EIA: 11.1 million bpd US crude in 2021, 11.9 million bpd next year

page

4

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

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

Vol. 26, No. 28 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of July 11, 2021 • $2.50

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

see INSIDER page 9

Coyote may be another Nanushuk find; Dunleavy sues, appoints

CONOCOPHILLIPS EXECUTIVES said

very little on June 30 about their latest dis-

covery, Coyote, just west of Kuparuk.

The top dogs, Chairman and CEO Ryan

Lance and Senior VP of global operations

Nick Olds, mentioned it in their early morn-

ing virtual Market Update.

At RDC’s annual luncheon in Anchorage

later that morning ConocoPhillips Alaska

President Erec Isaacson said Coyote was in the Brookian

topset above the Nuna Torok discovery, describing Coyote as

shallow.

In other words, Coyote appears to be another in a long

DOE orders two Alaska-specific supplements for Alaska LNG EIS

The U.S. Department of Energy’s Office of Fossil Energy

granted a rehearing request by Sierra Club on its 2020 final

order issued to Alaska LNG Project LLC for export of lique-

fied natural gas for Alaska sources to non-free trade agree-

ment countries.

Alaska Gasline Development Corp. filed to answer Sierra’s

Club request.

DOE said it participated as a cooperating agency in the

Federal Energy Regulatory Commission’s review of the

Alaska LNG project.

It intends to prepare a supplemental environmental impact

statement which, the agency said in a July 2 Federal Register

see CREDIT SALE page 11

88E tax credit sale may have included additional consideration

The $18.7 million sale of Alaska oil and gas production tax

credits by 88 Energy Ltd reported in the June 27 edition of

Petroleum News likely included additional consideration above its

cashable tax credits with a face value of $19.1 million.

“The overall impact of this transaction is not considered mate-

rial to 88 Energy as the Tax Credits applied to be cashed out and

approved by the Alaskan Government totaled US$19.1 million

(compared to the proceeds received from sale of tax credits of

US$18.7 million),” 88 Energy said in a June 21 release.

88 Energy said it had entered into an agreement for the sale

of “all the Alaskan Oil and Gas Tax Credits currently held by

Accumulate Energy Alaska, Inc., a 100% owned subsidiary of

88 Energy.”

see CARBON GRID page 8

see LNG REHEARING page 10

Pembina, TC Energy team up for large scale carbon grid project

Alberta’s drive to lead global carbon capture and storage

and clean up its fossil fuel image in the process has resulted in

two of Canada’s largest energy infrastructure companies col-

laborating on a grid with capacity to transport more than 20

million metric tons of carbon dioxide annually.

Pembina Pipeline and TC Energy say they will form the

backbone of the province’s capture and storage business.

They plan to retrofit existing, underutilized pipelines and

build new transportation systems to connect Alberta’s largest

sources of industrial emissions to a carbon storage facility at

Redwater, a small town 30 miles north of Edmonton.

To be called the Alberta Carbon Grid, ACG, it is being

designed initially to capture CO2 from power generation facilities

Chaos: OPEC+ fracas Cancelled output adjustment meeting has oil markets in rollercoaster mode

By STEVE SUTHERLIN Petroleum News

A laska North Slope crude slid $1.30 to close at

$73.92 per barrel July 7, as supply uncertain-

ty whipsawed oil markets due to a breakdown of

an output adjustment meeting of the Organization

of the Oil Exporting Countries and allied produc-

ing countries. West Texas Intermediate fell $1.17

to close at $72.20, and Brent shed $1.10 to close at

$73.43. Trading was erratic; earlier in the day WTI

was up more than 1.5%, approaching $75.

July 6 trading was equally choppy. WTI hit a 6-

year high early on before reversing to close 2.5%

lower.

The OPEC+ meeting, originally scheduled for

July 1, was expected by analysts to be routine

event with a likely outcome of a 500,000 barrel per

day increase of production by the group in August.

OPEC+ is currently maintaining a 5.8 million bpd

production curtailment, down from 9.9 million bpd

in April 2020.

The United Arab Emirates reportedly requested

Eni picking up the pace Nikaitchuq facilities work, drilling increases in 14th plan of development

By KAY CASHMAN Petroleum News

In its 14th plan of development for the North Slope

Nikaitchuq unit, operator and 100% working

interest owner Eni told Alaska’s Division of Oil and

Gas that facility upgrades will be completed to sup-

port the planned Nikaitchuq North exploration well

(NN-02), the two remaining Spy Island Drillsite

injection wells and the “potential” of six new wells

discovered from the SP03-NE2 pilot-hole analysis

from the 12th POD. (The work will include complet-

ing internal piping and electrical tie-ins for the new

six-slot well containment shelter installed during that

time.)

The 14th POD will run from Oct. 1, 2021, through

Sept. 30, 2022.

The Nikaitchuq unit consists of 11 state leases,

some 21,200 acres north of the Kuparuk unit. It pro-

duces from the Schrader Bluff formation with drilling

from two locations — the Oliktok Point Pad, or OPP,

and the Spy Island Drillsite, or SID, which is a man-

made gravel island in shallow state waters off Oliktok

Point where Nikaitchuq’s onshore production and

processing facilities are located.

Nordic Calista Rig No. 4 is currently cold

stacked at OPP. Eni plans to warm the rig up at the

end of Q3 2021 and conduct workover activities on

OPP in Q4 of this year and Q1 2022, as needed.

Currently workovers are planned on OI15-S4,

Rail scheme in trouble Alaska-to-Alberta rail, A2A, in bankruptcy, asks creditor protection, seeks buyers

By GARY PARK For Petroleum News

A grand scheme to open an Alaska-Alberta

resources rail link has been side-tracked

amidst a series of murky allegations.

The Alaska-to-Alberta Railway Development

Corp., which promotes itself under the A2A label

and is a proponent of the dream to move oil sands

crude from Alberta to Alaska ports, has filed for

creditor protection after Bridging Finance, its key

financier, went into receivership.

Although it did not answer requests for com-

ment, A2A said in a news release that the protec-

tion will allow it to pursue a court-supervised sale

or refinancing of engineering, permits and pending

permits, right-of-way agreements, marketing

materials and relationships with proposed partners,

First Nations and Alaska Native entities developed

for the 1,600-mile project.

The company said it acted to protect its assets

from being liquidated after a court appointed

PriceWaterhouseCoopers, PwC, as receiver in June

see OIL PRICES page 8

see NIKAITCHUQ PACE page 11

see A2A TROUBLE page 10

The company said it acted to protect its assets from being liquidated after a court appointed PriceWaterhouseCoopers, PwC,

as receiver in June and called a C$149 million loan made to A2A by Bridging

Finance.

The turmoil surrounding the OPEC+ negotiations will likely affect prices,

perhaps quite dramatically, in the future, and the price direction is an unknown,

according to former U.S. Energy Secretary Dan Brouillette.

2 PETROLEUM NEWS • WEEK OF JULY 11, 2021

Trusted upstream coverage >> www.petroleumnews.com

Petroleum News Alaska’s source for oil and gas news

Chaos: OPEC+ fracas Cancelled output meeting has oil markets in rollercoaster mode

Eni picking up the pace Nikaitchuq facilities work, drilling increases in plan of development

Rail scheme in trouble Alaska-to-Alberta rail in bankruptcy, asks creditor protection

ON THE COVER

Oil Patch Insider: Coyote may be another Nanushuk find; Dunleavy sues, appoints

DOE orders two Alaska-specific supplements for Alaska LNG EIS88E tax credit sale may have included additional considerationPembina, TC Energy team up for large scale carbon grid project

2 AIDEA looks for ANWR pre-development work

5 Oooguruk focused on facilities, workovers

EXPLORATION & PRODUCTION

6 US rotary rig count at 475, a gain of 5

GOVERNMENT

FINANCE & ECONOMY4 EIA forecasts 2021 US crude at 11.1M bpd

US natural gas expected to average 92.6 bcf per day this year, up 1.3%; electricity from hydro to drop 12% on western drought

GREEN ENERGY3 Comments on Turnagain Arm tidal power

EPA recommends analysis of potential environmental impacts while DOI says Tony Knowles Coastal Trail may be impacted

6 Boom in Native American oil a complication

Production up tenfold from Native lands since 2009, now some 3% of US production, complicating Bush administration climate push

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

contents

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

AIDEA looks for ANWR pre-development work By KRISTEN NELSON

Petroleum News

The Alaska Industrial Development and Export

Authority in late June asked for bids on a $1.5 mil-

lion contract for pre-development permitting and plan-

ning work on the leases it won in the U.S. Bureau of

Land Management’s January sale in the 1002 area of the

Arctic National Wildlife Refuge.

Leases from that sale were suspended June 1 by the

U.S. Department of the Interior. DOI cited Executive

Order 13990 which directed Interior to “place a tempo-

rary moratorium on activities of the General

Government relating to the Coastal Plain Oil and Gas

Leasing Program,” review that program and conduct a

new analysis of potential environmental impacts.

AIDEA has protested the suspension, asking for statu-

tory and regulatory evidence for the suspension.

On June 25, AIDEA’s board passed a resolution

authorizing the agency to spend up to $1.5 million on

pre-development permitting and planning work on the

leases.

“Activities will support a phased, multi-year seismic

acquisition program targeted to begin in 2022,” AIDEA

said.

Current assessments of resource potential in the 1002

Area are based on 2D seismic by the U.S. Geological

Survey in the 1980s.

“We can reliably enhance those early oil and gas

resource estimates through responsible, carefully

planned, low-impact 3D seismic surveys,” said AIDEA

Chairman Dana Pruhs.

The agency said processed data would be used to

identify the most prospective sites for resource recovery.

The agency’s request for proposals said the proposed

project schedule is from August 2021 to October 2022.

AIDEA said it “is seeking professional services to

complete and prepare the required pre-development per-

mitting activities for the purpose of supporting a phased,

multi-year seismic acquisition program on the

Authority’s oil and gas leases located within Section

1002 of the Arctic National Wildlife Refuge Coastal

Plain.”

The intent of the project, AIDEA said, “is to develop

and provide financing for the industrial development” of

its seven leases, covering 376,775 acres, acquired in

January. “The Project permitting components will

include but may not be limited to responsible develop-

ment and impact studies, data collection, and the

required regulatory permitting to support a phased,

multi-year seismic acquisition program,” and may

include:

•Stakeholder outreach and engagement;

•Development of plan of operations;

•Preparation of required permitting and authoriza-

tions;

•Planning, acquisition and completion of studies,

reports and data collection;

•Preparation of progress, compliance and final report-

ing as required;

•Planning, acquisition and completion of studies,

reports and data collection “reasonably necessary to pre-

vent negative surface impacts”; and

•All other services necessary to complete permitting.

AIDEA said additional environmental services may

be added to the work by amendment.

Proposals were due July 8. l

By ALAN BAILEY For Petroleum News

The Environmental Protection

Agency and the Department of the

Interior have both filed comments with

the Federal Energy Regulatory

Commission in response to an applica-

tion for a preliminary FERC permit for a

tidal energy facility at the mouth of

Turnagain Arm. Both agencies pointed

out some issues that need to be consid-

ered as part of any permitting for the pro-

posed project.

As previously reported in Petroleum

News, in March Turnagain Arm Tidal

Energy Corp. applied for a preliminary

permit for the Turnagain Arm Tidal

Electric Generation Project, or TATEG,

for the generation of electric power from

Cook Inlet tides. The permit would

enable Turnagain Arm Tidal Energy to

proceed with the investigations and

analysis required to potentially apply for

a license to construct the system.

The tides create powerful currents in

and out of Turnagain Arm. The project,

as envisaged, would involve the con-

struction of two 8-mile tidal fences

across the arm, to enable the operation of

tidal turbines. One fence would run from

near Fire Island to Point Possession on

the Kenai Peninsula, with a service road

along the top to allow access from the

Kenai Peninsula for servicing the tur-

bines. The second fence would be 7.5

miles in length and would be located 5-7

miles south of Fire Island and at least 5

miles from the other fence.

Installed capacity of 2,200 megawatts Tidal energy benefits from the advan-

tage of predictability in its renewable

power output but from the disadvantage

of varying in output as the tidal currents

wax and wane. The proposed system,

with a total of 220 10-megawatt turbines,

would have a total installed capacity of

2,200 megawatts and a baseline average

output of 1,200 megawatts. Turnagain

Arm Tidal Energy says that this power

capacity would be sufficient to meet the

entirety of the Alaska Railbelt electricity

demand. The company has proposed a

number of studies, including a study into

the potential use of industrial batteries to

mitigate the loss of power output during

periods of slack tides.

The company says that the two fences,

with their associated turbines, could har-

ness a large portion of the kinetic energy

associated with the water flow in and out

of the Turnagain Arm. The company also

says that the relatively slow rotation of

the turbine blades, together with their

large scale, will enable fish, whales and

other sea mammals to swim though the

fences without difficulty.

NEPA review required In a June 30 FERC filing the EPA

commented on the need to review the

project under the terms of the National

Environmental Policy Act.

“This proposed tidal energy project is

unprecedented in Alaska,” the filing

says, commenting that an alternatives

analysis under NEPA must include

appropriate management and mitigation

measures, including measures to reduce

the impacts of construction, operations

and decommissioning, and to minimize

impacts on traditional and cultural uses

and resources.

The EPA also expressed particular

concern about potential impacts on Cook

Inlet beluga whales, with a need for

analysis of the effects on the whales of

factors including the noise generated by

power stations and the physical barriers

associated with the power stations that

may impact the whales’ transits between

“foraging, nursing and/or birthing areas.”

More clarity will be needed over the abil-

ity of fish, whales and other sea mam-

mals to swim through the turbines, the

EPA said. The beluga whales, with their

population in significant decline, are list-

ed as endangered under the Endangered

Species Act.

In a mid-June filing the Center for

Biological Diversity, while commenting

that it did not yet have sufficient infor-

mation to take a position on whether the

project should proceed, had expressed

particular caution about potential

impacts on the beluga whales.

Among other factors listed by the EPA

are the need evaluate the impacts of any

dredging operations carried out in associ-

ation with the project, and the possible

impacts on subsistence resources. The

Cook Inlet is rich in resources used for

subsistence fishing, hunting and gather-

ing, the EPA said.

The EPA also recommends that the

NEPA analysis of the project should con-

sider the “reasonably foreseeable”

impacts of climate change on the project

and its infrastructure, as well as the

potential greenhouse gas emissions from

construction, operations and decommis-

sioning activities. Climate change will

alter water flow rates, temperatures,

wind fields and coastal water current pat-

terns, the EPA said.

Potential recreational impacts The DOI, in a June 25 filing, particular-

ly focused on the potential impact of the

tidal energy project on the Tony Knowles

Coastal Trail that runs along the Cook Inlet

coast, connecting Anchorage with the

Kincaid Park. The trail, which is popular

with walkers, skiers, cyclists and other

recreational users, includes 7.71 miles of

trail supported by the Land and Water

Conservation Fund, or LWCF. The

National Park Service is seeking the

appropriate records that define the bound-

aries of the LWCF area, to determine

whether the project would impact the area,

DOI said.

Any conversion of land within a LWCF

area would require compliance with feder-

al laws, including NEPA and the National

Historic Preservation Act, DOI cautioned.

Potential impacts to the recreational and

conservational purposes of the area,

including impacts of the design of the tidal

power system on the “viewshed” of the

area, need to be understood, DOI said. l

l G R E E N E N E R G Y

Comments on Turnagain Arm tidal power EPA recommends analysis of potential environmental impacts while DOI says Tony Knowles Coastal Trail may be impacted

PETROLEUM NEWS • WEEK OF JULY 11, 2021 3

In a June 30 FERC filing the EPA commented on the need to review

the project under the terms of the National Environmental

Policy Act.

By KRISTEN NELSON Petroleum News

The U.S. Energy Information

Administration said July 7 in its

Short-Term Energy Outlook for July that it

expects global crude oil production to rise,

largely from Organization of the

Petroleum Exporting Countries and part-

ners, reducing global oil inventory draws

and keeping prices for this year “similar to

current levels,” with a second half average

of $72 per barrel.

Brent averaged $73 per barrel in June,

up $5 from May and $33 higher than June

of 2020.

Next year, EIA said, it expects continu-

ing growth in production by OPEC+,

accelerating U.S. tight oil production and

other supply growth to “outpace growth in

global oil consumption and contribute to

declining oil prices,” which the agency

expects to average $67 per barrel in 2022.

Henry Hub natural gas prices averaged

$2.03 per million British thermal units in

2020 and EIA said it expects those prices

to rise to an annual average of $3.22 per

million Btu this year and then fall to $3 in

2022.

The July outlook remains subject to

heightened uncertainty due to the ongoing

economic recovery

from the COVID-19

pandemic, with U.S.

economic activity

and increase in ener-

gy use continuing to

rise after multiyear

lows in the second

quarter of 2020. EIA

said this outlook

assumes U.S. gross

domestic product will grow by 7.4% this

year and by 5% in 2022.

Electricity sales EIA said it is forecasting an increase of

2.8% in U.S. retail electricity sales this

year, led by a 5.1% increase in the indus-

trial sector with the commercial sector also

growing, but just at 2.1% because many

workers will continue to work from home.

“The increase in electricity sales to the

industrial sector is a strong sign of rising

levels of economic output as the COVID-

19 pandemic recedes in the United States,”

said EIA Acting Administrator Steve

Nalley.

EIA expects that renewable energy will

contribute a greater share of U.S. electric-

ity generation through 2022, reaching

23%, up from 20% in 2020, with about 50

gigawatts of solar and wind capacity

scheduled to come online in the next 18

months. 2022 is the first year that growth

in solar capacity will outpace wind capac-

ity growth, the agency said.

Hydropower generation in California

and the Northwest is expected to be down

by 11% this year because of weather con-

ditions, and down 12% nationwide.

“The extreme drought in the Northwest

and California is straining water reserves,

which we expect to cause a significant

decrease in electricity from hydropower

this year,” Nalley said.

US production levels U.S. crude oil production is forecast to

average 11.1 million bpd this year, down

200,000 bpd from 2020, EIA said, noting

that annual numbers “somewhat obscure

production trends,” with first quarter pro-

duction this year down by more than 2 mil-

lion bpd from the first quarter in 2020, “the

quarter before 2Q20 when production fell

sharply in response to falling oil prices.”

From the second through the fourth

quarter of this year, however, U.S. produc-

tion is expected to be up 400,000 bpd on

average from last year and the agency is

forecasting that U.S. crude production will

average 11.9 million bpd next year.

Trends in Lower 48 production are

expected to drive production levels, with

most of that production — excluding the

federal offshore Gulf of Mexico — tight

oil. EIA said its growth forecast is based

on West Texas Intermediate prices which

“indicate a favorable environment for

drilling activity.”

WTI averaged more than $70 per barrel

in June for the first time since October

2018 and EIA said it expects WTI to

remain above $60 per barrel through the

end of 2022, “a price that has signaled

robust activity among U.S. operators in the

past.” The agency said changes in rig

counts typically follow WTI price changes

by three to six months, with production

changes some two months after rig

changes, so “current crude oil price levels

will not likely affect production until late

2021.”

U.S. crude production is forecast to

average some 11.2 million bpd in the sec-

ond and third quarters of the year, “before

beginning to rise more steadily,” reaching

11.3 million bpd in the fourth quarter and

12.2 million bpd by the fourth quarter of

2022.

EIA did note that operators are adding

rigs more slowly than when prices reached

similar levels in the past. “If operators take

a more cautious approach to rig deploy-

ment than we are expecting, crude oil pro-

duction could be lower than in our fore-

cast,” the agency said.

Gulf of Mexico production is expected

to average 1.8 million bpd both this year

and next, with 10 new projects likely to

begin operations during the period expect-

ed to help offset declines at existing proj-

ects.

U.S. dry natural gas production is fore-

cast to average 92.6 billion cubic feet per

day this year, up 1.3% from 2020, with

natural gas production rising in response to

higher crude and natural gas prices.

With Henry Hub spot prices forecast to

average more than $1 per million Btu

higher than in 2020, an increase of 58%,

associated dry natural gas production in

the Permian from oil directed rigs is

expected to increase in 2021 as WTI prices

are up almost $27 per barrel, 68%, from

2020.

Dry natural gas production is expected

to average 94.7 bcf per day next year, up

2.3% from this year. l

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

EIA forecasts 2021 US crude at 11.1M bpd US natural gas expected to average 92.6 bcf per day this year, up 1.3%; electricity from hydro to drop 12% on western drought

4 PETROLEUM NEWS • WEEK OF JULY 11, 2021

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WTI averaged more than $70 per barrel in June for the first time

since October 2018 and EIA said it expects WTI to remain above

$60 per barrel through the end of 2022, “a price that has signaled

robust activity among U.S. operators in the past.”

By KRISTEN NELSON Petroleum News

Eni US Operating Co. has submitted its

15th plan of development for the

Oooguruk unit on the North Slope to the

Alaska Division of Oil and Gas. The 15th

POD covers Oct. 1, 2021, through Sept. 30,

2022. The submittal also includes a summa-

ry of plans for the 14th POD, Oct. 1, 2020,

through Sept. 30, 2021, and work accom-

plished or planned before the end of that

POD.

Eni took over as operator at Oooguruk

from Caelus Natural Resources Alaska

effective Aug. 1, 2019, Eni said. The unit

was formed in 2003 and presently consists

of 16 state leases, some 35,271 acres, with

cumulative production from three participat-

ing areas through May totaling 43.8 million

barrels of oil, and Oooguruk production

averaging 7,020 barrels per day from

January through May 31 of this year.

Eni said the automatic 10-year contrac-

tion (to just areas under production) for

Oooguruk has been revised by the

Department of Natural Resources, delaying

that date to Sept. 30, 2022.

14th POD Eni said that during the 14th POD “capi-

tal investment and development activities

continued to be affected by the low crude oil

prices, lack of demand for oil, and the logis-

tical interference of the COVID-19 pandem-

ic resulting in budget cuts, production cur-

tailments and project deferrals.”

In the three participating areas at

Oooguruk — the Oooguruk Nuiqsut PA,

Oooguruk Kuparuk PA and Oooguruk

Torok PA — there are 37 development wells

and a disposal well. There are also four well

completions outside of existing Oooguruk

PAs, two appraisal wells (one plugged and

abandoned), a Kuparuk test and an explo-

ration well, Sikumi 1 (P&A).

Eni said active development wells

include 23 oil producers (18 Nuiqsut, three

Kuparuk and two Torok), 13 injectors (10

Nuiqsut, two Kuparuk and one Torok) and

the one disposal well, with the producers —

with one exception — requiring gas lift to

produce, limited to some 15 million cubic

feet per day. There is also some 10 million

cfpd in formation gas.

The back-out cost at Kuparuk (Oooguruk

crude is processed at Kuparuk’s Central

Processing Facility 3) is significant, Eni

said, describing KRU as “primarily con-

strained by gas compression capacity,” so

KRU fluid production is backed out when

then high total gas oil ratio Oooguruk unit

fluids enter the system.

The high gas lift rate and Oooguruk for-

mation gas increase flowline pressure, and

that, combined with KRU back-out, means

all Oooguruk wells cannot be produced at

the same time using gas lift. During 2020, an

average of 12 of the producing 23 Oooguruk

wells were on line with total gas oil ratio

ranking typically determining which wells

are produced, the company said.

Eni discussed plans for additional wells

at only one of the PAs, Nuiqsut. The compa-

ny said future development plans include 12

additional Nuiqsut PA wells, with eight from

available well slots and four from reclaimed

well slots.

The company said it had planned several

workovers “to recomplete shut-in or low

performing wells prior to drilling planned

new wells in 2021” in the 14th POD but

those plans have been deferred due to low

crude oil prices, lack of demand for oil and

COVID-19 logistical interference.

The company did do a number of rigless

well interventions and maintenance opera-

tions.

14th POD facilities Eni said routine operations during the

14th POD included general maintenance

and replacement of critical oil, water and gas

piping and valves, along with field-wide

maintenance and routine maintenance on

the three power generation turbines and two

gas injection compressors at the onshore

Oooguruk Tie-in Pad. Cathodic protections

inspections were completed on the sub-sea

production flowline from the offshore

Oooguruk Drill Site to the tie-in pad, along

with a mandatory U.S. Department of

Transportation hydrotest.

In addition to some minor capital proj-

ects, major capital projects included finaliz-

ing commissioning and startup of the seawa-

ter injection system booster pump upgrade

at the drill site.

An engineering feasibility study was

completed for 20 million standard cubic feet

per day partial gas procession at the tie-in

“to mitigate gas processing constraints and

reduce associated costs from KRU CPF-3.”

That project received final Eni approval

with detailed engineering beginning in June

and startup forecast for 2023.

During the 14th POD Eni completed an

electrical power sharing feasibility study “to

consider interconnecting the Oooguruk and

Nikaitchuq power generation system to

allow a more robust and efficient power sys-

tem sharing between the two development

projects,” with financial approval in process

and startup forecast for 2023, once the proj-

ect is approved.

15th POD proposed operations Eni said there will be no significant

maintenance turnaround at Oooguruk dur-

ing the 15th POD. A number of minor cap-

ital projects are being evaluated.

Major capital projects include the partial

gas processing project, with engineering and

fabrication efforts planned to install 20 mil-

lion cfpd of on-site gas processing and com-

pression at the tie-in pad, “to mitigate gas

processing constraints and reduce associated

costs from CPF-3,” with project startup

scheduled for 2023.

Eni said it expects financial approval for

the electrical power sharing project, with

detailed design and fabrication in this POD

period and, once the project is approved,

startup scheduled for 2023.

Two rig workovers are planned for the

15th POD with drilling activities forecast to

be reactivated after 2025 based on maturity

of the partial gas processing project.

A table or proposed drilling activity

shows: two wells in 2025; three wells in

2026; three wells in 2027; and two extended

reach wells possible in 2028.

About those wells, Eni said it is evaluat-

ing two appraisal wells targeting the north-

ern Nuiqsut reservoir to test the productivity

and oil quality in leases northeast of existing

participating areas. The wells, designated

ERD-N01 and ERD-N02, are Eni said,

within the proven drilling radius, some

22,000 feet from the drilling island. l

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

Oooguruk focused on facilities, workovers New drilling deferred to completion of partial gas processing to mitigate gas constraints, reduce costs from Kuparuk River CPF-3

PETROLEUM NEWS • WEEK OF JULY 11, 2021 5

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ELKO buys chunk 88 Energy shares; divers prepare for Arctic threats

page

3

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

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

Vol. 26, No. 13 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 28, 2021 • $2.50

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

see LOW-CARBON ENERGY page 10

Canada, Germany, pursuing net-zero carbon emissions, team on hydrogen Canada and Germany have formed a partnership to enter the global race to produce and sell hydrogen in the market for low-carbon energy, with Germany already strongly placed in the world’s largest markets for alternative fuels. Energy ministers for the two countries signed a memorandum of understanding earlier in March to cooperate on energy policy and research as they strive to achieve net-zero greenhouse gas emissions by 2050.

But what they have not yet agreed to is what type of hydrogen

Economics crucial Sourdough uneconomic with 40% Alaska NPSL tax; Dunleavy bills update law

By KAY CASHMAN Petroleum News

P lanning and permitting for Jade Energy’s 2022 winter drilling in the

eastern North Slope Sourdough prospect is “on track and expected to accelerate” as ELKO International team members complete Emerald House’s (88 Energy) drilling operations at the Merlin 1 explo-ration well, says Erik Opstad who is 100% owner of Jade parent ELKO.

That said, one of the project’s remaining major hurdles is the fact that Sourdough development is not economic while burdened with a 40% state net profit share lease tax, a 12.5% royalty, “plus other

commercial limitations currently associ-ated with ADL 343112,” Opstad told Petroleum News March 19.

Jade is working with Sourdough stakeholders, he said, and making progress toward the mitigation of these limiting commercial issues, but there is still “some way to go.”

A net profit share lease, or NPSL, requires the lessee to pay the state a share of net profits — in addition to a tradition-al royalty percentage, the Alaska Department of Natural Resources’ Division of Oil and Gas said in a February presentation to the Alaska Senate

Ship blocks Suez Canal Prices jump after container ship lodges sideways in narrow entry from Red Sea

By STEVE SUTHERLIN Petroleum News

Alaska North Slope crude rocketed upward March 24 by $3.22, closing at $64.38 per bar-rel. West Texas Intermediate added $4.12 on the day to close at $61, while Brent closed at $64.41 for a gain of $3.62.

The gains largely erased losses from the previ-ous day, when prices closed sharply lower in a continuation of a price correction that struck after strong gains in early March capped a rally of over 30% since the beginning of the year. ANS fell $3.60 March 23 to $61, Brent fell $3.83 to $60.79 and WTI fell $3.79 to $57.76. The rally March 24 was sparked after the

Panama-flagged MV Ever Given — one of the world’s largest container ships — lodged sideways in the Suez Canal March 23, blocking all ship traf-fic from traversing the waterway. Taiwan-based Evergreen Marine Corp., the ship’s operator, said in a statement that the Ever

Targeting oil sands US lawmakers propose taxing Canadian crude; critics warn impact on pump prices

By GARY PARK For Petroleum News

In the less than three months since he occupied the White House, President Joe Biden has found himself at the center of more energy showdowns between the U.S. and Canada than either of his predecessors over the previous decade. To date, the cross-border feuding has involved Keystone XL, and Enbridge’s projects to spend billions of dollars upgrading Line 5 and Line 3, which deliver a combined 1.2 million barrels per day of Western Canadian crude to the U.S. Midwest and Ontario.

The stir the pot even more, two Democratic lawmakers have floated a bill that would slap an

excise tax on oil sands crude being shipped into the northern U.S. to build a fund for cleaning up any spills of crude.

The proposed law is being spearheaded by Earl Blumenauer (an Oregon member of the House of Representatives) and Ed Markey (a Massachusetts senator), both close allies of Biden, who has made

see SOURDOUGH PROSPECT page 8

see OIL PRICES page 11

see EXCISE TAX page 11

Vol. 26, No. 1 March 2021

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

Oil & Gas Directory

Latest Arctic Directory released

see MERLIN 1 page 12

Surface casing installed at 88 Energy’s Merlin 1 Nanushuk well 88 Energy’s Merlin 1 exploration well in the National Petroleum Reserve-Alaska has reached a depth of 1,512 feet, the company announced March 22. Surface casing has been cemented in place and the blowout preventer system has been tested. Following a successful formation integrity test, All American Oilfield’s Rig 111 is now continuing to drill towards targets in the Nanushuk formation. The planned total depth for the well is 6,000 feet.

see PROFIT SHARE BILL page 10

Amended version of net profit share bill clears House Resources A bill sponsored by Gov. Mike Dunleavy to provide the commissioner of the Department of Natural Resources author-ity to modify the profit share percentage in net profit share leases was amended and passed out of the House Resources Committee March 22. The companion bill in the Senate has been heard twice and is still in Senate Resources.

Both bills have referrals to Finance. House Bill 81 had not been scheduled for a hearing in House Finance when this issue of Petroleum News went to press; no additional hearings had

ERIK OPSTAD

Vortexa said the approximate rate of backlog is approximately 50 vessels per day and any delays leading to re-routings add 15 days to a Middle East to Europe voyage.

Canadian energy lawyers and industry observers estimate the cost could run to 5.5 cents a barrel raising the total tax burden on every barrel of diluted bitumen sold into the U.S. to 9 cents.

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6 PETROLEUM NEWS • WEEK OF JULY 11, 2021

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US rotary rig count at 475, a gain of 5 By KRISTEN NELSON

Petroleum News

The Baker Hughes U.S. rotary drilling rig count

stood at 475 the week ending July 2, a gain of five

from the previous week and up by 212 from 263 a year

ago.

When the count bottomed out at 244 in mid-August

last year, it was not just the low for 2020, but the lowest

the count has been since the Houston based oilfield serv-

ices company began issuing weekly U.S. numbers in

1944.

Prior to 2020, the low was 404 rigs in May 2016. The

count peaked at 4,530 in 1981.

The count was in the low 790s at the beginning of

2020, 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.

The July 2 count includes 376 rigs targeting oil, up by

four from the previous week and up 191 from 185 a year

ago, 99 rigs targeting gas, up by one from the previous

week and up by 23 from 76 a year ago, and no miscella-

neous rigs, unchanged from the previous week and down

by two from a year ago.

Thirty of the rigs reported July 2 were drilling direc-

tional wells, 429 were drilling horizontal wells and 16

were drilling vertical wells.

Alaska rig count unchanged The Colorado rig count (13) was up by three from the

previous week.

North Dakota (18), Pennsylvania (19) and Texas

(222) were each up by a single rig.

Wyoming (9) was down by one rig.

Rig counts in all other states were unchanged from the

previous week: Alaska (4), California (6), Louisiana

(52), New Mexico (75), Ohio (9), Oklahoma (27), Utah

(10) and West Virginia (9).

Baker Hughes shows Alaska with four rigs active July

2, unchanged from the previous week and up one from a

year ago, when the state’s count stood at three.

The rig count in the Permian, the most active basin in

the country, was up by one from the previous week at

237 and up by 111 from a count of 126 a year ago.

International count up by 8 The international rig count, which excludes U.S. and

Canada counts, was 758 in June, Baker Hughes said July

2, up by eight rigs from May, with one additional land rig

(572) and seven additional offshore rigs (186).

The international count is down 23 from June 2020,

when the count stood at 781, with land rigs down 15 and

offshore rigs down eight.

The June international average by area was Middle

East at 262, followed by 183 rigs active in Asia Pacific,

143 in Latin America, 105 in Europe and 65 in Africa.

The U.S. rig count averaged 464 in June, up 11 from

May’s average and up 190 year-over-year. The Canadian

rig count averaged 103 in June, up 44 from May’s aver-

age and up by 85 from June 2020.

The worldwide rig count, international and North

America, was 1,325 in June, up by 63 from 1,262 in May

and up 252 from 1,073 in June 2020.

Baker Hughes initiated the monthly international rig

count in 1975. l

l G O V E R N M E N T

Boom in Native American oil a complication Production up tenfold from Native lands since 2009, now some 3% of US production, complicating Bush administration climate push

By MATTHEW BROWN & FELICIA FONSECA Associated Press

On oil well pads carved from the wheat fields around

Lake Sakakawea, hundreds of pump jacks slowly

bob to extract 100 million barrels of crude annually from a

reservation shared by three Native American tribes.

About half their 16,000 members live on the Fort

Berthold Indian Reservation atop one of the biggest U.S.

oil discoveries in decades, North Dakota’s Bakken shale

formation.

The drilling rush has brought the tribes unimagined

wealth — more than $1.5 billion and counting — and they

hope it will last another 20 to 25 years. The boom also pro-

pelled an almost tenfold spike in oil production from

Native American lands since 2009, federal data shows,

complicating efforts by President Joe Biden to curb carbon

emissions.

Burning of oil from tribal lands overseen by the U.S.

government now produces greenhouse gases equivalent to

about 12 million vehicles a year, according to an

Associated Press analysis. But Biden exempted Native

American lands from a suspension of new oil and gas leas-

es on government-managed land in deference to tribes’

sovereign status.

A judge in Louisiana temporarily blocked the suspen-

sion June 15, but the administration continues to develop

plans that could extend the ban or make leases more costly.

More than 3% With tribal lands now producing more than 3% of U.S.

oil and huge reserves untapped, Interior Secretary Deb

Haaland — the first Native American to lead a U.S. cabi-

net-level agency — faces competing pressures to help a

small number of tribes develop their fossil fuels while also

addressing climate change that affects all Native commu-

nities.

“We’re one of the few tribes that have elected to devel-

op our energy resources. That’s our right,” tribal Chairman

Mark Fox told AP at the opening of a Fort Berthold muse-

um and cultural center built with oil revenue. “We can

develop those resources and do it responsibly so our chil-

dren and grandchildren for the next 100 years have some-

where to live.”

Smallpox nearly wiped out the Mandan, Hidatsa and

Arikara tribes in the mid-1800s. They lost most of their ter-

ritory to broken treaties — and a century later, their best

remaining lands along the Missouri River were flooded

when the U.S. Army Corps of Engineers created Lake

Sakakawea. With dozens of villages uprooted, many peo-

ple moved to a replacement community above the lake —

New Town.

Today, leaders of the three tribes view oil as their salva-

tion and want to keep drilling before it’s depleted and the

world moves past fossil fuels.

And they want the Biden administration to speed up

drilling permits and fend off efforts to shut down a pipeline

carrying most reservation oil to refineries.

Pipeline fight Yet tribes left out of the drilling boom have become

see OIL BOOM page 7

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outspoken against fossil fuels as climate change wors-

ens. One is the Standing Rock Sioux about 100 miles to

the south.

Home to the Dakota and Lakota nations, Standing

Rock gained prominence during a months-long standoff

between law enforcement and protesters, including tribal

officials, who tried to shut down the Dakota Access

Pipeline that carries Fort Berthold crude.

A judge revoked the pipeline’s government permit

because of inadequate environmental analysis and

allowed crude to flow during a new review. But Standing

Rock wants the administration to halt the oil for good,

fearing a pipeline break could contaminate its drinking

water.

Meantime, attention surrounding the skirmish provid-

ed the Sioux with foundation backing to develop a wind

farm in Porcupine Hills, an area of scrub oak and buffalo

grass with cattle ranches.

The pipeline fight stirs bitter memories in Fawn Wasin

Zi, a teacher who chairs the Standing Rock renewable

power authority. She grew up hearing her father and

grandmother tell about a government dam that created

Lake Oahe — how they had to leave their home then

watch government agents burn it, only to be denied hous-

ing, electricity and other promised compensation.

Wasin Zi, whose ancestors followed legendary Lakota

leader Sitting Bull, wants to ensure the tribe doesn’t fall

victim yet again to a changing world, where fossil fuels

warm the planet and bring drought and wildfire.

“We have to find a way to use the technology that’s

available right now, whether it’s geothermal or solar or

wind,” she said.

Only a dozen of the 326 tribal reservations produce

significant oil, according to a drilling analysis provided to

AP by S&P Global Platts.

Biden’s nominee to oversee them as assistant secretary

for Indian affairs, Bryan Newland, recently told a U.S.

Senate committee the administration recognizes the

importance of oil and gas to some reservations and

pledged to let tribes determine resource development.

Interior officials denied interview requests about tribal

energy plans, but said tribes were consulted in April after

Biden ordered the department to “engage with tribal

authorities” on developing renewables and fossil fuels.

Joseph McNeill Jr., manager of Standing Rock’s ener-

gy authority, said a conference call with Interior yielded

no pledges to further the tribe’s wind project. Fort

Berthold officials said they’ve had no offers of discus-

sions with the administration.

One tribe’s building boom Fort Berthold still reels from ills oil brought — worse

crime and drugs, tanker truck traffic, road fatalities, spills

of oil and wastewater. Tribal members lament that stars

are lost in the glare of flaring waste gas from wells.

Yet oil brought positive changes, too. As the tribes’

coffers fattened, dozens of projects got underway. The

reservation now boasts new schools, senior centers,

parks, civic centers, health and drug rehab facilities. Oil

money is building a $26 million greenhouse complex

heated by electricity from gas otherwise wasted.

The $30 million cultural center in New Town pieces

together the tribes’ fractured past through displays and

artifacts. A sound studio captures stories from elders who

lived through dam construction and flooding along the

Missouri. And one exhibit traces the oil boom after frack-

ing allowed companies to tap reserves once too difficult

to drill.

“Our little town, New Town, changed overnight,” said

MHA Nation Interpretive Center Director Delphine

Baker. “We never had traffic lights growing up. It’s like I

moved to a different town.”

Hoping for ‘morning light’ Lower on the Missouri, Standing Rock grapples with

high energy costs. There’s no oil worth extracting, no gas

or coal. The biggest employer beside tribal government is

a casino, where revenue plummeted during the pandemic.

“There’s nothing here. No jobs. Nothing,” said Donald

Whitelightning Jr., who lives in Cannon Ball, near the

Dakota Access Pipeline protest.

Whitelightning, who cares for his mother in a modest

home, said he pays up to $500 a month for electricity in

winter. Utility costs, among North Dakota’s highest,

severely strain a reservation officials say has 40% pover-

ty and 75% unemployment.

The tribe hopes its wind project, Anpetu Wi, meaning

“morning light,” will help. Officials predict its 235

megawatts — enough for roughly 94,000 homes —

would double their annual revenue and fund benefits like

those Fort Berthold derives from oil — housing, health

care, more jobs.

Standing Rock’s power authority can directly negoti-

ate aspects of the project. Yet it needs Interior approval

because the U.S. holds tribal lands in trust.

‘An oil field to protect’ Outside North Dakota, tribes with oil — the Osage in

Oklahoma, the Navajo in the Southwest and Native cor-

porations in Alaska — also are pushing the Biden admin-

istration to cede power over energy development, includ-

ing letting tribes conduct environmental reviews.

A Navajo company’s operations in the Aneth field in

southern Utah bring about $28 million to $35 million

annually. Active since the 1950s, the field likely has

another 30 years of life, said James McClure, chief exec-

utive of the Navajo Nation Oil and Gas Co.

The company has considered expanding into federal

land in New Mexico and Colorado. Biden’s attempts to

suspend new leases could slow those plans, and it’s con-

sidering helium production as an option.

In northern Oklahoma, the Osage have been drilling

oil for more than a century.

Cognizant of global warming and shifting energy mar-

kets, they are pondering renewables, too. For now, they

want the Biden administration to speed up drilling per-

mits.

“We are looking at what is going to be best for us,”

said Everett Waller, chairman of the tribe’s energy regu-

lator. “I wasn’t given a wind turbine. I was given an oil

field to protect.” l

continued from page 6

OIL BOOMWith tribal lands now producing more than 3% of U.S. oil and huge reserves untapped, Interior

Secretary Deb Haaland — the first Native American to lead a U.S. cabinet-level agency —

faces competing pressures to help a small number of tribes develop their fossil fuels while also addressing climate change that affects all

Native communities.

a larger increase in its own production

under the supply cut agreement, but Saudi

Arabia refused the demands.

Instead, the meeting was delayed and

extended, and then postponed indefinitely.

“The 18th OPEC and non-OPEC

Ministerial Meeting has been called off,”

OPEC Secretary General Mohammad

Sanusi Barkindo said in a July 5 letter to

heads of delegation of OPEC member

countries and non-OPEC oil producing

countries participating in the OPEC +

Declaration of Cooperation.

“The date of the next meeting will be

decided in due course, and we will inform

you accordingly,” Barkindo said.

Brent prices rose initially on the can-

cellation announcement July 5, before

turning lower in volatile trading. U.S.

markets were closed due to the July 4 hol-

iday.

WTI and Brent continued trading

lower as Petroleum News went to press

early on July 8. WTI was down 52 cents

to $71.68, while Brent fell 43 cents to $73

at 7:20 a.m. CDT.

The slide was swift and substantial. On

July 2, ANS ended the week on a high, up

30 cents to close at $76.83, WTI fell 7

cents to close at $75.16, and Brent rose 33

cents to close at $76.17.

Future direction uncertain The turmoil surrounding the OPEC+

negotiations will likely affect prices, per-

haps quite dramatically, in the future, and

the price direction is an unknown, accord-

ing to former U.S. Energy Secretary Dan

Brouillette.

“You could very easily see oil hitting

$100 a barrel — potentially even higher,”

Brouillette said in a July 7 CNBC inter-

view, adding that it’s “equally possible”

that prices could collapse.

“If there isn’t any agreement on pro-

duction, and countries tend to go off and

do their own thing, or do their own pro-

duction, you could have a collapse of oil

prices,” Brouillette said.

The U.S. Energy Administration said

in a report released July 7 that it expects

production to increase by more than glob-

al oil consumption.

“We expect rising production will

reduce the persistent global oil inventory

draws that have occurred for much of the

past year and keep prices similar to cur-

rent levels, averaging $72 per barrel dur-

ing the second half of 2021,” The EIA

said. “However, in 2022, we expect that

continuing growth in production from

OPEC+ and accelerating growth in U.S.

tight oil production, along with other sup-

ply growth, will outpace growth in global

oil consumption and contribute to declin-

ing oil prices. Based on these factors, we

expect Brent to average $67/b in 2022.”

According to a Bloomberg report, The

8 PETROLEUM NEWS • WEEK OF JULY 11, 2021

in the region.

Other industrial operations, such as petrochemical

and fertilizer plans, will eventually gain access to the

system which will have capacity of 60,000 mt, represent-

ing about 10% of industrial emissions in the province.

Principal segments of the ACG include overhauling

an existing pipeline in northern Alberta, with initial

design capacity of 40,000 mt per day; a central leg retro-

fit to gather and deliver up to 20,000 mt a day; a south-

west leg with possible capacity of 20,000 mt a day; and

multiple opportunities to extend the grid into other

regions. In addition, a reservoir site has been selected

near Edmonton to sequester more than 2 billion mt of

CO2.

Cost not yet known Mick Dilger, chief executive officer of Pembina, said

the partners will not have an estimated overall cost until

more engineering studies are completed, although using

new pipelines could push the total investment to multi-

billions of dollars.

He told the Globe and Mail the partners are pledging

to create an “open access” system “with many receipt

points and many delivery points.”

“We’re going to make money on this, but we’re not

hanging our hats on this thing just to make money.

There’s a bigger purpose here.”

The companies say tolls on the system will be less

than the current price of carbon in Alberta, making its

use more attractive for prospective customers and help-

ing the grid’s long-term competitive viability.

The partnership will be open to other owners with

suitable existing infrastructure.

Capture greatest challenge Dilger said the greatest challenge will be to capture

rather than to transport and store the CO2.

“We just need to find a way to do it for less cost and

we’ll need help from the federal government on that

side,” he said.

Dilger said the plan is to meet the aims of the big oil

sands producers who announced in June that they have

formed a partnership to achieve net-zero greenhouse gas

emissions from their operations over the next 30 years.

Alberta already has one CO2 pipeline — the Alberta

Carbon Trunk Line — which captures industrial emis-

sions and delivers them to aging oil and gas reservoirs to

rebuild pressures to enhance oil recovery.

Robert Hope, an analyst at Scotiabank, said the car-

bon grid plan “is a positive for Alberta and the broader

energy industry for Canada.”

By increasing carbon capture, storage and utilization,

the carbon intensity of Canadian oil and gas will

decrease, boosting the industry’s “ability to attract capi-

tal and grow,” he said.

Scott said the partners willingness to add other infra-

structure owners should be applauded because shrinking

the industry’s carbon footprint “should have wide-rang-

ing benefits.”

Expansion of infrastructure holdings For Pembina, this is the latest corporate move to

expand its infrastructure holdings.

It has launched an C$8.3 billion bid to takeover Inter

Pipeline, while fending off a hostile counter offer by

Brookfield Infrastructure Partners.

In addition it has joined forces with Western

Indigenous Pipeline Group to prepare an offer for the

Trans Mountain Pipeline, which is engaged in a C$12.6

billion system expansion, and has announced it is buying

a 50% stake in the proposed Cedar LNG project on the

British Columbia coast to partner with the Haisla Nation.

—GARY PARK

continued from page 1

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OIL PRICES

see OIL PRICES page 10

line of Nanushuk discoveries.

North Slope geologists that Petroleum News spoke

to all said they thought Coyote was an extension of Oil

Search’s Mitquq Nanushuk discovery; a younger, shal-

lower interval than Nuna.

ConocoPhillips’ map in last week’s page 1 article

titled Advancing Alaska shows Coyote parallel to the

Narwhal trend, which is the name

the company uses to describe the

Pikka-Nanushuk trend and their

own adjacent Narwhal trend.

Two 2020 Mitquq exploration

penetrations discovered a separate

reservoir lying to the east and par-

allel with the Pikka Nanushuk

reservoir, its tentative length and

width similar to that of Pikka —

and west of Kuparuk.

It appears, however, that most

of the leases around the area that do not belong to Oil

Search are controlled by ConocoPhillips.

Isaacson said, “we will be taking a look at develop-

ing” Coyote, which he also said could be developed

using Kuparuk infrastructure.

The Nanushuk up in the area of ConocoPhillips

leases has “typically been pretty shaley and has vary-

ing gravities of crude oils due to the mixing of source

rocks. But ConocoPhillips’ Coyote announcement tells

me they see something encouraging or they wouldn’t

be talking about it,” another long-time North Slope

geologist said.

North Slope discoveries in the Nanushuk formation

started in 2015, when innovative explorers Armstrong

Oil & Gas and Repsol E&P USA made their Pikka dis-

covery east of the Colville Delta.

ConocoPhillips followed with its Willow discovery

in 2016, and in 2017 Armstrong and Repsol successful-

ly drilled the Horseshoe No. 1, confirming that the

Nanushuk topset trend extended south from Pikka.

In 2018, ConocoPhillips discovered West Willow

while following up on information from its Putu and

Stony Hill wells to define their Narwhal trend.

When asked whether ConocoPhillips Narwhal wells

Putu and Stony Hill were in the Nanushuk formation,

U.S. Geological Survey geologist Dave Houseknecht

told Petroleum News in 2018 that they were. He had

previously said Willow was also a Nanushuk discovery.

—KAY CASHMAN

Alaska sues Biden administration ON JULY 7, THE 63RD ANNIVERSARY of the sign-

ing of the Alaska Statehood Act, Alaska Gov. Mike

Dunleavy announced the State of Alaska is suing the

U.S. Department of the Interior for “illegally and

unjustifiably extending decades-long restrictions on

nearly 28 million acres of federal land in Alaska.”

The action by Interior Secretary Deb Haaland

“blocks state land selections and Alaska Native

Vietnam Veteran allotments,” the governor’s press

release said.

“This is a methodical effort by the Biden adminis-

tration — more than just bureaucratic foot dragging —

to frustrate ANILCA and the Statehood land entitle-

ment and leave these lands locked up as de facto

parks,” said Dunleavy. “They are consciously ignoring

and going around appropriate processes to hold things

in perpetual limbo. It has needed to be challenged for a

long time and it needs to be challenged now more than

ever due to these new delays — and I am challenging

it. The intent of ANILCA matters, these unnecessary

withdrawals need to be lifted, and we need to finally

move this process forward. This is another federal

attempt to deny Alaska the full realization as a state

promised under our Statehood Compact, and it should

not stand.”

The Dunleavy administration contends that the

withdrawals have prevented Alaska from exercising its

Statehood right to claim valuable lands or assess the

natural resources on these lands.

Under a 1971 federal law, the secretary could issue

temporary land withdrawals to restrict the use of feder-

al land in Alaska to allow Interior time to determine

how federal lands should be used in the state. Many of

these 1970s-era orders have never been lifted even

though the “reasons for the withdrawals have been sat-

isfied for decades,” Dunleavy’s press release said.

Under 16 such orders, about 28 million acres of

land have “sat under outdated restrictions, all the while

with the federal government proposing that the with-

drawals be lifted but never doing so.”

In 2006, Interior’s Bureau of Land Management

reported to Congress that the temporary withdrawals

“could be lifted on over nearly all these areas without

affecting the public interest. Following that report,

BLM has completed numerous, multi-year reviews and

land-use plans, each recommending that the with-

drawals be lifted. In January of this year, then-Interior

Secretary David Bernhardt issued orders based on

these extensive analyses to finally lift these 16 land

withdrawals from about 28 million acres,” the

Dunleavy release said.

Shortly after assuming office, however, President

Biden’s new Interior Secretary, Deb Haaland,

announced she was unilaterally repealing Secretary

Bernhardt’s actions from taking affect for at least two

years, explaining that Interior needed to conduct even

more analyses of environmental, endangered species,

historical preservation, and military land use laws —

analyses that “BLM, itself, said it had already complet-

ed or were unnecessary.”

“Any reasonable grounds for withdrawing this land

expired long ago, and this renewed delay is entirely

unjustified. Interior’s final decision in January to end

those withdrawals was both appropriate and long over-

due,” said Attorney General Treg Taylor.

The state’s lawsuit asks the federal district court in

Alaska to prevent Interior from continuing to delay the

January 2021 orders and to direct the department to lift

the 16 withdrawals immediately.

—PETROLEUM NEWS

AEA, AIDEA appointments ALASKA GOV. MIKE DUNLEAVY announced the

appointment of 38 Alaskans to various state of Alaska

boards and commissions on July 7, including the reap-

pointment of John “Dana” Pruhs of Anchorage to both

the Alaska Energy Authority and the Alaska Industrial

Development and Export Authority. The new terms are

effective July 1 and run through July 1, 2023.

David Eisenberg of Anchorage was appointed by the

governor to the Alaska Royalty Oil and Gas

Development Board. His term will run from May 20,

2021, through June 30, 2025.

—PETROLEUM NEWS

PETROLEUM NEWS • WEEK OF JULY 11, 2021 9

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

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N-P Nabors Alaska Drilling NANA Worley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8 Nature Conservancy, The NEI Fluid Technology Nordic Calista . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11 North Slope Borough North Slope Telecom Northern Air Cargo Northern Solutions NRC Alaska, a US Ecology Co. Oil Search PND Engineers, Inc. PRA (Petrotechnical Resources of Alaska) . . . . . . . . . . . . . .2 Price Gregory International

Q-Z

Raven Alaska – Jon Adler Resource Development Council SALA Remote Medics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5 SeaTac Marine Services Security Aviation Shoreside Petroleum Soloy Helicopters Sourdough Express Strategic Action Associates Tanks-A-Lot Weston Solutions Wolfpack Land Co. Yukon Fire Protection

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

continued from page 1

INSIDER

EREC ISAACSON

10 PETROLEUM NEWS • WEEK OF JULY 11, 2021

and called a C$149 million loan made to A2A by

Bridging Finance.

In the course of an investigation by the Ontario

Securities Commission, OSC, numerous financial irreg-

ularities surrounding dealings by A2A founder Sean

McCoshen with Bridging were uncovered.

McCoshen issues McCoshen’s name has since been eliminated from

A2A’s website. A2A has said he will not be involved in

the process of finding other investors.

The company said that despite its lender’s receiver-

ship, it “believes the A2A rail project is sound and has

already made significant progress toward full financing,

above and beyond the development capital provided by

Bridging Finance …”

The OSC said one of McCoshen’s companies made

C$19.5 million in undisclosed payments to the personal

checking account of Bridging’s Chief Executive Officer

David Sharpe. Over the same period Bridging loaned

more than C$100 million to McCoshen’s other compa-

nies.

In addition, millions of dollars pledged for A2A were

directed into McCoshen’s personal bank account and to

an apparently unrelated company controlled by him.

Emails destroyed PwC also alleged that Sharpe asked an employee at

Bridging to destroy an estimated 34,000 emails amid

queries from the OSC and has called for repayment of

the largest loan on its books.

In a recent report to the court, PwC said a Bridging

employee disclosed that Sharpe instructed the employee

to appear at Bridging’s office on numerous occasions

last year and conduct “searches for emails to be delet-

ed.”

PwC said in a letter to about 26,000 Bridging

investors that the email deletions appeared to be “inten-

tional and targeted. Our forensics team is working to

recover those emails, if and wherever possible, and we

expect to report further on this once those efforts are

complete.”

Issues of concern with loan The receiver said in the letter to investors that it has

identified several “issues of concern” with Bridging’s

latest outstanding loan to A2A.

Bridging’s outstanding loans to A2A total C$208 mil-

lion, while Bridging has an equity stake in the company

that it has valued at C$109 million.

Citing transactions that “appear to be outside of the

normal course of business of Bridging,” PwC has

demanded that A2A repay its loans.

In an emailed statement to the Globe and Mail, an

attorney for Sharpe said the receiver’s comments have

impugned the rail project and are not in the interest of

Bridging’s investors.

“The railway is a critically important infrastructure

project to the Indigenous people and Canada more

broadly and, unless handled strategically, this receiver-

ship imperils its completion,” the attorney said.

She said multiple unnamed businesses have

expressed interest in purchasing the assets of Bridging.

One of the proudest claims of A2A was its intention

to make Indigenous communities in Alaska and Canada

key players in the rail project.

But that effort may already be in danger of unravel-

ling, with the Acho Dene Koe First Nation pulling out of

discussions with A2A.

In a new release it questioned the project’s financial

stability, credibility and viability.

If built the railroad has been forecast to cost upwards

of C$22 billion and accelerate the movement of goods

between Asia and North America. l

continued from page 1

A2A TROUBLE

notice, “will include an upstream analysis of potential

environmental impacts associated with natural gas pro-

duction on the North Slope of Alaska.” The SEIS will

also include a life cycle analysis “calculating the GHG

emissions for LNG exported from the proposed Alaska

LNG Project, taking into account unique issues relating

to production, pipeline transportation, and liquefaction

in Alaska.”

DOE said the life cycle analysis “will examine the life

cycle GHG emissions for LNG exported from Alaska by

vessel to import markets in Asia (the markets targeted for

exports from Alaska) and potentially in other regions.”

DOE has commissioned its National Energy

Technology Laboratory to conduct the studies.

In August 2020 DOE issued the Alaska LNG Order

under the Natural Gas Act to Alaska LNG Project LLC

whose member companies are ExxonMobil Alaska LNG

LLC, ConocoPhillips Alaska LNG Co. and Hilcorp

Alaska LLC.

Currently, DOE said, AGDC holds the FERC author-

ization for the Alaska LNG Project and Alaska LNG

holds DOE authorization for exports from the project.

AGDC has said it is in negotiations to obtain an option

to purchase Alaska LNG.

Rehearing request Sierra Club filed a request for rehearing in September

and in October DOE issued a notice providing for further

consideration of the request and of AGDC’s motion to

answer.

In December, Sierra Club filed a petition for review of

the Alaska LNG Order in the U.S. Court of Appeals for

the District of Columbia Circuit. Sierra Club and the

Center for Biological Diversity have also petitioned for

review of FERC’s order for the Alaska LNG Project.

On April 15, DOE said, the D.C. Circuit issued a con-

solidated order in both cases, denying a motion to con-

solidate the DOE and FERC cases. DOE said its certified

index to the administrative record was due April 19.

In its April 15 ruling DOE granted Sierra Club’s

rehearing request.

DOE said the request is granted to conduct “two

Alaska-specific environmental studies,” the life cycle

analysis and “an upstream study examining aspects of

natural gas production on the North Slope of Alaska.”

Since the issuance of DOE’s Alaska LNG Order,

President Joe Biden issued Executive Order 13990

directing agencies to review regulations, orders and

other actions issued after Jan. 20, 2017, that may

increase GHG emissions or otherwise impact climate

change. On Jan. 27 the president issued E.O. 14008

which set forth additional policies to address climate

change.

To comply with the executive orders, DOE said it is

necessary to “further evaluate the environmental impacts

of exporting LNG from the proposed Alaska LNG

Project to non-FTA countries.”

The life cycle analysis is necessary, DOE said, to fully

address Sierra Club’s arguments that production, trans-

portation and liquefaction issue “in Alaska are unique

and require specific analysis.”

And second, in response to Sierra Club’s arguments

concerning natural gas production on the North Slope,

DOE said it “has determined that it is prudent to com-

mission an environmental study examining potential

‘upstream’ impacts associated with any incremental nat-

ural gas production on the North Slope of Alaska for

exports of LNG.”

North Slope natural gas is extracted during oil pro-

duction and reinjected to maintain reservoir pressure

and enhance oil recovery, DOE said, and because of that

the “study on natural gas production also is expected to

evaluate potential environmental impacts associated

with diverting North Slope natural gas for the purpose of

liquefaction and export — a change in use that would be

made possible by the construction of the Alasa LNG

Project’s pipeline connecting the North Slope production

fields to the planned Liquefaction Facility.”

DOE said it would provide notice of the availability

of each study in the docket for the proceeding and in the

Federal Register and invite public comments on both

studies.

Order not withdrawn Sierra Club had also requested that the existing order

be withdrawn during the study proceeding, but DOE

denied that request, saying it found no evidence that

leaving the order in effect during the study proceeding

would harm or otherwise impact Sierra Club’s interest

and rights.

The project remains in a proposed phase, DOE said,

and construction is not imminent. The project sponsor,

AGDC, has not made a final investment decision, and

recently told DOE that the project could be operational

six years after the beginning of construction.

DOE said it saw no evidence construction would

begin while the studies were being done.

—KRISTEN NELSON

continued from page 1

LNG REHEARING

EIA said that the forecast was completed on

July 1, before OPEC+ cancelled its meet-

ing, but that it still expects OPEC+ to con-

tinue to increase production beyond July.

U.S. shale producers have been tread-

ing lightly, “notably restrained so far this

year even as oil surged past $70 a barrel,”

Reuters reported July 7. “They have

maintained a lower level of production

after vowing to investors that they would

hold the line on spending to boost

returns.”

Shale companies have been actively

hedging this year, but many have been

burned. A group of 53 producers followed

by Wood Mackenzie have combined loss-

es of $3.2 billion in the first quarter on

hedge contracts. The group has hedged

32% of expected 2021 production vol-

umes, less than at the same time a year

ago.

WoodMac said producers were likely

to leave remaining 2021 production

unhedged, sell at current prices, and focus

their hedges on 2022.

Air travel hits 2019 levels The U.S. Transportation Security

Administration said it screened more than

10.1 million travelers over the Fourth of

July holiday weekend, which includes

traveler screenings from July 1 to July 5.

“This milestone represents 83% of

travel volume for the same 5-day holiday

period in 2019,” the TSA said.

July 1 was the busiest day of the week-

end. TSA screened 2,147,090 people,

103% of the 2,088,760 travelers screened

on Thursday of Fourth of July weekend in

2019.

“This holiday weekend, TSA saw over

10 million passengers travel safely

through security checkpoints,” TSA

Administrator David Pekoske said. “With

some airports already exceeding 2019

travel volumes and many not far behind,

we expect the summer to remain busy for

travel.”

Jet fuel demand has been a pandemic

recovery laggard compared to gasoline

and motor fuel demand. l

continued from page 8

OIL PRICESShale companies have been

actively hedging this year, but many have been burned. A group of 53 producers followed by Wood Mackenzie have combined losses of $3.2 billion in the first quarter on hedge contracts. The group has

hedged 32% of expected 2021 production volumes, less than at

the same time a year ago.

Contact Steve Sutherlin at ssutherlin@petroleumnews.com

OI13-03, OP16-03, OI20-07, OI06-05,

OP09-S1.

Eni currently has plans to drill five wells

(four grassroots and one sidetrack) during

the 14th POD. The injector SI02-SE6 of the

original development plan is scheduled to

be drilled Q4 2021 and will help support

the SP01-SE7 and SP04-SE5 producers,

Eni said in its proposed 14th POD.

Two new production wells and an injec-

tion well are also planned to be completed

as part of the northeast extension during the

14th POD period. A second lateral is tenta-

tively planned to be added to SP05-FN7.

Currently, Doyon 15 Rig is completing a

series of workovers at SID as part of the

13th POD.

Plant maintenance shutdown Well operations are planned to continue

until July 2021 when all rig operations will

be suspended in preparation for the produc-

tion plant’s scheduled 10-year maintenance

shutdown and the arrival of materials to

continue workover and drilling operations.

For the 14th POD period from Oct. 1

through Sept. 30, 2022, well operations

will include the following (see Table 3 in

pdf and print versions of this story):

• Doyon 15 workovers in SID.

• Nordic Calista 4 workover activities in

OPP.

• Drilling activities currently approved

from SID.

• No new drilling activities are currently

approved from OPP.

Reservoir management plans Eni said that reservoir management

activities will continue in the Schrader

Bluff participating area, or SBPA, with the

following objectives:

• Maximize daily volumes and value by

optimizing hydrocarbon production.

• Minimize risk exposure to key produc-

ing wells and maintain well integrity.

• Continue the polymer injection test at

OPP through Q1 2022.

• Tracer sampling and interpretation in

the OP-I2 polymer pilot area.

• Proactively define and develop mitiga-

tion plans related to water production.

• Proactively acquire reservoir perform-

ance data critical to reservoir management

and overall recoverable volumes determi-

nation.

• Ensure timely execution of reservoir

surveillance plans, workovers, re-comple-

tions, and infill drilling.

• Update current reservoir simulations

and studies to reproduce the field behavior.

• Find cost-effective solutions to opti-

mize production.

Eni also said that a simulation model

will continue to be maintained and updated

to support the ongoing operations and

future development of the Schrader Bluff

OA reservoir. (The company has said the

top of the Schrader Bluff pool is the

Cretaceous shale below the Ugnu forma-

tion and the bottom of the pool is some 45

feet below the base of the Schrader Bluff

OA sand.)

Other facilities work In addition to the facilities upgrades pre-

viously mentioned, during the 14th POD

period, Eni said it will perform routine

maintenance and mechanical integrity

inspection of piping, equipment, vessels,

tanks and other safety systems. The compa-

ny has several planned minor facility

upgrades at OPP and SID.

For example, process hazard analysis

revalidation action items from the 11th

POD will continue to be addressed and mit-

igated and efforts cleaning and replace inlet

heat exchanger bundles will continue to add

more heat to the processing system. Actions

will be based on the heat exchanger analysis

performed in the 12th POD.

An alarm management and rationaliza-

tion study will be performed to reduce nui-

sance alarms in the OPP control room.

Financial approval is expected on the

electrical power sharing, or EPS, project to

interconnect the Nikaitchuq power infra-

structure with the Oooguruk power infra-

structure. Eni said it will allow more robust

and efficient power system sharing between

the two development projects.

Detailed design and fabrication will also

occur during the 14th POD. Once approved.

EPS startup is scheduled for 2023.

Exploration outside PA Eni drilled the Nikaitchuq North extend-

ed reach exploration well, NN-01 outside

the Nikaitchuq unit’s participating area

from SID into the Harrison Bay Block 6423

federal unit north of the Nikaitchuq state

unit boundary.

The NN-01 well was first spud at SID on

Dec. 25, 2017, but drilling did not get

underway until February 2018 because of

what Eni said were “unforeseen impacts to

the drilling schedule.”

The well was drilled to a measured depth

of 30,010 feet and suspended in August

2018, but not fully logged as it was short of

its target which seismic showed to be at

approximately 34,150 feet. NN-01 drilling

was done with Doyon Rig 15, which had

been specially modified for the well.

Drilling operations resumed in mid-

January 2019, but due to the “drilling com-

plications” at NN-01 that had plagued it

from the start, Eni said it suspended the well

in April of that year.

The U.S. Bureau of Ocean Energy

Management said Eni’s NN-02 well would

be “targeting the same seismic anomaly” as

the first well.

Like the first ultra-extended reach well,

NN-02 will be an S-shape wellbore into the

target reservoir.

Eni had planned to drill NN-02 in Q2

2020 during the winter drilling season and

complete it in Q3 2020. However; the com-

pany’s working interest partner elected to

go non-consent (not participate) in the

drilling of NN-02, resulting in Eni tem-

porarily postponing its drilling plans.

Eni applied for and received from the

U.S. Bureau of Safety and Environmental

Enforcement, or BSEE, a suspension of

operations for an additional 2-year period,

or until April 2022, to drill NN-02.

One of the reasons Eni gave for stepping

out north of the Nikaitchuq unit to test the

Nikaitchuq North prospect was it wanted

new oil to take advantage of significant

spare capacity in the standalone Nikaitchuq

unit production facility, which can currently

handle 40,000 barrels per day and can easily

be expanded to 50,000 bpd, according to

Eni.

May production from Nikaitchuq aver-

aged 17,250 bpd.

Unit contraction delayed Low oil prices, reduced oil demand and

impacts of the COVID-19 pandemic

prompted Eni to request a delay in unit con-

traction on state leases for the Nikaitchuq

unit.

The Division of Oil and Gas approved

the Nikaitchuq deferral on Feb. 17.

Unit contraction reduces a unit to

acreage within participating areas, the areas

from which production is occurring.

In granting the deferral, Division

Director Tom Stokes said Eni provided

“evidence that the Schrader Bluff reservoir

extends outside the current participating

area and has described long-term plans to

drill wells in this area.”

If the wells are drilled, and prove pro-

ductive, that area would likely be included

in the existing Schrader Bluff PA, he said.

Without a contraction delay, Eni might

have lost the right to drill there, and if the

Nikaitchuq unit was contracted, Stokes

said, “the resources outside the unit are

unlikely large enough to justify develop-

ment by another lessee who might acquire

the area in a future lease sale.”

The area would also likely require

“duplicative facilities to develop.”

If the area was contracted from the

Nikaitchuq unit, Stokes said, “then the rela-

tively small resource size and difficult

development options could prevent devel-

opment and thus strand state resources.”

Contraction of the Nikaitchuq unit was

deferred through Sept. 30, 2022, which

coincides with the expiration of the unit’s

next plan of development. l

PETROLEUM NEWS • WEEK OF JULY 11, 2021 11

For Your Rig and Mobile Camp Needs

www.nordic-calista.com (907) 561-7458

continued from page 1

NIKAITCHUQ PACE

Nikaitchuq field 2021-22 drilling schedule

The two statements, taken together,

indicate that the additional consideration

included non-cashable tax credits above

the $19.1 million mentioned in the

release.

In 2017, the Alaska Legislature ended

the cashable tax credit program — the

Carried-Forward Annual Loss Credit —

in two steps. First, the program was ended

as of Dec. 31, 2017, after which no further

credit certificates could be earned.

Second, the state said it would only cash

out the portion of the certificate that was

earned in the first half of 2017.

Accumulate was active throughout

2017, spudding the Icewine No. 2 well

in the second quarter, with production

testing and other work continuing past

year end.

Prior to drilling, 88 Energy said it esti-

mated a cost of $17.7 million for the well,

which has a well site in the Franklin

Bluffs region that allows the company to

access the drilling location year-round.

Accumulate had tax credits from pre-

vious years, having received payment of

$99,060 in 2016 for a portion of its out-

standing credits, according to state

records.

If acquired, tax credits from the latter

half of 2017 cannot be cashed out, but

they can be used by the acquiring compa-

ny to lower its tax bill.

The State of Alaska does release a

yearly report of the sum total of tax credit

certificates for which repurchase has been

requested, along with a list of the amount

repurchased per company, but it does not

break out the value of certificates held by

each company due to tax confidentiality

considerations, a state source said.

—STEVE SUTHERLIN

continued from page 1

CREDIT SALE

Contact Steve Sutherlin at ssutherlin@petroleumnews.com

12 PETROLEUM NEWS • WEEK OF JULY 11, 2021

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