.
“I could easily order the closing of therefineries that we have in the UnitedStates,” Chavez said Feb. 4 in a speech tosupporters. “I could easily sell the oil thatwe sell to the United States to other coun-tries in the world ... (to) real friends andallies like China, India or Europe.”
Chavez’s threat comes amid jittersabout a disruption in world oil supplies:Iran, OPEC’s second-largest producer,has been referred to the U.N. SecurityCouncil over its nuclear intentions, whileNigeria has been wracked by violence.
“The United States doesn’t face manyalternatives at this moment” and couldface a hike in oil prices if forced to findreplacements for Venezuelan imports,said Carlos Rossi, an economic adviser tothe Venezuelan HydrocarbonsAssociation.
But Rossi and other experts said thebigger loser likely would be Venezuela.
About half of exports to U.S.The South American country says it
exports about half of its official production
of 3.2 million barrels per day to the UnitedStates — much of that refined by Houston-based Citgo and sold through its 15,000retail gas stations.
Finding alternatives to Citgo’s refineries— specially designed to refine Venezuela’sheavy, highly sulfurous crude — would bedifficult, critics say.
“If they sell these refineries, there are noother refineries in the world able to processVenezuelan crude, not in sufficient capaci-ty,” said Jose Toro Hardy, a Chavez criticand former director of the state oil compa-ny, Petroleos de Venezuela SA, or PDVSA.
PDVSA has domestic refineries andsmaller operations in Europe, the U.S.Virgin Islands and Curacao, but they don’thave the capacity to take on Citgo’s share.
“You need refineries to sell oil,” Rossisaid. “The U.S. would feel the impact, butVenezuela would feel it much more.”
Citgo paid $785 million in dividends toPDVSA in 2005 — revenues that Chavez’sgovernment stands to lose if it sells.
Geography also works against Chavez’sthreat of making a clean break with theU.S. market: an oil tanker leavingVenezuela can get to Citgo’s Gulf Coastrefineries in five days compared to about30 days to travel to China.
The United States remains Venezuela’sNo. 1 buyer of oil. It relied on Venezuelafor 10 percent of its oil imports inNovember, the latest month for whichU.S. figures are available. ●
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 B7
● C A R A C A S , V E N E Z U E L A
Chavez threatens tosell U.S. refineriesAnalysts say loss of sales would hurt Venezuela, whichexports about half of its oil to the U.S., most refined by Citgo
V
ARIZONASheriff investigating rant against Exxon
The Maricopa County, Ariz., Sheriff’s office has launched a criminal investigationinto a Guadalupe, Ariz., radio disc jockey who reportedly encouraged listeners to setfire to Exxon gas pumps during his morning radio show.
Sheriff Joe Arpaio said KUPD (97.9 FM) disc jockey John Holmberg spent 22minutes Jan. 31 in a rant against soaring profits at Exxon Mobil Corp. and high gasprices.
“He said the only way oil companies will respond is to violence,” Arpaio said ofthe host of the popular “Morning Sickness” radio show. “He told people to throwmatches at gas pumps and called for a massive, bloody, fiery coup.”
Some worried Exxon employees told their bosses about the comments, and oilcompany officials asked Arpaio to investigate Holmberg. A second show disc jockey,Brady Bogen, is also under investigation.
“Employees are concerned they might be killed or injured because of these com-ments this guy has been making,” Arpaio said. Arpaio said Holmberg told Exxon hewas sorry, but company officials took the apology as sarcasm.
Both Holmberg and Bogen are out of town to attend the Super Bowl in Detroit anddetectives have not interviewed them.
—THE ASSOCIATED PRESS
MMS trims royalties due to storm damageThe Minerals Management Service will reduce royalties in the Gulf of Mexico for
restoration of production in areas that wouldn’t be profitable otherwise, Dow JonesNewswires reports. Applications were being accepted for the program as of Feb. 1.
Hurricanes Rita and Katrina knocked dozens of platforms out of service, and it’sestimated that 1 percent to 2 percent of the Gulf’s production won’t be restoredbecause the damage is too severe and the reservoirs aren’t large enough to makerebuilding profitable. The storms wrecked 115 of the Gulf’s 4,000 platforms anddamaged 52 more, the MMS reported.
Companies are continuing to restore production in the nation’s largest petroleumprovince, but the work has been slow. MMS figures as of Jan. 25 show nearly 25 per-cent of normal daily production of oil is still shut-in. That’s 373,407 barrels daily.
Things are a bit better on the gas front, with 16.5 percent of normal Gulf produc-tion still shut-in as of Jan. 25. That amounts to 1.7 billion cubic feet daily.
Since Aug. 26, lost oil production is 119 million barrels and lost gas production609 billion cubic feet.
—ALLEN BAKER
GULF OF MEXICO
GULF OF MEXICOCompanies honored for safety
Baker Energy Inc. won three safety awards and Rowan Drilling Co. units wonthree more for their safe operations in the Gulf of Mexico. The MineralsManagement Service announced the winners of its 2005 District Safety Award forExcellence on Feb. 3.
Baker Energy was the honored contractor in three of the five districts. The RowanAnchorage rig was the winner in the Lake Charles district, the Rowan Paris rig in theNew Orleans district, and the parent company in the Lafayette district.
Devon Energy Production Co. received two awards, as did Wood GroupProduction Services.
Others receiving awards were Exxon Mobil Corp., Chevron USA Inc., AnadarkoPetroleum Corp. Nexen Petroleum USA Inc., Dominion Exploration & ProductionInc., Spinnaker Exploration Co. LLC, Anglo-Suisse Offshore Partners LLC, andGlobal Santa Fe Corp.
MMS started the safety awards in 1983.—PETROLEUM NEWS
Geography also works againstChavez’s threat of making a cleanbreak with the U.S. market: an oiltanker leaving Venezuela can getto Citgo’s Gulf Coast refineries infive days compared to about 30
days to travel to China.
“head-to-head” battle, then added that“everything we do is aimed at providing abetter suite of opportunities than thoseKeystone presents.”
TransCanada wouldn’t get drawn intocommenting on its rival’s plans.
A spokeswoman said only thatTransCanada was happy to have obtainedthe shipping contracts and was now pre-pared to let the market decide which pipelinewill be built and when.
Many believe not all projects will be built
Rennie said Enbridge was not aware ofanyone who thought all of the oil sandspipeline projects on the table — includingthose by Kinder Morgan Canada (formerlyTerasen) and privately held Altex Energy —will be built.
That view is shared by many analysts,including Canaccord Capital’s Bob Hastingswho said there are limits to how much oilcan be produced and how many markets canhandle the volumes.
Enbridge similarly hedged its bets, con-ceding that whether Alberta Clipper is inservice by 2010 will hinge on whether all ofthe oil sands projects are completed and theability of United States refiners to handleboth bitumen and synthetic crude from west-ern Canada.
FirstEnergy Capital analyst Brian Purdyhas no doubt that Alberta Clipper andKeystone are in direct competition and hebelieves Keystone — a surprise entry lastyear from TransCanada which has littleexperience as an oil carrier — has becomethe front-runner by rounding up shippers,including ConocoPhillips, which has anoption to earn up to a 50 percent interest.
But if Keystone does not survive it makessense for Enbridge to be well-positioned tofill the gap, he said.
That could happen when TransCanadaseeks National Energy Board approval toconvert 520 miles of under-utilized gaspipeline in Canada for use in Keystone — aswitch that might be challenged byEnbridge’s gas distribution unit, which is acustomer on the gasline.
By way of bolstering their respectivepositions, TransCanada and Enbridge areboth talking about further expansions oftheir two projects.
Even before it has approval to start con-struction in 2007, TransCanada said poten-
tial shippers have shown interest in exten-sions from Patoka to Cushing, Okla., andbetween First Saskatchewan near Edmontonand Hardisty in southeastern Alberta.
Chief Executive Officer Hal Kvisle said abinding open season for those two additionswill be held later this year.
Alberta Clipper already represents a sub-stantial expansion of Enbridge’s currentprojects to achieve additional deliveries tothe U.S. Midwest and eventually the GulfCoast.
Its US$190 million Spearhead pipelinefrom Chicago to Cushing is scheduled tocome on stream in March and quickly fill its190,000 bpd capacity, prompting new dis-cussions with shippers on the possibility ofnear-term expansion.
In addition, Daniel said Enbridge has fullproducer backing for all three phases of itsSouthern Access project, a 400,000 bpd linenow under construction between Superiorand Chicago, and discussions are under waywith the Canadian Association of PetroleumProducers to increase the diameter of theline, leading to a possible US$250 million-$320 million extension to Patoka and poten-tially Wood River.
Daniel also reported substantial progresstowards concluding shipper agreements onits C$400 million Waupisoo pipeline,expected to start delivering 350,000 bpdfrom the oil sands region to Edmonton bymid-2008.
Kinder Morgan Canada yet to flex its muscles
Also in the mix is Kinder MorganCanada, which has yet to flex its musclessince taking over Terasen Pipelines beyondsaying in late January that it is identifyingmore opportunities than it originally antici-pated when the takeover was announced.
In a recent conference call, RichardKinder, president and chief executive officerof the parent company, outlined a broadrange of plans that will keep Kinder MorganCanada in the thick of the oil sands businessand position it to make even bolder moves ifTransCanada or Enbridge stumble.
Kinder said his company’sTransMountain line is “going faster than wethought and we think it’s going to providereal opportunities, not just for us but to breakthe bottleneck the producers have experi-enced.”
Based on “tremendous interest,” KinderMorgan decided to combine the first twophases of a TransMountain expansion,including a C$600 million pump stationaddition to be completed in 2007 and an
anchor loop across the Alberta-BritishColumbia border, hiking capacity to300,000 bpd by late 2008 from the current225,000 bpd.
An agreement with shippers and produc-ers was announced Jan. 26 to give commer-cial backing to the expansion through amemorandum of understanding with theCanadian Association of Petroleum produc-ers acting on behalf of TransMountain ship-pers and western Canadian producers togovern the tolling and financial parametersof the system for the next five years.
Kinder said the expansion does not ruleout the possibility of a northern leg to thedeepwater port at Kitimat in northern BritishColumbia, opening the way for Albertacrude shipments to Asia.
Kinder indicated the company is likely toaccelerate Phase 2 (to 400,000 bpd from300,000 bpd) and Phase 3 (to 700,000 bpd),delivering crude to the British ColumbiaLower Mainland and Washington staterefiners as well as moving crude by tanker tosouthern California.
Washington refineriesweighing conversions
A formal open season for the subsequentphases of TransMountain’s plans will belaunched in March.
He said the three big refineries inWashington, which currently process AlaskaNorth Slope crude, are weighing conver-sions so that they can run Alberta heavycrude.
“I think refiners working with producerswill strike a deal to move a whale of a lot ofheavy crude,” to Washington state, he said.
Kinder said prospects look “very good”for Kinder Morgan’s proposed 100,000 bpdcondensate import line from Kitimat toEdmonton in partnership with PembinaPipelines — a similar system to that plannedby Enbridge.
The two companies are also working onpossible export pipelines from Alberta toKitimat, opening the way to markets in Asiaand California.
Out on the horizon is privately ownedstart-up Altex Energy, which is offering abullet line to ship 250,000 bpd of raw bitu-men from Alberta to Texas, but has saidnothing in almost four months since enteringthe picture.
Koch’s Minnesota Pipe Line has becomeanother player by filing an application inJanuary to add 300 miles of new 24-inchdiameter line and add 160,000 bpd ofCanadian crude to its existing 300,000 bpdby early 2008. ●
B8 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
continued from page B1
GIANTS
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 B9
while its fate is uncertain, the testimony before Ways andMeans offers a good primer on an issue which will likely beon the November ballot.
Three cents per year The bill proposes a tax on North Slope gas reserves on
fields with known resources of at least a trillion cubic feetunitized before 2002. The proposed annual tax is 3 cents perthousand cubic feet. There is a credit provision for gas own-ers who commit to ship or sell their gas. The credits can beapplied against taxes due only after shipment begins of atleast 2 billion cubic feet a day and the credits are good onlythrough 2030.
When Croft introduced the bill to House Ways andMeans in April he told the committee that there is “a signif-icant probability that the major gas producers, the lease-holders on the North Slope, are interested in producingother gas fields first.” He said that may be because they canget higher rates of return from gas in other countries. “It alsomay be that those countries are ... less subtle in how theyapproach the decision of whether to develop.” He said thatcountries “unconstrained by ... things like constitutions” canbe pretty direct in protecting their sovereign interests. “AndI don’t think that the major oil companies have much choiceabout putting some of these gas fields on line.”
A combination of better rates of return and pressuresfrom other countries “are putting their gas reserves ahead ofours,” he said.
Croft: Alaska on the back burnerCroft told the committee that growing up in Alaska he’d
expected to see a gas line built right after the oil pipeline —in the early 1980s or, worst case, the late 1980s. But it neverhappened.
The state needs to “do something to assert our sover-eignty, to make sure that this is understood to be Alaska’sresource.”
Croft said he wants resource decisions made in Alaska,not in Congress, in the Exxon or BP boardrooms, or by theSierra Club.
HB 223, he said, is modeled after a Kentucky strandedcoal act. West Virginia coal companies bought up Kentuckyleases, he said, “not to develop them, but to not have themcompete with their other coal ventures.” Kentucky passed alaw to tax the coal in the ground. “And that idea appealedto me, to say you build the line or you pay the fine,” he said.
HB 223 would tax gas beginning in 2007 and creditcompanies once they agree to sell their gas or commit it “toa bona fide project.”
Croft referred to testimony by attorney Spencer Hosie ofSan Francisco-based Hosie Frost Large & McArthur, to theLegislative Budget and Audit and Senate Resources com-mittees in April (see story in May 8, 2005, issue ofPetroleum News), that Alaska leaseholders have an impliedduty to produce and market. The defense, he said, is impos-sibility or “commercial impracticability.”
Croft said that if Exxon wants a higher rate of return thanit would get on an Alaska project, “that is not a reason forthem not to develop.”
Rep. Ralph Samuels, R-Anchorage, asked Croft aboutreducing oil production by encouraging companies to sellgas now rather than using it to maintain reservoir pressure,and asked if the duty of the Alaska Oil and GasConservation Commission to maximize overall hydrocar-bon production was included in the bill.
Croft said that while the commission, along with lease-holders, has a role in determining re-injection at individualfields, the Legislature as the resource holder also has a role.The issue right now is bigger than individual fields, he said,because without a gas pipeline new fields can’t be devel-oped and even fields like Prudhoe Bay are reaching gas-handling capacity.
There is no “specific field-by-field balance” in the bill,he said, “because what this bill wants to do is provide a verystrong big hammer to get the gas pipeline going. After thegas pipeline goes, the tax goes away and the AOGCC canbalance those field-by-field decisions.”
Croft staffer Mark Gnadt told the committee that the listof gas exempt from the tax came from a letter ExxonMobilwrote to the commission in 1997 detailing how the compa-ny would determine how much gas they could market, orthe gas available for major gas sales. The wording in thebill, Gnadt said, is an adaptation of ExxonMobil’s wording.
ConocoPhillips: producers working with administration
At the April hearing the only oil company testimonycame from Michael Hurley, ConocoPhillips Alaska’s direc-
tor of state government relations. “ConocoPhillips strongly opposes this gas reserves tax,”
he told the committee. ConocoPhillips and the other North Slope producers, he
said, have been “diligently working with the administrationto hammer out a fiscal contract to provide the certainty tomove the project forward,” and said imposition of “this kindof punitive tax” would disrupt the negotiations effort.
He said ConocoPhillips does not believe “you can tax aproject into existence,” and said such a tax would not be anincentive, but would increase the uncertainties of an Alaskagas project.
Committee Chair Bruce Weyhrauch, R-Juneau, askedHurley if leases shouldn’t revert to the state if they are notdeveloped after a period of time. Hurley said Alaska leasesdo revert to the state if commercial quantities of hydrocar-bons are not found within a specified period.
Samuels asked: “If you’re developing the oil ... but youalso have paying quantities of gas, is it your interpretationthen that it is being developed just because oil’s beingdeveloped?”
“Yes,” Hurley replied. “If you produce the oil and warehouse the gas is that suf-
ficient under the leasehold?” Croft asked the committee. Hesaid he hoped not, because “then literally that gas could beput on hold for decades.”
His bill, Croft said, would provide consequences forholding that gas.
Hickel: outside interests holding resourcesWays and Means took testimony on the bill again in
January. Former Gov. Walter Hickel told the committee Jan. 11
that outside interests holding onto Alaska resources to avoidcompetition with resources elsewhere was a concern voicedby Alaska’s delegate to Congress, Bob Bartlett, at theAlaska constitutional convention 50 years ago. The gasreserves tax has been described as“punishing” the producers, Hickelsaid, and “that’s exactly right.” If youhold onto what may be more than atrillion dollars of someone else’sresources then you must pay a price,he said.
Rep. Norm Rokeberg, R-Anchorage, asked Hickel whyattempts to commercialize AlaskaNorth Slope gas by Yukon PacificCorp., of which Hickel was afounder, had been unsuccessful and ifthe price of gas in the past didn’t havea major impact on why the state’s gashasn’t been sold.
Hickel said price had nothing todo with it. The problem, he said, wasthat Yukon Pacific couldn’t make theowners sell the gas.
Hickel said that Alaska owns thegas, and has to learn to act like an owner state. If PrudhoeBay had been in Kansas, he said, 100 farmers would own itand their lawyers would be telling the companies to devel-op it, not waiting for the companies to act.
Croft: price for warehousingCroft told the committee Jan. 18 that the bill attempts to
set “a price for warehousing Alaska’s gas that is not overlypunitive, that has some rational relationship to the revenueswe would lose by not having this gas project, but enough ofan incentive to move these companies forward.”
While companies committing to a project can get a cred-it for the tax, the state won’t be paying interest, so the com-panies “lose the time-value of money,” Croft said. The cred-it can be applied against 50 percent of tax through 2030, hesaid, but not until the line is complete and moving gas; acomplete line moving gas is also the trigger for terminatingthe tax.
Since companies don’t receive credit under the bill untilthey commit to a project or agree to sell their gas, for every
year they delay in committing they get less back, and for“every year of delay on this project, that credit drops off that2030 cliff, and less and less of it do you get back, until threeor four years of delay, they’re not getting much back of it atall because of the way interest works.”
Value of non-producing leasesRep. Max Gruenberg, D-Anchorage, asked Croft if there
was any value to the companies in holding non-producingleases.
There are, Croft said, “significant reasons why Exxonand British Petroleum might want to reserve the gas, eventhough it’s perfectly economic to produce.”
A lot of a company’s stock value is based on its reserves,Croft told the committee. As companies have consolidatedthey produce more and more and while “that’s great foryour bottom line, it puts pressure on your reserves.” WallStreet, he said, wants to see adequate reserves.
“I don’t want to be Exxon’s reserves,” he said. Part of thereason for the bill, Croft said, is so that Alaska won’t bewarehousing gas to support a stock price. The stock priceissue also helps explain why ConocoPhillips is more inter-ested in the project than Exxon or BP, he said: “they havemore of their reserves here,” compared to ExxonMobil,which is also facing pressures elsewhere in the world todevelop its gas. If Indonesia and Russia and the Middle Eastare better at pressuring gas development, “we will just quitenaturally be put at the back of the bus.”
There is also ordinary business competition: Croft saidthat if Exxon knows it hurts ConocoPhillips if the project isput off two or three years, “then they get to squeeze someof their own competitors at the same time.”
“You start to put those together and there starts to be sig-nificant reasons why an Exxon or a British Petroleumwould decide, even though it makes money, let’s just not doit for a decade.”
Bill requires gas to flowWeyhrauch asked Croft why ConocoPhillips, which has
an agreement with the state on gas fiscal terms, should alsopay the tax.
Croft said the impact on major leaseholders wasaddressed through the credit, and an irrefutable start datewas required to avoid litigation, so the bill defines the proj-ect as under way when there is a pipeline pushing 2 billioncubic feet a day of gas.
A leaseholder’s credit starts when it “makes an irrevoca-ble agreement to sell or a binding transportation agree-ment,” he said.
Rep. Paul Seaton, R-Homer, asked: If owners don’tmake a binding agreement to sell or ship then they get nocredit? Croft said that was correct.
Asked by Rokeberg if ConocoPhillips’ agreement withthe state, if finalized, would meet the bill’s requirements,Croft said that depends on what the agreement is. If it’s anoption for fiscal terms that ConocoPhillips could take“whenever they wanted to, it would not apply here,” hesaid. That wouldn’t be a project it would just be fiscal termsthey could take or leave.
What, Rokeberg asked, if there is no project and a singlecompany, although it wants to sell, is unable to build a proj-ect on its own?
“The incentive will remain there until the pipeline isbuilt,” Croft said: “... those that act in the way that we wouldlike them to — those that move towards a project, not justa fiscal regime but a project — will get a credit for that andget all that money back. Those that we have to drag to thetable will not get that credit.”
If everything goes well and there is a gas contract signedand approved by the Legislature this year, but the gas taxincentive passes or HB 223 becomes law, Rokeberg asked,would the tax still go into effect in January 2007 even witha contract?
Croft said that was correct. He said “look at it as earnestmoney.” Even if there is an agreement, and with bindingagreements to ship, “we should keep this going so that wehave that earnest money and if they’re serious about it, if it’sa serious agreement, if it seriously gets us the gasline thatwe seriously want then they’ll get that money back, withoutinterest, but they’ll get it back.”
“But we have a system where for every year a delay willcost you and we know it: it’s liquidated damages or earnestmoney.”
Counter point: Griffin for ConocoPhillipsWhen House Ways and Means continued its hearing on
HB 223 on Jan. 25 it heard from Jack Griffin, vice presidentexternal affairs for ConocoPhillips Alaska, who told thecommittee: “ConocoPhillips now has a deal with the Stateof Alaska that it is willing to use as a basis to move forward
continued from page B1
GAS TAX
see GAS TAX page B11
“ConocoPhillips now has a deal with the Stateof Alaska that it is willing to use as a basis tomove forward on the project.” Agreement inprinciple was reached Oct. 21 and technicaland drafting issues were resolved over the
following weeks. Since the state andConocoPhillips reached that deal, they “have
been trying to negotiate a comprehensiveagreement that includes the other major NorthSlope producers.” —Jack Griffin, vice president external
affairs for ConocoPhillips Alaska
Former Gov. WalterHickel told the com-mittee Jan. 11 thatoutside interestsholding onto Alaskaresources to avoidcompetition withresources elsewherewas a concern voicedby Alaska’s delegateto Congress, BobBartlett, at the Alaskaconstitutional con-vention 50 years ago.
JUD
Y P
ATR
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B10 PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006
releasing the department’s proposed fiscalyear 2007 budget. “There will be a num-ber of opportunities this year to moveahead.”
Higher revenue proposalPro-ANWR lobbyist Roger Herrera
said it was Sen. Ted Stevens, R-Alaska,who brought to the Bush administration’sattention the higher revenue potential ofdrilling in the refuge’s 1.5-million-acrecoastal area.
The report resulted after Stevensrequested in mid-December that theCongressional Budget Office re-examinethe revenue projection for ANWR in lightof recent higher oil prices.
“The CBO actually came back with acalculation of $10 billion, but they listed
a more conservative figure of $6 billion,”Stevens’ aide, Courtney Boone, said Feb.8.
This year, the Energy InformationAdministration came up with the highercalculation based on its own model,Boone said.
The administration’s fiscal 2006 budg-et request assumed the first sale wouldgenerate $2.4 billion and a total of $5 bil-lion over a five-year period, also to besplit 50-50 withAlaska. That was thebasis for includingANWR drilling inthe Senate’s fili-buster-proof budgetr e c o n c i l i a t i o nprocess last year.But ANWR ran intotrouble in the Houseof Representativesafter passing theSenate and fell shortof the final budgetpackage.
Domenici to leadeffort
Longtime ANWRsupporter Sen. PeteDomenici, R-N.M.,who chairs theSenate Energy and Natural ResourcesCommittee, has said he will lead anothereffort to move ANWR drilling throughthe congressional budget process thisyear, based partially on recent Iranian oil-supply disruptions.
“Clearly, the administration continuesto recognize ANWR’s importance,”Boone said.
Though it is widely accepted thatRepublican leaders will make anotherpush to get ANWR drilling throughCongress this year, Herrera said no planhas yet crystallized. “If you listen to thegrapevine in D.C., it’s accepted thatanother effort will be made. … There areall sorts of options. … Beyond that, it’sjust rumor and supposition, and I don’tthink that has much value at this earlystage,” he added.
Additional Interior moniesInterior’s budget proposal also asked for
an increase of $12.4 million for Bureau ofLand Management activities on the NorthSlope, based on the assumption thatCongress will authorize ANWR energydevelopment in 2006. The additional fundswill support the required environmentalanalyses and other preparatory work inadvance of the first ANWR lease sale in2008.
The request will support BLM’s leasing,inspection, and monitoring program in theNational Petroleum Reserve-Alaska and
BLM’s participation in the North SlopeScience Initiative. BLM also will use fundsto respond to the environmental threatposed by abandoned legacy wells and relat-ed infrastructure on the North Slope,according to Interior.
The 2007 budget proposal also includesan increase of $6.5 million for the MineralsManagement Service to meet new responsi-bilities for offshore renewable energydevelopment. The budget proposes $3.8million in increases in BLM and the U.S.Geological Survey for oil shale develop-ment and a $1.9 million package of increas-es for gas hydrate research and develop-
ment by MMS, BLM and USGS.Environmentalists blasted the budget
proposal as contradicting President Bush’sJanuary State of the Union address in whichhe declared America is “addicted to oil,”and called the projections wildly inflated.
“Last week the president had what wethought was a landmark speech about ouraddiction to oil,’ Brian Moore of the AlaskaWilderness League told E&E Daily. “Itturns out we may be addicted to oil, but he’sstanding on the corner looking for a fix.”
“We shouldn’t even be talking aboutthis,” Moore said. “How many times hasCongress said no to this thing?” ●
Longtime ANWRsupporter Sen. PeteDomenici, R-N.M.,who chairs theSenate Energy andNatural ResourcesCommittee, has saidhe will lead anothereffort to moveANWR drillingthrough the con-gressional budgetprocess this year,based partially onrecent Iranian oil-supply disruptions.
continued from page B1
ANWR
Company symbol earnings % liquids % gas %
BP BP $3,685 +22 2,593,000 +1 8,714 +3
EnCana ECA
ExxonMobil XOM $10,710 +27 2,629,000 +3 9,822 -6
Can. Natural CNQ.TO
ConocoPhillips COP $3,679 +51 1,012,000* -2 3,471* +3
Chevron CVX $4,144 +21 1,715,000 +4 4,927 +32
Devon DVN $970 +44 219,700 -18 2,158 -11
Burlington BR $927 +132 159,900 +2 1,928 +2
Husky HSE.TO C$669 +197 215,900 +4 675 -3
Petro-Canada PCZ C$714 +58 292,300 +1 803 -10
Kerr-McGee KMG $2,156 NM 122,100 -34 890 -21
Nexen NXY.TO
Talisman TLM
Apache APA $787 +55 227,100 -10 1,234 -1
Suncor SU.TO C$1,245 +24 267,700 +20 193 -0-
Williams WMB
Pogo PPP $115 +199 35,685 +44 265 +10
XTO XTO $454 +161 52,619 +25 1,102 +20
Forest FST
Dominion D $1,033 -18 38,840 +38 824 -19
Occidental OXY $1,152 +55 452,000 +6 674 +5
Newfield NFX $184 +104 20,000 -31 439 -27
EOG EOG $462 +126 28,700 -4 1,312 +15
Imperial IMO C$1,016 +89 267,000 -3 579 –0-
Pioneer PXD $141 +38 66,036 -4 628 -10
Marathon MRO $1,265 +195 224,400 +38 1,005 +1
Chesapeake CHK
El Paso EP
Anadarko APC $874 +116 198,000 -11 1,386 -15
RD/Shell RDS-A $4,368 -4 1,986,000 –8 8,784 -10
Earnings from Top 30 North American E&P Capex SpendersEarnings fourth quarter 2005 • Change from fourth quarter 2004
Liquids production fourth quarter 2005 • Change from fourth quarter 2004Natural gas production fourth quarter 2005 • Change from fourth quarter 2004
OIL COMPANY EARNINGS
* Does not include share of Lukoil productionLiquids production in barrels per day. Natural gas production in millions of cubic feet per day.
NOTE: Top 30 is based on Petroleum News research
on the project.” Agreement in principle was reached Oct.
21, he said, and technical and draftingissues were resolved over the followingweeks.
Since the state and ConocoPhillipsreached that deal, he said, they “have beentrying to negotiate a comprehensive agree-ment that includes the other major NorthSlope producers.”
Griffin traced the history ofConocoPhillips’ role: participation in 2001
in a $125 million study to move a gas proj-ect forward; a leadership role in seekingreauthorization of the Stranded GasDevelopment Act; a leadership role inobtaining federal enabling legislation; and aleadership role in advancing an applicationto the state under the stranded gas act.
He said ConocoPhillips is ready to moveto the next step, but “cannot take that stepon our own.”
“This project requires economies ofscale that we cannot meet by ourselves.”
Concluding stranded gas negotiationsbetween the state and the three producershas been the company’s focus, he said, andthe gas reserves tax “undermines thoseefforts in part by penalizing ConocoPhillipsnotwithstanding the fact it has taken thevery steps that the administration and thisLegislature have urged it to take to advancethe North Slope gas project.”
Company can’t avoid taxGriffin said that “in contrast to testimony
previously provided to this committee, thereis nothing ConocoPhillips itself can do toavoid imposition of House Bill 223’s newtax, short of surrendering the billions of dol-lars we have already invested in the devel-opment at Prudhoe Bay.”
ConocoPhillips cannot avoid the tax “byselling its gas or by committing its gas to aproject under an open season,” he said.
“This tax is automatic and unavoidable.If we started welding steel and laying pipetomorrow we could not avoid this new tax.”
Griffin said ConocoPhillips believesclaims that the tax would be refunded if pro-ducers move forward with the project are“inaccurate and misleading.”
ConocoPhillips would likely pay inexcess of $200 million a year for the next 10years, and the tax would not be refunded for10 to 25 years in the future, with no interestpaid. There are limits on the amount ofcredit that could be applied in a givenmonth, and a cutoff for refunds, he said, thecombination of which ensures that “refundsunder this bill will only be a fraction of thetaxes actually paid.”
Griffin said ConocoPhillips believes HB223 “reflects bad public policy and we thinkit’s unfair.”
He said that in addition to the issues heraised, there are “a host of other legal andpolicy issues ... including serious issuesunder both the state and federal constitu-tions.”
Impact of unit agreementsSamuels asked how the Prudhoe Bay
unit agreement would work ifConocoPhillips ever wanted to move for-ward on its own with a gas project.
Griffin said the unit agreement“is essentially a partnership for thedevelopment of the resources, notfor the marketing. ... You form aunit agreement to ensure that thereisn’t physical or economic wasteof the resource, that you maximizethe production from a field withina given area.”
There are “no clear provisions”allowing ConocoPhillips to moveforward on its own with gas devel-opment, Griffin said.
Gas is re-injected now, Samuels said: ifConocoPhillips’ one-third was enough gasto build a pipeline, could the company takethat gas and allow BP’s and Exxon’s to stayin the ground?
Griffin said he thought that would be dif-ficult. “I don’t want to say it would beimpossible, at this stage, but I think it wouldbe difficult and certainly less than an idealchoice.”
Seaton asked if there would be “a causeof action” with the other owners ifConocoPhillips “was to sell its gas, its thirdof the gas, and that was then not injected inthe ground.” Would that be a violation of theproduction agreement for Prudhoe Bay, heasked.
“I can’t say that it would be a violation,”Griffin said. But he said he thought that ifone owner at Prudhoe Bay “wanted to takeits gas without the participation of the otherunit owners, we would most likely see thecourts asked to resolve differences in inter-pretations of those agreements.”
Gruenberg asked Griffin how thePrudhoe owners would prevent a projectbeing held up by another owner.
Griffin said that’s the goal of negotia-tions under the stranded gas act. “We’re alltrying to come together on a set of commer-cial terms that works for all of the majorNorth Slope gas owners.”
But, how, Gruenberg asked, do the own-ers resolve such issues on an ongoing basis?
Griffin said working interest owners in aunit generally have a common goal “tomaximize the production that can bederived economically from a unit” likePrudhoe Bay, and have “complex agree-ments that help govern our relationships.”
The issue of sitting on the gasWeyhrauch asked Griffin why he
believed HB 223 was bad public policy. Griffin said ConocoPhillips “has all of
the incentives necessary to move forwardon a gas project.”
The state already provided the right
incentive to move the project for-ward with the stranded gas devel-opment act, he said. “That’s theright incentive.”
A tax which is imposed “as aweapon to force private parties toexpend billions of dollars on thestate’s behalf without regard towhether the investment makessense — and there’s nothing inthe bill that would require that theinvestment actually make sense— is a novel and even unprece-
dented use of a state taxing authority,” hesaid.
Weyhrauch noted that one of the retortsto that is that the oil companies are using thegas as part of corporate portfolios “to showstockholders that the price of the stock isactually valid because you’re sitting on thislarge resource, and that it’s unfair (forAlaska) to serve as a reserve for the benefitof the corporation.”
“There is no benefit, in our view, to acorporation to quote sit end quote onPrudhoe Bay gas,” Griffin said.
A corporation cannot count gas as part ofits reserves base for Securities andExchange Commission reporting, or report-ing to shareholders and potential sharehold-ers, “until you’ve authorized the develop-ment of the project necessary to move thatgas to market. So it does absolutely no goodto sit on the gas and not move forward withit,” he said.
Seaton asked whether the Legislaturewould find any North Slope gas reserveslisted for any of the companies.
Griffin said he couldn’t speak for anycompany other than ConocoPhillips. “I cangive you our view and our pretty clearunderstanding of what the SEC rulesrequire. And our understanding is, untilyou’re authorized the expenditures neces-sary to make those reserves marketable,they don’t become reserves for reportingpurposes.
“They’re known resources, but they’renot reserves,” Griffin said, and it’s reservesthat the market and shareholders look at.
If gas had been sold in the 1980sRokeberg asked Griffin if he would pro-
vide state and federal constitutional issuesrelated to HB 223, and also asked Griffinwhat he thought would have happened ifNorth Slope gas had been sold to YukonPacific and a line had been in production in1994.
Griffin said that in the decades follow-ing the discovery of oil at Prudhoe Bay nat-
ural gas prices couldn’t support the cost oftransportation infrastructure to market oncethose markets were deregulated in the1980s.
He said “the state would be a far, farpoorer place today had we been foolishenough to build a gas project back then andessentially given away our gas for less thanthe cost of transporting it.”
The state would have lost the value ofthe gas, he said, and “we would have alsolost the value of approximately 3 billionbarrels of oil at Prudhoe Bay that we’vebeen able to recover as a consequence ofre-injecting that gas and making beneficialuse of the gas at Prudhoe Bay.”
Bill moves from committeeOn Feb. 3 House Ways and Means,
without objection, moved HB 223 out ofcommittee.
The bill is also the subject of an initia-tive and Samuels said that while he hasvoted for initiatives, he is a believer in thelegislative process: “despite all the rhetoricon both sides of the aisle, nothing ever real-ly swings too far one way or another,because it is so hard to get somethingthrough the process,” he said.
Initiatives circumvent the legislativeprocess, he said, and while the legislativeprocess is frustrating, it “brings forward allof the experts, all of the testimony, all of thepolitical maneuvering that make it so diffi-cult” to get some things through.
“It also brings all points of view to thetable,” he said.
Samuels thanked ConocoPhillips for itstestimony, and said while he could guesswhat ExxonMobil and BP think about thebill, he would have liked to have heard itfrom them.
“If we don’t have the debate in the leg-islative process, then we’ve lost a key ele-ment of having the legislative process,” hesaid.
Samuels said if the bill didn’t move,there won’t be a debate: “and then we’ll bestuck in what I consider the worst of allworlds — no debate in the legislativeprocess, the initiative process will moveforward, it will be on the ballot, and verylittle debate takes place in the public arenaand we’re making a huge public policydecision, worth a billion dollars a year”without debate.
Weyhrauch said the committee has“bent over backwards to take public testi-mony on these measures ... there’s been lotsof opportunity for that kind of public testi-mony.”●
PETROLEUM NEWS • WEEK OF FEBRUARY 12, 2006 B11
continued from page B9
GAS TAX
GasReservesTax Primer
Michael Hurley of ConocoPhillipssaid his company does not believe
“you can tax a project intoexistence,” and said a gas reserves
tax would not be an incentive tobuild a gas line, but would instead
increase the uncertainties of anAlaska gas project.
