Vol. 15, No. 23 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of June 6, 2010 • $2 ● EXPLORATION & PRODUCTION ● LAND & LEASING ● FINANCE & ECONOMY Governor signs McGuire bill reducing state’s geothermal royalty rates page 9 goinside Photos posted June 3, 2010 CLICK FOR CONTENTS PAGE :: BP buried in new tech suggestions :: Best intentions go green :: Shell scores at Challenge Bibendum :: Oil spill blame game buillds Photo: Shell Oil BP has reportedly received more than 60,000 emails and 10,000 phone calls offering advice on how to stop or clean-up the oil leak in the Gulf of Mexico. One company has even launched a website that it says will help BP identify the best technology. Read about what’s coming in and how BP is handling it in the latest edition. Also check out other hot issues in alternative fuels, “green tech” and learn how to reduce your carbon footprint with our student-led col- umn, 365 Days of Green. New developments daily. Latest from Greening of Oil Alyeska resists penalty; feds say improper restart after gas surge Federal pipeline regulators want to fine Alyeska Pipeline Service Co. for its actions following a dangerous surge of nat- ural gas into Pump Station 1 in early 2009. But Alyeska, which operates the 800-mile trans-Alaska oil pipeline, is fighting the proposed $41,300 fine and has asked the U.S. Pipeline and Hazardous Materials Safety Administration for “an in-person hearing.” PHMSA on Feb. 2 sent Alyeska a notice of probable viola- tion saying the company failed to follow its procedural manual for handling “abnormal operations.” Alyeska failed to verify system integrity before restarting the pipeline following a Jan. 15, 2009, event that sent a burst of Liberty not included Interior moratorium covers deepwater drilling; Shell Alaska delay separate By ERIC LIDJI For Petroleum News T he new federal moratorium on deepwater drilling won’t delay the Liberty project BP hopes to begin drilling this year from an existing island off the North Slope. “The deepwater moratorium does not apply to this particular project, which is based from a man-made island and would potentially be drilling directionally into formations under shallow water,” Frank Quimby, public information officer for the U.S. Department of the Interior, told Petroleum News on June 2. “If drilling permit applications are submitted for the project, the Department of the Interior will review them at the appropriate time and determine, based on safety and other considerations, whether the project should move forward with drilling under federal waters.” The Obama Administration on May 27 announced a six-month “pause” in deepwater drilling in the Outer Continental Shelf, as a response to the ongoing oil spill following the explosion of an offshore drilling rig at a BP exploration project in the Gulf of Mexico. For the purpose of the moratorium, “dee Supreme Court jumps in Justices agree to take DNR appeal in fight for Alaska’s Point Thomson gas field By WESLEY LOY For Petroleum News B ack in January, ExxonMobil had cause for cau- tious celebration after winning a key court rul- ing in its tussle with the state for control of the rich Point Thomson field on Alaska’s North Slope. Now the tide has turned as the courts have given state officials a reason to smile. The Alaska Supreme Court on May 28 agreed to entertain an unusual appeal from the state Department of Natural Resources. Department officials hope the high court will overturn Anchorage Superior Court Judge Sharon Gleason, whose Jan. 11 ruling delighted ExxonMobil and seemed to stagger the DNR and its lawyers. ExxonMobil’s attorneys had urged the Supreme Court justices not to get involved in a case that has yet to run its full course in the lower court. But the Supreme Court — with Justices Dana Fabe, Daniel Winfree and Craig Stowers participating — granted without discussion the DNR’s petition for review of the Gleason decision. Alberta gets pat on back Industry welcomes royalty revisions, estimates up to extra C$3B could be spent By GARY PARK For Petroleum News T he Alberta government’s latest stab at sweetening a relationship gone sour has attracted the most comforting noises from industry in recent years. In taking the second of three steps to mend fences, the province unveiled a bun- dle of incentives and scaled-back royalties May 27 that it figures could shrink its roy- alty haul by C$1.5 billion over the next three years, but the Canadian Association of Petroleum Producers believes could pump as much as an extra C$3 billion into upstream spending in 2011. The initial wave of reaction included research reports that hailed the incentives as “mate- rial and significant.” Investment bank FirstEnergy Capital said the “economic picture” for the com- panies it covers “is better coming off this announcement,” and peer firm Peters & Co. said the modifications “are a substan- tial improvement” from what the govern- ment indicated in March “when there was minimal benefit for any play unless com- modity prices increased significantly.” Macquarie Securities said the royalty framework is “directionally positive for producers in Alberta and hopefully provides a new stable and clear regime for producers to carry out their oil and gas “It was a decision made with an abundance of precaution… It’s not exactly part of the 30 day report, but it’s related to it.” —Frank Quimby, public information officer for the U.S. Department of the Interior ExxonMobil in recent months has drilled a pair of wells and plans to test them soon. The wells are part of a promised $1.3 billion gas cycling project to produce 10,000 barrels a day of condensate by year-end 2014. see APPEAL page 16 RON LIEPERT see ALBERTA page 16 see MORATORIUM page 15 Alyeska Pipeline target of 8 federal enforcement actions The operator of the 800-mile trans-Alaska pipeline is the tar- get of eight pending federal enforcement actions that add up to more than $1 million in unpaid fines. Most of the enforcement actions the federal Pipeline and Hazardous Materials Safety Administration has taken against the Alyeska Pipeline Service Co. have been pending more than two years. Alyeska is owned by an oil company consortium led by BP, Conoco Phillips and Exxon Mobil. The cases all involve alleged violations of federal pipeline safety regulations. Some allegations involve paperwork errors and inadequate procedures. But others are based on safety violations that were discovered after a pipeline accident, such as a spill or fire. Still other cases involve alleged violations of the rules for see ENFORCEMENT page 14 see PENALTY page 14
Transcript
Vol. 15, No. 23 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of June 6, 2010 • $2
� E X P L O R A T I O N & P R O D U C T I O N
� L A N D & L E A S I N G
� F I N A N C E & E C O N O M Y
Governor signs McGuire bill reducingstate’s geothermal royalty rates
page9
goinside
Photos posted June 3, 2010
CLICK FORCONTENTS PAGE
:: BP buried in new tech suggestions
:: Best intentions go green
:: Shell scores at Challenge Bibendum
:: Oil spill blame game buillds
Photo
: S
hell
Oil
BP has reportedly received more than 60,000 emails and 10,000phone calls offering advice on how to stop or clean-up the oil leakin the Gulf of Mexico. One company has even launched a websitethat it says will help BP identify the best technology. Read aboutwhat’s coming in and how BP is handling it in the latest edition. Alsocheck out other hot issues in alternative fuels, “green tech” andlearn how to reduce your carbon footprint with our student-led col-umn, 365 Days of Green. New developments daily.
Latest from Greening of Oil
Alyeska resists penalty; feds sayimproper restart after gas surge
Federal pipeline regulators want to fine Alyeska PipelineService Co. for its actions following a dangerous surge of nat-ural gas into Pump Station 1 in early 2009.
But Alyeska, which operates the 800-mile trans-Alaska oilpipeline, is fighting the proposed $41,300 fine and has askedthe U.S. Pipeline and Hazardous Materials SafetyAdministration for “an in-person hearing.”
PHMSA on Feb. 2 sent Alyeska a notice of probable viola-tion saying the company failed to follow its procedural manualfor handling “abnormal operations.”
Alyeska failed to verify system integrity before restartingthe pipeline following a Jan. 15, 2009, event that sent a burst of
Liberty not includedInterior moratorium covers deepwater drilling; Shell Alaska delay separate
By ERIC LIDJIFor Petroleum News
The new federal moratorium on deepwaterdrilling won’t delay the Liberty project BP
hopes to begin drilling this year from an existingisland off the North Slope.
“The deepwater moratorium does not apply to thisparticular project, which is based from a man-madeisland and would potentially be drilling directionallyinto formations under shallow water,” Frank Quimby,public information officer for the U.S. Department ofthe Interior, told Petroleum News on June 2. “Ifdrilling permit applications are submitted for theproject, the Department of the Interior will reviewthem at the appropriate time and determine, based onsafety and other considerations, whether the project
should move forward with drilling under federalwaters.”
The Obama Administration on May 27 announceda six-month “pause” in deepwater drilling in theOuter Continental Shelf, as a response to the ongoingoil spill following the explosion of an offshoredrilling rig at a BP exploration project in the Gulf ofMexico. For the purpose of the moratorium, “dee
Supreme Court jumps inJustices agree to take DNR appeal in fight for Alaska’s Point Thomson gas field
By WESLEY LOYFor Petroleum News
Back in January, ExxonMobil had cause for cau-tious celebration after winning a key court rul-
ing in its tussle with the state for control of the richPoint Thomson field on Alaska’s North Slope.
Now the tide has turned as the courts have givenstate officials a reason to smile.
The Alaska Supreme Court on May 28 agreed toentertain an unusual appeal from the stateDepartment of Natural Resources.
Department officials hope the high court willoverturn Anchorage Superior Court Judge SharonGleason, whose Jan. 11 ruling delighted ExxonMobiland seemed to stagger the DNR and its lawyers.
ExxonMobil’s attorneys had urged the SupremeCourt justices not to get involved in a case that has yetto run its full course in the lower court.
But the Supreme Court — with Justices DanaFabe, Daniel Winfree and Craig Stowers participating— granted without discussion the DNR’s petition forreview of the Gleason decision.
Alberta gets pat on backIndustry welcomes royalty revisions, estimates up to extra C$3B could be spent
By GARY PARKFor Petroleum News
The Alberta government’s latest stab atsweetening a relationship gone sour
has attracted the most comforting noisesfrom industry in recent years.
In taking the second of three steps tomend fences, the province unveiled a bun-dle of incentives and scaled-back royaltiesMay 27 that it figures could shrink its roy-alty haul by C$1.5 billion over the next three years,but the Canadian Association of PetroleumProducers believes could pump as much as an extraC$3 billion into upstream spending in 2011.
The initial wave of reaction included research
reports that hailed the incentives as “mate-rial and significant.”
Investment bank FirstEnergy Capitalsaid the “economic picture” for the com-panies it covers “is better coming off thisannouncement,” and peer firm Peters &Co. said the modifications “are a substan-tial improvement” from what the govern-ment indicated in March “when there wasminimal benefit for any play unless com-modity prices increased significantly.”
Macquarie Securities said the royalty frameworkis “directionally positive for producers in Albertaand hopefully provides a new stable and clearregime for producers to carry out their oil and gas
“It was a decision made with anabundance of precaution… It’s not exactlypart of the 30 day report, but it’s relatedto it.” —Frank Quimby, public information officer for
the U.S. Department of the Interior
ExxonMobil in recent months has drilleda pair of wells and plans to test themsoon. The wells are part of a promised
$1.3 billion gas cycling project to produce10,000 barrels a day of condensate by
year-end 2014.
see APPEAL page 16
RON LIEPERT
see ALBERTA page 16
see MORATORIUM page 15
Alyeska Pipeline target of 8 federal enforcement actions
The operator of the 800-mile trans-Alaska pipeline is the tar-get of eight pending federal enforcement actions that add up tomore than $1 million in unpaid fines.
Most of the enforcement actions the federal Pipeline andHazardous Materials Safety Administration has taken against theAlyeska Pipeline Service Co. have been pending more than twoyears. Alyeska is owned by an oil company consortium led by BP,Conoco Phillips and Exxon Mobil.
The cases all involve alleged violations of federal pipelinesafety regulations.
Some allegations involve paperwork errors and inadequateprocedures. But others are based on safety violations that werediscovered after a pipeline accident, such as a spill or fire.
Still other cases involve alleged violations of the rules for
P ioneer Natural Resources has com-pleted an internal investigation of its
Oooguruk field on Alaska’s North Slopetriggered by allegations originally receivedby the BP Ombudsman and later by Pioneerdirectly that operations at the field were notin compliance with state and federal regu-lations.
While the scorecard is not perfect, anattorney for Pioneer Natural Resources saidallegations about its operations atOooguruk on the North Slope include mis-understandings of work at the site and someallegations which cannot be substantiated.
An allegation that the company illegallyused a glycol-water mix for enhanced oilrecovery at Oooguruk turned out to be cor-rect. Jeffrey Leppo, an attorney with Stoel
Rives LLP in Seattle, said in a 37-page May24 letter to state and federal regulators (theU.S. Environmental Protection Agency, theAlaska Department of EnvironmentalConservation and the Alaska Oil and GasConservation Commission), that the com-pany determined that employees followedprocedures used at the Prudhoe Bay andKuparuk River fields in using a glycol-water mix for EOR. While the Alaska Oiland Gas Conservation Commission hadapproved use of the glycol-water mix forEOR at Prudhoe and Kuparuk, it had notapproved it for use at Oooguruk.
Leppo said Pioneer reported the use ofthe glycol-water mix at Oooguruk to theAOGCC in April after the company con-firmed the occurrence through its investi-gation; it has since obtained amendments toits injection orders allowing the use of theglycol-water mix, he said.
Internal investigationPioneer began an internal investigation
after it received a statement of concernsfrom the BP Ombudsman.
The company assembled an investiga-tion team from facilities outside of Alaskaand spent more than 1,000 hours initiallyvisiting and understanding the Ooogurukfacilities and interviewing personnel atOooguruk and in Anchorage, Leppo said.
Mike Kelley, a Pioneer employee fromMarch 2009 to March 2010, made the com-plaints, first anonymously and then in hisown name.
In an initial letter of March 12 the com-pany said it could not substantiate allega-tions made against it.
The company has since been workingthrough allegations in additional informa-tion it received from Kelley, includinginterviews and correspondence, in particu-lar a 140-page document it received fromKelley March 8 entitled “Alaska’s DeadliestSin.”
Leppo said Kelley contacted Pioneer inresponse to the March 12 letter, with whichhe disagreed, and provided additionaldetails and documentation.
Issues raised by Kelley fall into five cat-egories, Leppo said in the letter to regula-tors, including the injection of glycol intoEOR wells.
Some misinterpretationA second category of concerns “relate to
actual events, although the facts have beenmisinterpreted or misunderstood in a man-ner that suggest lawful and proper eventswere conducted in an unlawful or impropermanner,” Leppo said.
Another category of incidents wereresponded to and reported where appropri-ate.
These incidents include accidents andspills reported to the company’s health,safety and environment department andlogged by the company, Leppo said, andspills of a quantity requiring reporting toagencies are so reported.
“Pioneer’s investigation did not detectlax procedures, lapses in training, indiffer-ence to regulatory requirements or failureto report spills,” he said.
Where spills alleged in the Kelley docu-ment were confirmed to have occurred,they had been logged and-or reported.
Leppo said an example of an event thatwas reported occurred in June 2009 whensea ice was forced up the side of theOooguruk drill site and pushed “ice rubbleonto a portion of the ODS working sur-face.”
Stored materials, such as bags of drillingmud ingredients, were buried and dam-aged.
“Pioneer fully inventoried and reportedspills of these solids, and all but approxi-mately one pound of the affected materialwas recovered. No fluids were spilled,”Leppo said.
Pioneer also met with the Alaska
Department of EnvironmentalConservation after the incident to discusshow it was handled and steps being taken toaddress future potential similar occur-rences.
Some concerns weren’t substantiatedPioneer’s investigation was unable to
substantiate some concerns, such asKelley’s assertion that he saw caribou lick-ing spilled drilling salts at Oooguruk andinferred “the caribou hemorrhaged anddied from toxic effects.”
Leppo said Kelley did not report adrilling salt spill or any observations ofcaribou at the time “and there are no otherwitnesses, reported observations or corrob-orating evidence of this occurrence.” Lepposaid drilling salt products used by Pioneerat Oooguruk “do not contain toxic addi-tives.”
Much of the Kelly document “consistsof views and comments critical of applica-ble regulatory requirements and practiceswith which the author disagrees,” such asarguments for a moratorium on nearshoreoil and gas development in Alaska, criticalviews of the Alaska Oil and GasConservation Commission and criticismsof methods used by the State of Alaska tometer oil for royalty determination.
On those issues, Leppo said “Pioneerrespects the author’s right to responsiblyexpress himself, however, the company dis-agrees with the underlying assumptionsand the expressed opinions.”
Responsive changesLeppo said that in the process of its thor-
ough investigation of operations, “Pioneerhas identified areas where improvementscan be made in Oooguruk procedures,facilities, training and personnel,” and sev-eral of the changes are directly responsiveto concerns expressed by Kelley.
Among those issues, the glycol-watermixture used for EOR was addressed withAOGCC.
Concerning the nonhazardous waste andhydrocarbon cycling issues addressed inPioneer’s March 12 letter, Leppo said thecompany found nonhazardous wastes wereproperly identified and manifested for dis-posal and recycling and personnel properlytrained. However, with a flexible system thecompany is dependent on operator judg-ment, and is instituting changes to its facil-ities and procedures to isolate certain non-hazardous waste and recyclable materialstreams “with greater certainty.”
Pioneer will inspect the tundra adjacentto its onshore facilities for problem areas,another concern Kelley had — somethingthat could not be done earlier because ofArctic conditions — and assess whetherthere are problem areas and take remedialsteps where appropriate.
Leppo said that some of Kelley’s “frus-trations concern issues that he raised withoperations supervisors, and which wereproperly and responsively addressed,” but
4 PETROLEUM NEWS • WEEK OF JUNE 6, 2010
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Petroleum News and its supple-ment, Petroleum Directory, are
owned by Petroleum Newspapersof Alaska LLC. The newspaper ispublished weekly. Several of theindividuals listed above work forindependent companies that con-
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ARRC has the logistical know-how, muscle, and infrastructure to keep
Alaska’s resources and economy moving forward. Case in point,
in 2009, Alaska Railroad employees sent more than six million tons of freight across 651 miles of track.
StrengthINDUSTRIAL
� E X P L O R A T I O N & P R O D U C T I O N
Pioneer completes Oooguruk evaluationFinds issues, misunderstandings, events it can’t substantiate; reports what it’s found to federal, state agencies in 37-page letter
I t’s nothing like the heady heights of2008, but there’s a strong upward
move in Western Canada’s upstream fore-casts, buoyed by new incentives inAlberta and Saskatchewan, coupled withthe well-established drawing power ofBritish Columbia.
The pump priming moves with royaltyregimes have caused the CanadianAssociation of Oilwell DrillingContractors to boost its drilling and well-completion targets for 2010.
It now expects an average 400 rigs, or50 percent of the available fleet, will be atwork in Western Canada during the sec-ond half — double its previous target forthe July-September period and 56 percentabove its final-quarter projection.
CAODC predicts 11,587 well comple-tions for the year, 3,064 higher than itsoriginal forecast last October and in linewith a revised forecast by the PetroleumServices Association of Canada, which istargeting 11,250 completions, up 35 per-cent from 2009, and upbeat numbersissued by a number of analysts.
CAODC said its new numbers are oil-focused, bolstered by strong investorinterest in opportunities available in theCardium play of west-central Alberta andsuccess in Saskatchewan’s Bakken play.
The trend is helping pull the sector outof its deepest hole since 1993, although2008 remains a distant memory when arecord 20,700 wells were drilled.
in Alberta and Saskatchewan are prompt-ing independent observers to add theirweight to the improving conditions.
Peters & Co. analyst Todd Garmanexpects 11,000 wells this year and 12,500in 2011, while FirstEnergy Capital ana-lyst Kevin Lo is taking the most opti-mistic view, forecasting 12,089 wells thisyear and 13,015 next year.
CAODC President Don Herring saidthat along with the royalty changes andthe building excitement around the newresource plays, the “demand for crude oilis solid.”
Garman said that, despite the recentdip in crude prices, many conventional oil
plays remain profitable.He estimates the median breakeven
price at Bakken, Lower Shaunavon,Viking and Cardium wells at $54 a barrel,which implies a median return of 41 per-cent based on the current New YorkMercantile Exchange forward strip.
On the natural gas side, the consensusview of analysts and drillers is that $6 permillion British thermal units is the mini-mum price needed to stimulate a reboundin drilling activity, well above the prevail-ing forward strip and $2 above the 2009average.
Assumption of $82 WTIHerring said the major winners in his
sector are likely to be directional drillersbecause the bulk of unconventional gasand all new-style oil plays are using devi-ated drilling technology.
On the heels of the Alberta govern-ment’s announcement on May 27 of itsrevised royalties to stimulate develop-ment of unconventional plays andadvance horizontal drilling,Saskatchewan set a new maximum royal-ty rate of 2.5 percent on the first 882 mil-lion cubic feet of gas produced fromevery horizontal well drilled betweenJune 1, 2010, and March 31, 2013.
Saskatchewan Energy Minister BillBoyd said in a statement his province has“great potential” to utilize newer tech-nologies to develop its gas resources andreverse a slide in gas drilling over thepast seven years.
CAODC’s new drilling targets assumea WTI price of $82 per barrel and anAECO gas price of C$4.55 per thousandcubic feet as well as an average 10.3 daysto drill a well.
For the first quarter of this year, rigutilization in Western Canada averaged54 percent, 35 percent higher thanCAODC’s original projection, with rigactivity averaging 431, up from the antic-ipated 320, based partly on investorexpectations of changes to Alberta’s roy-alties.
As of May 28, industry figuresshowed 4,120 wells were completed sofar this year, compared with 3,281 overthe same period of 2009. �
The province of Saskatchewan is one step closer to joining Alberta as an oil sandsproducer.
Oilsands Quest has made regulatory submissions to the environment and energydepartments to produce up to 30,000 barrels per day using thermal recovery methodsat its Axe Lake property.
As well as production approval, it needs permissions to conduct a steam-assistedgravity drainage test to establish the operating parameters of a commercial venture.
The company said it is prepared to submit the commercial proposal following suc-cessful completion of the SAGD test.
Meanwhile, it will continue to develop detailed engineering plans, cost estimatesand financing arrangements based on current production testing activities.
Oilsands Quest Chief Financial Officer Susan MacKenzie said the latest filingsare an “exciting milestone” for her company and the province as concrete stepstowards Saskatchewan’s first commercial SAGD project.
Oilsands Quest has also requested a second one-year extension of itsSaskatchewan oil sands permits, while notifying the government it will relinquishtwo of its northernmost land permits while it concentrates on the properties consid-ered to be prospective.
The company, which owns 100 percent of 652,000 acres of permits and licenses,reported last year that it had found an estimated 1.5 billion barrels from 170 wells.
The province is believed to hold 60 billion barrels of bitumen resource, much ofit seen as a natural extension from Alberta oil sands deposits that are home to mega-projects by companies such as Suncor Energy and Husky Energy.
In July, Petroleum News is publishing a history of ExxonMobil’s 80-plus yearhistory in Alaska. Are you interested in advertising in this full color, perfectbound magazine? We can offer early takers special placements, such as in sections dealing with the discovery of Granite, Prudhoe Bay and Point
Thomson. Or Point Thomson development. Get in touch.
Alyeska restartstrans-Alaska pipelineLine shut down May 25 after 5,000 barrels spill into containmentarea; production cut to 8%; line down for almost 80 hours
By BECKY BOHRERAssociated Press Writer
The operator of the trans-Alaskapipeline system said late Friday it has
restarted the 800-mile line idled after a con-tained spill the week of May 24.
The pipeline was shut down for 79 hoursand 40 minutes, Alyeska Pipeline ServiceCo. spokeswoman Michelle Egan said.That’s its longest shutdown in at least adecade, surpassing the more than 66 hoursit was down in November 2002 due to anearthquake.
The line from Prudhoe Bay to Valdez hasbeen down since May 25, when Alyeskasaid a power failure during a planned shut-down allowed about 5,000 barrels of oil tospill into a containment area at PumpStation 9, about 100 miles south ofFairbanks.
“New oil has successfully been pumpedthrough Pump Station 9 and we’re doingthat now steadily,” Egan said the night ofMay 28. “That’s a significant milestoneafter a shutdown.”
There were no injuries and no impact tothe environment due to the spill or subse-quent oil recovery and restart operations,she said.
Alyeska has so far recovered 1,000 bar-rels of pooled oil from the containmentarea, Egan said.
Federal restart approvalAlyeska got federal approval for the
restart after addressing questions and con-cerns raised by the federal Pipeline andHazardous Materials SafetyAdministration. The agency on May 27issued Alyeska a corrective action order,seeking documentation and other detailssurrounding its plans to restart and mandat-ing specific steps — including having per-sonnel present 24-7 at the pump stationwhere power was lost — once the line wasback up.
Egan said a crew “will staff the pumpstation 24 hours a day until normal opera-tions resume,” adding about 200 peopleremain involved in managing the incident,including 125 people at the site and a teamin Fairbanks.
The spilled oil flowed into a storage tankat the pump station, then into the contain-
ment yard. The extra staffing will continueuntil that tank is back in service, Egan said,adding she had no estimate when that mightbe.
Alyeska had ordered production levelsdrastically cut — eventually to 8 percent ofnormal output — to keep from filling stor-age facilities before the line could berestarted safely. The company estimatedthat bought it time until noon May 28, butafter that deadline passed, Egan said thereremained a “little margin” and no immedi-ate need to order further cutbacks. Oil pro-ducers have been told they can resume 100percent production, she said.
Order routineDamon Hill, a spokesman for the
pipeline agency, described the correctiveaction order as routine for these types ofincidents.
The letter required certain actions sur-rounding the restart and mandated monitor-ing of and reporting on the spill area afterthe line is back up. An agency official, inissuing the order, found that a failure torequire such steps, in light of factors such asthe hazardous nature of oil, the age of theinfrastructure and investigations into thecause “would result in likely serious harmto life, property and the environment.”
Both the pipeline agency and the stateDepartment of EnvironmentalConservation are investigating the cause ofthe spill.
The trans-Alaska pipeline carries oilfrom the state’s North Slope to Valdez,where tankers pick it up and deliver it torefineries. In April, the pipeline moved645,113 barrels of oil per day, on average.Average crude oil production in the U.S. isabout 5.5 million barrels a day.
The system is owned by a consortium ofcompanies. The largest, with a nearly 47percent stake, is BP Pipelines (Alaska) Inc.Its parent company, BP PLC, has been deal-ing with the massive oil slick that resultedwhen a rig it leased in the Gulf of Mexicoexploded in April. BP’s work in Alaska hasdrawn attention since 2006 when 200,000gallons of oil spilled at Prudhoe Bay.
The other major owners of the pipelineare subsidiaries of the North Slope’s othermain players, Exxon Mobil Corp. andConocoPhillips. �
EXPLORATION & PRODUCTIONPipeline shutdown impacts ANS production
Alaska North Slope crude oil production averaged 588,921 barrels per day inMay, down 8.6 percent from an April average of 644,509 bpd, driven primarily byfive days of prorated production while the trans-Alaska oil pipeline was closeddown following a 5,000 barrel oil spill into a containment area at Pump Station 9south of Fairbanks.
Alaska Department of Revenue data show North Slope production dropped to391,769 bpd on May 25 and bottomed out at 50,840 bpd May 27 before returningto a normal level of 675,339 bpd May 30.
Crude oil was going into storage tanks while the line was shutdown All fields had reduced production in May compared to April except the BP
Exploration (Alaska)-operated Northstar field, one of the smallest, which showedan increase. That occurred because Northstar was offline April 16-20 due to main-tenance, so its production averaged only 15,558 bpd in April, well below theMarch average of 20,298 bpd.
The field averaged 16,634 bpd in May, up 6.92 percent from April, but down18 percent from the field’s March production.
Prudhoe down most barrelsThe largest per-barrel April to May drop was at the North Slope’s largest field,
the BP-operated Prudhoe Bay field, which averaged 288,130 bpd in May, down anaverage of 27,056 bpd from an April average of 315,186 bpd, a drop of 8.58 per-cent. Prudhoe production includes satellite fields at Aurora, Borealis, MidnightSun, Orion and Polaris.
The largest percentage drop was at BP’s Milne Point field, which averaged24,526 bpd in May, down 17.48 percent from an April average of 29,722 bpd.Milne Point production includes heavy oil from the Schrader Bluff formation.
Production at the BP-operated Lisburne field averaged 27,677 bpd in May,down 11.52 percent from an April average of 31,280 bpd. Lisburne productionincludes Point McIntyre and Niakuk.
The ConocoPhillips Alaska-operated Alpine field averaged 88,087 bpd in May,down 11.15 percent from an April average of 99,144 bpd. Alpine includes satel-lite production from Fiord, Nanuq and Qannik.
The BP-operated Endicott field averaged 12,025 bpd in May, down 8.4 percentfrom an April average of 13,128 bpd.
Alpine has smallest percentage dropThe ConocoPhillips-operated Kuparuk River field averaged 131,842 bpd in
Amid a swirling debate over future oiland gas activity in Canada’s off-
shore, spawned by the Gulf of Mexicoblowout, Enbridge is fanning the flamesby officially placing its plans to shipAlberta oil sands crude to Asia beforeregulators.
As it has promised all along, theCalgary-based pipeline company is press-ing ahead with the Northern Gatewayproject, regardless of what could be a full-scale showdown with environmentalistsand First Nations.
The proposal, submitted to theNational Energy Board for an environ-mental review, carries an estimated capi-tal cost of C$5.5 billion (C$6.65 billiononce financing costs are rolled in) fortwin pipelines covering 730 milesbetween the oil sands and the BritishColumbia deepwater port at Kitimat.
One 36-inch diameter line would carry525,000 barrels per day of petroleumproduct for export and one 20-inch linewould deliver 193,000 bpd of importedcondensate to thin petroleum products forpipeline transport. The scheduled in-serv-ice date is 2016.
Enbridge Chief Executive Officer PatDaniel indirectly acknowledged the regu-latory battle that lies ahead by declaringhis company takes “pride in our long-standing reputation as a safe pipelineoperator and socially responsible compa-ny. Construction and operation of theNorthern Gateway pipeline system andmarine terminal will be a model of world-class safety and environmental stan-dards.”
Strong opposition to projectJust as resolved were the opponents,
some of whom have said there are no con-ditions under which they will allow theproject to proceed, with an estimated 200tankers a year navigating in treacherouswaters off the British Columbia coast.
Coastal and inland First Nations and ahost of environmental groups are girding
for a fight over a project they argue is cer-tain to result in a spill that could jeopard-ize the land, people and wildlife for gen-erations to come.
As the environmentalists marshal theirarguments they point out that a recent sur-vey shows 80 percent of BritishColumbians don’t want crude tankers intheir coastal waters; they rate the federalenvironmental review process as “inade-quate” to cover the full range of tankertraffic concerns; they question Enbridge’smotives in pressing ahead against FirstNations resistance; and warn thatapproval of the project is “virtually guar-anteed” to face court challenges.
Enbridge said the primary purpose ofthe pipeline is to provide access forCanadian oil to international markets,with Northeast Asia offering the bestprospects, but a market analysis by con-sultant Muse Stancil did not includeCalifornia as a possible secondary desti-nation because implications of the state’slow carbon fuel standards are not yetclear.
However, the study did estimate thattotal potential crude demand in the west-ern United States is 110,000 bpd, morethan half of which could come from heav-ier Canadian crudes to offset fallingCalifornia volumes.
The Muse Stancil research focused onthe key markets as China and Japan, eachwith the potential to take 100,000 bpd,South Korea at 53,300 bpd and Taiwan at27,500 bpd.
It said that region holds the bestprospects because of its size, increasingdemand, existing refinery infrastructure,proximity to the B.C. coast, which is esti-mated to be 20 percent closer than MiddleEast supply sources and the desire byAsian refiners to reduce their dependenceon Middle East supplies.
Muse Stancil said there is also a strongprospect of other markets for Canadiancrude opening in the Asian-Pacific regionor India. �
PETROLEUM NEWS • WEEK OF JUNE 6, 2010 7
� P I P E L I N E S & D O W N S T R E A M
Canada faces offshore testEnbridge files for Northern Gateway, pledging ‘model of world-class safety’; environmentalists, First Nations ready for battle
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Canadian Beaufort ban urged Canadian regulators claim there could never be a duplication of the Gulf of
Mexico events in Atlantic Canada waters, at the same time a former federal sci-entist warned that an oil spill in the Beaufort Sea could have a “catastrophic”impact on the Arctic ecosystem.
William Adams, a former scientist at Environment Canada, urged federal law-makers to place a moratorium on drilling in the deeper waters of the Beaufortpending a comprehensive study.
“If you look at the leasing that has been done in the Beaufort, it extends outinto the moving pack ice,” he said. “I believe drilling in that area would beextremely risky.”
He said the behavior of a big spill in the Arctic is difficult to predict withoutmore field research, but cautioned that such a spill would inflict significant dam-age on mammals and seabirds.
Adams was one of the researchers involved in a joint government-industrystudy of the impact of an oil spill in the Canadian portion of the Beaufort.
That work, which simulated a spill of about 1,000 barrels per day in waterabout 10 meters deep, stretched over a decade from 1976 and remains the only
Homer Electric Association appears tohave reignited its efforts toward a
hydroelectric project on Alaska’s centralKenai Peninsula, and has rolled out a sig-nificant design change.
In a May 3 filing with the FederalEnergy Regulatory Commission, HEA’sKenai Hydro LLC said it plans to file alicense application for the project in
September 2011.The project centers on Grant Lake, an L-
shaped mountain lake of about 1,700 acresjust east of the Seward Highway near theMoose Pass community.
HEA sees hydro as a way to diversify itsenergy supply. The electric co-op currentlybuys all its power wholesale fromAnchorage-based Chugach ElectricAssociation. That contract expires at the endof 2013, and HEA aims to start making itsown power from natural gas or alternatives.
FERC intends to prepare an environmen-tal assessment of the Grant Lake project, andthe agency scheduled a pair of public scop-ing meetings on June 2-3 at the Moose PassCommunity Hall.
New designIn early February, Kenai Hydro told
FERC it was “suspending major activities toconsider how best to proceed” in light offinancial constraints and a reorganization ofthe company.
The effort now seems to have new life.Kenai Hydro’s project previously fea-
tured two major components, one involvinga dam to raise the level of Grant Lake andanother to pipe extra water into the lake fromnearby Falls Creek. Total cost for the projectwas said to be $30 million to $40 million.
Now the Falls Creek diversion has beenremoved from the project proposal, KenaiHydro project engineer Brad Zubeck toldFERC in the May 3 filing.
According to a FERC scoping document,the project as now proposed would consistof a 10-foot-high, 120-foot-wide concretegravity dam on Grant Lake, at the GrantCreek outlet; a concrete intake tower in thelake to withdraw water; and a 2,800-foot-long, 10-foot-high tunnel down which waterwould flow to a penstock and powerhouse.
The powerhouse would feature two gen-eration units with total installed capacity of4.5 megawatts.
The project also would require a 3½-mileoverhead or underground transmission line,and an access road.
Kenai Hydro proposes operating theproject as run-of-river during the summermonths, capturing high spring and summerrunoffs. During the winter months, the proj-ect would operate by drawing down GrantLake.
At 4.5 megawatts, the project is relative-ly small, considering HEA’s peak power sup-ply is 90 megawatts.
The FERC scoping document anticipatesthe final environmental assessment will beissued in January 2013.
The hydro project has drawn consider-able opposition from some Kenai Peninsularesidents. Opponents see it as a threat to thedownstream Kenai River, famed for its tro-phy salmon fishing. �
8 PETROLEUM NEWS • WEEK OF JUNE 6, 2010
May, down 6.16 percent from an Aprilaverage of 140,491 bpd. Kuparukincludes satellite production fromTabasco, Tarn, Meltwater and West Sak,as well as production from the PioneerNatural Resources Alaska-operatedOooguruk field. May production figuresfrom Oooguruk are not available, butAlaska Oil and Gas Conservation data forApril show production from the fieldaveraging about 12,000 bpd.
The temperature at Pump Station 1 onthe North Slope averaged 25 degreesFahrenheit in May, up from an average of14.9 F in April.
Cook Inlet crude oil production aver-aged 10,184 bpd in May, up 3.32 percentfrom an April average of 9,857 bpd.
ANS crude oil production peaked in1988 at 2.1 million bpd; Cook Inlet crudeoil production peaked in 1970 at morethan 227,000 bpd.
Kenai Hydro resumes work on power projectFERC to prepare environmental assessment for Grant Lake dam and tunnel, which would generate energy for Homer Electric Association
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“comprehensive” study of its kind, he toldthe House of Commons NaturalResources Committee.
The committee is studying whetherBeaufort drilling by a partnership ofImperial Oil and ExxonMobil and possi-bly BP in several hundred meters of watershould be permitted without a tougheningof safeguards.
Imperial: drilling 4-5 years awaySeparately, Imperial Chief Executive
Officer Bruce March said it would be atleast four or five years before his compa-ny would drill in the Beaufort.
He said Imperial plans to learn what itcan from the Gulf incident and implementany measures that are adopted by regula-tors.
Imperial and ExxonMobil made workcommitments of C$585 million for507,000 acres of Beaufort leases, 70miles north of the mainland and in waterdepths of up to 4,000 feet.
Max Ruelokke, chief executive officerof the Canada-Newfoundland andLabrador Offshore Petroleum Board, toldthe same committee of federal legislatorsMay 25 that would not be possible for ablowout at the Chevron Canada-operatedwell currently being drilled in the deep-water Orphan Basin to match the size ofthe Deepwater Horizon spill in the Gulf.
“The understanding we have is that(what) occurred (in the Gulf) is not some-thing that would ever have been allowedto happen in Canada,” he said.
Even if a major spill did occur, windand sea patterns would make it unlikelythat oil would reach the shores ofNewfoundland, he said.
The Chevron well is drilling in water2.6 kilometers deep — a record forCanada — while the BP well in the Gulfwas drilled to a water depth of 1.5 kilo-meters.
Ruelokke said his board, in tighteningoffshore drilling scrutiny in the wake ofthe BP disaster, has mandated a dual bar-
rier, requiring a well to be sealed off usingboth a concrete plug and a blowout pre-venter.
Based on his information, Ruelokkesaid drilling mud keeping the oil under-ground at the BP well had been flushedout before a concrete plug was properlyinstalled.
Review of Orphan operationsHe said Chevron has agreed to delay
Orphan operations before drilling in areaswhere there is an increased chance ofstriking oil, giving both the company andthe board time to review the operation.
“We’ll make sure the dual-barrier con-cept remains valid and both barriers willhave to be in place,” he told legislators.“So before there’s any potential to takeaway the drilling mud we’ll make surethere’s a cement plug in place. We’ll alsomake sure the blowout preventer is fullytested.”
Ruelokke said detailed modeling ofthe potential fate of a spill in AtlanticCanada , using 40 years of weather data,“indicates that even if a large spill were tooccur, it would be unlikely that oil wouldapproach the Newfoundland andLabrador shoreline. “Thus scenes that wesee off the Gulf … would not occur here.”
He said offshore Newfoundland hasproduced 1.1 billion barrels of oil since1997 and spilled only 1,100 barrels ofcrude in that time — a record hedescribed as “quite respectable.”
Canada is continuing to seek bids forexploration licenses in the Beaufort andMackenzie River Delta, including a par-cel about 120 miles offshore to the westof the existing rights held by Imperial andBP.
A spokeswoman for Indian andNorthern Affairs Minister Chuck Strahltold the National Post that the governmentis continuing to “consider its options withrespect to the calls for bids in theBeaufort. But no decision has been takenwith respect to the current call.”
ALTERNATIVE ENERGYGeothermal royalty reduced, new regs out
Alaska Gov. Sean Parnell signed Senate Bill 243 June 2, reducing geothermalroyal rates.
The bill, proposed by Sen. Lesil McGuire, R-Anchorage, made state royalty ratesfor geothermal the same as federal rates.
In the Senate Finance Committee the bill was expanded tomove authority over geothermal drilling and waste preventionfrom the Alaska Department of Natural Resources to theAlaska Oil and Gas Conservation Commission, which has thatauthority for oil and gas drilling in the state.
“This legislation makes geothermal power projects eco-nomically viable and therefore more likely to produce moreaffordable and reliable electric power for homes and business-es,” Parnell said in a statement after the bill signing. “This billassists companies seeking to build a commercial grade geot-hermal plant in Alaska by reducing the royalty payment.”
After the bill passed the Legislature in April, McGuire said since geothermalpower cannot be exported, “Alaska’s previously prohibitive royalty regime wouldsimply have been collected from ratepayers and geothermal development wouldhave been driven to private lands.”
The AOGCC published proposed regulations for geothermal wells May 28. The regulations include geothermal wells in the commission’s regulatory juris-
diction; extend existing oil and gas well regulations, where applicable, to geother-mal wells; allow the commission to grant regulatory variances and waivers whereappropriate; establish the calculation method for geothermal resource regulatorycost charge; and add geothermal wells to the commission’s definition of well. Theregulations are available on the commission’s website at www.aogcc.alaska.gov.
The commission will accept comments on the regulations, including the cost toprivate parties to comply with the regulations, through June 28.
Comments may also be submitted at a hearing on the regulations scheduled forJune 29 at the commission’s Anchorage office.
The state plans to issue a right-of-waylease for a new pipeline on the Kenai
Peninsula.In a May 28 proposal, Commissioner
of the Department of Natural ResourcesTom Irwin found Anchor Point Energy tobe fit, willing and able to build the NorthFork pipeline.
Anchor Point Energy, a subsidiary ofindependent producer Armstrong Oil andGas, plans to build two 4-inch pipelines tomove natural gas 7.4 miles from a produc-tion pad at its North Fork unit, north ofHomer, to Anchor Point, near the CookInlet coast.
Combined, the lines could move up to18 million cubic feet of natural gas perday.
The lines would then connect to a new
pipeline being permitted by EnstarNatural Gas.
The proposal now goes out for publiccomments through July 6, and a publichearing at the Anchor River Inn on June29, after which Irwin will make a finaldecision.
Armstrong hopes to start constructionthis September and finish by March.Under the lease terms, the company wouldhave two years to start work or risk for-feiting the lease.
Armstrong sanctioned the pipeline aspart of a 2009 gas supply contract withEnstar.
Another piece of the puzzleThe North Fork pipeline would make
major inroads toward developing thesouthern Kenai Peninsula, a region of thestate with known gas reserves, but littledevelopment.
In his proposed decision, Irwin notedthat the pipeline “has the potential tomake other marginal gas fields more eco-nomical and more likely to be developed.”North Fork is near the Chevron-operatedNikolaevsk unit and leases held by sever-al independents.
Chevron, though, wants infrastructurecloser to Nikolaevsk.
In the regulatory proceedings over theproposed Enstar pipeline, called theAnchor Point Pipeline, Chevron suggesteda route from Happy Valley south, closer toNikolaevsk, where Chevron previouslydelineated two prospects, known as “Red”and “Blue.”
Enstar is currently proposing a routedown the Sterling Highway.
Enstar said Chevron’s route wouldbypass Anchor Point, a city with 1,800people, and increase the eventual cost ofbringing gas to Homer, a city of more than5,000 people.
Chevron also wants a guarantee thatthe North Fork pipeline will be a commoncarrier line, meaning open to third-partygas. That would provide an incentive forChevron and other leaseholders in theregion to develop known reserves andexplore for new reserves.
Armstrong doesn’t expect future devel-opments to cause a problem.
“Besides the capacity and pressureconstraints, we are unaware of any reasonswhy sales quality gas from a new develop-ment could not tie in to our proposedpipeline,” the company wrote in filings.
The two pipelines, though, would con-nect near another development in theregion: the Cosmopolitan unit currentlybeing developed by Pioneer NaturalResources. While Pioneer seesCosmopolitan as primarily an oil play, itexpects some gas resources as well.
Pioneer plans to start drilling this year,with first oil scheduled for 2014.
A conflict at NikolaevskChevron doesn’t have much work
planned at Nikolaevsk. The company, through its affiliate
Union Oil Company of California, relin-quished the Blue prospect last year,because it chose not to drill new wells, andwasn’t able to farm out the Red prospect,both requirements set out in previousplans of development.
In late 2009, Chevron proposed a thirdplan of development for the Nikolaevskunit, but did not make any drilling com-mitments, saying it was scaling back CookInlet exploration and development activi-ties for 2010 due to “current market con-ditions.”
Chevron also said the lack of infra-structure “further impedes the timing offurther exploration and development” atNikolaevsk, but noted “Armstrong’s cur-rent work at North Fork may stimulateconstruction of a pipeline route fromHappy Valley that could be tied to Red,which may in turn enhance the farmoutopportunities at Nikolaevsk.”
The state rejected that developmentplan, noting that the proposed North Forkand Anchor Point pipelines would bringinfrastructure to within two miles ofNikolaevsk.
The state suggested some revisions:permit a pipeline by March 2010, sign agas supply agreement by September 2010and start producing from Nikolaevsk by
March 2011.Rather than file a revised plan of devel-
opment, Chevron appealed the ruling, say-ing it should have until March 2011, anextended deadline for the unit approvedlast year, to consider developmentoptions. Chevron noted that it is still look-ing for farmout opportunities, and that itrecently applied to form a Red participat-ing area at the unit.
More NFU wells possible Armstrong, meanwhile, is planning
additional work through a 45th plan ofdevelopment.
The company contracted PGS OnshoreInc. to conduct a 3-D seismic survey over20 square miles of the North Fork area.Armstrong wants to shoot that survey thisyear.
The results of that survey would guidefuture drilling. Depending on timing,Armstrong said it could potentially drilltwo North Fork wells into the Tyonek for-mation this year.
Even if those new wells don’t come topass this year, Armstrong said it “may betesting additional sands in the NFU No.34-26 wellbore and re-completing theNFU No. 41-35 during the 2010 drillingseason.” NFU No. 34-26 is the wellArmstrong drilled in 2008, while NFUNo. 41-35 is a nearby well Standard Oil ofCalifornia drilled back in 1965.
Enstar gets RCA approvalThe Anchor Point pipeline, the pipeline
Enstar plans to run up the SterlingHighway to the end of the KenaiKachemak Pipeline, is making regulatoryheadway as well.
The Regulatory Commission of Alaskarecently extended the service area of theAlaska Pipeline Co., an Enstar affiliate, toAnchor Point from its current southernreaches at the Happy Valley Extension ofthe Kenai Kachemak Pipeline inNinilchik.
Several issues remain unresolved,though.
10 PETROLEUM NEWS • WEEK OF JUNE 6, 2010
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North Fork pipeline moving forwardRCA expands Enstar area, Armstrong plans seismic, Chevron appeals Nikolaevsk decision, possible routing conflict brewing
Kelley was not advised whether or how hisconcerns were being addressed.
“Operations management are now beingtrained and encouraged to provide feedbackto personnel and to contractors regardinghow concerns are handled in order to avoidany misperception that such concerns arebeing ignored or mishandled.”
AOGCCKelley was critical of how the Alaska Oil
and Gas Conservation Commission con-ducts its business.
Commissioner Cathy Foerster toldPetroleum News in late March that the com-mission was beginning its own investigationbased on Kelley’s allegations, but thatbecause the allegations included not onlymatters under the commission’s purview, buthow the commission conducted its business,it was going to investigate itself through anindependent investigator.
The state put out a request for proposals. Foerster told Petroleum News June 1 that
the contract was awarded May 1 to HawkConsultants of Anchorage.
She said so far Hawk has gone throughthe lengthy document and identified theallegations, dividing them into those involv-ing AOGCC and those involving others. TheAOGCC issues have been put in categoriesand Hawk Consultants will be interviewingKelley, AOGCC staff and Pioneer employ-ees in putting together a report.
Foerster said the process is lengthy, butshe hopes to see a report from Hawk by theend of summer. �
By WESLEY LOYFor Petroleum News
Anchorage-based Doyon Drilling Inc.is suing a Texas engineering and
design company, accusing the firm ofchronically late and shoddy work on anew rig to serve BP on Alaska’s NorthSlope.
Doyon filed the suit May 7 in U.S.District Court in Anchorage againstHouston-based Loadmaster EngineeringInc.; its president, Roger Barnes; its vicepresident, Robert Cuddie; and parentcompany Loadmaster Universal Rigs Inc.
Doyon Drilling is a subsidiary ofDoyon Ltd., the Fairbanks-based Nativeregional corporation for Interior Alaska.
In the 36-page lawsuit, Doyon’slawyers including Robert Bundy ofAnchorage accuse Loadmaster of fraudu-lently taking a job it knew it couldn’t fin-ish on time, of blowing deadline afterdeadline, of overbilling for services and
of producing work that was so substan-dard that Doyon ultimately had to farmout much of the job to other firms.
The schedule slipped such that Doyonmissed its target of barging the new rig tothe North Slope in summer 2009.
And because fabrication of the rigcontinues, chances of making the 2010barge season is “at risk,” the suit says.
How it beganLoadmaster had not yet answered the
Doyon lawsuit as Petroleum News went topress.
The suit says BP Exploration (Alaska)Inc. in 2008 engaged Doyon Drilling toprovide a state-of-the-art drilling rig, Rig25, to operate on the North Slope byDecember 2009.
Doyon then contacted Loadmaster,Barnes and Cuddie about providing engi-neering services for the project.
Loadmaster got the job, worth $6.3million.
The suit says Doyon “emphasized andmade clear to Loadmaster that time wasof the essence for this project.”
But Loadmaster knew it didn’t havethe ability to make Doyon’s schedule, thesuit says, and the firm soon began to fallbehind on drawings it produced in con-junction with its office in Beijing, China.
Aside from missing deadlines,Loadmaster’s work was “grossly negli-gent and manifestly deficient,” the suitsays.
“Enormous time and resources werespent on needless rework, including thedevelopment of work-arounds, the re-cut-ting and re-fabrication of previously con-
structed steel components, and substan-tial reconstruction of electrical, piping,heating and ventilation systems,” the suitsays.
In late 2009, it was discovered Rig 25was far heavier than intended, which“forced a re-design and re-fabrication ofcertain trailers to sustain the increasedloads,” the suit says.
Doyon said it negotiated with BP anextension of the barging date from sum-mer 2009 to summer 2010.
The suit seeks unspecified damages. �
PETROLEUM NEWS • WEEK OF JUNE 6, 2010 11
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Canada has effectively been told to tend to its own knit-ting as Greenland prepares for the biggest offshore
exploration push in its history. Both the self-rule government and the World Wildlife
Fund have told the Canadian government there is no reasonto fear that a drilling accident could lead to a disaster on thescale of that in the Gulf of Mexico.
Canada’s Environment Minister Jim Prentice said heplans a “robust discussion” with Greenland officials at aJune 9 meeting about licenses Greenland has issued withinits territorial waters of Davis Strait, which is shared withCanada, to determine “when drilling would happen, underwhat conditions and with what contingency plans.”
Greenland calls regulations toughGreenland officials say exploration wells planned for
this summer will be drilled under some of the toughest reg-
ulations in the world — a claim endorsed by Craig Stewart,a spokesman for the World Wildlife Fund who said the rules“are far more onerous than what we have in Canada.”
Mininnguaq Kleist, head of foreign affairs forGreenland, said his government is “following and monitor-ing what is going on in the Gulf of Mexico and is very con-cerned about this.
“The way we will try to prevent such a thing from hap-pening in our area — if we find oil — is to have the stan-dards of the Nordic countries, where you have very highstandards on the environment and the technology used,” hesaid.
He said Greenland’s regulations are based on thoseapplied in Norway, with the major emphasis on using the“best available technology and the highest internationalstandards.”
Scottish-based Cairn Energy has earmarked $400 mil-lion to drill four wells this year west of Greenland’s DiskoIsland and more activity is in the works from explorationlicenses sold along almost the entire maritime border withCanada.
Six failed attemptsOver the past 30 years there have been six failed
attempts to strike oil, but interest is growing as globalwarming extends the Arctic drilling season.
A spokesman for Cairn said his company needs staminato test its eight licenses, given that the blocks are about3,800 square miles each.
A Greenpeace spokesman, while acknowledging theclose ties between oil exploration and Greenland’s hopes forindependence, noted the 2010 licensing round is “very farup north … and very far away from any form of supportshould things go wrong.”
The winners of the 14 blocks on offer over a 57,000square miles area in Baffin Bay will be announced inAugust. Bidders include Royal Dutch Shell and Statoil.
Holders of 13 licenses issued since 2002 are Cairn,ExxonMobil, Chevron, Encana, Husky Energy, DongEnergy, PA Resources and state-owned Nunaoil. �
Doyon Drilling sues Texas engineering firmFederal lawsuit accuses Loadmaster of slow and subpar work, delaying arrival of Rig 25 on Alaska’s North Slope to work for BP
Schlumberger launches new Ocean Store websiteSchlumberger said May 19 that it has launched the Ocean Store, a website where users
can browse, buy and download Petrel software plug-ins to extend their workflows. Theplug-ins are developed by a diverse ecosystem of software companies and universities. “Inthe oil and gas industry today, with more complex reservoirs and intense competition forreserves, oil and gas companies have to differentiate like never before,” said Tony Bowman,president, Schlumberger Information Systems. “The Ocean platform allows developers torapidly innovate to solve these tough challenges, enabling oil and gas companies to deployand use new technologies much faster. The store provides access to a growing set of capa-bilities that extend the already broad Petrel platform.” For more information visitwww.slb.com.
ExxonMobil and employees donate $100,000 to fundExxonMobil said May 21 that it has donated more than $100,000 in support of the
American Indian College Fund. The donation extends ExxonMobil’s partnership with thefund dating back to 1988 and will provide scholarships, sponsorship and administrativesupport to the organization. Part of the grant will be used to continue the ExxonMobilFoundation Tribal College Scholarship Program, which offers funds for Native American stu-
dents studying science,technology, engineering andmath at tribal colleges.Another portion is providedthrough the ExxonMobilEducational Matching GiftProgram, one of the mostgenerous of its kind in theU.S. Through this program,ExxonMobil matches 3:1 thecontributions of companyemployees, retirees, surviv-ing spouses and directors.For more information visitwww.exxonmobil.com.
Editor’s note: All of these news items — some in expanded form — will appear inthe next Arctic Oil & Gas Directory, a full color magazine that serves as a marketing toolfor Petroleum News’ contracted advertisers. The next edition will be released inSeptember.
Companies involved in Alaska and northern Canada’s oil and gas industry
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BP, struggling to cope with the disas-trous Gulf of Mexico oil spill, has
been hit in an Alaska court with anothershareholder lawsuit.
The City of Deerfield Beach Non-Uniform Employees Retirement Plan filedsuit May 25 in Superior Court inAnchorage against BP board members andothers including John Minge, president ofBP Exploration (Alaska) Inc.
The 57-page lawsuit appears to be vir-tually identical to a suit Jeffrey Pickett,described as an Alaska resident and BPshareholder, filed in the same court onMay 20.
Law firms including Ashburn & Masonof Anchorage and Robbins Geller Rudman
& Dowd of San Diego brought the suits.The latter, on its website, describes
itself as a class-action specialist. In federalcourt in Louisiana, the firm says it hascommenced a class action on behalf ofstock purchasers in Transocean Ltd.,whose offshore rig, the DeepwaterHorizon, exploded and sank in the Gulf.
Nature of suitsBoth the Alaska suits, known as “share-
holder derivative” actions, accuse BPdirectors and officers of mismanagementwith respect to the Gulf disaster and envi-ronmental problems in Alaska, where BPruns the giant Prudhoe Bay field.
Each lawsuit cites certain Alaskaevents, such as a major pipeline leak in2006, as examples of the company’s “lais-sez-faire attitude about safety and the envi-ronment.”
The City of Deerfield Beach Non-Uniform Employees Retirement Plan “isand has continuously been a shareholder ofBP since at least February 2008,” the suitfiled May 25 says.
Deerfield Beach is north of FortLauderdale, Fla.
Each Alaska suit asks for the samerelief: compensatory and punitive dam-ages; an injunction compelling the boardto see that BP managers don’t violate safe-ty and environmental laws; and appoint-
ment of an independent safety and envi-ronmental “corporate monitor” at BP.
BP Alaska spokesman Steve Rineharthas said the company typically doesn’tcomment on litigation.
National media reports say BP has beenbesieged with lawsuits in lieu of the Gulfdisaster. �
PETROLEUM NEWS • WEEK OF JUNE 6, 2010 13
� O I L P A T C H B I T S
Sitka marine launches new seismic boatGeokinetics Exploration, which recently acquired PGS Onshore, to take delivery of three specially built catamarans this summer
I n mid-May, Allen Marine launched a unique catamaranthat will be used by PGS Onshore, recently purchased
by Geokinetics Exploration, for seismic-related work in theBeaufort Sea this summer. It is the third such vessel theHouston-based Geokinetics has had the Sitka boat builderbuild, a contract that Allen Marine officials said wasapproaching $4 million.
The seismic work will be in the Canadian Beaufort Seaand managed by Geokinetics Canadian office. The Alaskaoffice will be sending some of its people with AlaskaBeaufort Sea experience to assist them. That PGS office ismanaged by Larry Watt, who will remain in the sameposition for Geokinetics.
On May 10 the third boat, the Geo Tiger II, underwenta brief sea trial at the Allen Marine’s Sawmill Creek Roadheadquarters.
A 64-foot aluminum boat with a split hull, the boat hasto be disassembled and placed onto trucks for the long tripnorth.
“It’s been a neat process, it’s totally different from whatwe normally do,” said Ken Baker, who managed the proj-ect for the Southeast Alaska boat building company.
Baker said Geokinetics wanted an entirely mobile fleet,and provided Allen with a design for boats that could bebroken down into pieces that could fit on standard ship-
ping trucks.Baker said the boats Allen recently completed could be
transported by truck, train, or even airplane.The catamarans are scheduled to leave Sitka June 7.
They will be barged to Skagway, and then loaded onto atruck for the drive north to Canada’s Beaufort Sea coast.
Due in Mackenzie Bay July 15The boats are due in Mackenzie Bay July 15. Once
there, a team of eight to 10 Allen workers, overseen byBaker, will put the boats back together.
Baker explained that the three boats will eventuallywork as part of a team. Each is equipped with two 600-horsepower motors, and the boats are designed to go 10 to11 knots.
The Geo Tiger II is a “gun boat” that will tow two largeskiffs equipped with “compressed-air shotguns.” The othertwo catamarans, line boats, will follow behind, layingcable.
The hull of each catamaran can be broken into threepieces. Each boat’s wheelhouse can also be removed, andbroken in two. Baker said each boat has about 4,000 con-necting bolts and two generators.
They’re designed to work in remote areas, and each isequipped with plenty of spare parts.
In February, Geokinetics purchased the onshore seismicdata acquisition and multi-client data library business ofPGS.
The acquisition, Geokinetics said, builds on itsstrengths in transition zone, ocean bottom cable and landvibroseis data acquisition and adds new operating areasincluding Alaska and Mexico, as well as certain new coun-tries in the Middle East and North Africa. �
—The Associated Press contributed to this article. Mostof the information came from an article by CraigGiammona, published in the Daily Sitka Sentinel.
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First, Enstar asked the RCA to approveconstruction of the proposed Anchor PointPipeline, but the RCA chose not to rule onthat matter in the current docket.
Second, the possibility for future con-flict remains. In a concurrent statement,RCA Commissioner Kate Giard notedthat if Armstrong ultimately needs a cer-tificate of public convenience and necessi-ty for the North Fork Pipeline, or Enstarneeds a state right-of-way lease for theAnchor Point Pipeline, state statute
requires a 30-day public comment period. Giard said Chevron’s comments “indi-
cate that there may be tension as to thelocation and routing” of a new pipeline,adding that “a contested applicationprocess will take longer to resolve.” Giardsuggested the two companies file applica-tions as soon as possible.
Enstar, meanwhile, insists it does notneed a right-of-way lease from the state,recently citing a newly passed state lawthat makes exceptions for extensions toexisting lines. �
gas into Pump Station 1, located at the BP-operated Prudhoe Bay oil field where thepipeline begins.
The gas surge occurred as BP workersused a cleaning pig to swab oil out of aPrudhoe transit line the company plannedto decommission because of corrosion. Theworkers were using pressurized gas to pushthe pig through the 34-inch line.
During the operation, the pig got stuckand a large volume of gas bypassed the tooland rushed to Pump Station 1.
The rapid influx of gas overpressuredtwo breakout tanks at the pump station, andthis caused relief vents and “blow out”hatches on the tanks to open and releaseflammable vapors, the Feb. 2 notice toAlyeska says.
“This event is an abnormal operation,”the notice says, a key finding that inPHMSA’s view triggered certain require-ments for Alyeska under pipeline safety
regulations.
Extremely serious eventThe gas release shut down Pump Station
1 for more than half an hour and forced theevacuation of some workers.
Jerry Brossia, a federal regulator in theJoint Pipeline Office in Anchorage, wasquoted in the Anchorage Daily News onFeb. 7, 2009, as saying the event had thepotential, at worst, to “burn Pump Station 1down.”
PHMSA contends Alyeska failed to fol-low its required procedural manual for han-dling abnormal operations and emergen-cies. The manual provides that theOperations Control Center controller “willverify system integrity and dispatchlinewide reconnaissance as appropriate,”PHMSA noted.
“After the overpressure of the … break-out tanks and subsequent vapor release,Alyeska did not verify and confirm systemintegrity before restarting the pipeline sys-tem,” the PHMSA notice of violation says.
“Furthermore, Alyeska did not conduct avisual inspection of the tanks before itrestarted the system. The vapor release andtank overpressure constituted a significantabnormal operation that could have harmedpipeline system integrity. Alyeska did notconduct a tank inspection until days afterrestarting the pipeline system.”
A compliance officer proposed a civilpenalty of $41,300 for the “probable viola-tion,” says the notice signed by ChrisHoidal, PHMSA’s Western Region directorin Denver.
Alyeska disagreesIn a March 10 response to PHMSA,
Alyeska says it believes it followed proce-dures.
“Alyeska disagrees that, as PHMSAalleges, ‘Alyeska’s Pump Station 1 breakouttanks, TK-110 and TK-111, were overpres-sured due to the rapid influx of natural gasinto the Trans Alaska Pipeline System.’Alyeska’s Incident Investigation Report,provided to PHMSA, specifically indicates
that ‘All automated systems and opera-tional protocols at TAPS PS 1 worked perdesign to shutdown the station and protectpersonnel and equipment.
“Further, Alyeska disputes that, asPHMSA alleges, ‘the breakout tank over-pressure and vapor release event’ wereabnormal conditions,” either under federalpipeline safety regulations or underAlyeska’s procedural manual.
Alyeska’s response concludes: “Alyeskarespectfully requests that PHMSA with-draw the finding and the proposed civilpenalty.”
Damon Hill, a PHMSA spokesman inWashington, D.C., told Petroleum News onMay 26 he couldn’t comment beyond thenotice of violation because “this case is stillan open enforcement action.”
Alyeska spokesman Michelle Egan,however, said Alyeska recently was con-tacted to schedule a hearing on the matter.
—WESLEY LOY
continued from page 1
PENALTY
monitoring and fixing corrosion in thepipeline that carries crude from the NorthSlope oil fields to the tanker port in Valdez.The oil in the pipeline accounts for about 10percent of U.S. oil production.
Federal pipeline regulators said they donot comment on pending cases but manydetails from the cases are available throughpublic records.
The pipeline agency’s largest unresolvedcase against Alyeska in the past five yearsincludes a $817,000 fine. The agency pro-posed the fine in 2007 after a series ofmishaps, including a storage tank fire, a900-gallon oil spill and a failed pipe clean-ing involving a device called a scraper pig.
The agency said the violations were“cause for concern regarding the operationalintegrity of TAPS.”
That 2007 case is still pending afterAlyeska challenged the agency’s major alle-gations in 2008 and asked for the penalty tobe withdrawn.
Out of the seven pending cases with finesattached that the pipeline agency has filedagainst Alyeska since 2006, the companyhas fully paid only one civil penalty —$56,000 levied in 2008 for Alyeska failing tomaintain records of repairs and not main-taining adequate corrosion protection on thepipeline near Glennallen.
In all, Alyeska faces proposed fines total-ing $1.4 million in the cases filed since2006.
The federal pipeline regulator said last
week it also has begun investigating theevents that led to an estimated 210,000-gal-lon oil spill Tuesday at Pump Station 9 nearDelta Junction. That spill is the largest forAlyeska since a Livengood man shot a holein the pipeline in 2001.
Damon Hill, a spokesman for the agency,said he couldn’t predict how long it will takefor the new case to be completed.
Some of the enforcement cases for whichAlyeska faces potential fines are as follows:
• Alyeska is accused of running a pipelinecorrosion test in May 2004 but not properlyanalyzing and reporting on its findings by a180-day deadline. The company also did notschedule an immediate repair for a dent inthe pipeline near Glennallen. The companycontested the allegations and later petitionedfor reconsideration of the agency’s decision,which set a final penalty at $263,000. Thecase is still pending.
• Pipeline regulators said Alyeska failedto test the cathodic protection — a metallayer that inhibits corrosion — at severalroad crossings by the required deadline andfailed to fix some problems discovered whenit later did the tests. The alleged violationsran from 2003 to 2006. The proposed fine is$170,000 and the case is listed as open withno other information.
• Alyeska is accused of not replacing“within a reasonable time” a pipe segment57 miles south of Prudhoe Bay where regu-lators were concerned about possible corro-sion. The pipe was scheduled for replace-ment in 2007 but the work was delayed. Forthat and several other alleged violations, reg-ulators proposed a $112,000 fine. Alyeskaagreed to replace the pipe but asked that theallegation be withdrawn. The case is still list-
ed as pending. One reason these cases have remained
unresolved for years is that Alyeska routine-ly disputes some allegations. Alyeska hasalso sought to reduce the size of the agency’sproposed fines, according to public filings.
Alyeska spokeswoman Michelle Egansaid the company sometimes disagrees withthe pipeline agency’s interpretation of regu-lations or disagrees with it on how to fix aproblem.
Even after a hearing, the pipeline agencycan take more than a year to issue a final rul-ing.
Egan said Alyeska pays a fine once theagency issues a final ruling.
The case involving the $263,000 pendingfine is a prime example of how long a casecan drag out.
In 2005, pipeline inspectors reviewedAlyeska records and found the two allegedcorrosion prevention violations.
In 2006, the pipeline agency proposed a$350,000 fine for the two violations.Alyeska contested the allegations and thesize of the fine. The pipeline agency held ahearing on the matter in 2007 and issued itsruling in January 2010. In its ruling, theagency reduced the penalty to $263,000.
Alyeska petitioned for reconsideration ofthe ruling. The company argued that the fineshould be cut more and that some of theagency’s findings were incorrect.
This March, the agency mostly deniedAlyeska’s petition and upheld the fine.
The status now: Alyeska said it has paid$90,000 and is contesting the rest of the fine.
The U.S. Fish and Wildlife Service has scheduled hearings on its proposed desig-nation of critical habitat for polar bear.
An Anchorage hearing will be held June 15 at the Z.L. Loussac Public Library; asecond hearing will be June 17 at the Inupiat Heritage Center in Barrow. Both hear-ings will be from 7-10 p.m., with the first hour a presentation on the draft economicanalysis for the proposed designation of critical habitat.
Public comments will be taken from 8-10 p.m. The June 17 hearing will be available by phone at 888-282-0437, pass code “polar
bear.” The proposed rule was published Oct. 29, 2009; a notice re-opening publiccomment was published May 5. Comments will be accepted through the end of busi-ness July 6.
Copies of the proposed rule and the draft economic analysis are available onlineat http://alaska.fws.gov/fisheries/mmm/polarbear/issues.htm.
CGGVeritas is committed to environmental responsibility in all our seismic operations. With experience working in some of the most sensitive regions of
Canada and the world, coupled with an industry-leading QHSE record, we can acquire your seismic data with minimum environmental impact.
Count on CGGVeritas to help you explore, develop and produce with confidence.
water” is defined as being deeper than 500feet.
The Liberty project would develop anOCS reservoir in federal jurisdiction usingultra extended reach drilling from theEndicott satellite drilling island, located instate waters.
BP plans to apply for drilling permits atLiberty “closer to the first developmentwell spud date, probably by fall,” accordingto local spokesman Steve Rinehart, whoadded “MMS has approved BP’sDevelopment and Production Plan for theLiberty project.”
He said BP hopes to have first oil pro-duction by 2011.
In addition to the moratorium on deep-water drilling, the Obama Administrationalso cancelled a pending lease sale in theGulf of Mexico and a planned lease sale offthe coast of Virginia, suspended 33exploratory wells currently being drilledand, most importantly for Alaska, suspend-ed two exploration programs planned forArctic waters this summer.
Those programs belong to Shell Oil,which planned to drill three wells in theChukchi Sea and two wells in the BeaufortSea this summer. Because of seasonaldrilling limitations, the suspension effec-tively pushes back those programs onewhole year.
Alaska added on to reportThe moratorium and other actions fol-
lowed a U.S. Department of the Interiorreport proposing safety measures after theDeepwater Horizon offshore drilling rigexploded in late April, causing a leak ofcrude oil from the ocean floor that remainsunstaunched.
That report, focused on safety issues inthe Gulf of Mexico, does not make recom-mendations about Alaska. The two Shellprojects would drill in about 150 feet ofwater, less than the 500-foot threshold forsuspension set out by the new moratorium.
“It was a decision made with an abun-dance of precaution. … It’s not exactly partof the 30 day report, but it’s related to it,”Quimby said about the “time out” forAlaska, as well as the cancellation of Lower48 lease sales.
He added that the DOI decision was nota denial of drilling permits, because Shellhad only announced its intention to drill thissummer, but had yet to file for drilling per-mits.
While Alaska is not examined in thereport, at least four Alaskans and formerAlaskans with engineering or drilling expe-
rience contributed to it as “expert consult-ants.”
Concerning the OCS exploration andproduction in general, the report makes rec-ommendations about blowout-preventers,well control systems and safety guidelines.
For all current and future OCS drilling,companies will be required to show thattheir safety plans meet the recommenda-tions outlined in the report. That comesfrom a June 2 announcement from BobAbbey, director of the Bureau of LandManagement and recently appointed actingdirector of the U.S. Minerals ManagementService.
Abbey also asked Congress to extend the30-day timeline for reviewing explorationplans to a 90-day timeline that can beextended if additional reviews are deemednecessary.
The DOI and the Council onEnvironmental Quality are reviewing howthe MMS uses “categorical exclusions” inreviews under the National EnvironmentalPolicy Act.
Shell: changes in place nowShell believes the recommendations “are
much like our global offshore drilling stan-dards,” according to a prepared statementfrom spokeswoman Kelly op de Weegh.
She said Shell uses “redundant safetysystems” to monitor wellbore pressure andtests its blowout preventers internally, inaddition to the testing required by regula-tion.
“We also utilize a set of practices, col-lectively called a Safety Case, which is alsorecommended in the DOI’s report. Shell’sSafety Case is a process drawn fromdecades of exceptional offshore perform-ance, state-of-the-art technology, peopleexpertise, and addresses the inherent risksin offshore exploration and production,” opde Weegh wrote.
The North Slope Borough, the munici-pality closest to the drilling, supported thedecision.
“The president did what he had to do,”Borough Mayor Edward Itta said in a pre-pared statement on May 27. “The spill hasconfirmed the many questions we haveabout safe practices and federal oversight.Everyone benefits from a delay at thispoint.”
Itta said the borough sent staff toWashington, D.C., to “get a better sense ofwhat our Congressional delegation is think-ing,” and planned to hear from the Alaskaheads of BP and Shell at an assembly meet-ing. “After that, we’ll decide on our futurecourse,” he said. �
continued from page 1
MORATORIUM
Drilling Morator ium Guidance Operations with Subsea BOP Stack – Water Depth Greater Than 500 Feet
Activity type 6 Month No Dr illing Morator ium Applies Drilling of new well Yes Wellbore Sidetrack on current drilling operations
Yes
Wellbore Bypass on current drilling operations
Yes
Workover Operations No Completion Operations No Abandonment Operations No Intervention (Non emergency) No Intervention ( Emergency) No Waterflood, Gas Injection, Disposal Wells
No
Operations with Sur face BOP Stack – Water Depth Greater Than 500 Feet
Drilling of new well Yes Wellbore Sidetrack on current drilling operations
Yes
Wellbore Bypass on current drilling operations
Yes
Workover Operations with stack No Completion Operations with stack No Abandonment Operations No Intervention (Non emergency) No Intervention (Emergency) No Waterflood, Gas Injection, Disposal Wells
development.”First Energy analyst Robert Fitzmartyn
said companies will have to more closelyexamine the numbers over the next fewweeks to decide whether to adjust theircapital budgets, but he is confident thatactivity will increase.
Saskatchewan lowers royaltyAs fast as Alberta brought in its regime,
the neighboring province of Saskatchewanlowered its maximum royalty rate to 2.5percent for the first 882 million cubic feetof gas produced from every horizontal welldrilled between June 1, 2010, and March31, 2013, in an effort to arrest a decline ingas drilling over the past seven years.
CAPP President David Collyer creditedthe government with delivering on its com-mitments to restore Alberta’s competitivestanding in North America by making per-manent a current incentive program royal-ty of 5 percent on new natural gas and con-ventional oil wells, which includes lower-ing the maximum royalty on conventionaloil to 40 percent from 50 percent and onboth conventional and unconventional nat-ural gas to 36 percent from 50 percent.
It has also offered incentives to startunlocking shale gas in Alberta, give a freshprod to the stalled coalbed methane sectorand to promote horizontal oil and gasdrilling.
The government estimated thatalthough the breaks might lower its royaltytake by C$1.5 billion that loss would bepartly offset by more than C$800 millionfrom increased land sales, tax revenues andoil patch activity.
Liepert: ‘nothing given away’Energy Minister Ron Liepert said
“there is nothing given away. We will berecovering a fair royalty return.”
“Industry and the investment communi-ty have asked for stability and predictabili-ty and that is what is being provided,” hesaid.
Liepert said the enhancements to thefiscal framework will allow new technolo-gies to be deployed, developing newresources and extending the life of existingconventional basins.
He said the objective is to promoteexploration and development of Alberta’sestimated 850 trillion cubic feet of poten-tial shale gas resources and 500 tcf ofpotential coalbed methane resources.
To recognize the higher costs and risksassociated with those emerging resourcesand technologies, the government isextending an up-front 5 percent royalty rateon a temporary basis, allowing operators torecover their costs.
Royalty regime changesAmong changes in the royalty regime,
Alberta will:• Set a maximum 5 percent royalty for
all new shale gas products for 36 produc-ing months. Charge a maximum royalty of5 percent over 18 months for productionfrom horizontal gas wells, setting a volumelimit of 500 million cubic feet equivalent.
• Impose a maximum 5 percent royaltyon horizontal oil wells or horizontal non-project oil sands wells, with volume andproduction limits tied to well depths.
• Set a maximum royalty of 5 percentfor all products from coalbed methanewells for 36 producing months, with vol-umes limited to 750 million cubic feetequivalent.
The new royalties will apply to wellsthat came on-stream on May 1 or later.
Program review in 2014The government promised it will review
the program in 2014 and will not terminateany elements without three years’ notice.
“Overall, it is very positive,” Collyersaid, adding the new regime has dealt withthe competitiveness issue, which has beenblamed for an exodus of billions of dollarsin upstream spending from Alberta toBritish Columbia, Saskatchewan and theUnited States.
On the shale gas front alone, Albertahas “lagged behind British Columbia andother jurisdictions,” he said.
Chris Seasons, president of DevonCanada and vice chairman of CAPP, fore-cast a 10 percent hike in capital spendingas a result of the incentives, placing hiscompany’s Alberta portfolio in the samecompetitive league “as anything we’ve gotacross North America.”
Gary Leach, executive director of theSmall Explorers and ProducersAssociation of Canada, said his membercompanies were “excited by the emergingtechnology and emerging resources pack-ages.”
“Hopefully, this will be a springboard toreducing the decline in conventional oilproduction and conventional natural gasand help us go after some of the reallyexciting potential resources, such as shalegas,” he said.
Peters & Co. said the approach is favor-able to mid-depth horizontal wells whichare rapidly accounting for a large chunk ofthe total well count, noting that horizontalwells have climbed from 12 percent in2009 to 26 percent so far this year.
However, it said that lowering the upperroyalty rates will affect only 12 of the 27identified plays in Alberta and estimatedthat commodity prices will need to morethan double from current levels for the newroyalties to have even a 10 percent positiveimpact.
Regulatory streamlining reportLiepert said the government plans to
release a progress report by mid-June on itsregulatory streamlining work — the thirdstep in the overhaul process that is beingtackled by the departments of energy, envi-ronment and sustainable resource develop-ment.
Collyer said that is an important step inimproving Alberta’s regulatory frameworkby blending environmental standards withgreater efficiencies.
Liepert also announced that new studiesare under way to support both industry andgovernment in the development of provin-cial resources.
The first will expand mapping, geolog-ical and resource knowledge of Alberta’sshale gas reserves and the second willexamine the enhanced recovery potentialof Alberta’s existing conventional oilresource pools that could “immenselyextend our total recoverable reserves” ifthey can benefit from the same technolog-ical advances that have unlocked shale gasand coalbed methane.
As well, Liepert said, the government isalready working with the industry on amature oilfield review for existingreserves, “trying to understand what tech-nological and economic incentives arerequired to get people to go back to thosefields.” �
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ALBERTA
“This changes the momentum,” saidKevin Banks, director of DNR’s Divisionof Oil and Gas. He noted, however, thatno one in DNR is ready just yet to pro-claim victory in the case.
High-stakes fightThe state since 2005 has been moving
to break up the Point Thomson unit andinvalidate the underlying leases ongrounds ExxonMobil and other lease-holders have failed after decades todevelop Point Thomson’s knownresources.
The leaseholders in turn have beenfighting the state through administrativeand court proceedings.
Point Thomson sits on state acreagesome 60 miles east of Prudhoe Bay, andis believed to contain 8 trillion cubic feetof gas and hundreds of millions of barrelsof petroleum liquids worth billions ofdollars.
In a ruling that came as a heavy blowto state officials, Gleason reversed DNRCommissioner Tom Irwin’s terminationof the Point Thomson unit and held thatthe leaseholders were wrongly denied anadministrative hearing under a key sec-tion of the unit agreement.
Attorneys for DNR, in appealing tothe Supreme Court, argued Gleason erredin nullifying Irwin’s unit termination.They also said her ruling would needless-ly force a very long, technical and expen-sive administrative hearing.
David Eglinton, a spokesman forExxonMobil in Houston, provided thisstatement to Petroleum News on theSupreme Court action: “ExxonMobil
remains confident in our position regard-ing the unit termination case. Our prefer-ence is to settle these issues directly withthe State to avoid protracted litigation andto put Point Thomson resources on pro-duction.”
Despite the court conflict,ExxonMobil, with Irwin’s permission, ismoving ahead with a limited gas cyclingdevelopment on two Point Thomson leas-es.
ExxonMobil in recent months hasdrilled a pair of wells and plans to testthem soon. The wells are part of a prom-ised $1.3 billion gas cycling project toproduce 10,000 barrels a day of conden-sate by year-end 2014.
Other major leaseholders at PointThomson include BP, Chevron andConocoPhillips.
Banks, in a May 28 interview withPetroleum News, said the shifting courtdecisions affect what have been ongoingtalks with ExxonMobil to try to resolvethe Point Thomson conflict.
“We’ve always been engaged withExxon,” he said. “The issues are prettycomplicated and any kind of agreementis going to have to work for both parties.”
A new kind of pressure is beginning tomount for both sides, as ExxonMobilsoon must place long lead-time orders tomeet its 2014 production goal. The itemsinclude extremely powerful, custom-designed compressors for pushing gasback down into the high-pressure PointThomson reservoir after condensates arecollected.
The company would like to knowwhere it stands overall on Point Thomsonbefore placing those costly orders. �
