l U T I L I T I E S

l G O V E R N M E N T

l P I P E L I N E S & D O W N S T R E A M

Vol. 24, No. 9 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 3, 2019 • $2.50

page10

Still two seasons for ANWR 10023-D seismic; no chance this winter

The very slim chance of a 3-D seismic survey being shotthis winter in the ANWR 1002 area (see Feb. 17 issue ofPetroleum News) has slipped to no chance, but the U.S. Fish& Wildlife Service is still going to allow two consecutive win-ter seasons to do the work, rather than just the one winter sea-son remaining on the initial proposed authorization.

Instead of starting the shoot this winter and finishing at theend of the second winter season in spring 2020, the new pro-posed Marine Mammal Protection Act incidental take regula-tion permit will allow seismic contractor SAExploration tobegin its program as early as December 2020 and finish in thespring of 2021.

There is other valuable geologic information coming from

Four gas wells online at KitchenLights but field still shut-in

In a recent Enstar Natural Gas Co. filing with the RegulatoryCommission of Alaska regarding Furie Operating Alaska’s prob-lems in delivering gas from its Kitchen Lights gas field in theCook Inlet, Enstar included an Oct. 31 report from Furie to Enstaron the results of its development drilling in the field during lastyear’s drilling season — Enstar has a gas supply agreement withFurie. The report confirms that Furie has now completed fourproduction wells in the field.

However, the field remains out of action as a consequence ofgas hydrates blocking the subsea pipeline that delivers gas fromthe offshore Julius R. platform to onshore processing facilities onthe Kenai Peninsula — Enstar told Petroleum News on Feb. 27

Devon heads for exit, joins flightfrom Canada by foreign firms

The exodus by foreign-based companies who have spentdecades in Alberta’s oil patch has moved into high gear withword from Devon Energy that it is open to offers for its oil sandsand heavy crude operations.

Carrying an estimated value of up to C$5 billion, the assetsinclude 121,000 barrels per day of production, largely from theJackfish thermal oil sands project and a smaller heavy oil venture.

In addition, the Oklahoma-based firm is seeking buyers for itsnatural gas unit in the Barnett Shale of Texas.

Devon’s decision to exit from Canada comes after years offailure by governments to approve new pipelines out of Albertaand gain access to world oil prices in Asia.

see ANWR SEISMIC page 12

see KITCHEN LIGHTS page 9

see FOREIGN EXODUS page 8

see FRENCH DISMISSED page 10

AOGCC: Dunleavy dismisses French;Forester to stay on temporarily

Gov. Mike Dunleavy dismissedAlaska Oil and Gas ConservationCommission Chair Hollis French Feb.26, following a public hearing earlier inFebruary and findings from the hearingofficer.

Commissioner Cathy Foerster, set toretire Feb. 28, told Petroleum News in anemail that she has been asked to stay onfor a bit until her position can be filled.AOGCC is a three-member commission,with two required for a quorum. French filled the public seat,

FERC reaches agreement on LNGexport project; 12 more in wings

Transco in offingRailbelt electricity transmission company applies to RCA for certificate

By ALAN BAILEYPetroleum News

Some of the Alaska Railbelt electric utilitiesand the American Transmission Co. have

formed the Alaska Railbelt Transmission LLC, orART, an electricity transmission company thatwould plan, operate, maintain, upgrade andfinance the electricity transmission network thatspans the Railbelt region.

ART has filed an application for a certificate ofpublic convenience and necessity with theRegulatory Commission of Alaska. The transmis-sion network is owned by six separate Railbeltelectric utilities and the state of Alaska: Currently

each utility manages and operates its own sector ofthe system.

ART told the RCA that the company’s imple-mentation of uniform system-wide transmission

An icebreaker is fundedAppropriations bill includes $655 million to build new polar security cutter

By ALAN BAILEYPetroleum News

The U.S. Congress has approved funding forthe construction of a new heavy polar ice-

breaker for the U.S. Coast Guard. The appropria-tions bill for fiscal year 2019, signed into law byPresident Donald Trump on Feb. 15, includes $655million for the construction of what is termed apolar security cutter, in effect a heavy icebreaker.

The appropriation follows the passage inAugust of a national defense authorization act,authorizing among other things the construction ofsix heavy polar-class icebreakers for the CoastGuard. The new appropriation accounts for thefirst of these vessels. In addition, the appropriationincludes another $20 million to cover the acquisi-

tion cost of long lead-time materials for the secondof the icebreakers.

New icebreakers neededCurrently the Coast Guard only operates two

Another Trans Mountain winEnergy board adds another 16 proposed recommendations to previous 156

By GARY PARKFor Petroleum News

For the second time in an estimated 1,010 days,Canada’s National Energy Board gave an

indisputable green light to the Trans Mountainpipeline expansion, TMX.

And again no one in the industry is inclined tobelieve that this is the final word and that construc-tion of the 590,000 barrels per day addition to thetransportation system from Alberta to the PacificCoast will proceed this year, regardless of the con-fident predictions by Alberta Premier RachelNotley and Canada’s Natural Resources MinisterAmarjeet Sohi that the C$9 billion project will becompleted.

In response to a directive last August from the

Federal Court of Appeal, the NEB reviewed its2016 recommendation for federal cabinet approvalof the pipeline twinning, delivering a 689-pagereport on Feb. 22, adding another 16 non-bindingrecommendations to the previous 156 conditions.

see RAILBELT TRANSCO page 12

see ICEBREAKER FUNDED page 11

see PIPELINE EXPANSION page 11

The company would charge standard feesfor the point-to-point delivery of

electricity from generation units to localdistribution networks, thus avoiding the

stacking or pancaking of separate fees bydifferent owners of different network

sectors, as happens at present.

Currently the Coast Guard only operatestwo polar capable icebreakers: the Healy,a medium duty icebreaker, much used asa base for polar research, and the PolarStar, which is a heavy icebreaker but is41 years old and nearing the end of its

operational life.

Eric Nuttall, a senior portfolio managerwith NinePoint Partners, said that if

Canadian oil producers can diversify theirmarkets investor fund flows should turn in

their favor again at a time when sharesare “trading at their lowest valuations in

generations.”

HOLLIS FRENCH

2 PETROLEUM NEWS • WEEK OF MARCH 3, 2019

GOVERNMENT

UTILITIES

EXPLORATION & PRODUCTION

NATURAL GAS

PIPELINES & DOWNSTREAM

4 Hilcorp requests Granite Point changes

6 US drilling rig count down 4 at 1,047

7 Solid waste treatment permit for GMT

7 State issues methane hydrate seismic permit

10 Preparations underway for Alkaid testing

7 BLM announces new Alaska state director

8 Exxon, Qatar Petroleum to expand LNG plant

6 PTEP settlement talks at FERC ongoing

10 FERC breakthrough on LNG certification

2 DNR inviting geothermal exploration

6 Electric car use growing in Alaska

Vehicles are expensive to buy but cheap to run; long distancedriving will require network of suitable charging stations

5 Court rules on Bradley Lake connection

Upholds view that RCA does not have jurisdiction overshipment of power from hydro facility through transmission line

ALTERNATIVE ENERGY

Transco in offingElectricity transmission company applies to RCA for certificate

An icebreaker is funded Bill includes $655 million to build new polar security cutter

Another Trans Mountain winEnergy board adds 16 more recommendations to previous 156

ON THE COVER

Still two seasons for ANWR 10023-D seismic; no chance this winter

AOGCC: Dunleavy dismisses French;Forester to stay on temporarilyFour gas wells online at KitchenLights but field still shut-inDevon heads for exit, joins flightfrom Canada by foreign firms

Petroleum News Alaska’s source for oil and gas newscontents

l A L T E R N A T I V E E N E R G Y

DNR inviting geothermal explorationAgency seeking applicants interested in exploration on 12 land tracts near Mount Spurr on the west side of the Cook Inlet

By ALAN BAILEYPetroleum News

Following a request for the nomination of land for inter-est in geothermal exploration, the Alaska Department

of Natural Resources’ Division of Oil and Gas is calling forapplications for exploration near Mount Spurr volcano onthe west side of Cook Inlet. The division is proposing toallow exploration on 12 tracts covering 28,800 acres of stateland on the flank of the mountain, about 40 miles west ofthe village of Tyonek.

Applications must be received by the division by 5 p.m.on March 21.

The concept would presumably involve finding suffi-cient subsurface heat for the generation of electricity.

Enticing targetLand near Mount Spurr is an enticing target for geother-

mal exploration, given the natural heat coming from activi-

ty within the volcano and the relative proximity to theAlaska Railbelt electricity grid — the Beluga power stationat one extremity of the grid is some 40 miles from the areaof exploration interest. A geophysical survey conducted inthe 1980s pointed to the possible existence of a layer ofwarm or hot brine 2,000 feet below a plateau at the entranceto the pass on the south flank of the mountain. There werealso geochemical indications of geothermal water in thearea.

And there has been previous geothermal interest in themountain.

Ormat explorationIn 2008 geothermal company Ormat Technologies

bought 15 leases on the mountain’s flanks. In 2009 the com-pany began evaluating the leases using various types of aer-ial survey, together with gravity and electromagnetic meas-urements. That led to the drilling of two core holes to depthsof 1,000 feet in 2010. The following year the company

brought in a drilling rig to drill to a depth of 4,000 feet.According to a report presented to the Alaska Senate

Resources Committee the deeper well encountered a rockthat does not hold heat particularly effectively. The wellencountered no hot water and subsurface temperatures nohigher than 140 F. There may also have been some mixingof geothermal fluid with cold glacial water from the sur-face, the company said.

Ormat planned further field work and drilling, perhapstesting the subsurface closer to the volcano’s crater.However, in February 2015 the company announced that itwas discontinuing its Mount Spurr venture, writing off the$7.3 million it had invested in the project.

Given the sparsity of the coring and drilling, it seemspremature to write off the geothermal potential of a loca-tion where there clearly must be subsurface heat. MountSpurr may yet prove a viable source of energy for theRailbelt.

see GEOTHERMAL INTEREST page 4

PETROLEUM NEWS • WEEK OF MARCH 3, 2019 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point, MPU M-12 Hilcorp Dreco 1000 UE 16 (SCR/TD) Standby Dreco D2000 Uebd 19 (SCR/TD) GTMU, CD5-24 ConocoPhillipsAC Mobile 25 Alpine CD2-162 ConocoPhillipsOIME 2000 141 (SCR/TD) Tinmiaq 16, Exploratory ConocoPhillips 142 (SCR/TD) Tinmiaq 10, Exploratory ConocoPhillips TSM 700 Arctic Fox #1 Pikka B Oil Search

Hilcorp Alaska LLC Rig No.1 Milne Point Hilcorp Alaska LLC

Kuukpik Drilling 5 Deadhorse Available

Nabors Alaska DrillingAC Coil Hybrid CDR-2 (CTD) Deadhorse 03-32BL1L2 BPAC Coil CDR-3 (CTD) Kuparuk 3M-26 ConocoPhillipsDreco 1000 UE 7-ES (SCR-TD) Kuparuk 2T-218 ConocoPhillipsMid-Continental U36A 3-S Stacked AvailableOilwell 700 E 4-ES (SCR) Stacked AvailableDreco 1000 UE 9-ES (SCR/TD) Stacked ConocoPhillipsOilwell 2000 Hercules 14-E (SCR) Deadhorse AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked Brooks Range Petroleum Oilwell 2000 Canrig 1050E 27-E (SCR-TD) Stacked Glacier Oil & Gas Oilwell 2000 33-E Deadhorse AvailableAcademy AC Electric CANRIG 99AC (AC-TD) Stacked RepsolOIME 2000 245-E (SCR-ACTD) Stacked ENIAcademy AC electric CANRIG 105AC (AC-TD) Pikka C ST1 Oil Search Academy AC electric Heli-Rig 106AC (AC-TD) Stacked Great Bear Petroleum

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Alpine ConocoPhillipsSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay AvailableIdeco 900 3 (SCR/TD) Winx exploration well Great BearRig Master 1500AC 4 (AC/TD) Oliktok Point ENI

Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay DS 18 BPNOV ADS-10SD 273 Prudhoe Bay DSW-59 BP

North Slope - Offshore

BPTop Drive, supersized Liberty rig Inactive BP

Doyon DrillingSky top Brewster NE-12 15 (SCR/TD) Spy Island NN-01 ENI

Nabors Alaska DrillingOIME 1000 19AC (AC-TD) Oooguruk Stacked Caelus Energy LLC

Cook Inlet Basin – Onshore

BlueCrest Alaska Operating LLCLand Rig BlueCrest Rig #1 Anchor Point, BlueCrest Alaska Operating LLC drilling production section of H14

Glacier Oil & Gas Rig 37 West McArthur River Unit Workover Glacier Oil & Gas

All American Oilfield LLCIDECO H-37 AAO 111 North Slope stacked Available

Aurora Well ServicesFranks 300 Srs. Explorer III AWS 1 Stacked out west side of Cook Inlet Available

Hilcorp Alaska LLCTSM-850 147 Stacked Hilcorp Alaska LLCTSM-850 169 Seaview Hilcorp Alaska LLC

Cook Inlet Basin – Offshore

Hilcorp Alaska LLCNational 110 C (TD) Platform C, Stacked Hilcorp Alaska LLC Rig 51 Steelhead Platform, Stacked Hilcorp Alaska LLC Rig 51 Monopod A-13, stacked Hilcorp Alaska LLC Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151, Moored in Kenai

Furie Operating AlaskaRandolf Yost jack-up Nikiski, OSK dock Available

Glacier Oil & GasNational 1320 35 Osprey Platform, activated Glacier Oil & Gas

Mackenzie Rig Status

Canadian Beaufort Sea

SDC Drilling Inc.SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available

Central Mackenzie ValleyAkitaTSM-7000 37 Racked in Norman Wells, NT Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of February 27, 2019.

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts* Feb. 22 Feb. 15 Year AgoUnited States 1,047 1,051 978Canada 212 224 306Gulf of Mexico 19 21 17

Highest/LowestUS/Highest 4530 December 1981US/Lowest 404 May 2016 *Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

By KRISTEN NELSONPetroleum News

H ilcorp Alaska LLC has applied to theAlaska Oil and Gas Conservation

Commission for amendments to the con-servation order governing production atthe Granite Point field in Cook Inlet.

The requested changes include a revi-sion in the description of the Middle Kenaioil pool, definition of a Hemlock oil pool,a revision of the rule on well spacing andauthorization for downhole comminglingof production.

The most recent production numbersfor the field, from AOGCC data forDecember, show an average of 2,702 bar-rels per day.

Hilcorp told the commission it propos-es to align the affected area of the GranitePoint field with the geographic boundaryof the recently expanded Granite Pointunit, which now consists of six state oiland gas leases, 15,411 acres, with opera-tions at the Anna, Baker and Granite Pointplatforms.

Hilcorp is the 100 percent workinginterest owner.

Crude oil and natural gas producedfrom the Anna, Bruce and Granite Pointplatforms is processed, metered andshipped from the Granite Point TankFarm, a 73-acre facility which is the pri-mary service and operation center for thethree platforms.

Hilcorp owns 100 percent of the sur-face estate and infrastructure at the GPTF.

Oil and gas produced from Anna runsvia subsea pipelines to a riser on the Bruceplatform and is transported from there toshore at the GPTF. Another subseapipeline system carries oil and gas fromthe Granite Point platform to the GPTF.

Oil is shipped from the GPTF via thenewly modified subsystem pipeline sys-tem to the Kenai Pipeline.

Discovery in 1960sHilcorp said Pan American Petroleum

Corp. acquired three oil and gas leaseswithin the Granite Point field in 1962; asingle lease at the field was acquired byUnion Oil Company of California andSocony Mobil Oil Co.

Oil was discovered in the Granite Pointfield in 1965 and the Anna, Bruce andGranite Point platforms were built in1966.

The field has produced oil and gas fromthe Tyonek and Hemlock formations sincethe mid-1960s.

AOGCC granted the first spacingexception at the field in 1967 and hasissued 17 additional spacing orders sincethen.

By 1991 Union had 100 percent inter-est in the three Pan American leases andbecame the lease operator of the fourGranite Point field leases and the threeplatforms; the company acquired twoadditional oil and gas leases in 1991.

In 1995 75 percent working interestwas transferred to Mobil Rocky MountainInc., later ExxonMobil Alaska ProductionInc.; and the three leases owned by Union,25 percent, and Exxon, 75 percent, wereunitized in 1998, becoming the SouthGranite Point unit, with Union as operator;the unit had 5,889 acres.

Hilcorp acquired the assets of Chevron,successor to Union, in 2012, and becameoperator of both the Granite Point andSouth Granite Point units. Later that year,Hilcorp became 100 percent WIO of theleases in the South Granite Point unit.

In 2014 the Department of NaturalResources approved expansion of theSouth Granite Point unit to include threenon-unitized operations associated withthe Anna and Bruce platforms, and theproposed unit, approved in 2015, became

the Granite Point unit.

Rules changes requestedAOGCC granted a request from

Hilcorp in 2014 to commingle productionbetween the Hemlock and Middle Kenaipools in the GP 11-13RD well, anapproval which extended the economiclife of the well and reduced waste.

Hilcorp noted that the commission con-cluded production from the Hemlock inthe GP 11-13RD was “very near its eco-nomic limit” and would have been aban-doned so that the Middle Kenai could beproduced. AOGCC said allowing com-mingling of production would allow someof the remaining 164,000 barrels ofreserves in the Hemlock to be recovered.

In its current request, Hilcorp said whatit is proposing would “prevent waste, pro-tect correlative rights and improve the ulti-mate recovery of remaining hydrocarbonsthroughout the Granite Point Field,” whilealso reducing administrative burdens onboth the company and commission staff.

“By eliminating the spacing restric-tions at the Granite Point Field horizontalwells can be drilled in the stacked sands ofthe Middle Kenai Oil Pool,” Hilcorp said.

“Historical drilling of horizontal wellsat the Granite Point Field have proven toimprove the ultimate recovery of thefield,” the company said, in support of itsrequest that spacing restrictions beremoved, allowing for “the decreasing ofwell spacing through the drilling of hori-zontal wells that will improve the ultimaterecovery.”

Hilcorp’s said its request to allow com-mingling of production from the MiddleKenai and Hemlock oil pools “will allowsingle zone Hemlock and/or Middle KenaiOil Pool wells that are at or near their eco-nomic limit to continue to be produced,therefore improving ultimate recovery ofthe Granite Point Field.”

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

Hilcorp requests Granite Point changesAsks AOGCC to amend pool rules, removing spacing requirements and allowing commingling of Middle Kenai, Hemlock production

4 PETROLEUM NEWS • WEEK OF MARCH 3, 2019

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Mount AugustineOn this occasion the state is not offer-

ing geothermal exploration opportunitieson the flanks of Mount Augustine, anoth-er volcano on the west side of the CookInlet. Presumably no one has nominated

this area for potential exploration. MountAugustine, while having obvious geother-mal potential, suffers from the disadvan-tage of being situated a long way from thenearest electricity infrastructure —Beluga is 150 miles to the northwest andNikiski is 112 miles away, on the east sideof the inlet. l

continued from page 2

GEOTHERMAL INTEREST

Hilcorp’s said its request to allowcommingling of production from

the Middle Kenai and Hemlock oilpools “will allow single zone

Hemlock and/or Middle Kenai OilPool wells that are at or near their

economic limit to continue to beproduced, therefore improving

ultimate recovery of the GranitePoint Field.”

see GRANITE POINT page 5

PETROLEUM NEWS • WEEK OF MARCH 3, 2019 5

(907) 562-5303 | akfrontier.com

Safety Health Environment Quality

THE TEAM THAT

DELIVERSField in decline

Hilcorp also said there have been no sig-nificant changes in pool rules for theGranite Point field for nearly 45 years.“Since that time, production from the field,and in particular the Middle Kenai OilPool, has been continuous, but in steadydecline,” the company said.

“While existing rules may have ade-quately protected correlative rights of thislegacy field’s original owners, and prevent-ed waste during the field’s initial develop-ment, they are not appropriate to theenhanced recovery effort necessary to pro-duce remaining hydrocarbon reserves,”Hilcorp told the commission.

The company said it purchased the lega-cy assets with the intent of maximizingrecovery of remaining hydrocarbons,requiring “a comprehensive capitalworkover program” to repair broken injec-tion wells; return shut-in production wellsto service; optimize existing well comple-tions; increase water injection and reservoirthroughput; pursue stimulation opportuni-ties; and identify and then execute newdrilling projects.

Hilcorp said the amendments it is pro-posing would give it “more developmentoptions to improve the ultimate recovery ofthe field.”

The commission has tentatively sched-uled a public hearing on the application forApril 4 at 9 a.m. but said if there are no time-ly requests for a hearing filed, it may consid-er issuing an order without a hearing. l

continued from page 4

GRANITE POINT

By ALAN BAILEYPetroleum News

In a Feb. 22 opinion, the AlaskaSupreme Court upheld a Superior

Court decision, ruling that the RegulatoryCommission of Alaska does not havejurisdiction over tariffs for the carriage ofpower from the Bradley Lake hydropowerfacility on a transmission line betweenSoldotna and Quartz Creek on the KenaiPeninsula. The court ruling impacts thecost of Bradley Lake power, which is usedby the Alaska Railbelt electricity utilitiesas part of their power supply mix.

Homer Electric Association, owner ofthe line, had filed a tariff for the shipmentof Bradley Lake power on the line. TheRCA had accepted the tariff filing but hadsuspended the tariff, pending an investiga-tion into the rates that HEA wanted tocharge. But other Railbelt electric utilities,the Alaska Energy Authority and the stateof Alaska Attorney General’s Office hadappealed the RCA’s right to adjudicate thetariff, saying that the tariffs for BradleyLake power transmission should be set bythe committee that oversees the operationof the Bradley Lake system. The courtshave now upheld that appeal.

The Bradley Lake facility, in the south-ern Kenai Peninsula, is a reliable source ofrelatively cheap electricity for the utilitiesthat use the Alaska Railbelt electricitygrid. The Alaska Energy Authority, a stateagency, owns the facility, which is operat-ed under contract by Homer ElectricAssociation and managed by a committee,the Bradley Project Management

Committee, or BPMC, consisting of rep-resentatives of the Railbelt electricity util-ities and AEA.

HEA transmission systemHEA owns the transmission system

that transports power from Bradley Lakeacross the western part of the KenaiPeninsula. In particular, an HEA line con-nects Bradley Lake to an HEA-ownedsubstation at Soldotna, in the interior ofthe peninsula. Another line, referred to asthe S/Q Line connects the Soldotna sub-station to a substation owned by ChugachElectric Association at Quartz Creek.Chugach Electric handles the shipment ofBradley Lake power from HEA’s trans-mission system, through ChugachElectric’s transmission system, for use byChugach Electric and on behalf of otherutilities that purchase Bradley Lakepower.

Until relatively recently ChugachElectric leased the Soldotna substationfrom HEA, with Chugach Electric meter-ing the Bradley Lake power throughput atSoldotna, for acceptance into the ChugachElectric network. But, following the expi-

ration of the Soldotna lease in January2014, HEA took over operation of thesubstation, removing Chugach Electric’smetering system and, in effect, movingChugach Electric’s acceptance point forBradley Lake power to Quartz Creek.

Under a series of agreements for theoperation of Bradley Lake, HEA under-takes to ship Bradley Lake power toSoldotna, while Chugach Electric shipsthe power from Soldotna to Quartz Creek,and hence into its own transmission net-work. The BPMC sets rates for the trans-mission of Bradley Lake power throughHEA’s system, to compensate HEA for theuse of its system.

Tariff filingsIn November 2013, in anticipation of

the expiration of the lease on the Soldotnasubstation, HEA filed two tariff letterswith the RCA, one for the claiming of lineloss costs associated with the transmissionof Bradley Lake power, and the other forsetting a tariff for the shipment of poweron the S/Q line between Soldotna andQuartz Creek. The commission rejectedthe line loss filing but agreed to review thetariff filing, saying that the Bradley Lake

agreements did not appear to address whatwould happen when the lease on theSoldotna substation expires.

Several of the utilities protested theRCA decision. And the BPMC took aposition that the Bradley Lake agreementswere not impacted by the expiration of theSoldotna lease, that Chugach Electric hasthe right to ship Bradley Lake power overthe S/Q line and that HEA is adequatelycompensated for the use of the line underthe terms of the agreements.

The utilities protesting the RCA posi-tion appealed the commission’s decisionin Superior Court. Observing that theBradley Lake agreements were signedafter the Soldotna substation lease hadalready gone into effect, the SuperiorCourt ruled, and the Supreme Court hadnow agreed, that the RCA does not havethe authority to review or determine therates for shipping Bradley Lake powerbetween Soldotna and Quartz Creek. Nordoes the commission have the authority toadjudicate over line losses associated withthe shipment of the power on HEA’s sys-tem, the courts have now ruled. l

l U T I L I T I E S

Court rules on Bradley Lake connectionSupreme Court upholds view that RCA does not have jurisdiction over shipment of power from hydro facility through transmission line

Under a series of agreements forthe operation of Bradley Lake,

HEA undertakes to ship BradleyLake power to Soldotna, while

Chugach Electric ships the powerfrom Soldotna to Quartz Creek,

and hence into its owntransmission network.

6 PETROLEUM NEWS • WEEK OF MARCH 3, 2019

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EXPLORATION & PRODUCTIONUS drilling rig count down 4 at 1,047

The number of rigs drilling for oil and natural gas in the U.S. was down by fourthe week ending Feb. 22 to 1,047.

Last year at this time there were 978 active rigs. Houston oilfield services company Baker Hughes reported that 853 rigs target-

ed oil (down four from the previous week) and 194 targeted natural gas(unchanged).

The company said 68 of the U.S. holes were directional, 916 were horizontaland 63 were vertical.

Among major oil and gas producing states, Alaska and California were each upby one rig.

North Dakota and Wyoming were unchanged. Colorado, New Mexico and Texas (the most active state with 508 rigs) were

each down by one rig. Louisiana and Oklahoma were each down by two rigs. Baker Hughes shows Alaska with 13 active rigs, up from nine a year ago. The U.S. rig count peaked at 4,530 in 1981. It bottomed out in May 2016 at 404.

—PETROLEUM NEWS

PTEP settlement talks at FERC ongoingThe Regulatory Commission of Alaska has

extended a suspension of its proceedings onthe tariff for the Point Thomson export line byone year.

RCA said Feb. 25 that counsel for theAlaska Attorney General, Regulatory Affairsand Public Advocacy Section, advised thecommission that settlement discussions in therelated Federal Energy RegulatoryCommission case dealing with the proposed increase in the tariff for PTE PipelineLLC are “showing signs of progress” and RAPA, on behalf of the parties, requestedan extension of the suspension in the docket. The existing suspension was due toexpire March 1.

The issue is a proposed increase in the Point Thomson Export Pipeline tariff. LastJuly PTEP LLC filed a revenue requirement study and proposed an increase in the tar-iff for intrastate shipments of condensate from $12.09 per barrel — established by asettlement — to $20.84 per barrel.

Based on progress in the FERC settlement discussions for the interstate rates, RCAsaid it is extending the tariff suspension for an additional year, ending March 1, 2020.The parties had requested a six-month suspension of the docket and said they wouldjointly file a progress report no later than May 31.

When PTEP proposed an increase in its rate the state protested, calling the pro-posed rate “unjust and unreasonable” citing lack of data on a number of issues.

In August RCA suspended the new rate for an initial period of six months and saidPTEP could collect the proposed new rate, “subject to refund of the differencebetween the temporary rate and the rate we establish at the conclusion of this proceed-ing plus interest.”

In response to the state’s challenge, PTE said its proposed equity risk premium wasbased on risks greater than a pipeline proxy group and the single throughput source ofthe pipeline, the Point Thomson unit (see stories in Aug. 12 and Sept. 9 issues ofPetroleum News).

—KRISTEN NELSON

PIPELINES & DOWNSTREAM

Based on progress in theFERC settlement discussionsfor the interstate rates, RCAsaid it is extending the tariffsuspension for an additionalyear, ending March 1, 2020.

l A L T E R N A T I V E E N E R G Y

Electric car usegrowing in AlaskaThe vehicles are expensive to buy but cheap to run; long distancedriving will require network of suitable charging stations

By ALAN BAILEYPetroleum News

With the number of models of electri-cally powered cars steadily increas-

ing, some people are predicting a rapidtransition away from traditional gasolinefueled vehicles. And Alaska appears to beseeing a steady growth in electric car use,albeit from a low start.

Sean Skaling, manager of business andsustainable program development forChugach Electric Association, told theAlaska Forum on the Environment on Feb.11 that it appeared that the number of vehi-cles purely powered by electricity in theAnchorage area has grown from 50 lastsummer to around 94 at present. There areabout 575 electric cars in the state as awhole. The use of electric vehicles is partic-ularly popular in the Juneau area, wheremileage range is not a worry and there isalso a network of vehicle charging stations.

Typically, for use in and around an urbanarea, an electric car owner will charge theircar at home overnight and have plenty ofmileage range for day-to-day use.

High energy efficiencySkaling said that the basic benefit of an

electric car is its very high energy efficien-cy, leading to relatively low running costs.

“About 80 percent of the energy that youput into the vehicle is used for propulsion,as opposed to a gasoline engine where it’smore like 30 percent,” Skaling said.

Low maintenance costs, with no needfor oil changes for example, also pushdown the running costs. And with instanttorque from the electric motor, an electriccar is fun to drive, Skaling said.

In Anchorage, based on the typical costof electricity and gasoline, the cost per mileof an electric vehicle works out at abouthalf that of a gasoline car. In cold winterweather, however, the need to use some of

the electricity from the battery to heat theinside of the car reduces that efficiency.Skaling said that, based on his experienceof electric car use, it appears that in temper-atures of around 5 F the vehicle’s rangedrops by about 40 percent relative towarmer weather, with the fall in rangeappearing to flatten out at still lower tem-peratures.

Total ownership costOne deterrent to the purchase of an elec-

tric car is the high car prices, with perhapsup to half of the car’s cost being the cost ofthe battery. However, this high up-frontcost can be offset by the low running costswhen calculating the total cost of owner-ship over a period of a few years. And thecost of the batteries is falling.

It appears that in, say, the Anchoragearea a major deterrent to electric car pur-chase is concern about car mileage rangeand the lack of a recharging infrastructurefor people who want to drive long distancesfrom town. Skaling said that the Railbeltelectric utilities are working with people tofigure out optimum locations for chargingstations around the state’s road system.

Funding for charging stationsBetsy McGregor from the Alaska

Energy Authority told the forum that AEAis going to disburse some of the money that

Betsy McGregor from the AlaskaEnergy Authority told the forum

that AEA is going to disbursesome of the money that it has been

allocated from a settlement withVolkswagen to help fund an

electric vehicle charging networkin Alaska.

see ELECTRIC CARS page 7

PETROLEUM NEWS • WEEK OF MARCH 3, 2019 7

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EXPLORATION & PRODUCTIONSolid waste treatment permit for GMT

The Alaska Department of Environmental Conservation has published a publicnotice for a solid waste treatment permit for ConocoPhillips Alaska’s GreaterMooses Tooth.

ADEC said the permit application for the operation of two grind and injectfacilities and accompanying temporary storage cells is complete and said it is pro-posing to issue a comprehensive solid waste permit to include both facilities.

Unit 1 will operate at pads in the Greater Mooses Tooth unit and the ColvilleRiver unit; unit 2 will be located at CD1, the main pad, in the Colville River unit.

ADEC said the permit will include the existing mobile G&I facility, a new sta-tionary G&I facility and associated temporary storage cells. The facilities will beoperated for storage and treatment of drilling waste and non-hazardous petroleumcontaminated soil prior to injection into a permitted underground injection controlwell.

Comments are due before 5 p.m., March 28. Greater Mooses Tooth is in the National Petroleum Reserve-Alaska.

Production began from GMT-1 in early October. A joint record of decision for GMT-2 by the federal Bureau of Land

Management and the U.S. Army Corps of Engineers was issued Oct. 15. Threeconstruction seasons are planned, beginning with gravel laying in early 2019 andfirst oil anticipated in the fourth quarter of 2021.

—KRISTEN NELSON

BLM announces new Alaska state directorThe U.S. Bureau of Land Management has announced the appointment of

Chad Padgett as the new director of the agency’s Alaska office. Padgett replacesActing State Director Ted Murphy.

For the past 10 years Padgett has served as Alaska state director inCongressman Don Young’s Anchorage office. From 2001 to 2009 he served as theAlaska state executive director for the U.S. Department of Agriculture’s FarmServices Agency, developing policies and a budget for Alaska, while also plan-ning, administering and directing programs and activities for the state. For twoyears Padgett took on the dual role of acting state director for USDA rural devel-opment, managing rural housing programs; community facilities; business andcooperative programs; and rural utilities programs throughout Alaska, BLM said.

Earlier in his career Padgett had also worked in Young’s office for a seven-yearstint, including six years as deputy district director for Alaska. As deputy directorhe oversaw the operation of five offices based in Alaska while also working close-ly with many federal agencies including BLM. Padgett has a bachelor’s degree inpolitical science and international relations from Boise State University, BLMsaid.

BLM also announced the appointment of Michael Nedd as BLM director ofoperations, overseeing more than 6,000 federal employees, mostly located in 14western states.

—ALAN BAILEY

GOVERNMENT

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it has been allocated from a settlement withVolkswagen to help fund an electric vehiclecharging network in Alaska. The settlementresults from cheating by Volkswagen overthe testing of emissions from its dieselvehicles. AEA has filed an emissions miti-gation plan with the trustees for the settle-ment. As part of the plan AEA is going to

make available matching funds for differentsectors of the road system, for entities inter-ested in installing vehicle charging sta-tions. The agency is trying to establish anelectric vehicle working group — theRailbelt electric utilities and theMunicipality of Anchorage have beenproactive in their participation,McGregor said. l

continued from page 6

ELECTRIC CARS

EXPLORATION & PRODUCTIONState issues methane hydrate seismic permit

Alaska’s Division of Oil and Gas has issued a land use permit toSAExploration Inc, allowing the company to conduct a seismic survey for themethane hydrate test well that was drilled in the Prudhoe Bay unit in December.The idea is to obtain a vertical seismic profile for the well, as part of a project todetermine whether methane hydrates can become a technically and commerciallyviable unconventional natural gas resource.

The well was drilled from a small, existing gravel pad in the western part ofthe Prudhoe Bay unit. The U.S. Department of Energy has said that its NationalEnergy Technology Laboratory formed a partnership with Japan Oil, Gas andMetals National Corp., the U.S. Geological Survey and Petrotechnical Resourcesof Alaska for the drilling of the well. BP, operator of the Prudhoe Bay unit, over-saw the drilling. The purpose of the well is to conduct long-term tests of gas pro-duction from hydrates in the subsurface.

The division says that a geophone for recording the seismic signals was placeddownhole in the well during the drilling operations and that no geophones will beplaced on the tundra. Four vibrator units, operating in pairs, will move in a circu-lar pattern around the project area to generate the seismic signals.

Methane hydrate is a solid in which molecules of methane, the primary com-ponent of natural gas, are concentrated inside a lattice of water molecules. Hugequantities of the material, which remains stable within a certain range of relativelyhigh pressures and low temperatures, are known to exist around the base of thepermafrost under the North Slope. It is thought that natural gas could be producedthrough some combination of elevating the temperature or reducing the pressurein a hydrate reservoir, but the long-term technical and economic feasibility of thisprocess has yet to be demonstrated.

—ALAN BAILEY

8 PETROLEUM NEWS • WEEK OF MARCH 3, 2019

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Better.

It follows an unloading of oil sandsassets by Royal Dutch Shell, Norway’sEquinor (formerly Statoil), ConocoPhillips,Murphy Oil and Marathon Oil. Spain’sRepsol is expected to be next in line.

Michael Dunn, an analyst with GMPFirstEnergy, said the flight from Canada isproof that foreign players are certain theycan generate cash more quickly and for lesscapital investment by “adjusting their strate-gies.”

He said Texas is “beating Alberta onfield-level economics and on egress. Theflavour of the day is definitely not the oilsands.”

The proof of Alberta’s dwindling appealoccurred in January when MEG Energyspurned a hostile takeover bid by HuskyEnergy for C$6.4 billion, certain it couldattract a better price.

As a result, the Beijing-controlled com-pany, which is producing 100,000 bpd fromits Christina Lake oil sands operation, isnow left feeling unwanted.

Dave Hager, Devon’s chief executiveofficer, said that if his firm can close a dealit will transform into a purely U.S. oil andgas producer, concentrating on shale assetssuch as Eagle Ford in Texas and Stack inOklahoma.

But he was adamant that Devon will “notgive (the Alberta) asset away,” saying suchofferings “don’t come to market every day.”

Analysts believe four of the largest oilsands producers — Husky, Suncor Energy,Imperial Oil and Canadian NaturalResources — will likely do a detailedassessment of Jackfish and the heavy oiloperations in east-central Alberta. Becauseof its focus on reducing a large debt load,Cenovus Energy is thought to be out of therunning.

However, most experts are cautiousabout the chances of a deal being done.

Devon, which has 750 employees, 400of them in Calgary, started its pullback fromCanada in 2014 when it sold natural gasoperations in Western Canada to CanadianNatural for C$3.1 billion, then two yearslater sold its 50 percent stake in the Accessoil sands pipeline to Wolf Midstream forC$1.4 billion.

—GARY PARK

continued from page 1

FOREIGN EXODUS

l N A T U R A L G A S

Exxon, Qatar Petroleum to expand LNG plantBy DAVID KOENIG

Associated Press Business Writer

ExxonMobil is making a big bet on the future ofexporting natural gas.

Exxon and Qatar Petroleum announced Feb. 5 thatthey will go ahead with a $10 billion project to export liq-uefied natural gas from a plant on the Texas Gulf Coast.

The companies said construction at the Golden Passplant in Sabine Pass, Texas, would start before April, andthe export operation is expected to begin running in2024.

Exxon said the project will create 9,000 jobs duringthe five years of construction and more than 200 perma-nent jobs. Exxon Chairman and CEO Darren Woods saidit would provide a long-term supply of liquefied naturalgas and stimulate the local economy.

Built to import gasThe Golden Pass plant opened in 2010 to import gas

that has been chilled into liquid form, allowing it to beloaded on to tankers for shipment. Its backers saw a mar-ket in importing natural gas, a cleaner fuel than oil.

As U.S. gas production soared in this decade, howev-er, with much of it coming from the Permian Basin in

west Texas and New Mexico, Exxon and others studiedways to boost sales by using the suddenly abundant sup-ply to meet surging global demand.

Globally, annual trade in liquefied gas grew fasterthan 10 percent in both 2017 and 2018, according to theInternational Energy Agency. Demand has been growingfastest in Asia, especially in China, but European coun-tries are also interested in stepping up imports as a wayto diversify their energy supply and reduce their relianceon Russian gas.

Trade expected to growTrade in liquefied gas is expected to rise by more than

two-thirds in the next 20 years, said Jean-BaptisteDubreuil, an analyst with the Paris-based group.

“It will be instrumental in the evolution of natural gastoward a more diversified, flexible and global market,”Dubreuil said.

The Texas project is expected to be the first of manysimilar announcements by energy companies this year.

Dubreuil said others are expected to come from the U.S.,Russia, Africa, and Qatar.

Exxon and Qatar Petroleum say the export facility inTexas will be able to produce about 16 million tons ofliquefied gas per year.

Qatar Petroleum owns 70 percent of the export projectand Exxon holds the other 30 percent after agreeing tobuy out ConocoPhillips’ 12.4 percent stake in the exist-ing liquefied natural gas import terminal and pipeline.That purchase is awaiting regulatory approval.

Exxon and Qatar Petroleum have worked together onexploration and development projects in Argentina,Brazil and Mozambique. Qatar Petroleum, a leadingexporter of liquefied natural gas, has announced plans toinvest $20 billion in the U.S. as it seeks to continueexpanding beyond its home borders.

At an event in Washington, Energy Secretary RickPerry called the announcement “the latest example of thevital partnership between the U.S. and Qatar,” includingmilitary ties and American colleges opening campuses inQatar.

On Jan. 1, Qatar left OPEC after a nearly two-yeartrade embargo against it by the oil cartel’s leader, SaudiArabia, and the United Arab Emirates, Bahrain andEgypt. l

Globally, annual trade in liquefied gas grewfaster than 10 percent in both 2017 and 2018,according to the International Energy Agency.

PETROLEUM NEWS • WEEK OF MARCH 3, 2019 9

Oil Patch Bits

ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS

Companies involved in Alaska’s oil and gas industry

All of the companies listed above advertise on a regular basis with Petroleum News

AAfognak Leasing LLCAirgas, an Air Liquide companyAK LoftAlaska Energy Services, LLCAlaska Dreams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12Alaska Frac Consulting LLCAlaska Frontier Constructors (AFC) . . . . . . . . . . . . . . . . . . . .5Alaska Marine LinesAlaska MaterialsAlaska RailroadAlaska Rubber & Rigging Supply Inc.Alaska Steel Co.Alaska Tent & TarpAlaska Textiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Alaska West ExpressAlpha Seismic CompressorsAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11Arctic ControlsARCTOS Alaska, Division of NORTECHArmstrongASRC Energy ServicesAT&TAvalon DevelopmentAviator Hotel

B-FBombay DeluxeBPBrandSafway Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Brooks Range SupplyCalista Corp.CarlileChosen ConstructionColville Inc.

Computing Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6CONAM ConstructionCruz ConstructionDenali Universal Services (DUS)Doyon AnvilDoyon AssociatedDoyon DrillingDoyon, Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6exp Energy ServicesF. R. Bell & Associates, Inc.FairweatherFlowline AlaskaFluor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Foss MaritimeFugro

G-MG COMMGeotempsGMW Fire ProtectionGreer Tank & WeldingGuess & Rudd, PCICE Services, Inc.InspirationsJudy Patrick PhotographyLittle Red Services, Inc. (LRS)Lounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMapmakers of AlaskaMaritime Helicopters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2Motion & Flow Control Products

N-PNabors Alaska Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Nalco ChampionNANA WorleyParsonsNature Conservancy, TheNEI Fluid TechnologyNordic Calista . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7North Slope TelecomNorthern Air CargoNRC Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12Oil Search . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Opti StaffingPacific Power GroupPENCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11Petro Star LubricantsPetroleum Equipment & Services, Inc.PRA (Petrotechnical Resources of Alaska)Price Gregory International

Q-ZRaven Alaska – Jon AdlerResource Development CouncilSAExplorationSecurity AviationSourdough ExpressStrategic Action AssociatesSummit ESP, A Halliburton Service . . . . . . . . . . . . . . . . . . . .4Tanks-A-LotThe Local PagesTOTE – Totem Ocean Trailer ExpressVolant ProductsWeston Solutions

Fluor awarded Halliburton project in Saudi ArabiaFluor Corp. announced Feb. 20 that it

was awarded the engineering, procure-ment and construction of the Halliburtonspecialty chemicals manufacturing reac-tion plant located in the PlasChem Park,Jubail, Saudi Arabia. Fluor booked theundisclosed contract value in the fourthquarter of 2018.

“Having completed the front-endengineering design, we are pleased toundertake the design and construction ofthis major investment that acceleratesHalliburton’s strategic expansion of itsfast-growing specialty chemicals business,” said Simon Nottingham, president of Fluor’senergy and chemicals business in Europe, Africa and the Middle East. “Fluor will use its fullintegrated solutions portfolio and its local execution capabilities to optimize the designand deliver a capital-efficient project with schedule certainty.”

The new chemicals facility will produce a wide range of specialty chemical products andintermediates to supply both the upstream and downstream oil and gas production indus-tries. Fluor’s scope includes engineering, procurement, construction and commissioning.

Fluor’s Al Khobar office in Saudi Arabia will lead the project with the team that per-formed the previous front-end engineering design contract and will be supported by Fluor’s

global chemicals experts.

Nabors appoints Anthony Chase as a director Nabors Industries Ltd. announced Feb. 25 that it has expanded its board to seven mem-

bers and appointed Anthony R. “Tony” Chase to fill the vacancy. Chase is the chairman andchief executive officer of ChaseSource L.P., a Houston-based staffing and real estate devel-opment firm. He was a founder of mobile phone provider Cricket Wireless and ChaseCom,L.P., a global customer relationship management and staffing services company, until itssale to AT&T Inc. in 2007. Chase has served as a director of both Anadarko Petroleum Corp.and Paragon Offshore plc since 2014.

He is a tenured professor of law at the University of Houston Law Center, where hebegan teaching in 1990, and has published numerous law review articles during his tenure.Chase is on the board of directors of the Texas Medical Center, M.D. Anderson Board ofVisitors and the Greater Houston Partnership, serving as its chairman during 2012. He isalso a trustee of the Houston Endowment, and serves on the board of trustees for St.John’s School and KIPP Schools. Chase graduated with honors from Harvard College andsubsequently earned M.B.A. and J.D. degrees from Harvard Business School and HarvardLaw School, respectively.

Anthony Petrello, Nabors’ chairman, CEO and president, commented, “We are verypleased to have Tony join the Nabors Board of Directors. His appointment reflects our con-tinued commitment to adding highly qualified, independent directors with strong back-grounds and relevant experience. Tony brings a wealth of experience and talent that canonly benefit Nabors and our shareholders.”

CO

URT

ESY

FLU

OR

that it is still not receiving any gas from Furie. As previous-ly reported in Petroleum News, Furie has not delivered anygas to Enstar since Jan. 25. Enstar has issued a defaultnotice to the gas producer, indicating that the gas supplyagreement with Furie would be terminated if the supplyproblem is not resolved.

On Feb. 20 Furie indicated to Petroleum News that itanticipated being able to restart Kitchen Lights productionshortly.

Four wells completedDuring the 2018 drilling season Furie re-entered and

completed the KLU A-1 development well and drilled anadditional development well, the KLU No. 4. The result isthat the company now has four wells capable of gas produc-tion.

According to Furie’s report to Enstar the eventual

drilling success in 2018 came after some drilling issues thathad pushed the drilling program right to the end of thedrilling season. Furie reported that it had also gone beyondits commitments in its development plan by drilling an“exploration tail” from the A-4 well, into the Tyonek forma-tion, below the Beluga formation, from which gas produc-tion is to come. It appears from the report that, although thedrilling into the Tyonek was completed, the findings in theTyonek proved disappointing.

However, as a consequence of the drilling and of theoptimization of production from the two other KitchenLights production wells, Furie will be able to meet thedemand specified in the company’s gas supply agreement,Furie’s report said. And the company said that it remainscommitted to expanding the gas reserves potential withinthe Kitchen Lights unit. Following the 2018 drilling pro-gram, production from the field should peak at about 40million cubic feet per day. However, a projected relativelyrapid well production decline rate means that a continuingdrilling program, as specified in the latest plan of develop-ment for the field, will be needed to maintain adequate gas

deliverability. The plan includes drilling an additionaldevelopment well and conducting workover operations onup to two of the existing wells, Furie told Enstar.

Although the recent drilling added incremental gasreserves from both the Sterling and Beluga formations,Furie has not yet resolved problems associated with exces-sive water production from the Sterling. Failure to deal withthese problems would impact Sterling gas reserves data.However, Petrotechnical Resources of Alaska is assistingthe company to address the underperformance of Sterlingwell completions. And production from a single interval inthe Sterling in the KLU A4 well shows some promise, witha production rate of 10 million cubic feet per day and nomeasurable water, Furie reported.

Meanwhile, the company continues develop and pro-duce from the Beluga formation, Furie said.

However, given the pipeline blockage that occurred afterFurie made its report, continuing production at the field willclearly depend on the company resolving its current gasdelivery problems.

—ALAN BAILEY

continued from page 1

KITCHEN LIGHTS

10 PETROLEUM NEWS • WEEK OF MARCH 3, 2019

EXPLORATION & PRODUCTIONPreparations underway for Alkaid testing

Pantheon Resources plc said Feb. 25 that preparations are underway for testingat the company’s Alkaid 1 well on the North Slope.

The well was drilled by Great Bear Petroleum in 2015; it was acquired byPantheon recently as part of its acquisition of two Great Bear subsidiaries, GreatBear Petroleum Ventures I and II.

Pantheon said the exploration well was drilled as a vertical test well in 2015but was not flow tested then due to an extreme weather event which caused exten-sive flooding in the region and to the Dalton Highway.

The Alkaid well was suspended to avoid equipment being stranded at location.Pantheon said all zones had been logged and sidewall cores had been taken at thedeepest zones, confirming indications of oil in three major zones, from some4,000 feet to some 8,100 feet.

“Pantheon plans to production test each of these zones subject to suitable bore-hole conditions,” the company said.

Construction of an ice road to the location is underway, the company said, andAll-American Oilfield Services Rig 111 has been contracted and is estimated toarrive on location the first week of March.

Pressure testing will be done and a cement bond log will be run to determinethe condition of the borehole for testing. Pantheon said each of the three zones“has major productive oil field analogues nearby.”

Pantheon said it will hold a 100 percent interest in the production testing oper-ations and a 75 percent interest in the event of a plug and abandon operation, withits joint venture partner Halliburton paying the remaining 25 percent share. WhileHalliburton will not participate as a working interest owner in the testing,Pantheon said Halliburton has a back-in right which would allow them to buyback into their nominal 25 percent working interest.

“We have worked tirelessly to be in a position to test Alkaid so soon after com-pletion of the Great Bear acquisition last month,” Pantheon Jay Cheatham said.“We hope and expect that Alkaid borehole conditions will allow us to undertakea full evaluation of the oil encountered in the three independent zones.”

—KRISTEN NELSON

FERC breakthrough on LNG certificationThe Federal Energy Regulatory Commission said Feb. 21 that it “has reached an

agreement that may provide a path forward” for consideration of the remaining 12pending liquified natural gas terminals before it.

FERC said this happened in the context of its Feb. 21 approval of Venture Global’sCalcasieu Pass LNG export project in Cameron Parish, Louisiana, in which the com-mission applied a new approach for consideration of direct greenhouse gas emissionsfrom LNG facilities.

One concurring and one dissenting opinion on the Feb. 21approval focused on the GHG impact of LNG facilities.

“Since I joined the Commission, it’s been a priority of mineto expedite and improve our LNG terminal application reviewprocess,” FERC Chairman Neil Chatterjee said. “I’m extremelypleased that we are issuing the certificate order for the CalcasieuPass LNG export terminal today.” He said the facility will beable to export 12 million metric tons of LNG a year.

Chatterjee said he appreciates the efforts of his colleagues inworking together to reach agreement on the Calcasieu Passfacility.

“This is significant, as I anticipate we’ll be able to use the framework developed inthis order to evaluate the other LNG certificates that the Commission is considering.”

Bloomberg said the Calcasieu Pass approval was the first authorization in twoyears for a new LNG export terminal and said this broke “an impasse that had threat-ened to bring approvals to a standstill.”

Of five seats on the commission, four are currently occupied. There was one dis-senting opinion in this decision, and one concurring opinion.

Chatterjee also said FERC signed a memorandum of understanding with the U.S.Department of Transportation’s Pipeline and Hazardous Materials SafetyAdministration, “cut through unnecessary red tape and reduced inter-agency frictionby signing the One Federal Decision MOU with our federal partners, and increasedthe number of engineers working on our reviews by casting a wide net to capture tal-ent everywhere we could find it.”

He called the Calcasieu Pass certification “a matter of truly strategic significance,”thanking FERC staff for hard work and fellow commissioners for working on theagreement. “Commissioner McNamee showed just how he got his reputation as beinga ‘lawyer’s lawyer’ through his attention to the law and work to find commonground. And Commissioner LaFleur was supportive of this project and construc-tive in working to reach our agreement,” Chatterjee said.

—KRISTEN NELSON

GOVERNMENT

NEIL CHATTERJEE

To advertise in Petroleum News, contact Susan Crane

at 907.770.5592petroleumnews.com

Foerster holds the petroleum engineerseat and Commissioner Dan Seamountthe geologist seat.

Petroleum News asked the governor’soffice about the status of appointments tothe commission but did not immediatelyhear back.

In a Jan. 17 letter, the governor noti-fied French of fivepotential groundsfor “removal fromoffice for cause.”The governor said inhis Feb. 26 decisionon removal forcause that he basedhis decision on twoof those grounds.

French contestedthe grounds for removal, exercising hisright to be publicly heard and a hearingwas held Feb. 6-8. The hearing officerpresented his findings of fact Feb. 12.

The hearing officer, TimothyPetumenos, considered the five groundsthe governor listed: chronic, unexcusedabsenteeism; browbeating fellow com-missioners; publicly undermining thework of the AOGCC; security breaches;and failure to perform routine AOGCCwork.

The governor said Feb. 26 that basedon information from the public hearing,he based his determination to dismiss onthe unexcused absenteeism and failure toperform routine work charges; hedeclined to base his decision on thecharges of browbeating, publicly under-mining decisions of the commission orbreaching critical commission security.

BrowbeatingPetumenos said he found insufficient

evidence for the charges of browbeating,publicly undermining the commissionand breaching commission security.

He said he found “no substantial evi-dence to support a removal for cause” forbrowbeating.

“Commissioner French was persistentand energetic in pursuing his view thatthe jurisdiction of the AOGCC was beinginterpreted more narrowly than hebelieved that the enabling statutesintended,” Petumenos said. “While itmay have been the case thatCommissioner French argued his posi-tion forcefully, fervently and persistently,there is insufficient evidence thatCommissioner French was unprofession-al, rude or bullying when he did so.”

The balance of the testimony at thehearing “was not directed to the tone,respectfulness or professionalism ofCommissioner French’s communicationsabout views he held, but rather toCommissioner French’s persistence,”Petumenos said.

He said he believes it “would set adangerous precedent” to remove a com-missioner “for ardently pursuing a mat-ter” on which the commissioner was inthe minority.

Publicly undermining AOGCCOn the issue of publicly undermining

the commission, Petumenos said much ofthat assertion appears to be based on evi-dence related to French’s minority viewof expanded jurisdiction. He also said thebalance of the evidence shows thatFrench was clear in his communicationsthat the views he presented were his andnot a quorum view of the commission.

Petumenos said he found “no substan-tial evidence” to support French’sremoval for cause on the ground that heundermined the AOGCC.

Security breachesThere were two security breach issues

— one was allowing unescorted visitorsbetween offices and the other was discus-sions French had about information fromthe KIC well being maintained in a safeat the commission.

Petumenos said he found insufficientevidence to support the claim that Frenchallowed visitors to walk around the officeunescorted.

After the issue arose of Frenchdescribing the location of KIC well infor-mation to a reporter, the other commis-sioners moved the safe holding thatinformation and Petumenos said afterFrench discovered the safe had beenmoved, he and Seamount began to worktogether on updated written security pro-cedures.

French defended his discussion of thelocation of KIC well materials on thebasis that the settlement agreement withthe owners of the data did not specifythat the location of the data remain con-fidential.

Petumenos said the governor wouldhave to decide whether the facts in thisinstance constitute a material cause forremoval of French.

Failure to perform routine workThere is substantial evidence that

French did not perform routine work,which then fell to others, Petumenos, butsaid there is not sufficient evidence thatFrench “did non-AOGCC work on officetime in a material way.”

As to French attending the AlaskaFederation of Natives during businesshours, Petumenos said there are discre-tionary decisions as to the use of a com-missioner’s time “that should not be sub-ject to the second guessing of other com-missioners rising to the level of groundsfor cause.”

Governor’s decisionDunleavy told French in his Jan. 17

letter that there were five potentialgrounds for removal for cause, describ-ing them generally as “neglect of dutyand misconduct in office.”

In his Feb. 27 statement of decisionDunleavy said he affirms his originaldecision “as to charges of neglect ofduty” but not on the other charges of mis-conduct (browbeating, publicly under-mining AOGCC and breaching criticalsecurity).

On the browbeating and publiclyundermining charges, the governor saidPetumenos found that “CommissionerFrench’s behavior and strident advocacy,even when considering matters that hadpreviously been decided by theCommission, was nonetheless within thescope of his discretion as a quasi-judi-cial, independent Commissioner.”

But on the neglect of duty charges,Dunleavy said Petumenos found “sub-stantial evidence to show an ‘overall pat-tern’ of absenteeism and that it was‘more norm than … exception.’”

Those absences from the office were“markedly different” from other past andpresent commissioners.

“My judgment is that CommissionerFrench neglected his duty to routinelyshow up for work, to work a full day, andto do his best to perform his obligationsas a fulltime, quasi-judicialCommissioner. Although French did notdevote office time to non-AOGCC work,he consistently failed to perform thework expected of him as aCommissioner,” the governor said.

—KRISTEN NELSON

continued from page 1

FRENCH DISMISSED

GOV. MIKE DUNLEAVY

polar capable icebreakers: the Healy, amedium duty icebreaker, much used as abase for polar research, and the Polar Star,which is a heavy icebreaker but is 41years old and nearing the end of its oper-ational life. A third icebreaker, the PolarSea, sister ship to the Polar Star, is laid upin port and has become a source of spareparts for the Polar Star.

In a Feb. 20 news release U.S. Sen.Dan Sullivan, R-Alaska, expressed hisdelight at the new icebreaker funding.

“After years of advocating for the fed-eral government to take America’s role asan Arctic nation seriously, we have finallysecured substantial resources for ourcountry to strengthen its position in theregion with a brand-new icebreaker,”Sullivan said. “With this appropriation,Congress and the Trump administrationare acknowledging that Alaska isAmerica’s Arctic, a fact that is importantto our broader national security interests.I was glad to have the opportunity to usemy leadership role on the Commerce andArmed Services Committees, in conjunc-tion with Senator Murkowski’s work onthe Appropriations Committee, to secureAmerica’s first new polar icebreaker in ageneration and the needs of the CoastGuard in Alaska.”

The authorization act passed last yearindicated a need to award a contract for

the first of the new vessels by fiscal year2019, to enable the vessel to go into serv-ice by fiscal year 2023.

A lengthy debateThe debate over how, when and at

what cost to acquire new U.S. polar ice-breakers has continued for many years. Inthe not too distant past the Coast Guardhas estimated the cost at about $1 billionper vessel. However, the agency soughtways to reduce that cost. According to aCongressional Research Service report, inJanuary 2018 the agency was estimatingthe cost at around $930 million per vessel.

In April of last year, the CRS issued areport saying that the Coast Guard hadfurther revised its estimated costs down-wards, on the basis that the icebreakercosts could be reduced through the use ofa standard, existing design for the vessels,and by placing a higher reliance on civil-ian commercial shipbuilding specifica-tions rather than military specifications.

The Coast Guard now thought that thefirst three vessels could be built at a totalcost of $2.1 billion, with an average cost

of $700 million per vessel, but with thefirst icebreaker costing more than theother two because of initial design costsand the inevitable learning curve for thefirst of the vessels. In a March 2018request for proposal that the Coast Guardissued for the advanced procurement anddetailed design for the icebreaker pro-gram, the agency gave an estimated costof $746 million for the first icebreaker andan average cost of $625 million per vesselfor three vessels, according to the CRS.

Questions from the GAOHowever, in September 2018 the GAO

issued a report questioning the lack of apreliminary design review for the pro-posed icebreaker program and suggestingthat the cost of the program may beunderestimated. In particular the estimat-ed cost and development schedule are

based on a preliminary concept ratherthan a mature design, the report com-mented. And the GAO said that the ice-breaker program had not fully assessedhow well some key technologies wouldwork on the planned ships.

A Congressional Research Servicereport published on Feb. 15 indicates thatthe Coast Guard is sticking with its esti-mate of an average cost of $700 millionper vessel, with the first icebreaker cost-ing more than the other two. The reportsays that the Coast Guard already has$359 million in prior-year funding thatcould be applied towards the constructionof the first two vessels. That would sug-gest that the new appropriation of $655million should be more than enough tocover the cost of the first vessel.l

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ICEBREAKER FUNDED

The federal regulator conceded the project could have“adverse environmental effects” on the British Columbiacoast and marine wildlife, including an endangered killerwhale population.

While a worst-case spill from the pipeline or an oiltanker was not likely, the impact would be “significant”said Robert Steedman, the NEB’s chief environmentofficer.

Although that consideration weighed heavily in theNEB’s reconsideration, the board decided the Canadiangovernment would be justified in allowing the project togo ahead “in light of the considerable benefits (toCanadians jobs, government revenues and greater mar-ket access for oil sands crude) and the measures to miti-gate the effects,” he told reporters.

New conditionsThe latest recommendations call for increased spill

response measures and reduced emissions from marinevessels operations in the area, including tougher controlson British Columbia ferries operating betweenVancouver Island and the Mainland and on whale watch-ing boats.

The NEB’s 689-page report also pointed to the posi-

tive impact from TMX construction and operations onthe training, jobs and business opportunities for allIndigenous communities along the pipeline route whosigned access and benefits agreements with formerpipeline owner Kinder Morgan and the Canadian gov-ernment which is the current owner, having bought theexisting Trans Mountain system for C$4.5 billion.

A deadline of May 22 has now been set for the federalgovernment, which has still to complete consultationswith 85 Indigenous communities, to deliver a conclusiveverdict on the TMX.

Fight not overBoth First Nations and environmental groups are

emphatic they will not give up their fight.“Even if one community, one nation says ‘no’ then

that project is not happening,” said Neskonlith ChiefJudy Wilson, who is also secretary of the Union of B.C.Indian Chiefs.

Eugene Kung, an attorney with West CoastEnvironmental Law, said the “fix was in from the start,”when the issue was turned over to the NEB. “I’m notsure it’s news that a captured regulator likes pipelines,”he said.

Industry leaders expect further court appeals but hopethe NEB’s latest round will limit those actions.

“As things take longer and longer, both sides dig inand become less flexible,” said Kevin Neveu, president

of Precision Drilling, saying the anti-development rhet-oric “has become less rational.”

Eric Nuttall, a senior portfolio manager withNinePoint Partners, said that if Canadian oil producerscan diversify their markets investor fund flows shouldturn in their favor again at a time when shares are “trad-ing at their lowest valuations in generations.”

Capital investment downThe NEB report was released against the backdrop of

findings by the C.D. Howe Institute that planned capitalinvestment in the Canadian energy sector dropped fromC$146 billion in 2014 to C$35 billion in 2018, basedlargely on Canada’s record for cancelling and delayingprojects.

Chris Bloomer, president of the Canadian EnergyPipelines Association, said the only “definitive point” inthe project’s history will occur “when we get oil flow-ing.”

“We’ve got to demonstrate that we can build theseprojects,” otherwise investors will continue to bail out ofCanada’s resource sectors, he said.

Ian Anderson, Trans Mountain’s president, said theNEB report “provides specific and achievable conditionsunder which we must operate (and that) will protect themarine and terrestrial environment and communities.” l

continued from page 1

PIPELINE EXPANSION

A Congressional Research Servicereport published on Feb. 15

indicates that the Coast Guard issticking with its estimate of an

average cost of $700 million pervessel, with the first icebreaker

costing more than the other two.

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pricing across the Railbelt and a unified transmissionsystem with non-discriminatory access for generationfacilities would facilitate maximum use of the most effi-cient power generation on the grid, and the integration ofhydropower and intermittent renewables such as windand solar.

Companies involvedHomer Electric Association, Municipal Light &

Power, Golden Valley Electric Association, the City ofSeward and ATC have formed the company. ChugachElectric Association and Matanuska Electric Associationhave also been involved in the process leading to the cer-tificate application. Chugach Electric is still conductingdue diligence prior to seeking board approval for its par-ticipation in the new company. Matanuska ElectricAssociation told the commission that it is conducting itsdue diligence of the ART concept and that it has some“significant areas of concern.”

The formation of ART comes as part of a multiyeareffort, encouraged by the RCA, for the utilities to take amore unified approach to the management and operationof the Railbelt electrical system.

The company would charge standard fees for thepoint-to-point delivery of electricity from generationunits to local distribution networks, thus avoiding thestacking or pancaking of separate fees by different own-ers of different network sectors, as happens at present.ART’s tariff also includes procedures and a fee structurefor connecting new generation facilities to the transmis-sion grid.

The member utilities would pool their transmissionsystem costs, with those costs being initially splitbetween the utilities based on agreed percentage alloca-tions. However, the concept is that, over time, costs willbe allocated based on the utilities’ shares of the transmis-sion load. The calculation of the revenue requirementfrom capital assets will be based on a capital structure of60 percent debt and 40 percent equity, with a return on

equity of 10 percent.

Ownership retainedThe individual utilities would retain their current

ownerships of their individual components of the trans-mission system, with ART operating their assets on theirbehalf. The company hopes to also take over the controlof the transmission assets associated with the BradleyLake hydropower facility on the Kenai Peninsula, andthe Alaska Intertie segment of the transmission systembetween Southcentral Alaska and the Interior. However,this would depend on a review of the relevant agree-ments for these sectors of the grid.

The participating utilities would continue the mainte-nance and repair of the components of the transmissiongrid that they own, but would do so under the terms ofservice agreements with ART. On the other hand, ARTwould determine how to delegate operations and mainte-nance responsibilities for transmission assets that it con-structs or that cross multiple utility service areas.Specific utilities have also agreed to execute serviceagreements with ART for specific services that would berequired for the entire system, such as finance, humanresources and transmission dispatch.

ART would plan, finance and manage upgrades to thetransmission system, using its funding resources, recov-ering the upgrade costs through the rates that it chargestransmission customers. Currently the fragmented oper-ation of the system inhibits upgrades, because an indi-vidual utility may be faced with funding an upgrade thatprovides benefits to other utilities. ART told the commis-sion that any new construction for the transmission sys-tem would be based on a regional integrated resourceplan.

ART would be governed by a board with one repre-sentative from each of the participating companies and atleast one independent director.

MEA’s concernsIn a letter to the utilities that have formed the new

transmission company, Tony Izzo, CEO of MatanuskaElectric Association, expressed his utility’s concerns.Izzo emphasized MEA’s commitment to working with

the other utilities on the transmission company concept.But, after reviewing the draft certificate application forthe new company, Izzo had proposed a joint due dili-gence effort by the utilities for the proposal. And, havingreceived no responses to this suggestion, MEA haddecided to proceed with its own due diligence effort —the due diligence analysis should be complete by the firsthalf of April, Izzo said.

Based on a preliminary analysis, MEA has concernsabout a number of issues including the tax implicationsof the new organization; requirements for return on equi-ty; required expenditures by each utility; the re-alloca-tion of the costs of shipping power through the network;compliance with utility bylaws; and the lack of an inde-pendent, stakeholder-involved planning and projectapproval process.

“This is a major decision for the future of our stateand each of our utilities,” Izzo wrote. “We are beingasked to form a long-term business arrangement with,and convey ownership of our system to a sophisticated,Outside, for-profit entity and we should apply the samelevel of sophistication to a thorough analysis.”

Other initiativesAlso as part of the multiyear effort towards more uni-

fied operation of the Railbelt electrical system the utili-ties have been proposing to form a Railbelt ReliabilityCouncil to oversee the operation of the entire system.The utilities have also developed a uniform set of relia-bility standards for the transmission system and areworking towards incorporating cybersecurity standards.There is a continuing debate over the mechanism where-by the standards would be enforced. The RCA has alsobeen pushing for the implementation of economic dis-patch, involving the continuous use of the most efficientavailable power generation across the grid. ChugachElectric, ML&P and MEA had been moving forwardwith a plan to implement economic dispatch across theirservice areas. However, that initiative is currently onhold, pending the planned purchase of ML&P byChugach Electric. l

continued from page 1

RAILBELT TRANSCO

Interior’s U.S. Geological Survey that will help biddersin the upcoming ANWR 1002 fall lease sale to betterunderstand the oil potential of the region, per the Feb.17 Petroleum News report, but new 3-D will not bepossible this season, SAExploration’s top executiveJeff Hastings told Petroleum News Feb. 25 after com-ing out of a meeting with F&W officials.

Partners SAExploration, Arctic Slope RegionalCorp. and Kaktovik Inupiat Corp. are behind the seis-mic that was expected to be shot this winter. The pro-

gram, referred to as the Marsh Creek 3-D survey, wasto encompass the entire 1002 area, some 2,600 squaremiles. A narrow strip along the coast, the 1002 area wasset aside for potential development by Congressbecause of its hydrocarbon-rich geology.

The 35-day federal government shutdown that start-ed in December was the main reason behind the delayin securing F&W permit in a timely manner, necessitat-ing a change in dates in the application, Hastings said.

“Since the government went back to work we’vebeen working with the agency to make the appropriatechanges because there were specific dates in that appli-cation that had to change. … By the time we workedthrough those things it was so late in the season if you

put publication in the Federal Register and a 30-daycomment period in the timetable, plus, say 15 daysafter that to process the ITR, you were getting intoApril and once you mobilize from Deadhorse it takesfour days to get to the 1002 border and then anotherfive days to get to the village of Kaktovik … it was justgetting too late and we preferred two full winter sea-sons to do the survey.”

At this point Hastings expects a permit to be issuedin mid-second quarter.

—KAY CASHMAN

continued from page 1

ANWR SEISMIC