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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
page
6
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:
P.O. Box 231647 Anchorage, AK 99523-1647) Subscription prices in U.S. — $118.00 1 year, $216.00 2 years
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POSTMASTER: Send address changes to Petroleum News, P.O. Box 231647 Anchorage, AK 99523-1647.
www.PetroleumNews.com
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
Steven Merritt PRODUCTION DIRECTOR
Alan Bailey CONTRIBUTING WRITER
Eric Lidji CONTRIBUTING WRITER
Gary Park CONTRIBUTING WRITER (CANADA)
Steve Sutherlin CONTRIBUTING WRITER
Judy Patrick Photography CONTRACT PHOTOGRAPHER
Forrest Crane CONTRACT PHOTOGRAPHER
Renee Garbutt CIRCULATION MANAGER
SECURITY SERVICEandACILITY MTED F
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DENALIUNIVERSAL.COMMCOMAL.COMERSAL.COMNIVERSAL.CLIUNIVERSANALIUNIVEDENALIUNDENALDEN
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
PETROLEUM NEWS • WEEK OF NOVEMBER 8, 2020 7
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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
B-F Bombay Deluxe BrandSafway Services Brooks Range Supply C & R Pipe and Steel Calista Corp. ChampionX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4 Chosen Construction Colville Inc. Computing Alternatives
CONAM Construction Cruz Construction Denali Universal Services (DUS) . . . . . . . . . . . . . . . . . . . . . .4 Doyon Anvil Doyon Associated Doyon Drilling Doyon, Limited EEIS Consulting Engineers, Inc. Egli Air Haul exp Energy Services F. R. Bell & Associates, Inc. Flowline Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8 Frost Engineering Service Co. – NW . . . . . . . . . . . . . . . . . .11 Fugro
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
Lynden Logistics Lynden Transport Maritime Helicopters
N-P Nabors Alaska Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7 NANA Worley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11 Nature Conservancy, The NEI Fluid Technology Nordic Calista North Slope Borough North Slope Telecom Northern Air Cargo NRC Alaska, a US Ecology Co. Oil Search PND Engineers, Inc. PRA (Petrotechnical Resources of Alaska) . . . . . . . . . . . . . .2 Price Gregory International . . . . . . . . . . . . . . . . . . . . . . . . . .6
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Raven Alaska – Jon Adler Resource Development Council . . . . . . . . . . . . . . . . . . . . . . .6 Security Aviation Shoreside Petroleum Soloy Helicopters Sourdough Express Strategic Action Associates Tanks-A-Lot Weston Solutions Wolfpack Land Co.
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
includes over 1,800 golf courses.” ClubBuy, the No. 1 general purchasing organization in sports and beyond, is managed
by the team at GolfNow and their partner’s team at Premier Inc., a source GPO. In total, its group members combined, spend over $60 billion annually. This spend total allows the group to negotiate prices never before seen in the world of sports. As a result, Minor League Baseball, and professional hockey leagues National Hockey League, American Hockey League and ECHL (formerly the East Coast Hockey League), along with more than 1,800 golf facilities, are participating members of this GPO.
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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
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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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