l EXPLORATION & PRODUCTION Conoco sanctions 2S · l EXPLORATION & PRODUCTION l ECONOMY l NATURAL...
20
l EXPLORATION & PRODUCTION l FINANCE & ECONOMY l NATURAL GAS page 5 Q&A: Feige sees state’s role as Alaska LNG partner as significant Vol. 19, No. 44 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of November 2, 2014 • $2.50 Mining Explorers provides a comprehensive overview of the mining companies investing the capital and time needed to unlock the enor- mous mineral potential of Alaska and northern Canada. 2014 Mining Explorers inside M ining explorers Discovering the future of Alaska and Canada's North M ining explorers Discovering the future of Alaska and Canada's North Conoco sanctions 2S Drill site is the first at Kuparuk in 12 years; 3S appraisal set for winter By ERIC LIDJI For Petroleum News I n two separate but similar projects, ConocoPhillips Alaska Inc. has sanctioned a new drill site and is permitting an appraisal well at opposite ends of the Kuparuk River unit. The Houston based independent recently received partner approval for the Drill Site 2S proj- ect in the southwest corner of the North Slope unit and intends to drill the Drill Site 3S-620 Moraine exploration well in the northwest corner of the unit this coming winter. The $500 million Drill Site 2S project includes a pad, a new gravel road and associated power lines, pipelines and surface facilities. With prelim- inary gravel work completed earlier this year, ConocoPhillips can build the pad over the winter, start drilling by the middle of next year and bring the pad online by late 2015, according to a compa- ny timeline. The drill site is expected to produce some 8,000 barrels per day at its peak. In addition to operator ConocoPhillips, the Kuparuk River unit owners include BP Exploration (Alaska) Inc., Chevron USA Inc. and ExxonMobil Alaska Production Inc. To the north, ConocoPhillips wants to drill the DS3S-620 Moraine well to gain “additional reser- voir information in this area and narrow uncertain- ty around reservoir description parameters includ- ing oil-water contact, sand quality and thickness, A Kitchen Lights enigma The pieces of the puzzle are falling into place, but how much gas is there? By ALAN BAILEY Petroleum News F urie Operating Alaska’s Spartan 151 jack-up drilling rig is safely moored at Port Graham for the winter, having completed another couple of exploration wells this year, seeking oil and gas in the Cook Inlet Kitchen Lights unit. And the com- pany’s Kitchen Lights gas production platform is moving south to Seattle, to overwinter there, with Furie now planning to install the platform in the waters of the inlet in the spring of 2015. But just what has the company found as a con- sequence of its Kitchen Lights drilling? To date the company has completed a total of five Kitchen Light wells and has announced a gas field devel- opment centered on one of these wells. The Kitchen Lights unit straddles the center of Cook Inlet, off the northern coast of the Kenai Peninsula. Furie’s efforts to bring a Kitchen Lights gas field into production, coupled with some tantaliz- ing announcements of discovered gas resources, have caused speculation over how much gas the company may be able to bring on line. And docu- ments relating to the drilling of the first of the company’s Kitchen Lights wells have recently been released by the Alaska Oil and Gas Commission, adding a further piece to the incom- plete puzzle of figuring out what Furie has discov- ered. The sequence of Kitchen Lights wells has broadly followed the requirements spelled out in Furie’s exploration plan, filed with the Alaska Buccaneer selling out Bankruptcy independent seeks court approval for sale to lender AIX Energy By ERIC LIDJI For Petroleum News B uccaneer Energy Ltd. is selling its Alaska assets to its largest creditor for $44 million. After holding an auction on Oct. 27, the Australian independent is asking a federal bank- ruptcy court in Texas to approve a sale to the Houston-based AIX Energy LLC. The proposed $44 million sale price represents a credit bid, which allows a secured creditor to offer the amount of its debt against cash bids from other potential buyers. A court-approved sale process allowed Buccaneer to either hold an auction or sell its assets directly to AIX Energy, should a solicitation fail to yield any qualified bids. The only qualified bid came from the Miller Energy Resources Inc.-affiliate Cook Inlet Energy LLC, which offered $35 million for the properties in a bid made Oct. 24. Miller had previously announced its intentions to bid between $40 mil- lion and $50 million. Buccaneer used the $44 million credit bid from AIX Energy as the opening bid for the auction. Cook Inlet Energy declined to increase its initial bid, which ended the auction. Should the AIX Energy sale fall through, Buccaneer would sell the assets to Cook Inlet Energy for $35 million. Buccaneer is asking the court to approve both contingencies. see DRILL SITE 2S page 18 see FURIE DRILLING page 19 see BUCCANEER SALE page 17 Shell asks for 5-year extension for Beaufort and Chukchi leases Shell spokeswoman Megan Baldino has confirmed a report that Shell has requested the federal Bureau of Safety and Environmental Enforcement to issue five-year extensions to the company’s Alaska Arctic outer continental shelf oil and gas leases. “The request reflects the extent of the actual delays we have experienced as a result of court decisions and agency actions for the last several years,” Baldino told Petroleum News in an Oct. 27 email. The report originated from a Freedom of Information Act request to the Bureau of Safety and Environmental Enforcement from environmental organization Oceana. BC finds no easy path to LNG riches, but says it’s competitive For all of its 140-year-plus history as a province of Canada, British Columbia has built its economic engine from parts assembled out of the natural resource sector. But beyond lumber, minerals and fish there has never been much evidence of a Plan B to cover its budget and spending needs, confining British Columbia to its role as a hewer of wood and drawer of water. Until less than a decade ago, the province — despite build- ing evidence of untold natural gas riches in its northeastern region — was even gearing up to import LNG. Then came a breakthrough from the use of horizontal drilling and multi-stage fracturing to release gas from shale deposits, coupled with the insatiable demand for LNG in Asia, with customers forking over US$18 per million British ther- mal units. In no time, global energy giants were assembling natural see LEASE EXTENSION page 15 see BC LNG page 15 PETE SLAIBY JUDY PATRICK
Transcript of l EXPLORATION & PRODUCTION Conoco sanctions 2S · l EXPLORATION & PRODUCTION l ECONOMY l NATURAL...
l E X P L O R A T I O N & P R O D U C T I O N
l F I N A N C E & E C O N O M Y
l N A T U R A L G A S
page5
Q&A: Feige sees state’s role asAlaska LNG partner as significant
Vol. 19, No. 44 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of November 2, 2014 • $2.50
Mining Explorers provides a comprehensive overview of the miningcompanies investing the capital and time needed to unlock the enor-mous mineral potential of Alaska and northern Canada.
2014 Mining Explorers inside
Mininge x p l o r e r s
Discoveringthe futureof Alaskaand Canada'sNorth
Mininge x p l o r e r s
Discoveringthe futureof Alaskaand Canada'sNorth
Conoco sanctions 2SDrill site is the first at Kuparuk in 12 years; 3S appraisal set for winter
By ERIC LIDJIFor Petroleum News
In two separate but similar projects,ConocoPhillips Alaska Inc. has sanctioned a
new drill site and is permitting an appraisal well atopposite ends of the Kuparuk River unit.
The Houston based independent recentlyreceived partner approval for the Drill Site 2S proj-ect in the southwest corner of the North Slope unitand intends to drill the Drill Site 3S-620 Moraineexploration well in the northwest corner of the unitthis coming winter.
The $500 million Drill Site 2S project includesa pad, a new gravel road and associated powerlines, pipelines and surface facilities. With prelim-
inary gravel work completed earlier this year,ConocoPhillips can build the pad over the winter,start drilling by the middle of next year and bringthe pad online by late 2015, according to a compa-ny timeline. The drill site is expected to producesome 8,000 barrels per day at its peak.
In addition to operator ConocoPhillips, theKuparuk River unit owners include BPExploration (Alaska) Inc., Chevron USA Inc. andExxonMobil Alaska Production Inc.
To the north, ConocoPhillips wants to drill theDS3S-620 Moraine well to gain “additional reser-voir information in this area and narrow uncertain-ty around reservoir description parameters includ-ing oil-water contact, sand quality and thickness,
A Kitchen Lights enigmaThe pieces of the puzzle are falling into place, but how much gas is there?
By ALAN BAILEYPetroleum News
Furie Operating Alaska’s Spartan 151 jack-updrilling rig is safely moored at Port Graham
for the winter, having completed another couple ofexploration wells this year, seeking oil and gas inthe Cook Inlet Kitchen Lights unit. And the com-pany’s Kitchen Lights gas production platform ismoving south to Seattle, to overwinter there, withFurie now planning to install the platform in thewaters of the inlet in the spring of 2015.
But just what has the company found as a con-sequence of its Kitchen Lights drilling? To date thecompany has completed a total of five KitchenLight wells and has announced a gas field devel-opment centered on one of these wells. The
Kitchen Lights unit straddles the center of CookInlet, off the northern coast of the Kenai Peninsula.
Furie’s efforts to bring a Kitchen Lights gasfield into production, coupled with some tantaliz-ing announcements of discovered gas resources,have caused speculation over how much gas thecompany may be able to bring on line. And docu-ments relating to the drilling of the first of thecompany’s Kitchen Lights wells have recentlybeen released by the Alaska Oil and GasCommission, adding a further piece to the incom-plete puzzle of figuring out what Furie has discov-ered.
The sequence of Kitchen Lights wells hasbroadly followed the requirements spelled out inFurie’s exploration plan, filed with the Alaska
Buccaneer selling out Bankruptcy independent seeks court approval for sale to lender AIX Energy
By ERIC LIDJIFor Petroleum News
Buccaneer Energy Ltd. is selling its Alaskaassets to its largest creditor for $44 million.
After holding an auction on Oct. 27, theAustralian independent is asking a federal bank-ruptcy court in Texas to approve a sale to theHouston-based AIX Energy LLC.
The proposed $44 million sale price representsa credit bid, which allows a secured creditor tooffer the amount of its debt against cash bids fromother potential buyers.
A court-approved sale process allowedBuccaneer to either hold an auction or sell itsassets directly to AIX Energy, should a solicitation
fail to yield any qualified bids.The only qualified bid came from the Miller
Energy Resources Inc.-affiliate Cook Inlet EnergyLLC, which offered $35 million for the propertiesin a bid made Oct. 24. Miller had previouslyannounced its intentions to bid between $40 mil-lion and $50 million.
Buccaneer used the $44 million credit bid fromAIX Energy as the opening bid for the auction.Cook Inlet Energy declined to increase its initialbid, which ended the auction.
Should the AIX Energy sale fall through,Buccaneer would sell the assets to Cook InletEnergy for $35 million. Buccaneer is asking thecourt to approve both contingencies.
see DRILL SITE 2S page 18
see FURIE DRILLING page 19
see BUCCANEER SALE page 17
Shell asks for 5-year extensionfor Beaufort and Chukchi leases
Shell spokeswoman Megan Baldinohas confirmed a report that Shell hasrequested the federal Bureau of Safetyand Environmental Enforcement to issuefive-year extensions to the company’sAlaska Arctic outer continental shelf oiland gas leases.
“The request reflects the extent of theactual delays we have experienced as aresult of court decisions and agencyactions for the last several years,”Baldino told Petroleum News in an Oct. 27 email.
The report originated from a Freedom of Information Actrequest to the Bureau of Safety and EnvironmentalEnforcement from environmental organization Oceana.
BC finds no easy path to LNGriches, but says it’s competitive
For all of its 140-year-plus history as a province of Canada,British Columbia has built its economic engine from partsassembled out of the natural resource sector.
But beyond lumber, minerals and fish there has never beenmuch evidence of a Plan B to cover its budget and spendingneeds, confining British Columbia to its role as a hewer ofwood and drawer of water.
Until less than a decade ago, the province — despite build-ing evidence of untold natural gas riches in its northeasternregion — was even gearing up to import LNG.
Then came a breakthrough from the use of horizontaldrilling and multi-stage fracturing to release gas from shaledeposits, coupled with the insatiable demand for LNG in Asia,with customers forking over US$18 per million British ther-mal units.
In no time, global energy giants were assembling natural
see LEASE EXTENSION page 15
see BC LNG page 15
PETE SLAIBY
JUD
Y P
ATR
ICK
2 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
Petroleum News North America’s source for oil and gas newscontents
4 Interior Energy Project hits milestones
7 Jury out on BC’s LNG tax regime
FINANCE & ECONOMY
5 Feige: SB 21 benefit with low oil prices
Outgoing House Resources co-chair says role of stateas partner in LNG project significant; encouragedby companies working together
9 EPA releases emission rule information
Publishes new data, ideas as part of public commentperiod for proposed power plant GHG emissionsregs; adds Indian Country rule
8 BLM releases Mooses Tooth final SEIS
Bureau of Land Management preferred alternativeincludes road, but is not ConocoPhillips proposal;drilling pad, access road moved
4 US tribes oppose Trans Mt pipeline plans
Tribal leaders tell Canada’s NEB Kinder Morgan’sexpansion poses serious consequences for way of life, Pacific Coast environment
14 Oil exports could reduce fuel costs
But the lifting of the export ban would also cause the price of US oil to rise and increases US environmental risks, GAO says
10 DOE announces hydrate research project
Selects project to characterize the properties of subseamethane hydrate resources in the Gulf of Mexicoouter continental shelf
14 Miller close to sealing Savant purchase
Deal would give Tennessee company control of Badamioil field on Alaska’s North Slope; new Cook Inlet well nears completion
LAND & LEASING
NATURAL GAS
PIPELINES & DOWNSTREAM
GOVERNMENT
Shell asks for 5-year extensionfor Beaufort and Chukchi leases
BC finds no easy path to LNGriches, but says it’s competitive
Conoco sanctions 2S
Drill site is the first at Kuparuk in 12 years; 3S appraisal set for winter
A Kitchen Lights enigma
The pieces of the puzzle are falling into place, but how much gas is there?
Buccaneer selling out
Bankruptcy independent seeks court approvalfor sale to lender AIX Energy
ON THE COVER
10 Report points to energy independence
14 AIDEA completes Mustang project deal
D I V E R S I F I E D D E V E L O P M E N T A N D S U P P O R T S E R V I C E S I N T H E A R C T I C & B E Y O N D
U I C U M I A Q . C O MUMIAQ Anchorage 6700 Arctic Spur RoadAnchorage, AK 99518 P: (907) 677-8220 F: (907) 677-8286
UMIAQ BarrowP.O. Box 955
Barrow, AK 99723 P: (907) 852-7447F: (907) 852-6488
Computing Alternatives
Information Technology Professionals
Ph| 907-644-4522Fx| 907-644-4523
[email protected] Silverado Way, Ste. I
Anchorage, AK 99518
• Custom Web, Desktop, &Mobile apps
• IT Business Analysis• Database Design & Modeling• Microsoft Server Maintenance
• SQL Server DatabaseAdministration
• Oil & Gas Risk Assessment and Regulatory Compliance Tools
• Revenue Taxation• Hospitality Systems
WE OFFER THE FOLLOWING SOLUTIONS TO PUBLIC AND
PRIVATE SECTORS
EXPLORATION & PRODUCTION6 Villagers reject Corps CD-5 explanation
Say that reasoning behind decision not to modify SEISrelies on unsupported and conflicting statements relating to project changes
SIDEBAR, Page 7: BC favors LNG with new climate-change law
PlacerUnit
SouthernMiluveach
Unit ProposedDS2S Pad& Ice Road
PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014 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) Prudhoe Bay DS 15-28A, workover BPDreco 1000 UE 16 (SCR/TD) Prudhoe Bay W-26A BPDreco D2000 Uebd 19 (SCR/TD) Alpine CD4 ConocoPhillipsAC Mobile 25 Prudhoe Bay DS 11-39 BPOIME 2000 141 (SCR/TD) Kuparuk 2F-21 ConocoPhillips
Kuukpik 5 Prudhoe Bay Available Nabors Alaska DrillingAC Coil Hybrid CDR-2 Kuparuk 2F-18 ConocoPhillipsDreco 1000 UE 2-ES (SCR-TD) Prudhoe Bay Available Mid-Continental U36A 3-S Prudhoe Bay AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay AvailableDreco 1000 UE 7-ES (SCR/TD) Kuparuk ConocoPhillipsDreco 1000 UE 9-ES (SCR/TD) Kuparuk ConocoPhillipsOilwell 2000 Hercules 14-E (SCR) Prudhoe Bay AvailableOilwell 2000 Hercules 16 (SCR/TD) Prudhoe Bay S-108 BP Emsco Electro-hoist-2 18-E (SCR) Prudhoe Bay StackedEmsco Electro-hoist Varco 22-E (SCR/TD) Prudhoe Bay StackedTDS3Emsco Electro-hoist Canrig 27-E (SCR-TD) Deadhorse, under contract 1050E to ExxonMobil for 2015
Emsco Electro-hoist 28-E (SCR) Prudhoe Bay StackedOilwell 2000 33-E Prudhoe Bay Available Academy AC Electric CANRIG 99AC (AC-TD) Deadhorse AvailablelOIME 2000 245-E (SCR-ACTD) Oliktok Point ENIAcademy AC electric CANRIG 105AC (AC-TD) Deadhorse AvailableAcademy AC electric Heli-Rig 106-E (AC-TD) Deadhorse Available
Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site E-34 BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site 2-32C BPIdeco 900 3 (SCR/TD) Kuparuk Well 1A-25 ConocoPhillips
Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay DS 18 BPNOV ADS-10SD 273 Prudhoe Bay DS W-59 BP
North Slope - Offshore
BPTop Drive, supersized Liberty rig Inactive BP
Doyon DrillingSky top Brewster NE-12 15 (SCR/TD) Spy Island SP21-NW1 L1 ENI
Nabors Alaska DrillingOIME 1000 19AC (AC-TD) Oooguruk ODSN-02 Caelus Alaska
Cook Inlet Basin – Onshore
Miller Energy ResourcesMesa 1000 Rig 37 Mobilized to North Fork to begin Miller Energy Resources drilling this winter
All American Oilfield AssociatesIDECO H-37 AAO 111 Going over to Trading Bay Cook Inlet Energy to perform a workover starting on 10/3/14
Aurora Well ServicesFranks 300 Srs. Explorer III AWS 1 Sterling, Stacked out at D&D yard Available
Doyon DrillingTSM 7000 Arctic Fox #1 North Kenai, stacked Nordaq
Nabors Alaska DrillingContinental Emsco E3000 273E Kenai AvailableFranks 26 Kenai StackedIDECO 2100 E 429E (SCR) Kenai StackedRigmaster 850 129 Kenai Available
SaxonTSM-850 147 Ninilchik Unit, Bartolowits pad Hilcorp Alaska drilling Frances #1TSM-850 169 Swanson River Hilcorp Alaska
Cook Inlet Basin – Offshore
XTO EnergyNational 110 C (TD) Idle XTO Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151 Furie Upper Cook Inlet KLU#1Cook Inlet EnergyNational 1320 35 Osprey Platform RU-1, workover Cook Inlet Energy Hilcorp Alaska LLC (Kuukpik Drilling, management contract) Monopod Platform, Drilling Trading Bay ST A-31 Hilcorp Alaska LLC
Patterson UTI Drilling Co LLC 191 West McArthur River Unit #8 Cook Inlet Energy
Kenai Offshore Ventures LeTourneau Class 116-C, Endeavor Port Graham Buccaneer Energy Ltd. jack-up
Mackenzie Rig Status
Canadian Beaufort Sea
SDC Drilling Inc.SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available
Central Mackenzie Valley
AkitaTSM-7000 37 Racked in Norman Well, NT Available
Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of October 30, 2014.
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* Oct. 24 Oct. 17 Year AgoUS 1,927 1, 918 1,738Canada 426 417 404Gulf 53 55 60
Highest/LowestUS/Highest 4530 December 1981US/Lowest 488 April 1999Canada/Highest 558 January 2000Canada/Lowest 29 April 1992 *Issued by Baker Hughes since 1944
The Alaska - Mackenzie Rig Report is sponsored by:
JUDY
PAT
RICK
By GARY PARKFor Petroleum News
An unprecedented intervention fromthe United States is pitting
Washington state Indian tribes againstKinder Morgan’s plans to expand its TransMountain crude pipeline from Alberta tothe Pacific Coast.
Tribal leaders testified before Canada’sNational Energy Board to voice their con-cerns about a dramatic increase in thenumber of oil tankers that would resultfrom increasing the pipeline’s shipmentsof crude bitumen from the oil sands to890,000 barrels per day from 300,000 bpd.
The existing pipeline delivers crude toBurnaby in Metro Vancouver and toWashington state.
Under the expansion, Trans Mountaincould load 34 tankers a month — com-pared with about five currently — atBurnaby’s Westridge dock from wherethey would generally travel through HaroStrait west of San Juan Island and the
Strait of Juan de Fuca on their way to mar-kets in Asia and the United States.
The tribal leaders, marking the firsttime U.S. tribes had appeared before theNEB, said the dangers of such an increasein tanker traffic posed a threat to their wayof life, culture and the environment.
Brian Cladoosby, chairman of theSwinomish Indian Tribal Community nearAnacortes, told the regulatory panel thathis 900-member tribe relies on salmon,shellfish and other natural resources.
Leonard Forsman, chairman of theSuquamish Tribe on the Kitsap Peninsula,said “the more traffic there is, the more oilthere is, the more opportunity there is for acatastrophic spill. We’re concerned about(what that would do) to the ecosystem.”
Although the U.S. tribes don’t speak forCanadian citizens they are “profoundlyimpacted by the project” and share a cul-ture with the Coast Salish people inCanada, said Jan Hasselman, a lawyerwith Earthjustice representing the tribes.
Gary Youngman, the lead for Trans
Mountain’s aboriginal engagement, saidKinder Morgan respects the tribes’ inputand values its relationship with them.
He promised every effort would bemade by Kinder Morgan to minimizeimpact and protect the environment.
The NEB panel is expected to release afinal report in January 2016 with a recom-mendation to the Canadian government.
Survey can continueSeparately, the drawn out battle
between Kinder Morgan and the City ofBurnaby has seen the company claim arare success.
The NEB issued an order allowingKinder Morgan to continue survey workthat could see it reroute the pipelinethrough a mountain in Burnaby.
But Burnaby Mayor Derek Corrigansaid his council will not give up the fightgiven that the survey work will take placeon city land.
“It’s not surprising that the (NEB) willattempt to extend their authority to run ourcity. I’m not surprised by it,” he said. “Ifwe are going to resolve this issue it willend up in federal courts.
“We are not going to accept this asbeing the final word for us,” he said, indi-cating the city will likely appeal after con-
sulting its lawyers.In the meantime, Kinder Morgan,
which did not comment on the NEB deci-sion, must give the city 48 hours writtennotice before resuming survey work.
The NEB also ruled it had the authorityto consider the constitutional question ofhow far its powers extended, while theCity of Burnaby argued the matter shouldbe handled by the British ColumbiaSupreme Court.
Agreement with Paul First NationThe company also reported a milestone
agreement with the Paul First Nation, anaboriginal community of 2,000 occupyingland on the Trans Mountain right of way30 miles west of Edmonton.
The mutual benefits agreement coverseducation and training related to pipelineconstruction and business opportunitiesfor the First Nation’s own companies andits joint-venture partnerships.
Paul Chief Casey Bird said the agree-ment extends beyond his community’s tra-ditional lands to include timber used tobuild mats that protect soil and reduceenvironmental impact. l
l P I P E L I N E S & D O W N S T R E A M
US tribes oppose Trans Mt pipeline plansTribal leaders tell Canada’s NEB Kinder Morgan’s expansion poses serious consequences for way of life, Pacific Coast environment
4 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
Kay Cashman PUBLISHER & EXECUTIVE EDITOR
Mary Mack CEO & GENERAL MANAGER
Kristen Nelson EDITOR-IN-CHIEF
Susan Crane ADVERTISING DIRECTOR
Bonnie Yonker AK / NATL ADVERTISING SPECIALIST
Heather Yates BOOKKEEPER & CIRCULATION MANAGER
Shane Lasley NORTH OF 60 MINING PUBLISHER
Marti Reeve SPECIAL PUBLICATIONS DIRECTOR
Steven Merritt PRODUCTION DIRECTOR
Alan Bailey SENIOR STAFF WRITER
Eric Lidji CONTRIBUTING WRITER
Wesley Loy CONTRIBUTING WRITER
Gary Park CONTRIBUTING WRITER (CANADA)
Rose Ragsdale CONTRIBUTING WRITER
Ray Tyson CONTRIBUTING WRITER
Judy Patrick Photography CONTRACT PHOTOGRAPHER
Mapmakers Alaska CARTOGRAPHY
Forrest Crane CONTRACT PHOTOGRAPHER
Tom Kearney ADVERTISING DESIGN MANAGER
Renee Garbutt CIRCULATION SALES
Ashley Lindly RESEARCH ASSOCIATE
Dee Cashman RESEARCH ASSOCIATE
ADDRESSP.O. Box 231647Anchorage, AK 99523-1647
NEWS [email protected]
CIRCULATION 907.522.9469 [email protected]
ADVERTISING Susan Crane • [email protected]
Bonnie Yonker • [email protected]
FAX FOR ALL DEPARTMENTS907.522.9583
OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 19, No. 44 • Week of November 2, 2014
Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518(Please mail ALL correspondence to:
P.O. Box 231647 Anchorage, AK 99523-1647)Subscription prices in U.S. — $98.00 1 year, $176.00 2 years
Canada — $185.95 1 year, $334.95 2 years Overseas (sent air mail) — $220.00 1 year, $396.00 2 years“Periodicals postage paid at Anchorage, AK 99502-9986.”
POSTMASTER: Send address changes to Petroleum News, P.O. Box 231647 Anchorage, AK 99523-1647.
www.PetroleumNews.com
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-
tract services to PetroleumNewspapers of Alaska LLC or are
freelance writers.
NATURAL GASInterior Energy Project hits milestones
A project to bring natural gas to the Fairbanks North Star Borough by 2016recently reached milestones at its upstream and downstream components, accordingto sponsors.
All permits for the North Slope liquefied natural gas facility are in place, accord-ing to the Alaska Industrial Development and Export Authority. And the InteriorGas Utility is now taking bids for the plastic distribution pipelines to be installed inNorth Pole next year.
With the permitting program for the North Slope plant complete, AIDEA said itcan now move toward closing on the financial arrangements with its private sectorpartner and then start procurement. AIDEA intends to hit both of those targets bythe end of the year.
AIDEA and the global infrastructure firm MWH Americas Inc. signed a conces-sion agreement in September. The agreement established a legal framework forAIDEA to own and MWH subsidiary Northern Lights Energy LLC to build andoperate the plant.
Within Prudhoe boundariesThe partners intend to build the North Slope LNG facility within the boundaries
of the Prudhoe Bay unit. With assistance from unit operator BP Exploration(Alaska) Inc., AIDEA significantly sped up the process of securing the final air
see ENERGY PROJECT page 6
PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014 5
40+YEARS WORKING IN ALASKAWith decades of Alaska-based experience, Fugro delivers comprehensive survey and geotechnical services for every phase of the project lifecycle.
Fugro, Tel: +1 907 561 3478Email: [email protected], www.fugro.com
By STEVE QUINNFor Petroleum News
House Resources co-chairman Eric Feige is windingdown his four-year career in the Legislature, a two-
term commitment that put this Chickaloon Republican onthe front lines of some critical oil and gas legislation.
Feige, who did not win his primary race, led the com-mittee through hearings on Gov. Sean Parnell’s oil taxchange (Senate Bill 21) and natural gas pipeline and LNGexport legislation (SB 138) among others.
Feige recapped his tenure as co-chair with PetroleumNews.
Petroleum News: What do youthink characterized your fouryears as co-chair?
Feige: The last four years therecertainly were some pretty majorissues we waded through and basi-cally got laws changed to improvethe investment climate for oil in thisstate. SB 21 was certainly a majoraccomplishment. It was a long battle to roll back ACES.It was gratifying to see the people defeat Ballot Measure1.
Petroleum News: As you look at SB 21, do you thinkit’s durable? Is there any component in there that mayneed tweaking two, four, six years down the road?
Feige: I think it’s probably a little too early to tell.Right now the price of oil is about $80 a barrel. That wascertainly not forecast. One of the things I looked back onas we were putting that bill together, we were knockingdown the tax rate at the upper prices levels.
One of the things we did with SB 21 that is coming inhandy now is that we actually raised the prices at lowertaxes. So below $90 a barrel, the state is actually taking inmore because of the minimum tax clauses we put in. Theimprovements to the investment climate have certainlystarted to show results. We’ll see how long this priceretraction lasts and we’ll see how much that affects theinvestment. As far as SB 21 goes, we’ve got to resist theurge to keep tweaking things all the time. We need a sta-ble investment climate and we need consistency.
Petroleum News: There was still concern about get-ting a meaningful definition of new oil, say as opposedto more oil. Do you see that being a problem ahead?
Feige: that was something we spent a lot of time on.The oil that’s there in the legacy fields and already haswells punched into those formations; that oil was going tobe produced one way or the other. It might have beenproduced under ACES at some point, maybe later ratherthan sooner. But what we were looking to do wasimprove the investment climate so that companies couldgo after those new pools of oil.
New oil is oil that comes from a reservoir that has not
been tapped into, as yet undiscovered, previously uneco-nomic, or for whatever reason it had not been developedat the time we passed the bill. It’s going to take invest-ment to bring that oil to market. The way we all looked atit was this was oil we do not have now and would not seein the near future because of the way ACES had beenimplemented. Given a lower tax rate on new oil and itresults in that oil coming to the surface, going to marketand it the state collecting a royalty and production tax onit, that’s one we could not have counted on under ACES.
Petroleum News: Do you think the state will be ableto differentiate between new oil and more oil?
Feige: I think we use the definition in the statutes thenit will be new oil. Will the people of the state understandthe difference? Yeah, it’s kind of a technical nuance.People can say what they want. We looked at the legacyfields as oil that would be produced no matter what. Wewere looking to get additional oil out of there.
Petroleum News: People who favored ACES said itneeded time to work when it firstcame out. Do you believe that shouldbe afforded to SB 21?
Feige: Time will tell. I think it’simportant for Alaska to kind of sit onwhat we have and give it time to work.Just in the short term we were lookingto improve the investment climate and bring more invest-ment to the state. Certainly in the short term, that hap-pened. You are seeing more drilling rigs committed to theslope. Commitments to purchase or lease, then bring upnew rigs, plus the additional jobs that come with thosenew rigs. The anecdotal evidence I hear talking to peoplein my district who work up on the slope, they’ve neverseen it busier. I think that is good news. It helped guidepeople’s decision to uphold SB 21.
Petroleum News: Speaking of development andanecdotal evidence, Conoco just announced a new padsanctioned. Is that what you had in mind?
Feige: I believe that’s 2S, which is basically new oil,which they proposed. I’m happy that it’s a new pad, andthat means you’re drilling in a new area. That’s going tocount as new oil. That would be my guess. That’s whatwe intended. From my perspective, it’s gratifying thatConocoPhillips as a company has decided to commithundreds of millions to developing new sources of oil. Ifthey did it because of a change we made in the tax struc-ture, that’s what we intended.
Petroleum News: You’ve flown people to the slopefor your work; do you see your work picking up nowthat you can devote time year round?
Feige: Oh, I don’t know. I’m optimistic that there willcertainly be more work. It depends on what the price ofoil does and what the companies feel the price is going tobe in the near future. I think most of them look at this asa relatively short-term retraction, then it will go back
above $100.
Petroleum News: Now that the debate over oil taxeshas died down do you think it will be easier for theLegislature to move forward on other things?
Feige: I think the Legislature should set aside oil andlet the work the 28th Legislature did, well let it work.Will they be able to do that, there are so many things thatdrive that, but I’m optimistic they will be able to let it liefor the time being.
Petroleum News: Let’s move on to the natural gasline and LNG export project. You folks delved into itand capped it off with some late meetings, but cameaway with a product most seemed to like thus far. Whatare your thoughts on how SB 138 played out?
Feige: That was a major achievement. I think we madesignificant progress. The idea of having the state act as apartner, both in taking on risk as well as increased rewardis a good thing. And there was a lot of back and forthwith the executive branch and the companies, and then
within the Legislature some of the enhance-ments that we felt were necessary to basicallycover the interests of the state. Things like theproperty tax revenue and payment in lieu oftaxes and how those impacts in those commu-nities, along the pipeline route, how thoseimpacts will be dealt with. We saw a great spir-
it of communication, not only with the governmentsalong there, but the companies. I think they will all beable to work together to address those issues. Quitefrankly, I was pretty encouraged by the level of coopera-tion that the companies exhibited not only working withthe state but also working among themselves.
Petroleum News: The debate over this bill wasn’tnearly as contentious as the oil tax debate and publicdifferences didn’t linger as with the oil tax discussion.Why do you think that was?
Feige: I think both sides of the aisle realize the gaspipeline project will bring significant benefits to the peo-ple of the state. Not only revenue going to the govern-ment, but just that lower cost energy that will be distrib-uted through the state as much as we can do that.
Petroleum News: Should we be optimistic about thedevelopments such as the applications to FERC andEnergy Department or was this really to be expected?
Feige: Each one of those actions was part of the time-line when we put this thing together. I guess on one hand,I’m encouraged that everything the partners said wouldhappen did happen and it happened on time. They obvi-ously are moving forward on their work. Hopefully itcontinues. Hopefully this retraction of oil prices does nothave a significant impact on the project moving forward.There are a lot of things going on external to the state inthe global LNG market. There are a lot of entities fighting
l G O V E R N M E N T
Feige: SB 21 benefit with low oil pricesOutgoing House Resources co-chair says role of state as partner in LNG project significant; encouraged by companies working together
REP. ERIC FEIGE
see FEIGE Q&A page 17
6 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
The State of Alaska, Department of Natural Resources, Division of Oil and Gas, is currently
recruiting for a Deputy DirectorJob Duties:
• Lead and collaborate with a diverse team of geoscientists, engineers, leasing, accounting, permitting, commercial, economic and legal professionals to evaluate, under Alaska Statutes and Regulations, issues relating to and the skills necessary to:• Form and administer oil and gas units;• Negotiate, draft and administer agreements between the State, the oil industry, Native corporations, local
governments, the federal government, and private individuals;• Interpret existing agreements, evaluate industry compliance with, and propose modifications or successor
agreements as necessary;• Consult with the Attorney General’s Office to assist in preparation of court documents, provide support and/or
testimony in litigation or legal negotiations;• Exercise project management principles in a collaborative and team-oriented work environment.
• Additional duties could include:• Exempt and Non-exempt personnel management;• Public testimony before State and National Legislators and general public
The successful candidate will demonstrate:
• Knowledge of Alaska oil and gas issues.• Knowledge of technical aspects of oil and gas exploration and development• Familiarity with Alaska Statutes, especially Title 38 and Title 31, and Alaska Regulations, especially Title 11 and Title 20.• Excellence in developing and maintaining working relationships both internal and external to an organization which
addresses and resolves complex management issues.• Strong project management, teamwork, and leadership experience and abilities.• Outstanding communication skills.• Strong negotiating and problem solving skills.
Education:
Required: College degree from a four-year accredited institution.Strongly preferred: Degree in petroleum engineering or geosciences. Secondarily preferred: Degree in resource management or law.
Selection Process:
The interview process may include up to three interviews. The successful applicant will be appointed by the Governor ofthe State of Alaska, and serves at the pleasure of the Governor and the Commissioner, Department of Natural Resources.Starting salary is dependent upon qualifications and experience.
To Apply:
Please submit the following items via e-mail to [email protected] before 4:00 p.m. on November 14, 2014:
1. Resume (detailing applicable knowledge and experience);2. List of three (3) professional references, at least one of which must be a current or past supervisor.
Notice to Applicants:
The State of Alaska complies with Title I of the Americans with Disabilities Act (ADA). Individuals with disabilities, who require accommodation, auxiliary aids or services, or alternative communication formats, please call 1-800-587-0430; or465-4095 in Juneau; or (907) 465-3412 (TTY); or correspond with the Division of Personnel & Labor Relations at 10th Fl.State Office Building, PO Box 110201, Juneau, AK 99811. The State of Alaska is an equal opportunity employer.
15G-10-033
quality control permit and associatedreports, according to AIDEA ExecutiveDirector Ted Leonard.
“We are grateful for BP’s help on mov-ing this critical part of the Interior EnergyProject forward,” Leonard said in a state-ment. “Their assistance allowed for a thor-ough and prompt analysis of the air permitapplication, and meant that AIDEA did nothave to expend valuable time andresources on gathering base data for thefinal permit needed to build the plant.”
The Interior Energy Project will truckLNG to the Fairbanks North Star Borough,where it will be re-gasified and deliveredto consumers on at least two distinct grids.
The Fairbanks Natural Gas grid is
already operational, although the utilityintends to expand its operations within thecity of Fairbanks using a $15 millionAIDEA loan.
The municipal Interior Gas Utility isbuilding a new grid in the city of NorthPole that will expand throughout the bor-ough. The utility is now taking bids. “Tobegin construction as soon as possible in2015, this large amount of pipe needs to beordered before December 2014,” InteriorGas Utility Project Manager David Prusaksaid in a statement. “We are grateful towork with AIDEA representatives whocontinue to be flexible and understand thecomplexity of this project and the aggres-sive timeline before us.”
—ERIC LIDJI
continued from page 4
ENERGY PROJECT
By ALAN BAILEYPetroleum News
A group of residents from the villageof Nuiqsut on the North Slope have
told the federal District Court in Alaskathat a report filed in September by theU.S. Army Corps of Engineers has failedto provide an adequate explanation ofwhy the Corps did not prepare an SEIS,or supplemental environmental impactstatement, when permittingConocoPhillips’ CD-5 oilfield develop-ment in the northeastern NationalPetroleum Reserve-Alaska, the first fieldto be developed in the reserve.
Dredge-and-fill permitThe permit at the center of the dispute
is the Corps’ dredge-and-fill permit. Thevillagers launched an appeal against thepermit in federal court in February 2013,saying that the CD-5 project had changedand new information had become avail-able since the Corps published an FEIS,or final environmental impact statement,in 2004. The FEIS encompassed thepotential development of several satellitefields to the Alpine oil field, includingCD-5. Under the terms of NEPA, theNational Environmental Policy Act, thechanged circumstances of the CD-5 proj-ect require revisions to the FEIS, the vil-lagers claimed.
In May of this year U.S. District JudgeSharon Gleason ruled that the Corps hadviolated NEPA by not explaining why it
had decided not to prepare a revised EISfor the CD-5 project. The judge orderedthe Corps to prepare an explanation for itsdecision. But, noting that the plaintiffs inthe appeal had not filed suit until morethan a year after the Corps had filed thedredge-and-fill permit, Gleason declinedto cancel the permit, thus allowingConocoPhillips to proceed with its CD-5development while the appeal case isbeing resolved.
Supplemental reportIn September the Corps complied with
the court order by filing a supplementalinformation report, setting out the reason-ing behind its decision not to rework theFEIS. The report says that in 2011 theCorps conducted a review “in light of themost current information about the poten-tial impacts of the proposed activities anddetermined that there were no significantchanges that altered the analysis underly-ing the 2004 FEIS.” Neither had therebeen any changed circumstances at theCD-5 development site, the report says.
The plan for the CD-5 project thatConocoPhillips finally permitted fellwithin a mid-range of alternatives consid-ered within the FEIS, with projectchanges “encompassed within the con-cept” of the Corps’ preferred alternative
for the project, as documented in theFEIS, the report says. And almost all thechanges mitigated potential adverseimpacts noted for that alternative, it says.
Changes to the CD-5 project plansince FEIS publication consist of the relo-cation of a bridge for crossing a channelof the Colville River; the re-alignment ofthe CD-5 access road; an increase in thesize of the CD-5 pad and a re-alignmentof the pad; the construction of two smallbridges as alternatives to culverts; anincrease in the impacted area of waters ofthe United States; and some additionalmeasures for reducing project environ-mental impacts, the Corps reported. TheCorps presented detailed justifications fornot viewing any of these changes asinvalidating the FEIS, saying for exam-ple, that the revised bridge location lieswithin a range of locations considered inthe FEIS.
Villagers respondIn a response filed on Oct. 14 the vil-
lagers who are appealing the Corps per-mit argued that the CD-5 project changesare substantial. The changes involve a 30-percent increase in gravel fill, and 43 per-cent lengthening of the access road, aswell as the addition of more and largerbridges, the villagers wrote. The Corpshas failed to present a reasoned analysisof why the project changes should beviewed as insignificant, they said.
“The project necessarily created newimpacts to the area’s complex hydrology,
wildlife, tundra, soils and aquatic habi-tat,” the villagers wrote.
And the villagers disagree with theCorps’ view that the changes fall withinthe scope of alternatives considered in theFEIS.
“The road and bridge locations werealso shifted several miles south and com-pletely rerouted from their original loca-tion — or any location considered in the2004 FEIS,” they wrote. “The Corps can-not avoid supplemental NEPA review bysimply ‘cobbling together’ portions ofalternatives that had been analyzed earli-er.”
New informationNew information that has become
available since the FEIS was completedincludes new insights into climatechange, and its potential impact on theproject, and the potential cumulativeimpacts of other projects in the CD-5region, the villagers have argued. TheCorps says that there has been no newinformation of sufficient impact to war-rant a revisit of the FEIS, while the vil-lagers say that the Corps has acted in anarbitrary manner by not formally assess-ing how new information may requiresome rethinking of the project impacts.
Judge Gleason has yet to rule on thelegal adequacy of the Corps’ supplemen-tal information report. l
l E X P L O R A T I O N & P R O D U C T I O N
Villagers reject Corps CD-5 explanationSay that reasoning behind decision not to modify SEIS relies on unsupported and conflicting statements relating to project changes
Judge Gleason has yet to rule onthe legal adequacy of the Corps’supplemental information report.
By GARY PARKFor Petroleum News
The response to the British Columbiagovernment’s big push to entice glob-
al energy giants to launch the province’sLNG industry has remained mostly sub-dued and non-committal as companies girdthemselves for the next phase in their deci-sion-making process.
While that takes shape some analysts arevoicing hope that the province could nowbe within months, or perhaps a few years, ofcorporate sanctioning for a handful of thelarger ventures.
British Columbia’s key selling featuresremain its vast natural gas deposits and itsproximity to the Asian markets.
But there is still a delicate balancing actbetween the obvious upside and the doubtsall players have over the capital costs, theavailability of skilled labor, the slow pace ofregulatory approvals and other taxes andregulations.
Some of the sharpest criticism comesfrom Jack Mintz, director of the School ofPublic Policy at the University of Calgary,who wrote in the National Post that the newfiscal regime “discourages LNG develop-ment.”
He said the policy “should be taken forwhat it is: A revenue grab without muchthought given to economic or policy objec-tives.”
“It sets a precedent of taxing differentlyone form on business activity compared toothers, distorting the allocation of capitaland labor in the economy.
“Instead of moving to a smart efficienttax system with respect to resource devel-opment, the province has created a poorpublic policy precedent for the comingyears,” Mintz said.
Separate decisionsGaetan Caron, a former chairman of
Canada’s National Energy Board and a col-league of Mintz’s at the University ofCalgary, said that regardless of whether theprojects are controlled by foreign govern-
ments or the private sector, each proposalwill make its own decision based on coststructures and the complexities of their pro-posals.
He suggested to the Financial Post that itis unlikely proponents will react in unisonto the tax regime, which is set at an initial1.5 percent of operating income followedby 3.5 percent after the recovery of invest-ment costs.
That is minimally offset by a 0.5 percenttax credit for the cost of natural gas provid-ed to an LNG facility of up to 3 percentagepoints of corporate taxable income (thuslowering the corporate tax rate to 8 percentfrom 11 percent).
Greg Pardy, an analyst at RBC Capitalmarkets, said in a report to clients that hisfirm views the tax structure as “a positivedevelopment in the context of intensified
LNG supply competition from the UnitedStates, East Africa and elsewhere. It wouldappear that British Columbia’s LNG taxwould not unduly burden a sector that hasyet to come into existence.”
Peters & Co, the Calgary-based invest-ment banker, said the tax represents a mod-est 30 cents per thousand cubic feet of gasfor an integrated project.
It told clients that although that is anincremental cost for developers, LNGexports from the British Columbia coast arelikely to proceed, with up to three projectscommissioned by 2025.
Tough competitionErnst & Young said British Columbia
faces tough global competition, notablyfrom some U.S. projects that are movingahead faster than expected.
“The market continues to develop andtax is only one of the factors that will deter-mine the competitiveness of a CanadianLNG project,” the firm said. “Global sup-ply/demand considerations, costs (both cap-ital and operating), environmental approvalconditions, First Nations support and thestate of the global debt and equity capitalmarkets will all be critical for a viable proj-ect.”
FirstEnergy Capital said in a report thatthe greater risks still stem from initial con-struction costs and the eventual selling priceof LNG in Asian markets.
It said a landed price of US$13 per mil-lion British thermal units could keep projecteconomics and rates of return “relativelyattractive.”
But FirstEnergy suggested that oilprices, which the Asian LNG customerswant to apply as a benchmark, pose a risk.
At Brent crude prices of US$100 perbarrel the LNG price in Japan is aboutUS$15 per million Btu, while a US$90price translates into US$13 for LNG.
Petronas most vocal criticMalaysia’s Petronas, operator of the pro-
posed Pacific NorthWest LNG project andthe most vocal critic of the directions beingpursued by the British Columbia govern-ment and the pace of the regulatory process,said only that it wants more time to digestthe tax regime before commenting.
But the company issued one cautionarynote, telling all levels of government thatthey must “recognize the need to remaincompetitive with other jurisdictions around
l N A T U R A L G A S
Jury out on BC’s LNG tax regimeSubdued reaction to new policy, critic convinced it will discourage development; industry tackles costs, labor, regulatory process
PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014 7
BC favors LNG with new climate-change lawThe British Columbia government has rolled out a new law for greenhouse gas
emissions that Environment Minister Mary Polak said will allow the province to meetits climate-change targets without jeopardizing its chances of an LNG industry.
But achieving that balance will mean tougher action on GHG emissions in othersectors to compensate for the new industry.
If the government attains its revised goal of five LNG plants (from the 18 current-ly being floated), British Columbia’s emissions would total 13 million metric tons ayear, requiring further cuts in transportation and buildings to reach the goal of 41 mil-lion metric tons in emissions cuts by 2020.
“Sure, it’s going to be really difficult,” Polak conceded to reporters.“We are going to have to be drilling down to more and more of the everyday things
that we can do” to lower GHG emissions, she said.To avoid driving away potential investors, Polak said companies will have “flexi-
ble options” to meet the government’s 2020 benchmark, including the ability to pur-chase offsets or to contribute to a fund that is designed to drive innovation in cleanertechnology.
But she would not estimate how much the government will pay towards incentivesto help LNG facilities achieve the benchmark.
David Keane, president of the British Columbia LNG Alliance, representing fiveprospective investors, said the GHG standards will have to be weighed along with thenew LNG tax structure, especially given that the GHG benchmark is “very low.”
The government is not including upstream emissions that result from gas explo-ration, extraction and transportation.
Andrew Weaver, the lone Green Party member of the provincial legislature, said
see LNG FAVOR page 9
see TAX REGIME page 9
By KRISTEN NELSONPetroleum News
The Greater Mooses Tooth 1 develop-ment in the National Petroleum
Reserve-Alaska is one step closer to mov-ing ahead — but not exactly as operatorConocoPhillips Alaska requested.
The federal Bureau of LandManagement released the final supple-mental environmental impact statementfor GMT1 Oct. 29, but said its preferredAlternative B was not Alternative A pro-posed by the company.
The agency said Alternative B “focus-es on keeping the proposed road andpipeline outside of the BLM-establishedFish Creek buffer, and has two fewerstream crossings than Alternative A.”
The agency said it would formallypublish the document in the FederalRegister on Nov. 7 with a record of deci-sion to be issued “at least 30 days after
the publication of the final SEIS.” GMT1 is the development of a discov-
ery made at Lookout and originally pro-posed as drill site CD-6. When it wasdetermined that CD-6 was not in the samereservoir as the Colville River unit, drillsites CD-1 through CD-5, CD-6 wasrenamed GMT1, part of the GreaterMooses Tooth unit.
Drilling pad, road movedBLM said the main differences
between Alternative B and Alternative Ainclude moving the drilling pad some 700feet to the southwest; routing the accessroad and pipeline from GMT1 to the CD-5 drill site south of the Fish Creek set-back; a new tie-in pad for the pipelineeast of the CD-5 drill site; eliminating abridge over Crea Creek and a culvert atBarely Creek.
BLM said Alternative B would have aslightly larger footprint and greater fill
requirement than Alternative A and saidthe route “may be more technically chal-lenging for road construction and mainte-nance (e.g., poor soils, thaw stability) dueto the extent of thaw basins along theroute.”
Both alternatives include an 11.8-acregravel pad, 33 wells and gravel supplyfrom the Arctic Slope Regional Corp.mine site.
Alternative B has a mile more ofaccess road, 8.6 miles compared to 7.6miles for Alternative A, and 18.2 miles ofelevated pipelines on vertical supportmembers compared to 17.9 miles forAlternative A.
The total gravel footprint ofAlternative B is larger at 80.4 acres, com-pared to 72.7 acres for Alternative A.
Other alternatives considered in thefinal SEIS were C, which evaluatedNuiqsut as a hub for industrial activitywith upgrades of roads and the Nuiqsut
Airport; Alternative D1, with no year-round road access between GMT1 andexisting Colville River unit facilities atAlpine; Alternative D2, similar to D1 butwith only seasonal drilling; andAlternative E, the no action alternative.
Congressional delegation disagreesThe Republican members of Alaska’s
congressional delegation, Sen. LisaMurkowski and Congressman DonYoung, objected to BLM’s assessment.
Murkowski said in an Oct. 29 state-ment that Interior’s final SEIS wasreleased “after months of delay,” andrejected ConocoPhillips’ preferred alter-native in favor of “a longer and moreexpensive road option.”
“Though I’m glad Interior has finallyissued this review, I am concerned aboutthe critical project decisions that arebeing left for the record of decision,which could impact whether this projectmoves forward or not,” Murkowski said.Interior needed to finalize the SEIS by theend of October to allow the U.S. ArmyCorps of Engineers and theEnvironmental Protection Agency “suffi-cient time to complete the permittingprocess in time for ConocoPhillips tobegin production by 2017,” but,Murkowski said, BLM will leave its finaldecision open until the Corps and EPAfinish their reviews.
“Federal leaseholders need to have apermitting process that is timely and pre-dictable in order to invest the billions ofdollars it takes to develop America’senergy resources,” she said.
Young said he was “pleased to see aplan that includes an access road,” butsaid he shared “some of the same con-cerns expressed today by industry repre-sentatives that this assessment leaves uswith too many unanswered questionsregarding the future of this project anddismisses a preferred road alternative.”
He also said the BLM assessmentleaves the Greater Mooses Tooth project“up against pending reviews by the EPAand Army Corps of Engineers, whichhave previously held up a number ofAlaskan projects, including productionwithin CD-5.”
“It remains to be seen what mitigationand other requirements will pile onto thisprocess, but for now I am happy to see itmove forward,” Young said.
Conoco has objectionsIn an Oct. 29 statement provided to
Petroleum News by email,ConocoPhillips said:
“We are pleased that the BLM haschosen a roaded alternative as their pre-ferred alternative for GMT1. However,the roaded alternative the agency has cho-sen, Alternative B, is not the alternativethat ConocoPhillips proposed. The pro-posed project, which is Alternative A, hasthe lowest environmental footprint,requires the least amount of gravel, andremains the best Alternative inConocoPhillips’ view. We are currentlypursuing a Corps of Engineers 404 permitfor Alternative A. The Corps has not yetdetermined which alternative is the ‘leastenvironmentally damaging practicablealternative’ (LEDPA). ConocoPhillipsexpects that the BLM has flexibility toapprove the alternative selected by theCorps.” l
l L A N D & L E A S I N G
BLM releases Mooses Tooth final SEISBureau of Land Management preferred alternative includes road, but is not ConocoPhillips proposal; drilling pad, access road moved
8 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014 9
www.lynden.com 1-888-596-3361
At Lynden, we understand that plans change but deadlines don’t. That’s why we proudly offer our exclusive
Dynamic Routing system. Designed to work around your unique requirements, Dynamic Routing allows you
to choose the mode of transportation — air, sea or land — to control the speed of your deliveries so they
arrive just as they are needed. With Lynden, you only pay for the speed you need!
Only pay for the speed you need... Dynamic Routing!SM
the proposed legislation is “shameful ...wehad leadership on the climate change file,but now we have given that up.”
He said the changed rules plan to targetthe “intensity level” of pollution rather thanthe absolute quantity of pollution.
Weaver called for hard caps on emis-sions from LNG and a plan to aggressivelyreduce emissions overall.
He accused the government of promot-ing a “grand illusion ... to convince BritishColumbians that we can have wealth andprosperity from a hypothetical LNG indus-try and still meet our climate targets andcontinue to be good stewards of the envi-ronment.”
Matt Horne, from the Alberta-basedPembina Institute, said the 2020 targetwould be a challenge “even without LNG,”noting the government has “stalled out”after hitting its target in 2012.
—GARY PARK
continued from page 7
LNG FAVOR
the world that currently, or plan to, exportLNG” — a reference in part to labor andconstruction costs.
Petronas has, for now, shifted its atten-tion to lobbying the Canadian governmentto provide financial relief for LNG exportterminals.
It has failed in the past in trying to per-suade the federal government to make taxconcessions related to asset depreciationrates, noting that the federal tax classifica-tion of LNG plants will be vital in deter-mining the economic viability of a project,including capital cost allowance rates.
A British Columbia LNG project in theClass 47 tax category would take 27 yearsto depreciate the bulk of its assets, com-pared with only seven years for a manufac-turing operation in Class 43, the CanadianAssociation of Petroleum Producers hasestimated. Faster depreciation allows com-panies to make tax deductions sooner. l
continued from page 7
TAX REGIME
l G O V E R N M E N T
EPA releases emission rule informationPublishes new data, ideas as part of public comment period for proposed power plant GHG emissions regs; adds Indian Country rule
By ALAN BAILEYPetroleum News
On Oct. 28 the Environmental Protection Agencyannounced that it was making available some new
information and ideas, in connection with the public com-ment period for the agency’s proposed regulations, estab-lishing limits for carbon dioxide emissions from U.S. powerplants. The agency also announced that it proposing an emis-sions rule that would apply to the handful of power plantsthat are located inside Indian Country. The proposed regula-tions set emissions targets on a state-by-state basis — theproposed new rule would bring Indian Country into the reg-ulatory scheme.
Comments on the proposed regulations are due by Dec.1.
State-based limitsThe regulations, which apply to large, commercial power
plants, would set each state a limit on the amount of carbondioxide that can be emitted per unit of power generated.States must develop plans for achieving their emissions lim-its by 2030 through some combination of power generation
efficiency, changes in generation technologies and improvedefficiency of power use. There are required dates for plansubmission. And, if a state does not end up with an EPA-approved plan, EPA will prepare and mandate a plan for thestate.
The target emissions limits are based on a percentage ofeach state’s power-generation-related carbon dioxide emis-sions in 2012.
EPA says that it has already received more than 1.5 mil-lion public comments on its proposals and that, at this point,it is publishing ideas and issues that these comments haveconsistently raised. During what remains of the commentperiod, people can consider these ideas and issues while for-mulating their own comments, the agency says.
Wide range of ideasDuring a press conference announcing the release of the
new information, Janet McCabe, acting assistant administra-tor for EPA’s Office of Air and Regulation, said her agencyhad heard a wide range of ideas and issues from states, stake-holders and the public about the proposed clean power plan.
The additional information that EPA is publishing reflectsquestions that people have commonly raised and does not
relate in any way to making the regulations either more strin-gent or less stringent, she said.
She said that, in particular, the notice of information dis-cusses three issues that have emerged from the commentsthat EPA has received:
• The possibility of having credits for early emissions cur-tailment, and the use of other more flexible arrangements tomeet the requirements of a proposed trajectory of emissionsreductions between 2020 and 2029;
• Additional ideas for using natural gas for emissionsreductions, beyond the possibilities discussed in EPA’s pro-posed regulations; and
• The possibility of a more regional approach to estab-lishing renewable energy targets.
The notice also discusses alternative ways that have beensuggested for calculating state emissions goals, she said.
EPA is also making available emissions data for the years2010 and 2011, in addition to the information already avail-able for 2012. That will enable people to assess the impactof using multiple years rather than a single year as the base-line for the emission levels, McCabe said. l
By ALAN BAILEYPetroleum News
A report issued on Oct. 23 by researchcompany Wood Mackenzie says that
the United States will achieve energy inde-pendence by 2025, based on current trends
in U.S. oil and gas production and con-sumption.
“A country can achieve energy inde-pendence through two channels, it caneither produce more or consume less, andthe U.S. is doing both,” said senior analystJames Brick. “Over the past seven years the
U.S. has added 3 million barrels per day oftight oil and 27.5 billion cubic feet per dayof shale gas to the global energy mix, aspectacular 42 percent increase in U.S. oiland gas production.”
At the same time, improving efficiencyin the use of oil for transportation is causingoil demand to drop, he said.
Export banA key to accelerating the rate at which
energy independence can be achieved is thelifting of a ban on the export of U.S. crudeoil. If the opening up of exports were to liftthe price of U.S. crude by, say, $5 per bar-rel, that could increase oil production by350,000 to 450,000 barrels per day, anincrease that would require about $5 billionof additional investment, Brick said.
But Brick acknowledged that upstreamoil producers would gain most from the lift-ing of the export ban, although oilfield serv-ice companies and rig manufacturers wouldalso benefit.
And, regardless of what happens to theexport ban, evolving technologies will like-ly continue to push up oil and gas produc-tion, Brick said. In particular, techniquessuch as enhanced oil recovery and the re-fracturing of wells are showing much prom-ise and could double hydrocarbon recoveryrates, he said.
Fuel efficiencyAlthough Wood Mackenzie has forecast
the fuel efficiency of the U.S. vehicle fleetto improve by more than 40 percent by2030, fuel efficiency could improve morequickly than that, driving down both oildemand and net oil imports. It is also possi-ble that there could be an increased tenden-cy for people to use cars in preference toless efficient light trucks and sport utilityvehicles.
Factors that could jeopardize theachievement of energy independenceinclude delays in developing critical exportfacilities; the imposition of regulations thatdiscourage well fracking; and energy poli-cies aimed at reducing carbon dioxide emis-sions, thus pushing a greater use of naturalgas for power generation, Brick said.
Wood Mackenzie concludes that, whilethe investments leading to energy inde-pendence will bring economic benefits tothe United States, the direct impacts of thatindependence will be more muted. AndU.S. energy markets will remain linked tointernational risks, Wood Mackenzie thinks.
“Irrespective of the timing of independ-ence, the U.S. has started its transformationfrom energy consuming giant to prominentexporter,” Brick concludes. “With this roleshift come obvious economic benefits butalso shifting risks and new responsibili-ties.” l
10 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
By ALAN BAILEYPetroleum News
The U.S. Department of Energy hasannounced that it has awarded a $41
million grant to a team that will collectsamples and conduct analyses, to bettercharacterize methane hydrate resourcesthat are known to exist in sands underdeepwater areas of the Gulf of Mexico.The idea is to gain insights into the phys-ical properties of the deposits for the pur-pose of methane hydrate resourceappraisal.
Researchers from the University ofTexas at Austin, the Ohio StateUniversity, the Columbia University-Lamont Doherty Earth Observatory, theConsortium for Ocean Leadership and theU.S. Geological Survey will conduct theproject, which will be managed by theOffice of Fossil Energy’s NationalEnergy Technology Laboratory.
Potential gas resourceMethane hydrate consists of methane,
the main component of natural gas,trapped in an ice-like lattice of water mol-ecules. The material, which is stablewithin a certain range of somewhat ele-vated pressures combined with low tem-peratures, is known to exist widely insome subsea settings, and straddling thebase of the permafrost on land in Arcticregions such as northern Alaska. Giventhe vast quantities of methane trappedinside methane hydrate deposits, thedeposits could become prolific sources ofnatural gas, should some viable means ofdeveloping the hydrate resources bedeveloped. On the other hand, there areconcerns that the natural decompositionof the hydrates could release the methane,a potent greenhouse gas, into the atmos-phere.
The Department of Energy has led amethane hydrate research program since
2000, in collaboration with other federalagencies, universities, industry and inter-national programs, to advance the scien-tific understanding of the material’sresource potential and its environmentalimpacts. In recent years DOE has provid-ed funding assistance for the drilling oftwo methane hydrate test wells onAlaska’s North Slope, to evaluate theproperties of permafrost-related hydratedeposits in that region.
Measurement and samplingThe new research project that the
department is now sponsoring will followup on some previous research in the Gulfof Mexico that successfully documentedthe presence of hydrate deposits in certainregions of the gulf. The new project willcollect in-situ measurements and coresamples to characterize the deposits. Theresearch team will assess the potential forproducing natural gas from the deposits
and will further delineate the extent of thedeposits on the U.S. outer continentalshelf.
The research will involve an offshoredrilling program, the collection of sam-ples and the gathering of downhole logdata. Tests will include the measurementof the hydrate reservoir response to short-duration pressure perturbations, DOEsays. Field data and laboratory analyseswill enable determinations of in-situhydrate concentrations, and the physicalproperties and thermodynamic state ofthe hydrate bearing sands, the agencysays.
Although this new research is aimed atthe outer continental shelf, DOE says thatit remains interested Alaska’s methanehydrate deposits and that it intends to fur-ther evaluate production methods for ter-restrial hydrates in the state. l
l E X P L O R A T I O N & P R O D U C T I O N
DOE announces hydrate research projectSelects project to characterize the properties of subsea methane hydrate resources in the Gulf of Mexico outer continental shelf
l E X P L O R A T I O N & P R O D U C T I O N
Report points to energy independenceWood Mackenzie says US will export more energy than it imports by 2025 thanks to higher oil and gas production, lower oil demand
By JEANNETTE LEEResearcher/Writer, Office
of the Federal Coordinator
Constraints on LNG transportLNG shipments are also relatively
inflexible. They need special, and veryexpensive, terminals for supercooling thegas to minus 260 degrees and then regasi-fying on delivery, and the gas usually iscontractually bound to specific destina-tions under the long-term deal signed byseller and buyer. Oil, on the other hand, ismore easily put on tankers and unloadedwherever it is needed.
Transportation constraints have his-torically limited LNG to production,trade and delivery in either of two basins— Pacific and Atlantic. Until Japan’sdemand jumped and prices soared afterthe Fukushima nuclear disaster in 2011,there was minimal cross-basin traffic. Atwhich point increased demand and high-er prices drew more Atlantic Basin LNG
to Japan.Transportation by sea
could one day connect themajor gas regions into aworldwide market, but many moretankers would need to be built.
There are about 4,000 oil tankers inthe world, 500 feet long and larger,according to Poten & Partners, a globalbroker and commercial adviser for theenergy and ocean transportation indus-tries. During 2013, about 360 LNGtankers were in service. An additional108 LNG carriers were on order, accord-ing to an end-of-year report by theInternational Gas Union. There, too, oilhas it beat — 600 oil tankers were onorder, said an August 2014 report byPoten & Partners.
The expansion of the Panama Canalwill help smooth the way for the buddingLNG export trade along the U.S. GulfCoast and cross-basin traffic. Most LNGcarriers are too big to pass through thecanal, but the expansion will enable 90
percent of LNG tankers to transit the isth-mus.
The Panama Canal Authority said in2013 that voyages to East Asia fromCheniere Energy’s Sabine Pass LNGexport plant under construction inLouisiana will be slashed by 20 days,round-trip. (Even so, the round-trip voy-age could still take more than six weeks.)
Liquefaction is expensiveThe price tags of contemporary LNG
projects, both proposed and under con-struction, commonly reach the billions ifnot tens of billions of dollars. Estimatesfor the Alaska LNG project to exportNorth Slope gas to Asia range from $45billion to $65 billion for a gas treatmentplant to remove carbon dioxide and otherimpurities, 800 miles of 42-inch-diameterhigh-strength steel pipe, a huge liquefac-tion plant, LNG storage tanks and amarine terminal.
The cost to process and ship oil to arefinery is small by comparison.
As an example, it costs less than $10to pipe a barrel of Alaska North Slopecrude almost 800 miles to the terminal atValdez and send it by tanker to U.S. WestCoast refineries — leaving 90 percent ofthe value of $100-a-barrel oil for produc-tion costs, taxes, capital investment andprofit.
But for LNG, the pipeline, liquefac-tion and tanker costs of North Slope gasdelivered to Japan could consume two-thirds of the fuel’s value at summer 2014Asian spot-market prices. Simply put, theprofit margin for investors is much slim-mer.
The liquefaction process is a big rea-son for the significant added expense toLNG. Liquefying Alaska North Slope gaswill cost more than moving it 800 milesby pipe to the tidewater plant.
Smaller market, fewer playersThe ubiquitous need for oil means
many parties are either in the business ofselling or buying it.
The huge number of crude oil buyersand sellers worldwide has enabled thecreation of a transparent and liquid mar-ket.
Not so for LNG, which inhabits amuch smaller realm. Oil pretty much hasthe transportation-fuel sector all to itself,while natural gas has to compete in theheating and electricity sectors with anarray of energy sources including coal,nuclear, solar, wind, hydroelectricity,geothermal and even oil.
“Not every country in the world usesgas, and if they do, the quantities will behighly variable, because power genera-tion fuel mixes vary so dramatically,”Nelly Mikhaiel, a New York City-basedsenior consultant at FACTS GlobalEnergy, wrote in a July 2014 email inter-view.
And for consumers who do use naturalgas, only a minority will be part of theLNG trade because pipeline gas deliver-ies cost less. In 2013, about 69 percent ofgas traded between countries flowed viapipeline. The United States, the world’slargest gas producer and consumer, burnsonly a trickle of LNG.
For some customer nations, LNG isused to guarantee supply diversity andsupplement existing pipeline imports, butin other cases, like Japan, it is a muchmore crucial part of the energy supply.
Japan buys LNG because no naturalgas pipelines have been built to the islandnation. In a move that shook the worldLNG market, Japan’s purchases jumped20 percent following the 2011 meltdownat Fukushima, a catastrophe that prompt-
l N A T U R A L G A S
Why LNG doesn’t trade like oilTransportation another difference between oil and gas and long-term contracts make natural gas pricing opaque, unlike crude oil
12 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
Serving Alaska for Over 25 Years
(907) 349-2931
Mountain Work • Sling Load Operations
Crew Haul • Aerial Survey
Aerial Filming • Offshore Operations
Ph: 907-246-3554 Fx: 907-246-3654Web: www.egliair.com
Serving Alaska since 1982
see LNG TRADING page 13
Most LNG carriers are too big topass through the canal, but the
expansion will enable 90 percentof LNG tankers to transit the
isthmus.
ed the Japanese government to take all itsnuclear plants offline.
The dearth of LNG-producing andconsuming countries — or lack of marketdepth — is one impediment to LNGbecoming a globally traded commodity,like oil.
“The huge number of global oil pro-ducers, consumers, traders and shipperswere a factor in the creation of a trulyglobal crude oil market,” Mikhaiel said.
She noted global LNG trade has grownin recent years, with new buyers and sell-ers joining the roster and more on theirway over the next couple of decades. Newor expanded LNG export plants in adozen countries started production in themid-2000s. Even the United States ispoised to join the rush by 2016 when thefirst Lower 48 export project is scheduledto start shipping cargoes from SabinePass, La.
The World Energy Council predictsthat between 2020 and 2050 global natu-ral gas exports by pipeline and as LNGwill almost triple. The push for cleaner-burning fuels is driving much of thatdemand growth, along with expandingeconomies in China, India and elsewhere.
Nonetheless, the enormous increaseforecast by the council will not raise thenumbers of buyers and sellers to the lev-els of those trading oil.
“It cannot and will not approach thesheer number of players that compriseand literally shape the world’s crude oilmarket,” Mikhaiel said. “LNG will neverhave the penetration enjoyed by oil, andhence, will remain comparatively small.”
How much is it, really?With high-speed electronic deals
around the world, traders know howmuch oil costs at a particular moment.Not so for LNG.
Over the past 30 years, three streamsof crude have emerged as the primaryprice benchmarks for the oil trade: WestTexas Intermediate, Brent Blend andDubai. For any contracted amount of oil,one of these benchmark prices is pluggedinto a formula that also takes into accountall sorts of variables that affect price,including quality, transportation andrefining costs.
“The global prices of various grades ofcrude oil are exceedingly transparent, andcan be learned by anyone with a tele-phone and/or an internet connection,”Mikhaiel said.
But because of the different marketconditions that prevail in various regionsof the world, there is no such thing as aglobal LNG price. Rather, natural gas andLNG prices can generally be categorizedby region.
They tend to trade regionally in largepart because of transportation costs andlogistics.
Each natural gas market —Asia-Pacific, Europe and North America — hasseparate internal dynamics that dictatetheir pricing. Their gas markets have dif-ferent histories, sources of supply andvarying degrees of reliance on imports:
Pricing in North America’s gas marketis pegged to gas-on-gas competition; withso many producers and so much gas in theUnited States and Canada, the competi-tion is every other supplier with the sameaccess to the same pipelines.
Asia’s gas prices rise and fall with oilprices, as oil-derived products are a keyalternative source of energy.
Europe’s system tends to be a blend ofthe two.
Oil’s benchmarks are based on spotcrude prices. But spot LNG markets
aren’t deep enough to serve as bench-marks, so they must rely on the closestsubstitute fuel to serve as an approximateprice marker. In Asia, it’s the crude oilprice — calculated on an energy-equiva-lent to gas — because LNG and oil wereused interchangeably there for electricityand heating in the 1970s.
Most of Asia does not have the optionof pipeline gas imports, which is one rea-son its LNG contracts remain chieflypegged to crude oil prices. Buyers andsellers generally negotiate a pricingmechanism in their contracts called an S-curve to protect both sides in times ofhigh and low oil prices. The curve softensthe effects of the oil-price linkage, help-ing buyers when oil prices are high andensuring that sellers don’t give up toomuch when prices are low.
Change is possibleIn recent years, Asian buyers have led
the call to delink the historical price con-nection to oil and instead would like tosee upcoming North American LNGdeliveries priced against the publicly trad-ed U.S. gas market price. (If Lower 48LNG export plants were operating in thesummer of 2014, and their cargoes werepegged to U.S. prices, the LNG would bedelivered to Asia at a significant discountto the traditional, long-term oil-linkedprices.)
Some North American LNG projectdevelopers have balked at this, arguing
that volatile U.S. gas prices would notprovide the security they need to under-write costly liquefaction plants. But otherexport project developers, particularly onthe U.S. Gulf Coast, are open to the newpricing structure, as long as the customertakes the market price risk and they getpaid a fixed rate for their liquefactionservices regardless of gas market prices.
“One indexation is not necessarily bet-ter than the other. It simply depends onhow much risk an individual buyer iswilling to assume in order to have theprice-risk diversity they want,” Mikhaielsaid.
While price negotiations continue,several gas buyers already have signedcontracts for LNG from Gulf Coast andEast Coast plants pegged to the U.S. gaspricing point at Henry Hub, Louisiana,giving them the new supply and pricediversity they want.
In addition to changing benchmarks,LNG pricing could become more trans-parent in the future. Because so manydeals are made privately in long-termcontracts, prices are often hard to pin-point. The Japanese government in April
2014 took a small step to clarify pricingby releasing average prices for spot-mar-ket liquefied natural gas sales.
The move by Japan’s trade ministry,according to Reuters, was intended to“add transparency to an opaque market”amid concern about rising costs in thewake of the shutdown of nuclear plantsafter the Fukushima crisis.
But reshaping LNG pricing and mar-kets to more closely resemble the oil tradewill be a long, slow process.
In its 2013 report on establishing a gastrading hub in Asia, the InternationalEnergy Agency said the transition from amarket dominated by long-term contractsand oil-index-based pricing to a competi-tive market with short-term contracts andmarket-based pricing “doesn’t happenovernight.” l
Editor’s note: Part 1 of this storyappeared in the Oct. 19 issue.
Editor’s note: This is a reprint from theOffice of the Federal Coordinator, AlaskaNatural Gas Transportation Projects,online at www.arcticgas.gov/why-lng-does-not-trade-like-oil.
PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014 13
cruzconstruct.comMain Office (907) 746-3144
North Slope (907) 659-2866
Where the road ends…Our Work Begins
We are proud to announce the launch of our latest division, Cruz Marine LLC. Our ABS Loadline Class tugs are the only double-hulled shallow draft tugs in Alaska and the Northwest. We can transport equipment, materials, and supplies to sites along the Arctic Ocean and Beaufort Sea, the west coast of Alaska or up inland waterways.
Whether by land or water, we can deliver what you need, when and where you need it.
MARINE LLC
Alaska’s Premier Motorola DealerProviding Alaskans with two way radio and wireless communications.
The future of two-way radio.
NORTH SLOPETELECOM, INC.
907.751.8200 | www.nstiak.com
MOTOTRBOTM PROFESSIONALDIGITAL TWO-WAYRADIO SYSTEM.
ComplianceSystems
SafetyPersonnel
ProfessionalServices
907.743.9871TotalSafety.com
Total Solutions:rea A Systems
G Detec Systems
2Safet Consultants
Safet M TrainingRemot rgenc M rt
T Safet r rointegrat fety c ct r fet workersassets, environment.
continued from page 12
LNG TRADINGThe dearth of LNG-producing andconsuming countries — or lack of
market depth — is oneimpediment to LNG becoming aglobally traded commodity, like
oil.
By ALAN BAILEYPetroleum News
The GAO, or GovernmentAccountability Office, has published
the results of a study into the implicationsof lifting restrictions on the export of crudeoil from the United States. The studyreached the apparently contradictory con-clusion that, while the removal of theexport ban would cause the price of U.S.crude oil to rise, the ban removal wouldalso cause a drop in fuel prices for U.S.consumers.
The GAO conducted its study byreviewing four studies on crude oil exports,including two sponsored by industry, andby seeking the views of a variety of stake-holders, including experts from academiaand industry.
Response to embargoThe U.S. introduced restrictions on the
export of domestic crude oil almost 40years ago in response to an Arab oil embar-
go and the economic recession that theembargo triggered. But with a recent rapidgrowth in U.S. oil production, net oilimports have dropped from about 60 per-cent of U.S. oil consumption in 2005 to 30percent of consumption during the first fivemonths of 2014, the GAO says. And netimports are expected to remain well below2005 levels in the future, the agency says.
With U.S. oil prices tending to be a fewdollars lower than international prices, theentry of U.S. oil production into the inter-national market would likely raise U.S.domestic oil prices by about $2 to $8, theGAO says. But the consequent changes in
the international oil market would proba-bly bring international crude oil pricesdown, reducing international fuel pricesand hence reducing U.S. prices for fuelssuch as gasoline and diesel, the agencysays.
However, the GAO cautioned that somestakeholders have pointed out that uncer-tainties over the extent of U.S. oil produc-tion increases, uncertainties over the abili-ty of U.S. refineries to absorb theseincreases; and uncertainties over the possi-ble response of the global crude market toU.S. exports all lead to correspondinguncertainties in assessing the impacts of oilexports.
Heightened U.S. oil prices as a result ofexporting oil could increase domestic oilproduction by 130,000 barrels per day to3.3 million barrels per day over the years2015 to 2035, the GAO suggests. And theresulting increased economic activitywould enlarge the U.S. economy. But theadditional crude oil production could alsopose risks to environmental factors, such asthe quality and quantity of groundwater,the emission of greenhouse gases and theimpacts of oil spills, the agency cautioned.
Strategic petroleum reserveThe GAO also commented on the
implications for the U.S. strategic petrole-um reserve of increased U.S. oil produc-tion — the reserve, a stockpile of storedcrude oil, was established at the same timeas export restrictions were introduced, toact as a buffer against oil supply disruption.
But times have changed. In May 2014the reserve held a 106-day supply, coupledwith private industry reserves of 114 days.These reserves were much higher than thelevels of 90 days of net imports required bythe International Energy Agency, the GAOpointed out. The GAO recommends thatthe Department of Energy should re-exam-ine the petroleum reserves needs, with thepossibility of selling any reserves thatexceed requirements.
Sen. Lisa Murkowski, ranking memberof the U.S. Senate Committee on Energyand Natural resources, welcomed the GAOreport.
“Removing export restrictions areexpected to increase the size of the econo-my, with implications for employment,investment, public revenue, and trade,”Murkowski said. “For example, removingrestrictions is expected to contribute tofurther declines in net crude oil imports,reducing the U.S. trade deficit.” l
14 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
Anchorage Honolulu Los Angeles
• Commercial Diving• Marine Construction Services• Platform Installation, Maintenance and Repair• Pipeline Installation, Maintenance and Repair• Underwater Certified Welding• NDT Services• Salvage Operations• Vessel Support and Operations
• Environmental Services• Oil-Spill Response, Containment and Clean-Up• Hazardous Wastes and Contaminated Site Clean-
Up and Remediation• Petroleum Vessel Services, e.g. Fuel Transfer• Bulk Fuel Oil Facility and Storage Tank
Maintenance, Management, and Operations
American MarineServices Group
6000 A Street, Anchorage, AK 99518
907-562-5420Deadhorse, AK
907-659-9010www.amarinecorp.com • www.penco.org
EXPLORATION & PRODUCTIONAIDEA completes Mustang project deal
The Alaska Industrial Development and Export Authority said Oct. 29 that ithas completed deal structuring with CES Oil Services to jointly finance and ownoil and gas production and processing facilities at the Mustang field on Alaska’sNorth Slope.
AIDEA and CES will own the facility; Brooks Range Petroleum Corp. willbuild and operate the facility. AIDEA will invest up to $50 million.
AIDEA previously invested $20 million for the construction of the Mustangroad and pad.
(See full story in Nov. 9 issue of Petroleum News.) —PETROLEUM NEWS
l F I N A N C E & E C O N O M Y
Miller close to sealing Savant purchaseDeal would give Tennessee company control of Badami oil field on Alaska’s North Slope; new Cook Inlet well nears completion
By WESLEY LOYFor Petroleum News
M iller Energy Resources Inc. says it’s close towrapping up its acquisition of Savant Alaska
LLC.The deal would give Miller control of the small
Badami oil field and related assets on Alaska’s NorthSlope.
In an Oct. 29 press release, Miller said it “hasreceived nearly all the regulatory approvals for its acqui-sition of Savant,” and that the transaction is expected toclose in November.
“Miller estimates that contractual purchase priceadjustments from the May 1, 2014 effective date, as aresult of ongoing production, will lower the effectiveacquisition price to approximately $5.8 million, downfrom $9.0 million,” the company said.
Upon closing, Miller said it expects the acquisitionwould add net production to the company of about 600barrels of oil per day.
Savant is the current operator of the Badami field, theeasternmost producing field on the North Slope. BP orig-inally developed Badami, which performed poorly.Production started in 1998.
Miller announced in mid-May that it had a bindingagreement to acquire Savant.
Under the deal, Miller is expected to acquire a 67.5percent working interest in the Badami unit, with ASRCExploration LLC remaining as a 32.5 percent workinginterest partner.
Tennessee sell-offTennessee-based Miller is a small, publicly traded
company listed on the New York Stock Exchange.The company recently reported total net production of
just over 3,000 barrels of oil equivalent per day. Miller’sproduction comes primarily from Alaska’s Cook Inletregion.
In the Oct. 29 press release, Miller announced it hadreached an agreement to sell “substantially all of itsTennessee oil and gas assets and related liabilities forapproximately $3.3 million in cash.”
The Tennessee deal is expected to close in November,Miller said.
Miller further announced that it “continues its discus-sions with Buccaneer Energy and its principal lender topurchase substantially all Buccaneer Energy’s Alaskaoperating assets out of bankruptcy.”
Well nears completionMiller, via its Anchorage-based subsidiary Cook Inlet
Energy LLC, operates the Osprey platform in the off-shore Redoubt unit.
Miller said it was finalizing completion of a new wellknown as RU-9.
“During drilling and logging RU-9, we saw prospec-tive zones in both the Tyonek as well as the deeperHemlock formations,” said David Hall, Miller’s chiefoperating officer. “We decided first to perforate and testthe Hemlock formation. Initial results revealed high-quality oil with a low water-cut and variable flow ratesthat, at times, appeared well in excess of our expecta-tions.”
Hall added: “Given indications of potential formationdamage around the well-bore incurred while drilling, wedecided to re-perforate the Hemlock formation and con-duct a reservoir analysis. We also decided to perforatethe Tyonek formation while these procedures were tak-ing place and prior to running final completion.”
Following completion of RU-9, Miller said its drillingplans include “several low-risk development oil wells atBadami.” l
l F I N A N C E & E C O N O M Y
Oil exports could reduce fuel costsBut the lifting of the export ban would also cause the price of US oil to rise and increases US environmental risks, GAO says
The study reached the apparentlycontradictory conclusion that,
while the removal of the exportban would cause the price of U.S.crude oil to rise, the ban removalwould also cause a drop in fuel
prices for U.S. consumers.
Oceana asked for a letter that PeterSlaiby, vice president, Shell Alaska, sentto the agency on July 10, requesting afive-year suspension of operations onShell’s Beaufort and Chukchi Sea leases,an action that would in effect extend theoriginal lease terms by five years.
Returned in 2005Shell returned to Alaska in 2005, with
plans to conduct exploration in the state’sArctic outer continental shelf but sincethen has run into multiple issues relating,in particular, to lawsuits against the gov-ernment permits that it needs and againstthe government leasing actions. To date,the company has only succeeded indrilling the top-hole sections of twoexploration wells, one in the Beaufort Seaand one in the Chukchi Sea. Although aseries of issues relating to that drilling,conducted in 2012, appears to have beena prime reason for the company decidingnot to drill in 2013, a continuing appealcase challenging the legality of the 2008lease sale in which Shell purchased itsChukchi Sea leases has caused the contin-uing postponement of further drilling.Shell is also waiting to evaluate the possi-ble impact on its program of new Arcticoffshore drilling safety regulations thatthe Department of the Interior has yet torelease for public comment.
Some of Shell’s Beaufort Sea leasesexpire as soon as 2017. The company’sChukchi Sea leases were issued in 2008on 10-year terms, but are currently undersuspension with no exploration activityallowed, because of the appeal against the
2008 lease sale.
Beaufort Sea planIn his July 10 letter Slaiby said that
Shell, having originally purchasedBeaufort Sea leases, planned to conductdrilling in those leases in 2007 and 2008.But the company abandoned this plan, inpart because of a court decision uphold-ing an appeal against governmentapproval of the company’s explorationplan, Slaiby wrote.
Then, following a legal challenge tothe five-year lease sale program underwhich Shell had purchased its BeaufortSea leases, Shell abandoned a plan to drillin the Beaufort Sea in 2009, he wrote. Thecompany then hoped to drill in theChukchi and Beaufort seas in 2010. Butfollowing a delay in the issuance by theDepartment of the Interior of a new envi-ronmental sensitivity analysis, and thenwith a halt to offshore drilling permittingfollowing the Deepwater Horizon oilspill, Shell’s 2010 drilling hopes came tonaught, Slaiby wrote.
A July 2010 decision by the federalcourt in Alaska to require the Departmentof the Interior to rework its environmen-tal impact statement for the 2008 ChukchiSea lease sale, following the appealagainst that sale, caused Shell to lose its
2011 Arctic drilling season, Slaiby wrote.And contributing to the loss of drillingseasons in the years 2007 to 2011 camedifficulties, delays and legal challenges inthe issue of air permits that Shell neededfor its drilling fleet, he wrote.
2014 court rulingA January 2014 ruling by the 9th
Circuit Court of Appeals, upholding thecontinuing appeal against the 2008Chukchi Sea lease sale, and a subsequentfurther rework of the lease sale environ-mental impact statement, nixed Shell’shopes of returning to the Chukchi Sea forthe 2014 drilling season, Slaiby wrote.
Shell has diligently carried out its obli-gations as a leaseholder and has spentmore than $6 billion on its Arctic Alaskaventure, Slaiby wrote. But the delays anduncertainties, exacerbated by the challeng-ing nature of operating on the Alaska outercontinental shelf, have impacted Shell’sability to conduct a sustainable strategy.
“The limited primary (lease) terms andlack of certainty on whether additionaltime may be granted on the leaseholdspose a significant challenge to Shell’s abil-ity to continue to invest in the AlaskaOCS,” Slaiby wrote. “Suspending theleases for five years now would provideShell assurance that any further invest-ment of the billions of dollars and effort toproceed with exploration and developmentwill not be lost due to expiration of theremaining lease portfolio that would benecessary to support a commercial devel-opment.”
Oceana, in its response to Shell’s letterto BSEE, said that Shell was aware of therisks it was taking when purchasing itsArctic leases.
“Shell spent billions of dollars fullyaware of the risks to that investment, andthe government should not bend the rulesto allow the company to continue businessas usual,” said Susan Murray, Oceana’sdeputy vice president. “Shell deserves nospecial treatment and, to the contrary, hasa track record of irresponsible choices thatwarrants close scrutiny and the higheststandards.”
Other companies applyConoco Phillips spokeswoman Amy
Burnett has confirmed to Petroleum Newsthat BSEE has turned down aConocoPhillips lease extension requestsimilar to Shell’s and that the company hasappealed the decision.
“ConocoPhillips will continue toengage with the government and otherleaseholders to help ensure a clear and sta-ble regulatory program prior to drilling inthe Chukchi Sea,” Burnett said in an Oct.30 email.
Statoil spokesman Jim Schwartz alsoconfirmed to Petroleum News that hiscompany applied to BSEE in July forChukchi Sea lease extensions. Schwartzsaid that Statoil is concerned about com-mitting to the huge cost of Arctic offshoreexploration without certainty about beingable to use its leases.
“Given the realities of working in theArctic and the long lead times … webelieve it’s prudent to confirm if leaseextensions will be granted before contractsare agreed to that have some significantfunding commitments associated withthem,” Schwartz said.
—ALAN BAILEY
PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014 15
continued from page 1
LEASE EXTENSION
gas exploration rights and staking outsites on the Pacific Coast to build lique-faction and tanker facilities.
Changing provincial viewsThe glowing outlook allowed Premier
Christy Clark, an unfailingly cheerfulperson in even the gloomiest of times, tosell the notion of a new industry thatwould invest C$1 trillion over 30 years,spawn 100,000 jobs and allow her gov-ernment to build a C$100 billionProsperity Fund to wipe out BritishColumbia’s debt (currently at C$60 bil-lion), while covering the cost of all imag-inable services and infrastructure.
That shaped a dramatic comebackfrom months of polls pointing to aresounding defeat for her Liberal Partyadministration and got her re-elected by asweeping margin in May 2013, all beforethe healthy margins in global LNG start-ed to evaporate along with the ProsperityFund before it had even been established.
The reversal of fortunes was evidenton Oct. 20 when the government deliv-ered its new LNG tax regime that effec-tively cut in half the royalty tax it count-ed on collecting, all to entice the energybehemoths to make their final commit-ments to LNG projects.
Now British Columbia is not even sureit will play host to an industry, althoughthere could be healthy returns if a handfulof companies does start producing fromthe province’s shale gas basins.
Finance Minister Mike de Jong, whileconceding the outlook for LNG is “notquite as lucrative as it once was,” said heis satisfied British Columbia has made acase for investment in the sector by strik-ing an “appropriate balance that is fairand reasonable for the proponents and fair
and reasonable for British Columbiansthemselves.”
He estimates the government wouldcollect nearly C$800 million from amedium-sized LNG plant in the first yearof production and that would grow mod-estly over the next decade.
In addition, an LNG plant would gen-erate additional corporate, motor vehiclefuel, property and carbon taxes as well asroyalties from natural gas.
De Jong brushed off criticism that thegovernment had been bullied into lower-ing its tax rate by LNG proponents, say-ing only that those companies had
“aggressively” advanced their position.
Report shows appealTo bolster its case within the highly
competitive global industry, BritishColumbia commissioned a report fromErnst & Young that shows its tax and roy-alty regime should be slightly moreappealing to companies than Australiaand the U.S. states of Alaska, Georgia,Louisiana, Texas and Oregon when thefiscal framework in each jurisdiction istotaled up across federal, provincial/stateand local governments.
But the margins — based on low- and
high-price scenarios — are slender in ananalysis that did not cover Qatar, theworld’s No. 1 LNG producer, or Russia,which has the world’s largest reserves andrecently inked a major gas deal withChina, which remains the largest prospec-tive customer for British Columbia LNG.
What the analysis does not cover is thecost of extracting the gas feedstock forLNG, building and operating pipelines tocoastal terminals and shipping the lique-fied product across the Pacific.
—GARY PARK
continued from page 1
BC LNG
“The limited primary (lease)terms and lack of certainty on
whether additional time may begranted on the leaseholds pose a
significant challenge to Shell’sability to continue to invest in the
Alaska OCS.” —Shell Alaska VicePresident Pete Slaiby
16 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
Calista Corp. begins shareholder outreach tourCalista Corp. is set to begin an outreach effort to provide information to shareholders
regarding an important resolution. Shareholders will decide whether to enroll descendants asshareholders in a binding resolution vote at the 2015 annual meeting. This effort was author-ized by shareholders through an advisory vote at the 2013 annual meeting of shareholders.
“The decision whether to enroll descendants as share-holders is a major turning point for Calista Corporation,”said board Chairman Willie Kasayulie. “There are manyfactors for shareholders to consider before making a deci-sion to vote yes or no. Calista will provide many optionsfor shareholders to get the information they need for aninformed vote.”
Calista’s outreach includes a tour of more than 20communities. The tour will include videos in English andYup’ik, and a presentation by Calista’s shareholder relations committee followed by a questionand answer period. By late November, www.CalistaVote.com will feature the videos, committeepresentation, a detailed list of frequently asked questions, and a list of tour dates and locations.By early 2015, a DVD with the videos will be sent to each tribal council and ANCSA village cor-poration in the Calista region.
If more than 50 percent of all shares voted on this resolution vote yes, the resolution will
pass. Should the resolution pass, Calista estimates it will issue the new classes of shares in thefirst half of 2017.
Explore Fairbanks unveils destination marketing video Explore Fairbanks announced that it has unveiled its new destination marketing video at the
2014 Alaska Tourism Industry Assoc. conference. The video incorporates summer and winter images, a host of Fairbanks locals, various modes
of transportation, places to visit and an assortment of activities, dining and more. The 3 minute 41 second video artfully and energetically highlights the many qualities that
define Fairbanks, the Interior, Denali National Park and the Arctic. A local band, Young Fangsprovided the background music for the video, performing their song “Show Me the Way” and isalso featured.
“I’ve been fascinated by the mystique of Interior Alaska for years, everything from the land-scapes and wildlife to the aurora borealis. … I consider Fairbanks to be my second home and Ican’t thank Explore Fairbanks enough for trusting me to help them share the region with therest of the world,” said director and producer Joseph Sliker of Gah! Films.
The original video will be used to market Fairbanks and the region to potential visitors viathe website, through multiple social media outlets, during events and more. Additionally the
ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS
Companies involved in Alaska and northern Canada’s oil and gas industry
All of the companies listed above advertise on a regular basis with Petroleum News
AAcuren USAAECOM EnvironmentAir LiquideAircaft Rubber Mfg. (ARM-USA)Alaska Analytical LaboratoryAlaska Clean Seas (ACS)Alaska CommunicationsAlaska Dreams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Alaska Marine Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Alaska RailroadAlaska Rubber Alaska Steel Co.Alaska TextilesAlaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Alpha Seismic CompressorsAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Arctic ControlsArctic Slope Telephone Assoc. Co-op.Arctic Wire Rope & SupplyARCTOSArmstrongASRC Energy ServicesAT&T . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20Avalon Development
B-FBPBaker HughesBald Mountain Air ServiceBattelle AnchorageBombay DeluxeBrooks Range SupplyCalista Corp.Canrig Drilling TechnologyCarlile Transportation ServicesCCI Industrial Services LLCCGGClearSpan Fabric StructuresCN RailColville Inc.Computing Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2CONAM ConstructionConocoPhillips AlaskaConstruction Machinery IndustrialCook Inlet Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Crowley SolutionsCruz Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Delta LeasingDenali IndustrialDET-TRONICSDowland-Bach Corp.
Doyon AnvilDoyon DrillingDoyon, LimitedDoyon Universal ServicesEgli Air Haul . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12exp Energy ServicesExpro Americas LLCF. Robert Bell and AssociatesFairweatherFive Star Oilfield ServicesFlowline Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19FluorFoss Maritime
G-MGBR Oilfield ServicesGCI Industrial Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11GCR Tires & ServiceGlobal Diving & SalvageGMW Fire ProtectionGolder AssociatesGreer Tank & WeldingGuess & Rudd, PCHawk Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7HDR AlaskaIFR WorkwearInspirationsJudy Patrick PhotographyKakivik Asset Management LLCKenworth Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Kuukpik Arctic ServicesLast Frontier Air VenturesLearn to ReturnLister IndustriesLittle Red Services, Inc. (LRS) . . . . . . . . . . . . . . . . . . . . . . . .12Lounsbury & Associates . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Lynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9MagTec AlaskaMapmakers of AlaskaMAPPA TestlabMaritime HelicoptersM-I SwacoMiller EnergyMotion Industries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7
N-PNabors Alaska Drilling
Nalco
NANA WorleyParsons
NASCO Industries Inc.
Nature Conservancy, The
NEI Fluid Technology
NMS Lodging
Nordic Calista
North Slope Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13
Northern Air Cargo
Northern Electric Inc.
Northrim Bank
Opti Staffing Group
Pacific Alaska Lumber
PacWest Drilling Supply
PENCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14
Pebble Partnership
Petroleum Equipment & Services . . . . . . . . . . . . . . . . . . . . .7
PND Engineers Inc.
PRA (Petrotechnical Resources of Alaska)
Price Gregory International
Remote Access Technology (RAT)
Resource Development Council
Ravn Alaska (formerly Era Alaska)
Q-ZSAExploration
Security Aviation
Sophie Station Suites
STEELFAB
Stoel Rives
Taiga Ventures
Tanks-A-Lot
The Local Pages
Think Office
Total Safety U.S. Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13
TOTE-Totem Ocean Trailer Express
Totem Equipment & Supply
TTT Environmental
Udelhoven Oilfield Systems Services
UMIAQ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2
Unique Machine
Univar USA
URS Alaska
Usibelli
Verizon
Vigor Alaska
Volant Products
Weston Solutions, Inc.
Oil Patch Bits
see OIL PATCH BITS page 17
PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014 17
for the a piece of that LNG markets share. On the onehand, you’ve got folks buying the LNG want to delink itfrom the JCC — the Japanese Crude Cocktail — andyou’ve got people who want to link it. That’s a marketbattle. We need a certain price going forward. We’ll haveto let the market play out. Again, in five years, it will tellthe tale.
Petroleum News: I realize we are only in pre-FEEDwith this project, is there anything that concerns younow?
Feige: I think the only thing that concerns me is whowins the governor’s seat. I’m hoping that Sean Parnellstays on as governor. I think that would provide a highdegree of consistency and sort of steadiness and purpose.I’m not so optimistic if Bill Walker and Byron Mallottcome into office. I’m just not certain as to exactly howBill Walker will treat this project if he comes in as gover-nor. He’s made enough conflicting statements over the lastcouple of years. I think the most important thing the statecan do in the future is be consistent. We’ve put the state onthis particular path right now as a partner. All those littlerelationships are part of the deal. If you start mucking withthat, you have the potential to blow up the deal and we goback to square one. The most important thing for both theexecutive and legislative branch is to stay on path, be con-sistent and not muck with what’s been agreed to.
Petroleum News: Do you think the current path nowthat the project is on will foster future exploration?
Feige: Oh, without a doubt. One of the things that’shindered oil exploration up north was the possibility thatyou go looking for oil and you find gas and you have noway to get the gas to market. With the expansion potentialwe built into this project and the state made allowances forin SB 138, companies may go looking for more oil, but ifthey find gas it’s not such a negative as it has been in pre-vious years. So yeah, overall we are going to see moreexploration. A lot of it will certainly be driven by price.I’m pretty optimistic that between the reforms of SB 21and the project that we outlined in SB 138, we’ve greatlyenhanced the investment climate up on the North Slope aswell as the rest of the state.
Petroleum News: With revenues in decline, do youthink the state can afford to be a partner?
Feige: You know it all depends. We are looking at afinal investment decision that wouldn’t occur for fiveyears. You have to take the position of conserve our cashas best we can. The Legislature will have to address lowoil prices and cut back things accordingly. A certainamount of that is already in the works. The recent pricechanges the last three months is going make that go faster.The state has really no other choice but to cut back on themoney that it spends whether that’s in the capital budgetor the operating budget. I’m optimistic they will rise to theoccasion.
Petroleum News: Let’s go back to the explorationtopic but farther north into Arctic waters. What are yourthoughts on the prospects of that moving forward?
Feige: Well, it depends on who sits in the White House.So far, the federal government has not exactly been a will-
ing partner. They seem to be more of an obstacle in devel-oping those federal lands than anything else. The marketseems to be willing. The companies are certainly willing.It’s the federal government that’s either not leasing thelands or throwing up all kind of road blocks. Just look atwhat they did in the National Petroleum Reserve. Thatneeds to change. That can provide a lot of income for thenation. As far in debt as this nation is right now, whyaren’t we developing those resources to get us out of debt?
Petroleum News: NPR-A will have its lease sale inNovember. Some say it’s window dressing for a sale thatreally isn’t substantive, others say they are good firststeps. How do you see it?
Feige: Well, they’ve had leases come up in NPR-Abefore. The last few years they have taken a lot of thatland off the table. They are calling it de facto wilderness.Under the spirit of it, you are supposed to go to Congressto get a wilderness declaration. This administration hasbasically tried to go around Congress on a lot of fronts. Ithink the federal government could be better at promotingresource development around the country, not just Alaska.
Petroleum News: Still on the Arctic, there are con-cerns that the White House wants to focus its efforts inthe Arctic on climate change rather than economicdevelopment when it takes over as chair for the ArcticCouncil?
Feige: I can see that happening. That seems to be con-sistent with the theme that this administration has beenfollowing.
Petroleum News: So what would you like to see forAlaska on the resource front, either with oil or naturalgas pipelines?
Feige: On the oil and gas side, we need to be consis-tent. We’ve spent a lot of political capital these last threeor four years getting ACES essentially repealed andreplaced with SB 21. I think we need to give it a chance toprove itself. ACES certainly had almost six years and itwas pretty clear that it wasn’t working the way the folkswho conceived it originally had foreseen. SB 21 needs tobe given a fair chance. We passed it believing it will docertain things and we have to give it time to do that. Wehave to be consistent to our investors and put forward asteady hand, not one that is reacting to the whims of who-ever happens to be in whatever seat at the time, whetherit’s the governor’s seat or the resources chairman’s seat.We have to be consistent because Alaska developed a rep-utation of changing its tax regime several times within acertain period. Alaska got a bad rap. The politics are nowswinging around to favor resource development in theU.S. as opposed to other places. We just need to steer asteady course and stick with it.
Petroleum News: You mentioned the state beinginconsistent of going from one tax regime to another.Doesn’t that present a double-edged sword by changingit again?
Feige: The question was, is this the right tax systemnow. I think we need to develop our other-than-oil econo-my. The problem is that it’s kind of difficult. We need todevelop more of our economy but at the same time makesure we keep oil and gas strong.
Petroleum News: I’m not trying to get you to secondguess yourself, but is there anything you might have
done differently in your four years as co-chair?Feige: No, I don’t think so. I wasn’t one of the legisla-
tors who picked up on the latest fad and went with it. If Isaw something that needed to be fixed, we tried to fix it. Iput in what I thought was the best course of action basedon what we knew at the time.
Quite frankly, I think we made some pretty good calls.Take the price retraction we have going on. At the time weput SB 21 in place, the price forecast was to be $100 to$110 a barrel for the next four years. We are a year and ahalf later and the price is down to $80 a barrel.
We also put into SB 21, one of the House Resourcesrevisions to the bill that actually raised the tax rate at thelower end. It was a fair trade, giving the companies moreon the upside and we protected ourselves more on thedown side. That was one of the things that we had to thinkabout and put in the bill on the eventuality that prices did-n’t go in the direction we thought back then.
We put a lot of thought into all of the legislation thatwe moved through the Resources Committee.
I have to say I had a great committee, especially thelast two years. I had some of the longest serving legisla-tors, certainly in the House. A lot of them had beenthrough them all: PPT, ACES, AGIA. So they had somepretty good perspectives and good experience in puttingtogether these types of legislation and they delivered. l
continued from page 5
FEIGE Q&A
video will be used to attract and inform a wide variety ofstakeholders and visitor industry professionals such as touroperators, meeting planners, airline executives, travelagents and media. To view the video please visit:http://youtu.be/UT7L9QDcfU0.
Vigor delivers 15,000 barrel Maxum Petroleum barge
The Seattle divisions of Vigor Fab and Elliott Bay DesignGroup said the 15,000-barrel tank barge Global Pilot hasbeen delivered to Maxum Petroleum.
Designed to balance performance with fabrication cost,the 15,000-barrel tank barge features a recessed machin-ery space aft for improved visibility and a state-of-the-arttankerman’s office. It also has dimensionally identical cargotanks, corrugated plate tank bulkheads and plate seamsarranged to maximize material usage of standard 8-footand 10-foot plates.
“The ability to collaborate closely with Elliott Bay andMaxum throughout this project was the perfect model foran efficient new build,” said Bryan Nichols, director of salesat Vigor Fab. “Our Seattle shipbuilding team is extremelyproud to have fabricated a quality barge which will expandMaxum’s multiple supply capacity in the Puget Sound foryears to come.”
“We’ve been looking forward to seeing the final prod-uct,” stated Mike Complita, EBDG’s vice president of ship-yard services. “It’s always exciting when a new designbecomes reality and goes into service.”
The 15,000-barrel tank barge is one of several bargesthat have been delivered by Vigor to EBDG’s designs overthe past decade. EBDG provided the contract design toMaxum and provided Production Support services to Vigor.
continued from page 16
OIL PATCH BITS
Earlier in the bankruptcy proceedings, AIX Energyhad agreed to be the “stalking horse bidder” in an auc-tion, committing to bid more than $58 million for theAlaska assets.
What’s includedThe sale covers “substantially all” of Buccaneer’s
assets.The most valuable among those assets is the Kenai
Loop gas field. The “field” includes seven leases (twowith the Alaska Mental Health Trust, one with CookInlet Region Inc. and four with the state of Alaska), fourwells and their data files, two drilling pads and associat-ed field infrastructure, all geological and geophysicaldata and existing permits.
The sale also includes considerable office equipment,furniture and software.
The field is currently involved in a correlative rightsdispute before the Alaska Oil and Gas ConservationCommission, which scheduled a public hearing for
December. The field has been illegally draining fromneighboring lands owned by the state, CIRI and the TrustLand Office, respectively. The AOGGC could requirepooling or unitization.
Additionally, some of the Kenai Loop leases areunder appeal or in litigation.
The sale also includes a tract at the former NorthwestCook Inlet unit in the waters of Cook Inlet and a tract atthe onshore West Nicolai prospect on the west side of theInlet.
The buyer will assume 13 contracts from Buccaneer.Those include three gas sales agreements with the EnstarNatural Gas Co.-affiliate Alaska Pipeline Co.; three sep-arate interruptible gas sales agreements with TesoroAlaska Co., Cook Inlet Energy and ConocoPhillipsAlaska Natural Gas Corp., respectively; a liquids saleagreement with Tesoro Alaska involving condensate, andsix leases, easements or other contracts.
Who is AIX?To pursue its broad ranges of projects across Cook
Inlet, Buccaneer assumed considerable debt, including alarge credit facility with Meridian Capital CIS Fund.
Meridian Capital CIS Fund was affiliated withMeridian Capital International Fund, which becameBuccaneer’s largest shareholder in mid-2013 with 19.9percent interest.
Meridian sold the debt to AIX Energy in April 2014.AIX Energy incorporated in Alaska in early May 2014,according to the state. Buccaneer filed for bankruptcy inlate May.
Early in the bankruptcy proceedings, a group of unse-cured creditors raised questions about the relationshipbetween Meridian and AIX Energy. The OfficialCommittee of Unsecured Creditors called AIX Energy “anewly formed shell entity comprised of individual oiland gas operators with whom Meridian had long-stand-ing prior personal relationships.” According to the com-mittee, AIX Energy used a “mirror loan” from Meridianto buy the loan, making the transaction “little more thana book entry.”
The creditors later reached a deal where AIX Energyagreed to pay $10 million into a trust that would beincluded in liquidation plans designed to repay unse-cured creditors. l
continued from page 1
BUCCANEER SALE
and oil viscosity,” according to recent fil-ings with the state Division of Oil andGas. “This information is critical for anyfuture development of this part of theKuparuk reservoir.”
Drill Site 2SARCO discovered an oil accumulation
in the Kuparuk reservoir in the southwestcorner of the unit in the late 1980s withthe KRU 21-10-08 well but never pursueddevelopment.
ConocoPhillips appraised the discov-ery in early 2012 with the Shark ToothNo. 1 well, which the company drilledfrom an ice pad located some four milesfrom Drill Site 2K.
At the time, the company told regula-tors that the well was “critical for anyfuture development of this part of theKuparuk reservoir” because it would“provide additional reservoir informationin this area and narrow uncertaintyaround reservoir description parametersincluding oil-water contact, sand qualityand thickness, and oil viscosity,” lan-guage identical to how the company iscurrently describing the Drill Site 3Swell.
Toward the end of 2012,ConocoPhillips said the well had “discov-ered hydrocarbons in the Kuparuk sands,in accordance with expectations, and con-firmed mapped volumes.”
The southwest corner of Kuparuk wasalready home to three drill sites — 2L,2M and 2K — but developing SharkTooth from any of those facilities wouldhave pushed the limits of existing drillingtechnology, according to ConocoPhillips.Therefore, the company decided to com-mission a new drill site, the first atKuparuk in nearly 12 years.
Drill Site 3SThat last pad was Drill Site 3S, which
ConocoPhillips built to support the Palmsatellite.
Phillips Alaska Inc. discovered thePalm satellite at the western edge ofKuparuk in 2001.
The Palm No. 1 well encountered 30feet of oil-saturated Kuparuk sandstone.An un-stimulated test of the associatedPalm No. 1A sidetrack flowed at some2,500 barrels per day. The company esti-mated recoverable reserves in the range of
35 million barrels.ConocoPhillips brought the satellite
online in November 2003 from Drill Site3S. The accumulation is in a Kuparuk C4interval now known to be in communica-tion with the main Kuparuk reservoir.Palm is generally managed as part of themain Kuparuk field.
In the winter of 2012-13,ConocoPhillips conducted a pilot test onDS 3S-19, one of the original develop-ment wells drilled at Palm in 2003. Thetest involved adding a perforation to thewell and performing hydraulic fracturingoperations to gauge the potential of devel-oping the overlying Cretaceous Brookian
Moraine interval. “Any developmentwould, of course, require adequateappraisal and study to prove commerciali-ty,” the company told state officials in its2013 plan of development, a sentiment thecompany reiterated in its 2014 plan ofdevelopment this past June.
The current project aims to appraise thecommerciality of the Moraine interval.
ConocoPhillips plans to drill the DS3S-620 Moraine well from an ice pad on ADL025528. The pad would connect back toDrill Site 3S using a 2.5-mile ice road.
The state is taking comments on theplan through Nov. 24.
Increased seismicBoth projects resulted from increased
seismic activity over the past decade.The Kuparuk West Sak 3-D seismic
survey in 2005 gave ConocoPhillips “asignificant number of leads for infill orsidetrack drilling,” as the companyexplained in its 2014 plan of develop-ment. ConocoPhillips commissioned acustom built coiled-tubing drilling rig,which has been steadily working throughthose drilling candidates since May 2009.
ConocoPhillips launched the WesternKuparuk 3-D seismic survey in 2011. Theresults of the program led to an “infra-structure-led exploration strategy,” whichfocuses on opportunities near existinginfrastructure, as opposed to the wildcatsConocoPhillips drilled in the far reachesof the National Petroleum Reserve-Alaska in the early 2000s.
A crowded regionAs the westernmost pad in the northern
half of the Kuparuk River unit, Drill Site3S has been an important staging area forother exploration companies exploring tothe west.
Pioneer Natural Resources intended tobuild a gravel road connecting DS-3S toits Nuna development, a scheme that suc-cessor Caelus Natural Resources maybring to fruition.
Repsol built an ice road from DS-3S tosupport exploration activities in early2012. The company is currently preparingdevelopment strategies based upon thatexploration work.
DS-3S is just northeast of the ASRCExploration-operated Placer unit. Theexploration arm of Arctic Slope RegionalCorp. formed the unit to explore aprospect that was contracted from theKuparuk River unit. The Placer unit isunder administrative appeal. l
18 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
Fairbanks location
Anchorage location
Kenworth Alaska with locations in Fairbanks and Anchorage, has beenproviding award winning customer service, parts and truck sales to
Alaskans for over 40 years.
Fairbanks — 2262 Van Horn Rd., 907-455-9900Anchorage — 2838 Porcupine Dr., 907-279-0602
www.kenworthalaska.com
Toll Free — 800-478-0602
Kuparuk River Unit
Oooguruk Unit
PlacerUnit
NikaitchuqUnit
Milne Point Unit
PrudhoeBay Unit
SouthernMiluveach
Unit
KOC
Oliktok Pt
HelmericksAirstrip
Proposed DS3S-620
Ice Pad & Road
ProposedDS2S Pad& Ice Road
0 3.5 7 10.5 141.75Miles
Copyright 2014MAPMAKERS ALASKA
continued from page 1
DRILL SITE 2S
Department of Natural Resources. Thatplan views the Kitchen Lights unit as fourdistinct exploration blocks: the southwestand central blocks in the more southerlypart of the unit; the Corsair block in thecentral part of the unit and the northernblock in the unit’s northeastern sector.The plan of exploration says that Furiemust drill wells in several of those blocks.
Discovery announcementIn the fall of 2011 Escopeta Oil Co., the
company from which Furie was subse-quently spun off, started its drilling cam-paign with the Kitchen Lights unit No. 1well in the Corsair block, announcing onNov. 4, 2011, that it had made a 3.5 trillioncubic feet of gas discovery. Thatannouncement, which met with someskepticism, was followed in March 2012by a more scaled down estimate of gasreserves of 750 billion cubic feet.
In 2011 Furie had suspended thedrilling of the No. 1 well at a depth of8,805 feet. And in the summer of 2012Furie used its Spartan rig to re-enter thewell, continuing the drilling to a depth of15,298 feet. Later that year the companydrilled the Kitchen Lights unit No. 2 welland a sidetrack to that well, while in thesummer of 2013 the company drilled theNo. 3 well to a vertical depth of 10,391feet.
All three of these wells are in theCorsair block. However, later in 2013Furie proceeded to follow the explorationplan requirements by starting the drillingof the Kitchen Lights No. 4 well, this timein the northern block. The company com-pleted that well this summer and, also thisyear, drilled the No. 5 well in the centralblock. The company plans to drill a sixthwell in 2015, with that well lying in thesouthwest block, the last of the blocks tobe drilled.
Resource delineation?Although Furie has obviously drilled
each of its wells in hopes of finding newhydrocarbon resources, the fact that theNo. 1 and No. 3 wells are only about aquarter of a mile apart would seem to sug-gest that a purpose of the No. 3 well wouldhave been the delineation of the discoverymade in the No. 1 well. That conclusionappears confirmed by the fact that Furie’splanned development centers on the No. 3well rather than the No. 1 well, the originaldiscovery well.
In May 2012 Damon Kade, then presi-dent of Furie, told Petroleum News that thepurpose of the No. 2 well was to furtherdelineate the company’s gas find, in addi-tion to seeking new resources.
In July 2013 Furie filed a formal state-ment of a gas discovery with the AlaskaDepartment of Natural Resources. Thatstatement documented a discovery made inthe No. 3 well, saying that the well hadencountered multiple productive gas poolsin the Sterling and Beluga formations atdepths ranging from 3,618 feet to 6,228feet. The statement said that modulardynamic testing had been conducted on 28gas pools and that six pools had been flowtested.
Furie has not announced any otherresults from its drilling.
Drilling recordsHowever, the recent publication by the
Alaska Oil and Gas ConservationCommission of documents relating to thedrilling of the Kitchen Lights unit No. 1well shed a little more light on the situa-tion, while falling short of providing dataneeded to assess the scale of Furie’s gasfind.
These documents include a letter datedDec. 21, 2011, to Alaska’s Division of Oiland Gas from Bruce Webb, now Furie’svice president for government and regula-tory affairs, stating that the intent had beento drill the No. 1 well to a depth of 16,500feet. Webb’s letter explained that a seriesof drilling delays had prevented the com-pletion of the No. 1 well in 2011, but thatthe company anticipated re-entering andcompleting the well in 2012. That re-entrywas indeed accomplished.
Although not mentioned in Webb’s let-ter, other records from the drilling indicatethat a 16,500-foot depth would place thebottom of the well in the mid-Jurassic,below the base of the Tertiary strata thathost all of the current producing Cook Inletoil and gas fields. A 2010 law passed bythe Alaska state Legislature providing for a$25 million tax credit for the first compa-ny to drill into the pre-Tertiary of the CookInlet from a jack-up rig would have pro-vided a strong incentive to drill into thoseJurassic rocks.
Many testsThe drilling reports from the Kitchen
Lights unit No. 1 well confirm that Furiedid indeed encounter gas during the 2011drilling project, with records of substantialflows of gas into the well at various depths,and of modular dynamic testing of poten-tial gas resources at multiple levels. A sum-mary of the various modular dynamic testsindicates 18 tests at depths between 4,247feet and 4,828 feet in the Sterling forma-tion; 15 tests at depths between 5,047 feetand 7,392 feet in the Beluga formation;and one test at between 8,700 feet and8,727 feet in the Tyonek formation.
The continued drilling of the No. 1 wellin 2012 stopped more than 1,000 feet short
of its original 16,500-foot target depth,with the bottom of the well reaching thedeeper part of the Tertiary section, ratherthan the Jurassic. Drilling reports from thewell suggest that the well only encounteredminor quantities of gas below 8,805 feet.And there is no indication of an oil find.Furie did not conduct any tests on the por-tions of the No. 1 well drilled in 2012, thedrilling documents state.
Substantial findThe scale of the gas-field development
that Furie is now engaged in, including theconstruction of an offshore platform andthe laying of a subsea pipeline, implies thatthe company did make a substantial gasfind with its Kitchen Lights No. 1 and No.3 wells. The company’s plan of operations
for its Kitchen Lights development saysthat its offshore platform will be centeredon the No. 3 well, with an initial subseagas line to shore capable of carrying up to100 million cubic feet of gas per day. Theplan includes the possibility of adding asecond, twin pipeline, also with a 100 mil-lion-cubic-feet-per-day capacity. The planof operations also says that development ofthe Kitchen Lights resource is expected toresult in the production of up to 30 billioncubic feet of gas per year.
Meantime, further development atKitchen Lights, and perhaps some furtherinsights into the project, will need to waitfor the melting of the sea ice in 2015, at theend of the coming winter. l
PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014 19
WE KNOW PIPES, INSIDE AND OUT.
Old Tyonek
Granit Pt
Production
Facility
NIk
iski
KLU 5
KLU 1KLU 3
KLU 4
KLU 2 & 2A
ANNA
Proposed
KLU A
BRUCE
GRANITE POINT
Kitchen LIghts Unit
Shadura
Unit
Swanson
River
Unit
Granit Pt
Unit
Corsiar Block
Southwest
Block
Northern
Block
Central Block
Town
Road
Furie Well
Oil & Gas Platform
Oil and/or Gas
Pipeline
Oil & Gas Unit
Boundary
0 2 4 6 81
Miles
Copyright 2014MAPMAKERS ALASKA
continued from page 1
FURIE DRILLING
Furie Operating Alaska has now drilled wells in three of the four exploration blocks in the Cook Inlet Kitchen Lights unit. A gas field devel-opment that is under way is centered on the Kitchen Lights unit No. 3 well in the Corsair block. In 2011 Furie announced a major gas findin the nearby Kitchen Lights unit No. 1 well.
20 PETROLEUM NEWS • WEEK OF NOVEMBER 2, 2014
Instant communication when you need it most.Introducing AT&T Enhanced Push-to-Talk.
We understand how your business works. That’s why we engineered a new push-to-talk service that works better for you.
AT&T Enhanced Push-to-Talk delivers more of everything you need—instant communication, up to 1,000 contacts and fl exible network technology. Plus, it’s available on a broad array of devices and platforms.
Visit your local AT&T store to get your business started today.To learn more, call 1-800-792-9281 or go to att.com/enhancedPTT4
You push-to-talk. We pushed it further.
Information on Enhanced Push-to-Talk, including terms and conditions, can be found online at www.att.com/enhancedptt4. © 2014 AT&T Intellectual Property. All rights reserved. AT&T, the AT&T logo and all other AT&T marks contained herein are trademarks of AT&T Intellectual Property and/or AT&T affiliated companies.
We have alarge polarbear blockingthe entrance.
Roger that.Call us whenall is clear.
