ProducersProducersThe

Oil & gas companies investing in Alask ’ f t

Oil & gas companies investing in Alaska’ f t

HEX gets to work at Kitchen Lights after $5M bankruptcy acquisition

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

l U T I L I T I E S

Vol. 25, No. 45 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of November 8, 2020 • $2.50

see JADE FILING page 11

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

ML&P purchase closes Chugach Electric completes purchase to become single Anchorage electric utility

By ALAN BAILEY For Petroleum News

On Oct. 30 Chugach Electric Association

announced that it had closed its acquisition of

Anchorage based Municipal Light & Power. As a

consequence there is now one rather than two electric

utilities serving residents and businesses in

Anchorage. The concept behind the takeover is the

minimization of the cost of electricity through

economies of scale, the elimination of duplicated

business functions and the optimum use of the most

efficient power generation capacity. Chugach Electric

is a member owned cooperative, regulated by the

Regulatory Commission of Alaska.

Chugach Electric said that the combined opera-

tions for the consolidated utility would begin on Nov.

4, at which point erstwhile ML&P customers would

be invited to become Chugach Electric members.

A complex deal Although simple in principle, the specifics of

achieving the deal proved extremely complicated,

requiring years of negotiation and a very lengthy

Regulatory Commission of Alaska review. In

Lasting COVID impact Rystad sees peak demand in 2028; oil benchmarks rise on election week

By STEVE SUTHERLIN Petroleum News

The COVID-19 pandemic — together with the

acceleration of the energy transition — will

have a lasting impact on global oil demand,

according to Rystad Energy.

In a Nov. 2 release, Rystad significantly revised

its long-term oil demand forecast, which it now

sees peaking at 102 million barrels per day in

2028, versus its previous call for peak oil demand

of just over 106 million bpd in 2030.

The consultancy said its new forecast assumes a

scenario under which “the share of oil in various

sectors develops in line with stated government

goals to move towards a cleaner carbon future,

notably in the electrification of transport.”

Rystad said the persistence of the pandemic is

likely to cause 2020 oil demand to decline to 89.3

million bpd, compared to 99.6 million bpd in 2019,

adding that it expects demand to recover to 94.8

million bpd in 2021, capped by regional lock-

downs and slow international aviation recovery.

Under the scenario, demand recovers to 98.4

million bpd in 2022, still retarded by structural

COVID-19 impacts such as less commuting and

slower aviation recovery, Rystad said, adding that

it expects 2023 that demand to exceed pre-

COVID-19 levels of 100.1 million bpd.

“The slow recovery will permanently affect glob-

al oil demand levels, shaving at least 2.5 million bpd

off our forecasts made before the coronavirus” said

Paying for a takeover Cenovus says Husky acquisition will cost 2,150 jobs, 25% of combined payroll

By GARY PARK For Petroleum News

Every shred of apparent good news from the

Canadian oil patch also comes at a stiff

human cost.

Those struggling to stem the outflow of jobs

enjoyed a fleeting moment of success on Oct. 26

when Suncor Energy announced it will move two

offices from Ontario back to their Calgary home

base in 2021 — a possible gain of 700 people.

No sooner was that development being wel-

comed by Calgary Mayor Naheed Nenshi and Mary

Moran, chief executive officer of Calgary Economic

Development, than a harsh setback was delivered.

Cenovus Energy disclosed that 25%, or 2,150

employees of the combined workforce from its

freshly announced takeover of Husky Energy,

would soon find themselves on the street.

Most job losses in Calgary The two companies confirmed that most of the

see ML&P PURCHASE page 10

see OIL PRICES page 8

see CENOVUS TAKEOVER page 7

Furie/HEX joins Inlet operators asking for AOGCC bonding relief

The Alaska Oil and Gas Conservation Commission took

public comments Nov. 4 on proposed changes to its bonding

regulations but only Furie Operating Alaska/HEX comment-

ed, briefly at the hearing, but primarily in a Nov. 2 letter from

its Chief Operating Officer Rick Dusenbery.

Furie/HEX is the operator at the Kitchen Lights unit in

Cook Inlet where 10 wells have been drilled, of which three

are plugged and abandoned, three are suspended and four are

producing.

The proposed changes (see story in Oct. 25 issue of

Petroleum News) include reduction in overall bonding for

fewer than 40 wells — although the amount for one to five

Jade files PTU Area F POD; Corps issues preliminary dredging permit

In coordination with ExxonMobil,

operator of the Point Thomson unit, and

other PTU lease owners, on Nov. 1 Jade

Energy LLC filed its third plan of devel-

opment for ADL 343112’s Area F, Tract

32, with Alaska’s Division of Oil and

Gas. Tract 32 contains BP’s mid-1990s

Sourdough oil discovery where Jade

plans to drill an appraisal well in first

quarter 2022.

Mobilization of a drilling rig and

heavy equipment is one of the more challenging elements of

Jade’s plans. Most drilling programs on the North Slope

Division approves Alkaid unit; Great Bear plans drilling in 2021

The Alaska Department of Natural Resources’ Division of Oil

and Gas has approved an application from Great Bear Petroleum

Ventures for formation of the Alkaid unit.

The company applied for unit formation in August (see

story in Sept. 13 issue of Petroleum News). The approval is

dated Nov. 2.

There are four state oil and gas leases in Alkaid, a total of

22,804 acres, along the trans-Alaska oil pipeline on the central

North Slope some 13 miles south of the Prudhoe Bay unit.

The division said Alkaid has been part of scattered exploration

efforts since the 1960s, and remains lightly explored, with no

wells drilled in the unit area prior to 2012 when Great Bear began

a drilling program to evaluate unconventional resources in the

Nova Gas line to northwestern Alberta OK’d but only after delays

Without much fanfare, the Canadian

government delivered victory to a full

array of participants and customers when

it approved a natural gas pipeline exten-

sion in northwestern Alberta.

The C$2.3 billion project by Nova

Gas Transmission Ltd., NGTL, a wholly

owned unit of TC Energy, will add 215

miles of new pipeline from west of Red

Deer to Grande Prairie, creating 5,500

construction jobs for Indigenous and

non-Indigenous workers, and carrying 3.5 billion cubic feet

per day to residential consumers, power producers who are

see ALKAID UNIT page 10

see BONDING RELIEF page 9

see NOVA GAS page 4

Although simple in principle, the specifics of achieving the deal proved extremely

complicated, requiring years of negotiation and a very lengthy

Regulatory Commission of Alaska review.

In a recent report, Scotia Capital analyst Jason Bouvier said divestiture of oil sands

assets and a drive to build scale will underpin a wave of domestic takeovers.

ERIK OPSTAD

SONYA SAVAGE

2 PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020

Petroleum News Alaska’s source for oil and gas newscontents

Alaska’sOil and GasConsultants

GeoscienceEngineeringProject ManagementSeismic and Well Data

3601 C Street, Suite 1424Anchorage, AK 99503

(907) 272-1232(907) 272-1344

www.petroak.cominfo@petroak.com

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

Division approves 47th Nicolai Creek POD By KRISTEN NELSON

Petroleum News

The Alaska Department of Natural Resources’

Division of Oil and Gas has approved the 47th plan

of development for the Nicolai Creek unit submitted in

September by Amaroq Resource LLC, the Nicolai Creek

operator and 100% working interest owner.

Nicolai Creek is a small gas field on the west side of

Cook Inlet.

The division approved the new POD, which covers

Dec. 29, 2020, through Dec. 28, 2021, but is requiring a

status report within 30 days before June 15 to update the

division on the status of injection operations at the NCU

No. 1B well and implications of Alaska Oil and Gas

Conservation Commission “orders regarding bond relief,

if any, to the future economic viability of the NCU.”

Amaroq intends to place the NCU No. 1B online as a

saltwater disposal well, the division said, and possibly

bring NCU No. 10 back online if the target injection

capacity at NCU No. 1B is achieved.

During the 46th POD, Amaroq received AOGCC

approval to convert the NCU No. 1B to injection, but fur-

ther surface equipment was required, the division said.

In its September 47th POD submittal, Amaroq told

the division that NCU No. 1B “was deemed ready for

injection of produced water in mid-June. Installation of

permanent surface injection facilities are in progress.”

The company said the NBC No. 10 remains shut-in until

the permanent water disposal facilities at NCU No. 1B

are complete.

Bonding issue On the AOGCC bonding issue, Amaroq has

appealed the commission’s $2.4 million bond require-

ment for plugging and abandonment of the six wells

Amaroq operates at Nicolai Creek. The commission

had not yet issued a decision on Amaroq’s appeal when

this issue of Petroleum News went to press, but is hold-

ing a Nov. 4 hearing (see story in this issue) on pro-

posed bonding changes which would reduce the

requirement from $400,000 each for one to 10 wells

($2.4 million for Amaroq’s six wells) to $400,000 each

for one to five wells, and for six to 20 wells, $2 million

plus $250,000 for each well above five, bringing

Amaroq’s total down by $150,000 to $2.25 million (see

story on proposed bonding changes in Oct. 25 issue of

Petroleum News).

In its September POD application, Amaroq said

long-range plans for Nicolai Creek depend on the oper-

ator’s ability to attract additional capital but listed the

first impact on its long-range plans as outcome of its

motion to AOGCC for reconsideration.

“If the operator is required to post a $2.4 million

bond with AOGCC pursuant to the newly established

requirements,” Amaroq told the division, “the field

immediately becomes uneconomic and is likely des-

tined for cessation of operations.” l

The division approved the new POD, which covers Dec. 29, 2020, through Dec. 28, 2021, but is requiring a status report within 30 days

before June 15 to update the division on the status of injection operations at the NCU No.

1B well and implications of Alaska Oil and Gas Conservation Commission “orders regarding

bond relief, if any, to the future economic viability of the NCU.”

ML&P purchase closes Chugach Electric completes deal to become single electric utility

Lasting COVID impact Rystad sees peak demand in ’28; benchmarks rise on election week

Paying for a takeover Cenovus: Husky acquisition will cost jobs, 25% of combined payroll

ON THE COVER

Jade files PTU Area F POD; Corps issues preliminary dredging permit

Division approves Alkaid unit; Great Bear plans drilling in 2021Furie/HEX joins Inlet operators asking for AOGCC bonding reliefNova Gas line to northwestern Alberta OK’d but only after delays

EXPLORATION & PRODUCTION2 Division approves 47th Nicolai Creek POD

3 Yukon Flats, Copper River data available

4 US rotary drilling rig count 296, up by 9

4 Cosmopolitan unit 2021 POD approved

5 Oil Search files second Pikka unit POD

Civil works program now underway; goal to enter FEED next year, positioning for project sanctioning in late 2021 or early 2022

3 ConocoPhillips budget flat in 2021

3rd quarter earnings down; Alaska one of firm’s 3 growth areas in world; if ballot measure passes Willow timing could change

6 HEX getting to work at Kitchen Lights

$5M acquisition came from Furie bankruptcy proceedings; John Hendrix taking pragmatic approach at Cook Inlet property

FINANCE & ECONOMY

PRODUCERS PREVIEW

To advertise: Contact Susan Crane

at 907.250.9769

PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020 3

229-6000

By KAY CASHMAN Petroleum News

As reported in the Oct. 29 Petroleum

News bulletin, in its third quarter

earnings report and conference call

ConocoPhillips listed the North Slope as

one of its three growth areas in the world

along with Norway and Malaysia.

In Alaska ConocoPhillips reported a

net loss of $16 million in third quarter,

with the company incurring an estimated

$136 million payable to the State of

Alaska in the form of production taxes,

royalties, property taxes and state

income tax.

Year to date ConocoPhillips had an

unadjusted net loss of $76 million in

Alaska. Its estimated obligations to the

State of Alaska (in the form of taxes and

royalties) in third quarter totaled $442

million, plus the company invested $882

million in North Slope capital projects;

hence the net loss for Alaska operations.

If Ballot Measure 1 passes, it will

impose a 150-300% tax increase on North

Slope oil production (difference based on

the price of oil), reducing the competitive-

ness of Alaska.

“We have years of development oppor-

tunities left in Alaska, but a shift of capital

from Alaska elsewhere is going to be

rational, if taxes increase,” Matt Fox,

ConocoPhillips executive vice president

and COO, said during the third quarter

conference call. “I mean this is a produc-

tion tax. And what you tax more, you get

less of.”

ConocoPhillips is moving forward

with the Willow project, but that “assumes

taxes will not increase,” Fox said. “If it

passes, we might want to reconsider the

timing.”

He also said that the Willow project

recently “passed a milestone. We got a

Record of Decision from the BLM after

more than two years of process. So that’s

keeping us on track with the project time-

line,” Fox said, noting “it’s important to

understand that the permit was received

under the 2013 activity plan for the

National Petroleum Reserve — those are

rules that were set under the Obama

administration so they should stand up

well to scrutiny if a change in the admin-

istration occurs.”

Fox also addressed the impact on fed-

eral land and permitting in Alaska should

a change in D.C. occur: “If there’s a

change in administration, we would

expect that to have a relatively limited

impact on us (in Alaska). I mean … feder-

al land only represents about 5% of our

production. Now some coming produc-

tion, GMT 2, in particular, is on federal

land, but it’s still underway. First produc-

tion will be at the end of next year. So, we

don’t expect that it will be affected at all.

Willow’s on federal land, of course … but

neither Willow or GMT 1 or GMT 2, the

federal land drill sites, is anything other

than conventional for stimulation tech-

niques. So, if this is about fracking there,

they shouldn’t be influenced by that.”

Sell down postponed During the Q&A portion of the Oct. 29

conference call, Jeanine Wai of Barclays

asked whether ConocoPhillips’ 25% sell

down of its Alaska position was still in the

works and whether the company’s final

investment decision on Willow develop-

ment was reliant on the sell down.

“We didn’t explicitly tie a Willow deci-

sion to a sell down,” Fox replied. “We

have postponed the timing of that until

some of these uncertainties are resolved,”

he said, referring to oil price and demand,

as well as Ballot Measure 1, but whatever

happens “the timing of the project isn’t

contingent on a sell down.”

2021 CapEx flat In Chairman and CEO Ryan Lance’s

prepared remarks at the beginning of the

conference call he said ConocoPhillips’

2021 capital budget will probably be sim-

ilar to that of 2020, with little to no pro-

duction growth.

“But is the right way generally to think

about it … (with a) mid-$40s threshold …

for production growth?” Wai asked Ryan.

“(Is it) a hard and fast criteria that needs to

be met? Or are there just a bunch of other

considerations that we would need to fac-

tor into the decision-making process?”

“Yes … we basically use cost of sup-

ply(in) … thinking about our plans for

2021,” Lance replied.

“But it’s not just cost of supply … it’s

also what kind of cash flow are we pro-

jecting to make. And we have the benefit

of a very strong balance sheet, so we can

use some of that, should we need to. But,

certainly, we’d be also trying to balance

the cash we’re making with the CapEx

that we’re spending on the dividend that

today satisfies 30% of our return criteria

and more, given the kinds of prices that

we’re seeing,” he added.

“So, certainly, (there are) some head-

winds in the commodity price outlook

right now, some with COVID resurgence

… demand certainly hasn’t started to

recover. And depending on what NOPEC

or OPEC does on the supply side and what

the U.S. response is, we’re watching all of

that really closely to make sure that what-

ever program we put in place for 2021, we

can balance with the cash flows that we

expect and make sure that we’re investing

only in the lowest cost of supply things

that we have in the portfolio,” Lance said.

Biden’s tax plan Doug Leggate with Bank of America

asked for additional details on Lance’s

comments around the potential election

outcomes: “And I’m thinking specifically

about tax. … The thing that strikes me as

a little bit disturbing is the potential for a

minimum 15% P&L tax that puts NOLs

(net operating loss) under a bit of a spot-

light. So, I’m just wondering if you guys

have thought about … any scenarios that

you’ve run outcomes on that you might

expect?”

“Yes. Sure,” Lance replied. “We’ve

certainly taken a look at the various tax

proposals out there, including Biden’s tax

proposal. There are two primary elements

of it that would impact us. Doug, the first

one is, obviously, the change in the corpo-

rate tax rate from 21% to 28%.

“And the second one that would be

fairly significant would be removal of

IDCs (intangible drilling costs), particu-

larly in our capital program and needing

to depreciate those over time,” Lance said.

“Those are the two main aspects as we

look through it that really would have an

impact on us.” l

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

ConocoPhillips budget flat in 2021 3rd quarter earnings down; Alaska one of firm’s 3 growth areas in world; if ballot measure passes Willow timing could change

EXPLORATION & PRODUCTIONYukon Flats, Copper River data available

The Alaska Department of Natural Resources’ Division of Oil and Gas said

Oct. 28 that it will make two sets of exploration seismic and well data available

within 30 days: Yukon Flats 2D seismic permitted by Doyon Ltd. and Tolsona 1

well data from Tolsona Oil and Gas Exploration.

The Yukon Flats seismic is in the Fairbanks Meridian, township 17 north,

ranges 6-8 west; townships 15-16 north, ranges 5-8 west; and township 14 north,

ranges 6-8 west.

The Tolsona 1 well is API number 50-099-20006-0000, in the Copper River

Meridian, township 4 north, range 4 west, section 23.

The notice and maps are available on the division’s website at:

https://dog.dnr.alaska.gov/Newsroom/.

—PETROLEUM NEWS

981.278.2771

RYAN LANCE MATT FOX

4 PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020

ADDRESS P.O. Box 231647 Anchorage, AK 99523-1647 NEWS 907.522.9469 publisher@petroleumnews.com CIRCULATION 907.522.9469 circulation@petroleumnews.com ADVERTISING Susan Crane • 907.770.5592 scrane@petroleumnews.com

OWNER: Petroleum Newspapers of Alaska LLC (PNA) Petroleum News (ISSN 1544-3612) • Vol. 25, No. 45 • Week of November 8, 2020

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

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Petroleum News and its supplement, Petroleum Directory, are owned by Petroleum Newspapers of Alaska LLC. The newspaper is published weekly. Several of the individuals

listed above work for independent companies that contract services to Petroleum Newspapers of Alaska

LLC or are freelance writers.

Kay Cashman PUBLISHER & FOUNDER

Mary Mack CEO & GENERAL MANAGER

Kristen Nelson EDITOR-IN-CHIEF

Susan Crane ADVERTISING DIRECTOR

Heather Yates BOOKKEEPER

Marti Reeve SPECIAL PUBLICATIONS DIRECTOR

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Alan Bailey CONTRIBUTING WRITER

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Renee Garbutt CIRCULATION MANAGER

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CORRECTIONDate not set for BLM NPR-A sale

In the Nov. 1 issue, Petroleum News incorrectly reported that the Bureau of

Land Management would hold its National Petroleum Reserve-Alaska lease sale

in January.

BLM has not yet set a date for the sale. What the agency has said is that deci-

sion on a sale date is expected by the end of the year.

EXPLORATION & PRODUCTIONUS rotary drilling rig count 296, up by 9

The Baker Hughes U.S. rotary rig count was at 296 for the week ending Oct. 30, up

by nine rigs from 287 the previous week, continuing an increase that began in mid-

August. The count is still down substantially from a year ago, by 526 from 822.

When the count hit 244 the week of Aug. 14, it was not just the low for 2020, but

the lowest it has been since the Houston based oilfield services company began issuing

a weekly U.S. rig count in 1944.

Prior to this year, the low was 404 rigs in May 2016. The count peaked at 4,530 in

1981.

At the beginning of the year the count was in the low 790s, where it remained

through mid-March, when it began to fall, dropping below what had been the historic

low in early May with a count of 374 and continuing to drop through the third week of

August when it gained back 10 rigs.

This week’s count includes 221 rigs targeting oil, up 10 from the previous week and

down 470 from a year ago, 72 rigs targeting gas, down one from the previous week and

down 58 from a year ago and three miscellaneous rigs, unchanged from the previous

week and up two from a year ago.

Twenty-two of the holes were directional, 254 were horizontal and 20 were vertical.

Alaska count unchanged The rig count for Texas (133), which has the most active rigs in the country, was up

by eight from the previous week, but down 283 from a year ago.

New Mexico (47) was up by two rigs.

Oklahoma (14) was down by a single rig from the previous week.

Rig counts were unchanged in the remaining states: Alaska (3), California (4),

Colorado (4), Louisiana (37), North Dakota (11), Ohio (6), Pennsylvania (18), Utah (3),

West Virginia (8) and Wyoming (3).

Baker Hughes shows Alaska with three active rigs Oct. 30, unchanged from the pre-

vious week and down by four from a year ago.

The rig count in the Permian, the most active basin in the country, was up by nine

from the previous week at 142, but down 274 from a count of 417 a year ago.

—KRISTEN NELSON

EXPLORATION & PRODUCTIONCosmopolitan unit 2021 POD approved

The Alaska Department of Natural Resources, Division of Oil and Gas

approved the BlueCrest Alaska Operating LLC 2021 Cosmopolitan unit plan of

development, according to an Oct. 21 letter issued by the division.

In its 2021 POD, BlueCrest plans to maintain production through well mainte-

nance, continue planning for future development and resume drilling during the

2021 POD period if oil markets improve, the division noted.

In its 2020 POD, the company had listed plans to drill one or two Trident mul-

tilateral wells, however no new wells were drilled because of the Covid-19 pan-

demic and collapse in oil markets, the division said, adding that production was

maintained, and planning for future development continued.

The division said that plans set forth in the 2021 POD protect the public inter-

est in diligent development of state resources, by maintaining production with the

possibility of increased production if oil markets support further expenditures.

“The 2021 POD therefore is necessary and advisable to protect the public inter-

est,” the division said, adding, “Due to current conditions, and in keeping with the

State’s recognition of other operator’s actions under similar conditions, the

drilling of additional wells at this time would be imprudent and not in the best

interest of all parties.”

The division said that “unique circumstances at this time” heavily influenced

its decision.

“Approval of a plan of development without firm drilling commitments at this

time is not a guarantee future similar plans will be approved,” it said.

—STEVE SUTHERLIN

switching from coal to gas-fired plants

and petrochemical companies relying on

gas for their feedstock.

The project, a key component of

NGTL’s C$9.9 billion infrastructure pro-

gram, also gives a badly needed lift to gas

producers who have been struggling to

build their markets.

Full summer of delay The only source of grumbling came

from the Alberta government, which con-

demned federal delays that cost a full

summer construction season.

“Despite months of delay, we are

pleased the federal government has

approved this key project, which will cre-

ate significant economic benefits and

good jobs ... at a time they are needed the

most,” said Alberta Energy Minister

Sonya Savage.

She said the bulk of construction is

“not expected to get underway until

2021.” The scheduled in-service date

ranges from 2021 to 2022.

The approval came with 35 conditions,

notably the restoration of 9,500 acres of

caribou habitat, an area 30 times the size

of the habitat affected by the pipeline.

Not the final word? But pro-pipeline factions know that

approvals from the highest level of gov-

ernment and courts are seldom the final

word for pipeline projects.

After a quiet period during the past

eight months of a ban on protests at ener-

gy construction sites under COVID-19

regulations there was a brief flare-up at

the long-delayed Trans Mountain crude

bitumen pipeline expansion from Alberta

to Vancouver.

It resulted in arrests of nine people

attempting to stop work in defiance of a

court injunction and claiming to repre-

sent the will of Tk’emlups te Secwempec

First Nation, which has a C$3 million

mutual benefits agreement with Trans

Mountain.

Tk’emlups Chief Rosanne Casimir

said First Nation elders and members

were not part of the protest.

“The area Trans Mountain is working

in is our area of responsibility. No one

else has the right to speak on our behalf,”

she said.

But the opposition reinforced the view

that serious resistance lies ahead for

Trans Mountain as pipeline work moves

into the Greater Vancouver region.

—GARY PARK

continued from page 1

NOVA GASBut pro-pipeline factions know that approvals from the highest level of government and courts are seldom the final word for

pipeline projects.

By KRISTEN NELSON Petroleum News

Oil Search, as operator at Pikka, has

filed the second plan of develop-

ment for the unit, including proposed

operations for the 2021-22 period begin-

ning Feb. 1, 2021, through Jan. 31, 2022.

A 2014 application for a unit at Pikka,

on the North Slope between the Kuparuk

River and Colville River units, was

approved by the Alaska Department of

Natural Resources’ Division of Oil and

Gas in 2015. Earlier this year, the Pikka

unit agreement term was extended to

June 1, 2025.

Completed activities The company listed activities com-

pleted under the first, 2020 POD for the

unit, and the POD for the upcoming year.

The 2020 POD described planned

activities “focused on the first year of a

planned two-year civil construction pro-

gram to build roads, ridges and pads

from currently existing infrastructure to

drill sites” in the Pikka unit, Oil Search

said.

Winter 2019-20 activities included ice

road construction to support gravel lay-

ing and mine site work.

Gravel placement was done for the

Nanushuk access road, the Nanushuk

Operations pad, the Nanushuk Process

Facility pad, the ND-B access road and

pad, an access road and pad for water

access to a lake and initial upgrades to

the Mustang Road.

A bridge was installed across the

Miluveach River and there was culvert

installation.

Work over this past summer included:

summer rework of gravel placed over the

winter, place of slope protection geotex-

tile, gravel bags and rip-rap material; and

additional Mustang Road upgrades.

Oil Search said it “continues to

advance facility engineering and design

and contract negotiations for PKU devel-

opment.” The Pikka B and C wells

allowed further appraisal of the Nanushuk

reservoir for FEED, front-end engineering

and design, the company said, “and will

inform the subsurface basis of design for

planning of development wells and pro-

duction infrastructure.”

Phased approach As previously reported in Petroleum

News, in response to COVID-19 and the

associated drop in oil prices the working

interest owners are moving toward a

phased approach “to reduce capital outlay

and improve project resilience by lowering

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

Oil Search files second Pikka unit POD Civil works program now underway; goal to enter FEED next year, positioning for project sanctioning in late 2021 or early 2022

PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020 5

WHATEVER

WHENEVER

WHEREVER

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907. 258.4704

see PIKKA UNIT page 7

By ERIC LIDJI For Petroleum News

HEX Cook Inlet LLC became the

newest operator in Alaska this sum-

mer when it closed on a deal to acquire

the assets of Furie Operating Alaska LLC

and related companies.

The $5 million acquisition was the cul-

mination of the intense bankruptcy pro-

ceedings of Furie and its partners

Cornucopia Oil & Gas Company LLC

and Corsair Oil &

Gas LLC.

The centerpiece

of the purchase is

the offshore Kitchen

Lights unit, which is

largest unit in Cook

Inlet by area and

which has been seen

as a source of

growth for the basin.

HEX Cook Inlet

LLC is a joint venture between HEX LLC

(80%) and Rogue Wave AK LLC (20%)

founded by longtime Alaska oil industry

player John Hendrix.

A native of Alaska with a long history

in the region, Hendrix has stated his

desire to hire locally. His company quick-

ly switched suppliers to Udelhoven

Oilfield System Services.

Fixing what it bought HEX is acquiring an underperforming

unit with considerable potential.

The Kitchen Lights unit

includes three previously dis-

tinct prospects that were unit-

ized and then administratively

divided into four exploration

blocks: Corsair, North, Central

and Southwest. All develop-

ment activities to date have

occurred within the Corsair

block.

Furie brought the unit into

production from the KLU 3 well in July

2013 and subsequently drilled three more

wells — the KLU A-1 well between 2016

and 2018, the KLU A-2A well in

September 2016, and the KLU A-4 well

in October 2018. The development work

involved construction of the new Julius R

platform in Cook Inlet.

By the time HEX arrived as the new

operator earlier this year, one of those

wells was offline, awaiting upgrades and

repairs. And the three producing wells

were underperforming. The Kitchen

Lights unit is currently producing around

13 million cubic feet per day, down from

approximately 18 million cubic feet from

a year earlier.

In one of its most immediate plans for

the unit, HEX is eager to have all four

existing wells produce from both the

Beluga and the Sterling formations. As a

first step toward that goal, the company is

applying for a produced water permit

from the state, which would allow it to

better handle waterlogged gas production

from the Sterling formation.

Improved water handling

would allow the company to

bring the offline well back

online and would reduce the

likelihood of prior technical

challenges recurring at the unit.

It would also allow the com-

pany to add Sterling perfora-

tions to the three existing wells

that are producing from the

Beluga formation, thereby

increasing overall production.

By late summer, HEX was still await-

ing the permit but had attempted repairs

on the KLU A-4 well. There were two

wireline fish and a tubing plug complicat-

ing operations.

“We made attempts to fish A-4 and

learned a lot about it,” Hendrix told

Petroleum News in mid-August. “Prior to

going to the next phase, we went ahead

and punched the tubing to ensure produc-

tion in case future fishing jobs prevented

access. A-4 is currently producing about

2.0 MMCFPD. We now have several

options in front of us.”

History and future growth Although HEX is currently focused on

maintaining existing assets, the Kitchen

Lights unit also contains significant

growth potential, whenever the time

comes.

Following a series of battles over work

commitments involving several smaller

players in Cook Inlet, the state formed the

83,394-acre unit in 2009 to prevent a

legal battle and encourage exploration

and development activities at a time of

dwindling local supplies.

The unit combined the Escopeta Oil &

Gas Co.-operated Kitchen unit, the

Renaissance Alaska LLC-operated

Northern Lights prospect and the Pacific

Energy Resources Ltd.-operated Corsair

prospect. A corporate shuffle in 2011 put

Furie in charge of the project.

Early plans of exploration for Kitchen

Lights established four exploration

blocks and required Furie to drill at least

one well in each block. The company

drilled exploration wells across the unit

between 2011 and 2014 before shifting to

development, leaving the North and

Central blocks underexplored and the

Southwest block undrilled, as of yet.

Beyond those aerial possibilities, the

unit is also thought to contain deep

resources. In previous plans, Furie pro-

posed wells below 20,000 feet to look for

deep Jurassic oil.

During the tenure of Furie and its

predecessors, the Kitchen Lights unit was

a perennial source of drama. After bring-

ing a jack-up rig to Alaska to drill the

prospect, the company was hit with a $15

million fine for violating the federal

Jones Act, the largest fine ever levied for

a violation of the federal law governing

domestic and foreign naval vessels.

Furie publicly criticized the state and

unilaterally suspended some operations in

the 2017 open water season following a

dispute with the state over oil and gas tax

credits.

The company regularly proposed

major exploration and development cam-

paigns for the unit, although it only made

minimal progress toward those commit-

ments. The state even put the unit into

default in late 2017 for Furie’s failure to

meet work commitments.

The company faced technical chal-

lenges in early 2019 when frozen hydrate

plugs complicated natural gas shipments,

leading the company to declare a force

majeure event and requiring Enstar

Natural Gas Co. to revise gas sales agree-

ments for the unit. l

Editor’s note: See this story in The Producers magazine, being released in the Nov. 22, 2020 edition of Petroleum News.

l T H E P R O D U C E R S M A G A Z I N E P R E V I E W

HEX getting to work at Kitchen Lights $5M acquisition came from Furie bankruptcy proceedings; John Hendrix taking pragmatic approach at Cook Inlet property

6 PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020

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job losses will occur in Calgary, where the

unemployment level is a crippling 13%.

A Husky spokesperson Kim

Guttormson said that “as with any merger

of this type there will be overlap and

there will be some difficult decisions as

we work to create a combined organiza-

tion best positioned for the future.”

Cenovus Chief Executive Officer Alex

Pourbaix, whose company initiated the

C$3.8 billion friendly takeover (which

carries a value of C$23.6 billion), said the

transaction was viewed as necessary “to

ensure our companies and our sectors

remain strong. But there is no escaping

the impact that they have on some

extremely talented and dedicated people.”

No White Rose expansion Also facing the chopping block is

Husky’s planned C$2.2 billion expansion

of its White Rose oil field offshore

Newfoundland that had been designed to

add 75,000 barrels per day to offset the

field’s decline over the last 15 years to

26,000 bpd.

Guttormson told the Globe and Mail

that all options for White Rose are under

review, adding that “accelerating aban-

donment (of White Rose) remains a pos-

sibility.”

Pourbaix had earlier confirmed that

work on the White Rose expansion,

which was suspended in March when

Corvid-19 hammered oil prices, could set

the stage for a worst-case scenario of

scrapping the project and decommission-

ing the field over time.

Canada’s Natural Resources Minister

Seamus O’Regan said recently that his

government is working with Husky to

find ways to save the expansion but con-

ceded there is little prospect the solution

lies in a public equity stake.

Husky Chief Executive Officer Rob

Peabody described the White Rose under-

taking as a “spectacularly good project for

Newfoundland,” although he agreed the

financial viability is affected by the gen-

eral health of the energy industry.

Restructuring ‘unfortunate reality’ Alberta Energy Minister Sonya Savage

said the job restructuring from the

Cenovus-Husky deal is an “unfortunate

reality” and will be “opportunistically

seized on” by those who want to see

Canada’s energy sector shut down entirely.

“But projections show continued

global demand for fossil fuels well into

the future,” she said.

Savage said Alberta’s economic

recovery plan is focused on ensuring the

oil and gas sector is put in a strong posi-

tion, while the province concentrates on

diversifying its economy to create new

jobs.

Moran said her organization will con-

tinue to call for more training programs

to help laid-off energy workers find jobs

in other industries.

“We’re talking to all organizations

(with a presence in Calgary) to consider

expansion, whether it be banks or truck-

ing companies or financial services or

agriculture companies.”

Oil sands focus For now, attention is focused on what

lies in store for the oil sands in particular

as foreign players shred their stakes in

the resource to reduce their carbon emis-

sions.

The Canadian industry is seen as hav-

ing no choice but to follow the lead of

senior U.S. energy companies and buy

smaller rivals with shaky balance sheets.

Suncor Energy and Canadian Natural

Resources will be the oil sands players to

watch. They are expected to lead the way

in snapping up reserves unloaded by

European majors and concentrating on

meeting environmental challenges, while

decreasing their own greenhouse gas

emissions through technological

advances in developing, extracting and

refining fossil fuels in Alberta.

The two biggest producers from the

oil sands are already making headway in

capturing and storing carbon dioxide.

Analysts are forecasting that small-

and medium-sized Canadian companies

will start a round of mergers to reduce

their operating costs and bolster their bal-

ance sheets.

In a recent report, Scotia Capital ana-

lyst Jason Bouvier said divestiture of oil

sands assets and a drive to build scale

will underpin a wave of domestic

takeovers.

“We believe the acquirers should be

able to drive value via a good purchase

price followed by real cost synergies,” he

wrote.

One of the prime targets is Chinese-

owned MEG Energy, which fended off a

hostile C$3.3 billion takeover offer by

Husky in 2018. The cost of that strategy is

now painfully obvious, with MEG’s mar-

ket capitalization having tumbled to C$720

million and its debt at C$3 billion. l

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Better.

breakeven costs,” Oil Search said in the

Pikka POD.

Phase 1 will be a single drill site,

ND-B, and associated pipelines and

production infrastructure.

Oil Search said “key forward devel-

opment activities subject to satisfactory

commercial terms and economic condi-

tions include completion of pre-FEED

activities and entry into FEED on the

proposed Project in 2021,” positioning

the project for sanction in late 2021 or

early 2022.

Detail engineering and supply chain

activities would begin after project

sanction with development drilling

scheduled to begin in 2022 from the

ND-B development pad, “initially tar-

geting the Nanushuk reservoir,” the

company said.

Processing facilities and additional

pipeline construction would occur in

parallel, with field production targeted

for 2025.

Development infrastructure Oil Search said development infra-

structure, “including future phases,”

includes: Nanushuk Processing Facility,

including power generation for project

facilities; Nanushuk Operation Pad,

including the main camp; ND-B devel-

opment pad, accommodating drilling

equipment and support facilities for

drilling and completion — and other

future development drill sites; infield

pipelines and cables from the process-

ing facility and drill site; pipelines and

cables, including import and export

pipelines; other civil infrastructure; and

the Seawater Treatment Plant which

will be constructed at Oliktok Point to

deliver water for enhanced recovery.

Oil Search said a participating area

has not yet been established but an

application for an initial Nanushuk PA

will be submitted prior to beginning of

regular production. l

continued from page 5

PIKKA UNIT

continued from page 1

CENOVUS TAKEOVER

Artyom Tchen, Rystad senior oil markets

analyst. “The lockdowns will stunt eco-

nomic recovery in the short-term and in

the long-term and the pandemic will also

leave behind a legacy of behavioral

changes that will also affect oil use.”

Rystad said the energy transition is

accelerating and also weighs on its peak

oil demand revision, supplementing the

effect of COVID-19 on oil demand.

All sectors contribute to the transition,

but at 60% of oil demand, transport will

be the ultimate driver of this shift, it said,

adding that by 2025, the plug-in-hybrid

and battery electric vehicles are expected

to achieve 14% market share in new pas-

senger vehicle sales — according to pub-

lic governmental targets — then further

grow to 80% by 2050.

Prices jump as US election arrives Crude oil benchmarks jumped higher

Nov. 2, following a rough patch of

decline in the previous week largely

attributed to looming coronavirus lock-

downs.

Alaska North Slope crude rose $1.22

to $38.06 per barrel, West Texas

Intermediate rose $1.02 to $36.81, and

Brent rose $1.51 to $38.97 as traders

anticipated a hinted delay in easing of

output cuts planned for January by the

Organization of Petroleum Exporting

Countries and allied nations.

On Nov. 3, ANS continued up $1.04 to

$39.11, WTI went up 85 cents to $37.66,

and Brent rose 75 cents to $39.71, after

the American Petroleum Institute report-

ed an 8 million barrel drop in crude stock-

piles in the prior week.

A splash of cold water was thrown on

price recovery hopes by a PVM Oil

Associates Ltd. report Nov. 3 which sug-

gested that the rally was powered by oil

traders covering short positions.

“The jump has borne all the hallmarks

of a massive, logical and even inevitable

short-covering prior to the U.S. presiden-

tial election,” said Tamas Varga of PVM.

“It would be tempting to conclude that the

recovery from last week’s slump is now

underway, but it is simply not a plausible

scenario.”

The PVM report said that as sentiment

changes in line with infection rates mar-

kets will strengthen, but prolonged rallies

are unlikely.

“That will only happen after full

recovery — and it is likely to be impres-

sive,” PVM said. “The timing of it, how-

ever, is presently impossible to foresee.”

Brent continued upward by $1.52 Nov.

4, hitting $41.23. WTI traded above $39.

Norway exploration halved The Norwegian Petroleum Directorate

has projected that about 30 exploration

wells will be drilled on the Norwegian

shelf in 2020, about half the level from

2019.

The decline in demand for oil and

lower prices have led oil companies to

reduce their exploration budgets for the

year and postpone a number of explo-

ration wells, the directorate said in an

Oct. 27 report.

“Without new discoveries, oil and gas

production could decline rapidly after

2030,” said Torgeir Stordal, NPD director

for exploration.

However, there are still substantial

remaining resources in all areas accord-

ing to the report.

“New exploration technology and big

data analyses can contribute to more dis-

coveries on a mature shelf,” Torgeir said,

adding, “A diverse range of players, good

access to acreage and a higher volume of

better-quality data have contributed to

many discoveries.”

In areas with available and cost-effec-

tive infrastructure, even small discoveries

can create substantial values, he said.

Low unit costs also mean that future

exploration can be profitable.

Average unit costs for discoveries in

the 2000-2019 period were in the $25 per

barrel range, and if costs can be contained

at that level, future exploration will be

profitable even with low oil prices, the

directorate said.

“It will be important to develop minor

discoveries while there is available

capacity in nearby infrastructure,” the

NPD said. “Exploration is urgently need-

ed in areas where the infrastructure has a

limited lifetime.” l

8 PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020

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By KAY CASHMAN Petroleum News

On Oct. 1, operator Brooks Range Petroleum

Corp., or BRPC, and Finnex LLC filed the

eighth annual plan of development for the

Southern Miluveach unit on behalf of the working

interest owners with Alaska’s Division of Oil and

Gas. Sustained oil production from the unit’s

Mustang field is planned by third quarter of next

year.

The eighth POD, which will run from Jan. 1 to

Dec. 31, 2021, takes up where work in the 8,960-

acre, five-lease, unit left off in December 2019.

Note: As previously reported in Petroleum News,

on Sept. 16 the Alaska Industrial Development and

Export Authority passed a resolution approving the

negotiation and execution of a debt settlement

restructuring agreement, or DSRA, and authorized

the sale of the Mustang oil field leases to Finnex.

Finnex is the special purpose vehicle, or SPV,

page

5

l F A C I L I T I E S

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

Vol. 25, No. 40 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of October 4, 2020 • $2.50

August ANS down marginally; Cook Inlet production off by 2%

see INSIDER page 11

Parks redo hangs on offshore O&G; Rivalry for oil investment heats up CONSERVING NATURAL RESOURCES

has “long been tied to and directly support-

ed by oil and gas development in the United

States,” Walter Cruickshank, Ph.D., acting

director of Interior’s Bureau of Ocean

Energy Management, wrote in a recent

release.

“This may seem counterintuitive to some,

but offshore energy development revenues

from qualified leases go right back into conservation initia-

tives throughout the United States via the Land and Water

Conservation Fund,” Cruickshank said in the story, which

was first published by The Vindicator.

Established in 1964, the LWCF supports federal, state and local land, water and wetlands purchases to expand public

access to public lands, “so more Americans can experience

see ICEBREAKER page 11

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

Russia’s new nuclear icebreaker completed, heads to Murmansk Construction of the Arktika, Russia’s newest nuclear ice-

breaker, has been completed and the vessel is heading from St. Petersburg to Murmansk, according to Rosatom State Atomic Energy Corp. Russia claims that the new vessel is the world’s largest nuclear icebreaker. Rosatom reports that the vessel is 173 meters in length, with a displacement of 33,540 tons. Two nuclear reactors power the vessel’s propulsion system. The ves-sel is the first of a series of four similar icebreakers, planned to be built in a program referred to as “project 22220.”

The Barents Observer has reported that one of the vessel’s three electrical propulsion engines is broken and will need to be replaced.

Russia’s particular focus is the operation of the Northern Sea route, the Arctic route around the north of the country, linking the Baltic Sea with South Korea and the north Pacific. With the continuing shrinkage of the Arctic sea ice extent and thinning of the ice, there is international interest in the potential for opening

Vol. 25, No. 2 October 2020

ArcticArcticCovering Arctic oil and gas operations and the logistics, construction and service firms that support them

Oil & Gas DirectoryOil & Gas Directory

Latest Arctic Directory released

BlueCrest’s 7th POD Maintain production; trident fishbone well on hold until prices firm up

By STEVE SUTHERLIN Petroleum News

BlueCrest Alaska Operating LLC will

implement well work in order to main-

tain production under its seventh plan of

development for the Cosmopolitan unit, in

effect from Jan. 1, 2021, through Dec. 31,

2021.

In a Sept. 25 letter to the Alaska

Department of Natural Resources Division

of Oil and Gas, BlueCrest said plans in its sixth POD

to drill at least one trident fishbone well in 2020,

which were delayed due to COVID-19 oil market

disruptions, will remain on hold for 2021 “until the

current market environment improves.”

Each trident fishbone well, built on the

company’s success with its single fishbone

wells, will “provide the same amount of

reservoir contact as 21-27 individual

wells.” J. Benjamin Johnson, BlueCrest

Energy CEO and president told Petroleum

News in 2019.

A complete well plan stands ready for

the company’s proposed H10 trident well,

Johnson said in a Sept. 29 interview.

“It’s on indefinite hold. We’re ready to

go but we’re waiting to have some confidence in oil

prices,” he said. “It’s a moving target; the oil prices

are down but costs have also come down.”

The company said the pause in drilling has

Trump bolsters A2A Says will issue presidential permit for Alaska-to-Alberta import and export line

By GARY PARK For Petroleum News

From the time it was floated five years ago, the lat-

est version of an Alaska-Alberta rail link has

been openly scorned by many and quietly given the

brush off by others.

For 130 years, various proposals have been made

for such a project to bolster imports and exports in

Alaska and Western Canada and have just as quickly

evaporated in the absence of financial backers.

But the idea keeps resurfacing as a serious plan to

move oil and other resources to and from the Pacific

Basin through Alaska.

The current proposal involves a venture by the

Alaska to Alberta Railway Development Corp., A2A.

In mid-2019 A2A announced it had reached an

agreement with the Alaska Railroad Corp. to develop

a joint operating plan to upgrade and extend the 515-

mile Alaska Railroad mainline between Seward and

North Pole.

Apparently the mega-undertaking has attracted

the attention of President Donald Trump, who

announced on Sept. 25 that he would issue a presi-

dential permit for the A2A project, a permit which the

president signed Sept. 28.

The plan involves building a 1,600-mile track

linking Anchorage, the Yukon, the Northwest

Territories and northern Alberta at a current cost esti-

mate of C$22 billion, with Alberta’s oil sands bitu-

men exports being carried by rail to Interior Alaska,

see MUSTANG PLAN page 9

see BLUECREST page 10

see A2A RAILWAY page 10

J. BENJAMIN JOHNSON

Mustang plan filed Oil production from the North Slope Southern Miluveach unit to start 3Q 2021

BRPC/Finnex said the Mustang project lost a year in its planned development schedule, “but the project remains fundamentally sound and (capable) of being brought to fruition.”

A special offer from Petroleum News!

Purchase a one year Petroleum News subscrip�on, and receive a gi� subscrip�on for just $1! Sign up today! CONTACT Renee Garbutt I 281-978-2771 rgarbutt@petroleumnews.com (Gift subscriptions must be used toward new subscribers. Special offer ends Dec. 31)

continued from page 1

OIL PRICES

On Nov. 3, ANS continued up $1.04 to $39.11, WTI went up 85 cents to $37.66, and Brent rose 75 cents to $39.71, after the American Petroleum Institute reported an 8

million barrel drop in crude stockpiles in the prior week.

Contact Steve Sutherlin at ssutherlin@petroleumnews.com

PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020 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

A Acuren AES Electric Supply, Inc Afognak Leasing LLC Ahtna, Inc. Airport Equipment Rental Alaska Dreams Alaska Frontier Constructors (AFC) Alaska Marine Lines Alaska Materials Alaska Railroad Alaska Steel Co. Alaska Tent & Tarp Alaska Textiles Alaska West Express Arctic Controls ARCTOS Alaska, Division of NORTECH Armstrong AT&T . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12 Avalon Development

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G-M GCI GMW Fire Protection Greer Tank & Welding Guess & Rudd, PC HDR Engineering, Inc. ICE Services, Inc. Inlet Energy Inspirations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 Judy Patrick Photography . . . . . . . . . . . . . . . . . . . . . . . . . . .5 Little Red Services, Inc. (LRS) . . . . . . . . . . . . . . . . . . . . . . . . .8 LONG Building Technologies Lounsbury & Associates Lynden Air Cargo Lynden Air Freight Lynden Inc. Lynden International

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Nordic Calista Services camps receive upgrades Nordic Calista Services, a drilling

and workover company owned by Calista Corp., recently said that it has performed extensive preventative maintenance on the majority of its five camps, all of which worked last drilling season. The updates include new sheeting, new plumbing, insulation and new paint. One of Nordic Calista’s smaller 20-person camp annexes, Camp 101, is now placed on a single trailer, like its other camps, for maximum mobility. Camp 101 adds needed bed space and washing facilities to existing camps, helping to meet new COVID-19 protocols for single occupancy rooms and social distancing.

Camp 101 is a 21-person camp annex with 10 double/1-single status rooms, which could come in handy if an existing camp needs extra beds for quarantining or to expand an existing camp to provide single occupancy rooms. The camp annex is also on a trailer for easy mobilization and has a recreation area and toilets/showers.

Camp 4 is currently committed for the exploration season. The rest are currently located in Deadhorse and are available for lease.

For more information visit www.nordic-calista.com

Diamond Grid and ClubBuy in agreement John Horjes, executive director for Diamond Grid USA & Canada, said Oct. 30 that

Diamond Grid is an approved vendor for GolfNow’s ClubBuy program. “We are pleased to join ClubBuy and be a vendor to 170,000 members, and that

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CO

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wells remains $400,000 each — additions to the reasons

the commission will consider for increasing or decreas-

ing bonding amounts and an extension of the time to pay

increases in bonding.

The commission will accept comments on the proposed

regulation changes in writing through Nov. 20.

Furie told the commission in its Nov. 2 letter that it sup-

ports the commission’s additions to the section on reasons

it may increase or decrease bonding amounts, the exten-

sion of payment installments from four to seven years and

agrees with the “nominal reduction in bonding require-

ments” for its seven wells from $2.8 million to $2.5 mil-

lion, but, Dusenbery said, “we still feel that this level of

bonding is counterproductive to exploration and develop-

ment in the Cook Inlet during these economically dis-

tressed times.”

He said the company has been in discussions with

AOGCC staff and wants to see bonding required for only

the four producing wells.

“The remaining wells have been suspended or are cur-

rently awaiting AOGCC’s final determination that they

have been properly suspended and will not fall under the

bonding requirements,” Dusenbery said.

Other bonds in place The letter also requests a bonding reduction based on

bonds or securities in place totaling more than $1.7 mil-

lion.

The company’s existing bonds include $650,000 with

AOGCC, an AOGCC blanket well bond of $200,000 (this

was the requirement covering all of an operator’s wells in

the state prior to 2019 bonding requirement changes), a

statewide oil and gas bond of $500,000 with the Alaska

Department of Natural Resources, $228,375 in pipeline

DR&R (dismantling, removal and restoration) with

DNR’s Division of Mining, Land and Water, with whom

the company also has a $50,000 bond for pipeline survey,

and a $100,000 DR&R sinking fund with DNR as part of

a DNR P&A Agreement.

Furie said the bond and financing plan it has in place

with DNR is dedicated to the company’s P&A obligations,

and said the deposits into the DR&R sinking fund should

be considered part of the security under the new regula-

tions.

Dusenbery said the company supports AOGCC’s

effort to reduce redundant bonding “and undue financial

burdens on small independent operators in the Cook

Inlet” during the current challenging economic condi-

tions. “Ensuring continued investment and production

from Cook Inlet will allow the Railbelt Utilities and the

Interior to provide reliable energy for a sustainable econ-

omy.”

The commission has considered or is considering bond

reduction requests from other small operators, primarily

in Cook Inlet. The state’s large producers have not

appealed the bonding increases.

To date, the commission has found in favor of two

operators: AIX, operator of the Kenai Loop field, which

has a bond with that field’s landowner, the Alaska Mental

Health Trust Land Office, specifically dedicated to P&A

of the field’s wells, did not have to increase its existing

AOGCC bond. Cook Inlet Energy, a Glacier Oil and Gas

company, won some reduction in its bonding increase

because of a bond in place specifically for P&A of two

disposal wells with the U.S. Environmental Protection

Agency.

—KRISTEN NELSON

continued from page 1

BONDING RELIEF

December 2017 then Anchorage Mayor

Ethan Berkowitz proposed the sale of

municipality-owned electric utility ML&P

to Chugach Electric. In April 2018

Anchorage voters gave the municipality the

authority to proceed with the sale.

Subsequently the two utilities worked out

the details of the deal, filed the proposed

deal with the RCA and participated with

other stakeholders in the RCA hearing.

On May 28 of this year the RCA issued

its approval of the purchase, subject to some

specific changes to the deal. Subsequently

the utilities have been able to complete the

utility consolidation.

An historic day “This is a historic day, and I am grateful

for the hard work and efforts of so many,”

said Chugach Electric CEO Lee Thibert on

Oct. 30. “We could not have done this with-

out the support of the employees, our board

of directors, the administration and

Anchorage Assembly, and the citizens of

Anchorage. This has truly been a communi-

ty effort.”

During an Oct. 30 press conference

Acting Anchorage Mayor Austin Quinn-

Davidson reflected on the total transaction

value of $986 million, characterizing this as

the biggest deal in Anchorage history.

“After three and a half years of hard

work, overwhelming approval by voters

and a vigorous review by the Regulatory

Commission of Alaska, it is an honor to be

able to announce that the acquisition of

ML&P by Chugach Electric is complete,”

Quinn-Davidson said.

Benefits to the municipality As a consequence of the deal several

hundred million dollars will be deposited

into the municipality’s trust account, as a

means of generating future revenue. And

$15 million from the deal will be dedicated

to addiction treatment services in the

municipality — Quinn-Davidson said that

the municipality anticipates purchasing the

Best Western hotel at the corner of 36th

Avenue and the New Seward Highway in

Anchorage, to convert the building into a

treatment facility.

“For the past three years we as a board

have been working hand in hand with our

very hard working and dedicated manage-

ment team on this acquisition,” said Bettina

Chastain, Chugach Electric board chair.

“We can make a real difference in the lives

of the people in our community by having

success in this transaction. I am really proud

to be part of this historic time.”

Outgoing ML&P general manager Anna

Henderson thanked the many people and

organizations, including ML&P employees,

Anchorage residents, Railbelt utilities and

government agencies, that had all help to

make the deal happen.

Characterizing the deal as retaining dem-

ocratic control of the power supply services

through customer membership of Chugach

Electric, Bill Falsey, Anchorage municipal

manager, said that closure of the deal is a

signature moment for the municipality.

“This is one of the longest talked about,

dreamed about, largest transactions in

municipal history, with real benefits to

ratepayers,” Falsey said.

Immediate benefits Quinn-Davidson mentioned immediate

rate reductions that ML&P customers will

see as a consequence of a rate relief provi-

sion built into the deal.

“The efficiencies created today will pro-

vide immediate benefits in savings to peo-

ple in a time of great need,” said

Christopher Constant, Anchorage Assembly

member for the downtown district.

Thibert said that a rate reduction mecha-

nism included in the settlement of the deal

should result in all Chugach Electric mem-

bers seeing a reduction in the fuel cost com-

ponent of their electricity bills at the begin-

ning of 2021. On the other hand, the base

rates for electricity will not immediately

change, with a new rate case probably not

being filed until 2023, Thibert said. Chugach

Electric has upheld a commitment to offer

jobs to all existing ML&P employees.

Four major components The deal has four major components: an

upfront payment to close the purchase; pay-

ments in lieu of tax to the municipality over

a period of 50 years, as compensation to the

municipality for the loss of tax revenue

from ML&P as a municipality-owned enti-

ty; a commitment to purchase electricity

from the Eklutna hydroelectric power facil-

ity from the municipality for 35 years; and

an agreement relating to benefits associated

with ML&P’s part ownership of the Beluga

River gas field in the Cook Inlet — both

Chugach Electric and ML&P owned por-

tions of the field.

RCA stipulations In order to approve the deal, the RCA

required three conditions that alter some of

the provisions of the proposed deal. Firstly,

the commission required a single rate struc-

ture for all ratepayers in the consolidated

utility, rather than a separate rate structure

for ratepayers in what had been the ML&P

service area. Secondly, the commission

required the use of a single cost of power

adjustment associated with the use of gas

from the Beluga River field. And thirdly, the

commission required that Chugach Electric

and Matanuska Electric Association form

an agreement for the implementation of

security constrained merit order dispatch

across their service areas.

That third condition would enable

Chugach Electric and MEA to minimize

electricity costs through the continuous use

of the most efficient available power gener-

ation across the region that the two utilities

serve.

The parties to the deal agreed to the

RCA’s conditions, hence enabling the deal

to proceed to closure. Thibert commented

that the RCA’s requirements had resulted in

a deal that is better than the one originally

presented to the commission.

“I think really, at the end of the day, the

commission looked at the best interests of

the member or the ratepayer, and we actual-

ly came up, I think, with a better agree-

ment,” he said.

Thibert cited the implementation of a

common rate structure for the entirety of

Chugach Electric’s expanded service area,

and the use of a common gas fuel price, to

be particularly beneficial. He also said that

Chugach Electric anticipates a ruling from

the RCA next week regarding the proposed

power pooling agreement with MEA.

“We will be working with them to com-

plete that agreement and hopefully get it

rolling within the next year,” Thibert said. l

10 PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020

continued from page 1

ML&P PURCHASE

area and drilled the Alcor 1 and Merak 1

wells.

“Following a significant decline in oil

price, Great Bear’s interest shifted to the

conventional targets located in the AKU

area,” where the company spud the Alkaid 1

well in 2015, the division said.

Alcor 1, Merak 1 Alcor 1, the first well drilled in the unit

area, was spud in June of 2012 and reached

a final depth of 10,812 feet measured depth,

10,802 feet true vertical depth. The division

said it penetrated numerous formations that

produce conventionally on the North Slope,

including the Kuparuk and Ivishak forma-

tions, as well as unconventional targets —

the Hue Shale/HRZ, Kingak and Shublik.

Great Bear spud the Merak 1 in August

2012, immediately after Alcor 1 was drilled.

Merak reached a MD of 11,094 feet and a

TVD of 11,081, penetrating the same for-

mations as the Alcor well.

Both wells were plugged and aban-

doned.

Alkaid 1 Great Bear didn’t drill again in the area

until February 2015, when it spud Alkaid 1.

It planned to drill that well to the Kuparuk,

but it was only drilled to 8,595 MD, 8,485

TVD, the division said, with operational

issues tied to Sag River flooding preventing

flow testing at the time; the well was sus-

pended.

Great Bear re-entered the Alkaid and

successfully flow tested it in February 2019.

The division said a 6-foot interval at 8,158-

8,164 feet was perforated in Upper

Brookian sands, “and a one-stage hydraulic

fracture treatment was initiated to stimulate

the well.”

The well was flowed for some 24 hours

and produced 108 barrels of 38 degree API

oil and 300 barrels of water, with the well

gas lifted during the test. Two shallower

zones were tested in addition to the deeper

perforations, with water recovered from the

West Sak at 5,378-5,398 feet MD and the

Ugnu also “interpreted to be wet.”

Following the flow test, the Alkaid was

again suspended.

Potential hydrocarbon accumulation “Based on non-confidential well control,

there is a potential hydrocarbon accumula-

tion within the proposed Alkaid Unit,” the

division said.

The target at Alkaid is called “the

Brookian Zone of interest” by Great Bear.

“It is composed of relatively thin bedded

sands with interbedded shales and silts,” the

division said, and is quite thick in the Alkaid

unit area, with some 400 feet of the

Brookian intersected in the Alkaid well,

which did not reach an oil-water contact or

the bottom of the formation.

The division said Great Bear provided

comprehensive interpretation and analysis

of available data in support of its unit appli-

cation, including interpretations of 3D seis-

mic, maps based on seismic attribute analy-

sis, structure maps, interval isopachs and

net pay maps integrating seismic and well

data and geologic cross sections.

Great Bear has interpreted 3D seismic

and analysis of its recently drilled wells, and

“has identified the Brookian section in the

AKU area as their preferred target to

progress towards a commercial develop-

ment,” and, the division said, review of con-

fidential data and interpretations of that data

“reasonably supports an interpretation that

the unit encompasses the minimum area

required to include all or part of a reservoir

and all or part of a potential hydrocarbon

accumulation,” with the area “proven

through drilling and testing.”

The division said, “additional delin-

eation work will determine the commercial

viability of the Brookian oil-bearing strata

at and away from the Alkaid 1 well.”

While the potential hydrocarbon accu-

mulation area meets the regulatory require-

ment for inclusion in a unit, it “will require

drilling, testing, and additional delineation

work in order to determine its commercial

viability,” the division said.

Plan of exploration approved The division has approved the plan of

exploration which accompanied Great

Bear’s unit application, effective Nov. 2 and

running through Nov. 1, 2022.

The company listed a number of non-

drilling activities: reprocessing some 50

square miles of merged 2012-16 3D

datasets, which will be completed prior to

drilling the Alkaid 2 to inform the target

interval for the lateral. Great Bear said the

work was unlikely to result in relocation of

the drill site or tophole location for the well,

“but it could result in slight deviation from

a true vertical well before hitting TVD.”

Among other non-drilling activities,

Great Bear said it would: “Engage an out-

side engineering firm to produce an engi-

neering study on a conceptual ‘hot tap’ of

TAPS within or near the Alkaid and Talitha

Units, working in consultation with Alyeska

Pipeline Service Company.”

(Great Bear applied for a unit at Talitha

at the same time it applied for the Alkaid

unit; the division has not yet issued a deci-

sion on that application.)

Planned drilling activities include the

Alkaid 2, with a planned TVD of 8,000 feet

“to the basin floor of the Brookian, a level

not reached” at Alkaid 1, Great Bear said.

“Multiple interesting zones may be

encountered throughout the drilling. The

well will penetrate the entirety of the

continued from page 1

ALKAID UNIT

see ALKAID UNIT page 11

PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020 11

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access their drill sites by ice or gravel

roads as will Jade, but the Area F POD

adds a barging program between West

Dock and the PTU Service Pier to the mix

as an intermediate step.

Jade expects to stage the rig, equipment

and some additional materials required to

support drilling into a laydown area desig-

nated by the PTU.

Barging operations would occur in the

summer and require some lead time to

organize, particularly given the fact that

some dredging will be required to land a

barge at Point Thomson and potentially

depart West Dock.

As part of its second plan of develop-

ment, the Alaska independent pursued

approvals to conduct a small-scale scree

operation on the PTU Service Pier

Approach, including a permit from the U.S.

Army Corps of Engineers.

On Nov. 2, the Corps sent Jade an

unsigned copy of the permit. The recipient,

Jade’s top executive and 50% owner Erik

Opstad, was told if he accepted the permit’s

conditions, to sign and return it to the

Corps, along with a $100 permit fee. In

turn, the Corps would send him a finalized

copy of the permit.

On Nov. 3 Opstad told Petroleum News

he had signed the permit and sent the check

that morning.

The third POD for Point Thomson unit

Area F, Tract 32, runs from Jan. 1, 2021,

through Dec. 31, 2021. Jade became major-

ity owner and operator of PTU Tract 32,

ADL 343112, in the southeastern portion of

Area F, by agreement with ExxonMobil

Alaska Production in mid-2018.

Accomplished in second POD Among, but not all, the work done in

the second POD period identified by Jade

in its third POD filing was data evalua-

tion. “Ongoing work conducted as part of

developing the 2nd POD raised several

concerns relative to Area-F development,

Jade wrote.

Given Jade’s interpretation of the

Sourdough volumetric resources, at cur-

rent oil prices development did not appear

to be economically viable, particularly

when burdened with a 40% net profit

share and a 12½% royalty, neither of

which the division was able to modify.

During first quarter 2020 Jade and the

agency “engaged in an intense and

lengthy bout of economic modeling of

Area-F resources using State of Alaska

methodology. The details and results of

that work are confidential under

38.05.035A(8), but we can say that the

parties now understand the economic

challenges to commercial development of

Area-F,” Jade said in the third POD.

Among other things, a repeat bathy-

metric survey was also done in the second

POD period. In September Jade executed

the first offshore bathymetric survey of

the PTU Service Dock Approach con-

ducted in Alaska using a helicopter.

Although one of Jade’s parent companies

(ELKO International LLC) had been

using helicopters to survey onshore lakes

for several years to meet state permit

requirements, “this fall was the first time

those techniques had been employed in

the offshore environment,” Jade said.

In the last 60 days of 2020, Jade

expects to further progress both of these

second POD priorities, as well as others,

recognizing that “COVID-19 impacts

could well worsen and we expect that

many of Jade’s commercial endeavors

and deal making capabilities will contin-

ue to be constrained by the difficult busi-

ness climate that currently exists in the

Alaska oil patch,” Jade told the division.

Third POD activities The goals and objectives under the

third POD are similar to those in the first

and second PODs but differ slightly in

detail, as work is accomplished. In no

specific order they include but are not

limited to:

1. Permitting — One of the primary

goals is to complete the permit package.

Jade said its focus is primarily on getting

a Plan of Operations approved because it

is more time-consuming than other per-

mits. Other major permits such as the per-

mit to drill are equally important “but

tend to be less problematic when it comes

to gaining approvals.”

2. Economic enhancement — Jade

feels that the economics of the project can

be materially improved, but such

improvement will take participation from

all stakeholders. One goal in 2021 is to

work toward facilitating material

improvement of project economics.

3. A third bathymetric survey — Given

the importance of the PTU Service Pier

Approach bathymetric survey data to

Jade’s mobilization plan “we will want to

keep a close eye on those characteristics.”

Using a helicopter in the September sur-

vey provided “significantly higher resolu-

tion than other methods. This game-

changing methodology offers cost saving

of 90% compared with other techniques,”

Jade said, noting it expects to run these

surveys “whenever needed to characterize

area bathymetric conditions on or off-

shore.”

4. Mobilization planning — Although

not forgotten, Jade said, mobilization

planning was on the back burner for much

of 2020 once it became clear that drilling

would be delayed at least a year (until

early 2022) “and perhaps longer given the

COVID-19 pandemic … coupled with

O&G project funding challenges due to

ANS crude price weakness and Alaska

tax uncertainties.” In 2021 Jade intends to

develop a detailed barge mobilization

plan for Nordic Rig 3 while also examin-

ing a snow trail alternative that may now

be possible due to the availability of new

technology.

—KAY CASHMAN

Brookian section. This will include an

evaluation of the deltaic interval of the

Brookian progradation,” the company

said.

The lateral for Alkaid 2, estimated at

10,000 feet, will run toward the south-

west and will be fracture stimulated.

There will be a long-term production

test “to determine the decline curve and

production profile” at Alkaid 2, with the

test long enough to establish the initial

production rate, slope of the decline

curve and the rate at which the decline

curve levels off so that the production tail

can be accurately predicted.

“We currently estimate that the pro-

duction test will be six to nine months in

duration,” Great Bear said.

Alkaid 2 drilling operations are sched-

uled for the summer of 2021 from a grav-

el pad just west of the Dalton Highway,

with the pilot production test projected

from September 2021 through mid-2022.

Great Bear said a number of factors

would determine whether Alkaid 2

results support drilling of Alkaid 3.

If that well is drilled it would be in the

winter of 2022, with the pilot production

test running from June 2022 through late

2022.

—KRISTEN NELSON

continued from page 10

ALKAID UNIT

continued from page 1

JADE FILING

Nordic Rig-3 on remote North Slope exploration pad very similar to that being planned for Jade 1.

In 2021 Jade intends to develop a detailed barge mobilization plan

for Nordic Rig 3 while also examining a snow trail

alternative that may now be possible due to the availability of

new technology.

12 PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020

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