Lalicker takes over as Hilcorp CEO;Hildebrand remains executive chair

page3

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

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

Vol. 23, No. 8 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of February 25, 2018 • $2.50

Western & central North Slope,Nanushuk excite investors at NAPE

Although bested by the excitement of

ANWR possibly opening to oil and gas

exploration, the rest of Alaska’s North Slope

also received some solid attention at the

recent NAPE Summit in Houston.

That shouldn’t be a surprise because the

western, not the eastern, North Slope holds

the hottest proven exploration play in North

America — the Nanushuk formation. The

area is already open to exploration and development and will

certainly be far less subject to lawsuits from the environmen-

tal community.

In addition to being the hottest play, the Nanushuk and

Torok geologic clinothem is the largest of its type in the

world.

A recent new assessment of the National Petroleum

Reserve-Alaska across the Colville River to the west dramat-

ically boosted technically recoverable undiscovered oil

reserves. Conducted by the U.S. Geological Survey and

Hilcorp permitting Seaview pad onKenai Peninsula south of Anchor Pt.

Hilcorp Alaska has applied to the Alaska Department of

Environmental Conservation to amend its Cook Inlet oil dis-

charge, prevention and contingency plan to add a new pad,

Seaview, on the Kenai Peninsula near Anchor Point. Hilcorp

said the pad location is some 1.25 miles east of Cook Inlet and

some 1.2 miles south of Anchor Point’s main business district.

It is some 850 feet west of the Anchor River and 2,000 feet

west of the Sterling Highway.

Hilcorp permitted and drilled seven shallow stratigraphic

test wells in the area over the summer, both on state oil and

gas lease acreage which the company holds and on fee lands.

Hilcorp said access to the proposed Seaview pad is from an

all-season gravel road which connects to the Old Sterling

Highway, some half mile to the west, which connects to

Sterling Highway some 1.25 miles to the north.

The company said it plans to construct the Seaview pad in

the second quarter of 2018. The pad will include drilling

equipment and work trailers, Hilcorp said.

On the issue of blowout concerns, the company said if a

$10 million in supplemental forANWR 1002 area seismic shoot

The administration has requested $10 million in the supple-

mental budget to allow the Alaska Department of Natural

Resources to participate in acquiring seismic data in the 1002

area of the Arctic National Wildlife Refuge, in anticipation of

federal lease sales in the area.

In the request the administration noted that the federal gov-

ernment has recently opened the 1002 area of ANWR to oil

and gas leasing, exploration and development.

“Availability of seismic data will improve interest in

exploring for oil and gas within the 1002 area,” the funds

request says. “This funding allows the state to work with other

interested parties to provide seismic data which will enhance

state revenue from lease sales and decrease time to drilling

and production.”

In a presentation of the supplemental budget in the Senate

Finance Committee Feb. 19, Office of Management and

Budget Director Pat Pitney said $10 million doesn’t go a long

way in seismic acquisition. The state gets 50 percent of

A changing worldBP Energy Outlook assesses the transition to an evolving energy future

By ALAN BAILEYPetroleum News

The BP Energy Outlook for 2018, published on

Feb. 20, predicts growing global energy

demand as standards of living improve in the

developing world, particularly in China and India,

but with Africa also factoring into this trend later

in the outlook period. Natural gas usage will grow

steadily in response to that demand, while the use

of renewable energy sources, especially wind and

solar, will likely increase rapidly.

In China in particular, renewables are expected

to overtake oil as an energy source by the end of

the period, However, global demand for oil will

probably remain robust for many years into the

future, the Outlook suggests.

The energy transitionThe Outlook considers what it characterizes as

the energy transition, the manner in which the evo-

BC pipe case weakensDilbit found to float on water for up to 3 weeks; premier says it would be studied

By GARY PARKFor Petroleum News

As the Canadian pipeline war of 2018 moves

toward a pivotal decision, which it is widely

assumed will see the federal government of Prime

Minister Justin Trudeau ordering work to proceed

on Kinder Morgan’s expansion of its Trans

Mountain export system, the underpinning of the

British Columbia government case against the

C$7.4 billion project is weakening.

In igniting the flareup between his province and

Alberta on Jan. 30, B.C. Environment Minister

George Heyman effectively placed a ban on

increased diluted bitumen, or dilbit, shipments

across his province pending more studies on the

impact of dilbit spills.

Sources within the B.C. government said that

declaration caught Premier John Horgan off guard

and unprepared at a time when he was on a trade

mission in Asia.

On his return, Horgan showed the first signs of

softening his government’s hard line.

“It’s never been my intention” to ban bitumen

first, then study the issue, he said, although he has

not ruled out limiting shipments at some later point

after study and consultation with the public.

However, Alberta Premier Rachel Notley has

refused to give B.C. the time to clarify its position

so long as it subverts federal trade rights.

She has startled her opponents by taking a

tough, unyielding stance, starting with a freeze on

FERC wants more infoAGDC finished 801 questions in January, now has 289 more, some previously asked

By KRISTEN NELSONPetroleum News

The Alaska Gasline Development Corp. said in

January that it had completed answering 801

questions posed by the Federal Energy Regulatory

Commission on AGDC’s application for a Natural

Gas Act Section 3 permit for the Alaska LNG proj-

ect. The application was submitted last April.

AGDC noted in its Jan 22 statement that FERC

said in December that when it had all the informa-

tion it would issue a notice scheduling the environ-

mental review and the date when a final environ-

mental impact statement would be issued.

“AGDC expects FERC will determine they now

have the information necessary to complete their

analysis and will soon publish a schedule” in the

Federal Register outlining activities leading up to

the final EIS, AGDC said in January.

But on Feb. 15 FERC sent another data request,

this one with 289 questions.

“This enclosure includes several requests for

information that have been made multiple times

during the pre-filing review phase, as well as in the

current application review, for which an adequate

response has not yet been received,” FERC said,

adding, in bolded text: “You should be aware that

the information described in the enclosure is nec-

essary for us to continue preparation of the draft

environmental impact statement.”

The FERC letter said there were also requests

based on information provided by AGDC since the

see INSIDER page 10

see SEAVIEW PAD page 9

see ANWR SEISMIC page 9

see BP OUTLOOK page 11

see PIPE CASE page 8

see FERC QUESTIONS page 11

Competition in energy markets willintensify because demand will slow as a

result of improved energy efficiency whiletechnical innovation will make more

energy available, the Outlook suggests.

2 PETROLEUM NEWS • WEEK OF FEBRUARY 25, 2018

To advertise: Contact Susan Crane at 907.770.5592

Petroleum News Alaska’s source for oil and gas newscontentsFACILITIES

FINANCE & ECONOMY

ALTERNATIVE ENERGY

ENVIRONMENT & SAFTEY

7 Kuparuk infrastructure upgrades approved

3 Lalicker takes over as CEO at Hilcorp

LAND & LEASING8 North Slope, Cook Inlet leases surrendered

2 Revised design for Grant Lake hydro

6 New ideas for dealing with oil spills

GOVERNMENT4 Simplifying the spill response planning

The state and federal governments are reorganizingregional contingency plans to simplify the planorganization and maintenance

3 EIA: US to be net energy exporter by 2022

Energy Information Administration ‘Annual EnergyOutlook 2018’; liquids, gas continue to grow through 2042, 2050, respectively

A changing worldBP Energy Outlook assesses transition to an evolving energy future

BC pipe case weakensDilbit found to float on water for up to 3 weeks

FERC wants more infoAGDC finished 801 questions in January, now has 289 more

ON THE COVER

Oil Patch Insider: Western & central North Slope,Nanushuk excite investors at NAPEHilcorp permitting Seaview pad on KenaiPeninsula south of Anchor Pt.$10 million in supplemental forANWR 1002 area seismic shoot

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

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

Revised design for Grant Lake hydroFERC seeks public comments prior to preparing environmental impact statement for project near Moose Pass on the Kenai Peninsula

By ALAN BAILEYPetroleum News

The Federal Energy Regulatory Commission is

requesting comments on a revised design for a pro-

posed hydroelectric project at Grant Lake on the Kenai

Peninsula. FERC is going to prepare an environmental

impact statement for the project and anticipates publish-

ing a draft EIS in October and a final EIS in April 2019.

Kenai Hydro LLC, a subsidiary of the Alaska Electric

and Energy Cooperative, the business entity that oper-

ates power generation and transmission facilities as a

part of Homer Electric Association, is proposing to build

the hydropower system to help meet Homer Electric’s

goal for the use of renewable energy in the utility’s

power generation mix.

Near Moose PassGrant Lake is an L-shaped water body in the hills

above and to the east of the Seward Highway, where the

highway runs through the valley of Moose Pass, with

Grant Creek flowing from Grant Lake into Lower Trail

Lake, just south of the southern end of Upper Trail Lake.

Construction of the five-megawatt hydro facility would

involve diverting water from Grant Lake through a tun-

nel to a powerhouse near the outlet of Grant Creek

canyon, a natural rock canyon.

The project has raised numerous concerns about pos-

sible impacts on the Kenai River watershed. The historic

Iditarod Trail from Seward to Nome also passes through

the project area, a situation that has required discussions

over any conflicts with the trail route.

Although Kenai Hydro had at one time considered the

possibility of constructing a concrete dam at the outlet

end of Grant Lake, the company eventually settled on a

design which eliminates the need for a dam and places a

water intake below the level of the lake’s natural water

surface, to the east of the lake’s outlet into Grant Creek.

A bypass pipe to Grant Creek would enable the required

minimum flow rate in Grant Creek to be maintained.

The maximum drawdown of the lake, to feed the

hydropower system, would take place in the winter, with

the spring runoff subsequently replenishing the lake.

Kenai Hydro filed a license application for the project

with FERC in April 2016 and FERC subsequently con-

ducted scoping meetings and prepared scoping docu-

ments for an environmental impact statement.

Agency requestFERC says that in October 2016 the National Marine

Fisheries Service and the U.S. Fish and Wildlife Service

asked Kenai Hydro if it would be feasible to move the

bypass flow into Grant Creek to a point close to the out-

let of the creek from Grant Lake. The agencies said that

this bypass relocation would facilitate downstream eco-

logical processes with little impact on the project eco-

nomics or power generation capabilities.

During the winter of 2016-17 Kenai Hydro conducted

engineering and economic feasibility assessments for the

see GRANT LAKE page 3

By KRISTEN NELSONPetroleum News

The U.S. is projected to become a net

energy exporter by 2022, the Energy

Information Administration said Feb. 6 in

presenting the agency’s “Annual Energy

Outlook 2018,” which looks out to 2050.

That estimate is a change from last year’s

outlook, officials said, which projected

the country would be come a net energy

exporter by 2026.

The 2022 date is based on EIA’s refer-

ence case, which assumes trend improve-

ment in known technologies, an econom-

ic view reflecting leading economic fore-

casters and demographers and current

laws and regulations.

In addition to the reference case, EIA

evaluates high and low economic growth

cases, high and low oil and gas resource

and technology cases and high and low

oil price cases. The U.S. becomes a net

energy exporter in all but two cases — the

low oil and gas resource and technology

case and the low oil price case.

The U.S. became a net energy importer

in 1953, EIA said in the outlook, “but

declining energy imports and growing

energy exports make the United States a

net energy exporter by the early 2020s in

the Reference Case.”

What is the U.S. exporting and import-

ing?

EIA said most U.S. energy trade his-

torically has been in crude oil and petro-

leum products, with the U.S. remaining

both an importer and exporter of petrole-

um liquids through 2050 in the reference

case — primarily importing crude oil and

exporting petroleum products such as

gasoline and diesel. In the reference case

the U.S. remains a net importer of petro-

leum and other liquids, while U.S. natural

gas trade — historically receiving natural

gas by pipeline from Canada and sending

it by pipeline to Mexico — becomes

increasingly dominated by liquefied natu-

ral gas exports to more distant locations.

Energy productionWith energy production growth

dependent on technology, resources and

market conditions, production is more

sensitive than consumption to assump-

tions in the side cases, EIA said.

The reference case projects total U.S.

energy production to increase by some 31

percent from 2017 through 2050. This

increase is led by renewables, natural gas

and crude oil, with crude oil production

increasing only during the first 15 years

of the projection period, EIA said.

Total production is bounded by

resources, with, for example, the high oil

and gas resource and technology case

assuming higher estimates than the refer-

ence case for unproved Alaska resources,

offshore Lower 48 resources and onshore

Lower 48 tight oil, tight gas and shale

gas. EIA said that side case “also assumes

lower costs of producing these resources

and faster technology improvement,”

with the low oil and gas resource and

technology case assuming the opposite.

In the high oil price case assumptions

include higher world petroleum products

demand, lower Organization of the

Petroleum Exporting Countries’ upstream

investment and higher non-OPEC costs

for exploration and development, with the

low oil price case assuming the opposite.

Natural gasNatural gas accounts for the largest

share of total energy production in the

reference case, EIA said, with renewables

other than hydropower growing the most

on a percentage basis.

In the reference case natural gas pro-

duction accounts for nearly 39 percent of

U.S. energy production by 2050, EIA

said, with production from shale gas and

tight oil playa as a share of U.S. natural

gas production expected to continue to

grow because the assumed resource size

is so large.

“Natural gas prices are highly sensi-

tive to domestic resource and technology

assumptions explored in the side cases,”

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

EIA: US to be net energy

exporter by 2022Energy Information Administration ‘Annual Energy Outlook 2018’;liquids, gas continue to grow through 2042, 2050, respectively

PETROLEUM NEWS • WEEK OF FEBRUARY 25, 2018 3

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agencies’ request. The company ultimate-

ly determined that the relocation of the

bypass flow would be viable and pro-

posed this option as the preferred design

for the hydropower facility. The company

subsequently filed an amendment to its

original FERC license application, to

incorporate the altered design. The new

design involves a pump system and a

weir structure at the outlet from the lake

and eliminates the bypass pipe in the ear-

lier design.

FERC is now seeking comments on

the amended design. l

continued from page 2

GRANT LAKE

FINANCE & ECONOMYLalicker takes over as CEO at Hilcorp

Greg Lalicker of Hilcorp Energy has taken over from founder

Jeffrey Hildebrand as chief executive officer of the company, the

Houston Chronicle is reporting.

A statement from Justin Furnace, the company’s corporate

director of external affairs, provided some details.

“It was announced internally in November 2017 that Greg

Lalicker would be assuming the role of Chief Executive Officer

at Hilcorp,” he said.

“The organizational change comes as the company, a long-

time producer in Alaska, Texas and Louisiana, continues to see

substantial growth in other legacy assets across the United

States.” Furnace said Jason Rebrook would take over from Lalicker as president, allow-

ing “Hilcorp to focus simultaneously on current asset development and potential future

growth.”

“Mr. Hildebrand will maintain his position as Executive Chairman and continue to

be heavily involved with the company.”

Hildebrand, a University of Texas graduate with geology and petroleum engineering

degrees, founded Hilcorp 1989 after working for other companies, among them Exxon

Mobil Corp.

The company came to Alaska in 2011 when it bought out Union Oil Company of

California and Chevron assets in Cook Inlet. At that time, Hilcorp’s website included

some company history, which described the company’s beginnings “as the proverbial

‘three guys and a telephone’ trying to make a living in the oil and gas business.”

By 2011, the company had grown to become one of the largest privately held explo-

ration and production companies in the U.S.

Lalicker, who has been with Hilcorp 12 years, is a University of Tulsa petroleum

engineering graduate who also holds degrees in law and business. He worked at

Australia’s BHP Billiton and at McKinsey & Co. before joining Hilcorp in 2006 as

executive vice president responsible for exploration and production.

Lalicker has most recently been president of Hilcorp and has been the face of the

company in Alaska, coming north to speak to local business groups and at conferences.

—KRISTEN NELSON

GREG LALICKER

see EIA OUTLOOK page 7

JUD

Y P

ATR

ICK

By ALAN BAILEYPetroleum News

The federal and state governments are

engaged in a project to reorganize and

simplify the arrangements for maintaining

government oil spill contingency plans for

Alaska, officials told the Alaska Forum on

the Environment on Feb. 15.

The agencies are “trying to streamline

the framework of government spill

response plans in Alaska and bring them

into closer consistency with national and

agency-level laws and regulations,” Nick

Knowles, the Environmental Protection

Agency’s Alaska area planner, told confer-

ence attendees.

Although any entity handling oil must

maintain an oil spill contingency plan,

backed up by the availability of appropriate

spill response resources, the state and fed-

eral governments also maintain plans. The

government plans help ensure that there are

adequate arrangements in place for dealing

with an oil spill, that adequate response

resources are available and that there are

specific tactics for dealing with spilled oil,

taking into account the concerns of com-

munities that may be impacted.

The government plans provide a frame-

work within which individual entity con-

tingency plans can be designed, ensuring

that the various plans meet government and

community requirements.

Goes back to Exxon ValdezThe current government planning sys-

tem dates back to the period following the

Exxon Valdez oil spill, when over a period

of a few years the federal government and

the state of Alaska engaged in parallel

efforts to create spill response plans. As a

consequence of working independently,

with Alaska moving ahead first, the two

government organizations came up with

two different plan frameworks. But the fed-

eral framework drove response planning

arrangements in states other than Alaska.

The federal system is driven top-down,

from a national contingency plan through

regional and area contingency plans within

the states.

Those differences between Alaska’s

plans and plans elsewhere persist. For

example, although the state, in common

with the federal government, uses a set of

procedures and standards under what is

called the incident command system for oil

spill response, the state plan documents do

not conform to the ICS standard as

employed in the national plan, Knowles

commented.

Moreover, Alaska now has a unified

plan for the whole state and a set of 10 sub-

area plans, under the unified plan, for dif-

ferent parts of the state. The unified plan

contains statewide policies and response

procedures, while each subarea plan con-

tains information specific to a subarea.

There is a regional response team that over-

sees maintenance of the unified plan and

subarea plans, while each subarea plan has

an area committee that is pulled together

periodically for plan updates. The concept

is that communities provide input to the

plans through the subarea committees.

It is, however, difficult to keep all the

Alaska plans updated when, for example,

the federal government issues new plan-

ning directives, especially given the num-

ber of subarea plans and the fact that an ad-

hoc committee must be formed to update

each plan. Policy changes can arise, for

example, as a result of incidents such as a

terrorist attack or a major spill such as the

Deepwater Horizon disaster, Knowles said.

Restructuring the Alaska systemThe envisaged reforms to the system

involve reconstituting the state’s unified

plan as an Alaska regional plan and, instead

of having 10 subarea plans, there would be

just four area plans. Four standing commit-

tees, rather than the previous 10 ad-hoc

committees, will maintain the area plans,

thus enabling plans to be updated annually,

rather than at the multiyear intervals that

result from the current arrangements. And

the rejigged plans would have a format

consistent with that of the national contin-

gency plan and those of other states, thus

simplifying the ability of out-of-state per-

sonnel to work with the Alaska documenta-

tion.

The four planning areas in Alaska

would consist of three offshore areas and

the entire Alaska landmass, more than

1,000 yards inland from the shore. The

three offshore areas, Southeast Alaska,

Prince William Sound, and western and

Arctic Alaska, would generally correspond

to the U.S. Coast Guard’s captain of the

port regions: The Coast Guard provides

federal oversight for offshore spill respons-

es, while the Environmental Protection

Agency is responsible for onshore federal

oversight. In the event of a spill, the appro-

priate federal agency would participate in a

unified command for the response, togeth-

er with the state, any appropriate local gov-

ernment entity and the party responsible for

the spill.

Underneath the area plans come more

specific plans, such as industry contin-

gency plans and plans for protecting specif-

ic geographic locations — the area plans

can help ensure consistency between these

various specific plans, Knowles explained.

The action planShannon Miller, interagency coordina-

tor from the Alaska Department of

Environmental Conservation, said that the

EPA, the Coast Guard and DEC have

worked together to build a plan of action

for transitioning to the new contingency

plan arrangements.

A key step will be the establishment of

the four committees for the Alaska plan-

ning areas, to maintain the new area plans.

The plan rework will involve recasting

information from the existing plans into the

new plan format. And each offshore area

plan will have an assigned on-scene com-

mander from the Coast Guard, she said.

Once the new plans are adopted, the old

plans will become redundant.

A statewide planning committee, which

has already met, is coordinating the plan-

ning effort, ensuring plan consistency.

DEC is resource constrained but wants

to see the new Alaska regional plan and

four area plans written and signed off by

the coming fall. The intent is to have the

committee for the western Alaska and

Arctic area meet in fall, and then have the

other committees meet by the fall of 2019,

Miller said.

Role of the committeesLt. Cmdr. Matt Hobbie, chief of plan-

ning and resource readiness for the U.S.

Coast Guard sector Anchorage, comment-

ed that the expectation is that the new area

committees will provide the flexibility to

deal with Alaska spill response issues. The

committees, in addition to appointed stand-

ing members from federal, state, local and

l G O V E R N M E N T

Simplifying the spill response planningThe state and federal governments are reorganizing regional contingency plans to simplify the plan organization and maintenance

4 PETROLEUM NEWS • WEEK OF FEBRUARY 25, 2018

Kay Cashman EXECUTIVE PUBLISHER & FOUNDER

Mary Mack CEO & GENERAL MANAGER

Kristen Nelson EDITOR-IN-CHIEF

Susan Crane ADVERTISING DIRECTOR

Heather Yates BOOKKEEPER

Marti Reeve SPECIAL PUBLICATIONS DIRECTOR

Steven Merritt PRODUCTION DIRECTOR

Alan Bailey SENIOR STAFF WRITER

Eric Lidji CONTRIBUTING WRITER

Gary Park CONTRIBUTING WRITER (CANADA)

Judy Patrick Photography CONTRACT PHOTOGRAPHER

Mapmakers Alaska CARTOGRAPHY

Forrest Crane CONTRACT PHOTOGRAPHER

Renee Garbutt CIRCULATION MANAGER

ADDRESS

P.O. Box 231647

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NEWS

907.522.9469

publisher@petroleumnews.com

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ADVERTISING

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scrane@petroleumnews.com

FAX FOR ALL DEPARTMENTS

907.522.9583

OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 23, No. 8 • Week of February 25, 2018

Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518(Please mail ALL correspondence to:

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POSTMASTER: Send address changes to Petroleum News, P.O. Box 231647 Anchorage, AK 99523-1647.

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Petroleum News and its supple-ment, Petroleum Directory, are

owned by Petroleum Newspapers ofAlaska LLC. The newspaper is pub-

lished weekly. Several of the individ-uals listed above work for inde-

pendent companies that contractservices to Petroleum Newspapers

of Alaska LLC or are freelance writers.

WELDING SUPPLIESLincoln Miller MilwaukeeStoody Tweco ThermalMathey ESAB Norton

& Victor Gas Equipment

CYLINDER GASESIndustrial, Blueshield Productivity Mixes, Medical and Specialty

Cylinders for rent, lease, and purchase

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see SPILL RESPONSE page 7

PETROLEUM NEWS • WEEK OF FEBRUARY 25, 2018 5

Hats off to Ryan Lance, Joe Marushack for latest

Alaska investment

Afognak Leasing LLC

Air Liquide

Airswift

Alaska Energy Services, LLC

Alaska Dreams

Alaska Frac Consulting LLC

Alaska Frontier Constructors (AFC)

Alaska Gasline Development Corp. (AGDC)

Alaska Marine Lines

Alaska Materials

Alaska Railroad

Alaska Rubber & Rigging Supply

Alaska Steel Co.

Alaska Textiles

Alaska West Express

Alpha Seismic Compressors

American Marine

Arctic Catering & Support Services

Arctic Controls

Arctic Fox Environmental

Arctic Wire Rope & Supply

Armstrong

ASRC Energy Services

AT&T

Avalon Development

Aviator Hotel

BELL & Associates

Bombay Deluxe

BP

Brooks Range Supply

C & R Pipe and Steel, Inc.

Calista Corp.

Carlile Transportation

Certek Heating Solutions

Chosen Construction

CMS, Inc./Hepworth Agency

Colville Inc.

Computing Alternatives

CONAM Construction

Construction Machinery Industrial

Cruz Construction

Dowland-Bach Corp.

Doyon Anvil

Doyon Associated

Doyon Drilling

Doyon, Limited

exp Energy Services

Fairweather

Flowline Alaska

Fluor

Foss Maritime

Fugro

GMW Fire Protection

Golder

Greer Tank & Welding

Guess & Rudd, PC

ICE Services, Inc.

Inspirations

Judy Patrick Photography

Kuukpik Arctic Services

Last Frontier Air Ventures

Little Red Services, Inc. (LRS)

Lounsbury & Associates

Lynden Air Cargo

Lynden Air Freight

Lynden Inc.

Lynden International

Lynden Logistics

Lynden Transport

Mapmakers of Alaska

MAPPA Testlab

Maritime Helicopters

Motion & Flow Control Products

Nabors Alaska Drilling

Nalco Champion

NANA WorleyParsons

NEI Fluid Technology

Nordic Calista

North Slope Telecom

Northern Air Cargo

Northern Solutions LLC

Northrim Bank

NRC Alaska

Nutrien

Olgoonik Corp.

PENCO

Petro Star Lubricants

PRA (Petrotechnical Resources of Alaska)

Price Gregory International

Resource Development Council

SAExploration

Sourdough Express

Tanks-A-Lot

The Local Pages

Unique Machine

Usibelli

Volant Products

Waste Management

We salute ConocoPhillips’ chairman & CEO Ryan Lance, Alaska

president Joe Marushack and their team for their recent $400 million acquisition of long-time partner

Anadarko’s interest in their North Slope leases and Alpine pipeline.

This investment accentuates ConocoPhillips’ commitment to

exploration and development on the western North Slope, where the company has made several

recent oil discoveries in the Nanushuk and Torok formations,

the hottest exploration play in North America and the largest

geologic clinothem of its type in the world.

Joe Marushack, President of ConocoPhillips

Alaska

Ryan Lance, ConocoPhillips’ chairman

& CEO

6 PETROLEUM NEWS • WEEK OF FEBRUARY 25, 2018

By ALAN BAILEYPetroleum News

The world of oil spill response is an evolving phenom-

enon, with people continuing to think up ingenious

new ways of finding and dealing with renegade hydrocar-

bons. On Feb. 12 attendees at the Alaska Forum on the

Environment heard about three developments, each with

the potential to improve response effectiveness: increasing

the efficiency of in-situ oil burning; the use of forward

looking infrared, or FLIR, for the detection of oil; and the

use of dogs to sniff out the locations of remnant oil hidden

along a shore.

Burn efficiencyThe in-situ burning of spilled oil is a proven technique

which has been used widely. But, while the complete burn-

ing of oil should result in the production of, essentially,

water and carbon dioxide, in practice the burning in not

complete and thus generates huge volumes of air-polluting

soot, while also leaving an oily residue. Can the burning be

rendered more efficient?

Ali Rangwala, a professor in Department of Fire

Protection Engineering in the Worcester Polytechnic

Institute, described research into why the burning is ineffi-

cient and, hence, how the efficiency may be improved.

One interesting finding from the research is that all oil fires

tend to burn at the same constant rate with the same flame

height, regardless of the size of the burn. The researchers

determined that soot from the fire limits the burn to that

constant rate. In effect, the soot blocks the radiated heat

from the fire reaching the burning oil, thus limiting the oil

to an equilibrium temperature below the temperature

required for rapid and more complete burning.

Flame refluxerTo counter the blanketing effect of the soot, the

researchers have tried experimental oil burns with what

is called a flame refluxer, a system of vertical metal rods

protruding up through the fire: The metal conducts heat

that would otherwise be lost from the upper part of the

fire back down into the oil, hence increasing the temper-

ature of the fire, and thus increasing the burn rate and

efficiency. The researchers have tried this technique

burning oil that has leaked from electrical transformers,

North Slope crude oil, an oil slick and organic waste.

Adding 37 vertical metal rods to a test burn involving

North Slope crude mixed with water, for example,

increased the burn rate by a factor of more than two,

while adding 59 rods increased the rate about six times,

Rangwala said.

Offshore burnsThe challenge in the case of an offshore oil slick is the

cooling effect of the water on which the thin layer of oil

floats. To overcome this problem, the researchers tried

placing a fine copper mesh on the slick and attaching

copper coils rather than rods to the mesh to transfer heat

into the burn. A burn in a test tank showed a six-fold

improvement in the burn rate relative to a traditional

burn approach, Rangwala said. The efficiency also

improved: oily residue left after the burn dropped from

32 percent of the original oil to somewhere between 1.5

and 4 percent, with much less smoke and a reduction of

50 percent in the ratio of carbon monoxide to carbon

dioxide generated.

There are many potential applications for this tech-

nique, Rangwala suggested.

Infrared oil detectionLee Majors, planning and development manager for

Alaska Clean Seas, the North Slope oil spill response

organization, talked about the use of forward looking

infrared to detect spilled oil. Infrared detection involves

the use of a camera designed for the sensing and imaging

of infrared radiation, a form of radiated heat. The camera

produces digital images similar to those from a conven-

tional digital camera but using infrared radiation rather

than visible light.

The infrared detection of oil depends on the fact that

oil and water have different levels of heat emission,

Majors explained. The slightly higher radiation from oil

appears as light areas in an FLIR image. And the tech-

nology is sufficiently sensitive to even detect the level of

the oil in an oil tank.

The technology can be used on many different plat-

forms, including ships, aircraft and drones. There are

also handheld FLIR devices. And FLIR cameras can be

used in almost all spill response situations. Conditions to

be evaluated when considering the use of FLIR particu-

larly relate to visibility, with fog, rain or snow potentially

detracting from the technology’s effectiveness, Majors

said. With ice prevalent on the North Slope for around

eight months of the year, ice conditions also must be

considered when evaluating the potential for FLIR use

on the Slope, he said.

Uses in ice and snowAlthough it is not possible to use FLIR to detect oil

under ice, the technology is very effective at locating oil

slicks on water between ice floes. On the North Slope

FLIR can also detect warm, recently produced oil that

has been spilled under snow — in a spill response the

technology can prove invaluable in outlining the full

extent of a spill in snow, beyond the area where the oil is

immediately visible. And a FLIR image can be merged

into a map of the spill.

However, FLIR cannot detect oil under snow, once

the oil has cooled. The FLIR images also become unre-

liable in detecting a very thin, surface oil layer, Majors

l E N V I R O N M E N T & S A F E T Y

New ideas for dealing with oil spillsImproved efficiency of in-situ burning, the use of forward looking infrared and the use of sniffer dogs to locate oil can all help

see NEW IDEAS page 9

PETROLEUM NEWS • WEEK OF FEBRUARY 25, 2018 7

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EIA said, with the growing demand for

natural gas pushing production into

more expensive-to-produce areas in all

cases, “putting upward pressure on

production costs and prices.”

The agency said growth in the domes-

tic and export markets drives an increase

in U.S. natural gas prices at benchmark

Henry Hub in the reference case, with

crude oil prices affecting natural gas

changes in global natural gas consump-

tion, U.S. exports and associated gas —

natural gas produced from oil formations.

In the reference case domestic natural

gas production grows 6 percent per year

from 2017 to 2020, then slows to less

than 1 percent per year through 2050.

The 2018 annual outlook reference

case has Henry Hub prices 14 percent

lower on average through 2050 than the

2017 outlook, EIA said, citing an estimat-

ed increase in lower-cost resources, pri-

marily in the Permian and Appalachian

basins, supporting higher production lev-

els at lower prices over the projection

period. Increased natural gas production

comes from both shale gas and tight oil

plays, which account for more than three-

quarters of natural gas production in the

U.S. by 2050.

Crude oilU.S. crude oil production in the refer-

ence case is projected to surpass the 1970

record of 9.6 million barrels per day this

year, and EIA said that production vol-

ume “will continue to grow as upstream

producers increase output because of the

combined effects of rising prices and pro-

duction cost reductions.”

Lower 48 onshore tight oil continues

to be the main driver of U.S. crude oil

output, accounting for some 65 percent

of cumulative domestic production in the

reference case through 2050.

EIA said that despite higher oil prices,

in the reference case “U.S. crude oil pro-

duction levels off between 11 million and

12 million barrels per day as tight oil

development moves into less productive

areas and as well productivity declines.”

North Sea Brent oil prices in 2016, in

real terms, “were at their lowest level

since 2004,” EIA said, and increased

modestly in 2017, a trend which EIA said

is expected to continue through 2050 in

the reference case, reaching $114 per bar-

rel in 2017 dollars in 2050 — compared

to $229 in the high oil price case and $52

in the low oil price case.

Outlook changesEIA said U.S. Geological Survey

assessments of the Wolfcamp and

Sprayberry formations were incorporated

into the current update, mainly affecting

regional oil and natural gas production

and related markets.

On the technology side, EIA said oil

and natural gas technology and operation

improvements were revised “by increas-

ing rates of technological progress during

the early development of currently unde-

veloped resources to reflect industry-

wide identification of the most produc-

tive areas and to select the best technolo-

gies for particular geologies.” l

continued from page 3

EIA OUTLOOK

tribal governments, will have members at

large representing entities such as the oil

industry, regional citizens’ advisory coun-

cils, oil spill response organizations and

non-government organizations. The stand-

ing committees will meet at least twice per

year, to consider plan updates based on

new knowledge, and will be expected to

produce annual reports and updates,

Hobbie said.

Given the very large geographic scale of

some of the new planning areas, the group

working on the Alaska contingency plan

reorganization did consider the possibility

of establishing more than one standing

committee for some areas. However, the

group determined that this would be

impractical, given the limited resources

available to conduct the substantial work

and reporting that each standing committee

has to carry out, Hobbie said.

However, although there will only be

one plan and one standing committee for

each planning area, a standing committee

could set up subcommittees or an ad-hoc

committee to address specific issues in an

area, he said.

Flexibility to adaptUltimately, the standing committees,

with their focus on improving the area con-

tingency plans, will become the most

important component of the system, Hobbie

said. The expectation is that the new com-

mittee structure will be able to more rapidly

and effectively accommodate the changing

needs for response capabilities in Alaska

than is possible under the current arrange-

ments. But the effectiveness of the commit-

tees will depend on help, especially help

from the communities that the contingency

plans are designed to protect, he said.

And the speakers emphasized their

desire to conduct outreach, to communi-

cate with communities about the planning

work. l

continued from page 4

SPILL RESPONSE

FACILITIESKuparuk infrastructure upgrades approved

Alaska’s Division of Oil and Gas has approved applications by ConocoPhillips

for a couple of upgrades to the surface infrastructure in the Kuparuk River field.

The first of the upgrades involves the relocation of a methanol storage tank and

a pump module from drill sites DS-3J and DS-1H to DS-1D. The modules will be

used for continuous methanol injection in the field. Installation of the modules on

DS-1D will involve the placement of eight 18-inch diameter vertical support

members, to support the modules on the pad.

The second upgrade involves the installation of a new 8-inch diameter seawa-

ter pipeline, connecting the pigging module on drill site 1B to an existing 12-inch

water pipeline. Laying of the 1,400-foot pipeline will involve constructing two

underground road crossings near the northeastern end of the Kuparuk Base Camp

and Central Production Facility No. 1.

—ALAN BAILEY

sales of B.C. wine in Alberta and warning

of more reprisals unless Trudeau upholds

Canada’s constitution which gives him

final authority over the movement of any

resources through pipelines that cross

provincial borders.

Study counters dilbit viewWhile the saber-rattling continues, new

research compiled by Natural Resources

Canada scientists counters the widely held

view that an escape of dilbit would be dis-

astrous to open water.

NRC scientist Heather Dettman said

tests conducted since 2014, using various

grades of dilbit, show that the substance

can float for up to three weeks, even under

wave conditions that would cause conven-

tional crude to mix with the water.

“The misinformation is that (dilbit)

would sink as soon as it hits the water,” she

said. “That’s the messaging that’s been out

there and that’s not what we’ve been find-

ing, even in fresh water.”

But she did concede that if a storm

pushed the dilbit ashore that would pose a

serious cleanup problem.

Dettman said the team of NRC scien-

tists is now trying to determine how long a

spill would pose a threat to the environ-

ment as well as figuring out how much

harm would be caused by the toxic solvents

used in dilbit.

However, she suggested light crude

might actually be more hazardous when it

hits water.

“That’s like adding cream to coffee,”

she said. “It’s all mixed in and it gets stuck

in the sediment.”

Dettman said dilbit “looks ugly and is

not good for fish. But because it’s there you

can pick it up (and) we get a very high

recovery rate.”

Kinder MorganKinder Morgan has made its own moves

to gain public support by promising that

when Trans Mountain reaches its design

capacity of 890,000 barrels per day (three

times current volumes), it will provide

large, powerful escort tugs through the

Juan de Fuca Strait between the B.C. main-

land and Vancouver Island to help either

avert or clean up spills.

The company said it will send more

than C$100 million in extra funding to the

Western Canada Marine Response Corp., a

federal government agency responsible for

mitigating oil spills, as it moves toward a

seven-fold increase in the number of

tankers leaving its Westridge terminal in

the Port of Vancouver to 34 shipments a

month.

For now, Kinder Morgan is also stand-

ing behind its record of never having a sin-

gle spill in the 62 years that tankers have

sailed from Westridge.

NEB, TrudeauIn the midst of the political furor

Canada’s National Energy Board has infu-

riated pipeline opponents by giving Kinder

Morgan the greenlight to start work on

Westridge expansion, while ending restric-

tions on the related construction work

around the terminal site.

The federal regulator also indicated it

will override any attempts by municipal

governments to stall progress on the

pipeline expansion.

Trudeau has stepped up his public role

in the debate by telling the National

Observer that in blocking the pipeline

Horgan is “putting at risk (Canada’s) entire

climate change plan. If the Kinder Morgan

pipeline does not go through, Alberta will

withdraw its support for the plan. We will

not have Alberta fighting to achieve its car-

bon targets.”

IndustryThe Canadian petroleum industry wants

to see the pipeline proceed, although there

is no commonly held view on what can be

done without damaging Alberta’s econo-

my.

“At the end of the day, it’s frustrating

because British Columbia would not last a

week without oil and gas,” said Mark

Salkeld, chief executive officer of the

Petroleum Services Association of Canada.

“They support the LNG industry, so

they are all for fossil fuels in their own

backyard. But they are ready to mess

around with Alberta and hold us back from

developing our natural resources because

they have access (to tanker ports on the

Pacific Coast) and we don’t,” he said.

While the bare-knuckles fight contin-

ues, Kevin Neveu, chief executive officer

of Precision Drilling, Canada’s largest

drilling contractor, said the slowdown in

building pipelines makes Alberta’s oil sec-

tor “less economic and less competitive.”

Energy consulting firm IHS Energy said

the widening gap between West Canada

Select heavy crude and benchmark U.S.

prices has widened, costing Canada more

than C$1 billion in the last two months

alone, affecting revenues to producers and

taxes and royalties to governments.

Gary Leach, president of the Explorers

and Producers Association of Canada, said

that while Alberta and B.C. trade blows,

ignoring their reliance on resource-based

economies, they are demonstrating to out-

side investors “the worst example of a dys-

functional federation.”

An editorial in the Calgary Herald said

Horgan has “exhibited a flair for the worst

kind of politics (by obstructing Trans

Mountain). He’s apparently quite comfort-

able with his province facilitating the

export (through a Vancouver shipping ter-

minal) of dirty coal from the United States

to generate electricity in Asia.”

“Horgan is seemingly quite content to

receive Alberta oil that keeps the bulk of

B.C. vehicles moving. But he flinches at

the prospect that Canada could end its

dependence on the United States and send

its oil to markets that would pay a higher

price — creating needed employment and

billions of dollars in revenue for govern-

ments at all levels.” l

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LAND & LEASINGNorth Slope, Cook Inlet leases surrendered

Armstrong Energy, ConocoPhillips Alaska and Hilcorp Alaska each surrendered

oil and gas leases to the state in late December and January.

The Alaska Division of Oil and Gas leasing report shows that Armstrong Energy

surrendered three adjacent leases in state waters offshore the National Petroleum

Reserve-Alaska on the west side of the North Slope, all part of a block held by the

company. A division map shows two of the three leases are the most southerly of a

block immediately offshore NPR-A; the third lease, the most easterly, is separated

from the shore by another lease held by Armstrong Energy.

ConocoPhillips surrendered a block of 13 North Slope leases immediately south

of the Prudhoe Bay unit. The Dalton Highway runs through the western portion of

this block.

Hilcorp surrendered three onshore Cook Inlet leases, all on the Kenai Peninsula,

one south of Clam Gulch and east of the Ninilchik unit; one northeast of Ninilchik

adjacent to the eastern edge of the Ninilchik unit; and one an isolated company lease

in the middle of the peninsula northeast of Nikolaevsk.

Three Cook Inlet area held by Woodstone Resources leases were terminated for

failure to pay rent. One is an isolated lease on the west side, west of Moquawkie and

northeast of Nicolai Creek. Two are adjacent leases east of Nikolaevsk and north of

Kachemak Bay on the southern Kenai Peninsula.

The division denied applications by Alliance Exploration to assign interests to

Linger Energy Holdings. Data filed with the Alaska Department of Commerce,

Community and Economic Development’s Division of Corporations, Business and

Professional Licensing show both entities are limited liability companies 100 per-

cent owned by The Linger Trust.

—KRISTEN NELSON

continued from page 1

PIPE CASE

said. However, a FLIR image can be used to assess the

thickness of an oil pool.

FLIR technology can also be used to detect marine

mammals, because of the heat that the animals radiate. In

fact, on the North Slope people use FLIR to detect polar

bear dens. Majors showed an image of a den, with a sow

and two cubs clearly visible.

Using trained dogsScott Pegau from the Prince William Sound Oil Spill

Recovery Institute talked about an evaluation of the use of

dogs to detect hidden, spilled oil on Prince William Sound

beaches. This is relic oil from the Exxon Valdez oil spill

that has been on the beaches for 25 years but that has not

been degraded because it is not in direct contact with the

sea or the atmosphere.

The idea is to retrain dogs that were originally intended

for detecting unexploded bombs, to find oil instead. Pegau

said that the dogs can be trained to recognize some specif-

ic threshold of oil concentration. The Prince William

Sound evaluation involved determining if a suitably

trained dog could find remnant oil by taking the dog to

two different residual oil sites. Could the dog both locate

oil and delineate the extent of an oil patch? If so, it could

be possible to map out areas of contamination without

having to dig ditches all across a beach.

The dog used for the Prince William Sound experiment

was part of a team of six dogs being used to detect oil in

streams as part of an oil spill cleanup in Saskatchewan,

Pegau said.

A team effortThe oil search test involved a specialist dog handler, a

dog trainer and a shoreline oil cleanup expert. The dog

was fitted with a GPS collar, to enable the team to track

the dog’s position. When the dog detected a target, it sig-

naled an alert. The team placed a flag to mark each alert.

It was found that for the most part the searches resulted in

oil patch delineation, with the dog handler having to

repeatedly move the dog out of an oil patch area, so that

the dog could locate another edge of the patch, Pegau

said.

In some cases the team buried an oil target, to see if the

dog would find it.

Oil detectionIn the experiment, the dog made 52 alerts for oil, 19 of

which were found to be associated with oil beneath the

surface and nine of which were not associated with the

presence of oil. It did not prove possible to verify whether

22 alerts were associated with oil. And two alerts were

found to be a result of site contamination because people

had just come from an oil impacted beach.

A reason for some false alerts may have been oil odors

migrating up the shore before reaching the surface, or

because of a very low oil concentration, Pegau said.

The result of the experiment was a determination that

the dog could detect known locations of oil in the context

of Prince William Sound, in areas where the oil is not

always visible. The most valuable use of dogs could be

determining which beaches are clear of oil, without hav-

ing to dig pits in the beaches, Pegau suggested. l

PETROLEUM NEWS • WEEK OF FEBRUARY 25, 2018 9

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continued from page 6

NEW IDEASwell blowout occurred, a small amount of oil

could possibly reach Cook Inlet via the Anchor

River in the summer, but based on modeling, no

oil would reach Cook Inlet in the winter.

Public comment on the application is being

accepted through March 13.

—KRISTEN NELSON

continued from page 1

SEAVIEW PAD

monies from leasing and royalty in the 1002 area

and she said if there is additional interest there will

be more revenues to the state.

DNR Commissioner Andy Mack told the com-

mittee that the Congressional Budget Office esti-

mated the two proposed lease sales in the 1002

area could generate $2.2 billion, and said the state

believes most of that money would come in the

first of the two proposed sales.

He said the state has learned through the tax

credit program how valuable seismic information

is, and with the potential of a significant amount of

revenue the state wants to do what it can to draw

as many qualified bidders as possible and increase

the value of the sale to the state.

—KRISTEN NELSON

continued from page 1

ANWR SEISMIC

based only on a re-evaluation of the

resource potential of the Nanushuk and

Torok — rock units associated with

major recent oil discoveries in the region

— USGS increased potential undiscov-

ered NPR-A oil reserves from a few hun-

dred thousand barrels in 2010 to 1.7-21.8

billion barrels, with a mean estimate of

8.8 billion barrels.

And all this is on top of already-dis-

covered Nanushuk oil on the western

North Slope, on both sides of the

Colville River, including Armstrong’s

big discovery at Pikka (1.2 billion bar-

rels, with a 120,000 barrel-a-day devel-

opment on track to produce in 2022) that

is east of the Colville and

ConocoPhillips’ Willow find in NPR-A

(300 million barrels of recoverable oil,

100,000 bpd possible from first develop-

ment in 2023) that ConocoPhillips exec-

utive Matt Fox said in November had

enabled the calibration of seismic tech-

niques to specifically search for similar

prospects.

The company identified “a lot” of

Willow lookalikes in the Nanushuk, per

Fox — “every one of them we’ve drilled

so far has had oil in it, so we’re hopeful

that several of these Willow lookalikes

will deliver.”

The thick sands that form the initially

discovered reservoir at Pikka can be

traced along a zone more than 40 miles

in length, with potentially more than 10

billion barrels of oil in place. Moreover,

the same geology extends for more than

a hundred miles across NPR-A, with 46

prospects identified on just one seismic

line, an Oil Search executive said recent-

ly.

In February 2016, before Armstrong’s

Horseshoe wildcat results were in, then-

Alaska Department of Natural Resources

Commissioner Mark Myers said “the

proven contingent oil reserve number

makes the (Pikka) discovery the largest

since the Alpine field, the probable con-

tingent reserve number the largest since

the Kuparuk field, and the possible con-

tingent number makes the discovery the

largest since Prudhoe.”

The NAPE Summit on Feb. 5-9 had

12,299 attendees, which was up about

1,000 from 2017. An annual event

designed to be the oil and gas industry’s

worldwide marketplace for the buying,

selling and trading of prospects and pro-

ducing properties, NAPE celebrated its

25th anniversary this year.

So, who expressed interest in the

western North Slope, home of the most

important trend in North Slope and U.S.

exploration activities over the past three

years?

Nanushuk area prospectsLong-time Alaska oil and gas investor

Paul Craig, who has an interest in the

three-lease South Nanushuk prospect

south of Horseshoe, plus a royalty over-

ride in the northern part of the undevel-

oped Umiat oil field, told Petroleum

News, “I left NAPE feeling very positive

about Alaska and about the future of

Umiat and the South Nanushuk prospect

given the level of interest shown at

NAPE” in the Nanushuk and Torok for-

mations.

“Some people are preoccupied with

ANWR opening … but we (the western

North Slope) have the biggest clinothem

in the world … with about 1 billion bar-

rels of oil in place at Umiat.”

In Craig’s opinion, “The Lower 48

has shifted from exploration to mining

projects in tight oil when they can get

production costs low enough. It doesn’t

have exploratory risk, but Bill Armstrong

and his partners are still out there doing

real exploration. That takes guts and

vision. Armstrong was preceded on the

North Slope by ARCO’s Robert O.

Anderson at the Prudhoe Bay discovery.

That’s what made America great in the

first place — people who took intelligent

risks.”

In the booth Craig was part of at

NAPE, three entities represented Cook

Inlet and North Slope opportunities —

Aurora Exploration, Craig’s company

Trading Bay Oil & Gas and Malamute

Energy.

Aurora Exploration is operator of the

Cook Inlet basin Nicolai Creek unit with

half of Aurora owned by Trading Bay,

and the other half by Aurora Power

Resources in which Scott Pfoff is the

principal owner.

The South Nanushuk prospect, owned

by Zamarello Trust, Trading Bay and

Paul Gardner, consists of 55-plus square

miles.

Malamute operates the undeveloped

Umiat oil field and was represented at

the summit by Leonard Sojka and Corri

Feigi, former director of Alaska’s

Division of Oil & Gas.

Pfoff’s impression of NAPE was a

“medium turnout” compared to previous

years. “I’ve seen it worse and I’ve seen

it a lot better,” he told PN.

There was nonetheless an uptick in

interest in Alaska over last year, he said;

both from people looking to invest and

companies interested in buying and oper-

ating prospects.

“We had some really good prospects

represented at our booth,” Pfoff said.

“They loved the geology.”

Guitar safest investment?Possibly one of the most risk-free

North Slope investments would be the

former Hemi Springs unit, adjacent the

southwest side of the Prudhoe Bay unit.

The Hemi Springs unit, which termi-

nated in 1992 under different ownership,

was renamed and unitized as the Guitar

unit by its current owner and operator

Alliance Exploration.

Both Barry Foote and his son Derek,

who heads up Alliance in Alaska and is

based in Sterling, said their preference

was to find a partner to come in and drill

a planned exploration well with them.

When asked whether Alliance has any

meetings with potential investors or buy-

ers scheduled, Derek told PN, “We tenta-

tively scheduled meetings for next

month (March). We’ll consider almost

anything … when you’re playing in

Alaska where the big boys play you have

to keep all avenues open.”

Derek said the Guitar unit “is the eas-

iest North Slope play to get developed

because it’s easily accessible and has an

existing well on one lease.”

The operator “should be able to cut

the time way down” that it takes to first

oil, he said, noting it would only require

6-7 miles of ice road to drill the well

Alliance has scheduled for next winter.

“The staging area that BP has is right

there; there’s an existing pad.”

The Guitar exploration plan said the

well will penetrate to the base of the

Ivishak and a lateral well will be drilled

into the Kuparuk C.

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INSIDER

see INSIDER page 12

PETROLEUM NEWS • WEEK OF FEBRUARY 25, 2018 11

lution of the worldwide energy system

may continue into the future. In introduc-

ing this year’s findings, Spencer Dale, BP

Group chief economist, said that the time

period that the Outlook encompasses has

been extended by five years to 2040, to

bring some features of the energy transi-

tion into sharper focus. Also, on the basis

that no suggested future energy scenario

will prove to be correct, the Outlook puts

forward six or seven different scenarios,

without suggesting a base or central sce-

nario that is thought most likely.

The value of forecasting is to better

understand the nature of the uncertainties

that people face, and the key judgments

and issues that will determine the future,

Dale said.

The Energy Outlook identifies three

key themes that will shape the energy tran-

sition over the next 20 to 30 years: the

growth in energy demand in the develop-

ing world; the increasing competitiveness

of energy markets; and the continuing

challenge of bringing down carbon emis-

sions to meet goals set in Paris in 2015.

Competition in energy markets will inten-

sify because demand will slow as a result

of improved energy efficiency while tech-

nical innovation will make more energy

available, the Outlook suggests.

And the Outlook looks at the energy

transition through three lenses: how energy

is used, where it is used and what form the

energy takes.

World GDP doublesUnder all scenarios the Outlook

assumes that the world gross domestic

product will more than double by 2040,

driven in part by population growth but

mainly by fast-growing emerging

economies. However, given anticipated

gains in energy efficiency, energy demand

would only increase by about one third.

Oil and other liquid fuels appear set to

play a continuing major role over the next

20 to 30 years, although demand growth

will likely slow and at some point, level

out. In particular, industrial non-fuel use of

oil will remain buoyant, given the rising

standards of living in various parts of the

world. Global coal consumption will likely

flatten.

Scenarios in which governments are

more aggressive in their climate policies

could push that leveling of oil demand

towards earlier years. However, in general,

future oil demand would tend to plateau

rather than peak and then drop. Oil and gas

remain important, regardless of which

energy scenario is considered.

Under a scenario referred to as the

“evolving transition,” a transition that con-

tinues along the current path, with the

energy system evolving in response to cur-

rent government policies, new technolo-

gies and social preferences, energy

demand increases by about one third by

2040. Industrial energy demand would

account for about half of the increase in

energy consumption, while growth in

demand from the transportation sector

would slow sharply as transportation effi-

ciency improves. The power generation

sector would account for almost 70 percent

of the increased need for primary energy,

in particular because of the need for home

appliances such as air conditioning in an

increasingly affluent world.

Electric carsThe Outlook devotes significant atten-

tion to questions around the increasing use

of electric cars, and the impact on oil

demand of the replacement of the internal

combustion engine by electrical power in

road vehicles. The Outlook links this phe-

nomenon with what it calls the mobility

revolution, in which the use of electric cars

— and in particular electrically powered

autonomous vehicles — could lead in the

2030s to a large growth in shared mobility,

where people increasingly ride in non-

owned cars. That phenomenon, coupled

with the need to consider hybrid electric

cars as well as pure electric cars, has led

the BP analysts to evaluate future electric

vehicle energy demand, not in terms of the

number of electric cars on the roads, but in

terms of the total number of road miles

powered by electricity. The use of

autonomous cars in conjunction with

shared mobility would increase the amount

and intensity of electric propulsion, as the

cost of car transportation drops.

However, the efficiency gains that a car

manufacturer could book as a result of sell-

ing more electric vehicles could partly off-

set the manufacturer’s need to improve the

efficiency of other types of vehicle, to

meet overall efficiency standards. Thus,

the reduction in oil demand from selling

more electric vehicles would tend to be

largely offset by less need to make internal

combustion engine cars more efficient.

But one scenario considers the possibil-

ity of a worldwide ban on any car with an

internal combustion engine from 2040

onwards, although with some internal

combustion engine vehicles still in use

while being phased out. This scenario,

while unlikely, provides some insights into

the manner in which electric car use may

impact oil demand. Dale commented that

the scenario seems improbable because it

exceeds even the most stringent govern-

ment policies announced to date, because

of the cost to people of switching to elec-

tric vehicles and because of the difficulties

of implementing the necessary electric car

charging infrastructure worldwide.

Under this scenario global oil demand

would drop by about 10 million barrels per

day. That represents about 10 percent of

current oil production. Projecting that for-

ward to anticipated energy demand in 2040

indicates that oil usage would likely be

slightly higher than today, thus suggesting

that electric car use will not prove a game

changer for oil demand.

Energy suppliesOn the supply side, the BP report sees

U.S. tight oil providing much of the supply

growth in oil in the earlier years of the

forecast. Then, as the growth in tight oil

starts to plateau, there will be a heightened

role for oil supplies from the members of

the Organization of the Petroleum

Exporting Countries. However, a key

uncertainty is the potential for tight oil pro-

duction to keep growing.

The Energy Outlook suggests that natu-

ral gas usage will grow much more strong-

ly than that of oil or coal. This growth will

take place in particular in the power and

industrial sectors. There will likely be an

increase in gas demand by developing

countries, with low cost gas becoming

increasingly available around the world as

liquefied natural gas supplies increase.

Moreover, government policies, particular-

ly in China, are encouraging moves away

from the use of coal towards cleaner, low

carbon fuels including natural gas.

However, even if stringent climate policies

were to dampen gas demand, that demand

is unlikely to drop below current levels.

The use of renewable energy, in partic-

ular wind and solar, is growing the fastest

of any energy sector, accounting for about

40 percent of the growth in primary energy

sources. Renewables are gaining share

within the energy mix more quickly than

has any other fuel seen in history.

Falling costs and, with that, increasing

competitiveness, are driving the growth in

renewable energy. In addition to continu-

ing improvements in technology, there is

strong government support for renewable

use. And as the use of renewables grows,

production improves and costs fall, leading

to faster growth. The result, by 2040, will

likely be the most diversified fuel mix that

the world has ever seen, with oil, gas, coal

and non-fossil fuels each accounting for

about 25 percent of the total energy supply.

And with maintained or increased future

government support for renewables, the

penetration of renewables could go much

higher.

Carbon emissionsThe anticipated future of carbon emis-

sions varies considerably between differ-

ent energy transition scenarios. Under the

evolving transition scenario, with energy

evolution continuing along its current path,

carbon emissions will continue to rise,

albeit much more slowly than in the past.

To bring carbon emissions to the levels

required by the Paris agreement, there will

need to be a much more decisive break

from past energy habits, with the power

generation sector being particularly critical

to driving change — even a future com-

plete ban on internal combustion engine

cars would do little to move the carbon

dioxide pendulum, Dale commented.

BP Group CEO Bob Dudley, when

introducing the Energy Outlook, com-

mented that a “race to renewables” will not

meet the Paris goals. The focus, instead,

needs to be on lower emissions. What is

needed is a comprehensive approach

involving both efficiency in energy use

and a continuing lower carbon fuel mix, he

said.

Dale commented that, in his view, the

key to reducing carbon emissions is carbon

pricing. Placing a price on carbon emis-

sions provides an incentive for everyone,

both energy producers and energy con-

sumers, to play a role in the carbon emis-

sions aspects of the energy transition, he

said. l

continued from page 1

BP OUTLOOK

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907. 258.4704

application was filed, such as supplemen-

tal filings and responses to previous data

requests and requests based on recent

stakeholder comments.

“AGDC has already provided FERC

with the information the corporation

believes is necessary for the agency to

complete the draft EIS,” Jesse Carlstrom,

AGDC’s communications manager, told

Petroleum News in a Feb. 16 email.

“However,” he said, “AGDC is commit-

ted to working collaboratively with

FERC to address the agency’s concerns

and will provide a schedule for submit-

ting responses to their additional ques-

tions no later than March 7, 2018.”

As to how the additional FERC

requests will impact the schedule for per-

mitting the project, Carlstrom said:

“AGDC remains committed that FERC

will have the information the agency

needs to prepare the draft Environmental

Impact Statement in 2018. AGDC plans

to continue advancing the Alaska LNG

project and will respond to FERC’s

request for clarification.”

ClarificationWhat is FERC requesting?

“FERC is now requesting clarification

on previous responses and requesting

more detailed information normally pro-

continued from page 1

FERC QUESTIONS

see FERC QUESTIONS page 12

vided during the State of Alaska permit-

ting process,” Carlstrom said.

He said that “in earlier responses to

FERC, AGDC indicated it is unneces-

sary to provide these studies at this point

in the application because this detailed

information is normally provided during

the State of Alaska permitting process.”

FERC said AGDC had previously

stated “that because these studies are not

required by the state or other entities,

AGDC will not provide the informa-

tion,” but, the letter continues, “FERC’s

regulations implementing the National

Environmental Policy Act require appli-

cations filed under the Natural Gas Act

to include the information identified in”

federal regulations and “applicants must

conduct any studies or provide any

information that the Commission staff

considers necessary or relevant to deter-

mine the impact of the proposal on the

human environment and natural

resources.”

The letter went on to say that “any

response from AGDC that states, ‘the

information is not required by the state

or other agency and will not be provid-

ed’ will be considered incomplete and

reissued,” with incomplete responses

and reissuance of requests for informa-

tion affecting the schedule for complet-

ing environmental review for the proj-

ect.

FERC said it also “anticipates addi-

tional data requests on the safety, relia-

bility, and engineering design, including

questions regarding compliance” with

federal regulations of the U.S.

Department of Transportation and the

U.S. Coast Guard.

AlternativesThe Matanuska-Susitna Borough told

FERC in early January that AGDC had

not studied Port Mackenzie as an alter-

native, but instead studied another site.

FERC is now asking for “an environ-

mental and engineering analysis of the

site” identified by the borough, and the

pipeline route to that site, including

specified information so that FERC “can

conduct a quantitative comparison

between AGDC’s proposed and alterna-

tive liquefaction sites,” including size in

acres; availability for purchase or long-

term lease; requirement for any addition-

al stabilization; any additional utility or

road infrastructure that would be

required; effects on waterway conges-

tion and safety; effects on commercial

and recreational use of waters; dredge

volumes necessary; marine mammal or

other species associated with the site;

effects on residential occupation or use

of areas; mainline pipeline length; num-

ber of waterbodies crossed by modified

mainline; National Wetland Inventory

mapped wetlands crossed by modified

mainline; compression requirement in

horsepower; and waters of the United

States within the site.

AGDC is also asking for “documen-

tation of recent consultation with the

Matanuska-Susitna Borough to support

the analysis.”

FERC also wants AGDC to revisit

Valdez as a site for the liquefaction facil-

ity, noting that the 1988 final EIA for the

Trans-Alaska Gas System found the

pipeline route to Valdez preferable to the

route to Cook Inlet.

FERC said AGDC indicated that

because the Delta and Gulkana rivers

were designated as Wild and Scenic

Rivers in 1980, that the Valdez route was

precluded.

FERC disagreed, saying the TAGS

final EIS evaluated the Wild and Scenic

Rivers issue and concluded the route

would not cross the portion of those

rivers designated as wild and scenic and

directed AGDC to provide a routing

analysis avoiding the designated por-

tions of the Delta and Gulkana rivers. As

with Port Mackenzie, FERC provided a

list of information required for a quanti-

tative comparison: length of pipeline;

length adjacent to existing rights of way;

gravel requirements; forestland crossed;

discontinuous permafrost; wetlands

crossed; waterbodies crossed; and water-

body crossings more than 100 feet in

length.

FERC is also requiring more informa-

tion on the Denali National Park and

Preserve preferred alternative alignment.

The agency said AGDC told it additional

field survey costs were not warranted.

The agency did not address the cost

factor directly but said: “FERC uses

three criteria when evaluating an alterna-

tive: whether or not it meets the project

objective, whether it is technically and

economically feasible, and whether it

offers a significant environment advan-

tage over the proposed route.”

FERC also inquired if a route alterna-

tive identified by the Knik Tribe in 2015

was still applicable and practicable,

directed AGDC to coordinate with the

tribe to see if their concerns had been

addressed and if not, “provide an engi-

neering and environmental analysis of

the alternative route identified by the

Knik Tribe to address their concerns.” l

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The unit currently has three leases

but will soon have four as the company

has signed an agreement with

ConocoPhillips and its partners, owner

of the fourth lease, and are awaiting

lease transfer by the state. The Hemi

Springs State No. 1 well, drilled by

ARCO in 1984 in that fourth lease, was

certified as capable of producing hydro-

carbons in payable quantities from the

Kuparuk C. And, although Alliance’s

well will target the Kuparuk C and

Ivishak, oil shows have been demon-

strated in the West Sak and Ugnu across

the region, Division of Oil and Gas

documents say.

In other division filings Alliance said

the ARCO well was not drilled in the

“most optimum location for Kuparuk C

pay production.” That well also pene-

trated the Ivishak and found a thick pay

section. (Ivishak is the main Prudhoe

formation.)

Depending on the results from their

first exploration well, Alliance may

drill a second well the following year

targeting a structural high in the

Ivishak, bounded by a fault.

NAPE was “pretty encouraging for

our play. … (We think we have) “a

good chance of getting a partner,”

Derek said.

“People have more interest in Alaska

right now because … there’s a lot of oil

left behind up here, whereas in the

Lower 48 there are a lot of frack plays

but not the major plays you can get on

the North Slope.”

Jim White, Alaska legendAlthough geologist Robert Blodgett

who strongly endorses the promising

Donkel-Cade Stinson project near

ANWR on the Eastern North Slope is

probably a close second in terms of

being interesting and knowledgeable,

wildcatter Jim White of Alaskan Crude

takes the prize.

White, who drilled his first wildcat in

Alaska in 1977, attended the NAPE

summit and actively promoted Alaska’s

missed opportunities in both the Cook

Inlet basin and the North Slope.

White would like to see a lot of

Alaskans get rich from oil operations: “I

think it’s time Alaska had a cottage oil

industry and its runs by Alaskans. My

pet peeve — the U.S. government want-

ed to get Alaska more settled, wanted

more people, so the deal years ago was

if you proved up on your homestead you

got the mineral rights to it. In 1959, the

new state government had a different

attitude. The state came back and hung

outrageous bonding requirements on our

homestead acreage if we wanted to drill

for oil or gas.”

“We probably own more oil and gas

mineral rights than any person or com-

pany in the state.”

White said he and his son (also Jim,

but with a different middle name, so not

Jim Jr.) have about 4,600 acres in the

state.

NAPE attendees, he said, were a lot

more receptive this year than I have seen

them in a very long time.”

—KAY CASHMAN

continued from page 10

INSIDERcontinued from page 11

FERC QUESTIONS