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

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

l N A T U R A L G A S

Vol. 23, No. 37 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of September 16, 2018 • $2.50

page2

Newfield looking at Alaska;Begich, Dunleavy weigh in;L48 shale boom tapering off

TEXAS-BASED INDEPENDENT

NEWFIELD EXPLORATION has people visit-

ing Alaska to look at the North Slope’s geo-

logic potential.

Headquartered in The Woodlands, Texas,

the visiting scientists are not handing out busi-

ness cards to everyone they meet, so the visit

is very hush-hush.

Per the big independent’s website,

Newfield is an oil company focused on profitably growing liq-

uids-rich unconventional resource plays in the Anadarko and

Arkoma basins of Oklahoma, the Williston basin (Bakken) of

State looks for RIK gas interest;includes Prudhoe, Point Thomson

The Alaska Department of Natural Resources, Division of Oil

and Gas, is soliciting interest in potential royalty in-kind natural

gas from the Prudhoe Bay and Point Thomson units.

The solicitation, dated Aug. 31, asks for expressions of interest

by letter within 30 days.

DNR said it is considering whether to take the state’s royalty

on future natural gas production from Prudhoe Bay and Point

Thomson in value or in kind.

“If DNR takes the royalty in kind, it is currently considering a

noncompetitive contract,” solicitation says. The department said

that to consider a noncompetitive contract it “first considers

whether there is a lack of competition and whether a noncompet-

GAO questions lack of preliminarydesign review for polar icebreakers

The U.S. Government Accountability Office has issued a

report raising questions over the reliability of the estimated

cost and schedule for developing new heavy polar icebreakers

for the U.S. Coast Guard. The Department of Homeland

Security, the agency that includes the Coast Guard, has

accepted the GAO’s findings.

Currently the Coast Guard only operates two polar capable

icebreakers: the Healy, a medium duty icebreaker, much used

as a base for polar research, and the Polar Star, which is a

heavy-duty icebreaker but is 41 years old. A third icebreaker,

the Polar Sea, sister ship to the Polar Star, is laid up in port and

has become a source of spare parts for the Polar Star.

Colville barges diesel to SlopeTransportation company Colville has transported 2 million

gallons of diesel fuel by barge to Prudhoe Bay on the North

Slope, the company has announced. This was the first bulk

delivery of fuel to the Slope by barge since the 1990s, and

possibly the largest shipment of its type ever, the company

said. The supply barge, owned and operated by Crowley

Marine, arrived at Deadhorse on Sept. 6. Because of the shal-

low water depths, the barge had to be moored 3 miles off-

shore, with the fuel being carried to shore in smaller vessels.

Onshore, the fuel was pumped into tanker trucks for transfer

to Colville’s tank farm in Deadhorse.

The U.S. Coast Guard and BP oversaw the operation, said

Dave Pfeifer, Colville president and chief executive officer.

More typically, fuel for use on the North Slope is delivered

to Deadhorse from a refinery in Valdez, using tanker trucks

see INSIDER page 10

see GAS INTEREST page 8

see POLAR ICEBREAKERS page 8

see DIESEL DELIVERY page 7

EIA: Brent averaged $73/barrel inAugust; US crude 10.9 million bpd

Pt Thomson extensionState stays 2019 date in 2012 settlement on Alaska LNG project progress

By KRISTEN NELSONPetroleum News

The state has stayed a deadline in its 2012 set-

tlement with Point Thomson operator

ExxonMobil Production Co.

The settlement required a plan for expansion of

Point Thomson production by the end of 2019 if a

major gas sale hadn’t been sanctioned by June

2016. Late last year the state and ExxonMobil

reached agreement on the company’s expansion

plan. The settlement required either increasing

production to 30,000 barrels per day of condensate

(the current facilities support 10,000 bpd, although

that rate has rarely been achieved) or moving nat-

ural gas to Prudhoe Bay for injection there (requir-

ing an agreement with the Prudhoe Bay working

interest owners and construction of a gas pipeline

between the fields).

Moving natural gas to Prudhoe was

ExxonMobil’s choice.

That work has now been deferred.

An optimistic outlookConocoPhillips ups GMT-2 forecast; moves ahead on Willow, further exploration

By ALAN BAILEYPetroleum News

In a highly upbeat presentation to a

joint meeting of the Alaska House and

Senate Resources committees on Sept.

10, Scott Jepsen, ConocoPhillips Alaska

vice president of external affairs and

transportation, overviewed his compa-

ny’s current exploration and develop-

ment plans in Alaska, and the resulting

major uptick in the company’s expectations for its

future Alaska oil production.

Increased production estimateJepsen said that his company has upped the esti-

mated peak production for its Greater

Mooses Tooth 2 development in the

northeastern National Petroleum

Reserve-Alaska from 30,000 barrels of

oil per day to 38,000 bpd. The federal

Bureau of Land Management has pub-

lished a final environmental impact state-

ment for the project, with a record of

decision anticipated in October. That

could lead to a final investment decision

for the project later this year, Jepsen said.

Meanwhile the Greater Mooses Tooth 1 devel-

opment is moving ahead, with first oil anticipated

by the end of the year. Peak production is expected

to run at about 30,000 bpd.

Trudeau treads carefullyAdministration examining options to salvage Trans Mountain, including an appeal

By GARY PARKFor Petroleum News

T he future of large-scale resource

projects in Canada depends heavily

on how his government responds to a

federal court ruling that has stalled

progress on the Trans Mountain pipeline

expansion, said Prime Minister Justin

Trudeau.

“What we need is not just this

pipeline. We need to be able to build resource proj-

ects of all different types with appropriate social

license,” he told reporters.

He said the objective is to ensure that Trans

Mountain and other projects do not get “bogged”

down in endless court battles.

Trudeau, firing back at his critics,

noted that TransCanada’s Keystone XL

project was long ago approved in

Canada, but has become entangled in the

United States over a failure to engage in

detailed consultations with communities

along the pipeline right of way.

“This is the way that the world is

going and if we can demonstrate clarity

and certainty for businesses through the

process to the investors we will be able

to get more built,” he said.

Decision impacts communitiesTrudeau called the court decision on Trans

Mountain “frustrating and devastating” for com-

see POINT THOMSON page 12

see CONOCO OUTLOOK page 11

see TRANS MOUNTAIN page 9

Also Sept. 10, the Alaska GaslineDevelopment Corp. announced that

ExxonMobil and AGDC had agreed towhat the corporation called “certain keyterms including price and a volume basisfor a Gas Sales Agreement,” captured in

a “Gas Sales Precedent Agreement”signed Sept. 10.

SCOTT JEPSEN

JUSTIN TRUDEAU

2 PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018

GOVERNMENT

FINANCE & ECONOMY

PIPELINES & DOWNSTREAM

EXPLORATION & PRODUCTION

ENVIRONMENT & SAFTEY

6 National rig count unchanged at 1,048

4 White requests Supreme Court rehearing

7 Hilcorp seeks rule change in NM gas basin

4 US accused of planning Keystone protest crackdown

6 Pipeline company found guilty in oil spill

6 Average gas price steady at $2.91/ gallon

3 BP’s Prudhoe power station OK’d for VPP

3 Northstar Kuparuk gas injection request

2 Brent averaged $73 per barrel in August

EIA projects $73 this year, $74 in ’19, up $3 from Augustforecast; US crude averaged 10.9 million bpd in August, up 120,000 from June

Pt Thomson extensionState stays 2019 date in settlement on Alaska LNG project progress

An optimistic outlookConoco ups GMT-2 forecast; moves ahead on Willow

Trudeau treads carefullyAdministration examining options to salvage Trans Mountain

ON THE COVER

Insider: Newfield looking at Alaska; Begich,Dunleavy weigh in; L48 shale boom tapering off

State looks for RIK gas interest;includes Prudhoe, Point ThomsonGAO questions lack of preliminarydesign review for polar icebreakersColville barges diesel to Slope

Petroleum News Alaska’s source for oil and gas newscontents

TELECOMMUNICATIONS AT

WORK IN ALASKA

Telecom Engineering

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Two-way Radio Systems

Microwave & Satellite Systems

Fiber Optics & Network Cabling

FCC Licensing

Tower Construction & Inspection

(907) 751-8200 www.nstiak.com

l F I N A N C E & E C O N O M Y

Brent averaged $73 per barrel in AugustEIA projects $73 this year, $74 in ’19, up $3 from August forecast; US crude averaged 10.9 million bpd in August, up 120,000 from June

By KRISTEN NELSONPetroleum News

The Brent crude oil spot price averaged $73 per barrel

in August, down almost $2 from July, the U.S.

Energy Information Administration said Sept. 11 in its

Short-Term Energy Outlook. The expected average for the

year is $73 per barrel, rising to $74 in 2019.

West Texas Intermediate is expected to average about

$6 per barrel lower than Brent in both years. EIA said both

the Brent and WTI forecasts for 2019, $74 and $67 per

barrel respectively, are $3 per barrel higher than in the

agency’s August STEO.

EIA Administrator Dr. Linda Capuano said in a Sept.

11 statement that rising upward expectations were “large-

ly due to lower expectations for

Canada’s crude oil production and

OPEC’s condensate production.”

The agency said production from

the United States was also expected

to be lower than projected in 2019.

But, Capuano said, the U.S.

“remains on pace to set new crude

oil production records in 2018 and

2019,” with an average of 10.7 mil-

lion barrels per day this year, up

almost 14 percent from last year.

U.S. crude oil production is estimated to have averaged

10.9 million bpd in August, EIA said, up 120,000 bpd

from June. The 2018 forecast is for an average of 10.7 mil-

lion bpd, up from 9.4 million bpd in 2017. In 2019 the

agency expects an average of 11.5 million bpd.

Globally, EIA is forecasting total global liquid fuels

inventories to drop by 400,000 bpd this year, compared

with 2017, and to increase by 100,000 bpd in 2019. “This

outlook of relatively stable inventory levels during the

forecast period contributes to a forecast of monthly aver-

age Brent crude oil prices remaining relatively stable,” the

agency said, between $72 and $76 per barrel from

September through the end of 2019.

Crude oil pricesEIA said that while crude oil prices were up for

DR. LINDA CAPUANO

see EIA OUTLOOK page 3

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August as a whole, crude oil prices and commodity

prices broadly fell early in the month. The agency noted

declines in some emerging market currencies as possibly

contributing to global economic growth concerns and the

potential impact on oil demand.

“However,” EIA said, “oil prices rose in the second

half of August following reports of reduced purchases of

Iranian crude oil ahead of the United States reinstituting

sanctions on Iran in November.” The agency noted other

supply developments which likely pulled on inventories,

contributing to higher prices.

“A restart to some Canadian production after July’s

oil sands outage is anticipated to be delayed until

September, and tropical storm activity in the U.S. Gulf of

Mexico led to the shutdown of some offshore crude oil

platforms,” EIA said.

Permian region crude oil production is estimated to

grow to 3.4 million bpd in September, with current esti-

mates of available regional refinery intake and pipeline

takeaway capacity at about 3.6 million bpd. EIA said

crude oil takeaway infrastructure constraints could con-

tribute to wide price discounts for Permian crude through

the third quarter of 2019, moderating production growth

compared to an unconstrained scenario.

“EIA still expects Permian crude oil production to

drive total U.S. production growth next year,” the agency

said, noting that many producers in the area say they can

operate profitably at prices in the mid-$50 per barrel

range, and might use higher cost transportation options

to move crude to the U.S. Gulf Coast or other regions.

“Some producers with a geographically diverse port-

folio of upstream properties could also redirect capital to

other areas or decide to reduce completion activity until

the transportation constraints ease,” the agency said.

Natural gas“EIA forecasts U.S. dry natural gas production to

increase by 10 percent in 2018 to a record high 81 billion

cubic feet per day with continued growth expected in

2019,” Capuano said.

Estimated U.S. dry natural gas production in August

was 82.2 bcf per day, up 0.7 bcf from August, the agency

said, and is projected to average 81 bcf per day this year,

up 7.4 bcf from 2017 and establishing a new record high.

EIA expects production to average 84.7 bcf per day in

2019.

The Henry Hub spot price averaged $2.96 per million

British thermal units in August, up 12 cents from July,

EIA said. The agency noted that cooling degree days in

the U.S. averaged 13 percent higher than the 10-year,

2008-17, average in August, contributing to high natural

gas demand for power presentation.

Henry Hub natural gas spot prices are expected to

average $2.99 per million Btu this year and $3.12 in

2019.

EIA said natural gas inventories have been low during

most of 2018 compared with the 2013-17 five-year aver-

age, reflecting “high residential and commercial con-

sumption in early 2018 and growth in both liquefied nat-

ural gas and pipeline exports over the past year.” l

continued from page 2

EIA OUTLOOK

ENVIRONMENT & SAFETYBP’s Prudhoe power station OK’d for VPP

The Alaska Department of Labor and Workforce Development said Sept. 5 that

BP Exploration Alaska’s Prudhoe Bay Central Power Station has been approved

for a renewal of the Alaska Occupational Safety and Health Voluntary Protection

Program at the “Star” or highest level.

The Central Power Station has been in the program since 1999, said BP

Exploration’s Beatrice Egbejimba.

“Recertification of VPP is evi-

dence of BP Exploration Alaska’s

exemplary occupational safety and

health program,” said Egbejimba, an

industrial hygienist with BP.

“The VPP program is an opportu-

nity to partner with AKOSH while

showcasing and enhancing our safe-

ty and health culture. VPP supports

BP Exploration Alaska’s culture of

caring and empowers employees to

share this culture with family and

friends outside of the workplace,” she said.

The department said VPP recognizes and promotes effective workplace safety

and health management through a cooperative program between a company’s

management, employees and AKOSH.

“Participating in the Voluntary Protection Program illustrates an employer’s

steadfast commitment to worker safety,” said Labor Commissioner Heidi Drygas.

“I applaud BP Exploration Alaska’s Central Power Station employees for their

efforts in managing and maintaining occupational safety and health.”

VPP Star recipients are not subject to random enforcement actions for five

years, the department said, although enforcement regulations remain in effect and

cases of employee complaints, accident investigations or other significant inci-

dents will result in an enforcement inspection.

Participants in the AKOSH VPP Star program, in addition to BP’s Central

Power Station, include: Alaska Clean Seas; Arctic Slope Regional Corp. Energy

Services Grind and Inject Plant & Oily Water Injection Facility; BP Central

Compression Plant & Gas Facility; ConocoPhillips Alaska Inc. Alpine field oper-

ations; ConocoPhillips Kuparuk area; Fairbanks Memorial Hospital; Insulfoam

Inc.; and UniSea Inc.

—PETROLEUM NEWS

VPP Star recipients are not subjectto random enforcement actions for

five years, the department said,although enforcement regulations

remain in effect and cases ofemployee complaints, accident

investigations or other significantincidents will result in anenforcement inspection.

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

Northstar Kuparukgas injection requestHilcorp officials explain to AOGCC why the company wants to startinjection into the A & C sands through converted production well

By ALAN BAILEYPetroleum News

Hilcorp Alaska anticipates a 4 million

to 5.5 million barrel boost in oil

recovery from Kuparuk sands in the

Northstar oilfield, if the company imple-

ments gas injection into the field’s

Kuparuk oil pool, company officials said

during an Alaska Oil and Gas

Conservation Commission hearing on

Sept. 6. As previously reported in

Petroleum News, Hilcorp has applied to

the commission for permission for the gas

injection. Without gas injection, ultimate

oil recovery from the pool would be lim-

ited to some 9 million barrels, the compa-

ny has said.

The field is operated from a gravel

island offshore in the Beaufort Sea, with

the unit straddling state nearshore waters

and waters of the federal outer continen-

tal shelf.

Jim Shine, Hilcorp land manager, told

the commission that the field has three

participating areas: the Northstar, Fido

and Hooligan participating areas. The

Northstar and Fido participating areas

have reservoirs in the Ivishak formation,

equivalent to the main reservoir of the

Prudhoe Bay field. The Hooligan has

reservoirs in the shallower Kuparuk A

and C sands.

Production historyProduction from the Ivishak began in

2001. Sustained production from the

Kuparuk C began in 2010 from a single

well, the NS-08 well. Production from

both the Kuparuk A and C began in 2016

through another well, the NS-18 well.

And the NS-15 well came on line from

the A and C sands in 2017, Hilcorp reser-

voir engineer Chris Kanyer told the com-

mission.

Gas from the Kuparuk, produced

along with oil and condensate, has been

injected into the Ivishak reservoir, for

So now, with more than enoughgas being produced to support

Ivishak production, there isadequate gas for injection into the

Kuparuk — Hilcorp wants toconvert the NS-18 into a gas

injection well for this purpose.

see INJECTION REQUEST page 4

4 PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018

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enhanced oil recovery from that reservoir.

But increased gas production, especially

from the N-15 well, has enabled the reser-

voir pressure in the Ivishak to be restored

to somewhere close to its original level.

So now, with more than enough gas being

produced to support Ivishak production,

there is adequate gas for injection into the

Kuparuk — Hilcorp wants to convert the

NS-18 into a gas injection well for this

purpose.

Hilcorp geoscientist Daniel Yancey

told the commission that the Kuparuk

sands lie between confining shale layers

above and below: 2,000 feet of HRZ and

Colville shales above, and more than

1,500 feet of the Kingak below. Hilcorp

well integrity engineer Wyatt Rivard pre-

sented evidence, demonstrating that

anticipated downhole pressures resulting

from the planned gas injection would be

well below the fracture pressure for the

shales. l

continued from page 3

INJECTION REQUEST

GOVERNMENTWhite requests Supreme Court rehearing

Jim White, owner of Alaskan Crude Corp., has asked the Alaska Supreme Court to

reconsider its recent ruling, upholding an Alaska Department of Natural Resources

decision to cancel Alaskan Crude’s lease covering the Moose Point prospect on the

northwest coast of the Kenai Peninsula. As reported in the Sept. 9 issue of Petroleum

News, DNR had cancelled the lease after Alaskan Crude did not continue a drilling

project in the lease, to meet an April 27, 2009, deadline set by DNR for completing a

well. DNR also set a 90-day deadline for bringing a Moose Point well into production,

should a viable resource be discovered.

White had argued that the deadline imposed by DNR had been invalid because it

had not been part of the original lease stipulations. White also said that questions over

the length of the winter drilling season, and over Alaska Oil and Gas Conservation

Commission requirements for a hearing into correlative rights for subsurface

resources, rendered investment in the drilling in time for the April deadline too finan-

cially risky — White supplies all of the financing for Alaskan Crude operations.

The state Superior Court found in favor of White. But the Supreme Court over-

turned the Superior Court decision, saying that DNR’s April deadline had provided

White with ample time to conduct the drilling.

In the request for a rehearing James Gottstein, attorney for White, argues that the

Supreme Court had overlooked the impact of the AOGCC requirement on DNR’s

deadline for production from the well. The court had also overlooked a requirement

for a DNR plan of development, if the well were to go into production. Thus, a rea-

sonable time to bring a well into production would be six months, rather than the 90-

days allowed under DNR’s order. Apparently these issues had been raised before the

Supreme Court.

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

US government accused of planning Keystoneprotest crackdown

By MATTHEW BROWNAssociated Press

Civil liberties advocates sued the U.S.

government Sept. 4, alleging law

enforcement agencies have been making

preparations to crack down on anticipated

protests over the Keystone XL oil pipeline.

Attorneys for the American Civil

Liberties Union and its Montana affiliate

filed the lawsuit in U.S. District Court in

Missoula against the Defense, Homeland

Security, Interior and Justice departments.

They asked the court to order the release

of all documents about cooperation over the

pipeline between federal, state and local law

enforcement and private security compa-

nies.

The groups cited confrontations between

law enforcement and protesters, including

many Native Americans, which turned vio-

lent during construction of the Dakota

Access Pipeline through South Dakota.

The clash over Dakota Access included

surveillance and prosecution of protesters,

Montana ACLU Attorney Alex Rate said.

Planning appears to be underway for a sim-

ilar response to protesters against Keystone

XL, Rate said, citing documents obtained

through public records requests submitted

to state and local agencies.

“The big question is what level of atten-

tion the (federal) government is paying to

the issue,” Rate said. “If you’re an indige-

nous person in Montana planning to protest

peacefully against the construction of the

pipeline, you have to be nervous about how

the government is going to react.”

The pipeline would transport up to

830,000 barrels of crude oil daily from

Canada through Montana and South Dakota

to Nebraska. It was approved by President

Donald Trump in March 2017, a decision

that’s been challenged in court.

A judge in that case in August ordered

federal officials to conduct a more thorough

review of the project after the Nebraska

Public Service Commission approved an

alternative route for the line through

Nebraska.

Defense Department spokesman Johnny

Michael said the agency was reviewing the

lawsuit and takes seriously its obligations to

release public records.

Homeland Security spokeswoman Katie

Waldman said the agency does not com-

ment on litigation.

The Interior Department referred ques-

tions to the Justice Department, which did

not immediately respond to a request for

comment.

The lawsuit included emails in which

federal officials discussed the establishment

of an “interagency team” to coordinate

security of Keystone XL construction.

Also included was a Homeland Security

analysis from last year on attacks on

pipelines by “environmental rights extrem-

ists.” The document focused in part on

activists who sought to shut down five

pipelines along the U.S.-Canada border

by illegally closing valves on the lines.

The material was obtained by the

ACLU under public records requests sub-

mitted to state and local agencies, Rate

said. l

see WHITE REHEARING page 7

PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018 5

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By AMANDA LEE MYERS & ROBERT JABLON

Associated Press

A pipeline company was convicted of

nine criminal charges Sept. 7 for

causing the worst California coastal spill

in 25 years, a disaster that blackened pop-

ular beaches for miles, killed wildlife and

hurt tourism and fishing.

A Santa Barbara County jury found

Houston-based Plains All American

Pipeline guilty of a felony count of failing

to properly maintain its pipeline and eight

misdemeanor charges, including killing

marine mammals and protected sea birds.

California Attorney General Xavier

Becerra said in a statement that Plains’

actions were not only reckless and irre-

sponsible but also criminal.

“Today’s verdict should send a mes-

sage: if you endanger our environment

and wildlife, we will hold you account-

able,” he said.

Plains said in a statement that the jury

didn’t find any knowing misconduct by

the company and “accepts full responsi-

bility for the impact of the accident.”

“We are committed to doing the right

thing,” the company said.

Company says jury erredThe company said its operation of the

pipeline met or exceeded legal and indus-

try standards, and believes the jury erred

in its verdict on one count where

California law allowed a conviction

under a standard of negligence.

“We intend to fully evaluate and con-

sider all of our legal options with respect

to the trial and resulting jury decision,”

Plains said.

The company is set to be sentenced on

Dec. 13. Because it’s a company, and not

a person, Plains only faces fines, though

it’s unclear how steep the penalties could

be.

Plains had faced a total of 15 charges

for the rupture of a corroded pipeline that

sent at least 123,000 gallons of crude oil

gushing onto Refugio State Beach in

Santa Barbara County, northwest of Los

Angeles.

Plains pleaded not guilty to the

charges and accused prosecutors of crim-

inalizing an unfortunate accident.

Errors called preventableBut federal inspectors found that

Plains had made several preventable

errors, failed to quickly detect the

pipeline rupture and responded too slow-

ly as oil flowed toward the ocean.

Plains operators working from a Texas

control room more than 1,000 miles away

had turned off an alarm that would have

signaled a leak and, unaware a spill had

occurred, restarted the hemorrhaging line

after it had shut down, which only made

matters worse, inspectors found.

The spill, two weeks shy of Memorial

Day, closed beaches with popular camp-

grounds for two months and put a crimp

in the local tourist economy and fishing

industry.

It also crippled the local oil business

because the pipeline was used to transport

crude to refineries from seven offshore

rigs, including three owned by Exxon

Mobil, that have been idle since the spill.

Producers bankruptLast year, Denver-based Venoco,

declared bankruptcy, in part because it

wasn’t able to operate its platform. The

state is now responsible for plugging and

decommissioning Veneco’s wells at an

estimated cost of $58 million. That

doesn’t include the eventual cost to

remove the enormous structure.

Plains apologized for the spill and paid

for the cleanup. The company’s 2017

annual report estimated costs from the

spill at $335 million, not including lost

revenues.

It is seeking approval to repair or

rebuild its corroded pipelines.

The company still faces possible fines

from the U.S. government and also faces

a federal class-action lawsuit by owners

of beachfront properties, fishing boat

operators, the petroleum industry and oil

workers who lost jobs because of the

spill.

The pipeline that spilled has been shut-

tered but Plains has applied to build a new

one in the same location.

Kristen Monsell, oceans legal director

with the Center for Biological Diversity,

said in a statement that Plains can’t be

given “a second chance to spill again.”

“It’s time to get dirty, dangerous

drilling out of our oceans, out of our

coastal areas and out of our state,” she

said. l

—Associated Press writer BrianMelley contributed to this report.

6 PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018

(907) 562-5303 | akfrontier.com

Safety Health Environment Quality

THE TEAM THAT

DELIVERS

EXPLORATION & PRODUCITONNational rig count unchanged at 1,048

The number of rigs drilling for oil and natural gas in the U.S. was unchanged

the week ending Sept. 7 at 1,048.

At this time a year ago there were 944 active rigs.

Houston oilfield services company Baker Hughes reported that 860 rigs target-

ed oil (down two from the previous week) and 186 targeted gas (up two). Two

were listed as miscellaneous (no change).

Among major oil- and gas-producing states, Louisiana gained three, Wyoming

gained two and Alaska and North Dakota each gained one. Oklahoma was down

two. Colorado and Texas were unchanged.

Texas, with 528 rigs, accounts for the majority of the nation’s rig activity, fol-

lowed by Oklahoma at 137 and New Mexico at 100.

The Baker Hughes rotary rig count shows six rigs active in Alaska, up from

four a year ago.

The U.S. rig count peaked at 4,530 in 1981. It bottomed out in May 2016 at

404.

—PETROLEUM NEWS

Average gas price steady at $2.91/ gallonU.S. gas prices remained steady

over the past two weeks and an analyst

says the pump price may start to drop

later in September.

Trilby Lundberg says the average

price of regular-grade gas as of Sept. 7

was $2.91 per gallon.

In California, however, the average

was $3.63, per gallon up 3 cents from

two weeks ago.

The price in the San Francisco Bay

Area was even higher while the city

with the lowest average was Jackson, Mississippi at $2.51 per gallon.

Consumers may see prices fall 2 to 4 cents per gallon by the end of September.

Lundberg says gasoline supplies are plentiful, growth in demand is weak and

refiners are ending their production of summer blend gas that's designed to reduce

pollution but is costlier to produce.

—ASSOCIATED PRESS

PIPELINES & DOWNSTREAM

Consumers may see prices fall 2to 4 cents per gallon by the end of

September. Lundberg saysgasoline supplies are plentiful,growth in demand is weak and

refiners are ending theirproduction of summer blend gas

that's designed to reduce pollutionbut is costlier to produce.

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

Pipeline company

found guilty in oil spill

PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018 7

l G O V E R N M E N T

Hilcorp seeks rule change in NM gas basinBy SUSAN MONTOYA BRYAN

Associated Press

AHouston-based oil and gas company

wants New Mexico regulators to ease

restrictions on well locations in two coun-

ties within one of the oldest producing

basins in the U.S., saying the change will

result in the capture of more natural gas.

The request involving San Juan and Rio

Arriba counties comes as an oil and gas

boom has helped to refuel state coffers.

That includes a recent record-breaking

lease sale on the other end of the state near

the Texas state line that promises nearly a

half-billion dollars more in revenues.

But environmentalists and landowners

are concerned about increasing well densi-

ties in the northwest as developers look to

tap more reserves in the San Juan Basin.

The request by Hilcorp Energy Co. is set

to be considered Sept. 13 by the Oil

Conservation Commission.

Critics want regulators to put off a deci-

sion until a thorough environmental review

is done. They’re citing potential cumulative

effects of the boom, saying more public

scrutiny is needed before rules are changed.

Rancher Don Schreiber said the most

pressing environmental questions in New

Mexico is how many wells an energy com-

pany can drill. He has lived in the region for

decades and remembers hunting deer as a

boy across San Juan County’s high desert.

“I’ve watched it go in a fairly short life-

time from a place of incredible beauty to a

borderline industrial site and certainly dou-

bling the wells would put us over the edge,”

he said.

More than 5,300 wellsHilcorp in a statement Sept. 10 denied

that the application is one that seeks to drill

more wells or change the way new wells are

permitted.

According to its application, the compa-

ny currently operates more than 5,300 pro-

ducing wells in what is known as the

Blanco-Mesaverde gas pool in San Juan

Basin. It also has thousands of wells that are

producing from other formations in the

region.

Those additional wells are situated to

recover reserves within the Blanco-

Mesaverde formation that aren’t being

tapped due to current density limits, the

company said.

“This allows all operators to reinvest and

upgrade existing well sites and production

equipment,” the company said, arguing that

this will result in extending the life of the

San Juan Basin.

The company also argued that changing

well density wouldn’t eliminate the need to

meet regulatory standards and other envi-

ronmental, cultural and archaeological

requirements for drilling new wells or

working on existing wells.

Since the beginning of 2018, the oil

commission has granted Hilcorp dozens of

exceptions to the density rules. The compa-

ny contends that updating the rules to allow

for eight wells — up from the current four

— on 320 acres would prevent waste and

boost the capture of natural gas.

Well spacing issueHilcorp’s request follows a previous pro-

posal to seek a change that would have

allowed Oil Conservation Division staff to

make decisions about well spacing rather

than go through a public hearing process.

The proposal piqued the interest of the state

attorney general’s office and it was ulti-

mately withdrawn.

Environmentalists on Sept. 10 asked the

attorney general’s office to weigh in this

time, citing concerns over public notice as

the announcement of the latest proposal and

the deadline for intervening spanned only a

week over the Labor Day holiday.

They argued that wasn’t enough time,

given the importance of the proposed

change.

Schreiber said granting the request

would amount to a parting gift to industry

as leadership at the state Energy, Minerals

and Natural Resources Department and the

oil commission is expected to change when

a new governor takes office in January.

State Energy Secretary Ken McQueen

and Oil Conservation Division director

Heather Riley both used to work for WPX

Energy, which operated in San Juan Basin

for years before shifting its focus to places

along the Texas-New Mexico border and

elsewhere. l

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Better.

A rehearing is justified, because, by

overlooking those AOGCC and DNR

requirements, the Supreme Court had not

considered the entirety of the contract

involved and of the material facts in the

case, as is required by law, Gottstein wrote.

Moreover, those two requirements, in

effect, meant that “Mr. White was doomed

from the beginning” in any effort to bring

the well into production within the DNR

deadline, even if White had continued with

the drilling in early 2009, Gottstein com-

mented.

—ALAN BAILEY

continued from page 4

WHITE REHEARING

that ply the Haul Road to the Slope.

Colville’s trucks make around 2,000 of

these trips each year, carrying about

10,000 gallons of fuel on each trip. The

delivery of fuel by barge, in effect,

replaces 200 tanker trips, Colville said.

Colville attributes its ability to con-

duct the barge operation to improving sea

ice conditions off northern Alaska and the

construction of Colville’s 5 million-gal-

lon fuel storage facility at Deadhorse.

Without the tank farm, there would be

insufficient fuel storage capacity at

Deadhorse to support the receipt of such

a large fuel shipment, the company said.

“This was a milestone for Colville and

the fuel transport industry and was

prompted by increased demand because

of all the new activity in the North Slope

oil fields. While we will consider future

barge deliveries, they will not replace our

trucking operation,” Pfeifer said.

—ALAN BAILEY

continued from page 1

DIESEL DELIVERY

The agency wants to build three new

heavy-duty icebreakers and three medium

icebreakers, in support of U.S. activities

in polar regions. The GAO report focuses

on the heavy icebreaker requirement.

Timing of the transitionAccording to the GAO report, the Polar

Star is currently expected to reach the end

of its operational life somewhere between

2020 and 2023. Since, however, the first of

the planned new icebreakers is not expect-

ed to be completed until 2024, the Coast

Guard anticipates renovating the Polar

Star’s systems, starting in 2020, to extend

the life of the vessel until the first of the

new vessels becomes available. But that

2024 schedule for the new vessel seems

unreliable, the GAO report says.

The construction schedule for the new

icebreakers appears to have been driven by

the timing of the predicted gap in icebreak-

er availability, rather than by a realistic

assessment of shipbuilding activities, the

report says. Although the Coast Guard has

followed standard DHS acquisition poli-

cies, the agency established design, cost

and schedule baselines without first con-

ducting a preliminary design review. Nor

did the agency conduct an assessment of

the maturity of the technologies planned to

be used in the icebreakers, the report says.

From the perspective of program costs,

the Coast Guard has not quantified the full

range of potential costs over the entire life

of the program. Thus, the cost estimate for

the entire program may be underestimated,

the GAO report says.

Cost and fundingThe Coast Guard has in the past indicat-

ed that each icebreaker may cost some $1

billion to construct. However, the agency

has suggested that efficiencies arising from

the use of a standardized design could

reduce that cost to $900 million. The

agency has requested $750 million in

funding, which, together with existing ice-

breaker funds, the agency has said, could

pay for the acquisition of the first icebreak-

er.

Congress recently passed a national

defense authorization act, authorizing the

construction of six polar class icebreakers.

However, although the Senate has passed a

funding bill that includes $750 million for

icebreaker funding, the House of

Representatives has not included the same

level of funding in its equivalent bill.

Integrated program officeMeanwhile, the Coast Guard and the

U.S. Navy have been operating an inte-

grated program office for the icebreaker

project. That office includes a ship design

team; a cost engineering and industrial

analysis group; and a directorate for deal-

ing with contracts. The office has already

completed an analysis and selection of the

best option for addressing the icebreaker

issue and has conducted an evaluation of

this option. Construction of the lead ship is

expected to start no later than June 2021,

with delivery of the vessel possible in the

fourth quarter of 2023. The Coast Guard

estimates the total full-lifecycle cost of the

three-heavy-icebreaker program to be in

the range of $8.5 billion to $9.8 billion, the

GAO report says.

The DHS has been seeking technical

proposals for the project, with price pro-

posals anticipated in October.

Conceptual designWork on a conceptual design began

back in 2016 and ultimately resulted in a

design concept involving an integrated

power plant providing electrical power for

rotatable propulsion pods under the ves-

sel’s stern. And, despite not having con-

ducted a preliminary review for the design

concept, the Coast Guard has used the con-

cept as the basis for a cost estimate, the

GAO report says. The predicted construc-

tion schedule is also based on this prelimi-

nary concept, rather than on a more mature

design, the GAO report says.

The Coast Guard views the preliminary

design as using proven technologies — the

type of power plant and thruster system

envisaged are already available commer-

cially. But the agency has not assessed the

readiness of the proposed technologies for

achieving the icebreaker program objec-

tives — it is necessary to evaluate the

effectiveness of the technologies in sup-

port of a different program or a different

operating environment from what has

already been demonstrated, the GAO

report says.

Thus, although the icebreaker project

team has thoroughly and accurately esti-

mated the cost of the icebreaker project,

within the parameters used for the estimat-

ing, there are remaining issues relating to

the credibility of the estimates. The devel-

opment schedule also appears optimistic.

In addition, the Coast Guard and the Navy

do not have a clear strategy for addressing

any cost growth in the program, the GAO

report says.

A number of recommendationsThe report makes a number of recom-

mendations, including a recommendation

that the icebreaker project team should

conduct a technology readiness assessment

of the conceptual icebreaker design. The

team should revisit the cost and schedule

estimates, taking full account of risks and

uncertainties in the program, and address-

ing how to deal with any cost growth. DHS

has agreed with the GAO recommendation

and has identified actions for addressing

the issues raised, the GAO report says.

—ALAN BAILEY

continued from page 1

POLAR ICEBREAKERS

8 PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018

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itive process is in the State’s best inter-

est.”

DNR said the current solicitation for

interest in future gas sales will allow the

state “to better understand competition

for its gas,” adding that it is not commit-

ting to take its royalty gas in kind or to

sell any volume of gas to any party.

“A public process, including legisla-

tive approval, is necessary before DNR

can enter into an agreement to sell royalty

in kind gas,” the department said.

DNR working issuesThe DNR commissioner has statutory

authority to negotiate commercial agree-

ments, market the state’s royalty in kind

and tax as gas volumes, and modify cer-

tain oil and gas lease terms.

Under Senate Bill 138, enacted in

2014, DNR would elect to receive Alaska

LNG royalty gas in kind, unless the DNR

commissioner finds that taking gas in

value would be in the best interest of the

state. Other than crude oil sold to in-state

refineries, the state takes its royalties on

crude oil production in value, with the

crude oil sold by producers and the state

taking payment for its royalty share.

DNR Commissioner Andy Mack told

legislators in a March update on the

Alaska LNG project that before entering

a contract to take gas as royalty in kind,

the department would issue a preliminary

best interest finding, take comments from

the public and the Royalty Oil and Gas

Development Advisory Board, and then

obtain legislature approval.

A final best interest finding would

then be issued.

Mack said any royalty in kind finding

has to come to the Legislature to be rati-

fied.

In a July update to legislators, DNR

Deputy Commissioner Mark Wiggin said

the department is working on royalty in

kind vs. royalty in value issues, including

eliminating switching between RIK and

RIV, a right the state now enjoys. He said

if RIK is selected, with the state taking

royalties (and probably also taxes) in gas

molecules, DNR would need a gas sale

agreement with the Alaska Gasline

Development Corp.

JDAThe joint development agreement for

Alaska LNG, signed in Beijing in early

November by the state, AGDC, China

Petrochemical Corp. (Sinopec), CIC

Capital Corp. and the Bank of China,

envisions that 75 percent of LNG from

the Alaska project will go to China, leav-

ing the state 25 percent to market to other

buyers and for in-state use. Those vol-

umes would include the state’s royalty

share.

The JDA says the parties will work

together on a scope of work defined in the

agreement, including the opportunity for

delivering 75 percent of the LNG pro-

duced from Alaska to China “at a cost-

based and stable price utilizing the bene-

fits of strategic financing and invest-

ment,” strategic financing opportunities

and a transparent investment model.

The JDA expires Dec. 31, 2018, unless

extended by mutual written agreement of

the parties.

—KRISTEN NELSON

continued from page 1

GAS INTEREST

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The construction schedule for thenew icebreakers appears to havebeen driven by the timing of the

predicted gap in icebreakeravailability, rather than by a

realistic assessment of shipbuildingactivities, the report says.

PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018 9

Oil Patch Bits

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

Companies involved in Alaska’s oil and gas industry

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

New ocean shipping options to Hawaii and GuamLynden International said Sept. 5 that it

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“The new service provides a lower-cost alternative to traditional steamship line serv-ice,” said Western Regional Sales Manager Charlie Ogle. “We offer twice monthly sailingsto Oahu with connections to the neighboring islands, “he added.

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COOEC-Fluor completes module fabrication projectFluor Corp. said Sept. 4 that its joint venture COOEC-Fluor Heavy Industries Co. Ltd.

fabrication yard has safely completed fabrication of the topsides, living quarters anddrilling modules for the CNOOC HZ32-5/33-1 Oilfield Joint Development Project. The mod-ules sailed away on schedule in July, destined for the Huizhou 32-5 oilfield development

approximately 105 miles south-east of Hong Kong in the PearlRiver Mouth basin of the SouthChina Sea.

“Both the COOEC-Fluor andCNOOC project managementteams successfully overcamenumerous challenges to com-plete the onshore constructionas scheduled, with zero punchlist items for onshore fabricationwork,” said Lianfeng Yang,CNOOC’s engineering, procure-ment and construction project manager. “We look forward to the COOEC-Fluor team suc-cessfully completing the close-out activities and sea fastening work.”

The fabrication yard delivered to the aggressive schedule and fabricated the 4,000-ton,four-deck topsides in less than 12 months with no follow-on work. Safety, a core value ofthe COOEC-Fluor yard, was at the forefront of all activities and the team achieved 1.5 mil-lion work hours without a lost-time incident.

“The project team optimized the fabrication methods and onshore commissioningscope, which minimized the schedule-intensive offshore installation requirements to main-tain schedule,” said Chris Vertanness, vice president of Fluor and director of operations atthe COOEC-Fluor fabrication yard. “The team’s planning, productivity and execution excel-lence enabled the delivery of the modules with the safety and schedule certainty ourclients expect.”

The platform is expected to continue to produce oil until after 2030.

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CO

URT

ESY

LYN

DEN

CO

URT

ESY

FLU

OR

munities that were counting on the employment that

would come with the C$9.3 billion Trans Mountain

expansion. The prime minister said his administration is

examining a wide range of legislative and other options to

salvage Trans Mountain, including an appeal to the

Supreme Court of Canada.

However, he would not go as far as using a “legislative

trick,” such as an emergency measure in the guise of the

“national interest” to bypass the federal court ruling.

Trudeau said that might “be satisfying in the short term,”

but it would set up fights and uncertainty for investors over

the coming years on any other project because you can’t

have a government that keeps invoking those sorts of

things.

“We would like to see shovels in the ground as quickly

as possible. This is a priority for Alberta and Canada. We

must make sure it’s done right,” he said.

While Trudeau mulls his next move, patience is wearing

thin in Calgary, the heads office city of Canada’s petroleum

industry, where unemployment rose to 8.2 percent in

August from 7.9 percent in July in a metropolitan popula-

tion of 1.4 million, compared with 6.7 percent for all of

Alberta, 6.4 percent in the provincial capital of Edmonton

and 6 percent across Canada.

As hundreds of laid off residents with no hope of finding

a new job start packing their bags and heading for the exit

door, the real estate market is swamped with more than

5,000 listings.

“Oil companies are still very reluctant to hire heads

office workers (where Calgary’s economic strength lies),”

said Court Ellingson, vice president of Calgary Economic

Development.

Even so, he is confident that a recovery will occur based

on signs of a return to upstream exploration and develop-

ment.

In the meantime, patience in the industry is fast

approaching breaking point as Alberta Premier Rachel

Notley discovered during a “tense” late-August meeting

with industry executives.

Those from the larger companies unburdened them-

selves, speaking about the chilling impact of the Trans

Mountain court ruling on their investment climate and

Canada’s inability to get major infrastructure built that has

prompted oil sands giant Suncor Energy to shelve all plans

to grow production until pipeline capacity out of Alberta is

increased.

Chris Bloomer, chief executive officer of the Canadian

Energy Pipeline Association, told the Calgary Herald his

sector is moving towards a “pretty desperate” situation.

Tamarack Valley Energy Chief Executive Officer Brian

Schmidt, who also attended the Notley session, said he is

“just watching people leave” the Western Canada

Sedimentary Basin. “No one is able to raise money here

right now,” he said. l

continued from page 1

TRANS MOUNTAIN

North Dakota and the Uinta basin of Utah.

Newfield also has oil developments off-

shore China, but approximately 98 percent

of the company’s proved reserves are

onshore U.S.

According to www.newfield.com,

“Newfield has a clear vision — to be rec-

ognized as the premier independent E&P

company delivering operational excel-

lence, top tier business results and value to

our shareholders, employees and the com-

munities in which we live and work.”

—KAY CASHMAN

Begich, Dunleavy weighin on Pt. Thomson,Walker’s LNG deal

THE DEMOCRATIC AND

REPUBLICAN CANDIDATES in the

Alaska governor’s race have weighed in on

incumbent Bill Walker’s latest announce-

ment on his $43 billion-plus proposal to

build a natural gas pipeline from the North

Slope to Nikiski on the Kenai Peninsula,

where the gas will be liquefied, with 75

percent of the LNG going to China. The

Chinese, represented by China

Petrochemical Corp. or Sinopec, CIC

Capital Corp. and the Bank of China, will

play a role in construction. In April, Alaska

Gasline Development Corp. President

Keith Meyer said Sinopec has a very capa-

ble construction company and has built

longer pipelines than this project, in higher

places and with larger plants. He said the

ability of Alaska companies is something

AGDC is promoting to the Chinese.

On Sept. 10 the governor’s office said

Alaska has agreed to extend a key deadline

in a 2012 lawsuit settlement with

ExxonMobil and BP over development of

the Point Thomson unit gas and conden-

sate field 60 miles east of Prudhoe Bay on

Alaska’s North Slope.

State Commissioner of Natural

Resources Andy Mack said the deal was

reached to facilitate PTU operator

ExxonMobil’s agreement to supply its

North Slope gas, both at Point Thomson

and in the BP-operated Prudhoe Bay unit,

to the proposed Alaska LNG Project. The

PTU holds an estimated 8 trillion cubic

feet of natural gas and is an important part

of the gas supply needed for the Alaska

LNG Project. The Prudhoe Bay unit holds

22 tcf of gas.

A letter of agreement entered into by

the state, ExxonMobil and BP extends a

December 2019 deadline for the compa-

nies to expand PTU development beyond a

pilot program now underway to produce

condensate from the Thomson sands,

although currently shutdown by Exxon

because of technical problems.

The stay will end when there is a final

investment decision on an Alaska LNG

Project or work on the Alaska LNG Project

is no longer progressing.

In a separate statement AGDC, backed

by gubernatorial incumbent Walker, said it

has reached an (unbinding) agreement with

Exxon on certain key terms including price

and volume for a gas sales agreement. It

was signed Sept. 10, AGDC said, for terms

for the purchase of Exxon’s share of

Prudhoe Bay and PTU natural gas.

Begich wants Alaska workers on gas line, concerned about China

Gubernatorial candidate Mark Begich

told Petroleum News Sept. 12 he was

always concerned about what the governor

gave up in gas proj-

ect-related negotia-

tions, noting there

are too many unan-

swered questions:

“We want to be sure

Alaska got a good

deal, not just a fair

one … or worse.”

“We want Alaska

workers working on

that pipeline if it

comes to fruition,” he said, which is some-

thing that cannot be legally mandated by

the state, although the state can insist

unionized labor be used.

Begich was also concerned about the

economics of the gas project, questioning

whether it made sense or whether it would

lay a heavy burden of debt on the state.

The former U.S. senator from Alaska

also referred to China’s controversial

involvement in South Africa, which has

U.S. security advisers worried in both

Congress and the executive branch.

“Look at what China is doing in South

Africa. The Chinese are extracting every-

thing they can, controlling resources. The

U.S. government, I believe, would not

allow China to control Alaska North Slope

gas. … In my opinion, if we can make a

North Slope LNG project economic and

not a burden on Alaska, then we should

market our gas to other Asian markets, so

China does not own the majority of our

gas and have any involvement in its con-

struction.”

Dunleavy said LNG project must make economic sense

Gubernatorial candidate Mike Dunleavy

released the following statement in

response to the Walker administration’s

“letter of understanding” with the Point

Thomson working interest owners on the

Alaska LNG Project.

“We all support

monetizing our vast

natural gas resources

for the benefit of all

Alaskans. But for

Alaskans to benefit,

the project must

make economic

sense, and today’s

announcement does-

n’t change that

underlying fact.

Without further information, and with too

many unanswered questions, we don’t

know if today’s news represents a positive

step forward for the project. What we do

know is that press releases don’t build

pipelines.”

“Our campaign remains committed to a

project that maximizes the benefit to all

Alaskans without jeopardizing our finan-

cial future, one driven by the private sec-

tor, not politics,” Dunleavy said.

—KAY CASHMAN

Financial Times: US shaleboom begins to cool

PER A SEPT. 7 ARTICLE in the

Financial Times, the U.S. shale oil industry

is “slowing as logistical challenges includ-

ing labor costs and a lack of adequate

pipeline capacity pile up.”

FT reporter Ed Crooks summarized

what the chief executives of oilfield serv-

ice firms Halliburton and Schlumberger

and major shale producer EOG Resources

10 PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018

229-6000

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continued from page 1

INSIDER

see INSIDER page 12

MARK BEGICH

MIKE DUNLEAVY

The GMT-1 development is expected

to cost a little under $1 billion. GMT-2,

with more wells required but with higher

expected production rates, will likely cost

about $1.5 billion.

The environmental impact statement

scoping process is underway for

ConocoPhillips’ proposed major Willow

development, in the Bear Tooth unit, to

the west of Greater Mooses Tooth. That

development could result in peak produc-

tion of some 100,000 bpd, with first oil

around 2024 to 2025, ConocoPhillips has

indicated. Initial development of Willow

will likely cost $2 billion to $3 billion,

with a further $2 billion to $3 billion

required for full field development.

Exploration and appraisal this winterJepsen said that, following a particu-

larly successful exploration drilling pro-

gram last winter, ConocoPhillips plans an

aggressive two-rig exploration and

appraisal drilling program for the coming

winter. The company has used seismic

surveying to identify a patchwork of

exploration targets in its western North

Slope leases, including in the northeast-

ern NPR-A. Currently 75 percent of those

targets remain untested.

The coming winter’s plan involves the

drilling of six to eight wells.

Two of those wells would be drilled by

the end of the year, testing prospects

reachable from existing oil field well

pads. One of these is the Cairn prospect in

the southwestern corner of the Kuparuk

River unit. The other involves the Putu

prospect, near the village of Nuiqsut, in

what ConocoPhillips terms the Narwhal

trend, to the east of the Colville River.

This is the same trend as the

Pikka/Horseshoe trend, where Oil Search

and its partners are planning the develop-

ment of a major oil field primarily involv-

ing a reservoir in the Nanushuk forma-

tion.

Third Putu wellDuring last winter’s exploration

drilling season, ConocoPhillips drilled

two wells, the Putu 2 and 2A wells, in the

Putu prospect. Those wells, which tested

successfully for oil, targeted two distinc-

tive seismic amplitude anomalies, Jepsen

explained. But there is a third anomaly,

immediately west of the two tested anom-

alies — the plan for later this year is to

drill into this third anomaly from the CD-

4 pad in the Colville Delta unit, Jepsen

said.

The focus of the remainder of the com-

ing winter’s drilling will be Willow —

ConocoPhillips wants to drill some hori-

zontal wells, to better understand the

potential productivity from the field, and

some vertical wells to test inter-well com-

munication, Jepsen said. The company

wants to further delineate the field and to

conduct further well tests. Exactly how

much will be done during the winter sea-

son will depend on how fast the drilling

projects proceed and on the weather con-

ditions, Jepsen said.

In the Narwhal trend, ConocoPhillips

experienced success last winter in finding

oil in two zones at its Stony Hill well, in

addition to the Putu discoveries. But the

Stony Hill and Putu discoveries require

additional appraisal drilling and addition-

al analysis, Jepsen said. Putu has the

advantage of being situated inside the

Colville River unit, somewhat closer to

existing facilities than Stony Hill, Jepsen

remarked.

Looking further ahead, from 2020

onwards, ConocoPhillips anticipates

drilling into that remaining 75 percent of

its North Slope prospects that have not

yet been tested, Jepsen said.

Dramatic change in outlookJepsen’s comments about

ConocoPhillips’ upcoming plans came

within the context of a dramatic change in

the company’s outlook for its future

Alaska oil production. As recently as

2013 the company was forecasting a con-

tinuing decline rate of 6 to 8 percent per

year in its oil output from its North Slope

operations. But now the company antici-

pates a complete reversal of that situation,

with production in 2028 expected to be

some 100,000 bpd above where it is now,

Jepsen said.

And that comes within a context of

new oil production from other companies

operating on the North Slope, in what

Jepsen characterized as a North Slope

renaissance. For example, Oil Search and

its partners are planning a major develop-

ment in the Pikka prospect, Hilcorp is

planning the Liberty development in the

Beaufort Sea, and Brooks Range

Petroleum has been moving ahead with

its Mustang development. All told, there

is the potential for a total of 400,000 bpd

of new oil, although that new production

would not all start at the same time.

There is also the continuing health of

the core North Slope fields: Prudhoe Bay,

Kuparuk and Alpine. These fields provide

the economies of scale in oil output that

make the new developments viable,

Jepsen commented.

Jepsen divided ConocoPhillips’ pre-

dicted future oil production into four

tranches: base production from existing

fields; additional production from new

developments in those fields; further

developments from new field projects;

and potential future production resulting

from exploration.

Impact of new technologiesBase production in the Prudhoe Bay,

Kuparuk and Alpine fields has benefited

from exciting new technologies, in partic-

ular new drilling technologies.

“We have really advanced drilling

technology to the point where it’s making

a significant difference in terms of what

we can develop and how much we can

develop,” Jepsen said.

For example, earlier this year

ConocoPhillips drilled a 21,000-foot hor-

izontal lateral from a CD-5 well in the

Colville River unit, the longest lateral

ever drilled in North America, Jensen

said. It is now possible to steer a well

more than 4 miles through a 10- to 15-

foot thick reservoir sand, enabling a more

than 4-mile exposure to oil bearing rock.

By contrast, in the early years of Prudhoe

Bay drilling, a directional well might pen-

etrate a reservoir sand at a 45-degree

angle, enabling perhaps an exposure to

just 21 to 22 feet of oil-bearing rock in a

15-foot thick sand body.

Highly deviated drilling can also

reduce the surface footprint of an oilfield

development. ConocoPhillips has com-

missioned a new Doyon Drilling ultra-

extended reach rig that can drill out to a

distance of more than 37,000 feet, allow-

ing access to 154 square miles of subsur-

face from a 14-acre drilling pad. The

company plans to use this rig to develop

its Fiord West prospect, in the northwest

corner of the Colville River unit, from the

existing CD-2 well pad. Fiord West has

presented a development challenge

because of its environmentally sensitive

location on the Beaufort Sea coast.

Other new developmentsOther new ConocoPhillips develop-

ments include expansion of operations at

the CD-5 pad in the Colville Delta unit,

GMT-1, GMT-2, and NE West Sak or

NEWS in the Kuparuk River unit. The

company is also considering extending its

West Sak development into an area it

refers to as Eastern NEWS, Jepsen said.

Also, in terms of oil from new devel-

opment, there is the Willow project. As

previously reported in Petroleum News,

ConocoPhillips has prepared a master

plan for that project, involving the devel-

opment of up to five drill sites hooked

into a central processing facility for the

field. Modules for the development

would be delivered by sealift via an artifi-

cial island in the nearshore waters of the

Beaufort Sea.

Another new technology,

ConocoPhillips’ compressed seismic

imaging technique, has enabled the com-

pany to increase its resource estimate for

Willow from 400 million to 750 million

barrels of oil. The new seismic technique

enables seismic data to be gathered four

times faster than previously and enables

the production of better seismic images,

Jepsen said.

Jepsen said ConocoPhillips anticipates

Willow production involving a technique

referred to as MWAG, the alternating

injection of water and miscible injectant

into the reservoir. The injection of water

would require seawater from the Kuparuk

seawater treatment plant, probably deliv-

ered by pipeline from Kuparuk Central

Processing Facility 2, Jepsen said.

Oil from a discovery in the West

Willow No. 1 exploration well, also

drilled last winter, could tie into the

Willow facilities at some stage in the

future. But that discovery requires further

testing and delineation, Jepsen said.

A combination of factorsJepsen attributed the transformation of

ConocoPhillips’ outlook for its North

Slope oil production to a combination of

technical innovation, a reduced cost of

supply, and a competitive tax environ-

ment under the provisions of tax legisla-

tion, Senate Bill 21.

Technical innovation, including the

advances in drilling techniques, has

helped the company target more

resources in existing fields, as well as

improving the viability of new develop-

ments. To manage costs, following the oil

price crash of 2014, the company has

taken a hard look at how to do things bet-

ter, bringing its Alaska cost profile down

to be competitive with other components

of the company’s portfolio, Jepsen said.

Jepsen particularly cautioned that

Alaska’s fiscal environment needs to

remain competitive with other oil produc-

ing regions — the current fiscal frame-

work under SB 21 keeps Alaska in the

game, he said. He also expressed concern

about the upcoming ballot on a proposed

new anadromous fish habitat protection

law. Uncertainty and potential litigation

associated with this measure could

become a big drag on development, he

said. l

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continued from page 1

CONOCO OUTLOOKAs recently as 2013 the company

was forecasting a continuingdecline rate of 6 to 8 percent per

year in its oil output from itsNorth Slope operations. But now

the company anticipates acomplete reversal of that situation,with production in 2028 expected

to be some 100,000 bpd abovewhere it is now, Jepsen said.

12 PETROLEUM NEWS • WEEK OF SEPTEMBER 16, 2018

By terms of a letter agreement dated Sept. 10, the

Alaska Department of Natural Resources, ExxonMobil

and BP (a major Point Thomson working interest owner)

agree that the year-end 2019 deadline has been stayed for

as long as the Alaska LNG Project is progressing. The

extension ends when the Alaska LNG Project reaches

final investment decision or when DNR notifies the par-

ties that the project is no longer progressing.

At the end of the extension the Point Thomson owners

will have 30 months to reach a final investment decision

on either of the expansion projects or lose acreage in the

field.

“The agreement continues to demand that our

resources at Point Thomson are developed to the maxi-

mum benefit of all Alaskans, and also aligns the state and

industry in a new way as the Alaska LNG Project

advances,” DNR Commissioner Andy Mack said in a

statement. “We are committed to development of this

critical resource, and this agreement keeps us on track.”

Gas sales agreementAlso Sept. 10, the Alaska Gasline Development Corp.

announced that ExxonMobil and AGDC had agreed to what

the corporation called “certain key terms including price

and a volume basis for a Gas Sales Agreement,” captured in

a “Gas Sales Precedent Agreement” signed Sept. 10.

AGDC and BP agreed to key terms of a gas sales agree-

ment, including price and volume, on May 4.

AGDC has not reached agreement with ConocoPhillips

— the other major North Slope leaseholder, a company

with natural gas interests at both Prudhoe Bay and Point

Thomson.

In a Sept. 10 statement on the ExxonMobil agreement

AGDC said the parties anticipated finalizing long-term gas

sales agreements for ExxonMobil’s share of both Prudhoe

Bay and Point Thomson gas. ExxonMobil has a 62.75 per-

cent share of Point Thomson and a 36.4 percent share of

Prudhoe Bay.

“This precedent agreement is good for Alaska and

ExxonMobil and represents a significant milestone to help

advance the state-led gasline project,” said ExxonMobil

Alaska President Darlene Gates. “As the largest holder of

discovered gas resources on the North Slope, ExxonMobil

has been working for decades to tackle the challenges of

bringing Alaska’s gas to market,” she said.

“The Alaska LNG project has made meaningful progress

over the past year,” said AGDC President Keith Meyer.

“We have secured the customers, we have advanced the

project with regulators, and now we have ExxonMobil’s

Gas Sales Precedent Agreement executed.”

Alaska Gov. Bill Walker said: “This agreement means

Alaska is one step closer to monetizing the North Slope’s

vast and proven natural gas resources. I am pleased with the

engagement and alignment from ExxonMobil for the

Alaska LNG project.”

Alaska’s congressional delegation welcomed the

announcement of the gas sales precedent agreement.

“This is a positive step in our state’s efforts to build a

new pipeline that will allow us to commercialize the North

Slope’s prolific natural gas resources,” the delegation said

in a Sept. 12 statement. “While we recognize that much

work remains to be done, we’re pleased to see the state

using its authority and leverage under the Point Thomson

settlement of 2012 to help move forward on this major

infrastructure project.”

The delegation, all Republicans, includes Congressman

Don Young and Sens. Lisa Murkowski and Dan Sullivan.

Agreement detailsThe Point Thomson Unit Letter Agreement said that for

purposes of the settlement agreement an Alaska LNG

Project means a fully integrated natural gas project produc-

ing LNG for export and natural gas for in-state delivery

being advanced by the state, a state-owned entity such as

AGDC “or an entity in which a State owned entity holds a

controlling equity share.”

The letter agreement says the June 30, 2017, plan of

development for Point Thomson, as supplemented in

October of that year and approved in August and December

2017, will remain in effect until the effective date of a major

gas sale POD, an expansion project POD or Dec. 31, 2019,

“if an MGS POD or Expansion Project POD has not been

submitted.”

The agreement calls for submittal of Point Thomson

PODs on a biennial basis beginning with the 2020-21 peri-

od. Those PODs would address initial production system

work or other exploration or development, including activ-

ities in support of the Alaska LNG Project.

On the extension period, a final investment decision is

defined as “a decision by the Alaska LNG Project owners to

construct the Alaska LNG Project, following securing the

necessary financing arrangements to construct and operate

the Alaska LNG Project.”

The agreements notes that the Point Thomson unit

working interest owners “have invested about $4 billion

in Point Thomson — more than 70 percent of that in

Alaska.” l

continued from page 1

POINT THOMSON

www.petroleumnews.com

said in presentations at the early

September Barclays conference in New

York.

“Evidence is accumulating that the

boom in the industry that began two years

ago is cooling off, particularly in what has

been its incandescent center, the Permian

basin of western Texas and eastern New

Mexico,” Crooks wrote, adding that both

Halliburton’s Jeff Miller and

Schlumberger’s Paal Kibsgaard “high-

lighted a slowdown in the number of new

wells being brought into production.”

Kibsgaard said the North America mar-

ket for hydraulic fracturing had “already

softened significantly more than we

expected” in the third quarter. The

Permian basin in particular, he said, faced

challenges that he expected to “have a

dampening effect on production growth,

wellhead prices and investment levels in

the coming year.”

Bill Thomas said EOG’s expectation

for the Permian basin was “probably a lit-

tle bit more subdued on growth than most

people would have it. It’ll grow certainly

for the next few years, but it’ll grow at a

slower pace every year and won’t be the

thing that’s going to destroy oil prices

again because it’s going to grow so fast.”

—KAY CASHMAN

continued from page 10

INSIDER

From left, Attorney General Jahna Lindemuth, ExxonMobil Alaska Production Manager Darlene Gates, Gov. Bill Walker, BPVice President of Commercial Ventures Damian Bilbao and DNR Commissioner Andy Mack.

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